Catalytic cracking with reduced emission of noxious gas

Emissions of sulfur oxides from the regenerator of a fluidized catalytic cracking unit are reduced by selectively removing a portion of the sulfur from sulfur-containing coke deposits on deactivated cracking catalyst. This is accomplished by reaction of these deposits with limited amounts of molecular oxygen in a stripping zone at a temperature in the range from about 550.degree. to about 700.degree. C. Effluent gas from the striping zone is combined with the cracked hydrocarbon products.

BACKGROUND OF THE INVENTION 
1. Field of the Invention 
This invention relates to a process for reducing the emissions of sulfur 
oxides from the regenerator of a catalytic cracking unit. More 
particularly, the invention relates to a selective removal of a portion of 
the sulfur from sulfur-containing coke deposits on deactivated cracking 
catalyst by reaction of these deposits with limited amounts of molecular 
oxygen in a stripping zone. 
2. Description of the Prior Art 
A major industrial problem involves the development of efficient methods 
for reducing the concentration of air pollutants, such as sulfur oxides, 
in waste gas streams which result from the processing and combustion of 
carbonaceous fuels which contain sulfur. The discharge of these waste gas 
streams into the atmosphere is environmentally undesirable at the sulfur 
oxide concentrations which are frequently encountered in conventional 
operations. The regeneration of cracking catalyst which has been 
deactivated by coke deposits in the catalytic cracking of 
sulfur-containing hydrocarbon feedstocks is a typical example of a process 
which can result in a waste gas stream containing relatively high levels 
of sulfur oxides. 
Catalytic cracking of heavy petroleum fractions is one of the major 
refining operations employed in the conversion of crude petroleum oils to 
useful products such as the fuels utilized by internal combustion engines. 
In fluidized catalytic cracking processes, high molecular weight 
hydrocarbon liquids and vapors are contacted with hot, finely-divided, 
solid catalyst particles either in a fluidized bed reactor or in an 
elongated transfer line reactor, and maintained at an elevated temperature 
in a fluidized or dispersed state for a period of time sufficient to 
effect the desired degree of cracking to lower molecular weight 
hydrocarbons of the kind typically present in motor gasoline and 
distillate fuels. 
In the catalytic cracking of hydrocarbons, some nonvolatile carbonaceous 
material or coke is deposited on the catalyst particles. Coke comprises 
highly condensed aromatic hydrocarbons and generally contains from about 4 
to about 10 percent hydrogen. When the hydrocarbon feedstock contains 
organic sulfur compounds, the coke also contains sulfur. As coke 
accumulates on the cracking catalyst, the activity of the catalyst for 
cracking and the selectivity of the catalyst for producing gasoline 
blending stocks diminishes. 
Catalyst which has become substantially deactivated through the deposit of 
coke is continuously withdrawn from the reaction zone. The catalyst 
particles are then reactivated to essentially their original capabilities 
by burning the coke deposits from the catalyst surfaces with an 
oxygen-containing gas such as air in a regeneration zone. Regenerated 
catalyst is continuously returned to the reaction zone to repeat the 
cycle. 
When sulfur-containing feedstocks, such as petroleum hydrocarbons 
containing organic sulfur compounds, are utilized in a catalytic cracking 
process, the coke deposited on the catalyst contains sulfur. During 
regeneration of the coked deactivated catalyst, the coke is burned from 
the catalyst surfaces which results in the conversion of the sulfur to 
sulfur dioxide together with small amounts of sulfur trioxide. This 
burning can be represented, in a simplified manner, as the oxidation of 
sulfur according to the following equations: 
EQU S (in coke)+O.sub.2 .fwdarw.SO.sub.2 ( 1) 
EQU 2SO.sub.2 +O.sub.2 .fwdarw.2SO.sub.3 ( 2) 
One approach to the removal of sulfur oxides from the waste gas produced 
during the regeneration of deactivated cracking catalyst involves 
scrubbing the gas downstream of the regenerator vessel with an inexpensive 
alkaline material, such as lime or limestone, which reacts chemically with 
the sulfur oxides to give a nonvolatile product which is discarded. 
Unfortunately, this approach requires a large and continual supply of 
alkaline scrubbing material, and the resulting reaction products can 
create a solid waste disposal problem of substantial magnitude. In 
addition, this approach requires complex and expensive auxiliary 
equipment. 
A second approach to the control of sulfur oxide emissions involves the use 
of sulfur oxide absorbents which can be regenerated either thermally or 
chemically. An example of this approach to the removal of sulfur oxides 
from the regeneration zone effluent gas stream in a cyclic, fluidized, 
catalytic cracking process is set forth in U.S. Pat. No. 3,835,031 to 
Bertolacini et al. This patent discloses the use of a zeolite-type 
cracking catalyst which is modified by impregnation with one or more metal 
compounds of Group IIA of the Periodic Table, followed by calcination, to 
provide from about 0.25 to about 5.0 weight percent of Group IIA metal or 
metals as an oxide or oxides. The metal oxide or oxides react with sulfur 
oxides in the regeneration zone to form nonvolatile inorganic sulfur 
compounds. These nonvolatile inorganic sulfur compounds are then converted 
to the metal oxide or oxides and hydrogen sulfide upon exposure to 
hydrocarbons and steam in the reaction and steam stripping zones of the 
process unit. The resulting hydrogen sulfide is disposed of in equipment 
which is conventionally associated with a fluidized catalytic cracking 
process unit. Belgian Pat. No. 849,637 is also directed to a process 
wherein a Group IIA metal or metals are circulated through a cyclic 
fluidized catalytic cracking process with the cracking catalyst in order 
to reduce the sulfur oxide emissions resulting from regeneration of 
deactivated catalyst. 
