Patent Publication Number: US-2022219097-A1

Title: Process and apparatus for heating stream from a separation vessel

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims priority from U.S. Provisional Application No. 63/136,061, filed Jan. 11, 2021, which is incorporated herein in its entirety. 
    
    
     FIELD 
     The field is hydroprocessing and separating hydrocarbon streams. 
     BACKGROUND 
     Hydroprocessing can include processes which convert hydrocarbons in the presence of hydroprocessing catalyst and hydrogen to more valuable products. 
     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. 
     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. Hydrocracking can be performed with one or two hydrocracking reactor stages. 
     A hydroprocessing recovery section typically includes a series of separators in a separation section to separate gases from the liquid materials and cool and depressurize liquid streams to prepare them for fractionation into products. Hydrogen gas is recovered for recycle to the hydroprocessing unit. A stripping column for stripping hydroprocessed effluent with a stripping medium such as steam is used to remove unwanted hydrogen sulfide from liquid product streams. A stripping column may be sufficient to separate product streams from a hydrotreating unit. A product fractionation column downstream of the stripping column is typically used to separate product streams from a hydrocracking unit. 
     A spiral tube heat exchanger comprises a vertical shell in which one or more bundles of tubes are helically or spirally wound around a central core or mandrels in numerous superposed layers. The spiral tube heat exchange can exchange heat between a stream circulating in the shell and a stream circulating in the tube. The numerous spiral tubes provide a greater quantity of surface area enabling heat exchange between streams with a lower temperature differential. 
     There is a continuing need, of imparting heat to streams in product recovery and appurtenant to the hydroprocessing reactor. 
     BRIEF SUMMARY 
     An apparatus and process heat a process stream taken from a separator vessel by heat exchange with a hydroprocessed effluent stream and return the heated process stream to the separator vessel. We have found the significant heater duty reduction is provided by this arrangement particularly for a hydroprocessing unit. A spiral tube heat exchanger can achieve heating of an already hot process stream by heat exchange with a hot effluent stream to make this arrangement work in a hydroprocessing unit. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a simplified process flow diagram. 
         FIG. 2  is an alternative process flow diagram to  FIG. 1 . 
         FIG. 3  is a further alternative process flow diagram to  FIG. 2 . 
     
    
    
