METHODS AND SYSTEMS FOR PROCESSING A CRUDE OIL FEEDSTOCK

Description

FIELD

The present specification generally relates to processes and systems for converting a crude oil feedstock to petrochemicals and fuel products.

TECHNICAL BACKGROUND

Light olefins, including ethylene, propylene, and butene, are basic intermediates used by a large portion of the petrochemical industry. In particular, pure streams of light olefins may be used during the production of various polymers and chemicals. Traditionally, light olefins may be produced by thermal cracking of petroleum fractions such as naphtha, kerosene, or gas oil. Light olefins could also be produced by catalytic cracking processes. As the demand for light olefins increases, there is a need for improved methods to produce light olefins.

SUMMARY

Accordingly, there is an ongoing need for methods of processing crude oil feedstocks for increasing production of light olefins and other petrochemicals and fuel products. The methods and systems of the present disclosure include processing a crude oil feedstock in an integrated method and system that includes cracking a first fraction and second fraction of the crude oil feedstock in a fluid catalytic cracking unit, and subsequent processing of an effluent from the fluid catalytic cracking unit and a third fraction of the crude oil feedstock in a mixed feed steam cracking unit, which may increase production of light olefins and other valuable petrochemicals. Integration of methods and systems for processing a crude oil herein may also reduce capital expenditures and/or operational expenditures compared to conventional methods and systems.

According to one or more embodiments of the present disclosure a method of processing a crude oil feedstock may comprise: separating the crude oil feedstock to produce: a first feed fraction comprising hydrocarbons having a boiling point of greater than 350° C.; a second feed fraction comprising hydrocarbons having a boiling point of greater than or equal to 160° C. and less than or equal to 350° C.; and a third feed fraction comprising hydrocarbons having a boiling point of less than 160° C.; cracking the first feed fraction in a first downflow reaction zone of a fluid catalytic cracking unit; cracking the second feed fraction in a second downflow reaction zone of the fluid catalytic cracking unit; fractionating an effluent from the fluid catalytic cracking unit to produce an FCC mixed C4 stream comprising C4 hydrocarbons; and processing the third feed fraction and saturated C4 hydrocarbons from the FCC mixed C4 stream in a mixed feed cracking zone of a mixed feed steam cracking unit to produce light olefins.

Additional features and advantages will be set forth in the detailed description which follows, and in part will be readily apparent to those skilled in the art from the description or recognized by practicing the embodiments as described in the written description and claims hereof, as well as the appended drawings.

It is to be understood that both the foregoing summary and the following detailed description are merely exemplary, and are intended to provide an overview or framework to understand the nature and character of the claims. The drawings are included to provide a further understanding of the embodiments and, together with the detailed description, serve to explain the principles and operations of the claimed subject matter. However, the embodiments depicted in the drawings are illustrative and exemplary in nature, and not intended to limit the claimed subject matter.

For the purpose of the simplified schematic illustrations and descriptions of FIG. 2A and FIG. 2B, 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 conventional chemical processing operations, such as refineries, such as, for example, air supplies, catalyst hoppers, and flue gas handling are not depicted. It would be known that these components are within the spirit and scope of the present embodiments disclosed. However, operational components, such as those described in the present disclosure, may be added to the embodiments described in this disclosure.

Additionally, the arrows in the simplified schematic illustrations of FIG. 2A and FIG. 2B refer to process streams. However, the arrows may equivalently refer to transfer lines, which may transfer process steams between two or more system components. Arrows that connect to one or more system components signify inlets or outlets in the given system components and arrows that connect to only one system component signify a system outlet stream that exits the depicted system or a system inlet stream that enters the depicted system. The arrow direction generally corresponds with the major direction of movement of the process stream or the process stream contained within the physical transfer line signified by the arrow.

The arrows in the simplified schematic illustrations of FIG. 2A and FIG. 2B may also refer to process steps of transporting a process stream from one system component to another system component. For example, an arrow from a first system component pointing to a second system component may signify “passing” a process stream from the first system component to the second system component, which may comprise the process stream “exiting” or being “removed” from the first system component and “introducing” the process stream to the second system component.

BRIEF DESCRIPTION OF THE DRAWINGS

While the specification concludes with claims particularly pointing out and distinctly claiming the subject matter of the description, it is believed that the description will be better understood from the following specification when taken in conjunction with the accompanying drawings, wherein:

FIG. 1 is a flowchart of a method of processing a crude oil feedstock, according to embodiments disclosed herein;

FIG. 2A schematically depicts a system for processing a crude oil feedstock, according to embodiments disclosed herein;

FIG. 2B schematically depicts a system for processing a crude oil feedstock, according to embodiments disclosed herein.

DETAILED DESCRIPTION

Reference will now be made in detail to embodiments of the present application, various embodiments of which will be described herein with specific reference to the accompanying drawings. Whenever possible, the same reference numerals will be used throughout the drawings to refer to the same or like parts.

The present disclosure is directed to methods of processing a crude oil feedstock. Such methods may enable conversion of crude oil feedstocks with a mixed feed steam cracking unit in an integrated manner into petrochemicals. Embodiments of the present disclosure may also include systems for processing a crude oil feedstock. The methods and systems include fluid catalytic cracking and mixed feed steam cracking. Such methods and systems may utilize minimum capital expenditures to prepare suitable feedstocks for the fluid catalytic cracking unit and the mixed feed steam cracking unit. Feeds to the fluid catalytic cracking unit may include heavier fractions of the crude oil feedstock. Feeds to the mixed feed steam cracking unit may include light products from the fluid catalytic cracking unit, and a light fraction of the crude oil feedstock, among others. Such methods and systems may be useful for increasing production of valuable products, such as light olefins while reducing capital expenditures and/or operational expenditures compared to conventional methods.

In the following detailed description, numerous specific details may be set forth in order to provide a thorough understanding of embodiments described herein. However, it will be clear to one skilled in the art when embodiments may be practiced without some or all of these specific details. In other instances, well-known features or processes may not be described in detail so as not to unnecessarily obscure the disclosure. In addition, like or identical reference numerals may be used to identify common or similar elements. Moreover, unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this disclosure belongs. In case of conflict, the present specification, including the definitions herein, will control.

