PROCESS FOR THE PRODUCTION OF HYDROGEN

Abstract

A process of hydrogen production comprising the steps of: subjecting a gaseous mixture comprising a hydrocarbon and steam, and having a steam to carbon ratio of at least 0.9:1, to adiabatic pre-reforming in a pre-reformer followed by autothermal reforming with an oxygen-rich gas in an autothermal reformer to generate a reformed gas mixture, optionally adding steam to the reformed gas mixture, increasing the hydrogen content of the reformed gas mixture by subjecting it to one or more water-gas shift stages in a water-gas shift unit to provide a hydrogen-enriched reformed gas, cooling the hydrogen-enriched reformed gas and separating condensed water therefrom, passing the resulting de-watered hydrogen-enriched reformed gas to a carbon dioxide separation unit to provide a carbon dioxide gas stream and a crude hydrogen gas stream, passing the crude hydrogen gas stream to a purification unit to provide a purified hydrogen gas and a fuel gas.

Claims

1-27. (canceled)

28. A process for the production of hydrogen comprising the steps of: (i) subjecting a gaseous mixture comprising a hydrocarbon and steam, and having a steam to carbon ratio of at least 0.9:1 to adiabatic pre-reforming in a pre-reformer followed by autothermal reforming with an oxygen-rich gas in an autothermal reformer to generate a reformed gas mixture, (ii) increasing the hydrogen content of the reformed gas mixture by subjecting it to one or more water-gas shift stages in a water-gas shift unit to provide a hydrogen-enriched reformed gas, (iii) cooling the hydrogen-enriched reformed gas and separating condensed water therefrom to provide a de-watered hydrogen-enriched reformed gas, (iv) passing the de-watered hydrogen-enriched reformed gas to a carbon dioxide separation unit to provide a carbon dioxide gas stream and a crude hydrogen gas stream, and (v) passing the crude hydrogen gas stream from the carbon dioxide removal unit to a purification unit to provide a purified hydrogen gas and a fuel gas, wherein the fuel gas is fed to one or more fired heaters used to heat one or more process streams within the process.

29. The process according to claim 28, wherein the hydrocarbon is a methane-containing gas stream, preferably containing >50% vol of methane.

30. The process according to claim 28, wherein the hydrocarbon is desulphurised.

31. The process according to claim 28, wherein the steam to carbon ratio is in the range 0.9:1 to 3.5:1.

32. The process according to claim 28, wherein the steam to carbon ratio is in the range 0.9:1 to below 2.4:1, and the process includes adding steam to the reformed gas mixture.

33. The process according to claim 28, wherein the gaseous mixture comprising the hydrocarbon and steam is formed by mixing the hydrocarbon with steam generated by the one or more fired heaters and/or by cooling the reformed gas mixture with water.

34. The process according to claim 28, wherein the oxygen-rich gas comprises at least 90% vol O.sub.2, preferably at least 95% vol O.sub.2, more preferably at least 98% vol O.sub.2.

35. The process according to claim 28, wherein the oxygen-rich gas is heated before being fed to the autothermal reformer in heat exchange with steam generated by cooling of the reformed gas.

36. The process according to claim 28, wherein the water-gas shift stage comprises a high-temperature shift stage and a downstream low-temperature shift stage.

37. The process according to claim 36, wherein the hydrocarbon is heated in heat exchange with a shifted gas stream recovered from the high-temperature shift stage.

38. The process according to claim 28, wherein steam generated in the one or more fired heaters is used to generate electrical power for the process.

39. The process according to claim 28, wherein there are at least two stages of cooling and separation of process condensate before the carbon dioxide removal stage.

40. The process according to claim 28, wherein the carbon dioxide removal stage is performed using a physical wash system or a reactive wash system, preferably a reactive wash system, especially an amine wash system.

41. The process according to claim 28, wherein one or more of the carbon dioxide removal unit streams are heated in heat exchange with steam generated in the one or more fired heaters.

42. The process according to claim 28, wherein the purification unit is a pressure swing adsorption unit or a temperature swing adsorption unit, preferably a pressure swing adsorption unit.

43. The process according to claim 28, wherein the carbon dioxide recovered from the carbon dioxide removal unit and the purified hydrogen gas recovered from the purification unit are each compressed in electrically-driven compressors.

44. The process according to claim 28, wherein a portion of the crude hydrogen or purified hydrogen is fed to the hydrocarbon.

45. The process according to claim 28, wherein a supplemental fuel is added to the fuel gas fed to the one or more fired heaters and the amount of the supplemental fuel is less than 5% vol, preferably less than 3% vol, more preferably less than 2% of the total fuel provided.

