阅读说明：本技术 用于减硫的再活化加氢处理的催化剂 (Catalyst for reactivation hydrotreating for sulfur reduction ) 是由 T·麦克休 J·西曼斯 B·维肖利 P·金坎农 J·W·汤普森 A·恩德林 于 2020-05-22 设计创作，主要内容包括：本文公开了用于提供用于硫回收操作中的尾气净化的催化剂的方法、系统和组合物。本公开的各个方面涉及获得在不是尾气处理过程的第一过程中使用的催化剂,然后在尾气处理过程中使用如此获得的催化剂。例如,催化剂最初可以是加氢处理催化剂。所公开的方法和系统的一个有利方面是用过的加氢处理催化剂的再利用减少了操作者因处置用过的催化剂而产生危险废物。最终,这有助于减少催化剂生命周期的环境影响。所公开的方法和系统还提供了经济上有吸引力的用于尾气处理的高性能催化剂来源,这有利于用过的催化剂产生者、催化剂提供者和催化剂消费者。(Disclosed herein are methods, systems, and compositions for providing catalysts for tail gas cleanup in sulfur recovery operations. Various aspects of the present disclosure relate to obtaining a catalyst for use in a first process that is not an exhaust gas treatment process, and then using the thus-obtained catalyst in an exhaust gas treatment process. For example, the catalyst may initially be a hydrotreating catalyst. One advantageous aspect of the disclosed methods and systems is that the reuse of the spent hydroprocessing catalyst reduces the hazardous waste to operators from disposing of the spent catalyst. Ultimately, this helps to reduce the environmental impact of the catalyst life cycle. The disclosed methods and systems also provide an economically attractive source of high performance catalyst for exhaust gas treatment, which is beneficial to used catalyst producers, catalyst providers, and catalyst consumers.)

1. A method of treating a gas stream in a tail gas treatment process, the method comprising:

contacting the gas stream with a catalyst which has previously been used in a hydrotreating process and which has been reactivated by a reactivation process before contacting the gas stream in a tail gas treatment process, wherein

The gas stream comprises one or more elements selected from elemental sulphur (S)_x) Sulfur dioxide (SO)₂) Carbonyl sulfide (COS) and carbon disulfide (CS)₂) And wherein

In the presence of hydrogen (H)₂) In the presence of a reactivation catalyst converts the one or more sulfur species to hydrogen sulfide (H)₂S)。

2. The method of claim 1, wherein the hydrotreating process is selected from the group consisting of petroleum hydrotreating processes, Hydrodesulfurization (HDS), Hydrodenitrogenation (HDN), hydrogenation, Hydrodemetallation (HDM), Naphtha Hydrotreating (NHT), Diesel Hydrotreating (DHT), Kerosene Hydrotreating (KHT), jet fuel hydrotreating (JHT), atmospheric gas oil hydrotreating, Vacuum Gas Oil (VGO) hydrotreating, and Fluid Catalytic Cracker (FCC) feed hydrotreating.

3. The process of claim 1, wherein the catalyst comprises one or more group VIIIB metals and one or more group VIB metals supported on an inorganic oxide support material.

4. The process of claim 1, wherein the catalyst comprises cobalt and molybdenum supported on alumina.

5. The process of claim 1, wherein the catalyst comprises nickel and molybdenum supported on alumina.

6. The method of claim 1, wherein the reactivation process includes regeneration.

7. The method of claim 6, wherein the regenerating comprises heating the catalyst in an oxygen-containing atmosphere at a temperature of from 300 ℃ to 500 ℃ for 30 minutes or more.

8. The process of claim 6, wherein hydrocarbons are removed from the catalyst prior to the regeneration treatment by solvent extraction or by contacting the catalyst with steam, natural gas combustion products, hydrogen or nitrogen at a temperature of from 150 ℃ to 550 ℃.

9. The method of claim 1, wherein the reactivation process includes rejuvenation.

10. The method of claim 9, wherein the rejuvenating comprises impregnating the catalyst with a solution containing a chelating agent and drying the catalyst at a temperature of 50 ℃ to 300 ℃.

11. The method of claim 10, wherein the chelating agent is an organic acid.

12. The method of claim 1, wherein the reactivation catalyst is presulfided prior to contact with the gas stream in the exhaust gas treatment process.

13. A method according to claim 1, wherein the reactivation catalyst is presulfided prior to contact with the gas stream in the exhaust gas treatment process.

14. The method of claim 1, wherein the reactivated catalyst is sized, reshaped and/or reformulated prior to contacting with the gas stream in the exhaust treatment process.

15. The method of claim 14, wherein the reactivated catalyst is sized by length grading the catalyst.

16. The method of claim 14, wherein the resizing, reshaping, and/or reformulating comprises grinding the reactivated catalyst into a fine powder and then reshaping the reactivated catalyst.

17. The process of claim 14, wherein the reactivated catalyst is resized from having a diameter of 1.3 to 2.5mm to having a diameter of 3 to 5 mm.

18. The method of claim 1, wherein contacting the gas stream with the reactivated catalyst comprises combining the reactivated catalyst with a second catalyst, wherein the second catalyst provides a lower pressure drop than the reactivated catalyst.

19. The method of claim 1, wherein contacting the gas stream with a reactivated catalyst comprises a short loading of reactivated catalyst.

20. The process of claim 1, wherein the reactivated catalyst exhibits a pressure drop of 0.05 to 0.20 psi/foot when sock loaded in ambient air and tested at a superficial velocity of 100 feet/minute.

21. A method of forming a reactivated catalyst for use in an exhaust treatment process, the method comprising:

obtaining a used catalyst from a hydroprocessing process, and

reactivating the catalyst to form a reactivated catalyst, wherein

When it is mixed with a mixture containing one or more kinds selected from elemental sulfur (S)_x) Sulfur dioxide (SO)₂) Carbonyl sulfide (COS) and carbon disulfide (CS)₂) The reactivated catalyst is capable of being exposed to hydrogen (H) gas when contacted with a sulfur-containing material₂) In the presence of a catalyst ofConversion of various sulfur-containing species to hydrogen sulfide (H)₂S) transformation.

22. The method of claim 21, the hydrotreating process selected from the group consisting of a petroleum hydrotreating process, Hydrodesulfurization (HDS), Hydrodenitrogenation (HDN), hydrogenation, Hydrodemetallation (HDM), Naphtha Hydrotreating (NHT), Diesel Hydrotreating (DHT), Kerosene Hydrotreating (KHT), jet fuel hydrotreating (JHT), atmospheric gas oil hydrotreating, Vacuum Gas Oil (VGO) hydrotreating, and Fluid Catalytic Cracker (FCC) feed hydrotreating.

23. The method of claim 21, wherein the used catalyst comprises:

surface area of 20m²G to 600m²A/g of an inorganic oxide support material, one or more group VIIIB metals and one or more group VIB metals supported on the inorganic oxide support material.

24. The method of claim 21, wherein the catalyst comprises cobalt and molybdenum supported on alumina.

25. The process of claim 21, wherein the catalyst comprises nickel and molybdenum supported on alumina.

26. The method of claim 21, wherein the reactivation includes regeneration.

27. The method of claim 26, wherein the regenerating comprises heating the catalyst in an oxygen-containing atmosphere at a temperature of from 300 ℃ to 500 ℃ for 30 minutes or more.

28. The process of claim 26, wherein hydrocarbons are removed from the catalyst prior to the regeneration treatment by solvent extraction or by contacting the catalyst with steam, natural gas combustion products, hydrogen or nitrogen at a temperature of from 150 ℃ to 550 ℃.

29. The method of claim 21, wherein the reactivation includes rejuvenation.

30. The method of claim 29, wherein the rejuvenating comprises impregnating the catalyst with a solution containing a chelating agent and drying the catalyst at a temperature of 50 ℃ to 300 ℃.

31. The method of claim 30, wherein the chelating agent is an organic acid.

32. The method of claim 21, further comprising presulfiding the reactivated catalyst.

33. The method of claim 21, further comprising presulfiding the reactivated catalyst.

34. The method of claim 21, further comprising resizing, reshaping, and/or reformulating the reactivated catalyst.

35. The method of claim 21, further comprising grinding the reactivated catalyst to a fine powder and subsequently reforming the reactivated catalyst.

36. The process of claim 35, wherein prior to reactivation, the used catalyst has a diameter of 1.3 to 2.5mm and the reformed reactivated catalyst has a diameter of 3 to 5 mm.

