Abstract:
A process is disclosed for recovering hydroprocessing effluent from a hydroprocessing unit utilizing a hot stripper and a cold stripper. Only the hot hydroprocessing effluent is heated in a fired heater prior to product fractionation, resulting in substantial operating and capital savings.

Description:
FIELD OF THE INVENTION 
       [0001]    The field of the invention is the recovery of hydroprocessed hydrocarbon streams. 
       BACKGROUND OF THE INVENTION 
       [0002]    Hydroprocessing can include processes which convert hydrocarbons in the presence of hydroprocessing catalyst and hydrogen to more valuable products. 
         [0003]    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 beds of the same or different catalyst. Slurry hydrocracking is a slurried catalytic process used to crack residue feeds to gas oils and fuels. 
         [0004]    Due to environmental concerns and newly enacted rules and regulations, saleable fuels must meet lower and lower limits on contaminates, such as sulfur and nitrogen. New regulations require essentially complete removal of sulfur from diesel. For example, the ultra low sulfur diesel (ULSD) requirement is typically less than about 10 wppm sulfur. 
         [0005]    Hydrotreating is a hydroprocessing process used to remove heteroatoms such as sulfur and nitrogen from hydrocarbon streams to meet fuel specifications and to saturate olefinic compounds. Hydrotreating can be performed at high or low pressures, but is typically operated at lower pressure than hydrocracking. 
         [0006]    Hydroprocessing recovery units typically include a stripper for stripping hydroprocessed effluent with a stripping medium such as steam to remove unwanted hydrogen sulfide. The stripped effluent then is heated in a fired heater to fractionation temperature before entering a product fractionation column to recover products such as naphtha, kerosene and diesel. 
         [0007]    Hydroprocessing and particularly hydrocracking is very energy-intensive due to the severe process conditions such as the high temperature and pressure used. Over time, although much effort has been spent on improving energy performance for hydrocracking, the focus has been on reducing reactor heater duty. However, a large heater duty is required to heat stripped effluent before entering the product fractionation column. 
         [0008]    There is a continuing need, therefore, for improved methods of recovering fuel products from hydroprocessed effluents. Such methods must be more energy efficient to meet the increasing needs of refiners. 
       BRIEF SUMMARY OF THE INVENTION 
       [0009]    In a process embodiment, the invention comprises a hydroprocessing process comprising hydroprocessing a hydrocarbon feed in a hydroprocessing reactor to provide hydroprocessing effluent stream. A relatively cold hydroprocessing effluent stream which is a portion of the hydroprocessing effluent stream is stripped in a cold stripper to provide a cold stripped stream. Lastly, a relatively hot hydroprocessing effluent stream which is a portion of the hydroprocessing effluent stream is stripped in a hot stripper to provide a hot stripped stream. 
         [0010]    In an additional process embodiment, the invention comprises a hydroprocessing product recovery process for recovering product from a cold hydroprocessing effluent stream and a hot hydroprocessing effluent stream comprising stripping the relatively cold hydroprocessing effluent stream in a cold stripper to provide a cold stripped stream. The relatively hot hydroprocessing effluent stream is stripped in a hot stripper to provide a hot stripped stream. Lastly, the cold stripped stream and the hot stripped stream are fractionated in a product fractionation column to provide product streams. 
         [0011]    In a further process embodiment, the invention comprises a stripping process comprising stripping a relatively cold hydroprocessing effluent stream in a cold stripper to provide a cold stripped stream. Lastly, a relatively hot hydroprocessing effluent stream is stripped in a hot stripper to provide a hot stripped stream. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0012]      FIG. 1  is a simplified process flow diagram of an embodiment of the present invention. 
           [0013]      FIG. 2  is a simplified process flow diagram of an alternative embodiment of the strippers of  FIG. 1 . 
           [0014]      FIG. 3  is a simplified process flow diagram of an additional alternative embodiment of the strippers of  FIG. 1 . 
           [0015]      FIG. 4  is a simplified process flow diagram of a further alternative embodiment of the strippers of  FIG. 1 . 
       
    
    
     DEFINITIONS 
       [0016]    The term “communication” means that material flow is operatively permitted between enumerated components. 
         [0017]    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. 
         [0018]    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. 
         [0019]    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. Feeds to the columns may be preheated. The top 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. Stripper columns omit a reboiler at a bottom of the column and instead provide heating requirements and separation impetus from a fluidized inert media such as steam. 
         [0020]    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 D2892 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. 
         [0021]    As used herein, the term “conversion” means conversion of feed to material that boils at or below the diesel boiling range. The diesel cut point of the diesel boiling range is between about 343° and about 399° C. (650° to 750° F.) using the True Boiling Point distillation method. 
         [0022]    As used herein, the term “diesel boiling range” means hydrocarbons boiling in the range of between about 132° and about 399° C. (270° to 750° F.) using the True Boiling Point distillation method. 
         [0023]    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 that may be operated at higher pressure. 
       DETAILED DESCRIPTION 
       [0024]    Traditional hydroprocessing design features one stripper which receives two feeds, a relatively cold hydroprocessed effluent stream which may be from a cold flash drum and a relatively hot hydroprocessed effluent stream which may be from a hot flash drum. Although these two feeds contain very different compositions, they can be traced back to the same location from a hydroprocessing reactor and perhaps, a hot separator. An overhead vapor stream of the hot separator may go to a cold separator and the liquid from the cold separator may go to a cold flash drum while a bottoms liquid of the hot separator may go to a hot flash drum. Traditionally, the liquid of both hot and cold flash drums are fed to a single stripper. A stripper bottoms stream may become the feed for the product fractionation column. The inefficiency of this one-stripper design is rooted in mixing of the liquids of the hot flash drum and the cold flash drum in the same stripper which partially undoes the separation previously accomplished in the hot separator and thus requires duplicative heating in a fired heater to the product fractionation column. 
