CA2698564A1

CA2698564A1 - In situ oxidation of subsurface formations

Info

Publication number: CA2698564A1
Application number: CA2698564A
Authority: CA
Inventors: Gary Lee Beer; Li Busheng; Weijian Mo
Original assignee: Shell Internationale Research Maatschappij B.V.; Gary Lee Beer; Li Busheng; Weijian Mo
Current assignee: Shell Internationale Research Maatschappij BV
Priority date: 2007-10-19
Filing date: 2008-10-13
Publication date: 2009-04-23
Anticipated expiration: 2028-10-13
Also published as: GB201004134D0; RU2010119957A; EP2201819A4; GB2465911A; US20090200025A1; MA31856B1; US8162059B2; US20090194333A1; RU2465624C2; JP2011501003A; RU2477368C2; US20090200031A1; US7866388B2; GB2464906B; WO2009052054A1; JP5551600B2; US8146661B2; RU2010119955A; US20090194329A1; CA2700737A1

Abstract

Methods and systems for treating a hydrocarbon containing formation described herein include providing heat to a first portion of the formation from a plurality of heaters in the first portion, producing fluids through one or more production wells in a second portion of the formation, reducing or turning off heat provided to the first portion after a selected time, providing an oxidizing fluid through one or more of the heater wells in the first portion, providing heat to the first portion and the second portion through oxidation of at least some hydrocarbons in the first portion, and producing fluids through at least one of the production wells in the second portion. At least two of the heaters may be located in heater wells in the first portion. The second portion may be substantially adjacent to the first portion. The produced fluids may include at least some oxidized hydrocarbons produced in the first portion.

Description

IN SITU OXIDATION OF SUBSURFACE FORMATIONS
BACKGROUND
Field of the Invention [001] The present invention relates generally to methods and systems for production of hydrocarbons, hydrogen, and/or other products from various subsurface formations such as hydrocarbon containing formations (for example, tar sands formations).
Description of Related Art [002] Hydrocarbons obtained from subterranean formations are often used as energy resources, as feedstocks, and as consumer products. Concerns over depletion of available hydrocarbon resources and concerns over declining overall quality of produced hydrocarbons have led to development of processes for more efficient recovery, processing and/or use of available hydrocarbon resources. In situ processes may be used to remove hydrocarbon materials from subterranean formations. Chemical and/or physical properties of hydrocarbon material in a subterranean formation may need to be changed to allow hydrocarbon material to be more easily removed from the subterranean formation. The chemical and physical changes may include in situ reactions that produce removable fluids, composition changes, solubility changes, density changes, phase changes, and/or viscosity changes of the hydrocarbon material in the formation. A fluid may be, but is not limited to, a gas, a liquid, an emulsion, a slurry, and/or a stream of solid particles that has flow characteristics similar to liquid flow.

[003] 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.

[004] In situ production of hydrocarbons from tar sand may be accomplished by heating and/or injecting a gas into the formation. U.S. Patent Nos. 5,211,230 to Ostapovich et al.
and 5,339,897 to Leaute describe horizontal production wells located in oil-bearing reservoirs. Vertical conduits may be used to inject an oxidant gas into the reservoir for in situ combustion.

[005] U.S. Patent No. 2,780,450 to Ljungstrom describes heating bituminous geological formations in situ to convert or crack a liquid tar-like substance into oils and gases.

[006] U.S. Patent No. 4,597,441 to Ware et al. describes contacting oil, heat, and hydrogen simultaneously in a reservoir. Hydrogenation may enhance recovery of oil from the reservoir.

[007] U.S. Patent Nos. 5,046,559 to Glandt and 5,060,726 to Glandt et al.
describe preheating portions of tar sand formations between injector wells and producer wells.
Steam may be injected from the injector wells into the formation to produce hydrocarbons at the producer wells.

[008] As outlined above, there has been a significant amount of effort to develop methods and systems to economically produce hydrocarbons, hydrogen, and/or other products from hydrocarbon containing formations. At present, however, there are still many hydrocarbon containing formations from which hydrocarbons, hydrogen, and/or other products cannot be economically produced. For example, production of hydrocarbons from a subsurface formation may produce coke and/or residual hydrocarbons in the formation.
Production and/or processing of the coke and/or residual hydrocarbons may not be economical feasible. Thus, there is still a need for improved methods and systems for production of hydrocarbons, hydrogen, and/or other products from various hydrocarbon containing formations.

SUMMARY

[009] Embodiments described herein generally relate to systems and/or methods for treating a subsurface formation.

[010] This invention advantageously provides a method for treating a hydrocarbon containing formation, comprising: providing heat to a first portion of the formation from a plurality of heaters in the first portion, at least two of the heaters being located in heater wells in the first portion; producing fluids through one or more production wells in a second portion of the formation, the second portion being at least partially substantially adjacent to the first portion; reducing or turning off the heat provided to the first portion after a selected time; providing an oxidizing fluid through one or more of the heater wells in the first portion; providing heat to the first portion and the second portion through oxidation of at least some hydrocarbons in the first portion, and movement of fluid heated by such oxidation from the first portion to the second portion; and producing fluids through at least one of the production wells in the second portion, the produced fluids comprising at least some oxidized hydrocarbons produced in the first portion.

[011] The invention provides a method for treating a subsurface formation, comprising:
heating a first portion from one or more heaters located in the first portion;
producing hydrocarbons from the first portion; reducing or turning off the heat provided to the first portion after a selected time; injecting an oxidizing fluid in the first portion to cause a temperature of the first portion to increase sufficiently to oxidize hydrocarbons in the first portion and a third portion, the third portion being substantially below the first portion;
heating a second portion from heat transferred from the first portion and/or third portion and/or one or more heaters located in the second portion such that an average temperature in the second portion is at least about 100 C, wherein the second portion is substantially adjacent to the first portion; allowing hydrocarbons to flow from the second portion into the first portion and/or third portion; reducing or discontinuing injection of the oxidizing fluid in the first portion; and producing additional hydrocarbons from the first portion of the formation, the additional hydrocarbons comprising oxidized hydrocarbons from the first portion, at least some hydrocarbons from the second portion, at least some hydrocarbons from the third portion of the formation, or mixtures thereof, and wherein a temperature of the first portion is below 600 C.

[012] The invention provides a method for treating a subsurface formation, comprising:
producing hydrocarbons from a first portion and/or a third portion by an in situ heat treatment process, heating a second portion with one or more heaters to an average temperature of about 100 C; the first portion and third portion being separated by the second portion; reducing or turning off the heat provided to the first portion after a selected time; injecting an oxidizing fluid in the first portion to cause a temperature of the first portion to increase sufficiently to oxidize hydrocarbons in the first portion;
injecting and/or creating a drive fluid and/or an oxidizing fluid in the third portion to cause at least some hydrocarbons to move from the third portion through the second portion to the first portion of the hydrocarbon layer; reducing or discontinuing injection of the oxidizing fluid in the first portion; and producing additional hydrocarbons and/or syngas from the first portion of the formation, the additional hydrocarbons and/or syngas comprising at least some hydrocarbons from the second and third portions of the formation.

[013] The invention provides a method for treating a subsurface formation, comprising:
producing at least one third of hydrocarbons from a first portion by an in situ heat treatment process, wherein an average temperature of the first portion is less than 350 C;
injecting an oxidizing fluid in the first portion to cause the average temperature of the first portion to increase sufficiently to oxidize hydrocarbons in the first portion and to raise the average temperature of the first portion to greater than 350 C; and injecting a heavy hydrocarbon fluid in the first portion to from a diluent and/or drive fluid, the heavy hydrocarbon fluid comprising one or more condensable hydrocarbons.

