Patent Application
20240132345
The present disclosure is directed to generating hydrogen while removing sulfur from a waste gas stream.
The production of natural gas often has associated hydrogen sulfide, which must be removed before the natural gas can be sold. Generally, this is performed through an absorption process that creates a sweetened gas stream and a waste gas stream. The waste gas stream is fed to a treatment and purification system to remove the hydrogen sulfide, and other sulfur compounds, in the form of sulfur. The sulfur can then be sold as a product.
As part of this procedure, a Claus plant is used. The Claus plant uses a reaction furnace to combust a portion of the hydrogen sulfide, forming sulfur dioxide. In the Claus reaction, the sulfur dioxide and the remaining hydrogen sulfide react to form water vapor and liquid sulfur. During the combustion process, a portion of the hydrogen sulfide dissociates, forming hydrogen and sulfur. A large proportion of the H2 and S will then re-associate back to form H2S, for example, as the combustion gases pass through a waste heat boiler that is downstream of the reaction furnace. Thus, the final H2 concentration in an overhead stream from a conventional tail gas treatment process generally varies between 3 and 5%.
An embodiment described in examples herein provides a method to form hydrogen while removing sulfur from an acid gas stream. The method includes feeding the acid gas stream into a porous burner in a reaction furnace, feeding an oxidizer stream into the porous burner, dissociating hydrogen sulfide into hydrogen and sulfur in the reaction furnace and injecting an inert coolant into the reaction furnace to cool reaction products forming a product gas stream.
Another embodiment described in examples herein provides a system to form hydrogen while removing sulfur from an acid gas stream. The system includes a reaction furnace including a porous burner, an inlet for an oxygen stream into the porous burner, an inlet for the acid gas stream into the porous burner, and a plurality of inlets on the reaction furnace for injecting an inert coolant.
Systems and methods are provided herein to increase the dissociation of H2S to H2 and S within a Sulfur Recovery Unit (SRU) setting, and enable the isolation of the H2. The dissociation is accomplished through partial oxidation of H2S in a direct-fired combustion chamber, using a “porous” burner to maximize H2S dissociation. The porous burner can allow the dissociation to approach or achieve equilibrium values. To minimize the re-association of H2 and S back to H2S, an accelerated cooling process is used, for example, through the injection of an inert stream into a reactive furnace proximate to the porous burner. The inert stream may include, but is not limited to, N2, argon, steam/H2O, or liquid sulfur. In some embodiments, an expansion shock is used to rapidly drop the temperature of the stream.
After the reactive furnace, the SRU includes units for the conversion of the H2S to elemental sulfur via the Claus process. The final tail gas stream from the SRU is then be processed in an additional unit that will separate and purify the H2 from the bulk gas stream. The H2 separation process may take the form of a membrane or an adsorption system. The high purity H2 stream can then be used within the plant for fuel gas or process feed stream, or exported from the plant as a product stream. The process also allows for CO2 sequestration.
A waste heat reboiler 114 is placed immediately downstream of the reaction furnace 102. The waste heat reboiler 114 further cools the fluid from the reaction furnace 102, while generating steam for other processes. Further steam is generated by a sulfur condenser 116 that is disposed downstream of the waste heat reboiler 114 to condense gaseous sulfur to liquid sulfur. The boiler feed water for the waste heat reboiler 114 and the sulfur condenser 116 is the heat exchange medium that is converted to steam. The boiler feed water is provided by a utilities unit, for example, in a refinery. The steam generated may be used inside the sulfur recovery unit, exported to other process units, or both. The liquid sulfur 118 is collected in a sulfur pit. The porous burner 104, reaction furnace 102, and waste heat reboiler 114 are discussed further with respect to
The vapor from the sulfur condenser 116 is then fed to a Claus plant 120. In various embodiments, the Claus plant 120 includes a 2-stage or 3-stage catalytic lineup for the reactions. A reduction-absorption tail gas treatment (TGT) process follows the Claus plant 120. This will allow for overall sulfur recovery efficiencies of 99.9+ percent.
In the TGT process, the tail gas from the Claus plant 120 is fed to a hydrogenation reactor 122. In the hydrogenation reactor, SO2 and sulfur vapor are hydrogenated back to H2S. Further, the reaction furnace 102 also produces CO as a side reaction. This CO is reacted with H2O in a water-gas shift reaction in the hydrogenation reactor to form H2 and CO2, which increases the overall yield of H2 in the process. Hydrogenation catalysts that can be used include a cobalt-molybdenum catalyst that is used for SRU service. The system is not limited to the cobalt-molybdenum catalyst, as in some embodiments, a cobalt-nickel catalyst, or a hydrotreating catalyst, is used.
