PROCESS FOR MAXIMIZING THE CONVERSION OF CRUDE OILS AND/OR CONDENSATES INTO VALUABLE CHEMICAL PRODUCTS WITH FLEXIBILITY TO PRODUCE ULTRA-LOW SULFUR DIESEL (ULSD)

Description

FIELD OF THE DISCLOSURE

Embodiments of the present disclosure generally relate to systems and processes allowing an operator to maximize production of chemicals while additionally providing the flexibility for the operator to produce diesel fuel or jet fuel when demand warrants.

BACKGROUND

Crude oil handling typically requires conventional refinery units such as crude distillation to segregate the various boiling range fractions for further downstream processing. Refinery and petrochemical complexes are segregated and operate independently of each other. The conventional and independent refinery configuration is capital and energy intensive.

HPNAs lead to rapid coke formation in a steam cracker furnace, which necessitates frequent decoke cycles, decreasing the overall on-stream factor of a refinery complex. Conversion of vacuum residue without significant formation of heavy polynuclear aromatics (HPNAs) that are detrimental to steam cracker furnaces downstream of the process is challenging. Further, the vacuum residue portion of the crude oil is very deficient in hydrogen, which decreases the yield of valuable chemicals in the steam cracking furnaces.

Various processes have been proposed recently to improve the economics of crude oil processing and maximize the production of chemicals. However, such processes may eliminate the ability to produce various desirable end products.

SUMMARY OF THE CLAIMED EMBODIMENTS

In one aspect, embodiments disclosed herein relate to a method for converting crude oil to chemicals and fuels by separating a crude oil into a light oil fraction, a medium oil fraction, and a heavy oil fraction. The medium oil fraction is distillate hydrotreated under low pressure conditions to produce a hydrotreated medium oil fraction. The method is operated in a max chemicals mode of operation for a first period of time and a chemicals plus fuels mode of operation for a second period of time. The max chemicals mode of operation includes feeding the light oil fraction to a steam cracker to crack hydrocarbons in the light oil to form a cracked light oil. In this mode of operation, an entirety of the hydrotreated medium oil fraction is fed to the steam cracker to crack hydrocarbons in the hydrotreated medium oil fraction to form a cracked medium oil. Within the max chemical mode of operation the cracked light oil is collectively separated from the cracked medium oil to recover two or more hydrocarbon fractions including a pyrolysis oil fraction. The chemicals plus fuels mode of operation includes separating the hydrotreated medium oil fraction to recover a light hydrotreated fraction, a diesel fuel fraction, a jet fuel fraction, and/or a heavy hydrotreated fraction. The light hydrotreated fraction is mixed with the light oil fraction to form a combined light oil fraction. The combined light oil fraction is fed to the steam cracker to crack hydrocarbons in the combined light oil fraction to form a cracked combined light oil. The heavy hydrotreated fraction is fed to the steam cracker to crack hydrocarbons in the heavy hydrotreated fraction to form a cracked medium oil. The cracked combined light oil is collectively separated from the cracked medium oil to recover two or more hydrocarbon fractions and a pyrolysis oil fraction.

In another aspect, embodiments disclosed herein relate to a system for converting crude oil to chemicals and fuels including a separation unit configured to separate a crude oil into a light oil fraction, a middle oil fraction, and a heavy oil fraction. A low pressure distillate hydrotreating unit hydrotreats the middle oil fraction at mild conditions to produce a hydrotreated middle oil fraction. The hydrotreated middle oil fractions is separated in a separation unit into a light hydrotreated fraction, a diesel fuel fraction, a jet fuel fraction, and a heavy hydrotreated fraction. The light fraction, the light hydrotreated fraction, and the heavy hydrotreated fraction are cracked in a steam cracker unit to produce cracked hydrocarbons. The cracked hydrocarbons are separated in a separation system into two or more hydrocarbon fractions and a pyrolysis oil fraction. The system includes a flow system to divert any portion or an entirety of the hydrotreated middle oil fraction to the steam cracker or provide an entirety or portion of the middle oil fraction to the separation system. The system includes a control system that increases or decreases the amount of the diesel fuel fraction or jet fuel fraction to control an amount of hydrotreated middle oil fraction fed to the steam cracker, control an amount of hydrotreated middle oil fraction fed to the separation system, control a cut point of the light oil fraction, control a cut point of the heavy oil fraction, and control a severity of reaction conditions in the distillate hydrotreating.

In another aspect, embodiments disclosed herein relate to a process for converting crude oil to chemicals and fuels by separating a crude oil into a light oil fraction, a medium oil fraction, and a heavy oil fraction. The medium oil fraction is distillate hydrotreated under low pressure conditions to produce a hydrotreated medium oil fraction. A pyrolysis oil is conditioned and hydroprocessed in a heavies conditioning unit to form hydroprocessed fractions and a very low sulfur fuel oil fraction. The hydroprocessed fractions and the hydrotreated middle oil fraction are collectively separated to recover three or more hydrocarbon fractions including a first hydrocarbon fraction, a diesel fuel fraction, a jet fuel fraction, and an unconverted oil fraction. The process includes recovering the unconverted oil fraction as at least a portion of the very low sulfur fuel oil. The light oil fraction, the hydrocarbon fraction, and a portion or an entirety of the diesel fuel fraction or jet fuel fraction is fed to a steam cracker to crack hydrocarbons in the respective fractions. The process is operated in a max chemicals mode of operation for a first period of time and a chemicals plus fuels mode of operation for a second period of time. The max chemicals mode of operation includes feeding the diesel fuel fraction or jet fuel fraction to the steam cracker to crack hydrocarbons and form a cracked fuel effluent. Within the max chemicals mode of operation the cracked hydrocarbons are collectively separated from the respective fractions to recover two or more hydrocarbon fractions including a pyrolysis oil fraction. The chemicals plus fuels mode of operation includes recovering a portion of the diesel fuel fraction or jet fuel fraction as a fuel product and collectively separating the cracked hydrocarbons to recover two or more hydrocarbon fractions, including the pyrolysis oil fraction.

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

BRIEF DESCRIPTION OF DRAWINGS

FIGS. 1-4 illustrate simplified process flow diagrams of systems for converting crude oils to chemicals and fuels according to one or more embodiments disclosed herein. FIG. 1 provides an embodiment for processing a very light crude oil or condensate liquids, whereas FIGS. 2 3, and 4 provide embodiments that additionally include process steps to enhance recovery from heavier crude oils.

To the extent possible, like numerals are used to represent like elements within the figures.

DETAILED DESCRIPTION

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, isobutylene, benzene, toluene, and para-xylenes.

Hydrotreating is a catalytic process, usually carried out in the presence of free hydrogen, in which the primary purpose when used to process hydrocarbon feedstocks is the removal of various metal contaminants (e.g., arsenic), heteroatoms (e.g., sulfur, nitrogen and oxygen), and aromatics from the feedstock. Generally, in hydrotreating operations cracking of the hydrocarbon molecules (i.e., breaking the larger hydrocarbon molecules into smaller hydrocarbon molecules) is minimized. As used herein, the term “hydrotreating” refers to a refining process whereby a feed stream is reacted with hydrogen gas in the presence of a catalyst to remove impurities such as sulfur, nitrogen, oxygen, and/or metals (e.g., nickel or vanadium) from the feed stream (e.g., the atmospheric tower bottoms) through reductive processes. Hydrotreating processes may vary substantially depending on the type of feed to a hydrotreater. For example, light feeds (e.g., naphtha) contain very little and few types of impurities, whereas heavy feeds (e.g., atmospheric tower bottoms (ATBs)) typically possess many different heavy compounds present in a crude oil. Apart from having heavy compounds, impurities in heavy feeds are more complex and difficult to treat than those present in light feeds. Therefore, hydrotreating of light feeds is generally performed at lower reaction severity, whereas heavy feeds require higher reaction pressures and temperatures.

Hydrocracking refers to a process in which hydrogenation and dehydrogenation accompanies the cracking/fragmentation of hydrocarbons, e.g., converting heavier hydrocarbons into lighter hydrocarbons, or converting aromatics and/or cycloparaffins (naphthenes) into non-cyclic branched paraffins.

“Conditioning,” “hydroprocessing” and like terms as used herein refers to conversion of hydrocarbons by one or both of hydrocracking and hydrotreating. “Destructive hydrogenation” and like terms refers to cracking of the hydrocarbon molecular bonds of a hydrocarbon, and the associated hydrogen saturation of the remaining hydrocarbon fragments, which can create stable lower boiling point hydrocarbon oil products, and may be inclusive of both hydrocracking and hydrotreating.

