US20090260812A1 - Methods of treating a hydrocarbon containing formation - Google Patents

Abstract

Methods of generating subsurface heat for treatment of a hydrocarbon containing formation are described herein. Methods include providing water through one or more wellbores to at least a portion of a hydrocarbon containing formation and combusting at least a portion of a fuel stream comprising hydrogen sulfide in the presence of an oxygen source in one or more heaters positioned in one of the wellbores to produce a combustion by-products stream. Heat from the combustion is transferred to a portion of the hydrocarbon containing formation. The combustion by-products stream includes one or more sulfur oxides. Heat of solution is released by contacting at least a portion of the combustion by-products stream with a portion of the water and/or a portion of water in the hydrocarbon containing formation.

Description

CROSS REFERENCE TO RELATED APPLICATIONS
• This application claims priority from U.S. Provisional Application Ser. No. 61/046,155 filed Apr. 18, 2008, which is hereby incorporated by reference in its entirety.
FIELD OF THE INVENTION
• The present invention relates to methods of treating of a hydrocarbon containing formation.
DESCRIPTION OF RELATED ART
• Hydrocarbons obtained from subterranean formations are often used as energy resources, as feedstocks, and as consumer products. Concerns over depletion of available hydrocarbon resources have led to development of processes for more efficient recovery, processing and/or use of available hydrocarbon resources.
• Hydrocarbon formations may be treated in various ways to produce formation fluids. For example, application of heat, gases, and/or liquids to hydrocarbon formations to mobilize and/or produce formation fluids has been used to more efficiently recover hydrocarbons from hydrocarbon formations.
• Hydrocarbon formations containing heavy hydrocarbons—for example, tar sands or oil shale formations—may be heated using heat treatment methods to more efficiently recover hydrocarbons from the heavy hydrocarbon containing formations. Such processes include in situ heat treatment systems, combustion fronts, and drive processes. Typically used hydrocarbon recovery drive processes include, but are not limited to, cyclic steam injection, steam assisted gravity drainage (SAGD), solvent injection, vapor solvent and SAGD, and carbon dioxide injection.
• Heaters have been used in hydrocarbon recovery drive processes to create high permeability zones (or injection zones) in hydrocarbon formations. Heaters may be used to create a mobilization geometry or production network in the hydrocarbon formation to allow fluids to flow through the formation during the drive process. For example, heaters may be used: to create drainage paths between the injection wells and production wells for the drive process; to preheat the hydrocarbon formation to mobilize fluids in the formation so that fluids and/or gases may be injected into the formation; and to provide heat to the fluids and/or gases used in the drive process within the hydrocarbon formation. Often, the amount of heat provided by such heaters is small relative to the amount of heat input from the drive process.
• Combustion of fossil fuel has been used to heat a formation, for example, by direct injection of hot fossil fuel combustion gases in the formation, by combustion of fossil fuels in the formation (e.g. in a combustion front), by heat transfer from the hot fossil fuel combustion gases to another heat transfer agent such as steam, or by use in heaters located in the hydrocarbon formation. Combustion of fossil fuels to heat a formation may take place in the formation, in a well, and/or near the surface. Combustion of fossil fuel generates carbon dioxide, an undesirable greenhouse gas, as a combustion by-product.
• Combustion of sulfur compounds has also been used to heat a hydrocarbon formation, where the sulfur containing combustion products may act as a drive fluid for the more efficient production of hydrocarbons from the hydrocarbon formation. U.S. Pat. No. 4,379,489 to Rollmann describes a method for recovery of heavy oil from a subterranean reservoir that includes burning liquid sulfur in an oxygen-containing gas underground to form sulfur dioxide. The sulfur dioxide may act as a drive fluid for the recovery of oil or it may react with limestone in the formation to form carbon dioxide, an alternate drive fluid. The pressure of the oxygen-containing gas is maintained at a pressure sufficient to keep the sulfur dioxide in the liquid state.
• An efficient, cost effective method for treating a hydrocarbon formation to more efficiently recover hydrocarbons from the hydrocarbon formation without the production of large quantities of carbon dioxide is desirable.
SUMMARY OF THE INVENTION
• The present invention is directed to a method of treating a hydrocarbon formation, comprising: providing water through one or more wellbores to at least a portion of a hydrocarbon containing formation; combusting at least a portion of a fuel stream comprising hydrogen sulfide in the presence of an oxidant in one or more heaters positioned in one of the wellbores to produce a combustion by-products stream, wherein the combustion by-products stream comprises one or more sulfur oxides; transferring heat from the combustion to a portion of the hydrocarbon containing formation; and contacting at least a portion of the combustion by-products stream with water in the hydrocarbon formation to release a heat of solution, where water contacted with the combustion by-products stream in the hydrocarbon formation may be the water provided to the hydrocarbon formation or may be water present in the hydrocarbon formation.
BRIEF DESCRIPTION OF THE DRAWINGS
• Further advantages of the present invention may become apparent to those skilled in the art with the benefit of the following detailed description of the preferred embodiments and upon reference to the accompanying drawings in which:
• FIG. 1 depicts a representation of a steam drive process.
• FIG. 2 depicts a schematic representation of an embodiment of treatment of formation fluids produced from a hydrocarbon formation.
• FIG. 3 depicts a cross-sectional representation of a portion of an embodiment of a hydrogen sulfide fueled flameless distributed combustor positioned in a vertical wellbore.
• FIG. 4 depicts a cross-sectional representation of a portion of an embodiment of a hydrogen sulfide fueled flameless distributed combustor with two fuel conduits.
• FIG. 5 depicts a cross-sectional representation of a portion of an embodiment of a hydrogen sulfide fueled flameless distributed combustor with three fuel conduits.
• FIG. 6 depicts a cross-sectional representation of a portion of an embodiment of a hydrogen sulfide fueled flameless distributed combustor with an ignition source positioned in a vertical wellbore.
• FIG. 7 depicts a cross-sectional representation of a portion of an embodiment of a hydrogen sulfide fueled burner positioned in a horizontal wellbore.
• FIG. 8 depicts a representation of an embodiment for producing hydrocarbons from a hydrocarbon containing formation using hydrogen sulfide fueled heater.
• FIG. 9 depicts a representation of a heat flux profile of a conventional steam injection process.
• FIGS. 10A and 10B depict representations of a heat flux profile of an embodiment of heating of steam using a hydrogen sulfide fueled heater.
• FIG. 11 depicts a representation of an embodiment for producing hydrocarbons using a vertical hydrogen sulfide fueled heater in combination with a horizontal steam injection well.
• While the invention is susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings. The drawings may not be to scale. It should be understood, however, that the drawings are not intended to limit the invention to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the present invention as defined by the appended claims.
DETAILED DESCRIPTION OF THE INVENTION
• The present invention is directed to providing subsurface heat to a hydrocarbon formation where the heat is generated by 1) combusting a fuel stream comprising hydrogen sulfide in a heater in the hydrocarbon formation and transferring at least a portion of the heat of combustion to the hydrocarbon formation; and 2) contacting the combustion by-products stream, which includes sulfur oxides such as sulfur dioxide, sulfur trioxide, and/or sulfuric acid, with water in the hydrocarbon formation to generate a heat of solution within the hydrocarbon formation. The water is provided to the hydrocarbon formation through a wellbore or is present in the hydrocarbon formation. The process of the present invention provides heat efficiently to the hydrocarbon formation since both the fuel steam—by combustion—and the combustion by-products—by heat of solution—transfer heat to the hydrocarbon formation. Since the fuel stream is sulfur based, production of carbon dioxide is avoided upon combustion of the sulfide components of the fuel stream, reducing the overall production of carbon dioxide of the heating process relative to processes that utilize a fuel stream comprised mostly of hydrocarbons.
• The process of oxidizing hydrogen sulfide through a combustion process to a produce sulfuric acid may have a heat value similar to methane combustion. For example, using data from “The Chemical Thermodynamics of Organic Compounds” by Stull et al.; Kreiger Publishing Company, Malabar Fla., 1987, pp. 220, 229, 230, 233 and 234, the enthalpies of reaction for the combustion of methane and hydrogen sulfide can be calculated. Combustion of methane produces carbon dioxide as a by-product, as shown by the following reaction:
• 
  CH₄+2O₂→CO₂+2H₂O(ΔH_rxn=−191.2 kcal/mol at 600° K).
• In contrast, oxidation (combustion) of hydrogen sulfide to form sulfuric acid has a calculated reaction enthalpy as shown in the following reaction:
• 
  H₂S+2O₂→H₂SO₄(ΔH_rxn=−185.4 kcal/mol at 600° K).
• More heat may be generated upon mixing the sulfuric acid in water by the heat of solution of sulfuric acid in water as shown below:
• 
  H₂SO₄+H₂O→50 wt % H₂SO₄(ΔH_dil=−14.2 kcal/mol at 298°K).
• The total amount of heat content produced from the combustion of hydrogen sulfide and the dissolution of the sulfuric acid may range from −185 kcal/mol to −206 kcal/mol depending on the amount of water used to produce the sulfuric acid. Combustion of hydrogen sulfide as a fuel instead of methane in accordance with the process of the present invention, therefore, provides heat to a hydrocarbon formation in an amount comparable to the combustion of methane while producing no carbon dioxide. Furthermore, the use of fuels containing hydrogen sulfide in the process of the present invention provides a method to dispose of waste hydrogen sulfide from other processes (for example, sour gas and/or hydrotreating effluent streams) without creating elemental sulfur.