37. The method of claim 21, wherein the used catalyst as used in the hydroprocessing process exhibits a pressure drop of 0.20 to 0.80 psi/ft, and wherein the method further comprises sizing, reshaping and/or reformulating the reactivated catalyst such that the reactivated catalyst exhibits a pressure drop of 0.05 to 0.20 psi/ft when sock-loaded in ambient air and tested at a superficial velocity of 100 ft/min.

Technical Field

The present application relates to catalysts and methods for tail gas treatment in hydrocarbon treatment processes. More particularly, the present application relates to reactivating catalysts used in hydroprocessing processes and using the reactivated catalysts for tail gas treatment.

Background

The necessity of removing sulfur from hydrocarbon streams such as oil and natural gas derivative streams to control pollution is well known. If sulfur is not removed from the hydrocarbon, sulfur dioxide and sulfur trioxide are formed upon combustion. These compounds can react with atmospheric moisture to form sulfuric acid, a factor contributing to a phenomenon known as acid rain. For this reason, in most jurisdictions, legislation requires that sulfur emissions to the environment be minimized.

Usually by so-called Hydrodesulfurization (HDS), also commonly referred to as hydrotreating (hydrotrea)ting, HDT) or Hydrotreating (HDP) catalytic processes remove sulfur from natural gas and other refined petroleum products. In this process, a hydrocarbon stream is mixed with hydrogen, heated and passed through a fixed catalyst bed at elevated temperature and pressure. A common catalyst for hydrotreating comprises a support material, such as alumina (Al)₂O₃) Silica-alumina, zeolite, or combinations thereof) with one or more group VIIIB metals such as cobalt (Co) or nickel (Ni) and one or more group VIB metals such as molybdenum (Mo) or tungsten (W). When hydroprocessing catalysts are used in the hydroprocessing process, the activity of the catalyst decreases over time due to the accumulation of carbonaceous deposits, known As coke, on the catalyst and/or due to the presence of deactivating inorganic materials such As silicon (Si), arsenic (As) and vanadium (V). Some of these catalysts may be activated and reused as HDS catalysts by regeneration or rejuvenation (rejuvenation), but in more general cases, the spent catalyst is not recycled but is disposed of as a hazardous waste. Thus, there is environmental and economic incentive to develop other uses for catalysts recovered from hydrocarbon processes such as HDS processing.

Summary of The Invention

Disclosed herein is a method of treating a gas stream in a tail gas treatment process, the method comprising: contacting a gas stream with a catalyst which has previously been used in a hydrotreating process and which has been reactivated by a reactivation process prior to contacting the gas stream in a tail gas treatment process, wherein the gas stream comprises one or more selected from elemental sulphur (S)_x) Sulfur dioxide (SO)₂) Carbonyl sulfide (COS) and carbon disulfide (CS)₂) And wherein in hydrogen (H)₂) In the presence of a reactivation catalyst converts the one or more sulfur species to hydrogen sulfide (H)₂S). According to some embodiments, the hydrotreating process is selected from the group consisting of petroleum hydrotreating process, Hydrodesulfurization (HDS), Hydrodenitrogenation (HDN), hydrogenation, Hydrodemetallation (HDM), Naphtha Hydrotreating (NHT), Diesel Hydrotreating (DHT), Kerosene Hydrotreating (KHT), jet fuel hydrotreating (JHT), atmospheric gas oil hydrotreating, Vacuum Gas Oil (VGO) hydrotreating, and fluid catalytic hydrotreatingHydrocracking of a chemical cracker (FCC) feed. According to some embodiments, the catalyst comprises one or more group VIIIB metals and one or more group VIB metals supported on an inorganic oxide support material. According to some embodiments, the catalyst comprises cobalt and molybdenum supported on alumina. According to some embodiments, the catalyst comprises nickel and molybdenum supported on alumina. According to some embodiments, the reactivation process includes regeneration. According to some embodiments, the regeneration comprises heating the catalyst in an oxygen-containing atmosphere at a temperature of from 300 to 500 ℃ for 30 minutes or more. According to some embodiments, hydrocarbons are removed from the catalyst prior to the regeneration treatment by solvent extraction or by contacting the catalyst with steam, natural gas combustion products, hydrogen or nitrogen at a temperature of 150 to 550 ℃. According to some embodiments, the reactivation process includes rejuvenation. According to some embodiments, rejuvenation includes impregnating the catalyst with a solution containing a chelating agent and drying the catalyst at a temperature of 50 ℃ to 300 ℃. According to some embodiments, the chelating agent is an organic acid. According to some embodiments, the reactivated catalyst is pre-sulfided prior to contact with the gas stream in the exhaust gas treatment process. According to some embodiments, the reactivated catalyst is pre-sulfided prior to contact with the gas stream in the exhaust treatment process. According to some embodiments, the reactivated catalyst is sized, reshaped and/or reformulated prior to contacting with the gas stream in the exhaust gas treatment process. According to some embodiments, the reactivated catalyst is resized by length grading the catalyst. According to some embodiments, the resizing, reshaping, and/or reformulating comprises grinding the reactivated catalyst into a fine powder and then reforming the reactivated catalyst. According to some embodiments, the reactivated catalyst is resized from having a diameter of 1.3 to 2.5mm to having a diameter of 3 to 5 mm. According to some embodiments, contacting the gas stream with the reactivated catalyst comprises combining the reactivated catalyst with a second catalyst, wherein the second catalyst provides a lower pressure drop than the reactivated catalyst. According to some embodiments, contacting the gas stream with the reactivated catalyst comprises a short loadingThe reactivated catalyst. According to some embodiments, the reactivated catalyst exhibits a pressure drop of 0.05 to 0.20 psi/foot when sock-loaded in ambient air and tested at a superficial velocity of 100 feet/minute.

Also disclosed herein is a method of forming a reactivation catalyst for an exhaust treatment process, the method comprising: obtaining a used catalyst from a hydroprocessing process, and reactivating the catalyst to form a reactivated catalyst when contacted with a catalyst comprising one or more members selected from the group consisting of elemental sulfur (S)_x) Sulfur dioxide (SO)₂) Carbonyl sulfide (COS) and carbon disulfide (CS)₂) The reactivated catalyst is capable of being exposed to hydrogen (H) gas when contacted with a sulfur-containing material₂) In the presence of a catalyst to convert the one or more sulfur species to hydrogen sulfide (H)₂S) transformation. According to some embodiments, the hydrotreating process is selected from the group consisting of petroleum hydrotreating processes, Hydrodesulfurization (HDS), Hydrodenitrogenation (HDN), hydrogenation, Hydrodemetallation (HDM), Naphtha Hydrotreating (NHT), Diesel Hydrotreating (DHT), Kerosene Hydrotreating (KHT), jet fuel hydrotreating (JHT), atmospheric gas oil hydrotreating, Vacuum Gas Oil (VGO) hydrotreating, and Fluid Catalytic Cracker (FCC) feed hydrotreating. According to some embodiments, the used catalyst comprises: surface area of 20 to 600m²A/g of an inorganic oxide support material, one or more group VIIIB metals and one or more group VIB metals supported on the inorganic oxide support material. According to some embodiments, the catalyst comprises cobalt and molybdenum supported on alumina. According to some embodiments, the catalyst comprises nickel and molybdenum supported on alumina. According to some embodiments, the reactivation includes regeneration. According to some embodiments, the regeneration comprises heating the catalyst in an oxygen-containing atmosphere at a temperature of from 300 to 500 ℃ for 30 minutes or more. According to some embodiments, hydrocarbons are removed from the catalyst prior to the regeneration treatment by solvent extraction or by contacting the catalyst with steam, natural gas combustion products, hydrogen or nitrogen at a temperature of 150 to 550 ℃. According to some embodiments, the reactivation includes rejuvenation. According to some embodiments, rejuvenation includes impregnating the catalyst with a solution containing a chelating agent and at 50 deg.CThe catalyst was dried at a temperature of 300 ℃. According to some embodiments, the chelating agent is an organic acid. According to some embodiments, the method further comprises presulfiding (pre-sulfiding) the reactivated catalyst. According to some embodiments, the method further comprises pre-sulfiding (pre-sulfiding) the reactivated catalyst. According to some embodiments, the method further comprises resizing, reshaping and/or reformulating the reactivated catalyst. According to some embodiments, the method further comprises grinding the reactivated catalyst to a fine powder and then reforming the reactivated catalyst. According to some embodiments, prior to reactivation, the used catalyst has a diameter of 1.3 to 2.5mm and the reformed reactivated catalyst has a diameter of 3 to 5 mm. According to some embodiments, the used catalyst as used in the hydroprocessing process exhibits a pressure drop of 0.20 to 0.80 psi/foot, and wherein the process further comprises sizing, reshaping and/or reformulating the reactivated catalyst such that the reactivated catalyst exhibits a pressure drop of 0.05 to 0.20 psi/foot when sock-loaded (sock-loaded) in ambient air and tested at a superficial velocity of 100 feet/minute.

