Method and apparatus for integrated ammonia cracking in steam methane reformer

Abstract

A method and apparatus for retrofitting an existing steam methane reformer (SMR) for ammonia cracking is provided. In this embodiment, the existing SMR may include a pre-reformer, a desulfurization unit, a furnace (50) having a plurality of SMR tubes and a plurality of combustors, a waste heat recovery section, a water gas shift reactor, a pressure swing adsorption (PSA) unit. In some embodiments, the method may comprise the steps of: providing the existing SMR; offline the desulfurization unit such that no fluid flows through the desulfurization unit during operation; offline the pre-reformer such that no fluid flows through the pre-reformer during operation; and an addition device for providing a gaseous ammonia stream to the SMR tubes.

Description

TECHNICAL FIELD

[0001] The present invention relates to an apparatus and method for producing hydrogen using existing industrial units. More specifically, embodiments of the present invention relate to avoiding steel embrittlement caused by nitrides, particularly in existing steam methane reformers that are retrofitted to produce hydrogen from ammonia feed. BACKGROUND

[0002] In order to reduce the impact of carbon dioxide emissions, new energy carriers are becoming increasingly important. Hydrogen is one of the main energy carriers; however, due to the small molecular size of elemental hydrogen, the high pressure requirements and the very low boiling point, its transportation is difficult and expensive.

[0003] Ammonia (NH3) has attracted some interest in the literature as it can be stored and transported using existing infrastructure (e.g. LPG infrastructure). Therefore, hydrogen production using ammonia instead of natural gas to produce elemental hydrogen is projected as the future of the next generation of hydrogen production. Unfortunately, the construction of new industrial facilities is quite costly and takes many years to design and produce. Therefore, any new dedicated ammonia cracking facility can take at least ten years or more before it can be put into operation. During this time, there is still a desire to produce hydrogen in a more environmentally sensitive manner, which includes cracking ammonia by using existing hydrogen production facilities.

[0004] Ammonia can be cracked into hydrogen and nitrogen at ambient pressure and moderate temperatures (450°C - 600°C) in the presence of a catalyst. In order to save hydrogen compression energy at the back end, it can be advantageous to apply higher pressure to the NH3 cracking reaction (due to the small molecular size of hydrogen, it is easier to compress ammonia compared to hydrogen). However, at higher pressures, the cracking reaction is not favorable according to Le Chatelier's principle, so higher temperatures are advantageous (about 700°C) in order to achieve an economic conversion rate.

[0005] Unfortunately, it is known that ammonia causes the formation of nitrides in steel during the process of cracking NH3 into H2 and N2, particularly at elevated temperatures. This is because the ammonia cracking reaction at elevated temperatures will result in the formation of atomic nitrogen that diffuses into the metallic material to form nitrides, thus causing steel embrittlement.

[0006] Since some steels also act as catalysts for the NH3 cracking process, the nitride formation of the steel can occur at its surface and at temperatures where only small ammonia conversion rates are observed. This means that the steel can already be at risk of embrittlement during the heating of ammonia to temperatures above 400°C.

[0007] Currently, steam methane reformers are operated at temperatures well above 700°C using hydrocarbon feedstocks such as natural gas, LPG, naphtha, refinery off-gases, etc. Figure 1A typical SMR process flow diagram is shown. Natural gas 2 at about 30°C and recycled hydrogen 4 are mixed and warmed in heat exchanger 10 to a temperature of about 360°C to form a hot feed stream 12. Hot feed stream 12 is then introduced into a sulfur removal unit 20 to remove sulfur from hot feed stream 12 to form a clean hot feed stream 22 having a significantly reduced amount of sulfur compared to hot feed stream 12. Clean hot feed stream 22 is then mixed with process steam 24 and heated in an SMR heat recovery section 30 before being introduced into a pre-reformer 40 in order to convert heavier hydrocarbons into methane and carbon oxides (CO, CO2) at a relatively low temperature (typically 400°C to 550°C). The lower temperature of the pre-reformer 40 is used to prevent coke from depositing on the walls and catalyst surface of reformer 50.

[0008] The pre-reformer partially completes the steam reforming reaction upstream of the main steam reformer using a highly active catalyst at much lower temperatures. In addition to reducing coke formation, the use of a pre-reformer advantageously allows the conventional steam reformer, which is the most expensive capital item in the plant, to be made smaller.

[0009] The pre-reformed stream 42 is then heated in SMR heat recovery section 30 using the heat from the flue gas of the primary SMR reaction before being introduced into the reforming tubes of SMR furnace 50. After heating, it is sent to steam methane reformer 50 for reforming to produce a raw syngas stream 52. Since the reforming reaction is endothermic, heat is added to the reaction by burning fuel in a burner. The resulting raw syngas stream 52 is then fed to a high temperature water gas shift reactor 60 where CO reacts with H2O to convert CO to CO2 and produce additional hydrogen. The resulting hot shift stream 62 is then introduced into natural gas preheater 10 in order to provide preheating of natural gas 2 earlier, producing a warm shift stream 64 which, in this embodiment, can have a temperature of about 322°C.

[0010] At the same time, boiler feed water 72 is drawn from a boiler feed water preparation system 70, pressurized by pump 80 in order to increase the boiler feed water pressure of a downstream steam generation system (not shown). The pressurized boiler feed water stream 82 at about 106°C and 60 bar gauge is then heated in a third heat exchanger 90 using the heat from warm shift stream 64 in order to produce a hot boiler feed water stream 92 at about 221°C and a cooler shift gas stream 94. Hot boiler feed water stream 92 can be used to generate steam in the downstream steam generation system (not shown).

[0011] Although natural gas typically contains nitrogen, this molecular nitrogen does not cause the formation of critical nitrides in steel. Therefore, existing SMRs do not take this into account when they are designed.

[0012] The current materials of application in the feed pre-treatment and pre-heat section of the SMR plant are carbon steel (CS), CrMo and stainless steel (SS). In short, all the materials of application contain alloying elements such as iron and chromium that can easily form nitrides. In addition, most of the process equipment in the synthesis gas generation unit operates at much higher than 400°C. Therefore, for existing hydrogen production facilities, it is not feasible to simply convert the feedstock from hydrocarbons to ammonia.

[0013] Considering the above temperature limits, process simulation of the ammonia cracking reaction in the proposed pressure range has shown that the conversion of ammonia will be in the range of 90% to 99.8%. The unconverted ammonia content will be in the range of 0.1 to 5.0 mol%, which is below the threshold to damage downstream equipment.

