US20130269935A1

US20130269935A1 - Treating hydrocarbon formations using hybrid in situ heat treatment and steam methods

Info

Publication number: US20130269935A1
Application number: US13/644,294
Authority: US
Inventors: Renfeng Richard Cao; Namit Jaiswal; Jeroen Cornelis VINK; Weijian Mo
Original assignee: Shell Oil Co
Current assignee: Shell USA Inc
Priority date: 2011-10-07
Filing date: 2012-10-04
Publication date: 2013-10-17
Also published as: CA2791725A1

Abstract

A method for treating a tar sands formation includes providing heated fluid to a first section of the hydrocarbon layer while providing heat to a second section of a hydrocarbon layer in the formation from a plurality of heaters located in the formation. The second section is vertically displaced from the first section. Heat is allowed to transfer from the heaters and heated water to at least a portion of the formation. Fluids are allowed to gravity drain to a third section of the hydrocarbon formation. Fluids are produced from the formation through at least one production well that is located in the third section of the formation.

Description

PRIORITY CLAIM

This patent claims priority to U.S. Provisional Patent Application No. 61/544,778 to Cao et al., entitled “METHODS OF TREATING HYDROCARBON FORMATIONS USING A HYBRID IN SITU HEAT TREATMENT AND STEAM”, filed Oct. 7, 2011, which is incorporated by reference in its entirety.

RELATED PATENTS

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.; 7,121,342 to Vinegar et al.; 7,320,364 to Fairbanks; 7,527,094 to McKinzie et al.; 7,584,789 to Mo et al.; 7,533,719 to Hinson et al.; 7,562,707 to Miller; 7,841,408 to Vinegar et al.; and 8,172,335 to Burns et al.; U.S. Patent Application Publication Nos. 2009-0189617 to Burns et al.; 2010/0258265 to Karanikas et al; 2011/0247806 to Harris; 2011/0247808 to Nguyen; 2011/0247820 to Marino et al.; and 2011/0247814 to Karanikas et al.; U.S. patent application Ser. No. 13/441,166 entitled PARTIAL SOLUTION MINING OF HYDROCARBON CONTAINING LAYERS PRIOR TO IN SITU HEAT TREATMENT” to Fowler et al., filed Apr. 6, 2012; and U.S. Provisional Patent Application No. 61/620,526 entitled “TREATMENT METHODS FOR NAHCOLITIC OIL SHALE FORMATION WITH FRACTURES” to Coles et al. filed Apr. 5, 2012.

BACKGROUND

1. Field of the Invention
The present invention relates generally to methods and systems for production of hydrocarbons 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 that were previously inaccessible and/or too expensive to extract using available methods. 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 and/or increase the value of the hydrocarbon material. 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.
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 fluids into the formation. U.S. Pat. Nos. 4,084,637 to Todd; 4,926,941 to Glandt et al.; 5,046,559 to Glandt, and 5,060,726 to Glandt, all of which are incorporated herein by reference, describe methods of producing viscous materials from subterranean formations that includes passing electrical current through the subterranean formation. Steam may be injected from the injector well into the formation to produce hydrocarbons.
Oil shale formations may be heated and/or retorted in situ to increase permeability in the formation and/or to convert the kerogen to hydrocarbons having an API gravity greater than 10°. In conventional processing of oil shale formations, portions of the oil shale formation containing kerogen are generally heated to temperatures above 370° C. to form low molecular weight hydrocarbons, carbon oxides, and/or molecular hydrogen. Some processes to produce bitumen from oil shale formations include heating the oil shale to a temperature above the natural temperature of the oil shale until some of the organic components of the oil shale are converted to bitumen and/or fluidizable material.
U.S. Pat. No. 3,515,213 to Prats, which is incorporated herein by reference, describes circulation of a fluid heated at a moderate temperature from one point within the formation to another for a relatively long period of time until a significant proportion of the organic components contained in the oil shale formation are converted to oil shale derived fluidizable materials.
U.S. Pat. Nos. 7,562,707 to Miller and 7,635,024 to Karanikas, which are incorporated herein by reference, describe methods for treating a hydrocarbon containing formation that includes providing heat from a plurality of heaters to mobilize hydrocarbons in the hydrocarbon formation.
U.S. Pat. Nos. 7,798,220 to Vinegar et al.; 7,717,171 to Stegemeier; 7,841,401 to Vinegar et al.; 7,739,947 to Stegemeier et al.; 7,681,647 to Mundunuri et al.; 7,677,314 to Hsu; 7,677,310 to Vinegar et al.; and 7,673,681 to Vinegar et al., which are incorporated herein by reference, describe methods for treating hydrocarbon formations that include heating hydrocarbons layers with heaters in combination with a drive and/or oxidizing fluid.
As discussed above, there has been a significant amount of effort to produce hydrocarbons and/or bitumen from hydrocarbon containing formations. At present, however, there are still many hydrocarbon containing formations that contain bitumen that cannot be economically produced. Thus, there is a need for improved methods for heating of a hydrocarbon containing formation that contains bitumen and production of bitumen and/or liquid hydrocarbons having desired characteristics from the hydrocarbon containing formation are needed.

SUMMARY

Methods of treating a hydrocarbon formation are described herein. In some embodiments a method for treating a tar sands formation includes providing heated fluid to a first section of the hydrocarbon layer while providing heat to a second section of a hydrocarbon layer in the formation from a plurality of heaters located in the formation, wherein the second section is vertically displaced from the first section; allowing the heat to transfer from the heaters and heated water to at least a portion of the formation; allowing fluids to gravity drain to a third section of the hydrocarbon formation; and producing fluids from the formation through at least one production well that is located in the third section of the formation.
In some embodiments, a method for treating a tar sands formation includes providing heat to a hydrocarbon layer in the formation from heated fluid injected in a first section of the formation and from a plurality of heaters located in a second section the formation; producing fluids from the second section of the formation; turning off or down heaters in the second section; and producing fluids from the formation from a third section of the formation, wherein the produced fluids include visbroken hydrocarbons from the first section.
In some embodiments, a method for treating a tar sands formation includes providing heated fluid to a first section of the hydrocarbon layer while providing heat to a second section of a hydrocarbon layer in the formation from a plurality of heaters located in the formation; allowing the heat to transfer from the heaters and heated fluid to at least a portion of the formation; allowing fluids to gravity drain to a third section of the hydrocarbon formation; and producing fluids from the formation through at least one production well that is located in at least the second section and third section in the formation, the third section containing bitumen, and the second section including upgraded hydrocarbons, wherein the second section is between the first and third sections.
In some embodiments, a method for treating a tar sands formation includes providing heat to first section of a hydrocarbon containing layer from a heater positioned in a wellbore, wherein the wellbore extends through the first section and a second section of the hydrocarbon containing formation; producing at least some fluids from the formation; generating steam in the first section of the hydrocarbon formation; providing at least a portion of the steam to a portion of the wellbore in the second section; providing heat to the second section from the steam; mobilizing hydrocarbons in the second section; and producing additional fluids from the formation.
In some embodiments, a method for treating a formation includes providing heat to a first section of a hydrocarbon layer in the formation from a plurality of heaters located in the formation while providing heated fluid to a second section of the hydrocarbon layer, wherein the first portion of the layer comprises an impermeable barrier; allowing the heat to transfer from the heaters and heated fluid to one or more portions of the formation, wherein at least a portion of the heat is sufficient to create permeability in the barrier; mobilizing hydrocarbon fluids in the formation; and producing hydrocarbon fluids from 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, power supplies, or heaters described herein.
In further embodiments, additional features may be added to the specific embodiments described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

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

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

FIG. 2 depicts a perspective view of an end portion of an embodiment of an insulated conductor.

FIG. 3 depicts an embodiment of three insulated conductors in an opening in a subsurface formation coupled in a wye configuration.

FIG. 4 depicts an embodiment of three insulated conductors that are removable from an opening in the formation.

FIGS. 5A and 5B depict cross-sectional representations of an embodiment of an insulated conductor heater with the temperature limited heater as the heating member.

FIG. 6 depicts a schematic representation of an embodiment of a heat transfer fluid circulation system for heating a portion of a formation.

FIG. 7 depicts a side view representation of an embodiment of treating hydrocarbon formation using an in situ hybrid treatment process.

FIG. 8 depicts a side view representation of an embodiment of in situ hybrid treatment process with production of hydrocarbons from multiple sections.

FIG. 9 depicts a side view representation of a production well 206 in fluid communication with injection well 270.

FIGS. 10 and 11 depict a side view representation of an embodiment of heating a hydrocarbon containing formation containing a barrier.

FIG. 12 depicts side view representations of an embodiment of heating a hydrocarbon containing formation in stages.

While the invention is susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and may herein be described in detail. The drawings may not be to scale. It should be understood, however, that the drawings and detailed description thereto are not intended to limit the invention to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the present invention as defined by the appended claims.

