WO2006116207A2

WO2006116207A2 - Treatment of gas from an in situ conversion process

Info

Publication number: WO2006116207A2
Application number: PCT/US2006/015286
Authority: WO
Inventors: Zaida Diaz; Alan Anthony Del Paggio; Vijay Nair; Augustinus Wilhelmus Maria Roes
Original assignee: Shell Internationale Research Maatschappij B.V.
Priority date: 2005-04-22
Filing date: 2006-04-24
Publication date: 2006-11-02
Also published as: EP1871986A1; AU2006239958A1; MA29468B1; EP1871985B1; AU2006239962A1; CN101163858B; CN101163854A; AU2006239962B2; EA012901B1; EA200702303A1; ATE435964T1; CA2606295A1; ZA200708090B; AU2006239997B2; NZ562240A; EA200702304A1; CA2605729C; AU2006239886B2; WO2006116095A1; AU2006239996A1

Abstract

The invention provides methods of producing methane that include: producing formation fluid from a subsurface in situ conversion process and separating the formation fluid to produce a liquid stream and a first gas stream. The first gas stream includes olefins. The first gas stream is contacted with a hydrogen source in the presence of one or more catalysts to produce a second gas stream. Steam, carbon monoxide, and/or hydrogen may be present or added to in the first stream during contacting. The second gas stream is contacted with a hydrogen source in the presence of one or more additional catalysts to produce a third gas stream that includes methane.

Description

TREATMENT OF GAS FROM AN IN SITU CONVERSION PROCESS

BACKGROTJNP 1. Field of the Invention

The present invention relates generally to methods and systems for producing hydrogen, methane, and/or other products from various subsurface formations such as hydrocarbon containing formations. 2. Description of Related Art

Hydrocarbons obtained from subterranean formations are often used as energy resources, as feedstocks, and as consumer products. Concerns over depletion of available hydrocarbon resources and concerns over declining overall quality of produced hydrocarbons have led to development of processes for more efficient recovery, processing and/or use of available hydrocarbon resources. In situ processes may be used to remove hydrocarbon materials from subterranean formations. 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.

Formation fluids obtained from subterranean formations using an in situ conversion 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 conversion 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 conversion 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 conversion process may not meet industry standards for transportation and/or commercial use. Thus, there is a need for improved methods and systems for treatment of formation fluids obtained from various hydrocarbon containing formations.

SUMMARY

Embodiments described herein generally relate to systems, and methods for producing methane and/or pipeline gas.

In certain embodiments, the invention provides a method of producing methane, including: producing formation fluid from a subsurface in situ conversion process; separating the formation fluid to produce a liquid stream and a first gas stream, wherein the first gas stream includes olefins; contacting at least the olefins in the first gas stream with a hydrogen source in the presence of one or more catalysts and steam to produce a second gas stream; and contacting the second gas stream with a hydrogen source in the presence of one or more additional catalysts to produce a third gas stream, wherein the third gas stream includes methane.

In certain embodiments, the invention also provides a method of producing methane, including: producing formation fluid from a subsurface in situ conversion process; separating the formation fluid to produce a liquid stream and a first gas stream; wherein the first gas stream includes carbon monoxide, olefins, and hydrogen; contacting the first gas stream with a hydrogen source in the presence of one or more catalysts to produce a second ^" gas mixture, wherein the second gas mixture includes methane, and wherein the hydrogen source includes hydrogen present in the first gas stream.

In certain embodiments, the invention also provides a method of producing methane, including: producing formation fluid from a subsurface in situ conversion process; separating the formation fluid to produce a liquid stream and a first gas stream, wherein the first gas stream includes carbon monoxide, hydrogen, and hydrocarbons having a carbon number of at least 2, wherein the hydrocarbons having a carbon number of at least 2 include paraffins and olefins; and contacting the first gas stream with hydrogen in the presence of one or more catalysts and carbon dioxide to produce a second gas stream, the second gas stream including methane and paraffins, and wherein the hydrogen source includes hydrogen present in the first gas stream. BRIEF DESCRIPTION OF THE DRAWINGS

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

FIG. 1 shows a schematic view of an embodiment of a portion of an in situ conversion system for treating a hydrocarbon containing formation. FIG. 2 depicts a schematic representation of an embodiment of a system for producing pipeline gas.

FIG. 3 depicts a schematic representation of an embodiment of a system for producing pipeline gas. FIG. 4 depicts a schematic representation of an embodiment of a system for producing pipeline gas. FIG. 5 depicts a schematic representation of an embodiment of a system for producing pipeline gas. FIG. 6 depicts a schematic representation of an embodiment of a system for producing pipeline gas. While the invention is susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and may herein be described in detail. The drawings may not be to scale. It should be understood, however, that the drawings and detailed description thereto are not intended to limit the invention to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the present invention as defined by the appended claims.

DETAILED DESCRIPTION

The following description generally relates to systems and methods for treating formation fluid produced from a hydrocarbon containing formation using an in situ conversion process. Hydrocarbon containing formations may be treated to yield hydrocarbon products, hydrogen, methane, 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, pvrobiturnen, 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.

A "formation" includes one or more hydrocarbon containing layers, one or more non-hydrocarbon layers, an overburden, and/or an underburden. The "overburden" and/or the "underburden" include one or more different types of impermeable materials. For example, overburden and/or underburden may include rock, shale, mudstone, or wet/tight carbonate. In some embodiments of in situ conversion 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 conversion 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 conversion process. In some cases, the overburden and/or the underburden may be somewhat permeable.

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

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. "Carbon number" refers to the number of carbon atoms in a molecule. A hydrocarbon fluid may include various hydrocarbons with different carbon numbers. The hydrocarbon fluid may be described by a carbon number distribution. Carbon numbers and/or carbon number distributions may be determined by true boiling point distribution and/or gas-liquid chromatography.

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.

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.

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.

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 hereinfthe terms "well" and "operung," wn'en referring to an opening in the formation may be used interchangeably with the term "wellbore."

