Method for producing hydrogen

Abstract

A method for producing hydrogen is described, the method comprising the steps of subjecting a gaseous mixture comprising hydrocarbons 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 oxygen-rich gas in an autothermal reformer to form a reformed gas mixture, optionally adding steam to the reformed gas mixture, increasing the hydrogen content of the reformed gas mixture by subjecting the reformed gas mixture to one or more water-gas shift stages in a water-gas shift unit to provide a hydrogen-rich reformed gas, cooling the hydrogen-rich reformed gas and separating condensed water therefrom, passing the resulting dehydrated hydrogen-rich 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 purified hydrogen and fuel gas, wherein the fuel gas is fed to one or more fired heaters for heating one or more process streams in the process.

Description

[0001] The present invention relates to a process for converting hydrocarbons into hydrogen while minimizing the production of carbon dioxide.

[0002] Methods for producing hydrogen are well known and typically include a flame steam methane reforming unit combined with a water gas shift and carbon dioxide (CO2) removal. Such methods produce large amounts of carbon dioxide in the flue gas at pressures that are not suitable for effective CO2 capture. There is a need for a hydrogen production process that produces lower levels of carbon dioxide effluent and achieves more efficient CO2 capture.

[0003] WO2011077106 (A1) discloses a method for reducing CO2 emissions from a combined cycle power generation process using a gaseous hydrocarbon feed, the method comprising splitting the hydrocarbon feed into two parts; a first smaller part and a second larger part, comprising: feeding the first smaller part to an autothermal reforming process to produce a hydrogen-containing gas and a carbon dioxide stream, combining the hydrogen-containing stream with the second part of the gaseous hydrocarbon, burning the resulting hydrocarbon-containing fuel stream with an oxygen-containing gas in a gas turbine to generate electricity and transferring the exhaust gas mixture from the gas turbine to a heat recovery steam generation system, the heat recovery steam generation system feeds one or more steam turbines to generate additional electricity. The captured carbon dioxide stream can be fed for storage or enhanced oil recovery processes.

[0004] An improved process has been developed where the percentage of CO2 captured can be 95% or higher.

[0005] Therefore, the present invention provides a method for producing hydrogen, the method comprising the following steps:

[0006] (i) subjecting a gaseous mixture comprising hydrocarbons and steam and having a steam to carbon ratio of at least 0.9:1 to adiabatic pre-reforming in a pre-reformer and thereafter autothermal reforming with oxygen-rich gas in an autothermal reformer to form a reformed gas mixture,

[0007] (ii) increasing the hydrogen content of the reformed gas mixture by subjecting the reformed gas mixture to one or more water gas shift stages in a water gas shift unit to provide a hydrogen-rich reformed gas,

[0008] (iii) cooling the hydrogen-rich reformed gas and separating condensed water therefrom to provide a dehydrated hydrogen-rich reformed gas,

[0009] (iv) passing the dehydrated hydrogen-rich reformate gas to a carbon dioxide separation unit to provide a carbon dioxide gas stream and a crude hydrogen gas stream, and

[0010] (v) passing the crude hydrogen gas stream from the carbon dioxide removal unit to a purification unit to provide purified hydrogen and fuel gas,

[0011] The fuel gas is fed to one or more fired heaters which are used to heat one or more process streams in a process.

[0012] By using a pre-reformer coupled to an autothermal reformer and operating at a selected steam to carbon ratio, all of the fuel gas can be used for one or more fired heaters, thereby minimizing CO2 emissions from the process. Further efficiency enhancements are also possible, achieving 95% or greater CO2 capture from the process.

[0013] The gaseous mixture may comprise any gaseous or low boiling hydrocarbon, such as natural gas, associated gas, LPG, petroleum fractions, diesel, naphtha or mixtures thereof, or hydrocarbon-containing waste gases from chemical processes, such as refinery waste gases or pre-reforming gases. The gaseous mixture preferably comprises methane, associated gas or natural gas comprising a considerable proportion of methane (e.g., more than 50% by volume of methane). Natural gas is particularly preferred. The hydrocarbon may be compressed to a pressure in the range of 10 bar to 100 bar (absolute pressure). The pressure of the hydrocarbon can effectively control the pressure in the entire process. The operating pressure is preferably in the range of 15 bar to 50 bar (absolute pressure), more preferably in the range of 25 bar to 50 bar (absolute pressure), because this provides enhanced performance in the process.

[0014] Unlike WO2011077106(A1), the hydrocarbons are not separated.

