Process for producing fuels, base oils and / or chemicals from renewable feedstocks

Abstract

A renewable feedstock is pre-treated and subsequently hydrotreated to produce an effluent. The effluent is separated into liquid streams and off-gas streams. At least one of the off-gas streams comprises hydrogen sulfide. The off-gas streams are passed to a biological desulfurization unit in which a substantial portion of the hydrogen sulfide is converted to biological sulfur. At least a portion of the biological sulfur is recycled to the pre-treatment step.

Description

Technical Field

[0001] This invention relates to the field of producing fuels and / or chemicals from renewable raw materials. 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 multiple parallel approaches. For example, not only can energy conservation, improved energy efficiency, and electrification be effective, but efforts to utilize renewable sources to produce fuels and fuel components and / or chemical feedstocks can also play a role.

[0003] Vegetable oils, oils derived from algae, and animal fats are considered renewable resources. Furthermore, decomposed materials, such as pyrolyzed recyclable materials or wood, are considered potential resources.

[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 hydrogenated to remove oxygen, sulfur, nitrogen, metals, and olefins.

[0006] The metals used in hydrotreating catalysts are typically produced as metal oxides and loaded into the reactor. Renewable feedstocks (such as vegetable oils, animal fats, or wood) typically have a sulfur content far below 1% by weight, and therefore the sulfur content in these feedstocks is usually too low to sulfide the hydrotreating catalyst.

[0007] H2S is a toxic gas that causes health problems. Furthermore, the gas must be compressed before it can be used in higher-pressure hydrogenation processing units or stored in high-pressure containers / cylinders. Storage of H2S also represents a risk of leakage into the surrounding environment. Therefore, sulfur additives are typically added to the feed. In the reactor, the additives are converted into hydrogen sulfide, which in turn converts metal oxides into metal sulfides. Sulfur additives include dimethyl sulfide (DMS), dimethyl disulfide (DMDS), di-tert-nonyl polysulfide (TNPS), and sulfur. ® These are typically expensive. Furthermore, additives are often produced using fossil fuels.

[0008] 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.

[0009] 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.

[0010] 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.

[0011] Janssen (US20230416614A1, December 28, 2023) describes a method for treating waste gas from the hydrotreatment of renewable feedstocks. The effluent from the hydrotreatment zone is separated into a liquid stream and a waste gas stream. The waste gas stream, containing carbon dioxide and hydrogen sulfide, is passed to a biological desulfurization unit, where the hydrogen sulfide is converted into elemental sulfur. Janssen suggests that elemental sulfur can be used in the production of fungicides, fertilizers, pesticides, pharmaceuticals, cosmetics, rubber products, vulcanizing agents for hydrotreatment, and sulfuric acid.

[0012] Marker et al. (US2009 / 77864A1, March 26, 2009) disclose an integrated method for producing diesel fuel from renewable feedstocks and for cultivating algae and greenhouse plants. Carbon dioxide is separated from a vapor stream in a deoxygenation reaction zone. The separated carbon dioxide is then transferred to the algae cultivation operation. Hydrogen produced by the algae can be used in the reaction zone to produce diesel fuel. Hydrogen sulfide can also be separated from the vapor stream and recycled back to the deoxygenation reaction zone.

[0013] 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 directed to 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.

[0014] 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, which increases the operating cost of the method.

[0015] There is still a need for a cost-effective method to sulfide catalysts used for hydrotreating renewable fuels. Summary of the Invention

[0016] According to one aspect of the invention, a method is provided for fuels, base oils, and / or chemicals derived from renewable feedstocks, the method comprising the steps of: pretreating the renewable feedstock to produce a pretreated feedstock; hydrotreating the pretreated feedstock to produce an effluent comprising a hydrotreated liquid and a vapor phase containing hydrogen sulfide; separating the effluent into one or more liquid streams and one or more waste streams, wherein at least one of the waste streams contains hydrogen sulfide; directing at least one of the waste streams to a biodesulfurization unit; converting a majority of the hydrogen sulfide in the biodesulfurization unit into bio-sulfur; and recycling at least a portion of the bio-sulfur back to the pretreatment step. Attached Figure Description

[0017] The method of the present invention will be better understood by referring to the following preferred embodiments and the accompanying drawings referenced therein, wherein:

[0018] Figures 1 to 3 This is a flowchart illustrating an embodiment of the method of the present invention. Detailed Implementation

[0019] This invention provides a method for producing fuels, base oils, and / or chemicals from renewable feedstocks. The renewable feedstock is pretreated to produce a pretreated feedstock, which is then hydrotreated. The effluent from the hydrotreatment step comprises a hydrotreated liquid and a vapor phase containing hydrogen sulfide. 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 containing H2S is directed to a biosulfurization unit. In the biosulfurization unit, H2S is converted into biosulfur. According to the invention, at least a portion of the biosulfur is recycled to the pretreatment step.

