Hydrogen production by steam reforming of sulfur

Abstract

A system and method for producing hydrogen, comprising steam reforming elemental sulfur to produce hydrogen gas and sulfur dioxide to obtain a mixture comprising hydrogen gas, sulfur dioxide, elemental sulfur gas, and water vapor; removing the elemental sulfur gas to obtain a process gas comprising hydrogen gas, sulfur dioxide, and water vapor; and separating the hydrogen gas or a hydrogen gas-rich stream.

Description

[Technical Field]

[0001] (Priority Claim) This application claims priority to U.S. Patent Application No. 17 / 946,413, filed September 16, 2022, the entire contents of which are incorporated herein by reference.

[0002] The present disclosure relates to producing hydrogen from sulfur vapor and water. [Background technology]

[0003] Hydrogen sulfide can be a by-product of natural gas processing and sulfur-containing crude oil refining. Other industrial sources of hydrogen sulfide can include pulp and paper manufacturing, chemical manufacturing, waste disposal, etc. In certain instances, hydrogen sulfide can be considered a precursor to elemental sulfur.

[0004] Sulfur recovery may refer to the conversion of hydrogen sulfide (HS) to elemental sulfur in a sulfur recovery unit (SRU), such as a Claus system. The most common technology for sulfur recovery is the Claus system, which may be referred to as a Claus process, Claus plant, Claus unit, etc. A Claus system includes a thermal reactor (e.g., a furnace) and multiple catalytic reactors to convert HS to elemental sulfur and remove (recover) the elemental sulfur.

[0005] Hydrogen is commercially produced from fossil fuels, etc. Hydrogen can be produced, for example, by hydrocarbon reforming or water electrolysis. Hydrogen is produced by coal gasification, biomass gasification, water electrolysis, or reforming or partial oxidation of natural gas or other hydrocarbons.

[0006] Natural gas reforming is the most common source of hydrogen production. Bulk hydrogen is typically produced by steam reforming of natural gas (methane). Conventional steam reforming involves heating natural gas (e.g., to 700°C to 1100°C) in the presence of steam and a nickel catalyst. This endothermic reaction produces carbon monoxide and hydrogen. The carbon monoxide gas can be subjected to a water-gas shift reaction to obtain additional hydrogen.

[0007] The produced hydrogen can be a feedstock for chemical processes such as ammonia production, aromatization, hydrodesulfurization, and hydrocarbon hydrogenation or hydrocracking. The produced hydrogen can be a feedstock for electrochemical processes such as fuel cells. Summary of the Invention

[0008] One aspect relates to a method for producing hydrogen, comprising steam reforming elemental sulfur from a sulfur pit to produce hydrogen gas and sulfur dioxide, thereby obtaining a mixture comprising hydrogen gas, sulfur dioxide, elemental sulfur gas, and steam. The method includes condensing the elemental sulfur gas in the mixture into liquid elemental sulfur in a condenser (heat exchanger) and discharging the liquid elemental sulfur from the condenser to the sulfur pit. The method includes discharging a process gas from the condenser, the process gas comprising the hydrogen gas and sulfur dioxide produced in the steam reforming.

[0009] Another aspect relates to a hydrogen production system that includes a vessel configured to receive elemental sulfur from a sulfur pit, steam reform the elemental sulfur into hydrogen gas and sulfur dioxide, and discharge a mixture having hydrogen gas, sulfur dioxide, elemental sulfur gas, and steam. The hydrogen production system includes a condenser heat exchanger that receives the mixture, condenses the elemental sulfur gas in the mixture into liquid elemental sulfur, discharges the liquid elemental sulfur to the sulfur pit, and discharges a process gas having hydrogen gas and sulfur dioxide produced by steam reforming in the vessel.

[0010] The details of one or more implementations are set forth in the accompanying drawings and the description below. Other features and advantages will be apparent from the description and drawings, and from the claims. [Brief explanation of the drawings]

[0011] [Figure 1] 1 is a plot of the change in Gibbs free energy as a function of temperature. [Figure 2] This is a diagram of the forward reaction. [Figure 3] This is a diagram of the reverse reaction. [Figure 4] FIG. 1 is a diagram of effective reactions. [Figure 5] 1 is a diagram of the reaction in a reducing environment (excess hydrogen sulfide) where sulfur dioxide is consumed at temperatures below 445°C. [Figure 6] 1 is a diagram of the overall reaction in an oxidizing environment (excess sulfur dioxide), sulfur steam reforming reaction. [Figure 7A] FIG. 1 is a diagram of a hydrogen production system. [Figure 7B] FIG. 1 is a diagram of a hydrogen production system. [Figure 8] FIG. 1 is a diagram of a hydrogen production system. [Figure 9A] FIG. 1 is a diagram of a hydrogen production system. [Figure 9B] FIG. 1 is a diagram of a hydrogen production system. [Figure 10A] FIG. 1 is a diagram of a hydrogen production system. [Figure 10B] FIG. 1 is a diagram of a hydrogen production system. [Figure 11] FIG. 1 is a diagram of a hydrogen production system. [Figure 12] FIG. 1 is a diagram of a hydrogen production system. [Figure 13A] FIG. 1 is a diagram of a hydrogen production system. [Figure 13B] FIG. 1 is a diagram of a hydrogen production system. [Figure 14] FIG. 1 is a diagram of a hydrogen production system. [Figure 15] FIG. 1 is a block flow diagram of a method for producing hydrogen. [Figure 16]FIG. 1 is a diagram of a selective amine process gas sweetening system. DETAILED DESCRIPTION OF THE INVENTION

[0012] The produced hydrogen gas (H2) can be utilized in the transportation and energy sectors, as a feedstock for chemical processes, etc. Embodiments herein can provide H2 for these uses (and other uses) by converting elemental sulfur (S) (and water) to H2 in a sulfur recovery plant or sulfur recovery unit (SRU).

[0013] Aspects of the present disclosure relate to producing hydrogen (H) from elemental sulfur (S) and water (H2O) to produce H2. In particular, S and H2O may be contacted at temperatures above the boiling point of S (445°C) to produce H2 and sulfur dioxide (SO2). The reaction may be characterized as sulfur steam reforming. The reaction may be or include 2H2O + S → 2H2 + SO2.

[0014] Again, this may be characterized as steam reforming of S. Steam reforming of S may be carried out in a Claus furnace (or Claus-type furnace) or in a sulfur steam reformer vessel. The H2 produced in the exhaust gas from the Claus furnace or sulfur steam reformer may be recovered as a product.

[0015] In the case of a Claus furnace (reactor), such steam reforming of S can occur in the intermediate zone of the Claus furnace. In this case, the intermediate zone (e.g., the second zone) of the Claus furnace can be called a sulfur steam reformer. The Claus reaction 2H2S + SO2 → 3S + 2H2O can also occur in the Claus furnace in the boiler section as the temperature decreases.

[0016] Sulfur steam reforming (whether in a Claus furnace intermediate zone or in a sulfur steam reformer) can be carried out in a reducing environment (excess H2S) or an oxidizing environment (excess SO2).

[0017] As used herein in this context, a reducing environment refers to the presence of excess H2S (but not excess SO2) in the exhaust gas stream with respect to the Claus reaction and any possible oxidation reactions (e.g., 2H2S + 3O2 → 2SO2 + 2H2O), etc. SO2 (including SO2 produced in sulfur steam reforming) can be converted to elemental sulfur by excess H2S. An oxidizing environment refers to the presence of excess SO2 (but not excess H2S) with respect to the Claus reaction, which can be promoted by sulfur steam reforming.

[0018] The temperature range for sulfur steam reforming operation can be, for example, 445°C (boiling point of sulfur) to 720°C (disproportionation of sulfur to disulfur). Claus reactions can occur below 445°C. Claus reactions (Rx4 below) can be avoided (eliminated) by maintaining temperatures above 445°C. Therefore, Claus reactions generally do not occur in sulfur steam reformers operating at temperatures in the range of 500°C to 600°C. Sulfur steam reforming generally occurs above 445°C. The production of disulfur at 720°C can be an undesirable side reaction. Therefore, a useful operating temperature range for sulfur steam reforming can be 445°C to 720°C, for example, an operating temperature range of 500°C to 600°C.

[0019] Claus reactions can occur in Claus furnaces (e.g., Claus furnaces with an intermediate zone where sulfur steam reforming occurs) and in stand-alone sulfur steam reformers (not Claus furnaces) in a reducing environment.

[0020] If excess hydrogen sulfide (HS) is fed into the first zone (combustion) of a Claus furnace, excess HS may be present in the intermediate zone, creating a reducing environment within the intermediate zone. In this case, the furnace exhaust gas may be passed through, for example, a catalytic converter within the Claus system. Also, the H2 gas produced during sulfur steam reforming within the furnace may be recovered.

[0021] In the intermediate zone (reaction zone) and exhaust zone (e.g., heat exchanger as a boiler) of the Claus furnace with excess H2S creating a reducing environment, S may be condensed and removed from the furnace exhaust gas, and the remaining furnace exhaust gas (with H2, H2S, and SO2) may be passed through a catalytic converter to produce S (condensed and removed via an associated condenser) and H2 rich gas.

[0022] In the catalytic converter, HS and SO react in a Claus reaction to produce S and HO vapor. As shown, any S vapor is condensed and removed as liquid S via a condenser associated with the catalytic converter. The remaining gas mixture exiting the final catalytic converter (after condensation and removal of S in the final condenser) containing HO vapor, H, carbon dioxide (CO), any nitrogen (N), and residual HS may be characterized as Claus tail gas, but with a significant amount of H. This Claus tail gas may be further processed, such as by water quenching to remove HO vapor and gas sweetening (such as selective amine treatment) to remove HS, thus recovering an H-rich gas with H product.

[0023] If H2S is sub-stoichiometric (oxidizing environment) in the Claus furnace intermediate zone, excess SO2 may be produced. In this case, a downstream catalytic converter is not used. H2-rich gas can be separated from the furnace exhaust gas by quenching the exhaust gas with cooled acid water, which can absorb and remove relatively large amounts of SO2. The resulting H2-rich gas can be obtained. Because of the sub-stoichiometric H2S (oxidizing environment) with excess SO2 in the intermediate and exhaust zones of a Claus furnace, H2-rich gas can be separated by quenching the exhaust gas with cooled acid water, which absorbs the SO2 from the furnace exhaust gas, leaving an H2-rich gas. A catalytic converter is not used. The sulfurous acid (water with absorbed SO2) produced can be oxidized to sulfuric acid in an oxidation tower using oxygen from the air. The water exiting the oxidation tower can be sent to a water treatment unit, such as reverse osmosis (RO), electrodialysis, or distillation, to recover and concentrate the sulfuric acid. The clean water can be reused. Concentrated sulfuric acid can be monetized or injected into the furnace to promote furnace combustion in oxygen.

[0024] In implementations where acid gas (having HS as the acid gas) is fed to a furnace (e.g., a Claus furnace) (whether the HS is in excess or substoichiometric), the oxidation reaction in the furnace (e.g., a reactor or a thermal reactor in the thermal stage of a Claus system) is 2HS + 3O2 → 2SO2 + 2HO, which involves using supplied oxygen (O2) gas to oxidize incoming HS from the supplied acid gas to produce SO2 and HO vapor. As a thermal reactor, the reactor can also perform the Claus reaction 2HS + SO2 → 3S + 2HO, in which HS gas reacts with SO2 to produce elemental S gas and HO vapor. The overall reaction including these two reactions (oxidation and Claus reactions) can be characterized as 2HS + O2 → 2S + 2HO. Additionally, according to embodiments of the present technology herein, liquid elemental S and water may be supplied (externally injected) to an intermediate zone (e.g., second zone) of the furnace (see, e.g., FIGS. 7A and 8), which acts as a steam reformer for elemental S. As previously mentioned, the reaction in the steam reforming of S may be, for example, 2H2O + S → 2H2 + SO2. The produced H2 may be recovered downstream as a product, and thus the system may be referred to as a hydrogen production system. Finally, the Claus reaction 2H2S + SO2 → 3S + 2H2O may be carried out (as a catalytic reaction) in a Claus catalytic converter (catalytic reactor) if used to receive exhausted furnace gas.

[0025] The following reactions have been considered for producing hydrogen in a conventional Claus reactor:

[0026] Partial combustion of methane followed by the water-gas shift reaction of carbon monoxide:

[0027]

number

[0028] Partial combustion of H2S followed by the water-gas shift reaction of sulfur monoxide:

[0029]

number

[0030] Methane steam reforming:

[0031]

number

[0032] While H2S steam reforming is not thermodynamically feasible within the operating temperature range of a Claus furnace (T<2000°K), sulfur steam reforming is thermodynamically feasible above the boiling point of sulfur (445°C or 718.15°K), as shown below.

[0033]

number

[0034] The temperatures shown in the reaction scheme above relate to the temperature at which the reaction reverses. To understand the potentially destructive effects of other reactions, including side reactions, the Gibbs free energy of these reactions was calculated as a function of temperature using the enthalpy and entropy of formation provided by NIST (National Institute of Standards and Technology). The results are shown in Figure 1.

[0035] Figure 1 plots ΔG (change in Gibbs free energy) in kilojoules per mole (kJ / mol) as a function of temperature in Kelvin (K). A line is plotted for each reaction (Rx1-20) shown in Figures 2-3. Vertical dashed line 100 is the vaporization temperature (boiling point) of elemental sulfur. Vertical dashed line 102 is the temperature at which vaporized sulfur dissociates into disulfur, S2. The graph indicates whether the reaction at a given temperature is equilibrium or non-equilibrium (0 ≠ ΔG ∀T), and whether it is a forward reaction (0 < ΔG and JPEG2025529521000005.jpg1122 ), or the reverse reaction (0 > ΔG and JPEG2025529521000006.jpg1020 ), ΔG is the change in Gibbs free energy, T is temperature in Kelvin, and ∀ is the mathematical symbol for "for all...". Figure 1 shows the change in Gibbs energy (Gibbs free energy) of the considered reaction as a function of temperature.

[0036] Figure 2 shows the forward reaction considered, and Figure 3 shows the reverse reaction considered.

[0037] The reactions considered are equilibrium reactions, with the exception of the non-equilibrium reaction Rx11. Another aspect is that molecular hydrogen is generally unreactive in the temperature window (T<4412°K) unless, for example, a metal catalyst is introduced. In other words, hydrogen at operating temperatures is typically not a reactant, since hydrogen is generally not consumed during the reaction. Therefore, reaction Rx11 does not occur (unless, for example, a metal catalyst such as platinum (Pt) or nickel (Ni) is present). Similarly, reactions Rx5 and Rx9 do not typically occur in the absence of a metal catalyst.

[0038] Equilibrium can be further promoted by adding an excess of one or more components. Excess HO vapor and excess H2S have been observed (simple arrows) to alter the reactions in a desired manner, with the exception of reaction Rx4 (the Claus reaction). Reaction Rx4 can be avoided by maintaining the temperature above 445°C (718°K). By maintaining the temperature above 718°K, the following reactions are generally eliminated from the possible reactions: Rx2, Rx4, Rx6, Rx8, Rx13, and Rx18.

[0039] Figure 4 shows the valid reactions considered. In other words, a valid set of reactions (or a set of valid reactions) is shown. In this context, "valid" means that a reaction occurs, and "invalid" means that a reaction does not occur.

[0040] Chemistry can dictate separation and heating strategies. Techniques (including systems and processes) are described below according to or in conjunction with heating approaches and subsequent separation techniques. There are a variety of heating configurations, as described below.

[0041] Furthermore, within the Claus furnace (e.g., within the second zone of the furnace) or sulfur steam reformer, and in the exhaust gas from the furnace or sulfur steam reformer, there are at least two environments that can affect the downstream configuration. As previously mentioned, these two environments or chemical types can be "reducing" or "oxidizing" environments.