The effluent from the hydrogenation reactor 122 is fed to a quench vessel 124. The quench vessel 124 rapidly cools the effluent, preventing further reactions from taking place. In the quench zones, or the quench vessel 124, an inert coolant is injected to reduce the temperature of the gas flowing through the quench vessel 124. In some embodiments, the quench vessel 124 is a water wash column.
The effluent from the quench vessel 124 is passed to an absorber 126, which uses a lean solvent to absorb H2S from the effluent forming a rich solvent stream 130 and a low H2S stream 132. The rich solvent stream 130 is passed to a stripper 134 that separates the H2S from the solvent, reforming a lean solvent stream that is returned to the absorber 126, and a recycle H2S stream 136 that is combined with the acid gas stream 106 that is fed to the porous burner 104.
The pressure of the low H2S stream 132 is boosted by a compressor 138 before being fed to a separation system 140. As the POST system 100 is configured to have an injection of concentrated, or substantially pure, O2 into the porous burner 104, the final overhead from the TGT primarily includes CO2, H2, and a saturated amount of H2O. The separation system 140 generates a hydrogen stream 142, a CO2 stream 144, and a liquid water stream 146. The hydrogen stream 142 and the CO2 stream 144 are substantially pure. As used herein, substantially pure indicates that the gas stream has a concentration of higher than about 90 vol. %, 95 vol. %, 99 vol. %, or higher.
In various embodiments, a portion of the hydrogen stream 142 is used to provide the hydrogen to the hydrogenation reactor 122. The remainder of the hydrogen stream 142 is used as a product stream, for example, as a reacted in other processes, as a fuel, or exported to a pipeline for sale. The CO2 stream 144 can be sold into a pipeline, for example, for enhanced oil recovery, or injected to a well for sequestration, among other uses.
In some embodiments, the liquid water stream 146 is removed from the other gases by condensation in a chiller, before separation of the remaining gases. The dewpoint of the remaining gases may affect the separation of H2 and CO2, for example, if an absorption unit is used. Accordingly, the chiller may be operated at a temperature of about 0.25° C. to about 5° C. to remove as much water as practical.
A separation system 140 is used to separate the H2 from the CO2. In various embodiments, the separation system 140 is a membrane separation system or an adsorption system, or a combination of both. These are discussed further with respect to
The POST system 100 maximizes the dissociation of H2S into H2 and sulfur in the thermal section of a Claus plant while simultaneously allowing for 99.9+% overall sulfur recovery efficiency via a 2-stage or 3-stage Claus plant with a Tail Gas Treatment (TGT) system, producing significant quantities of high purity H2 and allowing for sequestration of a high purity CO2 stream for decarbonization, e.g., through sequestration or sales.
The final process stream from the TGT absorber overhead contains CO2, H2, a saturated amount of H2O, and trace levels of H2S. This stream will be compressed to allow for the implementation of a membrane and/or adsorption unit(s) to separate the H2 from the process stream. The CO2, also being of high purity, is ready for sequestration for carbon capture efforts.
The porosity of the porous burner 104 is adjusted from the inlets 106 and 108 to the pores that open into the reaction furnace 102. In the beginning of the porous zone, the porosity is typically low, in the range of 5-10 vol. %, in order to “trap” the flame and avoid a flashback. In the reaction zone, porosity is in the range of 80-90 vol. % to maximize reaction volume and minimize velocity of the reactants.
In various embodiments, the porous burner 104 is made from refractory carbides, such as tungsten carbide, silicon carbide, or titanium carbide, among others. The porous burner 104 can be made from other materials, such as refractory ceramics that include yttrium-stabilized zirconia or yttrium-doped barium zirconate, among others. Other materials that can be used to form the porous burner 104 include silicides, such as molybdenum silicide, or tungsten silicide, among others. Nitrides can also be used to form the porous burner 104, such as silicon nitride and mixtures thereof.
In various embodiments, the POST system 100 increases the dissociation of H2S in the reaction furnace 102 by enriching the oxygen content of the oxidizer stream 108, for example, greater than about 90 vol. % purity, 95 vol. % purity, 99 vol. % purity, or higher. The use of the enriched oxygen increases the operating temperatures to be achieved, wherein higher temperatures result in higher levels of H2S dissociation. For example, temperatures as high as 1000° C., 1300° C., or 1500° C. can be achieved based on the limit of the refractory material for the porous burner 104. In other embodiments, normal air is used as the oxidizer stream 108.
