Abstract:
This invention focuses on the specialized catalyst and/or additive for lower FCCU gasoline and diesel blendstock component sulfur content. This invention utilizes a specified ratio of the transition metal oxides of cobalt and molybdenum to accomplish gasoline and diesel blendstock sulfur reduction. This is accomplished by minimizing sulfur compound formation in the FCCU riser. The cobalt and molybdenum oxides in the presence of H 2 S from cracked organic sulfur compounds are converted to metal sulfides. A portion of the overall sulfur reduction in the gasoline and diesel blendstock occurs emitted NO x  also is reduced.

Description:
CROSS REFERENCE TO RELATED APPLICATION 
     This application is a conversion of and claims the benefit of U.S. provisional patent application Ser. No. 60/798,267 filed May 4, 2006. 
    
    
     TECHNICAL FIELD 
     This invention relates to the reduction of sulfur in gasoline and other petroleum products produced by a catalytic cracking process. The invention uses a specific FCCU catalyst additive. This invention relates to a novel approach to FCCU gasoline sulfur reduction. The approach uses a specified ratio of the transition metal oxides of cobalt and molybdenum to accomplish gasoline and diesel blendstock sulfur reduction. This approach also reduces emitted NO x . 
     BACKGROUND OF THE INVENTION 
     Catalytic cracking is a petroleum refining process which is applied commercially on a very large scale. A majority of the refinery gasoline blending pool in the United States is produced by this process. In the catalytic cracking process heavy hydrocarbon fractions are converted into lighter products by reactions taking place at elevated temperature in the presence of a catalyst, with the majority of the conversion or cracking occurring in the vapor phase. The feedstock is thereby converted into gasoline, distillate and other liquid cracking products as well as lighter gaseous cracking products. 
     During catalytic cracking, heavy material, known as coke, is deposited onto the catalyst. This reduces its catalytic activity and regeneration is desired. After removal of hydrocarbons from the spent cracking catalyst, regeneration is accomplished by burning off the coke which restores the catalyst activity. The three characteristic steps of the catalytic cracking can be therefore be distinguished: a cracking step in which the hydrocarbons are converted into lighter products, a stripping step to remove hydrocarbons adsorbed on the catalyst and a regeneration step to burn off coke from the catalyst. The regenerated catalyst is then reused in the cracking step. Catalytic cracking feedstocks normally contain sulfur in the form of organic sulfur compounds such as mercaptans, sulfides and thiophenes. The products of the cracking process correspondingly tend to contain sulfur impurities even though about half of the sulfur is converted to hydrogen sulfide during the cracking process. 
     For modern refineries, the Fluid Catalytic Cracking Unit (FCCU) produces 40 to 60+% of the gasoline in the gasoline pool. In addition, the FCCU produces a blendstock component for diesel manufacture. Air quality regulations for these transportation fuels will require a further reduction in sulfur content as mandated by the Clean Air Act. For the FCCU process, there are two routes a refiner can utilize to further reduce the sulfur content of these transportation fuels. The first route is via a hydrotreatment process on the feedstock to the FCCU. This hydrotreatment process can by operational severity and design, remove a substantial amount of the feed sulfur to produce a gasoline sulfur content of 100 ppmw or less. The second route a refiner can take involves the use of a specialized catalyst or additive in the FCCU circulating catalyst inventory that can catalytically remove sulfur from the FCCU product distributions. Refiners may elect to use this route for both non-hydrotreated and/or hydrotreated FCCU feedstock derived from various crude sources. In addition, if a refiner utilizes the first route for desired gasoline sulfur content, when the hydrotreater is taken out of service for an outage, this specialized catalyst or additive can be utilized to minimize the increase of gasoline sulfur during the outage period. 
     A need exists to continue to remove SO 2  gas. A need also remains in the refining industry for improved compositions and processes which minimizes the content of gas phase reduced nitrogen species and NO x  emitted from a partial or complete combustion FCCU riser during an FCC process, which compositions are effective and simple to use. 
     Other objects and advantages of the present invention will become apparent to those skilled in the art upon a review of the following detailed description of the preferred embodiments and the accompanying drawings. 