[0042] A reducing environment in a Claus furnace (e.g., in the intermediate zone, second zone, and exhaust zone) has excess H2S, such as excess H2S in a Claus furnace or the second zone of a Claus-type furnace. Sulfur dioxide is consumed at low temperatures (e.g., below 445°C). Again, a "reducing" environment can be excess H2S in the second zone of the furnace. If excess H2S is fed to the furnace (creating a reducing environment), the exhaust gas with H2S can pass through a downstream catalytic converter to produce molten sulfur and H2-rich gas. In a reducing environment, the exhaust gas has H2S (considered excess H2S). As previously mentioned, furnace gas may be sent through a catalytic converter for the Claus reaction. In a reducing environment, the exhaust furnace gas with H2S also has SO2 (not considered excess SO2). Sulfur steam reforming in the furnace produces SO2, which is converted to liquid sulfur with excess H2S in a downstream catalytic converter.

[0043] In an oxidizing environment within a furnace or stand-alone sulfur steam reformer, the furnace intermediate zone (and exhaust zone) or the sulfur steam reformer has excess SO2, and the sulfur steam reforming reaction contributes SO2. The sulfur steam reforming reaction occurs within a stand-alone sulfur steam reformer, and may occur within the furnace intermediate zone. The furnace exhaust gas has more H2S than SO2 in the furnace exhaust gas. If H2S is less than stoichiometric (not excessive) in the furnace, excess SO2 (oxidizing environment) may be generated within the furnace (e.g., the second zone) and in the exhaust gas. In this case, H2-rich gas can be separated from the exhaust gas by quenching the exhaust gas with cooled acid water, which can absorb a relatively large amount of SO2. The generated sulfurous acid (hydrate of SO2) can be oxidized in a subsequent oxidation tower using oxygen from the air to produce sulfuric acid.

[0044] FIG. 5 shows the reactions in a reducing environment (with excess H2S), where SO2 is consumed at temperatures below 445°C. The first reaction is shown as the sulfur steam reforming reaction. The second reaction is shown as the Claus reaction. The third reaction, shown below the line, is the overall reaction in a reducing environment. This overall reaction is a combination of the sulfur steam reforming reaction and the Claus reaction, and is represented as the splitting or dissociation of H2S.

[0045] Figure 6 shows the sulfur steam reforming reaction. This reaction results in an oxidizing environment due to the formation of SO2 as a reaction product.

[0046] Heating of elemental sulfur and water for sulfur steam reforming can be direct heating by directly contacting the elemental sulfur and water with combustion gases in a furnace (e.g., Figures 7A-8), or indirect heating by heating in a sulfur burner, electric heater, or boiler (e.g., Figures 9A-14).

[0047] 7A-14 are summarized below. A reducing environment (excess H2S) or an oxidizing environment (excess SO2) is listed. A reducing environment, in this context, is defined as the presence of excess H2S. An oxidizing environment, in this context, is defined as the presence of excess SO2. Direct heating may be defined herein as a fluid being heated in direct contact with a heating medium (without conduction through an interface). A more detailed description of FIGS. 7A-14 is provided further below.

[0048] 7A and 7B: Direct heating of S and water in a reducing environment in the second zone of the Claus furnace by direct contact with furnace gas from the first zone of the Claus furnace, which functions as a sulfur steam reformer along with carrying out the Claus reaction in a heat recovery zone (e.g., boiler).

[0049] Figure 8: Direct heating of S and water in an oxidizing environment in the second zone of the Claus furnace by direct contact with furnace gases from the first zone of the Claus furnace. The second zone of the Claus furnace functions as a sulfur steam reformer as well as carrying out the Claus reaction in a heat recovery zone (e.g., boiler).

[0050] 9A and 9B: Indirect heating of S and water (using sulfur burners) for sulfur steam reforming in a sulfur steam reformer separate from the Claus furnace. The second zone of the Claus furnace has a reducing environment and performs the Claus reaction in a heat recovery zone (e.g., boiler).

[0051] 10A and 10B: Indirect heating of S and water (heating using an electric heater or boiler) for sulfur steam reforming in a sulfur steam reformer separate from the Claus furnace. The second zone of the Claus furnace has a reducing environment and the Claus reaction takes place in a heat recovery zone (e.g., boiler).

[0052] Figure 11: Indirect heating of S and water (heating using sulfur burners) for sulfur steam reforming in a sulfur steam reformer separate from the Claus furnace.

[0053] The second zone of the Claus furnace has an oxidizing environment and carries out the Claus reaction in a heat recovery zone (eg, a boiler).

[0054] Figure 12: Indirect heating of S and water (heating using an electric heater or boiler) for sulfur steam reforming in a sulfur steam reformer separate from the Claus furnace. The second zone of the Claus furnace has an oxidizing environment and the Claus reaction takes place in a heat recovery zone (e.g., a boiler). Heating of the fluid in the electric heater is indirect heating.

[0055] 13A and 13B: Indirect heating of S and water for sulfur steam reforming in a reducing environment of the sulfur steam reformer (indirect heating using an electric heater or boiler). There is no Claus furnace. There is no sulfur burner.

[0056] Figure 14: Indirect heating of S and water for sulfur steam reforming in an oxidizing environment of the sulfur steam reformer (indirect heating using an electric heater or boiler). There is no Claus furnace. There is no sulfur burner.

[0057] In Figures 7A-8, S and water are externally injected into the second zone of the Claus furnace. In Figures 9A-12, the system is not shown as injecting S and water externally into the second zone of the Claus furnace. Nevertheless, S and HO may be present, so a relatively small amount of sulfur steam reforming may occur within the second zone of the furnace even without S and HO injection. In Figures 13A-14, a Claus furnace is not present.

[0058] In Figures 7A, 9A and 10A, the system includes a Claus catalytic converter downstream of the Claus furnace.

[0059] In Figures 8, 11 and 12, the systems shown do not include a catalytic converter downstream of the Claus furnace, and therefore the Claus furnace may be characterized as a Claus-type furnace that is not a Claus system with catalytic stages.

[0060] In Figures 7B, 9B, 10B, and 13B, the downstream system includes a water quench (to condense and remove water vapor) and selective amine treatment to remove H2S. In Figures 8, 11, 12, and 14, the downstream system includes quenching and removing SO2 and H2S using aqueous sulfurous acid solution, and oxidizing the excess aqueous sulfurous acid solution to produce sulfuric acid using oxygen gas from air.

[0061] In Figures 13A and 14, liquid sulfur is fed into the system. There is no Claus furnace or Claus catalytic reactor. The system is not a Claus system.

[0062] 7A and 7B illustrate a hydrogen production system 100, which may be a sulfur recovery unit (SRU) (e.g., a Claus system) modified for hydrogen production. The SRU has a reactor vessel (e.g., a Claus furnace 101) that receives acid gases having HS and combusts the HS in a first zone of the furnace. For H production, elemental S and water can be supplied (including external injection) to a second zone of the furnace to steam reform the S to produce hydrogen gas (H) that is recovered downstream as a product.

[0063] The SRU converts HS to elemental S and recovers the elemental S. The SRU includes a reactor (e.g., 101) and a catalytic converter (e.g., 105) downstream of the reactor that converts HS to elemental S (catalytic reactor vessel). A condenser heat exchanger (e.g., 102a, 102b, 102c) may condense the elemental S gas / vapor into elemental S liquid for recovery (e.g., as molten sulfur in a sulfur pit). The condenser heat exchanger (e.g., a shell-and-tube heat exchanger) may also generate water vapor by vaporizing a water refrigerant using heat from the elemental S gas / vapor.

[0064] A furnace that converts H2S to elemental S may be located in the thermal section of the Claus main portion of the system 100. A catalytic converter that converts H2S to elemental S may be located in the catalytic section of the Claus main portion of the system 100.

[0065] The system 100 includes a Claus furnace 101 vessel having a first zone 101a and a second zone 101b. In an implementation, the inlet section 101x of the furnace 101 mixes streams 121, 122, and 143 (with combustible gases) in a nozzle and draws in oxygen 120 (e.g., from air) to ignite the mixture in the furnace flame and burn it in the furnace combustion chamber. The combustion chamber of the furnace 101 includes the first zone 101a and the second zone 101b. The combustion chamber of the furnace 101 has an internal baffle that separates the combustion chamber into the first zone 101a (closest to the inlet section 101x) and the second zone 101b (closest to the boiler 101c). The first zone 101a may operate at a temperature, for example, in the range of 1200°C to 1600°C. The Claus furnace 101 includes (or is associated with) a heat exchanger 101c that cools the furnace gases and vaporizes a water coolant to produce water vapor 125. The heat exchanger 101c may be part of the furnace 101 vessel. The heat exchanger 101c portion may be referred to as a boiler or waste heat boiler (WHB) in some implementations.

[0066] During operation, acid gas 121 is supplied to the first zone 101a of the furnace 101 and may flow through the inlet portion 101x and / or directly into the first zone 101a. The acid gas 121 includes at least carbon dioxide (CO) and H2S. Because the acid gas 121 includes H2S as an acid gas, it may be referred to as sour acid gas. The acid gas 121 and recycled H2S 143 may be partially combusted with supplied oxygen gas 120 within the first zone 101a of the Claus furnace 101. The Claus furnace 101 (and associated condenser 102a) may be considered the thermal stage of the SRU. The oxygen 120 may be supplied in supplied air or from an enriched or pure oxygen source. A fuel gas 122, such as methane, may be added to the furnace 101 to maintain the furnace temperature.

[0067] With acid gas 121 supplied for combustion in the first zone 101a of the Claus furnace 101, the oxidation reaction in the thermal stage within reactor 101 (thermal reactor) is 2H2S + 3O2 → 2SO2 + 2H2O, which involves using supplied oxygen (O2) gas 120 to oxidize H2S entering from the acid gas supply 121 to produce SO2 and water (H2O) vapor. Reactor 101 as a thermal reactor may also perform the Claus reaction 2H2S + SO2 → 3S + 2H2O within 101c, in which H2S gas reacts with SO2 to produce elemental sulfur (S) gas and water vapor. The overall reaction of an SRU (e.g., a Claus system) involving these two reactions (oxidation and Claus reactions) can be characterized as 2H2S + O2 → 2S + 2H2O.

[0068] The Claus reaction 2H2S + SO2 → 3S + 2H2O may be carried out (as a catalytic reaction) in catalytic converters 105 (catalytic reactors), each having a catalyst (catalyst bed) for carrying out the Claus reaction. The catalyst is used to convert H2S and SO2 to sulfur (facilitating the conversion of H2S and SO2 to sulfur). The catalyst (e.g., Claus catalyst) may include an activated alumina catalyst. The catalyst may include activated aluminum (III) oxide and / or titanium (IV) oxide. Other Claus catalysts are applicable.

[0069] With acid gas 121 supplied for combustion in the first zone 101a of the Claus furnace 101, a mixture of water 123 and liquid sulfur 124 may be injected into the second zone 101b of the Claus furnace 101. The sulfur steam reforming reaction in the second zone may occur at temperatures above 445°C (718.15°K). In these implementations, the second zone 101b may be referred to as a sulfur steam reformer. The mixture of water 123 and liquid sulfur 124 (injected) in the second zone 101b of the Claus furnace may be considered "direct heating" of the water 123 and sulfur 124. In other words, the injected mixture (123 and 124) comes into direct contact with the hotter combustion gases from the combustion of the acid gas 121. In other words, the furnace gases from the first zone 101a, which contain hot combustion gases, heat the water 123 and sulfur 124 in the second zone 101b by direct contact.

[0070] Furnace gas from the second zone 101b of the Claus furnace may be cooled in the heat exchanger 101c portion (e.g., as a WHB) of the Claus furnace 101. Steam 125, for example, high-pressure steam in the range of 600 pounds per square inch gauge (psig) to 900 psig, may be generated (e.g., from boiler feedwater, demineralized water, steam return, etc.) on the side of the heat exchanger 101c (e.g., a shell-and-tube heat exchanger) opposite the furnace gas.

[0071] Furnace exhaust gas 126 (furnace exhaust gas discharged from heat exchanger 101c as a cooled gas) (e.g., having a temperature of 315°C or less) exits heat exchanger 101c and enters condenser 102a (e.g., a shell-and-tube heat exchanger). Furnace exhaust gas 126 may be characterized as a process stream for recovering H2 produced in furnace 101. Condenser 102a outputs low-pressure steam 127a, liquid sulfur 128a to sulfur receiver 103, and process gas 129a to reheater 104a. Sulfur receiver 103 may be referred to as a sulfur pit, which may include a sulfur receiver, container, vessel, or the like. The sulfur receiver or sulfur pit may be a storage vessel where condensed sulfur is received, accumulated, and stored. The sulfur pit may also temporarily house elemental S extracted from an SRU or similar system and transported for further processing or to a transport system, etc.

[0072] Gas 129a may be referred to as the process stream when H produced in furnace 101 is recovered and H2S and SO2 are converted to elemental S via a Claus reaction. Condenser 102a condenses the elemental S gas / vapor in furnace exhaust gas 126 (using water as a cooling medium) to produce liquid sulfur 128a. Heat removed from furnace exhaust gas 126 vaporizes the water refrigerant to produce water vapor 127a (e.g., below 150 psig). Uncondensed furnace exhaust gas 126 is discharged to reheater 104a heat exchanger as process gas 129a. Process gas 129a contains H2, CO2, H2S, HO, SO2, and typically entrained residual S, and N2 if air is supplied to furnace 101 for oxygen gas 120.

[0073] Each Claus catalyst stage (of the H2 generation system 100 as an SRU or a Claus system) may include a reheater (e.g., 104a), a Claus catalytic converter 105 (a catalytic reactor vessel, which is a vessel having a bed of catalyst, e.g., a Claus catalyst), and a condenser (e.g., 102b). For clarity, only one Claus catalyst stage is shown. The system 100 may include two to four such catalyst stages. A typical Claus system may have two to three catalyst stages. While only one catalyst stage is shown, additional Claus catalyst stages (e.g., one additional catalyst stage as a second catalyst stage, or two additional catalyst stages as a second and third catalyst stage) are indicated by reference numeral 145.

[0074] The reheater 104a heat exchanger heats the process gas 129a to produce reheated process gas 130a that flows into the catalytic converter 105 of that catalyst stage. The reheater can facilitate control of the catalyst bed temperature within the catalytic converter 105. The reheater can be, for example, an indirect steam reheater (e.g., a shell-and-tube heat exchanger) in which the process stream (gas) is heated with steam as a heat carrier. The reheater can be, for example, a combustion reheater (e.g., a direct-fired heater) that burns fuel gas or acid gases to heat the process stream (e.g., a burner).

[0075] The reheated process gas 130a (gas mixture) flows into the first of a series of catalytic converters 105 (each with an associated condenser 102b heat exchanger for its respective catalytic stage). Again, for clarity, only one catalytic converter 105 is shown. Each catalytic converter 105 may perform a Claus reaction to convert H2S and SO2 in the process gas into elemental S and HO. The associated condenser 102b heat exchanger may condense elemental S gas / vapor from the process gas exiting the catalytic converter 105 into recovered liquid elemental sulfur 128b. The condenser 102b (e.g., a shell-and-tube heat exchanger) may also produce water vapor 127b (e.g., low-pressure water vapor below 150 psig) by vaporizing a water refrigerant. The process gas, minus the removed condensed sulfur 128b, may be advanced through the next reheater 104a to the next catalytic converter 105 in the next catalytic stage.

[0076] The process gas flows through a series of converters 105. After the second or third catalytic converter 105 (not shown) with a respective condenser heat exchanger 102b (not shown), the gas mixture 129b (as process gas) is heated in a reheater 104b to produce a heated process gas 130b as a process stream through the hydrogenation reactor 106 vessel.

