Hydrocarbon upgrading process

Low sulfur gasoline of relatively high octane number is produced from a catalytically cracked, sulfur-containing naphtha by hydrodesulfurization followed by treatment over an acidic catalyst, preferably an intermediate pore size zeolite such as ZSM-5. The treatment over the acidic catalyst in the second step restores the octane loss which takes place as a result of the hydrogenative treatment and results in a low sulfur gasoline product with an octane number comparable to that of the feed naphtha. In favorable cases, using feeds of extended end point such as heavy naphthas with 95 percent points above about 380.degree. F. (about 193.degree. C.), improvements in both product octane and yield relative to the feed may be obtained.

FIELD OF THE INVENTION 
This invention relates to a process for the upgrading of hydrocarbon 
streams. It more particularly refers to a process for upgrading gasoline 
boiling range petroleum fractions containing substantial proportions of 
sulfur impurities. 
BACKGROUND OF THE INVENTION 
Heavy petroleum fractions, such as vacuum gas oil, or even resids such as 
atmospheric resid, may be catalytically cracked to lighter and more 
valuable products, especially gasoline. Catalytically cracked gasoline 
forms a major part of the gasoline product pool in the United States. It 
is conventional to recover the product of catalytic cracking and to 
fractionate the cracking products into various fractions such as light 
gases; naphtha, including light and heavy gasoline; distillate fractions, 
such as heating oil and Diesel fuel; lube oil base fractions; and heavier 
fractions. 
Where the petroleum fraction being catalytically cracked contains sulfur, 
the products of catalytic cracking usually contain sulfur impurities which 
normally require removal, usually by hydrotreating, in order to comply 
with the relevant product specifications. These specifications are 
expected to become more stringent in the future, possibly permitting no 
more than about 300 ppmw sulfur in motor gasolines. In naphtha 
hydrotreating, the naphtha is contacted with a suitable hydrotreating 
catalyst at elevated temperature and somewhat elevated pressure in the 
presence of a hydrogen atmosphere. One suitable family of catalysts which 
has been widely used for this service is a combination of a Group VIII and 
a Group VI element, such as cobalt and molybdenum, on a suitable 
substrate, such as alumina. 
Sulfur impurities tend to concentrate in the heavy fraction of the 
gasoline, as noted in U.S. Pat. No. 3,957,625 (Orkin) which proposes a 
method of removing the sulfur by hydrodesulfurization of the heavy 
fraction of the catalytically cracked gasoline so as to retain the octane 
contribution from the olefins which are found mainly in the lighter 
fraction. In one type of conventional, commercial operation, the heavy 
gasoline fraction is treated in this way. As an alternative, the 
selectivity for hydrodesulfurization relative to olefin saturation may be 
shifted by suitable catalyst selection, for example, by the use of a 
magnesium oxide support instead of the more conventional alumina. 
In the hydrotreating of petroleum fractions, particularly naphthas, and 
most particularly heavy cracked gasoline, the molecules containing the 
sulfur atoms are mildly hydrocracked so as to release their sulfur, 
usually as hydrogen sulfide. After the hydrotreating operation is 
complete, the product may be fractionated, or even just flashed, to 
release the hydrogen sulfide and collect the now sweetened gasoline. 
Although this is an effective process that has been practiced on gasolines 
and heavier petroleum fractions for many years to produce satisfactory 
products, it does have disadvantages. 
Naphthas, including light and full range naphthas, may be subjected to 
catalytically reforming so as to increase their octane numbers by 
converting at least a portion of the paraffins and cycloparaffins in them 
to aromatics. Fractions to be fed to catalytic reforming, such as over a 
platinum type catalyst, also need to be desulfurized before reforming 
because reforming catalysts are generally not sulfur tolerant. Thus, 
naphthas are usually pretreated by hydrotreating to reduce their sulfur 
content before reforming. The octane rating of reformate may be increased 
further by processes such as those described in U.S. Pat. No. 3,767,568 
and U.S. Pat. No. 3,729,409 (Chen) in which the reformate octane is 
increased by treatment of the reformate with ZSM-5. 
Aromatics are generally the source of high octane number, particularly very 
high research octane numbers and are therefore desirable components of the 
gasoline pool. They have, however, been the subject of severe limitations 
as a gasoline component because of possible adverse effects on the 
ecology, particularly with reference to benzene. It has therefore become 
desirable, as far as is feasible, to create a gasoline pool in which the 
higher octanes are contributed by the olefinic and branched chain 
paraffinic components, rather than the aromatic components. Light and full 
range naphthas can contribute substantial volume to the gasoline pool, but 
they do not generally contribute significantly to higher octane values 
without reforming. 
Cracked naphtha, as it comes from the catalytic cracker and without any 
further treatments, such as purifying operations, has a relatively high 
octane number as a result of the presence of olefinic components. It also 
has an excellent volumetric yield. As such, cracked gasoline is an 
excellent contributor to the gasoline pool. It contributes a large 
quantity of product at a high blending octane number. In some cases, this 
fraction may contribute as much as up to half the gasoline in the refinery 
pool. Therefore, it is a most desirable component of the gasoline pool, 
and it should not be lightly tampered with. 
Other highly unsaturated fractions boiling in the gasoline boiling range, 
which are produced in some refineries or petrochemical plants, include 
pyrolysis gasoline. This is a fraction which is often produced as a 
by-product in the cracking of petroleum fractions to produce light 
unsaturates, such as ethylene and propylene. Pyrolysis gasoline has a very 
high octane number but is quite unstable in the absence of hydrotreating 
because, in addition to the desirable olefins boiling in the gasoline 
boiling range, it also contains a substantial proportion of diolefins, 
which tend to form gums after storage or standing. 
Hydrotreating of any of the sulfur containing fractions which boil in the 
gasoline boiling range causes a reduction in the olefin content, and 
consequently a reduction in the octane number and as the degree of 
desulfurization increases, the octane number of the normally liquid 
gasoline boiling range product decreases. Some of the hydrogen may also 
cause some hydrocracking as well as olefin saturation, depending on the 
conditions of the hydrotreating operation. 