• Terms used herein are defined as follows.
• “API gravity” refers to API gravity at 15.5° C. (60° F.). API gravity is as determined by ASTM Method D6822 or ASTM Method D1298.
• “ASTM” refers to American Standard Testing and Materials.
• 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 hydrocarbon impermeable materials. In some cases, the overburden and/or the underburden may be somewhat permeable to hydrocarbon materials.
• “Formation fluids” refer to fluids present in a formation and may include pyrolysis fluid, synthesis gas, mobilized hydrocarbons, and water (steam). Formation fluids may include hydrocarbon fluids as well as non-hydrocarbon fluids. The term “mobilized fluid” refers to fluids in a hydrocarbon containing formation that are able to flow as a result of treatment of the formation. “Produced fluids” refer to fluids removed from the formation.
• 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. “Flameless distributed combustor” refers to a substantially flameless heater where an oxidant stream and a fuel stream are mixed together over at least a portion of the distributed length of the heater at or above an auto-ignition temperature of the mixture.
• “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 compounds containing sulfur, oxygen, and nitrogen. Additional elements (for example, nickel, iron, vanadium, or mixtures thereof) may also be present in heavy hydrocarbons. 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 at least 100 centipoise at 15° C. Heavy hydrocarbons may include aromatics or other complex ring hydrocarbons.
• “Hydrocarbons” are generally defined as molecules formed primarily by carbon and hydrogen atoms. Hydrocarbons as used herein may also include metallic elements and/or other compounds that contain, but are not limited to, halogens, nitrogen, oxygen, and/or sulfur. Hydrocarbon compounds that contain sulfur are referred to as “organosulfur compounds.” 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, sulfur oxides, carbonyl sulfide, nitrogen oxide, water, ammonia, or mixtures thereof.
• “Oxidant” refers to compounds suitable to support combustion. Examples of oxidants include air, oxygen, and/or enriched air. “Enriched air” refers to air having a larger mole fraction of oxygen than air in the atmosphere. Air is typically enriched to increase combustion-supporting ability of the air.
• “SAGD” is steam assisted gravity drainage.
• “Tar” is a viscous hydrocarbon that generally has a viscosity greater than about 10,000 centipoise at 15° C. The specific gravity of tar generally is greater than 1.000. Tar may have an API gravity less than 10°.
• “Tar sands formation” refers to 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.
• “Water” refers to the liquid and vapor phases of water. For example, water, steam, super-heated steam.
• In the present invention, a fuel stream comprising hydrogen sulfide is combusted in one or more heaters positioned in a wellbore in a hydrocarbon formation, and heat from the combustion is transferred to a portion of the hydrocarbon formation. The combustion of the fuel stream produces a combustion by-products stream that comprises one or more sulfur oxides. The combustion by-product stream is contacted with water in the hydrocarbon formation to release a heat of solution into the hydrocarbon formation, further heating the hydrocarbon formation. The water with which the combustion by-products stream is contacted may be water in the hydrocarbon formation, water produced by the combustion of the fuel stream with an oxidant, or water provided through one or more wellbores to at least a portion of the hydrocarbon formation.
• In the process of the invention, water is provided through one or more wellbores to the hydrocarbon formation. The water is preferably provided through the wellbore(s) in which the fuel stream is combusted with the oxidant, so that the water may be used to regulate the heat produced by the combustion to prevent the heater from overheating.
• In an embodiment of the process of the invention, the process may be utilized in conjunction with a drive process to treat a hydrocarbon formation. Such drive processes include, but are not limited to, steam injection processes such as cyclic steam injection, SAGD, solvent injection, a vapor solvent and SAGD process, or carbon dioxide injection. The process of the invention may be used to preheat a hydrocarbon formation for a drive process, or may be used to provide heat during or after a drive process.
• FIG. 1 depicts a representation of a steam drive process in which the process of the present invention may be utilized. Hot water (steam)100 enters injection well102.Water100 may be injected at temperatures ranging from 80° C. to 500° C., preferably 100° C. to 270° C., and pressures ranging from 1 MPa to 15 MPa. Injection well102 may includeopenings104 to allowwater100 to flow and/or be pressurized intohydrocarbon layer106.Water100 provides heat to formation fluids in thehydrocarbon layer106. Heating the formation fluids may mobilize the formation fluids to promote drainage of the formation fluids towards production well108 positioned below injection well102.Formation fluid110 is produced from production well108 and transported to one or more processing facilities.
• Heaters may be positioned in the injection well102 in which a fuel stream comprising hydrogen sulfide may be combusted with an oxidant according to the process of the invention to provide further heat to the hydrocarbon formation to further mobilize theformation fluids110. Combustion by-products containing sulfur oxides may mix with the steam from the injection well in the hydrocarbon formation to provide even further heat to the hydrocarbon formation by releasing the heat of solution formed upon contact of the sulfur oxides with the steam into the hydrocarbon formation.
• In the process of the present invention, a fuel stream comprising hydrogen sulfide that is provided to a heater may produced from a hydrocarbon containing formation.FIG. 2 depicts a schematic representation of treatment of formation fluids produced from a hydrocarbon formation. Producedformation fluid110 entersfluid separation unit112 and is separated intoliquid stream114,gas stream116, andaqueous stream118. Producedformation fluid110 may obtained from a hydrocarbon formation that is primarily a gas reservoir or from a hydrocarbon formation that is primarily a liquid hydrocarbon reservoir.Liquid stream114 may be transported to other processing units and/or storage units.Gas stream116 may include, but is not limited to, hydrocarbons, carbonyl sulfide, hydrogen sulfide, sulfur oxides, organosulfur compounds, hydrogen, carbon dioxide, or mixtures thereof.Gas stream116 may entergas separation unit120 to separate at least a portion of agas hydrocarbon stream122, at least a portion of ahydrogen sulfide stream124, at least a portion of acarbon dioxide stream126, at least a portion of asulfur dioxide stream128, and at least a portion of ahydrogen stream130 from thegas stream116.
• One or more streams containing hydrogen sulfide from a variety of sources, including thegas stream116 from the hydrocarbon formation, may be combined and sent to a gas separation unit to produce the fuel stream comprising hydrogen sulfide utilized in the process of the present invention. For example, streams from gas reservoirs, liquid hydrocarbon reservoirs, and/or streams from surface facilities may be combined as a feedstream for the gas separation unit from which a hydrogen sulfide enriched gas may be separated. The resultinghydrogen sulfide stream124 may be stored and/or combined with one or more hydrogen sulfide streams produced from other gas separation units and/or other processing facilities to form a fuel stream comprising hydrogen sulfide for use in the process of the present invention.
• Gas separation units120 useful for forming the fuel stream comprising hydrogen sulfide utilized in the process of the present invention may include physical treatment systems and/or chemical treatment systems. Physical treatment systems include, but are not limited to, a membrane unit, a pressure swing adsorption unit, a liquid absorption unit, and/or a cryogenic unit. Chemical treatment systems may include units that use amines (for example, diethanolamine or di-isopropanolamine), zinc oxide, sulfolane, water, or mixtures thereof in the treatment process. In some embodiments,gas separation unit120 uses a Sulfinol gas treatment process for removal of sulfur compounds. Carbon dioxide may be removed using Catacarb® (Catacarb, Overland Park, Kans., U.S.A.) and/or Benfield (UOP, Des Plaines, Ill., U.S.A.) gas treatment processes. The gas separation unit may be a rectified adsorption and high pressure fractionation unit.
• The fuel stream comprising hydrogen sulfide used in the process of the present invention may include from 1% to 100%, from 3% to 90%, from 10% to 80%, or from 20% to 50% of hydrogen sulfide by volume, or may include at least 10%, or at least 30%, or at least 40%, or at least 50%, or at least 60%, or at least 70% hydrogen sulfide by volume. Hydrogen sulfide content in a stream may be measured using ASTM Method D2420. The fuel stream comprising hydrogen sulfide may include hydrocarbons (for example, methane, and ethane), hydrogen, carbon dioxide, or mixtures thereof. In some embodiments, the fuel may include organosulfur compounds. Examples of organosulfur compounds include, but are not limited to, methyl thiol, thiophene, thiophene compounds, carbon disulfide, carbonyl sulfide, or mixtures thereof. The use of fuels containing hydrogen sulfide and/or organosulfur compounds may allow from 0.3 moles to 1 mole of methane to be conserved per mole of atomic sulfur in the fuel. In an embodiment of the process of the invention, produced formation fluids from a hydrocarbon formation includinghydrogen sulfide stream124 in combination withgas stream116,hydrogen stream130, and/orgas hydrocarbon stream122 may be used as a fuel stream comprising hydrogen sulfide.
• The fuel stream comprising hydrogen sulfide may be dried to remove moisture to improve the combustibility of the fuel stream. For example, the fuel stream comprising hydrogen sulfide may be dried by contacting the hydrogen sulfide stream with ethylene glycol to remove water.
• In the process of the present invention, the oxidant with which the fuel stream comprising hydrogen sulfide is combusted is an oxygen-containing gas or liquid. The oxidant is preferably selected from compressed air, oxygen-enriched air, or oxygen gas. Compressed air may be provided as the oxidant in the process of the invention by compressing air by conventional air compressing processes, for example, air may be compressed by passing the air through a turbine compressor. Oxygen-enriched air, which may contain from 0.5 vol. % to 15 vol. % more oxygen than air, may be produced by compressing air and passing the compressed air through a membrane that reduces the amount of nitrogen in the air. Oxygen gas may be provided as the oxidant by conventional air separation technology.
