INTEGRATED PROCESS SOLUTION FOR MAXIMIZING CRUDE TO LIGHT OLEFINS AND CHEMICALS

Abstract

Systems and processes herein integrate a crude separation unit, a steam cracker unit, a hydrocracker unit, an aromatics processing unit, and a pyrolysis gasoline hydrogenation unit for separating a whole crude oil or other wide boiling hydrocarbon mixtures for producing olefins and aromatics.

Description

FIELD OF THE DISCLOSURE Embodiments of the present disclosure generally relate to the conversion of whole crudes and other wide boiling hydrocarbon mixtures to olefins.

BACKGROUND

In recent times, the evolving market dynamics have led refining companies to seek new opportunities in petrochemical production from crude oil, shifting their focus from fuel production due to decreasing fuel demand. Ethylene and propylene are of significant importance as key building blocks in the petrochemical industry.

One process to convert crude to olefins is disclosed in US20230212464. However, there remain challenges in the conversion of crude oils to light olefins.

SUMMARY OF THE CLAIMED EMBODIMENTS

In one aspect, embodiments disclosed herein relate to a process for converting whole crudes and other wide boiling hydrocarbon mixtures into light olefins. The process includes separating a wide boiling hydrocarbon mixture to recover a vaporized low boiling portion and a remaining liquid portion. The low boiling portion has an end boiling point in the range from about 150° C. to 550° C., such as from about 150° C. to 500° C. and the liquid portion has an end boiling point greater than the end boiling point of the light portion. The process further includes thermally cracking the low boiling portion to recover a first cracked effluent and separating the first cracked effluent to recover one or more light olefin fractions, a fuel oil fraction, a pyrolysis gasoline fraction, and a pyrolysis oil fraction. The pyrolysis gasoline fraction is then hydrogenated to form a hydrogenated pyrolysis gasoline, which is separated to recover a C5− fraction, a C6 to C8 fraction, and a C9+ fraction. The C9+ fraction and the pyrolysis oil fraction are hydrocracked to recover one or more hydrocracked effluents, which are separated to recover a light boiling fraction, a medium boiling fraction, and a high boiling fraction (for example, a C1 to C4 or C1 to C5 fraction, a naphtha range fraction, and a gas oil fraction). The process also includes thermally cracking the C5− fraction, the light boiling fraction, the medium boiling fraction, and the high boiling fraction, and collectively separating the cracked effluents with the first cracked effluent to recover the one or more light olefin fractions, the fuel oil fraction, the pyrolysis gasoline fraction, and the pyrolysis oil fraction.

In another aspect, embodiments disclosed herein relate to a process for producing olefins. The process includes separating a whole crude oil to recover a light cut and a heavy cut. The process also includes hydrogenating a pyrolysis gasoline to produce a hydrogenated effluent and separating the hydrogenated effluent to recover a C5− fraction, a C6 to C8 fraction, and a C9+ fraction. The C6 to C8 fraction are processed in one or more of an aromatics dealkylation unit, an aromatics extraction unit, and an aromatics saturation unit to recover a non-aromatic hydrocarbon stream. The process further includes hydrocracking a pyrolysis oil, the heavy cut, and the C9+ fraction, and optionally benzene, toluene, xylenes (BTX) and cycloalkanes, including multi-cyclic rings, to recover a hydrocracked effluent. The hydrocracked effluent, the non-aromatic hydrocarbon stream, the C5− fraction, and the light cut are then thermally cracked to recover one or more steam cracked effluents, which may be collectively separated to recover one or more olefin fractions, the pyrolysis gasoline, and the pyrolysis oil.

In another aspect, embodiments disclosed herein relate to a system for producing olefins. The system includes a crude separation unit for separating a whole crude oil to recover a light cut and a heavy cut. The system also includes a pyrolysis gasoline hydrogenation unit for hydrogenating a pyrolysis gasoline to produce a hydrogenated effluent and separating the hydrogenated effluent to recover a C5− fraction, a C6 to C8 fraction, and a C9+ fraction. Further, the system includes an aromatics processing unit for processing the C6 to C8 fraction in one or more of an aromatics dealkylation unit, an aromatics extraction unit, and an aromatics saturation unit to recover a non-aromatic hydrocarbon stream. Also provided in the system are a hydrocracker unit for hydrocracking a pyrolysis oil, the heavy cut, the C9+ fraction, and optionally benzene, toluene, xylenes (BTX) and cycloalkanes, including multi-cyclic rings, to recover a hydrocracked effluent, and a steam cracker for steam cracking the hydrocracked effluent, the non-aromatic hydrocarbon stream, the C5− fraction, and the light cut to recover one or more steam cracked effluents. Lastly, a separation system is provided for collectively separating the one or more steam cracked effluents to recover one or more olefin fractions, the pyrolysis gasoline, and the pyrolysis oil. A flow line is provided for feeding the pyrolysis gasoline from the separation system to the pyrolysis gasoline hydrogenation unit, and a flow line is provided for feeding the pyrolysis oil from the separation system to the hydrocracker unit.

Other aspects and advantages will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

The FIGURE illustrates a simplified block process flow diagram of systems for converting wide boiling hydrocarbon mixtures to light olefins and chemicals according to one or more embodiments disclosed herein.

DETAILED DESCRIPTION

Embodiments herein relate to processes and systems that take crude oil and/or other wide boiling hydrocarbon mixtures as a feedstock to produce petrochemicals, such as light olefins and diolefins (ethylene, propylene, butadiene, and/or butenes) and aromatics. More specifically, embodiments herein are directed toward methods and systems for making olefins and aromatics by thermal cracking of hydrocarbons.