Various proposals have been made for removing sulfur while retaining the 
more desirable olefins. U.S. Pat. No. 4,049,542 (Gibson), for instance, 
discloses a process in which a copper catalyst is used to desulfurize an 
olefinic hydrocarbon feed such as catalytically cracked light naphtha. 
In any case, regardless of the mechanism by which it happens, the decrease 
in octane which takes place as a consequence of sulfur removal by 
hydrotreating creates a tension between the growing need to produce 
gasoline fuels with higher octane number and--because of current 
ecological considerations--the need to produce cleaner burning, less 
polluting fuels, especially low sulfur fuels. This inherent tension is yet 
more marked in the current supply situation for low sulfur, sweet crudes. 
Other processes for treating catalytically cracked gasolines have also been 
proposed in the past. For example, U.S. Pat. No. 3,759,821 (Brennan) 
discloses a process for upgrading catalytically cracked gasoline by 
fractionating it into a heavier and a lighter fraction and treating the 
heavier fraction over a ZSM-5 catalyst, after which the treated fraction 
is blended back into the lighter fraction. Another process in which the 
cracked gasoline is fractionated prior to treatment is described in U.S. 
Pat. No. 4,062,762 (Howard) which discloses a process for desulfurizing 
naphtha by fractionating the naphtha into three fractions each of which is 
desulfurized by a different procedure, after which the fractions are 
recombined. 
SUMMARY OF THE INVENTION 
We have now devised a process for catalytically desulfurizing cracked 
fractions in the gasoline boiling range which enables the sulfur to be 
reduced to acceptable levels without substantially reducing the octane 
number. In favorable cases, the volumetric yield of gasoline boiling range 
product is not substantially reduced and may even be increased so that the 
number of octane barrels of product produced is at least equivalent to the 
number of octane barrels of feed introduced into the operation. 
The process may be utilized to desulfurize light and full range naphtha 
fractions while maintaining octane so as to obviate the need for reforming 
such fractions, or at least, without the necessity of reforming such 
fractions to the degree previously considered necessary. Since reforming 
generally implies a significant yield loss, this constitutes a marked 
advantage of the present process. 
According to the present invention, a sulfur-containing craked petroleum 
fraction in the gasoline boiling range is hydrotreated, in a first stage, 
under conditions which remove at least a substantial proportion of the 
sulfur. Hydrotreated intermediate product is then treated, in a second 
stage, by contact with a catalyst of acidic functionality under conditions 
which convert the hydrotreated intermediate product fraction to a fraction 
in the gasoline boiling range of higher octane value.

DETAILED DESCRIPTION 
Feed 
The feed to the process comprises a sulfur-containing petroleum fraction 
which boils in the gasoline boiling range. Feeds of this type include 
light naphthas typically having a boiling range of about C.sub.6 to 
330.degree. F., full range naphthas typically having a boiling range of 
about C.sub.5 to 420.degree. F., heavier naphtha fractions boiling in the 
range of about 260.degree. F. to 412.degree. F., or heavy gasoline 
fractions boiling at, or at least within, the range of about 330.degree. 
to 500.degree. F., preferably about 330.degree. to 412.degree. F. While 
the most preferred feed appears at this time to be a heavy gasoline 
produced by catalytic cracking; or a light or full range gasoline boiling 
range fraction, the best results are obtained when, as described below, 
the process is operated with a gasoline boiling range fraction which has a 
95 percent point (determined according to ASTM D 86) of at least about 
325.degree. F. (163.degree. C.) and preferably at least about 350 .degree. 
F. (1770.degree. C.), for example, 95 percent points of at least 
380.degree. F. (about 193.degree. C.) or at least about 400.degree. F. 
(about 220.degree. C.). 
The process may be operated with the entire gasoline fraction obtained from 
the catalytic cracking step or, alternatively, with part of it. Because 
the sulfur tends to be concentrated in the higher boiling fractions, it is 
preferable, particularly when unit capacity is limited, to separate the 
higher boiling fractions and process them through the steps of the present 
process without processing the lower boiling cut. The cut point between 
the treated and untreated fractions may vary according to the sulfur 
compounds present but usually, a cut point in the range of from about 
100.degree. F. (38.degree. C.) to about 300.degree. F. (150.degree. C.), 
more usually in the range of about 200.degree. F. (93.degree. C.) to about 
300.degree. F. (150.degree. C.) will be suitable. The exact cut point 
selected will depend on the sulfur specification for the gasoline product 
as well as on the type of sulfur compounds present: lower cut points will 
typically be necessary for lower product sulfur specifications. Sulfur 
which is present in components boiling below about 150.degree. F. 
(65.degree. C.) is mostly in the form of mercaptans which may be removed 
by extractive type processes such as Merox but hydrotreating is 
appropriate for the removal of thiophene and other cyclic sulfur compounds 
present in higher boiling components e.g. component fractions boiling 
above about 180.degree. F. (82.degree. C.). Treatment of the lower boiling 
fraction in an extractive type process coupled with hydrotreating of the 
higher boiling component may therefore represent a preferred economic 
process option. Higher cut points will be preferred in order to minimize 
the amount of feed which is passed to the hydrotreater and the final 
selection of cut point together with other process options such as the 
extractive type desulfurization will therefore be made in accordance with 
the product specifications, feed constraints and other factors. 
The sulfur content of these catalytically cracked fractions will depend on 
the sulfur content of the feed to the cracker as well as on the boiling 
range of the selected fraction used as the feed in the process. Lighter 
fractions, for example, will tend to have lower sulfur contents than the 
higher boiling fractions. As a practical matter, the sulfur content will 
exceed 50 ppmw and usually will be in excess of 100 ppmw and in most cases 
in excess of about 500 ppmw. For the fractions which have 95 percent 
points over about 380.degree. F. (193.degree. C.), the sulfur content may 
exceed about 1,000 ppmw and may be as high as 4,000 or 5,000 ppmw or even 
higher, as shown below. The nitrogen content is not as characteristic of 
the feed as the sulfur content and is preferably not greater than about 20 
ppmw although higher nitrogen levels typically up to about 50 ppmw may be 
found in certain higher boiling feeds with 95 percent points in excess of 
about 380 .degree. F. (193.degree. C.). The nitrogen level will, however, 
usually not be greater than 250 or 300 ppmw. As a result of the cracking 
which has preceded the steps of the present process, the feed to the 
hydrodesulfurization step will be olefinic, with an olefin content of at 
least 5 and more typically in the range of 10 to 20, e.g. 15-20, weight 
percent. 