"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. In some formations, portions of the formation and/or other materials in the formation may promote pyrolysis through catalytic activity.

"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.

"Cracking" refers to a process involving decomposition and molecular recombination of organic compounds to produce a greater number of molecules than were initially present. In cracking, a series of reactions take place accompanied by a transfer of hydrogen atoms between molecules. For example, naphtha may undergo a thermal cracking reaction to form ethene and H₂.

"Condensable hydrocarbons" are hydrocarbons that condense at 25 ⁰C 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 ⁰C and one atmosphere absolute pressure. Non-condensable hydrocarbons may include hydrocarbons having carbon numbers less than 5. "Olefins" are molecules that include unsaturated hydrocarbons having one or more non-aromatic carbon- carbon double bonds.

"API gravity" refers to API gravity at 15.5 ⁰C (60 ⁰F). API gravity is as determined by ASTM Method D6822.

"Periodic Table" refers to the Periodic Table as specified by the International Union of Pure and Applied Chemistry (IUPAC), October 2005.

"Column X metal" or "Column X metals" refer to one or more metals of Column X of the Periodic Table and/or one or more compounds of one or more metals of Column X of the Periodic Table, in which X corresponds to a column number (for example, 1-12) of the Periodic Table. For example, "Column 6 metals" refer to metals from Column 6 of the Periodic Table and/or compounds of one or more metals from Column 6 of the Periodic Table. "Column X element" or "Column X elements" refer to one or more elements of Column X of the Periodic

Table, and/or one or more compounds of one or more elements of Column X of the Periodic Table, in which X corresponds to a column number (for example, 13-18) of the Periodic Table. For example, "Column 15 elements" refer to elements from Column 15 of the Periodic Table and/or compounds of one or more elements from Column 15 of the Periodic Table. In the scope of this application, weight of a metal from the Periodic Table, weight of a compound of a metal from the Periodic Table, weight of an element from the Periodic Table, or weight of a compound of an element from the Periodic Table is calculated as the weight of metal or the weight of element. For example, if 0.1 grams OfMoO₃ is used per gram of catalyst, the calculated weight of the molybdenum metal in the catalyst is 0.067 grams per gram of catalyst. FIG. 1 depicts a schematic view of an embodiment of a portion of the in situ conversion system for treating the hydrocarbon containing formation. The in situ conversion system may include barrier wells 208. Barrier wells are used to torm 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 208 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 208 are shown extending only along one side of heat sources 210, but the barrier wells typically encircle all heat sources 210 used, or to be used, to heat a treatment area of the formation.

Heat sources 210 are placed in at least a portion of the formation. Heat sources 210 may include heaters such as insulated conductors, conductor-in-conduit heaters, surface burners, flameless distributed combustors, and/or natural distributed combustors. Heat sources 210 may also include other types of heaters. Heat sources 210 provide heat to at least a portion of the formation to heat hydrocarbons in the formation. Hydrocarbons in the formation may be pyrolyzed to form formation fluid. Energy may be supplied to heat sources 210 through supply lines 212. Supply lines 212 may be structurally different depending on the type of heat source or heat sources used to heat the formation. Supply lines 212 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.

Production wells 214 are used to remove formation fluid from the formation. In some embodiments, production well 214 may include one or more heat sources. A heat source in the production well may heat one or more portions of the formation at or near the production well. A heat source in a production well may inhibit condensation and reflux of formation fluid being removed from the formation. Formation fluid produced from production wells 214 may be transported through collection piping 216 to treatment facilities 218. Formation fluids may also be produced from heat sources 210. For example, fluid may be produced from heat sources 210 to control pressure in the formation adjacent to the heat sources. Fluid produced from heat sources 210 may be transported through tubing or piping to collection piping 216 or the produced fluid may be transported through tubing or piping directly to treatment facilities 218. Treatment facilities 218 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, formation fluid produced from the in situ conversion process is sent to a separator to split the formation fluid into one or more in situ conversion process liquid streams and/or one or more in situ conversion process gas streams. The liquid streams and the gas streams may be further treated to yield desired products.

In some embodiments, in situ process conversion gas is treated at the site of the formation to produce hydrogen. Treatment processes to produce hydrogen from the in situ process conversion gas may include steam methane reforming, autothermal reforming, and/or partial oxidation reforming. All or at least a portion of a gas stream may be treated to yield a gas that meets natural gas pipeline specifications. FIGS. 2, 3, 4, 5, and 6 depict schematic representations of embodiments of systems for producing pipeline gas from the in situ conversion process gas stream.

As depicted in FIG. 2, formation fluid 220 enters gas/liquid separation unit 222 and is separated into in situ conversion process liquid stream 224, in situ conversion process gas 226, and aqueous stream 228. In situ conversion process gas 226 enters unit 230. In unit 230, treatment of in situ conversion process gas 226 removes sulfur compounds, carbon dioxide, and/or hydrogen to produce gas stream 232. Unit 230 may include a physical treatment system and/or a chemical treatment system. The physical treatment system includes, 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, unit 230 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.

Gas stream 232 may include, but is not limited to, hydrogen, carbon monoxide, methane, and hydrocarbons having a carbon number of at least 2 or mixtures thereof. In some embodiments, gas stream 232 includes nitrogen and/or rare gases such as argon or helium. In some embodiments, gas stream 232 includes from 0.0001 grams (g) to 0.1 g, from 0.001 g to 0.05 g, or from 0.01 g to 0.03 g of hydrogen, per gram of gas stream. In certain embodiments, gas stream 232 includes from 0.01 g to 0.6 g, from 0.1 g to 0.5 g, or from 0.2 g to 0.4 g of methane, per gram of gas stream.

In some embodiments, gas stream 232 includes from 0.00001 g to 0.01 g, from 0.0005 g to 0.005 g, or from 0.0001 g to 0.001 g of carbon monoxide, per gram of gas stream. In certain embodiments, gas stream 232 includes trace amounts of carbon dioxide.

