SLURRY HYDROCRACKING PROCESS USING SPENT HYDROPROCESSING CATALYST

Abstract

A slurry hydrocracking process using spent hydroprocessing catalyst is described. The process includes obtaining the spent hydroprocessing catalyst from a hydroprocessing zone; reducing the size of the spent hydroprocessing catalyst; and introducing a heavy hydrocarbon feed and a hydrogen stream into a slurry hydrocracking zone in the presence of the reduced size spent hydroprocessing catalyst under slurry hydrocracking conditions to form a slurry hydrocracking effluent.

Description

BACKGROUND OF THE INVENTION

As the reserves of conventional crude oils decline, heavy oils must be upgraded to meet world demands. In heavy oil upgrading, heavier materials are converted to lighter fractions and most of the sulfur, nitrogen and metals must be removed. Heavy oils include materials such as petroleum crude oil, atmospheric tower bottoms products, vacuum tower bottoms products, heavy cycle oils, shale oils, coal derived liquids, crude oil residuum, topped crude oils and the heavy bituminous oils extracted from oil sands. These heavy hydrocarbon feedstocks may be characterized by low reactivity in visbreaking, high coking tendency, poor susceptibility to hydrocracking and difficulties in distillation. Most residual oil feedstocks which are to be upgraded contain some level of asphaltenes which are typically understood to be heptane insoluble compounds as determined by ASTM D3279 or ASTM D6560. Asphaltenes are high molecular weight compounds containing heteroatoms which impart polarity.

Heavy oils must be upgraded in a primary upgrading unit before they can be further processed into useable products. Primary upgrading units known in the art include, but are not restricted to, coking processes, such as delayed or fluidized coking, and hydrogen addition processes such as ebullated bed or slurry hydrocracking (SHC). As an example, the yield of liquid products, at room temperature, from the coking of some Canadian bitumens is typically about 55 to 60 wt-% with substantial amounts of coke as by-product. On similar feeds, ebullated bed hydrocracking typically produces liquid yields of 50 to 55 wt-%. U.S. Pat. No. 5,755,955 describes an SHC process which has been found to provide liquid yields of 75 to 80 wt-% with much reduced coke formation through the use of additives.

In SHC, a three-phase mixture of heavy liquid oil feed cracks in the presence of gaseous hydrogen over solid catalyst to produce lighter products under pressure at an elevated temperature. Iron sulfate has been disclosed as an SHC catalyst, for example, in U.S. Pat. No. 5,755,955.

During an SHC reaction, it is important to minimize coking Asphaltenes present as a byproduct from the SHC reaction product can, if not managed properly, self-associate, or flocculate to form larger molecules, generate a mesophase and precipitate out of solution to form coke. Mesophase formation is a critical reaction constraint in SHC reactions.

The catalysts for SHC are typically iron based. These iron based catalysts have lower hydrogenation activity than molybdenum based catalysts. Currently, the SHC reactions are thermal in nature with coke suppression being the target of the catalyst.

The addition rate to obtain the same hydrogenation activity in suppressing coke formation with the molybdenum-containing catalyst is therefore much lower than what is required for bauxite or ferrous sulfate catalyst.

However, molybdenum is an expensive metal and when used in ppm quantities as a bulk metal slurry catalyst, recovery is not efficient. Sustainable molybdenum management would improve the economics associated with using molybdenum catalyst.

U.S. Pat. No, 8,617, 955 described an SHC catalyst comprising molybdenum impregnated onto alumina. When this catalyst was charged to the reaction at a 300 wppm concentration in hydrocarbon, it provided equivalent activity to an iron catalyst while greatly lowering the amount of solids circulating through the reactor. The base provided bulk to the molybdenum catalyst allowing easier recycle and/or recovery. In addition, alumina in the base greatly suppressed formation of mesophase which leads to coke.

Although the catalyst described in U.S. Pat. No. 8,617, 955 is economically viable, it would be desirable to obtain a less expensive, yet effective molybdenum catalyst for SHC processes.

