+

WO2013033580A2 - Produit hydrotraité - Google Patents

Produit hydrotraité Download PDF

Info

Publication number
WO2013033580A2
WO2013033580A2 PCT/US2012/053417 US2012053417W WO2013033580A2 WO 2013033580 A2 WO2013033580 A2 WO 2013033580A2 US 2012053417 W US2012053417 W US 2012053417W WO 2013033580 A2 WO2013033580 A2 WO 2013033580A2
Authority
WO
WIPO (PCT)
Prior art keywords
compounds
hydroprocessed
weight
hydroprocessed product
ring
Prior art date
Application number
PCT/US2012/053417
Other languages
English (en)
Other versions
WO2013033580A3 (fr
Inventor
Teng Xu
Paul M. Edwards
Stephen H. Brown
Frank C. Wang
S. Mark Davis
Original Assignee
Exxonmobil Chemical Patents Inc.
Priority date (The priority date 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 date listed.)
Filing date
Publication date
Application filed by Exxonmobil Chemical Patents Inc. filed Critical Exxonmobil Chemical Patents Inc.
Priority to CN201280041813.4A priority Critical patent/CN103764797B/zh
Priority to PCT/US2012/053417 priority patent/WO2013033580A2/fr
Priority to CA2843515A priority patent/CA2843515C/fr
Priority to EP12762463.3A priority patent/EP2751233B1/fr
Publication of WO2013033580A2 publication Critical patent/WO2013033580A2/fr
Publication of WO2013033580A3 publication Critical patent/WO2013033580A3/fr

Links

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
    • 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
    • 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
    • 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
    • C10G2300/302—Viscosity
    • 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
    • C10G2400/00—Products obtained by processes covered by groups C10G9/00 - C10G69/14
    • C10G2400/30—Aromatics

