EP2751234A2 - Valorisation de produits de pyrolyse d'hydrocarbures par hydrotraitement - Google Patents

Valorisation de produits de pyrolyse d'hydrocarbures par hydrotraitement

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Publication number
EP2751234A2
EP2751234A2 EP12762465.8A EP12762465A EP2751234A2 EP 2751234 A2 EP2751234 A2 EP 2751234A2 EP 12762465 A EP12762465 A EP 12762465A EP 2751234 A2 EP2751234 A2 EP 2751234A2
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EP
European Patent Office
Prior art keywords
weight
mixture
utility fluid
liquid phase
range
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.)
Granted
Application number
EP12762465.8A
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German (de)
English (en)
Other versions
EP2751234B1 (fr
Inventor
Stephen H. Brown
Stephen M. Davis
John S. Buchanan
David T. Ferrughelli
Keith G. REED
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ExxonMobil Chemical Patents Inc
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ExxonMobil Chemical Patents Inc
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Publication of EP2751234A2 publication Critical patent/EP2751234A2/fr
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Publication of EP2751234B1 publication Critical patent/EP2751234B1/fr
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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
    • C10G49/00—Treatment of hydrocarbon oils, in the presence of hydrogen or hydrogen-generating compounds, not provided for in a single one of groups C10G45/02, C10G45/32, C10G45/44, C10G45/58 or C10G47/00
    • C10G49/18—Treatment of hydrocarbon oils, in the presence of hydrogen or hydrogen-generating compounds, not provided for in a single one of groups C10G45/02, C10G45/32, C10G45/44, C10G45/58 or C10G47/00 in the presence of hydrogen-generating compounds, e.g. ammonia, water, hydrogen sulfide
    • 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
    • C10G69/00—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one other conversion process
    • C10G69/02—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one other conversion process plural serial stages only
    • C10G69/06—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one other conversion process plural serial stages only including at least one step of thermal cracking in the absence of hydrogen

Definitions

  • the invention relates to upgraded pyrolysis products, processes for upgrading products obtained from hydrocarbon pyrolysis, equipment useful for such processes, and the use of upgraded pyrolysis products.
  • Pyrolysis processes such as steam cracking can be utilized for converting saturated hydrocarbon to higher- value products such as light olefin, e.g., ethylene and propylene. Besides these useful products, hydrocarbon pyrolysis can also produce a significant amount of relatively low- value products such as steam-cracker tar ("SCT").
  • SCT steam-cracker tar
  • SCT upgrading processes involving conventional catalytic hydroprocessing suffer from significant catalyst deactivation.
  • the process can be operated at a temperature in the range of from 250°C to 380°C, at a pressure in the range of 5400 kPa to 20,500 kPa, using catalysts containing one or more of Co, Ni, or Mo; but significant catalyst coking is observed.
  • catalyst coking can be lessened by operating the process at an elevated hydrogen partial pressure, diminished space velocity, and a temperature in the range of 200°C to 350°C; SCT hydroprocessing under these conditions is undesirable because increasing hydrogen partial pressure worsens process economics, as a result of increased hydrogen and equipment costs, and because the elevated hydrogen partial pressure, diminished space velocity, and reduced temperature range favor undesired hydrogenation reactions.
  • the invention relates to a hydrocarbon conversion process, comprising:
  • the utility fluid comprises the separated liquid phase in an amount > 90.0 wt. % based on the weight of the utility fluid.
  • the invention relates to a hydrocarbon conversion process, comprising:
  • the utility fluid comprises the separated light liquid in an amount > 90.0 wt.
  • a continuous hydrocarbon conversion process comprising:
  • the invention relates to a hydroprocessed tar having improved blending characteristics over the tar feed, e.g., the hydrotreated tar can be blended with other heavy hydrocarbon-containing streams with less asphaltene precipitation than is the case with the non-hydroprocessed tar.
  • the hydroprocessed tar is thus beneficial for use as a blendstock, e.g., for upgrading a wide range of relatively low- value heavy hydrocarbons.
  • Figure 1 schematically illustrates an embodiment of the invention where a separation stage is utilized downstream of a hydroprocessing stage to separate and recycle a portion of the reactor effluent's total liquid product for use as the utility fluid.
  • the invention is based in part on the discovery that catalyst coking can be lessened by hydroprocessing the SCT in the presence of a utility fluid comprising a significant amount of single or multi-ring aromatics. Unlike conventional SCT hydroprocessing, the process can be operated at temperatures and pressures that favor the desired hydrocracking reaction over aromatics hydrogenation. It has been discovered that a portion of the hydroprocessor's liquid-phase effluent can be recycled and utilized as the utility fluid.
  • SCT means (a) a mixture of hydrocarbons having one or more aromatic cores and optionally (b) non-aromatic and/or non-hydrocarbon molecules, the mixture being derived from hydrocarbon pyrolysis and having a boiling range > about 550°F (290°C) e.g., > 90.0 wt. % of the SCT molecules have an atmospheric boiling point > 550°F (290°C).
  • SCT can comprise, e.g., > 50.0 wt. %, e.g., > 75.0 wt. %, such as > 90.0 wt. %, based on the weight of the SCT, of hydrocarbon molecules (including mixtures and aggregates thereof) having (i) one or more aromatic cores and (ii) a molecular weight > about Cis.
  • SCT comprises a significant amount of Tar Heavies
  • TH Tar Heavies
  • the term "Tar Heavies” means a product of hydrocarbon pyrolysis, the TH having an atmospheric boiling point > 565°C and comprising > 5.0 wt. % of molecules having a plurality of aromatic cores based on the weight of the product.
  • the TH are typically solid at 25.0°C and generally include the fraction of SCT that is not soluble in a 5 : 1 (vol. :vol.) ratio of n-pentane: SCT at 25.0°C ("conventional pentane extraction").
  • the TH can include high-molecular weight molecules (e.g., MW > 600) such as asphaltenes and other high-molecular weight hydrocarbons.
  • high-molecular weight molecules e.g., MW > 600
  • asphaltenes and other high-molecular weight hydrocarbons e.g., MW > 600
  • asphaltenes or asphaltenes is defined as heptane insolubles, and is measured following ASTM D3279.
  • the TH can comprise > 10.0 wt. % of high molecular-weight molecules having aromatic cores that are linked together by one or more of (i) relatively low molecular-weight alkanes and/or alkenes, e.g., Ci to C3 alkanes and/or alkenes, (ii) C5 and/or Ce cycloparaffinic rings, or (iii) thiophenic rings.
  • > 60.0 wt. % of the TH's carbon atoms are included in one or more aromatic cores based on the weight of the TH's carbon atoms, e.g., in the range of 68.0 wt. % to 78.0 wt. %. While not wishing to be bound by any theory or model, it is also believed that the TH form aggregates having a relatively planar morphology, as a result of Van der Waals attraction between the TH molecules.
  • the large size of the TH aggregates which can be in the range of, e.g., ten nanometers to several hundred nanometers ("nm") in their largest dimension, leads to low aggregate mobility and diffusivity under catalytic hydroprocessing conditions.
