FIELD

[0001] Systems and methods are provided for upgrading refinery fuel gas and/or production of naphtha from refinery fuel gas.

BACKGROUND

[0002] For various reasons, refinery fuel gas can be a low value product stream from one or more refinery processes, and is often utilized for burning in refinery furnaces. While a refinery fuel gas for use in refinery furnaces would ideally mostly comprise methane, a refinery fuel gas stream may include a variety of compounds, including some C4+ or C5+ compounds, olefins, sulfur-containing compounds, and/or hydrogen. The presence of any of these additional components can cause a refinery furnace to run hotter than normal, thereby increasing NOx production.

[0003] U.S. Patent No. 4,831,203 discloses a process for an improved separation and recovery of liquid hydrocarbons in a FCC gas plant. The process includes integrating a catalytic bed oligomerization reactor within the FCC gas plant to produce a gasoline product stream from a light olefinic FCC product stream.

[0004] 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.

[0005] U.S. Patent No. 6,372,949 discloses a one-step process for converting an oxygenate- containing feed to liquid boiling range C5+ hydrocarbons. The feed is contacted with a catalyst having a unidimensional 10-ring zeolite at a temperature less than 350°C and a pressure above 40 psia.

SUMMARY

[0006] In an aspect, a method for producing a refinery fuel gas product is provided. The method can include exposing an olefin-containing feed comprising at least about 50 wt. % C1-C4 compounds, at least about 10 wt. % C2+ olefins, or a combination thereof to a separation process. An example of a suitable separation process can be exposing the olefin-containing feed to a liquid sorbent stram. Optionally, the olefin-containing feed can be derived from at least one of a thermal cracking effluent and a fluid catalytic cracking effluent. The liquid sorbent stream can comprise C5+ compounds. The liquid sorbent stream can absorb at least a portion of C3+ compounds present in the olefin-containing feed, thereby forming a first effluent. Optionally, at least a portion of the first effluent can then be exposed to one or more amine-containing compounds to remove at least a portion of sulfur-containing compounds present in the first effluent to form at least a desulfurized effluent. At least a portion of the desulfurized effluent can then be exposed to effective conversion conditions to produce an oligomerized effluent comprising oligomerized C5+ compounds. The effective conversion conditions can incldue exposing at least a portion of the desulfurized effluent to an acidic zeolite catalyst at (for example) a pressure of less than about 400 psig, and a temperature of from about 700°F to about 800°F. At least a portion of the C3+ compounds (or at least C5+ compounds) can be separated from the oligomerized effluent to form a light hydrocarbon effluent. The light hydrocarbon effluent can have an increased weight percent of methane relative to the oligomerized effluent. At least a portion of the light hydrocarbon effluent can be exposed to one or more amine-containing compounds to form a product effluent, the product effluent comprising at least about 70 wt% less (organic) sulfur compounds than the olefin-containing feed, at least about 10 wt% less (organic) nitrogen compounds than the olefin-containing feed, or a combination thereof.

[0007] In another aspect, a method for producing a refinery fuel gas product is provided. The method can include exposing an olefin-containing feed comprising at least about 50 wt. % C1-C4 compounds, at least about 10 wt. % C2-C4 olefins, or a combination thereof to a liquid sorbent stream to absorb at least a portion of C3+ compounds present in the olefin-containing feed, thereby forming a first effluent. The liquid sorbent stream can comprise C5+ compounds. Optionally, at least a portion of the first effluent can be exposed to one or more amine-containing compounds to remove at least a portion of sulfur-containing compounds present in the first effluent, thereby forming a desulfurized effluent. At least a portion of the desulfurized effluent can be exposed to effective conversion conditions to produce an oligomerized effluent comprising C5+ olefins and H2. The effective conversion conditions can include exposing at least a portion of the desulfurized effluent to an acidic zeolite catalyst at (for example) a pressure of less than about 400 psig and a temperature of from about 700°F to about 800°F. At least a portion of the oligomerized effluent and a sulfur-containing naphtha boiling range feed can then be exposed to a hydrodesulfurization catalyst under effective hydrodesulfurization conditions to form a desulfurized effluent. At least a portion of the C5+ olefins can then be separated from the desulfurized effluent to form at least a light hydrocarbon effluent. Optionally, the light hydrocarbon effluent can have an increased wt. % of methane and/or ethane relative to the oligomerized effluent. At least a portion of the light hydrocarbon effluent can be exposed to one or more amine-containing compounds to remove at least a portion of sulfur-containing compounds to form a product effluent. The product effluent can have a heating value of from about 850 BTU/SCF to about 1200 BTU/SCF.