[014] 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.

[015] In further embodiments, treating a subsurface formation is performed using any of the methods and/or systems described herein.

[016] In further embodiments, additional features may be added to the specific embodiments described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

[017] 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:

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

[019] FIG. 2 depicts a schematic of an embodiment of a first stage of treating a tar sands formation with heaters.

[020] FIG. 3 depicts a schematic of an embodiment of a second stage of treating the tar sands formation with fluid injection and oxidation.

[021] FIG. 4 depicts a schematic of an embodiment of a third stage of treating the tar sands formation with fluid injection and oxidation.

[022] FIG. 5 depicts a side view representation of a first stage of an embodiment of treating portions in a subsurface formation with heaters, oxidation and/or fluid injection.

[023] FIG. 6 depicts a side view representation of a second stage of an embodiment of treating portions in the subsurface formation with heaters, oxidation and/or fluid injection.

[024] FIG. 7 depicts a side view representation of an embodiment of treating portions in the subsurface formation with heaters, oxidation and/or fluid injection.

[025] FIG. 8 depicts an embodiment of treating a subsurface formation using a cylindrical pattern.

[026] FIG. 9 depicts an embodiment of treating multiple portions of a subsurface formation in a rectangular pattern.

[027] FIG. 10 is a schematic top view of the pattern depicted in FIG. 9.

[028] 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 of the present invention as defined by the appended claims.
DETAILED DESCRIPTION

[029] The following description generally relates to systems and methods for treating hydrocarbons in formations. Such formations may be treated to yield hydrocarbon products, hydrogen, and other products.

[030] "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.

[031] "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.

[032] "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 Hz.

[033] "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.

[034] A "formation" includes one or more hydrocarbon containing layers, one or more non-hydrocarbon layers, an overburden, and/or an underburden. "Hydrocarbon layers"
refer to layers in the formation that contain hydrocarbons. The hydrocarbon layers may contain non-hydrocarbon material and hydrocarbon material. The "overburden"
and/or the "underburden" include one or more different types of impermeable materials.
For example, the overburden and/or underburden may include rock, shale, mudstone, or wet/tight carbonate. In some embodiments of in situ heat treatment processes, the overburden and/or the underburden include a hydrocarbon containing layer or hydrocarbon containing layers that are relatively impermeable and are not subjected to temperatures during in situ heat treatment processing that result in significant characteristic changes of the hydrocarbon containing layers of the overburden and/or the underburden.
For example, the underburden may contain shale or mudstone, but the underburden is not allowed to heat to pyrolysis temperatures during the in situ heat treatment process. In some cases, the overburden and/or the underburden may be somewhat permeable.

[035] "Formation fluids" refer to fluids present in a formation and may include pyrolyzation fluid, synthesis gas, mobilized hydrocarbon, 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.

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

[037] 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.

[038] "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.

[039] 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.

[040] 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.

[041] "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.

[042] 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.

[043] 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.

[044] "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 or a portion of the formation to cause pyrolysis.

[045] "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.

[046] 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.

[047] "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.

[048] "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.

[049] "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.

[050] 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.

[051] 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.

[052] 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).

[053] In some embodiments, one or more sections are heated to temperatures that allow for pyrolysis reactions in the formation. In some embodiments, the average temperature of one or more sections of the formation may be raised to pyrolysis temperatures of hydrocarbons in the sections (for example, temperatures ranging from 230 C to 900 C, from 240 C to 400 C or from 250 C to 350 C).

[054] Heating the hydrocarbon containing formation with a plurality of heat sources may establish thermal gradients around the heat sources that raise the temperature of hydrocarbons in the formation to desired temperatures at desired heating rates. The rate of temperature increase through mobilization temperature range and/or pyrolysis temperature range for desired products may affect the quality and quantity of the formation fluids produced from the hydrocarbon containing formation. Slowly raising the temperature of the formation through the mobilization temperature range and/or pyrolysis temperature range may allow for the production of high quality, high API gravity hydrocarbons from the formation. Slowly raising the temperature of the formation through the mobilization temperature range and/or pyrolysis temperature range may allow for the removal of a large amount of the hydrocarbons present in the formation as hydrocarbon product.

[055] In some in situ heat treatment embodiments, a portion of the formation is heated to a desired temperature instead of slowly heating the temperature through a temperature range. In some embodiments, the desired temperature is 300 C, 325 C, or 350 C. Other temperatures may be selected as the desired temperature.

[056] 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.

[057] 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 is raised to pyrolysis temperatures without significant production before reaching pyrolysis temperatures. Formation fluids including pyrolysis products may be produced through the production wells.

[058] In some embodiments, the average temperature of one or more sections is 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.

[059] 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 are 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.

[060] 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 may encircle all heat sources 202 used, or to be used, to heat a treatment area of the formation.

[061] 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 is 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.

[062] Production wells 206 are used to remove formation fluid from the formation. In some embodiments, production we11206 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.

[063] In some embodiments, the heat source in production we11206 allows for vapor phase removal of formation fluids from the formation. Providing heating at or through the production well may: (1) inhibit condensation and/or refluxing of production fluid when such production fluid is moving in the production well proximate the overburden, (2) increase heat input into the formation, (3) increase production rate from the production well as compared to a production well without a heat source, (4) inhibit condensation of high carbon number compounds (C6 and above) in the production well, and/or (5) increase formation permeability at or proximate the production well.

[064] 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 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.

[065] 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 15 , 20 , 25 , 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.

[066] After mobilization or pyrolysis temperatures are reached and production from the formation is allowed, pressure in the formation may be varied to alter and/or control a composition of formation fluid produced, to control a percentage of condensable fluid as compared to non-condensable fluid in the formation fluid, and/or to control an API gravity of formation fluid being produced. For example, decreasing pressure may result in production of a larger condensable fluid component. The condensable fluid component may contain a larger percentage of olefins.

[067] 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.

[068] 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.

[069] 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 is jet fuel.

[070] In certain embodiments, a subsurface formation is treated in stages. The treatment may be initiated with electrical heating with further heating generated from oxidation of hydrocarbons and hot gas production from the formation. Hydrocarbons (e.g., heavy hydrocarbons and/or bitumen) may be moved from one portion of the formation to another where the hydrocarbons are produced from the formation. By using a combination of heaters, oxidizing fluid and/or drive fluid, the overall time necessary to initiate production from a formation may be decreased relative to times necessary to initiate production using heaters and/or drive processes alone. By controlling a rate of oxidizing fluid injection and/or drive fluid injection in conjunction with heating with heaters, a relatively uniform temperature distribution may be obtained in sections (portions) of the subsurface formation.

[071] A method for treating a hydrocarbon containing formation with heaters in combination with an oxidizing fluid may include providing heat to a first portion of the formation from a plurality of heaters located in heater wells in the first portion. Fluids may be produced through one or more production wells in a second portion of the formation that is substantially adjacent to the first portion. The heat provided to the first portion may be reduced or turned off after a selected time. An oxidizing fluid may be provided through one or more of the heater wells in the first portion. Heat may be provided to the first portion and the second portion through oxidation of at least some hydrocarbons in the first portion. Fluids may be produced through at least one of the production wells in the second portion. The fluids may include at least some oxidized hydrocarbons.
Transportation fuel may be produced from the hydrocarbons produced from the first and/or second of the formation.