Process Configuration 
The selected sulfur-containing, gasoline boiling range feed is treated in 
two steps by first hydrotreating the feed by effective contact of the feed 
with a hydrotreating catalyst, which is suitably a conventional 
hydrotreating catalyst, such as a combination of a Group VI and a Group 
VIII metal on a suitable refractory support such as alumina, under 
hydrotreating conditions. Under these conditions, at least some of the 
sulfur is separated from the feed molecules and converted to hydrogen 
sulfide, to produce a hydrotreated intermediate product comprising a 
normally liquid fraction boiling in substantially the same boiling range 
as the feed (gasoline boiling range), but which has a lower sulfur content 
and a lower octane number than the feed. This hydrotreated intermediate 
product which also boils in the gasoline boiling range (and usually has a 
boiling range which is not substantially higher than the boiling range of 
the feed), is then treated by contact with an acidic catalyst under 
conditions which produce a second product comprising a fraction which 
boils in the gasoline boiling range which has a higher octane number than 
the portion of the hydrotreated intermediate product fed to this second 
step. The product form this second step usually has a boiling range which 
is not substantially higher than the boiling range of the feed to the 
hydrotreater, but it is of lower sulfur content while having a comparable 
octane rating as the result of the second stage treatment. 
The catalyst used in the second stage of the process has a significant 
degree of acid activity, and for this purpose the most preferred materials 
are the crystalline refractory solids having an intermediate effective 
pore size and the topology of a zeolitic behaving material, which, in the 
aluminosilicate form, has a constraint index of about 2 to 12. 
Hydrotreating 
The temperature of the hydrotreating step is suitably from about 
400.degree. to 850.degree. F. (about 220.degree. to 454.degree. C.), 
preferably about 500.degree. to 800.degree. F. (about 260.degree. to 
427.degree. C.) with the exact selection dependent on the desulfurization 
desired for a given feed and catalyst. Because the hydrogenation reactions 
which take place in this stage are exothermic, a rise in temperature takes 
place along the reactor; this is actually favorable to the overall process 
when it is operated in the cascade mode because the second step is one 
which implicates cracking, an endothermic reaction. In this case, 
therefore, the conditions in the first step should be adjusted not only to 
obtain the desired degree of desulfurization but also to produce the 
required inlet temperature for the second step of the process so as to 
promote the desired shape-selective cracking reactions in this step. A 
temperature rise of about 20.degree. to 200.degree. F. (about 11.degree. 
to 111.degree. C.) is typical under most hydrotreating conditions and with 
reactor inlet temperatures in the preferred 500.degree. to 800.degree. F. 
(260.degree. to 427.degree. C.) range, will normally provide a requisite 
initial temperature for cascading to the second step of the reaction. When 
operated in the two-stage configuration with interstage separation and 
heating, control of the first stage exotherm is obviously not as critical; 
two-stage operation may be preferred since it offers the capability of 
decoupling and optimizing the temperature requirements of the individual 
stages. 
Since the feeds are readily desulfurized, low to moderate pressures may be 
used, typically from about 50 to 1500 psig (about 445 to 10443 kPa), 
preferably about 300 to 1000 psig (about 2170 to 7,000 kPa). Pressures are 
total system pressure, reactor inlet. Pressure will normally be chosen to 
maintain the desired aging rate for the catalyst in use. The space 
velocity (hydrodesulfurization step) is typically about 0.5 to 10 LHSV 
(hr.sup.-1), preferably about 1 to 6 LHSV (hr.sup.-1). The hydrogen to 
hydrocarbon ratio in the feed is typically about 500 to 5000 SCF/Bbl 
(about 90 to 900 n.l.l.sup.-1.), usually about 1000 to 2500 SCF/B (about 
180 to 445 n.l.l.sup.31 1). The extent of the desulfurization will depend 
on the feed sulfur content and, of course, on the product sulfur 
specification with the reaction parameters selected accordingly. It is not 
necessary to go to very low nitrogen levels but low nitrogen levels may 
improve the activity of the catalyst in the second step of the process. 
Normally, the denitrogenation which accompanies the desulfurization will 
result in an acceptable organic nitrogen content in the feed to the second 
step of the process; if it is necessary, however, to increase the 
denitrogenation in order to obtain a desired level of activity in the 
second step, the operating conditions in the first step may be adjusted 
accordingly. 
The catalyst used in the hydrodesulfurization step is suitably a 
conventional desulfurization catalyst made up of a Group VI and/or a Group 
VIII metal on a suitable substrate. The Group VI metal is usually 
molybdenum or tungsten and the Group VIII metal usually nickel or cobalt. 
Combinations such as Ni--Mo or Co--Mo are typical. Other metals which 
possess hydrogenation functionality are also useful in this service. The 
support for the catalyst is conventionally a porous solid, usually 
alumina, or silica-alumina but other porous solids such as magnesia, 
titania or silica, either alone or mixed with alumina or silica-alumina 
may also be used, as convenient. 
The particle size and the nature of the hydrotreating catalyst will usually 
be determined by the type of hydrotreating process which is being carried 
out, such as: a down-flow, liquid phase, fixed bed process; an up-flow, 
fixed bed, trickle phase process; an ebulating, fluidized bed process; or 
a transport, fluidized bed process. All of these different process schemes 
are generally well known in the petroleum arts, and the choice of the 
particular mode of operation is a matter left to the discretion of the 
operator, although the fixed bed arrangements are preferred for simplicity 
of operation. 
