BACKGROUND OF THE INVENTION In the refining of crude oil, gas oil hydrocrackers are used to convert heavy gas oils to lighter products using a single reaction stage or multiple reaction stages. In most instances, the various reaction stages operate at similar pressure levels. Where pressure levels are different, separate hydrogen loops are employed. Multiple reaction stages are used to achieve the following : high conversion employing minimum reactor volume and catalyst volume overall better product qualities lower hydrogen consumption The use of multiple reaction systems however involves more equipment including multiple expensive high-pressure pumps and compressors.

U. S. Patent No. 5,980, 729 discloses a configuration with multiple reaction zones in a single hydrogen loop. The process uses a hot stripper downstream of the denitrification/desulfurization zone. Liquid from the hot stripper is pumped to the hydrocracking reactor upstream of the hydrotreating

reactor. Recycle oil from the fractionation section is also pumped back to the hydrocracking reactor.

In conventional hydroprocessing, it is necessary to transfer hydrogen from a vapor phase into the liquid phase where it will be available to react with a petroleum molecule at the surface of the catalyst. This is accomplished by circulating very large volumes of hydrogen gas and the oil through a catalyst bed. The oil and the hydrogen flow through the bed and the hydrogen is absorbed into a thin film of oil that is distributed over the catalyst. Because the amount of hydrogen required can be large, 1000 to 5000 SCF/bbl of liquid, and the amount of catalyst required can also be large, the reactors are very large and can operate at severe conditions, from a few hundred psi to as much as 5000 psi and temperatures from around 400°F to 900°F.

U. S. Pat. No. 6,224, 747 teaches hydrocracking a VGO stream 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 hydrotreated in a hydrotreating reaction zone. The hydrocracked effluent serves as a heat sink for the hydrotreating reaction zone. The integrated reaction system provides a single hydrogen supply and recirculation system for use in two reaction systems. There is no temperature control between the hydrocracking reaction zone and the hydrotreating reaction zone, however.

U. S. Pat. No. 3,592, 757 (Baral) illustrates temperature control between zones by means of heat exchangers, as in the instant invention. Baral does not employ a single hydrogen loop, as does the instant invention. Baral discloses a hydrofiner (similar to a hydrotreater) operating in series with a hydrocracker, with a fraction of the product fed to a hydrogenator. A gas oil feed is fed with both make-up and recycle hydrogen to a hydrofiner. A recycle stream and additional recycle hydrogen are added to the hydrofiner product stream, and

the mixture is fed to a hydrocracker. The hydrocracker product stream is cooled and separated into a vapor and a liquid stream. The vapor stream is passed to a recycle hydrogen compressor recycle to the hydrofiner. The liquid stream is fractionated into a top, middle, and bottom stream. The bottom stream is recycled to the hydrocracker. The middle stream is mixed with hydrogen from a make-up hydrogen compressor and directed to a hydrogenator. Hydrogen recovered from the hydrogenator is compressed in a stage of the make-up hydrogen compressor and directed to the hydrofiner.

U. S. Pat. No. 5,114, 562 (Haun et al.) teaches a two-stage hydrodesulfurization (similar to hydrotreating) and hydrogenation process for distillate hydrocarbons. There is heat exchange between the two stages, but a single hydrogen loop is not employed. Two separate reaction zones are employed in series, the first zone for hydrodesulfurization and a second zone for hydrogenation. A feed is mixed with recycled hydrogen and fed to a desulfurization reactor. Hydrogen sulfide is stripped from the desulfurization reactor product by a countercurrent flow of hydrogen. The liquid product stream from this stripping operation is mixed with relatively clean recycled hydrogen and the mixture is fed to a hydrogenation reaction zone. Hydrogen is recovered from the hydrogenation reactor and recycled as a split stream to both the desulfurization reactor and the hydrogenation reactor. The hydrogen from the stripping operation is passed through a separator, mixed with the portion of the recycled hydrogen directed to the hydrogenation reactor, compressed, passed through a treating step and recycled to the hydrogenation reactor. Thus, the hydrocarbon feed stream passes in series through the desulfurization and hydrogenation reactors, while relatively low pressure hydrogen is provided for the desulfurization step and relatively high pressure hydrogen is provided for the hydrogenation step.

SUMMARY OF THE INVENTION The first embodiment for this invention is disclosed in Figure 1. The process configuration for the first embodiment is different from U. S. Pat. No. 5,980, 729 in many aspects. The primary reactor is a combination hydrotreating- hydrocracking reactor that uses no recycle liquid.

Liquid from the hot stripper downstream of the reactor is reduced in pressure to a subsequent reaction stage where hydrocracking reactions are completed.

No pump is involved in the transfer of liquid. Also, the second hydrocracking stage operates at lower pressure than the primary reaction stage.