Processes disclosed herein can be applied to feedstocks such as crude oils, condensates, condensate liquids and hydrocarbons. Restated, embodiments herein may apply to various hydrocarbon mixtures having a boiling point range inclusive of two or more fractions that may be preferentially cracked at different operating conditions. Embodiments herein may also process wide boiling feedstocks, inclusive of those having end points higher than 500° C.

Hydrocarbon feedstocks that may be processed according to embodiments herein include hydrocarbon mixtures such as whole crudes, virgin crudes, hydroprocessed crudes, gas oils, vacuum gas oils, heating oils, jet fuels, diesels, kerosenes, gasolines, synthetic naphthas, raffinate reformates, Fischer-Tropsch liquids, Fischer-Tropsch gases, natural gasolines, atmospheric distillates, vacuum distillates, virgin naphthas, natural gas condensates, atmospheric pipestill bottoms, vacuum pipestill streams including bottoms, wide boiling range naphtha to gas oil condensates, heavy non-virgin hydrocarbon streams from refineries, vacuum gas oils, heavy gas oils, atmospheric residuum, hydrocracker wax, and Fischer-Tropsch wax, among others. In some embodiments, the hydrocarbon mixture may include hydrocarbons boiling from the naphtha range or lighter (natural gas or ethane) to the vacuum gas oil range or heavier.

One or more of the above hydrocarbon feedstocks may be fed to systems and processes herein to produce olefins and aromatics. As used herein, the term “petrochemicals” refers to hydrocarbons including light olefins and diolefins and C6-C8 aromatics. Petrochemicals thus refers to hydrocarbons including ethylene, propylene, butenes, butadienes, pentenes, pentadienes, as well as benzene, toluene, and xylenes. Referring to a subset of petrochemicals, the term “chemicals,” as used herein, refers to ethylene, propylene, butadiene, 1-butene, 2-butene, isobutylene, benzene, toluene, and para-xylenes.

In some embodiments, systems and processes herein may be used for producing olefins or olefins and aromatics from a crude oil. “Crude oil” as used in the following discussion and the claims, is inclusive of natural gas condensates and condensate liquids produced from a hydrocarbon-bearing reservoir. Such feedstocks may undergo various upstream processing, such as proximate a well, to meet transport regulations or pipeline requirements for transportation to a chemical plant, petrochemical plant, or refinery. Various contaminants that are produced along with the hydrocarbons from the reservoir or that are introduced in such upstream processing are removed during the desalting process. Embodiments herein that are used for converting a crude oil to petrochemicals or olefins may thus include a step of desalting the crude oil.

System for producing olefins according to embodiments herein may include five primary unit operations, including a crude separation unit, a hydrocracking unit, a steam cracking unit, a pyrolysis gasoline hydrogenation unit, and an aromatics processing unit. Each of the unit operations may include one or more reactors for converting hydrocarbons therein, as well as one or more separators (distillation columns, extractive distillation columns, flash drums, strippers, etc. as known in the art) for separating the reactor effluents to recover desired products. While illustrated and described herein generally, it should be understood that, for simplicity of illustration, the multiple reactors, separators, as well as pumps, filters, feed treaters, valves, off-gas treaters, utility streams, heaters and heat exchangers, and other aspects not illustrated are present.

Crude Separation Unit

In general, the crude separation unit is provided for separating a whole crude oil or a wide boiling hydrocarbon mixture to recover a light cut and a heavy cut based on boiling point separations. In some embodiments, a light cut, one or more medium cuts, and a heavy cut may be recovered. The light cut is fed to the steam cracking unit and the heavy cut is fed to the hydrocracker unit. In embodiments producing one or more medium cuts, the medium cuts may be fed to either the steam cracking unit or the hydrocracker unit, depending upon the types of hydrocarbons therein and their affinity for steam cracking; medium cuts having a content of compounds sufficient to cause fouling in a steam cracker may be forwarded to the hydrocracker unit for conversion to steam crackable feeds, i.e., with a lower fouling tendency, for example.

A hydrocarbon feedstock, such as a crude oil or wide boiling hydrocarbon mixture, as described above, is initially separated in embodiments herein to produce two or more feeds of distinct boiling ranges for selective processing. Following desalting (if needed) and heating, the heated hydrocarbon feedstock is then fed to a separation system for separating a light paraffinic fraction or cut, recovered as a vapor from the separation system, from the heavier hydrocarbons in the desalted feed, recovered as a liquid from the separation system. The separation system may include, for example, an integrated separation device (ISD) or a heavy oil processing scheme (HOPS). In some embodiments, separation of the petroleum feeds may be performed in an integrated separation device (ISD), such as disclosed in US20130197283. In the ISD, an initial separation of a low boiling fraction is performed in the ISD based on a combination of centrifugal and cyclonic effects to separate the desired vapor fraction from liquid. In other embodiments, separation of the petroleum feeds may be performed in a Heavy Oil Processing Scheme (HOPS unit), such as described in US10793793, for example. In the HOPS unit, the hydrocarbon feedstock is preheated, mixed with dilution steam, and separated to recover a light fraction, vapor mixed with dilution steam, and a heavy fraction, a liquid stream comprising compounds that cannot be easily vaporized. An ISD or HOPS may be used, for example, to limit or eliminate carry over of liquid droplets that may contain heavier hydrocarbons that may have a tendency to foul heat exchangers and radiant coils. In some embodiments, the separation system is a simple flash drum, recovering hydrocarbons volatilized in an upstream heater or heat exchanger. Due to the fouling tendency of heavier hydrocarbons, the ISD or HOPS are preferred over simple flash drums or stripers so as to limit entrainment of liquid droplets that may contain the heavier hydrocarbons. The light paraffinic cut recovered as a vapor from the separation system may have an end boiling point, for example, in a range from 135° C. to 225° C., such as from about 160° C. to about 180° C. For feeds containing a low amount of compounds having a high fouling tendency, a light cut having an end boiling point up to 550° C., such as up to 250° C., 300° C., 400° C., or even 500° C. may be tolerated.

