SELF-HEAT-BALANCED HSFCC SYSTEMS AND PROCESSES FOR UPGRADING HYDROCARBON FEEDS

Description

TECHNICAL FIELD

Embodiments of the present disclosure generally relate to chemical processing and, more specifically, to processes and systems utilizing fluid catalytic cracking.

BACKGROUND

The worldwide increasing demand for light olefins (such as ethylene, propylene, and butylenes) remains a major challenge for many integrated refineries. In particular, the production of ethylene and propylene has attracted increased attention as pure olefin streams are considered the building blocks for polymer synthesis. Light olefins may be produced through fluid catalytic cracking processes. Typical hydrocarbon feeds for fluid catalytic cracking (“FCC”) processes range from hydrocracked bottoms to heavy feed fractions such as vacuum gas oil and atmospheric residue. However, these hydrocarbon feeds are limited in supply.

BRIEF SUMMARY

During the operation of an FCC reactor, a feedstock is reacted in the presence of a catalyst, which forms coke on the surface of the catalyst, thereby reducing the catalytic activity of the catalyst to produce spent catalyst. The spent catalyst is passed to a regenerator where the coke is combusted to regenerate and heat the regenerated catalyst. The hot, regenerated catalyst is then passed back to the FCC reactor where it provides heat for endothermic cracking reactions. However, the amount of heat provided by the coke is often insufficient, requiring the use of coking agents and/or supplemental fuel. Alternatively, the amount of coke formed is often too great, requiring the use of expensive catalyst cooling systems in order to prevent the FCC reactor from overheating.

Accordingly, there is an ongoing need for processes for upgrading hydrocarbon feeds in an FCC system that are heat balanced such that the FCC system operates in the absence of supplemental fuels, coking agents, and catalyst coolers. Embodiments of the present disclosure meet this need by providing a method for operating an FCC system with four reaction zones and a common regenerator, where different hydrocarbon feeds are passed to the reaction zones, such that, with proper selection of the hydrocarbon feeds, coke from the first and second reaction zones can balance a lack of coke from the third and fourth reaction zones. The feeds to the first reaction zone and second reaction zone may comprise a heavy hydrocarbon feed, such as a whole crude oil. The feeds to the third reaction zone and fourth reaction zone may comprise a whole crude oil or a whole gas condensate and may be lighter (e.g., having a lesser API gravity, a lesser boiling point range, or both) than the feed to the first and second reaction zones. The use of crude hydrocarbon feeds with these different and distinct API gravities may balance the heat load between the two reactions, obviating the need for supplemental fuels or catalyst coolers in the catalyst regeneration process. Further, the use of these whole, relatively unprocessed hydrocarbon feeds enables the use of widely available feedstocks with minimal processing.

According to embodiments of the present disclosure, a process for upgrading hydrocarbon feeds in a fluidized catalytic cracking system (FCC system) may comprise passing a first portion of a heavy hydrocarbon feed to a first FCC reactor and a second portion of the heavy hydrocarbon feed to a second FCC reactor. The heavy hydrocarbon feed may have an American Petroleum Institute (API) gravity of from 10° to 35°. The process may further comprise passing a first portion of a light hydrocarbon feed to a third FCC reactor and second portion of the light hydrocarbon feed to a fourth FCC reactor. The light hydrocarbon feed has an API gravity of from 38° to 100°. A cracking catalyst may be passed from a catalyst withdrawal well to the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor, where the catalyst withdrawal well is common to the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor. The first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor may be operated in parallel. The first portion and the second portion of the heavy hydrocarbon feed may be contacted with the cracking catalyst in the first FCC reactor and the second FCC reactor, respectively, at high severity conditions, where the contacting may cause at least a portion of the heavy hydrocarbon feed to undergo catalytic cracking. The first portion and the second portion of the light hydrocarbon feed may be contacted with the cracking catalyst in the third FCC reactor and the fourth FCC reactor, respectively, at high severity conditions, where the contacting may cause at least a portion of the light hydrocarbon feed to undergo catalytic cracking. The process may further comprise separating reaction mixtures from the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor to produce an FCC effluent and spent cracking catalyst. The spent cracking catalyst may be regenerated to produce regenerated catalyst. The regenerated catalyst may be passed back to the catalyst withdrawal well. The process may further comprise determining a heat balance requirement of the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor and controlling a flow rate of the cracking catalyst from the catalyst withdrawal well to the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor, based on the heat balance requirements of the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor.

These and other embodiments are described in more detail in the Detailed Description. It is to be understood that both the foregoing general description and the following detailed description present embodiments of the presently disclosed technology, and are intended to provide an overview or framework for understanding the nature and character of the technology as it is claimed. The accompanying drawings are included to provide a further understanding of the presently disclosed technology and are incorporated into and constitute a part of this specification. The drawings illustrate various embodiments and, together with the description, serve to explain the principles and operations of the presently disclosed technology. Additionally, the drawings and descriptions are meant to be merely illustrative, and are not intended to limit the scope of the claims in any manner.

BRIEF DESCRIPTION OF THE DRAWINGS

The following detailed description of specific embodiments of the present disclosure can be best understood when read in conjunction with the following drawings, where like structure is indicated with like reference numerals and in which:

FIG. 1 schematically depicts an FCC system, according to embodiments shown and described in this disclosure; and

FIG. 2 graphically depicts relative properties of various hydrocarbon feed streams used for producing one or more petrochemical products, according to embodiments shown and described in this disclosure; and

FIG. 3 schematically depicts a micro downer unit used to process hydrocarbon feed streams, according to embodiments shown and described in this disclosure.

For the purpose of describing the simplified schematic illustrations and descriptions of the relevant figures, the numerous valves, temperature sensors, electronic controllers and the like that may be employed and well known to those of ordinary skill in the art of certain chemical processing operations are not included. Further, accompanying components that are often included in typical chemical processing operations, such as air supplies, catalyst hoppers, and flue gas handling systems, may not be depicted. However, operational components, such as those described in the present disclosure, may be added to the embodiments described in this disclosure.

It should further be noted that arrows in the drawings refer to process streams. However, the arrows may equivalently refer to transfer lines that may serve to transfer process streams between two or more system components. Additionally, arrows that connect to system components define inlets or outlets in each given system component. The arrow direction corresponds generally with the major direction of movement of the materials of the stream contained within the physical transfer line signified by the arrow. Furthermore, arrows that do not connect two or more system components signify a product stream that exits the depicted system or a system inlet stream that enters the depicted system. Product streams may be further processed in accompanying chemical processing systems or may be commercialized as end products. System inlet streams may be streams transferred from accompanying chemical processing systems or may be non-processed feedstock streams. Some arrows may represent recycle streams, which are effluent streams of system components that are recycled back into the system. However, it should be understood that any represented recycle stream, in embodiments, may be replaced by a system inlet stream of the same material, and that a portion of a recycle stream may exit the system as a system product.

Additionally, arrows in the drawings may schematically depict process steps of transporting a stream from one system component to another system component. For example, an arrow from one system component pointing to another system component may represent “passing” a system component effluent to another system component, which may include the contents of a process stream “exiting” or being “removed” from one system component and “introducing” the contents of that product stream to another system component. It should be understood that arrows in the relevant figures are not indicative of necessary or essential steps.

It should be understood that according to the embodiments presented in the relevant figures, an arrow between two system components may signify that the stream is not processed between the two system components. In other embodiments, the stream signified by the arrow may have substantially the same composition throughout its transport between the two system components. Additionally, it should be understood that in embodiments, an arrow may represent that at least 75 wt. %, at least 90 wt. %, at least 95 wt. %, at least 99 wt. %, at least 99.9 wt. %, or even 100 wt. % of the stream is transported between the system components. As such, in embodiments, less than all of the streams signified by an arrow may be transported between the system components, such as if a slip stream is withdrawn from the system.

It should be understood that two or more process streams are “mixed” or “combined” when two or more lines intersect in the schematic flow diagrams of the relevant figures. Mixing or combining may also include mixing by directly introducing both streams into a like reactor, separation device, or other system component. For example, it should be understood that when two streams are depicted as being combined directly prior to entering a separation unit or reactor, that in embodiments the streams could equivalently be introduced into the separation unit or reactor and be mixed in the reactor.

Reference will now be made in greater detail to various embodiments, some embodiments of which are illustrated in the accompanying drawings. Whenever possible, the same reference numerals will be used throughout the drawings to refer to the same or similar parts.

DETAILED DESCRIPTION

Embodiments of the present disclosure relate to methods for operating a fluidized catalytic cracking system. In general, these methods are described herein in the context of one or more systems, shown in the drawings. According to embodiments, a process for upgrading hydrocarbon feeds in a fluidized catalytic cracking system (FCC system) may comprise passing a first portion of a heavy hydrocarbon feed to a first FCC reactor and a second portion of the heavy hydrocarbon feed to a second FCC reactor. The heavy hydrocarbon feed may have an American Petroleum Institute (API) gravity of from 10° to 35°. A first portion of a light hydrocarbon feed may be passed to a third FCC reactor and second portion of the light hydrocarbon feed may be passed to a fourth FCC reactor. The light hydrocarbon feed may have an API gravity of from 38° to 100°. A cracking catalyst may be passed from a catalyst withdrawal well to the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor, where the catalyst withdrawal well is common to the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor. The first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor may be operated in parallel. The first portion and the second portion of the heavy hydrocarbon feed may be contacted with the cracking catalyst in the first FCC reactor and the second FCC reactor, respectively, at high severity conditions. The contacting may cause at least a portion of the heavy hydrocarbon feed to undergo catalytic cracking. Similarly, the first portion and the second portion of the light hydrocarbon feed may be contacted with the cracking catalyst in the third FCC reactor and the fourth FCC reactor, respectively, at high severity conditions. The contacting may cause at least a portion of the light hydrocarbon feed to undergo catalytic cracking. Reaction mixtures from the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor may be separated to produce an FCC effluent and spent cracking catalyst. The spent cracking catalyst may be regenerated to produce regenerated catalyst and the regenerated catalyst may be passed back to the catalyst withdrawal well. The process may further comprise determining a heat balance requirement of the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor. A flow rate of the cracking catalyst from the catalyst withdrawal well to the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor may be controlled based on the heat balance requirements of the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor.

As used in this disclosure, a “reactor” refers to a vessel in which one or more chemical reactions occur between one or more reactants optionally in the presence of one or more catalysts. For example, a reactor may include a tank or tubular reactor configured to operate as a batch reactor, a continuous stirred-tank reactor (“CSTR”), or a plug flow reactor. Example reactors include packed bed reactors such as fixed bed reactors, and fluidized bed reactors. One or more “reaction zones” may be disposed in a reactor. As used in this disclosure, a “reaction zone” refers to an area where a particular reaction takes place in a reactor. For example, a packed bed reactor with multiple catalyst beds may have multiple reaction zones, where each reaction zone is defined by the area of each catalyst bed.

As used in this disclosure, a “separation unit” refers to any separation device that at least partially separates one or more chemicals that are mixed in a process stream from one another. For example, a separation unit may selectively separate differing chemical species, phases, or sized material from one another, forming one or more chemical fractions. Examples of separation units include, without limitation, distillation columns, flash drums, knock-out drums, knock-out pots, centrifuges, cyclones, filtration devices, traps, scrubbers, expansion devices, membranes, solvent extraction devices, and the like. It should be understood that separation processes described in this disclosure may not completely separate all of one chemical constituent from all of another chemical constituent. It should be understood that the separation processes described in this disclosure “at least partially” separate different chemical components from one another, and that even if not explicitly stated, it should be understood that separation may include only partial separation. As used in this disclosure, one or more chemical constituents may be “separated” from a process stream to form a new process stream. Generally, a process stream may enter a separation unit and be divided, or separated, into two or more process streams of desired composition.

As used in this disclosure, the term “high-severity conditions” generally refers to FCC temperatures of 500° C. or greater, a weight ratio of catalyst to hydrocarbon (“catalyst-to-oil ratio” or “CTO”) of equal to or greater than 5:1, and a residence time of less than 3 seconds, all of which may be more severe than typical FCC reaction conditions.

As used in this disclosure, a “catalyst” refers to any substance that increases the rate of a specific chemical reaction. Catalysts described in this disclosure may be utilized to promote various reactions, such as, but not limited to, cracking (including aromatic cracking), demetallization, desulfurization, and denitrogenation. As used in this disclosure, “cracking” generally refers to a chemical reaction where carbon-carbon bonds are broken. For example, a molecule having carbon to carbon bonds is broken into more than one molecule by the breaking of one or more of the carbon to carbon bonds, or is converted from a compound which includes a cyclic moiety, such as a cycloalkane, cycloalkane, naphthalene, an aromatic or the like, to a compound which does not include a cyclic moiety or contains fewer cyclic moieties than prior to cracking.

As used in this disclosure, the term “first catalyst” refers to catalyst that is introduced to the first reaction zone, such as the catalyst passed to the first FCC reactor. As used in this disclosure, the term “second catalyst” refers to catalyst that is introduced to the second FCC reactor, such as the catalyst passed to the second reaction zone. As used in this disclosure, the term “third catalyst” refers to catalyst that is introduced to the third FCC reactor, such as the catalyst passed to the third reaction zone. As used in this disclosure, the term “fourth catalyst” refers to catalyst that is introduced to the fourth FCC reactor, such as the catalyst passed to the fourth reaction zone. It should be understood that the first catalyst, the second catalyst, the third catalyst, and the fourth catalyst are the same in composition.