[0077] The hydrogenation reactor 106 may be part of a typical or conventional Claus system. Hydrogen gas in the process gas 130b may be utilized for hydrogenation in the reactor 106. The reactor 106 may include a catalyst to promote hydrogenation. For example, the reactor 106 may include a catalyst bed of a cobalt-nickel catalyst or a cobalt-molybdenum catalyst. In some implementations, the reactor 106 may be similar to a hydrogenation reactor in a Shell Claus off-gas treating (SCOT) process / system. Compounds hydrogenated in the reactor 106 may include SO (e.g., trace amounts of SO in the process gas 130b), which is converted to HS. The objective of the hydrogenation may be to ensure that little or no SO transfers to the absorber 111. This is because SO may react with amines in the absorber 111 to form stable salts, which may reduce the absorber's ability to capture HS. In other words, SO2 may convert amines into species that are unreactive towards H2S.

[0078] The hydrogenated gas 131b (process gas with H product) discharged from the hydrogenation reactor 106 is cooled in a cooler 102c using water as a cooling medium. The cooler 102c may be, for example, a shell-and-tube heat exchanger. The condenser 102c may generate low-pressure steam (e.g., less than 150 psig) by vaporizing the water refrigerant using heat from the hydrogenated gas 131b. The cooler 102c discharges a process gas 132 (gas mixture), which is the low-temperature hydrogenated gas 131b cooled by the cooler 102c. The process gas 132 may contain H, CO, HO, N (if air is supplied for the oxygen gas 120), and residual HS (e.g., a relatively small amount of HS, less than 3 or 4 volume percent [vol%]).

[0079] The process gas 132 may be further processed to recover H from the process gas 132. In implementations, the process gas 132 may be referred to as Claus tail gas, but has a significant amount of H (produced by S steam reforming in the furnace 101). As described below, further processing of the process gas 132 may include removing water from the process gas 132 in a quench tower 108 and processing in an amine system (including an absorber 111 and a regenerator 115) to remove H2S to produce product H2 along with CO2 and any N2.

[0080] The process gas 132 (gas mixture) discharged from the condenser 102c may be further cooled by a heat exchanger 107 (e.g., a shell-and-tube heat exchanger), which produces water vapor (e.g., low-pressure [LLP] water vapor below 60 psig) from the water refrigerant medium in the heat exchanger 107.

[0081] The cooled process gas 133 (gas mixture as a process stream) discharged from the condenser 102c may flow into a quench tower 108 (e.g., a vertical vessel) where the gas is cooled (e.g., to below 60°C) by passing the gas countercurrently through water 134 having a lower temperature than the gas. The quench tower 108 vessel may have packing within the vessel, for example, to increase contact between the gas mixture 138 (flowing upward through the tower 108) and the water 134 (flowing downward through the tower 108). The water 134 may be referred to as quench water. Water vapor in the gas is condensed within the quench tower 108. This condensed water, as excess water, is removed from the quench tower 108 as water 135, which is discharged from the bottom of the quench tower 108.

[0082] A portion of the water 135 is sent to sour water treatment as water 137. Another portion of the water 135 is sent to furnace 101. Yet another portion 134 of the water 135 is sent as recycle via pump 109 (e.g., a centrifugal pump) through an air cooler 110 heat exchanger to the top of tower 108. Water 134 may be discharged from air cooler 110 at, for example, 60°C or below.

[0083] The overhead gas 138 discharged upwardly from the quench tower 108 is generally the process gas 133 entering the tower 108 minus any water vapor that has been condensed and removed from the process gas 133. The overhead gas 133 may be sent to a gas sweetening unit (amine treatment system) to separate the H2S from the H2 in the overhead gas 133. The amine treatment system includes an absorber 111 and a regenerative distillation column 115 (also called a desorber), as described, for example, in U.S. Pat. Nos. 10,525,404, 11,241,652, and 11,130,094, all three of which are incorporated herein by reference in their entireties.

[0084] The overhead gas 138 from the quench tower 108 may enter an absorber 111, such as a selective amine treatment system, to separate the H2S from the H2 gas. In particular, the overhead gas 138 from the quench tower 108 enters the bottom of the tower vessel (e.g., having packing) of the absorber 111 and flows upwardly in a countercurrent direction to the liquid aqueous amine flowing downwardly through the absorber 111. The amine absorbs the H2S from the gas 138 to produce an intermediate product gas 140 that is discharged upwardly from the absorber 111.

[0085] In implementations, amines do not readily absorb CO2, so CO2 is not emitted with H2S143. The selective amine process can operate on the principle that the chemical structure of selective amines (e.g., methyldiethanolamine (MDEA)) is not suitable for forming carbamates with CO2. This is because MDEA does not have a proton on the nitrogen and can capture dissolved CO2 (or carbonic acid) only through deprotonation. Similarly, amines capture H2S via deprotonation. However, the gas dissolution rate in the amine solution (H2S is faster than CO2) is sufficiently large that, using residence time and absorber temperature, the selective amine process can separate H2S from CO2 with high selectivity. Trace amounts of CO2 may be present in the H2S143 stream. In that case, the amount of CO2 is extremely small.

[0086] The intermediate product gas 140 (gas stream) has an H product. The intermediate product gas 140 is called intermediate because the gas 140 contains CO in addition to H. The intermediate product gas 140 contains H and CO, and may further contain N gas if air is used as the source of oxygen gas 120. Again, the intermediate product gas 140 discharged upward from the absorber 111 has H gas (and N gas if air is utilized as the oxygen 120 source) as products along with CO. The intermediate product gas 140 may be further processed to isolate the product H gas, for example, by membrane separation, pressure swing adsorption (PSA), etc.

[0087] A bottoms stream 139 comprising liquid amine with HS separated from the hydrogen gas exits the bottom of the absorber 111 vessel and is sent via pump 112 through heat exchanger 113 to regenerative distillation column 115 (also known as a desorber vessel) as feed. Bottoms stream 139 is enriched in HS. In regenerator 115, the HS is removed (desorbed) from the amine. HS-enriched gas 143 exits regenerative distillation column 115 upwardly and is recycled as feed to furnace 101. The complementary gas in this HS-enriched gas 143 recycled to furnace 101 can be carbon dioxide.

[0088] The regenerator (desorber) column 115 has an associated reboiler 116 heat exchanger (e.g., using steam as the heat carrier). Bottoms 141 from the bottom of the regenerator 115 is vaporized in the reboiler 116 (e.g., a steam reboiler) and flows upwardly through the column 115 as a vapor.

[0089] Bottoms 142 (liquid amine lean in H2S) from the bottom of regeneration column 115 is sent via pump 117 through heat exchanger 113 (e.g., a shell-and-tube heat exchanger) and heat exchanger 114 to the top of absorber column 111. Both heat exchangers 113, 114 cool bottoms 142.

[0090] Regeneration column 115 may be characterized as a regeneration column because it receives a bottoms stream 139 (relatively rich in HS) (referred to as "rich amine" because of the HS-rich amine) from absorber column 111 and returns a stream 142 lean in HS (referred to as "lean amine" because of the HS-lean amine) to absorber column 111. Again, intermediate product gas 140 discharged from absorber column 111 (e.g., discharged upwardly from absorber column 111) includes H (as a product), may include CO, and may further include N if air is used as a source of feed O 120.

[0091] As mentioned above, the first application category of direct heating of steam and sulfur vapor can be in an oxidizing environment, as shown in the example of Figure 8. Excess SO2 is present in the furnace. This excess SO2 can result from sulfur steam reforming reactions in the furnace. A catalytic converter is not used because there is little or no H2S in the furnace exhaust gas, or there is less than stoichiometric H2S relative to SO2.

[0092] FIG. 8 illustrates a hydrogen production system 200 using a Claus-type furnace 201. Sour acid gas 221 and recycled sulfuric acid 259 are partially combusted with oxygen 220 (e.g., from supplied air) in a first zone 201a of the Claus furnace 201. The oxygen gas 220 supplied to the first zone 201a can be obtained from supplied air or from an enriched / pure oxygen source. The operating temperature of the Claus furnace 201 in the first zone 201a can be, for example, in the range of 1200°C to 1600°C. A fuel gas 222, such as natural gas or methane, can be added to generate combustion and maintain the temperature of the furnace 201. The supplied acid gas 221 can be replaced by liquid elemental sulfur (in that liquid sulfur is supplied instead of the acid gas 221). In that case, combustion can be considered to occur in a sulfur burner instead of a Claus furnace. Can liquid sulfur (if supplied in place of acid gas 221) be supplied to both the first and second zones? The liquid sulfur supplied to the first zone may help raise the reaction temperature (via combustion of S), and the liquid sulfur supplied to the second zone may be for carrying out the sulfur steam reforming reaction.

[0093] When acid gas 221 is supplied, a mixture of water 223 and liquid sulfur 224 is injected into second zone 201b of Claus furnace 201. This may be characterized as direct heating of water 223 and liquid sulfur 224. The sulfur steam reforming (steam reforming of sulfur) reaction in second zone 201b occurs at temperatures above 445°C (718.15°K). Sulfur steam reforming (reaction of elemental S with HO) produces H, which is recovered downstream as a product; therefore, system 200 may be referred to as an H production system.

[0094] Furnace gas (with H2) from the second zone of the Claus furnace is cooled in the heat exchanger portion 201c of the Claus furnace 201. This cooling in the heat exchanger 201c (e.g., WHB) of the furnace 201 produces water vapor 225 on the other side of the heat exchanger 201c. In other words, on one side of the heat exchanger 201c (e.g., a shell-and-tube heat exchanger), the furnace gas is cooled, and on the other side of the heat exchanger 201c, the water refrigerant vaporizes and exits as water vapor 225 (e.g., high-pressure water vapor in the range of 600 psig to 1500 psig).

[0095] Furnace exhaust gas 226 is the furnace exhaust gas discharged from heat exchanger 201c. Furnace exhaust gas 226 (discharged from furnace section 201c) as an effluent gas from furnace 201 may have a temperature of, for example, 315°C or less. The temperature (e.g., 300°C to 315°C) may be important because it may correspond to a minimum value for the viscosity of molten sulfur. Furnace exhaust gas 226 flows into condenser 202 (e.g., a shell-and-tube heat exchanger) that produces low-pressure steam 227 (e.g., <150 psig), and liquid sulfur 228 flows to sulfur pit 203. Process gas 232 (low-temperature gas) is maintained at its discharge temperature by heat tracing 207 to avoid sulfur deposition. Process gas 232 discharged from condenser 202 may be referred to as a process stream because it contains H2 (produced in sulfur steam reforming in second zone 201b of furnace 201) that is recovered as a product.

[0096] The cooling medium for condenser 202 may be water (e.g., boiler feedwater, demineralized water, steam return water, etc.), which is vaporized on one side of the condenser 202 heat exchanger by heat from furnace exhaust gas 226 on the other side of the condenser 202 heat exchanger to produce water vapor 227. Condenser 202 condenses (using a water coolant) elemental S vapor in furnace exhaust gas 226 to produce liquid elemental sulfur 228 that is discharged to sulfur pit 203. Furnace exhaust gas 226 minus condensed elemental sulfur 228 is discharged to quench tower 208 as process gas 232 (e.g., a cold gas as it has a lower temperature than furnace exhaust gas 226). Process gas 232 includes H (produced in the sulfur steam reforming in second zone 201b), HS, SO, CO, and a relatively small amount of S vapor. Heat tracing 207 may be positioned along the conduit that carries the process gas 232 to the quench tower 208 to prevent or reduce sulfur deposition (from elemental S vapor) in the process gas 232. The heat tracing 207 may be, for example, electric tracing or steam tracing, as will be understood by those skilled in the art. The heat tracing 207 may be a component of a heat tracing system.

[0097] Process gas 232 flows into quench tower 208, where the gas mixture is cooled (e.g., to 60°C) by passing the gas countercurrently through aqueous sulfurous acid solution 234. Residual elemental S contained in gas stream 232 is converted to soluble polythionic acid in the presence of excess sulfurous acid. Therefore, no (or little) solids or slurry accumulate in quench tower 208. Quench tower 208 may remove SO2 by absorption of SO2 into aqueous sulfurous acid solution 234. Dissolved SO2 can be hydrated to sulfurous acid: SO2 + H2O → H2SO3. H2S can readily react with sulfurous acid to form sulfur colloids, which can subsequently form polythionic acid. Gas 240 (gas stream) discharged upward from quench tower 208 contains product H2 gas and CO2 if liquid sulfur is not fed to furnace 201 instead of acid gas 221. If air is the source of oxygen 220, gas 240 may further include N2 gas. Gas 240 may be utilized as a product or may be processed to isolate H2 gas as a product.

[0098] Make-up water (make-up water 237) may be added to bottoms stream 209 of water (aqueous sulfurous acid solution) discharged from the bottom of column 208 to produce water 234. Water 234 (aqueous sulfurous acid solution) is sent via pump 209 through air cooler 210 heat exchanger to the top of column 208. The acid in water 234 may be sulfurous acid and some trace amounts of polythionic acid. Water 234 may more accurately be referred to as aqueous sulfurous acid or aqueous sulfurous acid solution. Air cooler 210 may cool water 234 (using air as the cooling medium) to a temperature below 60° C., for example.

[0099] A portion 250 of water 234 (aqueous sulfurous acid solution) (e.g., upstream of cooler 210) is sent to oxidation tower 251 vessel. The portion 250 of water 234 may enter the top of oxidation tower 251 and may flow downward within tower 251 in a countercurrent direction to air 253 flowing upward through tower 251. Air 253 may be injected into the bottom of tower 251 via blower 254 (e.g., a centrifugal fan) (e.g., receiving ambient air or plant utility air). The oxygen gas in air 253 may oxidize the aqueous sulfurous acid solution (H2SO3) to sulfuric acid (H2SO4) within oxidation tower 251. Overhead gas 252 (e.g., air substantially depleted of oxygen) exiting oxidation tower 251 upward comprises air 253 minus O2 gas from the air 253 utilized for oxidation. Thus, the overhead gas 252 is N2 gas containing some O2 gas (eg, 2-4% by volume O2).

[0100] Aqueous sulfuric acid solution 255 is discharged from the bottom of column 251 (e.g., as a bottoms stream) and sent through membrane 256. Membrane 256 may be a nanofiltration (NF) membrane, a reverse osmosis (RO) membrane, or the like, and related membrane systems. Membrane treatment of acidic aqueous waste is well known in the mining industry. Polymeric membranes are applicable for sulfuric acid recovery. One example of an applicable polymeric membrane is TFC-HR (thin film composite polyamide membrane) from Koch Membrane Systems, available from Koch Industries, Inc., headquartered in Wichita, Kansas, USA. Another example of an applicable polymeric membrane is HYDRACoRe70pHT (sulfonated polyethersulfone membrane) from Hydranautics, a division of Nitto Denko Corporation, headquartered in Osaka, Japan. Yet another example is Desal KH (piperazine-based polyamide membrane) available from Suez Waters USA Inc., headquartered in Revose, Pennsylvania, USA.

[0101] The membrane 256 outputs sulfuric acid 257 (e.g., more concentrated than the influent sulfuric acid 255) as a retentate and relatively pure or clean water 223 as a permeate. A portion 258 (e.g., concentrated) of the sulfuric acid 257 is removed as a useful product. Another portion 259 of the concentrated sulfuric acid 257 is fed (e.g., conveyed via a conduit) to the furnace 201 to enrich the Claus furnace 201 with oxygen, aspects of which may be described in U.S. Pat. No. 4,826,670, U.S. Patent Application Publication No. 2022 / 0177306, and U.S. Patent Application Publication No. 2022 / 0199908, all three of which are incorporated herein by reference in their entireties.

[0102] In an embodiment, for the indirect heating described above, the elemental S steam and water for sulfur steam reforming may be heated, for example, via [1] a sulfur burner or [2] an electric heater or boiler. This heating of the S steam and water may be referred to as indirect heating of the sulfur steam reformer. For example, such may be characterized as indirect heating in that the S steam and water are not directly heated in the second section of the Claus furnace, called the sulfur steam reformer. Such may also be characterized as indirect heating because the heating in the sulfur, electric heater, or boiler may be indirect (not in direct contact with the heat carrier). For example, heating in a sulfur burner may be characterized as indirect because heat transfer is by conduction through the tube walls.