[0008] In still another aspect, a refinery fuel gas product derived from at least one of a thermal cracking effluent and fluid catalytic cracking effluent is provided. The refinery fuel gas product can have a heating value of from about 850 BTU/SCF to about 1200 BTU/SCF. The refinery fuel gas product can include methane, ethane, and/or propane. The refinery fuel gas product can include at least about 5 wt. % of d compounds, about 5 wt% or less of C3+ compounds, about 5 wt% or less of olefins, an organic sulfur content of about 100 wppm or less, or a combination thereof.

[0009] In yet another aspect, a method for producing a refinery fuel gas product is provided. The method can include exposing an olefin-containing feed comprising at least about 50 wt. % Ci- C4 compounds, at least about 10 wt. % C2-C4 olefins, or a combination thereof to a liquid sorbent stream to absorb at least a portion of C3+ compounds present in the olefin-containing feed, thereby forming a first effluent. Optionally, at least a portion of the first effluent can be exposed to one or more amine-containing compounds to remove at least a portion of sulfur-containing compounds present in the first effluent, thereby forming a desulfurized effluent. At least a portion of the desulfurized effluent can be exposed to effective conversion conditions to produce an oligomerized effluent comprising C5+ olefins. The effective conversion conditions can include exposing at least a portion of the desulfurized effluent to an acidic zeolite catalyst at (for example) a pressure of less than about 300 psig and a temperature of from about 700°F to about 800°F. At least a portion of the oligomerized effluent (which can contain hydrogen) can be exposed to a catalyst to saturate at least a portion of the C5+ olefins, thereby forming a saturated oligomerized effluent. At least a portion of the C3+ olefins (or C5+ olefins) can be separated from the saturated oligomerized effluent to form a light hydrocarbon effluent. The light hydrocarbon effluent can have an increased wt. % of methane and/or ethane relative to the oligomerized effluent. At least a portion of the light hydrocarbon effluent can be exposed to one or more amine-containing compounds to remove at least a portion of sulfur-containing compounds present in the light hydrocarbon effluent, thereby forming a product effluent. The product effluent can correspond, for example, to a refinery fuel gas product having a heating value of from about 850 BTU/SCF to about 1200 BTU/SCF.

BRIEF DESCRIPTION OF THE FIGURE

[0010] FIG. 1 schematically shows an example of a reaction system for upgrading a refinery fuel gas product having a controlled energy content, according to an aspect of the invention. DETAILED DESCRIPTION

Overview

[0011] In various aspects, systems and methods are provided for upgrading a refinery fuel gas. In some aspects, this can include producing a refinery fuel gas product having a controlled energy content from an olefin-containing feed. Additionally or alternately, in some aspects this can include producing a naphtha boiling range product from a refinery fuel gas.

[0012] In one or more aspects, the olefin-containing feed can comprise a refinery fuel gas stream. An example of a refinery fuel gas stream can be a light ends stream produced by a Fluid Catalytic Cracking (FCC) and/or a coker unit. The olefin-containing feed can include hydrogen, methane, ethane, or other Cs- compounds, olefins, sulfur-containing compounds, nitrogen- containing compounds such as amines and ammonia, inert gases, or a combination thereof. At least a portion of the olefin-containing feed is exposed to a liquid stream comprising C5+ compounds (or heavier) to remove at least a portion of C3+ compounds present in the refinery fuel gas stream to form an effluent having a reduced content of C3+ hydrocarbons. One or more sulfur- containing compounds can be converted to H2S in the oligomerization zone For example, the effluent having a reduced content of C3+ hydrocarbons can be exposed to one or more amine compounds (such as an amine wash) to produce a desulfurized effluent. The desulfurized effluent can be exposed to effective conversion conditions to produce an oligomerized effluent comprising oligomerized olefins, such as C5+ olefins. The oligomerized olefins can be removed thereby forming a light hydrocarbon effluent. The light hydrocarbon effluent, corresponding to an upgraded refinery fuel gas, can optionally be exposed to an amine wash for further desulfurization. The resulting refinery fuel gas product can provide a variety of advantages when burned in refinery furnaces, such as buming at a more controlled temperature (i.e., not too hot), which can reduce NOx emissions.

