Patent Application
20180179456
The field is the hydrocracking of hydrocarbon streams, particularly two-stage hydrocracking and saturation of hydrocarbon streams.
Hydroprocessing can include processes which convert hydrocarbons in the presence of hydroprocessing catalyst and hydrogen to more valuable products. Hydrocracking is a hydroprocessing process in which hydrocarbons crack in the presence of hydrogen and hydrocracking catalyst to lower molecular weight hydrocarbons. Depending on the desired output, a hydrocracking unit may contain one or more fixed beds of the same or different catalyst.
Two-stage hydrocracking processes involve fractionation of a hydrocracked stream from a first stage hydrocracking reactor followed by hydrocracking of an unconverted oil (UCO) stream in a second stage hydrocracking reactor. However, the best two-stage hydrocracking process cannot achieve full conversion to materials boiling below the diesel cut point. Typically, a bottoms stream from the fractionation column in two-stage hydrocracking comprises a recycle oil (RO) stream and an UCO stream. The RO is recycled to the second stage hydrocracking reactor while the UCO is purged from the process to remove unconvertible heavy polynuclear aromatics (HPNA's) from the process. HPNA's are fused aromatic rings comprising more than eight rings. HPNA's in RO and UCO can cause significant adverse impact on hydrocracking operations such as fouling of the exchangers and coking on the catalyst. Several processes are available to manage HPNA rejection, such as steam stripping and adsorption
Hydrotreating is a process in which hydrogen is contacted with a hydrocarbon stream in the presence of hydrotreating catalysts which are primarily active for the removal of heteroatoms, such as sulfur, nitrogen and metals, such as iron, nickel, and vanadium 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. Resid hydrotreating is a hydrotreating process to remove metals, sulfur and nitrogen from an atmospheric or vacuum resid (VR) feed, so that it can be cracked to valuable fuel products.
Global crude oil consumption continues to increase especially in the developing countries and fuel specifications also continue to tighten. The outlets for residue fuel oil are decreasing, while the availability of heavy, sour crudes are increasing. The gas oil fraction of the atmospheric residue (AR) can be processed by hydrocracking to produce diesel fuels while the VR fraction can be converted into distillate fuels by a primary upgrading process such as slurry hydrocracking.
It would be highly desirable to have a combined solution to process the entire AR stream.
A process and apparatus for two stage hydrocracking of a resid feed stream involves the saturation of aromatics including PNA's from the first stage hydrocracking unit to prevent formation of HPNA's in the second stage hydrocracking unit. The saturated PNA's can be hydrocracked in the second stage to minimize or eliminate purged unconverted oil to approach or obtain maximum conversion. In an aspect, a separator may be used to flash gas from hydrotreated resid fed to the first stage hydrocracking reactor. The separator and the first stage hydrocracking reactor may be located in the same vessel.
The term “communication” means that material flow is operatively permitted between enumerated components.
The term “downstream communication” means that at least a portion of material flowing to the subject in downstream communication may operatively flow from the object with which it communicates.
The term “upstream communication” means that at least a portion of the material flowing from the subject in upstream communication may operatively flow to the object with which it communicates.
The term “direct communication” means that flow from the upstream component enters the downstream component without undergoing a compositional change due to physical fractionation or chemical conversion.
The term “column” means a distillation column or columns for separating one or more components of different volatilities. Unless otherwise indicated, each column includes a condenser on an overhead of the column to condense and reflux a portion of an overhead stream back to the top of the column and a reboiler at a bottom of the column to vaporize and send a portion of a bottoms stream back to the bottom of the column. Absorber and scrubbing columns do not include a condenser on an overhead of the column to condense and reflux a portion of an overhead stream back to the top of the column and a reboiler at a bottom of the column to vaporize and send a portion of a bottoms stream back to the bottom of the column. Feeds to the columns may be preheated. The overhead pressure is the pressure of the overhead vapor at the vapor outlet of the column. The bottom temperature is the liquid bottom outlet temperature. Overhead lines and bottoms lines refer to the net lines from the column downstream of any reflux or reboil to the column unless otherwise indicated. Stripping columns omit a reboiler at a bottom of the column and instead provide heating requirements and separation impetus from a fluidized inert vaporous media such as steam.
As used herein, the term “True Boiling Point” (TBP) means a test method for determining the boiling point of a material which corresponds to ASTM D-2892 for the production of a liquefied gas, distillate fractions, and residuum of standardized quality on which analytical data can be obtained, and the determination of yields of the above fractions by both mass and volume from which a graph of temperature versus mass % distilled is produced using fifteen theoretical plates in a column with a 5:1 reflux ratio.
As used herein, the term “initial boiling point” (IBP) means the temperature at which the sample begins to boil using ASTM D-6352.
As used herein, the term “T5”, “T70” or “T95” means the temperature at which 5 mass percent, 70 mass percent or 95 mass percent, as the case may be, respectively, of the sample boils using ASTM D-6352.
As used herein, the term “diesel cut point” is between about 343° C. (650° F.) and about 399° C. (750° F.) using the TBP distillation method.
As used herein, the term “diesel boiling range” means hydrocarbons boiling in the range of between about 132° C. (270° F.) and the diesel cut point using the TBP distillation method.
As used herein, the term “separator” means a vessel which has an inlet and at least an overhead vapor outlet and a bottoms liquid outlet and may also have an aqueous stream outlet from a boot. A flash drum is a type of separator which may be in downstream communication with a separator which latter may be operated at higher pressure.
As used herein, the term “polynuclear aromatics” (PNA) means an aromatic hydrocarbon comprising more than three but less than eight rings fused aromatic rings.
As used herein, the term “heavy polynuclear aromatics” (HPNA) means an aromatic hydrocarbon comprising eight or more fused aromatic rings.
The subject process and apparatus converts a resid feed stream into distillate fuels through combination of resid hydrotreating and two stages of hydrocracking. In the second stage of hydrocracking, aromatics including PNA's are substantially saturated to prevent HPNA formation and to minimize or eliminate a purge of unconverted oil (UCO), thereby improving overall conversion and yields. Formation of HPNA's is mainly due to condensation of polynuclear aromatics (PNA's) existing in RO. Saturation of PNA's in RO can reduce or eliminate HPNA formation in a second stage of hydrocracking, which then results in reducing or eliminating the UCO purge.
The subject apparatus and process minimizes or eliminates UCO production and HPNA management by integrating catalytic aromatics saturation in the second hydrocracking stage to enhance diesel yield selectivity and achieve near full conversion.
The apparatus and process 10 for hydrocracking a hydrocarbon stream comprise a first stage hydrocracking unit 12, a fractionation section 14 and a second stage hydrocracking unit 150. A resid hydrocarbon stream in resid line 18 and a first stage hydrogen stream in a first stage hydrogen line 22 are fed to the first stage hydrocracking unit 12.
In one aspect, the process and apparatus described herein are particularly useful for hydrocracking a hydrocarbon feed stream comprising a resid hydrocarbonaceous feedstock. A suitable resid feed is AR having an T5 between about 316° C. (600° F.) and about 399° C. (750° F.) and a T70 between about 510° C. (950° F.) and about 704° C. (1300° F.). VR having a T5 in the range between about 482° C. (900° F.) and about 565° C. (1050° F.) may also be a suitable feed. VR, atmospheric gas oils having T5 between about 288° C. (550° F.) and about 315° C. (600° F.) and vacuum gas oils (VGO) having T5 between about 316° C. (600° F.) and about 399° C. (750° F.) may also be blended with the AR to make a suitable resid feed. Deasphalted oil, visbreaker bottoms, clarified slurry oils, and shale oils may also be suitable resid feeds alone or by blending with AR or VR. Typically these resid feeds contain significant concentration of metals which have to be removed before the hydrocracking process. Typically, suitable resid feeds include about 50 to about 500 wppm metals but resid feeds with less than about 200 wppm metals are preferred. Nickel, vanadium and iron are some of the typical metals in resid feeds.
