Co-processing plastic waste in coker for jet fuel production

Abstract

Systems and methods are provided for co-processing plastic waste in a coker that is part of an integrated refining environment that produces kerosene, jet fuel, and / or jet fuel blending components as products. Co-processing may be performed in a fluidized coker, a delayed coker, or a combination of a fluidized coker and a delayed coker. After coking, one or more portions of a coker effluent that contributes to the formation of kerosene, jet fuel, and / or jet fuel blend component product (s) may be hydroprocessed. Hydroprocessing may be used to reduce or minimize the presence of unexpected nitrogen contaminants in the resulting kerosene, jet fuel, and / or jet fuel blend component product (s).

Description

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This application claims the benefit of and priority to U.S. Provisional Application No. 63 / 338,062, filed May 4, 2022, the disclosure of which is incorporated herein by reference. Technical Field

[0003] Systems and methods are provided for producing jet fuel in a coking environment from a feed derived at least in part from co-processing of plastic waste. Background Art

[0004] There is a growing interest in finding ways to recycle plastic waste so that the carbon from the underlying polymer can be recovered and incorporated into another product cycle. This may include incorporating the plastic waste as part of an input stream to produce additional polymers, to chemical plants to produce other products, and / or to produce refined products such as fuels and / or lubricants.

[0005] One of the difficulties in incorporating plastic waste as part of a refinery input stream is that plastic waste tends to correspond to a mixture of different types of plastic waste. Plastic waste may typically include various types of polymers, including polyolefins (e.g., low-density polyethylene, high-density polyethylene, polypropylene), polystyrene, nitrogen-containing polymers (e.g., nylon 6 and / or other polyamides), polyesters, polyethylene terephthalate, other oxygen-containing polymers, and chlorine-containing polymers (e.g., polyvinyl chloride (PVC) or polyvinylidene chloride (PVDC)).

[0006] Another difficulty in incorporating plastic waste into a refining process is that refineries typically produce an integrated product slate. The introduction of plastic waste into a refining process can typically result in the production of molecules that are incorporated into various products produced by the refinery. For example, the output from a delayed coker and / or a fluid coker can potentially be distributed in naphtha, kerosene (jet), diesel, lubricants and / or fuel oil products in an integrated refining setting. Therefore, in order to introduce plastic waste into such a refinery, either a) the process unit into which the plastic waste is introduced needs to be isolated, or the feed and / or refining process needs to be adjusted so that the introduction of plastic waste is compatible with all products produced as part of the refined product composition. Having to isolate a portion of a refinery can result in considerable capital costs and the production of the complete product composition of the refinery can be disrupted. Therefore, it would be desirable to determine a system and method that can use plastic waste as part of a refinery input stream during an integrated refining process.

[0007] International publication WO2021 / 091724 describes the co-processing of plastic waste in a fluidized coking environment or a delayed coking environment.

[0008] U.S. Patent Application Publication 2021 / 0087473 describes the use of delayed coking for the co-processing of plastic waste with heavy oil. The plastic waste may include plastics to which metals have been added. The added metals may be concentrated in the coke produced during delayed coking.

[0009] International Publication No. WO 1995 / 014069 describes dissolving waste plastic in an aromatic solvent prior to combining the dissolved plastic with a feed for a delayed coking process.

[0010] US Patent 4,851,601 describes co-processing plastic waste in a delayed coker followed by exposing the coker product to a second cracking stage wherein the coker product is exposed to a zeolite catalyst at elevated temperatures.

[0011] Chinese patent CN101230284 describes a method for coking plastic waste. The plastic waste is crushed to form small particles. The resulting particles are fluidized using a screw extrusion conveyor, and then heated and extruded to convert the plastic waste into a semi-fluid state. The heated and extruded plastic waste is then stored at a temperature of 290°C to 320°C to maintain the plastic in a liquid state. The liquid plastic waste is then pumped into a coking furnace, optionally together with a co-feed.

[0012] U.S. Pat. No. 9,920,255 describes a method for depolymerizing plastic materials. The method includes melting and degassing a plastic feed to form a molten plastic. A liquid crude fraction is then added to the molten plastic to reduce viscosity, after which the mixture of the molten plastic and the liquid crude product is introduced into a pyrolysis reactor. It should be noted that the plastic is melted and degassed before combining the plastic with any conventional co-feed, thereby increasing the number of separate reactor vessels required to integrate the plastic waste with conventional co-feeds.

[0013] U.S. Patent 6,861,568 describes a method for free radical initiated pyrolysis of plastic waste dissolved in an oil medium. After mixing the plastic waste with the oil, the mixture is transferred to a pyrolysis vessel. The pyrolysis temperature is generally described as 300°C-375°C, but an example of a partial reaction at 275°C is provided. Based on the pyrolysis conditions, one of the two main products is a reactor overhead stream including the desired distillation product and an incompressible overhead gas product. After condensing the desired distillation product, the remaining overhead gas product can be treated with water washing in order to remove any HCl that may be present. Therefore, a separate additional water washing stage is used to complete the HCl removal. Summary of the invention

[0014] In one aspect, a method for co-processing a plastic feedstock is provided. The method includes mixing a plastic feedstock with one or more additional feedstocks to form a feedstock mixture. The plastic feedstock may contain 25% by weight or less of at least one nitrogen-containing polymer relative to the weight of the plastic feedstock. The feedstock mixture may contain 0.5% by weight to 30% by weight of the plastic feedstock relative to the weight of the feedstock mixture. The method also includes exposing at least a portion of the feedstock mixture to coking conditions to form a conversion effluent containing one or more amides, one or more amines, or a combination thereof. The method also includes separating the conversion effluent to form at least one liquid product fraction having a T10 distillation point of 300° C. or less and a T90 distillation point of 170° C. or more. At least one liquid product fraction may have a basic nitrogen content of 100 wppm or more relative to the weight of at least one liquid product fraction. In addition, the method includes exposing at least a portion of at least one liquid product fraction to hydroprocessing conditions to form a hydroprocessed effluent containing a jet fuel boiling range fraction, the jet fuel boiling range fraction having a total nitrogen content of 10 wppm or less relative to the weight of the jet fuel boiling range fraction.

[0015] Optionally, the basic nitrogen content of the at least one liquid product fraction may correspond to 20 wt% or more, or 40 wt% or more of the total nitrogen content of the at least one liquid product fraction. Optionally, before hydroprocessing, the at least one liquid product fraction may have a basic nitrogen content of 150 wppm or more, or 300 wppm or more. BRIEF DESCRIPTION OF THE DRAWINGS

[0016] Figure 1 An example of a process configuration for co-processing a combined feed in a coking stage is shown.

[0017] Figure 2 Another example of a process configuration for co-processing a combined feed in a coking stage is shown.

[0018] Figure 3 An example of a fluid coking stage configuration is shown.

[0019] Figure 4 Another example of a fluid coking stage configuration is shown.

[0020] Details

[0021] All numerical values ​​in this detailed description and claims are modified by the indicated value of "about" or "approximately", and take into account experimental errors and variations that would be expected by a person of ordinary skill in the art.

[0022] In various aspects, systems and methods are provided for co-processing plastic waste in a coker as part of an integrated refining environment that produces kerosene, jet fuel, and / or jet fuel blending components as products. Co-processing can be performed in a fluid coker, a delayed coker, or a combination of a fluid coker and a delayed coker. After coking, one or more portions of the coker effluent that contribute to the formation of kerosene, jet fuel, and / or jet fuel blending component product(s) can be hydroprocessed. Hydroprocessing can be used, for example, to reduce or minimize the presence of unexpected nitrogen contaminants in the resulting kerosene, jet fuel, and / or jet fuel blending component product(s).

[0023] Plastic waste generally corresponds to a mixture of various types of polymers. Some types of polymers such as polyethylene, polypropylene or polystyrene correspond to hydrocarbons. As a result, in the case where the charring of such polymers forms liquid products, such liquid products also generally correspond to hydrocarbons.

[0024] Other types of polymers may include heteroatoms other than carbon and hydrogen as part of the monomers used to form the polymer. As an example, each repeating unit in polyvinyl chloride (PVC) and polyvinylidene chloride (PVDC) polymers includes one or more chlorines. Such chlorine-containing polymers can potentially release chlorine compounds that can contaminate the final product and / or can damage the processing environment.

[0025] Another group of polymers corresponds to nitrogen-containing polymers such as polyamides. Nylon 6 is an example of a commonly encountered polyamide. In a coking environment, polyamides (and / or other nitrogen-containing polymers) can form nitrogen-containing products with boiling points in the kerosene / jet fuel boiling range. For example, introducing a plastic feedstock including nylon 6 into a coking environment can lead to the formation of caprolactam, which is a kerosene / jet fuel boiling range amide. This can cause several difficulties. First, relative to the types of compounds present in the kerosene / jet fuel / jet fuel blending component fraction derived from a mineral feed, the presence of a large amount of amides in the kerosene / jet fuel boiling range fraction is unexpected. Secondly, because the decomposition of polyamides in a coking environment leads to the direct formation of kerosene / jet fuel boiling range compounds (e.g., caprolactam) containing nitrogen, co-processing plastic feedstocks in a coking environment can lead to unexpectedly high total nitrogen contents in the kerosene / jet fuel boiling range fraction, relative to the total nitrogen content of the mineral portion of the feed and / or relative to the nitrogen content of other fractions derived from the co-processing.

[0026] In various aspects, systems and methods are provided for co-processing plastic waste in a coking environment while reducing, minimizing or otherwise mitigating the impact of contaminants on the resulting kerosene / jet fuel boiling point fraction produced by the coking process. First, the type of plastic waste used for co-processing can be controlled to avoid excessive chlorine and / or nitrogen compounds in the coker effluent and / or in the kerosene / jet fuel boiling range portion of the coker effluent. This can include limiting the amount of nitrogen-containing polymers and / or chlorine-containing polymers present in the plastic waste.

[0027] Optionally, a thermal dehalogenation stage may be used to reduce or minimize the chlorine content of the plastic feedstock prior to exposing the plastic feedstock to the coking environment. After mixing the plastic feedstock with one or more additional feedstocks to form a combined feed corresponding to a solution or slurry, the combined feedstock may be exposed to a temperature of 150° C. to 300° C. in the presence of a purge gas to remove chlorine from the combined feedstock.

[0028] As a supplement to selecting plastic waste with appropriate composition for use as a co-feed, hydroprocessing can also be used to reduce or minimize the nitrogen content (e.g., amide content) of any kerosene / jet fuel boiling range fraction formed by the coker effluent. Due to the increased selectivity for forming nitrogen compounds in the kerosene / jet fuel boiling range, the presence of nitrogen-containing polymers in the combined feed can result in unexpectedly high nitrogen content in the kerosene / jet fuel boiling range fraction. In addition, other nitrogen-containing compounds may be present in other (higher boiling point) parts of the coker effluent. Such compounds in other parts of the coker effluent may also be exposed to hydroprocessing conditions. In the case where feed conversion occurs during hydroprocessing, resulting in the formation of additional kerosene / jet fuel boiling range components, such additional kerosene / jet fuel boiling range components may be added to the total kerosene / jet fuel boiling range product.

[0029] Coking can provide a flexible reaction system for the co-processing of plastic waste. Even though the type of polymers in the plastic waste can vary widely, coking can be performed to produce a liquid product composition. TM For coking, when co-processing conventional coker feed with plastic waste, syngas can also be produced while reducing or minimizing the net coke yield.