A change in the volume of gasoline boiling range material typically takes 
place in the first step. Although some decrease in volume occurs as the 
result of the conversion to lower boiling products (C.sub.5 -), the 
conversion to C.sub.5 - products is typically not more than 5 vol percent 
and usually below 3 vol percent and is normally compensated for by the 
increase which takes place as a result of aromatics saturation. An 
increase in volume is typical for the second step of the process where, as 
the result of cracking the back end of the hydrotreated feed, cracking 
products within the gasoline boiling range are produced. An overall 
increase in volume of the gasoline boiling range (C.sub.5 +) materials may 
occur. 
Octane Restoration--Second Step Processing 
After the hydrotreating step, the hydrotreated intermediate product is 
passed to the second step of the process in which cracking takes place in 
the presence of the acidic functioning catalyst. The effluent from the 
hydrotreating step may be subjected to an interstage separation in order 
to remove the inorganic sulfur and nitrogen as hydrogen sulfide and 
ammonia as well as light ends but this is not necessary and, in fact, it 
has been found that the first stage can be cascaded directly into the 
second stage. This can be done very conveniently in a down-flow, fixed-bed 
reactor by loading the hydrotreating catalyst directly on top of the 
second stage catalyst. 
The separation of the light ends at this point may be desirable if the 
added complication is acceptable since the saturated C.sub.4 -C.sub.6 
fraction from the hydrotreater is a highly suitable feed to be sent to the 
isomerizer for conversion to iso-paraffinic materials of high octane 
rating; this will avoid the conversion of this fraction to non-gasoline 
(C.sub.5 -) products in the second stage of the process. Another process 
configuration with potential advantages is to take a heart cut, for 
example, a 195.degree.-302.degree. F. (90.degree.-150.degree. C.) 
fraction, from the first stage product and send it to the reformer where 
the low octane naphthenes which make up a significant portion of this 
fraction are converted to high octane aromatics. The heavy portion of the 
first stage effluent is, however, sent to the second step for restoration 
of lost octane by treatment with the acid catalyst. The hydrotreatment in 
the first stage is effective to desulfurize and denitrogenate the 
catalytically cracked naphtha which permits the heart cut to be processed 
in the reformer. Thus, the preferred configuration in this alternative is 
for the second stage to process the C.sub.8 + portion of the first stage 
effluent and with feeds which contain significant amounts of heavy 
components up to about C.sub.13 e.g. with C.sub.9 -C.sub.13 fractions 
going to the second stage, improvements in both octane and yield can be 
expected. 
The conditions used in the second step of the process are those which 
result in a controlled degree of shape-selective cracking of the 
desulfurized, hydrotreated effluent from the first step produces olefins 
which restore the octane rating of the original, cracked feed at least to 
a partial degree. The reactions which take place during the second step 
are mainly the shape-selective cracking of low octane paraffins to form 
higher octane products, both by the selective cracking of heavy paraffins 
to lighter paraffins and the cracking of low octane n-paraffins, in both 
cases with the generation of olefins. Some isomerization of n-paraffins to 
branched-chain paraffins of higher octane may take place, making a further 
contribution to the octane of the final product. In favorable cases, the 
original octane rating of the feed may be completely restored or perhaps 
even exceeded. Since the volume of the second stage product will typically 
be comparable to that of the original feed or even exceed it, the number 
of octane barrels (octane rating.times.volume) of the final, desulfurized 
product may exceed the octane barrels of the feed. 
The conditions used in the second step are those which are appropriate to 
produce this controlled degree of cracking. Typically, the temperature of 
the second step will be about 300.degree. to 900.degree. F. (about 
150.degree. to 480.degree. C.), preferably about 350.degree. to 
800.degree. F. (about 177.degree. C.). As mentioned above, however, a 
convenient mode of operation is to cascade the hydrotreated effluent into 
the second reaction zone and this will imply that the outlet temperature 
from the first step will set the initial temperature for the second zone. 
The feed characteristics and the inlet temperature of the hydrotreating 
zone, coupled with the conditions used in the first stage will set the 
first stage exotherm and, therefore, the initial temperature of the second 
zone. Thus, the process can be operated in a completely integrated manner, 
as shown below. 
The pressure in the second reaction zone is not critical since no 
hydrogenation is desired at this point in the sequence although a lower 
pressure in this stage will tend to favor olefin production with a 
consequent favorable effect on product octane. The pressure will therefore 
depend mostly on operating convenience and will typically be comparable to 
that used in the first stage, particularly if cascade operation is used. 
Thus, the pressure will typically be about 50 to 1500 psig (about 445 to 
10445 kPa), preferably about 300 to 1000 psig (about 2170 to 7000 kPa) 
with comparable space velocities, typically from about 0.5 to 10 LHSV 
(hr.sup.-1), normally about 1 to 6 LHSV (hr.sup.-1). Hydrogen to 
hydrocarbon ratios typically of about 0 to 5000 SCF/Bbl (0 to 890 
n.l.l.sup.-1) preferably about 100 to 2500 SCF/Bbl (about 18 to 445 
n.l.l.sup.-1.) will be selected to minimize catalyst aging. 
The use of relatively lower hydrogen pressures thermodynamically favors the 
increase in volume which occurs in the second step and for this reason, 
overall lower pressures are preferred if this can be accommodated by the 
constraints on the aging of the two catalysts. In the cascade mode, the 
pressure in the second step may be constrained by the requirements of the 
first but in the two-stage mode the possibility of recompression permits 
the pressure requirements to be individually selected, affording the 
potential for optimizing conditions in each stage. 
Consistent with the objective of restoring lost octane while retaining 
overall product volume, the conversion to products boiling below the 
gasoline boiling range (C.sub.5 -) during the second stage is held to a 
minimum. However, because the cracking of the heavier portions of the feed 
may lead to the production of products still within the gasoline range, no 
not conversion to C.sub.5 - products may take place and, in fact, a net 
increase in C.sub.5 + material may occur during this stage of the process, 
particularly if the feed includes significant amount of the higher boiling 
fractions. It is for this reason that the use of the higher boiling 
naphthas is favored, especially the fractions with 95 percent points above 
about 350.degree. F. (about 177.degree. C.) and even more preferably above 
about 380.degree. F. (about 193.degree. C.) or higher, for instance, above 
about 400.degree. F. (about 205.degree. C.). Normally, however, the 95 
percent point will not exceed about 520.degree. F. (about 270.degree. C.) 
and usually will be not more than about 500.degree. F. (about 260.degree. 