Brief description of the drawings

Figure 1 illustrates a process for treating an acidic hydrocarbon feed, wherein the process comprises a hydrotreating step and a sulfur treatment step.

Figure 2 is a table showing the results of an analysis of regenerated, hot nitrogen stripped and solvent extracted catalysts.

Figure 3 is a table showing the performance of fresh, regenerated, rejuvenated, hot nitrogen stripped and solvent extracted catalysts for tail gas treatment at 1200 GHSV.

Fig. 4 shows the equation used to calculate the total sulfur conversion and a comparison of the total sulfur conversion using different catalysts.

The table of fig. 5 shows the performance of the regenerated and rejuvenated catalyst for exhaust treatment at 3000 GHSV.

Figure 6 shows a comparison of sulfur dioxide conversion at 3000GHSV using different catalysts.

Figure 7 shows a comparison of carbon disulfide conversion at 3000GHSV using different catalysts.

Figure 8 shows a comparison of carbonyl sulfide conversion at 3000GHSV using different catalysts.

Figure 9 shows a comparison of total sulfur conversion at 3000GHSV using different catalysts.

FIG. 10 illustrates a method for reactivating a catalyst for exhaust treatment.

Detailed Description

FIG. 1 illustrates various aspects of a hydrocarbon processing facility, such as a natural gas processing facility or an oil refinery facility. As noted above, such facilities may include one or more Hydrodesulfurization (HDS) reactors 102. An acidic hydrocarbon feed (i.e., a hydrocarbon feed containing organosulfur compounds) is provided to the HDS reactor 102. As described above, the hydrocarbon stream is heated, mixed with hydrogen, and passed over a catalyst at elevated temperature and pressure. As also noted above, catalysts for hydroprocessing typically comprise a support material, such as alumina (Al)₂O₃) Silica-alumina, zeolite, or combinations thereof) with one or more group VIIIB metals such as cobalt (Co) or nickel (Ni) and one or more group VIB metals such as molybdenum (Mo) or tungsten (W). The reactions that occur, i.e., hydrogenolysis reactions, are characterized by the breaking of C-S chemical bonds and the formation of C-H and H-S chemical bonds. In this way, the reaction of the hydrocarbon compound (containing embedded sulfur) with hydrogen allows the formation of hydrogen sulfide gas (H) by₂S) to release sulphur.

The effluent of the fixed bed reactor was cooled and the gas and liquid were separated. The gas comprises hydrogen and hydrogen sulphide, among other components. The gas is fed to the amine system 104. The amine system 104 includes an amine absorption system (not specifically shown) in which hydrogen sulfide is selectively absorbed into an amine absorbent. In this way the gas is purified to be free of hydrogen sulphide and the remaining hydrogen-rich gas stream is recycled mainly to be combined with fresh make-up hydrogen and fed again to the hydrodesulphurisation reactor 102. Within the amine system 104, will be "rich" in H₂The amine solution of S is sent to an amine regenerator (not specifically shown). The hydrocarbon liquid from the hydrotreater effluent gas separator is sent to a stripper 106 where hydrogen sulfide is stripped from the hydrocarbon liquid. This is achieved byThe liquid hydrocarbon stream with hydrogen sulfide is purified to be further refined. The stripped hydrogen sulfide-containing gas stream is then sent to an amine system 108 (similar to the amine system 104) where hydrogen sulfide is removed from the remaining gas stream using an amine absorbent. After regeneration of the hydrogen sulphide rich amine absorbent, a hydrogen sulphide rich gas stream is obtained. Most typically, the hydrogen sulfide stream is sent to a sulfur recovery system, which may include a modified Claus process coupled to a tail gas cleanup process for further processing and conversion to elemental sulfur. In some cases, although less common, the hydrogen sulfide-containing stream may be converted to sulfuric acid in a Wet Sulfuric Acid (WSA) plant.

Still referring to FIG. 1, the sulfur recovery system 110 is shown to include a modified Claus process 112 for converting hydrogen sulfide to elemental sulfur. The process comprises a thermal stage (typically a reactor) followed by two or more catalytic stages. In the hot stage, one third of the hydrogen sulfide in the feed stream is combusted to produce sulfur dioxide, according to reaction 1. According to the Claus reaction, reaction 2, sulfur dioxide reacts with hydrogen sulfide to produce elemental sulfur. Thus, the overall reaction can be expressed according to reaction 3.

The hydrogen sulphide containing feed stream is combusted and the amount of air is controlled to achieve the required sulphur dioxide level and to convert any ammonia and hydrocarbons present. Typically, about 60-70% of the sulfur entering the modified Claus process is converted to elemental sulfur in the thermal stage. The gas from the autothermal stage is then treated in each successive catalytic stage. Each catalytic stage consists of three process steps: reheating, catalytic conversion and condensation. In the reheating step, the gas stream is heated to a temperature required for the subsequent catalytic conversion stage. In the catalytic conversion step, an additional Claus conversion according to reaction 2 is effected with a Claus catalyst, which is generally based on titanium dioxide or aluminum oxide. The final step is to condense the gaseous sulfur formed in the upstream catalytic converter to liquid sulfur, which is then separated and recovered. Generally, sulfur recovery efficiencies in excess of 97% cannot be achieved by the modified Claus process alone. In order to achieve higher sulfur recoveries, e.g., in the range of 98-99.9%, required by many jurisdictions, a tail gas cleanup process is required.

Thus, the illustrated sulfur recovery system 110 also includes a tail gas cleanup process 114. A typical sulfur recovery tail gas cleanup system 114 includes a hydrogenation/amine treatment that can provide a sulfur recovery efficiency of 99.8 +% s. Strict environmental regulations, mandatory low emissions and high recovery limits force many acid gas treaters to adopt such hydrogenation/amine tail gas treatment processes.

One of the most common hydrogenation/amine treatment processes is the Shell Claus off-gas treatment (SCOT) process. In the SCOT process, the sulfur dioxide and other convertible sulfur compounds in the Claus tail gas are catalytically converted to hydrogen sulfide. First, the Claus tail gas is heated and mixed with a reducing gas stream comprising hydrogen and carbon monoxide. The reducing gas is typically produced by a Reducing Gas Generator (RGG)116 that operates under sub-stoichiometric combustion conditions to partially oxidize the fuel to carbon monoxide and hydrogen. The resulting gas stream (which contains species including sulfur dioxide (SO) obtained by mixing the Claus tail gas and the reducing gas) is then passed to hydrogenation reactor 118₂) Carbonyl sulfide (COS) and carbon disulfide (CS)₂) Elemental sulfur (S)_x) And carbon monoxide (CO)) over a hydrogenation catalyst. Most typically, the hydrogenation catalyst comprises cobalt and molybdenum on an alumina support. The catalyst promotes the hydrogenation of residual sulphur dioxide (reaction 4), the hydrolysis of carbonyl sulphide (reaction 5), the hydrolysis of carbon disulphide (reaction 6) and the hydrogenation of elemental sulphur (reaction 7), all of which are returned to H₂S。

SO₂+3H₂→H₂S+2H₂O reaction 4: SO₂Reduction of

COS+H₂O→H₂S+CO₂Reaction 5 hydrolysis of COS

CS₂+2H₂O→2H₂S+CO₂Reaction 6: CS₂Hydrolysis

Reaction 7 reduction of Sulfur

The catalyst also promotes the water gas shift reaction, wherein carbon monoxide reacts with water to form hydrogen and carbon dioxide according to reaction 8.

CO+H₂O→H₂+CO₂Reaction 8 Water gas Shift

The reactor effluent is typically cooled by a waste heat boiler (generating low pressure steam) and then through a water quench tower system, which both cools the gas and reduces the water content from about 30% to 5-10%. The cooled gas from the cooling/quenching apparatus 120 is then contacted with an amine absorbent in an amine contacting column. In the amine absorption system 122, H in the tail gas is removed₂S is absorbed into lean amine to enrich it (loaded with H)₂S) and purifying H₂And (4) S gas flow. The purified effluent gas stream is then sent to an incinerator as a final treatment step and then released to the atmosphere. The rich amine is sent to an amine regenerator where it is heated to drive off H₂S, reacting the H₂The S is recycled back to the Claus plant for conversion to elemental sulfur. In this way, the sulfur is essentially recycled until extinction. Feeding the lean regenerated amine back to the absorber for another H₂And S absorption circulation.