[0030] The co-processing of plastic waste in a coking environment (or other thermal conversion environment) can be carried out by subjecting the plastic waste to four types of processes. First, the plastic waste can be conditioned by classifying and changing the size of the plastic waste to improve the adaptability of the plastic waste for co-processing. Second, the conditioned plastic waste particles can be entrained and / or dissolved in a solvent and / or a base feed. In terms of the use of a solvent, the solvent may preferably correspond to a refinery stream, such as a refinery stream formed by the co-processing of plastic waste in a coking environment. Optionally, in terms of mixing the plastic waste feed with a solvent and / or a base feed, a stripping gas may be added to remove HCl or other gases that may be gradually generated as the plastic waste is heated. Third, a solution and / or slurry of plastic waste may be sent to a coking environment, such as a fluidized coking environment or a delayed coking environment. A solution and / or slurry of plastic waste may be introduced as a separate stream, or the solution and / or slurry may be mixed with a conventional coker feed before entering the coking environment. Fourth, the plastic waste may then be co-processed in a coking environment to produce a liquid product.

[0031] In some aspects, co-processing of plastic waste in a coking environment can provide advantages over conventional feeds for coking. Conventional coker feeds are often selected for coking based on a relatively low molar ratio of hydrogen atoms to carbon atoms in the feed. Many types of plastic waste include a higher molar ratio of hydrogen atoms to carbon atoms than such conventional coker feeds. This additional hydrogen content in the plastic waste can reduce the amount of coke formed, which is conducive to increasing the throughput of liquid products.

[0032] In some aspects, the coking process can be carried out in a fluidized coking environment such as Flexicoking TM Co-processing of plastic waste feedstock with coker feedstock in a coking environment. By substantially reducing or minimizing the particle size of particles in the plastic waste feedstock, plastic waste can be unexpectedly incorporated into a fluidized coking environment. Further additional benefits can be achieved in a flexicoking environment, where plastic waste can be co-processed while increasing the production of syngas.

[0033] definition

[0034] In this discussion, it is mentioned that “C x A fraction, stream, portion, feed or other quantity is defined as that fraction (or other quantity) in which 50% by weight or more of the fraction corresponds to hydrocarbons having "x" carbon numbers. When specifying a range such as "C x -C y ”, 50 wt% or more of the fraction corresponds to hydrocarbons having a carbon number between “x” and “y”. x+ ” (or “C x- ”) corresponds to a fraction in which 50% by weight or more of the fraction corresponds to hydrocarbons having a specified carbon number or more (or a specified carbon number or less).

[0035] In this discussion, the naphtha boiling range is defined as from about the boiling point of the C5 alkanes (about 30°C) to 177°C. The naphtha boiling range fraction is defined as a fraction having a T10 distillation point of 30°C or higher and a T90 distillation point of 177°C or lower. The heavy naphtha boiling range fraction is defined as a fraction having a T10 distillation point of 30°C or higher and a T90 distillation point of 204°C or lower. The kerosene or jet fuel boiling range is defined as 125°C to 300°C. The kerosene or jet fuel boiling range fraction is defined as a fraction having a T10 distillation point of 129°C or higher and a T90 distillation point of 300°C or lower. The distillate boiling range is defined as 177°C to 343°C. The distillate boiling range fraction is defined as a fraction having a T10 distillation point of 177°C or higher and a T90 distillation point of 343°C or lower. The gas oil boiling range is defined as 343°C to 566°C. The distillate boiling range fraction is defined as the fraction having a T10 distillation point of 343°C or higher and a T90 distillation point of 566°C or lower. The vacuum residue boiling range corresponds to temperatures above 566°C. In this discussion, the distillation point may be determined according to ASTM D86. If ASTM D86 is not suitable for characterizing the sample, ASTM 2887 may be used instead.

[0036] In some aspects, the fraction may be referred to as a fraction containing jet / kerosene. This may correspond to an input stream, an intermediate effluent or fraction, or a final product that includes a portion corresponding to the jet / kerosene boiling range. In this discussion, one way to determine such a fraction may be based on a fraction having a T90 distillation point of 129°C or higher and a T10 distillation point of 300°C or lower. In other words, the fraction may be sufficiently "heavy" so that at least a portion of the fraction boils above the naphtha range (T90 greater than 129°C), and the fraction may be sufficiently "light" so that at least a portion of the fraction boils below the distillate range (T10 less than 300°C). As an example, a light naphtha fraction may have a T10 of 30°C or higher and a T90 of 120°C or lower. Such a naphtha fraction will meet the requirement of having a T10 less than 300°C, but will not meet the requirement of having a T90 of 129°C or higher. As another example, a fraction containing kerosene and distillates may have a T10 of 200° C. and a T90 of 343° C. Such a fraction meets the definition of comprising jet or kerosene because the T10 is below 300° C. and the T90 is above 129° C.

[0037] In this discussion, a liquid product / liquid portion is defined as a product / portion that is in the liquid state at 25°C and 100 kPa-a. A gas or vapor product / gas or vapor portion is defined as a product / portion that is in the gas phase at 25°C and 100 kPa-a. It should be noted that at some point during processing, a liquid product / portion may be present in the gas phase due to elevated temperatures (and / or a combination of temperature and pressure) within the reaction system. Similarly, depending on the properties of the complete configuration used, a vapor product / portion may be in the liquid phase due to a combination of temperature and pressure at a location within the reaction system.

[0038] In this discussion, the total nitrogen in the sample can be measured according to ASTM D4629. In this discussion, the basic nitrogen content of the feed, fraction or product can be determined by measuring two samples of the feed, fraction or product according to the following method. First, the total nitrogen of the sample is characterized according to ASTM D4629. Next, the sample can be pickled by adding 1 ml of 1 N sulfuric acid to 10 ml of the sample. This mixture can be formed in a suitable container such as a 20 ml vial. The mixture of the sample and sulfuric acid is vigorously vibrated, and then allowed to settle for 5 minutes. After sedimentation, the sulfuric acid should be at the bottom of the container. The pickled sample is removed from the top of the container, such as by using a pipette to remove the pickled sample while not including any sulfuric acid. The pickled sample can then be characterized according to ASTM D4629. The difference in nitrogen content between the untreated sample and the pickled sample corresponds to the nitrogen removed by acid treatment. In this discussion, the nitrogen removed by acid treatment is defined as the basic nitrogen content. The amides and amines present in the sample correspond to basic nitrogen, so the presence of excess amides and amines in the sample due to decomposition of the nitrogen-containing polymer will result in a corresponding increase in the basic nitrogen content of the sample.

[0039] raw material

[0040] In some respects, the plastic raw material for co-processing may include one or more types of polymers such as corresponding to the polymers of plastic waste or be basically composed of it. The system and method described herein may be applicable to processing the plastic waste corresponding to a single type of olefinic polymer and / or the plastic waste corresponding to multiple olefinic polymers. In the aspect where the plastic raw material is basically composed of polymers, the raw material may include one or more types of polymers and any additives, modifiers, packaging dyes and / or other components that are usually added to the polymer during and / or after the preparation. The raw material may also include any component usually visible in the polymer waste.

[0041] In various fields, plastic raw material can include one or more nitrogen-containing polymers. The example of nitrogen-containing polymer includes polyamide (for example nylon 6), polyurethane and polynitrile. Nitrogen-containing polymer can correspond to 0.1 % by weight to 25 % by weight (relative to the weight of plastic raw material), or 1.0 % by weight to 25 % by weight, or 5.0 % by weight to 25 % by weight, or 10 % by weight to 25 % by weight, or 1.0 % by weight to 15 % by weight, or 5.0 % by weight to 15 % by weight, or 1.0 % by weight to 10 % by weight of plastic raw material.

[0042] In some respects, plastic raw material may include one or more chlorinated polymers. The example of chlorinated polymers includes PVC (polyvinyl chloride) and PVDC (polyvinylidene chloride). In some respects, chlorinated polymers may correspond to 0.001 % by weight to 15 % by weight (relative to the weight of plastic raw material), or 0.1 % by weight to 15 % by weight, or 1.0 % by weight to 15 % by weight, or 0.001 % by weight to 10 % by weight, or 0.1 % by weight to 10 % by weight, or 1.0 % by weight to 10 % by weight, or 0.001 % by weight to 5.0 % by weight, or 0.001 % by weight to 1.0 % by weight of plastic raw material.

[0043] In some aspects, the polymer raw material may include at least one of polyethylene and polypropylene.Polyethylene may correspond to any convenient type of polyethylene, such as high density or low density form of polyethylene.Similarly, any convenient type of polypropylene may be used.Additionally or alternatively, plastic raw materials may include one or more of polystyrene, polyamide (such as nylon), polyethylene terephthalate and ethylene vinyl acetate (copolymer).Other polyolefins may correspond to polymers (including copolymers) of butadiene, isoprene and isobutylene.In some aspects, polyethylene and polypropylene may be present in a mixture as a copolymer of ethylene and propylene.More generally, polyolefins may include various olefins such as copolymers of ethylene, propylene, butylene, hexene and / or any other olefins suitable for polymerization.

[0044] In this discussion, unless otherwise specified, the weight of polymer in the feedstock corresponds to the weight relative to the total polymer content in the feedstock. Included in this weight are any additives and / or modifiers and / or other components included in the formulated polymer. However, the weight percentages described herein do not include any solvents or carriers that may be optionally used to facilitate the transport of the polymer to the initial pyrolysis stage.

[0045] In some respects, plastic raw material can comprise 0.01 wt % to 35 wt % of polystyrene, or 0.1 wt % to 35 wt %, or 1.0 wt % to 35 wt %, or 0.01 wt % to 20 wt %, or 0.1 wt % to 20 wt %, or 1.0 wt % to 20 wt %, or 10 wt % to 35 wt %, or 5 wt % to 20 wt %. In some respects, plastic raw material can also comprise oxygen-containing polymers such as polyethylene terephthalate. It should be noted that polyamide also contains oxygen as a part of polymer structure. In this discussion, the polymer comprising oxygen and nitrogen as a part of the repeating unit for forming polymer is defined as nitrogen-containing polymer for the purpose of characterizing plastic raw material.

[0046] Plastic raw material can be combined with one or more other raw materials to form a combined feed for co-processing in a coking environment. In various aspects, the plastic raw material can correspond to 0.1% to 30% by weight (relative to the weight of the combined feed) of the combined feed for coking, or 0.1% to 20% by weight, or 0.1% to 10% by weight, or 0.1% to 5.0% by weight, or 1.0% to 30% by weight, or 1.0% to 20% by weight, or 1.0% to 10% by weight, or 1.0% to 5.0% by weight, or 5.0% to 30% by weight, or 5.0% to 20% by weight. In some aspects, 50% by weight or more of the combined feed can correspond to a raw material with a boiling point of 343°C or higher.

[0047] It should be noted that some types of plastic waste may also include bio-derived components. For example, some types of plastic labels may include biogenic waste in the form of paper compounds. In some aspects, 1.0% to 25% by weight of the plastic feedstock may correspond to bio-derived materials. Such bio-derived materials may also potentially contribute to the nitrogen content of the plastic feedstock.

