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

Abstract

Bio-sulphur produced in a biological desulfurization unit has an alkali-metal content in a range of from 0.5 to 4.0 wt.%. The bio-sulphur is treated to produce a sulphur additive having an alkali-metal content in a range of from 0.001 to 0.4 wt.%. The sulphur additive is passed to a processing step for production of fuels, base oils, and / or chemicals.

Description

PROCESS FOR PRODUCING FUEL, BASE OILS, AND / OR CHEMICALS FROM RENEWABLE FEEDSTOCKSFIELD OF THE INVENTION

[0001] The present invention relates to the field of producing fuel and / or chemicals from renewable feedstocks.BACKGROUND OF THE INVENTION

[0002] The increased demand for energy resulting from worldwide economic grow th and development have contributed to an increase in concentration of greenhouse gases in the atmosphere. This has been regarded as one of the most important challenges facing mankind in the 21stcentury. To mitigate the effects of greenhouse gases, efforts have been made to reduce the global carbon footprint. The capacity of the earth’s system to absorb greenhouse gas emissions is already exhausted. Accordingly, there is a target to reach net-zero emissions by 2050. To realize these reductions, the world is transitioning away from solely conventional carbon-based fossil fuel energy carriers. A timely implementation of the energy transition requires multiple approaches in parallel. For example, energy conservation, improvements in energy efficiency and electrification may play a role, but also efforts to use renewable resources for the production of fuels and fuel components and / or chemical feedstocks.

[0003] Vegetable oils, oils obtained from algae, and animal fats are seen as renewable resources. Also, deconstructed materials, such as pyrolyzed recyclable materials or wood, are seen as potential resources.

[0004] Renewable materials may comprise materials such as triglycerides with very high molecular mass and high viscosity, which means that using them directly or as a mixture in fuel bases is problematic for modem engines. On the other hand, the hydrocarbon chains that constitute, for example, triglycerides are essentially linear and their length (in terms of number of carbon atoms) are compatible with the hydrocarbons used in / as fuels. Thus, it is attractive to transform triglyceride-comprising feeds in order to obtain good quality fuel components. As well, renewable feedstocks may comprise unsaturated compounds and / or oxygenates that are unsaturated compounds.

[0005] Offgas containing H2S from conventional refineries is most commonly treated in a Claus unit. A Claus unit produces elemental sulphur from gaseous H2S by first reactingwith oxygen to produce sulphur dioxide and water. The sulphur dioxide then reacts with H2S to produced elemental sulphur and water.

[0006] A challenge with using a Claus unit to react with H2S in an offgas from a hydrotreating reactor used for treating renewable feedstocks is that there is a higher content of CO2 in the offgas as compared to conventional petroleum feedstocks due to the oxygen content of the renewable feedstocks. With excess amounts of CO2, the required temperatures for reaction to occur are not reached and / or excess by-products, for example carbonyl sulphide (COS), are produced. Accordingly, there is a need to find an alternative to Claus units for managing offgas streams from hydrotreating renewable feedstocks.

[0007] A biological desulfurization unit offers a solution to removing CO2 and H2S from an offgas stream, such as described in Janssen (US20230416614A1, 28 Dec 2023) relating to a process for treating offgas from hydrotreating of renewable feedstocks. An effluent from the hydrotreating zone is separated into a liquid stream and an offgas stream. The offgas stream comprising carbon dioxide and hydrogen sulphide is passed to a biological desulfurization unit, where the hydrogen sulphide is converted to elemental sulphur.

[0008] There remains a need for making use of sulphur produced from a biological desulfurization unit.SUMMARY OF THE INVENTION

[0009] According to one aspect of the present invention, there is provided a process for preparing a sulphur additive for producing fuel, base oil, and / or chemicals, comprising the steps of providing bio-sulphur produced from a biological desulfurization unit, the sulphur having an alkali-metal content in a range of from 0.5 to 4.0 wt.% (calculated as elemental alkali metal on a dry weight basis); treating the bio-sulphur to produce a sulphur additive having an alkali-metal content in a range of from 0.001 - 0.4 wt.%, preferably 0.01 - 0.1 wt.% (calculated as elemental alkali metal on a dry weight basis), and passing the sulphur additive to a processing step for production of fuels, base oils, and / or chemicals.BRIEF DESCRIPTION OF THE DRAWINGS

[0010] The process of the present invention will be better understood by referring to the following detailed description of preferred embodiments and the drawings referenced therein, in which:

[0011] Fig. 1 is a flow diagram illustrating one embodiment of the process of the present invention;

[0012] Fig. 2 is a flow diagram illustrating two other embodiments of the present invention, including one embodiment of a biological desulfurization unit;

[0013] Fig. 3 is a flow diagram illustrating another embodiment of a biological desulfurization unit integrated with the process of the present invention;

