FLUIDIZED COKING WITH REDUCED COKING VIA LIGHT HYDROCARBON ADDITION

Abstract

Systems and methods are provided for adding a heated stream of light hydrocarbons to a fluidized coking environment to improve liquid product yield and/or reduce coke production. The light hydrocarbons can correspond to C1-C10 hydrocarbons and/or hydrogen. The light hydrocarbons can be heated so that the light hydrocarbons are exposed to an activation temperature of 535° C. to 950° C. and/or an activation temperature higher than the temperature in the coking zone by 50° C. or more for an activation time prior to entering the fluidized coking reactor and/or the coking zone in the fluidized coking environment.

Description

FIELD

Systems and methods are provided for reducing coke formation and increasing liquid yield during fluidized coking by adding a light hydrocarbon stream at elevated temperature into the fluidized coking environment at one or more locations.

BACKGROUND

Coking is a carbon rejection process that is commonly used for upgrading of heavy oil feeds. Because coking does not require additional hydrogen to upgrade a feed, coking can be low cost alternative for upgrading of feeds that are challenging to process, such as feeds with a low ratio of hydrogen to carbon. In addition to producing a variety of liquid products, typical coking processes can also generate a substantial amount coke.

Coking processes in modem refinery settings 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. 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.

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 oxygen-deficient 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.

The Flexicoking™ process is described in patents of Exxon Research and Engineering Company, including, for example, U.S. Pat. No. 3,661,543 (Saxton), U.S. Pat. No. 3,759,676 (Lahn), U.S. Pat. No. 3,816,084 (Moser), U.S. Pat. No. 3,702,516 (Luckenbach), U.S. Pat. No. 4,269,696 (Metrailer). A variant is described in U.S. Pat. No. 4,213,848 (Saxton) in which the heat requirement of the reactor coking zone is satisfied by introducing a stream of light hydrocarbons from the product fractionator into the reactor instead of the stream of hot coke particles from the heater. Another variant is described in U.S. Pat. No. 5,472,596 (Kerby) using a stream of light paraffins injected into the hot coke return line to generate olefins. The light paraffins can have a residence time in the hot coke return line of greater than one second. Early work proposed units with a stacked configuration but later units have migrated to a side-by-side arrangement.

Delayed coking is also a process suitable 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. Generally, a residue fraction, such as a petroleum residuum feed is pumped to a pre-heater. The pre-heated feed is conducted to a coking zone, typically a vertically-oriented, insulated coker vessel, e.g., drum, through an inlet at the base of the drum. The hot feed thermally cracks over a period of time (the “coking time”) in the coker drum, liberating volatiles composed primarily of hydrocarbon products that continuously rise through the coke mass 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. Optionally, 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 coker drum is full of coke, the heated feed is switched to another drum and hydrocarbon vapors are purged from the coke drum with steam.

Although fluidized coking (such as Flexicoking™) can result in less coke production than delayed coking, further reductions in coke production and/or increases in liquid product yield from fluidized coking are desired. What is needed are systems and/or methods that can improve the yield of liquid product from fluidized coking, reduce the amount of coke production, or a combination thereof.

U.S. Pat. No. 5,370,787 describes a method for thermal treatment of petroleum residua with alkylaromatic or paraffinic co-reactant. The thermal treatment method produces additional liquid product by coking a heavy petroleum resid in the presence of light aromatics or paraffins.

U. S. Patent Application Publication 2013/0026069 describes a solvent assisted delayed coking process. The solvent is described as a paraffin solvent including paraffins having chain lengths of three to eight carbons. The solvent is introduced to flocculate the aspahltenes in the coking unit feed in order to reduce coke production and improve liquid yield. The solvent is injected into the feed prior to introducing the feed into the delayed coking furnace.

U.S. Pat. No. 8,888,991 describes a system and method for introducing an additive into a coking process. The process includes injecting a cracking catalyst into the vapor above the liquid/solid interface of a coking process. An additional carrier fluid or other type of quenching agent can also be introduced.