DETAILED DESCRIPTION

The following description generally relates to systems and methods for treating hydrocarbons in the formations. Such formations may be treated to yield hydrocarbon products, hydrogen, and other products.
“API gravity” refers to API gravity at 15.5° C. (60° F.). API gravity is as determined by ASTM Method D6822 or ASTM Method D1298.
“ASTM” refers to American Standard Testing and Materials.
In the context of reduced heat output heating systems, apparatus, and methods, the term “automatically” means such systems, apparatus, and methods function in a certain way without the use of external control (for example, external controllers such as a controller with a temperature sensor and a feedback loop, PID controller, or predictive controller).
“Asphalt/bitumen” refers to a semi-solid, viscous material soluble in carbon disulfide. Asphalt/bitumen may be obtained from refining operations or produced from subsurface formations.
“Carbon number” refers to the number of carbon atoms in a molecule. A hydrocarbon fluid may include various hydrocarbons with different carbon numbers. The hydrocarbon fluid may be described by a carbon number distribution. Carbon numbers and/or carbon number distributions may be determined by true boiling point distribution and/or gas-liquid chromatography.
“Condensable hydrocarbons” are hydrocarbons that condense at 25° C. and one atmosphere absolute pressure. Condensable hydrocarbons may include a mixture of hydrocarbons having carbon numbers greater than 4. “Non-condensable hydrocarbons” are hydrocarbons that do not condense at 25° C. and one atmosphere absolute pressure. Non-condensable hydrocarbons may include hydrocarbons having carbon numbers less than 5.
“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.
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.
“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 hybrid 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 hybrid 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 hybrid treatment process. In some cases, the overburden and/or the underburden may be somewhat permeable.
“Formation fluids” refer to fluids present in a formation and may include pyrolyzation fluid, synthesis gas, mobilized hydrocarbons, and water (steam). Formation fluids may include hydrocarbon fluids as well as non-hydrocarbon fluids. The term “mobilized fluid” refers to fluids in a hydrocarbon containing formation that are able to flow as a result of thermal treatment of the formation. “Produced fluids” refer to fluids removed from the formation.
A “heat source” is any system for providing heat to at least a portion of a formation substantially by conductive and/or radiative heat transfer. For example, a heat source may include electrically conducting materials and/or electric heaters such as an insulated conductor, an elongated member, and/or a conductor disposed in a conduit. A heat source may also include systems that generate heat by burning a fuel external to or in a formation. The systems may be surface burners, downhole gas burners, flameless distributed combustors, and natural distributed combustors. In some embodiments, heat provided to or generated in one or more heat sources may be supplied by other sources of energy. The other sources of energy may directly heat a formation, or the energy may be applied to a transfer medium that directly or indirectly heats the formation. It is to be understood that one or more heat sources that are applying heat to a formation may use different sources of energy. Thus, for example, for a given formation some heat sources may supply heat from electrically conducting materials, electric resistance heaters, some heat sources may provide heat from combustion, and some heat sources may provide heat from one or more other energy sources (for example, chemical reactions, solar energy, wind energy, biomass, or other sources of renewable energy). A chemical reaction may include an exothermic reaction (for example, an oxidation reaction). A heat source may also include a electrically conducting material and/or a heater that provides heat to a section 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.
An “in situ hybrid treatment process” refers to a process of injecting hot fluid in a formation while heating or simultaneously heating a hydrocarbon containing formation using an in situ heat treatment process 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. An example of a hot fluid is water.
“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.
“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.
“Perforations” include openings, slits, apertures, or holes in a wall of a conduit, tubular, pipe or other flow pathway that allow flow into or out of the conduit, tubular, pipe or other flow pathway.
Pyrolysis” is the breaking of chemical bonds due to the application of heat. For example, pyrolysis may include transforming a compound into one or more other substances by heat alone. Heat may be transferred to a section of the formation to cause pyrolysis.
“Pyrolyzation fluids” or “pyrolysis products” refers to fluid produced substantially during pyrolysis of hydrocarbons. Fluid produced by pyrolysis reactions may mix with other fluids in a formation. The mixture would be considered pyrolyzation fluid or pyrolyzation product. As used herein, “pyrolysis section” refers to a volume of a formation (for example, a relatively permeable formation such as a tar sands formation) that is reacted or reacting to form a pyrolyzation fluid.
“Rich layers” in a hydrocarbon containing formation are relatively thin layers (typically about 0.2 m to about 0.5 m thick). Rich layers generally have a richness of about 0.150 L/kg or greater. Some rich layers have a richness of about 0.170 L/kg or greater, of about 0.190 L/kg or greater, or of about 0.210 L/kg or greater. Lean layers of the formation have a richness of about 0.100 L/kg or less and are generally thicker than rich layers. The richness and locations of layers are determined, for example, by coring and subsequent Fischer assay of the core, density or neutron logging, or other logging methods. Rich layers may have a lower initial thermal conductivity than other layers of the formation. Typically, rich layers have a thermal conductivity 1.5 times to 3 times lower than the thermal conductivity of lean layers. In addition, rich layers have a higher thermal expansion coefficient than lean layers of the formation.
“Subsidence” is a downward movement of a portion of a formation relative to an initial elevation of the surface.
“Superposition of heat” refers to providing heat from two or more heat sources to a selected section of a formation such that the temperature of the formation at least at one location between the heat sources is influenced by the heat sources.
“Synthesis gas” is a mixture including hydrogen and carbon monoxide. Additional components of synthesis gas may include water, carbon dioxide, nitrogen, methane, and other gases. Synthesis gas may be generated by a variety of processes and feedstocks. Synthesis gas may be used for synthesizing a wide range of compounds.
“Tar” is a viscous hydrocarbon that generally has a viscosity greater than about 10,000 centipoise at 15° C. The specific gravity of tar generally is greater than 1.000. Tar may have an API gravity less than 10°.
A “tar sands formation” is a formation in which hydrocarbons are predominantly present in the form of heavy hydrocarbons and/or tar entrained in a mineral grain framework or other host lithology (for example, sand or carbonate). Examples of tar sands formations include formations such as the Athabasca formation, the Grosmont formation, and the Peace River formation, all three in Alberta, Canada; and the Faja formation in the Orinoco belt in Venezuela.
“Temperature limited heater” generally refers to a heater that regulates heat output (for example, reduces heat output) above a specified temperature without the use of external controls such as temperature controllers, power regulators, rectifiers, or other devices. Temperature limited heaters may be AC (alternating current) or modulated (for example, “chopped”) DC (direct current) powered electrical resistance heaters.
“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.
“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).
A “u-shaped wellbore” refers to a wellbore that extends from a first opening in the formation, through at least a portion of the formation, and out through a second opening in the formation. In this context, the wellbore may be only roughly in the shape of a “v” or “u”, with the understanding that the “legs” of the “u” do not need to be parallel to each other, or perpendicular to the “bottom” of the “u” for the wellbore to be considered “u-shaped”.
“Upgrade” refers to increasing the quality of hydrocarbons. For example, upgrading heavy hydrocarbons may result in an increase in the API gravity of the heavy hydrocarbons.
“Visbreaking” refers to the untangling of molecules in fluid during heat treatment and/or to the breaking of large molecules into smaller molecules during heat treatment, which results in a reduction of the viscosity of the fluid.
“Viscosity” refers to kinematic viscosity at 40° C. unless otherwise specified. Viscosity is as determined by ASTM Method D445.
“Wax” refers to a low melting organic mixture, or a compound of high molecular weight that is a solid at lower temperatures and a liquid at higher temperatures, and when in solid form can form a barrier to water. Examples of waxes include animal waxes, vegetable waxes, mineral waxes, petroleum waxes, and synthetic waxes.
The term “wellbore” refers to a hole in a formation made by drilling or insertion of a conduit into the formation. A wellbore may have a substantially circular cross section, or another cross-sectional shape. As used herein, the terms “well” and “opening,” when referring to an opening in the formation may be used interchangeably with the term “wellbore.”
A formation may be treated in various ways to produce many different products. Different stages or processes may be used to treat the formation during an in situ heat treatment process. In some embodiments, one or more sections of the formation are solution mined to remove soluble minerals from the sections. Solution mining minerals may be performed before, during, and/or after the in situ heat treatment process. In some embodiments, the average temperature of one or more sections being solution mined may be maintained below about 120° C.
In some embodiments, one or more sections of the formation are heated to remove water from the sections and/or to remove methane and other volatile hydrocarbons from the sections. In some embodiments, the average temperature may be raised from ambient temperature to temperatures below about 220° C. during removal of water and volatile hydrocarbons.
In some embodiments, one or more sections of the formation are heated to temperatures that allow for movement and/or visbreaking of hydrocarbons in the formation. In some embodiments, the average temperature of one or more sections of the formation are raised to mobilization temperatures of hydrocarbons in the sections (for example, to temperatures ranging from 100° C. to 250° C., from 120° C. to 240° C., or from 150° C. to 230° C.).
In some embodiments, one or more sections are heated to temperatures that allow for pyrolysis reactions in the formation. In some embodiments, the average temperature of one or more sections of the formation may be raised to pyrolysis temperatures of hydrocarbons in the sections (for example, temperatures ranging from 230° C. to 900° C., from 240° C. to 400° C. or from about 250° C. to 350° C.).
Heating the hydrocarbon containing formation with a plurality of heat sources may establish thermal gradients around the heat sources that raise the temperature of hydrocarbons in the formation to desired temperatures at desired heating rates. The rate of temperature increase through the mobilization temperature range and/or the pyrolysis temperature range for desired products may affect the quality and quantity of the formation fluids produced from the hydrocarbon containing formation. Slowly raising the temperature of the formation through the mobilization temperature range and/or pyrolysis temperature range may allow for the production of high quality, high API gravity hydrocarbons from the formation. Slowly raising the temperature of the formation through the mobilization temperature range and/or pyrolysis temperature range may allow for the removal of a large amount of the hydrocarbons present in the formation as hydrocarbon product.
In some in situ heat treatment embodiments, a portion of the formation is heated to a desired temperature instead of slowly raising the temperature through a temperature range. In some embodiments, the desired temperature is 300° C., 325° C., or 350° C. Other temperatures may be selected as the desired temperature.
Superposition of heat from heat sources allows the desired temperature to be relatively quickly and efficiently established in the formation. Energy input into the formation from the heat sources may be adjusted to maintain the temperature in the formation substantially at a desired temperature.
Mobilization and/or pyrolysis products may be produced from the formation through production wells. In some embodiments, the average temperature of one or more sections is raised to mobilization temperatures and hydrocarbons are produced from the production wells. The average temperature of one or more of the sections may be raised to pyrolysis temperatures after production due to mobilization decreases below a selected value. In some embodiments, the average temperature of one or more sections may be raised to pyrolysis temperatures without significant production before reaching pyrolysis temperatures. Formation fluids including pyrolysis products may be produced through the production wells.
In some embodiments, the average temperature of one or more sections may be raised to temperatures sufficient to allow synthesis gas production after mobilization and/or pyrolysis. In some embodiments, hydrocarbons may be raised to temperatures sufficient to allow synthesis gas production without significant production before reaching the temperatures sufficient to allow synthesis gas production. For example, synthesis gas may be produced in a temperature range from about 400° C. to about 1200° C., about 500° C. to about 1100° C., or about 550° C. to about 1000° C. A synthesis gas generating fluid (for example, steam and/or water) may be introduced into the sections to generate synthesis gas. Synthesis gas may be produced from production wells.
Solution mining, removal of volatile hydrocarbons and water, mobilizing hydrocarbons, pyrolyzing hydrocarbons, generating synthesis gas, and/or other processes may be performed during the in situ heat treatment process. In some embodiments, some processes may be performed after the in situ heat treatment process. Such processes may include, but are not limited to, recovering heat from treated sections, storing fluids (for example, water and/or hydrocarbons) in previously treated sections, and/or sequestering carbon dioxide in previously treated sections.
FIG. 1 depicts a schematic view of an embodiment of a portion of the in situ heat treatment system for treating the hydrocarbon containing formation. The in situ heat treatment system may include barrier wells 200. Barrier wells are used to form a barrier around a treatment area. The barrier inhibits fluid flow into and/or out of the treatment area. Barrier wells include, but are not limited to, dewatering wells, vacuum wells, capture wells, injection wells, grout wells, freeze wells, or combinations thereof. In some embodiments, barrier wells 200 are dewatering wells. Dewatering wells may remove liquid water and/or inhibit liquid water from entering a portion of the formation to be heated, or to the formation being heated. In the embodiment depicted in FIG. 1, the barrier wells 200 are shown extending only along one side of heat sources 202, but the barrier wells typically encircle all heat sources 202 used, or to be used, to heat a treatment area of the formation.
Heat sources 202 are placed in at least a portion of the formation. Heat sources 202 may include heaters such as insulated conductors, conductor-in-conduit heaters, surface burners, flameless distributed combustors, and/or natural distributed combustors. Heat sources 202 may also include other types of heaters. Heat sources 202 provide heat to at least a portion of the formation to heat hydrocarbons in the formation. Energy may be supplied to heat sources 202 through supply lines 204. Supply lines 204 may be structurally different depending on the type of heat source or heat sources used to heat the formation. Supply lines 204 for heat sources may transmit electricity for electric heaters, may transport fuel for combustors, or may transport heat exchange fluid that is circulated in the formation. In some embodiments, electricity for an in situ heat treatment process may be provided by a nuclear power plant or nuclear power plants. The use of nuclear power may allow for reduction or elimination of carbon dioxide emissions from the in situ heat treatment process.
When the formation is heated, the heat input into the formation may cause expansion of the formation and geomechanical motion. The heat sources may be turned on before, at the same time, or during a dewatering process. Computer simulations may model formation response to heating. The computer simulations may be used to develop a pattern and time sequence for activating heat sources in the formation so that geomechanical motion of the formation does not adversely affect the functionality of heat sources, production wells, and other equipment in the formation.
