CA2700732A1

CA2700732A1 - Cryogenic treatment of gas

Info

Publication number: CA2700732A1
Application number: CA2700732A
Authority: CA
Inventors: Jose Luis Bravo; Albert Destrehan Harvey; Harold J. Vinegar
Original assignee: Shell Internationale Research Maatschappij B.V.; Jose Luis Bravo; Albert Destrehan Harvey; Harold J. Vinegar
Current assignee: Shell Internationale Research Maatschappij BV
Priority date: 2007-10-19
Filing date: 2008-10-13
Publication date: 2009-04-23
Also published as: JP2011501863A; IL204374A; JP5379804B2; US20090194286A1; IL204535A; WO2009052045A1; GB201004435D0; US8240774B2; RU2010119952A; US20090194524A1; IL204535A0; MA31859B1; EP2201433A1; WO2009052054A1; CA2698564A1; EP2201819A4; GB201004134D0; RU2010119955A; RU2510601C2; IL204375A

Abstract

Systems and method of treating a gas stream are described. A method of treating a gas stream includes cryogenically separating a first gas stream to form a second gas stream and a third stream.
The third stream is cryogenically contacted with a carbon dioxide stream to form a fourth and fifth stream. A majority of the second gas stream includes methane and/or molecular hydrogen.
A majority of the third stream includes one or more carbon oxides, hydrocarbons having a carbon number of at least 2, one or more sulfur compounds, or mixtures thereof. A majority of the fourth stream includes one or more of the carbon oxides and hydrocarbons having a carbon number of at least 2. A majority of the fifth stream includes hydrocarbons having a carbon number of at least 3 and one or more of the sulfur compounds.

Description

CRYOGENIC TREATMENT OF GAS

BACKGROUND
1. Field of the Invention [0001] The present invention relates generally to methods and systems for treatment of gas. More particularly, the invention relates to cryogenic treatment of gas produced from various subsurface formations such as hydrocarbon containing formations.
2. Description of Related Art [0002] Hydrocarbons obtained from subterranean formations are often used as energy resources, as feedstocks, and as consumer products. Concerns over depletion of available hydrocarbon resources and concerns over declining overall quality of produced hydrocarbons have led to development of processes for more efficient recovery, processing and/or use of available hydrocarbon resources. In situ processes may be used to remove hydrocarbon materials from subterranean formations. Chemical and/or physical properties of hydrocarbon material in a subterranean formation may need to be changed to allow hydrocarbon material to be more easily removed from the subterranean formation. The chemical and physical changes may include in situ reactions that produce removable fluids, composition changes, solubility changes, density changes, phase changes, and/or viscosity changes of the hydrocarbon material in the formation. A fluid may be, but is not limited to, a gas, a liquid, an emulsion, a slurry, and/or a stream of solid particles that has flow characteristics similar to liquid flow.

[0003] Formation fluids obtained from subterranean formations using an in situ heat treatment process may be sold and/or processed to produce commercial products.
For example, methane may be produced from a hydrocarbon containing formation using an in situ heat treatment process. The methane may be sold or used as a fuel, or the methane may be sold or used as a feedstock to produce other chemicals. The formation fluids produced by an in situ heat treatment process may have different properties and/or compositions than formation fluids obtained through conventional production processes.
Formation fluids obtained from subterranean formations using an in situ heat treatment process may not meet industry standards for transportation and/or commercial use.
Formation fluids may be separated using cryogenic techniques that separate methane from the formation fluids to form a stream that includes hydrocarbons having a carbon number of at least 2 and sulfur containing compounds. The stream containing sulfur compounds may be sequestered.

[0004] U.S. Patent Application No. 2008/0034789 to Fieler et al. describes a method for hydrocarbon processing. In Fieler, a first hydrocarbon stream comprising methane and acid gas is processed to remove a portion of the acid gas therefrom, thereby producing a third stream that includes the acid gas removed from the first stream and a stream that includes less than 100 ppm of sulfur-containing compounds. The third stream may be sequestered.

[0005] Stream containing hydrocarbons and sulfur compounds have energy value, however, the level of sulfur and/or other unwanted gases in these streams may make separation of such streams difficult and/or economically disadvantageous.
Thus, there is a need for improved methods and systems for treatment of formation fluids obtained from various hydrocarbon containing formations.

SUMMARY

[0006] Embodiments described herein generally relate to systems and methods for treating a formation fluids obtained from a subsurface formation.

[0007] This invention advantageously provides a method of treating a gas stream, comprising: in a first cryogenic zone, cryogenically separating a first gas stream to form a second gas stream and a third stream, wherein a majority of the second gas stream comprises methane and/or molecular hydrogen and a majority of the third stream comprises one or more carbon oxides, hydrocarbons having a carbon number of at least 2, one or more sulfur compounds, or mixtures thereof; and in a second cryogenic zone, cryogenically contacting the third stream with a carbon dioxide stream to form a fourth stream and a fifth stream, wherein a majority of the fourth stream comprises one or more of the carbon oxides and hydrocarbons having a carbon number of at least 2, and a majority of the fifth stream comprises hydrocarbons having a carbon number of at least 3 and one or more of the sulfur compounds.

[0008] The invention provides a system of a gas stream, comprising: a first cryogenic separation zone configured receive a first gas stream and to cryogenically separate the first gas stream to form a second gas stream and a third gas stream, wherein the second gas stream comprises methane and/or molecular hydrogen and the third gas stream comprises one or more carbon oxides, hydrocarbons having a carbon number of at least 2, one or more sulfur compounds, or mixtures thereof; a second cryogenic separation zone configured to receive the third gas stream and carbon dioxide and wherein the second cryogenic separation unit is configured to cryogenically separate the third gas stream to from a fourth stream and fifth stream, wherein a majority of the fourth stream comprises one or more of the carbon oxides and hydrocarbons having a carbon number of at least 2, and a majority of the fifth stream comprises hydrocarbons having a carbon number of at least 3 and one or more of the sulfur compounds.

[0009] The invention provides a method of treating a formation fluid, comprising:
separating formation fluid from a subsurface in situ heat treatment process to form a liquid stream and a first gas stream, wherein the first gas stream comprises one or more carbon oxides, one or more sulfur compounds, hydrocarbons and/or molecular hydrogen;
in a first cryogenic zone, cryogenically separating the first gas stream to form a second gas stream and a third stream, wherein a majority of the second gas stream comprises methane and/or molecular hydrogen, and the third stream comprises hydrocarbons having a carbon number of at least 2, one or more sulfur compounds, one or more carbon oxides, or mixtures thereof; and in a second cryogenic zone, cryogenically separating the third gas stream to form a fourth stream and a fifth stream, wherein a majority the fourth stream comprises one or more carbon oxides and hydrocarbons having a carbon number of at most 2;
and a majority of the fifth stream comprises hydrocarbons having a carbon number of at least 3 and/or one or more sulfur compounds.

[0010] In further embodiments, features from specific embodiments may be combined with features from other embodiments. For example, features from one embodiment may be combined with features from any of the other embodiments.

[0011] In further embodiments, treating a subsurface formation is performed using any of the methods and/or systems, described herein.

[0012] In further embodiments, additional features may be added to the specific embodiments described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

[0013] Advantages of the present invention may become apparent to those skilled in the art with the benefit of the following detailed description and upon reference to the accompanying drawings in which:

[0014] FIG. 1 depicts a schematic view of an embodiment of a portion of the in situ heat treatment system for treating the hydrocarbon containing formation.

[0015] FIG. 2 depicts a schematic representation of an embodiment of a system for treating the mixture produced from an in situ heat treatment process.

[0016] FIG. 3 depicts a schematic representation of an embodiment of a system for treating in situ heat treatment process gas.

[0017] FIG. 4 depicts a schematic representation of an embodiment of a system for treating in situ heat treatment process gas.

[0018] FIG. 5 depicts a schematic representation of an embodiment of a system for treating in situ heat treatment process gas.

[0019] FIG. 6 depicts a schematic representation of an embodiment of a system for treating in situ heat treatment process gas.

[0020] FIG. 7 depicts a schematic representation of an embodiment of a system for treating in situ heat treatment process gas.

[0021] FIG. 8 depicts a schematic representation of an embodiment of a system for producing fuel for downhole oxidizer assemblies.

[0022] 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

[0023] The following description generally relates to systems and methods for treating hydrocarbons in the formations. Such formations may be treated to yield hydrocarbon products, hydrogen, and other products.

[0024] "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.

[0025] "ASTM" refers to American Standard Testing and Materials.

[0026] "Condensable hydrocarbons" are hydrocarbons that condense at 25 C and one atmosphere absolute pressure. Condensable hydrocarbons may include a mixture of hydrocarbons having carbon numbers greater than 4. "Non-condensable hydrocarbons" are hydrocarbons that do not condense at 25 C and one atmosphere absolute pressure. Non-condensable hydrocarbons may include hydrocarbons having carbon numbers less than 5.

[0027] "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.