[0013] One of the difficulties of burning a refinery fuel gas stream in a refinery furnace is that various amounts of H2, C2+ compounds (including C4+ or C5+ compounds), and or olefins, present in the refinery fuel gas stream can cause the furnace to bum faster and therefore at a higher local temperature than optimum. The exact composition of a fuel gas can strongly influence its buming and emission characteristics. If the actual mix of hydrocarbons in a fuel gas has an increased percentage of C2+ compounds relative to an expected composition, the resulting combustion reaction will generate an increased amount of heat, leading to an unexpectedly high local burner temperature. In certain scenarios, burning a furnace at an elevated temperature can increase NOx production. Further, by burning refinery fuel gas containing H2, C2+ compounds and/or olefins, a refinery may lose any potential value that can be obtained from the H2, C2+ compounds and/or olefins.

[0014] In some aspects, the systems and methods described herein can address one or more of the above problems. For example, by oligomerizing at least a portion of the olefins present in the refinery fuel gas to C5+ olefins and then removing these C5+ olefins, the resulting fuel gas will contain less C2+ compounds, or have an increased amount (wt. %) of methane compared to the initial refinery fuel gas. In various aspects, this refinery fuel gas product can have a more controlled energy content and can be burned in a refinery furnace without burning too hot at an early phase of combustion, which can reduce NOx production. Further, by separating out the C5+ olefins generated in the methods and systems described herein, a valuable product stream, e.g., naphtha boiling range compounds or products, can be recovered from a stream that may initially have little or no content of naphtha boiling range compounds. Thus, in various aspects, the systems and methods described herein can reduce NOx and SOx production at a refinery and produce valuable naphtha boiling range compounds or products, while reducing, minimizing, or possibly eliminating the need to implement other NOx-reducing processes, such as Selective Catalytic Reduction.

[0015] In other aspects, the desulfurized effluent is mixed with a sulfur containing naphtha stream such as light FCC naphtha, FCC naphtha, coker naphtha or pyrolysis naphtha to also reduce the sulfur content of said naphtha stream by hydrogen formed in the oligomization step. The oligomerization effluent is preferably sent to a fractionation system to recover C3-C4, C5+ and C2- rich fuel gas. C2- rich fuel gas is then scrubbed with at least one amine to remove H2S and NH3/HCN produced in the oligomerization reactor. In one aspect of this aspect the oligomerization effluent is sent to a hydrotreating reactor to saturate olefins and further desulfurize naphtha while consuming H2 present in said oligomerization effluent. Optionally, refrigeration can also be utilized to help separation of C3 or C2+ compounds from a fuel gas product.

[0016] The above aspects can assist with providing a fuel gas with a reduced or minimized variation in fuel content by reducing or minimizing the presence of olefins, H2 and/or C3+ compounds in the fuel gas. Reducing the variation in the energy content and/or flame speed of a fuel gas can reduce or minmize NOx (i.e., nitrogen oxides) generation in furnaces as said fuel gas is burned. By removing fast burning compounds, said fuel gas NOx production is reduced by more than 10% and in many cases by more than 25%. This helps sites to meet environmental regulations related to NOx emissions. Furthermore, the dual stage sulfur scrubbing in addition to oligomerization conversion of sulfur compounds in fuel gas to H2S allows fuel gas burning SOx emission reduction as well. [0017] In some aspects, an oligomerization reaction can be operated in a sweet spot that increases or maximizes C3- olefins conversion to C4+ or ethylene conversion to C3+ to minimize light olefins burning in furnaces. Unlike in the conventional oligomerization operations, the sweet operating spot does not necessarily maximize C5+ production but it ensures minimizing environmental emissions. A narrow temperature range of 700-800°F can be used for this purpose, such as 725-775°F.

