FIELD

[0001] Methods are provided for upgrading cracked products, such as thermally cracked products.

BACKGROUND

[0002] In certain systems, a heavier oil, such as an oil derived from tar sands, may be subjected to coking and/or other thermal cracking at the extraction site to produce lower boiling fractions for blending to form a synthetic crude. Thermally cracking a portion of the heavy oil to form lower boiling fractions can improve the transport characteristics of the resulting synthetic crude. However, the thermal cracking also results in a substantial loss of yield, including some yield loss due to conversion of feed to C3- compounds. A method that allows for improved liquid hydrocarbon yield from thermal cracking would be desirable.

[0003] U.S. Patent No. 5,482,617 discloses a process for desulfurization of hydrocarbon streams having at least 50 ppmw organic sulfur compounds, and C5+ hydrocarbons including benzene. The hydrocarbon stream is exposed to a fluidized bed of an acidic catalyst in the absence of added hydrogen at a pressure of 0.0 psig to 400 psig and a temperature of 400°F to 900°F.

[0004] U.S. Patent No. 4,456,779 discloses a process for the catalytic conversion of olefins to higher hydrocarbons. The process includes combining a liquid olefinic feed with a liquid lower alkane stream (C3-C4) at a temperature of about 230°C. The combined stream is exposed to an acidic zeolite catalyst, and the effluent is cooled and then debutanized and fractionated.

SUMMARY

[0005] In an aspect, a method for processing a cracked feed is provided. The method includes separating a cracked feed derived from a cracking process into a naphtha boiling range fraction and a light ends fraction. The cracked feed can include C6+ compounds and C4- compounds. The naphtha boiling range fraction can include at least about 90 vol. % of the C6+ compounds from the cracked feed. The light ends fraction can include at least about 90 vol. % of the C4- compounds from the cracked feed, at least about 5 vol. % hydrogen, or a combination thereof. The light ends fraction can be exposed to effective conversion conditions to produce an oligomerized olefin effluent comprising one or more naphtha boiling range compounds. The effective conversion conditions can include exposing at least a portion of the light ends fraction to an acidic conversion catalyst at a temperature of at least about 550°F and a pressure of at least about 10 psig. At least a portion of the oligomerized olefin effluent can then be hydrotreated to form a hydrotreated product effluent.

[0006] In some aspects, the resulting hydrotreated product effluent can be capable of being separated into at least a C4+ product stream and a fuel gas stream. Optionally, the hydrotreated product effluent can comprise less than about 5 wt. % olefins, less than about 10 wt. % hydrogen, or a combination thereof.

[0007] In another aspect, a system for processing a cracked feed is provided. The system can include a conversion reactor comprising a reactor inlet and a reactor outlet. The system can further include a hydrotreatment reactor comprising a hydrotreatment inlet and a hydrotreatment outlet. The hydrotreatment inlet can be in fluid communication with the reactor outlet of the conversion reactor. The system can further include one or more light ends recovery units comprising a light ends inlet, a gas outlet, and a C4+ product stream outlet. The light ends inlet can be in fluid communication with the hydrotreatment outlet. The system can still further include an amine wash comprising an amine wash inlet that is in fluid communication with the gas outlet of the one or more light ends recovery units.

BRIEF DESCRIPTION OF THE FIGURES

[0008] FIG. 1 schematically shows an example of a system for processing cracked products, according to an aspect of the invention;

[0009] FIG. 2 schematically shows a base or minimal system for processing cracked products as discussed in Example 1 ; and

[0010] FIG. 3 schematically shows a system for processing cracked products, according to an aspect of the invention, and is discussed in Example 1.

DETAILED DESCRIPTION

Overview

[0011] In various aspects, systems and methods are provided for processing low boiling products cracking process, such as the overhead fraction from a cracking process. Examples of suitable cracking processes can include thermal cracking (such as coking) and/or fluid catalytic cracking. Preferably, the cracking process can be performed with a reduced or minimized amount of external hydrogen addition, such as no external hydrogen addition. In various aspects, an overhead fraction, e.g., from a thermal cracking process, can be separated into a naphtha boiling range fraction and a light ends fraction. The naphtha boiling range fraction can be subjected to a high pressure hydrotreatment reactor to saturate at least a portion of the olefins therein, and can then be used as a liquid naphtha source. As discussed in detail below, the light ends fraction can be upgraded to increase the C4+ content, which can also be hydrotreated and subsequently used as a source of liquid naphtha, e.g., as a diluent for forming diluted bitumen. This initial fractionation of the cracked products into the light ends and naphtha boiling range fractions, and the separate treatment of these fractions can increase the yield of naphtha boiling range compounds, while reducing the amount of refinery fuel gas.

[0012] Traditionally, transport of heavier oils such as tar sands or other whole heavy crude can present difficulties due to requirements for pipeline and/or rail transport. To overcome these difficulties, tar sands and/or other heavy crude oils may require coking or cracking in order to produce lower viscosity fractions that can be blended with the heavy oil to make a syncrude that can be transported via a pipeline. The coking or cracking of such a heavier oil results in a product that may include naphtha boiling range compounds. In addition, a portion of this product stream, such as the overhead fraction, can be separated into a naphtha boiling range fraction and a light ends fraction. Traditionally, the naphtha boiling range fraction can undergo hydrotreatment for olefin saturation and/or sulfur removal. The resulting treated liquid naphtha product may be utilized as a diluent for making synthetic crude and/or diluted bitumen. In addition, traditionally, the light ends fraction may be subjected to C4 and C5 removal in a gas plant (and hydrotreated and added to the liquid naphtha product), with the resulting C3- portion being used as fuel gas. Relative to typical refinery products, fuel gas is usually considered as a low value product.