[0028] A "formation" includes one or more hydrocarbon containing layers, one or more non-hydrocarbon layers, an overburden, and/or an underburden. "Hydrocarbon layers"
refer to layers in the formation that contain hydrocarbons. The hydrocarbon layers may contain non-hydrocarbon material and hydrocarbon material. The "overburden"
and/or the "underburden" include one or more different types of impermeable materials.
For example, the overburden and/or underburden may include rock, shale, mudstone, or wet/tight carbonate. In some embodiments of in situ heat treatment processes, the overburden and/or the underburden may include a hydrocarbon containing layer or hydrocarbon containing layers that are relatively impermeable and are not subjected to temperatures during in situ heat treatment processing that result in significant characteristic changes of the hydrocarbon containing layers of the overburden and/or the underburden.
For example, the underburden may contain shale or mudstone, but the underburden is not allowed to heat to pyrolysis temperatures during the in situ heat treatment process. In some cases, the overburden and/or the underburden may be somewhat permeable.

[0029] "Formation fluids" refer to fluids present in a formation and may include pyrolyzation fluid, synthesis gas, mobilized hydrocarbons, and water (steam).
Formation fluids may include hydrocarbon fluids as well as non-hydrocarbon fluids. The term "mobilized fluid" refers to fluids in a hydrocarbon containing formation that are able to flow as a result of thermal treatment of the formation. "Produced fluids"
refer to fluids removed from the formation.

[0030] A "heat source" is any system for providing heat to at least a portion of a formation substantially by conductive and/or radiative heat transfer. For example, a heat source may include electric heaters such as an insulated conductor, an elongated member, and/or a conductor disposed in a conduit. A heat source may also include systems that generate heat by burning a fuel external to or in a formation. The systems may be surface burners, downhole gas burners, flameless distributed combustors, and natural distributed combustors. In some embodiments, heat provided to or generated in one or more heat sources may be supplied by other sources of energy. The other sources of energy may directly heat a formation, or the energy may be applied to a transfer medium that directly or indirectly heats the formation. It is to be understood that one or more heat sources that are applying heat to a formation may use different sources of energy. Thus, for example, for a given formation some heat sources may supply heat from electric resistance heaters, some heat sources may provide heat from combustion, and some heat sources may provide heat from one or more other energy sources (for example, chemical reactions, solar energy, wind energy, biomass, or other sources of renewable energy). A chemical reaction may include an exothermic reaction (for example, an oxidation reaction). A heat source may also include a heater that provides heat to a zone proximate and/or surrounding a heating location such as a heater well.

[0031] 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.

[0032] "Heavy hydrocarbons" are viscous hydrocarbon fluids. Heavy hydrocarbons may include highly viscous hydrocarbon fluids such as heavy oil, tar, and/or asphalt. Heavy hydrocarbons may include carbon and hydrogen, as well as smaller concentrations of sulfur, oxygen, and nitrogen. Additional elements may also be present in heavy hydrocarbons in trace amounts. Heavy hydrocarbons may be classified by API
gravity.
Heavy hydrocarbons generally have an API gravity below about 20 . Heavy oil, for example, generally has an API gravity of about 10-20 , whereas tar generally has an API
gravity below about 10 . The viscosity of heavy hydrocarbons is generally greater than about 100 centipoise at 15 C. Heavy hydrocarbons may include aromatics or other complex ring hydrocarbons.

[0033] Heavy hydrocarbons may be found in a relatively permeable formation.
The relatively permeable formation may include heavy hydrocarbons entrained in, for example, sand or carbonate. "Relatively permeable" is defined, with respect to formations or portions thereof, as an average permeability of 10 millidarcy or more (for example, 10 or 100 millidarcy). "Relatively low permeability" is defined, with respect to formations or portions thereof, as an average permeability of less than about 10 millidarcy.
One darcy is equal to about 0.99 square micrometers. An impermeable layer generally has a permeability of less than about 0.1 millidarcy.

[0034] Certain types of formations that include heavy hydrocarbons may also include, but are not limited to, natural mineral waxes, or natural asphaltites. "Natural mineral waxes"
typically occur in substantially tubular veins that may be several meters wide, several kilometers long, and hundreds of meters deep. "Natural asphaltites" include solid hydrocarbons of an aromatic composition and typically occur in large veins. In situ recovery of hydrocarbons from formations such as natural mineral waxes and natural asphaltites may include melting to form liquid hydrocarbons and/or solution mining of hydrocarbons from the formations.

[0035] "Hydrocarbons" are generally defined as molecules formed primarily by carbon and hydrogen atoms. Hydrocarbons may also include other elements such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulfur. Hydrocarbons may be, but are not limited to, kerogen, bitumen, pyrobitumen, oils, natural mineral waxes, and asphaltites. Hydrocarbons may be located in or adjacent to mineral matrices in the earth.
Matrices may include, but are not limited to, sedimentary rock, sands, silicilytes, carbonates, diatomites, and other porous media. "Hydrocarbon fluids" are fluids that include hydrocarbons. Hydrocarbon fluids may include, entrain, or be entrained in non-hydrocarbon fluids such as hydrogen, nitrogen, carbon monoxide, carbon dioxide, hydrogen sulfide, water, and ammonia.

[0036] An "in situ conversion process" refers to a process of heating a hydrocarbon containing formation from heat sources to raise the temperature of at least a portion of the formation above a pyrolysis temperature so that pyrolyzation fluid is produced in the formation.

[0037] An "in situ heat treatment process" refers to a process of heating a hydrocarbon containing formation with heat sources to raise the temperature of at least a portion of the formation above a temperature that results in mobilized fluid, visbreaking, and/or pyrolysis of hydrocarbon containing material so that mobilized fluids, visbroken fluids, and/or pyrolyzation fluids are produced in the formation.

[0038] "Organosulfur" refers to hydrocarbons that include sulfur. Examples of organosulfur compounds include, but are not limited to, thiophene, thiols, mercaptans, or mixtures thereof.

[0039] "Pyrolysis" is the breaking of chemical bonds due to the application of heat. For example, pyrolysis may include transforming a compound into one or more other substances by heat alone. Heat may be transferred to a section of the formation to cause pyrolysis.

[0040] "Pyrolyzation fluids" or "pyrolysis products" refers to fluid produced substantially during pyrolysis of hydrocarbons. Fluid produced by pyrolysis reactions may mix with other fluids in a formation. The mixture would be considered pyrolyzation fluid or pyrolyzation product. As used herein, "pyrolysis zone" refers to a volume of a formation (for example, a relatively permeable formation such as a tar sands formation) that is reacted or reacting to form a pyrolyzation fluid.

[0041] "Superposition of heat" refers to providing heat from two or more heat sources to a selected section of a formation such that the temperature of the formation at least at one location between the heat sources is influenced by the heat sources.

[0042] "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 .

[0043] A "tar sands formation" is a formation in which hydrocarbons are predominantly present in the form of heavy hydrocarbons and/or tar entrained in a mineral grain framework or other host lithology (for example, sand or carbonate). Examples of tar sands formations include formations such as the Athabasca formation, the Grosmont formation, and the Peace River formation, all three in Alberta, Canada; and the Faja formation in the Orinoco belt in Venezuela.

[0044] "Thickness" of a layer refers to the thickness of a cross section of the layer, wherein the cross section is normal to a face of the layer.

[0045] "Upgrade" refers to increasing the quality of hydrocarbons. For example, upgrading heavy hydrocarbons may result in an increase in the API gravity of the heavy hydrocarbons.

[0046] "Visbreaking" refers to the untangling of molecules in fluid during heat treatment and/or to the breaking of large molecules into smaller molecules during heat treatment, which results in a reduction of the viscosity of the fluid.

[0047] "Viscosity" refers to kinematic viscosity at 40 C unless specified.
Viscosity is as determined by ASTM Method D445.

[0048] The term "wellbore" refers to a hole in a formation made by drilling or insertion of a conduit into the formation. A wellbore may have a substantially circular cross section, or another cross-sectional shape. As used herein, the terms "well" and "opening,"
when referring to an opening in the formation may be used interchangeably with the term "wellbore."

[0049] A formation may be treated in various ways to produce many different products.
Different stages or processes may be used to treat the formation during an in situ heat treatment process. In some embodiments, one or more sections of the formation are solution mined to remove soluble minerals from the sections. Solution mining minerals may be performed before, during, and/or after the in situ heat treatment process. In some embodiments, the average temperature of one or more sections being solution mined may be maintained below about 120 C.

[0050] In some embodiments, one or more sections of the formation are heated to remove water from the sections and/or to remove methane and other volatile hydrocarbons from the sections. In some embodiments, the average temperature may be raised from ambient temperature to temperatures below about 220 C during removal of water and volatile hydrocarbons.

[0051] In some embodiments, one or more sections of the formation are heated to temperatures that allow for movement and/or visbreaking of hydrocarbons in the formation. In some embodiments, the average temperature of one or more sections of the formation are raised to mobilization temperatures of hydrocarbons in the sections (for example, to temperatures ranging from 100 C to 250 C, from 120 C to 240 C, or from 150 C to 230 C).