[0018] Based on one or more of the above features, the methods described herein can reduce fuel gas burning emissions while upgrading more than 60% of the olefin content of the fuel gas to larger compounds; reducing more than 70% of the organic sulfur content of the fuel gas with minimal or no H2 addition to the reaction environment; utilizing at least a portion of the H2 content of the fuel gas for hydrotreating; reducing corrosiveness of fuel gas by reducing the content of mercaptans and/or oxygenates in the fuel gas by at least 70%; and/or recovering more valuable LPG (liquefied propane gas) and heavier compounds from the fuel gas. The above benefits (individually or in combination) can be achieved by running an oligomerization reaction zone in a conversion mode that is selective for ethylene or ethylene-plus-propylene conversion, utilizing a hydroprocessing zone downstream of the oligomerization zone and using conventional fractionation, refrigeration and amine scrubbing for removing more H2S and recovering more C3+ compounds. Optionally, sulfur-containing olefinic naphtha can also be upgraded and desulfurized in the oligomerization step.

[0019] 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/or a final or T95 boiling point of less than about 450°F (232°C). 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. Olefin-Containing Feed

[0020] The olefin-containing feed can be any hydrocarbon feed that contains olefins. In one or more aspects, at least a portion of the olefin-containing feed can be a portion of a product stream from an FCC unit or flue gas from a cracking or coking process, such as a refinery fuel gas stream. More generally, the olefin-containing feed can correspond to a feed that is substantially composed of Ci - C4 hydrocarbons. While C5+ compounds can be included, conventional separation processes can typically allow for recovery of such C5+ compounds as part of a naphtha boiling range stream. Optionally, an olefin-containing feed can also include one or more sulfur-containing naphtha fractions such as light FCC naphtha, FCC naphtha and coker naphtha

[0021] In various aspects, the olefin-containing feed can include at least about 1 wt. 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. %. In the same or alternative aspects, the olefin-containing feed can include less than about 100 wt. % olefins, less than about 90 wt. %, less than about 80 wt. %, or less than about 70 wt. %.

[0022] In one or more aspects, the olefin-containing feed can include at least about 1 wt. % Ci- C4 hydrocarbon compounds, with a portion being C2-C4 olefins, such as the olefin amounts listed above, 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. %, at least about 70 wt. %, at least about 80 wt. %, at least about 90 wt. %, or at least about 95 wt. %. In the same or alternative aspects, the olefin-containing feed can include less than about 100 wt. % C1-C4 hydrocarbon compounds, with a portion being C2-C4 olefins, such as the olefin amounts listed above, less than about 90 wt. %, less than about 80 wt. %, or less than about 70 wt. %. In certain aspects, the olefin- containing 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 than the amount (wt. %) of C2-C4 olefins, at least about 20 wt. % greater, at least about 30 wt. % greater, at least about 40 wt. % greater, at least about 50 wt. % greater, at least about 60 wt. % greater, at least about 70 wt. % greater, at least about 80 wt. % greater, or at least about 90 wt. % greater.

[0023] In some aspects, while C5+ compounds can be included in the olefin-containing feed, preferably they can be separated out in a prior separation for recovery of naphtha. In such aspects, C5+ compounds can be present in the olefin-containing feed in an amount of about 5 wt. % or less, about 2.5 wt. % or less, or about 1 wt. % or less. In other aspects, a sulfur-containing C5+ naphtha feed can be added to an olefin-containing feed to use hydrogen generated from olefin oligomerization for naphtha sulfur reduction. In yet other aspects, an olefinic C5+ naphtha feed can be added to the olefin-containing feed to upgrade the C5+ olefins to higher value products.

[0024] In one or more aspects, the olefin-containing feed can include hydrogen gas in an amount of at least about 1 wt. %, at least about 5 wt. %, or at least about 10 wt. %. In the same or alternative aspects, the olefin-containing feed can include hydrogen gas in an amount of about 25 wt. % or less, or about 20 wt. % or less, or about 15 wt. % or less, or about 10 wt. % or less.

[0025] In some optional aspects, the olefin-containing 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 7000 wppm 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.

[0026] In one or more aspects, the olefin-containing feed can include an inert gas, such as nitrogen (N ₂ ). In such aspects, the inert gas may be present in the olefin-containing feed in an amount of at least about 0.5 wt. %, at least about 1 wt. %, at least about 5 wt. %, at least about 10 wt. %, at least about 20 wt. %, or at least about 30 wt. %. In the same or alternative aspects, the inert gas may be present in the olefin-containing feed in an amount of about 50 wt. % or less, about 40 wt. % or less, or 30 wt. % or less.

