KR20190086707A - Processes and systems for the conversion of crude oil to petrochemicals and fuel products that incorporate steam cracking, fluid catalytic cracking, and conversion of naphtha to chemical-rich reformates - Google Patents

Abstract

A process planning scheme is disclosed that enables the conversion of crude oil feeds into petrochemicals in an integrated manner with several processing units. This design utilizes minimum capital expenditure to produce a suitable feedstock for the steam cracker complex. An integrated process for converting crude oil to olefin and aromatic, and petroleum chemical products, including fuel products, involves the conversion of naphtha to mixed feed steam cracking, fluid catalytic cracking, and chemical-rich reforming . The feed to the mixed feed steam cracker may be a mixture of hard products from water addition room, a recycle stream from the C3 and C4 olefin recovery stages within the battery limits, and a recycle stream from pyrolysis gasoline and FCC naphtha aromatics extraction zone Includes Nate. The chemical reformate from the direct current naphtha stream is used as an additional feed to the aromatic extraction zone and / or mixed feed steam cracker.

Description

Processes and systems for the conversion of crude oil to petrochemicals and fuel products that incorporate steam cracking, fluid catalytic cracking, and conversion of naphtha to chemical-rich reformates

Related application

This application claims priority to U.S. Provisional Patent Application No. 62 / 450,060, filed January 24, 2017, and is a continuation-in-part of U.S. Patent Application No. 15 / 710,799 filed on September 20, 2017, U.S. Provisional Patent Application No. 62 / 424,883 filed on November 21, U.S. Provisional Patent Application Serial No. 62 / 450,018 filed on January 24, 2017, and U.S. Provisional Patent Application Serial No. 62 / 450,018 filed Jan. 24, 450,058, the entire contents of which are incorporated herein by reference in their entirety.

Field of invention

The presently disclosed subject matter relates to an integrated process and system for converting crude oil to petrochemicals and fuel products.

Related Technology Description

Lower olefins (i.e., ethylene, propylene, butylene and butadiene) and aromatics (i.e., benzene, toluene and xylene) are the basic intermediates widely used in the petrochemical and chemical industries. Thermal cracking, or steam cracking, is a major type of process for forming these materials, typically in the presence of steam and in the absence of oxygen. Typical feed materials for steam pyrolysis include petroleum gas, such as ethane, and distillates such as naphtha, kerosene and gas oil. The availability of these feedstocks is usually limited and requires costly and energy-consuming process steps in crude oil refinery.

A very significant portion of ethylene production relies on naphtha as the feed material. However, heavy naphthas have lower paraffins and higher aromatic contents than light naphthas and are therefore suitable as feedstocks in the production of unmodified ethylene. The heavy naphtha can vary in the amount of total paraffins and aromatics based on its source. The paraffin content can range between about 27-70%, the naphthene content can range between about 15-60%, and the aromatic content can range between about 10-36% (by volume).

Many chemical manufacturers are limited by the supply and quality of feedstock from nearby organic feedstocks due to their dependence on oil refinery by-products as feedstocks. Chemical manufacturers also limit the costly refinery and its associated fuel markets, which can have a negative impact on the economic value of refinery feeds. Higher global fuel efficiency standards for cars and trucks can reduce fuel demand, narrow refinery margins, and make fuel and chemical supplies and / or market economics difficult.

There is a need in the industry for improved processes for converting crude oil to basic chemical intermediates such as lower olefins and aromatics. In addition, there is a need in the industry for a new approach to scale-up economics that gives greater leverage to high-value chemical production opportunities.

summary

According to one or more embodiments, the present invention relates to an integrated process for producing petrochemicals and fuel products from crude oil feedstocks. The consolidation process comprises an initial separation step of separating at least a fraction comprising at least a direct current naphtha and a lighter component, at least one intermediate distillate fraction, a fraction, and an atmospheric residue fraction from the crude oil feed in the atmospheric distillation zone. The vacuum gas oil fraction is separated from the vacuum distillation zone in the atmospheric residue fraction. In a distillate water addition zone ("DHP") zone, such as a diesel hydrogenation unit, at least a portion of the intermediate distillate is processed to produce at least a naphtha fraction and a diesel fuel fraction. The vacuum gas oil fraction is processed in a fluid catalytic cracking zone to produce a light olefin FCC fraction, an FCC naphtha fraction and a cycle oil fraction that are at least recovered as petrochemicals.

The hard components from the atmospheric distillation zone, such as LPG, and the aromatic extraction zone raffinate, are processed in a mixed feed vapor cracking zone. All or part of the direct current naphtha is passed to the catalytic reforming zone to produce a chemical-rich reformate as an additional feed to the aromatic extraction zone. The product from the mixed feed steam cracking zone comprises a mixed product stream comprising H ₂ , methane, ethane, ethylene, mixed C 3 s, and mixed C 4 s; Pyrolysis gasoline stream; And a pyrolysis oil stream.

From the mixed product streams C3s and mixed C4s, the petrochemicals ethylene, propylene and butylene are recovered. Ethane and non-olefinic C3s are recycled to the mixed feed steam cracking zone and the non-olefinic C4s are recycled to a separate feed zone for the production of the mixed feed steam cracking zones or additional petrochemicals. Pyrolysis gasoline is treated in the py-gas water addition zone, which produces hydrogenated pyrolysis gasoline. The hydrotreated pyrolysis gasoline is sent to an aromatic extraction zone for recovering the aromatic extraction zone raffinate which is recycled to the aromatics and mixed feed steam cracking zones.

Still other aspects, embodiments, and advantages of these exemplary aspects and embodiments are discussed in detail below. It is also to be understood that both the foregoing description and the following detailed description are exemplary explanatory of various aspects and embodiments, and are intended to provide an overview or overview for understanding the nature and features of the claimed aspects and embodiments. BRIEF DESCRIPTION OF THE DRAWINGS The accompanying drawings are included to provide a further understanding of the various aspects and embodiments and are incorporated in and constitute a part of this specification. The drawings, along with the remainder of this disclosure, serve to explain the principles and operation of the described and claimed aspects and embodiments.

The invention is further described below with reference to the detailed description and the accompanying drawings, wherein like or similar elements are referred to by like numerals, wherein:
BRIEF DESCRIPTION OF THE DRAWINGS Figure 1 schematically illustrates the operation of the steam cracker complex upstream in embodiments of processes for producing petrochemicals and fuel products that incorporate fluid catalytic cracking and steam cracking;
Figure 2 schematically illustrates the operation of the steam cracker complex upstream in a further embodiment of the process for producing petrochemicals and fuel products that incorporates fluid catalytic cracking and steam cracking;
Figure 3 diagrammatically illustrates downstream operation including steam cracker complexes in embodiments of processes for producing petrochemicals and fuel products that incorporate fluid catalytic cracking and steam cracking;
Figure 4 diagrammatically illustrates downstream operation including steam cracker complexes in further embodiments of processes for producing petrochemical and fuel products that incorporate fluid catalytic cracking and steam cracking;
Figure 5 diagrammatically illustrates downstream operation including steam cracker complexes in further embodiments of processes for producing petrochemicals and fuel products that incorporate fluid catalytic cracking and steam cracking;
Figure 6 diagrammatically illustrates downstream operation including steam cracker complexes in embodiments of processes for making petrochemicals and fuel products that incorporate fluid catalytic cracking, steam cracking and metathesis;
Figure 7 diagrammatically illustrates operation in the downstream, including steam cracker complexes in embodiments of processes for producing petrochemicals and fuel products, incorporating fluid catalytic cracking, steam cracking and mixed butanol production ;
Figure 8 schematically illustrates the operation in downstream, including steam cracker complexes in embodiments of processes for producing petrochemicals and fuel products, incorporating fluid catalytic cracking, steam cracking, metathesis and mixed butanol production FIG.
Figures 9 and 10 schematically illustrate the operation of the steam cracker complex upstream in a further embodiment of a process for producing petrochemical and fuel products that incorporates fluid catalytic cracking and steam cracking;
11 schematically illustrates operation in the downstream, including steam cracker complexes in further embodiments of processes for producing petrochemicals and fuel products that incorporate fluid catalytic cracking and steam cracking;
Figures 12 and 13 schematically illustrate the operation of the steam cracker complex upstream in an additional embodiment of the process for producing petrochemicals and fuel products that incorporates fluid catalytic cracking and steam cracking;
Figures 14, 15 and 16 schematically illustrate the operation of a catalytic reforming zone for the production of a chemical-rich reformate;
Figure 17 schematically illustrates the operation of the catalytic reforming zone in another embodiment;
Figure 18 schematically illustrates a single reactor hydrocracking zone;
Figure 19 schematically illustrates a serial-flow hydrocracking zone with recycling;
Figure 20 schematically illustrates a two-step hydrocracking zone with recycling;
Figure 21 diagrammatically illustrates downstream operation including steam cracker complexes in an additional embodiment of a process for making petrochemical and fuel products that incorporate fluid catalytic cracking and steam cracking;
Figures 21a and 21b illustrate the general operation of the type of fluid catalytic cracking operation;
24 schematically illustrates operation in the downstream, including steam cracker complexes in a further embodiment of a process for producing petrochemicals and fuel products, incorporating fluid catalytic cracking, steam cracking and metathesis;
Figure 25 diagrammatically illustrates downstream operation including steam cracker complexes in further embodiments of processes for producing petrochemical and fuel products that incorporate fluid catalytic cracking and steam cracking; And
Figures 26 and 27 schematically illustrate the operation of the steam cracker complex upstream in still further embodiments of processes for producing petrochemical and fuel products that incorporate fluid catalytic cracking and steam cracking.

Technology

Several process unit integration schemes disclose process planning configurations that enable the conversion of crude oil feedstocks to petrochemicals. The design utilizes minimum capital expenditure to produce a suitable feedstock for the steam cracker complex. An integrated process for conversion of crude oil to olefin and aromatic, and petroleum chemical products, including fuel products, includes mixed feed steam cracking, fluid catalytic cracking, and conversion of naphtha to chemical rich reformates. The feed to the mixed feed steam cracker is fed back to the feedstock through the recycle stream from the battery-limited internal water addition zone, the recycle stream from the C3 and C4 olefin recovery stages, and the raffinate from the pyrolysis gasoline and FCC naphtha aromatics extraction zone . The chemical reformate from the direct current naphtha stream is used as an additional feed to the aromatic extraction zone and / or mixed feed steam cracker.

For a particular stream or streams, the phrase "major portion" means at least about 50 wt% and up to 100 wt%, or the same value of another specified unit.

For a particular stream or streams, the phrase "substantial portion" means at least about 75 wt% and up to 100 wt%, or the same value of another specified unit.

For a particular stream or streams, the phrase "substantial portion" means at least about 90, 95, 98 or 99 wt% and up to 100 wt%, or the same value of another specified unit.

For a particular stream or streams, the phrase "small portion" means about 1, 2, 4 or 10 wt%, up to about 20, 30, 40 or 50 wt%, or the same value of another specified unit .

The term " crude oil "as used herein refers to petroleum extracted from its untreated form, geological formation. Wherein the crude oil suitable as the source material for the process is selected from the group consisting of Arabian Heavy, Arabian Light, Arabian Extra Light, other Gulf Crude, Brent, North Sea Crude, North and West African Crude, Indonesian, Chinese Crude, And mixtures thereof. The crude petroleum mixture may be a full range crude oil or a top crude oil. As used herein, the term " crude oil "refers to a part of a pre-treatment such as water-oil separation; And / or gas-oil separation; And / or desalting; And / or stabilization refers also to such a mixture. In certain embodiments, the crude oil may include such a mixture having an API gravity (ASTM D287 standard) of at least about 20, 30, 32, 34, 36, 38, 40, Quot;

As used herein, the abbreviation "AXL" refers to an angle of about 38 degrees, 40 degrees, 42 degrees, or 44 degrees, and in certain embodiments, about 38 degrees to 46 degrees, 38 degrees to 44 degrees, 38 degrees to 42 degrees, Refers to Arab Extra Light crude oil characterized by API gravity in the range of 40.5 °, 39 ° - 46 °, 39 ° - 44 °, 39 ° - 42 °, or 39 ° - 40.5 °.

As used herein, the abbreviation "AL" refers to an angle of about 30 °, 32 °, 34 °, 36 °, or 38 °, and in certain embodiments, about 30 ° to 38 °, 30 ° to 36 °, , An Arab Light crew featuring API gravity in the range of 32 ° to 38 °, 32 ° to 36 °, 32 ° to 35 °, 33 ° to 38 °, 33 ° to 36 ° or 33 ° to 35 ° Refers to de-oil.

The abbreviation "LPG " used herein refers to the well-known acronym for the term" liquefied petroleum gas "and is generally a mixture of C3-C4 hydrocarbons. In certain embodiments, they are also referred to as "light oil fractions ".

The term "naphtha ", as used herein, refers to a naphtha of about 20-205, 20-193, 20-190, 20-180, 20-170, 32-205, 32-193, 32-190, 32-180, 32-170, 36 Refers to boiling hydrocarbons in the range of -205, 36-193, 36-190, 36-180, or 36-170 ° C.

The term "light naphtha ", as used herein, refers to a range of about 20-110, 20-100, 20-90, 20-88, 32-110, 32-100, 32-90, 32-88, 36-110, 36-100, Refers to boiling hydrocarbons within the range of 36-90 or 36-88 占 폚.

As used herein, the term "heavy naphtha" refers to a heavy naphtha of about 90-205, 90-193, 90-190, 90-180, 90-170, 93-205, 93-193, 93-190, 93-180, 93-170, Refers to boiling hydrocarbons in the range of 100-205, 100-193, 100-190, 100-180, 100-170, 110-205, 110-193, 110-190, 110-180 or 110-170 ° C.

In certain embodiments, naphtha, light naphtha, and / or heavy naphtha refer to such petroleum fractions obtained by crude oil distillation as described herein, or by distillation of an intermediate refinery process.

The term "DC" modifying is used herein to mean having its widely known meaning, that is, other refinery processes, such as water addition bubbles, directly derived from the atmospheric distillation unit without fluid catalytic cracking or steam cracking, optionally treated with steam stripping Describe the fraction. Examples thereof are "dicyanaphtha" and its abbreviation "SRN", as is well known, and thus refers to "naphtha" as defined above, derived directly from an atmospheric distillation unit and optionally treated with vapor stripping.

The term "kerosene ", as used herein, refers to kerosene at about 170-280, 170-270, 170-260, 180-280, 180-270, 180-260, 190-280, 190-270, 190-260, 193-280, 193 Quot; refers to boiling hydrocarbons within the range of -270 or 193-260 < 0 > C.

The term "hard kerosene ", as used herein, refers to any one or more of: about 170-250, 170-235, 170-230, 170-225, 180-250, 180-235, 180-230, 180-225, 190-250, 190-235, Refers to boiling hydrocarbons within the range of 190-230 or 190-225 [deg.] C

The term "heavy kerosene ", as used herein, refers to a mixture of about 225-280, 225-270, 225-260, 230-280, 230-270, 230-260, 235-280, 235-270, 235-260, Quot; refers to boiling hydrocarbons within a range of < / RTI >

As used herein, the term " atmospheric gas oil "and its abbreviation" AGO "refers to at least about 250-370, 250-360, 250-340, 250-320, 260-370, 260-360, 260-340, 260-320, -370, 270-360, 270-340 or 270-320 [deg.] C.

The term "heavy atmospheric gas oil" and abbreviation "H-AGO" as used herein in certain embodiments refers to the heaviest cut of hydrocarbons within the AGO boiling range, including the upper 3 to 30 ° C range For AGO having a range of about 250-360 DEG C, the range of H-AGO includes an initial boiling point of about 330-357 DEG C and a terminal boiling point of about 360 DEG C).

The term " intermediate atmospheric gas oil "and its abbreviation" M-AGO "as used herein in certain embodiments with H-AGO means that the residual AGO after H- AGO refers to hydrocarbons within the boiling range (e.g., for AGO having a range of about 250-360 占 폚, the range of M-AGO includes an initial boiling point of about 250 占 폚 and a terminal boiling point of about 330-357 占 폚 do).

In certain embodiments, the term "diesel" is used in connection with a DC fraction from an atmospheric distillation unit. In embodiments where this term is used, the diesel fraction also refers in certain embodiments to intermediate AGO range hydrocarbons in combination with heavy kerosene range hydrocarbons.

As used herein, the term " atmospheric residue "and its abbreviation" AR " refer to a bottoms hydrocarbon having an initial boiling point corresponding to the end point of the AGO range hydrocarbon and having an end point based on the characteristics of the crude oil feed.

As used herein, the term " vacuum gas oil "and its abbreviation" VGO "refer to any one of about 370-550, 370-540, 370-530, 370-510, 400-550, 400-540, 400-530, -550, 420-540, 420-530 or 420-510 [deg.] C.

As used herein, the term " hard vacuum gas oil "and its abbreviation" LVGO "refers to a hydrocarbon gas having a boiling point in the range of about 370-425, 370-415, 370-405, 370-395, 380-425, 390-425, Refers to boiling hydrocarbons.

The term " heavy vacuum gas oil "as used herein and its abbreviation" HVGO "refers to a hydrocarbon gas having a composition of about 425-550, 425-540, 425-530, 425-510, 450-550, 450-540, 450-530, Quot; refers to boiling hydrocarbons within a range of < / RTI >

As used herein, the term " vacuum residue "and its abbreviation" VR "refer to a bottoms hydrocarbon having an initial boiling point corresponding to the end point of the VGO range hydrocarbon and having an end point based on the characteristics of the crude oil feed.

The term "fuel" refers to the crude oil-derived product used as the energy carrier. Fuel produced routinely by oil refining includes, but is not limited to, gasoline, jet fuel, diesel fuel, fuel oil and petroleum coke. Unlike petrochemicals, which are certainly a collection of defined compounds, fuels are typically complex mixtures of different hydrocarbon compounds.

The term "kerosene fuel" or "kerosene fuel product" refers to a fuel product used as an energy carrier, such as jet fuel or other kerosene range fuel products (and precursors for making such jet fuels or other kerosene range fuel products). Kerosene fuels include, but are not limited to, kerosene fuel products that meet Jet A or jet A-1 jet fuel specifications.

The terms "diesel fuel" and "diesel fuel product" refer to the fuel product used as a suitable energy carrier for the compression-ignition engine (and precursor for making such fuel product). Diesel fuels include ultra-low sulfur diesel that complies with the Euro V diesel standard, but not limited to.

The term " aromatic hydrocarbon "or" aromatic "is very well known in the art. Thus, the term "aromatic hydrocarbon" relates to hydrocarbons bonded in a ring having considerably greater stability (due to deliquescence) than a virtually unstructured structure (e.g., Kekule structure). The most common method for determining the orientation of a given hydrocarbon is the diatropicity observation in its 1 H NMR spectrum, for example the presence of chemical shifts in the range of 7.2 to 7.3 ppm for benzene ring protons.

The term " naphthenic hydrocarbon "or" naphthene "or" cycloalkane "relates to the type of alkane used herein and thus having one or more rings of carbon atoms in its chemical structure.

The term "wild naphtha" is used herein to refer to a naphtha product derived from a water addition unit, for example, a distillate water addition unit, a diesel water addition unit and / or a gas oil water addition unit.

The term " non-converting oil "and its abbreviation" UCO "have their known meaning and are used herein to refer to a highly paraffinic fraction from a hydrocracker having a low nitrogen, sulfur and nickel content and to an end point of the AGO range hydrocarbon Within a range of about 340 to about 270 DEG C, such as about 340 to about 360 DEG C, or about 370 DEG C to about 370 DEG C, and in the range of about 510 to about 560 DEG C, such as about 540, 550, And hydrocarbons having terminal points. UCO is also known in the art by other synonyms including "hydro wax ".

As used herein, the term " reformate "or" chemical reformate "refers to a mixture of hydrocarbons rich in aromatics and intermediate products in the production of chemicals and / or gasolines, 30-185, 40-185, 30-170, or boiling hydrocarbons within the range of 40-170 < 0 > C.

The term "C # hydrocarbon" or "C #" is used herein with its well-known meaning, i.e., where "#" is an integer value and means the hydrocarbon having that value of carbon atoms. The term "C # + hydrocarbon" or "C # +" refers to a hydrocarbon having carbon atoms above its value. The term "C # -hydrocarbon" or "C # -" refers to hydrocarbons having carbon atoms below that value. Similarly, ranges are also defined, e.g., C1-C3 means a mixture comprising C1, C2, and C3.

The term "petrochemical" or "petrochemical product" refers to a chemical product derived from crude oil that is not used as a fuel. Petrochemical products include olefins and aromatics used as basic feedstocks for preparing chemicals and polymers. Representative olefinic petrochemical products include, but are not limited to, ethylene, propylene, butadiene, butylene-1, isobutylene, isoprene, cyclopentadiene and styrene. Representative aromatic petrochemical products include, but are not limited to, benzene, toluene, xylene, and ethylbenzene.

The term "olefin" is used herein as having its widely known meaning of being an unsaturated hydrocarbon containing at least one carbon-carbon double bond. As used herein, the term "olefin" refers to a mixture comprising two or more unsaturated hydrocarbons containing at least one carbon-carbon double bond. In certain embodiments, the term "olefin" relates to mixtures comprising two or more of ethylene, propylene, butadiene, butylene-1, isobutylene, isoprene and cyclopentadiene.

The term "BTX" as used herein refers to the well-known abbreviations for benzene, toluene and xylene.

The term "make-up hydrogen " in connection with water addition is commonly used herein to refer to the hydrogen demand of a zone that exceeds recycling from an integrated separation vessel; In certain embodiments used herein, all or a portion of the complementary hydrogen in the reactor in a given water addition or zone comes from a gas derived from the integrated process and the steam cracking zone (s) and reforming zone (s) in the system.

As used herein, the term " conversion of a crude to a chemical entity "refers to the conversion of a crude oil into a mixture of lower olefins such as but not limited to ethylene, propylene, butylene (including isobutylene), butadiene, MTBE, butanol, Benzene, toluene, xylene, and derivatives of the foregoing.

As used herein, the term " crude-to-chemical conversion ratio "refers to the ratio of input crude oil prior to desalting to petrochemical standards on a mass basis.

The term "Crude C4" refers to mixed C4 emissions from a steam cracking zone.

The term "C4 raffinate 1" or "C4 Raff-1" refers to a mixed C4s stream deviating from the butadiene extraction unit, i.e. mixed C4s from crude C4 except butadiene.

The term "C4 raffinate 2" or "C4 Raff-2" refers to a mixed C4s stream deviating from the MTBE unit, i.e. mixed C4s from crude C4 except butadiene and isobutene.

The term "C4 raffinate 3" or "C4 Raff-3" refers to a mixed C4s stream deviating from the C4 distillation unit, i.e. mixed C4s from crude C4 except butadiene, isobutene, and butane-1.

The term "pyrolysis gasoline" and its simplified form "py-gas" are used herein with their widely known meaning, i. E., About 400 DEG F., Lt; RTI ID = 0.0 > 300 F. < / RTI >

The term " pyrolysis oil "and its simplified form" py-oil "is used herein with its well-known meaning, i.e. it is a heavy oil fraction, C10 +, derived from steam cracking.

The term " hard pyrolysis oil "and its abbreviation" LPO "as used herein in certain embodiments refers to pyrolysis oils having a terminal boiling point of about 440, 450, 460 or 470 ° C.

The term " heavy pyrolysis oil "and its abbreviation" HPO "as used herein in certain embodiments refers to pyrolysis oils having an initial boiling point of about 440, 450, 460 or 470 ° C.

As used herein, the term " light cycle oil "and its abbreviation" LCO "refer to a light cycle oil produced by a fluid catalytic cracking unit. The distillation cut for this stream is, for example, in the range of about 220-330 占 폚. LCOs are often used in diesel blends according to diesel specifications, or they can be used as cutters for fuel oil tanks to reduce viscosity and sulfur content.

As used herein, the term " heavy cycle oil "and its abbreviation" HCO "refer to a heavy cycle oil produced by a fluid catalytic cracking unit. The distillation cut for this stream is, for example, in the range of about 330-510 [deg.] C. HCO is often used in process oil flushing systems. Additionally, the HCO is used to partially vaporize the debutanizer bottoms and then recycled back to the main fractionator in the fluid catalytic cracking unit as a recycle.

The term "cycle oil" as used herein refers to a mixture of different LCO and HCO.

Generally, an integrated process for producing petrochemicals and fuel products from a crude oil feed comprises at least a first atmospheric distillation zone fraction comprising a direct naphtha from a crude oil feed in an atmospheric distillation zone; A second atmospheric distillation zone fraction comprising at least a portion of the middle distillate, and an initial separation step for separating the third atmospheric distillation zone fraction comprising the atmospheric residue. The first vacuum distillation zone fraction containing the vacuum gas oil is separated from the third atmospheric distillation zone fraction in the vacuum distillation zone. At least part of the second atmospheric distillation zone fraction is processed to produce at least a first DHP fraction and a second DHP fraction, in a distillate water addition zone ("DHP") zone, The fraction contains naphtha and the second DHP fraction is used for diesel fuel production. The first vacuum distillation zone fraction contains at least a first fluid catalytic cracking fraction corresponding to at least light olefins, some of which are recovered as petrochemicals, Is processed in a fluid catalytic cracking zone to produce a second fluid catalytic cracking fraction corresponding to the cracked naphtha and a third fluid catalytic cracking fraction corresponding to the cycle oil.

The hard components from the atmospheric distillation zone, such as LPG, and the aromatic extraction zone raffinate, are processed in a mixed feed vapor cracking zone. All or a portion of the direct current naphtha is passed to the catalyst reforming zone to produce a chemical rich reformate as an additional feed to the aromatic extraction zone. The product from the mixed feed steam cracking zone comprises a mixed product stream containing H ₂ , methane, ethane, ethylene, mixed C 3 s, and mixed C 4 s, pyrolysis gasoline stream and pyrolysis oil stream.

From the mixed product stream, hydrogen gas, fuel gas, and petrochemicals ethylene, propylene and butylene are recovered. Ethane and non-olefinic C3s and C4s are recovered and the ethane and non-olefinic C3s are recycled to the steam cracking complex and the non-olefinic C4s are recycled to the steam cracking complex, or additional petrochemicals such as propylene and / Or a separate processing zone for the production of mixed butanol liquids. The pyrolysis gasoline is treated in the py-gas water addition zone to produce hydrotreated pyrolysis gasoline which is sent to an aromatic extraction complex to recover the raffinate containing aromatic petrochemicals and pyrolysis gasoline raffinate, . In certain embodiments, the fluid catalysed naphtha is also passed to an aromatic extraction complex to produce additional raffinate that is water-added and sent to additional aromatic petrochemical and steam cracking complexes.

Figures 1, 2 and 3 illustrate the conversion of crude oil to petrochemicals and fuel products, including a mixed feed steam cracking zone, a chemical modification zone and a high olefinic fluid catalytic cracking (HOFCC) zone 700 Fig. 1 is a schematic view showing a specific example of a process and a system. In general, Figs. 1 and 2 is a mixture feed steam cracking zone (MFSC) 230 represents the operation of the upstream Figure 3 mixture feed steam cracking comprising a zone (230), of Crude Oil transition zone down Indicates the operation in the stream. The integrated process and system includes a vacuum gas oil water addition room which operates as a vacuum gas oil hydrocracker 320 as shown in Figure 1 or as a vacuum gas oil hydrogen processor 300 as shown in Figure 2 .

Referring to Figures 1 and 2, the crude oil feed 102 comprises, in certain embodiments, AXL or AL, which may be in the atmospheric distillation zone (CDU) 110 , the saturated gas plant 150 and the vacuum distillation zone 160) is typically separated into a fraction in the crude complex 100, including the. Crude oil feed 102 is, in certain embodiments, LPN with light naphtha removed and into a fraction of atmospheric distillation zone 110 . As shown in FIG. 1, the light products, such as light hydrocarbons having less than six carbons, are passed to the mixed feed vapor decomposition zone 230 . In particular, the C2-C4 hydrocarbons 152 , including ethane, propane and butane, are passed through the saturated gas plant 150 from the atmospheric distillation zone 110 And is separated from the light oil and LPG 112 . Optionally, other hard products, indicated by dashed lines as stream 156 , such as light gases from refinery units in the integrated system and light gases from outside the battery limits in certain embodiments, are directed to the saturated gas plant 150 . The off-gas from the fluid catalytic cracking unit may be passed through an unsaturated gas plant and then integrated with the off-gas from the saturated gas plant 150 for normal handling of the fuel gas.

The separated C2-C4 hydrocarbons 152 are sent to the mixed feed vapor decomposition zone 230 . The off-gas 154 from the saturated gas plant 150 and the off-gas 208 from the mixed feed vapor decomposition zone 230 are typically known to contribute to a fuel gas ("FG") system, And removed as described above.

The direct current naphtha 136 from the atmospheric distillation zone 110 is passed to the catalytic reforming zone 400 to produce the chemical rich reformate 426 . In certain embodiments, all, substantial or substantial portions of the direct current naphtha 136 are sent to the catalyst reforming zone 400 . The remaining naphtha (if present) may be sent to the mixed feed vapor decomposition zone 230 (as shown in dashed lines) and / or added to the gasoline pool. Also, in certain embodiments, the direct naphtha stream 136 may contain naphtha from other sources as described herein, and may contain one or more of a wild naphtha, such as a combined distillate, gas oil, and / Naphtha ranges from above are often mentioned as hydrocarbons.

Also, in certain embodiments, optional diverters, shown as dashed valves and streams, bypass the catalyst reforming zone 400 and direct all or a portion of the direct current naphtha (full range, light naphtha, or heavy naphtha) And to the mixed feed steam cracking zone 230 . In this way, the manufacturer can change the amount of feed to match the desired output. Thus, all or a portion of the direct current naphtha may be sent to the catalyst reforming zone 400 and the remainder (if present) may be sent to the mixed feed vapor decomposition zone 230 . The amount can be determined according to, for example, the demand for olefinic petrochemicals, the demand for aromatic petrochemicals, the demand for gasoline, and / or the minimum range in which the unit is operated depending on the design capacity.

The intermediate distillate is used to produce diesel and / or kerosene, and additional feed to the mixed feed steam cracking zone 230 . In the embodiment shown in Figures 1 and 2, at least three different intermediate distillate cuts are processed for the production of fuel products and petrochemicals (via the steam cracker). In one example using the arrangement shown in Figures 1 and 2, the first atmospheric distillation zone middle distillate fraction 116 , referred to as the kerosene fraction in certain embodiments, contains a light kerosene range hydrocarbon, The second atmospheric distillation zone middle distillate fraction 122 , referred to as the diesel fraction, contains the heavy kerosene range hydrocarbons and the intermediate AGO range hydrocarbons, and in certain embodiments, the third atmospheric distillation zone intermediate referred to as the atmospheric gas oil fraction The distillate fraction ( 126 ) contains heavier AGO range hydrocarbons. In another example using the arrangement shown in Figures 1 and 2, the first intermediate distillate fraction 116 contains kerosene range hydrocarbons, the second middle distillate fraction 122 contains medium AGO range hydrocarbons, The middle distillate fraction ( 126 ) contains heavy AGO range hydrocarbons. In another example using the arrangement shown in Figures 1 and 2, the first middle distillate fraction 116 contains a portion of the light kerosene range hydrocarbon and the heavy kerosene range hydrocarbon, and the second middle distillate fraction 122 contains A portion of the heavy kerosene range hydrocarbon and a portion of the intermediate AGO range hydrocarbon and the third middle distillate fraction 126 contains the portion of the intermediate AGO range hydrocarbon and the heavy AGO range hydrocarbon.