U.S. Pat. No. 4,153,534 to Vasalos discloses a process similar to that set 
forth in U.S. Pat. No. 3,835,031, which involves the removal of sulfur 
oxides from the regeneration zone flue gas of a cyclic, fluidized, 
catalytic cracking unit through the use of a zeolite-type cracking 
catalyst in combination with a regenerable sulfur oxide absorbent which 
absorbs sulfur oxides in the regeneration zone and releases the absorbed 
sulfur oxides as a sulfur-containing gas in the reaction and steam 
stripping zones of the process unit. The sulfur oxide absorbent comprises 
at least one free or combined element selected from the group consisting 
of sodium, scandium, titanium, chromium, molybdenum, manganese, cobalt, 
nickel, antimony, copper, zinc, cadmium, the rare earth metals and lead. 
U.S. patent application Ser. No. 91,469 by McHenry (now U.S. Pat. No. 
4,276,150) discloses a third approach to the reduction of sulfur oxide 
emissions from the regeneration of deactivated cracking catalyst. This 
application is directed to a process for the fluidized catalytic cracking 
of a sulfur-containing heavy feedstock which contains at least a 
substantial fraction which cannot be vaporized at atmospheric pressure 
without extensive decomposition such as residuum and whole crude. These 
low quality feedstocks result in the formation of large quantities of 
sulfur-containing coke during catalytic cracking which, ordinarily, are 
substantially in excess of the amount of coke which must be burned in a 
conventional regeneration zone to provide process heat. McHenry discloses 
that the coke which is in excess of that required for process heat balance 
requirements can be removed and converted to a valuable product by 
gasification prior to subjecting the catalyst to conventional 
regeneration. The sulfur-containing coke deposits are gasified with oxygen 
and steam at a temperature of from about 593.degree. to about 1204.degree. 
C. in a stripper-gasifier to produce a low BTU gas stream comprising 
hydrogen sulfide, methane, carbon monoxide, hydrogen and carbon dioxide. 
The resulting low BTU gas is processed separately from the catalytic 
cracking products and can be passed to an amine absorption unit of 
conventional design for removal of hydrogen sulfide and traces of sulfur 
dioxide. 
The process which is described by the McHenry application, however, fails 
to either teach or suggest that the sulfur content of the coke deposits on 
deactivated cracking catalyst can be selectively removed by reaction with 
small amounts of molecular oxygen. The McHenry application also fails to 
suggest the possibility or desirability of contacting the 
sulfur-containing coke deposits on deactivated catalyst with small amounts 
of oxygen in a stripping zone and combining the resulting stripping zone 
effluent with cracked hydrocarbon products from the reaction zone for 
processing in a common product recovery zone. Further, the McHenry 
application fails to suggest the desirability of gasifying any portion of 
the coke deposits except when coke production is in excess of that 
required for heat balance requirements in the cracking process. 
Canadian Pat. No. 875,528 discloses a method for regenerating a cracking 
catalyst which involves reacting the coke deposits on deactivated catalyst 
with a regeneration gas which consists of oxygen and at least one member 
selected from the group consisting of steam and carbon dioxide at a 
temperature in the range of about 566.degree. to 816.degree. C. to form an 
effluent containing carbon monoxide. This effluent is then passed to a 
reaction zone wherein the carbon monoxide is combined with steam in a 
water gas shift reaction to produce hydrogen and carbon dioxide. It is 
further disclosed that the resulting product gases can be treated by 
conventional techniques to remove carbon dioxide and hydrogen sulfide. The 
Canadian Patent, however, requires a complete gasification of the coke 
deposits and also fails to teach or suggest that the sulfur content of the 
coke deposits on deactivated catalyst can be selectively removed by 
reaction with small amounts of molecular oxygen. Further, the Canadian 
Patent contains no suggestion that the gasification products could be 
combined with cracked hydrocarbon products for processing in a common 
product recovery zone. 
U.S. Pat. No. 2,398,739 to Greensfelder et al. discloses a multi-staged 
fluidized process for the regeneration of deactivated cracking catalyst 
with an oxygen-containing gas. This patent teaches the partial 
regeneration of spent cracking catalyst in a low temperature regenerator 
at a temperature between about 538.degree. and 593.degree. C. Partially 
regenerated catalyst is then passed to a high temperature regenerator 
wherein regeneration is completed at a temperature of about 677.degree. C. 
Similarly, published U.K. Patent Application No. 2,001,545 discloses a 
two-stage regeneration process wherein there is no major evolution of heat 
from either regeneration stage. These two references, however, contain no 
teaching or suggestion that the sulfur content of the coke deposits on 
deactivated cracking catalyst can be selectively removed by reaction with 
small amounts of oxygen. Indeed, these references contain no mention of 
sulfur or sulfur oxides in any context. In addition, they fail to suggest 
the possibility or desirability of contacting coke deposits on deactivated 
catalyst with small amounts of oxygen in a stripping zone and combining 
the resulting stripping zone effluent with cracked hydrocarbon products 
from the reaction zone for processing in a common product recovery zone. 