[0014] Fig. 4 is a flow diagram of another embodiment of the present invention applied to a process for hydroprocessing a renewable feedstock;

[0015] Fig. 5 is a flow diagram of a further embodiment of the present invention applied to a process for hydroprocessing a renewable feedstock; and

[0016] Fig. 6 is a flow diagram of yet another embodiment of the present invention applied to a process for steam cracking a renewable feedstock.DETAILED DESCRIPTION OF THE INVENTION

[0017] The present invention provides a process for preparing a sulphur additive for producing fuel, base oil, and / or chemicals from a renewable feedstock. Bio-sulphur produced in a biological desulfurization unit has an alkali-metal content in a range of from 0.5 to 4.0 wt.% (calculated as elemental alkali metal on a dry weight basis). The alkali-metal content has a deleterious effect on process equipment, catalyst, and / or product specifications. In accordance with the present invention, the bio-sulphur is treated to produce a sulphur additive having an alkali-metal content in a range of from 0.001 - 0.4 wt.%, preferably 0.01 - 0.1 wt.% (calculated as elemental alkali metal on a dry weight basis). The sulphur additive is passed to a processing step for production of fuels, base oils, and / or chemicals.

[0018] Fig. 1 illustrates one embodiment of the process of the present invention. Biosulphur 12 is treated in a sulphur-treating unit 14 to produce a sulphur additive 16 having a reduced alkali-metal content. The sulphur additive 16 is passed to a processing step 20 for the production of fuels, base oils, and / or chemicals 22 from a renewable feedstock 18.

[0019] Fig. 2 illustrates an embodiment of the process of the present invention, where the sulphur additive 16 is mixed with the renewable feedstock 18 before being fed to the processing step 20. The mixing may be accomplished in a manner known to those skilled in the art. An example of a suitable mixer 24 is a static inline mixer. In a preferred embodiment, the renewable feedstock 18 is heated with heater 26 prior to being directed to the sulphur-treating unit 14. The renewable feedstock 18 is preferably heated to a temperature in a range of from 100 to 130°C.

[0020] The amount of sulphur additive 16 to be added to the renewable feedstock 18 is dependent on the desired sulphur content in the processing step 20.

[0021] The bio-sulphur produced from a biological desulfurization unit is often viewed as a low- to negative-value product. Often the bio-sulphur is sent to landfill or used for producing fertilizers. Often there is an associated cost for transporting the sulphur to the landfill or to the fertilizer plant. Alternatively, bio-sulphur has been used for producing liquid sulphur by melting and purifying the sulphur in the bio-sulphur.

[0022] As noted above, there is a challenge in using a conventional Claus unit to treat off-gas from a process for producing fuels and chemicals from a renewable feedstock. In addition, the type of elemental sulphur produced in a Claus process suffers from not mixing well with the renewable feedstock causing it to drop out of the mixture and melt. The inventors have surprisingly discovered that the bio-sulphur produced from a biological desulfurization unit is better dissolved and utilized in a renewable feedstock, as compared to Claus sulphur.

[0023] The process of the present invention may be conducted with a bio-sulphur produced in the biological desulfurization unit, such as, for example, a THIOPAQ® O&G unit, available from Paqell B.V. (Utrecht, NL). Examples of suitable desulfurization units are described, for example, in US 10,543,458B2 (Klok et al.) and US9,902,975B2 (Klok et al.).

[0024] The THIOPAQ® O&G process can be applied to convert H2S from a variety of processes to bio-sulphur. Examples of processes include, without limitation, natural gas. refinery gas, fuel gas, flare gas, sour gas, acid gas, associated gas, Claus tail gas, biofuels production off gases, and biogas. Other sources of H2S where the THIOPAQ® process can be applied to produce bio-sulphur include, without limitation, gas originating from anaerobic digestion plants, anaerobic wastewater treatment plants and landfills.

[0025] The process of the present invention is important for the energy transition and can improve the environment by producing energy and / or chemicals from renewable sources, and in particular from degradable waste sources. By recovering the bio-sulphur from the biological desulfurization unit and reusing it in the hydrotreating step, the impact of waste sulphur on the environment is reduced. Further, by reducing or eliminating the need forconventional desulfurizing agents, the environmental impact caused by production of those desulfurizing agents is reduced. In a preferred embodiment, the CCh-rich gas stream is produced, captured, and stored and / or sequestered, thereby lowering the carbon intensity of processes for producing fuel and / or chemicals from renewable sources.

[0026] The bio-sulphur 12 may be conveyed to the location of the processing step 20. Alternatively, the process of the present invention may be integrated with a biological desulfurization unit 32, as depicted in Fig. 2.