  • SCT conversion can be run at lower pressures, e.g., 500 psig to 1500 psig, (34.5 to 103.4 bar gauge), leading to a significant reduction in cost and complexity over higher- pressure hydroprocessing.
  • the invention is also advantageous in that the SCT is not over- cracked so that the amount of light hydrocarbons produced in certain embodiments, e.g., C 4 or lighter, is less than approximately 5 wt. %, which results in a unique composition of multi ring compounds, and further reduces the amount of hydrogen consumed in the hydroprocessing step.
  • the invention relates to a hydroprocessed tar such as a hydroprocessed steam-cracked tar having an improved viscosity and blending characteristics.
  • hydroprocessed tar can be produced by catalytically hydroprocessing a tar feed in the presence of a utility fluid under catalytic hydroprocessing conditions including a temperature in the range of 375°C to 425°C, such as 385°C to 415°C; a pressure in the range of 45 bar (absolute) to 135 bar (absolute), such as 60 bar (absolute) to 90 bar (absolute); a molecular hydrogen treat rate (based on tar feed) in the range of 150 S m 3 /m 3 to 1200 S m 3 /m 3 (840 SCF/B to 6700 SCF/B), such as in the range of 180 S m 3 /m 3 to 450 S m 3 /m 3 (1000 SCF/B to 2500 SCF/B);
  • the utility fluid can be recycled from the hydroprocessor effluent (optionally following separation of the hydroprocessed tar fraction), or obtained from an external source.
  • the catalyst can be, e.g., a conventional sulfided alumina-supported cobalt-molybdenum catalyst. It has been observed that producing the hydroprocessed tar under these conditions results in less production of undesirable by products having a molecular weight less than or equal to that of C 4 (C 4 _ byproducts).
  • SCT starting material differs from other relatively high-molecular weight hydrocarbon mixtures, such as crude oil residue ("resid") including both atmospheric and vacuum resids and other streams commonly encountered, e.g., in petroleum and petrochemical processing.
  • the SCT's aromatic carbon content as measured by C 13 NMR is substantially greater than that of resid.
  • the amount of aromatic carbon in SCT typically is greater than 70 wt. % while the amount of aromatic carbon in resid is generally less than 40 wt. %.
  • a significant fraction of SCT asphaltenes have an atmospheric boiling point that is less than 565°C, for example, only 32.5 wt. % of asphaltenes in SCT 1 have an atmospheric boiling point that is greater than 565°C. That is not the case with vacuum resid wherein substantially 100 wt. % of the asphaltenes have an atmospheric boiling point > 565°C.
  • the total amount of metals is ⁇ 1000.0 ppmw (parts per million, weight) based on the weight of the SCT, e.g., ⁇ 100.0 ppmw, such as ⁇ 10.0 ppmw.
  • the total amount of nitrogen present in SCT is generally less than the amount of nitrogen present in a crude oil vacuum resid.
  • Methyls (wt. %) 1 1 7.5 9.77 13.35 11.73
  • Aromatic H (wt. %) 38.1 43.5 N.M. N.M. 6.81
  • Olefins (wt. %) 1.1 1.4 N.M. N.M. 0
  • the amount of aliphatic carbon and the amount of carbon subsisting in long chains is substantially lower in SCT compared to resid.
  • the SCT's total carbon is only slightly higher and the oxygen content (wt. basis) is similar to that of resid, the SCT's metals, hydrogen, and nitrogen (wt. basis) range is considerably lower.
  • the SCT's kinematic viscosity at 50°C is generally > 100 cSt, or > 1000 cSt even though the relative amount of SCT having an atmospheric boiling point > 565°C is much less than is the case for resid.
  • SCT is generally obtained as a product of hydrocarbon pyrolysis.
  • the pyrolysis process can include, e.g., thermal pyrolysis, such as thermal pyrolysis processes utilizing water.
  • thermal pyrolysis such as thermal pyrolysis processes utilizing water.
  • steam cracking is described in more detail below. The invention is not limited to steam cracking, and this description is not meant to foreclose the use of other pyrolysis processes within the broader scope of the invention.
  • Conventional steam cracking utilizes a pyrolysis furnace which has two main sections: a convection section and a radiant section.
  • the feedstock typically enters the convection section of the furnace where the first mixture's hydrocarbon component is heated and vaporized by indirect contact with hot flue gas from the radiant section and by direct contact with the first mixture's steam component.
  • the steam-vaporized hydrocarbon mixture is then introduced into the radiant section where the bulk of the cracking takes place.
  • a second mixture is conducted away from the pyrolysis furnace, the second mixture comprising products resulting from the pyrolysis of the first mixture and any unreacted components of the first mixture.
  • At least one separation stage is generally located downstream of the pyrolysis furnace, the separation stage being utilized for separating from the second mixture one or more of light olefin, SCN, SCGO, SCT, water, unreacted hydrocarbon components of the first mixture, etc.
  • the separation stage can comprise, e.g., a primary fractionator.
  • a cooling stage typically either direct quench or indirect heat exchange is located between the pyrolysis furnace and the separation stage.
  • SCT is obtained as a product of pyrolysis conducted in one or more pyrolysis furnaces, e.g., one or more steam cracking furnaces.
  • pyrolysis furnaces e.g., one or more steam cracking furnaces.
  • vapor-phase products such as one or more of acetylene, ethylene, propylene, butenes
  • liquid-phase products comprising, e.g., one or more of C5+ molecules and mixtures thereof.
  • the liquid-phase products are generally conducted together to a separation stage, e.g., a primary fractionator, for separations of one or more of (a) overheads comprising steam-cracked naphtha ("SCN", e.g., C5 - C10 species) and steam cracked gas oil (“SCGO"), the SCGO comprising > 90.0 wt. % based on the weight of the SCGO of molecules (e.g., C 10 - C 17 species) having an atmospheric boiling point in the range of about 400°F to 550°F (200°C to 290°C), and (b) bottoms (e.g., a tar stream) comprising > 90.0 wt. % SCT, based on the weight of the bottoms, the SCT having a boiling range > about 550°F (290°C) and comprising molecules and mixtures thereof having a molecular weight > about C15.
  • SCN steam-cracked naphtha
  • SCGO steam cracked gas oil
  • the feed to the pyrolysis furnace is a first mixture, the first mixture comprising > 10.0 wt. % hydrocarbon based on the weight of the first mixture, e.g., > 25.0 wt. %, > 50.0 wt. %, such as > 0.65 wt. %.
  • the hydrocarbon can comprise, e.g., one or more of light hydrocarbons such as methane, ethane, propane, butane etc., it can be particularly advantageous to utilize the invention in connection with a first mixture comprising a significant amount of higher molecular weight hydrocarbons because the pyrolysis of these molecules generally results in more SCT than does the pyrolysis of lower molecular weight hydrocarbons.
