Abstract:
In the refining of crude oil, vacuum gas oil hydrotreaters and hydrocrackers are used to remove impurities such as sulfur, nitrogen, and metals from the crude oil. Typically, the middle distillate boiling material (boiling in the range from 250° F.-735° F.) from VGO hydrotreating or moderate severity hydrocrackers does not meet the smoke point, the cetane number or the aromatic specification. In most cases, this middle distillate is separately upgraded by a middle distillate hydrotreater or, alternatively, the middle distillate is blended into the general fuel oil pool or used as home heating oil. With this invention, the middle distillate is hydrotreated in the same high pressure loop as the vacuum gas oil hydrotreating reactor or the moderate severity hydrocracking reactor. The investment cost saving and/or utilities saving are significant since a separate middle distillate hydrotreater is not required A major benefit of this invention is the potential for simultaneously upgrading difficult cracked stocks such as Light Cycle Oil, Light Coker Gas Oil and Visbroken Gas Oil or Straight-Run Atmospheric Gas Oils utilizing the high-pressure environment required for mild hydrocracking.

Description:
FIELD OF THE INVENTION  
         [0001]    This invention is directed to processes for upgrading the fraction boiling in the middle distillate range which is obtained from VGO hydrotreaters or moderate severity hydrocrackers. This invention involves a multiple-stage process employing a single hydrogen loop.  
         BACKGROUND OF THE INVENTION  
         [0002]    In the refining of crude oil, vacuum gas oil hydrotreaters and hydrocrackers are used to remove impurities such as sulfur, nitrogen, and metals from the crude oil. Typically, the middle distillate boiling material (boiling in the range from 250° F.-735° F.) from VGO hydrotreating or moderate severity hydrocrackers does not meet the smoke point, the cetane number or the aromatic specification. In most cases, this middle distillate is separately upgraded by a middle distillate hydrotreater or, alternatively, the middle distillate is blended into the general fuel oil pool or used as home heating oil. There are also streams in the diesel boiling range, from other units such as Fluid Catalytic Cracking, Delayed Coking and Visbreaking that require upgrading. Very often, existing diesel hydrotreaters are not designed to the pressure limits required to process these streams and the mild hydrocracking unit provides an opportunity for simultaneous upgrading of these streams.  
           [0003]    There have been some previously disclosed processes in which hydroprocessing occurs within a single hydroprocessing loop. International Publication No. WO 97/38066 (PCT/US97/04270), published Oct. 16, 1997, discloses a process for reverse staging in hydroprocessing reactor systems. This hydroprocessor reactor system comprises two reactor zones, one on top of the other, in a single reaction loop. In the preferred embodiment, a hydrocarbon feed is passed to a denitrification and desulfurization zone, which is the lower zone. The effluent of this zone is cooled and the gases are separated from it. The liquid product is then passed to the upper zone, where hydrocracking or hydrotreating may occur. Deeper treating preferably occurs in the upper zone.  
           [0004]    U.S. Pat. No. 5,980,729 discloses a configuration similar to that of WO 97/38066. A hot stripper is positioned downstream from the denitrification/desulfurization zone, however. Following this stripper is an additional hydrotreater. There is also a post-treat reaction zone downstream of the denitrification/desulfurization zone in order to saturate aromatic compounds. U.S. Pat. No. 6,106,694 discloses a similar configuration to that of U.S. Pat. No. 5,980,729, but without the hydrotreater following the stripper and the post-treat reaction zone.  
         SUMMARY OF THE INVENTION  
         [0005]    With this invention, the middle distillate is hydrotreated in the same high pressure loop as the vacuum gas oil hydrotreating reactor or the moderate severity hydrocracking reactor, but the reverse staging configuration employed in the references is not employed in the instant invention. The investment cost saving and/or utilities saving involved in the use of a single hydrogen loop are significant since a separate middle distillate hydrotreater is not required. Other advantages include optimal hydrogen pressures for each step, as well as optimal hydrogen consumption and usage for each product. There is also a maximum yield of upgraded product, without the use of recycle liquid. The invention is summarized below.  