The term “crude oil” or “crude oil feedstock” as used herein refers to petroleum extracted from geologic formations in its unrefined form. Crude oil suitable as the source material for the processes herein include Arabian Heavy, Arabian Light, Arabian Extra Light, other Gulf crudes, Brent, North Sea crudes, North and West African crudes, Indonesian, Chinese crudes, or mixtures thereof. The crude petroleum mixtures can be whole range crude oil or topped crude oil. As used herein, “crude oil” also refers to such mixtures that have undergone some pre-treatment such as water-oil separation; and/or gas-oil separation; and/or desalting; and/or stabilization. In certain embodiments, crude oil refers to any of such mixtures having an API gravity (ASTM D287 standard), of greater than or equal to about 15°, 20°, 30°, 32°, 34°, 36°, 38°, 40°, 420 or 44°.

The acronym “AXL” as used herein refers to Arab Extra Light crude oil, characterized by an API gravity of greater than or equal to about 38°, 40°, 420 or 44°, and in certain embodiments in the range of about 38°-46°, 38°-44°, 38°-42°, 38°-40.5°, 39°-46°, 39°-44°, 39°-42° or 39°-40.5°.

The acronym “AL” as used herein refers to Arab Light crude oil, characterized by an API gravity of greater than or equal to about 30°, 32°, 34°, 360 or 38°, and in certain embodiments in the range of about 30°-38°, 30°-36°, 30°-35°, 32°-38°, 32°-36°, 32°-35°, 33°-38°, 33°-36° or 33°-35°.

The term “light cycle oil” and its acronym “LCO” as used herein refers to the light cycle oil produced by fluid catalytic cracking units. The distillation cut for this stream is, for example, in the range of about 180-360° C. LCO is used sometimes in the diesel blends depending on the diesel specifications, or it can be utilized as a cutter to the fuel oil tanks for a reduction in the viscosity and sulfur contents.

The term “heavy cycle oil” and its acronym “HCO” as used herein refer to the heavy cycle oil which is produced by fluid catalytic cracking units. The distillation cut for this stream is, for example, in the range of about 360°−510° C. HCO is used sometimes in an oil flushing system within the process. Additionally, HCO is used to partially vaporize the debutanizer bottoms and then is recycled back as a circulating reflux to the main fractionator in the fluid catalytic cracking unit.

The term “cycle oil” is used herein to refer to a mixture of LCO and HCO.

As used in the present disclosure, the term “directly” refers to the passing of materials, such as an effluent, from a first component of the system to a second component of the system without passing the materials through any intervening components or systems operable to change the composition of the materials. Similarly, the term “directly” also refers to the introducing of materials, such as a feed, to a component of the system without passing the materials through any preliminary components operable to change the composition of the materials. Intervening or preliminary components or systems operable to change the composition of the materials can include reactors and separators, but are not generally intended to include heat exchangers, valves, pumps, sensors, or other ancillary components required for operation of a chemical process.

Further, combining two streams together upstream of the second component instead of passing each stream to the second component separately is also not considered to be an intervening or preliminary component operable to change the composition of the materials.

As used in the present disclosure, the terms “downstream” and “upstream” refer to the positioning of components or systems of the system relative to a direction of flow of materials through the system. For example, a second component may be considered “downstream” of a first component if materials flowing through the system encounter the first component before encountering the second component. Likewise, the first component may be considered “upstream” of the second component if the materials flowing through the system encounter the first component before encountering the second component.

As used in the present 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. Generally, an effluent has a different composition than the stream that entered the reactor, reaction zone, or separator. It should be understood that when an effluent is passed to another component or system, only a portion of that effluent may be passed. For example, a slipstream may carry some of the effluent away, meaning that only a portion of the effluent may enter the downstream component or system.

As used in the present disclosure, the term “reactor” refers to any vessel, container, conduit, or the like, in which a chemical reaction, such as catalytic cracking, occurs between one or more reactants optionally in the presence of one or more catalysts. A reactor can include one or a plurality of “reaction zones” disposed within the reactor. The term “reaction zone” refers to a region in a reactor where a particular reaction takes place.

As used in the present disclosure, the terms “separation unit” and “separator” refer to any separation device(s) that at least partially separates one or more chemical constituents in a mixture from one another. For example, a separation system selectively separates different chemical constituents from one another, forming one or more chemical fractions. Examples of separation systems include, without limitation, distillation columns, fractionators, flash drums, knock-out drums, knock-out pots, centrifuges, filtration devices, traps, scrubbers, expansion devices, membranes, solvent extraction devices, high-pressure separators, low-pressure separators, or combinations of these. The separation processes described in the present disclosure may not completely separate all of one chemical constituent from all of another chemical constituent. Instead, the separation processes described in the present disclosure “at least partially” separate different chemical constituents from one another and, even if not explicitly stated, separation can include only partial separation.

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 wt. %, from 70 wt. %, from 90 wt. %, from 95 wt. %, from 99 wt. %, from 99.5 wt. %, or from 99.9 wt. % of the contents of the stream to 100 wt. % of the contents of the stream). 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 “crude oil feedstock” passing to a first system component or from a first system component to a second system component should be understood to equivalently disclose “crude oil” passing to the first system component or passing from a first system component to a second system component.

The composition of feed streams and processing variables of FCC systems play a significant role on the reaction yields and heat balance within the systems. Conventional FCC systems and processes can require costly refining to produce suitable feed streams. Such additional costly refining can include separating and processing of one or more fractions of a hydrocarbon feedstock before introducing the refined conventional feed into the FCC system. These additional processing steps are energy intensive and reduce the amount of viable feed from an existing hydrocarbon source.

Accordingly, aspects of the present disclosure are directed to methods and systems for converting crude oil directly to greater value chemical products and intermediates. Such methods and systems may reduce capital expenditures, reduce operation expenditures, increase value of produced products, or combinations thereof.

