KR102005137B1 - Residue hydrocracking processing - Google Patents

Abstract

The process for upgrading the residual hydrocarbons of the present invention comprises the steps of solvent deasphalting the residue hydrocarbon fraction to produce a deasphalted oil fraction and an asphalt fraction; Contacting the asphalt fraction and hydrogen with a first hydrogen conversion catalyst in a first ebullated-bed hydroconversion reactor system; Recovering the effluent from the first boiling-point hydrogen conversion reactor system; And separating the effluent from the first boiling hydrogen conversion reactor system to recover one or more hydrocarbon fractions.

Description

RESIDUE HYDROCRACKING PROCESSING [0002]

The embodiments disclosed herein generally relate to hydrogen conversion processes including processes for the hydrocracking of residual oil and other heavy hydrocarbon fractions. More specifically, the embodiments disclosed herein are directed to solvent deasphalting of residu hydrocarbon feedstock, treatment of the resulting deasphalted oil in a residue desulfurization unit, It relates to the treatment of pitch from solvent deasphalted units in the unit of the residue hydrocracking.

As global demand for gasoline and other distillate refinery products such as kerosene, jet and light oil increases, there is a significant trend towards the transition from higher boiling point compounds to lower boiling point products come. In order to meet the growing demand for distillate fuels, refiners are working to add residuum, vacuum gas oil (VGO), and other heavy oil feedstocks to hydrogen to convert them into jet and diesel fuels (RDS), and solvent deasphalting (SDA) have been studied.

The catalysts have been developed to show good distillate selectivity, reasonable conversion activity and stability to heavier feedstocks. However, the conversion rates obtainable by the various processes are limited. For example, RDS units can produce 1 wt.% Sulfur fuel alone from high sulfur residues, but conversion is generally limited to about 35% to 40%. Others have proposed the use of SDA units to solvent deasphalting the residue feedstock and treating the deasphalted oil only in a residuum hydrocracking unit (RHU). Others have also recycled deasphalted oil (DAO) back to the RHU front end by treating the non-conversion decompression residue from RHU in the SDA unit. Others have suggested that SDA pitch be handled directly in RHU. Nonetheless, economical processes are required to achieve high hydrocarbon conversion and sulfur removal.

In one aspect, the embodiments disclosed herein relate to a process for upgrading residuum hydrocarbons. The process may comprise the steps of: solvent deasphalting the residue hydrocarbon fraction to produce a deasphalted oil fraction and an asphalt fraction; Contacting the asphalt fraction and hydrogen with a first hydrogen conversion catalyst in a first ebullated-bed hydroconversion reactor system; Recovering the effluent from the first boiling-point hydrogen conversion reactor system; And separating the effluent from the first boiling hydrogen conversion reactor system to recover one or more hydrocarbon fractions.

In another aspect, embodiments disclosed herein relate to a process for upgrading residuum hydrocarbons comprising the following steps: solvent deasphalting a residue hydrocarbon fraction to produce deasphalted oil fraction and asphalt oil ; Contacting the asphalt fraction and hydrogen with a first hydrogen conversion catalyst in a first boiling-point hydrogen conversion reactor system; Recovering the effluent from the first boiling-point hydrogen conversion reactor system; Separating the effluent from the first boiling-point hydrogen conversion reactor system to recover one or more hydrocarbon fractions; Contacting the deasphalted oil fraction and hydrogen with a second hydrogen conversion catalyst in a residual hydrodesulfurization unit; Recovering the effluent from the residual hydrodesulfurized units; Contacting said residue hydrodesulfurized unit effluent with a third hydrogen conversion catalyst in a hydrocracking reactor system; Recovering the effluent from the hydrogen conversion reactor system; And fractionating the effluent from the hydrocracking reactor system to recover one or more hydrocarbon fractions.

In another aspect, the embodiments disclosed herein relate to a process for upgrading residuum hydrocarbons comprising the following steps: solvent deasphalting the residue hydrocarbon fraction to produce a deasphalted oil fraction and an asphalt fraction ; Contacting the asphalt fraction and hydrogen with a first hydrogen conversion catalyst in a first boiling-point hydrogen conversion reactor system; Recovering the effluent from the first boiling-point hydrogen conversion reactor system; Separating the effluent from the first boiling-point hydrogen conversion reactor system to recover one or more hydrocarbon fractions; Contacting the deasphalted oil fraction and hydrogen with a second hydrogen conversion catalyst in a residual hydrodesulfurization unit; Recovering the effluent from the residual hydrodesulfurized units; Separating the effluent from the hydrogenation reactor system to recover one or more hydrocarbon fractions comprising a reduced pressure residue hydrocarbon fraction; Contacting the reduced-pressure residue hydrocarbon fraction with a third hydrogen conversion catalyst in a hydrocracking reactor system; Recovering the effluent from the hydrocracking reactor system; And fractionating the effluent from the hydrocracking reactor system to recover one or more hydrocarbon fractions.

Other aspects and advantages will be apparent from the following description and the appended claims.

Figure 1 is a simplified process flow diagram of a process for upgrading residue hydrocarbon feedstocks in accordance with embodiments disclosed herein.
Figure 2 is a simplified process flow diagram of a process for upgrading residue hydrocarbon feedstocks in accordance with embodiments disclosed herein.
Figure 3 is a simplified process flow diagram of an integrated hydroprocessing reactor system for use with processes for upgrading residue hydrocarbon feedstocks in accordance with embodiments disclosed herein.
Figure 4 is a simplified, alternative process flow diagram of an integrated hydroprocessing reactor system for use with processes for upgrading residue hydrocarbon feedstocks in accordance with embodiments disclosed herein.