[0027] The biological desulfurization unit 32 includes one or more bioreactors having sulphur-oxidizing microorganisms. Suitable microorganisms include, without limitation, sulphide-oxi dizing bacteria selected from HalothiobacUlus. Thioalkalimicrobium, Thioalkalispira^ Thioalkalihacter , Thioalkcdivibrio, genetically modified bacteria, and combinations thereof. The one or more bioreactors may be operated in an anaerobic mode, an aerobic mode, or a combination thereof. The microorganisms may be provided in suspension, immobilized on a suitable support, provided as a sludge blanket or film, and combinations thereof.

[0028] The biological desulfurization unit 32 converts a maj ority of the H2S from a H2S- containing gas stream 34 to bio-sulphur 12 and yields one or more treated gas streams 36. Preferably, from 90 to 100 mol% of the H2S is converted to bio-sulphur. More preferably, from 95 to 100 mol% of the H2S is converted to bio-sulphur 12. Preferably, less than 5 mol% of the H2S is converted to other sulphur compounds such as sulphates and thiosulfates. Treated gas streams may include, for example, a CO2 stream, a fuel gas stream, and / or a hydrogen-rich gas stream. Where a CO2 stream is produced, it is preferably further processed for storage and / or sequestration.

[0029] One embodiment of the bio-sulphur 12 produced in the biological desulfurization unit 32 is described in a Safety Data Sheet for THIOP AQ® Sulphur dated 2008-10-09 (revised 2018-01-17). It will be understood by those skilled in the art that the water content of the bio-sulphur 12 will be affected by the components of the biological desulfurization unit 32 and the operating conditions, which may also be impacted by the environmental conditions, especially temperature, under which the biological desulfurization unit 32 is operated. For example, if the biological desulfurization unit 32 includes a decanter centrifuge for separating the bio-sulphur 12 from the effluent of the bioreactor, the resulting bio-sulphur 12 may have a solids content of about 60 wt.%. However, if the biological desulfurizationunit 32 includes a setling tank for separating the bio-sulphur 12 from the effluent of the bioreactor, the resulting bio-sulphur 12 may have a solids content of about 40 wt.%.

[0030] The bio-sulphur 12 has a morphology that is different from a conventional sulphur produced by a Claus process. In the Claus process, sulphur is recovered as a liquid, which is then solidified. The solidified sulphur is then crushed into particles for use. The crushed particles have a relatively low surface area compared to the bio-sulphur 12 recovered in a biological desulfurization unit 32. The bio-sulphur 12 has been found to dissolve more effectively in the renewable feedstock 18 as compared to Claus sulphur. Without being bound by theory, it is believed that the bio-sulphur 12 dissolves and / or is suspended more effectively in the renewable feedstock 18 because of the relatively higher surface area, improved weting of the bio-sulphur surface, a morphology having a higher surface area (e.g., crystal structure having a high aspect ratio), and / or a lower packing density as compared to Claus sulphur.

[0031] In addition, the bio-sulphur 12 is more easily transported pneumatically, as compared to Claus sulphur, because it does not clog piping and related equipment because there is litle static charge build-up, loosely packed particles, and reduced bridge-building in storage vessels.

[0032] The bio-sulphur 12 has a density in a range of from 1.3 to 1.5 g / cm3. In contrast, sulphur produced via a Claus process has a density of about 2 g / cm3. The density will be understood to mean density as measured at SATP (Standard Ambient Temperature and Pressure), namely 25°C, 101 kPa.

[0033] The bio-sulphur 12 has an alkali-metal content in a range of from 0.5 to 4.0 wt.% (calculated as elemental alkali metal on a dry weight basis). The alkali-metal may be present as an ionic species, a salt, a complex, and combinations thereof. The alkali-metals of particular interest are sodium and potassium. The recited alkali-metal content in a range of from 0.5 to 4.0 wt.% is a total of all the alkali metals, including sodium, potassium, and / or other alkali metals.

[0034] The bio-sulphur 12 is treated in a sulphur-treating unit 14. The sulphur-treating unit 14 can be selected from a variety of unit operations and techniques. A particularly advantageous and efficient technique is to wash the bio-sulphur 12, for example, with water or an acidic solution. The sulphur-treating unit is operated to treat the bio-sulphur to producea sulphur additive having an alkali-metal content in a range of from 0.001 - 0.4 wt.%. preferably 0.01 - 0.1 wt.% (calculated as elemental alkali metal on a dry weight basis).

[0035] The sulphur-treating unit 14 preferably includes a dryer. Preferably, the biosulphur 12 is dried to a solids content in a range of from 60 to 90 wt.%. More preferably, the bio-sulphur 12 is dried to a solids content in a range of from 70 to 90 wt.%.

[0036] An embodiment of the biological desulfurization unit 32 is illustrated in Fig. 2. In this embodiment, the biological desulfurization unit 32 has an adsorption column 38 and a bioreactor 42. The H2S -containing stream 34 is fed to the absorption column 38. Preferably, a liquid sorbent 46 is fed to the absorption column 38 in a counter-current flow relative to the H2S -containing stream 34.

