Title of Invention

AN INTEGRATED HYDROCONVERSION PROCESS

Abstract

A VGO stream is initially hydrocracked in a hydrocracking reaction zone within an integrated hydroconversion process. Effluent from the hydrocracking reaction zone is combined with a light aromatic-containing feed stream and the blended stream hydro treated in a hydrotreating reaction zone. Heat exchange occurs between the hydrocracking reaction zone and the hydrotreating reaction zone, permitting the temperature control of the initial hydrocracking zone. The integrated reaction system provides a single hydrogen supply and recirculation system for use in two reaction processes.

Full Text

1 HYDROCRACKING PROCESS TO MAXIMIZE DIESEL 2 WITH IMPROVED AROMATIC SATURATION 3 4 BACKGROUND OF THE INVENTION 5 6 Much of refinery processing involves reaction of refinery streams in a 7 hydrogen atmosphere, (n order to maximize conversion efficiencies and to 8 maintain catalyst life, excess hydrogen is generally used in the catalytic 9 conversion processes, with the unreacted hydrogen being recovered, purified 10 and repressurized for use as a recycle stream. Such recycle processes are 11 costly, both in energy and in equipment. Some progress has been made in 12 developing methods for using a single hydrogen loop in a reaction process 13 having at least two stages. 14 15 In conventional hydroprocessing, it is necessary to transfer hydrogen from a 16 vapor phase into the liquid phase where it will be available to react with a 17 petroleum molecule at the surface of the catalyst. This is accomplished by 18 circulating very large volumes of hydrogen gas and the oil through a catalyst 19 bed. The oil and the hydrogen flow through the bed and the hydrogen is 20 absorbed into a thin film of oil that is distributed over the catalyst. Because 21 the amount of hydrogen required can be large, 1000 to 5000 SCF/bbI of liquid, 22 and the amount of catalyst required can also be large, the reactors are very 23 large and can operate at severe conditions, from a few hundred psi to as 24 much as 5000 psi and temperatures from around 400°F to 900°F. 25 26 U.S. Pat. No. 6,224,747 teaches hydrocracking a VGO stream in a 27 hydrocracking reaction zone within an integrated hydroconversion process. 28 Effluent from the hydrocracking reaction zone is combined with a light 29 aromatic-containing feed stream, and the blended stream hydrotreated in a 30 hydrotreating reaction zone. The hydrocracked effluent serves as a heat sink 31 for the hydrotreating reaction zone. The integrated reaction system provides 32 a single hydrogen supply and recirculation system for use in two reaction 33 systems. There is no temperature control between the hydrocracking reaction 34 zone and the hydrotreating reaction zone, however. 3 4 U.S. Pat. No. 3,592,757 (Baral) illustrates temperature control between zones 5 by means of heat exchangers , as in the instant invention. Baral does not 6 employ a single hydrogen loop, as does the instant invention. Baral discloses 7 a hydrofiner {similar to a hydrotreater) operating in series with a hydrocracker, 8 with a fraction of the product fed to a hydrogenator. A gas oil feed is fed with 9 both make-up and recycle hydrogen to a hydrofiner. A recycle stream and 10 additional recycle hydrogen are added to the hydrofiner product stream, and 11 the mixture is fed to a hydrocracker. The hydrocracker product stream is 12 cooled and separated into a vapor and a liquid stream. The vapor stream is 13 passed to a recycle hydrogen compressor recycle to the hydrofiner. The 14 liquid stream is fractionated into a top, middle", and bottom stream. The 15 bottom stream is recycled to the hydrocracker. The middle stream is mixed 16 with hydrogen from a make-up hydrogen compressor and directed to a 17 hydrogenator. Hydrogen recovered from the hydrogenator is compressed in a 18 stage of the make-up hydrogen compressor and directed to the hydrofiner. 19 20 U.S. Pat. No. 5,114,562 (Haun et al.) teaches a two-stage 21 hydrodesulfurization (similar to hydrotreating) and hydrogenation process for 22 distillate hydrocarbons. There is heat exchange between the two stages, but 23 a single hydrogen loop is not employed. Two separate reaction zones are 24 employed in series, the first zone for hydrodesulfurization and a second zone 25 for hydrogenation. A feed is mixed with recycled hydrogen and fed to a 26 desulfurization reactor. Hydrogen sulfide is stripped from the desulfurization 27 reactor product by a countercurrent flow of hydrogen. The liquid product 28 stream from this stripping operation is mixed with relatively clean recycled 29 hydrogen and the mixture is fed to a hydrogenation reaction zone. Hydrogen 30 is recovered from the hydrogenation reactor and recycled as a split stream to 31 both the desulfurization reactor and the hydrogenation reactor. The hydrogen 32 from the stripping operation is passed through a separator, mixed with the 33 portion of the recycled hydrogen directed to the hydrogenation reactor, 34 compressed, passed through a treating step and recycled to the 35 hydrogenation reactor. Thus, the hydrocarbon feed stream passes in series 36 through the desulfufization and hydrogenation reactors, while relatively low 37 pressure hydrogen is provided for the desulfuhzation step and relatively high 38 pressure hydrogen is provided for the hydrogenation step. 6 7 The instant invention is directed to temperature control between 8 hydrocracking and hydrotreating zones, employing a single hydrogen loop. 9 10 SUMMARY OF THE INVENTION 11 12 A VGO stream is initially hydrocracked in a first-stage hydrocracking reaction 13 zone within an integrated hydroconversion process. The integrated 14 hydroconversion process possesses at least one hydrocracking stage and at 15 least one hydrotreating stage. Effluent from the first-stage hydrocracking 16 reaction zone is combined with a light aromatic-containing feed stream, and 17 the blended stream is hydrotreated in a second stage, which comprises a 18 hydrotreating reaction zone. Heat exchange occurs between the first-stage 19 hydrocracking reaction zone and the second-stage hydrotreating reaction 20 zone, permitting the temperature control of the first-stage hydrotreating zone. 21 The temperature of the first-stage hydrotreater is lower than that of the 22 first-stage hydrocracker. This improves the aromatic saturation of the 23 converted hydrocarbons and also allows the catalyst of the first-stage 24 hydrotreating zone to be different from the catalyst in subsequent 25 hydrocracking zones that may be present. In one embodiment, the effluent 26 from the first-stage hydrotreater is heated in an exchanger, then passed to a 27 hot high pressure separator, where overhead light ends are removed and 28 passed to a cold high pressure separator. In the cold high pressure 29 separator, hydrogen and hydrogen sulfide gas is removed overhead and 30 materials boiling in the gasoline and diesel range are passed to a fractionator. 