Depending upon the aromaticity, sweetness, or fouling tendency of middle boiling components in the crude oil or wide boiling hydrocarbon feedstock, the end boiling point of the light fraction may range up to 550° C., such as up to about 500° C. In some embodiments a first separator, such as an ISD or a HOPS, may be used to recover a light boiling fraction, such as having an end boiling point in a range from 160° C. to 180° C., as described above, and following heating of the remaining heavier hydrocarbons, a second separator, such as an ISD or a HOPS, may be used to recover an intermediate or middle boiling range hydrocarbon cut, such as having an initial boiling point in a range from 160° C. to 180° C. and an end boiling point in a range from 280° C. to 350° C. The intermediate cut may be superheated and fed to a radiant coil to produce chemicals, such as ethylene and propylene, among others, and the cracked intermediate cut effluent may be quenched in a common or separate transfer line exchanger, fed to heat recovery, and thence to the fractionation zone for recovery of the various hydrocarbon fractions along with the other cracked effluents.

Light fractions processed, such as a 180° C.—cut, are generally suitable for direct feed for cracking, and do not require further processing. Depending upon the aromaticity, sweetness, or fouling tendency of middle and higher boiling components in the hydrocarbon feedstock, embodiments herein hydrocrack the residual liquid fraction following separation of the hydrocarbon feedstock in the crude separation unit. In addition to hydrocracking the residual liquid fraction, one or more higher boiling fractions or cuts as may be recovered in the crude separation unit, such as the one or more middle boiling cuts may also be processed in the hydrocracking unit so as to improve the crackability of the hydrocarbons in the respective cuts. The severity of the hydrocracking reactors and the integration of such treating systems, to provide “crackable” hydrocarbon feeds to the steam cracking unit used, may depend upon the feedstock(s) being processed and are not described here in greater detail.

Systems and processes herein thus include a heating and separation system for separating the wide boiling hydrocarbon feedstock into a light fraction containing volatilized hydrocarbons and a heavy fraction. If multiple fractions of particular cut points are desired, the resulting heavy (liquid) fraction may be further heated and separated to recover, for example, an intermediate boiling fraction and a residue fraction. Such sequential separations may be performed to generate two, three or more vaporized fractions, having a boiling range and cut point, and a residue fraction.

Separation of various fractions, such as a low boiling fraction (a 160° C.−fraction, for example) and a high boiling fraction (a 160° C.+fraction, for example), or such as a low, middle and high boiling fractions (a 160° C.−fraction, a 160-490° C. fraction, and a 490° C.+fraction, for example) may enhance the capital efficiently and operating costs of the processes and systems disclosed herein. While referring to three cuts in many embodiments herein, it is recognized by the present inventors that condensates, typically having a small amount of high boiling components, and whole crudes, having a greater quantity of high boiling components, may be processed differently. Accordingly, one, two, three or more individual cuts can be performed for the wide boiling range petroleum feeds, and each cut can be processed separately at optimum conditions.

Pyrolysis Gasoline Hydrogenation Unit

The pyrolysis gasoline hydrogenation unit is provided for hydrogenating pyrolysis gasoline, such as may be produced in the steam cracker unit. The pyrolysis gasoline unit includes reactors to hydrogenate the pyrolysis gasoline to produce a hydrogenated effluent and separators for separating the hydrogenated effluent to recover a C5− fraction, a C6 to C8 fraction, and a C9+ fraction. In some embodiments, a high boiling hydrogenated product may also be recovered, and in such embodiments the C9+ fraction may have an end boiling point in a range from about 200° C. to about 250° C.

Hydrogenation reactors useful in embodiments herein may include fixed bed reactors, bubbling bed reactors, motive bed reactors, slurry reactors, and other reactor types known in the art for contacting an unsaturated hydrocarbon with hydrogen over a hydrogenation catalyst. The reactor system may include one or more reactors, of the same or different type, and where multiple reactors are used, such reactors may be arranged in parallel, in series, or in both parallel and series.

Separation systems associated with the pyrolysis gasoline hydrogenation unit may include one or more distillation columns for recovering the desired fractions. For example, the separation system may include a hydrogen recovery unit for recovering an off-gas or recycle hydrogen fraction, a debutanizer or depentanizer for recover a C1 to C4 or a C1 to C5 fraction, and a naphtha fractionator for recovering a C6 to C8 fraction and a remaining heavies fraction, a C9+ fraction. In some embodiments, the heavies fraction may be further separated to limit an end boiling point of the C9+ fraction, as noted above. For feedstocks that may produce a pyrolysis gasoline fraction from the steam cracker system that contains sulfur-or nitrogen-containing compounds, the separation system may also contain amine or other treating systems for separating acid gases from recycle hydrogen.