It should be noted that figure 1 is intended to provide an overview of the SCOT process and is not intended to illustrate every piece of equipment and every variable. It should also be noted that other variations of the exhaust gas cleaning system are known in the art. For example, one variation of the original SCOT process is a low temperature SCOT process. In a conventional SCOT process, the tail gas stream is typically heated directly to about 260 ℃ to 300 ℃ using an in-line burner (i.e., RGG 116) and then fed to hydrogenation reactor 118. In the low temperature SCOT process, the tail gas stream is typically heated indirectly using a high pressure steam heater, typically to about 220-. The low temperature SCOT process also requires the use of an external hydrogen source because the reducing gas generator is no longer part of the process scheme. Finally, low temperature units typically use catalysts designed specifically for higher activity, typically by using higher concentrations of active metals to achieve similar conversion levels as conventional temperature units.

Another alternative tail gas cleanup process is BThe eavon Sulfur Removal (BSR) process, which also features the hydrogenation of Claus tail gas. In the BSR process, a Claus tail gas is heated by an in-line combustor (e.g., a reducing gas generator, RGG) under sub-stoichiometric conditions to partially oxidize the fuel to produce a reducing gas. The mixture of Claus tail gas and reducing gas is fed to a hydrogenation bed packed with cobalt and molybdenum on alumina. The same reactions (4-8) as outlined above for the SCOT process occur in the hydrogenation step. After the hydrogenation step, the gas is sent to a waste heat boiler that produces low pressure steam, which is then sent to a quench tower system that reduces both the temperature and significantly the water content. Aiming at recycling H from BSR process to another₂S gas (e.g. BSR/MDEA) or H₂Another process pairing is common where S gas is converted to elemental sulfur for recovery (e.g., BSR/selectix or BSR/Stretford).

Note that each of the off-gas cleanup processes described herein involves a hydrogenation reactor that affects reactions 4-7 described above. It is further noted that the hydrogenation catalyst used in the hydrogenation reactor of the tail gas cleanup process typically comprises a catalyst supported on a support material, such as alumina (Al)₂O₃) Silica-alumina, zeolite, or combinations thereof) with one or more group VIIIB metals such as cobalt (Co) or nickel (Ni) and one or more group VIB metals such as molybdenum (Mo) or tungsten (W).

Aspects of the present disclosure relate to obtaining a catalyst for use in a hydrotreating process and then using the thus-obtained catalyst in a tail gas treatment process. Applications from which the hydrotreating catalyst is derived may include, but are not limited to, use in Hydrodesulfurization (HDS), Hydrodenitrogenation (HDN), Hydrodemetallization (HDM), Hydrodearomatization (HDA), Hydrodeoxygenation (HDO), aromatics saturation, hydrocracking, and other hydrogenation processes. For example, the used catalyst may be derived from Naphtha Hydrotreating (NHT), Diesel Hydrotreating (DHT), Kerosene Hydrotreating (KHT), jet fuel hydrotreating (JHT), atmospheric gas oil hydrotreating, Vacuum Gas Oil (VGO) hydrotreating, Fluid Catalytic Cracker (FCC) feed hydrotreating applications, or any other petroleum fraction hydrotreating application. It is important to note that when reference is made to a hydroprocessing catalyst, this technique is usedThe term is not intended to include catalysts previously used in Claus tail gas treatment processes. The catalyst typically comprises a support material, such as alumina (Al), supported on a support material₂O₃) Silica-alumina, zeolite, or combinations thereof) with one or more group VIIIB metals such as cobalt (Co) or nickel (Ni) and one or more group VIB metals such as molybdenum (Mo) or tungsten (W). These hydrotreating catalysts may also have type I or type II active sites. The catalyst may also include promoters, such as boron or phosphorus promoters and the like.

As used herein, the term "reactivated catalyst" refers to a catalyst obtained from a hydrotreating process, which has been reactivated and then reused in a tail gas treatment process. The reactivated catalyst may be a regenerated and/or rejuvenated (reactivated) catalyst.

The term "regenerated catalyst" is used herein to refer to a spent catalyst that has been subjected to an in situ or ex situ controlled thermal treatment in the presence of oxygen to remove contaminants such as volatile hydrocarbons, carbon (coke), and sulfur. Regeneration processes are known to those skilled in the art and although these processes may differ in configuration details, they all aim to remove hydrocarbons, sulfur and carbon, convert essentially all metals to their oxide form and restore activity as much as possible while minimizing damage to achieve the highest yield and lowest possible product length loss. Most catalyst regeneration is performed ex situ, however, in situ regeneration may be performed, and the term "regeneration" as used herein is not intended to limit the scope to ex situ regeneration. Regeneration processes are typically used to hydrotreat the catalyst in a spent state to recover a portion of the fresh catalyst activity from the spent catalyst. The regenerated catalyst is typically reused in a low severity hydroprocessing unit as a low cost replacement for fresh catalyst. The regeneration process differs from the rejuvenation (rejuvenation) process in that it is not characterized by any metal redispersion process that reverses the activity reduction caused by metal agglomeration.

According to some embodiments, the regenerated catalyst may be prepared as described above by obtaining a catalyst that has been used in a hydroprocessing process. The obtained catalyst can be regenerated by heating the catalyst in air to remove contaminants from the catalyst from the hydrotreating process. For example, the catalyst may be heated at a temperature in the range of from about 200 ℃ to about 600 ℃, more preferably from 380 ℃ to about 500 ℃ for 1 to 24 hours, more preferably from 1 to 3 hours. One of the major contaminants removed during the regeneration process is coke. The coke concentration of the spent catalyst is typically greater than 4 wt.%. After regeneration, the coke concentration is typically less than 4 wt.%.

The term "rejuvenated" (or rejuvenated) catalyst is used herein to refer to a used catalyst that has been subjected to an in situ or ex situ controlled heat treatment (regeneration) to remove volatile hydrocarbons, carbon (coke) and sulfur, followed by ex situ application via an impregnated chelating agent to re-disperse the active metal sites on the support that have migrated, thereby causing metal site growth. After a specified aging period, the catalyst can be dried to the final product form. Rejuvenation processes are known to those skilled in the art and although these processes may vary in construction details, they all aim to remove hydrocarbons, sulfur and carbon, convert substantially all metals to their oxide form, re-disperse the active metal sites on the support, restore activity as much as possible while minimizing damage to achieve the highest yield and lowest product length loss. The regeneration process will generally restore sufficient activity to approach the performance of the fresh catalyst. In some cases, especially for class I catalysts, rejuvenation of the used catalyst may provide even higher performance (under hydrotreating conditions) than the original fresh catalyst. Due to the higher degree of activity recovery compared to regenerated catalyst, the regenerated catalyst can be reused in the same unit from which it was harvested or in one of the units with similar severity. It does not have to be cascaded to a less severe unit like the regenerated catalyst.

Any reconstitution method known in the art may be used in accordance with the present disclosure. According to some embodiments, the rejuvenated catalyst may be prepared by obtaining a catalyst for use in a hydroprocessing process as described above. According to some embodiments, the catalyst obtained first is regenerated as described above. After the regeneration process, the catalyst may be contacted with one or more reagents to rejuvenate the catalyst. Examples of reagents that can be used to contact the catalyst include one or more organic additives such as butanediol, methylglyoxal, glycolaldehyde, ethylene glycol, propylene glycol, glycerol, trimethylolethane, trimethylolpropane, diethylene glycol, dipropylene glycol, 1, 3-propanediol, triethylene glycol, tributylene glycol, tetraethylene glycol, tetrapentylglycol, polyethers such as polyethylene glycol, ethylene glycol monobutyl ether, diethylene glycol monomethyl ether, diethylene glycol monoethyl ether, diethylene glycol monopropyl ether, and diethylene glycol monobutyl ether. The catalyst may, for example, be contacted with a solution comprising the organic additive, such as a solution of the organic additive in an alcohol or an aqueous solution. Alternatively or additionally, the catalyst may be contacted with an acid such as glycolic acid, glyoxylic acid, lactic acid, diethylenetriaminepentaacetic acid, ethyleneaminetetraacetic acid, citric acid, tartaric acid, oxalic acid, malonic acid, malic acid, and the like. After contacting, the catalyst may be aged and/or dried. For example, the catalyst may be aged for a period of several hours to several days, such as 1 hour to 24 hours, 6 to 24 hours, or for example about 14 hours. According to some embodiments, the catalyst may be aged at room temperature. As used herein, "room temperature" refers to a temperature of about 20-25 ℃. According to some embodiments, a portion of the organic additive may remain in the catalyst even after drying.