With this invention, moderate to high conversion can be achieved using a single hydrogen loop. Product quality can be modulated to just meet specifications, eliminating product loss and saving hydrogen. The pressures of the reaction stages are maintained at levels suited for particular types of feed characteristics, i. e., only the first stage reactor that processes the most difficult feed must operate at the highest pressure level. High-temperature, high-pressure pumps are not involved in the process. The second hydrocracking reactor stage can operate in either co-current or counter-current mode with respect to the reaction gas, which in the present invention is primarily make-up hydrogen. The second hydrocracking reaction stage is fed with high purity make-up hydrogen to maximize hydrogen partial pressure. The second stage is loaded with very high activity catalyst that can be used for hydrocracking at relatively low pressures.

The second embodiment of this invention is disclosed in Figures 2 and 3. A VGO stream is initially hydrocracked in a first-stage hydrocracking reaction zone within an integrated hydroconversion process. The integrated hydroconversion process possesses at least one hydrocracking stage and at least one hydrotreating stage. Effluent from the first-stage hydrocracking

reaction zone is combined with a light aromatic-containing feed stream, and the blended stream is hydrotreated in a second stage, which comprises a hydrotreating reaction zone. Heat exchange occurs between the first-stage hydrocracking reaction zone and the second-stage hydrotreating reaction zone, permitting the temperature control of the first-stage hydrotreating zone.

The temperature of the first-stage hydrotreater is lower than that of the first-stage hydros acker. This improves the aromatic saturation of the converted hydrocarbons and also allows the catalyst of the first-stage hydrotreating zone to be different from the catalyst in subsequent hydrocracking zones that may be present. In one embodiment, the effluent from the first-stage hydrotreater is heated in an exchanger, then passed to a hot high pressure separator, where overhead light ends are removed and passed to a cold high pressure separator. In the cold high pressure separator, hydrogen and hydrogen sulfide gas is removed overhead and materials boiling in the gasoline and diesel range are passed to a fractionator.

Hydrogen sulfide is subsequently removed in an absorber and hydrogen is compressed and recirculated to be used as interbed quench, as well as mixed with vacuum gas oil feed.

The liquid effluent of the hot high pressure separator, which may contain materials boiling in the diesel range, is also passed to the fractionator. The fractionator bottoms may be subsequently hydrocracked and products may be subsequently hydrotreated in units not depicted.

The second embodiment of this invention offers several notable benefits. The invention provides a method for hydroprocessing two refinery streams using a single hydrogen supply and a single hydrogen recovery system.

Furthermore, the instant invention provides a method for hydrocracking a refinery stream and hydrotreating a second refinery stream with a common hydrogen feed supply. The feed to the hydrocracking reaction zone is not poisoned with contaminants present in the feed to the hydrotreating reaction

zone. The present invention is further directed to hydroprocessing two or more dissimilar refinery streams in an integrated hydroconversion process while maintaining good catalyst life and high yields of the desired products, particularly distillate range refinery products. Such dissimilar refinery streams may originate from different refinery processes, such as a VGO, derived from the effluent of a VGO hydrotreater, which contains relatively few catalyst contaminants and/or aromatics, and an FCC cycle oil or straight run diesel, which contains substantial amounts of aromatic compounds.

BRIEF DESCRIPTION OF THE DRAWINGS The Figures illustrate multiple reaction stages employing a single hydroprocessing loop. Figure 1 depicts the use of an interstage hot stripper and an interstage hot separator.

Figure 2 illustrates a hydrocracker and hydrotreater in series, in a single hydrogen loop separated by a heat exchanger. Light and heavy materials are separated from each other. Hydrogen and hydrogen sulfide might be removed from the light products. Hydrogen is compressed and recirculated.

Products are sent to a fractionator.

Figure 3 illustrates a hydrocracking step followed by separation and fractionation. Material removed overhead is combined with a light aromatic stream and hydrotreated. Hydrogen is separated from the hydrotreated effluent and recirculated. Products are sent to a fractionator.

DETAILED DESCRIPTION OF THE INVENTION Description of Figure 1 Preheated Oil feed in stream 1 is mixed with hydrogen in stream 40, which is preheated recycle and make-up hydrogen gas (reactor feed gas). The feed has been preheated in a process heat exchanger pumped up to the reactor pressure by the feed pump. The mixture of feed and reactor feed gas, now in stream 2, gets further preheated by heat exchange (in exchanger 41) and a final furnace (42) before it enters the first stage, downflow fixed bed primary reactor (3). The primary or first stage reactor contains multiple beds of hydroprocessing catalysts which may be beds of either hydrotreating or hydrocracking catalysts. Cold hydrogen from the recycle gas compressor is used as interbed quench (4,5, 6).