In one aspect, embodiments of the present invention generally relate to hydrogen conversion processes including processes for hydrocracking residues and other heavy hydrocarbon fractions. More specifically, the embodiments disclosed herein are directed to solvent deasphalting of a residue hydrocarbon feedstock, treatment of the deasphalted oil in residuum desulfurization units and residual hydrocracking units, and in separate residual hydrocracking units To the treatment of pitch from solvent deasphalting.

The hydrogen conversion processes disclosed herein can be used to react residue hydrocarbon feedstocks under elevated temperature and pressure conditions in the presence of hydrogen and at least one hydrogen conversion catalyst to convert the feedstock into reduced contaminant levels (such as sulfur and / or nitrogen) Lt; RTI ID = 0.0 > low molecular weight < / RTI > Hydrogen conversion processes include, for example, hydrogenation, hydrodesulfurization, hydrodenitrogenation, hydrocracking, hydrodemetallization, hydrogenated DeCCR (hydroDeCCR) Or hydrogen deasphaltenization, and the like.

As used herein, residue terms or other terms referring to residue hydrocarbons are defined as hydrocarbon fractions having a boiling point or boiling point region above about 340 ° C, but may also include the entire heavy crude oil treatment process . Residual hydrocarbon feedstocks that can be used in conjunction with the processes disclosed herein include various refinery and other similar hydrocarbon oil streams or combinations thereof, as well as atmospheric or reduced pressure residues, deasphalted oils, deasphalter pitch, hydrogenated Decomposed gas or liquid hydrocarbons, cracked tower bottoms or depressurized bottoms, DC vacuum gas streams, hydrocracked vacuum gas streams, fluid catalytically cracked (FCC) slurry streams, Shale-derived oils, carbon-derived oils, bio-derived crude oils, tar sands bitumen, tall oils, And black oils, where each hydrocarbon stream is treated by direct current, process derived, hydrocracked, partially desulfurized, It may be a metal / or part of the ride. In some embodiments, the residue hydrocarbon fractions may comprise hydrocarbons having a standard boiling point of at least 480 ° C, at least 524 ° C, or at least 565 ° C.

Referring now to FIG. 1, a residue hydrocarbon fraction (residue) 10 is fed to a solvent deasphalted unit (SDA) 12. In SDA 12, the residual hydrocarbons can produce a deasphalted oil (DAO) fraction 14 and a pitch fraction 15 by selectively dissolving asphaltenes and similar hydrocarbons in contact with a solvent.

Solvent deasphalting can be performed in the SDA 12, for example, by contacting the residue hydrocarbon feed with a light hydrocarbon solvent at a temperature ranging from about 38 ° C to about 204 ° C and a pressure ranging from about 7 barg to about 70 barg have. Solvents useful in SDA 12 may include C4, C5, C6 and / or C7 hydrocarbons, such as, for example, propane, butane, isobutene, pentane, isopentane, hexane, heptane, have. The use of light hydrocarbon solvents can provide a high lift (high DAO yield). In some embodiments, the DAO fraction 14 recovered from the SDA unit 12 contains 500 wppm to 5000 wppm of asphaltenes (i.e., insoluble heptane), 50 to 150 wppm of metals (Ni, V, and others ), And from 5% to 15% by weight of Conradson Carbon Residue (CCR).

The pitch fraction 15 may then be mixed with a diluent 17 such as a straight run vacuum gas oil (SRVGO) to produce a diluted pitch (residue) fraction 19. The diluted pitch fraction 19 and hydrogen 21 may then be fed to a boiler bed reactor system 42 which may comprise one or more boiler bed reactors wherein the boiling point hydrogen and hydrogen are converted into hydrogen conversions Contacting at least a portion of the pitch with hydrogen to form lighter hydrocarbons, demetallating the pitch hydrocarbons, removing the Conradson carbon residue, or converting other residues to useful products.

In the boiling layer reactor 42, the reactors are operated at a temperature in the range of about 380 ° C to 450 ° C, a partial pressure of hydrogen in the range of about 70 bara to about 170 bara, and a liquidus space velocity in the range of about 0.2 h ^-1 to about 2.0 h ^-1 . In boiling bed reactors, the catalyst can be backmixed and maintained in a random motion state by recirculation of the liquid product. This can be accomplished by first separating the recycled oil from the products in the gaseous phase. The oil may then be recycled by an external pump or a pump having a stirrer mounted on the lower head of the reactor as shown.

The target conversion in the boiling-bed reactor system 42 may range from about 40 wt% to about 75 wt%, depending on the feedstock being treated. In any case, the target conversion rates should be kept below the level at which the formation of sediment is excessive, thereby interrupting the continuity of operation. In addition to converting the residual hydrocarbons to lighter oil hydrocarbons, the sulfur removal may be in the range of about 40 wt% to about 80 wt%, the metal removal may be in the range of about 60 wt% to 85 wt% , The Conradson carbon residue (CCR) removal may be from about 30% to about 65% by weight.

Following conversion in boiler bed reactor system 42, the partially converted hydrocarbons can be recovered via flow line 44 as a combined gas / liquid effluent and fed to fractionation system 46 to produce one or more hydrocarbon fractions Can be recovered. As shown, the fractionation system 46 includes an offgas 48 containing light hydrocarbon gases and hydrogen sulfide (H ₂ S), a light naphtha fraction 50, a heavy naphtha fraction 52, The gas feed fraction 54, the gas feed fraction 56, the light pressure gas fraction 58, the heavy gas fraction 60, and the reduced pressure residue fraction 62. In some embodiments, the reduced pressure residue fraction 62 may be recycled to the SDA unit 12, the boiling bed reactor system 42, or other reactor units 16, 20 mentioned below for further processing . In other embodiments, the reduced-pressure residue fraction 62 may be mixed with a cutter fraction 66 to produce fuel oil.

