Process for Reducing the Asphaltene Yield and Recovering Waste Heat in a Pyrolysis Process by Quenching with a Hydroprocessed Product

Abstract

The invention relates to upgraded pyrolysis products, processes for upgrading products obtained from hydrocarbon pyrolysis, equipment useful for such processes, and the use of upgraded pyrolysis products.

Description

FIELD

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.

BACKGROUND

Light olefins such as ethylene and propylene are produced from the steam pyrolysis of hydrocarbons at high temperatures (800° C. and above) and low pressures (between atmospheric and a few atmospheres). Undesirable byproduct molecules from the pyrolysis are coke and asphaltenes. A substantial amount of the coke deposits on surfaces in the pyrolysis reaction system and eventually must be removed by de-coking. The asphaltene molecules are undesirable because they can foul the surfaces in the process as they condense, they are typically not compatible with other heavy fuel streams (they precipitate out of solution when mixed with typical fuel oil streams), and because they contribute to a high viscosity when blended. A standard method of defining and measuring the asphaltene content of a stream is to mix the stream with heptane and measure the weight of material that precipitates.

Although some asphaltene molecules are present in the hot pyrolysis effluent, most asphaltene molecules are believed to be formed from smaller reactive molecules downstream of the pyrolysis reactor. As the high temperature pyrolysis effluent is cooled, 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 FIG. 1). Generally, the lightest liquid product stream is steam-cracked naphtha (hereinafter SCN). The next heavier cut is steam-cracked gas oil (SCGO). The next heavier cut is quench oil, and the heaviest liquid cut is called steam-cracked tar (SCT). 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. When indirect methods are utilized to cool and begin to condense hydrocarbons, the fouling rates of the cooling surfaces may be unacceptably high. It is believed that 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.

What is needed is a process that will further reduce the quantity of asphaltenes that are formed in the steam-cracked tar cut. What is also needed is a method that allows recovery of more heat from the effluent of the pyrolysis reactor/furnace (e.g., more high-level waste heat).

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. Although 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.

There is therefore a need for a process which recovers more heat from the pyrolysis effluent, which produces fewer asphaltenes, and is compatible with SCT upgrading methods.

SUMMARY

In one embodiment, the invention relates to a hydrocarbon quenching process, comprising:

• • (a) providing a first mixture comprising ≧10.0 wt. % hydrocarbon based on the weight of the first mixture;
  • (b) pyrolyzing the first mixture to produce a second mixture comprising ≧1.0 wt. % of C₂ unsaturates and ≧1.0 wt. % tar based on the weight of the second mixture, the second mixture and having a first temperature T₁;
  • (c) adding a quench fluid to the second mixture to produce a quenched mixture having a second temperature T₂, wherein (i) T₁>T₂, (ii) T₁−T₂≧100.0° C., and (iii) at least a portion of the resulting quenched mixture is liquid;
  • (d) separating from the quenched mixture a vapor stream and a tar stream; and
  • (e) contacting at least a first portion of the tar stream with at least one hydroprocessing catalyst under catalytic hydroprocessing conditions in the presence of molecular hydrogen to produce a hydroprocessed product, wherein the quench fluid comprises ≧5.0 wt. % of the hydroprocessed product based on the weight of the quench fluid.

In another embodiment, the invention relates to a hydrocarbon quenching process, comprising:

• • (a) providing a first mixture comprising ≧10.0 wt. % hydrocarbon based on the weight of the first mixture;
  • (b) pyrolyzing the first mixture to produce a second mixture comprising ≧1.0 wt. % of C₂ unsaturates and ≧1.0 wt. % tar based on the weight of the second mixture, the second mixture being all vapor and having a first temperature T₁;
  • (c) adding a quench fluid to the second mixture to produce a quenched mixture having a second temperature T₂, wherein (i) T₁>T₂, (ii) T₁−T₂≧100.0° C., and (iii) at least portion of the resulting quenched mixture is liquid;
  • (d) separating from the quenched mixture a vapor stream and a tar stream, the tar stream being liquid-phase;
  • (e) providing a utility fluid, the utility fluid comprising ≧40.0 wt. % aromatic carbon, based on the weight of the utility fluid, and having an ASTM D86 10% distillation point ≧60.0° C. and a 90% distillation point ≦350.0° C.;
  • (f) mixing the utility fluid with at least a portion of the tar stream to form a hydroprocessor feed;
  • (g) contacting the hydroprocessor feed with at least one hydroprocessing catalyst under catalytic hydroprocessing conditions in the presence of molecular hydrogen to produce a hydroprocessor outlet stream; and
  • (h) separating from the hydroprocessor outlet stream at least 2 streams (i) a light hydroprocessor product comprising ≧40.0 wt. % aromatic carbon, based on the weight of the light hydroprocessor product, and having an ASTM D86 10% distillation point ≧60.0° C. and a 90% distillation point ≦350.0° C. and (ii) a heavy hydroprocessor product;
    wherein the 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.