[0020] Bio-sulfur produced by biological desulfurization units is typically considered a low- to negative-value product. Bio-sulfur is usually sent to landfills or used in fertilizer production. Transporting sulfur to landfills or fertilizer plants typically incurs associated costs. Alternatively, bio-sulfur has been used to produce liquid sulfur by melting and purifying the sulfur in bio-sulfur.

[0021] As noted above, treating exhaust gases from a method for producing fuels and chemicals from renewable feedstocks using conventional Claus processes presents challenges. Furthermore, the elemental sulfur produced in the Claus process is not well-mixable with renewable feedstocks, causing it to precipitate and melt from the mixture. The inventors have surprisingly discovered that bio-sulfur produced by a bio-desulfurization unit dissolves more readily in and is better utilized by renewable feedstocks.

[0022] Furthermore, the method of the present invention provides an integrated method for managing and reusing the byproducts of the method.

[0023] The method of this invention is important for energy transition and can improve the environment by producing energy and / or chemicals from renewable sources, particularly from biodegradable waste sources. By recovering biosulfur from the biosulfurization unit and reusing it in the hydrotreating step, the environmental impact of waste sulfur is reduced. Furthermore, the environmental impact of the production of conventional desulfurizing agents is reduced by decreasing or eliminating the need for them. In a preferred embodiment, a CO2-rich gas stream is generated, captured, stored, and / or sequestered, thereby reducing the carbon intensity of the method used to produce fuels and / or chemicals from renewable sources.

[0024] As used herein, the terms “renewable feedstock,” “renewable feed,” and “material from a renewable source” refer to feedstocks derived from renewable sources. Renewable sources can be animal, plant, microbial, and / or biologically derived or mineral-derived wastes suitable for producing fuels, fuel components, base oils, and / or chemical feedstocks. For example, vegetable oils, oils derived from algae, and animal fats are suitable renewable feedstocks. Furthermore, decomposed materials, such as pyrolytic recyclable materials or wood, are considered potential resources.

[0025] 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 oil, flaxseed oil, low-erucic acid rapeseed oil, carinata oil, castor oil, coconut oil, rapeseed oil, corn oil, cottonseed oil, fish oil, hemp seed 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, water chestnut oil, tall oil, tall oil fatty acids (TOFA), beef tallow, used cooking oil, yellow oil, white oil, and combinations thereof.

[0026] Another preferred class of renewable materials are liquids derived from biomass liquefaction 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 liquefaction and waste liquefaction processes can be used alone or in combination with biorenewable fats and oils.

[0027] The renewable materials used as raw materials in the methods of this invention may contain impurities. Examples of such impurities include, but are not limited to, solids, iron, chlorides, phosphorus, alkali metals, alkaline earth metals, polyethylene, and unsaponifiable compounds. The type and relative amount of impurities will depend on the type and quality of the raw material. Some impurities (e.g., unsaponifiable compounds) are permissible during processing. However, these impurities are removed from the renewable raw material prior to incorporation into the methods of this invention, if necessary. Examples of target impurities that are preferred to be removed from the renewable raw material include nitrogen, inorganic and organic chlorides, metals, and phosphorus.

[0028] 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 may 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. Petroleum-derived hydrocarbons typically have a sulfur content that eliminates the need for sulfur additives. Those skilled in the art will understand that the sulfur content of petroleum-derived hydrocarbons will depend on their source. The method of the present invention may be advantageous when the combined renewable and petroleum-derived feedstocks have a sulfur content of less than 0.3% by weight, preferably less than 0.2% by weight.

[0029] Now for reference Figure 1 The renewable raw material 12 is fed into the pretreatment unit 14. The pretreatment unit 14 is selected from the group consisting of: washing unit, adsorption unit, filtration unit, nanofiltration unit, evaporator, and combinations thereof.

[0030] An example of a suitable pretreatment unit 14 is described in Toukoniitty et al. (US11,427,782B2, August 30, 2022), which uses a silica-based adsorbent, a metal chloride adsorbent, or a metal oxide adsorbent to adsorb chlorides from a regenerable feed. An example of the use of nanofiltration pretreatment unit 14 is disclosed by den Boestert et al. (WO2022 / 129335A1, June 23, 2022).