The fractionation system 46 may include, for example, a high pressure, high temperature (HP / HT) separator to separate the effluent vapor from the effluent liquids. The separated steam may be subjected to gas cooling, refining, and recycle gas compression, or may be passed through an integrated hydroprocessing reactor system, either alone or in an external distillate and / or a distillate produced in a hydrocracking process , Followed by a process of gas cooling, refining, and compression.

The separated liquid from the HP / HT separator may be flashed and transferred to an atmospheric distillation system along with other distillate products recovered from the gas cooling and purification section. Atmospheric tower beds, such as hydrocarbons having an initial boiling point of at least about 340 ° C, such as an initial boiling point in the range of about 340 ° C to about 427 ° C, may then be further processed through a reduced pressure distillation system to recover the reduced pressure distillates.

The reduced pressure bed products, such as hydrocarbons having an initial boiling point of at least about 480 캜, such as an initial boiling point in the range of about 480 캜 to about 565 캜, can be separated by direct heat exchange or a portion of the residue hydrocarbon feedstock into the reduced pressure bed products After cooling, such as by direct injection into the tank facility.

In some embodiments, the fuel oil fraction 62 recovered from subsequent treatment in the boiler bed reactor system 42 and fractionation system 46 is 2.25 wt% or less; Up to 2.0% by weight in other embodiments; And in other embodiments up to 1.75 wt% sulfur content.

The deasphalted fraction 14 recovered from the SDA unit 12 can be selectively heated in combination with the hydrogen rich gas 23 and fed to the residual desulfurization (RDS) unit 16. The RDS unit 16 may comprise one or more residual sulfur desulfurization reactors.

In some embodiments, the RDS unit 16 may include one or more upflow reactors (UFRs) (not shown) upstream of the RDS reactors. The DAO feedstock may be mixed with the feedstock entering the hydrogen rich gas 23 or downstream of the UFRs upstream of the reactors and may be mixed with the effluent recovered from the UFRs in some embodiments. UFR can help increase catalyst lifetime in downstream RDS catalyst layers as well as removing some sulfur, Conradson carbon residues, and asphaltenes from the feed.

The operating conditions in the RDS unit 16, including UFRs and / or RDS reactors, can include a temperature in the range of about 360 ° C to about 400 ° C and a hydrogen partial pressure in the range of about 70 barg to about 170 barg. RDS can achieve a desulfurization rate of at least 70 wt% in some embodiments, at least 80 wt% in other embodiments, and at least 92 wt% in yet other embodiments.

The effluent 18 recovered from the RDS unit 16 may then be further treated in a hydrocracker reactor system 20 comprising one or more hydrocracking reactors disposed in series or in parallel.

In the reactor system 20, the RDS effluent has a hydrogen partial pressure in the range of about 70 bara to about 170 bara, a temperature in the range of about 380 ° C to about 450 ° C, and a hydrogen partial pressure in the range of about 0.2 h ^-1 to about 2.0 h ^-1 RTI ID = 0.0 > LHSV. ≪ / RTI > In some embodiments, the operating conditions in the hydrocracker reactor system 20 may be similar to those described above for the boiler reactor system 42. In other embodiments, such as where the hydrocracking reactor system 20 comprises one or more boiling-point reactors, the boiling-point reactors may be operated at higher severity conditions than the reactor system 42, Where higher hard conditions refer to higher temperatures, higher pressures, lower space velocities, or combinations thereof.

Depending on the degree to which the depressurized residue feedstock properties, metals and Conraddon carbon residues are removed in the RDS unit 16, and the SDA solvent used, the recovered DAO can be fed to a fixed bed reactor system or to a boiling layer reactor system (20), which may be similar to the boiler bed reactor system 42 described above with respect to gas / liquid separation and catalyst recycle among other similarities. Fixed bed reactor systems may be used, for example, in the fixed bed reactor system, the metals and the Conrads carbon residuals content of the DAO may be less than 80 wppm and less than 10 wt%, respectively, specifically less than 50 wppm and less than 7 wt%, respectively .

Boiling bed reactor systems may be used, for example, when metals and Conrads carbon residuals contents are higher than the contents of the fixed bed reactor system. In a both hydrocracking reactor system, the number of reactors used may depend on other factors such as the charge rate, the total target residual conversion rate level, and the conversion rate obtained in the RDS unit (16). In some embodiments, one or more hydrocracking reactors may be used in hydrocracker reactor system 20. [

Following conversion in hydrocracking reactor system 20, the partially converted hydrocarbons are withdrawn via stream line 22 as a combined vapor / liquid effluent and fed to fractionation system 24 to recover one or more hydrocarbon fractions can do. As shown, the fractionation system 24 includes a flue gas 26, a light naphtha fraction 28, a heavy naphtha fraction 30, a kerosene fraction 32, a gas oil fraction 34, , A heavy vacuum gas fraction 38, and a vacuum residue fraction 40. The vacuum distillation fraction 40 can be any of the following: In some embodiments, the reduced-pressure residual oil fraction 40 may be recycled for further processing. In other embodiments, the reduced-pressure residual oil fraction 40 may be mixed with the cutter fraction 64 to produce fuel oil.

The fractionation system 24 may include a high pressure, high temperature (HP / HT) separator, for example, to separate the effluent vapor from the effluent liquid. The separated steam may be subjected to gas cooling, refining, and recycle gas compression or may be passed through an integrated hydroprocessing reactor system (IHRS) alone or in the form of distillates produced in external distillates and / , Followed by a process of gas cooling, refining, and compression.

The separated liquid from the HP / HT separator may be flashed and transferred to an atmospheric distillation system along with other distillate products recovered from the gas cooling and purification section. Atmospheric tower beds, such as hydrocarbons having an initial boiling point of at least about 340 ° C, such as an initial boiling point in the range of about 340 ° C to about 427 ° C, may then be further processed through a reduced pressure distillation system to recover the reduced pressure distillates.

