US 20020112990 A1
A process for hydroprocessing liquid petroleum and chemical streams in two or more hydroprocessing stages wherein the liquid and vapor products from the first stage are sent to a separation zone wherein a liquid phase fraction is separated from a vapor phse fraction which contains vaporized heary hydrocarbon components. The vapor phase fraction is passed to a sorption zone wherein at least a portion of the heavy hydrocarbon components is removed. Both the liquid phase fraction and the sorbed heavy hydrocarbon components are sent to at least one additional hydroprocessing stage.
1. A two stage process for hydroprocessing a hydrocarbonaceous feedstock which process comprises:
(a) reacting said feedstock in a first reaction stage in the presence of a hydrogen-containing treat gas, said reaction stage containing one or more reaction zones operated at hydroprocessing conditions wherein each reaction zone contains a bed of hydroprocessing catalyst;
(b) passing the resulting product stream to a separation zone wherein a vapor phase fraction and a liquid phase fraction are produced, which vapor phase fraction containing vaporized high boiling hydrcarbon components;
(c) conducting at least a portion of said vapor phase fraction to a sorption zone wherein it is contacted with a sorption agent that is at a temperature less than that of said vapor phase fraction, thereby sorbing at least a portion of the vaporized high boiling hydrocarbon components from the vapor phase fraction;
(d) conducting said liquid phase fraction to a second reaction stage in the presence of a hydrogen-containing treat gas, said reaction stage containing one or more reaction zones operated at hydroprocessing conditions wherein each reaction zone contains a bed of hydroprocessing catalyst; and
e) collecting the hydroprocessed product stream for said second reaction stage.
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 This is a continuation-in-part of U.S. Ser. No. 09/457,437 filed Dec. 7, 1999, which was based on Provisional Application 60/111,176 filed on Dec. 7, 1998.
 1. Field of the Invention
 The present invention relates to a process for hydroprocessing liquid petroleum and chemical streams in two or more hydroprocessing stages wherein the liquid and vapor products from the first stage are sent to a separation zone wherein a liquid phase fraction is separated from a vapor phse fraction which contains vaporized heary hydrocarbon components. The vapor phase fraction is passed to a sorption zone wherein at least a portion of the heavy hydrocarbon components is removed. Both the liquid phase fraction and the sorbed heavy hydrocarbon components are sent to at least one additional hydroprocessing stage.
 2. Background of the Invention
 As supplies of lighter and cleaner feedstocks dwindle, the petroleum industry will need to rely more heavily on relatively high boiling feedstocks derived from such materials as coal, tar sands, oil-shale, and heavy crudes. Such feedstocks generally contain significantly more undesirable components, especially from an environmental point of view. Such undesirable components include halides, metals and heteroatoms such as sulfur, nitrogen, and oxygen. Furthermore, specifications for fuels, lubricants, and chemical products, with respect to such undesirable components, are continually becoming tighter. Consequently, such feedstocks and product streams require more severe upgrading in order to reduce the content of such undesirable components. More severe upgrading, of course, adds considerably to the expense of processing these petroleum streams.
 Hydroprocessing, which includes hydroconversion, hydrocracking, hydrotreating, and hydroisomerization, plays an important role in upgrading petroleum streams to meet the more stringent quality requirements. For example, there is an increasing demand for improved heteroatom removal, aromatic saturation, and boiling point reduction. Much work is presently being done in hydrotreating because of greater demands for the removal of heteroatoms, most notably sulfur, from transportation and heating fuel streams. Hydrotreating, or in the case of sulfur removal, hydrodesulfurization, is well known in the art and usually requires treating the petroleum streams with hydrogen in the presence of a supported catalyst at hydrotreating conditions. The catalyst is typically comprised of a Group VI metal with one or more Group VIII metals as promoters on a refractory support. Hydrotreating catalysts that are particularly suitable for hydrodesulfurization and hydrodenitrogenation generally contain molybdenum or tungsten on alumina promoted with a metal such as cobalt, nickel, iron or a combination thereof. Cobalt promoted molybdenum on alumina catalysts are most widely used for hydrodesulfurization, while nickel promoted molybdenum on alumina catalysts are the most widely used for hydrodenitrogenation and aromatic saturation.