  • the total of the first mixtures fed to a multiplicity of pyrolysis furnaces can comprise > 1.0 wt. % or > 25.0 wt. % based on the weight of the first mixture of hydrocarbons that are in the liquid phase at ambient temperature and atmospheric pressure.
  • the first mixture can further comprise diluent, e.g., one or more of nitrogen, water, etc., e.g., > 1.0 wt. % diluent based on the weight of the first mixture, such as > 25.0 wt. %.
  • diluent e.g., one or more of nitrogen, water, etc.
  • the first mixture can be produced by combining the hydrocarbon with a diluent comprising steam, e.g., at a ratio of 0.1 to 1.0 kg steam per kg hydrocarbon, or a ratio of 0.2 to 0.6 kg steam per kg hydrocarbon.
  • the first mixture's hydrocarbon comprises > 10.0 wt. %, e.g., > 50.0 wt. %, such as > 90.0 wt. % (based on the weight of the hydrocarbon) of one or more of naphtha, gas oil, vacuum gas oil, waxy residues, atmospheric residues, residue admixtures, or crude oil; including those comprising > about 0.1 wt. % asphaltenes.
  • Suitable crude oils include, e.g., high-sulfur virgin crude oils, such as those rich in polycyclic aromatics.
  • the first mixture's hydrocarbon comprises sulfur, e.g., > 0.1 wt.
  • the SCT contains a significant amount of sulfur derived from the first mixture's aromatic sulfur.
  • the SCT sulfur content can be about 3 to 4 times higher in the SCT than in the first mixture's hydrocarbon component, on a weight basis.
  • the first mixture's hydrocarbon comprises one or more crude oils and/or one or more crude oil fractions, such as those obtained from an atmospheric pipestill (“APS") and/or vacuum pipestill (“VPS").
  • the crude oil and/or fraction thereof is optionally desalted prior to being included in the first mixture.
  • An example of a crude oil fraction utilized in the first mixture is produced by separating APS bottoms from a crude oil and followed by VPS treatment of the APS bottoms.
  • the pyrolysis furnace has at least one vapor/liquid separation device (sometimes referred to as flash pot or flash drum) integrated therewith, for upgrading the first mixture.
  • vapor/liquid separator devices are particularly suitable when the first mixture's hydrocarbon component comprises > about 0.1 wt. % asphaltenes based on the weight of the first mixture's hydrocarbon component, e.g., > about 5.0 wt. %.
  • Conventional vapor/liquid separation devices can be utilized to do this, though the invention is not limited thereto. Examples of such conventional vapor/liquid separation devices include those disclosed in U.S. Patent Nos.
  • the composition of the vapor phase leaving the device is substantially the same as the composition of the vapor phase entering the device, and likewise the composition of the liquid phase leaving the flash drum is substantially the same as the composition of the liquid phase entering the device, i.e., the separation in the vapor/liquid separation device includes (or even consists essentially of) a physical separation of the two phases entering the drum.
  • At least a portion of the first mixture's hydrocarbon component is provided to the inlet of a convection section of a pyrolysis unit, wherein hydrocarbon is heated so that at least a portion of the hydrocarbon is in the vapor phase.
  • a diluent e.g., steam
  • the first mixture's diluent component is optionally (but preferably) added in this section and mixed with the hydrocarbon component to produce the first mixture.
  • the first mixture is then flashed in at least one vapor/liquid separation device in order to separate and conduct away from the first mixture at least a portion of the first mixture's high molecular- weight molecules, such as asphaltenes.
  • a bottoms fraction can be conducted away from the vapor-liquid separation device, the bottoms fraction comprising, e.g., > 10.0 % (on a wt. basis) of the first mixture's asphaltenes.
  • the steam cracking furnace can be integrated with a vapor/liquid separation device operating at a temperature in the range of from about 600°F to about 950°F (about 350°C to about 510°C) and a pressure in the range of about 275 kPa to about 1400 kPa, e.g., a temperature in the range of from about 430°C to about 480°C and a pressure in the range of about 700 kPa to 760 kPa.
  • the overheads from the vapor/liquid separation device can be subjected to further heating in the convection section, and are then introduced via crossover piping into the radiant section where the overheads are exposed to a temperature > 760°C at a pressure > 0.5 bar (gauge) e.g., a temperature in the range of about 790°C to about 850°C and a pressure in the range of about 0.6 bar (gauge) to about 2.0 bar (gauge), to carry out the pyrolysis (e.g., cracking and/or reforming) of the first mixture's hydrocarbon component.
  • a temperature > 760°C at a pressure > 0.5 bar (gauge) e.g., a temperature in the range of about 790°C to about 850°C and a pressure in the range of about 0.6 bar (gauge) to about 2.0 bar (gauge)
  • pyrolysis e.g., cracking and/or reforming
  • the first mixture's hydrocarbon component can comprise > 50.0 wt. %, e.g., > 75.0 wt. %, such as > 90.0 wt. % (based on the weight of the first mixture's hydrocarbon) of one or more crude oils, even high naphthenic acid-containing crude oils and fractions thereof.
  • Feeds having a high naphthenic acid content are among those that produce a high quantity of tar and are especially suitable when at least one vapor/liquid separation device is integrated with the pyrolysis furnace.
  • the first mixture's composition can vary over time, e.g., by utilizing a first mixture having a first hydrocarbon component during a first time period and then utilizing a first mixture having a second hydrocarbon component during a second time period, the first and second hydrocarbons being substantially different hydrocarbons or substantially different hydrocarbon mixtures.
  • the first and second periods can be of substantially equal duration, but this is not required. Alternating first and second periods can be conducted in sequence continuously or semi-continuously (e.g., in "blocked" operation) if desired.
  • This embodiment can be utilized for the sequential pyrolysis of incompatible first and second hydrocarbon components (i.e., where the first and second hydrocarbon components are mixtures that are not sufficiently compatible to be blended under ambient conditions).
  • first hydrocarbon component comprising a virgin crude oil can be utilized to produce the first mixture during a first time period and steam cracked tar utilized to produce the first mixture during a second time period.
  • the vapor/liquid separation device is not used.
  • the pyrolysis conditions can be conventional steam cracking conditions. Suitable steam cracking conditions include, e.g., exposing the first mixture to a temperature (measured at the radiant outlet) > 400°C, e.g., in the range of 400°C to 900°C, and a pressure > 0.1 bar, for a cracking residence time period in the range of from about 0.01 second to 5.0 second.
  • the first mixture comprises hydrocarbon and diluent, wherein the first mixture's hydrocarbon comprises > 50.0 wt.
  • the diluent comprises, e.g., > 95.0 wt. % water based on the weight of the diluent.
  • the first mixture comprises 10.0 wt. % to 90.0 wt.
  • the pyrolysis conditions generally include one or more of (i) a temperature in the range of 760°C to 880°C; (ii) a pressure in the range of from 1.0 to 5.0 bar (absolute), or (iii) a cracking residence time in the range of from 0.10 to 2.0 seconds.
  • a second mixture is conducted away from the pyrolysis furnace, the second mixture being derived from the first mixture by the pyrolysis.