The reduced pressure bed products, such as hydrocarbons having an initial boiling point of at least about 480 캜, such as an initial boiling point in the range of about 480 캜 to about 565 캜, can be separated by direct heat exchange or a portion of the residue hydrocarbon feedstock into the reduced pressure bed products After cooling, such as by direct injection into the tank facility.

The total conversion of the DAO fraction through the RDS unit 16 and the hydrocracker reactor system 20 may range from about 75 wt% to about 95 wt%, specifically from about 85 wt% to about 90 wt% .

In some embodiments, the fuel oil fraction 40 that is subsequently treated and recovered in the RDS unit 16, the hydrocracker reactor system 20, and the fractionation system 24 is 1.25 wt% or less; 1.0% by weight or less in other embodiments; And in other embodiments no more than 0.75 wt% sulfur.

The catalysts useful in RDS reactors, URFs, and boiling layer reactors may include any catalyst useful for hydrotreating or hydrocracking hydrocarbon feedstocks. The hydrotreating catalyst may include any catalyst composition that can be used, for example, to increase the hydrogen content and / or to promote the hydrogenation reaction of the hydrocarbon feedstocks to remove heteroatom contaminants . Hydrocracking catalysts may include, for example, any catalyst composition that can be used to catalyze the addition of hydrogen to large or complex hydrocarbon molecules, as well as to decompose molecules to obtain smaller, lower molecular weight molecules have.

The hydrogen conversion catalyst compositions used in the hydrogen conversion process according to the embodiments disclosed herein are well known to those of ordinary skill in the art and some are described in W.R. Commercially available from Grace & Co., Criterion Catalysts & Technologies, and Albemarle. Suitable hydrogen conversion catalysts may comprise one or more elements selected from groups 4-12 of the Periodic Table of the Elements. In some embodiments, the hydrogen conversion catalysts according to embodiments disclosed herein may include one or more of nickel, cobalt, tungsten, molybdenum, and tantalum, which are not supported or supported on a porous support, such as silica, alumina, titania, And combinations thereof, or may be constructed or essentially configured. As obtained from the manufacturer or as obtained from the regeneration process, the hydrogen conversion catalysts may be in the form of, for example, metal oxides. In some embodiments, the hydrogen conversion catalysts can be pre-sulfided and / or pre-sulfated or pre-conditioned before entering the hydrocracking reactor (s).

Distillate hydrotreating catalysts that may be useful include catalysts selected from those known to provide catalytic hydrogenation activity. At least one metal component selected from Group 8-10 elements and / or Group 6 elements is generally selected. Group 6 elements may include chromium, molybdenum, and tungsten. Groups 8-10 elements may include iron, cobalt, nickel, ruthenium, rhodium, palladium, osmium, iridium and platinum. The amount (s) of hydrogenated component (s) in the catalyst is calculated as the metal oxide (s) for 100 parts by weight of the total catalyst, suitably from about 0.5% to about 0.5% To about 10%, and from about 5% to about 25% of the Group 6 metal component (s) in a weight ratio, wherein the percent by weight ratio is based on the weight of the catalyst before sulfiding. The hydrogenation components of the catalyst may be in the form of oxides and / or sulfides. If at least the combination of Group 6 and Group 8 metal components is present as (mixed) oxides, they will be sulfided prior to proper use in hydrocracking. In some embodiments, the catalyst may comprise one or more components of nickel and / or cobalt and one or more components of molybdenum and / or tungsten or one or more components of platinum and / or palladium. Nickel and catalysts containing molybdenum, nickel and tungsten, platinum and / or palladium are useful.

Residual hydrotreating catalysts that may be useful are generally hydrogenated components selected from Group 6 elements (such as molybdenum and / or tungsten) and Group 8-10 elements (cobalt and / or nickel), or mixtures thereof Wherein the hydrogenation components can be supported on an alumina support. Phosphorous (Group 15) phosphorous oxide is optionally present as an active ingredient. Typical catalysts may contain from 3 to 35 weight percent hydrogenation components with an alumina binder. The catalyst pellets may range in size from 1/32 inch to 1/8 inch and may be spherical, extruded, trilobate or quadrilobate. In some embodiments, the feedstock passing through the catalyst zone first contacts a predetermined catalyst for metal removal, even though some sulfur, nitrogen and aromatics removal may also occur. Subsequent catalyst layers can be used for sulfur and nitrogen removal, albeit also expected to facilitate removal of metals and / or decomposition reactions. The catalyst layer (s) for demetallization, when present, can include catalyst (s) having an average pore size in the range of 125 to 225 Angstroms and a pore volume in the range of 0.5-1.1 cm 3 / g. The catalyst bed (s) for denitrification / desulfurization may include catalyst (s) having an average pore size in the range of 100 to 190 Angstroms and a pore volume in the range of 0.5-1.1 cm < 3 > / g. US Pat. No. 4,990,243 describes a hydrotreating catalyst having a pore size of at least about 60 angstroms, and preferably a pore size of about 75 angstroms to about 120 angstroms. Metal removal catalysts useful in the present process are described, for example, in US Pat. No. 4,976,848, the entire disclosure of which is incorporated herein by reference for any purpose. Thus, catalysts useful for desulfurization of heavy streams are described, for example, in US Patents 5,215,955 and 5,177,047, the entire disclosure of which is incorporated herein by reference for any purpose. Catalysts useful for desulfurization of middle distillate, reduced gas oil streams and naphtha streams are described, for example, in US Pat. No. 4,990,243, the entire disclosure of which is incorporated herein by reference in its entirety for all purposes, .