Aromatics Processing Unit

The aromatics processing unit is provided for processing the C6 to C8 fraction produced in the pyrolysis gasoline hydrogenation unit. The aromatics processing unit may include one or more unit operations, such as an aromatics dealkylation unit, an aromatics extraction unit, and an aromatics saturation unit, and may be configured to produce a non-aromatic hydrocarbon stream. Depending upon the configuration and arrangement of the included unit operations within the aromatics processing unit, embodiments may also produce one or more aromatics products (such as benzene, toluene, and xylenes (BTX)), and one or more cycloalkane products. The resulting streams may then be recovered as a product or may be recovered as a feedstock for further processing in the steam cracker unit or the hydrocracker unit.

In some embodiments, the aromatics processing unit includes an aromatics saturation unit. The aromatics saturation unit may include one or more reactors for contacting the C6 to C8 cut with hydrogen over an aromatics hydrogenation catalyst to produce a cycloalkanes/non-aromatics product containing saturated hydrocarbons, including a mixture of cycloalkanes and C6 to C8 paraffins. The saturated hydrocarbon mixture may then be fed to the steam cracking unit for production of additional ethylene and propylene. In some embodiments, the aromatics saturation unit includes a separation system to separate unreacted hydrogen from the saturated reactor effluent. In various embodiments, the separation system may include separators configured for separating a cycloalkane fraction or a cycloalkane-rich fraction from a C6 to C8 non-aromatics or C6 to C8 paraffin-rich fraction. The C6 to C8 paraffinic fraction may be fed to the steam cracker unit for conversion to ethylene and propylene. Alternatively, the cycloalkanes may be fed to the steam cracker unit or may be fed to the hydrocracker unit to produce a more suitable non-cyclic hydrocarbon feed that may then be fed to the steam cracker unit.

In some embodiments, the aromatics processing unit includes an aromatics dealkylation unit and an aromatics saturation unit. The aromatics dealkylation unit may include one or more reactors configured to produce a benzene product from an aromatics containing feedstock. For example, toluene and xylenes present in the C6 to C8 fraction may be converted to benzene in the aromatics dealkylation unit. The resulting dealkylation reaction product may then be separated to provide a benzene product stream and a paraffin stream. The paraffin stream may be fed to the steam cracker unit, while the benzene may be recovered as a product, or, depending upon market demand, a portion or an entirety of the benzene produced may be saturated in an aromatics saturation unit to provide a cycloalkane that may be fed to either the steam cracker unit or the hydrocracker unit, as described above.

In some embodiments, the aromatics processing unit includes a BTX extraction unit and an aromatics saturation unit. The BTX extraction unit may include one or more extractive distillation columns, for example, to separate the aromatic compounds from non-aromatic compounds contained in the C6 to C8 fraction. The C6 to C8 non-aromatics may be fed to the steam cracker unit for production of additional ethylene and propylene. The aromatic compounds may be recovered as a BTX product, or, depending upon market demand, a portion or an entirety of the BTX produced may be saturated in an aromatics saturation unit to provide a cycloalkane that may be fed to either the steam cracker unit or the hydrocracker unit, as described above, or a portion or an entirety of the BTX product may be sent to the hydrocracker unit.

Inclusion of either an aromatics dealkylation unit or a BTX extraction unit with an aromatics saturation unit provide flexibility to processes herein to capture aromatics for sale while also providing for conversion of any excess aromatics to propylene and ethylene, accommodating the ebb and flow of market demand for aromatics.

Hydrocracker Unit

The hydrocracker unit is provided for hydrocracking (i) a pyrolysis oil, such as may be produced in the steam cracker unit, (ii) the heavy cut, as produced in the crude separation unit, and (iii) the C9+ fraction, produced in the pyrolysis gasoline unit, and optionally (iv) the BTX produced from the BTX extraction unit and/or cycloalkanes from the aromatics saturation unit, to recover one or more hydrocracked effluents. The hydrocracker unit may include one or more hydrocracking reactors, and the respective feeds may be processed separately or collectively. The hydrocracker unit may also include separators to separate the hydrocracked effluent(s) into distinct boiling point fractions, such as a C1-C4 cut, a naphtha cut, and a gas oil fraction, which may be separately fed to and processed within the steam cracking unit.

Hydrocracking reactors useful in embodiments herein may include fixed bed reactors, bubbling bed reactors, motive bed reactors, slurry reactors, and other reactor types known in the art for contacting an hydrocarbons with hydrogen over a hydrocracking catalyst. The reactor system may include one or more reactors, of the same or different type, and where multiple reactors are used, such reactors may be arranged in parallel, in series, or in both parallel and series.

Separation systems associated with the hydrocracking unit may include one or more distillation columns for recovering desired fractions, such as a light boiling fraction, a medium boiling fraction, and a high boiling fraction. For example, the separation system may include a hydrogen recovery unit for recovering an off-gas or recycle hydrogen fraction, a debutanizer or depentanizer for recover a light hydrocarbon fraction, such as a C1 to C4 or a C1 to C5 fraction, a naphtha fractionator for recovering a fraction containing naphtha range hydrocarbons and a remaining heavies fraction, such as a gas oil fraction. For feedstocks that may produce a hydrocracker feedstock (heavies cut from the crude separation unit, pyrolysis oil from the steam cracker unit, C9+ fraction from the pyrolysis gasoline hydrogenation unit, BTX from the aromatics extraction unit, and/or cycloalkanes from the aromatics saturation unit) that contains sulfur-or nitrogen-containing compounds, the separation system may also contain amine or other treating systems for separating acid gases from recycle hydrogen.