For example, the first intermediate distillate fraction 116 may contain kerosene fuel product 172 , such as kerosene to produce jet fuel jet A or Jet A-1 specifications, and optionally other fuel products (not shown) Can be processed in the desulfurization process 170 . In certain embodiments herein, all or a portion of the first intermediate distillate fraction 116 is not used for fuel production, and is present in the mixed feed steam cracking zone 230 About And is used as a distillate water addition common feed to produce additional feed.

The second middle distillate fraction 122 is fed to the diesel hydrotreating zone 180 to produce a distillate water addition space to produce the wild naphtha 184 and a diesel fuel fraction 182 compliant with the Euro V diesel standard, Lt; / RTI > In an additional embodiment, all or a portion of the first intermediate distillate fraction 116 can be treated with a second middle distillate fraction 122 as indicated by the dashed lines.

In certain embodiments, all, a substantial, substantial, or major portion of the wild naphtha 184 may be sent alone or in combination with other wild naphtha fractions from within the integrated process to the mixed feed vapor decomposition zone 230 under; The portion that is not passed to the mixed feed steam cracking zone 230 may be sent to the crude complex 100 and / or to the direct catalytic reforming zone 400 and / or to the gasoline pool. In a further embodiment, all, substantial, substantial, or major portions of the wild naphtha 184 are passed alone or in combination with other wild naphtha fractions from within the integrated process into the crude complex 100 ; The portion that is not passed to the crude complex 100 may be sent to the mixed feed steam cracking zone 230 and / or to the direct catalytic reforming zone 400 and / or to the gasoline pool. In an additional embodiment, all, a substantial, substantial or major portion of the wild naphtha 184 is passed alone or in combination with other wild naphtha fractions from within the integrated process into the catalyst reforming zone 400 ; Portions that are not passed to the catalytic reforming zone 400 may be sent to the mixed feed steam cracking zone 230 and / or to the crude complex 100 and / or the gasoline pool. In embodiments where the wild naphtha 184 is sent through the crude complex 100 , all or a portion of the petroleum gas produced in the liquefied vacuum gas oil water addition room may be passed with the wild naphtha.

In a particular embodiment (as indicated by the dashed line), all, a substantial, substantial or major portion of the third middle distillate fraction 126 is combined with the vacuum gas oil stream 162 to form a vacuum gas oil water addition ball Sent to the zone; The portion that does not pass through the vacuum gas oil water addition zone can be sent to the high olefinic fluid catalytic decomposition zone 700 and bypasses the vacuum gas oil water addition zone. In a further embodiment (as indicated by the dashed line), all, substantial, substantial or major portion of the third middle distillate fraction 126 is sent to the high olefinic fluid catalytic cracking zone 700 , Bypassing the water addition zone; The portion that is not passed to the high olefinic fluid catalytic cracking zone ( 700 ) may be sent to the vacancy gas oil addition zone.

The atmospheric residue fraction ( 114 ) from the atmospheric distillation zone ( 110 ) is further separated in the vacuum distillation zone ( 160 ). The vacuum gas oil 162 from the vacuum distillation zone 160 is sent to the vacant gas oil water addition space. The heavier fraction 168 , vacuum residue from the vacuum distillation zone 160 can be sent to the fuel oil ("FO") pool or optionally processed in the residue treatment zone 800 shown in dashed lines. In certain embodiments, a small portion of the atmospheric residue fraction 114 can bypass the vacuum distillation zone 160 (not shown) and is directed to an optional residue treatment zone 800 .

In certain embodiments, all, substantial, substantial, or major portions of the vacuum gas oil 162 are routed to the vacuum gas oil water addition space. The water-untreated portion may be sent to the high olefinic fluid catalytic cracking zone ( 700 ). As shown in FIG. 1, the vacuum gas oil water addition hole has a vacuum gas oil hydrocracking zone 320 , which can operate under mild, moderate or severe hydrocracking conditions, And generally produces a hydrocracked naphtha fraction 326 , a diesel fuel fraction 322 , and a non-converting oil fraction 324 . The diesel fuel fraction 322 can be recovered, for example, as a fuel compliant with the Euro V diesel standard and combined with the diesel fuel fraction 182 from the diesel hydrotreating zone 180 . As shown in FIG. 2, the vacuum gas oil water addition hole is in a vacuum gas oil hydrotreating zone 300 that is capable of operating under mild, moderate or severe hydrotreating conditions, and generally comprises a hydrogenated gas oil fraction 304 , Naphtha and some intermediate distillates. The naphtha range product is the hydrotreated naphtha stream 306 Can be separated from the product in the vacuum gas oil hydrotreating zone ( 300 ). Alternatively, or in addition to the hydrotreated naphtha stream 306 , the cracked distillate stream 308 containing the hydrogenated distillate (and in certain embodiments, the naphtha range product) may contain additional water addition bubbles and / or diesel for separation into the hydrotreating zone 180, the product is sent to the diesel hydrotreating zone 180.

In certain embodiments, all, a substantial, substantial, or major portion of the wild naphtha fraction, stream 326 , or 306 from the vacuum gas oil water addition zone, alone or in combination with other Sent to the mixed feed steam cracking zone 230 in combination with the wild naphtha fraction; The portion that is not passed to the mixed feed steam cracking zone 230 may be sent to the crude complex 100 and / or the direct catalytic reforming zone 400 and / or to the gasoline pool. In a further embodiment, all, a substantial, substantial or major portion of the wild naphtha fraction from the vacuum gas oil water addition room can be either alone or in combination with other wild naphtha fractions from within the integrated process, 100 ); The portion that is not passed to the crude complex 100 is the mixed feed steam cracking zone 230 , And / or direct catalytic reforming zone 400 and / or gasoline pool. In an additional embodiment, all, a substantial, substantial or major portion of the wild naphtha fraction from the vacuum gas oil water addition zone, alone or in combination with other wild naphtha fractions from within the integrated process, ( 400 ); The portion that is not passed to the catalyst reforming zone 400 may be sent to the mixed feed steam cracking zone 230 and / or the crude complex 100 and / or the gasoline pool. In embodiments in which wild naphtha from the vacuum gas oil water addition zone is sent through the crude complex 100 , all or a portion of the liquefied petroleum gas produced in the vacuum gas oil water addition zone is passed with the wild naphtha .

The heavy product vacuum gas oil from the water addition zone is directed to the high olefinic fluid catalytic cracking zone 700 . Having a vacuum gas oil hydrotreating zone 300 In an embodiment, the heavy product is a hydrogenated gas oil fraction ( 304 ) containing a portion of the vacuum gas oil processor ( 300 ) effluent above the AGO, H-AGO or VGO boiling range. In embodiments having a vacuum gas oil hydrocracking zone 320 , the heavy product is a non-converting oil fraction 324 . A substantial, substantial or substantial portion of all of the heavy products from the vacuum gas oil water addition zone is directed to the high olefinic fluid catalytic cracking zone 700 . The remaining (if present) can be passed to the optional vacuum residue treatment zone 800 and / or passed to the mixed feed vapor decomposition zone 230 . Alternatively, the remainder may be recycled from the system and further processed (in decomposed VGO hydrocracking to extinction) and / or drained and / or passed to an optional residue treatment zone 800 .

The high olefinic fluid catalytic crack zone ( 700 ) is configured to produce a light olefin product ( 704 ) and a high olefinic fluid catalytic cracked naphtha ( 706 ). The light olefin product 704 can be recovered from the high olefinic fluid catalytic cracking zone 700 as is known or combined with the olefin recovery zone 270 and / or the mixed feed vaporization zone 230 as described herein It should be understood that it can be recovered. Off-gas from the high olefinic fluid catalytic cracking zone 700 can be integrated with the fuel gas system. In certain embodiments (not shown in FIG. 1), certain gases may be sent to the separation unit connected to the mixed feed vaporization zone 230 after treatment in an unsaturated gas plant, and / or LPGs May be sent to the mixed feed steam cracking zone 230 . (C2-stream and C3 < + > streams) All, substantial, substantial or major portions of the gas are sent through an unsaturated gas plant. The remainder, if present, may be sent to the mixed feed steam cracking zone 230 and / or the olefin recovery train 270 .

In certain embodiments, all or a portion of the high olefinic fluid catalyzed naphtha 706 may be added to the mixed feed steam cracking zone 230 as described below to increase the amount of raffinate as an additional feed can (and in conjunction with Figure 3) can be processed in the naphtha hydrotreating and collection center 610/620. Shown in dotted line, which part of the naphtha hydrotreating and collection center 610 is / are not sent to 620, and olefinic fluid catalytic cracked naphtha 706 it is recovered for hydrotreating and fuel production (not shown). For example, the object is sent at the maximum oil production chemical aspects, with both, a substantial portion, substantial portion or the main part of the naphtha hydrotreating and collection center 610/620 of the fluid catalytic cracked naphtha 706; The remainder, if present, is recovered for fuel production and entrainment into the gasoline pool.

In an additional embodiment, as shown in FIG. 4, all or a portion of the high olefinic fluid catalytic cracked naphtha 706 is hydrotreated and recovered for fuel production and penetration into the gasoline pool (not shown). Optionally, a portion of the high olefinic fluid catalytically cracked naphtha 706 that has not been recovered for fuel production may be removed to increase the amount of raffinate as an additional feed to the mixed feed steam cracking zone 230 , as described, it can be processed in the naphtha hydrotreating and collection center 610/620.

5, all or a portion of the high olefinic fluid catalytic cracked naphtha 706 is hydrotreated in the fluid catalytic cracked naphtha hydrotreating zone 670 and the hydrocracked hydrocatalyzed naphtha Stream 672 is sent directly to mixed feed steam cracking zone 230 . Any portion of the high olefinic fluid catalytic cracked naphtha 706 , shown in dashed lines and not sent to the mixed feed vapor decomposition zone 230 , is recovered for fuel production (not shown). In this manner, the components of the hydrocracked hydrocatalyzed naphtha stream 672 that are not decomposed in the mixed feed steam cracking zone 230 , including the aromatics, are separated from the pyrolysis gasoline from the mixed feed steam cracking zone 230 It increases the 212), and which is sent to the py-gas hydrotreating and collection center 600/620. In certain embodiments using the fluid catalytic cracked naphtha hydrotreating zone 670 , all, substantial, substantial, or major portions of the hydrotreated fluid catalytically cracked naphtha stream 672 may be removed from the mixed feed steam cracking zone 230 , ≪ / RTI > The remainder, if present, can be sent to the aromatics extraction 620 and / or passed to the recovery and / or chemical modification zone 400 for fuel production and indentation into the gasoline pool. In an additional embodiment using the fluid catalytic cracked naphtha hydrotreating zone 670 , all, substantial, substantial or major portions of the hydrotreated fluid catalytically cracked naphtha stream 672 are sent to the chemical modification zone 400 And the remainder, if any, can be sent to the aromatic extraction 620 and / or passed to the recovered and / or mixed feed steam cracking zone 230 for fuel production and entrainment into the gasoline pool.

Other products from the high olefinic fluid catalytic cracking zone 700 include cyclic oils, such as light cycle oil 708 and heavy cycle oil 710 . In certain optional embodiments, both the light cycle oil (708) or part is sent to the distillation Water was added ball zone 180, this mixture feed steam cracking zone 230, the diesel fuel fraction (182 passed by ) And the wild naphtha ( 184 ). In certain embodiments, all, a substantial, substantial or major portion of the light cycle oil 708 may be passed to the distillate water addition chamber 180 and the remaining portion may be sent to a vacuum gas oil processing zone. The heavy cycle oil stream 710 can be sent to the fuel oil pool or used as a feedstock for the production of carbon black.

3, the mixed feed steam cracking zone 230 , which operates as a high strength or low strength thermal cracking process, feeds its feed to the ethylene 202 , propylene 204 , , Mixed C4s 206 , pyrolysis gasoline 212 , pyrolysis oil 218 , and off-gas 208 Mainly convert. In addition, hydrogen 210 can be recovered from the cracked product and recycled to the hydrogen user within the composite limit. Although it is understood that in certain embodiments all or part of the ethane and propane can be converted, typical ethane and propane recycle in the steam cracking operation is not shown. In certain embodiments, all, substantial, substantial, or major portions of ethane are recycled to the mixed feed steam cracking zone 230 , and all, substantial, substantial, or major portions of propane are mixed feed steam cracking Zone 230 , respectively. In certain embodiments, hydrogen for the hydrogen user, both in the integrated process and in the system, is derived from the recovered hydrogen 210 from the decomposed product, and no external hydrogen is needed when the process is complete and equilibrium is reached. In a further embodiment, excess hydrogen can be recovered.

For simplicity, the operation in the olefin recovery train is not shown, but is well known and may be performed in the mixed feed steam cracking zone 230 as described herein for Figs. 3, 4, 5, 6, 7, 8, . ≪ / RTI >

A mixed C4s stream 206 containing a mixture of C4s from a mixed feed steam cracking zone 230 known as Crude C4s is fed to a butadiene extraction unit 500 for recovering the high purity 1,3-butadiene product 502 ). The first raffinate 504 ("C4-Raff-1") containing butane and butene is fed to a selective hydrogenation unit (SHU) and a methyl tertiary butyl ether ("MTBE") unit, SHU and MTBE zone 510 Where it is mixed with high purity fresh methanol 512 from the outside of the battery limit to produce MTBE 514 .

The second raffinate 516 ("C4 Raff-2") from the SHU and MTBE zone 510 contains the 1-butene product stream 522 and the alkane stream 524 (third raffinate & is sent to C4 distillation unit 520 for separation into C4-Raff-3 "), though in a particular embodiment the all or part of the remaining C4s will understand that can be converted, but the both thereof, a substantial portion, substantial portion or The main portion is recycled to the mixed feed steam cracking zone 230 . ( 202 ), propylene ( 204 ), propane ( 204 ), and propane ( 204 ) within a suitable arrangement of known separation steps for separating the steam cracking zone effluent, including hydrocarbons, hydrocarbons, hydrocarbons, And separation of the mixed C4s stream 206 occurs.

Pyrolysis gasoline (212) from the steam cracking zone 230 is supplied to the naphtha hydrotreating and collection center 610/620. In certain embodiments, selective hydrocarbons having 5-12 carbons are recovered from untreated pyrolysis gasoline and high olefinic fluid catalytic cracked naphtha ("FCCN") 706 , and the remainder are subsequently hydrogenated for aromatic recovery. In the naphtha hydrotreating unit 610 , the diolefins and olefins in the pyrolysis gasoline are saturated. Both, a substantial portion or substantial portion of the pyrolysis gasoline (212) from the steam cracking zone 230 is passed to the naphtha hydrotreating and collection center 610/620.

As noted above, in certain embodiments, all or part of the fluid catalytic cracked naphtha 706 may be fed to the mixed feed vapor decomposition zone 230 without the hydrotreating and aromatics separation steps, without the aromatic separation steps, Lt; / RTI > In a further embodiment, all or part of the fluid catalytic cracked naphtha 706 is recovered and used for fuel production.

Hydrotreated pyrolysis gasoline and fluid catalyzed cracked naphtha (in certain embodiments having C5s removed instead of or in combination with C5s from aromatic extraction zone 620 and recycled to mixed feed steam cracking zone 230 ) ( 620 ). Naphtha hydrotreating zone 610, and an aromatic extraction zone 620 and olefinic liquid catalyst in a single schematic block 610/620 in FIG. 3, 4, 5, 6, 7, 8, and 11 for simplicity . The naphtha hydrotreating zone 610 operates to hydrotreate pyrolysis gasoline 212 prior to aromatic recovery. In certain optional embodiments, the fluid catalytic cracked naphtha 706 is also hydrotreated within a separate hydrotreating zone (e. G., Shown in FIGS. 5, 21 and 24) and is subjected to hydrotreating pyrolysis gasoline in an aromatic extraction zone 620 ). ≪ / RTI >

In the embodiment herein, the chemical-rich reformate 426 is sent to the aromatic extraction zone 620 as an additional feed. Although the chemical-rich reformate 426 can be passed with pyrolysis gasoline and / or FCC naphtha in certain embodiments, the chemical-rich reformate 426 is treated in the catalytic reforming zone 400 , The processing can be bypassed. In a further embodiment, an operating mode is provided in which the chemical-rich reformate 426 can act as a feed to the aromatic extraction zone 620 and / or as a gasoline blending component. In this way, the manufacturer can change the amount of feed to match the desired output. Thus, 0-100% of the chemical-rich reformate 426 can be sent to the aromatic extraction zone 620 and the rest (if present) is sent to the gasoline blending pool (not shown). The amount can be determined according to, for example, the demand for aromatic petrochemicals, the demand for gasoline, and / or the minimum range in which the unit is operated depending on the design capacity.

The aromatic extraction zone 620 may comprise, for example, at least one overactive distillation unit and may comprise a hydrotreated pyrolysis gasoline and a fluid catalytically cracked naphtha in the presence of high-purity benzene, toluene, xylene, and C9 aromatics Lt ; RTI ID = 0.0 > 622 < / RTI > Respectively. The C5 raffinate 644 and the non-aromatic 646 (e.g., C6-C9) are recycled to the mixed feed vapor decomposition zone 230 . In certain embodiments, both, substantially or substantially all of C5 raffinate 644 and non-aromatic 646 Is passed to the mixed feed vapor decomposition zone ( 230 ). The heavy aromatic stream 642 (e.g., C10-C12) can be used as an aromatic solvent, as an octane boosting additive or as a cutter stock to the fuel oil pool. In certain embodiments ethylbenzene 628 can be recovered.

In certain embodiments, pyrolysis oil 218 may be blended into the fuel oil pool. In additional embodiments, pyrolysis oil 218 may be fractionated into hard pyrolysis oil and heavy pyrolysis oil (not shown). For example, the hard pyrolysis oil may be fed to the first intermediate distillate stream 116 and / or to the second intermediate distillate stream 230 for processing to produce additional feed to the diesel fuel product and / May be blended with stream 122 . In a further embodiment, the hard pyrolysis oil derived from pyrolysis oil 218 may be processed in a vacuum gas oil water addition room. In an additional embodiment, the hard pyrolysis oil from pyrolysis oil 218 may be blended into the fuel oil pool. In a further embodiment, the hard pyrolysis derived from the pyrolysis oil 218 may be processed in the residue processing zone 800 . In certain embodiments, all, substantial, substantial, or major portions of the hard pyrolysis oil may be passed to the diesel hydrotreating zone 180 and / or vacuum gas oil water addition space; The remainder may be blended into the fuel oil pool. The heavy pyrolysis oil may be blended into the fuel oil pool and used as a carbon black feed material and / or processed in an optional residue treatment zone 800 . In certain embodiments, all, a substantial, substantial or major portion of the pyrolysis oil 218 (hard and heavy) may be processed in the optional residue treatment zone 800 .

Figure 6 schematically illustrates further embodiments of processes and systems for the conversion of crude oil to petrochemicals and fuel products with metathesis conversion of C4 and C5 olefins to produce additional propylene. The process operates as described for either of FIGS. 1, 2, 4, or 5 for the upstream of the steam cracking operation and for the fluid catalytic cracking operation.

In the downstream of the steam cracking operation, the butadiene extraction train is fed directly from the diverter (from the dashed line) from the C4 distillation unit 520 to the mixed feed steam cracking zone 230 May optionally be operated in a manner similar to that of FIG. 3, shown as stream 524 .

In the metathesis operation mode, naphtha hydrotreating and collection center (610) / (620) C4 distillation unit 520 and a mixed C4 raffinate stream 532 from a C5 raffinate 540 from the ( "C4 Raff 3") Lt ; RTI ID = 0.0 > propylene 534 & Decomposition unit 530 for the metamorphosis conversion. In certain embodiments, all, substantial, substantial, or major portions of the cracked C5s from the py-gas hydrogenation processor can be sent to the metathesis unit 530 prior to aromatic extraction. As indicated, the portion 536 of the ethylene mixed feed steam cracking product 202 may be sent to the meteolytic unit 530 . In an additional embodiment, ethylene for metathesis unit 530 is supplied from outside of the composite limit, in addition to or in addition to the portion 536 of the ethylene mixed feed steam cracking product.

Selective recovery of various alkene and diene pyrolysis chemicals with 4 carbons and metathesis conversion to produce additional propylene is accomplished using a meteorolytic unit 530 . A stream 538 containing a substantially saturated mixture of C4 / C5 from the meteolysis unit 530 is recycled to the mixed feed vapor decomposition zone 230 .

In as shown in Figure 3, the configuration of Figure 6, the pyrolysis gasoline (212) from the steam cracking zone 230 is sent to the naphtha hydrotreating and collection center (610) / (620) where selection having 5-12 carbon The hydrocarbons can be recovered from the untreated pyrolysis gasoline and the fluid catalysed cracked naphtha, and the remainder are subsequently hydrogenated for aromatic recovery. Within the py-gas hydrotreating unit ("HTU"), diolefins and olefins in pyrolysis gasoline are saturated. In the aromatic extraction stage, the aromatics are separated from hydrotreated pyrolysis gasoline and hydrocatalyzed naphtha. For example, aromatic extraction can separate hydrotreated pyrolysis gasoline and hydrocatalyzed naphtha into high-purity benzene, toluene, xylene and C9 aromatics. The C 6 -C 9 aromatic stream 622 is recovered for the chemical market and the C 6 -C 9 non-aromatic stream 646 is recycled to the mixed feed vapor decomposition zone 230 and the C 10 -C 12 product stream 642 ) Can be used as an aromatic solvent or an octane boosting additive. In certain embodiments ethylbenzene 628 can be recovered. The C5 raffinate is sent to a meteolytic unit 530 , represented as stream 540 , and / or passed through a stream 644 , shown in dashed line in FIG. 6, to a mixed feed vapor decomposition zone 230 As in the example).

In the configuration shown in FIG. 6, an arbitrary die butter is shown, which is represented by a stream that is diverter and dashed line, bypassing the metathesis conversion process and thus all of C4 Raff-3 524 , To a mixed feed steam cracking zone 230 . In the meteorological mode, the flow passes to the meteorological switching unit 530 You can head. In a further alternative mode, the flow of C4 Raff-3 524 may be directed to the mixed feed vapor decomposition zone 230 and the metathesis conversion unit 530 . In this way, the manufacturer can change the amount of feed to match the desired output. Thus, a 0-100% third C4 raffinate stream 524 can be sent to the meteoric conversion unit 530 and the remainder (if present) is sent to the mixed feed vapor decomposition zone 230 . The amount can be determined according to, for example, the demand for ethylene, the demand for propylene, and / or the minimum range in which the unit is operated depending on the design capacity.

Figure 7 schematically illustrates additional embodiments of processes and systems for conversion of crude oil to petrochemicals and fuel products. The process operates as described for FIGS. 1, 2, 4, or 5, upstream of the steam cracking operation and for the fluid catalytic cracking operation. In this embodiment, an additional step is provided for converting the mixture of butenes to a suitable mixed butanol as a gasoline blending oxygenate. Suitable processes for converting a mixture of butenes to mixed butanol are described in one or more of co-owned patent publications US20160115107A1, US20150225320A1, US20150148572A1, US20130104449A1, US20120245397A1 and co-owned patents US9447346B2, US9393540B2, US9187388B2, US8558036B2, The entirety of which is incorporated herein by reference. In certain embodiments, particularly effective conversion processes known as "SuperButol (TM)" technology are integrated, which is a one-step process for converting a mixture of butenes to a mixed butanol liquid.

In the downstream of the steam cracking operation, the butadiene extraction train is fed directly from the diverter (from the dashed line) from the C4 distillation unit 520 to the mixed feed steam cracking zone 230 May optionally act in a manner similar to that of FIG. 3, shown as stream 524 . The Crude C4 processing center 550 is integrated for selective recovery of diene pyrolysis chemistries having various alkenes and four carbons and can be integrated into a butanol production unit (e.g., a "SuperButol ™" unit ) Hydrates a portion of C4.

For example, the mixed butanol production zone 550 operates to convert butene to butanol from the undevaluated refinery / petrochemical mixed olefin stream. Butanol provides an alternative option for oxygenates in gasoline blends. The Crude C4 processing center 550 includes, for example, the conversion of butene to butanol in one or more high pressure catalytic reactors, followed by gravity separation of butene and butanol from water, and subsequent separation of butanol product from butene by distillation do. The process steps include butene and water replenishment and recycling, butanol reaction, high pressure separation, low pressure separation, distillation stage distillation (product column) and aqueous distillation column.

7 shows a stream 552 containing butenes from the C4 distillation stage and stream 552 is sent to a crude C4 processing zone such as butanol production unit 550 to produce a mixture of butenes in a mixed butanol liquid 554 , in . In certain embodiments, all, substantial, substantial, or major portions of stream 552 are sent to butanol production unit 550 . The alkane ( 556 ) is recycled to the mixed feed vapor decomposition zone ( 230 ).

In the configuration of Figure 7, as shown in Figures 1 and 3, it is sent to the pyrolysis gasoline 212 naphtha hydrotreating and collection center (610) / (620) from the steam cracking zone 230 wherein 5 to 12 carbon Selective hydrocarbons having hydrocarbons can be recovered from untreated pyrolysis gasoline and hydrocatalyzed naphtha, and the remainder is hydrotreated sequentially for aromatic recovery. C5s is recycled to the mixed feed steam cracking zone 230. [ Within the py-gas hydrotreating unit, the diolefins and olefins in the pyrolysis gasoline are saturated. Hydrogenated pyrolysis gasoline from py-gas hydrotreating unit is sent to aromatic extraction. In the aromatic extraction stage, the aromatics are separated from hydrotreated pyrolysis gasoline and hydrocatalyzed naphtha. For example, aromatic extraction can separate hydrotreated pyrolysis gasoline and hydrocatalyzed naphtha into high-purity benzene, toluene, xylene and C9 aromatics. C6-C9 aromatics stream 622 may be recovered for the chemical market and C5 raffinate 644 and non-aromatics 646 (e.g., C6-C9) may be recovered for mixed feed steam cracking zone 230 And the heavier aromatic 642 (e.g., C10-C12) product may be used as an aromatic solvent or an octane boosting additive. In certain embodiments ethylbenzene 628 can be recovered.

In the configuration shown in Figure 7, an arbitrary die butter is shown, which is represented by a stream that is diverter and dashed line, bypassing the metathesis conversion process and thus all of C4 Raff-3 524 , To a mixed feed steam cracking zone 230 . In an alternative mode, the flow may be directed to a mixed butanol production zone 550 for conversion of the mixture of butenes to mixed butanol. In a further alternative mode, the flow of C4 Raff-3 524 may be directed to a mixed feed steam cracking zone 230 and a mixed butanol production zone 550 . In this way, the manufacturer can change the amount of feed to match the desired output. Thus, 0-100% of the third C4 raffinate stream 524 can be sent to the mixed butanol production zone 550 and the remainder (if present) is sent to the mixed feed vapor decomposition zone 230 . The amount can be determined according to, for example, the demand for ethylene, the demand for mixed butanol, and / or the minimum range in which the unit is operated depending on the design capacity

Figure 8 schematically illustrates further embodiments of processes and systems for conversion of crude oil to petrochemicals and fuel products. In this embodiment, the metathesis conversion of C4 and C5 olefins to produce additional propylene, and / or the additional step of conversion of the mixture of butenes to mixed butanol, suitable as a gasoline blending oxygenate and for octane improvement Are integrated. The process operates at the upstream of the steam cracking operation and for the fluid catalytic cracking operation as described for either of FIGS. 1, 2, 4 or 5.

In the downstream of the steam cracking operation, the butadiene extract train is fed from the C4 distillation unit 520 directly to the mixed feed steam cracking zone 230 from the diverter (by dashed line) May optionally operate in a manner similar to that of FIG. 3, shown as stream 524 . The configuration of FIG. 8 may include selective recovery of diene pyrolysis chemistries having various alkenes and four carbons, metathesis conversion to produce additional propylene, and / or conversion of a mixture of butenes to a suitable mixed butanol as a gasoline blending oxygenate .

FIG. 8 is a graph showing the effect of the butene mixture in the mixed C4 liquid zone 554 Shows a stream 552 containing butenes from the C4 distillation stage ("C4 Raff-3"), which is sent to the butanol production unit 550 for conversion. The alkane 556 is recycled to the mixed feed vapor decomposition zone 230 . Also, the portion 532 of the 2-butene-rich raffinate-3 from the C4 distillation unit 520 is directed to the additional propylene 534 And is passed to a meteorological unit 530 for metathesis conversion. As indicated, the portion 536 of the ethylene mixed feed vapor decomposition product may be sent to the meteolysis unit 530. [ In an additional embodiment, the ethylene for the metathesis unit 530 is supplied from outside of the composite limit, in addition to or in addition to the portion 536 of the ethylene product 202 . Stream 538 having a nearly saturated C4 / C5 mixture from the metathesis unit is recycled to the mixed feed vapor cracking zone.

In the configuration of Figure 8, as shown in Figure 3, the pyrolysis gasoline (212) from the steam cracking zone 230 is sent to the naphtha hydrotreating and collection center (610) / (620) where selection having 5-12 carbon Hydrocarbons can be recovered from untreated pyrolysis gasoline and hydrocatalyzed naphtha, and the remainder is hydrotreated sequentially for aromatic recovery. Within the py-gas hydrotreating unit, the diolefins and olefins in the pyrolysis gasoline are saturated. Hydrogenated pyrolysis gasoline from py-gas hydrotreating unit is sent to aromatic extraction. In the aromatic extraction step, aromatics are separated from hydrotreated pyrolysis gasoline and hydrocatalyzed naphtha. For example, aromatic extraction can separate hydrotreated pyrolysis gasoline and hydrocatalyzed naphtha into high-purity benzene, toluene, xylene and C9 aromatics. The C6-C9 aromatics stream 622 , BTX, may be recovered for the chemical market and the non-aromatics 646 (e.g., C6-C9) may be recycled to the mixed feed steam cracking zone 230 , A heavy aromatic 642 (e.g., C10-C12) product can be used as an aromatic solvent or an octane boosting additive. In certain embodiments ethylbenzene 628 can be recovered. The feed stream 540 can be sent to the meteorological unit 530 as shown and / or optionally recycled to the mixed feed steam cracking, as indicated by the dotted line stream 644 . In certain embodiments (not shown), all or part of the cracked C5s from the py-gas hydrogenation processor may be sent to the metathesis unit 530 prior to aromatic extraction.

In the configuration shown in Fig. 8, an arbitrary diverter is shown, which is represented by a diverter and dashed stream, bypassing the process of the metathesis conversion process and the mixed butanol of the mixture of butenes for conversion, Substantial, substantial, or major portion of Raff-3 524 into mixed feed steam cracking zone 230 . An optional valve may also be provided to direct the flow of C4 Raff-3 to one or both of the metathesis conversion unit 530 and / or the mixed butanol production zone 550 for conversion of the mixture of butenes to mixed butanol have. In a further alternative mode, the flow of C4 Raff-3 524 is directed to the bottom of the mixed feed vapor decomposition zone 230 Each of the metamorphosis switching unit 530 , (Stream ( 532 ), and a mixed butanol production zone 550 , (Stream (As < RTI ID = 0.0 > 552 ). ≪ / RTI > In this way, the manufacturer can change the amount of feed to match the desired output. Thus, all, substantial, substantial or major portions of the third C4 raffinate stream may be sent to the meteoric conversion unit 530 and the remainder (if any) may be fed to the mixed feed steam cracking zone 230 and / And is sent to the butanol production zone 550 . In certain embodiments, all, substantial, substantial, or major portions of the third C4 raffinate stream are sent to the meteoric conversion unit 530 and the remainder (if present) is fed to the mixed feed vapor decomposition zone 230 . In a further embodiment, all, substantial, substantial or major portions of the third C4 raffinate stream are sent to the metathesis conversion unit 530 and the remainder (if present) is fed to a mixed butanol production zone 550 ). In a further embodiment, all, substantial, substantial, or major portions of the third C4 raffinate stream are sent to a mixed butanol production zone 550 for the production of mixed butanol, the remainder (if present) Decomposition zone 230 and the decomposition zone conversion unit 530. [ In a further embodiment, all, substantial, substantial, or major portions of the third C4 raffinate stream are sent to a mixed butanol production zone 550 for the production of mixed butanol, the remainder (if present) And is sent to the decomposition zone 230 . In a further embodiment, all, a substantial, substantial or major portion of the third C4 raffinate stream is sent to a mixed butanol production zone 550 for the production of mixed butanol and the remainder (if present) 530 ). The amount can be determined according to, for example, the demand for ethylene, the demand for propylene, the demand for mixed butanol, and / or the minimum range in which the unit is operated depending on the design capacity.

