Process for treating off-gas from hydroprocessing of renewable feedstocks

Abstract

A process for treating off-gas produced in the processing of renewable feedstocks, the process comprising hydrotreating a renewable feedstock to produce an effluent having a hydrotreated liquid and a gas phase. The effluent gas phase contains hydrogen, carbon dioxide, hydrogen sulfide, and carbon monoxide. The effluent is separated into a liquid stream and an off-gas stream. The off-gas stream containing carbon dioxide and hydrogen sulfide is directed to a biological desulfurization unit where a substantial portion of the hydrogen sulfide is converted to elemental sulfur and a CO2-rich gas stream is produced.

Description

Technical Field

[0001] This invention relates to the field of producing fuels and / or chemicals from renewable raw materials, and more particularly to the treatment of waste gases generated in the process. Background Technology

[0002] The increased energy demand resulting from global economic growth and development has led to an increase in the concentration of greenhouse gases in the atmosphere. This is considered one of the most important challenges facing humanity in the 21st century. To mitigate the impact of greenhouse gases, efforts have been made to reduce the global carbon footprint. The Earth system's capacity to absorb greenhouse gas emissions has been exhausted. Therefore, the goal is to achieve net-zero emissions by 2050. To achieve these emission reduction targets, the world is transitioning from a purely traditional carbon-based fossil fuel energy source. The timely realization of this energy transition requires a multi-pronged approach. For example, energy conservation, improved energy efficiency, and electrification may play a role, but efforts are also being made to utilize renewable resources to produce fuels and fuel components and / or chemical feedstocks.

[0003] For example, vegetable oils, oils derived from algae, and animal fats are considered new sources for fuel production. Additionally, deconstructed materials are seen as potential sources of renewable fuel materials, such as recyclable materials from pyrolysis or wood.

[0004] Renewable feedstocks can include materials with very high molecular weights and high viscosity, such as triglycerides, meaning that using them directly or as a mixture as fuel base is problematic for modern engines. On the other hand, the hydrocarbon chains that make up, for example, triglycerides are essentially linear, and their length (in terms of carbon number) is compatible with hydrocarbons used / used as fuel. Therefore, converting feedstocks containing triglycerides to obtain high-quality fuel components is attractive. Similarly, renewable feedstocks can contain unsaturated compounds and / or oxygenated compounds as unsaturated compounds.

[0005] Therefore, renewable feedstocks are hydrotreated to remove oxygen, and in cases where renewable feedstocks are co-processed with petroleum-derived feedstocks, the feedstocks are also hydrotreated to remove sulfur.

[0006] The effluent from the hydrotreating step comprises a hydrotreated liquid and a gaseous phase containing hydrogen, carbon dioxide, hydrogen sulfide, carbon monoxide, and light hydrocarbons. The effluent is then separated into a liquid and a waste gas stream using various methods. From both an economic and environmental perspective, it is preferable to recycle the waste gas back to the reaction zone. However, without treatment, the concentrations of CO2 and / or carbon monoxide will increase, thereby reducing the hydrogen partial pressure and negatively impacting the hydrotreating reaction. It is possible to recover hydrogen through conventional separation steps, typically along with the recovery of H2S, CO2, and / or carbon monoxide.

[0007] H2S-containing waste gas from conventional oil refineries is most commonly treated in the Claus unit. The Claus unit produces elemental sulfur from gaseous H2S by first reacting it with oxygen to generate sulfur dioxide and water. Then, the sulfur dioxide reacts with H2S to produce elemental sulfur and water.

[0008] The challenge of using a Claus unit to react H2S from exhaust gas from a hydrotreating reactor used to process renewable feedstocks lies in the higher CO2 content in the exhaust gas compared to conventional petroleum feedstocks due to the oxygen content of renewable feedstocks. Excessive CO2 can prevent the reaching of the required reaction temperatures and / or generate excessive byproducts such as carbonyl sulfide (COS). Therefore, there is a need to find alternatives to Claus units for managing exhaust gas streams from hydrotreating renewable feedstocks.

[0009] US7,999,143B2 (Marker et al.) describes a method for producing diesel fuel from renewable feedstock with reduced hydrogen consumption. The method involves hydrogenating and deoxygenating the renewable feedstock. Water is added to the deoxygenation reaction to drive the reaction of carbon monoxide and water to form hydrogen and CO2. The gaseous effluent from the isomerization reactor is introduced into a system of at least two amine absorbers to separate CO2 and H2S from the effluent. The amine in the first amine absorber is regenerated to release CO2 and H2S. The released CO2 and H2S are passed to a second amine scrubber containing amines that are selective for H2S but not for CO2. The H2S is recycled to the deoxygenation zone.