  • the second mixture generally comprises > 1.0 wt. % of C2 unsaturates and > 0.1 wt. % of TH, the weight percents being based on the weight of the second mixture.
  • the second mixture comprises > 5.0 wt. % of C2 unsaturates and/or > 0.5 wt. % of TH, such as > 1.0 wt. % TH.
  • the second mixture generally contains a mixture of the desired light olefins, SCN, SCGO, SCT, and unreacted components of the first mixture (e.g., water in the case of steam cracking, but also in some cases unreacted hydrocarbon), the relative amount of each of these generally depends on, e.g., the first mixture's composition, pyrolysis furnace configuration, process conditions during the pyrolysis, etc.
  • the second mixture is generally conducted away for the pyrolysis section, e.g., for cooling and separation stages.
  • the second mixture's TH comprise > 10.0 wt. % of TH aggregates having an average size in the range of 10.0 nm to 300.0 nm in at least one dimension and an average number of carbon atoms > 50, the weight percent being based on the weight of Tar Heavies in the second mixture.
  • the aggregates comprise > 50.0 wt. %, e.g., > 80.0 wt. %, such as > 90.0 wt. % of TH molecules having a C:H atomic ratio in the range of from 1.0 to 1.8, a molecular weight in the range of 250 to 5000, and a melting point in the range of 100°C to 700°C.
  • the invention is compatible with cooling the second mixture downstream of the pyrolysis furnace, e.g., the second mixture can be cooled using a system comprising transfer line heat exchangers.
  • the transfer line heat exchangers can cool the process stream to a temperature in the range of about 700°C to 350°C, in order to efficiently generate super-high pressure steam which can be utilized by the process or conducted away.
  • the second mixture can be subjected to direct quench at a point typically between the furnace outlet and the separation stage. The quench can be accomplished by contacting the second mixture with a liquid quench stream, in lieu of, or in addition to the treatment with transfer line exchangers.
  • the quench liquid is preferably introduced at a point downstream of the transfer line exchanger(s).
  • Suitable quench liquids include liquid quench oil, such as those obtained by a downstream quench oil knock-out drum, pyrolysis fuel oil and water, which can be obtained from conventional sources, e.g., condensed dilution steam.
  • a separation stage is generally utilized downstream of the pyrolysis furnace and downstream of the transfer line exchanger and/or quench point for separating from the second mixture one or more of light olefin, SCN, SCGO, SCT, or water.
  • Conventional separation equipment can be utilized in the separation stage, e.g., one or more flash drums, fractionators, water-quench towers, indirect condensers, etc., such as those described in U.S. Patent No. 8,083,931.
  • a third mixture which is a tar stream, can be separated from the second mixture, with the third mixture tar stream comprising > 10.0 wt. % of the second mixture's TH based on the weight of the second mixture's TH.
  • the tar stream generally comprises SCT, which is obtained, e.g., from an SCGO stream and/or a bottoms stream of the steam cracker's primary fractionator, from flash-drum bottoms (e.g., the bottoms of one or more flash drums located downstream of the pyrolysis furnace and upstream of the primary fractionator), or a combination thereof.
  • SCT is obtained, e.g., from an SCGO stream and/or a bottoms stream of the steam cracker's primary fractionator, from flash-drum bottoms (e.g., the bottoms of one or more flash drums located downstream of the pyrolysis furnace and upstream of the primary fractionator), or a combination thereof.
  • the tar stream can comprise TH aggregates.
  • the tar stream comprises > 50.0 wt. % of the second mixture's TH based on the weight of the second mixture's TH.
  • the tar stream can comprise > 90.0 wt. % of the second mixture's TH based on the weight of the second mixture's TH.
  • the tar stream can have, e.g., (i) a sulfur content in the range of 0.5 wt. % to 7.0 wt. %, (ii) a TH content in the range of from 5.0 wt. % to 40.0 wt.
  • % the weight percents being based on the weight of the tar stream, (iii) a density at 15°C in the range of 1.01 g/cm 3 to 1.15 g/cm 3 , e.g., in the range of 1.07 g/cm 3 to 1.15 g/cm 3 , and (iv) a 50°C viscosity in the range of 200 cSt to 1.0 x 10 7 cSt.
  • the tar stream is generally conducted away from the separation stage for hydroprocessing of the tar stream in one or more hydroprocessing stages in the presence of a utility fluid, the utility fluid generally comprising a recycled liquid-phase portion of the hydroprocessor effluent.
  • Utility fluids useful in the invention will now be described in more detail.
  • the utility fluid is utilized in hydroprocessing the tar stream, e.g., for effectively increasing run-length during hydroprocessing and improving the properties of the hydroprocessed tar.
  • Effective utility fluids comprise aromatics, i.e., comprise molecules having at least one aromatic core.
  • the utility fluid comprises > 40.0 wt. % aromatic carbon such as > 60.0 wt. % aromatic carbon as measured by 13 C Nuclear Magnetic Resonance.
  • the utility fluid comprises a portion of the liquid-phase effluent. In other words, a portion of the hydroprocessing zone's total liquid-phase product is effectively recycled back to the hydroprocessor.
  • the utility fluid can comprise > 50.0 wt.
  • the liquid phase of the hydroprocessor effluent for simplicity, the liquid phase of the hydroprocessor effluent
  • the remainder of the liquid-phase effluent of the hydroprocessing stage (i.e., the remainder) of the hydroprocessor effluent may be conducted away from the process, and optionally used, e.g., as a low sulfur fuel oil blend component.
  • the effluent from the hydroprocessing stage may optionally pass through one or more separation stages.
  • Non- limiting examples of the separation stages may include: flash drums, distillation columns, evaporators, strippers, steam strippers, vacuum flashes, or vacuum distillation columns. These separation stages allow one skilled in the art to adjust the properties of the liquid-phase portion of the hydroprocessor effluent to be used as the utility fluid.
  • the liquid-phase portion of the hydroprocessor effluent may comprise > 90.0 wt. % of the hydroprocessor effluent's molecules having at least four carbon atoms based on the weight of the hydroprocessor effluent.
  • the liquid phase of the hydroprocessor effluent comprises > 90.0 wt. % of the hydroprocessor effluent's molecules (based on the weight of the hydroprocessor effluent) having an atmospheric boiling point > 65.0°C, e.g., > 100.0°C, such as > 150.0°C.
  • the total liquid-phase portion of the hydroprocessor effluent is separated into a light liquid and a heavy liquid where the heavy liquid comprises > 90 wt. % of the molecules with an atmospheric boiling point of > 250°C, e.g., > 350°C, that were present in the liquid phase.
  • the utility fluid can comprise a portion of the light liquid obtained from this separation.
  • the utility fluid that comprises at least a portion of the liquid phase of the hydroprocessor effluent can be augmented or replaced by supplemental utility fluids that have an ASTM D86 10% distillation point > 120°C, e.g., > 140°C, such as > 150°C and/or an ASTM D86 90% distillation point ⁇ 300°C.