[0013] In various aspects, methods and systems described herein can be used to reduce the yield of fuel gas while increasing the yield of naphtha boiling range products. In one or more aspects, the cracked products feed may be separated into a naphtha boiling range fraction and a light ends fraction. The naphtha boiling range fraction can be subjected to a high pressure hydrotreatment reactor to saturate at least a portion of the olefins therein as discussed above with respect to the traditional treatment. However, instead of sending a light ends fraction to the gas plant for C4/C5 recovery like in the traditional system discussed above, this fraction can be upgraded to produce additional liquid naphtha. For example, in such aspects, the light ends fraction can be exposed to effective conversion conditions to oligomerize at least a portion of the olefins to form an oligomerized olefin effluent. Since the cracked products feed can include coker fuel gas and/or purge streams from another hydrotreatment unit, the cracked products feed, and subsequent oligomerized olefin effluent, can include a significant amount of hydrogen that can be utilized to hydrotreat the oligomerized olefin effluent. Upon hydrotreatment of the oligomerized olefin effluent, the saturated product effluent can include naphtha boiling range compounds with a minimal amount of olefins, or no olefins. Additionally, this saturated product effluent can include a refinery fuel gas stream that has a reduced hydrogen content, due to the use of the hydrogen present in the saturated product effluent for the saturation of the oligomerized olefin effluent. The removal of H2 and olefins for an upgraded use (i.e., for use other than fuel value) has an additional benefit of reducing or minimizing NOx emissions of fuel gas during a burning process.

[0014] A C4+ product stream can be recovered from the saturated product effluent, e.g., via light ends recovery units discussed below. This C4+ product stream having a reduced or minimized olefin content can be utilized as a diluent for crude blending. In certain aspects, the total amount of the liquid product obtained by the C4+ product stream and the liquid naphtha recovered from the naphtha boiling range fraction can provide an increased yield of naphtha boiling range compounds compared to the traditional process discussed above. In addition, by sending the light ends fraction to be upgraded into additional naphtha boiling range compounds that are hydrotreated in a separate reactor, the volume of the original naphtha boiling range fraction going to the high pressure hydrotreatment reactor is reduced, thereby allowing for processing of an overall larger initial amount of heavy crude oil at the same hydrotreatment reactor capability.

[0015] In this discussion, unless otherwise specified, "naphtha boiling range" refers to an initial or T5 boiling point of at least about 50°F (10°C) and a final or T95 boiling point of less than about 450°F (232°C), less than about 400°F (204°C), or less than about 350°F (177°C). In this discussion, unless otherwise specified, "naphtha boiling range compounds" and/or "naphtha boiling range fraction" refers to one or more compounds that exhibit the naphtha boiling range specified above. In this discuss, unless otherwise specified, "overhead fraction" refers to the lighter components derived from a process of cracking a feed that can include light ends, such as methane, and can have a final or T95 boiling point of less than about 450°F (232°C), less than about 400°F (204°C), or less than about 350°F (177°C). In this discussion, unless otherwise specified, "light ends" generally refers to a fraction that is not liquid at standard temperature and pressure, and can include C1-C4 hydrocarbons, and may also include contaminates, such as H2S, NH3, CO, CO2, and/or any other gas at standard temperature and pressure. In this discussion, unless otherwise specified, "T5 boiling point" refers to a temperature at which 5 wt. % of the feed, effluent, product, stream, or composition of interest will boil. In this discussion, unless otherwise specified, "T95 boiling point" refers to a temperature at which 95 wt. % of the feed, effluent, product, stream, or composition of interest will boil. Boiling points or distillation points may be determined by a suitable ASTM method, such as D86 or D2887.

Cracked Products Feed

[0016] In the description of the cracked products feed below, a series of upper and lower range bounds is provided for a variety of feed properties (such as sulfur content and olefin content). For each feed property, each upper bound is explicitly contemplated in conjunction with each lower bound.

[0017] The cracked products feed can be any hydrocarbon feed having a suitable boiling range that is derived from a cracked products stream, such as a cracked product stream from coking, fluid catalytic cracking, and/or thermal cracking. In various aspects, the cracked products feed can include an overhead fraction from a coking, fluid catalytic cracking, and/or thermal cracking process. More generally, the cracked products feed can correspond to a feed that is at least partly composed of Ci - C9 hydrocarbons, with a portion of the Ci - C9 hydrocarbons being olefins. In the same or alternative aspects, the cracked products feed can include one or more low value refinery streams, such as refinery fuel gas and/or purge streams from a hydrotreatment reactor.

[0018] In various aspects, the cracked products feed can include at least about 10 wt. % olefins, at least about 20 wt. %, at least about 30 wt. %, at least about 40 wt. %, or at least about 50 wt. %. In the same or alternative aspects, the cracked products feed can include less than about 90 wt. % olefins, less than about 80 wt. %, less than about 70 wt. %, or less than about 60 wt. %.

[0019] In various aspects, the cracked products feed can include at least about 5 wt. %, at least about 10 wt. %, at least about 20 wt. %, at least about 30 wt. %, at least about 40 wt. %, at least about 50 wt. %, at least about 60 wt. %, or at least about 70 wt. % C1-C3 hydrocarbon compounds, with a portion being C2-C3 olefins, such as the olefin amounts listed above. In the same or alternative aspects, the cracked products feed can include less than about 100 wt. %, less than about 90 wt. %, less than about 80 wt. %, or less than about 70 wt. % C1-C3 hydrocarbon compounds, with a portion being C2-C3 olefins, such as the olefin amounts listed above. In certain aspects, the cracked products a feed can include C1-C3 hydrocarbon compounds, with a portion being C2-C3 olefins, such that the C1-C3 hydrocarbon compounds are at least about 10 wt. % greater, at least about 20 wt. % greater, at least about 30 wt. % greater, at least about 40 wt. % greater, at least about 50 wt. % greater, or at least about 60 wt. % greater than the amount (wt. %) of C2-C3 olefins.

[0020] In one or more aspects, the cracked products feed can include at least about 5 wt.

%, at least about 10 wt. %, at least about 20 wt. %, at least about 30 wt. %, at least about 40 wt. %, at least about 50 wt. %, at least about 60 wt. %, or at least about 70 wt. % C1-C4 hydrocarbon compounds, with a portion being C2-C4 olefins, such as the olefin amounts listed above. In the same or alternative aspects, the cracked products feed can include less than about 100 wt. %, less than about 90 wt. %, less than about 80 wt. %, or less than about 70 wt. % C1-C4 hydrocarbon compounds, with a portion being C2-C4 olefins, such as the olefin amounts listed above. In certain aspects, the cracked products feed can include C1-C4 hydrocarbon compounds, with a portion being C2-C4 olefins, such that the C1-C4 hydrocarbon compounds are at least about 10 wt. % greater, at least about 20 wt. % greater, at least about 30 wt. % greater, at least about 40 wt. % greater, at least about 50 wt. % greater, or at least about 60 wt. % greater than the amount (wt. %) of C2-C4 olefins.