 Much work is being done to develop more active catalysts and improved reaction vessel designs in order to meet the demand for more effective hydroprocessing processes. Various improved hardware configurations have been suggested. One such configuration is a countercurrent design wherein the feedstock flows downward through successive catalyst beds counter to upflowing treat gas, which is typically a hydrogen containing treat-gas. The downstream catalyst beds, relative to the flow of feed can contain high performance, but otherwise more sulfur sensitive catalysts because the upflowing treat gas carries away heteroatom components such as H2S and NH3 that are deleterious to the sulfur and nitrogen sensitive catalysts. While such countercurrent reactors have commercial potential, they never the less are susceptible to flooding. That is, where upflowing treat gas and gaseous products impede the downward flow of feed.
 Other process configurations include the use of multiple reaction stages, either in a single reaction vessel, or in separate reaction vessels. More sulfur sensitive catalysts can be used in downstream stages, as the level of heteroatom components becomes successively lower. European Patent Application 93200165.4 teaches a two-stage hydrotreating process performed in a single reaction vessel, but there is no suggestion of a unique stripping arrangement for the liquid reaction stream from each reaction stage.
 As discussed above, it is at times advantageous to conduct hydroprocessing in a two-stage operation where the combined liquid/vapor product from the first reactor is separated and the liquid combined with clean treat gas is passed to a second reaction stage. There is however a problem associated with the separated vapor phase product stream produced from the liquid/vapor separation step. This vapor phase, which will typically contain significant amounts of vaporized hydrocarbon including a high boiling tail. The entire hydrocarbon portion, but particularly the hig boiling, or heavy tail, may require additional hydroprocessing to meet product quality specifications; this additional hydroprocessing may be very difficult and expensive to accomplish. An example of particular commercial interest at this time is the two-stage hydrotreating of diesel fuel to meet legislated reductions in sulfur levels from the current specification of 500 wppm down to 50 wppm.
 While there is a substantial amount of art relating to hydroprocessing catalysts, as well as process designs, there still remains a need in the art for process designs that offer further improvement.
 In accordance with the present invention there is provided a two stage process for hydroprocessing a hydrocarbonaceous feedstock which process comprises:
 (a) reacting said feedstock in a first reaction stage in the presence of a hydrogen-containing treat gas, said reaction stage containing one or more reaction zones operated at hydroprocessing conditions wherein each reaction zone contains a bed of hydroprocessing catalyst;
 (b) passing the resulting product stream to a separation zone wherein a vapor phase fraction and a liquid phase fraction are produced, which vapor phase fraction contains vaporized high boiling hydrcarbon components;
 (c) conducting at least a portion of said vapor phase fraction to a sorption zone wherein it is contacted with a sorption agent that is at a temperature less than that of said vapor phase fraction, thereby sorbing at least a portion of the vaporized high boiling hydrocarbon components from the vapor phase fraction;
 (d) conducting said liquid phase fraction to a second reaction stage in the presence of a hydrogen-containing treat gas, said reaction stage containing one or more reaction zones operated at hydroprocessing conditions wherein each reaction zone contains a bed of hydroprocessing catalyst; and
 e) collecting the hydroprocessed product stream for said second reaction stage.
 In preferred embodiments of the present invention the vapor phase fraction can be treated by: (i) partial condensation of the vapor phase stream, (ii) usage of a contacting device with partial condensation and reflux to achieve multiple vapor liquid equilibrium stages, (iii) contacting the vapor phase stream with a heavy liquid stream, and (iv) a dephlegmator.
 In another preferred embodiment of the present invention the contacting with vapor phase fraction is contacted with the sorption agent in a trayed or packed device to result in multiple vapor liquid equilibrium stages.
 In yet another preferred embodiment of the present invention the sorption agent is a cooled heavy liquid liquid product from step (d).
 The FIGURE hereof shows multiple reaction vessels of the present invention showing separation of the liquid phase product from the vapor phase product and further processing of the liquid phase product stream.