[0014] While the downstream equipment is less likely to be affected by these drawbacks, the equipment upstream of the SMR furnace can be affected due to the feed stream being close to 100% ammonia.

[0015] Therefore, there is a need in the art to provide an industrial facility that can efficiently produce hydrogen from ammonia, in particular by retrofitting an existing hydrogen production industrial facility to produce hydrogen from an ammonia feed gas, while preventing or at least minimizing the embrittlement issues during operation. SUMMARY

[0016] The present invention relates to an apparatus and a method that meet at least one of these needs. In certain embodiments of the invention, a method for producing hydrogen via ammonia cracking in an existing steam methane reformer (SMR) is provided. The SMR can include a furnace and a pressure swing adsorption (PSA) unit, wherein the furnace has a plurality of SMR tubes and a plurality of burners. The method for producing hydrogen can include the steps of: providing a gaseous stream consisting essentially of ammonia at a selected minimum temperature; introducing the gaseous stream into the SMR tubes of the furnace under conditions effective to catalytically crack the ammonia, thereby forming a crude stream comprising hydrogen, nitrogen and unreacted ammonia; and introducing the crude stream into the PSA unit to produce a hydrogen product stream and a PSA tail gas.

[0017] In certain embodiments, the minimum temperature is a function of the pressure. The ammonia temperature can be such that the ammonia is in the gaseous state (preferably with a 20°C margin) to avoid condensation at cold spots. The higher the pressure, the higher the temperature. In certain embodiments, 100°C can be a good low choice as it involves about 65 bara. While ammonia cracking can be designed up to or even above this pressure, it is typically at a lower pressure of about 55 bara, which means that 100°C is a safe minimum temperature for most applications.

[0018] In alternative embodiments of the method for producing hydrogen: • the existing SMR is retrofitted to further include an ammonia storage vessel and an ammonia feed pump; • Step (a) further comprises withdrawing ammonia from an ammonia storage vessel; pumping ammonia in an ammonia feed pump to a pressure of 25-60 bar (gauge pressure); and then vaporizing the ammonia to provide a gaseous stream; • retrofitting an existing SMR to further comprise an ammonia vaporizer, wherein ammonia is vaporized in the ammonia vaporizer to form a gaseous stream, wherein the gaseous stream in step (a) is connected into a feed conduit or feed distribution system of the existing SMR, wherein the feed conduit and feed distribution system are upstream of the SMR tubes; • retrofitting an existing SMR to further comprise a new device selected from the group consisting of an ammonia vaporizer, an ammonia exchanger, an ammonia preheater, an ammonia pre-reactor, and combinations thereof, wherein the new device is disposed upstream of the SMR tubes and downstream of the ammonia feed pump; • the existing SMR comprises an existing feed superheat section upstream of the SMR tubes, wherein ammonia is vaporized in the existing feed superheat section; • the ammonia is vaporized using heat provided by electricity, steam, a crude stream, and / or a flue gas stream; • the ammonia is vaporized and preheated to less than 450°C, preferably less than 350°C, more preferably less than 300°C; • the crude stream contains less than 5.0 mol% unreacted ammonia • the conditions effective to catalytically crack ammonia include a pressure between 15-80 bar, preferably 20-60 bar, and a temperature between 600°C-850°C, preferably 650°C-750°C; and / or • the gaseous stream in step (a) is provided by a pressurized gaseous ammonia feed received from outside the existing SMR.

[0019] In another embodiment, a method for retrofitting an existing steam methane reformer (SMR) for ammonia cracking is provided. In this embodiment, the existing SMR can include a pre-reformer, a sulfur removal unit, a furnace, a waste heat recovery section, a water gas shift reactor, a pressure swing adsorption (PSA) unit, wherein the furnace has a plurality of SMR tubes and a plurality of burners. In certain embodiments, the method can include the steps of: providing an existing SMR; taking the sulfur removal unit offline such that no fluid flows through the sulfur removal during operation; taking the pre-reformer offline such that no fluid flows through the pre-reformer during operation; and an addition device for providing a gaseous ammonia stream to the SMR tubes.

[0020] In optional embodiments of the method for retrofitting an existing SMR: • the device for providing a gaseous ammonia stream comprises an ammonia storage vessel, an ammonia feed pump, and a device for vaporizing ammonia sourced from the ammonia storage vessel; • the apparatus for vaporizing ammonia further comprises a new equipment selected from the group consisting of an ammonia vaporizer, an ammonia exchanger, an ammonia preheater, an ammonia pre-reactor, and combinations thereof, wherein the new equipment is disposed upstream of the SMR tubes and downstream of the ammonia feed pump; • the apparatus for vaporizing ammonia further comprises an existing feed superheat section located upstream of the SMR tubes, wherein the existing feed superheat section is retrofitted by treating the inner surface of the existing feed superheat section to improve nitrogenization resistance; and / or • the step of treating the inner surface of the existing feed superheat section comprises a process selected from the group consisting of: (1) applying a protective liner material mechanically coupled to the inner surface, (2) applying an aluminized layer to the inner surface, and (3) applying a diffusion barrier layer used in conjunction with the aluminized layer, wherein the diffusion barrier layer is disposed between the inner surface and the aluminized layer.

[0021] In another embodiment, an apparatus for producing hydrogen via ammonia cracking using a retrofitted steam methane reformer (SMR) is provided. The apparatus can include: means for providing a pressurized and gaseous ammonia stream to a plurality of reactor tubes; a furnace having the plurality of reactor tubes and a plurality of burners, wherein the furnace is configured to catalytically crack ammonia within the reactor tubes to produce a raw process gas and a flue gas; a plurality of waste heat recovery sections; and a pressure swing adsorption (PSA) unit disposed downstream of the furnace, wherein the PSA unit is configured to receive the raw process gas or a gas derived therefrom and produce a hydrogen product stream and a PSA tail gas.

