Patent Grant
7677310
This patent application incorporates by reference in its entirety each of U.S. Pat. Nos. 6,688,387 to Wellington et al.; 6,991,036 to Sumnu-Dindoruk et al.; 6,698,515 to Karanikas et al.; 6,880,633 to Wellington et al.; 6,782,947 to de Rouffignac et al; 6,991,045 to Vinegar et al.; 7,073,578 to Vinegar et al.; and 7,121,342 to Vinegar et al. This patent application incorporates by reference in its entirety U.S. Patent Application Publication 2005-0269313 to Vinegar et al., U.S. Patent Application Publication 2007-0133960 to Vinegar et al., and U.S. Patent Application Publication 2007-0221377 to Vinegar et al. This patent application incorporates by reference in its entirety U.S. patent application Ser. No. 11/788,871 to Vinegar et al.
1. Field of the Invention
The present invention relates generally to methods and systems for production of hydrocarbons, hydrogen, and/or other products from various subsurface formations such as hydrocarbon containing formations.
2. Description of Related Art
Hydrocarbons obtained from subterranean formations are often used as energy resources, as feedstocks, and as consumer products. Concerns over depletion of available hydrocarbon resources and concerns over declining overall quality of produced hydrocarbons have led to development of processes for more efficient recovery, processing and/or use of available hydrocarbon resources. In situ processes may be used to remove hydrocarbon materials from subterranean formations. Chemical and/or physical properties of hydrocarbon material in a subterranean formation may need to be changed to allow hydrocarbon material to be more easily removed from the subterranean formation. The chemical and physical changes may include in situ reactions that produce removable fluids, composition changes, solubility changes, density changes, phase changes, and/or viscosity changes of the hydrocarbon material in the formation. A fluid may be, but is not limited to, a gas, a liquid, an emulsion, a slurry, and/or a stream of solid particles that has flow characteristics similar to liquid flow.
During some in situ processes, wax may be used to reduce vapors and/or to encapsulate contaminants in the ground. Wax may be used during remediation of wastes to encapsulate contaminated material. U.S. Pat. Nos. 7,114,880 to Carter, and 5,879,110 to Carter, each of which is incorporated herein by reference, describe methods for treatment of contaminants using wax during the remediation procedures.
In some embodiments, a casing or other pipe system may be placed or formed in a wellbore. U.S. Pat. No. 4,572,299 issued to Van Egmond et al., which is incorporated by reference as if fully set forth herein, describes spooling an electric heater into a well. In some embodiments, components of a piping system may be welded together. Quality of formed wells may be monitored by various techniques. In some embodiments, quality of welds may be inspected by a hybrid electromagnetic acoustic transmission technique known as EMAT. EMAT is described in U.S. Pat. Nos. 5,652,389 to Schaps et al.; 5,760,307 to Latimer et al.; 5,777,229 to Geier et al.; and 6,155,117 to Stevens et al., each of which is incorporated by reference as if fully set forth herein.
In some embodiments, an expandable tubular may be used in a wellbore. Expandable tubulars are described in U.S. Pat. Nos. 5,366,012 to Lohbeck, and 6,354,373 to Vercaemer et al., each of which is incorporated by reference as if fully set forth herein.
Heaters may be placed in wellbores to heat a formation during an in situ process. Examples of in situ processes utilizing downhole heaters are illustrated in U.S. Pat. Nos. 2,634,961 to Ljungstrom; 2,732,195 to Ljungstrom; 2,780,450 to Ljungstrom; 2,789,805 to Ljungstrom; 2,923,535 to Ljungstrom; and 4,886,118 to Van Meurs et al.; each of which is incorporated by reference as if fully set forth herein.
Application of heat to oil shale formations is described in U.S. Pat. Nos. 2,923,535 to Ljungstrom and 4,886,118 to Van Meurs et al. Heat may be applied to the oil shale formation to pyrolyze kerogen in the oil shale formation. The heat may also fracture the formation to increase permeability of the formation. The increased permeability may allow formation fluid to travel to a production well where the fluid is removed from the oil shale formation. In some processes disclosed by Ljungstrom, for example, an oxygen containing gaseous medium is introduced to a permeable stratum, preferably while still hot from a preheating step, to initiate combustion.
A heat source may be used to heat a subterranean formation. Electric heaters may be used to heat the subterranean formation by radiation and/or conduction. An electric heater may resistively heat an element. U.S. Pat. No. 2,548,360 to Germain, which is incorporated by reference as if fully set forth herein, describes an electric heating element placed in a viscous oil in a wellbore. The heater element heats and thins the oil to allow the oil to be pumped from the wellbore. U.S. Pat. No. 4,716,960 to Eastlund et al., which is incorporated by reference as if fully set forth herein, describes electrically heating tubing of a petroleum well by passing a relatively low voltage current through the tubing to prevent formation of solids. U.S. Pat. No. 5,065,818 to Van Egmond, which is incorporated by reference as if fully set forth herein, describes an electric heating element that is cemented into a well borehole without a casing surrounding the heating element.
U.S. Pat. No. 6,023,554 to Vinegar et al., which is incorporated by reference as if fully set forth herein, describes an electric heating element that is positioned in a casing. The heating element generates radiant energy that heats the casing. A granular solid fill material may be placed between the casing and the formation. The casing may conductively heat the fill material, which in turn conductively heats the formation.
U.S. Pat. No. 4,570,715 to Van Meurs et al., which is incorporated by reference as if fully set forth herein, describes an electric heating element. The heating element has an electrically conductive core, a surrounding layer of insulating material, and a surrounding metallic sheath. The conductive core may have a relatively low resistance at high temperatures. The insulating material may have electrical resistance, compressive strength, and heat conductivity properties that are relatively high at high temperatures. The insulating layer may inhibit arcing from the core to the metallic sheath. The metallic sheath may have tensile strength and creep resistance properties that are relatively high at high temperatures.
U.S. Pat. No. 5,060,287 to Van Egmond, which is incorporated by reference as if fully set forth herein, describes an electrical heating element having a copper-nickel alloy core.
Obtaining permeability in an oil shale formation between injection and production wells tends to be difficult because oil shale is often substantially impermeable. Many methods have attempted to link injection and production wells. These methods include: hydraulic fracturing such as methods investigated by Dow Chemical and Laramie Energy Research Center; electrical fracturing by methods investigated by Laramie Energy Research Center; acid leaching of limestone cavities by methods investigated by Dow Chemical; steam injection into permeable nahcolite zones to dissolve the nahcolite by methods investigated by Shell Oil and Equity Oil; fracturing with chemical explosives by methods investigated by Talley Energy Systems; fracturing with nuclear explosives by methods investigated by Project Bronco; and combinations of these methods. Many of these methods, however, have relatively high operating costs and lack sufficient injection capacity.
Large deposits of heavy hydrocarbons (heavy oil and/or tar) contained in relatively permeable formations (for example in tar sands) are found in North America, South America, Africa, and Asia. Tar can be surface-mined and upgraded to lighter hydrocarbons such as crude oil, naphtha, kerosene, and/or gas oil. Surface milling processes may further separate the bitumen from sand. The separated bitumen may be converted to light hydrocarbons using conventional refinery methods. Mining and upgrading tar sand is usually substantially more expensive than producing lighter hydrocarbons from conventional oil reservoirs.
In situ production of hydrocarbons from tar sand may be accomplished by heating and/or injecting a gas into the formation. U.S. Pat. Nos. 5,211,230 to Ostapovich et al. and 5,339,897 to Leaute, which are incorporated by reference as if fully set forth herein, describe a horizontal production well located in an oil-bearing reservoir. A vertical conduit may be used to inject an oxidant gas into the reservoir for in situ combustion.
U.S. Pat. No. 2,780,450 to Ljungstrom describes heating bituminous geological formations in situ to convert or crack a liquid tar-like substance into oils and gases.
U.S. Pat. No. 4,597,441 to Ware et al., which is incorporated by reference as if fully set forth herein, describes contacting oil, heat, and hydrogen simultaneously in a reservoir. Hydrogenation may enhance recovery of oil from the reservoir.
U.S. Pat. No. 5,046,559 to Glandt and U.S. Pat. No. 5,060,726 to Glandt et al., which are incorporated by reference as if fully set forth herein, describe preheating a portion of a tar sand formation between an injector well and a producer well. Steam may be injected from the injector well into the formation to produce hydrocarbons at the producer well.
As outlined above, there has been a significant amount of effort to develop methods and systems to economically produce hydrocarbons, hydrogen, and/or other products from hydrocarbon containing formations. At present, however, there are still many hydrocarbon containing formations from which hydrocarbons, hydrogen, and/or other products cannot be economically produced. Thus, there is still a need for improved methods and systems for production of hydrocarbons, hydrogen, and/or other products from various hydrocarbon containing formations.
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 some embodiments, a method for treating a tar sands includes: providing heat to at least part of a hydrocarbon layer in the formation from one or more heaters located in the formation; allowing the pressure to increase in an upper portion of the formation to provide a gas cap in the upper portion; and producing at least some hydrocarbons from a lower portion of the formation.
In some embodiments, a method for treating a karsted formation containing heavy hydrocarbons includes: providing heat to at least part of one or more karsted layers in the formation from one or more heaters located in the karsted layers; allowing a temperature in at least one of the karsted layers to reach a decomposition temperature of dolomite in the formation; allowing the dolomite to decompose and produce carbon dioxide; maintaining the carbon dioxide in the formation to provide a gas cap in an upper portion of at least one of the karsted layers; and producing at least some hydrocarbons from at least one of the karsted layers of the formation.
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, or heaters described herein.
In further embodiments, additional features may be added to the specific embodiments described herein.
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:
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.
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.
“Alternating current (AC)” refers to a time-varying current that reverses direction substantially sinusoidally. AC produces skin effect electricity flow in a ferromagnetic conductor.
“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).
“Bare metal” and “exposed metal” refer to metals of elongated members that do not include a layer of electrical insulation, such as mineral insulation, that is designed to provide electrical insulation for the metal throughout an operating temperature range of the elongated member. Bare metal and exposed metal may encompass a metal that includes a corrosion inhibiter such as a naturally occurring oxidation layer, an applied oxidation layer, and/or a film. Bare metal and exposed metal include metals with polymeric or other types of electrical insulation that cannot retain electrical insulating properties at typical operating temperature of the elongated member. Such material may be placed on the metal and may be thermally degraded during use of the heater.
Boiling range distributions for the formation fluid and liquid streams described herein are as determined by ASTM Method D5307 or ASTM Method D2887. Content of hydrocarbon components in weight percent for paraffins, iso-paraffins, olefins, naphthenes and aromatics in the liquid streams is as determined by ASTM Method D6730. Content of aromatics in volume percent is as determined by ASTM Method D1319. Hydrogen content in hydrocarbons in weight percent is as determined by ASTM Method D3343.
Bromine number” refers to a weight percentage of olefins in grams per 100 gram of portion of the produced fluid that has a boiling range below 246° C. and testing the portion using ASTM Method D1159.
“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.
“Cenospheres” refers to hollow particulate that are formed in thermal processes at high temperatures when molten components are blown up like balloons by the volatilization of organic components.
“Chemically stability” refers to the ability of a formation fluid to be transported without components in the formation fluid reacting to form polymers and/or compositions that plug pipelines, valves, and/or vessels.
“Clogging” refers to impeding and/or inhibiting flow of one or more compositions through a process vessel or a conduit.
“Column X element” or “Column X elements” refer to one or more elements of Column X of the Periodic Table, and/or one or more compounds of one or more elements of Column X of the Periodic Table, in which X corresponds to a column number (for example, 13-18) of the Periodic Table. For example, “Column 15 elements” refer to elements from Column 15 of the Periodic Table and/or compounds of one or more elements from Column 15 of the Periodic Table.
“Column X metal” or “Column X metals” refer to one or more metals of Column X of the Periodic Table and/or one or more compounds of one or more metals of Column X of the Periodic Table, in which X corresponds to a column number (for example, 1-12) of the Periodic Table. For example, “Column 6 metals” refer to metals from Column 6 of the Periodic Table and/or compounds of one or more metals from Column 6 of the Periodic Table.
“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.
“Coring” is a process that generally includes drilling a hole into a formation and removing a substantially solid mass of the formation from the hole.
“Cracking” refers to a process involving decomposition and molecular recombination of organic compounds to produce a greater number of molecules than were initially present. In cracking, a series of reactions take place accompanied by a transfer of hydrogen atoms between molecules. For example, naphtha may undergo a thermal cracking reaction to form ethene and H2.
“Curie temperature” is the temperature above which a ferromagnetic material loses all of its ferromagnetic properties. In addition to losing all of its ferromagnetic properties above the Curie temperature, the ferromagnetic material begins to lose its ferromagnetic properties when an increasing electrical current is passed through the ferromagnetic material.
“Cycle oil” refers to a mixture of light cycle oil and heavy cycle oil. “Light cycle oil” refers to hydrocarbons having a boiling range distribution between 430° F. (221° C.) and 650° F. (343° C.) that are produced from a fluidized catalytic cracking system. Light cycle oil content is determined by ASTM Method D5307. “Heavy cycle oil” refers to hydrocarbons having a boiling range distribution between 650° F. (343° C.) and 800° F. (427° C.) that are produced from a fluidized catalytic cracking system. Heavy cycle oil content is determined by ASTM Method D5307.
“Diad” refers to a group of two items (for example, heaters, wellbores, or other objects) coupled together.
“Diesel” refers to hydrocarbons with a boiling range distribution between 260° C. and 343° C. (500-650° F.) at 0.101 MPa. Diesel content is determined by ASTM Method D2887.
“Enriched air” refers to air having a larger mole fraction of oxygen than air in the atmosphere. Air is typically enriched to increase combustion-supporting ability of the air.
“Fluid pressure” is a pressure generated by a fluid in a formation. “Lithostatic pressure” (sometimes referred to as “lithostatic stress”) is a pressure in a formation equal to a weight per unit area of an overlying rock mass. “Hydrostatic pressure” is a pressure in a formation exerted by a column of water.
A “formation” includes one or more hydrocarbon containing layers, one or more non-hydrocarbon layers, an overburden, and/or an underburden. “Hydrocarbon layers” refer to layers in the formation that contain hydrocarbons. The hydrocarbon layers may contain non-hydrocarbon material and hydrocarbon material. The “overburden” and/or the “underburden” include one or more different types of impermeable materials. For example, the overburden and/or underburden may include rock, shale, mudstone, or wet/tight carbonate. In some embodiments of in situ heat treatment processes, the overburden and/or the underburden may include a hydrocarbon containing layer or hydrocarbon containing layers that are relatively impermeable and are not subjected to temperatures during in situ heat treatment processing that result in significant characteristic changes of the hydrocarbon containing layers of the overburden and/or the underburden. For example, the underburden may contain shale or mudstone, but the underburden is not allowed to heat to pyrolysis temperatures during the in situ heat treatment process. In some cases, the overburden and/or the underburden may be somewhat permeable.
“Formation fluids” refer to fluids present in a formation and may include pyrolyzation fluid, synthesis gas, mobilized hydrocarbons, and water (steam). Formation fluids may include hydrocarbon fluids as well as non-hydrocarbon fluids. The term “mobilized fluid” refers to fluids in a hydrocarbon containing formation that are able to flow as a result of thermal treatment of the formation. “Produced fluids” refer to fluids removed from the formation.
“Freezing point” of a hydrocarbon liquid refers to the temperature below which solid hydrocarbon crystals may form in the liquid. Freezing point is as determined by ASTM Method D5901.
“Gasoline hydrocarbons” refer to hydrocarbons having a boiling point range from 32° C. (90° F.) to about 204° C. (400° F.). Gasoline hydrocarbons include, but are not limited to, straight run gasoline, naphtha, fluidized or thermally catalytically cracked gasoline, VB gasoline, and coker gasoline. Gasoline hydrocarbons content is determined by ASTM Method D2887.
“Heat of Combustion” refers to an estimation of the net heat of combustion of a liquid. Heat of combustion is as determined by ASTM Method D3338.
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 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 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 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.
“Karst” is a subsurface shaped by the dissolution of a soluble layer or layers of bedrock, usually carbonate rock such as limestone or dolomite. The dissolution may be caused by meteoric or acidic water. The Grosmont formation in Alberta, Canada is an example of a karst (or “karsted”) carbonate formation.
“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.
“Kerosene” refers to hydrocarbons with a boiling range distribution between 204° C. and 260° C. at 0.101 MPa. Kerosene content is determined by ASTM Method D2887.
“Modulated direct current (DC)” refers to any substantially non-sinusoidal time-varying current that produces skin effect electricity flow in a ferromagnetic conductor.
“Naphtha” refers to hydrocarbon components with a boiling range distribution between 38° C. and 200° C. at 0.101 MPa. Naphtha content is determined by ASTM Method D5307.
“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.
“Nitrogen compound content” refers to an amount of nitrogen in an organic compound. Nitrogen content is as determined by ASTM Method D5762.
“Octane Number” refers to a calculated numerical representation of the antiknock properties of a motor fuel compared to a standard reference fuel. A calculated octane number is determined by ASTM Method D6730.
“Olefins” are molecules that include unsaturated hydrocarbons having one or more non-aromatic carbon-carbon double bonds.
“Olefin content” refers to an amount of non-aromatic olefins in a fluid. Olefin content for a produced fluid is determined by obtaining a portion of the produce fluid that has a boiling point of 246° C. and testing the portion using ASTM Method D1159 and reporting the result as a bromine factor in grams per 100 gram of portion. Olefin content is also determined by the Canadian Association of Petroleum Producers (CAPP) olefin method and is reported in percent olefin as 1-decene equivalent.
“Orifices” refer to openings, such as openings in conduits, having a wide variety of sizes and cross-sectional shapes including, but not limited to, circles, ovals, squares, rectangles, triangles, slits, or other regular or irregular shapes.
““P (peptization) value” or “P-value” refers to a numerical value, which represents the flocculation tendency of asphaltenes in a formation fluid. P-value is determined by ASTM method D7060.
“Pebble” refers to one or more spheres, oval shapes, oblong shapes, irregular or elongated shapes.
“Periodic Table” refers to the Periodic Table as specified by the International Union of Pure and Applied Chemistry (IUPAC), Nov. 2003. In the scope of this application, weight of a metal from the Periodic Table, weight of a compound of a metal from the Periodic Table, weight of an element from the Periodic Table, or weight of a compound of an element from the Periodic Table is calculated as the weight of metal or the weight of element. For example, if 0.1 grams of MoO3 is used per gram of catalyst, the calculated weight of the molybdenum metal in the catalyst is 0.067 grams per gram of catalyst.
“Physical stability” refers the ability of a formation fluid to not exhibit phase separation or flocculation during transportation of the fluid. Physical stability is determined by ASTM Method D7060.
“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.
“Residue” refers to hydrocarbons that have a boiling point above 537° C. (1000° F.).
“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.
“Smart well technology” or “smart wellbore” refers to wells that incorporate downhole measurement and/or control. For injection wells, smart well technology may allow for controlled injection of fluid into the formation in desired zones. For production wells, smart well technology may allow for controlled production of formation fluid from selected zones. Some wells may include smart well technology that allows for formation fluid production from selected zones and simultaneous or staggered solution injection into other zones. Smart well technology may include fiber optic systems and control valves in the wellbore. A smart wellbore used for an in situ heat treatment process may be Westbay Multilevel Well System MP55 available from Westbay Instruments Inc. (Burnaby, British Columbia, Canada).
“Subsidence” is a downward movement of a portion of a formation relative to an initial elevation of the surface.
“Sulfur compound content” refers to an amount of sulfur in an organic compound. Sulfur content is as determined by ASTM Method D4294.
“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.
“TAN” refers to a total acid number expressed as milligrams (“mg”) of KOH per gram (“g”) of sample. TAN is as determined by ASTM Method D3242.
“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.
“Thermally conductive fluid” includes fluid that has a higher thermal conductivity than air at standard temperature and pressure (STP) (0° C. and 101.325 kPa).
“Thermal conductivity” is a property of a material that describes the rate at which heat flows, in steady state, between two surfaces of the material for a given temperature difference between the two surfaces.
“Thermal fracture” refers to fractures created in a formation caused by expansion or contraction of a formation and/or fluids in the formation, which is in turn caused by increasing/decreasing the temperature of the formation and/or fluids in the formation, and/or by increasing/decreasing a pressure of fluids in the formation due to heating.
“Thermal oxidation stability” refers to thermal oxidation stability of a liquid. Thermal Oxidation Stability is as determined by ASTM Method D3241.
“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.
“Time-varying current” refers to electrical current that produces skin effect electricity flow in a ferromagnetic conductor and has a magnitude that varies with time. Time-varying current includes both alternating current (AC) and modulated direct current (DC).
“Triad” refers to a group of three items (for example, heaters, wellbores, or other objects) coupled together.
“Turndown ratio” for the temperature limited heater is the ratio of the highest AC or modulated DC resistance below the Curie temperature to the lowest resistance above the Curie temperature for a given current.
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 “unshaped”.
“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 specified. Viscosity is as determined by ASTM
Method D445.
“VGO” or “vacuum gas oil” refers to hydrocarbons with a boiling range distribution between 343° C. and 538° C. at 0.101 MPa. VGO content is determined by ASTM Method D5307.
A “vug” is a cavity, void or large pore in a rock that is commonly lined with mineral precipitates.
“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.”
Hydrocarbons in formations may be treated in various ways to produce many different products. In certain embodiments, hydrocarbons in formations are treated in stages.
Desorption of methane and vaporization of water occurs during stage 1 heating. Heating of the formation through stage 1 may be performed as quickly as possible. For example, when the hydrocarbon containing formation is initially heated, hydrocarbons in the formation desorb adsorbed methane. The desorbed methane may be produced from the formation. If the hydrocarbon containing formation is heated further, water in the hydrocarbon containing formation is vaporized. Water may occupy, in some hydrocarbon containing formations, between 10% and 50% of the pore volume in the formation. In other formations, water occupies larger or smaller portions of the pore volume. Water typically is vaporized in a formation between 160° C. and 285° C. at pressures of 600 kPa absolute to 7000 kPa absolute. In some embodiments, the vaporized water produces wettability changes in the formation and/or increased formation pressure. The wettability changes and/or increased pressure may affect pyrolysis reactions or other reactions in the formation. In certain embodiments, the vaporized water is produced from the formation. In other embodiments, the vaporized water is used for steam extraction and/or distillation in the formation or outside the formation. Removing the water from and increasing the pore volume in the formation increases the storage space for hydrocarbons in the pore volume.
In certain embodiments, after stage 1 heating, the formation is heated further, such that a temperature in the formation reaches (at least) an initial pyrolyzation temperature (such as a temperature at the lower end of the temperature range shown as stage 2). Hydrocarbons in the formation may be pyrolyzed throughout stage 2. A pyrolysis temperature range varies depending on the types of hydrocarbons in the formation. The pyrolysis temperature range may include temperatures between 250° C. and 900° C. The pyrolysis temperature range for producing desired products may extend through only a portion of the total pyrolysis temperature range. In some embodiments, the pyrolysis temperature range for producing desired products may include temperatures between 250° C. and 400° C. or temperatures between 270° C. and 350° C. If a temperature of hydrocarbons in the formation is slowly raised through the temperature range from 250° C. to 400° C., production of pyrolysis products may be substantially complete when the temperature approaches 400° C. Average temperature of the hydrocarbons may be raised at a rate of less than 5° C. per day, less than 2° C. per day, less than 1° C. per day, or less than 0.5° C. per day through the pyrolysis temperature range for producing desired products. Heating the hydrocarbon containing formation with a plurality of heat sources may establish thermal gradients around the heat sources that slowly raise the temperature of hydrocarbons in the formation through the pyrolysis temperature range.
The rate of temperature increase through the pyrolysis temperature range for desired products may affect the quality and quantity of the formation fluids produced from the hydrocarbon containing formation. Raising the temperature slowly through the pyrolysis temperature range for desired products may inhibit mobilization of large chain molecules in the formation. Raising the temperature slowly through the pyrolysis temperature range for desired products may limit reactions between mobilized hydrocarbons that produce undesired products. Slowly raising the temperature of the formation through the pyrolysis temperature range for desired products may allow for the production of high quality, high API gravity hydrocarbons from the formation. Slowly raising the temperature of the formation through the pyrolysis temperature range for desired products may allow for the removal of a large amount of the hydrocarbons present in the formation as hydrocarbon product.
In some in situ heat treatment embodiments, a portion of the formation is heated to a desired temperature instead of slowly heating the temperature through a temperature range. In some embodiments, the desired temperature is 300° 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 the desired temperature. The heated portion of the formation is maintained substantially at the desired temperature until pyrolysis declines such that production of desired formation fluids from the formation becomes uneconomical. Parts of the formation that are subjected to pyrolysis may include regions brought into a pyrolysis temperature range by heat transfer from only one heat source.
In certain embodiments, formation fluids including pyrolyzation fluids are produced from the formation. As the temperature of the formation increases, the amount of condensable hydrocarbons in the produced formation fluid may decrease. At high temperatures, the formation may produce mostly methane and/or hydrogen. If the hydrocarbon containing formation is heated throughout an entire pyrolysis range, the formation may produce only small amounts of hydrogen towards an upper limit of the pyrolysis range. After all of the available hydrogen is depleted, a minimal amount of fluid production from the formation will typically occur.
After pyrolysis of hydrocarbons, a large amount of carbon and some hydrogen may still be present in the formation. A significant portion of carbon remaining in the formation can be produced from the formation in the form of synthesis gas. Synthesis gas generation may take place during stage 3 heating depicted in
Total energy content of fluids produced from the hydrocarbon containing formation may stay relatively constant throughout pyrolysis and synthesis gas generation. During pyrolysis at relatively low formation temperatures, a significant portion of the produced fluid may be condensable hydrocarbons that have a high energy content. At higher pyrolysis temperatures, however, less of the formation fluid may include condensable hydrocarbons. More non-condensable formation fluids may be produced from the formation. Energy content per unit volume of the produced fluid may decline slightly during generation of predominantly non-condensable formation fluids. During synthesis gas generation, energy content per unit volume of produced synthesis gas declines significantly compared to energy content of pyrolyzation fluid. The volume of the produced synthesis gas, however, will in many instances increase substantially, thereby compensating for the decreased energy content.
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 tuned 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 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 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 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 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 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 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 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 facilitate vapor phase production of fluids from the formation. Vapor phase production may allow for a reduction in size of collection conduits used to transport fluids produced from the formation. 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. Therefore, 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.
Formation fluid may be hot when produced from the formation through the production wells. Hot formation fluid may be produced during solution mining processes and/or during in situ heat treatment processes. In some embodiments, electricity may be generated using the heat of the fluid produced from the formation. Also, heat recovered from the formation after the in situ process may be used to generate electricity. The generated electricity may be used to supply power to the in situ heat treatment process. For example, the electricity may be used to power heaters, or to power a refrigeration system for forming or maintaining a low temperature barrier. Electricity may be generated using a Kalina cycle or a modified Kalina cycle.
Aqua ammonia from tank 218 is directed by pump 220 to heat exchanger 214 and heat exchanger 222. Aqua ammonia from heat exchangers 214, 222 passes to separator 224. Separator 224 forms a rich ammonia gas stream and a lean ammonia gas stream. The rich ammonia gas stream is sent to turbine 226 to generate electricity.
The lean ammonia gas stream from separator 224 passes through heat exchanger 222. The lean gas stream leaving heat exchanger 222 is combined with the rich ammonia gas stream leaving turbine 226. The combination stream is passed through heat exchanger 228 and returned to tank 218. Heat exchanger 228 may be water cooled. Heater water from heat exchanger 228 may be sent to a surface water reservoir through line 230.
Aqua ammonia from tank 218 is directed by pump 220 to heat exchanger 234. The temperature of the aqua ammonia from tank 218 is raised in heat exchanger 234 by heat transfer with a combined aqua ammonia stream from turbine 226 and separator 224. The aqua ammonia stream from heat exchanger 234 passes to heat exchanger 236. The temperature of the stream is raised again by transfer of heat with a lean ammonia stream that exits separator 224. The stream then passes to heat exchanger 214. Heat from the produced fluid is used to evaporate aqua ammonia in heat exchanger 214. The aqua ammonia passes to separator 224.
Separator 224 forms a rich ammonia gas stream and a lean ammonia gas stream. The rich ammonia gas stream is sent to turbine 226 to generate electricity. The lean ammonia gas stream passes through heat exchanger 236. After heat exchanger 236, the lean ammonia gas stream is combined with the rich ammonia gas stream leaving turbine 226. The combined gas stream is passed through heat exchanger 234 to cooler 238. After cooler 238, the stream returns to tank 218.
In situ heat treatment process gas 240 may enter gas separation unit 328 to separate gas hydrocarbon stream 330 from the in situ heat treatment process gas. The gas separation unit is, in some embodiments, a rectified adsorption and high pressure fractionation unit. Gas hydrocarbon stream 330 includes hydrocarbons having a carbon number of at least 3.
In situ heat treatment process liquid stream 324 enters liquid separation unit 332. In some embodiments, liquid separation unit 332 is not necessary. In liquid separation unit 332, separation of in situ heat treatment process liquid stream 324 produces gas hydrocarbon stream 336 and salty process liquid stream 338. Gas hydrocarbon stream 336 may include hydrocarbons having a carbon number of at most 5. A portion of gas hydrocarbon stream 336 may be combined with gas hydrocarbon stream 330.
In situ heat conversion process gas 240 enters gas separation unit 328. In gas separation unit 328, treatment of in situ heat conversion process gas 240 removes sulfur compounds, carbon dioxide, and/or hydrogen to produce gas stream 330. In some embodiments, situ heat conversion process gas 240 includes 20 vol % hydrogen, 30% methane, 12% carbon dioxide, 14 vol % C2 hydrocarbons, 5 vol % hydrogen sulfide, 10 vol % C3 hydrocarbons, 7 vol % C4 hydrocarbons, 2 vol % C5 hydrocarbons, with the balance being heavier hydrocarbons, water, ammonia, COS, mercaptans and thiophenes.
Gas separation unit 328 may include a physical treatment system and/or a chemical treatment system. The physical treatment system includes, but is not limited to, a membrane unit, a pressure swing adsorption unit, a liquid absorption unit, and/or a cryogenic unit. The chemical treatment system may include units that use amines (for example, diethanolamine or di-isopropanolamine), zinc oxide, sulfolane, water, or mixtures thereof in the treatment process. In some embodiments, gas separation unit 328 uses a Sulfinol gas treatment process for removal of sulfur compounds. Carbon dioxide may be removed using Catacarb® (Catacarb, Overland Park, Kans., U.S.A.) and/or Benfield (UOP, Des Plaines, Ill., U.S.A.) gas treatment processes. The gas separation unit is, in some embodiments, a rectified adsorption and high pressure fractionation unit. In some embodiments, in suit heat conversion process gas is treated to remove at least 50%, at least 60%, at least 70%, at least 80% or at least 90% by volume of ammonia present in the gas stream.
As depicted in
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In some embodiments, cryogenic unit 2310 may include one distillation column with about 1 to about 30 stages, about 5 to about 25 stages, or about 10 to about 20 stages. Stages of cryogenic unit 2310 may be cooled to temperatures ranging from about −110° C. to about 10° C. For example, stage 1 (top stage) cooled to about −138° C., stage 5 cooled to about −25° C., stage 10° C. cooled to at about −1° C. At temperatures lower than −79° C. cryogenic separation of the carbon dioxide from other gases may be difficult due to the freezing point of carbon dioxide. In some embodiments, cryogenic unit 2310 is about 17 ft. tall and includes about 20 distillation stages. Cryogenic unit 2310 may be operated at a pressure of 40 bar with distillation temperatures ranging from about −45° C. to about −94° C.
Compressed gas stream 2302 may include sufficient hydrogen and/or hydrocarbons having a carbon number of at least 1 to inhibit solid carbon dioxide formation. For example, in situ heat conversion process gas 240 may include from about 30 vol % to about 40 vol % of hydrogen, from about 50 vol % to 60 vol % of hydrocarbons having a carbon number from 1 to 2, from about 0.1 vol % to about 3 vol % of carbon dioxide with the balance being other gases such as, but not limited to, carbon monoxide, nitrogen, and hydrogen sulfide. Inhibiting solid carbon dioxide formation may allow for better separation of gases and/or less fouling of the cryogenic unit. In some embodiments, hydrocarbons having a carbon number of at least five may be added to cryogenic unit 2310 to inhibit formation of solid carbon dioxide. The resulting methane/hydrogen gas stream 2312 may be used as an energy source. For example, methane/hydrogen gas stream 2312 may be transported to surface facilities and burned to generate electricity.
As shown in
A portion of liquid stream 2318 may be transported via conduit 2322 to one or more portions of the formation and sequestered. In some embodiments, all of liquid stream 2318 is sequestered in one or more portions of the formation. In some embodiments, a portion of liquid stream 2318 enters cryogenic unit 2324. In cryogenic unit 2324, liquid stream 2318 is separated into C2 hydrocarbons/carbon dioxide stream 2326 and hydrogen sulfide stream 2328. In some embodiments, C2 hydrocarbons/carbon dioxide stream 2326 includes at most 0.5 vol % of hydrogen sulfide.
Hydrogen sulfide stream 2328 includes, in some embodiments, about 0.01 vol % to about 5 vol % of C3 hydrocarbons. In some embodiments, hydrogen sulfide stream 2328 includes hydrogen sulfide, carbon dioxide, C3 hydrocarbons, or mixtures thereof. For example, hydrogen sulfide stream 2328 includes, about 32 vol % of hydrogen sulfide, 67 vol % carbon dioxide, and 1 vol % C3 hydrocarbons. In some embodiments, hydrogen sulfide stream 2328 is used as an energy source for an in situ heat treatment process and/or sent to a Claus plant for further treatment.
C2 hydrocarbons/carbon dioxide stream 2326 may enter separation unit 2330. In separation unit 2330 C2 hydrocarbons/carbon dioxide stream 2326 is separated into C2 hydrocarbons stream 2332 and carbon dioxide stream 2334. Separation of C2 hydrocarbons from carbon dioxide is performed using separation methods known in the art, for example, pressure swing adsorption units, and/or extractive distillation units. In some embodiments, C2 hydrocarbons are separated from carbon dioxide using extractive distillation methods. For example, hydrocarbons having a carbon number from 3 to 8 may be added to separation unit 2330. Addition of a higher carbon number hydrocarbon solvent allows C2 hydrocarbons to be extracted from the carbon dioxide. C2 hydrocarbons are then separated from the higher carbon number hydrocarbons using distillation techniques. In some embodiments, C2 hydrocarbons stream 2332 is transported to other process facilities and used as an energy source. Carbon dioxide stream 2334 may be sequestered in one or more portions of the formation. In some embodiments, carbon dioxide stream 2334 contains at most 0.005 grams of non-carbon dioxide compounds per gram of carbon dioxide stream. In some embodiments, carbon dioxide stream 2334 is mixed with one or more oxidant sources supplied to one or more downhole burners.
In some embodiments, a portion or all of C2 hydrocarbons/carbon dioxide stream 2326 are sequestered and/or transported to other facilities via conduit 2336. In some embodiments, a portion or all of C2 hydrocarbons/carbon dioxide stream 2326 is mixed with one or more oxidant sources supplied to one or more downhole burners.
As depicted in
In some embodiments, a portion or all of C2 hydrocarbons/carbon dioxide stream 2326 are transported via conduit 2336 to one or more portions of the formation and sequestered. In some embodiments, a portion or all of C2 hydrocarbons/carbon dioxide stream 2326 are treated in separation unit 2330. Separation unit 2330 is described above with reference to
Hydrogen sulfide/hydrocarbon gas stream 2340 may enter cryogenic separation unit 2342. In cryogenic separation unit 2342, hydrogen sulfide may be separated from hydrocarbons having a carbon number of at least 3 to produce hydrogen sulfide stream 2328 and C3 hydrocarbon stream 2320. Hydrogen sulfide stream 2328 may include, but is not limited to, hydrogen sulfide, C3 hydrocarbons, carbon dioxide, or mixtures thereof. In some embodiments, hydrogen sulfide stream 2328 may contain from about 20 vol % to about 80 vol % of hydrogen sulfide, from about 4 vol % to about 18 vol % of propane and from about 2 vol % to about 70 vol % of carbon dioxide. In some embodiments, hydrogen sulfide stream 2328 is burned to produce SOx. The SOx may sequestered and/or treated using known techniques in the art.
In some embodiments, C3 hydrocarbon stream 2320 includes a minimal amount of hydrogen sulfide and carbon dioxide. For example, C3 hydrocarbon stream 2320 may include about 99.6 vol % of hydrocarbons having a carbon number of at least 3, about 0.4 vol % of hydrogen sulfide and at most 1 ppm of carbon dioxide. In some embodiments, C3 hydrocarbon stream 2320 is transported to other processing facilities as an energy source. In some embodiments, C3 hydrocarbon stream 2320 needs no further treatment.
As depicted in
A portion or all of C2 hydrocarbons/hydrogen sulfide/carbon dioxide gas stream 2346 and hydrocarbon stream 2348 may enter cryogenic separation unit 2350. Hydrocarbon stream 2348 may be any hydrocarbon stream suitable for use in a cryogenic extractive distillation system. In some embodiments, hydrocarbon stream 2348 is n-hexane. In cryogenic separation unit 2350, C2 hydrocarbons/hydrogen sulfide/carbon dioxide gas stream 2346 is separated into carbon dioxide stream 2334 and hydrocarbon/H2S stream 2352. In some embodiments, carbon dioxide stream 2334 includes about 2.5 vol % of hydrocarbons having a carbon number of at most 2. In some embodiments, carbon dioxide stream 2334 may be mixed with diluent fluid for downhole burners, may be used as a carrier fluid for oxidizing fluid for downhole burners, may be used as a drive fluid for producing hydrocarbons, may be vented, and/or may be sequestered. In some embodiments, cryogenic separation unit 2350 is 4 m tall and includes 40 distillation stages. Cryogenic separation unit 2350 may be operated at a temperature of about −19° C. and a pressure of about 20 bar.
Hydrocarbon/hydrogen sulfide stream 2352 may enter cryogenic separation unit 2354. Hydrocarbon/hydrogen stream 2352 may include solvent hydrocarbons, C2 hydrocarbons and hydrogen sulfide. In cryogenic separation unit 2354, hydrocarbon/hydrogen sulfide stream 2352 may be separated into C2 hydrocarbons/hydrogen sulfide stream 2382 and hydrocarbon stream 2384. Hydrocarbon stream 2384 may contain hydrocarbons having a carbon number of at least 3. In some embodiments, separation unit 2354 is about 6.5 m. tall and includes 20 distillation stages. Cryogenic separation unit 2354 may be operated at temperatures of about −16° C. and a pressure of about 10 bar.
Hydrogen sulfide/hydrocarbon gas stream 2340 may enter cryogenic separation unit 2342. In cryogenic separation unit 2342, hydrogen sulfide may be separated from hydrocarbons having a carbon number of at least 3 to produce hydrogen sulfide stream 2328 and C3 hydrocarbon stream 2320. Hydrogen sulfide stream 2328 may include, but is not limited to, hydrogen sulfide, C2 hydrocarbons, C3 hydrocarbons, carbon dioxide, or mixtures thereof. In some embodiments, hydrogen sulfide stream 2328 contains from about 31 vol % hydrogen sulfide with the balance being C2 and C3 hydrocarbons. Hydrogen sulfide stream 2328 may be burned to produce SOx. The SOx may be sequestered and/or treated using known techniques in the art.
In some embodiments, cryogenic separation unit 2342 is about 4.3 m tall and includes about 40 distillation stages. Temperatures in cryogenic separation unit 2342 may range from about 0° C. to about 10° C. Pressure in cryogenic separation unit 2342 may be about 20 bar.
C3 hydrocarbon stream 2320 may include a minimal amount of hydrogen sulfide and carbon dioxide. In some embodiments, C3 hydrocarbon stream 2320 includes about 50 ppm of hydrogen sulfide. In some embodiments, C3 hydrocarbon stream 2320 is transported to other processing facilities as an energy source. In some embodiments, hydrocarbon stream C3 hydrocarbon stream 2320 needs no further treatment.
As depicted in
Methane/carbon dioxide/hydrogen sulfide stream 2358 may include hydrocarbons having a carbon number of at most 2 and hydrogen sulfide. Methane/carbon dioxide/hydrogen sulfide stream 2358 may be compressed in compressor 2362 and enter cryogenic separation unit 2364. In cryogenic separation unit 2364, methane/carbon dioxide/hydrogen sulfide stream 2358 is separated into carbon dioxide stream 2334 and methane/hydrogen sulfide stream 2312. In some embodiments, cryogenic separation unit 2364 is about 2.1 m tall and includes 20 distillation stages. Temperatures in cryogenic separation unit 2364 may range from about −56° C. to about −96° C. at a pressure of about 45 bar.
Carbon dioxide stream 2334 may include some hydrogen sulfide. For example carbon dioxide stream 2334 may include about 80 ppm of hydrogen sulfide. At least a portion of carbon dioxide stream 2334 may be used as a heat exchange medium in heat exchanger 2366. In some embodiments, at least a portion of carbon dioxide stream 2334 is sequestered in the formation and/or at least a portion of the carbon dioxide stream is used as a diluent in downhole oxidizer assemblies.
Hydrocarbon/hydrogen sulfide stream 2360 may include hydrocarbons having a carbon number of at least 2 and hydrogen sulfide. Hydrocarbon/hydrogen sulfide stream 2360 may pass through heat exchanger 2366 and enter separation unit 2368. In separation unit 2368, hydrocarbon/hydrogen sulfide stream 2360 may be separated into hydrocarbon stream 2370 and hydrogen sulfide stream 2328. In some embodiments, separation unit 2368 is about 7 m tall and includes 30 distillation stages. Temperatures in separation unit 2368 may range from about 60° C. to about 27° C. at a pressure of about 10 bar.
Hydrocarbon stream 2370 may include hydrocarbons having a carbon number of at least 3. Hydrocarbon stream 2370 may pass through expansion unit 2372 and form purge stream 2374 and hydrocarbon stream 2376. Purge stream 2374 may include some hydrocarbons having a carbon number greater than 5. Hydrocarbon stream 2376 may include hydrocarbons having a carbon number of at most 5. In some embodiments, hydrocarbon stream 2376 includes 10 vol % n-butanes and 85 vol % hydrocarbons having a carbon number of 5. At least a part of hydrocarbon stream 2376 may be recycled to cryogenic separation unit 2356 to maintain a ratio of about 1.4:1 of hydrocarbons to compressed gas stream 2302.
Hydrogen sulfide stream 2328 may include hydrogen sulfide, C2 hydrocarbons, and some carbon dioxide. In some embodiments, hydrogen sulfide stream 2328 includes from about 13 vol % hydrogen sulfide, about 0.8 vol % carbon dioxide with the balance being C2 hydrocarbons. At least a portion of the hydrogen sulfide stream 2328 may be burned as an energy source. In some embodiments, hydrogen sulfide stream 2328 is used as a fuel source in downhole burners.
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Liquid stream 334 includes, but is not limited to, hydrocarbons having a carbon number of at least 5 and/or hydrocarbon containing heteroatoms (for example, hydrocarbons containing nitrogen, oxygen, sulfur, and phosphorus). Liquid stream 334 may include at least 0.001 g, at least 0.005 g, or at least 0.01 g of hydrocarbons with a boiling range distribution between about 95° C. and about 200° C. at 0.101 MPa; at least 0.01 g, at least 0.005 g, or at least 0.001 g of hydrocarbons with a boiling range distribution between about 200° C. and about 300° C. at 0.101 MPa; at least 0.001 g, at least 0.005 g, or at least 0.01 g of hydrocarbons with a boiling range distribution between about 300° C. and about 400° C. at 0.101 MPa; and at least 0.001 g, at least 0.005 g, or at least 0.01 g of hydrocarbons with a boiling range distribution between 400° C. and 650° C. at 0.101 MPa. In some embodiments, liquid stream 334 contains at most 10% by weight water, at most 5% by weight water, at most 1% by weight water, or at most 0.1% by weight water.
In some embodiments, the separated liquid stream may have a boiling range distribution between about 50° C. and about 350° C., between about 60° C. and 340° C., between about 70° C. and 330° C. or between about 80° C. and 320° C. In some embodiments, the separated liquid stream has a boiling range distribution between 180° C. and 330° C.
In some embodiments, at least 50%, at least 70%, or at least 90% by weight of the total hydrocarbons in the separated liquid stream have a carbon number from 8 to 13. The separated liquid stream may have from about 50% to about 100%, about 60% to about 95%, about 70% to about 90%, or about 75% to 85% by weight of liquid stream may have a carbon number distribution from 8 to 13. At least 50% by weight of the total hydrocarbons in the separated liquid stream may have a carbon number from about 9 to 12 or from 10 to 11.
In some embodiments, the separated liquid stream has at most 15%, at most 10%, at most 5% by weight of naphthenes; at least 70%, at least 80%, or at least 90% by weight total paraffins; at most 5%, at most 3%, or at most 1% by weight olefins; and at most 30%, at most 20%, or at most 10% by weight aromatics.
In some embodiments the separated liquid stream has at most 15%, at most 10%, at most 5% by weight of naphthenes; at least 70%, at least 80%, or at least 90% by weight total paraffins; at most 5%, at most 3%, or at most 1% by weight olefins; and at most 30%, at most 20%, or at most 10% by weight aromatics.
In some embodiments, the separated liquid stream has a nitrogen compound content of at least 0.01%, at least 0.1% or at least 0.4% by weight nitrogen compound. The separated liquid stream may have a sulfur compound content of at least 0.01%, at least 0.5% or at least 1% by weight sulfur compound.
After exiting desalting unit 340, liquid stream 334 enters filtration system 342. In some embodiments, filtration system 342 is connected to the outlet of the desalting unit. Filtration system 342 separates at least a portion of the clogging compounds from liquid stream 334. In some embodiments, filtration system 342 is skid mounted. Skid mounting filtration system 342 may allow the filtration system to be moved from one processing unit to another. In some embodiments, filtration system 342 includes one or more membrane separators, for example, one or more nanofiltration membranes or one or more reverse osmosis membranes.
In some embodiments, liquid stream 334 is contacted with hydrogen in the presence of one or more catalysts to change one or more desired properties of the crude feed to meet transportation and/or refinery specifications using known hydrodemetallation, hydrodesulfurization, hydrodenitrofication techniques. Other methods to change one or more desired properties of the crude feed are described in U.S. Published Patent Applications Nos. 2005-0133414; 2006-0231465; and 2007-0000810 to Bhan et al.; 2005-0133405 to Wellington et al.; and 2006-0289340 to Brownscombe et al., all of which are incorporated by reference herein.
In some embodiments, the hydrotreated liquid stream has a nitrogen compound content of at most 200 ppm by weight, at most 150 ppm, at most 110 ppm, at most 50 ppm, or at most 10 ppm of nitrogen compounds. The separated liquid stream may have a sulfur compound content of at most 100 ppm, at most 500 ppm, at most 300 ppm, at most 100 ppm, or at most 10 ppm by weight of sulfur compounds.
In some embodiments, hydrotreating unit 350 is a selective hydrogenation unit. In hydrotreating unit 350, liquid stream 334 and/or filtered liquid stream 344 are selectively hydrogenated such that di-olefins are reduced to mono-olefins. For example, liquid stream 334 and/or filtered liquid stream 344 is contacted with hydrogen in the presence of a DN-200 (Criterion Catalysts & Technologies, Houston Tex., U.S.A.) at temperatures ranging from 100° C. to 200° C. and total pressures of 0.1 MPa to 40 MPa to produce liquid stream 352. In some embodiments, filtered liquid stream 344 is hydrotreated at a temperature ranging from about 190° C. to about 200° C. at a pressure of at least 6 MPa. Liquid stream 352 includes a reduced content of di-olefins and an increased content of mono-olefins relative to the di-olefin and mono-olefin content of liquid stream 334. The conversion of di-olefins to mono-olefins under these conditions is, in some embodiments, at least 50%, at least 60%, at least 80% or at least 90%. Liquid stream 352 exits hydrotreating unit 350 and enters one or more processing units positioned downstream of hydrotreating unit 350. The units positioned downstream of hydrotreating unit 350 may include distillation units, catalytic reforming units, hydrocracking units, hydrotreating units, hydrogenation units, hydrodesulfurization units, catalytic cracking units, delayed coking units, gasification units, or combinations thereof. In some embodiments, hydrotreating prior to fractionation is not necessary. In some embodiments, liquid stream 352 may be severely hydrotreated to remove undesired compounds from the liquid stream prior to fractionation. In certain embodiments, liquid stream 352 may be fractionated and then produced streams may each be hydrotreated to meet industry standards and/or transportation standards.
Liquid stream 352 may exit hydrotreating unit 350 and enter fractionation unit 354. In fractionation unit 354, liquid stream 352 may be distilled to form one or more crude products. Crude products include, but are not limited to, C3-C5 hydrocarbon stream 356, naphtha stream 358, kerosene stream 360, diesel stream 362, and bottoms stream 364. Fractionation unit 354 may be operated at atmospheric and/or under vacuum conditions.
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In some embodiments, at least 50%, at least 70%, or at least 90% by weight of the total hydrocarbons in distilled liquid stream 355 have a carbon number from 8 to 13. Distilled liquid stream 355 may have from about 50% to about 100%, about 60% to about 95%, about 70% to about 90%, or about 75% to 85% by weight may have a carbon number from 8 to 13. At least 50% by weight to the total hydrocarbon in distilled liquid stream 355 may have a carbon number from about 9 to 12 or from 10 to 11.
In some embodiments, hydrotreated and distilled liquid stream 355 has at most 15%, at most 10%, at most 5% by weight of naphthenes; at least 70%, at least 80%, or at least 90% by weight total paraffins; at most 5%, at most 3%, or at most 1% by weight olefins; and at most 25%, at most 20%, or at most 15% by weight aromatics.
In some embodiments, hydrotreated and distilled liquid stream 355 has a nitrogen compound content of at most 200 ppm by weight, at most 150 ppm, at most 110 ppm, at most 50 ppm, at most 10 ppm, or at most 5 ppm of nitrogen compounds. The hydrotreated and distilled liquid stream may have a sulfur content of at most 50 ppm, at most 30 ppm or at most 10 ppm by weight sulfur compound.
In some embodiments, hydrotreated and/or distilled liquid stream 355 has a wear scar diameter as measured by ASTM D5001, ranging from about 0.1 mm to about 0.9 mm, from about 0.2 mm to about 0.8 mm, or from 0.3 mm to about 0.7 mm. In some embodiments, hydrotreated and/or distilled liquid stream 355 has a wear scar diameter, as measured by ASTM D5001 of at most 0.85 mm, at most 0.8 mm, at most 0.6 mm, at most 0.5 mm, or at most 0.3 mm. A wear scar diameter, as determined by ASTM D5001, may indicate the hydrotreated and/or distilled stream may have acceptable lubrication properties for transportation fuel (for example, commercial aviation fuel, fuel for military purposes, JP-8 fuel, Jet A-1 fuel).
Hydrotreating to remove undesired compounds (for example, sulfur compounds and nitrogen compounds) from the liquid stream may decrease the liquid stream to be an effective lubricant (for example, lubricity properties when used as a transportation fuel). In some embodiments, hydrotreated and/or distilled liquid stream 355 has a minimal concentration and/or no detectable amounts of sulfur compounds. A low sulfur, nonadditized hydrotreated and/or distilled liquid stream 355 may have acceptable lubricity properties (for example, an acceptable wear scar diameter as measured by ASTM D5001). For example, the hydrotreated and distilled liquid stream may have a boiling range distribution from about 140° C. to about 260° C., a sulfur content of at most 30 ppm by weight, and a wear sear diameter of at most 0.85 mm.
In some embodiments, naphtha stream 358, kerosene stream 360, diesel stream 362 (shown in FIGS 5 and 5A), and distilled liquid stream 355 are evaluated to determine an amount, if any, of additives and/or hydrocarbons that may be added to prepare a fully formulated transportation fuel and/or lubricant. For example, a distilled stream made by the processes described herein was evaluated for use in military vehicles against Department of Defense standard MIL-DTL-83133E using ASTM test methods. The results of the test are listed in TABLE 1.
To enhance the use of the streams produced from formation fluid, hydrocarbons produced during fractionation of the liquid stream and hydrocarbon gases produced during separating the process gas may be combined to form hydrocarbons having a higher carbon number. The produced hydrocarbon gas stream may include a level of olefins acceptable for alkylation reactions.
In some embodiments, hydrotreated liquid streams and/or streams produced from fractions (for example, distillates and/or naphtha) are blended with the in situ heat treatment process liquid and/or formation fluid to produce a blended fluid. The blended fluid may have enhanced physical stability and chemical stability as compared to the formation fluid. The blended fluid may have a reduced amount of reactive species (for example, di-olefins, other olefins and/or compounds containing oxygen, sulfur and/or nitrogen) relative to the formation fluid. Thus, chemical stability of the blended fluid is enhanced. The blended fluid may decrease an amount of asphaltenes relative to the formation fluid. Thus, physical stability of the blended fluid is enhanced. The blended fluid may be a more a fungible feed than the formation fluid and/or the liquid stream produced from an in situ heat treatment process. The blended feed may be more suitable for transportation, for use in chemical processing units and/or for use in refining units than formation fluid.
In some embodiments, a fluid produced by methods described herein from an oil shale formation may be blended with heavy oil/tar sands in situ heat treatment process (IHTP) fluid. Since the oil shale liquid is substantially paraffinic and the heavy oil/tar sands IHTP fluid is substantially aromatic, the blended fluid exhibits enhanced stability. In certain embodiments, in situ heat treatment process fluid may be blended with bitumen to obtain a feed suitable for use in refining units. Blending of the IHTP fluid and/or bitumen with the produced fluid may enhance the chemical and/or physical stability of the blended product. Thus, the blend may be transported and/or distributed to processing units.
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In some embodiments, bottoms stream 364 may be hydrocracked to produce naphtha and/or other products. The resulting naphtha may, however, need reformation to alter the octane level so that the product may be sold commercially as gasoline. Alternatively, bottoms stream 364 may be treated in a catalytic cracker to produce naphtha and/or feed for an alkylation unit. In some embodiments, naphtha stream 358, kerosene stream 360, and diesel stream 362 have an imbalance of paraffinic hydrocarbons, olefinic hydrocarbons, and/or aromatic hydrocarbons. The streams may not have a suitable quantity of olefins and/or aromatics for use in commercial products. This imbalance may be changed by combining at least a portion of the streams to form combined stream 366 which has a boiling range distribution from about 38° C. to about 343° C. Catalytically cracking combined stream 366 may produce olefins and/or other streams suitable for use in an alkylation unit and/or other processing units. In some embodiments, naphtha stream 358 is hydrocracked to produce olefins.
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Additional C3-C5 hydrocarbon stream 356′ may be sent to alkylation unit 368, combined with C3-C5 hydrocarbon stream 356, and/or combined with hydrocarbon gas stream 330 to produce gasoline suitable for commercial sale. In some embodiments, the olefin content in hydrocarbon gas stream 330 is acceptable and an additional source of olefins is not needed.
Many wells are needed for treating the hydrocarbon formation using the in situ heat treatment process. In some embodiments, vertical or substantially vertical wells are formed in the formation. In some embodiments, horizontal or U-shaped wells are formed in the formation. In some embodiments, combinations of horizontal and vertical wells are formed in the formation.
A manufacturing approach for the formation of wellbores in the formation may be used due to the large number of wells that need to be formed for the in situ heat treatment process. The manufacturing approach may be particularly applicable for forming wells for in situ heat treatment processes that utilize u-shaped wells or other types of wells that have long non-vertically oriented sections. Surface openings for the wells may be positioned in lines running along one or two sides of the treatment area.
The manufacturing approach for the formation of wellbores may include: 1) delivering flat rolled steel to near site tube manufacturing plant that forms coiled tubulars and/or pipe for surface pipelines; 2) manufacturing large diameter coiled tubing that is tailored to the required well length using electrical resistance welding (ERW), wherein the coiled tubing has customized ends for the bottom hole assembly (BHA) and hang off at the wellhead; 3) deliver the coiled tubing to a drilling rig on a large diameter reel; 4) drill to total depth with coil and a retrievable bottom hole assembly; 5) at total depth, disengage the coil and hang the coil on the wellhead; 6) retrieve the BHA; 7) launch an expansion cone to expand the coil against the formation; 8) return empty spool to the tube manufacturing plant to accept a new length of coiled tubing; 9) move the gantry type drilling platform to the next well location; and 10) repeat.
In situ heat treatment process locations may be distant from established cities and transportation networks. Transporting formed pipe or coiled tubing for wellbores to the in situ process location may be untenable due to the lengths and quantity of tubulars needed for the in situ heat treatment process. One or more tube manufacturing facilities 2004 may be formed at or near to the in situ heat treatment process location. The tubular manufacturing facility may form plate steel into coiled tubing. The plate steel may be delivered to tube manufacturing facilities 2004 by truck, train, ship or other transportation system. In some embodiments, different sections of the coiled tubing may be formed of different alloys. The tubular manufacturing facility may use ERW to longitudinally weld the coiled tubing.
Tube manufacturing facilities 2004 may be able to produce tubing having various diameters. Tube manufacturing facilities may initially be used to produce coiled tubing for forming wellbores. The tube manufacturing facilities may also be used to produce heater components, piping for transporting formation fluid to surface facilities, and other piping and tubing needs for the in situ heat treatment process.
Tube manufacturing facilities 2004 may produce coiled tubing used to form wellbores in the formation. The coiled tubing may have a large diameter. The diameter of the coiled tubing may be from about 4 inches to about 8 inches in diameter. In some embodiments, the diameter of the coiled tubing is about 6 inches in diameter. The coiled tubing may be placed on large diameter reels. Large diameter reels may be needed due to the large diameter of the tubing. The diameter of the reel may be from about 10 m to about 50 m. One reel may hold all of the tubing needed for completing a single well to total depth.
In some embodiments, tube manufacturing facilities 2004 has the ability to apply expandable zonal inflow profiler (EZIP) material to one or more sections of the tubing that the facility produces. The EZIP material may be placed on portions of the tubing that are to be positioned near and next to aquifers or high permeability layers in the formation. When activated, the EZIP material forms a seal against the formation that may serve to inhibit migration of formation fluid between different layers. The use of EZIP layers may inhibit saline formation fluid from mixing with non-saline formation fluid.
The size of the reels used to hold the coiled tubing may prohibit transport of the reel using standard moving equipment and roads. Because tube manufacturing facility 2004 is at or near the in situ heat treatment location, the equipment used to move the coiled tubing to the well sites does not have to meet existing road transportation regulations and can be designed to move large reels of tubing. In some embodiments the equipment used to move the reels of tubing is similar to cargo gantries used to move shipping containers at ports and other facilities. In some embodiments, the gantries are wheeled units. In some embodiments, the coiled tubing may be moved using a rail system or other transportation system.
The coiled tubing may be moved from the tubing manufacturing facility to the well site using gantries 2006. Drilling gantry 2008 may be used at the well site. Several drilling gantries 2008 may be used to form wellbores at different locations. Supply systems for drilling fluid or other needs may be coupled to drilling gantries 2008 from central facilities 2010.
Drilling gantry 2008 or other equipment may be used to set the conductor for the well. Drilling gantry 2008 takes coiled tubing, passes the coiled tubing through a straightener, and a BHA attached to the tubing is used to drill the wellbore to depth. In some embodiments, a composite coil is positioned in the coiled tubing at tube manufacturing facility 2004. The composite coil allows the wellbore to be formed without having drilling fluid flowing between the formation and the tubing. The composite coil also allows the BHA to be retrieved from the wellbore. The composite coil may be pulled from the tubing after wellbore formation. The composite coil may be returned to the tubing manufacturing facility to be placed in another length of coiled tubing. In some embodiments, the BHAs are not retrieved from the wellbores.
In some embodiments, drilling gantry 2008 takes the reel of coiled tubing from gantry 2006. In some embodiments, gantry 2006 is coupled to drilling gantry 2008 during the formation of the wellbore. For example, the coiled tubing may be fed from gantry 2006 to drilling gantry 2008, or the drilling gantry lifts the gantry to a feed position and the tubing is fed from the gantry to the drilling gantry.
The wellbore may be formed using the bottom hole assembly, coiled tubing and the drilling gantry. The BHA may be self-seeking to the destination. The BHA may form the opening at a fast rate. In some embodiments, the BHA forms the opening at a rate of about 100 m per hour.
After the wellbore is drilled to total depth, the tubing may be suspended from the wellhead. An expansion cone may be used to expand the tubular against the formation. In some embodiments, the drilling gantry is used to install a heater and/or other equipment in the wellbore.
When drilling gantry 2008 is finished at well site 2012, the drilling gantry may release gantry 2006 with the empty reel or return the empty reel to the gantry. Gantry 2006 may take the empty reel back to tube manufacturing facility 2004 to be loaded with another coiled tube. Gantries 2006 may move on looped path 2014 from tube manufacturing facility 2004 to well sites 2012 and back to the tube manufacturing facility.
Drilling gantry 2008 may be moved to the next well site. Global positioning satellite information, lasers and/or other information may be used to position the drilling gantry at desired locations. Additional wellbores may be formed until all of the wellbores for the in situ heat treatment process are formed.
In some embodiments, positioning and/or tracking system may be utilized to track gantries 2006, drilling gantries 2008, coiled tubing reels and other equipment and materials used to develop the in situ heat treatment location. Tracking systems may include bar code tracking systems to ensure equipment and materials arrive where and when needed.
Second wellbore 452B may be formed in the subsurface formation with drill bit 2022 on drilling string 2016. In certain embodiments, drilling string 2016 includes one or more magnets 2546. Wellbore 452B may be formed in a selected relationship to wellbore 452A. In certain embodiments, wellbore 452B is formed substantially parallel to wellbore 452A. In other embodiments, wellbore 452B is formed at other angles relative to wellbore 452A. In some embodiments, wellbore 452B is formed perpendicular relative to wellbore 452A.
In certain embodiments, wellbore 452A includes sensing array 2548. Sensing array 2548 may include two or more sensors 2550. Sensors 2550 may sense magnetic fields produced by magnets 2546 in wellbore 452B. The sensed magnetic fields may be used to assess a position of wellbore 452A relative to wellbore 452B. In some embodiments, sensors 2550 measure two or more magnetic fields provided by magnets 2546.
Two or more sensors 2550 in wellbore 452A may allow for continuous assessment of the relative position of wellbore 452A versus wellbore 452B. Using two or more sensors 2550 in wellbore 452A may also allow the sensors to be used as gradiometers. In some embodiments, sensors 2550 are positioned in advance (ahead of) magnets 2546. Positioning sensors 2550 in advance of magnets 2546 allows the magnets to traverse past the sensors so that the magnet's position (the position of wellbore 452B) is measurable continuously or “live” during drilling of wellbore 452B. Sensing array 2548 may be moved intermittently (at selected intervals) to move sensors 2550 ahead of magnets 2546. Positioning sensors 2550 in advance of magnets 2546 also allows the sensors to measure, store, and zero the Earth's field before sensing the magnetic fields of the magnets. The Earth's field may be zeroed by, for example, using a null function before arrival of the magnets, calculating background components from a known sensor attitude, or using a gradiometer setup.
The relative position of wellbore 452B versus wellbore 452A may be used to adjust the drilling of wellbore 452B using drilling string 2016. For example, the direction of drilling for wellbore 452B may be adjusted so that wellbore 452B remains a set distance away from wellbore 452A and the wellbores remain substantially parallel. In certain embodiments, the drilling of wellbore 452B is continuously adjusted based on continuous position assessments made by sensors 2550. Data from drilling string 2016 (for example, orientation, attitude, and/or gravitational data) may be combined or synchronized with data from sensors 2550 to continuously assess the relative positions of the wellbores and adjust the drilling of wellbore 452B accordingly. Continuously assessing the relative positions of the wellbores may allow for coiled tubing drilling of wellbore 452B.
In some embodiments, drilling string 2016 may include two or more sensing arrays 2548. Sensing arrays 2548 may include two or more sensors 2550. Using two or more sensing arrays 2548 in drilling string 2016 may allow for the direct measurement of magnetic interference of magnets 2546 on the measurement of the Earth's magnetic field. Directly measuring any magnetic interference of magnets 2546 on the measurement of the Earth's magnetic field may reduce errors in readings (for example, error to pointing azimuth). The direct measurement of the field gradient from the magnets from within drill string 2016 also provides confirmation of reference field strength of the field to be measured from within wellbore 452A.
The electromagnetic field provided by the voltage signal may be sensed by sensor 2550. The sensed signal may be used to assess a position of wellbore 452B relative to wellbore 452A.
In some embodiments, wire 2552 is a ranging wire located in wellbore 452A. In some embodiments, the voltage signal is provided by an electrical conductor that will be used as part of a heater in wellbore 452A. In some embodiments, the voltage signal is provided by an electrical conductor that is part of a heater or production equipment located in wellbore 452A. Wire 2552, or other electrical conductors used to provide the voltage signal, may be grounded so that there is no current return along the wire or in the wellbore. Return current may cancel the electromagnetic field produced by the wire.
Where return current exists, the current may be measured and modeled to generate a “net current” from which a voltage signal may be resolved. For example, in some areas, a 600 A signal current may only yield a 3-6 A net current. Where it is not feasible to eliminate sufficient return current along the wellbore containing the conductor, in some embodiments, two conductors may be utilized installed in separate wellbores. In this method, signal wires from each of the existing wellbores are connected to opposite voltage terminals of the signal generator. The return current path is in this way guided through the earth from the contactor region of one conductor to the other.
In certain embodiments, the reference voltage signal is turned on and off (pulsed) so that multiple measurements are taken by sensor 2550 over a selected time period. The multiple measurements may be averaged to reduce or eliminate resolution error in sensing the reference voltage signal. In some embodiments, providing the reference voltage signal, sensing the signal, and adjusting the drilling based on the sensed signals are performed continuously without providing any data to the surface or any surface operator input to the downhole equipment. For example, an automated system located downhole may be used to perform all the downhole sensing and adjustment operations.
The signal field generated by the net current passing through the conductors needs to be resolved from the general background field existing when the signal field is “off”. A method for resolving the signal field from the general background field on a continuous basis may include: 1.) calculating background components based on the known attitude of the sensors and the known value background field strength and dip; 2.) a synchronized “null” function to be applied immediately before the reference field is switched “on”; and/or 3.) synchronized sampling of forward and reversed DC polarities (the subtraction of these sampled values may effectively remove the background field yielding the reference total current field).
The signal provided by source 2554 may be sensed by sensor 2550. The sensed signal may be used to assess a position of wellbore 452B relative to wellbore 452A. In certain embodiments, the signal is continuously sensed using sensor 2550. The continuously sensed signal may be used to continuously and/or automatically adjust the drilling of wellbore 452B. The continuous sensing of the electromagnetic signal may be dual direction—creating a data link between transceivers. The antenna/sensor 2550 may be directly connected to a surface interface allowing for a data link between surface and subsurface to be established.
In some embodiments, source 2554 and/or sensor 2550 are sources and sensors used in a walkover radio locater system. Walkover radio locater systems are, for example, used in telecommunications to locate underground lines. In some embodiments, the walkover radio located system components may be modified to be located in wellbore 452A and wellbore 452B so that the relative positions of the wellbores are assessable using the walkover radio located system components.
In certain embodiments, multiple sources and multiple sensors may be used to assess and adjust the drilling of one or more wellbores.
In one embodiment, wellbores 452A are drilled substantially vertically in the formation and wellbores 452B are drilled substantially horizontally in the formation. Thus, wellbores 452B are substantially perpendicular relative to wellbores 452A. Sensors 2550 in wellbores 452B may detect signals from one or more of sources 2554. Detecting signals from more than one source may allow for more accurate measurement of the relative positions of the wellbores in the formation. In some embodiments, electromagnetic attenuation and phase shift detected from multiple sources is used to define the position of a sensor (and the wellbore). The paths of the electromagnetic radio waves may be predicted to allow detection and use of the electromagnetic attenuation and the phase shift to define the sensor position.
Resulting electromagnetic field 2564 is measured by sensor 2550 (for example, a transceiving antenna) in bottom hole assembly 2018A of first wellbore 452A being drilled in proximity to the location of heater 716. A predetermined “known” net current in the formation may be relied upon to provide a reference magnetic field.
The injection of the reference current may be rapidly pulsed and synchronized with the receiving antenna and/or sensor data. Access to a high data rate signal from the magnetometers can be used to filter the effects of sensor movement during drilling. The measurement of the reference magnetic field may provide a distance and direction to the heater. Averaging many of these results will provide the position of the actively drilled hole. The known position of the heater and known depth of the active sensors may be used to assess position coordinates of easting, northing, and elevation.
The quality of data generated with such a method may depend on the accuracy of the net current prediction along the length of the heater. Using formation resistivity data, a model may be used to predict the losses to earth along the bottom hole assembly. The bottom hole assembly may be in direct contact with the formation and borehole fluids.
The current may be measured on both the element and the bottom hole assembly at the surface. The difference in values is the overall current loss to the formation. It is anticipated that the net field strength will vary along the length of the heater. The field is expected to be greater at the surface when the positive voltage applies to the bottom hole assembly.
If there are minimal losses to earth in the formation, the net field may not be strong enough to provide a useful detection range. In some embodiments, a net current in the range of about 2 A to about 50 A, about 5 A to about 40 A, or about 10 A to about 30 A, may be employed.