           [0006]    A method for hydroprocessing a hydrocarbon feedstock, said method employing at least two reaction zones within a single reaction loop, comprising the following steps:  
           [0007]    (a) passing a hydrocarbonaceous feedstock to a first hydroprocessing zone having one or more beds containing hydroprocessing catalyst, the hydroprocessing zone being maintained at hydroprocessing conditions, wherein the feedstock is contacted with catalyst and hydrogen;  
           [0008]    (b) passing the effluent of step (a) directly to a hot high pressure separator, wherein the effluent is contacted with a hot, hydrogen-rich stripping gas to produce a vapor stream comprising hydrogen, hydrocarbonaceous compounds boiling at a temperature below the boiling range of the hydrocarbonaceous feedstock, hydrogen sulfide and ammonia and a liquid stream comprising hydrocarbonaceous compounds boiling approximately in the range of said hydrocarbonaceous feedstock;  
           [0009]    (c) passing the vapor stream of step (b), after cooling and partial condensation, to a hot hydrogen stripper containing at least one bed of hydrotreating catalyst, where it is contacted countercurrently with hydrogen, while the liquid stream of step (b) is passed to fractionation;  
           [0010]    (d) passing the overhead vapor stream from the hot hydrogen stripper of step (c), after cooling and contacting with water, the overhead vapor stream comprising hydrogen, ammonia, and hydrogen sulfide, along with light gases and naphtha to a cold high pressure separator, where hydrogen, hydrogen sulfide and light hydrocarbonaceous gases are removed overhead, ammonia is removed from the cold high pressure separator as ammonium bisulfide in the sour water stripper, and naphtha and middle distillates are passed to fractionation;  
           [0011]    (e) passing the liquid stream from the hot hydrogen stripper of step (c) to a second hydroprocessing zone, the second hydroprocessing zone containing at least one bed of hydroprocessing catalyst suitable for aromatic saturation and ring opening, wherein the liquid is contacted under hydroprocessing conditions with the hydroprocessing catalyst, in the presence of hydrogen;  
           [0012]    (f) passing the overhead from the cold high pressure separator of step (d) to an absorber, where hydrogen sulfide is removed before hydrogen is compressed and recycled to hydroprocessing vessels within the loop; and  
           [0013]    (g) passing the effluent of step (e) to the cold high pressure separator of step (d). 
       
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0014]    [0014]FIG. 1 illustrates a hydroprocessing loop in which the post-treatment reactor is a middle distillate upgrader which operates at approximately the same pressure as the first stage reactor.  
         [0015]    [0015]FIG. 2 illustrates a hydroprocessing loop in which the post-treatment reactor is the same as that of FIG. 1, but operates at lower pressure than the first stage reactor. A noble metal catalyst is used in the post-treatment reactor. 
     
    
     DETAILED DESCRIPTION OF THE INVENTION  
       [0016]    Description of the Preferred Embodiment  
         [0017]    Description of FIG. 1  
         [0018]    Feed in stream  1  is mixed with recycle hydrogen and make-up hydrogen in stream  42 . The feed has been preheated in a process heat exchanger train, as are the gas streams. The mixture of feed and gas, now in stream  34 , is further heated using heat exchangers  43  and furnace  49 . Stream  34  then enters the first stage downflow fixed bed reactor  2 . The first bed  3  of reactor  2  may contain VGO hydrotreater catalyst or a moderate severity hydrocracker catalyst. There may be a succession of fixed beds  3 , with interstage quench streams,  4  and  5  delivering hydrogen in between the beds.  
         [0019]    The effluent  6  of the first stage reactor  2 , which has been hydrotreated and partially hydrocracked, contains hydrogen sulfide, ammonia, light gases, naphtha, middle distillate and hydrotreated vacuum gas oil. The effluent enters the hot high pressure separator or flash zone  8  at heavy oil reactor effluent conditions where part of the diesel and most of the lighter material is separated from the unconverted oil. The hot high pressure separator has a set of trays  44  with hydrogen rich gas introduced at the bottom for stripping through stream  46 .  