In certain embodiments, gas stream 232 may include from 0.0001 g to 0.5 g, from 0.001 g to 0.2 g, or from 0.01 g to 0.1 g of hydrocarbons having a carbon number of at least 2, per gram of gas stream. Hydrocarbons having a carbon number of at least 2 include paraffins and olefins. Paraffins and olefins include, but are not limited to, ethane, ethylene, acetylene, propane, propylene, butanes, butylenes, or mixtures thereof. In some embodiments, hydrocarbons having a carbon number of at least 2 include from 0.0001 g to 0.5 g, from 0.001 g to 0.2 g, or from 0.01 g to 0.1 g of a mixture of ethylene, ethane, and propylene. In some embodiments, hydrocarbons having a carbon number of at least 2 includes trace amounts of hydrocarbons having a carbon number of at least 4.

Pipeline gas (for example, natural gas) after treatment to remove the hydrogen sulfide, includes methane, ethane, propane, butane, carbon dioxide, oxygen, nitrogen, and small amounts of rare gases. Typically, treated natural gas includes, per gram of natural gas, 0.7 g to 0.98 g of methane; 0.0001 g to 0.2 g or from 0.001 g to 0.05 g of a mixture of ethane, propane, and butane; 0.0001 g to 0.8 g or from 0.001 g to 0.02 g of carbon dioxide; 0.00001 g to 0.02 g or from 0.0001 to 0.002 of oxygen; trace amounts of rare gases; and the balance being nitrogen. Such treated natural gas has a heat content of 40 MJ/Nm³ to 50 MJ/Nm³. Since gas stream 232 differs in composition from treated natural gas, gas stream 232 may not meet pipeline gas requirements. Emissions generated during burning of gas stream 232 may be unacceptable and/or not meet regulatory standards if the gas stream is to be used as a fuel. Gas stream 232 may include components or amounts of components that make the gas stream undesirable for use as a feed stream for making additional products.

In some embodiments, hydrocarbons having a carbon number greater than 2 are separated from gas stream 232. These hydrocarbons may be separated using cryogenic processes, adsorption processes, and/or membrane processes. Removal of hydrocarbons having a carbon number greater than 2 from gas stream 232 may facilitate and/or enhance further processing of the gas stream.

Process units as described herein may be operated at the following temperatures, pressures, hydrogen source flows, and gas stream flows, or operated otherwise as known in the art. Temperatures may range from 50 ⁰C to 600 ⁰C, from 100 ⁰C to 500⁰C, or from 200 ⁰C to 400 ⁰C. Pressures may range from 0.1 MPa to 20 MPa, from 1 MPa to 12 MPa, from 4 MPa to 10 MPa, or from 6 MPa to 8 MPa. Flows of gas streams through units described herein may range from 5 metric tons of gas stream per day ("MT/D") to 15,000 MT/D. In some embodiments, flows of gas streams through units described herein range from 10 MT/D to 10,000 MT/D or from 15 MT/D to 5,000 MT/D. In some embodiments, the hourly volume of gas processed is 5,000 to 25,000 times the volume of catalyst in one or more processing units. As depicted in FIG. 2, gas stream 232 and hydrogen source 234 enter hydrogenation unit 236. Hydrogen source 234 includes, but is not limited to, hydrogen gas, hydrocarbons, and/or any compound capable of donating a hydrogen atom. In some embodiments, hydrogen source 234 is mixed with gas stream 232 prior to entering hydrogenation unit 236. In some embodiments, the hydrogen source is hydrogen and/or hydrocarbons present in gas stream 232. In hydrogenation unit 236, contact of gas stream 232 with hydrogen source 234 in the presence of one or more catalysts hydrogenates unsaturated hydrocarbons in gas stream 232 and produces gas stream 238. Gas stream 238 may include hydrogen and saturated hydrocarbons such as methane, ethane, and propane. Hydrogenation unit 236 may include a knock-out pot. The knock-out pot removes any heavy by-products 240 from the product gas stream.

Gas stream 238 exits hydrogenation unit 236 and enters hydrogen separation unit 242. Hydrogen separation unit 242 is any suitable unit capable of separating hydrogen from the incoming gas stream. Hydrogen separation unit 242 may be a membrane unit, a pressure swing adsorption unit, a liquid absorption unit, or a cryogenic unit. In certain embodiments, hydrogen separation unit 242 is a membrane unit. Hydrogen separation unit 242 may include PRISM® membranes available from Air Products and Chemicals, Inc. (Allentown, Pennsylvania, U.S.A.). The membrane separation unit may be operated at a temperature ranging from 50 ⁰C to 80 ⁰C (for examples, at a temperature of 66 °C). In hydrogen separation unit 242, separation of hydrogen from gas stream 238 produces hydrogen rich stream 244 and gas stream 246. Hydrogen rich stream 244 may be used in other processes, or, in some embodiments, as hydrogen source 234 for hydrogenation unit 236.

In some embodiments, hydrogen separation unit 242 is a cryogenic unit. When hydrogen separation unit 242 is a cryogenic unit, gas stream 238 may be separated into a hydrogen rich stream, a methane rich stream, and/or a gas stream that contains components having a boiling point greater than or equal to the boiling point of ethane.

In some embodiments, hydrogen content in gas stream 246 is acceptable and further separation of hydrogen from gas stream 246 is not needed. When the hydrogen content in gas stream 246 is acceptable, the gas stream may be suitable for use as pipeline gas.

Further removal of hydrogen from gas stream 246 may be desired. In some embodiments, hydrogen is separated from gas stream 246 using a membrane. An example of a hydrogen separation membrane is described in U.S. Patent No. 6,821,501 to Matzakos et al.