  • This option can be especially useful during start-up or periods of unit upsets or other operability problems, such as for example when the tar stream quality changes.
  • the supplemental utility fluid can be a solvent or mixture of solvents.
  • the supplemental utility fluid (i) has a critical temperature in the range of 285°C to 400°C and (ii) comprises > 80.0 wt. % of 1-ring aromatics and/or 2-ring aromatics, including alkyl-functionalized derivatives thereof, based on the weight of the supplemental utility fluid.
  • the supplemental utility fluid can comprise, e.g., > 90.0 wt. % of a single-ring aromatic, including those having one or more hydrocarbon substituents, such as from 1 to 3 or 1 to 2 hydrocarbon substituents.
  • Such substituents can be any hydrocarbon group that is consistent with the overall solvent distillation characteristics.
  • hydrocarbon groups include, but are not limited to, those selected from the group consisting of Ci-Ce alkyl, wherein the hydrocarbon groups can be branched or linear and the hydrocarbon groups can be the same or different.
  • the supplemental utility fluid comprises > 90.0 wt. % based on the weight of the utility fluid of one or more of benzene, ethylbenzene, trimethylbenzene, xylenes, toluene, naphthalenes, alkylnaphthalenes (e.g., methylnaphtalenes), tetralins, or alkyltetralins (e.g., methyltetralins).
  • the supplemental utility fluid comprises ⁇ 10.0 wt. % of ring compounds with Ci-Ce sidechains having alkenyl functionality, based on the weight of the utility fluid.
  • the supplemental utility fluid comprises SCN and/or SCGO, e.g., SCN and/or SCGO separated from the second mixture in a primary fractionator downstream of a pyrolysis furnace operating under steam cracking conditions.
  • SCN or SCGO may be hydrotreated in different conventional hydrotreaters (e.g., not hydrotreated with the tar).
  • the supplemental utility fluid can comprise, e.g., > 50.0 wt. % of the separated gas oil, based on the weight of the supplemental utility fluid.
  • at least a portion of the utility fluid is obtained from the hydroprocessed product, e.g., by separating and recycling a liquid-phase portion of the hydroprocessor effluent having an atmospheric boiling point ⁇ 300°C.
  • the supplemental utility fluid contains sufficient amount of molecules having one or more aromatic cores to augment the utility fluid that comprises recycled hydroprocessed product to effectively increase run length during hydroprocessing of the tar stream.
  • the supplemental utility fluid can comprise > 50.0 wt. % of molecules having at least one aromatic core, e.g., > 60.0 wt. %, such as > 70 wt. %, based on the total weight of the utility fluid.
  • the supplemental utility fluid comprises (i) > 60.0 wt. % of molecules having at least one aromatic core and (ii) ⁇ 1.0 wt.
  • the relative amounts of utility fluid and tar stream during hydroprocessing are generally in the range of from about 20.0 wt. % to about 95.0 wt. % of the tar stream and from about 5.0 wt. % to about 80.0 wt. % of the utility fluid, based on total weight of utility fluid plus tar stream.
  • the relative amounts of utility fluid and tar stream during hydroprocessing can be in the range of (i) about 20.0 wt. % to about 90.0 wt. % of the tar stream and about 10.0 wt.
  • At least a portion of the utility fluid can be combined with at least a portion of the tar stream within the hydroprocessing vessel or hydroprocessing zone, but this is not required, and in one or more embodiments at least a portion of the utility fluid and at least a portion of the tar stream are supplied as separate streams and combined into one feed stream prior to entering (e.g., upstream of) the hydroprocessing vessel or hydroprocessing zone.
  • the feed stream to the hydroprocessor comprises 40.0 wt. % to 90.0 wt. % of SCT and 10.0 wt. % to 60.0 wt. % of utility fluid, the weight percents being based on the weight of the feed stream.
  • the tar : utility fluid ratio can be in the range of 0.50 : 1.0 to 3.0 : 1.0, such as 0.2 to 3.0.
  • Hydroprocessing of the tar stream in the presence of the utility fluid can occur in one or more hydroprocessing stages, the stages comprising one or more hydroprocessing vessels or zones.
  • Vessels and/or zones within the hydroprocessing stage in which catalytic hydroprocessing activity occurs generally include at least one hydroprocessing catalyst.
  • the catalysts can be mixed or stacked, such as when the catalyst is in the form of one or more fixed beds in a vessel or hydroprocessing zone.
  • hydroprocessing catalyst can be utilized for hydroprocessing the tar stream in the presence of the utility fluid, such as those specified for use in resid and/or heavy oil hydroprocessing, but the invention is not limited thereto.
  • Suitable hydroprocessing catalysts include those comprising (i) one or more bulk metals and/or (ii) one or more metals on a support. The metals can be in elemental form or in the form of a compound.
  • the hydroprocessing catalyst includes at least one metal from any of Groups 5 to 10 of the Periodic Table of the Elements (tabulated as the Periodic Chart of the Elements, The Merck Index, Merck & Co., Inc., 1996).
  • the catalyst has a total amount of Groups 5 to 10 metals per gram of catalyst of at least 0.0001 grams, or at least 0.001 grams or at least 0.01 grams, in which grams are calculated on an elemental basis.
  • the catalyst can comprise a total amount of Group 5 to 10 metals in a range of from 0.0001 grams to 0.6 grams, or from 0.001 grams to 0.3 grams, or from 0.005 grams to 0.1 grams, or from 0.01 grams to 0.08 grams.
  • the catalyst further comprises at least one Group 15 element.
  • An example of a preferred Group 15 element is phosphorus.
  • the catalyst can include a total amount of elements of Group 15 in a range of from 0.000001 grams to 0.1 grams, or from 0.00001 grams to 0.06 grams, or from 0.00005 grams to 0.03 grams, or from 0.0001 grams to 0.001 grams, in which grams are calculated on an elemental basis.
  • the catalyst comprises at least one Group 6 metal.
  • Group 6 metals include chromium, molybdenum and tungsten.
  • the catalyst may contain, per gram of catalyst, a total amount of Group 6 metals of at least 0.00001 grams, or at least 0.01 grams, or at least 0.02 grams, in which grams are calculated on an elemental basis.
  • the catalyst can contain a total amount of Group 6 metals per gram of catalyst in the range of from 0.0001 grams to 0.6 grams, or from 0.001 grams to 0.3 grams, or from 0.005 grams to 0.1 grams, or from 0.01 grams to 0.08 grams, the number of grams being calculated on an elemental basis.
  • the catalyst includes at least one Group 6 metal and further includes at least one metal from Group 5, Group 7, Group 8, Group 9, or Group 10.
  • Such catalysts can contain, e.g., the combination of metals at a molar ratio of Group 6 metal to Group 5 metal in a range of from 0.1 to 20, 1 to 10, or 2 to 5, in which the ratio is on an elemental basis.