     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 passing through a fractionation or conversion unit to undergo a compositional change due to physical fractionation or chemical conversion. 
     The term “bypass” means that the object is out of downstream communication with a bypassing subject at least to the extent of bypassing. 
     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. 
     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. 
     As used herein, the term “boiling point temperature” means atmospheric equivalent boiling point (AEBP) as calculated from the observed boiling temperature and the distillation pressure, as calculated using the equations furnished in ASTM D1160 appendix A7 entitled “Practice for Converting Observed Vapor Temperatures to Atmospheric Equivalent Temperatures”. 
     As used herein, the term “T5” or “T95” means the temperature at which 5 vol percent or 95 mass percent, as the case may be, respectively, of the sample boils using ASTM D-86 or TBP. 
     As used herein, the term “initial boiling point” (IBP) means the temperature at which the sample begins to boil using ASTM D2892, ASTM D-86 or TBP, as the case may be. 
     As used herein, the term “conversion” means conversion of feed to material that boils at or below the diesel or the heaviest desired product 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. 
     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. 
     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. 
     As used herein, the term “predominant”, “predominantly” or “predominate” means greater than 50%, suitably greater than 75% and preferably greater than 90%. 
     As used herein, the term “pass” is a flow of a specific stream through a heat exchanger. 
     As used herein, the term “bundle” is a group of tubes or channels containing a specific stream and comprising a pass through a heat exchanger. 
     DETAILED DESCRIPTION 
     We have found that heating a process stream taken from a separation vessel and returning the stream back to the separation vessel significantly reduces heater duty in the separation vessel. The process is well suited for a hydroprocessing unit. Additionally, we have found that heat exchanging the already hot process stream from the separation vessel with another hotter stream can be achieved in a spiral tube heat exchanger. 
     In one aspect, the process and apparatus described herein are particularly useful for hydroprocessing a hydrocarbon feed stream comprising a hydrocarbonaceous feedstock. Illustrative hydrocarbonaceous feed stocks particularly for hydroprocessing units having a hydroprocessing reactor  12  include hydrocarbon streams having initial boiling points (IBP) above about 260° C. (500° F.), such as atmospheric gas oil or vacuum gas oil (VGO) having T5 between about 288° C. (550° F.) and about 427° C. (800° F.) and a T95 between about 371° C. (700° F.) and about 650° C. (1200° F.). Distillates including cycle oils, coker distillates, straight run distillates, catalytic cracker distillates and hydrocracked distillates boiling in the diesel boiling range are suitable feedstocks. Other suitable feeds include deasphalted oil, pyrolysis-derived oils, high boiling synthetic oils, clarified slurry oils, deasphalted oil, and shale oil. Atmospheric residue having a T5 at or above about 343° C. (650° F.) and vacuum residue having a T5 above about 510° C. (950° F.) are also suitable. 
     In  FIG. 1 , the hydroprocessing unit  10  for hydroprocessing hydrocarbons comprises a hydroprocessing reactor  12 . A hydrocarbon feed stream in hydrocarbon line  18  may be fed to a surge drum  20  from which it is pumped to a manifold in line  22  and split into a first hydrocarbon feed stream in line  24  and a second hydrocarbon feed stream in line  26 . The first hydrocarbon feed stream and the second hydrocarbon feed stream should be of equal flow rates. The hydrocarbon feed stream may be split into additional streams of equal flow rates. A hydrogen stream in line  28  is also split into a first hydrogen stream in line  30  and a second hydrogen stream in line  32  of equal flow rates. The hydrogen stream  28  may be split into as many streams as the hydrocarbon feed stream in line  22  is split. The first hydrogen stream in line  30  may be combined with the first hydrocarbon feed stream in line  24  to provide a first combined hydrocarbon stream in line  34 . The second hydrogen stream in line  32  may be combined with the second hydrocarbon feed stream in line  26  to provide a second combined hydrocarbon stream in line  36 . 
     The first combined hydrocarbon stream in line  34  and the second combined hydrocarbon stream in line  36  are fed to a heat exchanger  40 . The first combined hydrocarbon stream is fed to a first inlet compartment  41  which feeds the first combined hydrocarbon stream into a first pass  42  in which it is indirectly heat exchanged through the first pass and collects in a first outlet compartment  43 . Alternatively, the first hydrogen stream in line  30  may be combined with the first hydrocarbon feed stream in line  24  in the first inlet compartment  41  to allow mixing or distribution of the streams in the first inlet compartment. The first inlet compartment  41  may be in the bottom of the heat exchanger  40  and the first outlet compartment  43  may be in the top of the heat exchanger. A first heated combined hydrocarbon stream exits the heat exchanger  40  in line  44 . The second combined hydrocarbon stream is fed to a second inlet compartment  45  which feeds the second combined hydrocarbon stream into a second pass  46  in which it is indirectly heat exchanged through the second pass and collects in a second outlet compartment  47 . Alternatively, the second hydrogen stream in line  32  may be combined with the second hydrocarbon feed stream in line  26  in the second inlet compartment  45  to allow mixing or distribution of the streams in the second inlet compartment. The second inlet compartment  45  may be in the bottom of the heat exchanger  40  and the second outlet compartment  47  may be in the top of the heat exchanger. A second heated combined hydrocarbon stream exits the heat exchanger  40  in line  48 . The first combined hydrocarbon stream and the second combined hydrocarbon stream are heat exchanged with a hot hydroprocessed effluent stream in line  50  from the hydroprocessing reactor  12  which may be circulated through the shell side of the heat exchanger  40 . The shell  49  of the heat exchanger  40  may be in downstream communication with the hydroprocessing reactor  12 . A cooled hydroprocessed effluent stream exits the heat exchanger  40  in line  52 . The hotter hydroprocessed effluent passes through the shell  49  counter-currently to the passage of the cooler hydrocarbon feed streams through the passes  42  and  46 . In a non-tubular heat exchanger, the hot hydroprocessed effluent stream can pass through channels arranged in thermal contact to channels through with the combined hydrocarbon feed stream passes. In an aspect the cool hydrocarbon feed streams pass upwardly and the hot hydroprocessed effluent stream passes downwardly in the heat exchanger  40 . 