In some embodiments, a method of removing hydrogen from gas stream 246 includes converting hydrogen to water. Gas stream 246 exits hydrogen separation unit 242 and enters oxidation unit 248, as shown in FIG. 2. Oxidation source 250 also enters oxidation unit 248. In oxidation unit 248, contact of gas stream 246 with oxidation source 250 produces gas stream 252. Gas stream 252 may include water produced as a result of the oxidation. The oxidation source may include, but is not limited to, pure oxygen, air, or oxygen enriched air. Since air or oxygen enriched air includes nitrogen, monitoring the quantity of air or oxygen enriched air provided to oxidation unit 248 may be desired to ensure the product gas meets the desired pipeline specification for nitrogen. Oxidation unit 248 includes, in some embodiments, a catalyst. Oxidation unit 248 is, in some embodiments, operated at a temperature in a range from 50 ⁰C to 500 ⁰C, from 100 ⁰C to 400 ⁰C, or from 200 ⁰C to 300 ⁰C. Gas stream 252 exits oxidation unit 248 and enters dehydration unit 254. In dehydration unit 254, separation of water from gas stream 252 produces pipeline gas 256 and water 258. Dehydration unit 254 may be, for example, a standard gas plant glycol dehydration unit and/or molecular sieves. In some embodiments, a change in the amount of methane in pipeline gas produced from an in situ conversion process gas is desired. The amount of methane in pipeline gas may be enhanced through removal of components and/or through chemical modification of components in the in situ conversion process gas.

FIG. 3 depicts a schematic representation of an embodiment to enhance the amount of methane in pipeline gas through reformation and methanation of the in situ conversion process gas.

Treatment of in situ conversion process gas as described herein produces gas stream 232. Gas stream 232, hydrogen source 234, and steam source 260 enter reforming unit 262. In some embodiments, gas stream 232, hydrogen source 234, and/or steam source 260 are mixed together prior to entering reforming unit 262. In some embodiments, gas stream 232 includes an acceptable amount of a hydrogen source, and thus external addition of hydrogen source 234 is not needed. In reforming unit 262, contact of gas stream 232 with hydrogen source 234 in the presence of one or more catalysts and steam source 260 produces gas stream 264. The catalysts and operating parameters may be selected such that reforming of methane in gas stream 232 is minimized. Gas stream 264 includes methane, carbon monoxide, carbon dioxide, and/or hydrogen. The carbon dioxide in gas stream 264, at least a portion of the carbon monoxide in gas stream 264, and at least a portion of the hydrogen in gas stream 264 is from conversion of hydrocarbons with a carbon number greater than 2 (for example, ethylene, ethane, or propylene) to carbon monoxide and hydrogen. Methane in gas stream 264, at least a portion of the carbon monoxide in gas stream 264, and at least a portion of the hydrogen in gas stream 264 is from gas stream 232 and hydrogen source 234.

Reforming unit 262 may be operated at temperatures and pressures described herein, or operated otherwise as known in the art. In some embodiments, reforming unit 262 is operated at temperatures ranging from 250 ⁰C to 500 ⁰C. In some embodiments, pressures in reforming unit 262 range from 1 MPa to 5 MPa. Removal of excess carbon monoxide in gas stream 264 to meet, for example, pipeline specifications may be desired. Carbon monoxide may be removed from gas stream 264 using a methanation process. Methanation of carbon monoxide produces methane and water. Gas stream 264 exits reforming unit 262 and enters methanation unit 266. In methanation unit 266, contact of gas stream 264 with a hydrogen source in the presence of one or more catalysts produces gas stream 268. The hydrogen source may be provided by hydrogen and/or hydrocarbons present in gas stream 264. In some embodiments, an additional hydrogen source is added to the methanation unit and/or the gas stream. Gas stream 268 may include water, carbon dioxide, and methane.

Methanation unit 266 may be operated at temperatures and pressures described herein or operated otherwise as known in the art. In some embodiments, methanation unit 266 is operated at temperatures ranging from 260 ⁰C to 320 ⁰C. In some embodiments, pressures in methanation unit 266 range from 1 MPa to 5 MPa. Carbon dioxide may be separated from gas stream 268 in carbon dioxide separation unit 270. In some embodiments, gas stream 268 exits methanation unit 266 and passes through a heat exchanger prior to entering carbon dioxide separation unit 270. In carbon dioxide separation unit 270, separation of carbon dioxide from gas stream 268 produces gas stream 272 and carbon dioxide stream 274. In some embodiments, the separation process uses amines to facilitate the removal of carbon dioxide from gas stream 268. Gas stream 272 includes, in some embodiments, at most 0.1 g, at most 0.08 g, at most 0.06, or at most 0.04 g of carbon dioxide per gram of gas stream. In some embodiments, gas stream 272 is substantially free of carbon dioxide. Gas stream 272 exits carbon dioxide separation unit 270 and enters dehydration unit 254. In dehydration unit 254, separation of water from gas stream 272 produces pipeline gas 256 and water 258.

