WO2013033575A1 - 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 - Google Patents

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 Download PDF

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WO2013033575A1
WO2013033575A1 PCT/US2012/053408 US2012053408W WO2013033575A1 WO 2013033575 A1 WO2013033575 A1 WO 2013033575A1 US 2012053408 W US2012053408 W US 2012053408W WO 2013033575 A1 WO2013033575 A1 WO 2013033575A1
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mixture
tar
hydroprocessing
weight
stream
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PCT/US2012/053408
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English (en)
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James R. Lattner
Linelle F. JACOB
Ananthakrishnan BHASKER
Keith G. REED
Teng Xu
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Exxonmobil Chemical Patents Inc.
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Publication of WO2013033575A1 publication Critical patent/WO2013033575A1/fr

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    • 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
    • C10G9/00—Thermal non-catalytic cracking, in the absence of hydrogen, of hydrocarbon oils
    • C10G9/34—Thermal non-catalytic cracking, in the absence of hydrogen, of hydrocarbon oils by direct contact with inert preheated fluids, e.g. with molten metals or salts
    • C10G9/36—Thermal non-catalytic cracking, in the absence of hydrogen, of hydrocarbon oils by direct contact with inert preheated fluids, e.g. with molten metals or salts with heated gases or vapours
    • 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
    • C10G2300/80—Additives

Definitions

  • the invention relates to process for reducing the asphaltene yield and recovering high level waste heat in a pyrolysis process by quenching the pyrolysis effluent hydroprocessed pyrolysis product.
  • asphaltene molecules are believed to be formed from smaller reactive molecules downstream of the pyrolysis reactor.
  • the highest boiling molecules condense first through the cooling steps.
  • the growth of asphaltene molecules is believed to depend on the residence time and temperature history of the condensed molecules in the liquid phase as they proceed through the various cooling steps.
  • the effluent cooling steps are staged to allow separation of the liquid products into various cuts, or boiling ranges of the streams (Refer to Figure 1).
  • the lightest liquid product stream is steam-cracked naphtha (hereinafter SCN).
  • SCN steam-cracked naphtha
  • SCGO steam- cracked gas oil
  • the next heavier cut is quench oil, and the heaviest liquid cut is called steam-cracked tar (SCT).
  • SCT steam-cracked tar
  • the asphaltenes are primarily contained in the SCT cut.
  • the quench oil cut is commonly recirculated and contacted with pyrolysis effluent to reduce the temperature of the effluent, or quench it.
  • This direct-contact quenching step has been found to be effective at minimizing the fouling problems encountered when cooling and condensing the highest boiling molecules from the pyrolysis effluent.
  • the fouling rates of the cooling surfaces may be unacceptably high.
  • the first molecules to condense are viscous, causing them to adhere to the cooling surfaces and suffer increased residence time at relatively high temperature eventually causing them to convert to solid carbonaceous material or coke. Because of the problem associated with condensing the heavy, viscous molecules on heat transfer surfaces, the amount of high level heat that can be recovered in a heat exchanger on the effluent of the pyrolysis reactor/furnace is limited, particularly when the pyrolysis feedslate comprises heavy liquids such as resid or crude.
  • the flow rate of quench oil is controlled to achieve a desired temperature of the effluent/quench oil mix, which is typically 250°C-320°C. At this mixture temperature, a small amount of the pyrolysis effluent is a liquid and is separated from the vapor and withdrawn from the process as the steam-cracked tar cut.
  • the SCT cut point temperature is selected so that it is neither too high, which can result in unacceptable fouling rates of the equipment and increased rates of asphaltene formation, nor too low, which can unnecessarily increase the yield of the SCT product (which is generally the lowest-valued product).