31 Hydrogen sulfide is subsequently removed in an absorber and hydrogen is 32 compressed and recirculated to be used as interbed quench, as well as mixed 33 with vacuum gas oil feed. 34 The liquid effluent of the hot high pressure separate, which may contain 35 materials boiling in the diesel range, is also passed to the fracticnator. The 36 fracticnator bottoms may be subsequently hydrocracked and products rr.ay be 37 subsequently hydrotreated in units not depicted. 5 6 This invention offers several notable benefits. The invention provides a 7 method forhydroprocessing two refinery streams using a single hydrogen 8 supply and a single hydrogen recovery system. Furthermore, the instant 9 invention provides a method for hydrocracking a refinery stream and 10 hydrotreating a second refinery stream with a common hydrogen feed supply. 11 The feed to the hydrocracking reaction zone is not poisoned with 12 contaminants present in the feed to the hydrotreating reaction zone. The 13 present invention is further directed to hydroj-ocessing two or more dissimilar 14 refinery streams in an integrated hydroconversion process while maintaining 15 good catalyst life and high yields of the desired products, particularly distillate 16 range refinery products. Such dissimilar refinery streams may originate from 17 different refinery processes, such as a VGO, derived from the effluent of a 18 VGO hydrotreater, which contains relatively few catalyst contaminants and/or 19 aromatics, and an FCC cycle oil or straight run diesel, which contains 20 substantial amounts of aromatic compounds. 21 22 BRIEF DESCRIPTION OF THE DRAWINGS 23 24 Figure 1 illustrates a hydrocracker and hydrotreater in series, in a single 25 hydrogen loop separated by a heat exchanger. Light and heavy materials are 26 separated from each other. Hydrogen and hydrogen sulfide might be 27 removed from the light products. Hydrogen is compressed and recirculated. 28 Products are sent to a fractionator. 29 30 Figure 2 illustrates a hydrocracking step followed by separation and 31 fractionation. Material removed overhead is combined with a light aromatic 32 stream and hydrotreated. Hydrogen is separated from the hydrotreated 33 effluent and recirculated. Products are sent to a fractionator. 1 DETAILED DESCRIPTION OF THE INVENTION 2 3 This invention relates to two reaction processes, using two dissimilar feeds, 4 which are combined into a single integrated reaction process, using a single 5 hydrogen supply and recovery system. In the process, a heavier feed is 6 hydrocracked to make a middle distillate and/or gasoline product, and a lighter 7 feed is hydrotreated to upgrade the fuel properties of the lighter feed. The 8 process is particularly useful for treating a second refinery stream which boiis 9 in a temperature range generally below that of the first refinery stream, or a 10 feedstream which is to be treated to remove aromatics before being 11 processed further. 12 13 In one embodiment of the process, a first refinery stream such as a VGO is 14 hydrocracked in the presence of hydrogen over a hydrocracking catalyst 15 contained in a first-stage hydrocracking zone at conditions sufficient to 16 remove at least a portion of the nitrogen compounds from the first refinery 17 stream and to effect a boiling range conversion. The entire effluent from the 18 first reaction zone is then heat exchanged with an incoming stream, then 19 combined with a second refinery stream. The combined feedstock, along with 20 optional additional hydrogen-rich gas, is passed to a second-stage reaction 21 zone, which is maintained at hydrotreating conditions sufficient to remove at 22 least a portion of the aromatic compounds from the second refinery stream. 23 The feedstocks may flow through one or both of the reaction zones in gravity 24 flow in a downwardly direction or upwardly against gravity. The process is in 25 contrast to a conventional practice of combining the second refinery stream 26 with the first refinery stream and hydrocracking the combination together. 27 Alternative conventional practice would treat the two feedstocks in separate 28 processes, with separate hydrogen supply, recovery and recycle systems. 29 30. The effluent from the first hydrotreating zone is heat exchanged with incoming 31 VGO feed, then hydrogen is removed in a separator. The effluent then 32 passes to a fractionator, with bottoms passing to another hydrocracking zone 33 (not depicted) and diesel passing to another hydrotreating zone(not depicted). 34 In an alternate embodiment, separation may occur following the first 35 hydrocracking stage. Liquid effluent may pass to fractionation, and lighter 36 materials are combined with a light aromatic feed and subsequently 37 hydrotreated. Hydrogen is separated from the hydrotreated effluent and 38 recirculated. Products are sent to a fractionator. 6 7 Feed and Effluent Characteristics - Hydrocracking Stage 8 9 A VGO is a preferred first refinery stream, and a synthetic or straight run 10 middle distillate is a preferred second refinery stream. A suitable synthetic 11 middle distillate, formed by cracking a heavier stock, may contain high 12 nitrogen levels. The second refinery stream, which is added to the 13 hydrocracking effluent before it enters the hydrotreating zone, generally boils 14 in the middle distillate boiling range, and is hydrotreated to remove nitrogen 15 and/or aromatics, without excessive cracking. The preferred first stage 16 contains hydrocracking catalyst, maintained at hydrocracking conditions. 