Figures 9 and 11 schematically illustrate further embodiments of processes and systems for conversion of crude oil to petrochemicals and fuel products. In the arrangement of FIGS. 9 and 11, the crude oil feed 102 , in certain embodiments AXL or AL, is fed to the atmospheric distillation zone 110 of the crude complex 100 . All or a portion of the direct current naphtha 136 is passed to the catalyst reforming zone 400 to produce a chemical rich reformate 426 . The lighter product 152 is sent to the mixed feed vapor decomposition zone 230 . The middle distillate fractions 116 and 122 are used to produce kerosene and diesel, and wild naphtha 184 as an additional feed to the mixed feed steam cracking zone 230 . In certain embodiments (as indicated by the dashed lines), all or a portion of the third middle distillate fraction 126 is sent to the vacuum gas oil water addition room, which is fed to the vacuum gas oil hydrocracker Or as a vacuum gas oil hydrotreater as shown in Fig. In certain embodiments (as indicated by the dashed lines), all or a portion of the third middle distillate fraction 126 is directed to the high olefinic fluid catalytic cracking zone 700 , bypassing the vacuum gas oil water addition zone do. In a further embodiment, the third middle distillate fraction 126 can be separated between the vacuum gas oil water addition room and the high olefinic fluid catalytic decomposition zone 700 .

The atmospheric residue fraction ( 114 ) is further distilled in the vacuum distillation zone ( 160 ). The VGO 162 from the vacuum distillation zone 160 is sent to the vacuum gas oil water addition room and the vacuum gas oil water addition room can be operated as a high intensity vacuum gas oil hydrotreater or as a weak vacuum gas oil hydrocracker have. The heavier fraction 168 , vacuum residue from the vacuum distillation zone 160 can be sent to the fuel oil ("FO") pool or optionally processed in the residue treatment zone 800 shown in dashed lines.

As shown in FIG. 9, the vacuum gas oil hydrotreater 300 can operate under mild, moderate or severe hydrotreating conditions, and generally produces decomposed product 308 and hydrotreated gas oil 304 . [0154] The vacuum gas oil treatment apparatus 300 The decomposed product 308 is sent to the diesel hydrotreating zone 180 . The hydrotreated gas oil 304 from the vacuum gas oil hydrotreater 300 is directed to a high olefinic fluid catalytic cracking zone 700 configured to produce the maximum light olefin product 704 . The light olefin product 704 may be recovered from the high olefinic fluid catalytic cracking zone 700 as is known or may be recovered from the olefin recovery zone 270 and / or the mixed feed vaporization zone 230 as described herein It should be understood that they can be recovered in combination. The hydrotreated gas oil fraction ( 304 ) generally contains a portion of the exhaust gas from the vacuum gas oil processor ( 300 ) that is above the AGO, H-AGO or VGO range.

10, the vacuum gas oil hydrocracker 320 may be operated under mild, moderate or severe hydrocracking conditions and may include a hydrocracked naphtha product 326 , a diesel fuel fraction 322 ), And a non-converting oil fraction 324 . The hydrocracked naphtha 326 from the vacuum gas oil hydrocracker 320 is directed to the mixed feed vapor decomposition zone 230 . The non-converting oil fraction 324 is sent to the high olefinic fluid catalytic cracking zone 700 . The diesel fuel fraction 322 can be recovered, for example, as fuel conforming to the Euro V diesel standard and combined with the diesel fuel fraction 182 from the diesel hydrotreating zone 180 .

In addition, an aromatic recovery center 620 is included, wherein the aromatics are separated from pyrolysis gasoline 212 and hydrogenated pyrolysis gasoline can be obtained. The C6-C9 aromatics 622 are recovered for the chemical market and the C6-C9 non-aromatics 646 are recycled to the mixed feed vapor decomposition zone 230 and the C10-C12 product 642 is recovered as an aromatic solvent Or as a gasoline blender as an octane boosting additive.

In certain embodiments, as shown within the dashed line, the high olefinic fluid catalytically cracked naphtha 706 is hydrotreated and fed to the aromatic extraction, and the light naphtha and the intermediate naphtha are fed into the mixed feed vapor decomposition zone 230 . The C5 and C9 streams from the high olefinic fluid catalytic cracker can be recycled to the mixed feed steam cracking zone 230 .

In a further embodiment, all or a portion of the high olefinic fluid catalysed naphtha 706 is used as a gasoline blending stock rather than being used as a feed to the mixed feed steam cracking zone as a whole; The remainder of the high olefinic fluid catalytic cracked naphtha 706 may be used as feed to the mixed feed vapor decomposition zone 230 .

In an additional embodiment, all or a portion of pyrolysis oil 218 from vapor decomposition zone 230 may be passed through a catalytic hydrogen addition process, such as a residue hydrocracking or conditioning process. In an additional embodiment, pyrolysis oil ( 218 ) is split into a hard and a heavy fraction, whereby the hard fraction is fed to a gas oil water addition space and the heavy fraction is fed to a catalytic hydrogen addition process, such as a residue hydrocracking or conditioning process.

In still further embodiments, all or a portion of the hydrotreated gas oil fraction or non-converting oil fraction from the gas oil water addition room may comprise, for example, an isodewaxing unit that enables the production of Group III lubricating oil or lubricating oil feed material, and And passed to the hydrogenation finishing reaction unit.

Figures 12, 13 and 21 illustrate embodiments of processes and systems for conversion of crude oil to petrochemicals and fuel products, including a mixed feed steam cracking zone and a high olefinic fluid catalytic cracking zone ( 700 ) It is schematically shown. In general, Figs. 12 and 13 also shows the operation of the upstream from the mixed feed steam cracking zone 230 21 illustrates the operation of the downstream containing mixture feed steam cracking zone 230.

The crude oil feed 102 is passed to the crude complex 100 . In the embodiments of Figures 12, 13 and 21, the crude complex 100 generally comprises an atmospheric distillation zone 110 , a saturated gas plant 150 and a vacuum distillation zone 160 . The atmospheric distillation unit is used in a well-known arrangement.

Crude intermediate stream obtained from the separation of the de composite 100 from the feed 102 includes the following: Crude conjugate off resulting in the 100 through the saturated gas plants (150), gas (154) , Which is passed to the fuel gas system; The light oil stream 152 obtained in the crude complex 100 through the saturated gas plant 150 is passed to the mixed feed steam cracking zone 230 ; All or a portion of the one or more direct naphtha stream (s), in this embodiment the light naphtha stream 138 and the heavy naphtha stream 140 , the light naphtha stream 138 , are passed to the mixed feed vapor decomposition zone 230 All or a portion of the heavy naphtha stream 140 is passed to the catalyst reforming zone 400 to produce a chemical rich reformate 426 ; A first intermediate distillate stream 118 , such as a light kerosene stream, a kerosene desulfurization zone 170 , e.g., a mercaptan oxidation zone; Passed through a second intermediate distillate stream 120 , such as a heavy kerosene stream, diesel hydrotreating zone 180 ; Passed through a third intermediate distillate stream 128 , such as an intermediate atmospheric gas oil stream, diesel hydrotreating zone 180 ; A fourth intermediate distillate stream 130 , such as a heavy atmospheric gas oil stream, a high olefinic fluid catalytic cracking zone 700 (directly or optionally through a vacuum gas oil hydrotreating zone 300 as indicated by the dashed line) ); An atmospheric residue fraction ( 114 ) passing through the vacuum distillation zone ( 160 ) of the crude complex ( 100 ); A vacuum gas oil stream 162 from the vacuum distillation zone 160 passing through the vacuum gas oil water addition chamber ; And vacuum residues 168 from the vacuum distillation zone 160 , all or a portion of which may optionally be passed through the residue treatment zone 800 , and / or the fuel oil pool.

The intermediate stream from the crude complex 100 is used in an effective manner in the integrated process and system herein. The light mineral oil stream 152 and a portion of the direct naphtha stream (s), in this embodiment the light naphtha 138 , are fed to the mixed feed steam cracking zone 152 as a feed for the conversion to light olefins and other valuable petrochemicals ( 230 ). In certain embodiments, all, substantial, or substantial portions of the light naphtha 138 are directed to the mixed feed vapor decomposition zone 230 and the remainder (if present) is passed to the catalyst reforming zone 400 . All or a portion of the heavy naphtha 140 from the atmospheric distillation zone 110 is passed through a catalytic reforming zone 400 to produce the rich chemical reformate 426, which is added to the aromatic extraction zone 620 May be sent as an enemy feed or used for gasoline blending. In certain embodiments, all, substantial or substantial portions of the heavy naphtha 140 are sent to the catalyst reforming zone 400 and the remainder (if any) is passed to the mixed feed vapor decomposition zone 230 . A DC naphtha stream, a light naphtha 138 and a heavy naphtha 140 , medium One or both may be optionally steam-stripped within the side stripper prior to sending to the mixed feed steam cracking zone 230 .

Although not shown, the components of the well-known crude complex include feed / product and pump-air heat exchangers, crucible filling heaters, crud tower (s), product strippers, cooling systems, high temperature and low temperature overhead drum systems A re-contactor and an off-gas compressor, and a unit for water washing of the overhead condensing system. The atmospheric distillation zone 110 may include well-known design features. Further, in certain embodiments, the naphtha, kerosene and atmospheric gas oil products from the atmospheric distillation column are vapor-stripped within a side stripper and the atmospheric residue is removed from the steam-stripping section in the reduced- - Stripped.

The feed to the atmospheric distillation zone 110 is primarily the crude feed 102 , but from the diesel hydrotreating zone 180 ; And in certain embodiments, the wild-naphtha, LPGs, and off-gas streams from the vacuum gas oil water addition stage and / or the optional residue treatment zone may be sent to the atmospheric distillation zone 110 where they are passed to the decomposition complex You must understand that you are discerned before. A demineralization unit (not shown) is typically included upstream of the distillation zone 110 . Significant amounts of water required for desalination can be obtained from acidic water strippers in integrated processes and systems.

The desalination unit refers to a well-known arrangement of vessels for crude oil desalination and is operated to reduce the salt content to a target level, for example, to a level of about 10, 5, or 3 wppm or less as used herein . In certain embodiments, two or more desorbents are included to achieve a target salt content of about 3 wppm or less.

In one embodiment of the present crude complex 100 herein, the feed 102 may be fed to the desalination unit, for example, at about 105-165, 105-150, 105-145, 120-165, 120-150, 120-145, 125-165, 125-150, 125-145, and in certain embodiments is preheated to a temperature in the range of about 135 ° C. In a suitable de-base single step to a typical level of from about ^{0.00285 kg / m 3 (1 lb} / 1000 bbl) it is designed to remove the salt. In certain embodiments, a plurality of preheat and desalination trains are used. The de-base operating pressure can be based on a pressure margin greater than the crude and water mixture vapor pressure at the de-base operating temperature, such as about 2.75-4.15, 2.75-3.80, 2.75-3.65, 3.10-4.15, 3.10-3.80, 3.10 -3.65, 3.25-4.15, 3.25-3.80, 3.25-3.65 and in certain embodiments to about 3.45 barg.

The atmospheric distillation zone 110 may use a fractionated product and a pumparound to provide sufficient heat for desalination. In certain embodiments, the de-base operating temperature can be controlled by a diesel pump air swing heat exchanger. In certain embodiments, the de-base saline water pre-heats the debris in the de-base-helix-type heat exchanger to minimize runoff and to achieve run-down cooling for the cooling water prior to saline being sent to the wastewater system.

In certain embodiments, the demineralized crude is preheated to a temperature (占 폚) in the range of about 180-201, 185-196, or 189-192, before entering the preflash tower. The preflash tower removes LPG and light naphtha from the crud before entering the final preheat exchanger. The preflash tower minimizes the operating pressure of the preheating train and also reduces the size requirement of the main crucible column to maintain liquid phase operation at the cruze furnace pass valve.

In one example of a suitable cold distillation system, the crucible furnace is heated to about 350-370, 355-365 or 360 (680 ° F) below the specific cut point prior to entering the flash zone of the cruze tower, Gt; (C) < / RTI > The furnace is designed at a suitable outlet temperature, for example, a temperature in the range of about 338-362, 344-354, or 348.9 (660F). The crucible column flash zone conditions include temperatures in the range of about 328-374, 328-355, 337-374, 327-355, or 346.1 (655F), and about 1.35-1.70, 1.35-1.60, 1.44-1.70 (Barg) in the range of 1.44-1.60 or 1.52.

In certain embodiments, the crued tower contains 59 trays and produces 6 cuts, and the draw temperature for each product is: light naphtha, 220 ° F (104 ° C) (overhead vapor); Heavy naphtha, 321 ° F (side draw); Kerosene, 205 ° C (401 ° F) (side draw); Diesel, 263.7 ° C (503 ° F) (side draw); AGO, 322.2 DEG C (612 DEG F) (side draw); Atmospheric residue, 645 ° C (tower bottom). Heavy naphtha dods include a rebound side stripper for the diesel pump surround, controlled at 185 ° C (365 ° F) D86 endpoints. Kerosene dross contains steam strippers at 14.54 kg / m ³ (5.1 lb / bb); The draw ratio is limited at the end by the freezing point. The diesel draw contains a steam stripper at 14.54 kg / m ³ (5.1 lb steam per bbl), which is controlled at 360 ° C (680 ° F) D 86 95% point. The AGO draw contains a vapor stripper at 14.82 kg / m ³ (5.2 lb steam per bbl), which sets overflash at 2 vol% for the crud. The Crude Tower also contains three pump-arounds for the tower stills, diesel, and AGO. The diesel pump air provides heat to the heavy naphtha stripper boiler and debutanee boiler while controlling the de-base operating temperature through swing heat. The bottom stream of the atmospheric column is vapor stripped at 28.5 kg / m ³ (10 lb steam / bbl).

The atmospheric residue stream 114 from the atmospheric distillation zone 110 is withdrawn from the vacuum distillation zone 160 And the vacuum distillation zone 160 supplies the atmospheric residue fraction 114 to the hard and heavy vacuum gas oil stream 162 , which is supplied to the VGO water addition chamber, and the vacuum residue stream 168 , 0-100 wt% thereof optionally it may be sent to the residue treatment zone 800; portions which are not processed in a fractionation and to a residue processing zone 800 is, for example, fuel oil pool (e. g. high sulfur fuel oil pool ). ≪ / RTI > Vacuum distillation zone 160 may include well-known design features, such as reduced pressure levels (mm Hg absolute pressure) operation within a range of about 30-40, 32-36, or 34, It can be held by an ejector or a mechanical vacuum pump. Vacuum column bottoms can be exchanged for cold to minimize coking, for example, at temperatures in the range of about 334-352, 334-371, 338-352, 338-371, or 343.3 (650F) It can be quenched. Vacuum distillation can be achieved in a single step or in multiple steps. In certain embodiments, the atmospheric residue fraction 114 is heated in a direct burned furnace and heated at a temperature in the range of about 390-436, 390-446, 380-436, 380-446, or 400-425 And charged with a vacuum fractionator.

In one embodiment, the atmospheric residue is heated to a temperature in the range of about 399-420, 399-430, 389-420, 389-430, or 409.4 (769F) in a vacuum furnace to about 392-412 (Mm Hg absolute pressure) within the range of about 30-40, 32-36, or 34, and a temperature (in degrees Celsius) in the range of 405-402, 392-422, 382-412, 382-422, Lt; / RTI > The vacuum column is maintained at a theoretical cut-point temperature (占 폚) in the range of about 524-551, 524-565, 511-551, 511-565 or 537.8 (1000F) by removing the hard VGO and heavy VGO from the vacuum residue . The overhead vacuum system may include two parallel trains of a jet ejector each including three jets. A conventional vacuum pump is used in the final stage. In one embodiment, the vacuum tower is sized for 0.35 C- agent and wetting rate of about ^{14.68 lpm / m 2 (0.3 gpm} / ft 2) in the cleaning zone bottom. Cleaning Zone Slope Wax is recycled into a vacuum furnace to minimize fuel oil production. Vacuum bed debris is quenched through exchange for crude at temperatures in the range of about 334-352, 334-371, 338-352, 338-371 or 650 ° F (343.3 ° C) to minimize caulking .

The saturated gas plant 150 is designed to process light oils to separate the LPG range components from the appropriate fuel gas range components as the steam cracker decomposition zone feed, And the like. The saturated gas plant 150 includes off-gas compression and recontacting to maximize LPG recovery, LPG fractionation from light naphtha, and off-gas / LPG amine treatment. In the integrated system and process embodiments herein, the light oil fraction processed in the at least one saturated gas plant is derived from crude distillation, such as light oil and LPG. In addition, be sent to the light gas, and the gas plant 150 is saturated as shown by a broken line light gas from the external of the battery limits in certain embodiments is an optionally stream 156 from the other light products, for example an integrated system in refinery units . For example, stream 156 may include off-gas and light oil fractions from diesel hydrotreating zone 180 , gas oil water addition room, py-gas hydrotreating zone 600 , and / or residue processing zone 800 ≪ / RTI > The products from the saturated gas plant 150 include an off-gas stream 154 , containing C1-C2 alkanes, passed through a fuel gas system and / or a steam cracker complex; And a light oil stream 152 , C2 +, and passed to the mixed feed vapor cracking unit 230. [

In certain embodiments, a suitable saturated gas plant 150 includes amine and corrosive material cleaning of the liquid feed, and amine treatment of the vapor feed prior to subsequent stages. The crude tower overhead vapor is compressed and recontacted with the naphtha before entering the amine scrubber for H ₂ S removal and then sent to the steam cracker complex. The recontact naphtha is debenated to remove LPGs and the LPGs are amine washed and sent to the steam cracker complex. The de-butanized naphtha is sent to the steam cracker complex separately from the heavy naphtha. As is known, the light naphtha absorbs C4 and heavier hydrocarbons from the vapor as it moves upward through the absorber / debutane. The off-gas from the absorber / debutanizer is compressed and sent to the refinery fuel gas system. The debutanizer tower low stream is sent to the mixed feed steam cracker as a source of additional feed.

The heavy naphtha 140 from the atmospheric distillation zone (110) both, a substantial portion or substantial portion (and all or a portion of the heavy naphtha 138] In certain embodiments of the example, not shown) is rich reformate 426 chemicals reforming catalyst is passed to the zone (400), rich in chemicals reformate 426 to produce is used for additionally as feed can be sent to the aromatic extraction zone 620 and / gasoline blending. Catalyst reforming zone 400 generally comprises a naphtha hydrotreating zone and a catalyst reforming zone. In certain embodiments, the catalyst modification zone also includes a reformate splitter and / or a benzene saturation unit. The products from the naphtha hydrotreating zone include LPG and gas, and the hydrogenated naphtha product sent to the naphtha reformer. The naphtha reformer converts the hydrogenated naphtha to a chemical-rich reformate, which is a significant source of aromatic bulk chemicals from the aromatics extraction zone downstream of the steam cracking operation. In certain embodiments, all or part of the chemical-rich reformate may be used in a conventional manner, i.e. as a gasoline blending component; The remainder may be used as feed to the mixed feed steam cracker.

The reactions involved in catalyst modification include hydrocracking, cyclic hydrogen elimination, dehydrogenation, isomerization, and to a lesser extent, demethylation and dealkylation. Certain hydrocarbon / naphtha feed molecules can go through more than one reaction category and / or form more than one product. The hydrocarbon / naphtha feed composition, the impurities present therein, and the desired product determine such process parameters as the choice of catalyst (s), process type, and the like.

The rate of reaction to the conversion of naphthene to aromatics is favored at low pressures, but so is the formation of coke which deactivates the catalyst. Thus, the aromatic yield increases with low operating pressure, but catalyst regeneration must be performed more often. Various methods are known for handling coke formation while maintaining a certain low operating pressure. The general type of catalyst reforming process configuration is systematically different and wherein the reforming catalyst is regenerated for removal of the coke formed during the reaction. Catalyst regeneration involving harmful coke combustion in the presence of oxygen includes semi-regeneration processes, cyclic regeneration and continuous catalyst regeneration (CCR). The semi-regeneration is the simplest configuration, and the entire unit, including all the reactors in the series, is stopped for catalyst regeneration in all reactors. The cyclic configuration utilizes an additional "swing" reactor that allows one reactor at a time to be off-line for regeneration while the other remains operational. The most complex continuous catalyst regeneration configurations provide operation that is essentially uninterrupted by catalyst removal, regeneration and replacement. The continuous catalyst regeneration configuration involves the ability to increase the strength of the operating conditions due to the higher catalytic activity, while the associated capital investment is inevitably higher.

In certain embodiments, the direct naphtha, or heavy naphtha, is separated into a non-normal rich stream containing a normal paraffin (n-paraffin) rich stream and a branched paraffin. This is accomplished using a separation zone 402 (shown as a dashed line, optionally), which may be based, for example, on commercially available technology from Honeywell UOP, US (MaxEne ™). The n-paraffin rich stream bypasses the catalyst reforming zone and is sent to the mixed feed vapor decomposition zone 230 , which allows for an increase in the combined yield of ethylene and propylene. Processing of the n-paraffin-rich stream in the mixed feed steam cracking zone 230 can also reduce caulking, which can promote throughput between de-coking cycles or increase in extended run-in. When the non-normal paraffin-rich stream is also processed in a catalytic reformer, there is a significant benefit, including improved selectivity and reduced coke formation for the catalyst, which can facilitate increased throughput.

A schematic process flow diagram of the catalytic reforming zone 400 in combination with the unit of FIG. 16 in certain embodiments is shown in FIGS. 14 and 15. FIG. The naphtha hydrotreating zone 410 is integrated with the catalytic reforming reaction zone 414 for processing the direct naphtha stream 136 (Figure 14) or the heavy naphtha stream 140 (Figure 15) , A chemical-rich reformate 426 as a gasoline blending component, or both as a chemical recovery and as a gasoline blending component. In certain embodiments, all, substantial, substantial or major portions of the chemical-rich reformate 426 may be passed to the aromatic extraction zone 620 and the remainder may be blended in the gasoline pool.

The naphtha feed 136 or 140 (or the non-normal paraffin-rich stream from the optional separation zone 402 in certain embodiments) is fed to a naphtha hydrotreating zone (not shown) to produce the hydrotreated naphtha stream 412 410 ) Hydrogenated. In the embodiment of FIG. 15 where the feed to the naphtha hydrotreating zone 410 is a heavy naphtha stream 140 , the light naphtha 138 may be sent to the mixed feed steam cracking unit 230 . In a further embodiment, the feed to the naphtha hydrotreating zone 410 may also be a mixture of a light naphtha (e.g., both the heavy naphtha stream 140 combined with what may be the light naphtha stream 138 described in other embodiments) Lt; RTI ID = 0.0 > naphtha. ≪ / RTI > Thus, depending on demand and / or the desired product slate, the light naphtha 138 can be sent to the mixed feed steam cracking unit 230 to increase the production of olefinic petrochemicals, or alternatively, Is included in the feed to the catalytic reforming zone to increase the production of chemical and / or fuel blending components. In certain embodiments, all, a substantial or substantial portion of the light naphtha 138 is sent to the mixed feed steam cracking unit 230 (the remainder being optionally passed to the catalyst reforming zone 400 ); And substantial portions of the heavy naphtha 140 are sent to the catalyst reforming zone 400 (the remainder being optionally passed to the mixed feed steam cracking unit 230 ).

Hydrotreating occurs in the presence of an effective amount of hydrogen in the recycle obtained from the naphtha hydrotreating zone 410 (not shown), recycle reformer hydrogen 406 , and, if necessary, supplemental hydrogen 408 (shown in phantom). The off-gas is recovered from the naphtha hydrotreating zone 410 and passed to the olefin recovery train, the saturated gas plant as part of another gas stream 156 , and / or the direct fuel gas system. Recovered from the liquefied petroleum gas naphtha hydrotreating zone 410 and sent to a mixed feed steam cracking zone, an olefin recovery train and / or a saturated gas plant.

In certain embodiments, all or a portion of the required supplemental hydrogen 408 is derived from the steam cracking hydrogen stream 210 from the olefin recovery train 270 . In an additional embodiment, the hydrogen gas recovered from the catalytic reforming zone 414 provides sufficient hydrogen to maintain the hydrogen demand of the naphtha hydrotreating zone 410 when the reaction reaches equilibrium. In a further embodiment, there is a net hydrogen increase in the catalytic reforming zone, such that hydrogen may be added to the fuel gas used to operate, for example, other hydrogen users in the consolidation process, and / or various heating units in the integrated process. Suitable naphtha hydrotreating zones 410 include, but are not limited to, Honeywell UOP, US; Chevron Lummus Global LLC (CLG), US; Axens, IFP Group Technologies, FR; Shell Global Solutions, US, Haldor Topsoe A / S, DK; GTC Technologies US, LLC, US; Or a system based on commercially available technology from Exxon Mobil Corporation, US.

The naphtha hydrotreating zone 410 is operated and utilized under the conditions of the catalyst (s) effective for the removal of significant amounts of sulfur and other known contaminants. Thus, the naphtha hydrotreating zone 410 treats the feed under hydrotreating conditions to produce an effective hydrogenated naphtha stream 412 as feed to the catalyst reforming reaction zone 414 . The naphtha hydrotreating zone 410 may be used to provide effective temperature, pressure, hydrogen partial pressure, liquid hourly space velocity (LHSV), or other suitable conditions for at least sufficient removal of sulfur, nitrogen, olefins and other contaminants necessary to meet the required product specifications, , Under the conditions of catalyst selection / loading. For example, conventional hydrotreatment in a naphtha reforming system generally occurs under relatively weak conditions effective to remove sulfur and nitrogen to levels below 0.5 ppmw.

In certain embodiments, the naphtha hydrotreating zone 410 operating conditions include:

Reactor inlet temperature (° C) within the range of about 355-400, 355-375, 355-385, 370-400, or 360-390;

Reactor outlet temperature (in 占 폚) within the range of about 400-450, 400-430, 410-450, 420-450 or 410-430;

(SOR) reaction temperature (占 폚) as the weight average layer temperature (WABT) within the range of about 330-375, 330-360, 340-375, 355-375 or 330-350;

(EOR) reaction temperature (° C) as WABT within the range of about 390-435, 390-420, 390-410, 400-410 or 400-435;

Reaction inlet pressure (barg) in the range of about 48-60, 48-52, 48-55, 50-55 or 50-60;

Reaction outlet pressure (barg) in the range of about 40-51, 40-44, 40-48, 45-51, or 45-48;

Hydrogen partial pressure (barg) (outlet) in the range of about 24-34, 24-30, 27-34 27-30 or 27-32;

At most about 645, 620, 570, 500 or 530, in certain embodiments about 413-640, 413-570, 413-542, 465-620, 465-570, 465-542, 491-620, 491-570 491-542 hydrotreating gas feed rate (SLt / Lt);

At most about 99, 90, 85, 78 or 70, in certain embodiments at about 57-90, 57-78, 57-75, 64-85, 64-78, 64-75, 68-85, 68-78 or 68-75 quench gas feed (SLt / Lt); And;

At most about 125, 110 or 102, in certain embodiments at least about 78-120, 78-110, 78-102, 87-120, 87-110, 87-102, 92-120, 92-110, 92-102, Supplemental hydrogen feed rate (SLt / Lt) of 95-100.

Effective direct current naphtha reactor catalysts include those which possess hydrotreating functionality and generally contain one or more active metal components of a metal or metal compound (oxide or sulfide) selected from the Periodic Table of Elements IUPAC Groups 6-10. In certain embodiments, the active metal component is at least one of cobalt, nickel, tungsten, and molybdenum. The active metal component is typically deposited or otherwise embedded on a support, such as atypical alumina, amorphous silica alumina, zeolite, or a combination thereof. The catalyst used in the hydrotreating zone 410 may comprise one or more catalysts selected from cobalt / molybdenum, nickel / molybdenum, nickel / tungsten, and cobalt / nickel / molybdenum. Cobalt / molybdenum, nickel / molybdenum, nickel / tungsten and cobalt / nickel / molybdenum may also be used. The combination may consist of different particles containing a single active metal species, or particles containing a plurality of active species. In certain embodiments, cobalt / molybdenum hydrodesulfurization catalysts are suitable. An effective liquid space velocity value (h ^-1 ) based on fresh feed relative to the hydrotreating catalyst is about 0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0, 0.5- 10.0, 0.5-5.0, 0.5-2.0, or 0.8-1.2. Suitable hydrotreating catalysts used in the hydrotreating zone 410 have an expected life within the range of about 28-44, 34-44, 28-38, or 34-38 months.

The hydrotreated naphtha stream is treated in a catalytic reforming zone to produce a reformate. Suitable catalyst modification zones include, but are not limited to, Honeywell UOP, US; Chevron Lummus Global LLC (CLG), US; Axens, IFP Group Technologies, FR; Haldor Topsoe A / S, DK; Or a system based on commercially available technology from Exxon Mobil Corporation, US.

The hydrotreated naphtha stream 412 is passed to the catalyst reforming reaction zone 414 . In certain embodiments, all, a substantial or substantial portion of all of the hydrotreated naphtha stream 412 may be passed to the catalyst reforming reaction zone 414 and the remainder may be blended in the gasoline pool. The reactor effluent 416 containing the hot reformate and the hydrogen is cooled and passed to a separator 418 for recovery of the hydrogen stream 404 and the separator tower low stream 420 . The hydrogen stream 404 is split into a portion 406 that is compressed and recycled back to the reformer reactor, and an excess hydrogen stream 428 in certain embodiments. The separator tower low stream 420 is passed to the ballast column 422 to produce a light oil stream 424 and a reformate stream 426 . The light oil stream 424 may be recovered and sent to a mixed feed vapor cracking zone, an olefin recovery train, and / or a saturated gas plant.

The net hydrogen stream 428 can be recovered from the catalyst reforming reaction zone 414 (shown optionally as a dotted line), which contains excess hydrogen passed to another hydrogen user, including: the catalyst reforming zone 400 Such as the naphtha hydrotreating zone 410 and the benzene saturation unit 438 shown in Figure 16 in certain embodiments; And / or other than the integrated process, such as a mid distillate, pyrolysis gasoline, vacuum gas oil and / or water addition unit (s) for the transalkylation reaction. Suitable benzene saturation systems include, but are not limited to, Honeywell UOP, US; Axens, IFP Group Technologies, FR; Or systems based on commercially available technology from GTC Technologies US, LLC, US.