[0027] In one or more optional aspects, nitrogen compounds can also be present in the olefin- containing 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. In another aspect, the nitrogen content can be about 250 wppm or less, or about 150 wppm or less, or about 100 wppm or less, or about 50 wppm or less.

[0028] As discussed above, in various aspects, the olefin-containing feed can include one or more low value refinery streams, such as refinery fuel gas or flue gas from a cracking or coking process. In such aspects, the one or more low value streams may be present in the olefin-containing feed in an amount of at least about 50 wt. %, 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. %. In the same or alternative aspects, the one or more low value streams may be present in the olefin- containing feed in an amount of about 100 wt. % or less, about 99 wt. % or less, about 95 wt. % or less, about 90 wt. % or less, about 80 wt. % or less, about 70 wt. % or less, or about 60 wt. % or less.

[0029] In one or more aspects, the olefin-containing feed can include a refinery fuel gas from an FCC unit, such as in the amounts discussed above. In such aspects, the refinery fuel gas can include a C ₄ - cut of the product effluent of an FCC unit. In various aspects, the refinery fuel gas from an FCC unit can include any combination of the properties of the olefin-containing feed discussed above.

[0030] In various aspects, any type of FCC process or system can be utilized to produce a refinery fuel gas that can be included in the olefin-containing feed. In a conventional FCC process, a feed, such as a feed boiling in the range of about 430°F to about 1050°F (221°C to 566°C) or higher, can be contacted with a conventional catalytic cracking catalyst under cracking conditions to produce a product effluent. The product effluent can be fractionated into a refinery fuel gas stream, a catalytic naphtha stream, a light cycle oil stream, and an FCC bottoms stream. In various aspects, such a fractionated refinery fuel gas stream can be utilized in the olefin-containing feed described herein. In one aspect, at least majority of C3-C4 compounds can also be fractionated out of the fuel gas.

[0031] It is appreciated that other olefin-containing feeds may be used in the processes disclosed herein and that the above-described feed properties are only exemplary.

Primary Absorber

[0032] In various aspects, the olefin-containing feed can pass through a heavy hydrocarbon liquid stream in a primary absorber to remove at least a portion of the heavy hydrocarbons, such as C3+, C4+, and/or C5+ hydrocarbons, from the olefin-containing feed. The heavy hydrocarbon liquid stream can be any type of conventional heavy hydrocarbon liquid stream utilized in conventional primary absorbers. In one or more aspects, the heavy hydrocarbon liquid stream can be a C5+ hydrocarbon liquid stream. In one or more aspects, the heavy hydrocarbon liquid stream can be a naphtha boiling range stream. In various aspects, the naphtha boiling range stream can be a catalytic naphtha stream of a product effluent of a FCC unit. In one or more aspects, at least a portion of the catalytic naphtha stream and at least a portion of the olefin-containing feed can be different fractions of a product effluent of an FCC unit or other cracking process. In various aspects, the heavy hydrocarbon liquid stream can be a virgin naphtha stream or wild naphtha from FCC or coker main fractionator overhead system.

[0033] It is appreciated that any conventional primary absorber can be used in the systems and processes described herein. In general, in a primary absorber, a pressurized gaseous feed, e.g., the olefin-containing feed described herein, is passed through a countercurrent flow of a heavy hydrocarbon liquid stream. Once the olefin-containing feed is passed through the heavy hydrocarbon liquid stream, a first effluent is formed. This first effluent can include a reduced level of C3+, C4+, and/or C5+ hydrocarbons compared to the olefin-containing feed. Alternatively, the first effluent can be a wet gas compressor outlet stream with or without effluent cooler and separator.

Amine Wash

[0034] In various aspects, the effluent having a reduced content of C3+ hydrocarbons that exits the primary absorber or wet gas compressor system can be subjected to an optional 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 effluent having a reduced content of C3+ hydrocarbons. 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 optional amine wash, the effluent having a reduced content of C3+ hydrocarbons 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 effluent having a reduced content of C3+ hydrocarbons to form a second or desulfurized effluent, which includes at least a portion of the remainder of the original olefin-containing feed.

