PROCESS FOR HYDROCRACKING A FEED STREAM

Description

FIELD

The field is related to a process of hydrocracking a feed stream. Particularly, the field is related to hydrocracking various feed streams.

BACKGROUND

Hydroprocessing can include processes which convert hydrocarbons in the presence of hydroprocessing catalyst and hydrogen to more valuable products. Hydrocracking is a hydroprocessing process in which hydrocarbons crack in the presence of hydrogen and hydrocracking catalyst to lower molecular weight hydrocarbons. Depending on the desired output, a hydrocracking unit may contain one or more fixed beds of the same or different catalyst. Hydrotreating is a process in which hydrogen is contacted with a hydrocarbon stream 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, olefinic hydrocarbons with double and triple bonds may be saturated. Aromatics may also be saturated. Some hydrotreating processes are specifically designed to saturate aromatics.

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. Typically, a bottom 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.

Light olefin production is vital to the production of sufficient plastics to meet worldwide demand. Ethylene and propylene are important chemicals for use in the production of other useful materials, such as polyethylene and polypropylene. Polyethylene and polypropylene are two of the most common plastics found in use today and have a wide variety of uses. Uses for ethylene and propylene include the production of vinyl chloride, ethylene oxide, ethylbenzene, cumene, polyols and alcohol.

Paraffin dehydrogenation (PDH) is a process in which light paraffins such as ethane, propane, and butane can be dehydrogenated to make ethylene, propylene, and butene respectively. Dehydrogenation is an endothermic reaction which requires external heat to drive the reaction to completion.

The great bulk of the ethylene consumed in the production of plastics and petrochemicals such as polyethylene is produced by the thermal cracking of hydrocarbons. Steam is usually mixed with the feed stream to the cracking furnace to reduce the hydrocarbon partial pressure and enhance olefin yield and to reduce the formation and deposition of carbonaceous material in the cracking reactors. The process is therefore often referred to as steam cracking or pyrolysis.

Feedstocks used in steam crackers to produce ethylene include ethane, LPG molecules such as propane and butanes, straight run light naphtha and straight run heavy naphtha. Mixed feed steam crackers may also use other components of crude oil distillation and refining processes such as straight-run distillate streams, hydrotreated distillate, hydrotreated vacuum gas oils, and heavy naphtha, diesel and unconverted oil hydrocrackers. Ethane and LPG are not readily available in many world geographic locations. Light and heavy naphtha are not available in abundance in crude oil for a world-scale economically competitive production of ethylene. Steam cracking operations to produce polyolefins suffer from feed limitations. For example, hydrotreated heavier crude components produce low yields of ethylene in steam crackers. Further, hydrocrackers producing primarily heavy naphtha for steam cracking are rich in naphthenes and isomers that produce higher yields of pyrolysis gasoline and pyrolysis oil and methane.

Pyrolysis gasoline (pygas) and fuel oil (pyoil) are less valuable by-products of steam cracking. Pygas contains large proportions of paraffins and aromatics. The resulting paraffins include normal and non-normal paraffins which can be recovered or further processed. Aromatics are very stable and difficult to crack in a steam cracker. The paraffinic side chains can be removed, but this leads to the production of multi-ring aromatics which increases the yield of low-value fuel oil.

Better processes and apparatuses are needed to overcome the aforesaid feed limitations.

BRIEF SUMMARY

A process of hydrocracking a feed stream is disclosed. The process comprises hydrocracking a feed stream in a hydrocracking reactor over a hydrocracking catalyst in the presence of a hydrocracking hydrogen stream at hydrocracking conditions. Under the hydrocracking conditions, at least 95 vol % of all rings present in the feed stream are opened to produce a hydrocracked effluent stream. The produced hydrocracked effluent stream is an aliphatic stream. The hydrocracking process can convert all the distillable, extractable and converted crude that boils at the same or higher boiling point than C6 naphthenes and benzene. The hydrocracked product stream of the process is not heavier than heavy naphtha.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic drawing of an exemplary embodiment of the present disclosure.

FIG. 2 is a schematic drawing of another exemplary embodiment of the present disclosure.

DEFINITIONS

The term “communication” means that fluid flow is operatively permitted between enumerated components, which may be characterized as “fluid communication”.

The term “downstream communication” means that at least a portion of fluid flowing to the subject in downstream communication may operatively flow from the object with which it fluidly communicates.

The term “upstream communication” means that at least a portion of the fluid flowing from the subject in upstream communication may operatively flow to the object with which it fluidly communicates.

The term “direct communication” means that fluid flow from the upstream component enters the downstream component without passing through any other intervening vessel.

The term “indirect communication” means that fluid flow from the upstream component enters the downstream component after passing through an intervening vessel.

The term “bypass” means that the object is out of downstream communication with a bypassing subject at least to the extent of bypassing.

The term “column” means a distillation column or columns for separating one or more components of different volatilities. Unless otherwise indicated, each column includes a condenser on an overhead of the column to condense and reflux a portion of an overhead stream back to the top of the column and a reboiler at a bottom of the column to vaporize and send a portion of a bottoms stream back to the bottom of the column. Feeds to the columns may be preheated. The top pressure is the pressure of the overhead vapor at the vapor outlet of the column. The bottom temperature is the liquid bottom outlet temperature. Overhead lines and bottoms lines refer to the net lines from the column downstream of any reflux or reboil to the column. Stripper columns may omit a reboiler at a bottom of the column and instead provide heating requirements and separation impetus from a fluidized inert media such as steam. Stripping columns typically feed a top tray and take main product from the bottom.

As used herein, the term “rich” can mean an amount of at least generally 50%, and preferably 70%, more preferably 90% or above by mass of a compound or class of compounds in a stream.

As used herein, the term “a component-rich stream” or “a stream rich in a component” means that the rich stream coming out of a vessel has a greater concentration of the component than any other stream from the vessel.

As used herein, the term “a component-lean stream” or “a stream lean in a component” means that the lean stream coming out of a vessel has a smaller concentration of the component than any other stream from the vessel.

As used herein, the term “initial boiling point” (IBP) means the temperature at which the sample begins to boil using a simulated distillation method of ASTM D-7169, ASTM D-86 or D 1160, or TBP, as the case may be.

As used herein, the term “end point” (EP) means the temperature at which the sample has all boiled off using a simulated distillation method of ASTM D-7169, ASTM D-86 or D 1160, or TBP, as the case may be.

As used herein, the term “separator” means a vessel which has an inlet and at least an overhead vapor outlet and a bottoms liquid outlet and may also have an aqueous stream outlet from a boot. A flash drum is a type of separator which may be in downstream communication with a separator that may be operated at higher pressure.