In some embodiments, two heaters are used as a long conductor for a reference current (pulsed DC or AC) to be injected for assessing a position of a first wellbore relative to a second wellbore. Utilizing two separate heater elements may result in relatively better control of return current path and therefore better control of reference current strength.
A two heater method may not rely on the accuracy of a “model of current loss to formation”, as current is contained in the heater element along the full length of the heaters. Current may be rapidly pulsed and synchronized with the transceiving antenna and/or sensor data to resolve distance and direction to the heater.
In some embodiments, parallel well tracking may be used for assessing a position of a first wellbore relative to a second wellbore. Parallel well tracking may utilize magnets of a known strength and a known length positioned in the pre-drilled second wellbore. Magnetic sensors positioned in the active first wellbore may be used to measure the field from the magnets in the second wellbore. Measuring the generated magnetic field in the second wellbore with sensors in the first wellbore may assess distance and direction of the active first wellbore. In some embodiments, magnets positioned in the second wellbore may be carefully positioned and multiple static measurements taken to resolve any general “background” magnetic field. Background magnetic fields may be resolved through use of a null function before positioning the magnets in the second wellbore, calculating background components from known sensor attitudes, and/or a gradiometer setup.
In some embodiments, reference magnets may be positioned in the drilling bottom hole assembly of the first wellbore. Sensors may be positioned in the passive second wellbore. The prepositioned sensors may be nulled prior to the arrival of the magnets in the detectable range in order to eliminate Earth's background field. This may significantly reduce the time required to assess the position and direction of the first wellbore during drilling as the bottom hole assembly may continue drilling with no stoppages. The commercial availability of low cost sensors such as a terrella (utilizing magnetoresistives rather than fluxgates) may be incorporated into the wall of a deployment coil at useful separations.
In some embodiments, multiple types of sources may be used in combination with two or more sensors to assess and adjust the drilling of one or more wellbores. A method of assessing a position of a first wellbore relative to a second wellbore may include a combination of angle sensors, telemetry, and/or ranging systems. Such a method may be referred to as umbilical position control.
Angle sensors may assess an attitude (azimuth, inclination, and roll) of a bottom hole assembly. Assessing the attitude of a bottom hole assembly may include measuring, for example, azimuth, inclination, and/or roll. Telemetry may transmit data (for example, measurements) between the surface and, for example, sensors positioned in a wellbore. Ranging may assess the position of a bottom hole assembly in a first wellbore relative to a second wellbore. The second wellbore, in some embodiments, may include an existing, previously drilled wellbore.
In the first wellbore, sensors 2550A may be coupled to first transceiving antenna 2556A. First transceiving antenna 2556A may communicate with second transceiving antenna 2556B in second wellbore 452B. The first transceiving antenna may be positioned on bottom hole assembly 2018. Sensors coupled to the first transceiving antenna may include, for example, magnetometers and/or accelerometers. In certain embodiments, sensors coupled to the first transceiving antenna may include dual magnetometers/accelerometer sets.
To accomplish data transfer 2560, first transceiving antenna 2556A transmits (“short hops”) measured data through the ground to second transceiving antenna 2556B located in the second wellbore. The data may then be transmitted to the surface via embedded wires 2558 in the deployment tubular.
Two redundant ranging systems may be utilized for umbilical control systems. A first ranging system may include a version of a plasma wave tracker (PWT).
A second ranging system may be based on using the signal strength and phase of the “through the earth” wireless link (for example, radio) established between the first transceiving antenna in the first wellbore and the second transceiving antenna in the second wellbore. Given the close spacing of holes, the variability in electrical properties of the formation and, thus, attenuation rates for the electromagnetic signal are expected to be predictable. Predictable attenuation rates for the electromagnetic signal allow the signal strength to be used as a measure of separation between the first and second transceiver pairs. The vector direction of the magnetic field induced by the electromagnetic transmissions from the first wellbore may provide the direction.
With a known resistivity of the formation and operating frequency, the distance between the source and point of measurement may be calculated.
Another factor which affects attenuation is the frequency the electromagnetic source operates on. Typically, the higher the frequency, the higher the attenuation and vice versa. A strategy for choosing between various frequencies may depend on the formation chosen. For example, while the attenuation at a resistivity of 100 ohm-m may be good for data communications, it may not be sufficient for distance calculations. Thus, a higher frequency may be chosen to increase attenuation. Alternatively, a lower frequency may be chosen for the opposite purpose.
Wireless data communications in ground may allow an opportunity for electromagnetic ranging and the variable frequency it operates on must be observed to balance out benefits for both functionalities. Benefits of wireless data communication may include, but not be limited to: 1) automatic depth sync through the use of ranging and telemetry; 2) fast communications with dedicated hardwired (for example, optic fiber) coil for a transceiving antenna running in, for example, the second wellbore; 3) functioning as an alternative method for fast communication when hardwire in, for example, the first wellbore is not available; 4) functioning in under balanced and over balanced drilling; 5) providing a similar method for transmitting control commands to a bottom hole assembly; 6) sensors are reusable reducing costs and waste; 7) decreasing noise measurement functions split between the first wellbore and the second wellbore; and/or 8) multiple position measurement techniques simultaneously supported may provide real time best estimate of position and attitude.
In some embodiments, it may be advisable to employ sensors able to compensate for magnetic fields produced internally by carbon steel casing built in the vertical section of a reference hole (for example, high range magnetometers). In some embodiments, modification may be made to account for problems with wireless antenna communications between wellbores penetrating through wellbore casings.
Pieces of formation or rock may protrude or fall into the wellbore due to various failures including rock breakage or plastic deformation during and/or after wellbore formation. Protrusions may interfere with drill string movement and/or the flow of drilling fluids. Protrusions may prevent running tubulars into the wellbore after the drill string has been removed from the wellbore. Significant amounts of material entering or protruding into the wellbore may cause wellbore integrity failure and/or lead to the drill string becoming stuck in the wellbore. Some causes of wellbore integrity failure may be in situ stresses and high pore pressures. Mud weight may be increased to hold back the formation and inhibit wellbore integrity failure during wellbore formation. When increasing the mud weight is not practical, the wellbore may be reamed.
Reaming the wellbore may be accomplished by moving the drill string up and down one joint while rotating and circulating. Picking the drill string up can be difficult because of material protruding into the borehole above the bit or BHA (bottom hole assembly). Picking up the drill string may be facilitated by placing upward facing cutting structures on the drill bit. Without upward facing cutting structures on the drill bit, the rock protruding into the borehole above the drill bit must be broken by grinding or crushing rather than by cutting. Grinding or crushing may induce additional wellbore failure.
Moving the drill string up and down may induce surging or pressure pulses that contribute to wellbore failure. Pressure surging or fluctuations may be aggravated or made worse by blockage of normal drilling fluid flow by protrusions into the wellbore. Thus, attempts to clear the borehole of debris may cause even more debris to enter the wellbore.
When the wellbore fails further up the drill string than one joint from the drill bit, the drill string must be raised more than one joint. Lifting more than one joint in length may require that joints be removed from the drill string during lifting and placed back on the drill string when lowered. Removing and adding joints requires additional time and labor, and increases the risk of surging as circulation is stopped and started for each joint connection.
In some embodiments, cutting structures may be positioned at various points along the drill string. Cutting structures may be positioned on the drill string at selected locations, for example, where the diameter of the drill string or BHA changes.
In some embodiments, some cutting structures may be upwardly facing, some cutting structures may be downwardly facing, and/or some cutting structures may be oriented substantially perpendicular to the drill string.
Positioning downward facing cutting structures 2020b at various locations along a length of the drill string may allow for reaming of the wellbore while the drill bit forms additional borehole at the bottom of the wellbore. The ability to ream while drilling may avoid pressure surges in the wellbore caused by the lifting the drill string. Reaming while drilling allows the wellbore to be reamed without interrupting normal drilling operation. Reaming while drilling allows the wellbore to be formed in less time because a separate reaming operation is avoided. Upward facing cutting structures 2020a allow for easy removal of the drill string from the wellbore.
In some embodiments, the drill string includes a plurality of cutting structures positioned along the length of the drill string, but not necessarily along the entire length of the drill string. The cutting structures may be positioned at regular or irregular intervals along the length of the drill string. Positioning cutting structures along the length of the drill string allows the entire wellbore to be reamed without the need to remove the entire drill string from the wellbore.
Cutting structures may be coupled or attached to the drill string using techniques known in the art (for example, by welding). In some embodiments, cutting structures are formed as part of a hinged ring or multi-piece ring that may be bolted, welded, or otherwise attached to the drill string. In some embodiments, the distance that the cutting structures extend beyond the drill string may be adjustable. For example, the cutting element of the cutting structure may include threading and a locking ring that allows for positioning and setting of the cutting element.
In some wellbores, a wash over or over-coring operation may be needed to free or recover an object in the wellbore that is stuck in the wellbore due to caving, closing, or squeezing of the formation around the object. The object may be a canister, tool, drill string, or other item. A wash-over pipe with downward facing cutting structures at the bottom of the pipe may be used. The wash over pipe may also include upward facing cutting structures and downward facing cutting structures at locations near the end of the wash-over pipe. The additional upward facing cutting structures and downward facing cutting structures may facilitate freeing and/or recovery of the object stuck in the wellbore. The formation holding the object may be cut away rather than broken by relying on hydraulics and force to break the portion of the formation holding the stuck object.
A problem in some formations is that the formed borehole begins to close soon after the drill string is removed from the borehole. Boreholes which close up soon after being formed make it difficult to insert objects such as tubulars, canisters, tools, or other equipment into the wellbore. In some embodiments, reaming while drilling applied to the core drill string allows for emplacement of the objects in the center of the core drill pipe. The core drill pipe includes one or more upward facing cutting structures in addition to cutting structures located at the end of the core drill pipe. The core drill pipe may be used to form the wellbore for the object to be inserted in the formation. The object may be positioned in the core of the core drill pipe. Then, the core drill pipe may be removed from the formation. Any parts of the formation that may inhibit removal of the core drill pipe are cut by the upward facing cutting structures as the core drill pipe is removed from the formation.
Replacement canisters may be positioned in the formation using over core drill pipe. First, the existing canister to be replaced is over cored. The existing canister is then pulled from within the core drill pipe without removing the core drill pipe from the borehole. The replacement canister is then run inside of the core drill pipe. Then, the core drill pipe is removed from the borehole. Upward facing cutting structures positioned along the length of the core drill pipe cut portions of the formation that may inhibit removal of the core drill pipe.
During some in situ heat treatment processes, wellbores may need to be formed in heated formations. Wellbores drilled into hot formation may be additional or replacement heater wells, additional or replacement production wells and/or monitor wells. Cooling while drilling may enhance wellbore stability, safety, and longevity of drilling tools. When the drilling fluid is liquid, significant wellbore cooling can occur due to the circulation of the drilling fluid.
In some in situ heat treatment processes, a barrier formed around all or a portion of the in situ heat treatment process is formed by freeze wells that form a low temperature zone around the freeze wells. A portion of the cooling capacity of the freeze well equipment may be utilized to cool the equipment needed to drill into the hot formation. Drilling bits may be advanced slowly in hot sections to ensure that the formed wellbore cools sufficiently to preclude drilling problems.
When using conventional circulation, drilling fluid flows down the inside of the drillpipe and back up the outside of the drillpipe. Other circulation systems, such as reverse circulation, may also be used. In some embodiments, the drill pipe may be positioned in a pipe-in-pipe configuration.
Drillpipe used to form the wellbore may function as a counter-flow heat exchanger. The deeper the well, the more the drilling fluid heats up on the way down to the drill bit as the drillpipe passes through heated portions of the formation. Thus the counter-flow heat exchanger effect reduces downhole cooling. When normal circulation does not deliver low enough temperature drilling fluid to the drill bit to provide adequate cooling, two options have been employed to enhance cooling. Mud coolers on the surface can be used to reduce the inlet temperature of the drilling fluid being pumped downhole. If cooling is still inadequate, insulated drillpipe can be used to reduce the counter-flow heat exchanger effect.
In some embodiments, all or a portion of conduit 436 may be insulated to reduce heat transfer to the cooled mud as the mud passes into the formation. Insulating all or a portion of conduit 436 may allow colder mud to be provided to the drill bit than if the conduit is not insulated. Conduit 436 may be insulated for greater than ¼ of the length of the conduit, for greater than ½ the length of the conduit, for greater than ¾ the length of the conduit, or for substantially all of the length of the conduit.
All or a portion of inlet leg 2378 may be insulated to inhibit heat transfer to the cooling fluid entering closed loop system 438 from cooling fluid leaving the closing loop system through exit leg 2380 and/or with the drilling mud. Insulating all or a portion of inlet leg 2378 may also maintain the cooling fluid at a low temperature so that the cooling fluid is able to absorb heat from the drilling mud in a region near drill bit 434 so that the drilling mud is able to cool the drill bit and/or the formation. In some embodiments, all or a portion of inlet leg 2378 is made of a material with low thermal conductivity to limit heat transfer to the cooling fluid in the inlet leg. For example, all or a portion of inlet leg 2378 may be made of a polyethylene pipe.
In some embodiments, inlet leg 2378 and the exit leg 2380 for the cooling fluid are arranged in a conduit-in-conduit configuration. In one embodiment, cooling fluid flows down the inner conduit (the inlet leg) and returns through the space between the inner conduit and the outer conduit (the exit leg). The inner conduit may be insulated or made of a material with low thermal conductivity to inhibit or reduce heat transfer between the cooling fluid going down the inner conduit and the cooling fluid returning through the space between the inner conduit and the outer conduit. In some embodiments, the inner conduit may be made of a polymer, such as high density polyethylene.
For various reasons including lost circulation, wells are frequently drilled with gas (for, example air, nitrogen, carbon dioxide, methane, ethane, and other light hydrocarbon gases) as the drilling fluid primarily to maintain a low equivalent circulating density (low downhole pressure gradient). Gas has low potential for cooling the wellbore because mass flow rates of gas drilling are much lower than when liquid drilling fluid is used. Also, gas has a low heat capacity compared to liquid. As a result of heat flow from the outside to the inside of the drillpipe, the gas arrives at the drill bit at close to formation temperature. Controlling the inlet temperature of the gas (analogous to using mud coolers when drilling with liquid) or using insulated drillpipe only marginally reduces the counter-flow heat exchanger effect when gas drilling. Some gases are more effective than others at transferring heat, but the use of gasses with better transfer properties does not significantly improve wellbore cooling while gas drilling.
Gas drilling may deliver the drilling fluid to the drill bit at close to the formation temperature. The gas may have little capacity to absorb heat. A defining feature of gas drilling is the low density column in the annulus. Immaterial to the benefits of gas drilling is the phase of the drilling fluid flowing down the inside of the drilling pipe. Thus, the benefits of gas drilling can be accomplished if the drilling fluid is liquid while flowing down the drillpipe and gas while flowing back up the annulus. The heat of vaporization is used to cool the drill bit and the formation rather than the sensible heat of the drilling fluid.
An advantage of this approach is that even though the liquid arrives at the bit at close to formation temperature, it can absorb heat by vaporizing. In fact, the heat of vaporization is typically larger than the heat that can be absorbed by a temperature rise. As a comparison, consider drilling a 7⅞″ wellbore with 3½″ drillpipe circulating low density mud at about 203 gpm and with about a 100 ft/min typical annular velocity. Drilling through a 450° F. zone at 1000 feet will result in a mud exit temperature about 8° F. hotter than the inlet temperature. This results in the removal of about 14,000 Btu/min. The removal of this much heat lowers the bit temperature from about 450° F. to about 285° F. If liquid water is injected down the drillpipe and allowed to boil at the bit and steam is produced up the annulus, the mass flow required to remove ½″ cuttings is about 34 lbm/min assuming the back pressure is about 100 psia. At 34 lbm/min the heat removed from the wellbore would be about 34 lbm/min×(1187−180) Btu/lbm or about 34,000 Btu/min. This heat removal amount is about 2.4 times the liquid cooling case. Thus, at reasonable annular steam flow rates, a significant amount of heat can be removed by vaporization.
The high velocities required for gas drilling are achieved by the expansion that occurs during vaporization rather than by employing compressors on the surface. Eliminating the need for compressors may simplify the drilling process, eliminate the cost of the compressor, and eliminate a source of heat applied to the drilling fluid on the way to the drill bit.
Critical to the process of delivering liquid to the drill bit is preventing boiling within the drillpipe. If the drilling fluid flowing downwards boils before reaching the drill bit, the heat of vaporization is used to extract heat from the drilling fluid flowing up the annulus. The heat transferred from the annulus (outside the drillpipe) to inside the drillpipe boiling the fluid is heat that is not rejected from the well when drilling fluid reaches the surface. Boiling that occurs inside of the drillpipe before the drilling fluid reaches the bottom of the hole is not beneficial to drill bit and/or wellbore cooling.
If the pressure in the drillpipe is maintained above the boiling pressure for a given temperature by use of a back pressure device, then the transfer of heat from outside the drillpipe to inside can be minimized or essentially eliminated. The liquid supplied to the drill bit may be vaporized. Vaporization may result in the drilling fluid adsorbing the heat of vaporization from the drill bit and formation. For example, if the back pressure device is set to allow flow only when the back pressure is above 250 psi, the fluid within the drillpipe will not boil unless the temperature is above 400° F. If the temperature of the formation is above this (for example, 500° F.) steps may be taken to inhibit boiling of the fluid on the way down to the drill bit. In an embodiment, the back pressure device is set to maintain a back pressure that inhibits boiling of the drilling fluid at the temperature of the formation (for example, 580 psi to inhibit boiling up to a temperature of 500° F.). In another embodiment, the drilling pipe is insulated and/or the drilling fluid is cooled so that the back pressure device is able to maintain the drilling fluid that reaches the drill bit as a liquid.
Two back pressure devices that may be used to maintain elevated pressure within the drillpipe are a choke and a pressure activated valve. Other types of back pressure devices may also be used. Chokes have a restriction in flow area that creates back pressure by resisting flow. Resisting the flow results in increased upstream pressure to force the fluid through the restriction. Pressure activated valves do not open until a minimum upstream pressure is obtained. The pressure difference across a pressure activated valves may determine if the pressure activated valve is open to allow flow or closed.
In some embodiments, both a choke and pressure activated valve may be used. A choke can be the bit nozzles allowing the liquid to be jetted toward the drill bit and the bottom of the hole. The bit nozzles may enhance drill bit cleaning and help prevent fouling of the drill bit and pressure activated valve. Fouling may occur if boiling in the drill bit or pressure activated valve caused solids to precipitate. The pressure activated valve may prevent premature boiling at low flow rates below flow rates at which the chokes are effective.
Additives may be added to the drilling fluid. The additives may modify the properties of the fluids in the liquid phase and/or the gas phase. Additives may include, but are not limited to surfactants to foam the fluid, additives to chemically alter the interaction of the fluid with the formations (for example, to stabilize the formation), additives to control corrosion, and additives for other benefits.
In some embodiments, a non-condensable gas may be added to the drilling fluid pumped down the drillpipe. The non-condensable gas may be, but is not limited to nitrogen, carbon dioxide, air, and mixtures thereof. Adding the non-condensable gas results in pumping a two phase mixture down the drillpipe. One reason for adding the non-condensable gas is to enhance the flow of the fluid out of the formation. The presence of the non-condensable gas may inhibit condensation of the vaporized drilling fluid and help to carry cuttings out of the formation. In some embodiments, one or more heaters may be present at one or more locations in the wellbore to provide heat that inhibits condensation and reflux of drilling fluid leaving the formation.
Managed pressure drilling and/or managed volumetric drilling may be used during formation of wellbores. The back pressure on the wellbore may be held to a prescribed value to control the down hole pressure. Similarly, the volume of fluid entering and exiting the well may be balanced so that there is no net influx or out-flux of drilling fluid into the formation.
In some embodiments, one piece of equipment may be used to drill multiple wellbores in a single day. The wellbores may be formed at penetration rates that are many times faster than the penetration rates using conventional drilling with drilling bits. The high penetration rate allows separate equipment to accomplish drilling and casing operations in a more efficient manner than using a one-trip approach. The high penetration rate requires accurate, real time directional drilling in three dimensions.
In some embodiments, high penetration rates may be attained using composite coiled tubing in combination with particle jet drilling. Particle jet drilling forms an opening in a formation by impacting the formation with high pressure fluid containing particles to remove material from the formation. The particles may function as abrasives. In addition to composite coiled tubing and particle jet drilling, a downhole electric orienter, bubble entrained mud, downhole inertial navigation, and a computer control system may be needed. Other types of drilling fluid and drilling fluid systems may be used instead of using bubble entrained mud. Such drilling fluid systems may include, but are not limited to, straight liquid circulation systems, multiphase circulation systems using liquid and gas, and/or foam circulation systems.
Composite coiled tubing has a fatigue life that is significantly greater than the fatigue life of coiled steel tubing. Composite coiled tubing is available from Airborne Composites BV (The Hague, The Netherlands). Composite coiled tubing can be used to form many boreholes in a formation. The composite coiled tubing may include integral power lines for providing electricity to downhole tools. The composite coiled tubing may include integral data lines for providing real time information regarding downhole conditions to the computer control system and for sending real time control information from the computer control system to the downhole equipment.
The coiled tubing may include an abrasion resistant outer sheath. The outer sheath may inhibit damage to the coiled tubing due to sliding experienced by the coiled tubing during deployment and retrieval. In some embodiments, the coiled tubing may be rotated during use in lieu of or in addition to having an abrasion resistant outer sheath to minimize uneven wear of the composite coiled tubing.
Particle jet drilling may advantageously allow for stepped changes in the drilling rate. Drill bits are no longer needed and downhole motors are eliminated. Particle jet drilling may decouple cutting formation to form the borehole from the bottom hole assembly. Decoupling cutting formation to form the borehole from the bottom hole assembly reduces the impact that variable formation properties (for example, formation dip, vugs, fractures and transition zones) have on wellbore trajectory. By decoupling cutting formation to form the borehole from the bottom hole assembly, directional drilling may be reduced to orienting one or more particle jet nozzles in appropriate directions. Additionally, particle jet drilling may be used to under ream one or more portions of a wellbore to form a larger diameter opening.
Particles may be introduced into a high pressure injection stream during particle jet drilling. The ability to achieve and circulate high particle laden fluid under high pressure may facilitate the successful use of particle jet drilling. One type of pump that may be used for particle jet drilling is a heavy duty piston membrane pump. Heavy duty piston membrane pumps may be available from ABEL GmbH & Co. KG (Buchen, Germany). Piston membrane pumps have been used for long term, continuous pumping of slurries containing high total solids in the mining and power industries. Piston membrane pumps are similar to triplex pumps used for drilling operations in the oil and gas industry except heavy duty preformed membranes separate the slurry from the hydraulic side of the pump. In this fashion, the solids laden fluid is brought up to pressure in the injection line in one step and circulated downhole without damaging the internal mechanisms of the pump.
Another type of pump that may be used for particle jet drilling is an annular pressure exchange pump. Annular pressure exchange pumps may be available from Macmahon Mining Services Pty Ltd (Lonsdale, Australia). Annular pressure exchange pumps have been used for long term, continuous pumping of slurries containing high total solids in the mining industry. Annular pressure exchange pumps use hydraulic oil to compress a hose inside a high-strength pressure chamber in a peristaltic like way to displace the contents of the hose. Annular pressure exchange pumps may obtain continuous flow by having twin chambers. One chamber fills while the other chamber is purged.
The bottom hole assembly may include a downhole electric orienter. The downhole electric orienter may allow for directional drilling by directing one or more particle jet drilling nozzles in desired directions. The downhole electric orienter may be coupled to a computer control system through one or more integral data lines of the composite coiled tubing. Power for the downhole electric orienter may be supplied through an integral power line of the composite coiled tubing or through a battery system in the bottom hole assembly.
Bubble entrained mud may be used as the drilling fluid. Bubble entrained mud may allow for particle jet drilling without raising the equivalent circulating density to unacceptable levels. A form of managed pressure drilling may be affected by varying the density of bubble entrainment. In some embodiments, particles in the drilling fluid may be separated from the drilling fluid using magnetic recovery when the particles include iron or alloys that may be influenced by magnetic fields. Bubble entrained mud may be used because using air or other gas as the drilling fluid may result in excessive wear of components from high velocity particles in the return stream: The density of the bubble entrained mud going downhole as a function of real time gains and losses of fluid may be automated using the computer control system.
In some embodiments, multiphase systems are used. For example, if gas injection rates are low enough that wear rates are acceptable, a gas-liquid circulating system may be used. Bottom hole circulating pressures may be adjusted by the computer control system. The computer control system may adjust the gas and/or liquid injection rates.
In some embodiments, pipe-in-pipe drilling is used. Pipe-in-pipe drilling may include circulating fluid through the space between the outer pipe and the inner pipe instead of between the wellbore and the drill string. Pipe-in-pipe drilling may be used if contact of the drilling fluid with one or more fresh water aquifers is not acceptable. Pipe-in-pipe drilling may be used if the density of the drilling fluid cannot be adjusted low enough to effectively reduce potential lost circulation issues.
Downhole inertial navigation may be part of the bottom hole assembly. The use of downhole inertial navigation allows for determination of the position (including depth, azimuth and inclination) without magnetic sensors. Magnetic interference from casings and/or emissions from the high density of wells in the formation may interfere with a system that determines the position of the bottom hole assembly based on magnet sensors.
The computer control system may receive information from the bottom hole assembly. The computer control system may process the information to determine the position of the bottom hole assembly. The computer control system may control drilling fluid rate, drilling fluid density, drilling fluid pressure, particle density, other variables, and/or the downhole electric orienter to control the rate of penetration and/or the direction of borehole formation.
In some embodiments, robots are used to perform a task in a wellbore formed or being formed using composite coiled tubing. The task may be, but is not limited to, providing traction to move the coiled tubing, surveying, removing cuttings, logging, and/or freeing pipe. For example, a robot may be used when drilling a horizontal opening if enough weight cannot be applied to bottom hole assembly to advance the coiled tubing and bottom hole assembly in the formed borehole. The robot may be sent down the borehole. The robot may clamp to the composite coiled tubing. Portions of the robot may extend to engage the formation. Traction between the robot and the formation may be used to advance the robot forward so that the composite coiled tubing and the bottom hole assembly advance forward.
The robots may be battery powered. To use the robot, drilling could be stopped, and the robot could be connected to the outside of the composite coiled tubing. The robot would run along the outside of the composite coiled tubing to the bottom of the hole. If needed, the robot could electrically couple to the bottom hole assembly. The robot could couple to a contact plate on the bottom hole assembly. The bottom hole assembly may include a step-down transformer that brings the high voltage, low current electricity supplied to the bottom hole assembly to a lower voltage and higher current (for example, one third the voltage and three times the amperage supplied to the bottom hole assembly). The lower voltage, higher current electricity supplied from the step-down transformer may be used to recharge the batteries of the robot. In some embodiments, the robot may function while coupled to the bottom hole assembly. The batteries may supply sufficient energy for the robot to travel to the drill bit and back to the surface.
In some embodiments, one or more portions of a wellbore may need to be isolated from other portions of the wellbore to establish zonal isolation. In some embodiments, an expandable may be positioned in the wellbore adjacent to a section of the wellbore that is to be isolated. A pig or hydraulic pressure may be used to enlarge the expandable to establish zonal isolation.
In some embodiments, pathways may be formed in the formation after the wellbores are formed. Pathways may be formed adjacent to heater wellbores and/or adjacent to production wellbores. The pathways may promote better fluid flow and/or better heat conduction. In some embodiments, pathways are formed by hydraulically fracturing the formation. Other fracturing techniques may also be used. In some embodiments, small diameter bores may be formed in the formation. In some embodiments, heating the formation may expand and close or substantially close the fractures or bores formed in the formation. The fractures or holes may extend when the formation is heated. The presence of fractures of holes may increase heat conduction in the formation.
Some wellbores formed in the formation may be used to facilitate formation of a perimeter barrier around a treatment area. Heat sources in the treatment area may heat hydrocarbons in the formation within the treatment area. The perimeter barrier may be, but is not limited to, a low temperature or frozen barrier formed by freeze wells, dewatering wells, a grout wall formed in the formation, a sulfur cement barrier, a barrier formed by a gel produced in the formation, a barrier formed by precipitation of salts in the formation, a barrier formed by a polymerization reaction in the formation, and/or sheets driven into the formation. Heat sources, production wells, injection wells, dewatering wells, and/or monitoring wells may be installed in the treatment area defined by the barrier prior to, simultaneously with, or after installation of the barrier.
A low temperature zone around at least a portion of a treatment area may be formed by freeze wells. In an embodiment, refrigerant is circulated through freeze wells to form low temperature zones around each freeze well. The freeze wells are placed in the formation so that the low temperature zones overlap and form a low temperature zone around the treatment area. The low temperature zone established by freeze wells is maintained below the freezing temperature of aqueous fluid in the formation. Aqueous fluid entering the low temperature zone freezes and forms the frozen barrier. In other embodiments, the freeze barrier is formed by batch operated freeze wells. A cold fluid, such as liquid nitrogen, is introduced into the freeze wells to form low temperature zones around the freeze wells. The fluid is replenished as needed.
In some embodiments, two or more rows of freeze wells are located about all or a portion of the perimeter of the treatment area to form a thick interconnected low temperature zone. Thick low temperature zones may be formed adjacent to areas in the formation where there is a high flow rate of aqueous fluid in the formation. The thick barrier may ensure that breakthrough of the frozen barrier established by the freeze wells does not occur.
In some embodiments, a double barrier system is used to isolate a treatment area. The double barrier system may be formed with a first barrier and a second barrier. The first barrier may be formed around at least a portion of the treatment area to inhibit fluid from entering or exiting the treatment area. The second barrier may be formed around at least a portion of the first barrier to isolate an inter-barrier zone between the first barrier and the second barrier. The inter-barrier zone may have a thickness from about 1 m to about 300 m. In some embodiments, the thickness of the inter-barrier zone is from about 10 m to about 100 m, or from about 20 m to about 50 m.
The double barrier system may allow greater project depths than a single barrier system. Greater depths are possible with the double barrier system because the stepped differential pressures across the first barrier and the second barrier is less than the differential pressure across a single barrier. The smaller differential pressures across the first barrier and the second barrier make a breach of the double barrier system less likely to occur at depth for the double barrier system as compared to the single barrier system.
The double barrier system reduces the probability that a barrier breach will affect the treatment area or the formation on the outside of the double barrier. That is, the probability that the location and/or time of occurrence of the breach in the first barrier will coincide with the location and/or time of occurrence of the breach in the second barrier is low, especially if the distance between the first barrier and the second barrier is relatively large (for example, greater than about 15 m). Having a double barrier may reduce or eliminate influx of fluid into the treatment area following a breach of the first barrier or the second barrier. The treatment area may not be affected if the second barrier breaches. If the first barrier breaches, only a portion of the fluid in the inter-barrier zone is able to enter the contained zone. Also, fluid from the contained zone will not pass the second barrier. Recovery from a breach of a barrier of the double barrier system may require less time and fewer resources than recovery from a breach of a single barrier system. For example, reheating a treatment area zone following a breach of a double barrier system may require less energy than reheating a similarly sized treatment area zone following a breach of a single barrier system.
The first barrier and the second barrier may be the same type of barrier or different types of barriers. In some embodiments, the first barrier and the second barrier are formed by freeze wells. In some embodiments, the first barrier is formed by freeze wells, and the second barrier is a grout wall. The grout wall may be formed of cement, sulfur, sulfur cement, or combinations thereof. In some embodiments, a portion of the first barrier and/or a portion of the second barrier is a natural barrier, such as an impermeable rock formation.
Vertically positioned freeze wells and/or horizontally positioned freeze wells may be positioned around sides of the treatment area. If the upper layer (the overburden) or the lower layer (the underburden) of the formation is likely to allow fluid flow into the treatment area or out of the treatment area, horizontally positioned freeze wells may be used to form an upper and/or a lower barrier for the treatment area. In some embodiments, an upper barrier and/or a lower barrier may not be necessary if the upper layer and/or the lower layer are at least substantially impermeable. If the upper freeze barrier is formed, portions of heat sources, production wells, injection wells, and/or dewatering wells that pass through the low temperature zone created by the freeze wells forming the upper freeze barrier wells may be insulated and/or heat traced so that the low temperature zone does not adversely affect the functioning of the heat sources, production wells, injection wells and/or dewatering wells passing through the low temperature zone.
Spacing between adjacent freeze wells may be a function of a number of different factors. The factors may include, but are not limited to, physical properties of formation material, type of refrigeration system, coldness and thermal properties of the refrigerant, flow rate of material into or out of the treatment area, time for forming the low temperature zone, and economic considerations. Consolidated or partially consolidated formation material may allow for a large separation distance between freeze wells. A separation distance between freeze wells in consolidated or partially consolidated formation material may be from about 3 m to about 20 m, about 4 m to about 15 m, or about 5 m to about 10 m. In an embodiment, the spacing between adjacent freeze wells is about 5 m. Spacing between freeze wells in unconsolidated or substantially unconsolidated formation material, such as in tar sand, may need to be smaller than spacing in consolidated formation material. A separation distance between freeze wells in unconsolidated material may be from about 1 m to about 5 m.
Freeze wells may be placed in the formation so that there is minimal deviation in orientation of one freeze well relative to an adjacent freeze well. Excessive deviation may create a large separation distance between adjacent freeze wells that may not permit formation of an interconnected low temperature zone between the adjacent freeze wells. Factors that influence the manner in which freeze wells are inserted into the ground include, but are not limited to, freeze well insertion time, depth that the freeze wells are to be inserted, formation properties, desired well orientation, and economics.
Relatively low depth wellbores for freeze wells may be impacted and/or vibrationally inserted into some formations. Wellbores for freeze wells may be impacted and/or vibrationally inserted into formations to depths from about 1 m to about 100 m without excessive deviation in orientation of freeze wells relative to adjacent freeze wells in some types of formations.
Wellbores for freeze wells placed deep in the formation, or wellbores for freeze wells placed in formations with layers that are difficult to impact or vibrate a well through, may be placed in the formation by directional drilling and/or geosteering. Acoustic signals, electrical signals, magnetic signals, and/or other signals produced in a first wellbore may be used to guide directionally drilling of adjacent wellbores so that desired spacing between adjacent wells is maintained. Tight control of the spacing between wellbores for freeze wells is an important factor in minimizing the time for completion of barrier formation.
In some embodiments, one or more portions of freeze wells may be angled in the formation. The freeze wells may be angled in the formation adjacent to aquifers. In some embodiments, the angled portions are angled outwards from the treatment area. In some embodiments, the angled portions may be angled inwards towards the treatment area. The angled portions of the freeze wells allow extra length of freeze well to be positioned in the aquifer zones. Also, the angled portions of the freeze wells may reduce the shear load applied to the frozen barrier by water flowing in the aquifer.
After formation of the wellbore for the freeze well, the wellbore may be backflushed with water adjacent to the part of the formation that is to be reduced in temperature to form a portion of the freeze barrier. The water may displace drilling fluid remaining in the wellbore. The water may displace indigenous gas in cavities adjacent to the formation. In some embodiments, the wellbore is filled with water from a conduit up to the level of the overburden. In some embodiments, the wellbore is backflushed with water in sections. The wellbore maybe treated in sections having lengths of about 6 m, 10 m, 14 m, 17 m, or greater. Pressure of the water in the wellbore is maintained below the fracture pressure of the formation. In some embodiments, the water, or a portion of the water is removed from the wellbore, and a freeze well is placed in the formation.
Formation refrigerant may flow through cold side conduit 454 from a refrigeration unit to inlet conduit 444 of freeze well 440. The formation refrigerant may flow through an annular space between inlet conduit 444 and canister 442 to warm side conduit 456. Heat may transfer from the formation to canister 442 and from the canister to the formation refrigerant in the annular space. Inlet conduit 444 may be insulated to inhibit heat transfer to the formation refrigerant during passage of the formation refrigerant into freeze well 440. In an embodiment, inlet conduit 444 is a high density polyethylene tube. At cold temperatures, some polymers may exhibit a large amount of thermal contraction. For example, a 260 m initial length of polyethylene conduit subjected to a temperature of about −25° C. may contract by 6 m or more. If a high density polyethylene conduit, or other polymer conduit, is used, the large thermal contraction of the material must be taken into account in determining the final depth of the freeze well. For example, the freeze well may be drilled deeper than needed, and the conduit may be allowed to shrink back during use. In some embodiments, inlet conduit 444 is an insulated metal tube. In some embodiments, the insulation may be a polymer coating, such as, but not limited to, polyvinylchloride, high density polyethylene, and/or polystyrene.
Freeze well 440 may be introduced into the formation using a coiled tubing rig. In an embodiment, canister 442 and inlet conduit 444 are wound on a single reel. The coiled tubing rig introduces the canister and inlet conduit 444 into the formation. In an embodiment, canister 442 is wound on a first reel and inlet conduit 444 is wound on a second reel. The coiled tubing rig introduces canister 442 into the formation. Then, the coiled tubing rig is used to introduce inlet conduit 444 into the canister. In other embodiments, freeze well is assembled in sections at the wellbore site and introduced into the formation.
An insulated section of freeze well 440 may be placed adjacent to overburden 458. An uninsulated section of freeze well 440 may be placed adjacent to layer or layers 460 where a low temperature zone is to be formed. In some embodiments, uninsulated sections of the freeze wells may be positioned adjacent only to aquifers or other permeable portions of the formation that would allow fluid to flow into or out of the treatment area. Portions of the formation where uninsulated sections of the freeze wells are to be placed may be determined using analysis of cores and/or logging techniques.
Inlet conduit 444 may include plastic portion 2394, transition piece 2396, outer sleeve 2398, and inner sleeve 2400. Plastic portion 2394 may be a plastic conduit that carries refrigerant into freeze well 440. In some embodiments, plastic portion 2394 is high density polyethylene pipe.
Transition piece 2396 may be a transition between plastic portion 2394 and outer sleeve 2398. A plastic end of transition piece 2396 may be fusion welded to the end of plastic portion 2394. A metal portion of transition piece may be butt welded to outer sleeve 2398. In some embodiments, the metal portion and outer sleeve 2398 are formed of 304 stainless steel. Other material may be used in other embodiments. Transition pieces 2396 may be available from Central Plastics Company (Shawnee, Okla.).
In some embodiments, outer sleeve 2398 may include stop 2402. Stop 2402 may engage a stop of inner sleeve 2400 to limit a bottom position of the outer sleeve relative to the inner sleeve. In some embodiments, outer sleeve 2398 may include opening 2404. Opening 2404 may align with a corresponding opening in inner sleeve 2400. A shear pin may be positioned in the openings during insertion of inlet conduit 444 in canister 442 to inhibit movement of outer sleeve 2398 relative to inner sleeve 2400. Shear pin is strong enough to support the weight of inner sleeve 2400, but weak enough to shear due to force applied to the shear pin when outer sleeve 2398 moves upwards in the wellbore due to thermal contraction or during installation of the inlet conduit after inlet conduit is coupled to canister 442.
Inner sleeve 2400 may be positioned in outer sleeve 2398. Inner sleeve has a length sufficient to inhibit separation of the inner sleeve from outer sleeve 2398 when inlet conduit has fully contracted due to exposure of the inlet conduit to low temperature refrigerant. Inner sleeve 2400 may include a plurality of slip rings 2406 held in place by positioners 2408, a plurality of openings 2410, stop 2412, and latch 2414. Slip rings 2406 may position inner sleeve 2400 relative to outer sleeve 2398 and allow the outer sleeve to move relative to the inner sleeve. In some embodiments, slip rings 2406 are TEFLON® rings, such as polytetrafluoroethylene rings. Slip rings 2406 may be made of different material in other embodiments. Positioners 2408 may be steel rings welded to inner sleeve. Positioners 2408 may be thinner than slip rings 2406. Positioners 2408 may inhibit movement of slip rings 2406 relative to inner sleeve 2400.
Openings 2410 may be formed in a portion of inner sleeve 2400 near the bottom of the inner sleeve. Openings 2410 may allow refrigerant to pass from inlet conduit 444 to canister 442. A majority of refrigerant flowing through inlet conduit 444 may pass through openings 2410 to canister 442. Some refrigerant flowing through inlet conduit 444 may pass to canister 442 through the space between inner sleeve 2400 and outer sleeve 2398.
Stop 2412 may be located above openings 2410. Stop 2412 interacts with stop 2402 of outer sleeve 2398 to limit the downward movement of the outer sleeve relative to inner sleeve 2400.
Latch 2414 may be welded to the bottom of inner sleeve 2400. Latch 2414 may include flared opening 2416 that engages tapered end 2390 of latch pin 2388. Latch 2414 may include spring ring 2418 that snaps into groove of latch pin 2392 to couple inlet conduit 444 to canister 442.
To install freeze well 440, a wellbore is formed in the formation and canister 442 is placed in the wellbore. The bottom of canister 442 has latch pin 2388. Transition piece is fusion welded to an end of coiled plastic portion 2394 of inlet conduit 444. Latch 2414 is placed in canister 442 and inlet conduit is spooled into the canister. Spacers may be coupled to plastic portion 2394 at selected positions. Latch may be lowered until flared opening 2416 engages tapered end 2390 of latch pin 2388 and spring ring 2406 snaps into the groove of the latch pin. After spring ring 2406 engages latch pin 2388, inlet conduit 444 may be moved upwards to shear the pin joining outer sleeve 2398 to inner sleeve 2400. Inlet conduit 444 may be coupled to the refrigerant supply piping and canister may be coupled to the refrigerant return piping.
If needed, inlet conduit 444 may be removed from canister 442. Inlet conduit may be pulled upwards to separate outer sleeve 2398 from inner sleeve 2400. Plastic portion 2394, transition piece 2396, and outer sleeve 2398 may be pulled out of canister 442. A removal instrument may be lowered into canister 442. The removal instrument may secure to inner sleeve 2400. The removal instrument may be pulled upwards to pull spring ring 2418 of latch 2414 out of groove 2392 of latch pin 2388. The removal tool may be withdrawn out of canister 442 to remove inner sleeve 2400 from the canister.
Various types of refrigeration systems may be used to form a low temperature zone. Determination of an appropriate refrigeration system may be based on many factors, including, but not limited to: a type of freeze well; a distance between adjacent freeze wells; a refrigerant; a time frame in which to form a low temperature zone; a depth of the low temperature zone; a temperature differential to which the refrigerant will be subjected; one or more chemical and/or physical properties of the refrigerant; one or more environmental concerns related to potential refrigerant releases, leaks or spills; one or more economic factors; water flow rate in the formation; composition and/or properties of formation water including the salinity of the formation water; and one or more properties of the formation such as thermal conductivity, thermal diffusivity, and heat capacity.
A circulated fluid refrigeration system may utilize a liquid refrigerant (formation refrigerant) that is circulated through freeze wells. Some of the desired properties for the formation refrigerant are: low working temperature, low viscosity at and near the working temperature, high density, high specific heat capacity, high thermal conductivity, low cost, low corrosiveness, and low toxicity. A low working temperature of the formation refrigerant allows a large low temperature zone to be established around a freeze well. The low working temperature of formation refrigerant should be about −20° C. or lower. Formation refrigerants having low working temperatures of at least −60° C. may include aqua ammonia, potassium formate solutions such as Dynalene® HC-50 (Dynalene® Heat Transfer Fluids (Whitehall, Pa., U.S.A.)) or FREEZIUM® (Kemira Chemicals (Helsinki, Finland)); silicone heat transfer fluids such as Syltherm XLT® (Dow Corning Corporation (Midland, Mich., U.S.A.); hydrocarbon refrigerants such as propylene; and chlorofluorocarbons such as R-22. Aqua ammonia is a solution of ammonia and water with a weight percent of ammonia between about 20% and about 40%. Aqua ammonia has several properties and characteristics that make use of aqua ammonia as the formation refrigerant desirable. Such properties and characteristics include, but are not limited to, a very low freezing point, a low viscosity, ready availability, and low cost.
Formation refrigerant that is capable of being chilled below a freezing temperature of aqueous formation fluid may be used to form the low temperature zone around the treatment area. The following equation (the Sanger equation) may be used to model the time t1 needed to form a frozen barrier of radius R around a freeze well having a surface temperature of Ts:
In these equations, kf is the thermal conductivity of the frozen material; cvf and cvu are the volumetric heat capacity of the frozen and unfrozen material, respectively; ro is the radius of the freeze well; vs is the temperature difference between the freeze well surface temperature Ts and the freezing point of water To; vo is the temperature difference between the ambient ground temperature Tg and the freezing point of water To; L is the volumetric latent heat of freezing of the formation; R is the radius at the frozen-unfrozen interface; and RA is a radius at which there is no influence from the refrigeration pipe. The Sanger equation may provide a conservative estimate of the time needed to form a frozen barrier of radius R because the equation does not take into consideration superposition of cooling from other freeze wells. The temperature of the formation refrigerant is an adjustable variable that may significantly affect the spacing between freeze wells.
EQN. 1 implies that a large low temperature zone may be formed by using a refrigerant having an initial temperature that is very low. The use of formation refrigerant having an initial cold temperature of about −30° C. or lower is desirable. Formation refrigerants having initial temperatures warmer than about −30° C. may also be used, but such formation refrigerants require longer times for the low temperature zones produced by individual freeze wells to connect. In addition, such formation refrigerants may require the use of closer freeze well spacings and/or more freeze wells.
The physical properties of the material used to construct the freeze wells may be a factor in the determination of the coldest temperature of the formation refrigerant used to form the low temperature zone around the treatment area. Carbon steel may be used as a construction material of freeze wells. ASTM A333 grade 6 steel alloys and ASTM A333 grade 3 steel alloys may be used for low temperature applications. ASTM A333 grade 6 steel alloys typically contain little or no nickel and have a low working temperature limit of about −50° C. ASTM A333 grade 3 steel alloys typically contain nickel and have a much colder low working temperature limit. The nickel in the ASTM A333 grade 3 alloy adds ductility at cold temperatures, but also significantly raises the cost of the metal. In some embodiments, the coldest temperature of the refrigerant is from about −35° C. to about −55° C., from about −38° C. to about −47° C., or from about −40° C. to about −45° C. to allow for the use of ASTM A333 grade 6 steel alloys for construction of canisters for freeze wells. Stainless steels, such as 304 stainless steel, may be used to form freeze wells, but the cost of stainless steel is typically much more than the cost of ASTM A333 grade 6 steel alloy.
In some embodiments, the metal used to form the canisters of the freeze wells may be provided as pipe. In some embodiments, the metal used to form the canisters of the freeze wells may be provided in sheet form. The sheet metal may be longitudinally welded to form pipe and/or coiled tubing. Forming the canisters from sheet metal may improve the economics of the system by allowing for coiled tubing insulation and by reducing the equipment and manpower needed to form and install the canisters using pipe.
A refrigeration unit may be used to reduce the temperature of formation refrigerant to the low working temperature. In some embodiments, the refrigeration unit may utilize an ammonia vaporization cycle. Refrigeration units are available from Cool Man Inc. (Milwaukee, Wis., U.S.A.), Gartner Refrigeration & Manufacturing (Minneapolis, Minn., U.S.A.), and other suppliers. In some embodiments, a cascading refrigeration system may be utilized with a first stage of ammonia and a second stage of carbon dioxide. The circulating refrigerant through the freeze wells may be 30% by weight ammonia in water (aqua ammonia). Alternatively, a single stage carbon dioxide refrigeration system may be used.
In some embodiments, refrigeration systems for forming a low temperature barrier for a treatment area may be installed and activated before freeze wells are formed in the formation. As the freeze well wellbores are formed, freeze wells may be installed in the wellbores. Refrigerant may be circulated through the wellbores soon after the freeze well is installed into the wellbore. Limiting the time between wellbore formation and cooling initiation may limit or inhibit cross mixing of formation water between different aquifers.
Grout, wax, polymer or other material may be used in combination with freeze wells to provide a barrier for the in situ heat treatment process. The material may fill cavities (vugs) in the formation and reduces the permeability of the formation. The material may have higher thermal conductivity than gas and/or formation fluid that fills cavities in the formation. Placing material in the cavities may allow for faster low temperature zone formation. The material may form a perpetual barrier in the formation that may strengthen the formation. The use of material to form the barrier in unconsolidated or substantially unconsolidated formation material may allow for larger well spacing than is possible without the use of the material. The combination of the material and the low temperature zone formed by freeze wells may constitute a double barrier for environmental regulation purposes. In some embodiments, the material is introduced into the formation as a liquid, and the liquid sets in the formation to form a solid. The material may be, but is not limited to, fine cement, micro fine cement, sulfur, sulfur cement, viscous thermoplastics, and/or waxes. The material may include surfactants, stabilizers or other chemicals that modify the properties of the material. For example, the presence of surfactant in the material may promote entry of the material into small openings in the formation.
Material may be introduced into the formation through freeze well wellbores. The material may be allowed to set. The integrity of the wall formed by the material may be checked. The integrity of the material wall may be checked by logging techniques and/or by hydrostatic testing. If the permeability of a section formed by the material is too high, additional material grout may be introduced into the formation through freeze well wellbores. After the permeability of the section is sufficiently reduced, freeze wells may be installed in the freeze well wellbores.
Material may be injected into the formation at a pressure that is high, but below the fracture pressure of the formation. In some embodiments, injection of material is performed in 16 m increments in the freeze wellbore. Larger or smaller increments may be used if desired. In some embodiments, material is only applied to certain portions of the formation. For example, material may be applied to the formation through the freeze wellbore only adjacent to aquifer zones and/or to relatively high permeability zones (for example, zones with a permeability greater than about 0.1 darcy). Applying material to aquifers may inhibit migration of water from one aquifer to a different aquifer. For material placed in the formation through freeze well wellbores, the material may inhibit water migration between aquifers during formation of the low temperature zone. The material may also inhibit water migration between aquifers when an established low temperature zone is allowed to thaw.
In some embodiments, the material used to form a barrier may be fine cement and micro fine cement. Cement may provide structural support in the formation. Fine cement may be ASTM type 3 Portland cement. Fine cement may be less expensive than micro fine cement. In an embodiment, a freeze wellbore is formed in the formation. Selected portions of the freeze wellbore are grouted using fine cement. Then, micro fine cement is injected into the formation through the freeze wellbore. The fine cement may reduce the permeability down to about 10 millidarcy. The micro fine cement may further reduce the permeability to about 0.1 millidarcy. After the grout is introduced into the formation, a freeze wellbore canister may be inserted into the formation. The process may be repeated for each freeze well that will be used to form the barrier.
In some embodiments, fine cement is introduced into every other freeze wellbore. Micro fine cement is introduced into the remaining wellbores. For example, grout may be used in a formation with freeze wellbores set at about 5 m spacing. A first wellbore is drilled and fine cement is introduced into the formation through the wellbore. A freeze well canister is positioned in the first wellbore. A second wellbore is drilled 10 m away from the first wellbore. Fine cement is introduced into the formation through the second wellbore. A freeze well canister is positioned in the second wellbore. A third wellbore is drilled between the first wellbore and the second wellbore. In some embodiments, grout from the first and/or second wellbores may be detected in the cuttings of the third wellbore. Micro fine cement is introduced into the formation through the third wellbore. A freeze wellbore canister is positioned in the third wellbore. The same procedure is used to form the remaining freeze wells that will form the barrier around the treatment area.
In some embodiments, material including wax is used to form a barrier in a formation. Wax barriers may be formed in wet, dry, or oil wetted formations. Wax barriers may be formed above, at the bottom of, and/or below the water table. Material including liquid wax introduced into the formation may permeate into adjacent rock and fractures in the formation. The material may permeate into rock to fill microscopic as well as macroscopic pores and vugs in the rock. The wax solidifies to form a barrier that inhibits fluid flow into or out of a treatment area. A wax barrier may provide a minimal amount of structural support in the formation. Molten wax may reduce the strength of poorly consolidated soil by reducing inter-grain friction so that the poorly consolidated soil sloughs or liquefies. Poorly consolidated layers may be consolidated by use of cement or other binding agents before introduction of molten wax.
In some embodiments, the formation where a wax barrier is to be established is dewatered before and/or during formation of the wax barrier. In some embodiments, the portion of the formation where the wax barrier is to form is dewatered or diluted to remove or reduce saline water that could adversely affect the properties of the material introduced into the formation to form the wax barrier.
In some embodiments, water is introduced into the formation during formation of the wax barrier. Water may be introduced into the formation when the barrier is to be formed below the water table or in a dry portion of the formation. The water may be used to heat the formation to a desired temperature before introducing the material that forms the wax barrier. The water may be introduced at an elevated temperature and/or the water may be heated in the formation from one or more heaters.
The wax of the barrier may be a branched paraffin to inhibit biological degradation of the wax. The wax may include stabilizers, surfactants or other chemicals that modify the physical and/or chemical properties of the wax. The physical properties may be tailored to meet specific needs. The wax may melt at a relative low temperature (for example, the wax may have a typical melting point of about 52° C.). The temperature at which the wax congeals may be at least 5° C., 10° C., 20° C., or 30° C. above the ambient temperature of the formation prior to any heating of the formation. When molten, the wax may have a relatively low viscosity (for example, 4 to 10 cp at about 99° C.). The flash point of the wax may be relatively high (for example, the flash point may be over 204° C.). The wax may have a density less than the density of water and may have a heat capacity that is less than half the heat capacity of water. The solid wax may have a low thermal conductivity (for example, about 0.18 W/m ° C.) so that the solid wax is a thermal insulator. Waxes suitable for forming a barrier are available as WAXFIX™ from Carter Technologies Company (Sugar Land, Tex., U.S.A.). WAXFIX™ is very resistant to microbial attack. WAXFIX™ may have a half life of greater than 5000 years.
In some embodiments, a wax barrier or wax barriers may be used as the barriers for the in situ heat treatment process. In some embodiments, a wax barrier may be used in conjunction with freeze wells that form a low temperature barrier around the treatment area. In some embodiments, the wax barrier is formed and freeze wells are installed in the wellbores used for introducing wax into the formation. In some embodiments, the wax barrier is formed in wellbores offset from the freeze well wellbores. The wax barrier may be on the outside or the inside of the freeze wells. In some embodiments, a wax barrier may be formed on both the inside and outside of the freeze wells. The wax barrier may inhibit water flow in the formation that would inhibit the formation of the low temperature zone by the freeze wells. In some embodiments, a wax barrier is formed in the inter-barrier zone between two freeze barriers of a double barrier system.
Material used to form the wax barrier may be introduced into the formation through wellbores. The wellbores may include vertical wellbores, slanted wellbores, and/or horizontal wellbores (for example, wellbores with sections that are horizontally or near horizontally oriented). The use of vertical wellbores, slanted wellbores, and/or horizontal wellbores for forming the wax barrier allows the formation of a barrier that seals both horizontal and vertical fractures.
Wellbores may be formed in the formation around the treatment area at a close spacing. In some embodiments, the spacing is from about 1.5 m to about 4 m. Larger or smaller spacings may be used. Low temperature heaters may be inserted in the wellbores. The heaters may operate at temperatures from about 260° C. to about 320° C. so that the temperature at the formation face is below the pyrolysis temperature of hydrocarbons in the formation. The heaters may be activated to heat the formation until the overlap between two adjacent heaters raises the temperature of the zone between the two heaters above the melting temperature of the wax. Heating the formation to obtain superposition of heat with a temperature above the melting temperature of the wax may take one month, two months, or longer. After heating, the heaters may be turned off. In some embodiments, the heaters are downhole antennas that operate at about 10 MHz to heat the formation.
After heating, the material used to form the wax barrier may be introduced into the wellbores to form the barrier. The material may flow into the formation and fill any fractures and porosity that has been heated. The wax in the material congeals when the wax flows to cold regions beyond the heated circumference. This wax barrier formation method may form a more complete barrier than some other methods of wax barrier formation, but the time for heating may be longer than for some of the other methods. Also, if a low temperature barrier is to be formed with the freeze wells placed in the wellbores used for injection of the material used to form the barrier, the freeze wells will have to remove the heat supplied to the formation to allow for introduction of the material used to form the barrier. The low temperature barrier may take longer to form.
In some embodiments, the wax barrier may be formed using a conduit placed in the wellbore.
Material in the annular space of wellbore 452 between conduit 464 and the formation may be removed through conduit by displacing the material with water or other fluid. Conduit 464 may be removed and a freeze well may be installed in the wellbore. This method may use less material than the method described above. The heating of the fluid may be accomplished in less than a week or within a day. The small amount of heat input may allow for quicker formation of a low temperature barrier if freeze wells are to be positioned in the wellbores used to introduce material into the formation.
In some embodiments, a heater may be suspended in the well without a conduit that allows for removal of excess material from the wellbore. The material may be introduced into the well. After material introduction, the heater may be removed from the well. In some embodiments, a conduit may be positioned in the wellbore, but a heater may not be coupled to the conduit. Hot material may be circulated through the conduit so that the wax enters fractures systems and/or vugs adjacent to the wellbore.
In some embodiments, material may be used during the formation of a wellbore to improve inter-zonal isolation and protect a low-pressure zone from inflow from a high-pressure zone. During wellbore formation where a high pressure zone and a low pressure zone are penetrated by a common wellbore, it is possible for fluid from the high pressure zone to flow into the low pressure zone and cause an underground blowout. To avoid this, the wellbore may be formed through the first zone. Then, an intermediate casing may be set and cemented through the first zone. Setting casing may be time consuming and expensive. Instead of setting a casing, material may be introduced to form a wax barrier that seals the first zone. The material may also inhibit or prevent mixing of high salinity brines from lower, high pressure zones with fresher brines in upper, lower pressure zones.
In some embodiments, a material including wax may be used to contain and inhibit migration in a subsurface formation that has liquid hydrocarbon contaminants (for example, compounds such as benzene, toluene, ethylbenzene and xylene) condensed in fractures in the formation. The location of the contaminants may be surrounded with heated injection wells. The material may be introduced into the wells to form an outer wax barrier. The material injected into the fractures from the injection wells may mix with the contaminants. The contaminants may be solubilized into the material. When the material congeals, the contaminants may be permanently contained in the solid wax phase of the material.
In some embodiments, a portion or all of the wax barrier may be removed after completion of the in situ heat treatment process. Removing all or a portion of the wax barrier may allow fluid to flow into and out of the treatment area of the in situ heat treatment process. Removing all or a portion of the wax barrier may return flow conditions in the formation to substantially the same conditions as existed before the in situ heat treatment process. To remove a portion or all of the wax barrier, heaters may be used to heat the formation adjacent to the wax barrier. In some embodiments, the heaters raise the temperature above the decomposition temperature of the material forming the wax barrier. In some embodiments, the heaters raise the temperature above the melting temperature of the material forming the wax barrier. Fluid (for example water) may be introduced into the formation to drive the molten material to one or more production wells positioned in the formation. The production wells may remove the material from the formation.
In some embodiments, a composition that includes a cross-linkable polymer may be used with or in addition to a material that includes wax to form the barrier. Such composition may be provided to the formation as is described above for the material that includes wax. The composition may be configured to react and solidify after a selected time in the formation, thereby allowing the composition to be provided as a liquid to the formation. The cross-linkable polymer may include, for example, acrylates, methacrylates, urethanes, and/or epoxies. A cross-linking initiator may be included in the composition. The composition may also include a cross-linking inhibitor. The cross-linking inhibitor may be configured to degrade while in the formation, thereby allowing the composition to solidify.
In situ heat treatment processes and solution mining processes may heat the treatment area, remove mass from the treatment area, and greatly increase the permeability of the treatment area. In certain embodiments, the treatment area after being treated may have a permeability of at least 0.1 darcy. In some embodiments, the treatment area after being treated has a permeability of at least 1 darcy, of at least 10 darcy, or of at least 100 darcy. The increased permeability allows the fluid to spread in the formation into fractures, microfractures, and/or pore spaces in the formation. Outside of the treatment area, the permeability may remain at the initial permeability of the formation. The increased permeability allows fluid introduced to flow easily within the formation.
In certain embodiments, a barrier may be formed in the formation after a solution mining process and/or an in situ heat treatment process by introducing a fluid into the formation. The barrier may inhibit formation fluid from entering the treatment area after the solution mining and/or in situ heat treatment processes have ended. The barrier formed by introducing fluid into the formation may allow for isolation of the treatment area.
The fluid introduced into the formation to form a barrier may include wax, bitumen, heavy oil, sulfur, polymer, gel, saturated saline solution, and/or one or more reactants that react to form a precipitate, solid or high viscosity fluid in the formation. In some embodiments, bitumen, heavy oil, reactants and/or sulfur used to form the barrier are obtained from treatment facilities associated with the in situ heat treatment process. For example, sulfur may be obtained from a Claus process used to treat produced gases to remove hydrogen sulfide and other sulfur compounds.
The fluid may be introduced into the formation as a liquid, vapor, or mixed phase fluid. The fluid may be introduced into a portion of the formation that is at an elevated temperature. In some embodiments, the fluid is introduced into the formation through wells located near a perimeter of the treatment area. The fluid may be directed away from the treatment area. The elevated temperature of the formation maintains or allows the fluid to have a low viscosity so that the fluid moves away from the wells. A portion of the fluid may spread outwards in the formation towards a cooler portion of the formation. The relatively high permeability of the formation allows fluid introduced from one wellbore to spread and mix with fluid introduced from other wellbores. In the cooler portion of the formation, the viscosity of the fluid increases, a portion of the fluid precipitates, and/or the fluid solidifies or thickens so that the fluid forms the barrier to flow of formation fluid into or out of the treatment area.
In some embodiments, a low temperature barrier formed by freeze wells surrounds all or a portion of the treatment area. As the fluid introduced into the formation approaches the low temperature barrier, the temperature of the formation becomes colder. The colder temperature increases the viscosity of the fluid, enhances precipitation, and/or solidifies the fluid to form the barrier to the flow of formation fluid into or out of the formation. The fluid may remain in the formation as a highly viscous fluid or a solid after the low temperature barrier has dissipated.
In certain embodiments, saturated saline solution is introduced into the formation. Components in the saturated saline solution may precipitate out of solution when the solution reaches a colder temperature. The solidified particles may form the barrier to the flow of formation fluid into or out of the formation. The solidified components may be substantially insoluble in formation fluid.
In certain embodiments, brine is introduced into the formation as a reactant. A second reactant, such as carbon dioxide, may be introduced into the formation to react with the brine. The reaction may generate a mineral complex that grows in the formation. The mineral complex may be substantially insoluble to formation fluid. In an embodiment, the brine solution includes a sodium and aluminum solution. The second reactant introduced in the formation is carbon dioxide. The carbon dioxide reacts with the brine solution to produce dawsonite. The minerals may solidify and form the barrier to the flow of formation fluid into or out of the formation.
In some embodiments, the barrier may be formed around a treatment area using sulfur. Advantageously, elemental sulfur is insoluble in water. Liquid and/or solid sulfur in the formation may form a barrier to formation fluid flow into or out of the treatment area.
A sulfur barrier may be established in the formation during or before initiation of heating to heat the treatment area of the in situ heat treatment process. In some embodiments, sulfur may be introduced into wellbores in the formation that are located between the treatment area and a first barrier (for example, a low temperature barrier established by freeze wells). The formation adjacent to the wellbores that the sulfur is introduced into may be dewatered. In some embodiments, the formation adjacent to the wellbores that the sulfur is introduced into is heated to facilitate removal of water and to prepare the wellbores and adjacent formation for the introduction of sulfur. The formation adjacent to the wellbores may be heated to a temperature below the pyrolysis temperature of hydrocarbons in the formation. The formation may be heated so that the temperature of a portion of the formation between two adjacent heaters is influenced by both heaters. In some embodiments, the heat may increase the permeability of the formation so that a first wellbore is in fluid communication with an adjacent wellbore.
After the formation adjacent to the wellbores is heated, molten sulfur at a temperature below the pyrolysis temperature of hydrocarbons in the formation is introduced into the formation. Over a certain temperature range, the viscosity of molten sulfur increases with increasing temperature. The molten sulfur introduced into the formation may be near the melting temperature of sulfur (about 115° C.) so that the sulfur has a relatively low viscosity (about 4-10 cp). Heaters in the wellbores may be temperature limited heaters with Curie temperatures near the melting temperature of sulfur so that the temperature of the molten sulfur stays relatively constant and below temperatures resulting in the formation of viscous molten sulfur. In some embodiments, the region adjacent to the wellbores may be heated to a temperature above the melting point of sulfur, but below the pyrolysis temperature of hydrocarbons in the formation. The heaters may be turned off and the temperature in the wellbores may be monitored (for example, using a fiber optic temperature monitoring system). When the temperature in the wellbore cools to a temperature near the melting temperature of sulfur, molten sulfur may be introduced into the formation.
The sulfur introduced into the formation is allowed to flow and diffuse into the formation from the wellbores. As the sulfur enters portions of the formation below the melting temperature, the sulfur solidifies and forms a barrier to fluid flow in the formation. Sulfur may be introduced until the formation is not able to accept additional sulfur. Heating may be stopped, and the formation may be allowed to naturally cool so that the sulfur in the formation solidifies. After introduction of the sulfur, the integrity of the formed barrier may be tested using pulse tests and/or tracer tests.
A barrier may be formed around the treatment area after the in situ heat treatment process. The sulfur may form a substantially permanent barrier in the formation. In some embodiments, a low temperature barrier formed by freeze wells surrounds the treatment area. Sulfur may be introduced on one or both sides of the low temperature barrier to form a barrier in the formation. The sulfur may be introduced into the formation as vapor or a liquid. As the sulfur approaches the low temperature barrier, the sulfur may condense and/or solidify in the formation to form the barrier.
In some embodiments, the sulfur may be introduced in the heated portion of the portion. The sulfur may be introduced into the formation through wells located near the perimeter of the treatment area. The temperature of the formation may be hotter than the vaporization temperature of sulfur (about 445° C.). The sulfur may be introduced as a liquid, vapor or mixed phase fluid. If a part of the introduced sulfur is in the liquid phase, the heat of the formation may vaporize the sulfur. The sulfur may flow outwards from the introduction wells towards cooler portions of the formation. The sulfur may condense and/or solidify in the formation to form the barrier.
In some embodiments, the Claus reaction may be used to form sulfur in the formation after the in situ heat treatment process. The Claus reaction is a gas phase equilibrium reaction. The Claus reaction is:
4H2S+2SO23S2+4H2O (EQN.2)
Hydrogen sulfide may be obtained by separating the hydrogen sulfide from the produced fluid of an ongoing in situ heat treatment process. A portion of the hydrogen sulfide may be burned to form the needed sulfur dioxide. Hydrogen sulfide may be introduced into the formation through a number of wells in the formation. Sulfur dioxide may be introduced into the formation through other wells. The wells used for injecting sulfur dioxide or hydrogen sulfide may have been production wells, heater wells, monitor wells or other type of well during the in situ heat treatment process. The wells used for injecting sulfur dioxide or hydrogen sulfide may be near the perimeter of the treatment area. The number of wells may be enough so that the formation in the vicinity of the injection wells does not cool to a point where the sulfur dioxide and the hydrogen sulfide can form sulfur and condense, rather than remain in the vapor phase. The wells used to introduce the sulfur dioxide into the formation may also be near the perimeter of the treatment area. In some embodiments, the hydrogen sulfide and sulfur dioxide may be introduced into the formation through the same wells (for example, through two conduits positioned in the same wellbore). The hydrogen sulfide and the sulfur dioxide may react in the formation to form sulfur and water. The sulfur may flow outwards in the formation and condense and/or solidify to form the barrier in the formation.
The sulfur barrier may form in the formation beyond the area where hydrocarbons in formation fluid generated by the heat treatment process condense in the formation. Regions near the perimeter of the treated area may be at lower temperatures than the treated area. Sulfur may condense and/or solidify from the vapor phase in these lower temperature regions. Additional hydrogen sulfide, and/or sulfur dioxide may diffuse to these lower temperature regions. Additional sulfur may form by the Claus reaction to maintain an equilibrium concentration of sulfur in the vapor phase. Eventually, a sulfur barrier may form around the treated zone. The vapor phase in the treated region may remain as an equilibrium mixture of sulfur, hydrogen sulfide, sulfur dioxide, water vapor and other vapor products present or evolving from the formation.
The conversion to sulfur is favored at lower temperatures, so the conversion of hydrogen sulfide and sulfur dioxide to sulfur may take place a distance away from the wells that introduce the reactants into the formation. The Claus reaction may result in the formation of sulfur where the temperature of the formation is cooler (for example where the temperature of the formation is at temperatures from about 180° C. to about 240° C.).
A temperature monitoring system may be installed in wellbores of freeze wells and/or in monitor wells adjacent to the freeze wells to monitor the temperature profile of the freeze wells and/or the low temperature zone established by the freeze wells. The monitoring system may be used to monitor progress of low temperature zone formation. The monitoring system may be used to determine the location of high temperature areas, potential breakthrough locations, or breakthrough locations after the low temperature zone has formed. Periodic monitoring of the temperature profile of the freeze wells and/or low temperature zone established by the freeze wells may allow additional cooling to be provided to potential trouble areas before breakthrough occurs. Additional cooling may be provided at or adjacent to breakthroughs and high temperature areas to ensure the integrity of the low temperature zone around the treatment area. Additional cooling may be provided by increasing refrigerant flow through selected freeze wells, installing an additional freeze well or freeze wells, and/or by providing a cryogenic fluid, such as liquid nitrogen, to the high temperature areas. Providing additional cooling to potential problem areas before breakthrough occurs may be more time efficient and cost efficient than sealing a breach, reheating a portion of the treatment area that has been cooled by influx of fluid, and/or remediating an area outside of the breached frozen barrier.