Oligomerization of Olefins

[0035] In various aspects, the effluent having a reduced content of C3+ hydrocarbons or the desulfurized effluent from the amine wash can be exposed to an acidic catalyst (such as a zeolite) under effective conversion conditions for olefinic oligomerization. Optionally, the zeolite or other acidic catalyst can also include a metal function, such as a Group VIII metal or other suitable metal or combinations of metals. The desulfurized effluent can be exposed to the acidic catalyst without providing preferably any 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 or comes along with the process feedstream. Exposing the desulfurized effluent to an acidic catalyst without providing 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; c) a combination thereof. It is noted that exposing the desulfurized effluent to an acidic catalyst without providing added hydrogen is explicitly defined to include the situation where no added hydrogen is present and/or where the partial pressure of hydrogen is 0 to within one decimal place (i.e., less than about 0.1 psig, or less than about 1 kPag).

[0036] 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.

[0037] 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.

[0038] The exposure of the desulfurized effluent to the acidic catalyst can be performed in any convenient manner, such as exposing the olefin-containing feed or the desulfurized effluent to the acidic catalyst under fluidized bed 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.

[0039] 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 desulfurized effluent. For example, such catalysts can convert C2-C4 olefins, such as those present in a fuel gas from an FCC unit, to C5+ olefins. 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 olefin-containing feed or the desulfurized effluent. 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. [0040] 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.

[0041] 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).

[0042] Useful metals 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.

[0043] 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.

[0044] 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.

[0045] In various aspects, the fluidized bed 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.

[0046] 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.

[0047] In various aspects, the desulfurized effluent 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.

[0048] In various aspects, the effective conversion conditions are chosen to increase the oligomerization of the olefins present in the olefin-containing feed or desulfurized effluent. In such aspects, the effective conversion conditions may include a temperature of from about 700°F (371°C) to about 800°F (427°C), or of from about 750°F (399°C) to about 800°F (427°C); and a pressure of about 150 psig (1.03 MPag) to about 200 psig (1.4 MPag), or about 300 psig (4.1 MPag) or less. In a conventional process, the goal would be to increase or maximize production of naphtha boiling range compounds, which occurs at 700°F (371°C) or less.

[0049] In one or more aspects, the effective conversion conditions for exposing the olefin- containing feed or the desulfurized effluent to an acidic catalyst can generally include a temperature of about 650°F (343°C) to about 1000°F (537°C). In certain aspects, naphtha products can be increased at a temperature of about 750°F (399°C) or less. In various aspects, olefin oligomerization can be increased at a temperature of from about 700°F (371°C) to about 800°F (427°C), or of from about 750°F (399°C) to about 800°F (427°C). In one or more aspects, by selecting a higher temperature range, such as about 700°F (371°C) to about 800°F (427°C), or about 750°F (399°C) to about 800°F (427°C), naphtha yield is reduced, but the overall level of C2-C3 olefin conversion is increased. In various aspects, by increasing the overall conversion of C2 or C2-C3 olefin oligomerization, the refinery fuel gas product produced in the processes described herein will be improved, as more olefins and/or C2+ compounds will have been oligomerized and removed prior to burning the refinery fuel gas product, which can reduce NOx production.

[0050] In various aspects, the effective conversion conditions for exposing the olefin- containing feed or the desulfurized effluent gas to an acidic catalyst can include a pressure of about 50 psia (0.34 MPa) to about 350 psig (2.4 MPag), or about 100 psig (0.69 MPag) to about 300 psig (4.1 MPag), or about 150 psig (1.03 MPag) to 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; and a weight hourly space velocity of about 0.05 hr ¹ to about 20 hr ¹ , or about 0.05 to about 10 hr ¹ , or about 0.1 to about 10 hr ¹ , or about 0.1 to about 2 hr ¹ , or about 0.1 hr ¹ to about 1.0 hr ¹ , or about 0.1 hr ¹ to about 0.75 hr ¹ , or about 0.1 hr ¹ to about 0.6 hr ¹ . However, preferably for the purposes of maximizing light olefins conversion a WHSV of 0.5 hr ¹ or higher is used to maximize C2-C3 conversion by reducing or minimizing C5+ cracking back to light components.

[0051] It is noted that in some aspects, temperatures of about 550°F (260°C) to about 700°F (371°C) can provide a beneficial combination of reactivity and run length. Temperatures below 550°F can result in high rates of catalyst deactivation, which leads to reduced reactivity extent of oligomerization reaction.