SUMMARY OF THE INVENTION

One aspect of the invention is a slurry hydrocracking process using spent hydroprocessing catalyst process. In one embodiment, the process includes obtaining the spent hydroprocessing catalyst from a hydroprocessing zone; reducing the size of the spent hydroprocessing catalyst; and introducing a heavy hydrocarbon feed and a hydrogen stream into a slurry hydrocracking zone in the presence of the reduced size spent hydroprocessing catalyst under slurry hydrocracking conditions to form a slurry hydrocracking effluent.

In another embodiment, the process involves obtaining the spent hydroprocessing catalyst from a hydroprocessing zone, wherein the spent hydroprocessing catalyst has at least one of: a metals content of at least about 10 wt %; a crushing strength of less than about 4 lbs; a relative weight activity of less than about 80% of a relative weight activity of an initial hydroprocessing catalyst; or a surface area of less than about 80% of a surface area of the initial hydroprocessing catalyst; and introducing a heavy hydrocarbon feed and a hydrogen stream into a slurry hydrocracking zone in the presence of the spent hydroprocessing catalyst under slurry hydrocracking conditions to form a slurry hydrocracking effluent.

BRIEF DESCRIPTION OF THE DRAWING

The FIGURE illustrates one embodiment of a SHC process.

DETAILED DESCRIPTION OF THE INVENTION

The present invention provides a slurry hydrocracking (SHC) process employing an effective but less expensive molybdenum catalyst. The catalyst is a spent hydroprocessing catalyst which is ground to a particle size of less than 500 μm.

As used herein, the term “boiling point temperature” means atmospheric equivalent boiling point (AEBP) as calculated from the observed boiling temperature and the distillation pressure, as calculated using the equations furnished in ASTM D1160 appendix A7 entitled “Practice for Converting Observed Vapor Temperatures to Atmospheric Equivalent Temperatures”.

As used herein, “pitch” means the hydrocarbon material boiling above about 524° C. (975° F.) AEBP as determined by any standard gas chromatographic simulated distillation method such as ASTM D2887, D6352 or D7169, all of which are used by the petroleum industry.

As used herein, “heavy vacuum gas oil” (HVGO) means the hydrocarbon material boiling in the range between about 427° C. (800° F.) and about 524° C. (975° F.).

As used herein, “light vacuum gas oil” (LVGO) means the hydrocarbon material boiling in the range between about 343° C. (650° F.) and about 427° C. (800° F.).

As used herein, solvent “insolubles” means materials not dissolving in the solvent named.

As used herein, “TIOR” is the toluene-insoluble organic residue which represents non-catalytic solids in the product part boiling over 524° C.

As used herein, “mesophase” is a component of TIOR that signifies the existence of coke, another component of TIOR. Mesophase is a semi-crystalline carbonaceous material defined as round, anisotropic particles present in pitch. The presence of mesophase can serve as a warning that operating conditions are too severe in an SHC and that coke formation is likely to occur under prevailing conditions.

As used herein, “mean particle or crystallite diameter” is understood to mean the same as the average particle or crystallite diameter and is calculated for all of the particles or crystallites fed to the reactor which may be determined by a representative sampling, respectively.

As used herein, “about” is understood to mean within 10% of the value, or within 5%, or within 1%.

Hydroprocessing is a process that uses a hydrogen-containing gas with suitable catalyst(s) for a particular application. In many instances, hydroprocessing is generally accomplished by contacting the selected feedstock in a reaction vessel or zone with the suitable catalyst under conditions of elevated temperature and pressure in the presence of hydrogen. It includes hydrotreating and hydrocracking Hydrotreating is a process in which hydrogen gas is contacted with a hydrocarbon stream in the presence of suitable catalysts which are primarily active for the removal of heteroatoms, such as sulfur, nitrogen, and metals from the hydrocarbon feedstock. In hydrotreating, hydrocarbons with double and triple bonds may be saturated.