[0103] S steam containing water, heated via a sulfur burner or electric heater (or boiler), can be subjected to steam reforming in a sulfur steam reformer vessel to produce H. The H-containing reforming mixture discharged from the sulfur steam reformer can be combined with furnace exhaust gas discharged from a Claus furnace (if present). Additionally, as shown, indirect heating can be performed in conjunction with a reducing environment in the second zone of the Claus furnace, or an oxidizing environment in the second zone of the Claus furnace, or within the sulfur steam reformer if a Claus furnace is not utilized in the system.

[0104] Indirect heating for sulfur steam reforming in a Claus furnace or a sulfur steam reformer separate from the Claus furnace is described below: [a] a system with a reducing environment in the second zone of the furnace and indirect heating via a sulfur burner (flame heater) for a sulfur steam reformer separate from the Claus furnace (e.g., Figures 9A and 9B); [b] a system with a reducing environment in the second zone of the furnace and indirect heating via an electric heater or boiler for a separate sulfur steam reformer (e.g., Figures 10A and 10B); [c] a system with an oxidizing environment in the second zone of the furnace and indirect heating via a sulfur burner (or flame heater) for a separate sulfur steam reformer (e.g., Figure 11); and [d] a system with an oxidizing environment in the second zone of the furnace and indirect heating via an electric heater or boiler for a separate sulfur steam reformer (e.g., Figure 12). Heating in sulfur burners may be considered "indirect" heating because the sulfur and water are not in direct contact with the combustion gases, but instead heat is transferred by conduction through the tube walls.

[0105] The term "indirect" heating may mean that heat transfer in sulfur burners, electric heaters, and boilers is not by direct contact with the heat medium, but instead by indirect contact. In implementations, if the heating element of an electric heater is immersed in the fluid to be heated, this is generally not considered direct heating in this context.

[0106] 9A and 9B illustrate a hydrogen production system 300, which may be a sulfur recovery unit (SRU) (e.g., a Claus system) incorporating hydrogen production. The SRU includes a reactor (e.g., Claus furnace 301) that receives acid gas (e.g., 321) having HS and combusts the HS in a first zone of the furnace. To produce hydrogen, elemental sulfur and water are heated in a sulfur burner 344, and the sulfur is steam reformed in a sulfur steam reformer 347 (which receives a heated mixture of sulfur and water) to produce H gas for downstream recovery. In an implementation, the sulfur burner 344 and the sulfur steam reformer 347 may be characterized as being operationally parallel to the Claus furnace 301.

[0107] The SRU converts HS to elemental sulfur and recovers the elemental sulfur. The SRU includes a Claus reactor 301 that converts HS to elemental S gas (vapor) and a catalytic converter 305 (catalytic reactor vessel) downstream of the reactor 301 that converts HS to elemental S gas (vapor). Condenser heat exchangers (e.g., 302a, 302b, 302c) can condense the produced elemental S gas into elemental S liquid (e.g., 328a, 328b) for recovery (e.g., to sulfur pit 303 as molten sulfur).

[0108] 9A, sulfur burner 344 has a combustion chamber for burning sulfur and a tube side for receiving combustion gases for heating gas components on the shell side. During operation, sulfur burner 344 is supplied with liquid water 323, liquid elemental sulfur 324c, and H2S gas 343 on the shell side of burner 344. Sulfur burner 344 heats liquid water 323, liquid elemental sulfur 324c, and H2S gas 343 on the shell side (outside the heat exchanger tubes) to a temperature of at least 445°C (718.15°K).

[0109] The sulfur burner 344 discharges a mixture 346 of HO vapor, HS, and S vapor (heated to at least 445°C) from the shell side to a sulfur steam reformer 347. In implementations, the sulfur steam reformer 347 may be, for example, a relatively large pipe with a static mixer within the pipe to increase gas-to-gas contact. Internal to the steam reformer 347 may be a static mixer. Thus, the sulfur steam reformer may be thought of as a wide spot in a line with an in-line static mixer.

[0110] In implementations, no heat is added to reformer 347 other than the heat in incoming mixture 346. In other implementations, a heating element can be included external to the reformer. However, the temperature of stream 346 (e.g., about 600°C) may be considered adequate and without significant heat loss from the pipes. Sulfur steam reforming in sulfur steam reformer 347 involves reacting S steam with HO to produce H. Any HS present may convert SO produced by S steam reforming to liquid sulfur during the cooling stage. With regard to thermal management, stream 343 may generally not need to be heated and may be added to stream 348.

[0111] The sulfur steam reformer 347 discharges a reformed mixture 348 (a product of the sulfur steam reformer 347, which includes H) to an economizer 350. The economizer 350 cools the reformed mixture 348 and discharges a cooled reformed mixture 349 with H. The economizer 350 may be a shell-and-tube heat exchanger. The economizer may be a heat exchanger in which the cross-exchanged hot and cold sources (streams) are from a system / process (process stream). In other words, the economizer may recover heat from the system (process).

[0112] Economizer 350 recovers heat from reformed mixture 348 and transfers the heat to liquid sulfur 324a to heat (preheat) and increase the temperature of liquid sulfur 324a. Liquid sulfur 324a heated in economizer 350 is provided as [1] heated liquid sulfur 324b for combustion in sulfur burner 344 and [2] heated liquid sulfur 324c on the shell side (outside the tubes) of sulfur burner 344.

[0113] Heat in the sulfur burner 344 is provided in the combustion chamber and in the heat exchanger tubes (e.g., tube side) of the sulfur burner 344 via combustion (e.g., gross combustion) of liquid sulfur 324b and oxygen 320b. In implementations, air can be supplied to provide the oxygen 320b. Products of tube-side combustion in the sulfur burner 344 include SO2 (and N2 gas if air is the oxygen 320b source) and a slight excess of O2 gas (e.g., <2% by volume). These combustion gases 345 can be routed (e.g., via conduits) from the tube side of the sulfur burner 344 to be discharged to the first zone 301a of the Claus furnace 301.

[0114] In the Claus furnace 301, sour acid gases 321 (having HS as the acid gas) are combusted (e.g., partially combusted) in a first zone 301a of the Claus furnace 301 with oxygen 320a (e.g., from supplied air) and with oxygen gas from the combustion gas 345. A fuel gas 322, such as methane, can be added to the first zone 301a to maintain the temperature of the furnace 301. The gases in the furnace 301 react in a second zone 301b of the Claus furnace 301 (reactor). As is typical in Claus reactors, the reactions can include an oxidation reaction (e.g., 2HS + 3O → 2SO + 2HO) and a Claus reaction in which the Claus reactor 301 converts HS to elemental S (e.g., in a boiler 301c).

[0115] The furnace 301 gases are cooled (via water as a cooling medium) in the heat exchanger portion 301c of the Claus furnace 301. The heat exchanger portion 301c may be referred to as (or may be associated with) the boiler or waste heat boiler (WHB) of the Claus furnace 301. The heat exchanger portion 301c may generate (produce) water vapor 325 (e.g., high pressure steam in the range of 600 psig to 1500 psig) from the water coolant medium on the side of the heat exchanger 301c opposite the furnace gases.

[0116] Furnace exhaust gas 326 (the effluent gas discharged from furnace 301) and cooled reformed mixture 349 with H are sent to (e.g., combined into) condenser 302a (e.g., a shell-and-tube heat exchanger) where they are combined into gas stream 351. Condenser 302a generates (produces) water vapor 327a (e.g., low-pressure water vapor <150 psig) by vaporizing a water refrigerant medium with heat from stream 351. In condenser 302a, elemental S vapor in gas stream 351 is condensed (via the water refrigerant medium) and discharged as liquid sulfur 328a, e.g., to sulfur pit 303. Incoming gas stream 351, minus condensed liquid sulfur 328a, exits condenser 302a as process gas 329a (a low-temperature gas). Process gas 329a is referred to as process gas when recovering H.

[0117] Process gas 329a is routed through (and heated in) reheater 304a heat exchanger and exits reheater 304a as reheated process gas 330a. Reheated process gas 330a is routed through a series of catalytic converters 305 (each having an associated condenser 302b). After the second or third catalytic converter 302 (not shown, as indicated by reference numeral 345) with its respective condenser 302 (not shown, as indicated by reference numeral 345), gas 329b (process stream comprising H) is heated through reheater 304b heat exchanger to produce process gas 330b (heated) that is routed to hydrogenation reactor 306. Hydrogenation reactor 306 may be similar to hydrogenation reactor 106 of FIGS. 7A and 7B. Only a relatively small amount of H2 in the heated gas 330b is available for hydrogenation (eg, of SO2 to H2S) in reactor 306.

[0118] The hydrogenated gas 331b (containing H) discharged from the hydrogenation reactor 306 is cooled in a heat exchanger 302c, thereby producing water vapor 327c (e.g., low-pressure water vapor <150 psig). The cooler 302c discharges the cooled hydrogenated gas 331b as a process gas 332 (gas mixture). The process gas 332 is the low-temperature hydrogenated gas 331b cooled by the cooler 302c. The process gas 332 may contain H, CO, HO, N (if air is supplied for the oxygen gas 320a or 320b), and residual HS (e.g., a relatively small amount of HS, less than 3 or 4% by volume).

[0119] The process gas 332 may be further processed to recover H from the process gas 332. In implementations, the process gas 332 may be referred to as Claus tail gas, but has a significant amount of H (produced by S steam reforming in the sulfur steam reformer 347). As described below, further processing of the process gas 332 may include removing water from the process gas 332 in a quench tower 308 and processing in an amine system (including an absorber 311 and a regenerator 315) to remove H2S to obtain product H2 along with CO2 and any N2.

[0120] The process gas 332 (gas mixture) discharged from the condenser 302c may be further cooled by a heat exchanger 307 (e.g., a shell-and-tube heat exchanger) that generates water vapor (e.g., low-low pressure (LLP) water vapor below 60 psig) from a water refrigerant medium within the heat exchanger 307.

[0121] As described with respect to FIGS. 7A and 7B, the cooled process gas 333 (gas mixture as a process stream) discharged from the condenser 302c may flow into a quench tower 308 (e.g., a vertical vessel) where the gas is cooled (e.g., to below 60°C) by passing the gas countercurrently through water 334, which has a lower temperature than the gas. The quench tower 308 vessel may have packing within the vessel, for example, to increase contact between the gas mixture (flowing upward through the tower 308) and the water 334 (flowing downward through the tower 308). Water vapor in the gas is condensed within the quench tower 308. Liquid water 335, including this condensate, is discharged from the bottom of the tower 308 (e.g., as a bottoms stream). The discharged water 335 may be split into three water streams 334, 337, and 323. Water 337 may be sent to sour water treatment. Water 323 may be sent to the shell side of sulfur burner 344 (a furnace with heat exchanger tubes, as illustrated). Water 334 may be recycled via pump 309 through a cooler 310 heat exchanger to the top of tower 308. Cooler 310 may reduce the temperature of water 334 to below 60°C. The cooling medium in cooler 310 may be cooling water or air.

[0122] Overhead gas 338 exiting the top of quench tower 308 contains H, H, S, and CO. Overhead gas 338 is sent to a gas sweetening unit (selective amine process) which includes an absorber tower 311 vessel, which absorbs H, S into liquid amine, and a regenerative distillation tower 315 vessel, which removes H from the liquid amine, and related equipment. Examples of such systems for separating H, S from overhead gas 338, which is a mixture of H, H, S, and CO (and N, if air is used as the source of oxygen 320a to furnace 301 or the source of oxygen 320b to sulfur burner 347), are described in U.S. Patent Nos. 10,525,404, 11,241,652, and 11,130,094.

[0123] As described with respect to FIG. 7B, overhead gas 338 from quench tower 308 may enter absorber 311, such as a selective amine treatment system, to separate HS from H gas. In particular, overhead gas 338 from quench tower 308 enters bottom absorber 311 column vessel (e.g., having packing) and flows upward countercurrently to the liquid aqueous amine flowing downward through absorber 311. The amine absorbs HS from gas 338 to produce intermediate product gas 340, which is discharged upward from absorber 311. Intermediate product gas 340 has an H product. Intermediate product gas 340 is referred to as intermediate because gas 340 contains CO in addition to H. Intermediate product gas 340 contains H and CO and may further contain N gas if air is used as the source of oxygen gas 320a. Again, the intermediate product gas 340 discharged upwardly as a gas stream from absorber 311 has H gas (and N gas if air is used as the source of oxygen 320a or 320b) as a product along with CO.

[0124] Absorber 311 and regenerative distillation column 315 and associated equipment may be considered an amine treatment system (selective amine process).

[0125] A bottoms stream 339 comprising liquid amine with HS separated from the H gas exits the bottom of the absorber 311 vessel and is sent via pump 312 through heat exchanger 313 to a regenerative distillation column 315 (also known as a desorber vessel) as feed. The bottoms stream 339 is enriched in HS. In the regenerator 315, the HS is removed (desorbed) from the amine. A gas 343 enriched in HS (e.g., at least 50% HS by volume) exits the regenerative distillation column 315 upward. This gas 343 may be introduced into the shell side of a sulfur burner 344. This gas 343 sent to the sulfur burner 344 may include carbon dioxide.

[0126] The regenerator (desorber) column 315 has an associated reboiler 316 heat exchanger (e.g., using steam as the heat carrier). The bottoms 341 from the bottom regenerator column 315 is vaporized in the reboiler 316 (e.g., a steam reboiler) and flows upwardly through the column 315 as a vapor.

[0127] Bottoms 342 (liquid amine lean in H2S) from the bottom of regeneration column 315 is sent via pump 317 through heat exchanger 313 (e.g., a shell-and-tube heat exchanger) and heat exchanger 314 (e.g., a shell-and-tube heat exchanger) to the top of absorber column 311. Both heat exchangers 313, 314 cool bottoms 342. Heat exchanger 313 may be a cross-exchanger in which bottoms 342 is cooled by bottoms stream 339 from absorber 311 and bottoms stream 339 is heated by bottoms 342 from regeneration column 315.

[0128] Regeneration column 315 may be characterized as a regeneration column because it receives bottoms stream 339 (relatively rich in HS) (referred to as rich amine because of the HS-rich amine) from absorber column 311 as feed and returns a stream 342 lean in HS (referred to as lean amine because of the HS-lean amine) to absorber column 311. Again, intermediate product gas 340 exiting absorber column 311 (e.g., exiting absorber column 311 upwardly) includes H (as a product), may include CO, and may further include N if air is used as the source of feed O 320a or 320b.

[0129] 10A and 10B illustrate a hydrogen production system 400, which may be an SRU (e.g., a Claus system) incorporating hydrogen generation, similar to the hydrogen production system 300 of FIG. 9A, except that an electric heater 444 or boiler is used instead of a sulfur burner (e.g., 344 in FIG. 9A) to heat the S steam and HO that are supplied to a steam reformer 447 (e.g., 347 in FIG. 9A). The boiler, if used, may be, for example, a steam heat exchanger. Here, the boiler (if used) may have a flame that heats water and converts it to steam, which is further heated to produce superheated steam. This steam may be a calorie carrier that heats the mixture of S, HO, and HS. The boiler may be a steam superheater or a superheated steam boiler.

