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WO2015183426A1 - Procédé et système de conversion de gaz de torche - Google Patents

Procédé et système de conversion de gaz de torche Download PDF

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Publication number
WO2015183426A1
WO2015183426A1 PCT/US2015/026510 US2015026510W WO2015183426A1 WO 2015183426 A1 WO2015183426 A1 WO 2015183426A1 US 2015026510 W US2015026510 W US 2015026510W WO 2015183426 A1 WO2015183426 A1 WO 2015183426A1
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WO
WIPO (PCT)
Prior art keywords
methane
output
volume
set point
gas
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Ceased
Application number
PCT/US2015/026510
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English (en)
Inventor
Ryan KEMMET
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
ADVANCED GREEN TECHNOLOGIES LLC
Original Assignee
ADVANCED GREEN TECHNOLOGIES LLC
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by ADVANCED GREEN TECHNOLOGIES LLC filed Critical ADVANCED GREEN TECHNOLOGIES LLC
Publication of WO2015183426A1 publication Critical patent/WO2015183426A1/fr
Anticipated expiration legal-status Critical
Priority to US15/362,598 priority Critical patent/US20170145330A1/en
Ceased legal-status Critical Current

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Classifications

    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G OR C10K; LIQUIFIED PETROLEUM GAS; USE OF ADDITIVES TO FUELS OR FIRES; FIRE-LIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
    • C10L3/08—Production of synthetic natural gas
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2/00—Production of liquid hydrocarbon mixtures of undefined composition from oxides of carbon
    • C10G2/30—Production of liquid hydrocarbon mixtures of undefined composition from oxides of carbon from carbon monoxide with hydrogen
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G OR C10K; LIQUIFIED PETROLEUM GAS; USE OF ADDITIVES TO FUELS OR FIRES; FIRE-LIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
    • C10L3/10—Working-up natural gas or synthetic natural gas
    • C10L3/101—Removal of contaminants
    • C10L3/102—Removal of contaminants of acid contaminants
    • C10L3/103—Sulfur containing contaminants
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1081—Alkanes
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G OR C10K; LIQUIFIED PETROLEUM GAS; USE OF ADDITIVES TO FUELS OR FIRES; FIRE-LIGHTERS
    • C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
    • C10L2290/46—Compressors or pumps
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G OR C10K; LIQUIFIED PETROLEUM GAS; USE OF ADDITIVES TO FUELS OR FIRES; FIRE-LIGHTERS
    • C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
    • C10L2290/54—Specific separation steps for separating fractions, components or impurities during preparation or upgrading of a fuel
    • C10L2290/541—Absorption of impurities during preparation or upgrading of a fuel