 Feedstocks suitable for use in such systems include those ranging from the naphtha boiling range to heavy feedstocks, such as gas oils and resids. Typically, the boiling range will be from about 40° C. to about 1000° C. Non-limiting examples of such feeds which can be used in the practice of the present invention include vacuum resid, atmospheric resid, vacuum gas oil (VGO), atmospheric gas oil (AGO), heavy atmospheric gas oil (HAGO), steam cracked gas oil (SCGO), deasphalted oil (DAO), and light cat cycle oil (LCCO).
 Non-limiting examples of hydroprocessing processes which can be practiced by the present invention include the hydroconversion of heavy petroleum feedstocks to lower boiling products; the hydrocracking of distillate, and higher boiling range feedstocks; the hydrotreating of various petroleum feedstocks to remove heteroatoms, such as sulfur, nitrogen, and oxygen; the hydrogenation of aromatics; the hydroisomerization and/or catalytic dewaxing of waxes, particularly Fischer-Tropsch waxes; and the demetallation of heavy streams. Ring-opening, particularly of naphthenic rings, can also be considered a hydroprocessing process.
 The practice of the present invention is applicable to all liquid-vapor countercurrent refinery and chemical processes. Feedstocks suitable for use in the practice of the present invention include those ranging from the naphtha boiling range to heavy feedstocks, such as gas oils and resids. Typically, the boiling range will be from about 40° C. to about 1000° C. Non-limiting examples of such heavy feedstocks include vacuum resid, atmospheric resid, vacuum gas oil (VGO), atmospheric gas oil (AGO), heavy atmospheric gas oil (HAGO), steam cracked gas oil (SCGO), deasphalted oil (DAO), and light cat cycle oil (LCCO). The feedstock can also be a Fischer-Tropsch reactor product stream.
 The process of the present invention can be better understood by a description of a preferred embodiment illustrated by the FIGURE hereof. The current invention offers an improvement over the prior art by use of a step to remove the heavy tail from the vapor stream and route it to second stage hydroprocessing (or another disposition) where it can more efficiently be processed. The term “heavy tail' as used herein means that portion of the vapor phase fraction that is composed of heavy hydrocarbon components that typically boil in excess of about 315° C., preferably in excess of about 345° C. The vapor phase fraction, because of the presence of this heavy tail, typically contains too high a level of sulfur to be blended into the final product. The majority of the sulfur present in the vapor phase fraction can be found in the heavy tail. Not only does the high sulfur content of this heavy tail prevent the vapor phase fraction from being blended into the final product, but they would normally require the presence of a third hydroprocessing stage to remove them because of their high boiling points. Removal of this heavy tail will thus allow the vapor product to be further processed much more easily or may even allow it to be blended into the final product without further processing. For purposes of discussion, the reaction stages will be assumed to be hydrotreating stages, although they can just as well be any of the other aforementioned types of hydroprocessing stages. Miscellaneous reaction vessel internals, valves, pumps, thermocouples, and heat transfer devices etc. are not shown in either figures for simplicity. The FIGURE hereof shows reaction vessel R1 a that contains reaction zones10 a and 10 b, each of which is comprised of a bed of hydroprocessing catalyst. It is preferred that the catalyst be in the reactor as a fixed bed, although other types of catalyst arrangements can be used, such as slurry or ebullating beds. Upstream of each reaction zone is a non-reaction zone 12 a and 12 b. The non-reaction zone is typically void of catalyst, that is, it will be an empty section in the vessel with respect to catalyst. There may also be provided a liquid distribution means LD upstream of each reaction stage. The type of liquid distribution means is believed not to limit the practice of the present invention, but a tray arrangement is preferred, such as sieve trays, bubble cap trays, or trays with spray nozzles, chimneys, tubes, etc.
