Hydrogen sulfide removal method

Abstract

A method and apparatus for removing hydrogen sulfide from a process gas stream is presented in which the process gas is contacted with a liquid catalyst in an absorber to remove hydrogen sulfide and produce a purified process gas stream. The liquid catalyst containing absorbed hydrogen sulfide is directly fed as a mixture to a separate independent oxidation unit, without subjecting the waste liquid catalyst mixture to a separation treatment of removing dissolved gas. The mixture is introduced directly into a downcomer of the oxidation unit between the oxidation and flash compound section and the degassing section where hydrocarbon gases entrained from the process gas stream are separated and removed from the oxidation unit. The final mixture is removed from the oxidation unit and a first portion of the final mixture is recycled to the absorber and a second portion is recycled to a desulfurization unit physically located higher than the oxidation unit.

Description

[0001] Cross - Reference to Related Applications

[0002] This application claims priority to U.S. Provisional Application No. 63 / 431,415, filed on December 9, 2022, the entire content of which is incorporated herein by reference. Technical Field

[0003] The present invention relates to a method and combination of unit operations for selectively removing hydrogen sulfide (H₂S) gas from a hydrocarbon - containing process gas stream using a multivalent metal redox catalyst solution (such as an iron chelate absorbent) to cause the H₂S gas in the process gas stream to selectively react to form elemental sulfur. More specifically, the present invention is an improvement over known methods in that by removing the known degassing or flash tank unit operation downstream of the absorber vessel, the overall footprint of the process is significantly reduced. To further reduce the footprint, the elemental sulfur removal unit operation is positioned and elevated above the reaction / oxidation unit operation to allow for gravity feeding of the recycled filtrate, thus eliminating expensive pumping equipment and storage vessels. Background Art

[0004] Methods for removing H₂S from process gas streams are known. For example, U.S. Patent No. 5,126,118 uses an absorber, a degasser, a reactor / oxidation chamber, and a sulfur filtration process to remove H₂S from a process gas. The process gas is contacted with a liquid catalytic metal redox absorbent solution. The process is as Figure 1 shown. An acidic process gas (feed gas 5) containing H₂S is introduced into an absorber vessel 2, where the H₂S is absorbed by a multivalent metal redox solution introduced through line 10, producing a low - sulfur (treated) process gas stream 12, which is removed from the absorber 2. The spent liquid catalyst solution containing the absorbed H₂S is removed from the absorber through line 14. Hydrocarbons in the acidic gas feed will equilibrate with the liquid catalytic metal redox absorbent solution. These soluble hydrocarbons must be removed before reaching the oxidation section of the reactor / oxidizer unit operation 18 to avoid potential fires or explosions. The removal of the dissolved hydrocarbon gas is accomplished using a degassing unit operation including a flash tank 16 and associated piping, flow controls, valves, and other devices so that the spent catalyst solution removed from the absorber through line 14 is degassed.

[0005] The absorbed H₂S and the degassed spent catalyst solution are removed from the flash tank 16 through line 17 and introduced into the oxidizer 18. This is shown in Figure 2is schematically shown. The substantially fully oxidized polyvalent metal redox solution from the final stage 18a of the oxidizer chamber is recycled to the absorber via the degassing section 18b by the recycle solution pump. This reaction to form elemental sulfur occurs during the oxidation of the polyvalent metal redox solution reduced in the oxidation section 18a of the oxidation chamber 18. The elemental sulfur formed is removed from the process using a combination of unit operations 20, which includes a solid filter, a filter vessel, a filtrate pump, a filter drip pan, a bag filter and vessel, a wash water pipeline, a control valve, a wash water pump, and associated piping.

[0006] Existing processes known for removing H2S from a process gas feed have several disadvantages. One disadvantage is the space footprint occupied by the overall process, especially that associated with the degassing unit operation and the separate sulfur recovery unit operation. Another disadvantage is the capital cost associated with the equipment used in these unit operations, as well as the utility costs for the pumps and control valves required for operation. Another problem associated with using a separate degassing unit operation is the increased residence time experienced by the absorbed H2S and spent catalyst solution once removed from the absorber and then introduced into the degassing unit operation. Due to regeneration delays, the increased residence time can lead to a higher likelihood of sulfur settling and blockages. Regeneration delays also result in the formation of an undesired over-consumption / reduction of the catalyst, which can lead to a permanent loss of the polyvalent metal in the form of solid sulfides.