[0021] In one or more aspects, the cracked products feed can include at least about 5 wt.

%, at least about 10 wt. %, at least about 20 wt. %, at least about 30 wt. %, at least about 40 wt. %, at least about 50 wt. %, at least about 60 wt. %, or at least about 70 wt. % C1-C9 hydrocarbon compounds, with a portion being C2-C9 olefins, such as the olefin amounts listed above. In the same or alternative aspects, the cracked products feed can include less than about 100 wt. %, less than about 90 wt. %, less than about 80 wt. %, or less than about 70 wt. % C1-C9 hydrocarbon compounds, with a portion being C2-C9 olefins, such as the olefin amounts listed above. In certain aspects, the cracked products feed can include C1-C9 hydrocarbon compounds, with a portion being C2-C9 olefins, such that the C1-C9 hydrocarbon compounds are at least about 10 wt. % greater, at least about 20 wt. % greater, at least about 30 wt. % greater, at least about 40 wt. % greater, at least about 50 wt. % greater, or at least about 60 wt. % greater than the amount (wt. %) of C2-C9 olefins.

[0022] In one or more aspects, the cracked products feed can include hydrogen gas in an amount of at least about 1 vol. %, at least about 5 vol. %, at least about 10 vol. %, or at least about 20 vol. %. In the same or alternative aspects, the cracked products feed can include hydrogen gas in an amount of about 20 vol. % or less, about 15 vol. % or less, or about 10 vol. % or less.

[0023] In one or more aspects, nitrogen can also be present in the cracked products feed.

In an aspect, the amount of nitrogen can be at least about 5 wppm, or at least about 10 wppm, or at least about 20 wppm, or at least about 40 wppm, or at least about 100 wppm, or at least about 1000 wppm. In another aspect, the nitrogen content can be about 2 wt% or less, or about 1 wt% or less, or about 1000 wppm or less, or about 100 wppm or less, or about 50 wppm or less.

[0024] In various aspects, the cracked products feed can have a sulfur content of at least about 100 wppm, or at least about 500 wppm, or at least about 1000 wppm, or at least about 1500 wppm. In another aspect, the sulfur content can be about 9 wt% or less, or about 5 wt% or less, or about 2 wt% or less, or about 1 wt% or less, or about 6000 wppm or less, or about 5000 wppm or less, or about 3000 wppm or less. The sulfur may be present as organically bound sulfur.

[0025] As discussed above, in some aspects, at least a portion of the cracked products feed can include one or more low value streams, such as light ends and/or a purge stream from a hydrotreatment reactor. In one aspect, the light ends may be derived from an overhead fraction from a coker, such as a coker for bitumen, and/or the purge stream may be derived from a diesel hydrotreatment reactor. In one aspect, the light ends may be present in a C9- cut (carbon containing compounds having nine carbon atoms or less) from a fractionator overhead of a bitumen coker. In various aspects, the one or more low value streams may be present in the cracked products feed in an amount of at least about 5 wt. %, at least about 10 wt. %, at least about 20 wt. %, at least about 30 wt. %, or at least about 40 wt. %. In the same or alternative aspects, the one or more low value streams may be present in the cracked products feed in an amount of about 90 wt. % or less, or about 80 wt. % or less, or about 70 wt. % or less, or about 60 wt. % or less, or about 50 wt. % or less.

[0026] In one or more aspects, a portion or all of the cracked products feed may be compressed, e.g., in a conventional compressor, to increase its pressure prior to the processing steps discussed below.

[0027] It is appreciated that other cracked products feeds or other feeds having olefins may be used in the processes disclosed herein and that the above-described feed properties are only exemplary.

Initial Fractionation of the Cracked Products Feed

[0028] In various aspects, the cracked products feed may undergo an initial fractionation to separate the feed into a naphtha boiling range fraction and a light ends fraction. In such aspects, the naphtha boiling range fraction of the cracked products feed may include carbon containing compounds having six carbon atoms or more (C ₆ +), or five carbon atoms or more (Cs+) in an amount of at least about 70 vol. %, at least about 80 vol., %, at least about 90 vol. % or at least about 95 vol. %, and/or the light ends fraction of the cracked products feed may include carbon containing compounds having five carbon atoms or less (C5-), or four carbon atoms or less (C4-) in an amount of at least about 70 vol. %, at least about 80 vol., %, at least about 90 vol. % or at least about 95 vol. %.

[0029] In one or more aspects, the cracked products feed may be fractionated using conventional techniques known to one skilled in the art. In various aspects, the cracked products feed may not be precisely fractionated, as the various fractions may undergo additional processing and/or additional separations described herein. In certain aspects, the cracked products feed may be subj ected to a flash fractionation using conventional refinery equipment. In one or more aspects, the cracked products feed may be separated into a naphtha boiling range fraction and a light ends fraction using a fractionator or a fractionation system (e.g., a gas plant), at a cut point of at least about 125 °F (51.7 °C), at least about 135 °F (57.2 °C), at least about 145 °F (62.8 °C), or at least about 160 °F (71.1 °C). [0030] In various aspects, the cracked products feed may be compressed, e.g., in a conventional refinery compressor, in order to ensure that at least a portion of the feed can be liquefies prior to the initial fractionation.

[0031] In one or more aspects, the naphtha boiling range fraction of the cracked products feed can be sent to a high pressure hydrotreating unit for sulfur removal and/or olefin saturation. In the same or alternative aspects, as discussed in detail below, the light ends fraction of the cracked products feed may be subjected to conditions for olefin oligomerization and/or sulfur removal prior to hydrotreatment. In certain aspects, the naphtha boiling range fraction may undergo hydrotreating as described below with respect to the oligomerized olefin effluent (produced from the light ends fraction). In one aspect, the hydrotreating conditions for the naphtha boiling range fraction may include a reaction total pressure that is increased relative to the reaction total pressure for the hydrotreatment of the oligomerized olefin effluent.