Heating the formation may cause an increase in permeability and/or porosity of the formation. Increases in permeability and/or porosity may result from a reduction of mass in the formation due to vaporization and removal of water, removal of hydrocarbons, and/or creation of fractures. Fluid may flow more easily in the heated portion of the formation because of the increased permeability and/or porosity of the formation. Fluid in the heated portion of the formation may move a considerable distance through the formation because of the increased permeability and/or porosity. The considerable distance may be over 1000 m depending on various factors, such as permeability of the formation, properties of the fluid, temperature of the formation, and pressure gradient allowing movement of the fluid. The ability of fluid to travel considerable distance in the formation allows production wells 206 to be spaced relatively far apart in the formation.
Production wells 206 are used to remove formation fluid from the formation. In some embodiments, production well 206 includes a heat source. The heat source in the production well may heat one or more portions of the formation at or near the production well. In some in situ heat treatment process embodiments, the amount of heat supplied to the formation from the production well per meter of the production well is less than the amount of heat applied to the formation from a heat source that heats the formation per meter of the heat source. Heat applied to the formation from the production well may increase formation permeability adjacent to the production well by vaporizing and removing liquid phase fluid adjacent to the production well and/or by increasing the permeability of the formation adjacent to the production well by formation of macro and/or micro fractures.
More than one heat source may be positioned in the production well. A heat source in a lower portion of the production well may be turned off when superposition of heat from adjacent heat sources heats the formation sufficiently to counteract benefits provided by heating the formation with the production well. In some embodiments, the heat source in an upper portion of the production well may remain on after the heat source in the lower portion of the production well is deactivated. The heat source in the upper portion of the well may inhibit condensation and reflux of formation fluid.
In some embodiments, the heat source in production well 206 allows for vapor phase removal of formation fluids from the formation. Providing heating at or through the production well may: (1) inhibit condensation and/or refluxing of production fluid when such production fluid is moving in the production well proximate the overburden, (2) increase heat input into the formation, (3) increase production rate from the production well as compared to a production well without a heat source, (4) inhibit condensation of high carbon number compounds (C₆hydrocarbons and above) in the production well, and/or (5) increase formation permeability at or proximate the production well.
Subsurface pressure in the formation may correspond to the fluid pressure generated in the formation. As temperatures in the heated portion of the formation increase, the pressure in the heated portion may increase as a result of thermal expansion of in situ fluids, increased fluid generation and vaporization of water. Controlling rate of fluid removal from the formation may allow for control of pressure in the formation. Pressure in the formation may be determined at a number of different locations, such as near or at production wells, near or at heat sources, or at monitor wells.
In some hydrocarbon containing formations, production of hydrocarbons from the formation is inhibited until at least some hydrocarbons in the formation have been mobilized and/or pyrolyzed. Formation fluid may be produced from the formation when the formation fluid is of a selected quality. In some embodiments, the selected quality includes an API gravity of at least about 20°, 30°, or 40°. Inhibiting production until at least some hydrocarbons are mobilized and/or pyrolyzed may increase conversion of heavy hydrocarbons to light hydrocarbons. Inhibiting initial production may minimize the production of heavy hydrocarbons from the formation. Production of substantial amounts of heavy hydrocarbons may require expensive equipment and/or reduce the life of production equipment.
In some hydrocarbon containing formations, hydrocarbons in the formation may be heated to mobilization and/or pyrolysis temperatures before substantial permeability has been generated in the heated portion of the formation. An initial lack of permeability may inhibit the transport of generated fluids to production wells 206. During initial heating, fluid pressure in the formation may increase proximate heat sources 202. The increased fluid pressure may be released, monitored, altered, and/or controlled through one or more heat sources 202. For example, selected heat sources 202 or separate pressure relief wells may include pressure relief valves that allow for removal of some fluid from the formation.
In some embodiments, pressure generated by expansion of mobilized fluids, pyrolysis fluids or other fluids generated in the formation may be allowed to increase because 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 minimal in situ stress. In some embodiments, the minimal in situ stress may equal to or approximate the lithostatic pressure of the hydrocarbon formation. For example, fractures may form from heat sources 202 to production wells 206 in the heated portion of the formation. The generation of fractures in the heated portion may relieve some of the pressure in the portion. Pressure in the formation may have to be maintained below a selected pressure to inhibit unwanted production, fracturing of the overburden or underburden, and/or coking of hydrocarbons in the formation.
After mobilization and/or pyrolysis temperatures are reached and production from the formation is allowed, pressure in the formation may be varied to alter and/or control a composition of produced formation fluid, to control a percentage of condensable fluid as compared to non-condensable fluid in the formation fluid, and/or to control an API gravity of formation fluid being produced. For example, decreasing pressure may result in production of a larger condensable fluid component. The condensable fluid component may contain a larger percentage of olefins.
In some in situ heat treatment process embodiments, pressure in the formation may be maintained high enough to promote production of formation fluid with an API gravity of greater than 20°. Maintaining increased pressure in the formation may inhibit formation subsidence during in situ heat treatment. Maintaining increased pressure may reduce or eliminate the need to compress formation fluids at the surface to transport the fluids in collection conduits to treatment facilities.
Maintaining increased pressure in a heated portion of the formation may surprisingly allow for production of large quantities of hydrocarbons of increased quality and of relatively low molecular weight. Pressure may be maintained so that formation fluid produced has a minimal amount of compounds above a selected carbon number. The selected carbon number may be at most 25, at most 20, at most 12, or at most 8. Some high carbon number compounds may be entrained in vapor in the formation and may be removed from the formation with the vapor. Maintaining increased pressure in the formation may inhibit entrainment of high carbon number compounds and/or multi-ring hydrocarbon compounds in the vapor. High carbon number compounds and/or multi-ring hydrocarbon compounds may remain in a liquid phase in the formation for significant time periods. The significant time periods may provide sufficient time for the compounds to pyrolyze to form lower carbon number compounds.
Generation of relatively low molecular weight hydrocarbons is believed to be due, in part, to autogenous generation and reaction of hydrogen in a portion of the hydrocarbon containing formation. For example, maintaining an increased pressure may force hydrogen generated during pyrolysis into the liquid phase within the formation. Heating the portion to a temperature in a pyrolysis temperature range may pyrolyze hydrocarbons in the formation to generate liquid phase pyrolyzation fluids. The generated liquid phase pyrolyzation fluids components may include double bonds and/or radicals. Hydrogen (H₂) in the liquid phase may reduce double bonds of the generated pyrolyzation fluids, thereby reducing a potential for polymerization or formation of long chain compounds from the generated pyrolyzation fluids. In addition, H₂may also neutralize radicals in the generated pyrolyzation fluids. H₂in 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.
An insulated conductor may be used as an electric heater element of a heater or a heat source. The insulated conductor may include an inner electrical conductor (core) surrounded by an electrical insulator and an outer electrical conductor (jacket). The electrical insulator may include mineral insulation (for example, magnesium oxide) or other electrical insulation.
In certain embodiments, the insulated conductor is placed in an opening in a hydrocarbon containing formation. In some embodiments, the insulated conductor is placed in an uncased opening in the hydrocarbon containing formation. Placing the insulated conductor in an uncased opening in the hydrocarbon containing formation may allow heat transfer from the insulated conductor to the formation by radiation as well as conduction. Using an uncased opening may facilitate retrieval of the insulated conductor from the well, if necessary.
In some embodiments, an insulated conductor is placed within a casing in the formation; may be cemented within the formation; or may be packed in an opening with sand, gravel, or other fill material. The insulated conductor may be supported on a support member positioned within the opening. The support member may be a cable, rod, or a conduit (for example, a pipe). The support member may be made of a metal, ceramic, inorganic material, or combinations thereof. Because portions of a support member may be exposed to formation fluids and heat during use, the support member may be chemically resistant and/or thermally resistant.
Ties, spot welds, and/or other types of connectors may be used to couple the insulated conductor to the support member at various locations along a length of the insulated conductor. The support member may be attached to a wellhead at an upper surface of the formation. In some embodiments, the insulated conductor has sufficient structural strength such that a support member is not needed. The insulated conductor may, in many instances, have at least some flexibility to inhibit thermal expansion damage when undergoing temperature changes.
In certain embodiments, insulated conductors are placed in wellbores without support members and/or centralizers. An insulated conductor without support members and/or centralizers may have a suitable combination of temperature and corrosion resistance, creep strength, length, thickness (diameter), and metallurgy that will inhibit failure of the insulated conductor during use.
FIG. 2 depicts a perspective view of an end portion of an embodiment of heater 212. Heater 212 may include insulated conductor 214. Insulated conductor 214 may have any desired cross-sectional shape such as, but not limited to, round (depicted in FIG. 2), triangular, ellipsoidal, rectangular, hexagonal, or irregular. In certain embodiments, insulated conductor 214 includes jacket 216, core 218, and electrical insulator 220. Core 218 may resistively heat when an electrical current passes through the core. Alternating or time-varying current and/or direct current may be used to provide power to core 218 such that the core resistively heats.
In some embodiments, electrical insulator 220 inhibits current leakage and arcing to jacket 216. Electrical insulator 220 may thermally conduct heat generated in core 218 to jacket 216. Jacket 216 may radiate or conduct heat to the formation. In certain embodiments, insulated conductor 214 is 1000 m or more in length. Longer or shorter insulated conductors may also be used to meet specific application needs. The dimensions of core 218, electrical insulator 220, and jacket 216 of insulated conductor 214 may be selected such that the insulated conductor has enough strength to be self supporting even at upper working temperature limits. Such insulated conductors may be suspended from wellheads or supports positioned near an interface between an overburden and a hydrocarbon containing formation without the need for support members extending into the hydrocarbon containing formation along with the insulated conductors.
Insulated conductor 214 may be designed to operate at power levels of up to about 1650 watts/meter or higher. In certain embodiments, insulated conductor 214 operates at a power level between about 500 watts/meter and about 1150 watts/meter when heating a formation. Insulated conductor 214 may be designed so that a maximum voltage level at a typical operating temperature does not cause substantial thermal and/or electrical breakdown of electrical insulator 220. Insulated conductor 214 may be designed such that jacket 216 does not exceed a temperature that will result in a significant reduction in corrosion resistance properties of the jacket material. In certain embodiments, insulated conductor 214 may be designed to reach temperatures within a range between about 650° C. and about 900° C. Insulated conductors having other operating ranges may be formed to meet specific operational requirements.
FIG. 2 depicts insulated conductor 214 having a single core 218. In some embodiments, insulated conductor 214 has two or more cores 218. For example, a single insulated conductor may have three cores. Core 218 may be made of metal or another electrically conductive material. The material used to form core 218 may include, but not be limited to, nichrome, copper, nickel, carbon steel, stainless steel, and combinations thereof. In certain embodiments, core 218 is chosen to have a diameter and a resistivity at operating temperatures such that its resistance, as derived from Ohm's law, makes it electrically and structurally stable for the chosen power dissipation per meter, the length of the heater, and/or the maximum voltage allowed for the core material.
In some embodiments, core 218 is made of different materials along a length of insulated conductor 214. For example, a first section of core 218 may be made of a material that has a significantly lower resistance than a second section of the core. The first section may be placed adjacent to a formation layer that does not need to be heated to as high a temperature as a second formation layer that is adjacent to the second section. The resistivity of various sections of core 218 may be adjusted by having a variable diameter and/or by having core sections made of different materials.
Electrical insulator 220 may be made of a variety of materials. Commonly used powders may include, but are not limited to, MgO, Al₂O₃, Zirconia, BeO, different chemical variations of Spinels, and combinations thereof. MgO may provide good thermal conductivity and electrical insulation properties. The desired electrical insulation properties include low leakage current and high dielectric strength. A low leakage current decreases the possibility of thermal breakdown and the high dielectric strength decreases the possibility of arcing across the insulator. Thermal breakdown can occur if the leakage current causes a progressive rise in the temperature of the insulator leading also to arcing across the insulator.
Jacket 216 may be an outer metallic layer or electrically conductive layer. Jacket 216 may be in contact with hot formation fluids. Jacket 216 may be made of material having a high resistance to corrosion at elevated temperatures. Alloys that may be used in a desired operating temperature range of jacket 216 include, but are not limited to, 304 stainless steel, 310 stainless steel, Incoloy® 800, and Inconel® 600 (Inco Alloys International, Huntington, W. Va., U.S.A.). The thickness of jacket 216 may have to be sufficient to last for three to ten years in a hot and corrosive environment. A thickness of jacket 216 may generally vary between about 1 mm and about 2.5 mm. For example, a 1.3 mm thick, 310 stainless steel outer layer may be used as jacket 216 to provide good chemical resistance to sulfidation corrosion in a heated zone of a formation for a period of over 3 years. Larger or smaller jacket thicknesses may be used to meet specific application requirements.
One or more insulated conductors may be placed within an opening in a formation to form a heat source or heat sources. Electrical current may be passed through each insulated conductor in the opening to heat the formation. Alternately, electrical current may be passed through selected insulated conductors in an opening. The unused conductors may be used as backup heaters. Insulated conductors may be electrically coupled to a power source in any convenient manner. Each end of an insulated conductor may be coupled to lead-in cables that pass through a wellhead. Such a configuration typically has a 180° bend (a “hairpin” bend) or turn located near a bottom of the heat source. An insulated conductor that includes a 180° bend or turn may not require a bottom termination, but the 180° bend or turn may be an electrical and/or structural weakness in the heater. Insulated conductors may be electrically coupled together in series, in parallel, or in series and parallel combinations. In some embodiments of heat sources, electrical current may pass into the conductor of an insulated conductor and may be returned through the jacket of the insulated conductor by connecting core 218 to jacket 216 (shown in FIG. 2) at the bottom of the heat source.