Hydrotreating catalyst deactivates with use in the hydrotreating process and may be replaced after a single cycle or it may be regenerated and reused in the hydrotreating process multiple times, until sufficient activity can no longer be recovered by the regeneration procedure. Surprisingly, the deactivated hydrotreating catalyst is still sufficiently active to be a viable catalyst in the slurry hydrocracking process.

One common type of hydrotreating catalysts includes at least one Group VIII metal (preferably iron, cobalt or nickel, more preferably cobalt and/or nickel) and at least one Group VI metal (preferably molybdenum or tungsten) on a high surface area support material, preferably alumina. The Group VIII metal is typically present in an amount ranging from about 1 to about 20 weight percent, or about 2 to about 12 weight percent, or about 2 to about 5 weight percent. The Group VI metal will typically be present in an amount ranging from about 1 to about 25 weight percent, or about 2 to about 25 weight percent, or 5 to about 20 weight percent. The support materials are typically metal oxides, including, but not limited to, alumina, silica, titania, zirconia, or mixtures thereof.

Hydrocracking is a type of hydroprocessing that is generally accomplished by contacting in a hydrocracking reaction vessel or zones a gas oil or other feedstock to be treated with a suitable hydrocracking catalyst under conditions of elevated temperature and pressure in the presence of hydrogen so as to yield a product containing a distribution of lower-boiling point hydrocarbon products desired by the refiner. The operating conditions and the hydrocracking catalysts within a hydrocracking reactor influence the yield of the hydrocracked products.

In some embodiments, the hydrocracking catalysts utilize amorphous bases or low-level zeolite bases combined with one or more Group VIII or Group VI metal hydrogenating components. In other embodiments, the hydrocracking catalyst comprises, in general, any crystalline zeolite cracking base upon which is deposited a minor proportion of a Group VIII metal hydrogenating component. Additional hydrogenating components may be selected from Group VI for incorporation with the zeolite base. The zeolite cracking bases are sometimes referred to in the art as molecular sieves and are usually composed of silica, alumina and one or more exchangeable cations such as sodium, magnesium, calcium, rare earth metals, etc. They are further characterized by crystal pores of relatively uniform diameter between about 4 and 14 Angstroms (10⁻¹⁰ meters). It is preferred to employ zeolites having a relatively high silica/alumina mole ratio between about 3 and 12. Suitable zeolites found in nature include, for example, mordenite, stilbite, heulandite, ferrierite, dachiardite, chabazite, erionite and faujasite. Suitable synthetic zeolites include, for example, the B, X, Y and L crystal types, e.g., synthetic faujasite and mordenite. The preferred zeolites are those having crystal pore diameters between about 8-12 Angstroms (10⁻¹⁰ meters), wherein the silica/alumina mole ratio is about 4 to 6. Examples of preferred zeolites include synthetic Y molecular sieve and beta zeolite. The active metals employed in the preferred hydrocracking catalysts of the present invention as hydrogenation components are those of Group VIII, i.e., iron, cobalt, nickel, ruthenium, rhodium, palladium, osmium, iridium and platinum. In addition to these metals, other promoters may also be employed in conjunction therewith, including the metals of Group VI, e.g., molybdenum and tungsten. The amount of hydrogenating metal in the catalyst can vary within wide ranges. Broadly speaking, any amount between about 0.05 percent and 30 percent by weight may be used. In the case of the noble metals, it is normally preferred to use about 0.05 to about 2 wt-%. The preferred method for incorporating the hydrogenating metal is to contact the zeolite base material with an aqueous solution of a suitable compound of the desired metal wherein the metal is present in a cationic form. Following addition of the selected hydrogenating metal or metals, the resulting catalyst powder is then filtered, dried, pelleted with added lubricants, binders or the like if desired, and calcined in air at temperatures of, e.g., 371° C. to 649° C. (700° F. to 1200° F.) in order to activate the catalyst and decompose ammonium ions. Alternatively, the zeolite component may first be pelleted, followed by the addition of the hydrogenating component and activation by calcining The catalysts may be employed in a hydroprocessing reactor in undiluted form, or the powdered zeolite catalyst may be mixed and copelleted with other relatively less active catalysts, diluents or binders such as alumina, silica gel, silica-alumina cogels, activated clays and the like in proportions ranging between 5 and 90 wt-%. These diluents may be employed as such or they may contain a minor proportion of an added hydrogenating metal such as a Group VI and/or Group VIII metal.