Steam Cracking Unit

The steam cracking unit includes one or more furnaces or cracking heaters for steam cracking the various crackable feedstocks provided from each of the crude separation unit, the aromatics processing unit, and the pyrolysis gasoline hydrogenation unit. One or more furnaces or cracking heaters may be provided for heating and thermally cracking the respective fractions or feeds, such as the hydrocracked effluent or distinct boiling point fractions derived therefrom, the non-aromatic hydrocarbon stream, the C5− fraction, and the light cut, to recover one or more steam cracked effluents. The steam cracking unit also includes a separation system for collectively separating the one or more steam cracked effluents to recover one or more olefin fractions, the pyrolysis gasoline fed to the pyrolysis gasoline hydrogenation unit, and the pyrolysis oil fed to the hydrocracker unit.

Steam cracking units herein include heaters and superheaters to heat the various feedstocks to elevated temperatures that may be slightly below or proximate the temperatures at which the onset of cracking reactions begin for the respective feedstock. The steam cracker feedstock(s) may then be superheated using one or more cracking heaters or radiant heating coils, thermally cracking the feedstock at an appropriate cracking temperature, such as greater than 700° C. up to about 1100° C., thereby thermally cracking the hydrocarbons to produce lighter hydrocarbons, such as ethylene, propylene, and butenes, among others.

The effluent(s) from the thermal cracking reactors or radiant coils are then fed to a transfer line exchanger to rapidly quench the cracked effluent to a temperature below cracking temperature. Additional heat may then be recovered from the cracked effluent and the cooled effluent is fed to a fractionation zone to separate the cracked effluent into various hydrocarbon fractions. Separation systems associated with a thermal cracking system may vary, and may be used to separate the cracked effluent into broad cuts, such as a hydrogen fraction, a C1, C2−, C3− or C4− cut, a naphtha range cut, a diesel or jet fuel range cut, a gas oil range cut, a pyrolysis gasoline fraction and a pyrolysis oil (heavy/bottoms) fraction. Some separation systems used in embodiments of fractionation zones herein may include demethanizers, deethanizers, depropanizers, as well as separators to recover the various olefins, such as a deethylenizer to separate ethylene from ethane, a depropylenizer to separate propane from propylene, as well as debutanizers, deisobutylenizers, or other various separators and distillation columns or extractive distillation columns that are known in the art for recovering specific hydrocarbons or hydrocarbon cuts from a mixture of hydrocarbons. Embodiments of separation systems used for separating the thermally cracked effluents herein may produce, among other fractions, an ethylene fraction, a propylene fraction, a pyrolysis gasoline fraction, a pyrolysis oil fraction, and a fuel oil fraction.

Steam cracking units herein may include cracking heaters, cracking furnaces, or combinations thereof. Cracking heaters, for example, may include electric heaters configured for heating of a hydrocarbon feedstock to cracking temperatures, may be furnaces configured for heating of a hydrocarbon feedstock to cracking temperatures, or may be a combination of cracking heaters and cracking furnaces that may be used for processing select feeds.

An objective of embodiments herein is to maximize yields of light olefins, especially ethylene and propylene, through the direct processing of crude oil or other wide boiling hydrocarbon mixtures. As outlined above, and as illustrated in the Figure, the process involves separating a hydrocarbon feedstock 10, such as a crude oil or a wide boiling hydrocarbon mixture, in a crude separation unit 12 by heating the crude oil in a heater followed by steam stripping or other separations to recover a lighter portion 14 of the crude which is routed to a steam cracker 16 and a balance liquid portion 18 processed in a hydrocracker 20 along with low-value pyrolysis oil or light pyrolysis oil 22 from the steam cracker 16. The effluent 24 from the hydrocracker is cooled and further processed in steam cracker 16. The products (not fed to other units) from the steam cracker include mainly ethylene 26 and propylene 28 along with small quantities of fuel oil 30. The steam cracker's pyrolysis gasoline 32 is processed in the pyrolysis gasoline hydrogenation (PGH) unit 34.

The PGH unit 34, as noted above, may produce a C5− stream 36, a C6-C8 cut 38, and a C9+ cut 40. The C6-C8 cut stream 38 generated from the PGH unit 34 may be saturated to cycloalkanes 44 in an aromatics saturation unit 42 and cracked in the steam cracker 16 to further improve the light olefins yields. In some embodiments, cycloalkanes 44A produced in the aromatics saturation unit 42 may be processed first in the hydrocracker unit 20 to produce light paraffins 24 which may be subsequently processed in the steam cracker 16 to improve the light olefins yields.

Alternatively, the C6-C8 cut may be processed in an aromatics dealkylation unit 50 or a BTX extraction unit 60. Benzene 52 or BTX 62 may be recovered as a product or may be further saturated to cycloalkanes in aromatics saturation unit 42 and fed to the steam cracker unit 16 or hydrocracker unit 20 as needed. For example, C6-C8 non-aromatics 64 from the BTX Extraction Unit 60 and C9-204° C. hydrocarbons from the PGH 34 unit are processed in the steam cracker 16 unit and the hydrocracker unit 20, respectively.

Various hydrogen supply streams 70 are also illustrated. The hydrogen supply streams 70 may be provided by a common feed, purification, compression, and recycle systems in some embodiments. In other embodiments, separate hydrogen feed, purification, compression, and recycle systems may be associated with each unit.