In general, the operating conditions for the reactor (s) in the catalyst reforming reaction zone 414 include the following:

Reactor inlet temperature (° C) within the range of about 450-580, 450-530, 450-500, 490-530, or 490-570;

Reactor outlet temperature (in 占 폚) in the range of about 415-540, 415-490, 415-500, 440-500, or 450-530;

(SOR) reaction temperature (占 폚) as the weight average layer temperature (WABT) within the range of about 445-520, 445-480, 445-500, 470-500 or 470-520;

About 490-550, 490-510, 490-540; (EOR) reaction temperature (° C) as WABT within the range of 500-550 or 520-540;

Reaction inlet pressure (barg) in the range of about 1.5-50 or 1.5-20;

Reaction exit pressure (barg) within the range of about 1.0-49 or 1-20;

Hydrogen to hydrocarbon molar ratio within the range of about 2: 1 to 5: 1.

The cyclic and CCR process designs include on-line catalyst regeneration or replacement, and thus the indicated lower pressure range is appropriate. For example, CCRs can operate within a range of about 5 bar, semi-regenerative systems operate at higher end of the range, and cyclic designs typically operate at higher pressures than CCRs and lower pressures than semi-regenerative systems.

An effective amount of a reforming catalyst is provided. Such catalysts include mono-functional or bi-functional reforming catalysts generally containing at least one active metal component of a metal or metal compound (oxide or sulfide) selected from the Periodic Table of Elements IUPAC Groups 8-10. The bi-functional catalyst has both metal and acidic sites. In certain embodiments, the active metal component may include one or more of platinum, rhenium, gold, palladium, germanium, nickel, silver, tin, iridium or halide. The active metal component is typically deposited or otherwise embedded on a support, such as atypical alumina, amorphous silica alumina, zeolite, or a combination thereof. In certain embodiments, alumina or silica or silica-alumina supported on platinum or platinum alloys is a reforming catalyst. The effective liquid space velocity values (h ^-1 ) based on the fresh feed relative to the hydrotreating catalyst are about 0.5-4, 0.5-2, .5-3, 1-3, 1-4, 1-2, 1.5 -4 or 1.5 - 3. Suitable reforming catalysts used in reforming reaction zone 414 have an expected lifetime in the range of about 6-18, 12-26, 18-54, or 24-72 months.

In certain embodiments, and with reference to Figure 16, in order to increase the production of gasoline fuel components, the reformate stream is passed through a separation and hydrogenation stage to reduce the total benzene content. For example, instead of passing all or part of the total reformate stream 426 to the aromatic extraction zone, it is passed to the reformate splitter 430 and passed through one or more relatively benzene-rich fractions 434 and one or more relatively benzene - into the under fractions 432 and 436 . Representatively, the relatively benzene-rich intermediate fraction 434 , known as the "benzene heart cut " contains about 10-20 vol% total reformate and contains about 20-30 vol% benzene. In contrast, the relatively benzene-less heavies reforming tower bottom fraction 436 contains about 40-80 V total reformate and generally has a benzene content in the range of about 0.3-1 vol% Low enough to pass into the gasoline pool 444 without further processing. The hard reformate column still fraction 432 , containing about 10-25 vol% total reformate, contains about 5-30 vol% benzene and is recovered or blended with other product pools.

The total reformate stream 426 The heart cut fraction 434 containing most of the benzene content can also be passed to the hydrogenation unit 438 , also referred to as a benzene saturation unit, or directly to the aromatic extraction unit. The hydrogenation reaction is carried out in the presence of a predetermined amount of hydrogen gas 440 for the conversion of benzene to cyclohexane, including the conversion reaction, and for the production of the benzene-free and, in certain embodiments, essentially benzene-free, gasoline blending component 442 ). ≪ / RTI >

All or a portion of the benzene-deficient blending component 442 may be mixed with the remaining gasoline pool component comprising the benzene-deficient heavy reformate bottom fraction 436 . For example, when blended with the heavy reformate fraction 432 , which may contain up to 1 vol% benzene, the final gasoline product containing less than about 1 vol% benzene can be recovered. In addition, all or a portion of the benzene-deficient blending component 442 may be sent to the mixed feed vapor decomposition zone 230 . Any portion of the light benzene deficient fraction 432 may be sent to the gasoline pool or mixed feed vapor decomposition zone 230 . All or a portion of the heavy benzene deficient fraction 436 may be sent to the aromatic extraction zone 620 or gasoline pool.

In a particular embodiment, to maximize the production of petrochemicals: all, substantial, substantial or major portion of the benzene-tallow heavy reforming tower bottom fraction 436 is passed to the aromatic extraction zone and the residues are passed through a gasoline pool Can be passed; All, substantial, substantial, or major portions of the hard reformate tower still fraction 432 may be passed to the mixed feed steam cracking zone 230 and the residues may be passed through a gasoline pool; And substantial portions, or substantial portions, of the benzene-poor blending component 442 can be sent to the mixed feed vapor decomposition zone 230 , and the residues can be passed through the gasoline pool.

Representative gasoline blending pools include C ₄ and heavier hydrocarbons having boiling points below about 205 ° C. In the catalytic reforming process, paraffins and naphthenes are reconstituted to produce relatively higher octane numbers of isomerized paraffins and aromatics. Catalytic reforming converts low octane n-paraffins to i-paraffins and naphthenes. Naphthenes are converted to higher octane aromatics. The aromatics may remain essentially unchanged or some may be hydrogenated to form naphthenes due to the reverse reaction that occurs in the presence of hydrogen.

In certain embodiments, the hydrogenation unit 438 operating conditions are in the range of about 200-600, 225-600, 250-600, 400-600, 200-550, 225-550, 250-550, or 400-550. Reaction temperature (占 폚); And a reaction pressure (barg) in the range of about 5-50, 15-50, 20-50, 5-45, 15-45, 20-45, 30-50, 30-45 or 30-50 . The hydrogenation unit 438 is known and may be, but is not limited to Honeywell UOP, US; Axens, IFP Group Technologies, FR; Or systems based on commercially available technology from GTC Technologies US, LLC, US.

An effective amount of a catalyst having an appropriate level of active material having hydrogenation functionality is present in the benzene saturation unit 438 , Within / RTI > Such catalysts generally contain at least one active metal component of a metal or metal oxide selected from the Periodic Table of Elements IUPAC Groups 6-10. In certain embodiments, the active metal component is at least one of nickel and platinum. The active metal component is typically deposited or otherwise embedded on a support, such as atypical alumina, amorphous silica alumina, zeolite, or a combination thereof. The effective liquid space velocity value (h ^-1 ) based on the fresh feed relative to the benzene saturation unit catalyst is about 0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0, 0.5 -10.0, 0.5-5.0, 0.5-2.0, or 0.8-1.2. The catalyst benzene saturation unit 438 used in the appropriate hydrotreating has an expected life within the range of about 28-44, 34-44, 28-38 or 34-38 months.

Referring to Fig. 17, another embodiment of the catalyst reforming system 414 is schematically illustrated. The reactor ( 414 ) Series. The feed material, hydrotreated naphtha 412 , is heat exchanged with the hot reformate stream 416 to increase the feed temperature. The heated feed is treated in a series of reaction zones containing the reformer reactor 414 shown in the exemplary embodiment as zone AD, although fewer zones may be used. The hot reformate stream 416 contains hot product hydrogen and reformate.

The reforming reaction is endothermic causing the reactants and product cooling, and is typically introduced into the direct-ignition furnace 446 prior to charging as a feed to the subsequent reforming reactor 414 It is necessary to heat the effluent. As a result of the very high reaction temperature, the catalyst particles are inactivated by coke formation on the catalyst which reduces the available surface area and active site for reactant contact.

The hot product hydrogen and reformate stream 416 passes through a heat exchanger and then a separator 418 for the recovery of hydrogen stream 404 and separator tower gypsum stream 420 . The recovered hydrogen stream 404 is compressed and recycled back to the reformer reactor and the excess hydrogen 428 It is divided. The separator tower low stream 420 is fed to the ballast column 422 to produce a light oil stream 424 and a reformate stream 426 .

As shown, the first intermediate distillate stream 118 is processed in a kerosene desulfurization zone 170 to remove unwanted sulfur compounds as is well known. The treated kerosene is recovered as kerosene fuel product 172 , such as jet fuel according to jet A or jet A-1 specifications, and optionally other fuel products. In the particular embodiment herein, all or a portion of the first intermediate distillate fraction 116 is not used for fuel production, and the mixed feed steam cracking zone 230 And is used as a distillate water addition common feed to produce additional feed.

For example, a suitable kerosene desulfurization zone 170 may include, but is not limited to, one or more of the following: (1) a hydrocarbon feedstock, such as but not limited to Merox ™ technology (Honeywell UOP, US), Sweetn'K technology (Axens, IFP Group Technologies, FR) or Thiolex ™ technology System. These types of processes are commercially well-established and suitable operating conditions for producing kerosene fuel products 172 and disulfide oils as by-products are well known. Impregnated carbon is used as a catalyst for promoting the conversion to a disulfide oil in a specific kerosene desulfurization technique. In certain embodiments, the normal treatment of acidic water from the kerosene desulfurization zone 170 and other unit operations is used to maximize process integration.

를 사용하는)를 사용하는, 잔류 H₂S 제거용 등유 공급물의 부식성 세척을 포함한다. 활성화된 탄소 촉매의 효과적인 양을 함유하는 반응기 용기는 머캅탄의 디설파이드로의 산화에 영향을 미치기 위해 부식성 용액과 함께 공기를 이용한다. 부식물은 반응기 탑저 섹션 내 처리 등유로부터 분리된다. 물 세척 후, 등유 생성물은 자유수 및 일부 가용성 물을 제거하기 위해 두 가지 병렬 염 필터 중의 하나를 통해 위로 통과한다. 등유 생성물은 등유 생성물이 가령, 제트 A 규격에 따르는 헤이즈, 색상 안정성 및 물 분리 규격을 충족시키는 것을 보장하기 위해, 고체, 수분, 에멀전 및 계면활성제의 제거용 두 가지 병렬 클레이 필터 중의 하나를 통해 아래로 통과한다.For example, an arrangement of a kerosene desulfurization zone may include an electrostatic core (e.g.,

Lt; RTI ID = 0.0 > H ₂ S < / RTI > removal. Reactor vessels containing an effective amount of activated carbon catalyst use air with caustic solutions to affect the oxidation of mercaptans to disulfides. The caustic is separated from the treated kerosene in the reactor bottom section. After the water wash, the kerosene product passes up through one of the two parallel salt filters to remove free water and some soluble water. The kerosene product is passed through one of two parallel clay filters for removal of solids, moisture, emulsions and surfactants, to ensure that the kerosene product meets the haze, color stability and water separation specifications, ≪ / RTI >

The second intermediate distillate stream 120 and the third intermediate distillate stream 128 are fed to the diesel hydrotreating zone 180 in the presence of an effective amount of hydrogen and supplemental hydrogen 186 obtained from recycling in the diesel hydrotreating zone 180. [ Lt; / RTI > In certain embodiments, all or a portion of the supplemental hydrogen 186 is derived from the steam cracking product hydrogen 210 stream from the olefin recovery train 270 . Suitable hydrotreating zones 180 include, but are not limited to, Honeywell UOP, US; Chevron Lummus Global LLC (CLG), US; Axens, IFP Group Technologies, FR; Haldor Topsoe A / S, DK; Or systems based on commercially available technology from the joint technology from KBR, Inc, US, and Shell Global Solutions, US.

The diesel hydrotreating zone 180 is effective to remove significant amounts of sulfur and other known contaminants , for example, to meet the required sulfur specifications for the diesel fuel product 182 , e.g., diesel fuel compliant with Euro V diesel standards. It works under conditions. In addition, the hydrotreated naphtha fraction 184 (sometimes referred to as wild naphtha) is recovered from the diesel hydrotreating zone 180 , which is fed into the mixed feed steam cracking zone 230 as one of a plurality of steam cracked feed sources . The off-gas is withdrawn from the diesel hydrotreating zone 180 and passed to the olefin recovery train, to the saturated gas plant, and / or to the direct fuel gas system as part of another gas stream 156 . The liquefied petroleum gas can be recovered from the diesel hydrotreating zone 180 and sent to a mixed feed vapor cracking zone, an olefin recovery train, and / or a saturated gas plant. In certain embodiments, the hydrogenated naphtha fraction 184 is sent through the crude complex 100 , either alone or in combination with other wild naphtha fractions from within the integrated process. In embodiments in which the hydrogenated naphtha fraction 184 is sent through the crude complex 100 , all or a portion of the liquefied petroleum gas produced in the diesel hydrotreating zone 180 is passed through the hydrogenated naphtha fraction 184 . In certain embodiments, all, a substantial or substantial portion of the wild naphtha 184 is sent to the mixed feed vapor decomposition zone 230 (either directly or through the crude complex 100 ).

The diesel hydrotreating zone 180 can optionally process other fractions from within the complex (not shown). In embodiments where a kerosene desulfurization zone 170 is used, all or a portion of the disulfide oil may be an additional feed to the diesel hydrotreating zone 180 . In addition, all or a portion of the first intermediate distillate fraction 116 may be an additional feed to the diesel hydrotreating zone 180 . In addition, all or a portion of the distillate from the vacuum gas oil water addition zone, and / or all or a portion of the distillate from the optional vacuum residue treatment zone may be sent to the diesel hydrotreating zone 180 . Any portion of the distillate that is not sent to the diesel hydrotreating zone 180 may be passed to the crude complex 100 or sent to the mixed feed vapor decomposition zone 230 . In addition, all or a portion of the light pyrolysis oil may be sent to the diesel hydrotreating zone 180 .

In certain embodiments, the diesel hydrotreating zone 180 also processes at least a portion of the light cycle oil 708 from the high olefinic fluid catalytic cracking zone 700 . Any portion of the light cycle oil 708 that is not sent to the diesel hydrotreating zone 180 may optionally be passed through the fuel oil pool and / or processed in the integrated gas oil water addition zone. For example, 0-30, 0-25, 0-20, 5-30, 5-25, 5-20, 10-20, 60-70, or 60-50 percent of the total light cycle oil 708 from the high olefinic fluid catalytic cracking zone 700 , 30, 10-25, or 10-20 wt% or less may be sent to the diesel hydrotreating zone 180 .

The diesel hydrotreating zone 180 may contain one or more fixed-bed, boiling-layer, slurry-layer, moving bed, continuous stirred tank (CSTR) or tubular reactor in series and / or parallel arrangement. In a specific embodiment, the diesel hydrotreating zone 180 comprises a layered catalyst system comprising a layered bed reactor with three catalyst beds and interlaminar quenching gas and having a layer of hydrated waxed catalyst disposed between the hydrotreating catalyst beds use. Additional equipment including exchangers, furnaces, feed pumps, quench pumps, and compressors are well known and are considered as part of the diesel hydrotreating zone 180 to feed the reactor (s) and maintain proper operating conditions do. In addition, the separation of the reaction product and the equipment, including providing the hydrogen recycle diesel hydrotreating zone 180, a pump, compressor, high-temperature separation vessel, low temperature separation vessel such as are well known and diesel hydrotreating zone (180 ). ≪ / RTI >

In certain embodiments, the diesel hydrotreating zone 180 operating conditions include:

Reactor inlet temperatures in the range of about 296-453, 296-414, 296-395, 336-453, 336-414, 336-395, 355-453, 355-414, 355-395 or 370-380 );

The reactor outlet temperature in the range of about 319-487, 319-445, 319-424, 361-487, 361-445, 361-424, 382-487, 382-445, 382-424 or 400-406 );

Within the range of about 271-416, 271-379, 271-361, 307-416, 307-379, 307-361, 325-416, 325-379, 325-361 or 340-346, ) (SOR) reaction temperature (占 폚);

Termination of execution as a WABT within the range of about 311-476, 311-434, 311-414, 352-476, 352-434, 352-414, 373-476, 373-434, 373-414 or 390-396 (EOR) reaction temperature (占 폚);

Reaction inlet pressure (barg) in the range of about 48-72, 48-66, 48-63, 54-72, 54-66, 54-63, 57-72, 57-66 or 57-63;

Reaction outlet pressure (barg) within the range of about 44-66, 44-60, 44-58, 49-66, 49-60, 49-58, 52-66, 52-60 or 52-58;

The hydrogen partial pressure (barg) (outlet) in the range of about 32-48, 32-44, 32-42, 36-48, 36-44, 36-42, 38-48, 38-44, ;

At most about 400, 385, 353 or 337, in certain embodiments at about 256-385, 256-353, 256-337, 289-385, 289-353, 289-337, 305-385, 305-353, 337 hydrotreating gas feed rate (standard liters per liter of hydrocarbon feed, SLt / Lt);

At most about 100, 85, 78 or 75, in certain embodiments at about 57-85, 57-78, 57-75, 64-85, 64-78, 64-75, 68-85, 68-78, or 68 A hydrogen quench gas supply rate (SLt / Lt) of -75; And

At least about 110, 108, 100, or 95 in certain embodiments, about 70-108, 70-100, 70-95, 80-108, 80-100, 80-95, 85-108, 85-100, 95 supplemental hydrogen feed rate (SLt / Lt).

An effective amount of a hydrotreating catalyst having hydrotreating functionality and generally containing at least one active metal component of a metal or metal compound (oxide or sulphide) selected from the elemental periodic table IUPAC groups 6-10, ( 180 ) Lt; / RTI > In certain embodiments, the active metal component is at least one of Co, Ni, W, and Mo. The active metal component is typically deposited or otherwise embedded on a support, such as atypical alumina, amorphous silica alumina, zeolite, or a combination thereof. The catalyst used in the diesel hydrotreating zone 180 may comprise one or more catalysts selected from Co / Mo, Ni / Mo, Ni / W, and Co / Ni / Mo. A combination of at least one of Co / Mo, Ni / Mo, Ni / W and Co / Ni / Mo may also be used. The combination may consist of different particles containing a single active metal species, or particles containing a plurality of active species. In certain embodiments, a Co / Mo hydrodesulfurization catalyst is suitable. An effective liquid space velocity value (h ^-1 ) based on fresh feed relative to the hydrotreating catalyst is about 0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0, 0.5- 10.0, 0.5-5.0, 0.5-2.0, or 0.8-1.2. The catalytic diesel hydrotreating zone 180 used in the appropriate hydrotreating has an expected life within the range of about 28-44, 34-44, 28-38 or 34-38 months.

In certain embodiments, an effective amount of a hydrochemical waxing catalyst is also added. In such embodiments, an effective hydrochemical waxing catalyst typically includes those used to isomerize and decompose paraffinic hydrocarbon feedstocks to improve low temperature flow properties, such as Ni, W, or molecular sieves or combinations thereof Catalyst. Catalysts comprising aluminosilicate molecular sieves, such as catalysts comprising Ni / W, zeolites with medium or large pore sizes, or combinations thereof, with zeolites having a medium or large pore size are suitable. Effective commercial zeolites include, for example, ZSM-5, ZSM-11, ZSM-12, ZSM-22, ZSM-23, ZSM 35 and zeolites of type beta and Y. The hydrotreating catalyst is typically supported on an oxide support such as Al ₂ O ₃ , SiO ₂ , ZrO ₂ , zeolite, zeolite-alumina, alumina-silica, alumina-silica-zeolite, activated carbon, and mixtures thereof. The effective liquid space velocity value (h ^-1 ) based on fresh feed relative to the hydrocracking catalyst is about 0.1-12.0, 0.1-8.0, 0.1-4.0, 0.5-12.0, 0.5-8.0, 0.5-4.0, 1.0-12.0, 1.0-8.0, 1.0-4.0, or 1.6-2.4. The appropriate hydrated waxing used in the catalytic diesel hydrotreating zone 180 has an expected life within the range of about 28-44, 34-44, 28-38, or 34-38 months.

In high capacity operation, two or more parallel trains of the reactor are used. In such an embodiment, the flow in the diesel hydrotreating zone 180 is split after the feed pump to the parallel train, where each train contains a feed / discharge heat exchanger, a feed heater, a reactor and a hot separator. Each reactor contains three catalyst beds with interlayer quench gas. A layered catalyst system having a layer of a hydrated waxed catalyst disposed between the layers of the hydrotreating catalyst is used. The trains are recombined after the hot separator. The column stills from the hot separator are combined and passed through a low temperature separator. The bottoms from the top and bottom separators from the hot separator are passed to the product stripper to produce stabilized ultra low sulfur diesel and wild naphtha. The column stills from the cryogenic separator are treated with absorption and amine scrubbing. The recycled hydrogen is recovered and passed (along with supplemental hydrogen) to the reaction zone as a process gas and a quench gas.

The VGO 162 (or separate LVGO and HVGO fractions) from the vacuum distillation zone 160 can be fed to the gas oil water addition chamber 162 in the presence of an effective amount of hydrogen and supplemental hydrogen 302 obtained from recycling in the gas oil water addition room, Zone 300 (FIG. 12) or 320 (FIG. 13). In certain embodiments, all or a portion of the supplemental hydrogen 302 is derived from the steam cracking hydrogen stream 210 from the olefin recovery train 270 . In certain embodiments (not shown in Figures 12 and 13), the heavy intermediate distillate fraction, such as the third middle distillate fraction 126 , e.g., all of the atmospheric gas oil from the atmospheric distillation zone 110 Or a portion thereof, such as a full range AGO, or fraction thereof, for example a fourth intermediate distillate stream 130 , such as heavy atmospheric gas oil, may also be treated in a gas oil water addition room. In addition, a portion of the third middle distillate fraction 126 may be sent to the gas oil water addition space and the remainder may be passed to the high olefinic fluid catalytic decomposition zone 700 without passing through the vacuum gas oil water addition room .

According to the process herein, the strength of the gas oil water addition operation can be used to alleviate the relative yield of olefins and aromatic chemicals from the overall composite and to improve the economic limit of the cracked heavy feed. This use of gas oil water addition as a chemical yield control mechanism is not common in the industry, where the fuel product is typically a product purpose.

12, in the hydrotreating mode of operation, the vacuum gas oil hydrotreating zone 300 operates under suitable hydrotreating conditions and is typically operated in the off-gas and light oil (not shown), the wild naphtha stream 306 , Thereby producing hydrogenated gas oil 304 . The off-off gas is recovered from the gas oil hydrotreating zone 300 and passed to the olefin recovery train, the saturated gas plant as part of another gas stream 156 , and / or the direct fuel gas system. The liquefied petroleum gas may be recovered from the gas oil hydrotreating zone 300 and sent to the mixed feed steam cracking zone, the olefin recovery train and / or the saturated gas plant. The naphtha fraction 306 is sent to the mixed feed vapor decomposition zone 230 . In certain embodiments, the hydrotreated naphtha fraction 306 is sent through the crude complex 100 , alone or in combination with other wild naphtha fractions from within the integrated process. In embodiments in which the hydrogenated naphtha fraction 306 is sent through the crude complex 100 , all or a portion of the liquefied petroleum gas produced in the gas oil hydrotreating zone 300 is passed through the hydrotreated naphtha fraction 306 . The hydrotreated gas oil ( 304 ) is sent to the high olefinic fluid catalytic cracking zone ( 700 ). In certain embodiments, as shown in Figure 10 described below, in addition to or in addition to the hydrotreated naphtha fraction 306 , all of the hydrogenated distillate and naphtha from the gas oil hydrotreating zone 300 or Some And passed to the diesel hydrotreating zone 180 .

The gas oil hydrotreating zone 300 generally comprises a major portion of the hydrotreated gas oil 304 that is passed through the high olefinic fluid catalytic cracking zone 700 and the removal of significant amounts of sulfur and other known contaminants, The distillate and hydrotreated naphtha 308 Lt; RTI ID = 0.0 > VGO < / RTI > The hydrotreated gas oil fraction ( 304 ) generally contains a portion of the exhaust gas from the vacuum gas oil processor ( 300 ) that is above the AGO, H-AGO or VGO range.

For example, a suitable gas oil hydrotreating zone 300 may include, but is not limited to, Honeywell UOP, US; Chevron Lummus Global LLC (CLG), US; Axens, IFP Group Technologies, FR; Or systems based on commercially available technology from Shell Global Solutions, US.

The gas oil hydrotreating zone 300 may contain one or more fixed-bed, boiling-layer, slurry-bed, moving bed, continuous stirred tank (CSTR) or tubular reactor in series and / or parallel arrangement. Additional equipment, including exchangers, furnaces, feed pumps, quench pumps, and compressors, is well known to supply to the reactor (s) and to maintain the proper operating conditions and is part of the gas oil hydrotreating zone 300 . Also included are equipment known to include pumps, compressors, high temperature separation vessels, low temperature separation vessels, etc., which separate the reaction products and provide hydrogen recycle in the gas oil hydrotreating zone 300 , Lt ; RTI ID = 0.0 > 300 < / RTI >

An effective amount of catalyst is provided in the gas oil hydrotreating zone 300 , including those having hydrotreating functionality for hydrodesulfurization and hydrogen denitrification. Such catalysts generally contain at least one active metal component of a metal or metal compound (oxide or sulfide) selected from the Periodic Table of Elements IUPAC Groups 6-10. In certain embodiments, the active metal component is at least one of Co, Ni, W, and Mo. The active metal component is typically deposited or otherwise embedded on a support, such as atypical alumina, amorphous silica alumina, zeolite, or a combination thereof. In certain embodiments, the catalyst used in the gas oil hydrotreating zone 300 comprises at least one layer selected from Co / Mo, Ni / Mo, Ni / W, and Co / Ni / Mo. A combination of at least one of Co / Mo, Ni / Mo, Ni / W and Co / Ni / Mo may also be used. The combination may consist of different particles containing a single active metal species, or particles containing a plurality of active species. In certain embodiments, the combination of a Co / Mo catalyst and a Ni / Mo catalyst is effective for hydrodesulfurization and hydrogen denitrification. With different catalysts in different reactors of each series, one or more series of reactors may be provided. For example, the first reactor comprises a Co / Mo catalyst and the second reactor comprises a Ni / Mo catalyst. Suitable catalysts used in the gas oil hydrotreating zone 300 have an expected lifetime in the range of about 28-44, 28-38, 34-44, or 34-38 months.

In certain embodiments, the gas oil hydrotreating zone 300 operating conditions include:

Reactor inlet temperatures in the range of about 324-496, 324-453, 324-431, 367-496, 367-453, 367-431, 389-496, 389-453, 389-431 or 406-414 );

The reactor outlet temperature within the range of about 338-516, 338-471, 338-449, 382-516, 382-471, 382-449, 404-516, 404-471, 404-449 or 422-430 );

Within the range of about 302-462, 302-422, 302-402, 342-462, 342-422, 342-402, 362-462, 362-422, 362-402 or 378-384, (SOR) reaction temperature (C) as WABT;

Termination of execution as a WABT within the range of about 333-509, 333-465, 333-443, 377-509, 377-465, 377-443, 399-509, 399-465, 399-443 or 416-424 (EOR) reaction temperature (占 폚);

The reaction inlet pressure (barg) in the range of about 91-137, 91-125, 91-119, 102-137, 102-125, 102-119, 108-137, 108-125, 108-119 or 110-116 );

Reaction exit pressure (barg) in the range of about 85-127, 85-117, 85-111, 96-127, 96-117, 96-111, 100-127, 100-117 or 100-111;

The hydrogen partial pressure (barg) in the range of about 63-95, 63-87, 63-83, 71-95, 71-87, 71-83, 75-95, 75-87, 75-83 or 77-81 ) (exit);

At most about 525, 510, 465 or 445, in certain embodiments at about 335-510, 335-465, 335-445, 380-510, 380-465, 380-445, 400-510, 400-465, or 400- 445 < / RTI > hydrogenation gas feed rate (SLt / Lt);

At most about 450, 430, 392 or 375, in certain embodiments at about 285-430, 285-392, 285-375, 320-430, 320-392, 320-375, 338-430, 338-392, or 338- 375 hydrogen quench gas feed rate (SLt / Lt);

At most about 220, 200, 180 or 172, in certain embodiments about 130-200, 130-180, 130-172, 148-200, 148-180, 148-172, 155-200, 155-180, or 155- Replenishment hydrogen feed rate (SLt / Lt) of 172; And

0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0, 0.4-10.0, 0.4-5.0, 0.4-3.0, or 0.5-0.0, based on the fresh feed relative to the hydrotreating catalyst. The liquid space velocity value in the range of 2.5 (h ^-1 ).

An effective amount of catalyst is provided in the gas oil hydrotreating zone 300 , including those having hydrotreating functionality for hydrodesulfurization and hydrogen denitrification. Such catalysts generally contain at least one active metal component of a metal or metal compound (oxide or sulfide) selected from the Periodic Table of Elements IUPAC Groups 6-10. In certain embodiments, the active metal component is at least one of Co, Ni, W, and Mo. The active metal component is typically deposited or otherwise embedded on a support, such as atypical alumina, amorphous silica alumina, zeolite, or a combination thereof. In certain embodiments, the catalyst used in the gas oil hydrotreating zone 300 comprises at least one layer selected from Co / Mo, Ni / Mo, Ni / W, and Co / Ni / Mo. A layer of a combination of at least one of Co / Mo, Ni / Mo, Ni / W and Co / Ni / Mo may also be used. The combination may consist of different particles containing a single active metal species, or particles containing a plurality of active species. In certain embodiments, the combination of a Co / Mo catalyst and a Ni / Mo catalyst is effective for hydrodesulfurization and hydrogen denitrification. With different catalysts in different reactors of each series, one or more series of reactors may be provided. For example, the first reactor comprises a Co / Mo catalyst and the second reactor comprises a Ni / Mo catalyst. The effective liquid space velocity value (h ^-1 ) based on the fresh feed relative to the hydrotreating catalyst is about 0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0, 0.4- 10.0, 0.4-5.0, 0.4-3.0, or 0.5-2.5. Suitable catalysts used in the gas oil hydrotreating zone 300 have an expected lifetime in the range of about 28-44, 28-38, 34-44, or 34-38 months.

Under these conditions and catalyst selection, the exemplary product from the gas oil hydrotreating zone 300 can be boiled at a boiling point of atmospheric pressure endpoint boiling point, e.g. below 370 ° C, including LPG, kerosene, naphtha, and atmospheric gas oil range components -30, 5-30, 2-27 or 5-27 wt% (relative to the feed to the gas oil hydrotreating zone 300 ). The remaining tower bottom fraction is a hydrogenated gas oil fraction, all or a portion of which can be effectively incorporated as a feed to the gas oil vapor cracking zone 250 as described herein.

In an additional embodiment, the gas oil hydrotreating zone 300 may operate under effective conditions to maximize targeted conversion to petrochemicals in the feed conditioning and steam cracker complexes. Thus, in certain embodiments, strength conditions are selected that achieve a different purpose than that used for conventional refinery operations. That is, while typical VGO hydrotreating operates with less emphasis on preserving liquid product yield, VGO hydrotreating in this embodiment works to produce higher yields of lighter products intentionally recovered to maximize chemical yield . In an embodiment for maximizing conversion to petrochemicals, the gas oil hydrotreating zone 300 operating conditions include:

The reactor inlet temperature (° C) within the range of about 461-496, 461-473, 485-496, or 473-485;

The reactor outlet temperature (in 占 폚) within the range of about 480-516, 480-489, 489-495, or 495-516;

(SOR) reaction temperature (占 폚) as the weight average layer temperature (WABT) within the range of about 430-462, 430-440, 440-450 or 450-462;

(EOR) reaction temperature (° C) as WABT within the range of about 473-509, 484-495, 473-484, or 495-509;

Reaction inlet pressure (barg) within the range of about 110-137, 113-137, 110-120, 120-129, or 129-137;

Reaction exit pressure (barg) within the range of about 104-118, 104-108, 112-118, or 108-112;

Hydrogen partial pressure (barg) (outlet) in the range of about 76-95, 76-83, 83-89, or 89-95;

A hydrogenation gas feed rate (SLt / Lt) of at most about 525, 485, 490 or 520, in certain embodiments at about 474-520, 474-488, 488-500, or 500-520;

A hydrogen quench gas feed rate (SLt / Lt) of at most about 450, 441, 416 or 429, in certain embodiments at about 400-441, 400-415, 415-430, or 430-441;

A supplemental hydrogen feed rate (SLt / Lt) of up to about 220, 200, 207 or 214, in certain embodiments from about 186-200, 190-200, 186-190, 190-195, or 195-200; And

Liquid space velocity values (h ^-1 ) in the range of about 0.5-0.7, 0.5-0.55, 0.55-0.6, 0.6-0.65, 0.65-0.7, based on fresh feed relative to the hydrotreating catalyst.

