PROCESS FOR PRODUCING HYDROGEN

Abstract

A process for the production of hydrogen comprising the steps of subjecting a gaseous mixture comprising a hydrocarbon and steam and having a steam to carbon ratio of at least 2.6:1, to steam reforming in a gas-heated reformer followed by autothermal reforming with an oxygen-rich gas in an autothermal reformer to generate a 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, and passing the crude hydrogen gas stream to a purification unit to provide a purified hydrogen gas and a fuel gas.

Claims

1.-21. (canceled)

22. 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 2.6:1, to steam reforming in a gas-heated 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, (iv) 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, and (v) passing the crude hydrogen gas stream to a purification unit to provide a purified hydrogen gas and a fuel gas, wherein the fuel gas is fed, as the sole fuel, to one or more fired heaters used to heat one or more process streams within the process.

23. The process according to claim 22, wherein the hydrocarbon is a methane-containing gas stream, preferably containing >50% vol of methane.

24. The process according to claim 22, wherein the hydrocarbon is desulphurised.

25. The process according to claim 22, wherein the steam to carbon ratio is in the range 2.8:1 to 3.5:1, preferably 2.9:1 to 3.2:1 or 3.2:1 to 3.5:1.

26. The process according to claim 22, wherein the gaseous mixture comprising the hydrocarbon and steam is formed by contacting the hydrocarbon with water in a saturator to form a saturated gas mixture, with optional direct addition of steam to the saturated gas mixture.

27. The process according to claim 22, wherein the water fed to the saturator is heated in heat exchange with the reformed gas mixture.

28. The process according to claim 22, 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.

29. The process according to claim 22, wherein the water-gas shift stage comprises an isothermal shift stage and optionally a downstream low-temperature shift stage.

30. The process according to claim 22, wherein there are two or three stages of cooling and separation of process condensate before the carbon dioxide removal stage.

31. The process according to claim 22, 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.

32. The process according to claim 22, wherein one or more of the carbon dioxide removal unit streams are heated in heat exchange with the hydrogen-enriched reformed gas stream.

33. The process according to claim 22, wherein the purification unit is a pressure swing adsorption unit or a temperature swing adsorption unit, preferably a pressure swing adsorption unit.

34. The process according to claim 22, 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.

35. The process according to claim 22, wherein a portion of the crude hydrogen or pure hydrogen is fed to the hydrocarbon.

36. The process according to claim 22, wherein there are two fired heaters fuelled by the fuel gas recovered from the purification unit; a first fired heater that heats the hydrocarbon and/or the gaseous mixture of hydrocarbon and steam, and a second fired heater that functions as a boiler to generate steam for the process.

37. The process according to claim 36 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 40-50% vol to the first fired heater and 60-50% vol to the second fired heater.

38. The process according to claim 36, wherein a portion of the steam generated in the second fired heater is used in the gaseous mixture fed to the gas-heated reformer.

39. The process according to claim 36, wherein steam generated in the second fired heater is provided via a steam drum coupled to an isothermal shift converter.

40. The process according to claim 39 wherein the entire steam for the process is generated by a combination of a saturator, the second fired heater and by a steam drum coupled to the isothermal shift converter.

41. The process according to claim 40 wherein the saturator generates 50-60% or 55-65% of the steam, the second fired heater raises 20-25% of the steam and the steam drum coupled to the isothermal shift converter raises the balance.

42. The process according to claim 22 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

[0051] The invention is illustrated by reference to the accompanying drawing in which:

[0052] FIG. 1 is a diagrammatic flowsheet of one embodiment of the invention.

[0053] 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.

[0054] 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 process gas mixture contains between 1 and 5% vol hydrogen. The hydrogen-containing natural gas stream is fed via line 14 to a first fired heater 16, where it is heated by combustion of a fuel gas fed via line 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 present in the natural gas 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.