As used in this disclosure, the term “spent catalyst” refers to catalyst that has been introduced to and passed through a reaction zone and contacted with a hydrocarbon feed, at reaction conditions but has not been regenerated in the regenerator or by a regeneration process following introduction to the reaction zone. The “spent catalyst” may have coke deposited on the catalyst and may include partially coked catalyst as well as fully coked catalysts. The amount of coke deposited on the “spent catalyst” may be greater than the amount of coke remaining on the regenerated catalyst following regeneration. The “first spent catalyst” may refer to spent catalyst that was coked in the first FCC reactor since its last regeneration. The “second spent catalyst” may refer to spent catalyst that was coked in the second FCC reactor since its last regeneration. The “third spent catalyst” may refer to spent catalyst that was coked in the third FCC reactor since its last regeneration. The “fourth spent catalyst” may refer to spent catalyst that was coked in the fourth FCC reactor since its last regeneration.

As used in this disclosure, the term “regenerated catalyst” refers to catalyst that has been contacted with a hydrocarbon feed at reaction conditions in a reaction zone and then regenerated in a regenerator or by a regeneration process to heat the catalyst to a greater temperature, oxidized and removed at least a portion of the coke from the catalyst to restore at least a portion of the catalytic activity of the catalyst, or both. The “regenerated catalyst” may have less coke, a greater temperature, or both compared to spent catalyst. The “regenerated catalyst” may have more coke compared to fresh catalyst that has not passed through a reaction zone and regenerator.

As used in this disclosure, the term “effluent” refers to a stream that is passed out of a reactor, a reaction zone, or a separator following a particular reaction or separation process. Generally, an effluent has a different composition than the stream that entered the separator, reactor, or reaction zone. It should be understood that when an effluent is passed to another system unit, only a portion of that system stream may be passed. For example, a slip stream (having the same composition) may carry some of the effluent away, meaning that only a portion of the effluent may enter the downstream system unit. The terms “reaction effluent” or “reactor effluent” are more particularly be used to refer to a stream that is passed out of a reactor or reaction zone.

It should further be understood that streams may be named for the components of the stream, and the component for which the stream is named may be the major component of the stream (such as comprising from 50 weight percent (“wt. %”), from 70 wt. %, from 90 wt. %, from 95 wt. %, from 99 wt. %, from 99.5 wt. %, or even from 99.9 wt. % of the contents of the stream to 100 wt. % of the contents of the stream, not including any purposely added diluents or inert constituents). It should also be understood that components of a stream are disclosed as passing from one system component to another when a stream comprising that component is disclosed as passing from that system component to another. For example, a disclosed “propylene stream” passing from a first system component to a second system component should be understood to equivalently disclose “propylene” passing from a first system component to a second system component, and the like.

As used in this disclosure, passing a stream or effluent from one unit “directly” to another unit refers to passing the stream or effluent from the first unit to the second unit without passing the stream or effluent through an intervening reaction system or separation system that substantially changes the composition of the stream or effluent. Heat transfer devices, such as heat exchangers, preheaters, coolers, condensers, or other heat transfer equipment, and pressure devices, such as pumps, pressure regulators, compressors, or other pressure devices, are not considered to be intervening systems that change the composition of a stream or effluent, unless otherwise specifically stated in the present disclosure. Combining two streams or effluents together upstream of a process unit also is not considered to comprise an intervening system that changes the composition of one or both of the streams or effluents being combined. Simply dividing a stream into two streams having the same composition is also not considered to comprise an intervening system that changes the composition of the stream.

Fluid catalytic cracking systems (FCC systems) utilize catalysts to crack hydrocarbon feeds in FCC reactors. During the cracking reaction, coke is formed that can accumulate on the catalysts, thereby deactivating the catalyst into spent catalyst. The spent catalyst can be regenerated by combusting the coke on the spent catalyst, which also increases the temperature of the regenerated catalyst. Passing the heated regenerated catalyst back into the FCC reactor can provide the heat required to conduct the endothermic cracking reaction. However, in some instances, such as when the hydrocarbon feed is a light hydrocarbon feed such as but not limited to a gas condensate, the amount of coke formed may not be sufficient to provide the heat necessary to conduct the cracking reaction. Thus, in many FCC systems, additional fuel sources must be introduced to the catalyst regenerator to further heat the catalyst. In other instances, such as when the hydrocarbon feed is a heavy hydrocarbon feed, the amount of coke formed may provide excess heat that is greater than the heat required for the cracking reactions and the regenerated catalyst must be cooled by using catalyst coolers prior to being passed back to the FCC reactor.

Therefore, there is an ongoing need for processes of operating an FCC system that are heat balanced such that no supplemental fuels or catalyst coolers are required. The present disclosure is directed to an FCC system comprising a plurality of FCC reactors in series using a common catalyst withdrawal well, and a common fluid-solid separator downstream of the FCC reactors, and a common regenerator. The FCC system has a heavy hydrocarbon feed introduced to a first subset of the FCC reactors and a light hydrocarbon feed introduced to a second subset of the FCC reactors. Common regeneration allows the greater coke from the cracking of the heavy hydrocarbon feed to be utilized to heat the spent catalyst from cracking the light hydrocarbon feed. The FCC system can be heat balanced by controlling the flow rate of the regenerated catalyst from the common catalyst withdrawal well to each of the individual FCC reactors.

Referring now to FIG. 1, the FCC system 100 includes four FCC reactors arranged in parallel. In each of the FCC reactors, a hydrocarbon feed stream contacts a cracking catalyst in a reaction zone maintained at high-severity conditions. When the hydrocarbon feed stream contacts the cracking catalyst at high-severity conditions, at least a portion of the hydrocarbon feed stream is cracked to produce greater value chemicals and intermediates. The contacting may also cause carbonaceous deposits, commonly referred to as coke, to form on the cracking catalyst. The coke deposits formed on the cracking catalyst may reduce the catalytic activity of the cracking catalyst. The spent catalyst having coke deposits may be separated from the cracking reaction products, stripped of removable hydrocarbons, and passed to a regeneration process where the coke is combusted in the presence of air to produce a regenerated catalyst that is catalytically effective. For example, coke deposits on the catalyst may cover up or block catalytically active sites on the spent catalyst, thus, reducing the number of catalytically active sites available, which may reduce the catalytic activity of the catalyst. Following regeneration, the amount of coke present on the regenerated catalyst may be less than or equal to 10 wt. %, less than or equal to 5 wt. %, or even less than or equal to 1 wt. % than the amount of coke present on the spent catalyst. The combustion products may be removed from the regeneration process as a flue gas stream. The heated regenerated catalysts may then be recycled back to the reaction zone of the FCC reactors.

Referring again to FIG. 1, an FCC system 100 is schematically depicted. The FCC system 100 may be a high-severity fluid catalytic cracking (“HSFCC”) system, which is an FCC system operated under high-severity conditions. The FCC system 100 generally receives a heavy hydrocarbon feed 102 and light hydrocarbon feed 104 and directly processes the heavy hydrocarbon feed 102 and light hydrocarbon feed 104 to produce one or more system product streams. The FCC system 100 may include a first FCC reactor 110, a second FCC reactor 120, a third FCC reactor 130, a fourth FCC reactor 140, and a common regenerator 160. These system components and their various arrangements will be described in detail herein.

In embodiments, the heavy hydrocarbon feed 102 may comprise a whole crude oil. The whole crude oil may be a raw hydrocarbon which has not been previously processed, such as through one or more of distillation, cracking, hydroprocessing, desalting, or dehydration. In embodiments, the crude oil may have undergone at least some processing, such as desalting, solids separation, scrubbing, desulfurization, or combinations of these, but has not been subjected to separation by boiling point temperature differences (e.g., distillation). For instance, the crude oil may be a de-salted crude oil that has been subjected to a de-salting process to remove water soluble salts, or the crude oil may be a hydrotreated crude oil that has been subjected to a hydrotreating process to remove contaminants, such as but not limited to sulfur compounds, nitrogen compounds, or other contaminants, from the crude oil. In embodiments, crude oil may not have undergone pretreatment, separation (such as distillation), or other operation that changes the hydrocarbon composition of the crude oil prior to introducing the crude oil to the process. As used herein, the “hydrocarbon composition” of the crude oil refers to the composition of the hydrocarbon constituents of the crude oil and does not include entrained non-hydrocarbon solids, salts, water, or other non-hydrocarbon constituents. In embodiments, the heavy hydrocarbon feed 102 may be one or more heavy oils, such as but not limited to an atmospheric residue, a vacuum residue, a cracker bottom stream, vacuum gas oils, other heavy oils, or combinations of these heavy oils.

The heavy hydrocarbon feed 102 may have an American Petroleum Institute (“API”) gravity of from 10° to 35°, such as an API gravity of from 10° to 33°, from 10° to 30°, from 10° to 28°, from 10° to 26°, from 10° to 24°, from 10° to 22°, from 10° to 20°, from 10° to 18°, from 10° to 16°, from 10° to 14°, from 12° to 35°, from 14° to 35°, from 16° to 35°, from 18° to 35°, from 20° to 35°, from 22° to 35°, from 24° to 35°, from 26° to 35°, from 28° to 35°, from 30° to 35°, from 20° to 30°, or any combination of these ranges. In embodiments, the heavy hydrocarbon feed 102 may be an Arab Heavy Crude Oil (a crude oil having an API gravity of approximately) 26.8°. Example properties of an Arab Heavy Crude Oil are provided in Table 1.

TABLE 1
Arab Heavy Crude Oil properties

Analysis	Units	Value

American Petroleum Institute	Degree	26.8
(API) gravity
Density	grams per cubic centimeter	0.8904
	(g/cm3)
Sulfur Content	weight percent (wt. %)	2.83
Nickel	parts per million by	16.4
	weight (ppmw)
Vanadium	ppmw	56.4
Sodium Chloride (NaCl) Content	ppmw	<5
Conradson Carbon	wt. %	8.2
Residue (CCR)
C5 Asphaltenes	wt. %	7.8
C7 Asphaltenes	wt. %	4.2

In embodiments, the heavy hydrocarbon feed 102 may be an Arab Light Crude Oil (a crude oil having an API gravity of approximately) 33°. Example properties of an Arab Light Crude Oil are provided in Table 2.

TABLE 2
Example of AL Export Crude Oil

Analysis	Units	Value	Test Method

American Petroleum	degree	33.13	ASTM D287
Institute (API) gravity
Density	grams per milliliter	0.8595	ASTM D287
	(g/mL)
Carbon Content	weight percent	85.29	ASTM D5291
	(wt. %)
Hydrogen Content	wt. %	12.68	ASTM D5292
Sulfur Content	wt. %	1.94	ASTM D5453
Nitrogen Content	parts per million	849	ASTM D4629
	by weight (ppmw)
Asphaltenes	wt. %	1.2	ASTM D6560
Micro Carbon Residue	wt. %	3.4	ASTM D4530
(MCR)
Vanadium (V) Content	ppmw	15	IP 501
Nickel (Ni) Content	ppmw	12	IP 501
Arsenic (As) Content	ppmw	0.04	IP 501

Boiling Point Distribution

Initial Boiling Point	Degrees Celsius	33	ASTM D7169
(IBP)	(° C.)
5% Boiling Point (BP)	° C.	92	ASTM D7169
10% BP	° C.	133	ASTM D7169
20% BP	° C.	192	ASTM D7169
30% BP	° C.	251	ASTM D7169
40% BP	° C.	310	ASTM D7169
50% BP	° C.	369	ASTM D7169
60% BP	° C.	432	ASTM D7169
70% BP	° C.	503	ASTM D7169
80% BP	° C.	592	ASTM D7169
90% BP	° C.	>720	ASTM D7169
95% BP	° C.	>720	ASTM D7169
End Boiling Point	° C.	>720	ASTM D7169
(EBP)
BP range C5-180° C.	wt. %	18.0	ASTM D7169
BP range 180° C.-350°	wt. %	28.8	ASTM D7169
C.
BP range 350° C.-540°	wt. %	27.4	ASTM D7169
C.
BP range >540° C.	wt. %	25.8	ASTM D7169
Weight percentages in Table 2 are based on the total weight of the crude oil.