There are various ways to evaluate a hydroprocessing catalyst for deactivation. One method involves determining the total metals content of the catalyst. When the total metal content is at least about 10%, the hydroprocessing catalyst may need to be replaced. The metals include nickel, vanadium, iron, silicon, sodium, potassium, calcium, magnesium, arsenic, and lead.

Another method of evaluating whether a hydroprocessing catalyst is spent is to determine the crush strength of the hydroprocessing catalyst. When the crush strength after regeneration is less than about 20 N, the hydroprocessing catalyst may need to be replaced. Crush strength can be measured using ASTM D4179, for example.

Still another method involves determining the relative weight activity or relative volume activity of the spent catalyst after regeneration compared to the initial hydroprocessing catalyst. The activity can be for desulfurization, denitrification, or demetallation. When the weight activity or the volume activity is less than about 80% of the initial weight or volume activity, the hydroprocessing catalyst may need to be replaced. Relative weight and relative volume activity are known tests, which are described in EP 2486109, for example.

Another indicator that the hydroprocessing catalyst may need to be replaced is the surface area of the spent catalyst. When the surface area of the spent catalyst after regeneration is less than about 80% of the surface area of the initial catalyst, the hydroprocessing catalyst may need to be replaced. The surface area is typically determined by nitrogen adsorption—for example, by the method of Brunauer, Emmett, and Teller (J. Am. Chem. Soc. v.60, p.309).

Currently, most of the spent hydroprocessing catalyst is not sent for metals recovery because the value of the metals does not justify the cost of recovery (except for noble metals). In many cases, the spent hydroprocessing catalyst is sent to landfills, with refiners paying for the disposal. By utilizing the spent hydroprocessing catalyst in the SHC process, the disposal cost can be reduced, and there is a ready source of material to be used in the SHC process. As a result, the cost of the molybdenum catalyst is reduced significantly.

The spent hydroprocessing catalyst may have a particle diameter of about 1-3 mm for spheres or lobed cross-section materials and up to about 10 mm of length for extrudates. It was determined that this is typically too abrasive to be used in some SHC equipment. Therefore, the spent hydroprocessing catalyst is reduced in size to an average particle size of less than about 500 μm, or less than about 400 μm, or less than about 300 μm, or less than about 200 μm, or less than about 100 μm, or less than about 75 μm, or less than about 50 μm, or less than about 40 μm, or less than about 30 μm, or less than about 20 μm, or less than about 15 μm, or less than about 10 μm, or less than about 5 μm, or less than about 1 μm. Although particles of less than about 1 can be used, it may be difficult to remove them from the slurry hydrocracking effluent using some processes such as a decanter. However, other recovery processes such as centrifuges could be used to recover particles smaller than 1

The particle size can be reduced using any suitable process including, but not limited to, grinding, ball milling, or jet milling. Wet ball milling is particularly advantageous because it combines the steps of grinding and slurrying the catalyst with the feedstock into a single process step. The processes used to reduce the size of the spent hydroprocessing catalyst may improve activity by exposing pores that are blocked by metals and coke deposits in the spent catalyst.

The spent hydroprocessing catalyst is recovered from a hydroprocessing zone, and reduced in size. The reduced size spent hydroprocessing catalyst is then used as the catalyst in the SHC zone.