A first hydrotreating hydrogen stream in a first hydrotreating hydrogen line 24 may split off from the first stage hydrogen line 22. The first hydrotreating hydrogen stream may join the hydrocarbonaceous stream in feed line 18 to provide a first hydrocarbon feed stream in a first hydrocarbon feed line 26. The first hydrocarbon feed stream in the first hydrocarbon feed line 26 may be heated by heat exchange with a first hydrocracked stream in first hydrocracked effluent line 48 and in a fired heater. The heated first hydrocarbon feed stream in line 28 may be fed to a first resid hydrotreating unit 30.
Hydrotreating is a process wherein hydrogen is contacted with hydrocarbon in the presence of hydrotreating catalysts which are primarily active for the removal of heteroatoms, such as sulfur, nitrogen and metals from the hydrocarbon feedstock. In hydrotreating, hydrocarbons with double and triple bonds may be saturated. Aromatics may also be saturated. Some hydrotreating processes are specifically designed to saturate aromatics.
The first resid hydrotreating unit 30 may comprise three hydrotreating reactors comprising a demetallizing reactor 34 and a desulfurization reactor 36. In an aspect, the resid hydrotreating unit 30 comprises a denitrogenation reactor 38. More or less hydrotreating reactors may be used, and each hydrotreating reactor 34, 36, 38 may comprise a part of a hydrotreating reactor or comprise one or more hydrotreating reactors. Each hydrotreating reactor 34, 36, 38 may comprise part of a catalyst bed or one or more catalyst beds in one or more hydrotreating reactor vessels 35. In
Suitable hydrotreating catalysts for use in the first resid hydrotreating unit 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 nickel and/or cobalt and at least one Group VI metal, preferably molybdenum and tungsten, on a high surface area support material, preferably alumina. It is within the scope of the present invention that more than one type of hydrotreating catalyst be used in the same reaction vessel or catalyst bed. The Group VIII metal is typically present in an amount ranging from about 1 to about 10 wt %, preferably from about 2 to about 5 wt %. The Group VI metal will typically be present in an amount ranging from about 1 to about 20 wt %, preferably from about 2 to about 10 wt %.
The first hydrocarbon feed stream in line 28 may be fed to the first hydrotreating reactor 34. The first hydrotreating reactor may comprise a demetallizing reactor 34. Water may be added to the resid feed in line 28. In an embodiment, the first demetallizing reactor 34 may comprise a hydrodemetallization catalyst comprising cobalt and molybdenum on gamma alumina. The demetallization reactor is intended to demetallize the heated resid stream, so to reduce the metals concentration in the fresh feed stream by about 40 to about 100 wt % and typically about 65 to about 95 wt % to produce a first demetallized effluent stream exiting the demetallization reactor 34. The metal content of the demetallized resid stream may be less than about 50 wppm and preferably between about 1 and about 25 wppm. The demetallization reactor 34 may also denitrogenate and/or desulfurize the resid stream. A demetallized effluent stream reduced in metals concentration relative to the resid stream may exit the first hydrotreating reactor 34 and enter the second hydrotreating reactor 36 comprising a second denitrogenation reactor.
The first resid hydrotreating unit 30 may include a second hydrotreating reactor 36. Demetallized effluent from the demetallization reactor 34 is supplemented with hydrotreating hydrogen from manifold 31 and fed to the second hydrotreating reactor 36. In an embodiment, the second hydrotreating reactor 36 may comprise a desulfurization reactor that includes a hydrodesulfurization catalyst which may comprise nickel or cobalt and molybdenum on gamma alumina to convert organic sulfur to hydrogen sulfide. The desulfurization reactor reduces the sulfur concentration in the resid feed stream by about 40 to about 100 wt % and typically about 65 to about 95 wt % to produce a desulfurized effluent stream exiting the desulfurized reactor. In this embodiment, the desulfurized effluent stream may exit the second hydrotreating reactor 36 and enter the third hydrotreating reactor 38.
The first resid hydrotreating unit 30 may include a third hydrotreating reactor 38. In an embodiment, desulfurized effluent from the desulfurization reactor 36 is supplemented with hydrogen from manifold 31 and fed the third hydrotreating reactor which may comprise a denitrogenation reactor 38 comprising a hydrodenitrogenation catalyst. The denitrogenation catalyst which may comprise nickel and molybdenum on gamma alumina to convert organic nitrogen to ammonia. The hydrodenitrogenation catalyst may also be able to saturate aromatics to naphthenes. The denitrogenation section reduces the nitrogen concentration in the resid stream by about 40 to about 100 wt % and typically about 65 to about 95 wt % to produce a denitrogenated effluent stream exiting the denitrogenation reactor 65. In this embodiment, the denitrogenated effluent may exit the third hydrotreating reactor 38. The denitrogenation catalyst in the third hydrotreating reactor 38 may be a different and preferably more active than the desulfurization catalyst in the second hydrotreating reactor 36. For example, the denitrogenation catalyst may have a higher metals concentration than the desulfurization catalyst.
It is contemplated that in the first resid hydrotreating unit 30 one, two or all of the hydrotreating reactors 34, 36 and 38 optionally demetallize and desulfurize the resid feed stream and optionally, demetallize, desulfurize and denitrogenate the resid feed stream in resid feed line 28. Preferably, the first hydrotreating unit 30 comprises three hydrotreating reactors to demetallize, desulfurize and denitrogenate the resid feed stream.
Supplemental hydrogen in a first hydrotreating supplemental hydrogen line 31 may be added at an interstage locations between hydrotreating reactors 34, 36 and 38 in the first resid hydrotreating unit 30.
Preferred reaction conditions in each of the hydrotreating reactors 34, 36 and 38 include a temperature from about 66° C. (151° F.) to about 455° C. (850° F.), suitably 316° C. (600° F.) to about 427° C. (800° F.) and preferably 343° C. (650° F.) to about 399° C. (750° F.), a pressure from about 2.1 MPa (gauge) (300 psig) to about 27.6 MPa (gauge) (4000 psig), preferably about 13.8 MPa (gauge) (2000 psig) to about 20.7 MPa (gauge) (3000 psig), a liquid hourly space velocity of the fresh hydrocarbonaceous feedstock from about 0.1 hr−1 to about 5 hr−1, preferably from about 0.2 to about 2 hr−1, and a hydrogen rate of about 168 Nm3/m3 (1,000 scf/bbl) to about 1,680 Nm3/m3 oil (10,000 scf/bbl), preferably about 674 Nm3/m3 oil (4,000 scf/bbl) to about 1,011 Nm3/m3 oil (6,000 scf/bbl).
A first hydrotreated resid stream that exits the first hydrotreating unit 30 in a first hydrotreating effluent line 32 has a reduced concentration of metals, sulfur and nitrogen relative to the resid stream in line 28 and can be taken as a first hydrocracking feed stream. Hydrogen gas laden with ammonia and hydrogen sulfide may be removed from the first hydrocracking feed stream in a hydrocracking separator, but the first hydrocracking feed stream may be fed directly to the hydrocracking reactor 40 without separation.
The first hydrotreated resid stream may be heated before entering a first hydrocracking reactor 40 in the first hydrotreating effluent line 32. The first hydrocracking reactor 40 may comprise a first hydrocracking reactor vessel 40v. The first hydrocracking reactor 40 is in downstream communication with the first hydrotreating unit 30. The first hydrocracking reactor vessel 40v may include a separator 72 above the first hydrocracking reactor 40 comprising one or more beds 42 of hydrocracking catalyst. In an aspect, the separator 72 and the first hydrocracking reactor 40 comprising the hydrocracking catalyst beds 42 may be in the same hydrocracking reactor vessel 40v.
