Patent Publication Number: US-2018044599-A1

Title: Process and apparatus for removal of heavy polynuclear aromatics in a hydrocracking process

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
     This application claims priority from Provisional Application No. 62/373,189 filed Aug. 10, 2016, the contents of which cited application are hereby incorporated by reference in its entirety. 
    
    
     FIELD 
     The technical field generally relates to processes and apparatuses for hydrocracking of hydrocarbon streams. More particularly, the technical field relates to an improved process and apparatus for removing heavy polynuclear aromatics from a hydrocracking process. 
     BACKGROUND 
     Hydroprocessing can include processes which convert hydrocarbons in the presence of hydroprocessing catalyst and hydrogen to more valuable products. Hydrocracking is a hydroprocessing process in which hydrocarbons crack in the presence of hydrogen and hydrocracking catalyst to lower molecular weight hydrocarbons. Depending on the desired output, a hydrocracking unit may contain one or more fixed beds of the same or different catalyst. Hydrotreating is a process in which hydrogen is contacted with hydrocarbon in the presence of hydrotreating catalysts which are primarily active for the removal of heteroatoms, such as sulfur, nitrogen and metals from the hydrocarbon feedstock. In hydrotreating, hydrocarbons with double and triple bonds may be saturated. Aromatics may also be saturated. Some hydrotreating processes are specifically designed to saturate aromatics. 
     Often, heavy polynuclear aromatic (may be abbreviated as “HPNA”) compounds may be a secondary product of a hydrocracking process particularly of high conversion hydrocracking units. Recycling unconverted oil to increase yields of distillate product can result in an accumulation of HPNA compounds in the unconverted oil. Accumulated HPNA compounds in the recycle oil may deposit on the catalyst as coke, which may degrade catalyst performance and result in shorter catalyst cycle length. In addition HPNA can deposit on equipment in the cooler sections of the process. Production of undesired HPNA compounds can be more pronounced for hydrocracking units processing heavier feeds. Thus, it would be desirable to remove the HPNA compounds from the unconverted oil so as to minimize the catalyst deactivation. 
     One option is to lower conversion by bleeding a portion of the unconverted oil to remove accumulated HPNA compounds. Unfortunately, this is often undesirable due to economic and logistic considerations because of yield loss and lack of market for the unconverted oil. 
     Thus, there is a desire to provide an improved process that provides improved performance and prevents HPNA compounds accumulation without the shortcomings discussed above. Furthermore, other desirable features and characteristics of the present invention will become apparent from the subsequent detailed description and the appended claims, taken in conjunction with the accompanying Figures and this background. 
     BRIEF SUMMARY 
     Various embodiments contemplated herein relate to processes and apparatuses for removing HPNA&#39;s from a hydrocracking process. The exemplary embodiments taught herein provide an improved process and apparatus for removing HPNA from a two-stage or a single-stage hydrocracking process. 
     In accordance with an exemplary embodiment, a process is provided for of removing HPNA compounds from a hydrocracked stream comprising passing at least a portion of the hydrocracked stream to a fractionation column to provide a plurality of fractionator product streams and a fractionator bottoms stream comprising unconverted hydrocarbons. A first stream and a second stream are taken from the fractionator bottoms stream. The first stream is passed through a HPNA adsorption zone to obtain a treated bottoms stream having a reduced concentration of HPNA compounds. The second stream is bypassed around the HPNA adsorption zone. Finally, the treated bottoms stream and the bypassed second stream are hydrocracked. 
     In accordance with another exemplary embodiment, a process is provided for upgrading a hydrocarbon stream comprising passing the hydrocarbon feedstream to a first hydrocracking reactor, the first hydrocracking reactor containing at least one bed of a first hydrocracking catalyst, wherein the hydrocarbon feedstream is contacted with the first hydrocracking catalyst under first hydrocracking conditions in the presence of hydrogen to produce a first hydrocracked effluent stream. At least a portion of the first hydrocracked effluent stream is passed to a fractionation column to provide a plurality of fractionator product streams and a fractionator bottoms stream comprising unconverted hydrocarbons. The fractionator bottoms stream is split to provide a first stream and a second stream. The first stream is passed through a HPNA adsorption zone to obtain a treated bottoms stream having a reduced concentration of HPNA compounds. The second stream is bypassed around the HPNA adsorption zone. The treated bottoms stream and the bypassed second stream are passed to a second hydrocracking reactor, the second hydrocracking reactor containing at least one bed of a second hydrocracking catalyst, wherein the treated bottoms stream and the bypassed second stream are contacted with a second hydrocracking catalyst under second hydrocracking conditions in the presence of hydrogen to provide a second hydrocracked effluent stream. 
     In accordance with yet another exemplary embodiment, an apparatus is provided for removing HPNA compounds from a hydrocracked stream comprising a fractionation column in communication with a hydrocracked effluent line to provide a plurality of fractionator product streams and a fractionator bottoms stream in a fractionator bottoms line. A first fractionator bottoms line is fluidly connected to the fractionator bottoms line. A second fractionator bottoms line is fluidly connected to the fractionator bottoms line. A HPNA adsorption zone is in downstream communication with the first fractionator bottoms line to provide a treated bottoms stream in a treated bottoms line having a reduced concentration of HPNA compounds. A hydrocracking reactor in communication with the treated bottoms line and the second fractionator bottoms line, the second fractionator bottoms line bypassing the HPNA adsorption zone. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a schematic drawing of a two-stage hydrocracking unit. 
         FIG. 2  is a schematic drawing of a single-stage hydrocracking unit. 
     
    
    
     DEFINITIONS 
     The term “communication” means that material flow is operatively permitted between enumerated components. 
     The term “downstream communication” means that at least a portion of material flowing to the subject in downstream communication may operatively flow from the object with which it communicates. 
     The term “upstream communication” means that at least a portion of the material flowing from the subject in upstream communication may operatively flow to the object with which it communicates. 
     The term “direct communication” means that flow from the upstream component enters the downstream component without undergoing a compositional change due to physical fractionation or chemical conversion. 
     The term “column” means a distillation column or columns for separating one or more components of different volatilities. Unless otherwise indicated, each column includes a condenser on an overhead of the column to condense and reflux a portion of an overhead stream back to the top of the column and a reboiler at a bottom of the column to vaporize and send a portion of a bottoms stream back to the bottom of the column. Absorber and scrubbing columns do not include a condenser on an overhead of the column to condense and reflux a portion of an overhead stream back to the top of the column and a reboiler at a bottom of the column to vaporize and send a portion of a bottoms stream back to the bottom of the column. Feeds to the columns may be preheated. The overhead pressure is the pressure of the overhead vapor at the vapor outlet of the column. The bottom temperature is the liquid bottom outlet temperature. Overhead lines and bottoms lines refer to the net lines from the column downstream of any reflux or reboil to the column unless otherwise indicated. Stripping columns omit a reboiler at a bottom of the column and instead provide heating requirements and separation impetus from a fluidized inert vaporous media such as steam. 