As described above, embodiments described herein provide flexibility for processing various feeds from condensates to crude with an end point boiling range up to 550° C. or in some cases up to 650° C. or as high as 700° C. Hydrocarbon mixtures may include whole crudes, virgin crudes, hydroprocessed crudes, gas oils, vacuum gas oils, heating oils, jet fuels, diesels, kerosene, gasolines, synthetic naphthas, raffinate reformates, Fischer-Tropsch liquids, Fischer-Tropsch gases, natural gasolines, distillates, virgin naphthas, natural gas condensates, atmospheric pipestill bottoms, vacuum pipestill stream including bottoms, wide boilng range naphtha to gas oil condensates, heavy non virgin hydrocarbon streams from refineries and plastic pyrolysis oil among others. If desired, these feeds may be pre-processed to remove a portion of sulfur, nitrogen, metals and Conradson Carbon upstream of processes disclosed herein.

When the end boiling point of the hydrocarbon mixture is high, such as above 480-500° C., it cannot be directly processed in the pyrolysis heater to produce olefins, as the heater cokes rapidly. While limiting the reactions conditions may reduce the fouling tendencies, the less severe conditions result in a significant loss in the yields. Whole crude is not cracked as it is not economical due to sub-optimal yields for co-processing of all the different cuts and also because of coking tendencies of heavy tail end present in the crude. Whole crude is generally fractionated, and only specific cuts are used in the pyrolysis heater to produce olefins. The remainder is used in the other processes.

In the current scheme, the feed is processed in the Crude Separation Unit which, in some embodiments, utilizes the Steam Cracker furnace(s) to preheat and subsequent steam stripping of the crude to separate it at the desired cut point(s). Steam used for stripping the light end of the crude also serves as a diluent which helps reduce the hydrocarbon partial pressure in the radiant coil thus improving the yields further. Lighter cut may be in the boiling range from end point 70° C. to 360° C. or as high as 500° C. and heavier cut boiling range (TBP) may be from 70° C. to greater than 700° C. Based on the quality of crude and the distribution of constituent paraffins, aromatics, napthenes and olefins, multiple raw separation units can also be utilized in the scheme to generate more than two cuts which are selectively processed in cracking heaters at different optimum point to maximize the olefin yield or can be processed in hydroprocessing unit or rejected to fuel oil pool.

The lighter portion of the crude may then be processed in the steam cracker furnace while the heavier is sent to the Hydrocracker for processing. The effluent from the hydrocracker which may be lighters (C1-C4 cut), naphtha, and gas oils are processed as a feed to the steam cracker. Hydrocracker severity can be adjusted to maximize the C1 to C4 and Naphtha yields. This improves the overall hydrogen content in the resulting hydrocracked feed to steam cracker thus maximizing the light olefin yield. This also improves the quality of hydrocracker unconverted oil making it a suitable cracker feedstock. This not only provides additional ethylene and propylene boost but also minimizes the fuel oil make from the unit thus improving the overall economics. Utilizing hydroprocessing platform also provides additional benefit of processing many low-quality refinery streams in the unit including light pyrolysis oil and C9-204° C. cut recycle from steam cracker.

PGH may include a reactor system containing two stage hydrogenation reactors where all diolefins and olefins are saturated and sulfur compounds like mercaptans and thiophenes are converted into hydrogen sulfide and leaves the unit. The final product of the PGH unit may include C5 range hydrocarbons which can be steam cracked, C6-C8 cut and a C9+ cut which can be routed back to the hydrocracking reactors. The C6-C8 cut from the PGH unit may be processed to cycloalkanes in the aromatics saturation unit.

Alternatively, the C6-C8 cut may be processed in an aromatics dealkylation unit to generate benzene and light paraffins. Benzene may be either withdrawn as a product or converted to cycloalkanes in an aromatics saturation unit. The light paraffins may be fed to the steam cracker.

Alternatively, the C6-C8 cut may be processed in a BTX Extraction unit to recover BTX which may be withdrawn as a product or may be recycled to the hydrocracker or processed to cycloalkanes in the aromatics saturation unit while C6-C8 non-aromatics from the unit may be fed to the steam cracker.

In some embodiments, the aromatics saturation unit uses reactive distillation to convert C6-C8 aromatics into cycloalkanes.

Cycloalkanes along with balance C6-C8 non-aromatics from the aromatics saturation unit may be fed to the steam cracker to improve the light olefins yields or may be processed first in the hydrocracker to produce light paraffins which may be subsequently processed in the steam cracker to further improve the light olefins yields.

Cycloalkanes recovered from the aromatic saturation unit can be processed at high cracking severity in steam cracking heater coils to generate high combined yield of ethylene and propylene but also generates significant quantities of pyrolysis oil. A lighter portion of this pyrolysis oil can be recovered as a separate stream from steam cracker and fed to the hydrocracker for cracking under high H2 partial pressure. Alternatively, cycloalkanes can also be cracked under severe conditions in hydrocracking reactor utilizing appropriate set of hydroprocessing catalyst resulting in opening of few saturated rings. Effluent from hydrocracker can then be cracked in the steam cracker.

C4 olefins/di-olefins rich stream from the steam cracker may also be used to produce additional propylene using Selective Hydrogenation, Catalytic Distillation and Metathesis. This option adds a flexibility to adjust the Propylene/Ethylene (P/E) ratio as per market demand. Alternatively, C4 olefins and diolefins may also be processed in C4 block to meet the specific C4 demand such Butadiene, Butene-1 etc. In yet other embodiments, combination of any above for C4-C5 processing may be used to meet the objectives of desired chemicals.