17 Likewise, the preferred second stage contains hydrotreating catalyst, 18 maintained at hydrotreating reaction conditions. In the process, the first and 19 the second stages are contained in two closely coupled reactor vessels, 20 separated by a heat exchanger, having a single integrated hydrogen supply 21 and recovery system serving both stages. The process serves to prevent 22 contaminants present in the second refinery stream from fouling the catalyst 23 in the first reaction zone. 24 25 One suitable first refinery stream is a VGO having a boiling point range 25 starling at a temperature above 500QF (260°C), usually within the temperature 27 range of 500°F-1100°F (260°C-593°C). A refinery stream wherein 75 vol% of 28 the refinery stream boils within the temperature range 650°F-1050°F is an 29 example feedstock for the first reaction zone. The first refinery stream may 30 contain nitrogen, usually present as organonitrogen compounds. VGO feed 31 streams for the first reaction zone contain less than about 200 ppm nitrogen 32 and less than 0.25 wt. % sulfur, though feeds with higher levels of nitrogen 33 and sulfur, including those containing up to 0.5 wt. % and higher nitrogen and 34 up to 5 wt. % sulfur and higher may be treated in the present process. The 35 first refinery stream is also preferably a low asphaltene stream. Suitable first 36 refinery streams contain less than about 500 ppm asphaltenes, preferably 37 (ess than about 200 ppm asphaltenes, and more preferably less than about 38 100 ppm asphaltenes. Example streams include light gas oil, heavy gas oil, 39 straight run gas oil, deasphalted oil, and the like. The first refinery stream 40 may have been processed, e.g., by hydrotreating, prior to the present process 41 to reduce or substantially eliminate its heteroatom content. The first refinery 42 stream may comprise recycle components. 10 11 The h yd roc racking reaction step removes nitrogen and sulfur from the first 12 refinery feed stream in the first hydrocracking reaction zone and effects a 13 boiling range conversion, so that the liquid portion of the first hydrocracking 14 reaction zone effluent has a normal boiling range below the normal boiling 15 point range of the first refinery feedstock. By "normal" is meant a boiling point 16 or boiling range based on a distillation at one atmosphere pressure, such as 17 that determined in a D1160 distillation. Unless otherwise specified, all 18 distillation temperatures listed herein refer to normal boiling point and normal 19 boiling range temperatures. The process in the first hydrocracking reaction 20 zone may be controlled to a certain cracking conversion or to a desired 21 product sulfur level or nitrogen level or both. Conversion is generally related 22 to a reference temperature, such as, for example, the minimum boiling point 23 temperature of the hydrocracker feedstock. The extent of conversion relates 24 to the percentage of feed boiling above the reference temperature which is 25 converted to products boiling below the reference temperature. 26 27 The hydrocracking reaction zone effluent includes normally liquid phase 28 components, e.g., reaction products and unreacted components of the first 29 refinery stream, and normally gaseous phase components, e.g., gaseous 30 reaction products and unreacted hydrogen. In the process, the hydrocracking 31 reaction zone is maintained at conditions sufficient to effect a boiling range 32 conversion of the first refinery stream of at least about 25%, based on a 650°F 33 reference temperature. Thus, at least 25% by volume of the components in 34 the first refinery stream which boil above about 65Q=F are converted in the 35 first hydrocracking reaction zone to components which boil below about 36 650°F. Operating at conversion levels as high as 100% is also within the 37 scope of the invention. Example boiling range conversions are in the range of 38 from about 30% to 90% or of from about 40% to 80%. The hydrocracking 39 reaction zone effluent is further decreased in nitrogen and sulfur content, with 40 at least about 50% of the nitrogen containing molecules in the first refinery 41 stream being converted in the hydrocracking reaction zone. Preferably, the 42 normally liquid products present in the hydrocracking reaction zone effluent 10 contain less than about 1000 ppm sulfur and less than about 200 ppm 11 nitrogen, more preferably less than about 250 ppm sulfur and about 100 ppm 12 nitrogen. 13 14 Conditions - Hydrocracking Stage 15 16 Reaction conditions in the hydrocracking reaction zone include a reaction 17 temperature between about 250°C and about 500DC (482°F-932°F), 18 pressures from about 3.5 MPa to about 24.2 MPa (500-3,500 psi), and a feed 19 rate (vol oil/vol cat h) from about 0.1 to about 20 hr"1. Hydrogen circulation 20 rates are generally in the range from about 350 std liters H£/kg oil to 1780 std 21 liters Hz/kg oil (2,310-11,750 standard cubic feet per barrel). Preferred 22 reaction temperatures range from about 340DC to about 455°C (644°F-851SF). 23 Preferred total reaction pressures range from about 7.0 MPa to about 24 20.7 MPa (1,000-3,000 psi). With the preferred catalyst system, it has been 25 found that preferred process conditions include contacting a petroleum 26 feedstock with hydrogen under hydrocracking conditions comprising a 27 pressure of about 13.8 MPa to about 20.7 MPa (2,000-3000 psi), a gas to oil 28 ratio between about 379-909 std liters H2/kg oil (2,500-6,000 scf/bbl), a LHSV 29 of between about 0.5-1.5 hr"1, and a temperature in the range of 36Q°C to 30 427°C (680°F-800°F). 31 1 Catalysts - Hydrocrackinq Stage 2 3 The hydrocracking stage and the hydrotreating stage may each contain one 4 or more catalysts. If more than one distinct catalyst is present in either of the 5 stages, they may either be blended or be present as distinct layers. Layered 6 catalyst systems are taught, for example, in U.S. Patent No. 4,590,243, the 7 disclosure of which is incorporated herein by reference for all purposes. 