     As used herein, the term “True Boiling Point” (TBP) means a test method for determining the boiling point of a material which corresponds to ASTM D-2892 for the production of a liquefied gas, distillate fractions, and residuum of standardized quality on which analytical data can be obtained, and the determination of yields of the above fractions by both mass and volume from which a graph of temperature versus mass % distilled is produced using fifteen theoretical plates in a column with a 5:1 reflux ratio. 
     As used herein, the term “T5” or “T95” means the temperature at which 5 volume percent or 95 volume percent, as the case may be, respectively, of the sample boils using ASTM D-86. 
     As used herein, the term “diesel boiling range” means hydrocarbons boiling in the range of between about 132° C. (270° F.) and the diesel cut point between about 343° C. (650° F.) and about 399° C. (750° F.) using the TBP distillation method. 
     As used herein, the term “separator” means a vessel which has an inlet and at least an overhead vapor outlet and a bottoms liquid outlet and may also have an aqueous stream outlet from a boot. A flash drum is a type of separator which may be in downstream communication with a separator which latter may be operated at higher pressure. 
     As used herein, the term “zone” can refer to an area including one or more equipment items and/or one or more sub-zones. Equipment items can include one or more reactors or reactor vessels, heaters, exchangers, pipes, pumps, compressors, controllers and columns. Additionally, an equipment item, such as a reactor, dryer, or vessel, can further include one or more zones or sub-zones. 
     As used herein, the term “HPNA” typically refer to compounds with six or more aromatic rings and often refer to compounds with eleven or more aromatic rings and typically produced in a hydrocracking reaction zone. 
     DETAILED DESCRIPTION 
     The following detailed description is merely exemplary in nature and is not intended to limit the various embodiments or the application and uses thereof. Furthermore, there is no intention to be bound by any theory presented in the preceding background or the following detailed description. The Figures have been simplified by the deletion of a large number of apparatuses customarily employed in a process of this nature, such as vessel internals, temperature and pressure controls systems, flow control valves, recycle pumps, etc. which are not specifically required to illustrate the performance of the invention. Furthermore, the illustration of the process of this invention in the embodiment of a specific drawing is not intended to limit the invention to specific embodiments set out herein. 
     We have found that passing only a portion of the fractionator bottoms stream comprising unconverted oil relieves accumulation of HPNA in the recycle oil feed to the hydrocracking unit. 
     The subject apparatus and process passes only a portion of recycle oil through a HPNA adsorption zone while another portion of the recycle oil bypasses the HPNA adsorption zone and subsequently both the fractions are hydrocracked. 
     The apparatus and process  10  for hydrocracking a hydrocarbon stream comprise a first stage hydrocracking unit  12 , a fractionation section  14  and a second stage hydrocracking unit  150 . A hydrocarbonaceous stream in hydrocarbon line  18  and a first stage hydrogen stream in a first stage hydrogen line  22  are fed to the first stage hydrocracking unit  12 . The first stage hydrocracking unit may include a hydrotreating reactor  30  and a first hydrocracking reactor  40 . The second stage hydrocracking unit  150  may include a second hydrocracking reactor  170 . 
     In one aspect, the process and apparatus described herein are particularly useful for hydrocracking a hydrocarbon feed stream comprising a hydrocarbonaceous feedstock. Illustrative hydrocarbonaceous feed stocks include hydrocarbon streams having initial boiling points (IBP) above about 288° C. (550° F.), such as atmospheric gas oils, vacuum gas oil (VGO) having T5 and T95 between about 315° C. (600° F.) and about 600° C. (1100° F.), deasphalted oil, coker distillates, straight run distillates, pyrolysis-derived oils, high boiling synthetic oils, cycle oils, clarified slurry oils, deasphalted oil, shale oil, hydrocracked feeds, catalytic cracker distillates, atmospheric residue having an IBP at or above about 343° C. (650° F.) and vacuum residue having an IBP above about 510° C. (950° F.). 
     A hydrotreating hydrogen stream in a hydrotreating hydrogen line  24  may be split off from the first stage hydrogen line  22 . The first hydrotreating hydrogen stream may join the hydrocarbonaceous stream in feed line  18  to provide a first hydrocarbon feed stream in a first hydrocarbon feed line  26 . The first hydrocarbon feed stream in the first hydrocarbon feed line  26  may be heated by heat exchange with a first hydrocracked effluent stream in line  48  and in a fired heater. The heated first hydrocarbon feed stream in line  28  may be fed to a hydrotreating reactor  30 . 
     Hydrotreating is a process wherein hydrogen is contacted with hydrocarbon in the presence of hydrotreating catalysts which are primarily active for the removal of heteroatoms, such as sulfur, nitrogen and metals from the hydrocarbon feedstock. In hydrotreating, hydrocarbons with double and triple bonds may be saturated. Aromatics may also be saturated. Some hydrotreating processes are specifically designed to saturate aromatics. 
     The hydrotreating reactor  30  may comprise a guard bed of hydrotreating catalyst followed by one or more beds of higher quality hydrotreating catalyst. The guard bed filters particulates and picks up contaminants in the hydrocarbon feed stream such as metals like nickel, vanadium, silicon and arsenic which deactivate the catalyst. The guard bed may comprise material similar to the hydrotreating catalyst. Supplemental hydrogen in a first hydrotreating supplemental hydrogen line  31  may be added at an interstage location between catalyst beds in the hydrotreating reactor  30 . 
     Suitable hydrotreating catalysts for use in the hydrotreating reactor are any known conventional hydrotreating catalysts and include those which are comprised of at least one Group VIII metal, preferably iron, cobalt and nickel, more preferably cobalt and/or nickel and at least one Group VI metal, preferably molybdenum and tungsten, on a high surface area support material, preferably alumina. Other suitable hydrotreating catalysts include zeolitic catalysts. In the high sulfur and nitrogen environment of the hydrotreating reactor  30 , noble metal catalysts would be discouraged. More than one type of hydrotreating catalyst may be used in the hydrotreating reactor  30 . The Group VIII metal is typically present in an amount ranging from about 2 to about 20 wt %, preferably from about 4 to about 12 wt %. The Group VI metal will typically be present in an amount ranging from about 1 to about 25 wt %, preferably from about 2 to about 25 wt %. 
     Preferred reaction conditions in the hydrotreating reactor  30  include a temperature from about 290° C. (550° F.) to about 455° C. (850° F.), suitably 316° C. (600° F.) to about 427° C. (800° F.) and preferably 343° C. (650° F.) to about 399° C. (750° F.), a pressure from about 2.1 MPa (gauge) (300 psig), preferably 4.1 MPa (gauge) (600 psig) to about 20.6 MPa (gauge) (3000 psig), suitably 12.4 MPa (gauge) (1800 psig), preferably 6.9 MPa (gauge) (1000 psig), a liquid hourly space velocity of the fresh hydrocarbonaceous feedstock from about 0.1 hr −1 , suitably 0.5 hr −1 , to about 10 hr −1 , preferably from about 1.5 to about 8.5 hr −1 , and a hydrogen rate of about 168 Nm 3 /m 3  (1,000 scf/bbl), to about 1,011 Nm 3 /m 3  oil (6,000 scf/bbl), preferably about 168 Nm 3 /m 3  oil (1,000 scf/bbl) to about 674 Nm 3 /m 3  oil (4,000 scf/bbl), with a hydrotreating catalyst or a combination of hydrotreating catalysts. 
