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WO2024155649A1 - Systèmes et procédés de traitement d'ammoniac pour la production d'énergie à l'aide de turbines à gaz - Google Patents

Systèmes et procédés de traitement d'ammoniac pour la production d'énergie à l'aide de turbines à gaz Download PDF

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Publication number
WO2024155649A1
WO2024155649A1 PCT/US2024/011734 US2024011734W WO2024155649A1 WO 2024155649 A1 WO2024155649 A1 WO 2024155649A1 US 2024011734 W US2024011734 W US 2024011734W WO 2024155649 A1 WO2024155649 A1 WO 2024155649A1
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WO
WIPO (PCT)
Prior art keywords
ammonia
stream
reformate stream
combustion
reformer
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.)
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PCT/US2024/011734
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English (en)
Inventor
Rex Morgan
Scott Macadam
Rishi Gupta
Young Suk Jo
Gregory Robert Johnson
Hyunho Kim
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Amogy Inc
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Amogy Inc
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Publication of WO2024155649A1 publication Critical patent/WO2024155649A1/fr
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    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B21/00—Nitrogen; Compounds thereof
    • C01B21/02—Preparation of nitrogen
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J23/00—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00
    • B01J23/38—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of noble metals
    • B01J23/40—Catalysts comprising metals or metal oxides or hydroxides, not provided for in group B01J21/00 of noble metals of the platinum group metals
    • B01J23/46—Ruthenium, rhodium, osmium or iridium
    • B01J23/462—Ruthenium
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen
    • C01B3/02—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen
    • C01B3/04—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by decomposition of inorganic compounds, e.g. ammonia
    • C01B3/047—Decomposition of ammonia

Definitions

  • SZEFs Scalable zero-emission fuels
  • Hydrogen being a scalable zero-emission fuel (SZEF)
  • SZEF scalable zero-emission fuel
  • Hydrogen can be synthetically produced without carbon emissions, for example, by electrolyzing fresh water using wind and solar energy.
  • Hydrogen can provide advantages over other chemical fuels, such as diesel, gasoline, or jet fuel, which have specific energies of about 45 megajoules per kilogram (heat), as well as over lithium- ion batteries, which have specific energies of about 0.95 mega Joule (MJ) / kilogram (kg) (electrical).
  • hydrogen has a specific energy of over 140 MJ/kg (heat), such that 1 kg of hydrogen can provide the same amount of energy as about 3 kg of gasoline or kerosene.
  • hydrogen reduces the amount of fuel (by mass) needed to provide a comparable amount of energy.
  • systems that consume hydrogen as a fuel generally produce benign or nontoxic byproducts such as water, and minimal or near zero greenhouse gas emissions (e.g., carbon dioxide and nitrous oxide), thereby reducing the environmental impacts of various systems (e.g., modes of transportation) that use hydrogen as a fuel source.
  • benign or nontoxic byproducts such as water, and minimal or near zero greenhouse gas emissions (e.g., carbon dioxide and nitrous oxide)
  • minimal or near zero greenhouse gas emissions e.g., carbon dioxide and nitrous oxide
  • storage of hydrogen may require tanks that can withstand high pressures (e.g., 350-700 bar or 5,000-10,000 psi), and/or may require cryogenic temperatures (since the boiling point of hydrogen at 1 atm of pressure is -252.8 °C).
  • hydrogen storage containers may be constructed using materials that are highly-specialized, costly, and difficult to develop, which may limit the ability to manufacture such hydrogen storage containers at a large scale.
  • Ammonia is a SZEF that can be used as a hydrogen carrier. Since ammonia can be stored at significantly lower pressures (and/or higher temperatures) than hydrogen, ammonia overcomes some of the aforementioned shortcomings of hydrogen, while still providing the advantages hydrogen by the decomposition of the ammonia. Further recognized herein are various limitations of conventional ammonia processing systems, which generally have slow startup times, non-ideal thermal characteristics, suboptimal ammonia conversion efficiencies, and high weight and volume requirements.
  • Embodiments of the present disclosure are directed to ammonia reforming systems and methods.
  • the present ammonia reforming systems and methods address the abovementioned shortcomings of conventional systems for storing and/or releasing hydrogen for utilization as a fuel.
  • the present ammonia reforming systems may generate high electrical power (about 5 kilowatts or greater), provide a high energy density (about 6 5 watt-hour (Wh) / kilogram (kg) or greater by weight and about 447 watt-hour (Wh) / liter (L) or greater by volume), and provide a high power density.
  • the present ammonia reforming systems and methods enable the usage of a gas turbine to combust ammonia and/or hydrogen, for example, by retrofitting a conventional or existing natural gas turbine.
  • a gas turbine By combusting ammonia and/or hydrogen in a gas turbine, carbon-based greenhouse gas emissions may be advantageously reduced.
  • the present ammonia reforming systems and methods may advantageously increase the overall energy efficiency of a gas turbine (by, for example, using catalysts having high ammonia-reforming efficiency at a relatively low temperature and/or finely controlling combustion heaters to accurately maintain the temperature of ammonia reformers).
  • the present ammonia reforming systems and methods may advantageously provide combustion fuel for self-heating (i.e., auto-thermal heating).
  • the ammonia reformers may be heated by the combustion of hydrogen extracted from the ammonia reforming itself, as opposed being heated by combustion of hydrocarbons or ammonia (which undesirably emits greenhouse gases, nitrogen oxides (NO X ), and/or particulate matter).
  • a separate tank may not be required for storing combustion fuel (e.g., hydrocarbons, hydrogen, or ammonia).
  • the present ammonia reforming systems and methods may advantageously provide a high purity reformate stream (e.g., at least about 99.9% H2/N2 mixture by molar fraction, or less than about 10 parts per million (ppm) of ammonia).
  • a high purity reformate stream e.g., at least about 99.9% H2/N2 mixture by molar fraction, or less than about 10 parts per million (ppm) of ammonia.
  • This high purity is achieved by utilizing an ammonia filter (e.g., adsorbents) to remove unconverted or trace ammonia, and by high NH3 conversion efficiency (conferred by the effective design of the reforming reactor, as well as the reforming catalyst).
  • the high purity reformate stream (H2/N2 mixture, or H2 stream) may be consumed by a proton exchange membrane fuel cell (PEMFC) or other power generation device (e.g., internal combustion engine (ICE) or solid oxide fuel cell (SOFC)).
  • PEMFC proton exchange membrane fuel cell
  • ammonia reforming systems and methods may be simple to operate and can provide a high degree of safety.
  • Ammonia can be provided to reformers using a single inlet (e.g., as opposed to a first inlet for a first reformer, a second inlet for a second reformer, and so on).
  • a single stream of ammonia can pass through several reformers (e.g., first passing through a startup reformer, and then into a main reformer, or vice versa).
  • This configuration can facilitate heat transfer from the reformers to the incoming ammonia stream (to vaporize the incoming ammonia stream) and can increase the overall ammonia conversion efficiency (i.e., by fully reforming the ammonia stream).
  • the ammonia flow rate can be controlled at the single inlet, and in the case of a major fault or dangerous event, the ammonia flow can be quickly shut off via the single inlet.
  • the present disclosure is directed to a method for reforming ammonia (NH3), comprising: (a) powering an electrical heater to heat a reformer from a first temperature to a second temperature, wherein the second temperature is in a target temperature range that is greater than about 200 °C and less than about 650 °C; (b) decomposing the ammonia in the reformer to generate a reformate stream comprising hydrogen and nitrogen; (c) combusting the reformate stream in a combustor of a gas turbine using oxygen at an oxygen flow rate; and (d) using heat from a combustion exhaust of the gas turbine to maintain the reformer in the target temperature range.
  • NH3 ammonia
  • the method further comprises decreasing power of the electrical heater.
  • the method further comprises measuring a temperature in the reformer; and based at least in part on the measured temperature being outside of the target temperature range, changing power of the electrical heater to maintain the reformer at the target temperature range. [0018] In some embodiments, the method further comprises using the heat of the combustion exhaust of the gas turbine to heat the ammonia before the ammonia enters the reformer to a temperature that is greater than about 25 °C and less than about 650 °C.
  • heating the ammonia evaporates at least a portion of the ammonia before the ammonia enters the reformer.
  • the method further comprises, before decomposing the ammonia, pressurizing the ammonia to greater than about 5 barg and less than about 50 barg.
  • the method further comprises before combusting the reformate stream, pressurizing the reformate stream to greater than about 10 barg and less than about 300 barg.
  • the ammonia is decomposed at an ammonia conversion efficiency of greater than about 5% and less than about 99%.
  • the method further comprises combusting ammonia and the reformate stream in the combustor of the gas turbine.
  • the method comprises controlling a molar ratio of the ammonia to the hydrogen in the reformate stream for the combustion of the ammonia and the reformate stream. [0025] In some embodiments, the molar ratio is controlled to be about 1 : 10 to about 10:1.
  • the molar ratio is controlled by adjusting an ammonia conversion efficiency of the decomposition of the ammonia.
  • the molar ratio is controlled by adjusting amounts of the ammonia and the reformate stream in a premixing chamber.
  • the method further comprises, before combusting the reformate stream in the combustor, combusting natural gas in the combustor.
  • the method further comprises, blending the reformate stream with natural gas to form a blended gas, and combusting the blended gas in the combustor.
  • the reformer is heated from the first temperature to the second temperature in less than about 60 minutes.
  • a time period between (1) starting to heat the reformer and (2) starting to combust the reformate stream in the gas turbine is less than about 60 minutes.
  • the method further comprises injecting water into the combustor of the gas turbine to reduce a flame temperature and/or increase a heat transfer coefficient.
  • the method further comprises storing auxiliary hydrogen in a hydrogen storage tank. [0034] In some embodiments, the method further comprises combusting the auxiliary hydrogen in the combustor of the gas turbine.
  • the method further comprises generating the auxiliary hydrogen using the reformate stream.
  • the method further comprises generating the auxiliary hydrogen using an electrolyzer.
  • the method further comprises generating auxiliary oxygen using the electrolyzer.
  • the method further comprises storing the auxiliary oxygen in an oxygen storage tank.
  • the method further comprises combusting the auxiliary oxygen in the combustor of the gas turbine.
  • the method further comprises removing or reducing residual NOx from the combustion exhaust of the gas turbine using a selective catalytic reduction (SCR) catalyst, wherein the residual NOx comprises nitrogen oxide (NO) or nitrogen dioxide (NO2).
  • SCR selective catalytic reduction
  • the method further comprises removing or reducing residual NH3 from the combustion exhaust of the gas turbine using a selective ammonia oxidation (SAO) catalyst.
  • the method further comprises removing or reducing residual NH3 from the reformate stream using a selective ammonia oxidation (SAO) catalyst.
  • the ammonia is decomposed at an ammonia conversion efficiency of greater than about 95%.
  • the method comprises, before (c), removing or reducing residual ammonia in the reformate stream using an ammonia filter.
  • the method comprises directing the combustion exhaust of the gas turbine to the ammonia filter to desorb the residual ammonia from the ammonia filter, thereby regenerating the ammonia filter.
  • the method further comprises using the heat of the combustion exhaust of the gas turbine to generate steam to drive a steam turbine.
  • the ammonia is decomposed by contacting the ammonia with a catalyst, wherein the catalyst comprises: a support comprising alumina (AI2O3) doped with lanthanum (La), cerium (Ce), and/or cesium (Cs); and an active metal comprising ruthenium (Ru) adjacent to the support.
  • the ammonia is decomposed by contacting the ammonia with a catalyst, wherein the catalyst comprises: a support comprising zirconia (ZrCh) doped with cerium (Ce) and/or potassium (K); and an active metal comprising ruthenium (Ru) adjacent to the support.
  • the ammonia is decomposed by contacting the ammonia with a catalyst, wherein the catalyst comprises: a support comprising alumina (AI2O3); and an active metal comprising ruthenium (Ru) adjacent to the support.
  • a catalyst comprises: a support comprising alumina (AI2O3); and an active metal comprising ruthenium (Ru) adjacent to the support.
  • the ammonia is decomposed by contacting the ammonia with a catalyst, wherein the catalyst comprises at least: an active metal comprising cobalt (Co), molybdenum (Mo), and X, wherein X comprises Ni, Fe, Cr, Cu, Mn, or Zn.
  • a catalyst comprises at least: an active metal comprising cobalt (Co), molybdenum (Mo), and X, wherein X comprises Ni, Fe, Cr, Cu, Mn, or Zn.
  • the present disclosure is directed to a method for reforming ammonia (NH3), comprising: (a) decomposing the ammonia at an ammonia flow rate in a reformer to generate a reformate stream comprising hydrogen and nitrogen, wherein a target temperature range of the reformer is greater than about 200 °C and less than about 650 °C; (b) optionally combusting a first portion of the reformate stream in a combustion heater to heat the reformer using oxygen at a first oxygen flow rate; (c) combusting a second portion of the reformate stream in a combustor of a gas turbine using oxygen at a second oxygen flow rate; and (d) maintaining the reformer at the target temperature range using, at least in part, heat from a combustion exhaust of the gas turbine.
  • a target temperature range of the reformer is greater than about 200 °C and less than about 650 °C
  • the method comprises combusting the first portion of the reformate stream in the combustion heater to heat the reformer.
  • the method comprises performing one or more of: changing the ammonia flow rate, changing the first oxygen flow rate, or changing the first portion of the reformate stream.
  • the method further comprises: measuring a temperature in the reformer; and based at least in part on the measured temperature being outside of the target temperature range, performing one or more of: changing the ammonia flow rate, changing the first oxygen flow rate, changing a percentage of the reformate stream that is the first portion of the reformate stream, changing a percentage of the reformate stream that is the second portion of the reformate stream, or changing a percentage of the reformate stream that is directed out of the combustion heater.
  • the method further comprises, based on an increased amount of the hydrogen combusted in the combustor of the gas turbine, performing one or more of: increasing the ammonia flow rate; increasing the first oxygen flow rate; increasing the second oxygen flow rate; increasing the percentage of the reformate stream that is the first portion of the reformate stream; or increasing the percentage of the reformate stream that is the second portion of the reformate stream.
  • the method further comprises, based on a decreased amount of the hydrogen combusted in the combustor of the gas turbine, performing one or more of decreasing the ammonia flow rate; decreasing the first oxygen flow rate; decreasing the second oxygen flow rate; decreasing the percentage of the reformate stream that is the first portion of the reformate stream; or decreasing the percentage of the reformate stream that is the second portion of the reformate stream.
  • the reformer comprises a first reformer and a second reformer.
  • the first portion of the reformate stream is generated by the first reformer.
  • (b) heats the second reformer.
  • the first portion of the reformate stream is generated by the second reformer.
  • the reformate stream generated by the first reformer is further reformed in the second reformer.
  • the reformate stream is directed from the second reformer to the first reformer, so that the reformate stream is further reformed in the first reformer.
  • the ammonia is directed to the first reformer before being directed to the second reformer.
  • an amount of ammonia directed to the second reformer is increased after the second reformer is heated to the target temperature range.
  • the amount of ammonia directed to the second reformer is increased to a first target ammonia flow rate range.
  • the second portion of the reformate stream is directed to the gas turbine when the first target ammonia flow rate range is reached.
  • the ammonia flow rate is subsequently increased to a second target ammonia flow rate range when the first target ammonia flow rate range is reached.
  • the method comprises powering an electrical heater to heat the first reformer from a first temperature to a second temperature, wherein the second temperature is in the target temperature range.
  • the method further comprises decreasing power of the electrical heater.
  • the method further comprises measuring a temperature in the first reformer; and based at least in part on the measured temperature being outside of the target temperature range, changing power of the electrical heater to maintain the first reformer at the target temperature range.
  • the electrical heater comprises a resistive heater.
  • the electrical heater comprises an induction heater.
  • the method comprises powering an electrical heater to heat the reformer from a first temperature to a second temperature, wherein the second temperature is in the target temperature range.
  • the method further comprises decreasing power of the electrical heater.
  • the method further comprises measuring a temperature in the reformer; and based at least in part on the measured temperature being outside of the second temperature, changing power of the electrical heater to maintain the reformer at the second temperature.
  • the electrical heater comprises a resistive heater.
  • the electrical heater comprises an induction heater.
  • a pressure of the reformate stream is reduced when the reformate stream is directed to the gas turbine compared to when the reformate stream is not directed to the gas turbine.
  • a threshold amount of the reformate stream being directed to the gas turbine results in substantially all of the reformate stream being directed to the gas turbine.
  • the present disclosure is directed to a method for reforming ammonia (NH3), comprising: decomposing ammonia in a reformer to generate a reformate stream comprising hydrogen and nitrogen; combusting the reformate stream in a combustor for a gas turbine; transferring heat from a combustion exhaust of the gas turbine to a boiler to heat a working fluid; and using the working fluid to drive a turbine.
  • NH3 ammonia
  • the working fluid is water.
  • the working fluid is an organic fluid.
  • the method further comprises transferring the heat from the combustion exhaust to the reformer.
  • the heat is transferred from the combustion exhaust to the reformer after (b).
  • the heat is transferred from the combustion exhaust to the reformer after (c).
  • the heat is transferred from the working fluid to the reformer.
  • the combustion exhaust is divided into a first stream and a second stream.
  • the first stream transfers the heat to the boiler to heat the working fluid.
  • the second stream transfers the heat to the reformer.
  • the method further comprises transferring heat from the boiler to the reformer.
  • the turbine comprises a plurality of stages, wherein at least one stage in the plurality of stages operates at a different pressure than another stage of the plurality of stages.
  • the reformer is in thermal communication with at least one stage of the plurality of stages.
  • the working fluid transfers heat from at least one stage of the plurality of stages to the reformer.
  • the present disclosure is directed to a method for reforming ammonia (NH3), comprising: (a) partially oxidizing ammonia to generate heat; (b) decomposing the ammonia using the heat to generate a reformate stream comprising hydrogen and nitrogen; (c) combusting the reformate stream to generate combustion exhaust; and (d) using the combustion exhaust to drive a gas turbine.
  • NH3 ammonia
  • (a) and (b) are performed in the same vessel.
  • (a), (b), and (c) are performed in the same vessel.
  • (a) and (b) are performed in a first chamber, and (c) is performed in a second chamber.
  • the present disclosure is directed to a method for reforming ammonia (NH3), comprising: transferring heat from a combustion exhaust of a gas turbine to a prereformer; decomposing ammonia at least partially using the prereformer to generate a reformate stream comprising hydrogen, nitrogen, and unconverted ammonia; decomposing the unconverted ammonia in the reformate stream using a reformer to generate additional hydrogen and nitrogen for the reformate stream; combusting the reformate stream to generate additional combustion exhaust; and driving a gas turbine using the additional combustion exhaust.
  • NH3 ammonia
  • a portion of the hydrogen generated by the prereformer, the reformer, or a combination thereof is combusted to heat the reformer.
  • the portion of the hydrogen generated by the prereformer, the reformer, or a combination thereof is combusted to heat the reformer after (c).
  • the present disclosure is directed to a method for reforming ammonia (NH3), comprising: (a) compressing air using a compressor; transferring heat from the air to a reformer; (b) decomposing ammonia in the reformer to generate a reformate stream comprising hydrogen and nitrogen; and (c) combusting the reformate stream in a combustor for a gas turbine.
  • the method further comprises transferring heat from the gas turbine to the air to cool the gas turbine.
  • the heat is transferred from the gas turbine to the air after (b).
  • the reformer is within a target temperature range that is greater than about 200 °C and less than about 800 °C.
  • the air is provided to the combustor.
  • the air is provided to the combustor after (b).
  • the present disclosure is directed to a method for reforming ammonia (NH3), comprising: transferring heat from a combustion exhaust of a gas turbine to a reformer, thereby cooling the combustion exhaust; and transferring heat from the gas turbine to the combustion exhaust to cool the gas turbine.
  • NH3 ammonia
  • the method further comprises decomposing ammonia in the reformer to generate a reformate stream comprising hydrogen and nitrogen.
  • the method further comprises combusting the reformate stream in a combustor for a gas turbine.
  • FIGS. 1A-4B are block diagrams illustrating an ammonia reforming system, in accordance with one or more embodiments of the present disclosure.
  • FIGS. 5A-5I are block diagrams illustrating utilization of a controller and sensors to control the ammonia reforming system shown in FIGS. 1A-4B, in accordance with one or more embodiments of the present disclosure.
  • FIGS. 6A-6T are block diagrams illustrating additional or alternative components and processes of the ammonia reforming system shown in FIGS. 1A-4B, in accordance with one or more embodiments of the present disclosure.
  • FIGS. 7-11C are flow charts illustrating startup processes for an ammonia reforming method, in accordance with one or more embodiments of the present disclosure.
  • FIGS. 12A-12B are flow charts illustrating post-startup processes for an ammonia reforming method, in accordance with one or more embodiments of the present disclosure.
  • FIG. 13 is a schematic diagram illustrating utilization of an oxidation-resistant catalyst to generate reformate to purge the ammonia reforming system shown in FIGS. 1A-4B, in accordance with one or more embodiments of the present disclosure.
  • FIG. 14 is a schematic diagram illustrating a system combining ammonia synthesis and ammonia reforming, in accordance with one or more embodiments of the present disclosure.
  • FIG. 15A is a schematic diagram illustrating a multi-stage ammonia filter, in accordance with one or more embodiments of the present disclosure.
  • FIG. 15B is a plot illustrating performance calculation data of the multi-stage ammonia filter shown in FIG. 15A, in accordance with one or more embodiments of the present disclosure.
  • FIGS. 16A-16F are block diagrams illustrating various recovery modules configured to recover waste heat and separation modules configured to separate hydrogen, nitrogen, oxygen, or water, in accordance with one or more embodiments of the present disclosure.
  • FIGS. 17A-17N are schematic diagrams illustrating various ammonia decomposition systems including a gas turbine, in accordance with one or more embodiments of the present disclosure.
  • FIG. 18 is a block diagram illustrating a computer system that is programmed or otherwise configured to implement methods and systems provided herein.
  • a and B may be construed to mean at least A, at least B, or at least A and B (i.e., a set comprising A and B, which set may include one or more additional elements).
  • a and/or B may be construed to mean only A, only B, or both A and B.
  • the expressions “at least about A, B, and C” and “at least about A, B, or C” may be construed to mean at least about A, at least about B, or at least about C.
  • the expressions “at most about A, B, and C” and “at most about A, B, or C” may be construed to mean at most about A, at most about B, or at most about C.
  • the expression "about A, B, or C” may be construed to mean about A, about B, or about C.
  • the expression “between about A and B, C and D, and E and F” may be construed to mean between about A and about B, between about C and about D, and between about E and about F.
  • the expression “between about A and B, C and D, or E and F” may be construed to mean between about A and about B, between about C and about D, or between about E and about F.
  • module and “unit” are used interchangeably and are not limited to a single component, piece, part, or individual unit.
  • ammonia conversion may be construed as a fraction of ammonia that is converted to hydrogen and nitrogen, and may be construed interchangeably.
  • an ammonia conversion efficiency of 90% may represent 90% of ammonia being converted to hydrogen and nitrogen.
  • auto-thermal reforming may be construed as a condition where an ammonia decomposition reaction (2NHs — > ⁇ N2 + 3H2; an endothermic reaction) is heated by a hydrogen combustion reaction (2H2 + O2 — > 2H2O; an exothermic reaction) using at least part of the hydrogen produced by the ammonia decomposition reaction itself.
  • auto-thermal reforming may be construed as a condition where an ammonia decomposition reaction is heated by a hydrogen combustion reaction using at least part of hydrogen produced by the ammonia decomposition reaction itself, electrical heating, or a combination of both (which may result in an overall positive electrical and/or chemical energy output).
  • the hydrogen produced from the ammonia decomposition reaction may be enough to provide the hydrogen combustion reaction with combustion fuel, and/or to provide electrical energy for the electrical heating via hydrogen-to-electricity conversion devices (e.g., fuel cell, combustion engine, etc.).
  • the hydrogen provided for the hydrogen combustion reaction and/or the electrical heating may or may not use the hydrogen from the ammonia decomposition reaction (for example, the hydrogen may be provided by a separate hydrogen source, the electricity may be provided from batteries or a grid, etc.).
  • auto-thermal reforming may be construed as a condition where an ammonia decomposition reaction is heated by a combustion reaction (e.g., ammonia combustion, hydrocarbon combustion, etc ), electrical heating, or a combination of both, which may result in an overall positive electrical and/or chemical energy output.
  • a combustion reaction e.g., ammonia combustion, hydrocarbon combustion, etc
  • electrical heating or a combination of both, which may result in an overall positive electrical and/or chemical energy output.
  • the chemical energy (e.g., lower heating value) from the hydrogen produced from the ammonia decomposition reaction may be higher than the combustion fuel chemical energy (e.g., lower heating value), and/or may be enough to provide electrical energy for the electrical heating via hydrogen-to-electricity conversion devices (e.g., fuel cell, combustion engine, etc.).
  • a startup mode may be construed as a process in which an ammonia reforming system is initiating an operation (e.g., heating up one or more reformers to a target temperature range).
  • an operation mode may be construed as a process in which the ammonia reforming system is generating an electrical power output (using one or more fuel cells) or generating a hydrogen output (for various chemical or industrial processes) while maintaining autothermal reforming.
  • a hot standby mode may be construed as a process in which autothermal reforming of the ammonia reforming system is maintained while the power output (using the one or more fuel cells) and/or the hydrogen output (supplied to various chemical or industrial processes) are reduced (e.g., to zero, or to an amount that is substantially less than the operation mode).
  • FIGS. 1A-4B are block diagrams illustrating an ammonia reforming system 100, in accordance with one or more embodiments of the present disclosure.
  • the ammonia reforming system 100 comprises an NH3 storage tank 102, a heat exchanger 106, one or more combustion-heated reformers 108, a combustion heater 109, one or more electrically-heated reformers 110, an electric heater 111, an air supply unit 116, an ammonia filter 122, and a fuel cell 124.
  • the NH3 storage tank 102 can be configured to store NH3 under pressure (e.g., 7-9 bars absolute) and/or at a low temperature (e.g., -30 °C).
  • the NH3 storage tank 102 can comprise a metallic material that is resistant to corrosion by ammonia (e.g., steel).
  • the storage tank 102 can comprise one or more insulating layers (e.g., perlite or glass wool).
  • an additional heater can be positioned near, adjacent, at, or inside the NH3 storage tank 102 to heat and/or pressurize the NH3 stored therein.
  • the heat exchanger 106 can be configured to exchange heat between various input fluid streams and output fluid streams.
  • the heat exchanger 106 can be configured to exchange heat between an incoming ammonia stream 104 provided by the storage tank 102 (e.g., relatively cold liquid ammonia) and a reformate stream 120 (e.g., a relatively warm H2/N2 mixture) provided by the reformers 108 and 110.
  • the heat exchanger 106 can be a plate heat exchanger, a shell-and-tube heat exchanger, or a tube-in-tube heat exchanger, although the present disclosure is not limited thereto.
  • the reformers 108 and 110 can be configured to generate and output the reformate stream 120 comprising at least a mixture of hydrogen (H2) and nitrogen (N2) (with a molar ratio of H2 to N2 of about 3: 1 at a high ammonia conversion).
  • the H2/N2 mixture may be generated by contacting the incoming ammonia stream 104 with NH3 reforming catalyst 130 positioned inside each of the reformers 108 and 110.
  • the reformers 108 and 110 can be heated to a sufficient temperature range to facilitate ammonia reforming (for example, of from about 400 °C to about 650 °C).
  • the reformers 108 and 110 can comprise a plurality of reformers, which may fluidically communicate in various series and/or parallel arrangements.
  • an electrically-heated reformer 110 may fluidically communicate in series or in parallel with a combustion-heated reformer 108 (or vice versa) as a pair of reformers 108-110.
  • Such a pair of reformers 108-110 may fluidically communicate in parallel with other reformer 108-110 or pairs of reformers 108-110 (so that pairs of reformers 108-110 combine their outputs into a single reformate stream 120), or may fluidically communicate in series with other reformers 108-110 or pairs of reformers 108-110.
  • the number of combustion-heated reformers 108 can be the same as the number of electrically-heated reformers 110, and the reformers 108-110 may fluidically communicate in various series and/or parallel arrangements.
  • two electrically-heated reformers 110 may fluidically communicate in series with two combustion -heated reformers 108 (or vice versa).
  • the number of combustion-heated reformers 108 can be different from the number of electrically-heated reformers 110 and the reformers 108-110 may fluidically communicate in various series and/or parallel arrangements.
  • two electrically- heated reformers 110 may fluidically communicate in series with four combustion-heated reformers 108 (or vice versa).
  • the combustion heater 109 can be in thermal communication with the combustion- heated reformer 108 to heat the NH3 reforming catalyst 130 in the reformer 108.
  • the combustion heater 109 can react at least part of the reformate stream 120 (e.g., the H2 in the H2/N2 mixture) with an air stream 118 (e.g., at least oxygen (O2)).
  • the heat from the exothermic combustion reaction in the combustion heater 109 can be transferred to the NH3 reforming catalyst 130 in the reformer 108.
  • the hot combustion product gas 114 can contact walls of the reformer 108, and the hot combustion product gas 114 can be subsequently output from the combustion heater 109 as combustion exhaust 114.
  • the combustion heater 109 can comprise a separate component from the reformer 108 (and may be slidably insertable or removable in the reformer 108). In some cases, the combustion heater 109 is a unitary structure with the combustion-heated reformer 108 (and both the reformer 108 and the heater 109 can be manufactured via 3D printing and/or casting).
  • the air supply unit 116 e.g., one or more pumps and/or compressors
  • the air stream 118 can comprise pure oxygen by molar fraction, or substantially pure oxygen by molar fraction (e.g., at least about 99% pure oxygen).
  • the electric heater 111 can be in thermal communication with the electrically-heated reformer 110 to heat the NH3 reforming catalyst 130 in the reformer 110.
  • the electric heater 111 can heat the NH3 reforming catalyst 130 in the electrically-heated reformer 110 by resistive heating or Joule heating.
  • the electrical heater 111 can comprise at least a heating element (e.g., nichrome or ceramic) that transfers heat to the catalyst 130 in the electrically-heated reformer 110.
  • the electrical heater 111 can comprise metal electrodes (e.g., copper or steel electrodes) that pass a current through the catalyst 130 to heat the catalyst 130 in the reformer 110.