8 Hydrocracking catalysts useful for the first stage are well known. In general, 9 the hydrocracking catalyst comprises a cracking component and a 10 hydrogenation component on an oxide support material or binder. The 11 cracking component may include an amorphous cracking component and/or a 12 zeolite, such as a Y-type zeolite, an ultrastable Y type zeolite, or a 13 dealuminated zeolite. A suitable amorphous cracking component is 14 silica-alumina, 15 16 The hydrogenation component of the catalyst particles is selected from those 17 elements known to provide catalytic hydrogenation activity. At least one metal 18 component selected from the Group VIII (IUPAC Notation) elements and/or 19 from the Group VI (IUPAC Notation) elements are generally chosen. Group V 20 elements include chromium, molybdenum and tungsten. Group Vlll elements 21 include iron, cobalt, nickel, ruthenium, rhodium, palladium, osmium, iridium 22 and platinum. The amount(s) of hydrogenation components) in the catalyst 23 suitably range from about 0.5% to about 10% by weight of Group Vlll metal 24 component(s) and from about 5% to about 25% by weight of Group VI metal 25 ccmponent(s), calculated as metal oxide(s) per 100 parts by weight of total 26 catalyst, where the percentages by weight are based on the weight of the 27 catalyst before sulfiding. The hydrogenation components in the catalyst may 28 be in the oxidic and/or the sulphidic form, tf a combination of at least a 29 Group VI and a Group Vlll metal component is present as (mixed) oxides, it 30 will be subjected to a sulfiding treatment prior to proper use in hydrocracking. 31 Suitably, the catalyst comprises one or more components of nickel and/or 32 cobalt and one or more components of molybdenum and/or tungsten or one 33 or more components of platinum and/or palladium, Catalysts containing 34 nickel and molybdenum, nickel and tungsten, platinum and/or palladium are 35 particularly preferred. 3 4 The hydrocracking catalyst particles of this invention may be prepared by 5 blending, or co-mulling, active sources of hydrogenation metals with a binder. 6 Examples of suitable binders include silica, alumina, clays, zirconia, titania, 7 magnesia and silica-alumina. Preference is given to the use of alumina as 8 binder. Other components, such as phosphorous, may be added as desired 9 to tailor the catalyst particles for a desired application. The blended 10 components are then shaped, such as by extrusion, dried and calcined at 11 temperatures up to 1200°F (649°C) to produce the finished catalyst particles. 12 Alternatively, equally suitable methods of preparing the amorphous catalyst 13 particles include preparing oxide binder particles, such as by extrusion, drying 14 and calcining, followed by depositing the hydrogenation metals on the oxide 15 particles, using methods such as impregnation. The catalyst particles, 16 containing the hydrogenation metals, are then further dried and calcined prior 17 to use as a hydrocracking catalyst. 18 19 Feed and Effluent Characteristics - Hydrotreater Stage 20 21 The second refinery feedstream has a boiling point range generally lower than 22 the first refinery feedstream. Indeed, it is a feature of the present process that 23 a substantial portion of the second refinery feedstream has a normal boiling 24 point in the middle distillate range, so that cracking to achieve boiling point 25 reduction is not necessary. Thus, at least about 75 vol% of a suitabfe second 26 refinery stream has a normal boiling point temperature of less than about 27 1000°F. A refinery stream with at least about 75% v/v of its components 28 having a normal boiling point temperature within the range of 250°F-700°F is 29 an example of a preferred second refinery feedstream. 30 31 The process of this invention is particularly suited for treating middle distillate 32 streams which are not suitable for high quality fuels. For example, the 33 process is suitable for treating a second refinery stream which contains high 34 amounts of nitrogen and/or high amounts of anomalies, including streams 35 which contain up to 90% aromatics and higher. Example second refinery 36 feedstreams which are suitable for treating in the present process include 37 straight run vacuum gas oils, including straight run diesel fractions, from crude 38 distillation, atmospheric tower bottoms, or synthetic cracked materials such as 39 coker gas oil, light cycle oil or heavy cycle oil. 7 8 After the first refinery feedstream is treated in the hydrocracking stage, the 9 first hydrocracking reaction zone effluent is combined with the second 10 feedstock, and the combination passed together with hydrogen over the 11 catalyst in the hydrotreating stage. Since the hydrocracked effluent is already 12 relatively free of the contaminants to be removed by hydrotreating, the 13 hydrocracker effluent passes largely unchanged through the hydrotreater. 14 And unreacted or incompletely reacted feed remaining in the effluent from the 15 hydrotreater is effectively isolated from the hydrocracker zone to prevent 16 contamination of the catalyst contained therein. 17 18 However, the presence of the hydrocracker effluent plays an important and 19 unexpected economic benefit in the integrated process. Leaving the 20 hydrocracker, the effluent carries with it substantial thermal energy. This 21 energy may be used to heat the second reactor feedstream in a heat 22 exchanger before the second feedstream enters the hydrotreater. This 23 permits adding a cooler second feed stream to the integrated system than 24 would otherwise be required, and saves on furnace capacity and heating 25 costs. 26 27 As the second feedstock passes through the hydrotreater, the temperature 28 again tends to increase due to exothermic reaction heating in the second 29 zone. The hydrocracker effluent in the second feedstock serves as a heat 30 sink, which moderates the temperature increase through the hydrotreater. 31 The heat energy contained in the liquid reaction products leaving the 32 hydrotreater is further available for exchange with other streams requiring 33 heating. Generally, the outlet temperature of the hydrotreater will be higher 34 than the outlet temperature of the hydrocracker. In this case, the instant 35 invention will afford the added heat transfer advantage of elevating the 36 temperature of the first hydrocracker feed for more effective heat transfer. 37 The effluent from the hydrocracker also carries the unreacted hydrogen for 38 use in the first-stage hydrotreater without any heating or pumping requirement 39 to increase pressure. 