     In an aspect, a process stream in line  54  may also be heated by heat exchange with the hydroprocessed effluent stream in line  50 . In an aspect, the process stream in line  54  may be heated by heat exchange with the hydroprocessed effluent stream in line  50  simultaneously with the heat exchange of the first combined hydrocarbon stream and the second combined hydrocarbon stream with the hydroprocessed effluent stream in line  50  in the heat exchanger  40 . The process stream in line  54  may pass through a third pass  56  in the heat exchanger  40  while it is heat exchanged with the hotter hydroprocessed effluent stream from line  50 . A heated process stream exits the heat exchanger  40  in line  58 . Preferably, the heat exchange in the heat exchanger  40  is all conducted within the shell  49  of the heat exchanger  40 . The hotter hydroprocessed effluent passes through the shell  49  counter-currently to the passage of the cooler process stream through the third pass  56 . In an aspect the cool process stream passes upwardly and the hot hydroprocessed effluent stream passes downwardly in the heat exchanger  40 . 
     The heat exchanger  40  may be any heat exchanger or heat exchange train that can achieve the heat exchange of all the mentioned streams. For example, the heat exchanger  40  may be a plate exchanger which has sufficient surface area to provide heat exchange between streams with lower temperature differentials. Plate exchangers may enable a specific stream to make multiple passes through a heat exchanger. In a further aspect, the heat exchanger  40  may be a spiral tube heat exchanger (STHE). A STHE comprises a vertical chamber within the shell  49  in which one or more bundles of tubes are helically or spirally wound around a central core or mandrel in numerous superposed layers. Each pass  42 ,  46  and  56  in the heat exchanger  40  may comprise a bundle of tubes spirally wound around a mandrel. While the tube side of each bundle is in communication with only the streams identified at the inlet and outlet of the pass, the tubes of each bundle may be co-arranged with other bundles within wound layers around a single mandrel to maximize heat transfer. The high surface area and flow arrangement afforded by the bundle of spirally wound tubes permits the process stream in line  54  ranging in temperature from about 230° C. (450° F.) to about 315° C. (600° F.) to be heat exchanged against the hydroprocessed effluent stream in line  50  at a temperature ranging from about 290° C. (550° F.) to about 468° C. (875° F.), suitably 316° C. (600° F.) to about 445° C. (833° F.) and preferably 343° C. (650° F.) to about 399° C. (750° F.). 
     The first heated combined hydrocarbon stream in line  44  and the second heated combined hydrocarbon stream in line  48  exit the heat exchanger  40  and are separately fed to the charge heater  60  in which they are heated to hydroprocessing reactor temperature and recombined in a hydroprocessing charge line  62 . The hydroprocessing charge line  62  delivers the charge hydrocarbon feed stream to the hydroprocessing reactor  12 . 
     Hydroprocessing that occurs in the hydroprocessing reactor  12  may be hydrotreating or hydrocracking. The embodiment of  FIG. 1  is most suited for hydrotreating a distillate feed stream in the hydroprocessing reactor  12 . Hydrotreating is a process in which 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. The hydroprocessing unit  10  will be described with the hydroprocessing reactor  12  comprising a hydrotreating reactor. 
     The hydroprocessing reactor  12  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 in one or more vessels. It is contemplated that the hydroprocessing reactor  12  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  12  may also be operated in a conventional continuous gas phase, a moving bed or a fluidized bed hydrotreating reactor. The hydroprocessing reactor  12  may provide conversion per pass of about 5 to about 40 vol %. 
     The hydroprocessing reactor  12  may comprise a guard bed of specialized material for pressure drop mitigation 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 may be added at an interstage location between catalyst beds in the hydrotreating reactor  12  for temperature control. 
     Suitable hydrotreating catalysts 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 description that more than one type of hydrotreating catalyst be used in the same 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 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 2.8 MPa (gauge) (400 psig) to about 17.5 MPa (gauge) (2500 psig), a liquid hourly space velocity of the fresh hydrocarbonaceous feedstock from about 0.1 hr −1 , suitably 0.5 hr −1 , to about 5 hr −1 , preferably from about 1.5 to about 4 hr −1 , and a hydrogen rate of about 84 Nm 3 /m 3  (500 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 1,250 Nm 3 /m 3  oil (7,500 scf/bbl), with a hydrotreating catalyst or a combination of hydrotreating catalysts. 
     The charge hydrocarbon feed stream in the hydroprocessing charge line  62  may be hydroprocessed in the hydroprocessing reactor  12  with the hydrogen stream over hydroprocessing catalyst to provide a hydroprocessed effluent stream. Specifically, the charge hydrocarbon feed stream in the hydroprocessing charge line  62  may be hydrotreated with the hydrogen stream over the hydrotreating catalyst in the hydroprocessing reactor  12  to provide the hydroprocessed effluent stream that exits the hydroprocessing reactor in a hydroprocessed effluent line  50 . The hydroprocessed effluent stream may exit the hydroprocessing reactor  12  in the hydroprocessed effluent line  50  and be cooled in the heat exchanger  40  as previously described. The shell  49  of the heat exchanger  40  may be in downstream communication with the hydroprocessing reactor  12 . It is alternatively contemplated that the hydroprocessed effluent stream may be received through a pass of the heat exchanger  40  which may be in direct downstream communication with the hydroprocessing reactor  12 . The cooled hydroprocessed effluent exits the heat exchanger  40  and enters a hot separator  70 . 