Generally, a catalyst is not needed for the reaction due to the very high reaction temperature. Further, the materials used to form the porous burner 104 itself also function as catalysts. However, refractory sulfides, including cerium sulfide, molybdenum sulfide, or barium sulfide, and mixtures thereof, can be included in the material of the porous burner 104 to increase the reaction rate.
The equilibrium predictions of the dissociation in the reaction furnace 102 are as high as 50 mol. % of the total inlet fed stream content of H2S. This is performed by forcing the reaction furnace 102 to operate at as high a temperature as is practical, as well as implementing a quenching, or accelerated cooling, mechanism to minimize or eliminate re-association of H2 and S to H2S. The inert stream such as N2 or H2O will rapidly quench the RF temperature to 500-700° C. The quenching method is performed by the injection of an inert coolant 110, such as N2, H2O, or molten sulfur, through inlets 112 that are placed on the reaction furnace 102. For example, the inert coolant 110 is injected into the reaction furnace 102 through 3 to 10 inlets 112 can be placed in the same plane, radially around the shell of the reaction furnace 102. If liquid sulfur is used for the quenching, the injected sulfur will be immediately vaporized and will then be re-condensed and recovered in the first condenser. The liquid sulfur is sourced from the sulfur produced in the plant. Once the process stream is quenched, no further reaction of the H2 occurs in the Claus plant.
Generally, the inlets 112 are placed in the reaction furnace 102 at a location that is associated with optimum residence time for the maximization of the H2 yield, while maintaining the temperature long enough to destroy contaminants before quenching. In some embodiments, the inlets 112 may be placed proximate to the porous burner 104, to minimize the residence time. For example, the amount of contaminants may allow for a faster quench while in other embodiments higher contaminants may make a higher residence time more important. In some embodiments, having low amounts of contaminants, the optimum residence time in the reaction furnace 102 for maximum H2 yield is between about 0.0 seconds to about 0.8 seconds. In other embodiments, the inlets 112 are placed closer to the waste heat reboiler to allow for a greater destruction of contaminants, for example, giving a residence time of about 1.5 seconds. The determination of the location of the inlets 112 is, thus, a trade-off between contaminants and hydrogen yield.
In the embodiment shown in
The cooled reaction gases, and liquid sulfur condensed from the reaction gases, exit the tubes 306 into an exit header 316. The liquid sulfur drains from the exit header 316 through a liquid sulfur outlet 318. A mesh pad 320 blocks entrained sulfur liquid from being carried out of the sulfur condenser 116 with the cooled reaction gases, coalescing entrained sulfur droplets, which drop back into the exit header 316 and drain through the liquid sulfur outlet 318. The cooled reaction gases pass through the mesh pad 320 into a gas header 322, and exit through a gas outlet 324. From the sulfur condenser 116, the cooled reaction gases flow to a Claus plant for further recovery of sulfur.
From the first catalytic converter 404, the reacted gases flow to a condenser 406. The condenser 406 cools the reacted gases and condenses sulfur 118, which is flowed, along with sulfur from the sulfur condenser, into a sulfur pit 408 for storage. The water vapor that is formed during the Claus reaction remains as a gas as the temperature of the condenser 406 is above the boiling point of water.
The cooled gases from the condenser 406 are reheated in second reheater 410 and flowed into a second catalytic converter 412, which converts further amounts of SO2(g) and H2S(g) into S(g) and H2O(g). The reacted gases from the second catalytic converter 412 are flowed to a second condenser 414, which cools the reacted gases and condenses a further amount of sulfur 118, which is flowed into the sulfur pit 408.
In embodiments in which a third stage is used in the Claus plant, the cool gases from the second condenser 414 are reheated in a third reheater 416 and flowed into a third catalytic converter 418, which converts further amounts of SO2(g) and H2S(g) into S(g) and H2O(g). The reacted gases from the third catalytic converter 418 are flowed to a third condenser 420, which cools the reacted gases and condenses a further amount of sulfur 118, which is flowed into the sulfur pit 408.