Conditions for Upgrading the Light Ends Fraction of the Cracked Products Feed

[0032] In various aspects, the light ends fraction of the cracked products feed can be exposed to an acidic catalyst (such as a zeolite) under effective conversion conditions for olefinic oligomerization and/or sulfur removal. Optionally, the zeolite or other acidic catalyst can also include a hydrogenation functionality, such as a Group VIII metal or other suitable metal that can activate hydrogenation/dehydrogenation reactions. The light ends fraction of the cracked products feed can be exposed to the acidic catalyst without providing substantial additional hydrogen to the reaction environment. Added hydrogen refers to hydrogen introduced as an input flow to the process, as opposed to any hydrogen that might be generated in-situ during processing. Exposing the feed to an acidic catalyst without providing substantial added hydrogen is defined herein as exposing the feed to the catalyst in the presence of a) less than about 100 SCF/bbl of added hydrogen, or less than about 50 SCF/bbl; b) a partial pressure of less than about 50 psig (350 kPag), or less than about 15 psig (100 kPag) of hydrogen; or c) a combination thereof. While this upgrading process is described with respect to the light ends fraction of the cracked products feed, it is appreciated that the entire cracked products feed or any portions thereof described above may be utilized in this upgrading process.

[0033] The acidic catalyst used in the processes described herein can be a zeolite-based catalyst, that is, it can comprise an acidic zeolite in combination with a binder or matrix material such as alumina, silica, or silica-alumina, and optionally further in combination with a hydrogenation metal. More generally, the acidic catalyst can correspond to a molecular sieve (such as a zeolite) in combination with a binder, and optionally a hydrogenation metal. Molecular sieves for use in the catalysts can be medium pore size zeolites, such as those having the framework structure of ZSM-5, ZSM-11, ZSM-12, ZSM-22, ZSM-23, ZSM-35, ZSM-48, or MCM-22. Such molecular sieves can have a 10-member ring as the largest ring size in the framework structure. The medium pore size zeolites are a well-recognized class of zeolites and can be characterized as having a Constraint Index of 1 to 12. Constraint Index is determined as described in U.S. Pat. No. 4,016,218 incorporated herein by reference. Catalysts of this type are described in U.S. Pat. Nos. 4,827,069 and 4,992,067 which are incorporated herein by reference and to which reference is made for further details of such catalysts, zeolites and binder or matrix materials.

[0034] Additionally or alternately, catalysts based on large pore size framework structures

(12-member rings) such as the synthetic faujasites, especially zeolite Y, such as in the form of zeolite USY. Zeolite beta may also be used as the zeolite component. Other materials of acidic functionality which may be used in the catalyst include the materials identified as MCM-36 and MCM-49. Still other materials can include other types of molecular sieves having suitable framework structures, such as silicoaluminophosphates (SAPOs), aluminosilicates having other heteroatoms in the framework structure, such as Ga, Sn, or Zn, or silicoaluminophosphates having other heteroatoms in the framework structure. Mordenite or other solid acid catalysts can also be used as the catalyst.

[0035] In various aspects, the exposure of the light ends fraction of the cracked products feed to the acidic catalyst can be performed in any convenient manner, such as exposing the light ends fraction of the cracked products feed to the acidic catalyst under fluidized bed or fluidized transport conditions. In some aspects, the particle size of the catalyst can be selected in accordance with the fluidization regime which is used in the process. Particle size distribution can be important for maintaining turbulent fluid bed conditions as described in U.S. Pat. No. 4,827,069 and incorporated herein by reference. Suitable particle sizes and distributions for operation of dense fluid bed and transport bed reaction zones are described in U.S. Pat. Nos. 4,827,069 and 4,992,607 both incorporated herein by reference. Particle sizes in both cases will normally be in the range of 10 to 300 microns, typically from 20 to 100 microns.

[0036] Acidic zeolite catalysts suitable for use as described herein can be those exhibiting high hydrogen transfer activity and having a zeolite structure of ZSM-5, ZSM-11, ZSM-12, ZSM- 22, ZSM-23, ZSM-35, ZSM-48, MCM-22, MCM-36, MCM-49, zeolite Y, and zeolite beta. Such catalysts can be capable of oligomerizing olefins from the light ends fraction of the cracked products feed. Such catalysts can also be capable of converting organic sulfur compounds such as mercaptans to hydrogen sulfide without added hydrogen by utilizing hydrogen present in the hydrocarbon feed. Group VIII metals such as nickel may be used as desulfurization promoters. A fluid-bed reactor/regenerator can assist with maintaining catalyst activity in comparison with a fixed-bed system. Further, the hydrogen sulfide produced in accordance with the processes described herein can be removed using conventional amine based absorption processes.

[0037] ZSM-5 crystalline structure is readily recognized by its X-ray diffraction pattern, which is described in U.S. Pat. No. 3,702,866. ZSM-11 is disclosed in U.S. Pat. No. 3,709,979, ZSM-12 is disclosed in U.S. Pat. No. 3,832,449, ZSM-22 is disclosed in U.S. Pat. No. 4,810,357, ZSM-23 is disclosed in U.S. Pat. Nos. 4,076,842 and 4,104,151, ZSM-35 is disclosed in U.S. Pat. No. 4,016,245, ZSM-48 is disclosed in U.S. Pat. No. 4,375,573 and MCM-22 is disclosed in U.S. Pat. No. 4,954,325. The U.S. Patents identified in this paragraph are incorporated herein by reference.

[0038] While suitable zeolites having a coordinated metal oxide to silica molar ratio of

20: 1 to 200: 1 or higher may be used, it can be advantageous to employ aluminosilicate ZSM-5 having a silica: alumina molar ratio of about 25: 1 to 70: 1, suitably modified. A typical zeolite catalyst component having Bronsted acid sites can comprises, consist essentially of, or consist of crystalline aluminosilicate having the structure of ZSM-5 zeolite with 5 to 95 wt. % silica, clay and/or alumina binder.