In some embodiments, a traveling thermocouple may be used to monitor the temperature profile of selected freeze wells or monitor wells. In some embodiments, the temperature monitoring system includes thermocouples placed at discrete locations in the wellbores of the freeze wells, in the freeze wells, and/or in the monitoring wells. In some embodiments, the temperature monitoring system comprises a fiber optic temperature monitoring system.
Fiber optic temperature monitoring systems are available from Sensornet (London, United Kingdom), Sensa (Houston, Tex., U.S.A.), Luna Energy (Blacksburg, Va., U.S.A.), Lios Technology GMBH (Cologne, Germany), Oxford Electronics Ltd. (Hampshire, United Kingdom), and Sabeus Sensor Systems (Calabasas, Calif., U.S.A.). The fiber optic temperature monitoring system includes a data system and one or more fiber optic cables. The data system includes one or more lasers for sending light to the fiber optic cable; and one or more computers, software and peripherals for receiving, analyzing, and outputting data. The data system may be coupled to one or more fiber optic cables.
A single fiber optic cable may be several kilometers long. The fiber optic cable may be installed in many freeze wells and/or monitor wells. In some embodiments, two fiber optic cables may be installed in each freeze well and/or monitor well. The two fiber optic cables may be coupled. Using two fiber optic cables per well allows for compensation due to optical losses that occur in the wells and allows for better accuracy of measured temperature profiles.
The fiber optic temperature monitoring system may be used to detect the location of a breach or a potential breach in a frozen barrier. The search for potential breaches may be performed at scheduled intervals, for example, every two or three months. To determine the location of the breach or potential breach, flow of formation refrigerant to the freeze wells of interest is stopped. In some embodiments, the flow of formation refrigerant to all of the freeze wells is stopped. The rise in the temperature profiles, as well as the rate of change of the temperature profiles, provided by the fiber optic temperature monitoring system for each freeze well can be used to determine the location of any breaches or hot spots in the low temperature zone maintained by the freeze wells. The temperature profile monitored by the fiber optic temperature monitoring system for the two freeze wells closest to the hot spot or fluid flow will show the quickest and greatest rise in temperature. A temperature change of a few degrees Centigrade in the temperature profiles of the freeze wells closest to a troubled area may be sufficient to isolate the location of the trouble area. The shut down time of flow of circulation fluid in the freeze wells of interest needed to detect breaches, potential breaches, and hot spots may be on the order of a few hours or days, depending on the well spacing and the amount of fluid flow affecting the low temperature zone.
Fiber optic temperature monitoring systems may also be used to monitor temperatures in heated portions of the formation during in situ heat treatment processes. The fiber of a fiber optic cable used in the heated portion of the formation may be clad with a reflective material to facilitate retention of a signal or signals transmitted down the fiber. In some embodiments, the fiber is clad with gold, copper, nickel, aluminum and/or alloys thereof. The cladding may be formed of a material that is able to withstand chemical and temperature conditions in the heated portion of the formation. For example, gold cladding may allow an optical sensor to be used up to temperatures of 700° C. In some embodiments, the fiber is clad with aluminum. The fiber may be dipped in or run through a bath of liquid aluminum. The clad fiber may then be allowed to cool to secure the aluminum to the fiber. The gold or aluminum cladding may reduce hydrogen darkening of the optical fiber.
A potential source of heat loss from the heated formation is due to reflux in wells. Refluxing occurs when vapors condense in a well and flow into a portion of the well adjacent to the heated portion of the formation. Vapors may condense in the well adjacent to the overburden of the formation to form condensed fluid. Condensed fluid flowing into the well adjacent to the heated formation absorbs heat from the formation. Heat absorbed by condensed fluids cools the formation and necessitates additional energy input into the formation to maintain the formation at a desired temperature. Some fluids that condense in the overburden and flow into the portion of the well adjacent to the heated formation may react to produce undesired compounds and/or coke. Inhibiting fluids from refluxing may significantly improve the thermal efficiency of the in situ heat treatment system and/or the quality of the product produced from the in situ heat treatment system.
For some well embodiments, the portion of the well adjacent to the overburden section of the formation is cemented to the formation. In some well embodiments, the well includes packing material placed near the transition from the heated section of the formation to the overburden. The packing material inhibits formation fluid from passing from the heated section of the formation into the section of the wellbore adjacent to the overburden. Cables, conduits, devices, and/or instruments may pass through the packing material, but the packing material inhibits formation fluid from passing up the wellbore adjacent to the overburden section of the formation.
In some embodiments, one or more baffle systems may be placed in the wellbores to inhibit reflux. The baffle systems may be obstructions to fluid flow into the heated portion of the formation. In some embodiments, refluxing fluid may revaporize on the baffle system before coming into contact with the heated portion of the formation.
In some embodiments, a gas may be introduced into the formation through wellbores to inhibit reflux in the wellbores. In some embodiments, gas may be introduced into wellbores that include baffle systems to inhibit reflux of fluid in the wellbores. The gas may be carbon dioxide, methane, nitrogen or other desired gas. In some embodiments, the introduction of gas may be used in conjunction with one or more baffle systems in the wellbores. The introduced gas may enhance heat exchange at the baffle systems to help maintain top portions of the baffle systems colder than the lower portions of the baffle systems.
The flow of production fluid up the well to the surface is desired for some types of wells, especially for production wells. Flow of production fluid up the well is also desirable for some heater wells that are used to control pressure in the formation. The overburden, or a conduit in the well used to transport formation fluid from the heated portion of the formation to the surface, may be heated to inhibit condensation on or in the conduit. Providing heat in the overburden, however, may be costly and/or may lead to increased cracking or coking of formation fluid as the formation fluid is being produced from the formation.
To avoid the need to heat the overburden or to heat the conduit passing through the overburden, one or more diverters may be placed in the wellbore to inhibit fluid from refluxing into the wellbore adjacent to the heated portion of the formation. In some embodiments, the diverter retains fluid above the heated portion of the formation. Fluids retained in the diverter may be removed from the diverter using a pump, gas lifting, and/or other fluid removal technique. In certain embodiments, two or more diverters that retain fluid above the heated portion of the formation may be located in the production well. Two or more diverters provide a simple way of separating initial fractions of condensed fluid produced from the in situ heat treatment system. A pump may be placed in each of the diverters to remove condensed fluid from the diverters.
In some embodiments, the diverter directs fluid to a sump below the heated portion of the formation. An inlet for a lift system may be located in the sump. In some embodiments, the intake of the lift system is located in casing in the sump. In some embodiments, the intake of the lift system is located in an open wellbore. The sump is below the heated portion of the formation. The intake of the pump may be located 1 m, 5 m, 10 m, 20 m or more below the deepest heater used to heat the heated portion of the formation. The sump may be at a cooler temperature than the heated portion of the formation. The sump may be more than 10° C., more than 50° C., more than 75° C., or more than 100° C. below the temperature of the heated portion of the formation. A portion of the fluid entering the sump may be liquid. A portion of the fluid entering the sump may condense within the sump. The lift system moves the fluid in the sump to the surface.
Production well lift systems may be used to efficiently transport formation fluid from the bottom of the production wells to the surface. Production well lift systems may provide and maintain the maximum required well drawdown (minimum reservoir producing pressure) and producing rates. The production well lift systems may operate efficiently over a wide range of high temperature/multiphase fluids (gas/vapor/steam/water/hydrocarbon liquids) and production rates expected during the life of a typical project. Production well lift systems may include dual concentric rod pump lift systems, chamber lift systems and other types of lift systems.
Temperature limited heaters may be in configurations and/or may include materials that provide automatic temperature limiting properties for the heater at certain temperatures. In certain embodiments, ferromagnetic materials are used in temperature limited heaters. Ferromagnetic material may self-limit temperature at or near the Curie temperature of the material and/or the phase transformation temperature range to provide a reduced amount of heat when a time-varying current is applied to the material. In certain embodiments, the ferromagnetic material self-limits temperature of the temperature limited heater at a selected temperature that is approximately the Curie temperature and/or in the phase transformation temperature range. In certain embodiments, the selected temperature is within about 35° C., within about 25° C., within about 20° C., or within about 10° C. of the Curie temperature and/or the phase transformation temperature range. In certain embodiments, ferromagnetic materials are coupled with other materials (for example, highly conductive materials, high strength materials, corrosion resistant materials, or combinations thereof) to provide various electrical and/or mechanical properties. Some parts of the temperature limited heater may have a lower resistance (caused by different geometries and/or by using different ferromagnetic and/or non-ferromagnetic materials) than other parts of the temperature limited heater. Having parts of the temperature limited heater with various materials and/or dimensions allows for tailoring the desired heat output from each part of the heater.
Temperature limited heaters may be more reliable than other heaters. Temperature limited heaters may be less apt to break down or fail due to hot spots in the formation. In some embodiments, temperature limited heaters allow for substantially uniform heating of the formation. In some embodiments, temperature limited heaters are able to heat the formation more efficiently by operating at a higher average heat output along the entire length of the heater. The temperature limited heater operates at the higher average heat output along the entire length of the heater because power to the heater does not have to be reduced to the entire heater, as is the case with typical constant wattage heaters, if a temperature along any point of the heater exceeds, or is about to exceed, a maximum operating temperature of the heater. Heat output from portions of a temperature limited heater approaching a Curie temperature and/or the phase transformation temperature range of the heater automatically reduces without controlled adjustment of the time-varying current applied to the heater. The heat output automatically reduces due to changes in electrical properties (for example, electrical resistance) of portions of the temperature limited heater. Thus, more power is supplied by the temperature limited heater during a greater portion of a heating process.
In certain embodiments, the system including temperature limited heaters initially provides a first heat output and then provides a reduced (second heat output) heat output, near, at, or above the Curie temperature and/or the phase transformation temperature range of an electrically resistive portion of the heater when the temperature limited heater is energized by a time-varying current. The first heat output is the heat output at temperatures below which the temperature limited heater begins to self-limit. In some embodiments, the first heat output is the heat output at a temperature about 50° C., about 75° C., about 100° C., or about 125° C. below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic material in the temperature limited heater.
The temperature limited heater may be energized by time-varying current (alternating current or modulated direct current) supplied at the wellhead. The wellhead may include a power source and other components (for example, modulation components, transformers, and/or capacitors) used in supplying power to the temperature limited heater. The temperature limited heater may be one of many heaters used to heat a portion of the formation.
In certain embodiments, the temperature limited heater includes a conductor that operates as a skin effect or proximity effect heater when time-varying current is applied to the conductor. The skin effect limits the depth of current penetration into the interior of the conductor. For ferromagnetic materials, the skin effect is dominated by the magnetic permeability of the conductor. The relative magnetic permeability of ferromagnetic materials is typically between 10 and 1000 (for example, the relative magnetic permeability of ferromagnetic materials is typically at least 10 and may be at least 50, 100, 500, 1000 or greater). As the temperature of the ferromagnetic material is raised above the Curie temperature, or the phase transformation temperature range, and/or as the applied electrical current is increased, the magnetic permeability of the ferromagnetic material decreases substantially and the skin depth expands rapidly (for example, the skin depth expands as the inverse square root of the magnetic permeability). The reduction in magnetic permeability results in a decrease in the AC or modulated DC resistance of the conductor near, at, or above the Curie temperature, the phase transformation temperature range, and/or as the applied electrical current is increased. When the temperature limited heater is powered by a substantially constant current source, portions of the heater that approach, reach, or are above the Curie temperature and/or the phase transformation temperature range may have reduced heat dissipation. Sections of the temperature limited heater that are not at or near the Curie temperature and/or the phase transformation temperature range may be dominated by skin effect heating that allows the heater to have high heat dissipation due to a higher resistive load.
Curie temperature heaters have been used in soldering equipment, heaters for medical applications, and heating elements for ovens (for example, pizza ovens). Some of these uses are disclosed in U.S. Pat. Nos. 5,579,575 to Lamome et al.; 5,065,501 to Henschen et al.; and 5,512,732 to Yagnik et al., all of which are incorporated by reference as if fully set forth herein. U.S. Pat. No. 4,849,611 to Whitney et al., which is incorporated by reference as if fully set forth herein, describes a plurality of discrete, spaced-apart heating units including a reactive component, a resistive heating component, and a temperature responsive component.
An advantage of using the temperature limited heater to heat hydrocarbons in the formation is that the conductor is chosen to have a Curie temperature and/or a phase transformation temperature range in a desired range of temperature operation. Operation within the desired operating temperature range allows substantial heat injection into the formation while maintaining the temperature of the temperature limited heater, and other equipment, below design limit temperatures. Design limit temperatures are temperatures at which properties such as corrosion, creep, and/or deformation are adversely affected. The temperature limiting properties of the temperature limited heater inhibit overheating or burnout of the heater adjacent to low thermal conductivity “hot spots” in the formation. In some embodiments, the temperature limited heater is able to lower or control heat output and/or withstand heat at temperatures above 25° C., 37° C., 100° C., 250° C., 500° C., 700° C., 800° C., 900° C., or higher up to 1131° C., depending on the materials used in the heater.
The temperature limited heater allows for more heat injection into the formation than constant wattage heaters because the energy input into the temperature limited heater does not have to be limited to accommodate low thermal conductivity regions adjacent to the heater. For example, in Green River oil shale there is a difference of at least a factor of 3 in the thermal conductivity of the lowest richness oil shale layers and the highest richness oil shale layers. When heating such a formation, substantially more heat is transferred to the formation with the temperature limited heater than with the conventional heater that is limited by the temperature at low thermal conductivity layers. The heat output along the entire length of the conventional heater needs to accommodate the low thermal conductivity layers so that the heater does not overheat at the low thermal conductivity layers and burn out. The heat output adjacent to the low thermal conductivity layers that are at high temperature will reduce for the temperature limited heater, but the remaining portions of the temperature limited heater that are not at high temperature will still provide high heat output. Because heaters for heating hydrocarbon formations typically have long lengths (for example, at least 10 m, 100 m, 300 m, 500 m, 1 km or more up to about 10 km), the majority of the length of the temperature limited heater may be operating below the Curie temperature and/or the phase transformation temperature range while only a few portions are at or near the Curie temperature and/or the phase transformation temperature range of the temperature limited heater.
The use of temperature limited heaters allows for efficient transfer of heat to the formation. Efficient transfer of heat allows for reduction in time needed to heat the formation to a desired temperature. For example, in Green River oil shale, pyrolysis typically requires 9.5 years to 10 years of heating when using a 12 m heater well spacing with conventional constant wattage heaters. For the same heater spacing, temperature limited heaters may allow a larger average heat output while maintaining heater equipment temperatures below equipment design limit temperatures. Pyrolysis in the formation may occur at an earlier time with the larger average heat output provided by temperature limited heaters than the lower average heat output provided by constant wattage heaters. For example, in Green River oil shale, pyrolysis may occur in 5 years using temperature limited heaters with a 12 m heater well spacing. Temperature limited heaters counteract hot spots due to inaccurate well spacing or drilling where heater wells come too close together. In certain embodiments, temperature limited heaters allow for increased power output over time for heater wells that have been spaced too far apart, or limit power output for heater wells that are spaced too close together. Temperature limited heaters also supply more power in regions adjacent the overburden and underburden to compensate for temperature losses in these regions.
Temperature limited heaters may be advantageously used in many types of formations. For example, in tar sands formations or relatively permeable formations containing heavy hydrocarbons, temperature limited heaters may be used to provide a controllable low temperature output for reducing the viscosity of fluids, mobilizing fluids, and/or enhancing the radial flow of fluids at or near the wellbore or in the formation. Temperature limited heaters may be used to inhibit excess coke formation due to overheating of the near wellbore region of the formation.
The use of temperature limited heaters, in some embodiments, eliminates or reduces the need for expensive temperature control circuitry. For example, the use of temperature limited heaters eliminates or reduces the need to perform temperature logging and/or the need to use fixed thermocouples on the heaters to monitor potential overheating at hot spots.
In certain embodiments, phase transformation (for example, crystalline phase transformation or a change in the crystal structure) of materials used in a temperature limited heater change the selected temperature at which the heater self-limits. Ferromagnetic material used in the temperature limited heater may have a phase transformation (for example, a transformation from ferrite to austenite) that decreases the magnetic permeability of the ferromagnetic material. This reduction in magnetic permeability is similar to reduction in magnetic permeability due to the magnetic transition of the ferromagnetic material at the Curie temperature. The Curie temperature is the magnetic transition temperature of the ferrite phase of the ferromagnetic material. The reduction in magnetic permeability results in a decrease in the AC or modulated DC resistance of the temperature limited heater near, at, or above the temperature of the phase transformation and/or the Curie temperature of the ferromagnetic material.
The phase transformation of the ferromagnetic material may occur over a temperature range. The temperature range of the phase transformation depends on the ferromagnetic material and may vary, for example, over a range of about 5° C. to a range of about 200° C. Because the phase transformation takes place over a temperature range, the reduction in the magnetic permeability due to the phase transformation takes place over the temperature range. The reduction in magnetic permeability may also occur hysteretically over the temperature range of the phase transformation. In some embodiments, the phase transformation back to the lower temperature phase of the ferromagnetic material is slower than the phase transformation to the higher temperature phase (for example, the transition from austenite back to ferrite is slower than the transition from ferrite to austenite). The slower phase transformation back to the lower temperature phase may cause hysteretic operation of the heater at or near the phase transformation temperature range that allows the heater to slowly increase to higher resistance after the resistance of the heater reduces due to high temperature.
In some embodiments, the phase transformation temperature range overlaps with the reduction in the magnetic permeability when the temperature approaches the Curie temperature of the ferromagnetic material. The overlap may produce a faster drop in electrical resistance versus temperature than if the reduction in magnetic permeability is solely due to the temperature approaching the Curie temperature. The overlap may also produce hysteretic behavior of the temperature limited heater near the Curie temperature and/or in the phase transformation temperature range.
In certain embodiments, the hysteretic operation due to the phase transformation is a smoother transition than the reduction in magnetic permeability due to magnetic transition at the Curie temperature. The smoother transition may be easier to control (for example, electrical control using a process control device that interacts with the power supply) than the sharper transition at the Curie temperature. In some embodiments, the Curie temperature is located inside the phase transformation range for selected metallurgies used in temperature limited heaters. This phenomenon provides temperature limited heaters with the smooth transition properties of the phase transformation in addition to a sharp and definite transition due to the reduction in magnetic properties at the Curie temperature. Such temperature limited heaters may be easy to control (due to the phase transformation) while providing finite temperature limits (due to the sharp Curie temperature transition). Using the phase transformation temperature range instead of and/or in addition to the Curie temperature in temperature limited heaters increases the number and range of metallurgies that may be used for temperature limited heaters.
In certain embodiments, alloy additions are made to the ferromagnetic material to adjust the temperature range of the phase transformation. For example, adding carbon to the ferromagnetic material may increase the phase transformation temperature range and lower the onset temperature of the phase transformation. Adding titanium to the ferromagnetic material may increase the onset temperature of the phase transformation and decrease the phase transformation temperature range. Alloy compositions may be adjusted to provide desired Curie temperature and phase transformation properties for the ferromagnetic material. The alloy composition of the ferromagnetic material may be chosen based on desired properties for the ferromagnetic material (such as, but not limited to, magnetic permeability transition temperature or temperature range, resistance versus temperature profile, or power output). Addition of titanium may allow higher Curie temperatures to be obtained when adding cobalt to 410 stainless steel by raising the ferrite to austenite phase transformation temperature range to a temperature range that is above, or well above, the Curie temperature of the ferromagnetic material.
In some embodiments, temperature limited heaters are more economical to manufacture or make than standard heaters. Typical ferromagnetic materials include iron, carbon steel, or ferritic stainless steel. Such materials are inexpensive as compared to nickel-based heating alloys (such as nichrome, Kanthal™ (Bulten-Kanthal AB, Sweden), and/or LOHM™ (Driver-Harris Company, Harrison, N.J., U.S.A.)) typically used in insulated conductor (mineral insulated cable) heaters. In one embodiment of the temperature limited heater, the temperature limited heater is manufactured in continuous lengths as an insulated conductor heater to lower costs and improve reliability.
In some embodiments, the temperature limited heater is placed in the heater well using a coiled tubing rig. A heater that can be coiled on a spool may be manufactured by using metal such as ferritic stainless steel (for example, 409 stainless steel) that is welded using electrical resistance welding (ERW). U.S. Pat. No. 7,032,809 to Hopkins, which is incorporated by reference as if fully set forth herein, describes forming seam-welded pipe. To form a heater section, a metal strip from a roll is passed through a former where it is shaped into a tubular and then longitudinally welded using ERW.
In some embodiments, a composite tubular may be formed from the seam-welded tubular. The seam-welded tubular is passed through a second former where a conductive strip (for example, a copper strip) is applied, drawn down tightly on the tubular through a die, and longitudinally welded using ERW. A sheath may be formed by longitudinally welding a support material (for example, steel such as 347H or 347HH) over the conductive strip material. The support material may be a strip rolled over the conductive strip material. An overburden section of the heater may be formed in a similar manner.
In certain embodiments, the overburden section uses a non-ferromagnetic material such as 304 stainless steel or 316 stainless steel instead of a ferromagnetic material. The heater section and overburden section may be coupled using standard techniques such as butt welding using an orbital welder. In some embodiments, the overburden section material (the non-ferromagnetic material) may be pre-welded to the ferromagnetic material before rolling. The pre-welding may eliminate the need for a separate coupling step (for example, butt welding). In an embodiment, a flexible cable (for example, a furnace cable such as a MGT 1000 furnace cable) may be pulled through the center after forming the tubular heater. An end bushing on the flexible cable may be welded to the tubular heater to provide an electrical current return path. The tubular heater, including the flexible cable, may be coiled onto a spool before installation into a heater well. In an embodiment, the temperature limited heater is installed using the coiled tubing rig. The coiled tubing rig may place the temperature limited heater in a deformation resistant container in the formation. The deformation resistant container may be placed in the heater well using conventional methods.
Temperature limited heaters may be used for heating hydrocarbon formations including, but not limited to, oil shale formations, coal formations, tar sands formations, and formations with heavy viscous oils. Temperature limited heaters may also be used in the field of environmental remediation to vaporize or destroy soil contaminants. Embodiments of temperature limited heaters may be used to heat fluids in a wellbore or sub-sea pipeline to inhibit deposition of paraffin or various hydrates. In some embodiments, a temperature limited heater is used for solution mining a subsurface formation (for example, an oil shale or a coal formation). In certain embodiments, a fluid (for example, molten salt) is placed in a wellbore and heated with a temperature limited heater to inhibit deformation and/or collapse of the wellbore. In some embodiments, the temperature limited heater is attached to a sucker rod in the wellbore or is part of the sucker rod itself. In some embodiments, temperature limited heaters are used to heat a near wellbore region to reduce near wellbore oil viscosity during production of high viscosity crude oils and during transport of high viscosity oils to the surface. In some embodiments, a temperature limited heater enables gas lifting of a viscous oil by lowering the viscosity of the oil without coking the oil. Temperature limited heaters may be used in sulfur transfer lines to maintain temperatures between about 110° C. and about 130° C.
The ferromagnetic alloy or ferromagnetic alloys used in the temperature limited heater determine the Curie temperature of the heater. Curie temperature data for various metals is listed in “American Institute of Physics Handbook,” Second Edition, McGraw-Hill, pages 5-170 through 5-176. Ferromagnetic conductors may include one or more of the ferromagnetic elements (iron, cobalt, and nickel) and/or alloys of these elements. In some embodiments, ferromagnetic conductors include iron-chromium (Fe—Cr) alloys that contain tungsten (W) (for example, HCM12A and SAVE12 (Sumitomo Metals Co., Japan) and/or iron alloys that contain chromium (for example, Fe—Cr alloys, Fe—Cr—W alloys, Fe—Cr—V (vanadium) alloys, and Fe—Cr—Nb (Niobium) alloys). Of the three main ferromagnetic elements, iron has a Curie temperature of approximately 770° C.; cobalt (Co) has a Curie temperature of approximately 1131° C.; and nickel has a Curie temperature of approximately 358° C. An iron-cobalt alloy has a Curie temperature higher than the Curie temperature of iron. For example, iron-cobalt alloy with 2% by weight cobalt has a Curie temperature of approximately 800° C.; iron-cobalt alloy with 12% by weight cobalt has a Curie temperature of approximately 900° C.; and iron-cobalt alloy with 20% by weight cobalt has a Curie temperature of approximately 950° C. Iron-nickel alloy has a Curie temperature lower than the Curie temperature of iron. For example, iron-nickel alloy with 20% by weight nickel has a Curie temperature of approximately 720° C., and iron-nickel alloy with 60% by weight nickel has a Curie temperature of approximately 560° C.
Some non-ferromagnetic elements used as alloys raise the Curie temperature of iron. For example, an iron-vanadium alloy with 5.9% by weight vanadium has a Curie temperature of approximately 815° C. Other non-ferromagnetic elements (for example, carbon, aluminum, copper, silicon, and/or chromium) may be alloyed with iron or other ferromagnetic materials to lower the Curie temperature. Non-ferromagnetic materials that raise the Curie temperature may be combined with non-ferromagnetic materials that lower the Curie temperature and alloyed with iron or other ferromagnetic materials to produce a material with a desired Curie temperature and other desired physical and/or chemical properties. In some embodiments, the Curie temperature material is a ferrite such as NiFe2O4. In other embodiments, the Curie temperature material is a binary compound such as FeNi3 or Fe3Al.
In some embodiments, the improved alloy includes carbon, cobalt, iron, manganese, silicon, or mixtures thereof. In certain embodiments, the improved alloy includes, by weight: about 0.1% to about 10% cobalt; about 0.1% carbon, about 0.5% manganese, about 0.5% silicon, with the balance being iron. In certain embodiments, the improved alloy includes, by weight: about 0.1% to about 10% cobalt; about 0.1% carbon, about 0.5% manganese, about 0.5% silicon, with the balance being iron.
In some embodiments, the improved alloy includes chromium, carbon, cobalt, iron, manganese, silicon, titanium, vanadium, or mixtures thereof. In certain embodiments, the improved alloy includes, by weight: about 5% to about 20% cobalt, about 0.1% carbon, about 0.5% manganese, about 0.5% silicon, about 0.1% to about 2% vanadium with the balance being iron. In some embodiments, the improved alloy includes, by weight: about 12% chromium, about 0.1% carbon, about 0.5% silicon, about 0.1% to about 0.5% manganese, above 0% to about 15% cobalt, above 0% to about 2% vanadium, above 0% to about 1% titanium, with the balance being iron. In some embodiments, the improved alloy includes, by weight: about 12% chromium, about 0.1% carbon, about 0.5% silicon, about 0.1% to about 0.5% manganese, above 0% to about 2% vanadium, above 0% to about 1% titanium, with the balance being iron. In some embodiments, the improved alloy includes, by weight: about 12% chromium, about 0.1% carbon, about 0.5% silicon, about 0.1% to about 0.5% manganese, above 0% to about 2% vanadium, with the balance being iron. In certain embodiments, the improved alloy includes, by weight: about 12% chromium, about 0.1% carbon, about 0.5% silicon, about 0.1% to about 0.5% manganese, above 0% to about 15% cobalt, above 0% to about 1% titanium, with the balance being iron. In certain embodiments, the improved alloy includes, by weight: about 12% chromium, about 0.1% carbon, about 0.5% silicon, about 0.1% to about 0.5% manganese, above 0% to about 15% cobalt, with the balance being iron. The addition of vanadium may allow for use of higher amounts of cobalt in the improved alloy.
Certain embodiments of temperature limited heaters may include more than one ferromagnetic material. Such embodiments are within the scope of embodiments described herein if any conditions described herein apply to at least one of the ferromagnetic materials in the temperature limited heater.
Ferromagnetic properties generally decay as the Curie temperature and/or the phase transformation temperature range is approached. The “Handbook of Electrical Heating for Industry” by C. James Erickson (IEEE Press, 1995) shows a typical curve for 1% carbon steel (steel with 1% carbon by weight). The loss of magnetic permeability starts at temperatures above 650° C. and tends to be complete when temperatures exceed 730° C. Thus, the self-limiting temperature may be somewhat below the actual Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor. The skin depth for current flow in 1% carbon steel is 0.132 cm at room temperature and increases to 0.445 cm at 720° C. From 720° C. to 730° C., the skin depth sharply increases to over 2.5 cm. Thus, a temperature limited heater embodiment using 1% carbon steel begins to self-limit between 650° C. and 730° C.
Skin depth generally defines an effective penetration depth of time-varying current into the conductive material. In general, current density decreases exponentially with distance from an outer surface to the center along the radius of the conductor. The depth at which the current density is approximately l/e of the surface current density is called the skin depth. For a solid cylindrical rod with a diameter much greater than the penetration depth, or for hollow cylinders with a wall thickness exceeding the penetration depth, the skin depth, δ, is:
δ=1981.5*(ρ/(μ*f))1/2; (EQN. 3)
in which:
Materials used in the temperature limited heater may be selected to provide a desired turndown ratio. Turndown ratios of at least 1.1:1, 2:1, 3:1, 4:1, 5:1, 10:1, 30:1, or 50:1 may be selected for temperature limited heaters. Larger turndown ratios may also be used. A selected turndown ratio may depend on a number of factors including, but not limited to, the type of formation in which the temperature limited heater is located (for example, a higher turndown ratio may be used for an oil shale formation with large variations in thermal conductivity between rich and lean oil shale layers) and/or a temperature limit of materials used in the wellbore (for example, temperature limits of heater materials). In some embodiments, the turndown ratio is increased by coupling additional copper or another good electrical conductor to the ferromagnetic material (for example, adding copper to lower the resistance above the Curie temperature and/or the phase transformation temperature range).
The temperature limited heater may provide a maximum heat output (power output) below the Curie temperature and/or the phase transformation temperature range of the heater. In certain embodiments, the maximum heat output is at least 400 W/m (Watts per meter), 600 W/m, 700 W/m, 800 W/m, or higher up to 2000 W/m. The temperature limited heater reduces the amount of heat output by a section of the heater when the temperature of the section of the heater approaches or is above the Curie temperature and/or the phase transformation temperature range. The reduced amount of heat may be substantially less than the heat output below the Curie temperature and/or the phase transformation temperature range. In some embodiments, the reduced amount of heat is at most 400 W/m, 200 W/m, 100 W/m or may approach 0 W/m.
In certain embodiments, the temperature limited heater operates substantially independently of the thermal load on the heater in a certain operating temperature range. “Thermal load” is the rate that heat is transferred from a heating system to its surroundings. It is to be understood that the thermal load may vary with temperature of the surroundings and/or the thermal conductivity of the surroundings. In an embodiment, the temperature limited heater operates at or above the Curie temperature and/or the phase transformation temperature range of the temperature limited heater such that the operating temperature of the heater increases at most by 3° C., 2° C., 1.5° C., 1° C., or 0.5° C. for a decrease in thermal load of 1 W/m proximate to a portion of the heater. In certain embodiments, the temperature limited heater operates in such a manner at a relatively constant current.
The AC or modulated DC resistance and/or the heat output of the temperature limited heater may decrease as the temperature approaches the Curie temperature and/or the phase transformation temperature range and decrease sharply near or above the Curie temperature due to the Curie effect and/or phase transformation effect. In certain embodiments, the value of the electrical resistance or heat output above or near the Curie temperature and/or the phase transformation temperature range is at most one-half of the value of electrical resistance or heat output at a certain point below the Curie temperature and/or the phase transformation temperature range. In some embodiments, the heat output above or near the Curie temperature and/or the phase transformation temperature range is at most 90%, 70%, 50%, 30%, 20%, 10%, or less (down to 1%) of the heat output at a certain point below the Curie temperature and/or the phase transformation temperature range (for example, 30° C. below the Curie temperature, 40° C. below the Curie temperature, 50° C. below the Curie temperature, or 100° C. below the Curie temperature). In certain embodiments, the electrical resistance above or near the Curie temperature and/or the phase transformation temperature range decreases to 80%, 70%, 60%, 50%, or less (down to 1%) of the electrical resistance at a certain point below the Curie temperature and/or the phase transformation temperature range (for example, 30° C. below the Curie temperature, 40° C. below the Curie temperature, 50° C. below the Curie temperature, or 100° C. below the Curie temperature).
In some embodiments, AC frequency is adjusted to change the skin depth of the ferromagnetic material. For example, the skin depth of 1% carbon steel at room temperature is 0.132 cm at 60 Hz, 0.0762 cm at 180 Hz, and 0.046 cm at 440 Hz. Since heater diameter is typically larger than twice the skin depth, using a higher frequency (and thus a heater with a smaller diameter) reduces heater costs. For a fixed geometry, the higher frequency results in a higher turndown ratio. The turndown ratio at a higher frequency is calculated by multiplying the turndown ratio at a lower frequency by the square root of the higher frequency divided by the lower frequency. In some embodiments, a frequency between 100 Hz and 1000 Hz, between 140 Hz and 200 Hz, or between 400 Hz and 600 Hz is used (for example, 180 Hz, 540 Hz, or 720 Hz). In some embodiments, high frequencies may be used. The frequencies may be greater than 1000 Hz.
To maintain a substantially constant skin depth until the Curie temperature and/or the phase transformation temperature range of the temperature limited heater is reached, the heater may be operated at a lower frequency when the heater is cold and operated at a higher frequency when the heater is hot. Line frequency heating is generally favorable, however, because there is less need for expensive components such as power supplies, transformers, or current modulators that alter frequency. Line frequency is the frequency of a general supply of current. Line frequency is typically 60 Hz, but may be 50 Hz or another frequency depending on the source for the supply of the current. Higher frequencies may be produced using commercially available equipment such as solid state variable frequency power supplies. Transformers that convert three-phase power to single-phase power with three times the frequency are commercially available. For example, high voltage three-phase power at 60 Hz may be transformed to single-phase power at 180 Hz and at a lower voltage. Such transformers are less expensive and more energy efficient than solid state variable frequency power supplies. In certain embodiments, transformers that convert three-phase power to single-phase power are used to increase the frequency of power supplied to the temperature limited heater.
In certain embodiments, modulated DC (for example, chopped DC, waveform modulated DC, or cycled DC) may be used for providing electrical power to the temperature limited heater. A DC modulator or DC chopper may be coupled to a DC power supply to provide an output of modulated direct current. In some embodiments, the DC power supply may include means for modulating DC. One example of a DC modulator is a DC-to-DC converter system. DC-to-DC converter systems are generally known in the art. DC is typically modulated or chopped into a desired waveform. Waveforms for DC modulation include, but are not limited to, square-wave, sinusoidal, deformed sinusoidal, deformed square-wave, triangular, and other regular or irregular waveforms.
The modulated DC waveform generally defines the frequency of the modulated DC. Thus, the modulated DC waveform may be selected to provide a desired modulated DC frequency. The shape and/or the rate of modulation (such as the rate of chopping) of the modulated DC waveform may be varied to vary the modulated DC frequency. DC may be modulated at frequencies that are higher than generally available AC frequencies. For example, modulated DC may be provided at frequencies of at least 1000 Hz. Increasing the frequency of supplied current to higher values advantageously increases the turndown ratio of the temperature limited heater.
In certain embodiments, the modulated DC waveform is adjusted or altered to vary the modulated DC frequency. The DC modulator may be able to adjust or alter the modulated DC waveform at any time during use of the temperature limited heater and at high currents or voltages. Thus, modulated DC provided to the temperature limited heater is not limited to a single frequency or even a small set of frequency values. Waveform selection using the DC modulator typically allows for a wide range of modulated DC frequencies and for discrete control of the modulated DC frequency. Thus, the modulated DC frequency is more easily set at a distinct value whereas AC frequency is generally limited to multiples of the line frequency. Discrete control of the modulated DC frequency allows for more selective control over the turndown ratio of the temperature limited heater. Being able to selectively control the turndown ratio of the temperature limited heater allows for a broader range of materials to be used in designing and constructing the temperature limited heater.
In some embodiments, the modulated DC frequency or the AC frequency is adjusted to compensate for changes in properties (for example, subsurface conditions such as temperature or pressure) of the temperature limited heater during use. The modulated DC frequency or the AC frequency provided to the temperature limited heater is varied based on assessed downhole conditions. For example, as the temperature of the temperature limited heater in the wellbore increases, it may be advantageous to increase the frequency of the current provided to the heater, thus increasing the turndown ratio of the heater. In an embodiment, the downhole temperature of the temperature limited heater in the wellbore is assessed.
In certain embodiments, the modulated DC frequency, or the AC frequency, is varied to adjust the turndown ratio of the temperature limited heater. The turndown ratio may be adjusted to compensate for hot spots occurring along a length of the temperature limited heater. For example, the turndown ratio is increased because the temperature limited heater is getting too hot in certain locations. In some embodiments, the modulated DC frequency, or the AC frequency, are varied to adjust a turndown ratio without assessing a subsurface condition.
At or near the Curie temperature and/or the phase transformation temperature range of the ferromagnetic material, a relatively small change in voltage may cause a relatively large change in current to the load. The relatively small change in voltage may produce problems in the power supplied to the temperature limited heater, especially at or near the Curie temperature and/or the phase transformation temperature range. The problems include, but are not limited to, reducing the power factor, tripping a circuit breaker, and/or blowing a fuse. In some cases, voltage changes may be caused by a change in the load of the temperature limited heater. In certain embodiments, an electrical current supply (for example, a supply of modulated DC or AC) provides a relatively constant amount of current that does not substantially vary with changes in load of the temperature limited heater. In an embodiment, the electrical current supply provides an amount of electrical current that remains within 15%, within 10%, within 5%, or within 2% of a selected constant current value when a load of the temperature limited heater changes.
Temperature limited heaters may generate an inductive load. The inductive load is due to some applied electrical current being used by the ferromagnetic material to generate a magnetic field in addition to generating a resistive heat output. As downhole temperature changes in the temperature limited heater, the inductive load of the heater changes due to changes in the ferromagnetic properties of ferromagnetic materials in the heater with temperature. The inductive load of the temperature limited heater may cause a phase shift between the current and the voltage applied to the heater.
A reduction in actual power applied to the temperature limited heater may be caused by a time lag in the current waveform (for example, the current has a phase shift relative to the voltage due to an inductive load) and/or by distortions in the current waveform (for example, distortions in the current waveform caused by introduced harmonics due to a non-linear load). Thus, it may take more current to apply a selected amount of power due to phase shifting or waveform distortion. The ratio of actual power applied and the apparent power that would have been transmitted if the same current were in phase and undistorted is the power factor. The power factor is always less than or equal to 1. The power factor is 1 when there is no phase shift or distortion in the waveform.
Actual power applied to a heater due to a phase shift may be described by EQN. 4:
P=I×V×cos(θ); (EQN. 4)
in which P is the actual power applied to a heater; I is the applied current; V is the applied voltage; and θ is the phase angle difference between voltage and current. Other phenomena such as waveform distortion may contribute to further lowering of the power factor. If there is no distortion in the waveform, then cos(θ) is equal to the power factor.
In certain embodiments, the temperature limited heater includes an inner conductor inside an outer conductor. The inner conductor and the outer conductor are radially disposed about a central axis. The inner and outer conductors may be separated by an insulation layer. In certain embodiments, the inner and outer conductors are coupled at the bottom of the temperature limited heater. Electrical current may flow into the temperature limited heater through the inner conductor and return through the outer conductor. One or both conductors may include ferromagnetic material.
The insulation layer may comprise an electrically insulating ceramic with high thermal conductivity, such as magnesium oxide, aluminum oxide, silicon dioxide, beryllium oxide, boron nitride, silicon nitride, or combinations thereof. The insulating layer may be a compacted powder (for example, compacted ceramic powder). Compaction may improve thermal conductivity and provide better insulation resistance. For lower temperature applications, polymer insulation made from, for example, fluoropolymers, polyimides, polyamides, and/or polyethylenes, may be used. In some embodiments, the polymer insulation is made of perfluoroalkoxy (PFA) or polyetheretherketone (PEEK™ (Victrex Ltd, England)). The insulating layer may be chosen to be substantially infrared transparent to aid heat transfer from the inner conductor to the outer conductor. In an embodiment, the insulating layer is transparent quartz sand. The insulation layer may be air or a non-reactive gas such as helium, nitrogen, or sulfur hexafluoride. If the insulation layer is air or a non-reactive gas, there may be insulating spacers designed to inhibit electrical contact between the inner conductor and the outer conductor. The insulating spacers may be made of, for example, high purity aluminum oxide or another thermally conducting, electrically insulating material such as silicon nitride. The insulating spacers may be a fibrous ceramic material such as Nextel™ 312 (3M Corporation, St. Paul, Minn., U.S.A.), mica tape, or glass fiber. Ceramic material may be made of alumina, alumina-silicate, alumina-borosilicate, silicon nitride, boron nitride, or other materials.
The insulation layer may be flexible and/or substantially deformation tolerant. For example, if the insulation layer is a solid or compacted material that substantially fills the space between the inner and outer conductors, the temperature limited heater may be flexible and/or substantially deformation tolerant. Forces on the outer conductor can be transmitted through the insulation layer to the solid inner conductor, which may resist crushing. Such a temperature limited heater may be bent, dog-legged, and spiraled without causing the outer conductor and the inner conductor to electrically short to each other. Deformation tolerance may be important if the wellbore is likely to undergo substantial deformation during heating of the formation.
In certain embodiments, an outermost layer of the temperature limited heater (for example, the outer conductor) is chosen for corrosion resistance, yield strength, and/or creep resistance. In one embodiment, austenitic (non-ferromagnetic) stainless steels such as 201, 304H, 347H, 347HH, 316H, 310H, 347HP, NF709 (Nippon Steel Corp., Japan) stainless steels, or combinations thereof may be used in the outer conductor. The outermost layer may also include a clad conductor. For example, a corrosion resistant alloy such as 800H or 347H stainless steel may be clad for corrosion protection over a ferromagnetic carbon steel tubular. If high temperature strength is not required, the outermost layer may be constructed from ferromagnetic metal with good corrosion resistance such as one of the ferritic stainless steels. In one embodiment, a ferritic alloy of 82.3% by weight iron with 17.7% by weight chromium (Curie temperature of 678° C.) provides desired corrosion resistance.
The Metals Handbook, vol. 8, page 291 (American Society of Materials (ASM)) includes a graph of Curie temperature of iron-chromium alloys versus the amount of chromium in the alloys. In some temperature limited heater embodiments, a separate support rod or tubular (made from 347H stainless steel) is coupled to the temperature limited heater made from an iron-chromium alloy to provide yield strength and/or creep resistance. In certain embodiments, the support material and/or the ferromagnetic material is selected to provide a 100,000 hour creep-rupture strength of at least 20.7 MPa at 650° C. In some embodiments, the 100,000 hour creep-rupture strength is at least 13.8 MPa at 650° C. or at least 6.9 MPa at 650° C. For example, 347H steel has a favorable creep-rupture strength at or above 650° C. In some embodiments, the 100,000 hour creep-rupture strength ranges from 6.9 MPa to 41.3 MPa or more for longer heaters and/or higher earth or fluid stresses.
In temperature limited heater embodiments with both an inner ferromagnetic conductor and an outer ferromagnetic conductor, the skin effect current path occurs on the outside of the inner conductor and on the inside of the outer conductor. Thus, the outside of the outer conductor may be clad with the corrosion resistant alloy, such as stainless steel, without affecting the skin effect current path on the inside of the outer conductor.
A ferromagnetic conductor with a thickness of at least the skin depth at the Curie temperature and/or the phase transformation temperature range allows a substantial decrease in resistance of the ferromagnetic material as the skin depth increases sharply near the Curie temperature and/or the phase transformation temperature range. In certain embodiments when the ferromagnetic conductor is not clad with a highly conducting material such as copper, the thickness of the conductor may be 1.5 times the skin depth near the Curie temperature and/or the phase transformation temperature range, 3 times the skin depth near the Curie temperature and/or the phase transformation temperature range, or even 10 or more times the skin depth near the Curie temperature and/or the phase transformation temperature range. If the ferromagnetic conductor is clad with copper, thickness of the ferromagnetic conductor may be substantially the same as the skin depth near the Curie temperature and/or the phase transformation temperature range. In some embodiments, the ferromagnetic conductor clad with copper has a thickness of at least three-fourths of the skin depth near the Curie temperature and/or the phase transformation temperature range.
In certain embodiments, the temperature limited heater includes a composite conductor with a ferromagnetic tubular and a non-ferromagnetic, high electrical conductivity core. The non-ferromagnetic, high electrical conductivity core reduces a required diameter of the conductor. For example, the conductor may be composite 1.19 cm diameter conductor with a core of 0.575 cm diameter copper clad with a 0.298 cm thickness of ferritic stainless steel or carbon steel surrounding the core. The core or non-ferromagnetic conductor may be copper or copper alloy. The core or non-ferromagnetic conductor may also be made of other metals that exhibit low electrical resistivity and relative magnetic permeabilities near 1 (for example, substantially non-ferromagnetic materials such as aluminum and aluminum alloys, phosphor bronze, beryllium copper, and/or brass). A composite conductor allows the electrical resistance of the temperature limited heater to decrease more steeply near the Curie temperature and/or the phase transformation temperature range. As the skin depth increases near the Curie temperature and/or the phase transformation temperature range to include the copper core, the electrical resistance decreases very sharply.
The composite conductor may increase the conductivity of the temperature limited heater and/or allow the heater to operate at lower voltages. In an embodiment, the composite conductor exhibits a relatively flat resistance versus temperature profile at temperatures below a region near the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor of the composite conductor. In some embodiments, the temperature limited heater exhibits a relatively flat resistance versus temperature profile between 100° C. and 750° C. or between 300° C. and 600° C. The relatively flat resistance versus temperature profile may also be exhibited in other temperature ranges by adjusting, for example, materials and/or the configuration of materials in the temperature limited heater. In certain embodiments, the relative thickness of each material in the composite conductor is selected to produce a desired resistivity versus temperature profile for the temperature limited heater.
In certain embodiments, the relative thickness of each material in a composite conductor is selected to produce a desired resistivity versus temperature profile for a temperature limited heater. In an embodiment, the composite conductor is an inner conductor surrounded by 0.127 cm thick magnesium oxide powder as an insulator. The outer conductor may be 304H stainless steel with a wall thickness of 0.127 cm. The outside diameter of the heater may be about 1.65 cm.
A composite conductor (for example, a composite inner conductor or a composite outer conductor) may be manufactured by methods including, but not limited to, coextrusion, roll forming, tight fit tubing (for example, cooling the inner member and heating the outer member, then inserting the inner member in the outer member, followed by a drawing operation and/or allowing the system to cool), explosive or electromagnetic cladding, arc overlay welding, longitudinal strip welding, plasma powder welding, billet coextrusion, electroplating, drawing, sputtering, plasma deposition, coextrusion casting, magnetic forming, molten cylinder casting (of inner core material inside the outer or vice versa), insertion followed by welding or high temperature braising, shielded active gas welding (SAG), and/or insertion of an inner pipe in an outer pipe followed by mechanical expansion of the inner pipe by hydroforming or use of a pig to expand and swage the inner pipe against the outer pipe. In some embodiments, a ferromagnetic conductor is braided over a non-ferromagnetic conductor. In certain embodiments, composite conductors are formed using methods similar to those used for cladding (for example, cladding copper to steel). A metallurgical bond between copper cladding and base ferromagnetic material may be advantageous. Composite conductors produced by a coextrusion process that forms a good metallurgical bond (for example, a good bond between copper and 446 stainless steel) may be provided by Anomet Products, Inc. (Shrewsbury, Mass., U.S.A.).
In some embodiments, the conductor (for example, an inner conductor, an outer conductor, or a ferromagnetic conductor) is the composite conductor that includes two or more different materials. In certain embodiments, the composite conductor includes two or more ferromagnetic materials. In some embodiments, the composite ferromagnetic conductor includes two or more radially disposed materials. In certain embodiments, the composite conductor includes a ferromagnetic conductor and a non-ferromagnetic conductor. In some embodiments, the composite conductor includes the ferromagnetic conductor placed over a non-ferromagnetic core. Two or more materials may be used to obtain a relatively flat electrical resistivity versus temperature profile in a temperature region below the Curie temperature, and/or the phase transformation temperature range, and/or a sharp decrease (a high turndown ratio) in the electrical resistivity at or near the Curie temperature and/or the phase transformation temperature range. In some cases, two or more materials are used to provide more than one Curie temperature and/or phase transformation temperature range for the temperature limited heater.
The composite electrical conductor may be used as the conductor in any electrical heater embodiment described herein. For example, the composite conductor may be used as the conductor in a conductor-in-conduit heater or an insulated conductor heater. In certain embodiments, the composite conductor may be coupled to a support member such as a support conductor. The support member may be used to provide support to the composite conductor so that the composite conductor is not relied upon for strength at or near the Curie temperature and/or the phase transformation temperature range. The support member may be useful for heaters of lengths of at least 100 m. The support member may be a non-ferromagnetic member that has good high temperature creep strength. Examples of materials that are used for a support member include, but are not limited to, Haynes® 625 alloy and Haynes® HR120® alloy (Haynes International, Kokomo, Ind., U.S.A.), NF709, Incoloy® 800H alloy and 347HP alloy (Allegheny Ludlum Corp., Pittsburgh, Pa., U.S.A.). In some embodiments, materials in a composite conductor are directly coupled (for example, brazed, metallurgically bonded, or swaged) to each other and/or the support member. Using a support member may reduce the need for the ferromagnetic member to provide support for the temperature limited heater, especially at or near the Curie temperature and/or the phase transformation temperature range. Thus, the temperature limited heater may be designed with more flexibility in the selection of ferromagnetic materials.
In certain embodiments, the diameter of core 508 is adjusted relative to a constant outside diameter of ferromagnetic conductor 512 to adjust the turndown ratio of the temperature limited heater. For example, the diameter of core 508 may be increased to 1.14 cm while maintaining the outside diameter of ferromagnetic conductor 512 at 1.9 cm to increase the turndown ratio of the heater.
In some embodiments, conductors (for example, core 508 and ferromagnetic conductor 512) in the composite conductor are separated by support member 514.
In certain embodiments, support member 514 is located inside the composite conductor.
In some embodiments, the thickness of inner conductor 490, which is copper, is reduced and the thickness of support member 514 is increased to increase the creep strength at the expense of reduced turndown ratio. For example, the diameter of support member 514 is increased to 1.6 cm while maintaining the outside diameter of inner conductor 490 at 1.9 cm to reduce the thickness of the conduit. This reduction in thickness of inner conductor 490 results in a decreased turndown ratio relative to the thicker inner conductor embodiment but an increased creep strength.
In one embodiment, support member 514 is a conduit (or pipe) inside inner conductor 490 and ferromagnetic conductor 512.
In certain embodiments, the composite electrical conductor is used as the conductor in the conductor-in-conduit heater. For example, the composite electrical conductor may be used as conductor 516 in
Conduit 518 is made of an electrically conductive material. Conduit 518 is disposed in opening 522 in hydrocarbon layer 460. Opening 522 has a diameter that accommodates conduit 518.
Conductor 516 may be centered in conduit 518 by centralizers 524. Centralizers 524 electrically isolate conductor 516 from conduit 518. Centralizers 524 inhibit movement and properly locate conductor 516 in conduit 518. Centralizers 524 are made of ceramic material or a combination of ceramic and metallic materials. Centralizers 524 inhibit deformation of conductor 516 in conduit 518. Centralizers 524 are touching or spaced at intervals between approximately 0.1 m (meters) and approximately 3 m or more along conductor 516.
A second low resistance section 520 of conductor 516 may couple conductor 516 to wellhead 450, as depicted in
Overburden casing 530 may be disposed in overburden 458. Overburden casing 530 is, in some embodiments, surrounded by materials (for example, reinforcing material and/or cement) that inhibit heating of overburden 458. Low resistance section 520 of conductor 516 may be placed in overburden casing 530. Low resistance section 520 of conductor 516 is made of, for example, carbon steel. Low resistance section 520 of conductor 516 may be centralized in overburden casing 530 using centralizers 524. Centralizers 524 are spaced at intervals of approximately 6 m to approximately 12 m or, for example, approximately 9 m along low resistance section 520 of conductor 516. In a heater embodiment, low resistance section 520 of conductor 516 is coupled to conductor 516 by one or more welds. In other heater embodiments, low resistance sections are threaded, threaded and welded, or otherwise coupled to the conductor. Low resistance section 520 generates little or no heat in overburden casing 530. Packing 532 may be placed between overburden casing 530 and opening 522. Packing 532 may be used as a cap at the junction of overburden 458 and hydrocarbon layer 460 to allow filling of materials in the annulus between overburden casing 530 and opening 522. In some embodiments, packing 532 inhibits fluid from flowing from opening 522 to surface 534.
For a temperature limited heater in which the ferromagnetic conductor provides a majority of the resistive heat output below the Curie temperature and/or the phase transformation temperature range, a majority of the current flows through material with highly non-linear functions of magnetic field (H) versus magnetic induction (B). These non-linear functions may cause strong inductive effects and distortion that lead to decreased power factor in the temperature limited heater at temperatures below the Curie temperature and/or the phase transformation temperature range. These effects may render the electrical power supply to the temperature limited heater difficult to control and may result in additional current flow through surface and/or overburden power supply conductors. Expensive and/or difficult to implement control systems such as variable capacitors or modulated power supplies may be used to compensate for these effects and to control temperature limited heaters where the majority of the resistive heat output is provided by current flow through the ferromagnetic material.
In certain temperature limited heater embodiments, the ferromagnetic conductor confines a majority of the flow of electrical current to an electrical conductor coupled to the ferromagnetic conductor when the temperature limited heater is below or near the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor. The electrical conductor may be a sheath, jacket, support member, corrosion resistant member, or other electrically resistive member. In some embodiments, the ferromagnetic conductor confines a majority of the flow of electrical current to the electrical conductor positioned between an outermost layer and the ferromagnetic conductor. The ferromagnetic conductor is located in the cross section of the temperature limited heater such that the magnetic properties of the ferromagnetic conductor at or below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor confine the majority of the flow of electrical current to the electrical conductor. The majority of the flow of electrical current is confined to the electrical conductor due to the skin effect of the ferromagnetic conductor. Thus, the majority of the current is flowing through material with substantially linear resistive properties throughout most of the operating range of the heater.
In certain embodiments, the ferromagnetic conductor and the electrical conductor are located in the cross section of the temperature limited heater so that the skin effect of the ferromagnetic material limits the penetration depth of electrical current in the electrical conductor and the ferromagnetic conductor at temperatures below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor. Thus, the electrical conductor provides a majority of the electrically resistive heat output of the temperature limited heater at temperatures up to a temperature at or near the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor. In certain embodiments, the dimensions of the electrical conductor may be chosen to provide desired heat output characteristics.
Because the majority of the current flows through the electrical conductor below the Curie temperature and/or the phase transformation temperature range, the temperature limited heater has a resistance versus temperature profile that at least partially reflects the resistance versus temperature profile of the material in the electrical conductor. Thus, the resistance versus temperature profile of the temperature limited heater is substantially linear below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor if the material in the electrical conductor has a substantially linear resistance versus temperature profile. For example, the temperature limited heater in which the majority of the current flows in the electrical conductor below the Curie temperature and/or the phase transformation temperature range may have a resistance versus temperature profile similar to the profile shown in
Resistance versus temperature profiles for temperature limited heaters in which the majority of the current flows in the electrical conductor also tend to exhibit sharper reductions in resistance near or at the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor. For example, the reduction in resistance shown in
In certain embodiments, the material and/or the dimensions of the material in the electrical conductor are selected so that the temperature limited heater has a desired resistance versus temperature profile below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor.
Temperature limited heaters in which the majority of the current flows in the electrical conductor rather than the ferromagnetic conductor below the Curie temperature and/or the phase transformation temperature range are easier to predict and/or control. Behavior of temperature limited heaters in which the majority of the current flows in the electrical conductor rather than the ferromagnetic conductor below the Curie temperature and/or the phase transformation temperature range may be predicted by, for example, its resistance versus temperature profile and/or its power factor versus temperature profile. Resistance versus temperature profiles and/or power factor versus temperature profiles may be assessed or predicted by, for example, experimental measurements that assess the behavior of the temperature limited heater, analytical equations that assess or predict the behavior of the temperature limited heater, and/or simulations that assess or predict the behavior of the temperature limited heater.
In certain embodiments, assessed or predicted behavior of the temperature limited heater is used to control the temperature limited heater. The temperature limited heater may be controlled based on measurements (assessments) of the resistance and/or the power factor during operation of the heater. In some embodiments, the power, or current, supplied to the temperature limited heater is controlled based on assessment of the resistance and/or the power factor of the heater during operation of the heater and the comparison of this assessment versus the predicted behavior of the heater. In certain embodiments, the temperature limited heater is controlled without measurement of the temperature of the heater or a temperature near the heater. Controlling the temperature limited heater without temperature measurement eliminates operating costs associated with downhole temperature measurement. Controlling the temperature limited heater based on assessment of the resistance and/or the power factor of the heater also reduces the time for making adjustments in the power or current supplied to the heater compared to controlling the heater based on measured temperature.
As the temperature of the temperature limited heater approaches or exceeds the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor, reduction in the ferromagnetic properties of the ferromagnetic conductor allows electrical current to flow through a greater portion of the electrically conducting cross section of the temperature limited heater. Thus, the electrical resistance of the temperature limited heater is reduced and the temperature limited heater automatically provides reduced heat output at or near the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor. In certain embodiments, a highly electrically conductive member is coupled to the ferromagnetic conductor and the electrical conductor to reduce the electrical resistance of the temperature limited heater at or above the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor. The highly electrically conductive member may be an inner conductor, a core, or another conductive member of copper, aluminum, nickel, or alloys thereof.
The ferromagnetic conductor that confines the majority of the flow of electrical current to the electrical conductor at temperatures below the Curie temperature and/or the phase transformation temperature range may have a relatively small cross section compared to the ferromagnetic conductor in temperature limited heaters that use the ferromagnetic conductor to provide the majority of resistive heat output up to or near the Curie temperature and/or the phase transformation temperature range. A temperature limited heater that uses the electrical conductor to provide a majority of the resistive heat output below the Curie temperature and/or the phase transformation temperature range has low magnetic inductance at temperatures below the Curie temperature and/or the phase transformation temperature range because less current is flowing through the ferromagnetic conductor as compared to the temperature limited heater where the majority of the resistive heat output below the Curie temperature and/or the phase transformation temperature range is provided by the ferromagnetic material. Magnetic field (H) at radius (r) of the ferromagnetic conductor is proportional to the current (I) flowing through the ferromagnetic conductor and the core divided by the radius, or:
H∝I/r. (EQN. 5)
Since only a portion of the current flows through the ferromagnetic conductor for a temperature limited heater that uses the outer conductor to provide a majority of the resistive heat output below the Curie temperature and/or the phase transformation temperature range, the magnetic field of the temperature limited heater may be significantly smaller than the magnetic field of the temperature limited heater where the majority of the current flows through the ferromagnetic material. The relative magnetic permeability (μ) may be large for small magnetic fields.
The skin depth (δ) of the ferromagnetic conductor is inversely proportional to the square root of the relative magnetic permeability (μ):
δ∝(1/μ)1/2. (EQN. 6)
Increasing the relative magnetic permeability decreases the skin depth of the ferromagnetic conductor. However, because only a portion of the current flows through the ferromagnetic conductor for temperatures below the Curie temperature and/or the phase transformation temperature range, the radius (or thickness) of the ferromagnetic conductor may be decreased for ferromagnetic materials with large relative magnetic permeabilities to compensate for the decreased skin depth while still allowing the skin effect to limit the penetration depth of the electrical current to the electrical conductor at temperatures below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor. The radius (thickness) of the ferromagnetic conductor may be between 0.3 mm and 8 mm, between 0.3 mm and 2 mm, or between 2 mm and 4 mm depending on the relative magnetic permeability of the ferromagnetic conductor. Decreasing the thickness of the ferromagnetic conductor decreases costs of manufacturing the temperature limited heater, as the cost of ferromagnetic material tends to be a significant portion of the cost of the temperature limited heater. Increasing the relative magnetic permeability of the ferromagnetic conductor provides a higher turndown ratio and a sharper decrease in electrical resistance for the temperature limited heater at or near the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor.
Ferromagnetic materials (such as purified iron or iron-cobalt alloys) with high relative magnetic permeabilities (for example, at least 200, at least 1000, at least 1×104, or at least 1×105 and/or high Curie temperatures (for example, at least 600° C., at least 700° C., or at least 800° C.) tend to have less corrosion resistance and/or less mechanical strength at high temperatures. The electrical conductor may provide corrosion resistance and/or high mechanical strength at high temperatures for the temperature limited heater. Thus, the ferromagnetic conductor may be chosen primarily for its ferromagnetic properties.
Confining the majority of the flow of electrical current to the electrical conductor below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor reduces variations in the power factor. Because only a portion of the electrical current flows through the ferromagnetic conductor below the Curie temperature and/or the phase transformation temperature range, the non-linear ferromagnetic properties of the ferromagnetic conductor have little or no effect on the power factor of the temperature limited heater, except at or near the Curie temperature and/or the phase transformation temperature range. Even at or near the Curie temperature and/or the phase transformation temperature range, the effect on the power factor is reduced compared to temperature limited heaters in which the ferromagnetic conductor provides a majority of the resistive heat output below the Curie temperature and/or the phase transformation temperature range. Thus, there is less or no need for external compensation (for example, variable capacitors or waveform modification) to adjust for changes in the inductive load of the temperature limited heater to maintain a relatively high power factor.
In certain embodiments, the temperature limited heater, which confines the majority of the flow of electrical current to the electrical conductor below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor, maintains the power factor above 0.85, above 0.9, or above 0.95 during use of the heater. Any reduction in the power factor occurs only in sections of the temperature limited heater at temperatures near the Curie temperature and/or the phase transformation temperature range. Most sections of the temperature limited heater are typically not at or near the Curie temperature and/or the phase transformation temperature range during use. These sections have a high power factor that approaches 1.0. The power factor for the entire temperature limited heater is maintained above 0.85, above 0.9, or above 0.95 during use of the heater even if some sections of the heater have power factors below 0.85.
Maintaining high power factors allows for less expensive power supplies and/or control devices such as solid state power supplies or SCRs (silicon controlled rectifiers). These devices may fail to operate properly if the power factor varies by too large an amount because of inductive loads. With the power factors maintained at high values; however, these devices may be used to provide power to the temperature limited heater. Solid state power supplies have the advantage of allowing fine tuning and controlled adjustment of the power supplied to the temperature limited heater.
In some embodiments, transformers are used to provide power to the temperature limited heater. Multiple voltage taps may be made into the transformer to provide power to the temperature limited heater. Multiple voltage taps allows the current supplied to switch back and forth between the multiple voltages. This maintains the current within a range bound by the multiple voltage taps.
The highly electrically conductive member, or inner conductor, increases the turndown ratio of the temperature limited heater. In certain embodiments, thickness of the highly electrically conductive member is increased to increase the turndown ratio of the temperature limited heater. In some embodiments, the thickness of the electrical conductor is reduced to increase the turndown ratio of the temperature limited heater. In certain embodiments, the turndown ratio of the temperature limited heater is between 1.1 and 10, between 2 and 8, or between 3 and 6 (for example, the turndown ratio is at least 1.1, at least 2, or at least 3).
In certain embodiments, electrical conductor 538 provides support for ferromagnetic conductor 512 and the temperature limited heater. Electrical conductor 538 may be made of a material that provides good mechanical strength at temperatures near or above the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 512. In certain embodiments, electrical conductor 538 is a corrosion resistant member. Electrical conductor 538 (support member 514) may provide support for ferromagnetic conductor 512 and corrosion resistance. Electrical conductor 538 is made from a material that provides desired electrically resistive heat output at temperatures up to and/or above the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 512.
In an embodiment, electrical conductor 538 is 347H stainless steel. In some embodiments, electrical conductor 538 is another electrically conductive, good mechanical strength, corrosion resistant material. For example, electrical conductor 538 may be 304H, 316H, 347HH, NF709, Incoloy® 800H alloy (Inco Alloys International, Huntington, W. Va., U.S.A.), Haynes® HR120® alloy, or Inconel® 617 alloy.
In some embodiments, electrical conductor 538 (support member 514) includes different alloys in different portions of the temperature limited heater. For example, a lower portion of electrical conductor 538 (support member 514) is 347H stainless steel and an upper portion of the electrical conductor (support member) is NF709. In certain embodiments, different alloys are used in different portions of the electrical conductor (support member) to increase the mechanical strength of the electrical conductor (support member) while maintaining desired heating properties for the temperature limited heater.
In some embodiments, ferromagnetic conductor 512 includes different ferromagnetic conductors in different portions of the temperature limited heater. Different ferromagnetic conductors may be used in different portions of the temperature limited heater to vary the Curie temperature and/or the phase transformation temperature range and, thus, the maximum operating temperature in the different portions. In some embodiments, the Curie temperature and/or the phase transformation temperature range in an upper portion of the temperature limited heater is lower than the Curie temperature and/or the phase transformation temperature range in a lower portion of the heater. The lower Curie temperature and/or the phase transformation temperature range in the upper portion increases the creep-rupture strength lifetime in the upper portion of the heater.
In the embodiment depicted in
In some embodiments, the support member and the corrosion resistant member are different members in the temperature limited heater.
In
In
In certain embodiments, the materials and design of the temperature limited heater are chosen to allow use of the heater at high temperatures (for example, above 850° C.).
Core 508 and conductive layer 510 are copper. In some embodiments, core 508 and conductive layer 510 are nickel if the operating temperatures is to be near or above the melting point of copper. Support members 514 are electrically conductive materials with good mechanical strength at high temperatures. Materials for support members 514 that withstand at least a maximum temperature of about 870° C. may be, but are not limited to, MO-RE® alloys (Duraloy Technologies, Inc. (Scottdale, Pa., U.S.A.)), CF8C+ (Metaltek Intl. (Waukesha, Wis., U.S.A.)), or Inconel® 617 alloy. Materials for support members 514 that withstand at least a maximum temperature of about 980° C. include, but are not limited to, Incoloy® Alloy MA 956. Support member 514 in conduit 518 provides mechanical support for the conduit. Support member 514 in conductor 516 provides mechanical support for core 508.
Electrical conductor 538 is a thin corrosion resistant material. In certain embodiments, electrical conductor 538 is 347H, 617, 625, or 800H stainless steel. Ferromagnetic conductor 512 is a high Curie temperature ferromagnetic material such as iron-cobalt alloy (for example, a 15% by weight cobalt, iron-cobalt alloy).
In certain embodiments, electrical conductor 538 provides the majority of heat output of the temperature limited heater at temperatures up to a temperature at or near the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 512. Conductive layer 510 increases the turndown ratio of the temperature limited heater.
For long vertical temperature limited heaters (for example, heaters at least 300 m, at least 500 m, or at least 1 km in length), the hanging stress becomes important in the selection of materials for the temperature limited heater. Without the proper selection of material, the support member may not have sufficient mechanical strength (for example, creep-rupture strength) to support the weight of the temperature limited heater at the operating temperatures of the heater.
In certain embodiments, materials for the support member are varied to increase the maximum allowable hanging stress at operating temperatures of the temperature limited heater and, thus, increase the maximum operating temperature of the temperature limited heater. Altering the materials of the support member affects the heat output of the temperature limited heater below the Curie temperature and/or the phase transformation temperature range because changing the materials changes the resistance versus temperature profile of the support member. In certain embodiments, the support member is made of more than one material along the length of the heater so that the temperature limited heater maintains desired operating properties (for example, resistance versus temperature profile below the Curie temperature and/or the phase transformation temperature range) as much as possible while providing sufficient mechanical properties to support the heater.
In some embodiments, a transition section is used between sections of the heater. For example, if one or more portions of the heater have varying Curie temperatures and/or phase transformation temperature ranges, a transition section may be used between portions to provide strength that compensates for the differences in temperatures in the portions.
The materials of the support member along the length of the temperature limited heater may be varied to achieve a variety of desired operating properties. The choice of the materials of the temperature limited heater is adjusted depending on a desired use of the temperature limited heater. TABLE 2 lists examples of materials that may be used for the support member. The table provides the hanging stresses (σ) of the support members and the maximum operating temperatures of the temperature limited heaters for several different outside diameters (OD) of the support member. The core diameter and the outside diameter of the iron ferromagnetic conductor in each case are 0.5″ and 0.765″, respectively.
In certain embodiments, one or more portions of the temperature limited heater have varying outside diameters and/or materials to provide desired properties for the heater.
In certain embodiments, one or more portions of the temperature limited heater have varying dimensions and/or varying materials to provide different power outputs along the length of the heater. More or less power output may be provided by varying the selected temperature (for example, the Curie temperature and/or the phase transformation temperature range) of the temperature limited heater by using different ferromagnetic materials along its length and/or by varying the electrical resistance of the heater by using different dimensions in the heat generating member along the length of the heater. Different power outputs along the length of the temperature limited heater may be needed to compensate for different thermal properties in the formation adjacent to the heater. For example, an oil shale formation may have different water-filled porosities, dawsonite compositions, and/or nahcolite compositions at different depths in the formation. Portions of the formation with higher water-filled porosities, higher dawsonite compositions, and/or higher nahcolite compositions may need more power input than portions with lower water-filled porosities, lower dawsonite compositions, and/or lower nahcolite compositions to achieve a similar heating rate. Power output may be varied along the length of the heater so that the portions of the formation with different properties (such as water-filled porosities, dawsonite compositions, and/or nahcolite compositions) are heated at approximately the same heating rate.