Useful Residue Hydrotreating catalysts include catalysts having a porous refractory substrate comprised of alumina, silica, phosphorous, or various combinations thereof. One or more types of catalysts can be used as a residual hydrotreating catalyst, and where more than one catalyst is used, the catalysts can exist as layers in the reactor region. The catalysts in the lower layer (s) may have good demetalization activity. The catalysts may also have hydrogenation and desulfurization activity, and it may be advantageous to use catalysts of large pore size to maximize the removal of metals. Catalysts with these properties are not optimal for removal of Conradson carbon residues and sulfur. The average pore size of the catalyst in the underlying layer or layers can typically be at least 60 angstroms, and in many cases can be considerably larger. The catalyst may contain a metal or a combination of metals such as nickel, molybdenum, or cobalt. Catalysts useful in the underlying layer or layers are described in US Patents 5,071,805, 5,215,955, and 5,472,928. For example, those catalysts based on the nitrogen process, such as those described in US Pat. No. 5,472,928, and having at least 20% of the pores in the range of 130 to 170 angstroms, may be useful for the lower catalyst layer (s). The catalysts present in the upper layer or layers of the catalyst zone should have greater hydrogenation activity when compared to the catalysts in the lower layer or layers. As a result, useful catalysts in the top layer or layers may be characterized by smaller pore sizes and larger Conradson carbon residue removal, denitrification and desulfurization activity. Typically, the catalysts may contain metals such as, for example, nickel, tungsten, and molybdenum to enhance hydrogenation activity. For example, such catalysts based on the nitrogen process, such as those described in US Pat. No. 5,472,928 and having at least 30% of pores in the range of 95 to 135 angstroms, may be useful in the upper catalyst layers. The catalysts can be shaped catalysts or spherical catalysts. Dense, less brittle catalysts can also be used in upflow fixed catalyst areas to minimize breakage of the catalyst particles in the product recovered from the reactor and entrainment of particulates.

One of ordinary skill in the art will appreciate that various catalyst layers can not consist of just one catalyst type but can be made of a mixture of different catalyst types to achieve an optimum level of removal of metals or Conradson carbon residue removal and desulfurization Lt; / RTI > Removal of the Conradson carbon residues, nitrogen, and sulfur may occur predominantly in the upper layer or layers, although some hydrogenation may occur in the lower portion of the region. Apparently additional metal removal can also occur. The specific catalyst or catalyst mixture for each layer, the number of layers in the region, the proportional volume in the bed of each layer, and the specific hydrotreating conditions selected are not only considered commercial considerations such as the cost of the catalyst The feedstock being treated by the unit, and the desired product to be recovered. All of these parameters are within the purview of those skilled in the petroleum refining industry, and can not be further described herein.

Referring now to FIG. 2, like numerals represent like parts, and a simplified process flow diagram for enhancing the residue hydrocarbon feedstocks in accordance with the embodiments disclosed herein is shown. As described above with respect to FIG. 1, the residue hydrocarbon feedstock 10 is treated through the SDA unit 12 and the resulting pitch fraction is treated in a boiling-bed reactor system 42 and a fractionation system 46. The deasphalted oil fraction 14 may be combined with the hydrogen rich gas 23 and fed to the RDS unit 16, which may comprise one or more residual sulfur desulfurization reactors.

The effluent 18 recovered from the RDS unit 16 may then be processed in the fractionation system 24 to produce the reduced-pressure residue fraction 40 as well as one or more hydrocarbon fractions 26, 28, 38. The reduced pressure residue fraction 40 and optionally one or more additional heavier hydrocarbon fractions recovered in the fractionation system 24 may then be fed to the hydrocracker reactor system 20 to produce additional distillate range hydrocarbons. Following conversion in the reaction system 20, the effluent 22 can be fractionated to recover various distillate hydrocarbon fractions. In some embodiments, effluent 22 can be fractioned with effluent 18 in a combined fractionation system that processes fractionation system 24 (as shown) or effluents 18, 44 .

The advantageous combination of SDA and RDS together with the boiling layer hydrogenolysis reactors can still result in a sulfur content of 1% by weight even when treating residual sulfur containing high sulfur such as, for example, having 6.5% During the production of sulfur stable diesel oil, the conversion of the DAO fraction can be increased to a very high level, such as 85% to 90% by weight. The treatment of the SDA pitch in a separate reaction / separation train converts the pitch from 40 wt% to 65 wt% to atmospheric and reduced pressure distillate boiling point materials while adding 2 wt% sulfur stabilized fuel Oil can be produced. The combined total conversion obtained from both treatment trains may be in the range as high as about 55 wt.% Or 60 wt.% To about 95 wt.% Or higher, and specifically may range from about 65 wt.% To about 85 wt.% . Furthermore, these conversion rates can be advantageously obtained without precipitate formation, which can lead to plugging and discontinuous operation when precipitates are formed.

Example

In the following examples, an Arabinian heavy vacuum residue of 40 k BPSD was first treated with a 73 vol% lift in SDA units. The physical properties of the obtained DAO and SDA pitches are summarized in Table 1. DAO containing 4.27% by weight of sulfur, 10% by weight of CCR and 47 wppm of Ni + V were then treated in RDS units to reduce the sulfur content of the feed from 85 to 87%. At the same time, the residual fraction of the feedstock was converted to 35 to 45%. In this example, the RDS effluent was subsequently hydrocracked in a single boiling-point reactor coupled in close proximity to the RDS reactor to increase the overall conversion to 85 vol% and the total HDS to 91.8 wt%. The resulting unconverted oil (UCO) was estimated to have a sulfur content of about 1.0 wt.% And 11.9 DEG and API gravity, respectively. The UCO from this reactor system is expected to meet low sulfur fuel oil requirements without the addition of additional cutterstock. The conversion rate and the total space velocity required to achieve this level of desulfurization is estimated to be about 0.2 hr < ^-1 >.