• In some embodiments, the ratio of hydrogen sulfide to oxidant is controlled during the combustion process. By selecting the amount of hydrogen sulfide relative to the amount of oxidant present—on the basis of atomic sulfur to atomic oxygen ratio or on a stoichiometric basis—and adjusting the amount of hydrogen sulfide to the selected amount, the amount of hydrogen sulfide in the combustion and the composition of the combustion by-products produced (for example, sulfur dioxide and/or sulfur trioxide) may be controlled. The amount of the fuel stream comprising hydrogen sulfide may be controlled and/or the amount the oxidant stream may be controlled to produce a selected ratio of hydrogen sulfide to oxidant for combustion such that a preferred combustion by-product stream composition is produced.
• The amounts of the fuel stream comprising hydrogen sulfide and the oxidant stream provided for combustion in the process of the present invention may be controlled in a manner such that combustion generates substantially sulfur trioxide in the combustion by-product stream. To produce a sulfur trioxide-rich combustion by-product stream, the ratio of hydrogen sulfide to oxidant may be controlled so that excess oxidant is combusted with the fuel stream comprising hydrogen sulfide relative to the hydrogen sulfide content of the fuel stream. Combusting a hydrogen sulfide lean mixture produces more sulfur trioxide than sulfur dioxide as a combustion by-product. The sulfur trioxide may react with water in the hydrocarbon formation to form sulfuric acid. Sulfur trioxide is readily converted to sulfuric acid, thus heat of solution may be produced and delivered to the hydrocarbon formation more rapidly than when hydrogen sulfide is combusted at a stoichiometric amount or deficient amount relative to the amount of oxidant.
• Alternatively, the amounts of the fuel stream comprising hydrogen sulfide and the oxidant provided for combustion in the process of the present invention may be controlled in a manner such that combustion generates substantially sulfur dioxide in the combustion by-product stream. To produce a sulfur dioxide-rich combustion by-product stream, the ratio of hydrogen sulfide to oxidant may be controlled so that a deficient amount of oxidant is combusted with the fuel stream comprising hydrogen sulfide relative to the hydrogen sulfide content of the fuel stream. Using an excess of hydrogen sulfide relative to oxidant produces a combustion by-products stream rich in sulfur dioxide that also contains hydrogen sulfide, and allows hydrogen sulfide and/or sulfur dioxide to be introduced into a layer of the hydrocarbon containing formation. A portion of the hydrogen sulfide and/or sulfur dioxide may contact at least a portion of the formation fluids and solvate and/or dissolve a portion of the heavy hydrocarbons in the formation fluids. Solvation and/or dissolution of at least a portion the heavy hydrocarbons may facilitate movement of the heavy hydrocarbons towards the production well. Furthermore, introduction of at least a portion of the combustion by-product stream comprising sulfur dioxide into the formation fluids may increase a shear rate applied to hydrocarbon fluids in the formation and decrease the viscosity of non-Newtonian hydrocarbon fluids within the formation. The introduction of the sulfur dioxide rich combustion by-products stream into the formation may thereby increase a portion of the formation available for production, and may increase a ratio of energy output of the formation (energy content of products produced from the formation) to energy input into the formation (energy costs for treating the formation).
• In a further alternative, the amounts of the fuel stream comprising hydrogen sulfide and the oxidant provided for combustion in the process of the present invention may be controlled to provide stoichometrically equivalent amounts of hydrogen sulfide and the oxidant. Combustion of a stoichiometric amount of hydrogen sulfide with oxygen may generate predominately sulfur dioxide and water as the combustion by-products as shown in the following reaction:
• 
  H₂S+1.5O₂→SO₂+H₂O(ΔH_rxn=−124 kcal/mol at 600° K).
• In addition to the heat value that is obtained from combustion of hydrogen sulfide, the introduction of heated sulfur dioxide/water combustion by-product stream into the hydrocarbon formation may facilitate recovery of hydrocarbons from the formation. The heat from the sulfur dioxide may transfer heat to fluids in the formation and the heated fluids may flow towards production wells. Furthermore, as discussed above, the sulfur dioxide in the combustion by-product stream may reduce the viscosity of hydrocarbon formation fluids in the hydrocarbon formation and thereby increase the amount of hydrocarbons available to be recovered from the formation. The heat of solution of sulfur dioxide, although less than the heat of solution of sulfuric acid, may also be transferred to the formation fluids of the hydrocarbon formation thereby mobilizing the formation fluids.
• The combustion of the fuel stream comprising hydrogen sulfide and the oxidant is effected in one or more heaters positioned in each of the one or more wellbores through which water is provided to the hydrocarbon formation. The heaters may be flameless distributed combustors, burners, or a mixture of both.
• In a preferred embodiment, each heater is a flameless distributed combustor in which the fuel stream comprising hydrogen sulfide and the oxidant are flamelessly combusted. In a flameless distributed combustor, the oxidant stream is provided in the heater at a velocity that is sufficiently elevated to prevent the formation of a fixed diffusion flame upon combustion of the mixture of the oxidant and the fuel stream in the heater, thereby ensuring a controlled heat release along the length of the flameless distributed combustor.
• In operating a flameless distributed combustor heater to combust the fuel stream comprising hydrogen sulfide and the oxidant stream, the fuel stream and the oxidant are mixed, where the mixture of the fuel stream and the oxidant is heated to a temperature at or above the auto-ignition temperature of the mixture, typically from 250° C. to 800° C., or from 300° C. to 750° C., or from 400° C. to 700° C. (where the auto-ignition temperature of a fuel stream of pure hydrogen sulfide is 260° C.). Prior to mixing the oxidant stream and the fuel stream comprising hydrogen sulfide in the heater, the oxidant stream, the fuel stream, or both may be pre-heated to a temperature sufficient to bring the mixture to a temperature at or above the auto-ignition temperature of the mixture upon mixing. The oxidant stream and/or the fuel stream comprising hydrogen sulfide may be pre-heated by heat exchange with a heat source, for example, steam or superheated steam. Alternatively, the fuel stream comprising hydrogen sulfide and the oxidant stream may be mixed and ignited using an ignition device—such as a spark plug or a glow plug—that facilitates raising the temperature of the mixture to at or above the auto-ignition temperature of the mixture.
• The heater may also be a burner that produces a flame. In operating a burner, the fuel stream comprising hydrogen sulfide and the oxidant stream are provided to the burner for combustion. The fuel stream and the oxidant stream may be mixed in the burner or may be mixed prior to being provided to the burner. The mixture of the fuel stream and the oxidant stream is combusted by raising the temperature of the mixture to a temperature at or above the auto-ignition temperature of the mixture, for example, by igniting the mixture with an ignition device such as a spark plug or a glow plug. The oxidant stream and the fuel stream comprising hydrogen sulfide are provided to the burner at a velocity such that a stable flame may be produced by the burner. The burner may include flame stabilizing shields near the burner flame to assist in stabilizing the flame after ignition.
• As noted above, in the process of the present invention water is provided to at least a portion of the hydrocarbon containing formation through one or more of the wellbores in which the fuel stream comprising hydrogen sulfide and the oxidant stream are combusted. The water provided to the one or more wellbores may be in the form of steam or superheated steam.
• At least a portion of the water supplied to a wellbore may be heated subsurface by the heat generated by the combustion of the fuel stream comprising hydrogen sulfide and the oxidant stream. The heat generated by combustion of the fuel stream comprising hydrogen sulfide and the oxidant stream may be thermally communicated to a portion of the water in the wellbore. The heated portion of the water may be in thermal communication with a portion of the hydrocarbon formation so that heat may be transferred from the heated portion of the water to the hydrocarbon formation to provide a driving force for mobilization of at least a portion of the formation fluids in the hydrocarbon formation. The heated portion of the water may be in thermal communication with the hydrocarbon formation along the length of the wellbore, and the heated portion of the water may be injected into the hydrocarbon formation along the length of the wellbore and/or at the terminus of the wellbore.
• Combustion of the fuel stream comprising hydrogen sulfide and the oxidant stream may be used for subsurface heating of water (steam) in the wellbore of the injection well. The water may be heated subsurface by combustion of a stream containing hydrogen sulfide in a subsurface section of the wellbore of the injection well. Heat from the subsurface combustion may enhance heat transfer to the hydrocarbon formation due to the generation of higher steam temperatures subsurface, thus the heat transfer region or “region of influence” (ROI) may be enlarged as compared to conventional steam drive processes. For example, subsurface heating using hydrogen sulfide may produce a combustion product stream having a temperature from about 500° C. to about 2000° C., which heats the water and/or hydrocarbon layer. In contrast, conventional steam injection methods may produce steam temperatures of about 290° C. for heating the hydrocarbon layer.