Exemplary products from gas oil hydrotreating zone 300 operating under effective conditions to maximize targeted conversion to petrochemicals in feed conditioning and cracking reactor complex under the above conditions and catalyst selection are LPG, kerosene, Naphtha, and 20-30, 22-28, 23-27, or 24-26 wt% boiling point boiling point at 370 ° C or lower, including atmospheric pressure gas oil range components (gas oil hydrotreating zone 300 ) relative to the < / RTI > The remaining tower bottom fraction is a hydrogenated gas oil fraction, all or a portion of which can be effectively incorporated as a feed to the gas oil vapor cracking zone 250 as described herein.

In a particular embodiment, the gas oil hydrotreating zone 300 contains one or more trains of reactors, the first reactor having two catalyst beds with two quench streams containing interlayer quench streams, the second reactor (Lag reactor) has one catalytic bed quench stream. In high capacity operation, two or more parallel trains of the reactor are used. In such an embodiment, the flow in the gas oil hydrotreating zone 300 is split after the feed pump to the parallel train, where each train contains a feed / effluent heat exchanger, a feed heater, a reactor and a hot separator . The train is reassembled after the hot separator. The column stills from the hot separator are combined and passed through a low temperature separator. The bottom charge from the hot separator is passed to a hot flash drum. The bottoms from the cryogenic separator and the column stills from the hot flash drum are passed to a low pressure flash drum to remove the off-gas. The hot flash liquid bottoms and low pressure flash bottoms are passed through a stripper to recover the hydrogenated gas oil and wild naphtha. The column stills from the cryogenic separator are treated with absorption and amine scrubbing. The recycled hydrogen is recovered and passed into the reaction zone as a process gas and quench gas (with supplemental hydrogen).

Figure 13 shows the hydrocracking mode of operation for vacuum gas oil treatment. The hydrocracking process is used commercially in many petroleum refineries. The hydrocracking process boils at a temperature above the conventional hydrocracking unit atmospheric gas oil range (e.g., within the range of about 370-520 ° C) and above the vacuum gas oil range in the residue hydrocracking unit (eg, about 520 Lt; RTI ID = 0.0 > C) < / RTI > Generally, the hydrocracking process divides feed molecules into smaller, lighter molecules with higher average volatility and economic value. Additionally, the hydrocracking process typically enhances the quality of the hydrocarbon feedstock by increasing the hydrogen-to-carbon ratio and by removing organic sulfur and organic nitrogen compounds. Significant economic benefits derived from hydrocracking processes have led to process improvements and significant development of more active catalysts.

The three major hydrocracking process schemes include single-step once through hydrocracking, serial-flow hydrocracking with or without recycling, and two-step recycled hydrocracking. Single-step unidirectional hydrocracking is the simplest of the hydrocracker configurations and is more severe than the hydrotreating process, but typically occurs under less severe operating conditions than conventional higher pressure hydrocracking processes. Single-step one-way hydrocracking requires one or more reactors for both the treatment step and the cracking reaction, and the catalyst must be capable of both hydrotreating and hydrocracking. This configuration is cost effective, but typically results in relatively low product yields (e.g., a maximum conversion rate of about 50 wt%). Single step hydrocracking is often designed to maximize the mid-distillate yield over single or dual catalyst systems. The dual catalyst system can be used in a laminated-layer configuration or in two different reactors. The effluent is passed through a fractionator column that separates the H ₂ S, NH ₃ , light gas (C ₁ -C ₄ ), naphtha and diesel products and is passed in a temperature range below the atmospheric gas oil fraction, Within the temperature range). Boiling hydrocarbons above the atmospheric gas oil range (eg, 370 ° C) are typically non-conversion oils. Any portion of these non-recycled oils that have not been recycled is discharged from the tower bottom fraction within the gas oil hydrocracking zone 320 as a hydrogen-enriched bleed stream and discharged into the high olefinic fluid catalytic cracking zone 700 ≪ / RTI > In certain embodiments, the non-converting oil may be processed in a lubricating oil production unit (not shown).

The gas oil hydrocracking zone 320 operates under mild, moderate or severe hydrocracking conditions and is typically operated in the off-gas and light oil (not shown), the wild naphtha stream 326 , the diesel fuel fraction 322 , To produce a conversion oil fraction 324 . The off-off gas is recovered from the gas oil hydrotreating zone 300 and passed to the olefin recovery train, to the saturated gas plant as part of another gas stream 156 , and / or to the direct fuel gas system. The liquefied petroleum gas can be recovered from the gas oil hydrocracking zone 320 and sent to an olefin recovery train and / or a saturated gas plant. The naphtha fraction 326 is sent to the mixed feed vapor decomposition zone 230 . In certain embodiments, the naphtha fraction 326 is sent through the crude complex 100 , either alone or in combination with other wild naphtha fractions from within the integrated process. In an embodiment, the naphtha fraction 326 is sent through the crude complex 100 and all or a portion of the liquefied petroleum gas produced in the gas oil hydrocracking zone 320 may be passed to the naphtha fraction 326 . The non-converting oil fraction 324 is sent to the high olefinic fluid catalytic cracking zone 700 . The diesel fuel fraction 322 can be recovered, for example, as a fuel conforming to the Euro V diesel standard and combined with the diesel fuel fraction 182 from the diesel hydrotreating zone 180 . The vacuum gas oil hydrocracker 320 may operate under mild, moderate, or severe conditions depending on factors including the feedstock and the desired degree of conversion

The gas oil hydrocracking zone 320 may operate under mild, moderate, or severe conditions depending on factors including the feedstock and the desired degree of conversion. Such conditions include the removal of significant amounts of sulfur and other known contaminants and the removal of the major portion of the hydrocracked product that is passed into the high olefinic fluid catalytic cracking zone 700 and a small portion of the off-gas, Lt; / RTI > of the feed (s).

For example, suitable vacuum gas oil hydrocracker zones 320 include, but are not limited to, Honeywell UOP, US; Chevron Lummus Global LLC (CLG), US; Axens, IFP Group Technologies, FR; Or systems based on commercially available technology from Shell Global Solutions, US.

The gas oil hydrocracking zone 320 may contain one or more fixed-bed, boiling-layer, slurry-bed, moving bed, continuous stirred tank (CSTR) or tubular reactor in series and / or parallel arrangement. Additional equipment, including exchangers, furnaces, feed pumps, quench pumps, and compressors, is well known in the art for supplying to the reactor (s) and maintaining proper operating conditions and is used as part of the gas oil hydrocracking zone 320 . Equipment gas oil hydrocracking zones 320 are also well known, including pumps, compressors, high temperature separation vessels, low temperature separation vessels, and the like, which separate the reaction products and provide internal hydrogen recycle, 0.0 > 320 < / RTI >

Serial-flow hydrocracking with or without recycling is one of the most commonly used configurations. Serial-flow hydrocracking uses one reactor (containing both a treatment and a cracking catalyst) or two or more reactors for both the treatment and decomposition reaction steps. In a serial-flow configuration, the entire hydrocracked product stream from the first reaction zone, including the light gases (typically C ₁ -C ₄ , H ₂ S, NH ₃ ), and all remaining hydrocarbons are sent to the second reaction zone Loses. The unconverted column bottoms from the fractionator column are recycled back into the first reactor for further cracking. This configuration has the potential to maximize the yield of heavy crude oil fractions, such as naphtha, kerosene and / or diesel range hydrocarbons, depending on the recycle cut point used in the distillation section to convert the vacuum gas oil to a light product.

Two-step recycle hydrocracking Two reactors are used and the unconverted column bottoms from the fractionation column are passed to the second reactor for further cracking. Because the first reactor achieves both hydrotreating and hydrocracking, the feed to the second reactor is virtually free of ammonia and hydrogen sulfide. This permits the use of high performance zeolite catalysts sensitive to contamination by sulfur or nitrogen compounds.

Effective hydrocracking catalysts generally contain from about 5 to about 40 wt%, based on catalyst weight, of at least one active metal component of a metal or metal compound (oxide or sulfide) selected from the Elements Periodic Table IUPAC Groups 6-10. In certain embodiments, the active metal component is at least one of Mo, W, Co, or Ni. The active metal component is typically deposited or otherwise embedded on a support, such as atypical alumina, amorphous silica alumina, zeolite, or a combination thereof. In certain embodiments, either alone or in combination with the metal, the Pt group metal, such as Pt and / or Pd, is present as a hydrogenation component, generally in an amount of from about 0.1 to about 2 wt% based on catalyst weight. Suitable hydrocracking catalysts have an expected lifetime in the range of about 18-30, 22-30, 18-26, or 22-26 months.

Exemplary products from the gas oil hydrocracking zone 320 may include atmospheric pressure end boiling points, such as LPG, kerosene, naphtha, and atmospheric gas oil range components, boiling at 370 ° C or below, 27-99, 27-90 , 27-82, 27-80, 27-75, 27-52, 27-48, 30-99, 30-90, 30-82, 30-80, 30-75, 30-52, 30-48, 48 -99, 48-90, 48-82, 48-80, 48-75, 48-52, 78-99, 78-90, 78-85, 80-90 or 80-99 wt% Relative to the feed to the decomposition zone 320 ). The remaining bottom fraction is a non-converting oil fraction, all or a portion of which may be effectively incorporated as a feed into the high olefinic fluid catalytic cracking zone 700 as described herein.

18 schematically illustrates an embodiment of a one-way single reactor hydrocracking zone 330 that includes a reaction zone 332 and a fractionation zone 342 , which may serve as a weak conversion or partial conversion hydrocracker.

The reaction zone 332 generally includes one or more inlets in fluid communication with a source of the initial feed material 334 and a source of hydrogen gas 338 . One or more outlets of the reaction zone 332 that emit the effluent stream 340 may include one or more inlet fractionation zones 342 (one or more high pressure and / or low pressure separation steps therebetween for recovery of recycled hydrogen) , Not shown).

Fractionation zone 342 is a gas 344, typically, _{H 2, H 2 S, NH} 3, and light hydrocarbons, at least one outlet for the discharge of (C ₁ -C _4); At least one outlet for recovering boiling intermediate distillate naphtha and diesel products within the product 346 , e.g., within the temperature range of the atmospheric gas oil range fraction below (e.g., within the temperature range of 36-370 ° C); And one or more outlets for discharging column bottoms 348 comprising hydrocarbons boiling above the atmospheric gas oil range (e.g., 370 ° C). In certain embodiments, the temperature cut point (and thus the end point for product 346 ) for tower bottom 348 is greater than the upper temperature limit of any gasoline, kerosene, and / or diesel product boiling point range for downstream operation . ≪ / RTI >

In operation of the unidirectional single reactor hydrocracking zone 330 , feed material stream 334 and hydrogen stream 338 are charged into reaction zone 332 . Hydrogen stream 338 is an amount effective to support the degree of hydrogen hydrocracking, feed type, and other factors required, and may be coupled to reaction zone 332 and / or, if desired, fractionator gas stream 344 and / Or any combination comprising recycled hydrogen 336 from an optional gas separation subsystem (not shown) derived from supplemental hydrogen 302 . In certain embodiments, the reaction zone may contain multiple catalyst layers and may contain one or more quench hydrogen streams between the layers (not shown).

The reaction effluent stream 340 contains a conversion, partially converted, and non-converting hydrocarbons. The reaction effluent stream 340 generally includes a fractionation zone 342 for collecting gas and liquid products and byproducts 344 and 346 and for separating the tower bottom fraction 348 After one or more high pressure and low pressure separation steps). This stream 348 is directed to a high olefinic fluid catalytic cracking zone 700 as described herein.

The gas stream 344 , which typically includes H ₂ , H ₂ S, NH ₃ , and light hydrocarbons (C ₁ -C ₄ ) can be released, recovered, and further processed. The effluent off-gas is passed to an olefin recovery train, a saturated gas plant as part of another gas stream 156 , and / or a direct fuel gas system. The liquefied petroleum gas may be recovered and sent to a mixed feed steam cracking zone, an olefin recovery train, and / or a saturated gas plant. The one or more cracked product streams 346 may be discharged through an appropriate outlet of the fractionator and processed further and / or downstream refinery for producing gasoline, kerosene and / or diesel fuel, or other petrochemical products Blended in operation.

In certain embodiments (not shown), the fractionation zone 342 may be configured to provide a suitable cut point, for example, a range of temperatures corresponding to the upper temperature range of a given gasoline, kerosene, and / or diesel product for downstream operation As shown in FIG. In certain embodiments, a suitable cut point is selected from the group consisting of 350-450 DEG C, 360-450 DEG C, 370-450 DEG C, 350-400 DEG C, 360-400 DEG C, 370-400 DEG C, 350-380 DEG C, Lt; / RTI > The stream above the cut point is directed to a high olefinic fluid catalytic cracking zone 700 as described herein.

For example, a suitable one-way single reactor hydrocracking zone 330 may include, but is not limited to, Honeywell UOP, US; Chevron Lummus Global LLC (CLG), US; Axens, IFP Group Technologies, FR; Or systems based on commercially available technology from Shell Global Solutions, US.

The reactor arrangement in the unidirectional single reactor hydrocracking zone 330 may contain one or more stationary-layer, boiling-layer, slurry-layer, moving bed, continuous stirred tank (CSTR), or tubular reactor, . The uni-directional single reactor hydrocracking zone 330 may operate in a weak hydrocracking mode of operation or a partial switching mode of operation. Additional equipment, including exchangers, furnaces, feed pumps, quench pumps, and compressors, is well known in the art to provide feed to the reactor (s) and to maintain proper operating conditions, and a portion of the unidirectional single reactor hydrocracking zone 330 . Equipment including pumps, compressors, high temperature separation vessels, low temperature separation vessels, etc., which separate the reaction products and provide hydrogen recycle in a unidirectional single reactor hydrocracking zone 330 , is well known and is a one- Is considered to be part of the decomposition zone 330 .

In certain embodiments, the operating conditions for the reactor (s) in the hydrocracking zone 330 using a one-way (single step without recycle) configuration and operating in a weak hydrocracking mode include the following:

Reactor inlet temperatures in the range of about 329-502, 329-460, 329-440, 372-502, 372-460, 372-440, 394-502, 394-460, 394-440 or 412-420 );

The reactor outlet temperature in the range of about 338-516, 338-471, 338-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450 or 422-430 );

Within the range of about 310-475, 310-435, 310-415, 350-475, 350-435, 350-415, 370-475, 370-435, 370-415 or 390-397, (SOR) reaction temperature (WABT);

Termination of execution as a WABT within the range of about 338-516, 338-471, 338-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450 or 422-430 (EOR) reaction temperature;

Reaction inlet pressure (barg) in the range of about 108-161, 108-148, 108-141, 121-161, 121-148, 121-141, 128-161, 128-148, 128-141 or 131-137 );

Reaction outlet pressure (barg) within the range of about 100-150, 100-137, 100-130, 112-150, 112-137, 112-130, 118-150, 118-137 or 118-130;

The hydrogen partial pressure (barg) in the range of about 77-116, 77-106, 77-101, 87-116, 87-106, 87-101, 92-116, 92-106, 92-101, ) (exit);

At least about 530, 510, 470 or 450, in certain embodiments about 340-510, 340-470, 340-450, 382-510, 382-470, 382-450, 400-510, 400-470, 400- 450 or 410-440 (SLt / Lt);

A hydrogen quench gas feed rate (SLt / Lt) of at most about 470, 427, 391 or 356, in certain embodiments at about 178-427, 178-214, 178-356, 214-321 or 178-391;

At most about 225, 215, 200 or 190, in certain embodiments at about 143-215, 143-200, 143-190, 161-215, 161-200, 161-190, 170-215, 170-200, or 170- 190 supplemental hydrogen velocity (SLt / Lt); And

In the range of about 0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0, 0.4-10.0, 0.4-5.0, or 0.5-3.0 on the basis of the fresh feed relative to the hydrocracking catalyst Space velocity value (h ^-1 ).

Under these conditions and catalyst selection, an exemplary product from a one-way single reactor hydrocracking zone 330 operating in a weak hydrocracking mode of operation comprises an LPG, kerosene, naphtha, and atmospheric gas oil range components, 27-52, 27-48, 30-50 or 30-52 wt% (relative to the feed to the gas oil hydrotreating zone 330 ) of boiling point, for example boiling below 370 ° C. The remaining bottom fraction is a non-converting oil fraction, all or a portion of which may be effectively incorporated as a feed into the high olefinic fluid catalytic cracking zone 700 as described herein.

In certain embodiments, operating conditions for the reactor (s) in the hydrocracking zone 330 using a one-way (single step without recycle) configuration and operating in a partial conversion mode include the following:

The inlet temperature of the reactor in the range of about 340-502, 340-460, 340-440, 372-502, 372-460, 372-440, 394-502, 394-460, 394-440 or 412-420 );

The reactor outlet temperature in the range of about 350-516, 350-471, 350-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450 or 422-430 );

Within the range of about 310-475, 310-435, 310-415, 350-475, 350-435, 350-415, 370-475, 370-435, 370-415 or 390-397, (SOR) reaction temperature (WABT);

Termination of execution as a WABT within the range of about 338-516, 338-471, 338-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450 or 422-430 (EOR) reaction temperature;

Reaction inlet pressure (barg) in the range of about 100-165, 100-150, 100-140, 120-165, 120-140, 130-165, 130-150, or 130-140;

Reaction exit pressure (barg) in the range of about 92-150, 92-137, 92-130, 112-150, 112-127, 112-130, 118-140, 118-130;

Hydrogen partial pressure (barg) (outlet) within the range of about 80-120, 80-106, 80-101, 90-120, 90-106, 90-101, 100-120, or 100-115;

At most about 677, 615, 587 or 573, in certain embodiments about 503-615, 503-587, 503-573, 531-615, 531-587, 531-573, 545-615, 545-587, or 545 -573 hydrogenation gas feed rate (SLt / Lt);

At most about 614, 558, 553 or 520, in certain embodiments at about 457-558, 457-533, 457-520, 482-558, 482-533, 482-520, 495-558, 495-533, or 495 Hydrogen-quenched gas feed rate (SLt / Lt) of -520;

At most about 305, 277, 264 or 252, in certain embodiments about 204-277, 204-264, 204-252, 216-277, 216-264, 216-252, 228-277, 228-264, or 228 Supplemental hydrogen velocity (SLt / Lt) of -252; And

0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0, 0.4-10.0, 0.4-5.0, 0.4-2.0, or 0.5-3.0 on the basis of fresh feed relative to the hydrocracking catalyst (H < ^-1 >).

Under these conditions and catalyst selection, the exemplary product from the one-way single reactor hydrocracking zone 330 operating as a partial conversion hydrocracker will contain atmospheric pressure end boiling point (LPG), including LPG, kerosene, naphtha, , 48-82, 50-80, 48-75, 50-75 wt% emissions (relative to feed to the gas oil hydrotreating zone 330 ) boiling below 370 ° C, for example. The remaining bottom fraction is a non-converting oil fraction, all or a portion of which may be effectively incorporated as a feed into the high olefinic fluid catalytic cracking zone 700 as described herein.

Figure 19 shows another embodiment of a serial flow hydrocracking zone 350 operating as a serial-flow hydrocracking system with recycling to either the first reactor zone, the second reactor zone, or both the first and second reactor zones It is schematically shown. Generally, the serial flow hydrocracking zone 350 includes a first reaction zone 352 , a second reaction zone 358 , and a fractionation zone 342 .

The first reaction zone 352 includes all or part of the source of initial feed material 334 , the source of hydrogen gas 338 , and the fractionation zone 342 tower bottom stream 348 in certain embodiments, 342 product at least one inlet in fluid communication with the recycle stream (364a) including a portion of stream 362 is typically included. One or more outlets of the first reaction zone 352 that emit the effluent stream 354 are in fluid communication with one or more inlets of the second reaction zone 358 . In certain embodiments, the effluent 354 is Is passed to the second reaction zone 358 without separation of excess hydrogen and light gas. In an optional embodiment, one or more high pressure and low pressure separation steps are provided (not shown) between the first and second reaction zones 352 , 358 for the recovery of recycled hydrogen.

The second reaction zone 358 may include at least one outlet of the first reaction zone 352 , optionally a source of additional hydrogen gas 356 , and a source of all of the fractionation stream 348 in the fractionation zone 342 in certain embodiments. Or portions and optionally one or more entrances in fluid communication with a recycle stream 364b that includes a fraction of fractionation zone 342 product stream 362. [ One or more outlets of the second reaction zone 358 that emit the effluent stream 360 are separated by a fractionation zone 342 (optionally with one or more high and low pressure separation steps therebetween for the recovery of recycled hydrogen, ) ≪ / RTI >

Fractionation zone 342 is a gas 344, typically, _{H 2, H 2 S, NH} 3, and light hydrocarbons, at least one outlet for the discharge of (C ₁ -C _4); One or more outlets for recovering product 346 , such as intermediate distillate naphtha and diesel product boiling within the temperature range of the atmospheric gas oil range fraction, e.g., within the temperature range of 36-370 占 폚; And one or more outlets for discharging column bottoms 348 comprising hydrocarbons boiling above the atmospheric gas oil range (e.g., about 370 ° C), from which the bleed stream 368 is removed from the process Lt; / RTI > In certain embodiments, the temperature cut point for tower bottom 348 (and thus the end point for product 346 ) is less than the upper temperature limit of a given gasoline, kerosene, and / or diesel product boiling point range for downstream operation . ≪ / RTI >

In operation of the serial flow hydrocracking zone 350 , feed material stream 334 and hydrogen stream 338 are charged into a first reaction zone 352 . The hydrogen stream 338 is an amount of hydrogen effective to support the degree of hydrocracking, feed type, and other factors required and is coupled to reaction zones 352 and 358 , and / or a fractionator gas stream 344 ) and recycled hydrogen 336 from an optional gas separation subsystem (not shown) derived from complementary hydrogen 302 . In certain embodiments, the reaction zone may contain multiple catalyst layers and may contain one or more quench hydrogen streams between the layers (not shown).

The first reaction zone 352 operates under effective conditions for the production of the reaction effluent stream 354 and optionally with the additional hydrogen stream 356 in a second reaction zone 358 (optionally one for recovering recycled hydrogen) After the above-described high-pressure and low-pressure separation steps). The second reaction zone 358 operates under conditions effective for the production of the reaction effluent stream 360 containing the converted, partially converted and unconverted hydrocarbons.

The reaction effluent stream 360 is generally passed to fractionation zone 342 to recover gas and liquid products and byproducts 344 and 346 and to separate tower bottom fraction 348 . A portion of the bottom low fraction 348 , stream 368 , is directed to the high olefinic fluid catalytic cracking zone 700 as described herein.

A gas stream 344 containing, typically, H ₂ , H ₂ S, NH ₃ , and light hydrocarbons (C ₁ -C ₄ ) can be released, recovered, and further processed. The effluent off-gas is passed to an olefin recovery train, a saturated gas plant as part of another gas stream 156 , and / or a direct fuel gas system. The liquefied petroleum gas may be recovered and sent to a mixed feed steam cracking zone, an olefin recovery train, and / or a saturated gas plant. The one or more cracked product streams 346 may be discharged through an appropriate outlet of the fractionator and processed further and / or downstream refinery for producing gasoline, kerosene and / or diesel fuel, or other petrochemical products Blended in operation. In certain embodiments, a diesel fraction 362 derived from one or more of the cracked product streams 346 may be integrated with the recycle stream to the reactor. This integration adds flexibility of construction between the production of diesel fuel or petrochemicals from the product stream 346 .

In certain embodiments (not shown), the fractionation zone 342 may be configured to provide a suitable cut point, for example, a range of temperatures corresponding to the upper temperature range of a given gasoline, kerosene, and / or diesel product for downstream operation As shown in FIG. In certain embodiments, a suitable cut point is selected from the group consisting of 350-450 DEG C, 360-450 DEG C, 370-450 DEG C, 350-400 DEG C, 360-400 DEG C, 370-400 DEG C, 350-380 DEG C, Lt; / RTI > The stream above the cut point is directed to a high olefinic fluid catalytic cracking zone 700 as described herein.

All or a portion of the sorbent tower bottoms stream 348 from the reaction effluent is recycled to the first or second reaction zone 352 and / or 358 (streams 364a and / or 364b ). In certain embodiments, a portion of the fractionator tower from the reaction effluent is removed as a bleed stream 368 . The bleed stream 368 may be about 0-10 vol%, 1-10 vol%, 1-5 vol%, or 1-3 vol% of the fractionator tower bottom 348 . This stream 368 is directed to a high olefinic fluid catalytic cracking zone 700 as described herein.

Thus, all or a portion of the sorbent tower bottoms stream 348 may be separated into a second reaction zone 358 as stream 364b , a first reaction zone 352 as stream 364a , 352 ) and ( 358 ). For example, the stream 364a recycled to zone 352 contains 0 to 100 vol%, in certain embodiments 0 to about 80 vol%, and in a further embodiment 0 to about 50 vol% stream 348 And stream 364b recycled to zone 358 contains 0 to 100 vol%, in certain embodiments 0 to about 80 vol%, and in a further embodiment 0 to about 50 vol% stream 348 do. In certain embodiments where recycling is at or near 100 vol%, non-converting oil recycling increases the yield of a suitable product as a feed to the mixed feed steam cracking zone 230 .

For example, suitable serial flow hydrocracking zones 350 include, but are not limited to, Honeywell UOP, US; Chevron Lummus Global LLC (CLG), US; Axens, IFP Group Technologies, FR; Or systems based on commercially available technology from Shell Global Solutions, US.

The reactor arrangement in the series flow hydrocracking zone 350 may contain one or more stationary-layer, boiling-layer, slurry-layer, moving bed, continuous stirred tank (CSTR), or tubular reactor, have. Additional equipment, including exchangers, furnaces, feed pumps, quench pumps, and compressors, is well known in the art to provide feed to the reactor (s) and to maintain proper operating conditions, and is part of the serial flow hydrocracking zone 350 . Also included are equipment including pumps, compressors, high temperature separation vessels, low temperature separation vessels, etc., which separate the reaction products and provide for hydrogen recycle in the in-line flow hydrocracking zone 350 , Lt ; RTI ID = 0.0 > 350 < / RTI >

In certain embodiments, the operating conditions for the first reactor (s) in the hydrocracking zone 350 using a one-way series configuration operating in a partial switching mode of operation include the following:

The inlet temperature of the reactor in the range of about 340-502, 340-460, 340-440, 372-502, 372-460, 372-440, 394-502, 394-460, 394-440 or 412-420 );

The reactor outlet temperature in the range of about 350-516, 350-471, 350-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450 or 422-430 );

Within the range of about 310-475, 310-435, 310-415, 350-475, 350-435, 350-415, 370-475, 370-435, 370-415 or 390-397, (SOR) reaction temperature (WABT);

Termination of execution as a WABT within the range of about 338-516, 338-471, 338-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450 or 422-430 (EOR) reaction temperature;

Reaction inlet pressure (barg) in the range of about 100-165, 100-150, 100-140, 120-165, 120-140, 130-165, 130-150, or 130-140;

Reaction exit pressure (barg) in the range of about 92-150, 92-137, 92-130, 112-150, 112-127, 112-130, 118-140, 118-130;

Hydrogen partial pressure (barg) (outlet) within the range of about 80-120, 80-106, 80-101, 90-120, 90-106, 90-101, 100-120, or 100-115;

At most about 668, 607, 580 or 566, in certain embodiments at about 497-607, 497-580, 497-566, 525-607, 525-580, 525-566, 538-607, 538-580, or 538 -566 hydrotreating gas feed rate (SLt / Lt);

At most about 819, 744, 711 or 694, in certain embodiments at about 609-744, 609-711, 609-694, 643-744, 643-711, 643-694, 660-744, 660-711, or 660 Hydrogen gas quenching gas feed rate (SLt / Lt) of -694;

At most about 271, 246, 235 or 224, in certain embodiments at about 182-246, 182-235, 182-224, 192-246, 192-235, 192-224, 203-246, 203-235, or 203 -224 supplemental hydrogen velocity (SLt / Lt); And

0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0, 0.4-10.0, 0.4-5.0, 0.4-2.0, or 0.5-1.5 on the basis of the fresh feed relative to the hydrocracking catalyst (H < ^-1 >).

In certain embodiments, the operating conditions for the second reactor (s) in the hydrocracking zone 350 using a one-way series configuration operating in a partial switching mode of operation include the following:

In certain embodiments, the partial conversion hydrocracking operating conditions employing a one-way configuration include the following:

The inlet temperature of the reactor in the range of about 340-502, 340-460, 340-440, 372-502, 372-460, 372-440, 394-502, 394-460, 394-440 or 412-420 );

The reactor outlet temperature in the range of about 350-516, 350-471, 350-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450 or 422-430 );

Within the range of about 310-475, 310-435, 310-415, 350-475, 350-435, 350-415, 370-475, 370-435, 370-415 or 390-397, (SOR) reaction temperature (WABT);

Termination of execution as a WABT within the range of about 338-516, 338-471, 338-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450 or 422-430 (EOR) reaction temperature;

Reaction inlet pressure (barg) in the range of about 90-150, 90-130, 90-140, 110-150, 110-130, 110-145, or 130-150;

Reaction exit pressure (barg) in the range of about 85-140, 85-127, 100-140, 112-130, 112-140, or 118-130;

Hydrogen partial pressure (barg) (outlet) within the range of about 80-130, 80-120, 80-101, 90-130, 90-120, 90-101, 100-130, or 100-115;

At most about 890, 803, 767 or 748, in certain embodiments at about 657-803, 657-767, 657-748, 694-803, 694-767, 694-748, 712-803, 712-767, or 712 The hydrogenation gas feed rate (SLt / Lt) of -748;

At most about 850, 764, 729 or 712, in certain embodiments at about 625-764, 625-729, 625-712, 660-764, 660-729, 660-712, 677-764, 677-729, or 677 A hydrogen quench gas supply rate (SLt / Lt) of -712;

At most about 372, 338, 323 or 309, in certain embodiments at about 250-338, 250-323, 250-309, 264-338, 264-323, 264-309, 279-338, 279-323, -309 supplemental hydrogen velocity (SLt / Lt); And

A liquid space velocity value in the range of about 0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 1.0-5.0, 2.0-4.0, or 1.0-3.0 on a fresh feed relative to the hydrocracking catalyst ( h ^-1 ).

Under these conditions and catalyst selection, the exemplary products from the partial conversion hydrocrackers using a one-way configuration can be boiled at a boiling point of atmospheric residue end point, e.g., below 370 C, including LPG, kerosene, naphtha, and atmospheric gas oil range components 48-82, 50-80, 48-75 or 50-75 wt% of the effluent. The remaining bottom fraction is a non-converting oil fraction, all or a portion of which may be effectively incorporated as a feed into the high olefinic fluid catalytic cracking zone 700 as described herein.