DAO  And SDA  Pitch property Properties VR raw material DAO SDA  pitch Feed rate, kBPSD 40.0 29.2 10.8 API Gravity 4.81 10.58 -8.68 importance 1.0381 0.9959 1.1521 Sulfur, weight% 5.2 4.27 7.37 Nitrogen, wt% 0.40 0.25 0.75 Oxygen, wt% 0.12 0.09 0.19 CCR, wt% 25 10 60 Ni + V, wppm 270 47 790 565 캜 -, volume%
565 DEG C +, vol% 10
90 13.7
86.3
100

In addition, a separate boiling layer reactor, containing 55% by volume of SDA pitch and then operating in parallel with the RDS and hydrocracking reactors, containing a single reactor and producing an intermediate sulfur vacuum residue containing 2.6% by weight of sulfur System. After the addition of the cutterstock, the resulting fuel days may contain less than 2% by weight of sulfur and certainly less than 1.5% by weight of sulfur, depending on the fuel oil blending components. The reactor space velocity for the pitch conversion unit is estimated to be about 0.25 h < ^{-1 &} gt ;, which results in an RDS plus 0.22 h < ^-1 > plus DAO hydrocracking reactor and the overall space velocity of the pitch conversion reactor.

The overall conversion rate obtained for this batch is 75 vol.%, Producing about 12,096 BPSD diesel, 12,332 BPSD hydrocracker or FCC raw material, 4,506 BPSD LS fuel oil and 4,760 BPSD intermediate sulfur reduced residual oil . The total yields and product properties for this treatment batch are given in Table 2.

Residual hydrocracking process
Total yield and properties Raw material weight% volume % importance API S,
weight% N, wt% CCR, wt% V, wppm Ni, wppm 360-565 C 9.3 10.0 0.9659 15.00 3.75 0.20 0.50 One 0.5 565 C + 90.7 90.0 1.046 3.770 5.35 0.42 27.51 226 72 Sum 100.0 100.0 1.038 4.815 5.2 0.40 25 205 65 Total product yield and properties product weight% volume % importance API S,
weight% N,
weight% CCR, wt% V, wppm Ni, wppm H ₂ S 4.75 NH ₃ 0.22 H ₂ O 0.09 C1 1.17 C2 1.04 C3 1.51 C4 1.44 2.57 0.584 C5-145C 11.08 15.73 0.7313 61.99 0.04 0.02 145-370C 30.24 36.46 0.8608 32.89 0.23 0.07 370-565C 28.00 30.83 0.9428 18.59 0.85 0.24 0.5 One <1 LS Residue
(565 C +) 9.64 10.14 0.9868 11.90 1.02 0.27 15.5 18 13.2 MS residue (565 C +) 12.91 11.90 1.1262 -5.86 2.60 0.73 53.4 164 111 Sum 102.09 107.63 C5 + 91.87 105.06 0.9077 24.39 0.8119 0.2292 C4 + 93.31 107.63 0.8999 25.73 0.7993 0.2256 Chemical H ₂ S Cons 1425.98 Total reject, wt% HDS 85.9 HDN 45.4 CCR 65.9 vanadium 88.7 nickel 75.6

Figures 3 and 4 illustrate two implementations for IHRS and are described below, but other implementations will be apparent to those of ordinary skill in the art. Figure 3 shows an embodiment in which the IHRS is installed in the downstream stream of the boiler bed reactor system 42. Figure 4 shows an embodiment in which the IHRS is installed in the downstream stream of the hydrocracker reactor system 20.

3, the effluent stream 44 from the boiling hydrotreater 42 can be cooled in a heat exchanger (not shown) and heated to boiling hard products below about 1000 &lt; 0 &gt; F standard boiling point and distillation The vapor stream containing the liquids and the liquid stream containing the unconverted residue can be supplied to the HP / HT V / L separator 81 which can be separated and processed separately in the downstream flow device. The vapor stream 67 may be fed to a fixed bed hydrotreater 86 to perform a hydrotreating, hydrogenating separation or a combination thereof. The effluent stream 68 from the IHRS fixed bed reactor system 86 is passed through the exhaust gas stream 48 described above, a light hydrotreated or hydrocracked naphtha stream 50, a heavy hydrotreated or hydrocracked naphtha stream 52, , A hydrotreated or hydrocracked kerosene stream 54, a hydrotreating or hydrocracked gas stream 56, and the like. The liquid stream 63 may be cooled in a heat exchanger (not shown) and may be cooled in a hard water or hydrocracked VGO stream 58, a heavy water or hydrodissolved VGO stream 60 and a non- (Not shown) prior to being fed to a decompression fractionation system 72 that recovers the adsorbent 62. In some embodiments, the reduced pressure bed product stream, such as hydrocarbons having an initial boiling point of at least about 480 캜, and in particular an initial boiling point in the range of about 480 캜 to about 565 캜, May be transferred to the tank facility after cooling, such as by directing a portion of the product to the decompression column bottoms product.

4, in a replaceable IHRS flow scheme, the effluent stream 22 from the boiler reactor system 20 can be cooled in a heat exchanger (not shown) and cooled to a temperature below about 1000 [deg.] F standard boiling point The vapor stream containing the boiling hard products and distillates and the liquid stream containing the unconverted residue can be fed to an HP / HT V / L separator 181 which can be separated and processed separately in the downstream flow device. The vapor stream 167 may be fed to a process bed hydrotreater 186 to perform hydrotreating, hydrocracking, or a combination thereof. The effluent stream 168 from the IHRS fixed bed reactor system 166 is passed through a flue gas stream 26, a light hydrotreated or hydrocracked naphtha stream 28, a heavy hydrotreated or hydrocracked naphtha stream 30, Treated or hydrocracked kerosene stream 32, a hydrotreating or hydrocracked diesel stream 34, and the like. The liquid stream 163 is cooled in a heat exchanger (not shown), depressurized in a pressure reduction system (not shown), pressurized to a light hydrogenated or hydrogenolyzed VGO stream 36, a heavy hydrogenated or hydrogenolyzed VGO To the decompression fractionation system 172 for recovering the stream 38 and the non-transformed reduced-pressure residue stream 40. In some embodiments, the reduced pressure bed product stream, such as hydrocarbons having an initial boiling point of at least about 480 캜, and in particular an initial boiling point in the range of about 480 캜 to about 565 캜, May be transferred to the tank facility after cooling, such as by directing a portion of the product to the decompression column bottoms product.