[0010] One challenge of relying on two amine scrubbers in series is that the H2S released from the second amine scrubber is in a low-pressure gas stream and requires extensive compression. Therefore, the need for extensive compression increases the operating cost of the method.

[0011] There is still a need for cost-effective methods to treat exhaust gases from the hydrogenation process of renewable fuels. Summary of the Invention

[0012] According to one aspect of the present invention, a method for treating waste gas generated in the processing of renewable feedstock is provided, the method comprising the steps of: hydrogenating the renewable feedstock to produce an effluent comprising a hydrogenated liquid and a gaseous phase containing hydrogen, carbon dioxide, hydrogen sulfide and carbon monoxide; separating the effluent into one or more liquid streams and one or more waste gas streams, wherein at least one of the waste gas streams comprises carbon dioxide and hydrogen sulfide; directing at least one of the one or more waste gas streams to a biological desulfurization unit; and converting a majority of the hydrogen sulfide in the biological desulfurization unit into elemental sulfur to produce a CO2-rich gas stream. Attached Figure Description

[0013] The method of the present invention can be better understood by referring to the following preferred embodiments and the accompanying drawings mentioned therein, in which:

[0014] Figure 1 This is a flowchart illustrating one embodiment of the method of the present invention having a separation unit downstream of a hydrotreating reactor;

[0015] Figure 2 This is a flowchart illustrating another embodiment of the method of the present invention having a thermal separator and a cold separator downstream of a hydrotreating reactor;

[0016] Figure 3 This is a flowchart illustrating another embodiment of the method of the present invention having a thermal separator, a cold separator, and a PSA unit downstream of a hydrotreating reactor;

[0017] Figure 4 This is a flowchart illustrating another embodiment of the method of the present invention having a thermal separator, a cold separator, and an amine scrubber downstream of a hydrotreating reactor;

[0018] Figure 5 This is a flowchart illustrating another embodiment of the method of the present invention having a thermal separator, a cold separator, a PSA unit, and an amine scrubber downstream of a hydrotreating reactor;

[0019] Figure 6 This is a flowchart illustrating another embodiment of the method of the present invention having a thermal separator, a cold separator, and a stripper downstream of a hydrotreating reactor;

[0020] Figure 7 This is a flowchart illustrating another embodiment of the method of the present invention having an integrated stripper and hot separator, a cold separator and a PSA unit, and a flowchart illustrating an embodiment of further processing; and

[0021] Figure 8 and Figure 9 This is a flowchart illustrating two embodiments of the biological desulfurization unit used in the method of the present invention. Detailed Implementation

[0022] This invention provides a method for treating waste gas generated during the hydrotreating of renewable feedstocks. The effluent generated during hydrotreating comprises a hydrotreated liquid and a gaseous phase containing hydrogen, carbon dioxide, hydrogen sulfide, light hydrocarbons, and carbon monoxide. The effluent is separated into one or more liquid streams and one or more waste gas streams. According to the invention, at least one of the waste gas streams containing H2S and CO2 is directed to a biological desulfurization unit. In the biological desulfurization unit, H2S is converted into elemental sulfur, thereby producing a CO2-rich gas stream with a reduced H2S content. Elemental sulfur can be used in the production of, for example but not limited to, fungicides, fertilizers, pesticides, pharmaceuticals, cosmetics, rubber products, vulcanizing agents for hydrotreating, and sulfuric acid.

[0023] The method of this invention is important for energy transition and can improve the environment by producing energy and / or chemicals from renewable resources, particularly from biodegradable waste sources. In a preferred embodiment, a CO2-rich gas stream is captured, stored, and / or sequestered, thereby reducing the carbon concentration in processes used to produce fuels and / or chemicals from renewable resources.

[0024] Renewable feedstocks include materials suitable for producing fuels, fuel components, and / or chemical feedstocks. A preferred class of renewable materials are biorenewable fats and oils comprising triglycerides, diglycerides, monoglycerides, free fatty acids, and / or fatty acid esters derived from biorenewable fats and oils. Examples of fatty acid esters include, but are not limited to, fatty acid methyl esters and fatty acid ethyl esters. Biorenewable fats and oils include both edible and inedible fats and oils. Examples of biorenewable fats and oils include, but are not limited to, algae oil, brown oils, low-erucic acid rapeseed oil, safflower oil, castor oil, coconut oil, rapeseed oil, corn oil, cottonseed oil, fish oil, jatropha oil, lard, flaxseed oil, milk fat, mustard oil, olive oil, palm oil, peanut oil, rapeseed oil, sewage sludge, soybean oil, soybean meal, sunflower oil, tallow, beef tallow, used cooking oils, yellow oils, and combinations thereof.

