METHOD FOR RETROFITTING A HYDROGEN PRODUCTION UNIT

Abstract

A method is described for retrofitting a hydrogen production unit, said hydrogen production unit having, a purification unit that separates the hydrogen-enriched gas into a hydrogen product stream and an off-gas stream, said method comprising the steps of: (a) installing a gas-heated reformer, and installing a carbon dioxide removal unit; (b) feeding a mixture of hydrocarbon and steam the gas-heated reformer, (c) combining the gas recovered with a second gas recovered and using the combined synthesis gas to heat reformer tubes in the gas-heated reformer; (d) recovering a cooled gas and passing the cooled gas to the water gas shift unit; (e) feeding the gas to the carbon dioxide removal unit to produce a carbon dioxide stream and a crude hydrogen stream, and; (f) passing the crude hydrogen stream to the purification unit. The invention further includes a process and system for producing hydrogen using the production unit.

Claims

1. A method for retrofitting a hydrogen production unit, said hydrogen production unit comprising, in series, a fired reformer containing a plurality of catalyst-containing reformer tubes fed with a mixture of hydrocarbon and steam and heated by combustion of a hydrocarbon fuel gas; a water gas shift unit fed with a synthesis gas recovered from the fired reformer that produces a hydrogen-enriched gas; and a purification unit that separates the hydrogen-enriched gas into a hydrogen product stream and an off-gas stream, said method comprising the steps of: (a) installing a gas-heated reformer in parallel to the fired reformer, and installing a carbon dioxide removal unit between the water-gas shift unit and the purification unit; (b) feeding a further portion of the mixture of hydrocarbon and steam to a plurality of catalyst-containing gas-heated reformer tubes in the gas-heated reformer, (c) combining the synthesis gas recovered from the fired reformer with a second synthesis gas recovered from the plurality of catalyst-containing gas-heated reformer tubes to form a combined synthesis gas mixture and using the combined synthesis gas mixture to heat the catalyst-containing gas-heated reformer tubes in a shell side of the gas-heated reformer; (d) recovering a partially cooled synthesis gas from the shell side of the gas-heated reformer and passing the partially cooled synthesis gas to the water gas shift unit; (e) feeding the hydrogen-enriched gas from the water-gas shift unit to the carbon dioxide removal unit to produce a carbon dioxide stream and a crude hydrogen stream, and; (f) passing at least a portion of the crude hydrogen stream to the purification unit to produce a purified hydrogen stream, wherein a portion of the crude hydrogen stream and/or a portion of the purified hydrogen stream are fed to the fired reformer in replacement of at least a portion of the hydrocarbon fuel gas.

2. The method according to claim 1, wherein the hydrocarbon in the mixture of hydrocarbon and steam comprises more than 50% by volume methane and prior to the retrofit, the hydrocarbon fuel gas comprises more than 50% by volume methane.

3. The method according to claim 1, wherein the hydrocarbon in the mixture of hydrocarbon and steam comprises natural gas, associated gas, LPG, petroleum distillate, diesel, naphtha or mixtures thereof, a refinery off-gas, or a pre-reformed gas.

4. The method according to claim 1, wherein the hydrocarbon fuel gas comprises natural gas.

5. The method according to claim 1, wherein a portion of the crude hydrogen stream and a portion of the purified hydrogen stream are fed to the fired reformer in replacement of at least a portion of the hydrocarbon fuel gas.

6. The method according to claim 1, wherein the gas-heated reformer is sized to provide essentially all of the hydrogen used as fuel in the fired steam reformer.

7. The method according to claim 1, wherein an adiabatic high temperature shift vessel containing an iron catalyst in the existing water gas shift unit is replaced with a cooled isothermal water gas shift vessel containing a copper catalyst.

8. The method according to claim 1, wherein the carbon dioxide removal unit operates by means of a physical wash system or a reactive wash system, preferably a reactive wash system, especially an amine wash system.

9. The method according to claim 1 wherein the purification unit operates by pressure swing adsorption and/or temperature swing adsorption.

10. The method according to claim 1, wherein at least a portion of the off-gas, stream is added to the hydrocarbon or the hydrocarbon and steam mixture fed to the steam reformers.