7 8 Conditions - Hydrotreater Stage 9 10 The hydrotreater is maintained at conditions sufficient to remove at least a 11 portion of the nitrogen compounds and at least a portion of the aromatic 12 compounds from the second refinery stream. The hydrotreater will operate at 13 a lower temperature than the hydrocracker, except for possible temperature 14 gradients resulting from exothermic heating within the reaction zones, 15 moderated by the addition of relatively cooler streams into the one or more 16 reaction zones. Feed rate of the reactant liquid stream through the reaction 17 zones will be in the region of 0,1 to 20 hr'1 liquid hourly space velocity. Feed 18 rate through the hydrotreater will be increased relative to the feed rate through 19 the hydrocracker by the amount of liquid feed in the second refinery 20 feedstream and will also be in the region of 0.1 to 20 hr"1 liquid hourly space 21 velocity. These process conditions selected for the first reaction zone may be 22 considered to be more severe than those conditions normally selected for a 23 hydrotreating process. 24 25 At any rate, hydrotreating conditions typically used in the hydrotreater will 26 include a reaction temperature between about 250°C and about 500°C 27 (482°F-932°F), pressures from about 3.5 MPa to about 24.2 MPa 28 (500-3,500 psi), and a feed rate (vol oil/vol cat h) from about 0.1 to about 29 20 hr"'. Hydrogen circulation rates are generally in the range from about 30 350 std liters Hz/kg oil to 178Q std liters H2/kg oil (2,310-11,750 standard cubic 31 feet per barrel). Preferred reaction temperatures range from about 340°C to 32 about 455°C (644°F-851 °F). Preferred total reaction pressures range from 33 about 7.0 MPa to about 20.7 MPa (1,000-3,000 psi). With the preferred 34 catalyst system, it has been found that preferred process conditions include 35 contacting a petroleum feedstock with hydrogen in the presence of the 36 layered catalyst system under hydrocracking conditions comprising a 37 pressure of about 16.0 MPa (2,300 psi), a gas to oil ratio at from about 38 379-909 std liters H2/kg oil (2,500 scf/bbl to about 6,000 scf/bbl), a LHSV of 39 between about 0.5-1.5 hr"1, and a temperature in the range of 360°C to 427°C 40 (680°F-800QF). Under these conditions, at least about 50% of the aromatics 41 are removed from the second refinery stream in the hydrotreater. It is 42 expected that as much as 30-70% or more of the nitrogen present in the 10 second refinery stream would also be removed in the process. However, 11 cracking conversion in the hydrotreater would be generally low, typically less 12 than 20%. Standard methods for determining the aromatic content and the 13 nitrogen content of refinery streams are available. These include ASTM 14 D5291 for determining the nitrogen content of a stream containing more than 15 about 1500 ppm nitrogen. ASTM D5762 may be used for determining the 16 nitrogen content of a stream containing less than about 1500 ppm nitrogen. 17 ASTM D2007 may be used to determine the aromatic content of a refinery 18 stream. 19 20 The second reaction stage contains hydrotreating catalyst, maintained at 21 hydrotreating conditions. Catalysts known for hydrotreating are useful for the 22 first-stage hydrotreater. Such hydrotreating catalysts are suitable for 23 hydroconversion of feedstocks containing high amounts of sulfur, nitrogen 24 and/or aromatic-containing molecules. It is a feature of the present invention 25 that the hydrotreating step may be used to treat feedstocks containing 26 asphaltenic contaminants which would otherwise adversely affect the catalytic 27 performance or life of the hydrocracking catalysts. The catalysts in the 28 hydrotreater are selected for removing these contaminants to low values. 29 Such catalysts generally contain at least one metal component selected from 30 Group VIII (IUPAC Notation) and/or at least one metal component selected 31 from the Group VI (IUPAC notation) elements. Group VI elements include 32 chromium, molybdenum and tungsten. Group VIII elements include iron, 33 cobalt and nickel. While the noble metals, especially palladium and/or 34 platinum, may be included, alone or in combination with other elements, in the 35 hydrotreating catalyst, use of the noble metals as hydrogenation components 36 is not preferred. The amount(s) of hydrogenation component(s) in the catalyst 37 suitably range from about 0.5% to about 10% by weight of Group VIII metal 38 component(s) and from about 5% to about 25% by weight of Group VI metal 39 component(s), calculated as metal oxide(s) per 100 parts by weight of total 40 catalyst, where the percentages by weight are based on the weight of the 41 catalyst before sulfiding. The hydrogenation components in the catalyst may 42 be in the oxidic and/or the sulfidic form. If a combination of at least a 10 Group VI and a Group VIII metal component is present as (mixed) oxides, it 11 will be subjected to a sulfiding treatment prior to proper use in hydrocracking. 12 Suitably, the catalyst comprises one or more components of nickel and/or 13 cobalt and one or more components of molybdenum and/or tungsten. 14 Catalysts containing cobalt and molybdenum are particularly preferred. 15 16 The hydrotreating catalyst particles of this invention are suitably prepared by 17 blending, or co-mulling, active sources of hydrogenation metals with a binder. 18 Examples of suitable binders include silica, alumina, clays, zirconia, titania, 19 magnesia and silica-alumina. Preference is given to the use of alumina as 20 binder. Other components, such as phosphorous, may be added as desired 21 to tailor the catalyst particles for a desired application. The blended 22 components are then shaped, such as by extrusion, dried and calcined at 23 temperatures up to 1200°F (649°C) to produce the finished catalyst particles. 24 Alternatively, equally suitable methods of preparing the amorphous catalyst 25 particles include preparing oxide binder particles, such as by extrusion, drying 26 and calcining, followed by depositing the hydrogenation metals on the oxide 27 particles, using methods such as impregnation. The catalyst particles, 28 containing the hydrogenation metals, are then further dried and calcined prior 29 to use as a hydrotreating catalyst. 