[0025] Another preferred class of renewable materials are liquids derived from biomass and waste liquefaction processes. Examples of such liquefaction methods include, but are not limited to, (hydrogen) pyrolysis, hydrothermal liquefaction, plastic liquefaction, and combinations thereof. Renewable materials derived from biomass and waste liquefaction processes can be used alone or in combination with biorenewable fats and oils.

[0026] The method of the present invention is particularly advantageous in the processing of renewable feedstocks. However, in one embodiment of the invention, the renewable feedstock can be co-processed with petroleum-derived hydrocarbons. Petroleum-derived hydrocarbons include, but are not limited to, all fractions from crude oil, natural gas condensate, tar sands, shale oil, synthetic crude oil, and combinations thereof. The combined renewable feedstock and petroleum-derived feedstock can have a renewable feed content ranging from 1% to 99% by weight.

[0027] Reactions in the hydrotreatment step include hydrogenation, hydrodeoxygenation, hydrodenitrogenation, hydrodesulfurization, and combinations thereof. Following the hydrotreatment step, hydroisomerization, selective cracking, and / or hydrodearomatization may be carried out in one or more catalyst beds / zones, in the same or different reactors, with or without gas separation.

[0028] The hydrotreating catalyst can be any catalyst known in the art suitable for hydrotreating, typically containing Group VIII and / or Group VIB metals. Hydrotreating catalysts in sulfide form are generally more active than those in oxide form. Meanwhile, renewable feedstocks typically have low sulfur content. Therefore, a sulfiding agent is added to the feedstock to maintain the catalyst in its sulfide form.

[0029] Preferably, the hydrotreatment catalyst comprises a sulfided catalytically active metal. Examples of suitable catalytically active metals include, but are not limited to, nickel sulfide, cobalt sulfide, molybdenum sulfide, tungsten sulfide, CoMo sulfide, NiMo sulfide, MoW sulfide, NiW sulfide, and combinations thereof. The catalyst bed / zone may have a mixture of two types of catalysts and / or a continuous bed / zone, including a stacked bed, and may have the same or different catalysts and / or catalyst blends. In the case of such sulfided hydrotreatment catalysts, a sulfur source is typically provided to the hydrotreatment catalyst to maintain the catalyst in a sulfided form during the hydrotreatment step.

[0030] The hydrogenation component can be used in bulk metallic form or the metal can be loaded onto a support. Suitable supports include refractory oxides, molecular sieves, and combinations thereof. Examples of suitable refractory oxides include, but are not limited to, alumina, amorphous silica-alumina, titanium dioxide, silica, and combinations thereof.

[0031] Hydrotreating catalysts can be sulfided in situ or ex-situ. In-situ sulfidation can be achieved by providing a sulfur source to the hydrotreating catalyst during process operation, typically H2S or H2S precursors (i.e., compounds that readily decompose into H2S, such as, for example, dimethyl disulfide, di-tert-nonyl polysulfide, or di-tert-butyl polysulfide). The sulfur source can be supplied with the feed, the hydrogen stream, or separately. Another suitable sulfur source is a sulfur-containing hydrocarbon stream co-fed with the feedstock whose boiling point is within the boiling range of diesel or kerosene. Furthermore, the addition of sulfur compounds to the hydrotreating feedstock helps control catalyst stability and reduce hydrogen consumption.

[0032] Preferably, H2S is supplied to the hydrotreating processor in an amount ranging from 50 ppmv to 5,000 ppmv, more preferably from 100 ppmv to 3,000 ppmv, and more preferably from 500 ppmv to 2,000 ppmv, or an equal amount of H2S precursor is supplied to the hydrotreating step based on the volume of hydrogen supplied. The amount of H2S depends on many factors, including, for example, the gas:oil ratio in the hydrotreating step.

[0033] Preferably, the hydrotreating step is carried out in the presence of hydrogen under hydrotreating conditions with a catalyst in the presence of 50 w-ppm to 20,000 w-ppm, preferably 1,000 w-ppm to 8,000 w-ppm, and most preferably 2,000 w-ppm to 5,000 w-ppm sulfur (calculated as elemental sulfur) in the total feed. The “total feed” of the hydrotreating processor refers to the total amount of fresh feed and any optional diluent.

[0034] The operating conditions in the hydrotreating step include pressures ranging from 1.0 MPa to 20 MPa based on the fresh feed, temperatures ranging from 200°C to 410°C, and operating conditions at 0.3 m... 3 / m 3 .h to 5m 3 / m 3 The liquid hourly space velocity is within the range of .h. Preferably, the pressure is selected from 2.0 MPa to 15 MPa. Preferably, the temperature is in the range of 200°C to 400°C, more preferably 240°C to 390°C, and most preferably 260°C to 385°C.