SUMMARY OF THE INVENTION 
This invention is directed to a process for the fluidized catalytic 
cracking of a hydrocarbon feedstock containing organic sulfur compounds 
which comprises: (a) cracking said feedstock in a reaction zone through 
contact with a particulate cracking catalyst; (b) separating cracking 
products from cracking catalyst which is deactivated by sulfur-containing 
coke deposits and passing said deactivated cracking catalyst to a 
stripping zone; (c) contacting the deactivated cracking catalyst with an 
oxygen-containing gas in said stripping zone at a temperature in the range 
from about 550.degree. to about 700.degree. C. and reacting the oxygen 
with said sulfur-containing coke deposits to form products which include 
sulfur-containing gases, wherein the amount of oxygen introduced into said 
stripping zone is effective to remove at least about 10 weight percent of 
the sulfur content and less than about 30 weight percent of the carbon 
content of said sulfur-containing coke deposits, and wherein said weight 
percent of the sulfur content removed is greater than said weight percent 
of the carbon content removed; (d) withdrawing an effluent gas from the 
stripping zone and combining said stripping zone effluent gas with said 
cracking products; (e) withdrawing from the stripping zone cracking 
catalyst which is deactivated by modified coke deposits having a reduced 
sulfur content and passing said catalyst from the stripping zone to a 
regeneration zone; (f) removing said modified coke deposits from the 
deactivated cracking catalyst in said regeneration zone by burning with an 
oxygen-containing regeneration gas, thereby heating and regenerating the 
cracking catalyst; and (g) withdrawing regenerated catalyst from the 
regeneration zone and passing said regenerated catalyst to the reaction 
zone. 
It has been discovered that the sulfur content of coke deposits on 
deactivated cracking catalyst can be selectively removed by reaction of 
these deposits with limited amounts of molecular oxygen. Accordingly, it 
is an object of this invention to provide a process for the selective 
removal of sulfur from coke deposits on deactivated cracking catalyst. 
Another object of this invention is to provide an improved method for 
reducing sulfur oxide emissions from the regenerator of a fluidized 
catalytic cracking unit. 
Other objects, aspects and advantages of the invention will be readily 
apparent from the following detailed description and claims.

DETAILED DESCRIPTION OF THE INVENTION 
It has been discovered that emissions of sulfur oxides from the 
regeneration zone of a fluidized catalytic cracking unit can be reduced by 
contacting deactivated cracking catalyst with small amounts of molecular 
oxygen in a stripping zone. The sulfur-containing coke deposits on 
deactivated cracking catalyst undergo a partial gasification in the 
stripping zone upon contact with the oxygen, and this results in a 
preferential removal of the hydrogen and sulfur content of the coke. The 
resulting catalyst which is discharged from the stripping zone carries a 
modified coke deposit which has a reduced sulfur content. As a 
consequence, the combustion of this modified coke in the regeneration zone 
affords a reduced amount of sulfur oxides. 
The sulfur-containing effluent gas from the stripping zone, which comprises 
hydrogen sulfide, is combined with the hydrocarbon cracking products from 
the reaction zone. This combination is then processed in the conventional 
product recovery facilities which are associated with the catalytic 
cracking unit. Although the invention disclosed herein is not to be so 
limited, the catalytic cracking products are typically separated in a 
fractionator and the low molecular weight products are passed from the 
fractionator to a vapor recovery unit wherein hydrogen sulfide is removed 
by scrubbing in one or more amine absorption towers. The most commonly 
used amines for hydrogen sulfide removal are monoethanolamine and 
diethanolamine. The hydrogen sulfide is subsequently removed from the 
amine scrubbing solution and can be converted to elemental sulfur, for 
example, by means of the Claus process. 
In the practice of this invention, molecular oxygen is introduced into the 
stripping zone in an amount which is effective to remove at least about 10 
weight percent, preferably at least about 20 weight percent, and more 
preferably at least about 30 weight percent of the sulfur content and less 
than about 30 weight percent of the carbon content of the 
sulfur-containing coke deposits on the deactivated catalyst. Although the 
chemical composition of the coke deposits can vary significantly, this 
will generally correspond to less than about 23 percent of the 
stoichiometric amount of oxygen required to completely convert the coke to 
carbon dioxide, steam and sulfur dioxide. It will be understood, of 
course, that said weight percent of the sulfur content removed is greater 
than said weight percent of the carbon content removed. During the 
practice of this invention, it is frequently possible to remove more than 
about 40 weight percent of the sulfur content of the coke deposits in the 
stripping zone while simultaneously removing less than about 10 weight 
percent of the carbon content. In a preferred embodiment of the invention, 
molecular oxygen is introduced into the stripping zone in an amount which 
is effective to remove at least about 10 weight percent of the sulfur 
content and less than about 10 weight percent of the carbon content of the 
sulfur-containing coke deposits on the deactivated catalyst. In this 
preferred embodiment, the amount of oxygen employed will generally 
correspond to less than about 8 percent of the stoichiometric amount 
required to completely convert the coke to carbon dioxide, steam and 
sulfur dioxide. 
Although the invention which is disclosed herein is not to be so limited, 
it is believed that the small amounts of oxygen which are introduced into 
the stripping zone serve to preferentially convert the hydrogen and sulfur 
content of the coke deposits to steam and sulfur dioxide respectively. In 
addition, a small portion of the carbon content of the coke deposits is 
converted to a mixture of carbon monoxide and carbon dioxide. The carbon 
monoxide then undergoes a water-gas shift reaction with steam to produce 
hydrogen according to equation (3), and the resulting hydrogen converts 
the sulfur dioxide to hydrogen sulfide according to equation (4). 
EQU CO+H.sub.2 O.fwdarw.CO.sub.2 +H.sub.2 (3) 
EQU SO.sub.2 +3H.sub.2 .fwdarw.H.sub.2 S+2H.sub.2 O (4) 
Finally, any residual sulfur dioxide in the stripping zone effluent 
undergoes conversion to hydrogen sulfide upon contact with the cracked 
hydrocarbon products from the reaction zone which include molecular 
hydrogen. 