Common industrial rehabilitation methods are exemplified as follows: described in U.S. Pat. No. 9,895,679(Porocel, Houston, TX); described in U.S. Pat. No. 7,696,120(Criterion, Houston, TX); described in U.S. Pat. No. 7,956,000(Albemarle Corporation, Charlotte, NC); and(Haldor Topsoe,Inc.,Houston,TX)。the contents of U.S. patent No. 9,895,679 ("the 679 patent") are incorporated herein by reference in their entirety.

According to some embodiments, the reactivated (i.e., regenerated or rejuvenated) catalyst may be applied "as is," i.e., in the original size, shape, and composition used in the hydroprocessing process. According to other embodiments, the catalyst may be resized, reshaped, reformulated, or any combination thereof prior to use in the exhaust treatment process. Changing the size involves changing the size of the catalyst. This may be achieved, for example, by length-grading the catalyst, which includes selectively removing the smallest catalyst particles, effectively increasing the average particle size of the remaining catalyst. Length fractionation may be accomplished by sieving/screening or by other more specialized methods known to those skilled in the art. Changing the size can also be accomplished by grinding the catalyst into a fine powder and reforming a different size catalyst. For example, changing the size may include grinding 1.3mm, 1.6mm, or 2.5mm catalyst extrudates to a fine powder and reforming to produce 3.0mm or 3.5mm catalyst extrudates. Reshaping includes changing the shape of the catalyst. For example, reshaping may include grinding a trilobe or tetralobal catalyst extrudate into a fine powder and reforming to produce a cylindrical extrudate, a spherical product, or even an annular/hollow cylindrical product. Resizing and reshaping may first involve reducing the catalyst from a "raw" form to a powder by a milling operation. Formation of the new size or shape may then be accomplished by any forming method, including but not limited to: extrusion (e.g., screw or piston extrusion), tableting, pelletizing, slugging, pelletizing, dripping, and the like.

Reformulation involves the incorporation of additional components or materials into the reactivated catalyst. For example, boehmite/pseudoboehmite alumina or anatase titania powders may be added in a ratio relative to the ground catalyst powder to produce a reconstituted product. Reformulation may involve the addition of the active metal, cocatalyst or other ingredient by physical mixing, such as co-grinding, mixing, plow mixing, paddle mixing or ribbon mixing. Reformulation may also involve the addition of metals, promoters or other ingredients, for example, by precipitation or impregnation. Alternatively, reformulation may involve a combination of physical mixing and impregnation to introduce additional components into the reactivated catalyst material. Any method employed to add additional components in any form to the reactivated catalyst constitutes reformulation. For example, the catalyst may be reconstituted by taking the catalyst in its native form and wetting the catalyst with a solution or slurry of an active phase precursor, e.g., a soluble metal salt of one or more group VIIIB metals such as cobalt (Co) or nickel (Ni) and one or more group VIB metals such as molybdenum (Mo) or tungsten (W). For example, the catalyst may be reconstituted by wet impregnation with excess solution, by dry impregnation (also referred to as incipient wetness impregnation or pore volume impregnation), or by precipitation.

Generally, an exhaust catalyst can be installed in one of three states: oxidation state, presulfurization state, or presulfurization (preactivation) state. The oxidation state can be described as a state in which almost all of the metal is present as the metal oxide and a significant amount of sulfur and a significant amount of metal sulfide are not present on the catalyst. Presulfiding can be described as a process in which elemental sulfur and/or sulfur-containing compounds are added to the catalyst and typically less than 60% of the metal oxide is converted to metal sulfide. Presulfiding (preactivation) can be described as a treatment in which typically more than 60% of the metal oxide is converted to a metal sulfide. The advantages of the presulfiding or presulfiding (preactivation) treatment (relative to the oxidation state) are mainly faster and easier start-up of the reactor after the initial loading. The reactivated hydroprocessing catalyst, whether in its native state or in a resized, reshaped and/or reformulated state, may be presulfided or presulfided prior to use in the intended application. The disclosure and claims set forth herein are not intended to limit the scope to any particular prevulcanisation or prevulcanisation technique, but are intended to apply to all such techniques.

The present inventors have surprisingly found that catalysts from hydrotreating applications can be reactivated for use in tail gas hydrogenation applications. One beneficial aspect of the disclosed methods and systems is that the reuse of the spent hydroprocessing catalyst reduces the hazardous waste generated by operators handling the spent catalyst. Ultimately, this helps to reduce the impact of the catalyst life cycle on the environment (carbon footprint). The disclosed methods and systems also provide an economically attractive source of high performance catalyst for exhaust treatment, which is beneficial to producers, catalyst suppliers, and catalyst consumers, all by beneficially reusing used catalyst that is otherwise hazardous waste.

Those skilled in the art will appreciate that some aspects of catalysts used for tail gas treatment (i.e., hydrogenation of tail gas components) may differ from aspects of catalysts used for non-tail gas treatment operations, such as hydrotreating and other processes described above. In other words, even though catalysts for both types of processes may use similar group metals supported on similar support materials, the catalysts may be optimized for one or the other process type. For example, a common difference between catalysts used in hydroprocessing applications and catalysts used in tail gas treatment is size. Typically, hydrogenation catalysts are available in smaller sizes, for example extrudates having a diameter size of 1.3mm, 1.6mm or 2.5mm are very common, while tail gas catalysts are available in larger sizes in various shapes/forms, typically 3 to 5mm in diameter. Another difference between a typical hydrotreating catalyst and a typical tail gas catalyst is the metals used and the metal concentrations. Commercial exhaust catalysts currently on the market are predominantly cobalt and molybdenum (CoMo) active metals, typically in the concentration range of 2-3.5% Co and 6-11% Mo. Commercial hydroprocessing catalysts currently on the market are predominantly cobalt and molybdenum (CoMo) or nickel and molybdenum (NiMo) active metal combinations. For commercial CoMo hydroprocessing catalysts, typical concentrations range from 3-4.5% Co and 12-17% Mo. Typical concentration ranges for commercial NiMo hydrotreating catalysts are 2.5-5% Ni and 9-19% Mo. Note that the active metal content of hydrotreating catalysts is typically much higher than the active metal content of tail gas catalysts. It is also noted that the use of Ni and/or W containing catalysts in tail gas service is not a common industrial practice, as is the case in hydroprocessing service. Another difference between these two catalysts is their shape. Hydrotreating catalysts are primarily multilobal extrudates, while tail gas catalysts come in a variety of shapes, including multilobal extrudates, spherical and even hollow cylindrical extrudates. Another difference between these two catalysts is that the hydrotreating catalyst comprises almost exclusively an extruded γ/δ/θ alumina phase catalyst support, while the tail gas catalyst comprises a spherical χ/ρ/η alumina phase catalyst support and an extruded γ/δ/θ alumina phase catalyst support.

One limitation of using reactivated hydroprocessing catalysts in tail gas service is the size difference of the catalyst particles. To the inventors' knowledge, this may be one of the reasons why no one has ever done so. As previously mentioned, the size of the hydrotreating catalyst is typically smaller than the size of the tail gas catalyst (1.3-2.5 mm vs.3-5mm, respectively). Smaller size catalysts result in higher packed bed pressure drop per linear foot. In many cases, this higher pressure drop may be unacceptable due to hydraulic capacity limitations imposed on the exhaust unit. Fortunately, the inventors have identified several methods to circumvent this obstacle. One option is to length grade the catalyst. Length fractionation is an industrially mature process that separates catalyst particles based on their size. By doing so, the smallest particles can be effectively removed, which increases the average length of the remaining catalyst extrudate particles. Bed void fraction is also increased by increasing the average particle length of the catalyst extrudates and tightening the particle size distribution. Both of these variations result in lower pressure drop per foot. Within certain limits, the degree of length grading can be fine-tuned according to the desired pressure drop curve. Length grading may be accomplished by screening/sieving or other more specialized methods. Another option is to load a highly active reactivated hydroprocessing catalyst bed that is shorter than the normally loaded fresh exhaust catalyst bed to achieve the desired pressure drop and performance curve for a standard fresh exhaust catalyst loading configuration. This is referred to as "short loading" and is possible because, in some cases, reactivating hydrotreating catalysts has performed better than competing fresh tail gas catalysts currently on the market. Another option is to combine a high activity and high pressure drop reactivated hydrotreating catalyst with a lower pressure drop (larger particle size) fresh or reactivated tail gas catalyst in a stacked bed configuration to achieve the desired performance and pressure drop profile. Another option is to combine a high activity and high pressure drop reactivated hydroprocessing catalyst with a low pressure drop (larger particle size) sized, reshaped and/or reformulated catalyst to achieve the desired performance and pressure drop.

