CN103764800A - Preheating feeds to hydrocarbon pyrolysis products hydroprocessing - Google Patents

Abstract

The invention relates to processes for upgrading products obtained from hydrocarbon pyrolysis, equipment useful for such processes, and the use of upgraded pyrolysis products. A tar-containing stream recovered from the pyrolysis effluent is mixed with a utility fluid, preheated and subsequently hydroprocessed.

Description

Feed Preheating in Hydrotreating of Hydrocarbon Pyrolysis Products

Cross References to Related Applications

This application claims application numbers 61/529,565 filed August 31, 2011, 61/529,588, filed August 31, 2011, and 61/657,299, filed June 8, 2012 The benefit of priority to the U.S. Provisional Application, which is incorporated herein by reference in its entirety.

technical field

The present invention relates to upgraded pyrolysis products, a method for obtaining upgraded products from hydrocarbon pyrolysis, and equipment for the above method.

Background technique

Pyrolysis processes such as steam cracking can be used to convert saturated hydrocarbons to high value products such as light olefins, eg, ethylene and propylene. In addition to these useful products, hydrocarbon pyrolysis can also produce large quantities of relatively low-value products such as steam cracking tars ("SCT").

SCT upgrading methods including conventional catalytic hydrotreating suffer from significant catalyst deactivation. The process can be operated at temperatures ranging from 250 °C to 380 °C and pressures ranging from 5400 kPa to 20,500 kPa using catalysts containing one or more of Co, Ni, or Mo; however, significant catalyst coking was observed. Although catalyst coking can be reduced by increasing hydrogen partial pressure, reducing space velocity, and operating at temperatures between 200°C and 350°C; however, SCT hydroprocessing is undesirable under these conditions because increasing hydrogen partial pressure Process economics are worsened by increased hydrogen and equipment costs, as well as undesired hydrogenation reactions due to increased hydrogen partial pressure, decreased space velocity, and decreased temperature.

Contents of the invention

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

(a) providing a first mixture comprising > 10.0 wt.% hydrocarbons, based on the weight of the first mixture;

(b) pyrolyzing the first mixture to produce a second mixture comprising ≥ 1.0 wt.% _C2 unsaturates and ≥ 1.0 wt.% tar, the weight percentages being based on the weight of the second mixture;

(c) separating a tar stream from the second mixture, wherein the tar stream comprises ≥ 90 wt.% of molecules of the second mixture having an atmospheric boiling point ≥ 290°C;

(d) Provide a utility fluid that contains ≥ 1.0 wt.% aromatics, based on the weight of the utility fluid;

(e) providing a hydrogen stream comprising molecular hydrogen;

(f) by (i) exposing the tar stream to 200.0° C. to 400.0° C. (ii) exposing the utility fluid to a temperature > 400.0° C. and then combining the tar stream with the heated utility fluid, and/or (iii) heating the tar stream by one or more of exposing the hydrogen stream to a temperature ≥ 400.0°C and then combining the tar stream with the heated hydrogen stream;

(g) in the hydroprocessing zone at a utility fluid:tar stream weight ratio of from 0.05 to Catalytic Hydroprocessing Conditions of 3.0 Hydrotreating at least a portion of the heated tar stream to produce a hydrotreated product, wherein the utility fluid comprises a hydrotreated product content > 10.0% by weight, based on the weight of the utility fluid.

In another embodiment the present invention relates to a hydrocarbon conversion process comprising: (a) providing a first mixture comprising > 50.0 wt.% hydrocarbons, based on the weight of the first mixture; (b) heating decomposing the first mixture to produce a second mixture comprising ≥ 1.0 wt.% _C2 unsaturates and ≥ 1.0 wt.% tar, the weight percentages being based on the weight of the second mixture; (c) separating the tar from the second mixture A stream, wherein the tar stream comprises ≥ 90 wt.% molecules of the second mixture having an atmospheric boiling point ≥ 290°C; (d) providing a utility fluid comprising ≥ 1.0 wt.% aromatics based on the weight of the utility fluid; (e) providing a hydrogen stream comprising molecular hydrogen; (f) by (i) directing the tar stream through at least one heater, (ii) directing the tar stream through a first channel of at least one heat exchanger and directing a heat transfer fluid through The second channel of the heat exchanger is used to extract heat from the heat transfer fluid to the tar stream, or (iii) heat the utility fluid to a temperature ≥ 425.0°C and combine the tar stream with the heated utility fluid. (g) hydrotreating at least a portion of the tar stream in a hydrotreating zone in the presence of the hydrogen stream and the utility fluid under catalytic hydrotreating conditions, the hydrotreating conditions comprising a temperature range of 300°C to 500°C, a pressure range of 15 bar (absolute pressure) to 135 bar (absolute pressure), and a utility fluid:tar weight ratio of 0.05-3.0, wherein (i) the utility fluid contains a content of the hydrotreated product of ≥ 50.0 wt.%, based on the weight of utility fluid; and (ii) the heat transfer fluid comprises the hydrotreated product in an amount > 50.0 wt%, based on the weight of heat transfer fluid.

Description of drawings

Figure 1 schematically illustrates the process layout for the hydrotreating reactor section that uses utility fluid to assist SCT hydrotreating. Potentially high coking areas are marked. Figures 2-4 schematically illustrate examples of process layouts within the scope of the present invention. The invention is not limited to these embodiments, and this description is not intended to exclude other embodiments within the broader scope of the invention. Figure 2 illustrates a hydroprocessing reactor section that uses a lower temperature first reactor section to minimize the risk of coking fouling in the reactor preheat sequence. Figure 3 illustrates a hydrotreater reactor section that surrounds the reactor feed/effluent heat exchanger with tar feed and feed conditioning heaters to minimize the risk of coking fouling. Figure 4 illustrates the hydrotreater reactor section where the catalyst bed heating at the top of the reactor minimizes the risk of coking fouling. Figure 5 shows two sets of curves for pressure drop across the reactor versus time for different temperature magnitudes.

Detailed description of the invention

SCT is usually obtained as a product of hydrocarbon pyrolysis. The pyrolysis method may include, for example, high temperature pyrolysis, such as a high temperature pyrolysis method using water. One of the pyrolysis methods described above, steam cracking, is disclosed in more detail below. The present invention is not limited to steam cracking, and certain embodiments are described in terms of steam cracking, not to the exclusion of other pyrolysis methods within the broader scope of the invention.

The present invention is based in part on the discovery that catalyst coking can be reduced by hydrotreating SCT in the presence of a utility fluid that contains a significant amount of aromatics, eg, mono- or polycyclic aromatics. It is desirable to heat the SCT and utility fluid mixture to the desired hydroprocessing temperature while avoiding coking of the preheated equipment while doing so.

Unlike conventional SCT hydroprocessing, the process operates at temperatures and pressures that favor the required hydrocracking reactions over aromatics hydrogenation. The term "SCT" means (a) a mixture of hydrocarbons having one or more aromatic nuclei and optionally (b) non-aromatic and/or non-hydrocarbon molecules derived from the pyrolysis of hydrocarbons and having a boiling range > about 550 °F (290°C), for example, ≥90.0 wt% of SCT molecules have an atmospheric boiling point ≥550°F (290°C). Based on the weight of SCT, the SCT may comprise, for example, > 50.0 wt.%, such as > 75.0 wt.%, such as > 90.0 wt.% _, of hydrocarbons having (i) one or more aromatic nuclei and (ii) molecular weight > about C Molecules (including their mixtures and aggregates).

Hydrotreating SCT improves the suitability of tar as a fuel oil by reducing its viscosity to increase compatibility with other fuel oils, narrowing its boiling point distribution, increasing its hydrogen content, and converting asphaltenes And the asphaltene precursors thereby increase the thermal stability of the tar. The resulting finished fuel oil product may be, for example, a globally commercialized alternative product of significantly higher value than untreated tar.

Figure 1 schematically illustrates a hydroprocessing reactor section for hydroprocessing SCT. As shown in FIG. 1 , the SCT stream 10 is combined 20 with utility fluid in feed tank 30 , pumped by pump 40 through line 50 , and then mixed with hydrogen-containing stream 60 . This mixture 61 is then preheated in heat exchanger 70 against the reactor effluent 120 followed by supplemental preheating to the reactor inlet temperature in process trim heater 90. The preheated mixture 100 is then directed into a hydroprocessing reactor 110 having three catalyst beds 115, 116, 117 of substantially equal volume. Optionally, the same catalyst is used in each bed. The catalyst can be, for example, a conventional hydrotreating catalyst, such as RT-621, available from Albermarle.

The hydroprocessor effluent stream is then directed via line 122 to exit heat exchanger 70 to one or more separation stages 130 for separation from the hydroprocessor effluent stream (i) via line 132 The outgoing purge gas stream (comprising, for example, excess or spent process gas), (ii) the outgoing hydrotreated product (comprising, for example, hydrotreated SCT) directed via line 134, and (iii) directing the exiting light gas stream (comprising eg methane and hydrogen sulphide) via line 133 for upgrading and/or use eg as fuel gas. Additional separations may be performed in the separation stage, for example, for separating light fuel oils and/or heavy oils from the hydrotreated product. Supplementary process gas (eg, molecular hydrogen) may be directed into separation section 130 via line 131 . Hydrogen-enriched treat gas is channeled out of section 130 via line 60 for recycling to hydrotreater 110 . Any H ₂ S and at least a portion of NH ₃ are removed in section 130 before the process gas enters line 60 .