Although not essential, the coked catalyst is preferably contacted with 
oxygen in a countercurrent manner within the stripping zone. In this 
preferred embodiment, molecular oxygen is introduced near the bottom of 
the stripping zone and is passed upwardly through the deactivated catalyst 
particles which are passed downwardly through the stripping zone. As a 
consequence of this countercurrent contacting, the reaction of coke with 
oxygen takes place primarily near the bottom of the stripping zone, and 
the resulting gasification products strip any residual volatile material 
and entrained hydrocarbon vapors from the spent catalyst as it enters and 
begins its downward passage through the stripping zone. In this 
embodiment, it is believed that the sulfur dioxide initially produced by 
reaction of the coke with oxygen is substantially converted to hydrogen 
sulfide during upward passage through the stripping zone. 
The molecular oxygen which is introduced into the stripping zone can 
contain one or more diluent gases such as nitrogen, steam, carbon dioxide 
and the like. Since air is conveniently employed as a source of molecular 
oxygen, a major portion of the diluent gas can be nitrogen. However, a 
preferred embodiment of the invention involves the use of substantially 
undiluted molecular oxygen. The use of substantially undiluted or pure 
oxygen is advantageous in that the reaction of oxygen with coke in the 
stripping zone will be faster in the absence of a diluent. In addition, 
the presence of significant amounts of a diluent gas, such as nitrogen, 
will place an undesirable loading on the downstream product recovery 
system since the stripping zone effluent gas is combined with the cracking 
products before passing to this system. Although the invention is not to 
be so limited, catalytic cracking products are conventionally separated in 
a fractionator and the low molecular weight products or wet gas is passed 
from the fractionator to a vapor recovery unit for further separation. As 
a first step in a conventional vapor recovery unit, the wet gas is usually 
compressed. Consequently, the presence of a diluent in the oxygen which is 
delivered to the stripping zone will serve to increase the wet gas volume 
and cause an unnecessary and usually undesirable increase in the loading 
on the wet gas compressor. 
In another embodiment of the invention, both steam and oxygen are 
introduced into the stripping zone. The steam can be introduced into the 
stripping zone separately from the oxygen or can be mixed with the oxygen 
as a diluent. In this embodiment, the mole ratio of steam to oxygen is 
desirably in the range from about 0.1/1 to about 5/1. The introduction of 
both steam and oxygen into the stripping zone is advantageous since the 
steam serves to promote the formation of molecular hydrogen by way of the 
water-gas shift reaction which is set forth as equation (3) above. In 
addition, the steam can also react with carbon in the coke on deactivated 
catalyst to form molecular hydrogen according to equation (5). 
EQU C (in coke)+H.sub.2 O.fwdarw.CO+H.sub.2 (5) 
The formation of this molecular hydrogen is desirable since it serves to 
promote the conversion of sulfur dioxide to hydrogen sulfide according to 
equation (4). It will be appreciated, of course, that the conversion of 
the sulfur dioxide produced in the stripping zone to hydrogen sulfide is 
desirable since sulfur dioxide irreversibly degrades the amines, such as 
monoethanolamine and diethanolamine, which are conventionally used to 
scrub hydrogen sulfide from the catalytic cracking products. 
In another embodiment of the invention, carbon monoxide is introduced into 
the stripping zone in addition to the molecular oxygen. The carbon 
monoxide can be mixed with one or more diluent gases such as nitrogen, 
steam, carbon dioxide and the like. Preferably, the carbon monoxide is 
introduced into the stripping zone separately from the molecular oxygen. 
it will be appreciated, of course, that explosive mixtures of carbon 
monoxide and oxygen are not employed in the stripping zone. The 
introduction of carbon monoxide serves to promote the formation of 
hydrogen by way of the water-gas shift reaction which is set forth in 
equation (3) and this, in turn, promotes the conversion of sulfur dioxide 
to hydrogen sulfide according to equation (4). Since many conventional 
techniques for the regeneration of cracking catalyst result in a 
regeneration zone effluent gas which contains up to about 7 or 8 mole 
percent carbon monoxide, such an effluent gas can serve as a convenient 
source of carbon monoxide. 
The stripping zone is maintained at a temperature in the range from about 
550.degree. to about 700.degree. C. Further, the stripping zone is also 
maintained at a higher temperature, desirably at least about 30.degree. C. 
higher, than that in the reaction zone. In a preferred embodiment of the 
invention, a suitable temperature in the stripping zone is maintained and 
precisely controlled by mixing a stream of hot regenerated cracking 
catalyst with the deactivated cracking catalyst in the stripping zone. The 
recycle ratio in the stripping zone of hot regenerated cracking catalyst 
to deactivated cracking catalyst is desirably within the range from about 
0.05 to about 1.0. Deactivated catalyst passes from the reaction zone to 
the stripping zone at a temperature which is typically in the range from 
about 450.degree. to about 540.degree. C. Such a temperature, however, is 
usually not adequate to promote a sufficiently rapid reaction in the 
stripping zone between the coke deposits and the limited amounts of oxygen 
which are employed in the practice of this invention. In addition, the 
exothermic reaction of coke deposits in the stripping zone with the 
limited amount of oxygen which is employed in the practice of this 
invention is usually insufficient to maintain a satisfactory stripping 
zone temperature without the input of additional heat. The recycle of hot 
regenerated catalyst from the regeneration zone to the stripping zone 
serves to provide an easily controlled and efficient input of additional 
heat to maintain the stripping zone at a suitable temperature. 