Embodiments herein relate to processes and systems for the conversion of crude oils and/or condensates into valuable chemical products with the flexibility to produce ultra-low sulfur diesel (ULSD). The crude oil and/or condensate feeds are separated and processed such that both a high quality ULSD product and a high quality steam cracker feed are produced. The resulting products are then sent to a steam cracker to maximize the percentage of valuable products produced from a barrel of crude oil while maintaining a reasonable decoking frequency of the steam cracking heaters. Thus, embodiments herein provide for upgrading crude into chemicals, ULSD, and/or VLSFO (Very Low Sulfur Fuel Oil), with the flexibility to operate the system to maximize chemicals production, maximize diesel fuel production, or to provide both products at a desired intermediate production capacity.

Embodiments herein relate to processes and systems that take crude oil and/or low value heavy hydrocarbons as feed and 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 a pre-conditioned crude oil or condensate. Processes herein may condition the residuum fraction of whole crude oils and natural condensates to produce feedstocks useful as a steam cracker feedstock.

Hydrocarbon mixtures useful in embodiments disclosed herein may include various hydrocarbon mixtures having a boiling point range, where the end boiling point of the mixture may be greater than 500° C., such as greater than 525° C., 550° C., or 575° C. The amount of high boiling hydrocarbons, such as hydrocarbons boiling over 550° C., may be as little as 0.1 wt %, 1 wt % or 2 wt %, but can be as high as 10 wt %, 25 wt %, 50 wt % or greater. The description is explained with respect to crude oil, such as whole crude oil, but any high boiling end point hydrocarbon mixture can be used. However, processes disclosed herein can be applied to crudes, condensates and hydrocarbons with a wide boiling curve and end points higher than 500° C. Such hydrocarbon mixtures may include 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, 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 to the vacuum gas oil range or heavier.

When the end boiling point of the hydrocarbon mixture is high, such as over 550° C., the hydrocarbon mixture cannot be processed directly in a steam pyrolysis reactor to produce olefins. The presence of these heavy hydrocarbons results in the formation of coke in the reactor, where the coking may occur in one or more of the convection zone preheating coils or superheating coils, in the radiant coils, or in transfer line exchangers, and such coking may occur rapidly, such as in few hours. Whole crude is not typically cracked commercially, as it is not economical. It is generally fractionated, and only specific cuts are used in a steam pyrolysis heater to produce olefins. The remainder is used in other processes. The cracking reaction proceeds via a free radical mechanism. Hence, high ethylene yield can be achieved when it is cracked at high temperatures. Lighter feeds, like butanes and pentanes, require a high reactor temperature to obtain high olefin yields. Heavy feeds, like gas oil and vacuum gas oil (VGO), require lower temperatures. Crude contains a distribution of compounds from butanes to VGO and residue (material boiling over 550° C.). Subjecting the whole crude without separation at high temperatures produces a high yield of coke (byproduct of cracking hydrocarbons at high severity) and plugs the pyrolysis reactor. The steam pyrolysis reactor has to be periodically shut down and the coke is cleaned by steam/air decoking. The time between two cleaning periods when the olefins are produced is called run length. When whole crude is cracked without separation, coke can deposit in the convection section coils (vaporizing the fluid), in the radiant section (where the olefin producing reactions occur) and/or in the transfer line exchanger (where the reactions are stopped quickly by cooling to preserve the olefin yields).

Processes and systems according to embodiments herein may include a feed preparations section, such as a desalter, for example. Following feed preparation, the desalted crude or condensate is then processed such that crackable feed is sent to a steam cracker and/or an aromatics complex. Processing of the feed to make it suitable for feed to a steam cracker may include various process operations, such as separation, conditioning (hydrotreating, hydrocracking, etc.), and other steps as described herein to facilitate the steam cracking of the hydrocarbons and production of the desired chemicals.

Systems for processing of crudes and other hydrocarbon feeds according to embodiments herein also provide flexibility for the recovery of selected distillate range fuel fractions, such as a diesel fuel or a jet fuel fraction. Such distillate range fuel fractions may contain very little sulfur, and thus may be classified as low or ultra-low sulfur fuels. As such, embodiments of systems herein may be operated in a maximum chemicals production mode, where the feed is used to make chemicals, or in a chemicals plus fuel production mode, where conditions in the system are adapted to produce a greater amount of diesel or jet fuels in addition to converting a substantial portion of the feeds to chemicals. Further, systems and processes herein may readily transition from the max chemicals mode to the chemicals plus fuel mode so that the plant may adapt to market needs. Thus, systems herein may be operated in a max chemicals mode of operation for a first period of time and operated in a chemicals plus fuels mode of operation for a second period of time

In one aspect, embodiments herein include separation of a crude oil into a light oil fraction, a medium oil fraction, and a heavy oil fraction. The medium oil fraction is then hydrotreated to produce a hydrotreated medium oil fraction.

In the max chemicals mode of operation, the light oil fraction is fed to a steam cracker to crack hydrocarbons in the light oil. An entirety of the hydrotreated medium oil fraction is also fed to the steam cracker to crack hydrocarbons in the hydrotreated medium oil fraction. The cracked medium oil fraction and the cracked light oil fraction may then be separated to recover various chemicals fractions, such as ethylene, propylene, and other chemicals as noted above. The cracked effluents may also include some heavier (higher boiling) components, which may be recovered as a pyrolysis oil fraction.

In the chemicals plus fuel mode of operation, the hydrotreated medium oil fraction may be separated to recover a light hydrotreated fraction, a diesel fuel or jet fuel fraction, and a heavy hydrotreated fraction. The light hydrotreated fraction may include light naphtha range and lighter (lower boiling) hydrocarbons, and the heavy hydrotreated fraction may include hydrocarbons heavier (higher boiling) than the diesel fuel or jet fuel fraction recovered. The light hydrotreated fraction and the light oil fraction may be collectively or separately fed to the steam cracker to crack hydrocarbons therein. Similarly, the heavy hydrotreated fraction may be fed to the same or a different steam cracker to crack hydrocarbons therein. The resulting cracked effluents may then be separated to recover various chemicals fractions and a pyrolysis oil fraction.

The separation system for separating the hydrotreated medium oil fraction may be a single or multiple distillation columns, for example. The columns may be designed to have a very high turn down ratio, allowing for a minimal feed while keeping the equipment operational during the max chemicals production mode, and thus providing for ramping up of the feed to transition to a chemicals plus fuel mode of operation, and a ramping down of the feed to transition back to max chemicals. Alternatively, the separation system may be shut down during max chemicals production mode and started up when it is desired to produce both fuels and chemicals.

The separation of the crude into the light oil fraction, medium oil fraction, and heavy oil fraction may be based on selected cut points. Cut points, as used herein, refer to the initial or final boiling point of a mixture. While the cut points may refer to a particular temperature, one skilled in the art recognizes that distillation may not always result in a “clean” separation of higher and lower boiling components, and the amount of compounds boiling below the intended cut point temperature target may vary depending upon the fractionation mechanism. Thus, cut points herein may be considered as 5% or 15% boiling temperatures for lower limits and 85% or 95% boiling temperatures for upper limits, such as may be measured according to one or more of ASTM D86, ASTM D1160, ASTM D2892, ASTM D7169, or ASTM D2887, for example.

Separation of the whole crude into the desired fractions may be performed using one or more separators (distillation columns, flash drums, etc.). In some embodiments, separation of the petroleum feeds may be performed in an integrated separation device (ISD), such as disclosed in US20130197283, which is incorporated herein by reference. 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. An additional separation step may then be used to separate a middle boiling fraction from high boiling components.

Typically, hydrocarbon components boiling above 490° C. contain asphaltenes and Conradson Carbon Residue, and thus need to be processed appropriately, as described further below. While embodiments are described as including a fraction below a temperature in the range from 90° C.-250° C., such as a 160° C.− fraction and a fraction above about 400° C.-560° C., such as a 490° C.+ fraction, it is noted that the actual cut points may be varied based on the type of whole crude or other heavy fractions being processed, as well as the operating mode of the system. For example, for a crude containing a low metals or nitrogen content, or a large quantity of “easier-to-process” components boiling, for instance, at temperatures up to 525° C., 540° C., or 565° C., it may be possible to increase the mid/high cut point while still achieving the benefits of embodiments herein. Similarly, the low/mid cut point may be as high as 220° C. in some embodiments, or as high as 250° C. in other embodiments. Further, it has been found that a low/mid cut point of about 160° C. may provide a benefit for sizing and operation of the reactors, such as a fixed bed conditioning reactor, for conditioning the mid fraction hydrocarbons (middle cut). Further still, for some feeds, such as condensate, the low/mid cut point may be as high as 565° C. The ability to vary the cut points may add flexibility to process schemes according to embodiments herein, allowing for processing of a wide variety of feeds while still producing the product mixture desired.