[072] FIG. 2 depicts a schematic of an embodiment of a first stage of treating the tar sands formation with electrical heaters. Hydrocarbon layer 214 may be separated into section 216A and section 216B. Heaters 218 may be located in section 216A.
Production wells 206 may be located in section 216B. In some embodiments, production wells 206 extend into section 216A.

[073] Heaters 218 may be used to heat and treat portions of section 216A
through conductive, convective, and/or raditativeheat transfer. For example, heaters 218 may mobilize, visbreak, and/or pyrolyze hydrocarbons in section 216A. Production wells 206 may be used to produce mobilized, visbroken, and/or pyrolyzed hydrocarbons from section 216A.

[074] FIG. 3 depicts a schematic of an embodiment of a second stage of treating the tar sands formation with fluid injection and oxidation. After at least some hydrocarbons from section 216A have been produced (for example, a majority of hydrocarbons in the section or almost all producible hydrocarbons in the section), the heater wells in section 216A may be converted to injection wells 220. In some embodiments, the heater wells are open wellbores below the overburden. In some embodiments, the heater wells are initially installed into wellbores that include perforated casings. In some embodiments, the heater wells are perforated using perforation guns after heating from the heater wells is completed.

[075] Injection wells 220 may be used to inject an oxidizing fluid (for example, air, oxygen, enriched air, or other oxidants) into the formation. In some embodiments, the oxidation includes liquid water and/or steam. The amount of oxidizing fluid may be controlled to adjust subsurface combustion patterns. In some embodiments, carbon dioxide or other fluids are injected into the formation to control heating/production in the formation. The oxidizing fluid may oxidize (combust) or otherwise react with hydrocarbons remaining in the formation (for example, coke). Water in the oxidizing fluid may react with coke and/or hydrocarbons in the hot formation to produce syngas in the formation. Production wells 206 in section 216B may be converted to heater/
gas production wells 222. Heater/gas production wells 222 may be used to produce oxidation gases and/or syngas products from the formation. Producing the hot oxidation gases and/or syngas through heater/gas production wells 222 in section 216B may heat the section to higher temperatures so that hydrocarbons in the section are mobilized, visbroken, and/or pyrolyzed in the section. Production wells 206 in section 216C may be used to produce mobilized, visbroken, and/or pyrolyzed hydrocarbons from section 216B.

[076] In certain embodiments, the pressure of the injected fluids and the pressure in formation are controlled to control the heating in the formation. The pressure in the formation may be controlled by controlling the production rate of fluids from the formation (for example, the production rate of oxidation gases and/or syngas products from heater/gas production wells 222). Heating in the formation may be controlled so that there is enough hydrocarbon volume in the formation to maintain the oxidation reactions in the formation. Heating may be controlled so that the formation near the injection wells is at a temperature that will generate desired synthesis gas if a synthesis gas generating fluid such as water is included in the oxidation fluid. Heating in the formation may also be controlled so that enough heat is generated to conductively heat the formation to mobilize, visbreak, and/or pyrolyze hydrocarbons in adjacent sections of the formation.

[077] The process of injecting oxidizing fluid and/or water in one section, producing oxidation gases and/or syngas products in an adjacent section to heat the adjacent section, and producing upgraded hydrocarbons (mobilized, visbroken, and/or pyrolyzed hydrocarbons) from a subsequent section may be continued in further sections of the tar sands formation. For example, FIG. 4 depicts a schematic of an embodiment of a third stage of treating the tar sands formation with fluid injection and oxidation.
The gas heater/producer wells in section 216B are converted to injection wells 220 to inject air and/or water. The producer wells in section 216C are converted to production wells (for example, heater/gas production wells 222) to produce oxidation gases and/or syngas products. Production wells 206 are formed in section 216D to produce upgraded hydrocarbons.

[078] In some embodiments, significant amounts of residue and/or coke remain in a subsurface formation after heating the formation with heaters and producing formation fluids from the formation. In some embodiments, sections of the formation include heavy hydrocarbons such as bitumen that are difficult to heat to mobilization temperatures adjacent to sections of the formation that are being treated using an in situ heat treatment process. Heating of heavy hydrocarbons may require high energy input, a large number of heater wells and/or increase in capital costs (for example, materials for heater construction). It would be advantageous to produce formation fluids from subsurface formations with lower energy costs, fewer heater wells and/or heater cost with improved product quality and/or recovery efficiency.

[079] In some embodiments, a method for treating a subsurface formation includes producing a at least a third hydrocarbons from a first portion by an in situ heat treatment process. An average temperature of the first portion is less than 350 C. An oxidizing fluid may be injected in the first portion to cause the average temperature in the first portion to increase sufficiently to oxidize hydrocarbon in the first portion and to raise the average temperature in the first portion to greater than 350 C. In some embodiments, the temperature of the first portion is raised to an average temperature ranging from 350 C to 700 C. A heavy hydrocarbon fluid that includes one or more condensable hydrocarbons may be injected in the first portion to from a diluent and/or drive fluid. In some embodiments, a catalyst system is added to the first portion.

[080] FIGS. 5, 6, and 7 depict side view representations of embodiments of treating a subsurface formation in stages with heaters, oxidizing fluid, catalyst, and/or drive fluid.
Hydrocarbon layer 214 may be divided into three or more treatment sections. In certain embodiments, hydrocarbon layer 214 includes five treatment sections: section 216A, section 216B, section 216C, section 216D and section 216E. Sections 216A and section 216C are separated by section 216B. Sections 216C and section 216E are separated by section 216D. Section 216A through section 216E may be horizontally displaced from each other in the formation. In some embodiments, one side of section 216A is adjacent to an edge of the treatment area of the formation or an untreated section of the formation is left on one side of section 216A before the same or a different pattern is formed on the opposite side of the untreated section.

[081] In certain embodiments, section 216A is heated to pyrolysis temperatures with heaters 218. Section 216A may be heated to mobilize and/or pyrolyze hydrocarbons in the section. In some embodiments, section 216A is heated to an average temperature of 250 C, 300 C, or up to 350 C. The mobilized and/or pyrolyzed hydrocarbons may be produced through one or more production wells 206. Once at least a third, a substantial portion, or all of the hydrocarbons have been produced from section 216A, the temperature in section 216A may be maintained at an average temperature that allows the section to be used as a reactor and/or reaction zone to treat formation fluid and/or hydrocarbons from surface facilities. Use of one or more heated portions of the formation to treat such hydrocarbons may reduce or eliminate the need for surface facilities that treat such fluids (for example, coking units and/or delayed coking units).

[082] In certain embodiments, heating and producing hydrocarbons from sections creates fluid injectivity in the sections. After fluid injectivity has been created in section 216A, an oxidizing fluid may be injected into the section. For example, oxidizing fluid may be injected in section 216A after at least a third or a majority of the hydrocarbons have been produced from the section. The fluid may be injected through heater wellbores, production wells 206, and/or injection wells located in section 216A. In some embodiments, heaters 218 continue to provide heat while the fluid is being injected. In certain embodiments, heaters 218 may be turned down or off before or during fluid injection.