     The first hydrocarbon feed stream in the first hydrocarbon feed line  28  is hydrotreated over the hydrotreating catalyst in the hydrotreating reactor  30  to provide a hydrotreated hydrocarbon feed stream that exits the hydrotreating reactor  30  in a hydrotreating effluent line  32  which can be taken as a first hydrocracking feed stream. The hydrogen gas laden with ammonia and hydrogen sulfide may be removed from the first hydrocracking feed stream in a separator, but the first hydrocracking feed stream is typically fed directly to the hydrocracking reactor  40  without separation. The first hydrocracking feed stream may be mixed with a first hydrocracking hydrogen stream in a first hydrocracking hydrogen line  33  from the first stage hydrogen line  22  and is fed through a first inlet  32   i  to the first hydrocracking reactor  40  to be hydrocracked. 
     Hydrocracking is to a process in which hydrocarbons crack in the presence of hydrogen to lower molecular weight hydrocarbons. The first hydrocracking reactor  40  may be a fixed bed reactor that comprises one or more vessels, single or multiple catalyst beds  42  in each vessel, and various combinations of hydrotreating catalyst, hydroisomerization catalyst and/or hydrocracking catalyst in one or more vessels. It is contemplated that the first hydrocracking reactor  40  be operated in a continuous liquid phase in which the volume of the liquid hydrocarbon feed is greater than the volume of the hydrogen gas. The first hydrocracking reactor  40  may also be operated in a conventional continuous gas phase, a moving bed or a fluidized bed hydroprocessing reactor. 
     The hydrotreated first hydrocracking feed stream is hydrocracked over a first hydrocracking catalyst in first hydrocracking catalyst beds  42  in the presence of a first hydrocracking hydrogen stream from a first hydrocracking hydrogen line  33  to provide a first hydrocracked effluent stream in line  48 . Subsequent catalyst beds  42  in the hydrocracking reactor may comprise hydrocracking catalyst over which additional hydrocracking occurs to the hydrocracked stream. Hydrogen manifold  44  may deliver supplemental hydrogen streams to one, some or each of the catalyst beds  42 . In an aspect, the supplemental hydrogen is added to each of the catalyst beds  42  at an interstage location between adjacent beds, so supplemental hydrogen is mixed with hydroprocessed effluent exiting from the upstream catalyst bed  42  before entering the downstream catalyst bed  42 . 
     The first hydrocracking reactor  40  may provide a total conversion of at least about 20 vol % and typically greater than about 60 vol % of the first hydrocracking feed stream in the hydrotreating effluent line  32  to products boiling below the diesel cut point. The first hydrocracking reactor  40  may operate at partial conversion of more than about 30 vol % or full conversion of at least about 90 vol % of the feed based on total conversion. The first hydrocracking reactor  40  may be operated at mild hydrocracking conditions which will provide about 20 to about 60 vol %, preferably about 20 to about 50 vol %, total conversion of the hydrocarbon feed stream to product boiling below the diesel cut point. 
     The first hydrocracking reactor  40  comprises a plurality of catalyst beds  42 . If the hydrocracking unit  12  does not include a hydrotreating reactor  30 , the first catalyst bed in the hydrocracking reactor  40  may include a hydrotreating catalyst for the purpose of saturating, demetallizing, desulfurizing or denitrogenating the first hydrocarbon feed stream before it is hydrocracked with the first hydrocracking catalyst in subsequent vessels or catalyst beds  42  in the first hydrocracking reactor  40 . Otherwise, the first or an upstream bed in the first hydrocracking reactor  40 . 
     The first hydrocracking catalyst may utilize amorphous silica-alumina bases or low-level zeolite bases combined with one or more Group VIII or Group VIB metal hydrogenating components if mild hydrocracking is desired to produce a balance of middle distillate and gasoline. In another aspect, when middle distillate is significantly preferred in the converted product over gasoline production, partial or full hydrocracking may be performed in the first hydrocracking reactor  40  with a catalyst which comprises, in general, any crystalline zeolite cracking base upon which is deposited a Group VIII metal hydrogenating component. Additional hydrogenating components may be selected from Group VIB for incorporation with the zeolite base. 
     The zeolite cracking bases are sometimes referred to in the art as molecular sieves and are usually composed of silica, alumina and one or more exchangeable cations such as sodium, magnesium, calcium, rare earth metals, etc. They are further characterized by crystal pores of relatively uniform diameter between about 4 and about 14 Angstroms (10 −10  meters). It is preferred to employ zeolites having a relatively high silica/alumina mole ratio between about 3 and about 12. Suitable zeolites found in nature include, for example, mordenite, stilbite, heulandite, ferrierite, dachiardite, chabazite, erionite and faujasite. Suitable synthetic zeolites include, for example, the B, X, Y and L crystal types, e.g., synthetic faujasite and mordenite. The preferred zeolites are those having crystal pore diameters between about 8 and 12 Angstroms (10 −10  meters), wherein the silica/alumina mole ratio is about 4 to 6. One example of a zeolite falling in the preferred group is synthetic Y molecular sieve. 
     The natural occurring zeolites are normally found in a sodium form, an alkaline earth metal form, or mixed forms. The synthetic zeolites are nearly always prepared first in the sodium form. In any case, for use as a cracking base it is preferred that most or all of the original zeolitic monovalent metals be ion-exchanged with a polyvalent metal and/or with an ammonium salt followed by heating to decompose the ammonium ions associated with the zeolite, leaving in their place hydrogen ions and/or exchange sites which have actually been decationized by further removal of water. Hydrogen or “decationized” Y zeolites of this nature are more particularly described in U.S. Pat. No. 3,100,006. 
     Mixed polyvalent metal-hydrogen zeolites may be prepared by ion-exchanging first with an ammonium salt, then partially back exchanging with a polyvalent metal salt and then calcining. In some cases, as in the case of synthetic mordenite, the hydrogen forms can be prepared by direct acid treatment of the alkali metal zeolites. In one aspect, the preferred cracking bases are those which are at least about 10 wt %, and preferably at least about 20 wt %, metal-cation-deficient, based on the initial ion-exchange capacity. In another aspect, a desirable and stable class of zeolites is one wherein at least about 20 wt % of the ion exchange capacity is satisfied by hydrogen ions. 
     The active metals employed in the preferred first hydrocracking catalysts of the present invention as hydrogenation components are those of Group VIII, i.e., iron, cobalt, nickel, ruthenium, rhodium, palladium, osmium, iridium and platinum. In addition to these metals, other promoters may also be employed in conjunction therewith, including the metals of Group VIB, e.g., molybdenum and tungsten. The amount of hydrogenating metal in the catalyst can vary within wide ranges. Broadly speaking, any amount between about 0.05 wt % and about 30 wt % may be used. In the case of the noble metals, it is normally preferred to use about 0.05 to about 2 wt % noble metal. 