In an aspect, the first hydrotreated resid stream enters the first hydrocracking reactor 40 near a top of the reactor vessel 40v and flows into the separator 72. The first hydrocracking separator is in downstream communication with the first hydrotreating unit 30. The first hydrotreated resid stream is fed into the separator 72 at an inlet 72i that is located above a lower edge of a tubular baffle 74 that is secured to the top of the vessel 40v. A first gas hydrotreated stream separates from a first liquid hydrotreated resid stream of the first hydrotreated resid stream and descends below and around the tubular baffle 74 to separate from the first liquid hydrotreated resid stream. The gas first hydrotreated resid stream is removed from an outlet 46o in the top of the hydrocracking reactor vessel 40v located inwardly of the baffle 74 via a hydrocracking separator overhead line 46. The gas first hydrotreated resid stream may be admixed with a hot gaseous stream provided via a hot separator overhead line 52 and the resulting admixed stream is carried via line 53 and introduced into a heat exchanger to be cooled. A resulting cooled and partially condensed hot separator admixed stream is introduced into a cold separator 56. The gas first hydrotreated resid stream removes with it a majority of the hydrogen sulfide and ammonia that tend to deactivate hydrocracking catalyst.
The first liquid hydrotreated resid stream separated in the separator 72 from the first hydrotreated resid stream flows downwardly onto a tray 76 that may generate a liquid level, such as a chimney tray. The liquid level is maintained by a vertical, weir 78 which may be tubular in an aspect. A cap 80 which may be tubular also with a wider inner diameter than the tubular weir 78 is superimposed over the weir. The tubular cap 80 has a closed upper end that is opposed to an opening in the weir 78 and the tray 76 to cooperatively prevent the direct, downward flow of liquid and any flow of undissolved vapor downwardly past the tray 76 into a mixing zone 82. The downwardly flowing first liquid hydrotreated resid stream from tray 76 is admixed in the mixing zone 82 with a first hydrocracking hydrogen stream from the first stage hydrogen line 22 from hydrogen manifold 44 introduced into the mixing zone 82 below the tray 76 and the separator 72. The liquid on the tray 76 and the downward flow of liquid prevents hydrogen from moving upwardly through the chimney tray to exit through the outlet 46o.
The liquid first hydrotreated resid stream mixed with the first hydrocracking hydrogen stream from manifold 44 is fed to a bed 42 of hydrocracking catalyst in the first hydrocracking reactor 40 to be hydrocracked.
Hydrocracking is a process in which hydrocarbons crack in the presence of hydrogen to lower molecular weight hydrocarbons. The first hydrocracking reactor 40 may be a fixed bed reactor that comprises one or more vessels, single or multiple catalyst beds 42 in each vessel, and various combinations of hydrotreating catalyst, hydroisomerization catalyst and/or hydrocracking catalyst in one or more vessels. It is contemplated that the first hydrocracking reactor 40 be operated in a continuous liquid phase in which the volume of the liquid hydrocarbon feed is greater than the volume of the hydrogen gas. The first hydrocracking reactor 40 may also be operated in a conventional continuous gas phase, a moving bed or a fluidized bed hydroprocessing reactor.
The first hydrocracking reactor 40 comprises a plurality of first hydrocracking catalyst beds 42. The first or an upstream bed in the first hydrocracking reactor 40 may comprise a first hydrocracking catalyst bed 42. The first hydrocracking reactor is in downstream communication with the hydrocracking separator 72.
The hydrotreated first hydrocracking feed stream is hydrocracked over a first hydrocracking catalyst in the first hydrocracking catalyst beds 42 in the presence of the first hydrocracking hydrogen stream from a first hydrocracking hydrogen line 22 to provide a first hydrocracked stream. Subsequent catalyst beds 42 in the hydrocracking reactor may comprise hydrocracking catalyst over which additional hydrocracking occurs to the hydrocracked stream. Hydrogen manifold 44 may deliver supplemental hydrogen streams from the first hydrocracking hydrogen line 22 to one, some or each of the catalyst beds 42. In an aspect, the supplemental hydrogen is added to each of the catalyst beds 42 at an interstage location between adjacent beds, so supplemental hydrogen is mixed with hydroprocessed effluent exiting from the upstream catalyst bed 42 before entering the downstream catalyst bed 42.
The first hydrocracking reactor 40 may provide a total conversion of at least about 20 vol % and typically greater than about 50 vol % of the first hydrocracking feed stream in the first hydrotreating effluent line 32 to products boiling below the diesel cut point. The first hydrocracking reactor 40 may operate at partial conversion of more than about 30 vol % or full conversion of at least about 90 vol % of the feed based on total conversion. The first hydrocracking reactor 40 may be operated at mild hydrocracking conditions which will provide about 20 to about 60 vol %, preferably about 20 to about 50 vol %, total conversion of the hydrocarbon feed stream to product boiling below the diesel cut point.
The first hydrocracking catalyst may utilize amorphous silica-alumina bases or low-level zeolite bases combined with one or more Group VIII or Group VIB metal hydrogenating components if mild hydrocracking is desired to produce a balance of middle distillate and gasoline. In another aspect, when middle distillate is significantly preferred in the converted product over gasoline production, partial or full hydrocracking may be performed in the first hydrocracking reactor 40 with a catalyst which comprises, in general, any crystalline zeolite cracking base upon which is deposited a Group VIII metal hydrogenating component. Additional hydrogenating components may be selected from Group VIB for incorporation with the zeolite base.
The zeolite cracking bases are sometimes referred to in the art as molecular sieves and are usually composed of silica, alumina and one or more exchangeable cations such as sodium, magnesium, calcium, rare earth metals, etc. They are further characterized by crystal pores of relatively uniform diameter between about 4 and about 14 Angstroms (10−10 meters). It is preferred to employ zeolites having a relatively high silica/alumina mole ratio between about 3 and about 12. Suitable zeolites found in nature include, for example, mordenite, stilbite, heulandite, ferrierite, dachiardite, chabazite, erionite and faujasite. Suitable synthetic zeolites include, for example, the B, X, Y and L crystal types, e.g., synthetic faujasite and mordenite. The preferred zeolites are those having crystal pore diameters between about 8 and 12 Angstroms (10−10 meters), wherein the silica/alumina mole ratio is about 4 to 6. One example of a zeolite falling in the preferred group is synthetic Y molecular sieve.
The natural occurring zeolites are normally found in a sodium form, an alkaline earth metal form, or mixed forms. The synthetic zeolites are nearly always prepared first in the sodium form. In any case, for use as a cracking base it is preferred that most or all of the original zeolitic monovalent metals be ion-exchanged with a polyvalent metal and/or with an ammonium salt followed by heating to decompose the ammonium ions associated with the zeolite, leaving in their place hydrogen ions and/or exchange sites which have actually been decationized by further removal of water. Hydrogen or “decationized” Y zeolites of this nature are more particularly described in U.S. Pat. No. 3,100,006.
Mixed polyvalent metal-hydrogen zeolites may be prepared by ion-exchanging first with an ammonium salt, then partially back exchanging with a polyvalent metal salt and then calcining. In some cases, as in the case of synthetic mordenite, the hydrogen forms can be prepared by direct acid treatment of the alkali metal zeolites. In one aspect, the preferred cracking bases are those which are at least about 10 wt %, and preferably at least about 20 wt %, metal-cation-deficient, based on the initial ion-exchange capacity. In another aspect, a desirable and stable class of zeolites is one wherein at least about 20 wt % of the ion exchange capacity is satisfied by hydrogen ions.
The active metals employed in the preferred first hydrocracking catalysts of the present invention as hydrogenation components are those of Group VIII, i.e., iron, cobalt, nickel, ruthenium, rhodium, palladium, osmium, iridium and platinum. In addition to these metals, other promoters may also be employed in conjunction therewith, including the metals of Group VIB, e.g., molybdenum and tungsten. The amount of hydrogenating metal in the catalyst can vary within wide ranges. Broadly speaking, any amount between about 0.05 wt % and about 30 wt % may be used. In the case of the noble metals, it is normally preferred to use about 0.05 to about 2 wt % noble metal.