Overall, embodiments herein may send a light pyrolysis oil to the hydrocracker for cracking and a heavy pyrolysis oil is sent for fuel oil blending.

Embodiments herein provide processing schemes for maximizes the conversion of crude oil into light olefins, and are flexible enough to also recover other chemicals as required. Embodiments herein provide enhanced flexibility in terms of feed and product processing. By doing so, it effectively minimizes capital expenditures, maintenance costs, and plot area requirements. Embodiments herein offer distinctive solutions to maximize the desired products or combination of products as needed, such as maximizing the ethylene and propylene or ethylene, propylene and aromatics/benzene or ethylene, propylene, aromatics/benzene and various C4 products from direct crude oil processing.

Crude to Chemicals (Propylene & Ethylene) conversion is typically 45-55 wt % using integration of steam cracker and hydrocracker. However, by using Lummus' Pyrotol® and Benzene CD Hydro Technology®, crude conversion to chemicals may be increased to 65-90 wt %. Also, hydroprocessing catalyst and operating conditions are adjusted to maximize the quality of products to make them better suited for generating higher quantities of light olefins when cracked in the steam cracker.

Conventional crude distillation and vacuum distillation units or solvent deasphalting units are costly and energy intensive and also not required in this process due to no particular need of generating on-spec fuels. Further, Lummus' HOPS is economical and energy efficient and suitable enough to split the crude into raw cuts for processing in separate units.

Another remarkable aspect of embodiments herein is flexibility in accommodating various feedstocks and adjusting product ratios. If there are changes in the quality of the feedstock, the processing scheme may easily adapt to handle it. Similarly, if there is a need to modify the Propylene/Ethylene ratio, it may be readily adjusted within the system. The scheme is also flexible with respect to the needs to generate either a benzene product or a mix of Benzene-Toluene-Xylene product or no aromatics at all giving refiner a flexibility to adjust the operations easily depending on the market needs.

Embodiments herein further provide for one or more of the following:

• • (1) Embodiments herein may maximize the production of light olefins by utilizing aromatic rich effluent from steam cracker. Saturating these aromatics followed by steam cracking or hydrocracking generates additional light olefins at the expense of Aromatics.
  • (2) Embodiments herein are flexible for feed variation and change in product demand (Propylene/Ethylene) & other chemicals. Benzene, Toluene, Xylene can be recovered as produced or consumed inside the unit to generate additional light olefins. Also, Toluene and Xylenes can be converted to Benzene for sales, when needed.
  • (3) Embodiments herein generate good quality feedstock for steam cracker by hydroprocessing heavier end of the crude.
  • (4) Embodiments herein provide an option to process low-value refinery streams as well as low value steam cracker recycles like light pyoil and C9-204C cut
  • (5) The Total Investment Cost (TIC)is significantly reduced in embodiments herein due to the optimization of the process units. Especially, the scheme uses raw cut crude separation to produce feeds for steam cracker and hydroprocessing unit thus saving significant cost involved in conventional route which utilizes atmospheric and vacuum crude distillation columns.
  • (6) Optimization of the process units not only contributes to lower investment costs but also leads to a smaller plot size area requirement.
  • (7) Embodiments herein ensure to maximize the profit margin per ton of feed charge, enhancing the financial returns for operators.

As provided by embodiments herein, processing schemes described above may give a solution to producers who are looking for maximizing petrochemicals such as ethylene and propylene directly from crude especially when there is significant volatility in the aromatics market.

Unless defined otherwise, all technical and scientific terms used have the same meaning as commonly understood by one of ordinary skill in the art to which these systems, apparatuses, methods, processes and compositions belong.

The singular forms “a,” “an,” and “the” include plural referents, unless the context clearly dictates otherwise.

As used here and in the appended claims, the words “comprise,” “has,” and “include” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps.

“Optionally” means that the subsequently described event or circumstances may or may not occur. The description includes instances where the event or circumstance occurs and instances where it does not occur.

When the word “approximately” or “about” are used, this term may mean that there can be a variance in value of up to ±10%, of up to 5%, of up to 2%, of up to 1%, of up to 0.5%, of up to 0.1%, or up to 0.01%.

Ranges may be expressed as from about one particular value to about another particular value, inclusive. When such a range is expressed, it is to be understood that another embodiment is from the one particular value to the other particular value, along with all particular values and combinations thereof within the range.

While the disclosure includes a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments may be devised which do not depart from the scope of the present disclosure. Accordingly, the scope should be limited only by the attached claims.

Claims

1. A process for converting whole crudes and other wide boiling hydrocarbon mixtures into light olefins, the process comprising:

separating a wide boiling hydrocarbon mixture to recover a vaporized low boiling portion and a remaining liquid portion, wherein the low boiling portion has an end boiling point in the range from about 150° C. to 550° C. and the liquid portion has an end boiling point greater than the end boiling point of the light portion;

thermally cracking the low boiling portion to recover a first cracked effluent;

separating the first cracked effluent to recover one or more light olefin fractions, a fuel oil fraction, a pyrolysis gasoline fraction, and a pyrolysis oil fraction;

hydrogenating the pyrolysis gasoline fraction to form a hydrogenated pyrolysis gasoline;

separating the hydrogenated pyrolysis gasoline to recover a C5− fraction, a C6 to C8 fraction, and a C9+ fraction;

hydrocracking the C9+ fraction, and the pyrolysis oil fraction to recover one or more hydrocracked effluents;

separating the one or more hydrocracked effluents to recover a light boiling fraction, a medium boiling fraction, and a high boiling fraction;

thermally cracking the C5− fraction, the light boiling fraction, the medium boiling fraction, and the high boiling fraction, and collectively separating the cracked effluents with the first cracked effluent to recover the one or more light olefin fractions, the fuel oil fraction, the pyrolysis gasoline fraction, and the pyrolysis oil fraction.

