EP3679113A1 - Hydrotraitement de fractions craquées de densité élevée - Google Patents

Hydrotraitement de fractions craquées de densité élevée

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Publication number
EP3679113A1
EP3679113A1 EP18778608.2A EP18778608A EP3679113A1 EP 3679113 A1 EP3679113 A1 EP 3679113A1 EP 18778608 A EP18778608 A EP 18778608A EP 3679113 A1 EP3679113 A1 EP 3679113A1
Authority
EP
European Patent Office
Prior art keywords
catalyst
feedstock
hydroprocessing
less
feed
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Withdrawn
Application number
EP18778608.2A
Other languages
German (de)
English (en)
Inventor
Mark A. DEIMUND
Samia ILIAS
Randolph J. Smiley
Ajit B. Dandekar
Scott J. WEIGEL
Darryl D. Lacy
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
ExxonMobil Technology and Engineering Co
Original Assignee
ExxonMobil Research and Engineering Co
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Filing date
Publication date
Application filed by ExxonMobil Research and Engineering Co filed Critical ExxonMobil Research and Engineering Co
Publication of EP3679113A1 publication Critical patent/EP3679113A1/fr
Withdrawn legal-status Critical Current

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Classifications

    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G45/00—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds
    • C10G45/02—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing
    • C10G45/04—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing characterised by the catalyst used
    • C10G45/06—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing characterised by the catalyst used containing nickel or cobalt metal, or compounds thereof
    • C10G45/08—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing characterised by the catalyst used containing nickel or cobalt metal, or compounds thereof in combination with chromium, molybdenum, or tungsten metals, or compounds thereof
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G45/00—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds
    • C10G45/44—Hydrogenation of the aromatic hydrocarbons
    • C10G45/46—Hydrogenation of the aromatic hydrocarbons characterised by the catalyst used
    • C10G45/48—Hydrogenation of the aromatic hydrocarbons characterised by the catalyst used containing nickel or cobalt metal, or compounds thereof
    • C10G45/50—Hydrogenation of the aromatic hydrocarbons characterised by the catalyst used containing nickel or cobalt metal, or compounds thereof in combination with chromium, molybdenum or tungsten metal, or compounds thereof
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G45/00—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds
    • C10G45/44—Hydrogenation of the aromatic hydrocarbons
    • C10G45/46—Hydrogenation of the aromatic hydrocarbons characterised by the catalyst used
    • C10G45/52—Hydrogenation of the aromatic hydrocarbons characterised by the catalyst used containing platinum group metals or compounds thereof
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G47/00—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions
    • C10G47/02—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions characterised by the catalyst used
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G47/00—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions
    • C10G47/02—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions characterised by the catalyst used
    • C10G47/10—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions characterised by the catalyst used with catalysts deposited on a carrier
    • C10G47/12—Inorganic carriers
    • C10G47/16—Crystalline alumino-silicate carriers
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G47/00—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions
    • C10G47/02—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions characterised by the catalyst used
    • C10G47/10—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions characterised by the catalyst used with catalysts deposited on a carrier
    • C10G47/12—Inorganic carriers
    • C10G47/16—Crystalline alumino-silicate carriers
    • C10G47/18—Crystalline alumino-silicate carriers the catalyst containing platinum group metals or compounds thereof
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G65/00—Treatment of hydrocarbon oils by two or more hydrotreatment processes only
    • C10G65/02—Treatment of hydrocarbon oils by two or more hydrotreatment processes only plural serial stages only
    • C10G65/12—Treatment of hydrocarbon oils by two or more hydrotreatment processes only plural serial stages only including cracking steps and other hydrotreatment steps
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/30—Physical properties of feedstocks or products
    • C10G2300/301—Boiling range
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/30—Physical properties of feedstocks or products
    • C10G2300/308—Gravity, density, e.g. API

Definitions

  • MCB main column bottoms
  • HAFO heavy aromatic fuel oil
  • MCB MCB
  • sulfur content ⁇ 3 wt%
  • the process comprises providing a feedstock comprising a density at 15°C of 1.06 g/cm 3 or more, at least 50 wt% of one or more 343°C+ cracked fractions, and a sulfur content of 0.8 to 5.0wt% sulfur, and, in a single reaction stage under fixed bed hydroprocessing conditions, exposing the feedstock to a first bulk or supported mixed metal catalyst comprising Ni and Mo; exposing the feedstock to a second bulk or supported mixed metal catalyst comprising Ni and W; and exposing the feedstock to a third catalyst comprising a zeolite-based hydrocracking catalyst.
  • the zeolite-based hydrocracking catalyst comprises a Group VIII noble metal such as Pt.
  • the Pt will typically comprises 0.5 to 2.5 wt% of the hydrocracking catalyst.
  • the zeolite exhibits a faujasite (FAU) framework type.
  • the third catalyst may comprise an aromatic saturation catalyst on an aluminosilicate support.
  • the arosat catalyst may include Pd, Pt, or a combination thereof. When the arosat catalyst comprises both Pd and Pt, it would typically do so in a wt% ration of about 3: 1 Pd to Pt.
  • the feedstock is a deasphalted heavy cracked feed.
  • the fixed bed hydroprocessing conditions include a temperature of 300°C to 400°C, a pressure of 1500 psig to 3000 psig, a hydrogen treat gas rate of 2,000 scf/bbl to 12,000 scf/bbl, and a LHSV of 0.21T 1 to 1.5 h "1 .
  • a system for processing a cracked feedstock comprising: a hydroprocessing reactor comprising a hydroprocessing inlet, and a hydroprocessing outlet, and a fixed bed comprising a first bulk or supported mixed metal catalyst comprising Ni and Mo; a second bulk or supported mixed metal catalyst comprising Ni and W; and a third catalyst comprising a zeolite-based hydrocracking catalyst; wherein the hydroprocessing inlet is designed to receive a feedstock comprising a density at 15°C of 1.06 g/cm 3 or more, at least 50 wt% of one or more 343°C+ cracked fractions, and a sulfur content of 1.0 to 5.0wt% sulfur; and wherein the fixed bed is oriented such that the feedstock contacts the first catalyst, second catalyst, and third catalyst sequentially.
  • FIG. 1 depicts catalyst bed configurations according the present disclosure and those used in Examples 1 and 2.
  • FIGS. 2A-2F provide graphical data obtained in Example 1.
  • FIGS. 3A-3F provide graphical data obtained in Example 2.
  • FIG. 4 depicts catalyst bed configurations according the present disclosure and those used in Example 3.
  • FIGS. 5A-5F provide graphical data obtained in Example 3.
  • FIG. 6 depicts catalyst bed configurations according the present disclosure and those used in Examples 4 and 5.
  • FIGS. 7A-7F provide graphical data obtained in Example 4.
  • FIGS. 8A-8F provide graphical data obtained in Example 5.
  • systems and methods are provided for upgrading a high density cracked feedstock, such as a catalytic slurry oil, by hydroprocessing.
  • a high density cracked feedstock such as a catalytic slurry oil
  • hydroprocessing a high density cracked feedstock
  • Difficulties in processing heavy cracked feeds can be related to difficulties in performing distillation on the feeds.
  • one of the strategies for processing a challenging feedstock can be to use distillation to separate a more favorable portion of a feed from a typically higher boiling less favorable portion.
  • an atmospheric distillation can be used to separate a feed into lower boiling portions and a higher boiling portion at a distillation cut point between about 600°F ( ⁇ 316°C) and about 700°F ( ⁇ 371°C).
  • the higher boiling portion can then correspond to a roughly 316°C+ portion, or a roughly 343°C+ portion, or a roughly 371°C+ portion.
  • a further distillation can be performed on this higher boiling portion under reduced pressure or vacuum distillation conditions. This can produce one or more vacuum distillate fractions and a bottoms fraction.
  • heavy cracked feeds such as catalytic slurry oils can often have a density of about 1.04 g/cm 3 or more, or about 1.06 g/cm 3 or more, or about 1.08 g/cm 3 or more, such as up to 1.14 g/cm 3 or possibly still higher.
