Molecular sieve abstract
Selective hydrodesulfurization of cracked naphtha, with minimum
attendant hydrogenation of olefins, is effected over a novel catalyst
composition comprising a sulfided, "manganese oxide octahedral
molecular sieve" supported catalyst bearing (i) at least one
non-noble Group VIII metal, (ii) at least one Group VI-B metal,
optionally (iii) at least one metal of Group I-A, II-A, III-B, or
the lanthanide series of rare earths, and optionally (iv) at least
one metal of Group I-B. The catalyst of the present invention is
highly selective in minimizing the olefin saturation and the resulting
octane loss in the cracked naphtha hydrodesulfurization process.
Molecular sieve claims
What is claimed:
1. A continuous process for treating a charge cracked naphtha containing
olefinic components and undesired sulfur which comprises:
maintaining a bed of sulfided, "manganese oxide octahedral
molecular sieve (OMS)" supported catalyst containing intentionally
added (i) a metal of non-noble group VIII, and (ii) a metal of Group
VI-B;
passing the charge cracked naphtha containing olefinic components
and undesired sulfur into contact with said catalyst in the presence
of a gas selected from pure hydrogen and a gas mixture comprising
greater than 60% by volume hydrogen;
maintaining said charge cracked naphtha containing olefinic components
and undesired sulfur in contact with said catalyst at hydrodesulfurization
conditions thereby effecting hydrodesulfurization of said charge
cracked naphtha containing olefinic components and undesired sulfur
and forming a product stream of desulfurized naphtha containing
a decreased content of sulfur and retaining at least 50% of the
olefin content of the charge cracked naphtha; and
recovering said product stream of cracked naphtha containing a
decreased content of sulfur.
2. The process for treating a charge cracked naphtha as claimed
in claim 1 wherein said charge is a naphtha from a catalytic cracking
unit.
3. The process for treating a charge cracked naphtha as claimed
in claim 1 wherein said charge is a naphtha from a coking unit.
4. The process for treating a charge cracked naphtha as claimed
in claim 1 wherein said charge is a naphtha from a visbreaker unit.
5. The process for treating a charge cracked naphtha as claimed
in claim 1 wherein said charge naphtha is a pyrolysis naphtha.
6. The process for treating a charge cracked naphtha as claimed
in claim 1 wherein said charge naphtha is derived from steam cracker
effluents.
7. The process for treating a charge cracked naphtha as claimed
in claim 1 wherein said charge naphtha is derived from a process
selected from the group consisting of catalytic cracking, thermal
cracking, coking, delayed coking, visbreaking, or steam cracking,
and mixtures thereof.
8. The process for treating a charge cracked naphtha as claimed
in claim 1 wherein said charge naphtha is selected from the group
consisting of light naphtha, full range naphtha, heavy naphtha,
or mixtures thereof, derived from petroleum, coal, shale, tar sands,
oil sands, and other synthetic fuels, and mixtures thereof.
9. The process for treating a charge cracked naphtha as claimed
in claim 1 wherein said charge naphtha is supplemented with higher
(than naphtha) boiling range distillate hydrocarbon feedstocks to
form a mix feed for the process.
10. The process for treating a charge cracked naphtha as claimed
in claim 1 wherein said catalyst contains cobalt as the Group VIII
metal.
11. The process for treating a charge cracked naphtha as claimed
in claim 1 wherein said catalyst contains molybdenum as the Group
VI-B metal.
12. The process for treating a charge cracked naphtha as claimed
in claim 1 wherein said catalyst contains Group VIII metal in amount
of 0.1-15 wt %.
13. The process for treating a charge cracked naphtha as claimed
in claim 1 wherein said catalyst contains Group VI-B metal in amount
of 0.1-40 wt %.