[0052] In various aspects, exposing the desulfurized effluent to the conversion conditions discussed above can produce an oligomerized effluent that includes oligomerized olefins. In such aspects, this oligomerized effluent can include an increased C5+ content and/or an increased amount of naphtha boiling range compounds compared to the olefin-containing feed or the desulfurized effluent. In certain aspects, at least about 10 wt. %, at least about 20 wt. %, at least about 30 wt. %, at least about 40 wt. %, or at least about 50 wt. % of the olefins from the olefin- containing feed or the desulfurized effluent can be incorporated into the oligomerized olefins in the oligomerized effluent. An oligomerized effluent can contain olefins, saturates and aromatics. Optional Saturation of the Oligomerized Olefins

[0053] In one or more aspects, the oligomerized olefins in the oligomerized effluent can be subjected to saturation conditions to saturate at least a portion of the oligomerized olefins. In various aspects, hydrogen present in the oligomerized 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 processed into a gasoline or other valuable product. In another embodiment when sulfur-containg naphtha is partially desulfurized in the oligomerization step, the optional saturation step can also increase the degree of desulfurization of naphtha in the overall process.

[0054] To saturate at least a portion of the oligomerized olefins present in the oligomerized effluent, the oligomerized effluent can be exposed to a hydrofinishing 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, such as Ni, NiW, NiMo, NiMoW, Co, C0M0, or CoW. 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 M41 S 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.

[0055] 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 .

[0056] 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 effluent. In this type of aspect, the gas phase reaction pressure of the oligomerization reactor effluent after a cooler can be used as the hydrogen-containing treat gas to prevent additional processing before hydrofinishing. 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 effluent can be exposed to the hydrotreating catalyst under conventional hydrotreating conditions and/or the hydrofinishing conditions described above.

Separation of Oligomerized Naphtha Boiling Range Product

[0057] In various aspects, the oligomerized olefins from the oligomerized effluent can be removed. Any conventional refinery processes, such as the use of a sponge absorber and/or a refrigeration system, can be utilized to remove at least a portion of the oligomerized olefins from the oligomerized effluent. In one or more aspects, in a sponge absorber, the oligomerized effluent can be exposed to a hydrocarbon liquid sorbent stream or sponge oil. A non-limiting list of hydrocarbon liquid sorbent streams includes a naphtha stream (e.g., a stripped heavy naphtha), light fuel oil, light cycle oil, or a combination thereof. In various aspects, the hydrocarbon liquid sorbent stream or sponge oil can have an initial or T5 boiling point of at least about 70°C (158°F), at least about 80°C (176°F), or at least about 90°C (194°F), and/or a T80 boiling point of less than about 315°C (600°F), less than about 288°C (550°F), or less than about 260° (500°F).

[0058] In one or more aspects, at least a portion of the oligomerized effluent can be exposed to a countercurrent flow of a hydrocarbon liquid sorbent stream to remove at least a portion of oligomerized olefins from the oligomerized effluent to form a fourth or light hydrocarbon effluent. In such aspects, the light hydrocarbon effluent can include at least about 20 wt. %, at least about 30 wt. %, at least about 40 wt. %, at least about 50 wt. %, at least about 75 wt. %, at least about 85 wt. %, or at least about 95 wt. % less C3+oligomerized olefins than the oligomerized effluent. Additional Amine Wash

[0059] In various aspects, the light hydrocarbon effluent may be subjected to an amine wash to remove at least a portion of sulfur-containing compounds present therein, such as H2S that may have been formed during the olefin oligomerization process. Any conventional amine wash process is suitable, such as the amine wash processes discussed above. The product effluent resulting from the amine wash can include a refinery fuel gas product.

[0060] Optionally, the rich amine from the additional amine wash can be cascaded as lean amine to the first amine wash. This can reduce or minimize the amine regeneration cost.

Refinery Fuel Gas Product

[0061] In various aspects, the refinery fuel gas product can include less olefins, less sulfur, and/or less nitrogen than the initial olefin-containing feed, which can provide a more controlled energy output when burned in refinery furnaces, and provide reduced NOx and/or SOx emissions.