     The method for incorporating the hydrogenation metal is to contact the base material with an aqueous solution of a suitable compound of the desired metal wherein the metal is present in a cationic form. Following addition of the selected hydrogenation metal or metals, the resulting catalyst powder is then filtered, dried, pelleted with added lubricants, binders or the like if desired, and calcined in air at temperatures of, e.g., about 371° C. (700° F.) to about 648° C. (1200° F.) in order to activate the catalyst and decompose ammonium ions. Alternatively, the base component may first be pelleted, followed by the addition of the hydrogenation component and activation by calcining. 
     The foregoing catalysts may be employed in undiluted form, or the powdered catalyst may be mixed and copelleted with other relatively less active catalysts, diluents or binders such as alumina, silica gel, silica-alumina cogels, activated clays and the like in proportions ranging between about 5 and about 90 wt %. These diluents may be employed as such or they may contain a minor proportion of an added hydrogenating metal such as a Group VIB and/or Group VIII metal. Additional metal promoted hydrocracking catalysts may also be utilized in the process of the present invention which comprises, for example, aluminophosphate molecular sieves, crystalline chromosilicates and other crystalline silicates. Crystalline chromosilicates are more fully described in U.S. Pat. No. 4,363,718. 
     By one approach, the hydrocracking conditions may include a temperature from about 290° C. (550° F.) to about 468° C. (875° F.), preferably 343° C. (650° F.) to about 445° C. (833° F.), a pressure from about 4.8 MPa (gauge) (700 psig) to about 20.7 MPa (gauge) (3000 psig), a liquid hourly space velocity (LHSV) from about 0.4 to less than about 2.5 hr −1  and a hydrogen rate of about 421 Nm 3 /m 3  (2,500 scf/bbl) to about 2,527 Nm 3 /m 3  oil (15,000 scf/bbl). If mild hydrocracking is desired, conditions may include a temperature from about 315° C. (600° F.) to about 441° C. (825° F.), a pressure from about 5.5 MPa (gauge) (800 psig) to about 13.8 MPa (gauge) (2000 psig) or more typically about 6.9 MPa (gauge) (1000 psig) to about 11.0 MPa (gauge) (1600 psig), a liquid hourly space velocity (LHSV) from about 0.5 to about 2 hr −1  and preferably about 0.7 to about 1.5 hr −1  and a hydrogen rate of about 421 Nm 3 /m 3  oil (2,500 scf/bbl) to about 1,685 Nm 3 /m 3  oil (10,000 scf/bbl). 
     The first hydrocracked effluent stream may exit the first hydrocracking reactor  40  in line  48  and be separated in the fractionation section  14  in downstream communication with the first hydrocracking reactor  40 . The fractionation section  14  comprises one or more separators and fractionation columns in downstream communication with the hydrocracking reactor  40 . 
     The first hydrocracked effluent stream in the first hydrocracked effluent line  48  may in an aspect be heat exchanged with the hydrocarbon feed stream in line  26  to be cooled and be mixed with a second hydrocracked effluent stream in a second hydrocracked effluent line  46 . The combined hydrocracked effluent line  49  may deliver a combined stream to a hot separator  50 . The hot separator separates the first hydrocracked effluent stream and the second hydrocracked effluent stream to provide a hydrocarbonaceous, hot gaseous stream in a hot overhead line  52  and a hydrocarbonaceous, hot liquid stream in a hot bottoms line  54 . The hot separator  50  may be in downstream communication with the first hydrocracking reactor  40 . The hot separator  50  operates at about 177° C. (350° F.) to about 371° C. (700° F.) and preferably operates at about 232° C. (450° F.) to about 315° C. (600° F.). The hot separator  50  may be operated at a slightly lower pressure than the first hydrocracking reactor  40  accounting for pressure drop through intervening equipment. The hot separator  50  may be operated at pressures between about 3.4 MPa (gauge) (493 psig) and about 20.4 MPa (gauge) (2959 psig). The hydrocarbonaceous, hot gaseous separated stream in the hot overhead line  52  may have a temperature of the operating temperature of the hot separator  50 . 
     The hot gaseous stream in the hot overhead line  52  may be cooled before entering a cold separator  56 . As a consequence of the reactions taking place in the first hydrocracking reactor  40  wherein nitrogen, chlorine and sulfur are removed from the feed, ammonia and hydrogen sulfide are formed. At a characteristic sublimation temperature, ammonia and hydrogen sulfide will combine to form ammonium bisulfide and ammonia, and chlorine will combine to form ammonium chloride. Each compound has a characteristic sublimation temperature that may allow the compound to coat equipment, particularly heat exchange equipment, impairing its performance. To prevent such deposition of ammonium bisulfide or ammonium chloride salts in the hot overhead line  52  transporting the hot gaseous stream, a suitable amount of wash water may be introduced into the hot overhead line  52  upstream of a cooler at a point in the hot overhead line where the temperature is above the characteristic sublimation temperature of either compound. 
     The hot gaseous stream may be separated in the cold separator  56  to provide a cold gaseous stream comprising a hydrogen-rich gas stream in a cold overhead line  58  and a cold liquid stream in a cold bottoms line  60 . The cold separator  56  serves to separate hydrogen rich gas from hydrocarbon liquid in the first hydrocracked effluent stream and the second hydrocracked effluent stream for recycle to the first stage hydrocracking unit  12  and the second stage hydrocracking unit  150  in the cold overhead line  58 . The cold separator  56 , therefore, is in downstream communication with the hot overhead line  52  of the hot separator  50  and the first hydrocracking reactor  40 . The cold separator  56  may be operated at about 100° F. (38° C.) to about 150° F. (66° C.), suitably about 115° F. (46° C.) to about 145° F. (63° C.), and just below the pressure of the first hydrocracking reactor  40  and the hot separator  50  accounting for pressure drop through intervening equipment to keep hydrogen and light gases in the overhead and normally liquid hydrocarbons in the bottoms. The cold separator  56  may be operated at pressures between about 3 MPa (gauge) (435 psig) and about 20 MPa (gauge) (2,901 psig). The cold separator  56  may also have a boot for collecting an aqueous phase. The cold liquid stream in the cold bottoms line  60  may have a temperature of the operating temperature of the cold separator  56 . 