As used herein, the term “predominant” or “predominate” means greater than 50%, suitably greater than 75% and preferably greater than 90%.

The term “Cx” is to be understood to refer to molecules having the number of carbon atoms represented by the subscript “x”. Similarly, the term “Cx−” refers to molecules with x and preferably x and less carbon atoms. The term “Cx+” refers to molecules with x and preferably x and more carbon atoms.

The term “unit” is to be understood to refer to one or more process steps comprising a chemical transformation. At the heart of a unit is one or more catalytic reactors or separation vessels necessary to accomplish the transformation. A unit may further comprise additional separation vessels including fractionation column(s) to separate product streams. A unit may further comprise pretreatment steps for the chemical transformation. Taken together, “unit” comprises one or more reactors or separation vessels and separation steps and pretreatment steps, whether or not shown in the diagram or explicitly discussed in the specification.

The terms “T10” and “T90” are used here to characterize the volatility of a petroleum fraction. T10 and T90 refer to the temperatures for recovery of 10% and 90%, respectively, in distillation of petroleum products corrected to atmospheric pressure using a laboratory standard method of ASTM D-7169, ASTM D-86 or D 1160, or TBP, as the case may be.

As used herein, the term “separator” means a vessel which has an inlet and at least an overhead vapor outlet and a bottoms liquid outlet and may also have an aqueous stream outlet from a boot. A flash drum is a type of separator which may be in downstream communication with a separator that may be operated at higher pressure.

As used herein, the term “carbon number” refers to the number of carbon atoms per hydrocarbon molecule.

As used herein, the term “passing” includes “feeding” and means that the material passes from a conduit or vessel to an object.

As used herein, the prefix “bio” as used herein, refers to an association with a renewable resource of biological origin, such resources generally being exclusive of fossil fuels.

As used herein, the term “net” with respect to products means products in the desired boiling range excluding unconverted materials such as unconverted oil.

DETAILED DESCRIPTION

The disclosure provides a process of hydrocracking a feed stream. The typical hydrocracking process produces highly naphthene-rich products such as producing heavy naphtha, distillates and unconverted oils rich with naphthene rings and lower concentrations of aromatic rings. The current process substantially saturates nearly all aromatics and opens the subsequently formed naphthene rings.

A process 101 of hydrocracking a feed stream is shown in FIG. 1. The process unit 101 is a single stage hydrocracking unit that comprises a first stage hydrocracking unit 12, and a fractionation section 14. As shown, a hydrocarbonaceous feed stream in line 102 is passed to the first stage hydrocracking unit 12. In accordance with the present disclosure, the hydrocarbonaceous feed stream in line 102 may be of petroleum origin or a bio-based or a combination of both. In an aspect, the hydrocarbonaceous feed stream in line 102 may comprise more than one feed stream. The hydrocarbonaceous feed stream in line 102 may comprise one or more hydrocarbons or heteroatomic hydrocarbonaceous components such as C6 naphthenes, benzene and C7 through nominally C80 to C100. Such feeds may include heavy naphtha, kerosene, heavy diesel, distillates, gas oil and deasphalted oil from the distillation and/or extraction of crude oils. Other such feeds can include intermediates of the same boiling ranges aforementioned derived from refining processes such as delayed coking, flexicoking, slurry or ebullated bed vacuum residue hydrocracking, fluidized catalytic cracking units and the like. Such feeds can also include plastic pyrolysis oils, Fischer-Tropsch liquids and waxes.

In accordance with the present disclosure, the hydrocarbonaceous feed stream in line 102 may be hydroprocessed in several different non-limiting hydroprocessing configurations such as a once-through, single stage recycle and two-stage hydrocracking configurations. The number of stages employed can be somewhat, but not necessarily, economically dependent on the feed properties. For example, feed streams devoid or with minimal threshold organic nitrogen concentration could be processed in a once-through configuration or a single-stage recycle configuration. A feed stream with a higher than threshold concentration of nitrogen would be more economically processed in a two-stage unit. In one example, a crude oil of a more typical Middle Eastern crude source is distilled into streams comprising heavy naphtha, kerosene, heavy diesel, atmospheric gas oil, vacuum gas oils and a vacuum residue. The vacuum residue may be further upgraded by extracting a deasphalted oil or the vacuum residue may be further converted into vacuum gas oil and lighter boiling products boiling higher than C6 naphthenes. One or more of the aforementioned distilled or extracted, streams upgraded from vacuum residue may be taken as the hydrocarbonaceous feed stream in line 102. Aromatic-rich streams may also be taken as a feed stream or a component of the hydrocarbonaceous feed stream in line 102. Plastics pyrolysis oil may also be taken as a feed stream or a component of the hydrocarbonaceous feed stream in line 102.

In an embodiment, the hydrocarbonaceous feed stream in line 102 may be processed in a single or a multistage hydrocracking unit. In an embodiment, the hydrocarbonaceous feed stream in line 102 may be processed in a single-stage hydrocracking unit as shown in the FIG. 1. In an exemplary embodiment, the first stage hydrocracking unit 12 is a single-stage hydrocracking unit comprising a first hydrocracking reactor 120. A single-stage hydrocracking unit 12 may be selected for feed that is less aromatic and more paraffinic.

Referring to FIG. 1, a first hydrotreating hydrogen stream in a first hydrotreating hydrogen line 182a may be taken from a first stage hydrogen line 182. The first hydrotreating hydrogen stream may join the hydrocarbonaceous feed stream in feed line 102 to provide a first hydrocarbon feed stream in a first hydrocarbon feed line 103. The first hydrocarbon feed stream in the first hydrocarbon feed line 103 may be heated by heat exchange in a heat exchanger 11 with a first hydrocracked stream in line 122. The heated first hydrocarbon feed stream in line 104 is heated in a fired heater 105. A heated first hydrocarbon feed stream in line 106 may be fed to a first hydrotreating reactor 110.

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, chlorine, and metals from the hydrocarbon feedstock. In hydrotreating, olefinic 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 hydrotreating reactor 110 may comprise a guard bed of hydrotreating catalyst followed by one or more beds of higher activity hydrotreating catalyst. The guard bed filters particulates and reacts contaminants in the hydrocarbon feed stream such as organo-metallic components containing metals like nickel, vanadium, silicon and arsenic which load onto the catalyst and deactivate the catalyst. The guard bed may comprise material similar to the hydrotreating catalyst. Supplemental hydrogen in a first hydrotreating supplemental hydrogen line 182b may be added at an interstage location between catalyst beds in the first hydrotreating reactor 110.

