SYNTHETIC GAS FROM BIOMASS AS FUEL FOR INDUSTRIAL HYDROGEN PRODUCTION

Abstract

The invention may include the use of existing biomass or waste gasification technologies that can be used to produce (at least in part) biogenic synthesis gas that can be used as fuel in hydrogen production plants. (Shorthand figure: Fig. 1)

Description

Title of the invention: SYNTHESIS GAS FROM BIOMASS AS FUEL FOR THE INDUSTRIAL PRODUCTION OF HYDROGEN

[0001] The present invention relates to an apparatus and method for producing hydrogen using syngas from biomass as fuel. More specifically, embodiments of the present invention relate to reducing the carbon footprint of a reforming unit and / or an ammonia cracker by reducing the carbonaceous gases produced. Furthermore, with hydrogen rapidly becoming the preferred energy carrier of the future due to its carbon-free nature, environmentally friendly hydrogen production is becoming increasingly important.

[0002] Steam methane reforming (SMR) is one of the industrial units currently used to produce hydrogen. In a typical SMR, methane and steam are combined and react at high temperatures to produce syngas (i.e., a mixture primarily composed of hydrogen, carbon monoxide, and carbon dioxide). This reaction is endothermic and therefore requires a heat input, which is provided by the combustion of a fuel (usually a portion of the methane feedstock) in the presence of oxygen to produce a flue gas consisting primarily of carbon dioxide, water, and unreacted oxygen. If oxygen is provided by air, the flue gas also contains nitrogen and nitrogen oxides (NOx). Syngas is typically upgraded by reacting the gas with water to convert carbon monoxide to carbon dioxide and additional hydrogen.Finally, the syngas is sent to a purifier (usually a pressure swing adsorber ("PSA")), to produce a pure hydrogen stream and a PSA tail gas stream, which consists primarily of carbon dioxide, some hydrogen, and unreacted methane. The PSA tail gas stream is then used as fuel, recycled and combined with natural gas for reforming, or recycled back to the PSA unit inlet.

[0003] As stated above, in a typical SMR, natural gas (NG) is used both as feedstock and as fuel. In the furnace, it is usually burned with the off-gas from the hydrogen purification unit. Therefore, typical burner systems are based on the co-combustion of methane with CO2, CO and H2, in the presence of nitrogen and oxygen from the air. Different options can be used to decarbonize these units.

[0004] Capture of CO2 in flue gases: this operation is generally expensive and difficult because it requires the installation of large scrubbing towers and large amounts of energy or steam. Another solution is to use NH3 as an additional fuel: this concept can be applied to both SMRs (NG as feed) and NH3 crackers (NH3 as feed).

[0005] If NH3 is used as fuel, special attention should be paid to: combustion properties (flame stability), design of the flue gas heat recovery section (larger flue gas quantities are expected due to the lower calorific value and radiation effect of NH3 compared to NG), and NOx removal. With regard to the latter aspect, usually expensive and large SCR units are required to reduce NOx from the initial level in the flue gas (> 1000 ppm) to the permitted emission levels (usually < 50 ppm).

[0006] Biomass and waste gasification is a process that converts solid fuels into a mixture of hydrogen, CO, CO2 and CH4, potentially also in the presence of H2O and N2, through a high temperature conversion (typically 600 - 1500°C) in the presence of an oxidizing agent such as oxygen (pure or air) and H2 O. Gasification of biogenic solid feedstocks is commercialized at scales ranging from a few hundred kW to ~ 150 MW. Although many efforts have been made to transform biomass and waste directly into hydrogen or chemicals, most current applications are aimed at producing heat and electricity.Examples include small units for powering combined heat and power (CHP) systems in homes, biomass power plants (simple cycle or IGCC), or plants that produce flammable gases that can be used in industrial kilns such as cement plants. The technologies are commercially available from several companies (see Table 1: Examples of mature technologies for biomass gasification).