• Subsurface heating of water (steam) supplied to an injection well may inhibit water condensation along the length of the injection well. Inhibiting water condensation in the injection well may enhance heating and allow more uniform heating of the hydrocarbon layer. Subsurface heating of steam may lessen the amount of steam required to be injected to heat the hydrocarbon layer, for example by lessening the amount of premature steam condensation. In some embodiments, water re-cycling facilities are reduced due to more efficient use of the steam. Subsurface heating of water may reduce or eliminate the requirement for hydrocarbon gases at the well site as an energy source, thereby allowing additional hydrocarbon gases to be sold for commercial and/or residential energy sources.
• The heated portion of the water may be used to sustain the combustion of the fuel stream comprising hydrogen sulfide and the oxidant stream in the wellbore downstream of the transfer of heat from the combustion to the water. The water may be heated to a temperature at or above the auto-ignition temperature of the mixture of the fuel stream and the oxidant stream by transfer of heat from the combustion to the water. The flow of the heated water may be directed into the wellbore (downstream from the wellhead) and heat may be transferred from the heated water to a mixture of the fuel stream comprising hydrogen sulfide and the oxidant stream downstream of the transfer of heat from the combustion to the water, where the heat transferred from the heated water to the downstream mixture of the fuel stream and the oxidant stream is sufficient to heat the mixture to a temperature at or above the auto-ignition temperature of the mixture so that the mixture combusts to provide further heat.
• The water in the wellbore or exiting the wellbore into the hydrocarbon formation may be heated by contact with at least a portion of the combustion by-products stream. The combustion by-products stream may directly transfer heat from the combustion to a least a portion of the water and the combustion by-products stream may generate a heat of solution upon being mixed with the water, particularly if the combustion by-products stream contains significant amounts of sulfur trioxide that may be converted to sulfuric acid upon mixing with the water. The water heated by the combustion by-products stream may transfer heat to a portion of the hydrocarbon formation to provide a driving force for mobilization of at least a portion of the formation fluids.
• Combustion by-products from surface facilities may be introduced into water (steam) being provided to a wellbore. Heat from the heaters may provide heat to the combustion by-products from the surface facilities to facilitate driving such combustion by-products into the formation. The water/steam provided to the wellbore may be initially heated using combustion by-products from surface facilities. The water stream provided to the one or more wellbores may also include carbon dioxide, sulfur dioxide, combustion by-products from surface facilities, or mixtures thereof. In particular, carbon dioxide may be sequestered in the hydrocarbon formation by injecting the carbon dioxide in a wellbore, where heat from the combustion of the fuel stream comprising hydrogen sulfide and the oxidant stream provides heat to the injected carbon dioxide to facilitate driving the carbon dioxide into the hydrocarbon formation.
• Heat may be transferred to fluids introduced into the formation, formation fluids and/or to a portion of the hydrocarbon containing formation through heat of reaction, heat of salvation, conductive heat, or convective heat. Fluids introduced into the formation and/or combustion by-products may transfer heat to at least a portion of the hydrocarbon containing formation and/or formation fluids.
• Convective heat transfer may occur when non-condensable non-miscible gases such as nitrogen contact the formation fluids and/or hydrocarbon containing formation. When the oxidant stream is formed of compressed air or oxygen-enriched air, the combustion by-products may include nitrogen gas. Convective heat transfer may also occur when superheated miscible solvent vapors (for example, hydrogen sulfide, carbon dioxide, and/or sulfur dioxide vapors) contact the formation fluids and/or hydrocarbon containing formation. Convective heat transfer may also occur when superheated non-miscible solvent vapors such as water contact the formation fluids and/or hydrocarbon containing formation.
• Conductive heat transfer may occur when hot liquid steam condensate contacts the formation fluids and/or hydrocarbon containing formation. Conductive heat transfer may occur when hot liquid miscible solvent (for example, hydrogen sulfide, carbon dioxide, and/or sulfur dioxide) contacts the formation fluids and/or hydrocarbon containing formation.
• Heat of reaction heat transfer may occur when one compound reacts with another compound. For example, sulfur oxides form solutions with liquid water in the hydrocarbon containing formation and/or in the outer portion of the wellbore to generate a heat of reaction. Heat of reaction also occurs as oxygen reacts with hydrocarbons or sulfur compounds to form carbon oxides or sulfur oxides.
• Heat of solution may occur when at least one component is dissolved in a solvent. For example, heat is generated when sulfuric acid is dissolved in water.
• The water may be provided in a first portion of a wellbore, for example a first conduit, and combustion of the fuel stream comprising hydrogen sulfide and the oxidant stream may occur in a second portion of the wellbore, for example a heater located in a second conduit. The second portion of the wellbore may be in thermal communication with the first portion of the wellbore so that heat from the combustion of the fuel stream and the oxidant stream may be transferred from the second portion of the wellbore to the water/steam flowing in the first portion of the wellbore. The first portion of the wellbore may be in thermal communication with a portion of the hydrocarbon formation so that heat from heated water/steam may be transferred from the heated water/steam to the portion of the hydrocarbon formation in thermal communication with the first portion of the wellbore. The first portion of the wellbore may be in thermal communication with the hydrocarbon formation along the length of the wellbore. The first portion of the wellbore may also be in thermal communication with the hydrocarbon formation at the terminus of the wellbore in the hydrocarbon formation, where the water/steam may be injected into the hydrocarbon formation.
• In some embodiments, the heater is positioned in an inner portion of a wellbore. An outer portion of the wellbore may allow addition of a stream that includes water (for example, a drive fluid or a solvent) and/or heating of the stream as it is introduced into the hydrocarbon containing formation. The heater may be positioned in an inner conduit coupled to an outer conduit. The two conduits may be placed in the wellbore. The conduits may be side by side. It should be understood that any number and/or configuration contemplated configuration of conduits may be used as contemplated or desired.
• Fuel may be provided to one or more fuel conduits, where at least one of the conduits provides a portion of the fuel comprising hydrogen sulfide and at least one of the conduits provides another fuel. The fuel may be provided to one or more fuel conduits in at least one of the heaters such that at least a portion of the fuel is introduced to an upstream portion of at least one of the heaters and at least a portion of the fuel stream is introduced to a downstream portion of at least one of the heaters. The fuel may be provided to one or more fuel conduits in at least one of the heaters, where at least one of the conduits is adjustable such that at least a portion of the fuel is delivered to a first portion of the heater and then to a second portion of the heater downstream of the first portion.
• Passing of the fluid (for example, a stream that includes water) through the outer portion of the wellbore and into the hydrocarbon containing formation may move or drive the formation fluids to a production well. The fluid may contact the formation fluids and mix with a portion of the formation fluids, solvate a portion of the formation fluids and/or dissolve a portion of the hydrocarbons. Contacting of the fluid with the formation fluids may lower the viscosity the formation fluids and promote movement of the formation fluids towards one or more production wells.
• Heat generated from the heater in the inner portion of the wellbore may heat at least a portion the fluid passing through the outer portion of the wellbore. Heat may also be generated by contact or reaction of the combustion by-products produced from the heater with the fluid passing through the outer portion of the wellbore. The combustion by-products may move or drive the fluid in the outer conduit into the hydrocarbon containing formation. In some embodiments, combustion generates combustion by-products that include sulfur dioxide. At least a portion of formation fluids in the hydrocarbon containing formation may mix with the generated sulfur dioxide to form a mixture.
• In some embodiments, transferring heat to at least a portion of the fluid passing through the outer portion may sustain oxidation and heat along portions of the heater along the length of the heater. Sustaining heat along a portion of the heater may enhance stability of the heater at oxidation temperatures under all operating conditions.
• FIGS. 3 through 7 are embodiments of hydrogen sulfide fueledheaters130 for subsurface heating.FIGS. 3 through 6 depict cross-sections of hydrogen sulfide fueled flameless distributed combustors.FIG. 7 depicts a cross-section of a hydrogen sulfide fueled burner.
• FIG. 3 depicts a perspective of a portion of hydrogen sulfide fueled flameless distributedcombustor150 positioned invertical wellbore102.Fuel stream152 comprising hydrogen sulfide (for example,gas stream116 and/orhydrogen sulfide stream124 optionally includingsulfur dioxide stream128,hydrogen stream130, and/orgas hydrocarbon stream122 fromFIG. 2) enterscentral fuel conduit154. Oxidant stream156 (for example, air, oxygen enriched air, oxygen gas, or mixtures thereof) enterscombustion conduit158. In some embodiments, heat fromwater162heats fuel stream152,oxidant stream156, and/or the fuel/oxidant mixture to a temperature at or above the auto-ignition temperature necessary to cause combustion of the fuel stream mixture. In some embodiments,fuel stream152 and/oroxidant stream156 are heated prior to entering the fuel conduit and/or combustion conduit to a temperature at or above the auto-ignition temperature of the mixture.Oxidant stream156 andfuel stream152 mix, and the fuel/oxidant mixture reacts (combusts) at a temperature at or above the auto-ignition temperature of the mixture.