In some embodiments, three insulated conductors 214 are electrically coupled in a 3-phase wye configuration to a power supply. FIG. 3 depicts an embodiment of three insulated conductors in an opening in a subsurface formation coupled in a wye configuration. FIG. 4 depicts an embodiment of three insulated conductors 214 that are removable from opening 222 in the formation. No bottom connection may be required for three insulated conductors in a wye configuration. Alternately, all three insulated conductors of the wye configuration may be connected together near the bottom of the opening. The connection may be made directly at ends of heating sections of the insulated conductors or at ends of cold pins (less resistive sections) coupled to the heating sections at the bottom of the insulated conductors. The bottom connections may be made with insulator filled and sealed canisters or with epoxy filled canisters. The insulator may be the same composition as the insulator used as the electrical insulation.
Three insulated conductors 214 depicted in FIGS. 3 and 4 may be coupled to support member 224 using centralizers 226. Alternatively, insulated conductors 214 may be strapped directly to support member 224 using metal straps. Centralizers 226 may maintain a location and/or inhibit movement of insulated conductors 214 on support member 224. Centralizers 226 may be made of metal, ceramic, or combinations thereof. The metal may be stainless steel or any other type of metal able to withstand a corrosive and high temperature environment. In some embodiments, centralizers 226 are bowed metal strips welded to the support member at distances less than about 6 m. A ceramic used in centralizer 226 may be, but is not limited to, Al₂O₃, MgO, or another electrical insulator. Centralizers 226 may maintain a location of insulated conductors 214 on support member 224 such that movement of insulated conductors is inhibited at operating temperatures of the insulated conductors. Insulated conductors 214 may also be somewhat flexible to withstand expansion of support member 224 during heating.
Support member 224, insulated conductor 214, and centralizers 226 may be placed in opening 222 in hydrocarbon layer 228. Insulated conductors 214 may be coupled to bottom conductor junction 230 using cold pin 232. Bottom conductor junction 230 may electrically couple each insulated conductor 214 to each other. Bottom conductor junction 230 may include materials that are electrically conducting and do not melt at temperatures found in opening 222. Cold pin 232 may be an insulated conductor having lower electrical resistance than insulated conductor 214.
Lead-in conductor 234 may be coupled to wellhead 238 to provide electrical power to insulated conductor 214. Lead-in conductor 234 may be made of a relatively low electrical resistance conductor such that relatively little heat is generated from electrical current passing through the lead-in conductor. In some embodiments, the lead-in conductor is a rubber or polymer insulated stranded copper wire. In some embodiments, the lead-in conductor is a mineral insulated conductor with a copper core. Lead-in conductor 234 may couple to wellhead 238 at surface 240 through a sealing flange located between overburden 242 and surface 240. The sealing flange may inhibit fluid from escaping from opening 222 to surface 240.
In certain embodiments, lead-in conductor 234 is coupled to insulated conductor 214 using transition conductor 236. Transition conductor 236 may be a less resistive portion of insulated conductor 214. Transition conductor 236 may be referred to as “cold pin” of insulated conductor 214. Transition conductor 236 may be designed to dissipate about one-tenth to about one-fifth of the power per unit length as is dissipated in a unit length of the primary heating section of insulated conductor 214. Transition conductor 236 may typically be between about 1.5 m and about 15 m, although shorter or longer lengths may be used to accommodate specific application needs. In an embodiment, the conductor of transition conductor 236 is copper. The electrical insulator of transition conductor 236 may be the same type of electrical insulator used in the primary heating section. A jacket of transition conductor 236 may be made of corrosion resistant material.
In certain embodiments, transition conductor 236 is coupled to lead-in conductor 234 by a splice or other coupling joint. Splices may also be used to couple transition conductor 236 to insulated conductor 214. Splices may have to withstand a temperature equal to half of a target zone operating temperature. Density of electrical insulation in the splice should in many instances be high enough to withstand the required temperature and the operating voltage.
In some embodiments, as shown in FIG. 3, packing material 238 is placed between overburden casing 240 and opening 222. In some embodiments, reinforcing material 242 may secure overburden casing 240 to overburden 244. Packing material 238 may inhibit fluid from flowing from opening 222 to surface 248. Reinforcing material 242 may include, for example, Class G or Class H Portland cement mixed with silica flour for improved high temperature performance, slag or silica flour, and/or a mixture thereof. In some embodiments, reinforcing material 242 extends radially a width of from about 5 cm to about 25 cm.
As shown in FIGS. 3 and 4, support member 224 and lead-in conductor 236 may be coupled to wellhead 246 at surface 248 of the formation. Surface conductor 250 may enclose reinforcing material 248 and couple to wellhead 246. Embodiments of surface conductors may extend to depths of approximately 3 m to approximately 515 m into an opening in the formation. Alternatively, the surface conductor may extend to a depth of approximately 9 m into the formation. Electrical current may be supplied from a power source to insulated conductor 214 to generate heat due to the electrical resistance of the insulated conductor. Heat generated from three insulated conductors 214 may transfer within opening 222 to heat at least a portion of hydrocarbon layer 228.
Heat generated by insulated conductors 214 may heat at least a portion of a hydrocarbon containing formation. In some embodiments, heat is transferred to the formation substantially by radiation of the generated heat to the formation. Some heat may be transferred by conduction or convection of heat due to gases present in the opening. The opening may be an uncased opening, as shown in FIGS. 3 and 4. An uncased opening eliminates cost associated with thermally cementing the heater to the formation, costs associated with a casing, and/or costs of packing a heater within an opening. In addition, heat transfer by radiation is typically more efficient than by conduction, so the heaters may be operated at lower temperatures in an open wellbore. Conductive heat transfer during initial operation of a heat source may be enhanced by the addition of a gas in the opening. The gas may be maintained at a pressure up to about 27 bars absolute. The gas may include, but is not limited to, carbon dioxide and/or helium. An insulated conductor heater in an open wellbore may advantageously be free to expand or contract to accommodate thermal expansion and contraction. An insulated conductor heater may advantageously be removable or redeployable from an open wellbore.
In certain embodiments, an insulated conductor heater assembly is installed or removed using a spooling assembly. More than one spooling assembly may be used to install both the insulated conductor and a support member simultaneously. Alternatively, the support member may be installed using a coiled tubing unit. The heaters may be un-spooled and connected to the support as the support is inserted into the well. The electric heater and the support member may be un-spooled from the spooling assemblies. Spacers may be coupled to the support member and the heater along a length of the support member. Additional spooling assemblies may be used for additional electric heater elements.
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 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.
FIGS. 5A and 5B depict cross-sectional representations of an embodiment of the insulated conductor heater with the temperature limited heater as the heating member. Insulated conductor 214 includes core 218, ferromagnetic conductor 252, inner conductor 254, electrical insulator 220, and jacket 216. Core 218 is a copper core. Ferromagnetic conductor 252 is, for example, iron or an iron alloy.
Inner conductor 254 is a relatively thin conductive layer of non-ferromagnetic material with a higher electrical conductivity than ferromagnetic conductor 252. In certain embodiments, inner conductor 254 is copper. Inner conductor 254 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 254 is copper with 6% by weight nickel (for example, CuNi6 or LOHM™). In some embodiments, inner conductor 254 is CuNi10Fe1Mn alloy. Below the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 252, the magnetic properties of the ferromagnetic conductor confine the majority of the flow of electrical current to inner conductor 254. Thus, inner conductor 254 provides the majority of the resistive heat output of insulated conductor 214 below the Curie temperature and/or the phase transformation temperature range.
In certain embodiments, inner conductor 254 is dimensioned, along with core 218 and ferromagnetic conductor 252, so that the inner conductor provides a desired amount of heat output and a desired turndown ratio. For example, inner conductor 254 may have a cross-sectional area that is around 2 or 3 times less than the cross-sectional area of core 218. Typically, inner conductor 254 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 254, core 218 has a diameter of 0.66 cm, ferromagnetic conductor 252 has an outside diameter of 0.91 cm, inner conductor 254 has an outside diameter of 1.03 cm, electrical insulator 220 has an outside diameter of 1.53 cm, and jacket 216 has an outside diameter of 1.79 cm. In an embodiment with a CuNi₆ inner conductor 254, core 218 has a diameter of 0.66 cm, ferromagnetic conductor 252 has an outside diameter of 0.91 cm, inner conductor 254 has an outside diameter of 1.12 cm, electrical insulator 220 has an outside diameter of 1.63 cm, and jacket 216 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 220 may be magnesium oxide, aluminum oxide, silicon dioxide, beryllium oxide, boron nitride, silicon nitride, or combinations thereof. In certain embodiments, electrical insulator 220 is a compacted powder of magnesium oxide. In some embodiments, electrical insulator 220 includes beads of silicon nitride.
In certain embodiments, a small layer of material is placed between electrical insulator 220 and inner conductor 254 to inhibit copper from migrating into the electrical insulator at higher temperatures. For example, a small layer of nickel (for example, about 0.5 mm of nickel) may be placed between electrical insulator 220 and inner conductor 254.
Jacket 216 is made of a corrosion resistant material such as, but not limited to, 347 stainless steel, 347H stainless steel, 446 stainless steel, or 825 stainless steel. In some embodiments, jacket 216 provides some mechanical strength for insulated conductor 214 at or above the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 252. In certain embodiments, jacket 216 is not used to conduct electrical current.
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 temperature limited 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 temperature limited heater is above about 250° C. to produce lighter hydrocarbon products. In some embodiments, 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 (at most about 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 or other fluid 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 over standard cold production with 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. 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 some in situ heat treatment process embodiments, a circulation system is used to heat the formation. Using the circulation system for in situ heat treatment of a hydrocarbon containing formation may reduce energy costs for treating the formation, reduce emissions from the treatment process, and/or facilitate heating system installation. In certain embodiments, the circulation system is a closed loop circulation system. FIG. 6 depicts a schematic representation of a system for heating a formation using a circulation system. The system may be used to heat hydrocarbons that are relatively deep in the ground and that are in formations that are relatively large in extent. In some embodiments, the hydrocarbons may be 100 m, 200 m, 300 m or more below the surface. The circulation system may also be used to heat hydrocarbons that are shallower in the ground. The hydrocarbons may be in formations that extend lengthwise up to 1000 m, 3000 m, 5000 m, or more. The heaters of the circulation system may be positioned relative to adjacent heaters such that superposition of heat between heaters of the circulation system allows the temperature of the formation to be raised at least above the boiling point of aqueous formation fluid in the formation.
In some embodiments, heaters 212 are formed in the formation by drilling a first wellbore and then drilling a second wellbore that connects with the first wellbore. Piping may be positioned in the u-shaped wellbore to form u-shaped heater 212. Heaters 212 are connected to heat transfer fluid circulation system 256 by piping. In some embodiments, the heaters are positioned in triangular patterns. In some embodiments, other regular or irregular patterns are used. Production wells and/or injection wells may also be located in the formation. The production wells and/or the injection wells may have long, substantially horizontal sections similar to the heating portions of heaters 212, or the production wells and/or injection wells may be otherwise oriented (for example, the wells may be vertically oriented wells, or wells that include one or more slanted portions).
As depicted in FIG. 6, heat transfer fluid circulation system 256 may include heat supply 258, first heat exchanger 260, second heat exchanger 262, and fluid movers 264. Heat supply 258 heats the heat transfer fluid to a high temperature. Heat supply 258 may be a furnace, solar collector, chemical reactor, nuclear reactor, fuel cell, and/or other high temperature source able to supply heat to the heat transfer fluid. If the heat transfer fluid is a gas, fluid movers 264 may be compressors. If the heat transfer fluid is a liquid, fluid movers 264 may be pumps.
After exiting formation 266, the heat transfer fluid passes through first heat exchanger 260 and second heat exchanger 262 to fluid movers 264. First heat exchanger 260 transfers heat between heat transfer fluid exiting formation 266 and heat transfer fluid exiting fluid movers 264 to raise the temperature of the heat transfer fluid that enters heat supply 258 and reduce the temperature of the fluid exiting formation 266. Second heat exchanger 262 further reduces the temperature of the heat transfer fluid. In some embodiments, second heat exchanger 262 includes or is a storage tank for the heat transfer fluid.
Heat transfer fluid passes from second heat exchanger 262 to fluid movers 264. Fluid movers 264 may be located before heat supply 258 so that the fluid movers do not have to operate at a high temperature.
In some embodiments, the heat transfer fluid is a high temperature hydrocarbon oil such as DowTherm™ A available from Dow® Chemical Company (Midland, Mich., USA). In some embodiments, the heat transfer fluid is a molten salt and/or molten metal. U.S. Published Patent Application 2008-0078551 to DeVault et al., which is incorporated by reference as if fully set forth herein, describes a system for placement in a wellbore, the system including a heater in a conduit with a liquid metal between the heater and the conduit for heating subterranean earth. Heat transfer fluid may be or include molten salts such as solar salt, salts presented in Table Error! Reference source not found., or other salts. The molten salts may be infrared transparent to aid in heat transfer from the insulated conductor to the canister. In some embodiments, solar salt includes sodium nitrate and potassium nitrate (for example, about 60% by weight sodium nitrate and about 40% by weight potassium nitrate). Solar salt melts at about 220° C. and is chemically stable up to temperatures of about 593° C. Other salts that may be used include, but are not limited to LiNO₃(melt temperature (T_m) of 264° C. and a decomposition temperature of about 600° C.) and eutectic mixtures such as 53% by weight KNO₃, 40% by weight NaNO₃and 7% by weight NaNO₂(T_mof about 142° C. and an upper working temperature of over 500° C.); 45.5% by weight KNO₃and 54.5% by weight NaNO₂(T_mof about 142-145° C. and an upper working temperature of over 500° C.); or 50% by weight NaCl and 50% by weight SrCl₂(T_mof about 19° C. and an upper working temperature of over 1200° C.).

