Process for Hydrocracking a Feed Stream

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

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.

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.

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 processof hydrocracking a feed stream is shown in. The process unitis a single stage hydrocracking unit that comprises a first stage hydrocracking unit, and a fractionation section. As shown, a hydrocarbonaceous feed stream in lineis passed to the first stage hydrocracking unit. In accordance with the present disclosure, the hydrocarbonaceous feed stream in linemay be of petroleum origin or a bio-based or a combination of both. In an aspect, the hydrocarbonaceous feed stream in linemay comprise more than one feed stream. The hydrocarbonaceous feed stream in linemay 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 linemay 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. Aromatic-rich streams may also be taken as a feed stream or a component of the hydrocarbonaceous feed stream in line. Plastics pyrolysis oil may also be taken as a feed stream or a component of the hydrocarbonaceous feed stream in line.

In an embodiment, the hydrocarbonaceous feed stream in linemay be processed in a single or a multistage hydrocracking unit. In an embodiment, the hydrocarbonaceous feed stream in linemay be processed in a single-stage hydrocracking unit as shown in the. In an exemplary embodiment, the first stage hydrocracking unitis a single-stage hydrocracking unit comprising a first hydrocracking reactor. A single-stage hydrocracking unitmay be selected for feed that is less aromatic and more paraffinic.

Referring to, a first hydrotreating hydrogen stream in a first hydrotreating hydrogen linemay be taken from a first stage hydrogen line. The first hydrotreating hydrogen stream may join the hydrocarbonaceous feed stream in feed lineto provide a first hydrocarbon feed stream in a first hydrocarbon feed line. The first hydrocarbon feed stream in the first hydrocarbon feed linemay be heated by heat exchange in a heat exchangerwith a first hydrocracked stream in line. The heated first hydrocarbon feed stream in lineis heated in a fired heater. A heated first hydrocarbon feed stream in linemay be fed to a first hydrotreating reactor.

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 reactormay 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 linemay be added at an interstage location between catalyst beds in the first hydrotreating reactor.

Suitable first hydrotreating catalysts for use in the first hydrotreating reactormay 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, noble metal catalysts would be discouraged. More than one type of first hydrotreating catalyst may be used in the first hydrotreating reactor. 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 reactormay 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, suitably 0.5 hr, to about 10 hr, preferably from about 1.5 to about 8.5 hr, 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 lineis hydrotreated over the first hydrotreating catalyst in the first hydrotreating reactorto provide a first hydrotreated hydrocarbon feed stream that exits the first hydrotreating reactorin a first hydrotreating effluent linewhich 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 reactorwithout separation. The first hydrocracking feed stream may be mixed with a first hydrocracking hydrogen stream in a first hydrocracking hydrogen linetaken from the first stage hydrogen lineand is fed through to the first hydrocracking reactor.

In an exemplary embodiment, the first hydrocracking feed stream in linemay be combined with a recycle oil stream in lineto provide a charge stream in line. The charge stream in linemay be combined with the first hydrocracking hydrogen stream in lineto provide a combined feed stream in line. The combined feed stream in lineis passed to the first hydrocracking reactor.

Hydrocracking is a process in which hydrocarbons crack in the presence of hydrogen to lower molecular weight hydrocarbons. The first hydrocracking reactormay 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 reactormay be operated in a conventional continuous gas phase, a moving bed or a fluidized bed hydroprocessing reactor. More typically, the first hydrocracking reactoris operated in a mixed phase with gas and liquid phases passing over a stationary solid, fixed bed of catalyst or catalysts.

The first hydrocracking reactorcomprises a plurality of first hydrocracking catalyst beds. If the first hydrocracking reactordoes not include a first hydrotreating reactor, the first catalyst bed in the hydrocracking reactormay 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 bedsin the first hydrocracking reactor. Otherwise, the first or an upstream bed in the first hydrocracking reactormay comprise a first hydrocracking catalyst bed.

The hydrotreated first hydrocracking feed stream is hydrocracked over a first hydrocracking catalyst in the first hydrocracking catalyst bedsin the presence of a first hydrocracking hydrogen stream in linefrom the first hydrocracking hydrogen lineto provide a first hydrocracked stream. Subsequent catalyst bedsin the first hydrocracking reactormay comprise hydrocracking catalyst over which additional hydrocracking occurs to the hydrocracked stream. Hydrogen manifoldmay deliver supplemental hydrogen streams to one, some or each of the catalyst beds. In an aspect, the supplemental hydrogen is added to each of the catalyst bedsat an interstage location between adjacent beds, so supplemental hydrogen is mixed with hydroprocessed effluent exiting from the upstream catalyst bedbefore entering the downstream catalyst bed

In the first hydrocracking reactor, under the aforesaid prevalent hydrocracking conditions, a predominant proportion of the rings present in the hydrocarbonaceous feed stream in linemay 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 linemay be opened to produce aliphatic hydrocarbons. In an exemplary embodiment, the rings present in the hydrocarbonaceous feed stream in linemay comprise naphthene rings and aromatics rings.

The first hydrocracking reactormay 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 reactorwith 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 reactoris 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.