C.). 
The catalyst used in the second step of the process possesses sufficient 
acidic functionality to bring about the desired cracking reactions to 
restore the octane lost in the hydrotreating step. The preferred catalysts 
for this purpose are the intermediate pore size zeolitic behaving 
catalytic materials are exemplified by those acid acting materials having 
the topology of intermediate pore size aluminosilicate zeolites. These 
zeolitic catalytic materials are exemplified by those which, in their 
aluminosilicate form would have a Constraint Index between about 2 and 12. 
Reference is here made to U.S. Pat. No. 4,784,745 for a definition of 
Constraint Index and a description of how this value is measured. This 
patent also discloses a substantial number of catalytic materials having 
the appropriate topology and the pore system structure to be useful in 
this service. 
The preferred intermediate pore size aluminosilicate zeolites are those 
having the topology of ZSM-5, ZSM-11, ZSM-12, ZSM-21, ZSM-22, ZSM-23, 
ZSM-35, ZSM-48, ZSM-50 or MCM-22. Zeolite MCM-22 is described in U.S. 
Pat. No. 4,954,325. Other catalytic materials having the appropriate 
acidic functionality may, however, be employed. A particular class of 
catalytic materials which may be used are, for example, the large pores 
size zeolite materials which have a Constraint Index of up to about 2 (in 
the aluminosilicate form). Zeolites of this type include mordenite, 
zeolite beta, faujasites such as zeolite Y and ZSM-4. 
These materials are exemplary of the topology and pore structure of 
suitable acid-acting refractory solids; useful catalysts are not confined 
to the aluminosilicates and other refractory solid materials which have 
the desired acid activity, pore structure and topology may also be used. 
The zeolite designations referred to above, for example, define the 
topology only and do not restrict the compositions of the 
zeolitic-behaving catalytic components. 
The catalyst should have sufficient acid activity to have cracking activity 
with respect to the second stage feed (the intermediate fraction), that is 
sufficient to convert the appropriate portion of this material as feed. 
One measure of the acid activity of a catalyst is its alpha number. This 
is a measure of the ability of the catalyst to crack normal hexane under 
prescribed conditions. This test has been widely published and is 
conventionally used in the petroleum cracking art, and compares the 
cracking activity of a catalyst under study with the cracking activity, 
under the same operating and feed conditions, of an amorphous 
silica-alumina catalyst, which has been arbitrarily designated to have an 
alpha activity of 1. The alpha value is an approximate indication of the 
catalytic cracking activity of the catalyst compared to a standard 
catalyst. The alpha test gives the relative rate constant (rate of normal 
hexane conversion per volume of catalyst per unit time) of the test 
catalyst relative to the standard catalyst which is taken as an alpha of 1 
(Rate Constant=0.016 sec.sup.-1). The alpha test is described in U.S. Pat. 
No. 3,354,078 and in J. Catalysis, 4, 527 (1965); 6, 278 (1966); and 61, 
395 (1980), to which reference is made for a description of the test. The 
experimental conditions of the test used to determine the alpha values 
referred to in this specification include a constant temperature of 
538.degree. C. and a variable flow rate as described in detail in J. 
Catalysis, 61, 395 (1980). 
The catalyst used in the second step of the process suitably has an alpha 
activity of at least about 20, usually in the range of 20 to 800 and 
preferably at least about 50 to 200. It is inappropriate for this catalyst 
to have too high an acid activity because it is desirable to only crack 
and rearrange so much of the intermediate product as is necessary to 
restore lost octane without severely reducing the volume of the gasoline 
boiling range product. 
The active component of the catalyst e.g. the zeolite will usually be used 
in combination with a binder or substrate because the particle sizes of 
the pure zeolitic behaving materials are too small and lead to an 
excessive pressure drop in a catalyst bed. This binder or substrate, which 
is preferably used in this service, is suitably any refractory binder 
material. Examples of these materials are well known and typically include 
silica, silica-alumina, silica-zirconia, silica-titania, alumina. 
The catalyst used in this step of the process may contain a metal 
hydrogenation function for improving catalyst aging or regenerability; on 
the other hand, depending on the feed characteristics, process 
configuration (cascade or two-stage) and operating parameters, the 
presence of a metal hydrogenation function may be undesirable because it 
may tend to promote saturation of olefinics produced in the cracking 
reactions as well as possibly bringing about recombination of inorganic 
sulfur. If found to be desirable under the actual conditions used with 
particular feeds, metals such as the Group VIII base metals or 
combinations will normally be found suitable, for example nickel. Noble 
metals such as platinum or palladium will normally offer no advantage over 
nickel. A nickel content of about 0.5 to about 5 weight percent is 
suitable. 
The particle size and the nature of the second conversion catalyst will 
usually be determined by the type of conversion process which is being 
carried out, such as: a down-flow, liquid phase, fixed bed process; an 
up-flow, fixed bed, liquid phase process; an ebulating, fixed fluidized 
bed liquid or gas phase process; or a liquid or gas phase, transport, 
fluidized bed process, as noted above, with the fixed-bed type of 
operation preferred. 
The conditions of operation and the catalysts should be selected, together 
with appropriate feed characteristics to result in a product slate in 
which the gasoline product octane is not substantially lower than the 
octane of the feed gasoline boiling range material; that is not lower by 
more than about 1 to 3 octane numbers. It is preferred also that the 
volumetric yield of the product is not substantially diminished relative 
to the feed. In some cases, the volumetric yield and/or octane of the 
gasoline boiling range product may well be higher than those of the feed, 
as noted above and in favorable cases, the octane barrels (that is the 
octane number of the product times the volume of product) of the product 
will be higher than the octane barrels of the feed. 