[0048] In some aspects, the coker feedstock for co-processing with the plastic waste feedstock may correspond to a relatively high boiling fraction, such as a heavy oil feedstock. For example, the coker feedstock portion of the feedstock may have a T10 distillation point of 343°C or higher, or 371°C or higher. Examples of suitable heavy oils for inclusion in the coker feedstock include, but are not limited to, reduced petroleum crude oil; petroleum atmospheric distillation bottoms; petroleum vacuum distillation bottoms, or residual oil; pitch; asphalt; bitumen; other heavy hydrocarbon residues; tar sand oil; shale oil; or even coal slurry or coal liquefaction products, such as coal liquefaction bottoms. Such a feed will typically have at least 5% by weight, typically 5-50% by weight of Conradson carbon residue (ASTM D189-165). In some preferred aspects, the feedstock is a petroleum vacuum residue.

[0049] Some examples of conventional petroleum feeds suitable for processing in a delayed coker or a fluidized bed coker may have compositions and properties within the ranges listed in Table 1 below.

[0050] Table 1: Examples of coker feedstocks

[0051] In addition to petroleum feedstocks, renewable feedstocks derived from biomass with a suitable boiling range may also be used as part of the coker feed. Such renewable feedstocks include feedstocks with a T10 boiling point of 340°C or higher and a T90 boiling point of 600°C or lower. An example of a suitable renewable feedstock derived from biomass may be a pyrolysis oil feedstock derived at least in part from biomass.

[0052] In various aspects, plastic waste can be prepared for introduction as a co-processed plastic feedstock by converting the plastic feedstock into particles and / or reducing the particle size of the plastic particles using one or more physical methods.

[0053] For plastic feedstock that is not initially in the form of particles, the first processing step may be a step of converting the plastic feedstock into particles and / or reducing the particle size. This may be accomplished using any convenient type of physical processing, such as chopping, crushing, grinding, shredding, or another type of physical conversion of plastic solids into particles. It should be noted that it may be desirable to convert the plastic into particles having a first average and / or median size, followed by additional physical processing to reduce the size of the particles.

[0054] Having a small particle size can facilitate the solvation of plastic particles in one or more additional raw materials and / or the distribution of plastic particles in a slurry of one or more additional raw materials in a desired time frame. Therefore, physical processing can be optionally performed to reduce the median particle size of the plastic particles to 10 cm or less, or 3.0 cm or less, or 2.5 cm or less, or 2.0 cm or less, or 1.0 cm or less, such as as low as 0.01 cm or can be smaller. For determining the median particle size, the particle size is defined as the diameter of the smallest enclosing sphere containing the particle.

[0055] Optionally, additional solvents may be added to the plastic particles and / or the combined feed to further facilitate dissolution of the plastic particles. Aromatic solvents are examples of potential additional solvents.

[0056] Intermediate outputs and products - amides, amines and nitrogen content

[0057] As mentioned above, the plastic raw material may include 0.1 wt% to 25 wt% of nitrogen-containing polymer relative to the weight of the plastic raw material. For typical nitrogen-containing polymers such as nylon or another type of polyamide, the nitrogen atoms correspond to 5.0 wt% to 20 wt% of the weight of the nitrogen-containing polymer. Therefore, the initial nitrogen content of the plastic raw material may range from 50 wppm to 50,000 wppm (5.0 wt%).

[0058] After exposure to the coking environment, it is believed that the nitrogen content from the plastic feedstock is unevenly distributed across the boiling range of the coker effluent. In contrast, the jet / kerosene boiling range components of the coker effluent may have an unexpectedly high proportion of nitrogen derived from the plastic feedstock. This may occur based on several mechanisms during coking.

[0059] First, for polymers such as nylon 6, caprolactam is a common decomposition product during pyrolysis. When nylon 6 is exposed to coking conditions, about 5.0% to 10% by weight of the coking products derived from nylon 6 may correspond to caprolactam. Because caprolactam is a jet fuel boiling range compound, the production of caprolactam results in a concentration of nitrogen from the plastic feedstock in the jet fuel boiling range portion of the coker effluent. More generally, in the case of larger segments formed during coking of polyamides, such larger segments will also correspond to amides.

[0060] Another mechanism for the nitrogen concentration in the jet / kerosene portion of the coker effluent can be based on the formation of terminal amines during coking. For example, the coking of nylon 6,6 can result in a high selectivity for the formation of cyclopentanone. When cyclopentanone is formed during coking, the cyclopentanone is usually separated from the chain segments in a manner that leaves behind the terminal primary amine. Such terminal primary amines can then react with other amines to form liquid boiling range compounds with a higher selectivity for naphtha and jet / kerosene boiling range compounds.

[0061] Based on the increased selectivity for forming nitrogen-containing jet fuel boiling range compounds from nitrogen-containing polymers in the plastic feedstock, co-processing under coking conditions can result in a kerosene / jet fuel boiling range coker effluent fraction having an unexpectedly high nitrogen content. In particular, the kerosene / jet fuel boiling range coker effluent fraction can have an unexpectedly high content of amides, amines, or combinations thereof.

[0062] Conventionally, the total nitrogen content of a jet / kerosene boiling range coker effluent derived from a mineral feedstock may range from about 100 wppm to 500 wppm. Within this total nitrogen content, conventionally, basic nitrogen may correspond to about 10% or less of the total nitrogen content. Thus, the amount of basic nitrogen expected in a conventional jet / kerosene boiling range fraction derived from a coker effluent is from 10 wppm to 50 wppm.

[0063] When the plastic feedstock for co-processing includes a nitrogen-containing polymer (e.g., polyamide), coking can result in the addition of 100 to 1000 wppm of amides and / or amines to the jet / kerosene boiling range portion of the coker effluent. For example, co-processing of a plastic feedstock including a nitrogen-containing polymer can result in the addition of 100 to 500 wppm of amides and / or amines, or 100 to 1000 wppm, or 100 to 5000 wppm, or 300 to 1000 wppm, or 300 to 5000 wppm, or 800 to 5000 wppm, or 1500 to 5000 wppm to the jet / kerosene boiling range portion of the coker effluent. In various aspects, the amides and / or amines produced by co-processing of nitrogen-containing polymers can result in an increase in the percentage of basic nitrogen in the jet / kerosene boiling range portion of the coker effluent. In such aspects, the basic nitrogen in the jet / kerosene boiling range portion of the coker effluent can correspond to 20 wt % or more, or 30 wt % or more, or 40 wt % or more, or 50 wt % or more, or 75 wt % or more, e.g., up to 95 wt % or potentially still higher, of the total nitrogen in the jet / kerosene boiling range portion of the coker effluent.

[0064] Based on the unexpected content of amide and / or amine nitrogen in the jet fraction, in various aspects, the basic nitrogen in the jet / kerosene boiling range portion of the coker effluent when co-processing plastic waste can be from 100 wppm to 550 wppm, or 100 wppm to 1000 wppm, or 100 wppm to 5000 wppm, or 150 wppm to 550 wppm, or 150 wppm to 1000 wppm, or 150 wppm to 5000 wppm, or 300 wppm to 550 wppm, or 300 wppm to 1000 wppm, or 300 wppm to 5000 wppm, or 550 wppm to 1000 wppm, or 550 wppm to 5000 wppm.

[0065] This unexpected increase of basic nitrogen caused by the amide and / or amine nitrogen increased can be removed by hydroprocessing.Due to the increase in nitrogen content, in order to realize the target total nitrogen in the jet / kerosene boiling range product of hydroprocessing, the severity of hydroprocessing can be increased.In various fields, hydroprocessing can be used to reduce the total nitrogen in the jet / kerosene boiling range product to 50wppm or less, or 10wppm or less, for example, to be low to substantially no total nitrogen content.In addition or alternatively, the basic nitrogen content of the jet / kerosene boiling range fraction can be reduced to 50wppm or less, or 10wppm or less, or 2.0wppm or less, for example, to be low to substantially no basic nitrogen content.

[0066] In some aspects, the increased severity of the hydroprocessing conditions required to remove additional basic nitrogen present in the coker jet fraction formed by co-processing of plastic waste can be characterized based on a hydroprocessing severity index. The severity index is based on the weight average bed temperature (WABT) for the hydroprocessing catalyst, the total pressure, and the liquid hourly space velocity (LHSV) of the feed relative to the catalyst volume. With respect to temperature, for every 10°C greater than 310°C for the WABT, add 1 to the severity index. With respect to pressure, for every 200 psi greater than 800 psig for the total pressure, add 1 to the severity index (for every 1400 kPa greater than 5500 kPa-g, add 1). With respect to space velocity, for LHSV less than 2.0 hr -1 Every 0.4 hr -1 Add 1 to the severity index.

[0067] Typically, a severity index of 3 to 10 (inclusive) can be used to remove additional basic nitrogen present in the jet / kerosene boiling range fraction produced by co-processing of plastic waste in a coker. As an example, exposure to a temperature comprising 335°C (+2 severity index), a pressure of 1100 psig / 7600 kPa-g (+1 severity index), and 1.5 hr -1 The coker jet / kerosene boiling range fraction subjected to hydroprocessing conditions at an LHSV (+1 severity index) of 1.5 hr corresponds to exposing the fraction to hydroprocessing conditions with a severity index of 4. This may be sufficient to remove the additional basic nitrogen produced in the co-processed jet / kerosene boiling range fraction derived from plastic waste in a coking environment. In contrast, the coker jet / kerosene boiling range fraction subjected to hydroprocessing conditions at 325°C (+1 severity), a pressure of 800 psig / 5500 kPa-g (+0 severity) and 1.5 hr -1 At the hydroprocessing conditions of (+1 severity), the severity index is only 2, and therefore the conditions are not sufficiently severe for removing additional basic nitrogen to the target value. It should be noted that severity index values ​​greater than 10 are effective for removing nitrogen, but are generally undesirable due to excessive coking of the fraction, resulting in a loss of product yield.

[0068] Intermediate outputs and products - other properties

[0069] In addition to nitrogen content, the kerosene / jet fuel boiling range product fractions may be characterized in other ways. In some aspects, the kerosene / jet fuel boiling range product fractions may have an octane number of 25-45, or 30-45, or 35-45, or 45-55. Additionally or alternatively, in some aspects, the jet fuel boiling range product fractions may have a sulfur content of 250 wppm or less, or 200 wppm or less, or 150 wppm or less, or 100 wppm or less, such as as low as 0.1 wppm or possibly even lower. Still further additionally or alternatively, the jet fuel boiling range product fraction may have a weight ratio of aliphatic sulfur to total sulfur of 0.05 or greater, or 0.1 or greater, such as up to 0.7 or possibly still higher, thus corresponding to a jet fuel boiling range product fraction comprising a major portion of a non-hydroprocessed mineral fraction; or the jet fuel boiling range product fraction may have a weight ratio of aliphatic sulfur to total sulfur of 0.02 or less, such as down to essentially no aliphatic sulfur, thus corresponding to a jet fuel boiling range product fraction comprising a major portion of a hydroprocessed mineral fraction.

[0070] Still other properties of the jet fuel boiling range product fraction may include a cloud point of -40°C or less, such as as low as -60°C; a pour point of -40°C or less, such as as low as -60°C; a freeze point of -40°C or less, or -47°C or less (e.g., as low as -60°C or possibly still lower); and a smoke point of 22 mm or greater.