         [0025]    Applicants propose to use two strippers, namely a hot stripper which is used for the hot hydroprocessed effluent stream which may be liquid from the hot flash drum and a cold stripper which is used for the cold hydroprocessed effluent stream which may be liquid from the cold flash drum. The cold stripper bottoms does not pass through the product fractionation feed heater but goes directly to the product fractionation column after being heated by less energy-intensive process heat exchange. The hot stripper bottoms may go to the product fractionation feed heater. In this design, the feed rate to the heater is reduced significantly and thus the product fractionation heater duty and size is reduced accordingly. By decreasing the feed rate to the product fractionation feed heater, the fuel used in the heater is decreased approximately 40 percent for a typical hydrocracking unit. 
         [0026]    The apparatus and process  10  for hydroprocessing hydrocarbons comprise a hydroprocessing unit  12  and a product recovery unit  14 . A hydrocarbon stream in hydrocarbon line  16  and a make-up hydrogen stream in hydrogen make-up line  18  are fed to the hydroprocessing unit  12 . Hydroprocessing effluent is fractionated in the product recovery unit  14 . 
         [0027]    A hydrogen stream in hydrogen line  76  supplemented by make-up hydrogen from line  18  may join the hydrocarbon feed stream in feed line  16  to provide a hydroprocessing feed stream in feed line  20 . The hydroprocessing feed stream in line  20  may be heated by heat exchange and in a fired heater  22  and fed to the hydroprocessing reactor  24 . 
         [0028]    In one aspect, the process and apparatus described herein are particularly useful for hydroprocessing a hydrocarbonaceous feedstock. Illustrative hydrocarbon feedstocks include hydrocarbonaceous streams having components boiling above about 288° C. (550° F.), such as atmospheric gas oils, vacuum gas oil (VGO) boiling between about 315° C. (600° F.) and about 565° C. (1050° F.), deasphalted oil, coker distillates, straight run distillates, pyrolysis-derived oils, high boiling synthetic oils, cycle oils, hydrocracked feeds, catalytic cracker distillates, atmospheric residue boiling at or above about 343° C. (650° F.) and vacuum residue boiling above about 510° C. (950° F.). 
         [0029]    Hydroprocessing that occurs in the hydroprocessing unit may be hydrocracking or hydrotreating. Hydrocracking refers to a process in which hydrocarbons crack in the presence of hydrogen to lower molecular weight hydrocarbons. Hydrocracking is the preferred process in the hydroprocessing unit  12 . Consequently, the term “hydroprocessing” will include the term “hydrocracking” herein. Hydrocracking also includes slurry hydrocracking in which resid feed is mixed with catalyst and hydrogen to make a slurry and cracked to lower boiling products. VGO in the products may be recycled to manage coke precursors referred to as mesophase. 
         [0030]    Hydroprocessing that occurs in the hydroprocessing unit may also be hydrotreating. Hydrotreating is a process wherein hydrogen is contacted with hydrocarbon in the presence of suitable catalysts which are primarily active for the removal of heteroatoms, such as sulfur, nitrogen and metals from the hydrocarbon feedstock. In hydrotreating, hydrocarbons with double and triple bonds may be saturated. Aromatics may also be saturated. Some hydrotreating processes are specifically designed to saturate aromatics. The cloud point of the hydrotreated product may also be reduced. 
         [0031]    The hydroprocessing reactor  24  may be a fixed bed reactor that comprises one or more vessels, single or multiple beds of catalyst in each vessel, and various combinations of hydrotreating catalyst and/or hydrocracking catalyst in one or more vessels. It is contemplated that the hydroprocessing reactor  24  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 hydroprocessing reactor  24  may also be operated in a conventional continuous gas phase, a moving bed or a fluidized bed hydroprocessing reactor. 
         [0032]    If the hydroprocessing reactor  24  is operated as a hydrocracking reactor, it may provide total conversion of at least about 20 vol-% and typically greater than about 60 vol-% of the hydrocarbon feed to products boiling below the diesel cut point. A hydrocracking reactor may operate at partial conversion of more than about 50 vol-% or full conversion of at least about 90 vol-% of the feed based on total conversion. A hydrocracking reactor 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 to product boiling below the diesel cut point. If the hydroprocessing reactor  24  is operated as a hydrotreating reactor, it may provide conversion per pass of about 10 to about 30 vol-%. 
         [0033]    If the hydroprocessing reactor  24  is a hydrocracking reactor, the first vessel or bed in the hydrocracking reactor  24  may include hydrotreating catalyst for the purpose of saturating, demetallizing, desulfurizing or denitrogenating the hydrocarbon feed before it is hydrocracked with hydrocracking catalyst in subsequent vessels or beds in the hydrocracking reactor  24 . If the hydrocracking reactor is a mild hydrocracking reactor, it may contain several beds of hydrotreating catalyst followed by a fewer beds of hydrocracking catalyst. If the hydroprocessing reactor  24  is a slurry hydrocracking reactor, it may operate in a continuous liquid phase in an upflow mode and will appear different than in  FIG. 1  which depicts a fixed bed reactor. If the hydroprocessing reactor  24  is a hydrotreating reactor it may comprise more than one vessel and multiple beds of hydrotreating catalyst. The hydrotreating reactor may also contain hydrotreating catalyst that is suited for saturating aromatics, hydrodewaxing and hydroisomerization. 
         [0034]    A 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  24  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. 
         [0035]    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 8-12 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. 
         [0036]    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. 3,130,006. 
         [0037]    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 percent, and preferably at least about 20 percent, 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 percent of the ion exchange capacity is satisfied by hydrogen ions. 
         [0038]    The active metals employed in the preferred hydrocracking catalysts of the present invention as hydrogenation components are those of Group VIII, i.e., iron, cobalt, nickel, ruthenium, rhodium, palladium, osmium, iridium and platinum. In addition to these metals, other promoters may also be employed in conjunction therewith, including the metals of Group 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 percent and about 30 percent by weight may be used. In the case of the noble metals, it is normally preferred to use about 0.05 to about 2 wt-%. 
         [0039]    The method for incorporating the hydrogenating 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 hydrogenating metal or metals, the resulting catalyst powder is then filtered, dried, pelleted with added lubricants, binders or the like if desired, and calcined in air at temperatures of, e.g., about 371° to about 648° C. (about 700° to about 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 hydrogenating component and activation by calcining. 