The operating conditions in the first and second steps may be the same or 
different but the exotherm from the hydrotreatment step will normally 
result in a higher initial temperature for the second step. Where there 
are distinct first and second conversion zones, whether in cascade 
operation or otherwise, it is often desirable to operate the two zones 
under different conditions. Thus the second zone may be operated at higher 
temperature and lower pressure than the first zone in order to maximize 
the octane increase obtained in this zone. 
Further increases in the volumetric yield of the gasoline boiling range 
fraction of the product, and possibly also of the octane number 
(particularly the motor octane number), may be obtained by using the 
C.sub.3-C4 portion of the product as feed for an alkylation process to 
produce alkylate of high octane number. The light ends from the second 
step of the process are particularly suitable for this purpose since they 
are more olefinic than the comparable but saturated fraction from the 
hydrotreating step. Alternativley, the olefinic light ends from the second 
step may be used as feed to an etherification process to produce ethers 
such as MTBE or TAME for use as oxygenate fuel components. Depending on 
the composition of the light ends, especially the paraffin/olefin ratio, 
alkylation may be carried out with additional alkylation feed, suitably 
with isobutane which has been made in this or a catalytic cracking process 
or which is imported from other operations, to convert at least some and 
preferably a substantial proportion, to high octane alkylate in the 
gasoline boiling range, to increase both the octane and the volumetric 
yield of the total gasoline product. 
In one example of the operation of this process, it is reasonable to expect 
that, with a heavy cracked naphtha feed, the first stage 
hydrodesulfurization will reduce the octane number by at least 1.5%, more 
normally at least about 3%. With a full range naphtha feed, it is 
reasonable to expect that the hydrodesulfurization operation will reduce 
the octane number of the gasoline boiling range fraction of the first 
intermediate product by at least about 5%, and, if the sulfur content is 
high in the feed, that this octane reduction could go as high as about 
15%. 
The second stage of the process should be operated under a combination of 
conditions such that at least about half (1/2) of the octane lost in the 
first stage operation will be recovered, preferably such that all of the 
lost octane will be recovered, most preferably that the second stage will 
be operated such that there is a net gain of at least about 1% in octane 
over that of the feed, which is about equivalent to a gain of about at 
least about 5% based on the octane of the hydrotreated intermediate. 
The process should normally be operated under a combination of conditions 
such that the desulfurization should be at least about 50%, preferably at 
least about 75%, as compared to the sulfur content of the feed. 
EXAMPLES 
The following examples illustrate the operation of the present process. In 
these examples, parts and percentages are by weight unless they are 
expressly stated to be on some other basis. Temperatures are in .degree.F. 
and pressures in psig, unless expressly stated to be on some other basis. 
In the following examples, unless it is indicated that there was some other 
feed, the same heavy cracked naphtha, containing 2% sulfur, was subjected 
to processing as set forth below under conditions required to allow a 
maximum of only 300 ppmw sulfur in the final gasoline boiling range 
product. The properties of this naphtha feed are set out in Table 1 below. 
TABLE 1 
______________________________________ 
Heavy FCC Naphtha 
______________________________________ 
Gravity, .degree.API 23.5 
Hydrogen, wt % 10.23 
Sulfur, wt % 2.0 
Nitrogen, ppmw 190 
Clear Research Octane, R + O 
95.6 
Composition, wt % 
Paraffins 12.9 
Cyclo Paraffins 8.1 
Olefins and Diolefins 
5.8 
Aromatics 73.2 
Distillation, ASTM D-2887, 
.degree.F./.degree.C. 
5% 289/143 
10% 355/207 
30% 405/224 
50% 435/234 
70% 455/253 
90% 482 
95% 488 
______________________________________ 
Table 2 below sets out the properties of the catalysts used in the two 
operating conversion stages: 
TABLE 2 
______________________________________ 
Catalyst Properties 
Hydrodesulfurization 
ZSM-5.sup.(1) 
Composition, wt % 
1st stage Catalyst 
2nd stage Catalyst 
______________________________________ 
Nickel -- 1.0 
Cobalt 3.4 -- 
moO.sub.3 15.3 -- 
Physical Properties 
Particle Density, g/cc 
-- 0.98 
Surface Area, m.sup.2 /g 
260 336 
Pore Volume, cc/g 
0.55 0.65 
Pore Diameter, A 
85 77 
______________________________________ 
.sup.(1) 65 wt % ZSM5 and 35 wt % alumina 
Both stages of the process were carried out in an isothermal pilot plant at 
the same conditions in the following examples: pressure of 600 psig, space 
velocity of 1 LHSV, a hydrogen circulation rate of 3200 SCF/Bbl (4240 kPa 
abs, 1 hr..sup.-1 LHSV, 570 n.l.l.sup.-1.). experiments were run at 
reactor temperatures from 500.degree. to 775.degree. F. (about 260.degree. 
to 415.degree. C.). 
In all the examples, the process according to the invention was operated in 
a cascade mode with both catalyst bed/reaction zones operated at the same 
pressure and space velocity and with no intermediate separation of the 
intermediate product of the hydrodesulfurization. 
Comparison Examples (HDS Only) 
The process was operated with only a hydrodesulfurization reaction zone. At 
a reaction temperature of 550.degree. F. (288.degree. C.), the product had 
a sulfur content of about 300 ppmw, and a clear research octane of about 
92.5. As the temperature of the desulfurization was increased, the sulfur 
content and the octane number continued to decline, as shown in FIGS. 1 
and 2 (curves HDS Alone). 
Examples of HDS Followed by ZSM-5 Upgrading with Both Beds at the Same 
Temperature 
The hydrodesulfurization was run in cascade with ZSM-5 upgrading without 
intermediate hydrogen sulfide separation, with both beds under isothermal 
conditions. The results are again shown in FIGS. 1 and 2 (curves 
HDS/ZSM-5). 
At a reaction temperature of 550.degree. F. (288.degree. C.), the product 
had slightly higher or about the same sulfur content as the 
hydrodesulfurization alone, that is a sulfur content of about 300 ppmw, 
and about the same clear research octane of about 92.5. As the temperature 
was increased to 600.degree. F. (315.degree. C.), the sulfur content of 
the product declined to about 200 ppmw, below that of the 
hydrodesulfurization alone; the octane number started to increase for the 
cascade operation as compared to the hydrodesulfurization alone. 