         [0020]    Stream  9  is primarily hydrotreated heavy gas oil, boiling at temperatures greater than 700° F. The valve  10  indicates that pressure is reduced before the unconverted oil is sent to the fractionation section in stream  11 .  
         [0021]    Stream  21  contains the overhead from the hot high pressure separator. Stream  21  is cooled in exchanger  22  (by steam generation or process heat exchange) before entering the hot hydrogen stripper/reactor  23 . Stream  21  flows downwardly through a bed of hydrotreating catalyst  52 , while being contacted with countercurrent flowing hydrogen from stream  51 .  
         [0022]    The overhead stream  26  contains hydrogen, ammonia and hydrogen sulfide, along with light gases and naphtha. The differential operating pressure between the hot hydrogen stripper/reactor  23  and cold high pressure separator  17  is maintained by control valve  50 . Stream  26  is cooled in exchanger  27  and joins stream  14  to form stream  16 . Water is injected (stream  36 ) into the stream  16  to remove most of the ammonia as ammonium bisulfide solution (ammonia and hydrogen sulfide react to form ammonium bisulfide which is converted to solution by water injection). The stream is then air cooled by cooler  45 . The stream  16  enters the cold high pressure separator  17 . Hydrogen, light hydrocarbonaceous gases, and hydrogen sulfide are removed overhead through stream  19 . Hydrogen sulfide is removed from the stream in the hydrogen sulfide absorber  20 . Ammonia and hydrogen sulfide are removed with the sour water stream (not shown) from the cold high pressure separator  17 .  
         [0023]    Stream  40 , which contains hydrogen-rich gas, is compressed in compressor  30  and splits into streams  29  and  32 . Stream  32  passes to the hot hydrogen stripper/reactor  23 . Stream  31  is diverted from stream  29  for use as interstage quench. Streams  4  and  5  are diverted from stream  31 . Stream  29 , containing hydrogen, is combined with hydrogen stream  42  prior to combining with oil feed stream  1 .  
         [0024]    Make-up hydrogen  38  is compressed and sent to four separate locations, upstream of reactor  2  to combine with feed stream  1  (through stream  42 ), to the hot high pressure separator  8  through stream  46 , to the hot hydrogen stripper/reactor through stream  51 , and to the middle distillate upgrader (stream  35 ) to combine with recycle diesel or kerosene or to be used as interstage quench. Stream  38 , containing make-up hydrogen, passes to the make-up hydrogen compressor  37 . From stream  41 , which exits compressor  37  containing compressed hydrogen, streams  35 ,  42  and  46  are diverted.  
         [0025]    The middle distillate upgrader  12  consists of one or more multiple beds  13  of hydrotreating/hydrocracking catalyst (such as Ni—Mo, Ni—W and/or noble metal) for aromatic saturation and ring opening to improve diesel product qualities such as aromatic level and cetane index. In the embodiment of FIG. 1, the middle distillate upgrader is operated at approximately the same pressure as the first stage reactor  2 . Quench gas (stream  47 ) may be introduced in order to control reactor temperature. Stream  24  may be combined with recycle diesel or kerosene (stream  48 ) from the fractionator when no other external feeds (stream  7 ) are to be processed and cooled in exchanger  25 . Hydrogen from stream  35  is combined with stream  24  prior to entering the middle distillate upgrader  12 . Stream  24  enters the reactor at the top and flows downwardly through the catalyst beds  13 .  
         [0026]    Stream  14 , which is the effluent from the middle distillate upgrader  12 , is used to heat the other process streams in the unit (see exchanger  15 ) and then joins with stream  26  to form stream  16 , which is sent to the effluent air cooler and then to the cold high-pressure separator  17 . Water is continuously injected into the inlet piping of the effluent air cooler to prevent the deposition of salts in the air cooler tubes. In the cold high pressure separator  17 , hydrogen, hydrogen sulfide and ammonia leave through the overhead stream  19 , while naphtha and middle distillates exit through stream  18  to fractionation (stream  39 ).  