FIG. 4 depicts a schematic representation of an embodiment to enhance the amount of methane in pipeline gas through concurrent hydrogenation and methanation of in situ conversion process gas. Hydrogenation and methanation of carbon monoxide and hydrocarbons having a carbon number greater than 2 in the in situ conversion process gas produces methane. Concurrent hydrogenation and methanation in one processing unit may inhibit formation of impurities. Inhibiting the formation of impurities enhances production of methane from the in situ conversion process gas. In some embodiments, the hydrogen source content of the in situ conversion process gas is acceptable and an external source of hydrogen is not needed. Treatment of in situ conversion process gas as described herein produces gas stream 232. Gas stream 232 enters hydrogenation and methanation unit 276. In hydrogenation and methanation unit 276, contact of gas stream 232 with a hydrogen source in the presence of a catalyst or multiple catalysts produces gas stream 278. The hydrogen source may be provided by hydrogen and/or hydrocarbons in gas stream 232. In some embodiments, an additional hydrogen source is added to hydrogenation and methanation unit 276 and/or gas stream 232. Gas stream 278 may include methane, hydrogen, and, in some embodiments, at least a portion of gas stream 232. In some embodiments, gas stream 278 includes from 0.05 g to 1 g, from 0.8 g to 0.99 g, or from 0.9 g to 0.95 g of methane, per gram of gas stream. Gas stream 278 may include, per gram of gas stream, at most 0.1 g of hydrocarbons having a carbon number of at least 2 g and at most 0.01 g of carbon monoxide. In some embodiments, gas stream 278 includes trace amounts of carbon monoxide and/or hydrocarbons having a carbon number of at least 2. Hydrogenation and methanation unit 276 may be operated at temperatures, and pressures, described herein, or operated otherwise as known in the art. In some embodiments, hydrogenation and methanation unit 276 is operated at a temperature ranging from 200 ⁰C to 350 ⁰C. In some embodiments, pressure in hydrogenation and methanation unit 276 is 2 MPa to 12 MPa, 4 MPa to 10 MPa, or 6 MPa to 8 MPa. In certain embodiments, pressure in hydrogenation and methanation unit 276 is about 8 MPa. The removal of hydrogen from gas stream 278 may be desired. Removal of hydrogen from gas stream 278 may allow the gas stream to meet pipeline specification and/or handling requirements.

In FIG. 4, gas stream 278 exits methanation unit 276 and enters polishing unit 280. Carbon dioxide stream 282 also enters polishing unit 280, or it mixes with gas stream 278 upstream of the polishing unit. In polishing unit 280, contact of the gas stream 278 with carbon dioxide stream 282 in the presence of one or more catalysts produces gas stream 284. The reaction of hydrogen with carbon dioxide produces water and methane. Gas stream 284 may include methane, water, and, in some embodiments, at least a portion of gas stream 278. In some embodiments, polishing unit 280 is a portion of hydrogenation and methanation unit 276 with a carbon dioxide feed line.

Polishing unit 280 may be operated at temperatures and pressures described herein, or operated as otherwise known in the art. In some embodiments, polishing unit 280 is operated at a temperature ranging from 200 ⁰C to 400 ⁰C. In some embodiments, pressure in polishing unit 280 is 2 MPa to 12 MPa, 4 MPa to 10 MPa, or 6 MPa to 8 MPa. In certain embodiments, pressure in polishing unit 280 is about 8 MPa.

Gas stream 284 enters dehydration unit 254. In dehydration unit 254, separation of water from gas stream 284 produces pipeline gas 256 and water 258.

FIG. 5 depicts a schematic representation of an embodiment to enhance the amount of methane in pipeline gas through concurrent hydrogenation and methanation of in situ conversion process gas in the presence of excess carbon dioxide and the separation of ethane and heavier hydrocarbons. Hydrogen not used in the hydrogenation methanation process may react^' with carbon dioxide to form water and methane. Water may then be separated from the process stream. Concurrent hydrogenation and methanation in the presence of carbon dioxide in one processing unit may inhibit formation of impurities.

Treatment of in situ conversion process gas as described herein produces gas stream 232. Gas stream 232 and carbon dioxide stream 282 enter hydrogenation and methanation unit 286. In hydrogenation and methanation unit 286, contact of gas stream 232 with a hydrogen source in the presence of one or more catalysts and carbon dioxide produces gas stream 288. The hydrogen source may be provided by hydrogen and/or hydrocarbons in gas stream 232. In some embodiments, the hydrogen source is added to hydrogenation and methanation unit 286 or to gas stream 232. The quantity of hydrogen in hydrogenation and methanation unit 286 may be controlled and/or the flow of carbon dioxide may be controlled to provide a minimum quantity of hydrogen in gas stream 288.

Gas stream 288 may include water, hydrogen, methane, ethane, and, in some embodiments, at least a portion of the hydrocarbons having a carbon number greater than 2 from gas stream 232. In some embodiments, gas stream 288 includes from 0.05 g to 0.7 g, from 0.1 g to 0.6 g, or from 0.2 g to 0.5 g of methane, per gram of gas stream. Gas stream 288 includes from 0.0001 g to 0.4 g, from 0.001 g to 0.2 g, or from 0.01 g to 0.1 g of ethane, per gram of gas stream. In some embodiments, gas stream 288 includes a trace amount of carbon monoxide and olefins.

Hydrogenation and methanation unit 286 may be operated at temperatures and pressures, described herein, or operated otherwise as known in the art. In some embodiments, hydrogenation and methanation unit 286 is operated at a temperature ranging from 60 ⁰C to 350 ⁰C and a pressure ranging from 1 MPa to 12 MPa, 2 MPa to 10 MPa, or 4 MPa to 8 MPa. In some embodiments, separation of ethane from methane is desirable. Separation may be performed using membrane and/or cryogenic techniques. Cryogenic processes may require that water levels in a gas stream be at most 1-10 part per million by weight.

Water in gas stream 288 may be removed using generally known water removal techniques. Gas stream 288 exit,s hydrogenation and methanation unit 286, passes through heat exchanger 290 and then enters dehydration unit 254. In dehydration unit 254, separation of water from gas stream 288 as previously described, as well as by contact with absorption units and/or molecular sieves, produces gas stream 292 and water 258. Gas stream 292 may have a water content of at most 10 ppm, at most 5 ppm, or at most 1 ppm. In some embodiments, water content in gas stream 292 ranges from O.Olppm to 10 ppm, from 0.05 ppm to 5 ppm, or from 0.1 ppm to 1 ppm.

Cryogenic separator 294 separates gas stream 292 into pipeline gas 256 and hydrocarbon stream 296. Pipeline gas stream 256 includes methane and/or carbon dioxide. Hydrocarbon stream 296 includes ethane and, in some embodiments, residual hydrocarbons having a carbon number of at least 2. In some embodiments, hydrocarbons having a carbon number of at least 2 may be separated into ethane and additional hydrocarbons and/or sent to other operating units.