  • the ammonia filter 122 can be configured to filter or remove trace ammonia in the reformate stream 120.
  • the ammonia filter 122 can be configured to reduce the concentration of NH3 in the reformate stream 120, for example, from greater than about 10,000 parts per million (ppm) to less than about 100 ppm.
  • the ammonia filter 122 can comprise a fluidized bed comprising a plurality of particles or pellets.
  • the ammonia filter 122 can be cartridge-based (for simple replaceability, for example, after the ammonia filter 122 is saturated with ammonia).
  • the ammonia filter 122 can comprise an adsorbent (e.g., bentonite, zeolite, clay, biochar, activated carbon, silica gel, metal organic frameworks (MOFs), and other nanostructured materials).
  • the adsorbent can comprise pellets and can be stored in one or more columns or towers.
  • the ammonia filter 122 can comprise an absorbent, a solvent-based material, and/or a chemical solvent.
  • the ammonia filter 122 comprises a multi-stage ammonia filtration system (e.g., water-based) comprising a plurality of filtration stages.
  • a multi-stage ammonia filtration system e.g., water-based
  • the replacement of water-based absorbents can be performed for continuous operation.
  • the multi-stage ammonia filter is described in detail with respect to FIGS. 15A-15B.
  • the ammonia filter 122 comprises a selective ammonia oxidation (SAG) reactor comprising oxidation catalysts configured to react the trace ammonia in the reformate stream 120 with oxygen (O2) to generate nitrogen (N2) and water (H2O).
  • SAG selective ammonia oxidation
  • the air stream 118 (or a separate oxygen source) can be provided to the SAG reactor to provide the oxygen for the oxidation reaction.
  • the ammonia filter 122 can comprise an acidic ammonia remover (for example, in addition to adsorbents), which can comprise an acidic solid or solution.
  • the acidic ammonia remover can be regenerated (to desorb the ammonia captured therein) by passing an electric current through the acidic ammonia remover.
  • the fuel cell 124 can comprise an anode, a cathode, and an electrolyte between the anode and the cathode.
  • the fuel cell 124 can comprise a polymer electrolyte membrane fuel cell (PEMFC), a solid oxide fuel cell (SOFC), a molten carbonate fuel cell (MCFC), a phosphoric acid fuel cell (PAFC), or an alkaline fuel cell (AFC), although the present disclosure is not limited thereto.
  • PEMFC polymer electrolyte membrane fuel cell
  • SOFC solid oxide fuel cell
  • MCFC molten carbonate fuel cell
  • PAFC phosphoric acid fuel cell
  • AFC alkaline fuel cell
  • the fuel cell 124 can be configured to receive hydrogen (e.g., at least part of the reformate stream 120) via one or more anode inlets, and oxygen (e.g., at least part of the air stream 118 or a separate air stream) via one or more cathode inlets.
  • hydrogen e.g., at least part of the reformate stream 120
  • oxygen e.g., at least part of the air stream 118 or a separate air stream
  • the fuel cell 124 can output unconsumed hydrogen (e.g., as an anode off-gas) via one or more anode outlets, and/or can output unconsumed oxygen (e.g., as a cathode off-gas) via one or more cathode outlets.
  • unconsumed hydrogen e.g., as an anode off-gas
  • unconsumed oxygen e.g., as a cathode off-gas
  • the anode off-gas and/or the cathode off-gas can be provided to the combustion heater 109 as reactants for the combustion reaction performed therein.
  • the storage tank 102 can be in fluid communication with the combustion-heated reformer 108 and/or the electrically-heated reformer 110 (e.g., using one or more lines or conduits).
  • the storage tank 102 can provide the incoming ammonia stream 104 (for example, by actuating a valve).
  • the heat exchanger 106 can facilitate heat transfer from the (relatively warmer) reformate stream 120 to the (relatively cooler) incoming ammonia stream 104 to preheat and/or vaporize the incoming ammonia stream 104 (changing the phase of the ammonia stream 104 from liquid to gas).
  • the incoming ammonia stream 104 can enter the reformers 108 and 110 to be reformed into hydrogen and nitrogen.
  • the incoming ammonia stream 104 can be partially reformed by the electrically-heated reformer 110 into a partially cracked reformate stream 120 (e.g., comprising at least about 10% H2/N2 mixture by molar fraction) (for example, during a start-up or initiation process).
  • the partially cracked reformate stream 120 can be further reformed in the combustion- heated reformer 108 to generate a substantially cracked reformate stream (e.g., comprising less than about 10,000 ppm of residual or trace ammonia by volume and/or greater than about 99% H2/N2 mixture by molar fraction).
  • Passing the ammonia stream 104 through the electrically-heated reformer 110 first, and then subsequently passing the ammonia stream 104 through the combustion-heated reformer 108, can advantageously result in more complete ammonia conversion (e.g., greater than about 99%).
  • the incoming ammonia stream 104 can be partially reformed by the combustion-heated reformer 108 into a partially cracked reformate stream 120 (e g., comprising at least about 10% H2/N2 mixture by molar fraction). Subsequently, the partially cracked reformate stream 120 can be further reformed in the electrically-heated reformer 110 to generate a substantially cracked reformate stream (e.g., comprising less than about 10,000 ppm of residual or trace ammonia by volume and/or greater than about 99% H2/N2 mixture by molar fraction).
  • a substantially cracked reformate stream e.g., comprising less than about 10,000 ppm of residual or trace ammonia by volume and/or greater than about 99% H2/N2 mixture by molar fraction.
  • Passing the ammonia stream 104 through the combustion-heated reformer 108 first, and then subsequently passing the ammonia stream 104 through the electrically-heated reformer 110, can advantageously result in more complete ammonia conversion (e.g., greater than about 99%).
  • the incoming ammonia stream 104 can be preheated by the combustion exhaust 114 and/or the combustion heater 109. In some cases, the preheated incoming ammonia stream 104 can enter the reformers 108 and 110 to be reformed into hydrogen and nitrogen.
  • the incoming ammonia stream 104 can be reformed by the electrically-heated reformer 110 to generate a partially or substantially cracked reformate stream 120 (for example, during a start-up or initiation process). Subsequently, at least part of the partially or substantially cracked reformate stream 120 generated by the electrically-heated reformer 110 can be combusted as a combustion fuel to heat at least one combustion heater 109 of the one or more combustion-heated reformers 108.
  • the electrically-heated reformer 110 can be configured to preheat or vaporize the incoming ammonia stream 104 (to avoid reforming liquid ammonia). In some cases, the electrically-heated reformer 110 can reform or crack the incoming ammonia stream 104 at an ammonia conversion efficiency of at least about 10, 15, 20, 25, 30, 35, 40, 45, 50, 55, 60, 65, 70, 75, 80, 85, 90, 95, 99, or 99.5%.
  • the electrically-heated reformer 110 can reform or crack the incoming ammonia stream 104 at an ammonia conversion efficiency of at most about 10, 15, 20, 25, 30, 35, 40, 45, 50, 55, 60, 65, 70, 75, 80, 85, 90, 95, 99, or 99.5%. In some cases, the electrically-heated reformer 110 can reform or crack the incoming ammonia stream 104 at an ammonia conversion efficiency of about 10 to about 30, about 20 to about 40, about 30 to about 50, about 40 to about 60, about 50 to about 70, about 60 to about 80, about 70 to about 90, about 80 to about 99%, or about 90 to about 99.5%.
  • power input to the electric heater 111 of the electrically-heated reformer 110 can be reduced or entirely turned off based on a temperature of the combustion-heated reformer 108 and/or the combustion heater 109 being equal to or greater than a target temperature (e.g., in a target temperature range). In some cases, power input to the electric heater 111 of the electrically- heated reformer 110 can be reduced or entirely turned off based on a flow rate of the incoming ammonia stream 104 being equal to or greater than a target flow rate range.
  • power input to the electric heater 111 of the electrically-heated reformer 110 can be turned on or increased during an entire operational time period of the ammonia reforming system 100 (e.g., during the startup mode, the operation mode, and/or the hot standby mode described in the present disclosure). In some cases, power input to the electric heater 111 of the electrically-heated reformer 110 can be turned on or off, or increased intermittently during the operational time period of the ammonia reforming system 100 (e.g., turned on or increased during the startup mode and/or the hot standby mode, and turned off or decreased during the operation mode).
  • power input to the electric heater 111 can be controlled so that the temperature of the electrically-heated reformer 110 and/or the electrical heater 111 increases or decreases at a target temperature change rate (ATemperature/ATime, e.g., °C/minute).
  • the target temperature change rate is at least about 5, 10, 20, 25, 30, 35, 40, 45, 50, 60, 65, 70, 75, 80, 85, 90, 95, or 100 °C/minute.
  • the target temperature change rate is at most about 5, 10, 20, 25, 30, 35, 40, 45, 50, 60, 65, 70, 75, 80, 85, 90, 95, or 100 °C/minute.
  • the ammonia filter 122 can be configured to remove trace ammonia in the reformate stream 120 and output a filtered reformate stream 123.
  • the filtered reformate stream 123 can be provided to the combustion heater 109 to combust for heating the reformer 108 (i.e., by auto-thermal reforming).
  • the filtered reformate stream 123 can be provided to the fuel cell 124 to generate electrical power 126.
  • An external load e.g., an electrical motor to power a transport vehicle, or a stationary electrical grid
  • the fuel cell 124 can provide the anode off-gas 128 (e.g., containing unconsumed or unconverted hydrogen) to the combustion heater 109 to combust for self-heating.
  • the ammonia reforming system 100 comprises a battery (so that the system 100 is a hybrid fuel cell-battery system).
  • the battery can be configured to power an external load in addition to the fuel cell 124.
  • the fuel cell 124 can be configured to charge the battery (for example, based a charge of the battery being less than a threshold charge).
  • a pressure swing adsorber (PSA) 127 can be configured to adsorb NH3 and/or N2 in the filtered reformate stream 123 (or the reformate stream 120) to further purify the filtered reformate stream 123.
  • the PSA can be configured to increase the molar fraction of H2 in the filtered reformate stream 123 (or the reformate stream 120) and decrease the molar fractions of NH3 and/or N2 in the filtered reformate stream 123 (or the reformate stream 120).
  • a PSA exhaust stream 128b comprising H2 (and which can additionally comprise NH3 and/or N2) can be provided to the combustion heater 109 to combust for self-heating the reformer 108 (i.e., by auto-thermal reforming). Additionally, a purified reformate stream 129 can be provided to the fuel cell 124 to generate the electrical power output 126.
  • a flow distributor 115 can be configured to distribute at least portion 128c of the reformate stream 120 (or the filtered reformate stream 123) to the combustion heater 109 as a combustion fuel.
  • the flow distributor 130 can comprise, for example, one or more flow control units (e.g., one or more valves, one or more pumps, one or more flow regulators, etc.).
  • a remaining reformate stream 117 can be provided to various chemical or industrial processes, including, but not limited to, steel or iron processing, combustion engines, combustion turbines, hydrogen storage, hydrogen for chemical processes, hydrogen fueling stations, etc. In some cases, the remaining reformate stream 117 can be supplied as a pilot, auxiliary, or main fuel to the combustion engines or combustion turbines.
  • the reformate stream 120, the filtered reformate stream 123, the purified reformate stream 129, and/or the remaining reformate stream 117 can be provided to an internal combustion engine (ICE). Heat emitted by the ICE can be used to heat the reformer 108 and/or the reformer 110 (e.g., using a heat exchanger).
  • ICE internal combustion engine
  • the reformate stream 120, the filtered reformate stream 123, the purified reformate stream 129, and/or the remaining reformate stream 117 can be used directly for chemical or industrial processes (e.g., to reduce iron), storage (e.g., hydrogen storage), and/or hydrogen fueling stations.
  • the fuel cell 124 can be absent, and at least part of the reformate 120 can be combusted to maintain an auto-thermal reforming process.
  • the remaining reformate 120 (that is not combusted) can be provided for chemical or industrial processes, storage (e.g., hydrogen storage), and/or hydrogen fueling stations.
  • the remaining reformate stream 120 is provided to an ICE.
  • heat emitted by the ICE can provide at least part or all of the heat required for ammonia reforming in the reformer 108 and/or the reformer 110.
  • Any of the embodiments, configurations and/or components described with respect to FIGS. 1A-4B can be partially or entirely powered by exhaust heat from a combustion engine.
  • FIGS. 5A-5I are block diagrams illustrating utilization of a controller 200 (e.g., computer or computing device), sensors Pl -P10, Tl-Tl l, FM1-FM11, AC 1 -AC 10, HC1-HC5 and flow control units FCU1-FCU11 to control the ammonia reforming system 100 shown in FIGS. 1A- 4B, in accordance with one or more embodiments of the present disclosure.
  • a controller 200 e.g., computer or computing device
  • sensors Pl -P10 e.g., computer or computing device
  • Tl-Tl l e.g., FM1-FM11
  • AC 1 -AC 10 e.g., AC 1 -AC 10
  • HC1-HC5 e.g., HC1-HC5
  • flow control units FCU1-FCU11 e.g., flow control units
  • the controller 200 can comprise one or more processors 202 and a memory 204.
  • the one or more processors 202 can comprise one or more processing or logic elements (e.g., one or more micro-processor devices, one or more central processing units (CPUs), one or more graphics processing units (GPUs), one or more application specific integrated circuit (ASIC) devices, one or more field programmable gate arrays (FPGAs), or one or more digital signal processors (DSPs)), and can be configured to execute, perform or implement algorithms, modules, processes and/or instructions (e.g., program instructions stored in memory).
  • processing or logic elements e.g., one or more micro-processor devices, one or more central processing units (CPUs), one or more graphics processing units (GPUs), one or more application specific integrated circuit (ASIC) devices, one or more field programmable gate arrays (FPGAs), or one or more digital signal processors (DSPs)
  • CPUs central processing units
  • GPUs graphics processing units
  • ASIC application specific integrated circuit
  • the one or more processors 202 can be embodied in an embedded system (for example, as part of a terrestrial vehicle, an aerial vehicle, a marine vehicle, a stationary device, etc.).
  • the memory 204 can be configured to store program instructions executable, performable or implementable by the associated one or more processors 202.
  • the memory medium 204 can comprise a non-transitory memory medium, and can comprise, but is not limited to, a read-only memory (ROM), a random-access memory (RAM), a magnetic or optical memory device (e.g., disk), a magnetic tape, a solid-state drive and the like.
  • the controller 200 can be in electronic communication with at least one of the sensors P1-P10, Tl-Tl l, FM1-FM11, AC1-AC10, HC1-HC5, and flow control units FCU1-FCU11 to monitor, measure, and/or control one or more characteristics or parameters of the ammonia reforming system 100.
  • the controller 200 can be connected by wire, or wirelessly, with the sensors P1-P10, Tl-Tl l, FM1-FM11, AC1-AC10, and HC1-HC5, and flow control units FCU1-FCU11.
  • a module 214 stored in the memory 204 can be configured to initiate or stop the monitoring or measurement of the ammonia reforming system 100.
  • a module 216 can be configured to control components of the ammonia reforming system 100 based on the monitored data (for example, by modulating heating power to the heaters 109 and 111, by modulating power output of the fuel cell 124, etc ).
  • the modules 214 and/or 216 can be implemented using a graphical user interface, such that a user of the controller 200 can view the monitored data (e.g., via one or more tables or charts) and/or manually control the ammonia reforming system 100.
  • the modules 214 and/or 216 can automatically control the ammonia reforming system 100 based on the measured on monitored data. It is noted that the modules 214 and 216 can be the same module (e.g., instead of being different modules).
  • the flow rate sensors FM1-FM11 can be configured to monitor or measure a flow rate (e.g., unit volume or unit mass per unit time) of a fluid (liquid or gas) in any component of the ammonia reforming system 100, and transmit data associated with the flow rate measurement to be stored in the memory 204.
  • a flow rate e.g., unit volume or unit mass per unit time
  • a fluid liquid or gas
  • the temperature sensors Tl-Tl l can be configured to detect a temperature (e.g., in Celsius or Kelvin) of any component of the ammonia reforming system 100 (for example, the walls of the reformers 108-110 or the walls of the heaters 109-111), or can be configured to detect the temperature of a fluid (liquid or gas) in any component of the ammonia reforming system 100, and transmit data associated with the temperature measurement to be stored in the memory 204.
  • a temperature e.g., in Celsius or Kelvin
  • the pressure sensors Pl -P10 can be configured to detect a pressure (e.g., gauge pressure (barg) or absolute pressure (bara)) of a fluid stream (liquid or gas) in any component of the ammonia reforming system 100, and transmit data associated with the pressure measurement to be stored in the memory 204.
  • a pressure e.g., gauge pressure (barg) or absolute pressure (bara)
  • barg gauge pressure
  • bara absolute pressure
  • the concentration sensors AC1-AC10 and HC1-HC5 can be configured to detect a concentration (e.g., in parts per million) of a fluid (liquid or gas) in any component of the ammonia reforming system 100, and transmit data associated with the concentration measurement to be stored in the memory 204.
  • a concentration e.g., in parts per million
  • a fluid liquid or gas
  • the pressure sensors Pl -P10 can be positioned in various components and/or fluid lines of the ammonia reforming system 100.
  • the pressure sensor Pl can be configured to measure the pressure of ammonia stored in the tank 102.
  • the pressure sensor P2 can be configured to measure the pressure of the incoming ammonia stream 104 before the stream 104 enters the heat exchanger 106.
  • the pressure sensor P3 can be configured to measure the pressure of the incoming ammonia stream 104 after the stream 104 exits the heat exchanger 106.
  • the pressure sensor P4 can be configured to measure the pressure of the air stream 118 after the stream 118 exits the air supply unit 116.
  • the pressure sensor(s) P5 can be configured to measure the pressure of fluid at one or more inlets, one or more outlets, and/or inside of the reformers 108-110 and/or the combustion heater 109.
  • the pressure sensor(s) P5 can be configured to measure the pressure of the incoming ammonia stream 104 at the inlets of the reformers 108-110, the partially cracked reformate stream 120 inside the reformers 108-110, and/or the substantially cracked reformate stream 120 at the outlets of the reformers 108-110.
  • the pressure sensor(s) P5 can be configured to measure the pressure of the reformate stream 120 and/or the air stream 118 at the inlets of the combustion heater 109, the combustion product gas 114 inside the combustion heater 109, and/or the combustion exhaust 114 at the outlets of the combustion heater 109.
  • the pressure sensor P6 can be configured to measure the pressure of the reformate stream 120 after the reformate stream exits the reformer 108-110 and before the reformate stream 120 enters the heat exchanger 106.
  • the pressure sensor(s) P7 can be configured to measure the pressure at one or more inlets, one or more outlets, and/or inside the ammonia filter 122.
  • the pressure sensor P8 can be configured to measure the pressure of the filtered reformate stream 123 before the stream 123 enters the fuel cell 124.
  • the pressure sensor(s) P9 can be configured to measure the pressure at one or more inlets, one or more outlets, and/or inside the fuel cell 124.
  • the pressure sensor P10 can be configured to measure the pressure of the anode off-gas 128 after the off-gas 128 exits the fuel cell 124 and/or before the off-gas 128 enters the combustion heater 109.
  • the temperature sensors Tl-Tl 1 can be positioned in various components and/or fluid lines of the ammonia reforming system 100.
  • the temperature sensor T1 can be configured to measure the temperature of ammonia stored in the tank 102.
  • the temperature sensor T2 can be configured to measure the temperature of the incoming ammonia stream 104 before the stream 104 enters the heat exchanger 106.
  • the temperature sensor T3 can be configured to measure the temperature of the incoming ammonia stream 104 after the stream 104 exits the heat exchanger 106.
  • the temperature sensor T4 can be configured to measure the temperature of the air stream 118 after the stream 118 exits the air supply unit 116.
  • the temperature sensor T5 can be configured to measure the temperature of fluid at one or more inlets, one or more outlets, and/or inside of the reformers 108-110 and/or the combustion heater 109.
  • the temperature sensor T5 can be configured to measure the temperature of the incoming ammonia stream 104 at the inlets of the reformers 108-110, the partially cracked reformate stream 120 inside the reformers 108-110, and/or the substantially cracked reformate stream 120 at the outlets of the reformers 108-110.
  • the temperature sensor T5 can be configured to measure the temperature of the reformate stream 120 and/or the air stream 118 at the inlets of the combustion heater 109, the combustion product gas 114 inside the combustion heater 109, and/or the combustion exhaust 114 at the outlets of the combustion heater 109.
  • the temperature sensor T6 can be configured to measure the temperature of the reformate stream 120 after the reformate stream exits the reformer 108-110 and before the reformate stream 120 enters the heat exchanger 106.
  • the temperature sensor T7 can be configured to measure the temperature at one or more inlets, one or more outlets, and/or inside the ammonia filter 122.
  • the temperature sensor T8 can be configured to measure the temperature of the filtered reformate stream 123 before the stream 123 enters the fuel cell 124.
  • the temperature sensor T9 can be configured to measure the temperature at one or more inlets, one or more outlets, and/or inside the fuel cell 124.
  • the temperature sensor T10 can be configured to measure the temperature of the anode off-gas 128 after the off-gas 128 exits the fuel cell 124 and before the off-gas 128 enters the combustion heater 109.
  • the temperature sensor T11 can be configured to measure the temperature at one or more inlets, one or more outlets, and/or inside the heat exchanger 106).
  • the temperature sensors Tl-Tl l can be configured to measure temperatures of the walls of the components and/or fluid lines of the ammonia reforming system 100 (as opposed to directly measuring the temperature of the fluids passing therethrough, for example, by physically contacting the sensors with the fluid streams).
  • the flow rate sensors FM1-FM11 can be positioned in various components and/or fluid lines of the ammonia reforming system 100.
  • FM1-FM11 can comprise one or more valves, one or more regulators, or one or more flow rate sensors configured to monitor and/or control the flow rates of fluid streams of the ammonia reforming system 100.
  • the flow meter FM1 can be configured to measure the flow rate of the incoming ammonia stream 104 before the stream 104 enters the heat exchanger 106.
  • the flow meter FM2 can be configured to measure the flow rate of the incoming ammonia stream 104 after the stream 104 exits the heat exchanger 106.
  • the flow meter FM3 can be configured to measure the flow rate of the air stream 118 at or inside the air supply unit 116.
  • the flow meter FM4 can be configured to measure the flow rate of the air stream 118 after the stream 118 exits the air supply unit 116.
  • the flow meter FM5 can be configured to measure the flow rate of fluid at one or more inlets, one or more outlets, and/or inside of the reformers 108-110 and/or the combustion heater 109.
  • the flow meter FM5 can be configured to measure the flow rate of the incoming ammonia stream 104 at the inlets of the reformers 108-110, the partially cracked reformate stream 120 inside the reformers 108-110, and/or the substantially cracked reformate stream 120 at the outlets of the reformers 108- 110.
  • the flow meter FM5 can be configured to measure the flow rate of the reformate stream 120 or anode off-gas 128 and/or the air stream 118 at the inlets of the combustion heater 109, the combustion product gas 114 inside the combustion heater 109, and/or the combustion exhaust 114 at the outlets of the combustion heater 109.
  • the flow meter FM6 can be configured to measure the flow rate of the reformate stream 120 after the reformate stream exits the reformer 108- 110 and before the reformate stream 120 enters the heat exchanger 106.
  • the flow meter FM7 can be configured to measure the flow rate at one or more inlets, one or more outlets, and/or inside the ammonia filter 122.
  • the flow meter FM8 can be configured to measure the flow rate of the filtered reformate stream 123 before the stream 123 enters the fuel cell 124.
  • the flow meter FM9 can be configured to measure the flow rate at one or more inlets, one or more outlets, and/or inside the fuel cell 124.
  • the flow meter FM10 can be configured to measure the flow rate of the anode off-gas 128 after the off-gas 128 exits the fuel cell 124 and before the off-gas 128 enters the combustion heater 109.
  • the flow meter FM11 can be configured to measure the one or more flow rates the one or more inlets, one or more outlets, or one or more locations in the heat exchanger 106.
  • the flow rate meters FM1-FM11 can comprise pumps, valves, blowers, compressors, or other fluid supply device, and the respective flow rate measurements can be performed by correlating a parameter of the fluid supply device with the flow rate.
  • the flow meter FM3 can be the air supply unit 116 itself. If the air supply unit 116 comprises a valve, the flow rate can be measured by correlating a size of an opening of the valve and/or one or more pressure measurements in the air supply unit 116. If the air supply unit comprises a pump or a compressor, the flow rate can be measured by at least partly correlating a revolutions-per- minute (RPM) of the pump or the compressor.
  • RPM revolutions-per- minute
  • the ammonia sensors AC 1 -AC 10 can be positioned in various components and/or fluid lines of the ammonia reforming system 100.
  • the ammonia sensor AC1 can be configured to measure the concentration of ammonia in the storage tank 102.
  • the ammonia sensor AC2 can be configured to measure the concentration of ammonia in the incoming ammonia stream 104 before the stream 104 enters the heat exchanger 106.
  • the ammonia sensor AC3 can be configured to measure the concentration of ammonia in the incoming ammonia stream 104 after the stream 104 exits the heat exchanger 106.
  • the ammonia sensor AC4 can be configured to measure the concentration of ammonia at one or more inlets, one or more outlets, and/or inside of the reformers 108-110 and/or the combustion heater 109.
  • the ammonia sensor AC4 can be configured to measure the concentration of ammonia in the incoming ammonia stream 104 at the inlets of the reformers 108-110, the partially cracked reformate stream 120 inside the reformers 108-110, and/or the substantially cracked reformate stream 120 at the outlets of the reformers 108-110.
  • the ammonia sensor AC4 can be configured to measure the concentration of ammonia in the reformate stream 120 and/or the air stream 118 at the inlets of the combustion heater 109, the combustion product gas 114 inside the combustion heater 109, and/or the combustion exhaust 114 at the outlets of the combustion heater 109.
  • the ammonia sensor AC5 can be configured to measure the concentration of ammonia in the reformate stream 120 after the reformate stream exits the reformer 108-110 and before the reformate stream 120 enters the heat exchanger 106.
  • the ammonia sensor AC6 can be configured to measure the concentration of ammonia at one or more inlets, one or more outlets, and/or inside the ammonia filter 122.
  • the ammonia sensor AC7 can be configured to measure the concentration of ammonia in the filtered reformate stream 123 before the stream 123 enters the fuel cell 124.
  • the ammonia sensor AC8 can be configured to measure the concentration of ammonia at one or more inlets, one or more outlets, and/or inside the fuel cell 124.
  • the ammonia sensor AC9 can be configured to measure the concentration of ammonia in the anode off-gas 128 after the off-gas 128 exits the fuel cell 124 and before the off-gas 128 enters the combustion heater 109.
  • the ammonia sensor AC 10 can be configured to measure the concentration of ammonia at one or more inlets, one or more outlets, and/or inside the heat exchanger 106.
  • the hydrogen concentration sensors HC1-HC5 positioned in various components and/or fluid lines of the ammonia reforming system 100.
  • the hydrogen concentration sensor HC 1 can be configured to measure the concentration of hydrogen at one or more inlets, one or more outlets, and/or inside of the reformers 108-110 and/or the combustion heater 109.
  • the hydrogen concentration sensor HC1 can be configured to measure the concentration of hydrogen in the incoming ammonia stream 104 at the inlets of the reformers 108-110, the partially cracked reformate stream 120 inside the reformers 108-110, and/or the substantially cracked reformate stream 120 at the outlets of the reformers 108-110.
  • the hydrogen concentration sensor HC1 can be configured to measure the concentration of hydrogen in the reformate stream 120, the fuel cell off-gas 128, and/or the air stream 118 at the inlets of the combustion heater 109, the combustion product gas 114 inside the combustion heater 109, and/or the combustion exhaust 114 at the outlets of the combustion heater 109.
  • the hydrogen concentration sensor HC2 can be configured to measure the concentration of hydrogen in the reformate stream 120 after the reformate stream exits the reformer 108-110 and before the reformate stream 120 enters the heat exchanger 106.
  • the hydrogen concentration sensor HC3 can be configured to measure the concentration of hydrogen in the filtered reformate stream 123 before the stream 123 enters the fuel cell 124.
  • the hydrogen concentration sensor HC4 can be configured to measure the concentration of hydrogen at one or more inlets, one or more outlets, and/or inside the fuel cell 124.
  • the hydrogen concentration sensor HC5 can be configured to measure the concentration of hydrogen in the anode off-gas 128 after the off-gas 128 exits the fuel cell 124 and before the off-gas 128 enters the combustion heater 109.
  • the flow control units FCU1-FCU11 can be positioned in various components and/or fluid lines of the ammonia reforming system 100.
  • FCU1-FCU11 can configured to monitor and/or control (i.e., increase, decrease, modulate, or maintain) one or more flow rates and/or one or more pressures of the ammonia reforming system 100.
  • FCU1-FCU11 can comprise one or more pressure drop elements configured to reduce pressure, one or more pumps, one or more check valves, one or more one-way valves, one or more three-way valves, one or more restrictive orifices, one or more valves, one or more flow regulators, one or more pressure regulators, one or more back pressure regulators, one or more pressure reducing regulators, one or more back flow regulators, one or more flow meters, one or more flow controllers, or any combination thereof.
  • the flow control units FCU1-FCU11 can be controlled manually, automatically, or electronically.
  • the flow control unit FCU1 can be configured to measure and/or control the flow rate and/or pressure of the incoming ammonia stream 104 before the stream 104 enters the heat exchanger 106.
  • the flow control unit FCU2 can be configured to measure and/or control the flow rate and/or pressure of the incoming ammonia stream 104 after the stream 104 exits the heat exchanger 106.
  • the flow control unit FCU3 can be configured to measure and/or control the flow rate and/or pressure of the air stream 118 at or inside the air supply unit 116.
  • the flow control unit FCU4 can be configured to measure and/or control the flow rate and/or pressure of the air stream 118 after the stream 118 exits the air supply unit 116.
  • the flow control unit FCU5 can be configured to measure and/or control the flow rate and/or pressure of fluid at one or more inlets, one or more outlets, and/or inside the reformers 108-110 and/or the combustion heater 109.
  • the flow control unit FCU5 can be configured to measure and/or control the flow rate and/or pressure of the incoming ammonia stream 104 at the inlets of the reformers 108-110, the partially cracked reformate stream 120 inside the reformers 108-110, and/or the substantially cracked reformate stream 120 at the outlets of the reformers 108-110.