[0052] In some embodiments, one or more sections are heated to temperatures that allow for pyrolysis reactions in the formation. In some embodiments, the average temperature of one or more sections of the formation may be raised to pyrolysis temperatures of hydrocarbons in the sections (for example, temperatures ranging from 230 C to 900 C, from 240 C to 400 C or from 250 C to 350 C).

[0053] Heating the hydrocarbon containing formation with a plurality of heat sources may establish thermal gradients around the heat sources that raise the temperature of hydrocarbons in the formation to desired temperatures at desired heating rates. The rate of temperature increase through mobilization temperature range and/or pyrolysis temperature range for desired products may affect the quality and quantity of the formation fluids produced from the hydrocarbon containing formation. Slowly raising the temperature of the formation through the mobilization temperature range and/or pyrolysis temperature range may allow for the production of high quality, high API gravity hydrocarbons from the formation. Slowly raising the temperature of the formation through the mobilization temperature range and/or pyrolysis temperature range may allow for the removal of a large amount of the hydrocarbons present in the formation as hydrocarbon product.

[0054] In some in situ heat treatment embodiments, a portion of the formation is heated to a desired temperature instead of slowly heating the temperature through a temperature range. In some embodiments, the desired temperature is 300 C, 325 C, or 350 C. Other temperatures may be selected as the desired temperature.

[0055] Superposition of heat from heat sources allows the desired temperature to be relatively quickly and efficiently established in the formation. Energy input into the formation from the heat sources may be adjusted to maintain the temperature in the formation substantially at a desired temperature.

[0056] Mobilization and/or pyrolysis products may be produced from the formation through production wells. In some embodiments, the average temperature of one or more sections is raised to mobilization temperatures and hydrocarbons are produced from the production wells. The average temperature of one or more of the sections may be raised to pyrolysis temperatures after production due to mobilization decreases below a selected value. In some embodiments, the average temperature of one or more sections may be raised to pyrolysis temperatures without significant production before reaching pyrolysis temperatures. Formation fluids including pyrolysis products may be produced through the production wells.

[0057] In some embodiments, the average temperature of one or more sections may be raised to temperatures sufficient to allow synthesis gas production after mobilization and/or pyrolysis. In some embodiments, hydrocarbons may be raised to temperatures sufficient to allow synthesis gas production without significant production before reaching the temperatures sufficient to allow synthesis gas production. For example, synthesis gas may be produced in a temperature range from about 400 C to about 1200 C, about 500 C to about 1100 C, or about 550 C to about 1000 C. A synthesis gas generating fluid (for example, steam and/or water) may be introduced into the sections to generate synthesis gas. Synthesis gas may be produced from production wells.

[0058] Solution mining, removal of volatile hydrocarbons and water, mobilizing hydrocarbons, pyrolyzing hydrocarbons, generating synthesis gas, and/or other processes may be performed during the in situ heat treatment process. In some embodiments, some processes may be performed after the in situ heat treatment process. Such processes may include, but are not limited to, recovering heat from treated sections, storing fluids (for example, water and/or hydrocarbons) in previously treated sections, and/or sequestering carbon dioxide in previously treated sections.

[0059] FIG. 1 depicts a schematic view of an embodiment of a portion of the in situ heat treatment system for treating the hydrocarbon containing formation. The in situ heat treatment system may include barrier wells 200. Barrier wells are used to form a barrier around a treatment area. The barrier inhibits fluid flow into and/or out of the treatment area. Barrier wells include, but are not limited to, dewatering wells, vacuum wells, capture wells, injection wells, grout wells, freeze wells, or combinations thereof. In some embodiments, barrier wells 200 are dewatering wells. Dewatering wells may remove liquid water and/or inhibit liquid water from entering a portion of the formation to be heated, or to the formation being heated. In the embodiment depicted in FIG.
1, the barrier wells 200 are shown extending only along one side of heat sources 202, but the barrier wells may encircle all heat sources 202 used, or to be used, to heat a treatment area of the formation.

[0060] Heat sources 202 are placed in at least a portion of the formation.
Heat sources 202 may include heaters such as insulated conductors, conductor-in-conduit heaters, surface burners, flameless distributed combustors, and/or natural distributed combustors. Heat sources 202 may also include other types of heaters. Heat sources 202 provide heat to at least a portion of the formation to heat hydrocarbons in the formation. Energy may be supplied to heat sources 202 through supply lines 204. Supply lines 204 may be structurally different depending on the type of heat source or heat sources used to heat the formation. Supply lines 204 for heat sources may transmit electricity for electric heaters, may transport fuel for combustors, or may transport heat exchange fluid that is circulated in the formation. In some embodiments, electricity for an in situ heat treatment process may be provided by a nuclear power plant or nuclear power plants. The use of nuclear power may allow for reduction or elimination of carbon dioxide emissions from the in situ heat treatment process.

[0061] Production wells 206 are used to remove formation fluid from the formation. In some embodiments, production well 206 includes a heat source. The heat source in the production well may heat one or more portions of the formation at or near the production well. In some in situ heat treatment process embodiments, the amount of heat supplied to the formation from the production well per meter of the production well is less than the amount of heat applied to the formation from a heat source that heats the formation per meter of the heat source.

[0062] In some embodiments, the heat source in production well 206 allows for vapor phase removal of formation fluids from the formation. Providing heating at or through the production well may: (1) inhibit condensation and/or refluxing of production fluid when such production fluid is moving in the production well proximate the overburden, (2) increase heat input into the formation, (3) increase production rate from the production well as compared to a production well without a heat source, (4) inhibit condensation of high carbon number compounds (C6 and above) in the production well, and/or (5) increase formation permeability at or proximate the production well.

[0063] Subsurface pressure in the formation may correspond to the fluid pressure generated in the formation. As temperatures in the heated portion of the formation increase, the pressure in the heated portion may increase as a result of thermal expansion of fluids, increased fluid generation, and vaporization of water. Controlling rate of fluid removal from the formation may allow for control of pressure in the formation.
Pressure in the formation may be determined at a number of different locations, such as near or at production wells, near or at heat sources, or at monitor wells.

[0064] In some hydrocarbon containing formations, production of hydrocarbons from the formation is inhibited until at least some hydrocarbons in the formation have been mobilized and/or pyrolyzed. Formation fluid may be produced from the formation when the formation fluid is of a selected quality. In some embodiments, the selected quality includes an API gravity of at least about 15 , 20 , 25 , 30 , or 40 .
Inhibiting production until at least some hydrocarbons are mobilized and/or pyrolyzed may increase conversion of heavy hydrocarbons to light hydrocarbons. Inhibiting initial production may minimize the production of heavy hydrocarbons from the formation. Production of substantial amounts of heavy hydrocarbons may require expensive equipment and/or reduce the life of production equipment.

[0065] After mobilization or pyrolysis temperatures are reached and production from the formation is allowed, pressure in the formation may be varied to alter and/or control a composition of formation fluid produced, to control a percentage of condensable fluid as compared to non-condensable fluid in the formation fluid, and/or to control an API gravity of formation fluid being produced. For example, decreasing pressure may result in production of a larger condensable fluid component. The condensable fluid component may contain a larger percentage of olefins.

[0066] In some in situ heat treatment process embodiments, pressure in the formation may be maintained high enough to promote production of formation fluid with an API
gravity of greater than 20 . Maintaining increased pressure in the formation may inhibit formation subsidence during in situ heat treatment. Maintaining increased pressure may reduce or eliminate the need to compress formation fluids at the surface to transport the fluids in collection conduits to treatment facilities.

[0067] Maintaining increased pressure in a heated portion of the formation may surprisingly allow for production of large quantities of hydrocarbons of increased quality and of relatively low molecular weight. Pressure may be maintained so that formation fluid produced has a minimal amount of compounds above a selected carbon number. The selected carbon number may be at most 25, at most 20, at most 12, or at most 8. Some high carbon number compounds may be entrained in vapor in the formation and may be removed from the formation with the vapor. Maintaining increased pressure in the formation may inhibit entrainment of high carbon number compounds and/or multi-ring hydrocarbon compounds in the vapor. High carbon number compounds and/or multi-ring hydrocarbon compounds may remain in a liquid phase in the formation for significant time periods. The significant time periods may provide sufficient time for the compounds to pyrolyze to form lower carbon number compounds.

[0068] Formation fluid produced from production wells 206 may be transported through collection piping 208 to treatment facilities 210. Formation fluids may also be produced from heat sources 202. For example, fluid may be produced from heat sources 202 to control pressure in the formation adjacent to the heat sources. Fluid produced from heat sources 202 may be transported through tubing or piping to collection piping 208 or the produced fluid may be transported through tubing or piping directly to treatment facilities 210. Treatment facilities 210 may include separation units, reaction units, upgrading units, fuel cells, turbines, storage vessels, and/or other systems and units for processing produced formation fluids. The treatment facilities may form transportation fuel from at least a portion of the hydrocarbons produced from the formation. In some embodiments, the transportation fuel may be jet fuel.