[0031] Suitable washing fluids include, but are not limited to, water, chelating agents, acids (preferably weak acids), caustic agents, and combinations thereof. A preferred acid is citric acid. A preferred chelating agent is EDTA. Suitable adsorbents include, but are not limited to, silica hydrogels, treated and / or activated clays (e.g., acid-washed clays and bleaching clays), diatomaceous earth, and combinations thereof. In a preferred embodiment, the washing unit is followed by an adsorption unit. In a preferred embodiment, the adsorption unit preferentially adsorbs water-soluble polar contaminants rather than lipophilic substances.

[0032] The pretreated feedstock is fed to hydrotreating zone 16, where it is reacted under hydrotreating conditions sufficient to induce reactions selected from hydrotreating reactions (including, but not limited to, hydrodeoxygenation, hydronitrogenation, hydrodesulfurization, hydrodearomatization, hydrogenation, hydrodemetallization, and combinations thereof). The reactions in hydrotreating zone 16 are catalytic reactions. Hydrotreating zone 16 can be single-stage or multi-stage and can be operated as a slurry, moving bed, fluidized bed, and / or fixed bed. In the case of fixed bed operation, the reactor in hydrotreating zone 16 can have a single catalyst bed or multiple catalyst beds. Hydrotreating zone 16 can consist of a single reactor or multiple reactors. Hydrotreating zone 16 can operate in a co-current flow, counter-current flow, or a combination thereof. Preferably, hydrotreating zone 16 operates in a co-current flow mode.

[0033] The catalyst can be the same or different throughout the hydrotreating zone 16. The hydrotreating zone 16 may include a single catalyst bed or multiple catalyst beds. The catalyst can be the same throughout a single catalyst bed, optionally a mixture of catalysts may be present, or different catalysts may be provided in two or more layers of the catalyst bed. In embodiments with multiple catalyst beds, the catalyst in each catalyst bed may be the same or different.

[0034] In one embodiment, the hydrotreating zone 16 further comprises a hydrogenation catalyst prior to the hydrotreating catalyst. The hydrogenation component may be used in bulk metallic form or the metal may be supported on a support. The active metal for hydrogenation includes catalytically active metals of Group VIII and / or Group VIB, including but not limited to Ni, Co, Mo, W, and combinations thereof. 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. Examples of suitable molecular sieves include, but are not limited to, zeolite Y, zeolite β, ZSM-5, ZSM-12, ZSM-22, ZSM-23, ZSM-48, SAPO-11, SAPO-41, magnesium alkali zeolite, and combinations thereof.

[0035] The hydrotreating zone 16 may also include one or more guard beds (not shown) for capturing and / or reacting with remaining contaminants in the feed 12. The hydrotreating zone 16 may also include one or more catalyst beds for hydroisomerization, selective cracking, and / or hydrodearomatization.

[0036] The hydrotreatment catalyst can be any catalyst known in the art suitable for hydrotreatment. The catalyst metal is typically in an oxide state when loaded into the reactor and is activated by sulfiding the metal oxide. Preferably, the hydrotreatment catalyst comprises a Group VIII and / or Group VIB catalytically active metal, including but not limited to Ni, Co, Mo, W, and combinations thereof.

[0037] As discussed above, hydrotreating catalysts in sulfide form are generally more active than those in oxide form. Because renewable feedstocks typically have low sulfur content, sulfiding agents are often added to the feedstock or hydrotreating zone to maintain the catalyst in its sulfide form.

[0038] According to the invention, the catalyst in the hydrotreating zone 16 is sulfided by adding recycled bio-sulfur 26 from the biodesulfurization unit 18, as will be discussed in more detail below.

[0039] At start-up, bio-sulfur 26 produced in the bio-desulfurization unit by another or earlier method can be used in the manner described herein. Alternatively, the catalyst can initially utilize conventional sulfurizing agents such as DMS, DMDS, TNPS, and SULFRZOL. ® The catalyst is vulcanized using a conventional vulcanizing agent. When using a recycled bio-sulfur stream, the feed of the conventional vulcanizing agent will be stopped if the conventional vulcanizing agent is used first to vulcanize the catalyst.

[0040] Preferably, the hydrotreating 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 or more types of catalysts and / or a continuous bed / zone, including a stacked bed, and may have the same or different catalysts and / or catalyst mixtures.