Accordingly, in some embodiments, the light cut may include hydrocarbons having a boiling point up to about 90° C. (e.g., a 90° C.− fraction), up to about 100° C., up to about 110° C., up to about 120° C., up to about 130° C., up to about 140° C., up to about 150° C., up to about 160° C., up to about 170° C., up to about 180° C., up to about 190° C., up to about 200° C., up to about 210° C., up to about 220° C., up to about 230° C., up to about 240° C., up to about 250° C. (e.g., a 250° C.− fraction), up to about 300° C., up to about 350° C., up to about 400° C., up to about 500° C., or up to about 565° C. Embodiments herein also contemplate the light cut being hydrocarbons having boiling points up to temperatures intermediate the aforementioned ranges. The lower limit of boiling point for the light cut may depend upon upstream processing (degassing, stabilization, etc.), and thus may include C3+, C4+, or C5+ boiling range material on the light end (initial boiling point range).

Depending upon the fractionation mechanism used, the light hydrocarbon “cut” may be relatively clean, meaning the light fraction may not have any substantial amount (>1 wt % as used herein) of compounds boiling above the intended boiling temperature target. For example, a 160° C.− cut may not have any substantial amount of hydrocarbon compounds boiling above 160° C. (i.e., >1 wt %). In other embodiments, the intended target “cut” temperatures noted above may be a 95% boiling point temperature, or in other embodiments as an 85% boiling point temperature, such as may be measured using ASTM D86 or ASTM D2887, or a True Boiling Point (TBP) analysis according to ASTM D2892, for example, and ASTM D7169 for heavy streams, such as those boiling above about 400° C. In such embodiments, there may be up to 5 wt % or up to 15 wt % of compounds above the indicated “cut” point temperature. For many whole crudes, the low/mid cut point may be such that the light boiling fraction has a 95% boiling point temperature in the range from about 90° C. to about 250° C. For other feeds, however, such as condensate, the light boiling fraction may have a 95% boiling point temperature in the range from about 500° C. to about 565° C., for example.

In some embodiments, the middle cut may include hydrocarbons having a boiling point from a lower limit of the light cut upper temperature (e.g., 90° C., 100° C., 110° C., 120° C., 130° C., 140° C., 150° C., 160° C., 170° C., 180° C., 190° C., 200° C., 210° C., 220° C., 230° C., 240° C., 250° C., 300° C., 350° C., or 400° C., for example) to an upper limit of hydrocarbons having a boiling point up to about 350° C., up to about 375° C., up to about 400° C., up to about 410° C., up to about 420° C., up to about 430° C., up to about 440° C., up to about 450° C., up to about 460° C., up to about 480° C., up to about 490° C., up to about 500° C., up to about 520° C., up to about 540° C., up to about 560° C., or up to about 580° C. As used herein, for example, a middle cut having a lower limit of 160° C. and an upper limit of 490° C. may be referred to as a 160° C. to 490° C. cut or fraction. Embodiments herein also contemplate the middle cut being hydrocarbons having boiling points from and/or up to temperatures intermediate the aforementioned ranges.

Depending upon the fractionation mechanism, the hydrocarbon “cut” for the middle cut may be relatively clean, meaning the middle cut may not have any substantial amount (>1 wt %) of compounds boiling below and/or may not have any substantial amount (>1 wt %) of compounds boiling above the intended boiling temperature target limits. For example, a 160° C. to 490° C. cut may not have any substantial amount of hydrocarbon compounds boiling below 160° C. or above 490° C. In other embodiments, the intended target “cut” temperatures noted above may be a 5 wt % or 15 wt % boiling point temperature on the lower limit and/or a 95% or 85% boiling point temperature on the upper limit, such as may be measured using ASTM D86 or ASTM D2887, or a True Boiling Point (TBP) analysis according to ASTM D2892, for example, and ASTM D7169 for heavy streams, such as those boiling above about 400° C. In such embodiments, there may be up to 5 wt % or up to 15 wt % of compounds above and/or below the “cut” point temperature, respectively.

In some embodiments, the heavy cut may include hydrocarbons having a boiling point above about 300° C., above about 375° C., above about 400° C. (e.g., a 400° C.+ fraction), above about 420° C., above about 440° C., above about 460° C., above about 480° C., above about 490° C., above about 500° C., above about 510° C., above about 520° C., above about 530° C., above about 540° C., above about 560° C., above about 580° C., above about 590° C., above about 600° C. (e.g., a 600° C.+ fraction), or above about 700° C. Embodiments herein also contemplate the heavy cut being hydrocarbons having boiling points above temperatures intermediate the aforementioned temperatures. The maximum boiling point of hydrocarbons contained within the heavy cut will, as would be readily recognized by one skilled in the art, depend upon the particular crude or condensate being processed, and thus the heavy cut is defined herein by only a lower bound.

Depending upon the fractionation mechanism, the heavy hydrocarbon “cut” may be relatively clean, meaning the heavy fraction may not have any substantial amount (>1 wt %) of compounds boiling below the intended boiling temperature target. For example, a 490° C.+ cut may not have any substantial amount of hydrocarbon compounds boiling below 490° C. In other embodiments, the intended target “cut” temperatures noted above may be a 95% boiling point temperature, or in other embodiments as an 85% boiling point temperature, such as may be measured using ASTM D86 or ASTM D2887, or a True Boiling Point (TBP) analysis according to ASTM D2892, for example, and ASTM D7169 for heavy streams, such as those boiling above about 400° C. In such embodiments, there may be up to 5 wt % or up to 15 wt % of compounds, respectively, below the “cut” point temperature.

While descriptions below are given with respect to limited temperature ranges, it is envisioned that any of the temperature ranges prescribed above can be used in the processes described herein. Further, with respect to cut points, those referred to may be clean, as described above, or may refer to 5% or 15% boiling temperatures for lower limits, or may refer to 85% or 95% boiling temperatures for upper limits.

As outlined above, the initial separation of the crude oil may be conducted in two separation stages according to some embodiments herein. In a first separation stage, a light cut may be separated from the crude oil, and in the second stage, the remaining hydrocarbons may be separated into a middle cut and a heavy cut.

The light cut, as described above, may be fed to a steam cracker section of the system with or without further processing. The light cut fed to the steam cracker section may include light naphtha and lighter hydrocarbons, for example, and in some embodiments may include heavy naphtha boiling range hydrocarbons.

During a max chemicals production mode, it may be beneficial to maintain a relatively high cut point for the light oil fraction, such as 200° C., 230° C., or 250° C., for example, such that the steam cracker receives a larger quantity of “easier-to-process” components as straight run material fed to the steam cracker. This may also free up capacity within the middle oil cut hydrotreater by diverting the “easier-to-process” hydrocarbons straight to the steam cracker, as well as allow an operator to tailor the severity in the middle cut hydrotreater toward processing and converting the higher boiling materials (adjusting conditions in view of the lack of the lighter “middle” boiling range materials). The cut point used may also depend upon the amount of sulfur, nitrogen, or other impurities contained in the various boiling ranges that may be selected, preferentially sending the bulk of the sulfur and nitrogen containing compounds for hydrotreatment, as it is desired to limit the among of these compounds being fed to the steam cracker.

Conversely, during a chemicals plus fuels mode of operation, a higher diesel fuel or jet fuel recovery may be had where a cut point for the light oil fraction is lower, such as 150° C., 160° C., 175° C., or 190° C. Diesel fuels have a boiling range of about 150° C. to about 380° C., and jet fuels have a boiling range of about 190° C. to about 275° C., and thus decreasing a cut point of the light oil fraction may increase an amount of diesel fuel and jet fuel range hydrocarbons fed through the system toward the separation system for separating the hydrotreated medium oil fraction and recovering the desired diesel fuel or jet fuel fraction.

Similarly, the cut point of the heavy oil fraction may be adjusted depending upon the mode of operation. The manner in which the heavy oil cut point is adjusted may depend upon the further processing that the heavy oil cut may undergo, if any.

In some embodiments, such as for a very light sweet crude or a condensate, the heavy oil cut may not undergo any further processing. Condensates and some very light, sweet crudes may contain, for example, less than 5 wt %, less than 4 wt %, less than 3 wt %, less than 2 wt %, or less than 1 wt % of “hard-to-process” heavy hydrocarbons, such as those boiling above 400° C., above 450° C., above 500° C., above 540° C., above 565° C. or above 580° C., and thus for systems only processing such feeds, it may be uneconomical to further process and condition the heavy oil fraction. For example, poor condensate gases may contain 1.5 vol % to 15 vol % middle oil cut and less than 1.5 vol % heavy oil cut, whereas other condensates (intermediate or rich condensates) may include a slightly greater amount of middle and heavy cut hydrocarbons. In such embodiments, the heavy cut may be combined with the pyrolysis oil to form a low sulfur fuel oil or an ultra-low sulfur fuel oil. For other feeds having a more substantial amount of heavier hydrocarbons, the heavy cut may be further processed to advantageously produce additional chemicals and/or fuels, as will be detailed further below. It is noted, however, that the wt % or vol % of the heavy oil cut is not the sole determining factor for economic viability, as the total amount of heavy oil within the feed should also be considered, larger systems processing a greater volume of total feed may find it economical to further process heavies at 2 vol % of the feed, whereas smaller systems processing a lesser volume of total feed may find it uneconomical.