[0007] [Tables 1] Company Name Raw Materials Size [MW Input] Application Comment / Details Sierra Energy TMS 1 PSC Fixed Bed Air Gasification Wrench Re2 Wood < 1.5 PSC Fixed Bed Air Gasification Xylowatt Wood 5 CHP, glass, cement 2-stage moving bed (pyrolysis + coal gasification), air-based Cortus Wood 6 CHP, H2, CO2 Two-stage steam gasification (pyrolysis + entrained flow coal gasification) EQTec FDR 20 PSC bubbling fluidized bed gasification, air-based Fulcrum / TRI TMS ~ 50 Biofuels Two-stage fluidized bed steam gasification with indirect heating via heat pipes Valmet Wood > 150 PSC Circulating finished bed gasification

[0008] The main disadvantages of carbon capture and storage (CCS) for carbon footprint reduction are: the high costs of flue gas capture, the need for CO2 transport and storage infrastructure, and permits and regulations that accept CCS as a net emission reduction measure. CCS is not considered a feasible option for remote sites, small production units, and sites far from CO2 sequestration sites and export terminals.

[0009] The main disadvantages of NH3 combustion are: limitations in the design of the flue gas section due to the reduced space available (in case of retrofitting), high price of NH3 in the current market, even for fossil NH3, competition with the food chain (NH3 as fertilizer) and difficulty in removing NOx. Especially for sites that are not close to NH3 import centers or local NH3 production, the availability of NH3 and obtaining a permit for handling large quantities of NH3 will be difficult.

[0010] The present invention relates to an apparatus and a method that meet at least one of these needs. In some cases, the invention may include the use of existing biomass or waste gasification technologies that can be used to produce (at least in part) biogenic syngas that can be used as fuel in hydrogen production plants.

[0011] An apparatus for producing hydrogen in a steam methane reformer while reducing carbon emissions is provided in one embodiment. In this embodiment, the apparatus may include: a dryer configured to remove moisture from a biomass to produce a dry biomass; a gasification unit in fluid communication with the dryer, the gasification unit configured to receive the dry biomass and gasify the dry biomass to produce a combustible gas mixture; a steam methane reformer in fluid communication with the gasification unit, the steam methane reformer configured to catalytically crack the methane to produce a reformed stream by burning the combustible gas mixture, the reformed stream including hydrogen, carbon monoxide, and unreacted methane;a conversion unit in fluid communication with the steam methane reformer, wherein the conversion unit is configured to receive the reformed stream in the presence of steam, perform a water gas reaction, and produce a shift gas stream comprising hydrogen and carbon dioxide; and a hydrogen purification unit configured to receive the shift gas stream and purify the shift gas stream to produce a hydrogen product stream and a tail gas; wherein a flue gas is produced by combustion of the combustible gas mixture.;

[0012] In optional embodiments of the apparatus: • the apparatus may also comprise a water cooling unit placed downstream of the steam methane reformer and upstream of the conversion unit, the water cooling unit being configured to cool the reformed stream; • the apparatus may also include a waste gas conduit configured to combine the waste gas with the combustible gas mixture; • the apparatus may also include a waste heat recovery unit in fluid communication with the steam methane reformer, the waste heat recovery unit being configured to transfer heat from the flue gases to other process streams, thereby producing cooler flue gases; • the dryer uses the cooler flue gas to remove moisture from the biomass by evaporation of water; and / or • depending on the gasification technology and the properties of the synthesis gas (temperature, impurities, etc.), different treatment schemes can be used from the group consisting of direct mixing with PSA off-gases to cool the synthesis gas, pre-cooling and condensation of the synthesis gas before mixing, cooling and washing of synthesis gas before mixing with off-gases, oxygen enrichment of combustion air or use of oxygen in place of combustion air, recycling of flue gases to control or concentrate CO2, further compression of synthesis gas, and combinations of these.