Referring now to FIG. 1, a method 100 of processing a crude oil feedstock is depicted. The method 100 may comprise separating the crude oil feedstock to produce a first feed fraction comprising hydrocarbons having a boiling point of greater than 350° C., a second feed fraction comprising hydrocarbons having a boiling point of greater than or equal to 160° C. and less than or equal to 350° C., and a third feed fraction comprising hydrocarbons having a boiling point of less than 160° C., at block 102; cracking the first feed fraction in a first downflow reaction zone of the fluid catalytic cracking unit, at block 104; cracking the second feed fraction in a second downflow reaction zone of a fluid catalytic cracking unit, at block 106; fractionating an effluent from the fluid catalytic cracking unit to produce an FCC mixed C4 stream comprising C4 hydrocarbons, at block 108; and processing the third feed fraction and saturated C4 hydrocarbons from the FCC mixed C4 stream in a mixed feed cracking zone of a mixed feed steam cracking unit to produce light olefins, at block 110.

As shown in the method 100 of FIG. 1, the method may comprise separating the crude oil feedstock to produce a first feed fraction comprising hydrocarbons having a boiling point of greater than 350° C., a second feed fraction comprising hydrocarbons having a boiling point of greater than or equal to 160° C. and less than or equal to 350° C., and a third feed fraction comprising hydrocarbons having a boiling point of less than 160° C., at block 102.

The crude oil feedstock may have an American Petroleum Institute (API) gravity of from 15 degrees to 50 degrees, such as from 20 degrees to 50 degrees, from 20 degrees to 40 degrees, from 20 degrees to 35 degrees, from 25 degrees to 50 degrees, from 25 degrees to 40 degrees, from 25 degrees to 35 degrees, from 30 degrees to 50 degrees, or from 30 degrees to 40 degrees. For example, the crude oil feedstock can be an Arab Light (AL) crude oil, an Arab Extra Light (AXL) crude oil, or combinations thereof. The crude oil feedstock can have a density of greater than 0.8 grams per milliliter (g/mL), greater than 0.82 g/mL, greater than 0.84 g/mL, or even greater than 0.85 g/mL as measured at 15 degrees Celsius. In embodiments, the crude oil feedstock can have a density of less than or equal to 1.0 g/mL, less than or equal to 0.95 g/mL, less than or equal to 0.90 g/mL, or even less than or equal to 0.88 g/mL as measured at 15 degrees Celsius. In embodiments, the crude oil feedstock is Arab Extra Light crude oil.

The crude oil feedstock may be a crude oil that has undergone at least some processing, such as desalting, solids separation, scrubbing, or combinations of these, but has not been subjected to distillation. For instance, the crude oil feedstock can be a de-salted crude oil that has been subjected to a de-salting process. In embodiments, the crude oil feedstock can include a crude oil that has not 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 fluid catalytic cracking unit. As used herein, the “hydrocarbon composition” of the crude oil feedstock refers to the composition of the hydrocarbon constituents of the crude oil feedstock and does not include entrained non-hydrocarbon solids, salts, water, or other non-hydrocarbon constituents.

In embodiments, the crude oil feedstock can be a crude oil having an initial boiling point temperature of greater than or equal to 30° C., such as from 30° C. to 50° C., or from 30° C. to 40° C., as determined according to standard test method ASTM D7169. In embodiments, the crude oil feedstock can be a crude oil having an end boiling point temperature greater than 720° C., as determined according to standard test method ASTM D7169. In embodiments, the crude oil feedstock can be a crude oil having a 50% boiling point temperature greater than 300° C., such as from 300° C. to 400° C., from 300° C. to 380° C., from 300° C. to 375° C., from 350° C. to 400° C., from 350° C. to 380° C., from 350° C. to 375° C., from 360° C. to 400° C., from 360° C. to 380° C., or even from 360° C. to 375° C., as determined according to standard test method ASTM D7169.

In embodiments, the crude oil feedstock can have a concentration of paraffin compounds of less than 50 wt. %, such as less than or equal to 40 wt. %, less than or equal to 35 wt. %, less than or equal to 30 wt. %, less than or equal to 25 wt. %, or even less than or equal to 20 wt. % per unit weight of the hydrocarbon feed, as determined according to ASTM 5443. In embodiments, the crude oil feedstock can have a concentration of paraffin compounds of from 5 wt. % to less than 50 wt. %, from 5 wt. % to 40 wt. %, from 5 wt. % to 35 wt. %, from 5 wt. % to 30 wt. %, from 5 wt. % to 25 wt. %, from 5 wt. % to 20 wt. %, from 10 wt. % to less than 50 wt. %, from 10 wt. % to 40 wt. %, from 10 wt. % to 35 wt. %, from 10 wt. % to 30 wt. %, from 10 wt. % to 25 wt. %, or even from 10 wt. % to 20 wt. % per unit weight of the crude oil feedstock.

In embodiments, the crude oil feedstock can have a concentration of aromatic compounds of greater than or equal to 20 wt. %, greater than or equal to 30 wt. %, greater than or equal to 40 wt. %, or even greater than or equal to 50 wt. % per unit weight of the crude oil feedstock, as determined according to ASTM 5443. In embodiments, the crude oil feedstock can have a concentration of aromatic compounds of from 20 wt. % to 90 wt. %, from 20 wt. % to 80 wt. %, from 20 wt. % to 70 wt. %, from 30 wt. % to 90 wt. %, from 30 wt. % to 80 wt. %, from 30 wt. % to 70 wt. %, from 40 wt. % to 90 wt. %, from 40 wt. % to 80 wt. %, from 40 wt. % to 70 wt. %, from 50 wt. % to 90 wt. %, from 50 wt. % to 80 wt. %, or even from 50 wt. % to 70 wt. % per unit weight of the crude oil feedstock.