Definitions

  • the invention relates to a method and apparatus arranged and designed for converting natural gas with high gas liquids content at remote locations to pipeline quality natural gas.
  • Oil wells often have an amount of natural gas associated with them.
  • the natural gas must be removed in order to remove the oil.
  • This natural gas is flared or burned. The flaring process causes volatile organic compound emissions and is being targeted for removal for environmental protection reasons.
  • Natural gas associated with oil wells though mostly methane, is often high in alkanes other than methane, such as ethane, propane and butane. These higher carbon number alkanes are of high value in the oil and gas industry and, in some embodiments, may allow for transport of the energy in the form of a highly dense liquid.
  • Membrane separation pressurizes the stream to high pressures (1000+ PSI) and forces the gas through membrane sieves which force the liquids to condense and allow the liquids to be removed.
  • Membrane separation is unable typically to remove ethane because of its small size and relatively close size to methane.
  • the quality of resulting natural gas from membrane separation is not of pipeline quality because of its ethane content.
  • Gas to liquid conversion involves first converting the methane stream into synthesis gas, which is a combination of hydrogen, carbon monoxide, and carbon dioxide.
  • synthesis gas is then processed to react the stream into high carbon number alkanes (e.g., by Fischer-Tropsch processes).
  • high carbon number alkanes e.g., by Fischer-Tropsch processes.
  • target liquid produced is methanol.
  • a method may clean flare gas by receiving a volume of natural gas, where the volume of natural gas includes a volume of methane and a volume of other alkanes.
  • the method may then control both an inlet flow of the volume of natural gas and a volume of water to at least one reformer system and cause the at least one reformer system to crack, convert, or change at least a portion of the volume of other alkanes from the volume of natural gas.
  • the at least one steam reformer system generates synthesis gas from the volume of natural gas and the volume of water.
  • the method may then combine the synthesis gas with hydrogen to form methane.
  • a method may control a system to clean flare gas.
  • the method may receive output measurements from the system. These output measurements may include one or more of a C0 2 output and a methane output.
  • the method may also determine if one or more of the C0 2 output measurement and the methane output measurement are different than a C0 2 output set point and a methane output set point, and adjust one or more of an inlet water flow to at least one steam reformer system and an inlet gas flow to the at least one steam reformer system in response to the C0 2 output set point and a methane output set point being different than the C0 2 output measurement and the methane output measurement.
  • the at least one steam reformer system may be configured to facilitate the formation of methane by: 1 ) receiving a volume of natural gas from the inlet gas flow, the volume of natural gas including a volume of methane and a volume of other alkanes; 2) receiving a volume of water from the inlet water flow; and 3) crack at least a portion of the volume of other alkanes from the volume of natural gas to generate synthesis gas from the volume of natural gas and the volume of water.
  • the method may then combine the synthesis gas with hydrogen to form methane.
  • a system for cleaning flare gas may include at least one steam reformer system, a methanizer, and a controller.
  • the at least one steam reformer system may be in fluid communication with both a source of natural gas and a source of water.
  • the at least one steam reformer system may also be configured to crack a volume of alkanes from a volume of natural gas to produce a volume of synthesis gas.
  • the methanizer may be in fluid communication with both the at least one steam reformer system and a source of hydrogen.
  • the methanizer may be configured to combine the volume of synthesis gas with a volume of hydrogen to form methane.
  • the controller may include one or more memories, one or more processors in communication with the one or more memories, and one or more computer-readable instructions stored in the one or more memories and executable by the one or more processors.
  • the instructions may be executable to receive output measurements from the system.
  • the output measurements may include one or more of a C0 2 output measurement and a methane output measurement.
  • the instructions may be further executable to determine if one or more of the C0 2 output measurement and the methane output measurement are different than a C0 2 output set point and a methane output set point, and to adjust one or more of an inlet water flow to at least one steam reformer system and an inlet gas flow to the at least one steam reformer system in response to the C0 2 output set point and a methane output set point being different than the C0 2 output measurement and the methane output measurement.
  • FIG. 1 illustrates components of a system for converting flare gas in an embodiment of the disclosure
  • FIG. 2 illustrates one embodiment of a method for converting flare gas in an embodiment of the disclosure
  • Figs. 3A, 3B, 3C, and 3D illustrate embodiments of a method for controlling a system to convert flare gas in an embodiment of the disclosure
  • Fig. 4 illustrates further components of a system for converting flare gas in an embodiment of the disclosure.
