2. Description of Related Art Hydrocarbons obtained from subterranean (e. g. , sedimentary) formations are often used as energy resources, as feedstocks, and as consumer products. Concerns over depletion of available hydrocarbon resources and 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 within 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 within 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.

Examples of in situ processes utilizing downhole heaters are illustrated in U. S. Patent Nos. 2,634, 961 to Ljungstrom, 2,732, 195 to Ljungstrom, 2,780, 450 to Ljungstrom, 2,789, 805 to Ljungstrom, 2,923, 535 to Ljungstrom, and 4,886, 118 to Van Meurs et al.

Combustion of a fuel may be used to heat a formation. Combusting a fuel to heat a formation may be more economical than using electricity to heat a formation. Several different types of heaters may use fuel combustion as a heat source that heats a formation. The combustion may take place in the formation, in a well, and/or near the surface. Combustion in the formation may be a fireflood. An oxidizer may be pumped into the formation. The oxidizer may be ignited to advance a fire front towards a production well. Oxidizer pumped into the formation may flow through the formation along fracture lines in the formation. Ignition of the oxidizer may not result in the fire front flowing uniformly through the formation.

Heat may be supplied to a formation from a surface heater. The surface heater may produce combustion gases that are circulated through wellbores to heat the formation. Alternately, a surface burner may be used to heat a heat transfer fluid that is passed through a wellbore to heat the formation. Examples of fired heaters, or surface burners that may be used to heat a subterranean formation, are illustrated in U. S. Patent Nos. 6,056, 057 to Vinegar et al. and 6,079, 499 to Mikus et al.

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. In some formations (e. g. , formations with relatively thin<BR> hydrocarbon layers, formations with relatively long horizontal hydrocarbon layers, etc. ), the use of horizontal heater wells may be more economically favorable. There is a need for systems and/or methods that can be efficiently used to form larger diameter horizontal wells which can in turn be used to heat formations. There is a need for systems and/or methods for providing heat efficiently and relatively inexpensively from heater wells to a hydrocarbon containing formation. There is also a need for heater wells that can be configured to allow burners and/or oxidizers to be placed on or near the surface of the formation. There is a need for heater wells that can be configured so that hot fluids from burners and/or oxidizers may flow through the heater well from a first end of the heater well and then exit the heater well at a second end.

SUMMARY OF THE INVENTION In an embodiment, hydrocarbons within a hydrocarbon containing formation (e. g. , a formation containing coal, oil shale, heavy hydrocarbons, or a combination thereof) may be converted in situ within the formation to yield a mixture of relatively high quality hydrocarbon products, hydrogen, and/or other products. One or more heat sources may be used to heat a portion of the hydrocarbon containing formation to temperatures that allow pyrolysis of the hydrocarbons. Hydrocarbons, hydrogen, and other formation fluids may be removed from the formation through one or more production wells. In some embodiments, formation fluids may be removed in a vapor phase.

In other embodiments, formation fluids may be removed in liquid and vapor phases or in a liquid phase.

Temperature and pressure in at least a portion of the formation may be controlled during pyrolysis to yield improved products from the formation.

In an embodiment, a system and a method may include an opening in the formation extending from a first location on the surface of the earth to a second location on the surface of the earth. Heat sources may be placed within the opening to provide heat to at least a portion of the formation.

A conduit may be positioned in the opening extending from the first location to the second location. In an embodiment, a heat source may be positioned proximate and/or in the conduit to provide heat to the conduit.

Transfer of the heat through the conduit may provide heat to a part of the formation. In some embodiments, an additional heater may be placed in an additional conduit to provide heat to the part of the formation through the additional conduit.

In some embodiments, an annulus is formed between a wall of the opening and a wall of the conduit placed within the opening extending from the first location to the second location. A heat source may be place proximate and/or in the annulus to provide heat to a portion the opening. The provided heat may transfer through the annulus to a part of the formation.

BRIEF DESCRIPTION OF THE DRAWINGS Advantages of the present invention may become apparent to those skilled in the art with the benefit of the following detailed description of the preferred embodiments and upon reference to the accompanying drawings in which: FIG. 1 depicts an illustration of stages of heating a hydrocarbon containing formation.

FIG. 2 shows a schematic view of an embodiment of a portion of an in situ conversion system for treating a hydrocarbon containing formation.

FIG. 3 illustrates a cross-sectional representation of an embodiment of a downhole combustor.

FIG. 4 depicts an embodiment of a heat source for a hydrocarbon containing formation.

FIG. 5 depicts a representation of a portion of a piping layout for heating a formation using downhole combustors.

FIG. 6 depicts a schematic representation of an embodiment of a heater well positioned within a hydrocarbon containing formation.

FIG. 7 depicts an embodiment of a heat source positioned in a hydrocarbon containing formation.

FIG. 8 depicts a schematic representation of an embodiment of a heat source positioned in a hydrocarbon containing formation.

FIG. 9 depicts an embodiment of a surface combustor heat source.

FIG. 10 depicts an embodiment of a conduit for a heat source with a portion of an inner conduit shown cut away to show a center tube.

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

DETAILED DESCRIPTION OF THE INVENTION The following description generally relates to systems and methods for treating a hydrocarbon containing formation (e. g. , a formation containing coal (including lignite, sapropelic coal, etc.), oil shale, carbonaceous shale, shungites, kerogen, bitumen, oil, kerogen and oil in a low permeability matrix, heavy hydrocarbons, asphaltites, natural mineral waxes, formations wherein kerogen is blocking production of other hydrocarbons, etc. ) using U- shaped heaters to heat the formation. Such formations may be treated to yield relatively high quality hydrocarbon products, hydrogen, and other products.