[0015] If the hydrocarbon contains sulfur compounds, it is desulfurized before or preferably after compression, including hydrodesulfurization using a CoMo or NiMo catalyst, and absorbing hydrogen sulfide using a suitable hydrogen sulfide adsorbent (e.g., zinc oxide adsorbent). Ultrapurified adsorbents can be effectively used downstream of the hydrogen sulfide adsorbent to further protect the steam reforming catalyst. Suitable ultrapurified adsorbents may include copper-zinc oxide / aluminum oxide materials and copper-nickel-zinc oxide / aluminum oxide materials. In order to facilitate hydrodesulfurization and / or reduce the risk of carbon deposition in the reforming process, hydrogen is preferably added to the compressed hydrocarbon. Based on a dry gas meter, the amount of hydrogen in the resulting mixed gas stream may be in the range of 1 volume % to 20 volume %, but preferably in the range of 1 volume % to 10 volume %, more preferably in the range of 1 volume % to 5 volume %. In a preferred embodiment, a portion of a crude hydrogen gas stream or a purified hydrogen gas stream may be mixed with compressed hydrocarbons. Hydrogen may be mixed with hydrocarbons upstream and / or downstream of any hydrodesulfurization stage.

[0016] If the hydrocarbons contain other contaminants, such as chlorides or heavy metal contaminants, these contaminants may be removed using conventional adsorbents prior to reforming, either upstream or downstream of any desulfurization. Adsorbents suitable for chloride removal are known and include alkalized alumina materials. Similarly, adsorbents for heavy metals such as mercury or arsenic are known and include copper sulfide materials.

[0017] The hydrocarbons may be preheated in one or more stages. They may conveniently be preheated after compression and before desulfurization. Various sources of hot gas are provided in the process of the invention which may be used for this task. For example, the hydrocarbon feed stream may be heated during heat exchange with a shifted gas stream recovered from a water gas shift stage, preferably a high temperature shift stage. In the case of desulfurizing the hydrocarbons, after desulfurization, the hydrocarbons may be further heated and then mixed with steam. The desulfurized hydrocarbons may be heated, for example, in a fired heater fueled by a fuel gas.

[0018] The hydrocarbons are mixed with steam. The steam introduction can be carried out by direct injection of steam and / or by saturating the hydrocarbons by contact with a stream of heated water. In a preferred embodiment, the gaseous mixture comprising hydrocarbons and steam is formed by directly mixing the hydrocarbons with steam (preferably with steam generated in one or more fired heaters and / or steam from cooling the reformed gas mixture with water). The amount of steam introduced is sufficient to obtain a steam-to-carbon ratio of at least 0.9:1 (defined as the ratio of steam to hydrocarbon carbon at the inlet of the reforming unit operation), i.e., at least 0.9 moles of steam per gram of hydrocarbon carbon atom in the gaseous mixture, with a preferred range of 0.9:1 to 3.5:1. In the case where the steam-to-carbon ratio at the inlet of the reforming unit operation is in the range of 0.9:1 to less than 2.4:1, additional steam will need to be added to the reformed gas upstream of the water gas shift stage. Operating the reforming section at a steam to carbon ratio in the range of 0.9:1 to less than 2.4:1 has the advantage of reducing the heating requirements and oxygen demand of the reforming stage and the front end equipment (e.g., fired heaters, pre-reformers, and autothermal reformers) will be smaller and reduce cost. With a steam to carbon ratio in the range of 2.4:1 to 3.5:1, there is no further steam addition upstream of the water gas shift unit, which may be useful in environments where steam addition to the reforming gas is impractical.

[0019] When preheating of the gaseous mixture comprising hydrocarbons and steam is carried out using one or more fired heaters, no further heating step is required before the adiabatic pre-reforming step.

[0020] A gaseous mixture comprising hydrocarbons and steam is subjected to an adiabatic steam reforming step in a pre-reformer vessel and thereafter to autothermal reforming in an autothermal reformer. The pre-reformer and the autothermal reformer are operated in series.

[0021] In pre-reforming, a gaseous mixture comprising hydrocarbons and steam is passed adiabatically through a bed of a steam reforming catalyst (typically a steam reforming catalyst having a high nickel content, e.g., greater than 40 wt%) at an inlet temperature in the range of 400° C. to 650° C., preferably in the range of 500° C. to 550° C. During this adiabatic pre-reforming step, any hydrocarbons higher than methane react with the steam to give a mixture of methane, carbon oxides and hydrogen. The use of such an adiabatic steam reforming step (commonly referred to as pre-reforming) is desirable to ensure that the feed to the autothermal reformer contains no hydrocarbons higher than methane and also contains some hydrogen.

[0022] In the present invention, a pre-reformed gas comprising methane, hydrogen, steam and carbon oxides is fed to an autothermal reformer in which the pre-reformed gas undergoes autothermal reforming. In the current process, all pre-reformed gases are fed to the autothermal reformer. If necessary, the temperature and / or pressure of the pre-reformed gas can be adjusted before the pre-reformed gas is fed to the autothermal reformer. In a preferred embodiment, the pre-reformed gas mixture recovered from the adiabatic reforming step is heated by passing it through a flame heater fueled by at least a portion of the fuel gas, specifically by the same flame heater used for preheating hydrocarbons, before feeding it to the autothermal reformer. Advantageously, the pre-reformed gas is heated to 600°C to 700°C, preferably 620°C to 680°C.