[0035] To control any temperature rise in the catalyst bed / zone, staged supply of feedstock and / or hydrogen can be applied. Another method to control temperature rise in the catalyst bed / zone is to dilute the feedstock, preferably via a hydrotreated liquid stream in the recirculation section. An alternative method to control temperature in the catalyst bed / zone is to introduce a hydrotreated liquid stream and / or recirculated gas as a quenching stream between the catalyst beds / zones.

[0036] In the hydrotreating step, the ratio of hydrogen supplied to feed is in the range of 200 to 10,000 standard L (under standard conditions of 0°C and 1 atm (0.101 MPa)) / kg feed, preferably 500 NL / kg to 8,000 NL / kg, more preferably 800 NL / kg to 3,000 NL / kg. The feed referred to herein is the total amount of fresh feedstock excluding diluents.

[0037] The hydrotreating step produces an effluent containing a hydrotreated liquid and a gaseous phase containing hydrogen, H2S, CO2, carbon monoxide, and light hydrocarbons.

[0038] The effluent is separated into one or more liquid streams and one or more waste gas streams. At least one of the waste gas streams contains CO2 and H2S. The concentrations of H2S and CO2 in the waste gas stream depend on the feedstock and the process conditions selected for the desired product. Preferably, the concentration of H2S in the waste gas stream is in the range of 50 ppmv to 5000 ppmv, more preferably 100 ppmv to 3000 ppmv, and most preferably 500 ppmv to 2000 ppmv. Preferably, the concentration of CO2 in the waste gas stream is in the range of 0.05 vol% to 15 vol%, more preferably 0.2 vol% to 10 vol%, and most preferably 1 vol% to 5 vol%. The volume ratio of CO2 to H2S in the waste gas stream is in the range of 500:1 to 1:1, preferably in the range of 200:1 to 3:1, more preferably in the range of 100:1 to 5:1, and even more preferably in the range of 50:1 to 7:1. The waste gas stream containing CO2 and H2S is then directed to the biological desulfurization unit, where H2S is converted into elemental sulfur and a CO2-rich gas stream is generated.

[0039] Several embodiments of the processing unit for implementing the method of the present invention are shown in Figures 1 to 7 For ease of discussion, additional equipment and process steps that can be used in methods for producing fuels and / or chemicals from renewable feedstocks are not shown. Additional equipment and / or process steps may include, for example, but not limited to, pre-processors, heaters, coolers, air coolers, heat exchangers, mixing chambers, valves, pumps, compressors, condensers, quenching streams, recirculation streams, slipstreams, scavenging streams, etc.

[0040] The process flow illustrating one embodiment of the present invention is shown in the diagram. Figure 1In this process, feed 12 is fed into hydrotreating reactor 14, with or without pretreatment. Hydrotreating reactor 14 produces an effluent containing a hydrotreated liquid and a gaseous phase containing hydrogen, H2S, CO2, carbon monoxide, and light hydrocarbons. The effluent from hydrotreating reactor 14 is then directed to one or more separation units 16 to separate the product into one or more liquid streams and one or more waste gas streams 20. At least one of the one or more waste gas streams 20 is directed to biological desulfurization unit 18. Figure 1 Other treated gas streams (not shown) may be generated during the process, including, for example, hydrogen-rich streams, fuel-rich gas streams, carbon monoxide, and combinations thereof. The biodesulfurization unit 18 converts most of the H2S to elemental sulfur 22 and generates one or more treated gas streams 24. Preferably, at least 90 mol% of H2S is converted to elemental sulfur. More preferably, 90 to 100 mol% of H2S is converted to elemental sulfur. The treated gas streams may include, for example, CO2 streams, fuel gas streams, and / or hydrogen-rich gas streams. The CO2 stream is preferably further treated for storage and / or sequestration. The hydrogen-rich gas stream is preferably recycled to the hydrotreatment reactor 14 and / or stripper. Depending on the pressure of the hydrogen-rich gas stream, for example due to the type of separation unit 16, the stream may be compressed to a higher pressure before recycling. In another embodiment, a methane-containing stream is directed to a hydrogen production unit.