In yet another embodiment, the invention relates to a hydrocarbon quenching process, comprising:

• • (a) providing a first mixture comprising ≧10.0 wt. % hydrocarbon based on the weight of the first mixture;
  • (b) pyrolyzing the first mixture to produce a second mixture comprising ≧1.0 wt. % of C₂ unsaturates and ≧1.0 wt. % tar based on the weight of the second mixture, the second mixture being all vapor and having a first temperature T₁;
  • (c) adding a quench fluid to the second mixture to produce a quenched mixture having a second temperature T₂, wherein (i) T₁>T₂, (ii) T₁−T₂>100.0° C., and (iii) at least portion of the resulting quenched mixture is liquid;
  • (d) separating from the quenched mixture a vapor stream and a tar stream;
  • (e) providing a utility fluid, the utility fluid comprising ≧40.0 wt. % aromatic carbon, based on the weight of the utility fluid, and having an ASTM D86 10% distillation point ≧60.0° C. and a 90% distillation point ≦350.0° C.;
  • (f) mixing the utility fluid with at least a portion of the tar stream to form a hydroprocessor feed;
  • (g) contacting the hydroprocessor feed with at least one hydroprocessing catalyst under catalytic hydroprocessing conditions in the presence of molecular hydrogen to produce a hydroprocessor outlet stream; and
  • (h) separating from the hydroprocessor outlet stream at least 2 streams (i) a light hydroprocessor product comprising ≧40.0 wt. % aromatic carbon, based on the weight of the light hydroprocessor product, and having an ASTM D86 10% distillation point ≧60.0° C. and a 90% distillation point ≦350.0° C. and (ii) a heavy hydroprocessor product; wherein the 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.

In certain embodiments, e.g., in any of the preceding embodiments, 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. % of molecules having an atmospheric boiling point ≧565° C. that are not asphaltenes, and (b)≦1000.0 ppmw metals, the weight percents being based on the weight of the tar stream; (iv) T₁ in the range of 600° C. to 850° C.; (v) T₂ in the range of 350° C. to 600° C.; (vi) T₃ in the range of 300° C. to 500° C.; and (vii) 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 m³/m³ to 445 S m³/m³ (where the denominator is based on per volume of tar).

BRIEF DESCRIPTION OF THE FIGURE

FIG. 1 schematically illustrates a typical steam pyrolysis quench system.

FIGS. 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 pyrolysis 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.

Optionally, in addition to the above, the heaviest liquid product (SCT) is withdrawn from the cut taken from the process at a temperature greater than 400° C.

Optionally, 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.

Specifically, 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.

While not wishing to be held to any particular theory, it is believed that the mechanism for asphaltene growth in steam-cracked tar involves coupling and oligomerization of the olefinic species, particularly the vinyl aromatic species. Further, it is believed that the initial coupling reaction is a second order in nature, meaning that the reaction rate increases with the square of the concentration of reactive species. When hydroprocessed under the conditions prescribed, the reactive olefinic bonds are saturated with hydrogen, which renders them unreactive for growth of asphaltenes. In addition, the mixing of hydroprocessed tar species (non-reactive) with the non-hydroprocessed species (reactive) dilutes the reactive species with inert species. Owing to the 2nd order nature of the reaction, the dilution with inert species slows the rate of the initial coupling reaction, which further serves to reduce the rate of oligomerization. Since 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.

Typical Steam Pyrolysis Quench System

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. In this furnace, 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 T₁, 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., T₁−T₂≧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. In this example, the heaviest liquid cut, steam-cracked tar 36, can be removed, e.g., as a 300° C. cut. Optionally, 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.

In a typical alternate configuration not shown in FIG. 1, 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. 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 FIG. 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. Furthermore, 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.

