FOR JET FUEL PRODUCTION

CROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application claims the benefit of and priority to US Provisional Application No. 63/338,062 filed May 4, 2022, the disclosure of which is incorporated herein by reference.

FIELD

[0002] Systems and methods are provided for production of jet fuel from feeds derived at least in part from co-processing of plastic waste in a coking environment.

BACKGROUND

[0003] There is increasing interest in finding ways to recycle plastic waste so that the carbon from the underlying polymers can be recovered and incorporated into another cycle of products. This can include incorporation of plastic waste as part of the input flows for production of additional polymers, production of other products from chemical plants, and or for production of refinery products (such as fuels and/or lubricants).

[0004] One of the difficulties with incorporation of plastic waste as part of the input flows for a refinery is that plastic waste tends to correspond to a mixture of different types of plastic waste. Plastic waste can commonly include a variety of types of polymers, including polyolefins (e.g., low density polyethylene, high density polyethylene, polypropylene), polystyrene, nitrogen-containing polymers (such as nylon 6 and/or other polyamides), polyesters, polyethylene terephthalate, other oxygen-containing polymers, and chlorine- containing polymers (e g., polyvinyl chloride (PVC) or poly vinylidene chloride (PVDC)).

[0005] Another difficulty with incorporation of plastic waste into refinery processes is that refineries ty pically make an integrated slate of products. Introduction of plastic waste into one refinery process can often result in production of molecules that are incorporated across a variety of the products generated at the refinery. For example, the outputs from a delayed coker and/or fluidized coker can potentially be distributed across naphtha, kerosene (jet), diesel, lubricant, and/or fuel oil products in an integrated refinery setting. Thus, in order to introduce plastic waste into such a refinery, either a) the process train where the plastic waste is introduced needs to be isolated, or the feed and/or refinery processes need to be adapted so that the introduction of the plastic waste is compatible with all of the products that are generated as part of the refinery product slate. Having to isolate a portion of a refinery can incur substantial capital costs as well as potentially disrupting production of the full product slate at a refinery. Therefore, it would be desirable to identify systems and methods that can enable use of plastic waste as part of refinery input streams during integrated refinery processing.

[0006] International Publication WO2021/091724 describes co-processing of plastic waste in a fluidized coking environment or a delayed coking environment.

[0007] U.S. Patent Application Publication 2021/0087473 describes using delayed coking for co-processing of plastic waste with heavy oils. The plastic waste can include plastics that have been additized with metals. The additized metals can be concentrated in the coke produced during the delayed coking.

[0008] International Publication WO1995/014069 describes dissolution of waste plastic in an aromatic solvent prior to combining the dissolved plastic with a feed for a delayed coking process.

[0009] U.S. Patent 4,851,601 descnbes co-processing of plastic waste in a delayed coker followed by exposing the coker products to a second cracking stage where the coker products are exposed to zeolitic catalysts at elevated temperature.

[0010] Chinese Patent CN101230284 describes methods for coking of plastic waste. The plastic waste is pulverized to form small particles. The resulting particles are fluidized using a screw extrusion conveyor, followed by heating and extrusion 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 the coker furnace, optionally along with a co-feed.

[0011] U.S. Patent 9,920,255 describes methods for depolymerization of plastic material. The methods include melting and degassing a plastic feed to form molten plastic. A liquid crude fraction is then added to the molten plastic to reduce the viscosity prior to introducing the mixture of molten plastic and liquid crude into the pyrolysis reactor. It is noted that the plastic is melted and degassed prior to combining the plastic with any conventional co-feed, thus increasing the number of separate reactor vessels needed for integrating the plastic waste with a conventional co-feed.

[0012] U.S. Patent 6,861,568 describes a method for performing radical-initiated pyrolysis on plastic waste dissolved in an oil medium. After mixing the plastic waste with oil, the mixture is delivered to a pyrolysis vessel. The pyrolysis temperature is generally described as 300°C - 375°C, although an example is provided of partial reaction at 275°C. Based on the pyrolysis conditions, one of the two primary' products is a reactor overhead stream that includes a desired distillate product and a non-condensible overhead gas product. After condensing out the desired distillate product, the remaining overhead gas product can be treated with a water wash in an effort to remove any HC1 that may be present. Thus, HC1 removal is accomplished using a separate, additional water wash stage.

SUMMARY

[0013] In an 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 can contain 25 wt% or less of at least one nitrogencontaining polymer relative to a weight of the plastic feedstock. The feedstock mixture can contain 0.5 wt% to 30 wt% of the plastic feedstock relative to a weight of the feedstock mixture. The method further includes 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. The method further 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. The at least one liquid product fraction can have a basic nitrogen content of 100 wppm or more relative to a weight of the at least one liquid product fraction. Additionally, the method includes exposing at least a portion of the at least one liquid product fraction to hydroprocessing conditions to form a hydroprocessed effluent that contains a jet boiling range fraction having a total nitrogen content of 10 wppm or less relative to a weight of the jet boiling range fraction.

[0014] Optionally, the basic nitrogen content of the at least one liquid product fraction can correspond to 20 wt% or more of the total nitrogen content of the at least one liquid product fraction, or 40 wt% or more. Optionally, the at least one liquid product fraction can have a basic nitrogen content of 150 wppm or more, or 300 wppm or more, prior to the hydroprocessing.

BRIEF DESCRIPTION OF THE DRAWINGS

[0015] FIG. 1 shows an example of a process configuration for co-processing a combined feed in a coking stage.

[0016] FIG. 2 shows another example of a process configuration for co-processing a combined feed in a coking stage.

[0017] FIG. 3 shows an example of a fluidized coking stage configuration.

[0018] FIG. 4 shows another example of a fluidized coking stage configuration.

DETAILED DESCRIPTION

[0019] All numerical values within the detailed description and the claims herein are modified by “about” or “approximately” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art.

[0020] In various aspects, systems and methods are provided for co-processing plastic waste in a coker as part of an integrated refinery environment that produces kerosene, jet fuel, and/or jet fuel blending components as a product. The co-processing can be performed in a fluidized coker, a delayed coker, or a combination of fluidized cokers and delayed cokers. After coking, hydroprocessing can be performed on one or more portions of the coker effluent that contribute to formation of the kerosene, jet fuel, and/or jet fuel blending component product(s). The hydroprocessing can be used, for example, to reduce or minimize the presence of unexpected nitrogen contaminants in the resulting kerosene, j et fuel, and/or j et fuel blending component product(s).

[0021] Plastic waste generally corresponds to a mixture of multiple types of polymers. Some types of polymers, such as polyethylene, polypropylene, or polystyrene, correspond to hydrocarbons. As a result, to the degree that coking of such polymers forms liquid phase products, such liquid phase products also typically correspond to hydrocarbons.

[0022] Other types of polymers can include heteroatoms different from carbon and hydrogen as part of the monomers used for forming the polymer. As an example, polyvinyl chloride (PVC) and poly vinylidene chloride (PVDC) include one or more chlorines per repeat unit in the polymer. Such chlorine-containing polymers can potentially evolve chlorine compounds that may contaminate the eventual products and/or that can cause damage to the processing environment.

[0023] 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 nitrogencontaining products with boiling points in the kerosene / jet boiling range. For example, introducing a plastic feedstock including Nylon 6 into a coking environment can result in formation of caprolactam, which is a kerosene / jet boiling range amide. This can pose several difficulties. First, the presence of substantial amounts of amides in a kerosone / jet boiling range fraction is unexpected relative to the types of compounds present in kerosene / jet fuel / jet fuel blending component fractions derived from mineral feeds. Second, because decomposition of polyamides in a coking environment results in direct formation of kerosene / j et boiling range compounds that contain nitrogen (such as caprolactam), co-processing of a plastic feedstock in a coking environment can result in unexpectedly high total nitrogen contents in the kerosene / jet 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.

[0024] 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 fraction generated from the coking process. First, the type of plastic waste used for co-processing can be controlled in order to avoid excessive quantities of chlorine and/or nitrogen compounds in the coker effluent and/or in the kerosene / jet boiling range portions of the coker effluent. This can include limiting the amount of nitrogen-containing polymers and/or chlorine-containing polymers that are present in the plastic waste.

[0025] Optionally, a thermal dehalogenation stage can 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 that corresponds to a solution or slurry, the combined feed can exposed to a temperature of 150°C to 300°C in the presence of purge gas to remove chlorine from the combined feed.

[0026] In addition to selecting plastic waste with an appropriate composition for use as a co-feed, hydroprocessing can be used to reduce or minimize the nitrogen content (such as the amide content) of any kerosene / jet boiling range fractions that are formed from the coker effluent. Due to increased selectivity for formation of nitrogen compounds in the kerosene / jet boiling range, the presence of nitrogen-containing polymers in the combined feed can lead to unexpectedly high nitrogen contents in the kerosene / jet boiling range fraction. Additionally, other nitrogen-containing compounds may be present in other (higher boiling) portions of the coker effluent. Such compounds in other portions of the coker effluent can also be exposed to hydroprocessing conditions. To the degree that feed conversion occurs during hydroprocessing that results in additional formation of kerosene / jet boiling range components, such additional kerosene / jet boiling range components can be added to the total kerosene / jet boiling range product.