Definitions

  • the invention relates to a hydroprocessed product that can be produced by hydroprocessing tar, such as a tar obtained from hydrocarbon pyrolysis.
  • the invention also relates to methods for producing such a hydroprocessed product, and the use of such a product, e.g., as a fuel oil blending component.
  • 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 hydroprocessed product, comprising: > 10.0 wt. % based on the weight of the hydroprocessed product of compounds selected from the group consisting of:
  • hydroprocessed product has a viscosity > 2.0 cSt at 50°C, and > 1.0 wt. % of the hydroprocessed product comprises compounds having an atmospheric boiling point > 565°C.
  • the invention relates to a hydroprocessed product produced by the method comprising:
  • hydroprocessed product has a viscosity and sulfur content less than that of the hydrocarbon mixture.
  • the invention relates to a hydroprocessed product made by a hydrocarbon conversion method, comprising: (a) providing a hydrocarbon mixture comprising > 2 wt. % sulfur, and > 0.1 wt. % of Tar Heavies, the weight percents being based on the weight of the hydrocarbon mixture;
  • hydroprocessed product has a viscosity and sulfur content less than that of the hydrocarbon mixture.
  • the invention relates to a hydroprocessed tar, comprising: > 10.0 wt. % based on the weight of the hydroprocessed tar of compounds selected from the group consisting of:
  • the hydroprocessed tar has a viscosity > 2.0 cSt at 50°C, and > 1.0 wt. % of the hydroprocessed tar comprises compounds having an atmospheric boiling point > 565°C.
  • the hydroprocessed tar comprises > 90.0 wt. % of hydroprocessed SCT based on the weight of the hydroprocessed tar.
  • the hydroprocessed tar is utilized to produce a blend, e.g., a mixture comprising (i) one or more of heavy fuel oil, vapor-liquid separator bottoms, fractionator tower bottoms, or SCT and (ii) > 5.0 wt. % of the hydroprocessed tar, the weight percents being based on the weight of the mixture.
  • the invention relates to a hydroprocessed product made by a hydrocarbon conversion method, comprising:
  • hydroprocessed product has a viscosity and sulfur content less than that of the hydrocarbon mixture.
  • Figure 1 shows a 2D GC Chromatogram obtained from a hydroprocessed product.
  • Figure 2 shows the molecular classes identified in the chromatogram of Figure 1.
  • the invention is based in part on the discovery that a hydroprocessed product having desirable properties can be made by hydroprocessing tar from pyrolysis of hydrocarbons, such as SCT, in the presence of a utility fluid comprising a significant amount of single or multi-ring aromatics.
  • SCT means (a) a mixture of hydrocarbons having one or more aromatic core 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.
  • 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.
  • the hydroprocessed product (and the SCT from which it can be derived) comprises to a large extent a mixture of multi-ring compounds.
  • the rings can be aromatic or non-aromatic and can contain a variety of substituents and/or heteroatoms.
  • the hydroprocessed product can contain, e.g., > 10.0 wt. %, or > 20.0 wt. %, or > 30.0 wt. %, based on the weight of the hydroprocessed product, of aromatic and non-aromatic multi-ring compounds.
  • the hydroprocessed product can be made by hydroprocessing a heavy tar stream made in one or more hydrocarbon pyrolysis processes such as steam cracking, the hydroprocessing being carried out in the presence of the specified utility fluid.
  • the hydroprocessing produces a highly-aromatic hydrocarbon having an atmospheric boiling point in the range of a heavy distillate, VGO, or even heavier hydrocarbon.
  • Such products are generally useful as, e.g., a blending component for fuel oil.
  • a molecule having 0.5 rings means a molecule having only one non-aromatic ring and no aromatic rings.
  • non-aromatic ring means four or more carbon atoms joined in at least one ring structure wherein at least one of the four or more carbon atoms in the ring structure is not an aromatic carbon atom.
  • Aromatic carbon atoms can be identified using, e.g., 13 C Nuclear magnetic resonance, for example.
  • Non-aromatic rings having atoms attached to the ring e.g., one or more heteroatoms, one or more carbon atoms, etc.
  • Non-aromatic rings having atoms attached to the ring e.g., one or more heteroatoms, one or more carbon atoms, etc.
  • non-aromatic rings examples include:
  • the non-aromatic ring can be statured as exemplified above or partially unsaturated for example, cyclopentene, cyclopenatadiene, cyclohexene and cyclohexadiene.
  • Non aromatic rings (which in SCT and the hydroprocessed product derived therefrom are primarily six and five member non-aromatic rings), can contain one or more heteroatoms such as sulfur (S), nitrogen (N) and oxygen (O).
  • S sulfur
  • N nitrogen
  • O oxygen
  • Non limiting examples of non- aromatic rings with heteroatoms includes the following
  • non-aromatic rings with hetero atoms can be statured as exemplified above or partially unsaturated.
  • a molecule having 1.0 ring means a molecule having only one aromatic ring or a molecule having only 2 non-aromatic rings and no aromatic rings.
  • aromatic ring means five or six joined in a ring structure wherein (i) at least four of the atoms joined in the ring structure are carbon atoms and (ii) all of the carbon atoms joined in the ring structure are aromatic carbon atoms.
  • Aromatic rings having atoms attached to the ring e.g., one or more heteroatoms, one or more carbon atoms, etc. but which are not part of the ring structure are within the scope of the term "non- aromatic ring”.
  • aromatic rings include, e.g.,:
  • the rings can be aromatic rings and/or non-aromatic rings.
  • the ring to ring connection can be of two types: type (1) where at least one side of the ring is shared, and type (2) where the rings are connected with at least one bond.
  • the type (1) structure is also known as a fused ring structure.
  • the type (2) structure is also commonly known as a bridged ring structure.
  • a few non-limiting examples of the type (1) fused ring structure are as follows:
  • the ring to ring connection may include all type (1) or type (2) connections or a mixture of both types (1) and (2).
  • Compounds of the 2.5 ring molecular class contain the following ring structures but no other rings: (i) two aromatic rings 2 ⁇ (1.0 ring) and one non-aromatic rings 1 ⁇ (0.5 ring) in the molecular structure or
  • compounds of the 3.0, 3.5, 4.0, 4.5, 5.0, etc. molecular classes contain a combination of non-aromatic rings counted as 0.5 ring, and aromatic rings counted as 1.0 ring, such that the total is 3.0, 3.5, 4.0, 4.5, 5.0, etc. respectively.
  • All of these multi-ring molecular classes include ring compounds having hydrogen, alkyl, or alkenyl groups bound thereto, e.g., one or more of H, CH 2 , C2 H 4 through C n H 2n , CH 3 , C2 H 5 through C n H 2n+1 .
  • n is in the range of from 1 to 6, e.g., from 1 to 5.
  • One skilled in the art can determine the types and amounts of compounds in the multi-ring molecular classes defined above in, e.g., the hydroprocessed product and the SCT from which it can be derived. Conventional methods can be utilized to do this, though the invention is not limited thereto.
  • two-dimensional gas chromatography 2D GC
  • 2D GC two-dimensional gas chromatography
  • the use of two-dimensional chromatography as an analytic tool for identifying the types and amounts of compounds of the specified molecular classes will now be described in more detail.
  • the invention is not limited to this method, and this description is not meant to foreclose other methods for identifying molecular types and amounts within the broader scope of the invention, e.g., other gas chromatography/mass spectrometry (GC/MS) techniques.
  • GC/MS gas chromatography/mass spectrometry
  • 2D GC In (2D GC), a sample is subjected to two sequential chromatographic separations.
  • the first separation is a partial separation by a first or primary separation column.
  • the partially separated components are then injected into a second or secondary column where they undergo further separation.