         [0040]    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. 
         [0041]    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 1.0 to less than about 2.5 hr −1  and a hydrogen rate of about 421 (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). 
         [0042]    Slurry hydrocracking catalyst are typically ferrous sulfate hydrates having particle sizes less than 45 μm and with a major portion, i.e. at least 50% by weight, in an aspect, having particle sizes of less than 10 μm. Iron sulfate monohydrate is a suitable catalyst. Bauxite catalyst may also be suitable. In an aspect, 0.01 to 4.0 wt-% of catalyst based on fresh feedstock are added to the hydrocarbon feed. Oil soluble catalysts may be used alternatively or additionally. Oil soluble catalysts include metal naphthenate or metal octanoate, in the range of 50-1000 wppm based on fresh feedstock. The metal may be molybdenum, tungsten, ruthenium, nickel, cobalt or iron. 
         [0043]    A slurry hydrocracking reactor may be operated at a pressure, in an aspect, in the range of 3.5 MPa (gauge) (508 psig) to 24 MPa (gauge) (3,481 psig), without coke formation in the reactor. The reactor temperature may be in the range of about 350° to 600° C. with a temperature of about 400° to 500° C. being typical. The LHSV is typically below about 4 h −1  on a fresh feed basis, with a range of about 0.1 to 3 hr −1  being suitable and a range of about 0.2 to 1 hr −1  being particularly suitable. The per-pass pitch conversion may be between 50 and 95 wt-%. The hydrogen feed rate may be about 674 to about 3370 Nm 3 /m 3  (4000 to about 20,000 SCF/bbl) oil. An antifoaming agent may also be added to the slurry hydrocracking reactor  24 , in an aspect, to the top thereof, to reduce the tendency to generate foam. 
         [0044]    Suitable hydrotreating catalysts for use in the present invention 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, as well as noble metal catalysts where the noble metal is selected from palladium and platinum. It is within the scope of the present invention that more than one type of hydrotreating catalyst be used in the same hydrotreating reactor  96 . 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-%. 
         [0045]    Preferred hydrotreating reaction conditions 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 4 hr −1 , preferably from about 1.5 to about 3.5 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. 
         [0046]    A hydroprocessing effluent exits the hydroprocessing reactor  24  and is transported in hydroprocessing effluent line  26 . The hydroprocessing effluent comprises material that will become a relatively cold hydroprocessing effluent stream and a relatively hot hydroprocessing effluent stream. The hydroprocessing unit may comprise one or more separators for separating the hydroprocessing effluent stream into a cold hydroprocessing effluent stream and hot hydroprocessing effluent stream. 
         [0047]    The hydroprocessing effluent in hydroprocessing effluent line  26  may in an aspect be heat exchanged with the hydroprocessing feed stream in line  20  to be cooled before entering a hot separator  30 . The hot separator separates the hydroprocessing effluent to provide a vaporous hydrocarbonaceous hot separator overhead stream in an overhead line  32  comprising a portion of a cold hydroprocessed effluent stream and a liquid hydrocarbonaceous hot separator bottoms stream in a bottoms line  34  comprising a portion of a cold hydroprocessed effluent stream and still a portion of a hot hydroprocessed effluent stream. The hot separator  30  in the hydroprocessing section  12  is in downstream communication with the hydroprocessing reactor  24 . The hot separator  30  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  30  may be operated at a slightly lower pressure than the hydroprocessing reactor  24  accounting for pressure drop of intervening equipment. The hot separator may be operated at pressures between about 3.4 MPa (gauge) (493 psig) and about 20.4 MPa (gauge) (2959 psig). 
         [0048]    The vaporous hydrocarbonaceous hot separator overhead stream in the overhead line  32  may be cooled before entering a cold separator  36 . As a consequence of the reactions taking place in the hydroprocessing reactor  24  wherein nitrogen, chlorine and sulfur are removed from the feed, ammonia and hydrogen sulfide are formed. At a characteristic 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 line  32  transporting the hot separator overhead stream, a suitable amount of wash water (not shown) may be introduced into line  32  upstream at a point in line  32  where the temperature is above the characteristic sublimation temperature of either compound. 
         [0049]    The cold separator  36  serves to separate hydrogen from hydrocarbon in the hydroprocessing effluent for recycle to the hydroprocessing reactor  24  in the overhead line  38 . The vaporous hydrocarbonaceous hot separator overhead stream may be separated in the cold separator  36  to provide a vaporous cold separator overhead stream comprising a hydrogen-rich gas stream in an overhead line  38  and a liquid cold separator bottoms stream in the bottoms line  40  comprising a portion of the cold hydroprocessing effluent stream. The cold separator  36 , therefore, is in downstream communication with the overhead line  32  of the hot separator  30  and the hydroprocessing reactor  24 . The cold separator  36  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 hydroprocessing reactor  24  and the hot separator  30  accounting for pressure drop of intervening equipment to keep hydrogen and light gases in the overhead and normally liquid hydrocarbons in the bottoms. The cold separator may be operated at pressures between about 3 MPa (gauge) (435 psig) and about 20 MPa (gauge) (2,901 psig). The cold separator  36  may also have a boot for collecting an aqueous phase in line  42 . 
         [0050]    The liquid hydrocarbonaceous stream in the hot separator bottoms line  34  may be fractionated as hot hydroprocessing effluent stream in the product recovery unit  14 . In an aspect, the liquid hydrocarbonaceous stream in the bottoms line  34  may be let down in pressure and flashed in a hot flash drum  44  to provide a hot flash overhead stream of light ends in an overhead line  46  comprising a portion of the cold hydroprocessed effluent stream and a heavy liquid stream in a bottoms line  48  comprising at least a portion of the hot hydroprocessed effluent stream. The hot flash drum  44  may be any separator that splits the liquid hydroprocessing effluent into vapor and liquid fractions. The hot flash drum  44  may be operated at the same temperature as the hot separator  30  but at a lower pressure of between about 2.1 MPa (gauge) (300 psig) and about 6.9 MPa (gauge) (1000 psig), suitably less than about 3.4 MPa (gauge) (500 psig). The heavy liquid stream in bottoms line  48  may be further fractionated in the product recovery unit  14 . In an aspect, the heavy liquid stream in bottoms line  48  may be introduced into a hot stripper  50  and comprise at least a portion, and suitably all, of a relatively hot hydroprocessing effluent stream. The hot stripper  50  is in downstream communication with a bottom of the hot flash drum  44  via bottoms line  48 . 