[0007] The improved hydrogen sulfide removal method described below shortens the residence time before reacting to form elemental sulfur, allows for the use of a gravity-fed process stream, reduces the space footprint occupied by the improved process, and eliminates many equipment and utility costs. Summary of the Invention

[0008] The methods and apparatus of the present disclosure are applicable to any H2S removal process that uses a polyvalent metal redox solution in two valence states to absorb H2S (with or without other impurities) and regenerate the metal redox solution.

[0009] The series of reactions involved in catalytically oxidizing a sulfur contaminant, such as hydrogen sulfide, to elemental sulfur using an iron chelate catalyst can be represented by the following reactions, where L generally represents two or more specific ligands selected for formulating the metal chelate catalyst mixture:

[0010] (1) H2S (气体) + H2O (液体) → H2S (水溶液) + H2O (液体)

[0011] (2) H2S (水溶液) → H + + HS -

[0012] (3) HS - + 2(Fe 3+ L2) → S (固体) + 2(Fe 2+ L2) + H +

[0013] By combining equations (1) to (3), the resulting equation is:

[0014] (4) H2S (气体) + 2(Fe 3+ L2) → 2H + + 2(Fe 2+ L2) + S (固体)

[0015] When using a mixture of polyvalent metal chelates to achieve the catalytic oxidation of hydrogen sulfide, in order to obtain an economically viable method for removing hydrogen sulfide from a gas stream, it is important that when the reaction solution is in contact with dissolved oxygen (preferably in the form of ambient air), in the same or a separate contact zone, the divalent iron chelates formed above are continuously regenerated by oxidation to trivalent iron chelates. When regenerating the metal chelate catalyst, a series of reactions occurring in the oxidizer section of the oxidation unit operation of the present disclosure can be represented by the following equations:

[0016] (5) O 2(气体) + 2H2O → O 2(水溶液) + 2H2O

[0017] (6) O 2(水溶液) + 2H2O + 4(Fe 2+ L2) → 4(OH - ) + 4(Fe 3+ L2)

[0018] By combining equations (5) to (6), the resulting equation (7) is:

[0019] (7) 1 / 2O2 + H2O + 2(Fe 2+ L2) → 2(OH - ) + 2(Fe 3+ L2)

[0020] And, when equations (4) and (7) are combined, the overall process can be represented by the following equation:

[0021] (8) H2S (气体) + 1 / 2O 2(气体) → S (固体) + H2O (液体)

[0022] A method and apparatus for removing H2S from a process gas using a catalytic metal redox absorption solution, absorbing H2S in an absorption chamber, and directly transporting the spent polyvalent metal redox solution to an oxidation and flash stage without flowing into a separate degassing unit operation. Before the spent liquid catalyst enters a series of separate oxidizer sections, in the oxidation and flash stage of the reactor / oxidation unit operation, the hydrocarbon substances absorbed in the acidic process gas stream to be treated are degassed.

[0023] The method of the present invention can be characterized as an anaerobic process scheme because the acidic feed gas containing H2S (which is substantially oxygen-free) is treated in an anaerobic absorber vessel, and the resulting mixture of the spent liquid catalyst, absorbed H2S, and any dissolved hydrocarbons does not come into contact with air or other oxygen-containing gas streams until after being treated in a separate oxidation unit operation. Importantly, the present method does not use a separate degassing unit operation, and thus does not use a flash tank, control valve, or associated piping. Instead, the mixture from the absorber directly enters the oxidation unit operation, which uses a separate vessel having multiple chambers or sections. The mixture is first introduced into a combined oxidation and flash stage, in which no oxygen-containing gas is introduced, or in some alternative embodiments, only a very small amount of air is introduced to assist with flow rate and / or liquid level control. The amount of air introduced should be controlled to ensure that the resulting gas mixture remains above the upper flammable limit. Alternatively, more air can be introduced to ensure that the resulting gas mixture remains below the lower flammable limit. In any case, the amount of oxygen in the oxidation and flash stage is not allowed to reach a flammable or combustible level. Combustible gas monitoring instruments can be used to monitor the gas outlet, and the air flow rate can be adjusted to maintain the desired concentration. Alternatively, the air flow rate can be controlled based on the ratio of the liquid and / or gas flow rates entering the absorber vessel.