  • the catalyst will contain the combination of metals at a molar ratio of Group 6 metal to a total amount of Groups 7 to 10 metals in a range of from 0.1 to 20, 1 to 10, or 2 to 5, in which the ratio is on an elemental basis.
  • the catalyst includes at least one Group 6 metal and one or more metals from Groups 9 or 10, e.g., molybdenum-cobalt and/or tungsten-nickel, these metals can be present, e.g., at a molar ratio of Group 6 metal to Groups 9 and 10 metals in a range of from 1 to 10, or from 2 to 5, in which the ratio is on an elemental basis.
  • these metals can be present, e.g., at a molar ratio of Group 5 metal to Group 10 metal in a range of from 1 to 10, or from 2 to 5, where the ratio is on an elemental basis.
  • Catalysts which further comprise inorganic oxides, e.g., as a binder and/or support, are within the scope of the invention.
  • the catalyst can comprise (i) > 1.0 wt. % of one or more metals selected from Groups 6, 8, 9, and 10 of the Periodic Table and (ii) > 1.0 wt. % of an inorganic oxide, the weight percents being based on the weight of the catalyst.
  • the invention encompasses incorporating into (or depositing on) a support one or catalytic metals e.g., one or more metals of Groups 5 to 10 and/or Group 15, to form the hydroprocessing catalyst.
  • the support can be a porous material.
  • the support can comprise one or more refractory oxides, porous carbon-based materials, zeolites, or combinations thereof suitable refractory oxides include, e.g., alumina, silica, silica-alumina, titanium oxide, zirconium oxide, magnesium oxide, and mixtures thereof.
  • suitable porous carbon-based materials include, activated carbon and/or porous graphite.
  • zeolites include, e.g., Y-zeolites, beta zeolites, mordenite zeolites, ZSM-5 zeolites, and ferrierite zeolites.
  • Additional examples of support materials include gamma alumina, theta alumina, delta alumina, alpha alumina, or combinations thereof.
  • the amount of gamma alumina, delta alumina, alpha alumina, or combinations thereof, per gram of catalyst support can be, e.g., in a range of from 0.0001 grams to 0.99 grams, or from 0.001 grams to 0.5 grams, or from 0.01 grams to 0.1 grams, or at most 0.1 grams, as determined by x-ray diffraction.
  • the hydroprocessing catalyst is a supported catalyst, the support comprising at least one alumina, e.g., theta alumina, in an amount in the range of from 0.1 grams to 0.99 grams, or from 0.5 grams to 0.9 grams, or from 0.6 grams to 0.8 grams, the amounts being per gram of the support.
  • the amount of alumina can be determined using, e.g., x-ray diffraction.
  • the support can comprise, e.g., at least 0.1 grams, or at least 0.3 grams, or at least 0.5 grams, or at least 0.8 grams of theta alumina.
  • the support can be impregnated with the desired metals to form the hydroprocessing catalyst.
  • the support can be heat-treated at temperatures in a range of from 400°C to 1200°C, or from 450°C to 1000°C, or from 600°C to 900°C, prior to impregnation with the metals.
  • the hydroprocessing catalyst can be formed by adding or incorporating the Groups 5 to 10 metals to shaped heat-treated mixtures of support. This type of formation is generally referred to as overlaying the metals on top of the support material.
  • the catalyst is heat treated after combining the support with one or more of the catalytic metals, e.g., at a temperature in the range of from 150°C to 750°C, or from 200°C to 740°C, or from 400°C to 730°C.
  • the catalyst is heat treated in the presence of hot air and/or oxygen-rich air at a temperature in a range between 400°C and 1000°C to remove volatile matter such that at least a portion of the Groups 5 to 10 metals are converted to their corresponding metal oxide.
  • the catalyst can be heat treated in the presence of oxygen (e.g., air) at temperatures in a range of from 35°C to 500°C, or from 100°C to 400°C, or from 150°C to 300°C. Heat treatment can take place for a period of time in a range of from 1 to 3 hours to remove a majority of volatile components without converting the Groups 5 to 10 metals to their metal oxide form.
  • Catalysts prepared by such a method are generally referred to as "uncalcined" catalysts or "dried.”
  • Such catalysts can be prepared in combination with a sulfiding method, with the Groups 5 to 10 metals being substantially dispersed in the support.
  • the catalyst comprises a theta alumina support and one or more Groups 5 to 10 metals
  • the catalyst is generally heat treated at a temperature > 400°C to form the hydroprocessing catalyst.
  • heat treating is conducted at temperatures ⁇ 1200°C.
  • the catalyst can be in shaped forms, e.g., one or more of discs, pellets, extrudates, etc., though this is not required.
  • shaped forms include those having a cylindrical symmetry with a diameter in the range of from about 0.79 mm to about 3.2 mm (l/32 nd to l/8 th inch), from about 1.3 mm to about 2.5 mm (l/20 th to l/10 th inch), or from about 1.3 mm to about 1.6 mm (l/20 th to l/16 th inch).
  • Similarly-sized non-cylindrical shapes are within the scope of the invention, e.g., trilobe, quadralobe, etc.
  • the catalyst has a flat plate crush strength in a range of from 50-500 N/cm, or 60-400 N/cm, or 100-350 N/cm, or 200-300 N/cm, or 220-280 N/cm.
  • Porous catalysts including those having conventional pore characteristics, are within the scope of the invention.
  • the catalyst can have a pore structure, pore size, pore volume, pore shape, pore surface area, etc., in ranges that are characteristic of conventional hydroprocessing catalysts, though the invention is not limited thereto.
  • the catalyst can have a median pore size that is effective for hydroprocessing SCT molecules, such catalysts having a median pore size in the range of from 30 A to 1000 A, or 50 A to 500 A, or 60 A to 300 A. Pore size can be determined according to ASTM Method D4284-07 Mercury Porosimetry.
  • the hydroprocessing catalyst has a median pore diameter in a range of from 50 A to 200 A.
  • the hydroprocessing catalyst has a median pore diameter in a range of from 90 A to 180 A, or 100 A to 140 A, or 1 10 A to 130 A.
  • the hydroprocessing catalyst has a median pore diameter ranging from 50 A to 150 A.
  • the hydroprocessing catalyst has a median pore diameter in a range of from 60 A to 135 A, or from 70 A to 120 A.
  • hydroprocessing catalysts having a larger median pore diameter are utilized, e.g., those having a median pore diameter in a range of from 180 A to 500 A, or 200 A to 300 A, or 230 A to 250 A.
  • the hydroprocessing catalyst has a pore size distribution that is not so great as to significantly degrade catalyst activity or selectivity.
  • the hydroprocessing catalyst can have a pore size distribution in which at least 60% of the pores have a pore diameter within 45 A, 35 A, or 25 A of the median pore diameter.
  • the catalyst has a median pore diameter in a range of from 50 A to 180 A, or from 60 A to 150 A, with at least 60% of the pores having a pore diameter within 45 A, 35 A, or 25 A of the median pore diameter.
  • the catalyst can have, e.g., a pore volume > 0.3 cm 3 /g, such > 0.7 cm 3 /g, or > 0.9 cm 3 /g.