Thus, for embodiments herein transitioning from a max chemicals operating mode to a chemicals plus fuels operating mode, and those transitioning back to a max chemicals operating mode, the transitioning may include adjusting a cut point of temperature of the light oil fraction, adjusting a cut point temperature of the heavy oil, varying a severity of the distillate hydrotreating (hydrotreating of the middle oil cut), as well as starting up/shutting down or increasing/decreasing a feed rate of the hydrotreated middle oil fraction to the separation system used for separating the hydrotreated medium oil fraction.

Transitioning from the max chemicals mode to the chemicals plus fuel mode may thus include decreasing a cut point temperature of the light oil fraction. For example, decreasing a cut point temperature of the light oil fraction from 230° C. to 150° C. would result in more of the hydrocarbons boiling in the lower end of the diesel fuel boiling range to be fed to the distillate hydrotreating system conditioning the middle oil cut and then feeding the middle cut to the separation system separating the hydrotreated middle oil cut, thus improving the production of diesel fuels during the chemicals plus fuels production.

Similarly, transitioning from the max chemicals mode to the chemicals plus fuel mode may include increasing a cut point temperature of the middle oil cut. This may introduce additional hydrocarbons that, through the destructive hydrogenation occurring in the distillate hydrotreating reactor(s), may provide additional diesel fuel range materials for recovery.

Transitioning from the max chemicals mode to the chemicals plus fuel mode may also include varying a severity of the distillate hydrotreating to increase the upgrading of hydrocarbons in the middle oil fraction to form diesel range hydrocarbons. One or more of reaction temperature, reaction pressure, hydrogen feed rate, and space velocity (residence time in the reactor) may be varied to aid in the production of additional diesel fuel range hydrocarbons.

While described above with respect to diesel fuel range hydrocarbons, similar adjustments may be made for improving jet fuel recovery. Although jet fuels and diesel fuels have overlapping distillation ranges, the cut points and conditions used for a process focused on recovery of either fuel may differ slightly.

In embodiments transitioning from chemicals plus fuels mode of operation to max chemicals operation mode, the converse of the above adjustments may be made. For example, decreasing a cut point temperature of the middle oil fraction, increasing a cut point temperature of the light oil fraction, or decreasing a severity of the distillate hydrotreating may be used to decrease the make of the fuels, but will still provide for the advantageous preparation of the crude oil and the respective light and middle oil cuts for processing within the steam cracker.

For crude oils containing a greater amount of heavier material, it may be economically favorable to further process the heavier hydrocarbons to form feedstocks suitable for processing in a steam cracker. As will be described further with respect to the Figures, some embodiments may condition the heavy oil cut and feed the conditioned heavy cut to the steam cracker. Other embodiments may process the heavy oil cut and may integrate the conditioned heavy cut with the separation system used for diesel fuel or jet fuel recovery. Various embodiments may additionally feed the pyrolysis oil recovered from steam cracker separations to the heavy cut hydroprocessing to improve an overall conversion of the system to chemicals. In such embodiments, a heavies conditioning unit may be provided for conditioning and hydroprocessing of the heavy oil fraction, or the heavy oil fraction plus the pyrolysis oil, to form one or more hydroprocessed fractions suitable for steam cracking or for diesel/jet fuel recovery and steam cracking. A very low sulfur fuel oil fraction, unsuitable for steam cracking, may also be recovered from the heavies conditioning unit.

In some embodiments, systems and processes for converting crude oil to chemicals and fuels, including upgrading of the heavy oil fraction, include a separation unit configured to separate a crude oil into a light oil fraction, a middle oil fraction, and a heavy oil fraction. Similar to embodiments above, the light/middle cut point may be a temperature in a range from about 90° C. to about 400° C., for example, which temperature may depend upon the mode of operation as well as the type of feed being processed. Similarly, the middle/heavy cut point may be a temperature in a range from about 300° C. to about 580° C., for example.

A low-pressure distillate hydrotreating unit is provided to hydrotreat the middle oil fraction, at mild conditions, to produce a hydrotreated middle oil fraction. A separation unit is then used to separate the hydrotreated middle oil fraction into a light hydrotreated fraction, a jet fuel fraction, a diesel fuel fraction, and/or a heavy hydrotreated fraction. A steam cracker unit is then used to crack the light oil fraction, the light hydrotreated fraction and the heavy hydrotreated fraction to produce cracked hydrocarbons, which may be separated in a separation system associated with the steam cracker unit, separating the cracked hydrocarbons into two or more product chemicals fractions and a pyrolysis oil fraction.

As with the embodiment described briefly above, depending upon the mode of operation (max chemicals or chemicals plus fuels), the hydrotreated middle oil fraction may be fed to the steam cracker unit, or the hydrotreated middle oil fraction may be fed to a separation system to recover a diesel fuel or jet fuel fraction while sending the remaining hydrocarbons in the hydrotreated middle oil fraction to the steam cracker. A flow system may be provided to divert a portion or an entirety of the hydrotreated middle oil fraction to the steam cracker, or to provide an entirety or portion of the middle oil fraction to the separation system, as required for the particular mode of operation.

A control system associated with the overall system may be used to increase or decrease an amount of the diesel fuel or jet fuel fraction, or to transition into and out of a particular mode of operation. The control system is configured, in some embodiments, to: control an amount of hydrotreated middle oil fraction fed to the steam cracker; control an amount of hydrotreated middle oil fraction fed to the separation system; control a cut point of the light oil fraction; control a cut point of the middle oil fraction; and/or to control a severity of reaction conditions in the distillate hydrotreating.

The heavy oil cut, in embodiments desiring to convert the heavy oil cut to chemicals, is fed to a heavies conditioning unit. In the heavies conditioning unit, the heavy oil cut, with or without the pyrolysis oil recovered from the steam cracker section, is conditioned (hydroprocessed, hydrotreated and/or hydrocracked) to recover one or more conditioned heavy fractions and a very low or ultra-low sulfur fuel oil fraction. The one or more conditioned heavy fractions, having been upgraded within the heavies conditioning unit, are suitable for feed to the steam cracker, and may be fed, collectively or separately via respective flow lines to the steam cracker.

In some embodiments, it may be desired to recover diesel fuel or jet fuel range hydrocarbons that may be produced during conditioning of the heavy oil fraction. In such embodiments, a flow line may be provided for feeding one or more of the heavy conditioned fractions to the separation unit used for separating the hydrotreated middle oil fraction. In this manner, diesel fuel and jet fuel range hydrocarbons may be recovered as a product when operating in a chemicals plus fuels mode. Additionally, redundant separation systems that may otherwise be desired to separate the conditioned heavy fraction into distinct steam cracker feeds for cracking at preferred conditions may be avoided.

For embodiments integrating middle oil fraction and heavy oil fraction separations, the overall system may thus include a separation unit for separating a crude oil into a light oil fraction, a medium oil fraction, and a heavy oil fraction. As with embodiments above, the medium oil fraction may be hydrotreated to produce a hydrotreated medium oil fraction. The pyrolysis oil and the heavy oil fraction may be fed to a heavies conditioning unit, for conditioning and hydroprocessing to form one or more hydroprocessed fractions and a very low sulfur fuel oil fraction. The one or more hydroprocessed fractions and the hydrotreated middle oil fraction may then be collectively separated to recover three or more hydrocarbon fractions, including a first hydrocarbon fraction, a diesel fuel or jet fuel fraction, and an unconverted oil fraction. The unconverted oil fraction may be blended, for example, with other residue streams in the system, to form a low sulfur fuel oil. The light oil fraction, the first hydrocarbon fraction, and none, a portion or an entirety of the diesel fuel or jet fuel fraction may be fed to a steam cracker to crack hydrocarbons in the respective fractions.

The integrated system may, similar to other embodiments herein, operate in a max chemicals mode of operation for a first period of time and operate in a chemicals plus fuels mode of operation for a second period of time. In the max chemicals mode of operation: an entirety of the diesel fuel or jet fuel fraction may be fed to the steam cracker to crack hydrocarbons in the diesel fuel or jet fuel fraction to form chemicals. In the chemicals plus fuel mode of operation: a portion or an entirety of the diesel fuel or jet fuel fraction may be recovered as a fuel product, the remaining fractions being fed to the steam cracker section.