[0071] Still other properties of the jet fuel boiling range product fraction may include a total acidity of 0.1 mg KOH / g or less, or 0.015 mgKOH / g or less, a sulfur content of 3000 wppm or less, a freezing point maximum of -40°C to -47°C, a viscosity at -20°C of 8.0 cSt or less, a flash point of at least 38°C, an initial boiling point of 140°C or more, a T10 distillation point of 205°C or less, and / or a final boiling point of 300°C or less. Another example of a property specification is a specification for a maximum pressure increase during a thermal stability test at 260°C (according to ASTM D3241) and / or a maximum deposit thickness on the surface of a heater tube, such as a maximum pressure increase of 25 mm Hg and / or a maximum deposit thickness of 85 nm. Yet another example of a property specification may be a water separation grade, such as a water separation grade of 85 or greater, as measured according to ASTM D3948. The water separation grade provides an indication of the amount of surfactant present in the jet fuel boiling range sample. Petroleum fractions having an appropriate boiling range and also meeting the various requirements of commercial standards can be tested (e.g., according to ASTM D3241) and certified for use as jet fuels. In some aspects, the kerosene boiling range fraction can correspond to a jet fuel fraction that meets the jet fuel specifications set forth in ASTM D1655. This can include a thermal stability breakpoint of 260°C or higher, or 275°C or higher, as defined by ASTM D3241.

[0072] Optional dechlorination of combined feeds

[0073] In various aspects, a combined feed for co-processing can be formed by mixing plastic raw materials with one or more other raw materials in a mixing vessel to form a raw material mixture. This will usually result in the formation of a solution of plastic raw materials in one or more other raw materials, but it is also possible that a slurry of plastic particles in one or more other raw materials can be formed. In some aspects, the raw material mixture can then be sent to a coking reactor, optionally after the mixed raw materials are mixed to improve the uniformity of the mixture. Additionally or alternatively, if it is desired to form a combined feed of dechlorination (or more generally dehalogenation), the combined feed can be maintained at a dechlorination temperature that allows the combined feed to be dechlorinated before co-processing.

[0074] After combining plastic raw materials and one or more additional feeds, the resulting combined feed can be mixed, for example in a mixing vessel. After mixing, the combined feed can be optionally maintained at a dechlorination temperature of 170°C to 350°C, or 170°C to 300°C, or 170°C to 250°C. The raw material mixture can be maintained at a dechlorination temperature for a sufficient period of time to allow dechlorination. According to this aspect, the raw material mixture can be maintained at a dechlorination temperature for 1.0 minutes to 240 minutes, or 1.0 minutes to 120 minutes, or 1.0 minutes to 60 minutes, or 5.0 minutes to 240 minutes, or 5.0 minutes to 120 minutes, or 5.0 minutes to 60 minutes, or 10 minutes to 240 minutes, or 10 minutes to 120 minutes, or 10 minutes to 60 minutes, or 1.0 minutes to 30 minutes. It should be noted that in a continuous or semi-continuous process, the average residence time of the raw material mixture in the mixing vessel is defined herein as the amount of time that the raw material mixture is maintained at the dechlorination temperature before leaving the container as part of the dechlorinated raw material mixture. It should be noted that the plastic raw material and one or more additional raw materials may be initially mixed at the dechlorination temperature, or the mixing temperature of the mixed raw materials may be different from the dechlorination temperature. If the mixing temperature is different from the dechlorination temperature, the raw material mixture can be heated to the dechlorination temperature and maintained at the dechlorination temperature for a desired period of time. Although it is feasible to mix the raw materials at a temperature higher than the dechlorination temperature, this is generally less preferred because if the mixing temperature is higher than 250°C, additional undesirable conversions of one or more additional raw materials may occur in the time period between when the mixing initially occurs and when the raw material mixture is cooled to the dechlorination temperature.

[0075] In some aspects, the feed mixture can be maintained at a dechlorination temperature for a sufficient period of time so that the resulting dechlorinated feed mixture is substantially dechlorinated. In this discussion, a substantially dechlorinated feed is defined as a feed comprising 0.005 wt % or less chlorine (relative to the gross weight of the dechlorinated feed), as determined by elemental analysis, such as as low as no chlorine content within the detection limit. For example, combustion ion chromatography can be used to measure the total chloride in a sample according to ASTM D7359. In other aspects, the feed mixture can be maintained at a dechlorination temperature until the dechlorinated mixture contains 2500 wppm or less chlorine, or 1000 wppm or less chlorine, or 500 wppm or less chlorine, or 100 wppm or less chlorine, such as as low as substantially no chlorine content within the detection limit. In still other aspects, the amount of chlorine remaining in the dechlorinated feed mixture can correspond to 20 wt % or less, or 10 wt % or less, or 5.0 wt % or less, or 1.0 wt % or less, of the original weight of chlorine in the feed mixture, e.g., as low as 0.01 wt % of the original weight of chlorine in the feed mixture, or potentially still lower.

[0076] During and / or after mixing, a purge gas may be passed through the feed mixture to remove the HCl formed while maintaining the feed mixture at a temperature of 170°C to 350°C (or 170°C to 300°C, or 170°C to 250°C). The purge gas and HCl may leave the mixing vessel as a purge discharge stream. Preferably, the purge gas may be fed into the same container for maintaining the feed mixture at the dechlorination temperature. In some alternative aspects, the feed may be mixed and / or maintained at the dechlorination temperature in one or more containers and then fed into a separate container or conduit where the purge gas is used to remove HCl. It should be noted that the thermal dechlorination process may also remove other halogens (in the form of HBr, HI or HF) if there are other types of halogen-containing polymers in the plastic feed. In the presence of other types of halogen-containing polymers, the total content of halogen-containing polymers in the plastic feed may correspond to the value provided above for the chlorine-containing polymer in the plastic feed.

[0077] The purge gas may correspond to a sufficient amount of purge gas to remove HCl as it is released during the dechlorination process. Additionally or alternatively, the purge gas may assist in mixing the plastic feedstock and one or more additional feedstocks in the container, which may promote complete dissolution of the plastic feedstock. An example range of a suitable rate of the purge gas stream may be 10,000 standard cubic feet of purge gas / metric ton of chlorinated polymer to 2,000,000 standard cubic feet of purge gas / metric ton of chlorinated polymer. This may alternatively be written as 10-2000 kSCF purge gas / metric ton of chlorinated polymer. Any convenient gas may be used as the purge gas. In order to minimize cost, gases such as nitrogen or steam may be suitable choices. Other purge gas options may correspond to light refining or process gas streams from a refining process, such as a light distillate stream (i.e., C 4- Stream). Preferably, the purge gas may include reduced or minimized amounts of contaminants, such as NH or H2S, or may be substantially free of such contaminants. The purge gas may then exit the mixing vessel (and / or other separate vessels) as a purge effluent stream comprising at least the purge gas and HCl produced during dechlorination. After dechlorination, the liquid product remaining in the mixing vessel may leave a dechlorinated feed mixture, which is then sent to a common processing stage.

[0078] In some aspects, the temperature in the mixing vessel may be selected so as to reduce or minimize the amount of volatile (organic) products other than HCl. In the mixing vessel, the volatile organic compounds may correspond to compounds (e.g., light gases and / or naphtha boiling range compounds) having a boiling point below the dechlorination temperature (i.e., below 170° C.-250° C.). In particular, the amount of light gases and / or naphtha boiling range compounds that boil at a temperature below the dechlorination temperature formed in the mixing vessel during dechlorination may be reduced or minimized. In some aspects, the conversion of one or more additional feedstocks in the mixing vessel may be sufficiently low so as to form 5.0% by weight or less of organic compounds that boil at a temperature below the dechlorination temperature (relative to the weight of the feedstock mixture), or 3.0% by weight or less, or 1.0% by weight or less, such as so low that substantially no organic compounds that boil at a temperature below the dechlorination temperature are formed. Reducing or minimizing the formation of volatile organic compounds is beneficial because any volatile organic species formed in the mixing vessel will tend to be removed from the mixing vessel by the purge gas as part of the purge effluent stream along with the HCl. This means that recovery of such organic compounds as products requires purification of the purge effluent from the mixing vessel. In aspects where a separate vessel or conduit is used to expose the feed mixture to the purge gas, the temperature of the mixture in the separate vessel or conduit may also be maintained at a temperature of 170° C. to 250° C. to reduce or minimize the formation of volatile organic products that will also be removed by the purge gas as part of the purge effluent.

[0079] In some alternative aspects, if it is desired to recover organic compounds from the purge effluent, it should be noted that the purge effluent stream can be subjected to contaminant removal in order to recover volatile organic products. The purge effluent stream can be subjected to optional contaminant removal by any convenient method. For example, conventional amine scrubbing (amine dissolved in water) can be used to remove HCl from the purge effluent stream.

[0080] When performing a thermal dehalogenation process, another option may be to also include a calcium source and / or an additional source of metals / materials having alkaline properties in the thermal dechlorination environment. For example, various types of calcium additives may be included in the thermal dechlorination environment, including (but not limited to) Ca(OH)2, CaO and / or CaCO3. During the thermal dehalogenation of plastic raw materials, the chlorine released from the thermal decomposition of the polymer may be generally released in the form of HCl. The presence of a calcium additive may be beneficial during the thermal dehalogenation by allowing at least a portion of the HCl to be converted into CaCl2. The stoichiometry of the additional product (one or more) formed may depend on the properties of the calcium additive. The CaCl2 formed in the thermal dehalogenation environment is a solid with relatively low solubility in the heavy crude oil fraction. By forming CaCl2, potentially highly corrosive HCl may be converted into a solid compound, the possibility of which causing surface corrosion in the reaction environment is low or minimal. The CaCl2 formed in the thermal dehalogenation environment may be removed by any convenient method such as sedimentation, centrifugation and / or filtration. It should be noted that some sodium compounds such as NaCO3 may also be used as reagent additives in the thermal dehalogenation environment to facilitate the removal of the generated chlorine-containing compounds from the reaction environment. More generally, various types of metals / materials with basic properties that allow for the formation of solid halide compounds can be used to facilitate the removal of halogens released as hydrogen halides in a thermal dehalogenation environment.

[0081] It should be noted that the inclusion of calcium additives and / or other alkaline additives in the thermal dehalogenation environment can reduce or minimize the need for using a purge gas in the thermal dehalogenation environment. For example, although both purge gas and calcium additives can be used, the addition of calcium additives causes the HCl formed during the thermal dehalogenation to be converted into a large amount of solid dehalogenation products. Such solid dehalogenation products can be filtered or otherwise physically separated from the remaining raw materials. The gaseous products formed in place of HCl can correspond to compounds such as CO2 and / or H2O. Although purge gas can be used to remove CO2 and / or H2O from the environment, there are various other options for processing such products. Other types of alkaline materials and / or similar exchanges of hydrogen halide gaseous products of CO2 and / or H2O can also be used for other hydrogen halides.

[0082] The pressure in the mixing vessel during dechlorination can be any convenient pressure. In some aspects, a pressure greater than 100 kPa-a can be used to further assist in reducing or minimizing the amount of volatile organic products that exit the mixing vessel as part of the purge gas. In such aspects, the pressure in the mixing vessel during the dechlorination process can be from 150 kPa-a to 1000 kPa-a.

[0083] Examples of common machining configurations

[0084] Figure 1 An example showing a configuration for co-processing plastic feedstocks in a coking environment. Figure 1 In the example configuration shown in , all portions of the coker effluent that contribute to the formation of kerosene / jet fuel boiling range products are passed through the same hydroprocessing stage(s).