  • the present disclosure describes the use of a novel combination of a synthesis gas generator combined with a hydrogen generator, a methanizer, and a dehydrator to create pipeline quality natural gas with little input energy required.
  • a process may convert natural gas with other alkanes present into natural gas with little or no alkanes present.
  • the processes 200, 300, 320, 350, 370 result in both the creation of synthesis gas and the methanization of that gas to form methane and water.
  • additional hydrogen must be added. This additional hydrogen can be pulled from the synthesis gas as a portion of the flow that has the carbon monoxide and carbon dioxide removed and/or the hydrogen can be supplied from an outside source 1 15.
  • an inlet gas 104 including high alkane gas has a ratio of carbon to hydrogen of about 2:5.75.
  • Inlet gas may include flare gas of varying composition that enters the system 100.
  • This gas may contain alkanes propane and ethane in high mole fraction as well as carbon dioxide, nitrogen, and water vapor, the largest mole fraction is methane.
  • This stream of high alkane gas may be combined with heat and water resulting in carbon monoxide and carbon dioxide in equal parts and hydrogen in half as much as the input plus the amount of hydrogen from water.
  • seven parts hydrogen must combine with one part carbon dioxide and one part carbon monoxide. This results in a need for extra hydrogen in embodiments of the system 100 that utilize a stream of high alkane gas.
  • Chemical reactions involved in the system 100 and the methods 200, 300, 320, 350, and 370 to clean flare gas as herein described may include:
  • sulfur removing filter system 106 may remove organic sulfurs and hydrogen sulfide from a high alkane gas stream to create a sulfur free natural gas stream.
  • the system 106 may remove the organic sulfurs and hydrogen sulfide through hydrogenation and absorption.
  • a single stage well head gas compressor compresses inlet gas streams into a pressure vessel which holds the gas at a higher pressure than required by the reformer and outputs gas pressure as required by reformer.
  • a gas compressor 108 may compress the sulfur free gas stream to a nominal pressure or may completely compress the gas to ensure movement of the gas through the system 100.
  • a secondary gas compressor 109A and/or 109B may be required to force water out of the resulting stream.
  • the process may also input water and at step 206, filter the water for reactors/reformers 1 14A and 1 14B, as described herein.
  • reformers 1 14A and 1 14B may include a steam methane reformation system and/or a steam ethane reformation system.
  • the gas stream may pass through an inlet reservoir 1 10 and regulator 1 12 to be separated into one or more reformer systems 1 14A, 1 14B. Additionally, the process 200 may pass a volume of the natural gas to burners 1 15A and 1 15B associated with each reactor, as further explained, below. At steps 208 and 210, the process 200 may pass the gas stream through mass flow controllers 1 16A, 1 16B. At steps 212 and 214, the process 200 may pass the filtered water through reactor water pumps 124, 125 to the reactors 1 14A and 1 14B. In some embodiments, the reactors 1 14A, 1 14B may be configured as steam methane reformers that include nickel-based catalysts.
  • the process may cause one or more of the reactors 1 14A, 1 14B, to generate synthesis gas.
  • one or more burners 1 15A and 1 15B may control an amount of heat for the reactors 1 14A, 1 14B to facilitate a reaction.
  • the burners 1 15A and 1 15B may burn the input gas to achieve a proper temperature in the reformers 1 14A and 1 14B associated with the burners.
  • the burner 1 15B heats the reformer 1 14B to a temperature to cause the cracking of C2+ hydrocarbons, and may not crack or reform methane.
  • a burner system i.e., burner 1 15A
  • a reformer system reactor i.e., reformer 1 14A
  • the reformers 1 14A and 1 14B may receive water from a source 122. The water may require filtration before being received by the reformer(s). The water is turned to steam in the reactors and the steam along with the catalyst and increased temperature in the reactors may crack or break apart the hydrocarbons.
  • one or more of steam methane reformers may communicate the synthesis gas to a hydrogen purifier 1 18.
  • the feed from the reformer system 1 14A may be fed to the hydrogen purifier 1 18 which allows a partial pressure of hydrogen to pass the purifier 1 18.
  • the purifier 1 18 may be configured to heat palladium or any other material and to separate hydrogen in the synthesis gas from carbon monoxide and carbon dioxide. A portion of synthesis gas may be sent through the purifier 1 18 to remove CO and CO 2 from the stream, leaving 95% purity hydrogen.
  • the system 100 may include a hydrogen supply 1 15 in combination with or in lieu of a reformer (e.g., 1 14A) to supply hydrogen to the methanizer 102. The remaining flow that does not flow through the hydrogen purifier 1 18 may then flow back to the burner system 1 15A for complete burning.
  • an exhaust 120 may provide an outlet on the purifier 1 18 for gases other than hydrogen.
  • the steam methane reformers 1 14A, 1 14B may be heated at steps 218A and 218B by the inlet natural gas stream and a portion of the synthesis gas stream, which enables a nearly pure output of carbon dioxide from the exhaust 120 at step 222.
  • water from a water source 122 may be input at steps 212 and 214 into the reformers 1 14A, 1 14B via a pump 124.
  • the pump 124 may be configured to match the flow of the water to the flow of the inlet gas stream.
  • the resulting synthesis gas stream and hydrogen stream may be combined and flow through a methanizer 102.
