Title of Invention	A METHOD OF PRODUCING METHANE FROM A SUBSURFACE IN SITU CONVERSION PROCESS
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.

Title of Invention

A METHOD OF PRODUCING METHANE FROM A SUBSURFACE IN SITU CONVERSION PROCESS

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.

Full Text	TREATMENT OF GAS FROM AN IN SITU CONVERSION PROCESS BACKGROUND 1. Field of the Invention The present invention relates generally to methods and systems for prodreing hydrogen, methane, and/or other products &om 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. Chernical 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 irnproved 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 froma 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 cazbon number of at least 2 include parafBns 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 embodinsent 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 foms, 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 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. DETAILEP DESCRIPTION The following description generally relates to systems and meflKxk for treating formation fluid produced fi-om a hydrocarbon containing formation using an in situ conversion process. Hydrocaxbon containing formations may be treated to yield hydrocarbon products, hydrogen, methane, and ottier products. "Hydrocarbons" are generally defined as molecules formed primarily by carbon and hydrogen atoms. Hydrocarbons may also include other elements such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulfur. Hydrocarbons may be, but are not limited to, kerogen, bitumen, pyrobitumen, oils, natural mineral waxes, and asphaltites. Hydrocarbons may be located in or adjacent to mineral matrices in the earth. Matrices may include, but are not limited to, sedimentary rock, sands, silicilytes, carbonates, diatondtes, 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 exanple, overburden and/or underburden may include rock, shale, mudstone, or wet'tigbt 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 tenqueratures during in situ conversion processing that result in significant characteristic changes of the hydrocarbon containing layers of the overburden and/or the underburden. For cxsanple, the underburden may contain shale or mudstone, but the imderburden is not allowed to heat to pyrolysis temperatures during the in situ conversion process. In some cases, the overburden and/or the undeiburden may be somewhat permeable. Fonnation 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. 'Troduced 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 tenperature 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 nuniber distribution. Carbon numbers and/or caxbon number distributions may be detennined 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 sur&ce 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 exan^le, for a given formation some heat sources may supply heat firom electric resistance heaters, some heat soiu'ces may provide heat fix>m combustion, and some heat sources may provide heat from one or more other ^lergy sources (for exan^le, chenoical reactions, solar energy, wind energy, biomass, or other sources of renewable energy). A chemical reaction may include an exothermic reaction (for exanple, an oxidation reaction). A heat source may also include a heater that provides heat to a zone proximate and/or surroimding 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 hereof. An "in situ conversion process" refers to a process of heating a hydrocarbon containing formation firom 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 fonnation. A wellbore may have a substantially circular cross section, or another cross-sectional shape. As used are used to from a barrier around a treatmerarea. 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 einbodiments, 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 bumers, flameless distributed combtistors, and/or natural distributed cornbustors. Heat sources 210 may also include other types of heaters. Heat sources 210 provide heat to at least a portion of the formation to beat hydrocarbons in the fomaation. Hydrocarbons in the formation may be pyrolyzed to form formation fluid. Energy may be supplied to heat sources 210 through supply lines 212. Siq>ply 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 cornbustors, 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 maybe transported through collection pq>ing 216 to treatment facilities 218. Formation fluids may also be produced from heat sources 210. For exarx^le, 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 naay be transported through tubing or piping to collection piping 216 or the produced fluid may be transported through tubing or piping direcfly 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 enibodiments, 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 treatmeat 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 confounds. 