  • performing a vacuum distillation under conventional vacuum distillation conditions becomes increasingly difficult and/or inefficient.
  • high density fractions can tend to have poor separation characteristics under conventional vacuum distillation conditions.
  • either substantial amounts of undesirable components can remain in the "desired" distillate fraction(s), and/or substantial amounts of the desired components can remain in the bottoms fraction.
  • first and second catalysts may be bulk metal or supported catalysts.
  • single reaction stage means that no intermediate separation is performed between exposing the feed to the catalysts. In other words, the reactions described herein may take place in a single reactor or multiple reactors. So long as no intermediate separation is performed between exposures to the different catalysts, then it can be said that the process takes place in a single reaction stage.
  • This third zeolite-based hydrocracking catalyst can be any number of commercially available hydrocracking catalysts. Additionally or alternatively, the third catalyst can include an aromatic saturation ("arosat") catalyst. Additionally or alternatively, the third catalyst can include a noble metal. Use of a zeolite-based hydrocracking catalyst with additional aromatic saturation and/or noble metal catalyst would conventionally be considered undesirable with feeds having high aromatic, nitrogen, and sulfur content because of rapid poisoning of the catalyst. Particularly, the organosulfur and organonitrogen species present in the feed are thought to interact with noble metals and acid sites on hydrocracking, arosat, and/or noble-metal catalysts, respectively, causing this catalyst poisoning and deactivation.
  • the first hydrotreating catalyst bed (Ni and Mo, in this instance) is intended to do hydrotreating on the "easier" S- and N- containing species to reduce the organosulfur and organonitrogen content dramatically from the levels found in the feed.
  • a second intermediate bed of higher activity hydrotreating catalyst (such as a Ni and W containing material) can further reduce organic S- and N-content to ppm levels by converting the more refractory molecules that are thought to act as stronger catalyst poisons.
  • the organosulfur and organonitrogen species cause significantly less poisoning and deactivation relative to their feed levels, and furthermore the hydrogen sulfide and ammonia present surprisingly do not appear to have any significant effect on catalyst activity in the third bed containing hydrocracking, arosat, and/or noble- metal catalysts.
  • Conversion relative to a temperature can be defined based on the portion of the feedstock that boils at greater than the conversion temperature.
  • the amount of conversion during a process can correspond to the weight percentage of the feedstock converted from boiling above the conversion temperature to boiling below the conversion temperature.
  • a feedstock that includes 40 wt% of components that boil at 700°F ( ⁇ 371°C) or greater. By definition, the remaining 60 wt% of the feedstock boils at less than 700°F ( ⁇ 371°C).
  • the amount of conversion relative to a conversion temperature of ⁇ 371 °C would be based only on the 40 wt% that initially boils at ⁇ 371 °C or greater. If such a feedstock could be exposed to a process with 30% conversion relative to a ⁇ 371 °C conversion temperature, the resulting product would include 72 wt% of ⁇ 371°C- components and 28 wt% of ⁇ 371°C+ components.
  • fractions generated during distillation of a feedstock or effluent may include naphtha fractions, kerosene fractions, diesel fractions, and other heavier (gas oil) fractions.
  • Each of these types of fractions can be defined based on a boiling range, such as a boiling range that includes at least -90 wt% of the fraction, or at least -95 wt% of the fraction.
  • At least -90 wt% of the fraction, or at least -95 wt% can have a boiling point in the range of ⁇ 85°F ( ⁇ 29°C) to ⁇ 350°F ( ⁇ 177°C).
  • at least -90 wt% of the fraction, and preferably at least -95 wt% can have a boiling point in the range of ⁇ 85°F ( ⁇ 29°C) to ⁇ 400°F ( ⁇ 204°C).
  • At least -90 wt% of the fraction, or at least -95 wt% can have a boiling point in the range of ⁇ 300°F ( ⁇ 149°C) to ⁇ 600°F ( ⁇ 288°C).
  • at least -90 wt% of the fraction, or at least -95 wt% can have a boiling point in the range of ⁇ 300°F ( ⁇ 149°C) to ⁇ 550°F ( ⁇ 288°C).
  • At least -90 wt% of the fraction, and preferably at least -95 wt% can have a boiling point in the range of ⁇ 350°F ( ⁇ 177°C) to ⁇ 700°F ( ⁇ 371°C).
  • at least -90 wt% of the fraction, and preferably at least -95 wt% can have a boiling point in the range of ⁇ 650°F ( ⁇ 343°C) to ⁇ 1100°F ( ⁇ 593°C).
  • a narrower boiling range may be desirable.
  • At least -90 wt% of the fraction, or at least -95 wt% can have a boiling point in the range of ⁇ 650°F ( ⁇ 343°C) to ⁇ 1000°F ( ⁇ 538°C), or ⁇ 650°F ( ⁇ 343°C) to ⁇ 900°F ( ⁇ 482°C).
  • a residual fuel product can have a boiling range that may vary and/or overlap with one or more of the above boiling ranges.
  • a residual marine fuel product can satisfy the requirements specified in ISO 8217, Table 2.
  • a low sulfur fuel oil can correspond to a fuel oil containing about 0.5 wt% or less of sulfur.
  • An ultra low sulfur fuel oil which can also be referred to as an Emission Control Area fuel, can correspond to a fuel oil containing about 0.1 wt% or less of sulfur.
  • a low sulfur diesel can correspond to a diesel fuel containing about 500 wppm or less of sulfur.
  • An ultra low sulfur diesel can correspond to a diesel fuel containing about 15 wppm or less of sulfur, or about 10 wppm or less.
  • a catalytic slurry oil when initially formed, can include several weight percent of catalyst fines. Any such catalyst fines can be removed prior to incorporating a fraction derived from a catalytic slurry oil into a product pool, such as a naphtha fuel pool or a diesel fuel pool.
  • references to a catalytic slurry oil are defined to include catalytic slurry oil either prior to or after such a process for reducing the content of catalyst fines within the catalytic slurry oil.
  • a catalytic slurry oil is an example of a suitable cracked fraction for incorporation into a feedstock. It is conventionally understood that conversion of ⁇ 1050°F+ ( ⁇ 566°C+) vacuum resid fractions by hydroprocessing and/or hydrocracking can be limited by incompatibility. Under conventional understanding, at somewhere between -30 wt% and -55 wt% conversion of the ⁇ 1050°F+ ( ⁇ 566°C+) portion, the reaction product during hydroprocessing can become incompatible with the feed.
  • ⁇ 566°C+ feedstock converts to ⁇ 1050°F- ( ⁇ 566°C-) products
  • hydrogen transfer, oligomerization, and dealkylation reactions can occur which create molecules that are increasingly difficult to keep in solution.
  • a second liquid hydrocarbon phase separates.
  • This new incompatible phase under conventional understanding, can correspond to mostly polynuclear aromatics rich in N, S, and metals.
  • the new incompatible phase can potentially be high in micro carbon residue (MCR).
  • MCR micro carbon residue
  • the new incompatible phase can stick to surfaces in the unit where it cokes and then can foul the equipment.
  • catalytic slurry oil can conventionally be expected to exhibit properties similar to a vacuum resid fraction during hydroprocessing. Based on the above conventional understanding, it can be expected that hydroprocessing of a catalytic slurry oil would cause incompatibility as the asphaltenes and/or ⁇ 566°C+ material converts.
  • a heavy cracked feed can be processed as part of a feed where the heavy cracked feed corresponds to at least about 25 wt% of the feed to a process for forming fuels, such as at least about 50 wt%, at least about 75 wt%, at least about 90 wt%, or at least about 95 wt%.
  • the feed can correspond to at least about 99 wt% of a heavy cracked feed, therefore corresponding to a feed that consists essentially of heavy cracked feed.
  • a feed can comprise about 25 wt% to about 100 wt% heavy cracked feed, or about 25 wt% to about 99 wt%, or about 50 wt% to about 90 wt%. It has been unexpectedly discovered that this sequential exposure of the heavy cracked feed to the catalysts at effective hydroprocessing conditions results in substantial conversion of the feed without causing excessive coking of the catalyst or differential pressure build across the hydroprocessing reactor, which would be indicative of asphaltene precipitation.