TABLE 1

Material	T_m(° C.)	T_b(° C.)

Zn	420	907
CdBr₂	568	863
CdI₂	388	744
CuBr₂	498	900
PbBr₂	371	892
TlBr	460	819
TlF	326	826
ThI₄	566	837
SnF₂	215	850
SnI₂	320	714
ZnCl ₂	290	732

Heat supply 258 is a furnace that heats the heat transfer fluid to a temperature in a range from about 200° C. to about 920° C., from about 300° C. to about 870° C., or from about 500° C. to about 850° C. In an embodiment, heat supply 258 heats the heat transfer fluid to a temperature of about 820° C. The heat transfer fluid flows from heat supply 258 to heaters 212. Heat transfers from heaters 212 to hydrocarbon layer 268 adjacent to the heaters. The temperature of the heat transfer fluid exiting formation 266 may be in a range from about 350° C. to about 580° C., from about 400° C. to about 530° C., or from about 450° C. to about 500° C. In some embodiments, the temperature of the heat transfer fluid exiting formation 266 is about 480° C. The metallurgy of the piping used to form heat transfer fluid circulation system 256 may be varied to significantly reduce costs of the piping. High temperature steel may be used from heat supply 258 to a point where the temperature is sufficiently low so that less expensive steel can be used from that point to first heat exchanger 260. Several different steel grades may be used to form the piping of heat transfer fluid circulation system 256.
Hydrocarbon containing formations (for example, oil shale formations and/or tar sands formations) may contain significant amounts of bitumen entrained in the mineral matrix of the formation and/or significant amounts of bitumen in shallow layers of the formation. Heating hydrocarbon formations containing entrained bitumen to high temperatures may produce non-condensable hydrocarbons and non-hydrocarbon gases instead of liquid hydrocarbons and/or bitumen. Heating shallow formation layers containing bitumen may also result in a significant amount of gaseous products produced from the formation. Methods and/or systems of heating hydrocarbon formations having entrained bitumen at lower temperatures that convert portions of the formation to bitumen and/or lower molecular weight hydrocarbons, and/or increases permeability in the hydrocarbon containing formation to produce liquid hydrocarbons and/or bitumen are desired.
A hydrocarbon formation may be treated using a steam injection process. The steam injection process, however, may not treat the formation uniformly. For example, steam injection may not be uniform throughout the formation. Variations in the properties of the formation (for example, fluid injectivities, permeabilities, and/or porosities) may result in non-uniform injection of the steam through the formation. Because of the non-uniform injection of the steam, the steam may remove hydrocarbons from different portions of the formation at different rates or with different results. For example, some portions of the formation may have little or no steam injectivity, which inhibits the hydrocarbon production from these portions. After the steam injection process is completed, the formation may have portions that have lower amounts of hydrocarbons produced (more hydrocarbons remaining) than other parts of the formation. Although steam injection can put a lot of energy into the reservoir in a short time, steam injection can not reach pyrolysis temperatures greater than 270° C.
Certain types of formations have low initial matrix permeabilities and contain formation fluid having high initial viscosities at initial or ambient condition that inhibit these formations from being easily treated using conventional steam drive processes such as SAGD or CSS. For example, carbonate formations (such as the Grosmont reservoir in Alberta, Canada) have low matrix permeabilities and contain formation fluid with high viscosities that make these formations unsuitable for conventional steam drive processes. Carbonate formations may also be highly heterogeneous (for example, have highly different vertical and horizontal permeabilities), which makes it difficult to control flow of fluids (such as steam) through the formation. In addition, some carbonate formations are relatively shallow formations with low overburden fracture pressures that inhibit the use of high pressure steam injection because of the need to avoid breaking or fracturing the overburden.
Typically, these initial permeabilities and initial viscosities are not favorable for steam injection into the hydrocarbon layers because the steam injection pressure needed to get steam to move hydrocarbons through the formation is above the fracture pressure of overburden of the formation. Staying below the overburden fracture pressure may be especially difficult for shallower formations (for example, the Grosmont reservoir) because the overburden fracture pressure is relatively small in such shallow formations. Heaters have been used to provide heat to hydrocarbon layers to increases the steam injectivity in the layer. Heat from the heaters may reduce the viscosity of formation fluid in the portion surrounding the heater such that steam injected into the layer at pressures below the overburden fracture pressure can move hydrocarbons in the layer. The use of heaters prior to, or after, steam injection, however, may be economically undesirable.
In some embodiments, hydrocarbon formations include pre-existing openings and/or fractures. For example, highly fractured carbonate formations, highly permeable layers (for example, greater than 1 Darcy) that heated fluid (for example, water) may be injected, or the like. The fractures may form interconnecting pathways (horizontal, vertical, and inclined pathways) in the formation. In some embodiments, the fractures are substantially horizontal or inclined in the formation and are separated by hydrocarbon layers. One or more fractures may be substantially vertical in the formation and be separated by hydrocarbon layers. In some embodiments, vertical fractures intersect horizontal fractures. In some embodiments, one or more wellbores are connected to one or more fractures in the formation. The fractures may have sufficient size to allow fluid to be injected into the fractures without further fracturing.
In certain embodiments, the initial vertical matrix permeability in hydrocarbon layers is at most about 300 millidarcy and the initial horizontal matrix permeability is at most about 1 darcy. In some carbonate formations, the initial vertical matrix permeability is less than the initial horizontal matrix permeability such as, for example, in the Grosmont reservoir in Alberta, Canada. The initial vertical and initial horizontal matrix permeabilities may vary depending on the location in the formation and/or the type of formation.
In some embodiments, the formation is fractured sufficiently that an in situ heat treatment process in combination with injection of hot fluid into the fractures may provide improved heat distribution to the formation and/or increase the amount of heat provided to the formation as compared to other conventional methods. For example the fracture dimension may range from 1 m to 30 mm, from 5 m to 25 m, or from 10 m to 20 m. In some embodiments a fracture spacing is 20 meters. The heated fluid may be injected in fractures and/or a portion of the formation that is vertically displaced from the portion of the formation that includes the heaters. For example, heated water may be provided above and/or below a portion of the formation that contains heaters. Use of the combination of hot water and heaters may allow the use of wider heater spacing while increasing the amount of heat provided to the formation. The use of an in situ hybrid process may also use a lower heating temperature while increasing the amount of heat provided to the formation.
Use of an in situ hybrid process (addition of heated fluid to the hydrocarbon layer during an in situ heat treatment process) may inhibit channeling or fingering that reduces the effectiveness of introduced pressurized fluid. Any energy added to the formation during the heated fluid injection process reduces the amount of energy and/or time needed to be supplied by heaters for the in situ heat treatment process. The heated water may be heated at surface facilities near the hydrocarbon formation. The use of heated water instead of steam may reduce or eliminate equipment required to produce steam for a steam drive. Reducing the amount of energy supplied by heaters or time to heat up the reservoir using heaters and hot fluid reduces costs for treating the formation using the in situ heat hybrid process. For example, two hot fluid injectors in combination with nine heaters may heat up a hydrocarbon layer to 150° C. in 180 days. An in situ heat treatment process using 16 heaters may take 700 days to heat up a hydrocarbon layer to 150° C.
In certain embodiments, in situ hybrid treatment of the relatively permeable formation containing hydrocarbons (for example, the tar sands formation) includes heating the formation to visbreaking temperatures. For example, the hybrid process (hot fluid heating while heating with heaters) may heat the formation to an average temperature 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 about 230° C., or between about 210° C. and about 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. In some embodiments, heating is conducted such that an average viscosity of formation fluids in a hot fluid injection section and a section heated by heaters are within about 20% of each other. 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 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.
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 some embodiments, heaters in the formation are operated at full power output to heat one or more portions of 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 1,000 kPa and about 15,000 kPa, between about 2,000 kPa and about 10,000 kPa, or between about 2,500 kPa and about 5,000 kPa. In one embodiment, the selected pressure is about 10,000 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 some embodiments, heating is conducted such that an average pressure in a hot fluid injection section and a section heated by heaters are within about 20% of each other.
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 fluids (for example, bitumen) from the bottom of 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 fewer fluids are produced at lower temperatures.
In some embodiments, the heated fluid is heated to a temperature using heat from the heaters such that an in situ drive fluid is created or produced. 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.
The hydrocarbon formation may include formation fluid (for example, hydrocarbons) having an initial viscosity of at least about 1 Pa·s (1,000 cp), at least about 5 Pa·s (5,000 cp) or at least 10 Pa·s (10,000 cp) at 15° C. The initial viscosity may vary depending on the location or depth of the fluid in the formation. Heat from the heat fluid and heaters may reduce the viscosity of hydrocarbons such that the hydrocarbons gravity drain to a bottom portion of the hydrocarbon formation. In some embodiments, the hydrocarbons drain through the fractures in the formation to a bottom portion of the hydrocarbon layer. In certain embodiments, the hydrocarbon layer in the formation has sufficient permeability to allow mobilized and/or visbroken fluids to drain to the bottom of the formation. For example, the hydrocarbon layer in the formation 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, the hydrocarbon layer has a relatively large vertical permeability to horizontal permeability ratio (K_v/K_h). For example, a hydrocarbon layer may have a K_v/K_hratio between about 0.01 and about 2, between about 0.1 and about 1, or between about 0.3 and about 0.7. The mobilized and/or visbroken hydrocarbons may be produced using a production well positioned in the bottom portion of the formation.
In some embodiments, heavy hydrocarbons gravity drain to a bottom portion of the formation while hydrocarbons near the heaters are upgraded (e.g., pyrolyzed and/or visbroken) to a higher quality formation fluid. For example, bitumen may gravity drain to the bottom of the form while a portion of the bitumen near the heaters is upgraded to a mixture of hydrocarbons having an API gravity of greater than 25°.
Using the in situ heat treatment process in combination with a heated water gravity drain process (in situ hybrid process) may allow more oil to be recovered from the formation as compared to conventional methods. For example, at least about 25%, at least about 50%, at least about 55%, or at least about 60% more oil may be recovered from the formation as compared to a steam drive process. 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. In some embodiments, 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.
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).
In certain embodiments, formations with the above properties (such as the Grosmont reservoir or other carbonate formations) are treated using a combination of heating from heaters and heated fluid. FIG. 7 depicts an embodiment for treating a formation with an in situ hybrid treatment processes. Injection well 270 may be located in first section 272A of hydrocarbon containing layer 268. Hydrocarbon containing layer 268 may be below overburden 274. Injection well 270 may be used to inject heated fluid (for example, heated water). In some embodiments, a heated fluid (for example, steam) is injected at a pressure of about 4.8 MPa (about 700 psi). Heaters 212 are located in second section 272B of hydrocarbon containing layer 268 between injection well 270 in first section 272A and production well 206 in third section 272C. In some embodiments, production well 206 may be used to produce hydrocarbons that have drained through first section 272A and second section 272B to third section 272C. In some embodiments, the second and third sections are vertically or relatively vertically displaced below the first section. The injection wells may have long, substantially horizontal sections similar to the heating portions of heaters 212, or the injections wells may be otherwise oriented (for example, the wells may be vertically oriented wells, or wells that include one or more slanted portions).
In certain embodiments, heaters 212 are located substantially horizontally in layer 268. In some embodiments, injection well 270 is located relatively vertically in layer 268 and production well 206 is located substantially horizontally in the layer. In some embodiments, production well 206 is located substantially vertically in the layer. In some embodiments, injection well 270 and production well 206 are located substantially horizontally in layer 268 while heaters 212 are located substantially horizontally in layer 268. In some embodiments more than one injection well is used in the first section.
In certain embodiments, heaters 212 are located approximately vertically equidistant between injection well 270 and production well 206 (the heater is at or near the midpoint between the injection well and the production well). As shown, heaters 212 are placed in an alternating triangular pattern in hydrocarbon layer 268. In some embodiments, heaters 212 are placed in an alternating triangular pattern in hydrocarbon layer 268 that repeats vertically to encompass a majority or the entire section of a hydrocarbon layer. The number of vertical rows of heaters 212 depends on factors such as, but not limited to, the desired spacing between the heaters and the thickness of hydrocarbon layer 268 and/or sections of the hydrocarbon layer (for example, section 272B of the hydrocarbon layer). In some embodiments, heaters 212 are arranged in other patterns. For example, heaters 212 may be arranged in patterns such as, but not limited to, hexagonal patterns, square patterns, or rectangular patterns.
Heaters 212 may provide heat to a portion of layer 268 surrounding the heater and between injection well 270 and production well 206 (for example, section 272B). Heaters 212 may include, but are not limited to, an electric heater such as an insulated conductor heater or a conductor-in-conduit heater, a circulated fluid heater, or combinations thereof. In certain embodiments, heat provided by heaters 212 increases the permeability in the portion surrounding the heater, which allows heated fluid to drain from second section 272B through to third section 272C. In certain embodiments, heaters 212 provide heat at high heat rates such as those used for the in situ hybrid treatment process (for example, heat injection rates of at least about 1000 W/m).
In certain embodiments, layer 268 has different initial vertical and horizontal matrix permeabilities (the initial matrix permeability is heterogeneous). In one embodiment, the initial vertical matrix permeability in layer 268 is at most about 300 millidarcy and the initial horizontal matrix permeability is at most about 1 darcy. In some carbonate formations, the initial vertical matrix permeability is less than the initial horizontal matrix permeability such as, for example, in the Grosmont reservoir in Alberta, Canada. The initial vertical and initial horizontal matrix permeabilities may vary depending on the location in the formation and/or the type of formation. In one embodiment, layer 268 includes formation fluid (for example, hydrocarbons) having an initial viscosity of at least about 10 Pa·s (10,000 cp) at 15° C. The initial viscosity may vary depending on the location or depth of the fluid in the formation.
Hot fluid injection through injection well 270 or directly into one or more fractures in the formation at the same time or substantially the same time heat is provided from heaters 212 reduces the viscosity of formation fluid in layer 268 such that hydrocarbon fluid drains towards production well 206. In some embodiments, the heaters are turned on prior to the injection of heated fluid to heat the formation such that some permeability in the formation is created for hot fluid injection.