• Central fuel conduit154 is positioned inside ofcombustion conduit158 and may extend the length of flameless distributedcombustor150.Central fuel conduit154 includesorifices160 along the length of the central fuel conduit.Orifices160 may be critical flow orifices.Orifices160 allow heated fuel to mix with heated oxidant so that the mixture reacts (flamelessly combusts) to produces heat. In some embodiments,orifices160 are shaped to allow a fuel to oxidant momentum ratio to range from 10 to 100, from 30 to 80, or from 50 to 70, where momentum is equal to the density of the fuel or oxidant times velocity of the fuel or oxidant squared. In some embodiments, a fuel to oxidant pressure ratio throughorifices160 ranges from 1.5 to 2.
• Combustion in a downstream portion ofcombustion conduit158 may transfer heat towater162 inouter conduit164. In some embodiments, the water is heated to form steam and/or super heated steam.Outer conduit164 may be the space formed between the inner wall of injection well102 and outer wall ofcombustion conduit158.Outer conduit164 may includeopenings104 that allow the water and/or heat to enter the hydrocarbon layer adjacent to the injection well. In some embodiments,outer conduit164 is a conduit that surroundscombustion conduit158 and is coupled to or an integral part of flameless distributedcombustor150. Couplingouter conduit164 to flameless distributedcombustor150 may facilitate insertion of the flameless distributed combustor into an existing injection well.
• In some embodiments, combustion of fuel incombustion conduit158 produces a combustion by-products stream. Combustion by-products stream may heatwater162. The combustion by-products stream may exitopenings104 and drive, heat, and/or reduce viscosity of formation fluids in the hydrocarbon containing formation. Contact of water with the combustion by-products stream in a portion of the formation at a distance from well102 may generate heat, and heat at least a portion of the formation to allow fluids to be mobilized.
• In some embodiments, a portion or portions ofcentral fuel conduit154 are adjustable. The ability to adjustcentral fuel conduit154 allows fuel to be provided to selected portions ofcombustion conduit158. For example, positioningcentral fuel conduit154 at an upstream portion of the flameless distributed combustor may facilitate the combustion process in the upstream portion of the well at a desired time. Once combustion is established, the fuel conduit may be advanced along the length of the injection well (or selected valves may be opened along the length of the injection well) to provide fuel to other combustors positioned in the well. In some embodiments,orifices160 may be adjusted to allow flow of fuel intocombustion conduit158. For example orifices,160 may be connected to a computer system that opens and/or closes the orifices as required.
• FIG. 4 depictscentral fuel conduit154 havinginner fuel conduit166 andouter fuel conduit168.Inner fuel conduit166 may be coupled and/or removably coupled toouter fuel conduit168.Inner fuel conduit166 may fit inside ofouter fuel conduit168 such that a space is formed between the two conduits. In some embodiments, the two conduits are co-axial. In some embodiments, the conduits are separate and parallel.
• Hydrogen sulfide stream124 entersinner fuel conduit166 and flows intoouter fuel conduit168 throughorifices170. In some embodiments, hydrogen sulfide is delivered toouter fuel conduit168 through an opening in a downstream portion (for example, the end of fuel conduit is open) ofinner fuel conduit166.Fuel stream152 entersouter fuel conduit168. In some embodiments, a portion ofinner fuel conduit166 relative toouter fuel conduit168 is adjustable to allow for removal of either of the conduits for maintenance purposes, and/or for selected delivery of hydrogen sulfide and/or fuel to selected portions of the flameless distributed combustor. Delivery of hydrogen sulfide as a separate stream may allow for control of the amount of hydrogen sulfide in the fuel stream provided tocombustion conduit158. In some embodiments,outer conduit168 is the hydrogen sulfide conduit and fuel is delivered to the formation throughinner conduit166.
• FIG. 5 depicts flameless distributedcombustor150 having more than one fuel conduit. As shown, the fuel conduits are separate and parallel to one another. In some embodiments, the conduits are co-axial.Fuel conduits154,154′,154″ includeorifices160,160′,160″ positioned at different intervals along the fuel conduits. Positioning of theorifices160,160′,160″ may allow for delivery of fuel to selected portions of flameless distributedcombustor150 at selected time periods. For example,fuel stream152 may be delivered to an upstream portion ofcombustion conduit158 throughorifice160. Combustion offuel152 in the upstream portion of thecombustion conduit158 may provide heat to steam162 in upstream portion ofouter conduit164.Fuel stream152′ enters a middle portion ofcombustion conduit158 throughorifices160′, mixes with oxidant, and then react to provide heat to steam in a middle portion ofouter conduit164.Fuel stream152″ delivered throughorifices160″ infuel conduit154″ and subsequent combustion in downstream portion ofcombustion conduit158 provides heat to steam in a downstream portion ofouter conduit164. In some embodiments, fuel streams152,152′,152″ contain different amounts of hydrogen sulfide. In some embodiments, fuel streams152,152′,152″ contain the same amounts of hydrogen sulfide. It should be understood that the number of fuel conduits and/or position of the orifices in the fuel conduit may be varied. In some embodiments,orifices160,160′,160″ are adjusted (opened and/or closed) to control the flow of fuel and/or hydrogen sulfide intocombustion conduit158.
• FIG. 6 depicts a cross-section of flameless distributedcombustor150 withignition device172.Ignition device172 may raise the temperature of the fuel/oxidant mixture to combustion temperatures incombustion conduit158. For example, once the fuel/oxidant mixture is ignited nearignition device172, heat from the flame heats the fuel/oxidant mixture to an auto-ignition temperature of the fuel/oxidant mixture to facilitate the reaction of the fuel with the oxidant to produce flameless combustion and heat.
• FIG. 7 depicts a perspective of hydrogen sulfide fueledburner174.Burner174 may includefuel conduit176,combustion conduit158, andouter conduit164.Ignition device172 may be positioned in a bottom portion ofcombustion conduit158. Fuel stream152 (for example,gas stream116,hydrogen sulfide stream124,sulfur dioxide stream128,hydrogen stream130, and/orgas hydrocarbon stream122 fromFIG. 2, (methane, natural gas, sour gas, or mixtures thereof) enterscentral fuel conduit176. Oxidant stream156 (for example, air, oxygen enriched air, or mixtures thereof) enterscombustion conduit158. In some embodiments,burner174 may include more than one fuel conduit. For example, one conduit for hydrogen sulfide and one conduit or a fossil fuel. In some embodiments,fuel conduit176 iscombustion conduit158 and combustion conduit isfuel conduit176.
• In some embodiments,fuel stream152 and/oroxidant stream156 are heated prior to entering the fuel conduit and/or combustion conduit. In some embodiments,water162heats fuel stream152 and/oroxidant stream156.Fuel stream152 andoxidant stream156 mix incombustion conduit158.Ignition device172 provides a spark to combust the fuel/oxidant mixture to produce a flame.
• In some embodiments, burner includes one ormore nozzles178. The fuel and oxidant may be mixed by flowing at least a portion of the fuel and at least a portion of the oxidant throughnozzles178.Nozzles178 may enhance mixing incombustion conduit158 and/orouter conduit164. Geometry of nozzles178 (for example, converging-diverging section dimensions, length, diameter, and/or flare angle) may be adjusted based on firing rate, fuel stream composition, and/or oxidant stream composition. A nozzle flare angle may range from 1 degree to 10 degrees, from 2 degrees to 9 degrees, or from 3 degrees to 8 degrees in the flow direction. In some embodiments,nozzles178 are shaped to allow concentric flow or counter-concentric flow (swirling of the mixture). The nozzle swirl angle may range from 10 degrees to 40 degrees, from 15 degrees to 35 degrees, or from 20 degrees to 30 degrees. In some embodiments, the nozzle swirl angle is 30 degrees. In some embodiments,burner174 does not includenozzles178.
• In some embodiments, a downstream portion offuel conduit176 may be tapered. The taper angle may range from 5 to 30 degrees, from 10 degrees to 25 degrees, or from 15 degrees to 20 degrees.
• Combustion of the fuel/oxidant mixture incombustion conduit158 ofburner174 may transfer heat towater162 inouter conduit164. In some embodiments, the water is heated to form steam and/or super heated steam.Outer conduit164 may be the space formed between the inner wall of injection well102 and outer wall ofcombustion conduit158.Outer conduit164 may includeopenings104 that allow the water and/or heat to enter the hydrocarbon layer adjacent to the injection well. In some embodiments,outer conduit164 is a conduit that surroundscombustion conduit158 and is coupled to or an integral part ofburner174. Couplingouter conduit164 toburner174 may facilitate insertion of the burner into an existing injection well. In some embodiments, the outer conduit is the fuel conduit and water is delivered through the inner conduit.
• In some embodiments, combustion of the fuel/oxidant mixture incombustion conduit158 ofburner174 produces the combustion by-products stream. Combustion by-products stream may heatwater162. The combustion by-products stream may exitopenings104 and drive, heat, and/or reduce viscosity of formation fluids in the hydrocarbon containing formation. Contact of water with the combustion by-products stream in a portion of the formation at a distance from well102 may generate heat and heat at least a portion of the formation to allow fluids to be mobilized.
• Heaters130 (for example, flameless distributed combustors and burners described inFIGS. 3-7) may be manufactured from materials suitable for downhole combustion processes. In some embodiments, water present in the fuel and/or hydrogen sulfide streams interacts with hydrogen sulfide to form a sulfide layer on metal surfaces of the conduit walls. Formation of the sulfide layer may inhibit further corrosion of the metal surfaces of the conduit walls by carbonic acid and/or other acids. The formation of the sulfide layer may allowouter conduit164,central fuel conduit154, andcombustion conduit158 to be fabricated from carbon steel or other alloys. For example, alloy 230, alloy 800H, alloy 370H or Hastelloy C276 may be used to manufacture portions ofheaters130. In some embodiments, inner fuel conduit166 (shown inFIG. 4) is manufactured from materials resistant to high temperature and/or high concentrations of hydrogen sulfide.