  • the cut point for forming a heavy cracked feed can be at least about 650°F ( ⁇ 343°C).
  • a heavy cracked feed can have a T5 distillation (boiling) point or a T10 distillation point of at least about 288°C, or at least about 316°C, or at least about 650°F ( ⁇ 343°C), as measured according to ASTM D2887.
  • the D2887 10% distillation point (T10) can be greater, such as at least about 675°F ( ⁇ 357°C), or at least about 700°F ( ⁇ 371°C).
  • a broader boiling range portion of FCC products can be used as a feed (e.g., a 350°F+ / ⁇ 177°C+ boiling range fraction of FCC liquid product), where the broader boiling range portion includes a 650°F+ ( ⁇ 343°C+) fraction that corresponds to aheavy cracked feed.
  • the heavy cracked feed (650°F+ / ⁇ 343°C+) fraction of the feed does not necessarily have to represent a "bottoms" fraction from an FCC process, so long as the heavy cracked feed portion comprises one or more of the other feed characteristics described herein.
  • a feedstock can be characterized based on the portion of the feedstock that boils above 1050°F ( ⁇ 566°C).
  • a feedstock (or alternatively a 650°F+ / ⁇ 343°C+ portion of a feedstock) can have an ASTM D2887 T95 distillation point of 1050°F ( ⁇ 566°C) or greater, or a T90 distillation point of 1050°F ( ⁇ 566°C) or greater. If a feedstock or other sample contains components that are not suitable for characterization using D2887, ASTM Dl 160 may be used instead for such components.
  • density, or weight per volume, of the heavy cracked feed can be characterized.
  • the density of the heavy cracked feed (or alternatively a 650°F+ / ⁇ 343°C+ portion of a feedstock) can be at least about 1.06 g/cc, or at least about 1.08 g/cc, or at least about 1.10 g/cc, such as up to about 1.20 g/cc.
  • the density of the heavy cracked feed can provide an indication of the amount of heavy aromatic cores that are present within the heavy cracked feed.
  • Contaminants such as organic nitrogen and organic sulfur are typically found in heavy cracked feeds, often in organically -bound form.
  • Nitrogen content can range from about 50 wppm to about 5000 wppm elemental nitrogen, or about 100 wppm to about 2000 wppm elemental nitrogen, or about 250 wppm to about 1000 wppm, based on total weight of the heavy cracked feed.
  • the nitrogen containing compounds can be present as basic or non-basic nitrogen species. Examples of nitrogen species can include quinolones, substituted quinolones, carbazoles, and substituted carbazoles.
  • the sulfur content of a heavy cracked feed can be at least about 500 wppm elemental sulfur, based on total weight of the heavy cracked feed.
  • the sulfur content of a heavy cracked feed can range from about 500 wppm to about 100,000 wppm elemental sulfur, or from about 1000 wppm to about 50,000 wppm, or from about 1000 wppm to about 30,000 wppm, based on total weight of the heavy component.
  • Sulfur may also be expressed as weight percent and can range from about 0.5wt% to about 6wt%, or from about lwt% to about 5wt%, or about 2wt% to about 4wt%.
  • Sulfur can usually be present as organically bound sulfur.
  • sulfur compounds examples include the class of heterocyclic sulfur compounds such as thiophenes, tetrahydrothiophenes, benzothiophenes and their higher homologs and analogs.
  • Other organically bound sulfur compounds include aliphatic, naphthenic, and aromatic mercaptans, sulfides, di- and polysulfides.
  • a favorable feature of hydroprocessing a heavy cracked feed can be the increase in product volume that can be achieved. Due to the high percentage of aromatic cores in a heavy cracked feed, hydroprocessing of heavy cracked feed can result in substantial consumption of hydrogen. The additional hydrogen added to a heavy cracked feed can result in an increase in volume for the hydroprocessed heavy cracked feed or volume swell. For example, the amount of C3+ liquid products generated from hydrotreatment and FCC processing of catalytic slurry oil can be greater than -100% of the volume of the initial catalytic slurry oil.
  • Hydroprocessing within the normal range of commercial hydrotreater operations can enable -2000-4000 SCF/bbl (-340 Nm 3 /m 3 to -680 m 3 /m 3 ) of hydrogen to be added to a feed corresponding to a deasphalted heavy cracked feed.
  • ⁇ 700°F- ( ⁇ 371°C-) products can result in substantial conversion of a deasphalted heavy cracked feed to ⁇ 700°F- ( ⁇ 371°C-) products, such as at least about 40 wt% conversion to ⁇ 371°C- products, or at least about 50 wt%, or at least about 60 wt%, and up to about 90 wt% or more.
  • the ⁇ 371°C- product can meet the requirements for a low sulfur diesel fuel blendstock in the U.S.
  • the ⁇ 371°C- product(s) can be upgraded by further hydroprocessing to a low sulfur diesel fuel or blendstock.
  • the remaining ⁇ 700°F+ ( ⁇ 371°C+) product can meet the normal specifications for a ⁇ -0.5 wt% S bunker fuel or a ⁇ ⁇ 0.1 wt% S bunker fuel, and/or may be blended with a distillate range blendstock to produce a finished blend that can meet the specifications for a ⁇ ⁇ 0.1 wt% S bunker fuel. Additionally or alternately, a ⁇ 343°C+ product can be formed that can be suitable for use as a ⁇ ⁇ 0.1 wt% S bunker fuel without additional blending.
  • the additional hydrogen for the hydrotreatment of the heavy cracked feed can be provided from any convenient source.
  • the remaining ⁇ 371°C+ product (and/or portions of the ⁇ 371°C+ product) can be used as feedstock to an FCC unit and cracked to generate additional LPG, gasoline, and diesel fuel, so that the yield of ⁇ 371°C- products relative to the total liquid product yield can be at least about 60 wt%, or at least about 70 wt%, or at least about 80 wt%.
  • the yield of C3+ liquid products can be at least about 100 vol%, such as at least about 105 vol%, at least about 110 vol%, at least about 115 vol%, or at least about 120 vol%.
  • the yield of C3+ liquid products can be about 100 vol% to about 150 vol%, or about 110 vol% to about 150 vol%, or about 120 vol% to about 150 vol%.
  • the systems and methods described herein can be used for processing feedstocks containing one or more types of cracked feeds that have a high density prior to hydroprocessing, such as a density of 1.04 g/cm 3 or more, or 1.06 g/cm 3 or more, or 1.08 g/cm 3 or more, such as up to 1.20 g/cm 3 or possibly still higher.
  • the feedstock including one or more cracked feeds can have an aromatics content of about 40 wt% to about 80 wt%, or about 40 wt% to about 70 wt%, or about 50 wt% to about 80 wt%.
  • other types of cracked stocks include, but are not limited to, heavy coker gas oils (such coker bottoms), steam cracker tars, coal tars, and visbreaker gas oils.
  • steam cracker tar as used herein is also referred to in the art as "pyrolysis fuel oil".
  • the terms can be used interchangeably herein.
  • the tar will typically be obtained from the first fractionator downstream from a steam cracker (pyrolysis furnace) as the bottoms product of the fractionator, nominally having a boiling point of at least about 550°F+ ( ⁇ 288°C+).
  • Boiling points and/or fractional weight distillation points can be determined by, for example, ASTM D2892.
  • SCT can have a T5 boiling point (temperature at which 5 wt% will boil off) of at least about 550°F ( ⁇ 288°C).
  • the final boiling point of SCT can be dependent on the nature of the initial pyrolysis feed and/or the pyrolysis conditions, and typically can be about 1450°F ( ⁇ 788°C) or less.
  • SCT can have a relatively low hydrogen content compared to heavy oil fractions that are typically processed in a refinery setting.
  • SCT can have a hydrogen content of about 8.0 wt% or less, about 7.5 wt% or less, or about 7.0 wt% or less, or about 6.5 wt% or less.