Since the initial permeabilities and initial viscosities are not favorable for steam injection into layer 268 and the steam injection pressure required to move hydrocarbons through the formation is above the fracture pressure of overburden 274, hot fluid injection while heating or simultaneously heating allows the pressure in the layer 268 to stay below the overburden fracture pressure. Thus, heating time required to mobilize hydrocarbons may be reduced. Since hot fluid is provided to a first portion of layer 268 (for example, section 272A) while heating a second portion of the layer (for example, section 272B), fewer heaters may be required as compared to a typical steam drive process and/or in situ heat treatment process. The in situ hybrid process may increase the efficiency of hydrocarbon production from layer 268. The interconnectivity may also allow less injection wells and/or production wells to be used in treating the layer.
In certain embodiments, heaters 212 provide heat prior to and/or during injection of hot fluid such that the viscosity of the hydrocarbons in near the heaters is reduced to below about 1 Pa·s (1,000 cp), below about 0.50 Pa·s (500 cp), below about 0.10 Pa·s (100 cp), or below about 0.05 Pa·s (50 cp). The spacing between heaters 212 and/or the heat output of the heaters may be designed and/or controlled to reduce the viscosity of the hydrocarbons in hydrocarbon layer 268 to desirable values. Heat provided by heaters 212 may be controlled so that little or no pyrolyzation occurs in hydrocarbon layer 268. Superposition of heat between the heaters may create one or more drainage paths (for example, paths for flow of fluids as shown by the arrow 276) between the heaters.
In certain embodiments, production well 206 is located proximate heaters 212 so that heat from the heaters superimposes over the production wells. The superimposition of heat from heaters 212 over production well 206 may create one or more drainage paths, in addition to fractures or fissures in the layer, from the heaters to the production wells. In certain embodiments, one or more of the drainage paths converge. For example, the drainage paths may converge at or near a bottommost heater and/or the drainage paths may converge at or near production wells 206. Fluids mobilized in hydrocarbon layer 268 tend to flow towards production well 206 in the hydrocarbon layer because of gravity and the heat and pressure gradients established by the heaters and/or the production wells. The drainage paths and/or the converged drainage paths allow production well 206 to collect mobilized fluids in hydrocarbon layer 268.
In certain embodiments, one or more heaters 212 are turned off after hydrocarbons are mobilized. The time a heater is turned off may be selected to provide, for example, desired properties in the hydrocarbons produced from the formation. After interconnectivity between the first portion (for example, section 272A) and third portion (for example, section 272B) of layer 268 all or some of heaters 212 may be turned off. In some embodiments, heaters are turned off after a desired amount of upgraded hydrocarbons are produced from the hydrocarbon layer (for example, heaters may be turned off after 5 years). In certain embodiments, heating from heaters 212 is controlled and/or the heaters are turned off at a time to inhibit coke formation in the layer. Simulation of reservoir conditions may be used to determine when/if the onset of coking may occur in the layer. Additionally, the hot fluid injection into the formation may assist in inhibiting coke formation in the layer.
In some embodiments, heaters are turned off after a desired amount of hydrocarbons are produced from the hydrocarbon layer and hot fluid is injected in the hydrocarbon layer to maintain a temperature of the hydrocarbon layer at or around 200° C. Due to the temperature in the hydrocarbon formation, hydrocarbons may drain or continue to drain to a bottom portion of the hydrocarbon layer. Residual heat from the portions of the hydrocarbon layer heated with heaters and heat from the injected hot fluid may transfer to other portions of the formation that are at a lower temperature. The energy provided by the continued hot fluid injection and the residual temperature from heating with heaters may allow more formation fluid to be recovered from the hydrocarbon layer.
In some embodiments, the hot fluid injection is discontinued and/or reduced after hydrocarbons are mobilized and/or hot fluid is distributed evenly in the hydrocarbon layer. The time hot fluid injection is discontinued or reduced may be selected to provide, for example, less water to the formation or when an average temperature of the hydrocarbon layer is greater than the boiling point of water (for example, an average temperature greater than 200° C. Reduction in the amount of hot fluid provided to the formation may limit or reduce the amount of energy required to vaporize the water to steam.
In some embodiments, a pattern for treating a formation includes a repeating pattern of heaters 212, injection well 270, and production well 206, as shown in FIG. 7. The pattern may be repeated horizontally and/or vertically in the formation. Using the repeating pattern to treat the formation may reduce the number of wells needed to treat the formation as compared to using typical steam drive processes or in situ heat treatment processes individually. In some embodiments, heaters 212 may be removed and reused in another portion of the formation, or another formation, after the heaters are turned off. The heaters may be allowed to cool down before being removed from the formation.
In certain embodiments, the bottommost heaters are located between about 2 m and about 10 m from the bottom of hydrocarbon layer 268, 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 well 206 is located at a distance from the bottommost heaters 212 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.
Different combinations of heaters, injection wells and/or production wells are used in the in situ hybrid process depending on economic conditions, the type of formation fluid to be produced, and/or energy balance required. Different combinations of heaters, injection wells and production wells may be determined using computer simulations of formation conditions. For example, a configuration having a low economic cost may include four heaters, 1 injection well and two production wells. A second configuration may include: 8 heaters, 1 injection well, and one production well for high energy efficiency. A third configuration may include 12 heaters, one steam injection well and one production well that produces from two different sections of the hydrocarbon layer for production of hydrocarbons having pipeline quality.
In certain embodiments, fluids are produced through production well 206 located in the lower portion of hydrocarbon layer 268. In some embodiments, fluids are produced through production wells located below and approximately midway between heaters 212 in the lower portion of hydrocarbon layer 268. In some embodiments, production well 206 is positioned substantially vertically below the bottommost heaters in hydrocarbon layer 268. Production well 206 may be located below heaters 212 at the bottom vertex of a pattern of the heaters (for example, at the bottom vertex of the triangular pattern of heaters. Locating production well 206 substantially vertically below the bottommost heaters may allow for efficient collection of mobilized fluids from hydrocarbon layer 268. Production well 206 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. In some embodiments, production well 206 is located a distance from the nearest heater of at most ⅔, at most ½, or at most ⅓ of the spacing between heaters in the pattern of heaters. In certain embodiments, production well 206 is located between about 2 m and about 10 m from the bottommost heaters, between about 4 m and about 8 m from the bottommost heaters, or between about 5 m and about 7 m from the bottommost heaters. Production wells 206 may be located between about 0.5 m and about 8 m from the bottom of hydrocarbon layer 268, between about 1 m and about 5 m from the bottom of the hydrocarbon layer, or between about 2 m and about 4 m from the bottom of the hydrocarbon layer. In some embodiments, a production well is located at least 30 m, at least 100 m, or at least 250 m from an injection well. In some embodiments, a production well is located from 150 m up to 200 m from an injection well, depending on the subsurface rock and fluid characteristics, such as, for example, oil viscosity, matrix permeability, fracture systems, and other known fluid characteristics. A large spacing between injection and production wells may allow more hydrocarbons to be produced from the formation at a lower cost.
In some embodiments, production well 206 includes a pump to move fluids to the surface of the formation. For example, formation fluids that include water may be removed from the formation, the water may be separated from hydrocarbons and heated, and then re-injected into the formation. In some embodiments, the viscosity of fluids (oil) in production well 206 is lowered using heaters and/or diluent injection (for example, using a conduit in the production wells for injecting the diluent).
Using the embodiment depicted in FIG. 7 to treat the formation (for example, the Grosmont reservoir) may increase oil production and/or decrease the amount of energy required to heat steam needed for oil production as compared to using the SAGD process only or in combination with an in situ heat treatment process.
In formations with low permeabilities, the hybrid heating process creates a “gas cushion” or pressure sink in the portion of the hydrocarbon formation. In some embodiments, the production of fluids is used to maintain the gas cap. Increased heating with heater may also maintain the gas cap and/or maintain quality in the production from the hydrocarbon formation. The gas cushion may inhibit pressures from increasing quickly to fracture pressure during the in situ hybrid treatment process. The gas cushion may provide a path for gases to escape or travel during early stages of heating during the in situ hybrid treatment process.
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 hot fluid and heaters 212 may be modified to create the gas cap at or near overburden 274 of hydrocarbon layer 268. The gas cap may push or drive liquids to the bottom of the hydrocarbon layer so that more liquids may be produced from the formation. In situ generation of the gas cap may be more efficient than introducing pressurized fluid into the formation. The in situ generated gas cap applies force evenly through the formation with little or no channeling or fingering that may reduce the effectiveness of introduced drive fluid.
In certain embodiments, production wells are located in more than one section in the formation. The sections may have the same or different initial permeabilities. In certain embodiments, a first section has an initial permeability of at least about 1 darcy and a second section has an initial permeability of at most about 0.1 darcy. In some embodiments, the first section has an initial permeability of between about 1 darcy and about 10 darcy. In some embodiments, the second section has an initial permeability between about 0.01 darcy and 0.1 darcy. In some embodiments, the sections may be separated by a substantially impermeable barrier (with an initial permeability of about 10μ darcy or less). Having the production well located in both sections allows for fluid communication (permeability) between the sections and/or pressure equalization between the sections.
Bridging the sections with the openings allows for fluid communication (permeability) between the sections and/or pressure equalization between the sections. 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 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 an in situ hybrid treatment).
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). Producing hydrocarbons from the lower portion first may create space in the lower formation for hydrocarbons from the upper portion to be conveyed by gravity to the lower portion. Not heating hydrocarbons in the upper portion of the formation may reduce over cracking or over pyrolyzing of these hydrocarbons, which may result in a better quality of produced hydrocarbons for the formation. Using such a strategy may result in a lower gas to oil ratio. In some embodiments, a greater reduction in the percentage of gas produced relative to the increase in the percentage of oil produced may result, but the overall total market value of the products may be greater.
In one embodiment, the formation is heated to 220° C. or 230° C. using the in situ hybrid process. 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, and a P-value of at least 1.1. 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.
FIG. 8 depicts a hybrid in situ treatment process using a production well passing through two sections. Injection well 270 may be located in first section 272A of hydrocarbon containing layer 268. Hydrocarbon layer 268 may be below overburden 274. Injection well 270 may be used to inject heated fluid. Heaters 212 are located in second section 272B of hydrocarbon containing layer 268. Production well 206 may include opening 278 positioned near heaters 212 in second section 272B and opening 280 positioned in a third section 272C of hydrocarbon containing layer 268. As shown, productions well 206 may be positioned substantially vertically in hydrocarbon containing layer 268. In some embodiments, productions well 206 may be positioned substantially horizontally in hydrocarbon containing layer 268. Production well 206 may be positioned at the edge of the treatment area.
As formation fluid drains to the bottom of hydrocarbon containing layer 268, fluid may flow into opening 280 of production well 206. During production of fluids from third section 272C (bottom of hydrocarbon layer 268), communication between the production well and opening 278 may be inhibited. Formation fluid produced from second section 272B through opening 280 may have an API gravity of greater than 10° and a viscosity of less than 10 Pa·s (10,000 cp) at 15° C. In some embodiments, formation fluid produced from opening 280 has an API gravity of about 10° and a viscosity of about 100 Pa·s (100,000 cp) at 15° C. The formation fluid may include visbroken hydrocarbons and/or mobilized hydrocarbons. (for example, bitumen, heavy hydrocarbons, or mixtures thereof). In some embodiments, the formation fluid may include water.
Once a sufficient amount of formation fluids are produced through opening 280, communication between the opening and production well 206 may be inhibited. Communication between opening 278 and production well 206 may be established (for example, opening a valve, and/or perforations in a conduit) and formation fluids may be produced. Formation fluids produced from opening 278 may include pyrolyzed hydrocarbon, visbroken hydrocarbons, and/or mobilized hydrocarbons. In some embodiments, formation fluids produced from opening 278 has an API gravity of about 21° and a viscosity of about 0.1 Pa·s (100 cp) at 15° C.
In some embodiments, opening 278 and/or opening 280 of production well 206 are connected with injection well 270 to allow fluid communication between the injection well and both sections of the production well. FIG. 9 depicts a side view representation of a production well 206 in fluid communication with injection well 270. Wellbore 282 may connect injection well 270 with production well 206. Fluid communication between the injection well and the production well may control pressure or inhibit pressure build-up in the production and/or injection wells during heating. Once the communication between injection well 270 and a first opening (for example, opening 278 and opening 284) is established, the communication between a second opening (for example, opening 280) of production well 206 may be inhibited (for example, by closing a valve or perforations in the wellbore). After closing opening 280, hot injection fluid may be injected into injection well 270 and flow horizontally to opening 278 and heats conductive heats formation section 272A and/or 272B. Heat fluid may be produced through production well 206 and/or flow into formation section 272B through opening 286 of the production well.
In some embodiments, formation fluids are produced through opening 278. After a sufficient amount of formation fluids are produced through opening 278, communication between the opening and production well 206 may be inhibited. Heavier hydrocarbons may then be produced through opening 280. Production through opening 278 then through opening 280 may allow pipelineable quality oil to be produced first from the formation. Production of hydrocarbons through opening 278 may allow further upgrading of heavier hydrocarbons as they drain into third section 272C.
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. 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 (for example, formation fluid produced from third section 272C) and/or as fluids are upgraded by passing by hot spots in the formation. In some embodiments, water may be produced from third section 272C prior to producing hydrocarbons.
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 (for example, fluid produced from second section 272B). 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 (for example, formation fluid produced from third section 272C) 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.
The differences between a hybrid heating process, a SAGD process, and an in situ heat treatment process may be significant. For example, a SAGD heating process may not include heaters while an in situ upgrading process may not include injection wells. In a typical SAGD process, two parallel horizontal oil wells are drilled in the formation, one about 4 m to 6 m above the other. The upper well injects steam, possibly mixed with solvents, and the lower one collects the heated crude oil or bitumen that flows out of the formation, along with any water from the condensation of injected steam. One the other hand, the distance between the injection well and production well in a hybrid heating process is typically ranges from 20 m to 200 m, which is significantly larger than that of the SAGD process.