  • the propensity of the tar molecules to produce asphaltenes can vary, and is believed to be a function of feedslate, severity of the pyrolysis reaction, and perhaps other factors that are not well understood. But regardless of this propensity, all tar cuts appear to "grow" asphaltenes as a function of the temperature and residence time history of the condensed molecules as they proceed through the quenching process. Processes are designed to minimize the residence time of the condensed SCT at the highest temperatures to minimize the asphaltene concentration in the SCT product. Even with these designs, the concentration of asphaltenes can be 10-50% in the tar cut. Samples captured and quickly quenched at the pyrolysis reactor effluent typically contain on the order of 5% asphaltenes.
  • 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 quenching process, comprising:
  • the invention relates to a hydrocarbon quenching process, comprising:
  • quench fluid comprises > 5.0 wt. % of the heavy hydroprocessor product based on the weight of the quench fluid and the utility fluid comprises > 5.0 wt. % of the light hydroprocessor product based on the weight of the quench fluid.
  • the invention relates to a hydrocarbon quenching process, comprising:
  • the invention includes one or more of the following optional features: (i) the utility fluid comprises > 5.0 wt. % of the heavy hydroprocessor product based on the weight of the utility fluid; (ii) the pyrolyzing is steam cracking; (iii) the tar stream comprises (a) > 10.0 wt.
  • the hydroprocessing conditions include one or more of a temperature in the range of 350°C to 450°C, a pressure in the range of 15 bar (absolute) to 135 bar (absolute), a space velocity (LHSV) in the range of 0.2 to 4, and a hydrogen consumption rate of 53 S m 3 / m 3 to 445 S m 3 / m 3 (where the denominator is based on per volume of tar).
  • Figure 1 schematically illustrates a typical steam pyrolysis quench system.
  • Figures 2-4 schematically illustrates quench systems according to several embodiments of the invention. DETAILED DESCRIPTION
  • the invention is based in part on the development of a conversion process where the effluent from a steam pyro lysis reactor/furnace is contacted with a quench oil, and where the quench oil is comprised of a stream that is recycled from the process, wherein this stream: a) is taken as a cut from the process at a temperature greater than 240°C, and b) at least a portion of this cut is hydroprocessed at a specified set of conditions.
  • the heaviest liquid product is withdrawn from the cut taken from the process at a temperature greater than 400°C.
  • the pyrolysis effluent is contacted with at least partially-hydrotreated tar to obtain a mixture temperature of greater than 400°C, and the mixture is separated into a vapor and a liquid portion, where the liquid portion is the heavy tar product (SCT) cut, and the vapor is cooled in a heat exchanger to recover the high level waste heat.
  • SCT heavy tar product
  • the hydroprocessed portion of the quench stream generally is at least 10%, preferably at least 20%, of the total quench stream, on a weight basis.
  • non-hydroprocessed cuts contain the same types of reactive olefinic species as in the tar, the use of non-hydroprocessed oils for quenching does not serve to reduce the rate of asphaltene growth in the steam-cracked tar cut.
  • FIG. 1 schematically illustrates a typical steam pyrolysis quench system.
  • a hydrocarbon feed 10 and steam 11 mixture is fed to a pyrolysis reactor/furnace 110.
  • the reaction mixture is quickly heated to a temperature where pyrolysis occurs, for example around 820°C.
  • the hot pyrolysis effluent 13 is quickly quenched from an initial temperature Ti, e.g., in the range of 600°C to 850°C, to a final temperature, e.g., in the range of 250°C to 500°C to slow down the reactions that lead to excessive coke and gas formation.
  • Quench oil 20 is mixed with the hot pyrolysis effluent 13 to reduce the temperature, e.g., Ti _ T 2 > 100°C, such as > 150°C, to create a two-phase mixture 14, where the liquid phase comprises the tar molecules.
  • the mixture 14 flows to the Primary Fractionator distillation column 130, where heat is removed and various liquid product cuts are taken. Heat is typically removed in various stages through side pumparound loops 132, 133 and 134, 135 using a combination of pumps and coolers, as shown in the Figures.
  • the staging of the heat removal steps allows some of the heat to be removed at a higher level, thus improving the energy efficiency of the process.
  • the heaviest liquid cut, steam-cracked tar 36 can be removed, e.g., as a 300°C cut.