[0027] Coking can provide a flexible reaction system for co-processing of plastic waste. Even though the type of polymers in plastic waste can vary widely, coking can be performed to generate a liquid product slate. In aspects where Flexi coking™ is used for coking, synthesis gas can also be generated while reducing or minimizing net coke yield when co-processing a conventional coker feed with plastic waste. [0028] The co-processing of plastic waste in a coking environment (or other thermal conversion environment) can be performed by performing four types of processes on the plastic waste. First, the plastic waste can be conditioned by classifying and sizing of the plastic waste to improve the suitability of the plastic waste for co-processing. Second, the conditioned plastic waste particles can be entrained and/or dissolved into a solvent and/or the base feed. In aspects where a solvent is used, the solvent can preferably correspond to a refinery stream, such as a refinery stream formed by the co-processing of the plastic waste in the coking environment. Optionally, in aspects where the plastic waste feed is mixed with a solvent and/or base feed, a stripping gas can be added to remove HC1 or other gases that may evolve as the plastic waste is heated. Third, the solution and/or slurry of plastic waste can be passed into a coking environment, such as a fluidized coking environment or a delayed coking environment. The solution and/or slurry of plastic waste can be introduced as a separate stream, or the solution and/or slurry can be mixed with a conventional coker feedstock prior to entering the coking environment. Fourth, the plastic waste can then be co-processed in the coking environment to generate liquid products.

[0029] In some aspects, co-processing of plastic waste in a coking environment can provide advantages relative to coking of a conventional feed. Conventional coker feeds are often selected for coking based on having a relatively low molar ratio of hydrogen atoms to carbon atoms in the feed. In comparison with such a conventional coker feed, many types of plastic waste include a higher molar ratio of hydrogen atoms to carbon atoms. This additional hydrogen content in plastic waste can reduce the amount of coke that is formed in favor of increased production of liquid products.

[0030] In some aspects, a plastic waste feedstock can be co-processed with a coker feedstock in a fluidized coking environment, such as a Flexi coking™ coking environment. By sufficiently reducing or minimizing the particle size of the particles in a plastic waste feedstock, the plastic waste can be unexpectedly incorporated into a fluidized coking environment. Further additional benefits can be realized in a Flexicoking environment, where plastic waste can be co-processed while increasing the amount of production of synthesis gas.

Definitions

[0031] In this discussion, a reference to a “C _x ” fraction, stream, portion, feed, or other quantity is defined as a fraction (or other quantity) where 50 wt% or more of the fraction corresponds to hydrocarbons having “x” number of carbons. When a range is specified, such as “C _x - C _y ”, 50 wt% or more of the fraction corresponds to hy drocarbons having a number of carbons between “x” and “y”. A specification of “C _x +” (or “C _x .“) corresponds to a fraction where 50 wt% or more of the fraction corresponds to hydrocarbons having the specified number of carbons or more (or the specified number of carbons or less).

[0032] In this discussion, the naphtha boiling range is defined as roughly the boiling point of a C5 alkane (roughly 30°C) to 177°C. A 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 less. A 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 less. The kerosene or jet boiling range is defined as 125°C to 300°C. A kerosene or jet boiling range fraction is defined as a fraction having a T10 distillation point of 129°C or more and a T90 distillation point of 300°C or less. The distillate boiling range is defined as 177°C to 343°C. A 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 less. The gas oil boiling range is defined as 343°C to 566°C. A distillate boiling range fraction is defined as a fraction having a T10 distillation point of 343°C or higher and a T90 distillation point of 566°C or less. The vacuum resid boiling range corresponds to temperatures greater than 566°C. In this discussion, distillation points can be determined according to ASTM D86. In the event that ASTM D86 is unsuitable for characterization of a sample, ASTM 2887 may be used instead.

[0033] In some aspects, a fraction can be referred to as a jet / kerosene containing fraction. This can correspond to an input flow, an intermediate effluent or fraction, or an end product that includes a portion corresponding to the jet / kerosene boiling range. In this discussion, one way of identifying such a fraction can be based on the fraction having both a T90 distillation point of 129°C or more and a T10 distillation point of 300°C or less. In other words, the fraction can be “heavy” enough that at least a portion of the fraction boils above the naphtha range (T90 is greater than 129°C), and the fraction can be “light” enough that at least a portion of the fraction boils below the distillate range (T10 is less than 300°C). As an example, a light naphtha fraction can have a T10 of 30°C or more and a T90 of 120°C or less. Such a naphtha fraction would satisfy the requirement of having a T10 of less than 300°C, but would not satisfy the requirement of having a T90 of 129°C or more. As another example, a fraction containing both kerosene and distillate could have a T10 of 200°C and a T90 of 343°C. Such a fraction satisfies the definition of including jet or kerosene, as the T10 is less than 300°C, and the T90 is greater than 129°C.

[0034] 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 is noted that at some points during processing, a liquid product I portion may be present in a gaseous phase due to an increased temperature (and/or the combination of temperature and pressure) within the reaction system. Similarly, depending on the nature of the full configuration used, a vapor product / portion may be in a liquid phase due to the combination of temperature and pressure at a location within the reaction system.

[0035] In this discussion, total nitrogen in a sample can be measured according to ASTM D4629. In this discussion, the basic nitrogen content of a feed, fraction, or product can be determined according to the following method by performing measurements on two samples of the feed, fraction, or product. First, the total nitrogen of a sample is characterized according to ASTM D4629. Next, a sample can be acid washed by adding 1 ml of 1 N sulfuric acid to a 10 ml sample. This mixture can be formed in a suitable vessel, such as a 20 ml vial. The mixture of the sample and the sulfur acid is shaken vigorously, and then allowed to settle for 5 minutes. After settling, the sulfuric acid should be at the bottom of the vessel. The acid washed sample is removed from the top of the vessel, such as by using a pipette to remove the acid washed sample while not including any of the sulfuric acid. The acid washed sample can then be characterized according to ASTM D4629. The difference in nitrogen content between the untreated sample and the acid washed sample corresponds to the nitrogen that is removed by acid treatment. In this discussion, the nitrogen removed by acid treatment is defined as the basic nitrogen content. Amides and amines present in a sample correspond to basic nitrogen, so the presence of excess amides and amines in a sample due to decomposition of nitrogencontaining polymers will result in a corresponding increase in the basic nitrogen content of a sample.

Feedstocks

[0036] In some aspects, a plastic feedstock for co-processing can include or consist essentially of one or more types of polymers, such as polymers corresponding to plastic waste. The systems and methods described herein can be suitable for processing plastic waste corresponding to a single type of olefinic polymer and/or plastic waste corresponding to a plurality of olefinic polymers. In aspects where the plastic feedstock consists essentially of polymers, the feedstock can include one or more types of polymers as well as any additives, modifiers, packaging dyes, and/or other components typically added to a polymer during and/or after formulation. The feedstock can further include any components typically found in polymer waste.

[0037] In various aspects, the plastic feedstock can include one or more nitrogencontaining polymers. Examples of nitrogen-containing polymers include polyamides (such as Nylon 6), polyurethanes, and polynitriles. The nitrogen-containing polymers can correspond to 0.1 wt% to 25 wt% of the plastic feedstock (relative to the weight of the plastic feedstock), or 1.0 wt% to 25 wt%, or 5.0 1.0 wt% to 15 wt%, or 5.0 wt% to 15 wt%, or 1.0 wt% to 10 wt%.

[0038] In some aspects, the plastic feedstock can include one or more chlorine-containing polymers. Examples of chlorine-containing polymers including PVC (polyvinyl chloride) and PVDC (polyvinylidene chloride). In some aspects, the chlorine-containing polymers can correspond to as 0.001 wt% to 15 wt% of the plastic feedstock (relative to the weight of the plastic feedstock), or 0.1 wt% to 15 wt%, or 1.0 wt% to 15 wt%, or 0.001 wt% to 10 wt%, or 0.1 wt% to 10 wt%, or 1.0 wt% to 10 wt%, or 0.001 wt% to 5.0 wt%, or 0.001 wt% to 1.0 wt%. [0039] In some aspects, the polymer feedstock can include at least one of polyethylene and polypropylene. The polyethylene can correspond to any convenient type of polyethylene, such as high density or low density versions of polyethylene. Similarly, any convenient type of polypropylene can be used. Additionally or alternately, the plastic feedstock can include one or more of polystyrene, polyamide (e.g., nylon), polyethylene terephthalate, and ethylene vinyl acetate. Still other polyolefins can correspond to polymers (including co-polymers) of butadiene, isoprene, and isobuty lene. In some aspects, the polyethylene and polypropylene can be present in the mixture as a co-polymer of ethylene and propylene. More generally, the polyolefins can include co-polymers of various olefins, such as ethylene, propylene, butenes, hexenes, and/or any other olefins suitable for polymerization.

[0040] In this discussion, unless otherwise specified, weights of polymers in a feedstock correspond to weights relative to the total polymer content in the feedstock. Any additives and/or modifiers and/or other components included in a formulated polymer are included in this weight. However, the weight percentages described herein exclude any solvents or carriers that might optionally be used to facilitate transport of the polymer into the initial pyrolysis stage.

[0041] In some aspects, the plastic feedstock can include 0.01 wt% to 35 wt% of polystyrene, or 0.1 wt% to 35 v %, 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 aspects, the plastic feedstock can also include oxygen-containing polymers, such as polyterephthalates. It is noted that polyamides also contain oxygen as part of the polymer structure. In this discussion, a polymer that includes both oxygen and nitrogen as part of the repeat unit for forming the polymer is defined as a nitrogen-containing polymer for purposes of characterizing the plastic feedstock. [0042] A plastic feedstock can be combined with one or more additional feedstocks to form a combined feed for co-processing in a coking environment. In various aspects, the plastic feedstock can correspond to 0. 1 wt% to 30 wt% of the combined feed for coking (relative to a weight of the combined feed), or 0.1 wt% to 20 wt%, or 0.1 wt% to 10 wt%, or 0.1 wt% to 5.0 wt%, or 1.0 wt% to 30 wt%, or 1.0 wt% to 20 wt%, or 1.0 wt% to 10 wt%, or 1.0 wt% to 5.0 wt%, or 5.0 wt% to 30 wt%, or 5.0 wt% to 20 wt%. In some aspects, 50 wt% or more of the combined feed can correspond to feedstock with a boiling point of 343°C or higher.

