STEAM METHANE REFORMING WITH PROCESS CARBON DIOXIDE CAPTURE AND AMMONIA FIRING

Abstract

A method for producing hydrogen in a steam methane reformer with reduced carbon emissions that can include the steps of: heating a feed stream comprising methane in a first heat exchanger to produce a heated feed stream, wherein the heated feed stream is at a temperature above 500° C.; introducing the heated feed stream into a reaction zone under conditions effective for catalytic conversion of the heated feed stream to produce a reformed stream, wherein the reformed stream comprises hydrogen, carbon monoxide, and unreacted methane; introducing the reformed stream in the presence of steam to a shift conversion unit that is configured to produce a shifted gas stream comprising hydrogen and carbon dioxide; and purifying the shifted gas stream to produce a hydrogen product stream and a tail gas; wherein the conditions effective for catalytic conversion of the heated feed stream comprise providing heat to the reaction zone via combustion of a fuel and a hydrogen fuel stream in presence of an oxidizer, wherein the fuel comprises ammonia, wherein a flue gas is produced by the combustion of the fuel and the hydrogen fuel stream.

Claims

1. A method for producing hydrogen in a steam methane reformer with reduced carbon emissions, the method comprising the steps of: heating a feed stream comprising methane in a first heat exchanger to produce a heated feed stream, wherein the heated feed stream is at a temperature above 500° C.; introducing the heated feed stream into a reaction zone under conditions effective for catalytic conversion of the heated feed stream to produce a reformed stream, wherein the reformed stream comprises hydrogen, carbon monoxide, and unreacted methane; introducing the reformed stream in the presence of steam to a shift conversion unit that is configured to produce a shifted gas stream comprising hydrogen and carbon dioxide; and purifying the shifted gas stream to produce a hydrogen product stream and a tail gas; wherein the conditions effective for catalytic conversion of the heated feed stream comprise providing heat to the reaction zone via combustion of a fuel and a hydrogen fuel stream in presence of an oxidizer, wherein the fuel comprises ammonia, wherein a flue gas is produced by the combustion of the fuel and the hydrogen fuel stream.

2. The method as claimed in claim 1, wherein the hydrogen fuel stream and the fuel have a combined molar flow rate, wherein a molar flow rate of the hydrogen combined to the combined molar flow rate is between 0.05 and 0.4, preferably between 0.1 and 0.25.

3. The method as claimed in claim 1, wherein the hydrogen fuel stream is combusted in an amount that is effective for providing stable combustion behavior.

4. The method as claimed in claim 1, further comprising the step of removing carbon dioxide from a stream selected from the group consisting of a first stream, a second stream, and combinations thereof, wherein the first stream is the shifted gas stream prior to purification in a hydrogen purification unit, wherein the second stream is the tail gas.

5. The method as claimed in claim 1, wherein the hydrogen fuel stream comprises at least a first portion of the tail gas.

6. The method as claimed in claim 1, wherein a second portion of the tail gas is fed to the reaction zone.

7. The method as claimed in claim 1, wherein the oxidizer is oxygen-enriched combustion air.

8. The method as claimed in claim 1, wherein the fuel and the hydrogen fuel stream are fed to a common burner system.

9. The method as claimed in claim 1, wherein the fuel and the hydrogen fuel stream are fed to separate burner systems.

10. The method as claimed in claim 1, further comprising vaporizing liquid ammonia in an ammonia vaporizer to produce gaseous ammonia, wherein ammonia in the fuel comprises the gaseous ammonia from the ammonia vaporizer.

11. The method as claimed in claim 1, further comprising removing NOx from the flue gas using a selective catalytic reduction unit.

12. The method as claimed in claim 11, further comprising the step of controlling an amount of unreacted ammonia in the flue gas.