  • the tar cut is conducted away via line 30 following pump 131.
  • Quench oil product 21 can be removed, e.g., as a 180°C cut, steam- cracked gas oil 22, e.g., as a 138°C cut, and steam-cracked naphtha 23, e.g., as an overhead distillate cut.
  • a vapor stream, generally comprising light gas (e.g., molecular hydrogen, water, methane, etc.) can be conducted away via line 26.
  • the mixing of the hot pyrolysis effluent 13 and quench streams 14 results in a two-phase mixture having a temperature of about 300°C.
  • the condensed liquid phase contains the reactive tar molecules, and the asphaltenes rapidly grow in this hot condensed state, and continue to grow until the withdrawn tar stream is cooled.
  • a heat exchanger is placed at the effluent of the reactor/furnace 13 which cools the effluent somewhat prior to contacting with the quench oil 20.
  • This exchanger is close-coupled to the furnace outlet transfer line, and is therefore referred to as a "Transfer Line Exchanger", or TLE.
  • TLE Transfer Line Exchanger
  • the amount of cooling that can be achieved is limited due to the presence of high-boiling molecules; too much cooling results in the condensation of the high-boiling molecules, which lead to rapid fouling of the exchanger and shortened run lengths between de-coking steps.
  • the TLE cooling limit before excessive fouling occurs depends on factors such as feedslate properties and cracking severity. In typical example this limit is approximately 620°C.
  • the 620°C effluent is then contacted with the 180°C quench oil 20 similar to what is shown in Figure 1.
  • the cooling duty required in the Primary Fractionator side pumparound loops is reduced by the heat removed in the TLE, and the required flow of quench oil 20 to achieve a 300°C quench temperature is less, but otherwise the two configurations result in substantially equivalent product cuts.
  • the presence or absence of a TLE on the pyrolysis effluent does not impact the benefits of the present invention, to be described in Examples 2, 3, and 4. [0023] Note that in either configuration of Example 1 (e.g., with or without a TLE) the quench oil is taken as a cut at about 180°C.
  • Example 2 is an embodiment of the hydroprocessed tar quench process, shown in Figure 2. Notable in this configuration is the hydroprocessor 140. Treat gas (comprising molecular hydrogen) is conducted to stage 140 via line 12. The product cuts on the Primary Fractionator 130 are the same as in Example 1, however the quench fluid is the 300°C tar cut, rather than the 180°C quench oil cut. A first portion of the tar cut is conducted to quench line 20 via line 18, and a second portion of the tar quench oil, which has been hydroprocessed as shown in Figure 2, is conducted to quench line 20 via line 19. The hydroprocessing of the tar renders the reactive molecules inert to further growth of asphaltenes.
  • Treat gas comprising molecular hydrogen
  • the inert molecules have similar boiling points of the tar molecules condensed by the quench fluid, they serve to dilute the reactive tar molecules and reduce the growth of asphaltenes. Furthermore, the lower asphaltene content of the tar feed to the hydroprocessor makes the hydroprocessing step easier, as the presence of asphaltenes in the hydroprocessor feed can lead to coking and plugging problems in the hydroprocessing process. Note that in this embodiment, the quench oil cut is no longer used as quench oil, but the name has been kept because the boiling ranges of the molecules are the same as in the base case. Instead this material is removed as quench oil product 21.
  • Example 2 shows that only a fraction of the quench oil flow needs to be hydroprocessed to achieve a mixture that is mostly hydroprocessed.
  • Example 3 is an embodiment that takes the tar product drawoff 32 upstream of the tar hydroprocessor following pump 141, as shown in Figure 3. This configuration has the potential to reduce the complexity of the tar hydroprocessing step, as the hydroprocessor in this example does not need to produce a finished product.
  • the tar product is withdrawn from the same part of the process as in the typical example shown in Figure 1. If, e.g., the flow rate through the hydroprocessor is twice the tar product flow rate, then the tar product contains 66.7% hydroprocessed molecules according to Equation (1) above. This level of hydroprocessing is believed to be sufficient for reduced asphaltene content and reduced tar viscosity.