     SUMMARY OF THE INVENTION 
     We have now found catalytic materials for use in the catalytic cracking process which are capable of improving the reduction in the sulfur content of the liquid products of the cracking process including, in particular, the gasoline and middle distillate cracking fractions. The present sulfur reduction catalysts may be used in the form of an additive catalyst in combination with the active cracking catalyst in the cracking unit, that is, in combination with the conventional major component of the circulating cracking catalyst inventory. 
     This invention focuses on the specialized catalyst additive for lower FCCU gasoline and diesel blendstock sulfur reduction. Compared to commercially available catalysts and additives, this invention offers the following benefits over current commercial offerings at a constant wt %. The improvements are: a significant improvement in gasoline sulfur reductions, a significant reduction in diesel blendstock component sulfur content, a significant reduction in thiophenic, benzothiophenic and di-benzothiophenic compounds, a significant increase in propylene, a significant increase in iso-butylenes, a significant increase in total pentenes with a corresponding increase in amylenes and iso-amylenes, a significant reduction in ethane, propane and butane, a significant reduction of organic sulfur compounds in the Liquefied Petroleum Gas (LPG) an increase in FCC gasoline (R+M/2) octane, a significant reduction of H2S and a reduction in flue gas NOx. 
     This is accomplished by; minimizing sulfur compound formation in the FCCU riser. The cobalt and molybdenum oxides in the presence of H2S from cracked organic sulfur compounds are converted to metal sulfides. A portion of the overall sulfur reduction in the gasoline and diesel blendstock occurs by minimizing the availability of H2S to combine with olefinic compounds formed in the cracking reactions. It further is accomplished by maximizing the amount of refractory sulfur left uncracked in the slurry oil while maintaining a specified slurry oil production target. As slurry oil refractory sulfur is reduced via cracking, the various lighter cracked sulfur compounds formed are distributed or cracked “upwards” into the diesel blendstock, gasoline and LPG range products. 
     While this specification is described in terms of cobalt and molybdenum oxides, the invention comprises a mixture of particulate metal oxides of Group 
     VIB metal oxides and Group VIII metal oxides. 
     In the preferred embodiment, the mixture of particulate metal oxides is pulverized particulate. In another embodiment, a conventional cracking catalyst is impregnated with the additive mixture. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The file of this patent contains at least one drawing executed in color. Copies of this patent with color drawing(s) will be provided by the Patent and Trademark Office upon request and payment of necessary fee. 
         FIG. 1  is a schematic diagram of an FCCU unit comprising a reactor and a riser showing the catalyst system of the present invention in place for the operating that FCCU unit. 
         FIG. 2  is a chart showing a significant improvement in dry gas conversion according to this invention. 
         FIG. 3  is a chart showing a significant improvement in C2 conversion according to this invention. 
         FIG. 4  is a chart showing a significant improvement in LPG conversion according to this invention. 
         FIG. 5  is a chart showing a significant improvement in C3 conversion according to this invention. 
         FIG. 6  is a chart showing a significant improvement in butane conversion according to this invention. 
         FIG. 7  is a chart showing a significant improvement in pentane conversion according to this invention. 
         FIG. 8  is a chart showing a significant improvement in transportation fuel selectivity according to this invention. 
         FIG. 9  is a chart showing a significant improvement in mercaptan reduction according to this invention. 
         FIG. 10  is a chart showing a significant improvement in LCN thiophene conversion according to this invention. 
         FIG. 11  is a chart showing a significant improvement in HCN thiophene conversion according to this invention. 
         FIG. 12  is a chart showing a significant improvement in HCN benzothiophene conversion according to this invention. 
         FIG. 13  is a chart showing a significant improvement in gasoline octane according to this invention. 
         FIG. 14  is a chart showing a significant reduction in H2S and shift in sulfur distribution according to this invention. 
         FIG. 15  is a chart showing a significant reduction in NOx according to this invention. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     The present additives are used as a component of the circulating inventory of catalyst in the catalytic cracking process referred to as an FCCU process. Briefly, the FCCU process in which the heavy hydrocarbon feed containing the organosulfur compounds will be cracked to lighter products takes place by contact of the feed in a cyclic catalyst recirculation cracking process with a circulating fluidizable catalytic cracking catalyst inventory. The significant steps in the cyclic process are: (i) the feed is catalytically cracked in a catalytic cracking zone, normally a riser cracking zone, operating at catalytic cracking conditions by contacting feed with a source of hot, regenerated cracking catalyst to produce an effluent comprising cracked products and spent catalyst containing coke and strippable hydrocarbons; (ii) the effluent is discharged and separated, normally in one or more cyclones, into a vapor phase rich in cracked product and a solids rich phase comprising the spent catalyst; (iii) the vapor phase is removed as product and fractionated in the FCC main column and may be associated side columns to form liquid cracking products including gasoline; (iv) the spent catalyst is stripped, usually with steam, to remove occluded hydrocarbons from the catalyst, after which the stripped catalyst is oxidatively regenerated to produce hot, regenerated catalyst which is then recycled to the cracking zone for cracking further quantities of feed. 