  • SCT can have a hydrogen content of about 5.5 wt% to about 8.0 wt%, or about 6.0 wt% to about 7.5 wt%.
  • SCT can have a micro carbon residue (or alternatively Conradson Carbon Residue) of at least about 10 wt%, or at least about 15 wt%, or at least about 20 wt%, such as up to about 40 wt% or more.
  • SCT can also be highly aromatic in nature.
  • the paraffin content of SCT can be about 2.0 wt% or less, or about 1.0 wt% or less, such as having substantially no paraffin content.
  • the naphthene content of SCT can also be about 2.0 wt% or less or about 1.0 wt% or less, such as having substantially no naphthene content.
  • the combined paraffin and naphthene content of SCT can be about 1.0 wt% or less.
  • aromatics at least about 30 wt% of SCT can correspond to 3 -ring aromatics, or at least 40 wt%.
  • the 3-ring aromatics content can be about 30 wt% to about 60 wt%, or about 40 wt% to about 55 wt%, or about 40 wt% to about 50 wt%. Additionally or alternately, at least about 30 wt% of SCT can correspond to 4-ring aromatics, or at least 40 wt%.
  • the 4-ring aromatics content can be about 30 wt% to about 60 wt%, or about 40 wt% to about 55 wt%, or about 40 wt% to about 50 wt%.
  • the 1-ring aromatic content can be about 15 wt% or less, or about 10 wt% or less, or about 5 wt% or less, such as down to about 0.1 wt%.
  • SCT can also have a higher density than many types of crude or refinery fractions.
  • SCT can have a density at 15°C of about 1.08 g/cm 3 to about 1.20 g/cm 3 , or 1.10 g/cm 3 to 1.18 g/cm 3 .
  • many types of vacuum resid fractions can have a density of about 1.05 g/cm 3 or less.
  • density (or weight per volume) of the heavy hydrocarbon can be determined according to ASTM D287 - 92 (2006) Standard Test Method for API Gravity of Crude Petroleum and Petroleum Products (Hydrometer Method), which characterizes density in terms of API gravity. In general, the higher the API gravity, the less dense the oil. API gravity can be 5° or less, or 0° or less, such as down to about -10° or lower.
  • Contaminants such as nitrogen and sulfur are typically found in SCT, often in organically -bound form.
  • Nitrogen content can range from about 50 wppm to about 10,000 wppm elemental nitrogen or more, based on total weight of the SCT.
  • Sulfur content can range from about 0.1 wt% to about 10 wt%, based on total weight of the SCT.
  • Coker bottoms represent another type of cracked feed suitable for hydroprocessing, optionally in combination with a catalytic slurry oil and/or steam cracker tar and/or other cracked fractions.
  • Coking is a thermal cracking process that is suitable for conversion of heavy feeds into fuels boiling range products.
  • the feedstock to a coker typically also includes 5 wt% to 25 wt% recycled product from the coker, which can be referred to as coker bottoms. This recycle fraction allows metals, asphaltenes, micro-carbon residue, and/or other solids to be returned to the coker, as opposed to being incorporated into a coker gas oil product.
  • the coker bottoms can correspond to a fraction with a T10 distillation point of at least 550°F (288°C), or at least 300°C, or at least 316°C, and a T90 distillation point of 566°C or less, or 550°C or less, or 538°C or less.
  • the coker recycle fraction can have an aromatic carbon content of about 20 wt% to about 50 wt%, or about 30 wt% to about 45 wt%, and a micro carbon residue content of about 4.0 wt% to about 15 wt%, or about 6.0 wt% to about 15 wt%, or about 4.0 wt% to about 10 wt%, or about 6.0 wt% to about 12 wt%.
  • At least a portion of a feedstock for processing as described herein can correspond to a vacuum resid fraction or another type 950°F+ (510°C+) or 1000°F+ (538°C+) fraction.
  • Another example of a method for forming a 950°F+ (510°C+) or 1000°F+ (538°C+) fraction is to perform a high temperature flash separation.
  • the 950°F+ (510°C+) or 1000°F+ (538°C+) fraction formed from the high temperature flash can be processed in a manner similar to a vacuum resid.
  • a vacuum resid fraction or a 950°F+ (510°C+) fraction formed by another process can be deasphalted at low severity to form a deasphalted oil.
  • the feedstock can also include a portion of a conventional feed for lubricant base stock production, such as a vacuum gas oil.
  • a vacuum resid (or other 510°C+) fraction can correspond to a fraction with a T5 distillation point (ASTM D2892, or ASTM D7169 if the fraction will not completely elute from a chromatographic system) of at least about 900°F (482°C), or at least 950°F (510°C), or at least 1000°F (538°C).
  • a vacuum resid fraction can be characterized based on a T10 distillation point (ASTM D2892 / D7169) of at least about 900°F (482°C), or at least 950°F (510°C), or at least 1000°F (538°C).
  • Resid (or other 510°C+) fractions can be high in metals.
  • a resid fraction can be high in total nickel, vanadium and iron contents.
  • a resid fraction can contain at least 0.00005 grams of Ni/V/Fe (50 wppm) or at least 0.0002 grams of Ni/V/Fe (200 wppm) per gram of resid, on a total elemental basis of nickel, vanadium and iron.
  • the heavy oil can contain at least 500 wppm of nickel, vanadium, and iron, such as up to 1000 wppm or more.
  • Contaminants such as nitrogen and sulfur are typically found in resid (or other 510°C+) fractions, often in organically-bound form.
  • Nitrogen content can range from about 50 wppm to about 10,000 wppm elemental nitrogen or more, based on total weight of the resid fraction.
  • Sulfur content can range from 500 wppm to 100,000 wppm elemental sulfur or more, based on total weight of the resid fraction, or from 1000 wppm to 50,000 wppm, or from 1000 wppm to 30,000 wppm.
  • Still another method for characterizing a resid (or other 510°C+) fraction is based on the Conradson carbon residue (CCR) of the feedstock.
  • the Conradson carbon residue of a resid fraction can be at least about 5 wt%, such as at least about 10 wt% or at least about 20 wt%. Additionally or alternately, the Conradson carbon residue of a resid fraction can be about 50 wt% or less, such as about 40 wt% or less or about 30 wt% or less.
  • a feedstock including one or more cracked fractions can be hydroprocessed to form a hydroprocessed effluent.
  • This can include hydrotreatment and/or hydrocracking to remove heteroatoms (such as sulfur and/or nitrogen) to desired levels, reduce Conradson Carbon content, and/or provide viscosity index (VI) uplift.
  • the hydroprocessing can be performed to achieve a desired level of conversion of higher boiling compounds in the feed to fuels boiling range compounds.
  • a feedstock can be hydroprocessed by demetallization, aromatics saturation, hydrotreating, hydrocracking, or a combination thereof.
  • the aromatics content of the feedstock can be at least 50 wt%, or at least 55 wt%, or at least 60 wt%, or at least 65 wt%, or at least 70 wt%, or at least 75 wt%, such as up to 90 wt% or more.
  • the saturates content of the feedstock can be 50 wt% or less, or 45 wt% or less, or 40 wt% or less, or 35 wt% or less, or 30 wt% or less, or 25 wt% or less, such as down to 10 wt% or less.
  • the aromatics content and/or the saturates content of a fraction can be determined based on ASTM D7419.
  • the hydroprocessing can be performed in a configuration including a single reaction stage.
  • the reaction conditions during demetallization and/or hydrotreatment and/or hydrocracking of the feedstock can be selected to generate a desired level of conversion of a feed.
  • Any convenient type of reactor such as fixed bed (for example trickle bed) reactors can be used.
  • Conversion of the feed can be defined in terms of conversion of molecules that boil above a temperature threshold to molecules below that threshold.
  • the conversion temperature can be any convenient temperature, such as ⁇ 700°F (371°C) or 1050°F (566°C).
  • the amount of conversion can correspond to the total conversion of molecules within the combined hydrotreatment and hydrocracking stages.