"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 within or adjacent to mineral matrices within 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,<BR> entrain, or be entrained in non-hydrocarbon fluids (e. g. , hydrogen ("H2"), nitrogen ("N2"), carbon monoxide, carbon dioxide, hydrogen sulfide, water, and ammonia).

A"formation"includes one or more hydrocarbon containing layers, one or more non-hydrocarbon layers, an overburden, and/or an underburden. An"overburden"and/or an"underburden"includes one or more different types of impermeable materials. For example, overburden and/or underburden may include rock, shale, mudstone, or wet/tight carbonate (i. e. , an impermeable carbonate without hydrocarbons). In some embodiments of in situ conversion processes, an overburden and/or an underburden may include a hydrocarbon containing layer or hydrocarbon containing layers that are relatively impermeable and are not subjected to temperatures during in situ conversion processing that result in significant characteristic changes of the hydrocarbon containing layers of the overburden and/or underburden. For example, an underburden may contain shale or mudstone. In some cases, the overburden and/or underburden may be somewhat permeable.

The terms"formation fluids"and"produced fluids"refer to fluids removed from a hydrocarbon containing formation and may include pyrolyzation fluid, synthesis gas, mobilized hydrocarbon, and water (steam). The term "mobilized fluid"refers to fluids within the formation that are able to flow because of thermal treatment of the formation. Formation fluids may include hydrocarbon fluids as well as non-hydrocarbon fluids.

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 within a conduit. A heat source may also include heat sources that generate heat by burning a fuel external to or within a formation, such as surface burners, downhole gas burners, flameless distributed combustors, and natural distributed combustors. In addition, it is envisioned that in some embodiments heat provided to or generated in one or more heat sources may be supplied by other sources of energy. The other sources of energy may directly heat a formation, or the energy may be applied to transfer media 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. 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 (e. g. , chemical reactions, solar energy, wind energy, biomass, or other sources of renewable energy). A chemical reaction may <BR> <BR> include an exothermic reaction (e. g. , an oxidation reaction). A heat source may include a heater that provides heat to a zone proximate and/or surrounding a heating location such as a heater well.

A"heater"is any system 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 (e. g., natural distributed combustors), and/or combinations thereof. A"unit of heat sources"refers to a number of heat sources that form a template that is repeated to create a pattern of heat sources within a formation.

The term"wellbore"refers to a hole in a formation made by drilling or insertion of a conduit into the <BR> <BR> formation. A wellbore may have a substantially circular cross section, or other cross-sectional shapes (e. g. , circles, ovals, squares, rectangles, triangles, slits, or other regular or irregular shapes). As used herein, the terms"well"and <BR> <BR> "opening, "when referring to an opening in the formation may be used interchangeably with the term"wellbore." "Pyrolyzation fluids"or"pyrolysis products"refers to fluid produced substantially during pyrolysis of hydrocarbons. Fluid produced by pyrolysis reactions may mix with other fluids in a formation. The mixture would be considered pyrolyzation fluid or pyrolyzation product. As used herein, "pyrolysis zone"refers to a volume of a<BR> formation (e. g. , a relatively permeable formation such as a tar sands formation) that is reacted or reacting to form a pyrolyzation fluid.

"Condensable hydrocarbons"are hydrocarbons that condense at 25 °C at 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.

Hydrocarbons in formations may be treated in various ways to produce many different products. In certain embodiments, such formations may be treated in stages. FIG. 1 illustrates several stages of heating a hydrocarbon containing formation. FIG. 1 also depicts an example of yield (barrels of oil equivalent per ton) (y axis) of formation fluids from a hydrocarbon containing formation versus temperature (°C) (x axis) of the formation (as the formation is heated at a relatively low rate).

Desorption of methane and vaporization of water occurs during stage 1 heating. Heating of the formation through stage 1 may be performed as quickly as possible. For example, when a hydrocarbon containing formation is initially heated, hydrocarbons in the formation may desorb adsorbed methane. The desorbed methane may be produced from the formation. If the hydrocarbon containing formation is heated further, water within the hydrocarbon containing formation may be vaporized. Water may occupy, in some hydrocarbon containing formations, between about 10 % to about 50 % of the pore volume in the formation. In other formations, water may occupy larger or smaller portions of the pore volume. Water typically is vaporized in a formation between about 160 °C and about 285 °C for pressures of about 6 bars absolute to 70 bars absolute. In some embodiments, the vaporized water may produce wettability changes in the formation and/or increase formation pressure. The wettability changes and/or increased pressure may affect pyrolysis reactions or other reactions in the formation. In certain embodiments, the vaporized water may be produced from the formation. In other embodiments, the vaporized water may be used for steam extraction and/or distillation in the formation or outside the formation.

Removing the water from and increasing the pore volume in the formation may increase the storage space for hydrocarbons within the pore volume.