     The cold gaseous stream in the cold overhead line  58  is rich in hydrogen. Thus, hydrogen can be recovered from the cold gaseous stream. The cold gaseous stream in the cold overhead line  58  may be passed through a trayed or packed recycle scrubbing column  62  where it is scrubbed by means of a scrubbing extraction liquid such as an aqueous solution fed by line  64  to remove acid gases including hydrogen sulfide and carbon dioxide by extracting them into the aqueous solution. Preferred aqueous solutions include lean amines such as alkanolamines DEA, MEA, and MDEA. Other amines can be used in place of or in addition to the preferred amines. The lean amine contacts the cold gaseous stream and absorbs acid gas contaminants such as hydrogen sulfide and carbon dioxide. The resultant “sweetened” cold gaseous stream is taken out from an overhead outlet of the recycle scrubber column  62  in a recycle scrubber overhead line  68 , and a rich amine is taken out from the bottoms at a bottom outlet of the recycle scrubber column in a recycle scrubber bottoms line  66 . The spent scrubbing liquid from the bottoms may be regenerated and recycled back to the recycle scrubbing column  62  in line  64 . The scrubbed hydrogen-rich stream emerges from the scrubber via the recycle scrubber overhead line  68  and may be compressed in a recycle compressor  70 . The scrubbed hydrogen-rich stream in the scrubber overhead line  68  may be supplemented with make-up hydrogen stream in the make-up line  20  upstream or downstream of the compressor  70 . The compressed hydrogen stream supplies hydrogen to the first stage hydrogen stream in the first stage hydrogen line  22  and a second stage hydrogen stream in a second stage hydrogen line  166 . The recycle scrubbing column  62  may be operated with a gas inlet temperature between about 38° C. (100° F.) and about 66° C. (150° F.) and an overhead pressure of about 3 MPa (gauge) (435 psig) to about 20 MPa (gauge) (2900 psig). 
     The hydrocarbonaceous hot liquid stream in the hot bottoms line  54  may be fractionated. In an aspect, the hot liquid stream in the hot bottoms line  54  may be let down in pressure and flashed in a hot flash drum  80  to provide a flash hot gaseous stream of light ends in a flash hot overhead line  82  and a flash hot liquid stream in a flash hot bottoms line  84 . The hot flash drum  80  may be in direct, downstream communication with the hot bottoms line  54  and in downstream communication with the first hydrocracking reactor  40 . In an aspect, light gases such as hydrogen sulfide may be stripped from the flash hot liquid stream in the flash hot bottoms line  84 . Accordingly, a stripping column  100  may be in downstream communication with the hot flash drum  80  and the hot flash bottoms line  84 . 
     The hot flash drum  80  may be operated at the same temperature as the hot separator  50  but at a lower pressure of between about 1.4 MPa (gauge) (200 psig) and about 6.9 MPa (gauge) (1000 psig), suitably no more than about 3.8 MPa (gauge) (550 psig). The flash hot liquid stream in the flash hot bottoms line  84  may be further fractionated in the fractionation section  14 . The flash hot liquid stream in the flash hot bottoms line  84  may have a temperature of the operating temperature of the hot flash drum  80 . 
     In an aspect, the cold liquid stream in the cold bottoms line  60  may be directly fractionated. In a further aspect, the cold liquid stream may be let down in pressure and flashed in a cold flash drum  86  to separate the cold liquid stream in the cold bottoms line  60 . The cold flash drum  86  may be in direct downstream communication with the cold bottoms line  60  of the cold separator  56  and in downstream communication with the first hydrocracking reactor  40 . 
     In a further aspect, the flash hot gaseous stream in the flash hot overhead line  82  may be fractionated in the fractionation section  14 . In a further aspect, the flash hot gaseous stream may be cooled and also separated in the cold flash drum  86 . The cold flash drum  86  may separate the cold liquid stream in line  60  and/or the flash hot gaseous stream in the flash hot overhead line  82  to provide a flash cold gaseous stream in a flash cold overhead line  88  and a flash cold liquid stream in a cold flash bottoms line  90 . In an aspect, light gases such as hydrogen sulfide may be stripped from the flash cold liquid stream in the flash cold bottoms line  90 . Accordingly, the stripping column  100  may be in downstream communication with the cold flash drum  86  and the cold flash bottoms line  90 . 
     The cold flash drum  86  may be in downstream communication with the cold bottoms line  60  of the cold separator  56 , the hot flash overhead line  82  of the hot flash drum  80  and the first hydrocracking reactor  40 . The flash cold liquid stream in the cold bottoms line  60  and the flash hot gaseous stream in the hot flash overhead line  82  may enter into the cold flash drum  86  either together or separately. In an aspect, the hot flash overhead line  82  joins the cold bottoms line  60  and feeds the flash hot gaseous stream and the cold liquid stream together to the cold flash drum  86  in a cold flash feed line  92 . The cold flash drum  86  may be operated at the same temperature as the cold separator  56  but typically at a lower pressure of between about 1.4 MPa (gauge) (200 psig) and about 6.9 MPa (gauge) (1000 psig) and preferably between about 3.0 MPa (gauge) (435 psig) and about 3.8 MPa (gauge) (550 psig). A flashed aqueous stream may be removed from a boot in the cold flash drum  86 . The flash cold liquid stream in the flash cold bottoms line  90  may have the same temperature as the operating temperature of the cold flash drum  86 . The flash cold gaseous stream in the flash cold overhead line  88  contains substantial hydrogen that may be recovered. 
     The fractionation section  14  may further include the stripping column  100  and a fractionation column  130 . Additionally, the fractionation section  14  may include a HPNA adsorption zone  200 . The stripping column  100  may be in downstream communication with a bottoms line in the fractionation section  14  for stripping volatiles from a first hydrocracked effluent stream and a second hydrocracked effluent stream. For example, the stripping column  100  may be in downstream communication with the hot bottoms line  54 , the flash hot bottoms line  84 , the cold bottoms line  60  and/or the cold flash bottoms line  90 . In an aspect, the stripping column  100  may be a vessel that contains a cold stripping column  102  and a hot stripping column  104  with a wall that isolates each of the stripping columns  102 ,  104  from the other. The cold stripping column  102  may be in downstream communication with the first hydrocracking reactor  40 , the second hydrocracking reactor  170 , the cold bottoms line  60  and, in an aspect, the flash cold bottoms line  90  for stripping the cold liquid stream. The hot stripping column  104  may be in downstream communication with the first hydrocracking reactor  40 , the second hydrocracking reactor  170 , and the hot bottoms line  54  and, in an aspect, the flash hot bottoms line  84  for stripping a hot liquid stream which is hotter than the cold liquid stream. The hot liquid stream may be hotter than the cold liquid stream, by at least 25° C. and preferably at least 50° C. 
     The flash cold liquid stream comprising the first hydrocracked effluent stream and the second hydrocracked effluent stream in the flash cold bottoms line  90  may be heated and fed to the cold stripping column  102  at an inlet which may be in a top half of the column. The flash cold liquid stream which comprises the first hydrocracked effluent stream and the second hydrocracked effluent stream may be stripped of gases in the cold stripping column  102  with a cold stripping media which is an inert gas such as steam from a cold stripping media line  106  to provide a cold stripper gaseous stream of naphtha, hydrogen, hydrogen sulfide, steam and other gases in a cold stripper overhead line  108  and a liquid cold stripped stream in a cold stripper bottoms line  110 . The cold stripper gaseous stream in the cold stripper overhead line  108  may be condensed and separated in a receiver  112 . A stripper net overhead line  114  from the receiver  112  carries a net stripper gaseous stream for further recovery of LPG and hydrogen in a light material recovery unit. Unstabilized liquid naphtha from the bottoms of the receiver  112  may be split between a reflux portion refluxed to the top of the cold stripping column  102  and a liquid stripper overhead stream which may be transported in a condensed stripper overhead line  116  to further recovery or processing. A sour water stream may be collected from a boot of the overhead receiver  112 . 