In the exemplary SHC process as shown in the Figure, one, two or all of a heavy hydrocarbon oil feed in line 8, a recycle pitch stream containing catalyst particles in line 39, and recycled HVGO in line 37 may be combined in line 10. The combined feed in line 10 is heated in the heater 32 and pumped through an inlet line 12 into an inlet in the bottom of the tubular SHC reactor 13.

The reduced size spent hydroprocessing catalyst can be added to one or more of the heavy hydrocarbon oil feed in line 8, the recycle pitch stream in line 39, and the recycled HVGO in line 37. The catalyst is present in an amount sufficient to achieve a concentration of molybdenum or tungsten in the combined stream of about 30 wppm to about 500 wppm, or about 30 wppm to about 400 wppm, or about 30 wppm to about 300 wppm, or about 30 wppm to about 250 wppm, or about 30 wppm to about 200 wppm, or about 30 wppm to about 150 wppm, or about 30 wppm to about 100 wppm. For example, if the spent catalyst contains 5 wt % molybdenum and the desired level is 500 wppm, about 1 wt % ground catalyst would be needed. If the spent catalyst contains 16% molybdenum and the desired level is 30 wppm, then about 200 wppm ground catalyst would be needed.

The heavy hydrocarbon oil feed to the process often comprises a vacuum column residual stream from a distillation column bottoms stream, such as with an initial boiling point from about 524+° C. (975+° F.), an atmospheric column residual stream, a visbreaker pitch stream, a fluid catalytic cracking main column bottoms stream (also called clarified slurry oil), and solvent deasphalted oil pitch. Other representative components, as fresh hydrocarbon feeds, that may be included in the heavy hydrocarbon feedstock include gas oils, such as straight-run gas oils (e.g., vacuum gas oil), recovered by fractional distillation of crude petroleum. Other gas oils produced in refineries include coker gas oil and visbreaker gas oil. In the case of a straight-run vacuum gas oil, the distillation end point is governed by the crude oil vacuum fractionation column and particularly the fractionation temperature cutoff between the vacuum gas oil and vacuum column bottoms split. Thus, refinery gas oil components suitable as fresh hydrocarbon feed components of the heavy hydrocarbon feedstock to the SHC reactor, such as straight-run fractions, often result from crude oil fractionation or distillation operations, while other gas oil components are obtained following one or more hydrocarbon conversion reactions. Whether or not these gas oils are present, the combined heavy hydrocarbon feedstock to the SHC reaction zone can be a mixture of hydrocarbons (i) boiling predominantly in a representative crude oil vacuum column residue range, for example above about 538° C. (1000° F.), and (ii) hydrocarbons boiling in a representative gas oil range, for example from about 343° C. (650° F.) to an end point of about 593° C. (1100° F.), with other representative distillation end points being about 566° C. (1050° F.), about 538° C. (1000° F.), and about 482° C. (900° F.). In this case, components (i) and (ii) of the heavy hydrocarbon feedstock are therefore representative of a crude oil vacuum column residue and asphalt from a solvent deasphalting unit (also called pitch), respectively.

Additional components of the heavy hydrocarbon feed can include residual oils such as a crude oil vacuum distillation column residuum boiling above 566° C. (1050° F.), tars, bitumen, coal oils, and shale oils. Other asphaltene-containing materials such as whole or topped petroleum crude oils including heavy crude oils may also be used as components processed by SHC. In addition to asphaltenes, these further possible components of the heavy hydrocarbon feedstock, as well as others, generally also contain significant metallic contaminants (e.g., nickel, iron and vanadium), a high content of organic sulfur and nitrogen compounds, and a high Conradson carbon residue. The metals content of such components, for example, may be 100 ppm to 1,000 ppm by weight, the total sulfur content may range from 1% to 7% by weight, and the API gravity may range from about −5° to about 35°. The Conradson carbon residue of such components is generally at least about 5%, and is often from about 10% to about 35% by weight.