14. The process for treating a charge cracked naphtha as claimed
in claim 1 wherein said "manganese oxide octahedral molecular
sieve" supported catalyst contains (I) 0.1-40 wt. % of at least
one Group VIE metal, (ii) 0.1-15 wt. % of at least one Group VIII
metal; (iii) 0.01-20 wt. % of at least one metal selected from the
group comprising Group I-A, II-A or III B metal, or a lanthanide
series, and (iv) at last one Group I-B metal.
15. The process for treating a charge cracked naphtha as in claim
14 wherein said catalyst contains potassium as the Group II-A metal.
16. The process for treating a charge cracked naphtha as in claim
21 wherein said catalyst contains calcium as the Group I-A metal
and copper as the Group I-B metal.
17. The process for treating a charge cracked naphtha as in claim
14 wherein said catalyst contains copper as the Group I-B metal
in an amount of 0.01-10 wt. %.
Molecular sieve description
FIELD OF THE INVENTION
This invention relates to hydrotreating of cracked naphtha. More
particularly it relates to a process for selectively deep hydrodesulfurizing
a cracked naphtha containing olefins under conditions to minimize
saturation of the olefin content and to a novel selective hydrodesulfurization
catalyst. This invention also relates to novel catalyst compositions
based on octahedral molecular sieves as the catalyst supports, useful
as catalysts for several catalytic reactions, including hydroprocessing
applications.
BACKGROUND OF THE INVENTION
It is well known that air pollution is a serious environmental
problem. A major source of air pollution worldwide is the exhaust
from fuel combusted in hundreds of millions of motor vehicles. Regulations
have been enacted reflecting the need to reduce harmful motor vehicle
emissions through more restrictive fuel standards. Fuels containing
sulfur produce sulfur dioxide and other pollutants which lead to
a host of environmental concerns, such as smog and related health
issues, acid rain leading to deforestation, and water pollution,
as well as a number of other environmental problems. In addition,
the sulfur compounds in the exhaust gases of the automobiles are
detrimental to the efficient functioning of the catalytic converter
in the automobile, leading to increased pollution. To help reduce
or eliminate these environmental problems, the sulfur content of
fuels has been, and will continue to be, restricted to increasingly
smaller concentrations, such as, for example less than 100 or even
50 parts per million (ppm).
The problem of sulfur in fuels is compounded in many areas where
there are diminishing or no domestic sources of crude oil having
relatively low sulfur content. For example, in the United States
the supply of domestic oil production relies increasingly on lower
grade crude oil with higher sulfur content. The need for lower sulfur
content fuel therefore increases demand for imported oil having
lower sulfur content, thereby increasing trade imbalance and vulnerability
due to dependence on foreign sources of oil.
The sulfur content in crude oil can take the form of a wide variety
of both aliphatic and aromatic sulfurous hydrocarbons. Various techniques
have been developed for removing sulfur compounds.
One such technique, called catalytic hydrodesulfurization (HDS),
involves reacting hydrogen with the sulfur compounds in the presence
of a catalyst. The general HDS reaction is illustrated in Equation
1.
In Equation 1 the sulfur compound, RSR', can be: a thiol or mercaptan,
where R is hydrocarbyl and R' is hydrogen; a sulfide or disulfide,
where the sulfur is connected to another sulfur atom in R or R'
hydrocarbyl groups; or can be a thiophene where R and R' are connected
to form a heterocyclic ring. The HDS reaction consumes hydrogen
(H.sub.2) and produces hydrogen sulfide (H.sub.2 S) and hydrocarbons.
The hydrogen sulfide can then be separated to give a petroleum product
in which the sulfur is significantly reduced or substantially eliminated.
HDS is one process within a class of processes known as hydrotreating,
or hydroprocessing, involving the introduction and reaction of hydrogen
with various hydrocarbonaceous compounds. Some of the other reactions
that take place simultaneously during the hydrotreating process
are hydrodenitrogenation (HDN), which is the removal of nitrogen
in the carbonaceous compounds containing nitrogen as ammonia, hydrodeoxygenation
(HDO), which is the removal of oxygen from carbonaceous compounds
containing oxygen as water, and hydrogenation (HYD) of unsaturated
hydrocarbons such as olefins and aromatics.