Chinese Patent CN106520181 describes a method for injecting the off-gas from a delayed coking process back into the delayed coker furnace tubes in place of a portion of the steam typically used in a delayed coking process. PCT Publication WO/2016/080999 also describes a delayed coking method involving recycle of off-gas from the coking process in place of a portion of the steam.

SUMMARY

In various aspects, a method for performing fluidized coking on a feedstock is provided. The method can include activating a stream comprising C₁-C₁₀ hydrocarbons, hydrogen, or a combination thereof by exposing the stream to an activation temperature for an activation time, preferably of 0.1 seconds to 10 seconds. Examples of suitable activation times can be 0.1 seconds to 1.0 seconds, or 0.1 seconds to 0.9 seconds, or 6.0 seconds to 10 seconds. The activation temperature can be higher than a coking zone temperature by 50° C. or more. A feedstock comprising a T10 distillation point of 343° C. or more can be exposed to a fluidized bed comprising solid particles in the presence of the activated stream under fluidized coking conditions in a reactor comprising the coking zone temperature to form a coker effluent. Optionally, the fluidized coking conditions can be effective for performing 10 wt % or more conversion of the feedstock relative to 343° C. Under the fluidized coking conditions, coke can be deposited on the solid particles. Optionally, the solid particles can correspond to coke particles. Preferably, the feedstock can be exposed to the solid particles without being exposed to additional cracking catalyst under the fluidized coking conditions.

In some aspects, the stream comprising C₁-C₁₀ hydrocarbons, hydrogen, or a combination thereof can correspond to C₁-C₅ alkanes and/or at least one of C₇-C₁₀ alkylaromatics and naphthenoaromatics. In some aspects, the activation temperature can be 535° C. to 950° C. Optionally, the coking zone temperature can be 650° C. or less.

In some aspects, the stream comprising C₁-C₁₀ hydrocarbons, hydrogen, or a combination thereof can be activated by introducing the stream into a conduit containing heated coke particles. Optionally, the conduit can provide direct fluid communication between the reactor and at least one of a heater and a gasifier. Additionally or alternately, the activated stream can be introduced into a coking zone of the reactor using one or more nozzles. Further additionally or alternately, the reactor can include a stripping zone below a coking zone, with the activated stream being introduced into the reactor as part of a stripping gas introduced into the stripping zone. Still further additionally or alternately, the activated stream can be introduced into the reactor as a fluidizing gas for the fluidized bed. In some aspects, introducing the activated stream can allow for a reduced mass flow rate of steam into the reactor.

In various aspects, an integrated fluidized coking system is also provided. The system can include a fluidized bed coker comprising a coker feed inlet, an activated gas inlet, a cold coke outlet, at least one hot coke inlet, and a coker product outlet. The system can further include a coke combustion reactor, including a coke combustion inlet in fluid communication with the cold coke outlet, a coke combustion outlet in fluid communication with the at least one hot coke inlet via at least one hot coke conduit, at least one coke combustion gas inlet, and a fuel gas outlet. The system can further include a first separation stage including a first separation stage inlet in fluid communication with the coker product outlet, a first separation stage heavy product outlet and a first separation stage light ends outlet, the first separation stage light ends outlet being in fluid communication with the activated gas inlet via an activated gas conduit. Additionally, the system can include a heater associated with the activated gas conduit for heating gas in the activated gas conduit.

Optionally, the fluidized bed coker can include a coking zone and a stripping zone, the activated gas inlet comprising a stripping gas inlet, a fluidizing gas inlet, or a combination thereof, the at least one hot coke inlet optionally being in fluid communication with a coking zone of the reactor, the at least one hot coke inlet optionally being in fluid communication with a stripping zone of the reactor, or a combination thereof. Optionally, the coke combustion reactor can correspond to a gasifier, the at least one coke combustion gas inlet corresponding to at least one gasifier gas inlet.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows an example of a fluidized bed coking system including a coker, a heater, and a gasifier.

FIG. 2 shows an example of a fluidized bed coking system including a coker and a gasifier.

FIG. 3 shows an example of a fluidized bed coking system including a coker, a heater, a gasifier, and various potential locations for insertion of heated light hydrocarbons into a fluidized coking process.