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. These molecules are therefore much lighter (more volatile) than the tar molecules, which are taken as a cut at about 300° C. When the light quench oil is contacted with the hot effluent to achieve a mix temperature of 300° C., the quench oil is mostly vaporized, leaving just the tar molecules in the liquid phase. In this configuration, the quench oil cannot serve to effectively dilute the reactive tar molecules, even if the light quench oil were to be hydroprocessed.

Aspects of the invention will now be described in more detail with reference to the embodiments shown in FIGS. 2, 3, and 4, The invention is not limited to these embodiments, and this description is not meant to foreclose other embodiments within the broader scope of the invention. Features having the same or similar function as in FIG. 1 are identified by the same index number.

Example 2

Hydroprocessed Tar Quench

Example 2 is an embodiment of the hydroprocessed tar quench process, shown in FIG. 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 FIG. 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. In addition, since 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.

The flow rate of quench oil is determined by the enthalpies of the pyrolysis effluent and quench streams, as well as the desired temperature after the quench mixing. This quench flow rate is generally much higher than the flow rate of the tar product cut, on the order of 10 times the product rate. It is not necessary to hydroprocess the entire quench flow 20; only a portion needs to be hydroprocessed. It is easy to show mathematically that the fraction of quench oil that is hydroprocessed is a function of the ratio of the hydroprocessed quench oil flow to the product tar flow by the following equation.

$\begin{array}{cc}x=\frac{y}{1+y}& \left(\mathrm{Equation}1\right)\end{array}$

where: x=the mass fraction of total quench oil that is hydrotreated

• • y=the mass ratio of hydrotreated quench oil to tar product flow rates

Thus, if the flow rate of hydroprocessed tar and tar product are equal, then y=1 and x=0.5 according to the equation above. This means that 50% (by mass) of the quench fluid is hydroprocessed. If the hydroprocessed tar flow rate is twice the product tar flow, then y=2 and x=0.667, meaning that 66.7% (by mass) of the quench fluid is hydroprocessed. If the total flow of quench fluid is 10 times the product tar flow rate, and y=1, then just 10% (by mass) of the total quench fluid comes directly from the hydroprocessor. But, this achieves a total quench fluid that is 50% (by mass) hydroprocessed because a portion of the bypassed quench fluid is actually recirculated from the process, which contains hydroprocessed fluid. Thus, it can be seen that only a small fraction of the quench oil needs to be routed through the hydroprocessor.

Example 3

Hydroprocessed Tar Quench with Tar Drawoff Upstream of Hydroprocessor

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 FIG. 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 FIG. 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

Hydroprocessed Tar Quench with Heavy Tar Knockout

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 FIG. 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).

Refer now to FIG. 4. Light tar 36 is withdrawn from the bottom of the primary fractionator 130 as a 340° C. cut. A portion of this cut is hydroprocessed in the hydroprocessor 140 as in the previous examples, and becomes the hydroprocessed tar quench oil 19. This tar quench oil is contacted with the pyrolysis effluent 13 as in the Examples 2 and 3, but the flow rate is selected to achieve a mixture temperature of approximately 494° C. At this higher temperature, a much smaller rate of liquid is condensed from the pyrolysis gas. This liquid is separated from the vapor in the tar knockout separator 120 by way of pump 142, and is referred to as the Heavy Tar 33 and heavy tar product 34, to differentiate it from the 340° C. tar cut (now referred to as Light Tar). The heavy tar cut 33 and 34 contains the asphaltenes and a much lower concentration of the lighter tar molecules. 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 T₃. T₂−T₃ 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. Optionally, steam is conducted away from exchanger 125 via line 17. 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 FIG. 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 near absence of asphaltenes in the light tar cut 36 from the bottoms of the primary fractionator also makes the Hydroprocessor process much less prone to coking, fouling, and plugging. However, it may be desirable to feed a portion of the heavy tar cut (containing asphaltenes) 35 to the Hydroprocessor 140. 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. 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. In the foregoing embodiments of FIGS. 2, 3, and 4, the utility fluid comprises the hydroprocessed tar that is recycled through the quench system. In certain embodiments a supplemental utility fluid can be provided as well. This is not explicitly shown in FIGS. 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.

Unlike conventional SCT hydrotreating, the hydroprocessing process can be operated at temperatures and pressures that favor the desired hydrocracking reaction over aromatics hydrogenation. The term “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 C₁₅.