[0039] These siliceous zeolites can be employed in their acid forms, ion-exchanged or impregnated with one or more suitable metals, such as Ga, Pd, Zn, Ni, Co, Mo, P, and/or other metals of Periodic Groups III to VIII. The zeolite may include other components, generally one or more metals of group IB, IIB, IIIB, VA, VIA or VIIIA of the Periodic Table (IUPAC).

[0040] Useful hydrogenation components can include the noble metals of Group VIIIA, such as platinum, but other noble metals, such as palladium, gold, silver, rhenium or rhodium, may also be used. Base metal hydrogenation components may also be used, such as nickel, cobalt, molybdenum, tungsten, copper or zinc.

[0041] The catalyst materials may include two or more catalytic components which components may be present in admixture or combined in a unitary multifunctional solid particle.

[0042] In addition to the preferred aluminosilicates, the gallosilicate, ferrosilicate and

"silicalite" materials may be employed. ZSM-5 zeolites can be useful in the process because of their regenerability, long life and stability under the extreme conditions of operation. Usually the zeolite crystals have a crystal size from about 0.01 to over 2 microns or more, such as 0.02-1 micron.

[0043] In various aspects, the catalyst particles can contain about 25 wt. % to about 40 wt.

% H-ZSM-5 zeolite, based on total catalyst weight, contained within a silica-alumina matrix. Typical Alpha values for the catalyst can be about 100 or less. Sulfur conversion to hydrogen sulfide can increase as the alpha value increases.

[0044] The Alpha Test is described in U.S. Pat. 3,354,078, and in the Journal of Catalysis,

Vol. 4, p. 527 (1965); Vol. 6, p. 278 (1966); and Vol. 61, p. 395 (1980), each incorporated herein by reference as to that description.

[0045] In various aspects, the light ends fraction of the cracked products feed may be exposed to the acidic catalyst by using a moving or fluid catalyst bed reactor. In such aspects, the catalyst may be regenerated, such via continuous oxidative regeneration. The extent of coke loading on the catalyst can then be continuously controlled by varying the severity and/or the frequency of regeneration. In a turbulent fluidized catalyst bed the conversion reactions are conducted in a vertical reactor column by passing hot reactant vapor upwardly through the reaction zone and/or reaction vessel at a velocity greater than dense bed transition velocity and less than transport velocity for the average catalyst particle. A continuous process is operated by withdrawing a portion of coked catalyst from the reaction zone and/or reaction vessel, oxidatively regenerating the withdrawn catalyst and returning regenerated catalyst to the reaction zone at a rate to control catalyst activity and reaction severity to effect feedstock conversion. Preferred fluid bed reactor systems are described in Avidan et al U.S. Pat. No. 4,547,616; Harandi & Owen U.S. Pat. No. 4,751,338; and in Tabak et al U.S. Pat. No. 4,579,999, incorporated herein by reference. In other aspects, other types of reactors can be used, such as fixed bed reactors, riser reactors, fluid bed reactors, and/or moving bed reactors.

[0046] In one or more aspects, effective conversion conditions for exposing the light ends fraction of the cracked products feed to an acidic catalyst can include a temperature of about 300°F (149°C) to about 900°F (482°C), or about 350°F (177°C) to about 850°F (454°C), or about 350°F (177°C) to about 800°F (427°C), or about 350°F (177°C) to about 750°F (399°C), or about 350°F (177°C) to about 700°F (371°C), or a temperature of at least about 400°F (204°C), or at least about 500°F (260°C), or at least about 550°F (288°C), or at least about 600°F (316°C); a pressure of about 10 psig (0.07 MPag) to about 600 psig (4.13 MPag), or a pressure of about 50 psig (0.34 MPag) to about 500 psig (3.4 MPag), or about 50 psig (0.34 MPag) to about 400 psig (2.8 MPag), or about 50 psig (0.34 MPag) to about 300 psig (2.1 MPag), or about 100 psig (0.69 MPag) to about 200 psig (1.4 MPag), or a pressure of at least about 10 psig (0.07 MPag), or at least about 50 psig (0.34 MPag), or a pressure of at least about 100 psig (0.69 MPag), or a pressure of at least about 150 psig (1.0 MPag), or a pressure of at least about 200 psig (1.4 MPag), or a pressure of about 350 psig (2.4 MPag) or less, or a pressure of about 300 psig (4.1 MPag) or less, or a pressure of about 250 psig (1.7 MPag) or less; and a WHSV of the lighter fraction of the cracked naphtha feed of about 0.05 hr ^"1 to about 40 hr ^"1 , or about 0.05 to about 30 hr ^"1 , or about 0.1 to about 20 hr ^"1 , or about 0.1 to about lOhr ¹ .

[0047] In various aspects, exposing the light ends fraction of the cracked products feed to the conversion conditions discussed above can produce an oligomerized olefin effluent that includes naphtha boiling range compounds. In such aspects, the naphtha boiling range compounds in the oligomerized olefin effluent can include compounds with 5 or more carbon atoms (C5+ compounds) in an amount of at least about 20 wt. %, at least about 30 wt. %, at least about 40 wt. %, at least about 50 wt. %, at least about 65 wt. %, at least about 70 wt. %, or at least about 75 wt. %. In one or more aspects, the oligomerized olefin effluent can include hydrogen (H2) at a partial pressure of about 1 psig (0.007 MPag) to about 50 psig (0.34 MPag), or about 3 psig (0.021 MPag) to about 40 psig (0.28 MPag), or about 5 psig (0.034 MPag) to about 30 psig (0.21 MPag), or about 10 psig (0.068 MPag) to about 20 psig (0.14 MPag); or at least about 1 psig (0.007 MPag), at least about 5 psig (0.034 MPag), at least about 10 psig (0.068 MPag), or at least about 20 psig (0.14 MPag). In certain aspects, the oligomerized olefin effluent can include hydrogen gas in an amount of at least about 1 wt. %, at least about 5 wt. %, at least about 10 wt. %, or at least about 20 wt. %. In various aspects, the naphtha boiling range compounds in the oligomerized olefin effluent can have an aromatic content of less than about 20 wt. %, less than about 15 wt. %, less than about 10 wt. %, or less than about 5 wt. %. In one or more aspects, the naphtha boiling range compounds in the oligomerized olefin effluent can have a reduced sulfur content compared to the olefin- containing feed. In such aspects, the sulfur content of naphtha boiling range compounds in the oligomerized olefin effluent can be about 1 wt% or less, or about 1000 wppm or less, or about 500 wppm or less, or about 75 wppm or less, or about 50 wppm or less, or about 30 wppm or less, or about 20 wppm or less, or about 10 wppm or less.