For embodiments in which the conditioned heavy cut is fed directly to the steam cracker, transitioning between modes of operation may be as described above (varying of the cut points of the light and middle cut, as well as varying a severity of the middle cut distillate hydrotreating). For embodiments in which the conditioned heavy cut is integrated with the hydrotreated middle cut separation system, varying of the cut points, severity of the middle distillate hydrotreating, as well as varying a severity of the heavy cut conditioning may be used to impact the production of diesel fuel or jet fuel range materials.

In some embodiments, a heavy hydrocarbon feedstock (i.e., an external or additional feed) may be fed to the heavies conditioning unit for concurrent conditioning and hydroprocessing along with the heavy oil fraction. For example, various heavy hydrocarbon streams, many of which were detailed above, may be provided from a nearby refinery and processed along with the heavy oil fraction as described herein. For such additional feeds, those containing a significant amount of light material, such as hydrocarbons boiling below about 360° C., the additional feed may be co-processed in the initial separation zone. For those containing little to no light hydrocarbons, the feeds may be provided directly to the heavies conditioning unit for co-processing.

In some embodiments, a light hydrocarbon feedstock (i.e., an external/additional feed) may be fed to the steam cracker for concurrent chemicals production along with the light oil fraction. For example, an ethane, propane, or butane feed, or other various light hydrocarbon fractions from a nearby refinery may be provided for cracking according to embodiments herein to produce additional chemicals.

Use of the above noted external feeds may be desirable in embodiments of one or both operating modes. Transitioning between modes of operation according to embodiments herein may also include initiating a supply of an external feed, terminating a supply of an external feed, or varying a feed rate of an external feed. For example, a steam cracker coil may have a reduced feed rate due to the withdrawal of a fuel fraction from the system during the chemicals plus fuels mode of operation. In such instances, an external feed may be fed to and processed within an available coil or to provide additional feed to occupy available coil volume during the chemicals plus fuels mode, while the external feed may not be needed during the max chemicals mode of operation. As another example, it may be desirable to bring heavy supplemental external feeds on line, fed to the heavies conditioning unit, when transitioning to chemicals plus fuels mode, thus producing additional distillate fuel range products from the destructive hydrogenating within the heavies conditioning section and, in some embodiments, the integrated middle fraction conditioning section.

Other low value refinery streams may thus also be processed according to embodiments herein to produce ultimately higher value products. Such streams include some or all of the following types of hydrocarbons: (i) Light cycle oil (LCO), such as LCO that is produced from FCC unit, which can be processed with the 160-490° C. fraction; (ii) a Slurry Oil, such as a slurry oil that is produced from an FCC unit, which can be processed with the 490° C.+ hydrocarbons; (iii) pitch, such as a pitch that is produced from a solvent deasphalting unit, which can be processed in the first conditioning system with the 490° C.+ hydrocarbons; and/or (iv) a Pyrolysis fuel oil (Pyoil), such as a pyrolysis fuel oil that is produced from a stream cracker, which stream can be processed with the 490° C.+ hydrocarbons. Other various hydrocarbon streams of similar boiling ranges may also be co-processed to produce petrochemicals in systems disclosed herein, where such streams may include light naphthas, heavy naphthas, crude oils, atmospheric residues, vacuum residues, synthetic crude oils, and other hydrocarbon streams containing heavy hydrocarbons. The cut points may also be varied in any of the ISDs to account for varying feedstock quality (i.e., metals, asphaltenes, and CCRs). In embodiments where the desalted crude has low contaminants, the initial cut points may be higher (i.e., above 160° C.), thereby reducing the operational load on the catalysts in the one or more conditioning systems. Alternatively, in embodiments where the desalted crude is high in contaminants, the initial cut points may be lower (i.e., below 160° C.), thereby feeding more of the hydrocarbons through a plurality of conditions systems and a second ISD for hydrotreatment and/or removal of undesirable heavy components, and thereby increasing the amount of naphtha range hydrocarbons being fed to steam cracking.

The mid-range hydrocarbon cut may be conditioned using one or more fixed bed reactors, such as hydrotreating and/or hydrocracking reactors, each of which may destructively hydrogenate the hydrocarbons in the mid-cut. The conditioning reactors may include catalysts for metals removal, sulfur removal, nitrogen removal, and the conditioning in these reactors may overall add hydrogen to the hydrocarbon components, making them easier to process downstream to produce petrochemicals. The fixed bed catalyst systems in the mid-cut conditioning zone, for example, may contain different layers of demetalizing, destructive hydrogenation and mesoporous zeolite hydrocracking catalysts to optimize the conversion of the heavy materials to a balance between a highly paraffinic stream that is suitable for olefins production and a rich in aromatics stream that is suitable for aromatics production.

In some embodiments, it may be desirable to further separate the mid-cut into a low-mid cut and a high-mid cut. For example, a mid-cut having a boiling range from 160° C. to 490° C. may be divided into a low-mid cut having a boiling range from about 160° C. to about 325° C. and a high-mid cut having a boiling range from about 325° C. to about 490° C. The conditioning trains may thus be configured to more selectively convert the hydrocarbon components in the respective low and high mid cuts to the desired conditioned effluents, where each train may be configured based on preferred catalysts to destructively hydrogenate the hydrocarbons therein, reactor sizing for expected feed volumes and catalyst lifetime, as well as operating conditions to achieve the desired conversions to naphtha range containing steam cracker feedstocks and distillate fuels (jet fuel and/or diesel fuel, for example). Similarly, division of the mid cut into three or more sub-cuts is also contemplated.

Embodiments herein further contemplate use of low-pressure distillate hydrotreating for upgrading of the middle oil cut. Low pressure distillate hydrotreating is a process used in the refining of crude oil to remove impurities from low-pressure distillates such as diesel and kerosene. The process heats the distillate to a temperature between 30° and 400° C. in the presence of hydrogen gas and a catalyst. The result of low-pressure distillate hydrotreating is a cleaner and more stable distillate, which can be further processed into higher-value products such as chemicals, diesel, or jet fuel. In this manner, the middle fraction is upgraded utilizing a fixed-bed hydroprocessing reactor operating at mild severity to increase hydrogen content to produce steam cracker feedstock and ULSD product (which can be optionally routed to steam cracker for maximizing chemicals production).

In some embodiments, conditioning of the middle cut (or heavy cut for a two-cut embodiment), such as a 160° C. to 490° C. cut, may result in conversion of greater than 50 wt % of the hydrocarbons therein to naphtha range hydrocarbons. In other embodiments, conditioning of the middle cut may result in conversion of greater than 55 wt %, greater than 60 wt %, or greater than 65 wt %, or greater than 70 wt % of the hydrocarbons therein to naphtha range hydrocarbons.

The hydrocarbons in a heavy cut may also be conditioned using one or more fixed bed reactors, slurry reactors, or ebullated bed reactors. Conditioning of the heavy cut, such as 490° C.+ hydrocarbons, may be performed, for example, in a residue hydrocracker, and may enhance the conversion of low value streams to high value petrochemical products via steam cracking. Residue hydrocracking may be performed, for example, in a fixed bed residue hydrocracker, an ebullated bed reactor, as well as slurry reactors. It is recognized, however, that the lifetime of destructive hydrogenation and/or hydrocracking catalysts may be negatively impacted by heavier components, such as where the feed includes components boiling above 565° C., for example. Similar to the mid-cut, division of the heavy cut into one or more sub-cuts is also contemplated.

The heavies conditioning system is designed to achieve four (4) goals. First, the heavies conditioning section may be used to increase the concentration of paraffins and naphthenes in the crude. Second, the conditioning section may decrease the concentration of polynuclear aromatic hydrocarbons (PNAs) in the crude. Third, the conditioning section may reduce the final boiling point (FBP) of the crude to below 540° C. And, fourth, the conditioning section may minimize the vacuum residue fraction of the crude oil.

Thus, in one or more embodiments herein, the heavy oil fraction (residue) is processed in ebullated bed or slurry reactors of the heavies conditioning unit to remove contaminants (such as coronene, ovaline), avoid formation of coke precursors, increase hydrogen content, and convert asphaltenic compounds. The effluent of the residue treatment reactors is then treated in an integrated hydrocracking fixed bed reactor within the heavies conditioning unit to further increase hydrogen content and make a suitable steam cracker feedstock.

Embodiments herein, when conditioning the middle and/or heavy fractions, may target conversion of the heavier hydrocarbons to form hydrocarbons lighter than diesel, for example. The hydrotreating and hydrocracking catalysts and operating conditions may thus be selected to target the conversion of the hydrocarbons, or the hydrocarbons in the respective fractions, to primarily (>50 wt %) naphtha range hydrocarbons. In one or more embodiments, hydrotreating and hydrocracking catalysts and operating conditions may thus be selected to target the conversion of the hydrocarbons, or the hydrocarbons in the in the respective fractions, to primarily (>50 wt %) steam crackable products. The use of catalysts and operating conditions in the conditioning section to target lighter hydrocarbon products may enhance the operability of the steam cracker and the production of chemicals.