In certain embodiments, portions of the temperature limited heater have different selected self-limiting temperatures (for example, Curie temperatures and/or phase transformation temperature ranges), materials, and/or dimensions to compensate for varying thermal properties of the formation along the length of the heater. For example, Curie temperatures, phase transformation temperature ranges, support member materials, and/or dimensions of the portions of the heaters depicted in
As one example, in an embodiment of the temperature limited heater depicted in
Reducing the temperature lag between different portions of the formation may reduce the overall time needed to bring the formation to a desired temperature. Reducing the time needed to bring the formation to the desired temperature reduces heating costs and produces desirable production fluids more quickly.
Temperature limited heaters with varying Curie temperatures and/or phase transformation temperature ranges may also have varying support member materials to provide mechanical strength for the heater (for example, to compensate for hanging stress of the heater and/or provide sufficient creep-rupture strength properties). For example, in the embodiment of the temperature limited heater depicted in
Such a substantially vertical temperature limited heater may have less expensive, lower strength materials in portion 552 because of the lower Curie temperature in this portion of the heater. For example, 347H stainless steel may be used for the support member because of the lower maximum operating temperature of portion 552 as compared to portion 550. Portion 550 may require more expensive, higher strength material because of the higher operating temperature of portion 550 due to the higher Curie temperature in this portion.
In some embodiments, a relatively thin conductive layer is used to provide the majority of the electrically resistive heat output of the temperature limited heater at temperatures up to a temperature at or near the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor. Such a temperature limited heater may be used as the heating member in an insulated conductor heater. The heating member of the insulated conductor heater may be located inside a sheath with an insulation layer between the sheath and the heating member.
Inner conductor 490 is a relatively thin conductive layer of non-ferromagnetic material with a higher electrical conductivity than ferromagnetic conductor 512. In certain embodiments, inner conductor 490 is copper. Inner conductor 490 may be a copper alloy. Copper alloys typically have a flatter resistance versus temperature profile than pure copper. A flatter resistance versus temperature profile may provide less variation in the heat output as a function of temperature up to the Curie temperature and/or the phase transformation temperature range. In some embodiments, inner conductor 490 is copper with 6% by weight nickel (for example, CuNi6 or LOHM™). In some embodiments, inner conductor 490 is CuNi10Fe1Mn alloy. Below the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 512, the magnetic properties of the ferromagnetic conductor confine the majority of the flow of electrical current to inner conductor 490. Thus, inner conductor 490 provides the majority of the resistive heat output of insulated conductor 558 below the Curie temperature and/or the phase transformation temperature range.
In certain embodiments, inner conductor 490 is dimensioned, along with core 508 and ferromagnetic conductor 512, so that the inner conductor provides a desired amount of heat output and a desired turndown ratio. For example, inner conductor 490 may have a cross-sectional area that is around 2 or 3 times less than the cross-sectional area of core 508. Typically, inner conductor 490 has to have a relatively small cross-sectional area to provide a desired heat output if the inner conductor is copper or copper alloy. In an embodiment with copper inner conductor 490, core 508 has a diameter of 0.66 cm, ferromagnetic conductor 512 has an outside diameter of 0.91 cm, inner conductor 490 has an outside diameter of 1.03 cm, electrical insulator 500 has an outside diameter of 1.53 cm, and jacket 506 has an outside diameter of 1.79 cm. In an embodiment with a CuNi6 inner conductor 490, core 508 has a diameter of 0.66 cm, ferromagnetic conductor 512 has an outside diameter of 0.91 cm, inner conductor 490 has an outside diameter of 1.12 cm, electrical insulator 500 has an outside diameter of 1.63 cm, and jacket 506 has an outside diameter of 1.88 cm. Such insulated conductors are typically smaller and cheaper to manufacture than insulated conductors that do not use the thin inner conductor to provide the majority of heat output below the Curie temperature and/or the phase transformation temperature range.
Electrical insulator 500 may be magnesium oxide, aluminum oxide, silicon dioxide, beryllium oxide, boron nitride, silicon nitride, or combinations thereof. In certain embodiments, electrical insulator 500 is a compacted powder of magnesium oxide. In some embodiments, electrical insulator 500 includes beads of silicon nitride.
In certain embodiments, a small layer of material is placed between electrical insulator 500 and inner conductor 490 to inhibit copper from migrating into the electrical insulator at higher temperatures. For example, the small layer of nickel (for example, about 0.5 mm of nickel) may be placed between electrical insulator 500 and inner conductor 490.
Jacket 506 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, jacket 506 provides some mechanical strength for insulated conductor 558 at or above the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 512. In certain embodiments, jacket 506 is not used to conduct electrical current.
In certain embodiments of temperature limited heaters, three temperature limited heaters are coupled together in a three-phase wye configuration. Coupling three temperature limited heaters together in the three-phase wye configuration lowers the current in each of the individual temperature limited heaters because the current is split between the three individual heaters. Lowering the current in each individual temperature limited heater allows each heater to have a small diameter. The lower currents allow for higher relative magnetic permeabilities in each of the individual temperature limited heaters and, thus, higher turndown ratios. In addition, there may be no return current needed for each of the individual temperature limited heaters. Thus, the turndown ratio remains higher for each of the individual temperature limited heaters than if each temperature limited heater had its own return current path.
In the three-phase wye configuration, individual temperature limited heaters may be coupled together by shorting the sheaths, jackets, or canisters of each of the individual temperature limited heaters to the electrically conductive sections (the conductors providing heat) at their terminating ends (for example, the ends of the heaters at the bottom of a heater wellbore). In some embodiments, the sheaths, jackets, canisters, and/or electrically conductive sections are coupled to a support member that supports the temperature limited heaters in the wellbore.
In
Insulated conductors 558 may be electrically coupled to each other at a lower end of the insulated conductors. In a three-phase wye configuration, insulated conductors 558 operate without a current return path. In certain embodiments, insulated conductors 558 are electrically coupled to each other in contactor section 566. In section 566, sheaths, jackets, canisters, and/or electrically conductive sections are electrically coupled to each other and/or to support member 560 so that insulated conductors 558 are electrically coupled in the section.
In certain embodiments, the sheaths of insulated conductors 558 are shorted to the conductors of the insulated conductors.
The sheaths of individual insulated conductors 558 may be shorted together to electrically couple the conductors of the insulated conductors, depicted in
In certain embodiments, coupling multiple heaters (for example, insulated conductor, or mineral insulated conductor, heaters) to a single power source, such as a transformer, is advantageous. Coupling multiple heaters to a single transformer may result in using fewer transformers to power heaters used for a treatment area as compared to using individual transformers for each heater. Using fewer transformers reduces surface congestion and allows easier access to the heaters and surface components. Using fewer transformers reduces capital costs associated with providing power to the treatment area. In some embodiments, at least 4, at least 5, at least 10, at least 25 heaters, at least 35 heaters, or at least 45 heaters are powered by a single transformer. Additionally, powering multiple heaters (in different heater wells) from the single transformer may reduce overburden losses because of reduced voltage and/or phase differences between each of the heater wells powered by the single transformer. Powering multiple heaters from the single transformer may inhibit current imbalances between the heaters because the heaters are coupled to the single transformer.
In order to provide power to multiple heaters using the single transformer, the transformer may have to provide power at higher voltages to carry the current to each of the heaters effectively. In certain embodiments, the heaters are floating (ungrounded) heaters in the formation. Floating the heaters allows the heaters to operate at higher voltages. In some embodiments, the transformer provides power output of at least about 3 kV, at least about 4 kV, at least about 5 kV, or at least about 6 kV.
In some embodiments, core 508 and/or jacket 506 include ferromagnetic materials. In some embodiments, one or more insulated conductors 558 are temperature limited heaters. In certain embodiments, the overburden portion of insulated conductors 558 include high electrical conductivity materials in core 508 (for example, pure copper or copper alloys such as copper with 3% silicon at a weld joint) so that the overburden portions of the insulated conductors provide little or no heat output. In certain embodiments, conduit 536 includes non-corrosive materials and/or high strength materials such as stainless steel. In one embodiment, conduit 536 is 347H stainless steel.
Insulated conductors 558 may be coupled to the single transformer in a three-phase configuration (for example, a three-phase wye configuration). Each insulated conductor 558 may be coupled to one phase of the single transformer. In certain embodiments, the single transformer is also coupled to a plurality of identical heaters 716 in other heater wells in the formation (for example, the single transformer may couple to 40 heaters or more in the formation). In some embodiments, the single transformer couples to at least 4, at least 5, at least 10, at least 15, or at least 25 additional heaters in the formation.
Electrical insulator 500′ may be located inside conduit 536 to electrically insulate insulated conductors 558 from the conduit. In certain embodiments, electrical insulator 500′ is magnesium oxide (for example, compacted magnesium oxide). In some embodiments, electrical insulator 500′ is silicon nitride (for example, silicon nitride blocks). Electrical insulator 500′ electrically insulates insulated conductors 558 from conduit 536 so that at high operating voltages (for example, 3 kV or higher), there is no arcing between the conductors and the conduit. In some embodiments, electrical insulator 500′ inside conduit 536 has at least the thickness of electrical insulators 500 in insulated conductors 558. The increased thickness of insulation in heater 716 (from electrical insulators 500 and/or electrical insulator 500′) inhibits and may prevent current leakage into the formation from the heater. In some embodiments, electrical insulator 500′ spatially locates insulated conductors 558 inside conduit 536.
Return conductor 2024 may be electrically coupled to the ends of insulated conductors 558 (as shown in
In certain embodiments, heater 716, depicted in
Heaters that include three insulated conductors 558 in conduit 536, as depicted in
Insulated conductors 558 may be pre-assembled prior to the bundling either on site or at a remote location. Insulated conductors 558 and return conductor 2024 may be positioned on spools. A machine may draw insulated conductors 558 and return conductor 2024 from the spools at a selected rate. Preformed blocks of insulation material may be positioned around return conductor 2024 and insulated conductors 558. In an embodiment, two blocks are positioned around return conductor 2024 and three blocks are positioned around insulated conductors 558 to form electrical insulator 500′. The insulated conductors and return conductor may be drawn or pushed into a plate of conduit material that has been rolled into a tubular shape. The edges of the plate may be pressed together and welded (for example, by laser welding). After forming conduit 536 around electrical insulator 500′, the bundle of insulated conductors 558, and return conductor 2024, the conduit may be compacted against the electrical insulator 2024 so that all of the components of the heater are pressed together into a compact and tightly fitting form. During the compaction, the electrical insulator may flow and fill any gaps inside the heater.
In some embodiments, heater 716 (which includes conduit 536 around electrical insulator 500′ and the bundle of insulated conductors 558 and return conductor 2024) is inserted into a coiled tubing tubular that is placed in a wellbore in the formation. The coiled tubing tubular may be left in place in the formation (left in during heating of the formation) or removed from the formation after installation of the heater. The coiled tubing tubular may allow for easier installation of heater 716 into the wellbore.
In some embodiments, one or more components of heater 716 are varied (for example, removed, moved, or replaced) while the operation of the heater remains substantially identical.
Electrical insulator 500 may be magnesium oxide, aluminum oxide, silicon dioxide, beryllium oxide, boron nitride, silicon nitride, or combinations thereof. In certain embodiments, electrical insulator 500 is a compacted powder of magnesium oxide. In some embodiments, electrical insulator 500 includes beads of silicon nitride. In certain embodiments, a small layer of material is placed between electrical insulator 500 and core 508 to inhibit copper from migrating into the electrical insulator at higher temperatures. For example, the small layer of nickel (for example, about 0.5 mm of nickel) may be placed between electrical insulator 500 and core 508.
Jacket 506 may be made of a corrosion resistant material such as, but not limited to, nickel, Alloy N (Carpenter Metals), 347 stainless steel, 347H stainless steel, 446 stainless steel, or 825 stainless steel. In some embodiments, jacket 506 is not used to conduct electrical current. In some embodiments where molten metal is the material in the conduit, current returns through the molten metal in the conduit and/or through the conduit.
In some embodiments where molten metal is the material in the conduit, the molten metal in the conduit is more resistive than the material of the jacket and the conduit. The electricity that passes through the molten metal in the conduit may resistively heat the molten metal. In some embodiments, the conduit is made of a ferromagnetic material, (for example 410 stainless steel). The conduit may function as a temperature limited heater with the magnetic field of the conduit controlling the location of the return current flow until the temperature of the conduit approaches, reaches or exceeds the Curie temperature or phase transition temperature of the conduit material.
In an embodiment, core 508 has a diameter of about 1 cm, electrical insulator 500 has an outside diameter of about 1.6 cm, and jacket 506 has an outside diameter of about 1.8 cm.
Material 2026 in conduit may be a molten metal or molten metal salt. Material 2026 may be placed inside conduit 518 in the space outside of insulated conductor 558. In certain embodiments, material 2026 is placed in the conduit in a solid form as balls or pellets. Material 2026 may be made of metal or metal salt that melts below operating temperatures of insulated conductor 558 but above ambient subsurface formation temperatures. Material 2026 may be placed in conduit 518 after insulated conductor 558 is placed in the conduit. In certain embodiments, material 2026 is placed in as a molten liquid. The molten liquid may be placed in conduit 518 before or after insulated conductor 558 is placed in the conduit (for example, the molten liquid may be poured into the conduit before or after the insulated conductor is placed in the conduit). Additionally, material 2026 may be placed in conduit 518 before or after insulated conductor 558 is energized (turned on).
Material 2026 may remain a molten liquid at operating temperatures of insulated conductor 558. In some embodiments, material 2026 melts at temperatures above about 100° C., above about 200° C., or above about 300° C. Material 2026 may remain a molten liquid at temperatures up to about 1400° C., about 1500° C., or about 1600° C. In certain embodiments, material 2026 is a good thermal conductor at or near the operating temperatures of insulated conductor 558. Material 2026 may include metals such as tin, zinc, an alloy such as a 60% by weight tin, 40% by weight zinc alloy; bismuth; indium; cadmium, aluminum; lead; and/or combinations thereof (for example, eutectic alloys of these metals such as binary or ternary alloys). In one embodiment, molten metal 2026 is tin. Molten metal 2026 may have a high Grashof number. Molten metals with high Grashof numbers will provide good convection currents in conduit 518. Material 2026 may include metal salts (for example, the metal salts presented in Table 3).
Material 2026 fills the space between conduit 518 and insulated conductor 558. Material 2026 may increase heat transfer between conduit 518 and insulated conductor 558 by heat conduction through the material and/or heat convection from movement of the material in the conduit. The temperature differential between conduit 518 and insulated conductor 558 may create convection currents (heat generated movement) in the conduit. Convection of material 2026 may inhibit hot spots along conduit 518 and insulated conductor 558. Using material 2026 allows insulated conductor 558 to be a smaller diameter insulated conductor, which may be easier and/or cheaper to manufacture.
In some embodiments, material 2026 returns electrical current to the surface from insulated conductor 558 (the molten metal acts as the return or ground conductor for the insulated conductor). Material 2026 may provide a current path with low resistance so that a long heater (long insulated conductor 558) is useable in conduit 518. Material 2026 may also inhibit skin effects in conduit 518, which allows longer heaters with lower voltages. The long heater may operate at low voltages for the length of the heater due to the presence of molten metal 2026.
In certain embodiments, insulated conductor 558 is buoyant in material 2026 in conduit 518. The buoyancy of insulated conductor 558 reduces creep associated problems in long, substantially vertical heaters. A bottom weight or tie down may be coupled to the bottom of insulated conductor 558 to inhibit the insulated conductor from floating in material 2026.
Conduit 518 may be a carbon steel or stainless steel canister. Conduit 518 may include inner cladding that is corrosion resistant to the molten metal or metal salt in the conduit. If the conduit contains a metal salt, the conduit may include nickel cladding, or the conduit may be or include a liner of a corrosion resistant metal such as Alloy N. If the conduit contains a molten metal, the conduit may include a corrosion resistant metal liner or coating, and/or a ceramic coating (for example, a porcelain coating or fired enamel coating). In an embodiment, conduit 518 is a canister of 410 stainless steel with an outside diameter of about 6 cm. Conduit 518 may not need a thick wall because material 2026 may provide internal pressure that inhibits deformation or crushing of the conduit due to external stresses.
In some embodiments, heat pipes are placed in the formation. The heat pipes may reduce the number of active heat sources needed to heat a treatment area of a given size. The heat pipes may reduce the time needed to heat the treatment area of a given size to a desired average temperature. A heat pipe is a closed system that utilizes phase change of fluid in the heat pipe to transport heat applied to a first region to a second region remote from the first region. The phase change of the fluid allows for large heat transfer rates. Heat may be applied to the first region of the heat pipes from any type of heat source, including but not limited to, electric heaters, oxidizers, heat provided from geothermal sources, and/or heat provided from nuclear reactors.
Heat pipes are passive heat transport systems that include no moving parts. Heat pipes may be positioned in near horizontal to vertical configurations. The fluid used in heat pipes for heating the formation may have a low cost, a low melting temperature, a boiling temperature that is not too high (e.g., generally below about 900° C.), a low viscosity at temperatures below above about 540° C., a high heat of vaporization, and a low corrosion rate for the heat pipe material. In some embodiments, the heat pipe includes a liner of material that is resistant to corrosion by the fluid. TABLE 3 shows melting and boiling temperatures for several materials that may be used as the fluid in heat pipes.
Heat pipes 2420 may include sealed conduit 2422, seal 2424, liquid heat transfer fluid 2426 and vaporized heat transfer fluid 2428. In some embodiments, heat pipes 2420 include metal mesh or wicking material that increases the surface area for condensation and/or promotes flow of the heat transfer fluid in the heat pipe. Conduit 2422 may have first portion 2430 and second portion 2432. Liquid heat transfer fluid 2426 may be in first portion 2430. Heat source 202 external to heat pipe 2420 supplies heat that vaporizes liquid heat transfer fluid 2426. Vaporized heat transfer fluid 2428 diffuses into second portion 2432. Vaporized heat transfer fluid 2428 condenses in second portion and transfers heat to conduit 2422, which in turn transfers heat to the formation. The condensed liquid heat transfer fluid 2426 flows by gravity to first portion 2430.
Position of seal 2424 is a factor in determining the effective length of heat pipe 2420. The effective length of heat pipe 2420 may also depend on the physical properties of the heat transfer fluid and the cross-sectional area of conduit 2422. Enough heat transfer fluid may be placed in conduit 2422 so that some liquid heat transfer fluid 2426 is present in first portion 2430 at all times.
Seal 2424 may provide a top seal for conduit 2422. In some embodiments, conduit 2422 is purged with nitrogen, helium or other fluid prior to being loaded with heat transfer fluid and sealed. In some embodiments, a vacuum may be drawn on conduit 2422 to evacuate the conduit before the conduit is sealed. Drawing a vacuum on conduit 2422 before sealing the conduit may enhance vapor diffusion throughout the conduit. In some embodiments, an oxygen getter may be introduced in conduit 2422 to react with any oxygen present in the conduit.
In some embodiments, a long temperature limited heater (for example, a temperature limited heater in which the support member provides a majority of the heat output below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor) is formed from several sections of heater. The sections of heater may be coupled using a welding process.
Beveled ends of ferromagnetic conductors 512 and electrical conductors 538 may be coupled together with coupling material 572. In certain embodiments, ends of ferromagnetic conductors 512 and electrical conductors 538 are welded (for example, orbital welded) together. Coupling material 572 may be 625 stainless steel or any other suitable non-ferromagnetic material for welding together ferromagnetic conductors 512 and/or electrical conductors 538. Using beveled ends when coupling together sections of the heater may produce a reliable and durable coupling between the sections of the heater.
During heating with the temperature limited heater, core coupling material 570 may expand more radially than ferromagnetic conductors 512, electrical conductors 538, and/or coupling material 572. The greater expansion of core coupling material 570 maintains good electrical contact with the core coupling material. At the coupling junction of the heater, electricity flows through core coupling material 570 rather than coupling material 572. This flow of electricity inhibits heat generation at the coupling junction so that the junction remains at lower temperatures than other portions of the heater during application of electrical current to the heater. The corrosion resistance and strength of the coupling junction is increased by maintaining the junction at lower temperatures.
In certain embodiments, the junction may be enclosed in a shield during orbital welding to enhance and/or ensure reliability of the weld. If the junction is not enclosed, disturbance of the inert gas caused by wind, humidity or other conditions may cause oxidation and/or porosity of the weld. Without a shield, a first portion of the weld was formed and allowed to cool. A grinder would be used to remove the oxide layer. The process would be repeated until the weld was complete. Enclosing the junction in the shield with an inert gas allows the weld to be formed with no oxidation, thus allowing the weld to be formed in one pass with no need for grinding. Enclosing the junction increases the safety of forming the weld because the arc of the orbital welder is enclosed in the shield during welding. Enclosing the junction in the shield may reduce the time needed to form the weld. Without a shield, producing each weld may take 30 minutes or more. With the shield, each weld may take 10 minutes or less.
Hinged door 584 may be closed. When hinged door 584 is closed, shield 574 forms a substantially airtight seal around the portions to be welded together. The orbital welder may be located inside the shield. The orbital welder may weld the lower conductor to the upper conductor. In certain embodiments, an inert gas (such as argon or krypton) is provided through openings (for example, gas feedthroughs) in wall 582. The inert gas may be provided so that the interior of shield 574 is substantially or completely flushed with the inert gas and any oxidizing fluid (for example, oxygen) is removed from inside the shield. A gas exit (for example, a gas outlet or gas exit feedthrough) may allow gas to be flushed through shield 574. Having the inert gas inside shield 574 during the welding process and removing oxidizing fluids (such as oxygen) from inside the shield, inhibits oxidization from occurring during the welding process. Inhibiting oxidation during the welding process inhibits the formation of oxide layers on the metals being welded and provides a more reliable welding process, a faster welding process, and a more reliable weld junction.
In certain embodiments, a positive pressure of inert gas is maintained inside shield 574 during the welding process. The positive pressure of inert gas inhibits outside gases (for example, oxygen or other oxidizing gases) from entering the shield, even if the shield has one or more leaks. In some embodiments, a vacuum may be pulled on shield 574 before providing the inert gas into the shield and/or before welding the portions together. Pulling a vacuum on the shield may remove contaminants such as particulates from inside the shield.
Progress of the welding operation may be monitored through viewing windows 590. When the weld is complete, shield 574 may be supported and first clamp member 586 may be unfastened from second clamp member 588. One or both inserts 580 may be removed or partially removed from lower plate 578 and upper plate 576 to facilitate lowering of the conductor. The conductor may be lowered in the wellbore until the end of the conductor is located at a desired position in shield 574. Shield 574 may be secured to the conductor with first clamp member 586 and second clamp member 588. Another conductor may be positioned in the shield. Inserts 580 may be positioned in upper and lower plates 576, 578; hinged door is closed 584; and the orbital welder is used to weld the conductors together. The process may be repeated until a desired length of conductor is formed.
The shield may be used to weld joints of pipe over an opening in the hydrocarbon containing formation. Hydrocarbon vapors from the formation may create an explosive atmosphere in the shield even though the inert gas supplied to the shield inhibits the formation of dangerous concentrations of hydrocarbons in the shield. A control circuit may be coupled to a power supply for the orbital welder to stop power to the orbital welder to shut off the arc forming the weld if the hydrocarbon level in the shield rises above a selected concentration.
In some embodiments, the temperature limited heater is used to achieve lower temperature heating (for example, for heating fluids in a production well, heating a surface pipeline, or reducing the viscosity of fluids in a wellbore or near wellbore region). Varying the ferromagnetic materials of the temperature limited heater allows for lower temperature heating. In some embodiments, the ferromagnetic conductor is made of material with a lower Curie temperature than that of 446 stainless steel. For example, the ferromagnetic conductor may be an alloy of iron and nickel. The alloy may have between 30% by weight and 42% by weight nickel with the rest being iron. In one embodiment, the alloy is Invar 36. Invar 36 is 36% by weight nickel in iron and has a Curie temperature of 277° C. In some embodiments, an alloy is a three component alloy with, for example, chromium, nickel, and iron. For example, an alloy may have 6% by weight chromium, 42% by weight nickel, and 52% by weight iron. A 2.5 cm diameter rod of Invar 36 has a turndown ratio of approximately 2 to 1 at the Curie temperature. Placing the Invar 36 alloy over a copper core may allow for a smaller rod diameter. A copper core may result in a high turndown ratio. The insulator in lower temperature heater embodiments may be made of a high performance polymer insulator (such as PFA or PEEK™) when used with alloys with a Curie temperature that is below the melting point or softening point of the polymer insulator.
In certain embodiments, a conductor-in-conduit temperature limited heater is used in lower temperature applications by using lower Curie temperature and/or the phase transformation temperature range ferromagnetic materials. For example, a lower Curie temperature and/or the phase transformation temperature range ferromagnetic material may be used for heating inside sucker pump rods. Heating sucker pump rods may be useful to lower the viscosity of fluids in the sucker pump or rod and/or to maintain a lower viscosity of fluids in the sucker pump rod. Lowering the viscosity of the oil may inhibit sticking of a pump used to pump the fluids. Fluids in the sucker pump rod may be heated up to temperatures less than about 250° C. or less than about 300° C. Temperatures need to be maintained below these values to inhibit coking of hydrocarbon fluids in the sucker pump system.
Conductive section 504 electrically couples inner conductor 490 to outer conductor 502 and/or jacket 506. In some embodiments, jacket 506 touches or electrically contacts conductive layer 510 (for example, if the heater is placed in a horizontal configuration). If jacket 506 is a ferromagnetic metal such as carbon steel (with a Curie temperature above the Curie temperature of outer conductor 502), current will propagate only on the inside of the jacket. Thus, the outside of the jacket remains electrically uncharged during operation. In some embodiments, jacket 506 is drawn down (for example, swaged down in a die) onto conductive layer 510 so that a tight fit is made between the jacket and the conductive layer. The heater may be spooled as coiled tubing for insertion into a wellbore. In other embodiments, an annular space is present between conductive layer 510 and jacket 506, as depicted in
In one embodiment, conductor 516 is 304 stainless steel and ferromagnetic conductor 512 is 446 stainless steel. Conductor 516 and ferromagnetic conductor 512 are electrically coupled to conduit 518 with sliding connector 528. Conduit 518 may be a non-ferromagnetic material such as austenitic stainless steel.
In certain embodiments, a temperature limited heater includes a flexible cable (for example, a furnace cable) as the inner conductor. For example, the inner conductor may be a 27% nickel-clad or stainless steel-clad stranded copper wire with four layers of mica tape surrounded by a layer of ceramic and/or mineral fiber (for example, alumina fiber, aluminosilicate fiber, borosilicate fiber, or aluminoborosilicate fiber). A stainless steel-clad stranded copper wire furnace cable may be available from Anomet Products, Inc. The inner conductor may be rated for applications at temperatures of 1000° C. or higher. The inner conductor may be pulled inside a conduit. The conduit may be a ferromagnetic conduit (for example, a ¾″ Schedule 80 446 stainless steel pipe). The conduit may be covered with a layer of copper, or other electrical conductor, with a thickness of about 0.3 cm or any other suitable thickness. The assembly may be placed inside a support conduit (for example, a 1¼″ Schedule 80 347H or 347HH stainless steel tubular). The support conduit may provide additional creep-rupture strength and protection for the copper and the inner conductor. For uses at temperatures greater than about 1000° C., the inner copper conductor may be plated with a more corrosion resistant alloy (for example, Incoloy® 825) to inhibit oxidation. In some embodiments, the top of the temperature limited heater is sealed to inhibit air from contacting the inner conductor.
The temperature limited heater may be a single-phase heater or a three-phase heater. In a three-phase heater embodiment, the temperature limited heater has a delta or a wye configuration. Each of the three ferromagnetic conductors in the three-phase heater may be inside a separate sheath. A connection between conductors may be made at the bottom of the heater inside a splice section. The three conductors may remain insulated from the sheath inside the splice section.
In some embodiments, the three-phase heater includes three legs that are located in separate wellbores. The legs may be coupled in a common contacting section (for example, a central wellbore, a connecting wellbore, or a solution filled contacting section).
In certain embodiments, heating elements 630 are exposed to hydrocarbon layer 460 and fluids from the hydrocarbon layer. Thus, heating elements 630 are “bare metal” or “exposed metal” heating elements. Heating elements 630 may be made from a material that has an acceptable sulfidation rate at high temperatures used for pyrolyzing hydrocarbons. In certain embodiments, heating elements 630 are made from material that has a sulfidation rate that decreases with increasing temperature over at least a certain temperature range (for example, 500° C. to 650° C., 530° C. to 650° C., or 550° C. to 650° C.). For example, 410 stainless steel may have a sulfidation rate that decreases with increasing temperature between 530° C. and 650° C. Using such materials reduces corrosion problems due to sulfur-containing gases (such as H2S) from the formation. In certain embodiments, heating elements 630 are made from material that has a sulfidation rate below a selected value in a temperature range. In some embodiments, heating elements 630 are made from material that has a sulfidation rate at most about 25 mils per year at a temperature between about 800° C. and about 880° C. In some embodiments, the sulfidation rate is at most about 35 mils per year at a temperature between about 800° C. and about 880° C., at most about 45 mils per year at a temperature between about 800° C. and about 880° C., or at most about 55 mils per year at a temperature between about 800° C. and about 880° C. Heating elements 630 may also be substantially inert to galvanic corrosion.
In some embodiments, heating elements 630 have a thin electrically insulating layer such as aluminum oxide or thermal spray coated aluminum oxide. In some embodiments, the thin electrically insulating layer is a ceramic composition such as an enamel coating. Enamel coatings include, but are not limited to, high temperature porcelain enamels. High temperature porcelain enamels may include silicon dioxide, boron oxide, alumina, and alkaline earth oxides (CaO or MgO), and minor amounts of alkali oxides (Na2O, K2O, LiO). The enamel coating may be applied as a finely ground slurry by dipping the heating element into the slurry or spray coating the heating element with the slurry. The coated heating element is then heated in a furnace until the glass transition temperature is reached so that the slurry spreads over the surface of the heating element and makes the porcelain enamel coating. The porcelain enamel coating contracts when cooled below the glass transition temperature so that the coating is in compression. Thus, when the coating is heated during operation of the heater, the coating is able to expand with the heater without cracking.
The thin electrically insulating layer has low thermal impedance allowing heat transfer from the heating element to the formation while inhibiting current leakage between heating elements in adjacent openings and/or current leakage into the formation. In certain embodiments, the thin electrically insulating layer is stable at temperatures above at least 350° C., above 500° C., or above 800° C. In certain embodiments, the thin electrically insulating layer has an emissivity of at least 0.7, at least 0.8, or at least 0.9. Using the thin electrically insulating layer may allow for long heater lengths in the formation with low current leakage.
Heating elements 630 may be coupled to contacting elements 632 at or near the underburden of the formation. Contacting elements 632 are copper or aluminum rods or other highly conductive materials. In certain embodiments, transition sections 638 are located between lead-in conductors 636 and heating elements 630, and/or between heating elements 630 and contacting elements 632. Transition sections 638 may be made of a conductive material that is corrosion resistant such as 347 stainless steel over a copper core. In certain embodiments, transition sections 638 are made of materials that electrically couple lead-in conductors 636 and heating elements 630 while providing little or no heat output. Thus, transition sections 638 help to inhibit overheating of conductors and insulation used in lead-in conductors 636 by spacing the lead-in conductors from heating elements 630. Transition section 638 may have a length of between about 3 m and about 9 m (for example, about 6 m).
Contacting elements 632 are coupled to contactor 640 in contacting section 642 to electrically couple legs 624, 626, 628 to each other. In some embodiments, contact solution 644 (for example, conductive cement) is placed in contacting section 642 to electrically couple contacting elements 632 in the contacting section. In certain embodiments, legs 624, 626, 628 are substantially parallel in hydrocarbon layer 460 and leg 624 continues substantially vertically into contacting section 642. The other two legs 626, 628 are directed (for example, by directionally drilling the wellbores for the legs) to intercept leg 624 in contacting section 642.
Each leg 624, 626, 628 may be one leg of a three-phase heater embodiment so that the legs are substantially electrically isolated from other heaters in the formation and are substantially electrically isolated from the formation. Legs 624, 626, 628 may be arranged in a triangular pattern so that the three legs form a triangular shaped three-phase heater. In an embodiment, legs 624, 626, 628 are arranged in a triangular pattern with 12 m spacing between the legs (each side of the triangle has a length of 12 m).
In certain embodiments, centralizers 524 are made of three or more parts coupled to heater 716 so that the parts are spaced around the outside diameter of the heater. Having spaces between the parts of a centralizer allows debris to fall along the heater (when the heater is vertical or substantially vertical) and inhibit debris from collecting at the centralizer. In certain embodiments, the centralizer is installed on a long heater without inserting a ring.
In certain embodiments, centralizer parts 524A, 524B, 524C include insulators 2594 and weld bases 2596. Insulators 2594 may be made of electrically insulating material such as, but not limited to, ceramic (magnesium oxide) or silicon nitride. Weld bases 2596 may be made of weldable metal such as, but not limited to, Alloy 625, the same metal used for heater 716, or another metal that may be brazed or solid state welded to insulators 2594 and welded to a metal used for heater 716.
In certain embodiments, insulators 2594 are brazed, or otherwise coupled, to weld bases 2596 to form centralizer parts 524A, 524B, 524C. In some embodiments, weld bases 2596 are coupled to heater 716 first and then insulators 2594 are coupled to the weld bases to form centralizer parts 524A, 524B, 524C. Insulators 2594 may be coupled to weld bases 2596 as the heater is being installed into the formation.
In certain embodiments, centralizer parts 524A, 524B, 524C are spaced evenly around the outside diameter of heater 716, as shown in
Having space between centralizer parts 524A, 524B, 524C allows installation of the heaters and centralizers from a spool or coiled tubing installation of the heaters and centralizers. Centralizer parts 524A, 524B, 524C also allow debris (for example, metal dust or pieces of formation) to fall along heater 716 through the area of the centralizer. Thus, debris is inhibited from collecting at or near centralizer 524. In addition, centralizer parts 524A, 524B, 524C may be inexpensive to manufacture and install and easy to replace if broken.
In certain embodiments, the thin electrically insulating layer allows for relatively long, substantially horizontal heater leg lengths in the hydrocarbon layer with a substantially u-shaped heater.
In certain embodiments, overburden casings (for example, overburden casings 530, depicted in
In certain embodiments, one or more non-ferromagnetic materials used in casings 530 are used in a wellhead coupled to the casings and legs 624, 626, 628. Using non-ferromagnetic materials in the wellhead inhibits undesirable heating of components in the wellhead. In some embodiments, a purge gas (for example, carbon dioxide, nitrogen or argon) is introduced into the wellhead and/or inside of casings 530 to inhibit reflux of heated gases into the wellhead and/or the casings.
In certain embodiments, one or more of legs 624, 626, 628 are installed in the formation using coiled tubing. In certain embodiments, coiled tubing is installed in the formation, the leg is installed inside the coiled tubing, and the coiled tubing is pulled out of the formation to leave the leg installed in the formation. The leg may be placed concentrically inside the coiled tubing. In some embodiments, coiled tubing with the leg inside the coiled tubing is installed in the formation and the coiled tubing is removed from the formation to leave the leg installed in the formation. The coiled tubing may extend only to a junction of hydrocarbon layer 460 and contacting section 642 (shown in
The phases of each triad 652 may be arranged so that legs A, B, C correspond between triads as shown in
In the early stages of heating, an exposed heating element (for example, heating element 630 depicted in
Using the temperature limited heaters as the heating elements limits the effect of water saturation on heater efficiency. With water in the formation and in heater wellbores, there is a tendency for electrical current to flow between heater elements at the top of the hydrocarbon layer where the voltage is highest and cause uneven heating in the hydrocarbon layer. This effect is inhibited with temperature limited heaters because the temperature limited heaters reduce localized overheating in the heating elements and in the hydrocarbon layer.
In certain embodiments, production wells are placed at a location at which there is relatively little or zero voltage potential. This location minimizes stray potentials at the production well. Placing production wells at such locations improves the safety of the system and reduces or inhibits undesired heating of the production wells caused by electrical current flow in the production wells.
Production well 206 may be placed at or near the center of hexagon 656. Placing production well 206 at or near the center of hexagon 656 places the production well at a location that reduces or inhibits undesired heating due to electromagnetic effects caused by electrical current flow in the legs of the triads and increases the safety of the system. Having two triads in hexagon 656 provides for redundant heating around production well 206. Thus, if one triad fails or has to be turned off, production well 206 still remains at a center of one triad.
As shown in
Triads of heaters and/or heater legs may be arranged in any shape or desired pattern. For example, as described above, triads may include three heaters and/or heater legs arranged in an equilateral triangular pattern. In some embodiments, triads include three heaters and/or heater legs arranged in other triangular shapes (for example, an isosceles triangle or a right angle triangle). In some embodiments, heater legs in the triad cross each other (for example, criss-cross) in the formation. In certain embodiments, triads includes three heaters and/or heater legs arranged sequentially along a straight line.
Contacting elements 632 are coupled to contactor 640 in contacting section 642 to electrically couple legs 624A, 626A, 628A to each other to form triad 652A and electrically couple legs 624B, 626B, 628B to each other to form triad 652B. In certain embodiments, contactor 640 is a ground conductor so that triad 652A and/or triad 652B may be coupled in three-phase wye configurations. In certain embodiments, triad 652A and triad 652B are electrically isolated from each other. In some embodiments, triad 652A and triad 652B are electrically coupled to each other (for example, electrically coupled in series or parallel).
In certain embodiments, contactor 640 is a substantially horizontal contactor located in contacting section 642. Contactor 640 may be a casing or a solid rod placed in a wellbore drilled substantially horizontally in contacting section 642. Legs 624A, 626A, 628A and legs 624B, 626B, 628B may be electrically coupled to contactor 640 by any method described herein or any method known in the art. For example, containers with thermite powder are coupled to contactor 640 (for example, by welding or brazing the containers to the contactor); legs 624A, 626A, 628A and legs 624B, 626B, 628B are placed inside the containers; and the thermite powder is activated to electrically couple the legs to the contactor. The containers may be coupled to contactor 640 by, for example, placing the containers in holes or recesses in contactor 640 or coupled to the outside of the contactor and then brazing or welding the containers to the contactor.
As shown in
Container 658 is coupled to contacting element 632 of leg 624. Container 658 may be soldered, welded, or otherwise electrically coupled to contacting element 632. Container 658 is a metal can or other container with at least one opening for receiving one or more contacting elements 632. In an embodiment, container 658 is a can that has an opening for receiving contacting elements 632 from legs 626, 628, as shown in
In some embodiments, contacting elements 632 contact the bottom of container 658. Contacting elements 632 may contact the bottom of container 658 and/or each other to promote electrical connection between the contacting elements and/or the container. In certain embodiments, end portions of contacting elements 632 are annealed to a “dead soft” condition to facilitate entry into container 658. In some embodiments, rubber or other softening material is attached to end portions of contacting elements 632 to facilitate entry into container 658. In some embodiments, contacting elements 632 include reticulated sections, such as knuckle-joints or limited rotation knuckle-joints, to facilitate entry into container 658.
In certain embodiments, an electrical coupling material is placed in container 658. The electrical coupling material may line the walls of container 658 or fill up a portion of the container. In certain embodiments, the electrical coupling material lines an upper portion, such as the funnel-shaped portion shown in
In certain embodiments, the electrical coupling material is a low-temperature solder that melts at relatively low temperature and when cooled forms an electrical connection to exposed metal surfaces. In certain embodiments, the electrical coupling material is a solder that melts at a temperature below the boiling point of water at the depth of container 658. In one embodiment, the electrical coupling material is a 58% by weight bismuth and 42% by weight tin eutectic alloy. Other examples of such solders include, but are not limited to, a 54% by weight bismuth, 16% by weight tin, 30% by weight indium alloy, and a 48% by weight tin, 52% by weight indium alloy. Such low-temperature solders will displace water upon melting so that the water moves to the top of container 658. Water at the top of container 658 may inhibit heat transfer into the container and thermally insulate the low-temperature solder so that the solder remains at cooler temperatures and does not melt during heating of the formation using the heating elements.
Container 658 may be heated to activate the electrical coupling material to facilitate the connection of contacting elements 632. In certain embodiments, container 658 is heated to melt the electrical coupling material in the container. The electrical coupling material flows when melted and surrounds contacting elements 632 in container 658. Any water within container 658 will float to the surface of the metal when the metal is melted. The electrical coupling material is allowed to cool and electrically connects contacting elements 632 to each other. In certain embodiments, contacting elements 632 of legs 626, 628, the inside walls of container 658, and/or the bottom of the container are initially pre-tinned with electrical coupling material.
End portions of contacting elements 632 of legs 624, 626, 628 may have shapes and/or features that enhance the electrical connection between the contacting elements and the coupling material. The shapes and/or features of contacting elements 632 may also enhance the physical strength of the connection between the contacting elements and the coupling material (for example, the shape and/or features of the contacting element may anchor the contacting element in the coupling material). Shapes and/or features for end portions of contacting elements 632 include, but are not limited to, grooves, notches, holes, threads, serrated edges, openings, and hollow end portions. In certain embodiments, the shapes and/or features of the end portions of contacting elements 632 are initially pre-tinned with electrical coupling material.
In some embodiments, container 658 has a funnel-shape, as shown in
Lower portions of contacting elements 632 inside container 658 may include 410 stainless steel or any other heat generating electrical conductor. Portions of contacting elements 632 above the heat generating portions of the contacting elements include copper or another highly electrically conductive material. Centralizers 524 may be located on the portions of contacting elements 632 above the heat generating portions of the contacting elements. Centralizers 524 inhibit physical and electrical contact of portions of contacting elements 632 above the heat generating portions of the contacting elements against walls of container 658.
When contacting elements 632 are locked into place inside container 658 by protrusions 666, 668, at least some electrical current may be pass between the contacting elements through the protrusions. As electrical current is passed through the heat generating portions of contacting elements 632, heat is generated in container 658. The generated heat may melt coupling material 670 located inside container 658. Water in container 658 may boil. The boiling water may convect heat to upper portions of container 658 and aid in melting of coupling material 670. Walls of container 658 may be thermally insulated to reduce heat losses out of the container and allow the inside of the container to heat up faster. Coupling material 670 flows down into the lower portion of container 658 as the coupling material melts. Coupling material 670 fills the lower portion of container 658 until the heat generating portions of contacting elements 632 are below the fill line of the coupling material. Coupling material 670 then electrically couples the portions of contacting elements 632 above the heat generating portions of the contacting elements. The resistance of contacting elements 632 decreases at this point and heat is no longer generated in the contacting elements and the coupling materials is allowed to cool.
In certain embodiments, container 658 includes insulation layer 672 inside the housing of the container. Insulation layer 672 may include thermally insulating materials to inhibit heat losses from the canister. For example, insulation layer 672 may include magnesium oxide, silicon nitride, or other thermally insulating materials that withstand operating temperatures in container 658. In certain embodiments, container 658 includes liner 674 on an inside surface of the container. Liner 674 may increase electrical conductivity inside container 658. Liner 674 may include electrically conductive materials such as copper or aluminum.
In certain embodiments, an explosive element is placed in container 658, depicted in
Heating elements 682 may be coupled to portions of contacting elements 632 inside container 658. Heating elements 682 may include ferromagnetic materials such as iron or stainless steel. In an embodiment, heating elements 682 are iron cylinders clad onto contacting elements 632. Heating elements 682 may be designed with dimensions and materials that will produce a desired amount of heat in container 658. In certain embodiments, walls of container 658 are thermally insulated with insulation layer 672, as shown in
In certain embodiments, heating elements 682 operate as temperature limited heaters when a time-varying current is applied to the heating elements. For example, a 400 Hz, AC current may be applied to heating elements 682. Application of the time-varying current to contacting elements 632 causes heating elements 682 to generate heat and melt coupling material 670. Heating elements 682 may operate as temperature limited heating elements with a self-limiting temperature selected so that coupling material 670 is not overheated. As coupling material 670 fills container 658, the coupling material makes electrical contact between portions of exposed material on contacting elements 632 and electrical current begins to flow through the exposed material portions rather than heating elements 682. Thus, the electrical resistance between the contacting elements decreases. As this occurs, temperatures inside container 658 begin to decrease and coupling material 670 is allowed to cool to create an electrical contacting section between contacting elements 632. In certain embodiments, electrical power to contacting elements 632 and heating elements 682 is turned off when the electrical resistance in the system falls below a selected resistance. The selected resistance may indicate that the coupling material has sufficiently electrically connected the contacting elements. In some embodiments, electrical power is supplied to contacting elements 632 and heating elements 682 for a selected amount of time that is determined to provide enough heat to melt the mass of coupling material 670 provided in container 658.
Time-varying electrical current may be applied to contacting elements 632 so that heating elements 682 generate heat. The generated heat may melt coupling material 670 located in container 658, as described for the embodiment depicted in
End portions 632B of contacting elements 632 may be made of a ferromagnetic material such as 410 stainless steel. Portions 632A may include non-ferromagnetic electrically conductive material such as copper or aluminum. Time-varying electrical current may be applied to contacting elements 632 so that end portions 632B generate heat due to the resistance of the end portions. The generated heat may melt coupling material 670 located in container 658, as described for the embodiment depicted in
Inner container 684 may be substantially solid with two openings 688 and 690. Inner container 684 is coupled to contacting element 632 of leg 624. For example, inner container 684 may be welded or brazed to contacting element 632 of leg 624. Openings 688, 690 are shaped to allow contacting elements 632 of legs 626, 628 to enter the openings as shown in
Explosive elements 700 may be coupled to the outer wall of inner container 684. In certain embodiments, explosive elements 700 are elongated explosive strips that extend along the outer wall of inner container 684. Explosive elements 700 may be arranged along the outer wall of inner container 684 so that the explosive elements are aligned at or near the centers of contacting elements 632, as shown in
Explosive elements 700 may be coupled to battery 702 and timer 704. Battery 702 may provide power to explosive elements 700 to initiate the explosion. Timer 704 may be used to control the time for igniting explosive elements 700. Battery 702 and timer 704 may be coupled to triggers 706. Triggers 706 may be located in openings 688, 690. Contacting elements 632 may set off triggers 706 as the contacting elements are placed into openings 688, 690. When both triggers 706 in openings 688, 690 are triggered, timer 704 may initiate a countdown before igniting explosive elements 700. Thus, explosive elements 700 are controlled to explode only after contacting elements 632 are placed sufficiently into openings 688, 690 so that electrical contact may be made between the contacting elements and inner container 684 after the explosions. Explosion of explosive elements 700 crimps contacting elements 632 and inner container 684 together to make electrical contact between the contacting elements and the inner container. In certain embodiments, explosive elements 700 fire from the bottom towards the top of inner container 684. Explosive elements 700 may be designed with a length and explosive power (band width) that gives an optimum electrical contact between contacting elements 632 and inner container 684.
In some embodiments, triggers 706, battery 702, and timer 704 may be used to ignite a powder (for example, copper thermite powder) inside a container (for example, container 658 or inner container 684). Battery 702 may charge a magnesium ribbon or other ignition device in the powder to initiate reaction of the powder to produce a molten metal product. The molten metal product may flow and then cool to electrically contact the contacting elements.
In certain embodiments, electrical connection is made between contacting elements 632 through mechanical means.
In certain embodiments, contacting elements 632 (depicted in
In certain embodiments, two legs in separate wellbores intercept in a single contacting section.
Heating elements 630 in legs 624 and 626 may be temperature limited heaters. In certain embodiments, heating elements 630 are solid rod heaters. For example, heating elements 630 may be rods made of a single ferromagnetic conductor element or composite conductors that include ferromagnetic material. During initial heating when water is present in the formation being heated, heating elements 630 may leak current into hydrocarbon layer 460. The current leaked into hydrocarbon layer 460 may resistively heat the hydrocarbon layer.
In some embodiments (for example, in oil shale formations), heating elements 630 do not need support members. Heating elements 630 may be partially or slightly bent, curved, made into an S-shape, or made into a helical shape to allow for expansion and/or contraction of the heating elements. In certain embodiments, solid rod heating elements 630 are placed in small diameter wellbores (for example, about 3¾″ (about 9.5 cm) diameter wellbores). Small diameter wellbores may be less expensive to drill or form than larger diameter wellbores, and there will be less cuttings to dispose of.
In certain embodiments, portions of legs 624 and 626 in overburden 458 have insulation (for example, polymer insulation) to inhibit heating the overburden. Heating elements 630 may be substantially vertical and substantially parallel to each other in hydrocarbon layer 460. At or near the bottom of hydrocarbon layer 460, leg 624 may be directionally drilled towards leg 626 to intercept leg 626 in contacting section 642. Drilling two wellbores to intercept each other may be easier and less expensive than drilling three or more wellbores to intercept each other. The depth of contacting section 642 depends on the length of bend in leg 624 needed to intercept leg 626. For example, for a 40 ft (about 12 m) spacing between vertical portions of legs 624 and 626, about 200 ft (about 61 m) is needed to allow the bend of leg 624 to intercept leg 626. Coupling two legs may require a thinner contacting section 642 than coupling three or more legs in the contacting section.
In certain embodiments, contacting elements 632 include one or more fins or projections. The fins or projections may increase an electrical contact area of contacting elements 632. In some embodiments, contacting element 632 of leg 626 has an opening or other orifice that allows the contacting element of 624 to couple to the contacting element of leg 626.
In certain embodiments, legs 624 and 626 are coupled together to form a diad. Three diads may be coupled to a three-phase transformer to power the legs of the heaters.
Coupling the diads to the secondaries of the delta three-phase transformer isolates the diads from ground. Isolating the diads from ground inhibits leakage to the formation from the diads. Coupling the diads to different phases of the delta three-phase transformer also inhibits leakage between the heating legs of the diads in the formation.
In some embodiments, diads are used for treating formations using triangular or hexagonal heater patterns.
In certain embodiments, exposed metal heating elements are used in substantially horizontal sections of u-shaped wellbores. Substantially u-shaped wellbores may be used in tar sands formations, oil shale formation, or other formations with relatively thin hydrocarbon layers. Tar sands or thin oil shale formations may have thin shallow layers that are more easily and uniformly heated using heaters placed in substantially u-shaped wellbores. Substantially u-shaped wellbores may also be used to process formations with thick hydrocarbon layers in formations. In some embodiments, substantially u-shaped wellbores are used to access rich layers in a thick hydrocarbon formation.
Heaters in substantially u-shaped wellbores may have long lengths compared to heaters in vertical wellbores because horizontal heating sections do not have problems with creep or hanging stress encountered with vertical heating elements. Substantially u-shaped wellbores may make use of natural seals in the formation and/or the limited thickness of the hydrocarbon layer. For example, the wellbores may be placed above or below natural seals in the formation without punching large numbers of holes in the natural seals, as would be needed with vertically oriented wellbores. Using substantially u-shaped wellbores instead of vertical wellbores may also reduce the number of wells needed to treat a surface footprint of the formation. Using less wells reduces capital costs for equipment and reduces the environmental impact of treating the formation by reducing the amount of wellbores on the surface and the amount of equipment on the surface. Substantially u-shaped wellbores may also utilize a lower ratio of overburden section to heated section than vertical wellbores.
Substantially u-shaped wellbores may allow for flexible placement of opening of the wellbores on the surface. Openings to the wellbores may be placed according to the surface topology of the formation. In certain embodiments, the openings of wellbores are placed at geographically accessible locations such as topological highs (for examples, hills). For example, the wellbore may have a first opening on a first topologic high and a second opening on a second topologic high and the wellbore crosses beneath a topologic low (for example, a valley with alluvial fill) between the first and second topologic highs. This placement of the openings may avoid placing openings or equipment in topologic lows or other inaccessible locations. In addition, the water level may not be artesian in topologically high areas. Wellbores may be drilled so that the openings are not located near environmentally sensitive areas such as, but not limited to, streams, nesting areas, or animal refuges.
In certain embodiments, portions of heating elements 630 are substantially parallel in hydrocarbon layer 460. In certain embodiments, heating elements 630 are exposed metal heating elements. In certain embodiments, heating elements 630 are exposed metal temperature limited heating elements. Heating elements 630 may include ferromagnetic materials such as 9% by weight to 13% by weight chromium stainless steel like 410 stainless steel, chromium stainless steels such as T/P91 or T/P92, 409 stainless steel, VM12 (Vallourec and Mannesmann Tubes, France) or iron-cobalt alloys for use as temperature limited heaters. In some embodiments, heating elements 630 are composite temperature limited heating elements such as 410 stainless steel and copper composite heating elements or 347H, iron, copper composite heating elements. Heating elements 630 may have lengths of at least about 100 m, at least about 500 m, or at least about 1000 m, up to lengths of about 6000 m.
Heating elements 630 may be solid rods or tubulars. In certain embodiments, solid rod heating elements have diameters several times the skin depth at the Curie temperature of the ferromagnetic material. Typically, the solid rod heating elements may have diameters of 1.91 cm or larger (for example, 2.5 cm, 3.2 cm, 3.81 cm, or 5.1 cm). In certain embodiments, tubular heating elements have wall thicknesses of at least twice the skin depth at the Curie temperature of the ferromagnetic material. Typically, the tubular heating elements have outside diameters of between about 2.5 cm and about 15.2 cm and wall thickness in range between about 0.13 cm and about 1.01 cm.
In certain embodiments, tubular heating elements 630 allow fluids to be convected through the tubular heating elements. Fluid flowing through the tubular heating elements may be used to preheat the tubular heating elements, to initially heat the formation, and/or to recover heat from the formation after heating is completed for the in situ heat treatment process. Fluids that may flow through the tubular heating elements include, but are not limited to, air, water, steam, helium, carbon dioxide or other fluids. In some embodiments, a hot fluid, such as carbon dioxide or helium, flows through the tubular heating elements to provide heat to the formation. The hot fluid may be used to provide heat to the formation before electrical heating is used to provide heat to the formation. In some embodiments, the hot fluid is used to provide heat in addition to electrical heating. Using the hot fluid to provide heat to the formation in addition to providing electrical heating may be less expensive than using electrical heating alone to provide heat to the formation. In some embodiments, water and/or steam flows through the tubular heating element to recover heat from the formation. The heated water and/or steam may be used for solution mining and/or other processes.
Transition sections 720 may couple heating elements 630 to sections 718. In certain embodiments, transition sections 720 include material that has a high electrical conductivity but is corrosion resistant, such as 347 stainless steel over copper. In an embodiment, transition sections include a composite of stainless steel clad over copper. Transition sections 720 inhibit overheating of copper and/or insulation in sections 718.
As depicted in
In certain embodiments, bus bar 726A is coupled to first end portions of heaters 716A-L and bus bar 726B is coupled to second end portions of heaters 716A-L. Bus bars 726A,B electrically couple heaters 716A-L to cables 722, 724 and transformer 728. Bus bars 726A,B distribute power to heaters 716A-L. In certain embodiments, bus bars 726A,B are capable of carrying high currents with low losses. In some embodiments, bus bars 726A,B are made of superconducting material such as the superconductor material used in cables 722, 724. In some embodiments, bus bars 726A,B may include carbon nanotube conductors.
As shown in
Applying the same voltage potentials to the end portions of all heaters 716A-L produces voltage potentials along the lengths of the heaters that are substantially the same along the lengths of the heaters.
In certain embodiments, the voltage potential at the midpoint of heaters 716A-L is about zero. Having similar voltage potentials along the lengths of heaters 716A-L inhibits current leakage between the heaters. Thus, there is little or no current flow in the formation and the heaters may have long lengths as described above. Having the opposite polarity and substantially equal voltage potentials at the end portions of the heaters also halves the voltage applied at either end portion of the heater versus having one end portion of the heater grounded and one end portion at full potential. Reducing (halving) the voltage potential applied to an end portion of the heater generally reduces current leakage, reduces insulator requirements, and/or reduces arcing distances because of the lower voltage potential to ground applied at the end portions of the heaters.
In certain embodiments, substantially vertical heaters are used to provide heat to the formation. Opposite polarity and substantially equal voltage potentials, as described above, may be applied to the end portions of the substantially vertical heaters.
Bus bar 726B may be a bus bar located in a substantially horizontal wellbore in contacting section 642. Second end portions of heaters 716A, 716B, 716C, 716D, 716E, 716F may be coupled to bus bar 726B by any method described herein or any method known in the art. For example, containers with thermite powder are coupled to bus bar 726B (for example, by welding or brazing the containers to the bus bar), end portions of heaters 716A, 716B, 716C, 716D, 716E, 716F are placed inside the containers, and the thermite powder is activated to electrically couple the heaters to the bus bar. The containers may be coupled to bus bar 726B by, for example, placing the containers in holes or recesses in bus bar 726B or coupled to the outside of the bus bar and then brazing or welding the containers to the bus bar.
Bus bar 726A and bus bar 726B may be coupled to transformer 728 with cables 722, 724, as described above. Transformer 728 may provide voltages to bar 726A and bus bar 726B as described above for the embodiments depicted in
In certain embodiments, it may be advantageous to allow some current leakage into the formation during early stages of heating to heat the formation at a faster rate. Current leakage from the heaters into the formation electrically heats the formation directly. The formation is heated by direct electrical heating in addition to conductive heat provided by the heaters. The formation (the hydrocarbon layer) may have an initial electrical resistance that averages at least 10 ohm·m. In some embodiments, the formation has an initial electrical resistance of at least 100 ohm·m or of at least 300 ohm·m. Direct electrical heating is achieved by having opposite potentials applied to adjacent heaters in the hydrocarbon layer. Current may be allowed to leak into the formation until a selected temperature is reached in the heaters or in the formation. The selected temperature may be below or near the temperature that water proximate one or more heaters boils off. After water boils off, the hydrocarbon layer is substantially electrically isolated from the heaters and direct heating of the formation is inefficient. After the selected temperature is reached, the voltage potential is applied in the opposite polarity and substantially equal magnitude manner described above for
Current is allowed to leak into the formation by reversing the polarity of one or more heaters shown in
In some embodiments, the heating elements have thin electrically insulating material, described above, to inhibit current leakage from the heating elements. In some embodiments, the thin electrically insulating layer is aluminum oxide or thermal spray coated aluminum oxide. In some embodiments, the thin electrically insulating layer is an enamel coating of a ceramic composition. The thin electrically insulating layer may inhibit heating elements of a three-phase heater from leaking current between the elements, from leaking current into the formation, and from leaking current to other heaters in the formation. Thus, the three-phase heater may have a longer heater length.
In certain embodiments, a plurality of substantially horizontal (or inclined) heaters are coupled to a single substantially horizontal bus bar in the subsurface formation. Having the plurality of substantially horizontal heaters connected to a single bus bar in the subsurface reduces the overall footprint of heaters on the surface of the formation and the number of wells drilled in the formation. In addition, the amount of subsurface space used to couple the heaters may be minimized so that more of the formation is treated with heat to recover hydrocarbons (for example, there is less unheated depth in the formation). The number and spacing of heaters coupled to the single bus bar may be varied depending on factors such as, but not limited to, size of the treatment area, vertical thickness of the formation, heating requirements for the formation, number of layers in the formation, and capacity limitations of a surface power supply.
In certain embodiments, heaters 716A,B include exposed metal heating elements. In certain embodiments, heaters 716A,B include exposed metal temperature limited heating elements. The heating elements may include ferromagnetic materials such as 9% by weight to 13% by weight chromium stainless steel like 410 stainless steel, chromium stainless steels such as T/P91 or T/P92, 409 stainless steel, VM12 (Vallourec and Mannesmann Tubes, France) or iron-cobalt alloys for use as temperature limited heaters. In some embodiments, the heating elements are composite temperature limited heating elements such as 410 stainless steel and copper composite heating elements or 347H, iron, copper composite heating elements. The substantially horizontal sections of heaters 716A,B in hydrocarbon layer 460 may have lengths of at least about 100 m, at least about 500 m, or at least about 1000 m, up to lengths of about 6000 m.
In some embodiments, as shown in
In certain embodiments, the groups of heaters 716A or 716B are each coupled to a single transformer. In some embodiments, three heaters in the groups are coupled in a triad configuration (each heater is coupled to one of the phases (A, B, or C) of a three phase transformer and the bus bar is coupled to the neutral, or center point, of the transformer). Each phase of the three-phase transformer may be coupled to more than one heater in each group of heaters (for example, phase A may be coupled to 5 heaters in the group of heaters 716A). In some embodiments, the heaters are coupled to a single phase transformer (either in series or in parallel configurations).
In certain embodiments, heaters 716A,B, depicted in
As shown in
In certain embodiments, heaters 716A,B are coupled to bus bars 726A,B using “mousetrap” type connectors 2028. In some embodiments, other couplings, such as those described herein or known in the art, are used to couple heaters 716A,B to bus bars 726A,B. For example, a molten metal or a liquid conducting fluid may fill up the connection space (in the wellbores) to electrically couple the heaters and the bus bars.
In some embodiments, a centralizer or other centralizing device is used to locate or guide heaters 716 and/or bus bars 726 so that the heaters and bus bars can be coupled.
In some embodiments, an explosive element is added to connector 2028, shown in
In some embodiment, the explosive bonding is applied along the axial direction of bus bar 726. In some embodiments, the explosive bonding process is a self cleaning process. For example, the explosive bonding process may drive out air and/or debris from between components during the explosion. In some embodiments, the explosive element is a shape charge explosive element. Using the shape charge element may focus the explosive energy in a desired direction.
In some embodiments, heaters 716A, 716B, 716C are insulated conductor heaters. In some embodiments, heaters 716A, 716B, 716C are conductor-in-conduit heaters. Heaters 716A, 716B, 716C may have substantially parallel heating sections in hydrocarbon layer 460. Heaters 716A, 716B, 716C may be substantially horizontal or at an incline in hydrocarbon layer 460. In some embodiments, heaters 716A, 716B, 716C enter the formation through common wellbore 452A. Heaters 716A, 716B, 716C may exit the formation through common wellbore 452B. In certain embodiments, wellbores 452A, 452B are uncased (for example, open wellbores) in hydrocarbon layer 460.
Openings 522A, 522B, 522C span between wellbore 452A and wellbore 452B. Openings 522A, 522B, 522C may be uncased openings in hydrocarbon layer 460. In certain embodiments, openings 522A, 522B, 522C are formed by drilling from wellbore 452A and/or wellbore 452B. In some embodiments, openings 522A, 522B, 522C are formed by drilling from each wellbore 452A and 452B and connecting at or near the middle of the openings. Drilling from both sides towards the middle of hydrocarbon layer 460 allows longer openings to be formed in the hydrocarbon layer. Thus, longer heaters may be installed in hydrocarbon layer 460. For example, heaters 716A, 716B, 716C may have lengths of at least about 1500 m, at least about 3000 m, or at least about 4500 m.
Having multiple long, substantially horizontal or inclined heaters extending from only two wellbores in hydrocarbon layer 460 reduces the footprint of wells on the surface needed for heating the formation. The number of overburden wellbores that need to be drilled in the formation is reduced, which reduces capital costs per heater in the formation. Heating the formation with long, substantially horizontal or inclined heaters also reduces overall heat losses in the overburden when heating the formation because of the reduced number of overburden sections used to treat the formation (for example, losses in the overburden are a smaller fraction of total power supplied to the formation).
In some embodiments, heaters 716A, 716B, 716C are installed in wellbores 452A, 452B and openings 522A, 522B, 522C by pulling the heaters through the wellbores and the openings from one end to the other. For example, an installation tool may be pushed through the openings and coupled to a heater in wellbore 452A. The heater may then be pulled through the openings towards wellbore 452B using the installation tool. The heater may be coupled to the installation tool using a connector such as a claw, a catcher, or other devices known in the art.
In some embodiments, the first half of an opening is drilled from wellbore 452A and then the second half of the opening is drilled from wellbore 452B through the first half of the opening. The drill bit may be pushed through to wellbore 452A and a first heater may be coupled to the drill bit to pull the first heater back through the opening and install the first heater in the opening. The first heater may be coupled to the drill bit using a connector such as a claw, a catcher, or other devices known in the art.
After the first heater is installed, a tube or other guide may be placed in wellbore 452A and/or wellbore 452B to guide drilling of a second opening.
After the second heater is installed, drilling guide 2582 may be placed in wellbore 452 to guide drilling of a third opening, as shown in
In some embodiments, all the openings are formed in the formation and then the heaters are installed in the formation. In certain embodiments, one of the openings is formed and one of the heaters is installed in the formation before the other openings are formed and the other heaters are installed. The first installed heater may be used to guide forming of the other openings in the formation. The first installed heater may be energized to produce an electromagnetic field that is used to guide the formation of the other openings. For example, the first installed heater may be energized with a bipolar DC current to magnetically guide drilling of the other openings.
In certain embodiments, heaters 716A, 716B, 716C are coupled to a single three-phase transformer 728 at one end of the heaters, as shown in
In some embodiments, the overburden section of heaters 716A, 716B, 716C are coated with an insulator, such as a polymer or an enamel coating, to inhibit shorting between the overburden sections of the heaters. In some embodiments, only the overburden sections of the heaters in wellbore 452A are coated with the insulator as the heater sections in wellbore 452B may not have significant electrical losses. In some embodiments, ends of heaters 716A, 716B, 716C in wellbore 452A are at least one diameter of the heaters away from overburden casing 530A so that no insulator is needed. The ends of heaters 716A, 716B, 716C may be, for example, centralized in wellbore 452A using a centralizer to keep the heaters the desired distance away from overburden casing 530A.
In some embodiments, the ends of heaters 716A, 716B, 716C passing through wellbore 452B are electrically coupled together and grounded outside of the wellbore, as shown in
In some embodiments, the ends of heaters 716A, 716B, 716C passing through wellbore 452B are electrically coupled together inside the wellbore. The ends of the heaters may be coupled inside the wellbore at or near the bottom of the overburden. Coupling the heaters together at or near the overburden reduces electrical losses in the overburden section of the wellbore.
Balls 2580 may be placed into the overburden section of wellbore 452B. Plate 2578 may allow balls 2580 to settle in the overburden section of wellbore 452B around heaters 716A, 716B, 716C. Balls 2580 may be made of electrically conductive material such as copper or nickel-plated copper. Balls 2580 and plate 2578 may electrically couple heaters 716A, 716B, 716C to each other so that the heaters are grounded. In some embodiments, portions of the heaters above plate 2578 (the overburden sections of the heaters) are made of carbon steel while portions of the heaters below the plate (build sections of the heaters) are made of copper.
In some embodiments, heaters 716A, 716B, 716C, as depicted in
In some embodiments, heaters 716A, 716B, 716C are divided into two or more sections of heating. In some embodiments, the heaters are divided into repeating sections of different heat outputs (for example, alternating sections of two different heat outputs that are repeated). The repeating sections of different heat outputs may be used, in some embodiments, to heat the formation in stages (for example, in a staged heating process as described herein). In one embodiment, the halves of the heaters closest to wellbore 452A may provide heat in a first section of hydrocarbon layer 460 and the halves of the heaters closest to wellbore 452B may provide heat in a second section of hydrocarbon layer 460. Hydrocarbons in the formation may be mobilized by the heat provided in the first section. Hydrocarbons in the second section may be heated to higher temperatures than the first section to upgrade the hydrocarbons in the second section (for example, the hydrocarbons may be further mobilized and/or pyrolyzed). Hydrocarbons from the first section may move, or be moved, into the second section for the upgrading. For example, a drive fluid may be provided to through wellbore 452A to move the first section mobilized hydrocarbons to the second section.
In some embodiments, more than three heaters extend from wellbore 452A and/or 452B. If multiples of three heaters extend from the wellbores and are coupled to transformer 728, the magnetic fields may cancel in the overburden sections of the wellbores as in the case of three heaters in the wellbores. For example, six heaters may be coupled to transformer 728 with two heaters coupled to each phase of the transformer to cancel the magnetic fields in the wellbores.
In some embodiments, multiple heaters extend from one wellbore in different directions.
In some embodiments, heaters 716A, 716B, 716C may have different heat outputs from heaters 716D, 716E, 716F so that hydrocarbon layer 460 is divided into two heating sections with different heating rates and/or temperatures (for example, a mobilization and a pyrolyzation section). In some embodiments, heaters 716A, 716B, 716C and/or heaters 716D, 716E, 716F may have heat outputs that vary along the lengths of the heaters to further divide hydrocarbon layer 460 into more heating sections. In some embodiments, additional heaters may extend from wellbore 452B and/or wellbore 452C to other wellbores in the formation as shown by the dashed lines in
In some embodiments, multiple levels of heaters extend between two wellbores.
In some embodiments, the levels are heated at different rates to create different heating zones in the formation. For example, the first level (heated by heaters 716A, 716B, 716C) may be heated so that hydrocarbons are mobilized, the second level (heated by heaters 716D, 716E, 716F) may be heated so that hydrocarbons are somewhat upgraded from the first level, and the third level (heated by heaters 716G, 716H, 716I) may be heated to pyrolyze hydrocarbons. As another example, the first level may be heated to create gases and/or drive fluid in the first level and either the second level or the third level may be heated to mobilize and/or pyrolyze fluids or just to a level to allow production in the level. In addition, heaters 716A, 716B, 716C, heaters 716D, 716E, 716F, and/or heaters 716G, 716H, 716I may have heat outputs that vary along the lengths of the heaters to further divide hydrocarbon layer 460 into more heating sections.