After stage 1 heating, the formation may be heated further, such that a temperature within the formation <BR> <BR> reaches (at least) an initial pyrolyzation temperature (e. g. , a temperature at the lower end of the temperature range shown as stage 2). Hydrocarbons within the formation may be pyrolyzed throughout stage 2. A pyrolysis temperature range may vary depending on types of hydrocarbons within the formation. A pyrolysis temperature range may include temperatures between about 250 °C and about 900 °C. A pyrolysis temperature range for producing desired products may extend through only a portion of the total pyrolysis temperature range. In some embodiments, a pyrolysis temperature range for producing desired products may include temperatures between about 250 °C to about 400 °C. If a temperature of hydrocarbons in a formation is slowly raised through a temperature range from about 250 °C to about 400 °C, production of pyrolysis products may be substantially complete when the temperature approaches 400 °C. Heating the hydrocarbon containing formation with a plurality of heat sources may establish thermal gradients around the heat sources that slowly raise the temperature of hydrocarbons in the formation through a pyrolysis temperature range.

In some in situ conversion embodiments, a temperature of the hydrocarbons to be subjected to pyrolysis may not be slowly increased throughout a temperature range from about 250 °C to about 400 °C. The hydrocarbons <BR> <BR> in the formation may be heated to a desired temperature, e. g. , about 325°C. Other temperatures may be selected as the desired temperature. Superposition of heat from heat sources may allow the desired temperature to be relatively quickly and efficiently established in the formation. Energy input into the formation from the heat sources may be adjusted to maintain the temperature in the formation substantially at the desired temperature. The hydrocarbons may be maintained substantially at the desired temperature until pyrolysis declines such that production of desired formation fluids from the formation becomes uneconomical.

Formation fluids including pyrolyzation fluids may be produced from the formation. The pyrolyzation fluids may include, but are not limited to, hydrocarbons, hydrogen, carbon dioxide, carbon monoxide, hydrogen sulfide, ammonia, nitrogen, water, and mixtures thereof. As the temperature of the formation increases, the amount of condensable hydrocarbons in the produced formation fluid tends to decrease. At high temperatures, the formation may produce mostly methane and/or hydrogen. If a hydrocarbon containing formation is heated throughout an entire pyrolysis range, the formation may produce only small amounts of hydrogen towards an upper limit of the pyrolysis range. After all of the available hydrogen is depleted, a minimal amount of fluid production from the formation will typically occur.

In an in situ conversion process embodiment, pressure may be increased within a selected section of a portion of a hydrocarbon containing formation to a selected pressure during pyrolysis. A selected pressure may be within a range from about 2 bars absolute to about 72 bars absolute or, in some embodiments, 2 bars absolute to 36 bars absolute. Alternatively, a selected pressure may be within a range from about 2 bars absolute to about 18 bars absolute.

In an embodiment, a portion of a hydrocarbon containing formation may be heated to increase a partial pressure of H2. In some embodiments, an increased H2 partial pressure may include H2 partial pressures in a range from about 0.5 bars absolute to about 7 bars absolute. Alternatively, an increased H2 partial pressure range may include H2 partial pressures in a range from about 5 bars absolute to about 7 bars absolute. For example, a majority of hydrocarbon fluids may be produced wherein a H2 partial pressure is within a range of about 5 bars absolute to about 7 bars absolute. A range of H2 partial pressures within the pyrolysis H2 partial pressure range may vary depending on, for example, temperature and pressure of the heated portion of the formation.

After pyrolysis of hydrocarbons, a large amount of carbon and some hydrogen may still be present in the formation. A significant portion of remaining carbon in the formation can be produced from the formation in the form of synthesis gas. Synthesis gas generation may take place during stage 3 heating depicted in FIG. 1. Stage 3 may include heating a hydrocarbon containing formation to a temperature sufficient to allow synthesis gas generation. For example, synthesis gas may be produced within a temperature range from about 400 °C to about 1200 °C. The temperature of the formation when the synthesis gas generating fluid is introduced to the formation may determine the composition of synthesis gas produced within the formation. If a synthesis gas generating fluid is introduced into a formation at a temperature sufficient to allow synthesis gas generation, synthesis gas may be generated within the formation. The generated synthesis gas may be removed from the formation through a production well or production wells. A large volume of synthesis gas may be produced during generation of synthesis gas.

Hydrocarbon containing formations may be selected for in situ conversion based on properties of at least a portion of the formation. For example, a formation may be selected based on richness, thickness, and/or depth (i. e., thickness of overburden) of the formation. In addition, the types of fluids producible from the formation may be a factor in the selection of a formation for in situ conversion. In certain embodiments, the quality of the fluids to be produced may be assessed in advance of treatment. Assessment of the products that may be produced from a formation may generate significant cost savings since only formations that will produce desired products need to be subjected to in situ conversion. Properties that may be used to assess hydrocarbons in a formation include, but are not limited to, an amount of hydrocarbon liquids that may be produced from the hydrocarbons, a likely API gravity of the produced hydrocarbon liquids, an amount of hydrocarbon gas producible from the formation, and/or an amount of carbon dioxide and water that in situ conversion will generate.

FIG. 2 shows a schematic view of an embodiment of a portion of an in situ conversion system for treating a hydrocarbon containing formation. Heat sources 100 may be placed within at least a portion of the hydrocarbon containing formation. Heat sources 100 may include, for example, electric heaters such as insulated conductors, conductor-in-conduit heaters, surface burners, flameless distributed combustors, and/or natural distributed combustors. Heat sources 100 may also include other types of heaters. Heat sources 100 may provide heat to at least a portion of a hydrocarbon containing formation. Energy may be supplied to the heat sources 100 through supply lines 102. The supply lines may be structurally different depending on the type of heat source or heat sources being used to heat the formation. Supply lines for heat sources may transmit electricity for electric heaters, may transport fuel for combustors, or may transport heat exchange fluid that is circulated within the formation.