[0024] Any dissolved hydrocarbon gas in the mixture is removed in the combined oxidation and flash stage and removed from the oxidation vessel for further treatment or mixed with the purified hydrocarbon gas removed from the absorber. The absorbed H2S entering the combined oxidation and flash stage is converted to elemental sulfur by contact with a fresh regenerated liquid catalyst solution, which flows in the same direction within the oxidation vessel and, after exiting the final oxidation section of the oxidation vessel, first removes any excess oxygen-containing gas through a degassing section and then enters the combined oxidation and flash stage. The fresh regenerated catalyst solution containing the highly oxidized polyvalent metal redox solution is mixed and contacted with the mixture taken from the absorber vessel (i.e., the H2S-loaded spent redox solution) to re-oxidize the dissolved HS - and S ＝and any multivalent metal sulfide (which may be chelated iron sulfide). The solution flowing out of the final oxidation stage is recycled to the oxidation flash composite stage through a degassing stage (preferably through a valve or other circulation control device), providing a continuous and controllable supply of oxidized metal to react with the sulfide, such that elemental sulfur is formed in the oxidation flash composite stage. This allows the solution to be circulated through the oxidation vessel at high speed, avoiding the high pumping costs typically associated with recycling a low-concentration multivalent metal solution through an absorber in stoichiometric amounts.

[0025] After leaving the reaction chamber, the spent catalyst solution is contacted with air or other oxygen-containing gas streams in a series of multiple oxidation stages, which may use distributors or other dispersion devices to introduce the oxygen-containing gas into a series of one or more oxidation stages. Contact of the reduced multivalent metal redox solution (i.e., the spent liquid catalyst) with the oxygen-containing gas re-oxidizes the multivalent metal redox solution to produce a highly oxidized multivalent metal redox solution (i.e., the regenerated liquid catalyst), which is removed from the oxidation vessel and then recycled back to the absorber vessel to contact the incoming acidic gas feed stream.

[0026] A portion of the regenerated liquid catalyst is removed from the recycle stream being sent to the absorber. The removed portion is continuously sent to a desulfurization unit operation. However, unlike known desulfurization unit operations, for example Figure 1 as shown, the method of the present disclosure requires that the sulfur unit operation be physically located above the oxidation vessel or at least lifted to a vertical height above the oxidation vessel. In other words, the desulfurization unit operation must be at a higher elevation than the oxidation vessel, preferably directly above the oxidation vessel, so that the desulfurization unit operation shares the same footprint as the oxidation vessel. Most preferably, the sulfur unit operation does not occupy a separate site outside the oxidation vessel, thus significantly reducing the overall process footprint.

[0027] Requiring the desulfurization device to operate at a higher elevation than the oxidation vessel allows the use of one or more dip tubes to gravity-feed the filtrate and / or collected liquid captured by the filter drip pan directly into the oxidation vessel. Using gravity to directly introduce the liquid stream into the oxidation vessel eliminates the need for pumps, piping, level controllers, storage vessels, and control valves, thus saving capital and energy costs. Preferably, one or more dip tubes are inserted directly below the liquid level in the low-pressure zone of the oxidation vessel. This can prevent the gas generated by the desulfurization unit operation from escaping from the process. The use of a drip pan provides a secondary seal for leaks or misfires generated during the cleaning of the filtered sulfur in the desulfurization operation. In a typical desulfurization process, the drip pan would drain into a secondary filtration process. In the method of the present disclosure, since the entire desulfurization unit operation is lifted above the oxidation vessel, gravity dip tubes can be used, thus avoiding the need and cost of a secondary filtration system, which also reduces the footprint of the method.