In some embodiments, the cooled gases, termed a Claus effluent stream, from the third condenser 420 is flowed directly to the hydrogenation reactor 122. After the hydrogenation reactor 122, the hydrogenated gases are flowed through the quench vessel 124 (
The adsorber 600 may be operated in a two-phase cycle. In a first phase 608, a first column 602 is operated in an adsorption mode, while the second column 604 is operated in a desorption mode. In the first phase 608, the compressed feed gas 610 is fed to the bottom of the first column 602 to adsorb and remove CO2. The product gas 612, which comprises substantially pure H2, exits the top of the first column 602. A portion of the product gas 612 is fed to the top of the second column 604 as a purge gas 614 that desorbs CO2 from the packing of the second column 604, creating a CO2 stream 616. During the desorption process, the second column 604 may be heated to drive the desorption of the CO2.
The operation of the first phase 608 continues until CO2 starts to break through the packing of the first column 602. At that point, the operation is reversed for a second phase 618. In the second phase 618, the first column 602 is operated in a desorption mode, while the second column 604 is operated in an adsorption mode.
At block 706, a portion of the acid gas stream is combusted with the oxygen to form SO2 and dissociate H2S into H2 and S. At block 708, an inert coolant is injected into the reaction furnace for accelerated cooling of the reaction products, at least partially preventing the re-association of H2 and S back to H2S.
As described herein, referring to
After the removal of the sulfur in the TGT process, a separation system 140 separates H2 from CO2. The hydrogen formed in the process is provided as a hydrogen stream 142 for use as a fuel or a product. The POST system 100 also produces the CO2 stream 144 for sequestration or sales.
An embodiment described in examples herein provides a method to form hydrogen while removing sulfur from an acid gas stream. The method includes feeding the acid gas stream into a porous burner in a reaction furnace, feeding an oxidizer stream into the porous burner, dissociating hydrogen sulfide into hydrogen and sulfur in the reaction furnace and injecting an inert coolant into the reaction furnace to cool reaction products forming a product gas stream.
In an aspect, the oxidizer stream includes oxygen.
In an aspect, the oxidizer stream includes air or oxygen enriched air.
In an aspect, the method includes feeding the product gas stream to a Claus plant to remove at least a portion of sulfur compounds from the product gas stream as elemental sulfur, forming a Claus effluent stream. In an aspect, the method includes hydrogenating the Claus effluent stream to form a hydrogenated stream, quenching the hydrogenated stream to form a quenched stream, and feeding the quench stream to an absorber to remove hydrogen sulfide forming a hydrogen-enhanced stream. In an aspect, the method includes feeding the hydrogen-enhanced stream to a membrane separator to generate a hydrogen stream. In an aspect, the method includes passing the hydrogen-enhanced stream through a carbon dioxide scrubber to form a carbon dioxide stream. In an aspect, the method includes feeding a rich absorbent stream from the absorber to a regenerator to form a hydrogen sulfide recycle stream and a lean absorbent stream, and feeding the lean absorbent stream into the absorber. In an aspect, the method includes blending the hydrogen sulfide recycle stream into the acid gas stream prior to feeding the acid gas stream to the porous burner.
In an aspect, the method includes treating the product gas stream in a Claus plant to remove hydrogen sulfide, treating an effluent from the Claus plant in an absorber to remove residual hydrogen sulfide, and separating hydrogen from an effluent from the absorber.
In an aspect, the method includes generating steam in a waste heat boiler downstream of the reaction furnace.
In an aspect, the method includes condensing liquid sulfur in a condenser downstream of the waste heat reboiler.
Another embodiment described in examples herein provides a system to form hydrogen while removing sulfur from an acid gas stream. The system includes a reaction furnace including a porous burner, an inlet for an oxygen stream into the porous burner, an inlet for the acid gas stream into the porous burner, and a plurality of inlets on the reaction furnace for injecting an inert coolant.
In an aspect, the system includes a waste heat boiler downstream of the reaction furnace.
In an aspect, the system includes a Claus plant downstream of the reaction furnace. In an aspect, the system includes a hydrogenation reactor downstream of the Claus plant. In an aspect, the system includes a quench vessel downstream of the hydrogenation reactor. In an aspect, the system includes an absorber downstream of the Claus plant. In an aspect, the system includes a regenerator coupled to the absorber.
In an aspect, the system includes a compressor downstream of the adsorber. In an aspect, the system includes a hydrogen purification unit downstream of the compressor. In an aspect, the hydrogen purification unit includes a hydrogen separation membrane. In an aspect, the hydrogen purification unit includes an adsorption system.
Other implementations are also within the scope of the following claims.