11. A process for the production of hydrogen comprising the steps of: (a) feeding a mixture of hydrocarbon and steam to a plurality of catalyst-containing reformer tubes in fired reformer that are heated by combustion of a fuel; (b) in parallel, passing a further portion of the mixture of hydrocarbon and steam to a plurality of catalyst-containing gas-heated reformer tubes in a gas-heated reformer; (c) combining a synthesis gas recovered from the fired reformer with a second synthesis gas recovered from the catalyst-containing gas-heated reformer tubes to form a combined synthesis gas mixture and using the combined synthesis gas mixture to heat the catalyst-containing gas-heated reformer tubes in a shell side of the gas heated reformer; (d) recovering a partially cooled synthesis gas from the shell side of the gas heated reformer and passing the partially cooled synthesis gas to a water gas shift unit to produce a hydrogen-enriched gas; (e) passing the hydrogen-enriched gas to a carbon dioxide removal unit that removes carbon dioxide from the hydrogen-enriched gas to provide a crude hydrogen stream; and (f) passing at least portion of the crude hydrogen stream to a purification unit that separates the crude hydrogen into a purified hydrogen stream and an off-gas stream, wherein a portion of the crude hydrogen stream and/or a portion of the purified hydrogen stream is fed to the fired reformer as fuel for the combustion.

12. The process recited in claim 11, wherein a portion of the crude hydrogen stream and a portion of the purified hydrogen stream are fed to the fired reformer as fuel for the combustion.

13. The process in claim 11, wherein the hydrocarbon in the mixture of hydrocarbon and steam comprises more than 50% by volume methane and the fuel for the combustion in the fired reformer comprises at least 75% vol H2, preferably at least 90% by volume H2, most preferably at least 95% by volume H2.

14. The process recited in claim 11, wherein the hydrocarbon in the mixture of hydrocarbon and steam comprises natural gas, associated gas, LPG, petroleum distillate, diesel, naphtha or mixtures thereof, a refinery off-gas, or a pre-reformed gas.

15. The process recited in claim 11, wherein the mixture of hydrocarbon and steam fed to the gas-heated reformer has a steam to carbon ratio that is greater than the steam to carbon ratio of the mixture of hydrocarbon and steam fed to the fired steam reformer.

16. The process recited in claim 11, wherein, carbon dioxide recovered from the carbon dioxide removal unit is compressed and used for the manufacture of chemicals, purified for use in the food industry, or sent to storage or sequestration or used in enhanced oil recovery processes.

17. The process recited in claim 11, wherein at least a portion of the off-gas, stream is added to the hydrocarbon or the hydrocarbon and steam mixture fed to the steam reformers.

18. A system or plant for the production of hydrogen comprising: (a) a fired reformer containing a plurality of catalyst-containing reformer tubes that are heated by combustion of a fuel; (b) a gas-heated reformer containing a plurality of catalyst-containing gas-heated reformer tubes, said fired reformer and said gas-heated reformer being configured to be fed with a mixture of hydrocarbon and steam in parallel; (c) means for combining a synthesis gas recovered from the fired reformer with a second synthesis gas recovered from the catalyst-containing gas-heated reformer tubes to form a combined synthesis gas mixture, and for heating the catalyst-containing gas-heated reformer tubes in a shell side of the gas heated reformer using the combined synthesis gas mixture; (d) a water gas shift unit configured to receive a partially cooled synthesis gas from the shell side of the gas heated reformer and to produce a hydrogen-enriched gas; (e) a carbon dioxide removal unit configured to receive the hydrogen-enriched gas from the water-gas shift unit, remove carbon dioxide therefrom, and to provide a crude hydrogen stream; and, (f) a purification unit configured to receive the crude hydrogen stream from the carbon dioxide removal unit and separate the crude hydrogen stream into a purified hydrogen stream and an off-gas stream, wherein the system further comprises means to feed a portion of the crude hydrogen stream and/or a portion of the purified hydrogen stream to the fired reformer as fuel for the combustion.