  • Suitable amounts of conversion of molecules boiling above 1050°F (566°C) to molecules boiling below 566°C include 30 wt% to 100 wt% conversion relative to 566°C, or 30 wt% to 90 wt%, or 30 wt% to 70 wt%, or 40 wt% to 90 wt%, or 40 wt% to 80 wt%, or 40 wt% to 70 wt%, or 50 wt% to 100 wt%, or 50 wt% to 90 wt%, or 50 wt% to 70 wt%.
  • the amount of conversion relative to 566°C can be 30 wt% to 100 wt%, or 50 wt% to 100 wt%, or 40 wt% to 90 wt%.
  • suitable amounts of conversion of molecules boiling above ⁇ 700°F (371°C) to molecules boiling below 371°C include 10 wt% to 70 wt% conversion relative to 371°C, or 10 wt% to 60 wt%, or 10 wt% to 50 wt%, or 20 wt% to 70 wt%, or 20 wt% to 60 wt%, or 20 wt% to 50 wt%, or 30 wt% to 70 wt%, or 30 wt% to 60 wt%, or 30 wt% to 50 wt%.
  • the amount of conversion relative to 371°C can be 10 wt% to 70 wt%, or 20 wt% to 50 wt%, or 30 wt% to 90 wt%.
  • the hydroprocessed effluent can also be characterized based on the product quality.
  • the liquid (C3+) portion of the hydroprocessed deasphalted oil / hydroprocessed effluent can have a sulfur content of about 1000 wppm or less, or about 500 wppm or less, or about 100 wppm or less (such as down to ⁇ 0 wppm).
  • the hydroprocessed deasphalted oil / hydroprocessed effluent can have a nitrogen content of 200 wppm or less, or 100 wppm or less, or 50 wppm or less (such as down to ⁇ 0 wppm).
  • the liquid (C3+) portion of the hydroprocessed deasphalted oil / hydroprocessed effluent can have a MCR content and/or Conradson Carbon residue content of 2.5 wt% or less, or 1.5 wt% or less, or 1.0 wt% or less, or 0.7 wt% or less, or 0.1 wt% or less, or 0.02 wt% or less (such as down to ⁇ 0 wt%).
  • MCR content and/or Conradson Carbon residue content can be determined according to ASTM D4530.
  • the portion of the hydroprocessed effluent having a boiling range / distillation point of less than about 700°F ( ⁇ 371°C) can be used as a low sulfur fuel oil or blendstock for low sulfur fuel oil.
  • such a portion of the hydroprocessed effluent can be used (optionally with other distillate streams) to form ultra-low sulfur naphtha and/or distillate (such as diesel) fuel products, such as ultra-low sulfur fuels or blendstocks for ultra-low sulfur fuels.
  • the portion having a boiling range / distillation point of at least about 700°F can be used as an ultra-low sulfur fuel oil having a sulfur content of about 0.1 wt% or less or optionally blended with other distillate or fuel oil streams to form an ultra-low sulfur fuel oil or a low sulfur fuel oil.
  • at least a portion of the liquid hydrotreated effluent having a distillation point of at least about ⁇ 371°C can be used as a feed for FCC processing.
  • the portion having a boiling range / distillation point of at least about 371°C can be used as a feedstock for lubricant base oil production.
  • the feedstock can be exposed to uniquely oriented stacked beds of hydrotreating catalyst under effective hydrotreating conditions in a single reaction stage.
  • the catalysts used can include conventional hydroprocessing catalysts, such as those comprising at least one Group VIII non-noble metal (Columns 8 - 10 of IUPAC periodic table), preferably Fe, Co, and/or Ni, such as Co and/or Ni; and at least one Group VI metal (Column 6 of IUPAC periodic table), preferably Mo and/or W.
  • Such hydroprocessing catalysts optionally include transition metal sulfides that are impregnated or dispersed on a refractory support or carrier such as alumina and/or silica.
  • the support or carrier itself typically has no significant/measurable catalytic activity.
  • Substantially carrier- or support-free catalysts commonly referred to as bulk catalysts, generally have higher volumetric activities than their supported counterparts.
  • the heavy cracked feed is exposed in order to a first bulk or supported mixed metal catalyst comprising Ni and Mo, a second bulk or supported mixed metal catalyst comprising Ni and W, and a third catalyst comprising a zeolite- based hydrocracking catalyst.
  • the catalysts can either be in bulk form or in supported form.
  • other suitable support/carrier materials can include, but are not limited to, zeolites, titania, silica-titania, and titania-alumina.
  • Suitable aluminas are porous aluminas such as gamma or eta having average pore sizes from 50 to 200 A, or 75 to 150 A (as determined by ASTM D4284); a surface area (as measured by the BET method) from 100 to 300 m 2 /g, or 150 to 250 m 2 /g; and a pore volume of from 0.25 to 1.0 cmVg, or 0.35 to 0.8 cmVg.
  • the support or carrier material is an amorphous support, such as a refractory oxide.
  • the support or carrier material can be free or substantially free of the presence of molecular sieve, where substantially free of molecular sieve is defined as having a content of molecular sieve of less than about 0.01 wt%.
  • the at least one Group VIII non-noble metal, in oxide form can typically be present in an amount ranging from about 2 wt% to about 40 wt%, preferably from about 4 wt% to about 15 wt%.
  • the at least one Group VI metal, in oxide form can typically be present in an amount ranging from about 2 wt% to about 70 wt%, preferably for supported catalysts from about 6 wt% to about 40 wt% or from about 10 wt% to about 30 wt%. These weight percents are based on the total weight of the catalyst.
  • Suitable metal catalysts include nickel/molybdenum (1-10% Ni as oxide, 10-40% Mo as oxide), or nickel/tungsten (1-10% Ni as oxide, 10-40% W as oxide) on alumina, silica, silica-alumina, or titania.
  • the hydroprocessing is carried out in the presence of hydrogen.
  • a hydrogen stream is, therefore, fed or injected into a vessel or reaction zone or hydroprocessing zone in which the hydroprocessing catalyst is located.
  • Hydrogen which is contained in a hydrogen "treat gas,” is provided to the reaction zone.
  • Treat gas can be either pure hydrogen or a hydrogen-containing gas, which is a gas stream containing hydrogen in an amount that is sufficient for the intended reaction(s), optionally including one or more other gasses (e.g., nitrogen and light hydrocarbons such as methane).
  • the treat gas stream introduced into a reaction stage will preferably contain at least about 50 vol. % and more preferably at least about 75 vol. % hydrogen.
  • the hydrogen treat gas can be substantially free (less than 1 vol%) of impurities such as H2S and NH3 and/or such impurities can be substantially removed from a treat gas prior to use.
  • Hydrogen can be supplied at a rate of from about 100 SCF/B (standard cubic feet of hydrogen per barrel of feed) (17 Nm /m 3 ) to about 15000 SCF/B (1700 NmVm 3 ).
  • the hydrogen is provided in a range of from about 2000 SCF/B (340 Nm /m 3 ) to about 12000 SCF/B (2040 Nm /m 3 ).
  • Hydrogen can be supplied co-currently with the input feed to the hydrotreatment reactor and/or reaction zone or separately via a separate gas conduit to the hydrotreatment zone.
  • Hydrotreating conditions can include temperatures of 200°C to 450°C, or 315°C to 425°C; pressures of 250 psig (1.8 MPag) to 5000 psig (34.6 MPag) or 300 psig (2.1 MPag) to 3000 psig (20.8 MPag), or about 2.9 MPag to about 13.9 MPag (-400 to -2000 psig); liquid hourly space velocities (LHSV) of 0.1 hr _1 to 10 hr 1 , or 0.1 hr ⁇ to 5.0 hr 1 ; and a hydrogen treat gas rate of from about 430 to about 2600 Nm /m 3 (-2500 to -15000 SCF/bbl), or about 850 to about 1700 Nm /m 3 (-5000 to -10000 SCF/bbl).
  • LHSV liquid hourly space velocities
  • the feedstock can be exposed to a hy drocracking catalyst under effective hydrocracking conditions.