30 31 The subject process is especially useful in the production of middle distillate 32 fractions boiling in the range of about 250°F-700°F (121°C-371°C) as 33 ■ determined by the appropriate ASTM test procedure. By a middle distillate 1 fraction having a boiling range of about 250°F-700°F is meant that at least 2 75 vol%, preferably 85 vol%, of the components of the middle distillate have a 3 normal boiling point of greater than about 250°F and furthermore that at least 4 about 75 vo)%, preferably 85 vol%, of the components of the middle distillate 5 have a normal boiling point of less than 700°F. The term "middle distillate" is 6 intended to include the diesel, jet fuel and kerosene boiling range fractions. 7 The kerosene or jet fuel boiling point range is intended to refer to a 8 temperature range of about 280°F-525°F (138°C-274°C), and the term "diesel 9 boiling range" is intended to refer to hydrocarbon boiling points of about 10 250°F-700°F (12VC-37VC). Gasoline or naphtha is normally the C5 to 400°F 11 (204°C) endpoint fraction of available hydrocarbons. The boiling point ranges 12 of the various product fractions recovered in any particular refinery will vary 13 with such factors as the characteristics of the crude oil source, refinery local 14 markets, product prices, etc. Reference is made to ASTM standards D-975 15 and D-3699-83 for further details on kerosene and diesel fuel properties. 16 17 The effluent of the hydrotreater is subsequently fractionated. The fractionator 18 bottoms may be subjected to subsequent hydrocracking and hydrotreating. 19 The range of conditions and the types of catalysts employed in the 20 subsequent treatments are the same as those which may be employed in the 21 first stage, although catalyst comprising zeolites may be more typically 22 employed. 23 24 Reference is now made to Figure 1, which discloses preferred embodiments 25 of the invention. Not included in the figures are various pieces of auxiliary 26 equipment such as heat exchangers, condensers, pumps and compressors, 27 which are not essential to the invention. 28 29 In Figure 1, two downflow reactor vessels, 5 and 15 are depicted. Between 30 them is heat exchanger 20. Each vessel contains at least one reaction zone. 31 The first-stage reaction, hydrocracking, occurs in vessel 5. The second-stage 32 reaction, hydrotreating, occurs in vessel 15. Each vessel is depicted as 33 having three catalyst beds. The first reaction vessel 5 is for cracking a first 34 refinery stream 1. The second reaction vessel 15 is for removing 35 nitrogen-containing and aromatic molecules from a second refinery stream 17. 36 A suitable volumetric ratio of the catalyst volume in the first reaction vessel to 37 the catalyst volume in the second reaction vessel encompasses a broad 38 range, depending on the ratio of the first refinery stream to the second refinery 39 stream. Typical ratios generally lie between 20:1 and 1:20. A preferred 40 volumetric range is between 10:1 and 1:10. A more preferred volumetric ratio 41 is between 5:1 and 1:2. 10 11 In the integrated process, a first refinery stream 1 is combined with a 12 hydrogen-rich gaseous stream 4 to form a first feedstock 12. The stream 13 exiting furnace 30, stream 13, is passed to first reaction vessel 5. 14 Hydrogen-rich gaseous stream 4 contains greater than 50% hydrogen, the 15 remainder being varying amounts of light gases, including hydrocarbon gases. 16 The hydrogen-rich gaseous stream 4 shown in the drawing is a blend of 17 make-up hydrogen 3 and recycle hydrogen 26. While the use of a recycle 1B hydrogen stream is generally preferred for economic reasons, it is not 19 required. First feedstock 1 may be heated in one or more exchangers, such 20 as exchanger 10, emerging as stream 12, and in one or more heaters, such 21 as heater 30, (emerging as stream 13) before being introduced to first 22 reaction vessel 5 in which hydrocracking preferably occurs. Hydrotreating 23 preferably occurs in vessel 15. 24 25 Hydrogen may also be added as a quench stream through lines 6 and 7, and 26 9 and 11, (which also come from hydrogen stream 4) for cooling the first and 27 the second reaction stages, respectively. The effluent from the hydrocracking 28 stage, stream 14 is cooled in heat exchanger 20 by stream 2. Stream 2 boils 29 in the diesel range and may be light cycle oil, light gas oil, atmospheric gas 30 oil, or a mixture of the three. Stream 2 emerges from exchanger 20 as 31 stream 16 and combines stream 14 as it emerges from exchanger 20 to form 32 combined feedstock 17. Hydrogen in stream 8 joins the combined feedstock 33 17 before it enters vessel 15. Stream 17 enters vessel 15 for hydrotreatment, 34 and exits as stream 18. 3 4 The second reaction stage, found in vessel 15, contains at least one bed of 5 catalyst, such as hydrotreating catalyst, which is maintained at conditions 6 sufficient for converting at least a portion of the nitrogen compounds and at 7 least a portion of the aromatic compounds in the second feedstock. 8 9 Hydrogen stream 4 may be recycle hydrogen from compressor 40. 10 Alternately, stream 4 may be a fresh hydrogen stream, originating from 11 hydrogen sources external to the present process. 12 13 Stream 18, the second reaction zone effluent, contains thermal energy which 14 may be recovered by heat exchange, such as in heat exchanger 10. Second 15 stage effluent 18 emerges from exchanger 10 as stream 19 and is passed to 16 hot high pressure separator 25. The liquid effluent of the hot high pressure 17 separator 25, stream 22 is passed to fractionation. The overhead gaseous 18 stream from separator 25, stream 21, is combined with water from stream 23 19 for cooling. The now cooled stream 21 enters the cold high pressure 20 separator 35. Light liquids are passed to fractionation in stream 27 (which 21 joins stream 22) and sour water is removed through stream 34. Gaseous 22 overhead stream 24 passes to amine absorber 45, for the removal of 23 hydrogen sulfide gas. Purified hydrogen then passes, through stream 26, to 24 the compressor 40, where it is recompressed and passed as recycle to one or 25 more of the reaction vessels and as a quench stream for cooling the reaction 26 zones. Such uses of hydrogen are well known in the art. 27 28 An example separation scheme for a hydroconversion process is taught in 29 U.S. Patent No. 5,082,551, the entire disclosure of which is incorporated 30 herein by reference for all purposes. 