[0041] Hydrotreating metals can be used in bulk metal form or supported on a substrate. Suitable substrates 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.

[0042] The operating conditions in the reactor of hydrotreating zone 16 include a pressure ranging from 1.0 MPa to 20 MPa based on the fresh feed, a temperature ranging from 200°C to 410°C, and a range of 0.3 m... 3 / m 3 .h to 5m 3 / m 3The liquid hourly space velocity is in 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.

[0043] The ratio of hydrogen supplied to the feed in the hydrotreating zone 16 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, and more preferably 800 NL / kg to 3,000 NL / kg. The feed referred to herein is the total amount of fresh feedstock excluding diluents.

[0044] The hydrotreating step produces an effluent containing a liquid phase of hydrotreating and a vapor phase containing hydrogen sulfide. Other components may be present in the vapor phase, including but not limited to hydrogen, carbon oxides (e.g., CO2 and / or CO), water, nitrogen, NH3, NO2, C1-C10 compounds, and combinations thereof. The relative amounts of components in the vapor phase can vary or change over time, depending at least on the catalyst, feed, and operating conditions. Typically, the vapor phase will contain H2S and CO2.

[0045] The effluent from the hydrotreating zone 16 is directed to one or more separation units 20 to separate the product into one or more waste gas streams 22 and one or more liquid streams 24. Examples of suitable embodiments of the separation units are disclosed in Janssen (US20230416614A1, December 28, 2023), but are not limited thereto.

[0046] A portion of one or more liquid streams 24 may be recycled to serve as a diluent and / or quench stream between catalyst beds in the reactor of the hydrotreating zone 16, for example, as Figure 3 As depicted. In cases where one or more separation units 20 include a thermal separator, the advantage of recirculating a portion of the liquid stream from the thermal separator is that it reduces operating costs associated with pumping and / or heating. Alternatively or additionally, the feed and / or hydrogen feed stream to the reactors in the hydrotreating zone 16 may be graded to two or more injection ports in each of the one or more reactors in the hydrotreating zone 16.

[0047] At least one of the one or more waste gas streams 22 containing H2S is directed to the biological desulfurization unit 18. Figure 1 The separation unit 20 of the method may generate other processed gas streams (not shown), including, for example, hydrogen-rich streams, fuel-rich gas streams, carbon monoxide, and combinations thereof.

[0048] When the waste gas stream 22 containing H2S contains CO2, the relative concentrations of H2S and CO2 in the waste gas stream depend on the feedstock and the process conditions selected for the desired product. When the waste gas stream 22 containing H2S does not contain CO2, CO2 can be added to the waste gas stream 22 or directly added to the biological desulfurization unit 18. 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.

[0049] The biological desulfurization unit 18 includes one or more bioreactors with sulfur-oxidizing microorganisms. Suitable microorganisms include, but are not limited to, sulfide-oxidizing bacteria, genetically modified bacteria, and combinations thereof selected from the genera *Halothiobacillus*, *Thioalkalimicrobium*, *Thioalkalispira*, *Thioalkalibacter*, and *Thioalkalivibrio*. One or more bioreactors may operate in anaerobic, aerobic, or combined modes. Microorganisms may be provided in suspension form, immobilized on a suitable support, provided as a sludge layer or membrane, and combinations thereof.

[0050] The biological desulfurization unit 18 can be a THIOPAQ purchased from Paqell BV (Utrecht, NL). ® O&G units. Examples of suitable desulfurization units are described, for example, in US 10,543,458B2 (Klok et al.) and US9,902,975B2 (Klok et al.).

[0051] The biological desulfurization unit 18 converts most of the H2S into bio-sulfur 26 and generates one or more treated gas streams 28. Preferably, 90 mol% to 100 mol% of H2S is converted into bio-sulfur. More preferably, 95 mol% to 100 mol% of H2S is converted into bio-sulfur. Preferably, less than 5 mol% of H2S is converted into other sulfur compounds, such as sulfates and thiosulfates. The treated gas streams may include, for example, a CO2 stream, a fuel gas stream, and / or a hydrogen-rich gas stream. The CO2 stream is preferably further treated for storage and / or sequestration.