The method for incorporating the hydrogenation metal is to contact the base material with an aqueous solution of a suitable compound of the desired metal wherein the metal is present in a cationic form. Following addition of the selected hydrogenation metal or metals, the resulting catalyst powder is then filtered, dried, pelleted with added lubricants, binders or the like if desired, and calcined in air at temperatures of, e.g., about 371° C. (700° F.) to about 648° C. (1200° F.) in order to activate the catalyst and decompose ammonium ions. Alternatively, the base component may first be pelleted, followed by the addition of the hydrogenation component and activation by calcining.
The foregoing catalysts may be employed in undiluted form, or the powdered catalyst may be mixed and copelleted with other relatively less active catalysts, diluents or binders such as alumina, silica gel, silica-alumina cogels, activated clays and the like in proportions ranging between about 5 and about 90 wt %. These diluents may be employed as such or they may contain a minor proportion of an added hydrogenating metal such as a Group VIB and/or Group VIII metal. Additional metal promoted hydrocracking catalysts may also be utilized in the process of the present invention which comprises, for example, aluminophosphate molecular sieves, crystalline chromosilicates and other crystalline silicates. Crystalline chromosilicates are more fully described in U.S. Pat. No. 4,363,718.
By one approach, the hydrocracking conditions in the first hydrocracking reactor 40 may include a temperature from about 290° C. (550° F.) to about 468° C. (875° F.), preferably about 343° C. (650° F.) to about 445° C. (833° F.), a pressure from about 2.1 MPa (gauge) (300 psig) to about 27.6 MPa (gauge) (4000 psig), preferably about 13.8 MPa (gauge) (2000 psig) to about 20.7 MPa (gauge) (3000 psig), a liquid hourly space velocity (LHSV) from about 0.1 to about 5 hr−1 and preferably about 0.5 to about 3 hr−1 and a hydrogen rate of about 168 Nm3/m3 (1,000 scf/bbl) to about 1,680 Nm3/m3 oil (10,000 scf/bbl), preferably about 674 Nm3/m3 oil (4,000 scf/bbl) to about 1,011 Nm3/m3 oil (6,000 scf/bbl).
The first hydrocracked stream may exit the first hydrocracking reactor 40 in the first hydrocracked effluent line 48 and be separated in the fractionation section 14 in downstream communication with the first hydrocracking reactor 40. The fractionation section 14 comprises one or more separators and fractionation columns in downstream communication with the hydrocracking reactor 40.
The first hydrocracked stream in the first hydrocracked effluent line 48 may in an aspect be heat exchanged with the hydrocarbon feed stream in line 26 to be cooled and be mixed with a second hydrocracked effluent in a second hydrocracked effluent line 44. The combined hydrocracked effluent line 49 may deliver a combined stream to a hot separator 50. Accordingly, the hot separator 50 is in downstream communication with the first hydrocracking reactor 40 and the second hydrocracking reactor 170.
The hot separator separates the first hydrocracked stream and the second hydrocracked stream to provide a hydrocarbonaceous, hot gaseous stream in a hot overhead line 52 and a hydrocarbonaceous, hot liquid stream in a hot bottoms line 54. The hot separator 50 may be in downstream communication with the hydrocracking reactor 40. The hot separator 50 operates at about 177° C. (350° F.) to about 371° C. (700° F.) and preferably operates at about 232° C. (450° F.) to about 315° C. (600° F.). The hot separator 50 may be operated at a slightly lower pressure than the first hydrocracking reactor 40 accounting for pressure drop through intervening equipment. The hot separator 50 may be operated at pressures between about 3.4 MPa (gauge) (493 psig) and about 20.4 MPa (gauge) (2959 psig). The hydrocarbonaceous, hot gaseous separated stream in the hot overhead line 52 may have a temperature of the operating temperature of the hot separator 50.
As a consequence of the reactions taking place in the first hydrocracking reactor 40 wherein nitrogen, chlorine and sulfur are removed from the feed, ammonia and hydrogen sulfide are formed. At a characteristic sublimation temperature, ammonia and hydrogen sulfide will combine to form ammonium bisulfide and ammonia, and chlorine will combine to form ammonium chloride. Each compound has a characteristic sublimation temperature that may allow the compound to coat equipment, particularly heat exchange equipment, impairing its performance. To prevent such deposition of ammonium bisulfide or ammonium chloride salts in the hot overhead line 52 transporting the hot gaseous stream, a suitable amount of wash water may be introduced into the hot overhead line 52 upstream of a cooler by water line 51 at a point in the hot overhead line where the temperature is above the characteristic sublimation temperature of either compound.
The hot gaseous stream in the overhead line 52 is combined with the gas first hydrotreated resid stream in the hydrocracking separator overhead line 46 exiting the top of the separator 72 which comprises valuable distillate hydrocarbons which can avoid being over cracked in the first hydrocracking reactor 40 to less valuable light hydrocarbons and contains hydrogen sulfide and ammonia that are detrimental to hydrocracking catalyst. The gas first hydrotreated resid stream bypasses the first hydrocracking reactor 40 and with the hot gaseous stream in the overhead line enters a cold separator in line 53. The hot gaseous stream in the hot overhead line 52 combined with the gas first hydrotreated resid stream may be cooled before entering a cold separator 56 in combine line 53. The cold separator 56 is in downstream communication with an overhead line 46 of the hydrocracking separator 72 and a hydrocracked effluent line 48 of said first hydrocracking reactor 40.
The hot gaseous stream and the gas first hydrotreated resid stream may be separated in the cold separator 56 to provide a cold gaseous stream comprising a hydrogen-rich gas stream including ammonia and hydrogen sulfide in a cold overhead line 58 and a cold liquid stream in a cold bottoms line 60. The cold separator 56 serves to separate hydrogen rich gas from hydrocarbon liquid in the first hydrocracked stream and the second hydrocracked stream for recycle to the first stage hydrocracking unit 12 and the second stage hydrocracking unit 150 in the cold overhead line 58. The cold separator 56, therefore, is in downstream communication with the hot overhead line 52 of the hot separator 50 and the hydrocracking reactor 40. The cold separator 56 may be operated at about 100° F. (38° C.) to about 150° F. (66° C.), suitably about 115° F. (46° C.) to about 145° F. (63° C.), and just below the pressure of the first hydrocracking reactor 40 and the hot separator 50 accounting for pressure drop through intervening equipment to keep hydrogen and light gases in the overhead and normally liquid hydrocarbons in the bottoms. The cold separator 56 may be operated at pressures between about 3 MPa (gauge) (435 psig) and about 20 MPa (gauge) (2,901 psig). The cold separator 56 may also have a boot for collecting an aqueous phase. The cold liquid stream in the cold bottoms line 60 may have a temperature of the operating temperature of the cold separator 56.
The cold gaseous stream in the cold overhead line 58 is rich in hydrogen. Thus, hydrogen can be recovered from the cold gaseous stream. However, this stream comprises much of the hydrogen sulfide and ammonia separated from the hydrotreated resid stream. The cold gaseous stream in the cold overhead line 58 may be passed through a trayed or packed recycle scrubbing column 62 where it is scrubbed by means of a scrubbing extraction liquid such as an aqueous solution fed by line 64 to remove and acid gases including hydrogen sulfide and carbon dioxide by extracting them into the aqueous solution. Preferred aqueous solutions include lean amines such as alkanolamines DEA, MEA, and MDEA. Other amines can be used in place of or in addition to the preferred amines. The lean amine contacts the cold gaseous stream and absorbs acid gas contaminants such as hydrogen sulfide and carbon dioxide. The resultant “sweetened” cold gaseous stream is taken out from an overhead outlet of the recycle scrubber column 62 in a recycle scrubber overhead line 68, and a rich amine is taken out from the bottoms at a bottom outlet of the recycle scrubber column in a recycle scrubber bottoms line 66. The spent scrubbing liquid from the bottoms may be regenerated and recycled back to the recycle scrubbing column 62 in line 64. The scrubbed hydrogen-rich stream emerges from the scrubber via the recycle scrubber overhead line 68 and may be compressed in a recycle compressor 70. The compressed hydrogen stream supplies hydrogen to the first stage hydrogen stream in the first stage hydrogen line 22 and a second stage hydrogen stream in a second stage hydrogen line 166. The recycle scrubbing column 62 may be operated with a gas inlet temperature between about 38° C. (100° F.) and about 66° C. (150° F.) and an overhead pressure of about 3 MPa (gauge) (435 psig) to about 20 MPa (gauge) (2900 psig).