FIG. 6 depicts a schematic representation of an embodiment to enhance the amount of methane in pipeline gas through concurrent hydrogenation and methanation of in situ conversion process gas in the presence of excess hydrogen. The use of excess hydrogen during the hydrogenation and methanation process may prolong catalyst life, control reaction rates, and/or inhibit formation of impurities.

Treatment of in situ conversion process gas as described herein produces gas stream 232. Gas stream 232 and hydrogen source 234 enter hydrogenation and methanation unit 298. In some embodiments, hydrogen source 234 is added to gas stream 232. In hydrogenation and methanation unit 298, contact of gas stream 232 with hydrogen source 234 in the presence of one or more catalysts produces gas stream 300. In some embodiments, carbon dioxide may be added to hydrogen and methanation unit 298. The quantity of hydrogen in hydrogenation and methanation unit 298 may be controlled to provide an excess quantity of hydrogen to the hydrogenation and methanation unit.

Gas stream 300 may include water, hydrogen, methane, ethane, and, in some embodiments, at least a portion of the hydrocarbons having a carbon number greater than 2 from gas stream 232. In some embodiments, gas stream 300 includes from 0.05 g to 0.9 g, from 0.1 g to 0.6 g, or from 0.2 g to 0.5 g of methane, per gram of gas stream. Gas stream 300 includes from 0.0001 g to 0.4 g, from 0.001 g to 0.2 g, or from 0.01 g to 0.1 g of ethane, per gram of gas stream. In some embodiments, gas stream 300 includes carbon monoxide and trace amounts of olefins. Hydrogenation and methanation unit 298 may be operated at temperatures and pressures, described herein, or operated otherwise as known in the art. In some embodiments, hydrogenation and methanation unit 298 is operated at a temperature ranging from 60 ⁰C to 400 ⁰C and a hydrogen partial pressure ranging from 1 MPa to 12 MPa, 2 MPa to 8 MPa, or 3 MPa to 5 MPa. In some embodiments, the hydrogen partial pressure in hydrogenation and methanation unit 298 is about 4 MPa.

Gas stream 300 enters gas separation unit 302. Gas separation unit 302 is any suitable unit or combination of units that is capable of separating hydrogen and/or carbon dioxide from gas stream 300. Gas separation unit may be a pressure swing adsorption unit, a membrane unit, a liquid absorption unit, and/or a cryogenic unit. In some embodiments, gas stream 300 exits hydrogenation and methanation unit 298 and passes through a heat exchanger prior to entering gas separation unit 302. In gas separation unit 302, separation of hydrogen from gas stream 300 produces gas stream 304 and hydrogen stream 306. Hydrogen stream 306 may be recycled to hydrogenation and methanation unit 298, mixed with gas stream 232 and/or mixed with hydrogen source 234 upstream of the hydrogenation methanation unit. In embodiments in which carbon dioxide is added to hydrogenation and methanation unit 298, carbon dioxide is separated from gas stream 304 in separation unit 302. The separated carbon dioxide may be recycled to the hydrogenation and methanation unit, mixed with gas stream 232 upstream of the hydrogenation and methanation unit, and/or mixed with the carbon dioxide stream entering the hydrogenation and methanation unit.

Gas stream 304 enters dehydration unit 254. In dehydration unit 254, separation of water from gas stream 304 produces pipeline gas 256 and water 258.

It should be understood that gas stream 232 may be treated by combinations of one or more of the processes described in FIGS. 2, 3, 4, 5, and 6. For example, all or at least a portion of gas streams from reforming unit 262 (FIG. 3) may be treated in hydrogenation and methanation units 276 (FIG. 4), 286 (FIG. 5), or 296 (FIG. 6). All or at least a portion of the gas stream produced from hydrogenation unit 236 may enter, or be combined with gas streams entering, reforming unit 262, hydrogenation and methanation unit 276, and/or hydrogenation and methanation unit 286. In some embodiments, gas stream 232 may be hydrotreated and/or used in other processing units. Catalysts used to produce natural gas that meets pipeline specifications may be bulk metal catalysts or supported catalysts. Bulk metal catalysts include Columns 6-10 metals. Supported catalysts include Columns 6-10 metals on a support. Columns 6-10 metals include, but are not limited to, vanadium, chromium, molybdenum, tungsten, manganese, technetium, rhenium, iron, cobalt, nickel, ruthenium, palladium, rhodium, osmium, iridium, platinum, or mixtures thereof. The catalyst may have, per gram of catalyst, a total Columns 6-10 metals content of at least 0.0001 g, at least 0.001 g, at least 0.01 g, or in a range from 0.0001-0.6 g, 0.005-0.3 g, 0.001-0.1 g, or 0.01-0.08 g. In some embodiments, the catalyst includes a Column 15 element in addition to the Columns 6-10 metals. An example of a Column 15 element is phosphorus. The catalyst may have a total Column 15 elements content, per gram of catalyst, in a range from 0.000001-0.1 g, 0.00001-0.06 g, 0.00005-0.03 g, or 0.0001-0.001 g. In some embodiments, the catalyst includes a combination of Column 6 metals with one or more Columns 7-10 metals. A molar ratio of Column 6 metals to Columns 7-10 metals may be in a range from 0.1-20, 1-10, or 2-5. In some embodiments, the catalyst includes Column 15 elements in addition to the combination of Column 6 metals with one or more Columns 7-10 metals.

In some embodiments, Columns 6-10 metals are incorporated in, or deposited on, a support to form the catalyst. In certain embodiments, Columns 6-10 metals in combination with Column 15 elements are incorporated in, or deposited on, the support to form the catalyst. In embodiments in which the metals and/or elements are supported, the weight of the catalyst includes all support, all metals, and all elements. The support may be porous and may include refractory oxides; oxides of tantalum, niobium, vanadium, scandium, or lanthanide metals; porous carbon based materials; zeolites; or combinations thereof. Refractory oxides may include, but are not limited to, alumina, silica, silica-alumina, titanium oxide, zirconium oxide, magnesium oxide, or mixtures thereof. Supports may be obtained from a commercial manufacturer such as CRI/Criterion Inc. (Houston, Texas, U.S.A.). Porous carbon based materials include, but are not limited to, activated carbon and/or porous graphite. Examples of zeolites include Y-zeolites, beta zeolites, mordenite zeolites, ZSM-5 zeolites, and ferrierite zeolites. Zeolites may be obtained from a commercial manufacturer such as Zeolyst (Valley Forge, Pennsylvania, U.S.A.).