[0055] The desulphurised natural gas is fed from the vessel 26 via line 28 to a saturator vessel 30 where it is passed counter-currently upwards against a stream of heated pressurised water fed to near the top of the saturator via line 32. The natural gas becomes saturated with steam as it passes through the saturator vessel 30. Water is recovered from the base of the saturator 30 via line 34, combined with a heated condensate and steam condensate formed elsewhere in the process, and recirculated via pump 36 to a heat exchanger 38, where it is heated before being returned to the saturator via line 32. The saturated desulphurised natural gas is recovered from the top on the saturator vessel 30 via line 40 and combined with steam fed via lines 42 and 44 to provide a steam to carbon ratio at the inlet to reforming unit operations of about 3.1:1.

[0056] The saturated desulphurised natural gas and steam mixture is fed via line 46 to the fired heater 16 where it is further heated before being fed from the heater 16 via line 48 to a plurality of externally-heated tubes 50, containing a pelleted nickel-based steam reforming catalyst, in gas-heated reformer 52. The hydrocarbons are converted to methane, hydrogen and carbon monoxide as the mixture passes over the steam reforming catalyst. The resulting steam reformed gas mixture is then fed directly via line 54 to the burner region of an autothermal reformer 56, where it is partially combusted with oxygen fed via line 58 that has been produced in an air separation unit 60, pre-heated in heat exchanger 62, and mixed with a small flow of saturated steam. The hot combusted gas mixture is then brought towards equilibrium over a fixed bed of a pelleted nickel-based steam reforming catalyst 64 disposed below the combustion zone in the autothermal reformer 56. The resulting hot reformed gas mixture is fed from the autothermal reformer 56 via line 66 to the shell side of the gas-heated reformer 52. The hot reformed gas mixture heats the external surfaces of the tubes 50 in the gas-heated reformer, thereby providing the heat for the steam reforming reactions. The resulting partially cooled reformed gas mixture is fed from the shell side of the gas-heated reformer 52 to via line 68 to the heat exchanger 38 where it is used to heat the saturator feed water 32 and form a cooled reformed gas.

[0057] The cooled reformed gas is fed from heat exchanger 38 via line 70 to catalyst-filled tubes 72 containing a particulate copper-based water-gas shift catalyst, in an isothermal shift vessel 74. The exothermic water-gas shift reaction, whereby the hydrogen content of the reformed gas is increased, and the carbon monoxide is converted to carbon dioxide, occurs as the gas passes through the catalyst filled tubes 72. The catalyst-filled tubes 72 are cooled by means of water under pressure supplied to the isothermal shift vessel 74 via line 76. A mixture of water and steam is recovered from the isothermal shift vessel 74 via line 78 connected to a steam drum 80. Water is separated from the steam in the steam drum and recirculated to the isothermal shift vessel 74.

[0058] The hydrogen-enriched reformed gas is fed from the isothermal shift reactor 74 via line 82 to a heat exchanger 84 in which it is cooled using a portion of a condensate recovered later in the process. The partially cooled gas is fed from heat exchanger 84 via line 86 to a CO.sub.2 reboiler 88, where it is further cooled in heat exchange with a CO.sub.2-laden absorbent liquid. 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 reboiler 88 via line 90 to a gas-liquid separator 92 in which the condensate is separated from the hydrogen-enriched reformed gas mixture. A portion of the condensate stream is fed from the separator 92 via a line 94 and pump 96 to the heat exchanger 84 where it is heated. A heated condensate is recovered from the heat exchanger 84 by line 98 and mixed with steam condensate fed via line 100 to form a combined condensate. The combined condensate is mixed with the saturator bottom water in line 34 and the combined liquids fed to the saturator 30 via pump 36. By re-using the condensates, organic compounds remaining after or formed during the reforming and shift stages may be returned to the process.

[0059] Another portion of the condensate may be recovered from the separator 92 via a line 104, combined with one or more additional condensate streams and sent to water treatment.

[0060] A partially de-watered hydrogen-enriched reformed gas mixture is recovered from the separator 92 via line 106 and further cooled in heat exchange with water in heat exchanger 108 and air in cooler 110. The cooled gas is passed to a second gas-liquid separator 112 to recover a further condensate stream 114. A partially de-watered hydrogen-enriched reformed gas mixture is recovered from the separator 112 via line 116 and further cooled in heat exchange with water in heat exchanger 118. The cooled gas is passed to a third gas-liquid separator 120 to recover a further condensate stream 122. The condensate streams 114 and 122 are combined with the stream 104 and sent for water treatment via line 124.