While hydrotreating SCT improves thermal stability, preheating SCT to the required reactor inlet temperature presents a risk of thermally unstable SCT forming fouling, such as coking. Such coking tends to foul the preheating equipment, reactor inlet, and the upper part of the catalyst bed.

It can be seen that using quartz to pack the reactor, for example, does not produce any catalyst fouling when heating the utility fluid/tar/hydrogen mixture. The quartz is inert to simulate any device exposed to the heated mixture. The reactor was run at 400°C and 425°C and the pressure drop across the reactor was measured. An increase in pressure drop over time is a sign of coking fouling. The conditions are as follows:

Reactor: 3/8OD tube, 18in. (45.72cm) long, 12in. (30.48)cm heating

Feed composition: SCT tar 60wt.%; 40wt% trimethylbenzene utility fluid

Outlet pressure: 1000psi (68.9 bar)

Liquid flow: 0.05cc/min (3ml/hr)

_H2 flow: 26.7sccm (3000scfb feed)

Figure 5 presents the results by plotting the observed pressure drop across the reactor versus run time at various temperatures. Note that the pressure drop and time scale are different in the two graphs. At 400°C under these conditions, the pressure drop is almost negligible after more than 80 hours of operation. However, at 425°C, the pressure drop increased rapidly after only 5 or 6 hours of operation, causing the reactor to shut down after less than 27 hours of operation. The pressure drop oscillations observed in the 425°C plot indicated coking fouling and blocked feed and hydrogen flow.

The coking fouling described above can limit the length of time that the conversion process can be continuously operated. Once coking fouls critical equipment, the conversion process needs to be interrupted to remove the coking. In order to be suitable for industrial operation, the conversion process should be able to run continuously for at least 1 day, (8.6×10 ⁴ seconds), preferably at least 1 week (6.0×10 ⁵ seconds), more preferably at least 1 month (2.6×10 ⁶ seconds) , most preferably at least 1 year (3.2×10 ⁷ seconds) without excessive fouling of the hydroprocessing equipment, or excessive coking of the hydroprocessing catalyst.

For example, for commercial operation, the pressure drop across a hydroprocessing reactor or other equipment should not exceed about 3.0, 4.0 or 5.0 times the initial (SOR) pressure drop at the design flow rate.

Safety margins are required for commercial operation below the temperature at which severe fouling is expected to occur. In addition, the heater or heat exchanger metal temperature will be higher than the bulk fluid temperature, which can lead to hotter metal surface coke fouling. Therefore, the ideal maximum value of the fluid bulk temperature for tar is set to be significantly lower than the temperature 425°C at which excessive fouling is observed, for example, in the range of 200.0°C-400.0°C, such as 300.0°C-400.0°C. Practice in steam cracking has shown that keeping the overall tar temperature below 300°C minimizes the risk of equipment fouling. Embodiments of the present invention exemplify maintaining the SCT or SCT mixed with utility fluid and/or hydrogen below 300°C. Those skilled in the art will appreciate that temperatures higher or lower than 300° C. may be selected for a particular case without undue experimentation.

In particular, in the example depicted in Figure 1, it has been determined that under certain conditions there is a risk of coking fouling in the feed side reactor feed/effluent heat exchanger 70 and the reactor inlet trim heater 90 , if the SCT, optionally combined with utility fluid and/or molecular hydrogen, is preheated in this equipment at a temperature in excess of about 572°F (300°C). Thus, in certain embodiments, the tar stream 10 enters the hydrotreater between 200°F-572°F (90°C-300°C) and is then heated to a hydrotreater reactor inlet temperature of 700° F-800°F (370°C-425°C). Figure 1 shows the hydroprocessing layout and the location of equipment with the potential for coking of the tar stream (or tar combined with utility fluid and/or molecular hydrogen) prior to its hydroprocessing. In certain embodiments, the utility fluid comprises, for example, recycled hydrotreated products during conversion, or similar materials. The utility fluid is thermally stable at typical reactor preheat temperatures of 700°F-800°F (370°C-425°C) and unlike fresh (untreated) tar streams, is not prone to coking in preheat equipment . Equipment locations highlighted with dotted circles in Figure 1 present a risk of coking fouling of tar components in the feed when heated above about 572°F (300°C).

Certain embodiments of the present invention are based in part on the development of methods for preheating untreated tar streams, such as SCT, to hydroprocessing reactor inlet temperatures. It reduces or even eliminates preheat equipment fouling (or reduces catalyst coke formation) to allow continuous reactor operation. Other embodiments of the invention are based on the development of tar hydroprocessing processes utilizing high-activity catalysts. In this embodiment, the need for upstream preheating of the hydrotreating tar is reduced or eliminated because the hydrotreating catalyst is sufficiently active at lower temperatures. These methods can be used alone or in combination. Application of the method further described below will allow the transformation process to run continuously for at least 1 day (8.6×10 ⁴ seconds), preferably at least 1 week (6.0×10 ⁵ seconds), more preferably at least 1 month (2.6×10 ⁶ seconds ), or most preferably at least 1 year (3.2×10 ⁷ seconds).

Characteristics of SCTs

It has been noted that SCT contains significant amounts of tar heavies ("TH"). As far as this specification and the appended claims are concerned, the term "tar heavies" means hydrocarbon pyrolysis products, TH boiling point at atmospheric pressure ≥ 565°C and containing ≥ 5.0wt.% molecules with multiple aromatic nuclei, Based on product weight. TH is generally solid at 25.0°C and usually includes the SCT fraction which is insoluble at 25.0°C in a 5:1 (vol.:vol.) ratio of n-pentane:SCT ("conventional pentane extraction method"). TH can include high molecular weight molecules (eg, MW > 600) such as asphaltenes and other high-molecular weight hydrocarbons. The term "asphaltenes" is defined as heptane insolubles and measured according to ASTM D3279. For example, TH contains ≥ 10.0 wt.% of alkanes and/or alkenes with (i) relatively low molecular weight, e.g., C ₁ -C ₃ alkanes and/or alkenes, (ii) C ₅ and/or alkenes Or C ₆ cycloparaffinic (cycloparaffinic) ring, or (iii) a high molecular weight molecule of one or more aromatic nuclei linked together in a thiophene (thiophenic) ring. Typically, ≧60.0 wt.% of the carbon atoms of TH are included in one or more aromatic nuclei based on TH carbon atom weight, for example, in the range of 68.0 wt.%-78.0 wt.%. While not wishing to be bound by any particular theory or paradigm, it is further believed that aggregates formed by TH have a relatively two-dimensional morphology due to the van der Waals attraction between TH molecules. TH aggregates are large in size, ranging, for example, from ten nanometers to hundreds of nanometers ("nm") in their largest dimension, resulting in aggregate mobility and low diffusivity under catalytic hydroprocessing conditions. In other words, conventional TH conversion suffers from severe mass-transport limitations, which lead to high selectivity of TH conversion to coke. SCT incorporating utility fluids has been found to break down the aggregates into individual molecules, for example, with a largest dimension < 5.0 nm and a molecular weight ranging from about 200 grams per mole to 2500 grams per mole. This leads to greater mobility and diffusivity of TH in SCT, resulting in shorter catalyst-contact times and less conversion to coking under hydrotreating conditions. Consequently, SCT conversion can be performed at lower pressures, eg, 500 psig to 1500 psig (34.5 to 103.4 bar gauge), resulting in significantly less cost and complexity for relatively high pressure hydroprocessing. Furthermore the present invention has the advantage that the SCT is not overcracked so that the amount of light hydrocarbons produced, eg, C _or light, is less than 5 wt%, which further reduces the amount of hydrogen consumed in the hydrotreating step.

The SCT starting material differs from other relatively high-molecular weight hydrocarbon mixtures such as crude oil residues ("residues") including both atmospheric and vacuum residues and others, for example, commonly found in petroleum and petrochemical processing. Encountered streams,. The aromatic carbon content of the SCT's is substantially higher than resid as measured by ¹³ CNMR. For example, the amount of aromatic carbon in SCT is generally greater than 70 wt% while that in resid is generally less than 40 wt%. The atmospheric boiling point of the important fraction of SCT asphaltenes is less than 565°C. For example, only 32.5wt% asphaltene in SCT1 has an atmospheric boiling point above 565°C. This is not the case with vacuum residue. Even though solvent extraction is an incomplete method, the results show that the asphaltenes in the vacuum residue are mostly heavy molecules with an atmospheric boiling point above 565 °C. When the heptane solvent extraction was performed under essentially the same conditions as for the vacuum resid, the asphaltenes obtained from SCT contained a much higher percentage (by weight) of atmospheric boiling point < Molecules at 565°C. SCT also differs from residual oils in the relative content of metals and nitrogen-containing compounds. In SCT, the total amount of metals is ≤ 1000.0 ppmw (parts per million, by weight) based on SCT weight, eg, ≤ 100.0 ppmw, eg ≤ 10.0 ppmw. The total amount of nitrogen present in the SCT is generally less than the nitrogen content of the crude oil vacuum resid.

Properties of selected two typical SCT samples and three typical resid samples are listed in the table below.