 The feedstream is fed to reaction vessel R1 via line 14 along with a hydrogen-containing treat gas via line 16. The feedstream and hydrogen-containing treat gas pass, cocurrently, through the one or more reaction zones of reaction vessel R1, which represents the first hydroprocessing stage. A combined liquid phase product stream and vapor phase product stream exit reaction vessel R1 via line 18 and into separation zone S wherein a liquid separated from a vapor phase fraction. The liquid phase fraction will typically be one that has components boiling in the range from about 150° C. to about 345° C. The vapor phase fraction will contain lighter components, but it will also contain a significant amount of higher boiling hydrocarbon components. These higher boiling components will boiling in the range of 315° C. or greater, even in the range of 345° C. or greater.
 The vapor phase fraction is passed to sorption zone ST via line 20 wherein it is contacted with a sorption agent STA that removes at least a portion, preferably substantially all, of the high boiling hydrocarbon component. Non-limiting examples of sorption agents suitable for use here include heavy boiling range streams, such as gas oils and resids. Such streams will typically boil in the range of about 530° C. to about 950° C. Non-limiting examples of such steams inlcude vaccum resid, atmospheric resid, vacuum gas oil (VGO), atmospheric gas oil (AGO), heavy atmospheric gas oil (HAGO), steam cracked gas oil (SCGO), deasphalted oil (DAO), and light cat cycle oil (LCCO). Preferred are the gas oils.
 It will be understood that the sorption device can be replaced by any other suitable means for removing the heavy tail from the vapor fraction. For example, in a preferred embodiment of the present invention the removal of the heavy tail comprises: (i) partial condensation of the vapor phase stream, (ii) usage of a contacting device with partial condensation and reflux to achieve multiple vapor liquid equilibrium stages, (iii) contacting the vapor phase stream with a heavy liquid stream, and (iv) a dephlegmator.
 The sorbed vapor phase fraction is collected overhead via line 22. The heavy hydrocarbon components from the stripper are passed via line 24 to second stage hydroprocessing unit R2. The liquid phase fraction from separation zone S is passed to reaction vessel R2 via line 26, along with fresh hydrogen-containing treat gas via line 28. Introducing clean treat gas (gas substantially free of H2S and NH3) allows the second reaction zone to operate more efficiently due to a reduction in the activity suppression effects exerted by H2S and NH3 and an increase in H2 partial pressure. This type of two-stage operation is particularly attractive for very deep removal of sulfur and nitrogen or when a more sensitive catalyst (i.e., hydrocracking, aromatic saturation, etc) is used in the second reactor. The liquid/vapor separation step can be a simple flash or may involve the addition of stripping steam or gas to improve the removal of H2S and NH3.
 In reactor R2, the combined liquid stream and treat gas are passed through one or more catalyst beds, or reaction zones, 26 a and 26 b and a product stream exits reaction vessel R2 via line 30. Reaction vessel also contains non-reaction zones 28 a and 28 b upstream of each reaction zone. LD is as defined for R1. The catalyst in this second reaction stage can be a high performance catalyst which otherwise can be more sensitive to heteroatom poisoning because of the lower level of heteroatoms in the treated feedstream, as well as low levels of heteroatom species H2S and NH3 in the treat gas.
 As previously mentioned, the reaction stages can contain any combination of catalysts depending on the feedstock and the intended final product. For example, it may be desirable to remove as much of the heteroatoms from the feedstock as possible. In such a case, both reaction stages will contain a hydrotreating catalyst. The catalyst in the downstream reaction stage can be more heteroatom sensitive because the liquid stream entering that stage will contain lower amounts of heteroatoms than the original feedstream and reaction inhibitors, such as H2S and NH3, have been reduced. When the present invention is used for hydrotreating to remove substantially all of the heteroatoms from the feedstream, it is preferred that the first reaction stage contain a Co—Mo on a refractory support catalyst and a downstream reaction stage contain a Ni—Mo on a refractory support catalyst.