[0130] An electric heater 444 (or boiler) heats the liquid water 423, liquid sulfur 424b, and hydrogen sulfide gas 443. In an implementation, the electric heater may have an electric heating element within a vessel. The mixture is heated, for example, by a heating element within a baffled U-shaped vessel. The mixture 446 of water vapor, hydrogen sulfide, and sulfur vapor exiting the electric heater 444 is heated to a temperature above 445°C (e.g., to at least 500°C, or within the range of 450°C to 550°C) and then sent to a sulfur steam reformer 447. In the sulfur steam reforming within the sulfur steam reformer 447, the sulfur vapor reacts with HO vapor to produce H gas, which can be recovered downstream of the system 400. The reformed mixture 448 (the product of the sulfur steam reformer 447) is sent to an economizer 450. The temperature of the reformed mixture 448 exiting the reformer 447 may be, for example, at least 600°C, or in the range of 550°C to 650°C. The economizer 450 cools the reformed mixture 448, recovers heat from the reformed mixture 448, and transfers the heat to the liquid sulfur 424a to raise the temperature of the sulfur 424a (e.g., to at least 300°C, e.g., in the range of 300°C to 315°C). The temperature of the cooled reformed mixture 449 exiting the economizer 450 may be, for example, less than 300°C.

[0131] In the Claus furnace 401 (reactor), sour acid gases 421 (including H2S and CO2) are partially burned (combusted) with oxygen 420 (e.g., from supplied air) in a first zone 401a of the Claus furnace 401. The oxygen gas 420 can be obtained from supplied air or from an enriched or pure oxygen source. A fuel gas 422, such as methane or natural gas, can be added to facilitate maintaining the temperature of the furnace 401 at a desired temperature. The oxidation reaction in the furnace 401 includes, for example, 2H2S + 3O2 → 2SO2 + 2H2O, which involves the oxidation of incoming H2S from the supplied acid gases 421 by supplied oxygen (O2) gas 420 to produce SO2 and H2O vapor. The furnace gases react in a second zone 401b of the Claus furnace 401. The reaction may involve the Claus reaction 2H2S + SO2 → 3S + 2H2O, in which H2S gas reacts with SO2 to produce elemental S gas and H2O vapor. The overall reaction involving the oxidation reaction and the Claus reaction may be characterized as 2H2S + O2 → 2S + 2H2O.

[0132] The furnace gas from the second zone 401b is cooled in the heat exchanger section 401c of the Claus furnace 401. The heat exchanger section 401c utilizes water as a cooling medium. High pressure steam 425 (e.g., in the range of 600 psig to 900 psig) can be generated by vaporizing a water coolant on the side of the heat exchanger section 401c opposite the furnace gas using heat from the furnace gas.

[0133] Furnace exhaust gas 426 (e.g., effluent furnace gas discharged from heat exchanger section 401c, e.g., having a temperature below 315°C) and cooled reformed mixture 449 (containing H) from economizer 450 may be collected together as gas 451. Gas 451 flows into condenser 402a heat exchanger (using water as a cooling medium) which produces steam 427a (e.g., low-pressure steam below 150 psig), liquid sulfur 428a sent to sulfur pit 403, and process gas 429a (low-temperature gas) (containing H) sent to reheater 404a. Process gas 429a is referred to as process gas because it contains recovered H. In addition to H, process gas 429a may contain HS, SO, CO, and uncondensed or entrained S, and N (if air is provided for O gas 420). Process gas 429a is routed through (and heated in) the reheater 404a heat exchanger and exits the reheater 404a as reheated process gas 430a.

[0134] The reheated process gas 430a is sent to the first catalytic converter in a series of catalytic converters 405 (each with an associated condenser 402b). The series of catalytic converters 405 is indicated by reference numeral 445. For example, there may be a total of two or three catalytic converters 405 and a total of two or three condensers 402b. After the second or third catalytic converter 405 (not shown) with its respective condenser 402b (not shown), as indicated by reference numeral 445, gas 429b (process stream with H) from the final condenser 402b (not shown) is heated through reheater 404b heat exchanger to produce process gas 430b (heated) that is sent to the hydrogenation reactor 406.

[0135] Hydrogenation reactor 406 may be similar to hydrogenation reactor 106 of Figure 7A and hydrogenation reactor 306 of Figure 9A. A relatively small amount of H2 in heated gas 430b is available for hydrogenation in reactor 406 (e.g., to hydrogenate SO2 to H2S).

[0136] The hydrogenated gas 431b (containing H) exiting the reactor 406 is cooled in a heat exchanger 402c, which produces low-pressure steam 427c (e.g., less than 150 psig) by vaporizing liquid water, which is used as a cooling medium. The gas mixture exiting the cooler 402c is process gas 432, which is further cooled in heat exchanger 407 to produce cooled process gas 433 (a gas that is cooler than the process gas 432) and produce low-pressure steam (e.g., less than 60 psig). The cooled process gas 433 contains H, and may also contain CO, HO, N (if air is provided for the oxygen gas 420), and HS (e.g., less than 3 or 4% by volume).

[0137] The cooled process gas 433 flows into a quench tower 408, where it is cooled to 60°C by passing it countercurrently with cooling water 434. The water vapor in the cooled process gas 433 is condensed in the quench tower 408. Liquid water 435, including this condensate, is discharged from the bottom of the tower 408 (e.g., as a bottoms stream). A portion of the water 435 is sent as water 437 for disposal or for further processing, such as sour water treatment. Another portion of the water 435 may be sent as water 423 through an electric heater 444 (or boiler) to a sulfur steam reformer 447. Yet another portion 434 of the water 435 is sent via a pump 409 (e.g., a centrifugal pump) to the top of the tower 408 through an air cooler 410 heat exchanger as recycle. The water 434 may be discharged from the air cooler 410 at a temperature below 60°C, for example. As shown, water 434 may flow downward through the tower 408 in a countercurrent direction to the cooled process gas 438 flowing upward through the quench tower 408. The water 434 may be considered a quench medium that condenses or absorbs water from the cooled process gas 438.

[0138] The overhead gas 438 discharged upwardly from the quench tower 408 is generally the cooled process gas 433 entering the tower 408 minus any water vapor that has been condensed and removed from the process gas 433. The overhead gas 438 discharged from the top of the quench tower 408 contains H, HS, and CO (and N if air is the source of the oxygen 420 supplied to the furnace 401).

[0139] The overhead gas 433 may be sent to a gas sweetening unit (amine treatment system) to separate the H2S from the H2 in the overhead gas 433, as generally described with respect to the amine treatment systems of Figures 7B and 9B. The amine treatment system includes an absorber 411 and a regenerative distillation column 415 (also called a desorber). In implementation, an applicable exemplary amine treatment system (selective amine process) may be similar to that shown in Figure 16.

[0140] Gas 443 enriched in H2S (e.g., at least 50% H2S by volume) is discharged upward from regenerative distillation column 415. This gas 443 may contain CO2 and may be conveyed (e.g., via a conduit) through electric heater 444 (or a boiler) to sulfur steam reformer 447. An intermediate product gas 440 stream having H2 product and CO2 (and N2 gas if air is used as the source of oxygen gas 420) is discharged upward from absorber 411 column vessel. Intermediate product gas 440 may be utilized by a user (e.g., in a chemical process) or may be further processed to isolate the H2 product. Hydrogen gas may be extracted and purified from this gas 440 (a mixture of H2 and at least CO2) discharged upward from absorber 411.

[0141] The amine treatment system (selective amine process) includes pumps 412, 417 and heat exchangers 413, 414, 416 as described with respect to Figures 7B and 9B.

[0142] 11 is a hydrogen production system 500 similar to system 300 of FIGS. 9A and 9B in that it utilizes indirect heating via sulfur burners 544 to heat S and HO upstream of a sulfur steam reformer 547. Indirect heating of the sulfur steam reformer 547 is achieved by heating S gas and HO vapor in the upstream sulfur burners 544. System 500 incorporates indirect heating (by using sulfur burners 544) of S and water for sulfur steam reforming in sulfur steam reformer 547 that is separate from the Claus furnace 501.

[0143] 9A and 9B, system 500 has an oxidizing environment in a second zone 501b of the furnace and therefore does not have a Claus catalytic converter (Claus catalytic reactor). The second zone 501b of the Claus furnace has an oxidizing environment and performs the Claus reaction.

[0144] Similar to system 200 of FIG. 8, downstream of system 500 includes quenching with aqueous sulfurous acid solution to remove SO2 and H2S, and oxidation of excess aqueous sulfurous acid solution with oxygen gas from air to produce sulfuric acid.

[0145] The Claus furnace 501 (Claus-type reactor) receives acid gas 521 having H2S and combusts the H2S in a first zone 501a of the furnace 501. The Claus furnace 501 converts the H2S into elemental S gas (vapor).

[0146] To produce H, elemental S and HO are heated in sulfur burner 544, and S is steam reformed in sulfur steam reformer 547 (which receives the heated mixture of S and HO) to produce H gas for downstream recovery. In an implementation, sulfur burner 544 and sulfur steam reformer 547 may be characterized as being operationally parallel to Claus furnace 501.

[0147] 9A and 11, the streams 346, 546 exiting the sulfur burner (approximately 600°C) may have even higher temperatures (e.g., approximately 600°C) and greater fluctuations. This is generally acceptable as long as the temperature of the streams 346, 546 is greater than 445°C and less than 720°C.

[0148] Similar to the sulfur burners described above, sulfur burner 544 has a combustion chamber for burning sulfur and a tube side for receiving combustion gases for heating gas components on the shell side. During operation, sulfur burner 544 supplies and heats liquid water 523 and liquid elemental sulfur 524c on the shell side (outside the heat exchanger tubes) of sulfur burner 544 to a temperature of at least 445°C. From the shell side, sulfur burner 544 outputs a mixture of HO vapor and S gas 546 (heated to at least 445°C) to a sulfur steam reformer 547.

[0149] Similar to the sulfur steam reformers described above, sulfur steam reforming in sulfur steam reformer 547 involves reacting S gas with HO to produce H. Sulfur steam reformer 547 discharges reformed mixture 548 (the product of sulfur steam reformer 547, which includes H) to economizer 550. Economizer 550 cools reformed mixture 548 and discharges cooled reformed mixture 549 with H.

[0150] Economizer 550 recovers heat from reformed mixture 548 and transfers the heat to liquid sulfur 524a to heat (preheat) the sulfur 524a and raise its temperature. Liquid sulfur 524a is supplied to economizer 550 from sulfur pit 503 via pump 518 (e.g., a centrifugal pump). Liquid sulfur 524a heated in economizer 550 is supplied as [1] heated liquid sulfur 524b for combustion in sulfur burner 544 and [2] heated liquid sulfur 524c for the shell side (outside the tubes) of sulfur burner 544.

[0151] Heat in the sulfur burner 544 is provided in the combustion chamber and in the heat exchanger tubes (e.g., tube side) of the sulfur burner 544 via combustion (e.g., gross combustion) of liquid sulfur 524b and oxygen 520b. In implementations, air can be supplied to provide the oxygen 520b. Products of tube-side combustion in the sulfur burner 544 include SO2 (and N2 gas if air is the oxygen 520b source) and relatively small amounts of O2 gas (e.g., <2% by volume). These combustion gases 545 can be conveyed (e.g., via conduits) from the tube side of the sulfur burner 544 to be discharged into the first zone 501a of the Claus furnace 501.

[0152] As shown, in the Claus furnace 501, sour acid gases 521 (having HS as the acid gas) are combusted (e.g., partially combusted) in a first zone 501a of the Claus furnace 501 with O 520 (e.g., from supplied air) and with O gas from the combustion gases 545. A fuel gas 522, such as methane, can be added to the first zone 501a to maintain the temperature of the furnace 501. The gases in the furnace 501 react in a second zone 501b of the Claus furnace 501 (reactor). As is typical in Claus reactors, the reactions can include an oxidation reaction (e.g., 2HS + 3O → 2SO + 2HO) and a Claus reaction in which the Claus reactor 501 converts the HS to elemental S gas (vapor).

[0153] The furnace 501 gases are cooled (via water as a cooling medium) in a heat exchanger portion 501c of the Claus furnace 501. The heat exchanger portion 501c may be referred to as the boiler or WHB of (or may be associated with) the Claus furnace 501. The heat exchanger portion 501c may generate (produce) water vapor 525 (e.g., high pressure steam in the range of 600 psig to 1500 psig) from the water coolant medium on the side of the heat exchanger 501c opposite the furnace gases.

[0154] The furnace exhaust gas 526 (gas discharged from the furnace 501) and the cooled reformed mixture 549 with H may be combined to produce gas 551, which is fed to a condenser 502 (e.g., a shell-and-tube heat exchanger). The condenser 502 generates (produces) water vapor 527 (e.g., low-pressure water vapor <150 psig) by vaporizing a water refrigerant medium using heat from the gas 551. In the condenser 502, elemental S gas in the gas 551 is condensed (via the water refrigerant medium) and discharged as liquid sulfur 528, for example, to a sulfur pit 503. The incoming gas 551, minus the condensed liquid sulfur 528, is discharged from the condenser 502 to a quench tower 508 as process gas 532 (low-temperature gas). The process gas 532 is referred to as process gas when recovering H.

[0155] In implementations, heat tracing 507 may be disposed along the conduit that carries the process gas 532 to the quench tower 508 to prevent or reduce sulfur deposition from elemental S vapor in the process gas 532. As previously mentioned, the heat tracing 507 may be, for example, electric tracing or steam tracing. The heat tracing 507 may be a component of a heat tracing system.

[0156] Process gas 532 flows into quench tower 508, where the gas is cooled (e.g., to 60°C) by passing the gas countercurrently through aqueous sulfurous acid solution 534. Residual elemental S entrained in process gas 532 can be converted to soluble polythionic acid in the presence of excess sulfurous acid. Therefore, no (or very little) solids accumulate in quench tower 508. Gas 540 (gas stream) discharged upward from quench tower 508 contains product H gas along with CO. If air is the oxygen 520 source for upstream furnace 501, gas 540 may further contain N gas. Discharged overhead gas 540 can be utilized as a product or processed to further isolate H gas.

[0157] Make-up water 537 (e.g., demineralized water, steam reflux, etc.) may be added to bottoms stream 509 (which may be referred to as water or aqueous sulfite solution) exiting the bottom of column 508 to obtain water 534 (which may be aqueous sulfite solution). Water 534 is pumped via pump 509 through air cooler 510 heat exchanger to the top of column 508. Air cooler 510 may cool water 534 (using air as a cooling medium) to a temperature below 60°C, for example.

[0158] A portion 550 of water 534 upstream of cooler 510 is sent to the top of oxidation tower 551 vessel and flows downward through tower 551 in a countercurrent direction to air 553 flowing upward through tower 551. Air 553 may be introduced into the bottom of tower 551 via blower 554 (e.g., a centrifugal fan) (e.g., receiving ambient air or plant utility air). Oxygen gas in air 553 may oxidize the aqueous sulfurous acid solution (H2SO3) in tower 551 to H2SO4. Overhead gas 552 may contain air 553 minus O2 gas from air 553 utilized (consumed) for oxidation. Gas 552 discharged upward from tower 551 may contain N2 gas with some O2 gas (e.g., 2-4% O2 by volume).

[0159] Aqueous sulfuric acid solution 555 is discharged from the bottom of column 551 (e.g., as a bottoms stream) and sent through membrane 556. Membrane 556 may be a membrane system having a polymer membrane, an NF membrane, an RO membrane, or the like, and associated membrane system equipment. Membrane 556 discharges sulfuric acid 557 (e.g., more concentrated than the influent sulfuric acid 555) as a retentate and relatively pure or clean water 523 as a permeate. A portion 558 (e.g., concentrated) of sulfuric acid 557 is removed as a useful product. Another portion 559 of concentrated sulfuric acid 557 is fed (e.g., conveyed via a conduit) to furnace 501 to enrich Claus furnace 501 with oxygen, embodiments of which may be described in U.S. Pat. No. 4,826,670, U.S. Patent Application Publication No. 2022 / 0177306, and U.S. Patent Application Publication No. 2022 / 0199908.