Table 1

*N.M.=Not determined

SCT aromatic carbon content is substantially higher than resid. The percentages of aliphatic carbons as well as carbons in the long chains are substantially lower in SCT compared to resid. Although the total carbon content of SCT is only slightly higher and the oxygen content (wt. basis) is similar to resid, the range of metal, hydrogen, and nitrogen content (wt. basis) of SCT is very low. SCT kinematic viscosity (cSt) at 50°C is usually ≥1000, or ≥100, even though the relative amount of SCT atmospheric boiling point ≥565°C is much lower compared to the case of vacuum residue.

SCT is usually obtained as a product of hydrocarbon pyrolysis. The pyrolysis process may include, for example, high temperature pyrolysis, such as a high temperature pyrolysis method utilizing water. One such pyrolysis process, steam cracking, is disclosed in more detail below. The present invention is not limited to steam cracking, and this description is not intended to exclude the use of other pyrolysis methods within the broad scope of the present invention.

Obtaining SCT by pyrolysis

Conventional steam cracking uses a cracking furnace which has two main sections: a convection section and a radiant section. The raw material feed (first mixture) typically enters the convection section of the furnace where the hydrocarbon components of the first mixture are heated and vaporized by indirect contact with the hot flue gas from the radiant section and direct contact with the steam components of the first mixture. The steam-vaporized hydrocarbon mixture is then introduced into the radiant section where most of the cracking takes place. A second mixture is directed away from the cracking furnace, the second mixture comprising products resulting from pyrolysis of the first mixture and any unreacted components of the first mixture. Typically at least one separation section is located downstream of the cracking furnace for separating one or more of light olefins, SCN, SCGO, SCT, water, unreacted hydrocarbon components of the first mixture, etc. from the second mixture. The separation section may comprise, for example, a primary fractionation column. Typically, a cooling section, generally direct quenching or indirect heat exchange, is located between the cracking furnace and the separation section.

In one or more embodiments, SCT is obtained as a product of pyrolysis carried out in one or more cracking furnaces, such as one or more steam cracking furnaces. In addition to SCT, such furnaces typically produce (i) gaseous products such as one or more of acetylene, ethylene, propylene, butene, and (ii) liquid phase products containing, for example, one or more C5 ₊ molecules and mixtures thereof. This liquid phase product is usually directed together to a separation section, e.g., a primary fractionation column, for separating one or more of (a) and (b), (a) being an overhead fraction comprising steam-cracked naphtha Oils ("SCN", e.g., C ₅ -C ₁₀ materials) and steam cracked gas oils ("SCGO") containing ≥ 90.0 wt.% based on the weight of SCGO, the SCGO having an atmospheric boiling range of about 400°F-550° Molecules of F (200°C-290°C) (for example, C ₁₀ -C ₁₇ species), and (b) is a bottom product containing ≥ 90.0 wt.% SCT, based on the weight of the bottom product, SCT boiling range ≥ about 550°F (290°C) and containing molecules with a molecular weight ≥ about C ₁₅ and mixtures thereof.

The feed to the cracking furnace is a first mixture comprising > 10.0 wt.% hydrocarbons based on the weight of the first mixture, eg > 25.0 wt.%, > 50.0 wt.%, such as > 65.0 wt.%. Although the hydrocarbon may contain, for example, one or more light hydrocarbons such as methane, ethane, propane, butane, etc., it is particularly beneficial to apply the present invention in conjunction with a first mixture containing a large amount of high molecular weight hydrocarbons because these molecules pyrolyze Typically more SCT is produced than pyrolysis of low molecular weight hydrocarbons. For example, it is beneficial for the total amount of the first mixture to be fed to the plurality of cracking furnaces to contain > 1.0 wt.% or > 25.0 wt.% of hydrocarbons in the liquid phase at ambient temperature and atmospheric pressure, based on the first mixture weight.

Additionally, the first mixture may contain a diluent, eg, one or more of nitrogen, water, and the like. For example, > 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 may be prepared by combining the hydrocarbon with a diluent comprising steam, for example, in a ratio of 0.1-1.0 kg steam per kg hydrocarbon, or in a ratio 0.2-0.6 kg steam per kg hydrocarbon.

In one or more embodiments, the hydrocarbons of the first mixture comprise ≥ 10.0 wt.%, for example, ≥ 50.0 wt.%, such as ≥ 90.0 wt.% (based on the weight of the hydrocarbon components) of naphtha, gas oil, One or more of press gas oil, waxy resid, atmospheric resid, resid blend, or crude oil; including those containing > about 0.1 wt. % asphaltenes. Suitable crude oils include, for example, high-sulfur virgin crude oils, such as those rich in polycyclic aromatic hydrocarbons. Optionally, the hydrocarbons of the first mixture comprise sulfur, e.g., > 0.1 wt.% sulfur based on the weight of the hydrocarbon components of the first mixture, 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 sulfur-containing molecules of the first mixture, eg, > 10.0 wt.% of the sulfur-containing molecules of the first mixture, comprise at least one aromatic ring ("aromatic sulfur"). When (i) the hydrocarbon of the first mixture is crude oil or a crude oil fraction containing ≥ 0.1 wt.% aromatic sulfur and (ii) the pyrolysis is steam cracking, then the SCT contains a substantial amount of sulfur derived from the first mixture aromatic sulfur . For example, on a weight basis, the SCT sulfur content in the SCT may be about 3-4 times higher than the hydrocarbon component of the first mixture.

In particular embodiments, the hydrocarbons of the first mixture comprise one or more crude oils and/or one or more crude oil fractions, such as from atmospheric pipe stills ("APS") and/or vacuum pipe distillation those obtained by the device (“VPS”). The crude oil and/or fractions thereof are optionally desalted before being included in the first mixture. An example of a crude oil fraction used for the first mixture is produced by combining the APS bottoms separated from the crude oil and the APS bottoms subsequently treated with VPS.

Optionally, the cracking furnace has at least one integrated vapor/liquefaction separation device (sometimes called a flash tank or flash tank) for upgrading the first mixture. The vapor/liquefaction separation device described above is particularly suitable when the hydrocarbon component of the first mixture contains ≥ about 0.1 wt.% asphaltenes based on the weight of the hydrocarbon component of the first mixture, eg, ≥ about 5.0 wt.%. These can be accomplished using conventional vapor/liquefaction separation devices, but the present invention is not limited thereto.上述常规汽/液化分离装置的实例包括在专利号为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;和7,235,705美国专利中公开的那些,其全部引入This application is incorporated by reference. Suitable vapor/liquefaction separation devices are also disclosed in US Pat. Nos. 6,632,351 and 7,578,929, which are incorporated herein by reference in their entirety. Typically, when a vapor/liquefaction separation unit is used, the composition of the gas phase leaving the unit is substantially the same as the composition of the gas phase entering the unit, and likewise the composition of the liquid phase leaving the flash tank is substantially the same as the composition of the liquid phase entering the unit , that is, the gas/liquid separation device separation essentially consists of the physical separation of the two phases entering the tank.

In embodiments using a gas/liquid separation device in combination with a cracking furnace, at least a portion of the hydrocarbon component of the first mixture is provided to the inlet of the convection section of the pyrolysis unit, wherein the hydrocarbons are heated such that at least a portion of the hydrocarbons are in the gas phase. When a diluent (e.g. steam) is used, the diluent component of the first mixture is optionally (but preferably) added to this paragraph and mixed with the hydrocarbon component to produce a first mixture in which at least a portion of the first mixture is in the gas phase, and then Flashing in at least one gas/liquid separation device separates and directs away at least a portion of the high molecular weight molecules of the first mixture, such as asphaltenes, from the first mixture. A bottoms fraction may be directed away from the vapor-liquid separation device, the bottoms fraction comprising, for example, > 10.0% (by weight) of asphaltenes of the first mixture. When the pyrolysis is steam cracking and the hydrocarbon components of the first mixture comprise one or more crude oils or fractions thereof, the steam cracking furnace may be combined with a gas/liquid separation unit operating The temperature range is about 600°F (315°C) to about 950°F (510°C) and the pressure range is about 275kPa to about 1400kPa, for example, the temperature range is about 430°C to about 480°C and the pressure range is about 700kPa to 760kPa . The overhead fraction from the gas/liquid separation unit can be further heated in the convection section and then introduced into the radiant section via crossover piping, wherein the overhead fraction is exposed to a temperature ≥ 760 °C at a pressure ≥ 0.5 bar (g), for example, at a temperature ranging from about 790° C. to about 850° C. and a pressure ranging from about 0.6 bar (g) to about 2.0 bar (g), to effect pyrolysis (e.g., cracking and / or reformatting).

One of the advantages of having a gas/liquid separation device downstream of the inlet of the convection section and upstream of the intersection pipe to the radiant section is that it allows for an increased range of hydrocarbons that can be used directly as the hydrocarbon component of the first mixture without pretreatment. The hydrocarbon component of a mixture may comprise ≥ 50.0 wt.%, for example, ≥ 75.0 wt.%, such as ≥ 90.0 wt.% (based on the weight of the hydrocarbon component of the first mixture) of one or more crude oils, even higher Crude oil and its fractions with naphthenic acid content. Feeds with a high naphthenic acid content are among those that produce large quantities of tars and are particularly suitable when at least one gas/liquid separation unit is combined with the cracking furnace. If desired, the composition of the first mixture can be changed over time, for example, by applying the first mixture with the first hydrocarbon component during a first time period, and then applying the first mixture with the second hydrocarbon component at a second time. During the cycle, the first and second hydrocarbons are substantially different hydrocarbons or substantially different mixtures of hydrocarbons. The first and second periods may have substantially equal times, but this is not required. Alternating the first and second periods of time may be performed continuously or semi-continuously (eg, in "closed" operation), if desired. This embodiment can be used for the sequential heating of incompatible first and second hydrocarbon components (i.e., where the first and second hydrocarbon components are a mixture that is not sufficiently compatible to blend under ambient conditions). untie. For example, a first hydrocarbon component comprising raw crude oil may be used to produce a first mixture during a first time period and steam cracked tars to produce a first mixture during a second time period.