In embodiments, the crude oil feedstock can have a concentration of naphthenes of greater than or equal to 25 wt. %, or even greater than or equal to 27 wt. % per unit weight of the hydrocarbon feed 102, as determined according to ASTM 5443. In embodiments, the crude oil feedstock can have a concentration of naphthenes of from 25 wt. % to 60 wt. %, from 25 wt. % to 50 wt. %, from 25 wt. % to 40 wt. %, from 25 wt. % to 35 wt. %, from 27 wt. % to 60 wt. %, from 27 wt. % to 50 wt. %, from 27 wt. % to 40 wt. %, or even from 27 wt. % to 35 wt. % per unit weight of the crude oil feedstock.

In embodiments, the crude oil feedstock can be a topped crude oil. As used in the present disclosure, the term “topped crude oil” refers to crude oil from which lesser boiling constituents have been removed through distillation, such as constituents having boiling point temperatures less than 180° C. or even less than 160° C. In embodiments, the crude oil feedstock comprises, consists of, or consists essentially of a topped crude oil, which has greater than or equal to 95%, greater than or equal to 98%, or even greater than or equal to 99% constituents having boiling point temperatures greater than or equal to 160° C. or greater than or equal to 180° C., depending on the cut point temperature of the topping unit.

The crude oil feedstock may be separated by a cut point temperature to produce the first feed fraction, the second feed fraction, and the third feed fraction.

One or more supplemental feed streams may be added to the crude oil feedstock prior to separating the crude oil feedstock. As previously described, in one or more embodiments, the crude oil feedstock may be crude oil. In one or more embodiments, the crude oil feedstock may be crude oil, and one or more supplemental feed streams comprising one or more of a vacuum residue, tar sands, bitumen, atmospheric residue, vacuum gas oils, demetalized oils, naphtha streams, other hydrocarbon streams, or combinations of these materials, may be added to the crude oil prior to fractionating the crude oil feedstock. Such a mixed feed stream may be considered a crude oil since the added components may be present in crude oils. In other embodiments, the crude oil feedstock may not include one or more supplemental feed streams.

In embodiments, the crude oil feedstock may be fractionated to produce the first feed fraction, the second feed fraction, and the third feed fraction. In embodiments, the crude oil feedstock may be separated to produce one of the first feed fraction, the second feed fraction, or the third feed fraction, and an intermediate stream comprising the other two of the first feed fraction, the second feed fraction, or the third feed fraction. The intermediate stream may be subsequently separated. For instance, the crude oil feedstock may be separated to produce the first feed fraction comprising hydrocarbons having a boiling point of greater than 350° C. and an intermediate stream comprising hydrocarbons having a boiling point of less than or equal to 350° C. In such embodiments, the intermediate stream may be subsequently separated to produce the second feed fraction comprising hydrocarbons having a boiling point of greater than or equal to 160° C. and less than or equal to 350° C. and the third feed fraction comprising hydrocarbons having a boiling point of less than 160° C.

In embodiments, greater than or equal to 50 wt. % of hydrocarbons in the first feed fraction may have a boiling point of greater than 350° C., such as greater than or equal to 60 wt. %, greater than or equal to 70 wt. %, greater than or equal to 80 wt. %, greater than or equal to 90 wt. %, greater than or equal to 95 wt. %, or greater than or equal to 99 wt. %, based on the total weight of the hydrocarbons in the first feed fraction.

In embodiments, greater than or equal to 50 wt. % of hydrocarbons in the second feed fraction may have a boiling point greater than or equal to 160° C. and less than or equal to 350° C., such as greater than or equal to 60 wt. %, greater than or equal to 70 wt. %, greater than or equal to 80 wt. %, greater than or equal to 90 wt. %, greater than or equal to 95 wt. %, or greater than or equal to 99 wt. %, based on the total weight of the hydrocarbons in the second feed fraction.

In embodiments, greater than or equal to 50 wt. % of hydrocarbons in the third feed fraction may have a boiling point of less than 160° C., such as greater than or equal to 60 wt. %, greater than or equal to 70 wt. %, greater than or equal to 80 wt. %, greater than or equal to 90 wt. %, greater than or equal to 95 wt. %, or greater than or equal to 99 wt. %, based on the total weight of the hydrocarbons in the second feed fraction.

As shown in the method 100 of FIG. 1, the method may comprise cracking the first feed fraction in a first downflow reaction zone of a fluid catalytic cracking unit, at block 104. The fluid catalytic cracking unit may include one or more reactors, such as a downflow reactor comprising a downflow reaction zone. In embodiments, the fluid catalytic cracking unit may include two or more downflow reactors and a regenerator zone operable to receive a spent catalyst from one or more downflow reactors and to regenerate the spent catalyst. A general description of a dual downer reactor unit is provided in U.S. Pat. No. 9,290,705, the complete disclosure of which is incorporated herein by reference. In embodiments, the fluid catalytic cracking unit may be operated with a catalyst-to-oil ratio of greater than or equal to 10:1.

As shown in the method 100 of FIG. 1, the method may comprise cracking the second feed fraction in a second downflow reaction zone of the fluid catalytic cracking unit, at block 106. The fluid catalytic cracking unit at block 104 may also be used at block 106. The first feed fraction and the second feed fraction may be cracked in separate downflow reaction zones of the fluid catalytic cracking unit, such as a first downflow reaction zone of a first downflow reactor and a second downflow reaction zone of a second downflow reactor.

As shown in the method 100 of FIG. 1, the method may comprise fractionating an effluent from the fluid catalytic cracking unit to produce an FCC mixed C4 stream comprising C4 hydrocarbons, at block 108.

The effluent from the fluid catalytic cracking unit may comprise reaction products from both the cracking of the first feed fraction and the cracking of the second feed fraction at block 104 and block 106, respectively. The effluent from the fluid catalytic cracking unit may be fractionated to produce the FCC mixed C4 stream, which may comprise butanes, cyclobutane, butene, butadiene, butyne, or combinations thereof. In embodiments, greater than or equal to 50 wt. %, 60 wt. %, 70 wt. %, 80 wt. %, 90 wt. %, 95 wt. %, or 99 wt. % of the FCC mixed C4 stream may comprise C4 hydrocarbons, based on the total weight of the FCC mixed C4 stream.