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 from0.0001 grams (g) to 01 g, from0.001 g to O.OS g, or from0.01 g to 0.03 g of hydrogen, per gram of gas stream. In certain enibodiinents, 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 mchides from0.00001 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 enibodiments, gas stream 232 includes trace amounts of carbon dioxide. In certain embodiments, gas stream 232 may include from0.0001 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 immber 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 gtoO.l g of a mixture of ethylene, ethane, and propylene. In some emtbodiments, hydrocarbons having a carbon number of at least 2 includes trace amounts of hydrocarbons having a carbon number of at least 4. Pipelii]ie gas (for example, natural gas) after treatment to remove the hydrogen sulfide, mcludes methane, ethane, propane, butane, carbon dioxide, oxygen, nitrogen, and small ansounts 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 compoments 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 &cilitate 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 m the art Temperatures may range from 50 X to 600 °C, from 100 °C to 500 °C, or from 200 X to 400 °C. Pressures may range from 0.1 MPa to 20 MPa, fix)m 1 MPa to 12 MPa, from 4 MPa to 10 MPa, or fix)m 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 confound 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 imit 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 imit 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 ten:q)erature ranging from 50 °C to 80 °C (for examples, at a tenq>erature 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 tiban or equal to the boiling point of ethane. hi some enibodiments, 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 imit 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 •=€ to 500 °C, from 100 °C to 400 °C, or from 200 =°C to 300°C. Gas stream 252 exits oxidation unitt 248 and enters dehydration unit 254. In dehydration unit 254, separation of water fromgas 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 modijBcation of conponents in the in situ conversion process gas. FIG. 3 depicts a schematic representation of an embodiment to enhance the amount of methane in pg)eline gas though 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 firom conversion of hydrocarbons wi& a carbon number greater dian 2 (for exanple, e&ylene, 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 firom 250 °C to 500 °C. hi some embodiments, pressures in reforming unit 262 range firom 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 fromgas 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 ernbodiments, an additional hydrogen source is added to the me&anation unit and/or the gas stream. Gas stream 268 may include water, carbon dioxide, and methane. Methanation unit 266 may be operated at ten^>eratures and pressures described borein or operated ofterwise as known in the art In some embodiments, methanation unit 266 is operated at teniperatures ranging from 260 ^C to 320 °C. In some enibodiments, pressures in methanation unit 266 range from 1 MPa to 5 MPa. Carbon dioxide may be separated form gas stream 268 in carbon dioxide separation unit 270. In some enibodiments, 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 anaines to fucilitate 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 in^urities. Inhibiting the formation of inipurities 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 mult^le 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 tmit 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 einbodiments, 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 nuinber 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 tenq)eratures, and pressures, described herein, or operated odierwise as known in the art In some embodiments, hydrogenation and methanation unit 276 is operated at a ten:q)erature ranging from 200 °C to 350 ^C. In some enabodiments, pressure in hydrogenation and methanation imit 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 metiianation 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 °C to 400 °C. 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 inay reacf 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 inpurities. 