In other embodiments, no gas/liquid separation device is used. For example when the hydrocarbons of the first mixture comprise crude oil and/or one or more fractions of crude oil, the pyrolysis conditions may be conventional steam cracking conditions. Suitable steam cracking conditions include, for example, exposure of the first mixture to a temperature (measured at the exothermic outlet) ≥ 400°C, e.g., in the range 400°C to 900°C, and a pressure ≥ 0.1 bar, with a cracking residence time period ranging from about 0.01 seconds to 5.0 seconds. In one or more embodiments, the first mixture comprises hydrocarbons and a diluent, wherein the hydrocarbons of the first mixture comprise > 50.0 wt. % waxy residue, atmospheric residue, petroleum One or more of naphtha, residual oil mixture, or crude oil. The diluent comprises, for example, ≧95.0 wt.% water, based on the weight of the diluent. When the first mixture contains 10.0wt.%-90.0wt.% diluent, based on the weight of the first mixture, the pyrolysis conditions generally include (i) temperature range 760°C-880°C; (ii) pressure range 1.0-5.0 bar (absolute pressure), or (iii) one or more of a cracking residence time in the range of 0.10-2.0 seconds.

A second mixture is directed away from the cracking furnace, the second mixture being derived from the first mixture by pyrolysis. When using specified pyrolysis conditions, the second mixture generally comprises > 1.0 wt.% _C2 unsaturates and > 0.1 wt.% TH, the weight percentages being based on the weight of the second mixture. Optionally, the second mixture comprises >5.0 wt.% _C2 unsaturates and/or >0.5 wt.% TH, such as >1.0 wt.% TH. Although the second mixture generally contains the light olefins required for the mixture, SCN, SCGO, SCT, and unreacted components of the first mixture (such as water in the case of steam cracking, and sometimes unreacted hydrocarbons), each of these is relatively The amount generally depends on, for example, the composition of the first mixture, the layout of the cracking furnace, process conditions during pyrolysis, and the like. Usually the second mixture is directed away for the pyrolysis stage, for example, for the cooling and separation stages.

In one or more embodiments, the TH of the second mixture comprises ≥ 10.0 wt.% TH aggregates with an average particle size of 10.0 nm to 300.0 nm in at least one dimension and an average number of carbon atoms ≥ 50, the weight percent Typically, the aggregate comprises ≥ 50.0 wt.%, such as ≥ 80.0 wt.%, such as ≥ 90.0 wt.%, based on the weight of the tar heavies of the second mixture, of TH molecules having a C:H atomic ratio in the range 1.0-1.8, molecular weight range 250-5000, and melting point range 100°C-700°C.

Although not required, the present invention is suitable for cooling the second mixture on the downstream side of the cracking furnace, for example, a system comprising a transfer line heat exchanger may be used to cool the second mixture. For example, the transfer line heat exchanger can cool the process stream to a temperature of about 700°C to 350°C, which can be used by or directed away from the process for efficient production of ultrahigh pressure steam. If desired, the second mixture can be subjected to direct quenching, generally at a location between the furnace exit and the separation section. This quenching can be accomplished by contacting the second mixture with a liquid quench stream instead or additionally by treating it with a transfer line heat exchanger. If used in conjunction with at least one transfer line heat exchanger, the quench liquid is preferably introduced at a location downstream of the transfer line heat exchanger. Suitable quench liquids include liquid quench oils, such as those obtained by downstream side knock-out drums, pyrolysis of fuel oil, and water, which may be obtained from conventional sources such as condensed dilution steam.

A separation section is typically applied upstream of the lower cracking furnace and downstream of the transfer line heat exchanger and/or at the quench location to separate one or more of the second mixture of light olefins, SCN, SCGO, SCT, or water. Conventional separation equipment may be used in the separation section, for example, one or more flash tanks, fractionators, water quench towers, indirect condensers, etc., such as those disclosed in US Pat. No. 8,083,931. In the separation section, a third mixture as a tar stream can be separated from the second mixture such that the third mixture tar stream comprises > 10.0 wt.% TH of the second mixture, based on the weight of TH of the second mixture. When the pyrolysis is steam cracking, the tar stream generally comprises SCT obtained, for example, from the SCGO stream and/or the bottoms stream of the steam cracker of the primary fractionation column, flash tank bottoms (e.g., at The bottom material of one or more flash tanks on the downstream side of the cracking furnace and the upstream side of the primary fractionator), or a combination thereof.

In one or more embodiments, the tar stream comprises > 50.0 wt.% TH of the second mixture, based on the weight of TH of the second mixture. For example, the tar stream can comprise > 90.0 wt.% TH of the second mixture, based on the weight of TH of the second mixture. The tar stream can have, for example, (i) a sulfur content in the range of 0.5 wt.% to 7.0 wt.%, (ii) a TH content in the range of 5.0 wt.% to 40.0 wt.%, the weight percentages being based on the weight of the tar stream, (iii) ) a density at 15°C ranging from 1.01 g/cm ³ to 1.15 g/cm ³ , eg, 1.07 g/cm ³ to 1.15 g/cm ³ , and (iv) a viscosity at 50°C ranging from 200 cSt to 1.0x10 ⁷ cSt.

The tar stream may contain TH aggregates. In one or more embodiments, the tar stream comprises > 50.0 wt. % TH aggregates of the second mixture, based on the weight of TH aggregates of the second mixture. For example, the tar stream can comprise > 90.0 wt. % TH aggregates of the second mixture, based on the weight of TH aggregates of the second mixture.

The tar stream is typically directed away from the separation section for hydrotreating of the tar stream in the presence of a utility fluid. Examples of utility fluids useful in the present invention are now disclosed in more detail. The present invention is not limited to use with these utility fluids, and this description is not intended to exclude other utility fluids within the broad scope of the present invention.

utility fluid

The utility fluid is used in hydroprocessing the tar stream, for example, to effectively increase run duration during hydroprocessing and improve hydroprocessing product properties. Effective utility fluid aromatics, ie, comprising molecules having at least one aromatic nucleus. In one or more embodiments the utility fluid comprises > 40.0 wt.% aromatic carbons, such as > 60.0 wt.% aromatic carbons, as measured by NMR. In one or more embodiments the utility fluid comprises a portion of the liquid phase of the hydrotreated product, effectively recycled back to the hydrotreater. The remaining hydrotreated product liquid phase can be directed away from the process and optionally used as a low sulfur fuel oil blend component. The hydrotreated product may optionally pass through one or more separation stages. Non-limiting examples of separation stages can include: flash tanks, distillation columns, evaporators, strippers, steam strippers, vacuum flashers, or vacuum distillation columns. These separation stages allow those skilled in the art to adjust the properties of the liquid phase used as utility fluid. The liquid phase of the hydroprocessed product may comprise > 90.0 wt.% molecules of the hydroprocessed product 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 molecules having an atmospheric boiling point > 65.0°C, > 150.0°C, > 260.0°C in the hydroprocessed product, based on the weight of the hydroprocessed product.

In another embodiment, the entire liquid phase of the hydrotreated product separates into light liquids and heavy liquids, wherein the heavy liquids comprise 90 wt.% molecules with an atmospheric boiling point > 300°C present in the liquid phase. The utility fluid contains a portion of the light liquid obtained from this separation. Optionally, in other embodiments, the utility fluid comprising the hydrotreated product may be added or replaced with a supplemental utility fluid such as described below.

In other embodiments the utility fluid comprises aromatics (ie, comprises molecules having at least one aromatic nucleus) and ASTM D86 10% distillation point > 60°C and 90% distillation point < 350°C. Optionally, the utility fluid (which may be a solvent or solvent mixture) has an ASTM D86 10% distillation point > 120°C, for example > 140°C, such as > 150°C and/or an ASTM D86 90% distillation point < 300°C.

In one or more embodiments, the utility fluid (i) has a critical temperature of 285°C-400°C and (ii) contains ≥80.0 wt.% of 1-ring aromatics and/or 2-ring aromatics, including their alkyl groups. Functionalized derivatives, based on the weight of utility fluid. For example, the utility fluid may comprise, for example, ≧90.0 wt.% mono-ring aromatic hydrocarbons, including those with one or more hydrocarbon substituents, such as 1-3 or 1-2 hydrocarbon substituents. The aforementioned substituents may be any hydrocarbon group consistent with the overall distillation characteristics of the utility fluid. Examples of the above-mentioned hydrocarbon groups include, but are not limited to, C ₁ -C ₆ alkyl groups, wherein the hydrocarbon groups may be branched or linear and the hydrocarbon groups may be the same or different. Optionally, the utility fluid comprises ≥ 90.0 wt.% ethylbenzene, trimethylbenzene, xylene, toluene, naphthalene, alkylnaphthalene (e.g., methylnaphthalene), tetralin, or alkylnaphthalene, based on the weight of the utility fluid One or more of full (such as methyl tetralin). It is generally desired that the utility fluid be substantially free of molecules having alkenyl functionality, particularly in embodiments where such molecules are present using hydrotreating catalysts which have a tendency to form coke. In embodiments, the utility fluid comprises < 10.0 wt. % cyclic compounds having C ₁ -C ₆ side chains having alkenyl functionality, based on the weight of the utility fluid.