[0043] It is noted that some types of plastic waste can also include bio-derived components. For example, some types of plastic labels can include biogenic waste in the form of paper compounds. In some aspects, 1.0 wt% to 25 wt% of the plastic feedstock can correspond to bio-derived material. Such bio-derived material can also potentially contribute to the nitrogen content of a plastic feedstock.

[0044] In some aspects, the coker feedstock for co-processing with the plastic waste feedstock can correspond to a relatively high boiling fraction, such as a heavy oil feed. For example, the coker feedstock portion of the feed can have a T10 distillation point of 343°C or more, or 371 °C or more. Examples of suitable heavy oils for inclusion in the coker feedstock include, but are not limited to, reduced petroleum crude; petroleum atmospheric distillation bottoms; petroleum vacuum distillation bottoms, or residuum; pitch; asphalt; bitumen; other heavy hydrocarbon residues; tar sand oil; shale oil; or even a coal slurry or coal liquefaction product such as coal liquefaction bottoms. Such feeds will ty pically have a Conradson Carbon Residue (ASTM D189-165) of at least 5 wt%, generally from 5 to 50 wt%. In some preferred aspects, the feed is a petroleum vacuum residuum.

[0045] Some examples of conventional petroleum chargestock suitable for processing in a delayed coker or fluidized bed coker can have a composition and properties within the ranges set forth below in Table 1.

Table 1: Example of Coker Feedstock [0046] In addition to petroleum chargestocks, renewable feedstocks derived from biomass having a suitable boiling range can also be used as part of the coker feed. Such renewable feedstocks include feedstocks with a T10 boiling point of 340°C or more and a T90 boiling point of 600°C or less. An example of a suitable renewable feedstock derived from biomass can be a pyrolysis oil feedstock derived at least in part from biomass.

[0047] In various aspects, the plastic waste can be prepared for introduction as a plastic feedstock for co-processing by using one or more physical processes to convert the plastic feedstock into particles and/or to reduce the particle size of the plastic particles.

[0048] For a plastic feedstock that is not initially in the form of particles, a first processing step can be a step to convert the plastic feedstock into particles and/or to reduce the particle size. This can be accomplished using any convenient type of physical processing, such as chopping, crushing, gnnding, shredding or another type of physical conversion of plastic solids into particles. It is noted that it may be desirable to convert plastic into particles of a first average and/or median size, followed by additional physical processing to reduce the size of the particles.

[0049] Having a small particle size can facilitate solvation of the plastic particles in the one or more additional feedstocks and/or distribution of plastic particles within a slurry of the one or more additional feedstocks in a desirable time frame. Thus, physical processing can optionally be 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 down to 0.01 cm or possibly still smaller. For determining a median particle size, the particle size is defined as the diameter of the smallest bounding sphere that contains the particle.

[0050] Optionally, an additional solvent can 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.

Intermediate Outputs and Products - Amide. Amine, and Nitrogen Content

[0051] As noted above, a plastic feedstock can include 0. 1 wt% to 25 wt% of nitrogencontaining polymers, relative to a weight of the plastic feedstock. For a typical nitrogencontaining polymer, such as a nylon or another type of polyamide, nitrogen atoms correspond to 5.0 wt% to 20 wt% of the weight of the nitrogen-containing polymer. Thus, the initial nitrogen content of the plastic feedstock can potentially range from 50 wppm to 50,000 wppm (5.0 wt%).

[0052] After exposure to a coking environment, it is believed that the nitrogen content from the plastic feedstock is not evenly distributed across the boiling range of the coker effluent. Instead, the jet / kerosene boiling range components of the coker effluent can have an unexpectedly high share of the nitrogen derived from the plastic feedstock. This can occur based on several mechanisms during coking.

[0053] First, for polymers such as Nylon 6, caprolactam is a common decomposition product during pyrolysis. When exposing Nylon 6 to coking conditions, roughly 5.0 wt% to 10 wt% of the coking products derived from Nylon 6 can correspond to caprolactam. Because caprolactam is a jet boiling range compound, the production of caprolactam results in a concentration of nitrogen from the plastic feedstock in the jet boiling range portion of the coker effluent. More generally, to the degree that larger chain fragments are formed during coking of a polyamide, such larger chain fragments will also correspond to amides.

[0054] Another mechanism for concentration of nitrogen in the jet / kerosene portion of the coker effluent can be based on the formation of terminal amines dunng coking. For example, coking of nylon 6,6 can result in high selectivity for formation of cyclopentanone. When cyclopentanone forms during coking, the cyclopentanone typically separates from a fragment in a manner that leaves behind a terminal primary amine. Such a terminal primary amine can then react with other amines to form liquid boiling range compounds, with a higher selectivity for naphtha and jet / kerosene boiling range compounds.

[0055] Based on the increased selectivity for formation of nitrogen-containing j et boiling range compounds from nitrogen-containing polymers in plastic feedstocks, co-processing under coking conditions can result in kerosene / jet boiling range coker effluent fractions with unexpectedly high nitrogen contents. In particular, the kerosene / jet boiling range coker effluent fractions can have unexpectedly high contents of amides, amines, or a combination thereof.

[0056] Conventionally, the total nitrogen content of a jet / kerosene boiling range coker effluent derived from a mineral feedstock can range from roughly 100 wppm to 500 wppm. Within this total nitrogen content, conventionally, the basic nitrogen can correspond to roughly 10% or less of the total nitrogen content. Thus, the amount of basic nitrogen expected in a conventional j et / kerosene boiling range fraction derived from a coker effluent is 10 wppm to 50 wppm.

[0057] When a plastic feedstock for co-processing includes nitrogen-containing polymers (such as polyamides), coking can result in 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 plastic feedstock including nitrogen-containing polymers can result in addition of 100 wppm to 500 wppm of amides and/or amines to the jet / kerosene boiling range portion of the coker effluent, or 100 wppm to 1000 wppm, or 100 wppm to 5000 wppm, or 300 wppm to 1000 wppm, or 300 wppm to 5000 wppm, or 800 wppm to 5000 wppm, or 1500 wppm to 5000 wppm. 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 I kerosene boiling range portion of the coker effluent can correspond to 20 wt% or more of the total nitrogen in the jet / kerosene boiling range portion of the coker effluent, or 30 wt% or more, or 40 wt% or more, or 50 wt% or more, or 75 wt% or more, such as up to 95 wt% or possibly still higher.

[0058] 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 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.

[0059] This unexpected increase in basic nitrogen due to increased amide and/or amine nitrogen can be removed by hydroprocessing. Due to the increase in nitrogen content, the severity of the hydroprocessing can be increased in order to achieve a target total nitrogen in the hydroprocessed jet / kerosene boiling range product. In various aspects, hydroprocessing can be used to reduce the total nitrogen in the jet / kerosene boiling range product to 50 wppm or less, or 10 wppm or less, such as down to substantially no total nitrogen content. Additionally or alternately, the basic nitrogen content of the jet I kerosene boiling range fraction can be reduced to 50 wppm or less, or 10 wppm or less, or 2.0 wppm or less, such as down to substantially no basic nitrogen content.

[0060] In some aspects, the increased severity of hydroprocessing conditions needed to remove the additional basic nitrogen present in a coker jet fraction formed from co-processing of plastic waste can be characterized based on a hydroprocessing severity index. The severity index is based on the weighted average bed temperature (WABT) for the hydroprocessing catalyst; the total pressure; and the liquid hourly space velocity (LHSV) of the feed relative to the volume of the catalyst. With regard to temperature, 1 is added to the severity index based for each 10°C greater than 310°C for the WABT. With regard to pressure, 1 is added to the severity index for each 200 psi greater than 800 psig for the total pressure (1 is added for each 1400 kPa greater than 5500 kPa-g). With regard to space velocity, 1 is added to the severity index for each 0.4 hr' ¹ lower than 2.0 hr' ¹ for the LHSV. [0061] Generally, a severity index of 3 to 10 (inclusive) can be used to remove the additional basic nitrogen present in a jet / kerosene boiling range fraction produced from coprocessing of plastic waste in a coker. As an example, a coker jet / kerosene boiling range fraction exposed to hydroprocessing conditions including a temperature of 335°C (+2 severity index), a pressure of 1100 psig / 7600 kPa-g (+1 severity index) and an LHSV of 1.5 hr (+1 severity index) corresponds to exposing the fraction to hydroprocessing conditions with a severity index of 4. This can be sufficient to remove the additional basic nitrogen generated in the jet / kerosene boiling range fraction derived from co-processing of plastic waste in a coking environment. By contrast, at hydroprocessing conditions of 325°C (+1 severity), a pressure of 800 psig / 5500 kPa-g (+0 severity), and 1.5 hr ⁴ (+1 severity), the severity index is only 2, and therefore the conditions would have insufficient severity for removal of the additional basic nitrogen to a target level. It is noted that severity index values greater than 10 are effective for removal of nitrogen, but are generally undesirable due to excess cracking of the fraction, resulting in a loss of product yield.

Intermediate Outputs and Products - Other Properties

[0062] In addition to nitrogen content, a kerosene / jet boiling range product fraction can be characterized in other manners. In some aspects, a kerosene / jet boiling range product fraction can have a cetane index of 25 - 45, or 30 - 45, or 35 - 45, or 45 - 55. Further additionally or alternately, in some aspects a jet boiling range product fraction can 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 down to 0. 1 wppm or possibly still lower. Yet further additionally or alternately, a jet boiling range product fraction can have a weight ratio of aliphatic sulfur to total sulfur of 0.05 or more, or 0.1 or more, such as up to 0.7 or possibly still higher, thus corresponding to a jet boiling range product fraction that includes a substantial portion of a non-hydroprocessed mineral fraction; or a jet boiling range product fraction can have a weight ratio of aliphatic sulfur to total sulfur of 0.02 or less, such as down to including substantially no aliphatic sulfur, thus corresponding to a jet boiling range product fraction that includes a substantial portion of a hydrotreated mineral fraction.

