US20180142167A1

US20180142167A1 - Process and system for conversion of crude oil to chemicals and fuel products integrating steam cracking and fluid catalytic cracking

Info

Publication number: US20180142167A1
Application number: US15/710,799
Authority: US
Inventors: Mohammad Saeed AL-GHAMDI; Bader BAHAMMAM; Naif AL OSAIMI; Sami BARNAWI
Original assignee: Saudi Arabian Oil Co
Current assignee: Saudi Arabian Oil Co
Priority date: 2016-11-21
Filing date: 2017-09-20
Publication date: 2018-05-24
Also published as: CN110088242A; US10913908B2; US20180223197A1; CN110088242B; US10717941B2; EP3541899B1; WO2018094351A1; JP2020512417A; KR20190087477A; WO2018094351A8; US20200239790A1; EP3541899A1

Abstract

An integrated process converting crude oil to petrochemical products including olefins and aromatics, and fuel products, is disclosed. The process includes steam cracking and fluid catalytic cracking. Feed to the steam cracker include several naphtha fractions from hydroprocessing zones within the battery limits, and recycle streams from extraction zones within the battery limits.

Description

RELATED APPLICATIONS

This application claims priority to U.S. Provisional Patent Application No. 62/424,883 filed Nov. 21, 2016, U.S. Provisional Patent Application No. 62/450,018 filed Jan. 24, 2017 and U.S. Provisional Patent Application No. 62/450,058 filed Jan. 24, 2017, the contents of which are incorporated herein by reference.

BACKGROUND OF THE INVENTION

Field of the Invention

The inventions disclosed herein relate to an integrated process and system for converting crude oil to refined products and improved feedstock for steam cracking to produce petrochemical products including olefins, aromatics, MTBE, and butadiene.

Description of Related Art

The lower olefins (i.e., ethylene, propylene, butylene and butadiene) and aromatics (i.e., benzene, toluene and xylene) are basic intermediates which are widely used in the petrochemical and chemical industries. Thermal cracking, or steam pyrolysis, is a major type of process for forming these materials, typically in the presence of steam, and in the absence of oxygen. Feedstocks for steam pyrolysis can include petroleum gases, 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-intensive process steps in a crude oil refinery.
A very significant portion of ethylene production relies on naphtha as the feedstock. However, heavy naphtha has a lower paraffin and higher aromatics content than light naphtha, making it less suitable as feedstock in the production of ethylene without upgrading. Heavy naphtha can vary in the amount of total paraffins and aromatics based on its source. Paraffins content can range between about 27-70%, naphthenes content can range between about 15-60%, and the aromatics content can range between about 10-36% (volume basis).
Many chemicals producers are limited by the supply and quality of feed from nearby refiners due to reliance on oil refinery byproducts as feed. Chemicals producers are also limited by the high cost of oil refining and its associated fuels markets, which may negatively influence the economic value of refinery sourced feeds. Higher global fuel efficiency standards for automobiles and trucks will reduce fuels demand and narrow refinery margins, and may complicate the economics of fuels and chemicals supply and/or markets.
A need remains in the art for improved processes for converting crude oil to basic chemical intermediates such as lower olefins and aromatics. In addition, a need remains in the art for new approaches that offer higher value chemical production opportunities with greater leverage on economies of scale.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention will be described in further detail below and with reference to the attached drawings in which the same or similar elements are referred to by the same number, and where:

FIG. 1 schematically depicts operations upstream of a steam cracker in one embodiment of a process for producing petrochemicals and fuel product integrating fluid catalytic cracking and steam cracking;

FIG. 2 schematically depicts operations upstream of a steam cracker in another embodiment of a process for producing petrochemicals and fuel product integrating fluid catalytic cracking and steam cracking;

FIG. 3 schematically depicts operations downstream of a steam cracker in an embodiment of a process for producing petrochemicals and fuel product integrating fluid catalytic cracking and steam cracking;

FIG. 4 schematically depicts operations downstream of a steam cracker in another embodiment of a process for producing petrochemicals and fuel product integrating fluid catalytic cracking and steam cracking;

FIG. 5 schematically depicts operations downstream of a steam cracker in a further embodiment of a process for producing petrochemicals and fuel product integrating fluid catalytic cracking and steam cracking;

FIG. 6 schematically depicts operations downstream of a steam cracker in an embodiment of a process for producing petrochemicals and fuel product integrating fluid catalytic cracking, steam cracking and metathesis;

FIG. 7 schematically depicts operations downstream of a steam cracker in an embodiment of a process for producing petrochemicals and fuel product integrating fluid catalytic cracking, steam cracking and mixed butanol production;

FIG. 8 schematically depicts operations downstream of a steam cracker in an embodiment of a process for producing petrochemicals and fuel product integrating fluid catalytic cracking, steam cracking, metathesis and mixed butanol production;

FIGS. 9 and 10 schematically depict operations upstream of a steam cracker in further embodiments of processes for producing petrochemicals and fuel product integrating fluid catalytic cracking and steam cracking;

FIG. 11 schematically depicts operations downstream of a steam cracker in further embodiments of a process for producing petrochemicals and fuel product integrating fluid catalytic cracking and steam cracking;

FIGS. 12 and 13 schematically depict operations upstream of a steam cracker in additional embodiments of processes for producing petrochemicals and fuel product integrating fluid catalytic cracking and steam cracking;

FIG. 14 schematically depicts operations downstream of a steam cracker in additional embodiments of a process for producing petrochemicals and fuel product integrating fluid catalytic cracking and steam cracking;

FIGS. 15 and 16 depict general operations of types of fluid catalytic cracking operations;

FIG. 17 schematically depicts operations downstream of a steam cracker in another embodiment of a process for producing petrochemicals and fuel product integrating fluid catalytic cracking, steam cracking and metathesis;

FIG. 18 schematically depicts operations downstream of a steam cracker in a further embodiment of a process for producing petrochemicals and fuel product integrating fluid catalytic cracking and steam cracking; and

FIGS. 19 and 20 schematically depict operations upstream of a steam cracker in still further embodiments of processes for producing petrochemicals and fuel product integrating fluid catalytic cracking and steam cracking;

SUMMARY

In accordance with one or more embodiments, the invention relates to an integrated process for producing petrochemicals and fuel product from a crude oil feed. The integrated process includes an initial separation step to separate from a crude oil feed in an atmospheric distillation zone at least a first ADU fraction comprising straight run naphtha; a second ADU fraction comprising at least a portion of middle distillates, and a third ADU fraction comprising atmospheric residue. A first VDU fraction comprising vacuum gas oil is separated from the third ADU fraction in a vacuum distillation zone. In a distillate hydroprocessing zone, such as a diesel hydrotreater, at least a portion of the second ADU fraction is processed to produce at least a first DHP fraction and a second DHP fraction, wherein the first DHP fraction comprises naphtha and the second DHP fraction is used for diesel fuel production. The first VDU fraction is processed in a fluid catalytic cracking zone to produce at least a first FCC fraction corresponding to light olefins that are recovered as petrochemicals, a second FCC fraction corresponding to FCC naphtha and a third FCC fraction corresponding to cycle oil. The first ADU fraction and an aromatics extraction zone raffinate are processed in a mixed feed stream cracking zone to produce a mixed product stream comprising H₂, methane, ethane, ethylene, mixed C3s and mixed C4s; a pyrolysis gas stream; and a pyrolysis oil stream. From the mixed product stream C3s and the mixed C4s, petrochemicals ethylene, propylene and butylenes are recovered. Ethane and non-olefinic C3s are recycled to the mixed feed stream cracking zone, and non-olefinic C4s are recycled to the mixed feed stream cracking zone or to a separate processing zone for production of additional petrochemicals. Pyrolysis gas is treated in a naphtha hydroprocessing zone to produce hydrotreated pyrolysis gas, that is routed to an aromatics extraction zone to recover aromatic products and the aromatics extraction zone raffinate that is recycled to the mixed feed stream cracking zone.
Still other aspects, embodiments, and advantages of these exemplary aspects and embodiments, are discussed in detail below. Moreover, it is to be understood that both the foregoing information and the following detailed description are merely illustrative examples of various aspects and embodiments, and are intended to provide an overview or framework for understanding the nature and character of the claimed aspects and embodiments. The accompanying drawings are included to provide illustration and a further understanding of the various aspects and embodiments, and are incorporated in and constitute a part of this specification. The drawings, together with the remainder of the specification, serve to explain principles and operations of the described and claimed aspects and embodiments.