46. The process according to claim 28, wherein there is a single fired heated fuelled at least in part by the fuel gas recovered from the purification unit and the single fired heater is used to heat the hydrocarbon, the reformed gas recovered from the pre-reforming stage upstream of the autothermal reforming stage, and water to generate at least part of the steam for the process.

47. The process according to claim 28, wherein there are two fired heaters fuelled at least in part by the fuel gas recovered from the purification unit; a first fired heater that heats the hydrocarbon feed stream and a reformed gas stream recovered from the pre-reforming stage upstream of the autothermal reforming stage, and a second fired heater that functions as a boiler to generate steam for the process.

48. The process according to claim 47 wherein the fuel gas split to the first and second fired heaters in the ranges of 10-90% vol to 90-10% vol respectively, preferably 60-80% vol to the first fired heater and 40-20% vol to the second fired heater.

49. The process according to claim 47, wherein a portion of the steam generated in the second fired heater is used to heat a CO.sub.2 absorbent liquid in the carbon dioxide separation unit.

50. The process according to claim 47, wherein steam generated in the second fired heater is used to superheat steam recovered from a steam drum coupled to a waste-heat boiler heated by the reformed gas.

51. The process according to claim 50, wherein the waste-heat boiler is also used to generate steam used to pre-heat the oxygen-rich gas.

52. The process according to claim 50, wherein a portion of the steam from the waste-heat boiler is passed to a steam expander to generate power.

53. The process according to claim 50, wherein when the steam to carbon ratio is below 2.4:1, a portion of the steam from the waste-heat boiler is added to the reformed gas.

54. The process according to claim 28, wherein the pure hydrogen stream is used in a downstream power process, heating process, a downstream chemical synthesis process or used to upgrade hydrocarbons.

Description

[0048] The invention is illustrated by reference to the accompanying drawing in which:

[0049] FIG. 1 is a diagrammatic flowsheet of one embodiment of the invention in which all of the process steam is added upstream of the reforming unit operations.

[0050] 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.

[0051] In FIG. 1 a natural gas stream comprising >85% vol methane fed via line 10 is mixed with a hydrogen-containing stream 12 such that the resulting mixture contains between 1 and 5% vol hydrogen. The hydrogen-containing natural gas stream is fed via line 14 to a heat exchanger 16, where it is heated by a high-temperature shifted gas 18. The heated natural gas mixture is then desulphurised by passing it via line 20 to a hydrodesulphurisation (HDS) vessel 22 containing a bed of hydrodesulphurisation catalyst, where organic sulphur compounds are converted with the hydrogen to hydrogen sulphide, and then via line 24 to a vessel 26 containing a bed of zinc oxide adsorbent and a bed of a copper-zinc-alumina ultra-purification adsorbent that remove hydrogen sulphide.

[0052] The desulphurised natural gas is fed from the vessel 26 via line 28 to a first fired heater 30 where it is heated by combustion of a fuel gas fed to the heater via line 32. The heated natural gas is taken from the heater 30 via line 34 and combined with steam fed via line 36 to provide a natural gas and steam mixture having a steam to carbon ratio of about 2.5:1.

[0053] The natural gas and steam mixture is fed via line 38 to an adiabatic pre-reformer 40 containing a bed of pelleted nickel-based steam reforming catalyst. The higher hydrocarbons are converted to methane and partially steam reformed to produce a pre-reformed gas mixture containing hydrogen as the mixture passes over the pre-reforming catalyst. The pre-reformed gas mixture is then fed from the pre-reformer 40 via line 42 to the first fired heater 30 where it is heated to the autothermal reformer inlet temperature.

[0054] The heated pre-reformed gas mixture is fed from the fired heater 30 via line 44 to the burner region of an autothermal reformer 46, where it is partially combusted with oxygen fed via line 48 that has been produced in an air separation unit 50 and pre-heated in heat exchanger 52. The hot combusted gas mixture is brought towards equilibrium over a fixed bed of a pelleted nickel-based secondary reforming catalyst 54 disposed below the combustion zone in the autothermal reformer 46. The resulting hot reformed gas mixture is fed from the autothermal reformer 46 via line 56 to the tube-side of a steam-raising boiler 58 coupled to a steam drum 60. The hot reformed gas mixture boils water fed to the shell side of the boiler from the steam drum 60 via line 62 and returns steam from the boiler to the steam drum 60 via line 64. Steam drum 60 coupled to the boiler 58 generates high-pressure steam, which is recovered from the steam drum 60, divided, and used in the process. The hot reformed gas mixture is cooled as it passes through the boiler 58.