[0069] FIG. 2 depicts a schematic representation of a system for producing crude products and/or commercial products from the in situ heat treatment process liquid stream and/or the in situ heat treatment process gas stream. Formation fluid 212 enters fluid separation unit 214 and is separated into in situ heat treatment process liquid stream 216, in situ heat treatment process gas 218, and aqueous stream 220. Liquid stream 216 may be transported to other processing units and/or facilities. In some embodiments, fluid separation unit 214 includes a quench zone.

[0070] In situ heat treatment process gas 218 may enter gas separation unit 222 to separate gas hydrocarbon stream 224 from the in situ heat treatment process gas. In some embodiments, the gas separation unit is a rectified adsorption and high pressure fractionation unit. Gas hydrocarbon stream 224 includes hydrocarbons having a carbon number of at least 3.

[0071] In situ heat treatment process gas 218 enters gas separation unit 222.
In gas separation unit 222, treatment of in situ heat conversion treatment gas 218 removes sulfur compounds, carbon dioxide, and/or hydrogen to produce gas hydrocarbon stream 224. In some embodiments, in situ heat treatment process gas 218 includes about 20 vol%
hydrogen, about 30% methane, about 12% carbon dioxide, about 14 vol% C2 hydrocarbons, about 5 vol% hydrogen sulfide, about 10 vol% C3 hydrocarbons, about 7 vol% C4 hydrocarbons, about 2 vol% C5 hydrocarbons, and mixtures thereof, with the balance being heavier hydrocarbons, water, ammonia, COS, thiols and thiophenes.

[0072] Gas separation unit 222 may include a physical treatment system and/or a chemical treatment system. The physical treatment system may include, but is not limited to, a membrane unit, a pressure swing adsorption unit, a liquid absorption unit, and/or a cryogenic unit. The chemical treatment system may include units that use amines (for example, diethanolamine or di-isopropanolamine), zinc oxide, sulfolane, water, or mixtures thereof in the treatment process. In some embodiments, gas separation unit 222 uses a Sulfinol gas treatment process for removal of sulfur compounds. Carbon dioxide may be removed using Catacarb (Catacarb, Overland Park, Kansas, U.S.A.) and/or Benfield (UOP, Des Plaines, Illinois, U.S.A.) gas treatment processes. In some embodiments, the gas separation unit is a rectified adsorption and high pressure fractionation unit. In some embodiments, in situ heat treatment process gas is treated to remove at least 50%, at least 60%, at least 70%, at least 80% or at least 90% by volume of ammonia present in the gas stream.

[0073] In situ heat treatment process gas 218 may include one or more carbon oxides and sulfur compounds that render the in situ heat treatment process gas unacceptable for sale, transportation, and/or use as a fuel. The in situ heat treatment process gas 218 may be processed as described herein to produce a gas stream acceptable for sale, transportation, and/or use as a fuel. It would be advantageous to separate the in situ treatment process gas 218 at the treatment site to produce streams useable as energy sources to lower overall energy costs. For example, streams containing hydrocarbons and/or hydrogen may be used as fuel for burners and/or process equipment. Streams containing sulfur compounds may be used as fuel for burners. Streams containing one or more carbon oxides and/or hydrocarbons may be used to form barriers around a treatment site. Streams containing hydrocarbons having a carbon number of at most 2 may be provided to ammonia processing facilities and/or barrier well systems. In situ heat treatment process gas 218 may include a sufficient amount of hydrogen such that the freezing point of carbon dioxide is depressed. Depression of the freezing point of carbon dioxide may allow cryogenic separation of hydrogen and/or hydrocarbons from the carbon dioxide using distillation methods instead of removing the carbon dioxide by cryogenic precipitation methods. In some embodiments, the freezing point of carbon dioxide may be depressed by adjusting the concentration of molecular hydrogen and/or addition of heavy hydrocarbons to the process gas stream.

[0074] As depicted in FIG. 3, in situ heat treatment process gas 218 may enter compressor 232 of gas separation unit 222 to form compressed gas stream 234 and heavy stream 236.
Heavy stream 236 may be transported to one or more liquid separation units for further processing. Compressor 232 may be any compressor suitable for compressing gas.
In certain embodiments, compressor 232 is a multistage compressor (for example 2 to 3 compressor trains) having an outlet pressure of about 40 bars. In some embodiments, compressed gas stream 234 may include at least 1 vol% carbon dioxide, at least 10 vol%
hydrogen, at least 1 vol% hydrogen sulfide, at least 50 vol% of hydrocarbons having a carbon number of at most 4, or mixtures thereof. Compression of in situ heat treatment process gas 218 removes hydrocarbons having a carbon number of at least 5 and water.
Removal of water and hydrocarbons having a carbon number of at least 5 from the in situ process gas allows compressed gas stream 234 to be treated cryogenically.
Cryogenic treatment of compressed gas stream 234 having small amounts of high boiling materials may be done more efficiently. In certain embodiments, compressed gas stream 234 is dried by passing the gas through a water adsorption unit. In some embodiments, compressing in situ heat treatment process gas 218 is not necessary.

[0075] As shown in FIGS. 3 through 7, gas separation unit 222 includes one or more cryogenic units or zones. Cryogenic units described herein may include one or more theoretical distillation stages. In FIGS. 3 through 7, one or more heat exchangers may be positioned prior to or after cryogenic units and/or separation units described herein to assist in removing and/or adding heat to one or more streams described herein. At least a portion or all of the separated hydrocarbons streams and/or the separated carbon dioxides streams may be transported to the heat exchangers. Heat integration from one or more heat exchangers to various units or zones may be applied to improve the energy efficiency of the process.

[0076] In some embodiments, theoretical distillation stages may include from 1 to about 100 stages, from about 5 to about 50 theoretical distillation stages, or from about 10 to about 40 theoretical distillation stages. Zones of the cryogenic units may be cooled to temperatures ranging from about -110 C to about 0 C. For example, zone 1 (top theoretical distillation stage) in a cryogenic unit is cooled to about -110 C, zone 5 (theoretical distillation stage 5) is cooled to about -25 C, and zone 10 (theoretical distillation stage 10) is cooled to about -1 C. Total pressures in cryogenic units may range from about 1 bar to about 50 bar, from about 5 bar to about 40 bar, or from about 10 bar to about 30 bar. Operating the cryogenic zones and/or units at these temperatures and pressures may allow separation of hydrogen sulfide and/or carbon dioxide from hydrocarbons in the process stream. Cryogenic units described herein may include condenser recycle conduits 238 and reboiler recycle conduits 240. Condenser recycle conduits 238 allow recycle of the cooled condensed gases so that the feed may be cooled as it enters the cryogenic units. Condenser liquid recycle or reflux may improve fractionation effectiveness. Temperatures in condensation loops may range from about -110 C
to about -1 C, from about -90 C to about -5 C, or from about -80 C to about -10 C.
Temperatures in reboiler loops may range from about 25 C to about 200 C, from about 50 C to about 150 C, or from about 75 C to about 100 C. Reboiler recycle conduits 240 allow recycle of the stream exiting the cryogenic unit to heat the feed as it enters the cryogenic unit. Recycle of the cooled and/or warmed separated stream may enhance energy efficiency of the cryogenic unit.

[0077] As shown in FIG. 3, compressed gas stream 234 enters methane/hydrogen cryogenic unit 242. In cryogenic unit 242, compressed gas stream 234 may be separated into a methane/molecular hydrogen gas stream 244 and a bottoms stream 246.
Bottoms stream 246 may include, but is not limited to carbon dioxide, hydrogen sulfide, and hydrocarbons having a carbon number of at least 2. A majority of methane/hydrogen stream 244 is methane and molecular hydrogen. Methane/hydrogen stream 244 may include a minimal amount of C2 hydrocarbons and carbon dioxide. For example, methane/hydrogen stream 244 may include about 1 vol% C2 hydrocarbons and about vol% carbon dioxide. In some embodiments, the methane/hydrogen stream is recycled to one or more heat exchangers positioned prior to cryogenic unit 242. In some embodiments, the methane/hydrogen stream is used as a fuel for downhole burners and/or an energy source for surface facilities.