In embodiments, the light hydrocarbon feed 104 may comprise hydrocarbons, such as at least 90 wt. %, at least 95 wt. %, or at least 99 wt. % of hydrocarbons on the basis of the total weight of the light hydrocarbon feed 104. The light hydrocarbon feed 104 may be a light crude oil or a gas condensate. The light hydrocarbon feed 104 may be a raw hydrocarbon which has not been previously processed, such as through one or more of distillation, cracking, hydroprocessing, desalting, or dehydration. In embodiments, the light hydrocarbon feed 104 may have undergone at least some processing, such as desalting, solids separation, scrubbing, desulfurization, or combinations of these, but has not been subjected to distillation. For instance, the light hydrocarbon feed 104 may be a de-salted hydrocarbon feed stream that has been subjected to a de-salting process to remove water soluble salts, or may be a hydrotreated hydrocarbon feed stream that has been subjected to a hydrotreating process but not to a distillation process. In embodiments, light hydrocarbon feed 104 may not have undergone pretreatment, separation (such as distillation), or other operation that changes the hydrocarbon composition of the crude hydrocarbon stream prior to introducing the hydrocarbon stream to the process. The light hydrocarbon feed 104 may have an API gravity of from 38° to 100°, such as from 40° to 100°, from 45° to 100°, from 50° to 100°, from 55° to 100°, from 60° to 100°, from 65° to 100°, from 70° to 100°, from 75° to 100°, from 80° to 100°, from 85° to 100°, from 90° to 100°, from 95° to 100°, from 38° to 95°, from 38° to 90°, from 38° to 85°, from 38° to 80°, from 38° to 75°, from 38° to 70°, from 38° to 65°, from 38° to 60°, from 38° to 55°, from 38° to 50°, from 38° to 45°, or any subset thereof. In embodiments, the light hydrocarbon feed 104 may comprise an Arab Extra Light Crude Oil (a crude oil having an API gravity of approximately) 40.5° or a Khuff Gas Condensate (a gas condensate having an API gravity of approximately) 52.26°.

In embodiments, the light hydrocarbon feed 104 has an API gravity greater than the API gravity of the heavy hydrocarbon feed 102. Generally, heavier hydrocarbon feeds (i.e., those with a lower API gravity) will produce more coke when cracked than lighter hydrocarbon feeds. Therefore, the combination of a light hydrocarbon feed 104 with an API gravity greater than the API gravity of the heavy hydrocarbon feed 102 may enable the operator to tune coke production (and therefore heat production in the common regenerator 160) by selecting feeds with differing API gravities. In embodiments, the API gravity of the light hydrocarbon feed 104 may greater than the API gravity of the heavy hydrocarbon feed 102 by a difference of at least 5°, such as at least 10°, at least 12°, at least 15°, at least 20°, or at least 25°, from 5° to 30°, from 5° to 50°, from 5° to 25°, from 10° to 30°, from 12° to 30°, from 12° to 25°, from 15° to 30°, from 20° to 30°, from 25° to 50°, from 25° to 40°, from 25° to 35°, from 25° to 30°, or any combination of these ranges.

In embodiments, the light hydrocarbon feed 104 may be a naphtha stream, a gas condensate stream, or a combination of these. As used in the present disclosure, the term “naphtha” may refer to an intermediate hydrocarbon composition derived from crude oil refining and having a boiling point temperature of from 35° C. to 200° C. Naphtha streams may include paraffinic, naphthenic, and aromatic hydrocarbons having from 4 to 11 carbon atoms. In embodiments, the light hydrocarbon feed 104 may be a naphtha stream comprising an Arab Extra Light (AXL) feedstock. An example boiling point distribution for an exemplary grade of an AXL crude oil is provided in Table 3.

TABLE 3
Example of AXL feedstock

Property	Units	Value	Test Method

0.1% Boiling Point (BP)	° C.	21	ASTM D7169
5% BP	° C.	65	ASTM D7169
10% BP	° C.	96	ASTM D7169
15% BP	° C.	117	ASTM D7169
20% BP	° C.	141	ASTM D7169
25% BP	° C.	159	ASTM D7169
30% BP	° C.	175	ASTM D7169
35% BP	° C.	196	ASTM D7169
40% BP	° C.	216	ASTM D7169
45% BP	° C.	239	ASTM D7169
50% BP	° C.	263	ASTM D7169
55% BP	° C.	285	ASTM D7169
60% BP	° C.	308	ASTM D7169
65% BP	° C.	331	ASTM D7169
70% BP	° C.	357	ASTM D7169
75% BP	° C.	384	ASTM D7169
80% BP	° C.	415	ASTM D7169
85% BP	° C.	447	ASTM D7169
90% BP	° C.	486	ASTM D7169
95% BP	° C.	537	ASTM D7169
End Boiling Point (EBP)	° C.	618	ASTM D7169

In embodiments, the light hydrocarbon feed 104 may be a gas condensate. Gas condensate (also referred to as natural gas liquids or natural gas condensate) refers to a mixture of relatively low-boiling hydrocarbon liquids obtained by condensation of the vapors of these relatively low-boiling hydrocarbon liquid constituents either in the natural gas well or as the natural gas stream exits from the well. The gas condensate may be mixture of liquid hydrocarbons having a specific gravity of from 0.5 to 0.8 and derived from raw natural gas produced from natural gas fields. Gas condensates may include paraffinic hydrocarbons having from 3 to 12 carbon atoms and lesser amounts of naphthenic and aromatic compounds compared to naphtha streams. Hydrocarbons with greater than 12 carbon atoms may also be present in gas condensates. The gas condensate may include at least 70 weight percent (wt. %), at least 75 wt. %, or even at least 80 wt. % hydrocarbons having a boiling point temperatures less than 265° C. The gas condensates may include the greater boiling hydrocarbons recovered from raw natural gas as a condensate in a natural gas processing plant. In embodiments, the light hydrocarbon feed 104 may be a Khuff gas condensate recovered from natural gas extracted from the Khuff reservoir in Saudi Arabia. Table 4 provides boiling point profile data for Khuff gas condensate.

TABLE 4
Boiling Point Temperature Profile for Khuff Gas Condensate

Boiling Point (BP) Temperature
Range	Weight	Cummulative	Volume

Initial BP	Final BP	Percent	Weight Percent	Percent
(° C.)	(° C.)	wt. %	wt. %	vol. %

C5 (35)	70	12.9	12.9	15.36
70	185	47.32	60.22	48.15
185	265	19.9	80.12	18.79
265	345	12.14	92.26	10.99
345	460	6.87	99.13	6.04
460	565	0.29	99.42	0.25
565	1000	0.56	99.98	0.41

In embodiments, a flowrate of the heavy hydrocarbon feed 102 may be at least 5% greater than the flowrate of the light hydrocarbon feed 104, such as at least 10%, at least 20%, from 5% to 50%, from 5% to 10%, from 10% to 15%, from 15% to 20%, from 20% to 25%, from 25% to 30%, from 30% to 40%, from 40% to 50%, or any combination of these ranges, greater than the flowrate of the light hydrocarbon feed 104.

In embodiments, the heavy hydrocarbon feed 102, the light hydrocarbon feed 104, or both may be preheated before being injected into the FCC reactor. The heavy hydrocarbon feed 102, the light hydrocarbon feed 104, or both may be preheated to a temperature of less than or equal to 350° C., less than or equal to 325° C., less than or equal to 300° C., less than or equal to 275° C., or less than or equal to 250° C. The flowrates of the heavy hydrocarbon feeds 102 and the light hydrocarbon feeds 104 may be regulated by flow controllers through the feed injectors. The pressure of each feed injector may determine the flowrate of the heavy hydrocarbon feed 102 or light hydrocarbon feed 104. The atomized hydrocarbon feed may mix with dispersion steam when injected into the reactor.

Referring now to FIG. 2, various hydrocarbon feed streams to be converted in a conventional FCC process are generally required to satisfy certain criteria in terms of the metals content and the Conradson Carbon Residue (“CCR”) or Ramsbottom carbon content. The CCR of a feed material is a measurement of the residual carbonaceous materials that remain after evaporation and pyrolysis of the feed material. Greater metals content and CCR of a feed stream may lead to more rapid deactivation of the catalyst. For greater levels of CCR, more energy may be needed in the regeneration step to regenerate the catalyst. For example, certain hydrocarbon feeds, such as residual oils, contain refractory components such as polycyclic aromatics, which are difficult to crack and promote coke formation in addition to the coke formed during the catalytic cracking reaction. Because of the greater levels of CCR of these certain hydrocarbon feeds, the burning load on the regenerator is increased to remove the coke and residue from the spent catalysts to transform the spent catalysts to regenerated catalysts. This requires modification of the regenerator to be able to withstand the increased burning load without experiencing material failure. In addition, certain hydrocarbon feeds to the FCC may contain large amounts of metals, such as nickel, vanadium, or other metals for example, which may rapidly deactivate the catalyst during the cracking reaction process. For example, the light hydrocarbon feed may include less than 2.0 wt. % CCR, less than 1.0 wt. % CCR, or less than 0.1 wt. % CCR, whereas the heavy hydrocarbon feed may have more than 2.0 wt. % CCR, or more than 5.0 wt. % CCR.

Referring again to FIG. 1, one or more supplemental feed streams (not shown) may be added to the heavy hydrocarbon feed 102, light hydrocarbon feed 104, or both to introduce the hydrocarbon feeds to their respective reaction zones. In embodiments, one or more supplemental feed streams may be added directly to the first reaction zone 112, the second reaction zone 122, the third reaction zone 132, the fourth reaction zone 142, or combinations thereof. In embodiments, no supplemental feed streams are combined with the heavy hydrocarbon feed 102 or the light hydrocarbon feed 104. As previously described, the supplemental feed stream may include one or more of vacuum residues, tar sands, bitumen, atmospheric residues, vacuum gas oils, demetalized oils, naphtha streams, other hydrocarbon streams, or combinations of these materials.

Referring still to FIG. 1, the heavy hydrocarbon feed 102 may be passed to a first FCC reactor 110 and a second FCC reactor 120. The first FCC reactor 110 may comprise a first reaction zone 112. The second FCC reactor 120 may comprise a second reaction zone 122. The first FCC reactor 110 and the second FCC reactor 120 may be in fluid communication with the heavy hydrocarbon feed 102 to pass the heavy hydrocarbon feed 102 to the first FCC reactor 110 and the second FCC reactor 120. The first FCC reactor 110 and the second FCC reactor 120 may each have one or a plurality of feed injectors (not shown) operable to inject the heavy hydrocarbon feed 102 into the first reaction zone 112 and the second reaction zone 122, respectively.

In embodiments, the light hydrocarbon feed 104 may be passed to a third FCC reactor 130 and a fourth FCC reactor 140. The third FCC reactor 130 may comprise a third reaction zone 132. The fourth FCC reactor 140 may comprise a fourth reaction zone 142. The third FCC reactor 130 and the fourth FCC reactor 140 may be in fluid communication with the light hydrocarbon feed 104 to pass the light hydrocarbon feed 104 to the third FCC reactor 130 and the fourth FCC reactor 140. The third FCC reactor 130 and the fourth FCC reactor 140 may each have one or a plurality of feed injectors (not shown) operable to inject the light hydrocarbon feed 104 into the third reaction zone 132 and the fourth reaction zone 142, respectively. In general, the hydrocarbon feed streams may be passed to the reaction zones where the hydrocarbon feed streams are contacted with a cracking catalyst at reaction conditions to form a reaction mixture comprising spent catalyst and an FCC effluent.

Turning now to the first FCC reactor 110, a first portion 102A of the heavy hydrocarbon feed 102 may be passed to a first FCC reactor 110 that includes a first reaction zone 112. The first portion 102A of the heavy hydrocarbon feed 102 may be added to the first reaction zone 112. The first portion 102A of the heavy hydrocarbon feed 102 may be combined or mixed with a first catalyst in the first reaction zone 112 and cracked to produce a first reaction mixture comprising a first spent catalyst and a first FCC reactor effluent. The first spent catalyst may be separated from the first FCC reactor effluent and passed to a regeneration zone 162 of the common regenerator 160.

A second portion 102B of the heavy hydrocarbon feed 102 may be passed to a second FCC reactor 120 that includes a second reaction zone 122. The second portion 102B of the heavy hydrocarbon feed 102 may be added to the second reaction zone 122. The second portion 102B of the heavy hydrocarbon feed 102 may be combined or mixed with a second catalyst and cracked to produce a second reaction mixture comprising a second spent catalyst and a second FCC reactor effluent. The second spent catalyst may be separated from the second FCC reactor effluent and passed to a regeneration zone 162 of the common regenerator 160.

A first portion 104A of a light hydrocarbon feed 104 may be passed to a third FCC reactor 130 that includes a third reaction zone 132. The first portion 104A of the light hydrocarbon feed 104 may be added to the third reaction zone 132. The first portion 104A of the light hydrocarbon feed 104 may be mixed with a third catalyst and cracked to produce a third reaction mixture comprising a third spent catalyst and a third FCC reactor effluent. The third spent catalyst may be separated from the third FCC reactor effluent and passed to the regeneration zone 162 of the common regenerator 160.

A second portion 104B of the light hydrocarbon feed 104 may be passed to a fourth FCC reactor 140 that includes a fourth reaction zone 142. The second portion 104B of the light hydrocarbon feed 104 may be added to the fourth reaction zone 142. The second portion 104B of the light hydrocarbon feed 104 may be mixed with a fourth catalyst and cracked to produce a fourth reaction mixture comprising a fourth spent catalyst and a fourth FCC reactor effluent. The fourth spent catalyst may be separated from the fourth FCC reactor effluent and passed to the regeneration zone 162 of the common regenerator 160.