[0023] The autothermal reforming device may include a burner arranged at the top of the reforming device, steam reforming gas and oxygen-enriched gas are fed to the burner, and the flame extends through the combustion zone below the burner, and a fixed bed of a granular steam reforming catalyst arranged below the combustion zone. In autothermal reforming, the heat of the endothermic steam reforming reaction is therefore provided by the combustion of a portion of the hydrocarbons in the pre-reforming feed gas. The pre-reforming gas is usually fed to the top of the reforming device, and the oxygen-enriched gas is fed to the burner, and mixing and combustion occur downstream of the burner, thereby producing a heated gas mixture, the composition of which reaches equilibrium when it passes through the steam reforming catalyst. The autothermal steam reforming catalyst is nickel supported on a refractory carrier (such as a ring or pellet of calcium aluminate, magnesium aluminate, alumina, titanium dioxide, zirconium oxide, etc.). In a preferred embodiment, the autothermal steam reforming catalyst includes a catalyst layer comprising zirconium oxide supported Ni and / or Ru on an alumina supported Ni catalyst bed to reduce the volatilization of the catalyst carrier that can cause the performance degradation of the autothermal reforming device.

[0024] The oxygen-enriched gas may contain at least 50% by volume O2 and may be an oxygen-enriched air mixture, however in the present invention, the oxygen-enriched gas preferably contains at least 90% by volume O2, more preferably at least 95% by volume O2, most preferably at least 98% by volume O2, or at least 99% by volume O2, for example, a pure oxygen stream obtained using a vacuum pressure swing adsorption (VPSA) unit or an air separation unit (ASU). The ASU may be electrically driven, and advantageously driven using renewable electricity to further improve process efficiency and minimize CO2 emissions.

[0025] The amount of oxygen-rich gas added is preferably such that 45 to 65 moles of oxygen are added per 100 moles of carbon when hydrocarbons are fed to the process. Preferably, the amount of oxygen added is such that the autothermal reforming gas leaves the autothermal reforming catalyst at a temperature in the range of 800° C. to 1100° C. In a preferred embodiment, a small amount of steam purge may be added to the oxygen-rich gas to prevent backflow when the unit is tripped.

[0026] After leaving the autothermal reformer, the reformed gas is then usually cooled in one or more steps of heat exchange. These may include at least the first stage of steam increase, such as using a boiler with a connected steam drum. In one embodiment, optionally after heating in one or more fired heaters, at least a portion of the steam produced by cooling the reformed gas is mixed with hydrocarbons to form a gaseous mixture comprising hydrocarbons and steam. In another embodiment, before being fed to the autothermal reformer, the oxygen-rich gas fed to the autothermal reformer is heated when heat exchange is carried out with the steam produced by cooling the reformed gas. For safety reasons, the reformed gas is preferably not used for directly heating the oxygen-containing gas fed to the autothermal reformer. Although one or more additional cooling steps can be performed, these cooling steps are usually not required in the present method.

[0027] The reformed gas recovered from the autothermal reformer includes hydrogen, carbon monoxide, carbon dioxide, steam and a small amount of unreacted methane, and may also contain a small amount of inert gases, such as nitrogen and argon. For example, in a process in which all process steam is added upstream of the reforming unit operation, the hydrogen content of the autothermal reformed gas may be in the range of 35% to 45% by volume and the CO content may be in the range of 10% to 20% by volume. In the current process, the hydrogen content in the reformed gas mixture is increased by subjecting the reformed gas mixture to one or more water-gas shift stages in a water-gas shift unit, thereby producing a hydrogen-rich reformed gas stream, and simultaneously converting carbon monoxide to carbon dioxide. The reaction may be as follows:

[0028]

[0029] Optionally, but specifically, in the case where the steam to carbon ratio of the gaseous mixture fed to the pre-reformer is less than 2.4: 1, additional process steam may be added to the reformed gas to improve the equilibrium position in the water gas shift stage. Therefore, in some embodiments, the method includes optionally adding steam to the reformed gas. Steam may be added to the reformed gas upstream of the water gas shift unit (e.g., upstream of the high temperature shift stage). The amount of steam to be added will vary depending on the amount of steam in the gaseous mixture containing hydrocarbons fed to the reforming stage. The amount of steam added is advantageously commensurate with maximizing carbon capture from the process, which is assisted by minimizing carbon monoxide leakage. Therefore, in the case where steam is added to the reformed gas, the molar steam to dry gas ratio of the reformed gas is preferably at least 0.7: 1, more preferably in the range of 0.7: 1 to 0.9: 1.

[0030] However, in the case of reforming with excess steam, it is generally not necessary to add steam to the reformed gas mixture recovered from the autothermal reformer.

[0031] Although a water-gas shift unit may include one shift stage employing a suitably stable and active shift catalyst, it is preferred to subject the reformed gas to two or more water-gas shift stages, including a high temperature shift, an intermediate temperature shift, an isothermal shift, and a low temperature shift. In this way, a favorable balance at low temperatures may be used to maximize hydrogen formation, along with the conversion of carbon monoxide to carbon dioxide. By using two or more shift stages, extremely low CO levels in the shifted gas are possible.