[0063] Still other properties of a jet boiling range product fraction can include a cloud point of -40°C or lower, such as down to -60°C; a pour point of -40°C or lower, such as down to -60°C; freeze point of -40°C or lower, or -47°C or lower (such as down to -60°C or possibly still lower); and a smoke point of 22 mm or more.

[0064] Yet other properties of a jet boiling range product fraction can include a total acidity of 0.1 mg KOH/g or less, or 0.015 mg KOH/g or less, a sulfur content of 3000 wppm or less, a freezing point maximum of -40°C or -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 deposit thickness on the surface of a heater tube and/or a maximum pressure increase during a thermal stability test at 260°C (according to ASTM D3241), such as a maximum deposit thickness of 85 nm and/or a maximum pressure increase of 25 mm Hg. Still another example of a property specification can be a water separation rating, such as a water separation rating of 85 or more, as measured according to ASTM D3948. A water separation rating provides an indication of the amount of surfactant present in a jet fuel boiling range sample. Petroleum fractions that have an appropriate boiling range and that also satisfy the various requirements for a commercial standard can be tested (such as 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 satisfies the specification for a jet fuel under ASTM DI 655. This can include a thermal stability breakpoint of 260°C or more, or 275°C or more, as defined by ASTM D3241.

Optional Dechlorination of Combined Feed

[0065] In various aspects, a combined feed for co-processing can be formed by mixing a plastic feedstock with one or more additional feedstocks in a mixing vessel to form a feedstock mixture. This will typically result in formation of a solution of the plastic feedstock in the one or more additional feedstocks, but it is also possible that a slurry of plastic particles in the one or more additional feedstocks may be formed. In some aspects, the feedstock mixture can then be passed into a coking reactor, optionally after mixing the feedstock to improve the uniformity of the mixture. Additionally or alternately, if it is desired to form a dechlorinated (or more generally dehalogenated) combined feed, the combined feed can be maintained at a dechlorination temperature to allow for dechlorination of the combined feed prior to performing the co-processing.

[0066] After combining the plastic feedstock and the one or more additional feedstocks, the resulting combined feed can be mixed, such as in a mixing vessel. After mixing, the combined feed can optionally be maintained at a dechlorination temperature of 170°C to 350°C, or 170°C to 300°C, or 170°C to 250°C. The feedstock mixture can be maintained at the dechlorination temperature for a sufficient period of time to allow for dechlorination. Depending on the aspect, the feedstock mixture can be maintained at the dechlorination temperature for 1.0 minute to 240 minutes, or 1.0 minute to 120 minutes, or 1.0 minute 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 minute to 30 minutes. It is noted that in a continuous or semi-continuous process, the average residence time for the feedstock mixture in the mixing vessel is defined herein as the amount of time that the feedstock mixture is maintained at the dechlorination temperature prior to leaving the vessel as part of the dechlorinated mixture of feedstocks. It is noted that the plastic feedstock and the one or more additional feedstocks can be initially mixed at the dechlorination temperature, or the mixing temperature for mixing the feedstocks can be different from the dechlorination temperature. If the mixing temperature is different from the dechlorination temperature, the feedstock mixture can be heated to the dechlorination temperature and maintained at the dechlorination temperature for the desired period of time. Although it would be possible to mix the feedstocks at a temperature greater than the dechlorination temperature, this is generally less preferable, as if the mixing temperature is greater than 250°C, additional undesired conversion of the one or more additional feedstocks could potentially occur in the time period between when mixing first occurs and when the feedstock mixture is cooled to the dechlorination temperature.

[0067] In some aspects, the feedstock mixture can be maintained at the dechlorination temperature for a sufficient period of time so that the resulting dechlorinated mixture of feedstocks is substantially dechlorinated. In this discussion, a substantially dechlorinated feed is defined as a feed that includes 0.005 wt% or less of chlorine (relative to the weight of the dechlorinated feed), as determined by elemental analysis, such as down to having no chlorine content within detection limit. For example, the total chlorides in a sample can be measured using combustion ion chromatography according to ASTM D7359. In other aspects, the feedstock mixture can be maintained at the dechlorination temperature until the dechlorinated mixture contains 2500 wppm or less of chlorine, or 1000 wppm or less of chlorine, or 500 wppm or less of chlorine, or 100 wppm or less of chlorine, such as down to having substantially no chlorine content within detection limit. In still other aspects, the amount of chlorine remaining in the dechlorinated mixture of feedstocks can correspond to 20 wt% or less of the original weight of chlorine in the feedstock mixture, or 10 wt% or less, or 5.0 wt% or less, or 1.0 wt% or less, such as down to 0.01 wt% of the original weight of chlorine in the feedstock mixture, or possibly still lower.

[0068] During and/or after mixing, a purge gas can be passed through the feedstock mixture to remove HC1 that is formed while maintaining the feedstock mixture at the temperature between 170°C to 350°C (or 170°C to 300°C, or 170°C to 250°C). The purge gas and HC1 can exit from the mixing vessel as a purge exhaust stream. Preferably, the purge gas can be passed into the same vessel that is used for maintaining the feedstock mixture at the dechlorination temperature. In some alternative aspects, the feedstocks can be mixed and/or maintained at the dechlonnation temperature in one or more vessels, and then passed into a separate vessel or conduit where the purge gas is used to remove the HC1. It is noted that the thermal dechlorination process can also remove other halogens (in the form of HBr, HI, or HF), if other types of halogen-containing polymers are present in the plastic feedstock. In aspects where other types of halogen-containing polymers are present, the total content of halogencontaining polymers in the plastic feedstock can correspond to the values provided above for chlorine-containing polymers in the plastic feedstock.

[0069] The purge gas can correspond to a sufficient amount of purge gas to remove HC1 as it evolves during the dechlorination process. Additionally or alternately, the purge gas can assist with mixing of the plastic feedstock and the one or more additional feedstocks in the vessel, which can facilitate complete dissolution of the plastic feedstock. Examples of suitable rates of purge gas flow can range from 10,000 standard cubic feet of purge gas per metric ton of chlorinated polymer to 2,000,000 standard cubic feet of purge gas per metric ton of chlorinated polymer. This can alternatively be written as 10 - 2000 kSCF purge gas / metric ton chlorinated polymer. Any convenient gas can be used as the purge gas. To minimize cost, a gas such as nitrogen or steam can be a suitable choice. Other purge gas choices can correspond to light refinery or process gas flows, such as alight ends stream (i.e., a C4- stream) from a refinery process. Preferably, the purge gas can include a reduced or minimized amount of contaminants, such as NH3 or H2S, or can be substantially free of such contaminants. The purge gas can then leave the mixing vessel (and/or other separate vessel) as a purge exhaust stream that includes at least purge gas and HC1 generated during dechlorination. After dechlorination, the remaining liquid product in the mixing vessel can leave a dechlorinated mixture of feedstocks that is then passed into a co-processing stage.

[0070] In some aspects, the temperature in the mixing vessel can be selected so that a reduced or minimized amount of formation occurs of volatile (organic) products different from HC1. In the mixing vessel, volatile organic compounds can correspond to compounds (such as light gases and/or naphtha boiling range compounds) that have a boiling point below the dechlorination temperature (i.e., lower than 170°C - 250°C). In particular, the amount of light gases and/or naphtha boiling range compounds formed in the mixing vessel during dechlorination that boil at less than the dechlorination temperature can be reduced or minimized. In some aspects, conversion of the one or more additional feedstocks in the mixing vessel can be sufficiently low so that 5.0 wt% or less of organic compounds are formed that boil at temperatures lower than the dechlorination temperature (relative to a weight of the feedstock mixture), or 3.0 wt% or less, or 1.0 wt% or less, such as down to forming substantially no organic compounds that boil at a temperature lower than the dechlorination temperature Reducing or minimizing the formation of volatile organic compounds is beneficial because any volatile organic species formed in the mixing vessel will have a tendency to by removed from the mixing vessel by the purge gas as part of the purge exhaust stream, along with the HC1. This means that recovery of such organic compounds as products requires decontamination of the purge exhaust from the mixing vessel. In aspects where a separate vessel or conduit is used for exposing the feedstock mixture to the purge gas, the temperature of the mixture in the separate vessel or conduit can also be maintained at a temperature of 170°C to 250°C to reduce or minimize formation of volatile organic products that would also be removed by the purge gas as part of the purge exhaust.

[0071] In some alternative aspects, if it is desired to recover organic compounds from the purge exhaust, it is noted that contaminant removal can be performed on the purge exhaust stream in order to recover the volatile organic products. The optional contaminant removal on the purge exhaust stream can be performed by any convenient method. For example, a conventional amine wash (amine dissolved in water) can be used to remove the HC1 from the purge exhaust stream.