While described with respect to two independent fractionation systems 24 and 46, the implementations disclosed herein also contemplate discerning flows 22 and 44 in a common fractionation system. For example, the effluents may be fed in common gas cooling, refining, and compression cycling prior to further processing in the above described atmospheric tower and reduced pressure tower. The use of a combined separation scheme can provide a reduced capital investment if desired, but can result in the production of a single fuel oil fraction having an intermediate sulfur level obtained by separate treatment. The combined separation scheme can also be used in conjunction with the IHRS fed by the combined effluents 22, 44 installed in the downstream stream of both the boiler reactor system 42 and the hydrocracker reactor system 20 .

As described above, the embodiments disclosed herein efficiently integrate SDA and RDS with residual hydrocracking, while extending the residual ratio conversion rate beyond what can be obtained by residual hydrocracking alone . Further, higher conversion rates can be obtained using smaller catalyst reactor volumes compared to other schemes proposed to obtain similar conversion rates. Further, embodiments disclosed herein can be used to produce fuel oil having less than 1 wt.% Sulfur from high sulfur containing residual feedstock while maximizing total conversion.

Advantageously, by limiting the conversion rate, the initial SDA can cause hydrocracking of the pitch to operate at relatively high temperature and space velocities without prone to form excessive precipitates. Also, since the DAO can have a very low asphaltene content, the hydrocracking of the DAO can also be performed at relatively high temperature and space velocities. As a result, the entire process schemes disclosed herein can still be performed using low reactor volumes while achieving high conversion rates. Thus, other obtained advantages may include: reduced catalyst consumption rate due to rejection of metals from asphalt from SDA units; Reduced capital investment; And, above all, the elimination or significant reduction of the need for the injection of slurry oil in the upstream stream of boiling layer reactors.

While the present disclosure includes a limited number of implementations, those of ordinary skill in the art having the benefit of this disclosure will appreciate that other embodiments may be devised which do not depart from the scope of the invention. Accordingly, the scope should be limited only by the appended claims.

Claims (22)