[0032] The high temperature shift is operated adiabatically in a shift vessel with an inlet temperature in the range of 300°C to 400°C, preferably in the range of 320°C to 360°C, over a bed of reduced iron catalyst, such as chromium oxide promoted magnetite. Alternatively, a promoted zinc aluminate catalyst may be used. The medium temperature shift and low temperature shift stages may be performed using a shift vessel containing a supported copper catalyst, in particular a copper / zinc oxide / aluminium oxide composition. In the low temperature shift, a gas containing carbon monoxide (preferably ≤ 6 vol% CO on a dry basis) and steam (at a steam to total dry gas molar ratio in the range of 0.3:1 to 1.5:1) may be passed over the catalyst in an adiabatic fixed bed with an outlet temperature in the range of 200°C to 300°C. Typically, the inlet gas is the product of a "high temperature shift" in which the carbon monoxide content has been reduced by reaction over an iron-chromium oxide catalyst at an outlet temperature in the range of 400°C to 500°C, followed by cooling by indirect heat exchange. The outlet carbon monoxide content from the low temperature water gas shift stage is typically in the range of 0.1% to 1.0% by volume, in particular below 0.5% by volume, on a dry basis. Alternatively, in a medium temperature shift, a gas containing carbon monoxide and steam is fed to the catalyst at an inlet temperature typically in the range of 200° C. to 240° C. at a pressure in the range of 15 bar to 50 bar (absolute pressure), but the inlet temperature may be as high as 280° C., and the outlet temperature is typically up to 300° C. but may be as high as 360° C.

[0033] A shift conversion unit comprising a combination of high-temperature shift and low-temperature shift stages, with each stage operating adiabatically, is preferred in the process of the invention.

[0034] Adiabatic operation of the shift stage results in an increase in the temperature of the shifted gas mixture, and subsequent heat exchange with one or more process fluids is generally desired. Where the shift unit comprises a high temperature shift stage, two stages of heat exchange are preferred, wherein the hot shifted gas mixture may be cooled by heat exchange with water under pressure and by heat exchange with a hydrocarbon. In a preferred arrangement, the hot shifted gas from the high temperature shift stage is cooled in a first stage of heat exchange with a hydrocarbon, and in a second stage of heat exchange with water under pressure.

[0035] Although the low temperature shift and medium temperature shift reactions can be operated adiabatically, they can also be operated isothermally, that is, heat exchange is performed in the shift vessel so that the reaction in the catalyst bed occurs when in contact with the heat exchange surface. The coolant can conveniently be water at a pressure that causes partial or complete boiling to occur. The resulting steam can be used, for example, to drive a turbine to obtain electricity or to provide process steam for water gas shift or steam reforming reactions. The water can be located in a tube surrounded by or surrounding the catalyst. Although the term "isothermal" is used, there may be a small increase in the gas temperature between the inlet and the outlet, so that the temperature of the hydrogen-rich reformed gas stream at the outlet of the isothermal shift converter can be between 1 degree Celsius and 25 degrees Celsius higher than the inlet temperature.

[0036] After one or more shift stages, the hydrogen-rich reformed gas is cooled to a temperature below the dew point so that steam condenses. Liquid water condensate can then be separated using one or more gas-liquid separators, which may have one or more additional cooling stages between them. Any coolant can be used. Preferably, the cooling of the hydrogen-rich reformed gas stream is first performed during heat exchange with water. In a preferred arrangement, the hydrogen-rich reformed gas mixture is cooled during heat exchange with water, and the resulting heated water is fed to a steam drum coupled to a boiler for cooling the reformed gas mixture. One or more additional stages of cooling are desired. Cooling can be performed in heat exchange in one or more stages using deionized water, air, or a combination of these substances.

[0037] Two or three condensate separation stages are preferred. If desired, some or all of the condensate can be used to generate steam for the adiabatic pre-reforming step, or can be used to generate steam added to the oxygen-rich gas fed to the autothermal reformer. In this way, organic compounds in the condensate can be returned to the process and the burden of any aqueous effluent treatment is thus reduced. Any condensate not used to generate steam can be sent as effluent to water treatment.

[0038] Typically, the hydrogen-rich reformed gas stream contains 20% to 30% by volume of carbon dioxide (on a dry basis). In the present invention, carbon dioxide is separated from the resulting dehydrated hydrogen-rich reformed gas stream after separation of condensed water.