Production wells 104 may be used to remove formation fluid from the formation. Formation fluid produced from production wells 104 may be transported through collection piping 106 to treatment facilities 108.

Formation fluids may also be produced from heat sources 100. For example, fluid may be produced from heat sources 100 to control pressure within the formation adjacent to the heat sources. Fluid produced from heat sources 100 may be transported through tubing or piping to collection piping 106 or the produced fluid may be transported through tubing or piping directly to treatment facilities 108. Treatment facilities 108 may include separation units, reaction units, upgrading units, fuel cells, turbines, storage vessels, and other systems and units for processing produced formation fluids.

An in situ conversion system for treating hydrocarbons may include barrier wells 110. In certain embodiments, barrier wells 110 may include freeze wells. In some embodiments, barriers may be used to inhibit migration of fluids (e. g. , generated fluids and/or groundwater) into and/or out of a portion of a formation undergoing an in situ conversion process. Barriers may include, but are not limited to naturally occurring portions (e. g. , overburden and/or underburden), freeze wells, frozen barrier zones, low temperature barrier zones, grout walls, sulfur wells, dewatering wells, injection wells, a barrier formed by a gel produced in the formation, a barrier formed by precipitation of salts in the formation, a barrier formed by a polymerization reaction in the formation, sheets driven into the formation, or combinations thereof.

As shown in FIG. 2, in addition to heat sources 100, one or more production wells 104 will typically be placed within the portion of the hydrocarbon containing formation. Formation fluids may be produced through production well 104. In some embodiments, production well 104 may include a heat source. The heat source may heat the portions of the formation at or near the production well and allow for vapor phase removal of formation fluids. The need for high temperature pumping of liquids from the production well may be reduced or eliminated.

Avoiding or limiting high temperature pumping of liquids may significantly decrease production costs. 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, and/or (3) increase formation permeability at or proximate the production well. In some in situ conversion process embodiments, an amount of heat supplied to production wells is significantly less than an amount of heat applied to heat sources that heat the formation.

River crossing rigs may be used to drill horizontal wellbores or substantially horizontal wellbores through a hydrocarbon layer. In certain embodiments, river crossing rigs are used to drill angled wellbores through an overburden of a formation with a substantially horizontal wellbore within the hydrocarbon layer. The river crossing rig may form a wellbore with a first opening at a first position on the surface and a second opening at a second position on the surface at the other end of the wellbore. A river crossing rig may include machinery at sites selected for the first and second openings. Machinery (e. g. , at the site of the first opening) may be used to drill the wellbore<BR> while the same machinery or other machinery (e. g. , at the site of the second opening) may be used to pull<BR> equipment (e. g. , heat sources, production conduits, etc. ) into the wellbore. In forming a wellbore with a river crossing rig, the drilling string of the river crossing rig may drill the wellbore at an angle as the drilling string enters the overburden of the formation. Drilling entry angles for river crossing rigs may vary between about 5° and about 20° with a typical angle of about 10° or about 12°. The wellbore is drilled at the entry angle until a specified depth is reached (generally at some location within the hydrocarbon layer of the formation), at which depth the drilling string is turned to drill in a substantially horizontally direction through the formation. The substantially horizontal section of the wellbore is drilled until the wellbore reaches a predetermined horizontal length. After the predetermined horizontal length is reached, the drilling string is turned to an exit angle, which is typically, but not necessarily, the same as the entry angle, to meet with machinery at the second end of the wellbore.

After the wellbore has been formed, machinery at either the first end and/or the second end of the wellbore may be used to pull equipment into the wellbore. In some embodiments, as the drilling string is pulled from the wellbore, the drilling string may be used to ream out the wellbore and/or increase the diameter of the wellbore. <BR> <BR> <P>Pulling equipment (e. g. , heaters or heat sources) into a long horizontal wellbore may be more efficient than pushing the equipment into the wellbore. River crossing rigs generally provide an inexpensive and efficient method for forming a horizontal wellbore in a hydrocarbon layer. The horizontal wellbore may have a first opening at a first position on the surface and a second opening at a second position on the surface. River crossing rigs are operated by companies such as The Crossing Company Inc. (Nisku, Alberta).

FIG. 3 illustrates a cross-sectional representation of an embodiment of a downhole combustor for heating a formation. Opening 112 is a single opening within hydrocarbon layer 114 that may have first end 116 and second end 118. Oxidizers 120 may be placed in opening 112 proximate a junction of overburden 122 and hydrocarbon layer 114 at first end 116 and second end 118. Insulation 124 may be placed proximate each oxidizer 120. Fuel conduit 126 may be used to provide fuel 128 from fuel source 130 to oxidizer 120. Oxidizing fluid 132 may be provided into opening 112 from oxidizing fluid source 134 through conduit 136. Casing 138 may be placed in opening 112. Casing 138 may be made of carbon steel. Portions of casing 138 that may be subjected to much higher temperatures (e. g. , proximate oxidizers 120) may include stainless steel or other high temperature, corrosion resistant metal. In some embodiments, casing 138 may extend into portions of opening 112 within overburden 122.

In a heat source embodiment, oxidizing fluid 132 and fuel 128 are provided to oxidizer 120 in first end 116. Heated fluids from oxidizer 120 in first end 116 tend to flow through opening 112 towards second end 118.