In some embodiments, conditioning of the heavy cut, such as a 490° C.+ cut, may result in conversion of at least 70 wt % of the compounds boiling in excess of 565° C. to lighter boiling compounds. Other embodiments may result in conversion of greater than 75 wt %, greater than 80 wt %, or greater than 85 wt % of the compounds boiling in excess of 565° C. to lighter boiling compounds.

As a result of such initial separations and conditioning, feeds to the steam cracker may be fed, in some embodiments, directly to the steam cracker without further processing. The light cut, having preferred properties, including one or more of boiling point, API, BMCI, hydrogen content, nitrogen content, sulfur content, viscosity, MCRT, or total metals content, may be fed directly to the steam cracker following separations in some embodiments. Effluents from the middle cut conditioning may also be fed directly to the steam cracker according to embodiments herein. Likewise, effluents from the heavy cut conditioning may be fed directly to the steam cracker in some embodiments.

The conditioning of the respective fractions as described herein may allow for the steam cracker, even while processing multiple feeds of varying boiling point ranges, to run for an extended period of time. In some embodiments, the steam cracker may be able to run for an uninterrupted run length of at least three years; at least four years in other embodiments; and at least five years in yet other embodiments.

Further, the initial hydrocarbon cut points, reactor sizes, catalysts, etc. may be adjusted or configured such that a run time of the steam cracker operations and conditioning processes may be aligned. For example, in the configuration of FIG. 1, a whole crude oil may be conditioned and the conditioned crude may then be steam cracked. The catalysts, reactor sizes, and conditions may be configured such that a run time of the conditioning unit is aligned with the run time of the steam cracker. Catalyst volumes, catalyst types, and reaction severity may all play a role in determining conditioning unit run times. Further, the extent of conditioning of the heavier hydrocarbons in the crude may impact coking in the thermal cracker. To maximize plant uptime, embodiments herein contemplate design and configuration of the overall system such that the conditioning system has a similar anticipated run time as the steam cracker for a given feedstock or a variety of anticipated feedstocks. Further, embodiments herein contemplate adjustment of reaction conditions (T, P, space velocity, etc.) in the conditioning section and/or the steam cracker based on a feedstock being processed, such that a run time of the conditioning section and the steam cracker are similar or aligned.

Alignment of run times may result in minimal downtime, such as where a catalyst turnover in a conditioning reactor is conducted concurrently with decoking of the steam cracker. Where the conditioning system includes multiple reactors or types of reactors, alignment of the run times may be based on the expected steam cracker performance. Further, where a hydrotreater, for example, may have a significantly longer run time than a hydrocracker in the conditioning section, parallel reactor trains and/or bypass processing may be used such that the overall run times of the conditioning and steam cracking units may be aligned.

Bypass processing may include, for example, temporarily processing a 490° C.+ cut in a reactor that normally processes a lighter feedstock. The heavier feedstock is anticipated to have more severe conditions and shorter catalyst life, and thus temporarily processing the heavies in a mid-range hydrocarbons conditioning reactor during a heavies catalyst change may allow the whole crude feed to continue to be fed to the steam cracker, without a shutdown, while the heavies conditioning reactor catalyst is replaced. Configuration of the mid-range conditioning reactors may also take into account the anticipated bypass processing when designing the overall system for aligned run times.

Steam cracker sections according to embodiments herein include one or more heaters for individually or collectively pre-heating of the respective conditioned hydrocarbon feeds, mixing the hydrocarbon feeds with steam, and heating of the mixed feeds to cracking temperatures. Further, the steam cracker sections herein include a separation system for separating the resulting cracked products into desired product fractions. The separation system may include one or multiple distillation columns, flash drums, extractive distillation columns, or other separation mechanisms known in the art for separation of a mixed hydrocarbon feed into various chemicals product fractions.

Systems for flexibly converting whole crudes to chemicals and fuels according to embodiments herein may also include a control system, such as a digital control system (DCS) or similar type computerized controls, to facilitate plant operations. The control systems may be used to control operations of the separators, reactors, heaters, and other unit operations, as well as the flow rates, pressures, and temperatures of such unit operations. Thus, the control system may be configured to control or adjust a cut point temperature of the light oil fraction, to control or adjust a cut point temperature of the middle oil fraction, to control or vary a severity within one or more reactors, to start up or shut down the separation system for separating the hydrotreated middle oil cut, as well as to control various flow rates, pressures and temperatures to maintain or transition to a particular mode of operation.

Advanced control systems may be used to control operating conditions in separators and individual processing sections as described above. Such controls may also incorporate advanced logic based on feed and product analyses to adjust operating conditions.

The steam cracker also provides system flexibility, the steam cracker being able to handle a wide variety of straight run and conditioned feeds to produce petrochemicals, as described herein. Thus, while many changes may be made to upstream operations when transitioning between operating modes, the steam cracker conditions may also be adjusted when transitioning to accommodate the differences in feed being provided during the respective modes of operation. Transitioning within the steam cracker section may include one or more of supplying, terminating supply, or varying a feed rate of supplemental external feeds provided directly to the steam cracker section, varying steam cracker heater operations, steam cracker firing rates or outlet temperatures, and varying steam cracker recovery section operating conditions, among others.

Advance control systems herein may be used, for example, to change heater and steam cracker operations prior to change over from diesel/gasoil feed to an external supplemental naphtha feed (max chemicals to chemicals plus fuel transition). Similarly, steam to hydrocarbon ratios for the steam cracker feeds may be made based on changing feed composition during the transition. Further the furnace outlet temperature may be adjusted for the steam cracker based on changing feed compositions during transitions. Overall, the goal may be to provide for smooth transition of operating conditions in each section (initial separations, hydrotreating, heavies conditioning, intra-unit separations, and steam cracking), coordinating operations of each portion of the plant.

Referring now to FIG. 1, FIG. 1 illustrates a simplified process flow diagram of a system for converting light crudes and condensates to chemicals and diesel or jet fuels according to embodiments herein. A wide boiling range heavy hydrocarbon feed, such as a desalted crude 1, is fed to a separation system 2. Separation system 2 may be an integrated separation device (ISD), as previously described and includes separation and heat integration, for example. In separation system 2, which may include a first separation stage 2A and a second separation stage 2B, the desalted crude 1 is separated into three fractions, including (a) a light oil cut 4, such as a 160° C.− fraction that does not require any conditioning and can be used as feed to the steam cracker section 6; (b) a middle oil cut 8, such as a 160-490° C. fraction that may be upgraded in a distillate hydrotreating unit 10; and (c) a heavy oil cut 12, such as a 490° C.+ fraction 15.

In distillate hydrotreating unit 10, the hydrocarbons in the middle oil cut are upgraded to produce a hydrotreated middle oil cut (effluent 14), having an increased hydrogen content that may be used as a steam cracker feedstock and to produce an ULSD product. The system of FIG. 1 includes a separation system 16 that may be used for fractionating the hydrotreated middle oil cut into a light hydrotreated cut 18, a diesel fuel or jet fuel fraction 20, and a heavy hydrotreated cut 22.

When operating the system of FIG. 1 in a max chemicals mode, the hydrotreated middle oil cut may bypass separation system 16 and may be fed directly to steam cracker section 6 via flow line 24. By not recovering a fuel fraction, the totality of the hydrotreated middle oil cut may be fed for conversion to chemicals in the steam cracker section 6, maximizing chemicals production.

When operating the system of FIG. 1 in the chemicals plus fuels mode, the middle oil cut may be processed in separation system 16, providing for the recovery of the desired diesel fuel or jet fuel fraction. The light hydrotreated cut 18 is then fed to the steam cracker section 6, or, as illustrated, combined with light oil cut 4 and fed to the steam cracker section 6 for production of chemicals. The heavy hydrotreated cut 22 is also fed to the steam cracker section 6 for production of chemicals.

Steam cracker section 6 includes one or more heaters, each having one or more process coils for heating the respective feeds, mixing the feeds with steam, and cracking the hydrocarbons therein to produce a cracked hydrocarbon product. Steam cracker section 6 also includes one or more separators (distillation columns, flash drums, extractive distillation columns, etc.) to separate the cracked hydrocarbon product into one, two, or several chemical fractions 26, such as an ethylene fraction, a propylene fraction, a butene fraction, an aromatics fraction, etc., as well as a heavy pyrolysis oil fraction 28.