2. The process of claim 1, wherein separating the wide boiling hydrocarbon mixture comprises separating the wide boiling mixtures to recover three or more fractions including the low boiling portion, one or more medium boiling portions, and the remaining liquid portion.

3. The process of claim 2, further comprising thermally cracking the one or more medium boiling portions.

4. The process of claim 1, further comprising saturating aromatics in the C6 to C8 fraction to recover a saturated hydrocarbon mixture comprising cycloalkanes and C6 to C8 paraffins.

5. The process of claim 4, further comprising thermally cracking the saturated hydrocarbon mixture.

6. The process of claim 4, further comprising separating the saturated hydrocarbon mixture to recover a cycloalkane fraction and a paraffin fraction.

7. The process of claim 6, further comprising (i) thermally cracking the paraffin fraction and the cycloalkane fraction or (ii) thermally cracking the paraffin fraction and hydrocracking the cycloalkane fraction.

8. The process of claim 1, further comprising feeding the C6 to C8 fraction to an aromatics extraction unit and therein extracting aromatics from the C6 to C8 fraction to produce an aromatics containing fraction and a C6 to C8 non-aromatics fraction.

9. The process of claim 8, further comprising thermally cracking the C6 to C8 non-aromatics fraction.

10. The process of claim 9, further comprising saturating aromatics in the aromatics containing fraction to recover a saturated hydrocarbon mixture.

11. The process of claim 10, further comprising thermally cracking the saturated hydrocarbon mixture.

12. The process of claim 10, further comprising separating the saturated hydrocarbon mixture to recover a cycloalkane fraction and a paraffin fraction.

13. The process of claim 12, further comprising (i) thermally cracking the paraffin fraction and the cycloalkane fraction or (ii) thermally cracking the paraffin fraction and hydrocracking the cycloalkane fraction.

14. The process of claim 1, further comprising feeding the C6 to C8 fraction to an aromatics dealkylation unit and therein dealkylating the C6 to C8 fraction to recover a benzene containing fraction and a paraffin containing fraction.

15. The process of claim 14, further comprising thermally cracking the paraffin containing fraction.

16. The process of claim 14, further comprising saturating aromatics in the benzene containing fraction to recover a saturated hydrocarbon mixture.

17. The process of claim 16, further comprising thermally cracking the saturated hydrocarbon mixture.

18. The process of claim 16, further comprising separating the saturated hydrocarbon mixture to recover a cycloalkane fraction and a paraffin fraction.

19. The process of claim 18, further comprising i) thermally cracking the paraffin fraction and the cycloalkane fraction or (ii) thermally cracking the paraffin fraction and hydrocracking the cycloalkane fraction.

20. A process for producing olefins, comprising:

separating a whole crude oil to recover a light cut and a heavy cut;

hydrogenating a pyrolysis gasoline to produce a hydrogenated effluent and separating the hydrogenated effluent to recover a C5− fraction, a C6 to C8 fraction, and a C9+ fraction;

processing the C6 to C8 fraction in one or more of an aromatics dealkylation unit, an aromatics extraction unit, and an aromatics saturation unit to recover a non-aromatic hydrocarbon stream;

hydrocracking a pyrolysis oil, the heavy cut, and the C9+ fraction to recover a hydrocracked effluent;

steam cracking the hydrocracked effluent, the non-aromatic hydrocarbon stream, the C5− fraction, and the light cut to recover one or more steam cracked effluents; and

collectively separating the one or more steam cracked effluents to recover one or more olefin fractions, the pyrolysis gasoline, and the pyrolysis oil.

21. A system for producing olefins, the system comprising:

a crude separation unit for separating a whole crude oil to recover a light cut and a heavy cut;

a pyrolysis gasoline hydrogenation unit for hydrogenating a pyrolysis gasoline to produce a hydrogenated effluent and separating the hydrogenated effluent to recover a C5− fraction, a C6 to C8 fraction, and a C9+ fraction;

an aromatics processing unit for processing the C6 to C8 fraction in one or more of an aromatics dealkylation unit, an aromatics extraction unit, and an aromatics saturation unit to recover a non-aromatic hydrocarbon stream;

a hydrocracker unit for hydrocracking a pyrolysis oil, the heavy cut, and the C9+ fraction to recover a hydrocracked effluent;

a steam cracker for steam cracking the hydrocracked effluent, the non-aromatic hydrocarbon stream, the C5− fraction, and the light cut to recover one or more steam cracked effluents; and

a separation system for collectively separating the one or more steam cracked effluents to recover one or more olefin fractions, the pyrolysis gasoline, and the pyrolysis oil;

a flow line for providing the pyrolysis gasoline from the separation system to the pyrolysis gasoline hydrogenation unit; and

a flow line for providing the pyrolysis oil from the separation system to the hydrocracker unit.

22. The system of claim 21, wherein the separation unit is configured to produce a C4 containing fraction, the system further comprising an olefin conversion unit configured to convert the C4 containing fraction to produce one or more products selected from propylene and ethylene.