The effluent 7 of the first stage reactor, which has been hydrotreated and partially hydrocracked, contains hydrogen sulfide, ammonia, light gases, naphtha, middle distillate, and hydrotreated vacuum gas oil. The effluent enters the hot high pressure separator (8) at slightly lower pressure and at slightly lower temperature, where most of the diesel and lighter material is separated from the unconverted oil. The hot high pressure separator has disc and doughnut type trays. Hydrogen rich gas, heated in exchanger 38, is introduced at the bottom for stripping through stream 9.

Stream 11 contains the overhead from the hot high-pressure separator. At this point, external feeds boiling in the middle-distillates boiling range such as Light Cycle Oil (LCO), Light Coker Gas Oil (LCGO), Atmospheric Gas Oil (AGO), Light Visbreaker Gas Oil (LVBGO), etc. , can be introduced (10).

Stream 11 is cooled by process heat exchange or by steam generation before entering the high-pressure hydrogen stripper-hydrotreater (14). Liquid in stream 11 flows downward through a bed of packing containing hydrotreating

catalyst, while being contacted with countercurrent flowing hydrogen from stream 25.

The overhead stream 15 contains primarily hydrogen, ammonia and hydrogen sulfide, along with some light gases and naphtha. It is cooled by process heat exchange (44), contacted with water (45), and further cooled by air cooling (46) before being fed to the Cold High Pressure Separator No. 1 (17). The water injection allows the removal of most of the ammonia from the hydrogen gas as ammonium bisulfide solution. Hydrogen, hydrogen sulfide and light hydrocarbonaceous gases are removed overhead as stream 18. Stream 20 is a sour water stream containing ammonium bisulfide. Stream 19 is a hydrocarbonaceous stream containing naphtha, kerosene and diesel range products. Stream 18 is sent to an amine absorber (21) where almost the entire quantity of hydrogen sulfide is removed from the hydrogen-rich stream by contacting with amine (47). After removal of the hydrogen sulfide, the gas is sent for compression to the recycle gas compressor (23). The compressed recycle gas (24) is split into streams 25 and 26. Stream 26 is further split into the first stage recycle gas feed (27) and stream 28 that supplies the quench to the first stage. Risk amine leaves the amine absorber as stream 48.

Bottoms from the hot high-pressure separator, stream 12, can be reduced in pressure and cooled down by process heat exchange before being fed to the second stage reactor (30) where hydrocracking reactions are completed and unconverted material in stream 12 is further converted to diesel and lighter products. The second stage reactor is fed with high purity make-up hydrogen (31) from an intermediate stage of the make-up hydrogen compressor (49).

The hydrogen, in the preferred mode, flows up the reactor in countercurrent fashion for maximizing the benefits of hydrogen partial pressure. The invention will also work with co-current introduction of make-up hydrogen.

The second stage reactor feed gas requirements in terms of adequate gas-to-oil ratio can be met by introducing all of the make-up hydrogen

required in all reaction stages to the front of second stage reactor. The invention has the provision, however, to introduce recycle hydrogen from the recycle gas compressor through stream 35.

The second reaction stage operates under a clean, ammonia and hydrogen sulfide free environment and thus hydrocracking rate constants are much higher. Catalyst deactivation is much reduced. These factors enable the operation at lower hydrogen partial pressures and with reduced catalyst requirements.

The lower bed or beds of the second stage reactor (30) can be loaded with hydrotreating catalyst where diesel range material (16) from the hydrogen stripper (14) can be introduced for completion of aromatic saturation and other hydroprocessing reactions. Alternately, stream 16 can be diverted directly to the fractionation section if the diesel quality is adequate.

There are at least two, preferably three to four, beds of hydroprocessing catalyst in reactor 30. The catalyst can be either base metal or noble metal hydroprocessing catalyst.

Stream 33, which comes from the top of the reactor, contains primarily hydrogen, although some H2S and ammonia may be present. It is cooled by process heat exchange (50) before being sent to Cold High Pressure Separator No. 2 (17.5). The overhead vapor of Cold High Pressure Separator No. 2 passes to the make-up hydrogen compressor (49), to the final stage of compression.

The liquid effluent from reactor 30, Stream 34, which contains light gases, naphtha, middle distillate and hydrotreated gas oil, is cooled by process heat exchange (51) and sent to Cold High Pressure Separator No. 2 (17.5).

Bottoms (line 37) from the Cold High Pressure Separator No. 2 is sent to fractionation.

The Make-up hydrogen compressor (49) is a multi-stage machine with typically three to four compression stages. After each stage of compression, the gas is cooled and any condensate knocked out in a knock-out drum (KOD). For this invention, the gas to the second reaction stage is withdrawn after an intermediate stage of compression. The gas stream (31) is sent to the second reaction stage (30) and is returned via the Cold High Pressure Separator No. 2 (stream 36) to the final stage of compression of the make-up hydrogen compressor.