13. The method as claimed in claim 1, wherein the fuel has an ammonia content greater than 50%.

14. The method as claimed in claim 1, wherein the fuel comprising ammonia is preheated to a temperature above 300° C.

15. A method for producing hydrogen in a steam methane reformer with reduced carbon emissions, the method comprising a first mode of operation and a second mode of operation, wherein during both modes of operation, the method comprises the steps of: a) heating a feed stream comprising methane in a first heat exchanger to produce a heated feed stream, wherein the heated feed stream is at a temperature above 500° C.; b) introducing the heated feed stream into a reaction zone under conditions effective for catalytically cracking the heated feed stream to produce reformed stream, wherein the reformed stream comprises hydrogen, carbon monoxide, and unreacted methane; c) introducing the reformed stream in the presence of steam to a shift conversion unit that is configured to produce a shifted gas stream comprising hydrogen and carbon dioxide; d) purifying the shifted gas stream to produce a hydrogen product stream and a tail gas; and e) removing carbon dioxide from a stream selected from the group consisting of a first stream, a second stream, and combinations thereof, wherein the first stream is the shifted gas stream, wherein the second stream is the tail gas, wherein the conditions effective for catalytically cracking the heated feed stream comprise providing heat to the reaction zone via combustion of a fuel and a hydrogen fuel stream in the presence of an oxidizer, wherein the hydrogen fuel stream comprises at least a first portion of the tail gas, wherein a flue gas is produced by the combustion of the fuel and the hydrogen fuel stream, wherein during the first mode of operation, the fuel comprises a hydrocarbon, wherein during the second mode of operation, the fuel comprises ammonia, wherein the flue gas produced by the second mode of operation comprises less carbon dioxide than the flue gas produced by the first mode of operation.

16. A method for producing hydrogen in a steam methane reformer comprising the steps of: a) heating a feed stream comprising methane in a first heat exchanger to produce a heated feed stream, wherein the heated feed stream is at a temperature above 500° C.; b) introducing the heated feed stream into a reaction zone under conditions effective for catalytically cracking the heated feed stream to produce a reformed stream and a flue gas stream, wherein the reformed stream comprises hydrogen, carbon monoxide, and unreacted methane; c) introducing the reformed stream in the presence of steam to a shift conversion unit that is configured to produce a shifted gas stream comprising hydrogen and carbon dioxide; d) purifying the shifted gas stream to produce a hydrogen product stream and a tail gas; e) capturing CO2 from the shifted gas stream or from the tail gas stream; f) storing liquid ammonia in a single storage vessel; g) vaporizing the liquid ammonia to create a gaseous ammonia stream; and h) using at least a portion of the gaseous ammonia as reformer fuel and using at least a portion of the gaseous ammonia as reactant for the reduction of NOx of the flue gas stream.

Description

BRIEF DESCRIPTION OF THE PRIOR ART DRAWINGS

[0054] These and other features, aspects, and advantages of the present invention will become better understood with regard to the following description, claims, and accompanying drawings. It is to be noted, however, that the drawings illustrate only several embodiments of the invention and are therefore not to be considered limiting of the invention's scope as it can admit to other equally effective embodiments.

[0055] FIG. 1 shows a prior art embodiment of a hydrogen production facility in accordance where CO.sub.2 is captured from the synthesis gas in a hydrogen production process.

[0056] FIG. 2 shows an embodiment of a hydrogen production facility in accordance with an embodiment of the present invention.

[0057] FIG. 3 shows an embodiment of a hydrogen production facility in accordance with an embodiment of the present invention.

[0058] FIG. 4 shows an embodiment of a hydrogen production facility in accordance with an embodiment of the present invention.

DETAILED DESCRIPTION

[0059] While the invention will be described in connection with several embodiments, it will be understood that it is not intended to limit the invention to those embodiments. On the contrary, it is intended to cover all the alternatives, modifications and equivalence as may be included within the spirit and scope of the invention defined by the appended claims.

[0060] In a preferred embodiment, the claimed process scheme includes a steam methane reformer, a CO-Shift conversion unit, a H.sub.2 purification unit, a cryogenic CO.sub.2 capture unit and the usage of hydrogen and/or ammonia or preferably a mixture of ammonia and hydrogen as make up fuel for the reformer.