[0037] The liquid sorbent 46 is preferably a liquid alkaline sorbent capable of absorbing H2S and where present, preferably, CO2. More preferably, the liquid sorbent 46 is selected from sodium carbonate, sodium bicarbonate, potassium carbonate, potassium bicarbonate, and combinations thereof. A hydrogen-containing offgas stream 36', depleted in H2S and CO2 is obtained from the adsorption column 38.

[0038] A stream from the absorption column 38 containing the liquid sorbent 46, now loaded with H2S and, preferably, CO2 from the FhS-containing stream 34, is directed to one or more bioreactors 42. Microorganisms in the bioreactor 42 convert sulphides into biosulphur 12.

[0039] A liquid product stream from the bioreactor 42 is passed to a separator 44 to separate precipitated solid bio-sulphur 12. The separator 44 may be a settling tank, a decanter centrifuge, a filter press, or a combination thereof. As mentioned above, it will be understood by those skilled in the art that the water content of the bio-sulphur 12 will be affected by the components of the biological desulfurization unit 32 and the operating conditions, which may also be impacted by the environmental conditions, especially temperature, under which the biological desulfurization unit 32 is operated.

[0040] Fig. 3 illustrates an embodiment of the biological desulfurization unit 32 having an adsorption column 38, an anaerobic bioreactor 42', an aerobic bioreactor 42", and a separator 44. In an anaerobic mode of operation, H2S is selectively converted to bio-sulphur 12 with little to no production of sulphates. In the embodiment of Fig. 3, microorganisms from the anaerobic bioreactor 42' are regenerated in the aerobic bioreactor 42". An oxy gencontaining stream 48, for example air, is sparged into the aerobic bioreactor 42".

[0041] As used herein, the terms “renewable feedstock.” “renewable feed,” and “material from renewable sources” mean a feedstock from a renewable source. A renewable source may be animal, vegetable, microbial, and / or bio-derived or mineral-derived waste materials suitable for the production of fuels, fuel components, base oils, and / or chemical feedstocks. For example, vegetable oils, oils obtained from algae, and animal fats are suitable renewable feedstocks. Also, deconstructed materials, such as pyrolyzed recyclable materials or wood, are seen as potential resources.

[0042] A preferred class of renewable materials are bio-renewable fats and oils comprising triglycerides, diglycerides, monoglycerides, free fatty acids, and / or fatty acid esters derived from bio-renewable fats and oils. Examples of fatty acid esters include, but are not limited to, fatty acid methyl esters and fatty acid ethyl esters. The bio-renewable fats and oils include both edible and non-edible fats and oils. Examples of bio-renewable fats and oils include, without limitation, algal oil, brown grease, camelina oil, canola oil, carinata oil, castor oil, coconut oil. colza oil, com oil. cottonseed oil, fish oil. hempseed oil, jatropha oil. lard, linseed oil, milk fats, mustard oil, olive oil, palm oil, peanut oil, rapeseed oil, sewage sludge, soy oils, soybean oil, sunflower oil, pongamia oil, tall oil, tall oil fatty acids (TOFA), tallow, used cooking oil, yellow' grease, white grease, and combinations thereof.

[0043] Another preferred class of renewable materials are liquids derived from biomass and waste liquefaction processes. Examples of such liquefaction processes include, but are not limited to, (hydro)pyrolysis, hydrothermal liquefaction, plastics liquefaction, and combinations thereof. Renewable materials derived from biomass and waste liquefaction processes may be used alone or in combination with bio-renewable fats and oils.

[0044] In one embodiment of the present invention, the processing step 20 is a process for hydroprocessing a renewable feedstock 18. One embodiment of the hydroprocessing process comprises a hydrotreating zone 52 and a separation zone 54, as depicted in Fig. 4.

[0045] The process of the present invention is particularly advantageous in the processing of renewable feedstocks. However, in one embodiment of the present invention, renewable feedstock may be co-processed with petroleum-derived hydrocarbons. Petroleum- derived hydrocarbons include, without limitation, all fractions from petroleum crude oil, natural gas condensate, tar sands, shale oil, synthetic crude, and combinations thereof. The petroleum-derived hydrocarbons typically have a sulphur content such that the addition of a sulphur additive is not needed. It will be understood by those skilled in the art that the sulphur content of petroleum-derived hydrocarbons will be dependent on the source. The process ofthe present invention may be advantageous when the combined renewable and petroleum- derived feedstock has a sulphur content less than 0.3 wt.% S, preferably less than 0.2 wt.% S.