[0062] In one or more aspects, the refinery fuel gas product includes at least about 40 wt. % less C2-C4 olefins than the initial olefin-containing feed, at least about 50 wt. % less, at least about 60 wt. % less, at least about 70 wt. % less, at least about 80 wt. % less, at least about 90 wt. % less, or at least about 95 wt. % less. In various aspects, the refinery fuel gas product includes at least about 40 wt. % less C2-C5 olefins than the initial olefin-containing feed, at least about 50 wt. % less, at least about 60 wt. % less, at least about 70 wt. % less, at least about 80 wt. % less, at least about 90 wt. % less, or at least about 95 wt. % less.

[0063] In one or more aspects, the refinery fuel gas product can include at least methane, ethane, and propane. The refinery fuel gas product can further comprise at least about 5 wt% C2 compounds, or at least about 10 wt%; about 5 wt% or less of C3+ compounds, or about 2 wt% or less; and/or about 5 wt% or less of olefins, or about 2 wt% or less. [0064] In one or more aspects, the organic sulfur content (i.e., excluding H2S) of the refinery fuel gas product can be about 500 wppm or less, or about 100 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. In the same or alternative aspects, the organic sulfur content of the refinery fuel gas product can be reduced by at least about 50%, or at least about 60%, or at least about 70%, or at least about 80%, or at least about 90%, or at least about 95% relative to the sulfur content of the initial olefin-containing feed. Additionally or alternately, the organic nitrogen content of the refinery fuel gas product can be reduced by at least about 10%, or at least about 30%, or at least about 50%, or at least about 70%, or at least about 90% relative to the nitrogen content of the initial olefin-containing feed.

[0065] In various aspects, the refinery fuel gas product can have a heating value of at least about 850 BTU/SCF, at least about 900 BTU/SCF, at least about 950 BTU/SCF, or at least about 1000 BTU/SCF. In the same or alternative aspects, the refinery fuel gas product can have a heating value of about 1500 BTU/SCF or less, about 1400 BTU/SCF or less, about 1300 BTU/SCF or less, about 1200 BTU/SCF or less, about 1100 BTU/SCF or less, or about 1050 BTU/SCF or less. Example of System Configuration

[0066] FIG. 1 depicts one example of a system 100 for producing a refinery fuel gas product from an olefin-containing feed. In the example system 100, the olefin-containing feed includes a refinery fuel gas stream 110 from an FCC unit 104, but any other convenient source of a refinery fuel gas containing olefins could also be used. In the FCC unit 104, a feed 102 is subjected to catalytic cracking conditions and the resulting effluent 106 can be subjected to a conventional fractionator 108. The fractionator 108 can separate the effluent 106 into a refinery fuel gas stream 110 and a catalytic naphtha stream 112. The fuel gas stream 110 and the catalytic naphtha stream 112 can have any or all of the respective properties discussed above. In the primary absorber 114, the fuel gas stream 110 is exposed to a countercurrent flow of a liquid sorbent stream that includes the catalytic naphtha stream 112, to thereby absorb at least a portion of the C3+ compounds present in the refinery fuel gas stream 110. The resulting effluent gas stream 116 is then subjected to a conventional amine wash 118, such as the amine wash discussed above, to remove at least a portion of the sulfur-containing compounds present in the effluent gas stream 116. The gas stream effluent 120 can be exposed to a conversion catalyst in the conversion reactor 122, such as one or more of the acidic catalysts discussed above. The conversion reactor 122 can be a fiuidized bed reactor. In one or more aspects, a portion 124 of the conversion catalyst in the conversion reactor 122 can be sent to a regenerator 126 for regeneration. The regenerated catalyst 128 can be returned to the conversion reactor 122. [0067] The conversion conditions in the conversion reactor 122 can be maximized to oligomerize at least a portion of the olefins present in the gas stream effluent 120. The effluent 130 exiting the conversion reactor 122 can include C5+ olefins, such as in the amounts discussed above. The effluent 130 can then be subjected to a sponge absorber 132, such as the sponge absorber discussed above, to remove at least a portion of the C5+ olefins present in the effluent 130. The effluent 134 exiting the sponge absorber 132 can then be subjected to another amine wash 136 to remove at least a portion of the sulfur-containing compounds present in the effluent 134. The resulting product effluent 138 includes a refinery fuel gas product, such as the refinery fuel gas product discussed above.

[0068] 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.