     Slurry oil can be combined and fed to a fluid catalytic cracking unit (FCCU) to crack the hydrocarbons contained therein to smaller chained hydrocarbons, especially gasoline boiling range and heating oil. Hydrotreating prior to cracking is considered beneficial in gasoline. The gasoline is improved and a considerable amount of the sulfur will be removed which reduces SO 2  emissions from FCCU itself. 
     The organic sulfur compounds are almost always considered to be contaminants. They hinder in downstream processing and at the very least make obnoxious SO2 gas when burned. For these reasons it is very desirable to remove these compounds. The degree of removal is dependent upon the use of the fraction. For instance, feed streams to catalytic reforming require extremely low sulfur concentrations. 
     The particulate additive of this invention is used in combination with an active catalytic cracking catalyst. Normally this is a faujasite such as zeolite Y and REY. Zeolite USY and REUSY also are known to process hydrocarbon feedstocks in the FCC unit to produce low-sulfur products. 
     The additive of this invention comprises a mixture of particulate metal oxides of Group VIB metal oxides and Group VIII metal oxides. The mixture of particulate metal oxides further comprises 5 to 30 wt. % of Group VIB metal oxides and 2 to 10 wt % of a Group VIII metal oxides. Preferably, the mixture of particulate metal oxides is pulverized particulate. Another embodiment of this invention further comprises the step of impregnating the cracking catalyst with the additive prior to catalytically cracking the petroleum feed fraction. 
     Preferably the Group VIB metal oxide is molybdenum oxide and the Group VIII metal oxide cobalt oxide. Preferably, the additive contains 5 to 20 wt. % of the Group VIB metal oxide and 2 to 5 wt. % of the Group VIII metal oxide. 
     Generally, the additive is present in an amount ranging from 1 to 25 weight percent of the weight of the cracking catalyst. Preferably, the additive is present in an amount ranging from 5 to 25 weight percent of the weight of the cracking catalyst. More preferably, the additive is present in an amount ranging from 10 to 25 weight percent of the weight of the cracking catalyst. 
     Generally, the additive has a particle size ranging from 1 nm to 900 nm. Preferably the additive has a particle sizing ranging from 50 nm to 800 nm. More preferably, the additive has a particle size ranging from 100 nm to 700 nm. 
       FIG. 1  is a schematic diagram of a typical FCC unit showing a regenerator, separator and stripper.  FIG. 1  shows an FCC unit, comprising standpipe  16  that transfers catalyst from regenerator  12  at a rate regulated by slide valve  10 . A fluidization medium from nozzle  8  transports catalyst upwardly through a lower portion of a riser  14  at a relatively high density until a plurality of feed injection nozzles  18  (only one is shown) inject feed across the flowing stream of catalyst particles. The resulting mixture continues upwardly through an upper portion of riser  14  to a riser termination device. This specific device utilizes at least two disengaging arms  20  tangentially discharge the mixture of gas and catalyst through openings  22  from a top of riser  14  into disengaging vessel  24  that effects separation of gases from the catalyst. Most of the catalyst discharged from openings  22  fall downwardly in the disengaging vessel  24  into bed  44 . Transport conduit  26  carries the separated hydrocarbon vapors with entrained catalyst to one or more cyclones  28  in reator or separator vessel  30 . Cyclones  28  separate spent catalyst from the hydrocarbon vapor stream. Collection chamber  31  gathers the separated hydrocarbon vapor streams from the cyclones for passage to outlet nozzle  32  and into a downstream fractionation zone (not shown). Diplegs  34  discharge catalyst from the cyclones  28  into bed  29  in a lower portion of disengaging vessel  30  which pass through ports  36  into bed  44  in disengaging vessel  24 . Catalyst and adsorbed or entrained hydrocarbons pass from disengaging vessel  24  into stripping section  38 . Catalyst from openings  22  separated in disengaging vessel  24  passes directly into stripping section  38 . Hence, entrances to the stripping section  38  include openings  22  and ports  36 . Stripping gas such as steam enters a lower portion of the stripping section  38  through distributor  40  and rises counter-current to a downward flow of catalyst through the stripping section  38 , thereby removing adsorbed and entrained hydrocarbons from the catalyst which flow upwardly through and are ultimately recovered with the steam by the cyclones  28 . Distributor  40  distributes the stripping gas around the circumference of stripping section  38 . In order to facilitate hydrocarbon removal, structured packing may be provided in stripping section  38 . The spent catalyst leaves stripping section  38  through port  48  to reactor conduit  46  and passes into regenerator  12 . The catalyst is regenerated in regenerator  12  as is known in the art and sent back to riser  14  through standpipe  16 . 