[083] During injection of oxidant, excess oxidant and/or oxidation products may be removed from section 216A through one or more production wells 206 and/or heater/gas production wells. In some embodiments, after the formation is raised to a desired temperature, a second fluid may be introduced into section 216A. The second fluid may be water and/or steam. Addition of the second fluid may cool the formation. For example, when the second fluid is steam and/or water, the reactions of the second fluid with coke and/or hydrocarbons are endothermic and produce synthesis gas. In some embodiments, oxidizing fluid is added with the second fluid so that some heating of section 216A occurs simultaneous with the endothermic reactions. In some embodiments, section 216A
is treated in alternating steps of adding oxidant and second fluid to heat the formation for selected periods of time.

[084] In certain embodiments, the pressure of the injected fluids and the pressure section 216A are controlled to control the heating in the formation. The pressure in section 216A
may be controlled by controlling the production rate of fluids from the section (for example, the production rate of hydrocarbons, oxidation gases and/or syngas products).
Heating in section 216A may be controlled so that section reaches a desired temperature (e.g., temperatures of at least 350 C, of at least about 400 C, or at least about 500 C, about 700 C, or higher). Injection of the oxidizing fluid may allow portions of the formation below the section heated by heaters to be heated, thus allowing heating of formation fluids in deeper and/or inaccessible portions of the formation. The control of heat and pressure in the section may improve efficiency and quality of products produced from the formation.

[085] During heating and/or after heating of section 216A, heavy hydrocarbons with low economic value and/or waste hydrocarbon streams from surface facilities may be injected in the section. Low economic value hydrocarbons and/or waste hydrocarbon streams may include, but are not limited to, hydrocarbons produced during surface mining operations, residue, bitumen and/or bottom extracts from bitumen mining. In some embodiments, hydrocarbons produced from section 216A or other sections of the formation may be introduced into section 216A. In some embodiments, one or more of the heater wells in section 216A are converted to injection wells.

[086] Heating of hydrocarbons and/or coke in section 216A may generate drive fluids.
Generated drive fluids in section 216A may include air, steam, carbon dioxide, carbon monoxide, hydrogen, methane, pyrolyzed hydrocarbons and/or in situ diluent. In some embodiments, hydrocarbon fluids are introduced into section 216A prior to injecting an oxidizing fluid and/or the second fluid. Oxidation and/or thermal cracking of introduced hydrocarbon fluids may create the drive fluid.

[087] In some embodiments, drive fluid may be injected into the formation. The addition of oxidizing fluid, steam, and/or water in the drive fluid may be used to control temperatures in section 216A. For example, the addition of hydrocarbons to section 216A
may cool the average temperature in section 216A to a temperature below temperatures that allow for cracking of the introduced hydrocarbons. Oxidizing fluid may be injected to increase and/or maintain the average temperature between 250 C and 700 C or between 350 C and 600 C. Maintaining the temperature between 250 C and 700 C may allow for the production of high quality hydrocarbons from the low value hydrocarbons and/or waste streams. Controlling the input of hydrocarbons, oxidizing fluid, and/or drive fluid into section 216A may allow for the production of condensable hydrocarbons with a minimal amount non-condensable gases. In some embodiments, controlling the input of hydrocarbons, oxidizing fluid, and/or drive fluid into section 216A may allow for the production of large amounts of non-condensable hydrocarbons and/or hydrogen with minimal amounts of condensable hydrocarbons.

[088] In some embodiments, a catalyst system is introduced to section 216A
when the section is at a desired temperature (for example, a temperature of at least 350 C, at least 400 C, or at least 500 C). In some embodiments, the section is heated after and/or during introduction of the catalyst system. The catalyst system may be provided to the formation by injecting the catalyst system into one or more injection wells and/or production wells in section 216A. In some embodiments, the catalyst system is positioned in wellbores proximate the section of the formation to be treated. The catalyst may be provided to section 216A as a slurry and/or a solution in sufficient quantity to allow the catalyst to be dispersed in the section. For example, the catalyst system may be dissolved in water and/or slurried in an emulsion of water and hydrocarbons. At temperatures of at least 100 C, at least 200 C, or at least 250 C, vaporization of water from the solution allows the catalyst to be dispersed in the rock matrix of section 216A.

[089] The catalyst system may include one or more catalysts. The catalysts may be supported or unsupported catalysts. Catalysts include, but are not limited to, alkali metal carbonates, alkali metal hydroxides, alkali metal hydrides, alkali metal amides, alkali metal sulfides, alkali metal acetates, alkali metal oxalates, alkali metal formates, alkali metal pyruvates, alkaline-earth metal carbonates, alkaline-earth metal hydroxides, alkaline-earth metal hydrides, alkaline-earth metal amides, alkaline-earth metal sulfides, alkaline-earth metal acetates, alkaline-earth metal oxalates, alkaline-earth metal formates, alkaline-earth metal pyruvates, or commercially available fluid catalytic cracking catalysts, dolomite, silicon-alumina catalyst fines, zeolites, zeolite catalyst fines any catalyst that promotes formation of aromatic hydrocarbons, or mixtures thereof.

[090] In some embodiments, fractions from surface facilities include catalyst fines.
Surface facilities may include catalytic cracking units and/or hydrotreating units. These fractions may be injected in section 216A to provide a source of catalyst for the section.
Injection of the fractions in section 216A may provide an advantageous method for disposal and/or upgrading of the fractions as compared to conventional disposal methods for fractions containing catalyst fines.

[091] After injecting catalyst in section 216A, the average temperature in section 216A
may be increased or maintained in a range from about 250 C to about 700 C, from about 300 C to about 650 C, or from about 350 C to about 600 C by injection of reaction fluids (for example, oxidizing fluid, steam, water and/or combinations thereof). In some embodiments, heaters 218 are used to raise or maintain the temperature in section 216A in the desired range. In some embodiments, heaters 218 and the introduction of reaction fluids into section 216A are used to raise or maintain the temperature in the desired range.
Hydrocarbon fluids may be introduced in section 216A once the desired temperature is obtained. In some embodiments, the catalyst system is slurried with a portion of the hydrocarbons, and the slurry is introduced to section 216A. In some embodiments, a portion of the hydrocarbon fluids are introduced to section 216A prior to introduction of the catalyst system. The introduced hydrocarbon fluids may be hydrocarbons in formation fluid from an adjacent portion of the formation, and/or low value hydrocarbons. The hydrocarbons may contact the catalyst system to produce desirable hydrocarbons (for example, visbroken hydrocarbons, cracked hydrocarbons, aromatic hydrocarbons, or mixtures thereof). The desired temperature in section 216A may be maintained by turning on heaters in the section and/or continuous injection of oxidizing fluid to cause exothermic reactions that heat the formation.

[092] In some embodiments, hydrocarbons produced through thermal and/or catalytic treatment in section 216A may be used as a diluent and/or a solvent in the section. The produced hydrocarbons may include aromatic hydrocarbons. The aromatic enriched diluent may dilute or solubilize a portion of the heavy hydrocarbons in section 216A and/or other sections in the formation (for example, sections 216B and/or 216C) and form a mixture. The mixture may be produced from the formation (for example, produced from sections 216A and/or 216C). In some embodiments, the mixture is produced from section 216B. In some embodiments, the mixture drains to a bottom portion of the section and solubilizes additional hydrocarbons at the bottom of the section. Solubilized hydrocarbons may be produced or mobilized from the formation. In some embodiments, fluids produced in section 216A (for example, diluent, desirable products, oxidized products, and/or solubilized hydrocarbons) may be pushed towards section 216B as shown by the arrows in FIG. 5 by oxidizing fluid, drive fluid, and/or created drive fluid.