[0022] In optional embodiments of the apparatus: • the means for providing a pressurized and gaseous ammonia stream to a plurality of reactor tubes comprises an ammonia storage vessel and an ammonia pump; • the means for providing a pressurized and gaseous ammonia stream to a plurality of reactor tubes further comprises an ammonia vaporizer, wherein ammonia is vaporized in the ammonia vaporizer to form the pressurized and gaseous ammonia stream, wherein the pressurized and gaseous ammonia stream is connected into a feed piping and / or a feed distribution system of an existing SMR, wherein the feed piping and / or the feed distribution system is immediately upstream of the SMR tubes; • the means for providing a pressurized and gaseous ammonia stream to a plurality of reactor tubes further comprises a new equipment selected from the group consisting of an ammonia vaporizer, an ammonia exchanger, an ammonia preheater, an ammonia pre-reactor, and combinations thereof, wherein the new equipment is disposed upstream of the SMR tubes and downstream of the ammonia feed pump; • the ammonia vaporizer is heated using electricity, steam, a raw stream, and / or a flue gas stream; • the ammonia vaporizer is configured to vaporize and preheat ammonia at a temperature below 450 °C, preferably below 350 °C, more preferably below 300 °C; • the apparatus further comprises a waste heat recovery section, wherein the means for providing a pressurized and gaseous ammonia stream to a plurality of reactor tubes further comprises heating pressurized ammonia from the ammonia pump in the waste heat recovery section to form the pressurized and gaseous ammonia stream; • the furnace is configured to operate at a pressure between 15-80 bar, preferably 20-60 bar, more preferably 20-35 bar, and at a temperature between 600°C-850°C, preferably 650°C-750°C; • the means for providing a pressurized and gaseous ammonia stream to the plurality of reactor tubes comprises a pipe having a nitriding resistant material (alloy 600 or 625 series, Ni-based metal or Ni content higher than 30%) or a nitriding protective layer on the inner surface of the pipe; • the nitriding protective layer is selected from the group consisting of a protective liner material mechanically coupled to the inner surface, an aluminized layer applied to the inner surface, a diffusion barrier layer used in combination with the aluminized layer applied to the inner surface, wherein the diffusion barrier layer is disposed between the inner surface and the aluminized layer, and a cladding layer applied to the inner surface; and / or • the plurality of catalyst tubes comprises a nitriding protective layer on the inner surface of the reactor tubes. BRIEF DESCRIPTION OF DRAWINGS

[0023] These and other features, aspects, and advantages of the present application will become better understood with reference to the following description, appended claims, and accompanying drawings. It should be noted, however, that the drawings are merely meant to illustrate several embodiments of the present application and therefore should not be considered as limiting the scope of the present application as the present application can allow for other equally effective embodiments.

[0024] Figure 1 An embodiment of a steam methane reformer facility according to the prior art is provided.

[0025] Figure 2 A simplified schematic of the overall scheme for catalytic cracking of ammonia to produce hydrogen according to an embodiment of the present application is provided.

[0026] Figure 3 An embodiment of the present application is provided.

[0027] Figure 4 A layout of the equipment of an embodiment of the present application is provided.

[0028] Figure 5 Another embodiment of the present application is provided.

[0029] Figure 6 Another embodiment of the present application is provided.

[0030] Figure 7 Another embodiment of the present application is provided.

[0031] Figure 8 Another embodiment of the present application is provided.

[0032] Figure 9 Another embodiment of the present application is provided.

[0033] Figure 10 Another embodiment of the application is provided. DETAILED DESCRIPTION

[0034] While the application will be described in conjunction with several embodiments, it will be understood that it is not intended to limit the application to those embodiments. On the contrary, it is intended to cover all alternatives, modifications, and equivalents that can be included within the spirit and scope of the application as defined by the appended claims.

[0035] Of course, it will be appreciated that in the course of implementing any such actual embodiments, numerous implementation-specific decisions must be made to achieve the developer's specific goals, such as compliance with system-related and business-related constraints, which will vary from one implementation to another. Moreover, such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking of design and fabrication for those of ordinary skill in the art having the benefit of this disclosure.

[0036] While decarbonization of NG-based H2 production is neither simple nor straightforward for the reasons outlined above, it is preferred to operate in a fully decarbonized case based on existing equipment with ammonia replacing fossil feedstocks. Ammonia itself can be produced from a variety of sources and it can be easily transported to all parts of the world by ship, pipeline or truck. It contains no carbon atoms. Therefore, its use within an SMR results in the inherent fully decarbonized nature of the process. However, replacing methane with NH3 is not straightforward and the process needs to be modified in order to operate safely and reliably. The use of NH3 has several significant advantages compared to an NG-based SMR and a new NH3 cracker: • The plant is fully or partially CO2emissions free. • No additional CCS infrastructure is required at the hydrogen use site, such as CC units, steam supply, CO2storage, CO2pipelines, storage tanks, CO2ships, sequestration sites, etc. • No additional legislation is required as NH3 is already traded globally and therefore its production and transportation are well known. • Existing SMR assets can be utilized, saving investment costs compared to new greenfield plants and allowing for faster deployment. • In existing catchments, existing infrastructure and connections to customers can be used. • In emerging markets, H2 is typically used for new applications that usually do not require steam. If NH3 is used in an SMR, the production of steam as a byproduct is reduced due to the lower heat duty required for the NH3 cracking reaction. This is beneficial and increases the overall efficiency of the plant compared to plants that are tailored for high steam output. • The operating envelope of the plant is wider due to mitigation of typical challenges in SMR, i.e. coking and metal dust corrosion.

[0037] In principle, methane and NH3 have some similarities and some differences. Ammonia can be decomposed into N2 and H2 in an endothermic reaction (see reaction below). This is equally true for methane. However, here the cracking products are carbon and H2. The production of solid C poses challenges (plugging, fouling, solid handling). Therefore, methane is usually converted in a reforming reaction, i.e. including water as reagent in order to suppress carbon formation. In this respect, NH3 cracking is much easier and does not require the addition of steam. NH3 decomposition (1) SMR reaction (2) SMR + water gas shift reaction (3)

[0038] In the improved SMR process with 100% NH3 feed, some process sections are no longer required, e.g. desulfurization, pre-reformer, water gas shift section and condensation system (see scheme).

[0039] This leads to reduced OPEX and higher reliability, as the respective catalyst containing vessels can be bypassed and thus do not require regular monitoring or catalyst replacement. This can also reduce the overall pressure drop within the system.

[0040] On the other hand, the process can include some additional units for NH3 handling. Some non-limiting examples can include NH3 storage, feed supply (pump + vaporizer) and optionally an additional water wash downstream of the reactor.

[0041] The ammonia cracking reaction requires much less heat per hydrogen molecule compared to the steam methane reforming reaction. For the case of 100% ammonia as feedstock, no process steam is required, as carbon formation of hydrocarbons at too high temperatures or heat fluxes or due to lack of process steam is no longer an issue. This further reduces the required process heat or alternatively allows for more ammonia to be converted to hydrogen and increase the hydrogen output of the existing units.