[0085] exist Figure 1 , plastic feedstock 101 and one or more additional feedstocks 105 are combined in container 110 to form a combined feed. Container 110 may optionally correspond to a mixing container, or mixing may be performed at another location. Figure 1 , an optional purge gas 112 stream is shown introduced into vessel 110. If the combined feed is subjected to thermal dechlorination (or more generally thermal dehalogenation), the purge gas 112 may be used to sweep away hydrogen chloride (and / or other hydrogen halides) to a purge gas effluent 118. Figure 1 Thermal dechlorination is shown occurring in vessel 110, although in other aspects one or more other vessels may be used.

[0086] The combined feed 115 (optionally thermally dechlorinated) may then be fed to a coking stage 120. The coking stage 120 may correspond to a delayed coker, a fluid coker, or a combination thereof. Figure 1 In the coking stage 120, one or more separators are also included for separating the coker effluent into a desired number of effluent fractions. Figure 1 In the example shown in , the coker effluent can be separated to form a coker light gas product 121, a coker naphtha 123, a light coker gas oil 125, and a heavy coker gas oil 127. A coke product 129 is also shown, although it should be understood that the coke product in the coker is typically withdrawn from the coker separately from the coker effluent.

[0087] One or more of the effluent fractions may then be sent to the hydroprocessing stage 130. Figure 1 In the example shown in , coker naphtha 123, light coker gas oil 125, and heavy coker gas oil 127 are all sent to the hydroprocessing stage 130. In other aspects, one or more of the effluent fractions may be sent to other process units instead. For example, one option may be to send coker naphtha 123 and light coker gas oil 125 to the hydroprocessing stage 130, while the heavy coker naphtha 127 is used for another purpose. As another example, coker naphtha 123 and heavy coker gas oil 127 may be sent to the hydroprocessing stage 130, while the light coker gas oil 125 is used for another purpose. Additionally or alternatively, in some aspects only a portion of one or more of the effluent fractions may be sent to the hydroprocessing stage 130, while other portions of a given effluent fraction may be used for other purposes.

[0088] After hydroprocessing 130, the hydroprocessed effluent 135 may be separated using one or more separation stages 140 to form at least a kerosene / jet fuel boiling range fraction and one or more other fractions. Figure 1 In the example shown in FIG. 1 , separation stage 140 produces a light fraction 141, a naphtha product 143, a kerosene or jet product 145, a diesel or distillate product 147, and a heavier product (e.g., hydrotreated heavy coker gas oil) 149. In other aspects, one or more of the additional products may be omitted. For example, the diesel or distillate product 147 and the heavier product 149 may correspond to a single product in some configurations.

[0089] Figure 2 Another example of a configuration for producing a jet / kerosene boiling range fraction is shown. Figure 2 In the hydroprocessing process, different fractions of the coker effluent are sent to different hydroprocessing stages. This can allow, for example, the higher boiling fractions of the coker effluent to be hydroprocessed under higher severity conditions. When the higher boiling fractions are processed separately, it is feasible that the higher boiling fractions can contain essentially no kerosene / jet fuel boiling range compounds before hydroprocessing. However, due to the conversion of the higher boiling fractions under the hydroprocessing conditions, the hydroprocessed effluent can contain kerosene / jet fuel boiling range components.

[0090] exist Figure 2 , plastic raw material 201 and one or more additional raw materials 205 are combined in container 210 to form a combined feed. Container 210 may optionally correspond to a mixing container, or mixing may be performed at another location. Figure 2 , an optional purge gas 212 stream is shown introduced into vessel 210. If the combined feed is subjected to thermal dechlorination (or more generally thermal dehalogenation), the purge gas 212 may be used to sweep away hydrogen chloride (and / or other hydrogen halides) to a purge gas effluent 218. Figure 1 Thermal dechlorination is shown occurring in vessel 210, although in other aspects one or more other vessels may be used.

[0091] The combined feed 215 (optionally thermally dechlorinated) may then be fed to a coking stage 220. The coking stage 220 may correspond to a delayed coker, a fluid coker, or a combination thereof. Figure 2 In the embodiment, the coking stage 220 also includes one or more separators for separating the coker effluent into a desired number of effluent fractions. Figure 2 In the example shown in FIG. 2 , the coker effluent can be separated to form a coker light gas product 221, a coker naphtha 223, a light coker gas oil 225, and a heavy coker gas oil 227. A coke product 229 is also shown, although it should be understood that the coke product in the coker is typically withdrawn from the coker separately from the coker effluent.

[0092] exist Figure 2 The liquid effluent fractions (coker naphtha 223, light coker gas oil 225, heavy coker gas oil 227) are then fed to multiple parallel hydroprocessing stages. Figure 2 In the example shown in , coker naphtha 223 is sent to hydroprocessing stage 250; light coker gas oil 225 is sent to hydroprocessing stage 260; and heavy coker gas oil 227 is sent to hydroprocessing stage 270. It should be understood that any convenient number of coker effluent fractions can be formed and sent to separate hydroprocessing stages. Similarly, more than one coker effluent fraction can be sent to a single hydroprocessing stage. Another option can be to use at least a portion of one or more of the coker effluent fractions for different purposes. Hydroprocessing stages 250, 260, and 270 can each correspond to one or more types of hydroprocessing, if desired. Hydroprocessing stages 250, 260, and 270 also include separators for separating the effluent of the hydroprocessing into product fractions.

[0093] exist Figure 2 In the configuration shown in , the hydroprocessing stage 270 produces at least one fraction 272 containing kerosene / jet fuel boiling range components and one or more products 275. The hydroprocessing stage 260 produces at least one fraction 262 containing kerosene / jet fuel boiling range components and one or more products 265. The fractions 262 and 272 can then be sent to the hydroprocessing stage 250 so that the jet / kerosene boiling range components from the fractions 262 and 272 can be combined into the kerosene / jet fraction 255 from the hydroprocessing stage 250. The fractions 262 and 272 can be sent to the hydroprocessing stage 250 before the hydroprocessing reactor(s) and / or before one or more separators for separating the hydroprocessing effluent. The hydroprocessing stage 250 can also form one or more lower boiling fractions 251 such as a naphtha fraction and / or a light fraction. Although not explicitly shown, one or more heavier fractions can also be produced, depending on the properties of the input stream(s) to the hydroprocessing stage 250.

[0094] Co-processing conditions - fluid coking and delayed coking

[0095] In various aspects, co-processing can be performed by exposing a combined feed of plastic feedstock and additional feedstock (optionally thermally dechlorinated) to coking conditions.

[0096] Coking processes in modern refineries can be generally classified as delayed coking or fluidized bed coking. Fluidized bed coking is a petroleum refining process in which a heavy petroleum feed, usually the non-distillable residue (residue) from the fractionation of heavy oils, is converted into lighter, more useful products by thermal decomposition (coking) at elevated reaction temperatures, typically 480°C to 590°C (-900°F to 1100°F) and in most cases 500°C-550°C (-930°F to 1020°F). Heavy oils that can be processed by fluid coking processes include heavy atmospheric residues, petroleum vacuum distillation bottoms, aromatic extracts, asphalt, and petroleum asphalt, which are from tar sands, tar pits and asphalt lakes in Canada (Athabasca, Alberta), Trinidad, Southern California (La Brea (Los Angeles)), McKittrick (Bakersfield, California), Carpinteria (Santa Barbara County, California), Lake Bermudez (Venezuela), and similar deposits such as those found in Texas, Peru, Iran, Russia and Poland. Such feeds can be processed together with biomass oil. Biomass oil and conventional feeds can be introduced separately, or biomass oil and conventional feeds can be mixed before being introduced into the coking environment. Biomass oil and / or conventional feeds can be introduced into the coking environment in a conventional manner.

[0097] Flexicoking developed by Exxon Research and Engineering Company TM The process is a variation of the fluidized coking process, which is operated in an apparatus that includes a reactor and a heater, and also includes a gasifier for gasifying the coke product (by reacting with an air / steam mixture to form a low heating value fuel gas). The stream of coke is sent from the heater to the gasifier, where all but a small portion of the coke is gasified in a fluidized bed in an oxygen-deficient environment to a low BTU gas (~120 BTU / standard cubic foot) by adding steam and air to form a fuel gas containing carbon monoxide and hydrogen. In conventional Flexicoking TM In the configuration, the fuel gas product from the gasifier containing entrained coke particles is returned to the heater to provide most of the heat required for thermal cracking in the reactor, the balance of the reactor heat requirement being supplied by combustion in the heater. A small amount of clean coke (about 1% of the feed) is withdrawn from the heater to remove metals and ash from the system. Liquid yields and properties are comparable to those from fluid coking. The fuel gas product is withdrawn from the heater after separation in internal cyclones, which return the coke particles through their legs.

[0098] In this description, the term "Flexicoking" (a trademark of ExxonMobil Research and Engineering Company) is used to name a fluidized coking process in which a heavy petroleum feed is subjected to thermal cracking in a fluidized bed of heated solid particles to produce lower molecular weight and boiling point hydrocarbons and coke as a byproduct, which is deposited on the solid particles in the fluidized bed. The resulting coke can then be converted to fuel gas by contact with steam and an oxygen-containing gas in a gasification reactor (gasifier) ​​at elevated temperatures. This type of configuration may be more generally referred to as integration of fluidized bed coking with gasification. Figure 3 and 4 An example of a fluid coking reactor including a gasifier is provided.

[0099] Figure 3An example of a Flexicoker unit (i.e., a system comprising a gasifier thermally integrated with a fluidized bed coker) is shown with three reaction vessels: a reactor, a heater, and a gasifier. The unit comprises a reactor section 10 having a coking zone and its associated stripping and washing sections (not shown separately), a heater section 11, and a gasifier section 12. The relationship of the coking zone, the washing zone, and the stripping zone in the reactor section is shown, for example, in U.S. Pat. No. 5,472,596, which is cited for describing a Flexicoking unit and its reactor sections. A heavy oil feed is introduced into the unit via line 13 and cracked hydrocarbon products are withdrawn via line 14. Fluidizing and stripping steam is supplied via line 15. Cold coke is withdrawn from the stripping section at the bottom of the reactor 10 by means of line 16 and transferred to the heater 11. The term "cold" is, of course, clearly relative when applied to the temperature at which the coke is withdrawn, since it is much higher than the ambient temperature at the operating temperature of the stripping section. The hot coke is circulated from the reactor 11 to the reactor 10 via line 17. The coke from the heater 11 is transferred to the gasifier 12 via line 21, and the hot partially gasified coke particles are circulated from the gasifier back to the heater via line 22. Excess coke is withdrawn from the heater 11 via line 23. In a conventional configuration, a gasifier 12 is provided, which has a steam and air supply via line 24, and hot fuel gas is taken from the gasifier via line 25 and sent to the heater. In some alternative aspects, instead of supplying air to the gasifier 12 via line 24, an oxygen stream having a purity of 95% by volume or greater, such as an oxygen stream from an air separation unit, may be provided. In such aspects, in addition to supplying the oxygen stream, an additional dilution gas stream may be supplied via line 31. The additional dilution gas may correspond to, for example, CO2 separated from the fuel gas produced during the gasification process. The fuel gas is withdrawn from the unit via line 26 on the heater; coke fines are removed from the fuel gas in a heater cyclone system 27, which includes primary and secondary cyclones connected in series, with a feed leg that returns the separated fines to the fluidized bed in the heater. The fuel gas from line 26 may then undergo further processing. For example, in some aspects, the fuel gas from line 26 may be sent to a separation stage to separate CO2 (and / or H2S). This may result in a stream with an increased concentration of syngas, which may then be sent to a conversion stage to convert the syngas into methanol.