DETAILED DESCRIPTION

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.

Overview

In various aspects, systems and methods are provided for adding a heated stream of light hydrocarbons to a fluidized coking environment to improve liquid product yield and/or reduce coke production. The light hydrocarbons can correspond to C₁-C₁₀ hydrocarbons. For example, the light hydrocarbons can correspond to C₁-C₅ alkanes and/or C₇-C₁₀ alkyl-aromatics or naphthenoaromatics. Optionally, hydrogen can be used in addition to or in place of the light hydrocarbons. The light hydrocarbons can be heated so that the light hydrocarbons are exposed to an activation temperature of 535° C. to 950° C. for an activation time prior to entering the fluidized coking reactor and/or the coking zone in the fluidized coking environment. The activation time can vary depending on various factors, including the activation temperature and the nature of the light hydrocarbons. Generally, the activation time is 0.1 seconds to 10 seconds. In some aspects, the activation time can be 0.1 seconds to 1.0 seconds, or 0.1 seconds to 0.9 seconds. This unexpectedly short activation time can allow for activation of light hydrocarbons while reducing or minimizing cracking of the light hydrocarbons prior to entering the fluidized coking environment. In other aspects, the activation time can be 6.0 seconds to 10 seconds. This longer activation time can be beneficial for smaller hydrocarbons such as methane or ethane that require addition time for activation. In various aspects, the light hydrocarbons can be heated so that the light hydrocarbons are at an activation temperature that is higher than the temperature in the coking zone by 50° C. or more for the activation time prior to entering the fluidized coking reactor and/or coking zone in the fluidized coking environment. Additionally or alternately, the activation temperature can be 650° C.-950° C., or 750° C. to 950° C., or 860° C. to 950° C.

One of the significant distinctions between a delayed coking reaction environment and a fluidized coking reaction environment is the residence time for hydrocarbons in the coking zone of the coker. In a delayed coking environment, the residence time for hydrocarbons in the coking zone can be on the order of minutes, such as 3 minutes to 15 minutes. By contrast, the residence time for hydrocarbons in the coking zone during fluidized coking can be 15 seconds or less. Due to this substantial difference in residence time, it is conventionally believed that addition of light hydrocarbons to the fluidized coking environment would not be effective for improvement of liquid yield. This conventional belief is based in part on the understanding that the lower reactivity of small hydrocarbons in the coking environment would mean that the small hydrocarbons would not have sufficient time and/or activation energy to undergo thermal reactions at the typical temperatures and pressures used in fluidized coking.

It has been unexpectedly discovered that heating the light hydrocarbons to an activation temperature above the temperature in the coking zone for an activation time can facilitate reaction of the light hydrocarbons during the short residence times involved in fluidized coking. The activation temperature can correspond to a temperature greater than the coking zone temperature by 50° C. or more, or 100° C. or more, or 150° C. or more, or 200° C. or more, such as up to 350° C. greater than the coking zone temperature or possibly still higher. Such a temperature can correspond to a temperature of 535° C. to 950° C., or 560° C. to 950° C., or 600° C. to 950° C., or 650° C. to 950° C., or 750° C. to 950° C., or 850° C. to 950° C. Without being bound by any particular theory, it is believed that activating the light hydrocarbons prior to introduction into the coking zone can allow for generation of radicals in the light hydrocarbons. This can also be referred to as activation of the light hydrocarbons. It is believed that these radicals based on light hydrocarbons can combine with radicals formed from the typically heavier (i.e., higher boiling) fractions used as feeds for coking. By reacting at least a portion of the heavy radicals from in the coker feed with lighter radicals, it is believed that the polymerization reactions that result in coke formation can be stopped at an earlier stage. It is believed that this can increase the amount of liquid product and/or reduce the amount of coke produced. In various aspects, the benefits of introducing light hydrocarbons into the fluidized reaction environment after exposure to elevated temperatures for an activation time can be achieved without introducing an additional cracking catalyst into the reaction environment. It is noted that coke particles are already present in a fluidized coking environment, and therefore do not correspond to “additional” particles in the coking environment.