[0042] In a standard steam reforming process, the addition of process steam provides significant waste heat on the process side and on the combustion side, both leading to a reduced thermal efficiency of the plant. Process steam is cooled and condensed in the synthesis gas cooling system preheating feedstock and other process streams.

[0043] With 100% ammonia feedstock, it is desirable to eliminate and minimize process steam to maximize thermal efficiency, and thus maximize the hydrogen product to ammonia feed ratio. As a result, much less waste heat is available on the process side of the unit, which is insufficient to preheat and vaporize the ammonia feedstock.

[0044] At the same time, less combustion heat is required to crack the ammonia, and thus less waste heat is contained in the flue gas and is only available at lower temperatures.

[0045] Figure 1 A flow diagram for pure NH3-based H2 production is shown in FIG. 1. Ammonia is stored in a suitable storage vessel 1, preferably as a refrigerated fluid at -33°C and ambient pressure or at elevated pressure and ambient temperature. The liquid NH3 feed is brought into the SMR system against the system pressure (5-40 bar) by means of a liquid pump 3, where it bypasses potential existing feed pre-treatment units 20, 40 (hydrogenation, H2S adsorption, pre-reforming), is preheated in a NH3 preheat section 10, 30, where it is evaporated and heated to suitable inlet conditions of 300°C-650°C. If the heat value of the off-gas from the PSA is insufficient to heat the reaction, a portion of the NH3 stream can be used as fuel 45 in the SMR furnace 50. In addition, a portion of the H2 or syngas stream can also be used as fuel in order to eliminate the bottleneck of existing heat exchangers. The preheating can be done using the hot streams within the waste heat recovery section 10, 30, 90. For example, flue gas 54 can provide the thermal energy for the waste heat recovery section 30. Although this feature is not shown in order not to further complicate the drawing, the present invention should not be limited to what is explicitly shown in the drawing.

[0046] The preheated NH3 feed 43 is directed into the SMR reactor 50, i.e. a setup with multiple tube reactors located within a heating furnace. The tubes can be filled with a standard reforming catalyst, e.g. based on Ni on AI2O3. In certain embodiments, the catalyst can be replaced by a more active catalyst system, especially for the purpose of eliminating the bottleneck. Within the SMR tubes, the NH3 feed is converted to a product mixture at temperatures of 500°C-900°C. The gas mixture 53 contains N2 and H2 as well as traces of unconverted NH3 (e.g. up to about 5 vol%). The heat required for this reaction is provided indirectly by the combustion in the combustion chamber through the SMR tube walls. The hot gas mixture 53 is cooled by water evaporation in a continuous heat exchanger 10 and within a process gas boiler 90. This results in steam as a by-product. The steam production can be adjusted by adjusting the load of the SMR combustion chamber. For this purpose, it can be necessary to burn additional NH3.

[0047] In the illustrated embodiment, the gas mixture 53 bypasses the existing water gas shift reactor 60 and is cooled in a series of waste heat recovery stages. After cooling, condensate 96 is removed from the cooled gas mixture 95 and the resulting dry gas mixture 101 is sent to a water wash column configured to remove unreacted ammonia gas from the dry gas mixture by using pressurized water 84, preferably sourced from the boiler feed water 70. In one embodiment, the treatment stage 102 can be a dedicated vessel to be added to the existing SMR system.

[0048] In one embodiment, the treatment stage can include a scrubbing column placed in the existing syngas cooling stage between the BFW preheater outlet and the PSA inlet, i.e. below the dew point of the process gas 101, preferably between the final cooler and the PSA inlet. High pressure boiler feed water 84 from the existing unit 70 will preferably be used for water dosing.

[0049] The treatment stage can be designed for inlet ammonia content in the range of 0.2 to 5 mol%. Since ammonia is very soluble in water, the water wash column can be designed and will reduce the remaining ammonia content in the PSA feed to levels below 100 ppm, preferably below 20 ppm, and allow feeding of a hydrogen and nitrogen mixture to the existing PSA.

[0050] The product gas 103 is sent to pressure swing adsorption (PSA) where H2 is purified to typically > 99.5% purity. The residual gas stream (tail gas) contains H2, N2 and NH3. A scrubbing column effluent stream 104 is drawn from the water wash column. In an optional embodiment, at least a portion 88 can be combined with the flue gas 54 of the SMR reactor 50.

[0051] In an embodiment not shown, the tail gas stream from the PSA can be sent to the SMR combustor in order to provide the heat required for the NH3 decomposition reaction. The presence of a mixture of H2 and NH3 as combustible components is beneficial because the fast H2 combustion and the slow NH3 combustion balance each other and allow the use of existing technology combustors. In certain embodiments, at least 14% of H2 is present in the tail gas. It is mentioned in the literature that 7-10% of H2 is already sufficient to allow smooth co-combustion of NH3 and H2. This also allows additional combustion of NH3 fuel without being affected by the slow NH3 combustion.

[0052] In another embodiment not shown, the tail gas can be sent back to the SMR reactor tubes in order to more fully convert any residual ammonia while also recovering additional residual hydrogen.

[0053] As noted in the background section, ammonia (particularly at elevated temperatures) can cause embrittlement issues within the system. Certain embodiments of the present invention seek to minimize these issues by using advantageous connection points to the existing SMR facility, which allow for reduced CAPEX during the retrofit program.

[0054] Figure 3 A simplified schematic of an embodiment of the present invention is provided. Ammonia 22 is drawn from ammonia source 1 and pressurized in ammonia pump 3, preferably to a pressure of (5-40 bar), and then heated in waste heat recovery section 30 to form preheated ammonia 42. As previously noted, a feed header 47 is used to deliver the preheated ammonia to the reactor tubes of the SMR to distribute the ammonia gas 42 to all of the associated reactor tubes. Those of ordinary skill in the art will also recognize that a second header can also be used to distribute the preheated ammonia 42 to multiple burners within the SMR. This feature is not shown in order not to burden the figure.

[0055] In certain embodiments, the feed header is located directly above the plurality of tubes, preferably within 10 meters.

[0056] Following catalytic conversion of the ammonia, the resulting mixed gas 53 is collected from the reactor tubes and then sent out for further processing. Figure 2 Non-limiting examples of further processing are provided.

[0057] Flue gas 54 (i.e., the combustion products) can be redirected from the combustion chamber to the waste heat recovery section 30 (i.e., a series of heat exchangers) where the heat is used to preheat and superheat various streams (e.g., combustion air, fuel, and feed). Untreated flue gas, which can contain NOx, can optionally be sent to flue gas treatment section 5 to form treated flue gas. In certain embodiments, treatment section 5 can include a DeNOx unit and / or a selective catalytic reformer (SCR). Ammonia 99 can be used in both the DeNOx unit and the SCR.