In another embodiment of the invention, a suitable temperature in the 
stripping zone is maintained and controlled by passing hot effluent gas 
from the regeneration zone into the stripping zone in a quantity which is 
effective for this purpose. The hot regeneration zone effluent gas which 
is passed into the stripping zone according to this embodiment will 
typically contain steam, carbon dioxide, nitrogen, small amounts of 
oxygen, and may or may not contain significant amounts of carbon monoxide 
depending on the precise process conditions employed within the 
regeneration zone. In effect, this embodiment involves the maintenance of 
a satisfactory stripping zone temperature by mixing the stripping zone 
oxygen with a hot diluent gas. It will be appreciated, of course, that the 
molecular oxygen which is used in the stripping zone can be introduced 
into the stripping zone separately from the hot regeneration zone effluent 
gas or the two can be mixed prior to their introduction into the stripping 
zone. This embodiment is not usually preferred, however, since the hot 
regeneration zone gas passed into the stripping zone serves to increase 
the volume of the stripping zone effluent and, consequently, places an 
increased and usually undesirable loading on the downstream product 
recovery system since the stripping zone effluent gas is combined with the 
cracking products before passing to this system. 
In a further embodiment of the invention, a suitable temperature in the 
stripping zone is maintained and controlled by passing both a stream of 
hot regenerated catalyst and a stream of hot effluent gas from the 
regeneration zone into the stripping zone in amounts which are effective 
for this purpose. 
In the practice of this invention, the stripping zone effluent gas is 
combined with the hydrocarbon cracking products from the reaction zone. 
This is highly advantageous since the product recovery system which is 
conventionally associated with a fluidized catalytic cracking unit can 
also be utilized to process the stripping zone effluent gas and remove the 
hydrogen sulfide which will be present. As a consequence, it is 
unnecessary to construct and operate a separate gas processing system to 
remove hydrogen sulfide from the stripping zone effluent gas and otherwise 
handle this gas stream. In addition, the catalytic cracking of a 
hydrocarbon feedstock results in the formation of significant amounts of 
hydrogen. Typically, hydrogen represents about 0.05 weight percent of the 
product from the catalytic cracking of a gas oil. Upon combination of the 
stripping zone effluent gas with the hydrocarbon cracking products, this 
hydrogen serves to effect a substantially complete conversion of any 
sulfur dioxide in the stripping zone effluent gas to hydrogen sulfide. 
This is important, of course, since sulfur dioxide irreversibly degrades 
the amines, such a monoethanolamine and diethanolamine, which are 
conventionally used to scrub hydrogen sulfide from a gas stream. 
Since the water-gas shift reaction, equation (3), can be promoted 
catalytically, a preferred embodiment of the invention involves 
circulating such a catalytic material through the catalytic cracking 
process cycle. The water-gas shift catalyst can be incorporated into the 
particles of cracking catalyst. Alternatively, the particles of cracking 
catalyst can be physically mixed with a separate fluidizable particulate 
solid which comprises the shift catalyst. The precise nature of the shift 
catalyst is not critical, and the amount of shift catalyst, calculated as 
the component metal or metals, is desirably from about 0.01 to about 10 
weight percent and preferably from about 0.05 to about 5 weight percent 
with respect to the cracking catalyst and any admixed solids including the 
shift catalyst. Suitable water-gas shift catalysts include, but are not 
limited to, Fe.sub.2 O.sub.3, Cr.sub.2 O.sub.3, MgO, NiO, CuO, Cu.sub.2 O, 
Na.sub.2 CO.sub.3, K.sub.2 CO.sub.3, Li.sub.2 CO.sub.3, Cs.sub.2 CO.sub.3 
and mixtures thereof. Iron oxide-chromium oxide catalysts are 
conventionally used in promoting the water-gas shift reaction, equation 
(3), and can advantageously be used in the practice of the present 
invention. These conventional iron oxide-chromium oxide catalysts 
generally contain a major amount of iron oxide, for example about 95 
weight percent, and a minor amount of chromium oxide, for example about 5 
weight percent. A shift catalyst comprising magnesium oxide can be 
advantageously employed if the stripping zone is operated at a relatively 
low temperature. The MgO absorbs carbon dioxide in the stripping zone and, 
as a consequence, the shift reaction can go to completion. The resulting 
MgCO.sub.3 then decomposes back to MgO with the release of carbon dioxide 
upon circulation to the regeneration zone, which is maintained at a higher 
temperature than the stripping zone. 
In those embodiments of the invention wherein a water-gas shift catalyst is 
employed, the shift catalyst is desirably incorporated into or deposited 
onto a support since this permits a more efficient contacting of the 
catalytic material with the gases in the stripping zone and also provides 
control over the attrition properties of the shift catalyst through proper 
selection of the support. It will be appreciated that the particles which 
contain the water-gas shift catalyst should be sufficiently strong that 
they are not subject to excessive attrition and degradation during 
fluidization. The average size of the particles will be desirably in the 
range from about 20 microns or less to about 150 microns, and preferably 
less than about 50 microns. Suitable supports include, but are not limited 
to, amorphous cracking catalysts, zeolite-type cracking catalysts, silica, 
alumina, mixtures of silica and alumina, natural and treated clays, 
kieselguhr, diatomaceous earth, kaolin and mullite. Desirably, the support 
is porous and has a surface area, including the area of the pores open to 
the surface, of at least about 10, preferably at least about 50, and most 
preferably at least about 100 square meters per gram. 
The metal or metals of the water-gas shift catalyst can be combined with a 
support either during or after preparation of the support. One method 
consists of impregnating a suitable support with an aqueous or organic 
solution or dispersion of a suitable compound or compounds of the metal or 
metals of the shift catalyst. Suitable compounds for use in impregnating 
the support include but are not limited to oxides, acetates, nitrates, 
hydroxides, bicarbonates and carbonates. The impregnation can be carried 
out in any manner which will not destroy the structure of the support. 