Each of these options allows for mitigating pressure drop limitations and making reactivated hydroprocessing catalysts suitable for use in tail gas units. According to some embodiments, the catalyst as used in the original hydroprocessing process will result in a pressure drop of about 0.20 psi/ft to about 0.80 psi/ft, for example about 0.40 psi/ft to about 0.60 psi/ft, when sock-loaded and tested in ambient air at a superficial velocity of 100 feet/minute. After the catalyst is resized, reshaped, reformulated, short loaded, and/or combined with another low pressure drop catalyst for exhaust treatment using one of the methods described above, the catalyst can induce a pressure drop of from about 0.05 psi/ft to about 0.20 psi/ft, such as from about 0.10 psi/ft to about 0.15 psi/ft, when sock loaded and tested in ambient air at a superficial velocity of 100 feet/minute.

One or more of the sizing, reforming, and reformulating steps described above may be used to reconfigure the catalyst obtained from the first non-exhaust treatment process to optimize the catalyst for exhaust treatment. Fig. 10 illustrates an embodiment of a process 1500 for reactivating a catalyst for exhaust treatment. The catalyst 1502 is first obtained from a non-exhaust gas treatment process. The catalyst may be, for example, a trilobe or quadralobe catalyst, and may typically have a size of about 1.3-2.5 mm. As mentioned above, the catalyst may comprise a support material such as alumina (Al)₂O₃) One or more group VIIIB metals and one or more group VIB metals on silica-alumina, zeolite, or combinations thereof.

The resulting catalyst may be subjected to thermal stripping or solvent extraction 1504, typically to remove residual hydrocarbons from the catalyst. For example, the thermal stripping process may involve contacting the catalyst with hot steam or gas, air, natural gas combustion products, hydrogen or nitrogen at a temperature of 150 ℃ to 550 ℃. For example, the solvent extraction process may involve contacting the catalyst with a non-polar solvent. The stripped or solvent extracted catalyst can be regenerated 1506, as described above. For example, the catalyst may be heated at a temperature of from about 200 ℃ to about 600 ℃, more preferably from 380 ℃ to about 500 ℃ for 1 to 24 hours, more preferably from 1 to 3 hours. The regenerated catalyst may be sized 1508, typically by grinding or milling the regenerated catalyst to form a powder. For example, the powder may be isolated by sieving. Powder 1510 can be reconstituted in one or more aspects. For example, the powder may be combined with additional support materials, such as alumina, to adjust the relative loading of the active catalyst material (i.e., metal). The catalyst may be reshaped 1512, for example, by extruding the resized and reformulated material into a shape that is the same or different than the original catalyst shape. For example, the original catalyst may have been multi-lobed with a given number of lobes (e.g., tri-lobed or tetra-lobed) and may be reshaped to produce a cylindrical or spherical catalyst. It should be noted that the catalyst may be further reformulated after reshaping. For example, the reshaped catalyst may be impregnated with additional active materials (e.g., cobalt, nickel, and/or molybdenum precursor materials). The catalyst may be rejuvenated 1514. For example, the newly formed catalyst may be exposed to one or more rejuvenating agents and processes as described above. According to some embodiments, the catalyst is impregnated with a chelating material as described above, aged and dried. According to some embodiments, the chelating material may include an organic additive, a portion of which remains in the catalyst material after the rejuvenation process.

It should be noted that process 1500 is merely exemplary. Some steps may be omitted or the steps may be performed in a different order. For example, the catalyst obtained from the original (non-exhaust gas treatment) process can be regenerated and rejuvenated and then re-sized and re-shaped, or can even be prepared without any re-sizing or re-shaping. Other modifications to process 1500 will be apparent to those skilled in the art based on this disclosure.

The following examples are included to illustrate aspects of the disclosed techniques and compositions.

Example 1: true airspeed (1,200GHSV) test

For each catalyst tested, a cylindrical vertically oriented glass reactor having an inner diameter of 3.0cm and a height of 51cm was filled with 70mL of catalyst. Fresh, regenerated andeach of the rejuvenated catalyst samples (# 1-10 and 13 in the following list) employed the same test protocol consisting of: first an in situ sulfidation (sulfiting) activation step, followed by the specified performance test conditions. During the in situ sulfidation step, a gas having the following molar composition was passed through the catalyst in a downflow mode: 2% H₂S、10％H₂And 88% N₂. The feed gas composition was set using appropriately calibrated mass flow controllers for each component and first verified by gas chromatography.

The space velocity of the gas during the in situ sulfidation step was 2,000 GHSV. The temperature was raised uniformly from 200 ℃ to 315 ℃ over 16 hours. The effluent gas composition was measured by gas chromatography every two hours. After the 16 hours were complete, the catalyst was considered to have been fully activated by the in situ sulfidation conditions. Since the active metal is already in the sulfided state, there are two test samples, the solvent extraction sample and the hot nitrogen stripped sample (# 11 and 12, respectively), that do not require sulfidisation in situ. An alternative activation start-up procedure for pre-activating (pre-sulphiding) the exhaust catalyst was chosen for these tests. For this alternative activation start-up procedure, a gas having the following molar composition was passed over the catalyst in a downflow manner: 3% H₂、3％CO、9％CO₂、25％H₂O and 60% N₂. Feed gas composition useMass flow controllers appropriately calibrated for each component were set and first verified by gas chromatography. The space velocity of the gas during the activation step was 500 GHSV. The temperature was raised uniformly from 200 ℃ to 315 ℃ over 24 hours. The effluent gas composition was measured by gas chromatography every two hours. At the end of this 24 hour period, the catalyst was considered to be fully activated and ready for performance testing.

After this start-up in-situ sulfidation or activation is complete, the catalyst bed is ready to be subjected to performance testing conditions. During performance testing conditions, a gas having the following molar composition was passed through the catalyst in a downflow manner: 70.05% N₂、25％H₂O、2.33％H₂、1.20％CO₂、0.59％CO、0.47％H₂S、0.23％SO₂0.060% COS and 0.061% CS₂. The feed gas composition was set using appropriately calibrated mass flow controllers for each component and first verified by gas chromatography. The gas space velocity for the performance test conditions was 1,200GHSV, equivalent to a residence time of 3 seconds, intended to represent the true industrial operating space velocity. Performance testing was performed at four different temperature conditions: 220 ℃, 240 ℃, 280 ℃ and 300 ℃. In each case, the temperature was maintained for 12 hours, which was sufficient to allow the performance to reach a steady state. Analysis of the composition of the reactor effluent was performed every two hours by gas chromatography. SO determination based on feed and average gas analysis at each performance test condition₂、CS₂And conversion of COS.

Thirteen different catalyst samples were tested according to the test protocol specified above. These samples are listed below:

1. regenerated commercial hydrotreating catalyst A (2.5mm, trilobal)

2.Reconstituted commercial hydrotreating catalyst A (2.5mm, trilobal)

3. Regenerated commercial hydrotreating catalyst B (2.5mm, quadrulobal)

4.Reconstituted commercial hydrotreating catalyst B (2.5mm, quadrulobal)

Freeh commercial hydrotreating catalyst C (2.5mm, quadrulobal)

6. Regenerated commercial hydrotreating catalyst C (2.5mm, quadrulobal), from application 1

7. Regenerated commercial hydrotreating catalyst C (2.5mm, quadrulobal), from application 2

8. Regenerated commercial hydrotreating catalyst D (2.5mm, trilobal)

9.Reconstituted commercial hydroprocessing catalyst D (2.5mm, trilobal)

10. Regenerated commercial hydrotreating catalyst E (2.5mm, trilobal)

11. Solvent extracted commercial hydrotreating catalyst F (2.5mm, trilobal)

12. Hot nitrogen stripped commercial hydrotreating catalyst F (2.5mm, trilobe), and

13. fresh commercial exhaust catalyst (3.2mm, trilobe).

Catalyst a was used in a diesel (ULSD) hydrotreating service prior to its reactivation. After use in diesel hydrotreating, catalyst a is regenerated and regenerated as described in the' 679 patent incorporated aboveAnd the restoration process is processed. In some cases, the regeneration process is characterized by: fluidized hot air stripping to remove hydrocarbons and reduce coke content followed by in each case high residence times, hot dipping of the moving belt to remove carbon and sulfur embedded deep within the catalyst pores.The rejuvenation process includes first catalyst regeneration as just described, followed by impregnation into the pores with a solution of the chelating agent. Allowing the impregnated catalyst to ageTake for a certain time and then dry. The rejuvenation process helps to reverse the metal agglomeration that occurs during catalyst operation and that results from the regeneration process. Although in these embodiments Porocel's regeneration and regeneration are usedThe rejuvenation process, but regeneration and rejuvenation processes are well known to those skilled in the art and are described, for example, in the above-referenced patents.