[0028] In summary, the methods and apparatus of the present disclosure allow for the continuous removal of hydrogen sulfide (H2S) gas from an acidic process gas stream by intimate contact with a catalytic multivalent metal redox solution in an absorption mass transfer zone (i.e., an adsorber vessel) to form a reduced multivalent metal redox solution containing dissolved HS - and S ＝ ions. The liquid removed from the absorber vessel is introduced directly into a separate oxidation unit without first introducing the reduced multivalent metal redox solution in a separate degassing unit operation. Instead, the reduced multivalent metal redox solution is introduced directly into a separate oxidation flash composite section of the oxidation unit where the dissolved HS - and S ＝ ions are converted to elemental sulfur and any dissolved hydrocarbon material is separated and discharged from the oxidation unit. This reduces the residence time of the absorbed HS - and S ＝ contained in the spent liquid catalyst solution prior to oxidation. By eliminating the known degassing unit operation, the liquid residence time can be reduced by up to 50%. The degassed multivalent metal redox solution in the oxidation flash composite section is then contacted directly in a series of multiple oxidation sections to regenerate the liquid catalyst by re-oxidizing the multivalent metal redox solution. The elemental sulfur formed is removed in a desulfurization unit operation that is physically located above the oxidation unit to reduce the process footprint and feeds the oxidation unit using one or more gravity feed draw tubes, thereby eliminating the need for pumps, level controllers, storage vessels, and associated piping. BRIEF DESCRIPTION OF THE DRAWINGS

[0029] The above and other aspects and advantages of the present invention will become more apparent from the following detailed description of the preferred embodiments in conjunction with the accompanying drawings, in which:

[0030] Figure 1 is a process flow diagram of a known H2S removal method;

[0031] Figure 2 is for Figure 1 a schematic flow diagram of the oxidation unit in;

[0032] Figure 3 is a process flow diagram of an embodiment of the H2S removal method of the present disclosure where the desulfurization unit operation is located at a high position directly above the oxidation unit operation;

[0033] Figure 4 is for Figure 3 a schematic flow diagram of the oxidation unit in;

[0034] Figure 5 is for Figure 3 a top view schematic diagram of the oxidation unit operation in;

[0035] Figure 6A is a flowchart of the first part of the method; and

[0036] Figure 6B is Figure 6A a flowchart of the second part of the method of Detailed implementation mode

[0037] Now turning to the drawings, first turning to Figure 3 , which shows a possible implementation of the process flow diagram of the H2S removal method of the present disclosure, generally represented by reference numeral 40 in the drawings. The method includes a separate absorber vessel 54, an oxidation unit operation 42, and a desulfurization unit operation 44. The oxidation unit 42 is generally as Figure 4 schematically shown, which includes an oxidation flash composite section 62a and a series of oxidation sections 62b, in which there are a plurality of downcomers 62d, weirs 62e, and baffles 62f for guiding and controlling the liquid flow within the oxidation unit 62. Figure 4 Four oxidation sections 62b are shown in - for absorbing oxygen from air or other oxygen-containing gas streams introduced through blower 80. Before the oxidation flash composite section 62a, there is a first downcomer in which the spent polyvalent metal solution with absorbed H2S from the absorber vessel 54 can enter the oxidation flash composite section 62a through the flow on the weir 62e. Alternatively, all or part of the spent polyvalent metal solution with absorbed H2S from the absorber vessel 54 can be directly added to the oxidation flash composite section 62a. The highly oxidized polyvalent metal redox solution, i.e., the regenerated liquid catalyst, flows into the first downcomer below the baffle 62f after first passing through the degassing section 62c, where entrained air or oxygen is removed from the regenerated solution to provide a gas-free liquid phase for pumping by the pump. In this improved design, oxygen can be prevented from entering the oxidation flash section 62a. The regenerated liquid catalyst flowing from the last oxidation section into the degassing section is substantially free of HS ＝ or S

[0038] The H2S-containing process gas, such as acid gas, flows into the absorber 54 through line 50, and fresh polyvalent metal redox solution (a combination of regenerated and / or newly added liquid catalyst) is pumped from the degassing section 62c through line 82 and pump 83 ( Figure 3)。Highly oxidized liquid catalyst in the material flow is introduced into absorber 54 through input pipeline 56, where a submerged conduit or other gas dispersion device (e.g., a distributor) ensures intimate contact with the liquid catalyst introduced through pipeline 56 and withdrawn from oxidation unit 62. The spent liquid catalyst, i.e., the multivalent metal redox solution loaded with H2S from absorber 54, flows by gravity or pressure difference through conduit 58 into a downcomer adjacent to oxidation flash composite section 62a. Importantly, there is no liquid / gas separator unit operation between absorber 54 and oxidation unit 62, so the residence time between the absorber and oxidation unit 62 is kept to a minimum, preferably less than 5 minutes.