[0061] FIG. 1 describes a typical hydrogen production process as known and considered as prior art. A hydrocarbon feedstock 1, typically natural gas, is used. In order to condition the feedstock to be processed by the steam methane reformer 51 certain feed pretreatment measures can occur and are summarized as pretreatment unit 50. These might include, but are not limited to, the removal of steam reforming catalyst poisons (e.g., sulphur, chloride, heavy metals). The feedstock might be heated and enriched with steam as required to achieve effective steam methane reforming process conditions. The pretreated steam reformer feedstock 2 is sent to the steam methane reformer 51 for generation of a hydrogen, CO.sub.2 and CO containing syngas 3. In order to increase the hydrogen and CO.sub.2 yield in the synthesis gas, a CO shift converter 52 is used. CO.sub.2 product 15a can be separated from syngas by a CO.sub.2 capture unit 53 using conventional physical or chemical solvent based technologies (e.g., amine wash or methanol wash technologies). The H.sub.2 rich gas 5 after the CO.sub.2 removal might be further purified by a dedicated H.sub.2 purification unit 54 to increase the H.sub.2 purity of the hydrogen product 6 as required.

[0062] Alternatively to a CO.sub.2 capture in syngas, CO.sub.2 might be captured from the PSA off gas 7 using a dedicated CO.sub.2 separation unit 55. The remaining PSA offgas gas 8 might be used as fuel for the steam methane reformer 51. The heat demand of the steam reformer 51 is typically higher than the heat supplied by combusting the remaining PSA off gas 8. In order to close the heat balance of the steam reformer, a defined hydrocarbon stream is used as make-up fuel 9. During the combustion of the PSA offgas or hydrocarbon make up fuel, NOx might be formed, and a DeNOX unit 57 might be required to reduce the NOx values below environmentally allowable thresholds. In order to also capture CO.sub.2 from the resulting DeNOX stream 11, a CO.sub.2 capture unit 56 in the flue gas system might be installed to generate a CO.sub.2 product stream 15c and a flue gas stream 10, 11, 12.

[0063] As mentioned above from a production cost perspective (considering operational expenditure and investment costs) the flue gas CO.sub.2 capture unit (56) is the most expensive solution versus CO.sub.2 capture from syngas 4 or PSA tail gas 7. This prior art process, while providing a high overall CO.sub.2 capture rate, provides a costly flue gas CO.sub.2 capture unit (56) that is just not economically feasible. Embodiments of the present invention are intended to overcome this problem.

[0064] As shown in FIG. 2, the claimed process includes a CO.sub.2 capture unit 55 in the PSA offgas 7a or alternatively a syngas CO.sub.2 capture unit 53. In order to avoid the costly flue gas CO.sub.2 capture unit (56 from FIG. 1) the hydrocarbon make up fuel (9 from FIG. 1) is replaced with carbon-free ammonia fuel 13. In certain embodiments, at least a first portion of the PSA off gas 8a can be mixed with the ammonia fuel 13. However, because these off gases 8a contain carbon, in certain embodiments of the invention, a portion of the off gases 8b can be recycled and combined with preheated feed 2 for further reaction and recovery. In embodiments in which stream 8a is decreased or non-existent, the amount of ammonia fuel can be further increased. In another optional embodiment (not shown), at least a part of the PSA off gas 8b can be recycled to the hydrogen purification unit 54 to recover the H.sub.2 contained in the off gas and to increase the overall H.sub.2 product yield.

[0065] Flue gas (10), generated from combustion of NH.sub.3 (13a) and, in certain embodiments, very small amount of off-gasses 8a, contains significantly lower CO.sub.2 (less than 5% as compared to flue gas (10) in FIG. 1). Therefore, embodiments of the invention allow for treatment of the flue gas 10 in a DeNOX unit 57 without further carbon capture units, such as required in prior art methods shown in FIG. 1.