[0046] The renewable feedstock 18 is sent to a hydrotreating zone 52, where the renewable feedstock 18 is reacted under hydrotreating conditions sufficient to cause a reaction selected from a hydrotreating reaction including, without limitation, hydrodeoxygenation, hydrodenitrogenation, hydrodesulphurization, hydrodearomatization, hydrogenation, hydrodemetallization, and combinations thereof. The reactions in the hydrotreating zone 52 are catalytic reactions. The hydrotreating zone 52 may be single-stage or multi-stage, and may be operated in a slurry, moving bed, fluidized bed, and / or fixed bed operation. In the case of a fixed bed operation, a reactor in the hydrotreating zone 52 may have a single catalyst bed or multiple catalyst beds. The hydrotreating zone 52 may be comprised of a single reactor or multiple reactors. The hydrotreating zone 52 may be operated in a co-current flow, counter-current flow, or a combination thereof. Preferably, the hydrotreating zone 52 is operated in a co-current flow.

[0047] The catalyst may be the same or different throughout the hydrotreating zone 52. The hydrotreating zone 52 may comprise a single catalyst bed or multiple catalyst beds. The catalyst may be the same throughout the single catalyst bed, optionally there is a mixture of catalysts, or different catalysts may be provided in two or more layers in the catalyst bed. In an embodiment of multiple catalyst beds, the catalyst may be same or different for each catalyst bed.

[0048] In one embodiment, the hydrotreating zone 52 further comprises a hydrogenation catalyst in advance of the hydrotreating catalyst. The hydrogenation components may be used in bulk metal form, or the metals may be supported on a carrier. Active metals for hydrogenation include catalytically active metals of Group VIII and / or Group VIB, including, without limitation, Ni. Co, Mo, W, and combinations thereof. Suitable carriers include refractory oxides, molecular sieves, and combinations thereof. Examples of suitable refractory oxides include, without limitation, alumina, amorphous silica-alumina, titania, silica, and combinations thereof. Examples of suitable molecular sieves include, without limitation, zeolite Y, zeolite beta, ZSM-5, ZSM-12, ZSM-22, ZSM-23, ZSM-48, S APO-11, SAPO-41. ferrierite, and combinations thereof.

[0049] The hydrotreating zone 52 may also include one or more guard beds (not shown) for capturing and / or reacting with contaminants in the renewable feedstock 18. Thehydrotreating zone 52 may also include one or more catalyst beds for hydroisomerization, selective cracking and / or hydrodearomatization.

[0050] The hydrotreating catalyst may be any catalyst known in the art that is suitable for hydrotreating. Catalyst metals are often in an oxide state when charged to a reactor and are activated by sulphiding the metal oxide. Preferably, the hydrotreating catalyst comprises catalytically active metals of Group VIII and / or Group VIB, including, without limitation, Ni, Co, Mo. W, and combinations thereof.

[0051] As discussed above, hydrotreating catalysts are generally more active in a sulphided form as compared to an oxide form of the catalyst. Because renewable feedstocks generally have a low sulphur content, a sulphiding agent is typically added to the feed or hydrotreating zone to maintain the catalyst in a sulphided form.

[0052] Preferably, the hydrotreating catalyst comprises sulphided catalytically active metals. Examples of suitable catalytically active metals include, without limitation, sulphided nickel, sulphided cobalt, sulphided molybdenum, sulphided tungsten, sulphided CoMo, sulphided NiMo, sulphided MoW, sulphided NiW. and combinations thereof. A catalyst bed / zone may have a mixture of two or more types of catalysts and / or successive beds / zones, including stacked beds, and may have the same or different catalysts and / or catalyst mixtures.

[0053] The hydrotreating metals may be used in bulk metal form, or the metals may be supported on a carrier. Suitable carriers include refractory oxides, molecular sieves, and combinations thereof. Examples of suitable refractory oxides include, without limitation, alumina, amorphous silica-alumina, titania, silica, and combinations thereof.

[0054] Operating conditions in the reactors of the hydrotreating zone 52 include pressures in a range of from 1.0 MPa to 20 MPa, temperatures in a range of from 200 to 410°C and liquid hourly space velocities in a range of from 0.3 m3 / m3.h to 5 m3 / m3.h based on fresh feed. Preferably, the pressure is selected from 2.0 MPa to 15 MPa. Preferably, the temperature is in the range of from 200 to 400°C, more preferably from 240 to 390°C, most preferably from 260 to 385°C.

[0055] The ratio of hydrogen to feed supplied in the hydrotreating zone 52 is in a range of from 200 to 10,000 normal L (at standard conditions of 0°C and 1 atm (0.101 MPa)) per kg of feed, preferably from 500 to 8,000 NL / kg, more preferably from 800 to 3,000 NL / kg. Reference herein to feed is the total of fresh feedstock excluding diluent.