In embodiments, steam (not shown) may be introduced to the FCC system 100. In embodiments, steam may be introduced to at least one of the heavy hydrocarbon feed 102 and the light hydrocarbon feed 104. Steam may act as a diluent to reduce a partial pressure of the hydrocarbons in at least one of the heavy hydrocarbon feed 102 and the light hydrocarbon feed 104. Steam may reduce secondary reactions and lead to a high yield of light olefins.

The first spent catalyst, the second spent catalyst, the third spent catalyst, and the fourth spent catalyst may be combined and regenerated in the regeneration zone 162 of the common regenerator 160 to produce a regenerated catalyst 168. In embodiments, the first spent catalyst, the second spent catalyst, the third spent catalyst, and the fourth spent catalyst are combined together prior to being passed to the regeneration zone 162 of the common regenerator 160. The regenerated catalyst 168 may have a catalytic activity that is at least greater than the catalytic activity of the spent catalyst (i.e., the first spent catalyst, the second spent catalyst, the third spent catalyst, and the fourth spent catalyst). The regenerated catalyst 168 may be passed back to the first reaction zone 112, the second reaction zone 122, the third reaction zone 132, and the fourth reaction zone 142 as the first catalyst, the second catalyst, the third catalyst, and the fourth catalyst, respectively. The first reaction zone 112, the second reaction zone 122, the third reaction zone 132, and the fourth reaction zone 142 may be operated in parallel.

It should be understood that, in embodiments, the first catalyst, the second catalyst, the third catalyst, and the fourth catalyst are the same in composition, and the first catalyst, the second catalyst, the third catalyst, and the fourth catalyst may be regenerated in a regeneration zone 162 of a common regenerator 160, as depicted in FIG. 1.

Still referring to FIG. 1, in embodiments, a first reaction mixture exiting the first reaction zone 112 may comprise the first spent catalyst and the first FCC reactor effluent. Similarly, a second reaction mixture exiting the second reaction zone 122 may comprise the second spent catalyst and the second FCC reactor effluent, a third reaction mixture exiting the third reaction zone 132 may comprise the third spent catalyst and the third FCC reactor effluent, and a fourth reaction mixture exiting the fourth reaction zone 142 may comprise the fourth spent catalyst and the fourth FCC reactor effluent. The reaction mixtures exiting the reaction zones may be passed to a common fluid-solid separator 170.

In embodiments, the first FCC reactor effluent, the second FCC reactor effluent, the third FCC reactor effluent, and the fourth FCC reactor effluent may be combined to form an FCC effluent 108. In embodiments, the first FCC reactor effluent, the second FCC reactor effluent, the third FCC reactor effluent, the fourth FCC reactor effluent, or combinations thereof are passed to the fluid-solid separator 170, combined, and separated from the first spent catalyst, second spend catalyst, third spent catalyst, and fourth spent catalyst to form the FCC effluent 108. The FCC effluent 108 may include a mixture of cracked hydrocarbon materials, which may be further separated into one or more greater value petrochemical products and recovered from the system in the one or more system product streams. For example, the FCC effluent 108 may include the petrochemical products. In embodiments, the petrochemical products may be at least one of ethylene, propene, butene, or pentene. In embodiments, the FCC effluent 108 may include one or more of cracked gas oil, cracked gasoline, cracked naphtha, mixed butenes, butadiene, propene, ethylene, other olefins, ethane, methane, other petrochemical products, or combinations of these. The cracked gasoline may be further processed to obtain aromatics such as benzene, toluene, xylenes, or other aromatics for example.

In embodiments, the FCC system 100 may include a product separator 180. The FCC effluent 108 may be introduced to the product separator 180 to be separated into a plurality of system product streams. Referring to FIG. 1, the product separator 180 may be fluidly coupled to the fluid-solid separator 170 to pass the FCC effluent 108 directly from the fluid-solid separator 170 to the product separator 180. The product separator 180 may be a distillation column or collection of separation devices that separates the FCC effluent 108 into one or more system product streams, which may include but are not limited to a fuel oil stream 181, a gasoline stream 182, a mixed butenes stream 183, a butadiene stream 184, a propene stream 185, an ethylene stream 186, a methane stream 187, light cycle oil streams 188 (e.g., streams boiling in the range from 216° C.-343° C.), heavy cycle oil streams 189 (e.g., streams boiling >343° C.), other product streams, or any combinations of these product streams. In embodiments, the product separator 180 may further produce a hydrogen stream 106. Each system product stream may be passed to one or more additional unit operations for further processing, or may be sold as raw goods. As used in this disclosure, the one or more system product streams may be referred to as “petrochemical products”, which may be used as intermediates in downstream chemical processing or packaged as finished products.

In embodiments, the spent catalyst 166 may be passed to the regenerator 160. The regenerator 160 may be fluidly coupled to a catalyst withdrawal well 150. The catalyst withdrawal well 150 may receive the regenerated catalyst 168 from the common regenerator 160.

In embodiments, the catalyst withdrawal well 150 may be a unit capable of distributing at least portions of the regenerated catalyst 168 to the first FCC reactor 110, the second FCC reactor 120, the third FCC reactor 130, and the fourth FCC reactor 140. The regenerated catalyst 168 may accumulate in the catalyst withdrawal well 150 prior to being passed to the first FCC reactor 110, the second FCC reactor 120, the third FCC reactor 130, and the fourth FCC reactor 140. In embodiments, a first regenerated catalyst slide valve 114 may be disposed between the catalyst withdrawal well 150 and the first FCC reactor 110. Similarly, a second regenerated catalyst slide valve 124 may be disposed between the catalyst withdrawal well 150 and the second FCC reactor 120, a third regenerated catalyst slide valve 134 may be disposed between the catalyst withdrawal well 150 and the third FCC reactor 130, and a fourth regenerated catalyst slide valve 144 may be disposed between the catalyst withdrawal well 150 and the fourth FCC reactor 140. The regenerated catalyst slide valves 114, 124, 134, 144 may control the amount of the regenerated catalyst 168 that is passed to each of the reaction zones. A first portion of the regenerated catalyst 168 may be passed to the first FCC reactor 110 as the first catalyst. Similarly, a second portion of the regenerated catalyst 168 may be passed to the second FCC reactor 120 as the second catalyst, a third portion of the regenerated catalyst 168 may be passed to the third FCC reactor 130 as the third catalyst, and a fourth portion of the regenerated catalyst 168 may be passed to the fourth FCC reactor 140 as the fourth catalyst.

In embodiments, the FCC system 100 may be fully automated. The FCC system 100 may detect the coke amount in the spent catalyst 166 exiting the fluid-solid separator 170. The coke amount may be detected by analyzing flue gases 194 exiting the regenerator 160, such as by passing the flue gas 194 through an in-line gas analyzer 198 and analyzing the amount of CO and CO₂ in the flue gas and flow rate of the flue gas 194 with the in-line gas analyzer 198 and calculating the amount of coke removed from the spent catalyst 166 in the regenerator from the amount of CO and CO2 in the flue gas 194 and the flow rate of the flue gas 194. If the amount of coke on the spent catalyst 166 is not sufficient to satisfy the heat balance requirements, the FCC system 100 may adjust the reactor outlet temperature (ROT) of each FCC reactor. The ROT may be controlled by adjusting the catalyst-to-oil ratio of each FCC reactor via the regenerated catalyst slide valves 114, 124, 134, 144 above the FCC reactor. In embodiments, the regenerated catalyst slide valves 114, 124, 134, 144 may automatically open to allow the required amount of catalyst to enter the FCC reactor to achieve a desired ROT to maintain the heat balance of the FCC system 100.

Referring again to FIG. 1, the same type of catalyst may be used throughout the FCC system 100, such as for the first catalyst, the second catalyst, the third catalyst, and the fourth catalyst. The catalyst used in the FCC system 100 may include one or more fluid catalytic cracking catalysts that are suitable for use in the reaction zones. The catalyst may be a heat carrier and may provide heat transfer to the heavy hydrocarbon feed 102 in the first reaction zone 112 and the second reaction zone 122 operated at high-severity conditions and the light hydrocarbon feed 104 in the third reaction zone 132 and the fourth reaction zone 142 operated at high-severity conditions. The catalyst may also have a plurality of catalytically active sites, such as acidic sites for example, that promote the cracking reaction. For example, in embodiments, the catalyst may be a high-activity FCC catalyst having high catalytic activity. Examples of fluid catalytic cracking catalysts suitable for use in the FCC system 100 may include, without limitation, zeolites, silica-alumina catalysts, carbon monoxide burning promoter additives, bottoms cracking additives, light olefin-producing additives, other catalyst additives, or combinations of these components. Zeolites that may be used as at least a portion of the cracking catalyst may include, but are not limited to Y, REY, USY, RE-USY zeolites, or any combinations of these zeolites. The catalyst may also include a shaped selective catalyst additive, such as ZSM-5 zeolite crystals or other pentasil-type catalyst structures, which are often used in other FCC processes to produce light olefins and/or increase FCC gasoline octane. In embodiments, the catalyst may include a mixture of a ZSM-5 zeolite and may have a matrix structure of a typical FCC cracking catalyst. In embodiments, the catalyst may be a mixture of Y and ZSM-5 zeolite catalysts embedded with clay, alumina, and binder.

In embodiments, at least a portion of the catalyst may be modified to include one or more rare earth elements (15 elements of the Lanthanide series of the IUPAC Periodic Table plus scandium and yttrium), alkaline earth metals (Group 2 of the IUPAC Periodic Table), transition metals, phosphorus, fluorine, or any combination of these, which may enhance olefin yield in one or more of the first reaction zone 112, the second reaction zone 122, the third reaction zone 132, the fourth reaction zone 142. Transition metals may include “an element whose atom has a partially filled d sub-shell, or which can give rise to cations with an incomplete d sub-shell” [IUPAC, Compendium of Chemical Terminology, 2nd ed. (the “Gold Book”) (1997). Online corrected version: (2006-) “transition element”]. One or more transition metals or metal oxides may also be impregnated onto the catalyst. Metals or metal oxides may include one or more metals from Groups 6-10 of the IUPAC Periodic Table. In embodiments, the metals or metal oxides may include one or more of molybdenum, rhenium, tungsten, or any combination of these. In embodiments, a portion of the catalyst may be impregnated with tungsten oxide.

In embodiments, the first portion 102A of the heavy hydrocarbon feed 102 may be introduced to a top of the first reaction zone 112. The first reaction zone 112 may be a down flow reactor or “downer” reactor in which the reactants flow vertically downward through the first reaction zone 112 to the fluid-solid separator 170. The first portion 102A of the heavy hydrocarbon feed 102 may be reacted by contact with the first catalyst in the first reaction zone 112 to cause hydrocarbons in the first portion 102A of the heavy hydrocarbon feed 102 to undergo cracking reactions to form at least one cracking reaction product, which may include at least one of the petrochemical products previously described. The first catalyst may have a temperature equal to or greater than the first cracking temperature of the first reaction zone 112 and may transfer heat to the first portion 102A of the heavy hydrocarbon feed 102 to promote the endothermic cracking reactions.

In embodiments, the second portion 102B of the heavy hydrocarbon feed 102 may be introduced to a top of the second reaction zone 122. The second reaction zone 122 may be a down flow reactor or “downer” reactor in which the reactants flow vertically downward through the second reaction zone 122 to the fluid-solid separator 170. The second portion 102B of the heavy hydrocarbon feed 102 may be reacted by contact with the second catalyst in the second reaction zone 122 to cause hydrocarbons in the second portion 102B of the heavy hydrocarbon feed 102 to undergo cracking reactions to form at least one cracking reaction product, which may include at least one of the petrochemical products previously described. The second catalyst may have a temperature equal to or greater than the second cracking temperature of the second reaction zone 122 and may transfer heat to the second portion 102B of the heavy hydrocarbon feed 102 to promote the endothermic cracking reactions.

It should be understood that the first reaction zone 112 of the first FCC reactor 110 and the second reaction zone 122 of the second FCC reactor 120 depicted in FIG. 1 are simplified schematics of one particular embodiment of the first reaction zone 112 and the second reaction zone 122, and other configurations of the first reaction zone 112 and the second reaction zone 122 may be suitable for incorporation into the FCC system 100. For example, in embodiments, the first reaction zone 112, the second reaction zone 122, or both may be an up-flow reaction zone. Other fluidized bed reaction zone configurations are contemplated. The first FCC reactor 110, the second FCC reactor 120, or both may be an FCC reactor in which, in the first reaction zone 112, the fluidized first catalyst contacts the first portion 102A of the heavy hydrocarbon feed 102 under high-severity conditions, and in the second reaction zone 122, the fluidized second catalyst contacts the second portion 102B of the heavy hydrocarbon feed 102 under high-severity conditions. The first cracking temperature of the first reaction zone 112, the second cracking temperature in the second reaction zone 122, or both may be from 500° C. to 800° C., from 500° C. to 700° C., from 500° C. to 650° C., from 500° C. to 600° C., from 550° C. to 800° C., from 550° C. to 700° C., from 550° C. to 650° C., from 550° C. to 600° C., from 600° C. to 800° C., from 600° C. to 700° C., or from 600° C. to 650° C. In embodiments, the first cracking temperature of the first reaction zone 112 and the second cracking temperature of the second reaction zone 122 may both be from 500° C. to 700° C. In embodiments, the first cracking temperature of the first reaction zone 112 and the second cracking temperature of the second reaction zone 122 may both be from 550° C. to 630° C. The first cracking pressure of the first reaction zone 112, the second cracking pressure of the second reaction zone 122, or both may be from 100 kilopascal (kPa) to 15000 kPa, such as from 100 kPa to 10000 kPa, from 100 kPa to 7500 kPa, from 100 kPa to 5000 kPa, from 100 kPa to 2500 kPa, from 100 kPa to 1000 kPa, from 1000 kPa to 15000 kPa, from 1000 kPa to 10000 kPa, from 1000 kPa to 5000 kPa, from 5000 kPa to 15000 kPa, from 5000 kPa to 10000 kPa, from 10000 kPa to 15000 kPa, or any combination of these ranges.