Heat may transfer from the heated fluids to hydrocarbon layer 126 along a length of opening 112. The heated fluids may be removed from the formation through second end 118. During this time, oxidizer 120 at second end 118 may be turned off. The removed fluids may be provided to a second opening in the formation and used as oxidizing fluid and/or fuel in the second opening. After a selected time (e. g. , about a week), oxidizer 120 at first end 116 may be turned off. At this time, oxidizing fluid 132 and fuel 128 may be provided to oxidizer 120 at second end 118 and the oxidizer turned on. Heated fluids may be removed during this time through first end 116. Oxidizers 120 at first end 116 and at second end 118 may be used alternately for selected times (e. g. , about a week) to heat hydrocarbon layer 114. This may provide a more substantially uniform heating profile of hydrocarbon layer 114. Removing the heated fluids from the opening through an end distant from an oxidizer may reduce a possibility of coking within opening 112 as heated fluids are removed from the opening separately from incoming fluids. The use of the heat content of an oxidizing fluid may also be more efficient as the heated fluids can be used in a second opening or second downhole combustor.

FIG. 4 depicts an embodiment of a heat source for a hydrocarbon containing formation. Fuel conduit 126 may be placed within opening 112. In some embodiments, opening 112 may include casing 138. Opening 112 is a single opening within the formation that may have first end 116 at a first location on the surface of the earth and second end 118 at a second location on the surface of the earth. Oxidizers 120 may be positioned proximate the fuel conduit in hydrocarbon layer 114. Oxidizers 120 may be separated by a distance ranging from about 3 m to about 50 m (e. g. , about 30 m). Fuel 128 may be provided to fuel conduit 126. In addition, steam 135 may be provided to fuel conduit 126 to reduce coking proximate oxidizers 120 and/or in fuel conduit 126. Oxidizing fluid 132 (e. g. , air and/or oxygen) may be provided to oxidizers 120 through opening 112. Oxidation of fuel 128 may generate heat. The heat may transfer to a portion of the formation. Oxidation products 140 may exit opening 112 proximate second location 118.

FIG. 5 depicts a schematic, from an elevated view, of an embodiment for using downhole combustors depicted in the embodiment of FIG. 3. In some embodiments, the schematic depicted in FIG. 5, and variations of <BR> <BR> the schematic, may be used for other types of heaters (e. g. , surface burners, flameless distributed combustors, etc.) that may utilize fuel fluid and/or oxidizing fluid in one or more openings in a hydrocarbon containing formation.

Openings 142,144, 146,148, 150, and 152 may have downhole combustors (as shown in the embodiment of FIG.

3) placed in each opening. More or fewer openings (i. e. , openings with downhole combustors) may be used as needed. A number of openings may depend on, for example, a size of an area for treatment, a desired heating rate, or a selected well spacing. Conduit 154 may be used to transport fluids from a downhole combustor in opening 142 to downhole combustors in openings 144,146, 148,150, and 152. The openings may be coupled in series using conduit 154. Compressor 156 may be used between openings, as needed, to increase a pressure of fluid between the openings. Additional oxidizing fluid may be provided to each compressor 156 from conduit 158. A selected flow of fuel from a fuel source may be provided into each of the openings.

For a selected time, a flow of fluids may be from first opening 142 towards opening 152. Flow of fluid within first opening 142 may be substantially opposite flow within second opening 144. Subsequently, flow within second opening 144 may be substantially opposite flow within third opening 146, etc. This may provide substantially more uniform heating of the formation using the downhole combustors within each opening. After the selected time, the flow of fluids may be reversed to flow from opening 152 towards first opening 142. This process may be repeated as needed during a time needed for treatment of the formation. Alternating the flow of fluids may enhance the uniformity of a heating profile of the formation.

FIG. 6 depicts a schematic representation of an embodiment of a heater well positioned within a hydrocarbon containing formation. Heater well 159 may be placed within opening 112. In certain embodiments, opening 112 is a single opening within the formation that may have first end 116 and second end 118 contacting the surface of the earth. Opening 112 may include elongated portions 160,162, 164. Elongated portions 160,164 may <BR> <BR> be placed substantially in a non-hydrocarbon containing layer (e. g. , overburden). Elongated portion 162 may be placed substantially within hydrocarbon layer 114 and/or a treatment zone.

In some heat source embodiments, casing 138 may be placed in opening 112. In some embodiments, casing 138 may be made of carbon steel. Portions of casing 138 that may be subjected to high temperatures may be made of more temperature resistant material (e. g. , stainless steel). In some embodiments, casing 138 may extend into elongated portions 160, 164 within overburden 122. Oxidizers 120, 166 may be placed proximate a junction of overburden 122 and hydrocarbon layer 114 at first end 116 and second end 118 of opening 112. Oxidizers 120,166 may include burners (e. g. , inline burners and/or ring burners). Insulation 124 may be placed proximate each oxidizer 120,166. Burners may be obtained from John Zink Company (Tulsa, Oklahoma) or Callidus Technologies (Tulsa, Oklahoma).

Conduit 168 may be placed within opening 112 forming annulus 170 between an outer surface of conduit 168 and an inner surface of the casing 138. Annulus 170 may have a regular and/or irregular shape within the opening. In some embodiments, oxidizers may be positioned within the annulus and/or the conduit to provide heat to a portion of the formation. Oxidizer 120 is positioned within annulus 170 and may include a ring burner. Heated fluids from oxidizer 120 may flow within annulus 170 to second end 118. Heated fluids from oxidizer 166 may be directed by conduit 168 through opening 112. Heated fluids may include, but are not limited to oxidation products, oxidizing fluid, and/or fuel. Flow of the heated fluids through annulus 170 may be in the opposite direction of the flow of heated fluids in conduit 168. In alternative embodiments, oxidizers 120,166 may be positioned proximate the same end of opening 112 to allow the heated fluids to flow through opening 112 in the same direction.