Hydrotreating the Oligomerized Olefin Effluent

[0048] In certain aspects, the oligomerized olefin effluent can be subj ected to hydrotreating conditions to saturate at least a portion of the oligomerized olefins and produce a saturated product effluent. In various aspects, hydrogen present in the oligomerized olefin effluent can be utilized to saturate the oligomerized olefins. This can provide an economical way to utilize the hydrogen present in the oligomerized effluent to increase the volume of the oligomerized olefins, which may ultimately be utilized as a diluent for crude blending. The hydrotreating conditions for saturation of olefins can optionally also be suitable for desulfurization of the oligomerized olefin effluent. The olefin saturation and/or desulfurization of the oligomerized olefin effluent can result in an upgrade in products value. [0049] In one or more aspects, at least a portion of the hydrogen used to saturate the oligomerized olefin effluent into a saturated product effluent may have been produced in the coking or cracking of a heavier oil, such as an oil derived from tar sand or a whole crude. In various aspects, at least a portion of the hydrogen used to saturate the oligomerized olefin effluent into a saturated product effluent may be a portion of an overhead fraction from a coker, or a cracking unit.

[0050] To saturate at least a portion of the oligomerized olefins present in the oligomerized effluent, the oligomerized effluent can be exposed to ahydrofinishing catalyst bed. Hydrofinishing catalysts can include catalysts containing Group VI metals, Group VIII metals, and mixtures thereof. In an aspect, preferred metals include at least one metal sulfide having a strong hydrogenation function. In another aspect, the hydrofinishing catalyst can include a Group VIII noble metal, such as Pt, Pd, or a combination thereof. The mixture of metals may also be present as bulk metal catalysts wherein the amount of metal is about 30 wt. % or greater based on catalyst. Suitable metal oxide supports include low acidic oxides such as silica, alumina, silica-aluminas or titania, preferably alumina. The preferred hydrofinishing catalysts will comprise at least one metal having relatively strong hydrogenation function on a porous support. Typical support materials include amorphous or crystalline oxide materials such as alumina, silica, and silica-alumina. The support materials may also be modified, such as by halogenation, or in particular fluorination. The metal content of the catalyst is often as high as about 20 weight percent for non-noble metals. In an aspect, a preferred hydrofinishing catalyst can include a crystalline material belonging to the M41S class or family of catalysts. The M41S family of catalysts are mesoporous materials having high silica content. Examples include MCM-41, MCM-48 and MCM-50. A preferred member of this class is MCM-41.

[0051] Hydrofinishing conditions can include temperatures from about 125°C (257°F) to about 425°C (797°F), or about 180°C (356°F) to about 280°C (536°F); a total pressure from about 200 psig (1.4 MPa) to about 800 psig (5.5 MPa), or about 400 psig (2.8 MPa) to about 700 psig (4.8 MPa); and a liquid hourly space velocity from about 0.1 hr ¹ to about 5 hr ¹ LHSV, preferably about 0.5 hr ¹ to about 1.5 hr ¹ .

[0052] Alternatively, a conventional hydrotreating catalyst for reducing sulfur content could be used to saturate at least a portion of the oligomerized olefins present in the oligomerized olefin effluent. Conventional hydrotreating catalysts for reducing sulfur content include catalysts composed of a Group VIB metal (Group 6 of IUPAC periodic table) and/or a Group VIII metal (Groups 8 - 10 of IUPAC periodic table) on a support. Suitable metals include cobalt, nickel, molybdenum, tungsten, or combinations thereof. Suitable supports include silica, silica-alumina, alumina, and titania. The oligomerized olefin effluent can be exposed to the hydrotreating catalyst under conventional hydrotreating conditions and/or the hydrofinishing conditions described above. To eliminate olefins in diluent a further hydroprocessing step may be utilized. This step can operate at a higher hydrogen partial pressure than the hydrofinishing step described above.

[0053] In various aspects, the saturated product effluent may have about 20 wt. % olefins or less, about 15 wt. % or less, about 10 wt. % or less, about 5 wt. % or less, or about 1 wt. % or less. In one or more aspects, the saturated product effluent may have about 0 wt. % olefins. In various aspects, the saturated product effluent may include a low hydrogen fuel gas, such a fuel gas having a hydrogen content of about 10 wt. % or less, about 7.5 wt. % or less, about 5 wt. % or less, about 2.5 wt. % or less, or about 1 wt. % or less.

Separation of the Saturated Product Effluent Using Light Ends Recovery Units

[0054] In various aspects, the saturated product effluent may be separated into one or more fractions to maximize the use of various components therein. In one or more aspects, the saturated product effluent may be separated into a liquid fraction and a vapor fraction, e.g., by condensation or other conventional refinery processes.

[0055] In various aspects, the liquid fraction of the saturated product effluent may be exposed to a depropanizer in order to separate out at least a portion of the carbon containing compounds having three carbon atoms or less (C3-) from the carbon containing compounds having four carbon atoms or more (C ₄ +). It is appreciated that any conventional depropanizer is suitable for such a separation. In certain aspects, the depropanizer may be a part of a gas plant at a refinery. A debutanizer may be utilized to separate at least a portion of C ₄ - compounds from a C5+ product stream to ensure specifications such as vapor pressure for the product is met.

[0056] In one or more aspects, the C3- fraction, and/or the vapor fraction may be directly sent to a fuel gas system. Alternatively, in various aspects, the C3- fraction and/or the vapor fraction of the saturated product effluent may be subjected to a deethanizer in order to separate out the carbon containing compounds having three carbon atoms or more (C3+) and/or the carbon containing compounds having two carbon atoms or more (C2+), prior to sending the lighter remainder to the site's fuel gas system. It is appreciated that any conventional or commercially available deethanizer may be suitable for such a separation.