[0039] The carbon dioxide separation stage can be performed using a physical scrubbing system or a reactive scrubbing system, preferably a reactive scrubbing system, especially an amine scrubbing system. Carbon dioxide can be separated by an acid gas recovery (AGR) process. In the AGR process, a dehydrated hydrogen-rich reformed gas stream (i.e., dehydrated shift gas) is contacted with a stream of a suitable absorbent liquid (such as an amine, specifically a methyldiethanolamine (MDEA) solution) so that carbon dioxide is absorbed by the liquid to obtain a loaded absorbent liquid and a gas stream with a reduced carbon dioxide content. The loaded absorbent liquid is then regenerated by heating and / or reducing the pressure to desorb carbon dioxide and obtain a regenerated absorbent liquid, which is then recycled to the carbon dioxide absorption stage. Alternatively, methanol or glycol can be used to capture carbon dioxide in a manner similar to amines. In a preferred arrangement, steam generated in one or more fired heaters is used to perform at least a portion of the heating to regenerate the absorbent liquid. If the carbon dioxide separation step is operated as a single pressure process, i.e., substantially the same pressure is used in the absorption and regeneration steps, only a small amount of recompression of the recycled carbon dioxide will be required.

[0040] For example, recovered carbon dioxide from AGR can be compressed and used to make chemicals, sent to storage or sequestration, used in enhanced oil recovery (EOR) processes, or used to produce other chemicals. Compression can be achieved using an electrically driven compressor powered by renewable electricity. In the case where CO2 is to be compressed for storage, transportation, or for use in EOR processes, the CO2 can be dried to prevent condensation of liquid water present in trace amounts. For example, CO2 can be dried to a dew point of ≤-10°C by passing it through a bed of a suitable desiccant (such as zeolite), or by contacting it with glycol in a glycol drying unit.

[0041] After separation of carbon dioxide, the process provides a crude hydrogen stream. The crude hydrogen stream may comprise 85% to 99% hydrogen by volume, preferably 90% to 99% hydrogen by volume, more preferably 95% to 99% hydrogen by volume, with the remainder comprising methane, carbon monoxide, carbon dioxide and inert gases. Although such a hydrogen stream is sufficiently pure for many uses, in the present invention, the crude hydrogen stream is passed to a purification unit to provide purified hydrogen and fuel gas, so that the fuel gas can be used in the process as an alternative to an external fuel source.

[0042] The purification unit may suitably include a membrane system, a temperature swing adsorption system or a pressure swing adsorption system. Such systems are commercially available. The purification unit is preferably a pressure swing adsorption unit. Such units include a regenerable porous adsorbent material that selectively captures gases other than hydrogen, thereby purifying it. The purification unit produces a pure hydrogen gas stream preferably having a purity greater than 99.5% by volume, more preferably greater than 99.9% by volume, which can be compressed and used for downstream power generation or heating processes, for example, by using it as a fuel in a gas turbine (GT) or by injecting it into a household or industrial networked gas pipeline system. Pure hydrogen can also be used in downstream chemical synthesis processes. Therefore, the pure hydrogen gas stream can be used to produce ammonia by reacting with nitrogen in an ammonia synthesis unit. Alternatively, pure hydrogen can be used with a gas containing carbon dioxide to make methanol in a methanol production unit. Alternatively, pure hydrogen can be used with a gas containing carbon monoxide to synthesize hydrocarbons in a Fischer-Tropsch production unit. Any known ammonia, methanol or Fischer-Tropsch production technology can be used. Alternatively, the hydrogen may be used to upgrade hydrocarbons, for example by hydrotreating or hydrocracking hydrocarbons in a hydrocarbon refinery, or in any other process in which pure hydrogen may be used.Compression may likewise be achieved using electrically driven compressors powered by renewable electricity.

[0043] If desired, a portion of the crude hydrogen or a portion of the pure hydrogen may be recycled to the hydrocarbon feed stream for desulfurization and to reduce the potential for carbon formation on the catalyst in the pre-reformer.

[0044] The purification unit is advantageously operated with the fuel gas continuously separated from the crude hydrogen stream. The fuel gas composition depends on the degree of purification of the crude hydrogen stream. The fuel gas may contain 80% to 90% hydrogen by volume, with the remainder containing methane, carbon monoxide, carbon dioxide and inert gases. The methane content may be in the range of 1% to 5% by volume, preferably 2% to 5% by volume. The carbon monoxide content may be in the range of 2% to 10% by volume, preferably 2% to 8% by volume. The carbon dioxide content may be in the range of 0% to 1.5% by volume. Traces of steam and nitrogen may also be present in the range of 0% to 5% by volume.

[0045] The combination of pre-reforming, autothermal reforming and water gas shift operated as described herein provides sufficient fuel gas to heat the process streams used in the process but without a large amount of additional fuel during normal operation. The volume of supplemental fuel in the process is advantageously kept to a minimum to maximize CO2 capture efficiency. The amount of supplemental fuel (e.g., natural gas) fed to one or more fired heaters along with the fuel gas is preferably less than 5 volume of the total fuel provided, more preferably less than 3 volume of the total fuel provided, and most preferably less than 2% of the total fuel provided.

[0046] In some circumstances, such as during start-up of the process, it may be necessary to temporarily supplement the fuel gas with hydrocarbon fuel, but this should not materially reduce the efficiency of the process, and during normal operation the fuel gas recovered from the purification unit will be the primary source of fuel provided to the one or more fired heaters.

[0047] In some embodiments, a single fired heater fueled at least in part by fuel gas recovered from purification is sufficient to heat hydrocarbons, reformed gas recovered from a pre-reforming stage upstream of the autothermal reforming stage, and water to produce at least a portion of the steam for the process.