     The cold stripping column  102  may be operated with a bottoms temperature between about 149° C. (300° F.) and about 288° C. (550° F.), preferably no more than about 260° C. (500° F.), and an overhead pressure of about 0.35 MPa (gauge) (50 psig), preferably no less than about 0.70 MPa (gauge) (100 psig), to no more than about 2.0 MPa (gauge) (290 psig). The temperature in the overhead receiver  112  ranges from about 38° C. (100° F.) to about 66° C. (150° F.) and the pressure is essentially the same as in the overhead of the cold stripping column  102 . 
     The cold stripped stream in the cold stripper bottoms line  110  may comprise predominantly naphtha and kerosene boiling materials. The cold stripped stream in line  110  may be heated and fed to the fractionation column  130 . The fractionation column  130  may be in downstream communication with the first hydrocracking reactor  40  and the second hydrocracking reactor  170 , the cold stripper bottoms line  110  of the cold stripping column  102  and the stripping column  100 . In an aspect, the fractionation column  130  may comprise more than one fractionation column. The fractionation column  130  may be in downstream communication with one, some or all of the hot separator  50 , the cold separator  56 , the hot flash drum  80  and the cold flash drum  86 . 
     The flash hot liquid stream comprising a hydrocracked stream in the hot flash bottoms line  84  may be fed to the hot stripping column  104  near a top thereof. The flash hot liquid stream may be stripped in the hot stripping column  104  of gases with a hot stripping media which is an inert gas such as steam from a line  120  to provide a hot stripper overhead stream of naphtha, hydrogen, hydrogen sulfide, steam and other gases in a hot stripper overhead line  118  and a liquid hot stripped stream in a hot stripper bottoms line  122 . The hot stripper overhead line  118  may be condensed and a portion refluxed to the hot stripping column  104 . However, in the embodiment of  FIG. 1 , the hot stripper overhead stream in the hot stripper overhead line  118  from the overhead of the hot stripping column  104  may be fed into the cold stripping column  102  directly in an aspect without first condensing or refluxing. The inlet for the cold flash bottoms line  90  carrying the flash cold liquid stream may be at a higher elevation than the inlet for the hot stripper overhead line  118 . The hot stripping column  104  may be operated with a bottoms temperature between about 160° C. (320° F.) and about 360° C. (680° F.) and an overhead pressure of about 0.35 MPa (gauge) (50 psig), preferably about 0.70 MPa (gauge) (100 psig), to about 2.0 MPa (gauge) (292 psig). 
     At least a portion of the hot stripped stream comprising a hydrocracked stream in the hot stripped bottoms line  122  may be heated and fed to the fractionation column  130 . The fractionation column  130  may be in downstream communication with the hot stripped bottoms line  122  of the hot stripping column  104 . The hot stripped stream in line  122  may be at a hotter temperature than the cold stripped stream in line  110 . 
     In an aspect, the hot stripped stream in the hot stripped bottoms line  122  may be heated and fed to a prefractionation separator  124  for separation into a vaporized hot stripped stream in a prefractionation overhead line  126  and a liquid hot stripped stream in a prefractionation bottoms line  128 . The vaporous hot stripped stream may be fed to the fractionation column  130  in the prefractionation overhead line  128 . The liquid hot stripped stream may be heated in a fractionation furnace and fed to the fractionation column  130  in the prefractionation bottoms line  128  at an elevation below the elevation at which the prefractionation overhead line  126  feeds the vaporized hot stripped stream to the fractionation column  130 . 
     The fractionation column  130  may be in downstream communication with the cold stripping column  102  and the hot stripping column  104  and may comprise more than one fractionation column for separating stripped hydrocracked streams into product streams. The fractionation column  130  may fractionate hydrocracked streams, the cold stripped stream, the vaporous hot stripped stream and the liquid hot stripped stream, with an inert stripping media stream such as steam from line  132  to provide plurality of fractionator product streams and a fractionator bottoms stream comprising unconverted hydrocarbons. The product streams from the fractionation column  130  may include a net fractionated overhead stream comprising naphtha in a net overhead line  134 , an optional heavy naphtha stream in line  136  from a side cut outlet, a kerosene stream carried in line  138  from a side cut outlet and a diesel stream in line  140  from a side cut outlet. 
     The fractionator bottoms stream comprising unconverted hydrocarbons boiling above the diesel cut point may be taken in a fractionator bottoms line  142  from a bottom of the fractionation column  130 . At least a portion of the fractionator bottoms stream may be recycled for further hydrocracking, which in the instant embodiment of  FIG. 1  as discussed, occurs in the second hydrocracking reactor  170 . The fractionator bottoms stream being recycled may range from about 10 to about 100 wt % of a fresh feed rate, preferably between about 30 and about 70 wt % of the fresh feed rate. In accordance with an exemplary embodiment as shown in  FIG. 1 , a first stream in a first fractionator bottoms line  202  may be taken from the fractionator bottoms stream in the fractionator bottoms line  142 . Further, a second stream in a second fractionator bottoms line  204  may be taken from the fractionator bottoms stream in the fractionator bottoms line  142 . Accordingly, the fractionator bottoms stream may be split to provide the first stream in line  202  and the second stream in line  204 . Therefore, in accordance with various embodiments, the first fractionator bottoms line  202  and the second fractionator bottoms line  204  may be fluidly connected to the fractionator bottoms line  142 . In various embodiments, a third stream may be taken in a bottoms purge line  205  from the fractionator bottoms line  142  and may be rejected as a bleed stream. The first stream, the second stream and the third stream may be taken as aliquot portions of the fractionator bottoms stream. 
     The first stream in line  202  may be passed through the HPNA adsorption zone  200  to obtain a treated bottoms stream in line  206  having a reduced concentration of HPNA compounds. Accordingly, the HPNA adsorption zone  200  may be in downstream communication with the first fractionator bottoms line  202  and the fractionator bottoms line  142 . In the HPNA adsorption zone  200 , the first stream may be contacted with a suitable adsorbent, which may selectively retain the HPNA compounds. Suitable adsorbents may include one or more of a molecular sieve, a silica gel, an activated carbon, an activated alumina, a silica-alumina gel, and a clay. In one example, the HPNA adsorption zone  200  may comprise an activated carbon. The adsorbent may be installed in the adsorption zone  200  in any suitable manner, such as a fixed bed arrangement. The adsorbent may be installed in one or more vessels and either in series or parallel flow. The HPNA adsorption zone  200  may be operated in a swing bed or in a lead-lag configuration. The HPNA adsorption zone  200  can be maintained at a pressure from about 170 kPa (25 psig) to about 4,300 kPa (624 psig), a temperature from about 10° C. (50° F.), to about 370° C. (698° F.), and an LHSV from about 0.1 to about 500 hr −1 . The flow of the first stream through the HPNA adsorption zone  200  may be conducted in an upflow, downflow or radial flow manner with the hydrocarbons in the liquid phase. 