[0061] The de-watered hydrogen-enriched reformed gas mixture is fed from the separator 120 via line 126 to a CO.sub.2 removal unit 128, such as an acid gas recovery unit, operating with a liquid absorbent wash system that absorbs CO.sub.2 from the gas. Absorbed CO.sub.2 is recovered from the CO.sub.2-laden absorbent liquid in the CO.sub.2 removal unit 128 by reducing the pressure and heating it in a reboiler 88 using the partially cooled hydrogen-enriched gas mixture in line 86. The recovered CO.sub.2 from the CO.sub.2 removal unit 128 is compressed and sent for storage via line 130.

[0062] A crude hydrogen gas stream 132 is recovered from the CO.sub.2 removal unit 128 and fed to a pressure swing adsorption unit 134 containing a porous adsorbent that traps carbon oxides and methane in the crude hydrogen, thereby producing a purified hydrogen stream. A purified hydrogen gas is recovered from the pressure swing adsorption unit 134 via line 136. A portion of the purified hydrogen is taken via line 138 and compressed to form the recirculated hydrogen stream 12. The remaining purified hydrogen is compressed and sent via line 140 either for storage, for the generation of power or heat or the synthesis of chemicals.

[0063] The pressure swing adsorption unit 134, 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 134 via line 142. A portion of the fuel gas in line 142 is provided to the first fired heater 16 via line 18 as the sole fuel to that heater. A second portion of the fuel gas in line 142 is provided as the sole fuel to a second fired heater 144 via line 146.

[0064] The second fired heater heats water, raises steam, and generates super-heated steam for the process by the combustion of the fuel gas. A stream of de-aerated water is fed to the second fired heater 144 via line 148. The resulting heated water is divided. A portion is fed from the fired heater 144 via line 150 to the steam drum 80 coupled to the isothermal water-gas shift reactor 74. Steam is then fed from the steam drum 80 via line 42 to the saturated natural gas stream 40. Another portion of the heated water generated from line 148 is fed via line 152 to a steam drum 154. Steam for the steam drum is also provided by recirculating water via from the steam drum a line 156 through the fired heater 144. Steam recovered from the steam drum 154 is divided. A portion is taken via line 158 to heat the oxygen stream in heat exchanger 62 and then steam condensate formed from the heat exchanger 62 is sent via line 100 to supplement the condensate saturator feed in line 102. A portion of steam from line 158 is added via line 162 to the preheated oxygen stream 58 before it is sent to the autothermal reformer burner. Another portion of the steam from steam drum 154 is sent via line 160 to the fired heater 144 for further heating to produce super-heated steam that is fed to the saturated natural gas stream 40 via line 44.

[0065] 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.