     The hot separator  70  separates the cooled hydroprocessed effluent stream to provide a hydrocarbonaceous, hot hydroprocessed vapor stream in a hot overhead line  72  extending from a top of the hot separator  70  and a hydrocarbonaceous, hot liquid stream in a hot bottoms line  74  extending from a bottom of the hot separator  70 . The hot separator  70  may be in downstream communication with the hydroprocessing reactor  12 . The hot separator  70  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  70  may be operated at a slightly lower pressure than the hydroprocessing reactor  12  accounting for pressure drop through intervening equipment. The hot separator  70  may be operated at pressures between about 3.4 MPa (gauge) (493 psig) and about 20.4 MPa (gauge) (2960 psig). The hot hydroprocessed vapor stream taken in the hot overhead line  72  may have a temperature of the operating temperature of the hot separator  70 . 
     The hot vapor stream in the hot overhead line  72  may be cooled by heat exchange and with an air cooler before entering a cold separator  76 . As a consequence of the reactions taking place in the hydroprocessing reactor  12  wherein nitrogen, chlorine and sulfur are reacted from the hydrocarbons in the feed, ammonia, hydrogen sulfide and hydrogen chloride are formed. At a characteristic sublimation temperature, ammonia and hydrogen sulfide will combine to form ammonium bisulfide, and ammonia and hydrogen chloride 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  72  transporting the hot vapor stream, a suitable amount of wash water may be introduced into the hot overhead line  72  upstream of the air cooler by water line  73  at a point in the hot overhead line where the temperature is above the characteristic sublimation temperature of either compound. 
     The hot vapor stream may be separated in the cold separator  76  to provide a cold hydroprocessed vapor stream comprising a hydrogen-rich gas stream in a cold overhead line  78  extending from a top of the cold separator  76  and a cold hydroprocessed liquid stream in a cold bottoms line  80  extending from a bottom of the cold separator  76 . The cold separator  76  serves to separate hydrogen rich gas from hydrocarbon liquid in the hydroprocessed stream for recycle to the reactor section  12  in the cold overhead line  78 . The cold separator  76 , therefore, is in downstream communication with the hot overhead line  72  of the hot separator  70  and the hydroprocessing reactor  12 . The cold separator  76  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  12  and the hot separator  70  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  76  may be operated at pressures between about 3 MPa (gauge) (435 psig) and about 20 MPa (gauge) (2,900 psig). The cold separator  76  may also have a boot for collecting an aqueous phase. The cold hydroprocessed liquid stream in the cold bottoms line  80  may have a temperature of the operating temperature of the cold separator  76 . 
     The cold hydroprocessed vapor stream in the cold overhead line  78  is rich in hydrogen. Thus, hydrogen can be recovered from the cold hydroprocessed vapor stream. The cold hydroprocessed vapor stream in the cold overhead line  78  may be passed through a trayed or packed recycle scrubbing column  82  where it is scrubbed by means of a scrubbing extraction liquid such as an aqueous solution fed by line  84  to remove acid gases including hydrogen sulfide by extracting them into the aqueous solution. Preferred extraction liquids include Selexol available from UOP LLC in Des Plaines, Ill. and amines such as alkanolamines including diethanol amine (DEA), monoethanol amine (MEA), methyl diethanol amine (MDEA), diisopropanol amine (DIPA), and diglycol amine (DGA). Other amines can be used in place of or in addition to the preferred amines. The lean amine contacts the cold hydroprocessed vapor stream and absorbs acid gas contaminants such as hydrogen sulfide. The resultant “sweetened” cold vapor stream is taken out from an overhead outlet of the recycle scrubber column  82  in a recycle scrubber overhead line  86 , 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  88 . The spent scrubbing liquid from the bottoms may be regenerated and recycled back to the recycle scrubbing column  82  in the solvent line  84 . The scrubbed hydrogen-rich stream emerges from the scrubber via the recycle scrubber overhead line  86  and may be compressed in a recycle compressor  90 . The scrubbed hydrogen-rich stream in the scrubber overhead line  86  may be supplemented with make-up hydrogen stream in the make-up line  92  upstream or downstream of the compressor  90 . The compressed hydrogen stream supplies hydrogen to the hydrogen stream in the hydrogen line  28 . The recycle scrubbing column  82  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 temperature of the scrubbing extraction liquid stream in the solvent line  84  may be between about 38° C. (100° F.) and about 70° C. (158° F.). 
     The hydrocarbonaceous hot hydroprocessed liquid stream in the hot bottoms line  74  may be let down in pressure and fed to a hot flash drum  94 . The hot flash drum  94  separates a hot flash hydroprocessed vapor stream of light ends and hydrogen in a hot flash overhead line  96  extending from a top of the hot flash drum and a hot flash hydroprocessed liquid stream in a hot flash bottoms line  98  extending from a bottom of the hot flash drum  94 . The hot flash drum  94  may be in downstream communication with the hot bottoms line  74  and in downstream communication with the hydroprocessing reactor  12 . The hot flash drum  94  may be operated at the same temperature as the hot separator  70  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 hot flash hydroprocessed liquid stream taken in the hot flash bottoms line  98  may have a temperature of the operating temperature of the hot flash drum  94 . 
     In an aspect, the cold hydroprocessed liquid stream in the cold bottoms line  80  may be let down in pressure and flashed in a cold flash drum  100  to separate the cold hydroprocessed liquid stream in the cold bottoms line  80 . The cold flash drum  100  may be in direct, downstream communication with the cold bottoms line  80  of the cold separator  76  and in downstream communication with the hydroprocessing reactor  12 . The cold flash drum  100  may separate the cold hydroprocessed liquid stream in the cold bottoms line  80  to provide a cold flash hydroprocessed vapor stream in a cold flash overhead line  102  extending from a top of the cold flash drum  100  and a cold flash hydroprocessed liquid stream in a cold flash bottoms line  104  extending from a bottom of the cold flash drum. In an aspect, light gases such as hydrogen sulfide may be stripped from the cold flash hydroprocessed liquid stream in the cold flash bottoms line  104 . Accordingly, a stripping column  110  comprising a separation vessel of this embodiment may be in downstream communication with the cold flash drum  100  and the cold flash bottoms line  104 . 