[0100] It should be noted that in some optional aspects, the heater cyclone system 27 may be located in a separate container (not shown) rather than in the heater 11. In such aspects, the pipeline 26 may extract the fuel gas from the separate container, and the pipeline 23 for purging excess coke may correspond to the pipeline that transports the coke fines away from the separate container. These coke fines and / or other partially gasified coke particles discharged from the heater (or gasifier) ​​may have an increased metal content relative to the raw material. For example, the weight percentage of metal in the coke particles discharged from the system (relative to the weight of the discharged particles) may be greater than the weight percentage of metal in the raw material (relative to the weight of the raw material). In other words, the metal from the raw material is concentrated in the discharged coke particles. Because the gasifier conditions do not produce slag, the discharged coke particles correspond to a mechanism for removing metals from the coker / gasifier environment. In some aspects, the metal may correspond to a combination of nickel, vanadium and / or iron. Additionally or alternatively, the gasifier conditions may be such that substantially no metal oxides are deposited on the interior walls of the gasifier, such as less than 0.1 wt. %, or less than 0.01 wt. % of the metals present in the feedstock introduced into the coker / gasifier system.

[0101] In such Figure 3 In the configuration of FIG. 1 , the system elements shown in the figure can be characterized based on the fluid communication between the elements. For example, the reactor section 10 is directly in fluid communication with the heater 11. The reactor section 10 is also indirectly in fluid communication with the gasifier 12 via the heater 11.

[0102] As an alternative, the integration of the fluidized bed coker with the gasifier can also be accomplished without the use of an intermediate heater. In such an alternative aspect, the cold coke from the reactor can be transferred directly to the gasifier. This transfer will in almost all cases be unambiguously direct, with one end of the tubular transfer line being connected to the coke outlet of the reactor and its other end being connected to the coke inlet of the gasifier, without an intermediate reaction vessel, i.e. a heater. However, the presence of means other than a heater, such as a lift gas inlet, etc., is not excluded. Similarly, although the hot, partially gasified coke particles from the gasifier are returned directly from the gasifier to the reactor, this only means that there is no need for a separate heating process as in a conventional three-vessel Flexicokart. TM An intermediate heater is provided in the reactor, while other devices such as gas lift inlets and outlets may be present between the gasifier and the reactor.

[0103] Figure 4 An example showing the integration of a fluidized bed coker with a gasifier but without a separate heater vessel. Figure 4 In the configuration shown in , the cyclone separator for separating the fuel gas from the catalyst fines is located in a separate vessel. In other aspects, the cyclone separator can be included in the gasifier vessel 41.

[0104] exist Figure 4 In the configuration shown in FIG. 4 , the configuration includes a reactor 40, a main gasifier vessel 41, and a separator 42. Heavy oil feed is introduced into the reactor 40 via line 43 and fluidizing / stripping gas via line 44; cracked hydrocarbon products are withdrawn via line 45. Cold stripped coke is conveyed directly from the reactor 40 to the gasifier 41 via line 46, while hot coke is returned to the reactor in line 47. Steam and oxygen are supplied via line 48. A gas stream containing coke fines is directed to the separator vessel 42 via line 49 connected to the gas outlet of the main gasifier vessel 41. The fines are separated from the gas stream in a cyclone separator system 50 comprising primary and secondary cyclones connected in series with a dipleg for returning the separated fines to the separator vessel. The separated fines are then returned to the main gasifier vessel via return line 51 and a fuel gas product is withdrawn via line 52. The coke is removed from the separator via line 53. The fuel gas from line 52 may then undergo further processing for separation of CO 2 (and / or H 2 S) and conversion of the syngas to methanol.

[0105] Cokers and gasifiers can be operated according to the parameters necessary for the desired coking process. Thus, the heavy oil feed will typically be a heavy (high boiling) vacuum petroleum crude oil; petroleum atmospheric distillation bottoms; petroleum vacuum distillation bottoms, or residue; asphalt; bitumen; petroleum asphalt; other heavy hydrocarbon residues; tar sand oil; shale oil; or even a coal slurry or coal liquefaction product, such as coal liquefaction bottoms. Such a feed will typically have a Conradso carbon residue (ASTM D189-165) of at least 5% by weight, typically 5-50% by weight. Preferably, the feed is a petroleum vacuum residue.

[0106] Fluid coking is carried out in an apparatus having a large reactor containing hot coke particles which are maintained under fluidized conditions at the desired reaction temperature by steam injected at the bottom of the vessel, wherein the average direction of motion of the coke particles is downward through the bed. The heavy oil feed is heated to a pumpable temperature, typically in the range of 350°C to 400°C (~660°F to 750°F), mixed with atomizing steam, and fed through a plurality of feed nozzles arranged in several successive levels in the reactor. Steam is injected into the stripping section at the bottom of the reactor and passes upward through the coke particles which descend through the dense phase of the fluidized bed in the main part of the reactor above the stripping section. Part of the feed liquid coats the coke particles in the fluidized bed and is subsequently cracked into a solid coke layer and lighter products produced as gas or vaporized liquid. The residence time of the feed in the coking zone, where the temperature is suitable for thermal cracking, is on the order of 1 to 30 seconds. The reactor pressure is relatively low in order to facilitate the gasification of hydrocarbon vapors, which pass upward from the dense phase of the fluidized bed in the coking zone into the dilute phase and into the cyclone separator at the top of the coking zone, where most of the entrained solids are separated from the gas phase by centrifugal force in one or more cyclones and returned to the dense fluidized bed through the cyclone legs by gravity. The mixture of hydrocarbon vapor and steam from the reactor is then discharged from the cyclone gas outlet to a scrubber section in a plenum located above the coking zone and separated from it by a partition. It is quenched in the scrubber section by contact with liquid descending on the shed. A pumping circulation loop circulates the condensate to an external cooler and returns to the top shed row of the scrubber section to provide cooling for the quenching and condensation of the heaviest fraction of the liquid product. This heavy fraction is usually recycled to disappearance by feeding back to the coking zone in the reactor.

[0107] During the fluid coking process, a heavy oil feed preheated to a temperature at which it can flow and pump is introduced into the coking reactor through an injection nozzle toward the top of the reactor vessel, which is configured to produce a feed spray that enters a bed of fluidized coke particles in the vessel. The temperature in the coking zone of the reactor is typically in the range of 450°C to 650°C, and the pressure is maintained at a relatively low level, typically in the range of 0 kPag to 700 kPag (~0 psig to 100 psig) and most often 35 kPag-320 kPag (~5 psig to 45 psig) to promote rapid drying of the coke particles, thereby preventing the formation of sticky, adherent high molecular weight hydrocarbon deposits on the particles that can cause reactor fouling. In some aspects, the temperature in the coking zone may be 450°C to 600°C, or 450°C to 550°C. Conditions may be selected so that a desired amount of feedstock conversion occurs in the fluidized bed reactor. For example, conditions may be selected to achieve at least 10 wt% conversion relative to 343°C (or 371°C), or at least 20 wt% conversion relative to 343°C (or 371°C), or at least 40 wt% conversion relative to 343°C (or 371°C), such as up to 80 wt% conversion or possibly even higher. The light hydrocarbon products of the coking (thermal cracking) reaction are vaporized, mixed with the fluidizing steam and passed upward through the dense phase of the fluidized bed into the dilute phase region above the dense fluidized bed of coke particles. This mixture of vaporized hydrocarbon products formed in the coking reaction flows upward through the dilute phase with steam at a critical velocity of about 1 to 2 m / s (~3 to 6 ft / s), entraining some fine coke solid particles separated from the cracking vapor in the reactor cyclone separator as described above. In aspects where steam is used as a fluidizing agent, the weight of steam introduced into the reactor may be selected relative to the weight of the feedstock introduced into the reactor. For example, the mass flow rate of the steam entering the reactor may correspond to 6.0% of the mass flow rate of the raw material, or 8.0% or more, such as up to 10% or possibly higher. If the activated light hydrocarbon stream is used as part of the stripping and / or fluidizing gas in the reactor, the amount of steam can be potentially reduced. In such aspects, the mass flow rate of the steam may correspond to 6.0% or less of the mass flow rate of the raw material, or 5.0% or less, or 4.0% or less, or 3.0% or less. Optionally, in some aspects, the mass flow rate of the steam may be lower, such as corresponding to 1.0% or less of the mass flow rate of the raw material, or 0.8% or less, or 0.6% or less, such as down to substantially all of the steam being replaced by activated light hydrocarbon steam. The cracked hydrocarbon vapor leaves the cyclone separator and enters the washing section of the reactor and then to product fractionation and recovery.

[0108] In a typical fluid coking process, the coke particles formed in the coking zone are carried downward in the reactor and leave the bottom of the reactor vessel through a stripping section where they are exposed to steam to remove occluded hydrocarbons. The solid coke from the reactor, consisting primarily of carbon with lesser amounts of hydrogen, sulfur, nitrogen and trace amounts of vanadium, nickel, iron and other elements derived from the feed, passes through the stripper and leaves the reactor vessel to a burner or heater where it is partially combusted with air in a fluidized bed to raise its temperature from 480°C to 700°C (from ~900°F to 1,300°F), thereby supplying the heat required for the endothermic coking reaction, after which a portion of the hot coke particles is recycled to the fluidized bed reaction zone to transfer heat to the reactor and serve as a core for coke formation. The remainder is withdrawn as a coke product. The net coke yield is only about 65% of that produced by delayed coking.

[0109] For a coking process including a gasification zone, the cracking process is carried out in a reactor, the coke particles pass downward through the coking zone, through a stripping zone, where the occluded hydrocarbons are stripped by an ascending stream of fluidizing gas (steam). They then leave the coking reactor and pass to a gasification reactor (gasifier), which contains a fluidized bed of solid particles and operates at a temperature higher than the coking zone of the reactor. In the gasifier, the coke particles are converted into a fuel gas containing carbon monoxide and hydrogen by reacting with steam and an oxygen-containing gas at elevated temperatures.

[0110] The gasification zone is typically maintained at an elevated temperature in the range of 850°C-1,000°C (-1560°F to 1830°F) and a pressure in the range of 0 kPag-1000 kPag (-0 psig to 150 psig), preferably 200 kPag-400 kPag (-30 psig to 60 psig). Steam and an oxygen-containing gas are introduced to provide a source of oxygen for fluidization and gasification. In some aspects, the oxygen-containing gas may be air. In other aspects, the oxygen-containing gas may have a low nitrogen content, such as oxygen from an air separation unit or an additional oxygen stream (comprising 95% by volume or more, or 98% by volume or more oxygen) sent to the gasifier for reaction with solid particles in the coking zone, the solid particles comprising coke deposited thereon. In aspects where the oxygen-containing gas has a low nitrogen content, a separate diluent stream, such as a recycled CO2 or H2S stream derived from the fuel gas produced by the gasifier, may also be passed to the gasifier.