It has been observed that SCT comprises a significant amount of Tar Heavies (“TH”). For the purpose of this description and appended claims, 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. The term “asphaltene or asphaltenes” is defined as heptane insolubles, and is measured following ASTM D3279. For example, 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., C₁ to C₃ alkanes and/or alkenes, (ii) C₅ and/or C₆ cycloparaffinic rings, or (iii) thiophenic rings. Generally, ≧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. In other words, conventional TH conversion suffers from severe mass-transport limitations, which result in a high selectivity for TH conversion to coke. It has been found that combining SCT with the utility fluid breaks down the aggregates into individual molecules of, e.g., ≧5.0 nm in their largest dimension and a molecular weight in the range of about 200 grams per mole to 2500 grams per mole. This results in greater mobility and diffusivity of the SCT's TH, leading to shorter catalyst-contact time and less conversion to coke under hydroprocessing condition. As a result, SCT conversion can be run at lower pressures, e.g., 500 psig to 1500 psig (34.5 to 103.4 bar gauge), leading to a significant reduction in cost and complexity over higher-pressure hydroprocessing. The invention is also advantageous in that the SCT is not over-cracked so that the amount of light hydrocarbons produced, e.g., C₄ 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 ¹³C is substantially greater than that of resid. For example, 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. 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. In SCT, 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.

Selected properties of two representative SCT samples and three representative resid samples are set out in the following table.

	TABLE 1
	SCT 1	SCT 2	RESID 1	RESID 2	RESID 3
CARBON (wt. %)	89.9	91.3	86.1	83.33	82.8
HYDROGEN (wt. %)	7.16	6.78	10.7	9.95	9.94
NITROGEN (wt. %)	0.16	0.24	0.48	0.42	0.4
OXYGEN (wt. %)	0.69	N.M.	0.53	0.87
SULFUR (wt. %)	2.18	0.38	2.15	5.84	6.1
Kinematic Viscosity at 50° C. (cSt)	988	7992	>1,000	>1,000	>1,000
Weight % having an atmospheric boiling	16.5	20.2
point ≧565° C.
Asphaltenes	22.6	31.9	91	85.5	80
NICKEL wppm	<0.7	N.M.*	52.5	48.5	60.1
VANADIUM wppm	0.22	N.M.	80.9	168	149
IRON wppm	4.23	N.M.	54.4	11	4
Aromatic Carbon (wt. %)	71.9	75.6	27.78	32.32	32.65
Aliphatic Carbon (wt. %)	28.1	24.4	72.22	67.68	67.35
Methyls (wt. %)	11	7.5	9.77	13.35	11.73
% C in long chains (wt. %)	0.7	0.63	11.3	15.28	10.17
Aromatic H (wt. %)	38.1	43.5	N.M.	N.M.	6.81
% Sat H (wt. %)	60.8	55.1	N.M.	N.M.	93.19
Olefins (wt. %)	1.1	1.4	N.M.	N.M.	0
*N.M. = Not Measured

The aliphatic carbon and % carbon in long chains is substantially lower in SCT compared to resid. Although 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. One such pyrolysis process, 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.

Obtaining SCT by Pyrolysis

Conventional steam cracking utilizes a pyrolysis furnace which has two main sections: a convection section and a radiant section. The feedstock (first mixture) 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. Generally, a cooling stage, typically either direct quench or indirect heat exchange is located between the pyrolysis furnace and the separation stage.

In one or more embodiments, SCT is obtained as a product of pyrolysis conducted in one or more pyrolysis furnaces, e.g., one or more steam cracking furnaces. Besides SCT, such furnaces generally produce (i) vapor-phase products such as one or more of acetylene, ethylene, propylene, butenes, and (ii) liquid-phase products comprising, e.g., one or more of C₅₊ molecules and mixtures thereof. The liquid-phase products are generally conducted together to a separation stage, e.g., a primary fractionator, for separations of one or more of (a) overheads comprising steam-cracked naphtha (“SCN”, e.g., C₅-C₁₀ species) and steam cracked gas oil (“SCGO”), the SCGO comprising ≧90.0 wt. % based on the weight of the SCGO of molecules (e.g., C₁₀-C₁₇ species) having an atmospheric boiling point in the range of about 400° F. to 550° F. (200° C. to 290° C.), and (b) bottoms (e.g., a tar stream) comprising ≧90.0 wt. % SCT, based on the weight of the bottoms, the SCT having a boiling range ≧ about 550° F. (290° C.) and comprising molecules and mixtures thereof having a molecular weight ≧ about C₁₅.