  • Example 4 is an embodiment where the process configuration takes additional advantage from the hydroprocessed tar quench oil.
  • the high-boiling inert quench fluid allows a heavier tar cut to be removed from the process, shown in Figure 4 owing to the dilution of the higher boiling tar molecules from the higher boiling inert quench fluid. This reduces the yield of the tar cut, from both the higher temperature cut point as well as from the reduced growth of asphaltenes (owing to the dilution from the inert quench).
  • This liquid is separated from the vapor in the tar knockout separator 120 by way of pump
  • a vapor phase is conducted away from knockout 120 via line 15, and then cooled, e.g., in a transfer line heat exchanger 125, from temperature T2 to a third temperature T 3 .
  • T2 - T 3 is generally greater than or equal to 50.0°C.
  • the cooled vapor stream is conducted away from exchanger 125 via line 16 to fractionator 130.
  • steam is conducted away from exchanger 125 via line
  • the light tar product 37 is virtually free of asphaltene molecules, as these have been separated in the tar knockout separator 120.
  • the absence of asphaltenes in the light tar 36 makes for a low viscosity and also makes it compatible with typical fuel oils, greatly increasing its value over tar products containing asphaltenes.
  • the light tar product withdrawal 37 is shown as a dashed line in Figure 4, because simulations show that, optionally, the light tar 36 stream can essentially be recycled to extinction, with all of these molecules eventually exiting as either heavy tar 34 or quench oil product 21.
  • the heavy tar product 34 will have very poor fuel blending qualities, as it will be extremely viscous and incompatible with typical fuel oils. The quality of the heavy tar can be greatly improved if a portion of it is recycled through the Hydroprocessor or hydroprocessed in a second hydroprocessor (not shown). Upon hydroprocessing using the prescribed conditions, it has been found that asphaltene molecules can be broken down into smaller molecules, as well as rendering them inert for growth back into asphaltenes. The ratio of heavy tar flow rate 35 sent to the hydroprocessor to the flow rate of heavy tar product 34 can be adjusted in order to achieve a heavy tar product that meets requirements for the chosen disposition of the heavy tar.
  • Equation (1) The requirement my simply be a viscosity specification that allows the stream to be pumped to a disposition, for example to partial oxidation.
  • the relationship shown in Equation (1) applies in this case as well; for example a ratio of 1 : 1 for the hydroprocessed flow rate relative to the product flow rate will achieve a heavy tar product 37 that is 50% (by mass) hydroprocessed.
  • 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.
  • the utility fluid comprises the hydroprocessed tar that is recycled through the quench system.
  • a supplemental utility fluid can be provided as well. This is not explicitly shown in Figures 2, 3, and 4.
  • the supplemental utility fluid would be circulated inside the hydroprocessor 140, such that it contacts the hydroprocessing catalyst in a mixture with the feed to the hydroprocessor. The required characteristics of the utility fluid are discussed below.
  • 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).
  • 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 Ci5.
  • TH TH
  • Ty Heavies means a product of hydrocarbon pyrolysis, the TH having an atmospheric boiling point >
  • 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
  • the TH can include high-molecular weight molecules
  • asphaltenes e.g., MW > 600
  • asphaltenes e.g., MW > 600
  • asphaltenes e.g., MW > 600
  • asphaltenes e.g., MW > 600
  • asphaltenes e.g., MW > 600
  • asphaltenes e.g., MW > 600
  • asphaltenes e.g., MW > 600
  • asphaltenes e.g., MW > 600
  • asphaltenes e.g., MW > 600
  • asphaltenes e.g., MW > 600
  • asphaltenes e.g., MW > 600
  • 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.
  • relatively low molecular-weight alkanes and/or alkenes e.g., Ci to C3 alkanes and/or alkenes
  • C5 and/or Ce cycloparaffinic rings e.g., C5 and/or Ce cycloparaffinic rings
  • thiophenic rings e.g., > 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 6
  • 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.