[0058] Lines 25 and 35 represent suitable connection points in accordance with certain embodiments of the present invention. Both connection points 25, 35 allow for bypassing most of the existing units (e.g., desulfurizer 20, pre-reformer 40), which thus greatly reduces potential embrittlement issues.

[0059] The first connection point 25 can be upstream of the first superheater coil or the second superheater coil as part of the waste heat recovery section 30. The second connection point 35 can be at or just upstream of the feed cross header 47. By using either of these connection points, little piping or equipment needs to be retrofitted using appropriate surface treatment.

[0060] In further embodiments, the pressure and temperature in the reactor tubes can be selected such that the ammonia content in the mixed gas 53 downstream of the reactor tubes is less than 2.5 mol%, which greatly reduces the risk of nitride formation and embrittlement problems in downstream equipment. Suitable pressures can be 15-40 bar (absolute), preferably 20-35 bar (absolute), while suitable temperatures can be 600°C-850°C, preferably 650°C-750°C.

[0061] In view of the above, in certain embodiments of the application, in order to retrofit an existing SMR, additional equipment can be included, such as an ammonia holdup vessel or tank and an ammonia feed pump. This is especially true in cases where the ammonia feed can be provided at sufficient pressure and in vaporized form. In cases where connection point 35 is used, it is preferred to heat the ammonia stream at a point between the ammonia pump and the feed header 47.

[0062] Figure 4 A schematic of the additional equipment that can be included in a retrofitted SMR facility is provided. This embodiment can include an ammonia holdup vessel 710, an ammonia feed pump 3, an ammonia preheater 715, an ammonia exchanger 725, an ammonia vaporizer 730, and a pre-reactor 740.

[0063] The ammonia vaporizer 730 and preheater 715 can be electrically heated, steam heated, or heated by process streams downstream of the existing process gas boilers, or by flue gas streams downstream of the existing flue gas boilers. The temperature of the heating medium used for the preheating / vaporization step can be less than 400°C, preferably less than 300°C. The ammonia exchanger 730 and / or pre-reactor 740 can be arranged as shown. Figure 4

[0064] In the embodiment shown, a first portion of liquid ammonia 702 is introduced into the ammonia holdup vessel 710 and then sent to the DeNox unit via line 714. A second portion of liquid ammonia 704 is compressed in the ammonia feed pump 3. After compression, the compressed liquid ammonia can then be connected into the retrofitted SMR facility via connection point 25 via line 713, or to connection point 35. Since connection point 25 is upstream of the existing heaters, the pressurized liquid ammonia 713 does not separate the heating devices from the ammonia preheater 715, ammonia exchanger 725, or ammonia vaporizer 730.

[0065] In certain embodiments where connection point 35 is desired (e.g., immediately upstream of the SMR tubes), then the compressed liquid ammonia 712 can be heated in the ammonia preheater 715, ammonia exchanger 725, and then vaporized in the ammonia vaporizer 730, and then undergo a pre-reaction conversion in the ammonia pre-reactor 740. The resulting pre-reacted ammonia stream 742 is used to provide pre-heat energy in the ammonia exchanger 725, and then sent to connection point 35 via line 744.

[0066] ​Nonetheless, one of ordinary skill in the art will recognize that in certain embodiments of the present application, none of the above-described equipment is required Figure 4 In particular, if ammonia is pressurized and supplied as a vapor, all of the additional equipment can be omitted, meaning that the pressurization and vaporization process steps occur outside the jurisdiction of the existing unit.

[0067] In certain embodiments, a nitrided protective layer can be applied to certain components of the equipment. The nitrided protective layer can be selected from the group consisting of a protective liner material mechanically coupled to the inner surface, an aluminized layer applied to the inner surface, a diffusion barrier layer used in conjunction with an aluminized layer applied to the inner surface, wherein the diffusion barrier layer is disposed between the inner surface and the aluminized layer, and a cladded layer applied to the inner surface. A more detailed discussion of acceptable nitrided protective layers can be found in co-pending U.S. Application 17 / 896,026, filed August 25, 2022, which is incorporated by reference in its entirety.

[0068] There are several challenges to cracking ammonia in existing SMRs: 1) Ammonia has a lower heat value (18.6 MJ / kg) relative to natural gas (42-55 MJ / kg), which will result in significantly higher fuel and air flow in the furnace at a given load; 2) Existing heat exchangers can not have the required heat exchange surface; 3) As reported in various studies, catalytic NH3 decomposition requires temperatures higher than 500°C (Wang et al., Ammonia as hydrogen carrier for transportation; investigation of the ammonia exhaust gas fuel reforming, page 9908). Therefore, it is desirable to reach this T at the inlet of the reformer / cracker. The transition from steam methane reforming to NH3 cracking requires lower loads and temperatures, and upsets the thermal integration, with the result that it can be challenging to reach this T threshold; 4) At temperatures higher than 600°C, unwanted nitride formation is more prevalent. At high temperatures in the SMR reformer (typically greater than 850°C at the outlet), nitridation can become a major issue; 5) The layout of the existing equipment can not be optimized, which can result in ammonia over-consumption; and 6) The difference between an SMR optimized for H2 and steam production and a NH3 cracking system that can actually run completely without steam.

[0069] The above-described challenges can be overcome by various alternative embodiments of the present application. For example,

[0070] In one embodiment with a cracking T of 800°C, a portion of the H2 production can be used as fuel (H2 make-up) to meet the original design flow in the furnace and flue gas system and to enable better fit with existing heat exchangers (issues 1 and 2).

[0071] However, the H2 make-up alone is not sufficient as it is difficult to reach a T of at least 500°C at the inlet of the cracker. To overcome this issue, an additional heat exchanger(s) can be added. In certain embodiments, a first heat exchanger is installed on the reformed H2 upstream of the PSA to evaporate ammonia using low grade heat (about 140°C) and at the same time use liquid ammonia as a cryogenic cooling medium for the final crude H2 cooling. This low grade heat is traditionally considered as waste heat on the SMR. (issue 3)

[0072] Optionally, a second heat exchanger can be installed on one of the SMR steam systems, either directly downstream of the existing boiler or downstream of the steam superheater. This second heat exchanger allows to optimize the heat integration on the SMR without disturbing the main process, resulting in an overall reduced NH3 consumption (issue 5).