The system of FIG. 1 may be operated such that the heavy oil cut 12 contains a small amount of the heavy hydrocarbons, such as less than about 5 vol % of the feed crude oil. For example, in embodiments processing a very light sweet crude or a poor condensate, the heavy oil cut may be less than 2 vol % of the feed crude oil. In such embodiments, the small amount of hydrocarbons in heavy oil cut 12 may be combined with pyrolysis oil 28 to form a fuel oil fraction 30. Fuel oil fraction 30, due to the hydrotreatment of the middle oil cut in distillate hydrotreating unit 10, may have a sulfur content and other properties so as to be classified as a very low or ultra-low sulfur fuel oil.

If desired, an external feedstock 32, such as a naphtha, liquid petroleum gas, or other light hydrocarbon feeds noted above, may be supplied to steam cracking section 6 for production of additional chemicals. Such feeds may be processed individually or may be mixed with a similar boiling range material selected from the light oil cut, the hydrotreated middle oil cut, or the heavy hydrotreated cut for processing in the steam cracking section 6. In some embodiments, an external feedstock 32, such as a naphtha, may be fed to the cracking coils typically used for cracking the volume of diesel fuel or jet fuel recovered via flow line 20 when operating in the chemicals plus fuels mode of operation. If needed, a treatment system 33 may be used to hydrotreat the external feedstock, such as for sulfur or contaminants removal, prior to use of the external feed in the steam cracker unit. In some embodiments, the external feed 32 may also be provided to the middle oil cut distillate hydrotreating section 10.

Production of chemicals or chemicals plus fuels may be altered in embodiments herein by additionally providing a C9+ aromatics recycle or a recycle of a light pyrolysis oil stream 35 to the distillate hydrotreating section 10. Further hydrotreating such hydrocarbons may provide for additional naphtha range materials that may be readily cracked to form chemicals, for example. The mode of operation may be used to determine whether or not such a recycle stream is provided.

The system of FIG. 1 may be used to flexibly produce max chemicals or to produce chemicals plus fuels, transitioning between operating modes as needed. Various operating variables may be adjusted to make the transition between modes, as noted above, including one or more of the following: operating temperature and/or pressure of first separation stage 2A; operating temperature and/or pressure of second separation stage 2B; reaction severity in hydrotreating unit 10; flow rate of hydrotreated middle oil cut fed to separation system 16; and flow rate of hydrotreated middle oil cut bypassing separation system 16. Processes herein may utilize each of these variables to transition between modes, and control systems herein may be configured to control these variables according to the mode of operation, as well as start up or ramp up and shut down or ramp down of separation system 16.

Referring now to FIG. 2, FIG. 2 illustrates a simplified process flow diagram of a system for converting crudes and condensates to chemicals and diesel or jet fuels according to embodiments herein. In this embodiment, the crude oil 1 is again separated into a light oil cut 4, a middle oil cut 8, and a heavy oil cut 12 in a separation system 2. The processing of the light oil cut and the middle oil cut are as described with respect to FIG. 1, feeding the respective fractions to the steam cracker to produce various chemicals fractions 26 and a pyrolysis oil 28. In this embodiment, however, the crude oil feed may have a quantity of heavy oil that makes it economically favorable to process the heavy oil cut to form additional chemicals.

The pyrolysis oil 28 recovered from steam cracker section 6 and the heavy oil cut 12 are fed to a heavies conditioning section 40 for conditioning of the heavy hydrocarbons to make a suitable steam cracker feed. As a first stage in the heavies conditioning section 40, the pyrolysis oil 28 and the heavy oil cut 12 are fed to a liquid circulation, ebullated bed residue hydrocracker (liquid circulation conditioning reactor 42). Following reaction within the liquid circulation conditioning reactor 42, the reaction effluent 44 may be fed to an effluent separation zone 46, separating the conditioned heavy hydrocarbons into a distillate fraction 48 and a heavy oil fraction 50. Effluent separation zone 46 may include an ISD, which may separate the lighter, conditioned hydrocarbons in stream 44 from heavier hydrocarbons.

The heavy oil fraction 50 is then fed to a first heavy oil reaction zone 52, which may include one or more hydrotreating and/or hydrocracking reactors to at least partially convert the heavy hydrocarbons. The hydrotreated heavy oil effluent 54 is then be fed to a heavy oil effluent separation zone 56, separating the lighter, converted materials in the hydrotreated oil into a hydrotreated distillate fraction 58, while the heavy unconverted oil fraction is recovered from effluent separation zone 56 as an ultra-low sulfur fuel oil stream 30.

Distillate fraction 48 and hydrotreated distillate fraction 58 are fed to a second heavy oil reaction zone 59, which may include one or more hydrotreating and/or hydrocracking reactors. Reaction zone 59 may be used to further condition the hydrocarbons in the respective fractions, making them suitable for use as a steam cracker feed. The hydrotreated distillate effluent 60 is then fed to a distillate separation zone 62, which may be used to separate the hydrotreated distillate effluent 60 into two or more distillate steam cracker feeds 64, 66, for processing in the steam cracker at appropriate conditions to produce chemicals.

With respect to flexibility of the process for producing max chemicals or chemicals plus fuel, the system as illustrated in FIG. 2 may be controlled in a manner similar to that as discussed with respect to FIG. 1. As the conditioned heavy oil is fed to the steam cracker, upfront separations and severity in middle oil cut hydrotreating, as well as flow rates/configuration, are the primary means of transitioning between the operating modes.

Referring now to FIG. 3, FIG. 3 illustrates a simplified process flow diagram of a system for converting crudes and condensates to chemicals and diesel or jet fuels according to embodiments herein. In this embodiment, the processing of the middle oil cut and the heavy oil cut may be integrated, similar to that as described for FIG. 2, providing more flexibility in producing diesel fuel or jet fuel products in addition to chemicals. In the embodiment of FIG. 3, however, separation system 16, is configured to fractionate the hydrotreated middle oil cut into a light hydrotreated cut 18, a diesel fuel or jet fuel fraction 20, and a heavy hydrotreated cut 22. Distillate separation zone 62 is used to separate the hydrotreated distillate effluent 60 to recover a light conditioned cut 64, a diesel fuel or jet fuel fraction 66, and a heavy conditioned cut 67. In a max chemicals mode, each of these streams (18, 20, 22, 64, 66, 67) may be fed to steam cracker unit 6 and cracked at appropriate conditions to produce chemicals. In a chemicals plus fuel mode, a portion of one or both streams 20, 66 may be recovered as a fuel product fraction (diesel fuel product or jet fuel product). Heavy conditioned cut 67 may, in some embodiments, be combined with the heavy unconverted oil recovered from effluent separation zone 56 to form an ultra-low sulfur fuel oil stream 30.

Referring now to FIG. 4, FIG. 4 illustrates a simplified process flow diagram of a system for converting crudes and condensates to chemicals and diesel or jet fuels according to embodiments herein. In this embodiment, the processing of the middle oil cut and the heavy oil cut may be integrated, providing more flexibility in producing diesel fuel or jet fuel products in addition to chemicals.

In the process of FIG. 4, similar to the processes of FIGS. 1 and 2, the light oil cut 4 is fed directly to the steam cracker. The middle oil cut 8 is also similarly processed in middle oil hydrotreater 10. Further, the heavy oil cut 12 is similarly processed in heavies conditioning unit 40. In this embodiment, however, the hydrotreated distillate effluent 60, is processed through separation zone 16 to recover diesel fuel or jet fuel range hydrocarbons that may have been formed during processing of the heavy oil cut in heavies conditioning unit 40. The hydrotreated distillate effluent 60 is fed to an intermediate separation zone 62, separating the hydrocarbons in the effluent to form a distillate fraction 64 and a lights fraction (not illustrated), which may include unreacted hydrogen and hydrogen sulfide, for example. Distillate fraction 64 is then co-processed with hydrotreated middle oil effluent 14 in separation zone 16 to provide the light hydrotreated fraction 18, heavy hydrotreated fraction 22, and diesel fuel or jet fuel fraction 20, each being fed to the steam cracker section 6 for production of chemicals. For chemicals plus fuels production, a portion or an entirety of the jet fuel or diesel fuel fraction may be recovered by fuel product stream 20A. Unconverted oil fraction 70 may be combined with the residue from separation zone 54 for inclusion with the ultra-low sulfur fuel oil 30.

While illustrated as feeding both streams 14 and 64 to separation zone 16, in some embodiments of FIG. 4, similar to other embodiments herein, bypass lines (similar to line 24 of FIGS. 1 and 2) may be provided to feed the various upgraded streams directly to the steam cracker unit 6 during max chemicals mode, if desired.

In the embodiment of FIG. 4, similar control schemes may be used to transition between max chemicals and chemicals plus fuels modes of operation. Additionally, the severity of reaction within each reaction zone (10, 42, 50, 59) of heavies conditioning unit 40 may be adjusted to increase or decrease an amount of diesel fuel or jet fuel produced by the system.