     In accordance with an exemplary embodiment, the first stream in line  202  passing through the HPNA adsorption zone  200  may be between 2 to 10% of the fresh feed rate. The second stream in line  204  may be passed around the HPNA adsorption zone  200 . Accordingly, the second stream and the second fractionator bottoms line  204  bypasses and may be out of communication with the HPNA adsorption zone  200 . 
     The treated bottoms stream in line  206  and the bypassed second stream in line  204  may be subsequently hydrocracked. Accordingly, the process may include hydrocracking the treated bottoms stream and the bypassed second stream. In accordance with an exemplary embodiment as shown in  FIG. 1 , the treated bottoms stream and the bypassed second stream may be combined in a line  208  and passed to the second hydrocracking reactor  170  present in the second stage hydrocracking unit  150 . In an aspect, the treated bottoms stream and the bypassed second stream may combine as a feed stream to the second stage hydrocracking unit  150 . In accordance with an exemplary embodiment, the treated bottoms stream and the bypassed second stream may pass through a hydrotreating reactor (not shown) prior to being passed to the second hydrocracking reactor  170 . 
     Heat may be removed from the fractionation column  130  by cooling at least a portion of the product streams and sending a portion of each cooled stream back to the fractionation column. These product streams may also be stripped to remove light materials to meet product purity requirements. A fractionated overhead stream in an overhead line  148  may be condensed and separated in a receiver  150  with a portion of the condensed liquid being refluxed back to the fractionation column  130 . The net fractionated overhead stream in line  134  may be further processed or recovered as naphtha product. The fractionation column  130  may be operated with a bottoms temperature between about 260° C. (500° F.), and about 385° C. (725° F.), preferably at no more than about 350° C. (650° F.), and at an overhead pressure between about 7 kPa (gauge) (1 psig) and about 69 kPa (gauge) (10 psig). A portion of the unconverted oil stream in the atmospheric bottoms line  142  may be reboiled and returned to the fractionation column  130  instead of adding an inert stripping media stream such as steam in line  132  to heat to the fractionation column  130 . 
     The combined stream in line  208  may be mixed with a second hydrotreating hydrogen stream in a second hydrocracking hydrogen line  152  to provide second hydrocracker feed stream in a second hydrocracker feed line  154 . The second hydrocracker feed stream may be heated by heat exchange with a second hydrocracked effluent stream in line  46  and in a fired heater before being passed to the second hydrocracking reactor  170 . The second hydrocracker feed stream is fed through a first inlet  162   i  to the second hydrocracking reactor  170  to be hydrocracked. 
     The second hydrocracking reactor  170  may be a fixed bed reactor that comprises one or more vessels, single or multiple catalyst beds  172  in each vessel, and various combinations of hydrotreating catalyst, hydroisomerization catalyst and/or hydrocracking catalyst in one or more vessels. It is contemplated that the second hydrocracking reactor  170  be operated in a continuous liquid phase in which the volume of the liquid hydrocarbon feed is greater than the volume of the hydrogen gas. The second hydrocracking reactor  170  may also be operated in a conventional continuous gas phase, a moving bed or a fluidized bed hydroprocessing reactor. 
     The second hydrocracker feed stream in the second hydrocracker feed line  154  is hydrocracked over the second hydrocracking catalyst in the second hydrocracking catalyst beds  172  in the presence of hydrogen to provide a second hydrocracked effluent stream. Subsequent catalyst beds  172  in the hydrocracking reactor may comprise hydrocracking catalyst over which additional hydrocracking occurs. Hydrogen manifold  176  may deliver supplemental hydrogen streams to one, some or each of the catalyst beds  172 . In an aspect, the supplemental hydrogen is added to each of the downstream catalyst beds  172  at an interstage location between adjacent beds, so supplemental hydrogen is mixed with hydrocracked effluent exiting from the upstream catalyst bed  172  before entering the downstream catalyst bed  172 . 
     The second hydrocracking reactor  170  may provide a total conversion of at least about 1 vol % and typically greater than about 40 vol % of the second hydrocracking feed stream in the second hydrotreating effluent line  162  to products boiling below the diesel cut point. The second hydrocracking reactor  170  may complete the conversion partially achieved in the first hydrocracking reactor  40 . The second hydrocracking reactor  170  may operate at partial conversion of more than about 30 vol % or full conversion of at least about 90 vol % of the first hydrocracking feed stream in the first hydrocracking feed line  32  based on total conversion. The second hydrocracking reactor  170  may be operated at mild hydrocracking conditions which will provide about 1 to about 60 vol %, preferably about 20 to about 50 vol %, total conversion of the hydrocarbon feed stream to product boiling below the diesel cut point. 
     The second hydrocracking reactor  170  comprises a plurality of catalyst beds  172 . In accordance with various embodiments, the first catalyst bed in the hydrocracking reactor  170  may include a hydrotreating catalyst for the purpose of saturating aromatic rings in the second hydrocracker feed stream in the second hydrocracker feed line  154  before it is hydrocracked with the second hydrocracking catalyst in subsequent vessels or catalyst beds  172  in the second hydrocracking reactor  170 . 
     The second hydrocracking catalyst may be the same as or different than the first hydrocracking catalyst or may have some of the same as and some different than the first hydrocracking catalyst in the first hydrocracking reactor  40 . The second hydrocracking catalyst may utilize amorphous silica-alumina bases or low-level zeolite bases combined with one or more Group VIII or Group VIB metal hydrogenating components. Additional hydrogenating components may be selected from Group VIB for incorporation with the zeolite base. 
     By one approach, the hydrocracking conditions in the second hydrocracking reactor  170  may be the same as or different than in the first hydrocracking reactor  40 . Conditions in the second hydrocracking reactor may include a temperature from about 290° C. (550° F.) to about 468° C. (875° F.), preferably 343° C. (650° F.) to about 445° C. (833° F.), a pressure from about 4.8 MPa (gauge) (700 psig) to about 20.7 MPa (gauge) (3000 psig), a liquid hourly space velocity (LHSV) from about 0.4 to less than about 2.5 hr −1  and a hydrogen rate of about 421 Nm 3 /m 3  (2,500 scf/bbl) to about 2,527 Nm 3 /m 3  oil (15,000 scf/bbl). 
     The second hydrocracked effluent stream may exit the second hydrocracking reactor  170  in the second hydrocracked effluent line  46 , be heat exchanged with the second hydrocracker feed stream in the second hydrocracker feed line  154  and combined with the first hydrocracked effluent stream in first hydrocracked effluent line  48 . The first hydrocracked effluent stream and the second hydrocracked effluent stream combined in combined hydrocracked effluent line  49  are separated and fractionated in the fractionation section  14  in downstream communication with the second hydrocracking reactor  170  as previously described. 
       FIG. 2  shows an embodiment of the apparatus and process  10 ′ that illustrates a single hydrocracking unit. Elements in  FIG. 2  with the same configuration as in  FIG. 1  will have the same reference numeral as in  FIG. 1 . Elements in  FIG. 2  which have a different configuration as the corresponding element in  FIG. 1  will have the same reference numeral but designated with a prime symbol (′). The configuration and operation of the embodiment of  FIG. 2  is essentially the same as in  FIG. 1  with the following exceptions. 