  • the flow control unit FCU5 can be configured to measure and/or control the flow rate and/or pressure of the reformate stream 120 or anode off-gas 128 and/or the air stream 118 at the inlets of the combustion heater 109, the combustion product gas 114 inside the combustion heater 109, and/or the combustion exhaust 114 at the outlets of the combustion heater 109.
  • the flow control unit FCU6 can be configured to measure and/or control the flow rate and/or pressure of the reformate stream 120 after the reformate stream exits the reformer 108-110 and before the reformate stream 120 enters the heat exchanger 106.
  • the flow control unitFCU7 can be configured to measure and/or control the flow rate and/or pressure at one or more inlets, one or more outlets, and/or inside the ammonia filter 122.
  • the flow control unit FCU8 can be configured to measure and/or control the flow rate and/or pressure of the filtered reformate stream 123 before the stream 123 enters the fuel cell.
  • the flow control unit FCU9 can be configured to measure and/or control the flow rate and/or pressure at one or more inlets, one or more outlets, and/or inside the fuel cell 124.
  • the flow control unit FCU10 can be configured to measure and/or control the flow rate and/or pressure of the anode off-gas 128 after the off-gas 128 exits the fuel cell 124 and before the off-gas 128 enters the combustion heater 109.
  • the flow control unit FM11 can be configured to measure and/or control the flow rate and/or pressure at one or more inlets, one or more outlets, and/or inside the heat exchanger 106.
  • the flow control units FCU1-FCU11 can comprise pumps, valves, blowers, compressors, or other fluid supply devices, and the respective flow rate measurements can be performed by correlating a parameter of the fluid supply device with the flow rate.
  • the flow control unit FCU3 can be the air supply unit 116 itself. If the air supply unit 116 comprises a valve, the flow rate can be measured by correlating a size of an opening of the valve and/or one or more pressure measurements in the air supply unit 116. If the air supply unit 116 comprises a pump or a compressor, the flow rate can be measured by at least partly correlating a revolutions-per-minute (RPM) of the pump or the compressor.
  • RPM revolutions-per-minute
  • the flow control unit FCU1-FCU11 and the flow meter FM1-FM11 are interchangeable and/or can have one or more identical or similar functionalities.
  • the flow control units FCU1-FCU11 and/or flow rate meters FM1- FM11 can maintain a flow rate to a target flow rate within a selected tolerance.
  • the selected tolerance can be at least about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%. In some instances, the selected tolerance can be at most about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%. In some instances, the selected tolerance can be between about 1 and 90, 5 and 80, 10 and about 70, 20 and 60, 30 and 50, or 40 and 90%. In some instances, the selected tolerance can be less than 20%.
  • the flow control units FCUl-FCUl 1 and/or flow rate meters FM1-FM11 can increase a flow rate to a target flow rate at a predefined ramp-up rate (within a selected tolerance).
  • the selected tolerance can be at least about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%. In some cases, the selected tolerance can be at most about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%. In some cases, the selected tolerance can be between about 1 and 90, 5 and 80, 10 and 70, 20 and 60, 30 and 50, or 40 and 90%. In some cases, the selected tolerance can be less than 20%.
  • the flow control units FCUl-FCUl 1 and/or flow rate meters FM1-FM11 can decrease a flow rate to a target flow rate at a predefined ramp-down rates (within a selected tolerance).
  • the selected tolerance can be at least about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%. In some cases, the selected tolerance can be at most about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%. In some cases, the selected tolerance can be between about 1 and 90, 5 and 80, 10 and 70, 20 and 60, 30 and 50, or 40 and 90%. In some cases, the selected tolerance can be less than 20%. [00193] Referring now to FIG.
  • one or more pressure regulators can be positioned in various components and/or fluid lines of the ammonia reforming system 100.
  • a back pressure regulator BPR1 (or a pressure reducing regulator PRR1) can be configured to maintain a pressure of the reformate stream 120 after the reformate stream exits the reformer 108-110, after (or before) the reformate stream 120 enters the heat exchanger 106, or before the reformate stream 120 enters the ammonia filter 122.
  • a back pressure regulator BPR2 (or a pressure reducing regulator PRR2) can be configured to maintain a pressure of the filtered reformate stream 123 after the reformate stream 123 exits the ammonia filter 122.
  • a back pressure regulator BPR3 (or a check valve CV1) can be configured to maintain a pressure of the anode off-gas 128.
  • a fault detection module 214 can be stored in the memory 204 of the controller 200 and can be configured to detect one or more faults in the ammonia reforming system 100 (e.g., by utilizing the sensors P1-P10, Tl-Tl l, FMl-FMl l,ACl-AC10, and HC1-HC5,).
  • the faults can comprise major faults or minor faults.
  • An example of a fault can comprise a fracture of and/or leak from a reactor vessel (e.g., a fracture in the reformers 108-110 or the heater 109).
  • the fracture and/or leak can be detected after a pressure sensor Pl -P10 measures a sudden drop in pressure of the reformate stream 120 in the combustion heater 109, or a sudden drop in pressure of the incoming ammonia stream 104 (or the partially cracked reformate stream 120) in the combustion-heated reformer 108 or the electrically- heated reformer 110.
  • the sudden drop in pressure can comprise a greater than 50% pressure drop (e.g., from 10 bara to less than or equal to 5 bara) within a predefined time.
  • the predefined time can be at least about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90 minutes. In some cases, the predefined time can be at most about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90 minutes.
  • a fault can comprise a leakage of ammonia above predetermined leakage levels.
  • the leakage of ammonia can be detected after an ammonia concentration sensor AC1- AC10 detects a concentration of ammonia greater than a threshold concentration (e.g., about 25 ppm) adjacent or near any component or fluid line of the ammonia reforming system 100.
  • a threshold concentration e.g., about 25 ppm
  • the ammonia concentration sensor AC 1 -AC 10 can be positioned outside the wall(s) or container(s) of the component or fluid line of the ammonia reforming system 100.
  • An example of a fault can comprise a temperature offset (e.g., by a tolerance about 10% or more) from a target temperature range.
  • a target temperature range of the reformers 108-110 can comprise about 400 to about 600 °C
  • a temperature sensor Tl-Tl l can measure a temperature of less than about 360 °C or greater than about 660 °C, indicating a temperature offset fault.
  • the reformers 108 and/or the reformer 110 can be maintained at a target temperature range of at least about 300, 350, 400, 450, 500, 550, 600, 650, 700, 750, or 800 °C, and at most about 400, 450, 500, 550, 600, 650, 700, 750, 800, or 900 °C.
  • the target temperature ranges between about 300 and 900, 350 and 800, 400 and 750, 450 and 700, 500 and 650, or 550 and 600 °C.
  • a target temperature range of the reformer 108 and a target temperature range of the reformer 110 can at least partially overlap.
  • a temperature offset is defined by a selected tolerance of a target temperature (or a tolerance of a lower limit of a target temperature range, or an upper limit of a target temperature range).
  • the selected tolerance can be at least about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100% of the target temperature.
  • the selected tolerance can be at most about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100% of the target temperature.
  • the selected tolerance can be between about 1 and 100, 5 and 90, 10 and 80, 20 and 70, 30 and 60, or 40 and 50% of the target temperature.
  • a fuel cell target temperature comprises about an ambient temperature to about 100 °C, about 100 °C to about 150 °C, or about 120 °C to about 200 °C.
  • the temperature offset fault can be detected after a temperature sensor Tl-Tl 1 measures a fuel cell temperature of less than about 108 °C or greater than about 220 °C.
  • An example of a fault can comprise a pressure offset (e.g., by a tolerance about 10% or more) from a target pressure range.
  • a target pressure range in the reformers 108-110 can comprise about 1 to about 5 bar-absolute (bara), about 3 to about 8 bara, about 5 to about 10 bara, or about 10 to about 20 bara.
  • a pressure sensor Pl -P10 can measure a pressure of less than about 9 bara or greater than about 22 bara, indicating a pressure offset fault.
  • a pressure offset is defined by a selected tolerance of a target pressure (or a tolerance of a lower limit of a target pressure range, or an upper limit of a target pressure range).
  • the selected tolerance can be at least about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100% of the target pressure.
  • the selected tolerance can be at most about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100% of the target pressure.
  • the selected tolerance can be between about 1 and 100, 5 and 90, 10 and 80, 20 and 70, 30 and 60, or 40 and 50% of the target pressure.
  • the target pressure can be a pressure (or a pressure range) at an outlet or inside of the NH3 storage tank 102, an inlet, an outlet, or inside of the combustion-heated reformer 108, an inlet, an outlet, or inside of the combustion heater 109, an inlet, an outlet, or inside of the electrically heated reformer 110, an inlet, an outlet, or inside of the heat exchanger 106, an inlet, an outlet, or inside of the ammonia filter 122, or an inlet, an outlet, or inside of the fuel cell 124.
  • An example of a fault can comprise a concentration offset (e.g., by a tolerance about 10% or more) from a target concentration range (or a tolerance of a lower limit of a target concentration range, or an upper limit of a target concentration range).
  • a target ammonia concentration range in the filtered reformate stream 123 can comprise about 0.001 to about 0.01 ppm, about 0.01 to about 0.1 ppm, about 0.1 to about 1 ppm, about 0.1 ppm to about 100 ppm.
  • an ammonia concentration sensor AC 1 -AC 10 can measure a concentration of greater than about 110 ppm, indicating a concentration offset fault.
  • a concentration offset is defined by a selected tolerance of a target concentration.
  • the selected tolerance can be at least about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100% of the target concentration.
  • the selected tolerance can be at most about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100% of the target concentration.
  • the selected tolerance can be between about 1 and 100, 5 and 90, 10 and 80, 20 and 70, 30 and 60, or 40 and 50% of the target concentration.
  • the controller can execute or perform a complete shutdown of the ammonia reforming system 100 by stopping a flow rate of the incoming NH3 stream 104, power provided the heaters 109-111, and/or the fuel cell 124.
  • the controller can execute or perform a partial shutdown of the ammonia reforming system 100 by reducing power provided to the heater 109- 111 and/or the fuel cell 124.
  • the combustion-heated reformer 108 can operate in a hot-standby mode to maintain the temperature in the combustion-heated reformer 108 within a target temperature range (the hot-standby mode is described in further detail with respect to FIG. 6L).
  • the hot standby mode e.g., without the fuel cell outputting power
  • the hot standby mode can be maintained until the shutdown process is executed.
  • the hot standby mode e.g., without the fuel cell outputting power
  • FIG. 6A is a block diagram illustrating the utilization of an anode off-gas 503 and a cathode off-gas 504 directed from the fuel cell 124 (for example, via one or more outlet ports in the fuel cell 124) as reactants for combustion in the combustion heater 109.
  • the anode off-gas 503 can be substantially similar or substantially identical to the off-gas 128 described with respect to FIGS. 1A-4B
  • the fuel cell can receive an anode input 501 (at least hydrogen, for example, in the reformate stream 120) and a cathode input 502 (at least oxygen, for example, in the air stream 118), for example, via one or more inlet ports in the fuel cell.
  • anode input 501 at least hydrogen, for example, in the reformate stream 120
  • a cathode input 502 at least oxygen, for example, in the air stream 118
  • Unconsumed hydrogen e.g., that is not consumed by the fuel cell 12
  • unconsumed oxygen e.g., that is not consumed by the fuel cell 12
  • a cathode off-gas 504 as reactants for the combustion reaction in the combustion heater 109.
  • water can be removed from the anode off-gas 503 and/or the cathode off-gas 504 before the anode off-gas 503 and/or the cathode off-gas 504 are provided to the combustion heater 109 (e.g., using a condenser or a filter).
  • FIG. 6B is a block diagram illustrating the utilization of heat from the combustion exhaust 114 (emitted by combustion heater 109) to regenerate the ammonia filter 122 (e.g., via temperature swing adsorption).
  • the desorbed ammonia 505 can be vented to the atmosphere, combusted in the combustion heater 109, or mixed with water and discharged externally.
  • the combustion exhaust stream 114 is used to regenerate the ammonia filter 122 by directly contacting the combustion exhaust stream 114 with the ammonia filter 122 (i.e., a direct purge of the filter material). In some cases, the combustion exhaust stream 114 is used to regenerate the ammonia filter 122 by transferring heat to the ammonia filter 122 via a heat exchanger (and/or an intermediate fluid, such as a glycol and/or water).
  • FIG. 6C is a block diagram illustrating the reduction of nitrogen oxides (NOx, e.g., NO, NO2, N2O, etc.) in the combustion exhaust 114 emitted by the combustion heater 109.
  • a selective catalytic reduction (SCR) catalyst 506, such as platinum or palladium, can be used to convert NO X into H2O and N2.
  • a reductant such as anhydrous ammonia (NH3), aqueous ammonia (NH4OH), or urea (CO(NH 2 ) 2 ) solution can be added to the exhaust 114 to react with NO X .
  • the purified exhaust 507 can be vented to the atmosphere. This removal of harmful NO X emissions advantageously reduces harm to the environment and living organisms.
  • FIG. 6D is a block diagram illustrating the utilization of the anode off-gas 503 and/or the cathode off-gas 504 to regenerate the ammonia filter 122 (e.g., via temperature swing adsorption).
  • the desorbed ammonia 508 can be vented to the atmosphere, or mixed with water and discharged externally.
  • combustion of the hydrogen in the anode off-gas 503 can provide heat to regenerate the ammonia filter 122.
  • lower temperature catalytic combustion of the hydrogen in the anode off-gas 503 can provide heat to regenerate the ammonia filter 122.
  • FIG. 6E is a block diagram illustrating the oxidation of trace or residual NH3 in the reformate stream 120 output by the combustion-heated reformer 108 and/or the electrically-heated reformer 110.
  • a selective ammonia oxidation (SAO) catalyst 509 such as tungsten, can be used to convert the trace or residual NH3 into N2 and H2O.
  • Air (comprising at least oxygen, e.g., the air stream 118) can be provided to the SAO catalyst 509 to react with the NH3.
  • the purified reformate stream 510 can be provided to the fuel cell 124 (to generate electricity) or to the combustion heater 109 (to be combusted for self-heating the reformer 108).
  • the SAO catalyst 509 when combined with the ammonia filter 122, can advantageously reduce the size (e.g., volume and weight) of the ammonia filter 122, and can reduce the need to periodically replace cartridges in (or periodically regenerate) the ammonia filter 122.
  • introducing air comprising at least oxygen
  • FIG. 6F is a block diagram illustrating the heating of the electrically-heated reformer 110 using an induction heater 511.
  • the induction heater 511 can comprise a magnetically-sensitive material in contact with the NH3 reforming catalyst in the electrically-heated reformer 110, in addition to a magnetic device (e.g., an electrical coil or other magnet) that generates a magnetic field to heat the magnetically-sensitive material (e.g., via an electromagnetic interaction).
  • a magnetic device e.g., an electrical coil or other magnet
  • FIG. 6G is a block diagram illustrating the utilization of a heat pump 514 to transfer heat 513 from a relatively cold component 512 to a relatively hot component 515.
  • the heat pump 514 can be driven by electricity (for example, vapor compression cycle), or driven by heat (for example, adsorption refrigeration), or a combination of both.
  • the components 512 and 514 can be any component of the ammonia reforming system 100 described in the present disclosure.
  • the heat pump 514 can transfer heat from the ammonia filter 122 to the reformate stream 120.
  • Other examples include, but are not limited to, liquefying ammonia gas, condensing water from a cathode off-gas or combustion exhaust, removing heat from one or more heat exchangers, or removing heat from one or more fuel cells.
  • the refrigerants of the heat pump 514 can comprise ammonia, water, or mixture of both.
  • FIG. 6H is a block diagram illustrating the utilization of a fluid pump 516 to pressurize the incoming ammonia stream 104 provided by the storage tank 102.
  • the storage tank 102 and/or the pump 516 can use the heat provided by one or more electrical heaters, the combustion-heated reformer 108, the combustion heater 109, and/or the electrically-heated reformer 110 to pressurize or vaporize the incoming ammonia stream 104.
  • the pump 516 can be electrically powered and/or controlled.
  • FIG. 61 is a block diagram illustrating the utilization of flow control units 517 to control the pressure, flow rate, and/or gas velocity of fluid streams in the ammonia reforming system 100.
  • the flow control units 517 can be substantially similar or substantially identical to the flow control units FCU1-10 described with respect to FIG. 5G.
  • the flow control units 517 can comprise one or more pressure drop elements, one or more pumps, one or more check valves, one or more oneway valves, one or more three-way valves, one or more restrictive orifices, one or more valves, one or more flow regulators, one or more pressure regulators, one or more back pressure regulators, one or more pressure reducing regulators, one or more back flow regulators, one or more flow meters, one or more flow controllers, or any combination thereof.
  • the flow control units 517 can be controlled manually, automatically, or electronically.
  • the fuel cell 124 can draw the reformate stream 120 at a pressure that is maintained within a selected tolerance (e.g., a tolerance of about 1%, about 5%, or about 10%) at the inlet of the fuel cell 124.
  • the target pressure can be at least about 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 15, 20, 25, 30, 35, or 40 bar absolute (bara) at the inlet of the fuel cell 124.
  • the target pressure can be at most about 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 15, 20, 25, 30, 35, or 40 bara at the inlet of the fuel cell 124.
  • the target pressure can be between about 1 and 40, 2 and 35, 3 and 30, 4 and 25, 5 and 20, or 10 and 15 bara at the inlet of the fuel cell 124.
  • the target pressure range is about 2 to about 5 bara at the inlet of the fuel cell 124.
  • the selected tolerance can be at least about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100% of a target pressure at the inlet of the fuel cell 124. In some cases, the selected tolerance can be at most about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100% of a target pressure at the inlet of the fuel cell 124. In some cases, the selected tolerance can be between about 1 and 100, 5 and 90, 10 and 80, 20 and 70, 30 and 60, or 40 and 50% of the target pressure at the inlet of the fuel cell 124.
  • the flow control units 517 can be controlled to modulate the pressure of the ammonia stream 104 (before the stream 104 enters the reformers 108-110), or the flow control units 517 can be controlled to modulate the pressure of the reformate stream 120 (before the stream 120 enters the fuel cell 124).
  • the pressure of the reformate stream 120 can be measured at the fuel cell inlet (using a pressure sensor P1-P10), and the flow control units 517 can be modulated (e.g., based on the pressure measured by the pressure sensor P 1 -P 10) to increase the flow rate of the ammonia stream 104 or the reformate stream 120 (to maintain the pressure of the reformate stream 120 at the selected tolerance at the fuel cell inlet).
  • one or more pressure regulators can be configured to maintain the pressure of the reformate stream 120 at the inlet of the fuel cell 124 within the selected tolerance.
  • the fuel cell 124 can draw the reformate stream 120 at a flow rate that is maintained within a selected tolerance (e.g., a tolerance of about 1%, about 5%, or about 10%) at the inlet of the fuel cell 124.
  • the selected tolerance can be at least about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100% of a target flow rate at the inlet of the fuel cell 124.
  • the selected tolerance can be at most about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100% of a target flow rate at the inlet of the fuel cell 124.
  • the selected tolerance can be between about 1 and 100, 5 and 90, 10 and 80, 20 and 70, 30 and 60, or 40 and 50% of the target flow rate at the inlet of the fuel cell 124.
  • a flow rate of the reformate stream 120 can be measured at the fuel cell inlet (using a flow rate sensor FM1-FM11), and the flow control units 517 can be controlled (based on the flow rate measured by the flow rate sensor FM1-FM11) to modulate the flow rate of the ammonia stream 104 (before the stream 104 enters the reformers 108-110), or the flow control units 517 can be controlled (based on the flow rate measured by the flow rate sensor FM1-FM11) to modulate the flow rate of the reformate stream 120 (before the stream 120 enters the fuel cell 124).
  • the flow control units 517 can be configured to modulate a gas velocity of the reformate stream 120 at the inlet of the fuel cell 124.
  • the hydrogen and/or nitrogen in the reformate stream 120 can purge liquid water in the fuel cell 124 by directing the liquid water out of the fuel cell 124.
  • the gas velocity of the reformate stream 120 can be modulated based on a concentration or volume of the liquid water in the fuel cell 124 (which can be measured using, e.g., one or more humidity sensors in the fuel cell 124 in communication with the controller 200 described with respect to FIG. 5A). For example, in response to the measured concentration or volume of water in the fuel cell 124 being greater than a threshold concentration or volume, the gas velocity of the reformate stream 120 can be increased to facilitate the purging of water in the fuel cell 124 (and vice versa).
  • At least a portion of the reformate stream 120 is recirculated in the fuel cell 124, and the recirculated portion can be adjusted based on a concentration or volume of the liquid water in the fuel cell 124, an H2 consumption rate of the fuel cell 124, an N2 concentration in the fuel cell 124, humidity in the fuel cell 124, the flow rate of the reformate stream 120 at the inlet of the fuel cell 124, or a power output of the fuel cell 124.
  • FIG. 6J is a block diagram illustrating a non-linear start-up sequence for the ammonia reforming system 100.
  • a first set of reformers 520 can comprise a plurality of electrically-heated reformers (e.g., each one being substantially similar or substantially identical to the electrically-heated reformer 110 described with respect to FIGS. 1A-4B).
  • a second set of reformers 521 and a third set of reformers 522 can comprise a plurality of combustion-heated reformers (e.g., each one being substantially similar or substantially identical to the combustion-heated reformer 108 described with respect to FIGS. 1A-4B).
  • the number of reformers in the second set 521 can be greater than the number of reformers in the first set 520, and likewise, it is contemplated that the number of reformers in the third set 522 can be greater than the number of reformers in the second set 521. In this way, a progressively larger number of reformers can be heated at each step of the nonlinear startup sequence.
  • the first set of reformers 520 can comprise two reformers
  • the second set of reformers 521 can comprise four reformers
  • the third set of reformers 522 can comprise eight reformers, and so on.
  • the non-linear start-up sequence can be performed by decomposing ammonia (e.g., the ammonia stream 104) using the first set of reformers 520 to generate a first reformate stream (e.g., the reformate stream 120). Subsequently, the reformate stream produced by the first set of reformers 520 can be combusted to heat the second set of reformers 521 to generate a second reformate stream. Subsequently, the second reformate stream produced by the second set of reformers 521 can be combusted to heat the third set of reformers 522 to generate a third reformate stream.
  • ammonia e.g., the ammonia stream 104
  • first reformate stream e.g., the reformate stream 120
  • the reformate stream produced by the first set of reformers 520 can be combusted to heat the second set of reformers 521 to generate a second reformate stream.
  • the second reformate stream produced by the second set of reformers 521 can be combusted to heat the third
  • non-linear start-up sequence can involve any number of sets of reformers (e.g., at least two sets of reformers), and each set of reformers can comprise any number of reformers (e.g., at least one reformer). It is also noted that the non-linear startup sequence can be initiated using the controller 200 (for example, by initiating the heating of the electrically-heated reformers of the first set of reformers 520).
  • FIG. 6K is a block diagram illustrating purging of the ammonia reforming system 100.
  • a purging gas 523 can purge the ammonia reforming system 100 of residual gases (for example, before starting the ammonia reforming system 100 or after shutting down the ammonia reforming system 100).
  • the purging gas 523 can direct residual ammonia in the ammonia reforming system 100 (for example, residual ammonia in the reformers 108-110) into water or a scrubber.
  • the purging gas 523 can comprise an inert or noble gas (for example, nitrogen or argon). In some cases, the purging gas 523 comprises hydrogen and can be flared or vented into the atmosphere.
  • the purging gas 523 can be stored in a dedicated tank, or can be generated by reforming ammonia.
  • the purging of the ammonia reforming system can be initiated using the controller 200 (for example, by modulating a valve to direct the purging gas 523 into the reformers 108-110).
  • FIG. 6L is a block diagram illustrating the initiation of a hot standby mode for the ammonia reforming system 100.
  • the hot standby mode can advantageously reduce the time required to return to an operation mode, for example, by avoiding a shut-down (or reduction in temperature) of the combustion reformer 108 and/or the combustion heater 109. Additionally, the hot standby mode can advantageously enable the system 100 to adjust and respond to power demand at the fuel cell and/or hydrogen demand at a hydrogen processing module.
  • the hot standby mode can advantageously enable the maintenance of the fuel cell and/or the hydrogen processing module (e.g., due to a fault at the fuel cell and/or the hydrogen processing module) without shutting down (or reducing the temperature of) the combustion reformer 108 and/or the combustion heater 109.
  • the hot standby mode enables the system 100 to operate for stationary or mobile hydrogen and/or power generation applications.
  • a flow control unit 524 can direct the reformate stream 120 (e g., as an H2 processing flow 119) to an H2 processing module 535.
  • the H2 processing module 535 can be configured to generate electrical power and/or to supply H2 to various chemical or industrial processes, including, but not limited to, steel or iron processing, combustion engines, combustion turbines, hydrogen storage, hydrogen for chemical processes, hydrogen fueling stations, and the like.
  • the H2 processing module 535 can comprise one or more fuel cells 124, one or more PSAs 127, one or more flow distributors 115, or one or more membrane hydrogen separation devices 527 (described with respect to FIGS. 1A-4B and FIG. 6S).
  • a leftover reformate stream 536 (e.g., unconsumed H2 from fuel cell 124, or H2 that is not supplied to chemical or industrial processes) can be supplied to the combustion heater 109 as a reactant for the combustion reaction.
  • the leftover reformate stream 536 can comprise the filtered reformate stream 123, the anode off-gas 128, the anode off-gas 503, the PSA exhaust stream 128b, the hydrogen separation device retentate stream 532, or the portion 128c of the reformate stream 120 distributed by the flow distributor 115.
  • the flow control unit 524 can be configured to monitor and/or modulate one or more flow rates and/or one or more pressures.
  • the flow control unit 524 can comprise one or more pressure drop elements configured to reduce pressure, one or more pumps, one or more valves, one or more check valves, one or more one-way valves, one or more three- way valves, one or more restrictive orifices, one or more flow regulators, one or more pressure regulators, one or more back pressure regulators, one or more pressure reducing regulators, one or more back flow regulators, one or more flow meters, one or more flow controllers, or any combination thereof. In some instances, the flow control unit 524 can be controlled manually, automatically, or electronically.
  • the power output by the one or more fuel cells 124, or the supply of H2 to the various chemical or industrial processes can be reduced or shut off entirely (by modulating the flow control unit 524 to direct at least part of the reformate stream 120 to the combustion heater 109 for combustion in the combustion heater 109), thereby maintaining the combustion-heated reformer 108 in a target temperature range.
  • Excess hydrogen can be vented or flared after passing the combustion heater 109 (due to fuel -rich conditions in the combustion-heater 109). In some cases, the excess hydrogen can be directed to a heat recovery module configured to recover hydrogen and/or heat from the combustion exhaust.
  • the hot standby mode can be terminated by modulating the flow control unit 524 to redirect the reformate stream 120 to the H2 processing module 535 (e.g., by increasing a flow rate or pressure of the H2 processing inlet flow 119, for example, at an inlet of the fuel cell 124), thereby starting or increasing the power output by and/or the H2 supplied to the H2 processing module 535.
  • the hot standby mode can advantageously maintain the target temperature range in the combustion-heated reformer 108 even while the H2 processing module 535 reduces or shuts off the electrical power output or the supply of H2 to the chemical or industrial processes (in other words, turning off the combustion-heated reformer 108 can be avoided).
  • a fault situation e.g., a fault associated with the fuel cell 124
  • completely shutting down the ammonia reforming system 100 can be prevented, and the time required to start-up the ammonia reforming system 100 (and increase power output by the H2 processing module 535, and/or increase the H2 supplied to the H2 processing module 535) can be reduced.
  • the flow rate of the incoming NH3 stream 104 may (or may not be) configured to be the same during the operation mode and hot standby mode. In some instances, the flow rate of the incoming NH3 stream 104 during the hot standby mode can be configured to be within a selected tolerance of the flow rate of the incoming NH3 stream 104 during the operation mode.
  • the selected tolerance can be at least about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%.
  • the selected tolerance can be at most about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%. In some cases, the selected tolerance can be between about 1 and 90, 5 and 80, 10 and 70, 20 and 60, 30 and 50, or 40 and 90%. In some instances, the selected tolerance is about 5 to about 20%.
  • the hot standby mode can be maintained without substantially reducing or increasing the flow rate of the incoming NH3 stream 104 (or the flow rate of the reformate stream 120).
  • the flow rate of the incoming NH3 stream 104 (or the flow rate of the reformate stream 120) can be maintained within a selected tolerance of a target flow rate.
  • the selected tolerance can be at most about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%.
  • the selected tolerance can be at least about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%.
  • the selected tolerance can be between about 1 and 90, 5 and 80, 10 and 70, 20 and 60, 30 and 50, or 40 and 90%.
  • the selected tolerance can be about 5 to about 20%.
  • combustion characteristics in the combustion heater 109 can be fuel-rich, and flare can be observed in the combustion exhaust 114.
  • the hot standby mode is maintained by modulating a flow rate of the air stream 118 (e.g., using the air supply unit 116), so that the amount of H2 combusted in the combustion heater 109 is modulated or controlled (which can prevent the excessive H2 combustion and overheating of the combustion heater 109 and/or combustion-heated reformer 108).
  • FIG. 6M is a plot illustrating a system pressure (e.g., pressure in the incoming ammonia stream 104, reformate stream 120, reformer 108-110, heat exchanger 106, or ammonia fdter 122) over time during the startup mode, during the operation mode, and during the hot-standby mode for the ammonia reforming system 100.
  • the system pressure e.g., pressure in the incoming ammonia stream 104, reformate stream 120, reformer 108-110, heat exchanger 106, or ammonia fdter 122
  • the system pressure can be measured, for example, using at least one of the pressure sensors Pl -P10.
  • the flow control unit 524 can be configured to initiate the hot standby mode by increasing the system pressure.
  • the flow control unit 524 can initiate the flow of the reformate stream 120 to the combustion heater 109 when the pressure of the reformate stream 120 (before reaching the flow control unit 524) is equal to or greater than a threshold pressure.
  • the system pressure can increase.
  • the flow rate of the incoming ammonia stream 104 can be maintained within a selected tolerance of at least about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%.
  • the flow rate of the incoming ammonia stream 104 can be maintained within a selected tolerance of at most about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%.