As noted above, the transitioning between various modes of operation may include the introduction of one or more low value streams into the system, providing for conversion of the low value streams to higher value chemicals. As illustrated in FIGS. 2 and 3, one or more low value streams 80 may be provided to the second stage separator 2B, or to heavies conditioning section 40, thereby allowing the hydrocarbons within the low value additional feeds to be processed in the most efficient manner to produce chemicals or chemicals and fuels.

Crude oil handling typically requires a conventional refinery unit such as crude distillation to segregate the various boiling range fractions for further downstream processing. Refinery and petrochemical complexes are segregated and operate independently of each other. The conventional and independent refinery configuration is capital and energy intensive, which can be eliminated and/or optimized using embodiments herein to meet the objective of maximizing the conversion of crude to high value products. Embodiments herein further provide flexibility to produce high quality ULSD while maximizing the production of high value chemicals products such as ethylene and propylene. The ULSD stream can either be recovered as a saleable product or fed into the steam cracker for additional chemicals production.

HPNAs lead to rapid coke formation in a steam cracker furnace, which necessitates frequent decoke cycles, decreasing the overall on-stream factor of the complex. Conversion of vacuum residue without significant formation of heavy polynuclear aromatics (HPNAs) that are detrimental to steam cracker furnaces downstream of the process is challenging.

The vacuum residue portion of the crude oil is very deficient in hydrogen, which decreases the yield of valuable chemicals in the steam cracking furnaces. By upgrading this portion of the feed through hydroprocessing according to embodiment herein to increase the hydrogen content, the total chemicals yield can be increased per barrel of feed. Embodiments herein thus increase the production of chemicals from each barrel of crude oil or condensate feed with reduced capital and energy intensity, while maintaining an option for producing a high quality ultra-low sulfur diesel.

In embodiments herein, the crude oil and/or condensate feed is initially separated in the upfront crude separation into distinct fractions such as a lighter fraction (nominally less than 160-200° C., which is rich in normal paraffins and thus a good steam cracker feedstock), a middle fraction containing distillate and gasoil range material (nominally 160-200 to 300-500° C.), and a heavy stream (nominally 300-500° C.+). The operating and capital efficiency of the overall unit are significantly increased while also lowering overall operating costs and carbon footprint.

The separation of the middle cut, which is rich in high-quality diesel range molecules allows for more capital-efficient processing to produce ULSD while still maintaining the option to route the diesel to the steam cracker for maximum petrochemical production. Embodiments herein thus allow for a more capital-efficient processing to produce ULSD while still maintaining the option to route the diesel to the steam cracker for maximum petrochemical production. This optional routing provides maximum flexibility for the product slate of the unit.

The upfront separation of the crude according to embodiments herein may be deeply integrated with the mixed feed steam cracking heaters, which may both reduce capital investment and increase the overall efficiency of the unit by optimizing the recovery of heat into the upfront separation process. The configurations herein may combine the energy requirements for the upfront crude separation to meet the downstream cracking heater vaporization requirement.

The system is designed to process all types of crude oil and condensate feeds, and as such specialized hydroprocessing operations are included to treat the middle cut to a diesel product and upgrade the heaviest, residue portion of the crude. Unlike a traditional refinery for producing chemicals, feeds to the steam cracker are not limited to light components and naphtha, rather a full range from naphtha to gasoil boiling range molecules can be fed to the heaters. The design of the cracking heaters and downstream system of embodiments herein accommodate the non-traditional feeds.

The individual blocks or processing operations according to embodiments herein may be deeply integrated such that they are combined into one unit/one technology. The operation and design of each block is tailored such that the product of each is suitable for either the following block or the end product goal. In a traditional configuration, this integration is not possible due to the differing requirements of intermediate and respective final products.

The following are brief synopses of exemplary configurations according to embodiments herein.

Some embodiments provide a configuration for processing very light, sweet crude feedstocks (API ˜>45°) and/or condensates with two crude separation steps to produce a light fraction, with components boiling below 160-200° C., a middle fraction, with components boiling between 160-200° C. to 460-500° C., and a residue bleed fraction with components boiling above ˜460-500° C. The light stream is sent to the steam cracker section without intermediate processing as it is rich in normal paraffins and thus an excellent steam cracker feedstock. The middle fraction is upgraded utilizing a fixed-bed hydroprocessing reactor operating at mild severity to increase hydrogen content to produce steam cracker feedstock and ULSD product (which can be optionally routed to steam cracker for maximizing chemicals production). The residue bleed along with the steam cracker pyrolysis fuel oil are routed to fuel oil without additional processing. Optional external feedstocks such as LPG and naphtha can be co-processed in steam cracker for additional chemical products.

Other embodiments provide a configuration for processing crude feedstocks with two crude separation steps to produce a light fraction, with components boiling below 160-200° C., middle fraction, with components boiling between 160-200° C. to 300-400° C., and residue fraction with components boiling above 300-400° C. The light stream is sent to the steam cracker section without intermediate processing as it is rich in normal paraffins and thus an excellent steam cracker feedstock. The middle fraction is upgraded utilizing a fixed-bed hydroprocessing reactor operating at mild severity to increase hydrogen content to produce steam cracker feedstock and ULSD product (which can be optionally routed to steam cracker for maximizing chemicals production). The residue fraction is upgraded in a liquid circulation, hydrocracking reactor system. The distillates products are further conditioned in a fixed bed hydroprocessing reactor to increase hydrogen content to produce steam cracker feedstock. The unconverted fraction from the resid upgrading process is further hydroprocessed to produce very low sulfur fuel oil (VLSFO). Pyrolysis oil from the Steam Cracker Section is recycled to the residue hydroprocessing step along with the residue portion of the crude oil feed. Optional external feedstocks such as LPG and naphtha can be co-processed in steam cracker for additional chemical products. Additional low value refinery streams such as slurry oil, LCO, high sulfur fuel oil can be co-processed in the heavies conditioning section.

Other embodiments provide a configuration for processing crude feedstocks with two crude separation steps to produce a light fraction, with components boiling below 160-200° C., middle fraction, with components boiling between 160-200° C. to 300-400° C., and residue fraction with components boiling above 300-400° C. The light stream is sent to the steam cracker section without intermediate processing as it is rich in normal paraffins and thus an excellent steam cracker feedstock. The middle fraction is upgraded utilizing a fixed bed hydroprocessing reactor operating at mild severity to increase hydrogen content to produce steam cracker feedstock and ULSD product. The residue fraction is upgraded in a liquid circulation, hydrocracking reactor system. The distillates products are further conditioned in an integrated fixed bed hydroprocessing reactor to increase hydrogen content to produce steam cracker feedstock. The effluent from both fixed bed hydroprocessing steps are routed to a common fractionation section to maximize ULSD production, if economically justified. The ULSD product can be optionally routed to steam cracker for maximizing chemicals production, and unconverted oil can be routed to steam cracker and/or fuel oil pool. The unconverted fraction from the resid upgrading process is further hydroprocessed to produce very low sulfur fuel oil (VLSFO). Pyrolysis oil from the steam cracker section is recycled to the residue hydroprocessing step along with the residue portion of the crude oil feed. Optional external feedstocks such as LPG and naphtha can be co-processed in steam cracker for additional chemical products. Additional low value refinery streams such as slurry oil, LCO, high sulfur fuel oil can be co-processed in the heavies conditioning section.

As described, embodiments herein provide for converting crude oil feed and/or condensates into chemicals and/or ULSD production with reduction and/or elimination of conventional refinery unit operations. A two-step crude separation is used to segregate the crude oil into distinct fractions: a light fraction, a middle fraction, and a residue fraction. The light stream is sent directly to the Steam Cracker Section for conversion to chemicals. The middle fraction is further conditioned in a mild fixed bed hydroprocessing step to produce ULSD product, which can be optionally routed to steam cracker for maximizing chemicals production. Depending on the feed, the residue fraction can be a bleed from the system, or can be routed to a liquid circulation, hydrocracking reactor system where the hydrogen content of the heavy fraction is increased and recovered products after additional conditioning in an integrated, fixed bed hydroprocessing step can be routed to either diesel product or sent to the steam cracking heaters to produce chemicals, thus increasing the overall production of total chemicals. The unconverted fraction from the resid upgrading process is further hydroprocessed to produce very low sulfur fuel oil (VLSFO). Pyrolysis oil from the steam cracker section is recycled to the residue hydroprocessing step along with the residue portion of the crude oil feed. Optional external feedstocks such as LPG and naphtha can be co-processed in steam cracker for additional chemical products. Additional low value refinery streams such as slurry oil, LCO, high sulfur fuel oil can be co-processed in the heavies conditioning section; the feed point within systems herein for such additional streams may depend upon the properties of the additional feed stream, and embodiments herein may include feed of one or more of such streams to any of the feed conditioning section, the liquid circulation reactors, or to the crackers within the heavies conditioning section.

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.