In certain embodiments, one or more layers in a hydrocarbon formation 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, a layer is heated to temperatures of at most 400° C., at most 450° C., or at most 500° C. (for example, to a temperature below a dolomite decomposition temperature at formation pressure). In some embodiments, the layer is 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 low weight percentages of clay minerals (for example, kaolinite) as compared to the clay content in other portions of the formation. For example, more heat may be provided to portions of the formation with at most 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 that have been assessed to have lower weight percentages of clay minerals as compared to other portions of the formation. In certain embodiments, the heaters are placed substantially horizontally in layers with low weight percentages of clay minerals.
Providing heat to portions of the formation with low weight percentages of clay minerals may minimize changes in the chemical structure of the clays. For example, heating clays to high temperatures may drive water from the clays and change the structure of the clays. The change in structure of the clay may adversely affect the porosity and/or permeability of the formation. If the clays are heated in the presence of air, the clays may oxidize and the porosity and/or permeability of the formation may be adversely affected. Portions of the formation with a high weight percentage of clay minerals may be inhibited from reaching temperatures above temperatures that effect the chemical composition of the clay minerals at formation pressures. For example, portions of the formation with large amounts of kaolinite relative to other portions of the formation may be inhibited from reaching temperatures above 240° C. In some embodiments, portions of the formation with a high quantity of clay minerals relative to other portions of the formation may be inhibited from reaching temperatures above 200° C., above 220° C., above 240° C., or above 300° C.
In some embodiments, the heated formation may include natural water and/or water that has been injected. Minerals (for example, carbonate minerals) in the formation may at least partially dissociate in the water to form carbonic acid. The concentration of carbonic acid in the water may be sufficient to make the water acidic. At pressure greater than ambient formation pressure, dissolution of minerals in the water may be enhanced, thus formation of acidic water is enhanced. Acidic water may react with other minerals in the formation such as dolomite (MgCa(CO₃)₂) and increase the solubility of the minerals. Water at lower pressures, or non-acidic water, may not solubilize the minerals in the formation. Dissolution of the minerals in the formation may form fractures in the formation. Thus, controlling the pressure and/or the acidity of water in the formation may control the solubilization of minerals in the formation. In some embodiments, other inorganic acids in the formation enhance the solubilization of minerals such as dolomite.
In some embodiments, the hydrocarbon layers are heated to temperatures above the decomposition temperature of 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 generate a gas cap in the formation. The carbon dioxide may be allowed to rise to the upper portions of the hydrocarbon layers to generate the gas cap.
FIG. 10 depicts a side view representation of an embodiment for producing mobilized fluids from a tar sands formation with a hydrocarbon layer that includes an impermeable layer or barrier. Injection well 270 may be located in first section 272A of hydrocarbon containing layer 268. Hydrocarbon layer 268 may be below overburden 274. Injection well 270 may be used to inject heated fluid (for example, heated water). Heaters 212 are located in second section 272B of hydrocarbon containing layer 268 between injection well 270 (first section 272A) and production well 206 (third section 272C). Barrier 288 is located in second section 272B. Barrier 288 may include clay compounds and/or carbonate compounds. The alternating triangular pattern of heaters 212 in hydrocarbon layer 268 repeats uninterrupted across barrier 288. Heaters 212 may be equidistantly spaced from each other. The number of vertical rows of heaters 212 depends on factors such as, but not limited to, the desired spacing between the heaters, the thickness of hydrocarbon layer 268, and/or the number and location of barriers. In some embodiments, heaters 212 are arranged in other patterns. For example, heaters 212 may be arranged in patterns such as, but not limited to, hexagonal patterns, square patterns, or rectangular patterns.
In some embodiments, hot fluid (for example, hot water) may be injected in hydrocarbon layer 268 through injection well 270 during the heating process. The hot fluid and/or heaters 212 near barrier 288 provide heat such that at least a portion of the barrier decomposes or fractures to form openings or drainage pathways 290 in the barrier, as shown in FIG. 11. Heat from heaters 212 and the heated fluid permeating the fractures in the formation reduces the viscosity of the hydrocarbon sufficiently to allow gravity drainage of the visbroken hydrocarbons in hydrocarbon layer 268 through pathways 290 as shown by arrows 276. In certain embodiments, heaters 212 provide heat that reduces the viscosity of the hydrocarbons in hydrocarbon layer 268 below about 0.50 Pa·s (500 cp), below about 0.10 Pa·s (100 cp), or below about 0.05 Pa·s (50 cp). The spacing between heaters 212 and/or the heat output of the heaters and/or hot fluid injection rate may be designed and/or controlled to assist in viscosity reduction of the hydrocarbons in hydrocarbon layer 268 to desirable values. Heat provided by heaters 212 may be controlled so that a selected amount of pyrolyzation occurs in hydrocarbon layer 268.
In certain embodiments, the bottommost heaters above barrier 288 are located between about 2 m and about 10 m from the barrier, between about 4 m and about 8 m from the bottom of the barrier, or between about 5 m and about 7 m from the barrier. Production wells 206 may be located between about 0.5 m and about 8 m from barrier 288, between about 1 m and about 5 m from the barrier, or between about 2 m and about 4 m from the barrier.
Production wells 206 may be used to produce hydrocarbons that have drained through first section 272A and second section 272B to third section 272C. In some embodiments, the second and third sections are vertically or substantially vertically displaced below the first section. In certain embodiments, heaters 212 are located substantially horizontally in layer 268. In some embodiments, injection well 270 is located substantially vertically in layer 268 and production well 206 is located substantially horizontally in the layer. In some embodiments, production well 206 is located substantially vertically in the layer. In some embodiments, injection well 270 and production well 206 are located substantially horizontally in layer 268 while heaters 212 are located substantially horizontally in layer 268. In some embodiments more than one injection well is used in the first section.
In certain embodiments, fluids mobilized in hydrocarbon layer 268 tend to flow towards the bottommost heaters 212 and production wells 206 in third section 272C of the hydrocarbon layer because of gravity and the heat and pressure gradients established by the heaters, hot fluid, and/or the production wells. Production wells 206 to collect mobilized fluids in third section 272C of hydrocarbon layer 268.
In some embodiments, heat is provided in or proximate production wells 206. Providing heat in or proximate production wells 206 may maintain and/or enhance the mobility of the fluids in the production wells. Heat provided in or proximate production wells 206 may superimpose with heat from heaters 212 to create the flow path from the heaters to the production wells. In some embodiments, production wells 206 include a pump to move fluids to the surface of the formation. In some embodiments, the viscosity of fluids (oil) in production wells 206 is lowered using heaters and/or diluent injection (for example, using a conduit in the production wells for injecting the diluent). Formation fluids are produced through production wells 206 located in the lower portion of hydrocarbon layer 268. The formation fluids include mobilized and/or visbroken fluids. In some embodiments, at least one production well 206 is capable of producing from one or more sections of the hydrocarbon layer as described herein.
In some embodiments, a drive process (or steam injection, for example, SAGD, cyclic steam soak, or another steam recovery process) and/or in situ heat treatment process are used to treat the formation and produce hydrocarbons from the formation. Heat from the in situ heat process and/or drive process may be used to generate steam in situ. The steam may be used to heat an untreated portion of the formation to a temperature sufficient to visbreak and/or mobilize hydrocarbons in the untreated portion of the formation.
In some embodiments, heaters are used to heat a first section the formation. At least one heater may be positioned in a first portion of a wellbore that extends from the first section of the formation into a second section of the formation. For example, heaters may be used to heat a first section of formation to pyrolysis temperatures to produce formation fluids. In some embodiments, heaters are used to heat a first section of the formation to temperatures below pyrolysis temperatures to visbreak and/or mobilize fluids in the formation. In other embodiments, a first section of a formation is heated by heaters prior to, during, or after a drive process is used to produce formation fluids.
In some embodiments, the formation is treated using the in situ heat treatment process for a significant time after the formation has been treated with a 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 drive processes. After heating the formation for a significant amount of time using heaters and/or injected fluid (for example, steam), water may be added to the heated section. Heat from some heaters and/or residual heat from the heated section may generate steam in situ. The generated steam may flow or be pressurized through the wellbore the previously existing substantially horizontal heater wellbore. The previously existing wellbore may extend through the first and second sections of the hydrocarbon containing formation. In some embodiments, the heater is removed from the wellbore prior to generating the steam.
Heat from the steam mobilizes (reduces the viscosity) formation fluids in the second section. The mobilized formation fluid may be produced from the formation. In some embodiments, the mobilized formation fluid includes, but is not limited to, heavy hydrocarbons, upgraded hydrocarbons, bitumen, water, or mixtures thereof.
FIG. 12 depicts a side view representation of an embodiment of generating steam in situ after treatment of a hydrocarbon containing formation. Hydrocarbon layer 268 may be divided into two or more treatment sections. In certain embodiments, hydrocarbon layer 268 includes two different types of treatment sections: section 272A, and section 272B. Section 272A and section 272B may be horizontally displaced from each other in the formation. In some embodiments, one side of section 272A is adjacent to an edge of the treatment area of the formation. Section 272A and section 272B may form a repeating pattern in the hydrocarbon containing layer.
In certain embodiments, section 272A may be heated to mobilize and/or pyrolyze hydrocarbons in the sections. The mobilized and/or pyrolyzed hydrocarbons may be produced from section 272A through production well 206. Little or no production of hydrocarbons to the surface may take place through section 272B. For example, section 272A may be heated to average temperatures of about 200° C. to 550° C.
In certain embodiments, heating and producing hydrocarbons from section 272A creates fluid injectivity in the section. After fluid injectivity has been created in section 272A, a fluid such as a drive fluid (for example, steam, water, or hydrocarbons) and/or an oxidizing fluid (for example, air, oxygen, enriched air, or other oxidants) may be injected into the section. The fluid may be injected through heaters 212, a production well, and/or an injection well located in section 272A. In some embodiments, heaters 212 continue to provide heat while the fluid is being injected. In other embodiments, heaters 212 may be turned down or off before or during fluid injection. Additional fluids may be produced from section 272A through production well 206. In some embodiments, a drive fluid is provided before or during heating of section 272A.
After the formation is raised to a desired temperature and a desired amount of formation fluid has been produced from section 272A, fluid (for example, water) may be introduced into section 272A to generate steam. In some embodiments, heater 212 may be removed from heater wellbore 292 prior to the injection of water. In some embodiments, the water may include nonpotable water and/or treated water from surface facility processes, water produced from the hydrocarbon containing formation, water produced from another portion of the hydrocarbon containing formation and/or mixtures thereof. The ability to reuse water from surface facilities and/or other hydrocarbon treatment process may lower capital expenditure for producing hydrocarbons from the hydrocarbon formation as compared to conventional processes.
Heat from section 272A may generate steam in the section. The generation of steam in section 272A may increase the pressure of the section so the generated steam moves out of the section into adjacent section 272B through existing heater wellbore 292 that extends from section 272A into section 272B. Heater wellbore 292 may include openings, slotted piping, and/or valves 294 that allow the generated steam to enter the wellbore in section 272A and exit the wellbore in section 272B. The increased temperature of section 272A may also provide heat to section 272B through conductive heat transfer and/or convective heat transfer from fluid flow (for example, hydrocarbons and/or drive fluid) to section 272B.
Steam generated in section 272A may flow towards section 272B, as shown by the arrows in FIG. 12. Fluid movement through the formation transfers heat convectively through hydrocarbon layer 268 into section 272B.
Low level heating of section 272B mobilizes (reduces the viscosity) hydrocarbons in the section. In addition, some heat may transfer conductively through the hydrocarbon layer between the sections. In some embodiments, the steam condenses to form water. The water may solubilize and/or reduce the viscosity of hydrocarbons in the section. Reduction in the viscosity of the hydrocarbons in the may allow a portion of the hydrocarbons to be mobilized in the section. The mobilized hydrocarbons in section 272B may gravity drain and be produced through production well 206, which may extend through section 272A through section 272B. Production well 206 may include opening 278 and opening 280 that allows production from section 272A and/or section 272B. In some embodiments, production well 206 is two separate production wells.
In certain embodiments, section 272B has a larger volume than section 272A. Section 272B 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 272B (the section is heated to lower temperatures), having a larger volume in section 272B reduces the total energy input to the formation per unit volume. The desired volume of section 272B may depend on factors such as, but not limited to, viscosity, oil saturation, and permeability. In some embodiments, the lower degree of heating in section 272B allows for lower capital costs as lower temperature materials (cheaper materials) may be used for wellbores used in section 272B.
It is to be understood the invention is not limited to particular systems described which may, of course, vary. It is also to be understood that the terminology used herein is for the purpose of describing particular embodiments only, and is not intended to be limiting. As used in this specification, the singular forms “a”, “an” and “the” include plural referents unless the content clearly indicates otherwise. Thus, for example, reference to “a core” includes a combination of two or more cores and reference to “a material” includes mixtures of materials.
In this patent, certain U.S. patents and U.S. patent applications have been incorporated by reference. The text of such U.S. patents and U.S. patent applications is, however, only incorporated by reference to the extent that no conflict exists between such text and the other statements and drawings set forth herein. In the event of such conflict, then any such conflicting text in such incorporated by reference U.S. patents and U.S. patent applications is specifically not incorporated by reference in this patent.
Further modifications and alternative embodiments of various aspects of the invention will be apparent to those skilled in the art in view of this description. Accordingly, this description is to be construed as illustrative only and is for the purpose of teaching those skilled in the art the general manner of carrying out the invention. It is to be understood that the forms of the invention shown and described herein are to be taken as the presently preferred embodiments. Elements and materials may be substituted for those illustrated and described herein, parts and processes may be reversed, and certain features of the invention may be utilized independently, all as would be apparent to one skilled in the art after having the benefit of this description of the invention. Changes may be made in the elements described herein without departing from the spirit and scope of the invention as described in the following claims.