• In some embodiments, a start-up mixture of hydrocarbon fuel containing a minimal amount of hydrogen sulfide or a less than a stoichiometric amount of hydrogen sulfide relative to the amount of oxidant is introduced intofuel conduit154 of heaters130 (for example, flameless distributedcombustor150 and/or burner174). In some embodiments, a start up fuel stream includes at most 1%, at most 0.5%, at most 0.01% by volume of hydrogen sulfide. In some embodiments, the start-up fuel includes hydrogen and/or oxygenated ethers such as dimethyl ether to lower the ignition temperature. Once combustion has been initiated, the hydrogen sulfide concentration infuel stream152 may be increased.
• In some embodiments, a mixture containing a low amount of hydrogen sulfide relative to oxidant is not necessary for start-up and/or for sustaining combustion. For example, the fuel stream may include from 0.1% to 100%, from 3% to 90%, from 10% to 80%, or from 20% to 50% of hydrogen sulfide by volume. In some embodiments, the fuel has a sulfur content of at least 0.01 grams, at least 0.1 grams, at least 0.5 grams or at least 0.9 grams of atomic sulfur per gram of fuel as determined by ASTM Method D4294.
• FIG. 8 depicts a representation of an embodiment for producing hydrocarbons from a hydrocarbon containing formation (for example, a tar sands formation).Hydrocarbon layer106 includes one or more portions with heavy hydrocarbons.Hydrocarbon layer106 may be belowoverburden180. Hydrocarbons may be produced fromhydrocarbon layer106 using more than one process.
• Hydrocarbons may be produced from a first portion ofhydrocarbon layer106 using a steam injection process and/or other drive process (for example, a carbon dioxide drive process). The steam injection process may include steam drive, cyclic steam injection, SAGD, or other process of steam injection into the formation. A portion ofhydrocarbon layer106 may be treated using heaters prior to the steam injection process. Heaters may be used to increase the temperature and/or permeability of the portion ofhydrocarbon layer106. Some hydrocarbons may be produced through production well108 by heating the hydrocarbon portion. Alternatively,hydrocarbon layer106 may not be heated prior to steam injection. The production well108 may be located at a depth of 100, 200, 500, 1000, 1500, 2500, 5000, 10000, or 10500 meters. The pattern and number of injection wells, heater wells and production wells may be any number or geometry sufficient to achieve production of formation fluids from a hydrocarbon containing formation.
• Injection well102 may includeheater130 or a series of heaters. Theheaters130 may be inserted in injection well102 after some hydrocarbons have been produced fromhydrocarbon layer106. The injection well102 may be located at a depth of below 100, 200, 500, 1000, 1500, 2500, 5000, or 10000 meters. Heating or injecting drive fluids at shallow depths of a formation may allow recovery of hydrocarbons that are not readily accessible through conventional steam drive processes and/or thermal heating using heaters. Heating or injecting drive fluids in a hydrocarbon containing formation at shallow depths may also allow recovery of hydrocarbons that are not readily accessible through conventional hydrocarbon recovery methods.
• The injection well102 may be fabricated from materials known in the art to be resistant to sulfur oxides. For example, injection well102 may be made from Hastelloy® C276, alloy 230, alloy 800H, alloy 370H, nickel/copper/iron alloys, or cobalt-chromium alloys.
• Water162 (for example, steam and/or hot water) may be injected into injection well102. Water may be injected at temperatures of at least 200° C., at least 225° C., at least 250° C., or at least 260° C. and pressures ranging from about 1 MPa to about 15 MPa.Fuel stream152 andoxidant stream156enter heaters130. Combustion of a fuel/oxidant mixture inheaters130 may heatwater162 and/or heat a portion ofhydrocarbon containing layer106. Heat fromwater162 may be sufficient to auto ignite the fuel/oxidant mixture.
• Heat produced during combustion of the fuel/oxidant mixture incombustion conduit158 transfers heat towater162.Heated water162 may flow intohydrocarbon layer106 throughopenings104. Heat and/or injectivity of steam, combustion gases and/or hydrogen sulfide may mobilize formation fluid inhydrocarbon layer106 towards production wells. The ability to heatwater162 in the formation may allow for expanded and/or more uniform heating ofhydrocarbon layer106.
• Heat from combustion and/orheated water162 forms a first heated zone. Hydrocarbons inhydrocarbon layer106 may be mobilized by the heat and produced fromproduction well108.
• Combustion of hydrogen sulfide/oxidant mixture produces a combustion by-products stream. The combustion by-products stream may include sulfur oxides such as sulfur trioxide and/or sulfur dioxide. Contacting (for example, mixing, solvating, and/or dissolving) of at least a portion of the sulfur oxides inwater162 may heat the water in well102 and/orhydrocarbon layer106 to form a second heated zone. The second heated zone may heat a portion of thehydrocarbon layer106 proximate the end of injection well102 and/or extend intohydrocarbon layer106. Due to the heat transfer and more uniform heating ofhydrocarbon layer106, an increased amount of hydrocarbons may be produced per volume as compared to conventional drive fluid processes. The first and second heated zones may overlap.
• In some embodiments, the second heated zone is a substantial distance from well102. For example, combustion by-products may drive the steam into the formation. As steam condenses, the sulfur oxides in the combustion by-products react with the condensed water to generate heat from the formation of sulfuric acid. The generated heat may provide heat to the formation to sufficiently mobilize hydrocarbons towardsproduction well108. The combination of subsurface steam heating in combination with latent heating (heating after the steam condenses) may facilitate recovery of hydrocarbons from the formation. The combination of sensible heat for all introduced components and latent heat may reduce energy and/or heating requirements for producing hydrocarbons from the formation as compared to the energy and/or heating requirements for conventional hydrocarbon recovery processes.
• The hydrocarbon formation may contain limestone. As the sulfur oxides contact the formation in the presence of water, the limestone reacts with the sulfur oxides and produces carbon dioxide. The carbon dioxide may serve as an additional drive fluid to push the fluids towardsproduction well108.
• The sulfur oxides may react with aromatic hydrocarbons in the formation fluids and form sulfonates. The formation of in-situ sulfonates may facilitate moving hydrocarbons towards one or more production wells.
• Formation fluids110 produced from production well108 may be treated in a surface facility (for example, in surface facilities described with respect toFIG. 2) to form a gas stream and a liquid stream. In some embodiments, the produced hydrocarbons have an API gravity of at most 15, at most 10, at most 8, or at most 6. The gas stream may include hydrogen sulfide, sulfur dioxide, hydrocarbon gases and/or carbon dioxide. In some embodiments, the sulfur dioxide is separated from the formation fluids using a regenerable process (for example, as described inFIG. 2). At least a portion of the sulfur dioxide may be introduced into theouter conduit164 and/or into the hydrocarbon containing formation. In some embodiments, formation fluids that include least a portion of the sulfur dioxide from the hydrocarbon containing formation are produced and separated from the formation fluids. At least a portion of the separated sulfur dioxide may be provided to the hydrocarbon containing formation and/or at least one of the flameless distributed combustors.
• All or a portion of thegas stream116 may be transferred tofuel stream152 and combusted inheater130. In some embodiments,fuel stream152 includes sulfur dioxide. In the presence of oxidant inheater130, at least a portion of the sulfur dioxide may be converted to sulfur trioxide and subsequently converted to sulfuric acid in the formation. In some embodiments, at least a portion of sulfur dioxide enters the formation. By recycling the sulfur dioxide, a majority of sulfur emissions produced from the formation and/or from surface facilities are abated, thus reducing emissions as compared to emissions (for example, carbon dioxide) generated by combustion of fossil fuels make steam for steam flooding.
• In some embodiments,water162 includes one or more surfactants and/or one or more foaming agents. Surfactants include thermally stable surfactants (for example, sulfates, sulfonates, alkyl benzene sulfonates, ethoxylated sulfates, and/or phosphates). The use of foaming agents and/or surfactants may change the surface tension between the hydrocarbons and the formation to allow the hydrocarbons to be mobilized towardsproduction well108. In some embodiments,water162 includes an antifoaming agent. The antifoaming agent may inhibit foaming of the formations fluids when carbon dioxide and surfactants are present.
• In some embodiments,water162 introduced intohydrocarbon layer106 includes hydrogen sulfide and or hydrogen. The hydrogen sulfide and/or hydrogen may solvate, dilute, and/or hydrogenate a portion of the heavy hydrocarbons to form a mixture that may mobilize formation fluid towardproduction well108. Formation of the mixture may increase production of hydrocarbons inhydrocarbon layer106. Solubilization, dilution, and/or hydrogenation of a portion of the heavy hydrocarbons may allow an increase in the amount of hydrocarbons produced from the hydrocarbon layer. The solvents and/or hydrogen sulfide may be separated from the mixture and injected withwater162 or used in other processes. For example, hydrogen sulfide may be separated from the mixture and combusted to heat water. In some embodiments, heat from hydrogenation of hydrocarbons transfers to a portion ofhydrocarbon layer106 and/or towater162.
• In some embodiments,heater130 or a series of heaters are positioned in injection well102.Water162, heated to at least 300° C., or at least 500° C., and pressurized to pressures ranging from 1 MPa to 15 MPa, may be introduced into well102 and transfer heat tohydrocarbon layer106. A portion ofwater162 may enterhydrocarbon layer106 throughopenings104.Water162 may cool as it flows throughouter conduit164. Heaters positioned downstream of the wellhead may be ignited toheat water162 as it flows throughouter conduit164. Heaters may heatwater162 to a temperature sufficient to heat hydrocarbon layer106 (for example, to temperatures ranging from about 200° C. to about 500° C.). Formation fluids may be moved by the heat and/orwater162 towardsproduction well108. Temperatures in various portions of well102 may be monitored. Heaters may be ignited at pre-determined temperatures inwell102. In some embodiments,water162 is heated subsurface to form super heated steam.