  • the two columns usually have different selectivities to achieve the desired degree of separation.
  • An example of 2D GC may be found in US Patent No. 5,169,039, which is incorporated by reference herein in its entirety.
  • a sample is injected into an inlet device connected to the inlet of the first column to produce a first dimension chromatogram.
  • the sample injection method used is not critical, and the use of conventional sample injection devices such as a syringe is suitable, though the invention is not limited thereto.
  • the inlet device holds a single sample, although those that hold multiple samples for injection into the first column are within the scope of the invention.
  • the column generally contains a stationary phase which is usually the column coating material.
  • the first column is generally coated with a non-polar material.
  • column coating material is methyl silicon polymer
  • the polarity can be measured by the percentage of methyl groups substituted by the phenyl group.
  • the polarity of a particular coating material can be measured on a % of phenyl group substitution scale from 0 to 100 with zero being non-polar and 80 (80% phenyl substitution) being polar.
  • These methyl silicon polymers are considered non-polar and have polarity values in the range 0 to 20.
  • Phenyl-substituted methyl silicon polymers are considered semi-polar and have polar values of 21 to 50.
  • Phenyl-substituted methyl silicon polymer coating materials are considered polar when greater than 51% phenyl-substituted methyl groups are included in the polymers.
  • Other polar coating polymers such as carbowaxes, are also used in chromatographic applications. Carbowaxes are polyethylene glycols of higher molecular weight.
  • a series of carborane silicon polymers sold under the trade name Dexsil have also been designed especially for high temperature applications.
  • the first column coated with a non-polar material, provides a first separation of the sample.
  • the first separation also known as the first dimension, generates a series of bands over a specified time period.
  • This first dimension chromatogram is similar to a conventional one-dimensional chromatogram.
  • the bands represent individual components or groups of components of the sample injected, and are generally fully separated or partially overlapped with adjacent bands.
  • the complex mixture When the complex mixture is separated by the first dimension column, it still suffers from many co-elutions (components not fully separated by the first dimension column).
  • the bands of separated materials from the first dimension are then completely sent to the second column to undergo further separation, especially on the co-eluted components.
  • the materials are further separated in the second dimension.
  • the second dimension is obtained from a second column coated with a semi-polar or polar material, preferably a semi- polar coating material.
  • a modulator is utilized to manage the flow between the end of the first column and the beginning of the second column.
  • Suitable modulators include thermal modulators utilizing trap/release mechanism, such as those in which cold nitrogen gas is used to trap separated sample from the first dimension followed by a periodic pulse of hot nitrogen to release trapped sample to the second dimension. Each pulse is analogous to a sample injection into the second dimension.
  • the role of the modulator is to (1) collect the continuous eluent flow out from the end of the first column with a fixed period of time (modulated period) and (2) inject to the beginning of the second column by release collected eluent at once at the end of the modulated period.
  • the function of the modulator is to (1) define the beginning time of a specific second dimensional column separation and (2) define the length of the second dimensional separation (modulation period).
  • the separated bands from the second dimension are coupled with the bands from the first dimension to form a comprehensive 2D chromatogram.
  • the bands are placed in a retention plane wherein the first dimension retention times and the second dimension retention times form the axes of the 2D chromatogram.
  • a conventional GC experiment takes 1 10 minutes to separate a mixture (a chromatogram with 110 minute retention time, x-axis).
  • a mixture a chromatogram with 110 minute retention time, x-axis.
  • it will become 660 chromatograms (60 second x 1 10 minute divided 10 second) where each 10 second chromatogram (y-axis) lines up one-by-one along the retention time axis (x-axis).
  • the x-axis is the first dimension retention time (the same as in conventional GC)
  • the y-axis is the second dimensional retention time
  • the peak intensity would project out in the third dimension z-axis.
  • the intensity can be converted based on a pre-defined gray scale (from black to white with different shades of grey) or a pre-defined color table to express their relative peak intensity.
  • Figure 1 shows a 2D GC of a hydroprocessed product sample obtained by hydroprocessing SCT in the presence of the specified utility fluid under the specified hydroprocessing conditions.
  • the 2D GC (GCxGC) system utilizes an Agilent 6890 gas chromatograph (Agilent Technology, Wilmington, DE) configured with inlet, columns, and detectors. A split/splitless inlet system with an eight-vial tray autosampler was used.
  • the two- dimensional capillary column system utilizes a non-polar first column (BPX-5, 30 meter, 0.25mm I.D., 1.0 ⁇ film), and a polar (BPX-50, 2 meter, 0.25mm ID., 0.25 ⁇ film), second column. Both capillary columns are obtained from SGE Inc. Austin, TX. A looped single jet thermal modulation assembly based on ZOEX technology (ZOEX Corp.
  • FIG. 1 shows a conventional quantitative analysis of the 2D GC data, utilizing a commercial program ("Transform” (Research Systems Inc. Boulder, CO) and "PhotoShop” program (Adobe System Inc. San Jose, CA) to generate the images.
  • 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 hydrocarbon.
  • high-molecular weight molecules e.g., MW > 600
  • asphaltenes and other high-molecular weight hydrocarbon e.g., MW > 600
  • asphaltene 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 guage), 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, e.g., C 4 or lighter, is less than 5 wt. %, which results in a unique composition of multi ring compounds, and further reduces the amount of hydrogen consumed in the hydroprocessing step.
  • 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 13 C 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. Even though solvent extraction is an imperfect process, results indicate that asphaltenes in vacuum resid are mostly heavy molecules having atmospheric boiling point that is greater than 565°C. When subjected to heptane solvent extraction under substantially the same conditions as those used for vacuum resid, the asphaltenes obtained from SCT contains a much greater percentage (on a wt. basis) of molecules having an atmospheric boiling point ⁇ 565°C than is the case for vacuum resid. SCT also differs from resid in the relative amount of metals and nitrogen-containing compounds present.
  • 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 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 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 - C 10 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 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 C 15 .
  • 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 > 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. %.
  • 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 component comprises > 10.0 wt. %, e.g., > 50.0 wt. %, such as > 90.0 wt. % (based on the weight of the hydrocarbon component) of one or more of naphtha, gas oil, vacuum gas oil, crude oil, resid, or resid admixtures; 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 component comprises sulfur, e.g., > 0.1 wt.
  • the first mixture's hydrocarbon component e.g., > 1.0 wt. %, such as in the range of about 1.0 wt. % to about 5.0 wt. %.
  • at least a portion of the first mixture's sulfur-containing molecules e.g., > 10.0 wt. % of the first mixture's sulfur-containing molecules, contain at least one aromatic ring ("aromatic sulfur").