  • conventional TH conversion suffers from severe mass-transport limitations, which result in a high selectivity for TH conversion to coke.
  • 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 NMR 13 C is substantially greater than that of resid.
  • the amount of aromatic carbon in SCT is 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.
  • 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.
  • 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 aliphatic carbon and % carbon in long chains is substantially lower in SCT compared to resid.
  • 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 - 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 (e.g., a tar stream) comprising > 90.0 wt.
  • 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 > 65.0 wt. %.
  • the hydrocarbon can comprise, e.g., one or more of light hydrocarbons such as methane, ethane, propane, butane, etc.
  • 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 to 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 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 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 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
  • Such 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. 7, 138,047; 7,090,765; 7,097,758; 7,820,035; 7,31 1,746;
  • Suitable vapor/liquid separation devices are also disclosed in U.S. Patent Nos. 6,632,351 and 7,578,929, which are incorporated by reference herein in their entirety.
  • 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. % based on the weight of the first mixture's hydrocarbon of one or more of waxy residues, atmospheric residues, naphtha, residue admixtures, or crude oil.
  • the diluent comprises, e.g., > 95.0 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, as has been shown in Figures 1, 2, 3, and 4.
  • 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).
  • the quench liquid comprises hydroprocessed tar according to the aforementioned embodiments of the invention.
  • a separation stage is generally utilized downstream of the pyro lysis 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 tar stream can be separated from the second mixture, with the 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 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 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 tar stream can comprise TH aggregates.
  • the tar stream comprises > 50.0 wt. % of the second mixture's TH aggregates based on the weight of the second mixture's TH aggregates.
  • the tar stream can comprise > 90.0 wt. % of the second mixture's TH aggregates based on the weight of the second mixture's TH aggregates.
  • At least a portion of the tar stream is generally conducted away from the separation stage for hydroprocessing of the tar stream in the presence of 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 is utilized in hydroprocessing the tar stream, e.g., for effectively increasing run-length during hydroprocessing and improving the properties of the hydroprocessed product.
  • 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 Resonace ("NMR").
  • NMR Nuclear Magnetic Resonace
  • the utility fluid can comprise > 50.0 wt. % of the liquid phase, such as > 75.0 wt. %, or > 95.0 wt. %, or even > 99.0 wt. % based on the weight of the utility fluid.
  • the utility fluid generally comprises a portion of the liquid phase of the hydroprocessed product, effectively being recycled as a quench fluid upstream of the hydroprocessing.
  • the remainder of the liquid phase of the hydroprocessed product may be conducted away from the process and optionally used as a low sulfur fuel oil blend component.
  • the hydroprocessed product 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 to be used as the utility fluid.
  • the liquid phase of the hydroprocessed product may comprise > 90.0 wt.
  • the liquid phase comprises > 90.0 wt. % of the hydroprocessed product's molecules based on the weight of the hydroprocessed product having an atmospheric boiling point > 65.0°C, > 150.0°C, > 260.0°C.
  • the total liquid phase of the hydroprocessed product 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 > 300°C that were present in the liquid phase.
  • the utility fluid comprises 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 hydroprocessed product (recycled in the quench fluid) can be augmented or replaced by supplemental utility fluids that have an ASTM D86 10% distillation point > 60°C, e.g., > 120°C, > 140°C, such as > 150°C and/or an ASTM D86 90% distillation point ⁇ 360°C, e.g., ⁇ 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 C1-C6 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., methylnaphthalenes), tetralins, or alkyltetralins (e.g., methyltetralins).
  • the supplemental utility fluid comprises ⁇ 10.0 wt. % of ring compounds with C1-C6 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.
  • the 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 re-cycling a portion of the hydroprocessed product 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 > 70.0 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. % of ring compounds with C1-C6 sidechains having alkenyl functionality, the weight percents being based on the weight of the utility fluid.