The FCC mixed C4 stream may be processed to increase a concentration of the saturated C4 hydrocarbons in the FCC mixed C4 stream. For instance, the FCC mixed C4 stream may be processed to convert isobutene to MTBE, extract 1-butene, hydrogenate other olefinic C4 hydrocarbons, such as 2-butene and/or butadiene, or combinations thereof.

The method may further comprise fractionating the effluent from the fluid catalytic cracking unit to produce one or more streams in addition to the FCC mixed C4 stream.

In embodiments, the method may comprise fractionating the effluent from the fluid catalytic cracking unit to produce an FCC gas stream comprising hydrogen gas, methane, ethane, or combinations thereof. In embodiments, at least a portion of the FCC gas stream may be recovered as fuel gas. The method may comprise recovering hydrogen gas, methane, or both from the FCC gas stream. In embodiments, at least a portion of the FCC gas stream may be processed in the mixed feed cracking zone of the mixed feed steam cracking unit. For instance, ethylene can be separated from the mixture of methane, hydrogen and C2s using a cold distillation section (“cold box”) including cryogenic distillation/separation operations, which can be integrated with the mixed feed cracking zone.

In embodiments, the method may comprise fractionating the effluent from the fluid catalytic cracking unit to produce an FCC mixed C3 stream comprising propane, propylene, or combinations thereof. In embodiments, greater than or equal to 50 wt. %, 60 wt. %, 70 wt. %, 80 wt. %, 90 wt. %, 95 wt. %, or 99 wt. % of the FCC mixed C3 stream may comprise C3 hydrocarbons, based on the total weight of the FCC mixed C3 stream.

Propylene may be recovered from the FCC mixed C3 stream to increase production of light olefins. Non-olefinic C3 hydrocarbons, such as propane, may be processed in the mixed feed cracking zone of the mixed feed steam cracking unit, which may increase production of light olefins from the mixed feed steam cracking unit.

In embodiments, the method may comprise fractionating the effluent from the fluid catalytic cracking unit to produce an FCC naphtha stream comprising hydrocarbons having at least 5 carbons and a boiling point less than or equal to 180° C. In embodiments, greater than or equal to 50 wt. %, 60 wt. %, 70 wt. %, 80 wt. %, 90 wt. %, 95 wt. %, or 99 wt. % of the FCC mixed C4 stream may comprise C5+ hydrocarbons having a boiling point less than or equal to 180° C., based on the total weight of the FCC naphtha stream.

In embodiments, the FCC naphtha stream may be hydrotreated to produce hydrotreated FCC naphtha. At least a portion of the hydrotreated FCC naphtha, such as raffinate from the hydrotreated FCC naphtha, may be passed to the mixed feed cracking zone for further processing, which may increase production of light olefins from the mixed feed steam cracking unit.

In embodiments, at least a portion of the hydrotreated FCC naphtha may be processed in an aromatics extraction complex for recovery of aromatic products such as benzene, paraxylene, or both. The processing of the hydrotreated FCC naphtha in the aromatics extraction complex may produce aromatics extraction raffinate. The aromatics extraction raffinate may be passed to the mixed feed cracking zone, which may increase production of light olefins from the mixed feed steam cracking unit. In embodiments, at least a portion of the hydrotreated FCC naphtha may be recovered as gasoline.

In embodiments, the method may comprise fractionating the effluent from the fluid catalytic cracking unit to produce an FCC light cycle oil stream comprising hydrocarbons having a boiling point of greater than 180° C. and less than or equal to 360° C. The FCC light cycle oil stream may be processed to produce diesel, naphtha, fuel oil, or combinations thereof. In embodiments, at least a portion of the FCC light cycle oil stream may be recycled to the fluid catalytic cracking unit for heat balancing in the fluid catalytic cracking unit. At least a portion of the FCC light cycle oil stream may be further cracked to produce other petrochemicals.

In embodiments, the method may comprise fractionating the effluent from the fluid catalytic cracking unit to produce an FCC heavy cycle oil stream comprising hydrocarbons having a boiling point of greater than 360° C. The method may include recycling the FCC heavy cycle oil from the FCC heavy cycle oil stream to the fluid catalytic cracking unit for heat balancing in the fluid catalytic cracking unit. In embodiments, at least a portion of the FCC heavy cycle oil stream may be treated for fuel oil production.

The method may comprise fractionating the effluent from the fluid catalytic cracking unit to produce at least one of an FCC gas stream comprising hydrogen gas, methane, ethane, ethylene or combinations thereof; an FCC mixed C3 stream comprising propane, propylene, or combinations thereof; an FCC mixed C4 stream comprising butanes, butenes, or combinations thereof; an FCC naphtha stream comprising hydrocarbons having at least 5 carbons and a boiling point less than or equal to 180° C.; an FCC light cycle oil stream comprising hydrocarbons having a boiling point of greater than 180° C. and less than or equal to 360° C.; or an FCC heavy cycle oil stream comprising hydrocarbons having a boiling point of greater than 360° C.

As shown in the method 100 of FIG. 1, the method may comprise processing the third feed fraction and saturated C4 hydrocarbons from the FCC mixed C4 stream in a mixed feed cracking zone of a mixed feed steam cracking unit to produce light olefins, at block 110. The products from the mixed feed cracking zone may include a mixed product stream comprising H₂, methane, ethane, ethylene, mixed C3 hydrocarbons, pygas, mixed C4 hydrocarbons, or combinations thereof. Ethylene and propylene may be recovered from the mixed product stream. Ethane and non-olefinic C3 hydrocarbons may be recycled to the mixed feed cracking zone or to a separate processing zone for production of additional petrochemicals. In embodiments, pygas may be recycled to the aromatics extraction complex.

In embodiments, the method may further comprise separating methyl tert-butyl ether, 1-butene, or both from the saturated C4 hydrocarbons prior to processing the saturated C4 hydrocarbons in the mixed feed cracking zone.