The light hydrocarbons (and/or hydrogen) can be added into the fluidized coking environment in a variety of manners. In some aspects, the light hydrocarbons can be added by introducing the light hydrocarbons through feed nozzles into the fluidized coking environment. Additionally or alternately, the light hydrocarbons can be used as a stripping gas in the reactor stripping section. In such aspects, the light hydrocarbons can replace at least a portion of the steam or other gas used for stripping of hydrocarbons from the coke particles. Additionally or alternately, the light hydrocarbons can be introduced into the dense phase of the fluidized bed as a fluidizing gas. In such aspects, the light hydrocarbons can replace at least a portion of the steam or other gas that is used as a fluidizing gas. Additionally or alternately, the light hydrocarbons can be introduced into the hot coke transfer line at an appropriate location so that the residence time of the light hydrocarbons at an elevated temperature corresponds to a desired activation time prior to entering the coking zone of the fluidizing coking environment.

In this discussion, a “C_x” hydrocarbon refers to a hydrocarbon compound that includes “x” number of carbons in the compound. A stream containing “C_x-C_y” hydrocarbons refers to a stream composed of one or more hydrocarbon compounds that includes at least “x” carbons and no more than “y” carbons in the compound. It is noted that a stream comprising C_x-C_y hydrocarbons may also include other types of hydrocarbons, unless otherwise specified.

Fluidized Coking with Integrated Gasification

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 by-product 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 oxygen-containing 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. 1 and 2 provide examples of fluidized coking reactors that include a gasifier, while FIG. 3 provides an example of a modified fluidized coking reactor for introduction of activated light hydrocarbons into the reactor and/or coking zone within the reactor.

FIG. 1 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.

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 %.

In configurations such as FIG. 1, 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.

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.

FIG. 2 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. 2, 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.

In the configuration shown in FIG. 2, 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.

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 bottoms. Such feeds will typically have a Conradson Carbon Residue (ASTM D189-165) of at least 5 wt. %, generally from 5 to 50 wt. %. Preferably, the feed is a petroleum vacuum residuum.

A typical petroleum chargestock suitable for processing in a fluidized bed coker can have a composition and properties within the ranges set forth below in Table 1.

TABLE 1
Example of Coker Feedstock
	Conradson Carbon	5 to 40	wt. %
	API Gravity	−10 to 35°
	Boiling Point	340° C.+ to 650° C.+
	Sulfur	1.5 to 8	wt. %
	Hydrogen	9 to 11	wt. %
	Nitrogen	0.2 to 2	wt. %
	Carbon	80 to 86	wt. %
	Metals	1 to 2000	wppm

More generally, the feed to the fluidized bed coker can have a T10 distillation point of 343° C. or more, or 371° C. or more.

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.

As 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 oxygen-containing gas into a fuel gas comprising carbon monoxide and hydrogen.

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 oxygen-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.

In the gasification zone the reaction between the coke and the steam and the oxygen-containing 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.

Configuration Example for Introduction of Light Hydrocarbons

FIG. 3 shows an example of a fluidized coking configuration that includes various locations for introduction of light hydrocarbons into the reactor and/or the coking zone of the fluidized coking environment after exposure of the light hydrocarbons (and/or hydrogen) to an activation temperature for an activation time. In FIG. 3, a feedstock 301 suitable for coking is introduced into reactor corresponding to a fluidized bed coker 312. The coking zone 317 and stripper section 318 of fluidized bed coker 312 are shown in FIG. 3. The feed 301 can correspond to a heavy oil feed, or any other convenient feed typically used as an input for a coker. In the configuration shown in FIG. 3, the fluidized bed coker 312 is integrated with a heater 314 and a gasifier 316. This combination of elements is similar to the configuration shown in FIG. 1. In other aspects, the fluidized bed coker can be integrated with a gasifier without having an intermediate heater.