[0056] The hydrotreating step produces an effluent compnsing a hydrotreated liquid and a vapour phase comprising hydrogen sulphide. Other components may be present in the vapour phase including, without limitation, hydrogen, carbon oxides (e.g., CO2 and / or CO), water, nitrogen, NH3, NO2, Cl - CIO compounds, and combinations thereof. Depending at least on the catalyst, feed and operating conditions, the relative amounts of components in the vapour phase may be different or change over time. Typically, the vapour phase will include H2S and CO2.

[0057] The effluent from the hydrotreating zone 52 is directed to one or more separation units 54 to separate the product into one or more offgas streams 56 and one or more liquid streams 22. Examples of suitable embodiments of the separation units, without limitation, are disclosed in Janssen (US20230416614A1, 28 Dec 2023).

[0058] A portion of the one or more liquid streams 22 may be recycled to be used as a diluent and / or a quench stream between catalyst beds in a reactor of the hydrotreating zone 52, for example as depicted in Fig. 4. Where the one or more separation units 54 includes a hot-separator, an advantage of recycling a portion of a liquid stream from the hot-separator is that operating costs associated with pumping and / or heating can be reduced. Alternatively, or in addition, feedstock and / or hydrogen feed streams to a reactor in the hydrotreating zone 52 may be staged to two or more injection ports in each of one or more reactors of the hydrotreating zone 52.

[0059] The one or more separation units 54 include, for example, without limitation, gas / liquid separators, including hot high- and low-pressure separators, intermediate highland low-pressure separators, cold high- and low-pressure separators, strippers, integrated strippers, and combinations thereof. Integrated strippers include strippers that are integrated with hot high- and low-pressure separators, intermediate high- and low-pressure separators, and cold high- and low-pressure separators. It will be understood by those skilled in the art that high-pressure separators operate at a pressure that is close to pressure of a hydrotreating reactor in the hydrotreating zone 52, suitably 0 - 10 bar (0 - 1 MPa) below the reactor outlet pressure, while a low-pressure separator is operated at a pressure that is lower than the hydrotreating reactor in the hydrotreating zone 52 pressure or high-pressure separator, suitably 0 - 15 barg (0 - 1.5 MPaG). Similarly, it will be understood by those skilled in the art that hot means that the hot-separator is operated at a temperature lower than a preceding reactor in the hydrotreating zone 52 temperature, suitably sufficiently above water dew point (e.g., >10°C, preferably >20°C, above the water dew point) and sufficiently greater than saltdeposition temperatures (e.g.. >10°C, preferably >20°C, above the salt deposition temperature), while intermediate- and cold-separators are at a reduced temperature relative to the preceding reactor in the hydrotreating zone 52. For example, a cold-separator is suitably at a temperature that can be achieved via an air cooler. A hot-separator preferably operates at a temperature in a range from 150 to 250°C, while a cold-separator preferably operates at a temperature in a range from 40 to 120°C. An intermediate temperature will be understood to mean any temperature between the temperature of a hot- or cold-separator.

[0060] In addition, the one or more separation units 54 may include, for example, without limitation, an amine scrubber, a pressure swing adsorption unit, a caustic wash, and combinations thereof.

[0061] In one embodiment, the liquid effluent from the one or more separation units 54 is fractionated into two or more product streams for components or as starting materials of fuels, base oils, and / or chemicals. In another embodiment, the liquid effluent is further processed, for example by hydroisomerization, hydrocracking, selective cracking, steam cracking, hydrodearomatization, and combinations thereof to produce components or starting materials of fuels, base oils, and / or chemicals.

[0062] The amount of sulphur additive 16 to be added to the renewable feedstock 18 is selected to achieve a sulphur concentration in the renewable feedstock 18 in a range of from 50 to 7,500 wppm. The amount of sulphur additive 16 added to the renewable feedstock 18 is in an amount in a range of from 100 to 10,000 wppm, preferably from 1,000 to 3,000 wppm.

[0063] Fig. 5 further illustrates an embodiment showing integration of the hydrotreating zone 52 with a hydroisomerization reactor 58. At least a portion of the one or more liquid streams from the separation units 54 is fed to the hydroisomerization reactor 58.

[0064] Paraffinic hydrocarbons in the hydrotreated liquid are isomerized in the hydroisomerization reactor 58 using a suitable isomerization catalyst including, without limitation, Group VIII metals, especially platinum and / or palladium, supported on a refractory oxide and / or a molecular sieve.

[0065] The isomerized liquid product is passed to a work-up section 62 that preferably includes a separator and one or more product strippers and / or fractionators to remove an offgas stream from the isomerized liquid product and further products having different boiling point ranges, including, diesel, naphtha, and jet fuels.