20 schematically illustrates a two-step hydrocracking zone 370 with recycling operating as a two-step hydrocracking system with recycling, another embodiment of an integrated hydrocracking unit operation. Generally, the hydrocracking zone 370 includes a first reaction zone 372 , a second reaction zone 382 , and a fractionation zone 342 .

The first reaction zone 372 generally includes one or more entrances in fluid communication with a source of initial feed material 334 and a source of hydrogen gas 338 . Which emits effluent stream 374 One or more outlets of the first reaction zone 372 may be separated from the at least one inlet of the fractionation zone 342 (optionally having at least one high pressure and low pressure separation step therebetween for recovery of recycled hydrogen, not shown) Communicate.

Fractionation zone 342 is a gas 344, typically, H ₂ S, NH _3, and light hydrocarbons, at least one outlet for the discharge of (C ₁ -C _4); One or more outlets for recovering boiling naphtha and diesel products within the product 346 , e.g., in the temperature range of less than the atmospheric gas oil range fraction (e.g., within a temperature range of 36 to 370 ° C); And one or more outlets for discharging column bottoms 348 comprising hydrocarbons boiling above the atmospheric gas oil range (e.g., about 370 ° C), from which the bleed stream 368 is removed from the process Lt; / RTI > In certain embodiments, the temperature cut point for tower bottom 348 (and thus the end point for product 346 ) is less than the upper temperature limit of a given gasoline, kerosene, and / or diesel product boiling point range for downstream operation . ≪ / RTI >

The fractionation zone 342 bottoms outlet is in fluid communication with one or more entrances of a second reaction zone 382 for the recycle stream 348a derived from the bottoms stream 348 . The recycled stream 348a may be all or part of the tower bottom stream 348 . In certain optional embodiments (as indicated by the dashed lines in FIG. 20), portion 348b is in fluid communication with one or more of the inlets of first reaction zone 372 .

The second reaction zone 382 is connected to the bottom of the tower bottom 348 A fractionation zone 342 , a bottoms outlet portion 348a , and one or more inlets in fluid communication with a source of hydrogen gas 384 . One or more outlets of the second reaction zone 382 that emit the effluent stream 386 are in the fractionation zone 342 (optionally with one or more high and low pressure separation steps therebetween for the recovery of recycled hydrogen, Lt; RTI ID = 0.0 > and / or < / RTI >

In operation of the two-step hydrocracking zone 370 , the feed stream 334 and the hydrogen stream 338 are charged into the first reaction zone 372 . Hydrogen stream 338 is an amount of hydrogen that is effective to support the degree of hydrodesolution, feed type, and other factors required, and is selected from an optional gas separation subsystem (not shown) coupled with reaction zones 372 and 382 And / or recycled hydrogen 336 and supplemental hydrogen 302 derived from the fractionator gas stream 344. The recycled hydrogen 336 may be recycled, In certain embodiments, the reaction zone may contain multiple catalyst layers and may contain one or more quench hydrogen streams between the layers (not shown).

The first reaction zone 372 operates under conditions effective for the production of the reaction effluent stream 374 and generally comprises a fractionation zone 342 for recovering gas and liquid products and byproducts and a separate bottom fraction, After one or more high pressure and low pressure separation steps to recover recycled hydrogen).

A gas stream 344 containing, typically, H ₂ , H ₂ S, NH ₃ , and light hydrocarbons (C ₁ -C ₄ ) can be released, recovered, and further processed. The effluent off-gas is passed to an olefin recovery train, a saturated gas plant as part of another gas stream 156 , and / or a direct fuel gas system. The liquefied petroleum gas may be recovered and sent to a mixed feed steam cracking zone, an olefin recovery train, and / or a saturated gas plant. The one or more cracked product streams 346 may be discharged through an appropriate outlet of the fractionator and processed further and / or downstream refinery for producing gasoline, kerosene and / or diesel fuel, or other petrochemical products Blended in operation. In certain embodiments, the diesel fraction 376 from one or more of the cracked product streams 346 may be combined with the feed to the second stage reactor 382 . This integration adds flexibility of construction between the production of diesel fuel or petrochemicals from the product stream 346 .

In certain embodiments (not shown), the fractionation zone 342 may be configured to provide a suitable cut point, for example, a range of temperatures corresponding to the upper temperature range of a given gasoline, kerosene, and / or diesel product for downstream operation As shown in FIG. In certain embodiments, a suitable cut point is selected from the group consisting of 350-450 DEG C, 360-450 DEG C, 370-450 DEG C, 350-400 DEG C, 360-400 DEG C, 370-400 DEG C, 350-380 DEG C, Lt; / RTI > The stream above the cut point is directed to a high olefinic fluid catalytic cracking zone 700 as described herein.

All or a portion of the sorbent tower bottoms stream 348 from the reaction effluent is stream 348a And is passed to the second reaction zone 382 . In certain embodiments, all or a portion of the tower bottoms stream 348 may be treated as a second reaction zone 382 as stream 348a , a first reaction zone 372 as stream 348b , Is recycled to both zones 372 and 382 . For example, stream 348b recycled to zone 372 may contain a stream 348 of 0 to 100 vol%, 0 to about 80 vol%, or 0 to about 50 vol%, and may be recycled to zone 382 Stream 348a comprises 0 to 100 vol%, 0 to about 80 vol%, or 0 to about 50 vol% of stream 348 . In certain embodiments where recycling is at or near 100 vol%, non-converting oil recycling increases the yield of a suitable product as a feed to the mixed feed steam cracking zone 230 .

In certain embodiments, a portion of the fractionator tower from the reaction effluent is removed as a bleed stream 368 . The bleed stream 368 may be about 0-10 vol%, 1-10 vol%, 1-5 vol%, or 1-3 vol% of the fractionator tower bottom 348 .

The second reaction zone 382 operates under conditions effective for the production of the reaction effluent stream 386 containing the converted, partially converted and unconverted hydrocarbons. The second stage reaction effluent stream 386 is passed through the fractionation zone 342 , optionally through one or more gas separators, to recover the recycled hydrogen and the particular light gas that has been removed

For example, suitable two-step hydrocracking zones 370 include, but are not limited to Honeywell UOP, US; Chevron Lummus Global LLC (CLG), US; Axens, IFP Group Technologies, FR; Or systems based on commercially available technology from Shell Global Solutions, US.

The two-stage reactor arrangement with recycled hydrocracking zone 370 may contain one or more stationary-bed, boiling-layer, slurry-bed, moving bed, continuous stirred tank (CSTR), or tubular reactor, They can be arranged in parallel. Part for supplying the reactor (s) and maintained at the correct operating conditions, the heat exchanger, a furnace, a feed pump, a quench pump, and additionally the device is well known and a two-step hydrogenation decomposition zone 370 containing a compressor . Also included are pumps, compressors, high temperature separation vessels, low temperature separation vessels, and the like, which provide separation of reaction products and provide for hydrogen recycle in a two-step hydrocracking zone 370 , Is considered to be a part of the decomposition zone 370 .

In certain embodiments, operating conditions for the first stage reactor (s) in the hydrocracking zone 370 using a two-stage recycle configuration operating in a full conversion mode of operation include the following:

The inlet temperature of the reactor in the range of about 340-502, 340-460, 340-440, 372-502, 372-460, 372-440, 394-502, 394-460, 394-440 or 412-420 );

The reactor outlet temperature in the range of about 350-516, 350-471, 350-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450 or 422-430 );

Within the range of about 310-475, 310-435, 310-415, 350-475, 350-435, 350-415, 370-475, 370-435, 370-415 or 390-397, (SOR) reaction temperature (WABT);

Termination of execution as a WABT within the range of about 338-516, 338-471, 338-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450 or 422-430 (EOR) reaction temperature;

The reaction inlet pressure (barg) in the range of about 100-180, 100-160, 100-141, 121-180, 121-160, 121-141, 128-180, 128-160, 128-141 or 131-180 );

Reaction exit pressure (barg) within the range of about 90-170, 90-137, 90-130, 112-170, 112-137, 112-130, 118-150, 118-137 or 118-170;

Hydrogen partial pressure (barg) (outlet) in the range of about 90-137, 90-106, 90-120, 100-137, 100-106, or 100-120;

At most about 1050, 940, 898 or 876, in certain embodiments at about 769-940, 769-898, 769-876, 812-940, 812-898, 812-876, 834-940, 834-898, or 834 -876 hydrotreating gas feed rate (SLt / Lt);

At most about 1100, 980, 935 or 913, in certain embodiments at about 801-980, 801-935, 801-913, 846-980, 846-935, 846-913, 868-980, 868-935, Hydrogen-quenched gas feed rate (SLt / Lt) of -913;

At most about 564, 512, 490 or 468, in certain embodiments at about 378-512, 378-490, 378-468, 401-512, 401-490, 401-468, 423-512, 423-490, or 423 -468 replenishment hydrogen velocity (SLt / Lt); And

0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0, 0.4-10.0, 0.4-5.0, 0.4-2.0, or 0.5-1.5 on the basis of the fresh feed relative to the hydrocracking catalyst (H < ^-1 >).

In certain embodiments, operating conditions for the second stage reactor (s) in the hydrocracking zone 370 using a two-stage recycle configuration operating in a full conversion mode of operation include the following:

In certain embodiments, the operating conditions for the reactor (s) in the first stage reaction zone of the two-step hydrocracking zone 370 include the following:

The inlet temperature of the reactor in the range of about 340-502, 340-460, 340-440, 372-502, 372-460, 372-440, 394-502, 394-460, 394-440 or 412-420 );

The reactor outlet temperature in the range of about 350-516, 350-471, 350-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450 or 422-430 );

Within the range of about 310-475, 310-435, 310-415, 350-475, 350-435, 350-415, 370-475, 370-435, 370-415 or 390-397, (SOR) reaction temperature (WABT);

Termination of execution as a WABT within the range of about 338-516, 338-471, 338-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450 or 422-430 (EOR) reaction temperature;

Reaction inlet pressure (barg) within the range of about 80-145, 80-100, 80-131, 80-120, 120-145, 100-145, or 130-145;

Reaction exit pressure (barg) within the range of about 75-137, 75-130, 90-130, 100-137, 100-122, or 112-137;

Hydrogen partial pressure (barg) (outlet) in the range of about 90-145, 90-106, 90-120, 100-145, 100-106, or 100-120;

At most about 910, 823, 785 or 767, in certain embodiments at about 673-823, 673-785, 673-767, 711-823, 711-785, 711-767, 729-823, 729-785, or 729 -767 hydrotreating gas feed rate (SLt / Lt);

At most about 980, 882, 842 or 822, in certain embodiments at about 721-882, 721-842, 721-822, 761-882, 761-842, 761-822, 781-882, 781-842, or 781 The hydrogen quench gas supply rate (SLt / Lt) of -822;

At most about 451, 410, 392 or 374, in certain embodiments about 303-410, 303-392, 303-374, 321-410, 321-392, 321-374, 338-410, 338-392, or 338 Supplemental hydrogen velocity (SLt / Lt) of -374; And

A liquid space velocity value in the range of about 0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 1.0-5.0, 2.0-4.0, or 1.0-3.0 on a fresh feed relative to the hydrocracking catalyst ( h ^-1 ).

Exemplary products from hydrocracking zone 370 operating as a two-stage hydrocracker (with recycle) in full conversion mode under these conditions and catalyst selection include LPG, kerosene, naphtha, and atmospheric gas oil range components which, relative to the feed of the atmospheric residue boiling point of the terminal, for example, boiling 78-99, 78-90, 78-85, 80-90, or 80-99 wt% of the effluent below 370 ℃ (hydrogenated decomposition zone 370 ). The remaining bottom fraction is a non-converting oil fraction, all or a portion of which may be effectively incorporated as a feed into the high olefinic fluid catalytic cracking zone 700 as described herein.

In certain embodiments, 0-100 wt% of the vacuum residue stream 168 can be processed within the residue treatment center 800 (shown as dashed lines as an optional embodiment). In an additional embodiment, 0-100 wt% pyrolysis oil from the steam cracker complex can be sent to the residue treatment center 800 . The residue treatment center 800 may include, but is not limited to, one or more of the following: a catalytic hydrogen addition process, such as a residue hydrocracking system; Thermal coking processes, such as delayed cokers; And / or a solvent deasphalting process. In certain embodiments, the residue treatment center 800 produces one or more of a distillate fraction 808 , a heavy fraction 806 , and / or a bottom fraction 804 . The distillate fraction 808 comprises one or more intermediate distillate streams boiling, for example, below the atmospheric gas oil range fraction or within the intermediate atmospheric gas oil range fraction below the temperature range (e.g., within the temperature range of 36-370 DEG C) can do. Note that when the residue treatment center 800 is solvent deasphalting, the distillate fraction 808 is not produced. The portion of the distillate fraction 808 can be used for the feed to one or more of the feed to the mixed feed steam cracking zone 230 , integrated water addition room, and / or for the production of fuel components . All or a portion of the heavy fraction 806 may be treated with one or more streams of treated heavy range hydrocarbons, for example boiling above the atmospheric gas oil range above (e.g., 370 占 폚) or above the intermediate atmospheric gas oil range; Or a deasphalted oil in a solvent deasphalting unit. A portion of the heavy fraction 806 may be used as feed to at least one of the feed to the gas oil cracking zone 250 and the integrated water addition zone and recovered as a non-conversion oil product, May be used for production of lubricant in the zone, and / or may be incorporated into the fuel oil pool. The bottom loose fraction 804 may comprise, for example, a pitch in the residue hydrocracking system, a petroleum coke in a delayed coker, or asphalt in a solvent deasphalting unit.

A specific example of a system and process involving a specific vacuum residue water addition space is described in "Process and System for Convergence, " entitled " Integrating Vacuum Residue Hydroprocessing" on November 17, 2017 Filed on November 17, 2017, entitled " SA3106 AFS 215,409 ", filed November 17, 2017, entitled " Process and System for Conversion of Crude Oil to Petrochemicals and Fuel Products, No. SA3107 AFS 215,410, which are co-applicants and are incorporated herein by reference in their entirety. Specific examples of systems and processes involving solvent deasphalting are described in U. S. Patent Application No. < RTI ID = 0.0 > (" U. < / RTI & [SA3108 AFS 215,411], which is a co-applicant and is incorporated herein by reference in its entirety. A specific example of a system and process involving thermal caulking is disclosed in U. S. Patent Application No. SA3109 " filed on November 17, 2017 entitled " Process and System for Conversion of Crude Oil to Petrochemicals and Fuel Products, AFS 215,412, which is a co-applicant and is incorporated herein by reference in its entirety.

The hydrotreated gas oil fraction ( 304 ) is sent to the high olefinic fluid catalytic cracking zone ( 700 ). In a particular embodiment, the fourth intermediate distillate stream 130 is also directed to the high olefinic fluid catalytic cracking zone 700 and bypasses the vacuum gas oil hydrotreating zone 300 , as shown within the dashed line. In certain embodiments, as shown in a dotted line, and the fourth middle distillate stream 130 prior to passing to the high olefinic a fluid catalytic cracking zone (700), for example a vacuum gas oil different to the hydrotreating zone 300, The feed is treated with hydrotreating.

The product comprises a fluid catalytic cracking naphtha 706 that can be sent to the naphtha hydrotreating zone 670 as shown in Figure 21, and the fuel gas and LPG passed to the unsaturated gas plant 702 ; The light cycle oil stream 708 , all or a portion thereof, is passed to the diesel hydrotreating zone 180 and passed through a slurry oil or a heavy cycle oil stream that can be sent to the fuel oil pool or used as a feedstock for the production of carbon black ( 710 ). In certain embodiments, all or a portion of the fluid catalytic cracked naphtha 706 may be sent to the aromatic extraction zone 620 without the hydrotreating. In certain embodiments, 0-100 wt% ( 712 ) light cycle oil stream 708 is sent to the fuel oil pool

The unsaturated gas plant 702 and the high olefinic fluid catalytic cracking recovery section (not shown) are operated to recover the C2-stream 714 and the C3 + stream passed to the olefin recovery train 270 . In certain embodiments, the high olefinic fluid catalytically cracked light olefins are used to remove contaminants including oxygen, nitrous oxide, nitrile, acetylene, methyl acetylene, butadiene, arsine, phosphine, stibine, Lt; / RTI > The treatment of the C2-off-gas stream in certain embodiments involves the use of a multi-functional catalyst as is known in the operation of an unsaturated gas plant before it is passed to the olefin recovery train 270 . Also, the C3 + stream ( 716 ), which generally contains C3s and C4s, is recovered from the high olefinic fluid catalytic cracking recovery section. In certain embodiments, the stream is treated in a mercaptan oxidation unit as is known in the operation of an unsaturated gas plant prior to sending it to olefin recovery train 270 or steam cracking zone 230 . In a particular embodiment, the C3 + stream 716 stream is sent to a splitter, which can be integrated or separated with the olefin recovery train 270 to recover the olefin, and the remaining LPGs are fed to the mixed feed vapor decomposition zone 230 , Lt; / RTI > A substantial, substantial, or major portion of both C2-stream 714 and C3 + stream 716 is sent through an unsaturated gas plant. The remainder, if present, may be sent to the mixed feed steam cracking zone 230 and / or the olefin recovery train 270 .

In certain embodiments, the vacuum gas oil hydrotreating zone 300 can be bypassed and the high olefinic fluid catalytic cracking and associated regenerator can be used to control the product from a unit comprising flue gas produced in a catalyst regenerator Lt; / RTI > In another embodiment, a vacuum gas oil hydrotreating zone 300 is utilized, and the VGO treatment reduces catalyst consumption and increases yield in high olefinic fluid catalytic cracking. In embodiments where the vacuum gas oil hydrotreating zone 300 is utilized, flue gas desulfurization of the flue gas produced in the catalyst regenerator is also provided.

As shown in Figures 12, 13 and 21, a portion of the cycle oil product from the high olefinic fluid catalytic cracking, cycle oil 708 , is passed to the diesel hydrotreating zone 180 , A portion of the cycle oil product, cycle oil 712 , is converted, for example, to be included in the fuel oil pool. The 0-5, 0-10, 0-15, or 0-20 amount (wt%) of the cycle oil stream 708 is passed to the diesel hydrotreating zone 180 and the remainder is passed through the fuel oil pool. Slurry oil 710 is also recovered from high olefinic fluid catalytic cracking zone 700 . This heavy product is an effective feedstock for carbon black production or may be contained in a fuel oil pool.

There are many commercially available systems for maximizing the production of propylene using fluid catalytic cracking units. Suitable high olefinic fluid catalytic cracking zones ( 700 ) include, but are not limited to, Axens, IFP Group Technologies, FR; Honeywell UOP, US; CN Petroleum & Chemical Corporation (Sinopec), CN; KBR, Inc, US; Or a system based on technology commercially available from Chicago Bridge & Iron Company NV (CB & I), NL.

The high olefinic fluid catalytic crack zone 700 may have one or more risers / reactors, a separator / stripper, and one or more regenerators. When a plurality of reactors are run, the propylene yield and selectivity can be maximized.

In certain embodiments, there is provided a fluid catalytic cracking unit configured to have a riser reactor that promotes light olefins, particularly propylene formation, and operates under conditions that minimize light olefin-consuming reactions, including hydrogen-transfer reactions. 21A is a simplified schematic diagram of a riser fluid catalytic cracking unit. The fluid catalytic cracking unit 720 includes a riser reactor. The fluid catalytic cracking unit 720 includes a reactor / separator 724 having a riser portion 726 , a reaction zone 728 and a separation zone 730 . The fluid catalytic cracking unit 720 also includes a spent regeneration vessel 732 for regenerating the spent catalyst. In certain embodiments involving steam or other suitable gas for feed atomization, the filler 722 is introduced into the reaction zone (not shown). In the present integrated process, the hydrotreated gas oil 722 is optionally treated with an effective amount of heated fresh or recycled (e.g., hydrogenated) gaseous oil carried through the conduit 734 from the regeneration vessel 732 in combination with an atmospheric gas oil, Mixed and closely contacted with the solid decomposing catalyst particles. The feed mixture and cracking catalyst is fed to riser 726 , Into me Under conditions to form the suspension to be introduced. In a continuous process, a mixture of cracking catalyst and hydrocarbon feedstock is fed upward through the riser 726 into the reaction zone 728 , Into me Go ahead. In riser 726 and reaction zone 728 , the hot decomposition catalyst particles catalytically decompose relatively large hydrocarbon molecules by carbon-carbon bond decomposition.

During the reaction, as is typical in fluid catalytic cracking operations, the cracking catalyst is caulked and thus has limited or no access to the active catalyst site. The reaction product, for example, in the reaction zone 728 , Within the fluid catalytic cracking unit 720 located at the top of the reactor 724 above is separated from the coked catalyst using any suitable known construction in the fluid catalytic cracking unit generally referred to as a separation zone 730 do. The separation zone may comprise, for example, a suitable device known to those of ordinary skill in the art, for example, a cyclone. The reaction product is withdrawn through conduit 736 . Catalyst particles containing coke deposits from the hydrocracking of the hydrocarbon feedstock pass through conduit 738 into the regeneration zone 732 It passes.

In the regeneration zone 732 , the coked catalyst is contacted with a stream of oxygen-containing gas, such as pure oxygen or air, which passes through the conduit 740 into the regeneration zone 732 I go in. The regeneration zone 732 is operated under known configurations and conditions in a typical fluid catalytic cracking operation. For example, the regeneration zone 732 may operate as a fluidized bed for producing a regeneration off-gas comprising combustion products discharged through the conduit 742 . The hot regenerated catalyst is transferred from regeneration zone 732 through conduit 734 to the bottom portion of riser 726 for mixing with the hydrocarbon feedstock.

In one embodiment, a suitable fluid catalytic cracking unit 720 may be similar to that described in US Pat. Nos. 7,312,370, 6,538,169, and 5,326,465, the disclosure of which is incorporated herein by reference in its entirety. In general, operating conditions for a suitable riser fluid catalytic cracking unit (720) reactor include the following:

Reaction temperature (° C) of about 480-650, 480-620, 480-600, 500-650, 500-620, or 500-600;

Reaction pressure (barg) of about 1-20, 1-10, or 1-3;

Contact times of about 0.5-10, 0.5-5, 0.5-2, 1- 10, 1-5, or 1-2 (in the reactor, second); And

1: 1 to 10: 1, 8: 1 to 20: 1, 8: 1 to 15: 1, or 8: 1 to 10: 1 Catalyst-to-feed ratio.

In certain embodiments, there is provided a fluid catalytic cracking unit comprised of a downflow reactor, which operates under conditions that promote light olefins, especially propylene formation, and light olefin-consuming reactions involving hydrogen-transfer reactions. Figure 21b is a simplified schematic diagram of a downflow fluid catalytic cracking unit. The fluid catalytic cracking unit 760 includes a reactor / separator 764 having a reaction zone 768 and a separation zone 770 . The fluid catalytic cracking unit 760 includes a regeneration spent-for-catalyst regeneration zone 772 . In particular, in certain embodiments involving feed spray vapors or other suitable gases, the fill 762 is introduced into the reaction zone (not shown). Of the regeneration zone 772, the heated fresh or high temperature regeneration effective amount of decomposition reaction of the solid catalyst particle zone (768) from To the top (Not shown) from the top of the reaction zone 768 through a downwardly directed conduit or pipe 774 , also referred to as a transition line or standpipe, for example. The high temperature catalyst flow is typically stabilized to be uniformly directed into the feed zone of the mixing zone or reaction zone 768 . The filler 762 typically includes a reaction zone 768 , of mine Is injected into the mixing zone through a feed injection nozzle located adjacent the point of introduction of the regenerated catalyst. These multiple injection nozzles result in thorough and uniform mixing of the hot catalyst and filler 762 , optionally in an integrated process hydrotreated gas oil here, in combination with an atmospheric gas oil, such as a heavy atmospheric gas oil. When the packing contacts the high temperature catalyst, a decomposition reaction occurs.

The cracked product of the reactive vapor hydrocarbon, the unreacted feed and the catalyst mixture rapidly flows into the bottom portion of the rapid separation zone 770 reactor / separator 764 through the remainder of the reaction zone 768 . The cracked and undifferentiated hydrocarbons are sent via conduit or pipe 776 to a conventional product recovery section known in the art to obtain fluid catalytic cracking products light olefins, gasoline, and cycle oil at a maximized propylene yield. If necessary for temperature control, a quench injection may be provided near the reaction zone 768 bottom just prior to the separation zone 770 . This quenched injection can be used to rapidly reduce or stop the cracking reaction and to control the cracking strength to achieve product slate.

The reaction temperature, ie, the outlet temperature of the downflow reactor, is controlled by opening and closing a catalyst slide valve (not shown) that controls the flow of the hot regenerated catalyst from the regeneration zone 772 to the top of the reaction zone 768 Lt; / RTI > And the heat required for the endothermic decomposition reaction is supplied by the regenerated catalyst. By varying the flow rate of the hot regenerated catalyst, the operating strength or decomposition conditions for producing the desired product slate can be controlled. A stripper 778 for separating the oil from the catalyst is also provided, which is transferred to the regeneration zone 772 . The catalyst from separation zone 770 flows through stream line 780 to a lower section of stripper 778 containing a suitable stripping gas, such as a catalyst stripping section into which steam is introduced. A downwardly flowing catalyst 788 , which passes in the opposite direction to the flowing stripping gas, is typically provided with a stripping section having several baffles or structured packings (not shown). The upwardly flowing stripping gas, typically steam, is used to "strip" or remove residual hydrocarbons remaining in or between the catalyst pores. The stripped, spent catalyst is fed into the regeneration zone 770 And is carried by lift from combustion air stream 790 via a lift riser. This spent catalyst can also contact additional combustion air and undergo controlled combustion of the stored coke. Flue gas is removed from the regenerator via conduit 792 . In the regenerator, the heat produced from the combustion of coke by-products is transferred to the catalytic reaction zone (768) of mine Thereby increasing the temperature required to provide heat for the endothermic cracking reaction. In accordance with the process herein, the hard solvent feed material is heated to < RTI ID = 0.0 > As combined with the heavy feedstock, the solvent to oil ratio in the initial solvent deasphalting / demetallization process is chosen to provide sufficient caulking of the catalyst to provide thermal balance during regeneration.

In one embodiment, a suitable fluid catalytic cracking unit 760 having a downflow reactor that can be used in the process described herein may be similar to that described in US Patent No. 6,656,346, and US Patent Publication No. 2002/0195373, The disclosure of which is incorporated herein by reference in its entirety. An important characteristic of the downflow reactor is that it provides a feed stream at the top of the reactor with a downward flow, a short residence time as compared to the riser reactor, and a high catalyst-to-mass ratio, for example within the range of about 20: 1 to about 30: Oil ratio. In general, operating conditions for suitable propylene production downflow fluid catalytic cracking units include:

Reaction temperature (° C) of about 550-650, 550-630, 550-620, 580-650, 580-630, 580-620, 590-650, 590-630, 590-620;

Reaction pressure (barg) of about 1-20, 1-10, or 1-3;

0.1 to 30, 0.1 to 10, 0.1 to 0.7, 0.2 to 30, 0.2 to 10, or 0.2 to 0.7 contact times (in the reactor, sec); And

To-feed ratio of from about 1: 1 to 40: 1, from 1: 1 to 30: 1, from 10: 1 to 30: 1, or from 10: 1 to 30: 1.

The catalysts used in the processes described herein may be any of the conventionally known or future developed catalysts used in the fluid catalytic cracking process, such as zeolites, silica-alumina, carbon monoxide combustion promoting additive, top cracking additive, light olefin- May be other catalyst additives routinely used in the catalytic cracking process. In certain embodiments, suitable cracked zeolites in a fluid catalytic cracking process include zeolites Y, REY, USY, and RE-USY. For improved naphtha cracking potential, a preferably shaped selective catalytic additive may be used, such as those used in fluid catalytic cracking processes to produce light olefins and increased fluid catalysed cracked gasoline octane, such as ZSM-5 zeolite crystals or other pentasil Type catalyst structure. This ZSM-5 additive can be mixed with the matrix structure in the cracking catalyst zeolite and the conventional fluid catalytic cracking catalyst and is particularly suitable for maximizing and optimizing the decomposition of the crude oil fraction in the downflow reaction zone.

Fluid catalytic cracking naphtha 706 is also recovered from high olefinic fluid catalytic cracking zone 700 . 12, 13 and 21, fluid catalytic cracked naphtha 706 is present in an effective amount of hydrogen obtained from recycle in naphtha hydrotreating zone 670 and supplemental hydrogen 674. In certain embodiments , The naphtha hydrotreating zone 670 , Within Is further processed. The effluent fuel gas is recovered and passed, for example, to the fuel gas system. In certain embodiments, all or a portion of the supplemental hydrogen 674 is derived from the hydrocracker hydrogen stream 210 from the olefin recovery train 270 .

The decomposed naphtha hydrotreating zone 670 operates under effective conditions to ensure virtually all nitrogen removal, since nitrogen is a limiting contaminant in aromatic extraction and subsequent processes. Because of the high temperature conditions effective for nitrogen removal, aromatic saturation occurs within the range of about 15% saturation prior to recovery. The effluent from the cracked naphtha hydrotreating zone 670 Hydrotreated hydrocracked naphtha stream 672 , and fuel gas.

Suitable decomposed naphtha hydrotreating zones 670 include, but are not limited to, Honeywell UOP, US; Chevron Lummus Global LLC (CLG), US; Or a system based on commercially available technology from Axens, IFP Group Technologies, FR.

The effluent from the cracked naphtha hydrotreating reactor generally contains C5-C9 + hydrocarbons. In certain embodiments of, the C5-C9 + hydrocarbons are passed into an aromatic extraction zone 620, an aromatic extraction zone 620 comprises a de-pentane Chemistry step for removing C5s. In other embodiments and as shown in Figures 12 and 13, the cracked naphtha hydrotreating zone 670 includes a despentanization step to remove C5s, which is directed to the mixed feed steam cracking zone 230 And is recycled as stream 676 . Hydrotreated hydrocracked naphtha stream 672 , generally containing C6-C9 + hydrocarbons, is passed to an aromatic extraction zone 620 .

The fluid catalytic cracked naphtha hydrotreating zone 670 may contain one or more fixed-bed, boiling-layer, slurry-bed, moving bed, continuous stirred tank (CSTR) or tubular reactor in series and / or parallel arrangement. Additional equipment, including exchangers, furnaces, feed pumps, quench pumps, and compressors, for supplying to the reactor (s) and maintaining proper operating conditions is well known and is well known in the art of fluid catalytic cracking naphtha hydrotreating zone 670 . Also included are equipment including pumps, compressors, high temperature separation vessels, low temperature separation vessels, etc., which separate the reaction products and provide hydrogen recycle in the fluid catalytic cracked naphtha hydrotreating zone 670 , Is considered to be part of the naphtha hydrotreating zone 670 .

The hydrocatalyzed naphtha hydrotreating zone 670 can be used to treat hydrocracked naphtha to produce a hydrotreated naphtha 672 that can be used as an additional feed to the aromatic extraction zone 620 for recovery of the BTX stream And is operated under the following effective conditions. In certain embodiments, the hydrotreated naphtha 672 may be used for fuel production.