Description

[0056] The invention will be further illustrated by reference to the Figures in which;

[0057] FIG. 1 is a flow sheet depicting a hydrogen production unit according to one embodiment of the invention comprising a fired steam reformer and an installed gas-heated reformer and carbon dioxide removal unit, with hydrogen product supplied as fuel for the fired steam reformer;

[0058] FIG. 2 is a flow sheet depicting a hydrogen production unit according to another embodiment of the invention comprising a fired steam reformer and an installed gas-heated reformer and carbon dioxide removal unit, with hydrogen product supplied as fuel for the fired steam reformer, and with off-gas from the purification unit supplied to the hydrocarbon feed; and

[0059] FIG. 3 is a comparative embodiment depicting a conventional hydrogen production unit comprising a fired steam reformer without a carbon dioxide removal unit or gas-heated reformer.

[0060] It will be understood by those skilled in the art that the drawings are diagrammatic and that further items of equipment such as reflux drums, pumps, vacuum pumps, temperature sensors, pressure sensors, pressure relief valves, control valves, flow controllers, level controllers, holding tanks, storage tanks, and the like may be required in a commercial plant. The provision of such ancillary items of equipment forms no part of the present invention and is in accordance with conventional chemical engineering practice.

[0061] In FIG. 1 a natural gas stream 10 is combined with a small amount of a compressed hydrogen stream 12 and the resulting mixture heated in the convection section of a fired steam reformer 14. The resulting heated gas mixture 16 is passed through a first purification vessel 18 containing a fixed bed of hydrodesulphurisation catalyst in which hydrogen in the feed is reacted with organic sulphur compounds therein to convert them to hydrogen sulphide. The resulting gas mixture is then passed through a second purification vessel 20 and a third purification vessel 22, each containing a bed of a hydrogen sulphide adsorbent that removes the sulphur compounds to form a desulphurised natural gas stream. The desulphurised natural gas stream recovered from vessel 22 is combined with superheated steam provided via line 24, and the resulting mixture of desulphurised natural gas and steam is heated in the convection section of the fired steam reformer 14. A first portion of the resulting pre-heated desulphurised natural gas and steam mixture is fed via line 26 to inlets of a plurality of externally heated catalyst-filled reformer tubes 28 in the fired steam reformer 14, and a second portion is fed via line 30, with optional additional steam supplied by line 32, to inlets of a plurality of externally heated catalyst-filled reformer tubes 34 in a gas-heated reformer 36. The plurality of catalyst-filled reformer tubes 28 in the fired steam reformer 14 are heated by combusting a fuel gas fed via line 38 in a radiant section of the fired reformer, located upstream of the convection section. Steam reforming reactions occur in the catalyst-filled reformer tubes 28, 34. A first crude synthesis gas 40 is recovered from outlets of the plurality of fired reformer tubes 28 and fed as a heating medium to a shell side of the gas heated reformer 36. The gas-heated reformer 36 is of a single tube-sheet design wherein a second synthesis gas mixture is discharged from the ends of the plurality of catalyst-filled tubes 34 into the shell side of the gas-heated reformer where mixes with the synthesis gas stream 40 recovered from the catalyst-filled tubes 28 of the fired reformer to form a combined synthesis gas, which then passes around the exterior of the tubes 34 as the heating medium. In consequence the combined synthesis gas is partially cooled. The cooled combined synthesis gas is recovered from the shell side of the gas heated reformer 36 via combined synthesis gas outlet and fed via line 42, to a heat exchanger 44 where it is further cooled and the resulting combined synthesis gas fed via line 46 to the inlet of a high-temperature shift vessel 48 containing a fixed bed of high temperature shift catalyst. The water-gas shift reactions occur over the high-temperature shift catalyst, forming a hydrogen enriched gas. The hydrogen enriched gas is recovered from the water gas shift vessel 48 and cooled in heat exchange with medium-pressure steam in heat exchanger 50, then boiler feed water in heat exchanger 52, and then water in heat exchangers 54 and 56 that cool the hydrogen-enriched gas to below the dew point such that a condensate is formed. The resulting mixture is fed from heat exchanger 56 via line 58 to a gas-liquid separator 60. The condensate is recovered from the gas-liquid separator 60 via line 62. The resulting de-watered hydrogen-enriched gas is fed via line 64 to a carbon dioxide removal unit 66 that uses an amine wash solution to recover carbon dioxide from the de-watered hydrogen-enriched gas. The carbon dioxide removal unit 66 uses a portion 68 of the condensate to heat and desorb carbon dioxide from the amine wash solution in a regeneration unit within the carbon dioxide removal unit. Water is recovered from the carbon dioxide removal unit 66 via line 70 and may be used for steam generation within the process. A carbon dioxide stream is recovered from the carbon dioxide removal unit 66 via line 72. The carbon dioxide stream 72 may be dried, purified and compressed for storage or for the synthesis of useful products (not shown). A crude hydrogen product is recovered from the carbon dioxide removal unit 66 and fed via line 74 to a purification unit 76 comprising a pressure-swing absorption vessel containing a sorbent. The pressure-swing absorption vessel produces a purified hydrogen product, which is recovered from the purification unit 76 via line 78. The purification unit also provides an off-gas stream, which is fed via line 80 to form part of the fuel gas stream 38 combusted in the fired steam reformer 14. A portion of the purified hydrogen product may be fed from line 78 via line 82 to compressor 84 where it is compressed to provide the hydrogen stream 12 added to the natural gas feed 10. A further portion of the purified hydrogen product is fed via line 86 to form the remainder of the fuel gas stream 38 combusted in the fired steam reformer 14. A remaining portion of the purified hydrogen product is exported via line 88 for use downstream. Flue gas from the fired steam reformer 14 is recovered from the convection section via line 90 and cooled in heat exchanger 92 before being vented to atmosphere. Heat exchanger 92 is used to heat combustion air 94, which is fed from heat exchanger 92 via line 96 to combust the fuel gas in stream 38 in the radiant section of the fired steam reformer.