[0052] An embodiment of bio-sulfur 26 produced in bio-desulfurization unit 18 is described in THIOPAQ dated 2008-10-09 (revised 2018-01-17). ® The material safety data sheet for sulfur is provided. Those skilled in the art will understand that the water content of the bio-sulfur 26 will be affected by the composition and operating conditions of the bio-sulfurization unit 18, which may also be affected by the environmental conditions of operation of the bio-sulfurization unit 18, particularly temperature. For example, if the bio-sulfurization unit 18 includes a settling centrifuge for separating bio-sulfur 26 from the effluent of the bioreactor, the resulting bio-sulfur 26 may have a solids content of approximately 60% by weight. However, if the bio-sulfurization unit 18 includes a settling tank for separating bio-sulfur 26 from the effluent of the bioreactor, the resulting bio-sulfur 26 may have a solids content of approximately 40% by weight.

[0053] Bio-sulfur 26 has a different morphology than conventional sulfur produced via the Claus process. In the Claus process, sulfur is recovered as a liquid and subsequently solidified. The solidified sulfur is then crushed into particles for use. The crushed particles have a relatively low surface area compared to bio-sulfur 26 recovered in the bio-desulfurization unit 18. It has been found that bio-sulfur 26 dissolves more efficiently in feedstock 12 compared to Claus sulfur. Without being bound by theory, it is believed that bio-sulfur 26 dissolves and / or suspends more efficiently in feedstock 12 because it has a relatively high surface area, improved wettability, a morphology with a higher surface area (e.g., a crystal structure with a high aspect ratio), and / or a lower bulk density compared to Claus sulfur.

[0054] Furthermore, compared to Claus sulfur, bio-sulfur 26 is easier to transport pneumatically because it does not clog pipes and related equipment. This is due to the near absence of static charge buildup, loosely packed particles, and reduced bridging in storage containers.

[0055] Biological sulfur 26 has a concentration of 1.3 g / cm³. 3 Up to 1.5g / cm 3 The density is within the range of [specific values]. Conversely, sulfur produced via the Claus process has a density of approximately 2 g / cm³. 3 The density. It should be understood that density refers to the density measured at SATP (standard ambient temperature and pressure) (i.e., 25°C, 101 kPa).

[0056] Biogenic sulfur 26 has an alkali metal content ranging from 0.5 wt% to 4.0 wt% (calculated as elemental alkali metals based on dry weight). Alkali metals can exist as ionic substances, salts, complexes, and combinations thereof. Sodium and potassium are of particular interest. The described alkali metal content ranging from 0.5 wt% to 4.0 wt% is the sum of all alkali metals (including sodium, potassium, and / or other alkali metals).

[0057] When the renewable feedstock 12 is mixed with bio-sulfur 26 prior to pretreatment in pretreatment unit 14, alkali metals are removed to acceptable levels. The acceptable level of alkali metals will be determined for the specific method, pretreatment unit, feedstock composition, feedstock dilution, catalyst type, and guard bed, etc. Examples of acceptable levels are a maximum of 5 ppmw, preferably a maximum of 2 ppmw, based on the feedstock including any diluent and calculated in elemental alkali metals by dry weight.

[0058] The hydrogen-rich gas stream from the biological desulfurization unit 18 is preferably recycled to the hydrogenation treatment zone 16 and / or the separation unit 20.

[0059] One or more separation units 20 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 hydrotreating reactor in the hydrotreating zone 16, 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 hydrotreating reactor in the hydrotreating zone 16 or the pressure of 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" means that the hot separator operates at a temperature lower than that of the preceding reactor in the hydrotreating zone 16, suitably sufficiently above the water dew point (e.g., ≥10°C, preferably ≥20°C) and sufficiently above the salt deposition temperature (e.g., ≥10°C, preferably ≥20°C), while the intermediate and cold separators are at reduced temperatures relative to the preceding reactor in the hydrotreating zone 16. For example, the cold separator is suitably at a temperature achievable by an air cooler. The hot separator preferably operates at a temperature in the range of 150°C to 250°C, while the cold separator preferably operates at a temperature in the range of 40°C to 120°C. "Intermediate temperature" should be understood to refer to any temperature between the temperatures of the hot and cold separators.

[0060] In addition, one or more separation units 20 may include, for example, but not limited to, amine scrubbers, pressure swing adsorption units, alkaline scrubbers, and combinations thereof.

[0061] In one embodiment, liquid effluent 24 from one or more separation units 20 is fractionated into two or more product streams for use as components of fuels, base oils, and / or chemicals, or as starting materials for fuels, base oils, and / or chemicals. In another embodiment, liquid effluent 24 is further processed, for example by hydroisomerization, hydrocracking, selective cracking, steam cracking, hydrodearomatization, and combinations thereof, to produce components or as starting materials for fuels, base oils, and / or chemicals. In a preferred embodiment, exhaust gases from these further processing reactors / zones may be mixed with exhaust gas streams 22 from one or more separation units 20.