In certain embodiments, the decomposed naphtha hydrotreating zone 670 operating conditions include the following:

Reactor inlet temperatures in the range of about 293-450, 293-410, 293-391, 332-450, 332-410, 332-391, 352-450, 352-410, 352-391 or 368-374 );

Reactor outlet temperatures in the range of about 316-482, 316-441, 316-420, 357-482, 357-441, 357-420, 378-482, 378-441, 378-420 or 396-404 );

Within the range of about 284-436, 284-398, 284-379, 322-436, 322-398, 322-379, 341-436, 341-398, 341-379 or 357-363, the weight average layer temperature (SOR) reaction temperature (C) as WABT;

Termination of execution as a WABT within the range of about 316-482, 316-441, 316-420, 357-482, 357-441, 357-420, 378-482, 378-441, 378-420 or 396-404 (EOR) reaction temperature (占 폚);

Reaction inlet pressure (barg) within the range of about 44-66, 44-60, 44-58, 49-66, 49-60, 49-58, 52-66, 52-60, 52-58 or 53-56 );

Reaction outlet pressure (barg) within the range of about 39-58, 39-53, 39-51, 43-58, 43-53, 43-51, 46-58, 46-53, or 46-51;

The hydrogen partial pressure (barg) (outlet) in the range of about 22-33, 22-30, 22-29, 25-33, 25-30, 25-29, 26-33, 26-30 or 26-29, ;

At most about 640, 620, 570 or 542, in certain embodiments about 413-620, 413-570, 413-542, 465-620, 465-570, 465-542, 491-620, 491-570, or 491- 542 < / RTI > hydrogen processing gas feed rate (SLt / Lt);

At most about 95, 85, 78 or 75, in certain embodiments at about 57-85, 57-78, 57-75, 64-85, 64-78, 64-75, 68-85, 75 hydrogen quench gas supply rate (SLt / Lt); And

At most about 120, 110, or 102, in certain embodiments about 78-120, 78-110, 78-102, 87-120, 87-110, 87-102, 92-120, 92-110, 92-102, Supplemental hydrogen feed rate (SLt / Lt) of 95-100.

An effective amount of a hydrotreating catalyst having hydrotreating functionality and containing at least one active metal component of a metal or metal compound (oxide or sulphide) selected from the Periodic Table of Elements IUPAC Groups 6-10 is the hydrocracking naphtha hydrogen Processing zone 670. < / RTI > In certain embodiments, the active metal component is at least one of Co, Ni, W, and Mo. The active metal component is typically deposited or otherwise embedded on a support, such as atypical alumina, amorphous silica alumina, zeolite, or a combination thereof. In certain embodiments, the catalyst used in the fluid catalytic cracked naphtha hydrotreating zone 670 comprises at least one catalyst selected from Co / Mo, Ni / Mo, Ni / W, and Co / Ni / Mo. A combination of at least one of Co / Mo, Ni / Mo, Ni / W and Co / Ni / Mo may also be used. The combination may consist of different particles containing a single active metal species, or particles containing a plurality of active species. In certain embodiments, a Co / Mo hydrodesulfurization catalyst is suitable. An effective liquid space velocity value (h ^-1 ) based on fresh feed relative to the hydrotreating catalyst is about 0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0, 0.5- 10.0, 0.5-5.0, 0.5-2.0, or 0.8-1.2. Suitable hydrotreating catalysts used in the fluid catalytic cracked naphtha hydrotreating zone 670 have an expected lifetime in the range of about 28-44, 34-44, 28-38 or 34-38 months.

The mixed feed steam cracking zone 230 , which operates as a high strength or low strength thermal cracking process, is generally formed by mixing LPG, naphtha and heavier hydrocarbons into a mixed product stream 220 containing C1-C4 paraffins and olefins Mainly convert. In certain embodiments, the mixed feed steam cracking zone 230 may be a unit of direct liquid from the crucible, propane (from outside the battery limits and / or recycled) and from the chemical production and recovery area in the integrated process and system. Process various recycle streams. Suitable mixed feed steam cracking zones 230 include, but are not limited to, Linde AG, DE; TechnipFMC plc, UK; Chicago Bridge & Iron Company NV (CB & I), NL; Or systems based on commercially available technology from KBR, Inc, US.

The plurality of feed to mixed feed steam cracking zone 230 includes the following: light ends from the crude complex 100 (152), light naphtha 138, and the heavy naphtha 140 (or other embodiments Full-range DC naphtha 136 as shown in FIG. An LPG stream 634 from the transalkylation reaction zone 630 ; A C3 + stream 716 recovered from the high olefinic fluid catalysis zone 700 ; A recycled stream 282 from methylacetylene / propadiene (MAPD) saturation and propylene recovery zone 280 as described below; C4 raffinate 524 from the 1-butene recovery zone 520 described below; A C5s stream 676 from a fluid catalytic cracked naphtha hydrotreating ("FCCN HT") zone 670 ; a C5s stream 606 from the py-gas hydrotreating zone 600 ; The wild naphtha 184 (via the crude complex in certain embodiments) from the diesel hydrotreating zone 180 described above; (Via the crude complex in certain embodiments) of the naphtha (wild naphtha 326 or hydrotreated naphtha 306 ) described above from the vacuum gas oil water addition zone described above; A raffinate stream 646 from the aromatic extraction zone 620 ; C5 cuts derived from the pyrolysis gasoline described below in certain embodiments; And optionally, propane stream 228 (from outside the battery limit). In certain embodiments, the mixed feed vapor decomposition zone 230 may allow feeds from other sources, such as other naphtha range feeds that may be available from outside the battery limit.

The product from the mixed feed steam cracking zone 230 is fed to the aromatic extraction zone 620 with a quenched cracked gas stream 220 containing mixed C1-C4 paraffins and olefins sent to the olefin recovery zone 270 , A raw pyrolysis gasoline stream 212 that is sent to the py-gas hydrotreating zone 600 to provide water 604 , and a pyrolysis fuel oil stream 218 .

Mix feed distillation zone 230 operates under parameters effective to decompose the feed into a desired product comprising ethylene, propylene, butadiene, and mixed butene. Pyrolysis gasoline and pyrolysis oil are also recovered. In certain embodiments, the steam cracking furnace (s) is operated under conditions effective to produce an effluent having a propylene-to-ethylene weight ratio of about 0.3-0.8, 0.3-0.6, 0.4-0.8, or 0.4-0.6.

The mixed feed steam cracking zone 230 generally comprises one or more furnace trains. For example, representative arrays include a well-known steam pyrolysis process, i.e., charging the thermal cracking feed to the convection section to raise the feed material temperature in the presence of steam, and heating the pyrolysis reactor containing the cracking furnace tube Lt; RTI ID = 0.0 > a < / RTI > In the convection section, the mixture is heated to a predetermined temperature using, for example, one or more waste heat streams or other suitable heating arrangement.

The feed mixture is heated to a high temperature in the convection section and the material having a boiling point below a predetermined temperature is vaporized. The heated mixture (with additional vapors in certain embodiments) is passed to a pyrolysis section operating at a shorter residence time, e.g., a further elevated temperature for less than one to two seconds, to effect pyrolysis to produce a mixed product stream do. For different inlet feeds to the mixed feed steam cracking zone 230 in certain embodiments, separate convection and radiation sections are used, each with optimized conditions for a particular feed.

In certain embodiments, steam cracking in mixed feed steam cracking zone 230 is performed using the following conditions: a convection section in the range of about 400-600, 400-550, 450-600, or 500-600 Internal temperature (캜); Pressure in convection section (barg) in the range of about 4.3-4.8, 4.3-4.45, 4.3-4.6, 4.45-4.8, 4.45-4.6 or 4.6-4.8; (° C) within the pyrolyzing section within the range of about 700-950, 700-900, 700-850, 750-950, 750-900, or 750-850; (Barg) in the pyrolysis section within the range of about 1.0-1.4, 1.0-1.25, 1.25-1.4, 1.0-1.15, 1.15-1.4, or 1.15-1.25; 0.5: 1-1.5: 1, 0.7: 1-2: 1, 0.7: 1-1.5: 1, 1: : Steam-to-hydrocarbon ratio in the convection section within the range of 1-2: 1 or 1: 1-1.5: 1; And residence time in seconds in the pyrolysis section within the range of about 0.05-1.2, 0.05-1, 0.1-1.2, 0.1-1, 0.2-1.2, 0.2-1, 0.5-1.2, or 0.5-1.

In operation of the mixed feed steam cracking zone 230 , the effluent from the cracking furnace is quenched, for example, using a transition line exchanger, and quenched in a quench tower. The hard product, the quenched cracked gas stream 220 , is sent to the olefin recovery zone 270 . Heavier products are separated in the hot distillation section. The raw pyrolysis gasoline stream is recovered in the quench system. The pyrolysis oil 218 is separated from the primary fractionator tower before the quench tower.

In operation of one embodiment of the mixed feed steam cracking zone 230 , the feed material is mixed with the dilution steam to reduce the hydrocarbon partial pressure and then preheated. The preheated feed is fed to a hollow tubular reactor mounted within the radiant section of the cracking furnace. Hydrocarbons undergo free-radical pyrolysis reactions to form light olefins, ethylene and propylene, and other by-products. In certain embodiments, dedicated decomposition furnaces are provided having optimized decomposition tube geometry for each of the major feedstock types, including ethane, propane, and butane / naphtha. Integrated systems and processes in the production of less valuable hydrocarbons, for example ethane, propane, C4 raffinate, and an aromatic raffinate is mixed feed steam cracking zone 230 of mine It is recycled to extinction.

In certain embodiments, the cracked gas from the furnace is cooled in a transition line exchanger (quench cooler) and produces an appropriate 1800 psig steam, for example, as a dilute vapor. The quenched cracked gas enters the primary fractionator connected to the mixed feed steam cracker 230 , which removes the pyrolysis fuel oil column bottoms from the lighter components. The primary fractionator enables effective recovery of pyrolysis fuel oil. The pyrolysis fuel oil is stripped with steam and cooled in a fuel oil stripper to control the product steam pressure. Secondary quenching is also performed by direct injection of the pyrolysis fuel oil as quench oil into the liquid furnace effluent. Stripped and cooled pyrolysis fuel oil may be sent to the fuel oil pool or product reservoir. A first fractionator overhead is sent to the quench tower; The concentrated dilution steam for the process water treatment, and the raw pyrolysis gasoline are recovered. The quench tower overhead is sent to the olefin recovery zone 270 , particularly the first compression stage. The raw pyrolysis gasoline is sent to the gasoline ballast to remove the light oil and control the steam pressure in downstream pyrolysis gasoline processing. Closed-loop dilution steam / process water systems are available in which dilute steam is generated using heat recovery from the primary fractionator quench pump air loop. The primary fractionator enables effective recovery of the pyrolysis fuel oil due to energy integration and pyrolysis fuel oil content in the hard fraction stream.

The combined product stream 220 effluent from the mixed feed vapor decomposition zone 230 is sent to the olefin recovery zone 270 . For example, the hard products C4-, H2 and H2S from the quench stage may be removed from the mixed product stream 220 , which is sent to the olefin recovery zone 270 , Within . The product includes: hydrogen 210 used for recycling and / or passed to the user; A fuel gas ( 208 ) passed through the fuel gas system; Ethane 272 recycled to the mixed feed steam cracking zone 230 ; Ethylene 202 recovered as product; A mixed C3 stream 286 passed through a methyl acetylene / propadiene saturation and propylene recovery zone 280 ; And a mixed C4 stream ( 206 ) that is passed to a butadiene extraction zone ( 500 ).

The olefin recovery zone 270 operates to produce standard light olefin (ethylene and propylene) products from the mixed product stream 220 . For example, the cooled gas intermediate product from the steam cracker is fed to a cracked gas compressor, a caustic wash zone, and one or more separation trains to separate the product by distillation. In a specific embodiment, two trains are provided. The distillation trains include a cryogenic distillation section where the lighter products such as methane, hydrogen, ethylene, and ethane are separated in the cryogenic distillation / separation operation. The mixed C2 stream from the steam cracker contains acetylene which is hydrogenated to produce ethylene in the acetylene selective hydrogenation unit. The system may also include ethylene, propane and / or propylene refrigeration facilities to enable cryogenic distillation.

In one embodiment, the combined product stream 220 effluent from the mixed feed steam cracking zone 230 is passed through three to five stages of compression. Acid gas is removed from the caustic wash tower with caustic. After the additional step of compression and drying, the hard cracked gas is cooled and sent to the depropanizer. In certain embodiments, the lightly cracked gas is cooled with a cascade 2-level refrigeration system (propylene, mixed binary refrigerant) for cryogenic separation. The front-end depropanizer optimizes cooling train and demethanizer loading. The depropanizer separates the C3 and the lighter cracked gas as an overhead stream, with C4s as the tower bottom stream and the heavier hydrocarbons. The depropanizer feedstock is sent to the debutanizer, which recovers the crude C4s stream 206 and the trace pyrolysis gasoline, which can be sent to the py-gas hydrotreating zone 600 (not shown).

The depropanizer overhead is passed through a series of acetylene conversion reactors and then fed to the demethanizer cooling train, which separates the hydrogen-rich product through a hydrogen purification system, such as pressure swing adsorption. Front-end acetylene hydrogenation is typically performed to optimize temperature control by removing the C2 splitter pasteurization section that is involved in product recovery, minimize green oil formation and simplify ethylene product recovery. In addition, hydrogen purification through pressure swing adsorption eliminates the need for methanation reactors, which are typically included in product recovery.

The demethanizer recovers methane in the overhead for the fuel gas, C2 in the demethanizer tower and the heavier gas are sent to the deethanizer. The deethanizer separates the ethane and ethylene overhead with a feed C2 splitter. The C2 splitter recovers the ethylene product 202 , in certain embodiments, the polymer-grade ethylene product in the overhead. Ethane 272 from the C2 splitter bottom is recycled to the mixed feed vapor decomposition zone 230 . The deethanizer feedstock is fed to propane 282 from a C3 splitter bottom which is recycled to the mixed feed steam cracking zone 230 Together , the propylene product 204 from it, in certain embodiments, the polymer-grade propylene product contains C3s recovered as an overhead of the C3 splitter.

Methane acetylene / propadiene (MAPD) saturation and propylene recovery zone 280 for selective hydrogenation to convert methyl acetylene / propadiene and recover propylene from mixed C3 stream 286 from olefin recovery zone 270 Is provided. Mixture C3 286 from the olefin recovery zone 270 contains significant amounts of propadiene and propylene. The methyl acetylene / propadiene saturation and propylene recovery zone 280 enables the production of propylene 204 , which may be polymer-grade propylene in certain embodiments.

Methyl acetylene / propadiene saturation and propylene recovery zone 280 receives hydrogen 284 and mixed C3 286 from olefin recovery zone 270 . The product from the methyl acetylene / propadiene saturation and propylene recovery zone 280 is the recovered propylene 204 and recycled C3 stream 282 sent to the steam cracking zone 230 . In certain embodiments, hydrogen 284 that saturates methyl acetylene and propadiene is derived from hydrogen 210 obtained from the olefin recovery zone 270 .

A stream 206 from the olefin recovery zone 270 containing a mixture of C4s known as crudes C4s is fed to a butadiene extraction zone (not shown ) to recover the high purity 1,3-butadiene product 502 from the mixed crud C4s 500 ). In certain embodiments (not shown), the hydrogenation step of the mixed C4 prior to the butadiene extraction zone 500 may be combined with an appropriate catalytic hydrogenation process using, for example, a fixed bed reactor to remove the acetylenic compound. 1,3-butadiene 502 is recovered from the hydrogenated mixed C4 stream by, for example, active distillation using n-methyl-pyrrolidone (NMP) or dimethylformamide (DMF) as solvent. The butadiene extraction zone 500 also produces a raffinate stream 504 containing butane / butene, which is passed through a methyl tertiary butyl ether zone 510 .

In one embodiment, in operation of the butadiene extraction zone 500 , stream 206 is preheated and vaporized into a first and active distillation column, e.g., having two sections. An NMP or DMF solvent separates 1,3-butadiene from other C4 components contained in stream 504 . The rich solvent is flushed with steam into the second and active distillation column to produce a high purity 1,3 butadiene stream as an overhead product. The liquid solvent from the flash and the second distillation column column bottoms are sent to the first solvent recovery column. The bottom liquid is circulated back to the extractor and the overhead liquid is passed to a second solvent recovery or solvent polishing column. The vapor overhead from the recovery column is combined with the recycled butadiene product to the extractor column to increase the 1,3-butadiene concentration. The 1,3-butadiene product 502 may be washed water to remove trace solvents. In certain embodiments, the product purity (wt%) is 97-99.8, 97.5-99.7 or the 1,3- butadiene of the feed 98-99.6 and the 1,3- butadiene 94-99, 94.5-98.5, or 95-98, Butadiene content (wt%) is recovered. In addition to the solvent, such as DMF, the additive chemistry is blended with the solvent to increase the butadiene recovery. In addition, the active distillation column and the primary solvent recovery column are boiled again using circulating hot oil from high pressure steam (e.g., 600 psig) and aromatic extraction zone 620 as a heat exchange fluid.

The methyl tertiary butyl ether zone 510 is incorporated to produce the methyl tertiary butyl ether 514 and the second C4 raffinate 516 from the first C4 raffinate stream 504 . In certain embodiments, C4 raffinate 1 ( 504 ) is treated with selective hydrogenation to selectively hydrogenate the remaining diene prior to reacting isobutene with methanol to produce the methyl tertiary butyl ether.

The purity specification for recovery of the 1-butene product stream 522 requires that the level of isobutylene in the second C4 raffinate 516 be reduced. Generally, a first C4 raffinate stream 504 containing mixed butane and butene and containing isobutylene is passed through the methyl tertiary butyl ether zone 510. [ Methanol 512 is also added, which reacts with isobutylene and produces methyl tertiary butyl ether ( 514 ). For example, the methyl tertiary butyl ether product and methanol are separated in a series of fractionators and sent to a second reaction stage. The methanol is removed by washing with water and a final fractionation step. The recovered methanol is recycled to the fixed bed downflow dehydrogenation reactor. In the specific embodiment described below with respect to Figure 24, for example, the additional isobutylene derived from the metathesis conversion unit is converted to the methyl tertiary butyl ether zone < RTI ID = 0.0 > 510 & Can be introduced.

In one embodiment of the methyl tertiary butyl ether zone 510 , the raffinate stream 504 contains 35-45%, 37-42.5%, 38-41%, or 39-40% isobutylene by weight . This component is removed from C4 raffinate 516 to form the 1-butene product stream 522 from C4 distillation unit 520 about For example, a purity specification of 98 wt% or more is obtained. Methanol 512 , high purity methanol having a purity level above 98 wt% from the outside of the battery limit in certain embodiments, and isobutylene contained in the raffinate stream 504 , and isobutylene contained in the raffinate stream 504 , Butylene 544 (shown in dashed lines as an optional feed) reacts in the first reactor. In certain embodiments, the first reactor is a fixed-bed downflow dehydrogenation reactor and is provided with a reforming reactor for conversion of isobutylene in the range of about 70-95%, 75-95%, 85-95%, or 90-95% Lt; / RTI > The effluent from the primary reactor is sent to the reaction column where the reaction is complete. In certain embodiments, the pyrogenic heat of the reaction column and the primary reactor may optionally be used to supplement the column reboiler with the provided steam. The reaction column column bottoms contain methyl tertiary butyl ether, trace amounts, for example, less than 2% unreacted methanol, and the heavier products produced in the primary and reaction columns. The reaction column overhead contains unreacted methanol and non-reactive C4 raffinate. This stream was washed with water to remove unreacted methanol and recycled as C4 raffinate ( 516 ) And is passed to the 1-butene recovery zone 520 . The recovered methanol is removed from the wash water in the methanol recovery column and recycled to the primary reactor.

The C4 raffinate stream 516 from the methyl tertiary butyl ether zone 510 is passed to a butene-one time C4 distillation unit 520 . In certain embodiments, the upstream zone of the methyl tertiary butyl ether (510), or methyl tertiary butyl ether zone 510 and between butene-1 recovery separation zone 520, a selective hydrogenation zone can also be included (Not shown). For example, in certain embodiments, the raffinate from the methyl tertiary butyl ether zone ( 510 ) is selectively hydrogenated in a selective hydrogenation unit to produce butene-1. Other co-monomers and paraffins are also co-produced. The selective hydrogenation zone is operated in the presence of an effective amount of hydrogen and complementary hydrogen obtained from recycling in a selective hydrogenation zone; In certain embodiments, all or a portion of the supplemental hydrogen for the selective hydrogenation zone is derived from the hydrocracker hydrogen stream 210 from the olefin recovery train 270 . For example, suitable selective hydrogenation zones include, but are not limited to, Axens, IFP Group Technologies, FR; Haldor Topsoe A / S, DK; Clariant International Ltd, CH; Chicago Bridge & Iron Company NV (CB & I), NL; Honeywell UOP, US; Or systems based on commercially available technology from Shell Global Solutions, US.

For selective recovery of the recycle stream 524 sent to the 1-butene product stream 522 and the mixed feed vapor decomposition zone 230 and / or sent to the metathesis zone in certain embodiments described herein, one or more A separation step is used. For example, 1-butene can be recovered using two separation columns, wherein the first column recovers the olefin from the paraffin and the second column separates the 1-butene from the mixture comprising 2-butene, Blended with paraffin from the first column and recycled as recycle stream 524 It is recycled as a steam cracker.

In a particular embodiment, the C4 raffinate stream 516 from the methyl tertiary butyl ether zone 510 is passed to a first splitter from which the isobutane, 1-butene, and n-butane, . Isobutane, 1-butene, and n-butane are recovered as an overhead, concentrated in an air cooler, and sent to a second splitter. The bottoms stream from the first splitter contains mainly cis- and trans-2-butene and may be added to the recycle stream 524 , or may be passed to the metathesis unit in certain embodiments described herein. In a particular arrangement, the first splitter overhead enters the mid-point of the second splitter. The isobutane product 526 may optionally be recovered at overhead (shown in dashed lines), the 1-butene product 522 is recovered as a side cut, and n-butane is recovered as the bottoms stream. The bottoms from both of the splitters are recovered as all or part of the recycle stream 524 .

The raw pyrolysis gasoline stream 212 from the steam cracker is treated and separated into treated naphtha and other fractions. In certain embodiments, substantially all, or substantially all, of the pyrolysis gasoline 212 from the steam cracking zone 230 is passed to the py-gas hydrotreating zone 600 . The raw pyrolysis gasoline stream 212 is processed in the py-gas hydrotreating zone 600 in the presence of an effective amount of hydrogen and supplemental hydrogen 602 obtained from recycling obtained from recycling. The effluent fuel gas is recovered and passed, for example, to the fuel gas system. In certain embodiments, all or a portion of the supplemental hydrogen 602 is derived from the steam cracking hydrogen stream 210 from the olefin recovery train 270 . For example, suitable py-gas hydrotreating zones 600 include, but are not limited to, Honeywell UOP, US; Chevron Lummus Global LLC (CLG), US; Axens, IFP Group Technologies, FR; Haldor Topsoe A / S, DK; Or a system based on technology commercially available from Chicago Bridge & Iron Company NV (CB & I), NL.

The Py-gas hydrotreating zone 600 is operated under conditions that can vary over a relatively wide range and utilizes the catalyst (s). These conditions and the catalyst (s) are selected for effective hydrogenation for saturation of certain olefinic and diolefinic compounds and, if necessary, hydrotreating to remove sulfur and / or nitrogen containing compounds. In certain embodiments, this is carried out in at least two catalytic stages, although other reactor configurations may be used. The py-gas hydrotreating zone 600 thus hydrogenates the pyrolysis gasoline stream 212 to produce an effluent pyrolysis gasoline 604 as feed to the aromatic extraction zone 620 . The off-gas is recovered from the py-gas hydrotreating zone 600 and passed to the olefin recovery train, the saturated gas plant as part of another gas stream 156 , and / or the direct fuel gas system. The liquefied petroleum gas can be recovered from the py-gas hydrotreating zone 600 and sent to the mixed feed steam cracking zone, the olefin recovery train and / or the saturated gas plant.

In the py-gas hydrotreating zone 600 , the diolefin in the feed and the olefin in the C6 + portion of the feed are saturated to produce feed to the naphtha stream ( 604 ), C5 + aromatic extraction zone. In certain embodiments, the de-pentanizing step, coupled with the py-gas hydrotreating zone 600 , is carried out, for example, to the mixed feed steam cracking zone 230 Separates all or a portion of C5s as a feed to additional feed 606 and / or to metathesis unit 530 (e.g., as shown in Figures 6, 8, or 24). In another embodiment, the de-pentanizing step connected to the aromatic extraction zone 620 can be carried out, for example, as an additional feed to the mixed feed steam cracking zone 230 and / or as a feed to the meteolysis unit 530 All or part of the hydrotreated naphtha stream 604 from C5s is separated.

In certain embodiments, pyrolysis gasoline is processed in a first reaction step for hydrogenation and stabilization. The diolefins are selectively saturated in the first reaction step and the remaining olefins are saturated in the second reaction step, converting the feed sulfur to hydrogen sulfide. The pyrolysis gasoline can be treated in a low temperature hydrogen treatment unit, thus reducing the level of aromatic saturation.

In an effective py-gas hydrotreating zone 600 In the example, the raw pyrolysis gasoline passes through the core liner before entering the feed surge drum. The first stage reactor operates in a mixed phase and selectively hydrogenates the diolefin to the mono-olefin and the unsaturated aromatic to the branched saturated aromatic. Pd-based catalyst materials are effective. In a particular embodiment, a two-parallel, first-stage reactor may be used that allows continuous process regeneration without interruption. In certain embodiments, the first-stage reactor contains three catalyst beds and the cooled first-stage separator liquid is recycled as a quench substance between the respective layers. The first-stage effluent is stabilized and separated in a column operating under a weak vacuum to reduce the temperature. In certain embodiments, C5 is exited from C6 +, followed by removal of C9 + and treatment with a deoxygenation group to produce a C6-C8 heart napta cut. The column operates under a weak vacuum to limit the critical temperature. A first step the product is stripped to remove hydrogen, H ₂ S, and other light ends. In certain embodiments, the stripped first-step product is depalptated to remove C5, for example, decomposed as a feed to the metathesis unit. The second stage reactor operates in a vapor phase to remove the sulfur and saturate the olefins. Step 2 The product is stripped to remove hydrogen, H ₂ S, and other light ends. In certain embodiments, both reactors are multi-layer and use product recycling to control the reactor temperature increase.

In certain embodiments, the py-gas hydrotreating zone 600 first reaction stage operating conditions include:

The inlet temperature of the reactor in the range of about 80-135, 80-125, 80-115, 95-135, 95-125, 95-115, 100-135, 100-125, 100-115 or 107-111 );

The reactor outlet temperature in the range of about 145-230, 145-206, 145-200, 165-230, 165-206, 165-200, 175-230, 175-206, 175-200 or 184-188 );

Within the range of about 75-125, 75-115, 75-110, 90-125, 90-115, 90-110, 95-125, 95-115, 95-110 or 99-104, (SOR) reaction temperature (C) as WABT;

Termination of execution as a WABT within the range of about 124-195, 124-180, 124-170, 140-195, 140-180, 140-170, 150-195, 150-180, 150-170 or 158-163 (EOR) reaction temperature (占 폚);

Reaction inlet pressure (barg) in the range of about 25-40, 25-35, 25-33, 28-40, 28-35, 28-33, 30-40, 30-35 or 30-33;

Reaction outlet pressure (barg) within the range of about 23-35, 23-33, 23-31, 25-35, 25-33, 25-31, 28-35, 28-33 or -28-31;

Hydrogen partial pressure (barg) (outlet) within the range of about 15-25, 15-22, 15-21, 18-25, 18-22, 18-21, 19-25 or 19-22;

At most about 180, 165 or 156, in certain embodiments at least about 120-180, 120-165, 120-156, 134-180, 134-165, 134-156, 140-180, 140-165 or 140-156 Hydrogen processing gas supply rate (SLt / Lt);

At most about 0.8, 0.7, 0.6, or 0.5, and within a range of about 0.35-0.6, 0.35-0.55, 0.35-0.5, 0.4-0.6, 0.4-0.55, 0.4-0.5, 0.45-0.6, Liquid quench feed ratios of 0.45-0.55 or 0.45-0.5 (Lt quench / Lt feed); And

34-47, 34-45, 40-55, 40-47, 40-45, 42-55, 42-47, or 42-47 in certain embodiments, up to about 60, 55, 45 supplemental hydrogen feed rate (SLt / Lt).

In certain embodiments, the py-gas hydrotreating zone 600 second reaction stage operating conditions include the following:

Reactor inlet temperatures in the range of about 225-350, 225-318, 225-303, 255-350, 255-318, 255-303, 270-350, 270-318, 270-303 or 285-291 );

Reactor outlet temperatures within the range of about 289-445, 289-405, 289-386, 328-445, 328-405, 328-386, 345-445, 345-405, 345-386 or 364-370 );

Within the range of about 217-336, 217-306, 217-291, 245-336, 245-306, 245-291, 260-336, 260-306, 260-291 or 274-280, the weight average layer temperature (SOR) reaction temperature (C) as WABT;

Termination of execution as a WABT within the range of about 325-416, 325-380, 325-362, 305-416, 305-380, 305-362, 325-416, 325-380, 325-362 or 340-346 (EOR) reaction temperature (占 폚);

Reaction inlet pressure (barg) in the range of about 25-37, 25-34, 25-32, 28-37, 28-34, 28-32, 29-37, 29-34 or 29-32;

Reaction exit pressure (barg) in the range of about 23-35, 23-32, 23-30, 26-35, 26-32, 26-30, 28-35, 28-32, or 28-30;

Hydrogen partial pressure (barg) (outlet) in the range of about 6-10, 6-9, 7-10 or 7-9;

At least about 135, 126, 116, or 110 in certain embodiments, about 84-126, 84-116, 84-110, 95-126, 95-116, 95-110, 100-126, 100-116, A hydrotreating gas feed rate (SLt / Lt) of 110; And

At most about 30, 27 or 24, in certain embodiments about 18-30, 18-27, 18-24, 21-30, 21-27, 21-24, 22-30, 22-27 or 22-24 Supplementary hydrogen feed rate (SLt / Lt).

An effective amount of a catalyst having selective hydrogenation functionality is provided which generally contains at least one active metal component metal or metal compound (oxide or sulfide) selected from Co, Mo, Pt, Pd, Fe, or Ni. The active metal component is typically deposited or otherwise embedded on a support, such as atypical alumina, amorphous silica alumina, zeolite, or a combination thereof. Exemplary selective hydrogenation catalysts mainly use Pd as an active metal component on an alumina support, including those commercially available under the trademarks Olemax ^® 600 and Olemax ^® 601. The effective liquid space velocity value (h ^-1 ) based on the fresh feed relative to the first stage pyrolysis gasoline reactor catalyst is about 0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3- 2.0, 0.5-10.0, 0.5-5.0, 0.5-2.0, or 0.9-1.44. Suitable catalysts used in the first stage pyrolysis gasoline reactor have an expected lifetime in the range of about 18-30, 22-30, 18-26 or 22-26 months.