  • Hydrocracking catalysts typically contain sulfided base metals on acidic supports, such as amorphous silica alumina, cracking zeolites such as USY, or acidified alumina. Often these acidic supports are mixed or bound with other metal oxides such as alumina, titania or silica.
  • suitable acidic supports include acidic molecular sieves, such as zeolites or silicoaluminophophates.
  • suitable zeolite is USY, such as a USY zeolite with cell size of 24.30 Angstroms or less.
  • the catalyst can be a low acidity molecular sieve, such as a USY zeolite with a Si to Al ratio of at least about 20, and preferably at least about 40 or 50.
  • ZSM-48 such as ZSM-48 with a S1O2 to AI2O3 ratio of about 110 or less, such as about 90 or less, is another example of a potentially suitable hydrocracking catalyst.
  • Still another option is to use a combination of USY and ZSM- 48.
  • Still other options include using one or more of zeolite Beta, ZSM-5, ZSM-35, or ZSM- 23, either alone or in combination with a USY catalyst.
  • Non-limiting examples of metals for hydrocracking catalysts include metals or combinations of metals that include at least one Group VIII metal, such as nickel, nickel-cobalt-molybdenum, cobalt-molybdenum, nickel-tungsten, nickel-molybdenum, and/or nickel -molybdenum-tungsten. Additionally or alternately, hydrocracking catalysts with noble metals can also be used. Non-limiting examples of noble metal catalysts include those based on platinum and/or palladium.
  • Support materials which may be used for both the noble and non-noble metal catalysts can comprise a refractory oxide material such as alumina, silica, alumina-silica, kieselguhr, diatomaceous earth, magnesia, zirconia, or combinations thereof, with alumina, silica, alumina-silica being the most common (and preferred, in one embodiment).
  • a refractory oxide material such as alumina, silica, alumina-silica, kieselguhr, diatomaceous earth, magnesia, zirconia, or combinations thereof, with alumina, silica, alumina-silica being the most common (and preferred, in one embodiment).
  • the amount of that hydrogenation metal can be at least about 0.1 wt% based on the total weight of the catalyst, for example at least about 0.5 wt% or at least about 0.6 wt%. Additionally or alternately when only one hydrogenation metal is present, the amount of that hydrogenation metal can be about 5.0 wt% or less based on the total weight of the catalyst, for example about 3.5 wt% or less, about 2.5 wt% or less, about 1.5 wt% or less, about 1.0 wt% or less, about 0.9 wt% or less, about 0.75 wt% or less, or about 0.6 wt% or less.
  • the collective amount of hydrogenation metals can be at least about 0.1 wt% based on the total weight of the catalyst, for example at least about 0.25 wt%, at least about 0.5 wt%, at least about 0.6 wt%, at least about 0.75 wt%, or at least about 1 wt%.
  • the collective amount of hydrogenation metals can be about 35 wt% or less based on the total weight of the catalyst, for example about 30 wt% or less, about 25 wt% or less, about 20 wt% or less, about 15 wt% or less, about 10 wt% or less, or about 5 wt% or less.
  • the amount of noble metal(s) is typically less than about 2 wt %, for example less than about 1 wt%, about 0.9 wt % or less, about 0.75 wt % or less, or about 0.6 wt % or less. It is noted that hydrocracking under sour conditions is typically performed using a base metal (or metals) as the hydrogenation metal.
  • a hydrocracking process under sour conditions can be carried out at temperatures of about 550°F (288°C) to about 840°F (449°C), hydrogen partial pressures of from about 1500 psig to about 5000 psig (10.3 MPag to 34.6 MPag), liquid hourly space velocities of from 0.05 h "1 to 10 h "1 , and hydrogen treat gas rates of from 35.6 m /m 3 to 2670 m /m 3 (200 SCF/B to 15,000 SCF/B).
  • the conditions can include temperatures in the range of about 600°F (343°C) to about 815°F (435°C), hydrogen partial pressures of from about 1500 psig to about 3000 psig (10.3 MPag-20.9 MPag), and hydrogen treat gas rates of from about 213 m /m 3 to about 1780 m /m 3 (1200 SCF/B to 10,000 SCF/B).
  • the LHSV can be from about 0.25 h "1 to about 50 h "1 , or from about 0.5 h "1 to about 20 h "1 , preferably from about 0.25 h "1 to about 4.0 h "1 .
  • the heavy cracked feed can be a deasphalted heavy cracked feed.
  • Deasphalting of heavy hydrocarbons such as vacuum resids, is known in the art and practiced commercially.
  • a deasphalting process typically corresponds to contacting a heavy hydrocarbon with an alkane solvent (propane, butane, pentane, hexane, heptane etc. and their isomers), either in pure form or as mixtures, to produce two types of product streams.
  • One type of product stream can be a deasphalted oil extracted by the alkane, which is further separated to produce deasphalted oil stream.
  • a second type of product stream can be a residual portion of the feed not soluble in the solvent, often referred to as rock or asphaltene fraction.
  • the deasphalted oil fraction can be further processed into make fuels or lubricants.
  • the rock fraction can be further used as blend component to produce asphalt, fuel oil, and/or other products.
  • the rock fraction can also be used as feed to gasification processes such as partial oxidation, fluid bed combustion or coking processes.
  • the rock can be delivered to these processes as a liquid (with or without additional components) or solid (either as pellets or lumps).
  • the input feed to the solvent deasphalting unit can be mixed with a solvent. Portions of the feed that are soluble in the solvent are then extracted, leaving behind a residue with little or no solubility in the solvent.
  • the portion of the deasphalted feedstock that is extracted with the solvent is often referred to as deasphalted oil.
  • Typical solvent deasphalting conditions include mixing a feedstock fraction with a solvent in a weight ratio of from about 1 : 2 to about 1 : 10, such as about 1 : 8 or less.
  • Typical solvent deasphalting temperatures range from 40°C to 200°C, or 40°C to 150°C, depending on the nature of the feed and the solvent.
  • the pressure during solvent deasphalting can be from about 50 psig (-345 kPag) to about 1000 psig (-6900 kPag).
  • the reactor comprises a first bulk or supported mixed metal catalyst comprising Ni and Mo, a second bulk or supported mixed metal catalyst comprising Ni and W, and a third catalyst comprising a zeolite-based hydrocracking catalyst.
  • the third catalyst may comprise a hydrocracking catalyst (Figure 1), a mixture of hydrocracking catalyst and arosat catalyst ( Figure 4), and/or a noble metal containing catalyst ( Figure 6).
  • a raw fluid catalytic cracking (FCC) main column bottoms (MCB) was obtained for catalytic testing of combined hydrotreating/hydrocracking catalysts systems.
  • the raw MCB feedstock had the following properties
  • the raw MCB stream from Table 1 was used as a feedstock for a pilot scale processing plant.
  • the MCB was exposed to four different catalyst beds, which are shown in Figure 1.
  • the first, second, and third beds include a stacked bed configurations including an initial layer bulk metal hydrotreating catalyst comprising Ni and Mo followed by a second layer of hydrotreating catalyst comprising Ni and W, which in turn is followed by a third and final layer of zeolite-based hydrocracking catalyst.
  • the only variance between these stacked beds occurs in the third and final layer.
  • the first bed contains a 1 wt% Pt hydrocracking catalyst exhibiting a FAU framework on a silica-alumina support with a silica to alumina ratio of about 20.
  • the second bed contains a commercially available hydrocracking catalyst comprising Ni and W exhibiting a FAU framework.
  • the third bed contains a 0.6 wt% Pt hydrocracking catalyst exhibiting a FAU framework on a silica-alumina support with a silica to alumina ratio of about 200.
  • the fourth bed is a control containing only a single layer of bulk metal hydrotreating catalyst comprising Ni and Mo.
  • the conditions for the run included a constant pressure of about 2175 psig (15 MPa) and about 10,000 SCF/B of hydrogen treat gas. Temperature and liquid hourly space velocity (LHSV) were varied between 680°F-700°F (360°C-371°C) and O.lS ⁇ -O.Sh: 1 , respectively. The results are shown in Figures 2A-F.