After drying, the composite can be calcined, if desired. Alternatively, a 
suitable compound or compounds of the metal of metals of the shift 
catalyst, for example an oxide or hydroxide of said metal or metals, can 
be combined with a support precursor such as silica gel, silica-alumina 
gel, or alumina gel prior to spray drying or other physical formation 
process. Subsequent drying and, if desired, calcination then affords the 
supported shift catalyst. 
Although the metal or metals of the water-gas shift catalyst can be 
combined with a support before introduction into the catalytic cracking 
process cycle, it is also advantageous to introduce a suitable compound or 
compounds of the metal or metals into the cracking process cycle and 
thereby achieve an in situ incorporation onto a support which comprises 
cracking catalyst. Such compound or compounds can be introduced in 
solution or dispersion form and in solid, liquid or gaseous state at any 
stage of the cracking process cycle so that wide distribution in the 
circulating catalyst is achieved. For example, such compound or compounds 
can be admixed either with the feedstock or fluidizing gas in the reaction 
zone; with the regeneration gas, torch oil or spray water in the 
regeneration zone; or can be introduced as a separate stream. If the 
compound or compounds are to be introduced as a separate stream, this can 
be accomplished by introducing the compound or compounds in the form of a 
solution or dispersion in either water or an organic liquid. Suitable 
organic liquids include but are not limited to alcohols of from 1 to 5 
carbon atoms, benzene, toluene, xylene, ethyl acetate and tetrahydrofuran. 
Suitable compounds for in situ incorporation include but are not limited 
to oxides, acetates, nitrates, hydroxides, bicarbonates and carbonates. 
FIG. 1 of the drawings is illustrative of one embodiment of the invention 
involving the introduction of both oxygen and steam into the stripping 
zone. A hydrocarbon feedstock which contains organic sulfur compounds is 
passed through line 1 and is contacted with hot regenerated catalyst from 
line 2 in the inlet portion of transfer line reactor 3. The resulting 
mixture of catalyst and hydrocarbon vapor passes upward through transfer 
line reactor 3. The feedstock undergoes catalytic cracking during passage 
through transfer line reactor 3, and the resulting mixture of catalyst and 
hydrocarbons is discharged into reactor vessel 4 through downward directed 
discharge head 5. The upper surface 6 of the dense phase of catalyst 
particles within vessel 4 is generally maintained below discharge head 5, 
thereby allowing hydrocarbon vapors to disengage from the catalyst 
particles without substantial contact with the dense phase. However, if 
desired, the location of catalyst phase interface 6 may be varied from a 
position below discharge head 5 to a position from discharge head 5. In 
the latter case, increased catalytic conversion of the feedstock will 
occur as a consequence of additional cracking taking place within the 
dense phase of catalyst in reactor vessel 4. 
Vapors and entrained catalyst particles passing upward through reactor 
vessel 4 enter primary cyclone separator 7. Most of the entrained catalyst 
particles are separated in the first stage cyclone 7 and are discharged 
downwardly through dip-leg 8 and into the dense phase bed of catalyst 
within reactor vessel 4. Vapors and remaining catalyst particles are 
passed through interstage cyclone line 9 to second stage cyclone separator 
10 where substantially all of the remaining catalyst is separated and 
passed downwardly through dip-leg 11 and into the dense phase bed of 
catalyst within reactor vessel 4. 
Effluent vapors pass from cyclone 10, through line 12, into plenum chamber 
13, and are discharged through line 14. Line 14 conveys the effluent 
vapors to a product recovery zone, not shown, wherein the vapors are 
separated into product fractions by methods which are well known in the 
art. 
Deactivated catalyst particles from the dense phase bed in the lower 
portion of reactor vessel 4, which carry sulfur-containing coke deposits, 
pass downwardly into stripping zone 15. Baffles 16 are situated in 
stripping zone 15, and a mixture of air and steam from line 17 is 
discharged through distribution ring 18 into the lower portion of 
stripping zone 15. The amount of oxygen discharged into stripping zone 15 
in the form of air is about 15 percent of the stoichiometric amount 
required to completely convert the coke deposits to carbon dioxide, steam 
and sulfur dioxide. The air and steam react with the sulfur-containing 
coke deposits in stripping zone 15 and the resulting upward flowing 
gasification products strip volatile material and entrained hydrocarbon 
vapors from the deactivated catalyst as it enters and begins its downward 
passage through stripping zone 15. The upward flowing gases serve to 
fluidize the catalyst particles in stripping zone 15 and in the dense 
phase bed within reactor vessel 4. 
Catalyst particles carrying modified coke deposits which have a reduced 
sulfur content are withdrawn from the bottom of stripping zone 15 through 
spent catalyst standpipe 19 at a rate controlled by valve 20, and 
discharge through line 21 into spent catalyst transfer line 22. 
Deactivated catalyst from line 21 is fluidized with air from line 23 and 
passes upwardly through transfer line 22 and into regulator vessel 24. 