The hydrotreating reactions can occur simultaneously to various
degrees when sulfur-, oxygen-, and nitrogen-containing and unsaturated
compounds are present in the petroleum. The hydrotreating reactions
are exothermic, producing heat. Such hydrotreatment has been used
to remove not only sulfur, but to also remove nitrogen and other
materials like metals, not only for environmental considerations
but for other reasons, such as to protect catalysts used in subsequent
processing from being poisoned by such elements. See, for example,
Applied Industrial Catalysis, Volume I, edited by B. E. Leach, Academic
Press (1983); Chemistry of Catalytic Processes, by B. C. Gates et
al., McGraw-Hill (1979); and Applied Heterogeneous Catalysis: Design,
Manufacture, and Use of Solid Catalysts, by J. F. LePage et al.,
Technip, Paris (1987).
As is well known to those skilled in the art, cracked naphtha obtained
as a product of a thermal or catalytic cracking operation or a coking
operation may contain a significant concentration of sulfur--up
to as much as 13000 wppm. Though this stream constitutes only 35-40%
of the total gasoline pool, it contributes a substantial quantity
of undesired sulfur to the gasoline pool. The other 60-65% of the
pool typically contains much lower concentrations of sulfur. It
is possible to decrease the sulfur content by (i) hydrotreating
the entire feedstock to the cracking/coker unit or (ii) hydrotreating
the product naphtha from these units.
The first noted alternative is a "brute force" effort
that is very expensive in that it requires a large hydrotreater,
and it consumes significant quantities of hydrogen. The second noted
alternative is a more direct approach, that is to hydrodesulfurize
the cracked naphtha. But unfortunately HDS of cracked naphtha using
standard hydrotreating catalysts under conditions required for sulfur
removal results in undesirable saturation of the olefins typically
originally present in amounts of 20 v %-60 v %, down to levels as
low as 2 v %; and this reduces the octane number (Octane Number
is the average of the Research Octane Number RON and the Motor Octane
Number MON) of the product gasoline by as much as 10 units. This
loss in octane number associated with desulfurization has a significant
impact on the octane number of the refinery gasoline pool. The lower
grade fuel probably also needs more refining, such as isomerization,
reforming, blending, or other refining, to produce higher octane
fuel, adding significantly to production expenses.
Selective HDS to remove sulfur while minimizing hydrogenation of
olefins and octane reduction by various techniques, such as selective
catalysts, has been described in literature. For example, U.S. Pat.
No. 4132632 (Yu et al.) and U.S. Pat. No. 4140626 (Bertolacini
et al.)--both assigned to Standard Oil Company (Indiana), disclose
selective desulfurization of cracked naphthas by using specific
catalysts having particular amounts of Group VI-B and VIII metals
on a magnesia containing support which is at least 70 wt % magnesium
oxide and which may also contain other refractory inorganic oxides
such as alumina, silica, or silica/alumina. U.S. Pat. Nos. 5266188
and 5348928 (Kukes et al.) assigned to Amoco Corporation disclose
the use of novel catalysts comprising a hydrogenation component
and a support component, for selective HDS. The hydrogenation component
of these novel catalysts comprises a Group VI-B metal and a Group
VIII metal, and the support component comprises from about 0.5 wt
% to about 50 wt % of a magnesium component and from about 0.02
wt % to about 10 wt % of an alkali metal component.
U.S. Pat. No. 4334982 of Jacquin et al. assigned to Institut
Francais du Petrole, disclosed the use of catalysts comprising cobalt
and molybdenum or tungsten supported on low surface area, low acidity
oxide supports, the atomic ratio of cobalt to the total metals being
greater than 0.55 in these catalysts, for selectively desulfurizing
hydrocarbon cuts of high olefin content without significant loss
in octane number. Use of alkali or alkaline earth metals in the
catalyst was not suggested.