  • pore volume can range, e.g., from 0.3 cmVg to 0.99 cmVg, 0.4 cmVg to 0.8 cmVg, or 0.5 cm 3 /g to 0.7 cmVg.
  • the hydroprocessing catalyst can have a surface area > 60 m 2 /g, or > 100 m 2 /g, or >
  • Hydroprocessing the specified amounts of tar stream and utility fluid using the specified hydroprocessing catalyst leads to improved catalyst life, e.g., allowing the hydroprocessing stage to operate continuously for at least 3 months, or at least 6 months, or at least 1 year without replacement, regeneration, or rejuvenation of the catalyst in the hydroprocessing or contacting zone.
  • Catalyst life is generally > 10 times longer than would be the case if no utility fluid were utilized, e.g., > 100 times longer, such as > 1000 times longer.
  • the hydroprocessing is carried out in the presence of hydrogen, e.g., by (i) combining molecular hydrogen with the tar stream and/or utility fluid upstream of the hydroprocessing and/or (ii) conducting molecular hydrogen to the hydroprocessing stage in one or more conduits or lines.
  • hydrogen e.g., by (i) combining molecular hydrogen with the tar stream and/or utility fluid upstream of the hydroprocessing and/or (ii) conducting molecular hydrogen to the hydroprocessing stage in one or more conduits or lines.
  • a "treat gas" which contains sufficient molecular hydrogen for the hydroprocessing and optionally other species (e.g., nitrogen and light hydrocarbons such as methane) which generally do not adversely interfere with or affect either the reactions or the products.
  • Unused treat gas can be separated from the hydroprocessor effluent for re-use, generally after removing undesirable impurities, such as ]3 ⁇ 4S and NH3.
  • the treat gas optionally contains > about 50 vol. % of molecular hydrogen, e.g., > about 75 vol. %, based on the total volume of treat gas conducted to the hydroprocessing stage.
  • the amount of molecular hydrogen supplied to the hydroprocessing stage is in the range of from about 300 SCF/B (standard cubic feet per barrel) (53 S m 3 /m 3 ) to 5000 SCF/B (890 S m 3 /m 3 ), in which B refers to barrel of the tar stream.
  • the molecular hydrogen can be provided in a range of from 1000 SCF/B (178 S m 3 /m 3 ) to 3000 SCF/B (534 S m 3 /m 3 ).
  • Hydroprocessing the tar stream in the presence of the specified utility fluid, molecular hydrogen, and a catalytically effective amount of the specified hydroprocessing catalyst under catalytic hydroprocessing conditions produces a hydroprocessed product including, e.g., upgraded SCT.
  • a hydroprocessed product including, e.g., upgraded SCT.
  • the hydroprocessing is generally carried out under hydroconversion conditions, e.g., under conditions for carrying out one or more of hydrocracking (including selective hydrocracking), hydrogenation, hydrotreating, hydrodesulfurization, hydrodenitrogenation, hydrodemetallation, hydrodearomatization, hydroisomerization, or hydrodewaxing of the specified tar stream.
  • the hydroprocessing reaction can be carried out in at least one vessel or zone that is located, e.g., within a hydroprocessing stage downstream of the pyro lysis stage and separation stage.
  • the specified tar stream generally contacts the hydroprocessing catalyst in the vessel or zone, in the presence of the utility fluid and molecular hydrogen.
  • Catalytic hydroprocessing conditions can include, e.g., exposing the combined diluent-tar stream to a temperature in the range from 50°C to 500°C or from 200°C to 450°C or from 220°C to 430°C or from 350°C to 420°C proximate to the molecular hydrogen and hydroprocessing catalyst.
  • a temperature in the range of from 300°C to 500°C, or 350°C to 430°C, or 360°C to 420°C can be utilized.
  • Liquid hourly space velocity (LHSV) of the combined diluent-tar stream will generally range from 0.1 If 1 to 30 h "1 , or 0.4 IT 1 to 25 h "1 , or 0.5 IT 1 to 20 IT 1 . In some embodiments, LHSV is at least 5 IT 1 , or at least 10 If 1 , or at least 15 If 1 .
  • Molecular hydrogen partial pressure during the hydroprocessing is generally in the range of from 0.1 MPa to 8 MPa, or 1 MPa to 7 MPa, or 2 MPa to 6 MPa, or 3 MPa to 5 MPa.
  • the partial pressure of molecular hydrogen is ⁇ 7 MPa, or ⁇ 6 MPa, or ⁇ 5 MPa, or ⁇ 4 MPa, or ⁇ 3 MPa, or ⁇ 2.5 MPa, or ⁇ 2 MPa.
  • the hydroprocessing conditions can include, e.g., one or more of a temperature in the range of 300°C to 500°C, a pressure in the range of 15 bar (absolute) to 135 bar, a space velocity in the range of 0.1 to 5.0, and a molecular hydrogen consumption rate of about 50 standard cubic meters/cubic meter (S m 3 /m 3 ) to about 450 S m 3 /m 3 (300 SCF/B to 2500 SCF/B).
  • the hydroprocessing conditions include one or more of a temperature in the range of 380°C to 430°C, a pressure in the range of 20 bar (absolute) to 120 bar (absolute), or 20 bar (absolute) to 100 bar (absolute), or 21 bar (absolute) to 81 bar (absolute), a space velocity (LHSV) in the range of 0.2 to 1.0, and a hydrogen consumption rate of about 70 S m 3 /m 3 to about 265 S m 3 /m 3 (400 SCF/B to 1500 SCF/B).
  • TH hydroconversion conversion is generally > 25.0% on a weight basis, e.g., > 50.0%.
  • FIG. 1 An embodiment of the invention is shown schematically in Figure 1.
  • a feedstock comprising (i) tar, such as SCT, provided via conduit 1 and (ii) utility fluid provided by conduit 7 is conducted via conduit 8 to hydroprocessing reactor 2 for hydroprocessing under one or more of the specified hydroprocessing conditions.
  • Molecular hydrogen treat gas is conducted to reactor 2 by one or more conduits (not shown).
  • the reactor's effluent is conducted via conduit 3 to separation stage 4.
  • a portion of the reactor effluent's total liquid product i.e., a portion of the total liquid-phase effluent from the hydroprocessor
  • An offgas comprising, e.g., molecular hydrogen, methane, and hydrogen sulfide is separated from the reactor effluent in separation stage 4 and is conducted away via conduit 6.
  • a hydroprocessed product comprising, e.g., C5+ hydrocarbon is conducted away via conduit 5.
  • an SCT it is desired to hydroprocess an SCT to achieve a beneficial blending characteristics and/or a relatively low viscosity, e.g., a viscosity ⁇ 20 cSt, such as ⁇ 15 cSt or ⁇ 10 cSt.