DESCRIPTION

Process scheme configurations are disclosed that enable conversion of crude oil feeds via several processing units in an integrated manner into chemicals. The designs utilize minimum capital expenditures to prepare suitable feedstocks for the steam cracker. The integrated process for converting crude oil to petrochemical products including olefins and aromatics, and fuel products, includes steam cracking and fluid catalytic cracking. Feed to the steam cracker include several naphtha fractions from hydroprocessing zones within the battery limits, and recycle streams from extraction zones within the battery limits.
The term “crude to chemicals conversion” as used herein refers to conversion of crude oil into petrochemicals including lower olefins ethylene, propylene, butylenes (including isobutylene), butadiene, MTBE, butanols, benzene, ethylbenzene, toluene, xylene, and derivatives of the foregoing.
The term “crude to chemicals conversion ratio” as used herein refers the ratio, on a mass basis, of the influent crude oil before desalting, to petrochemicals including lower olefins ethylene, propylene, butylenes (including isobutylene), butadiene, MTBE, butanols, benzene, ethylbenzene, toluene, xylene, and derivatives of the foregoing.
The term “crude oil” as used herein refers to petroleum extracted from geologic formations in its unrefined form. Any crude oil is suitable as the source material for the process of this invention, including Arabian Heavy, Arabian Light, Arabian Extra Light, other Gulf crudes, Brent, North Sea crudes, North and West African crudes, Indonesian, Chinese crudes and mixtures thereof. The crude petroleum mixtures can be whole range crude oil or topped crude oil. As used herein, “crude oil” also refers to such mixtures that have undergone some pre-treatment such as water-oil separation; and/or gas-oil separation; and/or desalting; and/or stabilization. In certain embodiments, crude oil refers to any of such mixtures having an API gravity (ASTM D287 standard), of greater than or equal to about 20°, 30°, 32°, 34°, 36°, 38°, 40°, 42° or 44°.
The acronym “AXL” as used herein refers to Arab Extra Light crude oil, characterized by an API gravity of greater than or equal to about 38°, 40°, 42° or 44°, and in certain embodiments in the range of about 38°-46°, 38°-46°, 38°-44°, 38°-42°, 38°-40.5°, 39°-46°, 39°-44°, 39°-42°, or 39°-40.5°.
The acronym “AL” as used herein refers to Arab Light crude oil, characterized by an API gravity of greater than or equal to about 30°, 32°, 34°, 36° or 38°, and in certain embodiments in the range of about 30°-38°, 30°-36°, 30°-35°, 32°-38°, 32°-36°, 32°-35°, 33°-38°, 33°-36°, or 33°-35°.
The term “LPG” as used herein refers to the well-known acronym for the term “liquefied petroleum gas,” and generally is a mixture of C3-C4 hydrocarbons. In certain embodiments, these are also referred to as “light ends.”
The term “naphtha” as used herein refers to hydrocarbons boiling in the range of about 20-193, 20-190, 20-180, 20-170, 32-193, 32-190, 32-180, 32-170, 36-193, 36-190, 36-180 or 36-170° C.
The term “light naphtha” as used herein refers to hydrocarbons boiling in the range of about 20-110, 20-100, 20-90, 20-88, 32-110, 32-100, 32-90, 32-88, 36-110, 36-100, 36-90 or 36-88° C.
The term “heavy naphtha” as used herein refers to hydrocarbons boiling in the range of about 90-193, 90-190, 90-180, 90-170, 93-193, 93-190, 93-180, 93-170, 100-193, 100-190, 100-180, 100-170, 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, or distillation of intermediate refinery processes as described herein.
The modifying term “straight run” is used herein having its well-known meaning, that is, describing fractions derived directly from the atmospheric distillation unit, optionally subjected to steam stripping, without other refinery treatment such as hydroprocessing, fluid catalytic cracking or steam cracking. An example of this is “straight run naphtha” and its acronym “SRN” which accordingly refers to “naphtha” defined above that is derived directly from the atmospheric distillation unit, optionally subjected to steam stripping, as is well known.
The term “kerosene” as used herein refers to hydrocarbons boiling in the range of about 170-280, 170-270, 170-260, 180-280, 180-270, 180-260, 190-280, 190-270, 190-260, 193-280, 193-270, or 193-260° C.
The term “light kerosene” as used herein refers to hydrocarbons boiling in the range of about 170-250, 170-235, 170-230, 170-225, 180-250, 180-235, 180-230, 180-225, 190-250, 190-235, 190-230, 190-225° C.
The term “heavy kerosene” as used herein refers to hydrocarbons boiling in the range of about 225-280, 225-270, 225-260, 230-280, 230-270, 230-260, 235-280, 235-270, 235-260, or 250-280° C.
The term “atmospheric gas oil” and its acronym “AGO” as used herein refer to hydrocarbons boiling in the range of about 250-370, 250-360, 250-340, 250-320, 260-370, 260-360, 260-340, 260-320, 270-370, 270-360, 270-340 or 270-320° C.
The term “heavy atmospheric gas oil” and its acronym “H-AGO” as used herein in certain embodiments refer to the heaviest cut of hydrocarbons in the AGO boiling including the upper 3-30° C. range (e.g., for AGO having a range of about 250-360° C., the range of H-AGO includes an initial boiling point from about 330-357° C. and an end boiling point of about 360° C.).
The term “medium atmospheric gas oil” and its acronym “M-AGO” as used herein in certain embodiments in conjunction with H-AGO refer to the remaining AGO after H-AGO is removed, that is, hydrocarbons in the AGO boiling excluding the upper about 3-30° C. range (e.g., for AGO having a range of about 250-360° C., the range of M-AGO includes an initial boiling point of about 250° C. and an end boiling point of about from about 330-357° C.).
In certain embodiments herein, the term “diesel” as used herein with reference to a straight run fraction from the atmospheric distillation unit. In embodiments in which this terminology is used, the diesel fraction refers to medium AGO range hydrocarbons and in certain embodiments also in combination with heavy kerosene range hydrocarbons,
The term “atmospheric residue” and its acronym “AR” as used herein refer to the bottom hydrocarbons having an initial boiling point of corresponding to the end point of the from the AGO range hydrocarbons, and having an end point based on the characteristics of the crude oil feed.
The term “vacuum gas oil” and its acronym “VGO” as used herein refer to hydrocarbons boiling in the range of about 370-550, 370-540, 370-530, 370-510, 400-550, 400-540, 400-530, 400-510, 420-550, 420-540, 420-530 or 420-510° C.
The term “vacuum residue” and its acronym “VR” as used herein refer to the bottom hydrocarbons having an initial boiling point of corresponding to the end point of the from the VGO range hydrocarbons, and having an end point based on the characteristics of the crude oil feed.
The term “fuels” refers to crude oil-derived products used as energy carrier. Fuels commonly produced by oil refineries include, but are not limited to, gasoline, jet fuel, diesel fuel, heavy fuel oil and petroleum coke. Unlike petrochemicals, which are a collection of well-defined compounds, fuels typically are complex mixtures of different hydrocarbon compounds.
“Kerosene fuel products” include jet fuel products, including fuel products and precursors for producing fuel products meeting Jet A or Jet A-1 specifications.
“Diesel fuel products” include fuel suitable for compression-ignition engines, including fuel products and precursors for producing fuel products such as ultra low sulfur diesel including those meeting Euro V specifications.
The term “aromatic hydrocarbons” or “aromatics” is very well known in the art. Accordingly, the term “aromatic hydrocarbon” relates to cyclically conjugated hydrocarbon with a stability (due to delocalization) that is significantly greater than that of a hypothetical localized structure (e.g. Kekule structure). The most common method for determining aromaticity of a given hydrocarbon is the observation of diatropicity in the 1H NMR spectrum, for example the presence of chemical shifts in the range of from 7.2 to 7.3 ppm for benzene ring protons
The terms “naphthenic hydrocarbons” or “naphthenes” or “cycloalkanes” is used herein having its established meaning and accordingly relates types of alkanes that have one or more rings of carbon atoms in the chemical structure of their molecules.
The term “wild naphtha” is used herein to refer to naphtha products derived from hydroprocessing units such as distillate hydroprocessing units, diesel hydroprocessing units and/or gas oil hydroprocessing units.
The term “light cycle oil” and its acronym “LCO” as used herein refers to the light cycle oil produced by fluid catalytic cracking units. The distillation cut for this stream is, for example, in the range of about 220-330° C. LCO is used sometimes in the diesel blends depending on the diesel specifications, or it can be utilized as a cutter to the fuel oil tanks for reduction in the viscosity and sulfur contents.
The term “heavy cycle oil” and its acronym “HCO” as used herein refer to the heavy cycle oil which is produced by fluid catalytic cracking units. The distillation cut for this stream is, for example, in the range of about 330-510° C. HCO is used sometimes in an oil flushing system within the process. Additionally, HCO is used to partially vaporize the debutanizer bottoms and then is recycled back as a circulating reflux to the main fractionator in the FCC unit.
The term “cycle oil” is used herein to refer to a mixture of LCO and HCO.
The term “C# hydrocarbons” or “C#”, is used herein having its well-known meaning, that is, wherein“#” is an integer value, means hydrocarbons having that value of carbon atoms. The term “C#+ hydrocarbons” or “C#+” refers to hydrocarbons having that value or more carbon atoms. The term “C#− hydrocarbons” or “C#-” refers to hydrocarbons having that value or less carbon atoms. Similarly, ranges are also set forth, for instance, C1-C3 means a mixture comprising C1, C2 and C3.
The term “petrochemicals” or “petrochemical products” refers to chemical products derived from crude oil that are not used as fuels. Petrochemical products include olefins and aromatics that are used as a basic feedstock for producing chemicals and polymers, and include olefins and aromatics. Typical olefinic petrochemical products include, but are not limited to, ethylene, propylene, butadiene, butylene-1, isobutylene, isoprene, cyclopentadiene and styrene. Typical aromatic petrochemical products include, but are not limited to, benzene, toluene, xylene and ethyl benzene.
The term “olefin” is used herein having its well-known meaning, that is, unsaturated hydrocarbons containing at least one carbon-carbon double bond. In plural, the term “olefins” means a mixture comprising two or more unsaturated hydrocarbons containing at least one carbon-carbon double bond. In certain embodiments, the term “olefins” relates to a mixture comprising two or more of ethylene, propylene, butadiene, butylene-1, isobutylene, isoprene and cyclopentadiene.
The term “crude C4” refers to the mixed C4 effluent from a steam cracking zone.
The term “C4 Raffinate 1” or “C4 Raff-1” refers to the mixed C4s stream leaving the butadiene extraction unit, that is, mixed C4s from the crude C4 except butadiene.
The term “C4 Raffinate 2” or “C4 Raff-2” refers to the mixed C4s stream leaving the MTBE unit, that is, mixed C4s from the crude C4 except butadiene and isobutene.
The term “C4 Raffinate 3” or “C4 Raff-3” refers to the mixed C4s stream leaving the C4 distillation unit, that is, mixed C4s from the crude C4 except butadiene, isobutene, and butane-1.
The terms “pyrolysis gas” and its abbreviated form “py-gas” are used herein having their well-known meaning, that is, thermal cracking products in the range of C5 to C9, for instance having end boiling points to about 204.4° C. (400° F.), in certain embodiments up to about 148.9° C. (300° F.).
The terms “pyrolysis oil” and its abbreviated form “py-oil” are used herein having their well-known meaning, that is, a heavy oil fraction, C10+, that is derived from steam cracking.
The term “BTX” as used herein refers to the well-known acronym for benzene, toluene and xylenes.
In general, the integrated process for producing petrochemicals and fuel product from a crude oil feed includes an initial separation step to separate from a crude oil feed in an atmospheric distillation zone at least a first ADU fraction comprising straight run naphtha; a second ADU fraction comprising at least a portion of middle distillates, and a third ADU fraction comprising atmospheric residue. A first VDU fraction comprising vacuum gas oil is separated from the third ADU fraction in a vacuum distillation zone. In a distillate hydroprocessing zone, such as a diesel hydrotreater, at least a portion of the second ADU fraction is processed to produce at least a first DHP fraction and a second DHP fraction, wherein the first DHP fraction comprises naphtha and the second DHP fraction is used for diesel fuel production The first VDU fraction is processed in a fluid catalytic cracking zone the to produce at least a first FCC fraction corresponding to light olefins that are recovered as petrochemicals, a second FCC fraction corresponding to FCC naphtha and a third FCC fraction corresponding to cycle oil. At least the first ADU fraction and a pyrolysis gas raffinate are processed in a steam cracking complex to produce a mixed product stream comprising H₂, methane, ethane, ethylene, mixed C3s, and mixed C4s, a pyrolysis gas stream and a pyrolysis oil stream. From the mixed product stream, hydrogen gas, fuel gas, and petrochemicals ethylene, propylene and butylenes are recovered. Ethane and non-olefinic C3s and C4s are recovered, with ethane and non-olefinic C3s recycled to the steam cracking complex, and non-olefinic C4s recycled to the steam cracking complex or passed to a separate processing zone for production of additional petrochemicals such as propylene and/or mixed butanol liquids. Pyrolysis gas is treated in a pyrolysis gas hydroprocessing zone to produce hydrotreated pyrolysis gas, that is routed to an aromatics extraction complex to recover aromatic petrochemicals and a raffinate including pyrolysis gas raffinate that is recycled to the steam cracking complex. In certain embodiments, FCC naphtha is also hydroprocessed and passed to the aromatics extraction complex to produce additional aromatic petrochemicals and additional raffinate that is routed to the steam cracking complex.
FIGS. 1 and 3 schematically depict one embodiment of a process and system for conversion of crude oil to chemicals and fuel products, including a mixed feed steam cracking zone and a high olefinic fluid catalytic cracking (HOFCC) zone 400. Generally, FIG. 1 schematically depicts operations upstream of the mixed feed steam cracking zone (MFSC) 700 while FIG. 3 schematically depicts operations downstream of the mixed feed steam cracking zone (MFSC) 700.
A crude oil feed 102, in certain embodiments AXL or AL, separated into fractions in a crude complex 100 typically including an atmospheric distillation zone (CDU) 104, a saturated gas plant 106 and a vacuum distillation zone (VDU) 108.
The crude oil feed 102 is fed into the atmospheric distillation zone 104. As shown in FIG. 1, light products, for instance, light hydrocarbons with fewer than six carbons, are passed to the mixed feed steam cracking zone (MFSC) 700. In particular, C3-C4 hydrocarbons 112 including propane and butanes are separated from the light ends and LPG 110 from the CDU 104 via the saturated gas plant 106. Optionally, other light products are routed to the saturated gas plant 106 (shown in dashed lines as stream 116), such as refinery units within the integrated system. Off-gases from the FCC unit, after passing through an unsat gas plant, can be integrated with off gases from the saturated gas plant 106 for fuel gas common handling.
The separated C3-C4 hydrocarbons 112 are routed to the MFSC zone 700. Off gases 114 from the saturated gas plant 106 and off gases 702 from the MFSC zone 700 are removed and recovered as is typically known, for instance to contribute to a fuel gas (FG) system. Straight run naphtha 118 is also routed to the MFSC zone 700 from the CDU 104.
Middle distillates are used to produce diesel and/or kerosene, and additional feed to the mixed feed steam cracking zone 700. In the embodiment shown in FIG. 1, at least three different middle distillate cuts are processed for production of fuel products and petrochemicals (via the steam cracker). In one example using the arrangement shown in FIG. 1, a first ADU fraction 120, colloquially referred to a kerosene fraction, contains light kerosene range hydrocarbons, a second ADU fraction 130, colloquially referred as a diesel fraction, contains heavy kerosene range hydrocarbons and medium AGO range hydrocarbons, and a third ADU fraction 140, colloquially referred to as an atmospheric gas oil fraction, contains heavy AGO range hydrocarbons. In another example using the arrangement shown in FIG. 1, a first ADU fraction 120 contains kerosene range hydrocarbons, a second ADU fraction 130 contains medium AGO range hydrocarbons and a third ADU fraction 140 contains heavy AGO range hydrocarbons. In another example using the arrangement shown in FIG. 1, a first ADU fraction 120 contains light kerosene range hydrocarbons and a portion of heavy kerosene range hydrocarbons, a second ADU fraction 130 contains a portion of heavy kerosene range hydrocarbons and a portion of medium AGO range hydrocarbons and a third ADU fraction 140 contains a portion of medium AGO range hydrocarbons and heavy AGO range hydrocarbons.
For example, a first ADU fraction 120 can be processed in a kerosene sweetening process 210 to produce kerosene fuel product 212, such as Jet A, and optionally other fuel products (not shown). Also, as shown, a second ADU fraction 130 is processed in a distillate hydroprocessing zone such as a diesel hydrotreater 220, to produce wild naphtha 222 and a diesel fuel fraction 224, for instance, Euro V diesel. Diesel fuel fraction 224 can optionally be combined with a diesel fuel fraction 314 from a vacuum gas oil hydrocracker 310 described with respect to FIG. 1. Wild naphtha 222 is routed to the MFSC zone 700 as an additional steam cracking feed.
In certain embodiments (as denoted by dashed lines), all or a portion of a third ADU fraction 140 is routed to a vacuum gas oil hydroprocessing zone, which can operate as a gas oil hydrocracker (VGO HCK) as shown in FIG. 1 or as a vacuum gas oil hydrotreater (VGO-HT) as shown in FIG. 2. In certain embodiments (as denoted by dashed lines), all or a portion of the third ADU fraction 140 is routed to the HOFCC zone 400, bypassing the vacuum gas oil hydroprocessing zone.
Atmospheric residue (AR) 150 is further distilled by the VDU 108. Vacuum gas oil (VGO) 160 from the VDU 108 is routed to the vacuum gas oil hydroprocessing zone. The heaviest fractions 162 from the VDU 108, vacuum residue, can be sent to a fuel oil (FO) pool.
As shown in FIG. 1, a VGO HCK 310 can operate under mild, moderate or severe hydrocracking conditions, and generally produces a hydrocracked naphtha product 312, a diesel fuel fraction 314, and hydrotreated gas oil 344. Hydrocracked naphtha 312 from the VGO HCK 310 is routed to the MFSC zone 700. A hydrotreated gas oil fraction 344 is routed to the HOFCC zone 400. The diesel fuel fraction 314 is recovered as fuel, for instance, Euro V Diesel, and can be combined with the diesel fuel fraction 224 from the diesel hydrotreater 220.
In certain embodiments, as shown in FIG. 2, a VGO-HT 340 can operate under mild, moderate or severe hydrotreating conditions, and generally produces cracked products 342 and a hydrotreated gas oil fraction 344. Cracked products 342 are routed to the diesel hydrotreater, and hydrotreated gas oil 344 is routed to the HOFCC zone 400. The hydrotreated gas oil fraction 344 generally contains the portion of the VGO HT 340 effluent that is at or above the AGO, H-AGO or VGO range.
The HOFCC zone 400 is configured to produce light olefin product 404 that is recovered and HOFCC naphtha 406. Off gases can be integrated with the fuel gas system. In certain embodiments (not shown in FIG. 1), certain gases can be routed to the separation units associated with the MFSC zone 700, and/or LPGs can be routed to the MFSC zone 700.
All or a portion of the HOFCC naphtha 406 can be processed as described below in a hydrotreating and an aromatics separation zone 500/600, to increase the quantity of raffinate as additional feed to the MFSC zone 700. Any portion of the HOFCC naphtha 406 that is not routed to the hydrotreating and an aromatics separation zone 500/600, shown in dashed lines, is hydrotreated and recovered for fuel production (not shown).
In additional embodiments, as shown in FIG. 4, all or a portion of the HOFCC naphtha 406 is hydrotreated and recovered for fuel production (not shown). Optionally, a portion of the HOFCC naphtha 406 that is not recovered for fuel production can be processed in the hydrotreating and an aromatics separation zone 500/600, as shown in dashed lines, to increase the quantity of raffinate as additional feed to the MFSC zone 700.
In additional embodiments, as shown in FIG. 5, all or a portion of the HOFCC naphtha 406 is hydrotreated in a FCC naphtha hydrotreating zone 540, and the hydrotreated FCC naphtha stream 546 is directly routed to the MFSC zone 700. Any portion of the HOFCC naphtha 406 that is not routed to the to the MFSC zone 700, shown in dashed lines, is recovered for fuel production (not shown). In this manner, components of the hydrotreated FCC naphtha stream 546, that are not cracked in the MFSC zone 700, including aromatics, increase the pyrolysis gas 712 from the MFSC zone 700, which are routed to the hydrotreating and an aromatics separation zone 500/600.
Other products from the HOFCC zone 400 include cycle oil, such as light cycle oil 408 and heavy cycle oil 410. In certain optional embodiments, all or a portion of the light cycle oil 408 is routed to the distillate hydroprocessing zone 220, thereby increasing the yield of the diesel fuel product 224 and wild naphtha 222 that is passed to the MFSC zone 700. Heavy cycle oil stream 410 can be routed to a fuel oil pool or used as feedstock for production of carbon black.
With continued reference to FIG. 3, the MFSC zone 700, which operates at high severity or low severity thermal cracking process, converts LPG, naphtha and heavier hydrocarbons primarily into ethylene 706, propylene 708 and some side products, and discharges off gases 702 that can be passed to an integrated fuel gas system. Further, hydrogen 704 is recovered from the cracked products and can be recycled to hydrogen users within the refinery limits. For simplicity, operations in an olefins recovery train are not shown, but are well known and are considered part of the MFSC zone 700 as described herein with respect to FIGS. 3, 4, 5, 6, 7, 3 and 11.
A stream 710 containing a mixture of C4s from the MFSC zone 700, known as crude C4s, is routed to a butadiene extraction unit 820 to recover a high purity 1,3-butadiene product 822. A first raffinate 824 (“C4-Raff-1”) containing butanes and butenes is passed to a selective hydrogenation unit (SHU) and MTBE (methyl tertiary butyl ether) unit, SHU and MTBE zone 840, where it is mixed with high purity fresh methanol 842 from outside battery limits to produce MTBE 844.