[0039] The dissolved and absorbed hydrogen sulfide component removed from the process gas by adsorption and contained in the spent multivalent metal redox solution removed from absorber 54 and directly introduced into oxidation unit 62 reacts with the highly oxidized multivalent metal redox solution flowing out of downcomer 62d from degassing section 62c. In the oxidation flash composite section, the dissolved and absorbed hydrogen sulfide component is converted into elemental sulfur or soluble polysulfides that cannot be oxidized to thiosulfates or sulfates. Importantly, the dissolved hydrocarbon gas not previously removed from absorber 54 is removed and discharged through pipeline 60. This conversion even starts in the absorber as the catalyst begins to be reduced in the presence of hydrogen sulfide. There is little oxygen in the oxidation flash composite section, thus minimizing the risk of fire and / or explosion. Preferably, the amount of oxygen in the oxidation flash composite section is kept low enough so that the combustible gas is always above the upper flammable limit.

[0040] After the sulfur and the multivalent metal redox solution are degassed in the oxidation flash composite section, the solution flows into the first oxidation section 62b below baffle 62f, where the multivalent metal redox solution is oxidized by oxygen-containing gas (preferably air) flowing through one or more distributors located in each oxidation section. The partially oxidized multivalent metal redox solution flows over weir 62e and into each oxidation section 62b below baffle 62f. In each subsequent oxidation section, the partially oxidized solution is further oxidized by the oxygen-containing gas injected into each section. Starting from the last oxidation section (as shown in the fourth section in Figure 4 ), the completely and highly oxidized multivalent metal redox solution flows over weir 62e and into the degassing section, where the excess gas is removed and then contacts the spent liquid catalyst entering in downcomer 62d. Supplementary or fresh liquid catalyst can be added to any oxidation section 62b through pipeline 64.

[0041] As Figure 3As shown, elemental sulfur is removed from the process as a filtered solid using desulfurization unit operation 44 via line 84. Importantly, the desulfurization unit operation must be above the oxidation unit 62 in order to utilize one or more gravity feed draw pipes 66 or 70. A slip stream 78 is continuously fed to the desulfurization unit operation 44 and is withdrawn from the regenerated liquid catalyst stream 82 that is recycled to the absorber 54. This slip stream is forced through a solid filtration device 45, where line 76 introduces water to wash the sulfur solids collected by the filtration device. The washed and recovered sulfur solids are removed from the process via line 84. The filtrate stream 74 containing the regenerated liquid catalyst is gravity fed via draw pipe 70 directly into one or more oxidizer sections 62b. Since the desulfurization unit operation 44 is spatially above the vertical height of the oxidation unit 62, gravity is used as the driving force to introduce the filtrate into the oxidizer section, eliminating the need for storage tanks, pumps, or other associated piping and level controllers required in previously known processes. The use of the gravity feed draw pipe also allows the filtrate to be selectively introduced below the liquid level of the oxidizer section. The filtrate can be added to any section using the draw pipe (62b is a preferred method). However, since the filtrate flow is intermittent and typically much lower than the flow of the internal recycle, adding it anywhere in the vessel 42 will not have an adverse effect. The draw pipe also prevents any flash vapor or air from flowing back from the vessel to the area around the filter. Additionally, the draw pipe prevents the migration of odors or potentially flammable gases to unnecessary areas around the filter.