     The cold flash drum  100  may be in downstream communication with the cold bottoms line  80  of the cold separator  76  and the hydroprocessing reactor  12 . The cold flash drum  100  may be operated at the same temperature as the cold separator  76  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 2.4 MPa (gauge) (350 psig) and about 3.8 MPa (gauge) (550 psig). A flashed aqueous stream may be removed from a boot in the cold flash drum  100 . The cold flash hydroprocessed liquid stream in the cold flash bottoms line  104  may have the same temperature as the operating temperature of the cold flash drum  100 . The cold flash hydroprocessed vapor stream in the cold flash overhead line  102  contains substantial hydrogen that may be recovered. 
     In an embodiment, the hot flash hydroprocessed vapor stream may be cooled in a cooler to condense heavier materials and fed to the cold flash drum  100  to be flashed with the cold hydroprocessed liquid stream in the cold bottoms line  80 . In an aspect, the cold bottoms line  80  may be joined by the hot flash overhead line  96  and receive the cooled hot flash hydroprocessed vapor stream in which case the cold bottoms line  80  delivers both streams, the cooled, hot flash hydroprocessed vapor stream and the cold hydroprocessed liquid stream, to the cold flash drum  100 . In this embodiment, the cold flash drum  100  may be in downstream communication with the hot flash overhead line  96  of the hot flash drum  94 . 
     The stripping column  110  may be in downstream communication with a separator  70 ,  76 ,  94 ,  100  or a bottoms line thereof for stripping volatile materials from the hydroprocessed stream. For example, the separation vessel may be the stripping column  110 . In an aspect, the stripping column  110  may be a separation vessel that contains a cold stripping column and a hot stripping column with a wall that isolates each of the stripping columns from the other. The stripping column  110  may be in downstream communication with the hydroprocessing reactor  12  for stripping a cold hydroprocessed liquid stream comprising either the cold hydroprocessed liquid stream in line  80  or the cold flash hydroprocessed liquid stream in line  104 . The stripping column  110  may be in downstream communication with the hydroprocessing reactor  12  for stripping a hot hydroprocessed liquid stream comprising either the hot hydroprocessed liquid stream in line  74  or the hot flash hydroprocessed liquid stream in line  98 . 
     The cold hydroprocessed liquid stream in the cold bottoms line  80  or the cold flash hydroprocessed liquid stream in the cold flash bottoms line  104  may be heated and fed to the stripping column  110  at an outlet  104   o  which may be in a top half of the column. The hot hydroprocessed liquid stream in the hot bottoms line  74  or the hot flash hydroprocessed liquid stream in the hot flash bottoms line  98  may be fed to the stripping column  110  at an outlet  98   o  below the inlet  104   o  for the cold hydroprocessed liquid stream. The cold hydroprocessed liquid stream or the cold flash hydroprocessed liquid stream and the hot hydroprocessed liquid stream or the hot flash hydroprocessed liquid stream may be stripped of gases by contact with a stripping media which is an inert gas such as steam from a stripping media line  112  to provide an overhead vapor stream of naphtha, hydrogen, hydrogen sulfide, steam and other gases in a separator overhead line  114  and a bottoms liquid stream in a separator bottoms line  116 . The separator overhead vapor stream in the separator overhead line  114  may be condensed and separated in a receiver  118 . A stripper net overhead line  120  from a stripper receiver  118  carries a net separator off gas of LPG, light hydrocarbons, hydrogen sulfide and hydrogen. Unstabilized liquid naphtha from the bottoms of the receiver  118  may be split between a reflux portion refluxed to the top of the stripping column  110  and a liquid stripper overhead stream which may be transported in a condensed stripper overhead line  122  to further recovery or processing. A sour water stream may be collected from a boot of the overhead receiver  118 . A product stream is provided in the bottoms liquid stream in the separator bottoms line  116  after cooling. The product stream is typically diesel in this embodiment and may be forwarded to a diesel product pool. 
     The stripping column  110  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 0.7 MPa (gauge) (100 psig), preferably no less than about 0.34 MPa (gauge) (50 psig), to no more than about 2.0 MPa (gauge) (290 psig). The temperature in the overhead receiver  116  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 stripping column  110 . 
     To reduce utilities in the separation vessel comprising the stripping column  110 , the process stream in the process line  54  is taken from the stripping column  110  and heated in the heat exchanger  40 . The process stream is fed through the third pass  56  and heat exchanged with the hydroprocessed effluent stream in line  50  from the hydroprocessing reactor  12  traveling through the shell side of the heat exchanger  40 . The heat exchanger  40  and particularly the third pass  56  may be in downstream communication, preferably direct downstream communication, with the stripping column  110 . The process stream in line  54  may be taken from an inlet  54   i  in a side  111  of the stripping column  110  and between an inlet  114   i  for the overhead line  114  and an inlet  116   i  for the bottoms line  116  and preferably below an outlet  98   o  of the hot flash liquid hydroprocessed stream in line  98  and an outlet  104   o  for the cold flash liquid hydroprocessed stream in line  104  and preferably above an outlet  112   o  for the stripping stream in line  112  to the stripping column  110 . The process stream may have an initial boiling point that is intermediate to an initial boiling point of the overhead vapor stream and the bottoms liquid stream. The process stream in the process line  54  is preferably taken as a liquid from a tray in the stripping column  110 . The process stream is heated in the third pass  56  in the heat exchanger  40  and returned in the return process line  58  to the stripping column  110  through an inlet  58   i  above the outlet  54   i . The stripping column  110  may be in downstream communication, preferably direct downstream communication, with the heat exchanger  40  and particularly the third pass  56  of the heat exchanger. 