A second raffinate 846 (“C4 Raff-2”) from the SHU and MTBE zone 840 is routed to a C4 distillation unit 860 for separation into a 1-butene product stream 862 and an alkane stream 866 containing saturated C4s, which is recycled to the MFSC zone 700. A person skilled in the art will appreciate that the separation of the ethylene 706, propylene 708 and the stream 710 occurs in a suitable arrangement of know separation steps for separating steam cracking zone effluents, including compression stage(s), depropanizer, debutanizer, demethanzier and deethanizer.
Pyrolysis gas (py-gas) 712 from the steam cracking zone is fed to a pyrolysis naphtha hydrotreatment and recovery center 500/600. Select hydrocarbons having 5-12 carbons may be recovered from untreated pyrolysis naphtha (UPN) and HOFCC naphtha (FCCN) 406, and the remainder is subsequently hydrotreated for aromatics recovery. In a py-gas hydrotreating unit, diolefins and olefins in the pyrolysis gas are saturated.
As noted above, in certain embodiments, all or a portion of the FCC naphtha 406 is used as additional feed to the mixed feed steam cracking zone 700 without the hydrotreating and aromatic separation steps, without the aromatic separation step, or without the hydrotreating step. In further embodiments, all or a portion of the FCC naphtha 406 is recovered and used for fuel production.
Hydrotreated py-gas and FCCN are routed to aromatics extraction zone 600 (with the py-gas hydrotreating and aromatics extraction shown for simplicity in a single step 500/600 in FIGS. 3, 4, 5, 6, 7, 8 and 11). A naphtha hydrotreating zone 500 operates to hydrotreat py-gas 712 prior to aromatics recovery. In certain optional embodiments, FCC naphtha 406 can also be hydrotreated in a separate hydrotreating zone (shown, for instance, in FIGS. 14 and 17), and routed to the aromatics extraction zone 600 with the hydrotreated py-gas.
The aromatics extraction zone 600 includes, for instance, one or more extractive distillation units, and operates to separate the hydrotreated pyrolysis naphtha (HPN) and FCCN into a stream 642 containing high-purity benzene, toluene, xylenes and C9 aromatics, which can be recovered for chemical markets. C5 raffinate 502 and non-aromatics 602 (for instance, C6-C9) are recycled to the MFSC zone 700, and heavy aromatic 660 (for instance, C10-C12) products can be used as an aromatic solvent or as an octane boosting additive. In certain embodiments ethylbenzene 644 can be recovered.
Pyrolysis oil (“py-oil”) 714 can be fractionated (not shown) into light pyrolysis oil (LPO) and heavy pyrolysis oil (HPO). LPO can be blended into diesel or kerosene, or can be hydrotreated or hydroprocessed for recycle to the steam cracking zone. HPO can be blended into the FO pool.
FIG. 6 schematically depicts another embodiment of a process and system for conversion of crude oil to chemicals and fuel products, with metathesis conversion of C4 and C5 olefins to propylene. The process operates as described with respect to any of FIG. 1, 2, 4 or 5 upstream of the steam cracking operations and with respect to the fluid catalytic cracking operations.
Downstream of the steam cracking operations, the butadiene extraction train can optionally operate in a manner similar to that in FIG. 3 shown as the stream 866 from a valve (in dashed lines) from the C4 distillation unit 860 directly to the MFSC zone 700. Selective recovery of various alkene and diene pyrolysis chemicals having four carbons, and metathesis conversion to produce additional propylene, is achieved using a metathesis unit 910.
A mixed C4 raffinate stream 912 (“C4 Raff 3”) from the C4 distillation unit 860 and C5 raffinate 922 from hydrotreating and an aromatics separation zone 500/600 are routed to the metathesis unit 910 for metathesis conversion to additional propylene 914. In certain embodiments, all or a portion cracked C5s from the py-gas hydrotreater can be routed to the metathesis unit 910 prior to aromatics extraction. As indicated, a portion 916 of the ethylene MFSC product can be routed to the metathesis unit 910. In additional embodiments, ethylene for the metathesis unit 910 is supplied from outside the refinery limits, instead of or in addition to the portion 916 of the ethylene MFSC product. A stream 918 containing a mixture of saturated C4/C5 from the metathesis unit 910 is recycled to the mixed feed steam cracking zone 700.
As in FIG. 3, in the configuration of FIG. 6, pyrolysis gas 712 from the steam cracking zone 700 is fed to a pyrolysis naphtha hydrotreatment and recovery center 500/600 where select hydrocarbons having 5-12 carbons can be recovered from UPN and FCCN, and the remainder is subsequently hydrotreated for aromatics recovery. In a py-gas hydrotreating unit (HTU), diolefins and olefins in the pyrolysis gas are saturated. In the aromatics extraction step, aromatics are separated from hydrotreated HPN and FCCN. For instance, aromatic extraction can separate the hydrotreated HPN and FCCN into high-purity benzene, toluene, xylenes and C9 aromatics. C6-C9 aromatics stream 642, BTX, is recovered for chemical markets, C6-C9 non-aromatics stream 602 is recycled to the MFSC zone 700, and C10-C12 products stream 660 may be used as an aromatic solvent or as an octane boosting additive. In certain embodiments ethylbenzene 644 can be recovered. C5 raffinate 922 is routed to the metathesis unit 910 as shown, and/or recycled to the MFSC zone 700 (as in the embodiment of FIG. 3) via stream 502, shown in dashed lines in FIG. 6.
As in FIG. 3, in the configuration of FIG. 6, pyrolysis oil 714 can be fractionated into light pyrolysis oil (LPO) and heavy pyrolysis oil (HPO). LPO can be blended into diesel or kerosene, or can be hydrotreated or hydroprocessed for recycle to the steam cracking zone. HPO can be blended into a FO pool.
In the configuration of FIG. 6, optional valves are provided to bypass metathesis conversion process, to therefore divert all of the C4 Raff-3 866 to the MFSC zone 700. In alternative modes, flow can be directed to the metathesis conversion unit 910. In further alternative modes, flow of the C4 Raff-3 866 can be directed to the MFSC zone 700 and the metathesis conversion unit 910. In this manner, a producer can vary the quantity of feed to tailor the desired outputs.
FIG. 7 schematically depicts another embodiment of a process and system for conversion of crude oil to chemicals and fuel products. The process operates as described with respect to FIG. 1, 2, 4 or 5 upstream of the steam cracking operations and with respect to the fluid catalytic cracking operations. In this embodiment, an additional step is provided to convert a mixture of butenes into mixed butanols suitable as a gasoline blending oxygenate and for octane enhancement. Suitable processes to convert a mixture of butenes into mixed butanols are described in one or more of commonly owned patent publications US20160115107A1, US20150225320A1, US20150148572A1, US20130104449A1, US20120245397A1 and commonly owned U.S. Pat. No. 9,447,346B2, U.S. Pat. No. 9,393,540B2, U.S. Pat. No. 9,187,388B2, U.S. Pat. No. 8,558,036B2, all of which are incorporated by reference herein in their entireties. In certain embodiments, a particularly effective conversion process known as “SuperButol™” technology is integrated, which is a one-step process that converts a mixture of butenes into mixed butanol liquids.
Downstream of the steam cracking operations, the butadiene extraction train can optionally operate in a manner similar to that in FIG. 3 shown as the stream 866 from a valve (in dashed lines) from the crude C4 distillation 860 directly to the MFSC zone 700. A crude C4 processing center 930 is integrated for selective recovery of various alkene and diene pyrolysis chemicals having four carbons, and in certain processing arrangements hydrating a portion of those C4's in a butanol production unit (such as a “SuperButol™” unit) to produce high value fuel additives.
FIG. 7 depicts a stream 932 containing butenes from the C4 distillation step routed to the butanol production unit 930 to convert the mixture of butenes into mixed butanol liquids 934. Alkanes 936 are recycled to the MFSC zone 700.
As in FIGS. 1 and 3, in the configuration of FIG. 7, pyrolysis gas 712 from the steam cracking zone 700 is fed to a pyrolysis naphtha hydrotreatment and recovery center 500/600 where select hydrocarbons having 5-12 carbons can be recovered from UPN and FCCN, and the remainder is subsequently hydrotreated for aromatics recovery. C5s are recycled to the MFSC zone 700. In a py-gas hydrotreating unit (HTU), diolefins and olefins in the pyrolysis gas are saturated. Hydrotreated py-gas from the py-gas HTU is routed to aromatics extraction. In the aromatics extraction step, aromatics are separated from hydrotreated HPN and FCCN. For instance, aromatic extraction can separate the hydrotreated HPN and FCCN into high-purity benzene, toluene, xylenes and C9 aromatics. C6-C9 aromatics stream 642 can be recovered for chemical markets, C5 raffinate 502 and non-aromatics 602 (for instance, C6-C9) can be recycled to the MFSC zone 700, and heavy aromatic 660 (for instance, C10-C12) products can be used as an aromatic solvent or as an octane boosting additive. In certain embodiments ethylbenzene 644 can be recovered.
As in FIG. 3, in the configuration of FIG. 7, pyrolysis oil 714 can be fractionated into light pyrolysis oil (LPO) and heavy pyrolysis oil (HPO). LPO can be blended into diesel or kerosene, or can be hydrotreated or hydroprocessed for recycle to the steam cracking zone. HPO can be blended into the FO pool.
In the configuration of FIG. 7, optional valves are provided to bypass the process for conversion of a mixture of butenes into mixed butanols, to therefore divert all of the C4 Raff-3 866 to the MFSC zone 700. In alternative modes, flow can be directed to the unit 930 for conversion of a mixture of butenes into mixed butanols. In further alternative modes, flow of the C4 Raff-3 866 can be directed to the MFSC zone 700 and the unit 930. In this manner, a producer can vary the quantity of feed to tailor the desired outputs.
FIG. 8 schematically depicts another embodiment of a process and system for conversion of crude oil to chemicals and fuel products. In this embodiment, additional step(s) of metathesis conversion of C4 and C5 olefins to propylene, and/or conversion of a mixture of butenes into mixed butanols liquid suitable as a gasoline blending oxygenate and for octane enhancement, are integrated. The process operates as described with respect to any of FIG. 1, 2, 4 or 5 upstream of the steam cracking operations and with respect to the fluid catalytic cracking operations.
Downstream of the steam cracking operations, the butadiene extraction train can optionally operate in a manner similar to that in FIG. 3 shown as the stream 866 from a valve (in dashed lines) from the C4 distillation unit 860 directly to the MFSC zone 700 as an optional mode of operation. The configuration in FIG. 8 integrates selective recovery of various alkene and diene pyrolysis chemicals having four carbons, metathesis conversion to produce additional propylene, and/or conversion of a mixture of butenes into mixed butanols liquid suitable as a gasoline blending oxygenate and for octane enhancement.
FIG. 8 depicts a stream 932 containing butenes from the C4 distillation step (“C4 Raff-3”) routed to a butanol production unit 930 for conversion of the mixture of butenes into mixed butanol liquids 934. Alkanes 936 are recycled to the MFSC zone 700. In addition, a portion 912 of the 2-butene rich raffinate-3 from the C4 distillation unit 860 is passed to a metathesis unit 910 for metathesis conversion to additional propylene 914. As indicated, a portion 916 of the ethylene MFSC product can be routed to the metathesis unit 910. A stream 918, having a mixture of saturated C4/C5 from metathesis unit, is recycled to the mixed feed steam cracking zone.
As in FIG. 3, in the configuration of FIG. 8, pyrolysis gas 712 from the steam cracking zone 700 is fed to a pyrolysis naphtha hydrotreatment and recovery center 500/600 where select hydrocarbons having 5-12 carbons can be recovered from UPN and FCCN, and the remainder is subsequently hydrotreated for aromatics recovery. In a py-gas hydrotreating unit (HTU), diolefins and olefins in the pyrolysis gas are saturated. Hydrotreated py-gas from the py-gas HTU is routed to aromatics extraction. In the aromatics extraction step, aromatics are separated from hydrotreated HPN and FCCN. For instance, aromatic extraction can separate the hydrotreated HPN and FCCN into high-purity benzene, toluene, xylenes and C9 aromatics. C6-C9 aromatics stream 642, BTX, can be recovered for chemical markets, non-aromatics 602 (for instance, C6-C9) can be recycled to the MFSC zone 700, and heavy aromatics 660 (for instance, C10-C12) products can be used as an aromatic solvent or as an octane boosting additive. In certain embodiments ethylbenzene 644 can be recovered. 922 can be routed to the metathesis unit 910 as shown, and/or optionally recycled to the MFSC as shown in dashed lines. In certain embodiments (not shown), all or a portion cracked C5s from the py-gas hydrotreater can be routed to the metathesis unit 910 prior to aromatics extraction.
As in FIG. 3, in the configuration of FIG. 8, pyrolysis oil 714 can be fractionated into light pyrolysis oil (LPO) and heavy pyrolysis oil (HPO). LPO can be blended into diesel or kerosene, or can be hydrotreated or hydroprocessed for recycle to the steam cracking zone. HPO can be blended into the FO pool.
In the configuration of FIG. 8, optional valves are provided to bypass metathesis conversion process and the process for conversion of a mixture of butenes into mixed butanols, to therefore divert all of the C4 Raff-3 866 to the MFSC zone 700. An optional valve also can be provided to direct flow of the C4 Raff-3 to one or both of the metathesis conversion unit 910 and/or the unit 930 for conversion of a mixture of butenes into mixed butanols. In further alternative modes, flow of the C4 Raff-3 866 can be directed to each of the MFSC zone 700, the metathesis conversion unit 910, and the unit 930. In this manner, a producer can vary the quantity of feed to tailor the desired outputs.
FIGS. 9 and 11 schematically depict another embodiment of a process and system for conversion of crude oil to chemicals and fuel products. In the arrangement of FIGS. 9 and 11, a crude oil feed 102, in certain embodiments AXL or AL, is fed to the crude distillation unit (CDU). Naphtha 118 and lighter products 112 are routed to a mixed feed steam cracking zone 700 (MFSC). Middle distillate fractions 120 and 130 are used to produce kerosene and diesel, and wild naphtha 222 as additional feed to the MFSC zone 700. In certain embodiments (as denoted by dashed lines), all or a portion of a third ADU fraction 140 is routed to a vacuum gas oil hydroprocessing zone, which can operate as a gas oil hydrocracker (VGO HCK) as shown in FIG. 9 or as a vacuum gas oil hydrotreater (VGO-HT) as shown in FIG. 10. In certain embodiments (as denoted by dashed lines), all or a portion of the third ADU fraction 140 is routed to the HOFCC zone 400, bypassing the vacuum gas oil hydroprocessing zone.
Atmospheric residue 150 is further distilled in a VDU 108. VGO 160 from the VDU 108 is routed to a vacuum gas oil hydroprocessing zone, which can operate as a high severity vacuum gas oil hydrotreater (VGO-HT) or a mild gas oil hydrocracker (VGO HCK). The heaviest fractions 162 from the VDU 108 are passed to a fuel oil (FO) pool.
As shown in FIG. 9, a VGO HT 340 can operate under mild, moderate or severe hydrotreating conditions, and generally produces cracked products 342 and hydrotreated gas oil 344. Cracked products 342 from the VGO HT 340 are routed to the diesel hydrotreater 220. Hydrotreated product gas oil 344 from the VGO HT 340 is routed to a HOFCC zone 400 configured to produce maximum light olefin product 404. The hydrotreated gas oil fraction 344 generally contains the portion of the VGO HT 340 effluent that is at or above the AGO, H-AGO or VGO range.
In certain embodiments, as shown in FIG. 10, a VGO HCK 310 can operate under mild, moderate or severe hydrocracking conditions, and generally produces a hydrocracked naphtha product 312, a diesel fuel fraction 314, and hydrotreated gas oil 344. Hydrocracked naphtha 312 from the VGO HCK 310 is routed to the MFSC zone 700. Hydrotreated gas oil 344 is routed to the HOFCC zone 400. The hydrotreated gas oil fraction 344 generally contains the portion of the VGO HCK 310 effluent that is at or above the AGO, H-AGO or VGO range. The diesel fuel fraction 314 is recovered as fuel, for instance, Euro V Diesel, and can be combined with the diesel fuel fraction 224 from the diesel hydrotreater 220.
Further, an aromatics recovery center 500/600 is shown, in which aromatics are separated from py-gas 712 and hydrotreated pyrolysis naphtha (HPN) can be obtained. C6-C9 aromatics 642 are recovered for chemical markets, C6-C9 non-aromatics 602 are recycled to the MFSC zone 700, and C10-C12 products 660 can be used as an aromatic solvent or used as gasoline blenders as an octane boosting additive.
In certain embodiments, as shown in dashed lines, HOFCC naphtha 406 is hydrotreated and fed to the aromatics extraction, the light naphtha and middle naphtha are fed to the mixed feed steam cracking zone 700. The C5 and C9 streams from the high olefinic fluid catalytic cracker can be recycled to the mixed feed steam cracking zone 700.
In a further embodiment, all or a portion of the HOFCC naphtha 406 is used as a gasoline blendstock, rather being used in its entirety as feed to the mixed feed steam cracking zone; any remainder of the of the HOFCC naphtha 406 can be used as feed to the mixed feed steam cracking zone 700.
In additional embodiments, all or a portion of py-oil 714 from the steam cracking zone 700 can be passed to a catalytic hydrogen addition process, such as a residue hydrocracking or conditioning process In additional embodiments, py-oil 714 is split into light and heavy fractions, whereby the light fraction is fed to the gas oil hydroprocessing zone and the heavy fraction is fed to the catalytic hydrogen addition process, such as a residue hydrocracking or conditioning process.
In still further embodiments, all or a portion hydrotreated gas oil fraction from the gas oil hydroprocessing zone is passed to an isodewaxing unit and a hydrofinishing unit, for instance, to enable production of group III lube oils or lube oil feedstocks.
FIGS. 12 and 14 schematically depict one embodiment of a process and system are provided for conversion of crude oil to chemicals and fuel products including a mixed feed steam cracking zone and a high olefinic fluid catalytic cracking (HOFCC) zone 400. FIG. 12 schematically depicts operations upstream of the mixed feed steam cracking zone (MFSC zone) 700 while FIG. 14 schematically depicts operations downstream of the MFSC zone 700.
A crude oil feed 102 is passed to a crude complex 100. In the embodiment of FIGS. 12 and 14, the crude complex 100 generally includes an atmospheric distillation zone 104, a saturated gas plant 106 and a vacuum distillation zone 108. The atmospheric distillation unit is used in well-known arrangements.
Intermediate streams obtained from the feed 102 via separation in the crude complex 100 include: off gas 114, obtained within the crude complex 100 via the saturated gas plant 106, and which is passed to a fuel gas system; a light ends stream 112, obtained within the crude complex 100 via the saturated gas plant 106, and which is passed to the MFSC zone 700; a naphtha stream 118 that is passed to the MFSC zone 700; a light kerosene stream 122 that is passed to a kerosene sweetening zone 210, such as a mercaptan oxidation zone; a heavy kerosene stream 124 that is passed to a diesel hydrotreating zone 220; a medium atmospheric gas oil stream 142 that is passed to the diesel hydrotreating zone 220; a heavy atmospheric gas oil stream 144 that is passed to a high olefinic fluid catalytic cracking (HOFCC) zone 400 (directly, or optionally through the vacuum gas oil hydrotreating zone 340, as indicated by dashed lines); an atmospheric residue 150 that is passed to the vacuum distillation zone 108 of the crude complex 100; a vacuum gas oil stream 160 from the vacuum distillation zone 108 that is passed to the vacuum gas oil hydrotreating zone 340; and a vacuum residue 162 from the vacuum distillation zone 108 that can be passed to a fuel oil pool.
The intermediate streams from the crude complex 100 are used in an efficient manner in the integrated process and system herein. The light ends stream 112 and the straight run naphtha stream 118 are routed to the MFSC zone 700 as feed for conversion into light olefins and other valuable petrochemicals. The straight run naphtha stream 118 can optionally be steam-stripped in a side stripper prior to routing to the MFSC zone 700,
Components of the crude complex not shown but which are well-known can include feed/product and pump-around heat exchangers, crude charge heaters, crude tower, product strippers, cooling systems, hot and cold overhead drum systems including re-contactors and off-gas compressors, and units for water washing of overhead condensing system. The atmospheric distillation zone 104 can include well-known design features. Furthermore, in certain embodiments, naphtha, kerosene and atmospheric gas oil products from the atmospheric distillation column are steam-stripped in side strippers, and atmospheric residue is steam-stripped in a reduced-size can section inside the bottom of the atmospheric distillation column.
For instance, the feed to the atmospheric distillation zone 104 is primarily the crude feed 102, although it shall be appreciated wild naphtha and off gas streams from the diesel hydrotreating zone 220 and the vacuum gas oil hydrotreating zone 340 can be routed to the atmospheric distillation zone 104 where they are fractionated before routing to the cracking complex.
A desalting unit (not shown) is typically included upstream of the distillation zone 104. A substantial amount of the water required for desalting can be obtained from a sour water stripper within the integrated process and system. In certain embodiments, fresh feed 102 is be preheated to about 135° C. (275° F.) before entering the desalter. Suitable desalters are designed to remove salt down to a typical level of about 0.00285 kg/m³(1 lb/1000 bbl) in a single stage. In certain embodiments, plural preheat and desalting trains are employed. The desalter operating pressure can be based on a margin of about 3.45 bar (50 psi) above crude and water mixture vapor pressure at desalter operating temperature to ensure liquid phase operation. The desalting unit refers to a well-known arrangement of vessels for desalting of crude oil, and as used herein is operated to reduce the salt content to a target level, for instance, to a level of less than or equal to about 10, 5, or 3 wppm. In certain embodiments two or more desalters are included to achieve a target salt content of less than or equal to about 3 wppm.