[0160] Figure 12 illustrates a hydrogen production system 600 that operates in an oxidizing environment in the second zone 601b of the Claus furnace (thus, there is no Claus catalytic converter) and uses indirect heating via an electric heater 644 or boiler for the sulfur steam reformer 647. System 600 is similar to system 500 of Figure 11, except that system 600 uses an electric heater 644 (or boiler) instead of a sulfur burner to heat the S steam and HO for the sulfur steam reformer 647. Like system 500 of Figure 11, system 600 operates in an oxidizing environment in the second zone 601b of the furnace, as previously described.

[0161] The Claus furnace 601 (Claus-type reactor) receives acid gas 621 containing HS and combusts the HS in a first zone 601a of the furnace 601. The Claus furnace 601 converts the HS into elemental S gas (vapor). In the first zone 601a of the Claus furnace, the sour acid gas 621 (containing HS as the acid gas) is combusted (e.g., partially combusted) with O 620 (e.g., from supplied air). Sulfuric acid 659 may decompose to provide O for combustion. In particular, sulfuric acid 659 first dehydrates to produce SO , which decomposes to produce SO and O in the Claus furnace. A fuel gas 622, such as methane, may be added to the first zone 601a to maintain the temperature of the first zone 601a of the furnace at a specified temperature value or within a specified temperature range. The gases in the furnace 601 are reacted in a second zone 601b of the Claus furnace 601. The reaction may involve the Claus reaction, which converts H2S and SO2 to elemental S and H2O.

[0162] As described for the Claus furnace of the previous figure, furnace 601 gas (mixture of gases) is cooled (via water as a cooling medium) in heat exchanger section 601c of Claus furnace 601c. Heat exchanger section 601c may generate (produce) water vapor 625 (e.g., high-pressure water vapor in the range of 600 psig to 1500 psig) by using heat from the furnace gas to vaporize the water coolant on the side of heat exchanger 601c opposite the furnace gas. The furnace gas cooled in heat exchanger section 601c (e.g., to 315°C or below) is exhausted from furnace 601 as furnace exhaust gas 626. Furnace exhaust gas 626 may include, for example, H2S, SO2, S, HO, and CO2 (and N2 if air is provided as a source of O2 620).

[0163] Elemental sulfur 624b and water 623 are heated in an electric heater 644 (or boiler) to produce H, and S is steam reformed in a downstream sulfur steam reformer 647 (which receives the heated mixture of S and HO) to produce H gas for further downstream recovery. In an implementation, the electric heater may be located on or in the sulfur steam reformer 647 instead of having an upstream electric heater 644. In an implementation, the electric heater 644 and sulfur steam reformer 647 may be characterized as being operationally parallel with the Claus furnace 601. The liquid water 623 and elemental sulfur 624b are heated (e.g., as a mixture) by the electric heater 644 (or boiler) to a temperature of at least 450°C, or at least 500°C, or in the range of 450°C to 550°C. The heated mixture 646 of water 623 and sulfur 624b is discharged from the electric heater 644 to a sulfur steam reformer 647. The sulfur steam reforming in the sulfur steam reformer 647 involves reacting S gas with H2O vapor to produce H2 gas. The sulfur steam reformer 647 discharges a reformed mixture 648 (a product of the sulfur steam reformer 647 that includes H2) to an economizer 650. The reformed mixture 648 can have a temperature of at least 600°C, or in the range of 550°C to 700°C, for example.

[0164] The following three reactions may occur within a sulfur steam reformer: The following three reactions may be considered the steam reforming of sulfur: The following three reactions may be exothermic, resulting in a temperature increase through the sulfur steam reformer (e.g., from 500°C at the inlet to 600°C at the outlet).

[0165]

number

[0166] Economizer 650 cools reformed mixture 648 and discharges cooled reformed mixture 649 with H. Liquid sulfur 624a is received by economizer 650 from sulfur pit 603 via pump 618. In cooling reformed mixture 648, economizer 650 transfers heat from reformed mixture 648 to liquid sulfur 624a to heat (preheat) and increase the temperature of liquid sulfur 624a. The heated liquid sulfur 624a from economizer 650 is supplied as liquid sulfur 624b to electric heater 644 (or boiler) for further heating for steam reforming in sulfur steam reformer 647.

[0167] The furnace exhaust gas 626 and the cooled reformed mixture 649 (with H) may be combined to produce a gas 651 that is fed to a condenser 602 (e.g., a shell-and-tube heat exchanger). In the condenser 602, elemental S gas in the gas 651 is condensed (via a water refrigerant medium) and discharged as liquid sulfur 628, for example, to a sulfur pit 603. The condenser 602 generates (produces) water vapor 627 (e.g., low-pressure water vapor <150 psig) by vaporizing the water refrigerant medium with heat from the gas 651.

[0168] The gas 651 entering the condenser 602, minus the condensed liquid sulfur 628, exits the condenser 602 as process gas 632 (a cold gas) to the quench tower 608. The process gas 632 is referred to as the process gas when recovering H. To prevent or reduce condensation or deposition of elemental S in the process gas 632, heat tracing 607 (e.g., electrical tracing or steam tracing) may be placed along the conduit carrying the process gas 632 to the quench tower 608.

[0169] The construction and operation of the quench tower 608 system and the oxidation tower 651 system are generally similar to the construction and operation of the quench tower 508 system and the oxidation tower 551 system of the system 500 of FIG.

[0170] Process gas 632 enters quench tower 608, where the gas is cooled (e.g., to 60°C) by passing the gas countercurrently through aqueous sulfurous acid solution 634. Elemental S in process gas 632 can be converted to soluble polythionic acid in the presence of excess sulfurous acid in quench tower 608. Overhead gas 640 exits quench tower 608 as a gas stream, containing CO and product H gas, and N gas if air is the oxygen 620 source. Makeup water 637 (e.g., steam reflux, process water, demineralized water, etc.) can be added to bottoms stream 609 (water or aqueous sulfurous acid solution) exiting the bottom of tower 608 to obtain water 634 (aqueous sulfurous acid solution). Water 634 is pumped via pump 609 through an air cooler 610 heat exchanger to the top of quench tower 608. The air cooler 610 may cool the water 634 (using air as the cooling medium) to a temperature below 60°C, for example.

[0171] A portion 650 of water 634 is sent to the top of oxidation tower 651 vessel and flows downward through tower 651 in a countercurrent direction to air 653 flowing upward through tower 651. Air 653 may be introduced into the bottom of tower 651 via blower 654 (e.g., a centrifugal fan). The oxygen gas in air 653 may oxidize the aqueous sulfurous acid solution (H2SO3) in oxidation tower 651 to H2SO4. Overhead gas 652 may contain air 653 minus the O2 gas from air 653 utilized (consumed) in the oxidation. Overhead gas 652 exhaust stream may contain N2 gas with some O2 gas (e.g., 2-4% O2 by volume).

[0172] Sulfuric acid 655 exits the bottom of column 651 (e.g., as a bottoms stream) and is sent through a membrane 656 system. The membrane 656 system may be an NF system or an RO system. The membrane may be a polymeric membrane. Membrane 656 exits sulfuric acid 657 (e.g., more concentrated than the influent sulfuric acid 655) as a retentate and relatively pure or clean water 623 as a permeate. A portion 658 (e.g., concentrated) of sulfuric acid 657 is removed as a monetized product. Another portion 659 of concentrated sulfuric acid 657 is fed (e.g., conveyed via a conduit) to furnace 601 to enrich Claus furnace 601 with oxygen.

[0173] 13A and 13B illustrate a hydrogen production system 700 in which a Claus furnace is not used. Elemental sulfur 724b and water 723 are heated in an electric heater 744 (or boiler) and subjected to sulfur steam reforming in a downstream sulfur steam reformer 747 to produce H. Hydrogen sulfide 743 gas is fed to the electric heater 744 to create a reducing environment (excess H2S) within the electric heater 744 and sulfur steam reformer 747. To supplement the hydrogen sulfide 743 with additional H2S, an acid gas with H2S may be introduced into the hydrogen sulfide 743 stream.

[0174] Liquid water 723, liquid sulfur 724b, and hydrogen sulfide 743 gas are separately heated in parallel by respective electric heaters 744 (or in parallel by boilers) to a temperature of at least 445°C, or in the range of 440°C to 550°C. The heated water 723, sulfur 724b, and hydrogen sulfide 743 exiting heaters 744 combine to produce a mixture 746 of water vapor, hydrogen sulfide, and sulfur vapor. Mixture 746 may have a temperature of at least 445°C, or in the range of 440°C to 550°C. This mixture 746 is sent to a sulfur steam reformer 747, where H2 is produced by steam reforming of elemental sulfur.

[0175] The reformed mixture 748 (product of the sulfur steam reformer 747) exiting the sulfur steam reformer 747 may be at a temperature of at least 600°C, or in the range of 550°C to 700°C, for example. The reformed mixture 748 may be sent to an economizer 750 which cools the reformed mixture 748 with liquid sulfur 724a as a cooling fluid, and exits the economizer 750 as a cooled reformed mixture 749 at a temperature below 300°C, or in the range of 300°C to 315°C. Claus reactions may occur within the economizer 750 once the temperature drops below 445°C.

[0176] Liquid sulfur 724a may be fed from sulfur pit 703 via pump 718 to economizer 750. Economizer 750 transfers heat from reforming mixture 748 to liquid sulfur 724a to heat (preheat) liquid sulfur 724a to a temperature of at least 300°C, or in the range of 300°C to 315°C, resulting in heated (preheated) liquid sulfur 724b. As shown, liquid sulfur 724b is further heated in electric heater 744 and sent in mixture 746 to sulfur steam reformer 747.

[0177] The cooled reformed mixture 749 discharged from the economizer 750 flows into a condenser 702a (e.g., a shell-and-tube heat exchanger). In the condenser 702a, the elemental S gas in the cooled reformed mixture 749 is condensed (via a water refrigerant medium) and discharged as liquid sulfur 728, for example, into a sulfur pit 703. The condenser 702a generates (produces) water vapor 727a (e.g., low-pressure steam <150 psig) by vaporizing the water refrigerant medium using heat from the cooled reformed mixture 749.

[0178] The cooled reformed mixture 749 entering the condenser 702a, minus the condensed liquid sulfur 728, exits the condenser 702 as process gas 729 (with H produced upstream of the sulfur steam reforming) at a temperature, for example, below 190°C, or in the range of 160°C to 210°C. The gas 729 may contain trace amounts of entrained elemental sulfur. The process gas 729 is routed through a reheater 704 heat exchanger to heat the process gas 729 and produce heated process gas 730 (which is heated process gas 729). The reheater 704 heats the process gas 729 to produce process gas 730 at a temperature, for example, at least 220°C, or in the range of 200°C to 250°C, which is fed to the hydrogenation reactor 706. The process gas 730 is routed from the reheater 704 to the hydrogenation reactor 706.

[0179] The hydrogenation reactor 706 may be similar to the hydrogenation reactors 106, 306, and 406 of Figures 7A, 9A, and 10A, respectively. A portion of the H2 in the heated process gas 730 is used to carry out hydrogenation in the reactor 706 (e.g., hydrogenation of SO2 with H2 to obtain HS).

[0180] The hydrogenated gas 731 (containing H) exiting the hydrogenation reactor 706 may have a temperature of, for example, at least 272°C, or in the range of 240°C to 320°C, and is cooled to a temperature below 200°C or below 165°C in the heat exchanger 702c. The gas 731 may generally be free of S, since any S is converted to HS in the hydrogenation reactor 706. The cooler 702c produces low-pressure steam 727b (e.g., below 150 psig) by vaporizing liquid water used as a cooling medium. The gas mixture exiting the cooler 702c is process gas 732, which is further cooled in the heat exchanger 707 to produce cooled process gas 733 (a gas at a lower temperature than the process gas 732) and low-pressure steam (e.g., below 60 psig). The cooled process gas 733 contains H, CO, HO, and HS. The source of CO in gas 733 may be from acid gases introduced in stream 743. Because air is not typically supplied to system 700, gas 733 generally does not contain N.

[0181] The construction and operation of the quench tower 708 and selective amine treatment (including absorber 711 and regenerator 715 and related equipment) is generally similar to the construction and operation of such equipment and processes described with respect to Figures 7B, 9B, and 10B.

[0182] The cooled process gas 733 enters the quench tower 708 and flows upward countercurrently to the water 734 flowing downward through the quench tower 708. The water 734 is at a lower temperature than the cooled process gas 733. Therefore, the water vapor in the process gas 733 is condensed within the quench tower 708.

[0183] Liquid water 735, including this condensate, is discharged from the bottom of column 708 (e.g., as a bottoms stream). A portion of water 735, along with any added water 737, is sent as water 723 through electric heater 744 to sulfur steam reformer 747. A portion of water 735 is recycled via pump 709 (e.g., a centrifugal pump) through air cooler 710 heat exchanger to the top of column 708 as water 734 and flows downwardly through quench tower 708. Water 734 may be considered quench water, condensing or absorbing water from process gas 733 flowing upwardly through quench tower 708.

[0184] The overhead gas 738 discharged upwardly from the quench tower 708 is generally the cooled process gas 733 entering the tower 708 minus any water vapor in the process gas 733 that is condensed within the tower 708. This overhead gas 738 discharged from the top of the quench tower 708 comprises H, HS, and CO.

[0185] The overhead gas 738 may be sent to a gas sweetening unit (amine treatment system that is a selective amine process) to separate the H2S from the H2 in the overhead gas 738, as generally described with respect to the amine treatment systems of Figures 7B, 9B, and 10B. The amine treatment system includes an absorber 711 and a regenerative distillation column 715 (also called a desorber). An applicable exemplary amine treatment system (selective amine process) is shown in Figure 16.

[0186] Gas 743 enriched in H2S (e.g., at least 70% H2S by volume) is discharged upward from regenerative distillation column 715. This gas 743 may be primarily H2S and may contain relatively small amounts of CO2 in addition to H2S. Gas 743 is passed through an electric heater 744 (or boiler) to a sulfur steam reformer 747. Intermediate product gas 740 having H2 products and CO2 is discharged upward from absorber 711 column vessel as a gas stream. H2 gas can be extracted and purified. The amine treatment system (selective amine process) includes pumps 712, 717 and heat exchangers 713, 714, 716, as described with respect to Figures 7B, 9B, and 10B.

[0187] FIG. 14 illustrates a hydrogen production system 800 that does not use a Claus furnace. Elemental sulfur 824b and water 823 are heated in parallel in separate electric heaters 844 (or boilers) to at least 445°C (or within a range of 440°C to 550°C) for sulfur steam reforming in a downstream sulfur steam reformer 847 to produce H2. A mixture of sulfur 820 and water 823 may be heated in the same electric heater. However, the reason for heating these two streams in separate electric heaters is that the two streams do not have the same boiling point. Therefore, heating sulfur 820 and water 823 separately allows for better control of the heating process. Hydrogen sulfide is not supplied to the sulfur steam reformer 847 so that an oxidizing environment (excess SO2) is present in the sulfur steam reformer 847.

[0188] The water 823 and sulfur 824b exiting the heater 844 are combined to produce a mixture 846 of H2O and S vapor. The mixture 846 may have a temperature of at least 445°C (or in the range of 440°C to 550°C). The mixture 846 is sent to a sulfur steam reformer 847 where H2 is produced by steam reforming of elemental S.

[0189] The reformed mixture 848 (product of the sulfur steam reformer 847) discharged from the sulfur steam reformer 847 may have a temperature of, for example, at least 600°C, or in a range of 550°C to 700°C. The reformed mixture 848 may contain H and SO produced in the steam reforming of sulfur, and may also contain S and HO that did not react in the steam reformer 847. The reformed mixture 848 may be sent to an economizer 850 that cools the reformed mixture 848 with liquid sulfur 824a as a cooling fluid, and discharges a cooled reformed mixture 849 at a temperature below 300°C, or in a range of 300°C to 315°C.