  • the flow rate of the incoming ammonia stream 104 can be maintained within a selected tolerance between about 1 and 90, 5 and 80, 10 and 70, 20 and 60, 30 and 50, or 40 and 90%. In some instances, the flow rate of the incoming ammonia stream 104 can be maintained within a selected tolerance of about 5 to about 20%.
  • the flow control unit 524 can direct a portion or all of the reformate stream 120 to the combustion heater 109 (thereby transitioning to the hot standby mode).
  • the selected tolerance of the threshold pressure can be at least about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%.
  • the selected tolerance of the threshold pressure can be at most about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%.
  • the selected tolerance of the threshold pressure can be between about 1 and 90, 5 and 80, 10 and 70, 20 and 60, 30 and 50, or 40 and 90%. In some instances, the selected tolerance is about 5 to about 20%.
  • the hot standby mode can be terminated, and the operation mode can be initiated by reducing the system pressure (e.g., pressure in the incoming ammonia stream 104, reformate stream 120, reformer 108-110, heat exchanger 106, or ammonia filter 122).
  • system pressure e.g., pressure in the incoming ammonia stream 104, reformate stream 120, reformer 108-110, heat exchanger 106, or ammonia filter 122).
  • the system pressure can be reduced by increasing or initiating the H2 processing inlet flow 119 to the H2 processing module 535 (while maintaining the flow rate of the incoming ammonia stream 104 within a selected tolerance).
  • the flow rate of the incoming ammonia stream 104 can be maintained within a selected tolerance of at least about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%.
  • the flow rate of the incoming ammonia stream 104 can be maintained within a selected tolerance of at most about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%.
  • the flow rate of the incoming ammonia stream 104 can be maintained within a selected tolerance of between about 1 and 90, 5 and 80, 10 and 70, 20 and 60, 30 and 50, or 40 and 90%. In some instances, the flow rate of the incoming ammonia stream 104 can be maintained within a selected tolerance of about 5 to about 20%.
  • the flow control unit 524 can redirect a portion or all of the reformate stream 120 supplied to the combustion heater 109 back to the H2 processing module 535.
  • the selected tolerance of the threshold pressure can be at least about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%.
  • the selected tolerance of the threshold pressure can be at most about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%.
  • the selected tolerance of the threshold pressure can be between about 1 and 90, 5 and 80, 10 and 70, 20 and 60, 30 and 50, or 40 and 90%. In some instances, the selected tolerance of the threshold pressure is about 5 to about 20%.
  • the leftover reformate stream 536 can be supplied to the combustion heater 109 (to transition to the operation mode).
  • the flow rate of the incoming NH3 stream 104 can increase while transitioning from the hot standby mode to the operation mode. In some embodiments, the flow rate of the incoming NH3 stream 104 can increase after transitioning from the hot standby mode to the operation mode (to increase the electrical power output by the H2 processing module 535, and/or to supply more H2 to the industrial or chemical processes of the H2 processing module 535).
  • the ammonia reforming system 100 comprises two or more ammonia reformers 108-110, and the hot standby mode can be initiated using at least one ammonia reformer 108-110, and the remaining ammonia reformers 108-110 can be maintained in the operation mode.
  • combustion of the reformate stream 120 maintains a temperature in the combustion-heated reformer 108 within a target temperature range (for example, during the hot standby mode).
  • the reformate stream 120 is directed to the combustion heater 109 in thermal communication with the combustion-heated reformer 108, so that the combustion heater 109 receives substantially all of the reformate stream 120.
  • an amount (e.g., flow rate) of the ammonia stream 104 directed to the combustion-heated reformer 108 is controlled so that a first portion of the reformate stream 120 (combusted in the combustion heater 109) comprises substantially all of the reformate stream 120 (for example, during the hot standby mode).
  • an amount e.g., flow rate
  • a second portion of the reformate stream 120 e.g., the H2 processing flow 119 that is processed in the hydrogen processing module 535 is increased (e.g., when transitioning from the hot standby mode to the operation mode).
  • the amount (e.g., flow rate) of the ammonia stream 104 directed to the combustion-heated reformer 108 can be increased to a first target ammonia flow rate range (for example, during the hot standby mode).
  • a second portion of the reformate stream 120 is directed out of the combustion heater 109 (e.g., vented or flared, or provided to a heat recovery module, for example, during the hot standby mode). In some cases, at least about 30, 40, 50, 60, 70, 80, or 90% of the reformate stream 120 can be directed out of the combustion heater 109 during the hot standby mode.
  • At most about 30, 40, 50, 60, 70, 80, or 90% of the reformate stream 120 can be directed out of the combustion heater 109 during the hot standby mode. In some cases, of from about 30 to about 60%, of from about 40 to about 70%, of from about 50 to about 80%, or of from about 60 to about 90% of the reformate stream 120 is directed out of the combustion heater 109 during the hot standby mode.
  • the system pressure (e g., pressure in the incoming ammonia stream 104, reformate stream 120, reformer 108-110, heat exchanger 106, or ammonia filter 122) during the startup mode and hot standby mode can be higher than the system pressure during the operation mode.
  • the system pressure during the startup mode can be the same as (or different from) the system pressure during the hot standby mode.
  • the system pressure during the startup mode and hot standby mode can be higher than the system pressure during the operation mode.
  • the system pressure during the startup mode can be the same as the system pressure during the hot standby mode within a selected tolerance.
  • the selected tolerance can be at least about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%.
  • the selected tolerance can be at most about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%.
  • the selected tolerance can be between about 1 and 90, 5 and 80, 10 and 70, 20 and 60, 30 and 50, or 40 and 90%. In some instances, the selected tolerance is about 5% to about 20%.
  • the startup mode can comprise a system configuration similar or at least partially identical to the hot standby mode described with respect to FIG. 6L, for example, a portion or all of the reformate stream 120 can be supplied to the combustion heater 109 using one or more flow control units (e.g., flow control unit 524).
  • the startup mode can be transitioned to the operation mode by reducing the system pressure (e.g., pressure in the incoming ammonia stream 104, reformate stream 120, reformer 108-110, heat exchanger 106, or ammonia filter 122).
  • the system pressure can be reduced by increasing or initiating the H2 processing inlet flow 119 to the H2 processing module 535 using one or more flow control units (e.g., flow control unit 524). In some cases, the system pressure can be reduced by increasing or initiating the H2 processing inlet flow 119 to the H2 processing module 535 using one or more flow control units while maintaining the flow rate of the incoming ammonia stream 104 within a selected tolerance. In some cases, the leftover reformate stream 536 can be supplied to the combustion heater 109 to transition to the operation mode using one or more flow control units. In some cases, the flow control unit 524 can be used to transition the startup mode to the operation mode by directing the H2 processing inlet flow 119 to the H2 processing module 535.
  • flow control unit 524 can be used to transition the startup mode to the operation mode by directing the H2 processing inlet flow 119 to the H2 processing module 535.
  • the selected tolerance can be at least about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%.
  • the selected tolerance can be at most about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%.
  • the selected tolerance can be between about 1 and 90, 5 and 80, 10 and 70, 20 and 60, 30 and 50, or 40 and about 90%.
  • the selected tolerance is about 5% to about 20%.
  • the flow rate of the incoming NH3 stream 104 may be (or may not be) configured to be the same during the startup mode and the operation mode.
  • the flow rate of the incoming NH3 stream 104 during the startup mode can be configured to be within a selected tolerance of the flow rate of the incoming NH3 stream 104 during the operation mode.
  • the selected tolerance can be at least about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%.
  • the selected tolerance can be at most about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%.
  • the selected tolerance can be between about 1 and 90, 5 and 80, 10 and 70, 20 and 60, 30 and 50, or 40 and 90%.
  • the selected tolerance is about 5% to about 20%.
  • the flow rate of the incoming NH3 stream 104 can increase while transitioning from the startup mode to the operation mode. In some embodiments, the flow rate of the incoming NH3 stream 104 can increase after transitioning from the startup mode to the operation mode to produce higher electrical power from and/or to supply more H2 to the industrial or chemical processes in the H2 processing module 535.
  • a pressure of the reformate stream 120 is reduced when the reformate stream 120 is directed through the hydrogen processing module 535 (e.g., during the operation mode) compared to when the reformate stream is not directed through the hydrogen processing module 535 (e.g., during the startup mode or the hot standby mode).
  • a threshold amount of the reformate stream 120 when a threshold amount of the reformate stream 120 is directed to the hydrogen processing module 535, substantially all of the reformate stream 120 passes through the hydrogen processing module 535 (e.g., during the operation mode). In some cases, a threshold amount of the reformate stream 120 being directed to the hydrogen processing module 535 results in at least about 50, 55, 60, 65, 70, 75, 80, 85, 90, or 95% of the reformate stream 120 being directed to the hydrogen processing module 535. [00263] In some embodiments, an amount (e.g., flow rate) of the ammonia stream 104 directed to the combustion-heated reformer 108 is increased over a time period (beginning when the combustion-heated reformer 108 is heated to a target temperature range).
  • the amount of the ammonia stream 104 directed to the combustion-heated reformer 108 is increased to a first target ammonia flow rate range.
  • the reformate stream 120 is directed to a hydrogen processing module 535 when the first target ammonia flow rate range is reached.
  • the flow rate of the ammonia stream 104 is subsequently increased to a second target ammonia flow rate.
  • a first portion of the reformate stream 120 is combusted with oxygen, and the oxygen is provided in a substantially constant proportion relative to the hydrogen in the first portion of the reformate steam 120.
  • the substantially constant proportion can comprise a constant mass ratio within a selected tolerance (e.g., mass of hydrogen to mass of oxygen), a constant volume ratio within a selected tolerance (e.g., volume of hydrogen to volume of oxygen), or a constant molar ratio within a selected tolerance (e.g., moles of hydrogen to moles of oxygen).
  • the selected tolerance can comprise at most about 1, 5, 10, 20, 30, 40, or 50% of a target proportion.
  • the selected tolerance can comprise of from about 1 to 10%, of from about 5 to 10%, or of from about 5 to 15% of a target proportion.
  • FIG. 6N is a block diagram illustrating the control of temperature inside the combustion-heated reformer 108 and/or the combustion heater 109.
  • the combustion heater 109 can be maintained at a target temperature range, for example, of from about 300 °C to about 700 °C. In some instances, the combustion-heated reformer 108 and/or the combustion heater 109 can be maintained at a target temperature range of from about 400 °C to about 600 °C. In some instances, the combustion-heated reformer 108 and/or the combustion heater
  • 109 can be maintained at a target temperature range of at least about 300, 350, 400, 450, 500, 550, 600, 650, 700, 750, or 800 °C, and at most about 400, 450, 500, 550, 600, 650, 700, 750, 800, or 900 °C.
  • the target temperature ranges between about 300 and 900, 350 and 800, 400 and 750, 450 and 700, 500 and 650, or 550 and 600 °C. It is noted that the electrically-heated reformer
  • the electrical heater 111 can be maintained at the same target temperature range (or a different target temperature range) as the combustion-heated reformer 108 and/or the combustion heater 109.
  • the flow rate and/or pressure of the ammonia stream 104, the air stream 118 (comprising oxygen), the reformate stream 120, and/or the anode off-gas 128 can be modulated (e.g., using flow control units 517 and/or the flow control units FCU1-FCU10) to maintain the temperature of the combustion-heated reformer 108 and/or the combustion heater 109 within the temperature range.
  • the flow rate and/or pressure of the ammonia stream 104 can be increased (thereby providing more reactant for the endothermic ammonia reforming reaction which absorbs heat).
  • the flow rate and/or pressure of the air stream 118 can be decreased (thereby providing less oxygen for the combustion reaction).
  • the flow rate and/or pressure of the reformate stream 120 can be decreased (thereby providing less hydrogen for the combustion reaction).
  • the flow rate and/or pressure of the anode off-gas 128 can be decreased (thereby providing less hydrogen for the combustion reaction).
  • water can be added to the reformate stream 120 provided to the combustion heater 109 (e.g., so that the water absorbs heat in the combustion heater 109).
  • the water is stored in a dedicated storage tank, and water can be provided from the storage tank when required for decreasing the temperature in the combustion heater 109.
  • the water is sourced from the cathode off-gas 504 emitted by the fuel cell 124 (for example, by using a condenser or a filter).
  • the water is sourced from the combustion exhaust 114 (for example, using a condenser or filter) and stored in the dedicated storage tank.
  • the water is sourced externally (e g., fresh water, tap water, distilled water, deionized water, etc.).
  • the water is sourced from the anode off-gas 128.
  • the flow rate and/or pressure of the ammonia stream 104 can be decreased (thereby providing less reactant for the endothermic ammonia reforming reaction, which absorbs heat).
  • the flow rate and/or pressure of the air stream 118 can be increased (thereby providing more oxygen and more combustion of H2 for the combustion reaction).
  • the flow rate and/or pressure of the reformate stream 120 can be increased (thereby generating more hydrogen from the ammonia reforming process and providing more hydrogen for the combustion reaction).
  • the flow rate and/or pressure of the anode off-gas 128 can be increased (thereby providing more hydrogen for the combustion reaction).
  • the hydrogen consumption rate from the fuel cell 124 can be reduced (thereby providing more hydrogen to the anode off-gas 128 and to the combustion heater 109 for the combustion reaction). In some cases, to decrease the temperature of the combustion-heated reformer 108 and/or the combustion heater 109, the hydrogen consumption rate from the fuel cell 124 can be increased (thereby providing less hydrogen to the anode off-gas 128 and to the combustion heater 109 for the combustion reaction).
  • the flow rate and/or pressure of the air stream 118 can be increased (thereby providing a fuel-lean or air-rich condition, where N2 absorbs at least part of the combustion heat and lowers the flame or combustion temperature at the combustion heater 109).
  • the fuel-lean or air-rich condition is maintained during at least about 10, 20, 30, 40, 50, 60, 70, 80, or 90% of the operational time period of the operation mode. In some cases, the fuel-lean or air-rich condition is maintained during at most about 10, 20, 30, 40, 50, 60, 70, 80, or 90% of the operational time period of the operation mode.
  • the fuel-lean or air-rich condition is maintained of from about 30% to about 50%, of from about 40% to about 60%, of from about 50% to about 70%, of from about 60% to about 80%, or of from about 70% to about 90% of the operational time period of the operation mode.
  • an amount of ammonia that is reformed can be adjusted in response to a variable need for hydrogen.
  • a ship moving into a head-wind can require more hydrogen (e.g., to generate more power from fuel cell(s)) compared to when the ship moves with the wind.
  • a dynamic control method can comprise directing the ammonia stream to a reformer at an ammonia flow rate to produce a reformate stream comprising hydrogen and nitrogen.
  • the method can further comprise combusting a first portion of the reformate stream with oxygen to heat the reformer.
  • a second portion of the reformate stream can be processed in a hydrogen processing module (e.g., in a fuel cell).
  • One or more adjustments can be made based at least in part on a stimulus (e.g., the stimulus can be a user input or an automated input based on a measurement).
  • the adjustment(s) can include changing the ammonia flow rate (i.e., increasing or decreasing an amount of ammonia reformed).
  • the adjustment(s) can also include changing a percentage of the reformate stream that is the first portion of the reformate stream (i.e., increasing or decreasing the percentage combusted to heat the reformer).
  • the adjustment(s) can also include changing a percentage of the reformate stream that is the second portion of the reformate stream (i.e., increasing or decreasing the percentage that is sent to the hydrogen processing module).
  • the adjustment(s) can also include changing a percentage of the reformate stream that is directed out of a combustion heater (e.g., increasing or decreasing the percentage that is vented or flared at a combustion exhaust of the combustion heater or increasing or decreasing the percentage that is directed to a heat recovery module).
  • the dynamic control method further comprises changing an oxygen flow rate (i.e., increasing or decreasing the oxygen flow rate) used for combustion to heat the reformer.
  • the stimulus comprises a change in an amount of the hydrogen used by the hydrogen processing module (i.e., an increase or a decrease in an amount of hydrogen used by the hydrogen processing module).
  • the stimulus comprises a temperature of the reformer being outside of a target temperature range.
  • the stimulus comprises a change in an amount or concentration of ammonia in the reformate stream (i.e., an increase or a decrease in an amount or concentration of ammonia in the reformate stream).
  • the temperature of the combustion heater 109 and/or the reformers 108 and/or 110 can be increased (to increase ammonia conversion efficiency). In some cases, to increase the amount or concentration of ammonia in the reformate stream 120, the temperature of the combustion heater 109 and/or the reformers 108 and/or 110 can be decreased (to lower the ammonia conversion efficiency). [00279] In some cases, the ammonia conversion efficiency is maintained to be at least about 80, 85, 90, 93, 95, 97, 98, 99, or 99.9%.
  • the ammonia conversion efficiency is maintained to be at most about 80, 85, 90, 93, 95, 97, 98, 99, or 99.9%. In some cases, the ammonia conversion efficiency is maintained to be of from about 80 to about 90%, of from about 97 to about 99.9%, of from about 95 to about 99%, of from about 90 to about 95%, of from about 97 to about 99%, or of from about 85 to about 90%.
  • the amount or concentration of ammonia in the reformate stream 120 is maintained to be at least about 100, 500, 1000, 2000, 3000, 4000, 5000, 6000, 7000, 8000, 9000, 10000, 20000, 30000, 40000, or 50000 ppm. In some cases, the amount or concentration of ammonia in the reformate stream 120 is maintained to be at most about 100, 500, 1000, 2000, 3000, 4000, 5000, 6000, 7000, 8000, 9000, 10000, 20000, 30000, 40000, or 50000 ppm.
  • a target amount or concentration of ammonia in the reformate stream 120 is of from about 500 to about 2500 ppm, of from about 1000 to about 3000 ppm, of from about 2000 to about 4000 ppm, of from about 3000 to about 5000 ppm, of from about 4000 to about 6000 ppm, of from about 5000 to about 7000 ppm, of from about 6000 to about 8000 ppm, of from about 7000 to about 9000 ppm, of from about 8000 to about 10000 ppm, of from about 5000 to about 15000 ppm, or of from about 5000 to about 20000 ppm.
  • the ammonia filter 122 is used to filter residual or trace ammonia in the reformate stream 120 and produce a filtered reformate stream 123.
  • the amount of ammonia reformed, the amount of reformate directed to the hydrogen processing unit, the amount of reformate directed to the combustion heater to heat the reformer, and/or the amount of reformate that is directed out of the combustion heater can be changed so that: a temperature of the reformer is within a target temperature range; and/or at most about 10% of the reformate stream is directed out of the combustion heater (e.g., vented or flared out of the combustion heater).
  • the adjustment(s) are performed or achieved for at least 95% of an operational time period (e.g., of the ammonia reforming system 100).
  • An operational time period can begin when initiating the heating of a start-up reformer (such as electrically-heated reformer 110), when initiating the flow of the ammonia stream 104 from the storage tank 102, or when initiating the flow of the reformate stream 120 to a hydrogen processing module, and can end after the reformer 108-110, the heaters 109-111, and/or fuel cell 124 are shut down.
  • the operational time period is at least about 8 consecutive hours. In some cases, the operational time period is at least about 4, 8, 12, 16, 20, 24, 28, or 32 consecutive hours. In some cases, the operational time period is at most about 4, 8, 12, 16, 20, 24, 28, or 32 consecutive hours.
  • any suitable amount of the reformate stream can be vented or flared.
  • the amount of ammonia reformed to produce the reformate stream is in excess of an amount of ammonia reformed that is used by the hydrogen processing module(s) and used to heat the reformer(s). This excess amount can represent a waste of ammonia fuel when reformate is vented or flared.
  • operating without excess ammonia reformation results in a lack of a buffer for the reformate required for processing in the hydrogen processing module(s) and heating the reformer(s).
  • about 20%, 15%, 10%, 5%, 3%, or 1% of the reformate stream is vented or flared.
  • less than about 20%, 15%, 10%, 5%, 3%, or 1% of the reformate stream is vented or flared.
  • the vented reformate can be stored in a tank (e.g., to store buffer hydrogen) for later use.
  • the vented reformate stored in the tank can be combusted to heat one or more reformers or can be provided to a hydrogen processing module.
  • the systems and methods described herein can be efficiently and reliably operated. Efficient and reliable operation can include meeting an efficiency target for a suitably long period of time or suitably large fraction of a time period.
  • the adjustment(s) can be performed or achieved for at least about 5, 10, 15, 20, 25, 30, 35, 40, 45, 50, 55, 60, 65, 70, 75, 80, 85, 90, 95, or 100% of an operational time period.
  • the adjustment s) can be performed or achieved for at most about 5, 10, 15, 20, 25, 30, 35, 40, 45, 50, 55, 60, 65, 70, 75, 80, 85, 90, 95, or 100% of an operational time period.
  • the operational time period is at least about 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 15, 20, 25, 50, 100, 500, 1000, or 2000 hours. In some cases, the operational time period is at most about 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 15, 20, 25, 50, 100, 500, 1000, or 2000 hours.
  • the stimulus is based at least in part on an increase in an amount of the hydrogen used by the hydrogen processing module.
  • the increase in an amount of hydrogen is a projected increase in an amount of hydrogen used (in other words, a predicted increase in demand of hydrogen by the hydrogen processing module at a subsequent time) or a target increase in an amount of hydrogen.
  • the combustion heater e.g., vented or flared
  • the stimulus is based at least in part on a decrease in an amount of the hydrogen used by the hydrogen processing module.
  • the decrease in an amount of hydrogen is a projected decrease in an amount of hydrogen used (in other words, a predicted decrease in demand of hydrogen by the hydrogen processing module at a subsequent time) or a target decrease in an amount of hydrogen.
  • the combustion heater e.g., vented or flared
  • the stimulus comprises (a) a discontinued processing of hydrogen using the hydrogen processing module or (b) a fault or malfunction of the hydrogen processing module.
  • a plurality of hydrogen processing modules each comprise the hydrogen processing module, and the stimulus comprises at least one of (a) a discontinued processing of the hydrogen using one of the plurality of hydrogen processing modules and/or (b) a fault or malfunction in one of the plurality of hydrogen processing modules.
  • the percentage of the reformate stream that is the second portion of the reformate stream (processed by the hydrogen processing module) is changed to about zero percent in response to the stimulus.
  • substantially none of the reformate stream is directed to the hydrogen processing module in response to the stimulus.
  • substantially all of the reformate stream is directed to at least one of the combustion-heated reformer and/or a combustion heater in thermal communication with the combustion-heated reformer in response to the stimulus.
  • a portion of the reformate stream is directed out of the combustion heater (e.g., vented, flared, or sent to a heat recovery module) in response to the stimulus.
  • the combustion heater e.g., vented, flared, or sent to a heat recovery module
  • the stimulus is detected using a sensor. In some cases, the stimulus is communicated to a controller. In some cases, the adjustment(s) are performed with the aid of a programmable computer or controller. In some cases, the adjustment(s) are performed using a flow control unit. [00295] In some cases, the stimulus is a pressure. In some cases, the pressure is increased in response to decreasing a flow rate to the hydrogen processing module. In some cases, the pressure is a pressure of the reformate stream.
  • the temperature inside the combustion-heated reformer 108 and/or the combustion heater 109 can be controlled using PID control, which entails a control loop mechanism employing feedback.
  • a PID controller can automatically apply an accurate and responsive correction to a control function.
  • the PID controller e.g., controller 200
  • one or more sensors e.g., temperature sensors T1-T10
  • T1-T10 temperature sensors
  • the temperature inside the combustion-heated reformer 108 and/or the combustion heater 109 can be controlled using Proportional (P), Proportional Integral (PI), or Proportional Derivative (PD) control, which entails a control loop mechanism employing feedback.
  • P Proportional
  • PI Proportional Integral
  • PD Proportional Derivative
  • a P, PI, or PD controller can automatically apply an accurate and responsive correction to a control function.
  • the P, PI, or PD controller e.g., controller 200
  • one or more sensors e.g., temperature sensors T1-T10 and/or time sensors
  • the PID controller can continuously calculate an error value (e(t)) as the difference between a desired setpoint (SP) and a measured process variable (PV), and can apply a correction based on proportional, integral, and derivative terms (denoted P, I, and D respectively).
  • the P, PI, or PD controller can apply a correction based on one or two of proportional, integral, and derivative terms (denoted P, I, and D respectively), accordingly.
  • proportional control can be performed by (a) calculating a temperature difference between a temperature measured in the combustion-heated reformer 108 or the combustion heater 109 and a set-point temperature within a target temperature range, and (b) (i) changing the ammonia flow rate (e.g., the flow rate of the ammonia stream 104) by an amount that is based at least in part on the temperature difference, (ii) changing the oxygen flow rate (e.g., increasing or decreasing the flow rate of the air stream 118) by an amount that is based at least in part on the temperature difference, (iii) changing a percentage of the reformate stream 120 that is processed by the H2 processing module 535 by an amount that is based at least in part on the temperature difference, (iv) changing a percentage of the reformate stream 120 that is combusted in the combustion heater by an amount that is based at least in part on the temperature difference, or (v) changing a percentage of the reformate stream 120 that is directed out of the combustion heater
  • the ammonia flow rate, the oxygen flow rate, the percentage of the reformate stream that is processed by the H2 processing module, the percentage of the reformate stream that is combusted in the combustion heater, and/or the percentage of the reformate stream that is directed out of the combustion heater can be changed by a proportional factor that is proportional to the temperature difference.
  • the value of the proportional factor can be greater when the temperature difference is greater. For example, for a set point temperature of 450 °C, the proportional factor can be greater for a measured temperature of 350 °C (a temperature difference of 100 °C) compared to a measured temperature of 400 °C (a temperature difference of 50 °C).
  • the proportional factor is different for each of changing the ammonia flow rate, the oxygen flow rate, the percentage of the reformate stream that is processed by the H2 processing module, the percentage of the reformate stream that is combusted in the combustion heater, and/or the percentage of the reformate stream that is directed out of the combustion heater.
  • calculating the temperature difference can be repeated at a subsequent time point to obtain a subsequent temperature difference, and changing the ammonia flow rate, the oxygen flow rate, the percentage of the reformate stream that is processed by the H2 processing module, the percentage of the reformate stream that is combusted in the combustion heater, and/or the percentage of the reformate stream that is directed out of the combustion heater can be repeated to further change the ammonia flow rate, the oxygen flow rate, the percentage of the reformate stream that is processed by the H2 processing module, the percentage of the reformate stream that is combusted in the combustion heater, and/or the percentage of the reformate stream that is directed out of the combustion heater (by an amount that is proportional to the subsequent temperature difference).
  • the aforementioned steps can be repeated until the measured temperature is within the target temperature range.
  • integral control can be performed.
  • the temperature measured in the reformer 108 or combustion heater 109 can be a first temperature that is measured at a first time point
  • the integral control can be performed by (a) measuring a second temperature of the reformer 108 or the combustion heater 109 at second time point subsequent to the first time point, (b) calculating a time period between the first time point and the second time point, (c) calculating a temperature difference between first temperature and the second temperature, and (d) changing one or more of the ammonia flow rate, the oxygen flow rate, the percentage of the reformate stream that is processed by the H2 processing module, the percentage of the reformate stream that is combusted in the combustion heater, and/or the percentage of the reformate stream that is directed out of the combustion heater (by an amount that is based at least in part on the time period and the temperature difference).
  • the aforementioned steps are repeated until the measured temperature is within the target temperature range.
  • FIG. 60 is a block diagram illustrating the flaring or venting 525 of hydrogen in the combustion exhaust 114 of the combustion heater 109 to depressurize the reformers 108-110.
  • the hydrogen can be flared in the combustion exhaust 114 of the combustion heater 109 by modulating a stochiometric ratio of (1) the hydrogen in the reformate stream 120 supplied to the combustion heater 109 to (2) the oxygen in the air stream 118 supplied to the combustion heater 109.
  • Modulating the stochiometric ratio can comprise modulating the flow rate and/or pressure of the air stream 118 supplied to the combustion heater 109 to maintain a fuel rich or air lean condition of the combustion reaction (in other words, the hydrogen can be in stoichiometric excess).
  • modulating the stoichiometric ratio can comprise modulating the flow rate and/or pressure of the reformate stream 120 supplied to the combustion heater 109 to maintain the fuel rich condition of the combustion reaction.
  • a temperature of the combustion heater 109 can be maintained to be less than a threshold temperature by modulating the flow rate and/or pressure of the air stream 118 supplied to the combustion heater 109 (e g., to enable a lower temperature catalytic combustion of the hydrogen).
  • the flow of the air stream 118 to the combustion heater 109 can be reduced or shut off completely, which can decrease the temperature of the combustion heater 109 to less than a combustion temperature, and therefore the hydrogen can be vented (instead of combusted).
  • an air-to-fuel ratio i.e., the air to fuel ratio divided by the stoichiometric air to fuel ratio, e.g., where an air-to-fuel ratio of 1 is the stoichiometric air to fuel ratio
  • an air-to-fuel ratio during the fuel-rich or air-lean combustion is about 0.2 to about 0.99.
  • the air-to-fuel ratio during the fuel-rich or air-lean combustion is at least about 0.2, 0.3, 0.4, 0.5, 0.6, 0.7, 0.8, 0.9, or 0.99.
  • the air-to-fuel ratio during the fuel-rich or air-lean combustion is at most about 0.2, 0.3, 0.4, 0.5, 0.6, 0.7, 0.8, 0.9, or 0.99. In some cases, the air-to-fuel ratio during the fuel-rich or air-lean combustion is about 0.2 to about 0.4, about 0.3 to about 0.5, about 0.4 to about 0.6, about 0.5 to about 0.7, about 0.6 to about 0.8, about 0.7 to about 0.9, or about 0.8 to about 0.99.
  • the air-to-fuel ratio of the fuel-rich or air-lean combustion during the operation mode is about 0.5 to about 0.99. In some cases, an air-to-fuel ratio of the fuel-rich or airlean combustion during the operation mode is at least about 0.5, 0.6, 0.7, 0.8, 0.9, or 0.99. In some cases, the air-to-fuel ratio of the fuel-rich or air-lean combustion during the operation mode is at most about 0.5, 0.6, 0.7, 0.8, 0.9, or 0.99. In some cases, the air-to-fuel ratio of the fuel-rich or air-lean combustion during the operation mode is about 0.5 to about 0.7, about 0.6 to about 0.8, about 0.7 to about 0.9, or about 0.8 to about 0.99.