[0062] Figure 2 Several embodiments of the present invention 10 are illustrated. It should be understood that each alternative embodiment presented herein may be used independently or in combination with another alternative embodiment of the present invention 10 presented herein.

[0063] In a preferred embodiment, the renewable feedstock 12 is heated by heater 32 before being guided to pretreatment unit 14. Preferably, the renewable feedstock 12 is heated to a temperature in the range of 100°C to 130°C.

[0064] In a preferred embodiment, bio-sulfur 26 is mixed with the renewable feedstock 12 prior to pretreatment. Mixing can be performed in a manner known to those skilled in the art. An example of a suitable mixer is a static in-line mixer. Preferably, the bio-sulfur 26 is mixed with the already heated renewable feedstock 12.

[0065] The amount of bio-sulfur 26 to be added to the renewable feedstock 12 is selected to achieve a sulfur concentration in the renewable feedstock 12 in the range of 50 ppmw to 7,500 ppmw. The amount of bio-sulfur 26 added to the renewable feedstock is in the range of 100 ppmw to 10,000 ppmw, preferably in the range of 1,000 ppmw to 3,000 ppmw.

[0066] Figure 2An embodiment for integrating a steam cracker 34 for olefin production is also illustrated. A portion of feedstock 26, pretreated with recycled bio-sulfur, may be directed to the steam cracker 34 as a sulfur source. Alternatively or additionally, a portion of one or more liquid streams 24 from separation unit 20 may be directed to the steam cracker 34. In this embodiment, as an example, a portion of one or more liquid streams 24 (not shown) may be fractionated to separate ultra-low sulfur diesel products for use as fuel, wherein the remainder of one or more liquid streams 24 is directed to the steam cracker 34 to produce olefins.

[0067] The advantage of providing a portion of the pretreated feedstock to the steam cracker 34 is that the sulfur in the pretreated feedstock is converted into H2S in the steam cracker 34, thus protecting the metal components of the steam cracker 34 and associated pipes and valves from corrosion.

[0068] Compared to biological desulfurization unit 18, Figure 2 An embodiment having an adsorption tower 36 and a bioreactor 38 is illustrated. One or more waste gas streams 22 are fed into the adsorption tower 36. Preferably, a liquid adsorbent 42 is fed into the adsorption tower 36 in a countercurrent manner relative to the waste gas stream 22.

[0069] The liquid adsorbent 42 is preferably a liquid alkaline adsorbent capable of absorbing H2S and, more preferably, CO2. More preferably, the liquid adsorbent 42 is selected from sodium carbonate, sodium bicarbonate, potassium carbonate, potassium bicarbonate, and combinations thereof. A hydrogen-containing waste gas stream 28', depleted of H2S and CO2, is obtained from the adsorption tower 36. In one or more embodiments, the hydrogen is compressed and recycled to the hydrotreating zone 16, separation unit 20 (e.g., stripper, integrated stripper, and / or hot high-pressure separator), and / or reactor for further treatment (e.g., hydroisomerization reactor 54). Figure 3 (as illustrated), hydrocrackers, selective cracking beds / zones, hydrodearomatization beds / zones, and combinations thereof. In other embodiments, the hydrogen-containing waste gas stream 28' is directed to a reforming unit.

[0070] The stream containing liquid adsorbent 42 from the absorber 36 is directed to one or more bioreactors 38, the liquid adsorbent now loaded with H2S and preferably CO2 from the exhaust gas stream 22. Microorganisms in the bioreactors 38 convert the sulfides into bio-sulfur 26.

[0071] The liquid product stream from bioreactor 38 is passed to separator 44 to separate precipitated solid bio-sulfur 26. Separator 44 may be a settling tank, a settling centrifuge, a centrifuge, a filter press, or a combination thereof. As mentioned above, those skilled in the art will understand that the water content of bio-sulfur 26 will be affected by the composition and operating conditions of bio-desulfurization unit 18, which may also be affected by the environmental conditions of operation of bio-desulfurization unit 18, especially temperature.

[0072] Figure 3 Several embodiments of the present invention 10 are illustrated. It should be understood that each alternative embodiment presented herein may be used independently or in combination with another alternative embodiment of the present invention 10 as presented herein.