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. %. Although 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. As an example, it can be advantageous for 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. %. When the pyrolysis is steam cracking, 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.

In one or more embodiments, 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. Optionally, the first mixture's hydrocarbon component comprises sulfur, e.g., ≧0.1 wt. % sulfur based on the weight of 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. %. Optionally, 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”). When (i) the first mixture's hydrocarbon is a crude oil or crude oil fraction comprising ≧0.1 wt. % of aromatic sulfur and (ii) the pyrolysis is steam cracking, then the SCT contains a significant amount of sulfur derived from the first mixture's aromatic sulfur. For example, 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.

In a particular embodiment, 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.

Optionally, 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. 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. Pat. Nos. 7,138,047; 7,090,765; 7,097,758; 7,820,035; 7,311,746; 7,220,887; 7,244,871; 7,247,765; 7,351,872; 7,297,833; 7,488,459; 7,312,371; and 7,235,705, which are incorporated by reference herein in their entirety. Suitable vapor/liquid separation devices are also disclosed in U.S. Pat. Nos. 6,632,351 and 7,578,929, which are incorporated by reference herein in their entirety. Generally, when using a vapor/liquid separation device, 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.

In embodiments using a vapor/liquid separation device integrated with the pyrolysis furnace, 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. When a diluent (e.g., steam) is utilized, 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, at least a portion of which is in the vapor phase, 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. When the pyrolysis is steam cracking and the first mixture's hydrocarbon component comprises one or more crude oil or fractions thereof, 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.

One of the advantages of having a vapor/liquid separation device downstream of the convection section inlet and upstream of the crossover piping to the radiant section is that it increases the range of hydrocarbon types available to be used directly, without pretreatment, as hydrocarbon components in the first mixture. For example, 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. If desired, 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). For example, a 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.

In other embodiments, the vapor/liquid separation device is not used. For example when the first mixture's hydrocarbon comprises crude oil and/or one or more fractions thereof, 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. In one or more embodiments, 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. % water based on the weight of the diluent. When the first mixture comprises 10.0 wt. % to 90.0 wt. % diluent based on the weight of the first mixture, 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. When the specified pyrolysis conditions are utilized, 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. Optionally, the second mixture comprises ≧5.0 wt. % of C₂ unsaturates and/or ≧0.5 wt. % of TH, such as ≧1.0 wt. % TH. Although 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 FIGS. 1, 2, 3, and 4.

In one or more embodiments, 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. Generally, 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.

Although it is not required, 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. For example, 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. Where employed in conjunction with at least one transfer line exchanger, 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 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. Pat. No. 8,083,931. In the separation stage, 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. When the pyrolysis is steam cracking, 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.

In one or more embodiments, the tar stream comprises ≧50.0 wt. % of the second mixture's TH based on the weight of the second mixture's TH. For example, 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/cm³ to 1.15 g/cm³, e.g., in the range of 1.07 g/cm³ to 1.15 g/cm³, and (iv) a 50° C. viscosity in the range of 200 cSt to 1.0×10⁷ cSt.

The tar stream can comprise TH aggregates. In one or more embodiments, 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. For example, 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.

Utility Fluid

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. In one or more embodiments the utility fluid comprises ≧40.0 wt. % aromatic carbon such as ≧60.0 wt. % aromatic carbon as measured by ¹³C. Nuclear Magnetic Resonace (“NMR”). For example, 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. % of the hydroprocessed product's molecules having at least four carbon atoms based on the weight of the hydroprocessed product. In other embodiments, 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.

In other embodiments, 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.

Optionally, in other embodiments, 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. In one or more embodiments, 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. For example, 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. 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. Optionally, 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). It is generally desirable for the supplemental utility fluid to be substantially free of molecules having alkenyl functionality, particularly in embodiments utilizing a hydroprocessing catalyst having a tendency for coke formation in the presence of such molecules. In an embodiment, 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.

In certain embodiments, 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. In certain embodiments, 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.

Generally, 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. For example, 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. In an embodiment, 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. For example, 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. % of the tar stream and from about 10.0 wt. % to about 60.0 wt. % of the utility fluid. 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.

It has been found that 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. In certain embodiments, 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. For example, 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

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.

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. In one or more embodiments, 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). Examples of such 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.