[0078] In some embodiments, cryogenic unit 242 may include one distillation column having 1 to about 30 theoretical distillation stages, about 5 to about 25 theoretical distillation stages, or about 10 to about 20 theoretical distillation stages.
Zones of cryogenic unit 242 may be cooled to temperatures ranging from about -150 C to about 10 C. For example, zone 1 (top theoretical distillation stage) is cooled to about -138 C, zone 5 (theoretical distillation stage 5) is cooled to about -25 C, and zone 10 C
(theoretical distillation stage 10) is cooled to at about -1 C. At temperatures lower than cryogenic separation of the carbon dioxide from other gases may be difficult due to the freezing point of carbon dioxide. In some embodiments, cryogenic unit 242 includes about theoretical distillation stages. Cryogenic unit 242 may be operated at a pressure of 40 20 bar with distillation temperatures ranging from about -45 C to about -94 C.
[0079] Compressed gas stream 234 may include sufficient hydrogen and/or hydrocarbons having a carbon number of at least 1 to inhibit solid carbon dioxide formation. For example, in situ heat treatment process gas 218 may include from about 30 vol%
to about 40 vol% of hydrogen, from about 50 vol% to 60 vol% of hydrocarbons having a carbon number from 1 to 2, from about 0.1 vol% to about 15 vol% of carbon dioxide with the balance being other gases such as, but not limited to, carbon monoxide, nitrogen, and hydrogen sulfide. Inhibiting solid carbon dioxide formation may allow for better separation of gases and/or less fouling of the cryogenic unit. In some embodiments, hydrocarbons having a carbon number of at least five may be added to cryogenic unit 242 to inhibit formation of solid carbon dioxide. The resulting methane/hydrogen gas stream 244 may be used as an energy source. For example, methane/hydrogen gas stream may be transported to surface facilities and burned to generate electricity.

[0080] As shown in FIG. 3, bottoms stream 246 enters cryogenic separation unit 248. In cryogenic separation unit 248, bottoms stream 246 is separated into C3 hydrocarbons stream 250 and gas stream 252. C3 hydrocarbons stream 250 may include hydrocarbons having a carbon number of at least 3. C3 hydrocarbons stream 250 may be a liquid and/or a gas depending on the separation conditions. In some embodiments, C3 hydrocarbons stream 250 includes at least 50 vol%, at least 70 vol% or at least 90 vol% of hydrocarbons. C3 hydrocarbons stream 250 may include at most 1 ppm of carbon dioxide, and about 0.1 vol% of hydrogen sulfide. In some embodiments, C3 hydrocarbons stream 250 includes hydrocarbons having a carbon number of at least 2 and organosulfur compounds. In some embodiments, C3 hydrocarbons stream 250 includes hydrocarbons having a carbon number from 3 to 5. In some embodiments, C3 hydrocarbons stream 250 includes hydrogen sulfide in quantities sufficient to require treatment of the stream to remove the hydrogen sulfide. In some embodiments, C3 hydrocarbons gas stream 250 is suitable for transportation and/or use as an energy source without further treatment. In some embodiments, C3 hydrocarbons stream 250 is used as an energy source for in situ heat treatment processes.

[0081] Gas stream 252 may include hydrocarbons having a carbon number of at least 2, carbon oxides and sulfur compounds. In some embodiments, gas stream 252 includes hydrocarbons having a carbon number of at most 2. A portion of gas stream 252 may be transported to one or more portions of the formation and sequestered. In some embodiments, all of gas stream 252 is sequestered in one or more portions of the formation. In some embodiments, a portion of gas stream 252 enters cryogenic unit 256.
In cryogenic unit 256, gas stream 252 is separated into C2 hydrocarbons/carbon dioxide stream 258 and hydrogen sulfide stream 260. In some embodiments, C2 hydrocarbons/carbon dioxide stream 258 includes at most 0.5 vol% of hydrogen sulfide.

[0082] In some embodiments, hydrogen sulfide stream 260 includes about 0.01 vol% to about 5 vol% of C3 hydrocarbons. In some embodiments, hydrogen sulfide stream includes hydrogen sulfide, carbon dioxide, C3 hydrocarbons, or mixtures thereof. For example, hydrogen sulfide stream 260 includes, about 32 vol% of hydrogen sulfide, 67 vol% carbon dioxide, and 1 vol% C3 hydrocarbons. In some embodiments, hydrogen sulfide stream 260 is used as an energy source for an in situ heat treatment process and/or sent to a Claus plant for further treatment.

[0083] A portion or all of C2 hydrocarbons/carbon dioxide stream 258 may enter separation unit 262. In separation unit 262, C2 hydrocarbons/carbon dioxide stream 258 is separated into C2 hydrocarbons stream 264 and carbon dioxide stream 266.
Separation of C2 hydrocarbons from carbon dioxide is performed using separation methods known in the art, for example, pressure swing adsorption units, and/or extractive distillation units. In some embodiments, C2 hydrocarbons are separated from carbon dioxide using extractive distillation methods. For example, hydrocarbons having a carbon number from 3 to 8 may be added to separation unit 262. Addition of a higher carbon number hydrocarbon solvent allows C2 hydrocarbons to be extracted from the carbon dioxide. C2 hydrocarbons are then separated from the higher carbon number hydrocarbons using distillation techniques. In some embodiments, C2 hydrocarbons stream 264 is transported to other process facilities and/or used as an energy source. For example, C2 hydrocarbons stream 264 may be provided to one or more ammonia processing facilities. Carbon dioxide stream 266 may be sequestered in one or more portions of the formation. In some embodiments, carbon dioxide stream 266 is provided to one or more barrier well systems. In some embodiments, carbon dioxide stream 266 contains at most 0.005 grams of non-carbon dioxide compounds per gram of carbon dioxide stream. In some embodiments, carbon dioxide stream 266 is mixed with one or more oxidant sources supplied to one or more downhole burners.

[0084] In some embodiments, a portion or all of C2 hydrocarbons/carbon dioxide stream 258 is sequestered and/or transported to other facilities and/or provided to one or more barrier well systems. In some embodiments, a portion or all of C2 hydrocarbons/carbon dioxide stream 258 is mixed with one or more oxidant sources supplied to one or more downhole burners.

[0085] As depicted in FIG. 4, bottoms stream 246 enters cryogenic separation unit 270. In cryogenic separation unit 270, bottoms stream 246 may be separated into C2 hydrocarbons/carbon dioxide stream 258 and hydrogen sulfide/hydrocarbon gas stream 272. In some embodiments, C2 hydrocarbons/carbon dioxide stream 258 contains hydrogen sulfide. Hydrogen sulfide/hydrocarbon gas stream 272 may include hydrocarbons having a carbon number of at least 3.

[0086] In some embodiments, a portion or all of C2 hydrocarbons/carbon dioxide stream 258 are transported via conduit 268 to other processes and/or to one or more portions of the formation to be sequestered. In some embodiments, a portion or all of C2 hydrocarbons/carbon dioxide stream 258 are treated in separation unit 262.
Separation unit 262 is described above with reference to FIG. 3.

[0087] Hydrogen sulfide/hydrocarbon gas stream 272 may enter cryogenic separation unit 274. In cryogenic separation unit 274, hydrogen sulfide may be separated from hydrocarbons having a carbon number of at least 3 to produce hydrogen sulfide stream 260 and C3 hydrocarbons stream 250. Hydrogen sulfide stream 260 may include, but is not limited to, hydrogen sulfide, C3 hydrocarbons, carbon dioxide, or mixtures thereof. In some embodiments, hydrogen sulfide stream 260 may contain from about 20 vol%
to about 80 vol% of hydrogen sulfide, from about 4 vol% to about 18 vol% of propane and from about 2 vol% to about 70 vol% of carbon dioxide. In some embodiments, hydrogen sulfide stream 260 is burned to produce SOX. The SO,, may be sequestered and/or treated using known techniques in the art.

[0088] In some embodiments, C3 hydrocarbons stream 250 includes a minimal amount of hydrogen sulfide and carbon dioxide. For example, C3 hydrocarbons stream 250 may include about 99.6 vol% of hydrocarbons having a carbon number of at least 3, about 0.4 vol% of hydrogen sulfide and at most 1 ppm of carbon dioxide. In some embodiments, C3 hydrocarbons stream 250 is transported to other processing facilities as an energy source.
In some embodiments, C3 hydrocarbons stream 250 needs no further treatment.

[0089] As depicted in FIG. 5, bottoms stream 246 may enter cryogenic separation unit 276.
In cryogenic separation unit 276, bottoms stream 246 may be separated into C2 hydrocarbons/hydrogen sulfide/carbon dioxide gas stream 278 and hydrogen sulfide/hydrocarbon gas stream 272. In some embodiments, cryogenic separation unit 276 includes 45 theoretical distillation stages. A top zone (top theoretical distillation stage) of cryogenic separation unit 276 may be operated at a temperature of -31 C and a pressure of about 20 bar.

[0090] A portion or all of C2 hydrocarbons/hydrogen sulfide/carbon dioxide gas stream 278 and hydrocarbon stream 280 may enter cryogenic separation unit 282.
Hydrocarbon stream 280 may be any hydrocarbon stream suitable for use in a cryogenic extractive distillation system. In some embodiments, hydrocarbon stream 280 is n-hexane.
In cryogenic separation unit 282, C2 hydrocarbons/hydrogen sulfide/carbon dioxide gas stream 278 is separated into carbon dioxide stream 266 and additional hydrocarbon/hydrogen sulfide stream 284. In some embodiments, cryogenic separation unit 282 includes 40 theoretical distillation stages. Cryogenic separation unit 282 may be operated at a temperature of about -19 C and a pressure of about 20 bar.