[0055] The resulting cooled reformed gas mixture is fed from the tube side of boiler 58 via line 66 to a first shift vessel 68 containing a fixed bed of particulate bed of iron-based high-temperature shift catalyst. The water-gas shift reaction whereby the hydrogen content of the reformed gas is increased, and the carbon monoxide converted to carbon dioxide occurs as the gas passes through the bed. The partially shifted reformed gas is fed from the first shift reactor via line 18 to the heat exchanger 16 where it pre-heats the natural gas, and then to a further heat exchanger 70 in which it is cooled with water under pressure. The cooled partially shifted gas mixture is fed from heat exchanger 70 via line 72 to a second shift vessel 74 containing a fixed bed of a particulate copper-based low-temperature shift catalyst. The water-gas shift reaction moves further to completion as the gas passes through the bed. The resulting hydrogen-enriched reformed gas mixture is then cooled in a heat exchanger 76, fed with cold pressurised demineralised deaerated water provided to the process via line 78. Part of the water recovered from heat exchanger 76 in line 80 is fed to the heat exchanger 70 used to cool the partially shifted gas mixture. The heated water recovered from the heat exchanger 70 is fed via line 82 to the steam drum 60 to provide coolant for the reformed gas mixture in the boiler 58.

[0056] The cooled hydrogen-enriched reformed gas is fed from the heat exchanger 76 via line 84 to a further heat exchanger 86, where it is further cooled with water. The cooling lowers the temperature of the gas mixture to below the dew point so that water condenses. The cooled stream is fed from the heat exchanger 86 to a gas-liquid separator 88 in which the condensate is separated from the hydrogen-enriched reformed gas mixture. The condensate is recovered from the separator 88 via a line 90. In this embodiment, a partially de-watered hydrogen-enriched reformed gas mixture is recovered from the separator 88 via line 92 and further cooled in heat exchange with water in heat exchanger 94. The cooled gas is passed to a second gas-liquid separator 96 to recover a further condensate stream 98. The condensate streams 90 and 98 are combined and sent for water treatment as effluent 100.

[0057] The de-watered hydrogen-enriched reformed gas mixture is fed from the separator 96 via line 102 to a CO.sub.2 removal unit 104, such as an acid gas recovery unit, operating with a liquid absorbent wash system that absorbs CO.sub.2 and any remaining H.sub.2O from the gas. Absorbed CO.sub.2 is recovered from the CO.sub.2-laden absorbent liquid in the unit 104 by heating it using steam fed to the unit 104 via line 106 and reducing the pressure. Water recovered with the CO.sub.2 is separated and sent for water treatment (not shown). Steam condensate is recovered from the CO.sub.2 removal unit 104 via line 108. The recovered CO.sub.2 from the CO.sub.2 removal unit 104 is sent via line 110 for compression and storage.

[0058] A crude hydrogen gas stream is recovered from the CO.sub.2 removal unit 104 and fed via line 112 to a pressure swing adsorption unit 114 containing a porous adsorbent that traps carbon oxides and methane in the crude hydrogen, thereby producing a purified hydrogen stream. The purified hydrogen gas is recovered from the pressure swing adsorption unit 114 via line 116. A portion of the purified hydrogen is taken via line 118 and compressed to form the recirculated hydrogen stream 12. The remaining purified hydrogen in line 120 is compressed and sent either for storage, for the generation of power or heat or for the production or conversion of chemicals.

[0059] The pressure swing adsorption unit 114, by adjusting the pressure, desorbs the carbon oxides and methane trapped in the porous adsorbent thereby generating a fuel gas. The fuel gas is recovered from the pressure swing adsorption unit 114 via line 122. A portion of the fuel gas in line 122 is provided to the first fired heater 30 via line 32 as the sole fuel to that heater. A second portion of the fuel gas in line 122 is provided as the sole fuel to a second fired heater 124 via line 126.

[0060] The second fired heater 124 raises steam for the process by the combustion of the fuel gas provided via line 126.

[0061] High-pressure steam is recovered from the steam drum 60 via line 128. A first portion, optionally after pressure reduction, is fed from line 128 via line 130 to heat the oxygen-rich gas in heat exchanger 52. Condensate is recovered from the heat exchanger 52 via line 132. A second portion is taken from the remaining high-pressure steam via lines 134 and 136 to the second fired heater 124 for further heating to produce superheated steam that is fed to the desulphurised natural gas stream 34 via line 36. A third portion is taken from the remaining high-pressure steam via line 138 to a steam turbine 140 to generate electrical power for the process, for example to drive the air separation unit 50 and/or electrically-driven compressors 144, 146 and 148.