The reduced size spent hydroprocessing catalyst may be added directly to the combined heavy hydrocarbon oil feed to the SHC reactor 13 from line 10 or may be mixed with another heavy hydrocarbon oil feed in lines 8, 37, or 39 before they are combined in line 10 and enter the reactor 13 as a slurry. Many mixing and pumping arrangements may be suitable. It is also contemplated that feed streams may be added separately to the SHC reactor 13.

Recycled hydrogen and make up hydrogen from line 30 are fed into the SHC reactor 13 through line 14 after undergoing heating in heater 31. Hydrocarbon feed from line 10 may be combined with the recycled hydrogen and make up hydrogen in line 14. The hydrogen in line 14 that is not premixed with feed may be added at one or more locations above the feed entry in line 12. Both feed from line 12 and hydrogen in line 14 may be distributed in the SHC reactor 13 with an appropriate distributor. Additionally, hydrogen may be added to the feed in line 10 before it is heated in heater 32 to prevent deposits in the heater 32 and delivered to the SHC reactor in line 12. Hydrogen can be added in lines 6 and 6′ to cool the reactor and control the reactor temperature profile.

Preferably the recycled pitch stream in line 39 makes up in the range of about 5 to about 15 wt-% of the feedstock to the SHC reactor 13, while the HVGO in line 37 makes up in the range of 5 to 50 wt-% of the feedstock, depending upon the quality of the feedstock and the once-through conversion level.

The feed entering the SHC reactor 13 comprises three phases, solid catalyst particles, vaporous, liquid and solid hydrocarbon feed and gaseous hydrogen.

The SHC process can be operated at quite moderate pressure, in the range of 3.5 to 27.6 MPa (500 to 4000 psig) and preferably in the range of 10.3 to 17.2 MPa (1500 to 2800 psig), without coke formation in the SHC reactor 13. The reactor temperature is typically in the range of about 400° C. to about 500° C. with a temperature of about 410° C. to about 475° C. being suitable and a range of 425° C. to 460° C. being preferred. The LHSV is typically below about 4 h⁻¹ on a fresh feed basis, with a range of about 0.1 to 3 h⁻¹ being preferred and a range of about 0.1 to 1 h⁻¹ being particularly preferred.

Although SHC can be carried out in a variety of known reactors of either up or downflow, it is particularly well suited to a tubular reactor through which feed, catalyst and gas move upwardly. Hence, the outlet from SHC reactor 13 is above the inlet. Although only one is shown in the Figure, one or more SHC reactors 13 may be utilized in parallel or in series.

Because the liquid feed is converted to vaporous product, foaming tends to occur in the SHC reactor 13. An antifoaming agent may also be added to the SHC reactor 13, preferably to the top thereof, to reduce the tendency to generate foam. Suitable antifoaming agents include silicones as disclosed in U.S. Pat. No. 4,969,988.

A gas-liquid mixture is withdrawn from the top of the SHC reactor 13 through line 15 and separated. The separation preferably takes place in a hot, high-pressure separator 20 kept at a separation temperature between about 200° C. and 470° C. (392° F. and 878° F.) and preferably at about the pressure of the SHC reactor. In the hot separator 20, the effluent from the SHC reactor 13 is separated into a liquid stream 16 and a gaseous stream 18. The liquid stream 16 contains HVGO. The gaseous stream 18 comprises between about 35 and 80 vol-% of the hydrocarbon product from the SHC reactor 13 and is further processed to recover hydrocarbons and hydrogen for recycle.