Fuel conduits 126 may be used to provide fuel 128 from fuel source 130 to oxidizers 120,166. Oxidizing fluid 132 may be provided to oxidizers 120,166 from oxidizing fluid source 134 through conduits 136. Flow of fuel 128 and oxidizing fluid 132 may generate oxidation products at oxidizers 120,166. In some embodiments, a flow of oxidizing fluid 132 may be controlled to control oxidation at oxidizers 120,166. Alternatively, a flow of fuel may be controlled to control oxidation at oxidizers 120,166.

In a heat source embodiment, oxidizing fluid 132 and fuel 128 are provided to oxidizer 120. Heated fluids from oxidizer 120 in first end 116 tend to flow through opening 112 towards second end 118. Heat may transfer from the heated fluids to hydrocarbon layer 114 along a segment of opening 112. The heated fluids may be removed from the formation through second end 118. In some embodiments, a portion of the heated fluids removed from the formation may be provided to fuel conduit 126 at second end 118 to be utilized as fuel in oxidizer 166.

Fluids heated by oxidizer 166 may be directed through the opening in conduit 168 to first end 116. In some embodiments, a portion of the heated fluids is provided to fuel conduit 126 at first end 116. Alternatively, heated fluids produced from either end of the opening may be directed to a second opening in the formation for use as either oxidizing fluid and/or fuel. In some embodiments, heated fluids may be directed toward one end of the opening for use in a single oxidizer.

Oxidizers 120,166 may be utilized concurrently. In some embodiments, use of the oxidizers may <BR> <BR> alternate. Oxidizer 120 may be turned off after a selected time period (e. g. , about a week). At this time, oxidizing fluid 132 and fuel 128 may be provided to oxidizer 166. Heated fluids may be removed during this time through first end 116. Use of oxidizer 120 and oxidizer 166 may be alternated for selected times to heat hydrocarbon layer 114. Flowing oxidizing fluids in opposite directions may produce a more uniform heating profile in hydrocarbon layer 114. Removing the heated fluids from the opening through an end distant from the oxidizer at which the heated fluids were produced may reduce the possibility for coking within the opening. Heated fluids may be removed from the formation in exhaust conduits in some embodiments. In addition, the potential for coking may be further reduced by removing heated fluids from the opening separately from incoming fluids (e. g., fuel and/or oxidizing fluid). In certain instances, some heat within the heated fluids may transfer to the incoming fluids to increase the efficiency of the oxidizers.

FIG. 7 depicts an embodiment of a heat source positioned within a hydrocarbon containing formation.

Surface units 171 (e. g. , oxidizers, burners and/or furnaces) provide heat to an opening in the formation. Surface units 171 may provide heat to conduit 168 positioned in conduit 173. Surface unit 171 positioned proximate first end 116 of opening 112 may heat fluids 174 (e. g. , air, oxygen, steam, fuel, and/or flue gas) provided to surface unit 171. Conduit 168 may extend into surface unit 171 to allow fluids heated in surface unit 171 proximate first end 116 to flow into conduit 168. Conduit 168 may direct fluid flow to second end 118. At second end 118 conduit 168 may provide fluids to surface unit 171. Surface unit 171 may heat the fluids. The heated fluids may flow into conduit 173. Heated fluids may then flow through conduit 173 towards first end 116. In some embodiments, conduit 168 and conduit 173 may be concentric.

In alternative embodiments, fluids may be compressed prior to entering the surface unit. Compression of the fluids may maintain a fluid flow through the opening. Flow of fluids through the conduits may affect the transfer of heat from the conduits to the formation.

In alternative embodiments, a single surface unit may be utilized for heating proximate first end 116.

Conduits may be positioned such that fluid within an inner conduit flows into the annulus between the inner conduit and an outer conduit. Thus the fluid flow in the inner conduit and the annulus may be counter current.

A heat source embodiment is illustrated in FIG. 8. Conduits 168,172 may be placed within opening 112.

Opening 112 may be an open wellbore. In alternative embodiments, a casing may be included in a portion of the <BR> <BR> opening (e. g. , in the portion in the overburden). In addition, some embodiments may include insulation surrounding a portion of conduits 168,172. For example, the portions of the conduits within overburden 122 may be insulated to inhibit heat transfer from the heated fluids to the overburden and/or a portion of the formation proximate the oxidizers.

FIG. 9 illustrates an embodiment of a surface combustor that may heat a section of a hydrocarbon containing formation. Fuel 128 may be provided to burner 178 through conduit 136. An oxidizing fluid may be provided into burner 178 from oxidizing fluid source 134. Fuel 128 may be oxidized with the oxidizing fluid in burner 178 to form oxidation products 140. Fuel 128 may include, but is not limited to, hydrogen, methane, ethane, and/or other hydrocarbons. Burner 178 may be located external to the formation or within opening 112 in hydrocarbon layer 114. Source 182 may heat fuel 128 to a temperature sufficient to support oxidation in burner 178. Source 182 may heat fuel 128 to a temperature of about 1425 °C. Source 182 may be coupled to an end of conduit 180. In a heat source embodiment, source 182 is a pilot flame. The pilot flame may burn with a small flow of fuel 128. In other embodiments, source 182 may be an electrical ignition source.