[0190] As illustrated for liquid sulfur 724a in Figure 13A, liquid sulfur 824a may be fed from sulfur pit 803 via pump 818 to economizer 850. Economizer 850 transfers heat from reforming mixture 848 to liquid sulfur 824a to heat (preheat) liquid sulfur 824a to a temperature of at least 300°C, or in the range of 300°C to 315°C, resulting in heated (preheated) liquid sulfur 824b. As shown, liquid sulfur 824b is further heated in electric heater 844 and sent in mixture 846 to sulfur steam reformer 847.

[0191] The cooled reformed mixture 849 discharged from the economizer 850 is conveyed via a conduit to a condenser 802 heat exchanger (e.g., a shell-and-tube heat exchanger). In the condenser 802, elemental S gas in the cooled reformed mixture 849 is condensed (via a water refrigerant medium) and discharged as liquid sulfur 828, for example, to a sulfur pit 803. The condenser 802 generates (produces) water vapor 827 (e.g., low-pressure steam <150 psig) by vaporizing the water refrigerant medium using heat from the cooled reformed mixture 849.

[0192] The cooled reformed mixture 849 entering the condenser 802, minus the condensed liquid sulfur 828, exits the condenser 802 as process gas 832 (with H produced upstream of the sulfur steam reforming). The process gas 832 contains H, HO, SO, and trace amounts of S vapor. The process gas 832 is sent to a quench tower 808. Heat tracing 807 may be positioned along the conduit carrying the process gas 832 to the quench tower 808 to prevent or reduce the deposition of any elemental S entrained in the process gas 832.

[0193] Process gas 832 is introduced into the bottom of quench tower 808 and flows upward in a countercurrent direction to water 834 (quench water) flowing downward through quench tower 808. Water 834 may be an aqueous sulfurous acid solution. SO2 in process gas 832 may be absorbed by water 834 in quench tower 808 to produce water 834 as sulfurous acid. Elemental S in process gas 832 may be converted to soluble polythionic acid in the presence of excess sulfurous acid in quench tower 808.

[0194] The overhead gas 840 exiting the quench tower 808 may be primarily H gas, such as at least 90% H by volume. The overhead gas 840 (exited as a gas stream) may be considered a product stream. The overhead gas 840 may be treated to further increase the H purity.

[0195] Make-up water 837 may be added to bottoms stream 809 (water or aqueous sulfite solution) exiting the bottom of 808 to produce water 834 (aqueous sulfite solution). Water 834 is pumped via pump 809 through an air cooler 810 heat exchanger to the top of quench tower 808. Air cooler 810 may cool water 834 (using air as a cooling medium) to a temperature below 60°C, for example.

[0196] A portion 850 of the water 834 (sulfurous acid) is sent to the top of the oxidation tower 851 vessel and flows downward through the oxidation tower 851 in a countercurrent direction to the air 853 flowing upward through the tower 851. The air 853 may be introduced into the bottom of the tower 851 via a blower 854 (e.g., a centrifugal fan). The oxygen gas in the air 853 may oxidize the aqueous sulfurous acid solution (H2SO3) in the oxidation tower 851 to H2SO4. The overhead gas 852 may contain air 853 minus the O2 gas derived from the air 853 utilized (consumed) for oxidation in the tower 851. The overhead gas 852 discharge stream may contain N2 gas with some O2 gas (e.g., 2-4% O2 by volume).

[0197] Sulfuric acid 855 exits the bottom of oxidation tower 851 (e.g., as a bottoms stream) and is sent through a membrane 856 system, as previously described. Membrane 856 outputs sulfuric acid 857 (e.g., more concentrated than the influent sulfuric acid 855) as a retentate and relatively pure or clean water 823 as a permeate. Sulfuric acid 857 (e.g., concentrated) may be removed as a valuable product. As described, liquid water 823 is included in mixture 846, which is sent through electric heater 844 and sent to sulfur steam reformer 847.

[0198] General notes regarding the above diagrams are provided. A reducing environment means that there is excess H2S at the outlet of the sulfur steam reformer. SO2 produced by sulfur steam reforming is reduced to sulfur by the excess H2S. An oxidizing environment means that there is excess SO2 at the outlet of the sulfur steam reformer. The sulfur steam is oxidized to SO2 by water. The excess H2S can be in molar excess relative to SO2. The excess SO2 can be in molar excess relative to H2S. The reducing environment in Figure 13A is via stream 743 as acid gas containing H2S, and excess H2S is found in stream 748, which creates a reducing environment. The oxidizing environment in Figure 14 is stream 848 containing SO2 (from the reaction), which creates an oxidizing environment. Claus reactions can occur in the sulfur steam reformer in the reducing environments of Figures 9A, 10A, and 13A, but not in the oxidizing environments of Figures 11, 12, and 14. The Claus reaction generally does not occur in sulfur steam reformers 347, 447, 547, 647, 747, 847 because the temperature is above the boiling point of sulfur (445°C).

[0199] FIG. 15 illustrates a method 1500 for producing hydrogen (H) gas. The method includes steam reforming elemental S to produce H. The produced H can be utilized in the transportation and energy sectors. The produced H can be a feedstock for chemical processes, electrochemical processes, and the like. The reformed elemental S includes elemental S from a sulfur pit. As known to those skilled in the art, a sulfur pit in this context is a sulfur receiver, which can include a receiver, container, vessel, or the like. A sulfur receiver or sulfur pit can be a storage vessel where liquid sulfur is accumulated and stored. A sulfur pit can temporarily house elemental S extracted from an SRU or similar system. The elemental sulfur can then be transported from the sulfur pit for further processing or to a transportation system, etc.

[0200] At block 1502, the method includes steam reforming elemental S, such as from a sulfur pit. The reaction in steam reforming may include 2H2O + S → 2H2 + SO2. Thus, in steam reforming, H2 gas and SO2 are produced. Additional reactions may also occur. Steam reforming of S may produce a mixture including H2 gas, SO2, elemental S gas, and H2O vapor. The elemental S and H2O vapor in the mixture may be or may include unreacted components from the steam reforming.

[0201] To perform steam reforming (block 1502) (see, e.g., the systems of FIGS. 7A-8), the method may include injecting elemental sulfur from a sulfur pit into an intermediate zone (e.g., a second zone) of a furnace (e.g., a Claus furnace or Claus-type furnace), injecting water into the intermediate zone, performing steam reforming in the intermediate zone, and discharging furnace exhaust gas from the furnace as the mixture described above. The mixture may be discharged to a condenser. In implementations, the intermediate zone of the furnace may be characterized or referred to as a sulfur steam reformer (not stand-alone but integrated within the furnace). The method may include supplying oxygen gas and an acid gas containing hydrogen sulfide and carbon dioxide to the furnace for combustion in a first zone of the furnace. In that case, the mixture discharged from the furnace may include carbon dioxide. Furthermore, the method may include heating the elemental sulfur injected into the intermediate zone and the water injected into the intermediate zone by direct contact with combustion gas (furnace gas) from the first zone flowing into the intermediate zone. In implementations, the hydrogen production method 1500 may generally include producing hydrogen in a sulfur recovery unit (SRU) having a furnace.

[0202] To perform steam reforming (block 1502) (see, for example, the systems of FIGS. 9A-14), the method may include supplying elemental sulfur from a sulfur pit to a vessel that is a sulfur steam reformer, supplying water to the vessel, performing steam reforming of the elemental sulfur in the vessel, and discharging a mixture having H gas, SO gas, elemental S gas, and H O vapor from the vessel. The mixture may be discharged to a condenser. Supplying elemental sulfur may include heating the elemental sulfur in an economizer (heat exchanger) using heat from the mixture discharged from the vessel. In that case, the method may include discharging the mixture from the vessel (sulfur steam reformer) through the economizer to the condenser (also a heat exchanger). Supplying elemental sulfur (and water) may include heating the elemental sulfur (and water) upstream of the vessel (sulfur steam reformer). This heating may include heating the elemental sulfur (and water) in an electric heater, boiler, or sulfur burner. The method (see, e.g., the systems of FIGS. 9A-12) may include supplying oxygen gas and an acid gas comprising hydrogen sulfide and carbon dioxide to a furnace, and exhausting furnace exhaust gas (comprising CO) from the furnace and combining it with the mixture flowing from the sulfur steam reformer to a condenser. In implementations, the hydrogen production method 1500 may produce hydrogen in an SRU having a vessel (the sulfur steam reformer) and a furnace (e.g., a Claus furnace or Claus-type furnace).

[0203] In block 1504 (see, e.g., the systems of Figures 7A-14), the method includes condensing elemental sulfur gas in the mixture (from the steam reforming) in a condenser to liquid elemental sulfur and discharging the liquid elemental sulfur from the condenser, for example, to a sulfur pit. The method includes discharging process gas from the condenser, the process gas including H gas and SO produced in the steam reforming. The process gas generally does not include the liquid elemental sulfur that is discharged from the condenser to the sulfur pit.

[0204] At block 1506 (see, e.g., the systems of FIGS. 7A-14), the method includes processing the process gas to obtain a stream having H produced in the steam reforming as a product. For example (see, e.g., FIGS. 8, 11, 12, and 15), the method may include, at block 1506, quenching the process gas in a quench tower with water to absorb SO from the process gas into the water, and discharging a gas stream having hydrogen gas from the steam reforming as a product upward from the quench tower. Such a method may, in certain implementations, be applied in conjunction with a reducing environment (excess H2S) in the upstream steam reforming (block 1502). In another embodiment (e.g., FIGS. 13A and 13B), the method may include, at block 1506, hydrogenating the process gas to convert sulfur dioxide in the process gas to hydrogen sulfide to obtain a hydrogenated process gas (having H produced in the upstream reforming), quenching the hydrogenated process gas with water to remove water vapor from the hydrogenated process gas, and absorbing the hydrogen sulfide from the hydrogenated process gas into a liquid amine to produce a stream having as a product H produced in the steam reforming.

[0205] The method may include, at block 1506, catalytically converting hydrogen sulfide and sulfur dioxide in the process gas to elemental S and removing elemental S to produce a second process gas having H produced in the steam reforming (block 1502). The method may include hydrogenating SO in the second process gas to HS to produce a third process gas (hydrogenated process gas) having HS produced in the hydrogenation and H produced in the steam reforming. The method may include quenching the third process gas with water to remove water vapor from the third process gas, and absorbing HS from the third process gas into a liquid amine to produce a stream having H produced in the steam reforming as a product. In particular, the method may include: [1] quenching a third process gas with water in a quench tower to remove water vapor from the third process gas; [2] discharging an overhead gas from the quench tower to an absorber tower, where the overhead gas comprises the third process gas without the water vapor removed from the third process gas in the quench tower; [3] absorbing HS from the overhead gas with a liquid amine in the absorber tower; and [4] discharging a stream having HS produced in the steam reforming (block 1502) as a product upward from the absorber tower. See, e.g., Figures 7A, 7B, 9A, 9B, 10A, and 10B for block 1506.

[0206] Figure 16 shows an example of a system that performs amine treatment of sour gas, also known as amine scrubbing, gas sweetening (gas sweetening unit), and H2S removal. This system can be a selective amine process that separates (removes) H2S from sour gas to produce sweet gas. This amine treatment can be used to treat SRU tail gas (Claus tail gas).

[0207] Figure 16 may be an example of a selective amine process that can be implemented in the hydrogen production systems of Figures 7B, 9B, 10B, and 13B. The absorber shown in Figure 16 may be similar to absorbers 111, 311, 411, and 711, and the regenerator shown in Figure 16 may be similar to regenerators 115, 315, 415, and 715.

[0208] The system shown in Figure 16 uses an aqueous solution of alkylamines (hereinafter referred to as "amines") to remove HS from sour gas. Due to the presence of HS in the gas, the gas may be referred to as a "sour" gas. The illustrated sour gas entering the system may be similar to the overhead gas 138, 338, 438, 738 (process gas having HS and H) discharged upwardly from the quench towers 108, 338, 408, 708 of Figures 7B, 9B, 10B, and 13B.

[0209] Amines utilized in gas sweetening units (selective amine processes) can include diethanolamine (DEA), monoethanolamine (MEA), methyldiethanolamine (MDEA), diisopropanolamine (DIPA), and aminoethoxyethanol (diglycolamine) (DGA). Commonly used amines are the alkanolamines DEA, MEA, and MDEA.

[0210] 7B, 9B, 10B, and 13B, a gas (e.g., process gas) containing H and HS (as well as CO) is treated in a sweetening unit of FIG. 16 to remove HS. The resulting dissociated and ionized species are scrubbed out of the gas phase by an amine solution because they are more soluble in solution. Thus, at the outlet of the amine scrubber, the sweetened gas is depleted of HS.

[0211] The chemistry of the amine treatment can vary, particularly depending on the type of amine. Absorption of H2S into liquid amines is well known and widely used in the oil and gas industry to selectively remove H2S from this H2S stream before sending it to an SRU. As an example, in the case of MDEA (represented as CH3R2N, where R: -CH2CH2OH), the acid-base reaction occurs by reacting the positively charged ammonium group CH3R2NH + This involves protonation of the amine electron pair to form JPEG2025529521000008.jpg990 It can be represented by:

[0212] For example, the absorption of CO2 into amines JPEG2025529521000009.jpg9104 There are also examples of amines that are not MDEA, as shown in

[0213] The chemical structure of the selective amine MDEA is not suitable for forming carbamates; it has no proton on the nitrogen and can only sequester dissolved CO2 (or carbonate) through deprotonation. Similarly, this amine captures HS via deprotonation. The gas dissolution rate in the amine solution (HS is faster than CO2) is sufficiently large that, using residence time and absorber temperature, the selective amine process can separate HS from CO2 with high selectivity.

[0214] The system shown in Figure 16 is just one example of a typical amine gas treatment process and includes an absorber tower and a regenerator distillation column. Sour gas enters the bottom of the absorber tower (vessel) and flows upward through the absorber tower. An aqueous solution of amine enters the top of the absorber tower and flows downward through the absorber tower countercurrent to the upwardly flowing sour gas. This amine solution entering the absorber tower can be referred to as lean amine because it contains little or no HS. The absorber tower may have trays as shown or may contain packing, providing surface area for contact between the lean amine and the sour gas, thereby creating mass transfer stages for the acid gases to be absorbed from the sour gas into the lean amine. Sweet gas containing little or no HS (e.g., similar to intermediate products 140, 340, 440, 740) is discharged upward from the absorber tower for use or further processing. The bottom of the absorber tower discharges rich amine (rich in H2S from absorbing H2S from the sour gas). In the illustrated example, the level of the rich amine solution may be maintained at the bottom of the absorber tower via a control valve and a level sensor.

[0215] The rich amine can flow into a regenerator (regenerator distillation column) that removes HS from the rich amine, and the regenerator may discharge lean amine from its bottom. The overhead gas from which HS has been removed is discharged upward from the regenerator and may be partially condensed. Reflux may be sent to the regenerator via a reflux drum (vessel) and a reflux pump (e.g., a centrifugal pump). HS (e.g., similar to HS 143, 343, 443, 743) may be discharged from the system as a gas from the vapor space of the reflux drum. The HS may be sent, for example, to a sulfur burner or an SRU (e.g., a Claus process system) where the HS is converted to elemental sulfur. The lean amine is discharged from the bottom of the regenerator. The regenerator includes a steam reboiler that vaporizes a portion of the lean amine for return to the regenerator. The liquid amine is pumped through a cross exchanger (cooled by rich amine) and a cooler heat exchanger (eg, cooling water is the cooling medium) and fed to the absorber tower.

[0216] One embodiment is a method for producing hydrogen. The method includes steam reforming elemental sulfur from a sulfur pit, thereby producing hydrogen gas and sulfur dioxide, resulting in a mixture containing hydrogen gas, sulfur dioxide, elemental sulfur gas, and steam. The steam reforming of elemental sulfur can be carried out at a temperature ranging from 445°C to 720°C, for example. The method includes condensing the elemental sulfur gas in the mixture into liquid elemental sulfur in a condenser (heat exchanger) and discharging the liquid elemental sulfur from the condenser to the sulfur pit. The method includes discharging a process gas from the condenser, the process gas containing the hydrogen gas and sulfur dioxide produced in the steam reforming and typically excluding the liquid elemental sulfur discharged from the condenser to the sulfur pit.