[0048] Although all process streams requiring heating may be heated in a single fired heater, in a preferred arrangement one fired heater is used for a process gas stream containing hydrocarbons and / or hydrogen, while the other fired heater is used only to boil water to produce steam. The latter may therefore also be described as a boiler. The fuel gas may therefore be divided between a first fired heater for heating a hydrocarbon and / or hydrogen-containing stream and a second fired heater for boiling water to produce steam. Using two fired heaters in this manner provides a number of different advantages; it allows steam to be added in the second fired heater for use as part of the start-up of the unit; it allows steam to be generated in the second fired heater while the unit is being shut down and supplied to the unit during this shut down; it makes start-up easier because the first and second fired heaters can be operated independently and eliminate coils that are heated in a no-flow state; and separation of the first fired heater allows nitrogen to be heated as part of the start-up procedure when the second fired heater is put into service or itself is being started up. The fuel gas is diverted to the first flame heater and the second flame heater in the range of 10 volume % to 90 volume % and 90 volume % to 10 volume %, respectively, preferably 60 volume % to 80 volume % to the first flame heater and 40 volume % to 20 volume % to the second flame heater.

[0049] The steam generated in the second fired heater can be used to heat the CO2 absorbent liquid in the carbon dioxide separation unit. The second fired heater can also be used to superheat steam recovered from a steam drum coupled to a waste liquid boiler heated by the reformed gas. The waste heat boiler is preferably also used to generate steam for preheating the oxygen-rich gas and / or providing process steam to be added upstream of the water-gas shift unit to maximize the conversion to hydrogen and carbon dioxide. A portion of the steam from the waste heat boiler can also be transferred to a steam expander to generate electricity.

[0050] The present invention is described with reference to the accompanying drawings, in which:

[0051] Figure 1is a schematic process flow diagram of one embodiment of the present invention wherein all process steam is added upstream of the reforming unit operation.

[0052] It will be appreciated by those skilled in the art that the drawings are illustrative and that other items of equipment may be required in a commercial installation, such as reflux tanks, pumps, vacuum pumps, temperature sensors, pressure sensors, pressure reducing valves, control valves, flow controllers, level controllers, collection tanks, storage tanks, etc. The provision of such ancillary items of equipment does not form part of the present invention and is in accordance with conventional chemical engineering practice.

[0053] exist Figure 1 In the process, a natural gas stream containing >85 vol% methane fed via line 10 is mixed with a hydrogen-containing stream 12 so that the resulting mixture contains between 1 vol% 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 shift gas 18. The heated natural gas mixture is then desulfurized by passing via line 20 to a hydrodesulfurization (HDS) vessel 22 containing a hydrodesulfurization catalyst bed, where organic sulfur compounds are converted to hydrogen sulfide using hydrogen, and then passed via line 24 to a vessel 26 containing a zinc oxide adsorbent bed and a copper-zinc-alumina ultrapurification adsorbent bed, where hydrogen sulfide is removed.

[0054] Sweet natural gas is fed from vessel 26 via line 28 to a first fired heater 30 where it is heated by combustion of fuel gas fed to the heater via line 32. The heated natural gas is taken from 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.

[0055] The natural gas and steam mixture is fed via line 38 to an adiabatic pre-reformer 40 containing a bed of granular nickel-based steam reforming catalyst. As the mixture passes over the pre-reformer catalyst, higher hydrocarbons are converted to methane and a portion of the steam is reformed to produce a pre-reformed gas mixture containing hydrogen. The pre-reformed gas mixture is then fed from the pre-reformer 40 to the first fired heater 30 via line 42 where it is heated to the autothermal reformer inlet temperature.

[0056] The heated pre-reformed gas mixture is fed from the fired heater 30 via line 44 to the burner area of ​​the autothermal reformer 46 where it is partially combusted with oxygen fed via line 48 which has been produced in the air separation unit 50 and preheated in the heat exchanger 52. The hot combusted gas mixture is equilibrated over a fixed bed of a particulate 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 boost boiler 58 coupled to a steam drum 60. The hot reformed gas mixture boils water fed from the steam drum 60 to the shell side of the boiler via line 62 and returns steam from the boiler to the steam drum 60 via line 64. The steam drum 60 coupled to the boiler 58 produces high pressure steam which is recovered from the steam drum 60, distributed and used in the process. The hot reformed gas mixture is cooled as it passes through the boiler 58 .