         [0027]    Description of FIG. 2  
         [0028]    As described in FIG. 1, feed in stream  1  is mixed with recycle hydrogen and make-up hydrogen in stream  42 . The feed has been preheated in a process heat exchange train as are the gas streams. The mixture of feed and gas, now in stream  34 , is further heated using heat exchangers  43  and furnace  51 . Stream  34  then enters the first stage downflow fixed bed reactor  2 . The first bed  3  of reactor  2  may contain VGO hydrotreater catalyst or a moderate severity hydrocracker catalyst. There may be a succession of fixed beds  3 , with interstage quench streams,  4  and  5  delivering hydrogen in between the beds.  
         [0029]    The effluent  6  of the first stage reactor, which has been hydrotreated and partially hydrocracked, contains hydrogen sulfide, ammonia, light gases, naphtha, middle distillate and hydrotreated vacuum gas oil. The effluent enters the hot high pressure separator or flash zone  8  at heavy oil reactor effluent conditions where part of the diesel and most of the lighter material is separated from the unconverted oil. The hot high pressure separator has a set of trays  44  with hydrogen rich gas introduced at the bottom for stripping through stream  46 .  
         [0030]    Stream  9  is primarily hydrotreated heavy gas oil, boiling at temperatures greater than 700° F. The valve  10  indicates that pressure is reduced before the unconverted oil is sent to the fractionation section in stream  11 .  
         [0031]    Stream  21  contains the overhead from the hot high pressure separator and  33  may be joined by external feed  7 . Stream  21  is then cooled in exchanger  22  (by steam generation or process heat exchange) before entering the hot hydrogen stripper/reactor  23 . Stream  21  flows downwardly through a bed of hydrotreating catalyst  52 , while being contacted with countercurrent flowing hydrogen from stream  32 .  
         [0032]    The overhead stream  26  from hot hydrogen stripper/reactor  52  contains hydrogen, ammonia and hydrogen sulfide, along with light gases and naphtha. It is cooled in exchanger  27 . Water is injected (stream  36 ) into the stream  26  to remove most of the ammonia as ammonium bisulfide solution (ammonia and hydrogen sulfide react to form ammonium bisulfide which is converted to solution by water injection). The stream is then air cooled by cooler  45 . The effluent from the air cooler enters the cold high pressure separator  17 . Hydrogen, light hydrocarbonaceous gases, and hydrogen sulfide are removed overhead through stream  19 . Hydrogen sulfide is removed (stream  51 ) from the stream in the hydrogen sulfide absorber  20 . Ammonia and hydrogen sulfide is removed with the sour water stream (stream  48 ) from the cold high pressure separator  17 . Stream  40 , which contains hydrogen, is compressed in compressor  30  and splits into streams  29  and  31 . Stream  31  is diverted from stream  29  for use as interstage quench. Streams  4  and  5  are diverted from stream  31 . Stream  29 , containing hydrogen, is combined with hydrogen stream  42  prior to combining with oil feed stream  1 .  
         [0033]    Make-up hydrogen  38  is compressed and sent to four separate locations, upstream of reactor  2  to combine with feed stream  1  (through stream  42 ), to the hot high pressure separator  8  through stream  46 , to the hot hydrogen stripper/reactor  23 , and to the middle distillate upgrader (stream  35 ) to combine with recycle diesel or kerosene or to be used as interstage quench. Stream  38 , containing make-up hydrogen, passes to the make-up hydrogen compressor  37 . From stream  41 , which exits compressor  37  containing compressed hydrogen, streams  35 ,  42  and  46  are diverted.  
         [0034]    In this embodiment, the middle distillate upgrading reactor  12  operates at lower pressure than the first stage reactor  2 . Liquid (stream  24 ) from the hot hydrogen stripper  52  is reduced in pressure (via valve  28 ) and is combined with make-up hydrogen (stream  35 ) after the second stage of compression of the make-up hydrogen compressor  37 . Recycle kerosene or diesel (stream  50 ) may be added at this point. The mixture is sent after preheat (in exchanger  25 ) to the middle distillate upgrader  12 , which is preferably loaded with one or more beds of noble metal catalyst  13 . Part of the make-up hydrogen is available as quench (stream  47 ) between the beds for multiple bed application. Reactor effluent (stream  14 ) is cooled in a series of heat exchangers  15  and sent to a cold high pressure separator  49 .  