  • aromatic sulfur aromatic sulfur
  • 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 combining 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 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 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 component) 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, tar stream can be separated from the second mixture, with the third mixture comprising > 10.0 wt. % of the second mixture's TH based on the weight of the second mixture's TH.
  • the third mixture 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 third mixture comprises > 50.0 wt. % of the second mixture's TH based on the weight of the second mixture's TH.
  • the third mixture can comprise > 90.0 wt. % of the second mixture's TH based on the weight of the second mixture's TH.
  • the third mixture 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 third mixture, (iii) a density at 15°C in the range of 0.98 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 third mixture can comprise TH aggregates.
  • the third mixture comprises > 50.0 wt. % of the second mixture's TH aggregates based on the weight of the second mixture's TH aggregates.
  • the third mixture can comprise > 90.0 wt. % of the second mixture's TH aggregates based on the weight of the second mixture's TH aggregates.
  • the third mixture is generally conducted away from the separation stage for hydroprocessing of the third mixture in the presence of a utility fluid.
  • a utility fluid Examples of utility fluids useful in the invention will now be described in more detail. The invention is not limited to the use of these utility fluids, and this description is not meant to foreclose other utility fluids within the broader scope of the invention.
  • the utility fluid comprises aromatics (i.e., comprises molecules having at least one aromatic core) and has an ASTM D86 10% distillation point > 60°C and a 90% distillation point ⁇ 360°C.
  • the utility fluid (which can be a solvent or mixture of solvents) has 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.
  • the utility fluid (i) has a critical temperature in the range of 285°C to 400°C and (ii) comprises > 80.0 wt.
  • the 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. Examples of such hydrocarbon groups include, but are not limited to, those selected from the group consisting of C1-C6 alkyl, wherein the hydrocarbon groups can be branched or linear and the hydrocarbon groups can be the same or different.
  • the utility fluid comprises > 90.0 wt.
  • the utility fluid comprises ⁇ 10.0 wt. % of ring compounds having C1-C6 sidechains with alkenyl functionality, based on the weight of the utility fluid.
  • the 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.
  • the SCN or SCGO can be hydrotreated in different conventional hydrotreaters (e.g. not hydrotreated with the tar).
  • the utility fluid can comprise, e.g., > 50.0 wt. % of the separated gas oil, based on the weight of the utility fluid.
  • at least a portion of the utility fluid is obtained from the hydroprocessed product, e.g., by separating and re-cycling a portion of the hydroprocessed product having an atmospheric boiling point ⁇ 300°C.
  • the utility fluid contains sufficient amount of molecules having one or more aromatic cores to effectively increase run length during hydroprocessing of the third mixture.
  • the 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 utility fluid comprises (i) > 60.0 wt. % of molecules having at least one aromatic core and (ii) ⁇ 1.0 wt. % of ring compounds with C1-C6 sidechains having alkenyl functionality, the weight percents being based on the weight of the utility fluid.
  • the utility fluid is utilized in hydroprocessing the third mixture, e.g., for effectively increasing run-length during hydroprocessing.
  • the relative amounts of utility fluid and third mixture during hydroprocessing are generally in the range of from about 20.0 wt. % to about 95.0 wt. % of the third mixture and from about 5.0 wt. % to about 80.0 wt. % of the utility fluid, based on total weight of utility fluid plus third mixture.
  • the relative amounts of utility fluid and third mixture during hydroprocessing can be in the range of (i) about 20.0 wt. % to about 90.0 wt. % of the third mixture and about 10.0 wt. % to about 80.0 wt.
  • At least a portion of the utility fluid can be combined with at least a portion of the third mixture 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 third mixture are supplied as separate streams and combined into one feed stream prior to entering (e.g., upstream of) the hydroprocessing stage(s).
  • the third mixture and utility fluid can be combined to produce a feedstock upstream of the hydroprocessing stage, the feedstock comprising, e.g., (i) about 20.0 wt. % to about 90.0 wt. % of the third mixture and about 10.0 wt. % to about 80.0 wt. % of the utility fluid, or (ii) from about 40.0 wt. % to about 90.0 wt. % of the third mixture and from about 10.0 wt. % to about 60.0 wt. % of the utility fluid, the weight percents being based on the weight of the feedstock.
  • the feedstock can be conducted to the hydroprocessing stage for the hydroprocessing.
  • Hydroprocessing of the third mixture 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 third mixture 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).
  • catalytic metals include, but are not limited to, vanadium, chromium, molybdenum, tungsten, manganese, technetium, rhenium, iron, cobalt, nickel, ruthenium, palladium, rhodium, osmium, iridium, platinum, or mixtures thereof.
  • 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 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 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 third mixture and utility fluid using the specified hydroprocessing catalyst leads to improved catalyst life, e.g., allowing the hydroprocessing stage to operate for at least 3 months, or at least 6 months, or at least 1 year without replacement 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 third mixture 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 third mixture 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 hydroprocessed product for re-use, generally after removing undesirable impurities, such as H 2 S and NH 3 .
  • 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 feed to the hydroprocessing stage (e.g., third mixture plus utility fluid).
  • B refers to barrel of feed to the hydroprocessing stage (e.g., third mixture plus utility fluid).
  • 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 third mixture 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 third mixture.
  • 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 pyrolysis stage and separation stage.
  • the specified third mixture 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-third mixture 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-third mixture will generally range from 0.1 If 1 to 30 If 1 , or 0.4 If 1 to 25 If 1 , or 0.5 If 1 to 20 If 1 .
  • LHSV is at least 5 If 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 ⁇ 2.5MPa, 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, or 20 bar to 120 bar, or 20 bar to 100 bar, a space velocity (LHSV) in the range of 0.1 to 5.0, and a molecular hydrogen consumption rate of about 53 standard cubic meters/cubic meter (S m 3 /m 3 ) to about 445 S m 3 /m 3 (300 SCF/B to 2500 SCF/B, where the denominator represents barrels of the third mixture, e.g., barrels of SCT).
  • 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 21 bar (absolute) to 81 bar (absolute), a space velocity in the range of 0.2 to 1.0, and a hydrogen consumption rate of about 70 S m 3 /m 3 to about 267 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%.
  • an effluent is conducted away from the hydroprocessing stage(s), the effluent comprising liquid-phase and vapor-phase portions.
  • the vapor-phase portion is generally separated from the effluent, e.g., by one or more vapor-liquid separators, and conducted away. Treat gas can be separated from the vapor portion for recycle and reuse, if desired.