[0057] 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 a granular bed of an iron-based high temperature shift catalyst. The water gas shift reaction thereby increases the hydrogen content of the reformed gas, and conversion of carbon monoxide to carbon dioxide occurs as the gas passes through the bed. The partially shifted reformed gas is fed from the first shift reactor to a heat exchanger 16 via line 18, where the natural gas is preheated, and then fed to another heat exchanger 70, where the natural gas is cooled under pressure with water. The cooled partially shifted gas mixture is fed from heat exchanger 70 to a second shift vessel 74 via line 72, which contains a fixed bed of a granular copper-based low temperature shift catalyst. As the gas passes through the bed, the water gas shift reaction moves further to completion. The resulting hydrogen-rich reformed gas mixture is then cooled in a heat exchanger 76, which is fed with cold pressurized deionized deaerated water, which is provided to the process via line 78. Part of the water recovered from heat exchanger 76 in line 80 is fed to heat exchanger 70 which is used to cool the partially shifted gas mixture. Heated water recovered from heat exchanger 70 is fed to steam drum 60 via line 82 to provide a coolant for the reformed gas mixture in boiler 58.

[0058] The cooled hydrogen-rich reformed gas is fed from heat exchanger 76 to another heat exchanger 86 via pipeline 84, wherein the reformed gas is further cooled with water. The cooling reduces the temperature of the gas mixture to below the dew point, so that water condenses. The cooling stream is fed from heat exchanger 86 to a gas-liquid separator 88, wherein the condensate is separated from the hydrogen-rich reformed gas mixture. The condensate is recovered from separator 88 via pipeline 90. In this embodiment, the partially dehydrated hydrogen-rich reformed gas mixture is recovered from separator 88 via pipeline 92, and is further cooled in heat exchanger 94 when heat exchanged with water. The cooled gas is transferred to a second gas-liquid separator 96 to recover another condensate stream 98. Condensate streams 90 and 98 are combined and delivered as effluent 100 for water treatment.

[0059] The dehydrated hydrogen-rich reformed gas mixture is fed from separator 96 to a CO2 removal unit 104, such as an acid gas recovery unit, via line 102, which operates in conjunction with a liquid absorptive scrubbing system that absorbs CO2 and any remaining H2O from the gas. The absorbed CO2 is recovered from the CO2-loaded absorptive liquid in unit 104 by heating and reducing the pressure using steam fed to unit 104 via line 106. The water recovered with the CO2 is separated and delivered for water treatment (not shown). Steam condensate is recovered from the CO2 removal unit 104 via line 108. The CO2 recovered from the CO2 removal unit 104 is delivered via line 110 for compression and storage.

[0060] A crude hydrogen stream is recovered from the CO2 removal unit 104 and fed via line 112 to a pressure swing adsorption unit 114 containing a porous adsorbent that captures carbon oxides and methane in the crude hydrogen, thereby producing a purified hydrogen stream. Purified hydrogen 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 a recycle hydrogen stream 12. The remaining purified hydrogen in line 120 is compressed and delivered for storage, for use in generating electricity or heat, or for use in generating or converting chemicals.

[0061] The pressure swing adsorption unit 114 desorbs carbon oxide and methane trapped in the porous adsorbent by adjusting the pressure, thereby producing fuel gas. The fuel gas is recovered from the pressure swing adsorption unit 114 via pipeline 122. A portion of the fuel gas in the pipeline 122 is provided to the first fired heater 30 via pipeline 32 as the sole fuel for the heater. A second portion of the fuel gas in the pipeline 122 is provided to the second fired heater 124 via pipeline 126 as the sole fuel.

[0062] The second fired heater 124 increases steam for the process by combusting fuel gas provided via line 126 .

[0063] 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 the 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, thereby producing superheated steam that is fed to the sweetened 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 produce electricity for the process, for example to drive the air separation unit 50 and / or electrically driven compressors 144, 146 and 148.

[0064] The hot water stream may be taken from preheated deionized water in line 80, as shown, or from preheated deionized water in line 82 and fed to a steam drum 152 via line 150, wherein the heated water is circulated through the second fired heater 124 via lines 154 and 156 to produce steam at low pressure. Steam from the steam drum 152 is recovered via line 106 and used to heat the CO2 absorbent liquid in the CO2 removal unit 104.

[0065] Efficient use of fuel gas to provide a heated natural gas feed stream and steam to the process minimizes CO2 emissions from the process.

[0066] Example 1

[0067] The present invention is based on Figure 1 The process flow described in is further illustrated by the following calculated process example.

[0068]

[0069]

[0070] Stream Number 42 44 48 56 66 72 78 Molar flow <![CDATA[kNm 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 ℃ 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 Butane mol% 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Pentane 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

[0071]

[0072]

[0073] Stream Number 110 112 116 120 122 126 128 Molar flow <![CDATA[kNm 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 ℃ 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 Butane mol% 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Pentane 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

[0074]

[0075]

[0076] The process allows for 95% capture of CO2 at a steam to carbon ratio of 2.5:1.

[0077] Example 2

[0078] The present invention is based on Figure 1 The process flow described in is further illustrated by the following calculated process example, which has the following changes:

[0079] a) reducing the operating pressure of the reforming unit operation to 26 barg;

[0080] 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;

[0081] c) adding oxygen to the autothermal reformer to achieve an outlet temperature of 1065°C;

[0082] d) adding steam boosted in the steam boost boiler 58 to the cooled reformate gas 66 so that the feed at the inlet of the high temperature water gas shift has a steam to dry gas ratio of 0.72:1;

[0083] e) cooling the product gas from the high temperature water-gas shift reactor 68 so that the feed gas to the low temperature water-gas shift reactor 74 has an inlet temperature of 190°C; and

[0084] f) Adjusting the balance of fired heater duties in the two fired heaters 30 and 124 to distribute the added process stream both upstream and downstream of the reforming unit operation.