[0062] A stream of hot water may be taken from the pre-heated demineralised water in line 80 as shown, or from the pre-heated demineralised water in line 82, and fed via line 150 to a steam drum 152 where the heated water is circulated via lines 154 and 156 through the second fired heater 124 to generate steam at low pressure. Steam from the steam drum 152 is recovered via line 106 and used to heat the CO.sub.2 absorbent liquid in the CO.sub.2 removal unit 104.

[0063] The efficient use of the fuel gas to provide the heated natural gas feed streams and steam for the process minimises CO.sub.2 emissions from the process.

EXAMPLE 1

[0064] The invention is further illustrated by the following calculated example of a process in accordance with the flowsheet depicted in FIG. 1.

TABLE-US-00001 Stream Number 10 12 18 20 32 36 38 Molar Flow kNm.sup.3/h 42.3 0.9 244.6 43.2 9.1 119.0 155.1 Mass Flow t/h 32.4 0.1 158.8 32.5 2.1 90.1 122.6 Temperature ° C. 40 70 454 380 40 450 540 Pressure bara 41.3 43.5 36.6 40.8 1.5 40.8 40.0 Molar Composition Methane mol % 92.17 0.00 0.20 90.33 3.13 0.00 25.15 Ethane mol % 6.32 0.00 0.00 6.19 0.00 0.00 1.72 Propane mol % 0.52 0.00 0.00 0.51 0.00 0.00 0.14 Butanes mol % 0.05 0.00 0.00 0.05 0.00 0.00 0.01 Pentanes mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Hydrogen mol % 0.00 100.00 48.27 1.99 85.97 0.00 0.56 Carbon Dioxide mol % 0.15 0.00 15.13 0.15 0.82 0.00 0.10 Carbon Monoxide mol % 0.00 0.00 3.17 0.00 5.09 0.00 0.00 Oxygen mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen mol % 0.19 0.00 0.12 0.19 1.90 0.00 0.06 Argon mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Water mol % 0.61 0.00 33.10 0.59 2.95 100.00 72.13 Methanol mol % 0.00 0.00 0.00 0.00 0.10 0.00 0.00 Ammonia mol % 0.00 0.00 0.00 0.00 0.03 0.00 0.00

TABLE-US-00002 Stream Number 42 44 48 56 66 72 78 Molar Flow kNm.sup.3/h 162.8 162.8 25.4 244.6 244.6 244.6 199.1 Mass Flow t/h 122.6 122.6 36.2 158.8 158.8 158.8 160.0 Temperature ° C. 470 650 210 1020 360 205 120 Pressure bara 39.8 39.5 40.0 37.5 37.0 35.6 43.0 Molar Composition Methane mol % 25.33 25.33 0.00 0.20 0.20 0.20 0.00 Ethane mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Propane mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Butanes mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Pentanes mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Hydrogen mol % 8.02 8.02 0.00 39.76 39.76 48.27 0.00 Carbon Dioxide mol % 2.42 2.42 0.00 6.70 6.70 15.13 0.00 Carbon Monoxide mol % 0.05 0.05 0.00 11.61 11.61 3.17 0.00 Oxygen mol % 0.00 0.00 99.50 0.00 0.00 0.00 0.00 Nitrogen mol % 0.05 0.05 0.50 0.09 0.09 0.12 0.00 Argon mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Water mol % 64.01 64.01 0.00 41.56 41.56 33.10 100.00 Methanol mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Ammonia mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00

TABLE-US-00003 Stream Number 80 82 84 100 102 106 108 Molar Flow kNm.sup.3/h 199.1 183.4 244.6 72.3 172.3 15.6 15.6 Mass Flow t/h 160.0 147.4 158.8 58.2 100.6 12.6 12.6 Temperature ° C. 135 230 212 114 71 157 154 Pressure bara 42.5 42.0 34.6 33.6 33.6 5.8 5.3 Molar Composition Methane mol % 0.00 0.00 0.20 0.00 0.29 0.00 0.00 Ethane mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Propane mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Butanes mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Pentanes mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Hydrogen mol % 0.00 0.00 51.08 0.00 72.50 0.00 0.00 Carbon Dioxide mol % 0.00 0.00 17.95 0.11 25.44 0.00 0.00 Carbon Monoxide mol % 0.00 0.00 0.33 0.00 0.47 0.00 0.00 Oxygen mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen mol % 0.00 0.00 0.12 0.00 0.18 0.00 0.00 Argon mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Water mol % 100.00 100.00 30.28 99.85 1.11 100.00 100.00 Methanol mol % 0.00 0.00 0.02 0.03 0.01 0.00 0.00 Ammonia mol % 0.00 0.00 0.00 0.01 0.00 0.00 0.00