In one or more embodiments, 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. For example, 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. In a particular embodiment, the catalyst further comprises at least one Group 15 element. An example of a preferred Group 15 element is phosphorus. When a Group 15 element is utilized, 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.

In an embodiment, the catalyst comprises at least one Group 6 metal. Examples of preferred 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. For example, 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.

In related embodiments, 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. Alternatively, 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.

When 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. When the catalyst includes at least one of Group 5 metal and at least one Group 10 metal, 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. For example, 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. For example, 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. Examples of 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. In a particular embodiment, 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. In alternative embodiments, 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.

When a support is utilized, 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. In certain embodiments, 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. Optionally, 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. Optionally, 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. In other embodiments, 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. When 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. Non-limiting examples of such 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 ( 1/32^nd to ⅛^th inch), from about 1.3 mm to about 2.5 mm ( 1/20^th to 1/10^th inch), or from about 1.3 mm to about 1.6 mm ( 1/20^th to 1/16^th inch). Similarly-sized non-cylindrical shapes are within the scope of the invention, e.g., trilobe, quadralobe, etc. Optionally, 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. When a porous catalyst is utilized, 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. For example, 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 Å to 1000 Å, or 50 Å to 500 Å, or 60 Å to 300 Å. Pore size can be determined according to ASTM Method D4284-07 Mercury Porosimetry.

In a particular embodiment, the hydroprocessing catalyst has a median pore diameter in a range of from 50 Å to 200 Å. Alternatively, the hydroprocessing catalyst has a median pore diameter in a range of from 90 Å to 180 Å, or 100 Å to 140 Å, or 110 Å to 130 Å. In another embodiment, the hydroprocessing catalyst has a median pore diameter ranging from 50 Å to 150 Å. Alternatively, the hydroprocessing catalyst has a median pore diameter in a range of from 60 Å to 135 Å, or from 70 Å to 120 Å. In yet another alternative, hydroprocessing catalysts having a larger median pore diameter are utilized, e.g., those having a median pore diameter in a range of from 180 Å to 500 Å, or 200 Å to 300 Å, or 230 Å to 250 Å.

Generally, the hydroprocessing catalyst has a pore size distribution that is not so great as to significantly degrade catalyst activity or selectivity. For example, the hydroprocessing catalyst can have a pore size distribution in which at least 60% of the pores have a pore diameter within 45 Å, 35 Å, or 25 Å of the median pore diameter. In certain embodiments, the catalyst has a median pore diameter in a range of from 50 Å to 180 Å, or from 60 Å to 150 Å, with at least 60% of the pores having a pore diameter within 45 Å, 35 Å, or 25 Å of the median pore diameter.

When a porous catalyst is utilized, the catalyst can have, e.g., a pore volume ≧0.3 cm³/g, such ≧0.7 cm³/g, or ≧0.9 cm³/g. In certain embodiments, pore volume can range, e.g., from 0.3 cm³/g to 0.99 cm³/g, 0.4 cm³/g to 0.8 cm³/g, or 0.5 cm³/g to 0.7 cm³/g.

In certain embodiments, a relatively large surface area can be desirable. As an example, the hydroprocessing catalyst can have a surface area ≧60 m²/g, or ≧100 m²/g, or ≧120 m²/g, or ≧170 m²/g, or ≧220 m²/g, or ≧270 m²/g; such as in the range of from 100 m²/g to 300 m²/g, or 120 m²/g to 270 m²/g, or 130 m²/g to 250 m²/g, or 170 m²/g to 220 m²/g.

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. Although relatively pure molecular hydrogen can be utilized for the hydroprocessing, it is generally desirable to utilize 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 H₂S and NH₃. The treat gas optionally contains ≧ about 50 vol. % of molecular hydrogen, e.g., ≧ about 75 vol. %, based on the total volume of treat gas conducted to the hydroprocessing stage.

Optionally, 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 m³/m³) to 5000 SCF/B (890 S m³/m³), in which B refers to barrel of the tar stream. For example, the molecular hydrogen can be provided in a range of from 1000 SCF/B (178 S m³/m³) to 3000 SCF/B (534 S m³/m³). 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. An example of suitable catalytic hydroprocessing conditions will now be described in more detail. The invention is not limited to these conditions, and this description is not meant to foreclose other hydroprocessing conditions within the broader scope of the invention.