[0072] When performing a thermal dehalogenation process, another option can be to also include a source of calcium and/or another source of metal / material with basic properties in the thermal dechlorination environment. For example, various types of calcium additives can be included in a thermal dechlorination environment, including (but not limited to) Ca(OH)2, CaO, and/or CaCOs. During thermal dehalogenation of a plastic feedstock, chlorine that evolves from thermal decomposition of a polymer can typically evolve in the form of HC1. The presence of a calcium additive can be beneficial during thermal dehalogenation by allowing at least a portion of the HC1 to be converted into CaCh. The stoichiometry of the additional product(s) formed can depend on the nature of the calcium additive. CaCh formed in the thermal dehalogenation environment is a solid that has a relatively low solubility in heavy crude oil fractions. By forming CaCh, potentially highly corrosive HC1 can be converted into a solid compound with low or minimal potential for causing corrosion of surfaces in the reaction environment. The CaCh formed in a thermal dehalogenation environment can be removed by any convenient method, such as settling, centrifugation, and/or filtration. It is noted that some sodium compounds, such as NaCCh, can also be used as reagent additives in a thermal dehalogenation environment to facilitate removal of resulting chlorine-containing compounds from the reaction environment. More generally, various types of metals I materials with basic properties that allow for formation of a solid halide compound can be used to facilitate removal of halogens that are evolved as hydrogen halides in the thermal dehalogenation environment.

[0073] It is noted that including a calcium additive and/or other basic additive in the thermal dehalogenation environment can reduce or minimize the need for using a purge gas in the thermal dehalogenation environment. For example, while both a purge gas and a calcium additive can be used, the addition of a calcium additive results in substantial conversion of HC1 formed during thermal dehalogenation into a solid dehalogenation product. Such a solid dehalogenation product can be filtered or otherwise physically separated from the remainder of the feedstock. The gas phase products formed in place of HC1 can correspond to compounds such as CO2 and/or H2O. While CO2 and/or H2O can be removed from the environment using a purge gas, there are a variety of other options for handling such products. Similar exchange of hydrogen halides gas phase products for CO2 and/or H2O can also be achieved using other types of basic materials and/or for other hydrogen halides.

[0074] 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 with reducing or minimizing the amount of volatile organic products that exit from the mixing vessel as part of the purge gas. In such aspects, the pressure in the mixing vessel during the dechlorination process can be 150 kPa-a to 1000 kPa-a.

Examples of Co-Processing Configurations

[0075] FIG. 1 shows an example of a configuration for co-processing plastic feedstock in a coking environment. In the example configuration shown in FIG. 1, all of the portions of the coker effluent that contribute to formation of a kerosene / jet boiling range product are passed through the same hydroprocessing stage(s).

[0076] In FIG. 1, a plastic feedstock 101 and one or more additional feedstocks 105 are combined in a vessel 110 to form a combined feed. Vessel 110 can optionally correspond to a mixing vessel, or mixing can be perfonned at another location. In FIG. 1, an optional purge gas 112 flow is shown as being introduced into vessel 110. If thermal dechlorination (or more generally thermal dehalogenation) is performed on the combined feed, purge gas 112 can be used to sweep out hydrogen chlorides (and/or other hy drogen halides) into purge gas exhaust 118. FIG. 1 shows the thermal dechlorination being performed in vessel 110, but in other aspects a one or more other vessels could be used. [0077] The combined feed 115 (optionally thermally dechlorinated) can then be passed into coking stage 120. Coking stage 120 can correspond to include a delayed coker, a fluidized coker, or a combination thereof. In FIG. 1, coking stage 120 also includes one or more separators for separating the coker effluent into a desired number of effluent fractions. In the example shown in FIG. 1, the coker effluent can be separated to form a coker light gas product 121, coker naphtha 123, tight coker gas oil 125, and heavy coker gas oil 127. A coke product 129 is also shown, although it is understood that the coke product in a coker is typically withdrawn from a coker separately from the coker effluent.

[0078] One or more of the effluent fractions can then be passed into a hydroprocessing stage 130. In the example shown in FIG. 1, coker naphtha 123, tight coker gas oil 125, and heavy coker gas oil 127 are all passed into the hydroprocessing stage 130. In other aspects, one or more of the effluent fractions could instead be sent to other process trains. For example, one option can be to pass coker naphtha 123 and light coker gas oil 125 into hydroprocessing stage 130, while heavy coker naphtha 127 is used for another purpose. As another example, coker naphtha 123 and heavy coker gas oil 127 can be passed into hydroprocessing stage 130, while using tight coker gas oil 125 for another purpose. Additionally or alternately, in some aspects only a portion of one or more of the effluent fractions can be passed into hydroprocessing stage 130, while other portions of a given effluent fraction may be used for other purposes.

[0079] After hydroprocessing 130, the hydroprocessed effluent 135 can be separated using one or more separation stages 140 to form at least a kerosene / jet boiling range fraction and one or more other fractions. In the example shown in FIG. 1 , separation stages 140 produce light ends 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 can be omitted. For example, diesel or distillate product 147 and heavier product 149 could correspond to a single product in some configurations.

[0080] FIG. 2 shows another example of a configuration for production of a j et / kerosene boiling range fraction. In FIG. 2, different fractions of the coker effluent are passed into different hydroprocessing stages. This can allow, for example, higher boiling portions of the coker effluent to be hydroprocessed under higher severity conditions. When a higher boiling fraction is processed separately, it is possible that the higher boiling fraction may contain substantially no kerosene / jet boiling range compounds prior to hydroprocessing. The hydroprocessed effluent, however, can contain kerosene / jet boiling range components due to conversion of the higher boiling fraction under the hydroprocessing conditions.

[0081] In FIG. 2, a plastic feedstock 201 and one or more additional feedstocks 205 are combined in a vessel 210 to form a combined feed. Vessel 210 can optionally correspond to a mixing vessel, or mixing can be performed at another location. In FIG. 2, an optional purge gas 212 flow is shown as being introduced into vessel 210. If thermal dechlorination (or more generally thermal dehalogenation) is performed on the combined feed, purge gas 212 can be used to sweep out hydrogen chlorides (and/or other hydrogen halides) into purge gas exhaust 218. FIG. 1 shows the thermal dechlorination being performed in vessel 210, but in other aspects a one or more other vessels could be used.

[0082] The combined feed 215 (optionally thermally dechlorinated) can then be passed into coking stage 220. Coking stage 220 can correspond to include a delayed coker, a fluidized coker, or a combination thereof. In FIG. 2, coking stage 220 also includes one or more separators for separating the coker effluent into a desired number of effluent fractions. In the example shown in FIG. 2, the coker effluent can be separated to form a coker light gas product 221, coker naphtha 223, light coker gas oil 225, and heavy coker gas oil 227. A coke product 229 is also shown, although it is understood that the coke product in a coker is typically withdrawn from a coker separately from the coker effluent.

[0083] In FIG. 2, the liquid effluent fractions (coker naphtha 223, light coker gas oil 225, heavy coker gas oil 227) are then passed into a plurality of hydroprocessing stages in parallel. In the example shown in FIG. 2, coker naphtha 223 is passed into hydroprocessing stage 250; light coker gas oil 225 is passed into hydroprocessing stage 260; and heavy coker gas oil 227 is passed into hydroprocessing stage 270. It is understood that any convenient number of coker effluent fractions could be formed and passed into separate hydroprocessing stages. Similarly, more than one coker effluent fraction can be passed into a single hydroprocessing stage. Still another option can be to use at least a portion of one or more of the coker effluent fractions for a different purpose. Hydroprocessing stages 250, 260, and 270 can each separately correspond to one or more types of hydroprocessing, if desired. The hydroprocessing stages 250, 260, and 270 also include separators for separation of hydroprocessed effluents into product fractions.

[0084] In the configuration shown in FIG. 2, hydroprocessing stage 270 generates at least one fraction 272 containing kerosene / jet boiling range components and one or more products 275. Hydroprocessing stage 260 generates at least one fraction 262 containing kerosene / jet boiling range components and one or more products 265. The fractions 262 and 272 can then be passed into hydroprocessing stage 250, so that the jet / kerosene boiling range components from fractions 262 and 272 can be combined into the kerosene / jet fraction 255 from hydroprocessing stage 250. Fractions 262 and 272 can be passed into hydroprocessing stage 250 pnor to the hydroprocessing reactor(s) and/or pnor to the one or more separators for separating the hydroprocessing effluent. Hydroprocessing stage 250 can also form one or more lower boiling fractions 251, such as a naphtha fraction and/or a light ends fraction. Although not explicitly shown, one or more heavier fractions could also be generated, depending on the nature of the input flow(s) to hydroprocessing stage 250.

Conditions for Co-Processing - Fluidized Coking and Delayed Coking

[0085] In various aspects, co-processing can be performed by exposing the (optionally thermally dechlorinated) combined feed of plastic feedstock and additional feedstocks to coking conditions.

[0086] Coking processes in modern refinery setings can typically be categorized as delayed coking or fluidized bed coking. Fluidized bed coking is a petroleum refining process in which heavy petroleum feeds, typically the non-distillable residues (resids) from the fractionation of heavy oils are converted to 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 from 500°C to 550°C (~ 930°F to 1020°F). Heavy oils which may be processed by the fluid coking process include heavy atmospheric resids, petroleum vacuum distillation bottoms, aromatic extracts, asphalts, and bitumens from tar sands, tar pits and pitch lakes of Canada (Athabasca, Alta.), Trinidad, Southern California (La Brea (Los Angeles), McKittrick (Bakersfield, Calif.), Carpinteria (Santa Barbara County, Calif), Lake Bermudez (Venezuela) and similar deposits such as those found in Texas, Peru, Iran, Russia and Poland. Such feeds can be co-processed with biomass oil. The biomass oil and conventional feed can be introduced separately, or the biomass oil and conventional feed can be mixed prior to introduction into the coking environment. The biomass oil and/or conventional feed can be introduced into the coking environment in a conventional manner.