Oxidation products 140 may be provided to opening 112 within inner conduit 184 coupled to burner 178.

Heat may be transferred from oxidation products 140 through outer conduit 186 into opening 112 and to hydrocarbon layer 114 along a length of inner conduit 184. Oxidation products 140 may cool along the length of inner conduit 184. For example, oxidation products 140 may have a temperature of about 870 °C proximate top of inner conduit 184 and a temperature of about 650°C proximate bottom of inner conduit 184. A section of inner conduit 184 proximate burner 178 may have ceramic insulator 188 disposed on an inner surface of inner conduit 184. Ceramic insulator 188 may inhibit melting of inner conduit 184 and/or insulation 124 proximate burner 178.

Opening 112 may extend into the formation a length up to about 550 m below surface 190.

Inner conduit 184 may provide oxidation products 140 into outer conduit 186 proximate a bottom of opening 112. Inner conduit 184 may have insulation 124. FIG. 10 illustrates an embodiment of inner conduit 184 with insulation 124 and ceramic insulator 188 disposed on an inner surface of inner conduit 184. Insulation 124 may inhibit heat transfer between fluids in inner conduit 184 and fluids in outer conduit 186. A thickness of insulation 124 may be varied along a length of inner conduit 184 such that heat transfer to hydrocarbon layer 114 may vary along the length of inner conduit 184. For example, a thickness of insulation 124 may be tapered from a larger thickness to a lesser thickness from a top portion to a bottom portion, respectively, of inner conduit 184 in opening 112. Such a tapered thickness may provide more uniform heating of hydrocarbon layer 114 along the length of inner conduit 184 in opening 112. Insulation 124 may include ceramic and metal materials. Oxidation products 140 may return to surface 190 through outer conduit 186. Outer conduit 186 may have insulation 124', as depicted in FIG. 9. Insulation 124'may inhibit heat transfer from outer conduit 186 to overburden 122.

Oxidation products 140 may be provided to an additional burner through conduit 192 at surface 190.

Oxidation products 140 may be used as a portion of a fuel fluid in the additional burner. Doing so may increase an efficiency of energy output versus energy input for heating hydrocarbon layer 114. The additional burner may provide heat through an additional opening in hydrocarbon layer 114.

In some embodiments, an electric heater may provide heat in addition to heat provided from a surface combustor. The electric heater may be, for example, an insulated conductor heater or a conductor-in-conduit heater as described in any of the above embodiments. The electric heater may provide the additional heat to a hydrocarbon containing formation so that the hydrocarbon containing formation is heated substantially uniformly along a depth of an opening in the formation.

Subsurface pressure in a hydrocarbon containing formation may correspond to the fluid pressure generated within the formation. Heating hydrocarbons within a hydrocarbon containing formation may generate fluids by pyrolysis. The generated fluids may be vaporized within the formation. Vaporization and pyrolysis reactions may increase the pressure within the formation. Fluids that contribute to the increase in pressure may include, but are not limited to, fluids produced during pyrolysis and water vaporized during heating. As temperature within a selected section of a heated portion of the formation increase, a pressure within the selected section may increase as a result of increased fluid generation and vaporization of water. Controlling a rate of fluid removal from the formation may allow for control of pressure in the formation.

In some embodiments, pressure within a selected section of a heated portion of a hydrocarbon containing formation may vary depending on factors such as depth, distance from a heat source, a richness of the hydrocarbons within the hydrocarbon containing formation, and/or a distance from a producer well. Pressure within a formation may be determined at a number of different locations (e. g. , near or at production wells, near or at heat sources, or at monitor wells).

Heating of a hydrocarbon containing formation to a pyrolysis temperature range may occur before substantial permeability has been generated within the hydrocarbon containing formation. An initial lack of permeability may inhibit the transport of generated fluids from a pyrolysis zone within the formation to a production well. As heat is initially transferred from a heat source to a hydrocarbon containing formation, a fluid pressure within the hydrocarbon containing formation may increase proximate a heat source. Such an increase in fluid pressure may be caused by generation of fluids during pyrolysis of at least some hydrocarbons in the formation. The increased fluid pressure may be released, monitored, altered, and/or controlled through the heat source. For example, the heat source may include a valve that allows for removal of some fluid from the formation.

In some heat source embodiments, the heat source may include an open wellbore configuration that inhibits pressure damage to the heat source.

In an in situ conversion process embodiment, pressure may be increased within a selected section of a portion of a hydrocarbon containing formation to a selected pressure during pyrolysis. A selected pressure may be within a range from about 2 bars absolute to about 72 bars absolute or, in some embodiments, 2 bars absolute to 36 bars absolute. Alternatively, a selected pressure may be within a range from about 2 bars absolute to about 18 bars absolute. In some in situ conversion process embodiments, a majority of hydrocarbon fluids may be produced from a formation having a pressure within a range from about 2 bars absolute to about 18 bars absolute. The pressure during pyrolysis may vary or be varied. The pressure may be varied to alter and/or control a composition of a formation fluid produced, to control a percentage of condensable fluid as compared to non-condensable fluid, and/or to control an API gravity of fluid being produced. For example, decreasing pressure may result in production of a larger condensable fluid component. The condensable fluid component may contain a larger percentage of olefins.