[0062] It will be understood that while this embodiment uses a portion of the purified hydrogen stream 78 via line 86 as a fuel in the fired steam reformer 14, it is possible to use a portion of the crude hydrogen product from line 74 as a fuel. This is depicted as dashed line 98.

[0063] Boiler feed water 100 is heated in heat exchanger 52 and passed to a steam drum 102 that provides steam for the process. The steam drum 102 has a steam boiler circuit 104 heated by the flue gas in the convection section of the fired steam reformer 14. The steam drum 102 also provides a hot water stream 106 used to cool the hydrogen-enriched gas in heat exchanger 50 and the crude synthesis gas in heat exchanger 46 before being returned to the steam drum 102 via line 108.

[0064] In FIG. 2, the process is as depicted in FIG. 1, except that a portion of the off-gas stream 80 is taken via line 110, compressed in compressor 112 and added via line 114 to the natural gas feed in line 10. In this arrangement, because the off-gas contains hydrogen, it is not necessary feed a portion of the purified hydrogen from line 78 via line 82 and compressor 84 to the natural gas. Alternatively, it is possible to retain line 82 and compressor 84 but feed the off-gas via line 110 and compressor 112 to the reformer feed downstream of the vessel 22, for example before or after addition of steam via line 24. Alternatively, a portion of the de-watered hydrogen-enriched gas from line 64, or a portion of the crude synthesis gas 74 may be used to provide the hydrogen for the purification.

[0065] In FIG. 3, the process is as depicted in FIG. 1, but the gas-heated reformer 36 and carbon dioxide removal unit 66 are not present. Accordingly, all of the hydrocarbon and steam mixture 26 is fed to the plurality of tubes 28 in the fired steam reformer 14 and the crude synthesis gas stream 40 from the fired steam reformer 14 is directed to the heat exchanger 44 and the water gas shift vessel 48. In this arrangement, a portion of the hydrogen product stream is not used as fuel for the fired steam reformer and accordingly all of the off gas from the purification unit 76 is directed via line 80 to the fired steam reformer as fuel. The offgas in line 80 is supplemented by the combustion of a natural gas fuel fed via line 120 in order to provide the heat for the steam reforming reaction.

[0066] The invention is further illustrated by reference to the following calculated Examples.