     In cracking carbo-metallic feedstocks in accordance with FCC processes, the regeneration gas may be any gas which can provide oxygen to convert carbon to carbon oxides. Air is highly suitable for this purpose in view of its ready availability. The amount of air required per pound of coke for combustion depends upon the desired carbon dioxide to carbon monoxide ratio in the effluent gases and upon the amount of other combustible materials present in the coke, such as hydrogen, sulfur, nitrogen and other elements capable of forming gaseous oxides at regenerator conditions. 
     The regenerator is operated at temperatures in the range of about 1000.degree to 1600.degree. F., preferably 1275.degree. to 1450.degree. F., to achieve adequate combustion while keeping catalyst temperature below those at which significant catalyst degradation can occur. In order to control these temperatures, it is necessary to control the rate of burning which in turn can be controlled at lest in part by the relative amounts of oxidizing gas and carbon introduced into the regeneration zone per unit time. 
     The catalyst of this invention, with or without the metal additive is charged to a FCCU unit of the type outlined in  FIG. 1  or to a Reduced Crude Conversion (RCC) unit. Catalyst particle circulation and operating parameters are brought up to process conditions by methods well-known to those skilled in the art. The equilibrium catalyst at a temperature of 1100.degree.-1500.degree. F. contacts the oil feed at riser wye  17 . The feed can contain steam, water, naphtha and/or flue gas and can be injected at point  8  or  18 . The catalyst and vaporous hydrocarbons travel up riser  14  at a contact time of 0.1-5 seconds, preferably 0.5-3 seconds. The catalyst and vaporous hydrocarbons are separated in riser termination device outlet  26  at a final reaction temperature of 900.degree.-1100.degree. F. The vaporous hydrocarbons are transferred to cyclones  28  where any entrained catalyst fines are separated and the hydrocarbon vapors are sent to a fractionator (not shown) via transfer line  32 . The coked catalyst then is transferred to stripper  38  for removal of entrained hydrocarbon vapors and then to regenerator vessel  12  to form a dense fluidized bed  13 . An oxygen containing gas such as air is admitted to the bottom of dense bed  13  in vessel  12  to combust the coke to carbon oxides. The resulting flue gas is processed through cyclones  11  and exits from the regenerator vessel  12  via line  23 . The regenerated catalyst is transferred to stripper  60  to remove any entrained combustion gases and then transferred to riser  14  via line  16  to repeat the cycle. 
     At such time that containment metals on the catalyst becomes intolerable high such that catalyst activity and selectivity declines, additional catalyst and additive can be added and deactivated catalyst withdrawn at addition-withdrawal point  9  into the dense bed  13  of regenerator  12  and/or or at addition-withdrawal point  7  into regenerated catalyst standpipe  16 . Addition-withdrawal points  7  and  9  can be utilized to add virgin catalysts containing one or more metal additives of the invention. 
     The additive generally contains 5 to 30 wt. % of a Group VIB metal, oxide and 2 to 10 wt. % of a Group VIII metal oxide and alumina. In the following Examples, the additive contained 5 to 20 wt. % of molybdenum and 2 to 5 wt. % of cobalt. 