  • a mixture comprising light hydrocarbons is separated from the liquid-phase portion of the hydroprocessor effluent, the light hydrocarbon mixture comprising > 90.0 wt. % of the liquid phase's molecules having atmospheric boiling point ⁇ 300°C based on the weight of the liquid-phase portion of the hydroprocessor effluent.
  • the conversion product i.e., the remainder of the liquid-phase portion of the hydroprocessor effluent following separation of the light hydrocarbon mixture generally comprises a hydroprocessed product.
  • hydroprocessed product comprises: > 10.0 wt. % based on the weight of the hydroprocessed product, e.g., > 20.0 wt. %, such as 20.0 wt. % to 40.0 wt. %, of one or more of (i) compounds in the 1.0 ring molecular class, (ii) compounds in the 1.5 ring molecular class, (iii) compounds defined in (i) or (ii) and further comprising one or more alkyl or alkenyl substituents on any ring, (iv) compounds defined in (i), (ii) or (iii) and further comprising hetero atoms selected from sulfur, nitrogen or oxygen.
  • the hydroprocessed product can have, e.g., a viscosity > 2.0 cSt at 50°C, e.g., in the range of 3.0 cSt to 50.0 cSt at 50°C.
  • > 1.0 wt. % of the hydroprocessed product comprises compounds having an atmospheric boiling point > 565°C, e.g., 2.0 wt. % to 10.0 wt. % based on the weight of the hydroprocessed product.
  • the hydroprocessed product can comprise, e.g., ⁇ 50.0 wt.
  • the hydroprocessed product can comprise, e.g., 20.0 wt. % to 40.0 wt. % of molecules having a number of aromatic rings in the range of from 3.0 to 5.0, based on the weight of the hydroprocessed product.
  • the hydroprocessed product can have, e.g., a sulfur content in the range of 0.01 wt. % to 3.5 wt. % based on the weight of the product.
  • the hydroprocessed product has a sulfur content that is ⁇ 0.5 times (wt. basis) that of the third mixture and a TH content ⁇ 0.7 times the TH content of the third mixture.
  • the hydroprocessed product comprises > 20.0 wt. % of the liquid-phase portion of the hydroprocessor effluent (based on the weight of the liquid-phase portion of the hydroprocessor effluent), e.g., > 40.0 wt. %, such as in the range of 20.0 wt. % to 70.0 wt. % or in the range of 40.0 wt. % to 60.0 wt. %.
  • hydroprocessed product When the hydroprocessing is operated under the conditions specified in the preceding section utilizing as a feed the specified third mixture (e.g., an SCT stream), hydroprocessed product generally has a density > 0.97 g/cm 3 at 15°C, such as o > 1.00 g/cm 3 at 15°C, and a viscosity ⁇ 90.0 % that of the third mixture's viscosity, e.g., ⁇ 75.0 % that of the third mixture's viscosity. Generally, > 50.0 wt.
  • the hydroprocessed product is in the form of multi-ring aromatic and non- aromatic molecules having a number of carbon atoms > 16 based on the weight of the hydroprocessed product, e.g., > 75.0 wt. %, such as > 90.0 wt. %.
  • > 50.0 wt. % the hydroprocessed product is in the form of multi-ring molecules. These can have, e.g., a number of carbon atoms in the range of from 25 to 40 based on the weight of the hydroprocessed product.
  • At least a portion of the light hydrocarbon mixture and/or at least a portion of the hydroprocessed product can be utilized within the process and/or conducted away for storage or further processing.
  • the relatively low viscosity of the hydroprocessed product compared to that of the third mixture can make it desirable to utilize at least a portion of the hydroprocessed product as a diluent (e.g., a flux) for heavy hydrocarbons, especially those of relatively high viscosity.
  • the hydroprocessed product can substitute for more expensive, conventional diluents.
  • Non-limiting examples of heavy, high-viscosity streams suitable for blending with the hydroprocessed product (or with the entire liquid-phase portion of the hydroprocessor effluent) include one or more of bunker fuel, burner oil, heavy fuel oil (e.g., No. 5 or No. 6 fuel oil), high-sulfur fuel oil, low-sulfur fuel oil, regular-sulfur fuel oil (RSFO), and the like.
  • the hydroprocessed product is utilized in a blend, the blend comprising (a) > 10.0 wt. % of the hydroprocessed product and (b) > 10.0 wt. % of a fuel oil having a sulfur content in the range of 0.5 wt. % to 3.5 wt. and a viscosity in the range of 100 cSt to 500 cSt at 50°C, the weight percents being based the weight of the blend.
  • the hydroprocessed product can be utilized for fluxing and conducting away a high-viscosity bottoms from a vapor-liquid separation device, such as those integrated with a pyro lysis furnace.
  • > 10.0% of the hydroprocessed product e.g., > 50.0%, such as > 75.0%
  • > 10.0% (on a wt. basis) of the bottoms fraction e.g., > 50.0%, such as > 75.0%, in order to lessen the bottom's viscosity.
  • At least a portion of the light hydrocarbon mixture is recycled upstream of the hydroprocessing stage for use as all or a portion of the utility fluid.
  • > 10.0 wt. % of the light hydrocarbon mixture can be utilized as the utility fluid, such as > 90.0 wt. %, based on the weight of the light hydrocarbon mixture.
  • a make-up portion of utility fluid can be provided to the process from another source.
  • low and high boiling-range cuts are separated from at least a portion of the hydroprocessed product, e.g., at a cut point in the range of about 320°C to about 370°C, such as about 334°C to about 340°C.
  • > 40.0 wt. % of the hydroprocessed product is generally contained in the lower-boiling fraction, e.g., > 50.0 wt. %, based on the weight of the hydroprocessed product.
  • At least a portion of the lower-boiling fraction can be utilized as a flux, e.g., for fluxing vapor/liquid separator bottoms, primary fractionator bottoms, etc.
  • At least a portion of the higher-boiling fraction can be utilized as a fuel, for example.
  • the process can further comprise hydrogenating or treating at least a portion of the hydroprocessed product of any the above embodiments to produce a naphthenic lubricating oil.
  • the hydroprocessing is carried out in a fixed bed reactor having an approximately 0.3" ID (inside diameter) stainless tube reactor body and three heating blocks.
  • the reactor was heated by a three-zone furnace.
  • Table 1 shows details of the catalyst used in the experiment. 12.6 g (17.5 cm 3 ) of RT-621, sized to 40-60 mesh, was loaded into the zone of the reactor within the furnace.
  • the unit is pressure tested at 1000 psig (68.9 bar gauge) with molecular nitrogen followed by molecular hydrogen.
  • the details are as follows.
  • Ramp reactor from 1 10°C to 250°C at l°C/min, hold at 250°C for 12 hr.
  • Ramp reactor from 250°C to 340°C at 1°C /min, and hold at 340°C until the pump is empty (duration of about 1.5 hr. + final holding at 340°C).
  • a SCT sample is obtained from a commercial steam cracker primary fractionator bottoms stream. Table 3 lists the typical properties for the SCT sample. Note that the sample contains about 2.2 wt. % of sulfur and a viscosity of 988 cSt at 50°C.
  • Table 3 Summary of properties for SCT feed and hydroprocessed product.
  • TLP total liquid product
  • the hydroprocessed product composition is determined by the combined use of 2D GC and simulated distillation.
  • 2D GC quantified the molecules that boil below roughly 565°C (1050°F) while simulated distillation determined the amount of hydroprocessed product fraction that boils above 565°C (1050°F).
  • Table 4 summarizes the compositional results for two hydroprocessed product samples taken during the run at 8 and 20 days-on- stream in addition to the composition of the feed. "Sats" refers to paraffinic molecules and 565°C+ refers to the amount of hydroprocessed fraction that boils above 565°C (1050°F).
  • the two hydroprocessed product compositions have a viscosity of 5.8 cSt at 50°C for the 8 DOS sample and 12.8 cSt at 50°C for the 20 DOS sample, respectively.
  • the hydroprocessed products have a significant viscosity premium.
  • Hydrocarbon processors typically use expensive streams such as kerojet as flux to blend high viscosity hydrocarbon streams such as vacuum resid to meet fuel oil viscosity spec.
  • the hydroprocessed product into a flux fraction and a heavy bottom fraction, e.g., using fractionation.
  • the viscosity of the flux fraction is set to be equal to that of SCGO while the heavy bottom fraction to be equal to the tar feed viscosity.