31 32 The absorber 45 may include means for contacting a gaseous component of 33 the reaction effluent 19 with a solution, such as an alkaline aqueous solution, 34 for removing contaminants such as hydrogen sulfide and ammonia which may 35 be generated in the reaction stages and may be present in reaction effluent 36 19. The hydrogen-rich gaseous stream 24 is preferably recovered from the 37 separation zone at a temperature in the range of 100CF-300°F or 38 100°F-200°F. 6 7 Liquid stream 22 is further separated in fractionator 50 to produce overhead 8 gasoline stream 28, naphtha stream 29, kerosene fraction 31, diesel stream 9 32 and fractionator bottoms 33, A preferred distillate product has a boiling 10 point range within the temperature range 250DF-700°F. A gasoline or naphtha 11 fraction having a boiling point range within the temperature range C5~400°F is 12 also desirable. 13 14 In Figure 2, two downflow reactor vessels, 5 and 15, are depicted. The first 15 stage reaction, hydrocracking, occurs in vessel 5. The second stage, 16 hydrotreating, occurs in vessel 15. Each vessel contains at least one reaction 17 zone. Each vessel is depicted as having three catalyst beds. The first 18 reaction vessel 5 is for cracking a first refinery stream 1. The second reaction 19 vessel 15 is for removing nitrogen-containing and aromatic molecules from a 20 second refinery stream 34. A suitable volumetric ratio of the catalyst volume 21 in the first reaction vessel to the catalyst volume in the second reaction vessel 22 encompasses a broad range, depending on the ratio of the first refinery 23 stream to the second refinery stream. Typical ratios generally lie between 24 20:1 and 1:20. A preferred volumetric range is between 10:1 and 1:10. A 25 more preferred volumetric ratio is between 5:1 and 1:2. 26 27 In the integrated process, a first refinery stream 1 is combined with a 28 hydrogen-rich gaseous stream 4 to form a first feedstock 12 which is passed 29 to first reaction vessel 5. Hydrogen-rich gaseous stream 4 contains greater 30 than 50% hydrogen, the remainder being varying amounts of light gases, 31 including hydrocarbon gases. The hydrogen-rich gaseous stream 4 shown in 32 the drawing is a blend of make-up hydrogen 3 and recycle hydrogen 26. 33 While the use of a recycle hydrogen stream is generally preferred for 34 economic reasons, it is not required. First feedstock 1 may be heated in one 35 or more exchangers or in one or more heaters before being combined with 36 hydrogen-rich stream 4 to create stream 12. Stream 12 is then introduced to 37 first reaction vessel 5, where the first stage, in which hydrocracking preferably 38 occurs, is located. The second stage is located in vessel 15, where 39 hydrotreating preferably occurs. 7 8 The effluent from the first stage, stream 14 is heated in heat exchanger 20. 9 Stream 14 emerges from exchanger 20 as stream 17 and passes to the 10 "hot/hot" high pressure separator 55. The liquid stream 36 emerges from the 11 "hot/hot" high pressure separator 55 and proceeds to fractionator 60. Stream 12 37 represents products streams for gasoline and naphtha, stream 38 13 represents distillate recycled back to the inlet of hydrotreater 15, and stream 14 39 represents clean bottoms material. 15 16 The gaseous stream 34 emerges from the "hot/hot" high pressure separator 17 55, and joins with stream 2, which boils in the diesel range and may be light 18 cycle oil, light gas oil, atmospheric gas oil, or a mixture of the three. It further 19 combines with hydrogen-rich stream 4 prior to entering vessel 15 for 20 hydrotreatment, and exits as stream 18. 21 22 The second reaction zone, found in vessel 15, contains at least one bed of 23 catalyst, such as hydrotreating catalyst, which is maintained at conditions 24 sufficient for converting at least a portion of the nitrogen compounds and at 25 least a portion of the aromatic compounds in the second feedstock. 26 27 Hydrogen stream 4 may be recycle hydrogen from compressor 40. 28 Alternately, stream 4 may be a fresh hydrogen stream, originating from 29 hydrogen sources external to the present process. 30 31 Stream 18, the second stage effluent, contains thermal energy which may be 32 recovered by heat exchange, such as in heat exchanger 10. Second stage 33 effluent 18 emerges from exchanger 10 as stream 19 and is passed to hot 34 high pressure separator 25. The liquid effluent of the hot high pressure 35 separator 25, stream 22 is passed to fractionation. The overhead gaseous 36 stream from separator 25, stream 21, is combined with water from stream 23 37 for cooling. The now cooled stream 21 enters the cold high pressure 38 separator 35. Light liquids are passed to fractionation in stream 27 (which 39 joins stream 22) and sour water is removed through stream 41. Gaseous 40 overhead stream 24 passes to amine absorber 45, for the removal of 41 hydrogen sulfide gas. Purified hydrogen then passes, through stream 26, to 42 the compressor 40, where it is recompressed and passed as recycle to one or 10 more of the reaction vessels and as a quench stream for cooling the reaction 11 zones. Such uses of hydrogen are well known in the art. 12 13 The absorber 45 may include means for contacting a gaseous component of 14 the reaction effluent 19 (stream 24) with a solution, such as an alkaline 15 aqueous solution, for removing contaminants such as hydrogen sulfide and 16 ammonia which may be generated in the reaction zones and may be present 17 in reaction effluent 19. The hydrogen-rich gaseous stream 24 is preferably 18 recovered from the separation zone at a temperature in the range of 19 100°F-300oFor100oF-200°F. 20 21 Liquid stream 22 is further separated in fractionator 50 to produce overhead 22 gasoline stream 28, naphtha stream 29, kerosene fraction 31, diesel stream 23 32 and fractionator bottoms 33. A preferred distillate product has a boiling 24 point range within the temperature range 250°F-700°F. A gasoline or naphtha 25 fraction having a boiling point range within the temperature range C5-400°F is 26 also desirable. 