[0085] The process flow in this arrangement also allows for 95% capture of CO2 at a steam to carbon ratio of 0.95:1, which reduces heat requirements and oxygen consumption in the autothermal reformer.

Claims

1. A method for producing hydrogen, the method comprising the following steps: (i) subjecting a gaseous mixture comprising hydrocarbons and steam and having a steam to carbon ratio in the range of 0.9:1 to less than 2.4:1 to adiabatic pre-reforming in a pre-reformer and thereafter autothermal reforming with oxygen-rich gas in an autothermal reformer to produce a reformed gas mixture, (ii) increasing the hydrogen content of the reformed gas mixture by adding steam to the reformed gas mixture and subjecting the reformed gas mixture to one or more water gas shift stages in a water gas shift unit to provide a hydrogen-rich reformed gas, (iii) cooling the hydrogen-rich reformed gas and separating condensed water therefrom to provide a dehydrated hydrogen-rich reformed gas, (iv) passing the dehydrated hydrogen-rich reformate 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 purified hydrogen and fuel gas, Wherein all of the fuel gas is fed to one or more fired heaters which are used to heat one or more process streams in the process.

2. The method of claim 1, wherein the hydrocarbon is a methane-containing gas stream.

3. The process of claim 1, wherein the hydrocarbons are desulfurized.

4. The method of claim 1, wherein the gaseous mixture comprising the hydrocarbons and steam is formed by mixing the hydrocarbons with steam generated by the one or more fired heaters and / or by cooling the reformed gas mixture with water.

5. The method of claim 1, wherein the oxygen-rich gas comprises at least 90 vol. % O2.

6. The method according to claim 1, wherein the oxygen-rich gas is heated while exchanging heat with steam generated by cooling the reformed gas before being fed to the autothermal reformer.

7. The method of claim 1, wherein the water-gas shift stage comprises a high temperature shift stage and a downstream low temperature shift stage.

8. A process according to claim 7, wherein the hydrocarbons are heated in heat exchange with a shifted gas stream recovered from a high temperature shift stage.

9. The process of claim 1 wherein steam generated in the one or more fired heaters is used to generate electricity for the process.

10. The method according to claim 1, wherein there are at least two stages of cooling and separation of the process condensate before the carbon dioxide removal stage.

11. The method of claim 1 , wherein the carbon dioxide removal stage is performed using a physical scrubbing system or a reactive scrubbing system.

12. The method of claim 1, 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.

13. The method of claim 1, wherein the purification unit is a pressure swing adsorption unit or a temperature swing adsorption unit.

14. The method of claim 1, wherein the carbon dioxide recovered from the carbon dioxide removal unit and the purified hydrogen recovered from the purification unit are each compressed in an electrically driven compressor.

15. The process of claim 1, wherein a portion of the crude hydrogen gas stream or the purified hydrogen gas is fed to the hydrocarbon.

16. The method of claim 1 wherein supplemental fuel is added to the fuel gas fed to the one or more fired heaters and the amount of supplemental fuel is less than 5% by volume of the total fuel provided.

17. A process according to claim 1, wherein there is a single fired heater fuelled at least in part by the fuel gas recovered from the purification unit and which is used to heat the hydrocarbons, to heat the reformed gas recovered from the pre-reforming stage upstream of the autothermal reforming stage, and to heat water to produce at least a portion of the steam used for the process.

18. A process according to claim 1, wherein there are two fired heaters fueled at least in part by the fuel gas recovered from the purification unit; a first fired heater which heats the hydrocarbon feed stream and the reformed gas stream recovered from the pre-reforming stage upstream of the autothermal reforming stage, and a second fired heater which is used as a boiler to generate steam for the process.

19. The method of claim 18, wherein the fuel gas is split to the first fired heater and the second fired heater in a range of 10 vol% to 90 vol% to 90 vol% to 10 vol%, respectively.

20. The method of claim 18, wherein a portion of the steam generated in the second fired heater is used to heat a CO2 absorbing liquid in the carbon dioxide separation unit.

21. The method of claim 18, wherein the 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.

22. The method of claim 21, wherein the waste heat boiler is also used to generate steam for preheating the oxygen-enriched gas.

23. The method of claim 21, wherein a portion of the steam from the waste heat boiler is passed to a steam expander to generate electricity.

24. The method of claim 21, wherein a portion of the steam from the waste heat boiler is added to the reformed gas when the steam to carbon ratio is below 2.4:

1.

25. The method of claim 1, wherein the purified hydrogen is used in a downstream power generation process, a heating process, a downstream chemical synthesis process, or for upgrading hydrocarbons.

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