- The atmospheric distillation zone 104 can employ fractionated products and pumparounds to provide enough heat for desalting. In certain embodiments, the desalter operating temperature can be controlled by a diesel pumparound swing heat exchanger. In certain embodiments, desalter brine preheats desalter makeup water in a spiral type heat exchanger to minimize fouling and achieve rundown cooling against cooling water before the brine is routed to the wastewater system.

In certain embodiments, desalted crude is preheated to about 190.6° C. (375° F.) before entering a preflash tower. The preflash tower removes LPG and light naphtha from the crude before it enters the final preheat exchangers. The preflash tower minimizes the operating pressure of the preheat train to maintain liquid phase operation at the crude furnace pass valves and also reduces the requisite size of the main crude column.
In one example of a suitable crude distillation system, a crude furnace vaporizes about 360° C. (680° F.) boiling point and lighter material before the crude enters the flash zone of the crude tower. The furnace is designed for an outlet temperature of about 348.9° C. (660° F.). Crude column flash zone conditions are about 346.1° C. (655° F.) and 1.52 bar (22 psig). The crude tower contains 59 trays and produces six cuts. Draw temperatures for each product are: light naphtha, 104.4° C. (220° F.) (overhead vapor); heavy naphtha, 160.6° C. (321° F.) (sidedraw); kerosene, 205° C. (401° F.) (sidedraw); diesel, 261.7° C. (503° F.) (sidedraw); AGO, 322.2° C. (612° F.) (sidedraw); atmospheric residue, 340.6° C. (645° F.) (bottoms). The heavy naphtha draw includes a reboiled side stripper against diesel pumparound, and is controlled to a 185° C. (365° F.) D86 end point. The kerosene draw includes a steam stripper at 14.54 kg/m³(5.1 lb steam per bbl); this draw rate is limited on the back end by freeze point. The diesel draw includes a steam stripper at 14.54 kg/m³(5.1 lb steam per bbl), and this draw is controlled to a 360° C. (680° F.) D86 95% point. The AGO draw includes a steam stripper at 14.82 kg/m³(5.2 lb steam per bbl), which sets the overflash at 2 vol % on crude. The crude tower also contains 3 pumparounds for top, diesel, and AGO. Diesel pumparound provides heat to the heavy naphtha stripper reboiler and debutanizer reboiler along with controlling desalter operating temperature via swing heat. The crude tower overhead vapor is compressed and recontacted with naphtha before entering an amine scrubber for H2S removal and is then routed to the cracker complex. Recontact naphtha is debutanized to remove LPGs which are amine washed and routed to the cracker complex. The debutanized naphtha is routed separately from the heavy naphtha to the cracker complex. The bottoms of the atmospheric column is steam stripped at 28.5 kg/m³(10 lb steam/bbl).
Atmospheric residue (AR) 150 from the atmospheric distillation zone 104 is further distilled in the vacuum distillation zone 108, which fractionates the atmospheric residue 150 into light and heavy vacuum gas oil streams 160 which are fed to the VGO hydrotreating zone 340, as well as a vacuum residue stream 162, for instance, which can be routed to a fuel oil (FO) pool (such as a high sulfur fuel oil pool). The vacuum distillation zone 108 can include well-known design features, such as operation at reduced pressure levels, for instance, in the range of about 15-50 mm Hg absolute pressure, which can be maintained by steam ejectors or mechanical vacuum pumps. Vacuum bottoms may be quenched to minimize coking, for instance, via exchange against crude at 650° F. Vacuum distillation can be accomplished in a single stage or in plural stages. In certain embodiments, the atmospheric residue 150 is heated in a direct fired furnace and charged to vacuum fractionator at about 400-425° C.
In one embodiment, the atmospheric residue is heated to 409.4° C. (769° F.) in the vacuum furnace to achieve a flash zone conditions of 401.7° C. (755° F.) and about 0.045 bar (34 mmHg). The vacuum column is designed for a 537.8° C. (1000° F.) theoretical cut point by removing LVGO and HVGO from the vacuum residue. The overhead vacuum system can include two parallel trains of jet ejectors each including three jets. A common vacuum pump is used at the final stage. In one embodiment, the vacuum tower is sized for a 0.35 C-Factor and about a 14.68 lpm/m²(0.3 gpm/ft²) wetting rate at the bottom of the wash zone. Wash zone slop wax is recycled to the vacuum furnace to minimize fuel oil production. Vacuum bottoms are quenched via exchange against crude to 343.3° C. (650° F.) to minimize coking.
The saturated gas plant 106 generally comprises a series of operations including fractionation and in certain systems absorption and fractionation, as is well known, with an objective to process light ends in order to separate fuel gas range components from the LPG range components that are suitable as a steam cracking zone feedstock. The saturated gas plant 106 includes off gas compression and recontacting to maximize LPG recovery, LPG fractionation from light naphtha, and off gas/LPG amine treatment. The light ends that are processed in one or more saturated gas plants within embodiments of the integrated system and process herein are derived from the crude distillation, such as light ends and LPG from a VGO hydrotreating zone and/or a py-gas hydrotreating zone and/or a naphtha hydrotreating zone. The products from the saturated gas plant 106 include: off gas 114, containing methane and ethane, that is passed to a fuel gas system; and light ends 112, containing C3+, that is passed to the mixed feed steam cracking unit 700.
In certain embodiments, a suitable saturated gas plant 106 includes amine and caustic washing of liquid feed, and amine treatment of vapor feed, before subsequent steps. As is well-known, light naphtha absorbs C4 and heavier hydrocarbons from the vapor as it travels upward through an absorber/deethanizer. Offgas from the absorber/deethanizer is compressed and sent to a refinery fuel gas system. In the system and process herein a deethanizer bottoms stream from the saturated gas plant 106 sent to the mixed feed steam cracking zone 700 as an additional source of feed.
A light kerosene fraction 122 is processed in a kerosene sweetening zone 210, to remove unwanted sulfur compounds, as is well-known, and recover a treated kerosene that can be used as a fuel product 212, for instance, jet fuel such as Jet A type jet fuel and optionally other fuel products. For instance, a suitable kerosene sweetening zone 210 can be based on Merox™ technology (Honeywell UOP, United States), Sweetn'K technology (Axens, IFP Group Technologies, France), or Thiolex™ technology (Merichem Company, United States). Processes of these types are well-established commercially and appropriate operating conditions are well known to produce fuel product 212 and byproducts disulfide oils 214. In certain kerosene sweetening technologies impregnated carbon is utilized as catalyst to promote conversion to disulfide oil. In certain embodiments, common treatment of sour water from the kerosene sweetening zone 210 and other unit operations is employed to maximize process integration. Disulfide oil is optionally passed to one of the integrated hydroprocessing units, for instance, shown in FIG. 12 routed to the diesel hydrotreating zone 220.
The heavy kerosene fraction 124 and medium atmospheric gas oil fraction 142 are processed in a diesel hydrotreating zone 220, in the presence of an effective amount of hydrogen 226. Diesel hydrotreating zone 220 also may process disulfide oil 214 from the kerosene sweetening zone 210, optionally shown in dashed lines. In certain embodiments, all or a portion of hydrogen 226 is derived from a steam cracker product hydrogen 704 stream from the olefins recovery train 730. For instance, a suitable hydrotreating zone 220 can be based on technology commercially available from Honeywell UOP, United States; Chevron Lummus Global LLC, (CLG), United States; Axens, IFP Group Technologies, France; Haldor Topsoe A/S, Denmark; or joint technology from KBR, Inc, United States, and Shell Global Solutions, United States.
The diesel hydrotreating zone 220 operates under conditions effective for removal of a significant amount of the sulfur and other known contaminants, for instance, to meet necessary sulfur specifications for a diesel fuel product 224, such as Euro V diesel. In addition, the hydrotreated naphtha fraction 222 (sometimes referred to as wild naphtha) is recovered from the diesel hydrotreating zone 220, which is routed to the MFSC zone 700 as an additional steam cracking feed. In certain embodiments, the hydrotreated naphtha fraction 222 is routed through the crude complex 100, alone, or in combination with other wild naphtha fractions from within the integrated process.
In certain embodiments, the diesel hydrotreating zone 220 also processes at least a portion of the hydrotreated distillates 342 from the vacuum gas oil hydrotreating zone 340. Any portion not routed to the diesel hydrotreating zone 220 can optionally be passed to the crude complex 100 or routed to the MFSC zone 700. For example, at least 0-100, 50-100, 60-100, 70-100, 80-100, 50-99, 60-99, 70-99 or 80-99 wt % of the total hydrotreated distillates 342 from the vacuum gas oil hydrotreating zone 340 can be routed to the diesel hydrotreating zone 220.
In certain embodiments, the diesel hydrotreating zone 220 also processes at least a portion of the cycle oil 408 from the HOFCC zone 400. Any portion of the cycle oil 408 not routed to the diesel hydrotreating zone 220 can optionally be passed to a fuel oil pool and/or be processed in the integrated gas oil hydroprocessing zone. For example, no more than 0-30, 0-25, 0-20, 5-30, 5-25, 5-20, 10-30, 10-25, or 10-20 wt % of the total cycle oil 408 from the HOFCC zone 400 can be routed to the diesel hydrotreating zone 220.
In certain embodiments, the diesel hydrotreating zone 220 also processes at least a portion of the disulfide oil 214 from the kerosene sweetening zone 210. Any portion of the disulfide oil 214 not routed to the diesel hydrotreating zone 220 can optionally be passed to a fuel oil pool and/or be processed in the integrated gas oil hydroprocessing zone. For example, no more than 0-30, 0-25, 0-20, 5-30, 5-25, 5-20, 10-30, 10-25, or 10-20 wt % of the total disulfide oil 214 from the kerosene sweetening zone 210 can be routed to the diesel hydrotreating zone 220.
The diesel hydrotreating zone 220 can contain one or more fixed-bed, ebullated-bed, slurry-bed, moving bed, continuous stirred tank (CSTR), or tubular reactors, in series and/or parallel arrangement. Additional equipment, including exchangers, furnaces, feed pumps, quench pumps, and compressors to feed the reactor(s) and maintain proper operating conditions, are well known and are considered part of the diesel hydrotreating zone 220. In addition, equipment, including pumps, compressors, high temperature separation vessels, low temperature separation vessels and the like to separate reaction products and provide hydrogen recycle within the diesel hydrotreating zone 220, are well known and are considered part of the diesel hydrotreating zone 220.
In certain embodiments, the diesel hydrotreating zone 220 contains a layered bed reactor with three catalyst beds and having interbed quench gas, and employs a layered catalyst system with the layer of hydrodewaxing catalyst positioned between beds of hydrotreating catalyst. In high capacity operations, two or more parallel trains of reactors are utilized. In such embodiments, flow in the diesel hydrotreating zone 220 is split after the feed pump into parallel trains, wherein each train contains feed/effluent heat exchangers, feed heater, a reactor and the hot separator. The trains recombine after the hot separators. Tops from the hot separators are combined and passed to a cold separator. Bottoms from the hot separators and from the cold separator are passed to a product stripper to produce stabilized ULSD and wild naphtha. Tops from the cold separator are subjected to absorption and amine scrubbing, and recycle hydrogen is recovered and passed to the reaction zone.
In certain embodiments, the diesel hydrotreating zone 220 operating conditions include:
a reactor inlet temperature (° C.) in the range of from about 296-453, 296-414, 296-395, 336-453, 336-414, 336-395, 355-453, 355-414, 355-395 or 370-380;
a reactor outlet temperature (° C.) in the range of from about 319-487, 319-445, 319-424, 361-487, 361-445, 361-424, 382-487, 382-445, 382-424 or 400-406;
a start of run (SOR) reaction temperature (° C.), as a weighted average bed temperature (WABT), in the range of from about 271-416, 271-379, 271-361, 307-416, 307-379, 307-361, 325-416, 325-379, 325-361 or 340-346;
an end of run (EOR) reaction temperature (° C.), as a WABT, in the range of from about 311-476, 311-434, 311-414, 352-476, 352-434, 352-414, 373-476, 373-434, 373-414 or 390-396;
a reaction inlet pressure (bar) in the range of from about 48-72, 48-66, 48-63, 54-72, 54-66, 54-63, 57-72, 57-66 or 57-63;
a reaction outlet pressure (bar) in the range of from about 44-66, 44-60, 44-58, 49-66, 49-60, 49-58, 52-66, 52-60 or 52-58;
a hydrogen partial pressure (bar) (outlet) in the range of from about 32-48, 32-44, 32-42, 36-48, 36-44, 36-42, 38-48, 38-44 or 38-42;
a hydrogen treat gas feed rate (standard liters per liter of hydrocarbon feed, SLt/Lt) up to about 400, 385, 353 or 337, in certain embodiments from about 256-385, 256-353, 256-337, 289-385, 289-353, 289-337, 305-385, 305-353 or 305-337;
a hydrogen quench gas feed rate (SLt/Lt) up to about 100, 85, 78 or 75, in certain embodiments from about 57-85, 57-78, 57-75, 64-85, 64-78, 64-75, 68-85, 68-78, 68-75; and
a make-up hydrogen feed rate (SLt/Lt) up to about 110, 108, 100 or 95, in certain embodiments from about 70-108, 70-100, 70-95, 80-108, 80-100, 80-95, 85-108, 85-100 or 85-95.
Effective hydrotreating catalyst in the diesel hydrotreating zone 220 include those possessing hydrotreating functionality and which generally contain one or more active metal component of metals or metal compounds (oxides or sulfides) selected from the Periodic Table of the Elements IUPAC Groups 6-10. In certain embodiments, the active metal component is one or more of cobalt, nickel, tungsten and molybdenum. The active metal component is typically deposited or otherwise incorporated on a support, such as amorphous alumina, amorphous silica alumina, zeolites, or combinations thereof. In certain embodiments, the catalyst used in the diesel hydrotreating zone 220 includes one or more catalyst selected from cobalt/molybdenum, nickel/molybdenum, nickel/tungsten, and cobalt/nickel/molybdenum. Combinations of one or more of cobalt/molybdenum, nickel/molybdenum, nickel/tungsten and cobalt/nickel/molybdenum, can also be used. The combinations can be composed of different particles containing a single active metal species, or particles containing multiple active species. In certain embodiments, cobalt/molybdenum hydrodesulfurization catalyst is suitable. Effective liquid hourly space velocity values (h⁻¹), on a fresh feed basis relative to the hydrotreating catalysts, are in the range of from 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 diesel hydrotreating zone 220 have an expected lifetime in the range of about 28-44 months, in certain embodiments about 34-38 months.
In certain embodiments, hydrodewaxing catalyst is also added. In such embodiments, effective hydrodewaxing catalysts include those typically used for isomerizing and cracking paraffinic hydrocarbon feeds to improve cold flow properties, such as catalysts comprising Ni, W, or molecular sieves or combinations thereof.
Catalyst comprising NiW, zeolite with medium or large pore sizes, or a combination thereof are suitable, along with catalyst comprising aluminosilicate molecular sieves such as zeolites with medium or large pore sizes. Effective commercial zeolites include for instance ZSM-5, ZSM-11, ZSM-12, ZSM 22, ZSM-23, ZSM 35, and zeolites of type beta and Y. Hydrodewaxing catalyst is typically supported on an oxide support such as Al₂O₃, SiO₂, ZrO₂, zeolites, zeolite-alumina, alumina-silica, alumina-silica-zeolite, activated carbon, and mixtures thereof. Effective liquid hourly space velocity values (h⁻¹), on a fresh feed basis relative to the hydrodewaxing catalyst, are in the range of from 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 to 2.4. Suitable hydrodewaxing catalysts used in the diesel hydrotreating zone 220 have an expected lifetime in the range of about 28-44 months, in certain embodiments about 34-38 months.
VGO 160 from the vacuum distillation zone 108 is processed in a gas oil hydroprocessing zone, in the presence of an effective amount of hydrogen 308. In certain embodiments, all or a portion of hydrogen 308 is derived from the steam cracker products. In certain embodiments (not shown in FIGS. 12 and 13), all or a portion of the atmospheric gas oil from the atmospheric distillation zone 104 can also be treated in the gas oil hydroprocessing zone, for instance, a full range AGO, or a fraction thereof such as heavy atmospheric gas oil stream 144. Further, a portion of the selected fraction can be routed to the gas oil hydroprocessing zone, while the remainder bypasses gas oil hydroprocessing.
As shown in FIG. 12, a VGO HT 340 operates under suitable hydrotreating conditions, and generally produces LPG, cracked products 342 and hydrotreated gas oil 344. Cracked products 342 are routed to the diesel hydrotreater, and hydrotreated gas oil 344 is routed to the HOFCC zone 400. VGO HT 340 can operate under mild, moderate or severe conditions, depending on factors including the feedstock and the desired degree of conversion.
The gas oil hydrotreating zone 340 generally operates under conditions effective for removal of a significant amount of the sulfur and other known contaminants, and for conversion of the VGO 160 feed into a major proportion of hydrotreated gas oil 344 that is passed to the HOFCC zone 400, and minor proportions of distillates and hydrotreated naphtha 342. The hydrotreated gas oil fraction 344 generally contains the portion of the VGO HT 340 effluent that is at or above the AGO, H-AGO or VGO range.
For instance, a suitable VGO HT zone 340 can be based on technology commercially available from Honeywell UOP, United States; Chevron Lummus Global LLC, (CLG), United States; Axens, IFP Group Technologies, France; or Shell Global Solutions, United States.
The gas oil hydrotreating zone 340 can contain one or more fixed-bed, ebullated-bed, slurry-bed, moving bed, continuous stirred tank (CSTR), or tubular reactors, in series and/or parallel arrangement. Additional equipment, including exchangers, furnaces, feed pumps, quench pumps, and compressors to feed the reactor(s) and maintain proper operating conditions, are well known and are considered part of the gas oil hydrotreating zone 340. In addition, equipment, including pumps, compressors, high temperature separation vessels, low temperature separation vessels and the like to separate reaction products and provide hydrogen recycle within the gas oil hydrotreating zone 340, are well known and are considered part of the gas oil hydrotreating zone 340.
In certain embodiments, the gas oil hydrotreating zone 340 operating conditions include:
a reactor inlet temperature (° C.) in the range of from about 324-496, 324-453, 324-431, 367-496, 367-453, 367-431, 389-496, 389-453, 389-431, or 406-414;
a reactor outlet temperature (° C.) in the range of from about 338-516, 338-471, 338-449, 382-516, 382-471, 382-449, 404-516, 404-471, 404-449 or 422-430;
a start of run (SOR) reaction temperature (° C.), as a weighted average bed temperature (° C.) (WABT), in the range of from about 302-462, 302-422, 302-402, 342-462, 342-422, 342-402, 362-462, 362-422, 362-402 or 378-384;
an end of run (EOR) reaction temperature (° C.), as a WABT, in the range of from about 333-509, 333-465, 333-443, 377-509, 377-465, 377-443, 399-509, 399-465, 399-443 or 416-424;
a reaction inlet pressure (bar) in the range of from about 91-137, 91-125, 91-119, 102-137, 102-125, 102-119, 108-137, 108-125, 108-119 or 110-116;
a reaction outlet pressure (bar) in the range of from about 85-127, 85-117, 85-111, 96-127, 96-117, 96-111, 100-127, 100-117 or 100-111;
a hydrogen partial pressure (bar) (outlet) in the range of from about 63-95, 63-87, 63-83, 71-95, 71-87, 71-83, 75-95, 75-87, 75-83 or 77-81;
a hydrogen treat gas feed rate (SLt/Lt) up to about 525, 510, 465 or 445, in certain embodiments from about 335-510, 335-465, 335-445, 380-510, 380-465, 380-445, 400-510, 400-465 or 400-445;
a hydrogen quench gas feed rate (SLt/Lt) up to about 450, 430, 392 or 375, in certain embodiments from about 285-430, 285-392, 285-375, 320-430, 320-392, 320-375, 338-430, 338-392 or 338-375 and
a make-up hydrogen feed rate (SLt/Lt) up to about 220, 200, 180 or 172, in certain embodiments from about 130-200, 130-180, 130-172, 148-200, 148-180, 148-172, 155-200, 155-180 or 155-172;
Effective hydrotreating catalyst in the gas oil hydrotreating zone 340 include those possessing hydrotreating functionality, for hydrodesulfurization and hydrodenitrification. Such catalyst generally contain one or more active metal component of metals or metal compounds (oxides or sulfides) selected from the Periodic Table of the Elements IUPAC Groups 6-10. In certain embodiments, the active metal component is one or more of cobalt, nickel, tungsten and molybdenum. The active metal component is typically deposited or otherwise incorporated on a support, such as amorphous alumina, amorphous silica alumina, zeolites, or combinations thereof. In certain embodiments, the catalyst used in the gas oil hydrotreating zone 340 includes one or more beds selected from cobalt/molybdenum, nickel/molybdenum, nickel/tungsten, and cobalt/nickel/molybdenum. Combinations of one or more beds of cobalt/molybdenum, nickel/molybdenum, nickel/tungsten and cobalt/nickel/molybdenum, can also be used. The combinations can be composed of different particles containing a single active metal species, or particles containing multiple active species. In certain embodiments, a combination of cobalt/molybdenum catalyst and nickel/molybdenum catalyst are effective for hydrodesulfurization and hydrodenitrification. One or more series of reactors can be provided, with different catalysts in the different reactors of each series. For instance, a first reactor includes cobalt/molybdenum catalyst and a second reactor includes nickel/molybdenum catalyst. Effective liquid hourly space velocity values (h⁻¹), on a fresh feed basis relative to the hydrotreating catalysts, are in the range of from 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, 0.4-2.0 or 0.5-1.0. Suitable catalyst used in the gas oil hydrotreating zone 340 have an expected lifetime in the range of about 28-44 months, in certain embodiments about 34-38 months.
In certain embodiments, the gas oil hydrotreating zone 340 contains one or more trains of reactors, with a first reactor having two catalyst beds with two quench streams including an interbed quench stream, and a second reactor having one catalyst bed with a quench stream. In high capacity operations, two or more parallel trains of reactors are utilized. In such embodiments, flow in gas oil hydrotreating zone 340 is split after the feed pump into parallel trains, wherein each train contains feed/effluent heat exchangers, feed heater, a reactor and the hot separator. The trains recombine after the hot separators. Tops from the hot separators are combined and passed to a cold separator. Bottoms from the hot separators are passed to a hot flash drum. Bottoms from the cold separator and tops from the hot flash drum are passed to a low pressure flash drum to remove off gasses. Hot flash liquid bottoms and low pressure flash bottoms are passed to a stripper to recover hydrotreated gas oil and wild naphtha. Tops from the cold separator are subjected to absorption and amine scrubbing, and recycle hydrogen is recovered and passed to the reaction zone.
Under the above conditions and catalyst selections, exemplary products from the gas oil hydrotreating zone 340 include LPG in the range of about 0.1-0.5 wt %, naphtha in the range of about 0.5-1 wt %, and hydrotreated VGO in the range of about 98.5-99.4 wt %. In other embodiments, conversion of gas oil can be in the range of up to about 30 wt % under mild or moderate hydrotreating conditions, and about 30-80 wt % under severe hydrotreating conditions.
In certain embodiments, as shown in FIG. 2, a VGO-HCK zone 310 operates under suitable hydrocracking conditions, and generally produces LPG, a hydrocracked naphtha intermediate 312, a diesel fuel product 314, and hydrotreated gas oil 344. Hydrocracked naphtha 312 from the VGO HCK 310 is routed to the MFSC zone 700 (directly, or through the crude complex 100). Hydrotreated gas oil 344 is routed to the HOFCC zone 400. The diesel fuel fraction 314 is recovered as fuel, for instance, Euro V Diesel, and can be combined with the diesel fuel fraction 224 from the diesel hydrotreater 220. VGO HCK 310 can operate under mild, moderate or severe conditions, depending on factors including the feedstock and the desired degree of conversion.