  • 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. % to about 80.0 wt. % of the utility fluid, or (ii) from about 40.0 wt. % to about 90.0 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 amount of hydroprocessed tar (as determined from equation (1)) that is generally present in the quench fluid is an appropriate amount for serving as the utility fluid during the hydroprocessing.
  • an amount of hydroprocessed tar in the range of about 20.0 wt. % to about 95.0 wt. % based on the weight of the quench fluid is suitable, also suitable as (and serves as) the utility fluid during hydroprocessing.
  • the amount of hydroprocessed tar can be, e.g., in the range of about 40.0 wt. % to about 90.0 wt. %, such as in the range of 45.0 wt. % to 70.0 wt. %, based on the weight of the quench fluid.
  • 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. [0064] Conventional 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).
  • 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. Typically, such 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,
  • 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 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 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 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 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
  • Liquid hourly space velocity (LHSV) of the combined diluent-tar stream will generally range from 0.1 h 1 to 30 h or 0.4 h 1 to 25 If 1 , or 0.5 If 1 to 20 If 1 . In some embodiments, 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 ⁇ 2.5 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, or 20 bar to 120 bar, or 21 bar to 100 bar, a space velocity in the range of 0.1 to 5.0, and a molecular hydrogen consumption rate (per volume of tar) 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).
  • 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 270 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%.
  • SCT 1 having the properties set out in Table 1, is obtained from primary fractionator bottoms, the primary fractionator being located downstream of a pyrolysis furnace.
  • the SCT is combined with a utility fluid comprising > 98.0 wt. % of trimethylbenzene to produce a mixture comprising 60.0 wt. % of the SCT and 40.0 wt. % of the utility fluid based on the weight of the mixture.
  • a stainless steel fixed-bed reactor is utilized for hydroprocessing the SCT 1 -utility fluid mixture, the reactor having an inside diameter of 7.62 mm and three heating blocks.
  • the reactor is heated by a three-zone furnace.
  • the reactor's central portion was loaded with 12.6 grams of conventional C0-M0/AI2O 3 residfining catalyst, RT-621, sized to 40-60 mesh.
  • Reactor zones on either side of the central zone are loaded with 80-100 mesh silicon carbide.
  • the reactor is pressure tested at 68 bar (absolute) using molecular nitrogen, followed by molecular hydrogen.
  • 200 cm 3 of a sulfiding solution is gradually introduced into the reactor during the following time intervals.
  • the sulfiding solution comprises 80 wt. % of a 130N lubricating oil basestock and 20 wt. % of ethyldisulfide based on the weight of the sulfiding solution.
  • the sulfiding solution has a sulfur content of 0.324 moles of sulfur per 100 cm 3 of sulfiding solution. Initially, the sulfiding solution is introduced at a rate of 60 cm 3 /hr at a pressure of 51 bar (absolute) and a temperature of 25°C. After about one hour the rate is reduced to 2.5 cm 3 per hour and molecular hydrogen is introduced at a rate of 20 standard cm 3 per minute while exposing the catalyst to a temperature of 25°C.
  • the catalyst After introducing the molecular hydrogen, the catalyst is exposed to an increasing temperature at a rate of 1°C per minute, until a temperature of 1 10°C is achieved, and then maintaining the 1 10°C temperature for one hour. The catalyst is again exposed to an increasing temperature at a rate of 1°C per minute until a temperature of 250°C is achieved, and then maintaining the 250°C temperature for 12 hours. The catalyst is yet again exposed to an increasing temperature at a rate of 1°C per minute until a temperature of 340°C is achieved, and then maintaining the 340°C temperature until all of the 200 cm 3 of sulfiding solution is consumed, i.e., sulfiding solution consumption being measured from the start of sulfiding.
  • the SCT 1 -utility fluid mixture is introduced at a rate of 6.0 cmVhr (0.34 LHSV).
  • the reactor temperature is increased at a rate of 1°C per minute until a temperature in the range of 375°C to 425°C is achieved.