After the final stage of compression, the high-pressure make-up hydrogen is sent to the first reaction stage, stream 39 and to the hot separator.

Reference is now made to Figure 2, which discloses preferred embodiments of the invention. Not included in the figures are various pieces of auxiliary equipment such as heat exchangers, condensers, pumps and compressors, which are not essential to the invention.

In Figure 2, two downflow reactor vessels, 5 and 15 are depicted. Between them is heat exchanger 20. Each vessel contains at least one reaction zone.

The first-stage reaction, hydrocracking, occurs in vessel 5. The second-stage reaction, hydrotreating, occurs in vessel 15. Each vessel is depicted as having three catalyst beds. The first reaction vessel 5 is for cracking a first refinery stream 1. The second reaction vessel 15 is for removing nitrogen-containing and aromatic molecules from a second refinery stream 17.

A suitable volumetric ratio of the catalyst volume in the first reaction vessel to the catalyst volume in the second reaction vessel encompasses a broad range, depending on the ratio of the first refinery stream to the second refinery stream. Typical ratios generally lie between 20: 1 and 1: 20. A preferred

volumetric range is between 10: 1 and 1: 10. A more preferred volumetric ratio is between 5: 1 and 1: 2.

In the integrated process, a first refinery stream 1 is combined with a hydrogen-rich gaseous stream 4 to form a first feedstock 12. The stream exiting furnace 30, stream 13, is passed to first reaction vessel 5.

Hydrogen-rich gaseous stream 4 contains greater than 50% hydrogen, the remainder being varying amounts of light gases, including hydrocarbon gases.

The hydrogen-rich gaseous stream 4 shown in the drawing is a blend of make-up hydrogen 3 and recycle hydrogen 26. While the use of a recycle hydrogen stream is generally preferred for economic reasons, it is not required. First feedstock 1 may be heated in one or more exchangers, such as exchanger 10, emerging as stream 12, and in one or more heaters, such as heater 30, (emerging as stream 13) before being introduced to first reaction vessel 5 in which hydrocracking preferably occurs. Hydrotreating preferably occurs in vessel 15.

Hydrogen may also be added as a quench stream through lines 6 and 7, and 9 and 11, (which also come from hydrogen stream 4) for cooling the first and the second reaction stages, respectively. The effluent from the hydrocracking stage, stream 14 is cooled in heat exchanger 20 by stream 2. Stream 2 boils in the diesel range and may be light cycle oil, light gas oil, atmospheric gas oil, or a mixture of the three. Stream 2 emerges from exchanger 20 as stream 16 and combines stream 14 as it emerges from exchanger 20 to form combined feedstock 17. Hydrogen in stream 8 joins the combined feedstock 17 before it enters vessel 15. Stream 17 enters vessel 15 for hydrotreatment, and exits as stream 18.

The second reaction stage, found in vessel 15, contains at least one bed of catalyst, such as hydrotreating catalyst, which is maintained at conditions

sufficient for converting at least a portion of the nitrogen compounds and at least a portion of the aromatic compounds in the second feedstock.

Hydrogen stream 4 may be recycle hydrogen from compressor 40.

Alternately, stream 4 may be a fresh hydrogen stream, originating from hydrogen sources external to the present process.

Stream 18, the second reaction zone effluent, contains thermal energy which may be recovered by heat exchange, such as in heat exchanger 10. Second stage effluent 18 emerges from exchanger 10 as stream 19 and is passed to hot high pressure separator 25. The liquid effluent of the hot high pressure separator 25, stream 22 is passed to fractionation. The overhead gaseous stream from separator 25, stream 21, is combined with water from stream 23 for cooling. The now cooled stream 21 enters the cold high pressure separator 35. Light liquids are passed to fractionation in stream 27 (which joins stream 22) and sour water is removed through stream 34. Gaseous overhead stream 24 passes to amine absorber 45, for the removal of hydrogen sulfide gas. Purified hydrogen then passes, through stream 26, to the compressor 40, where it is recompressed and passed as recycle to one or more of the reaction vessels and as a quench stream for cooling the reaction zones. Such uses of hydrogen are well known in the art.

An example separation scheme for a hydroconversion process is taught in U. S. Patent No. 5,082, 551, the entire disclosure of which is incorporated herein by reference for all purposes.

The absorber 45 may include means for contacting a gaseous component of the reaction effluent 19 with a solution, such as an alkaline aqueous solution, for removing contaminants such as hydrogen sulfide and ammonia which may be generated in the reaction stages and may be present in reaction effluent 19. The hydrogen-rich gaseous stream 24 is preferably recovered from the

separation zone at a temperature in the range of 100°F-300°F or 100°F-200°F.