         [0051]    In an aspect, the liquid hydroprocessing effluent stream in the cold separator bottoms line  40  may be fractionated as a cold hydroprocessing effluent stream in the product recovery unit  14 . In a further aspect, the cold separator liquid bottoms stream may be let down in pressure and flashed in a cold flash drum  52  to separate the cold separator liquid bottoms stream in bottoms line  40 . The cold flash drum  52  may be any separator that splits hydroprocessing effluent into vapor and liquid fractions. The cold flash drum may be in communication with a bottom of the cold separator  36  via bottoms line  40 . A cold stripper  60  may be in downstream communication with a bottoms line  56  of the cold flash drum  52 . 
         [0052]    In a further aspect, the vaporous hot flash overhead stream in overhead line  46  may be fractionated as a cold hydroprocessing effluent stream in the product recovery unit  14 . In a further aspect, the hot flash overhead stream may be cooled and also separated in the cold flash drum  52 . The cold flash drum  52  may separate the cold separator liquid bottoms stream in line  40  and hot flash vaporous overhead stream in overhead line  46  to provide a cold flash overhead stream in overhead line  54  and a cold flash bottoms stream in a bottoms line  56  comprising at least a portion of a cold hydroprocessed effluent stream. The cold flash bottoms stream in bottoms line  56  comprises at least a portion, and suitably all, of the cold hydroprocessed effluent stream. In an aspect, the cold stripper  60  is in downstream communication with the cold flash drum  52  via bottoms line  56 . The cold flash drum  52  may be in downstream communication with the bottoms line  40  of the cold separator  50 , the overhead line  46  of the hot flash drum  44  and the hydroprocessing reactor  24 . The cold separator bottoms stream in bottoms line  40  and the hot flash overhead stream in overhead line  46  may enter into the cold flash drum  52  either together or separately. In an aspect, the hot flash overhead line  46  joins the cold separator bottoms line  40  and feeds the hot flash overhead stream and the cold separator bottoms stream together to the cold flash drum  52 . The cold flash drum  52  may be operated at the same temperature as the cold separator  50  but typically at a lower pressure of between about 2.1 MPa (gauge) (300 psig) and about 7.0 MPa (gauge) (1000 psig) and preferably no higher than 3.1 MPa (gauge) (450 psig). The aqueous stream in line  42  from the boot of the cold separator may also be directed to the cold flash drum  52 . A flashed aqueous stream is removed from a boot in the cold flash drum  52  in line  62 . 
         [0053]    The vaporous cold separator overhead stream comprising hydrogen in the overhead line  38  is rich in hydrogen. The cold separator overhead stream in overhead line  38  may be passed through a trayed or packed scrubbing tower  64  where it is scrubbed by means of a scrubbing liquid such as an aqueous amine solution in line  66  to remove hydrogen sulfide and ammonia. The spent scrubbing liquid in line  68  may be regenerated and recycled back to the scrubbing tower  64 . The scrubbed hydrogen-rich stream emerges from the scrubber via line  70  and may be compressed in a recycle compressor  72  to provide a recycle hydrogen stream in line  74  which is a compressed vaporous hydroprocessing effluent stream. The recycle compressor  72  may be in downstream communication with the hydroprocessing reactor  24 . The recycle hydrogen stream in line  74  may be supplemented with make-up stream  18  to provide the hydrogen stream in hydrogen line  76 . A portion of the material in line  74  may be routed to the intermediate catalyst bed outlets in the hydroprocessing reactor  24  to control the inlet temperature of the subsequent catalyst bed (not shown). 
         [0054]    The product recovery section  14  may include a hot stripper  50 , a cold stripper  60  and a product fractionation column  90 . The cold stripper  60  is in downstream communication with the hydroprocessing reactor  24  for stripping the relatively cold hydroprocessing effluent stream which is a portion of the hydroprocessing effluent stream in hydroprocessing effluent line  26 , and the hot stripper is in downstream communication with the hydroprocessing reactor  24  for stripping the relatively hot hydroprocessing effluent stream which is also a portion of the hydroprocessing effluent stream in hydroprocessing effluent line  26 . In an aspect, the cold hydroprocessing effluent stream is the cold flash bottoms stream in bottoms line  56  and the hot hydroprocessing effluent stream is the hot flash bottoms stream in bottoms line  48 , but other sources of these streams are contemplated. 
         [0055]    The cold hydroprocessing effluent stream which in an aspect may be in the cold flash bottoms line  56  may be heated and fed to the cold stripper column  60  near the top of the column. The cold hydroprocessing effluent stream which comprises at least a portion of the liquid hydroprocessing effluent may be stripped in the cold stripper column  60  with a cold stripping media which is an inert gas such as steam from a cold stripping media line  78  to provide a cold vapor stream of naphtha, hydrogen, hydrogen sulfide, steam and other gases in an overhead line  80 . At least a portion of the cold vapor stream may be condensed and separated in a receiver  82 . An overhead line  84  from the receiver  82  carries vaporous off gas for further treating. Unstabilized liquid naphtha from the bottoms of the receiver  82  may be split between a reflux portion in line  86  refluxed to the top of the cold stripper column  60  and a product portion which may be transported in product line  88  to further fractionation such as in a debutanizer or a deethanizer column (not shown). The cold stripper column  60  may be operated with a bottoms temperature between about 149° C. (300° F.) and about 260° C. (500° F.) and an overhead pressure of about 0.5 MPa (gauge) (73 psig) to about 2.0 MPa (gauge) (290 psig). The temperature in the overhead receiver  82  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 stripper column  60 . 