[0041] One or more separation units 16 include, but are not limited to, gas / liquid separators, including hot high-pressure and low-pressure separators, intermediate high-pressure and low-pressure separators, cold high-pressure and low-pressure separators, strippers, integrated strippers, and combinations thereof. Integrated strippers include strippers integrated with hot high-pressure and low-pressure separators, intermediate high-pressure and low-pressure separators, and cold high-pressure and low-pressure separators. Those skilled in the art will understand that the high-pressure separator operates at a pressure close to that of the hydrotreatment reactor 14, suitably 0 to 10 bar (0 MPa to 1 MPa) lower than the reactor outlet pressure, while the low-pressure separator operates at a pressure lower than that of the hydrotreatment reactor 14 or the high-pressure separator, suitably 0 to 15 bar (0 MPaG to 1.5 MPaG). Similarly, those skilled in the art will understand that "hot" refers to the operation of the hot separator at a temperature close to that of the hydrotreatment reactor 14, suitably sufficiently above the water dew point (e.g., ≥20°C, preferably ≥10°C above the water dew point) and sufficiently above the salt deposition temperature (e.g., ≥20°C, preferably ≥10°C above the salt deposition temperature), while the intermediate and cold separators are at reduced temperatures relative to the hydrotreatment reactor 14. For example, the cold separator is suitably at a temperature achievable by an air cooler. "Intermediate temperature" should be understood to refer to any temperature between the temperatures of the hot and cold separators.

[0042] In addition, one or more separation units 16 may include, for example, but not limited to, amine scrubbers, pressure swing adsorption units, alkaline scrubbers, and combinations thereof.

[0043] exist Figure 2 In the illustrated embodiment, one or more separation units 16 include a thermal separator (HS) 16a, such as a hot high-pressure separator, a hot low-pressure separator, and / or an integrated stripper separator, and a cold separator (CS) 16b, such as a cold high-pressure separator and / or a cold low-pressure separator. In addition to light hydrocarbons, CO2, carbon monoxide, and H2S, HS16a also flashes out a hydrogen-rich gas, producing a liquid effluent. The HS16a exhaust gas is then cooled, for example in an air cooler (not shown) or a heat exchanger (not shown), and directed to CS16b, where at least a portion of the light hydrocarbons are separated from the exhaust gas stream as a liquid effluent. The exhaust gas stream 20 is directed to a biological desulfurization unit 18. Following the separation steps in HS16a and CS16b, the concentrations of H2S and CO2 in the exhaust gas stream 20 depend on the feedstock and process conditions selected for the desired products.

[0044] A portion of the liquid effluent from HS16a and / or CS16b can be recycled and / or used as a diluent and / or quenching stream between catalyst beds in the hydrotreatment reactor 14. Recycling from HS16a reduces operating costs associated with pumping and / or heating.

[0045] In one embodiment, the liquid effluent from HS16a and / or CS16b is fractionated into two or more product streams. In another embodiment, the liquid effluent is further processed, for example by hydroisomerization, hydrocracking, selective cracking, hydrodearomatization, and combinations thereof. In a preferred embodiment, exhaust gases from these further processing reactors / zones may be mixed with exhaust gas streams 20 from one or more separation units 16.

[0046] exist Figure 3 In the illustrated embodiment, one or more separation units 16 include HS16a, CS 16b, and a pressure swing adsorption (PSA) unit 16c. The exhaust gas stream from CS16b is directed to the PSA unit 16c to separate a hydrogen-rich stream from the exhaust gas stream 20 containing CO2 and H2S. The hydrogen-rich stream is preferably compressed in compressor 26 to recycle it to the hydrotreatment reactor 14, stripper, and / or another treatment unit. The exhaust gas stream 20 from PSA unit 16c is directed to a biological desulfurization unit 18. The exhaust gas stream 20 may also contain a portion of the exhaust gas from HS16a and / or CS16b.

[0047] exist Figure 4In the illustrated embodiment, one or more separation units 16 include HS16a, CS 16b, and an amine scrubber 16d. The exhaust gas stream from CS16b is directed to the amine scrubber 16d to separate a hydrogen-rich stream from the exhaust gas stream 20 containing CO2 and H2S. The hydrogen-rich stream is preferably compressed in compressor 26 to recycle the hydrogen to the hydrotreating reactor 14 and / or another treatment unit. The amine scrubber 16d may be a scrubber for removing carbon monoxide containing monoethanolamine (MEA), diethanolamine (DEA), methyldiethanolamine (MDEA), promoted MEA, DEA, and / or MDEA, activated MEA, DEA, and / or MDEA, and combinations thereof. The exhaust gas stream 20 from the amine scrubber 16d is directed to the biological desulfurization unit 18. The exhaust gas stream 20 may also contain a portion of the exhaust gas from HS16a and / or CS16b.

[0048] exist Figure 5 In the illustrated embodiment, one or more separation units 16 include HS16a, CS 16b, PSA unit 16c, and amine scrubber 16d. Exhaust gas from CS16b is directed to PSA unit 16c to separate a hydrogen-rich stream from the exhaust gas containing CO2 and H2S. The hydrogen-rich stream is preferably compressed in compressor 26 to recycle the hydrogen to hydrotreating reactor 14 and / or another treatment unit. Exhaust gas from PSA unit 16c is then directed to amine scrubber 16d to separate CO2- and H2S-lean scrubbing gas 25, thereby generating CO2- and H2S-rich exhaust gas 20. Exhaust gas 20 from amine scrubber 16d is directed to biodesulfurization unit 18. Exhaust gas 20 may also contain a portion of the exhaust gas from HS16a, CS16b, and / or PSA unit 16c. Scrubbing gas 25 may contain, for example, hydrogen, carbon monoxide, and methane.