In certain embodiments, three, or multiples of three, tubulars 484 and insulator conductors 558 enter the formation from a first common wellbore and exit the formation from a second common wellbore and are powered by a single, three-phase wye transformer. For example, tubular 484 and insulator conductor 558 may be used as heaters 716, depicted in
Tubular 484 may be ferromagnetic or include ferromagnetic materials. Tubular 484 may have a thickness selected so that when insulated conductor 558 is energized with time-varying current, the insulated conductor induces electrical current flow in tubular 484 due to the skin effect of the ferromagnetic material in the tubular. Thus, tubular 484 may provide heat to hydrocarbon layer 460 and the tubular defines the heating zone in the hydrocarbon layer. Tubular 484 may have a thickness that is greater than the skin depth of the ferromagnetic material in the tubular. For example, tubular 484 may have a thickness of at least 2 times, at least 3 times, or at least 4 times the skin depth of the ferromagnetic material. In certain embodiments, tubular 484 operates as a temperature limited heater.
In certain embodiments, tubular 484 is carbon steel. In some embodiments, the carbon steel tubular is coated with a corrosion resistant coating (for example, porcelain or ceramic coating) and/or an electrically insulating coating. In some embodiments, tubular 484 is made of corrosion resistant ferromagnetic material such as, but not limited to, 410 stainless steel, 446 stainless steel, T/P91 stainless steel, or T/P92 stainless steel. In some embodiments, tubular 484 is stainless steel with cobalt added (for example, between about 3% by weight and about 10% by weight cobalt added).
Tubular 484 may have large diameters as high pressure fluids may be present on both the inside and the outside of the tubular so that the pressure on the tubular is equalized or substantially equalized. For example, tubular 484 may have diameters of between about 1.5″ and about 5″. Increasing the diameter of tubular 484 is advantageous as the larger the diameter of the tubular, the more heat is output to the formation.
In certain embodiments, tubular 484 provides varying heat outputs along the length of the tubular. For example, tubular 484 may have different dimensions (for example, thicknesses or diameters) and/or different materials along the length of the tubular to provide the varying heat outputs. The different materials may provide different maximum temperatures (for example, different Curie temperatures) along the length of tubular 484 so that the tubular provides different heat outputs along the length of the tubular.
Providing different heat outputs along tubular 484 may provide different heating sections in hydrocarbon layer 460. For example, tubular 484 may be divided into two or more sections of heating. In one embodiment, a first portion of tubular 484 may provide heat to a first section of hydrocarbon layer 460 and a second portion of the tubular may provide heat to a second section of the hydrocarbon layer. Hydrocarbons in the first section may be mobilized by the heat provided by the first portion of tubular 484. Hydrocarbons in the second section may be heated by the second portion of tubular 484 to a higher temperature than the first section. The higher temperature in the second section may upgrade hydrocarbons in the second section relative to the first section. For example, the hydrocarbons may be further mobilized, visbroken, and/or pyrolyzed in the second section. Hydrocarbons from the first section may be moved into the second section by, for example, a drive fluid provided to the first section.
In certain embodiments, a heater is electrically isolated from the formation because the heater has little or no voltage potential on the outside of the heater.
As shown in
Heating element 630 is coupled to one or more sections 718. Sections 718 are located in overburden 458. Sections 718 include higher electrical conductivity materials such as copper or aluminum. In certain embodiments, sections 718 are copper clad inside carbon steel.
Center conductor 730 is positioned inside heating element 630. In some embodiments, heating element 630 and center conductor 730 are placed or installed in the formation by unspooling the heating element and the center conductor from one or more spools while they are placed into the formation. In some embodiments, heating element 630 and center conductor 730 are coupled together on a single spool and unspooled as a single system with the center conductor inside the heating element. In some embodiments, heating element 630 and center conductor 730 are located on separate spools and the center conductor is positioned inside the heating element after the heating element is placed in the formation.
In certain embodiments, center conductor 730 is located at or near a center of heating element 630. Center conductor 730 may be substantially electrically isolated from heating element 630 along a length of the center conductor (for example, the length of the center conductor in hydrocarbon layer 460). In certain embodiments, center conductor 730 is separated from heating element 630 by one or more electrically-insulating centralizers. The centralizers may include silicon nitride or another electrically insulating material. The centralizers may inhibit electrical contact between center conductor 730 and heating element 630 so that, for example, arcing or shorting between the center conductor and the heating element is inhibited. In some embodiments, center conductor 730 is a conductor (for example, a solid conductor or a tubular conductor) so that the heater is in a conductor-in-conduit configuration.
In certain embodiments, center conductor 730 is a copper rod or copper tubular. In some embodiments, center conductor 730 and/or heating element 630 has a thin electrically insulating layer to inhibit current leakage from the heating elements. In some embodiments, the thin electrically insulating layer is aluminum oxide or thermal spray coated aluminum oxide. In some embodiments, the thin electrically insulating layer is an enamel coating of a ceramic composition. The thin electrically insulating layer may inhibit heating elements of a three-phase heater from leaking current between the elements, from leaking current into the formation, and from leaking current to other heaters in the formation. Thus, the three-phase heater may have a longer heater length.
In certain embodiments, center conductor 730 is an insulated conductor. The insulated conductor may include an electrically conductive core inside an electrically conductive sheath with electrical insulation between the core and the sheath. In certain embodiments, the insulated conductor includes a copper core inside a non-ferromagnetic stainless steel (for example, 347 stainless steel) sheath with magnesium oxide insulation between the core and the sheath. The core may be used to conduct electrical current through the insulated conductor. In some embodiments, the insulated conductor is placed inside heating element 630 without centralizers or spacers between the insulated conductor and the heating element. The sheath and the electrical insulation of the insulated conductor may electrically insulate the core from heating element 630 if the center conductor and the heating element touch. Thus, the core and heating element 630 are inhibited from electrically shorting to each other. The insulated conductor or another solid center conductor 730 may be inhibited from being crushed or deformed by heating element 630. In certain embodiments, one end portion of center conductor 730 is electrically coupled to one end portion of heating element 630 at surface 534 using electrical coupling 732, as shown in
During application of electrical current to heating element 630 and center conductor 730, heat is generated by the heater. In certain embodiments, heating element 630 generates a majority or all of the heat output of the heater. For example, when electrical current flows through ferromagnetic material in heating element 630 and copper or another low resistivity material in center conductor 730, the heating element generates a majority or all of the heat output of the heater. Generating a majority of the heat in the outer conductor (heating element 630) instead of center conductor 730 may increase the efficiency of heat transfer to the formation by allowing direct heat transfer from the heat generating element (heating element 630) to the formation and may reduce heat losses across heater 716 (for example, heat losses between the center conductor and the outer conductor if the center conductor is the heat generating element). Generating heat in heating element 630 instead of center conductor 730 also increases the heat generating surface area of heater 716. Thus, for the same operating temperature of heater 716, more heat can be provided to the formation using the outer conductor (heating element 630) as the heat generating element rather than center conductor 730.
In some embodiments, a fluid flows through heater 716 (represented by arrows 736 in
Fluid flowing inside heater 716 (represented by arrows 736 in
In some embodiments, an insulated conductor heater is placed in the formation by itself and the outside of the insulated conductor heater is electrically isolated from the formation because the heater has little or no voltage potential on the outside of the heater.
Insulated conductor 558 has little or no current flowing along the outside surface of the insulated conductor so that the insulated conductor is electrically isolated from the formation and leaks little or no current into the formation. The outside surface (or jacket) of insulated conductor 558 is a metal or thermal radiating body so that heat is radiated from the insulated conductor to the formation.
In the embodiment depicted in
Because core 508 is made of a highly conductive material such as copper and jacket 506 is made of more resistive ferromagnetic material, a majority of the heat generated by insulated conductor 558 is generated in the jacket. Generating the majority of the heat in jacket 506 increases the efficiency of radiative heat transfer from insulated conductor 558 to the formation over an insulated conductor (or other heater) that uses a core or a center conductor to generate the majority of the heat.
In certain embodiments, core 508 is made of copper. Using copper in core 508 allows the heating section of the heater and the overburden section to have identical core materials. Thus, the heater may be made from one long core assembly. The long single core assembly reduces or eliminates the need for welding joints in the core, which can be unreliable and susceptible to failure. Additionally, the long, single core assembly heater may be manufactured remote from the installation site and transported in a final assembly (ready to install assembly) to the installation site. The single core assembly also allows for long heater lengths (for example, about 1000 m or longer) depending on the breakdown voltage of the electrical insulator.
In certain embodiments, jacket 506 is made from two or more layers of the same materials and/or different materials. Jacket 506 may be formed from two or more layers to achieve thicknesses needed for the jacket (for example, to have a thickness at least 3 times the skin depth of the ferromagnetic material used in the jacket). Manufacturing and/or material limitations may limit the thickness of a single layer of jacket material. For example, the amount each layer can be strained during manufacturing (forming) the layer on the heater may limit the thickness of each layer. Thus, to reach jacket thicknesses needed for certain embodiments of insulated conductor 558, jacket 506 may be formed from several layers of jacket material. For example, three layers of T/P92 stainless steel may be used to form jacket 506 with a thickness of about 3 times the skin depth of the T/P92 stainless steel.
In some embodiments, jacket 506 includes two or more different materials. In some embodiments, jacket 506 includes different materials in different layers of the jacket. For example, jacket 506 may have one or more inner layers of ferromagnetic material chosen for their electrical and/or electromagnetic properties and one or more outer layers chosen for its non-corrosive properties.
In some embodiments, the thickness of jacket 506 and/or the material of the jacket are varied along the heater length. The thickness and/or material of jacket 506 may be varied to vary electrical properties and/or mechanical properties along the length of the heater. For example, the thickness and/or material of jacket 506 may be varied to vary the turndown ratio along the length of the heater. In some embodiments, the inner layer of jacket 506 includes copper or other highly conductive metals in the overburden section of the heater. The inner layer of copper limits heat losses in the overburden section of the heater.
In some embodiments, insulated conductor 558 is placed in a tubular.
In certain embodiments, core 508 is copper, electrical insulator 500 is magnesium oxide, and jacket 506 is non-ferromagnetic stainless steel (for example, 347H stainless steel, 204-Cu stainless steel, or 204 M stainless steel). Insulated conductor 558 may be placed in tubular 484 to protect the insulated conductor, increase heat transfer to the formation, and/or allow for coiled tubing or continuous installation of the insulated conductor. Tubular 484 may be made of ferromagnetic material such as 410 stainless steel, T/P91 stainless steel, or carbon steel. In certain embodiments, tubular 484 is made of corrosion resistant materials. In some embodiments, tubular 484 is made of non-ferromagnetic materials.
In certain embodiments, jacket 506 of insulated conductor 558 is longitudinally welded to tubular 484 along weld joint 2576. The longitudinal weld may be a laser, a tandem GTAW (gas tungsten arc welding) weld, or an electron beam weld that welds the surface of jacket 506 to tubular 484. In some embodiments, tubular 484 is made from a longitudinal strip of metal. Tubular 484 may be made by rolling the longitudinal strip to form a cylindrical tube and then welding the longitudinal ends of the strip together to make the tubular.
In certain embodiments, insulated conductor 558 is welded to tubular 484 as the longitudinal ends of the strip are welded together (in the same welding process). For example, insulated conductor 558 is placed along one of the longitudinal ends of the strip so that jacket 506 is welded to tubular 484 at the location where the ends are welded together. In some embodiments, insulated conductor 558 is welded to one of the longitudinal ends of the strip before the strip is rolled to form the cylindrical tube. The ends of the strip may then be welded to form tubular 484.
In some embodiments, insulated conductor 558 is welded to tubular 484 at another location (for example, at a circumferential location away from the weld joining the ends of the strip used to form the tubular). For example, jacket 506 of insulated conductor 558 may be welded to tubular 484 diametrically opposite from where the longitudinal ends of the strip used to form the tubular are welded. In some embodiments, tubular 484 is made of multiple strips of material that are rolled together and coupled (for example, welded) to form the tubular with a desired thickness. Using more than one strip of metal may be easier to roll into the cylindrical tube used to form the tubular.
Jacket 506 and tubular 484 may be electrically and mechanically coupled at weld joint 2576. Longitudinally welding jacket 506 to tubular 484 inhibits arcing between insulated conductor 558 and the tubular. Tubular 484 may return electrical current from core 508 along the inside of the tubular if the tubular is ferromagnetic. If tubular 484 is non-ferromagnetic, a thin electrically insulating layer such as a porcelain enamel coating or a spray coated ceramic may be put on the outside of the tubular to inhibit current leakage from the tubular. In some embodiments, a fluid is placed in tubular 484 to increase heat transfer between insulated conductor 558 and the tubular and/or to inhibit arcing between the insulated conductor and the tubular. Examples of fluids include, but are not limited to, conductive gases such as helium, molten metals, and molten salts. In some embodiments, heat transfer fluids are transported inside tubular 484 and heated inside the tubular (in the space between the tubular and insulated conductor 558). In some embodiments, an optical fiber, thermocouple, or other temperature sensor is placed inside tubular 484.
In certain embodiments, the heater depicted in
As shown in
Heat may be provided to hydrocarbon layer 460A by heating element 630A for a selected amount of time (for example, a first amount of time). The selected amount of time may be based on a variety of factors including, but not limited to, formation characteristics or properties, present or future economic factors, or capital costs. For example, for an oil shale formation, hydrocarbon layer 460A may have a richness of about 0.12 L/kg (30.5 gals/ton) and the layer is heated for about 25 years. Production of formation fluids from hydrocarbon layer 460A may continue from the layer until production slows down to an uneconomical rate.
After hydrocarbon layer 460A is heated for the selected amount of time, heating element 630A is turned down and/or off. After heating element 630A is turned off, the heating element may be pulled firmly (for example, yanked) upwards so that the heating element breaks off at links 742. Both ends of heating element 630A at the surface may be pulled simultaneously so that links 742 break approximately simultaneously. Links 742 may be weak links designed to pull apart when a selected or sufficient amount of pulling force is applied to the links. For example, links 742 may be breakable mechanical couplings between portions of the heating element. The upper portions of heating element 630A are then pulled out of the formation and the substantially horizontal portion of heating element 630A is left in opening 522A, as shown in
In some embodiments, only one link 742 may be broken so that the upper portion above the one link can be removed and the remaining portions of the heater can be removed by pulling on the opposite end of the heater. Thus, the entire length of heating element 630A may be removed from the formation.
After upper portions of heating element 630A are removed from openings 522, plugs 744 may be placed into openings 522 at a selected location in hydrocarbon layer 460B, as depicted in
After plugs 744 and/or packing 532 is set into place in openings 522, substantially horizontal opening 522B may be formed in hydrocarbon layer 460B. Opening 522B may be formed by punching (for example, drilling) through casing 530 on the wall of opening 522. In certain embodiments, opening 522B is a substantially horizontal opening in hydrocarbon layer 460B. In some embodiments, opening 522B is an inclined opening in hydrocarbon layer 460B (for example, the layer may be an angled layer and the opening is angled to be substantially horizontal in the layer). Heating element 630B is then placed into opening 522B. Heating element 630B may be used to provide heat to hydrocarbon layer 460B. Formation fluids, such as pyrolyzed hydrocarbons and/or mobilized hydrocarbons, may be produced from hydrocarbon layer 460B during and/or after heating of the layer by heating element 630B.
In certain embodiments, opening 522 is a single-ended horizontal opening in hydrocarbon layer 460A (for example, the opening has only one end open at the surface of the formation).
In
As shown in
Heat may be provided to hydrocarbon layer 460A by heating element 630A for a selected amount of time. The selected amount of time may be based on a variety of factors including, but not limited to, formation characteristics or properties, present or future economic factors, or capital costs. For example, for an oil shale formation, hydrocarbon layer 460A may have a richness of about 0.12 L/kg (30.5 gals/ton) and the layer is heated for about 25 years. Production of formation fluids from hydrocarbon layer 460A may continue from the layer until production slows down to an uneconomical rate.
After hydrocarbon layer 460A is heated for the selected amount of time, heating element 630A is turned down and/or off. After heating element 630A is turned down and/or off, the heating element may be removed from opening 522A. In some embodiments, one or more portions of heating element 630A are left in opening 522A. For example, portions of hydrocarbon layer 460A may clamp or squeeze on heating element 630A so that the heating element cannot be completely removed from opening 522A. In such cases, heating element 630A may be broken at link 742 and the upper portion of heating element 630A is pulled out of the formation and the substantially horizontal portion of the heating element is left in opening 522A.
After heating element 630A is removed from opening 522, plug 744 may be placed into opening 522 at a selected location in hydrocarbon layer 460B, as depicted in
After plug 744 and/or packing 532 is set into place in opening 522, substantially horizontal opening 522B may be formed in hydrocarbon layer 460B. Opening 522B may extend horizontally from opening 522. In certain embodiments, opening 522B is a substantially horizontal opening in hydrocarbon layer 460B that terminates in the layer. In some embodiments, opening 522B is an inclined opening in hydrocarbon layer 460B (for example, the layer may be an angled layer and the opening is angled to be substantially horizontal in the layer). Opening 522B may be formed by punching (for example, drilling) through casing 530 on the wall of opening 522. Heating element 630B is then placed into opening 522B. Heating element 630B may be used to provide heat to hydrocarbon layer 460B. Formation fluids, such as pyrolyzed hydrocarbons and/or mobilized hydrocarbons, may be produced from hydrocarbon layer 460B during and/or after heating of the layer by heating element 630B.
Heating hydrocarbon layers 460A, 460B in the time-sequenced manners described above may be more economical than producing from only one layer or using vertical heaters to provide heat to the layers simultaneously. Using relatively vertical openings 522 to access both hydrocarbon layers at different times may save on capital costs associated with forming openings in the formation and providing surface facilities to power the heating elements. Heating hydrocarbon layer 460A first before heating hydrocarbon layer 460B may improve the economics of treating the formation (for example, the net present value of a project to treat the formation). In addition, impermeable zone 740 and packing 532 may provide a seal for hydrocarbon layer 460A after heating and production from the layer. This seal may be useful for abandonment of the hydrocarbon layer after treating the hydrocarbon layer.
In some embodiments, heat may be scavenged from hydrocarbon layer 460A and used to provide heat to hydrocarbon layer 460B. For example, a heat transfer fluid may be circulated through opening 522A to recover heat from hydrocarbon layer 460A. The heat transfer fluid may later be used to provide heat directly or indirectly (for example, using a heat exchanger to transfer heat to another heating fluid) to hydrocarbon layer 460B. In some embodiments, heat recovered from hydrocarbon layer 460A is used to provide power (for example, electrical power) to other heaters (for example, heating element 630B used in hydrocarbon layer 460B).
In some embodiments, synthesis gas generation or other post-treatment processes may be performed in hydrocarbon layer 460A before heating in hydrocarbon layer 460B is started. For example, carbon dioxide or other materials may be sequestered in hydrocarbon layer 460A before plugging or sealing off the layer.
In certain embodiments, portions of the wellbore that extend through the overburden include casings. The casings may include materials that inhibit inductive effects in the casings. Inhibiting inductive effects in the casings may inhibit induced currents in the casing and/or reduce heat losses to the overburden. In some embodiments, the overburden casings may include non-metallic materials such as fiberglass, polyvinylchloride (PVC), chlorinated PVC (CPVC), high-density polyethylene (HDPE), high temperature polymers (such as nitrogen based polymers), or other high temperature plastics. HDPEs with working temperatures in a usable range include HDPEs available from Dow Chemical Co., Inc. (Midland, Mich., U.S.A.). The overburden casings may be made of materials that are spoolable so that the overburden casings can be spooled into the wellbore. In some embodiments, overburden casings may include non-magnetic metals such as aluminum or non-magnetic alloys such as manganese steels having at least 10% manganese, iron aluminum alloys with at least 18% aluminum, or austentitic stainless steels such as 304 stainless steel or 316 stainless steel. In some embodiments, overburden casings may include carbon steel or other ferromagnetic material coupled on the inside diameter to a highly conductive non-ferromagnetic metal (for example, copper or aluminum) to inhibit inductive effects or skin effects. In some embodiments, overburden casings are made of inexpensive materials that may be left in the formation (sacrificial casings).
In certain embodiments, wellheads for the wellbores may be made of one or more non-ferromagnetic materials.
In some embodiments, ferromagnetic materials in the wellhead are electrically coupled to a non-ferromagnetic material (for example, copper) to inhibit skin effect heat generation in the ferromagnetic materials in the wellhead. The non-ferromagnetic material is in electrical contact with the ferromagnetic material so that current flows through the non-ferromagnetic material. In certain embodiments, as shown in
In some embodiments, two or more substantially horizontal wellbores are branched off of a first substantially vertical wellbore drilled downwards from a first location on a surface of the formation. The substantially horizontal wellbores may be substantially parallel through a hydrocarbon layer. The substantially horizontal wellbores may reconnect at a second substantially vertical wellbore drilled downwards at a second location on the surface of the formation. Having multiple wellbores branching off of a single substantially vertical wellbore drilled downwards from the surface reduces the number of openings made at the surface of the formation.
In certain embodiments, a horizontal heater, or a heater at an incline is installed in more than one part.
During installation of heater 716, heating section 716A may be installed first into the formation. Heating section 716A may be installed by pushing the heating section into the opening in the formation using a drill pipe or other installation tool that pushes the heating section into the opening. After installation of heating section 716A, the installation tool may be removed from the opening in the formation. Installing only heating section 716A with the installation tool at this time may allow the heating section to be installed further into the formation than if the heating section and the lead-in section are installed together because a higher compressive strength may be applied to the heating section alone (the installation tool only has to push in the horizontal or inclined direction).
In some embodiments, heating section 716A is coupled to mechanical connector 2028. Connector 2028 may be used to hold heating section 716A in the opening. In some embodiments, connector 2028 includes copper or other electrically conductive materials so that the connector is used as an electrical connector (for example, as an electrical ground). In some embodiments, connector 2028 is used to couple heating section 716A to a bus bar or electrical return rod located in an opening perpendicular to the opening of the heating section.
Lead-in section 716B may be installed after installation of heating section 716A. Lead-in section 716B may be installed with a drill pipe or other installation tool. In some embodiments, the installation tool may be the same tool used to install heating section 716A.
Lead-in section 716B may couple to heating section 716A as the lead-in section is installed into the opening. In certain embodiments, coupling joint 2570 is used to couple lead-in section 716B to heating section 716A. Coupling joint 2570 may be located on either lead-in section 716B or heating section 716A. In some embodiments, coupling joint 2570 includes portions located on both sections. Coupling joint 2570 may be a coupler such as, but not limited to, a wet connect or wet stab. In some embodiments, heating section 716A includes a catcher or other tool that guides an end of lead-in section 716B to form coupling joint 2570.
In some embodiments, coupling joint 2570 includes a container (for example, a can) located on heating section 716A that accepts the end of lead-in section 716B. Electrically conductive beads (for example, balls, spheres, or pebbles) may be located in the container. The beads may move around as the end of lead-in section 716B is pushed into the container to make electrical contact between the lead-in section and heating section 716A. The beads may be made of, for example, copper or aluminum. The beads may be coated or covered with a corrosion inhibitor such as nickel. In some embodiments, the beads are coated with a solder material that melts at lower temperatures (for example, below the boiling point of water in the formation). A high electrical current may be applied to the container to melt the solder. The melted solder may flow and fill void spaces in the container and be allowed to solidify before energizing the heater. In some embodiments, sacrificial beads are put in the container. The sacrificial beads may corrode first so that copper or aluminum beads in the container are less likely to be corroded during operation of the heater.
Continuous tubulars, such as coil tubing, have been used for many years. Running continuous tubulars into and/or out of a wellbore may be simpler and faster than running tubing formed of conventional jointed pipe.
Continuous tubulars may be run into and/or out of wellbores using injectors. Injectors may force the continuous tubulars into the wells through a lubricator assembly or stuffing box to overcome any well pressure until the weight of the continuous tubulars exceeds the force applied by the well pressure that acts against the cross-sectional area of the continuous tubulars. Once the weight of the continuous tubular overcomes the pressure, the continuous tubular may need to be supported by the injector. The process may be reversed as the continuous tubular is removed from the well.
A method for running dual jointed tubing strings into and out of wells is described in U.S. Pat. No. 4,474,236 to Kellett, which is incorporated by reference as if fully set forth herein. Kellett describes a method and apparatus for completing a well using jointed production and service strings of different diameters. The method includes steps of running the production string on a main tubing string hanger while maintaining control with a variable bore blowout preventer; and, running the service string into the main tubing string hanger while maintaining control with a dual bore blowout preventer.
Continuous tubulars have been used for various well treatment processes such as fracturing, acidizing, and gravel packing. Typically, several thousand feet of flexible, seamless tubing is coiled onto a large reel that is mounted on a truck or skid. A continuous tubular injector with a chain-track drive, or equivalent, may be mounted above the wellhead. The continuous tubular may be fed to the injector for injection into the well. The continuous tubular may be straightened as it is removed from the reel by a continuous tubular guide that aligns the continuous tubular with the wellbore and the injector mechanism.
The use of dual continuous tubulars for well servicing and production is known in the art. Recent developments in well completion and well workover have demonstrated the utility of using two continuous tubulars concurrently for many downhole operations. A difficulty with injecting dual continuous tubulars into a wellbore is the proximity of the respective continuous tubulars and the lack of working space to deploy a pair of continuous tubular injector assemblies mounted above the wellhead. This problem was apparently resolved with a coil tubing string injector assembly adapted to simultaneously inject dual string coil tubing into a wellbore, as disclosed in U.S. Pat. No. 6,516,891 to Dallas, which is incorporated herein by reference.
Another problem associated with the injection of dual continuous tubulars into a wellbore is the prevention of fluid leakage during the injection of the dual continuous tubulars, especially when a long downhole tool is connected to one or both of the continuous tubulars. Downhole tools typically have a larger diameter than the continuous tubular and cannot be plastically deformed, which presents certain difficulties. It is known in the art how to overcome these difficulties while injecting a single continuous tubular. For example, U.S. Pat. No. 4,940,095 to Newman, which is incorporated herein by reference, discloses a method of inserting a well service tool connected to a coiled tubing string, which avoids the high and/or remote mounting of a heavy coiled tubing injector drive mechanism. A closed-end lubricator is used to house the tool until it is run down through a blowout preventer connected to a top of the well. The pipe rams of the blowout preventer are closed around the tool to support it while a tubing injector is mounted to the wellhead and the coil tubing string is connected to the tool. The blowout preventer is then opened and the coil tubing string injector is used to run the tool into the well. However, Newman fails to address the use of dual string continuous tubulars.
Many subsurface wells are fitted with permanent sensors, such as pressure and temperature sensors, which require electrical power to transmit signals from the sensors to a remote point at the surface. Subsurface wells may employ subsurface equipment such as pumps or heaters, which may also require electrical power. In order to supply power to these subsurface pieces of equipment, electric current from a source outside of the wellhead must be transferred through the wellhead to the electrically responsive device. Electrical power can be supplied downhole by several methods. These methods include, but are not limited to, electrical umbilical cords, rigid tubular conductors, or coiled tubing. No matter which method of power supply is employed, in order to transfer the power through the wellhead, the power supply is transferred through either the tubing hanger or the casing hanger.
The extreme environmental conditions inside the wellhead coupled with the rough nature of completion operations may cause damage to devices used to supply electrical power. Damaged equipment may potentially lead to electrical short-circuits that can present a hazard to persons working around the wellhead. Since the majority of wellhead equipment is constructed of conductive materials, an electrical short inside of the wellhead may charge the outer surface of the wellhead. Unprotected persons may be exposed to electrical shock if contact is made with the wellhead's outer surface. Continuous tubulars subjected to electrical charge (for example, heaters) may be insulated from the wellhead of the wellbore.
Typically, a continuous tubular is inserted into a wellhead through a lubricator assembly or a stuffing box because there is a pressure differential between the wellbore and atmosphere. The pressure differential may be naturally or artificially created and produce oil or gas, or a mixture thereof, from the pressurized well. Wellhead mechanisms may inhibit movement of continuous tubulars upward and out of the wellbore as well as inhibit downward movement into the wellbore.
In certain embodiments, a suspension mechanism is capable of suspending dual continuous tubulars (for example, dual insulated conductor heaters). In some embodiments, the suspension mechanism includes slips or special fittings. With slips, a radial gripping force keeps dual continuous tubulars suspended and inhibits downward movement. In some embodiments, the slips inhibit upward movement (for example, upward movement of the dual continuous tubulars). Inhibiting upward movement may be accomplished by using a reverse slip arrangement. Conventional wellheads and hangers may not be designed to restrain movement of continuous tubulars in the upward direction. Instead, conventional wellheads and hangers may be only designed to suspend the strings due to the gravitational load of the continuous tubulars.
Deployment and suspension of continuous tubulars in the wellbore may require a mechanism that suspends the dual continuous tubulars in the wellhead by some suitable hanging mechanism or hanger. The hanging/suspension mechanisms may function when the dual legs of the continuous tubulars are deployed simultaneously. Conventionally, dual continuous tubulars are not deployed simultaneously. In some embodiments, a suspension mechanism is able to suspend the vertical downward load of both the tubulars as well as inhibit the upward movement of the tubulars.
The wellhead and the suspension mechanism may include one or more seals 2038. Seals 2038 may inhibit wellbore fluids from migrating upwards. Seals 2038 may help maintain a desired pressure in the wellbore. Wellcap 448 keeps the suspension mechanism in place and inhibits upward movement. Wellhead 450 may include an opening in which the suspension mechanism is positioned. The opening may narrow to a diameter less than that of the suspension mechanism to inhibit downward movement of the suspension mechanism.
In some embodiments, inhibitors include coatings. The coating may impart specific desirable properties to the inhibitor to which the coating is applied. For example, a coating may include a temperature resistant polymer coating.
Suspension mechanism 2040 may include lower portion 2040A and upper portion 2040B. Upper portion 2040B may include at least two openings with diameters large enough to allow passage of the tubulars at both ends of each opening, but small enough at the proximal ends of the openings to inhibit passage of upper inhibitors 2044B in an upward direction. The distal ends of the openings may be large enough to allow the upper inhibitors to sit within the openings of the upper portion 2044B of suspension mechanism 2040. Lower portion 2040A may include at least two openings with diameters large enough to allow passage of the tubulars at both ends of the openings, but small enough at the distal end of each opening to inhibit passage of lower inhibitors 2044A in a downward direction. The proximal ends of the openings may be large enough to allow the lower inhibitors to sit within the openings of lower portion 2040A of suspension mechanism 2040.
Suspension mechanism 2040 may include locks 2046. In some embodiments, locks 2046 are screws, bolts, or other types of fasteners. Locks 2046 inhibit movement of one or more portions of suspension mechanism 2040 within wellhead 450. Wellhead 450 may include an opening in which suspension mechanism 2040 is positioned. The opening may narrow to a diameter less than that of suspension mechanism 2040 to inhibit downward movement of the suspension mechanism.
In some embodiments, the above operation is done in a ‘false wellhead housing’ (not shown) just above the wellhead after the inhibitors are tightened together, the tubulars are lifted, until they clear the false-wellhead, which is then removed. The tubulars along with the suspension mechanism are lowered into a wellhead housing and the load is transferred to the shoulder (for example, a protrusion or narrowing of the opening in the wellhead which inhibits movement of the suspension mechanism beyond the protrusion). The locks 2046′″ are tightened to inhibit movement of the suspension mechanism relative to the wellhead.
In some embodiments, lower portion 2040A may include a tapered opening extending through it. The lower portion may include a carrier with a tapered shape complementary to the tapered opening in the lower portion. The carrier may sit within the tapered opening of the lower portion. Inhibitors 2044A fit in complementary tapered openings through the carrier. The load of the tubulars, once positioned, is transferred from the inhibitors to the carrier to the lower portion, and then to the wellhead. Using a lower portion with a carrier for the inhibitors may be advantageous when the distance between tubulars is small.
Power supplies are used to provide power to downhole power devices (downhole loads) such as, but not limited to, reservoir heaters, electric submersible pumps (ESPs), compressors, electric drills, electrical tools for construction and maintenance, diagnostic systems, sensors, or acoustic wave generators. Surface based power supplies may have long supply cabling (power cables) that contribute to problems such as voltage drops and electrical losses. Thus, it may be necessary to provide power to the downhole loads at high voltages to reduce electrical losses. However, many downhole loads are limited by an acceptable supply voltage level to the load. Therefore, an efficient high-voltage energy supply may not be viable without further conditioning. In such cases, a system for stepping down the voltage from the high voltage supply cable to the low voltage load may be necessary. The system may be a transformer.
The electrical power supply for downhole loads is typically provided using alternating voltage (AC voltage) from supply grids of 50 Hz or 60 Hz frequency. The voltage of the supply grid may correspond to the voltage of the downhole load. High supply voltages may reduce loss and voltage drop in the supply cable and/or allow the use of supply cables with relatively small cross sections. High supply voltages, however, may cause technically difficulties and require cost intensive isolation efforts at the load. Voltage drops, electrical losses, and supply cable cross section limits may limit the length of the supply cable and, thus, the wellbore depth or depth of the downhole load. Locating the transformer downhole may reduce the amount of cabling needed to provide power to the downhole loads and allow deeper wellbore depths and/or downhole load depths while minimizing voltage drops and electrical losses in the power system.
Current technical solutions for offshore-applications make use of sea-bed mounted step-down transformers to reduce cable loss (for example, “Converter-Fed Subsea Motor Drives”, Raad, R. O.; Henriksen, T.; Raphael, H. B.; Hadler-Jacobsen, A.; Industry Applications, IEEE Transactions on Volume 32, Issue 5, September-October 1996 Page(s): 1069-1079, which is incorporated by reference as if fully set forth herein). However, these sea-bed mounted transformers may not be useful to drive downhole loads under solid ground (for example, in a subsurface wellbore).
Core 2054 may include two half-shell core sections 2054A and 2054B around primary windings 2052A and secondary windings 2052B. In certain embodiments, core sections 2054A and 2054B are semicircular, symmetric shells. Core sections 2054A and 2054B may be single pieces that extend the full length of transformer 728 or the core sections may be assembled from multiple shell segments put together (for example, multiple pieces strung together to make the core sections). In certain embodiments, a core section is formed by putting together the section from two halves. The two halves of the core section may be put together after the windings, which may be pre-fabricated, are placed in the transformer.
In certain embodiments, core sections 2054A and 2054B have about the same cross section on the circumference of transformer 728 so that the core properly guides the magnetic flux in the transformer. Core sections 2054A and 2054B may be made of several layers of core material. Certain orientations of these layers may be designed to minimize eddy current losses in transformer 728. In some embodiments, core sections 2054A and 2054B are made of continuous ribbons and windings 2052A and 2052B are wound into the core sections.
Transformer 728 may have certain advantages over current transformer configurations (such as a toroid core design with the winding on the outside of the cores). Core sections 2054A and 2054B have outer surfaces that offer large surface areas for cooling transformer 728. Additionally, transformer 728 may be sealed so that a cooling liquid may be continuously run across the outer surfaces of the transformer to cool the transformer. Transformer 728 may be sealed so that cooling liquids do not directly contact the inside of the core and/or the windings. In certain embodiments, transformer is sealed in an epoxy resin or other electrically insulating sealing material. Cooling transformer 728 allows the transformer to operate at higher power densities. In certain embodiments, windings 2052A and 2052B are substantially isolated from core sections 2054A and 2054B so that the outside surfaces of transformer 728 may touch the walls of a wellbore without causing electrical problems in the wellbore.
In some embodiments, the profile of the core of transformer 728 and/or the winding window profile are made with clearances to allow for additional cooling devices, mechanical supports, and/or electrical contacts on the transformer. In some embodiments, transformer 728 is coupled to one or more additional transformers in the subsurface wellbore to increase power in the wellbore and/or phase options in the wellbore. Transformer 728 and/or the phases of the transformer may be coupled to the additional transformers, and/or the varying phases of the additional transformers, in either series or parallel configurations as needed to provide power to the downhole load.
Power lead 2058 may be coupled to transformer 728 and pass through packing material 532 to provide power to the downhole load (for example, a downhole heater). In certain embodiments, cooling fluid 2056 is located in wellbore 756. Transformer 728 may be immersed in cooling fluid 2056. Cooling fluid 2056 may cool transformer 728 by removing heat from the transformer and moving the heat away from the transformer. Cooling fluid 2056 may be circulated in wellbore 756 to increase heat transfer between transformer 728 and the cooling fluid. In some embodiments, cooling fluid 2056 is circulated to a chiller or other heat exchanger to remove heat from the cooling fluid and maintain a temperature of the cooling fluid at a selected temperature. Maintaining cooling fluid 2056 at a selected temperature may provide efficient heat transfer between the cooling fluid and transformer 728 so that the transformer is maintained at a desired operating temperature.
In certain embodiments, cooling fluid 2056 maintains a temperature of transformer 728 below a selected temperature. The selected temperature may be a maximum operating temperature of the transformer. In some embodiments, the selected temperature is a maximum temperature that allows for a selected operational efficiency of the transformer. In some embodiments, transformer 728 operates at an efficiency of at least 95%, at least 90%, at least 80%, or at least 70% when the transformer operates below the selected temperature.
In certain embodiments, cooling fluid 2056 is water. In some embodiments, cooling fluid 2056 is another heat transfer fluid such as, but not limited to, oil, ammonia, helium, or Freon® (E.I. du Pont de Nemours and Company, Wilmington, Del., U.S.A.). In some embodiments, the wellbore adjacent to the overburden functions as a heat pipe. Transformer 728 boils cooling fluid 2056. Vaporized cooling fluid 2056 rises in the wellbore, condenses, and flows back to transformer 728. Vaporization of cooling fluid 2056 transfers heat to the cooling fluid and condensation of the cooling fluid allows heat to transfer to the overburden. Transformer 728 may operate near the vaporization temperature of cooling fluid 2056.
In some embodiments, cooling fluid is circulated in a pipe that surrounds the transformer. The pipe may be in direct thermal contact with the transformer so that heat is removed from the transformer into the cooling fluid circulating through the pipe. In some embodiments, the transformer includes fans, heat sinks, fins, or other devices that assist in transferring heat away from the transformer. In some embodiments, the transformer is, or includes, a solid state transformer device such as an AC to DC converter.
In certain embodiments, cooling fluid 2056 is circulated using a heat pipe in wellbore 756.
Computational analysis has shown that a circulated water column was sufficient to cool a 60 Hz transformer that was 125 feet in length and generated 80 W/ft of heat. The transformer and the formation were initially at ambient temperatures. The water column was initially at an elevated temperature. The water column and transformer cooled over a period of about 1 to 2 hours. The transformer initially heated up (but was still at operable temperatures) but then was cooled by the water column to lower operable temperatures. The computations also showed that the transformer would be cooled by the water column when the transformer and the formation were initially at higher than normal temperatures.
In certain embodiments, a temperature limited heater is utilized for heavy oil applications (for example, treatment of relatively permeable formations or tar sands formations). A temperature limited heater may provide a relatively low Curie temperature and/or phase transformation temperature range so that a maximum average operating temperature of the heater is less than 350° C., 300° C., 250° C., 225° C., 200° C., or 150° C. In an embodiment (for example, for a tar sands formation), a maximum temperature of the heater is less than about 250° C. to inhibit olefin generation and production of other cracked products. In some embodiments, a maximum temperature of the heater above about 250° C. is used to produce lighter hydrocarbon products. For example, the maximum temperature of the heater may be at or less than about 500° C.
A heater may heat a volume of formation adjacent to a production wellbore (a near production wellbore region) so that the temperature of fluid in the production wellbore and in the volume adjacent to the production wellbore is less than the temperature that causes degradation of the fluid. The heat source may be located in the production wellbore or near the production wellbore. In some embodiments, the heat source is a temperature limited heater. In some embodiments, two or more heat sources may supply heat to the volume. Heat from the heat source may reduce the viscosity of crude oil in or near the production wellbore. In some embodiments, heat from the heat source mobilizes fluids in or near the production wellbore and/or enhances the flow of fluids to the production wellbore. In some embodiments, reducing the viscosity of crude oil allows or enhances gas lifting of heavy oil (approximately at most 10° API gravity oil) or intermediate gravity oil (approximately 12° to 20° API gravity oil) from the production wellbore. In certain embodiments, the initial API gravity of oil in the formation is at most 10°, at most 20°, at most 25°, or at most 30°. In certain embodiments, the viscosity of oil in the formation is at least 0.05 Pa·s (50 cp). In some embodiments, the viscosity of oil in the formation is at least 0.10 Pa·s (100 cp), at least 0.15 Pa·s (150 cp), or at least at least 0.20 Pa·s (200 cp). Large amounts of natural gas may have to be utilized to provide gas lift of oil with viscosities above 0.05 Pa·s. Reducing the viscosity of oil at or near the production wellbore in the formation to a viscosity of 0.05 Pa·s (50 cp), 0.03 Pa·s (30 cp), 0.02 Pa·s (20 cp), 0.01 Pa·s (10 cp), or less (down to 0.001 Pa·s (1 cp) or lower) lowers the amount of natural gas needed to lift oil from the formation. In some embodiments, reduced viscosity oil is produced by other methods such as pumping.
The rate of production of oil from the formation may be increased by raising the temperature at or near a production wellbore to reduce the viscosity of the oil in the formation in and adjacent to the production wellbore. In certain embodiments, the rate of production of oil from the formation is increased by 2 times, 3 times, 4 times, or greater, or up to 20 times over standard cold production, which has no external heating of formation during production. Certain formations may be more economically viable for enhanced oil production using the heating of the near production wellbore region. Formations that have a cold production rate approximately between 0.05 m3/(day per meter of wellbore length) and 0.20 m3/(day per meter of wellbore length) may have significant improvements in production rate using heating to reduce the viscosity in the near production wellbore region. In some formations, production wells up to 775 m, up to 1000 m, or up to 1500 m in length are used. For example, production wells between 450 m and 775 m in length are used, between 550 m and 800 m are used, or between 650 m and 900 m are used. Thus, a significant increase in production is achievable in some formations. Heating the near production wellbore region may be used in formations where the cold production rate is not between 0.05 m3/(day per meter of wellbore length) and 0.20 m3/(day per meter of wellbore length), but heating such formations may not be as economically favorable. Higher cold production rates may not be significantly increased by heating the near wellbore region, while lower production rates may not be increased to an economically useful value.
Using the temperature limited heater to reduce the viscosity of oil at or near the production well inhibits problems associated with non-temperature limited heaters and heating the oil in the formation due to hot spots. One possible problem is that non-temperature limited heaters can cause coking of oil at or near the production well if the heater overheats the oil because the heaters are at too high a temperature. Higher temperatures in the production well may also cause brine to boil in the well, which may lead to scale formation in the well. Non-temperature limited heaters that reach higher temperatures may also cause damage to other wellbore components (for example, screens used for sand control, pumps, or valves). Hot spots may be caused by portions of the formation expanding against or collapsing on the heater. In some embodiments, the heater (either the temperature limited heater or another type of non-temperature limited heater) has sections that are lower because of sagging over long heater distances. These lower sections may sit in heavy oil or bitumen that collects in lower portions of the wellbore. At these lower sections, the heater may develop hot spots due to coking of the heavy oil or bitumen. A standard non-temperature limited heater may overheat at these hot spots, thus producing a non-uniform amount of heat along the length of the heater. Using the temperature limited heater may inhibit overheating of the heater at hot spots or lower sections and provide more uniform heating along the length of the wellbore.
In certain embodiments, fluids in the relatively permeable formation containing heavy hydrocarbons are produced with little or no pyrolyzation of hydrocarbons in the formation. In certain embodiments, the relatively permeable formation containing heavy hydrocarbons is a tar sands formation. For example, the formation may be a tar sands formation such as the Athabasca tar sands formation in Alberta, Canada or a carbonate formation such as the Grosmont carbonate formation in Alberta, Canada. The fluids produced from the formation are mobilized fluids. Producing mobilized fluids may be more economical than producing pyrolyzed fluids from the tar sands formation. Producing mobilized fluids may also increase the total amount of hydrocarbons produced from the tar sands formation.
In
In the embodiments depicted in
In certain embodiments, hydrocarbon layer 460 has sufficient permeability to allow mobilized fluids to drain to production wells 206A and/or production wells 206B. For example, hydrocarbon layer 460 may have a permeability of at least about 0.1 darcy, at least about 1 darcy, at least about 10 darcy, or at least about 100 darcy. In some embodiments, hydrocarbon layer 460 has a relatively large vertical permeability to horizontal permeability ratio (Kv/Kh). For example, hydrocarbon layer 460 may have a Kv/Kh ratio between about 0.01 and about 2, between about 0.1 and about 1, or between about 0.3 and about 0.7.
In certain embodiments, fluids are produced through production wells 206A located near heaters 716 in the lower portion of hydrocarbon layer 460. In some embodiments, fluids are produced through production wells 206B located below and approximately midway between heaters 716 in the lower portion of hydrocarbon layer 460. At least a portion of production wells 206A and/or production wells 206B may be oriented substantially horizontal in hydrocarbon layer 460 (as shown in
In some embodiments, production wells 206A are positioned substantially vertically below the bottommost heaters in hydrocarbon layer 460. Production wells 206A may be located below heaters 716 at the bottom vertex of a pattern of the heaters (for example, at the bottom vertex of the triangular pattern of heaters depicted in
In certain embodiments, the bottommost heaters are located between about 2 m and about 10 m from the bottom of hydrocarbon layer 460, between about 4 m and about 8 m from the bottom of the hydrocarbon layer, or between about 5 m and about 7 m from the bottom of the hydrocarbon layer. In certain embodiments, production wells 206A and/or production wells 206B are located at a distance from the bottommost heaters 716 that allows heat from the heaters to superimpose over the production wells but at a distance from the heaters that inhibits coking at the production wells. Production wells 206A and/or production wells 206B may be located a distance from the nearest heater (for example, the bottommost heater) of at most ¾ of the spacing between heaters in the pattern of heaters (for example, the triangular pattern of heaters depicted in
In some embodiments, at least some production wells 206A are located substantially vertically below heaters 716 near shale break 746, as depicted in
In some embodiments, shale break 746 breaks down (is desiccated) as the shale break is heated by heaters 716 on either side of the shale break. As shale break 746 breaks down, the permeability of the shale break increases and the shale break allows fluids to flow through the shale break. Once fluids are able to flow through shale break 746, production wells above the shale break may not be needed for production as fluids can flow to production wells at or near the bottom of hydrocarbon layer 460 and be produced there.
In certain embodiments, the bottommost heaters above shale break 746 are located between about 2 m and about 10 m from the shale break, between about 4 m and about 8 m from the bottom of the shale break, or between about 5 m and about 7 m from the shale break. Production wells 206A may be located between about 2 m and about 10 m from the bottommost heaters above shale break 746, between about 4 m and about 8 m from the bottommost heaters above the shale break, or between about 5 m and about 7 m from the bottommost heaters above the shale break. Production wells 206A may be located between about 0.5 m and about 8 m from shale break 746, between about 1 m and about 5 m from the shale break, or between about 2 m and about 4 m from the shale break.
In some embodiments, heat is provided in production wells 206A and/or production wells 206B, depicted in
In certain embodiments, in situ heat treatment of the relatively permeable formation containing hydrocarbons (for example, the tar sands formation) includes heating the formation to visbreaking temperatures. For example, the formation may be heated to temperatures between about 100° C. and 260° C., between about 150° C. and about 250° C., between about 200° C. and about 240° C., between about 205° C. and 230° C., between about 210° C. and 225° C. In one embodiment, the formation is heated to a temperature of about 220° C. In one embodiment, the formation is heated to a temperature of about 230° C. At visbreaking temperatures, fluids in the formation have a reduced viscosity (versus their initial viscosity at initial formation temperature) that allows fluids to flow in the formation. The reduced viscosity at visbreaking temperatures may be a permanent reduction in viscosity as the hydrocarbons go through a step change in viscosity at visbreaking temperatures (versus heating to mobilization temperatures, which may only temporarily reduce the viscosity). The visbroken fluids may have API gravities that are relatively low (for example, at most about 10°, about 12°, about 15°, or about 19° API gravity), but the API gravities are higher than the API gravity of non-visbroken fluid from the formation. The non-visbroken fluid from the formation may have an API gravity of 7° or less.
In some embodiments, heaters in the formation are operated at full power output to heat the formation to visbreaking temperatures or higher temperatures. Operating at full power may rapidly increase the pressure in the formation. In certain embodiments, fluids are produced from the formation to maintain a pressure in the formation below a selected pressure as the temperature of the formation increases. In some embodiments, the selected pressure is a fracture pressure of the formation. In certain embodiments, the selected pressure is between about 1000 kPa and about 15000 kPa, between about 2000 kPa and about 10000 kPa, or between about 2500 kPa and about 5000 kPa. In one embodiment, the selected pressure is about 10000 kPa. Maintaining the pressure as close to the fracture pressure as possible may minimize the number of production wells needed for producing fluids from the formation.
In certain embodiments, treating the formation includes maintaining the temperature at or near visbreaking temperatures (as described above) during the entire production phase while maintaining the pressure below the fracture pressure. The heat provided to the formation may be reduced or eliminated to maintain the temperature at or near visbreaking temperatures. Heating to visbreaking temperatures but maintaining the temperature below pyrolysis temperatures or near pyrolysis temperatures (for example, below about 230° C.) inhibits coke formation and/or higher level reactions. Heating to visbreaking temperatures at higher pressures (for example, pressures near but below the fracture pressure) keeps produced gases in the liquid oil (hydrocarbons) in the formation and increases hydrogen reduction in the formation with higher hydrogen partial pressures. Heating the formation to only visbreaking temperatures also uses less energy input than heating the formation to pyrolysis temperatures.
Fluids produced from the formation may include visbroken fluids, mobilized fluids, and/or pyrolyzed fluids. In some embodiments, a produced mixture that includes these fluids is produced from the formation. The produced mixture may have assessable properties (for example, measurable properties). The produced mixture properties are determined by operating conditions in the formation being treated (for example, temperature and/or pressure in the formation). In certain embodiments, the operating conditions may be selected, varied, and/or maintained to produce desirable properties in hydrocarbons in the produced mixture. For example, the produced mixture may include hydrocarbons that have properties that allow the mixture to be easily transported (for example, sent through a pipeline without adding diluent or blending the mixture and/or resulting hydrocarbons with another fluid).
At certain times during the operating period, the concentration of components in the formation and/or produced fluids may change. As the concentration of the components in the formation and/or produced fluids and/or hydrocarbons separated from the produced fluid changes due to formation of the components, solubility of the components in the produced fluids and/or separated hydrocarbons tends to change. Hydrocarbons separated from the produced fluid are hydrocarbons that have been treated to remove salty water and/or gases from the produced fluid in order to transport the hydrocarbons. For example, the produced fluids and/or separated hydrocarbons may contain components that are soluble in the condensable hydrocarbon portion of the produced fluids at the beginning of processing. As properties of the hydrocarbons in the produced fluids change (for example, TAN, asphaltenes, P-value, olefin content, mobilized fluids content, visbroken fluids content, pyrolyzed fluids content, or combinations thereof), the components may tend to become less soluble in the produced fluids and/or in the hydrocarbon stream separated from the produced fluids. In some instances, components in the produced fluids and/or components in the separated hydrocarbons may form two phases and/or become insoluble. Formation of two phases, through flocculation of asphaltenes, change in concentration of components in the produced fluids, change in concentration of components in separated hydrocarbons, and/or precipitation of components may result in hydrocarbons that do not meet pipeline, transportation, and/or refining specifications. Additionally, the efficiency of the process may be reduced. For example, further treatment of the produced fluids and/or separated hydrocarbons may be necessary to produce products with desired properties.
During processing, the P-value of the separated hydrocarbons may be monitored and the stability of the produced fluids and/or separated hydrocarbons may be assessed. Typically, a P-value that is at most 1.0 indicates that flocculation of asphaltenes from the separated hydrocarbons generally occurs. If the P-value is initially at least 1.0, and such P-value increases or is relatively stable during heating, then this indicates that the separated hydrocarbons are relatively stabile. Stability of separated hydrocarbons, as assessed by P-value, may be controlled by controlling operating conditions in the formation such as temperature, pressure, hydrogen uptake, hydrocarbon feed flow, or combinations thereof.
In some embodiments, change in API gravity may not occur unless the formation temperature is at least 100° C. For some formations, temperatures of at least 220° C. may be required to reduce desired properties of the formation to produce hydrocarbons that meet desired specifications. At increased temperatures coke formation may occur, even at elevated pressures. As the properties of the formation are changed, the P-value of the separated hydrocarbons may decrease below 1.0 and/or sediment may form, causing the separated hydrocarbons to become unstable.
In some embodiments, olefins may form during heating of formation fluids to produce fluids having a reduced viscosity. Separated hydrocarbons that include olefins may be unacceptable for processing facilities. Olefins in the separated hydrocarbons may cause fouling and/or clogging of processing equipment. For example, separated hydrocarbons that contains olefins may cause coking of distillation units in a refinery, which results in frequent down time to remove the coked material from the distillation units.
During processing, the olefin content of separated hydrocarbons may be monitored and quality of the separated hydrocarbons assessed. Typically, separated hydrocarbons having a bromine number of 3% and/or a CAPP olefin number of 3% as 1-decene equivalent indicates that olefin production is occurring. If the olefin value decreases or is relatively stable during producing, then this indicates that a minimal or substantially low amount of olefins are being produced. Olefin content, as assessed by bromine value and/or CAPP olefin number, may be controlled by controlling operating conditions in the formation such as temperature, pressure, hydrogen uptake, hydrocarbon feed flow, or combinations thereof.
In some embodiments, the P-value and/or olefin content may be controlled by controlling operating conditions. For example, if the temperature increases above 225° C. and the P-value drops below 1.0 the separated hydrocarbons may become unstable. Alternatively, the bromine number and/or CAPP olefin number may increase to above 3%. If the temperature is maintained below 225° C., minimal changes to the hydrocarbon properties may occur. In certain embodiments, operating conditions are selected, varied, and/or maintained to produce separated hydrocarbons having a P-value of at least about 1, at least about 1.1, at least about 1.2, or at least about 1.3. In certain embodiments, operating conditions are selected, varied, and/or maintained to produce separated hydrocarbons having a bromine number of at most about 3%, at most about 2.5%, at most about 2%, or at least about 1.5%. Heating of the formation at controlled operating conditions includes operating at temperatures between about 100° C. and about 260° C., between about 150° C. and about 250° C., between about 200° C. and about 240° C., between about 210° C. and about 230° C., or between about 215° C. and about 225° C. and pressures between about 1000 kPa and about 15000 kPa, between about 2000 kPa and about 10000 kPa, or between about 2500 kPa and about 5000 kPa or at or near a fracture pressure of the formation. In certain embodiments, the selected pressure of about 10000 kPa produces separated hydrocarbons having properties acceptable for transportation and/or refineries (for example, viscosity, P-value, API gravity, olefin content, or combinations thereof).
Examples of produced mixture properties that may be measured and used to assess the separated hydrocarbon portion of the produced mixture include, but are not limited to, liquid hydrocarbon properties such as API gravity, viscosity, asphaltene stability (P-value), olefin content (bromine number and/or CAPP number). In certain embodiments, operating conditions in the formation are selected, varied, and/or maintained to produce an API gravity of at least about 15°, at least about 17°, at least about 19°, or at least about 20° in the produced mixture. In certain embodiments, operating conditions in the formation are selected, varied, and/or maintained to produce a viscosity (measured at 1 atm and 5° C.) of at most about 400 cp, at most about 350 cp, at most about 250 cp, or at most about 100 cp in the produced mixture. As an example, the initial viscosity in the formation of above about 1000 cp or, in some cases, above about 1 million cp. In certain embodiments, operating conditions are selected, varied, and/or maintained to produce an asphaltene stability (P-value) of at least about 1, at least about 1.1, at least about 1.2, or at least about 1.3 in the produced mixture. In certain embodiments, operating conditions are selected, varied, and/or maintained to produce a bromine number of at most about 3%, at most about 2.5%, at most about 2%, or at most about 1.5% in the produced mixture.
In certain embodiments, the mixture is produced from one or more production wells located at or near the bottom of the hydrocarbon layer being treated. In other embodiments, the mixture is produced from other locations in the hydrocarbon layer being treated (for example, from an upper portion of the layer or a middle portion of the layer).
In one embodiment, the formation is heated to 220° C. or 230° C. while maintaining the pressure in the formation below 10000 kPa. The separated hydrocarbon portion of the mixture produced from the formation may have several desirable properties such as, but not limited to, an API gravity of at least 19°, a viscosity of at most 350 cp, a P-value of at least 1.1, and a bromine number of at most 2%. Such separated hydrocarbons may be transportable through a pipeline without adding diluent or blending the mixture with another fluid. The mixture may be produced from one or more production wells located at or near the bottom of the hydrocarbon layer being treated.
In some embodiments, after the formation reaches visbreaking temperatures, the pressure in the formation is reduced. In certain embodiments, the pressure in the formation is reduced at temperatures above visbreaking temperatures. Reducing the pressure at higher temperatures allows more of the hydrocarbons in the formation to be converted to higher quality hydrocarbons by visbreaking and/or pyrolysis. Allowing the formation to reach higher temperatures before pressure reduction, however, may increase the amount of carbon dioxide produced and/or the amount of coking in the formation. For example, in some formations, coking of bitumen (at pressures above 700 kPa) begins at about 280° C. and reaches a maximum rate at about 340° C. At pressures below about 700 kPa, the coking rate in the formation is minimal. Allowing the formation to reach higher temperatures before pressure reduction may decrease the amount of hydrocarbons produced from the formation.
In certain embodiments, the temperature in the formation (for example, an average temperature of the formation) when the pressure in the formation is reduced is selected to balance one or more factors. The factors considered may include: the quality of hydrocarbons produced, the amount of hydrocarbons produced, the amount of carbon dioxide produced, the amount hydrogen sulfide produced, the degree of coking in the formation, and/or the amount of water produced. Experimental assessments using formation samples and/or simulated assessments based on the formation properties may be used to assess results of treating the formation using the in situ heat treatment process. These results may be used to determine a selected temperature, or temperature range, for when the pressure in the formation is to be reduced. The selected temperature, or temperature range, may also be affected by factors such as, but not limited to, hydrocarbon or oil market conditions and other economic factors. In certain embodiments, the selected temperature is in a range between about 275° C. and about 305° C., between about 280° C. and about 300° C., or between about 285° C. and about 295° C.
In certain embodiments, an average temperature in the formation is assessed from an analysis of fluids produced from the formation. For example, the average temperature of the formation may be assessed from an analysis of the fluids that have been produced to maintain the pressure in the formation below the fracture pressure of the formation.
In some embodiments, values of the hydrocarbon isomer shift in fluids (for example, gases) produced from the formation is used to indicate the average temperature in the formation. Experimental analysis and/or simulation may be used to assess one or more hydrocarbon isomer shifts and relate the values of the hydrocarbon isomer shifts to the average temperature in the formation. The assessed relation between the hydrocarbon isomer shifts and the average temperature may then be used in the field to assess the average temperature in the formation by monitoring one or more of the hydrocarbon isomer shifts in fluids produced from the formation. In some embodiments, the pressure in the formation is reduced when the monitored hydrocarbon isomer shift reaches a selected value. The selected value of the hydrocarbon isomer shift may be chosen based on the selected temperature, or temperature range, in the formation for reducing the pressure in the formation and the assessed relation between the hydrocarbon isomer shift and the average temperature. Examples of hydrocarbon isomer shifts that may be assessed include, but are not limited to, n-butane-δ13C4 percentage versus propane-δ13C3 percentage, n-pentane-δ13C5 percentage versus propane-δ13C3 percentage, n-pentane-δ13C5 percentage versus n-butane-δ13C4 percentage, and i-pentane-δ13C5 percentage versus i-butane-δ13C4 percentage. In some embodiments, the hydrocarbon isomer shift in produced fluids is used to indicate the amount of conversion (for example, amount of pyrolysis) that has taken place in the formation.
In some embodiments, weight percentages of saturates in fluids produced from the formation is used to indicate the average temperature in the formation. Experimental analysis and/or simulation may be used to assess the weight percentage of saturates as a function of the average temperature in the formation. For example, SARA (Saturates, Aromatics, Resins, and Asphaltenes) analysis (sometimes referred to as Asphaltene/Wax/Hydrate Deposition analysis) may be used to assess the weight percentage of saturates in a sample of fluids from the formation. In some formations, the weight percentage of saturates has a linear relationship to the average temperature in the formation. The relation between the weight percentage of saturates and the average temperature may then be used in the field to assess the average temperature in the formation by monitoring the weight percentage of saturates in fluids produced from the formation. In some embodiments, the pressure in the formation is reduced when the monitored weight percentage of saturates reaches a selected value. The selected value of the weight percentage of saturates may be chosen based on the selected temperature, or temperature range, in the formation for reducing the pressure in the formation and the relation between the weight percentage of saturates and the average temperature.
In some embodiments, weight percentages of n-C7 in fluids produced from the formation is used to indicate the average temperature in the formation. Experimental analysis and/or simulation may be used to assess the weight percentages of n-C7 as a function of the average temperature in the formation. In some formations, the weight percentages of n-C7 has a linear relationship to the average temperature in the formation. The relation between the weight percentages of n-C7 and the average temperature may then be used in the field to assess the average temperature in the formation by monitoring the weight percentages of n-C7 in fluids produced from the formation. In some embodiments, the pressure in the formation is reduced when the monitored weight percentage of n-C7 reaches a selected value. The selected value of the weight percentage of n-C7 may be chosen based on the selected temperature, or temperature range, in the formation for reducing the pressure in the formation and the relation between the weight percentage of n-C7 and the average temperature.
The pressure in the formation may be reduced by producing fluids (for example, visbroken fluids and/or mobilized fluids) from the formation. In some embodiments, the pressure is reduced below a pressure at which fluids coke in the formation to inhibit coking at pyrolysis temperatures. For example, the pressure is reduced to a pressure below about 1000 kPa, below about 800 kPa, or below about 700 kPa (for example, about 690 kPa). In certain embodiments, the selected pressure is at least about 100 kPa, at least about 200 kPa, or at least about 300 kPa. The pressure may be reduced to inhibit coking of asphaltenes or other high molecular weight hydrocarbons in the formation. In some embodiments, the pressure may be maintained below a pressure at which water passes through a liquid phase at downhole (formation) temperatures to inhibit liquid water and dolomite reactions. After reducing the pressure in the formation, the temperature may be increased to pyrolysis temperatures to begin pyrolyzation and/or upgrading of fluids in the formation. The pyrolyzed and/or upgraded fluids may be produced from the formation.
In certain embodiments, the amount of fluids produced at temperatures below visbreaking temperatures, the amount of fluids produced at visbreaking temperatures, the amount of fluids produced before reducing the pressure in the formation, and/or the amount of upgraded or pyrolyzed fluids produced may be varied to control the quality and amount of fluids produced from the formation and the total recovery of hydrocarbons from the formation. For example, producing more fluid during the early stages of treatment (for example, producing fluids before reducing the pressure in the formation) may increase the total recovery of hydrocarbons from the formation while reducing the overall quality (lowering the overall API gravity) of fluid produced from the formation. The overall quality is reduced because more heavy hydrocarbons are produced by producing more fluids at the lower temperatures. Producing less fluids at the lower temperatures may increase the overall quality of the fluids produced from the formation but may lower the total recovery of hydrocarbons from the formation. The total recovery may be lower because more coking occurs in the formation when less fluids are produced at lower temperatures.
In certain embodiments, the formation is heated using isolated cells of heaters (cells or sections of the formation that are not interconnected for fluid flow). The isolated cells may be created by using larger heater spacings in the formation. For example, large heater spacings may be used in the embodiments depicted in
In certain embodiments, the heat gradient in the formation is modified so that a gas cap is created at or near an upper portion of the hydrocarbon layer. For example, the heat gradient made by heaters 716 depicted in the embodiments depicted in
In certain embodiments, the number and/or location of production wells in the formation is varied based on the viscosity of fluid in the formation. The viscosities in the zones may be assessed before placing the production wells in the formation, before heating the formation, and/or after heating the formation. In some embodiments, more production wells are located in zones in the formation that have lower viscosities. For example, in certain formations, upper portions, or zones, of the formation may have lower viscosities. Thus, more production wells may be located in the upper zones. Locating production wells in the less viscous zones of the formation allows for better pressure control in the formation and/or producing higher quality (more upgraded) oil from the formation.
In some embodiments, zones in the formation with different assessed viscosities are heated at different rates. In certain embodiments, zones in the formation with higher viscosities are heated at higher heating rates than zones with lower viscosities. Heating the zones with higher viscosities at the higher heating rates mobilizes and/or upgrades these zones at a faster rate so that these zones may “catch up” in viscosity and/or quality to the slower heated zones.
In some embodiments, the heater spacing is varied to provide different heating rates to zones in the formation with different assessed viscosities. For example, denser heater spacings (less spaces between heaters) may be used in zones with higher viscosities to heat these zones at higher heating rates. In some embodiments, a production well (for example, a substantially vertical production well) is located in the zones with denser heater spacings and higher viscosities. The production well may be used to remove fluids from the formation and relieve pressure from the higher viscosity zones. In some embodiments, one or more substantially vertical openings, or production wells, are located in the higher viscosity zones to allow fluids to drain in the higher viscosity zones. The draining fluids may be produced from the formation through production wells located near the bottom of the higher viscosity zones.
In certain embodiments, production wells are located in more than one zone in the formation. The zones may have different initial permeabilities. In certain embodiments, a first zone has an initial permeability of at least about 1 darcy and a second zone has an initial permeability of at most about 0.1 darcy. In some embodiments, the first zone has an initial permeability of between about 1 darcy and about 10 darcy. In some embodiments, the second zone has an initial permeability between about 0.01 darcy and 0.1 darcy. The zones may be separated by a substantially impermeable barrier (with an initial permeability of at most about 10 μdarcy or less). Having the production well located in both zones allows for fluid communication (permeability) between the zones and/or pressure equalization between the zones.
In some embodiments, openings (for example, substantially vertical openings) are formed between zones with different initial permeabilities that are separated by a substantially impermeable barrier. Bridging the zones with the openings allows for fluid communication (permeability) between the zones and/or pressure equalization between the zones. In some embodiments, openings in the formation (such as pressure relief openings and/or production wells) allow gases or low viscosity fluids to rise in the openings. As the gases or low viscosity fluids rise, the fluids may condense or increase viscosity in the openings so that the fluids drain back down the openings to be further upgraded in the formation. Thus, the openings may act as heat pipes by transferring heat from the lower portions to the upper portions where the fluids condense. The wellbores may be packed and sealed near or at the overburden to inhibit transport of formation fluid to the surface.
In some embodiments, production of fluids is continued after reducing and/or turning off heating of the formation. The formation may be heated for a selected time. For example, the formation may be heated until it reaches a selected average temperature. Production from the formation may continue after the selected time. Continuing production may produce more fluid from the formation as fluids drain towards the bottom of the formation and/or fluids are upgraded by passing by hot spots in the formation. In some embodiments, a horizontal production well is located at or near the bottom of the formation (or a zone of the formation) to produce fluids after heating is turned down and/or off.
In certain embodiments, initially produced fluids (for example, fluids produced below visbreaking temperatures), fluids produced at visbreaking temperatures, and/or other viscous fluids produced from the formation are blended with diluent to produce fluids with lower viscosities. In some embodiments, the diluent includes upgraded or pyrolyzed fluids produced from the formation. In some embodiments, the diluent includes upgraded or pyrolyzed fluids produced from another portion of the formation or another formation. In certain embodiments, the amount of fluids produced at temperatures below visbreaking temperatures and/or fluids produced at visbreaking temperatures that are blended with upgraded fluids from the formation is adjusted to create a fluid suitable for transportation and/or use in a refinery. The amount of blending may be adjusted so that the fluid has chemical and physical stability. Maintaining the chemical and physical stability of the fluid may allow the fluid to be transported, reduce pre-treatment processes at a refinery and/or reduce or eliminate the need for adjusting the refinery process to compensate for the fluid.
In certain embodiments, formation conditions (for example, pressure and temperature) and/or fluid production are controlled to produce fluids with selected properties. For example, formation conditions and/or fluid production may be controlled to produce fluids with a selected API gravity and/or a selected viscosity. The selected API gravity and/or selected viscosity may be produced by combining fluids produced at different formation conditions (for example, combining fluids produced at different temperatures during the treatment as described above). As an example, formation conditions and/or fluid production may be controlled to produce fluids with an API gravity of about 19° and a viscosity of about 0.35 Pa·s (350 cp) at 19° C.
In some embodiments, formation conditions and/or fluid production is controlled so that water (for example, connate water) is recondensed in the treatment area. In some embodiments, water is vaporized in one section of the formation (for example, using heat provided from heaters) and recondensed in another section of the formation. Vaporized water may move from one section of the formation to another section due to pressure differentials in the formation. Recondensing water in the treatment area keeps the heat of condensation in the formation. The recondensed water may provide heat to the portion or section of the formation in which the water condenses. In some embodiments, condensation of water in the formation increases the mobility of liquid hydrocarbons (oil) in the formation. Liquid water may wet rock or other strata in the formation by occupying pores or corners in the strata and creating a slick surface that allows liquid hydrocarbons to move more readily through the formation.
In some embodiments, condensation of water in the formation pyrolyzes hydrocarbons in the formation. At higher operating pressures, water may condense in a temperature range near the pyrolysis temperature of hydrocarbons in the formation. In certain embodiments, pressure is controlled in the formation or a portion of the formation so that recondensing water pyrolyzes hydrocarbons in the formation, or the portion.