When the operation was carried out at an operating temperature of 
685.degree. F. (363.degree. C.), the octane number of the finished product 
was substantially the same as that of the feed naphtha, at 95.6 
(clear-research), which is 4.6 octane units higher than the octane number 
for the same operation using only hydrodesulfurization without second step 
upgrading, while meeting the desired sulfur content specifications. 
Examples of HDS Followed by ZSM-5 Upgrading with HDS at 700.degree. F. 
(370.degree. C.) 
The HDS bed was operated at 700.degree. F. (370.degree. C.) and the ZSM-5 
bed at a higher temperature (up to 775.degree. F., 413.degree. C.) to 
simulate a temperature increase across the HDS bed. The octane of the 
product gasoline was increased to 99 (clear research). The desulfurization 
achieved was sufficient to meet the 300 ppmw specification, as shown in 
FIGS. 1 and 2. 
When operating with the second stage of the process there is a substantial 
production of propylene, butenes and isobutane, as shown in FIG. 3 which 
reports the yields of these materials as a function of the operating 
temperatures. Using hydrodesulfurization alone, it will be apparent that 
substantially no C.sub.3 and C.sub.4 compounds are produced. By contrast, 
with the combination process, whether operated at constant temperature or 
with the ZSM-5 bed at higher temperature, there is a substantial quantity 
of these light materials formed, and the proportion formed increases with 
temperature. 
Therefore, operating the process at progressively higher temperatures 
increases the production of desirable light fractions, increases the 
octane number of the gasoline boiling range product fractions, and 
effectively desulfurizes the gasoline boiling range product to a 
sufficient extent. 
Examples of Combined HDS/ZSM-5 Upgrading with Feeds of Differing Boiling 
Range 
The feed was cascaded from the first stage hydrodesulfurization to the 
second stage (ZSM-5) upgrading without intermediate separation between to 
two stages. The intermediate product resulting from the 
hydrodesulfurization stage conversion had properties, including sulfur 
content and octane number, which were consistent with the properties of 
the same type of feed converted in a conventional commercially operating 
hydrotreater. The product resulting from the second stage upgrading has 
physical properties, including sulfur content and octane number, which 
demonstrate the improvement obtained by the two-stage operation. The 
operating conditions were 0.84 LHSV (hr..sup.-1),3200 SCF/Bbl (570 
n.l.l.sup.-1.) hydrogen:oil and 600 psig (4240 kPa abs) pressure with the 
temperature varied as described below. The results are set out in Table 3 
below. 
A full range FCC naphtha was hydrodesulfurized in Cases 1 and 2 in a first 
(HDS) reaction zone at 700.degree. F. (370.degree. C.). There was 
substantially complete sulfur removal from the feed at a substantial loss 
in octane number. In Case 1, the second stage zeolitic upgrading was 
carried out under relatively mild conditions and served to minimize the 
loss of octane. In Case 2, operating the second stage conversion at higher 
severity caused the octane number of the final product to more closely 
approach that of the feed. Cases 3 and 4 show the same results achieved 
with a feed of somewhat heavier FCC naphtha. 
TABLE 3 
__________________________________________________________________________ 
HDS/ZSM-5 Upgrading of FCC Naphtha Cuts 
Cases 1 2 3 4 
__________________________________________________________________________ 
Reactor 1 Temp., .degree.F. 
700 700 700 700 
Reactor 2 Temp., .degree.F. 
700 750 700 750 
Feed 
Boiling Range, .degree.F. 
95-500 
95-500 
230-500 
230-500 
API Gravity 54.3 54.3 34.2 34.2 
Sulfur, ppmw 3800 3800 5200 5200 
Nitrogen, ppmw 44 44 85 85 
Bromine No. 45.81 45.81 13.86 13.86 
Research Octane 
93.5 93.5 95.8 95.8 
Motor Octane 81.6 81.6 83.5 83.5 
Wt % C.sub.5++ 99.8 99.8 100.0 100.0 
Vol % C.sub.5 99.8 99.8 100.0 100.0 
Reactor 1 Product 
Sulfur, ppmw &lt;20 &lt;20 &lt;20 &lt;20 
Nitrogen, ppmw 2 2 &lt;1 &lt;1 
Bromine No. 0.11 0.11 0.03 0.03 
Research Octane 
80.8 80.8 89.3 89.3 
Motor Octane 75.3 75.3 78.4 78.4 
Wt % C.sub.5 99.2 99.2 100.2 100.2 
Vol % C.sub.5+ 97.6 97.6 102.2 102.2 
Vol % C.sub.3 Olefins 
0.0 0.0 0.0 0.0 
Vol % C.sub.4 Olefins 
0.0 0.0 0.0 0.0 
Vol % Isobutane 
0.0 0.0 0.0 0.0 
Potential Alkylate, vol %.sup.(1) 
0.0 0.0 0.0 0.0 
Reactor 2 Product 
Sulfur, ppmw &lt;20 &lt;20 &lt;20 &lt;20 
Nitrogen, ppmw &lt;1 &lt;1 &lt;1 &lt;1 
Bromine No. 1.63 1.49 1.51 0.91 
Research Octane 
87.4 92.9 93.2 97.3 
Motor Octane 80.2 84.5 82.0 86.2 
Wt % C.sub.5 94.9 82.7 97.3 91.0 
Vol % C.sub.5+ 92.5 80.4 98.7 91.7 
Vol % C.sub.3 Olefins 
0.2 0.3 0.2 0.3 
Vol % C.sub.4 Olefins 
0.4 0.4 0.5 0.4 
Vol % Isobutane 
1.6 5.8 1.0 3.7 
Potential Alkylate, Vol % 
1.0 1.2 1.2 1.2 
__________________________________________________________________________ 
.sup.(1) Potential alkylate defined as 1.7 .times. (C.sub.4.sup.= + 
C.sub.3.sup.=, % vol). 