Suitable first hydrotreating catalysts for use in the first hydrotreating reactor 110 may include any known conventional hydrotreating catalysts and include those which are comprised of at least one Group VIII metal, preferably iron, cobalt and nickel, more preferably cobalt and/or nickel and at least one Group VI metal, preferably molybdenum and tungsten, on a high surface area support material, preferably alumina. Other suitable hydrotreating catalysts include zeolitic catalysts. In the high sulfur and nitrogen environment of the first hydrotreating reactor 110, noble metal catalysts would be discouraged. More than one type of first hydrotreating catalyst may be used in the first hydrotreating reactor 110. The Group VIII metal is typically present in an amount ranging from about 2 to about 20 wt %, preferably from about 4 to about 12 wt %. The Group VI metal will typically be present in an amount ranging from about 1 to about 25 wt %, preferably from about 2 to about 25 wt %.

Preferred reaction conditions in the first hydrotreating reactor 110 may include a temperature from about 290° C. (550° F.) to about 455° C. (850° F.), suitably 316° C. (600° F.) to about 427° C. (800° F.) and preferably 343° C. (650° F.) to about 399° C. (750° F.), a pressure from about 2.1 MPa (gauge) (300 psig), preferably 4.1 MPa (gauge) (600 psig) to about 20.6 MPa (gauge) (3000 psig), suitably 13.8 MPa (gauge) (2000 psig), preferably 12.4 MPa (gauge) (1800 psig), a liquid hourly space velocity of the fresh hydrocarbonaceous feedstock from about 0.1 hr⁻¹, suitably 0.5 hr⁻¹, to about 10 hr⁻¹, preferably from about 1.5 to about 8.5 hr⁻¹, and a hydrogen rate of about 168 Nm3/m3 (1,000 scf/bbl), to about 1,011 Nm3/m3 oil (6,000 scf/bbl), preferably about 168 Nm3/m3 oil (1,000 scf/bbl) to about 674 Nm3/m3 oil (4,000 scf/bbl), with a hydrotreating catalyst or a combination of hydrotreating catalysts.

The heated first hydrocarbon feed stream in line 106 is hydrotreated over the first hydrotreating catalyst in the first hydrotreating reactor 110 to provide a first hydrotreated hydrocarbon feed stream that exits the first hydrotreating reactor 110 in a first hydrotreating effluent line 112 which can be taken as a first hydrocracking feed stream. The hydrogen gas laden with ammonia and hydrogen sulfide may be removed from the first hydrocracking feed stream in a separator, but the first hydrocracking feed stream is typically fed directly to the first hydrocracking reactor 120 without separation. The first hydrocracking feed stream may be mixed with a first hydrocracking hydrogen stream in a first hydrocracking hydrogen line 182c taken from the first stage hydrogen line 182 and is fed through to the first hydrocracking reactor 120.

In an exemplary embodiment, the first hydrocracking feed stream in line 112 may be combined with a recycle oil stream in line 168 to provide a charge stream in line 113. The charge stream in line 113 may be combined with the first hydrocracking hydrogen stream in line 182c to provide a combined feed stream in line 114. The combined feed stream in line 114 is passed to the first hydrocracking reactor 120.

Hydrocracking is a process in which hydrocarbons crack in the presence of hydrogen to lower molecular weight hydrocarbons. The first hydrocracking reactor 120 may be a fixed bed reactor that comprises one or more vessels, single or multiple catalyst beds in each vessel, and various combinations of hydrotreating catalyst, hydroisomerization catalyst and/or hydrocracking catalyst in one or more vessels. The first hydrocracking reactor 120 may be operated in a conventional continuous gas phase, a moving bed or a fluidized bed hydroprocessing reactor. More typically, the first hydrocracking reactor 120 is operated in a mixed phase with gas and liquid phases passing over a stationary solid, fixed bed of catalyst or catalysts.

The first hydrocracking reactor 120 comprises a plurality of first hydrocracking catalyst beds 120a. If the first hydrocracking reactor 120 does not include a first hydrotreating reactor 110, the first catalyst bed in the hydrocracking reactor 120 may include a first hydrotreating catalyst for the purpose of saturating, demetallizing, desulfurizing, dechlorinating or denitrogenating the first hydrocarbon feed stream before it is hydrocracked with the first hydrocracking catalyst in subsequent vessels or catalyst beds 120a in the first hydrocracking reactor 120. Otherwise, the first or an upstream bed in the first hydrocracking reactor 120 may comprise a first hydrocracking catalyst bed.

The hydrotreated first hydrocracking feed stream is hydrocracked over a first hydrocracking catalyst in the first hydrocracking catalyst beds 120a in the presence of a first hydrocracking hydrogen stream in line 182c from the first hydrocracking hydrogen line 182 to provide a first hydrocracked stream. Subsequent catalyst beds 120a in the first hydrocracking reactor 120 may comprise hydrocracking catalyst over which additional hydrocracking occurs to the hydrocracked stream. Hydrogen manifold 182d may deliver supplemental hydrogen streams to one, some or each of the catalyst beds 120a. In an aspect, the supplemental hydrogen is added to each of the catalyst beds 120a at an interstage location between adjacent beds, so supplemental hydrogen is mixed with hydroprocessed effluent exiting from the upstream catalyst bed 120a before entering the downstream catalyst bed 120a.

In the first hydrocracking reactor 120, under the aforesaid prevalent hydrocracking conditions, a predominant proportion of the rings present in the hydrocarbonaceous feed stream in line 102 may be opened to produce aliphatic hydrocarbons in a hydrocracked effluent stream. In an aspect, at least 95 vol % of all rings present in the hydrocarbonaceous feed stream in line 102 may be opened to produce aliphatic hydrocarbons. In an exemplary embodiment, the rings present in the hydrocarbonaceous feed stream in line 102 may comprise naphthene rings and aromatics rings.

The first hydrocracking reactor 120 may convert about 40 wt % to about 70 wt % of the total feed hydrocarbons into net product hydrocarbons boiling less than or equal to C6 paraffins or between about 18° C. (65° F.) and about 27° C. (80° F.). In another embodiment the preferred conversion may be about 45 wt % to about 60 wt % of the total feed hydrocarbons into net product hydrocarbons boiling less than or equal to C6 paraffins or between about 18° C. (65° F.) and about 27° C. (80° F.). The reduction in endpoint between the hydrocarbonaceous feed stream to the hydrocracking reactor and the hydrocracked effluent stream may be at least 500° C. (900° F.) and preferably at least 538° C. (1000° F.).