[0217] In implementations, the method may include quenching the process gas with water in a quench tower to cause the water to absorb sulfur dioxide from the process gas, and discharging a gas stream upwardly from the quench tower that includes hydrogen gas from the steam reforming as a product.

[0218] In implementations, the method includes hydrogenating a process gas to convert sulfur dioxide in the process gas to hydrogen sulfide to obtain a hydrogenated process gas that includes hydrogen gas produced in the steam reforming as a product, quenching the hydrogenated process gas with water to remove water vapor from the hydrogenated process gas, and absorbing hydrogen sulfide from the hydrogenated process gas into a liquid amine to obtain a stream that includes hydrogen gas produced in the steam reforming as a product.

[0219] In implementations, the method includes catalytically converting hydrogen sulfide and sulfur dioxide in the process gas to elemental sulfur and removing the elemental sulfur to obtain a second process gas containing hydrogen gas produced in the steam reforming. In that case, the method may include hydrogenating the sulfur dioxide in the second process gas to hydrogen sulfide to obtain a third process gas containing the hydrogen sulfide produced in the hydrogenation and the hydrogen gas produced in the steam reforming. The method may include quenching the third process gas with water to remove water vapor from the third process gas, and absorbing the hydrogen sulfide from the third process gas into a liquid amine to obtain a stream containing the hydrogen gas produced in the steam reforming as a product. The method may include quenching the third process gas with water in a quench tower to remove water vapor from the third process gas; discharging an overhead gas from the quench tower to an absorber tower, the overhead gas comprising the third process gas without the water vapor removed from the third process gas in the quench tower; absorbing hydrogen sulfide from the overhead gas with a liquid amine in the absorber tower; and discharging a stream comprising hydrogen gas produced in the steam reforming as a product upward from the absorber tower.

[0220] In implementations, the method includes injecting elemental sulfur from a sulfur pit into an intermediate zone of a furnace, injecting water into the intermediate zone, where steam reforming occurs in the intermediate zone, and discharging a mixture that is a furnace exhaust gas from the furnace to a condenser. The method may include supplying oxygen gas and an acid gas comprising hydrogen sulfide and carbon dioxide to the furnace for combustion in a first zone of the furnace, whereby the furnace exhaust gas comprises carbon dioxide. The method may include heating the elemental sulfur injected into the intermediate zone and the water injected into the intermediate zone by direct contact with the combustion gas from the first zone. In these implementations, the method of producing hydrogen may be to produce hydrogen in a sulfur recovery unit (SRU) that includes a furnace.

[0221] In implementations, the method may include supplying elemental sulfur from a sulfur pit to a vessel that is a sulfur steam reformer, supplying water to the vessel, where steam reforming occurs within the vessel, and discharging the mixture from the vessel to a condenser. Supplying elemental sulfur includes heating the elemental sulfur in an economizer including a heat exchanger using heat from the mixture discharged from the vessel, and discharging the mixture includes discharging the mixture from the vessel through the economizer to the condenser. Supplying elemental sulfur includes heating the elemental sulfur upstream of the vessel, where the heating includes heating the elemental sulfur in an electric heater, boiler, or sulfur burner. Supplying water includes heating water upstream of the vessel, where the heating includes heating the water in an electric heater, boiler, or sulfur burner. The method may include supplying oxygen gas and an acid gas comprising hydrogen sulfide and carbon dioxide to a furnace, and discharging furnace exhaust gas from the furnace to combine with the mixture flowing to the condenser, where the furnace exhaust gas comprises carbon dioxide. In that case, the method of producing hydrogen may be to produce hydrogen in a sulfur recovery unit (SRU) comprising a vessel and a furnace.

[0222] Another embodiment is a hydrogen production system that includes a vessel (e.g., a furnace or stand-alone sulfur steam reformer) configured to receive elemental sulfur from a sulfur pit, steam reform the elemental sulfur into hydrogen gas and sulfur dioxide, and discharge a mixture comprising hydrogen gas, sulfur dioxide, elemental sulfur gas, and steam. The hydrogen production system includes a condenser heat exchanger that receives the mixture, condenses the elemental sulfur gas in the mixture into liquid elemental sulfur, and discharges the liquid elemental sulfur to the sulfur pit and a process gas comprising hydrogen gas and sulfur dioxide produced by steam reforming in the vessel.

[0223] In an implementation, the hydrogen production system includes a quench tower that quenches the process gas with water to remove water vapor from the process gas and discharges an overhead gas containing hydrogen gas produced in the steam reforming as product to an absorber tower.

[0224] In an implementation, the hydrogen production system includes: [A] catalytic stages that convert hydrogen sulfide and sulfur dioxide in the process gas into elemental sulfur and remove the elemental sulfur to obtain a second process gas comprising hydrogen gas produced in steam reforming, each catalytic stage comprising a catalytic converter and a condenser heat exchanger; [B] hydrogenation reactors that hydrogenate the sulfur dioxide in the second process gas to hydrogen sulfide to produce a third process gas comprising the hydrogen sulfide formed in the hydrogenation reactor and the hydrogen gas produced in the steam reforming; [C] a quench tower that quenches the third process gas with water to remove water vapor from the third process gas and discharges an overhead gas comprising the hydrogen gas produced in the steam reforming to the absorber tower; and [D] an absorber tower configured to absorb the hydrogen sulfide contained in the overhead gas from the quench tower into a liquid amine and discharge an overhead stream from the absorber tower comprising hydrogen gas from the steam reforming as a product.

[0225] In an implementation, the vessel includes a furnace having an intermediate zone for receiving elemental sulfur and water for steam reforming the elemental sulfur, the furnace configured to receive acid gas and oxygen gas for combustion in a first zone of the furnace and heat the elemental sulfur and water in the intermediate zone with combustion gas from the first zone, and the discharged mixture includes carbon dioxide. The hydrogen production system can be or include a sulfur recovery unit (SRU) including the furnace and catalytic stages, each including a catalytic reactor and a condenser heat exchanger. The first catalytic stage of the catalytic stages is configured to receive the process gas.

[0226] In an implementation, the vessel is a sulfur steam reformer that receives elemental sulfur and water, steam reforms the elemental sulfur, and discharges the mixture to a condenser. The hydrogen production system may include an economizer, which is a heat exchanger configured to receive elemental sulfur from a sulfur pit and heat the elemental sulfur with heat from the mixture discharged from the sulfur steam reformer through the economizer to the condenser. The economizer is configured to discharge the heated elemental sulfur for the sulfur steam reformer. The hydrogen production system may include a heater operably disposed between the sulfur pit and the sulfur steam reformer and heating the elemental sulfur upstream of the sulfur steam reformer. The heater may include an electric heater, boiler, or sulfur burner. The hydrogen production system may include a furnace (in addition to the vessel) that receives acid gases and oxygen and discharges a furnace exhaust gas that combines with the mixture flowing to the condenser. The furnace exhaust gas includes carbon dioxide. The hydrogen production may be or include a sulfur recovery unit (SRU) that includes a furnace and catalytic stages, each including a catalytic reactor and a condenser heat exchanger. A first one of the catalytic stages is configured to receive a process gas.

[0227] Although several implementations have been described, it will nevertheless be understood that various modifications may be made without departing from the spirit and scope of the disclosure.

Claims

1. steam reforming elemental sulfur from the sulfur pit, the steam reforming producing hydrogen gas and sulfur dioxide to produce a mixture comprising hydrogen gas, sulfur dioxide, elemental sulfur gas, and steam; condensing the elemental sulfur gas in the mixture into liquid elemental sulfur in a condenser and discharging the liquid elemental sulfur from the condenser to the sulfur pit, the condenser comprising a heat exchanger; Discharging a process gas from the condenser, the process gas including hydrogen gas and sulfur dioxide produced in the steam reforming; A method for producing hydrogen, comprising:

2. 2. The method for producing hydrogen as claimed in claim 1, wherein the steam reforming of the elemental sulfur is carried out at a temperature in the range of 445°C to 720°C, and the process gas does not contain the liquid elemental sulfur discharged from the condenser to the sulfur pit.

3. injecting said elemental sulfur from said sulfur pit into an intermediate zone of a furnace; injecting water into the intermediate zone, wherein the steam reforming occurs within the intermediate zone; Discharging the mixture, which is a furnace exhaust gas, from the furnace to the condenser; The method for producing hydrogen according to claim 1 , comprising:

4. supplying oxygen gas and an acid gas comprising hydrogen sulfide and carbon dioxide to the furnace for combustion in a first zone of the furnace; heating the elemental sulfur injected into the intermediate zone and the water injected into the intermediate zone by direct contact with combustion gases from the first zone; Including, the furnace exhaust gas comprises carbon dioxide; The method for producing hydrogen according to claim 3.

5. The method of claim 4 , comprising producing hydrogen in a sulfur recovery unit (SRU) that includes the furnace.

6. delivering the elemental sulfur from the sulfur pit to a vessel that is a sulfur steam reformer; supplying water to the vessel, wherein the steam reforming occurs within the vessel; Discharging the mixture from the vessel into the condenser; The method for producing hydrogen according to claim 1 , comprising:

7. 7. The method for producing hydrogen according to claim 6, wherein supplying the elemental sulfur comprises heating the elemental sulfur in an economizer including a heat exchanger with heat from the mixture discharged from the vessel, and discharging the mixture comprises discharging the mixture from the vessel through the economizer to the condenser.

8. 7. The method for producing hydrogen according to claim 6, wherein providing the elemental sulfur comprises heating the elemental sulfur upstream of the vessel, and wherein the heating comprises heating the elemental sulfur in an electric heater, a boiler, or a sulfur burner.

9. 7. The method for producing hydrogen according to claim 6, wherein supplying the water comprises heating the water upstream of the vessel, and wherein heating comprises heating the water in an electric heater, a boiler, or a sulfur burner.

10. supplying oxygen gas and an acid gas comprising hydrogen sulfide and carbon dioxide to the furnace; Discharging furnace exhaust gas from the furnace and combining it with the mixture flowing to the condenser, the furnace exhaust gas comprising carbon dioxide; The method for producing hydrogen according to claim 6, comprising:

11. The method of claim 10, comprising producing hydrogen in a sulfur recovery unit (SRU) comprising the vessel and the furnace.

12. 2. The method of claim 1, comprising quenching the process gas with water in a quench tower to absorb sulfur dioxide from the process gas into the water, and discharging a gas stream upwardly from the quench tower comprising hydrogen gas from the steam reforming as a product.

13. hydrogenating the process gas to convert sulfur dioxide in the process gas into hydrogen sulfide, thereby obtaining a hydrogenated process gas containing the hydrogen gas produced in the steam reforming as a product; quenching the hydrogenated process gas with water to remove water vapor from the hydrogenated process gas; Absorbing hydrogen sulfide from the hydrogenated process gas into a liquid amine to obtain a stream containing as a product the hydrogen gas produced in the steam reforming; The method for producing hydrogen according to claim 1 , comprising:

14. catalytically converting hydrogen sulfide and sulfur dioxide in the process gas to elemental sulfur and removing the elemental sulfur to obtain a second process gas comprising hydrogen gas produced in the steam reforming; hydrogenating sulfur dioxide in the second process gas to hydrogen sulfide to obtain a third process gas containing the hydrogen sulfide produced in the hydrogenation and hydrogen gas produced in the steam reforming; The method for producing hydrogen according to claim 1 , comprising:

15. quenching the third process gas with water to remove water vapor from the third process gas; Absorbing hydrogen sulfide from the third process gas into a liquid amine to obtain a stream containing as a product the hydrogen gas produced in the steam reforming; The method for producing hydrogen according to claim 14, comprising:

16. quenching the third process gas with water in a quench tower to remove water vapor from the third process gas; discharge an overhead gas from the quench tower to an absorber tower, the overhead gas comprising the third process gas without the water vapor removed from the third process gas in the quench tower; Absorbing hydrogen sulfide from the overhead gas into a liquid amine in the absorber tower; Discharging upwardly from the absorber tower a stream comprising hydrogen gas produced in the steam reforming as a product; The method for producing hydrogen according to claim 14, comprising:

17. a vessel configured to receive elemental sulfur from the sulfur pit, steam reform the elemental sulfur into hydrogen gas and sulfur dioxide, and discharge a mixture comprising hydrogen gas, sulfur dioxide, elemental sulfur gas, and steam; a condenser heat exchanger that receives the mixture, condenses elemental sulfur gas in the mixture into liquid elemental sulfur, and discharges the liquid elemental sulfur into the sulfur pit and a process gas that includes hydrogen gas and sulfur dioxide produced by steam reforming in the vessel; A hydrogen production system comprising:

18. 18. The hydrogen production system of claim 17, wherein the vessel comprises a furnace having an intermediate zone for receiving the elemental sulfur and water and steam reforming the elemental sulfur, the furnace configured to receive acid gas and oxygen gas for combustion in a first zone of the furnace and to heat the elemental sulfur and water in the intermediate zone with combustion gases from the first zone, and wherein the mixture comprises carbon dioxide.

19. 20. The hydrogen production system of claim 18, further comprising a sulfur recovery unit (SRU) comprising the furnace and catalytic stages, each catalytic stage comprising a catalytic reactor and a condenser heat exchanger, wherein a first catalytic stage of the catalytic stages is configured to receive the process gas.

20. 18. The hydrogen production system of claim 17, wherein the vessel comprises a sulfur steam reformer that receives the elemental sulfur and water, steam reforms the elemental sulfur, and discharges the mixture to the condenser.

21. 21. The hydrogen production system of claim 20, further comprising an economizer, which is a heat exchanger configured to receive the elemental sulfur from the sulfur pit and heat the elemental sulfur with heat from the mixture discharged from the sulfur steam reformer through an economizer to the condenser, wherein the economizer is configured to discharge the heated elemental sulfur for the sulfur steam reformer.

22. 21. The hydrogen production system of claim 20, further comprising a heater operably disposed between the sulfur pit and the sulfur steam reformer, the heater heating the elemental sulfur upstream of the sulfur steam reformer, the heater comprising an electric heater, a boiler, or a sulfur burner.

23. 21. The hydrogen production system of claim 20, comprising a furnace that receives an acid gas and oxygen and outputs a furnace exhaust gas that combines with the mixture flowing to the condenser, the furnace exhaust gas comprising carbon dioxide.

24. 24. The hydrogen production system of claim 23, further comprising a sulfur recovery unit (SRU) comprising the furnace and catalytic stages, each catalytic stage comprising a catalytic reactor and a condenser heat exchanger, a first catalytic stage of the catalytic stages configured to receive the process gas.

25. catalytic stages for converting hydrogen sulfide and sulfur dioxide in the process gas into elemental sulfur and removing the elemental sulfur to obtain a second process gas comprising hydrogen gas produced in the steam reforming, each catalytic stage comprising a catalytic converter and a condenser heat exchanger; a hydrogenation reactor for hydrogenating sulfur dioxide in the second process gas to hydrogen sulfide to produce a third process gas comprising the hydrogen sulfide formed in the hydrogenation reactor and hydrogen gas produced in the steam reforming; a quench tower that quenches the third process gas with water to remove water vapor from the third process gas and discharges an overhead gas containing hydrogen gas produced in the steam reforming to an absorber tower; an absorber tower configured to absorb hydrogen sulfide contained in the overhead gas from the quench tower into a liquid amine and discharge an overhead stream from the absorber tower containing hydrogen gas from the steam reforming as a product; The hydrogen production system according to claim 17, comprising:

26. 18. The hydrogen production system according to claim 17, further comprising a quench tower that quenches the process gas with water to remove water vapor from the process gas, and discharges an overhead gas containing hydrogen gas produced in the steam reforming as a product to an absorber tower.

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