The hydrocarbonaceous hot liquid stream in the hot bottoms line 54 may be directly stripped. In an aspect, the hot liquid stream in the hot bottoms line 54 may be let down in pressure and flashed in a hot flash drum 80 to provide a flash hot gaseous stream of light ends in a flash hot overhead line 82 and a flash hot liquid stream in a flash hot bottoms line 84. The hot flash drum 80 may be in direct, downstream communication with the hot bottoms line 54 and in downstream communication with the first hydrocracking reactor 40. In an aspect, light gases such as hydrogen sulfide may be stripped from the flash hot liquid stream in the flash hot bottoms line 84. Accordingly, a stripping column 100 may be in downstream communication with the hot flash drum 80 and the hot flash bottoms line 84.
The hot flash drum 80 may be operated at the same temperature as the hot separator 50 but at a lower pressure of between about 1.4 MPa (gauge) (200 psig) and about 6.9 MPa (gauge) (1000 psig), suitably no more than about 3.8 MPa (gauge) (550 psig). The flash hot liquid stream in the flash hot bottoms line 84 may be further fractionated in the fractionation section 14. The flash hot liquid stream in the flash hot bottoms line 84 may have a temperature of the operating temperature of the hot flash drum 80.
In an aspect, the cold liquid stream in the cold bottoms line 60 may be directly stripped. In a further aspect, the cold liquid stream may be let down in pressure and flashed in a cold flash drum 86 to separate the cold liquid stream in the cold bottoms line 60. The cold flash drum 86 may be in direct downstream communication with the cold bottoms line 60 of the cold separator 56 and in downstream communication with the hydrocracking reactor 40.
In a further aspect, the flash hot gaseous stream in the flash hot overhead line 82 may be fractionated in the fractionation section 14. In a further aspect, the flash hot gaseous stream may be cooled and also separated in the cold flash drum 86. The cold flash drum 86 may separate the cold liquid stream in line 60 and/or the flash hot gaseous stream in the flash hot overhead line 82 to provide a flash cold gaseous stream in a flash cold overhead line 88 and a flash cold liquid stream in a cold flash bottoms line 90. In an aspect, light gases such as hydrogen sulfide may be stripped from the flash cold liquid stream in the flash cold bottoms line 90. Accordingly, a stripping column 100 may be in downstream communication with the cold flash drum 86 and the cold flash bottoms line 90.
The cold flash drum 86 may be in downstream communication with the cold bottoms line 60 of the cold separator 56, the hot flash overhead line 82 of the hot flash drum 80 and the hydrocracking reactor 40. The flash cold liquid stream in the cold bottoms line 60 and the flash hot gaseous stream in the hot flash overhead line 82 may enter into the cold flash drum 86 either together or separately. In an aspect, the hot flash overhead line 82 joins the cold bottoms line 60 and feeds the flash hot gaseous stream and the cold liquid stream together to the cold flash drum 86 in a cold flash feed line 92. The cold flash drum 86 may be operated at the same temperature as the cold separator 56 but typically at a lower pressure of between about 1.4 MPa (gauge) (200 psig) and about 6.9 MPa (gauge) (1000 psig) and preferably between about 3.0 MPa (gauge) (435 psig) and about 3.8 MPa (gauge) (550 psig). A flashed aqueous stream may be removed from a boot in the cold flash drum 86. The flash cold liquid stream in the flash cold bottoms line 90 may have the same temperature as the operating temperature of the cold flash drum 86. The flash cold gaseous stream in the flash cold overhead line 88 contains substantial hydrogen that may be recovered.
The fractionation section 14 may further include the stripping column 100, an atmospheric fractionation column 130 and a vacuum fractionation column 180. The stripping column 100 may be in downstream communication with a bottoms line in the fractionation section 14 for stripping volatiles from a first hydrocracked stream and a second hydrocracked stream. For example, the stripping column 100 may be in downstream communication with the hot bottoms line 54, the flash hot bottoms line 84, the cold bottoms line 60 and/or the cold flash bottoms line 90. In an aspect, the stripping column 100 may be a vessel that contains a cold stripping column 102 and a hot stripping column 104 with a wall that isolates each of the stripping columns 102, 104 from the other. The cold stripping column 102 may be in downstream communication with the first hydrocracking reactor 40, a second hydrocracking reactor 170, the cold bottoms line 60 and, in an aspect, the flash cold bottoms line 90 for stripping the cold liquid stream. The hot stripping column 104 may be in downstream communication with the first hydrocracking reactor 40, the second hydrocracking reactor 170, and the hot bottoms line 54 and, in an aspect, the flash hot bottoms line 84 for stripping a hot liquid stream which is hotter than the cold liquid stream. The hot liquid stream may be hotter than the cold liquid stream, by at least 25° C. and preferably at least 50° C.
The flash cold liquid stream comprising the first hydrocracked stream and the second hydrocracked stream in the flash cold bottoms line 90 may be heated and fed to the cold stripping column 102 at an inlet which may be in a top half of the column. The flash cold liquid stream which comprises the first hydrocracked stream and the second hydrocracked stream may be stripped of gases in the cold stripping column 102 with a cold stripping media which is an inert gas such as steam from a cold stripping media line 106 to provide a cold stripper gaseous stream of naphtha, hydrogen, hydrogen sulfide, steam and other gases in a cold stripper overhead line 108 and a liquid cold stripped stream in a cold stripper bottoms line 110. The cold stripper gaseous stream in the cold stripper overhead line 108 may be condensed and separated in a receiver 112. A stripper net overhead line 114 from the receiver 112 carries a net stripper gaseous stream for further recovery of LPG and hydrogen in a light material recovery unit. Unstabilized liquid naphtha from the bottoms of the receiver 112 may be split between a reflux portion refluxed to the top of the cold stripping column 102 and a liquid stripper overhead stream which may be transported in a condensed stripper overhead line 116 to further recovery or processing. A sour water stream may be collected from a boot of the overhead receiver 112.
The cold stripping column 102 may be operated with a bottoms temperature between about 149° C. (300° F.) and about 288° C. (550° F.), preferably no more than about 260° C. (500° F.), and an overhead pressure of about 0.35 MPa (gauge) (50 psig), preferably no less than about 0.50 MPa (gauge) (72psig), to no more than about 2.0 MPa (gauge) (290 psig). The temperature in the overhead receiver 112 ranges from about 38° C. (100° F.) to about 66° C. (150° F.) and the pressure is essentially the same as in the overhead of the cold stripping column 102.
The cold stripped stream in the cold stripper bottoms line 110 may comprise predominantly naphtha and kerosene boiling materials. The cold stripped stream in line 110 may be heated and fed to the atmospheric fractionation column 130. The atmospheric fractionation column 130 may be in downstream communication with the first hydrocracking reactor 40 and the second hydrocracking reactor 170, the cold stripper bottoms line 110 of the cold stripping column 102 and the stripping column 100. In an aspect, the atmospheric fractionation column 130 may be in downstream communication with one, some or all of the hot separator 50, the cold separator 56, the hot flash drum 80 and the cold flash drum 86.