  • the air-to-fuel ratio of the fuel-rich or air-lean combustion during the startup mode and/or hot standby mode is about 0.2 to about 0.8. In some cases, the air-to-fuel ratio of the fuel-rich or air-lean combustion during the startup mode and/or hot standby mode is at least about 0.2, 0.3, 0.4, 0.5, 0.6, 0.7, or 0.8. In some cases, the air-to-fuel ratio of the fuel-rich or air-lean combustion during the startup mode and/or the hot standby mode is at most about 0.2, 0.3, 0.4, 0.5, 0.6, 0.7, or 0.8.
  • the air-to-fuel ratio of the fuel-rich or air-lean combustion during the startup mode and/or the hot standby mode is about 0.2 to about 0.4, about 0.3 to about 0.5, about 0.4 to about 0.6, about 0.5 to about 0.7, or about 0.6 to about 0.8.
  • the combustion reaction in the combustion heater 109 can comprise an air-rich or fuel-lean condition (i.e., so that oxygen is in stoichiometric excess).
  • the fuel-lean combustion can increase thermal or energy efficiency of the reforming system 100, since a substantial majority, or all, of the combustion fuel (e.g., the reformate stream 120) is consumed.
  • the fuel-lean combustion can enable a small amount (or none) of the H2 at the combustion exhaust 114 to be flared or vented, which can reduce waste H2 since flared or vented H2 can not be used for power generation, or for chemical or industrial processes.
  • the fuel-lean combustion can prevent flammability of the combustion exhaust 114, and therefore can enable a safe operation of the ammonia reforming system 100.
  • the air-rich or fuel -lean combustion in the combustion heater 109 is maintained during at least about 10, 20, 30, 40, 50, 60, 70, 80, or 90% of the operational time period of the operation mode. In some cases, the air-rich or fuel-lean combustion in the combustion heater 109 is maintained during at most about 10, 20, 30, 40, 50, 60, 70, 80, or 90% of the operational time period of the operation mode. In some cases, the air-rich or fuel-lean combustion in the combustion heater 109 is maintained during substantially all of the operational time period of the operation mode.
  • the air-rich or fuel-lean combustion in the combustion heater 109 is maintained during of from about 10% to about 30%, of from about 20% to about 40%, of from about 30% to about 50%, of from about 40% to about 60%, of from about 50% to about 70%, of from about 60% to about 80%, or of from about 70% to about 90% of the operational time period of the operation mode.
  • the air-rich or fuel-lean combustion in the combustion heater 109 is maintained during at least about 10, 20, 30, 40, 50, 60, 70, 80, or 90% of the operational time period of the startup mode and/or hot standby mode. In some cases, the air-rich or fuel-lean combustion in the combustion heater 109 is maintained during at most about 10, 20, 30, 40, 50, 60, 70, 80, or 90% of the operational time period of the startup mode and/or hot standby mode. In some cases, the airrich or fuel-lean combustion in the combustion heater 109 is maintained during substantially all of the operational time period of the startup mode and/or hot standby mode.
  • increasing the air flow rate provided to the combustion heater 109 can decrease the temperature of the reformer 108 and/or combustion heater 109 (e.g., by providing more air (O2 and/or N2) to absorb heat from the combustion reaction).
  • decreasing the air flow rate provided to the combustion heater 109 can increase the temperature of the reformer 108 and/or combustion heater 109 (e.g., by providing less air to absorb heat from the combustion reaction).
  • the air flow rate provided to the combustion heater 109 is modulated to control the temperature of the reformer 108 and/or combustion heater 109.
  • an air-to-fuel ratio i.e., the air to fuel ratio divided by the stoichiometric air to fuel ratio, for example, where an air-to-fuel ratio of 1 is the stoichiometric air to fuel ratio
  • the air-fuel ratio is at least about 1.05, 1.1, 1.2, 1.3, 1.4, 1.5, 1.6, 1.7, 1.8, 1.9, 2, 2.5, 3, 3.5, 4, 4.5, or 5.
  • the air-fuel ratio is at most about 1.05, 1.1, 1.2, 1.3, 1.4, 1.5, 1.6, 1.7, 1.8, 1.9, 2, 2.5, 3, 3.5, 4, 4.5, or 5. In some cases, during the air-rich or fuel-lean combustion in the combustion heater 109, the air-fuel ratio is about 1.05 to about 1.3, about 1.1 to about 1.5, about 1.2 to about 1.7, about 1.3 to about 1.9, about 1.4 to about 2, about 1.5 to about 2, about 1.6 to about 3, about 2 to about 4, or about 3 to about 5.
  • the air-to-fuel ratio of an air-rich or fuel lean combustion during the operation mode is about 1.05 to about 3. In some cases, the air-to-fuel ratio of the air-rich or fuel lean combustion during the operation mode is at least about 1.05, 1.1, 1.2, 1.3, 1.4, 1.5, 1.6, 1.7, 1.8, 1.9, 2, 2.5, 3. In some cases, the air-to-fuel ratio of the air-rich or fuel -lean combustion during the operation mode is at most about 1.05, 1.1, 1.2, 1.3, 1.4, 1.5, 1.6, 1.7, 1.8, 1.9, 2, 2.5, 3.
  • the air- to-fuel ratio of the air-rich or fuel-lean combustion during the operation mode is about 1.05 to about 1.3, about 1.1 to about 1.5, about 1.2 to about 1.7, about 1.3 to about 1.9, about 1.4 to about 2, about
  • the air-to-fuel ratio of the air-rich or fuel-lean combustion during the startup mode and/or the hot standby mode is about 1 to about 5. In some cases, the air-to-fuel ratio of the air-rich or fuel-lean combustion during the startup mode and/or hot standby mode is at least about 1.05, 1.1, 1.2, 1.3, 1.4, 1.5, 1.6, 1.7, 1.8, 1.9, 2, 2.2, 2.4, 2.6, 2.8, 3, 3.5, 4, 4.5, or 5.
  • the air-to-fuel ratio of the air-rich or fuel-lean combustion during the startup mode and/or hot standby mode is at most about 1.05, 1.1, 1.2, 1.3, 1.4, 1.5, 1.6, 1.7, 1.8, 1.9, 2, 2.2, 2.4, 2.6, 2.8, 3, 3.5, 4, 4.5, or 5.
  • the air-fuel ratio of the air-rich or fuel-lean combustion during the startup mode and/or hot standby mode is about 1.05 to about 1.3, about 1.1 to about 1.5, about 1.2 to about 1.7, about 1.3 to about 1.9, about 1.4 to about 2, about 1.5 to about 2, about 1.6 to about 2, about 2 to about 2.5, about 2.2 to about 2.7, about 2.4 to about 2.9. about 2.6 to about 3.1, about 3 to about 3.5, about
  • the combustion in the combustion heater 109 can extinguish, and therefore can require reignition.
  • the reignition can be performed, for example, using an ignition source such as a spark plug or a heating element.
  • the reignition can be based at least in part on a temperature of the combustion exhaust 114 being less than a threshold combustion exhaust temperature (indicating a lack of flame in the combustion heater 109), on an oxygen concentration in the combustion exhaust 114 being greater than a threshold combustion exhaust oxygen concentration (indicating unreacted oxygen leaving the combustion heater 109), or on a hydrogen concentration in the combustion exhaust 114 being greater than a threshold hydrogen concentration (indicating unreacted hydrogen leaving the combustion heater 109).
  • the threshold combustion exhaust temperature is at least about 300, 350, 400, 450, 500, 550, 600, 650, 700, 750, 800, 850, or 900 °C. In some cases, the threshold combustion exhaust temperature is at most about 300, 350, 400, 450, 500, 550, 600, 650, 700, 750, 800, 850, or 900 °C. In some cases, the threshold combustion exhaust oxygen concentration is at least about 1, 3, 5, 8, 10, 15, 20, or 25% by volume or mass. In some cases, the threshold combustion exhaust oxygen concentration is at most about 1, 3, 5, 8, 10, 15, 20, or 25% by volume or mass.
  • the combustion heater 109 can combust ammonia to heat the combustion-heated reformer 108.
  • at least part of the ammonia stream 104 can be directed from the storage tank 102 to the combustion heater 109 to combust the ammonia stream 104 to heat the reformer 108.
  • an additional ammonia stream (separate from the ammonia stream 104) can be directed from an additional storage tank (separate from the storage tank 102) to the combustion heater 109 to combust the additional ammonia stream to heat the reformer 108.
  • a pure ammonia stream (i.e., comprising only ammonia) can be directed to the combustion heater 109 for combusting.
  • an ammonia stream mixed with a pilot fuel i.e., a promoter fuel to facilitate combustion
  • the pilot fuel can comprise a lower flash point compared to ammonia and can comprise a higher flame speed when combusted compared to ammonia.
  • the pilot fuel can comprise hydrogen (for example, the hydrogen in the reformate stream 120).
  • the pilot fuel is a hydrocarbon (that can be, for example, generated using renewable energy).
  • the reformate stream 120 can instead comprise ammonia for combustion in the combustion heater 109. Therefore, is also contemplated that the amount of ammonia for combustion can be controlled (e.g., the flow rate of the ammonia can be increased or decreased) based on a stimulus (for example, the temperature of the reformer 108 and/or the combustion heater 109).
  • FIGS. 6P-6R are block diagrams illustrating pressure drop elements 526a-c configured to maintain an even distribution of fluid pressure to a plurality of components of the ammonia reforming system 100.
  • the pressure drop elements 526a-c can comprise, for example, restricted orifices or apertures positioned in fluid lines and/or manifolds of the ammonia reforming system 100.
  • the pressure drop element 526a can be smaller in size (e g., the radius of an orifice or aperture) than the pressure drop element 526b, and in turn, the pressure drop element 526b can be smaller in size than the pressure drop element 526c.
  • a pressure drop of the pressure drop element 526a can be different from a pressure drop of the pressure drop elements 526b and/or 526c. In some instances, a pressure drop of the pressure drop element 526a can be same as a pressure drop of the pressure drop elements 526b and/or 526c within a selected tolerance. The selected tolerance can be less than 20%.
  • pressure drop elements 526a-c can be configured to distribute the ammonia stream 104 evenly to multiple reformers 108-110 (or sets of reformers 108- 110). As shown in FIG. 6Q, pressure drop elements 526a-c can be configured to distribute the reformate stream 120 evenly to multiple combustion heaters 109. As shown in FIG. 6R, pressure drop elements 526a-c can be configured to distribute the reformate stream 120 evenly to multiple fuel cells 124.
  • the one or more pressure drop elements illustrated in the FIGS. 6P-R can distribute a flow rate of fluid to each of the reformers 108-110, combustion heaters 109, or fuel cells 124 within a selected tolerance of a target flow rate.
  • the selected tolerance is at least about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100%, and at most about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100% of the target flow rate.
  • the selected tolerance can be between about 1 and 100, 5 and 90, 10 and 80, 20 and 70, 30 and 60, or 40 and 50%.
  • each of the three reformers receives flow rate of about 90 to about 110 slpm.
  • pressure drops across the one or more pressure drop elements can be changed or adjusted manually or electronically (e.g., with voltage and/or current signals).
  • one or more pressure drop elements, one or more valves, one or more pumps, one or more regulators, or any combination of thereof can adjust or maintain a flow rates to the one or more fuel cells 124 within a selected tolerance of a target flow rate.
  • the selected tolerance is at least about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100%, and at most about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100%.
  • the selected tolerance can be between about 1 and 100, 5 and 90, 10 and 80, 20 and 70, 30 and 60, or 40 and 50%. In some cases, the selected tolerance is less than about 20%.
  • the one or more pressure drop elements illustrated in FIGS. 6P-R can be at least partly replaced by (or can comprise additional) one or more flow control units comprising one or more pumps, one or more check valves, one or more one-way valves, one or more three-way valves, one or more restrictive orifices, one or more valves, one or more flow regulators, one or more pressure regulators, one or more back pressure regulators, one or more pressure reducing regulators, one or more back flow regulators, one or more flow meters, one or more flow controllers, or any combination thereof.
  • the one or more flow control units can be controlled manually, automatically, or electronically.
  • the one or more flow control units can maintain the desired flow rate distribution to the one or more reformers, one or more combustion heaters, or one or more fuel cells.
  • the flow rate distribution can be even (or uneven) depending on predetermined flow processing capabilities of the one or more reformers, one or more combustion heaters, or one or more fuel cells.
  • the one or more flow control units can distribute the flow to the reformers 108-110, combustion heaters 109, or fuel cells 124 within a selected tolerance of a target flow rate.
  • the selected tolerance is at least about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100%, and at most about 1, 5, 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100%.
  • the selected tolerance can be between about 1 and 100, 5 and 90, 10 and 80, 20 and 70, 30 and 60, or 40 and 50%.
  • the target flow rate to one reformer of a set of three reformers is about 100 slpm (standard liters per minute) with a selected tolerance of about 10%, each of the three reformers receives a flow rate of about 90 to about 110 slpm.
  • the selected tolerance is less than about 20%.
  • FIG. 6S is a block diagram illustrating a hydrogen separation device 527 configured to separate hydrogen from the reformate stream 120.
  • the hydrogen separation device 527 can comprise a retentate chamber 528, a membrane 529, and a permeate chamber 530.
  • the hydrogen separation device 527 can increase the hydrogen purity of the reformate stream 120, which can increase the hydrogen consumption rate or output voltage of the fuel cell 124 when the high hydrogen purity reformate stream 120 is provided to the fuel cell 124.
  • the membrane 529 can comprise platinum (Pt), palladium (Pd), vanadium (V), niobium (Nb), tantalum (Ta), an alloy thereof, or any combination thereof, although the present disclosure is not limited thereto.
  • the permeate stream 531 (comprising the separated hydrogen, e.g., 99% or more hydrogen) can exit the hydrogen separation device 527 (via an outlet in the permeate chamber 530) and be provided to the fuel cell 124 for electricity generation.
  • the retentate stream 532 comprising at least portion of the hydrogen from the reformate stream 120 can be supplied to the combustion heater 109 as a combustion fuel.
  • FIG. 6T is a block diagram illustrating an internal combustion engine (ICE) 533 configured to combust the reformate stream 120 (i.e., combust the hydrogen therein) to generate mechanical power (or electrical power).
  • the ICE 533 can comprise a reciprocating piston engine or a gas turbine.
  • the ICE 533 can be configured to combust the reformate stream 120 (e.g., such that hydrogen is the sole or primary fuel).
  • the reformate stream 120 can be co-combusted or co-fired with an additional fuel (e.g., auxiliary or secondary fuel), such that the hydrogen in the reformate stream 120 is advantageously provided as a pilot fuel (promoter fuel) that facilitates combustion of the additional fuel in the ICE 533.
  • additional fuel e.g., auxiliary or secondary fuel
  • the additional fuel can comprise ammonia (which, due to its low flame speed and high ignition chamber, is difficult to burn without a promoter fuel).
  • the additional fuel comprising the ammonia can be provided from the storage tank 102 (described with respect to FIGS. 1A-4B) to be co-combusted with the reformate stream 120 in the ICE 533.
  • the additional ammonia can be provided from a dedicated secondary storage tank that is separate from the storage tank 102.
  • the additional fuel comprises a hydrocarbon fuel, for example, gasoline, diesel, biodiesel, methane, biomethane, methanol, biomethanol, fatty-acid methyl ester (FAME), hydro-treated renewable diesel (HVO), Fischer-Tropsch (FT) diesel, marine oil, heavy fuel oil (HFO), marine diesel oil (MDO), and/or dimethyl ether (DME).
  • a hydrocarbon fuel for example, gasoline, diesel, biodiesel, methane, biomethane, methanol, biomethanol, fatty-acid methyl ester (FAME), hydro-treated renewable diesel (HVO), Fischer-Tropsch (FT) diesel, marine oil, heavy fuel oil (HFO), marine diesel oil (MDO), and/or dimethyl ether (DME).
  • a hydrocarbon fuel for example, gasoline, diesel, biodiesel, methane, biomethane, methanol, biomethanol, fatty-acid methyl ester (FAME), hydro-treated renewable diesel (HVO), Fischer
  • the additional fuel comprises a synthetic renewable fuel (e.g., scalable zero emissions fuel (SZEF)) produced using at least one of carbon capture, renewable electricity, or renewable hydrogen.
  • a synthetic renewable fuel e.g., scalable zero emissions fuel (SZEF)
  • SZEF scalable zero emissions fuel
  • a heat exchanger 534 can be utilized to transfer heat from an exhaust of the ICE 533 to the combustion heated reformer 108 and/or the electrically-heated reformer 110. This heat transfer can increase the overall energy efficiency of the ammonia reforming system 100.
  • FIGS. 7-11C are a flow charts illustrating various methods of initiating ammonia reforming (e.g., startup processes for the ammonia reforming system 100). It is noted that the method steps described with respect to FIGS. 7-11C can be performed using a controller (for example, by executing program instructions using the controller 200) in response to a stimulus.
  • the stimulus can comprise a manual input (e.g., user input), and/or an automated input.
  • the automated input can comprise a sensor measurement (e g., measured by sensors P1-P10, Tl-Tl l, FM1-FM11, and AC1- AC10) being greater than or less than a threshold (e.g., threshold temperature, threshold pressure, threshold flow rate, and so on).
  • a threshold e.g., threshold temperature, threshold pressure, threshold flow rate, and so on.
  • the controller can actuate a flow control unit (e.g., open or close a valve), and direct a fluid (e.g., ammonia stream 104, reformate stream 120, air stream 118, anode off-gas 128) by increasing or decreasing a flow rate of the fluid (in response or based on the manual input or the automated input).
  • a fluid e.g., ammonia stream 104, reformate stream 120, air stream 118, anode off-gas 128) by increasing or decreasing a flow rate of the fluid (in response or based on the manual input or the automated input).
  • the controller can increase or decrease heating power to the electrical heater (e.g., electrical heater 111) (in response or based on the manual input or the automated input).
  • the controller can increase or decrease the load at the fuel cell (e.g., fuel cell 124) (in response or based on the manual input or the automated input).
  • FIG. 7 is a flow chart illustrating a method of initiating ammonia reforming 600.
  • an electrically-heated reformer e.g., electrically-heated reformer 110
  • a target temperature within a target temperature range, for example, about 400 - about 600 °C.
  • the electrically-heated reformer can be heated by initiating power supply to the electrical heater.
  • ammonia e.g., incoming ammonia stream 104
  • ammonia can be directed to the electrically-heated reformer, and ammonia can be reformed using NH3 reforming catalysts in the electrically-heated reformer to generate hydrogen and nitrogen (e.g., an H2/N2 mixture, reformate stream 120).
  • air e.g., air stream 118
  • a combustion reaction e.g., in the combustion heater 109
  • the electrically-heated reformer can be optionally turned off or reduced (e.g., after the combustion-heated reformer reaches a target temperature range).
  • the electrically- heated reformer can be turned off or reduced by reducing the power supply to the electrical heater.
  • step 605 the flow rate of the incoming ammonia flow can be increased to a predefined flow rate (e.g., to generate a target flow rate of H2/N2 mixture in the reformate stream).
  • step 601 and step 602 can be performed in sequence or in parallel.
  • at least two steps in steps 601-605 can be performed in sequence or in parallel.
  • step 605 Once step 605 is performed, and self-sustained auto-thermal reforming is maintained (i.e., at a steady-state condition, or predetermined operational condition), the ammonia flow rate can be further increased above a predefined rate depending on operating requirements (e.g., fuel cell output power, electrically- heated reformer temperature(s), combustion-heated reformer temperature(s), reactor pressure(s), ammonia flowrate, etc.) while maintaining auto-thermal reforming.
  • Step 604 can be executed or unexecuted depending on combustion-heated reformer temperature and ammonia conversion efficiency.
  • the electrically- heated reformer can provide the majority or all of the hydrogen and nitrogen in the reformate stream (e.g., greater than about 50% of the hydrogen and nitrogen by volume).
  • FIG. 8 is a flow chart illustrating a method of initiating ammonia reforming 700.
  • an electrically-heated reformer e.g., electrically-heated reformer 110
  • a target temperature within a target temperature range, for example, about 400 - about 600 °C.
  • the electrically-heated reformer can be heated by initiating power supply to the electrical heater.
  • ammonia e.g., incoming ammonia stream 104
  • ammonia can be directed to the electrically-heated reformer, and ammonia can be reformed using NH3 reforming catalysts in the electrically-heated reformer to generate hydrogen and nitrogen (e.g., an H2/N2 mixture, reformate stream 120).
  • the reformate stream can be reacted with the air in a combustion reaction (in the combustion heater 109) to heat the combustion-heated reformer (e.g., combustion-heated reformer 109).
  • An ignition device e.g., spark plug
  • the flow rate of the air to the combustion heater can be adjusted to increase the temperature of the combustion-heated reformer. In some instances, the flow rate of the air is modulated to maintain a target temperature ramp rate of the combustion-heated reformer.
  • ammonia e.g., incoming ammonia stream 104
  • NH3 reforming catalysts in the combustion-heated reformer to generate hydrogen and nitrogen (e.g., an H2/N2 mixture, reformate stream 120).
  • the combustion-heated reformer can fluidically communicate in series or in parallel with the electrically-heated reformer (e.g., as shown in FIG. 13).
  • heating the electrically-heated reformer can be optionally turned off or reduced (e g., after the combustion-heated reformer reaches a target temperature range).
  • the electrically-heated reformer can be turned off or reduced by reducing the power supply to the electrical heater.
  • the flow rate of the incoming ammonia stream can be incrementally increased to a predefined flow rate (e.g., to generate a target flow rate of H2/N2 mixture in the reformate stream). Simultaneously, the flow rate of the air stream (to the combustion heater) can be increased. By simultaneously increasing both the flow rate of the incoming ammonia stream and the flow rate of the air stream, the combustion-heated reformer can be maintained in a target temperature range.
  • the reformate generated by the combustion-heated reformer (and optionally the reformate generated by the electrically-heated reformer) can be directed (e.g., using one or more flow control units, pumps, valves, and/or regulators) to the fuel cell (e.g., fuel cell 124).
  • the fuel cell e.g., fuel cell 124
  • the fuel cell can generate an electrical power output (to supply to an electrical load, e.g., an electrical grid, an electrical battery, or a motor for a vehicle).
  • an electrical load e.g., an electrical grid, an electrical battery, or a motor for a vehicle.
  • the anode off-gas from the fuel cell can be optionally directed to the combustion heater to be combusted.
  • a three-way valve can direct the reformate from (1) being provided directly to the combustion heater to (2) being provided to the fuel cell (and, subsequently, the anode off-gas can be provided to the combustion-heater).
  • the step 710 is performed before the step 709, or can be executed simultaneously.
  • the flow rate of the incoming ammonia stream and the flow rate of the air stream can be adjusted to maintain the target temperature in the combustion-heated reformer.
  • the ammonia reforming method (or system) can achieve a predetermined operational condition (steady-state condition)
  • step 706 can be executed or unexecuted based on the combustion- heated reformer temperature.
  • step 706 can be unexecuted based on the combustion- heated reformer temperature being less than a predetermined threshold temperature.
  • Step 709 can be executed any time after step 708.
  • FIG. 9 is a flow chart illustrating a method of initiating ammonia reforming 800.
  • an electrically-heated reformer e.g., electrically-heated reformer 110
  • a target temperature within a target temperature range, for example, about 400 - about 600 °C.
  • the electrically-heated reformer can be heated by initiating power supply to the electrical heater.
  • ammonia e.g., incoming ammonia stream 104
  • ammonia can be directed to the electrically-heated reformer, and ammonia can be reformed using NH3 reforming catalysts in the electrically-heated reformer to generate hydrogen and nitrogen (e.g., an H2/N2 mixture, reformate stream 120).
  • the anode off-gas from the fuel cell can be optionally directed to a combustion heater to be combusted with air (e.g., air stream 118).
  • An ignition device e.g., spark plug
  • the flow rate of the air to the combustion heater can be adjusted to increase the temperature of the combustion-heated reformer.
  • the fuel cell can generate an electrical power output (to supply to an electrical load, e.g., a motor for a vehicle).
  • an electrical load e.g., a motor for a vehicle.
  • the step 805 can be performed before the step 804 or can performed simultaneously.
  • ammonia e.g., incoming ammonia stream 104
  • NH3 reforming catalysts in the combustion-heated reformer to generate hydrogen and nitrogen (e.g., an H2/N2 mixture, reformate stream 120).
  • the combustion-heated reformer can fluidically communicate in series or in parallel with the electrically-heated reformer (e.g., as shown in FIG. 13).
  • heating the electrically-heated reformer can be optionally turned off or reduced (e.g., after the combustion-heated reformer reaches a target temperature range).
  • the electrically-heated reformer can be turned off or reduced by reducing the power supply to the electrical heater.
  • the flow rate of the incoming ammonia stream can be incrementally increased to a predefined flow rate (e.g., to generate a target flow rate of H2/N2 mixture in the reformate stream). Simultaneously, the flow rate of the air stream (to the combustion heater) can be increased. By simultaneously increasing both the flow rate of the incoming ammonia stream and the flow rate of the air stream, the combustion-heated reformer can be maintained in a target temperature range. [00372] At step 809, optionally, the flow rate of the incoming ammonia stream and the flow rate of the air stream can be further adjusted to maintain the target temperature in the combustion- heated reformer.
  • the ammonia reforming method (or system) can achieve a predetermined operational condition (steady-state condition)
  • step 807 can be executed or unexecuted based on the combustion- heated reformer temperature.
  • step 807 can be unexecuted based on the combustion- heated reformer temperature being less than a predetermined threshold temperature.
  • Step 805 can be executed any time after step 803.
  • FIG. 10 is a flow chart illustrating a method of initiating ammonia reforming 900.
  • an electrically-heated reformer e.g., electrically-heated reformer 110
  • a target temperature within a target temperature range, for example, about 400 - about 600 °C.
  • the electrically-heated reformer can be heated by initiating power supply to the electrical heater.
  • ammonia e.g., incoming ammonia stream 104
  • ammonia can be directed to the electrically-heated reformer, and ammonia can be reformed using NH3 reforming catalysts in the electrically-heated reformer to generate hydrogen and nitrogen (e.g., an H2/N2 mixture, reformate stream 120).
  • At step 903 at least a portion of the reformate stream (generated by the electrically- heated reformer) and air (e.g., air stream 118) can be directed to the combustion heater.
  • air e.g., air stream 118
  • the reformate stream can be reacted with the air in a combustion reaction (in the combustion heater 109) to heat the combustion-heated reformer (e.g., combustion-heated reformer 109).
  • An ignition device e.g., spark plug
  • the flow rate of the air to the combustion heater can be adjusted to increase the temperature of the combustion-heated reformer.
  • ammonia e.g., incoming ammonia stream 104
  • NH3 reforming catalysts in the combustion-heated reformer to generate hydrogen and nitrogen (e.g., an H2/N2 mixture, reformate stream 120).
  • the combustion-heated reformer can fluidically communicate in series or in parallel with the electrically-heated reformer (e.g., as shown in FIG. 13).
  • the flow rate of the incoming ammonia stream can be incrementally increased to a predefined flow rate (e.g., to generate a target flow rate of H2/N2 mixture in the reformate stream).
  • the flow rate of the air stream (to the combustion heater) can be increased.
  • the combustion-heated reformer can be maintained in a target temperature range.
  • the ammonia reforming method (or system) can achieve a predetermined operational condition (steady-state condition)
  • FIGS. 11A-11C are flow charts illustrating various methods of initiating an ammonia reforming system (e.g., ammonia reforming system 100) to power a device.
  • the device can be a load powered by a fuel cell of the ammonia reforming system (for example, an electrical motor for a mobile vehicle, a stationary data center, a cell phone tower, or a charging station) or an internal combustion engine powered by reformate generated by the ammonia reforming system.
  • a fuel cell of the ammonia reforming system for example, an electrical motor for a mobile vehicle, a stationary data center, a cell phone tower, or a charging station
  • an internal combustion engine powered by reformate generated by the ammonia reforming system.
  • FIG. 11A is a flow chart illustrating a method of initiating an ammonia reforming system using a battery (to power a device).
  • the device can be started.
  • an electrical vehicle or device can be switched on.
  • the ammonia reforming system can be started using a battery.
  • an electrical heater can receive electrical power from the battery to heat an electrically-heated reformer, and ammonia can be reformed using the NH3 reforming catalysts in the electrically-heated reformer.
  • the ammonia reforming system can be further operated.
  • any of the steps described with respect to FIGS. 7-10 can be executed or performed.
  • the device can be stopped.
  • an electrical vehicle or device can be switched off.
  • the ammonia reforming system can charge the battery (for example, by providing fuel cell power to the battery).
  • an electrical grid e.g., external electrical grid
  • the battery can charge the battery.
  • FIG. 11B is a flow chart illustrating a method of initiating an ammonia reforming system using stored hydrogen (to power a device).
  • the device can be started. For example, an electrical vehicle or device can be switched on.
  • the ammonia reforming system can be started using stored hydrogen (e.g., stored in a hydrogen storage tank).
  • stored hydrogen e.g., stored in a hydrogen storage tank.
  • a combustion heater can combust the hydrogen and air to heat a combustion-heated reformer, and ammonia can be reformed using the NH3 reforming catalysts in the combustion-heated reformer.
  • the ammonia reforming system can be further operated.
  • any of the steps described with respect to FIGS. 7-10 can be executed or performed.
  • the device can be stopped.
  • an electrical vehicle can be switched off.
  • the ammonia reforming system can generate hydrogen, and store the hydrogen (e g., in the hydrogen storage tank). It is noted that reformate (e.g., hydrogen/nitrogen mixture) can be stored in the hydrogen storage tank.
  • reformate e.g., hydrogen/nitrogen mixture
  • FIG. 11C is a flow chart illustrating a method of initiating an ammonia reforming system using an electrical grid (to power a device).
  • the device can be started.
  • a cell phone tower or charging device can be switched on.
  • the ammonia reforming system can be started using electrical power from an electrical grid.
  • an electrical heater can receive electrical power from the electrical grid to heat an electrically-heated reformer, and ammonia can be reformed using the NH3 reforming catalysts in the electrically-heated reformer.
  • the ammonia reforming system can be further operated.
  • any of the steps described with respect to FIGS. 7-10 can be executed or performed.
  • the device can be stopped.
  • a cell phone tower or charging device can be switched off.