Liquid stream 22 is further separated in fractionator 50 to produce overhead gasoline stream 28, naphtha stream 29, kerosene fraction 31, diesel stream 32 and fractionator bottoms 33. A preferred distillate product has a boiling point range within the temperature range 250°F-700°F. A gasoline or naphtha fraction having a boiling point range within the temperature range C5-400°F is also desirable.

In Figure 3, two downflow reactor vessels, 5 and 15, are depicted. The first stage reaction, hydrocracking, occurs in vessel 5. The second stage, hydrotreating, occurs in vessel 15. Each vessel contains at least one reaction zone. Each vessel is depicted as having three catalyst beds. The first reaction vessel 5 is for cracking a first refinery stream 1. The second reaction vessel 15 is for removing nitrogen-containing and aromatic molecules from a second refinery stream 34. A suitable volumetric ratio of the catalyst volume in the first reaction vessel to the catalyst volume in the second reaction vessel encompasses a broad range, depending on the ratio of the first refinery stream to the second refinery stream. Typical ratios generally lie between 20: 1 and 1: 20. A preferred volumetric range is between 10: 1 and 1: 10. A more preferred volumetric ratio is between 5: 1 and 1: 2.

In the integrated process, a first refinery stream 1 is combined with a hydrogen-rich gaseous stream 4 to form a first feedstock 12 which is passed to first reaction vessel 5. Hydrogen-rich gaseous stream 4 contains greater than 50% hydrogen, the remainder being varying amounts of light gases, including hydrocarbon gases. The hydrogen-rich gaseous stream 4 shown in the drawing is a blend of make-up hydrogen 3 and recycle hydrogen 26.

While the use of a recycle hydrogen stream is generally preferred for economic reasons, it is not required. First feedstock 1 may be heated in one

or more exchangers or in one or more heaters before being combined with hydrogen-rich stream 4 to create stream 12. Stream 12 is then introduced to first reaction vessel 5, where the first stage, in which hydrocracking preferably occurs, is located. The second stage is located in vessel 15, where hydrotreating preferably occurs.

The effluent from the first stage, stream 14 is heated in heat exchanger 20.

Stream 14 emerges from exchanger 20 as stream 17 and passes to the "hot/hot"high pressure separator 55. The liquid stream 36 emerges from the "hot/hot"high pressure separator 55 and proceeds to fractionator 60. Stream 37 represents products streams for gasoline and naphtha, stream 38 represents distillate recycled back to the inlet of hydrotreater 15, and stream 39 represents clean bottoms material.

The gaseous stream 34 emerges from the"hot/hot"high pressure separator 55, and joins with stream 2, which boils in the diesel range and may be light cycle oil, light gas oil, atmospheric gas oil, or a mixture of the three. It further combines with hydrogen-rich stream 4 prior to entering vessel 15 for hydrotreatment, and exits as stream 18.

The second reaction zone, found in vessel 15, contains at least one bed of catalyst, such as hydrotreating catalyst, which is maintained at conditions sufficient for converting at least a portion of the nitrogen compounds and at least a portion of the aromatic compounds in the second feedstock.

Hydrogen stream 4 may be recycle hydrogen from compressor 40.

Alternately, stream 4 may be a fresh hydrogen stream, originating from hydrogen sources external to the present process.

Stream 18, the second stage effluent, contains thermal energy which may be recovered by heat exchange, such as in heat exchanger 10. Second stage

effluent 18 emerges from exchanger 10 as stream 19 and is passed to hot high pressure separator 25. The liquid effluent of the hot high pressure separator 25, stream 22 is passed to fractionation. The overhead gaseous stream from separator 25, stream 21, is combined with water from stream 23 for cooling. The now cooled stream 21 enters the cold high pressure separator 35. Light liquids are passed to fractionation in stream 27 (which joins stream 22) and sour water is removed through stream 41. Gaseous overhead stream 24 passes to amine absorber 45, for the removal of hydrogen sulfide gas. Purified hydrogen then passes, through stream 26, to the compressor 40, where it is recompressed and passed as recycle to one or more of the reaction vessels and as a quench stream for cooling the reaction zones. Such uses of hydrogen are well known in the art.

The absorber 45 may include means for contacting a gaseous component of the reaction effluent 19 (stream 24) with a solution, such as an alkaline aqueous solution, for removing contaminants such as hydrogen sulfide and ammonia which may be generated in the reaction zones and may be present in reaction effluent 19. The hydrogen-rich gaseous stream 24 is preferably recovered from the separation zone at a temperature in the range of 100°F-300°F or 100°F-200°F.