     EXAMPLE 
     To demonstrate this invention, a ground Cobalt oxide-Moly oxide hydrotreating, catalyst was introduced to the laboratory FCC catalyst evaluation testing unit as an additive. The protocol used to evaluate this invention is identical to the protocol and conditions used to evaluate commercially available gasoline sulfur reducing catalysts. The additive was combined with a conventional zeolite catalyst. The following summarizes the test data and results at constant conversion weight percent and shows:
         1) A significant improvement in gasoline sulfur reduction.   2) A significant reduction in diesel blendstock component sulfur cont.   3) A significant reduction in thiophenic, benzothiophenic and de-benzothiophenic compounds.   4) A significant increase in propylene.   5) A significant increase in iso-butylenes.   6) A significant increase in total pentenes with a corresponding increase in amylenes and iso-amylenes.   7) A significant reduction in ethane, propane and butane.   8) A significant reduction of organic sulfur compounds in the Liquefied Petroleum Gas (LPG).   9) An increase in FCC gasoline (R+M)/2) octane.   10) A decrease in H2S.   11) A decrease in flue gas NOx.       

       FIG. 2  is a chart showing a significant improvement in dry gas conversion according to this invention. 
       FIG. 3  is a chart showing a significant improvement in C2 conversion according to this invention. 
       FIG. 4  is a chart showing a significant improvement in LPG conversion according to this invention. 
       FIG. 5  is a chart showing a significant improvement in C3 conversion according to this invention. 
       FIG. 6  is a chart showing a significant improvement in butane conversion according to this invention. 
       FIG. 7  is a chart showing a significant improvement in pentane conversion according to this invention. 
       FIG. 8  is a chart showing a significant improvement in transportation fuel selectivity according to this invention. 
       FIG. 9  is a chart showing a significant improvement in mercaptan reduction according to this invention. 
       FIG. 10  is a chart showing a significant improvement in LCN thiophene conversion according to this invention. 
       FIG. 11  is a chart showing a significant improvement in HCN thiophene conversion according to this invention. 
       FIG. 12  is a chart showing a significant improvement in HCN benzothiophene conversion according to this invention. 
       FIG. 13  is a chart showing a significant improvement in octane according to this invention. 
       FIG. 14  is a chart showing a significant reduction in H2S and shift in sulfur distribution according to this invention. 
       FIG. 15  is a chart showing a significant reduction in NOx according to this invention. 
     In the above protocols, the additive is typically used in an amount from about 0.1 to about 10 weight percent of the inventory in the FCCU. Preferably, the amount will be from about 0.5 to about 5 weight percent. About 2 weight percent represents a norm for most practical purposes. The additive may be added in the conventional manner, with make-up to the regenerator or by any other convenient method. The additive remains active for sulfur removal for extended periods of time although very high sulfur feeds may result in loss of sulfur removal activity in shorter times. 
     The effect of the present additives is to reduce the sulfur content of liquid cracking products, especially the light and heavy gasoline fractions, although reductions are also noted in the light cycle oil, making them more suitable for use as a diesel or home heating oil blend component. The significant reduction in H2S will also have a benefit on downstream processing units where H2S is removed via caustic and amine treatment. The lower H2S load on these units will improve unit efficiency and debottleneck capacity. The sulfur removed in the FCC is absorbed as a metal sulfide and released as Sox in the regenerator. 
     The ability of the additives of the invention to convert NO x  in a FCCU regenerator operated in a partial or complete burn mode also may be determined. The key performance measurement in this test is the NO x  conversion. It is desirable to have high NO x  conversion for a wide range of O 2  and CO amounts. The activity of the compositions for converting NO x  to nitrogen under various O 2  levels, in the reducing/oxidizing conditions possible in a regenerator operating in partial or complete burn are possible due to the oxygen storage capability of the additive. No other nitrogen oxides like N 2 O or NO 2  were detected. 
     MODIFICATIONS 
     Specific compositions, methods, or embodiments discussed are intended to be only illustrative of the invention disclosed by this specification. Variation on these compositions, methods, or embodiments are readily apparent to a person of skill in the art based upon the teachings of this specification and are therefore intended to be included as part of the inventions disclosed herein. 
     The above detailed description of the present invention is given for explanatory purposes. It will be apparent to those skilled in the art that numerous changes and modifications can be made without departing from the scope of the invention. Accordingly, the whole of the foregoing description is to be construed in an illustrative and not a limitative sense, the scope of the invention being defined solely by the appended claims.