  • FIG. 12A is a flow chart illustrating a method of operating ammonia reforming (e.g., ammonia reforming system 100), in accordance with one or more embodiments of the present disclosure.
  • self-sustaining autothermal operational conditions can be predetermined (e.g., minimum and maximum NH3 flow rates, corresponding fuel cell (FC) power and hydrogen consumption rates, minimum and maximum battery states of charge (SOC), minimum and maximum air flow rates, etc.).
  • predetermined e.g., minimum and maximum NH3 flow rates, corresponding fuel cell (FC) power and hydrogen consumption rates, minimum and maximum battery states of charge (SOC), minimum and maximum air flow rates, etc.
  • operational parameters can be maintained and/or adjusted to maintain and/or adjust fuel cell power output (and self-sustained autothermal reforming).
  • the method can comprise monitoring the power output of the fuel cell, and automatically or manually adjusting (increasing or decreasing) the power output (based on the electrical load coupled to the fuel cell).
  • the method can adjust various operational parameters including the flow rate of the air stream to the combustion heater, the flow rate of the incoming ammonia stream, the hydrogen consumption rate of the fuel cell, and/or the electrical power to the electrical heater.
  • a controller can control NH3 flow rate, control air flow rate, control NH3 flow pressures, control air flow pressures, control valves, control FC power output, control battery power output, control E-reformer power input, control FC hydrogen consumption rate, or any combination thereof.
  • one or more sensors can measure temperatures, pressures, fuel cell power output, battery power outputs, battery SOC, fuel cell hydrogen consumption rate, NH3 conversion efficiency, or any combination thereof.
  • the method can comprise increasing the power output of the fuel cell.
  • the hydrogen consumption rate of the fuel cell can be compared to a predetermined threshold consumption rate (the threshold consumption rate can be a specific value or a range).
  • the method can comprise increasing the power output of the fuel cell by increasing the hydrogen consumption rate (while still keeping the hydrogen consumption rate less than the predetermined threshold). The method may then proceed to step 1301.
  • the method can comprise comparing the ammonia flow rate into the system to a predetermined ammonia flow rate.
  • the predetermined ammonia flow rate can be a maximum ammonia flow rate for the system.
  • the method can comprise increasing the ammonia flow rate (based on the flow rate of the incoming ammonia stream being less than the predetermined ammonia flow rate). The method may then proceed to step 1301. [00409] At step 1308, the method can comprise maintaining the ammonia flow rate (based on the flow rate of the incoming ammonia stream being greater than the predetermined ammonia flow rate).
  • the method can comprise maintaining the power output of the fuel cell (based on the flow rate of the incoming ammonia stream being equal to or greater than the predetermined ammonia flow rate). In some cases, the power output of the fuel cell can be a maximum power output of the fuel cell. The method may then proceed to step 1301.
  • the method can comprise decreasing the power output of the fuel cell. Otherwise, the fuel cell power may not be decreased, and the method may proceed to step 1301.
  • the method can comprise comparing the flow rate of the incoming ammonia stream to a predetermined ammonia flow rate.
  • the predetermined ammonia flow rate can be a minimum ammonia flow rate.
  • method may proceed to step 1301.
  • the method can comprise reducing the flow rate of the incoming ammonia stream (based on the flow rate of the incoming ammonia stream being greater than the predetermined ammonia flow rate). The method may then proceed to step 1301.
  • the method can comprise maintaining the flow rate of the incoming ammonia stream (based on the flow rate of the incoming ammonia stream being equal to or less than the predetermined ammonia flow rate).
  • the method can comprise maintaining the power output of the fuel cell (based on the flow rate of the incoming ammonia stream being equal to or less than the predetermined ammonia flow rate). The method may then proceed to step 1301.
  • the method may comprise comparing the flow rate of the incoming ammonia stream to a predetermined ammonia flow rate. Regardless of the flow rate of the incoming ammonia stream being less than, equal to, or greater than the predetermined ammonia flow rate, the method can further comprise maintaining the flow rate of the incoming ammonia stream and proceeding to step 1301.
  • the predetermined ammonia flow rate can be a minimum ammonia flow rate. In this way, the fuel cell power is reduced and the incoming ammonia flow rate is maintained or at least within a desired range.
  • the method can comprise a shutdown process. In some cases, the shutdown process can comprise reducing any one of or a combination of ammonia flow rate, air flow rate, and fuel cell power to zero.
  • the method can comprise performing or executing a hot standby mode.
  • performing or executing the hot standby mode can comprise reducing the ammonia flow rate, air flow rate, and/or the fuel cell power to zero.
  • FIG. 12B is a flow chart illustrating a method of operating ammonia reforming (e.g., ammonia reforming system 100) using a battery, in accordance with one or more embodiments of the present disclosure.
  • ammonia reforming e.g., ammonia reforming system 100
  • self-sustaining autothermal operational conditions can be predetermined (e g., minimum and maximum NH3 flow rates, corresponding FC power and hydrogen consumption rates, minimum and maximum battery states of charge (SOC), minimum and maximum air flow rates, etc.).
  • operational parameters can be maintained and/or adjusted to maintain and/or adjust fuel cell power output (and self-sustained autothermal reforming).
  • the method can comprise monitoring the power output of the fuel cell, and automatically or manually adjusting (increasing or decreasing) the power output (based on the electrical load coupled to the fuel cell).
  • the method can adjust various operational parameters including the flow rate of the air stream to the combustion heater, the flow rate of the incoming ammonia stream, the hydrogen consumption rate of the fuel cell, and/or the electrical power to the electrical heater.
  • one or more controllers can control NH3 flow rate, control air flow rate, control NH3 flow pressures, control air flow pressures, control valves, control FC power output, control battery power output, control E-reformer power input, control FC hydrogen consumption rate, or any combination thereof.
  • one or more sensors can measure temperatures, pressures, fuel cell power output, battery power outputs, battery SOC, fuel cell hydrogen consumption rate, and NH3 conversion efficiency.
  • the method can comprise comparing the FC hydrogen consumption rate to a predetermined threshold FC hydrogen consumption rate.
  • the predetermined threshold FC hydrogen consumption rate can be a maximum consumption rate.
  • the method can comprise increasing the power output of the fuel cell by increasing the hydrogen consumption rate (while still keeping the hydrogen consumption rate less than the predetermined threshold). The method may then proceed to step 1401.
  • the battery can be used to provide electrical power to the electrical load.
  • the battery state of charge (SOC) can be compared to a predetermined minimum threshold.
  • the flow rate of the incoming ammonia stream can be compared to a predetermined ammonia flow rate.
  • the predetermined ammonia flow rate can be a maximum ammonia flow rate for the system.
  • the method can comprise increasing the flow rate of the incoming ammonia stream (based on the flow rate of the incoming ammonia stream being less than the predetermined ammonia flow rate). The method may then proceed to step 1401.
  • the method can comprise maintaining the flow rate of the incoming ammonia stream (based on the flow rate of the incoming ammonia stream being equal to or greater than the predetermined ammonia flow rate).
  • the method can comprise limiting an electrical load associated with the power demand. The method may then proceed to step 1401.
  • the method can comprise decreasing the power output of the fuel cell, and comparing a battery SOC to a predetermined threshold.
  • the method can comprise comparing the flow rate of the incoming ammonia stream to a predetermined ammonia flow rate.
  • the predetermined ammonia flow rate can be a minimum ammonia flow rate. Based on the flow rate of the incoming ammonia stream being less than the predetermined ammonia flow rate, method may then proceed to step 1401.
  • method can comprise reducing the fuel cell power output and proceed to step 1401. In this way, the fuel cell power is reduced and the incoming ammonia flow rate is maintained or at least within a desired range.
  • the method can comprise reducing the flow rate of the incoming ammonia stream (based on the flow rate of the incoming ammonia stream being greater than the predetermined ammonia flow rate). The method may then proceed to step 1401.
  • the method can comprise charging the battery using electrical power generated by the fuel cell.
  • the method can comprise determining if the battery is fully charged. Based on the battery being fully charged, the method can proceed to step 1413 or step 1401. Based on the battery being less than fully charged, the method may proceed to step 1401.
  • the method can comprise a shutdown process.
  • the shutdown process can comprise reducing any one of or a combination of ammonia flow rate, air flow rate, and fuel cell power to zero.
  • the method can comprise performing or executing a hot standby mode.
  • performing or executing the hot standby mode can comprise reducing the ammonia flow rate, the air flow rate, and/or the fuel cell power to zero.
  • the method can comprise the fuel cell providing power to the battery, and the battery can provide power for the electrical load.
  • the fuel cell can provide power to charge the battery, and the battery can provide power for the electrical load.
  • the system can execute the hot standby mode, or shut down the ammonia reforming system.
  • the system can unexecute the hot standby mode and generate power from the fuel cell.
  • FIG. 13 is a schematic diagram illustrating utilization of an oxidation-resistant catalyst 1501 to generate reformate to purge the ammonia reforming system 100 shown in FIGS. 1A-4B, in accordance with one or more embodiments of the present disclosure.
  • the electrically-heated reformer 110 can comprise oxidation-resistant catalyst 1501 therein.
  • the electrical heater 111 can heat the electrically-heated reformer 110 and the catalyst 1501 to a target temperature range (e.g., about 400 - about 600 °C).
  • the oxidation-resistant catalyst 1501 can be configured to resist oxidation at the target temperature range.
  • Ammonia can be reformed at the target temperature range using the oxidation-resistant catalyst 1501 to generate a reformate stream 1502 comprising hydrogen (H2) and nitrogen (N2).
  • the reformate stream 1502 can be provided to the reformer 108 filled with oxidationsensitive catalyst 1503.
  • the oxidation-sensitive catalyst 1503 can be sensitive to oxidation at the target temperature range (e.g., about 400 - about 600 °C) and/or in an environment comprising oxygen.
  • the reformate stream 1502 (purging gas) can purge any residual gases in the reformer 108 (e.g., residual ammonia).
  • the oxidation-resistant catalyst 1501 can be configured to generate reformate to purge residual gases in any type of reactor, and that the present disclosure is not limited to purging residual gases in the reformer 108 and/or 110.
  • the oxidation resistant catalyst 1501 can be used to generate reformate to purge a steam methane reforming (SMR) reactor, a methanol reforming reactor, or any other type of reactor.
  • SMR steam methane reforming
  • FIG. 14 is a schematic diagram illustrating a renewable energy system 1600 combining ammonia synthesis and ammonia reforming, in accordance with one or more embodiments of the present disclosure.
  • a storage tank 1601 (e.g., storage tank 102) can be configured to store ammonia.
  • An ammonia powerpack 1602 e.g., ammonia reforming system 100
  • a reformer e.g., reformers 108 and 110
  • a fuel cell can be configured to react the reformate-product H2 with oxygen (O2) to generate water (H2O) and an electrical power output to an electrical grid.
  • a gas recovery module 1606 can comprise a water condenser 1607 configured to extract the H2O from a cathode exhaust 1604 of the fuel cell, and a nitrogen separator or liquefier 1608 configured to extract the reformate-product N2 from an anode exhaust 1605 of the fuel cell.
  • the H2O can be extracted from both the cathode exhaust 1604 and the anode exhaust 1605.
  • the H2O can be extracted from the anode exhaust 1605.
  • the N2 can be extracted from both the cathode exhaust 1604 and the anode exhaust 1605.
  • the N2 can be extracted from the cathode exhaust 1604.
  • a water tank 1610 can be configured to store the extracted H2O and/or external H2O sourced from one or more external water sources 1609 (e.g., fresh water, distilled water, deionized water, etc.).
  • external water sources 1609 e.g., fresh water, distilled water, deionized water, etc.
  • An electrolyzer 1611 can be configured to convert the extracted H2O and/or the external H2O (stored in the water tank 1610) to renewably-generated H2 (i.e., green H2) using electrical power input from the electrical grid.
  • An air separator 1617 can be configured to separate air 1618 (e.g., from the atmosphere) to generate air-separated N2. Additionally, the air separator 1617 can be configured to generate O2 for the fuel cell.
  • An ammonia synthesis reactor 1613 can be configured react the renewably-generated H2 and the air-separated N2 to generate synthesized NH3 1614 (for example, via the Haber-Bosch process).
  • the synthesized NH3 can be stored in the ammonia storage tank 1601 (e.g., to be reformed by the ammonia powerpack 1602).
  • the ammonia synthesis reactor 1613 can be powered (i.e., heated) using electrical power input from the electrical grid.
  • a nitrogen tank 1615 is configured to receive and store the N2 from the liquefier or separator 1608, and is configured to provide the N2 to the ammonia synthesis reactor 1613 to react with the renewably-generated H2.
  • a controller e.g., controller 200
  • the controller can be configured to determine an electricity demand of the electrical grid (e.g., using grid data received from the external network).
  • the fuel cell of the ammonia powerpack 1602 can be directed to react the reformate-product H2 with O2 to generate H2O, and output 1603 electricity to the electrical grid.
  • the ammonia powerpack 1602 can export 1603 hydrogen to an external recipient.
  • the electrolyzer 1611 can be directed to convert the extracted H2O and/or the external H2O into the renewably-generated H2 using the input electricity from the electrical grid, and/or the ammonia synthesis reactor 1613 can be directed to react the renewably-generated H2 and the air-separated N2 (and/or the reformate-product N2) to synthesize the ammonia 1614.
  • a threshold electricity demand in other words, a high supply of electricity in the electrical grid
  • the electrolyzer 1611 can be directed to convert the extracted H2O and/or the external H2O into the renewably-generated H2 using the input electricity from the electrical grid
  • the ammonia synthesis reactor 1613 can be directed to react the renewably-generated H2 and the air-separated N2 (and/or the reformate-product N2) to synthesize the ammonia 1614.
  • the electrical power output of the fuel cell(s) is at least about 1 kilowatt (kW) to at most about 100 megawatt (MW). In some cases, the electrical power output of the fuel cell(s) is at least about 1 kW, 5 kW, 10 kW, 50 kW, 100 kW, 500 kW, 1 MW, 5 MW, 10 MW, 50 MW, or 100 MW. In some cases, the electrical power output of the fuel cell(s) is at most about 1 kW, 5 kW, 10 kW, 50 kW, 100 kW, 500 kW, 1 MW, 5 MW, 10 MW, 50 MW, or 100 MW.
  • the electrical power output of the fuel cell(s) is between about 1 kW and 100 MW, 5 kW and 50 MW, 10 kW and 10 MW, 50 kW and 5 MW, 100 kW and 1 MW, or 500 kW and 100 MW.
  • the renewable energy system can comprise a start-up time of at least about 10 minutes to at most about 3 hours, a steady operation time (e.g., of the powerpack 1602, the electrolyzer 1611 and/or the ammonia synthesis reactor 1613) of at least about 10 minutes to at most about 50 hours, and a shut-down time of at least about 10 min to at most about three hours.
  • the start-up time is at least about 10 min, 0.5, 1, 1.5, 2, 2.5, or 3 hours.
  • the start-up time is at most about 10 min, 0.5, 1, 1.5, 2, 2.5, or 3 hours. In some cases, the start-up time is between about 10 minutes and about 3 hours, between about 0.5 hours and about 2.5 hours, between about 1 hour and about 2 hours, or between about 1.5 hours and 3 hours. In some cases, the steady operation time is at least about 10 minutes, 0.5, 1, 5, 10, 15, 20, 25, 30, 35, 40, 45, or 50 hours. In some cases, the steady operation time is at most about 10 minutes, 0.5, 1, 5, 10, 15, 20, 25, 30, 35, 40, 45, or 50 hours.
  • the steady operation time is between about 10 minutes and 50 hours, 30 minutes and 45 hours, 1 hour and 40 hours, 5 hours and 35 hours, 10 hours and 30 hours, 15 hours and 25 hours, 20 hours and 50 hours.
  • the shut-down time is at least about 10 min, 0.5, 1, 1.5, 2, 2.5, or 3 hours. In some cases, the shut-down time is at most about 10 min, 0.5, 1, 1.5, 2, 2.5, or 3 hours. In some cases, the shutdown time is between about 10 minutes and 3 hours, 30 minutes and 2.5 hours, 1 hour and 2 hours, or 1.5 hours and 3 hours.
  • the electrical grid can preferably be provided with electricity from a zero- carbon or carb on -neutral source, for example, solar energy, wind energy, geothermal energy, hydroelectric energy, and/or nuclear energy.
  • FIG. 15A is a schematic diagram illustrating a multi-stage ammonia filter 1700, in accordance with one or more embodiments of the present disclosure.
  • FIG. 15B is a plot illustrating performance calculation data of a multi-stage ammonia filter 1700 at different stage numbers and water flow rates, in accordance with one or more embodiments of the present disclosure.
  • An ammonia scrubber 1701 can be configured to remove ammonia from a reformate stream 1702 (e.g., reformate stream 120) comprising at least H2, N2, and trace or residual NH3 (e.g., at an ammonia concentration of about 10,000 ppm or greater).
  • a filtered reformate stream 1703 e.g., filtered reformate stream 123 can be output from the scrubber 1701 with the trace or residual NH3 reduced (e.g., to an ammonia concentration less than about 500 ppm).
  • the filtered reformate stream 1703 can be subsequently directed to a combustion heater (e.g., combustion heater 109) or to a fuel cell (e.g., fuel cell 124).
  • the ammonia scrubber 1701 can comprise one or more equilibrium stages. Each of the equilibrium stages can comprise water configured to absorb the trace or residual NH3.
  • the ammonia scrubber 1701 can be configured to receive input water (e.g., water condensate 1705 from a fuel cell) and discharge output water (e.g., a mixture 1704 of water and scrubbed NH3).
  • the input water comprises fresh water, seawater, distilled water, and/or deionized water.
  • the discharged output water can be provided to an ammonia stripper 1706 in fluid communication with the ammonia scrubber 1701.
  • Ammonia can be removed from the discharged output water by passing air 1710 into the discharged output water in the ammonia stripper 1706.
  • a stripped mixture 1711 (comprising air, water, and ammonia) can be discharged from the ammonia stripper 1706.
  • the stripped mixture 1711 is directed to a combustion heater (e.g., combustion heater 109).
  • a pump 1707 can be configured to circulate water 1708 from the ammonia stripper 1706 to the ammonia scrubber 1701.
  • the water 1708 can be combined with the fuel cell condensate 1705 or any other external water sources before being directed into the ammonia scrubber 1701.
  • the multi-stage ammonia filter 1700 can be continuously regenerated (e.g., without having to replace one or more adsorbent filters), and an ammonia reforming system (e.g., ammonia reforming system 100) can be prevented from stopping (to regenerate the ammonia filter).
  • increasing the number of equilibrium stages and/or the water flow rates can increase NH3 absorption (and reduce NH3 concentration) in the filtered reformate stream 1703 as illustrated in FIG. 15B.
  • the NH3 concentration at the filtered reformate stream 1703 is below about 100, 500, 1000, 2000, 3000, 4000, 5000, 6000, 7000, 8000, or 9000 parts per million (ppm).
  • the NH3 concentration at the filtered reformate stream 1703 is at most about 100, 500, 1000, 2000, 3000, 4000, 5000, 6000, 7000, 8000, or 9000 ppm.
  • the NH3 concentration at the filtered reformate stream 1703 is at least about 100, 500, 1000, 2000, 3000, 4000, 5000, 6000, 7000, 8000, or 9000 ppm. In some instances, the NH3 concentration at the filtered reformate stream 1703 is between about 100 and 9000, 500 and 8000, 1000 and 7000, 2000 and 6000, 3000 and 5000, or 4000 and 9000 ppm. In some instances, the equilibrium stages in the ammonia scrubber can be at least 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 15, or 20 stages. In some instances, the equilibrium stages in the ammonia scrubber can be at most 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 15, or 20 stages.
  • the water flow rate can be at least about 1, 2, 4, 6, 8, 10, 12, 14, 16, 18, 20, 25, or 30 kilogram (kg) / second (s). In some instances, the water flow rate can be at most about 1, 2, 4, 6, 8, 10, 12, 14, 16, 18, 20, 25, or 30 kg/s. In some instances, the water flow rate can be between about 1 and 30, 2 and 25, 4 and 20, 6 and 18, 8 and 16, 10 and 14, or 12 and 30 kg/s.
  • FIGS. 16A-F are block diagrams illustrating various recovery modules 1801 configured to recover waste heat and a separation module 1801a configured to separate hydrogen, nitrogen, oxygen, or water, in accordance with one or more embodiments of the present disclosure.
  • the recovery module 1801 can be configured to convert the waste heat to electrical power or mechanical power 1802 (i.e., productive work).
  • the recovery module can comprise one or more turbines or turbo devices, and can utilize turbo-compounding (e.g., mechanical turbo-compounding or electrical turbo-compounding).
  • the heat recovery module 1801 comprises a heat exchanger, for example, a shell-and-tube heat exchanger or a plate heat exchanger.
  • the recovery module 1801 can be configured to utilize the waste heat to warm a fluid stream (e.g., preheat or vaporize the incoming ammonia stream 104).
  • the heat recovery module 1801 is a boiler configured to generate steam.
  • the steam can be directed to a turbine to generate mechanical power or electrical power.
  • the steam can be directed to the ammonia filter 112 to regenerate the ammonia filter 112 by desorbing the trace or residual ammonia from the ammonia filter 112 (in other words, perform temperature swing adsorption (TSA) and desorption).
  • TSA temperature swing adsorption
  • the heat recovery module 1801 comprises a heat pump configured to transfer heat from the combustion exhaust 114 to a working fluid (e.g., water to generate steam).
  • a working fluid e.g., water to generate steam.
  • the steam can be used to drive a turbine to generate electrical power or mechanical power, and/or can be used to regenerate the ammonia filter 112.
  • the heat pump can transfer heat from the reformate stream 120 (or portion thereof) or the leftover stream 536 (or portion thereof) and provide the heat to the working fluid.
  • the recovery module 1801 can advantageously increase an overall energy efficiency of the ammonia reforming system 100 (e.g., ammonia heating value to useful energy, such as electricity, i.e., energy conversion efficiency), for example, by at least 2%. In some cases, the recovery module 1801 can increase the overall energy efficiency by at least about 2, 3, 4, 5, 6, 7, 9, or 10%. In some cases, the recovery module 1801 can increase the overall energy efficiency by at most about 3, 4, 5, 6, 7, 9, or 10%.
  • an overall energy efficiency of the ammonia reforming system 100 e.g., ammonia heating value to useful energy, such as electricity, i.e., energy conversion efficiency
  • the recovery module 1801 can increase the overall energy efficiency by at least about 2, 3, 4, 5, 6, 7, 9, or 10%.
  • the combustion exhaust 114 from the combustion heater 109 can be provided to the recovery module 1801.
  • the recovery module 1801 can capture or recover heat from the combustion exhaust 114.
  • the reformate stream 120 (or portion thereof) and/or the leftover stream 536 (or portion thereof) can be provided to the recovery module 1801a (or a separation module 1801a).
  • the reformate stream 120 (or portion thereof) and/or the leftover stream 536 (or portion thereof) can bypass the combustion heater 109 (for example, diverted at a location upstream from the combustion heater 109) when provided to the recovery module 1801 (or the separation module 1801a).
  • the reformate stream 120 (or portion thereof) and/or the leftover stream 536 (or portion thereof) can bypass (i.e., be diverted from) the combustion heater 109 during the startup mode or the hot standby mode.
  • the reformate stream 120 (or portion thereof) and/or the leftover stream 536 (or portion thereof) may not bypass the combustion heater 109 during the operation mode (for example, may be provided only to the combustion heater 109 during the operation mode).
  • the reformate stream 120 (or portion thereof) and/or the leftover stream 536 (or portion thereof) may not bypass the combustion heater 109 during the startup mode, the operation mode, and/or the hot standby mode (for example, may be provided only to the combustion heater 109 during the startup mode, operation mode, or hot standby mode).
  • a separation module 1801a can separate hydrogen 1802a, nitrogen 1802b, and/or water 1802c from the combustion exhaust 114, the reformate stream 120 (or portion thereof), and/or the leftover stream 536 (or portion thereof).
  • the separation module 1801a can comprise a hydrogen separation membrane configured to separate the hydrogen 1802a from the combustion exhaust 114, the reformate stream 120 (or portion thereof), or the leftover stream 536 (or portion thereof) (which can comprise H2, N2, and/or H2O).
  • the hydrogen separation membrane can comprise platinum (Pt), palladium (Pd), vanadium (V), and/or other materials configured for hydrogen separation.
  • the separated hydrogen 1802a is stored in a storage tank.
  • the separated hydrogen 1802a is provided to a fuel cell (e.g., fuel cell 124). In some embodiments, the separated hydrogen 1802a is combusted (e.g., in the combustion heater 109 or in a boiler configured to generate steam). In some cases, the separated nitrogen 1802b can be vented to the atmosphere. In some cases, the separated nitrogen 1802b can be compressed and/or liquified. In some cases, the separation module 1801a comprises a pressure swing adsorption device (PSA) configured to separate the nitrogen 1802b. In some cases, the separation module 1801a can comprise a condenser or a filter configured to extract the water 1802c. In some cases, the separation module 1801a separates oxygen from the combustion exhaust 114.
  • PSA pressure swing adsorption device
  • the recovery module 1801 can comprise an auxiliary combustor 1803.
  • the auxiliary combustor 1803 can be configured to combust the hydrogen in the reformate stream 120 (or portion thereof) and/or the leftover stream 536 (or portion thereof).
  • the auxiliary combustor 1803 can be in thermal communication with the recovery module 1801 (e.g., to transfer heat to the recovery module 1801).
  • the auxiliary combustor 1803 can be separate from the combustion heater 109.
  • the auxiliary combustor 1803 combusts hydrogen in the reformate stream 120 (or portion thereof) and/or the leftover stream 536 (or portion thereof) during the hot standby mode and/or during the startup mode (e.g., to combust hydrogen in the leftover stream 536 that is not consumed by the hydrogen processing module 535).
  • flow control units e.g., valves
  • the recovery module 1801 can comprise a turbocharger 1804 and/or a turbine 1805a.
  • the turbocharger 1804 can be configured to be driven by the temperature and pressure of the combustion exhaust 114 to provide mechanical power 1802 to a compressor (e.g., air supply unit 116), which in turn compresses the air stream 118.
  • the compressed air stream 118 can be provided to the combustion heater 109 for combustion of the reformate stream 120 and/or the leftover stream 536.
  • the compression of the air stream 118 can advantageously reduce the fuel requirement for combustion in the combustion heater 109.
  • the turbine 1805a can be configured to be driven by the temperature and pressure of the combustion exhaust 114, and can comprise a generator configured to generate electrical power 1802.
  • the electrical power 1802 can be provided to a battery 1806 and/or an electrical motor 1807.
  • the electrical motor 1807 can be provided to convert the electrical power 1802 to mechanical power, and drive a transmission 1808 (e.g., which can propel a vehicle, for example, a marine vessel).
  • the battery 1806 can provide electrical power to the electrical motor 1807 (e.g., in addition to the fuel cell 124).
  • the generator can provide electrical power 1802 to charge the battery 1806 during the startup mode, the operation mode, and/or the hot standby mode.
  • the generator can provide electrical power 1802 to actuate the electrical motor 1807 during the operation mode.
  • the combustion exhaust 114 can pass in series from the turbocharger 1804 to the turbine 1805a, and the ammonia reforming system 100 can therefore utilize (electrical) turbocompounding.
  • the combustion exhaust 114 can pass in series from the turbine 1805a to the turbocharger 1804.
  • either the turbocharger 1804 or the turbine 1805a may not be present, so that the combustion exhaust 114 only passes the turbocharger 1804, or so that the combustion exhaust 114 only passes the turbine 1805a.
  • the recovery module 1801 can comprise the turbocharger 1804 and/or a turbine 1805b.
  • the turbine 1805b can be configured to be driven by the temperature and pressure of the combustion exhaust 114, and can be configured to generate mechanical power 1802 for the transmission 1808.
  • the hydrogen processing module 535 is an internal combustion engine (ICE) 535b and the turbine 1805b provides the mechanical power 1802 to the transmission 1808 (in addition to the mechanical power 535a provided by the ICE 535b).
  • ICE internal combustion engine
  • the combustion exhaust 114 can pass in series from the turbocharger 1804 to the turbine 1805b, and the ammonia reforming system 100 can therefore utilize (mechanical) turbocompounding.
  • the combustion exhaust 114 can pass in series from the turbine 1805b to the turbocharger 1804. In some cases, either the turbocharger 1804 or the turbine 1805b may not be present, so that the combustion exhaust 114 only passes the turbocharger 1804, or so that the combustion exhaust 114 only passes the turbine 1805b.
  • the recovery module 1801 can be a Rankine cycle device or module comprising a boiler 1809, a turbine 1810, and a condenser 1811.
  • a working fluid can circulate between the boiler 1809, the turbine 1810, and the condenser 1811.
  • the working fluid 1812 comprises water.
  • the water can be sourced from the cathode off-gas 504 emitted by the fuel cell 124, sourced from the combustion exhaust 114, and/or can be sourced externally (e.g., tap water, fresh water, sea water, etc.).
  • the boiler 1809 can vaporize the working fluid 1812 (using the waste heat transferred from the combustion exhaust 114) to generate steam 1812.
  • the steam 1812 can drive the turbine 1810 to generate electrical or mechanical power 1802 (e.g., to charge a battery, actuate an electrical motor, or drive a transmission).
  • the condenser 1811 can condense the steam 1812, and the working fluid 1812 can be provided to the boiler 1809 to perform the Rankine cycle again.
  • FIGS. 17A-17N are schematic diagrams illustrating various ammonia decomposition systems 1900a-n comprising a gas turbine 1904, in accordance with one or more embodiments of the present disclosure.
  • the gas turbine 1904 can be driven by the expansion of product gas from the combustion of ammonia, hydrogen, natural gas (or combinations thereof) with air in the combustion chamber 1902.
  • a compressor 1906 can compress air 1908, increasing the temperature and pressure of the air 1908 for the combustion in the combustion chamber 1902.
  • the gas turbine 1904 can be configured to generate electricity 1905 by rotating a generator (not shown).
  • the ammonia decomposition systems 1900a-n can advantageously reduce carbon-based greenhouse gas emissions (e.g., reducing the emissions of carbon dioxide in comparison to combusting only natural gas).
  • the ammonia decomposition systems 1900a-n can be retrofitted to existing turbines (e.g., natural gas turbines), which can extend the operational life of the existing gas turbines as the global economy decarbonizes (therefore reducing the risk of stranded assets).