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 pyrolysis stage and separation stage. The specified tar stream generally contacts the hydroprocessing catalyst in the vessel or zone, in the presence of the utility fluid and molecular hydrogen. Catalytic hydroprocessing conditions can include, e.g., exposing the combined diluent-tar stream to a temperature in the range from 50° C. to 500° C. or from 200° C. to 450° C. or from 220° C. to 430° C. or from 350° C. to 420° C. proximate to the molecular hydrogen and hydroprocessing catalyst. For example, a temperature in the range of from 300° C. to 500° C., or 350° C. to 450° C., or 360° C. to 420° C. can be utilized. Liquid hourly space velocity (LHSV) of the combined diluent-tar stream will generally range from 0.1 h⁻¹ to 30 h⁻¹, or 0.4 h⁻¹ to 25 h⁻¹, or 0.5 h⁻¹ to 20 h⁻¹. In some embodiments, LHSV is at least 5 h⁻¹, or at least 10 h⁻¹, or at least 15 h⁻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. In some embodiments, 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 m³/m³) to about 445 S m³/m³ (300 SCF/B to 2500 SCF/B). In one or more embodiment, 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 m³/m³ to about 270 S m³/m³ (400 SCF/B to 1500 SCF/B). When operated under these conditions using the specified catalyst, TH hydroconversion conversion is generally ≧25.0% on a weight basis, e.g., ≧50.0%.

We now present some examples that illustrate hydroprocessing SCT in the presence of a utility fluid.

Example 5

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 Co—Mo/Al₂O₃ 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. After loading, the reactor is pressure tested at 68 bar (absolute) using molecular nitrogen, followed by molecular hydrogen.

During catalyst sulfiding, 200 cm³ 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 cm³ of sulfiding solution. Initially, the sulfiding solution is introduced at a rate of 60 cm³/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 cm³ per hour and molecular hydrogen is introduced at a rate of 20 standard cm³ per minute while exposing the catalyst to a temperature of 25° C. 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 110° C. is achieved, and then maintaining the 110° 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 cm³ of sulfiding solution is consumed, i.e., sulfiding solution consumption being measured from the start of sulfiding.

After sulfiding, the SCT 1-utility fluid mixture is introduced at a rate of 6.0 cm³/hr (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 cm³/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 m³/m³ (within about +/−10%) over the 80 day period is indicative of a relatively low-level of SCT hydrogenation. For comparison purpose, the amount of hydrogen consumption would have been much more than 195 S m³/m³ if significant aromatics hydrogenation occurs.

The total liquid product (TLP) conducted away from the hydroprocessing is sampled at the eighth and twentieth day of the eighty-day hydroprocessing test. 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.

Example 6

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.

Example 7

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 T₁₀ 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. In other words, the fraction of the tar that benefits the most from hydroprocessing can be hydrotreated without significant catalyst coking. The example also demonstrates that 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.

All patents, test procedures, and other documents cited herein, including priority documents, are fully incorporated by reference to the extent such disclosure is not inconsistent and for all jurisdictions in which such incorporation is permitted.

While the illustrative forms disclosed herein have been described with particularity, it will be understood that various other modifications will be apparent to and can be readily made by those skilled in the art without departing from the spirit and scope of the disclosure. Accordingly, it is not intended that the scope of the claims appended hereto be limited to the example and descriptions set forth herein, but rather that the claims be construed as encompassing all the features of patentable novelty which reside herein, including all features which would be treated as equivalents thereof by those skilled in the art to which this disclosure pertains.

When numerical lower limits and numerical upper limits are listed herein, ranges from any lower limit to any upper limit are contemplated.

Claims

1. A hydrocarbon quenching process, comprising:

(a) providing a first mixture comprising ≧10.0 wt. % hydrocarbon based on the weight of the first mixture;

(b) pyrolyzing the first mixture to produce a second mixture comprising ≧1.0 wt. % of C2 unsaturates and ≧1.0 wt. % tar based on the weight of the second mixture, the second mixture and having a first temperature T1;

(c) adding a quench fluid to the second mixture to produce a quenched mixture having a second temperature T2, wherein (i) T1>Tz, (ii) T1−T2≧100.0° C., and (iii) at least a portion of the resulting quenched mixture is liquid;

(d) separating from the quenched mixture a vapor stream and a tar stream; and

(e) contacting at least a first portion of the tar stream with at least one hydroprocessing catalyst under catalytic hydroprocessing conditions in the presence of molecular hydrogen to produce a hydroprocessed product, wherein the quench fluid comprises ≧5.0 wt. % of the hydroprocessed product based on the weight of the quench fluid.