       FIG. 2  shows an alternate embodiment of the process and apparatus of  FIG. 1  in which the hydroprocessing reactor  12 ′ is a hydrocracking reactor and the separator vessel is a product fractionation column  130 . 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 similar to  FIG. 1  with the following exceptions. 
     In the embodiment of  FIG. 2 , the hydroprocessing reactor  12 ′ is a hydrocracking reactor that can accommodate any of the previously listed feedstocks. Hydrocracking refers to a process in which hydrocarbons crack in the presence of hydrogen to lower molecular weight hydrocarbons. Consequently, the term “hydroprocessing” will include the term “hydrocracking” herein. Hydroprocessing that occurs in the hydroprocessing reactor  12 ′ may also comprise hydrotreating that precedes hydrocracking in the same hydroprocessing reactor  12 ′ or in separate reactors. 
     The hydroprocessing reactor  12 ′ may be a fixed bed reactor that comprises one or more vessels, single or multiple catalyst beds 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  12 ′ 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  12 ′ may also be operated in a conventional continuous gas phase, a moving bed or a fluidized bed hydroprocessing reactor. 
     The hydroprocessing reactor  12 ′ comprises a plurality of hydrocracking catalyst beds. If the hydroprocessing reactor  12 ′ does not include a preceding hydrotreating reactor, the catalyst beds in the hydroprocessing reactor  12 ′ may include a hydrotreating catalyst for the purpose of saturating, demetallizing, desulfurizing or denitrogenating the hydrocarbon feed stream before it is hydrocracked with the hydrocracking catalyst in subsequent vessels or catalyst beds in the hydroprocessing reactor  12 ′. 
     The hydroprocessing charge line  62  delivers the heated charge hydrocarbon feed stream to the hydroprocessing reactor  12 ′. The heated charge hydrocarbon feed stream is hydrocracked over a hydrocracking catalyst in the hydroprocessing reactor  12 ′ in the presence of a hydrogen stream to provide a hydroprocessed effluent stream. 
     The hydroprocessing reactor  12 ′ may provide a total conversion of at least about 20 vol % and typically greater than about 60 vol % of the charged hydrocarbon stream in the heated combined hydrocarbon feed stream in the charge line  62  to products boiling below the cut point of the heaviest desired product which is typically diesel. The hydroprocessing reactor  12 ′ 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 hydroprocessing reactor  12 ′ 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 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 hydroprocessing reactor  12 ′ 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. 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, 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 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 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 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. (200° F.) in order to activate the catalyst and decompose ammonium ions. Alternatively, the base component may 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. 4,363,178. 
     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 35° C. (600° F.) to about 441° C. (825° F.), a pressure from about 5.5 MPa (gauge) (800 psig) to about 3.8 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 embodiment of  FIG. 2  also includes a stripping column  110 ′ as described in  FIG. 1 , but the stripping column  110 ′ is not the separation vessel from which the process stream to be heated in the heat exchanger  40  is taken. The stripping column  110 ′ is in downstream communication with the hydroprocessing reactor  12 ′. The stripping column  110 ′ strips a cold liquid hydroprocessed effluent stream which may be the cold flash liquid hydroprocessed effluent stream in line  104  and the hot liquid hydroprocessed effluent stream which may be the hot flash liquid hydroprocessed effluent stream in line  98  by contact with a stripping stream from line  112  to remove volatile materials. The stripping column  110 ′ provides a stripped hydroprocessed vapor stream in the stripper overhead line  114  and a stripped liquid hydroprocessed stream in a stripper bottoms line  116 ′. At least a portion of the stripped hydroprocessed liquid stream in the stripper bottoms line  116 ′ may be fed without heating to the product fractionation column  130  comprising the separation vessel in this embodiment. The product fractionation column  130  may be in downstream communication with the stripped bottoms line  116 ′ and with the stripping column  110 ′. The product fractionation column  130  may also be in downstream communication with the hot separator  70 , the cold separator  76 , the hot flash stripper  94 , and the cold flash drum  100 . The product fractionation column  130  may comprise more than one fractionation column for separating the stripped hydroprocessed stream into product streams. The product fractionation column  130  may fractionate the stripped hydroprocessed liquid stream in line  116 ′ by contact with an inert stripping gas stream. The product fractionation column  130  being the separator vessel separates the stripped hydroprocessed liquid stream in line  116 ′ into an overhead vapor stream in a fractionation overhead line  132  and a bottoms liquid stream in a fractionation bottoms line  134 . 
     The overhead vapor stream in the fractionation overhead line  132  may be condensed in a condenser  133  and separated in a receiver  136  with a portion of the condensed liquid being refluxed back to the product fractionation column  130 . The net fractionated overhead liquid stream in line  138  may be further processed or recovered as naphtha product. The bottoms liquid stream in the fractionation bottoms line  134  may be separated between a reboil portion that is reboiled in a reboiler  142  and returned to the product fractionation column  130  and a product stream in a fractionation product line  144 . The product stream in the fractionation product line  144  may comprise diesel or an unconverted oil (UCO) stream boiling above the diesel cut point if a feed heavier than diesel is supplied as the hydrocarbon feed stream in line  18 . A portion or all of the UCO stream in the fractionation product line  144  may be purged from the process, recycled to the hydroprocessing reactor  12 ′ or forwarded to a second stage hydrocracking reactor (not shown). If a UCO stream is generated in the fractionation product line  144 , other product streams may be taken from a side  131  of the fractionation column  130  including an optional heavy naphtha stream in line  146  from a side cut outlet, a kerosene stream carried in line  148  from a side cut outlet and a diesel stream in diesel line  150  from a side outlet. 