[0111] In the gasification zone, the reaction between the coke and the steam and oxygen-containing gas produces a fuel gas containing hydrogen and carbon monoxide and a partially gasified residual coke product. The conditions in the gasifier are selected accordingly to produce these products. The steam and oxygen rates (and any optional CO2 rates) will depend on the rate at which cold coke enters from the reactor, and to a lesser extent on the composition of the coke, which in turn will vary according to the composition of the heavy oil feed and the severity of the cracking conditions in the reactor, wherein these are selected according to the range of feed and desired liquid products. The fuel gas product from the gasifier may contain entrained coke solids and these are removed in the gasifier section of the device by a cyclone separator or other separation technology; the cyclone separator may be an internal cyclone separator in the main gasifier vessel itself or an external cyclone separator in a separate smaller vessel, as described below. The fuel gas product is taken out from the gasifier cyclone separator as an overhead. The resulting partially gasified solids are removed from the gasifier and introduced directly into the coking zone of the coking reactor at a level in the dilute phase above the lower dense phase.

[0112] In some aspects, coking conditions can be selected to provide a desired amount of conversion relative to 343° C. Typically, the desired amount of conversion can correspond to 10 wt % or greater, or 50 wt % or greater, or 80 wt % or greater relative to 343° C., e.g., up to substantially complete feedstock conversion.

[0113] Delayed coking is a process for the thermal conversion of heavy oils such as petroleum residues (also called "residue") to produce liquid and vapor hydrocarbon products and coke. Delayed coking of residues from heavy and / or sour (high sulfur) crude oils is performed by converting part of the residue to more valuable hydrocarbon products. The resulting coke has value as a fuel (fuel grade coke), electrodes for aluminum manufacturing (anode grade coke), etc., depending on its grade.

[0114] Typically, a residual fraction, such as a petroleum resid feed, is pumped into a preheater where it is preheated, for example, to a temperature of 480°C to 520°C. The preheated feed is then introduced into a coking zone, typically a vertically oriented insulated coker vessel, such as a drum, through an inlet at the bottom of the drum. The pressure in the drum is typically relatively low, such as 15 psig (~100 kPa-g) to 80 psig (~550 kPa-g), or 15 psig (~100 kPa-g) to 35 psig (~240 kPa-g), so that volatiles are removed at the top. The drum typically has an operating temperature of between about 475°C and 525°C. The hot feed is thermally cracked in the coke drum for a period of time ("coking time"), releasing volatiles, primarily consisting of hydrocarbon products, which are continuously lifted through a coke bed consisting of channels, holes and passages and collected at the top. The volatile products are introduced into the coker fractionator for distillation and recovery of coker gas, gasoline boiling range materials such as coker naphtha, light gas oil and heavy gas oil. In an embodiment, a portion of the heavy coker gas oil present in the product stream introduced into the coker fractionator can be captured for recycling and combined with fresh feed (coker feed component), thereby forming a coker heater or coke oven feed. In addition to the volatile products, the process also causes coke to accumulate in the drum. When the coke drum is full of coke, the heated feed is transferred to another drum and steam is used to remove hydrocarbon vapors from the coke drum. The drum is then quenched with water to reduce the temperature to 200°F (~95°C) to 300°F (~150°C), after which the water is discharged. When the drainage step is completed, the drum is opened and the coke is removed by drilling and / or cutting using a high-speed water jet ("hydraulic decoking").

[0115] Volatile products from the coke drum are directed away from the process for further processing. For example, the volatiles may be directed to a coker fractionator for distillation and recovery of coker gas, coker naphtha, light gas oil, and heavy gas oil. Such fractions, typically but not always after upgrading, may be used to blend fuel and lubricant products such as motor gasoline, motor diesel, fuel oil, and lubricant oil. Upgrading may include separation, heteroatom removal via hydrotreating and non-hydrotreating processes, dearomatization, solvent extraction, and the like. The process is compatible with a process in which at least a portion of the heavy coker gas oil present in the product stream introduced into the coker fractionator is captured for recycling and combination with fresh feed (coker feed components), thereby forming a coker heater or coke oven feed. The combined feed ratio ("CFR") is the volume ratio of the furnace feed (fresh feed plus recycle oil) to the fresh feed fed to a continuous delayed coker operation. Delayed coking operations typically employ 5% to 35% volume % recycle (CFR of about 1.05 to about 1.35). In some cases, there may be no recycle, and sometimes in dedicated applications, the recycle may be up to 200%.

[0116] Hydroprocessing of coker effluent fractions

[0117] In various aspects, at least a portion of one or more coker effluent liquid fractions may be exposed to hydroprocessing conditions to reduce or minimize the content of unexpected nitrogen-containing compounds in the final kerosene / jet fuel boiling range product. Such hydroprocessing may include, but is not limited to, hydrotreating, hydrocracking, catalytic dewaxing and / or hydroisomerization, aromatic saturation.

[0118] In this discussion, hydroprocessing is defined as exposing the input stream to the hydroprocessing stage to a H partial pressure of 50 kPa or greater (e.g., 3000 kPa) in the presence of a catalyst at a temperature between 150° C. and 450° C. Temperatures below 150° C. result in minimal hydroprocessing activity, while temperatures greater than 450° C. result primarily in thermal cracking of the hydrocarbonaceous feed.

[0119] Hydroprocessing (e.g., hydrotreating) may be performed in the presence of hydrogen. Hydrogen (contained in the hydrogen "treating gas") is provided to the reaction zone. For example, a hydrogen-containing stream is fed, injected, or otherwise introduced into a container, reaction zone, or hydroprocessing zone corresponding to the location of the hydroprocessing catalyst. The treating gas (as mentioned herein) may be either pure hydrogen or a hydrogen-containing gas stream containing hydrogen in an amount sufficient for the intended reaction (one or more). The treating gas may optionally include one or more other gases (e.g., nitrogen and light hydrocarbons such as methane) that do not adversely interfere with or affect the reaction or product. Impurities (e.g., H2S and NH3) are undesirable and can be removed from the treating gas to a sufficiently low level before the treating gas is introduced into the reactor. In the aspect where the treating gas stream may be different from a stream consisting essentially of hydrogen (i.e., at least 99% by volume hydrogen), the treating gas stream introduced into the reaction stage may contain at least 50% by volume, or at least 75% by volume hydrogen, or at least 90% by volume hydrogen.

[0120] During hydroprocessing, the feedstock may be contacted with a hydroprocessing catalyst under effective hydroprocessing conditions, which may include a temperature in the range of 450°F to 800°F (-232°C to -427°C), or 550°F to 750°F (-288°C to -399°C); a pressure in the range of 1.5 MPag to 20.8 MPag (-200 to -3000 psig), or 2.9 MPag to 13.9 MPag (-400 to -2000 psig); a liquid hourly space velocity (LHSV) of 0.1-10 hr -1 , or 0.1-5 hr -1 ; and hydrogen treatment gas rate of 430-2600 Nm 3 / m 3(~2500 to ~15000 SCF / bbl), or 850-1700 Nm 3 / m 3 (-5000 to -10000 SCF / bbl). Any convenient type of hydroprocessing catalyst may be used, such as hydroprocessing catalysts for naphtha hydroprocessing, distillate hydroprocessing, heavy oil hydroprocessing, and / or catalysts for broad-cut hydroprocessing.

[0121] The above hydroprocessing conditions cover a wide range of severity. In some aspects, hydroprocessing of a liquid coker effluent fraction substantially corresponding to a naphtha boiling range fraction, a kerosene / jet fuel boiling range fraction, or a combination thereof may be performed under milder conditions. A liquid coker effluent fraction substantially corresponding to a naphtha boiling range fraction, a kerosene jet fuel boiling range fraction, or a combination thereof is defined as a liquid coker effluent fraction having a T80 distillation point of 300° C. or less or a T90 distillation point of 300° C. or less. Such a liquid coker effluent fraction may have a T10 distillation point of 30° C. or more. In some aspects, the temperature may be in the range of 450°F to 700°F (-232°C to -371°C), or 450°F to 650°F (-232°C to -343°C); the pressure may be in the range of 1.5 MPag to 10.4 MPag (-200 psig to -1500 psig), or 2.9 MPag to 6.9 MPag (-400 psig to -1000 psig); the liquid hourly space velocity (LHSV) may be 0.1-10 hr -1 , or 0.1-5 hr -1 ; and hydrogen treatment gas rate of 430-2600 Nm 3 / m 3 (~2500 to ~15000 SCF / bbl), or 850-1700 Nm 3 / m 3 Such hydroprocessing of the liquid coker effluent fraction is carried out at a pressure of 5000 to 10000 SCF / bbl.

[0122] In some aspects where the coker effluent fraction comprises a substantial portion of the coker gas oil, higher severity hydroprocessing conditions may be used. In such aspects, temperatures may be in the range of 550°F to 800°F (-288°C to -427°C), or 600°F to 750°F (-316°C to -399°C); pressures may be in the range of 6.9 MPag to 20.8 MPag (-1000 to -3000 psig), or 6.9 MPag to 13.9 MPag (-1000 psig to -2000 psig); liquid hourly space velocity (LHSV) of 0.1-10 hr-1 , or 0.1-5 hr -1 ; and hydrogen treatment gas rate of 430-2600 Nm 3 / m 3 (~2500 to ~15000 SCF / bbl), or 850-1700 Nm 3 / m 3 The hydroprocessing was carried out at (~5000 to ~10000 SCF / bbl).

[0123] The catalyst in the hydroprocessing stage can be a conventional hydroprocessing catalyst, such as a catalyst consisting of a Group VIB metal and / or a Group VIII metal on a support. Suitable metals include cobalt, nickel, molybdenum, tungsten, or a combination thereof. Preferred combinations of metals include nickel and molybdenum, or nickel, cobalt and molybdenum. Suitable supports include silicon oxide, silicon oxide-alumina, aluminum oxide, and titanium oxide.

[0124] Another hydroprocessing option is to expose the coker effluent fraction (or at least a portion thereof) to catalytic dewaxing conditions. Exposing the coker effluent fraction to catalytic dewaxing may be performed after hydrotreating the fraction in the hydroprocessing stage, or catalytic dewaxing may correspond to the first (and possibly only) type of hydroprocessing in the hydroprocessing stage. It should be noted that many types of dewaxing catalysts include precious metal catalysts. For such types of catalysts, hydrotreating before dewaxing may be beneficial for improving the activity and / or run time of the dewaxing catalyst. For dewaxing catalysts that include non-precious metals and / or are primarily based on cracking rather than isomerization, the dewaxing catalyst may be able to tolerate higher levels of sulfur and / or nitrogen while still providing dewaxing activity.

[0125] Process conditions in the catalytic dewaxing zone (in the presence of a dewaxing catalyst) may include a temperature of 200°C to 450°C, or 270°C to 400°C, a hydrogen partial pressure of 1.8 MPag to 34.6 MPag (250 psig to 5000 psig), or 4.8 MPag to 20.7 MPag, and a pressure of 35.6 m 3 / m 3 (200 SCF / B)-1781 m 3 / m 3 (10,000 scf / B), preferably 178 m 3 / m 3 (1,000SCF / B)-890.6 m 3 / m 3 (5,000 SCF / B) of hydrogen treatment gas rate. The liquid hourly space velocity (LHSV) can be 0.2 h -1 -10 h -1 , for example 0.5 h -1-5 h -1 and / or 1 h -1 -4 h -1 .

[0126] For coker effluent fractions that include higher boiling point components, another option may be to expose the effluent fractions (or at least a portion thereof) to a catalyst under hydrocracking conditions. During hydrocracking, the feedstock may be contacted with a hydrocracking catalyst under effective hydrocracking conditions, which may include a temperature of 550°F (288°C) to 840°F (449°C), a hydrogen partial pressure of 250 psig-5000 psig (1.8 MPag to 34.6 MPag), a 0.05 h -1 - 10h -1 The liquid hourly space velocity and 35.6 m 3 / m 3 -1781 m 3 / m 3 (200 SCF / B to 10,000 SCF / B) of hydrogen treat gas rate.