  • the ammonia decomposition systems 1900a-n can provide a dispatchable source of renewably-sourced electricity generation which ramps up relatively quickly (acting as peaker plants when electricity demand is high and electricity supply is low).
  • FIGS. 17A-17N can be substantially similar or substantially identical in form and function to the numbered components described elsewhere herein.
  • gas turbine 1904 can be substantially similar or substantially identical in form and function to the H2 processing module 535 described elsewhere herein.
  • the processes (e.g., methods, steps, algorithms, etc.) described with respect to FIGS. 17A-17N can be implemented using the controller 200 (e.g., computer or computing device), sensors P1-P10, Tl-Tl l, FM1-FM11, AC1-AC10, HC1-HC5, and flow control units FCU1-FCU11 described with respect to FIGS. 5A-5I.
  • controller 200 e.g., computer or computing device
  • sensors P1-P10, Tl-Tl l, FM1-FM11, AC1-AC10, HC1-HC5, and flow control units FCU1-FCU11 described with respect to FIGS. 5A-5I It is noted that any embodiment described with respect to FIGS. 17A-17N can be combined with
  • FIG. 17A is a schematic diagram illustrating an ammonia decomposition system 1900a, in accordance with one or more embodiments of the present disclosure.
  • the system 1900a can comprise an NH3 storage tank 102, a heat exchanger 106, one or more reformers 108-110, an electrical heater 111, a combustion chamber 1902, a gas turbine 1904, a compressor 1906, a heat exchanger 1910, a heat exchanger 1912, a natural gas source 1914, a hydrogen source 1916, an electrolyzer 1918, an oxygen source 1920, a selective catalytic reduction (SCR) catalyst 1922, or a selective ammonia oxidation (SAG) catalyst 1924.
  • SCR selective catalytic reduction
  • SAG selective ammonia oxidation
  • the electrical heater 111 can be configured to heat the reform er(s) 108-110 to the target temperature range (e.g., greater than about 200 °C and less than about 700 °C). Additionally, the waste heat of the turbine exhaust 1909 can be configured to heat the reform er(s) 108-110 via the heat exchanger 1912 to maintain the reform er(s) 108-110 in the target temperature range. In some embodiments, the reformers) 108-110 are heated by both the electrical heater 111 as well as the turbine exhaust 1909 (in other words, both heating mechanisms can be turned on). In some embodiments, the reform er(s) 108-110 are heated by only the electrical heater 111, or by only the turbine exhaust 1909 (in other words, one of the heating mechanisms can be turned off while the other is turned on).
  • the power supplied to the electrical heater 111 can be increased, and the reformer(s) 108-110 can be heated from a first temperature (e.g., room temperature) to a second temperature (e.g., suitable for NHB reforming).
  • the second temperature can be at or within a target temperature range (for example, greater than about 200 °C and less than about 800 °C).
  • the target temperature range can be greater than about 200, 225, 250, 275, 300, 325, 350, 375, 400, 425, 450, 475, 500, 525, 550, 575, 600, 625, 650, 675, 700, 725, 750, or 775 °C.
  • the target temperature range can be less than about 225, 250, 275, 300, 325, 350, 375, 400, 425, 450, 475, 500, 525, 550, 575, 600, 625, 650, 675, 700, 725, 750, 775, or 800 °C.
  • the ammonia stream 104 (which can be vaporized from a liquid state to a gaseous state) can be provided to the reformer(s) 108-110 to generate the reformate stream 120.
  • the ammonia stream 104 before the ammonia stream 104 is provided to the reformer(s) 108-110, the ammonia stream 104 can be pressurized (e.g., using one or more compressors) to a pressure that is greater than about 5 barg and less than about 50 barg.
  • the ammonia stream 104 can be pressurized to a pressure that is greater than about 5, 10, 15, 20, 25, 30, 35, 40, or 45 barg.
  • the ammonia stream 104 can be pressurized to a pressure that is less than about 10, 15, 20, 25, 30, 35, 40, 45, or 50 barg. Pressurizing the ammonia stream 104 upstream of the reformer(s) 108-110 can reduce the need to pressurize the reformate stream 120 downstream of the reformer(s) 108-110.
  • the reformate stream 120 can exchange heat with the ammonia stream 104 via the heat exchanger 106 before being provided to the combustion chamber 1902 of the gas turbine 1904.
  • the reformate stream 120 can be combusted with the air 1908 in the combustion chamber 1902, and the expanding hot product gas can push blades to rotate the shaft of the turbine 1904 and generate the electricity 1905 via a generator.
  • the waste heat 1909 of the turbine can be provided to the heat exchanger 1910 (to vaporize and/or preheat the ammonia stream 104) and the heat exchanger 1912 (to maintain the temperature in the reformer(s) 108-110 in the target temperature range).
  • the waste heat 1909 can preheat the ammonia stream 104 to a temperature that is greater than about 25, 50, 75, 100, 125, 150, 175, 200, 225, 250, 275, 300, 325, 350, 375, 400, 425, 450, 475, 500, 525, 550, 575, 600, or 625 °C. In some cases, the waste heat 1909 can preheat the ammonia stream 104 to a temperature that is less than about 50, 75, 100, 125, 150, 175, 200, 225, 250, 275, 300, 325, 350, 375, 400, 425, 450, 475, 500, 525, 550, 575, 600, 625, or 650 °C.
  • the reformate stream 120 before the reformate stream 120 is provided to the combustion chamber 1902, the reformate stream 120 can be pressurized (e.g., using one or more compressors) to a pressure that is greater than about 5 barg and less than about 300 barg.
  • the reformate stream 120 can be pressurized to a pressure that is greater than about 5, 10, 15, 20, 25, 30, 35, 40, 45, 50, 55, 60, 65, 70, 75, 80, 85, 90, 95, 100, 110, 120, 130, 140, 150, 200, 250, 260, 270, 280 or 290 barg.
  • the reformate stream 120 can be pressurized to a pressure that is less than about 10, 15, 20, 25, 30, 35, 40, 45, 50, 55, 60, 65, 70, 75, 80, 85, 90, 95, 100, 110, 120, 130, 140, 150, 200, 250, 260, 270, 280, 290 or 300 barg.
  • a mixture of ammonia and hydrogen can be combusted in the combustion chamber 1902.
  • a ratio e.g., molar ratio, volume ratio, flow rate ratio, or partial pressure ratio
  • a ratio of ammonia to hydrogen in the combustion chamber 1902 can be controlled by (1) adjusting ammonia conversion efficiency of the decomposition reaction in the reformer(s) 108-110 (thereby controlling the proportion of ammonia and hydrogen in the reformate stream 120), and/or by (2) premixing or blending the reformate stream 120 with ammonia to form a mixed fuel in a premixing chamber (and subsequently providing the mixed fuel to the combustion chamber 1902).
  • the ammonia conversion efficiency can be controlled by adjusting the ammonia flow rate, temperature, and/or pressure in the reformer(s) 108-110. It is contemplated that increasing the ammonia flow rate (while maintaining the heat input) decreases the ammonia conversion efficiency, increasing the temperature increases the ammonia conversion efficiency, and increasing the pressure decreases the ammonia conversion efficiency. For example, to increase the proportion of hydrogen in the reformate stream 120 and decrease the proportion of ammonia in the reformate stream 120, the temperature of the reformer(s) 108-110 can be increased. Conversely, to decrease the proportion of hydrogen in the reformate stream 120 and increase the proportion of ammonia in the reformate stream 120, the temperature of the reform er(s) 108-110 can be decreased.
  • the reformer(s) 108-110 can generate a substantially-cracked reformate stream 120 with a high proportion of hydrogen and nitrogen (e.g., greater than about 99% by molar fraction), and the substantially-cracked reformate stream 120 can be premixed with ammonia in the premixing chamber to form the mixed fuel.
  • a flow control unit e.g., pump, valve, compressor, etc.
  • a flow control unit can be adjusted to provide more or less ammonia from storage tank 102.
  • the molar ratio of ammonia to hydrogen in the reformate stream 120 can be controlled to be about 70:30 (which can advantageously result in combustion characteristics that are similar to natural gas, for example, flame velocity and ignitability). In some embodiments, the molar ratio of the ammonia to the hydrogen in the reformate stream 120 can be controlled to be at least about 0: 100, 1 :99, 5:95, 10:90, 20:80, 30:70. 40:60, 50:50, 60:40, 70:30, 80:20, 90: 10, 95:5, 99: 1, or 100:0.
  • the molar ratio of the ammonia to the hydrogen in the reformate stream 120 can be controlled to be at most about 0: 100, 1 :99, 5:95, 10:90, 20:80, 30:70. 40:60, 50:50, 60:40, 70:30, 80:20, 90: 10, 95:5, 99: 1, or 100:0.
  • the heat of the turbine exhaust 1909 can be utilized to heat various components of the system 1900a.
  • the temperature of the turbine exhaust 1909 can be greater than about 400 °C and less than about 700 °C.
  • the heat of the exhaust gas 1909 can be used to preheat the ammonia stream 104 via the heat exchanger 1910 (thereby vaporizing and/or preheating the ammonia stream 104).
  • the heat of the turbine exhaust 1909 can also be used to heat the reformer(s) 108-110 via the heat exchanger 1912 (to maintain the temperature in the reformer(s) 108-110 at the target temperature range).
  • the heat exchangers 1910 and 1912 can be formed of a thermally conductive material, for example, a metal such as steel, aluminum, copper, or alloys thereof, or a ceramic material such as silicon carbide, aluminum nitride, or boron nitride.
  • the heat exchangers 1910 and 1912 can utilize an intermediate heat exchanging fluid (e.g., water or a glycol).
  • the power supplied to the electrical heater 111 can be reduced or turned off after the waste heat of the turbine exhaust 1909 is provided to heat the reformer 110. In some embodiments, the power supplied to the electrical heater 111 can be reduced or turned off before the waste heat of the turbine exhaust 1909 is provided to heat the reformer 110. In some embodiments, the temperature of the reformers) 108-110 can be measured (using a temperature sensor), and based at least in part on the measured temperature being outside of the target temperature range, the power of the electrical heater 111 can be adjusted to maintain the reformer(s) 108-110 at the target temperature range.
  • the transfer of heat from the turbine exhaust 1909 to the reformer(s) 108-110 can be controlled (by controlling the flow of the turbine exhaust 1909, e.g., using a flow control unit such as a pump, valve or compressor) to maintain the reform er(s) 108-110 at the target temperature range.
  • the gas turbine 1904 can be turned off or reduced in power (such that combustion in the combustion chamber 1902 is stopped or reduced), and the reformer(s) 108-110 can be maintained in the target temperature range using the heat from the electrical heater 111 (thereby keeping the reformer(s) 108-110 in a standby state).
  • a natural gas source 1914 can provide auxiliary fuel (e.g., methane) to be combusted in the combustion chamber 1902.
  • the natural gas source 1914 can comprise a natural gas pipeline or a natural gas storage tank.
  • natural gas can be used as a pilot fuel for a start-up process such that the natural gas is combusted in the combustion chamber 1902 (to heat the combustor 1902 to a target combustion temperature, e.g., greater than about 400 °C and less than about 1500 °C) before combusting ammonia or the reformate stream 120. Due to its facile ignitibility, using natural gas to preheat the combustion chamber 1902 can avoid the need to reform the ammonia into hydrogen for pilot fuel.
  • starting the turbine 1904 with natural gas and subsequently providing the waste heat 1909 to the reformer(s) 108-110 can initiate ammonia decomposition without the use (or minimal use) of the electrical heater 111 (which is beneficial in cases where the electrical heater I l l is not available for use in start-up, e.g., when the electrical heater 111 malfunctions or is out of service for repairs).
  • carbon capture and storage can be utilized to reduce carbon-based emissions from combusting the natural gas.
  • natural gas can be premixed or blended with ammonia (e.g., in a premixing chamber) to form a premixed fuel before combustion in the turbine combustor 1902.
  • a molar ratio of the natural gas to the ammonia (for example, CH ⁇ NHs ratio) can be controlled to be at least about 0: 100, 1:99, 5:95, 10:90, 20:80, 30:70. 40:60, 50:50, 60:40, 70:30, 80:20, 90: 10, 95:5, 99:1, or 100:0.
  • a molar ratio of the natural gas to the ammonia can be controlled to be at most about 0: 100, 1 :99, 5:95, 10:90, 20:80, 30:70. 40:60, 50:50, 60:40, 70:30, 80:20, 90: 10, 95:5, 99: 1, or 100:0.
  • a hydrogen source 1916 can provide auxiliary fuel to be combusted in the combustion chamber 1902.
  • the hydrogen source 1916 can comprise a hydrogen pipeline or a hydrogen storage tank.
  • an electrolyzer 1918 in fluid communication with a water source
  • the electrolyzer 1918 can generate the auxiliary hydrogen for storage in the hydrogen storage tank 1916. It is contemplated that the electrolyzer 1918 can generate the hydrogen when the supply of grid electricity is high (and therefore, the cost of grid electricity is low).
  • the auxiliary hydrogen can be used as a pilot fuel for a start-up process such that the auxiliary hydrogen is combusted in the combustion chamber 1902 (to heat the combustor 1902 to a target combustion temperature, e.g., greater than about 400 °C and less than about 1500 °C) before combusting ammonia and/or the reformate stream 120. Due to its facile ignitibility, using the auxiliary hydrogen to preheat the combustion chamber 1902 can avoid the need to reform the ammonia into hydrogen for pilot fuel.
  • a target combustion temperature e.g., greater than about 400 °C and less than about 1500 °C
  • starting the turbine 1904 with the auxiliary hydrogen and subsequently providing the waste heat 1909 to the reformer(s) 108-110 can initiate ammonia decomposition without the use (or minimal use) of the electrical heater 111 (which is beneficial in cases where the electrical heater 111 is not available for use in start-up, e.g., when the electrical heater 111 malfunctions or is out of service for repairs).
  • the electrolyzer 1918 can provide enriched oxygen (substantially pure oxygen, e g., greater than about 99% O2 by molar fraction) to an oxygen storage tank 1920.
  • the enriched oxygen can be provided for combustion in the combustion chamber 1902.
  • the enriched oxygen can further improve combustion characteristics (e.g., flame speed and ignitability).
  • the enriched oxygen can reduce NOx emissions (e.g., by providing less nitrogen).
  • the enriched oxygen can be compressed using the compressor 1906 and can be mixed with the air 1908.
  • the enriched oxygen is provided for combustion in the combustion chamber 1902 without the air 1908.
  • the SCR catalyst 1922 can be used to reduce nitrogen oxide (NOx) emissions (for example, NO, NO2, and N2O) by converting the NOx to nitrogen and water.
  • the SCR catalyst 1922 can comprise a catalytic material such as platinum or palladium.
  • a reductant such as anhydrous ammonia (NH3), aqueous ammonia (NH4OH), or urea (CO(NH2)2) solution can be added to the turbine exhaust 1909 to react with NOx.
  • the purified exhaust 1909 can be vented to the atmosphere. This removal of harmful NOx emissions advantageously reduces harm to the environment and living organisms.
  • the SAO catalyst 1924 can be used to convert trace or residual NH3 in the turbine exhaust 1909 into N2 and H2O. Air can be provided to the SAO catalyst 1924 to react with the NH3.
  • the SAO catalyst 1924 can comprise a catalytic material such as tungsten, vanadium, molybdenum, chromium, copper, cobalt, manganese, iron, nickel, silver, oxides thereof, and/or zeolites thereof.
  • introducing air (comprising at least oxygen) can combust and remove at least part of the residual NH3 (by converting into N2 and H2O) without the SAO catalyst 1924.
  • the SAO catalyst 1924 can combust and remove residual H2 (which can desirably prevent H2 from entering the atmosphere, since H2 is combustible and is an indirect greenhouse gas). This removal of harmful NH3 and H2 emissions advantageously reduces harm to the environment and living organisms.
  • the ammonia decomposition system 1900a can be started rapidly (to quickly match electricity demand when the electricity supply rapidly decreases, e.g., when solar power generation drops around sunset).
  • the reform er(s) 108-110 are heated from the first temperature to the second temperature in a time period that is less than about 30 minutes.
  • the reformer(s) 108-110 can be heated from the first temperature to the second temperature in a time period that is less than about 5, 10, 15, 20, 25, 30, 35, 40, 45, 50, 55, or 60 minutes.
  • a time period between (1) starting to heat the reformer(s) 108-110 and (2) starting to combust the reformate stream 120 in the combustor 1902 of the gas turbine 1904 is less than about 30 minutes.
  • the time period between (1) starting to heat the reform er(s) 108-110 and (2) starting to combust the reformate stream 120 in the combustor 1902 of the gas turbine 1904 can be less than about 5, 10, 15, 20, 25, 30, 35, 40, 45, 50, 55, or 60 minutes.
  • FIG. 17B is a schematic diagram illustrating an ammonia decomposition system 1900b, in accordance with one or more embodiments of the present disclosure.
  • the components of system 1900b described with respect to FIG. 17B can be substantially similar in form and function to the components of system 1900a described with respect to FIG. 17A.
  • the reformer(s) 108-110 can be configured to be heated by a combustion heater 109 (as described in detail elsewhere herein).
  • the reformer(s) 108-110 comprise a single reformer 108-110 that is heated by the combustion heater 109, the electrical heater 111, and the waste heat of the turbine exhaust 1909 (in other words, a hybrid-heating configuration).
  • the power supplied to the electrical heater 111 can be increased, and the reformer 108-110 can be heated from a first temperature (e.g., room temperature) to a second temperature (e g., suitable for NH3 reforming).
  • a first temperature e.g., room temperature
  • a second temperature e.g., suitable for NH3 reforming
  • the second temperature can be at or within a target temperature range (for example, greater than about 200 °C and less than about 700 °C).
  • the ammonia stream 104 (which can be vaporized from a liquid state to a gaseous state) can be provided to the reformer 108-110 to generate the reformate stream 120.
  • the reformate stream 120 can exchange heat with the ammonia stream 104 via the heat exchanger 106.
  • a first portion of the reformate stream 120 can be provided to the combustion heater 109 (thereby implementing self-sustained, autothermal reforming, as described elsewhere herein), and a second portion of the reformate stream 120 can be provided to the combustion chamber 1902 of the gas turbine 1904.
  • the reformate stream 120 can be combusted with the air 1908 in the combustion chamber 1902, and the expanding hot product gas can push blades to rotate the shaft of the turbine 1904 and generate the electricity 1905 via a generator.
  • the waste heat 1909 of the turbine can be provided to the heat exchanger 1910 (to vaporize the ammonia stream 104) and the heat exchanger 1912 (to maintain the temperature in the reform er(s) 108-110 at the target temperature range).
  • the temperature of the combustion heater 109 can be controlled based on a stimulus (as described with respect to FIG. 6N). Based on the stimulus, one or more of the following can be performed: (i) changing the flow rate of the ammonia stream 104 supplied to the reformer 108-110, (ii) changing the oxygen flow rate of the oxygen supplied to the combustion heater 109, or (iii) changing the first portion of the reformate stream 120.
  • a temperature can be measured in the reformer 108-110, and based at least in part on the measured temperature being outside of the target temperature range, one or more of the following are performed: (i) changing the flow rate of the ammonia stream 104 supplied to the reformer 108-110, (ii) changing the oxygen flow rate of the oxygen supplied to the combustion heater 109, (iii) changing a percentage of the reformate stream 120 that is the first portion of the reformate stream 120, (iv) changing a percentage of the reformate stream 120 that is the second portion of the reformate stream 120, or (v) changing a percentage of the reformate stream 120 that is directed out of the combustion heater 109.
  • one or more of the following are performed: (i) increasing the flow rate of the ammonia stream 104 supplied to the reformer 108-110, (ii) increasing the flow rate of the oxygen supplied to the combustion heater 109, (iii) increasing the flow rate of the oxygen supplied to the gas turbine 1904, (iv) increasing the percentage of the reformate stream 120 that is the first portion of the reformate stream 120; or (v) increasing the percentage of the reformate stream 120 that is the second portion of the reformate stream 120.
  • the increased amount of hydrogen combusted in the combustor 1902 of the gas turbine 1904 is a projected increased amount.
  • one or more of the following are performed: (i) decreasing the flow rate of the ammonia stream 104 supplied to the reformer 108-110, (ii) decreasing the flow rate of the oxygen supplied to the combustion heater 109, (iii) decreasing the flow rate of the oxygen supplied to the gas turbine 1904, (iv) decreasing the percentage of the reformate stream 120 that is the first portion of the reformate stream 120, or (v) decreasing the percentage of the reformate stream 120 that is the second portion of the reformate stream 120.
  • the decreased amount of hydrogen combusted in the combustor 1902 of the gas turbine 1904 is a projected decreased amount.
  • the system 1900b can implement a hot standby mode (as described with respect to FIG. 6L and elsewhere herein).
  • the hot standby mode can advantageously maintain the temperature in the combustion heater 109 and reformers 108-110 while the gas turbine 1904 is not operational.
  • the first portion of the reformate stream 120 (provided to the combustion heater 109) can comprise all of the reformate stream 120, and the second portion of the reformate stream 120 (provided to the combustor 1902) can comprise none of the reformate stream 120.
  • a pressure of the reformate stream 120 is reduced when the reformate stream 120 is directed to the gas turbine 1904 compared to when the reformate stream 120 is not directed to the gas turbine 1904.
  • a threshold amount of the reformate stream 120 being directed to the gas turbine 1904 results in substantially all of the reformate stream 120 being directed to the gas turbine 1904.
  • a threshold amount of the reformate stream 120 being directed to the gas turbine 1904 results in at least about 50, 55, 60, 65, 70, 75, 80, 85, 90, or 95% of the reformate stream 120 being directed to the gas turbine 1904.
  • FIG. 17C is a schematic diagram illustrating an ammonia decomposition system 1900c, in accordance with one or more embodiments of the present disclosure.
  • the components of system 1900c described with respect to FIG. 17C can be substantially similar in form and function to the components of systems 1900a-b described with respect to FIGS. 17A-B.
  • the reformer(s) 108-110 can comprise a first reformer 108-110 that is heated by the electrical heater 111 and a second reformer 108-110 that is heated by the combustion heater 109 and the waste heat of the turbine exhaust 1909.
  • the power supplied to the electrical heater 111 can be increased, and the first reformer 108-110 can be heated from a first temperature (e.g., room temperature) to a second temperature (e g., suitable for NH3 reforming).
  • a first temperature e.g., room temperature
  • a second temperature e.g., suitable for NH3 reforming
  • the second temperature can be at or within a target temperature range (for example, greater than about 200 °C and less than about 700 °C).
  • the ammonia stream 104 (which can be vaporized from a liquid state to a gaseous state) can be provided to the first reformer 108-110 to generate the reformate stream 120.
  • a first portion of the reformate stream 120 generated by the first reformer 108-110 can be combusted in the combustion heater 109 to heat the second reformer 108-110 to the target temperature range.
  • the first portion of the reformate stream 120 is generated by the second reformer 108-110.
  • the reformate stream 120 generated by the first reformer 108-110 is further reformed in the second reformer 108-110.
  • the reformate stream 120 is directed from the second reformer 108-110 to the first reformer 108-110, so that the reformate stream 120 is further reformed in the first reformer 108-110.
  • the ammonia stream 104 is directed to the first reformer 108-110 before being directed to the second reformer 108-110.
  • an amount of the ammonia stream 104 directed to the second reformer 108-110 is increased after the second reformer 108-110 is heated to the target temperature range. In some cases, the amount of the ammonia stream 104 directed to the second reformer 108-110 is increased to a first target ammonia flow rate range. In some cases, the second portion of the reformate stream 120 is directed to the gas turbine 1904 when the first target ammonia flow rate range is reached. In some cases, the ammonia flow rate is subsequently increased to a second target ammonia flow rate range when the first target ammonia flow rate range is reached.
  • FIG. 17D is a schematic diagram illustrating an ammonia decomposition system 1900d, in accordance with one or more embodiments of the present disclosure.
  • the components of system 1900d described with respect to FIG. 17D can be substantially similar in form and function to the components of systems 1900a-c described with respect to FIGS. 17A-C.
  • An NH3 filter 122 (described with respect to FIGS. 1A-4B) can be configured to remove or reduce residual or trace ammonia in the reformate stream 120 (before the reformate stream 120 is provided to the combustor 1902 of the gas turbine 1904). Utilizing the NH3 filter 122 can be advantageous in cases where it is desirable to avoid combustion of ammonia in the combustor 1902 (for example, to reduce the formation of NOx).
  • the system 1900d implements temperature swing adsorption (TSA) and desorption.
  • TSA temperature swing adsorption
  • the waste heat of the turbine exhaust 1909 can be used to desorb the ammonia filter 122 (e.g., based on an ammonia concentration sensor detecting saturation of the ammonia filter 122).
  • a valve 1926 e.g., three-way valve
  • the power supplied to the electrical heater 111 can be increased to provide heat to the reform er(s) 108-110 while the turbine exhaust 1909 is directed to the ammonia filter 122.
  • the ammonia filter 122 can comprise at least two adsorbent towers, and is configured so that a first adsorbent tower regenerates while a second adsorbent tower removes the trace ammonia.
  • an electrical heater can be configured to heat the ammonia filter 122to desorb the adsorbed ammonia and regenerate the ammonia filter 122.
  • FIGS. 17E-17H are schematic diagrams illustrating ammonia decomposition systems 1900e-h, in accordance with one or more embodiments of the present disclosure.
  • the components of systems 1900e-h described with respect to FIGS. 17E-17H can be substantially similar in form and function to the components of systems 1900a-d described with respect to FIGS. 17A-D.
  • system 1900e can implement a combined cycle (e.g., bottoming Rankine cycle), and thus can comprise a turbine 1930 (e.g., steam turbine) configured to generate additional electricity 1931.
  • a turbine 1930 e.g., steam turbine
  • the turbine 1930 can share the same rotating shaft and/or generator as the gas turbine 1904.
  • a boiler 1928 e.g., heat recovery steam generator (HRSG)
  • HRSG heat recovery steam generator
  • the working fluid is an organic fluid (e.g., with a boiling point that is lower than water).
  • the working fluid comprises at least one of an alkane, a haloalkane, 1,1,1,2-tetrafluoroethane (R-134a), pentafluoropropane (R- 245fa), benzene, methanol, ethanol, acetone and propane (R-290).
  • a condenser 1932 can be configured to condense the working fluid, and the working fluid can be supplied to the boiler 1928 to repeat the cycle.
  • the waste heat from the turbine exhaust 1909 can be transferred to the reformer(s) 108-110 via the heat exchanger 1912.
  • the waste heat from the turbine exhaust 1909 can be used to heat the working fluid in the boiler 1928.
  • the waste heat from the turbine exhaust 1909 can be transferred to the reformer(s) 108-110 (e.g., for a second time).
  • the waste heat from the turbine exhaust 1909 can be provided directly to the boiler 1928 to heat the working fluid (e g., without first being transferred to the reformer(s) 108- 110), and subsequently can be directed to the heat exchanger 1912 to heat the reformer(s) 108-110.
  • a compressor 1934 can pressurize the reformate stream 120.
  • an additional heater 1936 e.g., an electrical heater
  • the turbine 1930 can comprise a plurality of stages 1930a-c.
  • Each stage 1930a-c can operate at a different pressure (e.g., working fluid pressure).
  • working fluid pressure e.g., working fluid pressure
  • the working fluid can pass the high pressure stage 1930a at a relatively higher pressure.
  • the working fluid can pass the medium pressure stage 1930b at a lower pressure.
  • the working fluid can pass the low pressure stage 1930c at yet a lower pressure, and can be circulated to the condenser 1932 to repeat the Rankine cycle.
  • the reformer(s) 108-110 can be in thermal communication with (and/or adjacent to) the boiler 1928.
  • the working fluid can be heated by the turbine exhaust 1909, and the working fluid can transfer heat to the reformer(s) 108-110.
  • the reformer(s) 108-110 can be in thermal communication with (and/or adjacent to) at least one of the plurality of stages 1930a-c.
  • the working fluid transfers heat from at least one of the plurality of stages 1930a-c to the reformer(s) 108-100.
  • the turbine exhaust 1909 can be divided into a first stream 1909a and a second stream 1909b.
  • the first stream 1909a can transfer heat to the boiler 1928 to heat the working fluid
  • the second stream 1909b can transfer heat to the reformer(s) 108-110 via the heat exchanger 1912.
  • the first stream 1909a can comprise at least about 1, 5, 10, 15, 20, 25, 30, 35, 40, 45, 50, 55, 60, 65, 70, 75, 80, 85, 90, 95, or 100% of the turbine exhaust 1909 by volume. In some cases, the first stream 1909a can comprise at most about 1, 5, 10, 15, 20, 25, 30, 35, 40, 45, 50, 55, 60, 65, 70, 75, 80, 85, 90, 95, or 100% of the turbine exhaust 1909 by volume.
  • the second stream 1909b can comprise at least about 1, 5, 10, 15, 20, 25, 30, 35, 40, 45, 50, 55, 60, 65, 70, 75, 80, 85, 90, 95, or 100% of the turbine exhaust 1909 by volume. In some cases, the second stream 1909b can comprise at most about 1, 5, 10, 15, 20, 25, 30, 35, 40, 45, 50, 55, 60, 65, 70, 75, 80, 85, 90, 95, or 100% of the turbine exhaust 1909 by volume.
  • all of the turbine exhaust 1909 can be directed as the first steam 1909a to heat the reform er(s) 108-110 (and none of the turbine exhaust 1909 can be directed as the second stream 1909b to the boiler 1928). In some cases, all of the turbine exhaust 1909 can be directed as the second steam 1909b to heat the reformer(s) 108-110 (and none of the turbine exhaust 1909 can be directed as the first stream 1909a to the reformer(s) 108-110). Directing more heat from the turbine exhaust 1909 to the reformer(s) 108-110 can increase energy efficiency, while directing more heat from the turbine exhaust 1909 to the boiler 1928 to drive the turbine 1930 can increase electrical power output. In some cases, a fraction of the turbine exhaust 1909 directed as the first stream 1909a changes over time based at least in part on the electrical power output or electrical load demand.
  • FIG. 171 is a schematic diagram illustrating an ammonia decomposition system 1900i, in accordance with one or more embodiments of the present disclosure.