     The product fractionation column  110  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 380° C. (715° F.), and at an overhead pressure between about 7 kPa (gauge) (1 psig) and about 69 kPa (gauge) (10 psig). 
     To reduce utilities in the product fractionation column  130  which is the separation vessel in this embodiment, the process stream in the process line  54 ′ is taken from the product fractionation column  130  and heated in the heat exchanger  40 . The process stream is fed through the third pass  56  and heat exchanged with the hydroprocessed effluent stream in line  50  from the hydroprocessing reactor  12 ′ in the shell side of the heat exchanger  40 . The heat exchanger  40  and particularly the third pass  56  may be in downstream communication, preferably in direct downstream communication, with the product fractionation column  130 , separation vessel. The process stream in line  54 ′ may be taken from an inlet  54   i ′ in a side  131  of the product fractionation column  130  and between an inlet  132   i  for the overhead line  132  and an inlet  134   i  for the bottoms line  134  and preferably below an outlet  116   o  of the stripped liquid hydroprocessed stream in line  116 ′ to the product fractionation column  130 . The process stream in line  54 ′ may have an initial boiling point that is intermediate to an initial boiling point of the fractionation overhead vapor stream and the fractionation bottoms liquid stream. The process stream in the process line  54 ′ is preferably taken as a liquid from a tray in the product fractionation column  130 . The process stream is heated in the third pass in the heat exchanger  40  and returned in the return process line  58 ′ to the product fractionation column  130  through an outlet  58   o ′ of the return process line above the inlet  54   i ′. The product fractionation column  130  may be in downstream communication, preferably in direct downstream communication, with the heat exchanger  40  and particularly the third pass  56  of the heat exchanger. 
     We have found that heating this process stream taken from the product fractionation column  130  and returning it to the fractionation column can reduce the heater duty for the reboiler  142  significantly compared to routinely heating the stripped hydroprocessed liquid stream before it enters the product fractionation column. Moreover, the heating of the process stream in this way also surprising reduces duty required of the overhead condenser  133 . These were surprising benefits that were only made possible by using a heat exchanger  40  that can exchange heat between hot streams that have a lower temperature differential such as an STHE. Because the process stream in line  54 ′ is already hot, effective heat exchange between the process stream and a hydroprocessed effluent stream had not been previously explored. 
     The rest of the process and apparatus  10 ′ are as described for  FIG. 1 . 
       FIG. 3  shows an alternate embodiment of the process and apparatus of  FIG. 2  in which the hydroprocessing reactor  12 ′ is a hydrocracking reactor and the separator vessel is in downstream communication with the stripping column  110 ′ and the product fractionation column  130 * is in downstream communication with the separator vessel. Elements in  FIG. 3  with the same configuration as in  FIG. 2  will have the same reference numeral as in  FIG. 2 . Elements in  FIG. 3  which have a different configuration as the corresponding element in  FIG. 2  will have the same reference numeral but designated with an asterisk symbol (*). The configuration and operation of the embodiment of  FIG. 3  is essentially the same as in  FIG. 2  with the following exceptions. 
     In  FIG. 3 , the separator vessel is a preflash drum  160  which separates the stripped hydroprocessed liquid stream into a preflash overhead vapor stream in line  162  and a preflash bottoms liquid stream in line  164 . The preflash overhead vapor stream in line  162  is fed to the product fractionation column  130 * and the preflash bottoms liquid stream in line  164  is split between a feed preflash bottoms liquid stream in line  166  and the process stream in line  54 *. The preflash bottoms liquid stream in line  166  is fed to a product fractionation feed preheater  142 * which supplants the reboiler  142  of  FIG. 2  for providing heat to the product fractionation column  130 *. A heated preflash bottoms liquid stream from the preheater  142 * is fed to the product fractionation column  130 * in line  168  through an outlet  168   o  below an outlet  162   o  for the preflash overhead vapor stream in line  162 . 
     To reduce utilities in the product fractionation column  130 *, the process stream in the process line  54 * is taken from a portion of the preflash bottoms liquid stream in in the preflash bottoms line  164  and heated in the heat exchanger  40 . The process stream is fed through the third pass  56  and heat exchanged with the hydroprocessed effluent stream in line  50  from the hydroprocessing reactor  12 ′ in the shell side of the heat exchanger  40 . The heat exchanger  40  and particularly the third pass  56  may be in downstream communication, preferably in direct downstream communication, with the preflash drum  160 , separation vessel. The process stream in line  54 * may be taken from a bottom of the preflash flash drum  160  from an inlet  164   i  preferably below an outlet  116   o * of the stripped liquid hydroprocessed stream in line  116 * to the preflash drum  160 . The process stream in the process line  54 * is heated in the third pass  56  in the heat exchanger  40  and returned in the return process line  58 * through an outlet  58   o * above the inlet  164   i  to line  164  and below the outlet  116   o * of the line  116 * to be preflashed before entering the product fractionation column  130 . The heated return process stream in line  58 * may alternatively be combined with the stripped hydroprocessed stream in line  116 * before it enters the preflash drum  160  together. The preflash drum  160  may be in downstream communication, preferably in direct downstream communication, with the heat exchanger  40  and particularly the third pass  56  of the heat exchanger. 
     The rest of the process and apparatus  10 * are as described for  FIG. 2 . 
     Example 
     We ran a simulation to determine the reduction in heater duty provided by heat exchanging a process stream taken from the product fractionation column against the hydroprocessed effluent stream compared to heating the stripped hydroprocessed liquid stream before it is fed to the product fractionation column. The return temperature is the temperature of the heated process stream fed to the product fractionation column. The comparison is shown in the Table. 
     