[0049] exist Figure 6 In the illustrated embodiment, one or more separation units 16 include HS16a, CS 16b, and a stripper 16e. All or part of the liquid effluent from HS16a is directed to the stripper 16e, where pure hydrogen or a hydrogen-rich stream is used to separate any remaining entrained and / or dissolved gases from the hydrotreated liquid effluent. The liquid effluents from stripper 16e and CS16b may be further processed together or separately as previously described. At least a portion of the exhaust gas from CS16b is directed in exhaust gas stream 20 to the biodesulfurization unit 18. The exhaust gas from stripper 16e may be compressed in compressor 26 to recycle hydrogen to hydrotreatment reactor 14 and / or another treatment unit. Alternatively or additionally, exhaust gas stream 20 may also include a portion of the exhaust gas from HS16a and / or stripper 16e.

[0050] Figure 7An embodiment showing the integration of the hydrotreating reactor 14 and the hydroisomerization reactor 28 is illustrated. (See example...) Figure 7 As shown, one or more separation units 16 include an integrated stripper and hot high-pressure separator (HHPS) 16f, CS 16b, and PSA unit 16c. However, it should be understood that other combinations of separation units 16 as described and / or shown herein can be used for integration of the methods of the present invention with a hydroisomerization reactor 28 or other further processing units.

[0051] exist Figure 7 In one embodiment, the effluent from the hydrotreatment reactor 14 is directed to an integrated stripper and HHPS 16f, wherein at least a portion of the gaseous components in the liquid effluent is separated from and / or stripped from the liquid phase. The liquid feed from the integrated stripper and HHPS 16f is then fed to the hydroisomerization reactor 28.

[0052] Figure 7 Two alternative embodiments are also shown (dashed lines). In one alternative embodiment, a portion of the hydrotreated liquid is recycled to feed 12 in a recirculation stream 36. The volume ratio of the recirculated hydrotreated liquid 36 to the fresh feed 12 is preferably in the range of 1:1 to 30:1. In another alternative embodiment, a portion of the hydrotreated liquid is provided to the hydrotreatment reactor 14 as one or more quench streams 38. The quench streams 38 are used to control the temperature in the hydrotreatment reactor 14 and are therefore typically cooled using, for example, an air cooler (not shown) or a heat exchanger (not shown). One or more quench streams 38 may be added between catalyst beds / zones in the hydrotreatment reactor 14.

[0053] Alkane in the hydrotreated liquid is isomerized in hydroisomerization reactor 28 using a suitable isomerization catalyst, which includes, but is not limited to, Group VIII metals supported on refractory oxides and / or molecular sieves, particularly platinum and / or palladium.

[0054] like Figure 7 As shown, the effluent from the hydroisomerization reactor 28 is conveyed to a separator 32, such as an HHPS, to separate the isomerized liquid product from the waste gas stream. In a preferred embodiment, the isomerized waste gas stream is used as the stripping gas in the integrated stripper and HHPS 16f. In another embodiment, the stripping gas for the integrated stripper and HHPS 16f is provided wholly or partially from a fresh hydrogen stream, hydrogen from an integrated steam reformer or gasification unit, hydrogen recirculated from PSA unit 16b, and combinations thereof. Alternatively or additionally, the isomerized waste gas stream may be added to the stream from PSA unit 16c to compressor 26, preferably using an intermediate CHPS (not shown).

[0055] The isomerized liquid product from separator 32 is fed into product stripper 34 to strip the waste gas stream 44 from the isomerized liquid product 42. The stripped isomerized liquid product 42 can then be further processed, for example by fractionation (not shown) into products with different boiling point ranges, including diesel, naphtha and jet fuel.

[0056] The exhaust gas stream from CS16b is directed to PSA unit 16c to separate a hydrogen-rich stream from the exhaust gas stream 20, which contains CO2 and H2S. The hydrogen-rich stream is preferably compressed in compressor 26 to recycle the hydrogen to hydrotreating reactor 14 and / or another treatment unit.

[0057] exist Figures 1 to 7 In one embodiment, feed 12 is shown being fed into the top of the hydrotreatment reactor 14. However, feed 12 may be split and fed into the hydrotreatment reactor 14 at two or more inlets at the top of the hydrotreatment reactor 14 and / or, for example, at multiple points (not shown) between catalyst beds along the length of the hydrotreatment reactor 14. Similarly, in any embodiment, a recirculated stream (not shown) from a separation unit downstream of the hydrotreatment reactor 14 may be added to feed 12.