[0066] The FIG. 3 illustrates an additional aspect of the invention. When combustion of pure ammonia fuel or in a mixture with hydrogen the formation of NOx is enhanced an additional measure for mitigation might be necessary. Modern SMR plant might have already a DeNOx unit installed where older plant might not have or might have only reserved provision for future revamp. In the DeNOx plant, ammonia is used as reactant for the reduction of NOx to N2 and H2O. Ammonia is a toxic and flammable substance and the storage requires various safety precautions and thus lead to additional handling cost. In order to lower the capital expenditure of the system a combined liquid ammonia storage (58) and vaporization system (59) is foreseen. Thus the amount of ammonia containing equipment and piping systems are reduced. The liquid ammonia (14) from storage vessel 58 is vaporized by the ammonia vaporization system (59). The gaseous ammonia is the used as steam reformer fuel 13a and as reactant 13b for the DeNOx unit.

[0067] FIG. 4 provides another embodiment of the present invention in which dedicated CO2 separation unit 55 is preferably a cryogenic type separation device that is configured to separate CO2 and hydrogen from the PSA off gas stream 7a. These units are well known in the art, and will not be discussed herein in any detail. This unit can produce carbon dioxide 15b, a hydrogen stream 16, and off gas 8. As before, off gas 8a can be used for fuel, and second off gas 8b can be recycled to a location upstream the SMR 51. In this embodiment, hydrogen stream 16 can be split, with one portion being used as fuel, which helps with flame stability, while the other portion can be recycled to the PSA for further refinement. In certain embodiments, flow off gas 8a can be reduced or even eliminated entirely if flow rate of hydrogen stream 16 is sufficient for combustion purposes. This advantageously further reduces CO2 in the resulting flue gas 10.

[0068] In certain embodiments, approximately 20% vol hydrogen can be added to the ammonia fuel in order to achieve more stable combustion behavior and minimize the NOx emissions. In the embodiment with a syngas amine unit, the PSA tail gas will contain enough hydrogen to allow for this preferable NH.sub.3+H.sub.2 gas mixture.

[0069] In an embodiment in which a syngas amine wash unit (no matter whether CO.sub.2 capture for H.sub.2 production or CO.sub.2 removal because of a downstream coldbox for H.sub.2 and CO production) is used, the trim fuel ratio can be higher, meaning the ratio of additional fuel versus waste fuel streams (PSA or CB offgas) is higher, and the effect of replacing natural gas with ammonia on the CO.sub.2 emissions is relatively higher compared to low trim fuel ratio plant setups (w/o CO.sub.2 removal).

[0070] In optional embodiments, there can also be other parameters in plant design/operation that influence the trim fuel ratio—so in a revamp case the operating parameters of the SMR could be adjusted to maximize the ammonia as fuel.

[0071] In the embodiment having a Cryocap H.sub.2, where the PSA tail gas is used as feed for the capture unit, the residue from the Cryocap (which contains some H.sub.2 but also some CH.sub.4, CO and CO.sub.2) is recycled in majority to the SMR feed gas and preferably at more than 70% or 90%. Only a minority part is sent to fuel gas to ensure that there's no accumulation of inert gases (N2, Ar, . . . ) in the flue gas. To obtain the required suitable fuel mixture for NH.sub.3 combustion the amount of fuel gas from CryoCAP can be adjusted.

[0072] Alternatively, oxygen-enriched combustion air (23%) can be used to improve flame stability, increase the flame temperature and thus, the heat flux to the tubes.

[0073] In a further embodiment, preheating of ammonia at a temperature above 300° C. can be used to improve the flame stability, increase the reactiveness of the ammonia and decrease the amount of unburnt ammonia content in the flue gases as well as the amount of NOx in the flue gases.

[0074] As the NOx emissions are typically higher with ammonia fuel, a selective catalytic reduction (“SCR”) unit can be installed to treat the high NOx levels. In an embodiment where an SCR unit is already existing, an upgrade might be necessary depending on the performance with higher NOx inlet conditions.