[0013] In another embodiment, a method for producing hydrogen in a steam methane reformer with reduced carbon emissions is provided. In this embodiment, the method may comprise the steps of: drying a biomass in a dryer configured to remove moisture to produce a dry biomass; sending the dry biomass to a gasification unit to produce a fuel gas mixture of hydrogen, carbon monoxide, carbon dioxide, and methane; reforming a hydrocarbon stream in a steam methane reformer configured to catalytically crack methane to produce a reformed stream by burning the fuel gas mixture, wherein the reformed stream comprises unreacted hydrogen, carbon monoxide, and methane;introducing the reformed stream into a gas-water conversion unit configured to produce a shift gas stream comprising hydrogen and carbon dioxide; and introducing the shift gas stream into a hydrogen purification unit configured to produce a hydrogen product stream and a tail gas; wherein a flue gas is produced by combustion of the fuel gas mixture in the steam methane reformer.;

[0014] In optional embodiments of the method: • the method may also comprise a step of cooling the reformed stream before the conversion unit; • the method may also comprise a step of recycling the waste gas from the hydrogen purification unit into the combustible gas mixture; • the method may also include a waste heat recovery unit in fluid communication with the steam methane reformer, the waste heat recovery unit being configured to transfer heat from the flue gases to other process streams, thereby producing cooler flue gases; • the dryer uses the cooler flue gas to remove moisture from the biomass by evaporation of water; and / or • depending on the gasification technology and the properties of the synthesis gas (temperature, impurities, etc.), different treatment schemes can be used among the group consisting of direct mixing with PSA gas effluents to cool the synthesis gas, pre-cooling and condensation of synthesis gas prior to blending, cooling and scrubbing of synthesis gas prior to blending with off-gases, oxygen enrichment of combustion air or use of oxygen in place of combustion air, recycling of flue gases to control or concentrate CO2, further compression of synthesis gas, and combinations thereof.

[0015] In another embodiment, an apparatus for producing hydrogen in an ammonia cracker while reducing carbon emissions is provided. In this embodiment, the apparatus may comprise: a dryer configured to remove moisture from a biomass to produce a dry biomass; a gasification unit in fluid communication with the dryer, the gasification unit configured to receive the dry biomass and gasify it to produce a combustible gas mixture; an ammonia cracker in fluid communication with the gasification unit, wherein the ammonia cracker is configured to catalytically crack ammonia to produce a cracked stream by burning the combustible gas mixture to provide heat for cracking the ammonia, wherein the cracked stream comprises hydrogen, nitrogen, and unconverted ammonia;an ammonia removal unit in fluid communication with the ammonia cracker, wherein the ammonia removal unit is configured to receive the cracked stream and produce a hydrogen-rich gas and recovered ammonia; and a hydrogen purification unit configured to receive the hydrogen-rich gas and purify the hydrogen-rich gas to produce a hydrogen product stream and a tail gas; wherein a flue gas is produced by combustion of the fuel gas mixture.;

[0016] In optional embodiments of the apparatus: • the apparatus may also comprise a water cooling unit placed downstream of the ammonia cracking unit and upstream of the ammonia removal unit, the water cooling unit being configured to cool the cracked stream; • the apparatus may also include a waste gas conduit configured to combine the waste gas with the combustible gas mixture; • the apparatus may also include a waste heat recovery unit in fluid communication with the ammonia cracker, the waste heat recovery unit being configured to transfer heat from the flue gases to other process streams, thereby producing cooler flue gases; • the dryer uses the cooler flue gas to remove moisture from the biomass by evaporation of water; and / or • depending on the gasification technology and the properties of the syngas (temperature, impurities, etc.), different treatment schemes can be used from the group consisting of direct mixing with PSA off-gas to cool the syngas, pre-cooling and condensation of the syngas before mixing, cooling and washing of the syngas before mixing with the off-gas, oxygen enrichment of the combustion air or use of oxygen instead of combustion air, recycling of the flue gas to control or concentrate CO2, additional compression of the syngas, and combinations of these.