In certain embodiments, the utility fluid comprises SCN and/or SCGO, eg, SCN and/or SCGO, separated from the second mixture in a primary fractionation column on the downstream side of a cracking furnace operated under steam cracking conditions. The SCN or SCGO can be hydrotreated (eg not with the tar) in a different conventional hydrotreating unit. The utility fluid may comprise, for example, >50.0 wt.% separated gas oil, based on the weight of the utility fluid. In certain embodiments, at least a portion of the utility fluid is obtained from the hydroprocessed product, eg, by separating and recycling a portion of the hydroprocessed product having an atmospheric boiling point < 300°C.

Typically, the utility fluid contains a sufficient number of molecules having one or more aromatic nuclei to effectively increase the cycle time during hydroprocessing. For example, the utility fluid may comprise > 50.0 wt.% molecules having at least one aromatic nucleus, eg > 60.0 wt.%, such as > 70 wt.%, based on the total weight of the utility fluid. In embodiments, the utility fluid comprises (i) ≥ 60.0 wt.% molecules having at least one aromatic nucleus and (ii) ≤ 1.0 wt.% of C ₁ -C ₆ side chains having alkenyl functionality, the weight Percentages are based on the weight of utility fluid.

The utility fluid is used in hydrotreating the tar stream, for example, to effectively increase the cycle time during hydrotreating. The relative amounts of utility fluid and tar stream during hydroprocessing are typically about 20.0 wt.% to about 95.0 wt.% tar stream and about 5.0 wt.% to about 80.0 wt.% utility fluid, based on the total utility fluid plus tar stream weight. For example, the relative amounts of utility fluid and tar stream during hydroprocessing are typically (i) about 20.0 wt.% to about 90.0 wt.% tar stream and about 10.0 wt.% to about 80.0 wt.% utility fluid, or (ii ) from about 40.0 wt.% to about 90.0 wt.% tar stream and from about 10.0 wt.% to about 60.0 wt.% utility fluid. Optionally, the utility fluid:tar weight ratio in the hydrotreater feed is 0.05:1.0-3.0:1.0. At least a portion of the utility fluid may 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 is fed as a separate stream and combined into one feed stream prior to entry (eg, upstream of the hydroprocessing vessel or hydroprocessing zone). In certain embodiments, the feed stream to the hydrotreater comprises 40.0 wt.% to 90.0 wt.% SCT and 10.0 wt.% to 60.0 wt.% utility fluid, the weight percents being based on the feed stream the weight of.

Hydrotreating

Hydrotreating of the tar stream in the presence of a utility fluid may be carried out in one or more hydroprocessing stages comprising one or more hydroprocessing vessels or zones. Vessels and/or regions within a hydroprocessing section in which catalytic hydroprocessing operations are performed typically include at least one hydroprocessing catalyst. The catalysts may be mixed or stacked, such as when the catalysts are in the form of one or more fixed beds in a vessel or hydroprocessing zone.

Conventional hydrotreating catalysts may be used to hydrotreat the tar stream in the presence of a utility fluid, such as those designated for resid and/or heavy oil hydrotreating, although the invention is not limited thereto. Suitable hydrotreating catalysts include those comprising (i) one or more bulk metals and/or (ii) one or more supported metals. The metal may be in elemental or compound form. In one or more embodiments, the hydroprocessing catalyst includes at least one element of Groups 5-10 of the Periodic Table of Metals (published as the Periodic Chart of the Elements, The Merck Index, Merck & Co., Inc., 1996). Examples of the aforementioned catalyst 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 total amount of Group 5 to Group 10 metals of the catalyst is at least 0.0001 grams, or at least 0.001 grams, or at least 0.01 grams per gram of catalyst, where the grams are calculated on an elemental basis. For example, the catalyst comprises a total amount of Group 5-10 metals ranging from 0.0001 g to 0.6 g, or 0.001 g to 0.3 g, or 0.005 g to 0.1 g, or 0.01 g to 0.08 g. In specific embodiments, the catalyst further comprises at least one Group 15 element. An example of a preferred Group 15 element is phosphorus. When using group 15 elements, the catalyst includes a total amount of group 15 elements of 0.000001 g-0.1 g, or 0.00001 g-0.06 g, or 0.00005 g-0.03 g, or 0.0001 g-0.001 g, wherein the number of grams is calculated based on the element .

In embodiments, the catalyst comprises at least one Group 6 metal. Examples of preferred Group 6 metals include chromium, molybdenum and tungsten. The catalyst may comprise 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 per gram of catalyst, wherein the grams are calculated on an elemental basis. For example, the catalyst may comprise a total amount of Group 6 metal per gram of catalyst of from 0.0001 gram to 0.6 gram, or from 0.001 gram to 0.3 gram, or from 0.005 gram to 0.1 gram, or from 0.01 gram to 0.08 gram, 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 Group 5, Group 7, Group 8, Group 9, or Group 10 metal. The aforementioned catalyst may comprise, for example, a combination of metals in a molar ratio of Group 6 metal to Group 5 metal of 0.1 to 20, 1 to 10, or 2 to 5, wherein the ratio is calculated on an elemental basis. Alternatively, the catalyst comprises, for example, a combination of metals in a molar ratio of Group 6 metal to Group 7-10 metal of 0.1 to 20, 1 to 10, or 2 to 5, wherein the ratios are calculated on an elemental basis.

When the catalyst includes at least one Group 6 metal and one or more Group 9 or 10 metals, such as molybdenum-cobalt and/or tungsten-nickel, these metals, for example, by Group 6 metals relative to Group 9 and 10 metals present in a molar ratio of 1-10, or 2-5, wherein the ratio is calculated on an elemental basis. When the catalyst comprises at least one Group 5 metal and at least one Group 10 metal, these metals may be present, for example, in a molar ratio of 1-10, or 2-5, of Group 5 metal to Group 10 metal, wherein the ratios are calculated on an elemental basis . It is within the scope of the present invention that the catalyst also comprises inorganic oxides, for example as binder and/or support. For example, the catalyst may 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.% inorganic oxides , the weight percentage is based on the weight of the catalyst.

The present invention involves incorporation into (or deposition on) a support or catalyst metal, eg, one or more Group 5-10 and/or 15 metals, to form a hydroprocessing catalyst. The carrier is a porous material. For example, the support may comprise one or more refractory oxides, porous carbon-based materials, zeolites, or combinations thereof. Suitable refractory oxides include, for example, alumina, silica, silica-alumina, titania, zirconia, magnesia, and mixtures thereof. Suitable porous carbon-based materials include activated carbon and/or porous graphite. Examples of zeolites include, for example, Y-zeolite, beta zeolite, mordenite, ZSM-5 zeolite, and ferrierite. 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 may be from 0.0001 gram to 0.99 gram, or from 0.001 gram to 0.5 gram, or from 0.01 gram to 0.1 gram, or up to 0.1 gram , determined by X-ray diffraction. In particular embodiments, the hydroprocessing catalyst is a supported catalyst, the support comprising at least one alumina, for example, theta alumina, in an amount of 0.1 g to 0.99 g, or 0.5 g to 0.9 g, or 0.6 g to 0.8 grams, this amount is per gram of carrier. The amount of alumina can be determined using, for example, X-ray diffraction. In alternative embodiments, the support may 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 used, the support can be impregnated with the desired metals to form the hydroprocessing catalyst. Before impregnating the metal, the support may be heat-treated at 400°C-1200°C, or 450°C-1000°C, or 600°C-900°C. In certain embodiments, the hydrotreating catalyst can be formed by adding or incorporating a Group 5-10 metal to a shaped heat-treated support mixture. This type of formation is generally referred to as metallization over the support material. Optionally, the catalyst is heat treated, eg, at 150°C to 750°C, or 200°C to 740°C, or 400°C to 730°C, after the support incorporates one or more of the catalyst metals. Optionally, the catalyst is heat-treated at 400°C to 1000°C in the presence of hot air and/or oxygen-enriched air to remove volatiles and convert at least a portion of the Group 5-10 metals to their corresponding metal oxides. In other embodiments, the catalyst may be heat treated (eg, air) at 35°C to 500°C, or 100°C to 400°C, or 150°C to 300°C in the presence of oxygen. Heat treatment may be performed for a period of 1-3 hours to remove most of the volatile components without converting the Group 5-10 metals to their metal oxide forms. Catalysts prepared by the methods described above are often referred to as "green" or "dried" catalysts. The catalysts described above can be prepared in combination with the sulfide forming method, so that the Group 5-10 metal is substantially dispersed in the support. When the catalyst comprises a theta alumina support and one or more Group 5-10 metals, the catalyst is generally heat treated at > 400°C to form the hydrotreating catalyst. Generally, the above-mentioned heat treatment is carried out at ≤ 1200°C.