TABLE-US-00004 Stream Number 110 112 116 120 122 126 128 Molar Flow kNm.sup.3/h 43.7 127.2 111.2 110.3 16.0 6.9 181.8 Mass Flow t/h 85.8 13.7 10.0 9.9 3.7 1.6 146.2 Temperature ° C. 40 50 40 40 40 40 253 Pressure bara 1.5 33.6 33.1 33.1 1.5 1.5 42.0 Molar Composition Methane mol % 0.00 0.39 0.00 0.00 3.13 3.13 0.00 Ethane mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Propane mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Butanes mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Pentanes mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Hydrogen mol % 0.00 98.24 100.00 100.00 85.97 85.97 0.00 Carbon Dioxide mol % 100.00 0.10 0.00 0.00 0.82 0.82 0.00 Carbon Monoxide mol % 0.00 0.64 0.00 0.00 5.09 5.09 0.00 Oxygen mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen mol % 0.00 0.24 0.00 0.00 1.90 1.90 0.00 Argon mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Water mol % 0.00 0.37 0.00 0.00 2.95 2.95 100.00 Methanol mol % 0.00 0.01 0.00 0.00 0.10 0.10 0.00 Ammonia mol % 0.00 0.00 0.00 0.00 0.03 0.03 0.00

TABLE-US-00005 Stream Number 130 132 138 142 150 Molar Flow kNm.sup.3/h 4.6 4.6 65.2 65.2 15.6 Mass Flow t/h 3.7 3.7 52.4 52.4 12.6 Temperature ° C. 253 253 253 69 135 Pressure bara 42.0 41.5 42.0 0.3 42.5 Molar Composition Methane mol % 0.00 0.00 0.00 0.00 0.00 Ethane mol % 0.00 0.00 0.00 0.00 0.00 Propane mol % 0.00 0.00 0.00 0.00 0.00 Butanes mol % 0.00 0.00 0.00 0.00 0.00 Pentanes mol % 0.00 0.00 0.00 0.00 0.00 Hydrogen mol % 0.00 0.00 0.00 0.00 0.00 Carbon Dioxide mol % 0.00 0.00 0.00 0.00 0.00 Carbon Monoxide mol % 0.00 0.00 0.00 0.00 0.00 Oxygen mol % 0.00 0.00 0.00 0.00 0.00 Nitrogen mol % 0.00 0.00 0.00 0.00 0.00 Argon mol % 0.00 0.00 0.00 0.00 0.00 Water mol % 100.00 100.00 100.00 100.00 100.00 Methanol mol % 0.00 0.00 0.00 0.00 0.00 Ammonia mol % 0.00 0.00 0.00 0.00 0.00

[0065] The flowsheet allows for capture of 95% of CO.sub.2 at a steam to carbon ratio of 2.5:1.

EXAMPLE 2

[0066] The invention is further illustrated by the following calculated example of a process in accordance with the flowsheet depicted in FIG. 1 with the following changes: [0067] a) The operating pressure of the reforming unit operations is reduced to 26 barg; [0068] b) The steam to carbon ratio in the gaseous mixture comprising natural gas and steam fed to the pre-reformer 40 is 0.95:1; [0069] c) Oxygen is added to the autothermal reformer to achieve an exit temperature of 1065° C.; [0070] d) Steam raised in the steam-raising boiler 58 is added to the cooled reformed gas 66 such that the feed at the inlet to the high-temperature water-gas shift has a steam to dry gas ratio of 0.72:1; [0071] e) The product gas from the high-temperature water-gas shift reactor 68 is cooled such that the feed gas to the low-temperature water-gas shift reactor 74 has an inlet temperature of 190° C.; and [0072] f) The balance of the fired heater duties in the two fired heaters 30 and 124 is adjusted to provide the apportioning of the process steam addition to both upstream and downstream of the reforming unit operations.

[0073] The flowsheet in this arrangement also allows for capture of 95% of CO.sub.2 at a steam to carbon ratio of 0.95:1, which reduces the heat demand and oxygen consumption in the autothermal reformer.