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 imit 286 or to gas stream 232. The quantity of hydrogen in hydrogenation and methanation unit 286 may be controlled and/or ^ flow of carbon dioxide may be controlled to provide a TniTiinintii quantity of hydrogen in gas stream 288. Gas stream 288 may include water, hydrogen, methane, ethane, and, in some embodimraaits, at least a portion of the hydrocarbons having a carbon nuniber greater than 2 from gas stream 232. In some enibodiments, 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 me&ane, 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 e&ane, 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 °C to 350 °C and a pressure ranging from 1 MPa to 12 MPa, 2 MPa to 10 MPa, or4 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 exil;^ 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 wifh 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, wat^ 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 pipehne gas 256 and hydrocarbon stream 296. Pipeline gas stream 256 includes methane and/or carbon dioxide. Hydrocarbon stream 296 includes ethane and, in some enibodiiiients, residual hydrocarbons having a carbon niunber of at least 2. In some enibodiments, 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 inpurities. 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 sorrse enibodiments, hydrogen source 234 is added to gas stream 232. In hydrogenation and methanation unit 298, contact of gas stream 232 wi& hydrogen soiurce 234 in the presence of cme or more catalysts produces gas stream 300. In some embodiments, carbon dioxide may be added to hydrogen and metbanation unit 298. The quantity of hydrogen in hydrogenation and medianation unit 298 niay be controlled to provide an excess quantity of hydrogen to the hydrogenation and metbanation 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 from0.05 g to 0.9 g, from 0.1 g to 0.6 g, or from0.2 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 02 g, or firom 0.01 g to 0.1 g of ethane, per gram of gas stream. In some embodiments, gas stream 300 includes caifoon monoxide and trace amounts of olefins. Hydrogenation and metbanation unit 298 may be operated at tenq>eiatUFes and pressures, described herein, or operated otherwise as known in the art La some embodiments, hydrogenation and noe&anation unit 298 is operated at a tenq)erature ranging from 60 ^C to 400 °C 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 metbanation 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 fliat is capable of separating hydrogen and/or carbon dioxide from gas stream 300. Gas separation unit may be a pressure swing adsoxption unit, a membrane unit, a liquid absorption unit, and/or a cryogenic unit In some embodiments, gas stream 300 exits hydrogenation and metbanation 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 metibanation unit 298, mixed with gas stream 232 and/or mixed with hydrogen source 234 upstream of the hydrogenation melhanation unit In embodiments in which carbon dioxide is added to hydrogenation and metbanation 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 metbanation unit, mixed with gas stream 232 iq>stream of the hydrogenation and metbanation unit, and/or mixed with the carbon dioxide stream entering the hydrogenation and metbanation unit Gas stream 304 enters dehydration imit 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 conibinations of one or more of the processes described in FIGS. 2,3,4,5, and 6. For exanrple, all or at least a portion of gas streams fix>m reforming unit 262 (FIG. 3) may be treated in hydrogenation and metbanation 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 corobined with gas streams entering, reforming unit 262, hydrogenation and metbanation unit 276, and/or hydrogenation and metbanation imit 286. In some embodiments, gas stream 232 may be bydrotreated and/or used in other processing units. Catalysts used to produce natural gas &at meets pipeline specifications may be bulk metal catalysts or supported catalysts. Bulk metal catalysts include Columns 6-10 metals. Supported catalysts include Colimxos 6-10 metals on a support Columns 6-10 metals include, but are not limited to, vanadium, chromiimi, molybdenum, tungsten, manganese, technetium, rhenium, iron, cobal^ nickel, mdienium, 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 CLAIMS 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 conmprises 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 1-3, 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 flmd 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 con^rising treating the second gas stream to produce pipeline quality gas. 9. A method of producing metiiane, con^jrising: providing formation fluid fix)m 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 conprises carbon monoxide, hydrogen, and hydrocarbons having a carbon number of at least 2, wherein the hydrocarbons having a carbon nuniber of at least 2 comprise paraffis 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 parafins 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 coniprises at least 0.1 grams of nickel per gram of catalyst titaxiia, 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 compsing providing formation fluid from a subsurce 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 &e 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.