A first catalyst-to-oil weight ratio in the first reaction zone 112 may be from 3:1 to 50:1, from 3:1 to 45:1, from 3:1 to 40:1, from 3:1 to 40:1, from 3:1 to 35:1, from 3:1 to 30:1, from 3:1 to 25:1, from 3:1 to 15:1, from 3:1 to 10:1, from 10:1 to 50:1, from 10:1 to 45:1, from 10:1 to 40:1, from 10:1 to 35:1, from 10:1 to 30:1, from 10:1 to 25:1, from 10:1 to 15:1, from 15:1 to 50:1, from 15:1 to 45:1, from 15:1 to 40:1, from 15:1 to 35:1, from 15:1 to 30:1, from 15:1 to 25:1, from 25:1 to 50:1, from 25:1 to 45:1, from 25:1 to 40:1, from 25:1 to 35:1, from 25:1 to 30:1, from 22:1 to 25:1, from 24:1 to 28:1, from 30:1 to 40:1, or from 40:1 to 50:1. The first catalyst-to-oil weight ratio may be the weight ratio of the first catalyst to the first portion 102A of the heavy hydrocarbon feed 102 introduced to the first reaction zone 112. In embodiments, a second catalyst-to-oil weight ratio in the second reaction zone 122 may be from 3:1 to 50:1, from 3:1 to 45:1, from 3:1 to 40:1, from 3:1 to 40:1, from 3:1 to 35:1, from 3:1 to 30:1, from 3:1 to 25:1, from 3:1 to 15:1, from 3:1 to 10:1, from 10:1 to 50:1, from 10:1 to 45:1, from 10:1 to 40:1, from 10:1 to 35:1, from 10:1 to 30:1, from 10:1 to 25:1, from 10:1 to 15:1, from 15:1 to 50:1, from 15:1 to 45:1, from 15:1 to 40:1, from 15:1 to 35:1, from 15:1 to 30:1, from 15:1 to 25:1, from 25:1 to 50:1, from 25:1 to 45:1, from 25:1 to 40:1, from 25:1 to 35:1, from 25:1 to 30:1, from 22:1 to 25:1, from 24:1 to 28:1, from 30:1 to 40:1, or from 40:1 to 50:1. The second catalyst-to-oil weight ratio may be the weight ratio of the second catalyst to the second portion 102B of the heavy hydrocarbon feed 102 introduced to the second reaction zone 122. The catalyst-to-oil ratio of in the first FCC reactor 110 and the second FCC reactor 120 may be from 3:1 to 50:1.

The residence time of the first portion 102A of the heavy hydrocarbon feed 102 in contact with the first catalyst in the first reaction zone 112 may be from 0.1 seconds (“sec”) to 60 sec, from 0.1 sec to 50 sec, from 0.1 sec to 40 sec, from 0.1 sec to 30 sec, from 0.1 sec to 20 sec, from 0.1 sec to 10 sec, from 0.1 sec to 5 sec, from 0.1 sec to 3 sec, from 0.1 sec to 2 sec, from 3 sec to 60 sec, from 3 sec to 50 sec, from 3 sec to 40 sec, from 3 sec to 30 sec, from 3 sec to 20 sec, from 3 sec to 10 sec, from 10 sec to 60 sec, from 10 sec to 30 sec, from 30 sec to 60 sec, or any combination of these ranges. As used in this disclosure, “residence time” refers to the amount of time that the hydrocarbon feed is in contact with the catalyst at reaction conditions, such as the reaction temperature. The residence time of the second portion 102B of the heavy hydrocarbon feed 102 in contact with the second catalyst in the second reaction zone 122 may be from 0.1 sec to 60 sec, from 0.1 sec to 50 sec, from 0.1 sec to 40 sec, from 0.1 sec to 30 sec, from 0.1 sec to 20 sec, from 0.1 sec to 10 sec, from 0.1 sec to 5 sec, from 0.1 sec to 3 sec, from 0.1 sec to 2 sec, from 3 sec to 60 sec, from 3 sec to 50 sec, from 3 sec to 40 sec, from 3 sec to 30 sec, from 3 sec to 20 sec, from 3 sec to 10 sec, from 10 sec to 60 sec, from 10 sec to 30 sec, from 30 sec to 60 sec, or any combination of these ranges.

The operation of the first reaction zone 112 and the second reaction zone 122 may convert at least some of the hydrocarbons in the heavy hydrocarbon feed 102 into coke, which may be deposited upon the first catalyst and the second catalyst to form the first spent catalyst and the second spent catalyst, respectively. This coke may provide heat to regenerate the first spent catalyst and second spent catalysts. The coke on the first spent catalyst and second spent catalyst may also be sufficient to provide additional heat to aid in regenerating the third spent catalyst and fourth spent catalysts, which have reduced levels of coke, in the common regenerator 160. The operation of the first reaction zone 112, the second reaction zone 122, or both may convert from 5 wt. % to 15 wt. % of the hydrocarbons in the first portion 102A and the second portion 102B of the heavy hydrocarbon feed 102 into coke. In embodiments, the operation of the first reaction zone 112, the second reaction zone 122, or both may convert from 5 wt. % to 6 wt. %, from 6 wt. % to 7 wt. %, from 7 wt. % to 8 wt. %, from 8 wt. % to 9 wt. %, from 9 wt. % to 10 wt. %, from 10 wt. % to 11 wt. %, from 11 wt. % to 12 wt. %, from 12 wt. % to 13 wt. %, from 13 wt. % to 14 wt. %, from 14 wt. % to 15 wt. %, from 6 wt. % to 9 wt. %, from 8 wt. % to 11 wt. %, or any combination of these ranges, of the hydrocarbons in the first portion 102A and the second portion 102B of the heavy hydrocarbon feed 102 into coke.

The light hydrocarbon feed 104 may be passed to the third FCC reactor 130 and the fourth FCC reactor 140. In particular, a first portion 104A of the light hydrocarbon feed 104 may be passed to the third FCC reactor 130, and a second portion 104B of the light hydrocarbon feed 104 may be passed to the fourth FCC reactor 140. As shown in FIG. 1, the first portion 104A of the light hydrocarbon feed 104 may be injected into the third reaction zone 132, and second portion 104B of the light hydrocarbon feed 104 may be injected into the fourth reaction zone 142. The third catalyst and the fourth catalyst may be passed from the catalyst withdrawal well 150 to the third reaction zone 132 and the fourth reaction zone 142, respectively. The third FCC reactor 130 and the fourth FCC reactor 140 may each be a down flow reactor or “downer” reactor in which the reactants flow vertically downward through the third reaction zone 132 and the fourth reaction zone 142, respectively, to the fluid-solid separator 170. The third catalyst and the fourth catalyst may have a temperature equal to or greater than the third cracking temperature in the third reaction zone 132 and the fourth cracking temperature in the fourth reaction zone 142, and may transfer heat to the first portion 104A and the second portion 104B of the light hydrocarbon feed 104 to promote the endothermic cracking reactions.

It should be understood that the third reaction zone 132 of the third FCC reactor 130 and the fourth reaction zone 142 of the fourth FCC reactor 140 depicted in FIG. 1 are simplified schematics of one particular embodiment of the third reaction zone 132 and the fourth reaction zone 142, and other configurations of the third reaction zone 132 and fourth reaction zone 142 may be suitable for incorporation into the FCC system 100. For example, in embodiments, the third reaction zone 132, the fourth reaction zone 142, or both may be up-flow reaction zones. Other reaction zone configurations are contemplated. The third FCC reactor 130, the fourth FCC reactor, or both may be an FCC reactor in which, in the third reaction zone 132, the third catalyst contacts the first portion 104A of the light hydrocarbon feed 104 at high-severity conditions, and in the fourth reaction zone 142, the fourth catalyst contacts the second portion 104B of the light hydrocarbon feed 104 at high-severity conditions. The third cracking temperature of the third reaction zone 132, the fourth cracking temperature of the fourth reaction zone 142, or both may be from 500° C. to 800° C., from 500° C. to 700° C., from 500° C. to 650° C., from 500° C. to 600° C., from 550° C. to 800° C., from 550° C. to 700° C., from 550° C. to 650° C., from 550° C. to 600° C., from 600° C. to 800° C., from 600° C. to 700° C., or from 600° C. to 650° C. In embodiments, the third cracking temperature of the third reaction zone 132, the fourth cracking temperature of the fourth reaction zone 142, or both may be from 500° C. to 700° C. In embodiments, the third cracking temperature of the third reaction zone 132, the fourth cracking temperature of the fourth reaction zone 142, or both may be from 550° C. to 630° C. In embodiments, the third cracking temperature of the third reaction zone 132 and the fourth cracking temperature of the fourth reaction zone 142 may be different from the first cracking temperature of the first reaction zone 112, the second reaction temperature of the second reaction zone 122, or both. In embodiments, the third cracking temperature of the third reaction zone 132, the fourth reaction temperature of the fourth reaction zone 142, or both may be within 100° C., such as within 90° C., within 80° C., within 70° C., within 60° C., within 50° C., within 40° C., within 30° C., within 20° C., within 10° C., or within 5° C. of the first cracking temperature of the first reaction zone 112, the second reaction temperature of the second reaction zone, or both.

The third cracking pressure of the third reaction zone 132, the fourth cracking pressure of the fourth reaction zone 142, or both may be from 100 kilopascal (kPa) to 15000 kPa, such as from 100 kPa to 10000 kPa, from 100 kPa to 7500 kPa, from 100 kPa to 5000 kPa, from 100 kPa to 2500 kPa, from 100 kPa to 1000 kPa, from 1000 kPa to 15000 kPa, from 1000 kPa to 10000 kPa, from 1000 kPa to 5000 kPa, from 5000 kPa to 15000 kPa, from 5000 kPa to 10000 kPa, from 10000 kPa to 15000 kPa, or any combination of these ranges.

A third catalyst-to-oil weight ratio in the third reaction zone 132 may be from 3:1 to 50:1, from 3:1 to 45:1, from 3:1 to 40:1, from 3:1 to 40:1, from 3:1 to 35:1, from 3:1 to 30:1, from 3:1 to 25:1, from 3:1 to 15:1, from 3:1 to 10:1, from 10:1 to 50:1, from 10:1 to 45:1, from 10:1 to 40:1, from 10:1 to 35:1, from 10:1 to 30:1, from 10:1 to 25:1, from 10:1 to 15:1, from 15:1 to 50:1, from 15:1 to 45:1, from 15:1 to 40:1, from 15:1 to 35:1, from 15:1 to 30:1, from 15:1 to 25:1, from 25:1 to 50:1, from 25:1 to 45:1, from 25:1 to 40:1, from 25:1 to 35:1, from 25:1 to 30:1, from 22:1 to 25:1, from 24:1 to 28:1, from 30:1 to 40:1, or from 40:1 to 50:1. The third catalyst-to-oil weight ratio may be a weight ratio of the third catalyst to the first portion of the light hydrocarbon feed 104 introduced to the third reaction zone 132. In embodiments, a fourth catalyst-to-oil weight ratio in the fourth reaction zone 142 may be from 3:1 to 50:1, from 3:1 to 45:1, from 3:1 to 40:1, from 3:1 to 40:1, from 3:1 to 35:1, from 3:1 to 30:1, from 3:1 to 25:1, from 3:1 to 15:1, from 3:1 to 10:1, from 10:1 to 50:1, from 10:1 to 45:1, from 10:1 to 40:1, from 10:1 to 35:1, from 10:1 to 30:1, from 10:1 to 25:1, from 10:1 to 15:1, from 15:1 to 50:1, from 15:1 to 45:1, from 15:1 to 40:1, from 15:1 to 35:1, from 15:1 to 30:1, from 15:1 to 25:1, from 25:1 to 50:1, from 25:1 to 45:1, from 25:1 to 40:1, from 25:1 to 35:1, from 25:1 to 30:1, from 22:1 to 25:1, from 24:1 to 28:1, from 30:1 to 40:1, or from 40:1 to 50:1. The fourth catalyst-to-oil weight ratio may be a weight ratio of the fourth catalyst to the second portion of the light hydrocarbon feed 104 introduced to the fourth reaction zone 132.