  • the hydrogen flow combines with the synthesis gas flow from the reformer 1 14B system in the methanizer 102.
  • the methanizer 102 is configured to combine the hydrogen with the CO and CO 2 from the reformer 1 14B synthesis gas stream to form methane and water.
  • the methanizer includes a nickel based catalyst which is different from the catalyst of the reformers 1 14A, 1 14B.
  • a majority of the water is removed from the resulting methane and water stream from the methanizer, and the resulting stream is mostly methane.
  • the water may be recovered and reused through a de-ionization filtration system 128 via a pump 130 as feed stock for the one or more reformers 1 14A, 1 14B.
  • the deionized water system may create water to the purity and ion specification as required by the reformer systems 1 14A and 1 14B.
  • the means 126 includes a secondary process that forces the removal of water through deliquescent desiccant dehydration or may remove water by a coalescing, mechanical, and desiccant separation of water from the stream. The removed water may then be cycled back to the water supply 122 or otherwise fed back to the steam reformer systems 1 14A and 1 14B.
  • sensors 132, 134, 136 may measure the natural gas output as a measures of the methane and carbon dioxide or other hydrocarbons, as well as the output pressure of the natural gas stream. In some embodiments, the output pressure controls the total flow out of the system.
  • the process 200 may measure the methane and carbon dioxide or other matter in the stream using infrared sensors.
  • a sensor 132 may measure the output stream of natural gas as including about 90% or greater methane.
  • the process 200 may out put a gas stream including methane. These measurements, possibly including other measures, may then be processed by a controller 140, as further described, below.
  • Control of the system 100 and processes 200, described above, and 300, 320, 350, 370, described below, may be facilitated using computer-readable instructions that are stored within a tangible memory of a controller 140.
  • the controller 140 may include both a memory 140A for storing instructions and a microcontroller or processor 140B for executing instructions to control the system 100 and processes 200, 300, 320, 350, 370 and any other computer-controlled functions for converting flare gas, as described herein.
  • the processor 140B may include a register set or register space which may be entirely on-chip, or alternatively located entirely or partially off-chip and directly coupled to the processor 140B via dedicated electrical connections and/or via an interconnection bus.
  • the processor 140B may be any suitable processor, processing unit or microprocessor.
  • system 100 or any system employing various embodiments system 100 as herein described may be a multi-processor device and, thus, may include one or more additional processors that are identical or similar to the processor 140B and that are communicatively coupled to an interconnection bus.
  • the processor 140B may also be coupled to a chipset, which includes a memory controller and a peripheral input/output (I/O) controller.
  • the chipset typically provides I/O and memory management functions as well as a plurality of general purpose and/or special purpose registers, timers, etc. that are accessible or used by one or more processors coupled to the chipset.
  • the memory controller performs functions that enable the processor controller (or processors if there are multiple processors) to access a system memory and a mass storage memory (not shown).
  • the processor 140B may also include one or more memories 140A storing instruction modules to implement flare gas conversion strategies such as a method 200 (Fig. 2) or 300, 320, 350, 370 (Figs. 3A, 3B, 3C, and 3D) for converting flare gas to natural gas or other functions as herein described.
  • a flare gas conversion control module 140C may be stored in memory 140A and include tangible computer- executable instructions that are stored in a non-transitory computer-readable storage medium.
  • the instructions of the flare gas conversion control module 140C are executed by the processor 140B or the instructions can be provided from computer program products that are stored in tangible computer-readable storage mediums (e.g. RAM, hard disk, optical/magnetic media, etc.).
  • the control of the system 100 requires that the gas streams that are input to the various components of the system 100 are able to be varied.
  • the embodiments described herein generally rely on steam methane reformation and methanation.
  • the steam methane reformer system 1 14A and steam ethane reformer system 1 14B add water (in the form of steam) and gas together to crack the hydrocarbons. At different temperatures, additional hydrocarbons will crack. The lighter hydrocarbons have a higher activation energy and require additional heat input to crack. In order to run the reformer systems without coking them, water should be above a 1 :1 steam to carbon ratio.
  • the methanation step 224 (Fig.
  • controller 140 may execute one or more instructions to precisely control water in the reformer system 1 14B.
  • excess water has no effect because only hydrogen is ultimately resulting.
  • a process 300 executed by the controller 140 may control the pressure within the system 100 to achieve optimal or desired conversion of flare gas as herein described.
  • the controller 140 may receive a measured output pressure from the system 100.
  • the controller 140 may cause flow to one or more of the mass flow controllers 1 16A, 1 16B and to a reactor water pump 125 for reformer system 1 14B to increase.