[0058] The hydrotreatment reactor 14 may include one or more catalyst beds or one or more reaction vessels, each vessel containing one or more catalyst beds (not shown). The catalyst beds may be the same or different. The hydrotreatment reactor 14 may also include one or more guard beds (not shown) for capturing contaminants in the feed 12 and / or reacting with such contaminants. The hydrotreatment reactor 14 may also include one or more catalyst beds for hydroisomerization, selective cracking, and / or hydrodearomatization.

[0059] Then from Figures 1 to 7 At least a portion of one or more exhaust gas streams 20 from one or more separation units 16 shown is directed to the biological desulfurization unit 18.

[0060] Figure 8 An embodiment of the biological desulfurization unit 18 is shown. One or more waste gas streams 20 are fed into the absorption tower 52. Preferably, liquid adsorbent 54 is fed into the absorption tower 52 in a countercurrent manner relative to the waste gas streams 20.

[0061] The liquid adsorbent 54 is preferably a liquid alkaline adsorbent capable of absorbing H2S and CO2. More preferably, the liquid adsorbent 54 is selected from sodium carbonate, sodium bicarbonate, potassium carbonate, potassium bicarbonate, and combinations thereof. A hydrogen-containing waste gas stream 24, depleted of H2S and CO2, is obtained from the adsorption tower 52. In one or more embodiments, the hydrogen is compressed and recycled to the hydrotreatment reactor 14, the stripper 16e, the integrated stripper and HHPS 16f and / or the hydroisomerization reactor 28. In other embodiments, the hydrogen-containing waste gas stream is directed to a reforming unit.

[0062] An aqueous liquid adsorbent 54 loaded with H2S and CO2 is directed to one or more bioreactors 56. Microorganisms in the bioreactors 56 convert sulfides into elemental sulfur. The microorganisms are preferably sulfur-oxidizing microorganisms. Suitable microorganisms include, but are not limited to, sulfide-oxidizing bacteria selected from the genera *Halothiobacillus*, *Thioalkalimicrobium*, *Thioalkalispira*, *Thioalkalibacter*, sulfur-oxidizing bacteria (Thioalkalivibrio), and related bacteria.

[0063] Bioreactor 56 can operate in anaerobic, aerobic, or a combination thereof. Nutrients (not shown) can be added to bioreactor 56. Microorganisms can be provided in suspension, immobilized on a suitable support, provided as a sludge layer or membrane, or a combination thereof.

[0064] Figure 9 An embodiment of a biological desulfurization unit 18 with an anaerobic bioreactor 56a and an aerobic bioreactor 56b is shown. In anaerobic operation mode, H2S is selectively converted into elemental sulfur, with almost no sulfate production. Figure 9 In one embodiment, microorganisms from anaerobic bioreactor 56a are regenerated in aerobic bioreactor 56b. An oxygenated stream 58 (e.g., air) is injected into aerobic bioreactor 56b.

[0065] exist Figure 8 and Figure 9 In one embodiment, the liquid product stream from bioreactors 56 and 56b is conveyed to separator 64 to separate precipitated solid elemental sulfur 22. Separator 64 may be a settling tank, decanter, centrifuge, filter press, or a combination thereof.

[0066] The biological desulfurization unit 18 converts most of the H2S supplied to the unit into elemental sulfur. Preferably, at least 90 mol% of the H2S is converted into elemental sulfur. More preferably, 90 to 100 mol% of the H2S is converted into elemental sulfur. Preferably, less than 5 mol% of the H2S is converted into other sulfur compounds, such as sulfates and thiosulfates.

[0067] The biological desulfurization unit can be purchased from Paqell BV (Amsterdam, NL). O&G units. Examples of suitable desulfurization units are described, for example, in US10,543,458B2 (Klok et al.) and US9,902,975B2 (Klok et al.).

[0068] Example

[0069] For illustrative purposes only, the following non-limiting embodiments of the method of the invention claimed herein are provided.

[0070] The palm oil feedstock was used in a pilot plant for hydrotreating. Based on data collected during the pilot plant tests, in Figure 7 The simulation of H2S and CO2 content of other raw materials and products was determined at two points in the process shown.

[0071] Simulations were performed on the raw materials and products listed in Table I. Summer diesel fuel has a cloud point of -5°C.

[0072] Table I

[0073] 1 100% soybeans Summer diesel 2 100% tallow Summer diesel

[0074] For each of the feed / product combinations listed in Table I, the simulation provides Figure 7 The expected concentrations of H2S and CO2 at points A and B. Point A represents the hydrotreatment product at the outlet of hydrotreatment reactor 14. The values ​​in Table 2 are provided for the total effluent and the gas phase of the effluent. Point B represents the exhaust gas stream 20 from PSA unit 16c. The results are shown in Table II.