The first hydrocracking catalyst may utilize bases comprising amorphous silica-alumina or zeolites 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 light naphtha and LPG, which are aliphatic hydrocarbons or six carbon numbers and lower, are significantly preferred in the converted product over gasoline or distillate production, partial or complete hydrocracking conversion to aliphatic hydrocarbons of six carbon numbers or less may be performed in the first hydrocracking reactor 120 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. In one embodiment, when the first hydrocracking reactor 120 is operated in a single-stage reaction configuration, complete hydrocracking conversion to aliphatic hydrocarbons of six carbon numbers or less may be performed.

The zeolites in hydrocracking bases are sometimes referred to in the art as molecular sieves and are usually composed of silica, alumina and one or more exchangeable cations such as sodium, magnesium, calcium, rare earth metals, etc. They are further characterized by crystal pores of relatively uniform diameter between about 4 and about 14 Angstroms. It is preferred to employ zeolites having a relatively high silica/alumina mole ratio between about 3 and about 12. Suitable zeolites found in nature include, for example, mordenite, stilbite, heulandite, ferrierite, dachiardite, chabazite, erionite and faujasite. Suitable synthetic zeolites include, for example, the B, X, Y and L crystal types, e.g., synthetic faujasite and mordenite. The preferred zeolites are those having crystal pore diameters between about 8 and 12 angstroms, wherein the silica/alumina mole ratio is about 4 to 6. One example of a zeolite falling in the preferred group is synthetic Y molecular sieve.

The natural occurring zeolites are normally found in a sodium form, an alkaline earth metal form, or mixed forms. The synthetic zeolites are nearly always prepared 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 another embodiment, Group VIII metals such as nickel or cobalt may be used to promote the aromatic saturation and intermediates re-hydrogenation activity of Group VIB metals. Such Group VIB hydrogenation metals may comprise 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 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. 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 metal and activation by calcining. In yet another embodiment the base component may first be pelleted, followed by the addition of the hydrogenation metal and dried.

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.

In an embodiment, the hydrocracking conditions in the first hydrocracking reactor 120 may include a temperature from about 290° C. (550° F.) to about 468° C. (875° F.), preferably 343° C. (650° F.) to about 445° C. (833° F.), a pressure from about 4.8 MPa (gauge) (700 psig) to about 20.7 MPa (gauge) (3000 psig), a liquid hourly space velocity (LHSV) of about 0.3 to about 1.5 hr⁻¹, suitably no more than about 1.0 hr⁻¹ and preferably about 0.4 to about 0.7 hr⁻¹ and a hydrogen rate of about 421 Nm3/m3 (2,500 scf/bbl) to about 2,527 Nm3/m3 oil (15,000 scf/bbl). Hydrogen partial pressure may be 1 MPa (abs) (1500 psia) to about 1.7 MPa (abs) (2500 psia).

The first hydrocracked stream may exit the first hydrocracking reactor 120 in line 122. In an aspect, the net converted product in the first hydrocracked stream in line 122 may comprise at least about 95 vol % aliphatic components. In another aspect, the net converted product in the first hydrocracked stream in line 122 may comprise at least about 98 vol % aliphatic components. The first hydrocracked stream in line 122 may be separated in the fractionation section 14 in downstream communication with the first hydrocracking reactor 120. The fractionation section 14 may comprise one or more separators, stripper columns, and fractionation columns in downstream communication with the first hydrocracking reactor 120.

The first hydrocracked stream in the first hydrocracked line 122 may be cooled by heat exchange with the first hydrocarbon feed stream in line 103. C6 naphthenes, benzene and higher boiling unconverted components from the first hydrocracking reactor 120 are separated from a hydrogen-rich recycle gas, and C6 paraffin and lighter boiling net product components through a series of separation steps including higher-pressure flashes in the fractionation section 14.

In an embodiment, the first hydrocracked stream in line 122 is passed to a hot separator 125. The hot separator separates the first hydrocracked stream to provide a hydrocarbonaceous, hot gaseous stream in a hot overhead line 126 and a hydrocarbonaceous, hot liquid stream in a hot bottoms line 127. The hot separator 125 may be in downstream communication with the first hydrocracking reactor 120. The hot separator 125 may be operated 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 125 may be operated at a slightly lower pressure than the first hydrocracking reactor 120 accounting for pressure drop through intervening equipment. The hot separator 125 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 126 may have a temperature of the operating temperature of the hot separator 125.

The hot gaseous stream in the hot overhead line 126 may be cooled before entering a cold separator 128. As a consequence of the reactions taking place in the first hydrocracking reactor 120 wherein nitrogen, chlorine and sulfur are removed from the feed, ammonia and hydrogen sulfide and hydrogen chloride are formed. At a characteristic sublimation temperature, ammonia and hydrogen sulfide will combine to form ammonium bisulfide and ammonia, and ammonia and hydrogen chloride will combine to form ammonium chloride. Each compound has a characteristic sublimation temperature that may allow the compound to coat equipment, particularly heat exchange equipment, impairing its performance. To prevent such deposition of ammonium bisulfide or ammonium chloride salts in the hot overhead line 126 transporting the hot gaseous stream, a suitable amount of wash water may be introduced into the hot overhead line 126 upstream of a cooler by a water line 51 at a point in the hot overhead line where the temperature is above the characteristic sublimation temperature of either compound. In another embodiment a suitable amount of wash water may be introduced into line 122 by a water line (not shown).

The hot gaseous stream may be separated in the cold separator 128 to provide a cold gaseous stream comprising a hydrogen-rich gas stream in a cold overhead line 123 and a cold liquid stream in a cold bottoms line 129. The cold separator 128 serves to separate hydrogen rich gas from hydrocarbon liquid in the first hydrocracked stream for recycle to the first stage hydrocracking unit 12 in the cold overhead line 123. The cold separator 128, therefore, is in downstream communication with the hot overhead line 126 of the hot separator 125 and the first hydrocracking reactor 120. The cold separator 125 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 below the pressure of the first hydrocracking reactor 120 and the hot separator 125 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 128 may be operated at pressures between about 3 MPa (gauge) (435 psig) and about 20 MPa (gauge) (2,901 psig). The cold separator 128 may also have a boot for collecting an aqueous phase in line 131. The cold liquid stream in the cold bottoms line 129 may have a temperature of the operating temperature of the cold separator 128.