In embodiments, the third catalyst-to-oil weight ratio in the third reaction zone 132 and the fourth catalyst-to-oil weight ratio in the fourth reaction zone 142 may be different than the first catalyst-to-oil weight ratio in the first reaction zone 112, the second catalyst-to-oil weight ratio in the second reaction zone 122, or both. In embodiments, the third catalyst-to-oil weight ratio, the fourth catalyst-to-oil weight ratio, or both may be greater than the first catalyst-to-oil weight ratio, the second catalyst-to-oil weight ratio, or both. In embodiments, the third catalyst-to-oil weight ratio, the fourth catalyst-to-oil weight ratio, or both may be greater than the first catalyst-to-oil weight ratio, the second catalyst-to-oil weight ratio, or both. In embodiments, third catalyst-to-oil weight ratio, the fourth catalyst-to-oil weight ratio, or both may be about equal to the first catalyst-to-oil weight ratio, the second catalyst-to-oil weight ratio, or both.

The residence time of the first portion 104A of the light hydrocarbon feed 104 in contact with the third catalyst in the third reaction zone 132 may be from 0.1 seconds (“sec”) to 60 sec, from 0.1 sec to 50 sec, from 0.1 sec to 40 sec, from 0.1 sec to 30 sec, from 0.1 sec to 20 sec, from 0.1 sec to 10 sec, from 0.1 sec to 5 sec, from 0.1 sec to 3 sec, from 0.1 sec to 2 sec, from 3 sec to 60 sec, from 3 sec to 50 sec, from 3 sec to 40 sec, from 3 sec to 30 sec, from 3 sec to 20 sec, from 3 sec to 10 sec, from 10 sec to 60 sec, from 10 sec to 30 sec, from 30 sec to 60 sec, or any combination of these ranges. The residence time of the second portion 104B of the light hydrocarbon feed 104 in contact with the fourth catalyst in the fourth reaction zone 142 may be from 0.1 sec to 60 sec, from 0.1 sec to 50 sec, from 0.1 sec to 40 sec, from 0.1 sec to 30 sec, from 0.1 sec to 20 sec, from 0.1 sec to 10 sec, from 0.1 sec to 5 sec, from 0.1 sec to 3 sec, from 0.1 sec to 2 sec, from 3 sec to 60 sec, from 3 sec to 50 sec, from 3 sec to 40 sec, from 3 sec to 30 sec, from 3 sec to 20 sec, from 3 sec to 10 sec, from 10 sec to 60 sec, from 10 sec to 30 sec, from 30 sec to 60 sec, or any combination of these ranges. In embodiments, the residence time in the third reaction zone 132 and the fourth reaction zone 142 may be different from the residence time in the first reaction zone 112 and the second reaction zone 122. In embodiments, the residence time in the third reaction zone 132 and the fourth reaction zone 142 may be about equal to than the residence time in the first reaction zone 112 and the second reaction zone 122.

The operation of the third reaction zone 132 and the operation of the fourth reaction zone 142 may convert at least some of the hydrocarbons in the first portion 104A and second portion 104B of the light hydrocarbon feed 104 into coke, which may be deposited upon the third catalyst to form the third spent catalyst and the fourth catalyst to form the fourth spent catalyst. The combustion of this coke may provide insufficient heat to regenerate the third and fourth spent catalysts in the common regenerator 160. However, the lower amounts of coke on the third spent catalyst and the fourth spent catalyst may reduce or prevent overheating the common regenerator 160 due to the excess coke on the first spent catalyst and second spent catalyst. The operation of the third reaction zone 132 and the fourth reaction zone 142 may each convert from 1 wt. % to 7 wt. % of the hydrocarbons in the first portion 104A and the second portion 104B, respectively, of the light hydrocarbon feed 104 into coke. In embodiments, the operation of the third reaction zone 132 and the fourth reaction zone 142 may each convert from 1 wt. % to 2 wt. %, from 2 wt. % to 3 wt. %, from 3 wt. % to 4 wt. %, from 5 wt. % to 6 wt. %, from 6 wt. % to 7 wt. %, from 4 wt. % to 7 wt. %, from 1.5 wt. % to 4.5 wt. %, or any combination of these ranges, of the hydrocarbons in the first portion 104A of the light hydrocarbon feed 104 and the second portion 104B of the light hydrocarbon feed 104, respectively, into coke. In embodiments, the operation of the first reaction zone 112 and the second reaction zone 122 may convert a greater percentage of hydrocarbons in the heavy hydrocarbon feed 102 into coke compared to the percentage of hydrocarbons in the light hydrocarbon feed 104 converted to coke through operation of the third reaction zone 132 and the fourth reaction zone 142. In embodiments, the operation of the first reaction zone 112 and the second reaction zone 122 may each convert at least 1 wt. %, at least 2 wt. %, at least 3 wt. %, at least 5 wt. %, from 1 wt. % to 2 wt. %, from 2 wt. % to 3 wt. %, from 3 wt. % to 4 wt. %, from 4 wt. % to 5 wt. %, from 5 wt. % to 6 wt. %, from 6 wt. % to 7 wt. %, from 1 wt. % to 3 wt. %, from 2 wt. % to 4 wt. %, from 5 wt. % to 7 wt. %, or any combination of these ranges more of the heavy hydrocarbon feed 102 into coke compared to the percentage of hydrocarbons in the light hydrocarbon feed 104 converted to coke through operation of the third reaction zone 132 and the fourth reaction zone 142.

As stated, following the cracking reaction in the first reaction zone 112, the first reaction mixture from the first reaction zone 112 may include the first spent catalyst and the first FCC reactor effluent and may be passed to the fluid-solid separator 170. Likewise, following the cracking reactions in the second reaction zone 122, the second reaction mixture from the second reaction zone 122 may include the second spent catalyst and the second FCC reactor effluent and may be passed to the fluid-solid separator 170. Following the cracking reaction in the third reaction zone 132, the third reaction mixture from the third reaction zone 132 may include the third spent catalyst and the third FCC reactor effluent and may be passed to the fluid-solid separator 170. Likewise, following the cracking reaction in the fourth reaction zone 142, the fourth reaction mixture from the fourth reaction zone 142 may include the fourth spent catalyst and the fourth FCC reactor effluent and may be passed to the fluid-solid separator 170.

The fluid-solid separator 170 may comprise a disengager 172 and a stripper 174. The disengager 172 may comprise one or more gas-solid separators, such as one or more cyclones, for a rapid disengagement of the spent catalyst from the FCC reactor effluents. The separated spent catalyst may then be passed to the stripper 174 for stripping residual FCC reactor effluent from the spent catalyst. In the fluid-solid separator 170, the reaction mixtures from the four reaction zones (112, 122, 132, 142) that each include spent catalyst and FCC reactor effluent may be combined together in the disengager 172. In the disengager 172, at least a portion of the FCC effluent 108 may be separated from the spent catalyst. The spent catalyst exiting from the disengager 172 may retain a residual portion of the FCC effluent 108.

After the disengager 172, the combined spent catalyst, which may include the residual portion of the FCC effluent 108, may be passed to the stripper 174, where at least some of the residual portion of the FCC effluent 108 may be stripped from the spent catalyst and recovered as a stripped product stream (not shown). The stripped product stream may be passed to one or more than one downstream unit operations or combined with one or more than one other streams for further processing. Steam (not shown) may be introduced to the stripper 174 to facilitate stripping the FCC effluent 108 from the catalyst. The stripped product stream may include at least a portion of the steam introduced to the stripper 174. The stripped product stream may be discharged from the stripper 174 and may be passed through cyclone separators (not shown) and out of the stripper 174. The stripped product stream may be directed to one or more product recovery systems in accordance with known methods in the art, or may be recycled by combining with steam. The stripped product stream may also be combined with one or more other streams, such as the FCC effluent 108, for example.

The spent catalyst 166, which is the catalyst after stripping out the stripped product stream, may be passed from the stripper 174 to the regeneration zone 162 of the common regenerator 160 to be regenerated to produce regenerated catalyst 168. A spent catalyst slide valve 176 may control the amount of spent catalyst 166 that is passed to the regeneration zone 162 of the common regenerator 160.

Referring still to FIG. 1, as stated hereinabove, the first FCC reactor 110, the second FCC reactor 120, the third FCC reactor 130, and the fourth FCC reactor 140 may share a common regenerator 160. This use of a common regenerator 160, in combination with tailored hydrocarbon feeds, may enable heat balance in the regenerator such that no supplemental fuels, coking agents, or catalyst coolers may be necessary. The spent catalyst 166 may be passed to the common regenerator 160, where the spent catalyst 166 is regenerated to produce the regenerated catalyst 168. The common regenerator 160 may include the regeneration zone 162, a catalyst reactor 164, a catalyst separator 190, and a flue gas vent 192. The catalyst reactor 164 may be fluidly coupled to the regeneration zone 162 and the catalyst separator 190 for passing the regenerated catalyst 168 from the regeneration zone 162 to the catalyst separator 190.

In embodiments, less than 1 wt. % of supplemental fuels may be added to the common regenerator 160, on the basis of the total weight of spent catalyst 166 passed to the common regenerator 160. Supplemental fuels are any fuels added to the common regenerator 160 to provide additional heat to regenerate the catalyst, above the heat provided the coke on the spent catalyst 166. The use of supplemental fuels may increase the cost of operating an FCC system and may increase the complexity of the FCC system. In embodiments, less than 0.5 wt. %, less than 0.1 wt. %, less than 0.01 wt. % of supplemental fuels may be added to the common regenerator 160, on the basis of the total weight of spent catalyst 166 passed to the common regenerator 160.

In operation, the spent catalyst 166 may be passed from the stripper 174 of the fluid-solid separator 170 to the regeneration zone 162. Combustion gases 196 may be introduced to the regeneration zone 162. The combustion gases 196 may include one or more of combustion air, oxygen, or combinations of these. In the regeneration zone 162, the coke deposited on the spent catalyst 166 may at least partially oxidize (combust) in the presence of the combustion gases 196 to form at least carbon dioxide and water. In embodiments, the coke deposits on the spent catalyst 166 may be fully oxidized in the regeneration zone 162. Other organic compounds, such as any remaining residual FCC effluent 108 retained in the spent catalyst, for example, may also oxidize in the presence of the combustion gases 196 in the regeneration zone 162. Other gases, such as carbon monoxide for example, may be formed during coke oxidation in the regeneration zone 162. Oxidation of the coke deposits produces heat, which may be transferred to and retained by the regenerated catalyst 168.

The common regenerator 160 for regenerating the spent catalyst 166 may improve the overall efficiency of the FCC system 100. For example, cracking of the first portion 104A and the second portion 104B of the light hydrocarbon feed 104 in the third FCC reactor 130 and the fourth FCC reactor 140, respectively, may produce less coke deposits on the third catalyst and the fourth catalyst compared to cracking of the heavy hydrocarbon feed 102 in the first FCC reactor 110 and the second FCC reactor 120. Combustion of the coke deposits on the spent catalyst from the third reaction zone 132 and the fourth reaction zone 142 during regeneration produces heat, but the amount of coke present on the these spent catalysts may not be sufficient to produce enough heat to conduct the cracking reactions in the third reaction zone 132 or the fourth reaction zone 142. Thus, regeneration of the spent catalyst from the third reaction zone 132 and the fourth reaction zone 142 by itself may not produce enough heat to raise the temperature of the regenerated catalyst 168 to an acceptable cracking temperature in the third reaction zone 132 and the fourth reaction zone 142.

By comparison, the amount of coke formed and deposited on the first catalyst and the second catalyst during cracking of the first portion 102A and the second portion 102B of the heavy hydrocarbon feed 102 in the first FCC reactor 110 and the second FCC reactor 120, respectively, may be excessive and require the use of catalyst coolers in order to prevent the temperature of the regenerated catalyst 168 from being outside the range preferred to produce olefins or prevent material failures, were the first FCC reactor 110 and second FCC reactor 120 operated in isolation. Generally, catalyst coolers refer to physical devices, such as heat exchangers, used to cool catalyst particles. The amount of coke deposited on the first spent catalyst and second spent catalyst may be substantially greater than the coke deposits on the third spent catalyst and fourth spent catalyst produced in the third reaction zone 132 and the fourth reaction zone 142, respectively. As such, combustion of the coke deposits on the first spent catalyst and the second spent catalyst during catalyst regeneration may produce sufficient heat to raise the temperature of the regenerated catalyst 168 to high-severity conditions. The high-severity conditions may comprise a regenerated catalyst temperature equal to or greater than the cracking temperature of the first FCC reactor 110 and the second FCC reactor 120 or the cracking temperature of the third FCC reactor 130 and the fourth FCC reactor 140. The amount of coke deposited on the first and second catalysts may provide the heat required to conduct the cracking reactions in all four reaction zones 112, 122, 132, 142.

In embodiments, the flue gases 194 may convey the regenerated catalyst 168 through the catalyst reactor 164 from the regeneration zone 162 to the catalyst separator 190. The catalyst reactor 164 may act as an upflow fluidized bed reactor that facilitates contact between the spent catalyst 166 and the oxygen-containing gas to regenerate the spent catalyst 166. The regenerated catalyst 168 may accumulate in the catalyst separator 190 prior to passing from the catalyst separator 190 to the catalyst withdrawal well 150. The catalyst separator 190 may act as a fluid-solid separator that separates the flue gas 194 and combustion gases 196 from the regenerated catalyst 168. In embodiments, the flue gas 194 may pass out of the catalyst separator 190 through a flue gas vent 192 disposed in the catalyst separator 190.