[0087] The Flexicoking™ process, developed by Exxon Research and Engineering Company, is a variant of the fluid coking process that is operated in a unit including a reactor and a heater, but also including a gasifier for gasifying the coke product by reaction with an air/steam mixture to form a low heating value fuel gas. A stream of coke passes from the heater to the gasifier where all but a small fraction of the coke is gasified to a low-BTU gas (~120 BTU/standard cubic feet) by the addition of steam and air in a fluidized bed in an oxy gendeficient environment to form fuel gas comprising carbon monoxide and hydrogen. In a conventional Flexicoking™ 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 with the balance of the reactor heat requirement supplied by combustion in the heater. A small amount of net coke (about 1 percent of feed) is withdrawn from the heater to purge the system of metals and ash. The liquid yield and properties are comparable to those from fluid coking. The fuel gas product is withdrawn from the heater following separation in internal cyclones which return coke particles through their diplegs.

[0088] In this description, the term “Flexicoking” (trademark of ExxonMobil Research and Engineering Company) is used to designate a fluid coking process in which heavy petroleum feeds are subjected to thermal cracking in a fluidized bed of heated solid particles to produce hydrocarbons of lower molecular weight and boiling point along with coke as a byproduct which is deposited on the solid particles in the fluidized bed. The resulting coke can then converted to a fuel gas by contact at elevated temperature with steam and an oxygencontaining gas in a gasification reactor (gasifier). This type of configuration can more generally be referred to as an integration of fluidized bed coking with gasification. FIGS. 3 and 4 provide examples of fluidized coking reactors that include a gasifier.

[0089] FIG. 3 shows an example of a Flexicoker unit (i.e., a system including a gasifier that is thermally integrated with a fluidized bed coker) with three reaction vessels: reactor, heater and gasifier. The unit comprises reactor section 10 with the coking zone and its associated stripping and scrubbing sections (not separately indicated), heater section 11 and gasifier section 12. The relationship of the coking zone, scrubbing zone and stripping zone in the reactor section is shown, for example, in U.S. Pat. No. 5,472,596, to which reference is made for a description of the Flexicoking unit and its reactor section. A heavy oil feed is introduced into the unit by line 13 and cracked hydrocarbon product withdrawn through line 14. Fluidizing and stripping steam is supplied by line 15. Cold coke is taken out from the stripping section at the base of reactor 10 by means of line 16 and passed to heater 11. The term “cold” as applied to the temperature of the withdrawn coke is, of course, decidedly relative since it is well above ambient at the operating temperature of the stripping section. Hot coke is circulated from heater 11 to reactor 10 through line 17. Coke from heater 11 is transferred to gasifier 12 through line 21 and hot, partly gasified particles of coke are circulated from the gasifier back to the heater through line 22. The excess coke is withdrawn from the heater 11 by way of line 23. In conventional configurations, gasifier 12 is provided with its supply of steam and air by line 24 and hot fuel gas is taken from the gasifier to the heater though line 25. In some alternative aspects, instead of supplying air via a line 24 to the gasifier 12, a stream of oxygen with 95 vol% purity or more can be provided, such as an oxygen stream from an air separation unit. In such aspects, in addition to supplying a stream of oxygen, a stream of an additional diluent gas can be supplied by line 31. The additional diluent gas can correspond to, for example, CO2 separated from the fuel gas generated during the gasification. The fuel gas is taken out from the unit through line 26 on the heater; coke fines are removed from the fuel gas in heater cyclone system 27 comprising serially connected primary and secondary cyclones with diplegs which return the separated fines to the fluid bed in the heater. The fuel gas from line 26 can then undergo further processing. For example, in some aspects, the fuel gas from line 26 can be passed into a separation stage for separation of CO2 (and/or H2S). This can result in a stream with an increased concentration of synthesis gas, which can then be passed into a conversion stage for conversion of synthesis gas to methanol.

[0090] It is noted that in some optional aspects, heater cyclone system 27 can be located in a separate vessel (not shown) rather than in heater 11. In such aspects, line 26 can withdraw the fuel gas from the separate vessel, and the line 23 for purging excess coke can correspond to a line transporting coke fines away from the separate vessel. These coke fines and/or other partially gasified coke particles that are vented from the heater (or the gasifier) can have an increased content of metals relative to the feedstock. For example, the weight percentage of metals in the coke particles vented from the system (relative to the weight of the vented particles) can be greater than the weight percent of metals in the feedstock (relative to the weight of the feedstock). In other words, the metals from the feedstock are concentrated in the vented coke particles. Since the gasifier conditions do not create slag, the vented coke particles correspond to the mechanism for removal of metals from the coker / gasifier environment. In some aspects, the metals can correspond to a combination of nickel, vanadium, and/or iron. Additionally or alternately, the gasifier conditions can cause substantially no deposition of metal oxides on the interior walls of the gasifier, such as deposition of less than 0. 1 wt% of the metals present in the feedstock introduced into the coker / gasifier system, or less than 0.01 wt%.

[0091] In configurations such as FIG. 3, the system elements shown in the figure can be characterized based on fluid communication between the elements. For example, reactor section 10 is in direct fluid communication with heater 11. Reactor section 10 is also in indirect fluid communication with gasifier 12 via heater 11.

[0092] As an alternative, integration of a fluidized bed coker with a gasifier can also be accomplished without the use of an intermediate heater. In such alternative aspects, the cold coke from the reactor can be transferred directly to the gasifier. This transfer, in almost all cases, will be unequivocally direct with one end of the tubular transfer line connected to the coke outlet of the reactor and its other end connected to the coke inlet of the gasifier with no intervening reaction vessel, i.e., heater. The presence of devices other than the heater is not however to be excluded, e.g., inlets for lift gas etc. Similarly, while the hot, partly gasified coke particles from the gasifier are returned directly from the gasifier to the reactor this signifies only that there is to be no intervening heater as in the conventional three-vessel Flexicoker™ but that other devices may be present between the gasifier and the reactor, e.g., gas lift inlets and outlets.

[0093] FIG. 4 shows an example of integration of a fluidized bed coker with a gasifier but without a separate heater vessel. In the configuration shown in FIG. 4, the cyclones for separating fuel gas from catalyst fines are located in a separate vessel. In other aspects, the cyclones can be included in gasifier vessel 41.

[0094] In the configuration shown in FIG. 4, the configuration includes a reactor 40, a main gasifier vessel 41 and a separator 42. The heavy oil feed is introduced into reactor 40 through line 43 and fluidizing/ stripping gas through line 44; cracked hydrocarbon products are taken out through line 45. Cold, stripped coke is routed directly from reactor 40 to gasifier 41 by way of line 46 and hot coke returned to the reactor in line 47. Steam and oxygen are supplied through line 48. The flow' of gas containing coke fines is routed to separator vessel 42 through line 49 which is connected to a gas outlet of the main gasifier vessel 41. The fines are separated from the gas flow in cyclone system 50 comprising serially connected primary and secondary cyclones with diplegs which return the separated fines to the separator vessel. The separated fines are then returned to the main gasifier vessel through return line 51 and the fuel gas product taken out by way of line 52. Coke is purged from the separator through line 53. The fuel gas from line 52 can then undergo further processing for separation of CO2 (and/or H2S) and conversion of synthesis gas to methanol.

[0095] The coker and gasifier can be operated according to the parameters necessary for the required coking processes. Thus, the heavy oil feed will typically be a heavy (high boiling) reduced petroleum crude; petroleum atmospheric distillation bottoms; petroleum vacuum distillation bottoms, or residuum; pitch; asphalt; bitumen; other heavy hydrocarbon residues; tar sand oil; shale oil; or even a coal slurry or coal liquefaction product such as coal liquefaction botoms. Such feeds will typically have a Conradson Carbon Residue (ASTM DI 89-165) of at least 5 wt%, generally from 5 wt% to 50 wt%. Preferably, the feed is a petroleum vacuum residuum.

[0096] Fluidized coking is carried out in a unit with a large reactor containing hot coke particles which are maintained in the fluidized condition at the required reaction temperature with steam injected at the bottom of the vessel with the average direction of movement of the coke particles being downwards 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 multiple feed nozzles arranged at several successive levels in the reactor. Steam is injected into a stripping section at the bottom of the reactor and passes upwards through the coke particles descending through the dense phase of the fluid 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 layers of solid coke and lighter products which evolve as gas or vaporized liquid. The residence time of the feed in the coking zone (where temperatures are suitable for thermal cracking) is on the order of 1 to 30 seconds. Reactor pressure is relatively low in order to favor vaporization of the hydrocarbon vapors which pass upwards from dense phase into dilute phase of the fluid bed in the coking zone and into cyclones 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 by gravity through the cyclone diplegs. The mixture of steam and hydrocarbon vapors from the reactor is subsequently discharged from the cyclone gas outlets into 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 over sheds. A pump-around loop circulates condensed liquid to an external cooler and back to the top shed row of the scrubber section to provide cooling for the quench and condensation of the heaviest fraction of the liquid product. This heavy fraction is typically recycled to extinction by feeding back to the coking zone in the reactor.