[0075] Furthermore, because of the slow kinetics of ammonia combustion, ammonia is expected to be present in a significantly high concentration in the flue gases. It is therefore possible to make use of the ammonia already existing in the flue gas to optimally reduce the NOx through the SCR, ideally without injecting additional ammonia. There exists several strategies to control the amount of ammonia in the flue gases. The first is to play on the overall combustion air ratio, by either acting on the air flow rate, and/or on the fuel flow rate. Second, preheating ammonia can result in the control of its combustion kinetics and thus, can be considered as an effective way to control its content in the flue gases. Third, adding hydrogen in the fuel makes it possible to further control the flue gases composition. Last, preheating oxidizer temperature can be used to control the overall kinetics of the flame and thus, the amount of residual ammonia in the flue gases.

[0076] In an embodiment where no SCR/SNCR unit is already existing, the previous ammonia control strategies could also be implemented. This way, the furnace could get the SNCR function, without installing new equipment.

[0077] Operational Flexibility:

[0078] It is projected that the SMR can operate in two modes. Conventional mode (with natural gas plus PSA tail gas (or residue from cryocap)) and NH.sub.3/H.sub.2 off gas mode (no Natural gas injection). The first mode may be used for the first years of operation of the plant, and the second mode later on when CO.sub.2 emissions must be further reduced. In this case, burners and fuel system are designed accordingly.

[0079] Table I and Table II below show comparative data that compares an embodiment of the prior art (using NG as fuel) with results in which the fuel is at least partially replaced with ammonia (stream 13a) (i.e., 85% ammonia or 100% ammonia). As can be seen, there is a significant reduction in carbon dioxide emission.

TABLE-US-00001 TABLE I Comparison of Prior Art with Embodiments of the Invention Trim fuel replacement Case A Base case 85% 100% Hydrogen Nm3/hr 167343 167343 167343 production CO2 emission kg/hr 55594 27338 22351 CO2 emission kg CO2/kg H2 3.69 1.81 1.48 % reduction in % — 50.8% 59.8% CO2 emission

TABLE-US-00002 TABLE II Another Comparison of Prior Art with Embodiments of the Invention Trim fuel replacement Case B Base case 100% Hydrogen production Nm3/hr 25100 25100 CO2 emission kg/hr 16086 8904 CO2 emission kg CO2/kg H2 7.11 3.94 % reduction in CO2 emission % — 44.6%

[0080] As used herein, stable combustion behavior can be determined by measuring an extinction stretch rate of the flame produced by certain embodiments of the invention. In certain instances, combustion can be considered stable as long as the extinction stretch rate of a flame produced according to certain embodiments of the present invention is within 15%, preferably within 10%, more preferably within 5% of the extinction stretch rate of a flame produced using methane, off-gasses and air. While the invention has be described primarily in accordance with a steam methane reforming production unit, the invention can be equally applied to other hydrogen production facilities such as, but not limited to, autothermal reforming. In essence, embodiments of the invention include the combination of reducing CO.sub.2 in the flue gas by using a fuel gas comprised of ammonia, as well as carbon capture on the resulting process streams (i.e., streams that result from the conversion of the feed stream to hydrogen).

[0081] While the invention has been described in conjunction with specific embodiments thereof, it is evident that many alternatives, modifications, and variations will be apparent to those skilled in the art in light of the foregoing description. Accordingly, it is intended to embrace all such alternatives, modifications, and variations that fall within the spirit and broad scope of the appended claims. The present invention may suitably comprise, consist or consist essentially of the elements disclosed and may be practiced in the absence of an element not disclosed. Furthermore, language referring to order, such as first and second, should be understood in an exemplary sense and not in a limiting sense. For example, it can be recognized by those skilled in the art that certain steps or devices can be combined into a single step/device.

[0082] The singular forms “a”, “an”, and “the” include plural referents, unless the context clearly dictates otherwise. The terms about/approximately a particular value include that particular value plus or minus 10%, unless the context clearly dictates otherwise.

[0083] Optional or optionally means that the subsequently described event or circumstances may or may not occur. The description includes instances where the event or circumstance occurs and instances where it does not occur.

[0084] Ranges may be expressed herein as from about one particular value, and/or to about another particular value. When such a range is expressed, it is to be understood that another embodiment is from the one particular value and/or to the other particular value, along with all combinations within said range.