[0073] exist Figure 3 In one embodiment, bio-sulfur 26 is passed to dryer 46 before being combined with renewable feedstock 12. Preferably, the bio-sulfur 26 is dried to a solids content in the range of 60% to 90% by weight. More preferably, the bio-sulfur 26 is dried to a solids content in the range of 70% to 90% by weight.

[0074] Figure 3 An embodiment of a biological desulfurization unit 18 is illustrated, which includes an adsorption tower 36, an anaerobic bioreactor 38', an aerobic bioreactor 38" and a separator 44. In anaerobic operation mode, H2S is selectively converted into biogenic sulfur 26, with almost no sulfate production. Figure 3 In one embodiment, microorganisms from anaerobic bioreactor 38' are regenerated in aerobic bioreactor 38"". An oxygenated stream 48 (e.g., air) is injected into aerobic bioreactor 38".

[0075] Figure 3 An embodiment of the invention 10 is also illustrated, which has a pressure swing adsorption (PSA) unit 20' in one or more separation units 20. Waste gas streams from another separation unit 20 are directed to the PSA unit 20' to separate a hydrogen-rich stream from the waste gas stream 22 containing CO2 and H2S. The hydrogen-rich stream is preferably compressed in a compressor 52 to recycle the hydrogen to the hydrogenation treatment zone 16 and / or another treatment unit.

[0076] Figure 3 An embodiment showing the integration of the hydrotreating zone 16 with the hydroisomerization reactor 54 is also illustrated. At least a portion of one or more liquid streams 24 from the separation unit 20 is fed into the hydroisomerization reactor 54.

[0077] Alkane in the hydrotreated liquid is isomerized in hydroisomerization reactor 54 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.

[0078] The isomerized liquid product is passed to a post-treatment section 56, which preferably includes a separator and one or more product strippers and / or fractionators to remove the exhaust gas stream from the isomerized liquid product and other products with different boiling point ranges, including diesel, naphtha and jet fuel.

[0079] exist Figures 1 to 3 In one embodiment, feed 12 is exemplified as being fed to the top of the reactor in the hydrotreating zone 16. However, feed 12 may be split and fed into the hydrotreating zone 16 at two or more inlets at the top and / or, for example, at multiple points (not shown) between catalyst beds along the length of the reactor in the hydrotreating zone 16.

[0080] Figure 3 Two alternative embodiments are also illustrated, in which a portion of one or more liquid streams 24 is recycled as a diluent to feed 12. The volume ratio of diluent to fresh feed 12 is preferably in the range of 1:1 to 30:1. In another alternative embodiment, a portion of one or more liquid streams 24 is provided as one or more quench streams to the reactor in the hydrotreating zone 16. The quench streams are used to control the temperature in the hydrotreating zone 16 and are therefore typically cooled using, for example, an air cooler (not shown) or a heat exchanger (not shown). One or more quench streams may be added between the catalyst beds / zones of the reactor in the hydrotreating zone 16.

[0081] Example

[0082] For illustrative purposes only, the following non-limiting embodiments of the method of the invention protected by the claims are provided.

[0083] Example 1

[0084] The purpose of this embodiment is to determine whether bio-sulfur from biodesulfurization is soluble in soybean oil. Soybean oil was chosen as representative of the range of renewable feedstocks mentioned above.

[0085] Bio-sulfur was added at a concentration of 5% by weight to a beaker containing 300g of soybean oil. The oil mixture was heated to 100°C and stirred. The mixture was then allowed to cool to ambient temperature. The test was repeated at 120°C using 5% by weight of bio-sulfur in 300g of soybean oil. Once cooled, the transparent top layer of the mixture was sampled and the sulfur concentration was tested.

[0086] A precipitate was observed in the cooled beaker. Therefore, this example was repeated using 0.5% by weight bio-sulfur from soybean oil. After the mixture cooled to ambient temperature, no obvious precipitate was observed in the beaker.

[0087] A comparative test was conducted using 0.5% by weight of Claus sulfur. Claus sulfur was observed to sink to the bottom of the beaker and melt.

[0088] The results are shown in Table 1.

[0089] Table 1

[0090]

[0091] Unbound by theory, the structure of biogenic sulfur is believed to offer improved results compared to Claus sulfur. The S8 structure of biogenic sulfur is believed to open at 120°C, unlike Claus sulfur which melts and precipitates from solution.