Landscapes

  • Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Engineering & Computer Science (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Physics & Mathematics (AREA)
  • Thermal Sciences (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
  • Industrial Gases (AREA)

Abstract

L'invention concerne un produit hydrotraité qui peut être obtenu par un hydrotraitement de goudron, tel qu'un goudron obtenu par pyrolyse d'hydrocarbures. L'invention concerne également des procédés de production d'un tel produit hydrotraité et son utilisation, par exemple en tant que composant de mélange de mazout.
PCT/US2012/053417 2011-08-31 2012-08-31 Produit hydrotraité WO2013033580A2 (fr)

Priority Applications (4)

Application Number Priority Date Filing Date Title
CN201280041813.4A CN103764797B (zh) 2011-08-31 2012-08-31 加氢处理的产物
PCT/US2012/053417 WO2013033580A2 (fr) 2011-08-31 2012-08-31 Produit hydrotraité
CA2843515A CA2843515C (fr) 2011-08-31 2012-08-31 Produit hydrotraite
EP12762463.3A EP2751233B1 (fr) 2011-08-31 2012-08-31 Méthode de production d'un produit hydrotraité

Applications Claiming Priority (7)

Application Number Priority Date Filing Date Title
US201161529588P 2011-08-31 2011-08-31
US201161529565P 2011-08-31 2011-08-31
US61/529,565 2011-08-31
US61/529,588 2011-08-31
US201261657299P 2012-06-08 2012-06-08
US61/657,299 2012-06-08
PCT/US2012/053417 WO2013033580A2 (fr) 2011-08-31 2012-08-31 Produit hydrotraité

Publications (2)

Publication Number Publication Date
WO2013033580A2 true WO2013033580A2 (fr) 2013-03-07
WO2013033580A3 WO2013033580A3 (fr) 2013-04-25

Family

ID=51862039

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2012/053417 WO2013033580A2 (fr) 2011-08-31 2012-08-31 Produit hydrotraité

Country Status (4)

Country Link
EP (1) EP2751233B1 (fr)
CN (1) CN103764797B (fr)
CA (1) CA2843515C (fr)
WO (1) WO2013033580A2 (fr)

Cited By (16)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US8987537B1 (en) 2014-05-22 2015-03-24 Shell Oil Company Fuel compositions
US9057035B1 (en) 2014-02-17 2015-06-16 Shell Oil Company Fuel compositions
WO2015167774A2 (fr) 2014-04-30 2015-11-05 Exxonmobil Chemical Patents Inc Valorisation des produits de pyrolyse d'hydrocarbures
US20150344790A1 (en) * 2014-05-29 2015-12-03 Exxonmobil Chemical Patents Inc. Pyrolysis Tar Upgrading Process
WO2015191236A1 (fr) * 2014-06-13 2015-12-17 Exxonmobil Chemical Patents Inc. Valorisation des hydrocarbures
US9637694B2 (en) 2014-10-29 2017-05-02 Exxonmobil Chemical Patents Inc. Upgrading hydrocarbon pyrolysis products
US9765267B2 (en) 2014-12-17 2017-09-19 Exxonmobil Chemical Patents Inc. Methods and systems for treating a hydrocarbon feed
US9771524B2 (en) 2014-06-13 2017-09-26 Exxonmobil Chemical Patents Inc. Method and apparatus for improving a hydrocarbon feed
WO2018111573A1 (fr) 2016-12-16 2018-06-21 Exxonmobil Chemical Patents Inc. Conversion de goudron de pyrolyse
WO2018111576A1 (fr) 2016-12-16 2018-06-21 Exxonmobil Chemical Patents Inc. Prétraitement de goudron de pyrolyse
WO2018111572A1 (fr) 2016-12-16 2018-06-21 Exxonmobil Chemical Patents Inc. Conversion de goudron de pyrolyse
WO2018111574A1 (fr) 2016-12-16 2018-06-21 Exxonmobil Chemical Patents Inc. Prétraitement de goudron de pyrolyse
WO2018213025A1 (fr) 2017-05-17 2018-11-22 Exxonmobil Chemical Patents Inc. Valorisation de produits de pyrolyse d'hydrocarbures
US10597592B2 (en) 2016-08-29 2020-03-24 Exxonmobil Chemical Patents Inc. Upgrading hydrocarbon pyrolysis tar
US10704001B2 (en) 2017-07-14 2020-07-07 Exxonmobil Research And Engineering Company Multi-stage upgrading pyrolysis tar products
US11401473B2 (en) 2018-08-30 2022-08-02 Exxonmobil Chemical Patents Inc. Process to maintain high solvency of recycle solvent during upgrading of steam cracked tar

Families Citing this family (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
SG11202101186WA (en) 2018-08-22 2021-03-30 Exxonmobil Chemical Patents Inc Self-sulfiding of guard reactor catalyst for solvent assisted tar conversion processes
CN110646556B (zh) * 2019-09-26 2022-03-08 中国神华煤制油化工有限公司 有机样品的成分分析方法

Citations (16)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5169039A (en) 1990-02-28 1992-12-08 Photofinish Cosmetics, Inc. Two-stroke fluid dispenser with actuator-operated valve for controlling fluid flow between internal fluid chamber
US6632351B1 (en) 2000-03-08 2003-10-14 Shell Oil Company Thermal cracking of crude oil and crude oil fractions containing pitch in an ethylene furnace
US7090765B2 (en) 2002-07-03 2006-08-15 Exxonmobil Chemical Patents Inc. Process for cracking hydrocarbon feed with water substitution
US7097758B2 (en) 2002-07-03 2006-08-29 Exxonmobil Chemical Patents Inc. Converting mist flow to annular flow in thermal cracking application
US7138047B2 (en) 2002-07-03 2006-11-21 Exxonmobil Chemical Patents Inc. Process for steam cracking heavy hydrocarbon feedstocks
US7220887B2 (en) 2004-05-21 2007-05-22 Exxonmobil Chemical Patents Inc. Process and apparatus for cracking hydrocarbon feedstock containing resid
US7235705B2 (en) 2004-05-21 2007-06-26 Exxonmobil Chemical Patents Inc. Process for reducing vapor condensation in flash/separation apparatus overhead during steam cracking of hydrocarbon feedstocks
US7244871B2 (en) 2004-05-21 2007-07-17 Exxonmobil Chemical Patents, Inc. Process and apparatus for removing coke formed during steam cracking of hydrocarbon feedstocks containing resids
US7247765B2 (en) 2004-05-21 2007-07-24 Exxonmobil Chemical Patents Inc. Cracking hydrocarbon feedstock containing resid utilizing partial condensation of vapor phase from vapor/liquid separation to mitigate fouling in a flash/separation vessel
US7297833B2 (en) 2004-05-21 2007-11-20 Exxonmobil Chemical Patents Inc. Steam cracking of light hydrocarbon feedstocks containing non-volatile components and/or coke precursors
US7311746B2 (en) 2004-05-21 2007-12-25 Exxonmobil Chemical Patents Inc. Vapor/liquid separation apparatus for use in cracking hydrocarbon feedstock containing resid
US7312371B2 (en) 2004-05-21 2007-12-25 Exxonmobil Chemical Patents Inc. Steam cracking of hydrocarbon feedstocks containing non-volatile components and/or coke precursors
US7351872B2 (en) 2004-05-21 2008-04-01 Exxonmobil Chemical Patents Inc. Process and draft control system for use in cracking a heavy hydrocarbon feedstock in a pyrolysis furnace
US7488459B2 (en) 2004-05-21 2009-02-10 Exxonmobil Chemical Patents Inc. Apparatus and process for controlling temperature of heated feed directed to a flash drum whose overhead provides feed for cracking
US7820035B2 (en) 2004-03-22 2010-10-26 Exxonmobilchemical Patents Inc. Process for steam cracking heavy hydrocarbon feedstocks
US8083931B2 (en) 2006-08-31 2011-12-27 Exxonmobil Chemical Patents Inc. Upgrading of tar using POX/coker