[093] In some embodiments, the temperatures in section 216A and the generation of drive fluid in section 216A increases the pressure of section 216A so the drive fluid pushes fluids through section 216B into section 216C. Hot fluids flowing from section 216A
into section 216B may melt, solubilize, visbreak and/or crack fluids in section 216B sufficiently to allow the fluids to move to section 216C. In section 216C, the fluids may be upgraded and/or produced through production wells 206.

[094] In some embodiments, a portion of the catalyst system from section 216A
enters section 216B and/or section 216C and contacts fluids in the sections. Contact of the catalyst with formation fluids in 216B and/or section 216C may result in the production of hydrocarbons having a lower API gravity than the mobilized fluids.

[095] The fluid mixture formed from contact of hydrocarbons, formation fluid and/or mobilized fluids with the catalyst system may be produced from the formation.
The liquid hydrocarbon portion of the fluid mixture may have an API gravity between 10 and 25 , between 12 and 23 or between 15 and 20 . In some embodiments, the produced mixture has at most 0.25 grams of aromatics per gram of total hydrocarbons. In some embodiments, the produced mixture includes some of the catalysts and/or used catalysts.

[096] In some embodiments, contact of the hydrocarbon fluids with the catalyst system produces coke in 216A. Oxidizing fluid may be introduced into section 216A.
The oxidizing fluid may react with the coke to generate heat that maintains the average temperature of section 216A in a desired range. For some time intervals, additional oxidizing fluid may be added to section 216A to increase the oxidation reactions to regenerate catalyst in the section. The reaction of the oxidizing fluid with the coke may reduce the amount of coke and heat formation and/or catalyst to temperatures sufficient to remove impurities on the catalyst. Coke, nitrogen containing compounds, sulfur containing compounds, and/or metals such as nickel and/or vanadium may be removed from the catalyst. Removing impurities from the catalyst in situ may enhance catalyst life. After catalyst regeneration, introduction of reaction fluids may be adjusted to allow section 216A
to return to an average temperature in the desired temperature range. The average temperature in section 216A may the controlled to be in range from about 250 C to about 700 C. Hydrocarbons may be introduced in section 216A to continue the cycle.
Additional catalyst systems may be introduced into the formation as needed.

[097] A method for treating a subsurface formation in stages may include using an in situ heat treatment process in combination with injection of an oxidizing fluid and/or drive fluid in one or more portions (sections) of the formation. In some embodiments, hydrocarbons are produced from a first portion and/or a third portion by an in situ heat treatment process. A second portion that separates the first and third portions may be heated with one or more heaters to an average temperature of at least about 100 C. The heat provided to the first portion may be reduced or turned off after a selected time.
Oxidizing fluid may be injected in the first portion to oxidize hydrocarbons in the first portion and raise the temperature of the first portion. A drive fluid and/or additional oxidizing fluid may be injected and/or created in the third portion to cause at least some hydrocarbons to move from the third portion through the second portion to the first portion of the hydrocarbon layer. Injection of the oxidizing fluid in the first portion may be reduced or discontinued and additional hydrocarbons and/or syngas may be produced from the first portion of the formation. The additional hydrocarbons and/or syngas may include at least some hydrocarbons from the second and third portions of the formation.
Transportation fuel may be produced from the hydrocarbons produced from the first, second and/or third portions of the formation. In some embodiments, a catalyst system is provided to the first portion and/or third portion.

[098] In certain embodiments, sections 216A and 216C are heated at or near the same time to similar temperatures (for example, pyrolysis temperatures) with heaters 218.
Sections 216A and 216C may be heated to mobilize and/or pyrolyze hydrocarbons in the sections. The mobilized and/or pyrolyzed hydrocarbons may be produced (for example, through one or more production wells 206) from section 216A and/or section 216C.
Section 216B may be heated to lower temperatures (for example, mobilization temperatures) by heaters 218. Sections 216D and 216E may not be heated. Little or no production of hydrocarbons to the surface may take place through section 216B, section 216D and/or section 216E. For example, sections 216A and 216C may be heated to average temperatures of at least about 300 C or at least about 330 C while section 216B
is heated to an average temperature of at least about 100 C, sections 216D
and 216E are not heated and no production wells are operated in section 216B, section 216D, and/or section 216E. In some embodiments, heat from section 216A and/or section 216C
transfers to sections section 216D and/or section 216E.

[099] In some embodiments, heavy hydrocarbons in section 216B may be heated to mobilization temperatures and flow into sections 216A and 216C. The mobilized hydrocarbons may be produce from production wells 206 in sections 216A and 216C.
After some or most of the fluids have been produced from sections 216A and 216C, production of formation fluids in the sections may be slowed and/or discontinued.

[0100] In certain embodiments, heating and producing hydrocarbons from sections 216A
and 216C creates fluid injectivity in the sections. After fluid injectivity has been created in section 216C, an oxidizing fluid may be injected into the section. For example, oxidizing fluid may be injected in section 216C after a majority of the hydrocarbons have been produced from the section. The fluid may be injected through heaters 218, production wells 206, and/or injection wells located in section 216C. In some embodiments, heaters 218 continue to provide heat while the fluid is being injected. In certain embodiments, heaters 218 may be turned down or off before or during fluid injection.

[0101] During injection of oxidant, excess oxidant and/or oxidation products may be removed from section 216C through one or more production wells 206 and/or heater/gas production wells. In some embodiments, after the formation is raised to a desired temperature, a second fluid may be introduced into section 216C. The second fluid may be steam and/or water. Addition of the second fluid may cool the formation. For example, when the second fluid is steam and/or water, the reactions of the second fluid with coke and/or hydrocarbons are endothermic and produce synthesis gas. In some embodiments, oxidizing fluid is added with the second fluid so that some heating of section 216C occurs simultaneous with the endothermic reactions. In some embodiments, section 216C
is treated in alternating steps of adding oxidant and second fluid to heat the formation for selected periods of time.

[0102] In certain embodiments, the pressure of the injected fluids and the pressure section 216C are controlled to control the heating in the formation. The pressure in section 216C
may be controlled by controlling the production rate of fluids from the section (for example, the production rate of hydrocarbons, oxidation gases and/or syngas products).
Heating in section 216C may be controlled so that there is enough hydrocarbon volume in the section to maintain the oxidation reactions in the formation. Heating and/or pressure in section 216C may also be controlled (for example, by producing a minimal amount of hydrocarbons, oxidation gases and/or syngas products) so that enough pressure is generated to create fractures in sections adjacent to the section (for example, creation of fractures in section 216B). Creation of fractures in adjacent sections may allow fluids from adjacent sections to flow into section 216C and cool the section. Injection of oxidizing fluid may allow portions of the formation below the section heated by heaters to be heated, thus allowing heating of formation fluids in deeper and/or inaccessible portions of the subsurface to be accessed. Section 216C may be cooled from temperatures that promote syngas production to temperatures that promote formation of visbroken and/or upgrade products. Such control of heat and pressure in the section may improve efficiency and quality of products produced from the formation.

[0103] During heating of section 216C or after the section has reached a desired temperature (e.g., temperatures of at least 300 C, at least about 400 C, or at least about 500 C), an oxidizing fluid and/or a drive fluid may be injected and/or created in section 216A. The drive fluid includes, but is not limited to, steam, water, hydrocarbons, surfactants, polymers, carbon dioxide, air, or mixtures thereof. In some embodiments, the catalyst system described herein is injected in section 216A. In some embodiments, the catalyst system is injected prior to injecting the oxidizing fluid. In some embodiments, production of fluid from section 216A is discontinued prior to injecting fluids in the section. In some embodiments, heater wells in section 216A are converted to injection wells.