Liquid stream 22 is further separated in fractionator 50 to produce overhead gasoline stream 28, naphtha stream 29, kerosene fraction 31, diesel stream 32 and fractionator bottoms 33. A preferred distillate product has a boiling point range within the temperature range 250°F-700°F. A gasoline or naphtha fraction having a boiling point range within the temperature range C5-400°F is also desirable.

Feeds A wide variety of hydrocarbon feeds may be used in first embodiment of this invention. Typical feedstocks include any heavy or synthetic oil fraction or process stream having a boiling point above 392°F (200°C). Such feedstocks include vacuum gas oils, heavy atmospheric gas oil, delayed coker gas oil, visbreaker gas oil demetallized oils, vacuum residua, atmospheric residua, deasphalted oil, Fischer-Tropsch streams, and FCC streams.

In the case of the second embodiment one suitable first refinery feed stream is a VGO having a boiling point range starting at a temperature above 500°F (260°C), usually within the temperature range of 500°F-1100°F (260°C-593°C). A refinery stream wherein 75 vol% of the refinery stream boils within the temperature range 650°F-1050°F is an example feedstock for the first reaction zone. The first refinery stream may contain nitrogen, usually present as organonitrogen compounds. VGO feed streams for the first reaction zone contain less than about 200 ppm nitrogen and less than 0.25 wt. % sulfur, though feeds with higher levels of nitrogen and sulfur, including those containing up to 0.5 wt. % and higher nitrogen and up to 5 wt. % sulfur and higher may be treated in the present process. The first refinery stream is also preferably a low asphaltene stream. Suitable first refinery streams contain less than about 500 ppm asphaltenes, preferably less than about 200 ppm asphaltenes, and more preferably less than about 100 ppm asphaltenes. Example streams include light gas oil, heavy gas oil, straight run gas oil, deasphalted oil, and the like. The first refinery stream may have been processed, e. g. , by hydrotreating, prior to the present process to reduce or substantially eliminate its heteroatom content. The first refinery stream may comprise recycle components.

The hydrocracking reaction step removes nitrogen and sulfur from the first refinery feed stream in the first hydrocracking reaction zone and effects a

boiling range conversion, so that the liquid portion of the first hydrocracking reaction zone effluent has a normal boiling range below the normal boiling point range of the first refinery feedstock. By"normal"is meant a boiling point or boiling range based on a distillation at one atmosphere pressure, such as that determined in a D1160 distillation. Unless otherwise specified, all distillation temperatures listed herein refer to normal boiling point and normal boiling range temperatures. The process in the first hydrocracking reaction zone may be controlled to a certain cracking conversion or to a desired product sulfur level or nitrogen level or both. Conversion is generally related to a reference temperature, such as, for example, the minimum boiling point temperature of the hydrocracker feedstock. The extent of conversion relates to the percentage of feed boiling above the reference temperature which is converted to products boiling below the reference temperature.

The hydrocracking reaction zone effluent includes normally liquid phase <BR> <BR> components, e. g. , reaction products and unreacted components of the first<BR> refinery stream, and normally gaseous phase components, e. g. , gaseous reaction products and unreacted hydrogen. In the process, the hydrocracking reaction zone is maintained at conditions sufficient to effect a boiling range conversion of the first refinery stream of at least about 25%, based on a 650°F reference temperature. Thus, at least 25% by volume of the components in the first refinery stream which boil above about 650°F are converted in the first hydrocracking reaction zone to components which boil below about 650°F. Operating at conversion levels as high as 100% is also within the scope of the invention. Example boiling range conversions are in the range of from about 30% to 90% or of from about 40% to 80%. The hydrocracking reaction zone effluent is further decreased in nitrogen and sulfur content, with at least about 50% of the nitrogen containing molecules in the first refinery stream being converted in the hydrocracking reaction zone. Preferably, the normally liquid products present in the hydrocracking reaction zone effluent contain less than about 1000 ppm sulfur and less than about 200 ppm

nitrogen, more preferably less than about 250 ppm sulfur and about 100 ppm nitrogen.

Catalyst Each hydroprocessing zone in either embodiment may contain only one catalyst, or several catalysts in combination. In the preferred embodiment, hydrocracking is occurring in the first zone and hydrotreating is occurring in the second zone.