U.S. Pat. No. 5340466 of Dai et al. assigned to Texaco Inc. discloses
the use of novel catalysts comprising an alkali metal, a metal of
Group VIII, and a metal of Group VI-B on an alumina support containing
hydrotalcite-like composition, for the selective HDS of cracked
naphtha. U.S. Pat. No. 5358633 of Dai et al. assigned to Texaco
Inc. discloses the use of transition alumina bearing Group VIII
metal oxide and a Group VI-B metal oxide as selective HDS catalysts,
the atom ratio of Group VIII metal to Group VI-B metal being 1-8
in these catalysts.
U.S. Pat. No. 5423976 of Sudhakar et al. assigned to Texaco Inc.
discloses the use of a sulfided, carbon supported catalyst bearing
(i) a non-noble Group VIII metal, (ii) a Group VI-B metal, and (iii)
a metal of Group I-A, II-A, III-B, or a lanthanide, for HDS of cracked
naphtha with minimum attendant hydrogenation of olefins that are
present in the naphtha.
U.S. Pat. Nos. 5286373 and 5423975 of Sudhakar et al. assigned
to Texaco Inc. disclose the use of highly deactivated hydrotreating
catalysts and spent resid upgrading catalysts respectively, without
regenerating them, for the selective HDS of cracked naphthas with
minimal olefin saturation and octane loss.
It would be desirable to have an efficient process for removing
sulfur from olefin containing fuel feedstocks, like naphtha. A process
which minimizes loss of octane value using an inexpensive procedure
under a wide range of conditions, would contribute to a cleaner
environment.
It would be especially advantageous if the process was selective
HDS, because it consumes a lower level of hydrogen compared to normal
HDS or hydrotreating operations. This is a result of the low level
of hydrogenation due to low catalytic hydrogenation activity. This
would save not only on the cost of hydrogen but provides improved
operation and control of the HDS reaction due to lower reaction
heat generation compared with using fresh hydrotreating catalyst.
If the process could be operated at lower pressures than standard
HDS reactions, the process would be even more desirable commercially.
It has now been found that catalysts supported on "manganese
oxide octahedral molecular sieves" are highly suited for the
selective hydrodesulfurization of cracked naphthas. It is an object
of this invention to provide a novel catalyst, and process for hydrotreating
a charge cracked naphtha.
It is another object of the present invention to provide a novel
catalyst and process that reduce cracked naphtha diene concentration
significantly.
It is yet another object of the present invention to provide a
novel catalyst and process that yields gasoline of less color and
improved stability.
An additional advantage of the selective HDS of the present invention
is the ability to operate the HDS process at lower pressures than
standard HDS reactions. This provides a significant cost savings.
It is yet another object of the present invention to provide a
novel catalyst composition useful after sulfiding, for hydrodesulfurization
(HDS), hydrodenitrogenation (HDN), hydrodeoxygenation (HDO), hydrodearomatization
(HDAr), hydrogenation (HYD), hydrofining, hydrodemetallization,
mild hydrocracking, and for other hydroprocessing reactions such
as dewaxing, improving the hydrogen to carbon ratio, API gravity,
color etc. of hydrocarbon oils. Catalyst compositions of this invention
are anticipated to be useful for hydroprocessing various hydrocarbon
feedstocks such as naphthas, middle distillates, gas oils, vacuum
gas oils and residua, derived from any source such as petroleum,
coal, oil shale, tar sands, and oil sands.
In the oxidic or reduced state, these catalyst compositions are
anticipated to be useful for several other catalytic reactions including
but not limited to hydrogenation, selective hydrogenation, hydrogen
transfer, oxidation, selective oxidation for example of mercaptans,
reduction, dehydrogenation, oxydehydrognation, oxidative coupling,
synthesis gas reactions including the synthesis of oxygenates, isomerization,
cracking, aromatization, halogenation, dehalogenation, hydrodehalogenation,
hydration and dehydration. In the oxidic or reduced state, these
compositions are also anticipated to be useful as adsorbents, reactive
adsorbents, or selective adsorbents in several applications including
removal of hydrocarbons, sulfur and nitrogen oxides from stack gases,
ozone, toxic chemicals such as phosgene and halogen compounds.