Examples of the Effect of HDS Severity on ZSM-5 Upgrading 
In the two cases illustrated here, the second (ZSM-5) stage, the 
temperature was held constant at 700.degree. F. (370.degree. C.) while the 
HDS temperature was varied to either 350.degree. F. (177.degree. C.) or 
550.degree. F. (288.degree. C.) at 0.84 LHSV (hr..sup.-1, 3200 SCF/Bbl 
(570 n.l.l.sup.-1) hydrogen:oil 600 psig (4240 kPa abs) pressure. The 
results are shown in Table 4 below. 
Case 1 demonstrates the results of upgrading cracked naphtha with ZSM-5 
without prior hydrotreatment. During the experiment, the temperature of 
the first reactor was 350.degree. F., which is sufficiently low to make 
this stage hydrotreating ineffective and made this first stage merely a 
pre-heater. The second stage alone did not remove the required amount of 
sulfur. 
In Case 2, mild hydrotreatment prior in the first stage did achieve the 
required desulfurization. However, the first stage of hydrotreatment 
completely saturated the olefins in the feed, as indicated by the bromine 
number reduction, and this resulted in a 9 number loss of research octane. 
The second stage processing over the ZSM-5 catalyst restored the lost 
octane. 
TABLE 4 
______________________________________ 
Effect of Hydrotreating Severity on ZSM-5 
Upgrading of FCC Naphtha 
Case 1 2 
______________________________________ 
Reactor 1 Temp., .degree.F. 
350 550 
Reactor 2 Temp., .degree.F. 
700 700 
Feed 
Boiling Range, .degree.F. 
95-500 95-500 
API Gravity 54.3 54.3 
Sulfur, ppmw 3800 3800 
Nitrogen, ppmw 44 44 
Bromine No. 45.81 45.81 
Research Octane 93.5 93.5 
Motor Octane 81.6 81.6 
Wt % C.sub.5 + 99.8 99.8 
Vol % C.sub.5 + 99.8 99.8 
Reactor 1 Product 
Sulfur, ppmw -- &lt;20 
Nitrogen, ppmw -- 3 
Bromine No. -- 0.08 
Research Octane -- 84.5 
Motor Octane -- 76.8 
Wt % C.sub.5 + -- 99.3 
Vol % C.sub.5 + -- 96.2 
Vol % C.sub.3 Olefins 
-- 0.0 
Vol % C.sub.4 Olefins 
-- 0.0 
Vol % Isobutane -- 0.0 
Potential Alkylate Vol % 
-- 0.0 
Reactor 2 Product 
Sulfur, ppmw 1700 30 
Nitrogen, ppmw 25 &lt;1 
Bromine No. 12.70 1.40 
Research Octane 94.0 90.0 
Motor Octane 83.7 82.0 
Wt % C.sub.5 + 94.3 94.7 
Vol % C.sub.5 + 88.8 92.0 
Vol % C.sub.3 Olefins 
0.5 0.2 
Vol % C.sub.4 Olefins 
1.1 0.4 
Vol % Isobutane 1.9 1.6 
Potential Alkylate vol % 
2.7 1.0 
______________________________________ 
Examples with Zeolites Other Than ZSM-5 (Second Step) 
These evaluations were conducted in a similar manner to those described 
above for the HDS/ZSM-5 studies using an isothermal pilot plant with both 
reaction zones at the same temperature (700.degree. F., 370.degree. C.) 
and H.sub.2 pressure (600 psig, 4240 kPa). The same Co-Mo/Al.sub.2 O.sub.3 
hydrotreating catalyst was used but the second stage catalysts were MCM-22 
and zeolite beta. The zeolite beta catalyst was prepared from a steamed 
H-beta zeolite and the MCM-22 catalyst from unsteamed H-MCM-22 with 
alumina binder in each case. The feed was a heavy catalytically cracked 
gasoline similar to that used in the ZSM-5 studies; its properties are 
shown in Table 5 together with those for the feed used in the ZSM-5 
studies. 
The results are given below in Table 6 together the results obtained with 
the ZSM-5 catalyst at 700.degree. F. (370.degree. C.) for comparison. The 
results are also shown graphically in FIGS. 4 to 6. 
TABLE 5 
______________________________________ 
Feed Properties - Heavy Gasoline 
Catalyst MCM-22/Beta ZSM-5 
______________________________________ 
H, wt % 10.64 10.23 
S, wt % 1.45 2.0 
N, wt % 170 190 
Bromine No. 11.7 14.2 
Paraffins, vol % 24.3 26.5 
Research Octane 94.3 95.6 
Motor Octane 82.8 81.2 
Distillation, D 2887 (F.degree./C.degree.) 
5% 284/140 289/143 
30% 396/202 405/207 
50% 427/219 435/224 
70% 451/233 453/234 
95% 492/256 488/253 
______________________________________ 
TABLE 6 
______________________________________ 
Catalyst Evaluations 
Ni ZSM-5 MCM-22 Beta 
______________________________________ 
420.degree. + F Conv., % 
15.6 27.4 31.4 
C.sub.3 =, wt % 
0.22 0.14 0.08 
C.sub.4 =, wt % 
0.51 1.10 0.35 
C.sub.5 =, wt, % 
0.47 1.90 0.49 
Paraffins 
Branched C.sub.4, wt % 
1.00 1.21 1.47 
Branched C.sub.5, wt % 
0.86 0.72 1.60 
______________________________________ 
These results show that both zeolite beta and MCM-22 are more active for 
420.degree. F.+ (215.degree. C.+) conversion (FIG. 6) than the ZSM-5 but 
slightly less effective for octane enhancement than ZSM-5 (FIG. 5). The 
MCM-22 catalyst, however, produces more C.sub.4 /C.sub.5 olefins than 
either ZSM-5 or zeolite beta (Table 6). The zeolite beta catalyst has a 
very high yield of isobutanes and isopentanes (Table 6). The 
desulfurization performances are shown in FIG. 4. The H-form beta and 
MCM-22 achieved desulfurization to less than 25 ppmw as compared to 180 
ppmw for the NiZSM-5.