[0017] In another embodiment, a method for producing hydrogen in an ammonia cracker with reduced carbon emissions is provided. In this embodiment, the method may comprise the steps of: drying a biomass in a dryer configured to remove moisture to produce a dry biomass; sending the dry biomass to a gasification unit to produce a fuel gas mixture of hydrogen, carbon monoxide, carbon dioxide, and methane; cracking an ammonia stream in an ammonia cracker configured to catalytically crack ammonia to produce a cracked stream by burning the fuel gas mixture to provide heat for cracking the ammonia, wherein the cracked stream comprises hydrogen, nitrogen, and unconverted ammonia;introducing the cracked stream into an ammonia removal unit configured to produce a hydrogen-rich gas and recovered ammonia; and introducing the hydrogen-rich gas into a hydrogen purification unit to produce a hydrogen stream and a tail gas; wherein a flue gas is produced by combustion of the combustible gas mixture in the ammonia cracker.;

[0018] In optional embodiments of the method: • the method may also include a step of cooling the reformed stream before the conversion unit. • the method may also comprise a step of recycling the waste gas from the hydrogen purification unit into the combustible gas mixture. • the method may also include a step of recycling the ammonia recovered from the ammonia removal unit into the fuel gas mixture. • the method may also include a waste heat recovery unit in fluid communication with the ammonia cracker, wherein the waste heat recovery unit is configured to transfer heat from the flue gas to other process streams, thereby producing cooler flue gas. • the dryer uses the cooler combustion gases to remove moisture from the biomass by evaporating the water. Depending on the gasification technology and syngas properties (temperature, impurities, etc.), different treatment schemes can be used from the group consisting of direct mixing with PSA off-gas to cool the syngas, pre-cooling and condensation of the syngas before mixing, cooling and scrubbing of the syngas before mixing with the off-gas, oxygen enrichment of the combustion air or use of oxygen instead of combustion air, flue gas recycling to control or concentrate CO2, additional compression of the syngas, and combinations of these.

[0019] These features, as well as other aspects and advantages of the present invention, will be better understood in light of the description, the claims and the accompanying drawings. It should be noted, however, that the drawings illustrate only several embodiments of the invention and should therefore not be considered as limiting the scope of the invention, which may admit other equally effective embodiments.

[0020] [Fig.l] [Fig.l] shows an example of a plant for producing hydrogen by steam methane reforming, in accordance with an example of the present invention; and

[0021] [Fig.2] shows an example of a hydrogen production plant by ammonia cracking, in accordance with an example of the present invention.

[0022] Although the invention is described in connection with several embodiments, it is understood that it is not intended to be limited to these embodiments. Rather, it is intended to cover all alternatives, modifications, and equivalents that may be included within the spirit and scope of the invention defined by the appended claims.

[0023] Typical biomass gasification technologies produce a gas that can easily be combusted, but is difficult to purify to obtain pure hydrogen or syngas for synthesis applications. Cogeneration and heating applications, on the other hand, are already at the cutting edge. Syngas from biomass or waste gasification has a calorific value and composition comparable to that of the fuel combusted in a normal SMR furnace. Therefore, existing concepts and, potentially, existing assets should also be suitable for the combustion of this syngas (see Table 2: Composition and properties of different gaseous fuels for hydrogen production).