Other objects will be apparent to those skilled in the art.
STATEMENT OF THE INVENTION
In accordance with certain of its aspects this invention is directed
to a process for treating a charge cracked naphtha containing olefinic
components and undesired sulfur which comprises
maintaining a bed of sulfided, "manganese oxide octahedral
molecular sieve" supported catalyst containing intentionally
added (i) a metal of non-noble Group VIII, and (ii) a metal of Group
VI-B, and optionally (iii) a metal of Group I-A, II-A, III-B, or
a lanthanide, and optionally (iv) a metal of Group I-B;
passing a charge cracked naphtha containing olefinic components
and undesired sulfur into contact with said catalyst along with
hydrogen;
maintaining said charge cracked naphtha containing olefinic components
and undesired sulfur in contact with said catalyst and hydrogen
at hydrodesulfurizing conditions thereby effecting hydrodesulfurization
of said charge cracked naphtha containing olefinic components and
undesired sulfur; and
forming a product stream of desulfurized naphtha containing a decreased
content of sulfur; and
recovering said product stream of cracked naphtha containing a
decreased content of sulfur.
DESCRIPTION OF THE INVENTION
The charge hydrocarbon which may be treated by the process of this
invention may include those which are commonly designated as cracked
naphthas and include light cracked naphtha (boiling range of about
C.sub.5 to about 330.degree. F.), a full range cracked naphtha (boiling
range of about C.sub.5 to about 420.degree. F. or higher), heavy
cracked naphtha (boiling range of about 330.degree. F., up to 500.degree.
F.), etc. These hydrocarbons which are in the gasoline boiling range,
are typically recovered from thermal or catalytic cracking or coking
operations and are generally passed to the gasoline pool. Examples
include light, full range and heavy fluid catalytic cracked (FCC)
naphthas, light, full range and heavy coker naphthas, and gasoline
range hydrocarbon fractions from visbreaker operations.
Highly unsaturated hydrocarbon fractions boiling in the range of
gasoline called "pyrolysis gasolines" are produced in
petrochemical plants or refineries. Pyrolysis gasolines contain
significant concentration of olefins, and therefore are suitable
feeds for the selective HDS process of the present invention. The
hydrocarbon fractions called "steam cracking effluents"
which contain significant concentrations of olefins and boil in
gasoline range are also suitable to be treated using the novel catalysts
and process of the present invention.
The cracked naphthas may also be supplemented with higher boiling
range distillate feedstocks to form a mix feed for the process and
catalysts of the present invention. Among the distillate feeds that
are suitable for this purpose include, but are not limited to, light
catalytic gas oils (LCGO), also called light catalytic cycle oils
(LCCO), light coker gas oils (LKGO), straight run kerosine and light
gas oils, etc. After the selective HDS of the mix feed, the naphtha
portion can be separated by distillation, and directed into the
gasoline pool.
The novel catalysts of the present invention may also be advantageously
utilized for selectively hydrodesulfurizing olefin containing naphtha
boiling range hydrocarbon streams which are derived from coal liquefaction,
shale oils, sand oils or any other type of carbonaceous fuels.
The novel catalysts of the present invention may also be advantageously
utilized for hydrodesulfurizing straight run heavy naphtha, and
middle distillate feedstocks such as light gas oils, and light and
heavy kerosines, regardless of the origin of those middle distillates.
For example, light gas oils produced in delayed cokers, fluid catalytic
crackers, mild hydrocrackers, or straight run from crude, can be
hydrodesulfurized using the catalysts of the present invention.