[0066] In the embodiments of Figs. 4 and 5, the renewable feedstock 18 is illustrated as being fed to the top of a reactor in the hydrotreating zone 52. However, the renewable feedstock 18 may be divided and fed to the hydrotreating zone 52 at two or more inputs at the top and / or at multiple points (not shown), for example, between catalyst beds, along the length of a reactor in the hydrotreating zone 52.

[0067] Fig. 5 also illustrates two optional embodiments wherein a portion of the one or more liquid streams from the separation units 54 is recycled to the renewable feedstock 18 as a diluent. The volumetric ratio of diluent to fresh feed 18 is preferably in a range of from 1 : 1 to 30: 1. In another optional embodiment, a portion of the one or more liquid streams is provided as one or more quench streams to a reactor in the hydrotreating zone 52. The quench stream is used to control temperature in the hydrotreating zone 52 and 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 catalyst beds / zones in a reactor of the hydrotreating zone 52.

[0068] In another embodiment of the present invention, the processing step 20 is a process for steam cracking a renewable feedstock 18. The embodiment is illustrated in Fig. 6.

[0069] The processing step 20 has a steam cracker 64. a fractionator 66, and a stripper 68. In addition, the steam cracking step includes a quench system, a quench water tower, and a quench loop (not shown). The renewable feedstock 18 is passed to the steam cracker 64 where the renewable feedstock 18 is cracked into smaller hydrocarbon fragments to generate a steam cracker effluent.

[0070] In the steam cracker 64, H2S acts as coke inhibitor. In conventional steam cracking processes, H2S is formed in the steam cracker 64 through cracking of sulphur- containing hydrocarbons (e.g., mercaptans or thiophenes). In the case where feed contains little or no sulphur species, sulphiding compounds (e.g., DMS or DMDS) are added to generate H2S. In accordance with the present invention, where the renewable feedstock 18 has little or no sulphur, sulphur additive 16 is added to provide the source of H2S.

[0071] The amount of sulphur additive 16 to be added to the renewable feedstock 18 is in a range of from 10 to 200 vppm, preferably from 30 to 200 vppm. Preferably, the sulphur additive 16 is provided at a concentration to result in an H2S concentration in a range of from 10 to 200 vppm, more preferably 30 - 100 vppm, as measured in the effluent of steam cracker64. The lower concentration limit is selected based on experience that 1 vppm of H2S already had a large influence on the CO in the effluent gas. Above the upper concentration limit, H2S can adversely affect the yield and possibly result in CS2 in the product. Additionally, above the upper concentration limit, the sulphur can be corrosive and even detrimental to coke inhibition.

[0072] In the steam cracker 64, optionally with a preheater, the renewable feedstock 18 is heated to a temperature in a range of from 700°C to 850°C to transform oligomers and paraffins in the renewable feedstock 18 into a steam cracker effluent containing monomers and other higher value chemicals, such as, without limitation, hydrogen, ethylene, propylene, butadiene, and benzene. Steam is usually added to the steam cracker 64, acting as a diluent to reduce the hydrocarbon partial pressure and thereby enhance the olefin yield. Steam also reduces the formation and deposition of carbonaceous material or coke in the cracking zone. The cracking occurs in the absence of oxygen. The residence time at the cracking conditions is very short, typically on the order of milliseconds.

[0073] The process of the present invention is most particularly advantageous in the processing of feed streams comprising substantially 100% renewable feedstocks. However, in the present invention, renewable feedstock may be co-processed with non-renewable feedstock, such as a feedstock comprising petroleum-derived hydrocarbons and / or a feedstock comprising other non-renewable hydrocarbons. Other non-renewable, nonpetroleum-derived hydrocarbons may comprise circular hydrocarbons, such as waste plastics pyrolysis oil. Petroleum-derived hydrocarbons include, without limitation, all fractions from petroleum crude oil, natural gas condensate, tar sands, shale oil, synthetic crude, and combinations thereof. The present invention is more particularly advantageous for a combined renewable and petroleum-derived feedstock comprising a renewable feed content in a range of from 10 to 99 wt.%, suitably 20 to 99 wt.%, more suitably 30 to 99 wt.%. In the present invention, the renewable feedstock may be co-processed with a heavy fraction from a petroleum re finery. For example, the petroleum-derived feedstock may be a heavy fraction from a gas oil unit.

[0074] The steam cracker effluent is preferably cooled to a temperature less than 500°C before being fed to the fractionator 66. Preferably, heat may be recovered from the steam cracker effluent to generate steam to be used, for example, in the process.