[0024] [Tables2] Fuel H2 LE CO CO2 CH4 N2 hydrocarbons / goud ron LHV Wobbe index [%] [%] [%] [%] [%] [%] [MJ / Nm3] [MJ / Nm3] Biological synthesis gas * 6 0 0 9 11 Synthesis gas # 16 17 13 5 49 0 5 5.5 Natural gas (GN)$ 0 0 2 85 9 4 33 41 NH3 - - - - - - 14 18 NH3 pre-cracked fuel SMR (effluent gas eux + combus tible GN) 45 2 44 10 0 0 8.6 10

[0025] In the case of low temperature gasification technologies, for example from a fixed bed or a fluidized bed, significant amounts of hydrocarbons such as CH4, C2-C4 hydrocarbons, as well as tar components, which are usually problematic for downstream synthesis, are actually beneficial since they provide additional calorific value. This reduces the amount of fuel gas required for the combustion chamber and allows for no limitation of downstream flue gas equipment. As shown in Table 2, typical calorific values are normally lower than those of natural gas, but can be higher than those of NH3 or cracked NH3. Since hydrogen is always present in sufficient quantities in the PSA / H2 purification unit, the combustion must be smooth and NOx and particulate levels must be low.

[0026] Another symbiotic aspect is that the synthesis gas can be obtained at high temperatures, typically 200-400°C. This saves the energy required for preheating the fuel and ensures that there is no condensation of heavy hydrocarbons, such as tars. Compared to NH3 combustion, significantly lower NOx contents are expected, which should be similar to those of a standard SMR.

[0027] For an economical process, waste, e.g. forest residues, residues from wood processing or alternative biogenic solid fuels such as RTFs, can be targeted, as they can be considered as waste and, due to their biogenic content, their carbon footprint is significantly reduced and close to zero. This is different for NH3, whose carbon footprint is always related to its production (either from renewable energy (PV / wind / hydro) or from natural gas with CCS), as well as its transportation to the target sites. In both cases, it can be assumed that the carbon footprint of waste-based syngas is lower than that of natural gas combustion or imported NH3.

[0028] Another advantage concerns fuel costs: compared to natural gas at €50 / MWh, biomass is the cheapest fuel (~€20 / MWh for a wood price of €100 / t). Similarly, compared to NH3, biomass is significantly cheaper (~€76 / MWh for NH3 at €400 / t). If the CAPEX of biomass gasification is not too high, biomass has the potential to produce a fuel gas at competitive costs.

[0029] A plant that uses gasified biomass as fuel could still operate with other gaseous fuels such as natural gas, hydrogen or ammonia. This results in great flexibility. Depending on market conditions, it is possible to choose the cheapest fuel without modifying the plant equipment.

[0030] If waste or other feedstocks containing significant amounts of critical trace components such as chlorine, sulfur, phosphorus, or metals are used, an additional gas cleaning step can be added to remove these components from the syngas before combustion. These components are barely present in biomass and wood, but are highly present in syngas containing plastics (see Table 3 Trace Components in Potential Feedstocks).

[0031] [Tables3] Raw materials S [mass-%] N [mass-%] Cl [mass-%] softwood 0.005 0.05 0.03 hardwood wood waste 0.03-0.1 2-3 0.01-0.2 bark 0.05 0.6 0.15 sewage sludge 1 4 0.05 FTR / (plastic / wood mixture) 0.1 0.4 0.6 plastic waste 0.3 0.9 2

[0032] These components originate from certain polymer fractions (e.g., PVC resulting in the formation of chlorine / HCl, rubber containing sulfur) or from additives and dyes which can lead to significant amounts of these contaminants in the syngas. It is recommended to remove them before combustion, in order to avoid the formation of hazardous components in the flue gases, e.g., HCl, dioxins, SO / SO2, etc.

[0033] For this disposal, suitable technologies are available on the market. Non-limiting examples include scrubbing (for HCl) or absorption (e.g., on zinc oxide) technologies. As a general rule, it is preferable to carry out these operations at low temperatures, which involves an additional cooling step, which results in a decrease in the thermal efficiency of the installations. Therefore, wood, wood waste, forest residues and even agricultural residues are the preferred fuels to enable simple treatment schemes.