Family Cites Families (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3817853A (en) * 1972-05-30 1974-06-18 Union Oil Co Coking of pyrolysis tars
US4225415A (en) * 1979-08-10 1980-09-30 Occidental Petroleum Corporation Recovering hydrocarbons from hydrocarbon-containing vapors
CN100503789C (zh) * 2007-04-24 2009-06-24 中国石油化工集团公司 一种结焦抑制剂及其制备方法和应用
CN101629107A (zh) * 2008-09-22 2010-01-20 何巨堂 一种含重馏分的煤焦油的加氢改质方法
US8197668B2 (en) * 2009-07-09 2012-06-12 Exxonmobil Chemical Patents Inc. Process and apparatus for upgrading steam cracker tar using hydrogen donor compounds
CN101864327A (zh) * 2010-04-29 2010-10-20 长岭炼化岳阳工程设计有限公司 一种煤焦油加氢改质的方法

Patent Citations (17)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5169039A (en) 1990-02-28 1992-12-08 Photofinish Cosmetics, Inc. Two-stroke fluid dispenser with actuator-operated valve for controlling fluid flow between internal fluid chamber
US6632351B1 (en) 2000-03-08 2003-10-14 Shell Oil Company Thermal cracking of crude oil and crude oil fractions containing pitch in an ethylene furnace
US7090765B2 (en) 2002-07-03 2006-08-15 Exxonmobil Chemical Patents Inc. Process for cracking hydrocarbon feed with water substitution
US7097758B2 (en) 2002-07-03 2006-08-29 Exxonmobil Chemical Patents Inc. Converting mist flow to annular flow in thermal cracking application
US7138047B2 (en) 2002-07-03 2006-11-21 Exxonmobil Chemical Patents Inc. Process for steam cracking heavy hydrocarbon feedstocks
US7578929B2 (en) 2002-07-03 2009-08-25 Exxonmoil Chemical Patents Inc. Process for steam cracking heavy hydrocarbon feedstocks
US7820035B2 (en) 2004-03-22 2010-10-26 Exxonmobilchemical Patents Inc. Process for steam cracking heavy hydrocarbon feedstocks
US7247765B2 (en) 2004-05-21 2007-07-24 Exxonmobil Chemical Patents Inc. Cracking hydrocarbon feedstock containing resid utilizing partial condensation of vapor phase from vapor/liquid separation to mitigate fouling in a flash/separation vessel
US7244871B2 (en) 2004-05-21 2007-07-17 Exxonmobil Chemical Patents, Inc. Process and apparatus for removing coke formed during steam cracking of hydrocarbon feedstocks containing resids
US7297833B2 (en) 2004-05-21 2007-11-20 Exxonmobil Chemical Patents Inc. Steam cracking of light hydrocarbon feedstocks containing non-volatile components and/or coke precursors
US7311746B2 (en) 2004-05-21 2007-12-25 Exxonmobil Chemical Patents Inc. Vapor/liquid separation apparatus for use in cracking hydrocarbon feedstock containing resid
US7312371B2 (en) 2004-05-21 2007-12-25 Exxonmobil Chemical Patents Inc. Steam cracking of hydrocarbon feedstocks containing non-volatile components and/or coke precursors
US7351872B2 (en) 2004-05-21 2008-04-01 Exxonmobil Chemical Patents Inc. Process and draft control system for use in cracking a heavy hydrocarbon feedstock in a pyrolysis furnace
US7488459B2 (en) 2004-05-21 2009-02-10 Exxonmobil Chemical Patents Inc. Apparatus and process for controlling temperature of heated feed directed to a flash drum whose overhead provides feed for cracking
US7235705B2 (en) 2004-05-21 2007-06-26 Exxonmobil Chemical Patents Inc. Process for reducing vapor condensation in flash/separation apparatus overhead during steam cracking of hydrocarbon feedstocks
US7220887B2 (en) 2004-05-21 2007-05-22 Exxonmobil Chemical Patents Inc. Process and apparatus for cracking hydrocarbon feedstock containing resid
US8083931B2 (en) 2006-08-31 2011-12-27 Exxonmobil Chemical Patents Inc. Upgrading of tar using POX/coker

Non-Patent Citations (1)

* Cited by examiner, † Cited by third party
Title
"The Merck Index", 1996, MERCK & CO., INC., article "Periodic Chart of the 20 Elements"