       
         
           
               
               
               
               
             
               
                 TABLE 
               
               
                   
               
               
                   
                   
                 Base 
                 Multi stream 
               
               
                   
                 Unit 
                 Case 
                 STHE 
               
               
                   
               
             
            
               
                 Stripped Hydroprocessed Liquid 
                 MMBtu/hr  
                 45 (11) 
                  0 
               
               
                 Stream Exchanger Duty 
                 (MMkcal/hr) 
                   
                   
               
               
                 Product Fractionation Process 
                 MMBtu/hr  
                 0 
                 45 (11) 
               
               
                 Stream Reboiler Duty 
                 (MMkcal/hr) 
                   
                   
               
               
                 Return Temperature 
                 ° F. (° C.) 
                   
                 483 (250) 
               
               
                 Product Fractionator Reboiler 
                 MMBtu/hr  
                 98.3  
                 84.6 (21.3) 
               
               
                 Heater Duty 
                 (MMkcal/hr) 
                 (24.7) 
                   
               
               
                 Product Fractionator Overhead 
                 MMBtu/hr  
                 142.6  
                 129 (32.5) 
               
               
                 Condenser Duty 
                 (MMkcal/hr) 
                 (36.0) 
                   
               
               
                 Heater Duty Reduction 
                 % 
                 Base 
                 16 
               
               
                 Condenser duty reduction 
                 % 
                 Base 
                 11 
               
               
                   
               
            
           
         
       
     
     Heat exchanging a process stream taken from the product fractionation column against the hydroprocessed effluent stream and returning it to the column in this way can reduce the fractionator reboiler heater duty by up to 13.7 MMBtu/hr (3.5 MMkcal/hr) based on a recent design, worth 350,000 $/year based on US Gulf Coast prices compared with routinely preheating the stripped feed to the product fractionation column. Additionally, the condenser duty is surprisingly reduced as well by a similar duty. This additional benefit is very significant and is made feasible by using a STHE. 
     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 disclosure is a hydroprocessing process comprising hydroprocessing a hydrocarbon feed stream in a hydroprocessing reactor with a hydrogen stream over hydroprocessing catalyst to provide hydroprocessed effluent stream; separating the hydroprocessed effluent stream to provide a hydroprocessed vapor stream and a hydroprocessed liquid stream; and separating the hydroprocessed liquid stream in a separation vessel into an overhead vapor stream and a bottoms liquid stream; and heating a hydroprocessing process stream taken from the separation vessel to provide a heated process stream and returning the heated process stream to the separation vessel. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising heating the process stream by heat exchange. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising heating the process stream by heat exchange with the hydroprocessed effluent stream. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising heating the hydrocarbon feed stream and the process stream simultaneously by heat exchange with the hydroprocessed effluent stream. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising splitting the hydrocarbon feed stream into at least a first feed stream and a second feed stream and simultaneously heating the first hydrocarbon feed stream, the second hydrocarbon feed stream and the process stream by heat exchange with the hydroprocessed effluent stream. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising performing the heat exchange in a spiral tube heat exchanger. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising stripping the hydroprocessed liquid stream by contact with a stripping stream to remove volatile materials in the separation vessel to provide the overhead vapor stream and the bottoms liquid stream. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph wherein the process stream is taken from a side of the separation vessel. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph wherein separating the hydroprocessed effluent stream to provide a hydroprocessed vapor stream and a hydroprocessed liquid stream further comprises stripping a hot hydroprocessed liquid stream by contact with a stripping stream to remove volatile materials to provide the hydroprocessed liquid stream and the hydroprocessed vapor stream. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising taking the process stream from the bottoms liquid stream from the separation vessel. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising taking a fractionation feed stream from the bottoms liquid stream and fractionating the fractionation feed stream. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising fractionating the hydroprocessed liquid stream in the separation vessel. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising taking the process stream from the separation vessel having an initial boiling point that is intermediate to an initial boiling point of the overhead vapor stream and the bottoms liquid stream. 
     A second embodiment of the disclosure is a separation process comprising separating a stream in a separation vessel to provide an overhead vapor stream and a bottoms liquid stream; taking a process stream from the separation vessel having an initial boiling point that is intermediate to an initial boiling point of the overhead vapor stream and the liquid bottoms stream; and heat exchanging the process stream in a spiral tube heat exchanger. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph further comprising heat exchanging the process stream with a hot stream in a shell side of the spiral tube heat exchanger. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph simultaneously heat exchanging the process stream and another stream with a hot stream in the spiral tube heat exchanger. 
     A third embodiment of the disclosure is a hydroprocessing apparatus comprising a hydroprocessing reactor; a separation vessel in downstream communication with the hydroprocessing reactor; and a heat exchanger having a pass in downstream communication with the separation vessel and the separation vessel in downstream communication with the pass of the heat exchanger. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph wherein the separation vessel is a stripping column. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph further comprising a stripping column in downstream communication with the hydroprocessing reactor and the separation vessel is in downstream communication with the stripping column. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph wherein the separation vessel is a fractionation column with a reboiler on a bottoms line. 
     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.