The cold gaseous stream in the cold overhead line 123 is rich in hydrogen. Thus, hydrogen can be recovered from the cold gaseous stream. The cold gaseous stream in the cold overhead line 123 may be passed through a trayed or packed recycle scrubbing column 175 where it is scrubbed by means of a scrubbing extraction liquid such as an aqueous solution fed by line 121 to remove acid gases including hydrogen sulfide and carbon dioxide by extracting them into the aqueous solution. Preferred aqueous solutions include lean amines such as alkanolamines DEA, MEA, and MDEA. Other amines can be used in place of or in addition to the preferred amines. The lean amine contacts the cold gaseous stream and absorbs acid gas contaminants such as hydrogen sulfide and carbon dioxide. The resultant “sweetened” cold gaseous stream is taken out from an overhead outlet of the recycle scrubber column 175 in a recycle scrubber overhead line 176, 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 177. The spent scrubbing liquid from the bottoms may be regenerated and recycled back to the recycle scrubbing column 175 in line 121. The scrubbed hydrogen-rich stream emerges from the scrubber via the recycle scrubber overhead line 176 and may be compressed in a recycle compressor 180. The scrubbed hydrogen-rich stream in the scrubber overhead line 176 may be supplemented with make-up hydrogen stream in the make-up line 177 upstream or downstream of the compressor 180. A combined hydrogen rich stream in line 178 may be passed to the compressor 180. A compressed hydrogen stream is taken in line 181 from the compressor 180. The compressed hydrogen stream in line 181 supplies hydrogen to the first stage hydrogen stream in the first stage hydrogen line 182. The recycle scrubbing column 175 may be operated with a gas inlet temperature between about 38° C. (100° F.) and about 80° C. (175° 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 127 may be directly stripped. In an aspect, the hot liquid stream in the hot bottoms line 127 may be let down in pressure and flashed in a hot flash drum 130 to provide a flash hot gaseous stream of light ends in a flash hot overhead line 132 and a flash hot liquid stream in a flash hot bottoms line 138. The hot flash drum 130 may be in direct, downstream communication with the hot bottoms line 127 and in downstream communication with the first hydrocracking reactor 120. In an aspect, light gases such as hydrogen sulfide may be stripped from the flash hot liquid stream in the flash hot bottoms line 138. Accordingly, a stripping column 140 may be in downstream communication with the hot flash drum 130 and the hot flash bottoms line 138.

The hot flash drum 130 may be operated at the same temperature as the hot separator 125 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 138 may be further fractionated in the fractionation section 14. The flash hot liquid stream in the flash hot bottoms line 138 may have a temperature of the operating temperature of the hot flash drum 130.

In an aspect, the cold liquid stream in the cold bottoms line 129 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 135 to separate the cold liquid stream in the cold bottoms line 129. The cold flash drum 135 may be in direct downstream communication with the cold bottoms line 129 of the cold separator 128 and in downstream communication with the hydrocracking reactor 120.

In a further aspect, the flash hot gaseous stream in the flash hot overhead line 132 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 135. The cold flash drum 135 may separate the cold liquid stream in line 129 and/or the flash hot gaseous stream in the flash hot overhead line 132 to provide a flash cold gaseous stream in a flash cold overhead line 136 and a flash cold liquid stream in a cold flash bottoms line 137. In an aspect, light gases such as hydrogen sulfide may be stripped from the flash cold liquid stream in the flash cold bottoms line 137. Accordingly, a stripping column 140 may be in downstream communication with the cold flash drum 135 and the cold flash bottoms line 137.

The cold flash drum 135 may be in downstream communication with the cold bottoms line 129 of the cold separator 128, the hot flash overhead line 132 of the hot flash drum 130 and the hydrocracking reactor 120. The flash cold liquid stream in the cold bottoms line 129 and the flash hot gaseous stream in the hot flash overhead line 132 may enter into the cold flash drum 135 either together or separately. In an aspect, the hot flash overhead line 132 joins the cold bottoms line 129 and feeds the flash hot gaseous stream and the cold liquid stream together to the cold flash drum 135 in a cold flash feed line 133. The cold flash drum 135 may be operated at the same temperature as the cold separator 128 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 135 in line 134. The flash cold liquid stream in the flash cold bottoms line 137 may have the same temperature as the operating temperature of the cold flash drum 135. The flash cold gaseous stream in the flash cold overhead line 136 contains substantial hydrogen that may be recovered.

The fractionation section 14 may include the stripping column 140 and a naphtha splitter column 160. The stripping column 140 may be in downstream communication with a bottoms line in the fractionation section 14 for stripping volatiles from a first hydrocracked stream. For example, the stripping column 140 may be in downstream communication with the hot bottoms line 127, the flash hot bottoms line 138, the cold bottoms line 129 and/or the cold flash bottoms line 137.

The flash cold liquid stream comprising the first hydrocracked stream in the flash cold bottoms line 137 may be heated and fed to the stripping column 140 at an inlet which may be in a top half of the column. The flash cold liquid stream which comprises the first hydrocracked stream may be stripped of gases in the stripping column 140 with a stripping media which is an inert gas such as steam from a stripping media line 141 to provide a stripper gaseous stream of naphtha, hydrogen, hydrogen sulfide, steam and other gases in a stripper overhead line 142. The stripper gaseous stream in the stripper overhead line 142 may be condensed in a condenser 21 and separated in a receiver 143. In an aspect, the condenser 21 is a total condenser. A stripper overhead line 149 from the receiver 143 carries a net stripper gaseous stream for further recovery. An overhead liquid stream is taken in line 144 from the receiver 143. A reflux stream is taken in line 146 from the overhead liquid stream and recycled near the top of the stripping column 140. A net liquid stream is taken from the overhead liquid stream 144 in line 147. The net liquid stream in line 147 may be combined with the stripper overhead stream in line 149 to provide a net stripper overhead stream in line 151.

The net stripper overhead stream in line 151 may be taken for recovery of C1-C3 hydrocarbons. Some C4 may be present in the net stripper overhead stream in line 151. For example, a propane stream may be recovered from the net stripper overhead stream in line 151. A light ends stream of C1-C2 hydrocarbons may also be separated from the net stripper overhead stream in line 151. Butane may also be separated from the net stripper overhead stream in line 151. A sour water stream may be collected from a boot of the overhead receiver 143 in line 145.

The stripping column 140 may be operated with a bottoms temperature between about 149° C. (300° F.) and about 360° C. (680° F.) or about 160° C. (320° F.) to about 288° C. (550° F.), and an overhead pressure of about 0.35 MPa (gauge) (50 psig), preferably no less than about 0.50 MPa (gauge) (72 psig), to no more than about 2.0 MPa (gauge) (290 psig). The temperature in the overhead receiver 143 may range from about 38° C. (100° F.) to about 66° C. (150° F.) and the pressure is essentially the same as in the overhead of the stripping column 140.

The flash hot liquid stream comprising a hydrocracked stream in the hot flash bottoms line 138 may be fed to the stripping column 140 near a bottom half of the column. The flash hot liquid stream may be stripped in the stripping column 140 of gases with a stripping media which is an inert gas such as steam from a line 141. A liquid stripped stream is taken from the stripper bottoms in a stripper bottoms line 148.