  • the controller 140 may cause flow to one or more of the mass flow controllers 1 16A, 1 16B and to a reactor water pump 125 for reformer system 1 14B to decrease.
  • the controller 140 may execute one or more instructions to continuously or periodically monitor an output gas stream for methane and carbon dioxide content.
  • the goal for the system 100 is to achieve an output of greater than 90% methane and less than 5% carbon dioxide.
  • the sensors 132, 134 may sense methane and carbon dioxide levels using infrared sensors or other devices. Adjusting the water can have several effects on the system. First, if there is too much water, more C0 2 will be produced in the reformer system 1 14B because there is more oxygen that can bond to carbons.
  • the controller 140 may then execute an instruction to decrease the water input to allow less oxygen to be bonded to carbons, resulting in increased CO production, which is easier to convert to methane and water in the methanation reactor 102. Lowering the water flow may increase the reactions available in the methanation reactor 102.
  • the goal of the water system that feeds reformer system 1 14B is always to be at the lowest flow possible while producing the least amount of CO 2 and the most amount of methane.
  • the controller 140 implements two approaches. For example, an excess amount of hydrogen in the output gas composition makes it difficult to measure the composition. In this scenario, decreasing the flow rate from the reformer system 1 14A may be the best result. Further, there also could be hydrocarbon slip coming from the reformer system 1 14B and this would need to be resolved with additional water.
  • the process 320 (Fig. 3B) illustrates various steps executed by the controller 140 to control the system 100 and adjust the output flow.
  • the sensors 132 and 134 may measure the CO 2 and Methane of the gas output by the system 100. If, at step 324, the CO 2 is higher than a set point and the methane is lower than the set point, the controller 140 may execute an instruction to decrease inlet water flow to the reformer system 1 14B at step 326. The controller 140 and sensors 132 and 134 may continue to monitor the output and, at step 328, if the methane does not increase, then the controller 140 may execute an instruction to decrease inlet gas flow to the reformer system 1 14A at step 330.
  • the controller 140 may execute an instruction to decrease inlet water flow to the reformer system 1 14B at step 334.
  • the controller 140 may execute an instruction to decrease inlet gas flow to the reformer system 1 14A at step 338.
  • the controller 140 and sensors 132 and 134 may continue to monitor the output and, at step 328, if the methane does not increase, then the controller 140 may execute an instruction to increase inlet water flow to the reformer system 1 14B at step 342 and also increase inlet gas flow to the reformer system 1 14A at step 344.
  • step 346 the controller 140 may take no action at step 348.
  • the controller 140 may execute a process 350 at step 352 to control inlet water flow to the reformer system 1 14A by accessing a table that is based on the inlet gas flow for the reformer system 1 14B at step 354.
  • the controller 140 may execute a process 370 at step 372 to control each of the burners 1 15A and 1 15B by executing a PID loop to maintain an optimal temperature for the reformer systems 1 14A, 1 14B at step 374.
  • Flare Gas is typically composed of Methane, Ethane, Propane, Butane, Pentane and some Hexane. It may have additional components as well, but these natural gas liquids in the natural gas cause the gas to not be able to be used in generators or put onto the pipeline.
  • Table 1 shows an example composition of flare gas.
  • the resulting gas is typically H2 + 0.5 CO + 0.5 CO 2 , meaning 50% of the carbons become CO and 50% become CO 2 .
  • the next step includes combining this gas flow with a near 100% hydrogen stream from a second steam methane reformer that has had the CO and CO 2 filtered out and putting this combined stream through a methanizer 102.
  • a methanizer 102 may for example be used in gas chromatographs to help in the detection of small concentrations of CO and CO 2 , or as a final purification means on hydrogen generators that are feeding fuel cells, to ensure no CO or CO 2 enters the fuel cell - it converts these to methane and water.
  • the resulting gas has a large concentration of water combined with methane; this water needs to be removed before the methane is usable.
  • Water removal from methane may be performed by various methods including coalescing and membrane filtration, with regenerative desiccant as needed.
  • At least one means of generating syn gas from a varied gas composition combined with at least one means of generating hydrogen from a varied gas composition, combining the syn gas and hydrogen streams and causing this combined stream to enter at least one means for combining syn gas and hydrogen into methane and water.
  • adding a means to remove the water from the methane of various types may be further included.
  • references in this specification to "one embodiment” or “an embodiment” means that a particular feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment of the disclosure.
  • the appearances of the phrase “in one embodiment” in various places in the specification are not necessarily all referring to the same embodiment, nor are separate or alternative embodiments mutually exclusive of other embodiments.
  • various features are described which may be exhibited by some embodiments and not by others.
  • various requirements are described which may be requirements for some embodiments but not for other embodiments.