The hydrocracking catalyst generally comprises a cracking component, a hydrogenation component, and a binder. Such catalysts are well known in the art. The cracking component may include an amorphous silica/alumina phase and/or a zeolite, such as a Y-type or USY zeolite. Catalysts having high cracking activity often employ REX, REY and USY zeolites. The binder is generally silica or alumina. The hydrogenation component will be a Group Vi, Group Vil, or Group VIII metal or oxides or sulfides thereof, preferably one or more of iron, chromium, molybdenum, tungsten, cobalt, or nickel, or the sulfides or oxides thereof. If present in the catalyst, these hydrogenation components generally make up from about 5% to about 40% by weight of the catalyst. Alternatively, noble metals, especially platinum and/or palladium, may be present as the hydrogenation component, either alone or in combination with the base metal hydrogenation components: iron, chromium molybdenum, tungsten, cobalt, or nickel. If present, the platinum group metals will generally make up from about 0. 1 % to about 2% by weight of the catalyst.

Hydrotreating catalyst usually is designed to remove sulfur and nitrogen and provide a degree of aromatic saturation. It will typically be a composite of a Group Vi metal or compound thereof, and a Group VIII metal or compound thereof supported on a porous refractory base such as alumina. Examples of

hydrotreating catalysts are alumina supported cobalt-molybdenum, nickel sulfide, nickel-tungsten, cobalt-tungsten and nickel-molybdenum. Typically, such hydrotreating catalysts are presulfided.

Catalyst selection is dictated by process needs and product specifications. In particular, a noble catalyst may be used in the second stage when there is a low amount of H2S present. A low acidity catalyst may be used in the bottom of the second stage hydrocracker in order to avoid overcracking distillate to gas and naphtha.

Conditions-Hvdrocracking Stage Reaction conditions in the hydrocracking reaction zone include a reaction temperature between about 250°C and about 500°C (482°F-932°F), pressures from about 3.5 MPa to about 24.2 MPa (500-3,500 psi), and a feed rate (vol oil/vol cat h) from about 0.1 to about 20 hurl. Hydrogen circulation rates are generally 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). Preferred reaction temperatures range from about 340°C to about 455°C (644°F-851 °F).

Preferred total reaction pressures range from about 7.0 MPa to about 20.7 MPa (1,000-3, 000 psi). With the preferred catalyst system, it has been found that preferred process conditions include contacting a petroleum feedstock with hydrogen under hydrocracking conditions comprising a pressure of about 13.8 MPa to about 20.7 MPa (2,000-3000 psi), a gas to oil ratio between about 379-909 std liters H2/kg oil (2,500-6, 000 scf/bbl), a LHSV of between about 0.5-1. 5 hr', and a temperature in the range of 360°C to 427°C (680°F-800°F).

Feed and Effluent Characteristics-Hvdrotreater Stage The second refinery feedstream has a boiling point range generally lower than the first refinery feedstream. Indeed, it is a feature of the present process that a substantial portion of the second refinery feedstream has a normal boiling point in the middle distillate range, so that cracking to achieve boiling point reduction is not necessary. Thus, at least about 75 vol% of a. suitable second refinery stream has a normal boiling point temperature of less than about 1000°F. A refinery stream with at least about 75% v/v of its components having a normal boiling point temperature within the range of 250°F-700°F is an example of a preferred second refinery feedstream.

The process of this invention is particularly suited for treating middle distillate streams which are not suitable for high quality fuels. For example, the process is suitable for treating a second refinery stream which contains high amounts of nitrogen and/or high amounts of aromatics, including streams which contain up to 90% aromatics and higher. Example second refinery feedstreams which are suitable for treating in the present process include straight run vacuum gas oils, including straight run diesel fractions, from crude distillation, atmospheric tower bottoms, or synthetic cracked materials such as coker gas oil, light cycle oil or heavy cycle oil.

After the first refinery feedstream is treated in the hydrocracking stage, the first hydrocracking reaction zone effluent is combined with the second feedstock, and the combination passed together with hydrogen over the catalyst in the hydrotreating stage. Since the hydrocracked effluent is already relatively free of the contaminants to be removed by hydrotreating, the hydrocracker effluent passes largely unchanged through the hydrotreater.

And unreacted or incompletely reacted feed remaining in the effluent from the hydrotreater is effectively isolated from the hydrocracker zone to prevent contamination of the catalyst contained therein.

However, the presence of the hydrocracker effluent plays an important and unexpected economic benefit in the integrated process. Leaving the hydrocracker, the effluent carries with it substantial thermal energy. This energy may be used to heat the second reactor feedstream in a heat exchanger before the second feedstream enters the hydrotreater. This permits adding a cooler second feed stream to the integrated system than would otherwise be required, and saves on furnace capacity and heating costs.

As the second feedstock passes through the hydrotreater, the temperature again tends to increase due to exothermic reaction heating in the second zone. The hydrocracker effluent in the second feedstock serves as a heat sink, which moderates the temperature increase through the hydrotreater.

The heat energy contained in the liquid reaction products leaving the hydrotreater is further available for exchange with other streams requiring heating. Generally, the outlet temperature of the hydrotreater will be higher than the outlet temperature of the hydrocracker. In this case, the instant invention will afford the added heat transfer advantage of elevating the temperature of the first hydrocracker feed for more effective heat transfer.