[0073] The use of H2 as the main fuel is more challenging than natural gas combustion, but is overall well understood, partly due to the experience in using PSA tail gas as fuel in the SMR. In contrast to NH3 combustion which is challenging due to its low flame speed, H2 combustion is not as critical in this respect as it burns much faster than natural gas or NH3.

[0074] In another embodiment with a cracking T of 600°C, a similar configuration proves to be advantageous: a limited amount of H2 make-up allows to match the existing heat exchanger setup and to reduce accordingly the load and the space velocity in the NH3 cracker; and the addition of a heat exchanger on the crude H2 upstream of the PSA and a heat exchanger on the steam system allow us to reach the required 500°C cracker inlet T (issue 3) while reducing the ammonia consumption by 5-10% (issue 5).

[0075] In this embodiment, H2 is co-combusted with NH3 (about 50 : 50 by LHV), resulting in a fuel mixture with combustion characteristics that are easier to handle than pure H2 or pure NH3 combustion. In addition, at this lower cracking T, the risk of nitrogen-induced material degradation is significantly reduced (issue 4)

[0076] Finally, as an advantage of these above embodiments, the volumetric flow on the process line is lower than SMR. In case green ammonia is used and existing plants are connected to the H2 pipeline, the green H2 production can be increased to levels beyond what is possible with steam methane reforming, and another SMR on the same pipeline can reduce its production, thereby improving the overall carbon intensity of H2 on the pipeline.

[0077] The reference case for SMR (case la) is described in Figure 5 The process gas 100 is preheated in heat exchanger 150, desulfurized in 151, mixed with steam 103, and then heated to about 650°C in reformer feed preheater 152. The steam methane reforming reaction is carried out in the packed catalyst tubes of reformer 153 at an outlet reforming temperature of 850°C-900°C. The hot synthesis gas is used to evaporate steam in process gas boiler 154 / 169 before being sent to the water gas shift reactor 155. The shifted synthesis gas 107 is used to preheat natural gas in 156 / 150, and subsequently cooled to a temperature of about 110°C in boiler feed water heater 157 / 168. The synthesis gas 109 is then cooled by air coolers and final coolers in heat exchange equipment 158 before being sent to the PSA, from which a stream of H2 with high purity (99.9%) 111 is recovered.

[0078] The PSA tail gas 112, composed of CO2, H2, and unreacted CO and CH4, is sent to the combustor of reformer furnace 162, where it is mixed and combusted with natural gas fuel 113 and hot combustion air 116. Part of the heat generated in the furnace is used for the endothermic reforming reaction in 153. The remaining heat in flue gas 117 is then used in turn to heat the reformer feed in 163 / 152, superheat steam in 164 / 170, heat combustion air in 165 / 161, generate steam in flue gas boiler 166 / 169, and preheat combustion air in 167 / 160.

[0079] In this particular SMR, for simplicity we consider a generic steam system for the process gas and flue gas. Boiler feed water 123 is preheated by the shifted synthesis gas in 168, evaporated by the process gas 105 and flue gas 119 in boiler 169, and superheated by the shifted synthesis gas 108 in 170. The required amount of steam 127 is then mixed with the process natural gas 102, and the remaining steam 126 is exported as a co-product.

[0080] In case lb (as Figure 6In the example shown, NH3 is used as process feedstock 200 and fuel 211. The desulfurizer 151 and water-gas shift reactor 155 are no longer needed and are therefore bypassed. The small amount of steam generated can be used as process steam 225 / 202 to mitigate the risk of corrosion caused by nitriding downstream of the process. For the remainder, the heat exchanger arrangement is similar to that in case 1a.

[0081] H2 production matches the production under the SMR baseline, and steam production is similar to the baseline, except that almost all of the produced steam is output. However, the compatibility with the existing SMR is quite poor (see Table 1). Due to the lower LHV of NH3 as fuel compared to NG, the molar flow rate of NH3 is significantly higher, resulting in a 2.5-fold increase in combustion air flow rate and a 2.4-fold increase in flue gas volume flow rate at the reformer outlet. For heat exchangers E-F1 "Reformer Feed Heater", E-F4 "Hot Air Combustion Heater", E-F5 "Flue Gas Boiler", and E-F6 "Cold Air Combustion Heater", the required heat exchange surface area is more than doubled (Table 1).

[0082] In an alternative embodiment of case 1c, we maintain with Figure 6 The same arrangement was used, but the pyrolysis temperature was lowered to 800°C and the hot combustion air temperature was increased to 480°C in an attempt to reduce the required amount of NH3 as fuel. The increased combustion air temperature resulted in a significant decrease in steam output relative to Case 1b, and the steam output flow rate is now consistent with the baseline case. Compared to Case 1b, the molar flow rate of NH3 fuel, the flue gas volumetric flow rate, and the combustion air mass flow rate are significantly reduced, but remain too high relative to the baseline case. While the required heat exchange surface is now suitable for the E-F5 "flue gas boiler," the E-F1 and E-F6 are still too small, and the fit with the E-F4 becomes worse.

[0083] In case 1d (see Figure 7 We maintain the same setup as in cases 1b and 1c, but now redirect a portion of the H2 product, 326, for use as fuel. Combustion air and flue gas flow rates are now better matched to the SMR baseline. The hot combustion air temperature can now be lowered, resulting in E-F4 better matching the baseline. However, with flue gas temperatures below SMR, E-F3 is now too small, and E-F1 is also too small despite the reduced pyrolyzer inlet T. Figure 7 In this process, a portion of the purified H2 product recovered from the PSA can preferably be fed into the fuel.

[0084] Alternatively, a similar "H2 topping" effect can be obtained by taking a portion of the crude H2 upstream of the PSA, or by retrofitting the PSA to reduce H2 recovery, so that the required amount of H2 for the fuel is contained in the PSA tail gas 310. In Table 1, we provide the molar flow of H2 sent to the fuel (not including the molar flow of H2 already present in the PSA tail gas), corresponding to the setup described in Figure 7 Taking into account the alternative that the H2 contribution to the fuel is provided upstream of the PSA or through the PSA tail gas, we also include in Table 1 the "H2 fuel ratio" η¾, defined as follows: (1)

[0085] In case 1e (see Figure 8 ), we add a new heat exchanger 457 on the crude H2 upstream of the PSA and an additional NH3 heater 450, as the waste heat on the SMR is now considered to be available for the evaporation process NH3. The heat integration is further improved, the steam output is increased, and E-F3 provides a better fit than the base case. The drawback is that E-F1 is still undersized, despite a low cracker inlet T of 400°C. At a cracker inlet T below 500°C, the kinetics of the cracking reaction can be poor in the first section of the reformer tubes, which would then effectively be used as a heat exchanger section rather than a reactor.