  • the feed was processed in the pilot plant for about 47 days with an initial temperature of 680°F (360°C) and LHSV of 0.25b- 1 . At about Day 37, temperature was increased to 700°F (371°C). At about Day 43, LHSV was increased to 0.5h _1 .
  • the stacked configuration generally results in comparable or better conversion of 700°F+ molecules and lower density than using bulk metal hydrotreating catalyst comprising Ni and Mo alone. Remaining data related to naphtha yield, distillate yield, sulfur content, and nitrogen content are generally comparable and within acceptable ranges.
  • a deasphalted fluid catalytic cracking (FCC) main column bottoms (MCB) was obtained for catalytic testing of combined hydrotreating/hydrocracking catalysts systems.
  • the deasphalted MCB feedstock had the following properties
  • the MCB was exposed to the same four catalyst beds as Example 1, which are shown in Figure 1.
  • the conditions for the run included a constant pressure of about 2175 psig (15 MPa) and about 10,000 SCF/B of hydrogen treat gas.
  • Temperature and liquid hourly space velocity (LHSV) were varied between 680°F-700°F (360°C-371°C) and O.lS ⁇ -O.Shr 1 , respectively.
  • the results are shown in Figures 3A-F.
  • the feed was processed in the pilot plant for about 25 days with an initial temperature of 700°F (371 °C) and LHSV of 0.5 ⁇ "1 . At about Day 13, LHSV was decreased to 0.25 ⁇ "1 . At about Day 18, temperature was decreased to 680°F (360°C).
  • the advantages of the stacked bed configurations are particularly telling in the context of the deasphalted MCB.
  • the stacked configuration results in better conversion of 700°F+ molecules and lower density than using bulk metal hydrotreating catalyst comprising Ni and Mo alone in all cases.
  • Remaining data related to naphtha yield, distillate yield, sulfur content, and nitrogen content are generally comparable and within acceptable ranges.
  • Examples 1 and 2 prove the discovery that a combination of bulk-metal hydrotreating catalyst followed by zeolitic, metal-containing, hydrocracking catalyst can achieve high yields of ULSD blendstock and reduce 700°F+ range material. This is non-intuitive for a single reaction stage because conventional wisdom would dictate that the use of such zeolitic, metal-containing, hydrocracking catalysts would be ineffective due to rapid poisoning of the catalyst.
  • a deasphalted FCC MCB was obtained for catalytic testing, comparing several combination of NiMo and NiW bulk-metal hydrotreating catalysts followed by mixtures of hydrocracking and aromatic saturation ("arosat") catalysts.
  • the deasphalted MCB feedstock had the same properties as the deasphalted MCB feedstock in Table 2 above.
  • the deasphalted MCB from Table 2 was used as a feedstock for a pilot scale processing plant.
  • the deasphalted MCB was exposed to four different catalyst beds, which are shown in Figure 4. From left to right, the first, second, and third beds include a stacked bed configurations including an initial layer bulk metal hydrotreating catalyst comprising Ni and Mo followed by a second layer of hydrotreating catalyst comprising Ni and W, which in turn is followed by a third and final layer of mixed zeolite-based hydrocracking catalyst and noble metal arosat catalyst.
  • the final layer of Bed 1 contains an equal mixture (by weight) of approximately 1.0wt% Pt impregnated on a FAU-type zeolite with an S1O2/AI2O3 ratio of -20 in an extrudate with commercially available alumina, and an arosat catalyst containing both Pd and Pt (0.77wt% and 0.25wt%, respectively) on a mesoporous aluminosilicate support with an S1O2/AI2O3 ratio of -50.
  • the final layer of Bed 2 contains an equal mixture (by weight) of approximately 1.0wt% Pt impregnated on a FAU-type zeolite with an S1O2/AI2O3 ratio of -60 in an extrudate with commercially available alumina, and an arosat catalyst containing both Pd and Pt (0.77wt% and 0.25wt%, respectively) on a mesoporous aluminosilicate support with an S1O2/AI2O3 ratio of -50.
  • the final layer of Bed 3 contains an equal mixture (by weight) of approximately 1.0wt% Pt impregnated on a FAU-type zeolite with an S1O2/AI2O3 ratio of -20 in an extrudate with commercially available alumina, and an arosat catalyst containing 2.0wt%Pt on a 40A-pore mesoporous aluminosilicate support.
  • the conditions for the run included a constant pressure of about 2175 psig (15 MPa) and about 10,000 SCF/B of hydrogen treat gas. Temperature and liquid hourly space velocity (LHSV) were varied between 680°F-700°F (360°C-371°C) and O.lS ⁇ -O.Sh: 1 , respectively. The results are shown in Figures 5A-F.
  • the feed was processed in the pilot plant for about 25 days with an initial temperature of 700°F (371°C) and LHSV of 0.5 ⁇ "1 . At about Day 13, LHSV was decreased to 0.25 ⁇ "1 . At about Day 18, temperature was decreased to 680°F (360°C).
  • the advantages of the stacked bed configurations are particularly telling in the context of the deasphalted MCB.
  • the stacked configuration results in better conversion of 700°F+ molecules and lower density than using bulk metal hydrotreating catalyst comprising Ni and Mo alone in all cases.
  • Remaining data related to naphtha yield, distillate yield, sulfur content, and nitrogen content are generally comparable or better and within acceptable ranges.
  • Example 3 proves the discovery that a combination of bulk-metal hydrotreating catalyst followed by a hydrocracking/arosat mixed catalyst can achieve high yields of ULSD blendstock and reduce 700°F+ range material. This is non- intuitive for a single reaction stage because conventional wisdom would dictate that the use of such a catalyst mixture would be ineffective due to rapid poisoning of the catalyst.
  • Example 4 Noble Metal Catalysts and Mixed Catalysts for Heavy Cracked Feeds
  • a raw FCC MCB was obtained for catalytic testing of combined noble metal catalysts systems.
  • the raw MCB feedstock had the same properties as the raw MCB feedstock in Table 1 above.
  • the raw MCB from Table 1 was used as a feedstock for a pilot scale processing plant.
  • the MCB was exposed to seven different catalyst beds, which are shown in Figure 6.
  • the stacked beds, beds 1-6 include an initial layer bulk metal hydrotreating catalyst comprising Ni and Mo followed by a second layer of hydrotreating catalyst comprising Ni and W, which in turn is followed by a third and final layer containing one of six different noble- metal hydrocracking, arosat, or combined hydrocracking/arosat catalysts.
  • the final layer of Bed 1 is mesoporous aluminosilicate with an S1O2/AI2O3 ratio of -50 containing a mixture of Pd and Pt (0.77wt% and 0.25 wt%, respectively).
  • the final layer of Bed 2 is zeolite-based (FAU), with an S1O2/AI2O3 ratio of -200 and a Pt content of 0.6wt% bound in an extrudate with commercially available alumina.
  • the final layer of Bed 3 is FAU- based, having an S1O2/AI2O3 ratio of -20 and Pt content of 1.0wt% bound in an extrudate with commercially available alumina.
  • the final layer of Bed 4 contains an equal mixture (by weight) of approximately 1.0wt% Pt impregnated on a FAU-type zeolite with an S1O2/AI2O3 ratio of -20 in an extrudate with commercially available alumina, and an arosat catalyst containing both Pd and Pt (0.77wt% and 0.25wt%, respectively) on a mesoporous aluminosilicate support with an S1O2/AI2O3 ratio of -50.
  • the final layer of Bed 5 contains an equal mixture (by weight) of approximately 1.0wt% Pt impregnated on a FAU-type zeolite with an S1O2/AI2O3 ratio of -60 in an extrudate with commercially available alumina, and an arosat catalyst containing both Pd and Pt (0.77wt% and 0.25wt%, respectively) on a mesoporous aluminosilicate support with an SiC /AkCb ratio of -50.
  • the final layer of Bed 6 contains an equal mixture (by weight) of approximately 1.0wt% Pt impregnated on a FAU- type zeolite with an S1O2/AI2O3 ratio of -20 in an extrudate with commercially available alumina, and an arosat catalyst containing 2.0wt% Pt on a 40A-pore mesoporous aluminosilicate support.