A liquid portion of the product from the hot separator 20 may be used to form the recycle stream to the SHC reactor 13 after separation which may occur in a liquid vacuum fractionation column 24. Line 16 introduces the liquid fraction from the hot high pressure separator 20 to a liquid vacuum fractionation column 24, which is preferably a vacuum distillation column. The liquid vacuum fractionation column 24 is typically maintained at a pressure between about 1.7 and 10.0 kPa (0.25 and 1.5 psi) and at a vacuum distillation temperature resulting in an atmospheric equivalent cut point between LVGO and HVGO of between about 250° C. and 500° C. (482° F. and 932° F.). Three fractions may be separated in the liquid fractionation column 24: an overhead fraction of LVGO in an overhead line 38 which may be further processed, a HVGO stream from a side cut in line 29, and a pitch stream obtained in a bottoms line 40 which typically boils above 450° C. At least a portion of this pitch stream may be recycled back in line 39 to form part of the feed slurry to the SHC reactor 13. Remaining catalyst particles from SHC reactor 13 will be present in the pitch stream in lines 39 and 41.

A filtration device 42 such as a centrifuge, a sieve device or other suitable means may separate catalyst particles from pitch at temperature of about 250° C. to about 350° C. A sieve device is illustrated as the filtration device 42. In the filtration device 42, catalyst particles do not permeate a sieve 43, but are returned in line 44 to the recycle pitch line 39 to reenter the reactor with the recycled pitch. Filtered pitch with very little catalyst loading is removed from the filtration device 42 in line 45. Any remaining portion of the pitch stream is recovered in line 46.

During the SHC reaction, it is important to minimize coking Adding a low-polarity aromatic oil to the feedstock reduces coke production. The polar aromatic material may come from a wide variety of sources. A portion of the HVGO containing polar aromatic material in line 29 may be recycled by line 37 to form part of the feed slurry to the SHC reactor 13. The remaining portion of the HVGO may be recovered in line 35.

The gaseous stream in line 18 may be combined with the overhead fraction of LVGO from the overhead line 38 and may be delivered to a cool, high pressure separator 19. Within the cool separator 19, the product is separated into a gaseous stream rich in hydrogen which is drawn off through the overhead in line 22 and a liquid hydrocarbon product which is drawn off the bottom through line 28.

The hydrogen-rich stream 22 may be passed through a packed scrubbing tower 23 where it is scrubbed by means of a scrubbing liquid in line 25 to remove hydrogen sulfide and ammonia. The spent scrubbing liquid in line 27 may be regenerated and recycled and is usually an amine. The scrubbed hydrogen-rich stream emerges from the scrubber via line 34 and is combined with fresh make-up hydrogen added through line 33 and recycled through a recycle gas compressor 36 and line 30 back to reactor 13.

The bottoms line 28 may carry liquid SHC product to a product fractionator 26. The liquid SHC product may be stripped in a stripping column before entering the product fractionator 26 to remove hydrogen sulfide. The product fractionator 26 may comprise one or several vessels although it is shown only as one in the Figure. The product fractionator produces a C₄-stream recovered in overhead line 52, a naphtha product stream in line 54, a diesel stream in line 56 and a light vacuum gas oil (LVGO) stream in bottoms line 58.

While at least one exemplary embodiment has been presented in the foregoing detailed description of the invention, it should be appreciated that a vast number of variations exist. It should also be appreciated that the exemplary embodiment or exemplary embodiments are only examples, and are not intended to limit the scope, applicability, or configuration of the invention in any way. Rather, the foregoing detailed description will provide those skilled in the art with a convenient road map for implementing an exemplary embodiment of the invention. It being understood that various changes may be made in the function and arrangement of elements described in an exemplary embodiment without departing from the scope of the invention as set forth in the appended claims.

Claims

1. A slurry hydrocracking process using spent hydroprocessing catalyst comprising:

obtaining the spent hydroprocessing catalyst from a hydroprocessing zone;

reducing the size of the spent hydroprocessing catalyst; and

introducing a heavy hydrocarbon feed and a hydrogen stream into a slurry hydrocracking zone in the presence of the reduced size spent hydroprocessing catalyst under slurry hydrocracking conditions to form a slurry hydrocracking effluent.

2. The process of claim 1 wherein the spent hydroprocessing catalyst comprises at least one Group VIII metal and at least one Group VI metal on a support.