[0097] During a fluidized coking process, the heavy oil feed, pre-heated to a temperature at which it is flowable and pumpable, is introduced into the coking reactor towards the top of the reactor vessel through injection nozzles which are constructed to produce a spray of the feed into the bed of fluidized coke particles in the vessel. Temperatures in the coking zone of the reactor are typically in the range of 450°C to 650°C and pressures are kept at a relatively low level, typically in the range of 0 kPag to 700 kPag (~ 0 psig to 100 psig), and most usually from 35 kPag to 320 kPag (~ 5 psig to 45 psig), in order to facilitate fast drying of the coke particles, preventing the formation of sticky, adherent high molecular weight hydrocarbon deposits on the particles which could lead to reactor fouling. In some aspects, the temperature in the coking zone can be 450°C to 600°C, or 450°C to 550°C. The conditions can be selected so that a desired amount of conversion of the feedstock occurs in the fluidized bed reactor. For example, the conditions can be selected to achieve at least 10 wt% conversion relative to 343°C (or 371°C), or at least 20 wt% conversion relative 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 still higher. The light hydrocarbon products of the coking (thermal cracking) reactions vaporize, mix with the fluidizing steam and pass upwardly through the dense phase of the fluidized bed into a dilute phase zone above the dense fluidized bed of coke particles. This mixture of vaporized hydrocarbon products formed in the coking reactions flows upwardly through the dilute phase with the steam at superficial velocities of roughly 1 to 2 meters per second (~ 3 to 6 feet per second), entraining some fine solid particles of coke which are separated from the cracking vapors in the reactor cyclones as described above. In aspects where steam is used as the fluidizing agent, the weight of steam introduced into the reactor can be selected relative to the weight of feedstock introduced into the reactor. For example, the mass flow rate of steam into the reactor can correspond to 6.0% of the mass flow rate of feedstock, or 8.0% or more, such as up to 10% or possibly still higher. The amount of steam can potentially be reduced if an activated light hydrocarbon stream is used as part of the stripping and/or fluidizing gas in the reactor. In such aspects, the mass flow rate of steam can correspond to 6.0% of the mass flow rate of feedstock or less, or 5.0% or less, or 4.0% or less, or 3.0% or less. Optionally, in some aspects, the mass flow rate of steam can be still lower, such as corresponding to 1.0% of the mass flow rate of feedstock or less, or 0.8% or less, or 0.6% or less, such as down to substantially all of the steam being replaced by the activated light hydrocarbon stream. The cracked hydrocarbon vapors pass out of the cyclones into the scrubbing section of the reactor and then to product fractionation and recovery.

[0098] In a general fluidized coking process, the coke particles formed in the coking zone pass downw ards in the reactor and leave the bottom of the reactor vessel through a stripper section where they are exposed to steam in order to remove occluded hydrocarbons. The solid coke from the reactor, consisting mainly of carbon with lesser amounts of hydrogen, sulfur, nitrogen, and traces of vanadium, nickel, iron, and other elements derived from the feed, passes through the stripper and out of the reactor vessel to a burner or heater where it is partly burned in a fluidized bed with air to raise its temperature from 480°C to 700°C (~ 900°F to 1300°F) to supply the heat required for the endothermic coking reactions, after which a portion of the hot coke particles is recirculated to the fluidized bed reaction zone to transfer the heat to the reactor and to act as nuclei for the coke formation. The balance is withdrawn as coke product. The net coke yield is only about 65 percent of that produced by delayed coking.

[0099] For a coking process that includes a gasification zone, the cracking process proceeds in the reactor, the coke particles pass downwardly through the coking zone, through the stripping zone, where occluded hydrocarbons are stripped off by the ascending current of fluidizing gas (steam). They then exit the coking reactor and pass to the gasification reactor (gasifier) which contains a fluidized bed of solid particles and which operates at a temperature higher than that of the reactor coking zone. In the gasifier, the coke particles are converted by reaction at the elevated temperature with steam and an oxy gen-containing gas into a fuel gas comprising carbon monoxide and hydrogen.

[0100] The gasification zone is typically maintained at a high temperature ranging from 850°C to 1000°C (~ 1560°F to 1830°F) and a pressure ranging from 0 kPag to 1000 kPag (~0 psig to 150 psig), preferably from 200 kPag to 400 kPag (~ 30 psig to 60 psig). Steam and an oxygen-containing gas are introduced to provide fluidization and an oxygen source for gasification. In some aspects the oxygen-containing gas can be air. In other aspects, the oxy gen-containing gas can have a low nitrogen content, such as oxygen from an air separation unit or another oxygen stream including 95 vol% or more of oxygen, or 98 vol% or more, are passed into the gasifier for reaction with the solid particles comprising coke deposited on them in the coking zone. 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, can also be passed into the gasifier.

[0101] In the gasification zone the reaction between the coke and the steam and the oxy gencontaining gas produces a hydrogen and carbon monoxide-containing fuel gas and a partially gasified residual coke product. Conditions in the gasifier are selected accordingly to generate these products. Steam and oxygen rates (as well as any optional CO2 rates) will depend upon the rate at which cold coke enters from the reactor and to a lesser extent upon 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 with these being selected according to the feed and the range of liquid products which is required. The fuel gas product from the gasifier may contain entrained coke solids and these are removed by cyclones or other separation techniques in the gasifier section of the unit; cyclones may be internal cyclones in the main gasifier vessel itself or external in a separate, smaller vessel as described below. The fuel gas product is taken out as overhead from the gasifier cyclones. The resulting partly 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.

[0102] In some aspects, the coking conditions can be selected to provide a desired amount of conversion relative to 343°C. Typically, a desired amount of conversion can correspond to 10 wt% or more, or 50 wt% or more, or 80 wt% or more, such as up to substantially complete conversion of the feedstock relative to 343 °C.

[0103] Delayed coking is a process for the thermal conversion of heavy' oils such as petroleum residua (also referred to as "resid") to produce liquid and vapor hydrocarbon products and coke. Delayed coking of resids from heavy and/or sour (high sulfur) crude oils is carried out by converting part of the resids to more valuable hydrocarbon products. The resulting coke has value, depending on its grade, as a fuel (fuel grade coke), electrodes for aluminum manufacture (anode grade coke), etc.

[0104] Generally, a residue fraction, such as a petroleum residuum feed is pumped to a preheater where it is pre-heated, such as to a temperature from 480°C to 520°C. The pre-heated feed is then conducted to a coking zone, typically a vertically-oriented, insulated coker vessel, e.g., drum, through an inlet at the base of the drum. Pressure in the drum is usually 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) to allow volatiles to be removed overhead. Typical operating temperatures of the drum will be between roughly 475°C to 525°C. The hot feed thermally cracks over a period of time (the "coking time") in the coke drum, liberating volatiles composed primarily of hydrocarbon products that continuously rise through the coke bed, which consists of channels, pores and pathways, and are collected overhead. The volatile products are conducted to a coker fractionator for distillation and recovery of coker gases, gasoline boiling range material 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 recycle and combined with the fresh feed (coker feed component), thereby forming the coker heater or coker furnace charge. In addition to the volatile products, the process also results in the accumulation of coke in the drum. When the coke drum is full of coke, the heated feed is switched to another drum and hydrocarbon vapors are purged from the coke drum with steam. The drum is then quenched with water to lower the temperature down to 200°F (-95 °C) to 300°F (~150°C), after which the water is drained. When the draining step is complete, the drum is opened and the coke is removed by drilling and/or cutting using high velocity water jets (“hydraulic decoking”).

[0105] The volatile products from the coke drum are conducted away from the process for further processing. For example, volatiles can be conducted to a coker fractionator for distillation and recovery of coker gases, coker naphtha, light gas oil, and heavy gas oil. Such fractions can be used, usually, but not always, following upgrading, in the blending of fuel and lubricating oil products such as motor gasoline, motor diesel oil, fuel oil, and lubricating oil. Upgrading can include separations, heteroatom removal via hydrotreating and non- hydrotreating processes, de-aromatization, solvent extraction, and the like. The process is compatible with processes where at least a portion of the heavy coker gas oil present in the product stream introduced into the coker fractionator is captured for recycle and combined with the fresh feed (coker feed component), thereby forming the coker heater or coker furnace charge. The combined feed ratio ("CFR") is the volumetric ratio of furnace charge (fresh feed plus recycle oil) to fresh feed to the continuous delayed coker operation. Delayed coking operations typically employ recycles of 5 vol% to 35% vol% (CFRs of about 1.05 to about 1.35). In some instances, there can be no recycle and sometimes in special applications recycle can be up to 200%.

Hydroprocessing of Coker Effluent Fractions

[0106] In various aspects, at least a portion of one or more coker effluent liquid fractions can be exposed to hydroprocessing conditions to reduce or minimize the content of unexpected nitrogen-containing compounds in the final kerosene / jet boiling range product. Such hydroprocessing can include, but is not limited to, hydrotreatment, hydrocracking, catalytic dewaxing and/or hydroisomerization, aromatic saturation.

[0107] In this discussion, hydroprocessing is defined as exposing an input flow to a hydroprocessing stage to a partial pressure of H2 of 50 kPa or more (such as 3000 kPa) in the presence of a catalyst at a temperature of 150°C to 450°C. Temperatures below 150°C result in de minimis hydroprocessing activity, while temperatures greater than 450°C primarily result in thermal cracking of hydrocarbon-like feeds.

[0108] Hydroprocessing (such as hydrotreating) is carried out in the presence of hydrogen. Hydrogen, contained in a hydrogen “treat gas,” is provided to the reaction zone. For example, a hydrogen-containing stream is fed, inj ected, or otherwise introduced into a vessel, reaction zone, or hydroprocessing zone corresponding to the location of a hydroprocessing catalyst. Treat gas, as referred to herein, can be either pure hydrogen or a hydrogen-containing gas stream containing hydrogen in an amount that is sufficient for the intended reaction(s). Treat gas can optionally include one or more other gasses (e.g., nitrogen and light hydrocarbons such as methane) that do not adversely interfere with or affect either the reactions or the products. Impurities, such as H2S and NH3 are undesirable and can typically be removed from the treat gas to a sufficiently low level before conducting the treat gas to the reactor. In aspects where the treat gas stream can differ from a stream that substantially consists of hydrogen (i.e., at least 99 vol% hydrogen), the treat gas stream introduced into a reaction stage can contain at least 50 vol%, or at least 75 vol% hydrogen, or at least 90 vol% hydrogen.