         [0035]    Overhead vapor  38  from the cold high pressure separator  49  is essentially high-purity hydrogen with a small amount of hydrocarbonaceous light gases. The vapor is sent to the make-up hydrogen compressor  37 . Compressed make-up hydrogen (stream  29 ) is sent to the high pressure reactor  2 , the high pressure separator  8 , and hot hydrogen stripper/reactor  23 . Bottoms (stream  18 ) from the cold high-pressure separator  17  is sent to the fractionation section (stream  53 ) after pressure reduction.  
         [0036]    Stream  14 , which is the effluent from the middle distillate upgrader  12 , is used to heat the other process streams in the unit (see exchanger  15 ) and passes to the cold high pressure separator  49 . The liquid effluent of cold high pressure separator  49 , stream  39 , passes to fractionation.  
         [0037]    Feeds  
         [0038]    A wide variety of hydrocarbon feeds may be used in the instant invention. Typical feedstocks include any heavy or synthetic oil fraction or process stream having a boiling point above 300° F. (150° C.). Such feedstocks include vacuum gas oils, heavy atmospheric gas oil, delayed coker gas oil, visbreaker gas oil, demetallized oils, vacuum residua, atmospheric residua, deasphalted oil, Fischer-Tropsch streams, FCC streams, etc.  
         [0039]    For the first reaction stage, typical feeds will be vacuum gas oil, heavy coker gas oil or deasphalted oil. Lighter feeds such as straight run diesel, light cycle oil, light coker gas oil or visbroken gas oil can be introduced upstream of the hot hydrogen stripper/reactor  23 .  
         [0040]    Products  
         [0041]    [0041]FIGS. 1 and 2 depict two different versions of the instant invention, directed primarily to high quality middle distillate production as well as to production of heavy hydrotreated gas oil.  
         [0042]    The process of this invention is especially useful in the production of middle distillate fractions boiling in the range of about 250° F.-700° F. (121° C.-371° C.). A middle distillate fraction is defined as having a boiling range from about 250° F. to 700° F. At least 75 vol %, preferably 85 vol %, of the components of the middle distillate have a normal boiling point of greater than 250° F. At least about 75 vol %, preferably 85 vol %, of the components of the middle distillate have a normal boiling point of less than 700° F. The term “middle distillate” includes the diesel, jet fuel and kerosene boiling range fractions. The kerosene or jet fuel boiling point range refers to the range between 280° F. and 525° F. (138° C.-274° C.). The term “diesel boiling range” refers to hydrocarbons boiling in the range from 250° F. to 700° F. (121° C.-371° C.).  
         [0043]    Gasoline or naphtha may also be produced in the process of this invention. Gasoline or naphtha normally boils in the range below 400° F. (204° C.), or C 5 —. Boiling ranges of various product fractions recovered in any particular refinery will vary with such factors as the characteristics of the crude oil source, local refinery markets and product prices.  
         [0044]    Heavy diesel, another product of this invention, usually boils in the range from 550° F. to 750° F.  
         [0045]    Conditions  
         [0046]    Hydroprocessing conditions is a general term which refers primarily in this application to hydrocracking or hydrotreating, preferably hydrocracking. The first stage reactor, as depicted in FIGS. 1 and 2, may be either a VGO hydrotreater or a moderate severity hydrocracker.  
         [0047]    Hydrotreating conditions include a reaction temperature between 400° F.-900° F. (204° C.-482° C.), preferably 650° F.-850° F. (343° C.-454° C.); a pressure from 500 to 5000 psig (pounds per square inch gauge) (3.5-34.6 MPa), preferably 1000 to 3000 psig (7.0-20.8 MPa); a feed rate (LHSV) of 0.5 hr −1  to 20 hr −1  (v/v); and overall hydrogen consumption 300 to 5000 scf per barrel of liquid hydrocarbon feed (53.4-356 m 3 /m 3  feed).  