3. The process of claim 2 wherein the at least one Group VIII metal comprises iron, cobalt, and nickel, wherein the Group VI metal comprises molybdenum and tungsten, and wherein the support comprises a metal oxide.

4. The process of claim 1 wherein the spent hydroprocessing catalyst comprises at least one Group VIII or Group VI metals on an amorphous base or a zeolite base.

5. The process of claim 4 wherein the at least one Group VIII metal comprises iron, cobalt, and nickel, wherein the Group VI metal comprises molybdenum and tungsten, and wherein the zeolite base comprises alumina and silica.

6. The process of claim 1 wherein the reduced size spent hydroprocessing catalyst is present in an amount of about 200 wppm to about 1 wt %.

7. The process of claim 1 wherein reducing the size of the spent hydroprocessing catalyst comprises one or more of grinding the spent hydroprocessing catalyst, ball milling the spent hydroprocessing catalyst, and jet milling the spent hydroprocessing catalyst.

8. The process of claim 1 wherein the reduced size spent hydroprocessing catalyst has an average size of less than 500 μm.

9. The process of claim 1 wherein the reduced size spent hydroprocessing catalyst has an average size of less than 100 μm.

10. The process of claim 1 further comprising recovering the reduced size spent hydroprocessing catalyst from the slurry hydrocracking effluent.

11. The process of claim 10 further comprising recycling the recovered catalyst.

12. A slurry hydrocracking process using spent hydroprocessing catalyst comprising:

obtaining the spent hydroprocessing catalyst from a hydroprocessing zone, the spent hydroprocessing catalyst comprising at least one Group VIII metal and at least one Group VI metal on a support or at least one Group VIII or Group VI metals on an amorphous base or a zeolite base;

grinding the spent hydroprocessing catalyst to reduce the size of the spent hydroprocessing catalyst to less than 500 μm; and

introducing a heavy hydrocarbon feed and a hydrogen stream into a slurry hydrocracking zone in the presence of the ground spent hydroprocessing catalyst under slurry hydrocracking conditions to form a slurry hydrocracking effluent.

13. The process of claim 12 wherein the at least one Group VIII metal comprises iron, cobalt, and nickel and wherein the Group VI metal comprises molybdenum and tungsten, and wherein the support comprises a metal oxide.

14. The process of claim 13 wherein the metal oxide comprises alumina, silica, titania, zirconia, or mixtures thereof.

15. The process of claim 12 wherein the at least one Group VIII metal comprises iron, cobalt, and nickel, wherein the Group VI metal comprises molybdenum and tungsten, and wherein the zeolite base comprises alumina and silica.

16. The process of claim 12 wherein the reduced size spent hydroprocessing catalyst is present in an amount of about 30 wppm to about 100 wppm.

17. The process of claim 12 wherein the ground spent hydroprocessing catalyst has an average size of less than 500 μm.

18. The process of claim 12 wherein the ground spent hydroprocessing catalyst has an average size of less than 100 μm.

19. The process of claim 12 further comprising recovering the ground spent hydroprocessing catalyst from the slurry hydrocracking effluent.

20. A slurry hydrocracking process using spent hydroprocessing catalyst comprising:

obtaining the spent hydroprocessing catalyst from a hydroprocessing zone, wherein the spent hydroprocessing catalyst has at least one of: a metals content of at least about 10 wt %; a crushing strength after regeneration of less than about 20 N; a weight activity after regeneration of less than about 80% of a weight activity of an initial hydroprocessing catalyst or a volume activity after regeneration of less than about 80% of a volume activity of the initial hydroprocessing catalyst; or a surface area after regeneration of less than about 80% of a surface area of the initial hydroprocessing catalyst; and

introducing a heavy hydrocarbon feed and a hydrogen stream into a slurry hydrocracking zone in the presence of the spent hydroprocessing catalyst under slurry hydrocracking conditions to form a slurry hydrocracking effluent.