In FIG. 3, fluidized bed coker 312 generates a coker effluent 305 that includes fuel boiling range liquids generated during the coking process. Heat for coker 312 can be provided by hot coke recycle line 374 from heater 314 and/or second hot coke recycle line 386 from gasifier 316. In the configuration shown in FIG. 3, the hot coke recycle line 374 from heater 314 is passed into coking zone 317 of coker 312. In some aspects, the hot coke recycle line 374 can be passed into the stripping section 318. The second hot coke recycle line 386 from gasifier 316 is passed into stripping section 318 of coker 312. In some aspects, the second hot coke recycle line 386 can instead be passed into the coking zone 317. This can provide separate control of the heating in the coking zone 317 and stripping section 318 of coker 312. In other aspects, any convenient number and combination of hot coke recycle lines from heater 314 and/or gasifier 316 can be used to provide heat to coker 312.

During operation of coker 312, activated stream can be passed into the coker in a variety of manners. Some options can involve separately activating a light hydrocarbon (and/or hydrogen) stream and injecting the activated stream into coker 312. For example, the activated stream can be injected using input line 342 into coking zone 317; input line 344 into stripping section 318; and/or input line 346 into stripping section 318. Injecting the activated stream using input line 342 can assist with fluidizing the fluidized bed in coking zone 317. Injecting the activated stream into the stripping section 318 using line 344 or line 346 can provide gas for stripping hydrocarbons from coke particles and/or for fluidization. Optionally, this injection can be performed using separate nozzles, or the activated stream can be injected into an existing conduit with fluid flow into the coker 312. Additionally or alternately, a light hydrocarbon stream can be injected into a coke transfer conduit, such as by injecting light hydrocarbon stream 367 into coke conduit 386 or light hydrocarbon stream 363 into coke conduit 374. In such aspects, the light hydrocarbon stream can be injected into the coke conduit at an appropriate location to achieve exposure of the light hydrocarbon stream to the activation temperature for 1.0 seconds or less. Each of activated streams 342, 344, and 346 and light hydrocarbon streams 363 and 367 corresponds to an optional stream that can be present independent of the existence of any of the other activated streams and/or light hydrocarbon streams. Optionally, one or more of the activated streams 342, 344, or 346 and/or light hydrocarbon streams 363 or 367 can correspond to a recycle stream based on recycle of at least a portion of coker effluent 305 (such as a portion of gas phase product 357) and/or a recycle based on recycle of at least a portion of fuel gas stream 321.

Cold coke from coker 312 is passed into heater 314 via line 384. Coke from heater 314 is transferred to gasifier 316 through line 394 and hot, partly gasified particles of coke are circulated from the gasifier back to the coker 312 through line 386. As noted above, line 386 could instead be passed into heater 314, and then heater 314 could provide both hot coke lines to reactor 312. Fuel gas generated in gasifier 316 is returned to heater 314 via line 392 and then exits as fuel gas stream 321. It is noted that gasifier 316 does not generate a slag that is separately removed from the gasifier. Instead, excess coke is withdrawn from the heater 314 and/or gasifier 316 (not shown). Oxygen and steam for the gasifier are introduced, for example, via line 304. Coker effluent 305 from the coker 312 can then be passed into a separation stage 350 for separation of a liquid product 355 from a light ends or gas phase product 357.

Example: Yield Improvement Based on Injection of Activated Light Hydrocarbons

The predicted yields of a delayed coking unit, a conventional Flexicoking unit, and a Flexicoking unit using a C₁-C₄ hydrocarbon stream as the fluidization gas in place of steam are compared in Table 1. The predicted weight percentages for products shown in Table 1 are weight percentages relative to the amount of input feedstock. In the first row shows the predicted yield of gas phase products, with the predicted yield of gas phase olefins in parentheses. The second row shows the predicted yield of liquid coker products. The third row shows the predicted amount of fuel gas generated from gasification of coke during Flexicoking. (Gasification is not performed in conventional delayed coking.) The fourth row shows predicted net coke production. Row 5 shows the superficial velocity of the diluent gas used for fluidizing the fluidized coking bed. Row 6 shows the fluidization medium. The predicted values in Table 2 demonstrate the potential benefit in increased liquid yield based on use of an activated light hydrocarbon stream in the fluidized coking environment.