[0104] In some embodiments, drive fluids are created in section 216A. Created drive fluids may include air, steam, carbon dioxide, carbon monoxide, hydrogen, methane, pyrolyzed hydrocarbons and/or diluent. In some embodiments, hydrocarbons (for example, hydrocarbons produced from section 216A and/or section 216C, low value hydrocarbons and/or or waste hydrocarbon streams) are provided as a portion of the drive fluid. In some embodiments, hydrocarbons are introduced into section 216A
prior to injecting an oxidizing fluid and/or the second fluid. Oxidation, catalytic cracking, and/or thermal cracking of introduced hydrocarbon fluids may create the drive fluid and/or a diluent.

[0105] In some embodiments, oxidizing fluid, steam or water are provided as a portion of the drive fluid. The addition of oxidizing fluid, steam, and/or water in the drive fluid may be used to control temperatures in the sections. For example, the addition of steam or water may be cool the section. In some embodiments, water injected as the drive fluid is turned into steam in the formation due to the higher temperatures in the formation. The conversion of water to steam may be used to reduce temperatures or maintain temperatures in the sections between 270 C and 450 C. Maintaining the temperature between and 450 C may produce higher quality hydrocarbons and/or generate a minimal amount of non-condensable gases.

[0106] Residual hydrocarbons and/or coke in section 216A may be melted, visbroken, upgraded and/or oxidized to produce products that may be pushed towards section 216B as shown by the arrows in FIG. 5. In some embodiments, the temperature in section and the generation of drive fluid in section 216A may increase the pressure of section 216A so the drive fluid pushes fluids through section 216B into section 216C.
Hot fluids flowing from section 216A into section 216B may melt and/or visbreak fluids in section 216B sufficiently to allow the fluids to move to section 216C. In section 216C, the fluids may be upgraded and/or produced through production wells 206.

[0107] In some embodiments, oxidizing fluid injected in section 216A is controlled to raise the average temperature in the section to a desired temperature (for example, at least about 350 C, or at least about 450 C). Injection of oxidizing fluid and/or drive fluid in section 216A may continue until most or a substantial portion of the fluids from section 216A are moved through section 216B to section 216C. After a period of time, injection of oxidant and/or drive fluid into 216A is slowed and/or discontinued.

[0108] Injection of oxidizing fluid into section 216C may be slowed or stopped during injection and/or creation of drive fluid and/or creation of diluent in section 216A. In some embodiments, injection of oxidizing fluid in section 216C is continued to maintain an average temperature in the section of about 500 C during injection and/or creation of drive fluid and/or diluent in section 216A. In some embodiments, the catalyst system is injected in section 216C.

[0109] As section 216A and/or section 216C are treated with oxidizing fluid, heaters in sections 216D and 216E may be turned on. In some embodiments, section 216D is heated through conductive heat transfer from section 216C and/or convective heat transfer.
Section 216E may be heated with heaters. For example, an average temperature in section 216E may be raised to above 300 C while an average temperature in section 216D is maintained between 80 C and 120 C (for example, at about 100 C).

[0110] As temperatures in section 216E reach a desired temperature (for example, above 300 C), production of formation fluids from section 216E through production wells 206 may be started. The temperature may be reached before, during or after oxidizing fluid and/or drive fluid is injected and/or drive fluid and/or diluent is created in section 216A.

[0111] Once the desired temperature in section 216E has been obtained (for example, above 300 C, or above 400 C), production may be slowed and/or stopped in section 216C
and oxidation fluid and/or drive fluid is injected and/or created in section 216C to move fluids from section 216C through cooler section 216D towards section 216E as shown by the arrows in FIG. 6. Injection and/or creation of additional oxidation fluid and/or drive fluid in section 216C may upgrade hydrocarbons from section 216B that are in section 216C and/or may move fluids towards section 216E.

[0112] In some embodiments, heaters in combination with heating produced by oxidizing hydrocarbons in sections 216A, 216C and/or section 216E allows for a reduction in the number of heaters to be used in the sections and/or less capital costs as heaters made of less expensive materials may be used. The heating pattern may be repeated through the formation.

[0113] In some embodiments, fluids in hydrocarbon layer 214 (for example, layers in a tar sands formation) may preferentially move horizontally within the hydrocarbon layer from the point of injection because the layers tend to have a larger horizontal permeability than vertical permeability. The higher horizontal permeability allows the injected fluid to move hydrocarbons between sections preferentially versus fluids draining vertically due to gravity in the formation. Providing sufficient fluid pressure with the injected fluid may ensure that fluids are moved from section 216A through section 216B into section 216C for upgrading and/or production or from section 216C through section 216D into section 216E
for upgrading and/or production. Increased heating in sections 216A, 216C, and 216E may mobilize fluids from sections 216B and 216D into adjacent sections. Increased heating may also mobilize fluids below section 216A through 216E and the fluid may flow from the colder sections into the heated sections for upgrading and/or production due to pressure gradients established by producing fluid from the formation. In some embodiments, one or more production wells are placed in the formation below sections 216A through 216E to facilitate production of additional hydrocarbons.

[0114] In some embodiments, after sections 216A and 216C are heated to desired temperatures, the oxidizing fluid is injected into section 216C to increase the temperature in the section. The fluids in section 216C may move through section 216B into section 216A as indicated by the arrows in FIG. 7. The fluids may be produced from section 216A. Once a majority of the fluids have been produced from section 216A, the treatment process described in FIGS. 5 and 6 may be repeated.

[0115] In some embodiments, treating a formation in stages includes heating a first portion from one or more heaters located in the first portion. Hydrocarbons may be produced from the first portion. Heat provided to the first portion may be reduced or turned off after a selected time. A second portion may be substantially adjacent to the first portion. An oxidizing fluid may be injected in the first portion to cause a temperature of the first portion to increase sufficiently to oxidize hydrocarbons in the first portion and a third portion, the third portion being substantially below the first portion. The second portion may be heated from heat provided from the first portion and/or third portion and/or one or more heaters located in the second portion such that an average temperature in the second portion is at least about 100 C. Hydrocarbons may flow from the second portion into the first portion and/or third portion. Injection of the oxidizing fluid may be reduced or discontinued in the first portion. The temperature of the first portion may cool to below 600 C to 700 C and additional hydrocarbons may be produced from the first portion of the formation. The additional hydrocarbons may include oxidized hydrocarbons from the first portion, at least some hydrocarbons from the second portion, at least some hydrocarbons from the third portion of the formation, or mixtures thereof.
Transportation fuel may be produced from the hydrocarbons produced from the first, second and/or third portions of the formation.

[0116] In some embodiments, in situ heat treatment followed by oxidation and/or catalyst addition as described for horizontal sections is performed in vertical sections of the formation. Heating a bottom vertical layer followed by oxidation may create microfractures in middle sections thus allowing heavy hydrocarbons to flow from the "cold" middle section to the warmer bottom section. Lighter fluids may flow into the top section and continue to be upgraded and/or produced through production wells.
In some embodiments, two vertical sections are treated with heaters followed by oxidizing fluid.