[0042] Another benefit of requiring the desulfurization unit operation 44 to be directly elevated above the oxidation unit 62 is that the filter drip pan 68 located below the solid filtration process 45 can also use the gravity feed draw pipe 66. The filter drip pan 68 is designed to collect any filtrate leaks that may occur during the filtration process, and the draw pipe 66 can directly introduce any collected leaked filtrate into one or more oxidizer sections 62b, again eliminating the need for storage tanks, pumps, or other associated piping and level controllers required in previously known processes.

[0043] A gas dispersion device, such as a distributor, can be used in one or more oxidizer sections 62b. Such a dispersion device can simply be formed by multiple slit and plugged hoses and connected to a pipe running along the bottom of one or more oxidizer sections. Similarly, other structured air distributors or diffusers known to those skilled in the art can be used. Excess oxygen-containing gas is removed from the oxidation unit 62 via exhaust line 72, and the exhaust line 72 also vents the degassing section 62c since sections 62b and 62c have a common gas space along the top of the oxidation unit 62.

[0044] The circular design of the oxidation unit 62 can be used to further reduce the total footprint of the process and equipment.Figure 5 One such design is shown, generally designated 100, and includes an oxidation flash composite chamber 102 and a series of oxidation chambers 104, 106, and 108. A degassing section 109 is located between the final oxidation section 108 and the downcomer 113, and spent liquid catalyst and absorbed H2S are introduced into the downcomer through line 58. Horizontally and vertically spaced weir and baffle combinations 122 and 124 define a downcomer 62d that separates the degassing chamber 109 from the oxidation flash composite chamber 102. Other weir and baffle combinations 114 / 116 and 118 / 120 define other downcomers and separate oxidation chambers 106 and 108. A single baffle 110 disposed between the oxidation flash composite chamber 102 and the first oxidation section 104 causes liquid to flow under the baffle 110 to reach the first oxidation section 104. Similarly, a single weir 111 disposed between the degassing chamber 10 and the final oxidation section 108 causes liquid to flow over the weir 111 to reach the downcomer 113. The baffle under which the liquid flows prevents fluid communication above the liquid level between adjacent sections. Although Figure 5 not shown, air distributors may be provided in the oxidizer sections 104, 106, and 108.

[0045] Figures 6A to 6B A block diagram illustrating an example of a continuous method for sequentially contacting a liquid reagent with a process gas and a second gas is shown. As an example, Figures 6A to 6B the method 200 shown in provides a method implementation that can be applied to the above-described equipment (as an example) related to Figures 3 to 5 The method 200 may include one or more operations, functions, or actions shown as one or more blocks 202 to 214. Although these blocks are shown in a sequential order, these blocks may also be executed in parallel and / or in an order different from the order described herein. Additionally, individual blocks may be combined into fewer blocks, divided into more blocks, and / or removed depending on the desired implementation.

[0046] Initially, at block 202, the method 200 includes introducing a process gas containing hydrocarbons and hydrogen sulfide into an absorber containing a liquid catalyst solution, where hydrogen sulfide is removed from the process gas stream and absorbed into the liquid catalyst solution, forming a spent liquid catalyst mixture.

[0047] At block 204, the method 200 further includes separately removing a clean process gas stream and the spent liquid catalyst mixture from the absorber.

[0048] At block 206, method 200 further includes introducing the spent liquid catalyst mixture directly into a downcomer or an oxidation flash composite section located in a separate, stand-alone oxidation unit without subjecting the spent liquid catalyst mixture to a separation process for removing dissolved gases, where the downcomer is located between the oxidation flash composite section and the degassing section, and where, when all or a portion of the spent liquid catalyst mixture is directly added to the downcomer, regenerated liquid catalyst is introduced into the downcomer and mixed with the spent liquid catalyst mixture to form a second mixture.

[0049] At block 208, method 200 further includes introducing the second mixture into the oxidation flash composite section where hydrocarbon gas entrained from the process gas stream is separated, vented, and removed from the oxidation unit, and where absorbed hydrogen sulfide is converted to elemental sulfur to form a third mixture.

[0050] At block 210, method 200 further includes introducing the third mixture into a first oxidation section where oxygen-containing gas is introduced and mixed with the third mixture such that the liquid catalyst is oxidized and a fourth mixture is formed.