Referring now to FIG. 2A, a system 200 for processing a crude oil feedstock 202 is depicted. Any description of like terms used in the context of the method 100 may apply to the same terms used in the system 200. For instance, any description of the “crude oil feedstock” in the method 100 may apply to the “crude oil feedstock 202” of the system 200.

As shown in FIG. 2A, the crude oil feedstock 202 may be passed to a first feed splitter 204 operable to separate the crude oil feedstock 202 into a first feed fraction 206 and an intermediate fraction 208. The intermediate fraction 208 may be passed to a second feed splitter 210 operable to separate the intermediate fraction 208 into a second feed fraction 212 and a third feed fraction 214. The first feed fraction may comprise hydrocarbons having a boiling point of greater than 350° C. The second feed fraction may comprise hydrocarbons having a boiling point of greater than or equal to 160° C. and less than or equal to 350° C. The third feed fraction may comprise hydrocarbons having a boiling point of less than 160° C. While the system 200 includes the first feed splitter 204 and second feed splitter 210, any separator(s) may be used to separate the crude oil feedstock 202 into the first feed fraction 206, second feed fraction 212, and the third feed fraction 214.

The first feed fraction 206 and the second feed fraction 212 may be passed to a first downflow reaction zone and a second downflow reaction zone, respectively, of a fluid catalytic cracking unit 216, such as a dual downer reactor. The dual downer reactor may be operable to separately crack the first feed fraction 206 and the second feed fraction 212 and combine the products in an effluent from the fluid catalytic cracking unit 218. As previously incorporated herein in its entirety, the dual downer reactor 204 may include any configuration provided in U.S. Pat. No. 9,290,705.

The effluent from the fluid catalytic cracking unit 218 may be passed to a first separation unit 220. The first separation unit 220 may be operable to fractionate the effluent from the fluid catalytic cracking unit 218 into two or more fractions. In embodiments, the fluid catalytic cracking unit 216 may be directly connected to the first separation unit 220. The first separation unit 220 may be operable to separate the effluent from the fluid catalytic cracking unit 218 into an FCC mixed C4 stream 228, an FCC gas stream 224, an FCC mixed C3 stream 226, an FCC naphtha stream 230, an FCC light cycle oil stream 232, an FCC heavy cycle oil stream 222, or any combination thereof.

The FCC mixed C4 stream 228 may be passed to a processing unit 236 operable to increase a concentration of saturated C4 hydrocarbons in the FCC mixed C4 stream 228. In embodiments, the processing unit 236 may be operated at conditions for converting isobutene to MTBE, extraction of 1-butene, the hydrogenation of other olefinic C4 hydrocarbons, such as 2-butene and/or butadiene, or combinations thereof. In embodiments, the first separation unit 220 may be directly connected to the processing unit 236.

A product stream 242 may be passed from the processing unit 236 to a mixed feed steam cracking unit 244. The product stream 242 may comprise saturated C4 hydrocarbons. The mixed feed steam cracking unit 244 may be operated under conditions to produce light olefins 262 from other petrochemicals. In embodiments, the mixed feed steam cracking unit 244 may be heated at temperature of from 600° C. to 900° C. The mixed feed steam cracking unit 244 may be operated with a steam-to-hydrocarbon weight ratio of from 1:3 to 1:9, such as from 1:3 to 1:6, from 1:4 to 1:8, or from 1:5 to 1:6. The mixed feed steam cracking unit 244 may be operated with residence time of from 0.01 seconds to 1 seconds. In embodiments, one or more petrochemicals may be recovered from the processing unit 236 such as methyl tert-butyl ether 254, 1-butene 256, or both. In embodiments, the processing unit 236 may be directly connected to the mixed feed steam cracking unit 244.

The system 200 may include a cold distillation unit 234 fluidly connected to the first separation unit 220 and the mixed feed steam cracking unit 244. The FCC gas stream 224 may be passed to the cold distillation unit 234 operable to recover one or more fuel gases 264, such as hydrogen gas, methane, or both and/or ethylene in stream 266. Stream 246, which may include ethane and non-olefinic C3 hydrocarbons may be recycled from the cold distillation unit 234 to the mixed feed steam cracking unit 244, which may increase production of light olefins 262 from the mixed feed steam cracking unit 244. The light olefins 262 may be recovered, such as by passing the light olefins 262 to the cold distillation unit 234 and recovering the light olefins in stream 266, which may include ethylene, propylene, or both. In embodiments, the light olefins recovered may be integrated into one or more systems or processes to produce polyethylene, polypropylene, or both.

The FCC mixed C3 stream 226 may be passed to the cold distillation unit 234, which may be operable to recover propylene in the cold distillation unit 234 and/or recycle non-olefinic C3 hydrocarbons to the mixed feed steam cracking unit 244 through stream 246.

The system 200 may include a hydrotreating unit 238 downstream of the first separation unit 220 operable to receive a product stream from the 220. The FCC naphtha stream 230 may be passed to the hydrotreating unit 238 operable to hydrotreat hydrocarbons in the FCC naphtha stream 230 and produce the hydrotreated FCC naphtha.

In embodiments, the hydrotreating unit 238 may reduce sulfur and/or nitrogen content in the FCC naphtha stream 230. In embodiments, the hydrotreating unit 238 may reduce nitrogen content to less than or equal to 50%, less than or equal to 40%, less than or equal to 30%, less than or equal to 20%, or even less than or equal to 10% of the original content of nitrogen in the FCC naphtha stream 230. For example, the hydrotreating unit 238 may reduce sulfur content to less than or equal to 50%, less than or equal to 40%, less than or equal to 30%, less than or equal to 20%, or even less than or equal to 10% of the original content of sulfur in the FCC naphtha stream 230.

The hydrotreating unit 238 may be a variety of reactor types, such as, without limitation, a fixed-bed, ebullated-bed, moving-bed, or slurry-bed. The hydrotreating unit 238 may comprise multiple beds in series. In some embodiments, a fixed-bed reactor may be desirable because it is more flexible than some other types of reactors because the feedstock can have a cycle length during the Turnaround & Inspection (T&I) cycles. In further embodiments, an ebullated-bed reactor may be desirable because it is more flexible than some other types of reactors because it can be run isothermally as the heat generated is quenched by the injection of cold feedstock.