[0109] During hydrotreatment, a feedstock can be contacted with a hydrotreating catalyst under effective hydrotreating conditions which can include temperatures 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); pressures 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 from 0.1 to 10 hr' ¹ , or 0.1 to 5 hr' ¹ ; and a hydrogen treat gas rate of from 430 to 2600 Nnf/m ³ (-2500 to -15000 SCF/bbl), or 850 to 1700 NmW (-5000 to -10000 SCF/bbl). Any convenient type of hydrotreating catalyst may be used, such as hydrotreating catalysts for naphtha hydrotreating, distillate hydrotreating, heavy oil hydrotreating, and/or for catalysts for hydrotreatment of wide cut fractions.

[0110] The above hydrotreatment conditions cover a wide range of severities. In some aspects, hydrotreatment of a liquid coker effluent fraction that substantially corresponds to a naphtha boiling range fraction, a kerosene / jet boiling range fraction, or a combination thereof, can be performed at milder conditions. A liquid coker effluent fraction that substantially corresponds to a naphtha boiling range fraction, a kerosene jet boiling range fraction, or a combination thereof is defined as a liquid coker effluent fraction that has 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 can have a T10 distillation point of 30°C or higher. In some aspects, hydrotreatment of such a liquid coker effluent fraction can be performed at temperatures 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); pressures 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); a liquid hourly space velocity (LHSV) of from 0.1 to 10 hr' ¹ , or 0.1 to 5 hr' ¹ ; and a hydrogen treat gas rate of from 430 to 2600 Nm ³ /m ³ (-2500 to -15000 SCF/bbl), or 850 to 1700 Nm ³ /m ³ (-5000 to -10000 SCF/bbl).

[OHl] In some aspects when a coker effluent fraction includes a substantial portion of coker gas oil, higher severity hydro treatment conditions can be used. In such aspects, hydrotreatment can be performed at temperatures 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 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); a liquid hourly space velocity (LHSV) of from 0.1 to 10 hr' ¹ , or 0.1 to 5 hr' ¹ ; and a hydrogen treat gas rate of from 430 to 2600 Nm ³ /m ³ (-2500 to -15000 SCF/bbl), or 850 to 1700 Nm ³ /m ³ (-5000 to -10000 SCF/bbl).

[0112] The catalyst in a hydrotreatment stage can be a conventional hydrotreating catalyst, such as a catalyst composed of a Group VIB metal and/or a Group VIII metal on a support. Suitable metals include cobalt, nickel, molybdenum, tungsten, or combinations thereof. Preferred combinations of metals include nickel and molybdenum or nickel, cobalt, and molybdenum. Suitable supports include silica, silica-alumina, alumina, and titania.

[0113] Another hydroprocessing option is to expose a coker effluent fraction (or at least a portion thereof) to catalytic dewaxing conditions. Exposing a coker effluent fraction to catalytic dewaxing can be performed after hydrotreatment of the fraction in a hydroprocessing stage, or the catalytic dewaxing can correspond to the first (and possibly only) type of hydroprocessing in a hydroprocessing stage. It is noted that many types of dewaxing catalysts involve noble metal catalysts. For such types of catalysts, performing hydrotreatment prior to dewaxing may be beneficial for improving the activity and/or operating lifetime of the dewaxing catalyst. For dewaxing catalysts that include non-noble metals and/or that are based primarily 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.

[0114] Process conditions in a catalytic dewaxing zone (in the presence of a dewaxing catalyst) can include a temperature of from 200°C to 450°C, or 270°C to 400°C, a hydrogen partial pressure of from 1.8 MPag to 34.6 MPag (250 psig to 5000 psig), or 4.8 MPag to 20.7 MPag, and a hydrogen treat gas rate of from 35.6 m ³ /m ³ (200 SCF/B) to 1781 m7m ³ (10,000 scf/B), preferably 178 m ³ /m ³ (1,000 SCF/B) to 890.6 m ³ /m ³ (5,000 SCF/B). The liquid hourly space velocity (LHSV) can be from 0.2 h' ¹ to 10 h' ¹ , such as from 0.5 h' ¹ to 5 h' ¹ and/or from 1 1T ¹ to 4 h' ¹ .

[0115] For coker effluent fractions that include higher boiling components, another option can be to expose the effluent fraction (or at least a portion thereof) to a catalyst under hydrocracking conditions. During hydrocracking, a feedstock can be contacted with a hydrocracking catalyst under effective hydrocracking conditions which can include temperatures of 550°F (288°C) to 840°F (449°C), hydrogen partial pressures of from 250 psig to 5000 psig (1.8 MPag to 34.6 MPag), liquid hourly space velocities of from 0.05 h' ¹ to 10 h' ¹ , and hydrogen treat gas rates of from 35.6 m ³ /m ³ to 1781 m ³ /m ³ (200 SCF/B to 10,000 SCF/B).

[0116] Still another hydroprocessing option can be to expose a coker effluent fraction to a catalyst under aromatic saturation conditions / hydrofinishing conditions. Aromatic saturation conditions can include temperatures from 125°C to 425°C, preferably 180°C to 280°C, a hydrogen partial pressure from 500 psig (3.4 MPa) to 3000 psig (20.7 MPa), preferably 1500 psig (10.3 MPa) to 2500 psig (17.2 MPa), and liquid hourly space velocity from 0.1 hr' ¹ to 5 hr' ¹ LHSV, preferably 0.5 hr' ¹ to 2.0 hr' ¹ . Additional Embodiments

[0117] 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 a weight of the plastic feedstock, the feedstock mixture comprising 0.5 wt% to 30 wt% of the plastic feedstock relative to a 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 a 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 boiling range fraction having a total nitrogen content of 10 wppm or less relative to a weight of the jet boiling range fraction, wherein the one or more amides, one or more amines, or a combination thereof optionally comprise caprolactam.

[0118] Embodiment 2. The method of Embodiment 1 , wherein the basic nitrogen content of the at least one liquid product fraction comprises 20 wt% or more of the total nitrogen content of the at least one liquid product fraction.

[0119] Embodiment 3. The method of Embodiment 1, wherein the basic nitrogen content of the at least one liquid product fraction comprises 40 wt% or more of the total nitrogen content of the at least one liquid product fraction.

[0120] Embodiment 4. The method of any of the above embodiments, wherein the at least one liquid product fraction comprises a basic nitrogen content of 150 wppm or more.

[0121] Embodiment 5. The method of any of the above embodiments, wherein the at least one liquid product fraction comprises a basic nitrogen content of 300 wppm or more.

[0122] Embodiment 6. The method of any of the above embodiments, wherein the at least one liquid product fraction comprises a total nitrogen content of 700 wppm or more.

[0123] 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 the 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 a jet boiling range fraction having 10 wppm or less of basic nitrogen, wherein optionally each of the plurality of liquid product fractions comprise 100 wppm or more of basic nitrogen.

[0124] Embodiment 8. The method of any of the above embodiments, further comprising separating the hydroprocessed effluent to form the jet boiling range fraction and one or more additional hydroprocessed fractions having a T10 distillation point of 300°C or higher.

[0125] Embodiment 9. The method of Embodiment 8, wherein separating the conversion effluent comprises forming at least one additional liquid product fraction having a T10 distillation point of 300°C or higher, 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 the hydroprocessing conditions. [0126] Embodiment 10. The method of any of the above embodiments, wherein separating the conversion effluent compnses 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 second hydroprocessing conditions to form a second hydroprocessed effluent; and separating the second hydroprocessed effluent to form a second jet boiling range fraction and at least one additional hydroprocessed fraction having a T10 distillation point of 300°C or higher.

[0127] Embodiment 11. The method of any of the above embodiments, wherein at least one of the one or more additional feedstocks comprises a T10 distillation point of 300°C or higher.

[0128] Embodiment 12. The method of any of the above embodiments, wherein the plastic feedstock further comprises 5.0 wt% or less of at least one chlorine-containing polymer relative to a weight of the plastic feedstock, the method further comprising: maintaining the feedstock mixture in a vessel at a dechlorination temperature of 170°C to 300°C for 1.0 minute to 240 minutes to form a dechlorinated mixture of feedstocks, wherein exposing at least a portion of the feedstock mixture to coking conditions comprises exposing at least a portion of the dechlorinated mixture of feedstocks to coking conditions.

[0129] Embodiment 13. The method of Embodiment 12, wherein the one or more additional feedstocks comprise a T10 distillation point that is greater than the dechlorination temperature; or wherein the dechlorinated mixture of feedstocks comprises 1000 wppm or less of Cl relative to a weight of the dechlorinated mixture of feedstocks; or a combination thereof. [0130] Embodiment 14. The method of any of the above embodiments, wherein the hydroprocessing conditions comprise a severity index of 3 to 10.

[0131] Embodiment 15. A hydroprocessed effluent comprising ajet boiling range fraction formed according to the method of any of Embodiments 1 to 14.

[0132] Additional Embodiment 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.

[0133] Additional Embodiment B. The method of any of the above embodiments, wherein the coking conditions comprise fluidized coking conditions, delayed coking conditions, or a combination thereof.

[0134] When numerical lower limits and numerical upper limits are listed herein, ranges from any lower limit to any upper limit are contemplated. While the illustrative embodiments of the disclosure have been described with particularity, it will be understood that various other modifications will be apparent to and can be readily made by those skilled in the art without departing from the spirit and scope of the disclosure. Accordingly, it is not intended that the scope of the claims appended hereto be limited to the examples and descriptions set forth herein but rather that the claims be construed as encompassing all the features of patentable novelty which reside in the present disclosure, including all features which would be treated as equivalents thereof by those skilled in the art to which the disclosure pertains.

[0135] The present disclosure has been described above with reference to numerous embodiments and specific examples. Many variations will suggest themselves to those skilled in this art in light of the above detailed description. All such obvious variations are within the full intended scope of the appended claims.