Claims

What is claimed is:

1. A method for treating a tar sands formation, comprising:

providing heated fluid to a first section of the hydrocarbon layer while providing heat to a second section of a hydrocarbon layer in the formation from a plurality of heaters located in the formation, wherein the second section is vertically displaced from the first section;

allowing the heat to transfer from the heaters and heated water to at least a portion of the formation;

allowing fluids to gravity drain to a third section of the hydrocarbon formation; and

producing fluids from the formation through at least one production well that is located in the third section of the formation.

2. The method of claim 1, wherein the heat and heated fluid are provided simultaneously.

3. The method of claim 1, wherein the heated fluid is provided to a highly permeable fracture in the second section.

4. The method of claim 1, wherein the heated fluid comprises water.

5. The method of claim 1, wherein the second section is vertically displaced substantially above the first section.

6. The method of claim 1, wherein the third section is vertically displaced substantially below the second section.

7. The method of claim 1, further comprising heating such that an average pressure in the two sections is within about 20% of each other.

8. The method of claim 1, further comprising heating such that an average viscosity in the two sections is within about 20% of each other.

9. The method of claim 1, wherein the at least one production well allows fluid communication between the bottom section and the second section.

10. The method of claim 1, wherein the heated fluid comprises water and heating the fluid in the first section heats the water sufficiently to form steam.

11. The method of claim 1, wherein a temperature of the heated fluid is greater than 100° C.

12. The method of claim 1, further comprising controlling an average pressure in the formation such that the average pressure remains below a selected pressure.

13. The method of claim 12, wherein the selected pressure is the fracture pressure of the formation.

14. The method of claim 12, wherein the selected pressure is between about 1000 kPa and about 15000 kPa.

15. The method of claim 12, wherein the selected pressure is a pressure below which substantial hydrocarbon coking in the formation occurs when the average temperature in the formation is less than 300° C.

16. The method of claim 15, wherein the selected pressure is between about 100 kPa and about 1000 kPa.

17. The method of claim 1, wherein the plurality of heaters comprise:

piping positioned in at least two wellbores in the first section;

a fluid circulation system coupled to the piping; and

a heat supply configured to heat a liquid heat transfer fluid circulated by the circulation system through the piping to heat the temperature of the formation to temperatures that allow for mobilization of hydrocarbons in the formation.

18. The method of claim 17, wherein the heat transfer fluid comprises one or more metals.

19. The method of claim 17, wherein the heat transfer fluid comprises one or more molten salts.

20. The method of claim 17, wherein the heat transfer fluid comprises hydrocarbons.

21. The method of claim 1, wherein at least one of the heaters of the plurality of heaters comprises one or more insulated electrical conductors.

22. The method of claim 1, wherein the second section has a permeability of greater than about 1 Darcy.

23. The method of claim 1, wherein the hydrocarbon layer comprise fractures.

24. The method of claim 1, wherein the hydrocarbon layer comprises fractures and wherein a fracture spacing is at least about 20 m.

25. The method of claim 1, wherein the heated fluid is provided in an injection well and wherein the injection well is at least 50 m from the production well.

26. The method of claim 1, wherein the first and second sections comprise hydrocarbon having a viscosity of at least 10 Pa·s.

27. The method of claim 1, wherein the heated fluid is provided to a substantially vertical injection well.

28. The method of claim 1, wherein at least one of the heaters is substantially horizontal or inclined in the first section.

29. A method for treating a tar sands formation, comprising:

providing heat to a hydrocarbon layer in the formation from heated fluid injected in a first section of the formation and from a plurality of heaters located in a second section the formation;

producing fluids from the second section of the formation;

turning off or down heaters in the second section; and

producing fluids from the formation from a third section of the formation, wherein the produced fluids comprise visbroken hydrocarbons from the first section.

30. A method for treating a tar sands formation, comprising:

providing heated fluid to a first section of the hydrocarbon layer while providing heat to a second section of a hydrocarbon layer in the formation from a plurality of heaters located in the formation;

allowing the heat to transfer from the heaters and heated fluid to at least a portion of the formation;

producing fluids from the formation through at least one production well that is located in at least the second section and third section in the formation, wherein the third section comprises bitumen and the second section comprises upgraded hydrocarbons, and wherein the second section is between the first and third sections.

31. The method of claim 30, wherein the upgraded hydrocarbons have an API gravity of greater than about 25.

32. The method of claim 30, wherein the bitumen is produced from the third section prior to producing the upgraded hydrocarbons from the second section.

33. The method of claim 30, wherein the production well comprises a heater, and wherein heat from the heater upgrades at least a portion of the bitumen.

34. The method of claim 30, wherein the upgraded hydrocarbons are produced from the second section prior to producing the bitumen from the third section.

35. The method of claim 30, further comprising removing water from the formation prior to producing fluids.

36. A method for treating a formation, comprising:

providing heat to a first section of a hydrocarbon layer in the formation from a plurality of heaters located in the formation while providing heated fluid to a second section of the hydrocarbon layer, wherein the first portion of the layer comprises an impermeable barrier;

allowing the heat to transfer from the heaters and heated fluid to one or more portions of the formation, wherein at least a portion of the heat is sufficient to create permeability in the barrier;

mobilizing hydrocarbon fluids in the formation; and

producing hydrocarbon fluids from the formation.

37. The method of claim 36, wherein the barrier comprises carbonate.

38. The method of claim 36, wherein the barrier comprises dolomite.

39. A method for treating a tar sands formation, comprising:

providing heat to first section of a hydrocarbon containing layer from a heater positioned in a wellbore, wherein the wellbore extends through the first section and a second section of the hydrocarbon containing formation;

producing at least some fluids from the formation;

generating steam in the first section of the hydrocarbon formation;

providing at least a portion of the steam to a portion of the wellbore in the second section;

providing heat to the second section from the steam;

mobilizing hydrocarbons in the second section; and

producing additional fluids from the formation.

40. The method of claim 39, wherein generating steam comprises injecting water into the first section of the hydrocarbon formation.

41. The method of claim 39, wherein generating steam comprises injecting water into the first section of the hydrocarbon formation, wherein the water comprises nonpotable water.

42. The method of claim 39, wherein generating steam comprises injecting water into the first section of the hydrocarbon formation, wherein the water comprises water produced from a hydrocarbon containing formation.

43. The method of claim 39, wherein the heater is removed from the wellbore prior to generating steam.

44. The method of claim 39, wherein the additional fluids comprise bitumen and water.