  • the components of system 1900j described with respect to FIG. 171 can be substantially similar in form and function to the components of systems 1900a-h described with respect to FIGS. 17A-H.
  • a reformer and a combustor can be integrated as a single module 1938 (e.g., a combined reformer/combustor 1938).
  • the combined ref ormer/ combustor 1938 can be an autothermal reformer (ATR).
  • the ammonia stream 104 can be partially oxidized (e.g., so that only a portion of the ammonia is oxidized) in the reformer/combustor 1938.
  • the partially oxidized portion can comprise at least about 1, 5, 10, 15, 20, 25, 30, 35, 40, 45, 50, 55, 60, 65, 70, 75, 80, 85 or 90% of the ammonia by volume.
  • the partially oxidized portion can comprise at most about 1, 5, 10, 15, 20, 25, 30, 35, 40, 45, 50, 55, 60, 65, 70, 75, 80, 85, 90, or 95% of the ammonia by volume.
  • the partial oxidation can provide heat for reforming ammonia in the reformer/combustor 1938 to generate hydrogen and nitrogen.
  • the ammonia that is not partially oxidized is reformed.
  • the portion of the ammonia that is reformed can comprise at least about 25, 30, 35, 40, 45, 50, 55, 60, 65, 70, 75, 80, 85 90, 95%, or 100% of the ammonia that is not oxidized by volume.
  • the portion of the ammonia that is reformed can comprise at most about 25, 30, 35, 40, 45, 50, 55, 60, 65, 70, 75, 80, 85 90, 95%, or 100% of the ammonia that is not oxidized by volume.
  • the mixture of hydrogen and nitrogen (and optionally ammonia) is combusted in the reform er/combustor 1938 to drive the gas turbine 1904.
  • the ref ormer/ combustor 1938 can receive air 1908 via the compressor 1906.
  • the combustion of the mixture in the reform er/combustor 1938 can be stoichiometric, fuel-lean, or air-rich.
  • the combustion of the mixture in the reformer/combustor 1938 is air-rich.
  • the combustion of the mixture in the reformer/combustor 1938 is air-rich and fully combusts the mixture.
  • the reformer/combustor 1938 comprises a single housing or vessel. In some cases, the reformer and the combustor can share the single housing or vessel. In some cases, the reformer and the combustor can be located in separate chambers of the single housing or vessel. In some cases, the reformer and the combustor can be located in separate chambers.
  • the partial oxidation step and the reforming step occur in a first housing or vessel, and the combustion step occurs in a second housing or vessel. In some cases, the partial oxidation step, the reforming step, and/or the combustion step occur in the same housing or vessel. In some cases, each of the partial oxidation step, the reforming step, and/or the combustion step occur in different housing or vessels.
  • the air 1908 and ammonia 104 are premixed before the partial oxidation step. In some cases, the air 1908 and the hydrogen and nitrogen generated in the reforming step (and optionally ammonia) are premixed before the combustion step.
  • the air 1908 and ammonia 104 are not premixed before the partial oxidation step. In some cases, the air 1908 and the hydrogen and nitrogen generated in the reforming step (and optionally ammonia) are not premixed before the combustion step.
  • FIG. 17J is a schematic diagram illustrating an ammonia decomposition system 1900j, in accordance with one or more embodiments of the present disclosure.
  • the components of system 1900j described with respect to FIG. 17 J can be substantially similar in form and function to the components of systems 1900a-i described with respect to FIGS. 17A-I.
  • a prereformer 1940 can be utilized to partially reform the ammonia stream 104 and generate hydrogen and nitrogen.
  • the ammonia that is not converted by the prereformer 1940 can be further converted by the reformer(s) 108-110.
  • the prereformer 1940 can reform the ammonia stream 104 at an ammonia conversion efficiency that is at most about 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%. In some cases, the prereformer 1940 can reform the ammonia stream 104 at an ammonia conversion efficiency that is at least about 5, 10, 20, 30, 40, 50, 60, 70, 80, or 90%. [00548] In some cases, the reformer(s) 108-110 can reform the unconverted ammonia at an ammonia conversion efficiency that is at most about 80, 85, 90, 95, 99 or 99.9%.
  • the reformer(s) 108-110 can reform the unconverted ammonia at an ammonia conversion efficiency that is at least about 80, 85, 90, 95, or 99%.
  • the ammonia stream 104 can be substantially or fully reformed to generate the reformate stream 120 (e.g., to greater than about 99% ammonia conversion) for combustion to drive the gas turbine 1904.
  • the heat from the turbine exhaust 1909 (which can be sufficient to partially crack the ammonia 104) is transferred to the prereformer 1940 via the heat exchanger 1942.
  • the prereformer 1940 can be substantially similar or substantially identical in form and function to the reformer 108 and/or the reformer 110.
  • the prereformer 1940 can be heated by a combustion heater and/or an electrical heater in thermal communication with the prereformer 1940, and the prereformer 1940 can comprise an ammonia reforming catalyst therein.
  • a portion of the hydrogen generated by the prereformer 1940, the reformer(s) 108-110, or a combination thereof can be combusted to heat the prereformer 1940, reform er(s) 108-110, or a combination thereof.
  • FIG. 17K is a schematic diagram illustrating an ammonia decomposition system 1900k, in accordance with one or more embodiments of the present disclosure.
  • the components of system 1900k described with respect to FIG. 17K can be substantially similar in form and function to the components of systems 1900a-j described with respect to FIGS. 17A-J.
  • the reformer(s) 108-110 can operate without being heated using the turbine exhaust 1909. In this way, the reformer(s) 108-110 can be easily integrated (i.e., retrofitted) with existing gas turbines (for example, natural gas turbines). In some cases, the reformer(s) 108-110 can be installed and configured modularly. For example, an array of reformers 108-110 (for example, ten or more reformers 108-110) can be in fluid communication with the combustor 1902 of the gas turbine 1904.
  • FIGS. 17L-M are schematic diagrams illustrating ammonia decomposition systems 19001-m, in accordance with one or more embodiments of the present disclosure.
  • the components of systems 19001-m described with respect to FIGS. 17L-M can be substantially similar in form and function to the components of systems 1900a-k described with respect to FIGS. 17A-K.
  • compressed air 1906a can be provided from the compressor 1906 to the heat exchanger 1912, thereby transferring heat from the compressed air 1906a to the reformer(s) 108-110. After being cooled by the heat exchanger 1912, the compressed air 1906 can be used to cool the turbine 1904.
  • compressed air 1906a can be provided from the compressor 1906 to the heat exchanger 1912, thereby transferring heat from the compressed air 1906a to the reformer(s) 108-110. After being cooled by the heat exchanger 1912, the compressed air 1906 can be provided to the combustor 1902.
  • FIG. 17N is a schematic diagram illustrating an ammonia decomposition system 1900o, in accordance with one or more embodiments of the present disclosure.
  • the components of system 1900o described with respect to FIG. 17N can be substantially similar in form and function to the components of systems 1900a-m described with respect to FIGS. 17A-M.
  • turbine exhaust 1909 can be provided to the heat exchanger 1912, thereby transferring heat from the turbine exhaust 1909 to the reformer(s) 108-110. After being cooled by the heat exchanger 1912, the turbine exhaust 1909 can be used to cool the turbine 1904.
  • the cooling of turbine prevents overheating of the turbine and advantageously improves the durability of the turbine.
  • the reformer(s) 108-110 can comprise one or more catalysts configured to convert the ammonia stream 104 to the reformate stream 120.
  • the catalyst can comprise a support comprising alumina (AI2O3) doped with at least one of lanthanum (La), cerium (Ce), or cesium (Cs), and an active metal comprising ruthenium (Ru) adjacent to the support.
  • AI2O3 alumina
  • Ce cerium
  • Cs cesium
  • Ru ruthenium
  • the catalyst can comprise a support comprising zirconia (ZrCh) doped with cerium (Ce) and/or potassium (K), and an active metal comprising ruthenium (Ru) adjacent to the support.
  • ZrCh zirconia
  • Ce cerium
  • K potassium
  • Ru ruthenium
  • the catalyst comprises an active metal comprising cobalt (Co), molybdenum (Mo), and X, wherein X comprises Ni, Fe, Cr, Cu, Mn, or Zn.
  • the catalyst can comprise a support comprising a conductive material (e.g., silicon carbide (SiC)) and an active metal adjacent to the support.
  • a conductive material e.g., silicon carbide (SiC)
  • an active metal adjacent to the support.
  • the catalyst can comprise a support comprising alumina (AI2O3) doped with magnesium oxide (MgO) and an active metal comprising ruthenium (R.u) adjacent to the support.
  • the catalyst can comprise a support comprising at least one of alumina (e.g., alpha alumina, gamma alumina, theta alumina, or a combination thereof), silica, carborundum, zeolite, ceria, zirconia, graphite oxide, carbon, graphene, carbon nanofibers or carbon nanotubes, and an active metal comprising ruthenium (Ru) adjacent to the support.
  • the support is doped with at least one of a rare earth metal, an alkali metal or an alkaline earth metal.
  • the support comprises a support surface modifier or a promoter.
  • a hydrogen carrier can be reformed in the reformers 108 and 110 instead of ammonia, and that the HC can replace ammonia for any embodiment described herein.
  • the HC comprises an alkane
  • the reforming reaction performed in the reformers 108-110 comprises:
  • the HC can comprise methane (CH4)
  • the reforming reaction and a water gas-shift (WGS) reaction performed in the reformers 108-110 comprises:
  • the HC can comprise ethane, methane, propane, butane, pentane, hexane, heptane, octane, nonane, decane, a higher alkane, an isomer thereof, or any combination thereof.
  • the HC comprises an alcohol.
  • the HC can comprise methanol
  • the reforming reaction performed in the reformers 108-110 comprises:
  • the HC can comprise ethanol, methanol, propanol, butanol, pentanol, hexanol, heptanol, octanol, nonanol, decanol, a higher alcohol, an isomer thereof, or any combination thereof.
  • the HC comprises a liquid organic hydrogen carrier (LOHC).
  • LOHC liquid organic hydrogen carrier
  • the reforming reaction performed in the reformers 108-110 comprises:
  • the HC can comprise cyclohexane (e.g., which can be reformed to benzene), methylcyclohexane (e.g., which can be reformed to toluene), decalin (e.g., which can be reformed to naphthalene), perhydro-N- ethyl carb azole (e.g., which can be reformed to N-ethylcarbazole), perhydrodibenzyltoluene (e.g., which can be reformed to dibenzyltoluene).
  • cyclohexane e.g., which can be reformed to benzene
  • methylcyclohexane e.g., which can be reformed to toluene
  • decalin e.g., which can be reformed to naphthalene
  • perhydro-N- ethyl carb azole e.g
  • FIG. 17 shows a computer system 2001 that is programmed or otherwise configured to control the systems disclosed herein.
  • the computer system 2001 can regulate various aspects of the systems disclosed in the present disclosure.
  • the computer system 2001 can be an electronic device of a user or a computer system that is remotely located with respect to the electronic device.
  • the electronic device can be a mobile electronic device.
  • the computer system 2001 comprises a central processing unit (CPU, also “processor” and “computer processor” herein) 2005, which can be a single core or multi core processor, or a plurality of processors for parallel processing.
  • the computer system 2001 also comprises memory or memory location 2010 (e.g., random-access memory, read-only memory, flash memory), electronic storage unit 2015 (e g., hard disk), communication interface 2020 (e.g., network adapter) for communicating with one or more other systems, and peripheral devices 2025, such as cache, other memory, data storage and/or electronic display adapters.
  • the memory 2010, storage unit 2015, interface 2020 and peripheral devices 2025 are in communication with the CPU 2005 through a communication bus (solid lines), such as a motherboard.
  • the storage unit 2015 can be a data storage unit (or data repository) for storing data.
  • the computer system 2001 can be operatively coupled to a computer network (“network”) 2030 with the aid of the communication interface 2020.
  • the network 2030 can be the Internet, an internet and/or extranet, or an intranet and/or extranet that is in communication with the Internet.
  • the network 2030 in some cases is a telecommunication and/or data network.
  • the network 2030 can comprise one or more computer servers, which can enable distributed computing, such as cloud computing.
  • the network 2030 in some cases with the aid of the computer system 2001, can implement a peer-to-peer network, which can enable devices coupled to the computer system 2001 to behave as a client or a server.
  • the CPU 2005 can execute a sequence of machine-readable instructions, which can be embodied in a program or software.
  • the instructions can be stored in a memory location, such as the memory 2010.
  • the instructions can be directed to the CPU 2005, which can subsequently program or otherwise configure the CPU 2005 to implement methods of the present disclosure. Examples of operations performed by the CPU 2005 can include fetch, decode, execute, and writeback.
  • the CPU 2005 can be part of a circuit, such as an integrated circuit.
  • a circuit such as an integrated circuit.
  • One or more other components of the system 2001 can be included in the circuit.
  • the circuit is an application specific integrated circuit (ASIC).
  • ASIC application specific integrated circuit
  • the storage unit 2015 can store files, such as drivers, libraries and saved programs.
  • the storage unit 2015 can store user data, e.g., user preferences and user programs.
  • the computer system 2001 in some cases can include one or more additional data storage units that are external to the computer system 2001, such as located on a remote server that is in communication with the computer system 2001 through an intranet or the Internet.
  • the computer system 2001 can communicate with one or more remote computer systems through the network 2030.
  • the computer system 2001 can communicate with a remote computer system of a user.
  • remote computer systems include personal computers (e.g., portable PC), slate or tablet PC’s (e.g., Apple® iPad, Samsung® Galaxy Tab), telephones, Smart phones (e.g., Apple® iPhone, Android-enabled device, Blackberry®), or personal digital assistants.
  • the user can access the computer system 2001 via the network 2030.
  • Methods as described herein can be implemented by way of machine (e.g., computer processor) executable code stored on an electronic storage location of the computer system 2001, such as, for example, on the memory 2010 or electronic storage unit 2015.
  • the machine executable or machine readable code can be provided in the form of software.
  • the code can be executed by the processor 2005.
  • the code can be retrieved from the storage unit 2015 and stored on the memory 2010 for ready access by the processor 2005.
  • the electronic storage unit 2015 can be precluded, and machine-executable instructions are stored on memory 2010.
  • the code can be pre-compiled and configured for use with a machine having a processer adapted to execute the code, or can be compiled during runtime.
  • the code can be supplied in a programming language that can be selected to enable the code to execute in a pre-compiled or as- compiled fashion.
  • aspects of the systems and methods provided herein, such as the computer system 2001, can be embodied in programming.
  • Various aspects of the technology can be thought of as “products” or “articles of manufacture” typically in the form of machine (or processor) executable code and/or associated data that is carried on or embodied in a type of machine readable medium.
  • Machine-executable code can be stored on an electronic storage unit, such as memory (e.g., read-only memory, random-access memory, flash memory) or a hard disk.
  • “Storage” type media can include any or all of the tangible memory of the computers, processors or the like, or associated modules thereof, such as various semiconductor memories, tape drives, disk drives and the like, which can provide non-transitory storage at any time for the software programming. All or portions of the software can at times be communicated through the Internet or various other telecommunication networks. Such communications, for example, can enable loading of the software from one computer or processor into another, for example, from a management server or host computer into the computer platform of an application server.
  • another type of media that can bear the software elements include optical, electrical and electromagnetic waves, such as used across physical interfaces between local devices, through wired and optical landline networks and over various air-links.
  • a machine readable medium such as computer-executable code
  • a machine readable medium can take many forms, including but not limited to, a tangible storage medium, a carrier wave medium or physical transmission medium.
  • Non-volatile storage media include, for example, optical or magnetic disks, such as any of the storage devices in any computer(s) or the like, such as can be used to implement the databases, etc. shown in the drawings.
  • Volatile storage media include dynamic memory, such as main memory of such a computer platform.
  • Tangible transmission media include coaxial cables; copper wire and fiber optics, including the wires that comprise a bus within a computer system.
  • Carrier-wave transmission media can take the form of electric or electromagnetic signals, or acoustic or light waves such as those generated during radio frequency (RF) and infrared (IR) data communications.
  • RF radio frequency
  • IR infrared
  • Common forms of computer-readable media therefore include for example: a floppy disk, a flexible disk, hard disk, magnetic tape, any other magnetic medium, a CD-ROM, DVD or DVD-ROM, any other optical medium, punch cards paper tape, any other physical storage medium with patterns of holes, a RAM, a ROM, a PROM and EPROM, a FLASH-EPROM, any other memory chip or cartridge, a carrier wave transporting data or instructions, cables or links transporting such a carrier wave, or any other medium from which a computer can read programming code and/or data.
  • the computer system 2001 can comprise or be in communication with an electronic display 2035 that comprises a user interface (UI) 2040 for providing.
  • UI user interface
  • Examples of UI’s include, without limitation, a graphical user interface (GUI) and web-based user interface.
  • Methods and systems of the present disclosure can be implemented by way of one or more algorithms.
  • An algorithm can be implemented by way of software upon execution by the central processing unit 2005.
  • the computer system 2001 can be substantially similar or substantially identical to the controller 200 described with respect to FIGS. 5A-5I.
  • the processor(s) 202 can be substantially similar or substantially identical to the central processing unit 2005
  • the memory 204 can be substantially similar or substantially identical to the memory 2010.
  • the maintaining step further comprises changing power of the electrical heater.
  • the maintaining step further comprises decreasing power of the electrical heater.
  • the method further comprising decreasing power of the electrical heater.
  • the method further comprising: measuring a temperature in the reformer; and based at least in part on the measured temperature being outside of the target temperature range, changing power of the electrical heater to maintain the reformer at the target temperature range.
  • the method further comprising heating the ammonia, before the ammonia enters the reformer, to a temperature that is greater than about 25 °C and less than about 650 °C using the heat of the combustion exhaust of the gas turbine.
  • heating the ammonia evaporates at least a portion of the ammonia before the ammonia enters the reformer.
  • the method further comprising, before decomposing the ammonia, pressurizing the ammonia to greater than about 5 barg and less than about 50 barg.
  • the method further comprising, before combusting the reformate stream, pressurizing the reformate stream to greater than about 10 barg and less than about 300 barg.
  • ammonia is decomposed at an ammonia conversion efficiency of greater than about 5% and less than about 99%.
  • the method further comprising combusting ammonia and the reformate stream in the combustor of the gas turbine.
  • the method further comprising controlling a molar ratio of the ammonia to the hydrogen in the reformate stream for the combustion of the ammonia and the reformate stream.
  • the method further comprising, before combusting the reformate stream in the combustor, combusting natural gas in the combustor.
  • the method further comprising blending the reformate stream with natural gas to form a blended gas and combusting the blended gas in the combustor.
  • the method further comprising injecting water into the combustor of the gas turbine to reduce a flame temperature and/or increase a heat transfer coefficient.
  • the method further comprising storing auxiliary hydrogen in a hydrogen storage tank.
  • the method further comprising combusting the auxiliary hydrogen in the combustor of the gas turbine.
  • the method further comprising generating the auxiliary hydrogen using the reformate stream.
  • the method further comprising generating the auxiliary hydrogen using an electrolyzer.
  • the method further comprising generating auxiliary oxygen using the electrolyzer.
  • the method further comprising storing the auxiliary oxygen in an oxygen storage tank.
  • the method further comprising combusting the auxiliary oxygen in the combustor of the gas turbine.
  • the method further comprising removing or reducing residual NOx from the combustion exhaust of the gas turbine using a selective catalytic reduction (SCR) catalyst, wherein the residual NOx comprises nitrogen oxide (NO) or nitrogen dioxide (NO2).
  • SCR selective catalytic reduction
  • the method further comprising removing or reducing residual NH3 from the combustion exhaust of the gas turbine using a selective ammonia oxidation (SAO) catalyst.
  • SAO selective ammonia oxidation
  • the method further comprising removing or reducing residual NH3 from the reformate stream using a selective ammonia oxidation (SAO) catalyst.
  • SAO selective ammonia oxidation
  • the method further comprising, before (c), removing or reducing residual ammonia in the reformate stream using an ammonia filter.
  • the method further comprising directing the combustion exhaust of the gas turbine to the ammonia filter to desorb the residual ammonia from the ammonia filter, thereby regenerating the ammonia filter.
  • the method further comprising generating steam to drive a steam turbine using the heat of the combustion exhaust of the gas turbine.
  • the ammonia is decomposed by contacting the ammonia with a catalyst
  • the catalyst comprises: a support comprising alumina (AI2O3) doped with lanthanum (La), cerium (Ce), and/or cesium (Cs); and an active metal comprising ruthenium (Ru) adjacent to the support.
  • the ammonia is decomposed by contacting the ammonia with a catalyst, wherein the catalyst comprises: a support comprising zirconia (ZrO2) doped with cerium (Ce) and/or potassium (K); and an active metal comprising ruthenium (Ru) adjacent to the support.
  • ZrO2 zirconia
  • Ce cerium
  • K potassium
  • Ru ruthenium
  • the ammonia is decomposed by contacting the ammonia with a catalyst, wherein the catalyst comprises: a support comprising alumina (AI2O3); and an active metal comprising ruthenium (Ru) adjacent to the support.
  • a catalyst comprising: a support comprising alumina (AI2O3); and an active metal comprising ruthenium (Ru) adjacent to the support.
  • the ammonia is decomposed by contacting the ammonia with a catalyst, wherein the catalyst comprises at least: an active metal comprising cobalt (Co), molybdenum (Mo), and X, wherein X comprises Ni, Fe, Cr, Cu, Mn, or Zn.
  • a catalyst comprises at least: an active metal comprising cobalt (Co), molybdenum (Mo), and X, wherein X comprises Ni, Fe, Cr, Cu, Mn, or Zn.
  • a method for reforming ammonia comprises: e. decomposing the ammonia at an ammonia flow rate in a reformer to generate a reformate stream comprising hydrogen and nitrogen, wherein a target temperature range of the reformer is greater than about 200 °C and less than about 650 °C; optionally combusting a first portion of the reformate stream in a combustion heater to heat the reformer using oxygen at a first oxygen flow rate; g. combusting a second portion of the reformate stream in a combustor of a gas turbine using oxygen at a second oxygen flow rate; and h. maintaining the reformer at the target temperature range using, at least in part, heat from a combustion exhaust of the gas turbine.
  • a method for reforming ammonia comprises: e. decomposing the ammonia at an ammonia flow rate in a reformer to generate a reformate stream comprising hydrogen and nitrogen, wherein a target temperature range of the reformer is greater than about 200 °C and less than about 650 °C; f. combusting a first portion of the reformate stream in a combustion heater to heat the reformer using oxygen at a first oxygen flow rate; g. combusting a second portion of the reformate stream in a combustor of a gas turbine using oxygen at a second oxygen flow rate; and h. maintaining the reformer at the target temperature range using, at least in part, heat from a combustion exhaust of the gas turbine.
  • the method comprising (f) combusting the first portion of the reformate stream in the combustion heater to heat the reformer.
  • the method further comprising the step of transferring heat from the combustion exhaust of the gas turbine to a boiler to heat a working fluid.
  • the method further comprising the step of using the working fluid to drive the gas turbine.
  • the method further comprising performing one or more of: i. changing the ammonia flow rate, ii. changing the first oxygen flow rate, or iii. changing the first portion of the reformate stream.
  • the method further comprising: measuring a temperature in the reformer; and based at least in part on the measured temperature being outside of the temperature range, performing one or more of: i. changing the ammonia flow rate, ii. changing the first oxygen flow rate, iii. changing a percentage of the reformate stream that is the first portion of the reformate stream, iv. changing a percentage of the reformate stream that is the second portion of the reformate stream, or v. changing a percentage of the reformate stream that is directed out of the combustion heater.
  • the method further comprising, based on an increased amount of the hydrogen combusted in the combustor of the gas turbine, performing one or more of: q. increasing the ammonia flow rate; r. increasing the first oxygen flow rate; s. increasing the second oxygen flow rate; t. increasing the percentage of the reformate stream that is the first portion of the reformate stream; or u. increasing the percentage of the reformate stream that is the second portion of the reformate stream.
  • the method further comprising, based on a decreased amount of the hydrogen combusted in the combustor of the gas turbine, performing one or more of: v. decreasing the ammonia flow rate; w. decreasing the first oxygen flow rate; x. decreasing the second oxygen flow rate; y. decreasing the percentage of the reformate stream that is the first portion of the reformate stream; or z. decreasing the percentage of the reformate stream that is the second portion of the reformate stream.
  • the reformer comprises a first reformer and a second reformer.
  • ammonia is directed to the first reformer before being directed to the second reformer.
  • ammonia flow rate is subsequently increased to a second target ammonia flow rate range when the first target ammonia flow rate range is reached.
  • the method further comprising powering an electrical heater to heat the first reformer from a first temperature to a second temperature, wherein the second temperature is in the target temperature range.
  • the method further comprising decreasing power of the electrical heater.
  • the method further comprising: measuring a temperature in the first reformer; and based at least in part on the measured temperature being outside of the target temperature range, changing power of the electrical heater to maintain the first reformer at the target temperature range.
  • the electrical heater comprises a resistive heater.
  • the electrical heater comprises an induction heater.
  • the method further comprising, powering an electrical heater to heat the reformer from a first temperature to a second temperature, wherein the second temperature is in the target temperature range.
  • the method further comprising decreasing power of the electrical heater.
  • the method further comprising: measuring a temperature in the reformer; and based at least in part on the measured temperature being outside of the second temperature, changing power of the electrical heater to maintain the reformer at the second temperature.
  • a method for reforming ammonia comprises: j. decomposing ammonia in a reformer to generate a reformate stream comprising hydrogen and nitrogen; k. combusting the reformate stream in a combustor for a gas turbine; 1. transferring heat from a combustion exhaust of the gas turbine to a boiler to heat a working fluid; and m. using the working fluid to drive a turbine.
  • the working fluid is water.
  • the method further comprising transferring the heat from the combustion exhaust to the reformer.
  • the method further comprising transferring heat from the boiler to the reformer.
  • the turbine comprises a plurality of stages, wherein at least one stage in the plurality of stages operates at a different pressure than another stage of the plurality of stages.
  • a method for reforming ammonia comprises: n. partially oxidizing ammonia to generate heat; o. decomposing the ammonia using the heat to generate a reformate stream comprising hydrogen and nitrogen; p. combusting the reformate stream to generate combustion exhaust; and aa. using the combustion exhaust to drive a gas turbine.
  • a method for reforming ammonia comprises: bb. transferring heat from a combustion exhaust of a gas turbine to a prereformer; cc. decomposing ammonia at least partially using the prereformer to generate a reformate stream comprising hydrogen, nitrogen, and unconverted ammonia; dd. decomposing the unconverted ammonia in the reformate stream using a reformer to generate additional hydrogen and nitrogen for the reformate stream; ee. combusting the reformate stream to generate additional combustion exhaust; and ff driving a gas turbine using the additional combustion exhaust.
  • the method further comprising heating the reformer by combusting a portion of the hydrogen generated by the prereformer, the reformer, or a combination thereof.
  • a method for reforming ammonia comprises: gg. compressing air using a compressor; hh. transferring heat from the air to a reformer; jj. decomposing ammonia in the reformer to generate a reformate stream comprising hydrogen and nitrogen; and kk. combusting the reformate stream in a combustor for a gas turbine.
  • the method further comprising transferring heat from the gas turbine to the air to cool the gas turbine.
  • a method for reforming ammonia comprising: 11. transferring heat from a combustion exhaust of a gas turbine to a reformer, thereby cooling the combustion exhaust; and mm. transferring heat from the gas turbine to the combustion exhaust to cool the gas turbine.
  • the method further comprising decomposing ammonia in the reformer to generate a reformate stream comprising hydrogen and nitrogen.
  • the method further comprising combusting the reformate stream in a combustor for a gas turbine.

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Abstract

La présente divulgation concerne des systèmes et des procédés de traitement d'ammoniac. Un dispositif de chauffage peut chauffer des reformeurs, les reformeurs comprenant des catalyseurs de reformage d'ammoniac (NH3) en communication thermique avec le dispositif de chauffage. Du NH3 peut être dirigé vers les reformeurs depuis des réservoirs de stockage, et le NH3 peut être décomposé pour générer un flux de reformat comprenant de l'hydrogène (H2) et de l'azote (N2). Au moins une partie du flux de reformat peut être brûlée pour chauffer les reformeurs. Une turbine à gaz peut brûler le flux de reformat pour générer de l'électricité.
PCT/US2024/011734 2023-01-17 2024-01-17 Systèmes et procédés de traitement d'ammoniac pour la production d'énergie à l'aide de turbines à gaz Ceased WO2024155649A1 (fr)

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Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US12491498B2 (en) 2021-06-11 2025-12-09 Amogy Inc. Systems and methods for processing ammonia

Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO1996033794A1 (fr) * 1995-04-25 1996-10-31 Energy And Environmental Research Corporation Procedes et systemes de transfert thermique a l'aide d'un catalyseur avec agent de combustion non melange
WO2021151885A1 (fr) * 2020-01-31 2021-08-05 Casale Sa Procédé de reformage intégré à un générateur à turbine à gaz
WO2022241260A1 (fr) * 2021-05-14 2022-11-17 Amogy Inc. Systèmes et procédés de traitement d'ammoniac
WO2022245879A2 (fr) * 2021-05-18 2022-11-24 Obantarla Corp. Systèmes et procédés de conversion de gaz de torche modulaires autonomes
US20220403775A1 (en) * 2021-05-14 2022-12-22 Amogy Inc. Systems and methods for processing ammonia

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO1996033794A1 (fr) * 1995-04-25 1996-10-31 Energy And Environmental Research Corporation Procedes et systemes de transfert thermique a l'aide d'un catalyseur avec agent de combustion non melange
WO2021151885A1 (fr) * 2020-01-31 2021-08-05 Casale Sa Procédé de reformage intégré à un générateur à turbine à gaz
WO2022241260A1 (fr) * 2021-05-14 2022-11-17 Amogy Inc. Systèmes et procédés de traitement d'ammoniac
US20220403775A1 (en) * 2021-05-14 2022-12-22 Amogy Inc. Systems and methods for processing ammonia
WO2022245879A2 (fr) * 2021-05-18 2022-11-24 Obantarla Corp. Systèmes et procédés de conversion de gaz de torche modulaires autonomes

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US12491498B2 (en) 2021-06-11 2025-12-09 Amogy Inc. Systems and methods for processing ammonia

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