  • the mixture and sulfided catalyst are exposed to a temperature in the range of 375°C to 425°C, a pressure in the range of 51 bar (absolute) to 82 bar (absolute), and a molecular hydrogen flow rate of 54 cm 3 /min (3030 SCF/B).
  • the hydroprocessing is carried out for 80 days, the conversion of the SCT's molecules having an atmospheric boiling point > 565°C is constant at about 60% (wt. basis) over the 80 day period, indicating no significant catalyst coking.
  • the substantially constant molecular hydrogen consumption rate of 195 S m 3 /m 3 (within about +/- 10%) over the 80 day period is indicative of a relatively low-level of SCT hydrogenation.
  • the amount of hydrogen consumption would have been much more than 195 S m 3 /m 3 if significant aromatics hydrogenation occurs.
  • TLP total liquid product
  • Rotary evaporation is utilized to remove from the TLP molecules having an atmospheric boiling point ⁇ 300.0°C, such as the trimethylbenzene solvent.
  • the remainder of the TLP after rotary evaporation separation (the upgraded SCT) is analyzed for sulfur content and viscosity for comparison with the SCT-1 feed.
  • results of these analysis show that the upgraded SCT samples contain 0.06 wt. % sulfur (eighth day sample) and 0.3 wt. % sulfur (twentieth day sample), which amounts are much less than the 2.18 wt. % sulfur of the SCT-1 feed.
  • the results also show a significant kinetic viscosity improvement of 5.8 cSt at 50°C (eighth day sample) and 12.8 cSt at 50°C (twentieth day sample) over the SCT-1 value of 988 cSt at 50°C.
  • SCT 2 40.0 wt. % of second SCT sample (SCT 2, from Table 1) is combined with 60.0 wt. % of the utility fluid utilized in Example 5 to produce an SCT -utility fluid mixture.
  • the mixture was hydrotreated in reactor that is substantially similar to the one utilized in Example 5, utilizing substantially the same catalyst as in Example 5.
  • the catalyst is subjected to substantially the same sulfiding treatment as in Example 5, and the hydroprocessing conditions are also substantially the same.
  • the hydroprocessing is conducted for > 30 days without significant catalyst deactivation. This example demonstrates that SCT hydroprocessing can be utilized even in the case of SCT having a kinematic viscosities > 7000 cSt at 50°C.
  • SCT 1 is distilled to produce a bottoms fraction comprising 50 wt. % of the SCT- 1, based on the weight of the SCT-1.
  • the bottoms fraction which is a solid at room temperature, has a T 10 of approximately 430°C and a T45 of approximately 560°C.
  • a mixture is produced by combining 60.0 wt. % of the bottoms fraction and 40.0 wt. % of the utility fluid utilized in Example 5, the weight percents being based on the weight of the mixture.
  • the mixture is hydrotreated in the same reactor as utilized in Example 5, under substantially the same process conditions.
  • the catalyst utilized is substantially the same as that of Example 1 and is sulfided in substantially the same way.
  • the hydroprocessing is conducted for 15 days without a significant change in the conversion of the mixture's 565°C, indicating good catalyst stability without significant catalyst coking.
  • This example demonstrates that reactor sizes and hydrogen consumption can be lessened without significant catalyst deactivation by treating only the fraction of SCT with the highest viscosity and lowest hydrogen content.
  • the fraction of the tar that benefits the most from hydroprocessing can be hydrotreated without significant catalyst coking.
  • one-ring aromatic streams (such as the utility fluid) can be blended with highly aromatic tars that are solids at room temperature and that such a blend can be hydrotreated without significant catalyst coking or reactor fouling.
  • the remaining fraction(s) of SCT-1 from the initial separation of Example 7 are readily hydroprocessed using conventional means.

Abstract

La présente invention concerne des produits de pyrolyse améliorés, des procédés d'amélioration de produits résultant d'une pyrolyse des hydrocarbures, un équipement utilisable à cet effet et l'utilisation desdits produits de pyrolyse améliorés.
PCT/US2012/053408 2011-08-31 2012-08-31 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 WO2013033575A1 (fr)

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