Catalyst B was used to treat vacuum gas oil for fluid catalytic cracking feed pretreatment prior to its reactivation. After its use in the vacuum gas oil treatment, catalyst B is regenerated andand the restoration process is processed.

A fresh sample of commercially available hydrotreating catalyst C was obtained in the spare catalyst market for performance testing purposes.

Catalyst C from application 1 was used in gas oil hydrotreating service prior to regeneration. After being used for the hydrotreatment of a gas oil, the catalyst C is treated by a regeneration process as described above.

Catalyst C from application 2 was used in a kerosene hydrotreating service prior to regeneration. After its use in the hydrotreatment of kerosene, catalyst C is treated by a regeneration process as described above.

Catalyst D was used in a diesel (ULSD) hydrotreating service prior to reactivation. After its use in the hydrotreatment of diesel (ULSD), catalyst D is regenerated and purified as described aboveAnd the restoration process is processed.

Catalyst E was used in hydroprocessing services prior to reactivation. After being used in a hydroprocessing service, catalyst E is treated by a regeneration process.

Catalyst F was used for Vacuum Gas Oil (VGO) pretreatment service of hydrocracking prior to recovery of the spent sample. After being used for the service of Vacuum Gas Oil (VGO) pretreatment for hydrocracking, the catalyst F was divided into two samples and subjected to two different treatments. The first treatment was a soxhlet solvent extraction with toluene for 4 hours, followed by drying at 110 ℃ for 2 hours. The purpose of solvent extraction is to remove residual hydrocarbons from the spent catalyst. The second treatment was thermal stripping in a rotary tube calciner at 370 ℃ for 1 hour under a pure nitrogen purge. Hot nitrogen stripping also aims to remove residual hydrocarbons from the spent catalyst sample.

Fresh commercial exhaust catalysts are available in the rich catalyst market for performance testing purposes.

All of the hydroprocessing catalysts tested were the same size and shape as they were used when initially serviced and were not reformulated. Catalysts A, B and C are both different catalysts made by different manufacturers and used for different hydroprocessing services. Catalyst a and catalyst D were made by the same manufacturer, used for the same service, and even initially used in the same reactor but were different catalysts, where catalyst a was CoMo on alumina and catalyst D was NiMo on alumina. Catalyst C from application 1 and catalyst C from application 2 were made by the same manufacturer and were the same type of catalyst, but from different reactors after being used for different hydroprocessing services, and both had different contaminant characteristics. Catalysts a and D-F are both produced by the same manufacturer, but they are different catalysts in which different types of metals and metal concentrations are present. Catalysts A-C are all cobalt and molybdenum (CoMo) on alumina supports, while catalysts D-F are nickel and molybdenum (NiMo) on alumina supports. The fresh exhaust catalyst used for the competitive evaluation and the fresh catalyst C reference sample were not found to have been subjected to any previous service and were used in a completely fresh form without change, as if directly from the manufacturer. The selective analytical data for the catalyst samples subjected to the performance test are shown in table 1 (fig. 2). Of each catalystThe reconstituted sample is derived from the same source material as the reconstituted sample, anAnd are expected to be almost the same in terms of physical properties in table 1. In the case of catalyst F, the metals data for the lab scale regeneration samples were obtained by performing XRF analysis, while other analytical data were from solvent extracted and hot nitrogen stripped samples in the pre-performance state. Catalysts a and C are both phosphorus promoted CoMo on alumina catalyst, while catalyst B is non-phosphorus promoted CoMo on alumina catalyst. On the other hand, catalysts D and F are both phosphorus promoted NiMo on alumina catalyst, while catalyst E is non-phosphorus promoted NiMo on alumina catalyst. Catalyst E was silicon promoted, while all other catalysts were not. In general, the list of catalysts tested in example 1 and fig. 2 indicates that some typical catalysts from the hydrotreating catalyst market were tested, ranging from CoMo to NiMo, from phosphorus promoted to non-phosphorus promoted, from higher to lower active metal loaded, from silicon promoted to non-silicon promoted, from fresh to regenerated and rejuvenated (as well as hot nitrogen stripped and solvent extracted), and from different catalyst types/products, manufacturers, and hydrotreating applications.

The test protocol and the test results of the catalyst are listed in table 2 (fig. 3). First look at SO₂Conversion performance, fig. 3 shows that of the 36 performance data points generated for 9 regenerated and rejuvenated hydroprocessing catalysts in their native form at each temperature condition, only four performance data points are lower than for the fresh tail gas competitive reference catalyst. The fact that 32 of the 36 performance data points indicate superior performance (performance odds approaching 90%) provides strong evidence that the reactivated hydroprocessing catalyst can be suitable for Claus tail gas hydroprocessing. Overall, the conversion of all the regenerated and rejuvenated hydroprocessing catalysts tested in their native form is very high: (>98%). The solvent extraction and hot nitrogen stripping versions of catalyst F also achieve high SO₂Conversion, of which only three of the eight performance data points are below the fresh exhaust gas competitive reference catalyst. From a practical point of view, due to SO₂Hydrogenation ratio of COS and CS₂Is much easier and in many cases approaches 100%, thus comparing different catalystsIntermediate COS and CS₂Hydrolytic properties are generally more useful for better discrimination and differentiation of properties.

Then look at CS₂Conversion performance, fig. 3 shows that of the 36 performance data points generated by the 9 regenerated and rejuvenated hydroprocessing catalysts in their native form at each condition, only one performance data point is lower than the fresh tail gas competitive reference catalyst. The fact that 35 of the 36 performance data points indicate superior performance (97% performance advantage) provides that the reactivated hydroprocessing catalyst can be suitable for CS in Claus tail gas hydroprocessing₂Convincing evidence of hydrolysis. One notable observation is that the superior performance of all hydrotreating catalysts tested was more pronounced at the temperature conditions of 240 ℃, 280 ℃ and 300 ℃ compared to the fresh tail gas competitive reference catalyst. Only at 220 ℃ will the performance of three of the nine regenerated and rejuvenated hydroprocessing catalysts in their native form be significantly reduced(s) ((s))>10%). Despite a significant drop in performance at 220 ℃, even so all catalysts, except for one hydrotreating catalyst, exhibited higher CS₂And (4) conversion activity. The performance of the thermal nitrogen stripping and solvent extraction versions of catalyst F was generally lower than the fresh exhaust gas competitive reference catalyst, with seven of the eight performance data points being lower than the fresh exhaust gas competitive reference catalyst. It is worth noting that the solvent extraction profile of catalyst F shows almost the same but slightly lower performance as the fresh tail gas competitive reference catalyst, while the hot nitrogen stripping profile of catalyst F shows a wider and wider range of performance inefficiencies as the temperature decreases.

Looking next at COS conversion performance, fig. 3 shows that of the 36 performance data points generated by the 9 regenerated and rejuvenated hydroprocessing catalysts in their native form under each condition, 10 performance data points are lower than the fresh exhaust gas competitive reference catalyst. Of these 36 performance data points, 26 indicate superior performance (72% performance advantage), providing evidence that these reactivated hydroprocessing catalysts can be suitable for COS hydrolysis in Claus tail gas hydroprocessing. Notably, less than the fresh exhaust gas competitive parameter among the 10 data points8 of the cocatalysts are for threeTwo of the rejuvenated catalysts were tested. In general, it was observed thatIt has been surprisingly discovered that the COS conversion performance of the rejuvenated catalyst is lower than its rejuvenated catalyst counterpart. Even in the case where this is the case,the rejuvenated catalyst still exhibited a fairly high level of COS conversion and was not significantly lower than the fresh competitive exhaust gas reference catalyst. Considering only the regenerated hydroprocessing catalyst in its native form, the performance odds increase to 22/24, i.e., 92%. Although the data also show that generally, rejuvenation does not contribute to higher COS conversion performance, it does for higher CS₂The conversion performance contributes. Overall, the data show that both the regenerated hydrotreating catalyst and the rejuvenated hydrotreating catalyst in their native form provide superior COS conversion performance relative to the fresh tail gas competitive reference catalyst. The solvent extraction and hot nitrogen stripping versions of catalyst F performed significantly worse than the fresh tail gas competitive reference catalyst. In fact, both showed half or less of the observed COS conversion for the fresh commercial tail gas reference catalyst at the highest temperature (300 ℃) and the conversion actually turned negative at the lowest temperature (220 ℃), i.e. net COS formation, indicating that these catalysts are very unsuitable for COS conversion.