The regenerated catalyst 168 passing out of the regeneration zone 162 may have less than 1 wt. % coke deposits, based on the total weight of the regenerated catalyst 168. In embodiments, the regenerated catalyst 168 passing out of the regeneration zone 162 may have less than 0.5 wt. %, less than 0.1 wt. %, or less than 0.05 wt. % coke deposits. In embodiments, the regenerated catalyst 168 passing out of the regeneration zone 162 may have from 0.001 wt. % to 1 wt. %, from 0.001 wt. % to 0.5 wt. %, from 0.001 wt. % to 0.1 wt. %, from 0.001 wt. % to 0.05 wt. %, from 0.005 wt. % to 1 wt. %, from 0.005 wt. % to 0.5 wt. %, from 0.005 wt. % to 0.1 wt. %, from 0.005 wt. % to 0.05 wt. %, from 0.01 wt. % to 1 wt. %, from 0.01 wt. % to 0.5 wt. % to 0.01 wt. % to 0.1 wt. %, from 0.01 wt. % to 0.05 wt. % coke deposits, based on the total weight of the regenerated catalyst 168. In embodiments, the regenerated catalyst 168 passing out of regeneration zone 162 may be substantially free of coke deposits. As used in this disclosure, the term “substantially free” of a component means less than 1 wt. % of that component in a particular portion of a catalyst, stream, or reaction zone. As an example, the regenerated catalyst 168 that is substantially free of coke deposits may have less than 1 wt. % of coke deposits. Removal of the coke deposits from the regenerated catalyst 168 in the regeneration zone 162 may remove the coke deposits from the catalytically active sites, such as acidic sites for example, of the catalyst that promote the cracking reaction. Removal of the coke deposits from the catalytically active sites on the catalyst may increase the catalytic activity of the regenerated catalyst 168 compared to the spent catalyst 166. Thus, the regenerated catalyst 168 may have a catalytic activity that is greater than the spent catalyst 166.

The regenerated catalyst 168 may absorb at least a portion of the heat generated from combustion of the coke deposits. The heat may increase the temperature of the regenerated catalyst 168 compared to the temperature of the spent catalyst 166. The regenerated catalyst 168 may accumulate in the catalyst withdrawal well 150 until it is passed back to the first FCC reactor 110 as at least a portion of the first catalyst, the second FCC reactor 120 as at least a portion of the second catalyst, the third FCC reactor 130 as at least a portion of the third catalyst, and the fourth FCC reactor 140 as at least a portion of the fourth catalyst. The regenerated catalyst 168 in the catalyst withdrawal well 150 may have a temperature that is equal to or greater than the cracking temperature in the first and second reaction zones, the cracking temperature in the third and fourth reaction zones, or both. The greater temperature of the regenerated catalyst 168 may provide heat for the endothermic cracking reactions in the first reaction zone 112, the second reaction zone 122, the third reaction zone 132, and the fourth reaction zone 142.

As previously discussed, the heavy hydrocarbon feed 102 and light hydrocarbon feed 104, can have a wide range of compositions and a wide range of boiling points. Because of the difference of compositions, each of the heavy hydrocarbon feed 102 and the light hydrocarbon feed 104 may benefit from different operating temperatures and catalyst activities to produce desired yields of one or more petrochemical products or increase the selectivity of the reaction for certain products. For example, the heavy hydrocarbon feed 102 may be more reactive and, thus, may require less cracking activity than the light hydrocarbon feed 104 to produce sufficient yields of or selectivity for a specific petrochemical product. However, the light hydrocarbon feed 104 may produce insufficient coke to operate the regenerator. The lesser cracking activity suitable for the heavy hydrocarbon feed 102 may be provided by reducing the first cracking temperature in the first reaction zone 112, reducing the second cracking temperature in the second reaction zone 122, or combinations thereof. In contrast, the light hydrocarbon feed 104 may be less reactive and may require greater catalytic activity, such as by increasing the third cracking temperature in the third reaction zone 132, increasing the fourth cracking temperature in the fourth reaction zone 142, or combinations thereof, compared to the heavy hydrocarbon feed 102 to produce sufficient yields of or selectivity for the specific petrochemical products. However, cracking the heavy hydrocarbon feed 102 alone may produce excess coke, requiring catalyst coolers.

It should be understood that the FCC system 100 may include a common regenerator 160 to regenerate the spent catalyst 166 to produce the regenerated catalyst 168. Therefore, the regenerated catalyst 168 passed to the first FCC reactor 110 is the same as and has the same catalytic effectiveness and temperature as the regenerated catalyst 168 passed to the second FCC reactor 120, the third FCC reactor 130, and the fourth FCC reactor 140. However, as previously discussed, the reaction conditions in the first FCC reactor 110, the second FCC reactor 120, the third FCC reactor 130, or the fourth FCC reactor 140 for producing sufficient yields of or selectivity for specific petrochemical products may be different than the reaction conditions provided by passing the regenerated catalyst 168 to the first FCC reactor 110, the second FCC reactor 120, the third FCC reactor 130, or the fourth FCC reactor 140.

As previously discussed, the FCC system 100 may be fully automated to control the flow rate of regenerated catalyst 168 to each of the first FCC reactor 110, the second FCC reactor 120, the third FCC reactor 130, the fourth FCC reactor 140, or combinations of these FCC reactors based on the heat requirements of the FCC system 100. Referring again to FIG. 1, the FCC system 100 may further include a control system 300 having one or a plurality of processors 302, one or a plurality of memory modules 304 communicatively coupled to the processors 302, and machine readable and executable instructions 306 stored on the memory modules 304. The control system 300 may be communicatively coupled to the in-line gas analyzer 198 through which the flue gas 168 is passed downstream of the regenerator 160. The in-line gas analyzer 198 may be configured to analyze the flue gas 168 and send electronic signals to the control system 300, where the electronic signals are indicative of a flow rate of the flue gas 168, the concentrations of one or more constituents of the glue gas 168, or both. In embodiments, the electronic signals may be indicative of a flow rate of the flue gas 168 and a concentration of CO, CO₂, or both in the flue gas 168. The control system 300 may also be communicatively coupled to one or more of the regenerated catalyst slide valves 114, 124, 134, 144.

The control system 300 may be configured, such as through the machine readable and executable instructions 306, to automatically receive the electronic signals from the in-line gas analyzer 198 in the flue gas 168 and determine an amount of coke combusted and removed from the spent catalyst 166. The control system 300 may determine whether the amount of coke combusted and removed from the spent catalyst 166 is sufficient to satisfy the heat balance requirements of the FCC system 100. In embodiments, determining whether the amount of coke combusted and removed from the spent catalyst 166 is sufficient to satisfy the heat balance requirements of the FCC system 100 may include comparing the amount of coke combusted and removed from the spent catalyst 166 to a threshold amount of coke, which is amount of coke needed to perfectly heat balance the FCC system 100.

The control system 300 may be configured, such as through machine readable and executable instructions 306, to automatically control one or more of the regenerated catalyst slide valves 114, 124, 134, 144 in response to the determination of whether the amount of coke combusted and removed from the spent catalyst 166 is sufficient to satisfy the heat balance requirements of the FCC system 100. Adjusting one or more of the regenerated catalyst slide valves 114, 124, 134, 144 may change the reactor outlet temperature (ROT) for one or more of the first FCC reactor 110, the second FCC reactor 120, the third FCC reactor 130, the fourth FCC reactor 140, or combinations thereof, which may in turn change the amount of coke produced and deposited on the spent catalyst 166. For instance, if the amount of coke combusted and removed from the spent catalyst 166 is less than the threshold amount of coke, the control system 306 may be configured to automatically increase the flow rate of the regenerated catalyst 168 to the first FCC reactor the second FCC reactor 120, the third FCC reactor 130, the fourth FCC reactor 140, or combinations thereof, which may increase the ROT and increase the amount of coke produced and deposited on the spent catalyst 166 in the FCC reactors. Likewise, if the amount of coke combusted and removed from the spent catalyst 166 is greater than the threshold amount of coke, the control system 306 may be configured to automatically decrease the flow rate of the regenerated catalyst 168 to the first FCC reactor the second FCC reactor 120, the third FCC reactor 130, the fourth FCC reactor 140, or combinations thereof, which may decrease the ROT and decrease the amount of coke produced and deposited on the spent catalyst 166 in the FCC reactors. The control system 300 may be configured to send one or more control signals to one or more of the regenerated catalyst slide valves 114, 124, 134, 144, where the control signals may be indicative of positions of the regenerated catalyst slide valves 114, 124, 134, 144.

The machine readable and executable instructions 306, when executed by the processors 302, may cause the control system 300 to automatically perform the following: receive electronic signals from the in-line gas analyzer 198 in the flue gas 168, where electronic signals may be indicative of a flow rate of the flue gas 168 and a concentration of CO, CO2, or both in the flue gas 168; determine an amount of coke combusted and removed from the spent catalyst 166 in the regenerator 166; and control one or more of the regenerated catalyst slide valves 114, 124, 134, 144 in response to the amount of coke combusted and removed from the spent catalyst 166 in the regenerator 166. In embodiments, the machine readable and executable instructions 306, when executed by the processors 302, may automatically cause the control system 300 to determine whether the amount of coke combusted and removed from the spent catalyst 166 is sufficient to satisfy the heat balance requirements of the FCC system 100 based on the amount of coke combusted and removed from the spent catalyst 166. In embodiments, the machine readable and executable instructions 306, when executed by the processors 302, may automatically cause the control system 300 to compare the amount of coke combusted and removed from the spent catalyst 166 to a threshold amount of coke and determine whether the amount of coke combusted and removed from the spent catalyst 166 is sufficient from the comparison.

Referring to FIG. 1, as previously discussed, the control system 300 may include the one or more processors 302 and one or more memory modules 304. The one or more processors 302 may include any device capable of executing computer-readable executable instructions stored on a non-transitory computer-readable medium. Accordingly, each processor 302 may include an integrated circuit, a microchip, programmable logic controller, a computer, and/or any other computing device. The one or more memory modules 304 are communicatively coupled to the one or more processors 302 over a communication path. The communication path may be wired or wireless. The communication path may be electronic, optical, electromagnetic, or other type of communication. The one or more memory modules 304 may be configured as volatile and/or nonvolatile memory and, as such, may include random access memory (including SRAM, DRAM, and/or other types of RAM), flash memory, secure digital (SD) memory, registers, compact discs (CD), digital versatile discs (DVD), and/or other types of non-transitory computer-readable mediums. The one or more memory modules 304 may be configured to store machine readable and executable instructions 306 for operating one or more components of the FCC system 100.

Embodiments of the present disclosure include logic stored on the one or more memory modules 304 that includes machine-readable and executable instructions or an algorithm written in any programming language of any generation (e.g., 1GL, 2GL, 3GL, 4GL, and/or 5GL) such as, machine language that may be directly executed by the one or more processors 302, assembly language, obstacle-oriented programming (OOP), scripting languages, microcode, etc., that may be compiled or assembled into machine readable instructions and stored on a machine readable medium. Similarly, the logic and/or algorithm may be written in a hardware description language (HDL), such as logic implemented via either a field-programmable gate array (FPGA) configuration or an application-specific integrated circuit (ASIC), and their equivalents. Accordingly, the logic may be implemented in any conventional computer programming language, as pre-programmed hardware elements, and/or as a combination of hardware and software components.

EXAMPLES

The various embodiments of methods and systems for the conversion of a feedstock fuels will be further clarified by the following examples. The examples are illustrative in nature, and should not be understood to limit the subject matter of the present disclosure.

In both of the following Example A and Example B, a catalyst blend was utilized. The catalyst blend comprising a blend of 75 wt. % HS-FCC/5a (purchased from JGC Catalysts and Chemicals LTD) and 25 wt. % OlefinsUltra® (purchased from W.R. Grace and Co.) was prepared by physical blending. Prior to the experiment, the catalyst was steam deactivated at 810° C. for 6 hours to mimic the equilibrium catalyst in the commercial process.

Properties of the feeds utilized are given in Table 5, where KGC refers to a Khuff Gas Condensate, AXL refers to an Arab Extra Light Crude Oil, and AH refers to an Arab Heavy Crude Oil. “Watson K”, or the Watson characterization factor, is calculated using the average boiling point and specific gravity of the hydrocarbon feed and is used to classify oils based on their hydrocarbon types.

	TABLE 5
	KGC	AXL	AH

Density @ 15.6° C. (g/cm3)	0.7707	0.8234	0.8947
Specific Gravity (at 60° F.)	0.770026	0.8227	0.2939
MeABP Mean Average Boiling	151.76	493.87	695.94
Point (MeABP) (° F.)
Watson K	11.02	11.96	11.74
Molecular Weight (g/mol)	83.27	201.29	304.14
API Gravity	52.26	40.5	26.80

Referring now to FIG. 3, the operation of each of the reaction zones was simulated individually utilizing a micro downer unit (MDU), manufactured by Amtech. FIG. 3 schematically depicts a micro downer unit 200 as used to simulate the examples herein. The micro downer unit 200 generally comprises a catalyst hopper 210, a reactor 220, and a stripper 230.