The catalyst shape can be, for example, one or more of discs, pellets, extrudates, etc., although these are not required. Non-limiting examples of the above shapes include those symmetrical cylinders with a diameter of about 0.79 mm to about 3.2 mm (1/32-1/8 inch), about 1.3 mm to about 2.5 mm (1/20-1/10 inch ), or about 1.3mm to about 1.6mm (1/20-1/16 inch). Likewise - non-cylindrical shapes of particle size are within the scope of the invention, eg, trilobed shapes, quadrilobed shapes, etc. Optionally, the flat plate crush strength of the catalyst is 50-500N/cm, or 60-400N/cm, or 100-350N/cm, or 200-300N/cm, or 220-280N/cm.

Porous catalysts, including those characterized by conventional pores, are within the scope of this invention. When a porous catalyst is used, the catalyst's porous structure, pore diameter, pore volume, pore shape, pore surface area, etc., are within the range of conventional hydroprocessing catalyst characterization, although the present invention is not limited thereto. For example, the median pore size of the catalyst is effective for hydroprocessing SCT molecules, said catalyst median pore size ranges from 30 Angstroms to 1000 Angstroms, or from 50 Angstroms to 500 Angstroms, or from 60 Angstroms to 300 Angstroms. Pore size can be determined according to ASTM method D4284-07 mercury porosimetry.

In particular embodiments, the hydrotreated pore size ranges from a median of 50 Angstroms to 200 Angstroms. Alternatively, the hydrotreated pore diameter has an intermediate value of 90 angstroms-180 angstroms, or 100 angstroms-140 angstroms, or 110 angstroms-130 angstroms. In another embodiment, the hydrotreated pore size ranges from a median of 50 Angstroms to 150 Angstroms. Alternatively, the hydrotreated pore size has an intermediate value of 60 angstroms to 135 angstroms, or 70 angstroms to 120 angstroms. In another alternative embodiment, hydroprocessing catalysts of larger median pore size are used, for example, those having a median pore size of 180 Angstroms to 500 Angstroms, or 200 Angstroms to 300 Angstroms, or 230 Angstroms to 250 Angstroms.

Typically, the hydrotreating catalyst pore size distribution is not broad enough to significantly reduce catalyst activity or selectivity. For example, the hydroprocessing catalyst has a pore size distribution in which at least 60% of the pores have a pore size within a median of 45 angstroms, 35 angstroms, or 25 angstroms. In certain embodiments, the catalyst has a median pore diameter of 50 angstroms to 180 angstroms, or 60 angstroms to 150 angstroms, and at least 60% of the pores have a pore diameter within the median of 45 angstroms, 35 angstroms, or 25 angstroms.

When a porous catalyst is used, the pore volume of the catalyst is, for example, ≥0.3 cm ³ /g, such as ≥0.7 cm ³ /g, or ≥0.9 cm ³ /g. In certain embodiments, the pore volume is, for example, from 0.3 cm ^{3 /} g to 0.99 cm ³ /g, from 0.4 cm 3 /g ^to 0.8 cm ³ /g, or from 0.5 cm 3 /g to 0.7 ^{cm 3} /g.

In certain embodiments, a relatively large surface area is desirable. For example, the surface area of the hydrotreating catalyst is ≥60m ² /g, or ≥100m ² /g, or ≥120m ² /g, or ≥170m ² /g, or ≥220m ² /g, or ≥270m ² /g; For example, 100m ² /g-300m ² /g, or 120m ² /g-270m ² /g, or 130m ² /g-250m ² /g, or 170m ² /g-220m ² /g.

Hydrotreating a specified amount of tar and utility fluid using a specified hydrotreating catalyst results in improved catalyst life, e.g., allowing the hydrotreating section to operate for at least 3 months (7.8×10 ⁶ seconds), or at least 6 months (1.6×10 ⁷ seconds), or at least 1 year (3.2×10 ⁷ seconds) without replacing the catalyst in the hydrotreating or contacting zone. Catalyst life is typically >10 times longer than without utility fluid, eg >100 times longer, such as >1000 times longer.

Hydroprocessing is carried out in the presence of hydrogen, for example, by (i) combining molecular hydrogen with the tar stream and/or utility fluid upstream of hydroprocessing and/or (ii) directing molecular hydrogen in one or more pipelines or pipelines to the hydrotreating section. Although relatively pure molecular hydrogen can be used for the hydroprocessing, it is often desirable to apply a "treat gas" that 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 or affect the reaction or the product. Typically after removal of unwanted impurities such as _H2S and _NH3 , unused process gas can be separated from the hydrotreated product for re-use. The treat gas optionally comprises > about 50 vol.% molecular hydrogen, eg, > about 75 vol.%, based on the total volume of treat gas directed into the hydrotreating section.

Optionally, the amount of molecular hydrogen provided to the hydrotreating section is about 300 SCF/B (standard cubic feet per barrel) (53S m ³ /m ³ ) to 5000 SCF/B (890 S m ³ /m ³ ), where B Refers to the tar logistics barrel. For example, molecular hydrogen is provided in the range of 1000 SCF/B (178S m ³ /m ³ ) to 3000 SCF/B (534S m ³ /m ³ ). Hydroprocessed products prepared by hydroprocessing a tar stream under catalytic hydroprocessing conditions in the presence of a specified utility fluid, molecular hydrogen, and a catalytically effective amount of a specified hydroprocessing catalyst include, for example, upgraded SCT. Examples of suitable catalytic hydroprocessing conditions are now disclosed in more detail. The present invention is not limited to these conditions, and this description is not intended to exclude other hydroprocessing conditions within the broad scope of the present invention.

This hydrotreating is usually carried out under hydroconversion process conditions, for example, in hydrocracking (including selective hydrocracking), hydrogenation, hydrotreating, hydrodesulfurization, hydrodenitrogenation, etc. , under the conditions of one or more of hydrodemetallization, hydrodearomatization, hydroisomerization, or hydrodewaxing. The hydroprocessing reaction may be carried out in at least one vessel or zone located, for example, within the hydroprocessing section of the pyrolysis section and downstream of the separation section. The designated tar stream contacts the hydrotreating catalyst in the presence of utility fluid and molecular hydrogen, typically in a vessel or zone. Catalytic hydrotreating conditions that may be used may include, for example, exposing the combined diluent-tar stream to 50°C to 500°C or 200°C to 450°C or 220°C to 430°C or 350°C to 420°C in proximity to molecular hydrogen and Hydrotreating catalysts. For example, the temperature range is 300°C-500°C, or 350°C-430°C, or 360°C-420°C. The combined utility fluid tar stream weight hourly space velocity (WHSV) generally ranges from 0.1h ^-1 to 30h ^-1 , or from 0.1h ^-1 to 25h ^-1 , or from 0.1h- ¹ to 4.0h ^-1 . In some embodiments, the LHSV is at least 0.1h ⁻¹ , 5h ⁻¹ , or at least 10h ⁻¹ , or at least 15h ⁻¹ . The partial pressure of molecular hydrogen during hydroprocessing usually ranges from 0.1 MPa to 8 MPa, or from 1 MPa to 7 MPa, or from 2 MPa to 6 MPa, or from 3 MPa to 5 MPa. In some embodiments, the molecular hydrogen partial pressure is ≤7 MPa, or ≤6 MPa, or ≤5 MPa, or ≤4 MPa, or ≤3 MPa, or ≤2.5 MPa, or ≤2 MPa. The hydrotreating conditions may include, for example, a temperature of 300°C-500°C, a pressure of 15 bar (absolute pressure)-135 bar, a space velocity of 0.1-5.0 WHSV, and a molecular hydrogen consumption rate of about 53 standard cubic meters per volume of tar. m (S m ³ /m ³ ) to about 445 S m ³ /m ³ (300SCF/B-2500SCF/B). In one or more embodiments, the hydroprocessing conditions generally include a temperature of 380°C-430°C, a pressure of 21 bar (absolute pressure)=81 bar (absolute pressure), a space velocity of 0.2-1.0, and a hydrogen consumption rate of about 71S One or more of m ³ /m ³ to about 267S m ³ /m ³ (400SCF/B-1500SCF/B). When operating under these conditions using the specified catalyst, the TH hydroconversion is typically ≥ 25.0% by weight, eg, ≥ 50.0%.

Mitigation of fouling/coking of preheating equipment

The problem of coking fouling of preheating equipment can be reduced or eliminated by, for example, certain embodiments of the present invention, some embodiments of which are now disclosed in more detail with reference to FIGS. 2-4. It is clear that these methods can be used alone or in combination. The present invention is not limited to these embodiments, and this description is not intended to exclude other fouling reduction methods within the broad scope of the present invention.

In FIGS. 2-4 , devices that implement substantially the same function as in FIG. 1 are identified by the same reference numerals.