 The term “hydrotreating” as used herein refers to processes wherein a hydrogen-containing treat gas is used in the presence of a suitable catalyst that is primarily active for the removal of heteroatoms, such as sulfur, and nitrogen, and for some hydrogenation of aromatics. Suitable hydrotreating catalysts for use in the present invention are any conventional hydrotreating catalysts and includes those which are comprised of at least one Group VIII metal, preferably Fe, Co and Ni, more preferably Co and/or Ni, and most preferably Co; and at least one Group VI metal, preferably Mo and W, more preferably Mo, on a high surface area support material, preferably alumina. Other suitable hydrotreating catalysts include zeolitic catalysts, as well as noble metal catalysts where the noble metal is selected from Pd and Pt. It is within the scope of the present invention that more than one type of hydrotreating catalyst be used in the same reaction vessel. The Group VIII metal is typically present in an amount ranging from about 2 to 20 wt. %, preferably from about 4 to 12%. The Group VI metal will typically be present in an amount ranging from about 5 to 50 wt. %, preferably from about 10 to 40 wt. %, and more preferably from about 20 to 30 wt. %. All metals weight percents are on support. By “on support” we mean that the percents are based on the weight of the support. For example, if the support were to weigh 100 g. then 20 wt. % Group VIII metal would mean that 20 g. of Group VIII metal was on the support. Typical hydrotreating temperatures range from about 100° C. to about 400° C. with pressures from about 50 psig to about 3,000 psig, preferably from about 50 psig to about 2,500 psig. If the feedstock contains relatively low levels of heteroatoms, then the hydrotreating step may be eliminated and the feedstock passed directly to an aromatic saturation, hydrocracking, and/or ring-opening reaction stage.
 In another embodiment of the present invention the vapor product stream from separation zone S is passed to a condensation zone and the resulting liquid condensate is combined with the liquid phase product stream exiting separation zone S and is passed to reaction vessel R2. The off-gas from the condensation zone is collected or passed for further processing.
 The reaction stages used in the practice of the present invention are operated at suitable temperatures and pressures for the desired reaction. For example, typical hydroprocessing temperatures will range from about 40° C. to about 450° C. at pressures from about 50 psig to about 3,000 psig, preferably 50 to 2,500 psig.
 For purposes of hydroprocessing, the term “hydrogen-containing treat gas” means a treat gas stream containing at least an effective amount of hydrogen for the intended reaction. The treat gas stream introduced to the reaction vessel will preferably contain at least about 50 vol. %, more preferably at least about 75 vol. % hydrogen. It is preferred that the hydrogen-containing treat gas be make-up hydrogen-rich gas, preferably substantially pure hydrogen.
 Depending on the nature of the feedstock and the desired level of upgrading, more than two reaction stages may be preferred. For example, when the desired product is a distillate fuel, it is preferred that it contain reduced levels of sulfur and nitrogen. Further, distillates containing paraffins, especially linear paraffins are often preferred over naphthenes, which are often preferred over aromatics. To achieve this, at least one downstream catalyst will be selected from the group consisting of hydrotreating catalysts, hydrocracking catalysts, aromatic saturation catalysts, and ring-opening catalysts. If it is economically feasible to produce a product stream with high levels of paraffins, then the downstream reaction stages will preferably include an aromatic saturation stage and a ring-opening stage.
 If one of the downstream reaction stages is a hydrocracking stage, the catalyst can be any suitable conventional hydrocracking catalyst run at typical hydrocracking conditions. Typical hydrocracking catalysts are described in U.S. Pat. No. 4,921,595 to UOP, which is incorporated herein by reference. Such catalysts are typically comprised of a Group VIII metal hydrogenating component on a zeolite cracking base. The zeolite cracking bases are sometimes referred to in the art as molecular sieves, and are generally composed of silica, alumina, and one or more exchangeable cations such as sodium, magnesium, calcium, rare earth metals, etc. Crystal pores of relatively uniform diameter between about 4 and 12 Angstroms further characterize them. It is preferred to use zeolites having a relatively high silica/alumina mole ratio greater than about 3, preferably greater than about 6. Suitable zeolites found in nature include mordenite, clinoptiliolite, ferrierite, dachiardite, chabazite, erionite, and faujasite. Suitable synthetic zeolites include the Beta, X, Y, and L crystal types, e.g., synthetic faujasite, mordenite, ZSM-5, MCM-22 and the larger pore varieties of the ZSM and MCM series. A particularly preferred zeolite is any member of the faujasite family, see Tracy et al., Proc. of the Royal Soc., 1996, Vol. 452, p. 813. It is to be understood that these zeolites may include demetallated zeolites that are understood to include significant pore volume in the mesopore range, i.e., 20 to 500 Angstroms. Non-limiting examples of Group VIII metals that may be used on the hydrocracking catalysts include iron cobalt, nickel, ruthenium, rhodium, palladium, osmium, iridium, and platinum. Preferred are platinum and palladium, with platinum being more preferred. The amount of Group VIII metal will range from about 0.05 wt. % to 30 wt. %, based on the total weight of the catalyst. If the metal is a Group VIII noble metal, it is preferred to use about 0.05 to about 2 wt. %. Hydrocracking conditions include temperatures from about 200° to 425° C., preferably from about 220° to 330° C., more preferably from about 245° to 315° C.; pressure of about 200 psig to about 3,000 psig; and liquid hourly space velocity from about 0.5 to 10 V/V/Hr, preferably from about 1 to 5 V/V/Hr.