The effluent from the hydrocracker also carries the unreacted hydrogen for use in the first-stage hydrotreater without any heating or pumping requirement to increase pressure.

Conditions-Hydrotreater Stage The hydrotreater is maintained at conditions sufficient to remove at least a portion of the nitrogen compounds and at least a portion of the aromatic compounds from the second refinery stream. The hydrotreater will operate at a lower temperature than the hydrocracker, except for possible temperature gradients resulting from exothermic heating within the reaction zones, moderated by the addition of relatively cooler streams into the one or more

reaction zones. Feed rate of the reactant liquid stream through the reaction zones will be in the region of 0.1 to 20 hrl liquid hourly space velocity. Feed rate through the hydrotreater will be increased relative to the feed rate through the hydrocracker by the amount of liquid feed in the second refinery feedstream and will also be in the region of 0.1 to 20 hrl liquid hourly space velocity. These process conditions selected for the first reaction zone may be considered to be more severe than those conditions normally selected for a hydrotreating process.

At any rate, hydrotreating conditions typically used in the hydrotreater will include a reaction temperature between about 250°C and about 500°C (482°F-932°F), pressures from about 3.5 MPa to about 24.2 MPa (500-3,500 psi), and a feed rate (vol oil/vol cat h) from about 0.1 to about 20 hurl. Hydrogen circulation rates are generally 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). Preferred reaction temperatures range from about 340°C to about 455°C (644°F-851 °F). Preferred total reaction pressures range from about 7.0 MPa to about 20.7 MPa (1,000-3, 000 psi). With the preferred catalyst system, it has been found that preferred process conditions include contacting a petroleum feedstock with hydrogen in the presence of the layered catalyst system under hydrocracking conditions comprising a pressure of about 16.0 MPa (2,300 psi), a gas to oil ratio at from about 379-909 std liters H2/kg oil (2,500 scf/bbl to about 6,000 scf/bbl), a LHSV of between about 0.5-1. 5 hic', and a temperature in the range of 360°C to 427°C (680°F-800°F). Under these conditions, at least about 50% of the aromatics are removed from the second refinery stream in the hydrotreater. It is expected that as much as 30-70% or more of the nitrogen present in the second refinery stream would also be removed in the process. However, cracking conversion in the hydrotreater would be generally low, typically less than 20%. Standard methods for determining the aromatic content and the nitrogen content of refinery streams are available. These include ASTM

D5291 for determining the nitrogen content of a stream containing more than about 1500 ppm nitrogen. ASTM D5762 may be used for determining the nitrogen content of a stream containing less than about 1500 ppm nitrogen.

ASTM D2007 may be used to determine the aromatic content of a refinery stream.

Products The embodiments of this invention are especially useful in the production of middle distillate fractions boiling in the range of about 250-700°F (121-371°C).

A middle distillate fraction is defined as having an approximate boiling range from about 250 to 700°F. At least 75 vol%, preferably 85 vol%, of the components of the middle distillate have a normal boiling point of greater than 250°F. At least about 75 vol%, preferably 85 vol%, of the components of the middle distillate have a normal boiling point of less than 700°F. The term "middle distillate"includes the diesel, jet fuel and kerosene boiling range fractions. The kerosene or jet fuel boiling point range refers to the range between 280 and 525°F (38-274°C). The term"diesel boiling range"refers to hydrocarbons boiling in the range from 250 to 700°F (121-371 °C).

Gasoline or naphtha may also be produced in the process of this invention.

Gasoline or naphtha normally boils in the range below 400°F (204°C), or C5-.

Boiling ranges of various product fractions recovered in any particular refinery will vary with such factors as the characteristics of the crude oil source, local refinery markets and product prices.

Heavy hydrotreated gas oil, another product of this invention, usually boils in the range from 550 to 700°F.

Example These are the conditions and results obtained using the process depicted in Figure 1: Stage 1 Hydrogen Stage 2 Stripper/Hydrotreater Catalyst Base metal Base metal Base metal or Hydrogenation Noble Metal Component LHSV, ho~1 0. 3-3.5 0.3-2. 0 0.5-7. 0 Operating 300-440 250-400 250-440 Temperature, °C Reactor Inlet 100-230 90-220 80-170 Pressure, kg/cm2g Gas/Oil Ratio 160-1500 160-1500 160-850 Nm3/m3 Conversion, % 20-70 25-75 Kerosene Smoke 13-25 20-40 Point, mm Diesel Cetane 30-55 50-75 Number Generally, cetane uplift is 20 to 45 and improvement in kerosene smoke point is 7-27 mm.