[0091] In some embodiments, carbon dioxide stream 266 includes about 2.5 vol%
of hydrocarbons having a carbon number of at most 2. In some embodiments, carbon dioxide stream 266 may be mixed with diluent fluid and/or oxidant for downhole burners, may be used as a carrier fluid for oxidizing fluid for downhole burners, may be used as a drive fluid for producing hydrocarbons, may be vented, may be used in barrier wells, and/or may be sequestered. In some embodiments carbon dioxide stream 266 is solidified.

[0092] Additional hydrocarbon/hydrogen sulfide stream 284 may be in the gas or liquid phase depending on the composition of the stream and/or the process conditions.
Additional hydrocarbon/hydrogen sulfide stream 284 may enter cryogenic separation unit 286. Additional hydrocarbon/hydrogen sulfide stream 284 may include solvent hydrocarbons, C2 hydrocarbons and hydrogen sulfide. In cryogenic separation unit 286, additional hydrocarbon/hydrogen sulfide stream 284 may be separated into C2 hydrocarbons/hydrogen sulfide gas stream 288 and hydrocarbon stream 290.
Hydrocarbon stream 290 may contain hydrocarbons having a carbon number of at least 3.
Hydrocarbon stream 290 may be a liquid or gas depending on the composition of the stream and/or process conditions. In some embodiments, separation unit 286 includes 20 theoretical distillation stages. Cryogenic separation unit 286 may be operated at temperatures of about -16 C and a pressure of about 10 bar.

[0093] Hydrogen sulfide/hydrocarbon gas stream 272 may enter cryogenic separation unit 274. In cryogenic separation unit 274, hydrogen sulfide may be separated from hydrocarbons having a carbon number of at least 3 to produce hydrogen sulfide stream 260 and C3 hydrocarbons stream 250. Hydrogen sulfide stream 260 may include, but is not limited to, hydrogen sulfide, C2 hydrocarbons, C3 hydrocarbons, carbon dioxide, or mixtures thereof. In some embodiments, hydrogen sulfide stream 260 contains about 31 vol% hydrogen sulfide with the balance being C2 and C3 hydrocarbons. Hydrogen sulfide stream 260 may be burned to produce SOX. The SOX may be sequestered and/or treated using known techniques in the art.

[0094] In some embodiments, cryogenic separation unit 274 includes about 40 theoretical distillation stages. Temperatures in cryogenic separation unit 274 may range from about 0 C to about 10 C. Pressure in cryogenic separation unit 274 may be about 20 bar.

[0095] C3 hydrocarbons stream 250 may be a gas or liquid stream depending on the composition of the stream and/or process conditions. C3 hydrocarbons stream 250 may include a minimal amount of hydrogen sulfide and carbon dioxide. In some embodiments, C3 hydrocarbons stream 250 includes about 50 ppm of hydrogen sulfide. In some embodiments, C3 hydrocarbons stream 250 is transported to other processing facilities as an energy source. In some embodiments, hydrocarbons stream C3 hydrocarbon stream 250 needs no further treatment.

[0096] As depicted in FIG. 6, compressed gas stream 234 may be treated using a modified Ryan/Holmes type process to recover the carbon dioxide from the compressed gas stream.
Compressed gas stream 234 enters cryogenic separation unit 292. In some embodiments cryogenic separation unit 292 includes 40 theoretical distillation stages.
Cryogenic separation unit 292 may be operated at a temperature ranging from about 60 C
to about -56 C and a pressure of about 30 bar. In cryogenic separation unit 292, compressed gas stream 234 may be separated into methane/carbon dioxide gas stream 294 and hydrocarbon/hydrogen sulfide stream 296.

[0097] Methane/carbon dioxide gas stream 294 may include hydrocarbons having a carbon number of at most 2 and carbon dioxide. Methane/carbon dioxide gas stream 294 may be compressed in compressor 298 and enter cryogenic separation unit 300. In cryogenic separation unit 300, methane/carbon dioxide gas stream 294 is separated into carbon dioxide stream 266 and methane stream 244. In some embodiments, cryogenic separation unit 300 includes 20 theoretical distillation stages. Temperatures in cryogenic separation unit 300 may range from about -56 C to about -96 C at a pressure of about 45 bar.

[0098] Carbon dioxide stream 266 may include some hydrogen sulfide. For example, carbon dioxide stream 266 may include about 80 ppm of hydrogen sulfide. At least a portion of carbon dioxide stream 266 may be used as a heat exchange medium in heat exchanger 302. In some embodiments, at least a portion of carbon dioxide stream 266 is sequestered in the formation and/or at least a portion of the carbon dioxide stream is used as a diluent in downhole oxidizer assemblies.

[0099] Hydrocarbon/hydrogen sulfide stream 296 may include hydrocarbons having a carbon number of at least 2 and hydrogen sulfide. Hydrocarbon/hydrogen sulfide stream 296 may be a gas or liquid stream depending on the hydrocarbon content of the stream and/or process conditions. Hydrocarbon/hydrogen sulfide stream 296 may pass through heat exchanger 302 and enter separation unit 304. In separation unit 304, hydrocarbon/hydrogen sulfide stream 296 may be separated into hydrocarbon stream 306 and hydrogen sulfide stream 260. In some embodiments, separation unit 304 includes 30 theoretical distillation stages. Temperatures in separation unit 304 may range from about 60 C to about 27 C at a pressure of about 10 bar.

[0100] Hydrocarbon stream 306 may include hydrocarbons having a carbon number of at least 3. Hydrocarbon stream 306 may include some hydrocarbons having a carbon number greater than 5. Hydrocarbon stream 306 may include hydrocarbons having a carbon number of at most 5. In some embodiments, hydrocarbon stream 306 includes 10 vol% n-butanes and 85 vol% hydrocarbons having a carbon number of 5. At least a portion of hydrocarbon stream 306 may be recycled to cryogenic separation unit 292 to maintain a ratio of about 1.4:1 of hydrocarbons to compressed gas stream 234.

[0101] Hydrogen sulfide stream 260 may include hydrogen sulfide, C2 hydrocarbons, and some carbon dioxide. In some embodiments, hydrogen sulfide stream 260 includes about 13 vol% hydrogen sulfide, about 0.8 vol% carbon dioxide with the balance being hydrocarbons. At least a portion of the hydrogen sulfide stream 260 may be burned as an energy source. In some embodiments, hydrogen sulfide stream 260 is used as a fuel source in downhole burners.

[0102] In some embodiments, substantial removal of all the hydrogen sulfide from the C2 hydrocarbons is desired. C2 hydrocarbons may be used as an energy source in surface facilities. Recovery of C2 hydrocarbons may enhance the energy efficiency of the process.
Separation of hydrogen sulfide from C2 hydrocarbons may be difficult because hydrocarbons boil at approximately the same temperature as a hydrogen sulfide/C2 hydrocarbons mixture. Addition of higher molecular weight (higher boiling) hydrocarbons does not enable the separation between hydrogen sulfide and C2 hydrocarbons as the addition of higher molecular weight hydrocarbons decreases the volatility of the C2 hydrocarbons. It has been advantageously found that the addition of carbon dioxide to the hydrogen sulfide/C2 hydrocarbons mixture allows separation of hydrogen sulfide from the C2 hydrocarbons.

[0103] As shown in FIG. 7, bottoms stream 246 and carbon dioxide stream 314 enter cryogenic separation unit 316. In some embodiments, the carbon dioxide stream is added to the bottom stream prior to entering the cryogenic separation unit. In cryogenic separation unit 316, bottoms stream 246 may be separated into C2 hydrocarbons/carbon dioxide gas stream 258 and hydrogen sulfide/hydrocarbon stream 318 by addition of sufficient carbon dioxide to form a C2 hydrocarbons/carbon dioxide azeotrope (for example, a C2 hydrocarbons/carbon dioxide volume ratio of 0.17:1 may be used).
The C2 hydrocarbons/carbon dioxide azeotrope has a boiling point lower than the boiling point of C2 hydrocarbons. For example, the C2 hydrocarbons/carbon dioxide azeotrope, where the C2 hydrocarbons are ethane, has a boiling point that is 14 C lower than C2 boiling point at bar, and a boiling point that is 22 C lower than the C2 boiling point at 40 bar. Use of a C2 hydrocarbons/carbon dioxide azeotrope allows formation of a C2 hydrocarbons/carbon dioxide stream having a minimal amount of hydrogen sulfide (for example, a C2 hydrocarbons/carbon dioxide stream having at most 30 ppm, at most 25 ppm, at most 20 10 ppm, or at most 10 ppm of hydrogen sulfide). In some embodiments, cryogenic separation unit 316 includes 40 theoretical distillation stages and may be operated at a pressure of about 10 bar.