The flash hot liquid stream comprising a hydrocracked stream in the hot flash bottoms line 84 may be fed to the hot stripping column 104 near a top thereof. The flash hot liquid stream may be stripped in the hot stripping column 104 of gases with a hot stripping media which is an inert gas such as steam from a line 120 to provide a hot stripper overhead stream of naphtha, hydrogen, hydrogen sulfide, steam and other gases in a hot stripper overhead line 118 and a liquid hot stripped stream in a hot stripper bottoms line 122. The hot stripper overhead line 118 may be condensed and a portion refluxed to the hot stripping column 104. However, in the embodiment of
At least a portion of the hot stripped stream comprising a hydrocracked stream in the hot stripped bottoms line 122 may be heated and fed to the atmospheric fractionation column 130. The atmospheric fractionation column 130 may be in downstream communication with the hot stripped bottoms line 122 of the hot stripping column 104. The hot stripped stream in line 122 may be at a hotter temperature than the cold stripped stream in line 110.
In an aspect, the hot stripped stream in the hot stripped bottoms line 122 may be heated and fed to a prefractionation separator 124 for separation into a vaporized hot stripped stream in a prefractionation overhead line 126 and a liquid hot stripped stream in a prefractionation bottoms line 128. The vaporous hot stripped stream may be fed to the atmospheric fractionation column 130 in the prefractionation overhead line 126. The liquid hot stripped stream may be heated in a fractionation furnace and fed to the atmospheric fractionation column 130 in the prefractionation bottoms line 128 at an elevation below the elevation at which the prefractionation overhead line 126 feeds the vaporized hot stripped stream to the atmospheric fractionation column 130.
The atmospheric fractionation column 130 may be in downstream communication with the cold stripping column 102 and the hot stripping column 104 and may comprise more than one fractionation column for separating stripped hydrocracked streams into product streams.
The atmospheric fractionation column 130 may fractionate hydrocracked streams, the cold stripped stream, the vaporous hot stripped stream and the liquid hot stripped stream, with an inert stripping media stream such as steam from line 132 to provide several product streams. The product streams from the atmospheric fractionation column 130 may include a net fractionated overhead stream comprising naphtha in a net overhead line 134, an optional heavy naphtha stream in line 136 from a side cut outlet, a kerosene stream carried in line 138 from a side cut outlet and a diesel stream in line 140 from a side cut outlet. A first atmospheric fractionated stream is taken in a bottoms line 142 from the atmospheric fractionation column 130.
Heat may be removed from the atmospheric fractionation column 130 by cooling at least a portion of the product streams and sending a portion of each cooled stream back to the atmospheric fractionation column. These product streams may also be stripped to remove light materials to meet product purity requirements. A fractionated overhead stream in an overhead line 148 may be condensed and separated in a receiver 150 with a portion of the condensed liquid being refluxed back to the product fractionation column 130. The net fractionated overhead stream in line 134 may be further processed or recovered as naphtha product. The product fractionation column 130 may be operated with a bottoms temperature between about 260° C. (500° F.), and about 385° C. (725° F.), preferably at no more than about 350° C. (650° F.), and at an overhead pressure between about 7 kPa (gauge) (1 psig) and about 69 kPa (gauge) (10 psig). A portion of the first atmospheric fractionated stream in the atmospheric bottoms line 142 may be reboiled and returned to the atmospheric fractionation column 130 instead of adding an inert stripping media stream such as steam in line 132 to heat to the atmospheric fractionation column 130.
The second vacuum fractionation column 180 may be in downstream communication with the first atmospheric fractionation column 130 and particularly the bottoms line 142. Consequently, the heavy fractionation column 100 is in downstream communication with the bottoms line 142 from the first atmospheric fractionation column 130. In an aspect, the prefractionation bottoms line 128 may feed the vacuum fraction column 180 and bypass the first atmospheric fractionation column 130. An inert gas such as steam from line 188 may provide heat to the vacuum fractionation column 180 and strip lighter components from the heavier components. The vacuum fractionation column 180 produces a heavy diesel product stream in line 184 from a side cut outlet. The vacuum fractionation column may operate to produce a diesel stream with a diesel TBP cut point of between about 370° and about 390° C. and a T95 of no more than 380° C. and preferably no more than 360° C.
A heavy upper stream may be provided in an upper line from an upper half of the vacuum fractionation column from an overhead outlet in overhead line 190 and/or a side line 192 from a side cut outlet and fed in a heavy return line 194 to the atmospheric fractionation column 130. The atmospheric fractionation column 130 may be in downstream communication with an upper line 192 from an upper half of the vacuum fractionation column 180. Accordingly, the atmospheric fractionation column 130 is also in downstream communication with the vacuum fractionation column 180.
A RO stream in a heavy bottoms line 186 may be recovered from a bottom of the heavy fractionation column 180. The recycle oil stream has a boiling point above the diesel cut point and may be recycled to the second hydrocracking stage 150. Additionally, any HPNAs present may be separated from the recycle oil stream in the heavy bottoms line 186 before the recycle oil stream is recycled to the second hydrocracking stage 150. Several processes are available to manage HPNA rejection, such as steam stripping and adsorption. An unconverted oil stream which may be concentrated in heavy polynuclear aromatics may be taken from the heavy bottoms line 186 in purge line 187 while the remaining RO stream is recycled to the second hydrocracking stage in line 200. The purge stream 187 is normally minimized.
The vacuum fractionation column 180 is operated at below atmospheric pressure in the overhead. The overhead stream in overhead line 190 may feed a vacuum generating device 174. The vacuum generating device 174 may include and eductor in communication with an inert gas stream 176 such as steam which pulls a vacuum on the overhead stream in the overhead line 190. A condensed hydrocarbon stream in line 178 from the vacuum generating device 174 may supply the heavy return stream 194 by itself or with the upper stream in the side line 192. A condensed aqueous stream may also be removed from the vacuum generating device in line 182. A light diesel vaporous stream may be removed from the vapor generating device in line 144.
Heat may be removed from the vacuum fractionation column 180 by cooling the light stream in line 192 and/or the diesel stream in line 184 and sending a portion of each cooled stream back to the column. The diesel stream in line 184 may be stripped to remove light materials to meet product purity requirements. The vacuum fractionation column 180 may be operated with a bottoms temperature between about 260° C. (500° F.), and about 370° C. (700° F.), preferably no more than about 300° C. (570° F.), and at an overhead pressure between about 10 kPa (absolute) (1.5 psia), preferably about 20 kPa (absolute) (3 psia), and about 70 kPa (gauge) (10 psig). A portion of the RO in the heavy bottoms line 186 may be reboiled and returned to the vacuum fractionation column 180 instead of using steam stripping to add heat to the heavy fractionation column 180.
In an aspect, the UCO stream in purge line 187 comprises less than 20 wt % of the resid stream in line 18. Suitably, the UCO stream in line 187 comprises less than 10 wt % of the hydrocarbonaceous stream in line 18. Preferably, the UCO stream in line 187 comprises less than 5 wt % of the hydrocarbonaceous stream in line 18. More preferably, the UCO stream in line 187 comprises less than 1 wt % of the hydrocarbonaceous stream in line 18. The present process and apparatus 10 may make purge of the unconverted oil stream unnecessary such that all of the UCO stream in the fractionator bottoms line 186 is recycled as RO in the RO stream in a recycle line 200 to the second stage hydrocracking unit 150. A portion or all of the RO stream in the fractionator bottoms line 186 may be recycled in the recycle line 200 as a RO stream to a second hydrocracking unit 150. More or all of the RO stream in the fractionator bottoms line 186 may be recycled to the second stage hydrocracking unit 150 because the second stage hydrocracking unit saturates aromatics including HPNA precursors; i.e., PNA's, to naphthenes, so that they can be hydrocracked in the second hydrocracking reactor 170.