         [0048]    In the embodiment shown in FIG. 1, the first stage reactor and the middle distillate upgrader are operating at the same pressure. In the embodiment shown in FIG. 2, the middle distillate upgrader is operating at a lower pressure than the first stage reactor.  
         [0049]    Typical hydrocracking conditions include a reaction temperature of from 400° F.-950° F. (204° C.-510° C.), preferably 650° F.-850° F. (343° C. -454° C.). Reaction pressure ranges from 500 to 5000 psig (3.5-34.5 MPa), preferably 1500 to 3500 psig (10.4-24.2 MPa). LHSV ranges from 0.1 to 15 hr −1  (v/v), preferably 0.25-2.5 hr −1 . Hydrogen consumption ranges from 500 to 2500 scf per barrel of liquid hydrocarbon feed (89.1-445 m 3  H 2 /m 3  feed).  
         [0050]    Catalyst  
         [0051]    A hydroprocessing zone may contain only one catalyst, or several catalysts in combination.  
         [0052]    The hydrocracking catalyst generally comprises a cracking component, a hydrogenation component and a binder. Such catalysts are well known in the art. The cracking component may include an amorphous silica/alumina phase and/or a zeolite, such as a Y-type or USY zeolite. Catalysts having high cracking activity often employ REX, REY and USY zeolites. The binder is generally silica or alumina. The hydrogenation component will be a Group VI, Group VII, or Group VIII metal or oxides or sulfides thereof, preferably one or more of molybdenum, tungsten, cobalt, or nickel, or the sulfides or oxides thereof. If present in the catalyst, these hydrogenation components generally make up from about 5% to about 40% by weight of the catalyst. Alternatively, platinum group metals, especially platinum and/or palladium, may be present as the hydrogenation component, either alone or in combination with the base metal hydrogenation components molybdenum, tungsten, cobalt, or nickel. If present, the platinum group metals will generally make up from about 0.1% to about 2% by weight of the catalyst.  
         [0053]    Hydrotreating catalyst, if used, will typically be a composite of a Group VI metal or compound thereof, and a Group VIII metal or compound thereof supported on a porous refractory base such as alumina. Examples of hydrotreating catalysts are alumina supported cobalt-molybdenum, nickel sulfide, nickel-tungsten, cobalt-tungsten and nickel-molybdenum. Typically, such hydrotreating catalysts are presulfided.  
       EXAMPLE  
       [0054]    [0054]                                             POST-HYDROTREATING OF MILD HYDROCRACKER       DISTILLATES FOR CETANE UPGRADING                Mild Hydrocracked   Mild Hydrocracked           Distillate from   Distillate from           Vacuum Gas Oil/   Middle Eastern           Coker Gas Oil       Feed   Blend   Vacuum Gas Oil               Mild Hydrocracking   30 Liquid Volume %   31 Liquid Volume %       Conversion   &lt;680° F.   &lt;700° F.       Hydrotreating Catalyst   Noble metal/Zeolite   Base metal/Alumina       Hydrotreating       Conditions:       Catalyst Bed   594   720       Temperature, ° F.       LHSV, 1/hr   1.5   2.0       Gas/Oil Ratio, SCF/B   3000   5000       H 2  Partial Pressure, psia   800   1900       Cetane Uplift (typical)   7 to 15   2 to 7                    
         [0055]    The Table above illustrates the effectiveness of upgrading the effluent of the first stage reactor, which has been mildly hydrocracked. The effluent is hydrotreated in the middle distillate upgrader. Cetane uplift (improvement) is greater, and at less severe conditions, using a catalyst having a noble metal hydrogenation component with a zeolite cracking component than when using a catalyst having base metal hydrogenation components on alumina, an amorphous support. Cetane uplift can be higher if external diesel range feeds ( 7 ) are added upstream of Hot High Pressure Separator  44 .