         [0056]    A hydrocracked cold stripped stream in bottoms line  92  may be heated with a process heater that is less intensive than a fired heater and fed to the product fractionation column  90 . Consequently, the product fractionation column  90  is in downstream communication with the bottoms line  92  of the cold stripper. The cold stripped stream may be heat exchanged with a bottoms stream in bottoms line  126  from the product fractionation column  90  or other suitable stream before entering the product fractionation column  90 . 
         [0057]    The hot hydroprocessing effluent stream which may be in the hot flash bottoms line  48  may be fed to the hot stripper column  50  near the top thereof. The hot hydroprocessing effluent stream which comprises at least a portion of the liquid hydroprocessing effluent may be stripped in the hot stripper column  50  with a hot stripping media which is an inert gas such as steam from line  94  to provide a hot vapor stream of naphtha, hydrogen, hydrogen sulfide, steam and other gases in an overhead line  96 . At least a portion of the hot vapor stream may be condensed and separated in a receiver  98 . An overhead line  100  from the receiver  98  carries vaporous off gas for further treating. Unstabilized liquid naphtha from the bottoms of the receiver  98  may be split between a reflux portion in line  102  refluxed to the top of the hot stripper column  50  and a product portion which may be transported in product line  104  to further fractionation such as to a debutanizer column or a deethanizer column (not shown). It is also contemplated that the product portion from the hot stripper column  50  in line  104  be fed to the cold stripper column  60 . The hot stripper column  50  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 0.5 MPa (gauge) (73 psig) to about 2.0 MPa (gauge) (292 psig). The temperature in the overhead receiver  98  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 hot stripper column  50 . 
         [0058]    A hydroprocessed hot stripped stream is produced in bottoms line  106 . At least a portion of the hot stripped stream in bottoms line  106  may be fed to the product fractionation column  90 . Consequently, the product fractionation column  90  is in downstream communication with the bottoms line  106  of the hot stripper. 
         [0059]    A fired heater  108  in downstream communication with the hot bottoms line  106  may heat at least a portion of the hot stripped stream before it enters the product fractionation column  90  in line  110 . The cold stripped stream in line  92  can be added to the product fractionation column  90  at a location that does not require heating in the fired heater  108 . The cold bottoms line  92  carrying the cold stripped stream to the product fractionation column  90  may bypass the fired heater  108 . A cold inlet for the cold stripped stream in line  92  to the product fractionation column  90  is at a higher elevation than a hot inlet for the hot stripped stream in line  110  to the product fractionation column  90 . 
         [0060]    In an aspect, the hot stripped stream in hot bottoms line  106  may be separated in a separator  112 . A vaporous hot stripped stream in overhead line  114  from the separator  112  may be passed into the product fractionation column  90  at an inlet lower than or at the same elevation as the cold inlet for the cold stripped stream in line  92 . A liquid hot stripped stream in bottoms line  116  may be the portion of the hot stripped stream that is fed to the product fractionation column  90  after heating in the fired heater  108  to be a fired hot stripped stream in line  110 . The fired hot stripped stream in line  110  may be introduced into the product fractionation column  90  at an elevation lower than the cold inlet for the cold stripped stream in line  92  and the inlet for the vapor stream in line  114 . 
         [0061]    The product fractionation column  90  may be in communication with the cold stripper column  60  and the hot stripper  50  for separating stripped streams into product streams. The product fractionation column  90  may also strip the cold stripped stream in line  92  and the hot stripped stream in line  106 , which may be the vaporous hot stripped stream in line  114  and the liquid hot stripped stream in line  116  or the fired hot stripped stream in line  110 , with stripping media such as steam from line  118  to provide several product streams. The product streams may include an overhead naphtha stream in overhead line  120 , a kerosene stream in line  122  from a side cut outlet, a diesel stream carried in line  124  from a side cut outlet and an unconverted oil stream in a bottoms line  126  which may be suitable for further processing, such as in an FCC unit. Heat may be removed from the product fractionation column  90  by cooling the kerosene in line  122  and diesel in line  124  and sending a portion of each cooled stream back to the column. The overhead naphtha stream in line  120  may be condensed and separated in a receiver  128  with liquid being refluxed back to the product fractionation column  90 . The net naphtha stream in line  130  may require further processing such as in a naphtha splitter column before blending in the gasoline pool. The product fractionation column  90  may be operated with a bottoms temperature between about 288° C. (550° F.) and about 370° C. (700° F.), preferably about 343° C. (650° F.) and at an overhead pressure between about 30 kPa (gauge) (4 psig) to about 200 kPa (gauge) (29 psig). A portion of the unconverted oil in the bottoms line  126  may be reboiled and returned to the product fractionation column  90  instead of using steam stripping. 
         [0062]    Sour water streams may be collected from boots (not shown) of overhead receivers  82 ,  98  and  128 . 
         [0063]    In the embodiment of  FIG. 1 , the overhead recovery for each of the strippers  50  and  60  are separate. We have found that the overhead vapor from each of the strippers  50  and  60  are very similar in composition, temperature and pressure.  FIG. 2  illustrates an embodiment of the hot stripper column  50  and the cold stripper column  60  share a common overhead recovery apparatus  200 . Many of the elements in  FIG. 2  have the same configuration as in  FIG. 1  and bear the same respective reference number. Elements in  FIG. 2  that correspond to elements in  FIG. 1  but have a different configuration bear the same reference numeral as in  FIG. 1  but are marked with a prime symbol (&#39;). 
         [0064]    In  FIG. 2 , hot hydroprocessing effluent in line  48  feeds a hot stripper column  50 ′ and a cold hydroprocessing effluent in line  56  feeds a cold stripper column  60 ′ as in  FIG. 1 . A cold stripping media line  78  to the cold stripper column  60 ′ supplies cold stripping media to the cold stripper column  60 ′ and a hot stripping media line  94  to the hot stripping column  50 ′ supplies hot stripping media to the hot stripper column  50 ′. Stripping media is typically medium pressure steam and the label of hot and cold with respect to stripping media does not indicate relative temperature. Trays  220  in the hot stripper column  50 ′ and trays  222  in the cold stripper column  60 ′ or other packing materials enhance vapor liquid contacting and stripping. A cold stripped stream is produced in bottoms line  92  and a hot stripped stream is produced in bottoms line  106 . A cold stripper bottoms section  228  is isolated from the hot stripper bottoms section  232  of the hot stripper to isolate the cold stripped stream in bottoms line  92  from the hot stripped stream in hot bottoms line  106 . The cold stripped bottoms line  92  of the cold stripper column  60 ′ is isolated from a hot stripped bottoms line  106  of the hot stripper column  50 ′ to further isolate a cold stripped bottoms stream from a hot stripped bottoms stream. 