TABLE 2
Coking Product Yields
	Delayed		Flexicoking with
	Coking	Flexicoking	Activated Gas Injection
Gas (Olefins) wt %	6.6 (1)	10.8 (2)	9 (4)
Liquid wt %	67.0	67.2	73
Gasified Coke wt %	—	21	17
Net Coke wt %	26.4	1	1
Dilute velocity, ft/s	—	3.7	6+
Fluidization medium	—	Steam	C1-C4

ADDITIONAL EMBODIMENTS

Embodiment 1

A method for performing fluidized coking on a feedstock, comprising: activating a stream comprising C₁-C₁₀ hydrocarbons, hydrogen, or a combination thereof by exposing the stream comprising C₁-C₁₀ hydrocarbons, hydrogen, or a combination thereof to an activation temperature for an activation time of 0.1 seconds to 10 seconds, the activation temperature being higher than a coking zone temperature by 50° C. or more; and exposing, in a reactor, a feedstock comprising a T10 distillation point of 343° C. or more to a fluidized bed comprising solid particles in the presence of the activated stream under fluidized coking conditions comprising the coking zone temperature to form a coker effluent, the fluidized coking conditions comprising 10 wt % or more conversion of the feedstock relative to 343° C., the fluidized coking conditions being effective for depositing coke on the solid particles.

Embodiment 2

The method of Embodiment 1, wherein the stream comprising C₁-C₁₀ hydrocarbons, hydrogen, or a combination thereof comprises C₁-C₅ alkanes, or wherein the stream comprising C₁-C₁₀ hydrocarbons, hydrogen, or a combination thereof comprises at least one of C₇-C₁₀ alkylaromatics and naphthenoaromatics, or a combination thereof.

Embodiment 3

The method of any of the above embodiments, wherein the activation temperature is 535° C. to 950° C. (or 600° C. to 950° C., or 750° C. to 950° C., or 860° C. to 950° C.); or wherein the activation temperature is greater than the coking zone temperature by 100° C. or more (or 150° C. or more, or 200° C. or more); or a combination thereof.

Embodiment 4

The method of any of the above embodiments, wherein the coking zone temperature is 650° C. or less (or 550° C. or less).

Embodiment 5

The method of any of the above embodiments, wherein the activation time is 0.1 seconds to 1.0 seconds (or 0.1 seconds to 0.9 seconds); or wherein the activation time is 6.0 seconds to 10 seconds.

Embodiment 6

The method of any of the above embodiments, wherein the feedstock is exposed to the fluidized bed comprising solid particles under the fluidized coking conditions in a coking zone, the activated stream being exposed to the activation temperature for the activation time prior to entering the coking zone.

Embodiment 7

The method of any of the above embodiments, wherein the feedstock is exposed to the fluidized bed comprising solid particles under the fluidized coking conditions without being exposed to an additional cracking catalyst under the fluidized coking conditions.

Embodiment 8

The method of any of the above embodiments, further comprising activating the stream comprising C₁-C₁₀ hydrocarbons, hydrogen, or a combination thereof by introducing the stream comprising C₁-C₁₀ hydrocarbons, hydrogen, or a combination thereof into a conduit containing heated coke particles, the conduit providing direct fluid communication between the reactor and at least one of a heater and a gasifier.

Embodiment 9

The method of any of Embodiments 1-7, a) further comprising introducing the activated stream into a coking zone of the reactor using one or more nozzles; b) wherein the reactor comprises a stripping zone below a coking zone, the method further comprising introducing the activated stream into the reactor as part of a stripping gas introduced into the stripping zone; c) further comprising introducing the activated stream into the reactor as a fluidizing gas for the fluidized bed; or d) a combination of two or more of a), b), and c).

Embodiment 10

The method of any of the above embodiments, wherein a mass flow rate of steam into the reactor relative to the mass flow rate of feedstock into the reactor is 6.0% or less (or 5.0% or less, or 4.0% or less, or 3.0% or less), or wherein the mass flow rate of steam into the reactor relative to the mass flow rate of feedstock into the reactor is 1.0% or less (or 0.8% or less, or 0.6% or less, or 0.4% or less).