In some in situ conversion process embodiments, increased pressure due to fluid generation may be maintained within the heated portion of the formation. Maintaining increased pressure within a formation may inhibit formation subsidence during in situ conversion. Increased formation pressure may promote generation of high quality products during pyrolysis. Increased formation pressure may facilitate vapor phase production of fluids from the formation. Vapor phase production may allow for a reduction in size of collection conduits used to transport fluids produced from the formation. Increased formation pressure may reduce or eliminate the need to compress formation fluids at the surface to transport the fluids in collection conduits to surface facilities.

Maintaining increased pressure within a formation may also facilitate generation of electricity from produced non- condensable fluid. For example, the produced non-condensable fluid may be passed through a turbine to generate electricity.

Increased pressure in the formation may also be maintained to produce more and/or improved formation fluids. In certain in situ conversion process embodiments, significant amounts (e. g. , a majority) of the hydrocarbon fluids produced from a formation may be non-condensable hydrocarbons. Pressure may be selectively increased and/or maintained within the formation to promote formation of smaller chain hydrocarbons in the formation.

Producing small chain hydrocarbons in the formation may allow more non-condensable hydrocarbons to be produced from the formation. The condensable hydrocarbons produced from the formation at higher pressure may be of a higher quality (e. g. , higher API gravity) than condensable hydrocarbons produced from the formation at a lower pressure.

A high pressure may be maintained within a heated portion of a hydrocarbon containing formation to inhibit production of formation fluids having carbon numbers greater than, for example, about 25. Some high carbon number compounds may be entrained in vapor in the formation and may be removed from the formation with the vapor. A high pressure in the formation may inhibit entrainment of high carbon number compounds and/or multi-ring hydrocarbon compounds in the vapor. Increasing pressure within the hydrocarbon containing formation may increase a boiling point of a fluid within the portion. 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.

Maintaining increased pressure within a heated portion of the formation may surprisingly allow for production of large quantities of hydrocarbons of increased quality. Maintaining increased pressure may promote vapor phase transport of pyrolyzation fluids within the formation. Increasing the pressure often permits production of lower molecular weight hydrocarbons since such lower molecular weight hydrocarbons will more readily transport in the vapor phase in the formation.

Generation of lower molecular weight hydrocarbons (and corresponding increased vapor phase transport) is believed to be due, in part, to autogenous generation and reaction of hydrogen within a portion of the hydrocarbon containing formation. For example, maintaining an increased pressure may force hydrogen generated during pyrolysis into a liquid phase (e. g. , by dissolving). Heating the portion to a temperature within a pyrolysis temperature range may pyrolyze hydrocarbons within the formation to generate pyrolyzation fluids in a liquid phase. The generated components may include double bonds and/or radicals. H2 in the liquid phase may reduce double bonds of the generated pyrolyzation fluids, thereby reducing a potential for polymerization or formation of long chain compounds from the generated pyrolyzation fluids. In addition, hydrogen may also neutralize radicals in the generated pyrolyzation fluids. Therefore, H2 in the liquid phase may inhibit the generated pyrolyzation fluids from reacting with each other and/or with other compounds in the formation. Shorter chain hydrocarbons may enter the vapor phase and may be produced from the formation.

Operating an in situ conversion process at increased pressure may allow for vapor phase production of formation fluid from the formation. Vapor phase production may permit increased recovery of lighter (and relatively high quality) pyrolyzation fluids. Vapor phase production may result in less formation fluid being left in the formation after the fluid is produced by pyrolysis. Vapor phase production may allow for fewer production wells in the formation than are present using liquid phase or liquid/vapor phase production. Fewer production wells may significantly reduce equipment costs associated with an in situ conversion process.

In an embodiment, a portion of a hydrocarbon containing formation may be heated to increase a partial pressure of H2. In some embodiments, an increased H2 partial pressure may include H2 partial pressures in a range from about 0.5 bars to about 7 bars. Alternatively, an increased H2 partial pressure range may include H2 partial pressures in a range from about 5 bars to about 7 bars. For example, a majority of hydrocarbon fluids may be produced wherein a H2 partial pressure is within a range of about 5 bars to about 7 bars. A range of H2 partial pressures within the pyrolysis H2 partial pressure range may vary depending on, for example, temperature and pressure of the heated portion of the formation.

Maintaining a H2 partial pressure within the formation of greater than atmospheric pressure may increase an API value of produced condensable hydrocarbon fluids. Maintaining an increased H2 partial pressure may increase an API value of produced condensable hydrocarbon fluids to greater than about 25° or, in some instances, greater than about 30°. Maintaining an increased H2 partial pressure within a heated portion of a hydrocarbon containing formation may increase a concentration of H2 within the heated portion. The H2 may be available to react with pyrolyzed components of the hydrocarbons. Reaction of H2 with the pyrolyzed components of hydrocarbons may reduce polymerization of olefins into tars and other cross-linked, difficult to upgrade, products.

Therefore, production of hydrocarbon fluids having low API gravity values may be inhibited.

Controlling pressure and temperature within a hydrocarbon containing formation may allow properties of the produced formation fluids to be controlled. For example, composition and quality of formation fluids produced from the formation may be altered by altering an average pressure and/or an average temperature in a selected section of a heated portion of the formation. The quality of the produced fluids may be evaluated based on characteristics of the fluid such as, but not limited to, API gravity, percent olefins in the produced formation fluids, ethene to ethane ratio, atomic hydrogen to carbon ratio, percent of hydrocarbons within produced formation fluids having carbon numbers greater than 25, total equivalent production (gas and liquid), total liquids production, and/or liquid yield as a percent of Fischer Assay.

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