[0117] In some embodiments, heaters in combination with an oxidizing fluid and/or drive fluid are used in various patterns. For example, cylindrical patterns, square patterns, or hexagonal patterns may be used to heat and produce fluids from a subsurface formation.
FIGS. 8 and 9, depict various patterns for treatment of a subsurface formation. FIG. 8 depicts an embodiment of treating a subsurface formation using a cylindrical pattern. FIG.
9 depicts an embodiment of treating multiple sections of a subsurface formation in a rectangular pattern. FIG. 10 is a schematic top view of the pattern depicted in FIG. 9.

[0118] Hydrocarbon layer 214 may be separated into section 216A and section 216B.
Section 216A represents a section of the subsurface formation that is to be produced using an in situ heat treatment process. Section 216B represents a section of formation that surrounds section 216A and is not heated during the in situ heat treatment process. In certain embodiments, section 216B has a larger volume than section 216A and/or section 216C. Section 216A may be heated using heaters 218 to mobilize and/or pyrolyze hydrocarbons in the section. The mobilized and/or pyrolyzed hydrocarbons may be produced (for example, through one or more production wells 206) from section 216A.
After some or all of the hydrocarbons in section 216A have been produced, an oxidizing fluid may be injected into the section. The fluid may be injected through heaters 218, a production well, and/or an injection well located in section 216A. In some embodiments, at least a portion of heaters 218 are used and/or converted to injection wells. In some embodiments, heaters 218 continue to provide heat while the fluid is being injected. In other embodiments, heaters 218 may be turned down or off before or during fluid injection.

[0119] In some embodiments, providing oxidizing fluid such as air to section 216A causes oxidation of hydrocarbons in the section and in portions of section 216C. In some embodiments, treatment of section 216A with the heaters creates coked hydrocarbons and formation with substantially uniform porosity and/or substantially uniform injectivity so that heating of the section is controllable when oxidizing fluid is introduced to the section.
The oxidation of hydrocarbons in section 216A will maintain the average temperature of the section or increase the average temperature of the section to higher temperatures (for example, above 400 C, above 500 C, above 600 C, or higher).

[0120] In some embodiments, an average temperature of section 216C that is located below section 216A increases due to heat generated through oxidation of hydrocarbons and/or coke in section 216A. For example, an average temperature in section 216C may increase from formation temperature to above 500 C. As the average temperature in section 216A and/or section 216C increases through oxidation reactions, the temperature in section 216B increases and fluids may be mobilized towards section 216A as shown by the arrows in FIGS. 8 and 9. In some embodiments, section 216B is heated by heaters to an average temperature of at least about 100 C.

[0121] In section 216A, mobilized hydrocarbons are oxidized and/or pyrolyzed to produce visbroken, oxidized, pyrolyzed products. For example, cold bitumen in section 216B may be heated to mobilization temperature of at least about 100 C so that it flows into section 216A and/or section 216C. In section 216A and/or section 216C, the bitumen is pyrolyzed to produce formation fluids. Fluids may be produced through production wells 206 and/or heater/gas production wells in section 216A. In some embodiments, no fluids are produced from section 216A during oxidation. Injection of oxidizing fluid may be reduced or discontinued in section 216A once a desired temperature is reached (for example, a temperature of at least 350 C, at least 300 C, or above 450 C). Once oxidizing fluid is slowed and/or discontinued in sections 216A, 216C, the sections may cool (e.g.
to temperatures below about 700 C, about 600 C, below 500 C or below 400 C) and remain at upgrading and/or pyrolysis temperatures for a period of time. Fluids may continue to be upgraded and may be produced from section 216A through production wells.

[0122] In certain embodiments, section 216B and/or section 216D as described in reference to FIGS. 2-10 has a larger volume than section 216A, section 216C, and/or section 216E. Section 216B and/or section 216D 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 216B and/or section 216D (the section is heated to lower temperatures), having a larger volume in section 216B and/or section 216D reduces the total energy input to the formation per unit volume. The desired volume of section 216B and/or section 216D may depend on factors such as, but not limited to, viscosity, oil saturation, and permeability. In addition, the degree of coking is much less in section 216B
and/or section 216D due to the lower temperature so less hydrocarbons are coked in the formation when section 216B and/or section 216D has a larger volume. In some embodiments, the lower degree of heating in section 216B and/or section 216D
allows for cheaper capital costs as lower temperature materials (cheaper materials) may be used for heaters used in section 216B and/or section 216D.

[0123] Using the remaining hydrocarbons for heat generation and only using electrical heating for the initial heating stage may improve the overall energy use efficiency of treating the formation. Using electrical heating only in the initial step may decrease the electrical power needs for treating the formation. In addition, forming wells that are used for the combination of production, injection, and heating/gas production may decrease well construction costs. In some embodiments, hot gases produced from the formation are provided to turbines. Providing the hot gases to turbines may recover some energy and improve the overall energy use efficiency of the process used to treat the formation.

[0124] Treating the subsurface formation, as shown by the embodiments of FIGS.
2, 3, 4, 5, 6, 7, and 8 may utilize carbon remaining after production of mobilized, visbroken, and/or pyrolyzed hydrocarbons for heat generation in the formation. In some embodiment, treating hydrocarbons in the subsurface formation, as shown in by the embodiments in FIGS. 2-8 creates products having economic value from hydrocarbons having low economic value and/or from waste hydrocarbon streams from surface facilities.

[0125] 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 fluid" includes mixtures of fluids.

[0126] Further modiflcations and alternative embodiments of various aspects of the invention will be apparent to those skilled in the art in view of this description.
Accordingly, this description is to be construed as illustrative only and is for the purpose of teaching those skilled in the art the general manner of carrying out the invention. It is to be understood that the forms of the invention shown and described herein are to be taken as the presently preferred embodiments. Elements and materials may be substituted for those illustrated and described herein, parts and processes may be reversed, and certain features of the invention may be utilized independently, all as would be apparent to one skilled in the art after having the benefit of this description of the invention. Changes may be made in the elements described herein without departing from the spirit and scope of the invention as described in the following claims.

Claims

1. A method for treating a hydrocarbon containing formation, comprising:
providing heat to a first portion of the formation from a plurality of heaters in the first portion, at least two of the heaters being located in heater wells in the first portion;
producing fluids through one or more production wells in a second portion of the formation, the second portion being at least partially substantially adjacent to the first portion;
reducing or turning off the heat provided to the first portion after a selected time;
providing an oxidizing fluid through one or more of the heater wells in the first portion;
providing heat to the first portion and the second portion through oxidation of at least some hydrocarbons in the first portion and movement of the fluids heated by such oxidation from the first portion to the second portion; and producing fluids through at least one of the production wells in the second portion, the produced fluids comprising at least some oxidized hydrocarbons produced in the first portion.

2. The method of claim 1, further comprising producing fluids comprising at least some oxidation products through one or more production wells located in a third portion of the formation, the third portion being substantially adjacent to the second portion.

3. The method of claim 1, wherein one or more of the heaters are substantially horizontal or inclined.

4. The method of claim 1, further comprising controlling the pressure in the formation to at least partially control the oxidation of hydrocarbons in the formation.

5. The method of claim 1, wherein the oxidizing fluid comprises air, and further comprising using at least some of the produced fluids to power one or more turbines at the surface of the formation.

6. The method of claim 1, further comprising heating with heaters, producing, and providing heat through oxidation to a second or additional portions of the formation in a sequential manner.