The gas oil hydrocracking zone 310 generally operates under conditions effective for removal of a significant amount of the sulfur and other known contaminants, and for conversion of the VGO 160 feed into a major proportion of hydrocracked products and a minor portion of unconverted, hydrotreated product that is passed to the HOFCC zone 400.
For instance, a suitable VGO HCK zone 310 can be based on technology commercially available from Honeywell UOP, United States; Chevron Lummus Global LLC, (CLG), United States; Axens, IFP Group Technologies, France; or Shell Global Solutions, United States.
The gas oil hydrocracking zone 310 can contain one or more fixed-bed, ebullated-bed, slurry-bed, moving bed, continuous stirred tank (CSTR), or tubular reactors, in series and/or parallel arrangement. Additional equipment, including exchangers, furnaces, feed pumps, quench pumps, and compressors to feed the reactor(s) and maintain proper operating conditions, are well known and are considered part of the gas oil hydrocracking zone 310. In addition, equipment, including pumps, compressors, high temperature separation vessels, low temperature separation vessels and the like to separate reaction products and provide hydrogen recycle within the gas oil hydrocracking zone 310, are well known and are considered part of the gas oil hydrocracking zone 310.
In certain embodiments, gas oil hydrocracking zone 310 mild operating conditions include:
a reactor inlet temperature in the range of from about 329-502, 329-460, 329-440, 372-502, 372-460, 372-440, 394-502, 394-460, 394-440 or 412-420;
a reactor outlet temperature in the range of from about 338-516, 338-471, 338-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450 or 422-430;
a start of run (SOR) reaction temperature, as a weighted average bed temperature (WABT), in the range of from about 310-475, 310-435, 310-415, 350-475, 350-435, 350-415, 370-475, 370-435, 370-415 or 390-397;
an end of run (EOR) reaction temperature, as a WABT, in the range of from about 338-516, 338-471, 338-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450 or 422-430;
a reaction inlet pressure (bar) in the range of from about 108-161, 108-148, 108-141, 121-161, 121-148, 121-141, 128-161, 128-148, 128-141 or 131-137;
a reaction outlet pressure (bar) in the range of from about 100-150, 100-137, 100-130, 112-150, 112-137, 112-130, 118-150, 118-137 or 118-130;
a hydrogen partial pressure (bar) (outlet) in the range of from about 77-116, 77-106, 77-101, 87-116, 87-106, 87-101, 92-116, 92-106, 92-101 or 94-98;
a hydrogen treat gas feed rate (SLt/Lt) up to about 530, 510, 470 or 450, in certain embodiments from about 340-510, 340-470, 340-450, 382-510, 382-470, 382-450, 400-510, 400-470, 400-450 or 410-440;
a hydrogen quench gas feed rate (SLt/Lt) up to about 850, 835, 765 or 730, in certain embodiments from about 556-835, 556-765, 556-730, 625-835, 625-765, 625-730, 660-835, 660-765, 660-730 or 680-710; and
a make-up hydrogen feed rate (SLt/Lt) up to about 225, 215, 200 or 190, in certain embodiments from about 143-215, 143-200, 143-190, 161-215, 161-200, 161-190, 170-215, 170-200 or 170-190;
Effective hydrocracking catalyst in the gas oil hydrocracking zone 310 include generally about 5-40 wt % based on the weight of the catalyst, of one or more active metal component of metals or metal compounds (oxides or sulfides) selected from the Periodic Table of the Elements IUPAC Groups 6-10. In certain embodiments, the active metal component is one or more of molybdenum, tungsten, cobalt or nickel. The active metal component is typically deposited or otherwise incorporated on a support, such as amorphous alumina, amorphous silica alumina, zeolites, or combinations thereof. In certain embodiments, alone or in combination with the above metals, platinum group metals such as platinum and/or palladium, may be present as a hydrogenation component, generally in an amount of about 0.1-2 wt % based on the weight of the catalyst. Effective liquid hourly space velocity values (h⁻¹), on a fresh feed basis relative to the hydrocracking catalysts, are in the range of from 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, 0.4-2.0 or 0.5-1.0. Suitable catalyst used in the gas oil hydrocracking zone 310 have an expected lifetime in the range of about 18-30 months, in certain embodiments about 22-26 months.
In certain embodiments, the gas oil hydrocracking zone 310 can contain one or more fixed-bed, ebullated-bed, slurry-bed, moving bed, continuous stirred tank (CSTR), or tubular reactors, in series and/or parallel arrangement. Additional equipment, including high and low pressure exchangers, furnaces, feed pumps, quench pumps, and compressors to feed the reactor(s) and maintain proper operating conditions, are well known and are considered part of the gas oil hydrocracking zone 310. In addition, equipment, including pumps, compressors, high temperature separation vessels, low temperature separation vessels and the like to separate reaction products and provide hydrogen recycle within the gas oil hydrocracking zone 310, are well known and are considered part of the gas oil hydrocracking zone 310.
Under the above conditions and catalyst selections, exemplary products from the gas oil hydrocracking zone 310 include LPG in the range of about 5-10 wt %, naphtha in the range of about 30-60 wt %, diesel in the range of about 20-50 wt %, and hydrotreated VGO in the range of about 0-30 wt % and/or unconverted oil in the range of about 0-15 wt %.
The hydrotreated gas oil fraction 344 is routed to the HOFCC zone 400. In certain embodiments, as shown in dashed lines, heavy atmospheric gas oil 144 is also routed the HOFCC zone 400, bypassing the vacuum gas oil hydrotreating zone 340. In certain embodiments, as shown in dashed lines, heavy atmospheric gas oil 144 is subjected to hydrotreating prior to passage to the HOFCC zone 400, for instance with the other feeds to the vacuum gas oil hydrotreating zone 340.
Products include fuel gas and LPG to that are passed to an unsaturated gas plant 402, FCC naphtha 406, which can be routed to a naphtha hydrotreating zone 540 as shown in FIG. 14; a light cycle oil stream 408 that is passed to the diesel hydrotreating zone 220 and/or routed to a fuel oil pool, and a slurry oil or heavy cycle oil stream 410 that can be routed to a fuel oil pool or used as feedstock for production of carbon black. In certain embodiments, all or a portion of FCC naphtha 406 can be routed to aromatics extraction zone 600 without hydrotreating.
The unsaturated gas plant 402 and an HOFCC recovery section (not shown), which are operated to recover a C2− stream 414 that is passed to an olefins recovery train 730. In certain embodiments HOFCC light ends are selectively treated for removal of contaminants including oxygen, nitrous oxides and nitriles, while preserving ethylene content, before being passed to the olefins recovery train 730. Furthermore, a C3+ stream 416, generally containing C3 s and C4s, is recovered from the HOFCC recovery section and passed to the steam cracking zone 700 as additional feed. In certain embodiments, the C3+ stream 416 stream is sent to a splitter, which can be integrated with or separate from the olefins recovery train 730, to recover olefins, and the remaining LPGs are routed to the steam cracking zone 700.
In certain embodiments, the vacuum gas oil hydrotreating zone 340 can be avoided and the HOFCC and associated regenerator are operated to treat the products from the unit, including flue gases produced in the catalyst regenerator, for control of sulfur. In other embodiments, the vacuum gas oil hydrotreating zone 340 is utilized, as treating the VGO reduces catalyst consumption in the HOFCC and enhances yield. In embodiments in which the vacuum gas oil hydrotreating zone 340 is utilized, flue gas desulfurization of flue gases produced in the catalyst regenerator is also provided.
As shown in FIGS. 12 and 14, a portion of the cycle oil product from the HOFCC, cycle oil 408, is passed to the diesel hydrotreating zone 220, and a portion of the cycle oil product from the HOFCC, cycle oil 412, is diverted, for instance, for inclusion in a fuel oil pool. A quantity (wt %) of 0-5, 0-10, 0-15, or 0-20 of cycle oil stream 408 is passed to the diesel hydrotreating zone 220 and the remainder passed to a fuel oil pool. Slurry oil 410 is also recovered from the HOFCC zone 400. This heavy product is an effective feedstock for carbon black production, or can be included in a fuel oil pool.
There are many commercially available for maximizing the propylene production utilizing an FCC unit. A suitable HOFCC zone 400 can be, for example, based on technology commercially available from Axens, IFP Group Technologies, France; Honeywell UOP, United States; China Petroleum & Chemical Corporation (Sinopec), China; KBR, Inc, United States; or Chicago Bridge & Iron Company N.V. (CB&I), the Netherlands.
The HOFCC zone 400 can have one or more risers/reactors, a disengager/stripper and one or more regenerators. If plural reactors are implemented, propylene yield and selectivity can be maximized.
In certain embodiments, a fluid catalytic cracking unit configured with a riser reactor is provided that operates under conditions that promote formation of light olefins, particularly propylene, and that minimize light olefin-consuming reactions including hydrogen-transfer reactions. FIG. 15 is a simplified schematic illustration of a riser fluid catalytic cracking unit. A fluid catalytic cracking unit 420 includes a riser reactor. Fluid catalytic cracking unit 420 includes a reactor/separator 424 having a riser portion 426, a reaction zone 428 and a separation zone 430. Fluid catalytic cracking unit 420 also includes a regeneration vessel 432 for regenerating spent catalyst. A charge 422 is introduced to the reaction zone, in certain embodiments accompanied by steam or other suitable gas for atomization of the feed (not shown). The charge 422, in the integrated process herein hydrotreated gas oil, optionally in combination with atmospheric gas oil such as heavy atmospheric gas oil, is admixed and intimately contacted with an effective quantity of heated fresh or regenerated solid cracking catalyst particles which are conveyed via a conduit 434 from regeneration vessel 432. The feed mixture and the cracking catalyst are contacted under conditions to form a suspension that is introduced into the riser 426. In a continuous process, the mixture of cracking catalyst and hydrocarbon feedstock proceed upward through the riser 426 into reaction zone 428. In riser 426 and reaction zone 428, the hot cracking catalyst particles catalytically crack relatively large hydrocarbon molecules by carbon-carbon bond cleavage.
During the reaction, as is conventional in fluid catalytic cracking operations, the cracking catalysts become coked and hence access to the active catalytic sites is limited or nonexistent. Reaction products are separated from the coked catalyst using any suitable configuration known in fluid catalytic cracking units, generally referred to as the separation zone 430 in a fluid catalytic cracking unit 420, for instance, located at the top of the reactor 424 above the reaction zone 428. The separation zone can include any suitable apparatus known to those of ordinary skill in the art such as, for example, cyclones. The reaction product is withdrawn through conduit 436. Catalyst particles containing coke deposits from fluid cracking of the hydrocarbon feedstock pass through a conduit 438 to regeneration zone 432.
In regeneration zone 432, the coked catalyst comes into contact with a stream of oxygen-containing gas, such as pure oxygen or air, which enters regeneration zone 432 via a conduit 440. The regeneration zone 432 is operated in a configuration and under conditions that are known in typical fluid catalytic cracking operations. For instance, regeneration zone 432 can operate as a fluidized bed to produce regeneration off-gas comprising combustion products which is discharged through a conduit 442. The hot regenerated catalyst is transferred from regeneration zone 432 through conduit 434 to the bottom portion of the riser 426 for admixture with the hydrocarbon feedstock and noted above.
In one embodiment, a suitable a fluid catalytic cracking unit 420 can be similar to that described in U.S. Pat. Nos. 7,312,370, 6,538,169, and 5,326,465, which are incorporated herein by reference. In general, the operating conditions for the reactor of a suitable riser fluid catalytic cracking unit 420 include:
reaction temperature (° C.) of from about 480-650, 480-620, 480-600, 500-650, 500-620, or 500-600;
reaction pressure (bar) of from about 1-20, 1-10, or 1-3;
contact time (in the reactor, seconds) of from about 0.5-10, 0.5-5, 0.5-2, 1-10, 1-5, or 1-2; and
a catalyst to feed ratio of about 1:1 to 15:1, 1:1 to 10:1, 1:1 to 20:1, 8:1 to 20:1, 8:1 to 15:1, or 8:1 to 10:1.
In certain embodiments, a fluid catalytic cracking unit configured with a downflow reactor is provided that operates under conditions that promote formation of light olefins, particularly propylene, and that minimize light olefin-consuming reactions including hydrogen-transfer reactions. FIG. 16 is a simplified schematic illustration of a downflow fluid catalytic cracking unit. A fluid catalytic cracking unit 460 includes a reactor/separator 464 having a reaction zone 468 and a separation zone 470. Fluid catalytic cracking unit 460 also includes a regeneration zone 472 for regenerating spent catalyst. In particular, a charge 462 is introduced to the reaction zone, in certain embodiments accompanied by steam or other suitable gas for atomization of the feed (not shown). An effective quantity of heated fresh or hot regenerated solid cracking catalyst particles from regeneration zone 472 is conveyed to the top of reaction zone 468 also transferred, for instance, through a downwardly directed conduit or pipe 474, commonly referred to as a transfer line or standpipe, to a withdrawal well or hopper (not shown) at the top of reaction zone 468. Hot catalyst flow is typically allowed to stabilize in order to be uniformly directed into the mix zone or feed injection portion of reaction zone 468. The charge 462 is injected into a mixing zone through feed injection nozzles typically situated proximate to the point of introduction of the regenerated catalyst into reaction zone 468. These multiple injection nozzles result in the thorough and uniform mixing of the hot catalyst and the charge 462, in the integrated process herein hydrotreated gas oil, optionally in combination with atmospheric gas oil such as heavy atmospheric gas oil. Once the charge contacts the hot catalyst, cracking reactions occur.
The reaction vapor of hydrocarbon cracked products, unreacted feed and catalyst mixture quickly flows through the remainder of reaction zone 468 and into the rapid separation zone 470 at the bottom portion of reactor/separator 464. Cracked and uncracked hydrocarbons are directed through a conduit or pipe 476 to a conventional product recovery section known in the art to yield fluid catalytic cracking products light olefins, gasoline and cycle oil, with a maximized propylene yield. If necessary for temperature control, a quench injection can be provided near the bottom of reaction zone 468 immediately before the separation zone 470. This quench injection quickly reduces or stops the cracking reactions and can be utilized for controlling cracking severity.
The reaction temperature, i.e., the outlet temperature of the downflow reactor, can be controlled by opening and closing a catalyst slide valve (not shown) that controls the flow of regenerated catalyst from regeneration zone 472 into the top of reaction zone 468. The heat required for the endothermic cracking reaction is supplied by the regenerated catalyst. By changing the flow rate of the hot regenerated catalyst, the operating severity or cracking conditions can be controlled to produce the desired product slate. A stripper 478 is also provided for separating oil from the catalyst, which is transferred to regeneration zone 472. The catalyst from separation zone 470 flows to the lower section of the stripper 478 that includes a catalyst stripping section into which a suitable stripping gas, such as steam, is introduced through streamline 480. The stripping section is typically provided with several baffles or structured packing (not shown) over which the downwardly flowing catalyst 488 passes counter-currently to the flowing stripping gas. The upwardly flowing stripping gas, which is typically steam, is used to “strip” or remove any additional hydrocarbons that remain in the catalyst pores or between catalyst particles. The stripped or spent catalyst is transported by lift forces from the combustion air stream 490 through a lift riser of the regeneration zone 470. This spent catalyst, which can also be contacted with additional combustion air, undergoes controlled combustion of any accumulated coke. Flue gases are removed from the regenerator via conduit 492. In the regenerator, the heat produced from the combustion of the by-product coke is transferred to the catalyst raising the temperature required to provide heat for the endothermic cracking reaction in the reaction zone 468. According to the process herein, since the light solvent feedstock is combined with the heavy feedstock as the feed 462, the solvent to oil ratio in the initial solvent deasphalting/demetallizing process is selected so as to provide sufficient coking of the catalyst to provide the heat balance during regeneration.
In one embodiment, a suitable fluid catalytic cracking unit 460 that can be employed in the process described herein can be similar to those described in U.S. Pat. No. 6,656,346, and US Patent Publication Number 2002/0195373, both of which are incorporated herein by reference. Important properties of downflow reactors include introduction of feed at the top of the reactor with downward flow, shorter residence time as compared to riser reactors, and high catalyst to oil ratio, for instance, in the range of about 20:1 to about 30:1. In general, the operating conditions for the reactor of a suitable propylene production downflow FCC unit include
reaction temperature (° C.) of from about 550-650, 550-630, 550-620, 580-650, 580-630, 580-620, 590-650, 590-630, 590-620;
reaction pressure (bar) of from about 1-20, 1-10, or 1-3;
contact time (in the reactor, seconds) of from about 0.1-30, 0.1-10, 0.1-0.7, 0.2-30, 0.2-10, or 0.2-0.7; and
a catalyst to feed ratio of about 1:1 to 40:1, 1:1 to 30:1, 10:1 to 30:1, or 10:1 to 30:1.
The catalyst used in the process described herein can be conventionally known or future developed catalysts used in FCC processes, such as zeolites, silica-alumina, carbon monoxide burning promoter additives, bottoms cracking additives, light olefin-producing additives and any other catalyst additives routinely used in the FCC process. In certain embodiments, suitable cracking zeolites in the FCC process include zeolites Y, REY, USY, and RE-USY. For enhanced naphtha cracking potential, a preferred shaped selective catalyst additive can be employed, such as those used in FCC processes to produce light olefins and increase FCC gasoline octane is ZSM-5 zeolite crystal or other pentasil type catalyst structure. This ZSM-5 additive can be mixed with the cracking catalyst zeolites and matrix structures in conventional FCC catalyst and is particularly suitable to maximize and optimize the cracking of the crude oil fractions in the downflow reaction zones.
FCC naphtha 406 is also recovered from the HOFCC zone 400. In certain embodiments, as depicted for instance in FIGS. 12, 13 and 14, FCC naphtha 406 is further treated in the naphtha hydrotreating zone 540 in the presence of an effective amount of hydrogen 542. Effluent fuel gas 544 is recovered and, for instance, passed to a fuel gas system. In certain embodiments, all or a portion of hydrogen 542 is derived from the steam cracker products.
The cracked naphtha hydrotreating zone 540 operates under conditions effective to ensure removal of substantially all nitrogen, since nitrogen is a limiting contaminant in the aromatics extraction and subsequent processes. Due to the high temperatures conditions effective for and nitrogen removal, saturation of aromatics occurs, for instance, in the range of about 15% saturation, ahead of recovery. Effluents from the cracked naphtha hydrotreating zone 540 are a hydrotreated FCC naphtha stream 546, and fuel gas 544.
A suitable cracked naphtha hydrotreating zone 540 can be based on technology commercially available from Honeywell UOP, United States; Chevron Lummus Global LLC, (CLG), United States; or Axens, IFP Group Technologies, France.
The effluent from the cracked naphtha hydrotreating reactor generally contain C5-C9+ hydrocarbons. In certain embodiments, C5-C9+ hydrocarbons are passed to the aromatics extraction zone 600, and the aromatics extraction zone 600 includes a depentanizing step to remove C5s. In other embodiments and as shown for instance in FIGS. 12 and 13, cracked naphtha hydrotreating zone 540 includes a depentanizing step to remove C5s, which are recycled as stream 548 to the mixed feed steam cracking zone 700. The hydrotreated FCC naphtha stream 546, generally containing C6-C9+ hydrocarbons, is passed to the aromatics extraction zone 600.
The FCC naphtha hydrotreating zone 540 can contain one or more fixed-bed, ebullated-bed, slurry-bed, moving bed, continuous stirred tank (CSTR), or tubular reactors, in series and/or parallel arrangement. Additional equipment, including exchangers, furnaces, feed pumps, quench pumps, and compressors to feed the reactor(s) and maintain proper operating conditions, are well known and are considered part of the FCC naphtha hydrotreating zone 540. In addition, equipment, including pumps, compressors, high temperature separation vessels, low temperature separation vessels and the like to separate reaction products and provide hydrogen recycle within the FCC naphtha hydrotreating zone 540, are well known and are considered part of the FCC naphtha hydrotreating zone 540.
The FCC naphtha hydrotreating zone 540 is operated under conditions effective to treat FCC naphtha to produce hydrotreated naphtha 546 that can be used as additional feed to the aromatics extraction zone 600 for recovery of BTX streams. In certain embodiments hydrotreated naphtha 546 can be used for fuel production.
In certain embodiments, the cracked naphtha hydrotreating zone 540 operating conditions include:
a reactor inlet temperature in the range of from about 293-450, 293-410, 293-391, 332-450, 332-410, 332-391, 352-450, 352-410, 352-391; or 368-374;
a reactor outlet temperature in the range of from about 316-482, 316-441, 316-420, 357-482, 357-441, 357-420, 378-482, 378-441, 378-420 or 396-404;
a start of run (SOR) reaction temperature, as a weighted average bed temperature (WABT), in the range of from about 284-436, 284-398, 284-379, 322-436, 322-398, 322-379, 341-436, 341-398, 341-379 or 357-363;
an end of run (EOR) reaction temperature, as a WABT, in the range of from about 316-482, 316-441, 316-420, 357-482, 357-441, 357-420, 378-482, 378-441, 378-420 or 396-404;
a reaction inlet pressure (bar) in the range of from about 44-66, 44-60, 44-58, 49-66, 49-60, 49-58, 52-66, 52-60, 52-58 or 53-56;
a reaction outlet pressure (bar) in the range of from about 39-58, 39-53, 39-51, 43-58, 43-53, 43-51, 46-58, 46-53, or 46-51
a hydrogen partial pressure (bar) (outlet) in the range of from about 22-33, 22-30, 22-29, 25-33, 25-30, 25-29, 26-33, 26-30, or 26-29;
a hydrogen treat gas feed rate (SLt/Lt) up to about 640, 620, 570 or 542, in certain embodiments from about 413-620, 413-570, 413-542, 465-620, 465-570, 465-542, 491-620, 491-570 or 491-542;
a hydrogen quench gas feed rate (SLt/Lt) up to about 95, 85, 78 or 75, in certain embodiments from about 57-85, 57-78, 57-75, 64-85, 64-78, 64-75, 68-85, 68-78 or 68-75; and
a make-up hydrogen feed rate up to about 120, 110 or 102, in certain embodiments from about 78-120, 78-110, 78-102, 87-120, 87-110, 87-102, 92-120, 92-110, 92-102 or 95-100.
Effective hydrotreating catalyst in the FCC naphtha hydrotreating zone 540 include those possessing hydrotreating functionality and which generally contain one or more active metal component of metals or metal compounds (oxides or sulfides) selected from the Periodic Table of the Elements IUPAC Groups 6-10. In certain embodiments, the active metal component is one or more of cobalt, nickel, tungsten and molybdenum. The active metal component is typically deposited or otherwise incorporated on a support, such as amorphous alumina, amorphous silica alumina, zeolites, or combinations thereof. In certain embodiments, the catalyst used in the FCC naphtha hydrotreating zone 540 includes one or more catalyst selected from cobalt/molybdenum, nickel/molybdenum, nickel/tungsten, and cobalt/nickel/molybdenum. Combinations of one or more of cobalt/molybdenum, nickel/molybdenum, nickel/tungsten and cobalt/nickel/molybdenum, can also be used. The combinations can be composed of different particles containing a single active metal species, or particles containing multiple active species. In certain embodiments, cobalt/molybdenum hydrodesulfurization catalyst is suitable. Effective liquid hourly space velocity values (h⁻¹), on a fresh feed basis relative to the hydrotreating catalysts, are in the range of from 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 FCC naphtha hydrotreating zone 540 have an expected lifetime in the range of about 28-44 months, in certain embodiments about 34-38 months.