[0092] Example 2

[0093] The efficacy of the sulfidation catalyst was tested in a high-pressure autoclave experiment using soybean oil doped with bio-sulfur.

[0094] 3 grams of soybean oil and 0.5% by weight of bio-sulfur were added to an autoclave along with 3 grams of unsulfurized NiMo catalyst (Tests 1 to 4). Test 6 was performed to provide a comparison with no catalyst added. Tests 5 and 7 were performed to provide a comparison with conventional SULFRAZOL as a sulfurizing agent. ® For comparison, the temperature of the autoclave was gradually increased from ambient laboratory temperature to the range of 200°C to 320°C as shown in Table 2 to simulate the catalyst sulfidation process in the hydrotreating reactor. The temperature was maintained at the levels indicated in Table 2 for 12 hours at a hydrogen partial pressure of 70 bar.

[0095] Based on known DMDS and SULFRZOL ® The decomposition temperatures were specifically 200 °C and 160 °C, respectively, chosen as the optimal temperatures. The decomposition temperature indicates the temperature at which the sulfurizing agent activates its catalyst. The results in Table 2 indicate that bio-sulfur is expected to have the same decomposition mechanism as conventional sulfurizing agents.

[0096] During the tests, a decrease in hydrogen partial pressure was observed. The amount of sulfur remaining in the oil was measured after each test, as shown in Table 2. No measurable sulfur was found in tests 1 through 4, and no H2S formation was observed, indicating that bio-sulfur was consumed by catalyst sulfidation. Possibly, the hydrogen partial pressure was insufficient to produce H2S. Tests 6 and 7, without catalyst, showed sulfur remaining in the oil, further providing evidence of catalyst sulfidation in tests 1 through 4.

[0097] Table 2

[0098]

[0099] 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 producing fuels, base oils, and / or chemicals from renewable feedstocks, the method comprising the following steps: Pre-treating renewable raw materials to produce pre-treated feedstock; The pretreated feedstock is hydrotreated to produce an effluent containing a hydrotreated liquid and an effluent containing a vapor phase of hydrogen sulfide. The effluent is separated into one or more liquid streams and one or more waste gas streams, wherein at least one of the waste gas streams contains hydrogen sulfide; At least one of the one or more waste gas streams is directed to the biological desulfurization unit; The majority of the hydrogen sulfide in the biological desulfurization unit is converted into bio-sulfur; and At least a portion of the bio-sulfur is recycled to the pretreatment step.

2. The method of claim 1, wherein the bio-sulfur is dried prior to the recycling step.

3. The method of claim 2, wherein the bio-sulfur is dried to a solid content in the range of 60% to 90% by weight.

4. The method according to claim 1, wherein the bio-sulfur has a concentration of 1.3 g / cm³. 3 Up to 1.5g / cm 3 The density within the range.

5. The method according to claim 1, wherein the bio-sulfur has an alkali metal content in the range of 0.5% to 4.0% by weight (calculated as elemental alkali metal content based on dry weight).

6. The method according to claim 1 or 2, wherein the pretreatment step further comprises heating the renewable feedstock and mixing the bio-sulfur with the heated renewable feedstock.

7. The method of claim 6, wherein the renewable raw material is heated to a temperature in the range of 100°C to 130°C.

8. The method of claim 1, wherein the bio-sulfur is added to the renewable feedstock in an amount ranging from 100 ppmw S to 10,000 ppmw S, preferably from 1,000 ppmw S to 3,000 ppmw S.

9. The method of claim 1, wherein the hydrogenation step is carried out using a catalyst containing a catalytically active amount of a metal or metal sulfide, the metal or metal sulfide being selected from the group consisting of Group VIII, Group VIB, and combinations thereof.

10. The method of claim 1, wherein 90 mol% to 100 mol% of the hydrogen sulfide is converted into bio-sulfur.

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

12. The method of claim 1, wherein the pretreatment step comprises a preprocessor selected from the group consisting of: a washing unit, an adsorption unit, a filtration unit, a nanofiltration unit, an ultrafiltration unit, an evaporator, and combinations thereof.

13. 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, integrated strippers, and combinations thereof, and optionally amine separators, pressure swing adsorption units, alkaline washers, and combinations thereof.

14. The method of claim 1, further comprising the step of directing a portion of the one or more liquid streams to a steam cracker for the production of olefins.

15. The method of claim 1, further comprising the step of guiding a portion of the pretreated feedstock having the recycled bio-sulfur to a steam cracker for the production of olefins.

Images