2. The process of claim 1, wherein the quench fluid further comprises a second portion of the tar stream in an amount ≧10.0 wt. % based on the weight of the quench fluid.

3. The process of claim 2, wherein the second portion of the tar stream bypasses the hydroprocessing of step (e).

4. The process of claim 1, wherein the hydroprocessed product comprises ≧10.0 wt. % of a hydroprocessed tar and ≧10.0 wt. % of a low-boiling mixture, the low boiling mixture having an ASTM D86 10% distillation point ≧60.0° C. and a 90% distillation point ≦350.0° C.

5. The process of claim 1, wherein the first temperature T1 is in the range of 600° C. to 850° C.

6. The process of claim 1, wherein the second temperature T2 is in the range of 250° C. to 500° C.

7. The process of claim 1, wherein a third portion of the tar stream is withdrawn from the process.

8. The process of claim 1, wherein a second portion of the hydroprocessed product is withdrawn from the process.

9. The process of claim 1, wherein pyrolyzing in step (b) takes place in the presence of steam.

10. The process of claim 9, wherein the pyrolyzing is steam cracking.

11. A hydrocarbon quenching process, comprising:

(a) providing a first mixture comprising ≧10.0 wt. % hydrocarbon based on the weight of the first mixture;

(b) pyrolyzing the first mixture to produce a second mixture comprising ≧1.0 wt. % of C2 unsaturates and ≧1.0 wt. % tar based on the weight of the second mixture, the second mixture having a first temperature T1,

(c) adding a quench fluid to the second mixture to produce a quenched mixture having a second temperature T2, wherein (i) T1>Tz, (ii) T1−T2≧100.0° C., and (iii) at least portion of the resulting quenched mixture is liquid;

(d) separating from the quenched mixture a vapor stream and a heavy tar stream;

(e) cooling the vapor stream to a third temperature T3, wherein T2>T3 and T2−T3≧50.0° C.;

(f) separating from the cooled vapor stream a second vapor stream and a light tar stream; and

(g) hydroprocessing the light tar stream to produce a hydroprocessed product, wherein the quench fluid comprises ≧5.0 wt. % of the hydroprocessed product based on the weight of the quench fluid.

12. The process of claim 11, further comprising hydroprocessing at least a portion of the heavy tar stream to produce a second hydroprocessed product, wherein the quench fluid further comprises ≧5.0 wt. % of the second hydroprocessed product based on the weight of the quench fluid.

13. The process in claim 11, further comprising (i) mixing a portion of the heavy tar stream from step (d) with a portion of the light tar stream from step (f) to form a mixed tar stream and (ii) hydroprocessing at least a portion of the mixed tar stream to produce a second hydroprocessed product, wherein the quench fluid further comprises ≧5.0 wt. % of the second hydroprocessed product based on the weight of the quench fluid.

14. The process of claim 11, wherein the quench fluid further comprises a second portion of the light tar stream in an amount ≧10.0 wt. % based on the weight of the quench fluid.

15. The process of claim 11, wherein the second portion of the light tar stream bypasses the hydroprocessing of step (g).

16. The process of claim 11, wherein the first hydroprocessed product comprises ≧10.0 wt. % of a hydroprocessed tar and ≧10.0 wt. % of a low-boiling mixture, the low boiling mixture having an ASTM D86 10% distillation point ≧60.0° C. and a 90% distillation point ≦350.0° C., and the weight percents being based on the weight of the first hydroprocessed product.

17. The process of claim 11, wherein T1 is in the range of 600° C. to 850° C.

18. The process of claim 11, wherein T2 is in the range of 350° C. to 600° C.

19. The process of claim 11, wherein T3 is in the range of 300° C. to 500° C.

20. The process of claim 11, further comprising conducting away at least a portion of the heavy tar stream.

21. The process of claim 11, further comprising conducting away a third portion of the light tar stream.

22. The process of claim 11, further comprising conducting away at least a portion of the first hydroprocessed product.

23. The process of claim 11, wherein pyrolyzing in step (b) takes place in the presence of steam.

24. The process of claim 23, wherein the pyrolyzing is steam cracking.

25. The process of claim 1, wherein the hydroprocessing takes place in the presence of a supplemental utility fluid comprising aromatics and having an ASTM D86 10% distillation point ≧60° C. and a 90% distillation point ≦360° C.