At least a portion of the stripped stream comprising a hydrocracked stream in the stripped bottoms line 148 may be taken in a reboiling line 152. The reboiling stream may be heated in a reboiler 153 to provide a heated reboiling stream in line 154 which is recycled to near the bottoms of the stripping column 140. The net liquid stripped stream in the net stripper bottoms line 151 is passed to the naphtha splitter column 160. The naphtha splitter column 160 may be in downstream communication with the stripped bottoms line 148 of the stripping column 140.

In an aspect, the stripped stream in the stripped bottoms line 151 may be heated and fed to the naphtha splitter column 160. In an aspect, the naphtha splitter column 160 may comprise more than one fractionation column for separating stripped hydrocracked streams into product streams. The naphtha splitter column 160 may fractionate hydrocracked stream in the liquid stripped stream to provide the product streams. The product streams from the naphtha splitter column 160 may include a splitter net overhead stream comprising liquefied petroleum gas and light naphtha and a bottoms product stream comprising heavy naphtha. The bottoms stream of heavy naphtha exhibits a T90 between about 77° C. (170° F.) and about 93° C. (200° F.). The bottoms stream has an endpoint less than that of the hydrocarbonaceous feed stream in line 102 by at least about 110° C. (200° F.), preferably by at least about 360° C. (650° F.), and most preferably at least about 528° C. (950° F.).

The present process nearly completely saturates all aromatics and opens at least 95 vol % of all rings. The present process produces hydrocarbons which are lighter than a heavy naphtha stream of C10 to C13 hydrocarbons.

A splitter overhead stream in an overhead line 161 may be condensed in a condenser 31 and separated in a receiver 155 with a portion of the condensed liquid being refluxed back to the naphtha splitter column 160 in a reflux stream in line 159. In an aspect, the condenser 31 is a total condenser. The splitter net overhead stream in line 158 may be an aliphatic C4-C6 stream which can be further processed to recover butane and light naphtha as product. In a preferred embodiment, the net liquid product stream in line 158 is predominantly aliphatic, and preferably predominantly aliphatic hydrocarbons of C6 and lower. The net product stream of light naphtha exhibits a T90 between about 18° C. (65° F.) and about 27° C. (80° F.). The naphtha splitter column 160 may be operated with a bottom 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 splitter bottoms stream comprising heavy naphtha may be taken in a splitter column bottoms line 164 from a bottom of the naphtha splitter column 160. The splitter bottoms stream in line 164 is an unconverted oil stream comprising C6 naphthenes, benzene and unconverted material with boiling points higher than benzene. In an exemplary embodiment, the splitter bottoms stream in line 164 comprises heavy naphtha and HPNA's together. A reboiling stream may be taken in line 163 from the splitter bottoms stream in line 164. The reboiling stream may be heated in a reboiler 32 to provide a heated reboiling stream in line 165 which is recycled to the bottoms of the naphtha splitter column 160. A net splitter bottoms stream in line 168 may be taken from the splitter bottoms stream in line 164 recycled as a recycle oil (RO) to the first hydrocracking reactor 120. In an embodiment, the net splitter bottoms stream in line 168 is combined with the first hydrocracking feed stream in line 112 and charged to the first hydrocracking reactor 120. A purge stream in line 139 may be taken from the splitter bottoms stream in line 164 for HPNA removal. In an aspect, the splitter bottoms stream in line 164 comprises about 100 to about 1000 wppm HPNA. In another embodiment, the splitter bottoms stream in line 164 comprises less than about 30 wt % aromatics.

The single-stage process may convert about 40 to about 70 wt % of the total feed into net product components boiling less than or equal to C7 paraffins in a per-pass conversion. In another embodiment, the preferred per-pass conversion may be about 45 wt % to about 60 wt % conversion into net product components boiling less than or equal to C7 paraffins. The combined feed ratio of the unit may be varied between about 1.01 to about 2.5. The overall conversion in the single-stage configuration on the basis of feed rate is at least about 90%, preferably at least about 95%, more preferably at least about 98% and most preferably at least about 100% conversion of components boiling above the C7 paraffin range to components boiling below the C7 paraffin range which are preferably C6-aliphatic hydrocarbons.

FIG. 2 shows an alternative embodiment to the embodiment of FIG. 1 which employs a two-stage configuration for hydrocracking. Elements in FIG. 2 with the same configuration as in FIG. 1 will have the same reference numeral as in FIG. 1. Elements in FIG. 2 which have a different configuration as the corresponding element in FIG. 1 will have the same reference numeral but designated with a prime symbol (′). The configuration and operation of the embodiment of FIG. 2 is essentially the same as in FIG. 1 with the following exceptions.

A process 101′ of hydrocracking a feed stream is shown in FIGURE. The process 101′ is a two-stage hydrocracking configuration comprising the first stage hydrocracking unit 12′ and a second stage hydrocracking unit 16. The second stage hydrocracking unit 16 converts the aromatics present in the naphtha splitter column bottoms stream in line 164′. The two-stage configuration of the process 101′ of FIG. 2 is more suited to a feed 102 of higher aromatic concentration which is harder to convert to below the heavy naphtha boiling range.

Referring to the process 101′, the first hydrocracked stream in the first hydrocracked line 122 may be cooled by heat exchange with the first hydrocarbon feed stream in line 103. The cooled first hydrocracked stream is combined with a second hydrocracked effluent stream in a second hydrocracked effluent line 174. A combined hydrocracked effluent stream in line 124 may be delivered to the fractionation section 14. C6 naphthenes, benzene and higher boiling components from the combined hydrocracked effluent stream in line 124 are separated from a hydrogen-rich recycle gas, and C6 paraffin and lighter boiling net product components through a series of separation steps including higher-pressure flashes in the fractionation section 14.

The net splitter bottoms stream in line 168′ may be recycled as a recycle oil (RO) stream to the second hydrocracking unit 16. The second stage hydrocracking unit 16 saturates remaining aromatics to naphthenes and hydrocracks naphthenes to aliphatics in the second hydrocracking reactor 170.

The second hydrocracking unit 16 comprises a second hydrocracking reactor 170. The net splitter bottoms stream in line 168′ may be mixed with a second hydrocracking hydrogen stream in a second hydrocracking hydrogen line 183a taken from the second stage hydrogen line 183 to provide a second hydrocarbon feed stream in a second hydrocarbon feed line 166. The compressed hydrogen stream in line 181′ supplies hydrogen to the second stage hydrogen line 183. The second hydrocarbon feed stream in line 166 is heated and fed to the second hydrocracking reactor 170. The second hydrocarbon feed stream in the second hydrocarbon feed line 166 may be heated by heat exchange in a heat exchanger 41 with the second hydrocracked stream in line 174. The heat exchanged second hydrocarbon feed stream in line 167 may be heated in a fired heater 168. A heated second hydrocarbon feed stream in line 169 may be fed to the second hydrocracking reactor 170.