7. The method of claim 1, further comprising injecting steam into the formation.

8. A method for treating a subsurface formation, comprising:
heating a first portion from one or more heaters located in the first portion;

producing hydrocarbons from the first portion;
reducing or turning off the heat provided to the first portion after a selected time;
injecting an oxidizing fluid in the first portion to cause a temperature of the first portion to increase sufficiently to oxidize hydrocarbons in the first portion and a third portion, the third portion being substantially below the first portion;
heating a second portion from heat transferred from the first portion and/or third portion and/or one or more heaters located in the second portion such that an average temperature in the second portion is at least about 100 °C, wherein the second portion is substantially adjacent to the first portion;
allowing hydrocarbons to flow from the second portion into the first portion and/or third portion;
discontinuing or reducing injection of the oxidizing fluid in the first portion; and producing additional hydrocarbons from the first portion of the formation, the additional hydrocarbons comprising oxidized hydrocarbons from the first portion, at least some hydrocarbons from the second portion, at least some hydrocarbons from the third portion of the formation, or mixtures thereof, and wherein a temperature of the first portion is below 600 °C.

9. The method of claim 8, wherein the third portion is directly below the first portion.

10. The method of claim 8, wherein the second portion is directly adjacent to the first portion.

11. The method of claim 8, wherein producing comprises producing a majority of the hydrocarbons from the formation.

12. The method of claim 8, further comprising injecting steam into the formation.

13. A method for treating a subsurface formation, comprising:
producing a majority of hydrocarbons from a first portion and/or a third portion by an in situ heat treatment process, heating a second portion with one or more heaters to an average temperature of at least about 100 °C; the first portion and third portion being separated by the second portion;
reducing or turning off the heat provided to the first portion after a selected time;
injecting an oxidizing fluid in the first portion to cause a temperature of the first portion to increase sufficiently to oxidize hydrocarbons in the first portion;

injecting an oxidizing fluid and/or a drive fluid and/or creating a drive fluid in the third portion to cause at least some hydrocarbons to move from the third portion through the second portion to the first portion of the hydrocarbon layer;
reducing or discontinuing injection of the oxidizing fluid in the first portion; and producing additional hydrocarbons and/or syngas from the first portion of the formation, the additional hydrocarbons and/or syngas comprising at least some hydrocarbons from the second and third portions of the formation.

14. The method of claim 13, wherein the oxidizing fluid comprises air and/or hydrocarbons produced from the first portion and/or the second portion.

15. The method of claim 13, wherein the drive fluid comprises steam, water, carbon dioxide, carbon monoxide, methane, pyrolyzed hydrocarbons, and/or air.

16. The method of claim 13, wherein the average temperature of the third portion ranges from 270 °C to 450 °C.

17. The method of claim 13, further comprising heating to create sufficient drive fluid in the third portion such that injecting drive fluid and/or oxidizing fluid in the third portion is discontinued.

18. The method of claim 13, further comprising heating a fourth portion and a fifth portion of the hydrocarbon formation with heaters, wherein the fourth portion is between the first and fifth portion and wherein a temperature of the fourth portion is less than a temperature than the first portion and a temperature of the fifth portion; and a producing hydrocarbons from the fifth portion.

19. The method of claim 18, further comprising reducing or discontinuing production in the fifth portion; and injecting an oxidizing fluid in the fifth portion to cause a temperature of the fifth portion to increase sufficiently to oxidize hydrocarbons in the fifth portion, wherein injecting occurs during moving hydrocarbons from the third portion to the first portion and producing additional hydrocarbons from the first portion.

20. The method of claim 18, wherein a temperature of the first portion is below 450 °C, a temperature of the fourth portion is at least about 100 °C, and a temperature of the fifth portion is at least 450 °C.

21. The method of claim 18, further comprising:
reducing or discontinuing production of additional hydrocarbons from the first portion;

injecting and/or creating a drive fluid and/or an oxidizing fluid in the first portion to cause at least some hydrocarbons to move from the first portion through the fourth portion to the fifth portion of the hydrocarbon layer;
reducing injection of the oxidizing fluid into the fifth portion; and producing additional hydrocarbons and/or syngas from the fifth portion of the formation, the additional hydrocarbons and/or syngas comprising at least some hydrocarbons from the first and fourth portions of the formation.

22. The method of claim 13, wherein the formation has a horizontal permeability that is higher than a vertical permeability so that the majority of hydrocarbons that move are moving substantially horizontally through the formation.

23. The method of claim 13, wherein the second portion has a larger volume than the first portion and/or the third portion.

24. The method of claim 13, wherein at least some of the heaters in the first portion are turned down and/or off after injecting oxidizing fluid in the first portion.

25. The method of claim 13, further comprising controlling the temperature and the pressure in the first portion and/or the third portion such that (a) at least a majority of the hydrocarbons in the first portion and/or the third portion are visbroken, (b) the pressure is below the fracture pressure of the first portion and/or the third portion, and (c) at least some hydrocarbons in the first portion and/or the third portion form a fluid comprising visbroken hydrocarbons that can be produced through a production well.

26. The method of claim 13, further comprising mobilizing at least some hydrocarbons in the second portion using heat provided from heaters located in the second portion, heat transferred from the first portion, and/or heat transferred from the third portion.

27. The method of claim 13, further comprising providing a catalyst system to the third portion prior to injecting and/or creating a drive fluid; and contacting the hydrocarbons in the third portion with the catalyst system to produce an in situ diluent.

28. The method of claim 27, wherein the in situ diluent comprises aromatic hydrocarbons;
and further comprising solubilizing bitumen and/or heavy hydrocarbons in the third portion.

29. The method of claim 13, further comprising injecting steam into the formation.

30. A method for treating a subsurface formation, comprising:

producing at least one third of hydrocarbons from a first portion of the formation by an in situ heat treatment process, wherein an average temperature of the first portion is less than 350 °C;
injecting an oxidizing fluid in the first portion to cause the average temperature of the first portion to increase sufficiently to oxidize hydrocarbons in the first portion and to raise the average temperature of the first portion to greater than 350 °C; and injecting a heavy hydrocarbon fluid in the first portion to form a diluent and/or drive fluid, the heavy hydrocarbon fluid comprising condensable hydrocarbons.

31. The method of claim 30, wherein the average temperature of the first portion is raised to a temperature ranging from 350 °C and 700 °C.

32. The method of claim 30, further comprising producing hydrocarbons fro a second portion of the formation, the second portion being substantially adjacent to the first portion.

33. The method of claim 30, further comprising producing hydrocarbons fro a second portion of the formation, the second portion being substantially adjacent to the first portion and further causing the diluent and/or drive fluid to move into the second portion, thereby mobilizing at least some hydrocarbons in the second portion.

34. The method of claim 30, further comprising using the diluent and/or drive fluid to produce additional hydrocarbons from the first portion or from a section adjacent to the first section.

35. The method of claim 30, further comprising providing a catalyst system to the first portion.

36. The method of claim 30, further comprising providing a catalyst system to the first portion, the catalyst system being adapted to catalytically crack at least a portion of the condensable hydrocarbon in the heavy hydrocarbon fluid.

37. The method of claim 30, further comprising adding a catalyst to the first portion after at lest one third of the hydrocarbons are produced from the first portion.

38. The method of claim 30, further comprising producing used catalyst from surface treatment facilities to the formation.

39. The method of claim 30, further comprising injecting steam into the formation.

40. The method of claims 1, 8, 13, and 30, further comprising using the produced fluids to make a transportation fuel.

41. A transportation fluid made using the method of claim 40.