Full Text

TREATMENT OF GAS FROM AN IN SITU CONVERSION PROCESS
BACKGROUND
1. Field of the Invention
The present invention relates generally to methods and systems for prodreing hydrogen, methane, and/or other products &om 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. Chernical 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 irnproved 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 froma 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 cazbon number of at least 2 include parafBns 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 embodinsent 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 foms, 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 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.
DETAILEP DESCRIPTION
The following description generally relates to systems and meflKxk for treating formation fluid produced fi-om a hydrocarbon containing formation using an in situ conversion process. Hydrocaxbon containing formations may be treated to yield hydrocarbon products, hydrogen, methane, and ottier products.
"Hydrocarbons" are generally defined as molecules formed primarily by carbon and hydrogen atoms. Hydrocarbons may also include other elements such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulfur. Hydrocarbons may be, but are not limited to, kerogen, bitumen, pyrobitumen, oils, natural mineral waxes, and asphaltites. Hydrocarbons may be located in or adjacent to mineral matrices in the earth. Matrices may include, but are not limited to, sedimentary rock, sands, silicilytes, carbonates, diatondtes, 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 exanple, overburden and/or underburden may include rock, shale, mudstone, or wet'tigbt 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 tenqueratures during in situ conversion processing that result in significant characteristic changes of the hydrocarbon containing layers of the overburden and/or the underburden. For cxsanple, the underburden may contain shale or mudstone, but the imderburden is not allowed to heat to pyrolysis temperatures during the in situ conversion process. In some cases, the overburden and/or the undeiburden may be somewhat permeable.
Fonnation 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. 'Troduced 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 tenperature 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 nuniber distribution. Carbon numbers and/or caxbon number distributions may be detennined 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 sur&ce 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 exan^le, for a given formation some heat sources may supply heat firom electric resistance heaters, some heat soiu'ces may provide heat fix>m combustion, and some heat sources may provide heat from one or more other ^lergy sources (for exan^le, chenoical reactions, solar energy, wind energy, biomass, or other sources of renewable energy). A chemical reaction may include an exothermic reaction (for exanple, an oxidation reaction). A heat source may also include a heater that provides heat to a zone proximate and/or surroimding 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 hereof.
An "in situ conversion process" refers to a process of heating a hydrocarbon containing formation firom 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 fonnation. A wellbore may have a substantially circular cross section, or another cross-sectional shape. As used

are used to from a barrier around a treatmerarea. 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 einbodiments, 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 bumers, flameless distributed combtistors, and/or natural distributed cornbustors. Heat sources 210 may also include other types of heaters. Heat sources 210 provide heat to at least a portion of the formation to beat hydrocarbons in the fomaation. Hydrocarbons in the formation may be pyrolyzed to form formation fluid. Energy may be supplied to heat sources 210 through supply lines 212. Siq>ply 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 cornbustors, 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 maybe transported through collection pq>ing 216 to treatment facilities 218. Formation fluids may also be produced from heat sources 210. For exarx^le, 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 naay be transported through tubing or piping to collection piping 216 or the produced fluid may be transported through tubing or piping direcfly 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 enibodiments, 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

treatmeat 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 confounds. 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 from0.0001 grams (g) to 0*1 g, from0.001 g to O.OS g, or from0.01 g to 0.03 g of hydrogen, per gram of gas stream. In certain enibodiinents, 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 mchides from0.00001 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 enibodiments, gas stream 232 includes trace amounts of carbon dioxide.
In certain embodiments, gas stream 232 may include from0.0001 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 immber 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 gtoO.l g of a mixture of ethylene, ethane, and propylene. In some emtbodiments, hydrocarbons having a carbon number of at least 2 includes trace amounts of hydrocarbons having a carbon number of at least 4.
Pipelii]ie gas (for example, natural gas) after treatment to remove the hydrogen sulfide, mcludes methane, ethane, propane, butane, carbon dioxide, oxygen, nitrogen, and small ansounts 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 compoments 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 &cilitate 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 m the art Temperatures may range from 50 X to 600 °C, from 100 °C to 500 °C, or from 200 X to 400 °C. Pressures may range from 0.1 MPa to 20 MPa, fix)m 1 MPa to 12 MPa, from 4 MPa to 10 MPa, or fix)m 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 confound 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 imit 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 imit 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 ten:q)erature ranging from 50 °C to 80 °C (for examples, at a tenq>erature 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 tiban or equal to the boiling point of ethane.
hi some enibodiments, 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 imit 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 •=*€ to 500 °C, from 100 °C to 400 °C, or from 200 =°C to 300°C.