The RO stream in RO line 200 may be recycled to a second hydrocracking unit 150. In hydrocracking, we have found that HPNA formation is due to condensation of aromatic precursors present in the hydrocarbon feed stream or the RO stream. We propose to maximize saturation of aromatics to naphthenes to minimize formation of HPNA's from PNA's. Additionally, saturated rings are more readily cracked in the second hydrocracking reactor 170. Aromatic saturation typically requires a noble metal catalyst. In the second hydrocracking unit 150, most of the sulfur and nitrogen has already been removed as hydrogen sulfide and ammonia from the recycle gas from the cold gaseous stream from cold overhead line 58 in the amine scrubbing column 62 and from the stripper off gas in the stripper net overhead line 114. Hence, these contaminants will not deactivate a noble metal catalyst in a second hydrotreating reactor 160.
The second hydrocracking unit 150 comprises a second hydrotreating reactor 160 and a second hydrocracking reactor 170. The RO stream may be mixed with make-up hydrogen gas in line 20 and/or a second hydrotreating hydrogen stream in a second hydrotreating hydrogen line 152 from the second stage hydrogen stream in the second stage hydrogen line 166 to provide a hydrotreating RO stream in a second hydrotreating feed line 154. The hydrotreating RO stream is heated and fed to the second hydrotreating reactor 160. The hydrotreating RO stream in the second hydrocarbon feed line 154 is hydrotreated over the second hydrotreating catalyst in the second hydrotreating reactor 160 to provide a second hydrotreated RO stream that exits the second hydrotreating reactor 160 in a second hydrotreating effluent line 162 which can be taken as a second hydrocracking feed stream. Supplemental hydrogen in a second hydrotreating supplemental hydrogen line 161 from the second stage hydrogen stream in the second stage hydrogen line 166 may be added at an interstage location between catalyst beds in the second hydrotreating reactor 160.
The second hydrotreating reactor 160 is in downstream communication with the atmospheric fractionation column 130 and the vacuum fractionation column 180. Particularly, the second hydrotreating reactor 160 is in downstream communication with a bottoms line 186 of the vacuum fractionation column 180.
The hydrotreating that is performed in the second hydrotreating reactor is geared predominantly toward aromatics saturation. The second hydrotreating catalyst in the second hydrotreating reactor 160 is preferably different from the first hydrotreating catalyst in the first hydrotreating unit 30. Suitable second hydrotreating catalysts for use in the second hydrotreating reactor are saturation hydrotreating catalysts and include those which are comprised of at least one Group VIII metal, preferably a noble metal comprising rhenium, ruthenium, rhodium, palladium, silver, osmium, iridium, platinum, and/or gold and optionally at least one non-noble metal, preferably cobalt, nickel, vanadium, molybdenum and/or tungsten, on a high surface area support material, preferably alumina. Other suitable hydrotreating catalysts include zeolitic catalysts and/or un-supported hydrotreating catalysts. More than one type of second hydrotreating catalyst may be used in the second hydrotreating reactor 160. The noble metal is typically present in an amount ranging from about 0.001 to about 20 wt %, preferably from about 0.05 to about 2 wt %. The non-noble metal will typically be present in an amount ranging from about 0.05 to about 30 wt %, preferably from about 1 to about 20 wt %. At least 40 wt % of the aromatics, preferably at least 60%, more preferably at least 90 % of the aromatics, in the RO stream entering the second hydrotreating reactor 160 in the second hydrocarbon feed line 154 are saturated in the second hydrotreating reactor 160.
Preferred reaction conditions in the second hydrotreating reactor 160 include a temperature from about 290° C. (550° F.) to about 455° C. (850° F.), suitably about 316° C. (600° F.) to about 427° C. (800° F.) and preferably about 343° C. (650° F.) to about 399° C. (750° F.), a pressure from about 2.1 MPa (gauge) (300 psig) to about 27.6 MPa (gauge) (4000 psig), preferably about 13.8 MPa (gauge) (2000 psig) to about 20.7 MPa (gauge) (3000 psig), a liquid hourly space velocity of the fresh hydrocarbonaceous feedstock from about 0.1 hr−1 to about 10 hr−1, preferably from about 1 to about 5 hr−1, and a hydrogen rate of about 168 Nm3/m3 (1,000 scf/bbl) to about 1,680 Nm3/m3 oil (10,000 scf/bbl), preferably about 674 Nm3/m3 oil (4,000 scf/bbl) to about 1,011 Nm3/m3 oil (6,000 scf/bbl), with a hydrotreating catalyst or a combination of hydrotreating catalysts.
Gas may be separated from the second hydrocracking feed stream in the second hydrotreating effluent line 162 to remove hydrogen gas laden with small amounts of ammonia and hydrogen sulfide from the second hydrocracking feed stream in a separator, but the second hydrocracking feed stream is suitably fed directly to the second hydrocracking reactor 170 without separation. The second hydrocracking feed stream may be mixed with a second hydrocracking hydrogen stream in a second hydrocracking hydrogen line 164 from the second stage hydrogen line 166 and is fed through a first inlet 162i to the second hydrocracking reactor 170 to be hydrocracked. The second hydrocracking reactor 170 may be in downstream communication with the first hydrotreating unit 30, the first hydrocracking reactor 40, the second hydrotreating reactor 160, the atmospheric fractionation column 130 and the vacuum fractionation column 180.
The second hydrocracking reactor 170 may be a fixed bed reactor that comprises one or more vessels, single or multiple catalyst beds 172 in each vessel, and various combinations of hydrotreating catalyst, hydroisomerization catalyst and/or hydrocracking catalyst in one or more vessels. It is contemplated that the second hydrocracking reactor 170 be operated in a continuous liquid phase in which the volume of the liquid hydrocarbon feed is greater than the volume of the hydrogen gas. The second hydrocracking reactor 170 may also be operated in a conventional continuous gas phase, a moving bed or a fluidized bed hydroprocessing reactor.
The second hydrocracking reactor 170 comprises a plurality of catalyst beds 172. If the second hydrocracking unit 150 does not include a second hydrotreating reactor 160, the first catalyst bed in the hydrocracking reactor 170 may include a second hydrotreating catalyst for the purpose of saturating aromatic rings in the RO stream before it is hydrocracked with the second hydrocracking catalyst in subsequent vessels or catalyst beds 172 in the second hydrocracking reactor 170.
The second hydrocracking feed stream is hydrocracked over the second hydrocracking catalyst in the second hydrocracking catalyst beds 172 in the presence of a second hydrocracking hydrogen stream from a second hydrocracking hydrogen line 164 to provide a second hydrocracked stream. Subsequent catalyst beds 172 in the hydrocracking reactor may comprise hydrocracking catalyst over which additional hydrocracking occurs. Hydrogen manifold 176 may deliver supplemental hydrogen streams from the second stage hydrogen line 166 to one, some or each of the catalyst beds 172. In an aspect, the supplemental hydrogen is added to each of the downstream catalyst beds 172 at an interstage location between adjacent beds, so supplemental hydrogen is mixed with hydrocracked effluent exiting from the upstream catalyst bed 172 before entering the downstream catalyst bed 172.
The second hydrocracking reactor 170 may provide a total conversion of at least about 1 vol % and typically greater than about 40 vol % of the second hydrocracking feed stream in the second hydrotreating effluent line 162 to products boiling below the diesel cut point. The second hydrocracking reactor 170 may complete the conversion partially achieved in the first hydrocracking reactor 40. The second hydrocracking reactor 170 may operate at partial conversion of more than about 30 vol % or full conversion of at least about 90 vol % of the first hydrocracking feed stream in the first hydrocracking feed line 32 based on total conversion. The second hydrocracking reactor 170 may be operated at mild hydrocracking conditions which will provide about 1 to about 60 vol %, preferably about 20 to about 50 vol %, total conversion of the resid hydrocarbon feed stream to product boiling below the diesel cut point.