1. An integrated hydro conversion process having at least two stages, each stage possessing at least one reaction zone, comprising; (a) combining a first refinery stream with a first hydrogen-rich gaseous stream to form a first feedstock (b) passing the first feedstock to a reaction zone of the first stage, which is maintained at conditions sufficient to effect a boiling range conversion, to form a first reaction zone effluent comprising normally liquid phase components and normally gaseous phase components; (cj passing the first reaction zone effluent of step (b) to a heat exchanger or series of exchangers, where it exchanges heat with a second refinery stream; (d) combining the first reaction zone effluent of step (b) with the second refinery stream of step (c) to form a second feedstock; (e) passing the second feedstock of step (d) to a reaction zone of the second stage, which is maintained at conditions sufficient for converting at least a portion of the aromatics present in the second refinery stream, to form a second reaction zone effluent; (0 separating the second reaction zone effluent of step (e) into a liquid stream comprising products and a second hydrogen-rich gaseous stream; (g) recycling at least a portion of the second hydrogen-rich gaseous stream of step (f) to a reaction zone of the first stage; and (h) passing the liquid stream comprising products of step (f) to a fractionation column, wherein product streams comprise gas or naphtha stream removed overhead, one or more middle distillate streams, and a bottoms stream suitable for further processing. 2- The process according to Claim 1 wherein the reaction zone of step 1 (b) is maintained at conditions sufficient to effect a boiling range conversion of the first refinery stream of at least about 25%. 3. The process according to Claim 2 wherein the reaction zone of step 1(b) is maintained at conditions sufficient to effect a boiling range conversion of the first refinery stream of between 30% and 90%. A. The process according to Claim 1 wherein the first refinery stream of step 1(a) has a normal boiling point range within the temperature range 500°F-1100°F (262°C-593°C). 5. The process according to Claim 1 wherein the first refinery stream of step 1(a) is a VGO. 3. The process according to Claim 1 wherein at least about 80% by volume of the second refinery stream of step 1 (c) boils at a temperature of less than about 1000°F. 7. The process according to Claim 1 wherein at least about 50% by volume of the second refinery stream of step 1 (c) has a normal boiling point within the middle distillate range. 3, The process according to Claim 6 wherein at least about 80% by volume of the second refinery stream of step 1 (c) boils with the temperature range of 250°F-700°F. The process according to Claim 1 wherein the second refinery stream of step 1(c) is a synthetic cracked stock. The process according to Claim 1 wherein the second refinery stream of step 1 (c) is selected from the group consisting of light cycle oil, light gas oil, and atmospheric gas oil. The process according to Claim 1 wherein the second refinery stream of step 1 (c) has an aromatics content of greater than about 50%. The process according to Claim 11 wherein the second refinery stream of step 1 (c) has an aromatics content of greater than about 70%. The process according to Claim 1 wherein the reaction zone of step 1(b) stage is maintained at hydrocracking reaction conditions, including a reaction temperature in the range of from about 340°C to about 455°C (644°F-851°F), a reaction pressure in the range of about 3.5-24.2 MPa {500-3500 pounds per square inch), a feed rate (vol oil/vol cat h) from about 0.1 to about 10 hr*1 and a hydrogen circulation rate ranging from about 350 std liters H3/kg oil to 1780 std liters H2/kg oil (2,310-11,750 standard cubic feet per barrel). The process according to Claim 1 wherein the reaction zone of step 1(e) is maintained at hydrotreating reaction conditions, including a reaction temperature in the range of from about 250°C to about 500DC (482°F-932°F), a reaction pressure in the range of from about 3.5 MPa to 24.2 MPa (500-3,500 psi), a feed rate (vol oii/vol cat h) from about 0.1 to about 20 hr"1, and a hydrogen circulation rate in the range from about 350 std liters H2/kg oil to 1780 std liters H2/kg oil (2,310-11,750 standard cubic feet per barrel). 15. The process according to Claim 1 for producing at least one middle distillate stream having a boiling range within the temperature range 250°F-700°F. 16. An integrated hydroconversion process having at least two stages, each stage possessing at least one reaction zone, comprising: (a) combining a first refinery stream with a first hydrogen-rich gaseous stream to form a first feedstock; (b) passing the first feedstock to a reaction zone of the first stage, which is maintained at conditions sufficient to effect a boiling range conversion, to form a first reaction zone effluent comprising normally liquid phase components and normally gaseous phase components; (c) passing the first reaction zone effluent of step (b) to a heat exchanger or series of exchangers, where it exchanges heat with other refinery streams; (d) passing the effluent of step (c) to a hot high pressure separator, where it is separated into a liquid stream which is passed to fractionation, and a gaseous stream, which is combined with a second refinery stream which comprises light cycle oil, light gas oil, atmospheric gas oil or mixtures of all three; (e) passing the combined gaseous stream of step (d) to a reaction zone of the second stage, which is maintained at conditions sufficient for converting at least a portion of the aromatics present in the second refinery stream, to form a second reaction zone effluent; (f) separating the second reaction zone effluent of step (e) into a liquid stream comprising products and a second hydrogen-rich gaseous stream; (g) recycling at least a portion of the second hydrogen-rich gaseous stream of step (0 to a reaction zone of the first stage; and (h) passing the liquid stream comprising products of step (f) to a fractionation column, wherein product streams comprise a gas or naphtha stream removed overhead, one or more middle distillate streams, and a bottoms stream suitable for further processing. 17. An integrated hydroeonverion process, substantially as hereinabove described and illustrated with reference to the accompanying drawings.

Documents:

0943-mas-2002 abstract.pdf

0943-mas-2002 claims.pdf

0943-mas-2002 correspondence-others.pdf

0943-mas-2002 correspondence-po.pdf

0943-mas-2002 description(complete).pdf

0943-mas-2002 drawings.pdf

0943-mas-2002 form-1.pdf

0943-mas-2002 form-18.pdf

0943-mas-2002 form-3.pdf

0943-mas-2002 others.pdf

943-MAS-2002 OTHER PATENT DOCUMENT 03-09-2009.pdf