Gas stream 252 exits oxidation unitt 248 and enters dehydration unit 254. In dehydration unit 254, separation of water fromgas 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 modijBcation of conponents in the in situ conversion process gas.
FIG. 3 depicts a schematic representation of an embodiment to enhance the amount of methane in pg)eline gas though 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 firom conversion of hydrocarbons wi& a carbon number greater dian 2 (for exanple, e&ylene, 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 firom 250 °C to 500 °C. hi some embodiments, pressures in reforming unit 262 range firom 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 fromgas 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 ernbodiments, an additional hydrogen source is added to the me&anation unit and/or the gas stream. Gas stream 268 may include water, carbon dioxide, and methane.
Methanation unit 266 may be operated at ten^>eratures and pressures described borein or operated ofterwise as known in the art In some embodiments, methanation unit 266 is operated at teniperatures ranging from 260 ^C to 320 °C. In some enibodiments, pressures in methanation unit 266 range from 1 MPa to 5 MPa.
Carbon dioxide may be separated form gas stream 268 in carbon dioxide separation unit 270. In some enibodiments, 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 anaines to fucilitate 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 in^urities. Inhibiting the formation of inipurities 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 mult^le 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 tmit 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 einbodiments, 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 nuinber 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 tenq)eratures, and pressures, described herein, or operated odierwise as known in the art In some embodiments, hydrogenation and methanation unit 276 is operated at a ten:q)erature ranging from 200 °C to 350 ^C. In some enabodiments, pressure in hydrogenation and methanation imit 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 metiianation 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 °C to 400 °C. 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 inay reacf 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 inpurities.
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 imit 286 or to gas stream 232. The quantity of hydrogen in hydrogenation and methanation unit 286 may be controlled and/or ^ flow of carbon dioxide may be controlled to provide a TniTiinintii quantity of hydrogen in gas stream 288.
Gas stream 288 may include water, hydrogen, methane, ethane, and, in some embodimraaits, at least a portion of the hydrocarbons having a carbon nuniber greater than 2 from gas stream 232. In some enibodiments, 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 me&ane, 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 e&ane, 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 °C to 350 °C and a pressure ranging from 1 MPa to 12 MPa, 2 MPa to 10 MPa, or4 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 exil;^ 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 wifh 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, wat^ 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 pipehne gas 256 and hydrocarbon stream 296. Pipeline gas stream 256 includes methane and/or carbon dioxide. Hydrocarbon stream 296 includes ethane and, in some enibodiiiients, residual hydrocarbons having a carbon niunber of at least 2. In some enibodiments, 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 inpurities.
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 sorrse enibodiments, hydrogen source 234 is added to gas stream 232. In hydrogenation and methanation unit 298, contact of gas stream 232 wi& hydrogen soiurce 234 in the presence of cme or more catalysts produces gas stream 300. In some embodiments,

carbon dioxide may be added to hydrogen and metbanation unit 298. The quantity of hydrogen in hydrogenation and medianation unit 298 niay be controlled to provide an excess quantity of hydrogen to the hydrogenation and metbanation 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 from0.05 g to 0.9 g, from 0.1 g to 0.6 g, or from0.2 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 02 g, or firom 0.01 g to 0.1 g of ethane, per gram of gas stream. In some embodiments, gas stream 300 includes caifoon monoxide and trace amounts of olefins.
Hydrogenation and metbanation unit 298 may be operated at tenq>eiatUFes and pressures, described herein, or operated otherwise as known in the art La some embodiments, hydrogenation and noe&anation unit 298 is operated at a tenq)erature ranging from 60 ^C to 400 °C 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 metbanation 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 fliat is capable of separating hydrogen and/or carbon dioxide from gas stream 300. Gas separation unit may be a pressure swing adsoxption unit, a membrane unit, a liquid absorption unit, and/or a cryogenic unit In some embodiments, gas stream 300 exits hydrogenation and metbanation 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 metibanation unit 298, mixed with gas stream 232 and/or mixed with hydrogen source 234 upstream of the hydrogenation melhanation unit In embodiments in which carbon dioxide is added to hydrogenation and metbanation 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 metbanation unit, mixed with gas stream 232 iq>stream of the hydrogenation and metbanation unit, and/or mixed with the carbon dioxide stream entering the hydrogenation and metbanation unit
Gas stream 304 enters dehydration imit 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 conibinations of one or more of the processes described in FIGS. 2,3,4,5, and 6. For exanrple, all or at least a portion of gas streams fix>m reforming unit 262 (FIG. 3) may be treated in hydrogenation and metbanation 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 corobined with gas streams entering, reforming unit 262, hydrogenation and metbanation unit 276, and/or hydrogenation and metbanation imit 286. In some embodiments, gas stream 232 may be bydrotreated and/or used in other processing units.
Catalysts used to produce natural gas &at meets pipeline specifications may be bulk metal catalysts or supported catalysts. Bulk metal catalysts include Columns 6-10 metals. Supported catalysts include Colimxos 6-10 metals on a support Columns 6-10 metals include, but are not limited to, vanadium, chromiimi, molybdenum, tungsten, manganese, technetium, rhenium, iron, cobal^ nickel, mdienium, 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