Embodiment 11

The method of any of the above embodiments, further comprising: introducing an oxygen-containing stream and steam into a coke combustion stage, the coke combustion stage optionally comprising a gasifier; passing at least a portion of the solid particles comprising deposited coke from the reactor to the coke combustion stage; exposing the at least a portion of the solid particles comprising deposited coke to combustion conditions to form a gas phase product comprising H₂, CO, and CO₂ and partially combusted solid particles; removing at least a first portion of the partially combusted solid particles from the coke combustion stage; passing at least a second portion of the partially combusted solid particles from the coke combustion stage to the reactor; and separating the coker effluent to form a lower boiling product comprising at least a portion of the stream comprising C₁-C₁₀ hydrocarbons, hydrogen, or a combination thereof.

Embodiment 12

The method of any of the above embodiments, wherein the solid particles comprise coke particles.

Embodiment 13

An integrated fluidized coking system, comprising: a fluidized bed coker comprising a coker feed inlet, an activated gas inlet, a cold coke outlet, at least one hot coke inlet, and a coker product outlet; a coke combustion reactor comprising: a coke combustion inlet in fluid communication with the cold coke outlet, a coke combustion outlet in fluid communication with the at least one hot coke inlet via at least one hot coke conduit, at least one coke combustion gas inlet, and a fuel gas outlet; a first separation stage comprising a first separation stage inlet in fluid communication with the coker product outlet, a first separation stage heavy product outlet and a first separation stage light ends outlet, the first separation stage light ends outlet being in fluid communication with the activated gas inlet via an activated gas conduit; and a heater associated with the activated gas conduit for heating gas in the activated gas conduit.

Embodiment 14

The system of Embodiment 13, wherein the fluidized bed coker comprises a coking zone and a stripping zone, the activated gas inlet comprising a stripping gas inlet, a fluidizing gas inlet, or a combination thereof, the at least one hot coke inlet optionally being in fluid communication with a coking zone of the reactor, the at least one hot coke inlet optionally being in fluid communication with a stripping zone of the reactor, or a combination thereof.

Embodiment 15

The system of Embodiment 13 or 14, wherein the coke combustion reactor comprises a gasifier, the at least one coke combustion gas inlet comprising at least one gasifier gas inlet.

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 invention 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 invention. 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 invention, including all features which would be treated as equivalents thereof by those skilled in the art to which the invention pertains.

The present invention 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.

Claims

1. A method for performing fluidized coking on a feedstock, comprising:

activating a stream comprising C1-C10 hydrocarbons, hydrogen, or a combination thereof by exposing the stream comprising C1-C10 hydrocarbons, hydrogen, or a combination thereof to an activation temperature for an activation time of 0.1 seconds to 10 seconds, the activation temperature being higher than a coking zone temperature by 50° C. or more; and

exposing, in a reactor, a feedstock comprising a T10 distillation point of 343° C. or more to a fluidized bed comprising solid particles in the presence of the activated stream under fluidized coking conditions comprising the coking zone temperature to form a coker effluent, the fluidized coking conditions comprising 10 wt % or more conversion of the feedstock relative to 343° C., the fluidized coking conditions being effective for depositing coke on the solid particles.

2. The method of claim 1, wherein the stream comprising C1-C10 hydrocarbons, hydrogen, or a combination thereof comprises C1-C5 alkanes, or wherein the stream comprising C1-C10 hydrocarbons, hydrogen, or a combination thereof comprises at least one of C7-C10 alkylaromatics and naphthenoaromatics, or a combination thereof.

3. The method of claim 1, wherein the activation temperature is 535° C. to 950° C.

4. The method of claim 1, wherein the activation temperature is greater than the coking zone temperature by 100° C. or more.

5. The method of claim 1, wherein the coking zone temperature is 650° C. or less.

6. The method of claim 1, wherein the activation time is 0.1 seconds to 1.0 seconds.

7. The method of claim 1, wherein the activation time is 6.0 seconds to 10 seconds.

8. The method of claim 1, wherein the feedstock is exposed to the fluidized bed comprising solid particles under the fluidized coking conditions in a coking zone, the activated stream being exposed to the activation temperature for the activation time prior to entering the coking zone.