Supported catalysts may be prepared using generally known catalyst preparation techniques. Examples of catalyst preparations are described in U.S. Patent Nos. 6,218,333 to Gabrielov et al.; 6,290,841 to Gabrielov et al.; 5,744,025 to Boon et al., and 6,759,364 to Bhan.

In some embodiments, the support is impregnated with metal to form the catalyst. In certain embodiments, the support is heat treated at temperatures in a range from 400 ⁰C to 1200 ⁰C; from 450 ⁰C to 1000 ⁰C, or from 600 ⁰C to 900 °C prior to impregnation with a metal. In some embodiments, impregnation aids are used during preparation of the catalyst. Examples of impregnation aids include a citric acid component, ethylenediaminetetraacetic acid (EDTA), ammonia, or mixtures thereof.

The Columns 6-10 metals and support may be mixed with suitable mixing equipment to form a Columns 6- 10 metals/support mixture. The Columns 6-10 metals/support mixture may be mixed using suitable mixing equipment. Examples of suitable mixing equipment include tumblers, stationary shells or troughs, Muller mixers (batch type or continuous type), impact mixers, and any other generally known mixer, or other device, that will suitably provide the Columns 6-10 metals support mixture. In certain embodiments, the materials are mixed until the Columns 6-10 metals are substantially homogeneously dispersed in the support.

In some embodiments, the catalyst is heat treated at temperatures from 150-750 ⁰C, from 200-740 ⁰C, or from 400-730 °C after combining the support with the metal. In some embodiments, the catalyst is heat treated in the presence of hot air and/or oxygen rich air at a temperature in a range between 400 ⁰C and 1000 ⁰C to remove volatile matter to convert at least a portion of the Columns 6-10 metals to the corresponding metal oxide.

In other embodiments, a catalyst precursor is heat treated in the presence of air at temperatures in a range from 35-500 ⁰C for a period of time in a range from 1-3 hours to remove a majority of the volatile components without converting the Columns 6-10 metals to the corresponding metal oxide. Catalysts prepared by such a method are generally referred to as "uncalcined" catalysts. When catalysts are prepared in this manner, in combination with a sulfiding method, the active metals may be substantially dispersed in the support. Preparations of such catalysts are described in U.S. Patent Nos. 6,218,333 to Gabrielov et al., and 6,290,841 to Gabrielov et al. In some embodiments, the catalyst and/or a catalyst precursor is sulfided to form metal sulfides (prior to use) using techniques known in the art (for example, ACTICAT™ process, CRI International, Inc. (Houston, Texas, U.S.A.)). In some embodiments, the catalyst is dried then sulfided. Alternatively, the catalyst may be sulfided in situ by contact of the catalyst with a gas stream that includes sulfur-containing compounds. In-situ sulfurization may utilize either gaseous hydrogen sulfide in the presence of hydrogen or liquid-phase sulfurizing agents such as organosulfur compounds (including alkylsulfides, polysulfides, thiols, and sulfoxides). Ex-situ sulfurization processes are described in U.S. Patent Nos. 5,468,372 to Seamans et al., and 5,688,736 to Seamans et al.

In some embodiments, a first type of catalyst ("first catalyst") includes Columns 6-10 metals and the support. The first catalyst is, in some embodiments, an uncalcined catalyst. In some embodiments, the first catalyst includes molybdenum and nickel. In certain embodiments, the first catalyst includes phosphorus. In some embodiments, the first catalyst includes Columns 9-10 metals on a support. The Column 9 metal may be cobalt and the Column 10 metal may be nickel. In some embodiments, the first catalyst includes Columns 10-11 metals. The Column 10 metal may be nickel and the Column 11 metal may be copper.

The first catalyst may assist in the hydrogenation of olefins to alkanes. In some embodiments, the first catalyst is used in the hydrogenation unit. The first catalyst may include at least 0.1 g, at least 0.2 g, or at least 0.3 g of Column 10 metals per gram of support. In some embodiments, the Column 10 metal is nickel. In certain embodiments, the Column 10 metal is palladium and/or a mixed alloy of platinum and palladium. Use of a mixed alloy catalyst may enhance processing of gas streams with sulfur containing compounds. In some embodiments, the first catalyst is a commercial catalyst. Examples of commercial first catalysts include, but are not limited to, Criterion 424, DN-140, DN-200, and DN-3100, KL6566, KL6560, KL6562, KL6564, KL7756; KL7762, KL7763, KL7731, C-624, C654, all of which are available from CRI/Criterion Inc.

In some embodiments, a second type of catalyst ("second catalyst") includes Column 10 metal on a support. The Column 10 metal may be platinum and/or palladium. In some embodiments, the catalyst includes 0.001 g to 0.05 g, or 0.01 g to 0.02 g of platinum and/or palladium per gram of catalyst. The second catalyst may assist in the oxidation of hydrogen to form water. In some embodiments, the second catalyst is used in the oxidation unit. In some embodiments, the second catalyst is a commercial catalyst. An example of commercial second catalyst includes KL87748, available from CRI/Criterion Inc.