 Non-limiting examples of aromatic hydrogenation catalysts include nickel, cobalt-molybdenum, nickel-molybdenum, and nickel-tungsten. Noble metal containing catalysts can also be used. Non-limiting examples of noble metal catalysts include those based on platinum and/or palladium, which is preferably supported on a suitable support material, typically a refractory oxide material such as alumina, silica, alumina-silica, kieselguhr, diatomaceous earth, magnesia, and zirconia. Zeolitic supports can also be used. Such catalysts are typically susceptible to sulfur and nitrogen poisoning. The aromatic saturation stage is preferably operated at a temperature from about 40° C. to about 400° C., more preferably from about 260° C. to about 350° C., at a pressure from about 100 psig to about 3,000 psig, preferably from about 200 psig to about 1,200 psig, and at a liquid hourly space velocity (LHSV) of from about 0.3 V/V/Hr. to about 2 V/V/Hr.
 The liquid phase in the reaction vessels used in the present invention will typically be the higher boiling point components of the feed. The vapor phase will typically be a mixture of hydrogen-containing treat gas, heteroatom impurities like H2S and NH3, and vaporized lower-boiling components in the fresh feed, as well as light products of hydroprocessing reactions. If the vapor phase effluent still requires further hydroprocessing, it can be passed to a vapor phase reaction stage containing additional hydroprocessing catalyst and subjected to suitable hydroprocessing conditions for further reaction. It is also within the scope of the present invention that a feedstock that already contains adequately low levels of heteroatoms be fed directly into the reaction stage for aromatic saturation and/or cracking.
 The present invention can be better understood by reference to the following example that is present for illustrative purposes only and is not to be taken as limiting the invention in any way.
 A diesel oil feed (previously hydrotreated) containing 180 wppm of sulfur was processed in a counter current reactor pilot unit. Operating conditions were 185 psig total pressure, 350° C., 2 lhsv (liquid hourly space velocity), and treat gas rate of 1114 scf/b (standard cubic feet per barrel) H2. The catalyst used was a commercially available CoMo on alumina containing about 3.8 wt. % Co and about 13.2 wt. % Mo. The liquid product leaving the bottom of the reactor was approximately 70 wt. % of the feed and had a sulfur content of 44 wppm. The vapor leaving the top of the reactor with the treat gas, approximately 30 wt. % of the feed, was condensed and found to contain 93 wppm sulfur. Blending the two products would result in a total product having a sulfur content of 59 wppm, which exceeds the anticipated environmental specifications.
 The condensed vapor was then fractionated by distillation and the various cuts were analyzed for sulfur content:
 Through this analysis it was discovered that almost half of the sulfur was contained in less than 5% of the heaviest material (650° F.+(344° C.+) boiling range material) and that the vast majority was in the 600° F.+(315° C.+) material. If the heavy tail is removed from the condensed vapor stream then the resultant stream can be blended with the bottoms liquid to give an overall product that is of high quality. This also shows that the sulfur species can be concentrated for further treatment.