To prepare for the experiment, catalyst was loaded into the catalyst hopper 210 and liquid traps 240 were set. The hydrocarbon feed 202 was loaded into a syringe 215. Then, nitrogen gas (N₂) 204 and air (not shown) were supplied to the syringe 215. Next, the heating system was started for the catalyst hopper 210, the reactor 220, and the stripper 230. The temperatures and pressures of each unit were allowed to equilibrate to their corresponding set points. A reaction mixture 232 exited the stripper 230. Liquid product was collected in the liquid traps 240 and gas products 242 were sent to a gas chromatograph (GC) for analysis. The liquid product collected were sent for SimDist analysis to determine the composition of the reaction products. The coke content was measured by catalyst combustion through measuring the released carbon dioxide (CO₂) 236 that exited the vent 234. The results of the simulation using different hydrocarbon feeds are shown in Table 6.

TABLE 6
Feed	KGC	AXL	AH

Temperature (° C.)	647	651	645
Catalyst-to-oil ratio	30	32	33

Residence time (sec)	~2
Catalyst code	UMix75 (steam deactivated at 810° C. for 6 hours)

Yields (wt. %)
H2—C2 (dry gas)	4	9	9
C2═	8	12	11
C3═	16	22	23
C4═	9	10	11
Total light olefins	33	45	46
Gasoline	51	30	28
Coke	1.3	5	8

In Examples A and B, the required coke and catalyst to hydrocarbon ratio were determined by simulation, while holding the feed rate (30 thousand barrels of oil per day (KBPD) per reactor for a total of 120 KBPD for both reactors), feed temperature (300° C.), steam inlet rate (14 wt. % of fresh feed), downer inlet temperature (DIT) (695° C.) and downer outlet temperature (640° C.) constant.

In Example A, KGC was utilized as the light hydrocarbon feed and AH was utilized as the heavy hydrocarbon feed. The results of Example A are shown in Table 7.

TABLE 7
Example A

Feed	KGC	AH

Feed rate (t/h)	306.35	355.62
Catalyst-to-oil ratio (wt./wt.)	23.66	26.42
Conversion of feed (%)	99%	100%
Heat of reaction (kcal/kg)	125.51	145.70
Required produced coke (wt. % of feed)	3.00%	9.27%

In Example B, AXL was utilized as the light hydrocarbon feed and AH was utilized as the heavy hydrocarbon feed. The results of Example B are shown in Table 8.

TABLE 8
Example B

Feed	AXL	AH

Feed rate (t/h)	327.30	355.62
C/O ratio (wt./wt.)	26.30	26.42
Conversion of feed (%)	99%	100%
Heat of reaction (kcal/kg)	134.09	145.70
Required produced coke (wt. % of feed)	5.50%	7.74%

As can be seen from Table 7, the combination of KGC and AH requires about 13 wt. % of coke production. As can be seen from Table 8, the combination of AXL and AH produces about 13 wt. % of coke production. Thus, the coke needs are balanced and the regenerator may be operated without catalyst coolers or supplemental fuels.

A first aspect of the present disclosure is directed to a process for upgrading hydrocarbon feeds in a fluidized catalytic cracking system (FCC system), the process comprising: passing a first portion of a heavy hydrocarbon feed to a first FCC reactor and a second portion of the heavy hydrocarbon feed to a second FCC reactor, where the heavy hydrocarbon feed has an American Petroleum Institute (API) gravity of from 10° to 35°; passing a first portion of a light hydrocarbon feed to a third FCC reactor and second portion of the light hydrocarbon feed to a fourth FCC reactor, where the light hydrocarbon feed has an API gravity of from 38° to 100°; passing a cracking catalyst from a catalyst withdrawal well to the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor, where the catalyst withdrawal well is common to the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor and the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor are operated in parallel; contacting the first portion and the second portion of the heavy hydrocarbon feed with the cracking catalyst in the first FCC reactor and the second FCC reactor, respectively, at high severity conditions, where the contacting causes at least a portion of the heavy hydrocarbon feed to undergo catalytic cracking; contacting the first portion and the second portion of the light hydrocarbon feed with the cracking catalyst in the third FCC reactor and the fourth FCC reactor, respectively, at high severity conditions, where the contacting causes at least a portion of the light hydrocarbon feed to undergo catalytic cracking; separating reaction mixtures from the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor to produce an FCC effluent and spent cracking catalyst; regenerating the spent cracking catalyst to produce regenerated catalyst; passing the regenerated catalyst back to the catalyst withdrawal well; determining a heat balance requirement of the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor; and controlling a flow rate of the cracking catalyst from the catalyst withdrawal well to the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor, based on the heat balance requirements of the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor.

A second aspect of the present disclosure may include the first aspect, wherein regenerating the spent catalyst occurs in a common regenerator.

A third aspect of the present disclosure may include the second aspect, wherein the common regenerator is operated without supplemental fuel or catalyst coolers.

A fourth aspect of the present disclosure may include any one of the first through third aspects, wherein separating the reaction mixtures of the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor comprises: passing the reaction mixtures from the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor to a common fluid-solid separator; and separating the reaction mixtures in the common fluid-solid separator to produce the FCC effluent and the spent cracking catalyst.

A fifth aspect of the present disclosure may include any one of the first through fourth aspects, wherein controlling the flow rate comprises operating a first valve, a second valve, a third valve, and a fourth valve to control the flow rate of the cracking catalyst passed from the catalyst withdrawal well to the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor, respectively.

A sixth aspect of the present disclosure may include the fifth aspect, wherein the first valve is disposed between the catalyst withdrawal well and the first FCC reactor, the second valve is disposed between the catalyst withdrawal well and the second FCC reactor, the third valve is disposed between the catalyst withdrawal well and the third FCC reactor, and the fourth valve is disposed between the catalyst withdrawal well and the fourth FCC reactor.

A seventh aspect of the present disclosure may include any one of the first through sixth aspects, wherein controlling the flow rate comprises detecting an amount of coke on the spent cracking catalyst.

An eighth aspect of the present disclosure may include any one of the first through seventh aspects, wherein controlling the flow rate comprises determining a heat balance requirement of the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor.

A ninth aspect of the present disclosure may include any one of the first through eighth aspects, wherein controlling the flow rate comprises: detecting an amount of coke on the spent cracking catalyst; determining a heat balance requirement of the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor; comparing the amount of coke to the heat balance requirements of the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor; and operating a first valve, a second valve, a third valve, and a fourth valve to adjust a catalyst-to-oil ratio in the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor, wherein adjusting the catalyst-to-oil ratio changes a reactor outlet temperature of the first FCC reactor, the second FCC reactor, the third FCC reactor, the fourth FCC reactor, or combinations thereof.

A tenth aspect of the present disclosure may include any one of the first through ninth aspects, wherein a cracking temperature of the first FCC reactor and the second FCC reactor is within 100° C. of a cracking temperature of the third FCC reactor and the fourth FCC reactor.

An eleventh aspect of the present disclosure may include any one of the first through tenth aspects, wherein: the heavy hydrocarbon feed has an API gravity of from 10° to 30°; the light hydrocarbon feed has an API gravity of from 40° to 100°; a catalyst-to-oil ratio of the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor is from 3:1 to 50:1.

A twelfth aspect of the present disclosure may include any one of the first through eleventh aspects, wherein regenerating the spent cracking catalyst comprises combusting coke deposited on the spent cracking catalyst.

A thirteenth aspect of the present disclosure may include any one of the first through twelfth aspects, wherein the heavy hydrocarbon feed is heated to less than or equal to 350° C. prior to being passed to the first FCC reactor and the second FCC reactor, the light hydrocarbon feed is heated to less than or equal to 350° C. prior to being passed to the third FCC reactor and the fourth FCC reactor, or both.

A fourteenth aspect of the present disclosure may include any one of the first through thirteenth aspects, where the heavy hydrocarbon feed is a whole crude oil.

A fifteenth aspect of the present disclosure may include any one of the first through fourteenth aspects, wherein the heavy hydrocarbon feed is Arab Heavy crude oil.

A sixteenth aspect of the present disclosure may include any one of the first through fifteenth aspects, wherein the light hydrocarbon feed comprises a light crude oil, an extra light crude oil, or a gas condensate.

A seventeenth aspect of the present disclosure may include any one of the first through sixteenth aspects, wherein the light hydrocarbon feed comprises Arab Extra Light crude oil or Khuff Gas Condensate.

An eighteenth aspect of the present disclosure may include any one of the first through seventeenth aspects, wherein the light hydrocarbon feed and the heavy hydrocarbon feed have not been subjected to separation by boiling point temperature difference.

A nineteenth aspect of the present disclosure may include any one of the first through eighteenth aspects, wherein the API gravity of the light hydrocarbon feed is at least 25° higher than the API gravity of the heavy hydrocarbon feed.

A twentieth aspect of the present disclosure may include any one of the first through nineteenth aspects, wherein the light hydrocarbon feed, the heavy hydrocarbon feed, or both are hydrotreated feed streams.

A twenty-first aspect of the present disclosure may include any one of the first through twentieth aspects, wherein: the first FCC reactor and the second FCC reactor converts from 8 wt. % to 11 wt. % of the heavy hydrocarbon feed to coke; and the third FCC reactor and the fourth FCC reactor converts from 1.5 wt. % to 4.5 wt. % of the light hydrocarbon feed to coke.

A twenty-second aspect of the present disclosure may include any one of the first through twenty-first aspects, wherein: the first FCC reactor and the second FCC reactor converts from 6 wt. % to 10 wt. % of the heavy hydrocarbon feed to coke; the third FCC reactor and the fourth FCC reactor converts from 4 wt. % to 7 wt. % of the light hydrocarbon feed to coke.

A twenty-third aspect of the present disclosure may include the twenty-first aspect, wherein the first FCC reactor and the second FCC reactor coverts at least 2% more of the heavy hydrocarbon feed to coke than the third FCC reactor and the fourth FCC reactor converts the light hydrocarbon feed to coke.

A twenty-fourth aspect of the present disclosure may include any one of the first through twenty-third aspects, wherein no coke precursors are introduced to the heavy hydrocarbon feed or to the light hydrocarbon feed.

A twenty-fifth aspect of the present disclosure may include any one of the first through twenty-fourth aspects, wherein the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor operate at a temperature of from 500° C. to 800° C.

A twenty-sixth aspect of the present disclosure may include any one of the first through twenty-fifth aspects, wherein the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor operate at a pressure of from 100 kPa to 15000 kPa.

A twenty-seventh aspect of the present disclosure may include any one of the first through twenty-sixth aspects, wherein a residence time of the heavy hydrocarbon feed in the first FCC reactor and the second FCC reactor is from 0.1 seconds to 60 seconds and a residence time of the light hydrocarbon feed in the third FCC reactor and the fourth FCC reactor is from 0.1 seconds to 60 seconds, or both.

A twenty-eighth aspect of the present disclosure may include any one of the first through twenty-seventh aspects, wherein the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor are each independently operated at a temperature of greater than or equal to 580° C., a catalyst-to-oil ratio of from 3:1 to 50:1, and a residence time of from 0.1 seconds to 60 seconds.

A twenty-ninth aspect of the present disclosure may include any one of the first through twenty-eighth aspects, wherein the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor are each operated in a down-flow configuration.

A thirtieth aspect of the present disclosure may include any one of the first through twenty-ninth aspects, further comprising separating the FCC effluent into one or more product streams.

A thirty-first aspect of the present disclosure may include any one of the first through thirtieth aspects, wherein the one or more product streams comprise a fuel oil stream, a gasoline stream, a mixed butenes stream, a butadiene stream, a propene stream, an ethylene stream, a methane stream, a light cycle oil stream, or a heavy cycle oil stream.

A thirty-second aspect of the present disclosure may include any one of the first through thirty-first aspects, wherein: the heavy hydrocarbon feed has an API gravity of from 20° to 30°; the light hydrocarbon feed has an API gravity of from 40° to 55°; a catalyst-to-oil ratio of the first FCC reactor, the second FCC reactor, the third FCC reactor, and the fourth FCC reactor is from 3:1 to 50:1.

It is noted that any two quantitative values assigned to a property may constitute a range of that property, and all combinations of ranges formed from all stated quantitative values of a given property are contemplated in this disclosure.

It is noted that one or more of the following claims utilize the term “where” as a transitional phrase. For the purposes of defining the present technology, it is noted that this term is introduced in the claims as an open-ended transitional phrase that is used to introduce a recitation of a series of characteristics of the structure and should be interpreted in like manner as the more commonly used open-ended preamble term “comprising.”

Having described the subject matter of the present disclosure in detail and by reference to specific aspects, it is noted that the various details of such aspects should not be taken to imply that these details are essential components of the aspects. Rather, the claims appended hereto should be taken as the sole representation of the breadth of the present disclosure and the corresponding scope of the various aspects described in this disclosure. Further, it will be apparent that modifications and variations are possible without departing from the scope of the appended claims.