[0034] Both installations described are based on the combustion of a fuel with a residual heat recovery system. Generally, the flue gases are fed to the chimney at a temperature between 100 and 200 °C. This corresponds to a loss of energy, because this temperature level does not allow for cost-effective heat recovery. This corresponds to a loss of energy, because this low temperature level does not allow for cost-effective heat recovery. Biomass contains significant amounts of water. To increase the efficiency of the process, it would be useful to dry it before introducing it into the gasifier. The temperature of the flue gases is still high enough to promote drying of the biomass. However, special precautions should be taken to avoid condensation in the flue gases.It is also possible to use any other hot stream on the process side, on the flue gas side or in the gasification section. Such thermal integration is beneficial to both. respects: it reduces the water content of the gasified fuel and allows the residual heat of the combustion gases to be used to a greater extent. This integration could also be totally or partially indirect by using the steam from the co-product as an energy vector to dry the biomass.

[0035] [Fig.l] shows a first example of using an SMR scheme. A biomass feedstock 2 is sent to a dryer 5 in order to reduce the moisture content of the biomass feedstock 2 to produce a dry feedstock 6. This dry raw material 6 is then sent to the gasification unit 10, which is configured to convert the biomass into a combustible gas mixture 12. This gasification may be based on one of the existing and proven gasification technologies, for example double fluidized bed steam gasification, fluidized bed gasification, entrained flow gasification, fixed or moving bed gasification, using one or more oxidants, for example air, oxygen and / or steam.

[0036] The fuel gas mixture 12 may be cleaned (not shown in the diagram) to remove particulates and other trace components if necessary (mainly for waste raw materials). Then, the fuel gas mixture 12 is mixed, hot or cold, with the PSA off-gas 54 from the SMR process, to obtain a second fuel gas mixture 14, which is redirected to the SMR combustion chamber 20. The second fuel gas mixture 14 may be preheated before entering the furnace.

[0037] The second fuel gas mixture 14 is then combusted with the preheated air 18. In the heated hearth of the SMR, the process steps remain unchanged compared to a conventional SMR, namely The purified and preheated natural gas 16 is mixed with steam 36, injected into the tubes of the SMR 20, converted by means of a suitable catalyst, cooled by means of indirect water cooling 30, converted again at lower temperatures with steam in a water gas displacement reactor 40, cooled and, after condensation of the water, the synthesis gas mixture 42 is sent to a pressure swing adsorption system 50 for H2 purification, thus producing a hydrogen stream 52.

[0038] The PSA waste gas 54 is returned to be combusted with the biological syngas 12 from the biomass gasification. The flue gas 24 is cooled in the waste heat recovery section 25 and used to preheat various process streams, before its low temperature heat (100-200°C) is used to dry the raw material 2 in the raw material drying step 5 via line 26. The wet flue gases 8 are discharged from the dryer 5. Export steam 38 may also be produced during the process.

[0039] Depending on the gasification technology and the properties of the syngas (temperature, impurities, etc.), different treatment schemes can be used. These can include, among others, direct mixing with the PSA off-gas to cool the syngas, pre-cooling and condensation of the syngas before mixing, cooling and scrubbing of the syngas before mixing with the off-gas, oxygen enrichment of the combustion air or use of oxygen instead of combustion air, flue gas recycling to control or concentrate CO2, additional compression of the syngas, etc. The concept can be applied to new and existing SMR plants (retrofit option). These concepts can be combined with carbon capture technologies on the flue gas stream to generate negative carbon emissions.

[0040] [Fig. 2] shows an example of using an NH3 cracking scheme. A biomass feedstock 2 is sent to a dryer 5 to reduce the moisture content of the biomass feedstock 2 to produce a dry feedstock 6. This dry feedstock 6 is then sent to the gasification unit 10 which is configured to convert the biomass into a combustible gas mixture 12. This gasification may be based on one of the existing and proven gasification technologies, for example double fluidized bed steam gasification, fluidized bed gasification, entrained flow gasification, fixed or moving bed gasification, using one or more oxidants, for example air, oxygen and / or steam.