In an embodiment, the first stage hydrocracking reactor 120 is in upstream fluid communication with the fractionation section 14 and the second stage hydrocracking reactor 170 is in downstream fluid communication with the fractionation section 14.

The second hydrocarbon feed stream in line 169 can be taken as a second hydrocracking feed stream. The second hydrocracking feed stream in line 169 may be charged to the second hydrocracking reactor 170 to be hydrocracked. In a second stage of hydrocracking in the second hydrocracking reactor 170, a further conversion of the unconverted components into C6 paraffins and lighter boiling components takes place such that the overall conversion on the basis of feed rate of the feed stream in line 102 is at least about 90 wt %. In an embodiment, the overall conversion on the basis of feed rate of the feed stream in line 102 in the second hydrocracking reactor 170 is at least about 95 wt %. In an embodiment, the overall conversion on the basis of feed rate of the feed stream in line 102 in the second hydrocracking reactor 170 is at least about 98 wt %. In a preferred embodiment, the overall conversion on the basis of feed rate of the feed stream in line 102 in the second hydrocracking reactor 170 is at least about 100 wt %.

The second hydrocracking reactor 170 may be a fixed bed reactor that comprises one or more vessels, single or multiple catalyst beds 170a in each vessel, and various combinations of hydrotreating catalyst, hydroisomerization catalyst and/or hydrocracking catalyst in one or more vessels. The second hydrocracking reactor 170 may also be operated in a conventional continuous gas phase, a moving bed or a fluidized bed hydroprocessing reactor. In an embodiment, the second hydrocracking reactor 170 comprises a plurality of catalyst beds 170a.

The second hydrocracking feed stream is hydrocracked over the second hydrocracking catalyst in the second hydrocracking catalyst beds 170a in the presence of a second hydrocracking hydrogen stream from a second hydrocracking hydrogen line 183a to provide a second hydrocracked stream. Subsequent catalyst beds 170a in the hydrocracking reactor may comprise hydrocracking catalyst over which additional hydrocracking occurs. Hydrogen manifold 183b may deliver supplemental hydrogen streams to one, some or each of the catalyst beds 170a. In an aspect, the supplemental hydrogen is added to each of the downstream catalyst beds 170a at an interstage location between adjacent beds, so supplemental hydrogen is mixed with hydrocracked effluent exiting from the upstream catalyst bed 170a before entering the downstream catalyst bed 170a. The second hydrocracking reactor 170 may complete the conversion partially achieved in the first hydrocracking reactor 120.

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 120. The second hydrocracking catalyst may utilize hydrocracking catalyst bases comprising amorphous silica-alumina bases or zeolites 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.

In an aspect, the hydrocracking conditions in the second hydrocracking reactor 170 may be the same as or different than in the first hydrocracking reactor 120. Conditions in the second hydrocracking reactor may include a temperature from about 290° C. (550° F.) to about 468° C. (875° F.), preferably 343° C. (650° F.) to about 445° C. (833° F.), a pressure from about 4.8 MPa (gauge) (700 psig) to about 20.7 MPa (gauge) (3000 psig), a liquid hourly space velocity (LHSV) from about 0.3 to about 1.5 hr⁻¹ or about 0.4 to about 1.0 hr⁻¹, or to about 0.7 hr⁻¹ and a hydrogen rate of about 421 Nm3/m3 (2,500 scf/bbl) to about 2,527 Nm3/m3 oil (15,000 scf/bbl). Hydrogen partial pressure may be 1 MPa (abs) (1500 psia) to about 1.7 MPa (abs) (2500 psia).

In the second hydrocracking reactor 170 under the aforesaid prevalent hydrocracking conditions, at least 95 vol % of all rings, preferably all the rings present in the recycle oil stream in line 168′ may be opened to produce a hydrocracked effluent stream. In an exemplary embodiment, the rings present in the recycle oil stream in line 168′ may comprise naphthene rings and aromatics rings. The second stage hydrocracking unit 16 saturates remaining aromatics in the recycle oil stream in line 168′ to naphthenes and hydrocracks naphthenes to aliphatics in the second hydrocracking reactor 170. The second hydrocracking reactor 170 may saturate and hydrocrack at least 95 vol % of all rings, preferably all the rings present in the recycle oil stream in line 168′. In an embodiment, the net converted products in the second hydrocracked effluent stream in line 174 may comprise at least about 95 vol %, suitably at least about 98 vol % and preferably all aliphatic components. The second hydrocracked effluent stream in line 174 may comprise predominantly non-aromatic components.

The second hydrocracked stream may exit the second hydrocracking reactor 170 in the second hydrocracked effluent line 174, be heat exchanged with the recycle oil stream in line 168′ and be combined with the first hydrocracked effluent stream in first hydrocracked effluent line 122. The first hydrocracked effluent stream and the second hydrocracked effluent stream combined in combined hydrocracked effluent line 124 are separated and fractionated in the fractionation section 14 in downstream communication with the second hydrocracking reactor 170 as previously described. Both the first hydrocracked effluent stream in line 122 and the second hydrocracked effluent stream in line 174 are passed through one or more interstage separation steps in the fractionation section 14 to recover products before recycle oil is charged to the downstream second stage hydrocracking reactor 170. The rest of the process 101′ is same is described in FIG. 1.

The two-stage process 101′ may be more carbon efficient in producing less methane as a net product than what would be obtained in a single-stage or once-through configuration at the aforementioned overall conversions. The two-stage process is recommended for highly aromatic feeds.

In accordance with the present disclosure, the net product streams including the net fractionated overhead stream in line 158, and the net stripper overhead stream in line 151 comprise less than about 5 wt % naphthenes or aromatics. In an embodiment, the net product streams from the process comprise less than about 1 wt % naphthenes and aromatics. In a preferred embodiment, the net product streams from the process comprise does not contain any naphthenes or aromatics. In this way, the hydrocracking process 101 and 101′ nearly completely saturates all aromatics and opens at least 95 vol % of all rings, suitably at least 98 vol % of all rings and preferably all rings. In addition, the hydrocracking process 101 and 101′ can process all the distillable, extractable and converted crude that boils at the same or higher boiling point than C7 hydrocarbons including naphthenes, benzenes and alkylbenzenes.

EXAMPLE

A simulation study was performed to demonstrate the current process of hydrocracking a feed stream. The study was conducted both a two-stage hydrocracking and a single-stage hydrocracking configuration. For this study, a similar feed stream was passed to both the two-stage hydrocracking reactor and the single-stage hydrocracking reactor. The results including the operating conditions, and yields are summarized in the Table.