With continued reference to FIG. 14, the MFSC zone 700, which operates at high severity or low severity thermal cracking process, generally converts LPG, naphtha and heavier hydrocarbons primarily into a mixed product stream 728 containing mixed C1-C4 paraffins and olefins. In certain embodiments, the mixed feed steam cracking zone 700 processes straight-run liquids from the crude unit, propane (from outside battery limits and/or recycled) and various recycle streams from chemical production and recovery areas within the integrated process and system. A suitable MFSC zone 700 can be based on technology commercially available from Linde AG, Germany; TechnipFMC plc, United Kingdom; Chicago Bridge & Iron Company N.V. (CB&I), the Netherlands; or KBR, Inc, United States.
In the embodiment depicted in FIGS. 12, 13 and 14, the plural feeds to the mixed feed steam cracking zone 700 include: light ends 112 and straight run naphtha 118 from the crude complex 100; a LPG stream 656 from dealkylation zone 650; a C3+ stream 416 recovered from the HOFCC zone 400; propane (from outside battery limits, stream 688, a recycle stream 724 from the MAPD saturation and propylene recovery zone 720); C4 raffinate 866 from the hydrogenation and separation zone 860; C5s stream 548 from the FCCN HT zone 540; C5s stream 528 from the pyrolysis gas hydrotreating zone 520; wild naphtha 222 from the diesel hydrotreating zone 220 (in certain embodiments via the crude complex); and a raffinate stream 602 from the aromatics extraction zone 600.
The products from the mixed feed steam cracking zone 700 include quenched cracked gas stream 728 containing mixed C1-C4 paraffins and olefins that is routed to the olefins recovery zone 730, a raw pyrolysis gas stream 712 that is routed to a pyrolysis gas hydrotreating zone 520 to provide feed 526 to the aromatics extraction zone 600, and a pyrolysis fuel oil stream 714 that is routed to a fuel oil pool.
The mixed feed steam cracker generally comprises one or more trains of furnaces. For instance, a typical arrangement includes reactors that can operate based on well-known steam pyrolysis methods, that is, charging the thermal cracking feed to a convection section in the presence of steam to raise the temperature of the feedstock, and passing the heated feed to the pyrolysis reactor containing furnace tubes for cracking. In the convection section, the mixture is heated to a predetermined temperature, for example, using one or more waste heat streams or other suitable heating arrangement.
The mixed feed steam cracker operates under parameters effective to crack the feed into desired products including ethylene, propylene, butadiene, and mixed butenes. Pyrolysis gas and pyrolysis oil are also recovered. In certain embodiments, the steam cracking furnace(s) are operated at conditions effective to produce an effluent having a propylene to ethylene weight ratio of from about 0.3-0.8, 0.3-0.6, 0.4-0.8 or 0.4-0.6.
In certain embodiments, the mixture is heated to a high temperature and material with a boiling point below the predetermined temperature is vaporized. The heated mixture along with additional steam is passed to the pyrolysis section operating at an elevated temperature for short residence times, such as one second or less, effectuating pyrolysis to produce a mixed product stream. In certain embodiments, steam cracking is carried out using the following conditions: a temperature in the range of 400-600° C. in the convection section, a temperature in the range of 750-900° C. in the pyrolysis section; a steam-to-hydrocarbon ratio in the in the convection section in the range of 0.3:1 to 2:1; and a residence time in the convection section and in the pyrolysis section in the range of from 0.05-2 seconds.
In operation of the mixed feed steam cracking zone 700, effluent from the cracking furnaces is cooled, for instance, using transfer line exchangers, and quenched in a quench tower (not show). The light products, quenched cracked gas stream 728, are routed to the olefins recovery zone 730. Heavier products are separated in a hot distillation section. A raw pyrolysis gas stream is recovered in the quench system. Pyrolysis oil 714 is separated at a primary fractionator tower (not shown) before the quench tower.
In operation of one embodiment of the mixed feed steam cracking zone 700, the feedstocks are mixed with dilution steam to reduce hydrocarbon partial pressure and then are preheated. The preheated feeds are fed to empty tubular reactors mounted in the radiant sections of the cracking furnaces. The hydrocarbons undergo free-radical pyrolysis reactions to form light olefins ethylene and propylene, and other by-products. In certain embodiments, dedicated cracking furnaces are provide with cracking tube geometries optimized for each of the main feedstock types, including ethane, propane, and butanes/naphtha. Less valuable hydrocarbons, such as ethane, propane, C4 raffinate, and aromatics raffinate, that are produced within the integrated system and process, are recycled to extinction in the MFSC zone 700. Cracked gas from the furnaces is cooled in transfer line exchangers, for example, producing 1800 psig steam suitable as dilution steam. Quenched cracked gas enters a primary fractionator that removes pyrolysis fuel oil bottoms from lighter components. The primary fractionator enables efficient recovery of pyrolysis fuel oil. Pyrolysis fuel oil is stripped with steam in a fuel oil stripper to control product vapor pressure, and cooled. In addition, secondary quench is carried out by direct injection of pyrolysis fuel oil as quench oil into liquid furnace effluents. The stripped and cooled pyrolysis fuel oil can be sent to a fuel oil pool or product storage. The primary fractionator overhead is sent to a quench water tower; condensed dilution steam for process water treating, and raw pyrolysis gas, are recovered. Quench water tower overhead is sent to the olefins recovery zone 730, in particular a first compression stage. Raw pyrolysis gas is sent to a gasoline stabilizer to remove any light ends and to control vapor pressure in downstream pyrolysis gas processing. A closed-loop dilution steam/process water system is enabled, in which dilution steam is generated using heat recovery from the primary fractionator quench pumparound loops. The primary fractionator enables efficient recovery of pyrolysis fuel oil; due to energy integration and pyrolysis fuel oil content in the light fraction stream.
The mixed product stream 728 effluent from the MFSC zone 700 is routed to an olefins recovery zone 730. For instance, light products from the quenching step, C4−, H2 and H2S, are contained in the mixed product stream 728 that is routed to the olefins recovery zone 730. Products include: hydrogen 704 that is used for recycle and/or passed to users; fuel gas 702 that is passed to a fuel gas system; ethane 718 that is recycled from the MFSC zone 700; ethylene 706 that is recovered as product; a mixed C3 stream 726 that is passed to an MAPD saturation and propylene recovery zone 720; and a mixed C4 stream 710 that is passed to a butadiene extraction zone 820.
The olefins recovery zone 730 operates to produce on-specification light olefin (ethylene and propylene) products from the mixed product stream 728. For instance, cooled gas intermediate products from the steam cracker is fed to a cracked gas compressor, caustic wash zone, and one or more separation trains for separating products by distillation. In certain embodiments two trains are provided. The distillation train includes a cold distillation section, wherein lighter products such as methane, hydrogen, ethylene, and ethane are separated in a cryogenic distillation/separation operation. The mixed C2 stream from the steam cracker contains acetylenes that are hydrogenated to produce ethylene in an acetylene selective hydrogenation unit. This system also includes ethylene and propylene refrigeration facilities to enable cryogenic distillation.
In one embodiment, the mixed product stream 728 effluent from the MFSC zone 700 is passes through three to five stages of compression. Acid gases are removed with caustic in a caustic wash tower. After an additional stage of compression and drying, light cracked gases are chilled and routed to a depropanizer. In certain embodiments light cracked gases are chilled with a cascaded two-level refrigeration system (propylene, mixed binary refrigerant) for cryogenic separation. A front-end depropanizer optimizes the chilling train and demethanizer loading. The depropanizer separates C3 and lighter cracked gases as an overhead stream, with C4s and heavier hydrocarbons as the bottoms stream. The depropanizer bottoms are routed to the debutanizer, which recovers a crude C4s stream 710 and any trace pyrolysis gas, which can be routed to the pyrolysis gas hydrotreating zone 520 (not shown).
The depropanizer overhead passes through a series of acetylene conversion reactors, and is then fed to the demethanizer chilling train, which separates a hydrogen-rich product via a hydrogen purification system, such as pressure swing adsorption. Front-end acetylene hydrogenation is implemented to optimize temperature control, minimum green oil formation and simplify ethylene product recovery by eliminating a C2 splitter pasteurization section that is otherwise typically included in product recovery. In addition, hydrogen purification via pressure swing adsorption eliminates the need for methanation reactor that is otherwise typically included in product recovery.
The demethanizer recovers methane in the overhead for fuel gas, and C2 and heavier gases in the demethanizer bottoms are routed to the deethanizer. The deethanizer separates ethane and ethylene overhead which feeds a C2 splitter. The C2 splitter recovers ethylene product 706, in certain embodiments polymer-grade ethylene product, in the overhead. Ethane 718 from the C2 splitter bottoms is recycled to the MFSC zone 700. Deethanizer bottoms contain C3s from which propylene product 708, in certain embodiments polymer-grade propylene product, is recovered as the overhead of a C3 splitter, with propane 724 from the C3 splitter bottoms recycled to the MFSC zone 700.
A methyl acetylene (propyne) and propadiene (MAPD) saturation and propylene recovery zone 720 is provided for selective hydrogenation to convert methyl acetylene/propadiene, and to recover propylene from a mixed C3 stream 726 from the olefins recovery zone 730. The mixed C3 726 from the olefins recovery zone 730 contains a sizeable quantity of propadiene and propylene. The MAPD saturation and propylene recovery zone 720 enables production of polymer-grade propylene 708.
The MAPD saturation and propylene recovery zone 720 receives hydrogen 722 and mixed C3 726 from the olefins recovery zone 730. Products from the MAPD saturation and propylene recovery zone 720 are propylene 708 which is recovered, and the recycle C3 stream 724 that is routed to the steam cracking zone 700. In certain embodiments, hydrogen 722 to saturate methyl acetylene and propadiene is derived from hydrogen 704 obtained from the olefins recovery zone 730.
A stream 710 containing a mixture of C4s, known as crude C4s, from MFSC zone 700 is routed to a butadiene extraction zone 820 to recover a high purity 1,3-butadiene product 822 from the mixed crude C4s. In certain embodiments (not shown), a step of hydrogenation of the mixed C4 before the butadiene extraction zone 820 can be integrated to remove acetylenic compounds, for instance, with a suitable catalytic hydrogenation process using a fixed bed reactor. 1,3-butadiene 822 is recovered from the hydrogenated mixed C4 stream by extractive distillation using, for instance, dimethylformamide (DMF) as solvent. The butadiene extraction zone 820 also produces a raffinate stream 824 containing butane/butene, which is passed to an MTBE zone.
In one embodiment, in operation of the butadiene extraction zone 820, the stream 710 is preheated and vaporized into a first extractive distillation column, for instance having two sections. DMF solvent separates the 1,3-butadiene from the other C4 components contained in stream 824. Rich solvent is flashed with vapor to a second extractive distillation column that produces a high purity 1,3 butadiene stream as an overhead product. Liquid solvent from the flash and the second distillation column bottoms are routed to a primary solvent recovery column. Bottoms liquid is circulated back to the extractor and overhead liquid is passed to a secondary solvent recovery or solvent polishing column. Vapor overhead from the recovery columns combines with recycle butadiene product into the bottom of the extractor to increase concentration of 1,3-butadiene. The 1,3-butadiene product 822 can be water washed to remove any trace solvent. In certain embodiments, the product purity (wt %) is 97-99.8, 97.5-99.7, or 98-99.6, 1,3-butadiene; 94-99, 94.5-98.5, or 95-98 of the 1,3-butadiene content (wt %) of the feed is recovered. In addition, the extractive distillation column and primary solvent recovery columns are reboiled using high pressure steam (for instance, 600 psig) and circulating hot oil from the aromatics extraction zone 600 as heat exchange fluid.
An MTBE zone 840 is integrated to produce MTBE 844 and a second C4 raffinate 846 from the first C4 raffinate stream 824. In certain embodiments C4 Raffinate 1 824 is subjected to selective hydrogenation to selectively hydrogenate any remaining dienes and prior to reacting isobutenes with methanol to produce MTBE
Purity specifications for recovery of a 1-butene product stream 862 necessitate that the level of isobutylene in the second C4 raffinate 846 be reduced. In general, the first C4 raffinate stream 824 containing mixed butanes and butenes, and including isobutylene, is passed to the MTBE zone 840. Methanol 842 is also added, which reacts with isobutylene and produces MTBE 844. For instance, MTBE product and methanol are separated in a series of fractionators, and routed to a second reaction stage. Methanol is removed with water wash and a final fractionation stage. Recovered methanol is recycled to the fixed bed downflow dehydrogenation reactors.
In certain embodiments, described below with respect to FIG. 17, additional isobutylene can be introduced to the MTBE zone 840, for instance, derived from a metathesis conversion unit, such as those described herein and depicted in FIG. 6 or 8.
In operation of one embodiment of the MTBE zone 840, the raffinate stream 824, contains 35-45%, 37-42.5%, 38-41% or 39-40% isobutylene by weight. This component must be removed from the C4 raffinate 846 to attain requisite purity specifications, for instance, greater than or equal to 98 wt % for the 1-butene product stream 862 from the hydrogenation and separation zone 860. Methanol 842, in certain embodiments high purity methanol having a purity level of greater than or equal to 98 wt % from outside battery limits, and the isobutylene contained in the raffinate stream 824, react in a primary reactor, in certain embodiments a fixed bed downflow dehydrogenation reactor. Isobutylene conversion in the primary reactor can be in the range of about 70-95%, 75-95%, 85-95% or 90-95% on a weight basis. Effluent from the primary reactor is routed to a reaction column where reactions are completed. In certain embodiments, exothermic heat of the reaction column and the primary reactor can optionally be used to supplement the column reboiler along with provided steam. The reaction column bottoms contains MTBE, traces amounts, for instance, less than 2%, of unreacted methanol, and heavy products produced in the primary reactor and reaction column. Reaction column overhead contains unreacted methanol and non-reactive C4 raffinate. This stream is water washed to remove unreacted methanol and passed to the hydrogenation and separation zone 860 as the C4 raffinate 846. Recovered methanol is removed from the wash water in a methanol recovery column and recycled to the primary reactor.
The C4 raffinate stream 846 from the MTBE zone 840 is passed to separation zone 860 for butene-1 recovery. In certain embodiments, upstream of the MTBE zone 840, or between the MTBE zone 840 and butene-1 recovery, a selective hydrogenation zone can also be included (not shown). For instance, in certain embodiments, raffinate from the MTBE zone 840 is selectively hydrogenated in a selective hydrogenation unit as is well-known to produce butene-1. Other co-monomers and paraffins are also coproduced. For selective recovery of a 1-butene product stream 862 and a recycle stream 866 that is routed to the MFSC zone 700, one or more separation steps are used. For example, 1-butene can be recovered using two separation columns, where the first column recovers olefins from the paraffins and the second column separates 1-butene from the mixture including 2-butene, which is blended with the paraffins from the first column and recycled to the steam cracker as a recycle stream 866.
In certain embodiments, the C4 raffinate stream 846 from the MTBE zone 840 is passed to a first splitter, from which from isobutane, 1-butene, and n-butane are separated from heavier C4 components. Isobutane, 1-butene, and n-butane are recovered as overhead, condensed in an air cooler and sent to a second splitter. Bottoms from the first splitter, which contains primarily cis- and trans-2 butene can be added to the recycle stream 866, or in certain embodiments described herein passed to a metathesis unit. In certain arrangements, the first splitter overhead enters the mid-point of the second splitter. Isobutane product 864 can be recovered in the overhead, 1-butene product 862 is recovered as a sidecut, and n-butane is recovered as the bottoms stream. Bottoms from both splitters is recovered as all or a portion of recycle stream 866.
The raw pyrolysis gas stream 712 from the steam cracker is treated and separated into treated naphtha and other fractions. The raw pyrolysis gas stream 712 and is processed in a pyrolysis gas hydrotreating zone 520, in the presence of an effective amount of hydrogen 522. Effluent fuel gas 524 is recovered and, for instance, passed to a fuel gas system. In certain embodiments, all or a portion of hydrogen 522 is derived from the steam cracker products. For instance, a suitable pyrolysis gas hydrotreating zone 520 can be based on technology commercially available from Honeywell UOP, United States; Chevron Lummus Global LLC, (CLG), United States; Axens, IFP Group Technologies, France; Haldor Topsoe A/S, Denmark; or Chicago Bridge & Iron Company N.V. (CB&I), the Netherlands.
The pyrolysis gas hydrotreating zone 520 operated under conditions, and utilizes catalyst(s), that can be varied over a relatively wide range. These conditions and catalyst(s) are selected for effective hydrogenation for saturation of certain olefin and diolefin compounds, and if necessary for 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 can be utilized. Accordingly, pyrolysis gas hydrotreating zone 520 subjects the pyrolysis gas stream 712 to hydrogenation to produce hydrotreated pyrolysis naphtha 526 effective as feed to the aromatics extraction zone 600. In the pyrolysis gas hydrotreating zone 520, diolefins in the feed and olefins in the C6+ portion of the feed are saturated to produce a naphtha stream 526, a C5+ feed to the aromatics extraction zone. In certain embodiments, a depentanizing step associated with the pyrolysis gas hydrotreating zone 520 separates all or a portion of the Cys, for instance, as additional feed 528 to the mixed feed steam cracking zone 700 and/or as feed to a metathesis unit 910 (as shown, for instance, in FIG. 6, 8 or 17). In other embodiments, a depentanizing step associated with the aromatics extraction zone 600 separates all or a portion of the C5s from the hydrotreated naphtha stream 526, for instance, as additional feed to the mixed feed steam cracking zone 700 and/or as feed to a metathesis unit 910.
In certain embodiments, pyrolysis gas is processed in a first reaction stage for hydrogenation and stabilization. Diolefins are saturated selectively in the first reaction stage, and remaining olefins are saturated in the second reaction stage along with converting feed sulfur into hydrogen sulfide. The pyrolysis gas can be treated in a cold hydrotreating unit, therefore reducing the level of aromatics saturation.
In an example of an effective pyrolysis gas hydrotreating zone 520, raw pyrolysis gas is passed through a coalescer before entering a feed surge drum. The first stage reactor operates in mixed phase and selectively hydrogenates diolefins to mono-olefins and unsaturated aromatics to side-chain saturated aromatics. Palladium-based catalyst materials are effective. Two parallel first-stage reactors can be used in certain embodiments to allow for regeneration in a continuous process without shutdown. In certain embodiments, the first-stage reactor contains three catalyst beds with cooled first stage separator liquid recycled as quench material between each bed. First-stage effluent is stabilized and separated in a column operating under slight vacuum to reduce temperature. In certain embodiments C5 from the C6+ is drawn, followed by a deoctanizer to remove C9+ and produce a C6-C8 heart naphtha cut. The column operates under slight vacuum to limit temperature. The first stage product is stripped to remove hydrogen, H₂S, and other light ends. In certain embodiments, the stripped first stage product is depentanized to remove cracked C5, for instance, as feed to a metathesis unit. A second stage reactor operates in vapor phase and removes sulfur and saturates olefins. The second stage product is stripped to remove hydrogen, H₂S, and other light ends. In certain embodiments, both reactors are multi-bed and use product recycle to control reactor temperature rise.
In certain embodiments, the first reaction stage of the pyrolysis gas hydrotreating zone 520 operating conditions include:
a reactor inlet temperature (° C.) in the range of from about 80-135, 80-125, 80-115, 95-135, 95-125, 95-115, 100-135, 100-125, 100-115 or 107-111;
a reactor outlet temperature (° C.) in the range of from about 145-230, 145-206, 145-200, 165-230, 165-206, 165-200, 175-230, 175-206, 175-200 or 184-188;
a start of run (SOR) reaction temperature (° C.), as a weighted average bed temperature (WABT), in the range of from about 75-125, 75-115, 75-110, 90-125, 90-115, 90-110, 95-125, 95-115, 95-110 or 99-104;
an end of run (EOR) reaction temperature (° C.), as a WABT, in the range of from about 124-195, 124-180, 124-170, 140-195, 140-180, 140-170, 150-195, 150-180, 150-170 or 158-163;
a reaction inlet pressure (bar) in the range of from about 25-40, 25-35, 25-33, 28-40, 28-35, 28-33, 30-40, 30-35 or 30-33;
a reaction outlet pressure (bar) in the range of from about 23-35, 23-33, 23-31, 25-35, 25-33, 25-31, 28-35, 28-33 or 28-31;
a hydrogen partial pressure (bar) (outlet) in the range of from about 15-25, 15-22, 15-21, 18-25, 18-22, 18-21, 19-25 or 19-22;
a hydrogen treat gas feed rate (SLt/Lt) up to about 180, 165 or 156, in certain embodiments from about 120-180, 120-165, 120-156, 134-180, 134-165, 134-156, 140-180, 140-165 or 140-156;
a liquid quench feed ratio (Lt quench/Lt feed) up to about 0.8, 0.7, 0.6 or 0.5, and in certain embodiments in the range of from 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, 0.45-0.55 or 0.45-0.5; and
a make-up hydrogen feed rate (SLt/Lt) up to about 60, 55, 47 or 45, in certain embodiments from about 34-55, 34-47, 34-45, 40-55, 40-47, 40-45, 42-55, 42-47 or 42-45.
In certain embodiments, the second reaction stage of the pyrolysis gas hydrotreating zone 520 operating conditions include:
a reactor inlet temperature (° C.) in the range of from about 225-350, 225-318, 225-303, 255-350, 255-318, 255-303, 270-350, 270-318, 270-303 or 285-291.
a reactor outlet temperature (° C.) in the range of from about 289-445, 289-405, 289-386, 328-445, 328-405, 328-386, 345-445, 345-405, 345-386 or 364-370
a start of run (SOR) reaction temperature (° C.), as a weighted average bed temperature (WABT), in the range of from about 217-336, 217-306, 217-291, 245-336, 245-306, 245-291, 260-336, 260-306, 260-291 or 274-280;
an end of run (EOR) reaction temperature (° C.), as a WABT, in the range of from about 325-416, 325-380, 325-362, 305-416, 305-380, 305-362, 325-416, 325-380, 325-362 or 340-346;
a reaction inlet pressure (bar) in the range of from about 25-37, 25-34, 25-32, 28-37, 28-34, 28-32, 29-37, 29-34 or 29-32;
a reaction outlet pressure (bar) in the range of from about 23-35, 23-32, 23-30, 26-35, 26-32, 26-30, 28-35, 28-32 or 28-30;
a hydrogen partial pressure (bar) (outlet) in the range of from about 6-10, 6-9, 7-10 or 7-9;