         [0065]    An overhead line  80 ′ carrying a cold vapor stream from an overhead section  204  of a cold stripper  60 ′ and an overhead line  96 ′ carrying a hot vapor stream from an overhead section  202  of a hot stripper  50 ′ both feed a common overhead condenser  208  for condensing the cold vapor stream and the hot vapor stream to provide a condensed overhead stream in condensate line  210 . The condenser  208  is in downstream communication with the overhead section  204  and the overhead line  80 ′ of the cold stripper and overhead section  202  and the overhead line  96 ′ of the hot stripper  50 ′. The cold vapor stream in overhead line  80 ′ and the hot vapor stream in overhead line  96 ′ may be mixed in a joined line  206  before entering the condenser  208 . Condensate line  210  may transport the condensed overhead stream to a common overhead receiver  212  in downstream communication with the overhead line  80 ′ of the cold stripper  60  and the overhead line  96 ′ of the hot stripper  50 ′. In the overhead receiver  212 , the condensed overhead stream is separated into an off-gas stream in an overhead line  214  for further processing and a condensed receiver bottoms stream in bottoms line  216 . A sour water stream may be recovered from a boot (not shown) in receiver  212 . The common overhead receiver  212  is operated in the same temperature and pressure ranges as the individual cold overhead receiver  82  and hot overhead receiver  98 . 
         [0066]    The condensed receiver bottom stream in bottoms line  216  may be split into three portions. At least a first portion of the condensed receiver bottoms stream in line  216  may be refluxed to a top of the hot stripper  50 ′ in a hot reflux line  102 ′. The hot reflux line  102 ′ may be in downstream communication with the bottoms line  216  of the overhead receiver  212  and the hot stripper  50 ′ may be in downstream communication with the hot reflux line  102 ′. 
         [0067]    At least a second portion of the condensed receiver bottoms stream in line  216  may be refluxed to a top of the cold stripper  60 ′ in a cold reflux line  86 ′. The cold reflux line  86 ′ may be in downstream communication with the bottoms line  216  of the overhead receiver  212  and the cold stripper  60 ′ may be in downstream communication with the cold reflux line  86 ′. The flow rate of cold reflux in line  86 ′ and hot reflux in line  102 ′ must be regulated to ensure each stripper column  50 ′ and  60 ′ receives sufficient reflux to provide sufficient liquid to the respective columns. 
         [0068]    A third portion of the condensed receiver bottoms in line  216  comprising unstabilized naphtha may be transported in line  218  to a fractionation column (not shown) for further processing. 
         [0069]    The embodiment of  FIG. 2  reduces capital equipment for the overhead recovery apparatus  200  in half by using only one condenser, receiver and associated piping instead of two. 
         [0070]    The rest of the embodiment in  FIG. 2  may be the same as described for  FIG. 1  with the previous noted exceptions. 
         [0071]    In the embodiment of  FIG. 2 , the overhead section for each of the stripper columns  50 ′ and  60 ′ were kept separate.  FIG. 3  illustrates an embodiment of a hot stripper section  50 ″ and a cold stripper section  60 ″ sharing a common overhead section  302 . Many of the elements in  FIG. 3  have the same configuration as in  FIG. 1  and bear the same respective reference number. Elements in  FIG. 3  that correspond to elements in  FIG. 1  but have a different configuration bear the same reference numeral as in  FIG. 1  but are marked with a double prime symbol (″). 
         [0072]    In the embodiment of  FIG. 3 , a cold stripper section  60 ″ and a hot stripper section  50 ″ are contained in the same stripping vessel  330  and share the same overhead section  302 . The cold stripper section  60 ″ and the hot stripper section  50 ″ are adjacent to each other in the stripping vessel  330 . 
         [0073]    The heavier material in the hot hydroprocessing effluent in line  48  fed to the hot stripper section  50 ″ has a different composition than the cold hydroprocessed effluent  56  fed to the cold stripper section  60 ″. For example, the hot hydroprocessed effluent  48  may have more sulfur compounds and be hotter than the cold hydroprocessed effluent  56 . To maintain the beneficial effect of the invention, a barrier  340  prevents vapor and liquid material in the hot stripper section  50 ″ from entering into the cold stripper section  60 ″. 
         [0074]    The barrier  340  in  FIG. 3  may comprise a vertical wall. The barrier  340  may extend all the way to a bottom  336  of the vessel  330  and be coextensive with a bottom section  328  of the cold stripper section  60 ″. A top of the barrier  340  is spaced apart from a top  342  of the stripping vessel  330  to allow the overhead cold vapor from the cold stripper section  60 ″ to mix with the hot vapor from the hot stripper section  50 ″ in the common overhead section  302 . No material from the hot stripper section  50 ″ passes to the cold stripper section  60 ″ below a top of the barrier  340  in the stripping vessel  330 . The cold stripper bottoms section  328  is isolated from the hot stripper bottoms section  332  of the hot stripper to isolate the cold stripped stream in bottoms line  92 ″ from the hot stripped stream in bottoms line  106 ″. 