Transfer line 22 terminates in a downwardly directed discharge head 25, 
and effluent from transfer line 22 is discharged below the surface 26 of 
the dense phase of fluidized catalyst particles in the regenerator vessel 
24. Catalyst within the regenerator vessel 24 is fluidized by combustion 
air from line 27 which is discharged through air ring 28, whereupon the 
coke deposits on the catalyst are burned and the catalytic activity of the 
deactivated catalyst is restored. Combustion gases continuously pass 
upwardly from the dense catalyst phase into the dilute phase above the 
catalyst interface 26. These combustion gases, together with entrained 
catalyst particles, enter primary cyclone separator 29. Most of the 
entrained catalyst particles are separated in the first stage cyclone 29 
and are discharged downwardly through dip-leg 30 and into the dense 
catalyst phase within regenerator vessel 24. Combustion gases and 
remaining catalyst particles are passed through interstage cyclone line 31 
to second stage cyclone separator 32 where substantially all of the 
remaining catalyst is separated and passed downwardly through dip-leg 33 
and into the dense catalyst phase within regenerator vessel 24. Effluent 
gases from cyclone separator 32 pass through line 34, into plenum 35, and 
are discharged through line 26. Effluent combustion gases from line 36 can 
be discharged directly to the atmosphere or, alternatively, can be passed 
through conventional particulate control equipment and conventional heat 
exchange means prior to such discharge into the atmosphere. If desired, 
the effluent gases can also be passed through an expander turbine prior to 
discharge into the atmosphere. 
Regenerated catalyst having a low content of residual coke is withdrawn 
from the bottom of regenerator vessel 24 through standpipe 37 at a rate 
controlled by valve 38 to supply hot regenerated catalyst to line 2 which 
is described above. A recycle stream of hot regenerated catalyst is also 
withdrawn from regenerator vessel 24 through line 39 at a rate controlled 
by valve 40 and discharges through line 41 into stripping zone 15. The 
recycle stream of regenerated catalyst is passed into stripping zone 15 
from line 41 at a rate sufficient to maintain the temperature in stripping 
zone 15 within the range from about 550.degree. to about 700.degree. C. 
and to provide a recycle ratio of hot regenerated catalyst to deactivated 
catalyst within the range from about 0.05 to about 1.0. 
Conversion of a selected hydrocarbon feedstock in a fluidized catalytic 
cracking process is effected by contact with a cracking catalyst, 
preferably in one or more fluidized transfer line reactors, at conversion 
temperature and at a fluidizing velocity which limits the conversion time 
to not more than about ten seconds. Conversion temperatures are desirably 
in the range from about 450.degree. to about 565.degree. C., and 
preferably from about 450.degree. to about 540.degree. C. 
In the usual case where a gas oil feedstock is employed in a conventional 
fluidized catalytic cracking process, the throughput ratio (TPR), or 
volume ratio of total feed to fresh feed, can vary from about 1.0 to about 
3.0. Conversion level can vary from about 40% to about 100% where 
conversion is here defined as the percentage reduction of hydrocarbons 
boiling above 221.degree. C. at atmospheric pressure by formation of 
lighter materials or coke. The weight ratio of catalyst to oil in the 
reactor can vary within the range from about 2 to about 25 so that the 
fluidized dispersion will have a density in the range from about 16 to 
about 320 kilograms per cubic meter. Fluidizing velocity can be in the 
range from about 3.0 to about 30 meters per second, and the cracking 
process is preferably effected in a transfer line reactor wherein the 
ratio of length to average diameter is at least about 25. 
In a fluidized catalytic cracking process catalyst regeneration is 
accomplished by burning the coke deposits from the catalyst surfaces in a 
regeneration zone with an oxygen-containing gas such as air. Deactivated 
cracking catalyst typically contains from about 0.5 to about 3 weight 
percent coke and regenerated catalyst desirably contains less than about 
0.3, preferably less than about 0.2 and most preferably less than about 
0.1 weight percent of residual coke. Any conventional regeneration 
technique can be employed, including that which is set forth in U.S. Pat. 
No. 3,909,392 to Horecky et al. The regeneration zone temperatures are 
ordinarily in the range from about 565.degree. C. to about 815.degree. C. 
and are preferably in the range from about 620.degree. to about 
735.degree. C. When air is used as the regeneration gas, it enters the 
regenerator from a blower or compressor and a fluidizing velocity in the 
range from about 0.05 to about 8.0 meters per second, preferably from 
about 0.05 to about 1.5 meters per second and more preferably from about 
0.15 to about 1.0 meters per second is maintained in the regenerator. 
Regenerated catalyst is then recycled to the transfer line reactor for 
further use in the conversion of hydrocarbon feedstock. 
A suitable hydrocarbon feedstock for use in a fluidized catalytic cracking 
process in accordance with this invention can contain from about 0.05 to 
about 10 percent of sulfur in the form of organic sulfur compounds. 
Advantageously, the feedstock contains from about 0.1 to about 6 weight 
percent sulfur and more advantageously contains from about 0.2 to about 4 
weight percent sulfur wherein the sulfur is present in the form of organic 
sulfur compounds. Suitable feedstocks include, but are not limited to, 
sulfur-containing petroleum fractions such as light gas oils, heavy gas 
oils, wide-cut gas oils, vacuum gas oils, naphthas, decanted oils, 
residual fractions and cycle oils derived from any of these as well as 
sulfur-containing hydrocarbon fractions derived from shale oils, tar sands 
processing, synthetic oils, coal liquefaction and the like. Any of these 
suitable feedstocks can be employed either singly or in any desired 
combination. 
Conventional hydrocarbon cracking catalysts include those of the amorphous 
silica-alumina type having an alumina content of about 10 to about 30 
weight percent. Catalysts of the silica-magnesia type are also suitable 
which have a magnesia content of about 20 weight percent. Preferred 
catalysts include those of the zeolite-type which comprise from about 0.5 
to about 50 weight percent and preferably from about 1 to about 30 weight 
percent of a crystalline alumino-silicate component distributed throughout 
a porous matrix. Zeolite-type cracking catalysts are preferred because of 
their thermal stability and high catalytic activity. 