[0075] Table II

[0076]

[0077] Simulation results show that CO2 concentrations are relatively higher than H2S, posing a challenge to conventional gas treatment via the Claus reaction. The simulations also confirm that treating the waste gas stream within a biological desulfurization unit provides improved gas treatment, offering environmental and economic advantages over conventional solutions.

[0078] While various embodiments and uses have been described with reference to them, it should be understood that these embodiments are exemplary and the scope of the invention is not limited thereto. Many variations, modifications, additions, and improvements are possible.

Claims

1. A method for treating waste gas generated during the processing of renewable raw materials, the method comprising the following steps: - Hydrotreating renewable feedstocks to produce effluents containing a hydrotreated liquid and a gaseous phase containing hydrogen, carbon dioxide, hydrogen sulfide and carbon monoxide; - Separate the effluent into one or more liquid streams and one or more waste gas streams, wherein at least one of the waste gas streams contains carbon dioxide and hydrogen sulfide; - To guide at least one of the one or more waste gas streams to the biological desulfurization unit; and - The majority of the hydrogen sulfide in the biological desulfurization unit is converted into elemental sulfur and a CO2-rich gas stream is generated.

2. The method of claim 1, wherein the separation step comprises directing the effluent to one or more separator units selected from the group consisting of: hot high-pressure separators, hot low-pressure separators, intermediate high-pressure separators, intermediate low-pressure separators, cold high-pressure separators, cold low-pressure separators, strippers, and combinations thereof, and optionally amine separators, pressure swing adsorption units, alkaline washes, and combinations thereof.

3. The method of claim 1, wherein the separation step includes directing the effluent to one or more separator units, the separator unit being an integrated stripper.

4. The method according to claim 1, wherein the hydrotreating step further comprises the step of sulfiding the hydrotreating catalyst used for hydrotreating the renewable feedstock.

5. The method of claim 4, wherein the hydrotreating catalyst comprises a catalytically active amount of a metal selected from the group consisting of Group VIII, Group VIB, and combinations thereof.

6. The method of claim 4, wherein the sulfidation step comprises adding a gas stream of hydrogen sulfide, providing a hydrogen sulfide precursor, and combinations thereof.

7. The method according to claim 1, wherein the hydrogen sulfide concentration of the exhaust gas stream is in the range of 50 ppmv to 5,000 ppmv.

8. The method according to claim 7, wherein the hydrogen sulfide concentration of the exhaust gas stream is in the range of 100 ppmv to 3,000 ppmv.

9. The method of claim 7, wherein the hydrogen sulfide concentration of the exhaust gas stream is in the range of 500 ppmv to 2,000 ppmv.

10. The method of claim 1, wherein the carbon dioxide concentration of the exhaust gas stream is in the range of 0.05 vol% to 15 vol%.

11. The method of claim 10, wherein the carbon dioxide concentration of the exhaust gas stream is in the range of 0.2 vol% to 10 vol%.

12. The method of claim 10, wherein the carbon dioxide concentration of the exhaust gas stream is in the range of 1 vol% to 5 vol%.

13. The method according to claim 1, wherein the volume ratio of carbon dioxide to hydrogen sulfide in the exhaust gas stream is in the range of 500:1 to 1:

1.

14. The method according to claim 13, wherein the volume ratio of carbon dioxide to hydrogen sulfide in the exhaust gas stream is in the range of 200:1 to 3:

1.

15. The method according to claim 13, wherein the volume ratio of carbon dioxide to hydrogen sulfide in the exhaust gas stream is in the range of 100:1 to 5:

1.

16. The method of claim 13, wherein the volume ratio of carbon dioxide to hydrogen sulfide in the exhaust gas stream is in the range of 50:1 to 7:

1.

17. The method of claim 2, wherein hydrogen is separated from the one or more waste gas streams in the pressure swing adsorption unit prior to the conversion step, optionally further comprising the step of recycling the hydrogen to the hydrotreating step.

18. The method of claim 1, wherein at least 90 mol% of the hydrogen sulfide is converted into elemental sulfur.

19. The method of claim 18, wherein 90 mol% to 100 mol% of the hydrogen sulfide is converted into elemental sulfur.

20. The method according to claim 1, wherein the biological desulfurization unit comprises an absorption tower, a bioreactor, and a separator.

21. The method of claim 1, wherein the CO2-rich gas stream is provided to the carbon storage process.

22. The method of claim 1, wherein the CO2-rich gas stream is provided to the carbon sequestration process.

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