CLAIMS
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 conmprises 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 1-3, 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 flmd 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 con^rising treating the second gas stream to produce pipeline quality gas.
9. A method of producing metiiane, con^jrising:
providing formation fluid fix)m 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 conprises carbon monoxide, hydrogen, and hydrocarbons having a carbon number of at least 2, wherein the hydrocarbons having a carbon nuniber of at least 2 comprise paraffis 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 parafins 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 coniprises at least 0.1 grams of nickel per gram of catalyst

titaxiia, 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 compsing providing formation fluid from a subsurce 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 &e
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.

Documents:

4140-CHENP-2007 AMENDED CLAIMS 09-09-2014.pdf

4140-CHENP-2007 AMENDED PAGES OF SPECIFICATION 09-09-2014.pdf

4140-CHENP-2007 FORM-1 09-09-2014.pdf

4140-CHENP-2007 POWER OF ATTORNEY 09-09-2014.pdf

4140-CHENP-2007 CORRESPONDENCE OTHERS 23-04-2013.pdf

4140-CHENP-2007 CORRESPONDENCE OTHERS 05-11-2013.pdf

4140-CHENP-2007 EXAMINATION REPORT REPLY RECIEVED 09-09-2014.pdf

4140-CHENP-2007 FORM-3 23-04-2013.pdf

4140-chenp-2007 form-18.pdf

4140-chenp-2007-abstract.pdf

4140-chenp-2007-claims.pdf

4140-chenp-2007-correspondnece-others.pdf

4140-chenp-2007-description(complete).pdf

4140-chenp-2007-drawings.pdf

4140-chenp-2007-form 1.pdf

4140-chenp-2007-form 3.pdf

4140-chenp-2007-form 5.pdf

4140-chenp-2007-pct.pdf

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Patent Number

262929

Indian Patent Application Number

4140/CHENP/2007

PG Journal Number

39/2014

Publication Date

26-Sep-2014

Grant Date

24-Sep-2014

Date of Filing

20-Sep-2007

Name of Patentee

SHELL INTERNATIONALE RESEARCH MAATSCHAPPIJ B.V

Applicant Address

CAREL VAN BYLANDTLAAN 30, NL-2596 HR THE HAGUE, THE NETHERLANDS.

Inventors:

#	Inventor's Name	Inventor's Address
1	DEL, PAGGIO, ALAN, ANTHONY	8106 MORNINGBROOK CT., SPRING TEXAS 77379, USA.
2	ROSE, AUGUSTINUS, WILHELMUS, MARIA	5807 SANTA FE SPRINGS DRIVE, HOUSTON, TEXAS 77041, USA.
3	DIAZ, ZAIDA	12106 MEADOW LAKE, HOUSTON, TEXAS 77077, USA.
4	NAIR, VIJAY	21818 MOORTOWN CIRCLE, KATY TEXAS 77450, USA.

PCT International Classification Number

C10L 03/08

PCT International Application Number

PCT/US2006/015286

PCT International Filing date

2006-04-24

PCT Conventions:

#	PCT Application Number	Date of Convention	Priority Country
1	60/674,081	2005-04-22	U.S.A.