In some embodiments, a third type of catalyst ("third catalyst") includes Columns 6-10 metals on a support. In some embodiments, the third catalyst includes Columns 9-10 metals on a support. The Column 9 metal may be cobalt and the Column 10 metal may be nickel. In some embodiments, the content of nickel metal is from 0.1 g to 0.3 g, per gram of catalyst. The support for a third catalyst may include zirconia. The third catalyst may assist in the reforming of hydrocarbons having a carbon number greater than 2 to carbon monoxide and hydrogen. The third catalyst may be used in the reforming unit. In some embodiments, the third catalyst is a commercial catalyst. Examples of commercial third catalysts include, but are not limited to, CRG-FR and/or CRG-LH available from Johnson Matthey (London, England).

In some embodiments, a fourth type of catalyst ("fourth catalyst") includes Columns 6-10 metals on a support. In some embodiments, the fourth catalyst includes Column 8 metals in combination with Column 10 metals on a support. The Column 8 metal may be ruthenium and the Column 10 metal may be nickel, palladium, platinum, or mixtures thereof. In some embodiments, the fourth catalyst support includes oxides of tantalum, niobium, ^• vanadium, the lanthanides, scandium, or mixtures thereof. The fourth catalyst may be used to convert carbon monoxide and hydrogen to methane and water. In some embodiments, the fourth catalyst is used in the methanation unit. In some embodiments, the fourth catalyst is a commercial catalyst. Examples of commercial fourth catalysts, include, but are not limited to, KATALCO^® 11-4 and/or KATALCO^® 11-4R available from Johnson Matthey.

In some embodiments, a fifth type of catalyst ("fifth catalyst") includes Columns 6-10 metals on a support. In some embodiments, the fifth catalyst includes a Column 10 metal. The fifth catalyst may include from 0.1 g to 0.99 g, from 0.3 g to 0.9 g, from 0.5 g to 0.8 g, or from 0.6 g to 0.7 g of Column 10 metal per gram of fifth catalyst. In some embodiments, the Column 10 metal is nickel. In some embodiments, a catalyst that has at least 0.5 g of nickel per gram of fifth catalyst has enhanced stability in a hydrogenation and methanation process. The fifth catalyst may assist in the conversion of hydrocarbons and carbon dioxide to methane. The fifth catalyst may be used in hydrogenation and methanation units and/or polishing units. In some embodiments, the fifth catalyst is a commercial catalyst. An example of a commercial fifth catalyst is KL6524-T, available from CRI/Criterion Inc.

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.

Claims

C L AI M S

1. A method of producing methane, comprising: providing formation fluid from a subsurface in situ conversion process; separating the formation fluid to produce a liquid stream and a first gas stream, wherein the first gas stream comprises olefins; contacting at least a portion of the olefins in the first gas stream with a hydrogen source in the presence of one or more catalysts and steam to produce a second gas stream; and contacting the second gas stream with a hydrogen source in the presence of one or more additional catalysts to produce a third gas stream, wherein the third gas stream comprises methane.

2. The method as claimed in claim 1, wherein at least one of the additional catalysts comprises nickel.

3. The method as claimed in any of claims 1 or 2, wherein the hydrogen source is hydrogen present in the first gas stream or second gas stream.

4. The method as claimed in any of claims 1-2V, further comprising treating the third gas stream to produce pipeline quality gas.

5. A method of producing methane, comprising: providing formation fluid from a subsurface in situ conversion process; separating the formation fluid to produce a liquid stream and a first gas stream; wherein the first gas stream comprises carbon monoxide, olefins, and hydrogen; and contacting the first gas stream with a hydrogen source in the presence of one or more catalysts to produce a second gas mixture, wherein the second gas mixture comprises methane, and wherein the hydrogen source comprises hydrogen present in the first gas stream.

6. The method as claimed in any of claims 1-5, wherein the first gas stream further comprises ethane.

7. The method as claimed in any of claims 5 or 6, wherein at least one of the catalysts comprises at least 0.3 grams of nickel per gram of catalyst.

8. The method as claimed in any of claims 5-7, further comprising treating the second gas stream to produce pipeline quality gas.

9. A method of producing methane, comprising: providing formation fluid from a subsurface in situ conversion process; separating the formation fluid to produce a liquid stream and a first gas stream, wherein the first gas stream comprises carbon monoxide, hydrogen, and hydrocarbons having a carbon number of at least 2, wherein the hydrocarbons having a carbon number of at least 2 comprise paraffins and olefins; and contacting the first gas stream with hydrogen in the presence of one or more catalysts and carbon dioxide to produce a second gas stream, the second gas stream comprising methane and paraffins, and wherein the hydrogen source comprises hydrogen present in the first gas stream.

10. The method as claimed in claim 9, wherein the paraffins comprise ethane.

11. The method as claimed in any of claims 9 or 10, further comprising separating the methane from the paraffins.

12. The method as claimed in any of claims 9-11, wherein at least one of the catalysts comprises at least 0.1 grams of nickel per gram of catalyst.

13. The method as claimed in any of claims 9-12, wherein the second gas stream comprises water.

14. The method as claimed in claim 13, further comprising separating water from the second gas stream.

15. The method as claimed in claim 13, further comprising separating water from the second gas stream to produce a third gas stream, wherein the third gas stream has a water content of about 0.01 ppm to about 10 ppm.

16. The method as claimed in any of claims 1-15, wherein at least one of the catalysts comprises one or more metals from Columns 6-10 of the Periodic Table and/or one or more compounds of one or more metals from Columns 6-10 of the Periodic Table.

17. The method as claimed in any of claims 1-16, wherein at least one of the catalysts comprises nickel.

18. The method as claimed in any of claims 1-17, wherein at least one of the catalysts comprises alumina, titania, zirconia, or mixtures thereof.

19. The method as claimed in any of claims 1-18, wherein the olefins comprise ethylene and propylene.

20. A method to produce methane comprising providing formation fluid from a subsurface in situ conversion process; separating the formation fluid to produce a liquid stream and one or more gas streams, wherein at least one of the gas streams comprises olefins; and contacting at least one or more of the gas streams using one or more of the methods as claimed in any of claims 1-19.

21. A composition comprising methane produce using one or more of the methods as claimed in any of claims 1-20.