[0075] The fractionator 66 separates hydrocarbons in the steam cracker effluent into fractions based on boiling point ranges. For example, the steam cracker effluent is separated into a heavy7oil and an overhead gas. The overhead gas has a temperature in a range of from 100°C to 110°C and is fed to a quench water tower to separate lighter hydrocarbons from gasoline components, among other light hydrocarbons and H2. A portion of the heavy oil is passed to a quench oil loop and a heavy' oil stripper 68. The heavy oil generated in the fractionator 66 contains light fuel oil (LFO), medium fuel oil (MFO), and heavy fuel oil (HFO). The stripper 68 strips the LFO from the HFO to generate a stripper LFO and a stripper HFO. The viscosity of the quench oil is determined based on the amount of LFO and MFO. As the viscosity of the quench oil should be maintained sufficiently low (e.g., 1- 85 cSt @ 100°C) to mitigate flow problems in the quench loop, the stripper LFO may be circulated back to the fractionator 66. The more LFO and MFO present in the quench oil, the lower the viscosity7will be. However, the LFO in the quench oil may vaporize, thereby decreasing its concentration in the quench oil and undesirably increasing the viscosity. Preferably, the stripper LFO is circulated back to the fractionator 66 to increase the concentration of the LFO in the heavy' oil and, consequently, the quench oil.

[0076] Preferably, H2S is removed in an acid gas removal unit (not shown). Examples of suitable acid gas removal units include, without limitation, a caustic tower, an amine column, and combinations thereof.

[0077] While the presence of LFO in the quench oil may facilitate maintaining the viscosity at desirable levels, certain feeds may not generate a sufficient amount of LFO in the steam cracker 64.

[0078] The drawings illustrate several embodiments of the present invention 10. It will be understood that each alternative embodiment presented therein may be used independently or in combination with another alternative embodiment in the present invention 10 presented herein.

[0079] While the embodiments are described with reference to various implementations and exploitations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations, modifications, additions and improvements are possible.

Claims

CLAIMS1. A process for preparing a sulphur additive for producing fuel, base oil, and / or chemicals, comprising the steps of: providing bio-sulphur produced from a biological desulfurization unit, the sulphur having an alkali-metal content in a range of from 0.5 to 4.0 wt.% (calculated as elemental alkali metal on a dry weight basis); treating the bio-sulphur to produce a sulphur additive having an alkali-metal content in a range of from 0.001 - 0.4 wt.%. preferably 0.01 - 0.1 wt.% (calculated as elemental alkali metal on a dry weight basis), and passing the sulphur additive to a processing step for production of fuels, base oils, and / or chemicals.

2. The process of claim 1 , wherein the treating step further comprises the step of drying the bio-sulphur.

3. The process of claim 2, wherein the bio-sulphur is dried to a solids content in a range of from 60 to 90 wt.%.

4. The process of claim 1, wherein the bio-sulphur has a density in a range of from 1.3 to 1.5 g / cm3.

5. The process of claim 1, wherein the passing step comprises the steps of: providing a renewable feedstock comprising triglycerides, diglycerides, monoglycerides, free fatty acids, and / or fatty acid esters derived from bio-renewable fats and oils: pretreating the renewable feedstock to produce a pretreated renewable feedstock; mixing at least a portion of the pretreated renewable feedstock with the sulphur additive; and hydrotreating the pretreated renewable feedstock and the mixed sulphur additive to produce an effluent comprising a hydrotreated liquid.

6. The process of claim 5, wherein the renewable feedstock is heated to a temperature in a range of from 100 to 130°C.

7. The process of claim 5, wherein the bio-sulphur is added to the renewable feedstock in an amount in a range of from 100 to 10,000 wppm S, preferably in a range of from 1,000 to 3,000 wppm S.

8. The method of claim 5, wherein the sulphur additive is added to the pretreated renewable feedstock to achieve a sulphur concentration in the renewable feedstock in a range of from 50 to 7,500 wppm.

9. The process of claim 5. wherein the hydrotreating step is conducted with a catalyst comprising a catalytically active amount of a metal, or metal sulphides, selected from the group consisting of Group VIII, Group VIB and combinations thereof.

10. The process of claim 1, wherein the biological desulfurization unit comprises an absorption column, a bioreactor, and a separator.

11. The method of claim 1, wherein the passing step comprises the steps of: providing a renewable feedstock comprising triglycerides, diglycerides, monoglycerides, free fatty acids, and / or fatty acid esters derived from bio-renewable fats and oils, and hydrotreated bio-renewable fats and oils, liquids derived from biomass liquefaction processes, waste plastics pyrolysis oil, and combinations thereof; preheating the renewable feedstock and the sulphur additive resulting in a preheated feed stream; feeding the preheated feed stream and steam into a steam cracker; and pyrolytically cracking the renewable feedstock to provide an effluent containing olefins.

12. The method of claim 11, wherein the sulphur additive is added to the renewable feedstock in a range of from 10 to 200 vppm.

13. The method of claim 1 1, wherein the sulphur additive is added to the renewable feedstock to provide an H2S concentration in a range of from 10 to 200 vppm, preferably 30 - 100 vppm, as measured in the effluent of the steam cracker.

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