[0051] At block 212, method 200 further includes removing the fourth mixture from the first oxidation section and introducing the fourth mixture into one or more separate oxidation sections until a final mixture containing regenerated liquid catalyst and elemental sulfur is formed.

[0052] At block 214, method 200 further includes separating elemental sulfur from the filtrate and injecting the filtrate directly into one or more oxidation sections using a gravity-feed draw pipe.

[0053] In one example, the method further includes removing the final mixture from the oxidation unit and recycling a first portion of the final mixture to the absorber, recycling a second portion of the final mixture to a desulfurization unit physically higher than the oxidation unit, and recycling a third portion of the final mixture within the oxidation unit. One third of this stream is recycled through the oxidizer via the downcomer. The liquid forms a circulating flow in the chamber and various streams can be added / removed therefrom.

[0054] In one example, the first portion of the final mixture recycled to the absorber is less than 75 weight percent of the final mixture. In another example, the flow of liquid through the oxidation unit is achieved by a density difference of the solution across the sections of the oxidation unit. In another example, the liquid catalyst is a multivalent metal redox solution and the oxygen-containing gas is air.

[0055] In another instance, the filtrate contains a portion of the liquid catalyst, and elemental sulfur is recovered from the water wash filtration device that produces the filtrate. In such an instance, the method can further include a liquid receiving tray located below the water wash filtration device, the liquid receiving tray receiving the liquid leaked from the desulfurization unit, wherein the received leaked liquid is gravity-fed through a suction pipe into one or more oxidizer sections.

[0056] In another instance, the concentration and flow rate of the liquid catalyst in the absorber provide an amount of the multivalent metal redox solution that is more than 100% stoichiometric amount required to react with all of the hydrogen sulfide in the process gas stream. In another instance, wherein the liquid catalyst is a catalytic ferric chelate solution, the catalytic ferric chelate solution is reduced to a ferrous solution by hydrogen sulfide gas in the absorber. In another instance, the degassing section removes free gaseous oxygen from the regenerated liquid catalyst. In another instance, the oxidation flash composite section removes free gaseous hydrocarbons from the second mixture, and the removed free gaseous hydrocarbons are removed from the oxidation unit through an outlet directly connected to the oxidation flash composite section.

[0057] In another instance, one or more oxidizer sections are separated by additional downcomers defined by weir plates and baffle structures, wherein one or more oxidizer stages remain in liquid communication with each other. In another instance, the method further includes an oxygen-containing gas outlet that removes excess oxygen-containing gas from one of the one or more oxidizer sections. In another instance, the method further includes a supplementary liquid catalyst pipeline directly connected to the oxidation flash composite section for introducing supplementary liquid catalyst, water, or other chemicals into the oxidation flash composite section. In another instance, the method further includes a control valve located between the absorber and a separate independent oxidation unit, the control valve being configured to reduce the pressure of the waste liquid catalyst mixture before the waste liquid catalyst mixture enters the separate independent oxidation unit and to convert any dissolved hydrocarbon substances into free gaseous hydrocarbons.

[0058] The above description of the specific embodiments will fully disclose the general nature of the present invention, so that others can, by applying existing knowledge, easily modify and / or adapt these specific embodiments for various applications without departing from the general concept. Therefore, such adaptations and modifications are intended to be understood within the equivalent meaning and scope of the disclosed embodiments. It should be understood that the wording or terminology herein is for the purpose of description and not limitation. In addition, the present disclosure is illustrated only by the preferred embodiments, and many changes can be made to the details or the arrangement of structures, component combinations, and process steps without departing from the spirit and scope of the present invention as claimed hereinafter.