[0104] At least a portion of C2 hydrocarbons/carbon dioxide stream 258 and hydrocarbon recovery stream 320 may enter separation unit 262. Hydrocarbon recovery stream may include hydrocarbons having a carbon number ranging from 4 to 7. In separation unit 262, contact of C2 hydrocarbons/carbon dioxide stream 258 with hydrocarbon recovery stream 320 allows for separation of hydrocarbons from the C2 hydrocarbons/carbon dioxide stream to form separated carbon dioxide stream 266 and C2 rich hydrocarbon stream 322. For example, a hydrocarbon recovery stream to C2 hydrocarbons/carbon dioxide stream ratio of 1.25 to 1 may effectively extract all the hydrocarbons from the carbon dioxide. The ratio of hydrocarbon recovery stream to C2 hydrocarbons/carbon dioxide stream may depend on the relative concentrations of C2 hydrocarbons and carbon dioxide in the C2 hydrocarbons/carbon dioxide stream. Separated carbon dioxide stream 266 may be sequestered in the formation, used as a drive fluid, recycled to cryogenic separation unit 316, or used as a cooling fluid in other processes.

[0105] C2 rich hydrocarbon stream 322 may enter hydrocarbon recovery unit 324.
In hydrocarbon recovery unit 324, C2 rich hydrocarbon stream 322 may be separated into light hydrocarbons stream 326 and bottom hydrocarbon stream 328. In some embodiments, hydrocarbon recovery unit 324 includes 30 theoretical distillation stages and is operated at a pressure of 10 bar. Light hydrocarbons stream 326 may include hydrocarbons having a carbon number from 2 to 4, a residual amount of hydrogen sulfide, thiols, and/or COS. For example, light hydrocarbons stream 326 may have about 30 ppm hydrogen sulfide, 280 ppm thiols and 260 ppm COS. Light hydrocarbons stream 326 may be treated further (for example, contacted with molecular sieves) to remove the sulfur compounds. In some embodiments, light hydrocarbons stream 326 requires no further purification and is suitable for transportation and/or use as a fuel.

[0106] Hydrocarbon stream 328 may include hydrocarbons having a carbon number ranging from 3 to 7. Some of hydrocarbon stream 328 may be directed to separation unit 330 and/or separation unit 262 after passing through one or more heat exchangers 302.
Heat exchangers 302 may be integrated with one or more units to maximize energy efficiency. Mixing of hydrocarbon stream 328 with hydrocarbon recovery stream stabilize the composition of hydrocarbon recovery stream 320 and avoid build-up of heavy hydrocarbons and sulfur compounds (for example, organosulfur compounds). In some embodiments, hydrocarbon stream 328 and hydrocarbon recovery stream 320 are the same stream. In some embodiments, hydrocarbon stream 328 is treated to remove sulfur compounds (for example, the hydrocarbon stream is contacted with caustic).

[0107] Hydrogen sulfide/hydrocarbon gas stream 318 from cryogenic separation unit 316 may include, but is not limited to, hydrocarbons having a carbon number of at least 3, hydrocarbons that include organosulfur compounds, hydrogen sulfide, or mixtures thereof.
A portion or all of hydrogen sulfide/hydrocarbon gas stream 318 and hydrocarbon recovery stream 320 enter hydrogen sulfide separation unit 330. Output from cryogenic separation unit 330 may include hydrogen sulfide stream 260 and rich C3 hydrocarbons stream 332.
To facilitate separation of the hydrogen sulfide from rich C3 hydrocarbon stream 332, a volume ratio of 0.73 to 1 of rich C3 hydrocarbons stream to hydrogen sulfide may be used.
In some embodiments, separation unit 330 includes 30 theoretical distillation stages.
Cryogenic separation unit 330 may be operated at a temperature of about -16 C
and a pressure of about 10 bar. C3 hydrocarbon stream 332 may contain hydrocarbons having a carbon number of at least 3. At least a portion of C3 hydrocarbon stream 332 may enter hydrocarbon recovery unit 324.

[0108] Hydrogen sulfide stream 260 may include, but is not limited to, hydrogen sulfide, C2 hydrocarbons, C3 hydrocarbons, carbon dioxide, or mixtures thereof. In some embodiments, hydrogen sulfide stream 260 contains about 99 vol% hydrogen sulfide with the balance being C2 and C3 hydrocarbons. Hydrogen sulfide stream 260 may be burned to produce SOX. In some embodiments, at least a portion of the hydrogen sulfide stream is used as a fuel in downhole burners. The SOX may be used as a drive fluid, sequestered and/or treated using known techniques in the art.

[0109] In some embodiments, non-condensable gases produced from treatment areas of in situ heat treatment processes are used as fuel for heaters that heat treatment areas in the formation. The heaters may be burners. The burners may be oxidizers of downhole oxidizer assemblies, flameless distributed combustors and/or burners that heat a heat transfer fluid used to heat the treatment areas. The non-condensable gases may include combustible gases (for example, hydrogen, hydrogen sulfide, methane and other hydrocarbon gases) and noncombustible gases (for example, carbon dioxide). The presence of noncombustible gases may inhibit coking of the fuel and/or may reduce the flame zone temperature of oxidizers when the fuel is used as fuel for oxidizers of downhole oxidizer assemblies. The reduced flame zone temperature may inhibit formation of NOX
compounds and/or other undesired combustion products by the oxidizers. Other components such as water may be included in the fuel supplied to the burners.
Combustion of in situ heat treatment process gas may reduce and/or eliminate the need for gas treatment facilities and/or the need to treat the non-condensable portion of formation fluid produced using the in situ heat treatment process to obtain pipeline gas and/or other gas products.
Combustion of in situ heat treatment process gas in burners may create concentrated carbon dioxide and/or SOX effluents that may be used in other processes, sequestered and/or treated to remove undesired components.

[0110] In some embodiments, use of non-condensable fluids from in situ heat treatment processes in burners reduces or eliminates the need to build power plants near the in situ heat treatment processes. Heat initially used to increase the temperature of treatment areas in the formation may be provided by burning pipeline gas or other fuel. After the formation begins producing formation fluid, a portion or all of the non-condensable fluids produced from the formation may replace or supplement the pipeline gas or other fuel used to heat treatment areas.

[0111] In some embodiments, the oxidizing fluid supplied to the burners is air or enriched air. In some embodiments, the oxidizing fluid is produced by blending oxygen with a carrier fluid such as carbon dioxide to reduce or eliminate the presence of nitrogen in the oxidizing fluid. For example, the oxidizing fluid may be about 50% by volume oxygen and about 50% by volume carbon dioxide. Eliminating or reducing nitrogen in the oxidizing fluid may eliminate or reduce the amount of NOX compounds generated by the burners. Eliminating or reducing nitrogen in the oxidizing fluid may also enable transporting and geologically storing exhaust gases from the burners without having to separate nitrogen from the exhaust gases.

[0112] FIG. 8 depicts an embodiment of a system that uses non-condensable fluid from an in situ heat treatment process to heat a treatment area in a formation.
Formation fluid 212 produced from treatment areas in the formation enters separation unit 214.
Separation unit 214 may separate the formation fluid into in situ heat treatment process liquid stream 216, in situ heat treatment process gas 218, and aqueous stream 220. In situ heat treatment process gas 218 may entrain some water and/or condensable hydrocarbons. In situ heat treatment process gas 218 enters gas separation unit 222. Gas separation unit 222 may remove one or more components from in situ heat treatment process gas 218 to produce fuel 400 and one or more other streams 402. For example, other streams 402 may include carbon dioxide streams 266 and 314 from processes described in FIGS. 3-7. Fuel 400 may include, but is not limited to, hydrogen, sulfur compounds, hydrocarbons having a carbon number of at most 5, carbon oxides, nitrogen compounds, or mixtures thereof.
Fuel 400 may include streams produced as described in FIGS. 3-7 (for example, streams 244, 250, 258, 264, 288, 290, or mixtures thereof). In some embodiments, gas separation unit 222 uses chemical and/or physical treatment systems and/or systems described in FIGS. 2-7 to remove or reduce the amount of carbon dioxide in fuel 400. In some embodiments, in situ heat treatment process gas 218 is minimally treated before being used as a fuel. For example, gas separation unit 222 may minimally treat in situ heat treatment process gas 218 to remove water and/or hydrocarbons having a carbon number greater than 5.
In some embodiments, in situ heat treatment process gas 218 is suitable for use as a fuel so the gas separation unit 222 is not necessary.

[0113] Fuel 400 may enter fuel conduit 404 that provides fuel to oxidizers of oxidizer assemblies (for example, a plurality of oxidizer assemblies such as downhole oxidizer assembly as described in U.S. Published Application No. 20080135254 to Vinegar et al.) that heat treatment area 406. Air stream 408 and/or diluent fluid 410 may be mixed with oxidizing fluid 412 to form mixed oxidizing fluid 414 that is provided to the oxidizers of the downhole oxidizing assemblies. Diluent fluid 410 may be, but is not limited to, carbon oxides separated from in situ heat treatment process gas 218, a portion of stream 402 from gas separation unit 222, carbon dioxide 406 from the exhaust of the downhole oxidizing assemblies, separated carbon dioxide gas streams from gas separation systems described in FIGS. 2-7, or mixtures thereof. In some embodiments, diluent fluid 410 includes sufficient amounts of carbon dioxide to inhibit oxidation of conduits and/or metal parts in fuel conduit 404 that come in contact with oxidizing fluid 412. In some embodiments, the amount of excess oxidant supplied to the downhole oxidizers is reduced to less than about 50% excess oxidant by volume by mixing oxidizing fluid 412 with the diluent fluid 410.