• In some embodiments, subsurface heating ofwater162 increases a volume of a hydrocarbon containing layer to be heated as compared to heating using conventional steam injection methods. Subsurface heating allows the use of substantially liquid water and/or low pressure steam as a drive fluid instead of having to heat or pressurize steam at or above formation pressures prior to injection into the hydrocarbon containing formation. Subsurface heating of water in an injection well may create a steam reboiler along the length of the flameless distributed oxidizer. The ability to substantially heat the drive fluid (for example, steam) along the length of the heater may allow the hydrocarbon layer to be heated in a more uniform manner as compared to a system using a surface heated drive fluid. More uniform heating may allow production wells to be positioned at greater distances from the injection well as compared to conventional steam injection processes.
• In some embodiments, subsurface heating of water changes the heat flux profile of the system as compared to conventional drive fluid injection processes.FIG. 9 depicts a schematic of a heat flux profile of an embodiment of a conventional steam injection process. The injected steam in a conventional steam injection process flows to the end of injection well102, the steam cools, and forms condensate as it moves towards portions of the well farthest from the injection site. Cooling of the steam decreases the amount of heat that is transferred to the hydrocarbon layer as indicated by the arrow length. Thus, heat transfer may be greatest at sections closest to wellhead relative to the end portions of the well.
• In some embodiments, a method of treating a hydrocarbon containing formation, includes providing steam to at least a portion of a hydrocarbon containing formation from a plurality of locations in a wellbore, where the steam is hotter than a temperature of the portion of the hydrocarbon containing formation; and heating the steam in the wellbore by combusting at least a portion of a mixture that includes fuel and oxidant in the wellbore, where the fuel includes hydrogen sulfide. Heat from the combustion transfers to the steam; and the steam is heated such that the steam provided to the portion of the hydrocarbon containing formation at a first location in the wellbore is hotter than steam provided at a second location in the wellbore; and the first location is further from a surface of the formation than the second location along the length of the wellbore. In some embodiments, combustion generates a combustion by-products stream and at least a portion of the combustion by-products stream is contacted with a portion of the water in a portion of the hydrocarbon containing formation that is downstream of the formation surface, along the length of the wellbore, from the transferred heat portion. In some embodiments, at least a portion of the heat is transferred to at least a portion the hydrocarbon containing formation; and at least a portion of formation fluids are mobilized in the heated portion.
• FIGS. 10A and 10B depict schematics of a heat flux profile of an embodiment of subsurface heating ofsteam using heaters130 in a horizontal injection well102. As shown inFIG. 10A, longer arrows indicate more heat is generated at the downstream portion of the well than at the upstream portion of the well when usingheaters130 to heat water in the formation. As shown,steam162 is heated such that the steam provided to the layer at the downstream portion of the wellbore is hotter than steam provided to the hydrocarbon containing formation near the upstream portion of the formation. By controlling where the hotter portion is along the length of the wellbore heat may be transferred in a uniform manner to the formation, thus the heat flux, hot spots and/or cold spots along the length of the wellbore may be controlled. Hydrocarbons mobilized by the heat and/or steam from injection well102 are produced fromproduction well108. In some embodiments, the downstream portion of the wellbore is proximate to a portion of formation having more hydrocarbons per volume (richer in hydrocarbons), as compared to the first location, thus allowing heat to transfer to hydrocarbons that may be more difficult to produce using conventional steam drive processes. In some embodiments, production well108 may include openings to allow the hydrocarbons to flow into the well.
• As shown inFIG. 10B, a shape of the heat flux profile may be parabolic. Heated water enters injection well102 and heats an upstream portion of the well. As the water cools the heat profile diminishes. As the water cools, the heaters in well102 are ignited to reheat the water. Other heat flux profiles, such as a substantially constant heat flux, may be obtained by adjusting the portion of the openings and/or heaters.
• By keeping temperatures of the steam along the length of the wellbore at a constant temperature, the fuel and oxidant temperatures along the length of the wellbore may be buffered, thus inhibiting temperature fluctuations (for example, formation of hot spots and/or cold spots) along the length of the heater. Inhibiting temperature fluctuations may sustain and/or enhance oxidation along the length of the heater. Such consistent heating of the wellbore may allow heat to transfer uniformly to the formation thus facilitating mobilization and/or production of formation fluids from the hydrocarbon containing formation.
• Uniform transfer of heat tohydrocarbon layer106 from injection well102 usingheaters130 may facilitate mobilization of more hydrocarbons towardsproduction well108. The change in heat flux profile and more uniform heating of the hydrocarbon layer may allow production well108 to be positioned at distances greater than those used for conventional drive fluid injection, thus allowing hydrocarbons in less accessible areas to be produced.
• In some embodiments, production of hydrocarbons from a hydrocarbon containing layer is enhanced by heating an area with a hydrogen sulfide fueled heater located in a well proximate the end of one or more horizontal steam injection wells. The heat provided by the hydrogen sulfide fueled heater may enhance production of hydrocarbons from the hydrocarbon layer.
• In some embodiments, a method of treating a hydrocarbon containing formation, includes: providing steam to at least a portion of a hydrocarbon containing formation from a plurality of substantially horizontal steam injection wells; combusting at least a portion of a mixture that includes hydrogen sulfide and oxidant in one or more flameless distributed combustors positioned in one or more substantially vertical wellbores to generate heat, where at least one of the substantially vertical wellbores is within ten meters of an end of at least one of the substantially horizontal steam injection wells; allowing a portion of the generated heat to transfer to a portion of the hydrocarbon containing formation located between at least one of the substantially horizontal steam injection wells and at least one of the substantially vertical heater wells; and mobilizing at least a portion of formation fluids in the heated portion of the hydrocarbon containing formation. In some embodiments, the generated heat transfers to the portion by conduction, convention or by heat of solution. wherein the generated heat transfers to the portion by convection.
• In some embodiments, a portion of the steam is heated by combusting at least a portion of the mixture in one or more flameless distributed combustors positioned in at least one of the substantially horizontal steam injection wells. In some embodiments, a portion of the steam is heated by combusting at least a portion of the mixture in one or more burners positioned in at least one of the substantially horizontal steam injection wells.
• The steam transfers heat to at least a portion of the hydrocarbon containing formation. At least a portion of the steam may drive at least a portion of the formation fluids towards one or more production wells. Formation fluids may be produced from a volume between at least one of the substantially vertical heater wells and at least one of the substantially horizontal steam injection wells. In some embodiments, the hydrocarbon formation is heated prior to providing the water. In some embodiments, at least a portion of the combustion by-products is provided to the formation. At least a portion of the combustion by-products and/or at least a portion of the steam into the formation provide a driving force for mobilization of at least a portion of the formation fluids.
• In some embodiments, the combustion by-products stream include sulfur oxides, and at least a portion of the combustion by-products steam is provided to the hydrocarbon containing formation such that at least a portion of the steam and a portion of the sulfur oxides mixes with water in the formation to generate heat of solution and at least a portion of the solution heat is transferred to a portion of the hydrocarbon containing formation.
• FIG. 11 depicts a representation of a system for producing hydrocarbons using a substantially vertical hydrogen sulfide fueled heater in combination with a substantially horizontal or inclined steam injection well. Vertical heater well186 may be positioned proximate the downstream portion of horizontal steam injection well102. For example, vertical heater well186 may be positioned from 1 to 10 meters from the end of horizontal injection well102. Production well108 extends past injection well102 and belowheater well186. Vertical heater well186 includes hydrogen sulfide fueledheaters130 described herein. Heat generated from heater well186 through oxidation of hydrogen sulfide inheaters130 may mobilize hydrocarbons towardsproduction well108. Heat transfer produced from hydrogen sulfide fueled heater well186, in combination with heat and stream drive from steam injection well102, may allow more hydrocarbons to be produced from production well108 as compared to conventional drive processes using horizontal injection wells.
• Further modifications and alternative embodiments of various aspects of the invention will be apparent to those skilled in the art in view of this description. Accordingly, this description is to be construed as illustrative only and is for the purpose of teaching those skilled in the art the general manner of carrying out the invention. It is to be understood that the forms of the invention shown and described herein are to be taken as examples of 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 (11)