         [0075]    Hot hydroprocessing effluent in line  48  feeds the hot stripper section  50 ″ and a cold hydroprocessing effluent in line  56  feeds a cold stripper section  60 ″ on opposite sides of the barrier  340 . A cold stripping media line  78  to the cold stripper section  60 ″ supplies stripping media to the cold stripper section  60 ″ and a hot stripping media line  94  to the hot stripping section  50 ″ supplies stripping media to the hot stripper section  50 ″. Stripping media is typically medium pressure steam and the label of hot and cold with respect to stripping media does not indicate relative temperature. Trays  344  in the hot stripper section  50 ″ and trays  346  in the cold stripper section  60 ″ or other packing materials enhance vapor liquid contacting and stripping. A cold stripped bottoms line  92 ″ may extend from the bottom section  328  of the cold stripper section  60 ″ for withdrawing a cold stripped stream through a bottom  336  of the cold stripper  60 ″. A hot stripped bottoms line  106 ″ may extend from a bottom section  332  of the hot stripper section  50 ″ for withdrawing a hot stripped stream through a bottom  336  of the hot stripper  50 ″. A cold stripped stream is produced in bottoms line  92 ″ and a hot stripped stream is produced in bottoms line  106 ″. 
         [0076]    A common overhead apparatus  300  services vapor from the common overhead section  302  of the hot stripper section  50 ″ and the cold stripper section  60 ″. The hot vapor stream from the hot stripper section  50 ″ and the cold vapor stream from the cold stripper section  60 ″ mix in the common overhead section  302 . An overhead line  306  from the common overhead section  302  of the cold stripper  60 ″ and the hot stripper  50 ″ both feed a common overhead condenser  308  for condensing the mixed cold vapor stream and hot vapor stream together to provide a condensed overhead stream in condensate line  310 . The condenser  308  is in downstream communication with the overhead section  302  and the overhead line  306  of the cold stripper and the hot stripper  50 ′. Condensate line  310  may transport the condensed overhead stream to a common overhead receiver  312  in downstream communication with the overhead line  306  of the cold stripper  60 ″ and the hot stripper  50 ″. In the overhead receiver  312 , the condensed overhead stream is separated into an off-gas stream in an overhead line  314  for further processing and a condensed receiver bottoms stream in bottoms line  316 . 
         [0077]    The condensed receiver bottom stream in bottoms line  316  may be split into two portions. At least a first portion of the condensed receiver bottoms stream in line  316  may be refluxed to the common overhead section  302  at a top of the hot stripper  50 ″ and the cold stripper  60 ″ in an aspect above the barrier  340  in a common reflux line  320 . A second portion of the condensed receiver bottoms stream in line  316  comprising unstabilized naphtha may be transported in line  318  to a fractionation column (not shown) for further processing. A sour water stream may be recovered from a boot (not shown) in receiver  312 . 
         [0078]    The rest of the embodiment in  FIG. 3  may be the same as described for  FIG. 1  with the previous noted exceptions. The adjacent strippers in the same vessel  330  require only one vessel and one foot print for a single stripper vessel  330  instead of two vessels. 
         [0079]    In the embodiment of  FIG. 3 , the hot stripper section  50 ″ and the cold stripper section  60 ″ are adjacent to each other in the same vessel  300  and share a common overhead section  302 .  FIG. 4  illustrates an embodiment of a hot stripper section  50 ″′ and a cold stripper section  60 ″′ contained in the same vessel, but stacked on top of each other and using separate overhead sections  402 ,  404  but with a common overhead recovery apparatus  400 . Many of the elements in  FIG. 4  have the same configuration as in  FIGS. 1 ,  2  and  3  and bear the same respective reference number. Elements in  FIG. 4  that correspond to elements in  FIG. 1  but have a different configuration bear the same reference numeral as in  FIG. 1  but are marked with a double prime symbol (′″). 
         [0080]    In the embodiment of  FIG. 4 , a cold stripper section  60 ′ and a hot stripper section  50 ′ are contained in the same stripping vessel  430  but do not share the same overhead sections  402 ,  404  or bottoms sections  432 ,  428 . The cold stripper section  60 ″′ and the hot stripper section  50 ″′ are stacked on top of each other in the stripping vessel  400 , in an aspect with the cold stripper section  60 ′ on top of the hot stripper section  50 ″′. 
         [0081]    The heavier material in the hot hydroprocessing effluent in line  48  fed to the hot stripper section  50 ″′ has a different composition than the cold hydroprocessed effluent  56  fed to the cold stripper section  60 ″′. For example, the hot hydroprocessed effluent  48  may have more sulfur compounds and be hotter than the cold hydroprocessed effluent  56 . To maintain the beneficial effect of the invention, a barrier  440  prevents material, vapor and liquid, in the hot stripper section  50 ″′ from entering with unwanted sulfur compounds into the cold stripper section  60 ′. The barrier  440  particularly prevents hydrogen sulfide in the vapor from the overhead section  402  of the hot stripper  50 ″′ from entering into a cold stripped stream in bottoms line  92 ″′. 
         [0082]    The barrier  440  in  FIG. 4  may comprise a hemispherical wall or head. The barrier  440  may extend across the entire cross section of a bottom section  428  of the cold stripper section  60 ″′. The barrier may include a hemispherical wall  442  or head extending across the entire cross section of the overhead  402  of the hot stripper section  50 ″′ instead of or in addition to the barrier  440 . The barrier  440  prevents the overhead hot vapor or other material from the hot stripper section  50 ″ from mixing with the cold vapor or other material from the cold stripper section  60 ″′. No material from the hot stripper section  50 ′ passes to the cold stripper section  60 ′ and vice versa. The cold stripper bottoms section  428  is isolated from the hot stripper bottoms section  432  of the hot stripper to isolate the cold stripped stream in bottoms line  92 ″′ from the hot stripped stream in bottoms line  106 ″′. Moreover, the cold stripper bottom section  428  is isolated from the hot stripper overhead section  402  to prevent hydrogen sulfide from the hot stripper overhead section  402  from entering into the cold stripped stream in cold bottoms line  92 ″′. 