a hydrogen treat gas feed rate (SLt/Lt) up to about 135, 126, 116 or 110, in certain embodiments from about 84-126, 84-116, 84-110, 95-126, 95-116, 95-110, 100-126, 100-116 or 100-110; and
a make-up hydrogen feed rate (SLt/Lt) up to about 30, 27 or 24, in certain embodiments from about 18-30, 18-27, 18-24, 21-30, 21-27, 21-24, 22-30, 22-27 or 22-24.
Effective catalyst possessing selective hydrogenation functionality and which generally contain one or more active metal component of metals or metal compounds (oxides or sulfides) selected from cobalt, molybdenum, platinum, palladium, iron, or nickel. The active metal component is typically deposited or otherwise incorporated on a support, such as amorphous alumina, amorphous silica alumina, zeolites, or combinations thereof. Exemplary selective hydrogenation catalyst predominantly use palladium as the active metal component on alumina support, including those commercially available under the trade name Olemax® 600 and Olemax® 601. Effective liquid hourly space velocity values (h⁻¹), on a fresh feed basis relative to the first stage py-gas reactor catalyst, are in the range of from 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 to 1.44. Suitable catalysts used in the first stage py-gas reactor have an expected lifetime in the range of about 18-30 months, in certain embodiments about 22-26 months.
Effective second stage py-gas reactor catalyst include those having hydrogenation functionality and which generally contain one or more active metal component of metals or metal compounds (oxides or sulfides) selected from the Periodic Table of the Elements IUPAC Groups 6-10. In certain embodiments, the active metal component is one or more of cobalt, nickel, tungsten and molybdenum. The active metal component is typically deposited or otherwise incorporated on a support, such as amorphous alumina, amorphous silica alumina, zeolites, or combinations thereof. In certain embodiments, the catalyst used in the first stage py-gas reactor includes one or more catalyst selected from cobalt/molybdenum, nickel/molybdenum, nickel/tungsten, and cobalt/nickel/molybdenum. Combinations of one or more of cobalt/molybdenum, nickel/molybdenum, nickel/tungsten and cobalt/nickel/molybdenum, can also be used. For example, a combination of catalyst particles commercially available under the trade names Olemax® 806 and Olemax® 807 can be used, with active metal components of cobalt and nickel molybdenum. The combinations can be composed of different particles containing a single active metal species, or particles containing multiple active species. Effective liquid hourly space velocity values (h⁻¹), on a fresh feed basis relative to the first stage py-gas reactor catalyst, are in the range of from 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 py-gas reactor have an expected lifetime in the range of about 18-30 months, in certain embodiments about 22-26 months.
Hydrotreated pyrolysis naphtha 526 and hydrotreated FCCN 546 are routed to aromatics extraction zone 600. The aromatics extraction zone 600 includes, for instance, one or more extractive distillation units, and operates to separate the hydrotreated pyrolysis naphtha and FCC naphtha into high-purity benzene, toluene, xylenes and C9 aromatics. As depicted in FIG. 14, a benzene stream 604, a mixed xylenes stream 606 and a raffinate stream 602 are recovered from the aromatics extraction zone 600, with the raffinate stream 602 routed to the MFSC zone 700 as additional feed. In addition, a toluene stream 608 is passed from the aromatics extraction zone 600 to a toluene and C9+ disproportionation zone 650 for production of additional benzene and xylenes, recycled as stream 658 to the aromatics extraction zone 600. In certain embodiments ethylbenzene can be recovered (not shown).
In certain embodiments of operation of the aromatics extraction zone 600, aromatics are separated from the feed by extractive distillation using, for instance, n-formylmorpholine (NFM), as an extractive solvent. Benzene, toluene, mixed xylenes and C9+ aromatics are separated via distillation. Benzene and mixed xylenes are recovered as product streams 604 and 606, and toluene 608 and C9+ aromatics 610 are sent to the toluene and C9+ disproportionation zone 650. The disproportionation zone product stream 658 containing benzene and mixed xylenes is returned to the recovery section of the aromatics extraction zone 600. A paraffinic raffinate stream 602 is recycled as feed to the MFSC zone 700. In certain embodiments, the paraffinic raffinate stream 602 is in direct fluid communication with the MFSC zone 700, that is, the stream is not subject to further catalytic processing prior to the steam cracking step.
Selection of solvent, operating conditions, and the mechanism of contacting the solvent and feed permit control over the level of aromatic extraction. For instance, suitable solvents include n-formylmorpholine, furfural, N-methyl-2-pyrrolidone, dimethylformamide, dimethylsulfoxide, phenol, nitrobenzene, sulfolanes, acetonitrile, furfural, or glycols, and can be provided in a solvent to oil ratio of up to about 20:1, in certain embodiments up to about 4:1, and in further embodiments up to about 2:1. Suitable glycols include diethylene glycol, ethylene glycol, triethylene glycol, tetraethylene glycol and dipropylene glycol. The extraction solvent can be a pure glycol or a glycol diluted with from about 2-10 wt % water. Suitable sulfolanes include hydrocarbon-substituted sulfolanes (e.g., 3-methyl sulfolane), hydroxy sulfolanes (e.g., 3-sulfolanol and 3-methyl-4-sulfolanol), sulfolanyl ethers (i.e., methyl-3-sulfolanyl ether), and sulfolanyl esters (e.g., 3-sulfolanyl acetate).
The aromatic separation apparatus can operate at a temperature in the range of from about 40-200, 40-150, 60-200, 60-150, 86-200 or 80-150° C. The operating pressure of the aromatic separation apparatus can be in the range of from about 1-20, 1-16, 3-20, 3-16, 5-20 or 5-16 bar. Types of apparatus useful as the aromatic separation apparatus in certain embodiments of the system and process described herein include extractive distillation columns.
In one embodiment of operation of the aromatics extraction zone 600, the feed contains primarily C6+ components, and is fractionated into a “heart cut” of C6-C8, a heavy C9+ fraction. The C6-C8 cut is routed to the extractive distillation system where aromatics are separated from non-aromatics (saturates) via solvent distillation. The raffinate (non-aromatics) from the C6-C8 is removed and recycled back to the cracking complex as a feedstock. The aromatics are soluble in the solvent and are carried from the bottom of the extractive distillation column to the solvent stripper where they are stripped from the solvent to produce aromatics extract and lean solvent which is recycled back to the extractive distillation column. The mixed aromatics extract is routed to a series of fractionation columns (a benzene column, a toluene column and a xylene column) where each aromatic species is successively removed, for instance, as benzene stream 604 and mixed xylenes stream 606. The heavy C9+ fraction is further separated into C9 and C10+ material. The toluene and C9 products are routed to the toluene and C9+ disproportionation zone 650 where they are reacted to form additional benzene and mixed xylenes. This stream is recycled back to the fractionation portion of the aromatics extraction zone 600 to recover the benzene and mixed xylenes as well as to recycle the unconverted toluene and C9 aromatics. The disproportionation effluent does not require re-extraction in the solvent distillation section and therefore is routed to the inlet of the benzene column. In certain embodiments toluene can be recycled to extinction, or approaching extinction. C10 and heavier aromatics are removed as product 660 and can be used as cutter stock into a fuel oil pool.
The toluene and C9+ dealkylation and disproportionation zone 650 operates to disproportionate toluene and C9+ aromatics to increase production of mixed xylenes. Product ratio of benzene and xylene can be adjusted by selection of catalyst, feedstock and operating conditions. Zone 650 receives as feed the toluene stream 608 and the C9+ aromatics stream 610 from the aromatics extraction zone 600.
The toluene and C9+ dealkylation and disproportionation zone 650 operates to disproportionate toluene and C9+ aromatics into a mixture 658 of benzene and mixed xylenes. Product ratio of benzene and xylene can be adjusted by selection of catalyst, feedstock and operating conditions. Zone 650 receives as feed the toluene stream 608 and the C9+ aromatics stream 610 from the aromatics extraction zone 600. A small quantity of hydrogen 652, in certain embodiments which is obtained all or in part from the hydrogen stream 704 derived from the olefins recovery zone 730, is supplied for transalkylation reactions. Side cracking reactions occur producing fuel gas stream 654, for instance, passed to the fuel gas system, and LPG stream 656 that is recycled to mixed feed steam cracking zone. A small amount, such as 0.5-3 wt % of the total feed to the aromatics extraction, of heavy aromatics are produced due to condensation reactions and are can be passed sent to the fuel oil pool.
In operation of one embodiment of the toluene and C9+ dealkylation and disproportionation zone 650, toluene and C9 aromatics are reacted with hydrogen to form a mixture of C6-C11 aromatics. The mixed aromatic product is recycled back to the aromatics extraction zone 600 where the benzene and mixed xylenes are recovered as products. C7 and C9 aromatics are recycled back as feed to zone 650, and the C10+ fraction is removed for use, for instance, as fuel oil cutter stock. The disproportionation reactions occur in the present of an effective quantity of hydrogen. Minimal amounts of hydrogen is consumed by cracking reactions under reactor conditions. Purge gas is recycled back to the cracking complex for component recovery.
Pyrolysis oil (“py-oil”) 714 can be recovered as-is, or fractionated (not shown) into light pyrolysis oil (LPO) and heavy pyrolysis oil (HPO). If recovered as is, it can be blended in a fuel oil pool as a low sulfur component, and/or used a carbon black feedstock. LPO can be blended into diesel or kerosene fractions, or can be hydrotreated or hydroprocessed for recycle to the steam cracker. HPO can be blended into the fuel oil pool.
FIG. 17 depicts a variation to any of the above described processes, including integration of a metathesis unit 910. Feedstocks to the metathesis unit 910 include: a portion 916 of the ethylene MFSC product; a C4 raffinate 3 stream 912 from hydrogenation and separation zone 860, and an olefinic C5 cut 528 from the pyrolysis gas hydrotreating zone 520. Products from the metathesis unit 910 include propylene 914 and isobutylene 920, which is routed to the added to the MTBE zone 840. A stream 924, having a mixture of saturated C4/C5 from a metathesis unit, is recycled to the mixed feed steam cracking zone.
FIG. 18 depicts an embodiment in which FCC naphtha 406 and the raw pyrolysis gas stream 712 from the steam cracker are commingled and processed in a naphtha hydrotreating zone 500 in the presence of an effective amount of hydrogen 504. In certain embodiments, all or a portion of hydrogen 504 is derived from the steam cracker products. Effluent fuel gas 508 is recovered and, for instance, passed to a fuel gas system.
The effluent from the cracked naphtha hydrotreating reactor generally contain C5-C9+ hydrocarbons. In certain embodiments, C5-C9+ hydrocarbons are passed to the aromatics extraction zone 600, and the aromatics extraction zone 600 includes a depentanizing step to remove C5s. In other embodiments and as shown for instance in FIG. 18, naphtha hydrotreating zone 500 includes a depentanizing step to remove C5s, which are recycled as stream 502 to the mixed feed steam cracking zone 700. The hydrotreated mixed naphtha stream 506, generally containing C6-C9+ hydrocarbons, is passed to the aromatics extraction zone 600.
FIG. 19 depicts an embodiment in which kerosene sweetening is in an optional unit, that is, the light kerosene fraction 122 can be routed either through the kerosene sweetening zone 210 or routed to the distillate hydrotreating zone 220.
During periods in which maximizing the fuel fraction 212 is desired, light kerosene fraction 122 can be routed to the kerosene sweetening zone 210. During periods in which the feedstock to the MFSC zone 700 is to be maximized, light kerosene fraction 122 can be routed to the distillate hydrotreating zone 220, so as to produce additional hydrotreated naphtha 222. In additional alternative embodiments, the light kerosene fraction 122 can be split so that a portion is passed to the distillate hydrotreating zone 220 and the remaining portion is passed to the kerosene sweetening zone 210.
FIG. 20 depicts an embodiment in which kerosene sweetening is eliminated a light kerosene fraction 122 is routed to the distillate hydrotreating zone 220. While not shown, it will be appreciated that in the embodiment of FIG. 20 a full range kerosene fraction can be obtained from the atmospheric distillation zone 104 rather than the separate light kerosene fraction 122 and heavy kerosene fraction 124
Advantageously, process dynamics of the configurations and the integration of units and streams attain a very high level of integration of utility streams between the MFSC and other process units, result in increased efficiencies and reduced overall operating costs. For instance, the hydrogen can be tightly integrated so that the net hydrogen demand from outside of the battery limits is minimized or even eliminated. In certain embodiments, the overall hydrogen utilization from outside of the battery limits is less than about 40, 30, 15, 10 or 5 wt % hydrogen based on the total hydrogen required by the hydrogen users in the integrated process. Hydrogen is recovered from the olefins recovery train, and is supplied to the hydrogen users in the system, including the diesel hydrotreater, the gas oil hydrotreater or hydrocracker, the py-gas hydrotreater, the FCC naphtha hydrotreater, and dealkylation, so as to derive most or all of the utility hydrogen from within the battery limits. In certain embodiments make-up hydrogen is only required to initiate the operation, so that when the reactions reach equilibrium, the hydrogen derived from the MFSC products provides sufficient hydrogen to maintain the hydrogen requirements of the hydrogen users in the integrated process.
Each of the processing units are operated at conditions typical for such units, which conditions can be varied based on the type of feed to maximize, within the capability of the unit's design, the desired products. Desired products can include fractions suitable as feedstock to the MFSC zone 700, or fractions suitable for use as fuel products. Likewise, processing units employ appropriate catalyst depending upon the feed characteristics and the desired products. Certain embodiments of these operating conditions and catalysts are described herein, although it shall be appreciated that variations are well known in the art and are within the capabilities of those skilled in the art.
For the purpose of the simplified schematic illustrations and descriptions herein, accompanying components that are conventional in crude centers, such as the numerous valves, temperature sensors, preheater(s), desalting operation(s), and the like are not shown.
Further, the numerous valves, temperature sensors, electronic controllers and the like that are customarily employed and well known to those of ordinary skill in the art of fluid catalyst cracking are not included. Further, accompanying components that are in conventional in fluid catalyst cracking systems such as, for example, air supplies, catalyst hoppers, flue gas handling the like are also not shown.
In addition, accompanying components that are in conventional hydroprocessing units such as, for example, hydrogen recycle sub-systems, bleed streams, spent catalyst discharge sub-systems, and catalyst replacement sub-systems the like are not shown.
Further, accompanying components that are in conventional thermal cracking systems such as steam supplies, coke removal sub-systems, pyrolysis sections, convection sections and the like are not shown.
Embodiments described herein provide the ability to achieve a crude to chemical conversion ratio in the range of, for instance, up to 80%, 50% or 45%, and in certain embodiments in the range of about 39-45%. It should be appreciated that this crude to chemicals conversion ratio can vary depending on criteria such as feed, selected technology, catalyst selection and operating conditions for the individual unit operations.
In some embodiments, individual unit operations can include a controller to monitor and adjust the product slate as desired. A controller can direct parameters within any of the individual unit operations the apparatus depending upon the desired operating conditions, which may, for example, be based on customer demand and/or market value. A controller can adjust or regulate valves, feeders or pumps associated with one or more unit operations based upon one or more signals generated by operator data input and/or automatically retrieved data.
Such controllers provide a versatile unit having multiple modes of operation, which can respond to multiple inputs to increase the flexibility of the recovered product. The controller can be implemented using one or more computer systems which can be, for example, a general-purpose computer. Alternatively, the computer system can include specially-programmed, special-purpose hardware, for example, an application-specific integrated circuit (ASIC) or controllers intended for a particular unit operation within a refinery.
The computer system can include one or more processors typically connected to one or more memory devices, which can comprise, for example, any one or more of a disk drive memory, a flash memory device, a RAM memory device, or other device for storing data. The memory is typically used for storing programs and data during operation of the system. For example, the memory can be used for storing historical data relating to the parameters over a period of time, as well as operating data. Software, including programming code that implements embodiments of the invention, can be stored on a computer readable and/or writeable nonvolatile recording medium, and then typically copied into memory wherein it can then be executed by one or more processors. Such programming code can be written in any of a plurality of programming languages or combinations thereof.
Components of the computer system can be coupled by one or more interconnection mechanisms, which can include one or more busses, for instance, between components that are integrated within a same device, and/or a network, for instance, between components that reside on separate discrete devices. The interconnection mechanism typically enables communications, for instance, data, instructions, to be exchanged between components of the system.
The computer system can also include one or more input devices, for example, a keyboard, mouse, trackball, microphone, touch screen, and other man-machine interface devices as well as one or more output devices, for example, a printing device, display screen, or speaker. In addition, the computer system can contain one or more interfaces that can connect the computer system to a communication network, in addition or as an alternative to the network that can be formed by one or more of the components of the system.
According to one or more embodiments processes herein, the one or more input devices can include sensors and/or flow meters for measuring any one or more parameters of the apparatus and/or unit operations thereof. Alternatively, one or more of the sensors, flow meters, pumps, or other components of the apparatus can be connected to a communication network that is operatively coupled to the computer system. Any one or more of the above can be coupled to another computer system or component to communicate with the computer system over one or more communication networks. Such a configuration permits any sensor or signal-generating device to be located at a significant distance from the computer system and/or allow any sensor to be located at a significant distance from any subsystem and/or the controller, while still providing data therebetween. Such communication mechanisms can be affected by utilizing any suitable technique including but not limited to those utilizing wireless protocols.
Although the computer system is described by way of example as one type of computer system upon which various aspects of the processes herein can be practiced, it should be appreciated that the invention is not limited to being implemented in software, or on the computer system as exemplarily described. Indeed, rather than implemented on, for example, a general purpose computer system, the controller, or components or subsections thereof, can alternatively be implemented as a dedicated system or as a dedicated programmable logic controller (PLC) or in a distributed control system. Further, it should be appreciated that one or more features or aspects of the processes can be implemented in software, hardware or firmware, or any combination thereof. For example, one or more segments of an algorithm executable by a controller can be performed in separate computers, which in turn, can be in communication through one or more networks.
In some embodiments, one or more sensors and/or flow meters can be included at locations throughout the process, which are in communication with a manual operator or an automated control system to implement a suitable process modification in a programmable logic controlled process. In one embodiment, a process includes a controller which can be any suitable programmed or dedicated computer system, PLC, or distributed control system. The flow rates of certain product streams can be measured, and flow can be redirected as necessary to meet the requisite product slate.
Factors that can result in various adjustments or controls include customer demand of the various hydrocarbon products, market value of the various hydrocarbon products, feedstock properties such as API gravity or heteroatom content, and product quality (for instance, gasoline and mid distillate indicative properties such as octane number for gasoline and cetane number for mid distillates).
The disclosed processes and systems create new outlets for direct conversion of crude oil, for instance, light crudes such as Arab Extra Light (AXL) or Arab Light (AL) crude oil. Additionally, the disclosed processes and systems offer novel configurations that, compared to known processes and systems, requires lower capital expenditure relative to conventional approaches of chemical production from fuels or refinery byproducts and that utilize refining units and an integrated chemicals complex. The disclosed processes and systems substantially increase the proportion of crude oil that is converted to high purity chemicals that traditionally command high market prices. Complications resulting from advancing the threshold of commercially proven process capacities are minimized or eliminated using the processes and systems described herein.
The disclosed processes and systems utilize different commercially proven units arranged in novel configurations. These novel configurations enable production of refined products and petrochemicals products including olefins, aromatics, MTBE, and butadiene. The disclosed processes and systems allow chemicals producers to de-couple from fuel markets and have more freedom to increase chemical yields as a fraction of crude rate, as compared to traditional chemical production using refinery fuels as feedstock. Also, the disclosed processes and systems substantially increase the proportion of crude oil that is converted to high purity chemicals that traditionally command high market prices.
The disclosed processes and systems provide alternatives for chemicals production that have lower capital investment relative to conventional routes that utilize refining units and an integrated chemicals complex. Moreover, the disclosed processes and systems offer the flexibility of simultaneously producing fuel products and chemical products. The ratio of chemicals to residual fuels can be modulated by process operations to address changing fuels and chemical market opportunities. In certain embodiments, the process configuration are flexible to enable processing 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 configurations offer the flexibility to structure operations to adjust the ratio of petrochemicals to refined products in order to achieve optimum operations and allows shifting the production ratio of chemicals to fuels, adjusting to market conditions.
The method and system of the present invention have been described above and in the attached drawings; however, modifications will be apparent to those of ordinary skill in the art and the scope of protection for the invention is to be defined by the claims that follow.