In certain embodiments, a drive process (for example, a steam injection process such as cyclic steam injection, a steam assisted gravity drainage process (SAGD), a solvent injection process, a vapor solvent and SAGD process, or a carbon dioxide injection process) is used to treat the tar sands formation in addition to the in situ heat treatment process. In some embodiments, heaters are used to create high permeability zones (or injection zones) in the formation for the drive process. Heaters may be used to create a mobilization geometry or production network in the formation to allow fluids to flow through the formation during the drive process. For example, heaters may be used to create drainage paths between the heaters and production wells for the drive process. In some embodiments, the heaters are used to provide heat during the drive process. The amount of heat provided by the heaters may be small compared to the heat input from the drive process (for example, the heat input from steam injection).
In some embodiments, the in situ heat treatment process creates or produces the drive fluid in situ. The in situ produced drive fluid may move through the formation and move mobilized hydrocarbons from one portion of the formation to another portion of the formation.
In some embodiments, the in situ heat treatment process may provide less heat to the formation (for example, use a wider heater spacing) if the in situ heat treatment process is followed by the drive process. The drive process may be used to increase the amount of heat provided to the formation to compensate for the loss of heat injection.
In some embodiments, the drive process is used to treat the formation and produce hydrocarbons from the formation. The drive process may recover a low amount of oil in place from the formation (for example, less than 20% recovery of oil in place from the formation). The in situ heat treatment process may be used following the drive process to increase the recovery of oil in place from the formation. In some embodiments, the drive process preheats the formation for the in situ heat treatment process. In some embodiments, the formation is treated using the in situ heat treatment process a significant time after the formation has been treated using the drive process. For example, the in situ heat treatment process is used 1 year, 2 years, 3 years, or longer after a formation has been treated using the drive process. The in situ heat treatment process may be used on formations that have been left dormant after the drive process treatment because further hydrocarbon production using the drive process is not possible and/or not economically feasible. In some embodiments, the formation remains at least somewhat preheated from the drive process even after the significant time.
In some embodiments, heaters are used to preheat the formation for the drive process. For example, heaters may be used to create injectivity in the formation for a drive fluid. The heaters may create high mobility zones (or injection zones) in the formation for the drive process. In certain embodiments, heaters are used to create injectivity in formations with little or no initial injectivity. Heating the formation may create a mobilization geometry or production network in the formation to allow fluids to flow through the formation for the drive process. For example, heaters may be used to create a fluid production network between a horizontal heater and a vertical production well. The heaters used to preheat the formation for the drive process may also be used to provide heat during the drive process.
The vertical location of heaters 716 with respect to injection wells 748 and production wells 206 depends on, for example, the vertical permeability of the formation. In formations with at least some vertical permeability, injected steam will rise to the top of the permeable layer in the formation. In such formations, heaters 716 may be located near the bottom of hydrocarbon layer 460, as shown in
In certain embodiments, a fluid is injected into the formation (for example, a drive fluid or an oxidizing fluid) to move hydrocarbons through the formation from a first section to a second section. In some embodiments, the hydrocarbons are moved from the first section to the second section through a third section.
In certain embodiments, sections 2572A and 2572C are heated at or near the same time to similar temperatures (for example, pyrolysis temperatures). Sections 2572A and 2572C may be heated to mobilize and/or pyrolyze hydrocarbons in the sections. The mobilized and/or pyrolyzed hydrocarbons may be produced (for example, through one or more production wells) from section 2572A and/or section 2572C. Section 2572B may be heated to lower temperatures (for example, mobilization temperatures). Little or no production of hydrocarbons to the surface may take place through section 2572B. For example, sections 2572A and 2572C may be heated to average temperatures of about 300° C. while section 2572B is heated to an average temperature of about 100° C. and no production wells are operated in section 2572B.
In certain embodiments, heating and producing hydrocarbons from section 2572C creates fluid injectivity in the section. After fluid injectivity has been created in section 2572C, a fluid such as a drive fluid (for example, steam, water, or hydrocarbons) and/or an oxidizing fluid (for example, air, oxygen, enriched oxygen, or other oxidants) may be injected into the section. The fluid may be injected through heaters 716, a production well, and/or an injection well located in section 2572C. In some embodiments, heaters 716 continue to provide heat while the fluid is being injected. In other embodiments, heaters 716 may be turned down or off before or during fluid injection.
In some embodiments, providing oxidizing fluid such as air to section 2572C causes oxidation of hydrocarbons in the section. For example, coked hydrocarbons and/or heated hydrocarbons in section 2572C may oxidize if the temperature of the hydrocarbons is above an oxidation ignition temperature. In some embodiments, treatment of section 2572C with the heaters creates coked hydrocarbons with substantially uniform porosity and/or substantially uniform injectivity so that heating of the section is controllable when oxidizing fluid is introduced to the section. The oxidation of hydrocarbons in section 2572C will maintain the average temperature of the section or increase the average temperature of the section to higher temperatures (for example, about 400° C. or above).
In some embodiments, injection of the oxidizing fluid is used to heat section 2572C and a second fluid is introduced into the formation after or with the oxidizing fluid to create drive fluids in the section. During injection of air, excess air and/or oxidation products may be removed from section 2572C through one or more producer wells. After the formation is raised to a desired temperature, a second fluid may be introduced into section 2572C to react with coke and/or hydrocarbons and generate drive fluid (for example, synthesis gas). In some embodiments, the second fluid includes water and/or steam. Reactions of the second fluid with carbon in the formation may be endothermic reactions that cool the formation. In some embodiments, oxidizing fluid is added with the second fluid so that some heating of section 2572C occurs simultaneous with the endothermic reactions. In some embodiments, section 2572C may be treated in alternating steps of adding oxidant to heat the formation, and then adding second fluid to generate drive fluids.
The generated drive fluids in section 2572C may include steam, carbon dioxide, carbon monoxide, hydrogen, methane, and/or pyrolyzed hydrocarbons. The high temperature in section 2572C and the generation of drive fluid in the section may increase the pressure of the section so the drive fluids move out of the section into adjacent sections. The increased temperature of section 2572C may also provide heat to section 2572B through conductive heat transfer and/or convective heat transfer from fluid flow (for example, hydrocarbons and/or drive fluid) to section 2572B.
In some embodiments, hydrocarbons (for example, hydrocarbons produced from section 2572C) are provided as a portion of the drive fluid. The injected hydrocarbons may include at least some pyrolyzed hydrocarbons such as pyrolyzed hydrocarbons produced from section 2572C. In some embodiments, steam or water are provided as a portion of the drive fluid. Providing steam or water in the drive fluid may be used to control temperatures in the formation. For example, steam or water may be used to keep temperatures lower in the formation. In some embodiments, water injected as the drive fluid is turned into steam in the formation due to the higher temperatures in the formation. The conversion of water to steam may be used to reduce temperatures or maintain lower temperatures in the formation.
Fluids injected in section 2572C may flow towards section 2572B, as shown by the arrows in
Low level heating of section 2572B mobilizes hydrocarbons in the section. The mobilized hydrocarbons in section 2572B may be moved by the injected fluid through the section towards section 2572A, as shown by the arrows in
In certain embodiments, at least some hydrocarbons in section 2572B are mobilized and drained from the section prior to injecting the fluid into the formation. Some formations may have high oil saturation (for example, the Grosmont formation has high oil saturation). The high oil saturation corresponds to low gas permeability in the formation that may inhibit fluid flow through the formation. Thus, mobilizing and draining (removing) some oil (hydrocarbons) from the formation may create gas permeability for the injected fluids.
Fluids in hydrocarbon layer 460 may preferentially move horizontally within the hydrocarbon layer from the point of injection because tar sands tend to have a larger horizontal permeability than vertical permeability. The higher horizontal permeability allows the injected fluid to move hydrocarbons between sections preferentially versus fluids draining vertically due to gravity in the formation. Providing sufficient fluid pressure with the injected fluid may ensure that fluids are moved to section 2572A for upgrading and/or production.
In certain embodiments, section 2572B has a larger volume than section 2572A and/or section 2572C. Section 2572B may be larger in volume than the other sections so that more hydrocarbons are produced for less energy input into the formation. Because less heat is provided to section 2572B (the section is heated to lower temperatures), having a larger volume in section 2572B reduces the total energy input to the formation per unit volume. The desired volume of section 2572B may depend on factors such as, but not limited to, viscosity, oil saturation, and permeability. In addition, the degree of coking is much less in section 2572B due to the lower temperature so less hydrocarbons are coked in the formation when section 2572B has a larger volume. In some embodiments, the lower degree of heating in section 2572B allows for cheaper capital costs as lower temperature materials (cheaper materials) may be used for heaters used in section 2572B.
Some formations with little or no initial injectivity (such as karsted formations or karsted layers in formations) may have tight vugs in one or more layers of the formations. The tight vugs may be vugs filled with viscous fluids such as bitumen or heavy oil. In some embodiments, the vugs have a porosity of at least about 20 porosity units, at least about 30 porosity units, or at least about 35 porosity units. The formation may have a porosity of at most about 15 porosity units, at most about 10 porosity units, or at most about 5 porosity units. The tight vugs inhibit steam or other fluids from being injected into the formation or the layers with tight vugs. In certain embodiments, the karsted formation or karsted layers of the formation are treated using the in situ heat treatment process.
Heating of these formations or layers may decrease the viscosity of the fluids in the tight vugs and allow the fluids to drain (for example, mobilize the fluids). The formations with karsted layer may have sufficient permeability so that when the viscosity of fluids (hydrocarbons) in the formation is reduced, the fluids drain and/or move through the formation relatively easily (for example, without a need for creating higher permeability in the formation).
In some embodiments, the relative amount (the degree) of karsted in the formation is assessed using techniques known in the art (for example, 3D seismic imaging of the formation). The assessment may give a profile of the formation showing layers or portions with varying amounts of karsted in the formation. In certain embodiments, more heat is provided to more karsted portions of the formation. Less heat may be provided to less karsted portions. In some embodiments, selective amounts of heat are provided to portions of the formation as a function of the degree of karsted in the portions. More or less heating may be provided by varying the number and/or density of heaters in the portions with varying degrees of karsted.
In certain embodiments, the karsted portions have higher viscosities than other non-karsted portions of the formation. Thus, more heat may be provided to the karsted portions to reduce the viscosity of the hydrocarbons in the karsted portions.
In certain embodiments, only the karsted layers of the formation are treated using the in situ heat treatment process. Other non-karsted layers of the formation may be used as seals for the in situ heat treatment process. For example, karsted layers with higher quality (more hydrocarbons in the layer) may be treated while other layers are used as seals for the treatment process. In some embodiments, karsted layers with low quality are used as seals for the treatment process.
In some embodiments, karsted layers with lower quality are treated along with karsted layers with higher quality. In one embodiment, karsted layers with lower quality (upper and lower karsted layers) are above and below a karsted layer with higher quality (middle karsted layer). Less heat may be provided to the upper and lower karsted layers than the middle karsted layer. Less heat may be provided in the upper and lower karsted layers by having greater heat spacing and/or less heaters in the upper and lower karsted layers. In some embodiments, lower heating of the upper and lower karsted layers includes heating the layers to mobilization and/or visbroken temperatures but not to pyrolysis temperatures.
One or more production wells may be located in the middle karsted layer. Mobilized and/or visbroken hydrocarbons from the upper karsted layer may drain to the production wells in the middle karsted layer. Heat provided to the lower karsted layer may create a thermal expansion drive and/or a gas pressure drive in the lower karsted layer. The thermal expansion and/or gas pressure may drive fluids from the lower karsted layer to the middle karsted layer. These fluids may be produced through the production wells in the middle karsted layer. Providing some heat to the upper and lower karsted layers may increase the total recovery of fluids from the formation by, for example, 25% or more.
In some embodiments, the karsted layers with lower quality are further heated to pyrolysis temperatures after production from the karsted layer with higher quality is completed or almost completed. The karsted layers with lower quality may also be further treated by producing fluids through production wells located in the layers.
In some embodiments, the drive process is used after the in situ heat treatment of the karsted formation or karsted layers. In some embodiments, heaters are used to preheat the karsted formation or karsted layers to create injectivity in the formation. In situ heat treatment of karsted formations and/or karsted layers may allow for drive fluid injection where it was previously unfavorable or unmanageable. Typically, karsted formations were unfavorable for the drive process because of the channels in the formations a that did not allow for pressure build up in the formation. In situ heat treatment of karsted formations may allow for steam injection by reducing the viscosity of hydrocarbons in the formation and allowing pressure to buildup in the formations.
In certain embodiments, the karsted formation or karsted layers are heated to temperatures below the decomposition temperature of minerals in the formation (for example, rock minerals such as dolomite and/or clay minerals such as kaolinite, illite, or smectite). In some embodiments, the karsted formation or karsted layers are heated to temperatures of at most about 400° C., at most about 450° C., or at most about 500° C. (for example, to a temperature below a dolomite decomposition temperature at formation pressure). In some embodiments, the karsted formation or karsted layers are heated to temperatures below a decomposition temperature of clay minerals (such as kaolinite) at formation pressure.
In some embodiments, heat is preferentially provided to portions of the formation with lower weight percentages of clay minerals (for example, kaolinite). For example, more heat may be provided to portions of the formation with at most about 1% by weight clay minerals, at most 2% by weight clay minerals, or at most 3% by weight clay minerals than portions of the formation with higher weight percentages of clay minerals. In some embodiments, the rock and/or clay mineral distribution is assessed in the formation prior to designing a heater pattern and installing the heaters. The heaters may be arranged to preferentially provide heat to the portions of the formation with the lower weight percentages of clay minerals. In certain embodiments, the heaters are placed substantially horizontally in layers with lower weight percentages of clay minerals.
Preferentially providing heat to portions with lower weight percentages of clay minerals may minimize the amount of carbon dioxide or other gases produced at lower temperatures in the formation. Portions of the formation with the higher weight percentages of clay minerals may be inhibited from reaching temperatures above decomposition temperatures of the clay minerals at formation pressures by the decomposition of the clay minerals. For example, portions with the higher weight percentages of kaolinite may be inhibited from reaching temperatures above about 240° C. In some embodiments, portions of the formation with the higher weight percentages of clay minerals may be inhibited from reaching temperatures above about 200° C., above about 220° C., above about 240° C., or above about 300° C.
In some embodiments, the decomposition of minerals in the formation is enhanced with presence of water in the formation at higher pressures. With sufficiently high pressures in the formation, water may become acidic. The acidic water may react with minerals such as dolomite and increase the decomposition of the minerals. Water at lower pressures, or non-acidic water, may not react with the minerals in the formation. Thus, controlling the pressure and/or the acidity of water in the formation may control the decomposition of minerals in the formation. In some embodiments, other inorganic acids in the formation enhance the decomposition of minerals such as dolomite.
In some embodiments, the karsted formation or karsted layers are heated to temperatures above the decomposition temperature minerals in the formation. At temperatures above the minerals decomposition temperature, the minerals may decompose to produce carbon dioxide or other products. The decomposition of the minerals and the carbon dioxide production may create permeability in the formation and mobilize viscous fluids in the formation. In some embodiments, the produced carbon dioxide is maintained in the formation to produce a gas cap in the formation. The carbon dioxide may be allowed to rise to the upper portions of the karsted layers to produce the gas cap.
In some embodiments, heaters are used to produce and/or maintain the gas cap in the formation for the in situ heat treatment process and/or the drive process. The gas cap may drive fluids from upper portions to lower portions of the formation and/or from portions of the formation towards portions of the formation at lower pressures (for example, portions with production wells). In some embodiments, little or no heating is provided in the portions of the formation with the gas cap. In some embodiments, heaters in the gas cap are turned down and/or off after formation of the gas cap. Using less heating in the gas cap may reduce the energy input into the formation and increase the efficiency of the in situ heat treatment process and/or the drive process. In some embodiments, production wells and/or heater wells that are located in the gas cap portion of the formation may be used for injection of fluid (for example, steam) to maintain the gas cap.
In some embodiments, the production front of the drive process follows behind the heat front of the in situ heat treatment process. In some embodiments, areas behind the production front are further heated to produce more fluids from the formation. Further heating behind the production front may also maintain the gas cap behind the production front and/or maintain quality in the production front of the drive process.
In certain embodiments, the drive process is used before the in situ heat treatment of the formation. In some embodiments, the drive process is used to mobilize fluids in a first section of the formation. The mobilized fluids may then be pushed into a second section by heating the first section with heaters. Fluids may be produced from the second section. In some embodiments, the fluids in the second section are pyrolyzed and/or upgraded using the heaters.
In formations with low permeabilities, the drive process may be used to create a “gas cushion” or pressure sink before the in situ heat treatment process. The gas cushion may inhibit pressures from increasing quickly to fracture pressure during the in situ heat treatment process. The gas cushion may provide a path for gases to escape or travel during early stages of heating during the in situ heat treatment process.
In some embodiments, the drive process (for example, the steam injection process) is used to mobilize fluids before the in situ heat treatment process. Steam injection may be used to get hydrocarbons (oil) away from rock or other strata in the formation. The steam injection may mobilize the oil without significantly heating the rock.
In some embodiments, injection of a fluid (for example, steam or carbon dioxide) may consume heat in the formation and cool the formation depending on the pressure in the formation. In some embodiments, the injected fluid is used to recover heat from the formation. The recovered heat may be used in surface processing of fluids and/or to preheat other portions of the formation using the drive process.
Heaters 716 are used to heat the second portion of hydrocarbon layer 460 to mobilization, visbreaking, and/or pyrolysis temperatures. Second hydrocarbons are produced from the second portion through production well 206B. In some embodiments, the second hydrocarbons include at least some pyrolyzed hydrocarbons. In certain embodiments, the second hydrocarbons have an API gravity of at least 15°, at least 20°, or at least 25°.
In some embodiments, the first portion of hydrocarbon layer 460 is treated using heaters after the steam injection process. Heaters may be used to increase the temperature of the first portion and/or treat the first portion using an in situ heat treatment process. Second hydrocarbons (including at least some pyrolyzed hydrocarbons) may be produced from the first portion through production well 206A.
In some embodiments, the second portion of hydrocarbon layer 460 is treated using the steam injection process before using heaters 716 to treat the second portion. The steam injection process may be used to produce some fluids (for example, first hydrocarbons or hydrocarbons mobilized by the steam injection) through production well 206B from the second portion and/or preheat the second portion before using heaters 716. In some embodiments, the steam injection process may be used after using heaters 716 to treat the first portion and/or the second portion.
Producing hydrocarbons through both processes increases the total recovery of hydrocarbons from hydrocarbon layer 460 and may be more economical than using either process alone. In some embodiments, the first portion is treated with the in situ heat treatment process after the steam injection process is completed. For example, after the steam injection process no longer produces viable amounts of hydrocarbon from the first portion, the in situ heat treatment process may be used on the first portion.
Steam is provided to injection well 748 from facility 750. Facility 750 is a steam and electricity cogeneration facility. Facility 750 may burn hydrocarbons in generators to make electricity. Facility 750 may burn gaseous and/or liquid hydrocarbons to make electricity. The electricity generated is used to provide electrical power for heaters 716. Waste heat from the generators is used to make steam. In some embodiments, some of the hydrocarbons produced from the formation are used to provide gas for heaters 716, if the heaters utilize gas to provide heat to the formation. The amount of electricity and steam generated by facility 750 may be controlled to vary the production rate and/or quality of hydrocarbons produced from the first portion and/or the second portion of hydrocarbon layer 460. The production rate and/or quality of hydrocarbons produced from the first portion and/or the second portion may be varied to produce a selected API gravity in a mixture made by blending the first hydrocarbons with the second hydrocarbons. The first hydrocarbon and the second hydrocarbons may be blended after production to produce the selected API gravity. The production from the first portion and/or the second portion may be varied in response to changes in the marketplace for either first hydrocarbons, second hydrocarbons, and/or a mixture of the first and second hydrocarbons.
First hydrocarbons produced from production well 206A and/or second hydrocarbons produced from production well 206B may be used as fuel for facility 750. In some embodiments, first hydrocarbons and/or second hydrocarbons are treated (for example, removing undesirable products) before being used as fuel for facility 750. In some embodiments, coke or other hydrocarbon residue produced or removed from the formation (for example, mined from the formation). The hydrocarbon residue may be gasified or burned in a residue burning facility before providing the hydrocarbons to facility 750. The residue burning facility may produce hydrocarbon gases (such as natural gas) and/or other products (such as carbon dioxide or syngas products). The carbon dioxide may be sequestered in the formation after treatment of the formation.
The amount of first hydrocarbons and second hydrocarbons used as fuel for facility 750 may be determined, for example, by economics for the overall process, the marketplace for either first or second hydrocarbons, availability of treatment facilities for either first or second hydrocarbons, and/or transportation facilities available for either first or second hydrocarbons. In some embodiments, most or all the hydrocarbon gas produced from hydrocarbon layer 460 is used as fuel for facility 750. Burning all the hydrocarbon gas in facility 750 eliminates the need for treatment and/or transportation of gases produced from hydrocarbon layer 460.
The produced first hydrocarbons and the second hydrocarbons may be treated and/or blended in facility 752. In some embodiments, the first and second hydrocarbons are blended to make a mixture that is transportable through a pipeline. In some embodiments, the first and second hydrocarbons are blended to make a mixture that is useable as a feedstock for a refinery. The amount of first and second hydrocarbons produced may be varied based on changes in the requirements for treatment and/or blending of the hydrocarbons. In some embodiments, treated hydrocarbons are used in facility 750.
In some embodiments, the steam injection process and the in situ heat treatment process (for example, the in situ conversion process) are used synergistically in different layers (for example, vertically displaced layers) in the formation. For example, in a karsted formation, different zones or layers in the formation may have different oil saturations, water saturations, porosities, and/or permeabilities. Some layers may have good steam injectivities while others have near zero steam injectivity. The steam injectivity may depend on the water saturation of the zone and the permeability. Thus, varying the use of the steam injection process and the in situ heat treatment process in these layers may be economically advantageous by, for example, producing more hydrocarbons with less energy input into the formation. The steam injection process may include steam drive, cyclic steam injection, SAGD, or other process of steam injection into the formation.
In one embodiment, hydrocarbon layers 460A,C have lower oil saturations, higher water saturations, and lower porosities than hydrocarbon layer 460B. The steam injection process may be used in hydrocarbon layers 460A,C using injection wells 748A,C and production wells 206A,C. The in situ heat treatment process may be used in hydrocarbon layer 460B using heaters 716 and production well 206B. In some embodiments, the in situ heat treatment process is used in hydrocarbon layer 460B, which has high oil saturation and low steam injectivity. After the in situ heat treatment of hydrocarbon layer 460B, the layer may have steam injectivity and be treated using the steam injection process.
Injecting steam into hydrocarbon layers 460A,C above and below hydrocarbon layer 460B may increase the efficiency of producing hydrocarbons from the formation. Steam injection in hydrocarbon layers 460A,C lowers the viscosity and increases the pressures in these layers so that hydrocarbons move into hydrocarbon layer 460B. Heat from hydrocarbon layer 460B may conduct and/or convect into hydrocarbon layers 460A,C and preheat these layers to lower the oil viscosity and/or increase the steam injectivity in hydrocarbon layers 460A,C. Additionally, some steam may rise from hydrocarbon layer 460C into hydrocarbon layer 460B. This steam may provide additional heat and increased mobilization in hydrocarbon layer 460B. The steam injection process and/or the in situ heat treatment process may be used (for example, varied) as described above for the embodiment depicted in
In some embodiments, impermeable shale layers exist between hydrocarbon layer 460B and hydrocarbon layers 460A,C. Using the in situ heat treatment process on hydrocarbon layer 460B may desiccate the shale layers and increase the permeability of the shale layers to allow fluid flux through the shale layers. This increased permeability in the shale layers allows mobilized hydrocarbons to flow from hydrocarbon layer 460A into hydrocarbon layer 460B. These hydrocarbons may be upgraded and produced in hydrocarbon layer 460B.
Conduit 754 may be made from carbon steel or more corrosion resistant materials such as stainless steel. Conduit 754 may include apparatus and mechanisms for gas lifting or pumping produced oil to the surface. For example, conduit 754 includes gas lift valves used in a gas lift process. Examples of gas lift control systems and valves are disclosed in U.S. Pat. Nos. 6,715,550 to Vinegar et al. and 7,259,688 to Hirsch et al., and U.S. Patent Application Publication No. 2002-0036085 to Bass et al., each of which is incorporated by reference as if fully set forth herein. Conduit 754 may include one or more openings (perforations) to allow fluid to flow into the production conduit. In certain embodiments, the openings in conduit 754 are in a portion of the conduit that remains below the liquid level in wellbore 756. For example, the openings are in a horizontal portion of conduit 754.
Heater 760 is located in conduit 754, as shown in
In certain embodiments, heater 760 includes ferromagnetic materials such as Carpenter Temperature Compensator “32”, Alloy 42-6, Alloy 52, Invar 36, or other iron-nickel or iron-nickel-chromium alloys. In certain embodiments, nickel or nickel-chromium alloys are used in heater 760. In some embodiments, heater 760 includes a composite conductor with a more highly conductive material such as copper on the inside of the heater to improve the turndown ratio of the heater. Heat from heater 760 heats fluids in or near wellbore 756 to reduce the viscosity of the fluids and increase a production rate through conduit 754.
In certain embodiments, portions of heater 760 above the liquid level in wellbore 756 (such as the vertical portion of the wellbore depicted in
In certain embodiments, heater 760 is electrically isolated on the heater's outside surface and allowed to move freely in conduit 754. In some embodiments, electrically insulating centralizers are placed on the outside of heater 760 to maintain a gap between conduit 754 and the heater.
In some embodiments, heater 760 is cycled (turned on and off) so that fluids produced through conduit 754 are not overheated. In an embodiment, heater 760 is turned on for a specified amount of time until a temperature of fluids in or near wellbore 756 reaches a desired temperature (for example, the maximum temperature of the heater). During the heating time (for example, 10 days, 20 days, or 30 days), production through conduit 754 may be stopped to allow fluids in the formation to “soak” and obtain a reduced viscosity. After heating is turned off or reduced, production through conduit 754 is started and fluids from the formation are produced without excess heat being provided to the fluids. During production, fluids in or near wellbore 756 will cool down without heat from heater 760 being provided. When the fluids reach a temperature at which production significantly slows down, production is stopped and heater 760 is turned back on to reheat the fluids. This process may be repeated until a desired amount of production is reached. In some embodiments, some heat at a lower temperature is provided to maintain a flow of the produced fluids. For example, low temperature heat (for example, 100° C., 125° C., or 150° C.) may be provided in the upper portions of wellbore 756 to keep fluids from cooling to a lower temperature.
In some embodiments, a temperature limited heater positioned in a wellbore heats steam that is provided to the wellbore. The heated steam may be introduced into a portion of the formation. In certain embodiments, the heated steam may be used as a heat transfer fluid to heat a portion of the formation. In some embodiments, the steam is used to solution mine desired minerals from the formation. In some embodiments, the temperature limited heater positioned in the wellbore heats liquid water that is introduced into a portion of the formation.
In an embodiment, the temperature limited heater includes ferromagnetic material with a selected Curie temperature and/or a selected phase transformation temperature range. The use of a temperature limited heater may inhibit a temperature of the heater from increasing beyond a maximum selected temperature (for example, at or about the Curie temperature and/or the phase transformation temperature range). Limiting the temperature of the heater may inhibit potential burnout of the heater. The maximum selected temperature may be a temperature selected to heat the steam to above or near 100% saturation conditions, superheated conditions, or supercritical conditions. Using a temperature limited heater to heat the steam may inhibit overheating of the steam in the wellbore. Steam introduced into a formation may be used for synthesis gas production, to heat the hydrocarbon containing formation, to carry chemicals into the formation, to extract chemicals or minerals from the formation, and/or to control heating of the formation.
A portion of the formation where steam is introduced or that is heated with steam may be at significant depths below the surface (for example, greater than about 1000 m, about 2500, or about 5000 m below the surface). If steam is heated at the surface of the formation and introduced to the formation through a wellbore, a quality of the heated steam provided to the wellbore at the surface may have to be relatively high to accommodate heat losses to the wellbore casing and/or the overburden as the steam travels down the wellbore. Heating the steam in the wellbore may allow the quality of the steam to be significantly improved before the steam is provided to the formation. A temperature limited heater positioned in a lower section of the overburden and/or adjacent to a target zone of the formation may be used to controllably heat steam to improve the quality of the steam injected into the formation and/or inhibit condensation along the length of the heater. In certain embodiments, the temperature limited heater improves the quality of the steam injected and/or inhibits condensation in the wellbore for long steam injection wellbores (especially for long horizontal steam injection wellbores).
A temperature limited heater positioned in a wellbore may be used to heat the steam to above or near 100% saturation conditions or superheated conditions. In some embodiments, a temperature limited heater may heat the steam so that the steam is above or near supercritical conditions. The static head of fluid above the temperature limited heater may facilitate producing 100% saturation, superheated, and/or supercritical conditions in the steam. Supercritical or near supercritical steam may be used to strip hydrocarbon material and/or other materials from the formation. In certain embodiments, steam introduced into the formation may have a high density (for example, a specific gravity of about 0.8 or above). Increasing the density of the steam may improve the ability of the steam to strip hydrocarbon material and/or other materials from the formation.
In some embodiments, the tar sands formation may be treated by the in situ heat treatment process to produce pyrolyzed product from the formation. A significant amount of carbon in the form of coke may remain in tar sands formation when production of pyrolysis product from the formation is complete. In some embodiments, the coke in the formation may be utilized to produce heat and/or additional products from the heated coke containing portions of the formation.
In some embodiments, air, oxygen enriched air, and/or other oxidants may be introduced into the treatment area that has been pyrolyzed to react with the coke in the treatment area. The temperature of the treatment area may be sufficiently hot to support burning of the coke without additional energy input from heaters. The oxidation of the coke may significantly heat the portion of the formation. Some of the heat may transfer to portions of the formation adjacent to the treatment area. The transferred heat may mobilize fluids in portions of the formation adjacent to the treatment area. The mobilized fluids may flow into and be produced from production wells near the perimeter of the treatment area.
Gases produced from the formation heated by combusting coke in the formation may be at high temperature. The hot gases may be utilized in an energy recovery cycle (for example, a Kalina cycle or a Rankine cycle) to produce electricity.
The air, oxygen enriched air and/or other oxidants may be introduced into the formation for a sufficiently long period of time to heat a portion of the treatment area to a desired temperature sufficient to allow for the production of synthesis gas of a desired composition. The temperature may be from 500° C. to about 1000° C. or higher. When the temperature of the portion is at or near the desired temperature, a synthesis gas generating fluid, such as water, may be introduced into the formation to result in the formation of synthesis gas. Synthesis gas produced from the formation may be sent to a treatment facility and/or be sent through a pipeline to a desired location. During introduction of the synthesis gas generating fluid, the introduction of air, oxygen enriched air, and/or other oxidants may be stopped, reduced, or maintained. If the temperature of the formation reduces so that the synthesis gas produced from the formation does not have the desired composition, introduction of the syntheses gas generating fluid may be stopped or reduced, and the introduction of air, enriched air and/or other oxidants may be started or increased so that oxidation of coke in the formation reheats portions of the treatment area. The introduction of oxidant to heat the formation and the introduction of synthesis gas generating fluid to produce synthesis gas may be cycled until all or a significant portion of the treatment area is treated.
In certain embodiments, a tar sands formation is treated in stages. The treatment may be initiated with electrical heating with further heating generated from oxidation of hydrocarbons and hot gas production from the formation.
Heaters 716 may be used to heat and treat portions of section 2572A through conductive heat transfer. For example, heaters 716 may mobilize, visbreak, and/or pyrolyze hydrocarbons in section 2572A. Production wells 206 may be used to produce mobilized, visbroken, and/or pyrolyzed hydrocarbons from section 2572A.
Injection wells 748 may be used to inject air (or other oxidizing fluids) and/or water into the formation. In some embodiments, carbon dioxide or other fluids are injected into the formation to control heating/production in the formation. Air or oxidizing fluids may oxidize (combust) hydrocarbons remaining in the formation (for example, coke). Water may react with the hot formation to produce syngas in the formation. Production wells 206 in section 2572B may be converted to gas heater/producer wells 2574. Wells 2574 may be used to produce oxidation gases and/or syngas products from the formation. Producing the hot oxidation gases and/or syngas through wells 2574 in section 2572B may heat the section to higher temperatures so that hydrocarbons in the section are mobilized, visbroken, and/or pyrolyzed in the section. Production wells 206 in section 2572C may be used to produce mobilized, visbroken, and/or pyrolyzed hydrocarbons from section 2572B.
In certain embodiments, the pressure of the injected fluids and the pressure in formation are controlled to control the heating in the formation. The pressure in the formation may be controlled by controlling the production rate of fluids from the formation (for example, the production rate of oxidation gases and/or syngas products). Heating in the formation may be controlled so that there is enough hydrocarbon volume in the formation to maintain the oxidation reactions in the formation. Heating in the formation may also be controlled so that enough heat is generated to conductively heat the formation to mobilize, visbreak, and/or pyrolyze hydrocarbons in adjacent sections of the formation.
The process of injecting air and/or water one section, producing oxidation gases and/or syngas products in an adjacent section to heat the adjacent section, and producing upgraded hydrocarbons (mobilized, visbroken, and/or pyrolyzed hydrocarbons) from a subsequent section may be continued in further sections of the tar sands formation. For example,
Treating the tar sands formation, as shown by the embodiments of
In some embodiments, temperature limited heaters are manufactured from austenitic stainless steels. These austenitic steels may include alloys with a face centered cubic (fcc) austenite phase being the primary phase. The fcc austenite phase may be stabilized by controlling the Fe—Cr—Ni and/or the Fe18Cr8—Ni concentration. Strength of the austenitic phase may be increased by incorporating other alloys in the fcc lattice. For low-temperature applications, the strength may be raised by adding alloying elements that increase the strength of the fcc lattice. This type of strengthening may be referred to as “solid solution strengthening”. As the use temperature is increased, however, alloying elements in the austenite phase may react to form new phases such as M23C6, where M includes chromium and other elements that can form carbides. Other phases may form in austenite containing elements from Columns 4-13 of the Periodic Table. Examples of such elements include, but are not limited to, niobium, titanium, vanadium, tungsten, aluminum, or mixtures thereof. The size and distribution of various phases and their stability in the desired use temperature range determines the mechanical properties of the stainless steel. Nano-scale dispersions of precipitates such as carbides may produce the highest strength at high temperatures, but due to the size of the carbides, they may become unstable and coarsen. Alloys containing nano-scale precipitate dispersions may be unstable at temperatures of at least 750° C. Since, heaters may heat a subsurface formation to temperatures at least 700° C., heaters having improved strength alloys capable of withstanding temperatures of at least 700° C. are desired.
In some embodiments, iron, chromium, and nickel alloys containing manganese, copper and tungsten, in combination with niobium, carbon and nitrogen, may maintain a finer grain size despite high temperature solution annealing or processing. Such behavior may be beneficial in reducing a heat-affected-zone in welded material. Higher solution-annealing temperatures are particularly important for achieving the best metal carbide (MC) nanocarbide. For example, niobium carbide nanocarbide strengthens during high-temperature creep service, and such effects are amplified (finer nanocarbide structures that are stable) by compositions of the improved alloys. Tubing and canister applications that include the composition of the improved alloys and are wrought processed result in stainless steels that may be able to age-harden during service at 700° C. to 800° C. Improved alloys may be able to age-harden even more if the alloys are cold-strained prior to high-temperature service, but such cold-prestraining is not necessary for good high temperature properties or age-hardening. Some prior art alloys, such as NF709 require cold-prestraining to achieve good high temperature creep properties, and this is a disadvantage in particular because after such alloys are welded, the advantages of the cold-prestraining in the weld heat effected zone are lost. Other prior art alloys are adversely effected by cold-prestraining with respect to high-temperature strength and long-term durability. Thus, cold prestraining may be limited or not permitted by, for example, construction codes.
In some embodiments of the new alloy compositions, the alloy may be cold worked by, for example, twenty percent, and the yield strength at 800° C. is not changed by more than twenty percent from yield strength at 800° C. of freshly annealed alloy.
The improved alloys described herein are suitable for low temperature applications, for example, cryogenic applications. The improved alloys which have strength and sufficient ductility at temperatures of, for example, −50° C. to −200° C., also retain strength at higher temperatures than many alloys often used in cryogenic applications, such as 201LN and YUS130, thus for services such as liquefied natural gas, where a failure may result in a fire, the improved alloy would retain strength in the vicinity of the fire longer than other materials.
An improved alloy composition may include, by weight: about 18% to about 22% chromium, about 5% to about 13% nickel (and in some embodiments, from about 5% to about 9% by weight nickel), about 1% to about 10% copper (and in some embodiments, above 2% to about 6% copper), about 1% to about 10% manganese, about 0.3% to about 1% silicon, about 0.5% to about 1.5% niobium, about 0.5% to about 2% tungsten, and with the balance being essentially iron (for example, about 47.8% to about 68.12% iron). The composition may, in some embodiments, include other components, for example, about 0.3% to about 1% molybdenum, about 0.08% to about 0.2% carbon, about 0.2% to about 0.5% nitrogen or mixtures thereof. Other impurities or minor components typically present in steels may also be present. Such an improved alloy may be useful when processed by hot deformation, cold deformation, and/or welding into, for example, casings, canisters, or strength members for heaters. In some embodiments, the improved alloy includes, by weight: about 20% chromium, about 3% copper, about 4% manganese, about 0.3% molybdenum, about 0.77% niobium, about 13% nickel, about 0.5% silicon, about 1% tungsten, about 0.09% carbon, and about 0.26% nitrogen, with the balance being essentially iron. In certain embodiments, the improved alloy includes, by weight: about 19% chromium, about 4.2% manganese, about 0.3% molybdenum, about 0.8% niobium, about 12.5% nickel, about 0.5% silicon, about 0.09% carbon, about 0.24% nitrogen by weight with the balance being essentially iron. In certain embodiments, the improved alloy includes, by weight: about 21% chromium, about 3% copper, about 8% manganese, about 0.3% molybdenum, about 0.8% niobium, about 7% nickel, about 0.5% silicon, about 1% tungsten, about 0.13% carbon, and about 0.37% nitrogen, with the balance being essentially iron. In some embodiments, the improved alloy includes, by weight: about 20% chromium, about 4.4% copper, about 4.5% manganese, about 0.3% molybdenum, about 0.8% niobium, about 7% nickel, about 0.5% silicon, about 1% tungsten, about 0.24% carbon, about 0.3% nitrogen by weight with the balance being essentially iron. In some embodiments, improved alloys may vary an amount of manganese, amount of nickel, a W/Cu ratio, a Mo/W ratio, a C/N ratio, a Mn/N ratio, a Mn/Nb ratio, a Mn/Si ratio and/or a Mn/Ni ratio to enhance resistance to high temperature sulfidation, increase high temperature strength, and/or reduce cost. For example, for the improved wrought alloys to have a stable parent austenite phase, high strength from 600° C. to 900° C., and stable nano carbide and nanocarbonitride microstructures, the improved wrought alloys may include combinations of alloying elements present in the improved wrought alloys such that the following ratios (using wt. %) are achieved: a) Mo/W—0.3 to 0.5; b) W/Cu—0.25 to 0.33; c) C/N—0.25 to 0.33; d) Mn/Ni—0.3 to 1.5; e) Mn/N—20 to 25; f) Mn/Nb—5 to 13; and g) Mn/Si—4 to 20; and carbon plus nitrogen is from about 0.3 wt % to about 0.6 wt %.
Improved wrought alloy compositions may include the compositions described in the preceding paragraphs and compositions disclosed in U.S. Pat. No. 7,153,373, which is incorporated herein by reference. The improved wrought alloy composition may include at least 3.25% by weight precipitates at about 800° C. The improved wrought alloy composition may have been processed by aging or hot working and/or by cold working. As a result of such aging or hot working and/or cold working, the improved wrought alloy compositions (for example, NbC, Cr-rich M23C6) may contain nanocarbonitrides precipitates. Such nanocarbonitride precipitates are not known to be present in cast compositions such as those disclosed in U.S. Pat. No. 7,153,373, and are believed to form upon hot working and/or cold working of the compositions. The nanocarbonitride precipitates may include particles having dimensions from about 5 nanometers to about 100 nanometers, from about 10 nanometers to about 90 nanometers, or from about 20 nanometers to about 80 nanometers. These wrought alloys may have microstructures that include, but are not limited to, nanocarbides (for example, NbC, Cr-rich M23C6), which form during aging (stress-free) or creep (stress<0.5 yield stress (YS)). The nanocarbide precipitates may include particles having dimensions from 5 nanometers to 100 nanometers, from about 10 nanometers to about 90 nanometers, or from about 20 nanometers to about 80 nanometers. The microstructures may be a consequence of both the native alloy composition and the details of the wrought processing. In solution annealed material, the concentration of such nanoscale particles may be low. The nanoscale particles may be affected by solution anneal temperature/time (more and finer dispersion with longer anneal above 1150° C.) and by cold- or warm-prestrain (cold work) after the solution anneal treatment. Cold prestrain may create dislocation networks within the grains that may serve as nucleation sites for the nanocarbides. Solution annealed material initially has zero percent cold work. Bending, stretching, coiling, rolling or swaging may create, for example about 5 to about 15% cold work. The effect of the nanocarbides on yield strength or creep strength may be to provide strength based on dislocation-pinning, with more closely-spaced pinning sites (higher concentration, finer dispersion) providing more strength (particles are barriers to climb or glide of dislocations).
The improved wrought alloy may include nanonitrides (for example, niobium chromium nitrides (NbCrN)) in the matrix together with nanocarbides, after, for example, being aged for 1000 hours at about 800° C. The nanonitride precipitates may include particles having dimensions from about 5 nanometers to about 100 nanometers, from about 10 nanometers to about 90 nanometers, or from about 20 nanometers to about 80 nanometers. Niobium chromium nitrides have been identified using analytical electron microscopy as rich in niobium and chromium, and as the tetragonal nitride phase by electron diffraction (both carbides are cubic phases). X-ray energy dispersive quantitative analysis has shown that for the improved alloy compositions, these nanoscale nitride particles may have a composition by weight of: about 63% niobium, about 28% chromium, and about 6% iron, with other components being at most 5% each. Such niobium chromium nitrides were not observed in aged cast stainless steels with similar compositions, and appear to be a direct consequence of the wrought processing.
In some embodiments, the improved wrought alloy may include a mixture of microstructures (for example, a mixture of nanocarbides and nanonitrides). The mixture of microstructures may be responsible for the improved strength of these alloy compositions at elevated temperatures, such as, for example, about 900-1000° C. In some embodiments, the improved alloys may have a yield strength greater than 35 kpsi, or 30 kpsi at about 800° C.
In some embodiments, the improved alloys are processed to produce a wrought material. Processing may include steps such as the following. A centrifugal cast pipe may be cast from the improved alloy. A section may be removed from the casting and heat treated at a temperature of at least 1250° C. for, for example, three hours. The heat treated section may be hot rolled at a temperature of at least 1200° C. to a thickness of about half of the original thickness inches), annealed at a temperature of at least 1200° C. for fifteen minutes, and then sandblasted. The sandblasted section may be cold rolled to a thickness of about one third of the original cast thickness. The cold rolled section may be annealed to a temperature of at least 1250° C. for a period of time, for example, an hour, in, for example, air with an argon cover, and then given a final additional heat treatment for one hour at a temperature of at least 1250° C. in air with an argon blanket. An alternative process may include any of the following: initially homogenizing the cast plate at a temperature of at least 1200° C. for a period of time, for example 1-½ hours; hot rolling at a temperature of at least 1200° C. to two thirds of the original cast thickness; and annealing the cold-rolled plate for one hour at a temperature of at least 1200° C. The improved alloys may be extruded at, for example, about 1200° C., with, for example, a mandrel diameter of about 22.9 millimeters (0.9 inches) and a die diameter of about 34.3 millimeters (1.35 inches) to produce good quality tubes.
The wrought material may be welded by, for example, laser welding or tungsten gas arc welding. Thus, tubes may be produced by rolling plates and welding seams.
Annealing the improved alloys at higher temperatures, such as about 1250° C., may improve properties of the alloys. At a higher temperature, more of the phases go into solution and upon cooling precipitate into phases that contribute positively to the properties, such as high temperature creep and tensile strength. Annealing at temperatures higher than 1250° C., such as about 1300° C. may be beneficial. For example, the calculated phase present in the improved alloys may decrease by about 0.08% at about 1300° C. as opposed to the phase present in the improved alloys at about 1200° C. Thus, upon cooling, more useful precipitates may form by about 0.08%. Improved alloys may have high temperature creep strengths and tensile strengths that are superior to conventional alloys. For example, niobium stabilized stainless steel alloys that include manganese, nitrogen, copper and tungsten may have high temperature creep strengths and tensile strengths that are improved, or substantially improved relative to conventional alloys such as 347H.
Improved alloys may have increased strength relative to standard stainless steel alloys such as Super 304H at high temperatures (for example, about 700° C., about 800° C., or above about 1000° C.). Superior high temperature creep-rupture strength (for example, creep-rupture strength at about 800° C., about 900° C., or about 1250° C.) may be improved as a result of (a) composition, (b) stable, fine-grain microstructures induced by high temperature processing, and (c) age-induced precipitation structures in the improved alloys. Precipitation structures include, for example, microcarbides that strengthen grain boundaries and stable nanocarbides that strengthen inside the grains. Presence of phases other than sigma, laves, G, and chi phases contribute to high temperature properties. Stable microstructures may be achieved by proper selection of components. High temperature aging induced or creep-induced microstructures may have minimal or no intermetallic sigma, laves and chi phases. Intermetallic sigma, laves and chi phases may weaken the strength properties of alloys and are therefore generally undesirable.
At about 800° C., the improved alloys may include at least 3% or at least 3.25% by weight of microcarbides, other phases, and/or stable, fine grain microstructure that produce strength. At about 900° C., the improved alloys may include, by weight, at least 1.5%, at least 2%, at least 3%, at least 3.5%, or at least 5% microcarbides, other phases, and/or stable, fine grain microstructure that produce strength. These values may be higher than the corresponding values in 347H or Super 304H stainless steel alloys at about 900° C. At about 1250° C. improved alloys may include at least 0.5% by weight microcarbides, other phases, and/or stable, fine grain microstructure that produce strength. The resulting higher weight percent of microcarbides, other phases, and/or stable, fine grain microstructure, and the exclusion of sigma and laves phases, may account for superior high temperature performance of the improved alloys.
Alloys having similar or superior high temperature performance to the improved alloys may be derived by modeling phase behavior at elevated temperatures and selecting compositions that retain at least 1.5%, at least 2%, or at least 2.5% by weight of phases other than sigma or laves phases at, for example, about 900° C. For example, a stable microstructure may include an amount, by weight, of: niobium that is nearly ten times the amount of carbon, from 1% to 12% manganese, and from 0.15 to 0.5% of nitrogen. Copper and tungsten may be included in the composition to increase the amount of stable microstructures. The choice of elements for the improved alloys allows processing by various methods and results in a stable, fine grain size, even after heat treatments of at least 1250° C. Many prior art alloys tend to grain coarsen significantly when annealed at such high temperatures whereas the improved alloy can be improved by such high temperature treatment. In some embodiments, grain size is controlled to achieve desirable high temperature tensile and creep properties. Stable grain structure in the improved alloys reduces grain boundary sliding, and may be a contributing factor for the better strength relative to commercially available alloys at temperatures above, for example, about 650° C.
A downhole heater assembly may include 5, 10, 20, 40, or more heaters coupled together. For example, a heater assembly may include between 10 and 40 heaters. Heaters in a downhole heater assembly may be coupled in series. In some embodiments, heaters in a heater assembly may be spaced from about 8 meters (about 25 feet) to about 60 meters (about 195 feet) apart. For example, heaters in a heater assembly may be spaced about 15 meters (about 50 feet) apart. Spacing between heaters in a heater assembly may be a function of heat transfer from the heaters to the formation. Spacing between heaters may be chosen to limit temperature variation along a length of a heater assembly to acceptable limits. Heaters in a heater assembly may include, but are not limited to, electrical heaters, flameless distributed combustors, natural distributed combustors, and/or oxidizers. In some embodiments, heaters in a downhole heater assembly may include only oxidizers.
Oxidizing fluid 808 may be supplied to oxidizer assembly 800 through oxidant conduit 810. In some embodiments, fuel conduit 806 and/or oxidizers 802 may be positioned concentrically, or substantially concentrically, in oxidant conduit 810. In some embodiments, fuel conduit 806 and/or oxidizers 802 may be arranged other than concentrically with respect to oxidant conduit 810. In certain branched opening embodiments, fuel conduit 806 and/or oxidant conduit 810 may have a weld or coupling to allow placement of oxidizer assemblies 800 in branches of the opening. Exhaust gas 812 may pass through outer conduit 814 and out of the formation.
In some embodiments, the downhole oxidizer assembly includes a water conduit positioned in the oxidant conduit that is configured to deliver water to the fuel conduit prior to the first oxidizer in the oxidizer assembly. A portion of the water conduit may pass through a heated zone generated by the first oxidizer prior to a water entry point into the fuel conduit. In some embodiments, the fuel conduit is positioned adjacent to the oxidizers, and branches from the fuel conduit provide fuel to the other oxidizers. In some embodiments, the fuel conduit may comprise one or more orifices to selectively control the pressure loss along the fuel conduit.
Fuel 804 may be supplied to oxidizers 802 through fuel conduit 806. In some embodiments, the fuel for the oxidizers may be synthesis gas. In some embodiments, the fuel is synthesis gas (for example, a mixture of hydrogen and carbon monoxide) that was produced using an in situ heat treatment process. In some embodiments, the fuel contains products from a coal or heavy oil gasification process. The coal or heavy oil gasification process may take place above ground or below ground. After initiation of combustion of fuel and oxidant mixture in oxidizers 802, composition of the fuel may be varied to enhance operational stability of the oxidizers.
In certain embodiments, fuel used to initiate combustion may be enriched to decrease the temperature required for ignition or otherwise facilitate startup of oxidizers 802. In some embodiments, hydrogen or other hydrogen rich fluids may be used to enrich fuel initially supplied to the oxidizers. After ignition of the oxidizers, enrichment of the fuel may be stopped. In other embodiments, the fuel may comprise natural gas mixed with heavier components such as ethane, propane, butane, or carbon monoxide. In some embodiments, a portion or portions of fuel conduit 806 may include a catalytic surface (for example, a catalytic outer surface) to decrease an ignition temperature of fuel 804.
In some embodiments, non-condensable gases produced from treatment areas of in situ heat treatment processes are used as fuel for heaters that heat treatment areas in the formation. The heaters may be burners. The burners may be oxidizers of downhole oxidizer assemblies, flameless distributed combustors and/or burners that heat a heat transfer fluid used to heat the treatment areas. The non-condensable gases may include combustible gases (for example, hydrogen, hydrogen sulfide, methane and other hydrocarbon gases) and noncombustible gases (for example, carbon dioxide). The presence of noncombustible gases may inhibit coking of the fuel and/or may reduce the flame zone temperature of oxidizers when the fuel is used as fuel for oxidizers of downhole oxidizer assemblies. The reduced flame zone temperature may inhibit formation of NOx compounds and/or other undesired combustion products by the oxidizers. Other components such as water may be included in the fuel supplied to the burners. Combustion of in situ heat treatment process gas may reduce and/or eliminate the need for gas treatment facilities and/or the need to treat the non-condensable portion of formation fluid produced using the in situ heat treatment process to obtain pipeline gas and/or other gas products. Combustion of in situ heat treatment process gas in burners may create concentrated carbon dioxide and/or SOx effluents that may be used in other processes, sequestered and/or treated to remove undesired components.
In some embodiments, use of non-condensable fluids from in situ heat treatment processes in burners reduces or eliminates the need to build power plants near the in situ heat treatment processes. Heat initially used to increase the temperature of treatment areas in the formation may be provided by burning pipeline gas or other fuel. After the formation begins producing formation fluid, a portion or all of the non-condensable fluids produced from the formation may replace or supplement the pipeline gas or other fuel used to heat treatment areas.
In some embodiments, the oxidizing fluid supplied to the burners is air or enriched air. In some embodiments, the oxidizing fluid is produced by blending oxygen with a carrier fluid such as carbon dioxide to reduce or eliminate the presence of nitrogen in the oxidizing fluid. For example, the oxidizing fluid may be about 50% by volume oxygen and about 50% by volume carbon dioxide. Eliminating or reducing nitrogen in the oxidizing fluid may eliminate or reduce the amount of NOx compounds generated by the burners. Eliminating or educing nitrogen in the oxidizing fluid may also enable transporting and geologically storing exhaust gases from the burners without having to separate nitrogen from the exhaust gases.
Fuel 2534 enters fuel conduit 806 that provides fuel to oxidizers of oxidizer assemblies (for example, a plurality of oxidizer assemblies such as the downhole oxidizer assembly 800 depicted in
Initially, pipeline gas or other fuel may be supplied to treatment area 2538. Valves 2544 may be adjusted to control the amount of initial fuel supplied to treatment area 2538 as fuel 2534 becomes available. Initially, air stream 2514 may be supplied to treatment area 2538 as the oxidizing fluid. After additional oxidant sources become available, valves 2544′ may be adjusted to control the composition of oxidizing fluid 2542 provided to treatment area 2538.
Exhaust gas 812 from burners used to heat treatment area 2538 may be directed to exhaust treatment unit 2508. Exhaust gas 812 may include, but is not limited to, carbon dioxide and/or SOx. In exhaust separation unit 2508, carbon dioxide stream 2510 is separated from SOx stream 2512. Separated carbon dioxide stream 2510 may be mixed with diluent fluid 2540, may be used as a carrier fluid for oxidizing fluid 808, may be used as a drive fluid for producing hydrocarbons, and/or may be sequestered. SOx stream 2512 may be treated using known SOx treatment methods (for example, sent to a Claus plant). Formation fluid 320′ produced from heat treatment area 2538 may be mixed with formation fluid 320 from other treatment areas and/or formation fluid 320′ may enter separation unit 322.
In some embodiments, onsite production of oxygen gas is desirable. Production of oxygen gas at or proximate downhole oxidizer assemblies may reduce production costs and/or enhance efficiency of operation of the production of formation fluids. Oxygen gas may be produced by separation of oxygen from air using cryogenic and/or non-cryogenic systems. Non-cryogenic systems include, but are not limited to, pressure swing adsorption, vacuum swing adsorption, vacuum-pressure swing adsorption, membranes, or combinations thereof. Cryogenic systems rely on differences in boiling points to separate and purify the desired products.
Oxygen steam 2518 enters mixed oxidizing fluid 2542 conduit and/or is mixed with oxidizing fluid 808. A portion of nitrogen stream 2520 may be recycled to air separation unit 2516 for use as a coolant. Nitrogen stream 2520 may be used for as a drive fluid, as a reactant to produce ammonia, as a coolant for forming a low temperature barrier, as a fluid used during drilling, or as a fluid for other processes.
In some embodiments, oxygen is produce through the decomposition of water. For example, electrolysis of water produces oxygen and hydrogen. Using water as a source of oxygen provides a source of oxidant with minimal or no carbon dioxide emissions. The produced hydrogen may be used as a hydrogenation fluid for treating hydrocarbon fluids in situ or ex situ, a fuel source and/or for other purposes.
In some embodiments, on site production of hydrogen as a fuel for burners is desirable. The use of hydrogen as the fuel for burners may allow exhaust streams from the burners to be vented to the atmosphere with little or no treatment of the exhaust streams. Hydrogen may be produced by reformation of hydrocarbons, by partial oxidation of hydrocarbons or by a combination of reformation and partial oxidation. Water-gas shift reactions may be used after reformation and/or partial oxidation of hydrocarbons to maximize hydrogen production. For example, autothermal reformation of hydrocarbons having a carbon number of at most 5 produces hydrogen and carbon oxides. The produced hydrogen may be used as a hydrogenation fluid for treating hydrocarbon fluids in situ or ex situ, a fuel source and/or for other purposes.
Reformer unit 2530 may be, for example, an autothermal reformer and/or a steam reformer. Reformer unit 2530 may include one or more catalysts that enhance the production of hydrogen and carbon dioxide from hydrocarbons. For example, reformation unit 2530 may include water gas shift catalysts. Reformation unit 2530 may include one or more separation systems (for example, membranes and/or a pressure swing adsorption system) capable of separating hydrogen from other components. Reformation of fuel 2534 and/or in situ heat treatment process gas 240 may produce hydrogen stream 2528 and carbon oxide stream 2532. Reformation of fuel 2534 and/or in situ heat treatment process gas 240 may be performed using techniques known in the art for catalytic and/or thermal reformation of hydrocarbons to produce hydrogen. In some embodiments, fuel 2534 and/or in situ heat treatment process gas 240 is passed through a drying system prior to entering reformation unit 2530 to remove water in the fuel and/or gas.
Hydrogen stream 2528 may be provided to fuel conduit 806. A portion or all of hydrogen stream 2528 may be used for other purposes such as, but not limited to, an energy source and/or a hydrogen source for in situ or ex situ hydrogenation of hydrocarbons. Valves 2544 may be adjusted to control the amount of initial fuel supplied to treatment area 2538 as fuel 2534 and/or hydrogen stream 2528 become available.
Carbon oxide stream 2532 may include, but is not limited to, carbon dioxide and carbon monoxide. Carbon oxide stream 2532 may be mixed with diluent fluid 2540, may be used as a carrier fluid for oxidizing fluid 808, may be used as a drive fluid for producing hydrocarbons, may be vented, and/or may be sequestered. Combinations of processes described in
Coke formation may occur inside the fuel conduit if the fuel contains hydrocarbons components and the heat flux is sufficiently high. After oxidizer ignition, steps may be taken to reduce coking. For example, steam or water may be added to fuel conduit 806. In some embodiments, coking is inhibited by decreasing a residence time of fuel in fuel conduit 806. The residence time of fuel in fuel conduit 806 may decreased by varying the size of the fuel conduit. For example, one portion of fuel conduit 806 may be approximately ¾ inch (approximately 1.9 cm) in diameter while another portion may be approximately ⅜ inch (approximately 0.95 cm) in diameter. Alternatively, the thickness and length of all or portions of fuel conduit 806 may be varied.
In some embodiments, coking is inhibited by insulating portions of fuel conduit 806 that pass through high temperature zones proximate oxidizers 802. For example, a portion of fuel conduit 806 may be coated with an insulating layer and/or a conductive layer. The insulating layer may be made from thermal insulating materials such as silicon carbide, alumina, mullite, zirconia, and other material known in the art. The conductive layer may be made from commercially available highly conductive materials such as ceramics and/or high temperature metals, including but not limited to Hexyloy (available from Arklay S. Richards Co., Inc.). The insulating layer and/or the conductive layer may be applied to fuel conduit 806 using a high velocity oxygen fuel or air plasma process. The resulting layer or layers may be heat treated.
In some embodiments, the fuel conduit is treated to remove coke formed in the fuel conduit by decoking. Decoking may be performed through mechanical means and/or chemical means. For example, coke may be removed from the fuel conduit by pumping a metal, studded, foam, or plastic pig through the fuel conduit. In an embodiment, a rod is inserted into fuel conduit 806 to dislodge coke particles and push them towards the last oxidizer in the oxidizer assembly. The rod may be a hydrolance or other high pressure pipe or tube used to direct high pressure water, air, nitrogen, and/or other gas to dislodge the coke.
Insulating layer 2064 may be placed around fuel conduit 806 to at least partially surround a portion of the fuel conduit. Insulating layer 2064 may be made of a material with low thermal conductivity. Insulating layer 2064 may inhibit coking in fuel conduit 806. Insulating layer 2064 may only surround portions of fuel conduit 806 that pass through oxidizers 802. In some embodiments, the insulating layer covers the portion of the fuel conduit passing through the oxidizer and a portion of the fuel conduit before and/or after the oxidizer. In some embodiments, the entire fuel conduit is insulated.
Thermally conductive layer 2066 may surround or partially surround insulating layer 2064. Thermally conductive layer 2066 may be located adjacent to flame zone 2070. Thermally conductive layer 2066 may spread the heat of flame zone 2070 over a large area to help reduce the temperature applied to insulating layer 2064 below the flame zone. In some embodiments, the insulating layer does not include a thermally conductive layer.
The flow of fuel in fuel conduit 806 is represented by arrow 2074, and the flow of gas (for example, air and exhaust products and unburned fuel from previous oxidizers) in oxidant conduit 810 is represented by arrow 2076. Exhaust gases from all oxidizers in the oxidizer assembly pass through outer conduit 814 in the direction indicated by arrow 2078. Flow of gas between fuel conduit 806 and insulating sleeve 2064 may reduce the amount of heat transfer from the insulating sleeve to the fuel conduit. Flame zone 2070 may have a temperature of about 1100° C. (about 2000° F.) while the temperature in oxidant conduit adjacent to the shield of oxidizer 802 may be about 700° C. (about 1300° F.).
Oxidant may be supplied through the oxidant conduit to the oxidizers. Oxidizing fluid may include, but is not limited to, air, oxygen enriched air, and/or hydrogen peroxide. Depletion of oxygen in the oxidant may occur toward a terminal end of an oxidizer assembly. In some embodiments, the amount of excess oxidant supplied to the oxidizers is reduced to less than about 50% excess oxidant by weight by controlling the pressure, temperature, and flow rate of the oxidant in the oxidant conduit. For example, after ignition, the amount of oxidant can be reduced when the temperature of the fuel conduit reaches about 650° C. (about 1200° F.). In some embodiments, the amount of excess oxidant is reduced to less than about 25% excess oxidant by weight. In other embodiments, the amount of excess oxidant is reduced to less than about 10% excess oxidant by weight.
In some embodiments, the amount of excess oxidant is reduced when the temperature downstream of the oxidizers becomes sufficiently hot to support reaction of oxidant and fuel outside of the oxidizers. Oxidant and fuel may react in regions between oxidizers. During such operation, the oxidizer assembly functions much like a flameless distributed combustor. Generating heat in the regions between the oxidizers may result in a smoother temperature profile along the length of the oxidizer assembly. The excess oxidant may be reduced such that the last oxidizer in the oxidizer assembly substantially eliminates the remaining oxidant in the oxidant conduit. The last oxidizer may be a catalytic oxidizer to minimize or eliminate oxidant remaining in the oxidant conduit.
When the temperature along the length of the oxidizer assembly increases to a temperature sufficient to support reaction of oxidant with fuel outside of the shields of the oxidizers, the mode of operation of the oxidizer assembly may shift from a series of individual oxidizers with aerodynamically staged flames to a more uniformly distributed or “reactor-stable” mode of operation. During the reactor-stable mode of operation, combustion may take place outside the shield along the entire length of the oxidant conduit. Under this condition stability is achieved by balancing overall heat loss and heat generation over the broad reaction zone. Local recirculation of hot combustion products to incoming reactants enables minimum reaction temperature where fuel-oxidant mixtures will oxidize without aerodynamic stabilization. In this mode of operation, the oxidizers may still serve as a “safety” or means of continuing stabilization, if the temperature falls below the temperature needed to sustain oxidation of the fuel and oxidant in one or more regions of the oxidizer. During reactor-stable mode of operation, the amount of excess oxygen supplied to the oxidizer assembly may be reduced. Having the ability to reduce the amount of excess oxygen supplied to the oxidizer assembly may significantly improve the overall economics of the system used to heat the formation.
A common problem associated with the operation of gas burners employing a flame mechanism is that at high temperatures, particularly above about 1500° C. (about 2730° F.), oxygen and nitrogen present in the air combine by a thermal formation mechanism to form pollutants such as NO and NO2, commonly referred to as NOx. By controlling the flow of fuel and oxidant and by maintaining a distributed temperature, the formation of NOx may be inhibited. In some embodiments, the flow of fuel and oxidant is controlled to produce less than about 10 parts per million by weight of NOx from the gas burner. The flow of oxidant may be controlled by having openings in shields of the oxidizers sized to bring a sufficient flow rate to the flame zone to dilute the flame without causing the flame to be extinguished. Additionally, water added to the fuel conduit may inhibit NOx formation.
In some embodiments, initiation of the burner assembly is accomplished by initializing combustion in a specified sequence beginning with the last oxidizer in the assembly. Referring to
In an embodiment, the start up sequence is optimized by controlling the oxidant and fuel pressure differential along the length of the oxidizer assembly. Because the pressure differential varies over the length of the burner assembly, a planned sequential ignition from oxidizer to oxidizer, starting with last (most remote) oxidizer 2082 may be achieved. In this embodiment, the fuel-oxidant mixture in the ignition region is optimized at last oxidizer 2082, then at the second to last oxidizer 2084, and so on, with the fuel-to-oxidant ratio being least optimal at first oxidizer 2080. The profiles may be controlled to change the sequence of ignition. In an embodiment, the profiles may be reversed so that first oxidizer 2080 is ignited first. Altering the profiles may comprise altering the pressure differential along the oxidizer assembly length by design of the fuel conduit diameter coupled with optimization of opening sizes that provide fuel to the oxidizers, of opening sizes that provide oxidant to the mix chambers of the oxidizers, and of openings in the shields that supply oxidant to the flame zone. In addition, control may be facilitated by flow restrictions positioned in fuel conduit 806.
In some embodiments, flame stabilizers may be added to the oxidizers. The flame stabilizers may attach the flame to the shield. The high bypass flow around the oxidizer cools the shield and protects the internals of the oxidizer from damage enabling long term operation.
In some embodiments, deflectors may be positioned on the outer surface of the shield near to openings in the shield. The deflectors may direct some of the gas flowing through the oxidant conduit through the openings in the shield.
In one embodiment, one or more of the oxidizers have flame stabilizers that utilize a louvered design to direct flow into the shield.
As depicted in
In some embodiments, one or more of the openings in the shield may be angled in a non-perpendicular direction relative to the longitudinal axis of the shield. Angled openings act as nozzles to alter the entry path of gas into the shield. Angled openings may promote formation of internal low velocity recirculation zones where the reaction front can stabilize and improve the stability and reliability of the oxidizer.
The use of flame stabilizers, various sizes of openings in the shield and/or angled openings may establish the flame zone of the oxidizer close to the shield and as far away from the fuel conduit to maximize radial separation of the flame zone from the fuel conduit to minimize direct heating of the fuel conduit by the flame zone. The use of flame stabilizers, various sizes of openings in the shield and/or angled openings may also achieve lower NOx emissions by effectively aerodynamically staging the combustion zone and creating fuel rich and lean zones. In fuel rich zones, N2 formation (instead of NOx) will be favored and aerodynamic staging will control peak temperatures and thermal NOx formation. Such configurations can also enable control of the peak longitudinal temperature profile and flame radiation, hence suppressing overheating of the fuel conduit.
In some embodiments, fuel passes through a heated region before being supplied to the first oxidizer (oxidizer 2080 in
In some embodiments, a portion of the fuel flowing in the annular space between sleeve 2090 and fuel conduit 806 passes through openings 826 into the annular space between the fuel conduit and shield 824. Supplying fuel into this annular space may allow flame zone 2070 to extend through a significant portion of first oxidizer 2080 so that the first oxidizer is able to input more heat into the formation. First oxidizer 2080 may be configured to input more heat into the formation to help compensate for heat losses attributable to the oxidizer being the first oxidizer of the oxidizer assembly. Having first oxidizer configured to input more heat into the formation than other oxidizers of the oxidizer assembly may allow for a decrease in the total number of oxidizers needed in the downhole assembly.
One or more of the oxidizers in an oxidizer assembly may be a catalytic burner. The catalytic burners may include a catalytic portion (for example, a catalyst chamber) followed by a homogenous portion (for example, an ignition chamber). Catalytic burners may be started late in an ignition sequence, and may ignite without igniters. Oxidant for the catalytic burners may be sufficiently hot from upstream burners (for example, the oxidant may be at a temperature of about 370° F. (about 700° C.) if the fuel is primarily methane) so that a primary mixture would react over the catalyst in the catalyst portion and produce enough heat so that exiting products ignite a secondary mixture in the homogenous portion of the oxidizer. In some embodiments, the fuel may include enough hydrogen to allow the needed temperature of the oxidant to be lower. Catalysts used for this purpose may include palladium, platinum, platinum/iridium, platinum/rhodium or mixtures thereof.
In some embodiments a catalytic burner may include an igniter to simplify startup procedures.
Heated fuel and oxidant from mixing chamber 818 pass to catalyst 840. The fuel and oxidant react on catalyst 840 to form hot reaction products. The hot reaction products may be directed to heat shield 824. Additional fuel enters heat shield 824 through openings 826C in fuel conduit 806. Additional oxidant enters heat shield 824 through openings 832. The hot reaction products generated by catalyst 840 may ignite fuel and oxidant in autoignition zone 842. Autoignition zone 842 may allow fuel and oxidant to form main combustion zone 2070. In some embodiments, the catalytic burner includes flame stabilizers or other types of gas flow modifiers.
In some embodiments, all of the oxidizers in the oxidizer assembly are catalytic burners. In some embodiments, the first or the first several oxidizers in the oxidizer assembly are catalytic burners. The oxidant supplied to these burners may be at a lower temperature than subsequent burners. Using catalytic burners with igniters may stabilize the first performance of the first several oxidizers in the oxidizer assembly. Catalytic burners may be used in-line with other burners to reduce emissions by allowing lower flame temperatures while still having substantially complete combustion.