         [0083]    Hot hydroprocessing effluent in line  48  feeds the hot stripper section  50 ″′ and a cold hydroprocessing effluent in line  56  feeds a cold stripper section  60 ″′ on opposite sides of the barrier  440 . A cold stripping media line  78  to the cold stripper section  60 ″′ supplies stripping media to the cold stripper section  60 ″′ and a hot stripping media line  94  to the hot stripping section  50 ″′ supplies stripping media to the hot stripper section  50 ″′. Stripping media is typically medium pressure steam and the label of hot and cold with respect to stripping media does not indicate relative temperature. Trays  444  in the hot stripper section  50 ″ and trays  446  in the cold stripper section  60 ″′ or other packing materials enhance vapor liquid contacting and stripping. A cold stripped bottoms line  92 ″′ may extend from the bottom section  428  of the cold stripper section  60 ″′ for withdrawing a cold stripped stream through the barrier  440  which may be at the bottom of the cold stripper section  60 ″′. The cold stripped bottoms line  92 ″′ may extend through the barrier  440  and a wall  450  of the stripping vessel  430  for withdrawing the cold stripped stream through the wall  450  in the stripping vessel  400 . 
         [0084]    A hot stripped bottoms line  106 ″′ may extend from a bottom section  432  of the hot stripper section  50 ″′ for withdrawing a hot stripped stream through a bottom  436  of the hot stripper  50 ″′. A cold stripped stream is produced in bottoms line  92 ″′ and a hot stripped stream is produced in bottoms line  106 ″′. 
         [0085]    An overhead line  80 ″′ from an overhead section  404  of a cold stripper section  60 ″′ and an overhead line  96 ″′ from an overhead section  402  of a hot stripper section  50 ″′ both feed a common overhead condenser  408  for condensing the cold vapor stream and the hot vapor stream to provide a condensed overhead stream in condensate line  410 . It is also contemplated that a separate overhead recovery apparatus can be used for each overhead line  80 ″′ and  96 ″′ as in  FIG. 1 . The condenser  408  is in downstream communication with the overhead section  404  and the overhead line  80 ″′ of the cold stripper section  60 ″′ and overhead section  402  and the overhead line  96 ″′ of the hot stripper section  50 ″′. The cold vapor stream in overhead line  80 ″′ and the hot vapor stream in overhead line  96 ″′ may be mixed in a joined line  406  before entering the condenser  408 . Condensate line  410  may transport the condensed overhead stream to a common overhead receiver  412  in communication with the overhead line  80 ′″ of the cold stripper section  60 ″′ and the overhead line  96 ″′ of the hot stripper section  50 ″′. In the overhead receiver  412 , the condensed overhead stream is separated into an off-gas stream in an overhead line  414  for further processing and a condensed receiver bottoms stream in bottoms line  416 . A sour water stream may also be collected from a boot (not shown) of the overhead receiver  412 . 
         [0086]    The condensed receiver bottom stream in bottoms line  416  may be split into three portions. At least a first portion of the condensed receiver bottoms stream in line  416  may be refluxed to a top of the hot stripper section  50 ′″ in a hot reflux line  102 ″′. The hot reflux line  102 ″′ may be in downstream communication with the bottoms line  416  of the overhead receiver  412 , and the hot stripper section  50 ″′ may be in downstream communication with the hot reflux line  102 ″′. 
         [0087]    At least a second portion of the condensed receiver bottoms stream in line  416  may be refluxed to a top of the cold stripper section  60 ″′ in a cold reflux line  86 ″′. The cold reflux line  86 ″′ may be in downstream communication with the bottoms line  416  of the overhead receiver  412 , and the cold stripper section  60 ″′ may be in downstream communication with the cold reflux line  86 ″′. The flow rate of cold reflux in line  86 ″′ and hot reflux in line  102 ″′ must be regulated to ensure each stripper section  50 ″′ and  60 ″′ receives sufficient reflux to provide sufficient liquid to the respective columns. 
         [0088]    A third portion of the condensed receiver bottoms in line  416  comprising unstabilized naphtha may be transported in line  418  to a fractionation column (not shown) for further processing. 
         [0089]    The rest of the embodiment in  FIG. 4  may be the same as described for  FIGS. 1 ,  2  and  3  with the previous noted exceptions. The stacked strippers require only one vessel and one foot print for a single stripper vessel  430  instead of two vessels. 
       EXAMPLE 
       [0090]    The present invention which utilizes a hot stripper and a cold stripper instead of a single stripper counter-intuitively saves capital and operating expense. The cold stripped stream does not pass through the product fractionation feed heater but goes to the product fractionation column after being heated by process exchange. Only the hot stripped stream in the bottoms line goes to the product fractionation feed heater thus reducing the feed rate to the heater significantly and thereby reducing the product fractionation feed heater duty and size accordingly. 
         [0091]    We calculate for a hydroprocessing unit that hydroprocesses 10.5 megaliters (66,000 bbl) of feed per day, the decrease in feed rate to the product fractionation feed heater provided by the invention results in a decrease in the fuel used in the heater by over 40 percent. Less steam is generated by heat exchange with hot streams because the recovery unit operates with more heat efficiency. Overall, the hydroprocessing apparatus with a hot stripper and a cold stripper can run for operating costs that are $2.5 million less per year than the conventional hydroprocessing apparatus with a single stripper. 
         [0092]    The capital costs for the same apparatus are also reduced. Although two strippers are slightly more expensive than one stripper, the fired heater is approximately 40 percent smaller due to its lower duty. As a result, the two-stripper invention results in $1.6 million reduction in capital equipment expenses. 
         [0093]    The present invention which adds a vessel to the recovery unit surprisingly results in less operational cost and capital cost. 
         [0094]    Preferred embodiments of this invention are described herein, including the best mode known to the inventors for carrying out the invention. It should be understood that the illustrated embodiments are exemplary only, and should not be taken as limiting the scope of the invention. 
         [0095]    Without further elaboration, it is believed that one skilled in the art can, using the preceding description, utilize the present invention to its fullest extent. The preceding preferred specific embodiments are, therefore, to be construed as merely illustrative, and not limitative of the remainder of the disclosure in any way whatsoever. 
         [0096]    In the foregoing, all temperatures are set forth in degrees Celsius and, all parts and percentages are by weight, unless otherwise indicated. Pressures are given at the vessel outlet and particularly at the vapor outlet in vessels with multiple outlets. 
         [0097]    From the foregoing description, one skilled in the art can easily ascertain the essential characteristics of this invention and, without departing from the spirit and scope thereof, can make various changes and modifications of the invention to adapt it to various usages and conditions.