     The process and apparatus  10 ′ does not comprise a second stage hydrocracking unit  150 . Accordingly, the treated bottoms stream in line  206  and the bypassed second stream in line  204  may be combined in a line  208 ′ and passed back to the hydrocracking reactor  40 . In an aspect, the treated bottoms stream and the bypassed second stream may combine in a combined stream to the hydrocracking unit  12 ′. In accordance with an exemplary embodiment as shown in  FIG. 2 , the combined stream in line  208 ′ may be mixed with the hydrocarbon line  18 ′ to provide the hydrocarbon feed stream in the hydrocarbon feed line  26 ′ which is subsequently processed as described in  FIG. 1 . In an aspect, the combined stream in line  208 ′ may bypass the hydrotreating reactor  30  and is provided to the hydrotreating effluent line  32  and passed to the hydrocracking reactor  40  for further processing a described in  FIG. 1 . 
     By splitting the fractionator bottoms stream, the present process and apparatus allows the operator to tailor the operation for the actual HPNA removal requirements as operating severity and feed changes. If the unit is processing a feed high in HPNA precursors, the operator has the option to increase the flow to the HPNA adsorption zone by reducing the bypass. Likewise, during periods of feeds low in HPNA precursors, the flow to the chambers could be reduced by increasing the bypass. Further, as the flow to the HPNA adsorption zone is reduced, this results in smaller activated carbon chamber and reduced frequency of activated carbon replacement. 
     SPECIFIC EMBODIMENTS 
     While the following is described in conjunction with specific embodiments, it will be understood that this description is intended to illustrate and not limit the scope of the preceding description and the appended claims. 
     A first embodiment of the invention is a process of removing HPNA compounds from a hydrocracked stream, the process comprising passing at least a portion of the hydrocracked stream to a fractionation column to provide a plurality of fractionator product streams and a fractionator bottoms stream comprising unconverted hydrocarbons; taking a first stream from the fractionator bottoms stream; taking a second stream from the fractionator bottoms stream; passing the first stream through a HPNA adsorption zone to obtain a treated bottoms stream having a reduced concentration of HPNA compounds; bypassing the second stream around the HPNA adsorption zone; and hydrocracking the treated bottoms stream and the bypassed second stream. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising hydrocracking a hydrocarbon feedstream in a first hydrocracking reactor, wherein the hydrocarbon feedstream is contacted with a first hydrocracking catalyst under first hydrocracking conditions in the presence of hydrogen to provide the hydrocracked stream. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the step of hydrocracking the treated bottoms stream and the bypassed second stream occurs in the first hydrocracking reactor. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the step of hydrocracking the treated bottoms stream and the bypassed second stream occurs in a second hydrocracking reactor. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the HPNA adsorption zone comprises an activated carbon. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising hydrotreating the hydrocarbon feedstream in a hydrotreating reactor prior to hydrocracking the hydrocarbon feedstream in the first hydrocracking reactor. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the treated bottoms stream and the bypassed second stream are passed through the hydrotreating reactor prior to the step of hydrocracking. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising passing the hydrocracked stream through one or more vapor-liquid separators to provide a recycle hydrogen gas stream and at least one liquid process stream; and passing the at least one liquid process stream to the fractionation column to provide the plurality of fractionator product streams and the fractionator bottoms stream. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising taking a third stream from the fractionator bottoms stream and rejecting the third stream as a bleed stream. 
     A second embodiment of the invention is a process for upgrading a hydrocarbon stream, the process comprising passing the hydrocarbon feedstream to a first hydrocracking reactor, the first hydrocracking reactor containing at least one bed of a first hydrocracking catalyst, wherein the hydrocarbon feedstream is contacted with the first hydrocracking catalyst under first hydrocracking conditions in the presence of hydrogen to produce a first hydrocracked effluent stream; passing at least a portion of the first hydrocracked effluent stream to a fractionation column to provide a plurality of fractionator product streams and a fractionator bottoms stream comprising unconverted hydrocarbons; splitting the fractionator bottoms stream to provide a first stream and a second stream; passing the first stream through a HPNA adsorption zone to obtain a treated bottoms stream having a reduced concentration of HPNA compounds; bypassing the second stream around the HPNA adsorption zone; and passing the treated bottoms stream and the bypassed second stream to a second hydrocracking reactor, the second hydrocracking reactor containing at least one bed of a second hydrocracking catalyst, wherein the treated bottoms stream and the bypassed second stream are contacted with a second hydrocracking catalyst under second hydrocracking conditions in the presence of hydrogen to provide a second hydrocracked effluent stream. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph, wherein the HPNA adsorption zone comprises an activated carbon. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph further comprising hydrotreating the hydrocarbon feedstream in a hydrotreating reactor prior to hydrocracking the hydrocarbon feedstream in the first hydrocracking reactor. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph, wherein the treated bottoms stream and the bypassed second stream are passed through the hydrotreating reactor prior to being passed to the second hydrocracked reactor. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph further comprising passing the first hydrocracked effluent stream through one or more vapor-liquid separators to provide a recycle hydrogen gas stream and at least one liquid process stream; passing the at least one liquid process stream to the fractionation column to provide the plurality of fractionator product streams and the fractionator bottoms stream. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph further comprising obtaining a third stream from the fractionator bottoms stream, the third stream being rejected as a bleed stream. 
     A third embodiment of the invention is an apparatus for removing HPNA compounds from a hydrocracked stream, the apparatus comprising a fractionation column in communication with a hydrocracked effluent line to provide a plurality of fractionator product streams and a fractionator bottoms stream in a fractionator bottoms line; a first fractionator bottoms line fluidly connected to the fractionator bottoms line; a second fractionator bottoms line fluidly connected to the fractionator bottoms line; a HPNA adsorption zone in downstream communication with the first fractionator bottoms line to provide a treated bottoms stream in a treated bottoms line having a reduced concentration of HPNA compounds; and a hydrocracking reactor in communication with the treated bottoms line and the second fractionator bottoms line, the second fractionator bottoms line bypassing the HPNA adsorption zone. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph, wherein the HPNA adsorption zone comprises an activated carbon. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph further comprising a first hydrocracking reactor to provide a hydrocracked stream in the hydrocracked effluent line. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph, wherein the hydrocracking reactor is the first hydrocracking reactor. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph, wherein the hydrocracking reactor is a second hydrocracking reactor, the second hydrocracking reactor in downstream communication with the first hydrocracking reactor. 
     Without further elaboration, it is believed that using the preceding description that one skilled in the art can utilize the present invention to its fullest extent and easily ascertain the essential characteristics of this invention, without departing from the spirit and scope thereof, to make various changes and modifications of the invention and to adapt it to various usages and conditions. The preceding preferred specific embodiments are, therefore, to be construed as merely illustrative, and not limiting the remainder of the disclosure in any way whatsoever, and that it is intended to cover various modifications and equivalent arrangements included within the scope of the appended claims. 
     In the foregoing, all temperatures are set forth in degrees Celsius and, all parts and percentages are by weight, unless otherwise indicated.