In some embodiments, a catalytic converter may be positioned at the end of the oxidizer assembly or in the exhaust gas return. The catalytic converter may remove unburned hydrocarbons and/or remaining NOx compounds or other pollutants. The catalytic converter may benefit from the relatively high temperature of the exhaust gas. In some embodiments, catalytic burners in series may be integrated with coupled catalytic converters to limit undesired emissions from the oxidizer assembly. In some embodiments, a selectively permeable material may be used to allow carbon dioxide or other fluids to be separated from the exhaust gas.
In one embodiment, initiation of the burner assembly may be accomplished by initializing combustion with hydrogen and later switching to natural gas or another fuel. The use of hydrogen-enriched fuel may suppress flame radiation and reduce heating of the fuel conduit. Oxidizers of the oxidizer assembly may be ignited using hydrogen or fuel that is highly enriched with hydrogen. Once ignited, the composition of fuel may be adjusted to comprise natural gas and/or other fuels. The initial use of hydrogen or hydrogen-enriched fuel widens the flammability envelope enabling much easier startup. An initial fuel composition could then be “chased” with production gas or other more economical gases. Alternatively, the entire system could burn hydrogen. With no carbon in the fuel, there would be no need for additional decoking methods.
Oxidant conduit 810 is positioned in outer conduit 814. Fuel conduits 806 are positioned in the space between oxidant conduit 810 and outer conduit 814. In the depicted embodiment, four fuel conduits 806 are shown. More than four fuel conduits or less than four fuel conduits may be positioned in the oxidizer assembly in other embodiments. Fuel taps 2442 may pass from fuel conduits 806 through oxidant conduit 810 to a mix chamber of an oxidizer. In some embodiments, each fuel conduit 806 supplies a single oxidizer. In some embodiments, one fuel conduit supplies two or more oxidizers of the oxidizer assembly. Portions or all of fuel conduits 806 and/or portions or all of fuel taps 2442 may be insulated. In some embodiments, fuel conduits 806 are positioned radially away from oxidant conduit 810 so that exhaust gas returning through the space between outer conduit 814 and the oxidant conduit transfers heat with the fuel conduits to limit the upper temperature attained by the fuel conduits.
Using multiple fuel conduits may allow the supply of fuel to be interrupted to one or more of oxidizers without adversely affecting all of the oxidizers. Multiple fuel conduits also allow for adjustment of fuel mixtures supplied to the oxidizers during startup and after steady operation of the oxidizers is established.
Igniter supply conduits 2444 may be positioned in the space between oxidant conduit 810 and outer conduit 814. In some embodiments, the igniter supply conduits are positioned in the oxidant conduit. Igniters 816 may branch from igniter supply conduits 2444 into ignition chamber 822 of the oxidizers. In the depicted embodiment, four igniter supply conduits 2444 are shown. More than four igniter supply conduits or less than four igniter supply conduits may be positioned in the oxidizer assembly in other embodiments. Igniter supply conduits may be conduits that convey a fuel (for example, hydrogen) to a catalyst in the igniter. Igniter supply conduits may hold insulated conductors that provide electricity to the igniters. The igniters may be glow plugs, spark plugs, or other types of igniters that use electricity to ignite the oxidizers. In some embodiments, the igniter supply conduit is an insulated conductor. In some embodiments, some igniter supply conduits may convey fuel and other igniter supply conduits of the oxidizer assembly may transmit electricity.
A mixture of fuel and oxidant passes from mix chamber 818 to ignition chamber 822 through mixture opening 2446. Mixture opening 2446 may be positioned along a central axis of oxidizer 802 as depicted in
In some embodiments, igniter 816 branches from igniter supply conduit 2444 through oxidant line into ignition chamber 822. Igniter 816 may be used during start up of the oxidizer assembly to initiate combustion of fuel and oxidant mixture passing through opening 2446. In some embodiments, use of the igniters is stopped after start up of the oxidizers in the oxidizer assembly. Flame zone 2070 generated by combusting the oxidant and fuel mixture may extend through ignition chamber 822 into shield 824. Shield 824 may stabilize flame zone 2070 and inhibit blow out of the flame zone by oxidant and exhaust gas flowing through oxidant conduit 810.
In some embodiments, one or more small oxidant conduit lines may be positioned in the oxidizer assembly to provide additional oxidizing fluid to the oxidizers located near the end of the oxidizer assembly. Small oxidant lines may be positioned in the main oxidant conduit and/or in the space between the oxidant conduit and the outer conduit. Additional oxidizing fluid may be introduced into the exhaust and oxidizing fluid flowing through the main oxidant conduit. The additional oxidizing fluid may result in combustion of all of the fuel supplied to the oxidizers.
In some embodiments, oxidizers that produce a flame are used as preheaters upstream of flameless distributed combustors. The oxidizers preheat the oxidizing fluid and/or the fuel supplied to the flameless distributed combustors above a temperature of about 815° C., which is above the auto-ignition temperature of a mixture of oxidant fluid and fuel.
The flameless distributed combustor segments may be 100 ft to 500 ft in length. Shorter or longer flameless distributed combustor segment lengths may also be used. The oxidizer assembly may have less than ten oxidizers.
Flameless distributed combustors 2448 depicted in
In some embodiments, one or more additional fuel conduits may be positioned in the space between the oxidant conduit and the outer conduit. Taps from the additional fuel conduits may pass through the oxidant conduit to provide fuel to the oxidizers and/or to the central fuel conduit prior to one the oxidizers.
In some embodiments, pulverized coal is the fuel used to heat the subsurface formation. The pulverized coal may be carried into the wellbores with a non-oxidizing fluid (for example, carbon dioxide and/or nitrogen). An oxidant may be mixed with the pulverized coal at several locations in the wellbore. The oxidant may be air, oxygen enriched air and/or other types of oxidizing fluids. Igniters located at or near the mixing locations initiate oxidation of the coal and oxidant. The igniters may be catalytic igniters, glow plugs, spark plugs, and/or electrical heaters (for example, an insulated conductor temperature limited heater with heating sections located at mixing locations of pulverized coal and oxidant) that are able to initiate oxidation of the oxidant with the pulverized coal. In
The particles of the pulverized coal may be small enough to pass through flow orifices and achieve rapid combustion in the oxidant. The pulverized coal may have a particle size distribution from about 1 micron to about 300 microns, from about 5 microns to about 150 microns, or from about 10 microns to about 100 microns. Other pulverized coal particle size distributions may also be used. At 600° C., the time to burn the volatiles in pulverized coal with a particle size distribution from about 10 microns to about 100 microns may be about one second.
When using coal as the fuel for downhole oxidizers, exhaust gases from the heater wells may be treated to remove unreacted coal, ash, fines and/or other particles in the exhaust gas. In some embodiments, the exhaust gas passes through one or more cyclones to remove particles from the exhaust gas. The exhaust gas may be further processed to remove selected compounds (for example, sulfur and/or nitrogen compounds), may be used as a drive fluid for mobilizing hydrocarbons in a formation, may be sequestered in a subsurface formation, and/or may be otherwise handled.
In other embodiments, other types of downhole oxidizers are used for the subsurface oxidation of coal to heat selected portions of the formation.
In an embodiment, coal and carrier gas is introduced into heater 2092 through first conduit 2094, and oxidant is introduced through second conduit 2096. The flow rate and/or pressure in first conduit 2094 and second conduit 2096 are controlled so that the oxidant flows through critical flow orifices 2098 into the coal and carrier gas flowing through first conduit 2094. Reaction of the coal and oxidant occurs in first conduit 2094. Exhaust gases pass through outer conduit 814 to the surface. Passing the exhaust gases past the locations where oxidant and coal are oxidized may reduce temperature variations along the length of the heated section of heater 2092.
In an embodiment, oxidant is introduced into heater 2092 through first conduit 2094, and coal and carrier gas is introduced through second conduit 2096. The flow rate and/or pressure in first conduit 2094 and second conduit 2096 are controlled so that the coal and carrier gas flows through critical flow orifices 2098 into the oxidant flowing through first conduit 2094. Reaction of the coal and oxidant occurs in first conduit 2094. Exhaust gases pass through outer conduit 814 to the surface.
In an embodiment, oxidant is introduced into heater 2092 through first conduit 2094, and coal and carrier gas is introduced through second conduit 2096. The flow rate and/or pressure in first conduit 2094 and second conduit 2096 are controlled so that the oxidant flows through critical flow orifices 2098 into the coal and carrier gas flowing through second conduit 2096. Reaction of the coal and oxidant occurs in second conduit 2096. Reacting coal and oxidant in second conduit 2096 and passing exhaust gases through outer conduit 814 to the surface may reduce the formation of hot zones adjacent to sections of heater 2092 where oxidation occurs.
In an embodiment, coal and carrier gas is introduced into heater 2092 through first conduit 2094, and oxidant is introduced through second conduit 2096. The flow rate and/or pressure in first conduit 2094 and second conduit 2096 are controlled so that the coal and carrier gas flows through critical flow orifices 2098 into oxidant flowing through second conduit 2096. Reaction of the coal and oxidant occurs in second conduit 2096. Exhaust gases pass through outer conduit 814 to the surface.
In some in situ heat treatment processes, coal or biomass may be used as a fuel to directly heat a portion of the formation. The fuel may be provided as a solid. The fuel may be ground or otherwise sized so that the size of the chunks, pellets, or granules provides a large surface area that facilities combustion of the fuel. A u-shaped wellbore may be formed in the formation. In some embodiments, the fuel is burned as the fuel is transported on a grate through the formation. In some embodiments, the fuel is burned in a batch or semi-batch operation. Fuel is placed on a train and the train is moved to a location in the formation. The fuel is combusted, and then the train is pulled out of the formation and another train is placed in the formation with fresh fuel. Heat from the burning fuel may heat the formation. Enough fuel may be placed on the grates so that all of the fuel is combusted before the grate is removed from the wellbore.
Coal and/or biomass may be significantly less expensive than other energy sources for heating the formation (for example, electricity and/or gas). Combusting coal in the formation may improve energy efficiency and lower cost as compared with using the coal to produce electricity that in turn is used to heat the formation.
In some embodiments, a removable electric heater or combustor is used to initiate combustion of the fuel. The electric heater and/or combustor may be inserted in the formation beneath the overburden. The electric heater and/or combustor may be used to raise the temperature near the interface between the overburden and the treatment area above an auto-ignition temperature of the fuel on the grate. The fuel on the grate may begin to combust as the fuel passes through the heated zone. Heat from combusting fuel heats the treatment area. When the treatment area adjacent to the entrance to the treatment area rises above the auto-ignition temperature of the fuel, use of the electric heater and/or combustor may be stopped. In some embodiments, the electric heater and/or combustor are removed from the wellbores.
Carriers 2464 may include grates 2478 and ash catchers 2480. Fuel 2466 may be positioned on top of grates 2478. Fuel 2466 placed on grate 2478 of carrier 2464 may be pulverized, ground or otherwise sized so that the average particle size of the fuel is larger than the size of openings through grate. When fuel 2466 burns, ash may fall through the openings in grates to fall on ash catchers 2480. Oxidant conduit 2468 and heater 2476 may pass through ash catchers 2480.
Oxidant conduit 2468 may carry an oxidant such as air, enriched air, or oxygen and a carrier fluid (for example, carbon dioxide) to fuel 2466. Oxidant conduit 2468 may include a number of openings that allow the oxidant to be introduced into the formation along the length of the U-shaped wellbore that is to be heated. In some embodiments, the openings are critical flow orifices. In some embodiments, more than one oxidant conduit 2468 is placed in the U-shaped wellbore. In some embodiments, one or more oxidant conduits 2468 enter the formation from each side of the U-shaped wellbore.
Conveyor 2470 may pull train 2460 through the U-shaped wellbore. In some embodiments, conveyor 2470 is a belt, cable and/or chain. In some embodiments, fuel is transported pneumatically through the wellbore. Canisters with openings are loaded with fuel. Openings in the canisters allow oxidant in and exhaust products out of the canisters. The canisters may be pneumatically drawn through the wellbore.
Clean-up bins 2472 may be positioned periodically in train 2460. Clean-up bins may remove ash from the wellbore that does not fall into ash catchers 2480. Clean-up bins 2472 may have an open end that substantially conforms to the bottom of casing 2462.
Temperature sensors in the wellbore may provide information on temperature along the wellbore to a control system. Speed, position, loading patterns of the grates, and oxidant delivery through the oxidant conduit may be adjusted by the control system to control the heating of the treatment area.
In some embodiments, the train is drawn in a loop through two or more u-shaped wellbores positioned in the formation.
Exhaust conduits 2484 may convey exhaust from the burned fuel to exhaust treatment system 2486. Exhaust treatment system 2486 may treat exhaust to remove noxious compounds from the exhaust (for example, NOx and COx). In some embodiments, exhaust treatment system KC140 may include a catalytic converter system. Treated exhaust may be used for other processes (for example, the treated exhaust may be used as a drive fluid) and/or the treated exhaust may be sequestered.
In some in situ heat treatment process embodiments, a circulation system is used to heat the formation. The circulation system may be a closed loop circulation system.
In some embodiments, heaters 760 may be 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 760. Heaters 760 are connected to heat transfer fluid circulation system 868 by piping. Gas at high pressure may be used as the heat transfer fluid in the closed loop circulation system. In some embodiments, the heat transfer fluid is carbon dioxide. Carbon dioxide is chemically stable at the required temperatures and pressures and has a relatively high molecular weight that results in a high volumetric heat capacity. Other fluids such as steam, air, helium and/or nitrogen may also be used. The pressure of the heat transfer fluid entering the formation may be 3000 kPa or higher. The use of high pressure heat transfer fluid allows the heat transfer fluid to have a greater density, and therefore a greater capacity to transfer heat. Also, the pressure drop across the heaters is less for a system where the heat transfer fluid enters the heaters at a first pressure for a given mass flow rate than when the heat transfer fluid enters the heaters at a second pressure at the same mass flow rate when the first pressure is greater than the second pressure.
In some embodiments, a liquid heat transfer fluid is used as the heat transfer file. The liquid heat transfer fluid may be a natural or synthetic oil, molten metal, molten salt, or other type of high temperature heat transfer fluid. A liquid heat transfer fluid may allow for smaller diameter piping and reduced pumping/compression costs. In some embodiments, the piping is made of a material resistant to corrosion by the liquid heat transfer fluid. In some embodiments, the piping is lined with a material that is resistant to corrosion by the liquid heat transfer fluid. For example, if the heat transfer fluid is a molten fluoride salt, the piping may include a 10 mil thick nickel liner. The piping may be formed by roll bonding a nickel strip onto a strip of the piping material (for example, stainless steel), rolling the composite strip, and longitudinally welding the composite strip to form the piping. Other techniques may also be used. Corrosion of nickel by the molten fluoride salt may be less than 1 mil per year at a temperature of about 840° C.
Heat transfer fluid circulation system 868 may include heat supply 870, first heat exchanger 872, second heat exchanger 874, and compressor 876. Heat supply 870 heats the heat transfer fluid to a high temperature. Heat supply 870 may be a furnace, solar collector, chemical reactor, nuclear reactor, fuel cell exhaust heat, or other high temperature source able to supply heat to the heat transfer fluid. In the embodiment depicted in
Heat transfer fluid from heat supply 870 of heat transfer fluid circulation system 868 passes through overburden 458 of formation 758 to hydrocarbon layer 460. Portions of heaters 760 extending through overburden 458 may be insulated. In some embodiments, the insulation or part of the insulation is a polyimide insulating material. Inlet portions of heaters 760 in hydrocarbon layer 460 may have tapering insulation to reduce overheating of the hydrocarbon layer near the inlet of the heater into the hydrocarbon layer.
In some embodiments, the diameter of the pipe in overburden 458 may be smaller than the diameter of pipe through hydrocarbon layer 460. The smaller diameter pipe through overburden 458 may allow for less heat transfer to the overburden. Reducing the amount of heat transfer to overburden 458 reduces the amount of cooling of the heat transfer fluid supplied to pipe adjacent to hydrocarbon layer 460. The increased heat transfer in the smaller diameter pipe due to increased velocity of heat transfer fluid through the small diameter pipe is offset by the smaller surface area of the smaller diameter pipe and the decrease in residence time of the heat transfer fluid in the smaller diameter pipe.
After exiting formation 758, the heat transfer fluid passes through first heat exchanger 872 and second heat exchanger 874 to compressor 876. First heat exchanger 872 transfers heat between heat transfer fluid exiting formation 758 and heat transfer fluid exiting compressor 876 to raise the temperature of the heat transfer fluid that enters heat supply 870 and reduce the temperature of the fluid exiting formation 758. Second heat exchanger 874 further reduces the temperature of the heat transfer fluid before the heat transfer fluid enters compressor 876.
In some embodiments, a liquid heat transfer fluid may be used instead of a gas heat transfer fluid. The compressor banks represented by compressor 876 in
In some embodiments, piping for the circulation system may allow the direction of heat transfer fluid flow through the formation to be changed. Changing the direction of heat transfer fluid flow through the formation allows each end of a u-shaped wellbore to initially receive the heat transfer fluid at the hottest temperature of the heat transfer fluid for a period of time, which may result in more uniform heating of the formation. The direction of heat transfer fluid may be changed at desired time intervals. The desired time interval may be about a year, about six months, about three months, about two months or any other desired time interval.
In some embodiments, the circulation system may be used in conjunction with electrical heating. In some embodiments, at least a portion of the pipe in the U-shaped wellbores adjacent to portions of the formation that are to be heated is made of a ferromagnetic material. For example, the piping adjacent to a layer or layers of the formation to be heated is made of 9% to 13% chromium steel, such as 410 stainless steel. The pipe may be a temperature limited heater when time varying electric current is applied to the piping. The time varying electric current may resistively heat the piping, which heats the formation and the material in the piping. In some embodiments, direct electric current may be used to resistively heat the pipe, which heats the formation. In some embodiments, the material used to form the pipe in the U-shaped wellbore does not include ferromagnetic material. Direct or time varying current may be used to resistively heat the pipe, which heats the formation.
In some embodiments, one or more insulated conductors are placed in the piping. Electrical current may be supplied to the insulated conductors to resistively heat at least a portion of the insulated conductors. Heated insulated conductors may provide heat to the contents of the piping and the piping. The piping heated by the insulated conductor may heat adjacent formation.
In some embodiments, the circulation system is used to heat the formation to a first temperature, and electrical energy is used to maintain the temperature of the formation and/or heat the formation to higher temperatures. The first temperature may be sufficient to vaporize aqueous formation fluid in the formation. The first temperature may be at most about 200° C., at most about 300° C., at most about 350° C., or at most about 400° C. Using the circulation system to heat the formation to the first temperature allows the formation to be dry when electricity is used to heat the formation. Heating the dry formation may minimize electrical current leakage into the formation.
In some embodiments, the circulation system and electrical heating may be used to heat the formation to a first temperature. The formation may be maintained, or the temperature of the formation may be increased from the first temperature, using the circulation system and/or electrical heating. In some embodiments, the formation may be raised to the first temperature using electrical heating, and the temperature may be maintained and/or increased using the circulation system. Economic factors, available electricity, availability of fuel for heating the heat transfer fluid, and other factors may be used to determine when electrical heating and/or circulation system heating are to be used.
In some embodiments, electrical heating is used to raise the temperature of the piping to a desired temperature. The desired temperature may be a temperature higher than a temperature needed to maintain the heat transfer fluid (for example, a molten metal or a molten salt) in a liquid phase. The electrical heating may inhibit plugging of the piping and allow the heat transfer to flow through the piping.
In embodiments where the electrical heating is needed to raise the temperature of the piping to or above a desired temperature, the lead-in conductors are coupled to the piping at or near the surface so that all of the piping in the formation is heated to the desired temperature. Piping near the surface may include electrical insulation (for example, a porcelain coating).
In some embodiments, the lead-in conductors are placed inside of the pipe of the closed loop circulation system. In some embodiments, the lead-in conductors are positioned outside of the pipe of the closed loop circulation system. In some embodiments, the lead-in conductors are insulated conductors with mineral insulation, such as magnesium oxide. The lead-in conductors may include highly electrically conductive materials such as copper or aluminum to reduce heat losses in overburden 458 during electrical heating.
In certain embodiments, the portions of heater 760 in overburden 458 are used as lead-in conductors. The portions of heater 760 in overburden 458 may be electrically coupled to the portion of heater 760 in hydrocarbon layer 460. In some embodiments, one or more electrically conducting materials (such as copper or aluminum) are coupled (for example, cladded or welded) to the portions of heater 760 in overburden 458 to reduce the electrical resistance of the portions of the heater in the overburden. Reducing the electrical resistance of the portions of heater 760 in overburden 458 reduces heat losses in the overburden during electrical heating.
In some embodiments, the portion of heater 760 in hydrocarbon layer 460 is a temperature limited heater with a self-limiting temperature between about 600° C. and about 1000° C. The portion of heater 760 in hydrocarbon layer 460 may be a 9% to 13% chromium stainless steel. For example, portion of heater 760 in hydrocarbon layer 460 may be 410 stainless steel. Time-varying current may be applied to the portion of heater 760 in hydrocarbon layer 460 so that the heater operates as a temperature limited heater.
Electrical power supply system 908 may include transformer 728 and cables 722, 724. In certain embodiments, cables 722, 724 are capable of carrying high currents with low losses. For example, cables 722, 724 may be thick copper or aluminum conductors. The cables may also have thick insulation layers. In some embodiments, cable 722 and/or cable 724 may be superconducting cables. The superconducting cables may be cooled by liquid nitrogen. Superconducting cables are available from Superpower, Inc. (Schenectady, N.Y., U.S.A.). Superconducting cables may minimize power loss and/or reduce the size of the cables needed to couple transformer 728 to the heaters. In some embodiments, cables 722, 724 may be made of carbon nanotubes.
In some embodiments, a liquid heat transfer fluid is used to heat the treatment area. In some embodiments, the liquid heat transfer fluid is a molten salt or a molten metal. The liquid heat transfer fluid may have a low viscosity and a high heat capacity at normal operating conditions. When the liquid heat transfer fluid is a molten salt or other fluid that has the potential to solidify in the formation, piping of the system may be electrically coupled to an electricity source to resistively heat the piping when needed and/or one or more heaters may be positioned in or adjacent to the piping to maintain the heat transfer fluid in a liquid state.
Hot heat transfer fluid from heat exchanger 2490 may pass to a manifold that provides heat transfer fluid to individual heater legs positioned in the treatment area of the formation. The heat transfer fluid may pass to the heater legs by gravity drainage. The heat transfer fluid may pass through overburden 458 to hydrocarbon containing layer 460 of the treatment area. The piping adjacent to overburden 458 may be insulated. Heat transfer fluid flows downwards to sump 2498.
Gas lift piping may include gas supply line 2500 within conduit 2504. Gas supply line 2500 may enter sump 2498. When lift chamber 2502 in sump 2498 fills to a selected level with heat transfer fluid, a gas lift control system operates valves of the gas lift system so that the heat transfer fluid is lifted through the space between gas supply line 2500 and conduit 2504 to separator 2506. Separator 2506 may receive heat transfer fluid and lifting gas from a piping manifold that transports the heat transfer fluid and lifting gas from the individual heater legs in the formation. Separator 2506 separates the lift gas from the heat transfer fluid. The heat transfer fluid is sent to vessel 2488.
Conduits 2504 from sumps 2498 to separator 2506 may include one or more insulated conductors or other types of heaters. The insulated conductors or other types of heaters may be placed in conduits 2504 and/or be strapped or otherwise coupled to the outside of the conduits. The heaters may inhibit solidification of the heat transfer fluid in conduits 2504 during the gas lift from sump 2498.
Circulation systems may be used to heat portions of the formation. Production wells in the formation are used to remove produced fluids. After production from the formation has ended, the circulation system may be used to recover heat from the formation.
In some embodiments, nuclear energy may be used to heat the heat transfer fluid used in the circulation system to heat a portion of the formation. Heat supply 870 in
In some embodiments, a nuclear reactor may heat helium. For example, helium flows through a pebble bed reactor, and heat transfers to the helium. The helium may be used as the heat transfer fluid to heat the formation. In some embodiments, the nuclear reactor may heat helium, and the helium may be passed through a heat exchanger to provide heat to the heat transfer fluid used to heat the formation. The pebble bed reactor may include a pressure vessel that contains encapsulated enriched uranium dioxide fuel. Helium may be used as a heat transfer fluid to remove heat from the pebble bed reactor. Heat may be transferred in a heat exchanger from the helium to the heat transfer fluid used in the circulation system. The heat transfer fluid used in the circulation system may be carbon dioxide, a molten salt, or other fluid. Pebble bed reactor systems are available from PBMR Ltd (Centurion, South Africa).
In some embodiments, the system may include auxiliary power unit 900. In some embodiments, auxiliary power unit 900 generates power by passing the helium from heat exchanger units 888 through a generator to make electricity. The helium may be sent to one or more compressors and/or heat exchangers to adjust the pressure and temperature of the helium before the helium is sent to nuclear reactor 886. In some embodiments, auxiliary power unit 900 generates power using a heat transfer fluid (for example, ammonia or aqua ammonia). Helium from heat exchanger units 888 is sent to additional heat exchanger units to transfer heat to the heat transfer fluid. The heat transfer fluid is taken through a power cycle (such as a Kalina cycle) to generate electricity. In an embodiment, nuclear reactor 886 is a 400 MW reactor and auxiliary power unit 900 generates about 30 MW of electricity.
In some in situ heat treatment embodiments, compressors provide compressed gases to the treatment area. For example, compressors may be used to provide oxidizing fluid 808 and/or fuel 804 to a plurality of oxidizer assemblies like oxidizer assembly 800 depicted in
A significant cost of the in situ heat treatment process may be operating the compressors and/or pumps over the life of the in situ heat treatment process if conventional electrical energy sources are used to power the compressors and/or pumps of the in situ heat treatment process. In some embodiments, nuclear power may be used to generate electricity that operates the compressors and/or pumps needed for the in situ heat treatment process. The nuclear power may be supplied by one or more nuclear reactors. The nuclear reactors may be light water reactors, pebble bed reactors, and/or other types of nuclear reactors. The nuclear reactors may be located at or near to the in situ heat treatment process site. Locating the nuclear reactors at or near to the in situ heat treatment process site may reduce equipment costs and electrical transmission losses over long distances. The use of nuclear power may reduce or eliminate the amount of carbon dioxide generation associated with operating the compressors and/or pumps over the life of the in situ heat treatment process.
Excess electricity generated by the nuclear reactors may be used for other in situ heat treatment process needs. For example, excess electricity may be used to cool fluid for forming a low temperature barrier (frozen barrier) around treatment areas, and/or for providing electricity to treatment facilities located at or near the in situ heat treatment process site. In some embodiments, the electricity or excess electricity produced by the nuclear reactors may be used to resistively heat the conduits used to circulate heat transfer fluid through the treatment area.
In some embodiments, excess heat available from the nuclear reactors may be used for other in situ processes. For example, excess heat may be used to heat water or make steam that is used in solution mining processes. In some embodiments, excess heat from the nuclear reactors may be used to heat fluids used in the treatment facilities located near or at the in situ heat treatment site.
In some embodiments, geothermal energy may be used to heat or preheat a treatment area of an in situ heat treatment process or a treatment area to be solution mined. Geothermal energy may have little or no carbon dioxide emissions. In some embodiments, geothermally heated fluid may be produced from a layer or layers located below or near the treatment area. The geothermally heated fluid includes, but is not limited to, steam, water, and/or brine. One or more of the layers may be geothermally pressurized geysers. Geothermally heated fluid may be pumped from one or more of the layers. The layer or layers may be at least 2 km, at least 4 km, at least 8 km or more below the surface. The geothermally heated fluid may be at a temperature of at least 100° C., at least 200° C., or at least 300° C.
The geothermally heated fluid may be produced and circulated through piping in the treatment area to raise the temperature of the treatment area. In some embodiments, the geothermally heated fluid is introduced directly into the treatment area. In some embodiments, the geothermally heated fluid is circulated through the treatment area or piping in the treatment area without being produced to the surface and re-introduced into the treatment area. In some embodiments, the geothermally heated fluid may be produced from a location near the treatment area. The geothermally heated fluid may be transported to the treatment area. Once transported to the treatment area, the geothermally heated fluid is circulated through piping in the treatment area and/or the geothermally heated fluid is introduced directly into the treatment area.
In some embodiments, geothermally heated fluid produced from a layer or layers is used to solution mine minerals from the formation. The geothermally heated fluid may be used to raise the temperature of the formation to a temperature below the dissociation temperature of the minerals, but to a temperature high enough to increase the amount of mineral going into solution in a first fluid introduced into the formation. The geothermally heated fluid may be introduced directly into the formation as all or a portion of the first fluid and/or the geothermally heated fluid may be circulated through piping in the formation.
In some embodiments, geothermally heated fluid produced from a layer or layers may be used to heat the treatment area before using electrical heaters, gas burners, or other types of heat sources to heat the treatment area to pyrolysis temperatures. The geothermally heated fluid may not be at a temperature sufficient to raise the temperature of the treatment area to pyrolysis temperatures. Using the geothermally heated fluid to heat the treatment area before using electrical heaters or other heat sources to heat the treatment area to pyrolysis temperatures may reduce energy costs for the in situ heat treatment process.
In some embodiments, hot dry rock technology may be used to produce steam or other hot heat transfer fluid from a deep portion of the formation. Injection wells may be drilled to a depth where the formation is hot. The injection wells may be at least 2 km, at least 4 km, or at least 8 km deep. Sections of the formation adjacent to the bottom portions of the injection wells may be hydraulically, or otherwise fractured, to provide large contact area with the formation and/or to provide flow paths to heated fluid production wells. Water, steam and/or other heat transfer fluid (for example, a synthetic oil or a natural oil) may be introduced into the formation through the injection wells. Heat transfers to the introduced fluid from the formation. Steam and/or hot heat transfer fluid may be produced from the heated fluid production wells. In some embodiments, the steam and/or hot heat transfer fluid is directed into the treatment area from the production wells without first producing the steam and/or hot heat transfer fluid to the surface. The steam and/or hot heat transfer fluid may be used to heat a portion of a hydrocarbon containing formation above the deep hot portion of the formation.
In some embodiments, steam produced from heated fluid production wells may be used as the steam for a drive process (for example, a steam flood process or a steam assisted gravity drainage process). In some embodiments, steam or other hot heat transfer fluid produced through heated fluid production wells is passed through U-shaped wellbores or other types of wellbores to provide initial heating to the formation. In some embodiments, cooled steam or water, or cooled heat transfer fluid, resulting from the use of the steam and/or heat transfer fluid from the hot portion of the formation may be collected and sent to the hot portion of the formation to be reheated.
In certain embodiments, a controlled or staged in situ heating and production process is used to in situ heat treat a hydrocarbon containing formation (for example, an oil shale formation). The staged in situ heating and production process may use less energy input to produce hydrocarbons from the formation than a continuous or batch in situ heat treatment process. In some embodiments, the staged in situ heating and production process is about 30% more efficient in treating the formation than the continuous or batch in situ heat treatment process. The staged in situ heating and production process may also produce less carbon dioxide emissions than a continuous or batch in situ heat treatment process. In certain embodiments, the staged in situ heating and production process is used to treat rich layers in the oil shale formation. Treating only the rich layers may be more economical than treating both rich layers and lean layers because heat may be wasted heating the lean layers.
In certain embodiments, heaters 716 in one of the sections are turned on while the heaters in other sections remain turned off. For example, heaters 716 in section 910 may be turned on while the heaters in the other sections are left turned off. Heat from heaters 716 in section 910 may create permeability, mobilize fluids, and/or pyrolysis fluids in section 910. While heat is being provided by heaters 716 in section 910, production well 206 in section 912 may be opened to produce fluids from the formation. Some heat from heaters 716 in section 910 may transfer to section 912 and “pre-heat” section 912. The pre-heating of section 912 may create permeability in section 912, mobilize fluids in section 912, and allow fluids to be produced from the section through production well 206.
In certain embodiments, a portion of section 912 proximate production well 206, however, is not heated by conductive heating from heaters 716 in section 910. For example, the superposition of heat from heaters 716 in section 910 does not overlap the portion proximate production well 206 in section 912. The portion proximate production well 206 in section 912 may be heated by fluids (such as hydrocarbons) flowing to the production well (for example, by convective heat transfer from the fluids).
As fluids are produced from section 912, the movement of fluids from section 910 to section 912 transfers heat between the sections. The movement of the hot fluids through the formation increases heat transfer within the formation. Allowing hot fluids to flow between the sections uses the energy of the hot fluids for heating of unheated sections rather than removing the heat from the formation by producing the hot fluids directly from section 910. Thus, the movement of the hot fluids allows for less energy input to get production from the formation than is required if heat is provided from heaters 716 in both sections to get production from the sections.
In certain embodiments, the temperature of the portion proximate production well 206 in section 912 is controlled so that the temperature in the portion is at most a selected temperature. For example, the temperature in the portion proximate the production well may be controlled so that the temperature is at most about 100° C., at most about 200° C., or at most about 250° C. In some embodiments, the temperature of the portion proximate production well 206 in section 912 is controlled by controlling the production rate of fluids through the production well. In some embodiments, producing more fluids increases heat transfer to the production well and the temperature in the portion proximate the production well.
In some embodiments, production through production well 206 in section 912 is reduced or turned off after the portion proximate the production well reaches the selected temperature. Reducing or turning off production through the production well at higher temperatures keeps heated fluids in the formation. Keeping the heated fluids in the formation keeps energy in the formation and reduces the energy input needed to heat the formation. The selected temperature at which production is reduced or turned off may be, for example, about 100° C., about 200° C., or about 250° C.
In some embodiments, section 910 and/or section 912 may be treated prior to turning on heaters 716 to increase the permeability in the sections. For example, the sections may be dewatered to increase the permeability in the sections. In some embodiments, steam injection or other fluid injection may be used to increase the permeability in the sections.
In certain embodiments, after a selected time, heaters 716 in section 912 are turned on. Turning on heaters 716 in section 912 may provide additional heat to sections 910 and 912 to increase the permeability, mobility, and/or pyrolysis of fluids in these sections. In some embodiments, as heaters 716 in section 912 are turned on, production in section 912 is reduced or turned off (shut down) and production well 206 in section 914 is opened to produce fluids from the formation. Thus, fluid flow in the formation towards production well 206 in section 914 and section 914 is heated by the flow of hot fluids as described above for section 912. In some embodiments, production well 206 in section 912 may be left open after the heaters are turned on in the section, if desired. In some embodiments, production in section 912 is reduced or turned off at the selected temperature, as described above.
The process of reducing or turning off heaters and shifting production to adjacent sections may be repeated for subsequent sections in the formation. For example, after a selected time, heaters in section 914 may be turned on and fluids produced from production well 206 in section 916 and so on through the formation.
In some embodiments, heat is provided by heaters 716 in alternating sections (for example, sections 910, 914, and 918) while fluids are produced from the sections in between the heated sections (for example, sections 912 and 916). After a selected time, heaters 716 in the unheated sections (sections 912 and 916) are turned on and fluids are produced from one or more of the sections as desired.
In certain embodiments, a smaller heater spacing is used in the staged in situ heating and producing process than in the continuous or batch in situ heat treatment processes. For example, the continuous or batch in situ heat treatment process may use a heater spacing of about 12 m while the in situ staged heating and producing process uses a heater spacing of about 10 m. The staged in situ heating and producing process may use the smaller heater spacing because the staged process allows for relatively rapid heating of the formation and expansion of the formation.
In some embodiments, the sequence of heated sections begins with the outermost sections and moves inwards. For example, for a selected time, heat may be provided by heaters 716 in sections 910 and 918 as fluids are produced from sections 912 and 916. After the selected time, heaters 716 in sections 912 and 916 may be turned on and fluids are produced from section 914. After another selected amount of time, heaters 716 in section 914 may be turned on, if needed.
In certain embodiments, sections 910-918 are substantially equal sized sections. The size and/or location of sections 910-918 may vary based on desired heating and/or production from the formation. For example, simulation of the staged in situ heating and production process treatment of the formation may be used to determine the number of heaters in each section, the optimum pattern of sections and/or the sequence for heater power up and production well startup for the staged in situ heating and production process. The simulation may account for properties such as, but not limited to, formation properties and desired properties and/or quality in the produced fluids. In some embodiments, heaters 716 at the edges of the treated portions of the formation (for example, heaters 716 at the left edge of section 910 or the right edge of section 918) may have tailored or adjusted heat outputs to produce desired heat treatment of the formation.
In some embodiments, the formation is sectioned into a checkerboard pattern for the staged in situ heating and production process.
In some embodiments, heaters in sections 910A are turned on and fluids are produced from sections 910B and/or sections 912B. After the selected time, heaters in sections 912A may be turned on and fluids are produced from sections 912B and/or 914B. After another selected time, heaters in sections 914A may be turned on and fluids are produced from sections 914B and/or 916B. After another selected time, heaters in sections 916A may be turned on and fluids are produced from sections 916B and/or 918B. In some embodiments, heaters in a “B” section that has been produced from may be turned on when heaters in the subsequent “A” section are turned on. For example, heaters in section 910B may be turned on when the heaters in section 912A are turned on. Other alternating heater startup and production sequences may also be contemplated for the in situ staged heating and production process embodiment depicted in
In some embodiments, the formation is divided into a circular, ring, or spiral pattern for the staged in situ heating and production process.
In some embodiments, fluids are injected to drive fluids between sections of the formation. Injecting fluids such as steam or carbon dioxide may increase the mobility of hydrocarbons and may increase the efficiency of the staged in situ heating and production process. In some embodiments, fluids are injected into the formation after the in situ heat treatment process to recover heat from the formation. In some embodiments, the fluids injected into the formation for heat recovery include some fluids produced from the formation (for example, carbon dioxide, water, and/or hydrocarbons produced from the formation). In some embodiments, the embodiments depicted in
In certain embodiments, several rectangular checkerboard patterns (for example, rectangular checkerboard pattern 920 depicted in
In certain embodiments, the startup of treatment of rectangular checkerboard patterns 920(1-36) proceeds in a sequential process. The sequential process may include starting the treatment of each of the rectangular checkerboard patterns one by one sequentially. For example, treatment of a second rectangular checkerboard pattern (for example, the onset of heating of the second rectangular checkerboard pattern) may be started after treatment of a first rectangular checkerboard pattern and so on. The startup of treatment of the second rectangular checkerboard pattern may be at any point in time after the treatment of the first rectangular checkerboard pattern has begun. The time selected for startup of treatment of the second rectangular checkerboard pattern may be varied depending on factors such as, but not limited to, desired heating rate of the formation, desired production rate, subsurface geomechanical properties, subsurface composition, and/or other formation properties. In some embodiments, the startup of treatment of the second rectangular checkerboard pattern begins after a selected amount of fluids have been produced from the first rectangular checkerboard pattern area or after the production rate from the first rectangular checkerboard pattern increases above a selected value or falls below a selected value.
In some embodiments, the startup sequence for rectangular checkerboard patterns 920(1-36) is arranged to minimize or inhibit expansion stresses in the formation. In an embodiment, the startup sequence of the rectangular checkerboard patterns proceeds in an outward spiral sequence, as shown by the arrows in
Starting treatment in rectangular checkerboard patterns at or near the center of treatment area 882 and moving outwards maximizes the starting distance from barrier 922. Barrier 922 may be most likely to fail when heat is provided at or near the barrier. Starting treatment/heating at or near the center of treatment area 882 delays heating of rectangular checkerboard patterns near barrier 922 until later times of heating in treatment area 882 or at or near the end of production from the treatment area. Thus, if barrier 922 does fail, the failure of the barrier occurs after a significant portion of treatment area 882 has been treated.
Starting treatment in rectangular checkerboard patterns at or near the center of treatment area 882 and moving outwards also creates open pore space in the inner portions of the outward moving startup pattern. The open pore space allows portions of the formation being started at later times to expand inwards into the open pore space and, for example, minimize shearing in the formation.
In some embodiments, support sections are left between one or more rectangular checkerboard patterns 920(1-36). The support sections may be unheated sections that provide support against geomechanical shifting, shearing, and/or expansion stress in the formation. In some embodiments, some heat may be provided in the support sections. The heat provided in the support sections may be less than heat provided inside rectangular checkerboard patterns 920(1-36). In some embodiments, each of the support sections may include alternating heated and unheated sections. In some embodiments, fluids are produced from one or more of the unheated support sections.
In some embodiments, one or more of rectangular checkerboard patterns 920(1-36) have varying sizes. For example, the outer rectangular checkerboard patterns (such as rectangular checkerboard patterns 920(21-26) and rectangular checkerboard patterns 920(31-36)) may have smaller areas and/or numbers of checkerboards. Reducing the area and/or the number of checkerboards in the outer rectangular checkerboard patterns may reduce expansion stresses and/or geomechanical shifting in the outer portions of treatment area 882. Reducing the expansion stresses and/or geomechanical shifting in the outer portions of treatment area 882 may minimize or inhibit expansion stress and/or shifting stress on barrier 922.
In certain embodiments, heater spacing decreases as the heater pattern moves away from the production well. Thus, the density of heater wells increases as the heaters get further away from the production well.
Decreasing the density of heaters 716 closer to production well 206 provides less heating at or near the production well. Less heating at or near the production well keeps lower temperatures in the production well so that less energy is removed from the formation through produced fluids and more energy is kept in the formation to heat the formation. Thus, such a pattern of heaters increases waste energy recovery from the formation. Increasing waste energy recovery in the formation increases energy efficiency in treating the formation. For example, treating a formation using the irregular hexagonal pattern depicted in
In some embodiments, heaters 716 are turned on in a sequence from outside in towards production well 206. As depicted in
In some embodiments, the temperature at or near production well 206 is controlled so that the temperature is at most a selected temperature. For example, the temperature at or near the production well may be controlled so that the temperature is at most about 100° C., at most about 150° C., at most about 200° C., or at most about 250° C. In certain embodiments, the temperature at or near production well 206 is controlled by reducing or turning off the heat provided by heaters 716 nearest the production well (for example, the heaters in row A). In some embodiments, the temperature at or near production well 206 is controlled by controlling the production rate of fluids through the production well.
In some embodiments, formation fluid is produced from first section 2100. The formation fluid may be produced through production wells 206. In some embodiments, the formation fluids drain by gravity to a bottom portion of the layer. The drained fluids may be produced from production wells 206 positioned at the bottom portion of the layer. Production of the formation fluids may continue until a majority of condensable hydrocarbons in the formation fluid are produced. After the majority of the condensable hydrocarbons have been produced, first section 2100 heat from heaters 716 may be reduced and/or discontinued to allow a reduction in temperature in the first section. In some embodiments, after the majority of the condensable hydrocarbons have been produced, a pressure of first section 2100 may be reduced to a selected pressure after the first section reaches the selected temperature. Selected pressures may range between about 100 kPa and about 1000 kPa, between 200 kPa and 800 kPa or below a fracture pressure of the formation.
In some embodiments, the formation fluid includes at least some pyrolyzed hydrocarbons. Some hydrocarbons may be pyrolyzed in portions of first section 2100 that are at higher temperatures than a remainder of the first section. For example, portions of formation adjacent heaters 716 may be at somewhat higher temperatures than the remainder of first section 2100. The higher temperature of the formation adjacent to heaters 716 may be sufficient to cause pyrolysis of hydrocarbons. Some of the pyrolysis product may be produced through production wells 206.
One or more sections (for example, second section 2102 and/or third section 2104) may be above or proximate to first section 2100. Some heat from first section 2100 may transfer to second section 2102 and third section 2104. In some embodiments, sufficient heat may transfer from first section 2100 to allow for recovery of some hydrocarbons from second section 2102 and/or third section 2104.
In some embodiments, a solvation fluid is provided to first section 2100 through injection wells 748A to solvate hydrocarbons within the first section. In some embodiments, solvation fluid is added to first section 2100 after a majority of the condensable hydrocarbons have been produced and the first section has cooled. Solvation fluids include, but are not limited to, water, hydrocarbons, surfactants, polymers, carbon disulfide, carbon dioxide, or mixtures thereof. The solvation fluid may solvate and/or dilute the hydrocarbons to form a mixture of condensable hydrocarbons and solvation fluids. Formation of the mixture increased production of hydrocarbons remaining in the first section. Solubilization of hydrocarbons in first section 2100 may allow the hydrocarbons to be produced from the first section after heat has been removed from the section. The mixture may be produced through production wells 206.
In some embodiments, heat from first section 2100 may mobilize or substantially mobilize fluid in second section 2102 and/or third section 2104. In some embodiments, a solvation fluid is provided to second section 2102 and/or third section 2104 through injection wells 748B, 748C to increase mobilization of hydrocarbons within the second section or the third section. The solvation fluid may increase a flow of mobilized hydrocarbons into first section 2100. For example, a pressure gradient may be produced between second section 2102 and/or 2104 and first section 2100 such that the flow of fluids from the second section and/or third section to the first section is increased. The solvation fluid may solubilize a portion of the hydrocarbons in second section 2102 and/or third section 2104 to form a mixture. Solubilization of hydrocarbons in second section 2102 and/or third section 2104 may allow the hydrocarbons to be produced from the second section and/or third section without direct heating of the sections.
In some embodiments, water may be used as a solvation fluid. Water may be injected into a portion of first section 2100, second section 2102 and/or third section 2104 through injection wells 748A, 748B, 748C. Addition of water to oat least a selected section of first section 2100, second section 2102 and/or third section 2104 may water wet a portion of the sections. The water wet portions of the selected section may be pressurized by known methods and a water/hydrocarbon mixture may be collected using one or more production wells.
In certain embodiments, first section 2100, second section 2102 and/or third section 2104 may be treated with a hydrocarbons (for example, naphtha, kerosene, diesel, vacuum gas oil, or a mixture thereof). In some embodiments, the hydrocarbons have an aromatic content of at least 1% by weight, at least 5% by weight, at least 10% by weight, at least 20% by weight or at least 25% by weight. Hydrocarbon may be injected into a portion of first section 2100, second section 2102 and/or third section 2104 through injection wells 748A, 748B, 748C. In some embodiments, the hydrocarbons are produced from first section 2100 and/or other portions of the formation. In certain embodiments, the hydrocarbons are produced from the formation, treated to remove heavy fractions of hydrocarbons (for example, asphaltenes, hydrocarbons having a boiling point of at least 300° C., of at least 400° C., at least 500° C., or at least 600° C.) and the hydrocarbons are re-introduced into the formation. In some embodiments, one section may be treated with hydrocarbons while another section is treated with water. In some embodiments, water treatment of a section may be alternated with hydrocarbon treatment of the section.
In an embodiment, a blend made from hydrocarbon mixtures produced from first section 2100 may be used as a solvation fluid. The blend may include about 20 weight % light hydrocarbons (or blending agent) or greater (for example, about 50 weight % or about 80 weight % light hydrocarbons) and about 80 weight % heavy hydrocarbons or less (for example, about 50 weight % or about 20 weight % heavy hydrocarbons). The weight percentage of light hydrocarbons and heavy hydrocarbons may vary depending on, for example, a weight distribution (or API gravity) of light and heavy hydrocarbons, a relative stability of the blend or a desired API gravity of the blend. For example, in some embodiments, the weight percentage of light hydrocarbons in the blend may be less than 50 weight percent or less than 20 weight percent. In certain embodiments, the weight percentage of light hydrocarbons may be selected to mix the least amount of light hydrocarbons with heavy hydrocarbons that produces a blend with a desired density or viscosity.
In some embodiments, polymer and/or monomer may be used as a solvation fluid. Polymer and/or monomers may solvate hydrocarbons to allow mobilization of the hydrocarbons towards one or more production wells. The polymer and/or monomer may reduce the mobility of a water phase in pores of the hydrocarbon containing formation. The reduction of water mobility may allow the hydrocarbons to be more easily mobilized through the hydrocarbon containing formation. Polymers that may be used include, but are not limited to, polyacrylamides, partially hydrolyzed polyacrylamide, polyacrylates, ethylenic copolymers, biopolymers, carboxymethylcellulose, polyvinyl alcohol, polystyrene sulfonates, polyvinylpyrrolidone, AMPS (2-acrylamide-2-methyl propane sulfonate) or combinations thereof. Examples of ethylenic copolymers include copolymers of acrylic acid and acrylamide, acrylic acid and lauryl acrylate, lauryl acrylate and acrylamide. Examples of biopolymers include xanthan gum and guar gum. In some embodiments, polymers may be crosslinked in situ in the hydrocarbon containing formation. In other embodiments, polymers may be generated in situ in the hydrocarbon containing formation. Polymers and polymer preparations for use in oil recovery are described in U.S. Pat. Nos. 6,427,268 to Zhang et al.; 6,439,308 to Wang; 5,654,261 to Smith; 5,284,206 to Surles et al.; 5,199,490 to Surles et al.; and 5,103,909 to Morgenthaler et al., all of which are incorporated by reference herein.
In some embodiment, the solvation fluid may include one or more nonionic additives (for example, alcohols, ethoxylated alcohols, nonionic surfactants and/or sugar based esters). In some embodiments, the solvation fluid may include one or more anionic surfactants (for example, sulfates, sulfonates, ethoxylated sulfates, and/or phosphates).
In some embodiments, the solvation fluid may include carbon disulfide. Hydrogen sulfide, in addition to other sulfur compounds produced from the formation, may be converted to carbon disulfide using known methods. Suitable methods may include oxidation reaction of the sulfur compound to sulfur and/or sulfur dioxides, and by reaction of sulfur and/or sulfur dioxides with carbon and/or a carbon containing compound to form the carbon disulfide formulation. The conversion of the sulfur compounds to carbon disulfide and the use of the carbon disulfide for oil recovery are described in U.S. Patent Publication No. 2006/0254769 to Van Dorp et al., which is incorporated by reference as if fully set forth herein. The carbon disulfide may be introduced into first section 2100, second section 2102 and/or third section 2104 as a solvation fluid.
Producing fluid from production wells in first section 2100 may lower the average pressure in the formation by forming an expansion volume for fluids heated in adjacent sections of the formation. Thus, producing fluid from production wells in the first section 2100 may establish a pressure gradient in the formation that draws mobilized fluid from second section 2102 and/or third section 2104 into the first section.
In some embodiments, a pressurizing fluid is provided in second section 2102 and/or third section 2104 (for example, through injection wells 748A, 748B) to increase mobilization of hydrocarbons within the sections. The pressurizing fluid may enhance the pressure gradient in the formation to flow mobilized hydrocarbons into first section 2100. In certain embodiments, the production of fluids from first section 2100 allows the pressure in second section 2102 and/or third section 2104 to remain below a selected pressure (for example, a pressure below which fracturing of the overburden and/or underburden may occur).
In some embodiments, a pressurizing fluid is provided to second section 2102 and/or third section 2104 in combination with the solvation fluid to increase mobility of hydrocarbons within the formation. The pressurizing fluid may include gases such as carbon dioxide, nitrogen, steam, methane, and/or mixtures thereof. In some embodiments, fluids produced from the formation (for example, combustion gases, heater exhaust gases, or produced formation fluids) may be used as pressurizing fluid. Providing a pressurizing fluid may increase a shear rate applied to hydrocarbon fluids in the formation and decrease the viscosity of non-Newtonian hydrocarbon fluids within the formation. In some embodiments, pressurizing fluid is provided to the selected section before significant heating of the formation. Pressurizing fluid injection may increase a portion of the formation available for production. Pressurizing fluid injection may increase a ratio of energy output of the formation (energy content of products produced from the formation) to energy input into the formation (energy costs for treating the formation).
Providing the pressurizing fluid may increase a pressure in a selected section of the formation. The pressure in the selected section may be maintained below a selected pressure. For example, the pressure may be maintained below about 150 bars absolute, about 100 bars absolute, or about 50 bars absolute. In some embodiments, the pressure may be maintained below about 35 bars absolute. Pressure may be varied depending on a number of factors (for example, desired production rate or an initial viscosity of tar in the formation). Injection of a gas into the formation may result in a viscosity reduction of some of the tar in the formation.
In some embodiments, pressure is maintained by controlling flow of the pressurizing fluid into the selected section. In other embodiments, the pressure is controlled by varying a location or locations for injecting the pressurizing fluid. In other embodiments, pressure is maintained by controlling a pressure and/or production rate at production wells 206. In some embodiments, the pressurized fluid (for example, carbon dioxide) is separated from the produced fluids and re-introduced into the formation. After production has been stopped, the fluid may be sequestered in the formation.
Enhanced hydrocarbon recovery methods may be used to produce additional hydrocarbons from portions of the formation adjacent to areas treated using in situ heat treatment processes. Systems and methods for enhanced hydrocarbons recovery are described in U.S. Pat. Nos. 3,943,160 to Farmer, III et al.; 3,946,812 to Gale et al.; 4,077,471 to Shupe et al.; 4,216,079 to Newcombe; 5,318,709 to Wuest et al.; 5,723,423 to Van Slyke; 6,022,834 to Hsu et al.; 6,269,881 to Chou et al.; and 7,055,602 to Shpakoff et al., all of which are incorporated by reference herein.
In certain embodiments, formation fluid is produced from first section 2100, second section 2102 and/or third section 2104. The formation fluid may be produced through production wells 206A, 206B, 206C. The formation fluid produced from second section 2102 and/or third section 2104 may include solvation fluid, hydrocarbons from first section 2100 second section 2102 and/or third section 2104, or mixtures thereof.
The produced fluids may be transported through conduits (pipelines) between the formation and a treatment facility or refinery. The produced fluids may be transported through a pipeline to another location for further transportation (for example, the fluids can be transported to a facility at a river or a coast through the pipeline where the fluids can be further transported by tanker to a processing plant or refinery).
Hydrocarbons may be produced from first section 2100, second section 2102 and/or third section 2104 such that at least about 30% by weight, at least about 40%, at least about 50%, at least about 60% or at least about 70% by volume of the initial mass of hydrocarbons in the formation are produced.
In certain embodiments, through addition of solvation fluids additional hydrocarbons may be produced from the formation such that at least about 60%, at least about 70%, or at least about 80% by volume of the initial volume of hydrocarbons in the sections, is produced from the formation.
In some embodiments, the fluids produced prior to solvent treatment include heavy hydrocarbons. The produced fluids may include at least 85 vol % hydrocarbon liquids and at most 15 vol % gases, at least 90 vol % hydrocarbon liquids and at most 10 vol % gases, or at least 95 vol % hydrocarbon liquids and at most 5 vol % gases. The heavy hydrocarbon liquids may be separated from the produced fluids (for example, separated from the gas and/or water in the produced fluids). The separated hydrocarbon liquids may have an API gravity between 19° and 25°, between 20° and 24°, or between 21° and 23°. A viscosity of the separated hydrocarbon liquids may be at most 350 cp at 5° C. A P-value of the separated hydrocarbon liquids may be at least 1.1, at least 1.5 or at least 2.0. The separated hydrocarbon liquids may have bromine of at most 3% and/or CAPP number of at most 2%. In some embodiments, the separated hydrocarbon liquids have an API gravity between 19° and 25°, a viscosity ranging at most 350 cp at 5° C., a P-value of at least 1.1, a CAPP number of at most 2% as 1-decene equivalent, and/or a bromine number of at most 2%.
In some embodiments, the mixture produced after solvent treatment includes solvation fluids, bitumen, visbroken fluids, pyrolyzed fluids, or mixtures therein. The mixture may be separated into heavy hydrocarbon liquids and solvation fluid. The heavy hydrocarbon liquids separated from the mixture may have an API gravity of between 10° and 25°, between 15° and 24°, or between 19° and 23°. In some embodiments the heavy hydrocarbon liquids are re-injected in another section of the formation.
During an in situ heat treatment process, some formation fluid may migrate outwards from the treatment area. The formation fluid may include benzene and/or other contaminants. Some portions of the formation that contaminants migrate to will be subsequently treated when a new treatment area is defined and processed using the in situ heat treatment process. Such contaminants may be removed or destroyed by the subsequent in situ heat treatment process. Some areas of the formation to which contaminants migrate may not become part of a new treatment area subjected to in situ heat treatment. Migration inhibition systems may be implemented to inhibit contaminants from migrating to areas in the formation that are not to be subjected to in situ heat treatment.
In some embodiments, a barrier (for example, a low temperature zone or freeze barrier) surrounds at least a portion of the perimeter of a treatment area. The barrier may be 20 m to 100 m from the closest heaters in the treatment area used in the in situ heat treatment process to heat the formation. Some contaminants may migrate outwards as vapor towards the barrier through fractures or permeable zones. Some of the contaminants may condense in the formation.
In some in situ heat treatment embodiments, a migration inhibition system may be used to minimize or eliminate migration of formation fluid from the treatment area of the in situ heat treatment process.
In some embodiments, one or more of the migration inhibition wells 924 include heaters. The heaters may be used to heat portions of the formation adjacent to the wells to a relatively low temperature. The relatively low temperature may be a temperature below a dissociation temperature of minerals in the formation adjacent to the well or below a pyrolysis temperature of hydrocarbons in the formation. The temperature that the low temperature heater wells raise the formation to may be less than 260° C., less than 230° C., or less than 200° C. In some embodiments, heating elements in migration inhibition wells 924 may be tailored so that the heating elements only heat portions of the formation that have permeability sufficient to allow for the migration of fluid (for example, fracture systems) and/or to allow for introduction of fluid from the migration inhibition wells.
In some embodiments, one or more heater wells may be installed adjacent to the migration inhibition wells 924. The heater wells may heat adjacent formation to an average temperature less than the dissociation temperature of minerals in the formation and/or less than the pyrolysis temperature of hydrocarbons in the formation. The heater wells may increase the permeability of the formation adjacent to migration inhibition wells 924. Heating elements in the heater wells may be tailored to only heat portions of the formation that have permeability sufficient to allow for migration of fluid and/or introduction of fluid from migration inhibition wells 924 into the formation.
The heat supplied by heaters near or from the migration inhibition wells may inhibit condensation of migrating vapors located adjacent to the migration inhibition wells. Sweep fluid introduced into the formation through the migration inhibition wells may drive migrating vapors back to the heated treatment area. At least a portion of the migrating vapors returned to the treatment area may react in the treatment area. At least a portion of the migrating vapors returned to the treatment area may be produced from the formation through production wells.
Some or all migration inhibition wells 924 may be injector wells that allow for the introduction of a sweep fluid into the formation. The injector wells may include smart well technology. Sweep fluid may be introduced into the formation through critical orifices, perforations or other types of openings in the injector wells. In some embodiments, the sweep fluid is carbon dioxide. The carbon dioxide may be carbon dioxide produced from an in situ heat treatment process. The sweep fluid may be or include other fluids, such as nitrogen, methane or other non-condensable hydrocarbons, exhaust gases, air, water, and/or steam. The sweep fluid may provide positive pressure in the formation outside of treatment area 882. The positive pressure may inhibit migration of formation fluid from treatment area 882 towards barrier 922. The sweep fluid may move through fractures in the formation toward or into treatment area 882. The sweep fluid may carry fluids that have migrated away from treatment area 882 back to the treatment area. The pressure of the fluid introduced through migration inhibition wells 924 may be maintained below the fracture pressure of the formation.
After an in situ process, energy recovery, remediation, and/or sequestration of carbon dioxide or other fluids in the treated area; the treatment area may still be at an elevated temperature. Sulfur may be introduced into the formation to act as a drive fluid to remove remaining formation fluid from the formation. The sulfur may be introduced through outermost wellbores in the formation. The wellbores may be injection wells, production wells, monitor wells, heater wells, barrier wells, or other types of wells that are converted to use as sulfur injection wells. The sulfur may be used to drive fluid inwards towards production wells in the pattern of wells used during the in situ heat treatment process. The wells used as production wells for sulfur may be production wells, heater wells, injection wells, monitor wells, or other types of wells converted for use as sulfur production wells.
In some embodiments, sulfur may be introduced in the treatment area from an outermost set of wells. Formation fluid may be produced from a first inward set of wellbores until substantially only sulfur is produced from the first inward set of wells. The first inward set of wells may be converted to injection wells. Sulfur may be introduced in the first inward set of wells to drive remaining formation fluid towards a second inward set of wells. The pattern may be continued until sulfur has been introduced into all of the treatment area. In some embodiments, a line drive may be used for introducing the sulfur into the treatment area.
In some embodiments, molten sulfur may be injected into the treatment area. The molten sulfur may act as a displacement agent that moves and/or entrains remaining fluid in the treatment area. The molten sulfur may be injected into the formation from selected wells. The sulfur may be at a temperature near a melting point of sulfur so that the sulfur has a relatively low viscosity. In some embodiments, the formation may be at a temperature above the boiling point of sulfur. Sulfur may be introduced into the formation as a gas or as a liquid.
Sulfur may be introduced into the formation until substantially only sulfur is produced from the last sulfur production well or production wells. When substantially only sulfur is produced from the last sulfur production well or production wells, introduction of additional sulfur may be stopped, and the production from the production well or production wells may be stopped. Sulfur in the formation may be allowed to remain in the formation and solidify.
Alternative energy sources may be used to supply electricity for subsurface electric heaters. Alternative energy sources include, but are not limited to, wind, off-peak power, hydroelectric power, geothermal, solar, and tidal wave action. Some of these alternative energy sources provide intermittent, time-variable power, or power-variable power. To provide power for subsurface electric heaters, power provided by these alternative energy sources may be conditioned to produce power with appropriate operating parameters (for example, voltage, frequency, and/or current) for the subsurface heaters.
In some embodiments, gas turbine 928 is used to generate electricity to power heaters 760. Windmill 926 and/or gas turbine 928 may be coupled to transformer 930. Transformer 930 may convert power from windmill 926 and/or gas turbine 928 into electrical power with appropriate operating parameters for heaters 760 (for example, AC or DC power with appropriate voltage, current, and/or frequency may be generated by the transformer).
In certain embodiments, tap controller 932 is coupled to transformer 930, control system 934, and heaters 760. Tap controller 932 may monitor and control transformer 930 to maintain a constant voltage to heaters 760, regardless of the load of the heaters. Tap controller 932 may control power output in a range from 5 MVA (megavolt amps) to 500 MVA, from 10 MVA to 400 MVA, or from 20 MVA to 300 MVA. Tap controller 932 may be designed to meet selected design requirements such as, but not limited to, load limitations of components (such as transformer 930, control system 934, and/or heaters 760) and the expected full load current in the electrical circuit. Tap controller 932 may be an electromechanical, mechanical, electrical, electromagnetic, or solid state tap controller. In one embodiments, tap controller 932 is a 32 step (±16 steps) electromechanical tap controller obtained from ABB Ltd. (Asea Brown Boveri) (Zurich, Switzerland). Tap controller 932 may be a step controller that changes power in steps over a period of time (for example, 1 step per minute). Tap controller 932 may operated over a percentage of the total range (for example, ±15% of the voltage or ±10% of the voltage).
As an example, during operation, an overload of voltage may be sent from transformer 930. Tap controller 932 may modify the load provided to heaters 760 and distribute the excess load to other heaters and/or other equipment in need of power. In some embodiments, tap controller 932 may store the excess load for future use.
Control system 934 may control tap controller 932. Control system 934 may be, for example, a computer controller or an analog logic system. Control system 934 may use data supplied from power sensors 936 to generate predictive algorithms and/or control tap controller 932. For example, data may be an amount of power generated from windmill 926, gas turbine 928, and/or transformer 930. Data may also include an amount of resistive load of heaters 760. Power sensors 936 may be toroidal current sensors that output voltages that are proportional to the currents in wires passing through the sensors.
Automatic voltage regulation for resistive load of a heater enhances the life of the heaters and/or allows constant heat output from the heaters to a subsurface formation. Adjusting the load demands instead of adjusting the power source allows enhanced control of power supplied to heaters and/or other equipment that requires electricity. Power supplied to heaters 760 may be controlled within selected limits (for example, a power supplied and/or controlled to a heater within 1%, 5%, 10%, or 20% of power required by the heater). Control of power supplied from alternative energy sources may allow output of prime power at its rating, allow energy produced (for example, from an intermittent source, a subsurface formation, or a hydroelectric source) to be stored and used later, and/or allow use of power generated by intermittent power sources to be used as a constant source of energy.
Some hydrocarbon containing formations, such as oil shale formations, may include nahcolite, trona, dawsonite, and/or other minerals within the formation. In some embodiments, nahcolite is contained in partially unleached or unleached portions of the formation. Unleached portions of the formation are parts of the formation where minerals have not been removed by groundwater in the formation. For example, in the Piceance basin in Colorado, U.S.A., unleached oil shale is found below a depth of about 500 m below grade. Deep unleached oil shale formations in the Piceance basin center tend to be relatively rich in hydrocarbons. For example, about 0.10 liters to about 0.15 liters of oil per kilogram (L/kg) of oil shale may be producible from an unleached oil shale formation.
Nahcolite is a mineral that includes sodium bicarbonate (NaHCO3). Nahcolite may be found in formations in the Green River lakebeds in Colorado, U.S.A. In some embodiments, at least about 5 weight %, at least about 10 weight %, or at least about 20 weight % nahcolite may be present in the formation. Dawsonite is a mineral that includes sodium aluminum carbonate (NaAl(CO3)(OH)2). Dawsonite is typically present in the formation at weight percents greater than about 2 weight % or, in some embodiments, greater than about 5 weight %. Nahcolite and/or dawsonite may dissociate at temperatures used in an in situ heat treatment process. The dissociation is strongly endothermic and may produce large amounts of carbon dioxide.
Nahcolite and/or dawsonite may be solution mined prior to, during, and/or following treatment of the formation in situ to avoid dissociation reactions and/or to obtain desired chemical compounds. In certain embodiments, hot water or steam is used to dissolve nahcolite in situ to form an aqueous sodium bicarbonate solution before the in situ heat treatment process is used to process hydrocarbons in the formation. Nahcolite may form sodium ions (Na+) and bicarbonate ions (HCO3-) in aqueous solution. The solution may be produced from the formation through production wells, thus avoiding dissociation reactions during the in situ heat treatment process. In some embodiments, dawsonite is thermally decomposed to alumina during the in situ heat treatment process for treating hydrocarbons in the formation. The alumina is solution mined after completion of the in situ heat treatment process.
Production wells and/or injection wells used for solution mining and/or for in situ heat treatment processes may include smart well technology. The smart well technology allows the first fluid to be introduced at a desired zone in the formation. The smart well technology allows the second fluid to be removed from a desired zone of the formation.
Formations that include nahcolite and/or dawsonite may be treated using the in situ heat treatment process. A perimeter barrier may be formed around the portion of the formation to be treated. The perimeter barrier may inhibit migration of water into the treatment area. During solution mining and/or the in situ heat treatment process, the perimeter barrier may inhibit migration of dissolved minerals and formation fluid from the treatment area. During initial heating, a portion of the formation to be treated may be raised to a temperature below the dissociation temperature of the nahcolite. The temperature may be at most about 90° C., or in some embodiments, at most about 80° C. The temperature may be any temperature that increases the solvation rate of nahcolite in water, but is also below a temperature at which nahcolite dissociates (above about 95° C. at atmospheric pressure).
A first fluid may be injected into the heated portion. The first fluid may include water, brine, steam, or other fluids that form a solution with nahcolite and/or dawsonite. The first fluid may be at an increased temperature, for example, about 90° C., about 95° C., or about 100° C. The increased temperature may be similar to the temperature of the portion of the formation.
In some embodiments, the first fluid is injected at an increased temperature into a portion of the formation that has not been heated by heat sources. The increased temperature may be a temperature below a boiling point of the first fluid, for example, about 90° C. for water. Providing the first fluid at an increased temperature increases a temperature of a portion of the formation. In certain embodiments, additional heat may be provided from one or more heat sources in the formation during and/or after injection of the first fluid.
In other embodiments, the first fluid is or includes steam. The steam may be produced by forming steam in a previously heated portion of the formation (for example, by passing water through u-shaped wellbores that have been used to heat the formation), by heat exchange with fluids produced from the formation, and/or by generating steam in standard steam production facilities. In some embodiments, the first fluid may be fluid introduced directly into a hot portion of the portion and produced from the hot portion of the formation. The first fluid may then be used as the first fluid for solution mining.
In some embodiments, heat from a hot previously treated portion of the formation is used to heat water, brine, and/or steam used for solution mining a new portion of the formation. Heat transfer fluid may be introduced into the hot previously treated portion of the formation. The heat transfer fluid may be water, steam, carbon dioxide, and/or other fluids. Heat may transfer from the hot formation to the heat transfer fluid. The heat transfer fluid is produced from the formation through production wells. The heat transfer fluid is sent to a heat exchanger. The heat exchanger may heat water, brine, and/or steam used as the first fluid to solution mine the new portion of the formation. The heat transfer fluid may be reintroduced into the heated portion of the formation to produce additional hot heat transfer fluid. In some embodiments, heat transfer fluid produced from the formation is treated to remove hydrocarbons or other materials before being reintroduced into the formation as part of a remediation process for the heated portion of the formation.
Steam injected for solution mining may have a temperature below the pyrolysis temperature of hydrocarbons in the formation. Injected steam may be at a temperature below 250° C., below 300° C., or below 400° C. The injected steam may be at a temperature of at least 150° C., at least 135° C., or at least 125° C. Injecting steam at pyrolysis temperatures may cause problems as hydrocarbons pyrolyze and hydrocarbon fines mix with the steam. The mixture of fines and steam may reduce permeability and/or cause plugging of production wells and the formation. Thus, the injected steam temperature is selected to inhibit plugging of the formation and/or wells in the formation.