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  • Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Engineering & Computer Science (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Hydrogen, Water And Hydrids (AREA)

Abstract

Un volume de gaz naturel comprenant un volume de méthane et un volume d'autres alcanes peut être nettoyé des autres alcanes à l'aide d'un système de reformage à la vapeur pour créer un gaz de synthèse. Ce gaz de synthèse peut ensuite être combiné à de l'hydrogène pour produire du méthane et de l'eau.
PCT/US2015/026510 2014-05-27 2015-04-17 Procédé et système de conversion de gaz de torche Ceased WO2015183426A1 (fr)

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US15/362,598 US20170145330A1 (en) 2014-05-27 2016-11-28 Method and system for converting flare gas

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US201462003532P 2014-05-27 2014-05-27
US62/003,532 2014-05-27

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US9777237B2 (en) 2014-11-12 2017-10-03 Element 1 Corp. Refining assemblies and refining methods for rich natural gas
US9828561B2 (en) 2014-11-12 2017-11-28 Element 1 Corp. Refining assemblies and refining methods for rich natural gas
US12138586B2 (en) 2012-08-30 2024-11-12 Element 1 Corp Hydrogen purification devices
US12187612B2 (en) 2021-06-15 2025-01-07 Element 1 Corp Hydrogen generation assemblies

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KR102254409B1 (ko) * 2019-07-22 2021-05-21 필즈엔지니어링 주식회사 플레어 가스를 이용한 수소 생산장치 및 이 장치에 의한 수소 생산방법
WO2023150350A2 (fr) 2022-02-07 2023-08-10 Cummins Power Generation Inc. Système et procédé de production d'hydrogène alimenté par des déchets
WO2023214076A1 (fr) * 2022-05-06 2023-11-09 Michael Stusch Procédé intégré de conversion de gaz de torche en hydrogène avec stockage d'hydrogène et unité intégrée correspondante
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