Cited By (32)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9057035B1 (en) 2014-02-17 2015-06-16 Shell Oil Company Fuel compositions
US10577551B2 (en) 2014-02-17 2020-03-03 Shell Oil Company Fuel compositions
US9487718B2 (en) 2014-02-17 2016-11-08 Shell Oil Company Fuel compositions
WO2015167774A2 (fr) 2014-04-30 2015-11-05 Exxonmobil Chemical Patents Inc Valorisation des produits de pyrolyse d'hydrocarbures
US9777227B2 (en) 2014-04-30 2017-10-03 Exxonmobil Chemical Patents Inc. Upgrading hydrocarbon pyrolysis products
US8987537B1 (en) 2014-05-22 2015-03-24 Shell Oil Company Fuel compositions
US10457881B2 (en) 2014-05-22 2019-10-29 Shell Oil Company Fuel compositions
US9499758B2 (en) 2014-05-22 2016-11-22 Shell Oil Company Fuel compositions
US20150344790A1 (en) * 2014-05-29 2015-12-03 Exxonmobil Chemical Patents Inc. Pyrolysis Tar Upgrading Process
US10000710B2 (en) * 2014-05-29 2018-06-19 Exxonmobil Chemical Patents Inc. Pyrolysis tar upgrading process
US9771524B2 (en) 2014-06-13 2017-09-26 Exxonmobil Chemical Patents Inc. Method and apparatus for improving a hydrocarbon feed
WO2015191236A1 (fr) * 2014-06-13 2015-12-17 Exxonmobil Chemical Patents Inc. Valorisation des hydrocarbures
US10518234B2 (en) 2014-06-13 2019-12-31 Exxonmobil Chemical Patents Inc. Hydrocarbon upgrading
US10035961B2 (en) 2014-06-13 2018-07-31 Exxonmobil Chemical Patents Inc. Hydrocarbon upgrading
US9637694B2 (en) 2014-10-29 2017-05-02 Exxonmobil Chemical Patents Inc. Upgrading hydrocarbon pyrolysis products
US9765267B2 (en) 2014-12-17 2017-09-19 Exxonmobil Chemical Patents Inc. Methods and systems for treating a hydrocarbon feed
US10597592B2 (en) 2016-08-29 2020-03-24 Exxonmobil Chemical Patents Inc. Upgrading hydrocarbon pyrolysis tar
US11162037B2 (en) 2016-12-16 2021-11-02 Exxonmobil Chemical Patents Inc. Pyrolysis tar conversion
US11060039B2 (en) 2016-12-16 2021-07-13 Exxonmobil Chemical Patents Inc. Pyrolysis tar pretreatment
US11530361B2 (en) 2016-12-16 2022-12-20 Exxonmobil Chemical Patents Inc. Pyrolysis tar conversion
WO2018111572A1 (fr) 2016-12-16 2018-06-21 Exxonmobil Chemical Patents Inc. Conversion de goudron de pyrolyse
WO2018111576A1 (fr) 2016-12-16 2018-06-21 Exxonmobil Chemical Patents Inc. Prétraitement de goudron de pyrolyse
WO2018111573A1 (fr) 2016-12-16 2018-06-21 Exxonmobil Chemical Patents Inc. Conversion de goudron de pyrolyse
US11168268B2 (en) 2016-12-16 2021-11-09 Exxonmobil Chemical Patents Inc. Pyrolysis tar conversion
US10968404B2 (en) 2016-12-16 2021-04-06 Exxonmobil Chemical Patents Inc. Pyrolysis tar upgrading
US10072218B2 (en) 2016-12-16 2018-09-11 Exxon Mobil Chemical Patents Inc. Pyrolysis tar conversion
US10988698B2 (en) 2016-12-16 2021-04-27 Exxonmobil Chemical Patents Inc. Pyrolysis tar pretreatment
WO2018111574A1 (fr) 2016-12-16 2018-06-21 Exxonmobil Chemical Patents Inc. Prétraitement de goudron de pyrolyse
WO2018213025A1 (fr) 2017-05-17 2018-11-22 Exxonmobil Chemical Patents Inc. Valorisation de produits de pyrolyse d'hydrocarbures
US10344222B2 (en) 2017-05-17 2019-07-09 Exonmobil Chemical Patents Inc. Upgrading hydrocarbon pyrolysis products
US10704001B2 (en) 2017-07-14 2020-07-07 Exxonmobil Research And Engineering Company Multi-stage upgrading pyrolysis tar products
US11401473B2 (en) 2018-08-30 2022-08-02 Exxonmobil Chemical Patents Inc. Process to maintain high solvency of recycle solvent during upgrading of steam cracked tar

Also Published As

Publication number Publication date
WO2013033580A3 (fr) 2013-04-25
CA2843515C (fr) 2016-11-01
CA2843515A1 (fr) 2013-03-07
CN103764797B (zh) 2016-04-06
CN103764797A (zh) 2014-04-30
EP2751233B1 (fr) 2016-09-14
EP2751233A2 (fr) 2014-07-09

Similar Documents

Publication Publication Date Title
CA2843515C (fr) Produit hydrotraite
US9102884B2 (en) Hydroprocessed product
US9777227B2 (en) Upgrading hydrocarbon pyrolysis products
US9090836B2 (en) Upgrading hydrocarbon pyrolysis products
EP2751234B1 (fr) Valorisation de produits de pyrolyse d'hydrocarbures par hydrotraitement
US9637694B2 (en) Upgrading hydrocarbon pyrolysis products
US20140061100A1 (en) Process for Reducing the Asphaltene Yield and Recovering Waste Heat in a Pyrolysis Process by Quenching with a Hydroprocessed Product
US20140061096A1 (en) Upgrading Hydrocarbon Pyrolysis Products by Hydroprocessing
US9090835B2 (en) Preheating feeds to hydrocarbon pyrolysis products hydroprocessing
US10597592B2 (en) Upgrading hydrocarbon pyrolysis tar
CN110869473A (zh) 多级改质热解焦油产品
US11352576B2 (en) Process for C5+ hydrocarbon conversion
CA2845002C (fr) Prechauffage des charges d'alimentation pour hydrotraitement des produits de pyrolyse d'hydrocarbures
Metecan et al. Naphtha derived from polyolefins
US11473024B2 (en) Processing pyrolysis tar particulates
WO2019164673A1 (fr) Procédés de pyrolyse d'hydrocarbures
WO2013033575A1 (fr) Procédé de réduction de la production d'asphaltènes et de récupération de la chaleur des déchets d'un processus de pyrolyse par refroidissement rapide au moyen d'un produit hydrotraité
US11236276B2 (en) Self-sulfiding of guard reactor catalyst for solvent assisted tar conversion processes
CN115667466B (zh) 焦油加氢处理用流体

Legal Events

Date Code Title Description
WWE Wipo information: entry into national phase

Ref document number: 201280041813.4

Country of ref document: CN

ENP Entry into the national phase

Ref document number: 2843515

Country of ref document: CA

NENP Non-entry into the national phase

Ref country code: DE

REEP Request for entry into the european phase

Ref document number: 2012762463

Country of ref document: EP

121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 12762463

Country of ref document: EP

Kind code of ref document: A2

点击 这是indexloc提供的php浏览器服务，不要输入任何密码和下载