The hydrotreating unit 238 may include one or more hydroprocessing catalysts that include one or more active metals and one or more supports. Without limitation, the active metals may be comprise metals from IUPAC Groups 6, 8, 9, and 10, such as cobalt, nickel, molybdenum, or tungsten. The support materials may be chosen from, without limitation alumina, silica, titania, zeolites, or combination thereof. For example, in some embodiments, the catalyst of the hydrotreating unit 238 may comprise one metal from IUPAC Group 6 and one metal from IUPAC Groups 8-10. Example IUPAC Group 6 metals include molybdenum and tungsten. Example IUPAC Group 8-10 metals include nickel and cobalt.

According to one or more embodiments, the hydrotreating unit 238 may have a weighted average bed temperature of from 300° C. to 450° C., such as from 320° C. to 380° C. The hydrotreating unit 238 may have a LHSV of 0.5/hour (inverse hours) to 10/hour, such as from 1/hour to 2/hour. The hydrotreating unit 238 may have a hydrogen to oil ratio of from 100 StLt per liters of oil to 5000 StLt per liters of oil, such as from 100 StLt per liters of oil to 1500 StLt per liters of oil.

In embodiments, the first separation unit 220 may be directly connected to the hydrotreating unit 238. At least a portion of the hydrotreated FCC naphtha may be passed to the mixed feed steam cracking unit 244, as shown as stream 260. In embodiments, the stream 260 may comprise at least 50 wt. %, at least 60 wt. %, at least 70 wt. %, at least 80 wt. %, or at least 90 wt. % paraffinic compounds. In embodiments, the stream 260 may comprise at least 50 wt. %, at least 60 wt. %, at least 70 wt. %, at least 80 wt. %, or at least 90 wt. % naphtha.

The system 200 may include an aromatics extraction complex 250 fluidly connected to the hydrotreating unit 238. At least a portion of the hydrotreated FCC naphtha may be passed to the aromatics extraction complex 250, as shown as stream 248. In embodiments, the hydrotreating unit 238 may be directly connected to the aromatics extraction complex 250. The aromatics extraction complex 250 may be operable to recover one or more aromatics from the hydrotreated FCC naphtha such as benzene 270, paraxylene 272, or both. A raffinate stream 252 may be recycled from the aromatics extraction complex 250 to the hydrotreating unit 238.

The FCC light cycle oil stream 232 may be passed to a processing unit 240 operable to increase a concentration of diesel, naphtha, and/or fuel oil. In embodiments, a naphtha stream 258 may be passed from the processing unit 240 to the hydrotreating unit 238. In embodiments, at least a portion of the FCC light cycle oil stream 232 may be recycled to the fluid catalytic cracking unit 216 (not shown).

In embodiments, the FCC heavy cycle oil stream 222 may be recycled to the fluid catalytic cracking unit 216. In embodiments, at least a portion of the FCC heavy cycle oil stream 222 may be passed to a processing unit for fuel oil production (not shown).

Referring now to FIG. 2B, a system 201 for processing a crude oil feedstock 202 is depicted. Any description of like terms used in the context of the method 100, or the system 200 may be applied to the same terms used in the system 201. For instance, any description of the crude oil feedstock in the method 100 may apply to the crude oil feedstock 202 of the system 201. Further, for instance, any description of the first separation unit 220 in system 200 may apply to the first separation unit 220 in system 201.

As shown in FIG. 2B, the system 201 differs from system 200 of FIG. 2A in that the aromatics extraction complex 250 is not included in the system 201. In system 201, a product stream 274 comprising gasoline may be recovered from the hydrotreating unit 238.

This disclosure includes numerous aspects. One aspect is a method of processing a crude oil feedstock, the method comprising: separating the crude oil feedstock to produce: a first feed fraction comprising hydrocarbons having a boiling point of greater than 350° C.; a second feed fraction comprising hydrocarbons having a boiling point of greater than or equal to 160° C. and less than or equal to 350° C.; and a third feed fraction comprising hydrocarbons having a boiling point of less than 160° C.; cracking the first feed fraction in a first downflow reaction zone of a fluid catalytic cracking unit; cracking the second feed fraction in a second downflow reaction zone of the fluid catalytic cracking unit; fractionating an effluent from the fluid catalytic cracking unit to produce an FCC mixed C4 stream comprising C4 hydrocarbons; and processing the third feed fraction and saturated C4 hydrocarbons from the FCC mixed C4 stream in a mixed feed cracking zone of a mixed feed steam cracking unit to produce light olefins.

Another aspect is any above aspect or combination of aspects, further comprising processing the FCC mixed C4 stream to increase a concentration of the saturated C4 hydrocarbons in the FCC mixed C4 stream.

Another aspect is any above aspect or combination of aspects, further comprising separating methyl tert-butyl ether, 1-butene, or both from the saturated C4 hydrocarbons prior to processing the saturated C4 hydrocarbons in the mixed feed cracking zone.

Another aspect is any above aspect or combination of aspects, wherein fractionating the effluent from the fluid catalytic cracking unit further produces at least one of: an FCC gas stream comprising hydrogen gas, methane, ethane, ethylene or combinations thereof; an FCC mixed C3 stream comprising propane, propylene, or combinations thereof; an FCC naphtha stream comprising hydrocarbons having at least 5 carbons and a boiling point less than or equal to 180° C.; an FCC light cycle oil stream comprising hydrocarbons having a boiling point of greater than 180° C. and less than or equal to 360° C.; or an FCC heavy cycle oil stream comprising hydrocarbons having a boiling point of greater than 360° C.

Another aspect is any above aspect or combination of aspects, further comprising: fractionating the effluent from the fluid catalytic cracking unit to produce an FCC gas stream comprising hydrogen gas, methane, ethane, ethylene or combinations thereof; and processing the ethane from the FCC gas stream in the mixed feed cracking zone.