9. The method of claim 1, wherein the feedstock is exposed to the fluidized bed comprising solid particles under the fluidized coking conditions without being exposed to an additional cracking catalyst under the fluidized coking conditions.

10. The method of claim 1, further comprising activating the stream comprising C1-C10 hydrocarbons, hydrogen, or a combination thereof by introducing the stream comprising C1-C10 hydrocarbons, hydrogen, or a combination thereof into a conduit containing heated coke particles, the conduit providing direct fluid communication between the reactor and at least one of a heater and a gasifier.

11. The method of claim 1, further comprising introducing the activated stream into a coking zone of the reactor using one or more nozzles.

12. The method of claim 1, wherein the reactor comprises a stripping zone below a coking zone, the method further comprising introducing the activated stream into the reactor as part of a stripping gas introduced into the stripping zone.

13. The method of claim 1, further comprising introducing the activated stream into the reactor as a fluidizing gas for the fluidized bed.

14. The method of claim 10, wherein a mass flow rate of steam into the reactor relative to the mass flow rate of feedstock into the reactor is 6.0% or less.

15. A method for performing fluidized coking on a feedstock, comprising:

activating a stream comprising C1-C10 hydrocarbons, hydrogen, or a combination thereof by exposing the stream to an activation temperature for and activation time of 0.1 seconds to 10 seconds, the activation temperature being higher than a coking zone temperature by 50° C. or more;

exposing, in a reactor, a feedstock comprising a T10 distillation point of 343° C. or more to a fluidized bed comprising solid particles in the presence of the activated stream under fluidized coking conditions comprising the coking zone temperature to form a coker effluent, the fluidized coking conditions comprising 10 wt % or more conversion of the feedstock relative to 343° C., the fluidized coking conditions being effective for depositing coke on the solid particles;

introducing an oxygen-containing stream and steam into a coke combustion stage;

passing at least a portion of the solid particles comprising deposited coke from the reactor to the coke combustion stage;

exposing the at least a portion of the solid particles comprising deposited coke to combustion conditions to form a gas phase product comprising H2, CO, and CO2 and partially combusted solid particles;

removing at least a first portion of the partially combusted solid particles from the coke combustion stage;

passing at least a second portion of the partially combusted solid particles from the coke combustion stage to the reactor; and

separating the coker effluent to form a lower boiling product comprising at least a portion of the stream comprising C1-C10 hydrocarbons, hydrogen, or a combination thereof.

16. The method of claim 15, wherein the coke combustion stage comprises a gasifier.

17. The method of claim 15, wherein the solid particles comprise coke particles.

18. The method of claim 1, wherein the activation time is 0.1 seconds to 1.0 seconds, or wherein the activation time is 6.0 seconds to 10 seconds.

19. An integrated fluidized coking system, comprising:

a fluidized bed coker comprising a coker feed inlet, an activated gas inlet, a cold coke outlet, at least one hot coke inlet, and a coker product outlet;

a coke combustion reactor comprising: a coke combustion inlet in fluid communication with the cold coke outlet, a coke combustion outlet in fluid communication with the at least one hot coke inlet via at least one hot coke conduit, at least one coke combustion gas inlet, and a fuel gas outlet;

a first separation stage comprising a first separation stage inlet in fluid communication with the coker product outlet, a first separation stage heavy product outlet and a first separation stage light ends outlet, the first separation stage light ends outlet being in fluid communication with the activated gas inlet via an activated gas conduit; and

a heater associated with the activated gas conduit for heating gas in the activated gas conduit.

20. The system of claim 19, wherein the fluidized bed coker comprises a coking zone and a stripping zone, the activated gas inlet comprising a stripping gas inlet, a fluidizing gas inlet, or a combination thereof.

21. The system of claim 19, wherein the coke combustion reactor comprises a gasifier, the at least one coke combustion gas inlet comprising at least one gasifier gas inlet.

22. The system of claim 19, wherein the at least one hot coke inlet is in fluid communication with a coking zone of the reactor, or wherein the at least one hot coke inlet is in fluid communication with a stripping zone of the reactor, or a combination thereof.