The crystalline aluminosilicate or zeolite component of the zeolite-type 
cracking catalyst can be of any type or combination of types, natural or 
synthetic, which is known to be useful in catalyzing the cracking of 
hydrocarbons. Suitable zeolites include both naturally occurring and 
synthetic aluminosilicate materials such as faujasite, chabazite, 
mordenite, Zeolite X (U.S. Pat. No. 2,882,244), Zeolite Y (U.S. Pat. No. 
3,130,007) and ultrastable large-pore zeolites (U.S. Pat. Nos. 3,293,192 
and 3,449,070). The crystalline aluminosilicates having a faujasite-type 
crystal structure are particularly suitable and include natural faujasite, 
Zeolite X and Zeolite Y. These zeolites are usually prepared or occur 
naturally in the sodium form. The presence of this sodium is undesirable, 
however, since the sodium zeolites have a low catalytic activity and also 
a low stability at elevated temperatures in the presence of steam. 
Consequently, the sodium content of the zeolite is ordinarily reduced to 
the smallest possible value, generally less than about 1.0 weight percent 
and preferably below about 0.3 weight percent through ion exchange with 
hydrogen ions, hydrogen-precursors such as ammonium ion, or polyvalent 
metal cations including calcium, magnesium, strontium, barium and the rare 
earth metals such as cerium, lanthanum, neodymium and their mixtures. 
Suitable zeolites are also able to maintain their pore structure under the 
high temperature conditions of catalyst manufacture, hydrocarbon 
processing and catalyst regeneration. These materials have a uniform pore 
structure of exceedingly small size, the cross section diameter of the 
pores being in the range from about 4 to about 20 angstroms, preferably 
from about 8 to about 15 angstroms. 
The matrix of the zeolite-type cracking catalyst is a porous refractory 
material within which the zeolite component is dispersed. Suitable matrix 
materials can be either synthetic or naturally occurring and include, but 
are not limited to, silica, alumina, magnesia, boria, bauxite, titania, 
natural and treated clays, kieselguhr, diatomaceous earth, kaolin and 
mullite. Mixtures of two or more of these materials are also suitable. 
Particularly suitable matrix materials comprise mixtures of silica and 
alumina, mixtures of silica with alumina and magnesia, and also mixtures 
of silica and alumina in combination with natural clays and clay-like 
materials. Mixtures of silica and alumina are preferred, however, and 
contain preferably from about 10 to about 65 weight percent of alumina 
mixed with from about 35 to about 90 weight percent of silica. 
The following examples are intended only to illustrate the invention and 
are not to be construed as imposing limitations on the invention. 
EXAMPLE 1 
A 200 gram sample of particulate silica-alumina cracking catalyst which was 
deactivated by sulfur-containing coke deposits was placed in a test vessel 
surrounded by a furnace to provide the desired experimental temperature. 
The coked catalyst sample was fluidized by a flow of nitrogen which was 
passed through the fixed fluidized bed of catalyst at a rate of 800 
cc./min. during the period of time required to heat the catalyst sample to 
a temperature of 649.degree. C. The flow of nitrogen was then terminated, 
and a mixture of air and steam was passed through the fixed fluidized bed 
at 649.degree. C. for 15 minutes at a rate of 800 cc./min. of air and 0.05 
g/min. of water (corresponding to a mole ratio of steam to oxygen of 
0.4/1). The data which are set forth in the following Table demonstrate 
that the initial coke deposit was modified in such a manner that 7 percent 
of the carbon, 30 percent of the sulfur, and 42 percent of the hydrogen 
were removed as gases. With respect to the sulfur removed, 62 percent was 
discharged in the effluent gas from the test vessel as hydrogen sulfide 
and the remainder was discharged as sulfur dioxide. These test results 
serve to illustrate the selective removal of the sulfur and hydrogen 
content of coke deposits on deactivated cracking catalyst upon reaction 
with a mixture of air and steam. The results further demonstrate that 
large quantities of the sulfur can be removed in the form of hydrogen 
sulfide. 
TABLE 
______________________________________ 
Start of End of 
Test Test 
______________________________________ 
Carbon on catalyst, wt. % 
1.347 1.250 
Hydrogen on catalyst, wt. % 
0.153 0.089 
Sulfur on catalyst, wt. % 
0.0779 0.0544 
SO.sub.2 produced, grams 
-- 0.0171.sup.a 
H.sub.2 S produced, grams 
-- 0.0280.sup.b 
______________________________________ 
.sup.a All of the SO.sub.2 was produced during fluidization of the sample 
with steam and air. - 
.sup.b 0.0128 grams of the hydrogen sulfide (46%) was produced during 
fluidization of the coked catalyst sample with nitrogen prior to 
contacting with steam and air. 
EXAMPLE 2 
At a temperature of 649.degree. C., a gas mixture composed of 4 mole 
percent oxygen and 96 mole percent nitrogen was passed at a rate of 1000 
cc./min. through a 10 gram sample of HFZ-20 particulate cracking catalyst 
(marketed by the Houdry Division of Air Products and Chemicals, Inc.) 
which was deactivated with sulfur-containing coke deposits. Effluent gas 
was passed through an SO.sub.2 analyzer and, in addition, samples were 
periodically collected and analyzed for CO and CO.sub.2 content by gas 
chromatography. These analytical results are shown in FIG. 2, which 
illustrates the variation of effluent gas composition with time. The 
results in FIG. 2 indicate that the sulfur content of coke is removed at a 
faster rate than the carbon content.