[0114] Initially, pipeline gas or other fuel may be supplied to treatment area 406. Valves 418 may be adjusted to control the amount of initial fuel supplied to treatment area 406 as fuel 400 becomes available. Initially, air stream 408 may be supplied to treatment area 406 as the oxidizing fluid. After additional oxidant sources become available, valves 418' may be adjusted to control the composition of oxidizing fluid 414 provided to treatment area 406.

[0115] Exhaust gas 420 from burners used to heat treatment area 406 may be directed to exhaust treatment unit 422. Exhaust gas 420 may include, but is not limited to, carbon dioxide and/or SOX. In exhaust separation unit 422, carbon dioxide stream 416 is separated from SOX stream 424. Separated carbon dioxide stream 416 may be mixed with diluent fluid 410, may be used as a carrier fluid for oxidizing fluid 412, may be used as a drive fluid for producing hydrocarbons, and/or may be sequestered. SOX stream 224 may be treated using known SOX treatment methods (for example, sent to a Claus plant).
Formation fluid 212' produced from heat treatment area 406 may be mixed with formation fluid 212 from other treatment areas and/or may enter separation unit 214.

[0116] It is to be understood the invention is not limited to particular systems described which may, of course, vary. It is also to be understood that the terminology used herein is for the purpose of describing particular embodiments only, and is not intended to be limiting. As used in this specification, the singular forms "a", "an" and "the" include plural referents unless the content clearly indicates otherwise. Thus, for example, reference to "a bolt" includes a combination of two or more bolts and reference to "a fluid"
includes mixtures of fluids.

[0117] Further modifications and alternative embodiments of various aspects of the invention will be apparent to those skilled in the art in view of this description.
Accordingly, this description is to be construed as illustrative only and is for the purpose of teaching those skilled in the art the general manner of carrying out the invention. It is to be understood that the forms of the invention shown and described herein are to be taken as the presently preferred embodiments. Elements and materials may be substituted for those illustrated and described herein, parts and processes may be reversed, and certain features of the invention may be utilized independently, all as would be apparent to one skilled in the art after having the benefit of this description of the invention. Changes may be made in the elements described herein without departing from the spirit and scope of the invention as described in the following claims.

Claims

1. A method of treating a gas stream, comprising:
in a first cryogenic zone, cryogenically separating a first gas stream to form a second gas stream and a third stream, wherein a majority of the second gas stream comprises methane and/or molecular hydrogen and a majority of the third stream comprises one or more carbon oxides, hydrocarbons having a carbon number of at least 2, one or more sulfur compounds, or mixtures thereof; and in a second cryogenic zone, cryogenically contacting the third stream with a carbon dioxide stream to form a fourth stream and a fifth stream, wherein a majority of the fourth stream comprises one or more of the carbon oxides and hydrocarbons having a carbon number of at least 2, and a majority of the fifth stream comprises hydrocarbons having a carbon number of at least 3 and one or more of the sulfur compounds.

2. The method of claim 1, wherein the cryogenic separation in the first cryogenic zone comprises cryogenic distillation.

3. The method of claim 1, wherein the cryogenic separation in the second cryogenic zone comprises cryogenic distillation.

4. The method of claim 1, wherein the cryogenic separation in the first and second cryogenic zones comprises cryogenic distillation.

5. The method of claim 1, wherein the carbon dioxide stream is added to the third stream in or before the second cryogenic zone.

6. The method of claim 1, wherein one or more of the sulfur compounds comprises hydrogen sulfide and contacting the third stream with the carbon dioxide stream enhances the separation of the second stream from the third stream.

7. The method of claim 1, wherein one or more of the sulfur compounds is hydrogen sulfide.

8. The method of claim 1, further comprising compressing the first gas stream prior to cryogenically separating the first gas stream to produce a stream comprising hydrocarbon having a carbon number of at least 5 and the first gas stream.

9. The method of claim 1, further comprising separating formation fluid from a subsurface in situ heat treatment process to form a liquid stream and the first gas stream, wherein the first gas stream comprises one or more carbon oxides, one or more sulfur compounds, hydrocarbons and/or molecular hydrogen.

10. The method of claim 1, further comprising, in a third cryogenic zone, cryogenically contacting the fourth stream with a hydrocarbon recovery stream to form a sixth stream and a seventh stream, a majority of the sixth stream comprising hydrocarbons having a carbon number of at least 2 and a majority of the seventh stream comprising carbon oxides.

11. The method of claim 1, further comprising, in a third cryogenic zone, cryogenically separating the fifth stream to form a stream comprising hydrogen sulfide and a stream comprising hydrocarbons having a carbon number of at least 3.

12. The method of claim 1, further comprising providing the fifth stream comprising the hydrocarbons having a carbon number of at least 3 to other processing facilities.

13. The method of claim 1, further comprising:
in a third cryogenic zone, cryogenically separating the fourth stream to form a sixth stream and a seventh stream, the sixth stream comprising hydrocarbons having a carbon number of at least 2 and the seventh stream comprising one or more of the carbon oxides;
in a fourth cryogenic zone, cryogenically separating the fifth stream to form a stream comprising hydrogen sulfide and a stream comprising hydrocarbons having a carbon number of at least 3;
combining the sixth stream having a carbon number of at least 2 with the stream comprising hydrocarbons having a carbon number of at least 3 to from a combined stream;
and in a fifth cryogenic zone, cryogenically separating the combined stream to form a stream comprising hydrocarbons having a carbon number from 2 to 4 and a stream comprising hydrocarbons having a carbon number from 4 to 7; and providing at least a portion of the hydrocarbon stream comprising hydrocarbons having a carbon number ranging from 4 to 7 to the third cryogenic zone.

14. A system of treating a gas stream, comprising:
a first cryogenic separation zone configured receive a first gas stream and to cryogenically separate the first gas stream to form a second gas stream and a third gas stream, wherein the second gas stream comprises methane and/or hydrogen and the third gas stream comprises one or more carbon oxides, hydrocarbons having a carbon number of at least 2, and one or more sulfur compounds;
a second cryogenic separation zone configured to receive the third gas stream and carbon dioxide and wherein the second cryogenic separation unit is configured to cryogenically separate the third gas stream to from a fourth stream and fifth stream, wherein a majority of the fourth stream comprises one or more of the carbon oxides and hydrocarbons having a carbon number of at least 2 and a majority of the fifth stream comprises hydrocarbons having a carbon number of at least 3 and one or more of the sulfur compounds.

15. A method of treating a formation fluid, comprising:
separating formation fluid from a subsurface in situ heat treatment process to form a liquid stream and a first gas stream, wherein the first gas stream comprises one or more carbon oxides, one or more sulfur compounds, hydrocarbons, and/or molecular hydrogen;
in a first cryogenic zone, cryogenically separating the first gas stream to form a second gas stream and a third stream, wherein a majority of the second gas stream comprises methane and/or molecular hydrogen, and the third stream comprises hydrocarbons having a carbon number of at least 2, one or more sulfur compounds, one or more carbon oxides or mixtures thereof; and in a second cryogenic zone, cryogenically separating the third gas stream to form a fourth stream and a fifth stream, wherein a majority the fourth stream comprises one or more carbon oxides and hydrocarbons having a carbon number of at most 2; and a majority of the fifth stream comprises hydrocarbons having a carbon number of at least 3 and/or one or more sulfur compounds.

16. The method of claim 15, further comprising separating the fifth stream to form a stream comprising one or more sulfur compounds and a stream comprising hydrocarbons having a carbon number of at least 3.

17. The method of claim 15, wherein the fourth gas stream further comprises hydrogen sulfide.

18. The method of claim 15, wherein the fourth stream further comprises hydrogen sulfide and the method comprises:
in a third cryogenic zone, cryogenically contacting at least a portion of the fourth stream with a hydrocarbons stream comprising hydrocarbons having a carbon number of at least 4 to form a sixth stream and a seventh stream, wherein a majority of the sixth stream comprises hydrogen sulfide and a majority of the seventh stream comprises hydrocarbons having a carbon number of at least 2.

19. A method of heating a subsurface formation, comprising:

supplying fuel to a plurality of oxidizers positioned in the subsurface formation, at least a portion of the fuel being produced by cryogenically separating a gas stream using a method as claimed in claim 1 or 15;
supplying an oxidant to the plurality of oxidizers;
mixing a portion of the fuel with a portion of the oxidant; and combusting the fuel and oxidant mixture to produce heat that heats at least a portion of the subsurface formation.

20. The method of claim 19, wherein at cryogenically separating the gas stream produces a stream comprising carbon dioxide, and mixing at least a portion of the produced carbon dioxide with the oxidant.