  • Bed 7 is a bulk-metal NiMo hydrotreating catalyst used for comparison to these stacked beds.
  • the conditions for the run included a constant pressure of about 2175 psig (15 MPa) and about 10,000 SCF/B of hydrogen treat gas. Temperature and liquid hourly space velocity (LHSV) were varied between 680°F-700°F (360°C-371°C) and O.lS ⁇ -O.Sh: 1 , respectively. The results are shown in Figures 7A-F.
  • the feed was processed in the pilot plant for about 47 days with an initial temperature of 680°F (360°C) and LHSV of 0.25b- 1 . At about Day 37, temperature was increased to 700°F (371°C). At about Day 43, LHSV was increased to 0.5h _1 .
  • the stacked configuration generally results in comparable or better conversion of 700°F+ molecules and lower density than using bulk metal hydrotreating catalyst comprising Ni and Mo alone. Remaining data related to naphtha yield, distillate yield, sulfur content, and nitrogen content are generally comparable and within acceptable ranges.
  • Example 5 Noble Metal Catalysts and Mixed Catalysts for Deasphalted Heavy Cracked Feeds
  • a deasphalted FCC MCB was obtained for catalytic testing, comparing several combination of NiMo and NiW bulk-metal hydrotreating catalysts followed by one of six different noble-metal hydrocracking, arosat, or combined hydrocracking/arosat catalysts.
  • the deasphalted MCB feedstock had the same properties as the deasphalted MCB feedstock in Table 2 above.
  • the deasphalted MCB was used as a feedstock for a pilot scale processing plant.
  • the deasphalted MCB was exposed to the same seven catalyst beds as Example 4, which are shown in Figure 6.
  • the conditions for the run included a constant pressure of about 2175 psig (15 MPa) and about 10,000 SCF/B of hydrogen treat gas.
  • Temperature and liquid hourly space velocity (LHSV) were varied between 680°F-700°F (360°C-371°C) and O.lS ⁇ -O.Shr 1 , respectively.
  • the results are shown in Figures 8A-F.
  • the feed was processed in the pilot plant for about 25 days with an initial temperature of 700°F (371 °C) and LHSV of 0.5 ⁇ "1 .
  • Example 3 proves the discovery that a combination of bulk-metal hydrotreating catalyst followed by a mixture of noble metal micro- and/or mesoporous hydrocracking and arosat catalysts can achieve high yields of ULSD blendstock and reduce 700°F+ range material. This is non-intuitive for a single reaction stage because conventional wisdom would dictate that the use of such a catalyst mixture would be ineffective due to rapid poisoning of the catalyst.
  • Embodiment 1 A process for upgrading a heavy cracked feedstock, comprising: providing a feedstock comprising a density at 15°C of 1.06 g/cm 3 or more, at least 50 wt% of one or more 343°C+ cracked fractions, and a sulfur content of 0.8 to 5.0wt% sulfur; in a single reaction stage under fixed bed hydroprocessing conditions, exposing the feedstock to a first bulk or supported mixed metal catalyst comprising Ni and Mo; exposing the feedstock to a second bulk or supported mixed metal catalyst comprising Ni and W; and exposing the feedstock to a third catalyst comprising a zeolite-based hydrocracking catalyst.
  • Embodiment 2 The process of embodiment 1, wherein the zeolite-based hydrocracking catalyst comprises a Group VIII noble metal.
  • Embodiment 3 The process of embodiment 2, wherein the zeolite-based hydrocracking catalyst comprises 0.5 to 2.5 wt% Pt.
  • Embodiment 4 The process of any of the previous embodiments, wherein the third catalyst further comprises an aromatic saturation catalyst comprising Pd, Pt, or a combination thereof on an aluminosilicate support.
  • Embodiment 5 The process of embodiment 4, wherein the aromatic saturation catalyst comprises Pd and Pt in a wt% ratio of about 3 : 1 Pd to Pt.
  • Embodiment 6 The process of embodiment 4 or 5, wherein the aromatic saturation catalyst comprises 2.0 wt% Pt.
  • Embodiment 7 The process of any of the previous embodiments, wherein the zeolite exhibits a faujasite (FAU) framework type.
  • FAU faujasite
  • Embodiment 8 The process of any of the previous embodiments, wherein the feedstock comprises a density at 15°C of 1.1 g/cm 3 or more, a Tio of at least 343°C and a T90 of at least 475°C; and a sulfur content of 3.0 wt% to 5.0wt%.
  • Embodiment 9 The process of any of the previous embodiments, wherein the feedstock comprises a de-asphalted heavy cracked feedstock.
  • Embodiment 10 The process of any of the previous embodiments, wherein the fixed bed hydroprocessing conditions include a temperature of 300°C to 400°C, a pressure of 1500 psig to 3000 psig, a hydrogen treat gas rate of 2,000 scf/bbl to 12,000 scf/bbl, and a LHSV of O.211- 1 to 1.5 h "1 .
  • Embodiment 1 A system for processing a cracked feedstock comprising: a hydroprocessing reactor comprising a hydroprocessing inlet, and a hydroprocessing outlet, and a fixed bed comprising a first bulk or supported mixed metal catalyst comprising Ni and Mo; a second bulk or supported mixed metal catalyst comprising Ni and W; and a third catalyst comprising a zeolite-based hydrocracking catalyst; wherein the hydroprocessing inlet is designed to receive a feedstock comprising a density at 15 °C of 1.06 g/cm 3 or more, at least 50 wt% of one or more 343°C+ cracked fractions, and a sulfur content of 1.0 to 5.0wt% sulfur; and wherein the fixed bed is oriented such that the feedstock contacts the first catalyst, second catalyst, and third catalyst sequentially.

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Abstract

L'invention concerne des systèmes et des procédés permettant de valoriser une charge d'alimentation craquée lourde dans un étage de réaction unique dans des conditions d'hydrotraitement en lit fixe, lesdits systèmes et procédés comprenant l'exposition de la charge d'alimentation à un premier catalyseur métallique mixte en vrac ou supporté comprenant du Ni et du Mo; l'exposition de la charge d'alimentation à un deuxième catalyseur métallique mixte en vrac ou supporté comprenant du Ni et du W; et l'exposition de la charge d'alimentation à un troisième catalyseur comprenant un catalyseur d'hydrocraquage à base de zéolite.
EP18778608.2A 2017-09-08 2018-08-29 Hydrotraitement de fractions craquées de densité élevée Withdrawn EP3679113A1 (fr)

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US20180230389A1 (en) 2017-02-12 2018-08-16 Magēmā Technology, LLC Multi-Stage Process and Device for Reducing Environmental Contaminates in Heavy Marine Fuel Oil
US12025435B2 (en) 2017-02-12 2024-07-02 Magēmã Technology LLC Multi-stage device and process for production of a low sulfur heavy marine fuel oil
US10604709B2 (en) 2017-02-12 2020-03-31 Magēmā Technology LLC Multi-stage device and process for production of a low sulfur heavy marine fuel oil from distressed heavy fuel oil materials
US12071592B2 (en) 2017-02-12 2024-08-27 Magēmā Technology LLC Multi-stage process and device utilizing structured catalyst beds and reactive distillation for the production of a low sulfur heavy marine fuel oil
US11788017B2 (en) 2017-02-12 2023-10-17 Magëmã Technology LLC Multi-stage process and device for reducing environmental contaminants in heavy marine fuel oil
US11826738B2 (en) * 2020-07-27 2023-11-28 Uop Llc High activity and high distillate yield hydrocracking catalysts with intimate interaction between unsupported metal oxide and zeolite
US11578276B2 (en) 2021-07-01 2023-02-14 Saudi Arabian Oil Company Two stage catalytic process for pyrolysis oil upgrading to BTX
US11377400B1 (en) 2021-07-01 2022-07-05 Saudi Arabian Oil Company Three stage catalytic process for pyrolysis oil upgrading to xylenes

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