As can be seen from fig. 3, the regenerated and rejuvenated hydroprocessing catalyst in its native form compares very favorably with the fresh tail gas competitive reference catalyst. To more fully understand how performance affects catalyst impact on Sulfur Recovery Efficiency (SRE), sulfur in SO was calculated₂、CS₂And a combined measure of overall conversion in COS (combined metric). The equation used to calculate this measure is reproduced in FIG. 4, and FIG. 4 also provides the use of these 13 catalystsComparison of the overall sulfur conversion obtained (table 3). All nine of the regenerated and rejuvenated hydrotreating catalysts in their native form outperformed the fresh tail gas competitive reference catalyst at 240 ℃ and above. At low temperatures of 220 ℃, the performance of 6 of the regenerated and rejuvenated catalysts was significantly better than the fresh exhaust gas competitive reference catalyst, while 3 were within 1%, which is a small difference. Thus, in practice, the performance of the regenerated and rejuvenated hydroprocessing catalyst in its native form is comparable to or better than that of the fresh commercial tail gas reference catalyst. Overall, this overall view of sulfur conversion performance indicates that the regenerated and rejuvenated hydroprocessing catalyst, if properly applied, can well replace the very mature tail gas catalyst products on the market, such as the measured fresh tail gas competitive reference catalyst. The performance of both the solvent extraction version and the hot nitrogen stripping version of catalyst F was significantly lower than the fresh tail gas competitive reference catalyst. The poor performance results of the solvent extraction and hot nitrogen stripping versions of catalyst F can be explained by the fact that coke deactivation of the spent catalyst is not eliminated by these treatments, as is the case with regeneration by thermal oxidation. The regeneration treatment is necessary to substantially remove the coke present on the catalyst and to ensure a high performance catalyst for this application.

Example 2 "stress test" at high space velocity (3,000GHSV) "

The performance of catalysts 1-4 and 13 described in example 1 was tested using the same experimental setup but under high space velocity conditions. The gas space velocity for the performance test conditions was 3,000GHSV, equivalent to a residence time of 1.2 seconds, intended to represent a "stress test" to further distinguish relative catalyst performance compared to the 1,200GHSV test. The performance test was performed under three different temperature conditions: 220 ℃, 250 ℃ and 280 ℃. Under each condition, the temperature was maintained for 12 hours. Analysis of the composition of the reactor effluent was performed every two hours by gas chromatography. From the analysis of the feed and effluent gases at each performance test condition, SO can be determined₂、CS₂And conversion of COS. Table 4 (FIG. 5) and FIGS. 6-9 showTest results at 3,000 GHSV.

FIG. 6 shows SO at 3000GHSV with five catalysts₂Conversion performance. Of the twelve performance data points generated by the four regenerated and rejuvenated hydroprocessing catalysts at each condition, only three were below the fresh tail gas competitive reference catalyst, while two of the three were less than 1% performance weak. The fact that nine of the twelve performance data points indicate excellent performance indicates that the hydrotreating catalyst is suitable for sulfur dioxide hydrogenation in Claus tail gas hydrogenation service. Overall, the conversion of all test samples above 220 ℃ is still very high: (>97%). Three of the four hydrotreating catalysts exhibited higher performance than the fresh tail gas competitive reference catalyst at 220 ℃.

FIG. 7 shows CS at 3000GHSV using five catalysts₂Conversion performance. Of the twelve performance data points generated by the five regenerated and rejuvenated hydrotreating catalysts at each condition, they all showed superior performance compared to the fresh tail gas competitive reference catalyst. The fact that all 12 data points show excellent performance indicates that the hydrotreating catalyst can be suitably used for CS in Claus tail gas hydrotreating₂And (4) hydrolyzing. The hydroprocessing catalysts tested not only performed well but also, overall, at large amplitudes (A), (B), (C), (D) and (D)>20%) performed well, which is a very surprising finding. As with the 1,200GHSV test outlined in example 1, it is important to note that these results also indicate that the regeneration process is enhanced for CS₂Activity of hydrolysis.

Fig. 8 shows COS conversion performance at 3000GHSV using five catalysts. Of the twelve performance data points generated by the four regenerated and rejuvenated hydroprocessing catalysts at each condition, only two were lower than the performance data points for the fresh tail gas competitive reference catalyst. Ten of the twelve performance data points indicate excellent performance, clearly showing that the hydrotreating catalyst can be suitable for COS hydrolysis in Claus tail gas hydrogenation service. Notably, the hydroprocessing catalyst samples tested were competitive with the fresh tail gas reference catalyst at 250 ℃ and aboveThe performance of the agent is about 20% higher. Only at 220 c, the conversion of COS was lower for two of the four hydrotreating catalysts than for the fresh tail gas competitive reference catalyst. For overall tail gas hydrogenation performance, the data indicates that both the regenerated and the rejuvenated forms can provide good performance compared to the fresh tail gas competitive reference catalyst. One interesting feature to note is thatThe rejuvenated catalyst a sample showed a negative conversion, or net formation, of COS at 220 ℃. This may be because the COS hydrolysis pathway of the catalyst is kinetically limited, thus not allowing close to the calculated equilibrium conversion and meaning that the rate of COS formation may be faster than the rate of reaction consumption. This is also indicated by the fact that at 220 ℃ and 1,200GHSV the conversion is about 62% (see example 1), but in this example at a higher space velocity (3000GHSV) the conversion drops to-20%, or 20% net formation.

In general, regenerated and rejuvenated hydroprocessing catalysts are advantageous compared to fresh tail gas competitive reference catalysts. Fig. 5 and 9 show the performance of these catalysts in terms of overall sulfur recovery efficiency (SRE, see equation of fig. 4) at 3000 GHSV. All of the regenerated and rejuvenated catalysts tested showed performance comparable or better to the fresh exhaust gas competitive reference catalyst for overall sulfur conversion performance. With the exception of the regenerated catalyst a sample at 220 ℃, the overall situation is one of the significantly superior performance compared to the fresh exhaust gas competitive reference catalyst. These "stress test" results further confirm that the findings from the true 1,200GHSV test in example 1, i.e., regenerated and rejuvenated hydrotreating catalyst, if applied correctly, can provide an excellent replacement for a very mature exhaust catalyst product on the market, such as a fresh exhaust competitive reference catalyst.

Example 3: preparation of regenerated 3.39 wt% cobalt-16.57 wt% molybdenum-balance alumina catalyst

The following are the preparation toolsWith 3.39 wt.% cobalt (as CoO) and 16.57 wt.% molybdenum (as MoO)₃) And the balance is mainly alumina (Al)₂O₃) Preparation procedure of the catalyst. The source of cobalt and molybdenum metals was from 2.5mm trilobe CoMo on a used alumina hydrotreating catalyst (see catalyst C-application 1 in table 1) containing 3.39% cobalt and 16.57% molybdenum as determined by XRF analysis. The hydroprocessing catalyst is regenerated by a regeneration process as described in example 1 above. In this way, a sample of regenerated catalyst C-application 1 was prepared for performance testing under real exhaust conditions (see data in tables 2 and 3).

While the invention disclosed herein has been described in terms of specific embodiments and applications thereof, numerous modifications and variations can be made thereto by those skilled in the art without departing from the scope of the invention set forth in the claims.

Example 4: preparation of a rejuvenated catalyst of 3.50 wt% nickel-15.86 wt% molybdenum-balance alumina.

The following is a preparation having 3.50 wt% nickel (as NiO) and 15.86 wt% molybdenum (as MoO)₃) And the balance is mainly alumina (Al)₂O₃) Preparation procedure of the catalyst. The source of nickel and molybdenum metals was from 2.5mm trilobe NiMo on a used alumina hydrotreating catalyst containing 3.50% nickel and 15.86% molybdenum as determined by XRF analysis. The catalyst is prepared by using a Porocel catalyst described in U.S. Pat. No. 9,895,679And (4) preparing a recovery process. In this way, prepareA sample of rejuvenated commercial hydrotreating catalyst D (2.5mm trilobe) was tested for performance under real tail gas conditions (see data in tables 2 and 3).

While the invention disclosed herein has been described in terms of specific embodiments and applications thereof, numerous modifications and variations can be made thereto by those skilled in the art without departing from the scope of the invention set forth in the claims.