1. A method of treating a hydrocarbon containing formation, comprising:

providing water through one or more wellbores to at least a portion of a hydrocarbon containing formation;

combusting at least a portion of a fuel stream comprising hydrogen sulfide in the presence of an oxidant in one or more heaters positioned in one or more of the wellbores to produce a combustion by-products stream, wherein the combustion by-products stream comprises one or more sulfur oxides;

transferring heat from the combustion to a portion of the hydrocarbon containing formation; and

contacting at least a portion of the combustion by-products stream with water in the hydrocarbon formation to release a heat of solution, where water contacted with the combustion by-products stream in the hydrocarbon formation may be the water provided to the hydrocarbon formation or may be water present in the hydrocarbon formation.

2. The method ofclaim 1, wherein the combustion by-products stream comprises sulfuric acid, and wherein contacting of water with at least a portion of the combustion by-products stream comprising sulfuric acid generates heat by contact of water with sulfuric acid.

3. The method ofclaim 1, wherein at least one of the sulfur oxides comprises sulfur dioxide and/or sulfur trioxide.

4. The method ofclaim 1, wherein at least a portion of the fuel stream is produced from formation fluids from the hydrocarbon formation.

5. The method ofclaim 1, wherein at least one of the heaters comprises a flameless distributed combustor and/or a burner.

6. The method ofclaim 1, further comprising transferring at least a portion of the combustion by-products stream comprising sulfur oxides into the formation such that at least a portion of the sulfur oxides reduces the viscosity of hydrocarbons in the formation.

7. The method ofclaim 1, wherein at least a portion of water heated by contact with the combustion by-products stream and/or at least a portion of the combustion by-products stream provide a driving force for mobilization of at least a portion of the formation fluids.

8. The method ofclaim 1, wherein at least a portion of the water provided to the wellbores is in the form of steam and the steam heats a mixture formed from the fuel and the oxidant to at or above the auto-ignition temperature of the mixture.

9. The method ofclaim 1, wherein a portion of the water is provided in an first portion of a wellbore, and wherein combustion occurs in a second portion of the wellbore in which the water is provided, where the second portion of the wellbore communicates thermally with the first portion of the wellbore such that at least a portion of the heat generated by combustion is transferred to a portion of the water.

10. The method ofclaim 9, wherein at least a portion of the water heated by the heat generated by combustion communicates thermally with a portion of the hydrocarbon formation to transfer heat to the portion of the hydrocarbon formation.

11. The method ofclaim 1, wherein the fuel stream is provided to one or more fuel conduits in at least one of the heaters, wherein at least one of the conduits provides a portion of the fuel comprising hydrogen sulfide and at least one of the conduits provides another fuel.

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