[0086] In case 1f (see Figure 9 ), we add another heat exchanger 571 / 552 that uses a portion of the steam production 529 to further evaporate and preheat the NH3 feedstock. The steam output is reduced, but the heat integration is significantly improved. Compared to case 1e, the amount of H2 required as fuel is decreased, and the overall NH3 consumption is reduced. The cracker inlet T has increased above the threshold of 500°C, and the fit with the base case is now satisfactory, as there is no single heat exchanger that is undersized.

[0087] Furthermore, in the case of a desired increase in H2 production capacity beyond the original SMR, the bottleneck of the heat exchangers would be located at E-F1. However, it would be possible to simply increase the load on the new heat exchanger 571 on the steam system to correspondingly reduce the load on E-F1.

[0088] Another similar configuration is described in Figure 10 . On the SMR, the flue gas at the flue (H2S + CO2) Figure 5The steam (122) in the flue gas must be kept above the dew point of the sulfuric acid to avoid corrosion, resulting in the flue gas being discharged at approximately 140°C. With NH3 as both feedstock and fuel, this constraint no longer applies, allowing the installation of heat exchangers 668 / 651 to utilize this low-grade heat in the flue gas to evaporate the NH3 feed. The advantage here is that, although lacking the flexibility offered by heat exchangers on a steam system, the steam output will not be reduced. In this case, assuming similar temperature levels for the crude H2 609 and the flue gas 623, the heat exchangers / NH3 evaporators 658 / 650 and 668 / 651 can be combined into a single unit.

[0089] One of the main uncertainties in using existing SMR to crack NH3 lies in the achievable flue gas temperature at the cracker outlet (the so-called "bridge-wall temperature"), which can affect the overall thermal integration of the process and is primarily dominated by overall heat transfer within the furnace and SMR tubes. Cases 1g and 1h use the same setup as Case 1f, where the bridge-wall temperature varies by -50°C or +50°C, respectively. As shown in Table 1, these variations can be easily compensated for by adjusting a portion of the H2 products used as fuel, and the remaining critical process parameters and required heat exchange surface remain unaffected. Therefore, this H2 fueling setup provides robust control parameters that ensure process parameters remain within acceptable ranges.

[0090] At temperatures above 600°C, the formation of undesirable nitrides is more common. At pyrolysis temperatures of 800°C, nitride formation can become a major problem, requiring costly mitigation measures (e.g., as described above). Furthermore, high pyrolysis temperatures imply higher loads on the reformer / pyrolyzer, and therefore higher total NH3 consumption.

[0091] In case 2b (see Table 2), we copied... Figure 9 The setup utilizes H2 fueling, with additional heat exchangers 558 / 550 on the crude H2 and additional heat exchangers 571 / 552 on the steam system to evaporate and preheat the NH3 feedstock, despite a cracking T of 600°C. Compared to case 1f, a larger amount of NH3 fuel is required, but the desired portion of H2 production fed into the fuel is drastically reduced, resulting in a reduction in overall NH3 consumption. Again, this flexible setup allows for the satisfaction of requirements on process parameters (cracker inlet T > 500°C) and heat exchanger area, despite a significantly lower cracking T relative to SMR. Cases 2c and 2d, where the bridge-wall temperature variations are -50°C and +50°C respectively, again demonstrate that any variation or uncertainty in the bridge-wall temperature can be easily compensated for by the amount of H2 product used as fuel.

[0092] Table 1 : SMR base case, and NH3 cracking case at cracking T > 800°C

[0093] Table 2: SMR base case, and NH3 cracking case at cracking T = 600°C

[0094] As used herein, "immediately upstream of the SMR tubes" is intended to cover the case where the feed distribution system is located directly above the plurality of tubes, or within at most 10 m above based on the tail end length, connecting the distribution system (manifold) with the SMR tubes.

[0095] While the application has been described in connection with specific embodiments thereof, it will be readily appreciated by those skilled in the art that numerous alternatives, modifications and adaptations thereof will be apparent. Therefore, it is intended that the application not be limited to the

[0096] The singular forms "a," "an," and "the" include plural referents unless the context clearly dictates otherwise. The term "about" or "approximately" with reference to a particular recited value of a parameter includes deviations of plus or minus 10% of the recited value, unless otherwise stated.

[0097] Optional or optionally means that the subsequently described event or circumstance can or cannot occur. This description includes instances where the event or circumstance occurs and instances where it does not.

[0098] Ranges can be expressed herein as from about one particular value, and / or to about another particular value. When such a range is expressed, another embodiment is from the one particular value and / or to the other particular value, as well as all combinations within the range.

Claims

1. A method for producing hydrogen via ammonia cracking in an existing steam methane reformer (SMR), the SMR comprising a furnace (50) and a pressure swing adsorption (PSA) unit, wherein, The furnace (50) has a plurality of SMR tubes and a plurality of burners, the method comprising the steps of: (a) providing a gaseous stream (43) consisting essentially of ammonia at a temperature of at least 100°C; (b) introducing the gaseous stream (43) into the SMR tubes of the furnace (50) under conditions effective to catalytically crack the ammonia, thereby forming a crude stream (53) comprising hydrogen, nitrogen, and unreacted ammonia; and (c) introducing the crude stream (53) into the PSA unit to produce a hydrogen product stream and a PSA tail gas.

2. The method of claim 1, wherein, The existing SMR is retrofitted to further include an ammonia storage vessel (1) and an ammonia feed pump (3).

3. The method of claim 2, wherein, Step (a) further includes withdrawing ammonia from the ammonia storage vessel; pumping the ammonia in the ammonia feed pump (3) to a pressure of 25-60 bar (gauge); and then vaporizing (30) the ammonia to provide the gaseous stream (43).

4. The method of claim 3, wherein, The existing SMR is retrofitted to further include an ammonia vaporizer (30), wherein the ammonia is vaporized in the ammonia vaporizer to form the gaseous stream, wherein the gaseous stream in step (a) is connected into a feed conduit or feed distribution system (45) of the existing SMR, wherein the feed conduit and feed distribution system are upstream of the SMR tubes.

5. The method of claim 3, wherein, The existing SMR is retrofitted to further include new equipment selected from the group consisting of an ammonia vaporizer (30, 730), an ammonia exchanger (725), an ammonia preheater (715), an ammonia pre-reactor (740), and combinations thereof, wherein the new equipment is disposed upstream of the SMR tubes and downstream of the ammonia feed pump.