Claims

1. A continuous method for bringing a liquid reagent into contact with a process gas and a second gas in sequence, the method comprising: (a) introducing a process gas containing hydrocarbons and hydrogen sulfide into an absorber containing a liquid catalyst solution, in which the hydrogen sulfide is removed from the process gas stream and absorbed into the liquid catalyst solution to form a spent liquid catalyst mixture; (b) separately removing a clean process gas stream and the spent liquid catalyst mixture from the absorber; (c) directly introducing the spent liquid catalyst mixture into a downcomer or an oxidation flash composite section located in a separate independent oxidation unit without subjecting the spent liquid catalyst mixture to a separation treatment for removing dissolved gases, wherein the downcomer is located between the oxidation flash composite section and a degassing section, and wherein when all or part of the spent liquid catalyst mixture is directly added to the downcomer, a regenerated liquid catalyst is introduced into the downcomer and mixed with the spent liquid catalyst mixture to form a second mixture; (d) introducing the second mixture into the oxidation flash composite section, in which hydrocarbon gas entrained from the process gas stream is separated, discharged and removed from the oxidation unit, and any remaining absorbed hydrogen sulfide is converted to elemental sulfur in the oxidation flash composite section to form a third mixture; (d) introducing the third mixture into a first oxidation section, in which an oxygen-containing gas is introduced to mix with the third mixture so that the liquid catalyst is oxidized and a fourth mixture is formed; (e) removing the fourth mixture from the first oxidation section and introducing the fourth mixture into one or more separate oxidation sections until a final mixture containing a regenerated liquid catalyst and elemental sulfur is formed; and (f) separating the elemental sulfur from the filtrate and directly injecting the filtrate into one or more oxidation sections using a gravity feed stream.

2. The method according to claim 1, wherein the method further comprises: removing the final mixture from the oxidation unit and recycling a first portion of the final mixture to the absorber, recycling a second portion of the final mixture to a desulfurization unit physically higher than the oxidation unit, and recycling a third portion of the final mixture inside the oxidation unit.

3. The method according to claim 2, wherein the first portion of the final mixture recycled to the absorber is less than 75% by weight of the final mixture.

4. The method according to any one of claims 2 to 3, wherein the filtrate contains a portion of the liquid catalyst, and the elemental sulfur is recovered from a water washing and filtering device that produces the filtrate.

5. The method according to claim 4, wherein the method further comprises a liquid receiving tray located below the water washing and filtering device, the liquid receiving tray receiving liquid leaked from the desulfurization unit, and the received leaked liquid being gravity-fed through a suction pipe into the one or more oxidation sections.

6. The method according to any one of claims 1 to 5, wherein the liquid flows through the oxidation unit by the density difference between the solutions of each stage of the oxidation unit and the corresponding downcomer.

7. The method according to any one of claims 1 to 6, wherein the liquid catalyst is a multivalent metal redox solution, and the oxygen-containing gas is air.

8. The method according to any one of claims 1 to 7, wherein the concentration and flow rate of the liquid catalyst in the absorber provide more than 100% stoichiometric amount of the multivalent metal redox solution required to react with all hydrogen sulfide in the process gas stream.

9. The method according to any one of claims 1 to 8, wherein the liquid catalyst is a catalytic ferric chelate solution, and the catalytic ferric chelate solution is reduced to a ferrous solution by hydrogen sulfide gas in the absorber.

10. The method according to any one of claims 1 to 9, wherein the degassing section removes free gaseous oxygen from the regenerated liquid catalyst.

11. The method according to any one of claims 1 to 10, wherein the oxidation flash composite section removes free gaseous hydrocarbons from the second mixture, and the removed free gaseous hydrocarbons are removed from the oxidation unit through an outlet directly connected to the oxidation flash composite section.

12. The method according to any one of claims 1 to 11, wherein the one or more oxidizer sections are separated by additional downcomers defined by a weir-baffle structure, and the one or more oxidizer sections maintain liquid communication with each other.

13. The method according to any one of claims 1 to 12, wherein the method further includes an oxygen-containing gas outlet for removing excess oxygen-containing gas from one of the one or more oxidizer sections.

14. The method according to any one of claims 1 to 13, wherein the method further includes a supplementary liquid catalyst pipeline directly connected to the oxidation flash composite section for introducing supplementary liquid catalyst, water or other chemicals into the oxidation flash composite section.

15. The method according to any one of claims 1 to 14, wherein the method further includes a control valve located between the absorber and the separate and independent oxidation unit, and the control valve is configured to reduce the pressure of the waste liquid catalyst mixture before the waste liquid catalyst mixture enters the separate and independent oxidation unit and convert any dissolved hydrocarbons into free gaseous hydrocarbons.

Images