Deasphalting the residue hydrocarbon fraction to solvent deasphalting to produce a deasphalted oil fraction and an asphalt fraction;
Feeding the asphalt fraction produced in said solvent deasphalting to a first ebullated-bed hydroconversion reactor system;
Contacting the produced asphalt fraction and hydrogen with the first hydrogen conversion catalyst in the first boiling-point hydrogen conversion reactor system;
Recovering the effluent from the first boiling-point hydrogen conversion reactor system;
Separating the effluent from the first boiling-point hydrogen conversion reactor system to recover one or more hydrocarbon fractions;
Contacting the deasphalted oil fraction and hydrogen with a second hydrogen conversion catalyst in a fixed bed residue hydrodesulfurization unit;
Recovering the effluent from the fixed bed residue hydrodesulfurization unit; And
Contacting the fixed bed residue hydrodesulfurized unit effluent or a portion thereof with a third hydrogen conversion catalyst in a second ebullated-bed hydrocracking reactor system, wherein the residuum hydrocarbons ). The method according to claim 1,
Further comprising the step of mixing the asphalt fraction with a diluent to form a diluted asphalt fraction prior to the contacting step. 3. The method of claim 2,
The diluent is a process for upgrading residual hydrocarbons including straight run reduced pressure gas oil. The method according to claim 1,
Further comprising fractionating the effluent from the second ebullated-bed hydrocracking reactor system to recover one or more hydrocarbon fractions. delete The method according to claim 1,
Wherein the deasphalted fraction is a process for upgrading residual hydrocarbons having a metal content in the range of 50 to 150 ppm by weight and a Conradson carbon residue (CCR) content in the range of 5 to 15% by weight. 5. The method of claim 4,
Wherein the effluent from the first boiling hydrogen conversion reactor system and the hydrocracking reactor system is fractionated in a common fractionation system. 5. The method of claim 4,
Wherein the one or more hydrocarbon fractions produced by fractionating the effluent from one or both of the first boiling-point hydrogenation reactor system and the second boiling-point hydrocracking reactor system are separated from the residual hydrocarbons comprising the reduced-pressure residue hydrocarbon fraction Advanced Process. 9. The method of claim 8,
Further comprising recycling the reduced-pressure residue hydrocarbon fraction to at least one of the solvent deasphalting, the first boiling-point hydrocarbon reactor system, and the second boiling-point hydrocracking reactor system. The method according to claim 1,
The residue hydrocarbon fraction may be recovered from the crude hydrocarbon fraction under reduced pressure or reduced pressure residues, deasphalted oils, deasphalter pitch, hydrogenolyzed normal bottoms or reduced pressure bottoms, The present invention relates to a process for the production of hydrocarbon-derived oils, for example, hydrocarbons, reduced pressure gas oils, fluid catalytically cracked (FCC) slurry oils, reduced pressure gas streams from boiling layers, shale-derived oils, A process for upgrading residual hydrocarbons comprising at least one of bio-derived crude oils, tar sands bitumen, tall oils and black oils. The method according to claim 1,
Contacting in the first boiling hydrogen conversion reactor system results in hydrocarbon conversion in the range of 40 wt% to 75 wt%, sulfur removal in the range of 40 wt% to 80 wt% By weight and 60% by weight to 85% by weight, and the Conradson Carbon Residue (CCR) removal is 30% to 65% by weight of the residue hydrocarbons. 5. The method of claim 4,
Wherein the total conversion of the deasphalted oil fraction through both the fixed bed residual oil desulfurization unit and the hydrocracking reactor system is in the range of 75 wt% to 95 wt%. 5. The method of claim 4,
Wherein the fuel oil produced through fractionation of the second boiling range hydrocracking reaction system effluent is a process for upgrading residual hydrocarbons having a sulfur content of up to 1% by weight. The method according to claim 1,
Wherein the fuel oil produced through fractionation of the first boiling layer reaction system effluent is a process for upgrading residual hydrocarbons having a sulfur content of up to 2% by weight. 5. The method of claim 4,
Wherein the total conversion of the residue hydrocarbon fraction is in the range of 60 wt% to 95 wt%. The method according to claim 1,
The solvent used in the solvent deasphalted unit is a process for upgrading residual hydrocarbons which are light hydrocarbons containing 3 to 7 carbon atoms. The method according to claim 1,
Further comprising the step of contacting the effluent from the first boiling hydrogen conversion reactor with a second hydrogen conversion catalyst prior to fractionation of the effluent from the first boiling hydrogen conversion reactor system, . 5. The method of claim 4,
Further comprising contacting the effluent from the second boiling point hydrocracking reactor system with a second hydrogen conversion catalyst prior to fractionating the effluent from the second boiling point hydrocracking reactor system, Advanced Processes. Solvent deasphalting the residue hydrocarbon fraction to produce a deasphalted oil fraction and an asphalt fraction;
Contacting the asphalt fraction and hydrogen with a first hydrogen conversion catalyst in a first boiling-point hydrogen conversion reactor system;
Recovering the effluent from the first boiling-point hydrogen conversion reactor system;
Separating the effluent from the first boiling-point hydrogen conversion reactor system to recover one or more hydrocarbon fractions;
Contacting the deasphalted oil fraction and hydrogen with a second hydrogen conversion catalyst in a fixed bed residue hydrodesulfurization unit;
Recovering the effluent from the fixed bed residue hydrodesulfurization unit;
Contacting the fixed bed residue hydrodesulfurized unit effluent with a third hydrogen conversion catalyst in a second boiling point hydrocracking reactor system comprising at least one boiling hydrocracking reactor;
Recovering the effluent from the second boiling point hydrocracking reactor system; And
Fractionating the effluent from the second boiling point hydrocracking reactor system to recover one or more hydrocarbon fractions. Solvent deasphalting the residue hydrocarbon fraction to produce a deasphalted oil fraction and an asphalt fraction;
Contacting the asphalt fraction and hydrogen with a first hydrogen conversion catalyst in a first boiling-point hydrogen conversion reactor system;
Recovering the effluent from the first boiling-point hydrogen conversion reactor system;
Separating the effluent from the first boiling-point hydrogen conversion reactor system to recover one or more hydrocarbon fractions;
Contacting the deasphalted oil fraction and hydrogen with a second hydrogen conversion catalyst in a fixed bed residue hydrodesulfurization unit;
Recovering the effluent from the fixed bed residue hydrodesulfurization unit;
Fractionating the effluent from the fixed bed residue hydrodesulfurization unit to recover one or more hydrocarbon fractions comprising a reduced pressure residue hydrocarbon fraction;
Contacting the reduced-pressure residue hydrocarbon fraction with a third hydrogen conversion catalyst in a second boiling-point hydrocracking reactor system comprising at least one boiling-point hydrocracking reactor;
Recovering the effluent from the second boiling point hydrocracking reactor system; And
Fractionating the effluent from the second boiling point hydrocracking reactor system to recover one or more hydrocarbon fractions. Solvent deasphalting the residue hydrocarbon fraction to produce a deasphalted oil fraction and an asphalt fraction;
Contacting the asphalt fraction and hydrogen with a first hydrogen conversion catalyst in a first boiling-point hydrogen conversion reactor system;
Recovering the effluent from the first boiling-point hydrogen conversion reactor system;
Contacting the effluent from the first boiling-point hydroconversion reactor with a second hydrogen-conversion catalyst prior to fractionation of effluent from the first boiling-point hydrogen-transformation reactor system to recover one or more hydrocarbon fractions;
Contacting the deasphalted oil fraction and hydrogen with a third hydrogen conversion catalyst in a fixed bed residual hydrodesulfurization unit;
Recovering the effluent from the fixed bed residue hydrodesulfurization unit;
Contacting the fixed bed residue hydrodesulfurized unit effluent with a fourth hydrogen conversion catalyst in a second boiling point hydrocracking reactor system comprising at least one boiling hydrocracking reactor;
Recovering the effluent from the second boiling point hydrocracking reactor system; And
Fractionating the effluent from the second boiling point hydrocracking reactor system to recover one or more hydrocarbon fractions. Solvent deasphalting the residue hydrocarbon fraction to produce a deasphalted oil fraction and an asphalt fraction;
Contacting the asphalt fraction and hydrogen with a first hydrogen conversion catalyst in a first boiling-point hydrogen conversion reactor system;
Recovering the effluent from the first boiling-point hydrogen conversion reactor system;
Separating the effluent from the first boiling-point hydrogen conversion reactor system to recover one or more hydrocarbon fractions;
Contacting the deasphalted oil fraction and hydrogen with a second hydrogen conversion catalyst in a fixed bed residue hydrodesulfurization unit;
Recovering the effluent from the fixed bed residue hydrodesulfurization unit;
Contacting the fixed bed residue hydrodesulfurized unit effluent or a portion thereof with a third hydrogen conversion catalyst in a second boiling point hydrocracking reactor system comprising at least one boiling hydrocracking reactor;
Recovering the effluent from the second boiling point hydrocracking reactor system; And
Contacting the effluent from the second boiling point hydrocracking reactor system with a fourth hydrogen conversion catalyst prior to fractionating the effluent from the hydrocracking reactor system to recover one or more hydrocarbon fractions; The process of upgrading the residual hydrocarbons involved.

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