[0127] Yet another hydroprocessing option may be to expose the coker effluent fraction to the catalyst under aromatic saturation conditions / hydrofinishing conditions. Aromatic saturation conditions may include a temperature of 125°C to 425°C, preferably 180°C to 280°C, a hydrogen partial pressure of 500 psig (3.4 MPa) to 3000 psig (20.7 MPa), preferably 1500 psig (10.3 MPa) to 2500 psig (17.2 MPa) and a liquid hourly space velocity of 0.1 hr -1 -5 hr -1 LHSV, preferably 0.5 hr -1 Up to 2.0 hr -1 .

[0128] Additional embodiments

[0129] Embodiment 1. A method for co-processing a plastic feedstock, comprising: mixing a plastic feedstock with one or more additional feedstocks to form a feedstock mixture, the plastic feedstock comprising 25 wt% or less of at least one nitrogen-containing polymer relative to the weight of the plastic feedstock, the feedstock mixture comprising 0.5 wt% to 30 wt% of the plastic feedstock relative to the weight of the feedstock mixture; exposing at least a portion of the feedstock mixture to coking conditions to form a conversion effluent comprising one or more amides, one or more amines, or a combination thereof; separating the conversion effluent to form at least one liquid product fraction having a T10 distillation point of 300°C or less and a T90 distillation point of 170°C or more, the at least one liquid product fraction comprising a basic nitrogen content of 100 wppm or more relative to the weight of the at least one liquid product fraction; and exposing at least a portion of the at least one liquid product fraction to hydroprocessing conditions to form a hydroprocessed effluent comprising a jet fuel boiling range fraction, the jet fuel boiling range fraction having a total nitrogen content of 10 wppm or less relative to the weight of the jet fuel boiling range fraction, wherein the one or more amides, one or more amines, or a combination thereof optionally comprises caprolactam.

[0130] Embodiment 2. The method of Embodiment 1, wherein the basic nitrogen content of at least one liquid product fraction is 20 weight percent or more of the total nitrogen content of the at least one liquid product fraction.

[0131] Embodiment 3. The method of Embodiment 1, wherein the basic nitrogen content of the at least one liquid product fraction is 40 weight percent or more of the total nitrogen content of the at least one liquid product fraction.

[0132] Embodiment 4. The method of any of the above embodiments, wherein at least one liquid product fraction comprises a basic nitrogen content of 150 wppm or more.

[0133] Embodiment 5. The method of any of the above embodiments, wherein at least one liquid product fraction comprises a basic nitrogen content of 300 wppm or more.

[0134] Embodiment 6. The method of any of the above embodiments, wherein at least one liquid product fraction comprises a total nitrogen content of 700 wppm or more.

[0135] Embodiment 7. The method of any of the above embodiments, wherein separating the conversion effluent forms a plurality of liquid product fractions having a T10 distillation point of 300°C or less, a T90 distillation point of 170°C or more, or a combination thereof, and wherein exposing at least a portion of at least one liquid product fraction to hydroprocessing conditions comprises exposing at least a portion of the plurality of liquid product fractions to hydroprocessing conditions to form a plurality of hydroprocessed effluents comprising jet fuel boiling range fractions having 10 wppm or less basic nitrogen, wherein optionally each of the plurality of liquid product fractions comprises 100 wppm or more basic nitrogen.

[0136] Embodiment 8. The method of any of the above embodiments, further comprising separating the hydroprocessing effluent to form a jet fuel boiling range fraction and one or more additional hydroprocessing fractions having a T10 distillation point of 300° C. or higher.

[0137] Embodiment 9. The method of Embodiment 8, wherein separating the conversion effluent includes forming at least one additional liquid product fraction having a T10 distillation point of 300°C or greater, and wherein exposing at least a portion of the at least one liquid product fraction to hydroprocessing conditions also includes exposing at least a portion of the at least one additional liquid product fraction to hydroprocessing conditions.

[0138] Embodiment 10. The method of any of the above embodiments, wherein separating the conversion effluent includes forming at least one additional liquid product fraction having a T10 distillation point of 300°C or higher, the method further comprising: exposing the at least one additional liquid product fraction to a second hydroprocessing condition to form a second hydroprocessed effluent; and separating the second hydroprocessed effluent to form a second jet fuel boiling range fraction and at least one additional hydroprocessed fraction having a T10 distillation point of 300°C or higher.

[0139] Embodiment 11. The method of any of the above embodiments, wherein at least one of the one or more additional feedstocks has a T10 distillation point of 300°C or higher.

[0140] Embodiment 12. The method of any of the above embodiments, wherein the plastic raw material further comprises 5.0 wt% or less of at least one chlorine-containing polymer relative to the weight of the plastic raw material, the method further comprising: maintaining the raw material mixture in a container at a dechlorination temperature of 170°C to 300°C for 1.0 minute to 240 minutes to form a dechlorinated raw material mixture, wherein exposing at least a portion of the raw material mixture to coking conditions comprises exposing at least a portion of the dechlorinated raw material mixture to coking conditions.

[0141] Embodiment 13. The method of Embodiment 12, wherein the one or more additional feedstocks have a T10 distillation point above the dechlorination temperature; or wherein the dechlorinated feedstock mixture contains 1000 wppm or less Cl relative to the weight of the dechlorinated feedstock mixture; or a combination thereof.

[0142] Embodiment 14. The method of any of the above embodiments, wherein the hydroprocessing conditions comprise a severity index of 3 to 10.

[0143] Embodiment 15. A hydroprocessing effluent comprising a jet fuel boiling range fraction formed according to the method of any one of Embodiments 1 to 14.

[0144] Additional Embodiments A. The method of any of the above embodiments, wherein the plastic feedstock comprises plastic particles having an average diameter of 10 cm or less.

[0145] Additional Embodiment B. The method of any of the above embodiments, wherein the coking conditions comprise fluid coking conditions, delayed coking conditions, or a combination thereof.

[0146] When numerical lower limits and numerical upper limits are listed herein, the range from any lower limit to any upper limit is encompassed. Although the illustrative embodiments of the disclosure have been specifically described, it will be understood that various other modifications will be apparent to those skilled in the art and can be easily made without departing from the spirit and scope of the disclosure. Therefore, it is not intended that the scope of the appended claims be limited to the examples and descriptions set forth herein, but rather the claims should be interpreted as covering all features of patentable novelty present in the disclosure, including all features that would be considered equivalents by a technician in the field to which the disclosure belongs.

[0147] The disclosure has been described above with reference to a number of embodiments and specific examples. Based on the above detailed description, those skilled in the art will themselves think of many changes. All such obvious changes are within the full scope of the appended claims.

Claims

1. A method for co-processing plastic raw materials, comprising: mixing a plastic raw material with one or more additional raw materials to form a raw material mixture, the plastic raw material comprising 25% by weight or less of at least one nitrogen-containing polymer relative to the weight of the plastic raw material, the raw material mixture comprising 0.5% by weight to 30% by weight of the plastic raw material relative to the weight of the raw material mixture; exposing at least a portion of the feedstock mixture to coking conditions to form a conversion effluent comprising one or more amides, one or more amines, or a combination thereof; separating the conversion effluent to form at least one liquid product fraction having a T10 distillation point of 300° C. or less and a T90 distillation point of 170° C. or more, the at least one liquid product fraction comprising a basic nitrogen content of 100 wppm or more relative to the weight of the at least one liquid product fraction; and At least a portion of the at least one liquid product fraction is exposed to hydroprocessing conditions to form a hydroprocessed effluent comprising a jet fuel boiling range fraction having a total nitrogen content of 10 wppm or less relative to the weight of the jet fuel boiling range fraction.

2. The process according to claim 1, wherein the basic nitrogen content of the at least one liquid product fraction is 20% by weight or more of the total nitrogen content of the at least one liquid product fraction.

3. The process of claim 1, wherein the basic nitrogen content of the at least one liquid product fraction is 40 wt% or more of the total nitrogen content of the at least one liquid product fraction.

4. The process of claim 1, wherein at least one liquid product fraction comprises a basic nitrogen content of 150 wppm or more.

5. The process of claim 1, wherein at least one liquid product fraction comprises a basic nitrogen content of 300 wppm or more.

6. The process of claim 1, wherein at least one liquid product fraction comprises a total nitrogen content of 700 wppm or more.

7. The method of claim 1 , wherein separating the conversion effluent forms a plurality of liquid product fractions having a T10 distillation point of 300° C. or less, a T90 distillation point of 170° C. or greater, or a combination thereof, and wherein exposing at least a portion of at least one of the liquid product fractions to hydroprocessing conditions comprises exposing at least a portion of the plurality of liquid product fractions to hydroprocessing conditions to form a plurality of hydroprocessed effluents comprising a jet fuel boiling range fraction having 10 wppm or less basic nitrogen.

8. The process of claim 7, wherein each of the plurality of liquid product fractions comprises 100 wppm or more basic nitrogen.

9. The method of claim 1 further comprising separating the hydroprocessed effluent to form a jet fuel boiling range fraction and one or more additional hydroprocessed fractions having a T10 distillation point of 300°C or greater.

10. The process of claim 9, wherein separating the conversion effluent comprises forming at least one additional liquid product fraction having a T10 distillation point of 300°C or greater, and wherein exposing at least a portion of the at least one liquid product fraction to hydroprocessing conditions further comprises exposing at least a portion of the at least one additional liquid product fraction to hydroprocessing conditions.

11. The process of claim 1 , wherein separating the conversion effluent comprises forming at least one additional liquid product fraction having a T10 distillation point of 300° C. or greater, the process further comprising: exposing at least one additional liquid product fraction to second hydroprocessing conditions to form a second hydroprocessed effluent; and The second hydroprocessed effluent is separated to form a second jet fuel boiling range fraction and at least one additional hydroprocessed fraction having a T10 distillation point of 300°C or greater.

12. The process of claim 1, wherein at least one of the one or more additional feedstocks has a T10 distillation point of 300°C or greater.

13. The method according to claim 1, wherein the plastic raw material further comprises 5.0 wt% or less of at least one chlorine-containing polymer relative to the weight of the plastic raw material.

14. The method according to claim 13, further comprising: maintaining the raw material mixture in the container at a dechlorination temperature of 170° C. to 300° C. for 1.0 minute to 240 minutes to form a dechlorinated raw material mixture, Wherein exposing at least a portion of the feedstock mixture to coking conditions comprises exposing at least a portion of the dechlorinated feedstock mixture to coking conditions.

15. The process of claim 13, wherein the one or more additional feedstocks have a T10 distillation point above the dechlorination temperature.

16. The method of claim 13, wherein the dechlorinated feed mixture comprises 1000 wppm or less Cl relative to the weight of the dechlorinated feed mixture.

17. The method of claim 1, wherein the plastic raw material comprises plastic particles having an average diameter of 10 cm or less.

18. The method of claim 1, wherein the one or more amides comprises caprolactam.

19. The method of claim 1, wherein the coking conditions comprise fluid coking conditions, delayed coking conditions, or a combination thereof.

20. The method of claim 1, wherein the hydroprocessing conditions comprise a severity index of 3 to 10.

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