[0041] The fuel gas mixture 12 may be cleaned (not shown in the diagram) to remove particulates and other trace components if necessary (mainly for waste raw materials). Then, the fuel gas mixture 12 is mixed hot or cold with the off-gases 55 from the NH3 cracking process and optionally with NH3 recycle 45 from the NH3 removal unit 41 to provide a second fuel gas mixture 14, which is redirected to the hearth of the NH3 cracker 21, where it may be preheated and is then combusted with preheated air 18.

[0042] In the heated NH3 cracking hearth, the process steps remain unchanged compared to a conventional NH3 cracker, i.e. The vaporized and preheated NH3 feed 17 is injected into the NH3 cracking tubes of the ammonia cracker 21, converted by means of a suitable catalyst into an H2-rich synthesis gas mixture, cooled in the cooling section 31 and first sent to an NH3 removal unit 41, in which the unconverted NH3 is removed from the hydrogen-rich stream and can be recycled into the fuel system. Alternatively, the recovered unconverted NH3 can be recycled and used as fuel 45 or as feed NH3 (not shown). The H2-rich gas 43 is then sent to a pressure swing adsorption device 51 or other H2 purification process, thereby producing a hydrogen stream 52.

[0043] The residual gaseous effluents 55 are returned to be mixed with the biogas 12 from the gasification of the biomass 10 and, optionally, with the NH3 45 from the NH3 removal unit 4L. The flue gases 24 are cooled in the wastewater treatment unit 25 and used to preheat various process streams, before their low temperature heat (100 - 200 °C) is used to dry the raw material 2 in the raw material drying step 5, via line 26.

[0044] Depending on the gasification technology and the properties of the syngas (temperature, impurities, etc.), different treatment schemes can be used. These may include, among others, direct mixing with the PSA off-gas to cool the syngas, pre-cooling and condensation of the syngas before mixing, cooling and scrubbing of the syngas before mixing with the off-gas, oxygen enrichment of the combustion air or use of oxygen instead of combustion air, flue gas recycling to control or concentrate CO2, additional compression of the syngas, etc. These concepts can be combined with carbon capture technologies on the flue gas stream to generate negative carbon emissions.Table 4 presents the preliminary material balance of several H2 production processes with biological syngas as fuel.

[0045] [Tables4 SMR SMR SMR NH3 cracker NH3 cracker NH3 cracker Capacity in h2 [Nm3 / h] 10 000 50 000 100 000 10 000 50 000 100 000 Fuel requirements [MW] 2 10 21 3 14 28 Biom ass consumption [t / h] 0.6 3.0 5.9 0.8 4.0 8.0 CO2 emissions 0.4 2 4 - - - saved s * [t / h]

Claims

[Claim 1] Claims Apparatus for producing hydrogen in a steam methane reformer with reduced carbon emissions, the apparatus comprising: a dryer (5) configured to remove moisture from a biomass (2) to produce a dry biomass (6); a gasification unit (10) in fluid communication with the dryer (5), the gasification unit (10) being configured to receive the dry biomass (6) and gasify the dry biomass (6) to produce a combustible gas mixture (12); a steam methane reformer (20) in fluid communication with the gasification unit (10), wherein the steam methane reformer (20) is configured to catalytically crack methane to produce a reformed stream (22) by burning the fuel gas mixture (12) to provide the heat necessary to crack the methane, wherein the reformed stream (22) comprises hydrogen, carbon monoxide and unreacted methane; a conversion unit (40) in fluid communication with the steam methane reformer (20), wherein the conversion unit (40) is configured to receive the reformed stream (22) in the presence of steam, perform a water gas reaction, and produce a shift gas stream (42) comprising hydrogen and carbon dioxide; and a hydrogen purification unit (50) configured to receive the shift gas stream (42) and purify the shift gas stream (42) to produce a hydrogen product stream (52) and a waste gas; wherein a combustion gas (24) is produced by the combustion of the combustible gas mixture (12).

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