[0057] In certain aspects, prior to sending the C3- fraction (with or without the C3 and C2 compounds) and/or the vapor fraction to the site's fuel gas system, the C3- fraction and/or the vapor fraction may be exposed to an amine wash (or another conventional sulfur removal method) to remove at least a portion of the sulfur-containing compounds, such as H2S, present in the C3- fraction and/or the vapor fraction. Any conventional amine wash process is suitable. A non- limiting list of amine-containing compounds that can be used in an amine wash include diethanolamine, monoethanolamine, methyldiethanolamine, diisopropanolamine, and aminoethoxyethanol (diglycolamine). In one or more aspects, in the amine wash, the C3- fraction and/or the vapor fraction can be exposed to one or more amine-containing compounds to remove at least a portion of the H2S or other sulfur-containing compounds present in the C3- fraction and/or the vapor fraction to form a desulfurized site fuel gas.

Saturated C4+ Product Effluent

[0058] In various aspects, after hydrotreatment of the oligomerized olefin effluent and the separations discussed above, a saturated C4+ product effluent may be obtained. In one or more aspects, the saturated C4+ product effluent may have an olefin content of about 20 wt. % or less, about 15 wt. % or less, about 10 wt. % or less, about 5 wt. % or less, or about 1 wt. % or less. In one or more aspects, the saturated C4+ product effluent may have about 0 wt. %, or no, olefins. In various aspects, the saturated C4+ product effluent can include naphtha boiling range compounds in an amount of at least about 60 wt. %, at least about 70 wt. %, at least about 80 wt. %, at least about 90 wt. %, at least about 95 wt. %, or at least about 99 wt. %.

[0059] In certain aspects, the saturated C4+ product effluent, which may include naphtha boiling range compounds with little to no olefins, may be suitable for use as a diluent for crude blending. In one or more aspects, the saturated C4+ product effluent may be utilized as a diluent for upgraded bitumen or other crude oil including bitumen.

[0060] In one aspect, the saturated C4+ product effluent may be utilized as a lean oil in an absorber, e.g., to remove at least a portion of heavy hydrocarbons, such as C4+ and/or C5+ hydrocarbons from a feed or stream, e.g., a hydrocarbon stream from a refinery gas plant. It is appreciated that any conventional absorber can be used in the systems and processes described herein. In general, in an absorber, a pressurized gaseous feed, is passed through a countercurrent flow of a lean oil liquid stream, e.g., the saturated C4+ product effluent. In one or more aspects, the saturated C4+ product effluent may be supplemented with hydrotreated naphtha boiling range compounds for use as the lean oil.

[0061] In various aspects, the saturated C4+ product effluent (and any C4+ or C5+ hydrocarbons recovered in the absorber) may be stored in naphtha/distillate tanks separate from any coker wild naphtha so as to not contaminate the saturated C4+ product effluent, which may have low olefin, low sulfur, and/or low nitrogen properties, with the coker wild naphtha. Example of System Configuration

[0062] FIG. 1 depicts one example of a system 100 for processing cracked products. In the example system 100, a heavy oil feed 102, such as an oil derived from tar sand or a whole crude, may be subjected to certain conditions in the vessel 104 for coking and/or cracking to produce a cracked products feed 106, such as the cracked products feed discussed above. The cracked products feed 106 may be compressed in a conventional compressor 110 (along with a refinery fuel gas stream 108, such as a refinery fuel gas from a diesel hydrotreatment reactor). This combined and compressed stream 1 12 may be subjected to an initial fractionation in a fractionator 114 in order to separate at least a portion of the stream 112 into naphtha boiling range fraction 116 and a light ends fraction 124 of the cracked products feed. The naphtha boiling range fraction 116 may be subjected to hydrotreatment conditions in a hydrotreatment reactor 118 in order to saturate at least a portion of the olefins in the fraction and/or for sulfur removal to provide a hydrotreated naphtha boiling range fraction 120.

[0063] The light ends fraction 124 may be subjected to conversion conditions in a reactor

126 in order to oligomerize at least a portion of the olefins in the light ends fraction 124, thereby producing an oligomerized olefin effluent 128. The light ends fraction feed may first be amine treated to remove H2S and/or water washed to remove NH3 before entering the oligomerization reactor to minimize volume, use lower grade metallurgy, and/or minimize basic nitrogen reaction with the catalyst's acid sites. The oligomerized olefin effluent 128 may be subjected to hydrotreatment conditions in a hydrotreatment reactor 130 in order to saturate at least a portion of the oligomerized olefins in the oligomerized olefin effluent 128 and/or for sulfur removal to produce a saturated product effluent 132. This saturated product effluent 132 can be subjected to light ends recovery units 134 for one or more separations, such as those discussed above with respect to the saturated product effluent. For example, the saturated product effluent 132 may be separated into a liquid fraction and a vapor fraction, where the liquid fraction is subjected to a depropanizer or partially debutanized to remove C3- compounds and optionally a portion of high vapor pressure C4's from the liquid fraction, thereby leaving a C4+ product stream 142. The C4+ product stream 142 can include the amounts of olefins, hydrogen, and/or sulfur discussed above with respect to the C4+ product. In addition, as discussed above, the C4+ product stream 142 may be utilized as a diluent for a crude blending and/or as a lean oil in an absorber to recover C4 and/or C5 from a feed, such as a gas plant-derived feed.

[0064] The vapor fraction and/or the C3- compounds from the liquid fraction may be subjected to a deethanizer, with the resulting lighter fraction forming at least a portion of a refinery fuel gas stream 136. The refinery fuel gas stream 136 may be subjected to an amine wash 138 in order to remove sulfur, such as H2S, and produce a desulfurized fuel gas 140, which may be sent to a site's fuel gas system. In addition, the product stripper overhead 122 from the hydrotreater 118 may be mixed with the saturated product effluent and subjected to the light ends recovery units 134 discussed above.