	TABLE
	Two-stage	Single-stage
	Hydrocracking	Hydrocracking

	Operating
	Configuration

	First Stage		Integrated
	Partial	Second	Mode	Single
	Conversion	Stage	Yields	Stage

Feed Streams

		Heavy
	Crude Oil	Naphtha		Crude Oil
	Diesel, Vacuum	from		Diesel, Vacuum
	Gas Oil,	First Stage		Gas Oil,
	Deasphalted Oil	Partial		Deasphalted Oil
	Blend	Conversion		Blend

FEED PROPERTY
Specific Gravity	0.877	0.749		0.877
(15° C./15° C.)
Organic Nitrogen,	570	<1		570
wt.- ppm
Distillation, wt.-%	Simulated	Simulated		Simulated
off (° C.)	Distillation	Distillation		Distillation
5	199	64		199
50	350	125		350
End Point	735	222		735
OPERATING
CONDITIONS
Hydrotreating LHSV,	1.6	—		1.1
1/h
Hydrocracking LHSV,	2.2	1.0		1.5
hr−1
H2 Partial Pressure,	2300	1950		2300
psi Absolute
Overall Conversion	37	100	100	100
into C6 and Lighter,
wt.-%
Yields, wt.-%
C1-C4	17	58	53	59
C5-C6 Aliphatic	22	42	49	41
Hydrocarbon
C6 Naphthenes	0.65	2.1	1.9	1.8
Heavy Naphtha	63	0	0	0
Recycled Oil
Simulated Distillation		138		208
End Point, ° C.

The results shown in the Table demonstrate the hydrocracking process for both a two-stage configuration and a single-stage configuration. The feed represents a blend of distillable and extractable components from a crude oil. The first stage partial conversion was performed at 37 wt % conversion to C6 and lighter hydrocarbons. The heavy naphtha unconverted to C6 aliphatic hydrocarbons from the first stage is further cracked in a second stage. The heavy naphtha from the partial first stage conversion mode is 100% converted into C6 and lighter aliphatic hydrocarbons. The integrated yields from the two modes, which would represent a two-stage configuration, are shown in the table. Hydrogen partial pressure was calculated by multiplying pressure the inlet hydrogen purity in mole-%.

In the single stage, the blend of distillable and extractable crude oil components were 100% converted in the single stage operation. The resultant product aliphatic hydrocarbons were more than 98% of the net products. The endpoint reduction of the feed into recycle oil was >500° C. The end point of the recycle oil indicates that the boiling range of the recycle oil is entirely in a heavy naphtha boiling range.

SPECIFIC EMBODIMENTS

While the following is described in conjunction with specific embodiments, it will be understood that this description is intended to illustrate and not limit the scope of the preceding description and the appended claims.

A first embodiment of the present disclosure is a process of hydrocracking a feed stream, comprising hydrocracking a feed stream in a hydrocracking reactor over a hydrocracking catalyst in the presence of a hydrocracking hydrogen stream at hydrocracking conditions to open at least 95 vol % of all rings present in the feed stream to produce a hydrocracked effluent stream that is aliphatic. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph wherein the rings comprise naphthene rings and aromatics rings. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising fractionating the hydrocracked effluent stream to produce an overhead stream and a bottoms stream comprising heavy naphtha; and recycling the bottoms stream. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the bottoms stream has a T90 temperature of about 176° C. to about 260° C. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the bottoms stream comprises at least 0.01 wt % HPNA. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the hydrocracking unit is a two-stage hydrocracking reactor configuration comprising a first stage hydrocracking reactor upstream of fractionation and a second stage hydrocracking reactor downstream of fractionation. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising charging the bottoms stream to the second stage hydrocracking reactor, wherein the bottoms stream comprises less than about 30 wt % aromatics. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the hydrocracking conditions comprise an LHSV of about 0.3 to about 1.0 hr⁻¹. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the hydrocracked effluent stream net products are at least 98 vol % aliphatic. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein a hydrocracked stream is passed through an interstage separation step before passing to a downstream hydrocracking reactor bed. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising separating the hydrocracked effluent stream into a first vapor stream and a first liquid stream; fractionating the first liquid stream to provide the bottoms stream; and passing the bottoms stream to the second stage hydrocracking reactor.

A second embodiment of the present disclosure is a process of hydrocracking a feed stream, comprising hydrocracking a feed stream comprising one or more of a naphtha stream, a kerosene stream, a diesel stream, a gas oil stream, deasphalted oil stream, a pyrolysis oil stream, and a pyrolysis gasoline stream, in a hydrocracking reactor over a hydrocracking catalyst in the presence of a hydrocracking hydrogen stream to open at least 95 vol % of all rings present in the feed stream and produce a hydrocracked effluent stream; fractionating the hydrocracked effluent stream to produce an overhead stream and a bottoms stream comprising heavy naphtha; and hydrocracking the bottoms stream. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph wherein the rings comprise naphthene rings and aromatics rings. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph wherein the bottoms stream is hydrocracked in a separate hydrocracking reactor than the feed stream. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph, wherein the hydrocracking reactor is a two-stage hydrocracking reactor comprising a first stage hydrocracking reactor upstream of fractionation and a second stage hydrocracking reactor downstream of fractionation. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph further comprising recycling the bottoms stream to the second stage hydrocracking reactor, wherein the bottoms comprises less than about 30 wt % aromatics. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph, wherein the hydrocracked effluent stream is at least 98 vol % aliphatic.

A third embodiment of the present disclosure is a process of hydrocracking a feed stream, comprising hydrocracking a first feed stream comprising one or more of a kerosene stream, a diesel stream, a gas oil stream, a deasphalted oil stream, pyrolysis gasoline stream, and a pyrolysis oil stream and a second feed stream comprising a naphtha stream or a butane stream in a hydrocracking reactor over a hydrocracking catalyst in the presence of a hydrocracking hydrogen stream to produce a hydrocracked effluent stream. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph, wherein the hydrocracking reactor is a two-stage hydrocracking reactor comprising a first stage hydrocracking reactor and a second stage hydrocracking reactor, and wherein a first stage hydrocracked effluent stream is passed without separation to the second stage hydrocracking reactor. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph wherein at least 95 vol % of all rings present in the first feed stream and the second feed stream are opened to produce the hydrocracked effluent stream.

Without further elaboration, it is believed that using the preceding description that one skilled in the art can utilize the present disclosure to its fullest extent and easily ascertain the essential characteristics of this disclosure, without departing from the spirit and scope thereof, to make various changes and modifications of the disclosure 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.