[0067] The process of FIGS. 1 and 2 were modelled based on a natural gas feed and fuel to illustrate the achievable reductions in CO.sub.2 emissions. A comparative example based on FIG. 3, was also modelled. The results for FIG. 2 were as follows:

TABLE-US-00001 Stream Number 10 12 16 24 26 30 Temperature C. 40 100 380 411 550 550 Pressure bar a 28.5 30.0 27.0 26.3 24.8 24.8 Mass Flow tonne/h 35.00 0 58.51 135.8 194.3 33.03 Vapour Flow Nm.sup.3/h 45890 0 91450 169000 260400 44270 Molecular Weight 17.09 2.02 14.34 18.02 16.72 16.72 Composition mol % Water 0.25 100.00 64.97 64.97 Hydrogen 100.00 26.61 9.35 9.35 Carbon Monoxide 12.37 4.35 4.35 Carbon Dioxide 0.50 0.31 0.11 0.11 Nitrogen Methane 95.00 58.19 20.44 20.44 Ethane 3.00 1.51 0.53 0.53 Propane 1.00 0.50 0.18 0.18 Butane 0.50 0.25 0.09 0.09 Oxygen Heavies

TABLE-US-00002 Stream Number 32 40 42 58 64 74 Temperature C. 420 880 671 40 40 40 Pressure bar a 39.2 22.0 21.3 19.3 19.3 19.2 Mass Flow tonne/h 20.61 161.3 215.2 215.2 136.2 41.64 Vapour Flow Nm.sup.3/h 25650 296300 382900 284700 235800 Molecular Weight 18.02 12.20 12.60 12.6 10.72 3.96 Composition mol % Water 100.00 28.80 32.99 25.93 0.41 0.10 Hydrogen 51.63 48.74 55.80 75.05 90.53 Carbon Monoxide 11.61 10.18 3.11 4.18 5.05 Carbon Dioxide 5.16 5.45 12.51 16.80 0.02 Nitrogen Methane 2.80 2.65 2.65 3.56 4.29 Ethane Propane Butane Oxygen Heavies

TABLE-US-00003 Stream Number 78 80 86 88 90 112 Temperature C. 40 40 40 40 397 485 Pressure bar a 18.9 1.70 18.9 18.9 0.96 28.5 Mass Flow tonne/h 10.83 1.238 6.073 10.83 246.0 23.51 Vapour Flow Nm.sup.3/h 187920 2400 67520 120400 220700 45560 Molecular Weight 2.02 11.57 2.02 2.02 24.98 11.57 Composition mol % Water 0.51 31.64 0.51 Hydrogen 100.00 53.42 100.00 100.00 53.42 Carbon Monoxide 24.84 24.84 Carbon Dioxide 0.12 0.50 0.12 Nitrogen 66.57 Methane 21.11 21.11 Ethane Propane Butane Oxygen 1.29 Heavies

[0068] In comparison, the results for FIG. 3 were as follows:

TABLE-US-00004 Stream Number 10 26 80 88 90 120 Temperature C. 40 550 40 40 372 40 Pressure bar a 28.5 24.8 1.70 19.9 0.96 2.25 Mass Flow tonne/h 34.21 145.2 81.88 12.14 415.1 8.213 Vapour Flow Nm.sup.3/h 44860 184200 67120 135000 317000 10770 Molecular Weight 17.09 17.67 27.34 2.02 29.35 17.09 Composition mol % Water 74.88 1.20 16.99 Hydrogen 0.76 27.71 100.00 Carbon Monoxide 13.43 Carbon Dioxide 0.50 0.12 48.46 18.67 0.50 Nitrogen 63.11 Methane 95.00 23.14 9.20 95.00 Ethane 3.00 0.73 3.00 Propane 1.00 0.24 1.00 Butane 0.50 0.12 0.50 Oxygen 1.23 Heavies

[0069] The processes of FIGS. 1, 2 and 3 may be compared in terms of fuel demand and CO.sub.2 efficiency. The results were as follows:

TABLE-US-00005 NG Feed H.sub.2 Product NG Fuel CO.sub.2 Captured CO.sub.2 Released CO.sub.2 Captured Case Nm.sup.3/h Nm.sup.3/h Nm.sup.3/h tonne/h tonne/h % FIG. 1 54090 148700 0 79.85 33.09 70.7 FIG. 2 45890 120400 0 93.79 2.17 97.7 FIG. 3 44860 135000 10770 0 116.00 0

[0070] Whereas the process of FIG. 1 provides about 70% CO.sub.2 capture with an increased hydrogen productivity compared to the comparative process depicted in FIG. 3, FIG. 2, with off-gas recycle provides over 97% CO.sub.2 capture with only a small drop in hydrogen production.