The temperature of the first fluid may be varied during the solution mining process. As the solution mining progresses and the nahcolite being solution mined is farther away from the injection point, the first fluid temperature may be increased so that steam and/or water that reaches the nahcolite to be solution mined is at an elevated temperature below the dissociation temperature of the nahcolite. The steam and/or water that reaches the nahcolite is also at a temperature below a temperature that promotes plugging of the formation and/or wells in the formation (for example, the pyrolysis temperature of hydrocarbons in the formation).
A second fluid may be produced from the formation following injection of the first fluid into the formation. The second fluid may include material dissolved in the first fluid. For example, the second fluid may include carbonic acid or other hydrated carbonate compounds formed from the dissolution of nahcolite in the first fluid. The second fluid may also include minerals and/or metals. The minerals and/or metals may include sodium, aluminum, phosphorus, and other elements.
Solution mining the formation before the in situ heat treatment process allows initial heating of the formation to be provided by heat transfer from the first fluid used during solution mining. Solution mining nahcolite or other minerals that decompose or dissociate by means of endothermic reactions before the in situ heat treatment process avoids having energy supplied to heat the formation being used to support these endothermic reactions. Solution mining allows for production of minerals with commercial value. Removing nahcolite or other minerals before the in situ heat treatment process removes mass from the formation. Thus, less mass is present in the formation that needs to be heated to higher temperatures and heating the formation to higher temperatures may be achieved more quickly and/or more efficiently. Removing mass from the formation also may increase the permeability of the formation. Increasing the permeability may reduce the number of production wells needed for the in situ heat treatment process. In certain embodiments, solution mining before the in situ heat treatment process reduces the time delay between startup of heating of the formation and production of hydrocarbons by two years or more.
In some formations, a portion of the formation with unleached minerals may be below a leached portion of the formation. The unleached portion may be thick and substantially impermeable. A treatment area may be formed in the unleached portion. Unleached portion of the formation to the sides, above and/or below the treatment area may be used as barriers to fluid flow into and out of the treatment area. A first treatment area may be solution mined to remove minerals, increase permeability in the treatment area, and/or increase the richness of the hydrocarbons in the treatment area. After solution mining the first treatment area, in situ heat treatment may be used to treat a second treatment area. In some embodiments, the second treatment area is the same as the first treatment area. In some embodiments, the second treatment has a smaller volume than the first treatment area so that heat provided by outermost heat sources to the formation do not raise the temperature of unleached portions of the formation to the dissociation temperature of the minerals in the unleached portions.
In some embodiments, a leached or partially leached portion of the formation above an unleached portion of the formation may include significant amounts of hydrocarbon materials. An in situ heating process may be used to produce hydrocarbon fluids from the unleached portions and the leached or partially leached portions of the formation.
Heat sources 202 in first treatment area 882′ may be used to heat the first treatment area to pyrolysis temperatures. In some embodiments, one or more heat sources 202 are placed in the formation before first treatment area 882′ is solution mined. The heat sources may be used to provide initial heating to the formation to raise the temperature of the formation and/or to test the functionality of the heat sources. In some embodiments, one or more heat sources are installed during solution mining of the first treatment area, or after solution mining is completed. After solution mining, heat sources 202 may be used to raise the temperature of at least a portion of first treatment area 882′ above the pyrolysis and/or mobilization temperature of hydrocarbons in the formation to result in the generation of mobile hydrocarbons in the first treatment area.
Barrier wells 200 may be introduced into the formation. Ends of barrier wells 200 may extend into and terminate in unleached zone 950. Unleached zone 950 may be impermeable. In some embodiments, barrier wells 200 are freeze wells. Barrier wells 200 may be used to form a barrier to fluid flow into or out of unleached zone 952. Barrier wells 200, overburden 458, and the unleached material above first treatment area 882′ may define second treatment area 882″. In some embodiments, a first fluid may be introduced into second treatment area 882″ through solution mining wells 938 to raise the initial temperature of the formation in second treatment area 882″ and remove any residual soluble minerals from the second treatment area. In some embodiments, the top barrier above first treatment area 882′ may be solution mined to remove minerals and combine first treatment area 882′ and second treatment area 882″ into one treatment area. After solution mining, heat sources may be activated to heat the treatment area to pyrolysis temperatures.
Water inside treatment area 882 may be pumped out of the treatment area through injection wells 748 and/or production wells 206. In certain embodiments, injection wells 748 are used as production wells 206 and vice versa (the wells are used as both injection wells and production wells). Water may be pumped out until a production rate of water is low or stops.
Heat may be provided to treatment area 882 from heat sources 202. Heat sources may be operated at temperatures that do not result in the pyrolysis of hydrocarbons in the formation adjacent to the heat sources. In some embodiments, treatment area 882 is heated to a temperature from about 90° C. to about 120° C. (for example, a temperature of about 90° C., 95° C., 100° C., 110° C., or 120° C.). In certain embodiments, heat is provided to treatment area 882 from the first fluid injected into the formation. The first fluid may be injected at a temperature from about 90° C. to about 120° C. (for example, a temperature of about 90° C., 95° C., 100° C., 110° C., or 120° C.). In some embodiments, heat sources 202 are installed in treatment area 882 after the treatment area is solution mined. In some embodiments, some heat is provided from heaters placed in injection wells 748 and/or production wells 206. A temperature of treatment area 882 may be monitored using temperature measurement devices placed in monitoring wells 956 and/or temperature measurement devices in injection wells 748, production wells 206, and/or heat sources 202.
The first fluid is injected through one or more injection wells 748. In some embodiments, the first fluid is hot water. The first fluid may mix and/or combine with non-hydrocarbon material that is soluble in the first fluid, such as nahcolite, to produce a second fluid. The second fluid may be removed from the treatment area through injection wells 748, production wells 206, and/or heat sources 202. Injection wells 748, production wells 206, and/or heat sources 202 may be heated during removal of the second fluid. Heating one or more wells during removal of the second fluid may maintain the temperature of the fluid during removal of the fluid from the treatment area above a desired value. After producing a desired amount of the soluble non-hydrocarbon material from treatment area 882, solution remaining within the treatment area may be removed from the treatment area through injection wells 748, production wells 206, and/or heat sources 202. The desired amount of the soluble non-hydrocarbon material may be less than half of the soluble non-hydrocarbon material, a majority of the soluble non-hydrocarbon material, substantially all of the soluble non-hydrocarbon material, or all of the soluble non-hydrocarbon material. Removing soluble non-hydrocarbon material may produce a relatively high permeability treatment area 882.
Hydrocarbons within treatment area 882 may be pyrolyzed and/or produced using the in situ heat treatment process following removal of soluble non-hydrocarbon materials. The relatively high permeability treatment area allows for easy movement of hydrocarbon fluids in the formation during in situ heat treatment processing. The relatively high permeability treatment area provides an enhanced collection area for pyrolyzed and mobilized fluids in the formation. During the in situ heat treatment process, heat may be provided to treatment area 882 from heat sources 202. A mixture of hydrocarbons may be produced from the formation through production wells 206 and/or heat sources 202. In certain embodiments, injection wells 748 are used as either production wells and/or heater wells during the in situ heat treatment process.
In some embodiments, a controlled amount of oxidant (for example, air and/or oxygen) is provided to treatment area 882 at or near heat sources 202 when a temperature in the formation is above a temperature sufficient to support oxidation of hydrocarbons. At such a temperature, the oxidant reacts with the hydrocarbons to provide heat in addition to heat provided by electrical heaters in heat sources 202. The controlled amount of oxidant may facilitate oxidation of hydrocarbons in the formation to provide additional heat for pyrolyzing hydrocarbons in the formation. The oxidant may more easily flow through treatment area 882 because of the increased permeability of the treatment area after removal of the non-hydrocarbon materials. The oxidant may be provided in a controlled manner to control the heating of the formation. The amount of oxidant provided is controlled so that uncontrolled heating of the formation is avoided. Excess oxidant and combustion products may flow to production wells in treatment area 882.
Following the in situ heat treatment process, treatment area 882 may be cooled by introducing water to produce steam from the hot portion of the formation. Introduction of water to produce steam may vaporize some hydrocarbons remaining in the formation. Water may be injected through injection wells 748. The injected water may cool the formation. The remaining hydrocarbons and generated steam may be produced through production wells 206 and/or heat sources 202. Treatment area 882 may be cooled to a temperature near the boiling point of water. The steam produced from the formation may be used to heat a first fluid used to solution mine another portion of the formation.
Treatment area 882 may be further cooled to a temperature at which water will condense in the formation. Water and/or solvent may be introduced into and be removed from the treatment area. Removing the condensed water and/or solvent from treatment area 882 may remove any additional soluble material remaining in the treatment area. The water and/or solvent may entrain non-soluble fluid present in the formation. Fluid may be pumped out of treatment area 882 through production well 206 and/or heat sources 202. The injection and removal of water and/or solvent may be repeated until a desired water quality within treatment area 882 is achieved. Water quality may be measured at injection wells 748, heat sources 202, and/or production wells 206. The water quality may substantially match or exceed the water quality of treatment area 882 prior to treatment.
In some embodiments, treatment area 882 may include a leached zone located above an unleached zone. The leached zone may have been leached naturally and/or by a separate leaching process. In certain embodiments, the unleached zone may be at a depth of at least about 500 m. A thickness of the unleached zone may be between about 100 m and about 500 m. However, the depth and thickness of the unleached zone may vary depending on, for example, a location of treatment area 882 and/or the type of formation. In certain embodiments, the first fluid is injected into the unleached zone below the leached zone. Heat may also be provided into the unleached zone.
In certain embodiments, a section of a formation may be left untreated by solution mining and/or unleached. The unleached section may be proximate a selected section of the formation that has been leached and/or solution mined by providing the first fluid as described above. The unleached section may inhibit the flow of water into the selected section. In some embodiments, more than one unleached section may be proximate a selected section.
Nahcolite may be present in the formation in layers or beds. Prior to solution mining, such layers may have little or no permeability. In certain embodiments, solution mining layered or bedded nahcolite from the formation causes vertical shifting in the formation.
In certain embodiments, removing nahcolite from the formation interconnects two or more wells in the formation. Removing nahcolite from zones in the formation may increase the permeability in the zones. Some zones may have more nahcolite than others and become more permeable as the nahcolite is removed. At a certain time, zones with the increased permeability may interconnect two or more wells (for example, injection wells or production wells) in the formation.
In some embodiments, a treatment area has nahcolite beds above and/or below the treatment area. The nahcolite beds may be relatively thin (for example, about 5 m to about 10 m in thickness). In an embodiment, the nahcolite beds are solution mined using horizontal solution mining wells in the nahcolite beds. The nahcolite beds may be solution mined in a short amount of time (for example, in less than 6 months). After solution mining of the nahcolite beds, the treatment area and the nahcolite beds may be heated using one or more heaters. The heaters may be placed either vertically, horizontally, or at other angles within the treatment area and the nahcolite beds. The nahcolite beds and the treatment area may then undergo the in situ heat treatment process.
In some embodiments, the solution mining wells in the nahcolite beds are converted to production wells. The production wells may be used to produce fluids during the in situ heat treatment process. Production wells in the nahcolite bed above the treatment area may be used to produce vapors or gas (for example, gas hydrocarbons) from the formation. Production wells in the nahcolite bed below the treatment area may be used to produce liquids (for example, liquid hydrocarbons) from the formation.
In some embodiments, the second fluid produced from the formation during solution mining is used to produce sodium bicarbonate. Sodium bicarbonate may be used in the food and pharmaceutical industries, in leather tanning, in fire retardation, in wastewater treatment, and in flue gas treatment (flue gas desulphurization and hydrogen chloride reduction). The second fluid may be kept pressurized and at an elevated temperature when removed from the formation. The second fluid may be cooled in a crystallizer to precipitate sodium bicarbonate.
In some embodiments, the second fluid produced from the formation during solution mining is used to produce sodium carbonate, which is also referred to as soda ash. Sodium carbonate may be used in the manufacture of glass, in the manufacture of detergents, in water purification, polymer production, tanning, paper manufacturing, effluent neutralization, metal refining, sugar extraction, and/or cement manufacturing. The second fluid removed from the formation may be heated in a treatment facility to form sodium carbonate (soda ash) and/or sodium carbonate brine. Heating sodium bicarbonate will form sodium carbonate according to the equation:
2NaHCO3→Na2CO3+CO2+H2O. (EQN. 7)
In certain embodiments, the heat for heating the sodium bicarbonate is provided using heat from the formation. For example, a heat exchanger that uses steam produced from the water introduced into the hot formation may be used to heat the second fluid to dissociation temperatures of the sodium bicarbonate. In some embodiments, the second fluid is circulated through the formation to utilize heat in the formation for further reaction. Steam and/or hot water may also be added to facilitate circulation. The second fluid may be circulated through a heated portion of the formation that has been subjected to the in situ heat treatment process to produce hydrocarbons from the formation. At least a portion of the carbon dioxide generated during sodium carbonate dissociation may be adsorbed on carbon that remains in the formation after the in situ heat treatment process. In some embodiments, the second fluid is circulated through conduits previously used to heat the formation.
In some embodiments, higher temperatures are used in the formation (for example, above about 120° C., above about 130° C., above about 150° C., or below about 250° C.) during solution mining of nahcolite. The first fluid is introduced into the formation under pressure sufficient to inhibit sodium bicarbonate from dissociating to produce carbon dioxide. The pressure in the formation may be maintained at sufficiently high pressures to inhibit such nahcolite dissociation but below pressures that would result in fracturing the formation. In addition, the pressure in the formation may be maintained high enough to inhibit steam formation if hot water is being introduced in the formation. In some embodiments, a portion of the nahcolite may begin to decompose in situ. In such cases, nahcolite is removed from the formation as soda ash. If soda ash is produced from solution mining of nahcolite, the soda ash may be transported to a separate facility for treatment. The soda ash may be transported through a pipeline to the separate facility.
As described above, in certain embodiments, following removal of nahcolite from the formation, the formation is treated using the in situ heat treatment process to produce formation fluids from the formation. In some embodiments, the formation is treating using the in situ heat treatment process before solution mining nahcolite from the formation. The nahcolite may be converted to sodium carbonate (from sodium bicarbonate) during the in situ heat treatment process. The sodium carbonate may be solution mined as described above for solution mining nahcolite prior to the in situ heat treatment process.
In some formations, dawsonite is present in the formation. Dawsonite within the heated portion of the formation decomposes during heating of the formation to pyrolysis temperature. Dawsonite typically decomposes at temperatures above 270° C. according to the reaction:
2NaAl(OH)2CO3→Na2CO3+Al2O3+2H2O+CO2. (EQN. 8)
Sodium carbonate may be removed from the formation by solution mining the formation with water or other fluid into which sodium carbonate is soluble. In certain embodiments, alumina formed by dawsonite decomposition is solution mined using a chelating agent. The chelating agent may be injected through injection wells, production wells, and/or heater wells used for solution mining nahcolite and/or the in situ heat treatment process (for example, injection wells 748, production wells 206, and/or heat sources 202 depicted in
In some embodiments, alumina within the formation may be solution mined using a basic fluid after the in situ heat treatment process. Basic fluids include, but are not limited to, sodium hydroxide, ammonia, magnesium hydroxide, magnesium carbonate, sodium carbonate, potassium carbonate, pyridine, and amines. In an embodiment, sodium carbonate brine, such as 0.5 Normal Na2CO3, is used to solution mine alumina. Sodium carbonate brine may be obtained from solution mining nahcolite from the formation. Obtaining the basic fluid by solution mining the nahcolite may significantly reduce costs associated with obtaining the basic fluid. The basic fluid may be injected into the formation through a heater well and/or an injection well. The basic fluid may combine with alumina to form an alumina solution that is removed from the formation. The alumina solution may be removed through a heater well, injection well, or production well.
Alumina may be extracted from the alumina solution in a treatment facility. In an embodiment, carbon dioxide is bubbled through the alumina solution to precipitate the alumina from the basic fluid. Carbon dioxide may be obtained from dissociation of nahcolite, from the in situ heat treatment process, or from decomposition of the dawsonite during the in situ heat treatment process.
In certain embodiments, a formation may include portions that are significantly rich in either nahcolite or dawsonite only. For example, a formation may contain significant amounts of nahcolite (for example, at least about 20 weight %, at least about 30 weight %, or at least about 40 weight %) in a depocenter of the formation. The depocenter may contain only about 5 weight % or less dawsonite on average. However, in bottom layers of the formation, a weight percent of dawsonite may be about 10 weight % or even as high as about 25 weight %. In such formations, it may be advantageous to solution mine for nahcolite only in nahcolite-rich areas, such as the depocenter, and solution mine for dawsonite only in the dawsonite-rich areas, such as the bottom layers. This selective solution mining may significantly reduce fluid costs, heating costs, and/or equipment costs associated with operating the solution mining process.
In certain formations, dawsonite composition varies between layers in the formation. For example, some layers of the formation may have dawsonite and some layers may not. In certain embodiments, more heat is provided to layers with more dawsonite than to layers with less dawsonite. Tailoring heat input to provide more heat to certain dawsonite layers more uniformly heats the formation as the reaction to decompose dawsonite absorbs some of the heat intended for pyrolyzing hydrocarbons.
Solution mining dawsonite and nahcolite may be relatively simple processes that produce alumina and soda ash from the formation. In some embodiments, hydrocarbons produced from the formation using the in situ heat treatment process may be fuel for a power plant that produces direct current (DC) electricity at or near the site of the in situ heat treatment process. The produced DC electricity may be used on the site to produce aluminum metal from the alumina using the Hall process. Aluminum metal may be produced from the alumina by melting the alumina in a treatment facility on the site. Generating the DC electricity at the site may save on costs associated with using hydrotreaters, pipelines, or other treatment facilities associated with transporting and/or treating hydrocarbons produced from the formation using the in situ heat treatment process.
In some embodiments, acid may be introduced into the formation through selected wells to increase the porosity adjacent to the wells. For example, acid may be injected if the formation comprises limestone or dolomite. The acid used to treat the selected wells may be acid produced during in situ heat treatment of a section of the formation (for example, hydrochloric acid), or acid produced from byproducts of the in situ heat treatment process (for example, sulfuric acid produced from hydrogen sulfide or sulfur).
In some embodiments, a saline rich zone is located at or near an unleached portion of the formation. The saline rich zone may be an aquifer in which water has leached out nahcolite and/or other minerals. A high flow rate may pass through the saline rich zone. Saline water from the saline rich zone may be used to solution mine another portion of the formation. In certain embodiments, a steam and electricity cogeneration facility may be used to heat the saline water prior to use for solution mining.
Treatment area 882 may have significant amounts of nahcolite. Saline zone 2106 is located at or near treatment area 882. In certain embodiments, zone 2106 is located up dip from treatment area 882. Zone 2106 may be leached or partially leached such that the zone is mainly filled with saline water.
In certain embodiments, saline water is removed (pumped) from zone 2106 using production well 206. Production well 206 may be located at or near the lowest portion of zone 2106 so that saline water flows into the production well. Saline water removed from zone 2106 is heated to hot water and/or steam temperatures in facility 750. Facility 750 may burn hydrocarbons to run generators that produce electricity. Facility 750 may burn gaseous and/or liquid hydrocarbons to make electricity. In some embodiments, pulverized coal is used to make electricity. The electricity generated may be used to provide electrical power for heaters or other electrical operations (for example, pumping). Waste heat from the generators is used to make hot water and/or steam from the saline water. After the in situ heat treatment process of one or more treatment areas 882 results in the production of hydrocarbons, at least a portion of the produced hydrocarbons may be used as fuel for facility 750.
The hot water and/or steam made by facility 750 is provided to solution mining well 938. Solution mining well 938 is used to solution mine treatment area 882. Nahcolite and/or other minerals are removed from treatment area 882 by solution mining well 938. The nahcolite may be removed as a nahcolite solution from treatment area 882. The solution removed from treatment area 882 may be a brine solution with dissolved nahcolite. Heat from the removed nahcolite solution may be used in facility 750 to heat saline water from zone 2106 and/or other fluids. The nahcolite solution may then be injected through injection well 748 into zone 2106. In some embodiments, injection well 748 injects the nahcolite solution into zone 2106 up dip from production well 206. Injection may occur a significant distance up dip so that nahcolite solution may be continuously injected as saline water is removed from the zone without the two fluids substantially intermixing. In some embodiments, the nahcolite solution from treatment area 882 is provided to injection well 748 without passing through facility 750 (the nahcolite solution bypasses the facility).
The nahcolite solution injected into zone 2106 may be left in the zone permanently or for an extended period of time (for example, after solution mining, production well 206 may be shut in). In some embodiments, the nahcolite stored in zone 2106 is accessed at later times. The nahcolite may be produced by removing saline water from zone 2106 and processing the saline water to make sodium bicarbonate and/or soda ash.
Solution mining using saline water from zone 2106 and heat from facility 750 to heat the saline water may be a high efficiency process for solution mining treatment area 882. Facility 750 is efficient at providing heat to the saline water. Using the saline water to solution mine decreases costs associated with pumping and/or transporting water to the treatment site. Additionally, solution mining treatment area 882 preheats the treatment area for any subsequent heat treatment of the treatment area, enriches the hydrocarbon content in the treatment area by removing nahcolite, and/or creates more permeability in the treatment area by removing nahcolite.
In certain embodiments, treatment area 882 is further treated using an in situ heat treatment process following solution mining of the treatment area. A portion of the electricity generated in facility 750 may be used to power heaters for the in situ heat treatment process.
In some embodiments, a perimeter barrier may be formed around the portion of the formation to be treated. The perimeter barrier may inhibit migration of formation fluid into or out of the treatment area. The perimeter barrier may be a frozen barrier and/or a grout barrier. After formation of the perimeter barrier, the treatment area may be processed to produce desired products.
Formations that include non-hydrocarbon materials may be treated to remove and/or dissolve a portion of the non-hydrocarbon materials from a section of the formation before hydrocarbons are produced from the section. In some embodiments, the non-hydrocarbon materials are removed by solution mining. Removing a portion of the non-hydrocarbon materials may reduce the carbon dioxide generation sources present in the formation. Removing a portion of the non-hydrocarbon materials may increase the porosity and/or permeability of the section of the formation. Removing a portion of the non-hydrocarbon materials may result in a raised temperature in the section of the formation.
After solution mining, some of the wells in the treatment may be converted to heater wells, injection wells, and/or production wells. In some embodiments, additional wells are formed in the treatment area. The wells may be heater wells, injection wells, and/or production wells. Logging techniques may be employed to assess the physical characteristics, including any vertical shifting resulting from the solution mining, and/or the composition of material in the formation. Packing, baffles or other techniques may be used to inhibit formation fluid from entering the heater wells. The heater wells may be activated to heat the formation to a temperature sufficient to support combustion.
One or more production wells may be positioned in permeable sections of the treatment area. Production wells may be horizontally and/or vertically oriented. For example, production wells may be positioned in areas of the formation that have a permeability of greater than 5 darcy or 10 darcy. In some embodiments, production wells may be positioned near a perimeter barrier. A production well may allow water and production fluids to be removed from the formation. Positioning the production well near a perimeter barrier enhances the flow of fluids from the warmer zones of the formation to the cooler zones.
Heat may be provided to treatment area 882 through heaters positioned in injection wells 748. In some embodiments, the heaters in injection wells 748 heat formation adjacent to the injections wells to temperatures sufficient to support combustion. Heaters in injection wells 748 may raise the formation near the injection wells to temperatures from about 90° C. to about 120° C. or higher (for example, a temperature of about 90° C., 95° C., 100° C., 110° C., or 120° C.).
Injection wells 748 may be used to introduce a combustion fuel, an oxidant, steam and/or a heat transfer fluid into treatment area 882, either before, during, or after heat is provided to the treatment area 882 from heaters. In some embodiments, injection wells 748 are in communication with each other to allow the introduced fluid to flow from one well to another. Injection wells 748 may be located at positions that are relatively far away from perimeter barrier 922. Introduced fluid may cause combustion of hydrocarbons in treatment area 882. Heat from the combustion may heat treatment area 882 and mobilize fluids toward production wells 206.
A temperature of treatment area 882 may be monitored using temperature measurement devices placed in monitoring wells and/or temperature measurement devices in injection wells 748, production wells 206, and/or heater wells.
In some embodiments, a controlled amount of oxidant (for example, air and/or oxygen) is provided in injection wells 748 to advance a heat front towards production wells 206. In some embodiments, the controlled amount of oxidant is introduced into the formation after solution mining has established permeable interconnectivity between at least two injection wells. The amount of oxidant is controlled to limit the advancement rate of the heat front and to limit the temperature of the heat front. The advancing heat front may pyrolyze hydrocarbons. The high permeability in the formation allows the pyrolyzed hydrocarbons to spread in the formation towards production wells without being overtaken by the advancing heat front.
Vaporized formation fluid and/or gas formed during the combustion process may be removed through gas wells 960 and/or injection well 748. Venting of gases through the gas wells and/or the injection well may force the combustion front in a desired direction.
In some embodiments, the formation may be heated to a temperature sufficient to cause pyrolysis of the formation fluid by the steam and/or heat transfer fluid. The steam and/or heat transfer fluid may be heated to temperatures of about 300° C., about 400° C., about 500° C., or about 600° C. In certain embodiments, the steam and/or heat transfer fluid may be co-injected with the fuel and/or oxidant.
Gases may be produced during in situ heat treatment processes and during many conventional production processes. Some of the produced gases (for example, carbon dioxide and/or hydrogen sulfide) when introduced into water may change the pH of the water to less than 7. Such gases are typically referred to as sour gas or acidic gas. Introducing sour gas from produced fluid into subsurface formations may reduce or eliminate the need for or size of certain surface facilities (for example, a Claus plant or Scot gas treater). Introducing sour gas from produced formation fluid into subsurface formations may make the formation fluid more acceptable for transportation, use, and/or processing. Removal of sour gas having a low heating value (for example, carbon dioxide) from formation fluids may increase the caloric value of the gas stream separated from the formation fluid.
Net release of sour gas to the atmosphere and/or conversion of sour gas to other compounds may be reduced by utilizing the produced sour gas and/or by storing the sour gas within subsurface formations. In some embodiments, the sour gas is stored in deep saline aquifers. Deep saline aquifers may be at depths of about 900 m or more below the surface. The deep saline aquifers may be relatively thick and permeable. A thick and relatively impermeable formation strata may be located over deep saline aquifers. For example, 500 m or more of shale may be located above the deep saline aquifer. The water in the deep saline aquifer may be unusable for agricultural or other common uses because of the high mineral content in the water. Over time, the minerals in the water may react with introduced sour gas to form precipitates in the deep saline aquifer. The deep saline aquifer used to store sour gas may be below the treatment area, at another location in the same formation, or in another formation. If the deep saline aquifer is located at another location in the same formation or in another formation, the sour gas may be transported to the deep saline aquifer by pipeline.
In some embodiments, injection wells used to inject sour gas may be vertical, slanted, and/or directionally steered wells with a significant horizontal or near horizontal portion. The horizontal or near horizontal portion of the injection well may be located near or at the bottom of the deep saline aquifer.
The separated sour gas may be transported to formation 2110 via conduit 2118 (for example, a pipeline). Formation 2110 may include aquifer 2112 (for example, a deep saline aquifer) and barrier portion 2114 (for example, shale). The sour gas may be injected into deep saline aquifer 2112 through injection well 2116. Injection well 2116 may have vertical portion 2122 and horizontal portion 2124. Horizontal portion 2124 may be near or at the bottom of deep saline aquifer 2112. The sour gas may be less dense than formation fluid in the deep saline aquifer. The sour gas may diffuse upwards in the aquifer towards barrier layer 2114. Horizontal portion 2124 may allow injection of the sour gas in a large portion of deep saline aquifer 2112. Openings in horizontal portion 2124 may be critical flow orifices so that fluid is introduced substantially equally along the length of the horizontal portion.
Cement 2120 may be used to seal conduit 2118 in formation. Cement 2120 used in injection wellbores to form seals at the surface and/or at an interface of deep saline aquifer with barrier layer 2114 may be selected so that the cement does not degrade due to the temperature, pressure and chemical environment due to exposure to sour gas.
The deep saline aquifer or aquifers used to store sour gas may be at sufficient depth such that the carbon dioxide in the sour gas is introduced in the formation in a supercritical state. Supercritical carbon dioxide injection may maximize the density of the fluid introduced into the formation. The depths of outlets of injection wells used to introduce acidic gases in the formation may be 900 m or more below the surface.
Injection of sour gas into a non-producing formation and/or using sour gas as flooding agents are described in U.S. Pat. Nos. 7,128,150 to Thomas et al.; RE39,244 to Eaton; RE39,077 to Eaton; 6,755,251 to Thomas et al.; 6,283,230 to Peters, all of which are incorporated by reference as if fully set forth herein.
During production of formation fluids from a subsurface formation, acidic gases may react with water in the formation and produce acids. For example, carbonic acid may be produced from the reaction of carbon dioxide with water during heating of the formation. Portions of wells made of certain materials, such as carbon steel, may start to deteriorate or corrode in the presence of the produced acids. To inhibit corrosion due to produced acids (for example, carbonic acid), fluids and/or polymers (for example, corrosion inhibitors, foaming agents, surfactants, basic fluids, hydrocarbons, high density polyethylene, or mixtures thereof) may be introduced in the wellbore to neutralize and/or dissolve the acids.
In some embodiments, hydrogen sulfide and/or carbon dioxide are separated from the produced gases and introduced into one or more wellbores in a subsurface formation. Water present in the gas introduced into the formation may interact with hydrogen sulfide to form a sulfide layer on metal surfaces of the injection well. Formation of the sulfide layer may inhibit further corrosion of the metal surfaces of the injection well by carbonic acid and/or other acids. The formation of the sulfide layer may allow for the use of carbon steel or other relatively inexpensive alloys during the introduction of sour gas into subsurface formations.
In certain embodiments, a temperature measurement tool assesses the active impedance of an energized heater. The temperature measurement tool may utilize the frequency domain analysis algorithm associated with Partial Discharge measurement technology (PD) coupled with timed domain reflectometer measurement technology (TDR). A set of frequency domain analysis tools may be applied to a TDR signature. This process may provide unique information in the analysis of the energized heater such as, but not limited to, an impedance log of the entire length of the heater per unit length. The temperature measurement tool may provide certain advantages for assessing the temperature of a downhole heater.
In certain embodiments, the temperature measurement tool assesses the impedance per unit length and gives a profile on the entire length of the heated section of the heater. The impedance profile may be used in association with laboratory data for the heater (such as temperature and resistance profiles for heaters measured at various loads and frequencies) to assess the temperature per unit length of the heated section. The impedance profile may also be used to assess various computer models for heaters that are used in association with the reservoir simulations.
In certain embodiments, the temperature measurement tool assesses an accurate impedance profile of a heater in a specific formation after a number of heater wells have been installed and energized in the specific formation. The accurate impedance profile may assess the actual reactive and real power consumption for each heater that is used similarly. This information may be used to properly size surface electrical distribution equipment and/or eliminate any extra capacity designed to accommodate any anticipated heater impedance turndown ratio or any unknown power factor or reactive power consumption for the heaters.
In certain embodiments, the temperature measurement tool is used to troubleshoot malfunctioning heaters and assess the impedance profile of the length of the heated section. The impedance profile may be able to accurately predict the location of a faulted section and its relative impedance to ground. This information may be used to accurately assess the appropriate reduction in surface voltage to allow the heater to continue to operate in a limited capacity. This method may be more preferable than abandoning the heater in the formation.
In certain embodiments, frequency domain PD testing offers an improved set of PD characterization tools. A basic set of frequency domain PD testing tools are described in “The Case for Frequency Domain PD Testing In The Context Of Distribution Cable”, Steven Boggs, Electrical Insulation Magazine, IEEE, Vol. 19, Issue 4, July-August 2003, pages 13-19, which is incorporated by reference as if fully set forth herein. Frequency domain PD detection sensitivity under field conditions may be one to two orders of magnitude greater than for time domain testing as a result of there not being a need to trigger on the first PD pulse above the broadband noise, and the filtering effect of the cable between the PD detection site and the terminations. As a result of this greatly increased sensitivity and the set of characterization tools, frequency domain PD testing has been developed into a highly sensitive and reliable tool for characterizing the condition of distribution cable during normal operation while the cable is energized, the sensitivity and accuracy of which have been confirmed through independent testing.
In some embodiments, a method of treating formation that has previously undergone an in situ heat treatment process includes providing a recovery fluid to the formation. The recovery fluid may include, but is not limited to, water, steam, air, oxygen, carbon dioxide, methane and/or other non-condensable hydrocarbon gases, and/or mixtures thereof. Heat from one or more heat sources may provide heat to a section of the formation. In some embodiments, contact of formation fluid with the recovery fluid may generate heat through oxidation of the formation fluid and/or solid hydrocarbons in the formation (for example, coke). The formation may be heated or allowed to heat to temperatures ranging from about 200° C. to about 1200° C., or from about 300° C. to about 1000° C., or from about 500° C. to about 800° C. Heating of the formation in the presence of the recovery fluid may reduce coke in the formation and produce gas. Once the recovery process has been completed, one or more heated portions of the formation may be used an in situ reactor and/or reaction zone to treat formation fluid, and/or hydrocarbons from surface facilities. Using one or more heated portions of the formation to treat such hydrocarbons may reduce or eliminate the need for surface facilities that treat such fluids (for example, coking units and/or delayed coking units).
A catalyst system may be introduced to the heated portion of the formation. In some embodiments, the portion of the formation is heated after and/or during introduction of the catalyst system. The catalyst system may be provided to the formation by injection of the catalyst system into an injection well and/or a production well in the section of the formation to be treated. In some embodiments, the catalyst system may be positioned in a well bore proximate the section of the formation to be treated.
The catalyst system may be provided to the formation with a carrier fluid. The carrier fluid may include, but is not limited, to hydrocarbons, water, steam, in situ heat treatment process gas, hydrogen, or mixtures thereof. In some embodiments, the catalyst system is slurried with the carrier fluid and/or another fluid and the slurry is introduced to the heated portion of the formation. In some embodiments, carrier fluid is a liquid and the formation may have sufficient heat to vaporize at least a portion of the carrier fluid. Vaporization of the carrier fluid may leave at least a portion of the catalyst system in the formation and/or in a well bore.
The catalyst system may include one or more catalysts. The catalysts may be supported or unsupported catalysts. Catalysts include, but are not limited to, alkali metal carbonates, alkali metal hydroxides, alkali metal hydrides, alkali metal amides, alkali metal sulfides, alkali metal acetates, alkali metal oxalates, alkali metal formates, alkali metal pyruvates, alkaline-earth metal carbonates, alkaline-earth metal hydroxides, alkaline-earth metal hydrides, alkaline-earth metal amides, alkaline-earth metal sulfides, alkaline-earth metal acetates, alkaline-earth metal oxalates, alkaline-earth metal formates, alkaline-earth metal pyruvates, or commercially available fluid catalytic cracking catalysts, dolomite, any catalyst that promotes formation of aromatic hydrocarbons, or mixtures thereof.
Hydrocarbons may be introduced into the heated portion of the formation. In some embodiments, the catalyst system is slurried with a portion of the hydrocarbons and the slurry is introduced to the heated portion of the formation. The introduced hydrocarbons may be hydrocarbons in formation fluid from an adjacent portion of the formation, condensable hydrocarbons that have been previously produced or created in surface facilities that would need to be further treated to produce desirable products. Such hydrocarbons may be introduced into the formation through one or more injection wells. Such hydrocarbons may include residue, asphaltenes, bitumen or other types of hydrocarbons. The hydrocarbons may contact the catalyst system to produce desirable products (for example, visbroken hydrocarbons and/or cracked hydrocarbons). The desirable products may be removed from the formation.
In some embodiments, the desirable products may include aromatics. The aromatics may solubilize a portion of the heavy hydrocarbons in the formation. The mixture of desirable products and heavy hydrocarbons may be produced from the formation. In some embodiments, the mixture of hydrocarbons and formation fluid may drain to a bottom portion of a layer and solubilize additional hydrocarbons at the bottom of the layer. The resulting mixture may be produced from production wells positioned at the bottom of the layer.
Heating the formation in the presence of the hydrocarbons may mobilize formation fluids in the heated first portion to allow the formation fluid to contact the catalyst system. In some embodiments, heating the first portion may increase permeability of the formation and allow formation fluid (for example, bitumen) from a second portion of the formation to flow into the heated first portion and contact the catalyst system. In some embodiments, the fluids may be driven to the heated portion of the formation using a drive fluid (for example, carbon dioxide and/or steam).
In some embodiments, a portion of the formation may be heated to a temperature to mobilized formation fluids (for example, temperatures of at least 200° C.). At least a portion of the mobilized fluids may be produced form the formation. The catalyst system may be introduced after a portion of the mobilized fluids have been removed. The catalyst system may be introduced in a carrier fluid and/or as a slurry. Contact of the catalyst system with at least a portion of the mobilized fluids may produce hydrocarbons having a lower API gravity than the mobilized fluids.
The fluid mixture produced from contact of hydrocarbons, formation fluid and/or mobilized fluids with the catalyst system may be produced from the formation. In certain embodiments, the fluid mixture may be produced through a production well. The liquid hydrocarbon portion of the fluid mixture may have an API gravity between 10° and 25°, between 12° and 23° or between 15° and 20°. In some embodiments, the produce mixture has at most 0.25 grams of aromatics per gram of total hydrocarbons. In some embodiments, the produced mixture includes some of the catalysts and/or used catalysts.
During contacting, impurities (for example, coke, nitrogen containing compounds, sulfur containing compounds, and/or metals such as nickel and/or vanadium) may form on the catalyst. Removal of the impurities on the catalyst in situ may enhance catalyst life. In situ removal of the impurities may be performed through combustion of the catalyst. In some embodiments, an oxidant (for example, air, oxygen, and/or synthesis gas generating fluid) may be introduced into the formation and the formation heated to a temperature sufficient to allow combustion of impurities on the catalyst to occur.
Contact of the hydrocarbons with catalyst system may produce coke. The amount of coke may be reduced by introduction of an oxidant (for example, air and/or synthesis gas generating fluid). Oxidation of the coke may produce gases. In some embodiments, the formation may be heated to initiate oxidation of the coke. The produced gases may be produced from the formation through one or more production wells.
Additional catalysts may be introduced into the formation during the contacting process, after a portion of the coke has been removed from the existing catalyst, and/or after reduction of coke in the formation to continue the treatment process.
Non-restrictive examples are set forth below.
Temperature Limited Heater Experimental Data
δ=R1−R1×(1−(1/RAC/RDC))1/2; (EQN. 9)
where δ is the skin depth, R1 is the radius of the cylinder, RAC is the AC resistance, and RDC is the DC resistance. In
A 6 foot temperature limited heater element was placed in a 6 foot 347H stainless steel canister. The heater element was connected to the canister in a series configuration. The heater element and canister were placed in an oven. The oven was used to raise the temperature of the heater element and the canister. At varying temperatures, a series of electrical currents were passed through the heater element and returned through the canister. The resistance of the heater element and the power factor of the heater element were determined from measurements during passing of the electrical currents.
Data 1122 depicts electrical resistance versus temperature for 300 A at 60 Hz AC applied current. Data 1124 depicts resistance versus temperature for 400 A at 60 Hz AC applied current. Data 1126 depicts resistance versus temperature for 500 A at 60 Hz AC applied current. Curve 1128 depicts resistance versus temperature for 10 A DC applied current. The resistance versus temperature data indicates that the AC resistance of the temperature limited heater linearly increased up to a temperature near the Curie temperature of the ferromagnetic conductor. Near the Curie temperature, the AC resistance decreased rapidly until the AC resistance equaled the DC resistance above the Curie temperature. The linear dependence of the AC resistance below the Curie temperature at least partially reflects the linear dependence of the AC resistance of 347H at these temperatures. Thus, the linear dependence of the AC resistance below the Curie temperature indicates that the majority of the current is flowing through the 347H support member at these temperatures.
Data 1130 depicts resistance versus temperature for 100 A at 60 Hz AC applied current. Data 1132 depicts resistance versus temperature for 400 A at 60 Hz AC applied current. Curve 1134 depicts resistance versus temperature for 10 A DC. The AC resistance of this temperature limited heater turned down at a higher temperature than the previous temperature limited heater. This was due to the added cobalt increasing the Curie temperature of the ferromagnetic conductor. The AC resistance was substantially the same as the AC resistance of a tube of 347H steel having the dimensions of the support member. This indicates that the majority of the current is flowing through the 347H support member at these temperatures. The resistance curves in
From the data in the experiments for the temperature limited heater with the copper core, the iron-cobalt ferromagnetic conductor, and the 347H stainless steel support member, the turndown ratio (y-axis) was calculated as a function of the maximum power (W/m) delivered by the temperature limited heater. The results of these calculations are depicted in
A theoretical model has been used to predict the experimental results. The theoretical model is based on an analytical solution for the AC resistance of a composite conductor. The composite conductor has a thin layer of ferromagnetic material, with a relative magnetic permeability μ2/μ0>>1, sandwiched between two non-ferromagnetic materials, whose relative magnetic permeabilities, μ1/μ0 and μ3/μ0, are close to unity and within which skin effects are negligible. An assumption in the model is that the ferromagnetic material is treated as linear. In addition, the way in which the relative magnetic permeability, μ2/μ0, is extracted from magnetic data for use in the model is far from rigorous.
Magnetic data was obtained for carbon steel as a ferromagnetic material. B versus H curves, and hence relative permeabilities, were obtained from the magnetic data at various temperatures up to 1100° F. and magnetic fields up to 2000e (oersteds). A correlation was found that fitted the data well through the maximum permeability and beyond.
For the dimensions and materials of the copper/carbon steel/347H heater element in the experiments above, theoretical calculations were carried out to calculate magnetic field at the outer surface of the carbon steel as a function of skin depth. Results of the theoretical calculations were presented on the same plot as skin depth versus magnetic field from the correlations applied to the magnetic data from
The skin depths obtained from the intersections of the same temperature curves in
One feature of the theoretical model describing the flow of alternating current in the three-part temperature limited heater is that the AC resistance does not fall off monotonically with increasing skin depth.
and the effect of this wavelength on the boundary conditions at the copper/carbon steel and carbon steel/347H interface may be behind the structure in
Temperature Limited Heater Simulations
A numerical simulation (FLUENT available from Fluent USA, Lebanon, N.H., U.S.A.) was used to compare operation of temperature limited heaters with three turndown ratios. The simulation was done for heaters in an oil shale formation (Green River oil shale). Simulation conditions were:
At a turndown ratio of 4:1, the Curie temperature was not exceeded even after 678 days. The center conductor temperature never exceeded the Curie temperature for the turndown ratio of 4:1. The center conductor showed a temperature profile for the 4:1 turndown ratio that was somewhat flatter than the temperature profile for the 3:1 turndown ratio. These simulations show that the heater temperature stays at or below the Curie temperature for a longer time at higher turndown ratios. For this oil shale richness profile, a turndown ratio of at least 3:1 may be desirable.
Simulations have been performed to compare the use of temperature limited heaters and non-temperature limited heaters in an oil shale formation. Simulation data was produced for conductor-in-conduit heaters placed in 16.5 cm (6.5 inch) diameter wellbores with 12.2 m (40 feet) spacing between heaters using a formation simulator (for example, STARS) and a near wellbore simulator (for example, ABAQUS from ABAQUS, Inc., Providence, R.I., U.S.A.). Standard conductor-in-conduit heaters included 304 stainless steel conductors and conduits. Temperature limited conductor-in-conduit heaters included a metal with a Curie temperature of 760° C. for conductors and conduits. Results from the simulations are depicted in
High Voltage Insulated Conductors
Simulations (using STARS) were carried out to simulate heating a formation using the heater embodiments shown in
For the simulation, the insulated conductor heaters were placed in a conduit (for example, conduit 536 in
The simulation was used to simulate heating of 2000 feet of formation depth (target zone) below an overburden of 1225 feet. The voltage provided to the heaters was a constant voltage of 4160 V. The formation properties used were for a typical tar sands formation in the Peace River field in Alberta, Canada. The heater spacing was 40 feet.
Plot 2148 depicts average formation temperature using the heater with the designed heater output of 220 W/ft (0.1016″ core diameters). Plot 2146 depicts average formation temperature using the heater with the designed heater output of 250 W/ft (0.1084″ core diameters). Plot 2144 depicts average formation temperature using the heater with the designed heater output of 280 W/ft (0.115″ core diameters). Plot 2150 depicts the target temperature for the formation of 527° F. As shown by plots 2144, 2146, and 2148, the average formation temperatures increased relatively linearly over time. In addition, time to reach the target formation temperature decreased with the higher powered heaters. For the 220 W/ft heater, the time to reach the target formation temperature was about 1322 days. For the 250 W/ft heater, the time to reach the target formation temperature was about 1145 days. For the 280 W/ft heater, the time to reach the target formation temperature was about 1055 days. The simulation shows that heater embodiments shown in
Phase Transformation and Curie Temperature Experimental Calculations
Calculations for the Curie temperature (Tc) and the phase transformation behavior were done for various mixtures of cobalt, carbon, manganese, silicon, vanadium, and titanium using computational thermodynamic software (ThermoCalc is obtained from Thermo-Calc Software, Inc., (McMurray, Pa., U.S.A) and JMatPro is obtained from Sente Software, Ltd., (Guildford, United Kingdom)) to predict the effect of additional elements on Curie Temperature for selected compositions, the temperature (A1) at which ferrite transforms to paramagnetic austenite, and the phases present at those temperatures. An equilibrium calculation temperature of 700° C. was used in all calculations to determine the Curie temperature of ferrite. As shown in TABLE 4, as the weight percentage of cobalt in the composition increased, Tc increased and A1 decreased; however, Tc remained above A1. An increase in the A1 temperature may be predicted upon sufficient addition of carbide formers vanadium, titanium, niobium, tantalum, and tungsten. For example, about 0.5% by weight of carbide formers may be used in an alloy that includes about 0.1% by weight of carbon. Addition of carbide formers allows replacement of the Fe3C carbide phase with a MC carbide phase. From the calculations, excess amounts of vanadium appeared to not have an impact on Tc, while excess amounts of other carbide formers reduced the Tc.
Several iron-cobalt alloys were prepared and their compositions are given in TABLE 5. These cast alloys were processed into rod and wire, and the measured and calculated Tc for the rods are listed. Averages of cooling and hearing Tc measurements were used since no irreversible hysteresis effect was observed during heating and cooling. As shown in TABLE 5, the agreement between calculated Tc and the measured Tc was acceptable.
The measured Tc were performed by a torus technique in which a torus was wound with the sample material. A thermocouple was attached midway along the length.
Calculations for the Curie temperature and the phase transformation behavior were done for various mixtures of cobalt, carbon, manganese, silicon, vanadium, chromium, and titanium using the computational thermodynamic software (ThermoCalc and JMatPro) to predict the effect of additional elements on Curie Temperature (Tc) for selected compositions and the temperature (A1) at which ferrite transforms to paramagnetic austenite. An equilibrium calculation temperature of 700° C. was used in all calculations. As shown in TABLE 6, as the weight percentage of cobalt in the composition increased, Tc increased and A1 decreased. As shown in TABLE 6, addition of vanadium and/or titanium increased A1. The addition of vanadium may allow increased amounts of chromium to be used in Curie heaters.
Several iron-chromium alloys were prepared and their compositions are given in TABLE 7. These cast alloys were processed into rods and wire, and the calculated and measured Tc using a torus technique is listed, along with calorimetry measurements.
Modeling of Alloy Phase Behavior
Modeling of phase behavior for different improved alloy compositions to determine compositions that contain increased amounts of phases that contribute positively to physical properties was performed. Compositions such as Cu, Z, M(C,N), M2(C,N), and M23C6, may minimize the amount of phases that are embrittling phases such as G, sigma, laves, and chi. There may be other reasons to include certain components. For example, silicon is typically included in stainless steel alloys to improve processing properties, and nickel and chromium are typically included in the alloys to impart corrosion resistance. When two components may be included to accomplish the same result, then the less expensive component may be beneficially included. For example, to the extent manganese may be substituted for nickel without sacrificing performance, such a substitution may reduce the cost of the alloy at current component prices.
The effect of total phase content of the alloys similar to those described above has been found to be approximated by the equation:
σr=1.0235(TPC)+5.5603. (EQN. 10)
Where σr is the creep rupture strength for one thousand hours at 800° C. in kilo-pound per square inch (ksi) and TPC is the total phase content calculated for the composition. This estimate was further improved by only including in the TPC term the amount of Cu phase, Z phase, M(C,N) phase, M2(C,N) phase, and M23C6 phase (the “desirable phases”), and calculating the constants on this basis. Another improvement to this estimate may be to use only the difference between the desirable phases present at the annealing temperature and at 800° C. Thus, the components that do not go into solution in the annealing process were not considered because they do not add significantly to the strength of the alloys at elevated temperatures. For example, the difference between the amount of Cu phase, Z phase, M(C,N) phase, M2(C,N) phase, and M23C6 phase present based on equilibrium calculations at annealing temperatures less the amount calculated to be present at 800° C. may be 1% by weight of the alloy, or it could be 1.5% by weight of the alloy or 2% by weight of the alloy, to result in an alloy with good high temperature strength. Further, the annealing temperature may be 1200° C., or it may be 1250° C., or it may be 1300° C.
The improved alloys may be further understood by modeling the addition, or reduction, of different metals to determine the effect of changing amounts of that metal on the phase content of the alloy. For example, with a starting composition by weight of: 20% chromium, 3% copper, 4% manganese, 0.3% molybdenum, 0.8% niobium, 12.5% nickel, 0.5% silicon, 1% tungsten, 0.1% carbon and 0.25% elemental nitrogen, modeling with varying amounts of chromium results in included phases of M23C6, M(C,N), M2(C,N), Z, Cu, chi, laves, G, and sigma at 800° C., according to
Alloy Examples
Alloys A through N were prepared according to TABLE 8. Measured compositions are included in the TABLE 8 when such measurements are available. The total phase content of the alloys is calculated for the listed composition.
aCalculated using actual composition;
bNonconsumable-arc melted;
cRemelted by element compensation;
dContains 1.7% sigma phase and 1.55% laves phase;
eInduction melted;
fContains 3.9% sigma phase and 1.7% chi phase;
gIncludes 1.7% sigma and 1.55% laves phases.
Hot Working with Niobium Example
To determine the capability for alloys to be hot worked, samples of alloys C, D, E, F, K, L, and M in TABLE 8 were prepared by arc-melting one pound samples into ingots of 25.4 millimeter×25.4 millimeter×101.6 millimeter (1 inch×1 inch×4 inch). After cutting hot-tops and removing some shrinkage underneath, each sample was homogenized at 1200° C. for one hour, and then hot-rolled to a thickness of 12.7 millimeter (0.5 inch) at 1200° C. with intermediate heat. The samples were then cold rolled to a 6.34 millimeter (0.25 inch) thick plate and vacuum annealed at 1200° C. for one hour.
When alloy D (0% by weight niobium) was hot rolled, it cracked and the rolling to 12.7 millimeter (0.5 inch) thickness could not be accomplished. Alloy L (0.12% by weight niobium) could be hot-rolled, but developed cracks from the edge of the samples progressing toward the center of the sample, and would not be a useful material after such hot rolling. Alloy M (0.51% Nb) could be hot-rolled, without developing cracks or other problems. The other samples were processed using the above described procedure without any problems, resulting in 6.35 millimeter (0.25 inch) plates that were free of cracks. It has been found that even 0.07% by weight niobium in the alloy composition may significantly reduce the tendency of the alloy to develop cracks during hot working. An alloy having at lest 0.5% by weight niobium can be incorporated in wrought alloys to improve properties such as hot workability. Some alloys may have by weight from 0.5% o 1.2% niobium, from 0.6% to 1.0% niobium, or from 0.7% to 0.9% niobium to improve the alloy properties.
High Temperature Heat Treating Example
Samples of alloys A and B from TABLE 8 were processed by two different methods. Process A included a heat treating and an annealing step at a temperature of 1200° C. Process B included a heat treating and an annealing step at a temperature of 1250° C. With the higher heat treating and annealing temperatures, measurable improvements in yield strength and ultimate tensile strength were observed for the two alloys when processed at the higher temperature.
The process at a temperature of 1200° C. was accomplished as follows: sections of 15.24 cm (six inch) ID by 3.81 cm (1.5 inches) thick centrifugally cast pipe were homogenized at a temperature of 1200° C. for one and a half hours; a section was then hot-rolled at 1200° C. to a 25.4 cm (one inch) thickness for alloy A and a 1.91 cm (three-quarter inch) thickness for alloy B; after cooling to room temperature, the plates were annealed at 1200° C. for fifteen minutes; the plates were then cold-rolled to a thickness of 13.97 millimeter (0.55 inches). The cold-rolled plates were annealed for one hour at 1200° C. in air under an argon blanket. The annealed plates were annealed for a final time at 1250° C. for one hour in air under an argon blanket. This process is referred to herein as process A.
The process with higher heat treating and annealing temperatures varied from the above procedure by homogenization of the cast plates at a temperature of 1250° C. for three hours instead of one and a half hours; hot rolling was carried out at 1200° C. from a 38.1 millimeter (1.5 inch) thickness to a 19.05 millimeter (0.75 inch) thickness; and the resulting plate was annealed for fifteen minute at 1200° C. followed by cold-rolling to 13.97 millimeter (0.55 inch) thickness. This process is referred to herein as process B.
In
In
In
In
Both ultimate tensile strength and yield strength were greater for the alloys treated at higher temperatures as compared to 347H stainless steel. A considerable improvement over 347H can be seen for alloys A, B, G, H, I, J, and K. For example, alloys A, B, G, H, I, J, and K retained tensile properties to test temperatures of 1000° C. For an application where yield strength of 20 ksi was needed, alloys A, B, G, H, I, J, and K provide the needed yield strength for at least an additional 250° C. For a 5 ksi difference between yield and ultimate tensile strength at test temperatures, alloys A, B, G, H, I, J, and K may be used at temperatures of 950° C. and 1000° C. as opposed to only 870° C. for 347H.
Samples of Alloy B, treated by process A and by process B were subjected to stress-rupture tests and the results are tabulated in TABLE 9. It can be seen from Table 9 that process B, with a higher annealing temperature, resulted in 47% to 474% improvement in time to rupture.
High Temperature Yield after Cold Work and Aging Example
A sample of alloy B, processed by process B, was aged at 750° C. for 1000 hours after being cold worked by 2.5%, 5%, and 10%, and without cold working. After aging, each was tested for tensile strength and yield strength at 750° C. Results are tabulated in TABLE 10. It can be seen from TABLE 10 that the yield strength increased significantly as a result of cold work and high temperature aging. The ultimate tensile strength at 750° C. decreased only slightly as a result of the high temperature aging and cold working. The annealed only sample and the aged only sample were also tested at room temperature for yield strength and ultimate tensile strength. The yield strength at room temperature increased from 307 MPa to 318 MPa as a result of the aging. The ultimate tensile strength decreased from 720 MPa to 710 MPa as a result of the high temperature aging.
These characteristics may be compared to competing alloys, such as 347H, which significantly lose high temperature properties as a result of only, for example, 10% cold work. Because fabrication of tubulars and heaters useful in an in situ heat treatment process often require cold work for their fabrication, improvement of some high temperature properties, or at least lack of significant loss of high temperature properties may be a significant advantage for alloys having these characteristics. It may be particularly advantageous when these properties are improved, or at least not significantly decreased, by high temperature aging.
Creep Example
Samples of alloys were subjected to 100 MPa stress at 800° C. in a nitrogen with 0.1% oxygen test environment. Each of the samples was first annealed for one hour at 1200° C. TABLE 11 shows the time to rupture, elongation at rupture, and total phase content, where the total phase content is known.
A sample of the improved alloy B was processed and rolled into a tube. The seam welded to form a 31.75 millimeter (1.25 inch) OD pipe. The pipe was then cut and welded back together in order to test the strength of the weld. The filler metal was ERNiCrMo-3, and the weld was completed with argon shielding gas and three passes with a preheat minimum temperature of 50° C. and an interpass maximum temperature of 350° C. Creep failure was tested for the segment of welded pipe at 44.8 MPa and 900° C. A rupture time of 41 hours was measured with failure at a strain of 5.5%. This demonstrated that the weld, including the heat affected zone around the weld, was not significantly weaker than the base alloy.
Tar Sands Simulation
A STARS simulation was used to simulate heating of a tar sands formation using the heater well pattern depicted in
From the STARS simulation, the ratio of energy out (produced oil and gas energy content) versus energy in (heater input into the formation) was calculated to be about 12 to 1 after about 5 years. The total recovery percentage of oil in place was calculated to be about 60% after about 5 years. Thus, producing oil from a tar sands formation using an embodiment of the heater and production well pattern depicted in
Tar Sands Example
A STARS simulation was used in combination with experimental analysis to simulate an in situ heat treatment process of a tar sands formation. Heating conditions for the experimental analysis were determined from reservoir simulations. The experimental analysis included heating a cell of tar sands from the formation to a selected temperature and then reducing the pressure of the cell (blow down) to 100 psig. The process was repeated for several different selected temperatures. While heating the cells, formation and fluid properties of the cells were monitored while producing fluids to maintain the pressure below an optimum pressure of 12 MPa before blow down and while producing fluids after blow down (although the pressure may have reached higher pressures in some cases, the pressure was quickly adjusted and does not affect the results of the experiments).
Plot 2154 depicts barrels of oil equivalent from producing fluids and production at blow down (correlated to volume percentage of OBIP). Plot 2156 depicts barrels of oil equivalent from producing fluids (correlated to volume percentage of OBIP). Plot 2158 depicts oil production from producing fluids (correlated to volume percentage of OBIP). Plot 2160 depicts barrels of oil equivalent from production at blow down (correlated to volume percentage of OBIP). Plot 2162 depicts oil production at blow down (correlated to volume percentage of OBIP). As shown in
Pre-Heating Using Heaters for Injectivity Before Steam Drive Example
An example using heaters to preheat for the drive process depicted in
The following conditions were assumed for purposes of this example:
Electric heating for one well pattern for one year is given by:
QE=qh·t·s(BTU/pattern/year); (EQN. 11)
with QE=(200 watts/ft)[0.001 kw/watt](1 yr)[365 day/yr][24 hr/day][3413 BTU/kw·hr](330 ft)=1.9733×109 BTU/pattern/year.
Steam heating for one well pattern for one year is given by:
Qs=qs·t·hs(BTU/pattern/year); (EQN. 12)
with Qs=(500 bbls/day)(1 yr) [365 day/yr][1000 BTU/lb][350 lbs/bbl]=63.875×109 BTU/pattern/year.
Thus, electric heat divided by total heat is given by:
QE/(QE+Qs)×100=3% of the total heat. (EQN. 13)
Thus, the electrical energy is only a small fraction of the total heat injected into the formation.
The actual temperature of the region around a heater is described by an exponential integral function. The integrated form of the exponential integral function shows that about half the energy injected is nearly equal to about half of the injection well temperature. The temperature required to reduce viscosity of the heavy oil is assumed to be 500° F. The volume heated to 500° F. by an electric heater in one year is given by:
VE=πr2. (EQN. 14)
The heat balance is given by:
QE=(πrE2)(s)(ρc)(ΔT). (EQN. 15)
Thus, rE can be solved for and is found to be 10.4 ft. For an electric heater operated at 1000° F., the diameter of a cylinder heated to half that temperature for one year would be about 23 ft. Depending on the permeability profile in the injection wells, additional horizontal wells may be stacked above the one at the bottom of the formation and/or periods of electric heating may be extended. For a ten year heating period, the diameter of the region heated above 500° F. would be about 60 ft.
If all the steam were injected uniformly into the steam injectors over the 100 ft. interval for a period of one year, the equivalent volume of formation that could be heated to 500° F. would be give by:
Qs=(πrs2)(s)(ρc)(ΔT). (EQN. 16)
Solving for rs gives an rs of 107 ft. This amount of heat would be sufficient to heat about ¾ of the pattern to 500° F.
Tar Sands Oil Recovery Example
A STARS simulation was used in combination with experimental analysis to simulate an in situ heat treatment process of a tar sands formation. The experiments and simulations were used to determine oil recovery (measured by volume percentage (vol %) of oil in place (bitumen in place) versus API gravity of the produced fluid as affected by pressure in the formation. The experiments and simulations also were used to determine recovery efficiency (percentage of oil (bitumen) recovered) versus temperature at different pressures.
Nanofiltration Example
A liquid sample (500 mL, 398.68 grams) was obtained from an in situ heat treatment process. The liquid sample contained 0.0069 grams of sulfur and 0.0118 grams of nitrogen per gram of liquid sample. The final boiling point of the liquid sample was 481° C. and the liquid sample had a density of 0.8474 g/ml. The membrane separation unit used to filter the sample was a laboratory flat sheet membrane installation type P28 as obtained from CM Celfa Membrantechnik A.G. (Switzerland). A single 2-micron thick poly di-methyl siloxane membrane (GKSS Forschungszentrum GmbH, Geesthact, Germany) was used as the filtration medium. The filtration system was operated at 50° C. and a pressure difference over the membrane was 10 bar. The pressure at the permeate side was nearly atmospheric. The permeate was collected and recycled through the filtration system to simulate a continuous process. The permeate was blanketed with nitrogen to prevent contact with ambient air. The retentate was also collected for analysis. During filtration the average flux of 2 kg/m2/bar/hr did not measurably decline from an initial flux during the filtration. The filtered liquid (298.15 grams, 74.7% recovery) contained 0.007 grams of sulfur and 0.0124 grams of nitrogen per gram of filtered liquid; and the filtered liquid had a density of 0.8459 g/ml and a final boiling point of 486° C. The retentate (56.46 grams, 14.16% recovery) contained 0.0076 grams of sulfur and 0.0158 grams of nitrogen per gram of retentate; and the retentate had a density of 0.8714 g/ml and a final boiling point of 543° C.
Fouling Testing Example
The unfiltered and filtered liquid samples from the previous Example were tested for fouling behavior. Fouling behavior was determined using an Alcor thermal fouling tester. The Alcor thermal fouling tester is a miniature shell and tube heat exchanger made of 1018 steel which was grated with Norton R222 sandpaper before use. During the test the sample outlet temperature, (Tout) was monitored while the heat-exchanger temperature (Tc) was kept at a constant value. If fouling occurs and material is deposited on the tube surface, the heat resistance of the sample increases and consequently the outlet temperature decreases. Hence the decrease in outlet temperature after a given period of time is a measure of fouling severity. The temperature decrease after two hours of operation is used as fouling severity indicator. ΔT=Tout(o)−Tout(2h). Tout(o) is defined as the maximum (stable) outlet temperature obtained at the start of the test, Tout(2h) is recorded 2 hours after the first noted decrease of the outlet temperature or when the outlet temperature has been stable for at least 2 hours.
During each test, the liquid sample was continuously circulated through the heat exchanger at approximately 3 mL/min. The residence time in the heat exchanger was about 10 seconds. The operating conditions were as follows: 40 bar of pressure, Tsample was about 50° C., Tc was 350° C., test time was 4.41 hours. The ΔT for the unfiltered liquid stream sample was 15° C. The ΔT for the filtered sample was zero.
This example demonstrates that nanofiltration of a liquid stream produced from an in situ heat treatment process removes at least a portion of clogging compositions.
Olefin Production Example
An experimental pilot system was used to conduct the experiments. The pilot system included a feed supply system, a catalyst loading and transfer system, a fast fluidized riser reactor, a stripper, a product separation and collecting system, and a regenerator. The riser reactor was an adiabatic riser having an inner diameter of from 11 mm to 19 mm and a length of about 3.2 m. The riser reactor outlet was in fluid communication with the stripper that was operated at the same temperature as the riser reactor outlet flow and in a manner to provide essentially 100 percent stripping efficiency. The regenerator was a multi-stage continuous regenerator used for regenerating the spent catalyst. The spent catalyst was fed to the regenerator at a controlled rate and the regenerated catalyst was collected in a vessel. Material balances were obtained during each of the experimental runs at 30-minute intervals. Composite gas samples were analyzed by use of an on-line gas chromatograph and the liquid product samples were collected and analyzed overnight. The coke yield was measured by measuring the catalyst flow and by measuring the delta coke on the catalyst as determined by measuring the coke on the spent and regenerated catalyst samples taken for each run when the unit was operating at steady state.
A liquid stream produced from an in situ heat treatment process was fractioned to obtain a vacuum gas oil (VGO) stream having a boiling range distribution from 310° C. to 640° C. The VGO stream was contacted with a fluidized catalytic cracker E-Cat containing 10% ZSM-5 additive in the catalytic system described above. The riser reactor temperature was maintained at 593° C. (1100° F.). The product produced contained, per gram of product, 0.1402 grams of C3 olefins, 0.137 grams of C4 olefins, 0.0897 grams of C5 olefins, 0.0152 grams of iso-C5 olefins, 0.0505 grams isobutylene, 0.0159 grams of ethane, 0.0249 grams of isobutane, 0.0089 grams of n-butane, 0.0043 grams pentane, 0.0209 grams iso-pentane, 0.2728 grams of a mixture of C6 hydrocarbons and hydrocarbons having a boiling point of at most 232° C. (450° F.), 0.0881 grams of hydrocarbons having a boiling range distribution between 232° C. and 343° C. (between 450° F. and 650° F.), 0.0769 grams of hydrocarbons having a boiling range distribution between 343° C. and 399° C. (650° F. and 750° F.) and 0.0386 grams of hydrocarbons having a boiling range distribution of at least 399° C. (750° F.) and 0.0323 grams of coke.
This example demonstrates a method of producing crude product by fractionating liquid stream produced from separation of the liquid stream from the formation fluid to produce a crude product having a boiling point above 343° C.; and catalytically cracking the crude product having the boiling point above 343° C. to produce one or more additional crude products, wherein least one of the additional crude products is a second gas stream.
Production of Olefins from a Liquid Stream Example
A thermally cracked naphtha was used to simulate a liquid stream produced from an in situ heat treatment process having a boiling range distribution from 30° C. to 182° C. The naphtha contained, per gram of naphtha, 0.186 grams of naphthenes, 0.238 grams of isoparaffins, 0.328 grams of n-paraffins, 0.029 grams cyclo-olefins, 0.046 grams of iso-olefins, 0.064 grams of n-olefins and 0.109 grams of aromatics. The naphtha stream was contacted with a FCC E-Cat with 10% ZSM-5 additive in the catalytically cracking system described above to produce a crude product. The riser reactor temperature was maintained at 593° C. (1100° F.). The crude product included, per gram of crude product, 0.1308 grams ethylene, 0.0139 grams of ethane, 0.0966 grams C4-olefins, 0.0343 grams C4 iso-olefins, 0.0175 grams butane, 0.0299 grams isobutane, 0.0525 grams C5 olefins, 0.0309 grams C5 iso-olefins, 0.0442 grams pentane, 0.0384 grams iso-pentane, 0.4943 grams of a mixture of C6 hydrocarbons and hydrocarbons having a boiling point of at most 232° C. (450° F.), 0.0201 grams of hydrocarbons having a boiling range distribution between 232° C. and 343° C. (between 450° F. and 650° F.), 0.0029 grams of hydrocarbons having a boiling range distribution between 343° C. and 399° C. (650° F. and 750° F.) and 0.00128 grams of hydrocarbons having a boiling range distribution of at least 399° C. (750° F.) and 0.00128 grams of coke. The total amount of C3-C5 olefins was 0.2799 grams per gram of naphtha.
This example demonstrates a method of producing crude product by fractionating liquid stream produced from separation of the liquid stream from the formation fluid to produce a crude product having a boiling point above 343° C.; and catalytically cracking the crude product having the boiling point above 343° C. to produce one or more additional crude products, wherein least one of the additional crude products is a second gas stream.
In this patent, certain U.S. patents, U.S. patent applications, and other materials (for example, articles) have been incorporated by reference. The text of such U.S. patents, U.S. patent applications, and other materials 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, U.S. patent applications, and other materials is specifically not incorporated by reference in this patent.
Further modifications and alternative embodiments of various aspects of the invention may be apparent to those skilled in the art in view of this description. Accordingly, this description is to be construed as illustrative only and is for the purpose of teaching those skilled in the art the general manner of carrying out the invention. It is to be understood that the forms of the invention shown and described herein are to be taken as the presently preferred embodiments. Elements and materials may be substituted for those illustrated and described herein, parts and processes may be reversed, and certain features of the invention may be utilized independently, all as would be apparent to one skilled in the art after having the benefit of this description of the invention. Changes may be made in the elements described herein without departing from the spirit and scope of the invention as described in the following claims. In addition, it is to be understood that features described herein independently may, in certain embodiments, be combined.
This patent application claims priority to U.S. Provisional Patent No. 60/853,096 entitled “SYSTEMS, METHODS, AND PROCESSES FOR USE IN TREATING SUBSURFACE FORMATIONS” to Vinegar et al. filed on Oct. 20, 2006, which is incorporated by reference in its entirety, and to U.S. Provisional Patent No. 60/925,685 entitled “SYSTEMS AND PROCESSES FOR USE IN IN SITU HEAT TREATMENT PROCESSES” to Vinegar et al. filed on Apr. 20, 2007, which is incorporated by reference in its entirety.
The Government has certain rights in this invention pursuant to Agreement No. ERD-05-2516 between UT-Battelle, LLC, operating under prime contract No. DE-ACO5-00OR22725 for the US Department of Energy and Shell Exploration and Production Company. The Government has certain rights in the invention pursuant to Agreement Nos. SD 10634 and NFE 062050824 between Sandia National Laboratories (operating under Agreement DE-AC04-94AL85000Sa for the U.S. Department of Energy) and Shell Exploration and Production Company.
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