Another aspect is any above aspect or combination of aspects, further comprising recovering hydrogen gas, methane, ethylene, or combinations thereof from the FCC gas stream.

Another aspect is any above aspect or combination of aspects, further comprising: fractionating the effluent from the fluid catalytic cracking unit to produce an FCC mixed C3 stream; and processing propane from the FCC mixed C3 stream in the mixed feed cracking zone.

Another aspect is any above aspect or combination of aspects, further comprising: fractionating the effluent from the fluid catalytic cracking unit to produce an FCC naphtha stream comprising hydrocarbons having at least 5 carbons and a boiling point less than or equal to 180° C.; hydrotreating the FCC naphtha stream to produce hydrotreated FCC naphtha; and passing at least a portion of the hydrotreated FCC naphtha to the mixed feed cracking zone.

Another aspect is any above aspect or combination of aspects, further comprising: processing the hydrotreated FCC naphtha in an aromatics extraction complex for recovery of aromatic products and production of aromatics extraction raffinate; and passing the aromatics extraction raffinate to the mixed feed stream cracking zone.

Another aspect is any above aspect or combination of aspects, further comprising recovering gasoline from the hydrotreated FCC naphtha.

Another aspect is any above aspect or combination of aspects, further comprising: fractionating the effluent from the fluid catalytic cracking unit to produce an FCC light cycle oil stream comprising hydrocarbons having a boiling point of greater than 180° C. and less than or equal to 360° C.; and processing the FCC light cycle oil stream to produce diesel, naphtha, fuel oil, or combinations thereof.

Another aspect is any above aspect or combination of aspects, further comprising fractionating the effluent from the fluid catalytic cracking unit to produce an FCC heavy cycle oil stream having a boiling point of greater than 360° C.; and at least one of: passing the FCC heavy cycle oil from the FCC heavy cycle oil stream to the fluid catalytic cracking unit; and processing FCC heavy cycle oil from the FCC heavy cycle oil stream to produce fuel oils.

Another aspect is any above aspect or combination of aspects, wherein at least one of: the second feed fraction is added directly to the fluid catalytic cracking unit the first feed fraction is added directly to the fluid catalytic cracking unit; and the third feed fraction is added directly to the mixed feed steam cracking unit.

Another aspect is any above aspect or combination of aspects, wherein the crude oil feedstock has an American Petroleum Institute gravity of greater than or equal to 15 degrees and less than or equal to 50 degrees.

Another aspect is a system for processing a crude oil feedstock, the system comprising: a feed splitter operable to separate the crude oil feedstock into a first feed fraction, a second feed fraction, and a third feed fraction; a dual downer reactor operable to receive the first feed fraction and the second feed fraction; a first separation unit downstream of the dual downer reactor; a processing unit operable to receive an FCC mixed C4 stream from the first separation unit; and a mixed feed steam cracking unit operable to receive the third feed fraction and a product stream from the processing unit.

Another aspect is any above aspect or combination of aspects, further comprising a hydrotreating unit downstream of the first separation unit operable to receive a product stream from the first separation unit.

Another aspect is any above aspect or combination of aspects, further comprising an aromatics extraction complex fluidly connected to the hydrotreating unit.

Another aspect is any above aspect or combination of aspects, wherein the first separation unit is directly connected to the hydrotreating unit, and the hydrotreating unit is directly connected to the aromatics extraction complex.

Another aspect is any above aspect or combination of aspects, wherein at least one of: the dual downer reactor is directly connected to the first separation unit; the first separation unit is directly connected to the processing unit; and the processing unit is directly connected to the mixed feed steam cracking unit.

Another aspect is any above aspect or combination of aspects, further comprising a cold distillation unit fluidly connected to the first separation unit and the mixed feed steam cracking unit.

It will be apparent to persons of ordinary skill in the art that various modifications and variations can be made without departing from the scope disclosed herein. Since modifications, combinations, sub-combinations, and variations of the disclosed embodiments, which incorporate the spirit and substance disclosed herein, may occur to persons of ordinary skill in the art, the scope disclosed herein should be construed to include everything within the scope of the appended claims and their equivalents.

For the purposes of defining the present technology, the transitional phrase “consisting of” may be introduced in the claims as a closed preamble term limiting the scope of the claims to the recited components or steps and any naturally occurring impurities. For the purposes of defining the present technology, the transitional phrase “consisting essentially of” or “consists essentially of” may be introduced in the claims to limit the scope of one or more claims to the recited elements, components, materials, or method steps as well as any non-recited elements, components, materials, or method steps that do not materially affect the novel characteristics of the claimed subject matter. The transitional phrases “consisting of” and “consisting essentially of” may be interpreted to be subsets of the open-ended transitional phrases, such as “comprising” and “including,” such that any use of an open ended phrase to introduce a recitation of a series of elements, components, materials, or steps should be interpreted to also disclose recitation of the series of elements, components, materials, or steps using the closed terms “consisting of” and “consisting essentially of.” For example, the recitation of a composition “comprising” components A, B, and C should be interpreted as also disclosing a composition “consisting of” components A, B, and C as well as a composition “consisting essentially of” components A, B, and C. Any quantitative value expressed in the present application may be considered to include open-ended embodiments consistent with the transitional phrases “comprising” or “including” as well as closed or partially closed embodiments consistent with the transitional phrases “consisting of” and “consisting essentially of.”

As used in the Specification and appended Claims, the singular forms “a”, “an”, and “the” include plural references unless the context clearly indicates otherwise. The verb “comprises” and its conjugated forms should be interpreted as referring to elements, components or steps in a non-exclusive manner. The referenced elements, components or steps may be present, utilized or combined with other elements, components or steps not expressly referenced.

It should be understood 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. The subject matter disclosed herein has been described in detail and by reference to specific embodiments. It should be understood that any detailed description of a component or feature of an embodiment does not necessarily imply that the component or feature is essential to the particular embodiment or to any other embodiment. Further, it should be apparent to those skilled in the art that various modifications and variations can be made to the described embodiments without departing from the spirit and scope of the claimed subject matter.