6. The method of claim 3, wherein, The existing SMR includes an existing feed superheat section upstream of the SMR tubes, wherein the ammonia is vaporized in the existing feed superheat section.

7. The method of claim 3, wherein, The ammonia is vaporized using heat provided by electricity, steam, the crude stream (53), and / or a flue gas stream (54).

8. The method of claim 3, wherein, The ammonia is vaporized and preheated to less than 450°C, preferably less than 350°C, more preferably less than 300°C.

9. The method of any of the preceding claims, wherein, The crude stream (53) contains less than 5.0 mol% of unreacted ammonia.

10. The method of any of the preceding claims, wherein, The conditions effective to catalytically crack the ammonia include a pressure of between 15-80 bar, preferably 20-60 bar, and a temperature of between 600°C-850°C, preferably 650°C-750°C.

11. The method of any of the preceding claims, wherein, The gaseous stream in step (a) is provided by a pressurized gaseous ammonia feed received from outside the existing SMR.

12. A method for retrofitting an existing steam methane reformer (SMR) for ammonia cracking, the existing SMR comprising a pre-reformer (20), a desulfurization unit (40), a furnace (50), a waste heat recovery section (10, 30, 90), a water gas shift reactor (60), a pressure swing adsorption (PSA) unit, wherein, The furnace (50) has a plurality of SMR tubes and a plurality of burners, the method comprising the steps of: (a) providing the existing SMR; (b) taking the desulfurization unit (40) offline so that no fluid flows through the desulfurization during operation; (c) taking the pre-reformer (20) offline so that no fluid flows through the pre-reformer during operation; and (d) an addition device for providing a gaseous ammonia stream (1, 3, 43, 45) to the SMR tubes.

13. The method of claim 12, wherein, The device for providing the gaseous ammonia stream includes an ammonia storage vessel (1), an ammonia feed pump (3), and a device (10, 30) for vaporizing ammonia sourced from the ammonia storage vessel.

14. The method of claim 13, wherein, The apparatus for vaporizing ammonia further comprises a new equipment selected from the group consisting of an ammonia vaporizer (30, 730), an ammonia exchanger (725), an ammonia preheater (715), an ammonia pre-reactor (740), and combinations thereof, wherein the new equipment is disposed upstream of the SMR tubes and downstream of an ammonia feed pump (3).

15. The method of claim 13, wherein, The apparatus for vaporizing ammonia further comprises an existing feed superheat section (30) located upstream of the SMR tubes, wherein the existing feed superheat section is retrofitted by treating the inner surface of the existing feed superheat section to improve nitrogenization resistance.

16. The method of claim 13, wherein, The step of treating the inner surface of the existing feed superheat section comprises a process selected from the group consisting of: (1) applying a protective liner material mechanically coupled to the inner surface, (2) applying an aluminized layer to the inner surface, and (3) applying a diffusion barrier layer used in conjunction with the aluminized layer, wherein the diffusion barrier layer is disposed between the inner surface and the aluminized layer.

17. An apparatus for producing hydrogen via ammonia cracking using a retrofitted steam methane reformer (SMR), the apparatus comprising: an apparatus for providing a pressurized and gaseous ammonia stream (1, 3, 43, 45) to a plurality of reactor tubes; a furnace (50) having a plurality of reactor tubes and a plurality of burners, wherein the furnace (50) is configured to catalytically crack the ammonia within the reactor tubes to produce a raw process gas (53) and flue gas; a plurality of waste heat recovery sections; and a pressure swing adsorption (PSA) unit disposed downstream of the furnace (50), wherein the PSA unit is configured to receive the raw process gas (53) or a gas derived therefrom and produce a hydrogen product stream and a PSA tail gas.

18. The apparatus of claim 17, wherein, The apparatus for providing a pressurized and gaseous ammonia stream to a plurality of reactor tubes comprises an ammonia storage vessel (1) and an ammonia pump (3).

19. The apparatus of claim 18, wherein, The apparatus for providing a pressurized and gaseous ammonia stream to a plurality of reactor tubes further comprises an ammonia vaporizer (10, 30, 730), wherein ammonia is vaporized in the ammonia vaporizer to form the pressurized and gaseous ammonia stream (43), wherein the pressurized and gaseous ammonia stream is connected into a feed piping and / or feed distribution system (45) of the existing SMR, wherein the feed piping and / or feed distribution system is immediately upstream of the SMR tubes.

20. The apparatus of claim 18, wherein, The apparatus for providing a pressurized and gaseous ammonia stream to a plurality of reactor tubes further comprises a new equipment selected from the group consisting of an ammonia vaporizer (10, 30, 730), an ammonia exchanger (725), an ammonia preheater (715), an ammonia pre-reactor (740), and combinations thereof, wherein the new equipment is disposed upstream of the SMR tubes and downstream of the ammonia feed pump.

21. The apparatus of claim 18, wherein, The ammonia vaporizer (10, 30, 730) is heated using electricity, steam, the raw stream (53), and / or a flue gas stream.

22. The apparatus of claim 18, wherein, The ammonia vaporizer (10, 30, 730) is configured to vaporize and preheat ammonia at a temperature below 450°C, preferably below 350°C, more preferably below 300°C.

23. The apparatus of claim 18, further comprising a waste heat recovery section (10, 30, 90), wherein, The apparatus for providing a pressurized and gaseous ammonia stream to a plurality of reactor tubes further comprises heating pressurized ammonia from the ammonia pump in the waste heat recovery section to form the pressurized and gaseous ammonia stream.

24. The apparatus of claim 17, wherein, The furnace (50) is configured to operate at a pressure between 15-80 bar, preferably 20-60 bar, more preferably 20-35 bar, and at a temperature between 600°C-850°C, preferably 650°C-750°C.

25. The apparatus of claim 17, wherein, The apparatus for providing a pressurized and gaseous ammonia stream to a plurality of reactor tubes includes a pipe comprising a nitriding resistant material and / or having a nitriding protective layer on an inner surface of the pipe.

26. The apparatus of claim 25, wherein, The nitriding protective layer is selected from the group consisting of a protective liner material mechanically coupled to the inner surface, an aluminized layer applied to the inner surface, a diffusion barrier layer used in conjunction with an aluminized layer applied to the inner surface, wherein the diffusion barrier layer is disposed between the inner surface and the aluminized layer, and a cladding layer applied to the inner surface.

27. The apparatus of claim 17, wherein, The plurality of catalyst tubes includes a nitriding protective layer on an inner surface of the reactor tubes.

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