Example - Increased Yields from the Processing of a Cracked Products Feed

[0065] It has been discovered that, using the methods for processing cracked products feeds described herein, the yield of naphtha boiling range compounds may be increased and a reduced hydrogen content refinery fuel gas may be produced.

[0066] Particularly, this Example describes empirical modelling that was performed using a fixed amount of a cracked products feed in various processes (outlined in FIGS. 2 and 3). FIG. 3 models a process based on the methods described above, while for comparison, FIG. 2 models a base process.

[0067] FIG. 2 depicts a schematic of a base or minimal process 200 for processing a cracked light products stream 202, such as the cracked light products formed according to any of the processes described herein. In this process 200, the cracked light products stream 202 is subjected to separation in light ends recovery units 204, such as the light ends recovery units discussed above. In this empirically modelled system 200, the light ends recovery units 204 separated the cracked products feed into a light ends fraction 206 and a fraction 208 containing naphtha boiling range compounds. The empirical modelling revealed that 1 1,452 MMBTU/hr of the light ends fraction 206 are produced in this system 200 based on a fixed amount of cracked light products stream 202. Further, the empirical modelling revealed that 85,280 kilobarrels per day (kbd) of the naphtha boiling range compounds fraction 208 are produced in this system 200.

[0068] FIG. 3 depicts a schematic of a process 300 for processing the cracked light products

302 of example 2 according to this invention, such as the cracked products feed discussed above. It is appreciated that the system 300 details an alternative process than that described in detail above, e.g., the process 100 of FIG. 1. As discussed below, in this alternative system 300, the light ends recovery units 314 have been placed upstream of the conversion reactor 320 as opposed to after, as described with reference to the system 100 of FIG. 1. One skilled in the art would appreciate that this alternative system 300 may be better suited for systems having a lower volume conversion reactor.

[0069] The cracked products feed 302 is subjected to an initial fractionation in vessel 304, such as a partial debutanizer. The cracked products feed 302 is separated into a naphtha boiling range fraction 306 that is subjected to hydrotreatment, e.g., high pressure hydrotreatment, in a hydrotreatment reactor 308. The system 300 is modelled to produce 63,191 kbd of the hydrotreated naphtha boiling range fraction 310.

[0070] The light ends fraction 312 is subjected to light ends recovery units 314 in order to separate the light ends fraction 312 into a C5+ compounds portion 322, a C4- compound portion 318, and a refinery fuel gas and/or the C3 or C2 compounds portion 316. The system 300 is modelled to produce 7,511 MMBTU/hr of this refinery fuel gas stream 316. The C4- compound portion 318 is subjected to effective conversion conditions in a conversion reactor 320 in order to produce an oligomerized olefin effluent 324 and additional fuel gas 328. In this modelled system 300, the oligomerized olefin effluent 324 is mixed with the C5+ compounds 322 and is modelled to produce 35,441 kbd of liquid C5+ product 326 including naphtha boiling range compounds. Further, steam generation as a result of extra heat generated during the reactions is modelled to be about 258 MMBTU/hr. These modelled amounts of products and steam are based on the same fixed amount of feed as in the system 200 modelling.

[0071] The system 300 is modelled to produce more liquid naphtha product (326 and 310, totaled to 98,632 kbd) compared to the modelled production of 85,280 kbd of liquid naphtha product in the minimal system 200. Thus, by the inclusion of an initial fractionation and an olefin oligomerization process, the system 300 is modelled to produce 15.6 % more liquid naphtha product than the minimal system 200. In addition, the system 300 is modelled to result in a reduced amount of net site fuel gas production equivalent: 11,452 MMMBTU/hr in the system 200 compared to 7,769 MMBTU/hr (7,511 MMBTU/hr from the fuel gas 316 and 258 MMBTU/hr from the fuel gas equivalent 328).

[0072] Table 1 below provides the analysis of the model conversion feed and product effluent for the system 300.

Effluent Yields

[0073] As can be seen in Table 1, the level of C5+ compounds is expected to be significantly increased in the product effluent compared to the feed (155,183.5 lbs/hr for the product compared to 43,703.6 lbs/hr for the feed) , and the C5+ compounds are further expected to include 69.1 wt. % of the olefins from the feed. Further, consistent with the oligomerization of olefins, the levels of olefins (ethylene, propene, butene, and butadiene) in the product effluent are significantly decreased relative to the levels in the feed ((product levels: 8,711.9 lbs/hr (ethylene), 5,807.9 lbs/hr (propene) and 13,713.2 lbs/hr (butenes)); (feed levels: 39,935.2 lbs/hr (ethylene), 64,851.8 lbs/hr (propene), and 50,201.8 lbs/hr (butenes)).

[0074] Table 2 below provides an analysis of the fuel gases modelled in the system 200 and the system 300 of FIGS. 2 and 3, respectively. Table 2: Fuel Gas Analysis: Expected Differences Based on the Modelled Systems 200 and 300

[0075] As can be seen in Table 2, the level of olefins (butene, propene, and ethene) is significantly reduced in the fuel gas of the system 300 compared to the system 200 (9,157 lb- mols/hr (butene), 36,467 lb-mols/hr (propene), and 37,671 lb-mols/hr (ethene) in the system 200 compared to 4 lb-mols/hr (butene), 17 lb-mols/hr (propene), and 20 lb-mols/hr (ethene) in the system 300). This reduction of olefins is expected to be due to the capturing of these olefins in the olefin oligomerization reaction in the system 300. Additionally, the level of other heavier hydrocarbons such as butane and pentane are significantly reduced in the fuel gas of the system 300 compared to the system 200 (5,152 lb-mols/hr (butane) and 7,643 lb-mols/hr (pentane) in the system 200 compared to 1,224 lb-mols/hr (butane) and 2,932 lb-mols/hr (pentane) in the system 300). This reduction is due to the additional, upfront fractionation conducted on the cracked naphtha feed in the system 300, prior to fractionation in the light ends recovery units.

[0076] Although the present invention has been described in terms of specific embodiments, it is not so limited. Suitable alterations/modifications for operation under specific conditions should be apparent to those skilled in the art. It is therefore intended that the following claims be interpreted as covering all such alterations/modifications as fall within the true spirit/scope of the invention.