The second hydrocracking catalyst may be the same as or different than the first hydrocracking catalyst or may have some of the same as and some different than the first hydrocracking catalyst in the first hydrocracking reactor 40. The second hydrocracking catalyst may utilize amorphous silica-alumina bases or low-level zeolite bases combined with one or more Group VIII or Group VIB metal hydrogenating components. Additional hydrogenating components may be selected from Group VIB for incorporation with the zeolite base.
By one approach, the hydrocracking conditions in the second hydrocracking reactor 170 may be the same as or different than in the first hydrocracking reactor 40. Conditions in the second hydrocracking reactor may include a temperature from about 290° C. (550° F.) to about 468° C. (875° F.), preferably about 343° C. (650° F.) to about 445° C. (833° F.), a pressure from about 2.1 MPa (gauge) (300 psig) to about 27.6 MPa (gauge) (4000 psig), preferably about 13.8 MPa (gauge) (2000 psig) to about 20.7 MPa (gauge) (3000 psig), a liquid hourly space velocity (LHSV) from about 0.4 to about 2.5 hr−1 and a hydrogen rate of about 168 Nm3/m3 (1,000 scf/bbl) to about 1,680 Nm3/m3 oil (10,000 scf/bbl), preferably about 674 Nm3/m3 oil (4,000 scf/bbl) to about 1,011 Nm3/m3 oil (6,000 scf/bbl).
The second hydrocracked stream may exit the second hydrocracking reactor 170 in the second hydrocracked effluent line 44, be heat exchanged with the hydrotreating RO stream in the second hydrotreating feed line 154 and combined with the first hydrocracked effluent stream in first hydrocracked effluent line 48. The first hydrocracked effluent stream and the second hydrocracked effluent stream combined in combined hydrocracked effluent line 49 are separated and fractionated in the fractionation section 14 in downstream communication with the second hydrocracking reactor 170 as previously described.
By saturating aromatics and PNA's; i.e., HPNA precursors, the present process and apparatus can achieve near total conversion of an atmospheric resid stream in hydrocarbonaceous feed line 18 to product boiling at or below the diesel cut point. The product is free or has only minimal quantity of HPNA's allowing a longer cycle length for the process and apparatus because the equipment is not fouled and the catalyst deactivates more slowly while eliminating the need to manage HPNA's. The saturated rings are more readily cracked in the second hydrocracking reactor 170 improving overall yield to distillate. The distillate product has a lower aromatics content, thereby boosting its cetane number and providing a higher volume yield with lower concentrations of sulfur and nitrogen.
While the following is described in conjunction with specific embodiments, it will be understood that this description is intended to illustrate and not limit the scope of the preceding description and the appended claims.
A first embodiment of the invention is a process for hydrocracking a hydrocarbon resid stream comprising hydrotreating a resid stream over a demetallization catalyst and a desulfurization catalyst in the presence of hydrogen to provide a hydrotreated resid stream reduced in metals and sulfur concentration; hydrocracking the hydrotreated resid stream over a first hydrocracking catalyst and hydrogen to provide a first hydrocracked stream; fractionating the hydrocracked stream at a pressure of at least atmospheric to provide a fractionated stream; fractionating the fractionated stream at a pressure below atmospheric to provide a recycle oil stream; hydrotreating the recycle oil stream over a hydrotreating catalyst to provide a second hydrocracking feed stream; and hydrocracking the second hydrocracking feed stream over a second hydrocracking catalyst in the presence of hydrogen to provide a second hydrocracked stream. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph wherein the hydrotreating the recycle oil stream comprises hydrotreating the recycle oil stream over a noble metal catalyst. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph wherein the hydrotreating the recycle oil stream comprises hydrotreating the recycle oil stream to saturate at least 40 wt % of aromatics in the recycle oil stream. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising hydrotreating the resid stream includes hydrotreating the resid stream over a denitrogenation catalyst in the presence of hydrogen to provide a hydrotreated resid stream reduced in nitrogen concentration. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph wherein a hydrotreating catalyst in the first hydrotreating step is different than a hydrotreating catalyst in the second hydrotreating step. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising separating a gas hydrotreated resid stream from the hydrotreated resid stream before hydrocracking the hydrotreated resid stream. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising separating the gas stream in a cold separator to provide a recycle gas stream. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising separating the hydrocracked stream in a hot separator into a hot vapor stream and a hot liquid stream and separating the hot vapor stream in the cold separator. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising separating the second hydrocracked stream in the hot separator to provide a liquid hydrocracked stream for fractionation. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising separating the first hydrocracked stream and the second hydrocracked stream in the hot separator to provide a liquid hydrocracked stream for fractionation.
A second embodiment of the invention is a process for hydrocracking a hydrocarbon resid stream comprising hydrotreating a resid stream over a demetallization catalyst, a desulfurization catalyst and a denitrogenation catalyst in the presence of hydrogen to provide a hydrotreated resid stream reduced in metals, sulfur and nitrogen concentration; hydrocracking the hydrotreated resid stream over a first hydrocracking catalyst and hydrogen to provide a first hydrocracked stream; fractionating the hydrocracked stream at a pressure of at least atmospheric to provide a fractionated stream; fractionating the fractionated stream at a pressure below atmospheric to provide a recycle oil stream; hydrotreating the recycle oil stream over a hydrotreating catalyst to provide a second hydrocracking feed stream; and hydrocracking the second hydrocracking feed stream over a second hydrocracking catalyst in the presence of hydrogen to provide a second hydrocracked stream. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph wherein the hydrotreating the recycle oil stream comprises hydrotreating the recycle oil stream over a noble metal catalyst. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph wherein the hydrotreating the recycle oil stream comprises hydrotreating the recycle oil stream to saturate at least 60 wt % of aromatics in the recycle oil stream. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph wherein a hydrotreating catalyst in the first hydrotreating step is different than a hydrotreating catalyst in the second hydrotreating step. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph further comprising separating a gas hydrotreated resid stream from the hydrotreated resid stream before hydrocracking the hydrotreated resid stream. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph further comprising separating the gas stream in a cold separator to provide a recycle gas stream.
A third embodiment of the invention is an apparatus for hydrocracking a hydrocarbon stream comprising a first hydrotreating unit for demetallizing and desulfurizing a first resid stream; a first separator in communication with the first hydrotreating reactor; a first hydrocracking reactor in downstream communication with the first separator; a first fractionation column in downstream communication with the first hydrocracking reactor; a second fractionation column in downstream communication with the first fractionation column; a second hydrotreating reactor in downstream communication with the second fractionation column; and a second hydrocracking reactor in downstream communication with the second hydrotreating reactor. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph wherein the first separator and the first hydrocracking reactor are in the same vessel. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph wherein a cold separator is in downstream communication with an overhead line of the separator and an effluent line of the first hydrocracking reactor. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph wherein a hot separator is in downstream communication with the first hydrocracking reactor and the second hydrocracking reactor.
Without further elaboration, it is believed that using the preceding description that one skilled in the art can utilize the present invention to its fullest extent and easily ascertain the essential characteristics of this invention, without departing from the spirit and scope thereof, to make various changes and modifications of the invention and to adapt it to various usages and conditions. The preceding preferred specific embodiments are, therefore, to be construed as merely illustrative, and not limiting the remainder of the disclosure in any way whatsoever, and that it is intended to cover various modifications and equivalent arrangements included within the scope of the appended claims.
In the foregoing, all temperatures are set forth in degrees Celsius and, all parts and percentages are by weight, unless otherwise indicated.
This application claims priority from Provisional Application No. 62/439,318 filed Dec. 27, 2016, the contents of which cited application are hereby incorporated by reference in its entirety.
| Number | Date | Country | |
|---|---|---|---|
| 62439318 | Dec 2016 | US |