Figure 2 depicts an embodiment in which the lower temperature first reactor section is used to minimize the risk of coking fouling in the reactor preheat sequence. This embodiment uses additional heat sources: pre-heaters 51 and 53. Heat source 51 may be, for example, a heat exchanger to further preheat the hydrotreater feed by dissipating heat from the hydrotreater effluent via line 121 on the downstream side of heat exchanger 70 guide. Heat source 53 may be, for example, a second line of tubing in conditioning heater 90 . This embodiment also utilizes a first lower temperature stage 110 hydroprocessing reactor in which the first reactor stage stream 54 is only heated to 500°F-600°F (260°C-315°C) and is not heated at that temperature. Reactor feed preheaters 51 and 53 will foul. In practice, the first reactor section (or zone) operates at a temperature at least 100° C. lower than the second hydrotreater section (or zone) 111 . Optionally, the first reactor stage can be operated at a temperature at least 50°C or 25°C lower than that of the second stage. The effluent 55 from the first stage reactor 110 is expected to be thermally stable and optionally thereafter further preheated to No risk of coking fouling.

The first hydroprocessing stage 110 hydrotreats the most coking active precursors (asphaltenes, cyclodienes, vinyl aromatics, olefins, dienes, oxygenates) so that the resulting first stage reactor effluent 55 can be further In the preheater 90, it is heated to the inlet temperature of the second stage reactor without coking. The feed side of the feed/effluent heat exchanger 70 is also protected from coking by this layout. This embodiment can also be achieved by selecting a high activity catalyst for catalyst bed 115, which allows the first stage reactor to operate at lower temperatures.

Lower reactor inlet temperatures below which coking of tar occurs is possible by using more active hydrotreating catalysts including, but not limited to:

a.Nebula20 obtained from Albemarle

b. Criterion DN3651, DN3551

c. Albermarle KF860

Increasing the utility fluid/tar ratio in the reactor feed reduces feed coking up to a point. The method as illustrated in Figure 2 is consistent with a utility fluid/tar ratio of 40 wt% utility fluid/60 wt% tar. Raising this ratio tends to reduce coking because the utility fluid does not form coke, eg, where the reactor feed has a utility fluid:tar weight basis > 0.7, eg > 1.0, such as > 3.0.

Figure 3 depicts an embodiment where the SCT feed surrounds the reactor feed/effluent heat exchanger and feed conditioning heaters to avoid the risk of tar coking. In this embodiment, the SCT 10 is not heated in the reactor feed/effluent heat exchanger 70 or reactor feed conditioning heater 90 but brought to a temperature close to the reactor inlet or the reactor feed distributor Internally the hydrogen has been sufficiently superheated in the reactor feed/effluent heat exchanger 70 and reactor feed conditioning heater 90 when it is mixed with the utility fluid and hydrogen 91 . Hydrogen 60 and utility fluid 20 are mixed and directed to the feed side of reactor feed/effluent heat exchanger 70 and then to reactor feed conditioning heater 90 and heated above the desired reactor inlet temperature. Hot mixture 91 is then mixed with SCT 50 and the entire mixture 100 enters reactor 110 now at the desired reactor inlet temperature. The risk of tar coking fouling has been mitigated or eliminated in the reactor feed/effluent heat exchanger 70 and reactor feed conditioning heater 90 because the SCT feed is not preheated. Optionally, in another embodiment not shown in Figure 3, only the utility fluid passes through the feed/effluent heat exchanger. The tar feed, utility fluid, and recycle hydrogen can then be heated in the reactor feed adjustment heater.

The rationale for this embodiment is not to preheat the tar stream to a temperature above that which would create coking problems. Instead, the preheat energy is provided by heating the utility fluid and hydrogen above the desired reactor inlet temperature and then mixing the tar stream with the higher temperature utility fluid and hydrogen at or very close to the reactor inlet , where mixing is achieved to the desired reactor inlet temperature and immediate contact with the catalyst and initiation of the hydrotreating reaction.

In another embodiment the reactor feed/effluent heat exchanger and feed trim heater are redundant. This selection mitigates the effects of any tar-coking fouling. This prudence would allow on-line or off-line decoking and more importantly continuous reactor operation. The downstream side of the feed heater may include a tank to recover the spalled coke during the decoking operation. This rationale is also used in any method layout to supplement anti-coking risk mitigation.

Feeds are applied ^to tune the heater structure to achieve higher mass flux ^, lower heat flow of less than 31,500W/ ^m2 , and less than 910 °F (488°C) maximum film temperature minimizes coking.

Figure 4 depicts an embodiment in which heat is applied to the catalyst bed at the top of the reactor to minimize the risk of coking fouling. The SCT is not preheated in the reactor feed/effluent heat exchanger 70 or reactor feed conditioning heater 90, but is heated by supplying external heat 102 to at least the first as the reaction progresses within the reactor 110 itself. Catalyst bed 118 is gradually brought to temperature. For example the first catalyst bed can be designed as a tubular reactor with the catalyst in the tube and the heat transfer fluid in the shell. In one embodiment the heat is provided by the heat transfer fluid in streams 102 and 101 that are simultaneously heated and fed.

In other embodiments streams 102 and 101 may represent steam or hot process fluid or any other heat source, eg, external electrical wall heaters. This approach was observed to reduce or eliminate fouling in pilot plant studies. It was found that preheating the tar, utility fluid and hydrogen while in the presence of the catalyst resulted in much more successful, coke-free operation than preheating prior to contacting the catalyst. It should be understood that the catalyst bed structure of the tubular reactor is within the scope of knowledge of those skilled in the art. Also, the temperature control system can be designed by those skilled in the art of process control, taking into account that heat is added to the exothermic reaction zone.

The utility fluid and hydrogen can optionally be preheated as required in the reactor feed/effluent heat exchanger 70 and reactor feed conditioning heater 90 to make energy more efficient and reduce the Heat source heating requirements. The SCT is not preheated in the reactor feed/effluent heat exchanger 70 or reactor feed conditioning heater 90 . In another embodiment not shown in Figure 4 the SCT may be preheated to a temperature low enough to avoid coking or fouling.

In embodiments utilizing hydroprocessed liquid product recycle as the utility fluid, the recycle may be degassed by taking the recycle from the bottoms of a stabilizer distillation column. This liquid recycle can also be taken from the flash separator bottoms.

Example

过程模拟软件是一种稳态的模拟器，能改善过程设计以及运算分析。它是设计成能实施用于许多化学过程的严格的质量以及能量平衡计算。用于

模拟反应器进料以及产物表征基于沸点曲线(模拟蒸馏GC,ASTM D2887)以及来自实验数据的密度。Below is an example implementation depicted in Figures 2-4, calculated using Process simulation software, obtained from Invensys Inc.

Process simulation software is a steady-state simulator that improves process design and operational analysis. It is designed to perform rigorous mass and energy balance calculations for many chemical processes. for

Simulated reactor feed and product characterization were based on boiling point curves (simulated distillation GC, ASTM D2887) and densities from experimental data.

For all embodiments, with reference to Figures 1, 2, 3, and 4, the separation section 130 represents conventional separation equipment for hydroprocessing, including high-temperature and low-temperature separators, stabilization towers, acid gas removal, and auxiliary equipment such as heat exchangers and Recycle gas compressor. Optionally, light fuel and heavy fuel oil separations are provided to produce two hydroprocessed products. The light fuel oil is used as utility fluid 20 in this option.

Hydrotreater effluent stream 122 enters separation section 130 . The equipment described above in the separation section separates this stream into products and by-products including the hydrotreated product 134, purge gas stream 132, and light gas stream 133, which can be used as fuel gas. If optional light fuel and heavy fuel oil fractionation columns are provided, stream 134 represents two separate products, light fuel oil and heavy fuel oil. Make-up hydrogen enters separation section 130 as stream 131 . Stream 60 is recycled hydrogen rich gas. In all cases, H ₂ S and NH ₃ are removed before stream 60 is sent back to the hydrotreater and in separation section 130 .

Comparative Example 1

In the comparative example depicted in FIG. 1 , as indicated, there is a risk of coking fouling on the feed side of the reactor feed/effluent heat exchanger 70 and the reactor inlet feed trim heater 90 . In all examples, unless otherwise stated, the catalyst is considered to be a conventional hydrotreating catalyst, such as RT-621, obtained from Albermarle. The required hydrotreating or reactor inlet 100 for this catalyst is considered to be 750°F (400°C) and 995 psig (67 bar).

Example 2

Figure 2 depicts an embodiment in which a lower temperature first reactor section is used to minimize the risk of coking fouling in the reactor preheat sequence. This embodiment uses a first lower temperature section 110 hydroprocessing reactor using a higher activity catalyst such as Nebula 20 Criterion DN3651, DN3551 or Albermarle KF860 so that the first reactor section feed 54 is only heated to 600°F (375°C) . The first stage reactor effluent 55 reaches 611°F (322°C). Here, however, the most coking-active precursors (asphaltenes, cyclodienes, vinylaromatics, olefins, dienes, oxygenates) have been hydrotreated. The first stage reactor effluent 55 is then heated to 742°F (394°C) in the feed preheat heat exchanger 70 and heated to a second stage reactor inlet temperature of 750°F (400°C) in the preheater 90 ). The second stage reactor 111 contains two RT-621 catalyst beds 116,117.

Example 3

FIG. 3 depicts an embodiment wherein the SCT feed surrounds the reactor feed/effluent heat exchanger 70 and reactor feed conditioning heater 90 . The SCT feed stream 50 is at 534°F (279°C) in this example. Hydrogen 60 and utility fluid 20 are mixed and directed to the feed side of reactor feed/effluent heat exchanger 70 and heated to 780°F (415°C) versus 804°F (429°C) reactor effluent 120 . Heated stream 80 is then directed to reactor feed conditioning heater 90 and heated to 940°F (504°C). This 940°F (504°C) hot mixture 91 is then mixed with the 534°F (279°C) SCT 50 and the entire mixture 100, now at the desired reactor inlet temperature of 750°F (400°C), enters reactor 110.