[0066] 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 20 28 32 40 42 Molar Flow kNm.sup.3/h 36.4 0.7 37.2 37.2 381.7 106.2 25.1 Mass Flow t/h 29.3 0.1 29.3 29.3 306.9 84.9 20.1 Temperature ° C. 40 94 230 227 255 228 256 Pressure bara 45.0 47.0 43.5 43.3 43.5 42.8 44.0 Molar Composition Unit Methane mol % 89.00 0.00 87.24 87.24 0.01 30.53 0.00 Ethane mol % 7.00 0.00 6.86 6.86 0.00 2.40 0.00 Propane mol % 1.00 0.00 0.98 0.98 0.00 0.34 0.00 Butanes mol % 0.10 0.00 0.10 0.10 0.00 0.03 0.00 Pentanes mol % 0.01 0.00 0.01 0.01 0.00 0.00 0.00 Hydrogen mol % 0.00 100.00 1.98 1.98 0.00 0.69 0.00 Carbon Dioxide mol % 2.00 0.00 1.96 1.96 0.02 0.75 0.00 Carbon Monoxide mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Oxygen mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen mol % 0.89 0.00 0.87 0.87 0.00 0.31 0.00 Argon mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Water mol % 0.00 0.00 0.00 0.00 99.96 64.92 100.00 Methanol mol % 0.00 0.00 0.00 0.00 0.01 0.02 0.00 Ammonia mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Stream Number 44 48 54 58 66 70 82 Molar Flow kNm.sup.3/h 24.9 156.2 180.6 18.5 233.5 233.5 233.4 Mass Flow t/h 20.0 125.1 125.1 26.2 151.3 151.3 151.3 Temperature ° C. 450 440 694 209 1020 240 257 Pressure bara 43.8 41.3 35.4 40.5 34.6 33.6 33.1 Molar Composition Methane mol % 0.00 20.75 14.71 0.00 0.14 0.14 0.14 Ethane mol % 0.00 1.63 0.00 0.00 0.00 0.00 0.00 Propane mol % 0.00 0.23 0.00 0.00 0.00 0.00 0.00 Butanes mol % 0.00 0.02 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 0.47 23.98 0.00 38.89 38.89 48.87 Carbon Dioxide mol % 0.00 0.51 5.62 0.00 6.46 6.46 16.48 Carbon Monoxide mol % 0.00 0.00 1.58 0.00 10.35 10.35 0.32 Oxygen mol % 0.00 0.00 0.00 97.83 0.00 0.00 0.00 Nitrogen mol % 0.00 0.21 0.18 0.49 0.18 0.18 0.18 Argon mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Water mol % 100.00 76.15 53.92 1.68 43.98 43.98 33.99 Methanol mol % 0.00 0.01 0.00 0.00 0.00 0.00 0.02 Ammonia mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Stream Number 90 100 98 106 116 124 126 Molar Flow kNm.sup.3/h 233.4 3.4 67.3 165.1 155.8 11.7 154.3 Mass Flow t/h 151.3 2.7 54.2 96.3 88.8 9.5 87.7 Temperature ° C. 120 255 180 120 71 71 40 Pressure bara 32.1 43.5 43.5 32.1 31.4 31.1 31.1 Molar Composition Methane mol % 0.14 0.00 0.00 0.19 0.21 0.00 0.21 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 % 48.87 0.00 0.00 69.08 73.22 0.00 73.89 Carbon Dioxide mol % 16.48 0.00 0.10 23.26 24.64 0.14 24.87 Carbon Monoxide mol % 0.32 0.00 0.00 0.45 0.48 0.00 0.48 Oxygen mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen mol % 0.18 0.00 0.00 0.25 0.26 0.00 0.27 Argon mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Water mol % 33.99 100.00 99.86 6.75 1.17 99.72 0.27 Methanol mol % 0.02 0.00 0.03 0.02 0.02 0.12 0.01 Ammonia mol % 0.00 0.00 0.01 0.00 0.00 0.02 0.00 Stream Number 130 132 140 142 148 150 158 160 Molar Flow kNm.sup.3/h 38.4 115.8 100.5 14.6 57.2 25.5 3.7 24.9 Mass Flow t/h 75.3 12.3 9.0 3.2 45.8 20.5 3.0 20.0 Temperature ° C. 1 49 10 40 107 235 256 256 Pressure bara 21.0 31.1 46.0 1.5 47.0 46.5 44.0 44.0 Molar Composition Methane mol % 0.00 0.28 0.00 2.19 0.00 0.00 0.00 0.00 Ethane mol % 0.00 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 0.00 Butanes mol % 0.00 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 0.00 Hydrogen mol % 0.21 98.43 100.00 87.56 0.00 0.00 0.00 0.00 Carbon Dioxide mol % 99.74 0.04 0.00 0.32 0.00 0.00 0.00 0.00 Carbon Monoxide mol % 0.00 0.64 0.00 5.09 0.00 0.00 0.00 0.00 Oxygen mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Nitrogen mol % 0.00 0.36 0.00 2.82 0.00 0.00 0.00 0.00 Argon mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Water mol % 0.05 0.23 0.00 1.82 100.00 100.00 100.00 100.00 Methanol mol % 0.00 0.02 0.00 0.16 0.00 0.00 0.00 0.00 Ammonia mol % 0.00 0.00 0.00 0.03 0.00 0.00 0.00 0.00

[0067] The flowsheet allows for capture of about 97% CO.sub.2 at a steam to carbon ratio of 3.1:1.