An effective amount of a second-stage pyrolysis gasoline reactor catalyst is provided that has hydrogenation functionality and generally contains at least one active metal component of a metal or metal compound (oxide or sulfide) selected from the Elements Periodic Table IUPAC Groups 6-10 . In certain embodiments, the active metal component is at least one of Co, Ni, W, and Mo. The active metal component is typically deposited or otherwise embedded on a support, such as atypical alumina, amorphous silica alumina, zeolite, or a combination thereof. In certain embodiments, the catalyst used in the first stage pyrolysis gasoline reactor comprises at least one catalyst selected from Co / Mo, Ni / Mo, Ni / W, and Co / Ni / Mo. A combination of at least one of Co / Mo, Ni / Mo, Ni / W and Co / Ni / Mo may also be used. For example, a combination of a commercially available catalyst particles under the trademark Olemax ^® 806 and Olemax ^® 807 having an active metal components of Co and Ni / Mo may be used. The combination may consist of different particles containing a single active metal species, or particles containing a plurality of active species. The effective liquid space velocity value (h ^-1 ) based on the fresh feed relative to the first stage pyrolysis gasoline reactor catalyst is about 0.1-10.0, 0.1-5.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3- 2.0, 0.5-10.0, 0.5-5.0, 0.5-2.0, or 0.8-1.2. Suitable catalysts used in the second stage pyrolysis gasoline reactor have an expected lifetime in the range of about 18-30, 22-30, 18-26 or 22-26 months.

All or a portion of the hydrotreated pyrolysis gasoline 604 , the hydrotreated hydrocatalytic cracked naphtha 672 , and the chemical rich reformate stream 426 are sent to the aromatic extraction zone 620 . As noted above, the chemical-rich reformate stream 426 May be used in various amounts as feed to the aromatic extraction zone 620 . In certain embodiments, all, substantial, or substantial portions of the hydrotreated pyrolysis gasoline 604 are passed to the aromatic extraction zone 620 to maximize the production of petrochemicals. In an operating mode where the production of gasoline is intended, a portion of the hydrotreated pyrolysis gasoline 604 is passed to a gasoline pool (not shown).

The aromatic extraction zone 620 includes, for example, one or more overactive distillation units and operates to separate the hydrotreated pyrolysis gasoline and the fluid catalyzed naphtha into high-purity benzene, toluene, xylene, and C9 aromatics. As shown in Figure 21, the benzene stream 624, a mixed xylene stream 626 and raffinate stream 646 is recovered from the aromatic extraction zone 620, the raffinate stream 646 is additionally supplied water To the mixed feed steam cracking zone 230 . The toluene stream 636 is also fed to the toluene and C9 + alkyl exchange reaction zone 630 for the production of additional benzene and xylene from the aromatic extraction zone 620 And into the aromatic extraction zone 620 And is recycled as stream 640 . In certain embodiments ethylbenzene can be recovered (not shown). The heavy aromatics 642 are also recovered from the aromatic extraction zone 620 .

In certain embodiments of the operation of the aromatic extraction zone 620 , the aromatics are separated from the feed by over-active distillation using, for example, n-formylmorpholine (NFM) as the active solvent. Benzene, toluene, mixed xylene and C9 + aromatics are separated by distillation. Benzene and mixed xylenes are recovered as product streams 624 and 626 and toluene 636 and C9 + aromatics 638 are sent to toluene and C9 + transalkylation reaction zone 630 . The transalkylation reaction zone product stream 640 contains benzene and the mixed xylene is returned to recover the aromatic extraction zone 620 section. The paraffinic raffinate stream 646 is recycled as a feed to the mixed feed steam cracking zone 230 . In certain embodiments, the paraffinic raffinate stream 646 is in direct fluid communication with the mixed feed steam cracking zone 230 , i.e., the stream is not further treated with a catalyst process prior to the steam cracking step.

The choice of solvent, the operating conditions, and the mechanism of contacting the solvent and feed allow control over the level of aromatic extraction. For example, suitable solvents include n-formylmorpholine, perfural, N-methyl-2-pyrrolidone, dimethylformamide, dimethylsulfoxide, phenol, nitrobenzene, sulfolane, acetonitrile, In a solvent to oil ratio of about 20: 1, in certain embodiments up to about 4: 1, and in a further embodiment up to about 2: 1. Suitable glycols include diethylene glycol, ethylene glycol, triethylene glycol, tetraethylene glycol and dipropylene glycol. The extraction solvent may be a pure glycol or a glycol diluted with about 2-10 wt% water. Suitable sulfolanes include, but are not limited to, hydrocarbon-substituted sulfolanes (e.g., 3-methylsulfolane), hydroxysulfolanes (such as 3-sulfolanol and 3-methyl- Ethers (e.g., methyl-3-sulfanyl ether), and sulforanyl esters (e.g., 3-sulforanyl acetate).

The aromatics separator can operate at temperatures in the range of about 40-200, 40-150, 60-200, 60-150, 86-200, or 80-150 degrees Celsius. The operating pressure of the aromatic separator can be in the range of about 1-20, 1-16, 3-20, 3-16, 5-20 or 5-16 barg. A type of apparatus useful as an aromatic separation apparatus in certain embodiments of the systems and processes described herein comprises an active distillation column.

In one embodiment of the operation of the aromatic extraction zone 620 , the feed mainly contains the C6 + component and is fractionated into the "heart cut" of the C6-C8, heavy C9 + fraction. The C6-C8 cut is sent to the active distillation system where the aromatics are separated from non-aromatic (saturated) by solvent distillation. The raffinate (non-aromatic) from C6-C8 is removed and recycled back to the decomposition complex as feed material. The aromatics are soluble in the solvent and are transported from the bottom of the active distillation column to a solvent stripper where they are stripped from the solvent to produce aromatic extraction and tributary solvents which are recycled back into the active distillation column. Mixed aromatic extraction is carried out in a series of fractionated columns (benzene column, toluene column and xylene column), where each aromatic species is separated into a mixture of benzene stream 624 and mixed xylene stream 626 , And is continuously removed. The heavy C9 + fraction is further separated into C9 and C10 + materials. Toluene and C9 product are sent to toluene and C9 + alkyl exchange reaction zone 630 where they react to form additional benzene and mixed xylene. This stream is recycled back to the fractional portion of the aromatic extraction zone 620 to recover benzene and mixed xylenes and also to recycle non-converted toluene and C9 aromatics. The transalkylation effluent does not require re-extraction in the solvent distillation section and is therefore sent to the benzene column inlet. In certain embodiments, the toluene may be recycled until it disappears, or nearly extinguishes. C10 and heavier aromatics are removed as product 642. [ In certain embodiments, ethylbenzene can be recovered.

The toluene and C9 + alkyl exchange reaction zone 630 is a mixed stream 640 containing benzene, mixed xylene and heavy aromatics, Into Toluene and C9 + aromatic disproportionation. The product ratio of benzene and xylene can be adjusted by the choice of catalyst, feed material and operating conditions. The alkyl exchange reaction zone 630 receives the toluene stream 636 and the C9 + aromatic stream 638 from the aromatic extraction zone 620 as a feed. In a particular embodiment, a small amount of hydrogen 632 , all or part of which is derived from the hydrogen stream 210 derived from the partial olefin recovery zone 270 , Is supplied for the transalkylation reaction. For example, a side cracking reaction occurs that produces a LPG stream 634 that is recycled to the fuel gas stream that is passed to the fuel gas system and to the mixed feed steam cracking zone. A small amount, for example 0.5-3 wt%, of the total feed to the aromatic extraction of the heavy aromatics is produced due to the condensation reaction and is passed to the mixed stream 640 to be recovered using the other heavy aromatics.

In an operation of one embodiment of the toluene and C9 + alkyl exchange reaction zone 630 , toluene and C9 aromatics react with hydrogen under mild conditions to form a mixture of C6-C11 aromatics. The mixed aromatic product stream 640 is recycled back to the aromatic extraction zone 620 where benzene and mixed xylene are recovered as product. The C7 and C9 aromatics are recycled back as feed to the transalkylation reaction zone 630 and the C10 + fraction is recycled as a heavy aromatic stream 642 Is removed from the aromatic extraction zone 620 . The disproportionation reaction takes place in the presence of an effective amount of hydrogen. The minimum amount of hydrogen is consumed by the decomposition reaction under reactor conditions. The purge gas is recycled back to the decomposition complex for component recovery.

In certain embodiments, the pyrolysis oil streams 236 and 256 may be blended into the fuel oil pool as low sulfur components and / or used as a carbon black feed material. In an additional embodiment, one or both of pyrolysis oil streams 236 and 256 may be separated into hard pyrolysis oil and heavy pyrolysis oil (not shown). For example, a hard pyrolysis oil may be blended with one or more of the intermediate distillate streams so that 0-100% hard pyrolysis oil from either or both pyrolysis oil streams 236 and ( 256 ) / RTI > and / or mixed feed steam cracking zone 230 to produce an additional feed. In another embodiment, 0-100% hard pyrolysis oil derived from one or both of the pyrolysis oil streams 236 , 256 may be processed in a vacuum gas oil water addition room. In certain embodiments, all, substantial, substantial, or major portions of the hard pyrolysis oil may be passed through either or both of the diesel hydrotreating zone 180 and / or the vacuum gas oil water addition room; The remainder may be blended into the fuel oil pool. The heavy pyrolysis oil can be blended into the fuel oil pool as a low sulfur component, and / or used as a carbon black feed material. In a further embodiment, stream 236, 256 of one or both the thermal cracking of light 0-100% derived from the oil and / or 0 to 100% of the heavy pyrolysis oil pyrolysis oil is arbitrary residue treatment zone (800 ). ≪ / RTI > In certain embodiments, all, substantial, substantial or major portions of the pyrolysis oil streams 236 , 256 (hard and heavy) may be processed in the optional residue treatment zone 800 .

FIG. 24 illustrates a modification to any of the processes described above, including the incorporation of a metrology unit 530 . For example, suitable metathesis zones 530 may include, but are not limited to, systems based on commercially available technology from the Chicago Bridge & Iron Company NV (CB & I), NL.

The feed to metathesis unit 530 includes: a portion 536 of the ethylene mixed feed steam cracking product; A C4 raffinate 3 stream 532 from a C4 distillation unit 520 , and an olefinic C5 cut 606 from a py-gas hydrotreating zone 600 . C4 raffinate-3 stream 532 is 0-100% of total C4 raffinate-3 from 1-butene recovery zone 520 ; The remaining portion 524 may be recycled into the mixed feed vapor decomposition zone 230 . The metathesis unit 530 from the product contains propylene 534 and stream 542 and has a nearly saturated mixture of C4 / C5 from the metathesis unit recycled to the mixed feed vapor cracking zone. In certain embodiments, isobutylene 544 may also be recovered (shown in dashed lines) and sent to the methyl tertiary butyl ether zone 510 . In embodiments that operate without separation of isobutylene, this is included in stream 542. [

25 shows an embodiment in which a raw pyrolysis gasoline stream 212 from a fluid catalytic cracked naphtha 706 and a steam cracker are combined and processed in a naphtha hydrotreating zone 610. [ The naphtha hydrotreating zone 610 operates in the presence of an effective amount of hydrogen and supplemental hydrogen 680 obtained from recycling in the naphtha hydrotreating zone 610 . In certain embodiments, all or a portion of the supplemental hydrogen 680 is derived from the steam cracker hydrogen stream 210 from the olefin recovery train 270 . The effluent fuel gas is recovered and passed, for example, to the fuel gas system.

The effluent from the cracked naphtha hydrotreating reactor generally contains C5-C9 + hydrocarbons. In certain embodiments of, the C5-C9 + hydrocarbons are passed into an aromatic extraction zone 620, an aromatic extraction zone 620 comprises a de-pentane Chemistry step for removing C5s. 25, the naphtha hydrotreating zone 610 includes a despentanization step for removing C5s, which includes a stream 644 to a mixed feed steam cracking zone 230 , . The hydrotreated mixed naphtha stream 678 , generally containing C6-C9 + hydrocarbons, is passed to the aromatic extraction zone 620 . The process of FIG. 25 operates in accordance with any of the descriptions for FIGS. 12, 13 and 21, or any other embodiment, in all other aspects.

Figure 26 shows an embodiment in which kerosene desulphurisation is within an optional unit, i.e., the first intermediate distillate fraction 118 can be sent through the kerosene desulfurization zone 170 or sent to the distillate hydrotreating zone 180 Respectively. The process of FIG. 27 operates in accordance with any of the descriptions of FIGS. 12, 13 and 21, or any of the other embodiments herein, in all other aspects.

During the period when kerosene fuel 172 is desired to be maximized, first intermediate distillate fraction 118 may be sent to kerosene desulfurization zone 170 . During the period during which the feed to the mixed feed vaporization zone 230 is maximized, the first intermediate distillate fraction 118 is fed to the distillate hydrotreating zone 180 to produce additional hydrotreated naphtha 184 Can be sent. In an additional alternative embodiment, the first intermediate distillate fraction 118 can be separated (e.g., by diverting to volume or weight basis) so that a portion is passed to the distillate hydrotreating zone 180 and the remaining Is passed to the kerosene desulfurization zone 170 .

Fig. 27 shows a specific example in which kerosene desulfurization is removed. Thus, in the embodiment of FIG. 27, two intermediate distillate fractions are used. In this embodiment, the first middle distillate fraction 124 is sent to the distillate hydrotreating zone 180 and the second middle distillate fraction 134 is sent to the third intermediate distillate Fraction 126. < / RTI > 27, the first middle distillate fraction 124 contains kerosene range hydrocarbons and intermediate AGO range hydrocarbons, and the second atmospheric distillation zone middle distillate fraction 134 contains the heavy AGO range < RTI ID = 0.0 > Contains hydrocarbons. 27, the first middle distillate fraction 124 contains kerosene range hydrocarbons, and a portion of the intermediate AGO range hydrocarbons and the second middle distillate fraction 134 is the intermediate AGO range hydrocarbons And some of the heavy AGO range hydrocarbons. The process of FIG. 27 operates in accordance with any of the descriptions of FIGS. 9 and 11, or any of the other embodiments herein, in all other aspects.

Advantageously, the process dynamics of the construction and integration of the unit and stream obtain a very high level of integration of the feed streams between the mixed feed steam cracking and other process units, resulting in increased efficiency and reduced overall operating costs. For example, hydrogen can be tightly integrated so that net hydrogen demand from outside the battery limits is minimized or even eliminated. In certain embodiments, the overall hydrogen utilization from outside the battery limits is less than about 40, 30, 15, 10, or 5 wt% hydrogen based on the total hydrogen required by the hydrogen user in the consolidation process. Hydrogen recovery from olefin recovery trains and chemical reformers, diesel hydrogenation, gas oil hydrogenation or hydrocracking, py-gas hydrogenation, hydrocatalytic cracked naphtha hydrogenation And a hydrogen exchange system. In certain embodiments, there is no use of external hydrogen and only supplemental hydrogen is required to initiate operation, so that when the reaction reaches equilibrium, the hydrogen derived from the mixed feed steam cracking product is released to the hydrogen user It provides enough hydrogen to sustain hydrogen demand. In a further embodiment, there is a net hydrogen increase, so that hydrogen can be added to the fuel gas used, for example, to operate the various heating units in the integrated process.

The integrated process described herein also provides a useful outlet for off-gas and light oil from the water addition unit. For example, the crude stream 156 is passed to a saturated gas plant 150 DE composite 100 is added ball unit, for example, from a diesel hydrotreating zone 180, a gas oil hydrotreating zone 300, and / Or off-gas and light oil from the py-gas hydrotreating zone 600 . In other embodiments, all or part of these may be sent to the mixed feed steam cracking unit 230 in combination with or instead of passing these off-gas and light oil fractions through stream 156 . For example, C2s can be separated from a mixture of methane, hydrogen and C2s using a cryogenic distillation / separation operation including a cryogenic distillation section ("low temperature box"), which includes a mixed feed steam cracking unit 230 , The gas plant 150 and / or the olefin recovery zone 270 , Of which It can be integrated with one or all. Methane and hydrogen may be introduced into the fuel gas system or the olefin recovery zone 270 May be passed to an appropriate section, such as a hydrogen purification system. In still further embodiments, all or part of the off-gas and light oil may be passed through the olefin recovery zone 230 in combination with, or instead of, passing the off-gas and light oil through stream 156 and / then 270 appropriate section, for example in combination with or may be sent to de-propane group, group or propane overhead of de-gas.

The embodiments described herein have the ability to achieve a crude to chemical conversion ratio, for example, in the range of up to 80, 50, or 45 wt%, and in certain embodiments in the range of about 39-45 wt% to provide. In certain embodiments, the chemical conversion ratio is in the range of at least about 39 wt%, and in certain embodiments in the range of about 39-80, 39-50, or 39-45 wt%. It is to be understood that this crude to chemical conversion ratio can vary depending on the criteria, for example, the feed, the selected technique, the catalyst selection and the operating conditions for individual unit operation.

In some embodiments, the individual unit operation may include a controller for monitoring and adjusting a given product slate. The controller directs the parameters in any of the individual units directly and operates the device according to certain operating conditions that may be based on, for example, consumer demand and / or market value. The controller may adjust or adjust a valve, a feeder, or a pump connected to one or more unit operations in accordance with one or more signals generated by operator data input and / or automatically extracted data.

Such a controller can provide a versatile unit having multiple operating modes and respond to multiple inputs to increase recovered product flexibility. The controller may be implemented using one or more computer systems, which may be, for example, a general-purpose computer. Alternatively, the computer system may include a special-programmed, special-purpose hardware, for example, an application-specific integrated circuit (ASIC) or controller intended for operation of a particular unit within the organism.

A computer system may typically include one or more processors coupled to one or more memory devices, which may include, for example, one or more of a disk drive memory, a flash memory device, a RAM memory device, or other device for storing data have. The memory is typically used to store programs and data during operation of the system. For example, the memory may be used to store historical data for parameters over time, as well as operational data. Software including programming code for implementing embodiments of the present invention may be stored on a computer readable and / or writable non-volatile recording medium, and thereafter may be typically copied into a memory and executed thereafter by one or more processors . Such programming code may be written in any of a plurality of programming languages or a combination thereof.

Components of a computer system may be coupled by one or more interconnection mechanisms, which may include, for example, one or more buses between components that are integrated within the same device, and / Network. The interconnection mechanism typically enables communications, e.g., data and instructions, to be exchanged between system components.

The computer system also includes one or more input devices, such as a keyboard, a mouse, a trackball, a microphone, a touch screen and other person-machine interface devices, and also one or more output devices such as a printing device, can do. A computer system may also include one or more interfaces that may connect the computer system to a communication network in addition to or instead of a network that may be formed by one or more of the components of the system.

According to one or more embodiments of the process described herein, the one or more input devices may include sensors and / or flow meters for measuring one or more parameters of the device and / or its unit operation. Alternatively, one or more of the sensors, flow meters, pumps, or other components of the apparatus may be connected to a communications network operatively coupled to the computer system. One or more of the above may be coupled with another computer system or component to communicate with the computer system over one or more communication networks. Such a configuration allows the sensor or signal-generating device to be located at a considerable distance from the computer system and / or still provide data therebetween, while allowing the sensor to be located at a significant distance from the subsystem and / or controller . Such communication mechanisms may be performed using any suitable technique, including, but not limited to, using wired and / or wireless networks and protocols.

Although a computer system has been described above by way of illustration of one type of computer system in which various aspects of the process herein may be practiced, it should be understood that the present invention is not limited to a software system, or to a computer system as illustratively described do. In fact, for example, rather than executing on a general purpose computer system, the controller, or component or subsection thereof, may alternatively be implemented within a dedicated system or a dedicated programmable logic controller (PLC) or distributed control system . In addition, it should be understood that one or more of the features or aspects of the process may be implemented in software, hardware or firmware, or a combination thereof. For example, one or more segments of an algorithm executable by the controller may be performed in a separate computer and eventually communicated over one or more networks.

In some embodiments, one or more sensors and / or flow meters may be included at a location throughout the process, which communicates with a passive operator or automated control system to perform the appropriate process variations in a programmable logic controlled process. In one embodiment, the process includes a controller that can be a suitably programmed or dedicated computer system, a PLC, or a distributed control system. The flow rate of a particular product stream can be measured and the flow can be reset if necessary to meet the required product slate.

Factors that can cause various adjustments or controls include the consumer demand for various hydrocarbon products, the market value of various hydrocarbon products, the feed material characteristics such as API gravity or heteroatom content, and product quality (e.g., gasoline and medium distillate display properties such as gasoline ≪ / RTI > octane number for the intermediate distillate and the number of octane for the middle distillate).

The disclosed processes and systems form a new outlet for the direct conversion of crude oil, e.g., light crude, such as Arab Extra Light (AXL) or Arab Light (AL) crude oil. Additionally, the disclosed processes and systems require lower capital expenditure relative to conventional approaches to the production of chemicals from fuels or refinery by-products, as compared to known processes and systems, Suggest a new configuration. The disclosed processes and systems significantly increase the proportion of crude oil converted to high purity chemicals that traditionally require high market prices. The complexity due to increased thresholds of commercially proven process capacities using the processes and systems described herein is minimized or eliminated.

The disclosed processes and systems utilize different commercially-proven units arranged in a novel configuration. These novel arrangements enable the production of refined products and petrochemical products including olefins, aromatics, MTBE, and butadiene. The disclosed processes and systems allow the chemical manufacturer to further liberate from the fuel market and increase chemical yield as a fraction of the crude fraction compared to traditional chemical production using refinery intermediates or by-products as feedstock. In addition, the disclosed processes and systems significantly increase the proportion of crude oil that is converted to high purity chemicals that traditionally require high market prices.

The disclosed processes and systems provide an alternative for chemical production with lower capital costs compared to conventional routes using refinery units and integrated chemical composites. In addition, the disclosed processes and systems provide flexibility while simultaneously producing fuel products and chemical products. The ratio of chemical to residual fuel can be controlled by process operations to address fuel changes and chemical market opportunities. In certain embodiments, the process configuration is flexible to enable production of crude oil, such as Arab Light or Arab Extra Light, to provide superior production of chemical products while minimizing the production of refined fuel products. The arrangement allows structural operation to provide flexibility to adjust the ratio of petrochemical to refined product to achieve optimal operation and to change the production rate of the chemical to fuel, thereby meeting market conditions.

For example, in a vacuum gas oil water addition vessel, as the strength increases, the yield of UCO (or hydrogenated gas oil) decreases with increasing naphtha yield, but the yield for most of the distillate does not change as much This is because the wild naphtha product is the result of distillate decomposition. The UCO product is chemically reconstituted to be much more paraffinic in nature through ring opening reactions and remains as a gas oil boiling range product. By adjusting the strength of the vacuum gas oil water addition hole, the shift is between the naphtha and UCO (or hydrotreated gas oil) relative product ratios. The yield of olefins in naphtha in the steam cracker is better than that of UCO (or hydrotreated gas oil); The yield of heavy products (mixed C4s and pyrolysis gasoline) from UCO (or hydrogenated gas oil) is superior to naphtha. Thus, a key advantage of the vacuum gas oil addition process is the economical and dramatic resolution of changes in market conditions for dramatically changeable olefins and aromatics.

Each processing unit is operated in a representative condition for such a unit, and this condition can be changed based on the type of feed that maximizes the desired product within the unit design capabilities. The desired product may comprise an appropriate fraction as the feed to the mixed feed steam cracking zone 230 , or a fraction suitable for use as a fuel product. Similarly, the processing unit uses the appropriate catalyst (s) according to the feed properties and the desired product. While specific embodiments of these operating conditions and catalysts are described herein, it should be understood that variations are well within the skill of the art and are well known in the art.

For the purposes of the simplified schematic diagram and description herein, conventional accessory components, such as numerous valves, temperature sensors, preheat heater (s), desalination operation (s), etc., are not shown in conventional crowned centers .

In addition, it does not include a number of conventional valves, temperature sensors, electrical controllers, etc. in conventional fluid catalytic cracking. Additionally, conventional accessory components such as, for example, an air source, a catalyst hopper, flue gas handling, etc., in a fluid catalytic cracking system are also not shown.

In addition, conventional accessory components such as, for example, a hydrogen recycle sub-system, a bleed stream, a spent catalyst release sub-system, and a catalyst replacement sub-system are also not shown in the water addition unit.

In addition, conventional accessory components such as a vapor source, a coke removal sub-system, a pyrolysis section, a convection section, etc., are not shown in the thermal decomposition system.

The method and system of the present invention are described above and in the accompanying drawings; Modifications, however, will be apparent to those of ordinary skill in the art and the scope of protection to the present invention should be defined by the following claims.

Claims (32)

An integrated process for producing petrochemicals and fuel products from crude oil feeds, including:
From the crude oil feed, at least one of the following in the atmospheric distillation unit (ADU)
A first ADU fraction comprising DC naphtha,
A second ADU fraction comprising at least a portion of the intermediate distillate from the crude oil feed, and
A third ADU fraction comprising atmospheric residue;
From the third ADU fraction, in a vacuum distillation unit (VDU), at least the following separation
A vacuum gas oil comprising a first VDU fraction;
Subjecting the distillate from the second ADU fraction to water addition in a water distillate (DHP) zone middle distillate, and recovering at least a first DHP fraction and a second DHP fraction, wherein the first DHP fraction is naphtha And the second DHP fraction is used for diesel fuel production;
Processing the naphtha from the first ADU fraction within the catalytic reforming zone, and recovering the chemical rich reformate;
Processing the first VDU fraction in the fluid catalytic cracking zone to produce a first FCC fraction corresponding to the light olefin recovered at least as petrochemical, a second FCC fraction corresponding to FCC naphtha, and a third FCC fraction corresponding to the cycle oil To produce;
Within the Mixed Feed Steam Decomposition (MFSC) zone, raffinate derived from the naphtha and aromatic extraction zones from the first ADU fraction, and from the gas oil cracked (GOSC) zone, Wherein the steam cracking comprises at least an effective mixed product stream H2, methane, ethane, ethylene, mixed C3s and mixed C4s; Pyrolysis gas; And operating under conditions to recover pyrolysis oil;
Recovering H2, methane, non-olefinic C2-C4s, and petrochemicals ethylene, propylene and butylene from the mixed product stream,
Adding water to the pyrolysis gas from the steam cracking in the naphtha water addition room and recovering the hydrogenated pyrolysis gas; And
Separating the chemical-rich reformate from the aromatic and catalytic reforming zones from the hydrotreating pyrolysis gas in an aromatic extraction zone for the recovery of petrochemical aromatic products and aromatic extraction zones raffinates, Nate is all or part of the aromatic extraction zone raffinate. The method of claim 1, wherein the chemical modification zone is a semi-regenerative, cyclic regeneration, or continuous regeneration zone that enables the production of a chemically-rich reformate by contacting the naphtha feed with a mono-functional or bi- A process comprising a catalyst regeneration arrangement. Process according to claims 1 or 2, wherein the naphtha is hydrotreated prior to processing in the catalyst reforming zone. The process according to any one of claims 1-3, wherein the n-paraffin-rich stream is separated from the naphtha prior to modification, wherein at least a portion of the paraffin-rich stream is passed to the MFSC. The process according to any one of claims 1-4, further comprising hydrotreating the second FCC fraction to produce hydrotreated FCC naphtha. 6. The process of claim 5, further comprising processing the hydrotreated FCC naphtha in an aromatic extraction complex for recovery of additional aromatic product and additional aromatic extraction zone raffinate recycled to the mixed feed stream cracking zone. 6. The process of claim 5, further comprising recovering C5s from the hydrotreated FCC naphtha and recycling the recovered C5s to a mixed feed stream cracking zone. 8. The process of claim 7, further comprising processing the hydrotreated FCC naphtha in an aromatic extraction complex for recovery of additional aromatic product and additional aromatic extraction zone raffinate recycled to the mixed feed stream cracking zone. The process according to any one of claims 1-8, wherein at least a substantial portion of the first DHP fraction is passed to the MFSC zone or ADU. The method of any one of claims 1-9, wherein the vacuum gas oil from the first VDU fraction is worked up in the gas oil water addition zone (GOHP) zone prior to processing in the fluid catalytic cracking zone, and A first GOHP fraction passed through the fluid catalytic cracking zone, boiling below the atmospheric residue end boiling point and comprising LPG, a naphtha and a middle distillate range component, and a second GOHP fraction containing heavy oil / RTI > 11. The process of claim 10 wherein at least a substantial portion of the naphtha from the first GOHP fraction is directed to a mixed feed stream cracking zone or an atmospheric distillation zone. 11. The process of claim 10, wherein at least a substantial portion of the first GOHP fraction is sent to the distillate water addition space. 11. The process of claim 10 wherein the intermediate distillate in the second ADU fraction further comprises a heavy atmospheric gas oil that is processed in a gas oil water addition room. 11. The method of claim 10, wherein the intermediate distillate further comprises a heavy atmospheric gas oil processed in a fluid catalytic cracking zone without water addition, wherein the first VDU fraction is in a gas oil water addition zone Process of adding water. 11. The process of claim 10, further comprising passing at least a portion of the third FCC fraction to a distillate water addition chamber. 11. The method of claim 10 wherein the GOHP zone operates under hydrocracking conditions to convert 27-99 wt% of the feed to the GOHP zone into a first GOHP fraction and in the presence of a hydrocracking catalyst, Process involving non-conversion oil. 11. The method of claim 10 wherein the GOHP zone operates under hydrotreating conditions to convert 2-30 wt% of the feed to the GOHP zone into a first GOHP fraction and in the presence of a hydrotreating catalyst, Process involving hydrogenated gas oil. 11. The process of claim 10 wherein the intermediate distillate in the second ADU fraction further comprises a heavy atmospheric gas oil delivered to the GOHP zone. 11. The process of claim 10 wherein the intermediate distillate in the second ADU fraction further comprises a heavy atmospheric gas oil processed in a GOSC zone without water addition. 11. The method of claim 10, wherein the intermediate distillate in the second ADU fraction is selected from the group consisting of kerosine processed in a kerosene desulfurization process to recover kerosene fuel products, Process comprising diesel fraction. 21. The process of claim 20, wherein the intermediate distillate in the second ADU fraction further comprises a heavy atmospheric gas oil processed in a GOHP zone or a GOSC zone. 2. The process of claim 1, wherein at least a substantial portion of the first DHP fraction is passed to an MFSC zone or an ADU. 11. The process of claim 10 wherein at least a substantial portion of the naphtha from the first GOHP fraction is directed to a chemical modification zone. 11. The process of claim 10, wherein at least a substantial portion of the first GOHP fraction is sent to the distillate water addition space. The process of any one of claims 1-24, wherein the non-olefinic C4s recovered from the mixed product stream are recycled to the mixed feed stream cracking zone. The process of any one of claims 1-24, wherein the non-olefinic C4s recovered from the mixed product stream are recycled to a separate processing zone for the production of additional petrochemicals. 27. The process of claim 26, wherein the separate processing zone is a process for converting a mixture of butenes to mixed butanol. 27. The process according to claim 26, further comprising:
Recovering C5s from the hydrogenated pyrolysis gas;
Passing the recovered C5s to a separate processing zone for the production of additional petrochemicals; And
Passing a portion of the recovered ethylene into a separate processing zone;
Wherein the separate processing zone is a metathesis reaction zone that produces a C4 / C5 raffinate stream that is recycled to the petrochemical propylene and mixed feed stream cracking zones. The method of any one of claims 1-24, further comprising recovering C5s from the hydrotreated pyrolysis gas and recovering the recovered C5s in a MFSC zone, a separate processing zone for the production of additional petrochemicals, Lt; RTI ID = 0.0 > zone < / RTI > and a separate processing zone for the production of additional petrochemicals. 30. The process of claim 29, wherein the recovered C5s is passed to a mixed feed stream decomposition zone. 30. The process of claim 29, wherein the recovered C5s is passed to a separate processing zone for the production of additional petrochemicals, wherein the separate processing zone converts the mixture of butenes to mixed butanol. The process of any one of the preceding claims, wherein a crude to chemical conversion of at least about 39 wt% is achieved.

Images