Example 4

Figure 4 depicts an embodiment in which heat is applied to the catalyst bed at the top of the reactor to minimize the risk of coking fouling. The SCT does not preheat in the reactor feed/effluent heat exchanger 70 or the reactor feed conditioning heater 90, but instead steps up to 750°F (400°C) reaction temperature with the first catalyst zone in the reactor 110 The reaction proceeded within 118. Hydrogen 60 and utility fluid 20 are mixed and directed to the feed side of reactor feed/effluent heat exchanger 70 and then to reactor feed conditioning heater 90 and heated to 750°F (400°C). This mixture 100 then enters reactor 110 . SCT feed stream 50 at 534°F (279°C) also enters reactor 110 . The first catalyst bed 118 is designed as a tubular reactor with RT-621 catalyst in the tube and heat transfer fluid in the shell. The mixture 100 of heated hydrogen and utility fluid mixes with the SCT feed stream and enters the tube 118 containing the catalyst and begins the reaction. Heat transfer fluid stream 102 enters 118 shell side heat at 800°F-850°F (427°C-454°C) to the reactor and exits as stream 101 which can then be tuned to another tray in preheat furnace 90 Tube heating (not shown). The SCT feed, utility fluid, and hydrogen mixture exit the tubular reactor 118 at the desired reaction temperature of 750°F (400°C) and enter catalyst beds 116 and 117 containing RT-621 catalyst.

All patents, test procedures, and other documents cited in this application, including priority documents, are fully incorporated by reference to the extent such disclosure is consistent with this application and for all jurisdictions for which such citation is permitted.

While the illustrative forms of the present disclosure have been described in detail, it is clear 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 to limit the scope of the claims appended hereto to the examples and descriptions set forth in this application, but the claims are construed to encompass all of the patentable novel features of this disclosure, including those to which this disclosure pertains. All features are considered equivalents by those skilled in the art.

Where numerical lower limits and numerical upper limits are listed in this application, ranges from any lower limit to any upper limit are contemplated.

Claims (21)

1. A process for hydrocarbon conversion comprising: (a) providing a first mixture comprising > 10.0 wt.% hydrocarbons, based on the weight of the first mixture; (b) pyrolyzing the first mixture to produce a second mixture comprising ≥ 1.0 wt.% _C2 unsaturates and ≥ 1.0 wt.% tar, the weight percentages being based on the weight of the second mixture; (c) separating a tar stream from the second mixture, wherein the tar stream comprises ≥ 90 wt.% of molecules of the second mixture having an atmospheric boiling point ≥ 290°C; (d) Provide a utility fluid that contains ≥ 1.0 wt.% aromatics, based on the weight of the utility fluid; (e) providing a hydrogen stream comprising molecular hydrogen; (f) by (i) exposing the tar stream to a temperature of 200.0°C to 400.0°C, (ii) exposing the utility fluid to a temperature > 400.0°C and then combining the tar stream with the heated utility fluid , and/or (iii) heating the tar stream by one or more of exposing the hydrogen stream to a temperature > 400.0°C and then combining the tar stream with the heated hydrogen stream; (g) in the hydroprocessing zone at a utility fluid:tar stream weight ratio of from 0.05 to Catalytic Hydroprocessing Conditions of 3.0 Hydrotreating at least a portion of the heated tar stream to produce a hydrotreated product, wherein the utility fluid comprises > 10.0 weight percent of the hydrotreated product, based on the weight of the utility fluid. 2. The method of claim 1, wherein the hydrotreated product is produced continuously for at least 6.0 x ¹⁰⁵ seconds. 3. The method of claim 1 or 2, wherein the hydrotreated product is produced continuously for at least 2.6×10 ⁶ seconds. 4. The method of claim 1 or 2, wherein the hydrotreated product is produced continuously for at least 3.2×10 ⁷ seconds. 5. The method of any one of claims 1-4, wherein the hydrocarbons of the first mixture comprise naphtha, gas oil, vacuum gas oil, waxy residue, atmospheric residue, residue mixture, or crude oil one or more of . 6. The method of any one of claims 1-5, wherein the tar of the second mixture comprises (i) ≥ 10.0 wt.% non-asphaltene molecules having an atmospheric boiling point ≥ 565°C and (ii) ≤ 1000.0 ppmw metals, The weight percent is based on the weight of the tar of the second mixture. 7. The process of any one of claims 1-6, wherein the hydrotreating is carried out at a temperature of 200.0°C to 450.0°C in the presence of at least one hydrotreating catalyst. 8. The process of any one of claims 1-7, wherein in step (f)(i) the tar is heated to a temperature of 200.0°C to 300.0°C. 9. The method of any one of claims 1-8, wherein step (f)(i) comprises (A) directing the tar stream through at least one heater, wherein the tar stream extracts heat, (B) directing the tar stream passing the stream through a first channel of at least one heat exchanger and directing at least a portion of the hydrotreated product through a second channel of a heat exchanger to extract heat from the hydrotreated product to the tar stream, or (C) at least A portion of this tar stream reacts exothermically. 10. The method of any one of claims 1-9, wherein (i) the hydrotreated product comprises ≥ 10.0 wt.% light fuel oil component and ≥ 10.0 wt.% heavy fuel oil component, based on The weight of the hydrotreated product, (ii) the utility fluid accounts for ≥ 90.0 wt.% of the fuel oil component, based on the amount of the utility fluid, and (iii) the light fuel oil component has an ASTM D86 10% Distillation point ≥ 60.0°C and 90% distillation point ≤ 350.0°C. 11. The method of any one of claims 1-8, wherein step (f)(i) comprises directing the tar stream together with the utility fluid through at least one heater, wherein the tar stream and the utility fluid pass from the heater absorb heat. 12. The method of any one of claims 1-8, wherein step (f)(i) comprises directing the hydrogen stream, the tar stream together with the utility fluid through at least one heater, wherein the tar stream, the utility fluid The fluid and the hydrogen flow extract heat from the heater. 13. The method of any one of claims 1-8, wherein step (f) comprises heating the utility fluid to a temperature > 425.0°C and combining the tar stream with the heated utility fluid. 14. A process for hydrocarbon conversion comprising: (a) providing a first mixture comprising > 50.0 wt.% hydrocarbons, based on the weight of the first mixture; (b) pyrolyzing the first mixture in the presence of steam to produce a second mixture comprising > 1.0 wt.% _C2 unsaturates and > 1.0 wt.% tar, the weight percentages being based on the weight of the second mixture; (c) separating a tar stream from the second mixture, wherein the tar stream comprises ≥ 90 wt.% of molecules of the second mixture having an atmospheric boiling point ≥ 290°C; (d) Provide a utility fluid that contains ≥ 1.0 wt.% aromatics based on the weight of the utility fluid; (e) providing a hydrogen stream comprising molecular hydrogen; (f) by (i) directing the tar stream through at least one heater, (ii) directing the tar stream through a first channel of at least one heat exchanger and directing a heat transfer fluid through a second channel of the heat exchanger to One or more of extracting heat from the heat transfer fluid to the tar stream, or (iii) heating the utility fluid to a temperature > 425.0°C and combining the tar stream with the heated utility fluid. 200.0℃-400.0℃ temperature; (g) hydrotreating at least a portion of the tar stream in the presence of the hydrogen stream and the utility fluid in the hydrotreating zone under catalytic hydrotreating conditions, the hydrotreating conditions comprising a temperature range of 300°C to 500°C, a pressure of range 15 bar (abs) to 135 bar (abs), and a utility fluid:tar weight ratio of 0.05-3.0, wherein (i) the utility fluid contains ≥ 50.0 wt.% of the hydrotreated product, based on the weight of the utility fluid; and (ii) the heat transfer fluid comprises the hydrotreated product in an amount > 50.0 wt%, based on the weight of the heat transfer fluid. 15. The method of claim 14, wherein the hydroprocessing zone comprises at least two catalyst beds, wherein at least external heating is provided to the first catalyst bed. 16. The method of claim 15, wherein external heat is supplied to the first catalyst bed comprising a plurality of tubes comprising at least one hydrotreating catalyst and directing at least a portion of the tar stream, the hydrogen stream, and the utility A fluid is passed through the plurality of tubes under catalytic hydrotreating conditions, and the external heat is provided to an outer surface of the plurality of tubes. 17. The method of claims 14-16, wherein the pressure drop across the hydroprocessing zone is 3.0 times less than the initial pressure drop across the hydroprocessing zone. 18. The process of claims 14-17, wherein the hydrogen consumption per unit volume of the hydrotreated tar stream does not exceed 267 S ^m3 / ^m3 . 19. The method of claims 14-18, wherein the hydroprocessing zone is divided into at least a first and a second hydroprocessing zone and wherein the first hydroprocessing zone is at least 100°C lower than the second hydroprocessing zone operate. 20. The process of claims 14-19, wherein the hydroprocessing zone comprises at least one bed of high activity hydroprocessing catalyst. 21. The method of claim 20, wherein the catalyst is selected from Nebula20, Criterion DN3651, Criterion DN3551, or Albermarle KF860, and combinations thereof.

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