  • one or more of the specified SCT can be hydroprocessed in the presence of one or more of the specified utility fluid under catalytic hydroprocessing conditions including a temperature in the range of 375°C to 425°C, such as 385°C to 415°C; a pressure in the range of 45 bar (absolute) to 135 bar (absolute), such as 60 bar (absolute) to 90 bar (absolute); a molecular hydrogen treat rate (based on tar feed) in the range of 150 S m 3 /m 3 to 1200 S m 3 /m 3 (840 SCF/B to 6700 SCF/B), such as in the range of 180 S m 3 /m 3 to 450 S m 3 /m 3 (1000 SCF/B to 2500 SCF/B); and an LHSV in the range of 0.1 to 2.0, such as 0.25 to 0.50 LHSV on total feed (tar
  • C 4- byproducts is sensitive to the temperature to which the SCT is exposed during hydroprocessing, and that the production of these byproducts increases under the specified conditions when that temperature is greater than about 425°C.
  • the utility fluid utilized in this embodiment can be recycled from the hydroprocessor effluent (optionally following separation of the hydroprocessed tar fraction), this is not required.
  • fresh utility fluid is utilized, such as utility fluid having substantially the same composition as the supplemental utility fluid.
  • the utility fluid:tar weight ratio under these conditions can be in the range of in the range of 0.05: 1.0 to 2.0: 1.0, such as 0.10: 1.0 to 1.0: 1.0, or 0.1 : 1.0 to 0.5: 1.0.
  • a 56 cm length of 3/8 inch SS tubing with a total volume of 20 cm 3 was used as a reactor.
  • the middle 34 cm is held at a near-isothermal temperature of 400°C during the course of the experiment.
  • the volume of the hot zone is 14 cm 3 .
  • the entire reactor was loaded with 20 cm 3 of a commercial NiMo oxide on alumina hydrotreating catalyst (RT-621), and 5 cm 3 of 80 mesh silica to pack the interstitial spaces.
  • RT-621 commercial NiMo oxide on alumina hydrotreating catalyst
  • 100.0 wt. % of a feedstock is provided via conduit 8 to reactor 2.
  • the feedstock comprises 60.0 wt. % of SCT (having similar properties to those of SCT-1) conducted to the process via conduit 1 and 40.0 wt. % of utility fluid, the utility fluid being a portion of the reactor's total liquid-phase effluent conducted to conduit 8 via conduit 7, the weight percents being based on the weight of the feedstock.
  • the feedstock is fed to the reactor at a rate of 7 cmVhr via conduit 8.
  • Molecular hydrogen is fed to reactor 2 at a rate of 26 standard cm 3 per minute (seem) via a conduit (not shown).
  • the reactor is operated continuously under substantially the specified conditions for 80 days without a significant pressure drop (within about 10.0 % of the initial pressure drop).
  • Hydroprocessing conditions in reactor 2 include a pressure of approximately 70 bar (1000 psig), a temperature of 400°C, a molecular hydrogen consumption rate of 200 m 3 /m 3 (1100 SCFB) on a feedstock basis, and a space velocity (LHSV) of 0.44.
  • the reactor effluent comprises a vapor phase and a liquid phase, the liquid phase being the total liquid product.
  • the amount of total liquid product is approximately 95.0 wt. % of the total liquid feed to the reactor.
  • the effluent of reactor 2 is conducted via conduit 3 to separation stage 4. A portion of the reactor's liquid-phase effluent (comprising 40.0 wt.
  • Stage 4 is also utilized to separate from the reactor effluent a hydroprocessed product comprising C5+ hydrocarbon in an amount of approximately 56.0 wt. % based on the weight of the reactor effluent.
  • Stage 4 is utilized to separate a vapor product "offgas" 6 from the reactor effluent, the vapor product comprising approximately 1.1 wt. % of hydrogen sulfide and approximately 1.1 wt. % of molecular hydrogen based on the weight of the reactor effluent.
  • the offgas further comprises small amounts of other vapors (e.g., methane), to yield a total reactor effluent of 100.0 wt. % based on the weight of the feedstock.
  • the composition of the reactor effluent's liquid phase and vapor phase and the feedstock are analyzed by conventional means.
  • the SCT has a density of l. l lg/cm 3 , and comprises 2.2 wt. % sulfur and 1600 ppmw nitrogen, based on the weight of the SCT.
  • the hydroprocessed product comprises C5+ hydrocarbon and 800 ppmw of nitrogen.
  • the hydroprocessed product has a density (at 15°C) of 1.01 g/cm 3 , a viscosity of 8.8 cSt at 50°C, and a blend number I n of about 50.
  • Reactor pressure drop is on the order of 0.1 bar.
  • the hydroprocessed product contains only 0.4 wt. % sulfur.
  • the boiling range of the feedstock is 25 wt. % 500°F-650°F (260°C-345°C) light gas oil, 50 wt. % 650°F-1050°F (345°C-565°C) heavy gas oil, and 25 wt. % 1050°F+ (565°C+) based on the weight of the feedstock.
  • the product boiling range is 10 wt. % C 12- , 40 wt. % 400°F-650°F (205°C-345°C) light gas oil, 42 wt. % 650°F-1050°F (345°C-565°C) heavy gas oil, and 8 wt. % 1050°F+ (565°C+), based on the weight of the hydroprocessed product.
  • the process is useful because it converts a sour, high viscosity, high density tar stream into a lower viscosity, lower density, ⁇ 0.5 wt. % S stream with much improved properties for blending into finished fuels.
  • Example 3 The experiment of Example 1 is repeated, except for increasing the amount of the recycled portion of the total liquid-phase reactor effluent in conduit 7, to produce a feedstock comprising 80.0 wt. % liquid product and 20.0 wt. % SCT based on the weight of the feedstock. This corresponds to a utility fluid:tar stream weight ratio of 4: 1.
  • reactor 2 In operation, reactor 2 exhibited an increased pressure drop after just a few hours on-stream. After two weeks on-stream the pressure drop increased to > 20 bar (>300 psi) and operation had to be halted.
  • Example 3 Example 3
  • Example 2 The experiment of Example 2 is repeated, except that the feedstock comprises 91.0 wt. % total liquid product and 9.0 wt. % SCT based on the weight of the feedstock. This corresponds to a utility fluid:tar stream weight ratio of 10: 1.
  • a utility fluid:tar stream weight ratio of 10: 1. In operation, an increased reactor pressure drop is observed immediately. After 12 hours on-stream the reactor pressure drop is > 20 bar (> 300 psi) and operation had to be halted.

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Abstract

L'invention concerne des procédés de valorisation de produits obtenus par pyrolyse d'hydrocarbures, un équipement utile pour lesdits procédés et l'utilisation des produits de pyrolyse valorisés.
EP12762465.8A 2011-08-31 2012-08-31 Valorisation de produits de pyrolyse d'hydrocarbures par hydrotraitement Not-in-force EP2751234B1 (fr)

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WO2013033590A2 (fr) 2013-03-07
WO2013033590A3 (fr) 2013-04-25
CA2843517A1 (fr) 2013-03-07
EP2751234B1 (fr) 2016-11-16
CN103764799A (zh) 2014-04-30

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