Claims

1. An integrated process for producing petrochemicals and fuel products from a crude oil feed comprising:

separating from the crude oil feed in an atmospheric distillation zone at least a first ADU fraction comprising straight run naphtha; a second ADU fraction comprising at least a portion of middle distillates from the crude oil feed, and a third ADU fraction comprising atmospheric residue;

separating from the third ADU fraction in a vacuum distillation zone a first VDU fraction comprising vacuum gas oil;

processing in a distillate hydroprocessing zone at least a portion of the second ADU fraction to produce at least a first DHP fraction and a second DHP fraction, wherein the first DHP fraction comprises naphtha and the second DHP fraction is used for diesel fuel production;

processing in a fluid catalytic cracking zone the first VDU fraction to produce at least a first FCC fraction corresponding to light olefins that are recovered as petrochemicals, a second FCC fraction corresponding to FCC naphtha and a third FCC fraction corresponding to cycle oil;

processing in a mixed feed stream cracking zone the first ADU fraction and an aromatics extraction zone raffinate, to produce at least

a mixed product stream comprising H2, methane, ethane, ethylene, mixed C3s and mixed C4s,

a pyrolysis gas stream, and

a pyrolysis oil stream;

recovering, from the mixed product stream, H2, methane, ethane, non-olefinic C3s and C4, and petrochemcials ethylene, propylene and butylenes,

passing recovered ethane and non-olefinic C3s to the mixed feed stream cracking zone, and passing non-olefinic C4s to the mixed feed stream cracking zone or to a separate processing zone for production of additional petrochemicals;

processing in a naphtha hydroprocessing zone pyrolysis gas from the mixed feed stream cracking zone to produce hydrotreated pyrolysis gas;

processing hydrotreated pyrolysis gas in an aromatics extraction zone to recover aromatic products and the aromatics extraction zone raffinate that is recycled to the mixed feed stream cracking zone.

2. The process as in claim 1, wherein the first DHP fraction is passed to the mixed feed steam cracking zone.

3. The process as in claim 1, wherein the first DHP fraction is passed to the mixed feed steam cracking zone through the atmospheric distillation zone, wherein the first DHP fraction passes to the mixed feed steam cracking zone with the first ADU fraction.

4. The process as in any of claims 1-3, further comprising hydrotreating the second FCC fraction to produce hydrotreated FCC naphtha.

5. The process as in claim 4, further comprising recovering C5s from the hydrotreated FCC naphtha and recycling the recovered C5s to the mixed feed stream cracking zone.

6. The process as in claim 4 or 5, further comprising processing the hydrotreated FCC naphtha in the aromatics extraction complex for recovery of additional aromatic products and additional aromatics extraction zone raffinate that is recycled to the mixed feed stream cracking zone.

7. The process as in any of claims 1-6, further comprising recovering C5s from the hydrotreated pyrolysis gas and passing the recovered C5s to the mixed feed stream cracking zone, the separate processing zone for production of additional petrochemicals, or both to the mixed feed stream cracking zone and the separate processing zone for production of additional petrochemicals.

8. The process as claim 7 wherein the recovered C5s are passed to the mixed feed stream cracking zone.

9. The process as claim 7 wherein the recovered C5s are passed to the separate processing zone for production of additional petrochemicals, wherein the separate processing zone converts mixture of butenes into mixed butanols.

10. The process as in any of claims 1-9, further comprising processing in a gas oil hydroprocessing zone the first VDU fraction prior to processing in the fluid catalytic cracking zone, wherein the gas oil hydroprocessing zone produces a first GOHP fraction containing hydrotreated distillates and a second GOHP fraction containing hydrotreated gas oil, wherein the second GOHP fraction is passed to the fluid catalytic cracking zone.

11. The process as in claim 10, wherein the hydrotreated distillates in the first GOHP fraction comprise naphtha that is routed to the mixed feed stream cracking zone and middle distillates used for fuel production.

12. The process as in claim 11, wherein the naphtha from the first GOHP fraction is passed to the mixed feed steam cracking zone.

13. The process as in claim 11, wherein the naphtha from the first GOHP fraction is passed to the mixed feed steam cracking zone through the atmospheric distillation zone, wherein the naphtha from the first GOHP fraction passes to the mixed feed steam cracking zone with the first fraction.

14. The process as in claim 10, wherein the first GOHP fraction is passed to the distillate hydroprocessing zone.

15. The process as in claim 10, further wherein the middle distillates in the second ADU fraction comprise heavy atmospheric gas oil that is processed in the gas oil hydroprocessing zone.

16. The process as in claim 10, further wherein the middle distillates in the second ADU fraction comprise heavy atmospheric gas oil that is processed in the fluid catalytic cracking zone without hydroprocessing, and the first VDU fraction is hydroprocessed in the gas oil hydroprocessing zone.

17. The process as in claim 10, further comprising passing at least a portion of the third FCC fraction in the distillate hydroprocessing zone.

18. The process as in any of claims 1-17, wherein the step of separating from the crude oil feed in an atmospheric distillation zone further comprises recovering light petroleum gases, the process further comprising processing the light petroleum gases in a saturated gas plant to recover C3s and C4s that are routed to the mixed feed stream cracking zone.

19. The process as in any of claims 1-18, wherein the middle distillates in the second ADU fraction comprise

kerosene that is processed in a kerosene sweetening process to recover a kerosene fuel product, and

a straight run diesel fraction that is the portion of the second ADU fraction that is processed in the distillate hydroprocessing zone.

20. The process as in claim 19, further wherein the middle distillates in the second ADU fraction comprise heavy atmospheric gas oil that is processed in the fluid catalytic cracking zone.

21. The process as in any of claims 1-20, wherein non-olefinic C4s recovered from the mixed product stream are recycled to the mixed feed stream cracking zone.

22. The process as in any of claims 1-19, wherein non-olefinic C4s recovered from the mixed product stream are recycled to the separate processing zone for production of additional petrochemicals.

23. The process as claim 22, further comprising

recovering C5s from the hydrotreated pyrolysis gas;

passing the recovered C5s to the separate processing zone for production of additional petrochemicals;

passing a portion of the recovered ethylene to the separate processing zone;

wherein the separate processing zone carries is a metathesis reaction zone which produces petrochemical propylene and a C4/C5 raffinate stream that is recycled to the mixed feed stream cracking zone.

24. An integrated process for producing petrochemicals and fuel product comprising

(a) providing

(a)(1) a mixed feed steam cracking zone receiving a plurality of feeds from multiple sources, and outputting a mixed C1-C4 stream, a py-gas stream and a py-oil stream;

(a)(2) a fluid catalytic cracking zone operating under conditions effective for high olefin production, receiving a VGO stream, and outputting a C2− stream, a C3-C4 stream, a FCC naphtha stream, and one or more cycle oil streams;

(a)(3) an olefins recovery zone receiving the mixed C1-C4 stream from the mixed feed steam cracking zone, and outputting an ethane stream, a hydrogen gas stream, a fuel gas stream, an ethylene stream, a mixed C3s stream and a mixed C4s stream; and

(a)(4) an aromatics extraction zone receiving the py-gas stream, and outputting BTX products and a raffinate stream;

(b) charging the plurality of feeds to the mixed feed steam cracking zone, the plurality of feeds including an LPG stream, a straight run naphtha stream, the ethane stream from the olefins recovery zone and the raffinate stream from the aromatics extraction zone;

(c) passing the mixed C1-C4 stream to the olefins recovery zone for separation into at least the ethane stream, the hydrogen gas stream, the fuel gas stream, the ethylene stream, the mixed C3s stream and the mixed C4s stream, and recycling the ethane stream to the mixed feed steam cracking zone;

(d) hydrotreating all or a portion of the py-gas stream, and passing the hydrotreated py-gas stream to the aromatics extraction zone for separation into BTX and the raffinate stream, and routing the raffinate stream to the mixed feed steam cracking zone;

(e) charging the VGO stream to the fluid catalytic cracking zone for production of and separation into the C2− stream, the C3-C4 stream, the FCC naphtha stream, and the one or more cycle oil streams.

25. The integrated process as in claim 24, further comprising routing hydrotreated naphtha, derived from hydrotreating a straight run diesel stream, to the mixed feed steam cracking zone as an additional one of the plurality of feeds, and further comprising recovering a diesel fuel stream.

26. The integrated process as in claim 25, wherein a source of hydrogen for the step of hydrotreating all or a portion of the straight run diesel stream is from the olefins recovery zone.

27. The integrated process as in claim 24, further comprising routing hydrotreated naphtha, derived from hydrotreating a portion of a kerosene stream, to the mixed feed steam cracking zone as an additional one of the plurality of feeds, and further comprising recovering a diesel fuel stream.

28. The integrated process as in claim 27, wherein the portion of the kerosene stream that is hydrotreated is a heavy kerosene stream.

29. The integrated process as in claim 27, further comprising hydrotreating a medium AGO stream with the heavy kerosene stream.

30. The integrated process as in claim 27, wherein a source of hydrogen for the step of hydrotreating the portion of a kerosene stream is from the olefins recovery zone.

31. The integrated process as in claim 24, wherein the LPG stream, the straight run naphtha stream, the AGO stream and the VGO stream are derived from a common crude oil feed.

32. The integrated process as in claim 25, wherein the LPG stream, the straight run naphtha stream, the straight run diesel stream and the VGO stream are derived from a common crude oil feed.

33. The integrated process as in claim 31 or 31, wherein the common crude oil feed is Arab Extra Light crude oil.

34. The integrated process as in claim 31 or 31, wherein the common crude oil feed is Arab Light crude oil.

35. The integrated process as in claim 31 or 31, further comprising subjecting a kerosene fraction from the common crude oil feed to a kerosene sweetening process to recover a jet fuel product.

36. The integrated process as in claim 24, further comprising hydrotreating all or a portion of the FCC naphtha stream to produce a hydrotreated FCC naphtha stream, and routing all or a portion of the hydrotreated FCC naphtha stream to the aromatics extraction zone.

37. The integrated process as in claim 36, wherein a source of hydrogen for hydrotreating all or a portion of the FCC naphtha stream is from the olefins recovery zone.

38. The integrated process as in claim 36, wherein hydrotreating of all or a portion of the py-gas stream occurs in a different reactor than hydrotreating of all or a portion of the FCC naphtha stream.

39. The integrated process as in claim 38, wherein

a source of hydrogen for hydrotreating all or a portion of the py-gas stream is from the olefins recovery zone, and

a source of hydrogen for hydrotreating all or a portion of the FCC naphtha stream is from the olefins recovery zone.

40. The integrated process as in claim 36, wherein hydrotreating of all or a portion of the py-gas stream occurs in the same reactor as the hydrotreating of all or a portion of the FCC naphtha stream.

41. The integrated process as in claim 40, wherein a source of hydrogen for hydrotreating all or a portion of the py-gas stream and all or a portion of the FCC naphtha stream is from the olefins recovery zone.

42. The integrated process as in claim 24, wherein a source of hydrogen for hydrotreating all or a portion of the py-gas stream is from the olefins recovery zone.

43. The integrated process as in claim 24, further comprising hydrotreating all or a portion of an AGO stream, all or a portion of the VGO stream, or a combination of all or a portion of the AGO stream and all or a portion of the VGO stream, to produce a hydrotreated naphtha stream, a diesel fuel stream and hydrotreated gas oil stream, wherein the hydrotreated gas oil stream is the feed to the fluid catalytic cracking zone.

44. The integrated process as in claim 43, wherein a source of hydrogen for hydrotreating is from the olefins recovery zone.

45. The integrated process as in claim 43, wherein the hydrotreated naphtha stream is routed to the mixed feed steam cracking zone as an additional one of the plurality of feeds.

46. The integrated process as in claim 43, comprising hydrotreating a feed comprising heavy AGO from the AGO stream and the VGO stream.

47. The integrated process as in claim 24, further comprising

hydrotreating all or a portion of an AGO stream, all or a portion of the VGO stream, or a combination of all or a portion of the AGO stream and all or a portion of the VGO stream, to produce a distillates stream, a diesel fuel stream and a hydrotreated gas oil stream, wherein the hydrotreated gas oil stream is the feed to the fluid catalytic cracking zone; and

routing hydrotreated naphtha, derived from hydrotreating a straight run diesel stream, to the mixed feed steam cracking zone as an additional one of the plurality of feeds, and further comprising recovering a diesel fuel stream from the straight run diesel stream and the distillates stream.

48. The integrated process as in claim 47, wherein a source of hydrogen for hydrotreating all or a portion of the straight run diesel stream is from the olefins recovery zone.

49. The integrated process as in claim 47 or 48, wherein a source of hydrogen for hydrotreating all or a portion of the AGO stream and/or all or a portion of the VGO stream is from the olefins recovery zone.

50. The integrated process as in claim 47, wherein the distillates stream from the hydrotreating zone (GOHT) is hydrotreated with the straight run diesel stream.

51. The integrated process as in claim 47, comprising hydrotreating a feed comprising heavy AGO from the AGO stream and the VGO stream.

52. The process as in claim 24, wherein the olefins recovery zone includes cooling, compression, caustic washing, and one or more distillation steps for separation into hydrogen, fuel gas, ethane that is recycled to the mixed feed steam cracking zone, ethylene, mixed C3s and mixed C4s.

53. The process as in claim 24, further comprising passing light olefin intermediate product from the fluid catalytic cracking zone subjected to an unsaturated gas reaction zone to the olefins recovery zone.

54. The process as in claim 53, further comprising subjected the mixed C3s from the olefins recovery zone to methyl acetylene/propadiene (MAPD) saturation by reaction with hydrogen to produce a saturated mixed C3 intermediate, wherein the saturated mixed C3 intermediate contains a reduced proportion of methyl acetylene/propadiene compared to the mixed C3s from the olefins recovery zone and an increased proportion of propylene.

55. The process as in claim 54, further comprising separating propylene from other mixed C3 compounds in the saturated mixed C3 intermediate.

56. The process as in claim 55, further comprising recycling the other mixed C3 compounds to the mixed feed steam cracking zone.