The novel catalysts of the present invention may also be advantageously
utilized for hydrodesulfurization in "blocked operation"
mode. For example, a hydrotreating reactor containing the novel
catalyst of the present invention can be used to selectively desulfurize
cracked naphtha for a certain period of time, then the operation
can be switched to desulfurize a middle distillate such as a light
gas oil for a certain period of time, and then switched back again
to selectively desulfurize cracked naphtha.
The process and the novel catalyst compositions of the present
invention may also be utilized for selectively hydrogenating dienes
to mono-olefins under suitable reaction conditions. Use of these
catalysts for this particular application would be as a guard bed
catalyst in any catalytic process that is affected adversely by
the presence of diene impurities in the feed for that catalytic
process. Examples of such catalytic processes which may benefit
by the novel catalyst compositions of the present invention include
paraffin and olefin isomerization processes, olefin skeletal isomerization
processes, etherification processes which involve reaction of branched
olefin containing streams with alcohols, and the like.
Since a substantial portion of the original olefin content is not
saturated in the selective HDS process of the present invention,
some of these olefins which are left behind react with the hydrogen
sulfide formed in the hydrodesulfurization reaction, to form mercaptans.
This is called a recombination reaction. These mercaptans formed
by the recombination reaction and existing in the product desulfurized
naphtha may be removed or converted to disulfides by subsequently
subjecting the product naphtha to a known mercaptan removal or oxidation
process to remove the mercaptans and obtain a desulfurized naphtha
product of lesser sulfur content. Alternatively, the disulfides
can be left behind in the product if the total sulfur concentration
meets the specifications. There are several mercaptan removal and
oxidation processes, such as the Merox process, known in the literature.
In practice of the process of this invention for selective HDS
of cracked naphtha, the charge cracked naphtha is admitted to the
catalyst bed and maintained therein at the conditions following,
listed in Table 2:
The process of the present invention may be effected in any type
of reactor system such as fixed bed reactor system, ebullated bed
reactor system, fluidized bed reactor system, moving bed, slurry
reactor system, and the like. In the case of the preferred fixed
bed reactor system, the reaction zone may consist of one or more
fixed bed reactors and may comprise a plurality of catalyst beds.
It is preferred to use extrudates, pellets, pills, spheres or granules
of the catalyst in a fixed bed reactor system, preferably under
conditions where substantial feed vaporization occurs. However,
the finished catalysts of the present invention can be in any physical
form described above, as well as powder.
Catalyst Supports:
The support used for making the catalysts of the present invention
is "manganese oxide octahedral molecular sieves (OMS)"
or its precursors, "manganese oxide octahedral layered materials
(OL-1)". The OMS materials use MnO.sub.6 octahedra as the basic
structural unit to form mono-directional tunnel structures. The
synthetic todorokite (OMS-1) and cryptomelane (OMS-2) have (3.times.3)
and (2.times.2) tunnels with pore sizes of 6.9.times.6.9 A and 4.6.times.4.6
.ANG., respectively (FIG. 1). The precursors of OMS, birnessites
or octahedral layered materials (OL-1), consist of layers of edge
and corner linked MnO.sub.6 octahedra with water molecules and metal
cations in the interlayer voids and have an interlayer distance
of 7 to 10 .ANG.. Certain metal cations can incorporate into the
OMS and OL structures through framework, tunnel, and interlayer
substitutions. The framework substitutions of OMS and OL are represented
as [M]-OMS and [M]-OL, while the tunnel and interlayer substitutions
are represented as M-OMS and M-OL, respectively.
OMS-1 have the following composition:
where A is +1 +2 +3 or +4 charged tunnel cations or a combination
of them, 0<a<6; B is +1 +2 +3 or +4 charged framework cations
or a combination of them, 0<b<12 n>0 and characterized
by a specified X-ray powder diffraction pattern.
OMS-2 have the following composition:
where A is +1 +2 +3 or +4 charged tunnel cations or a combination
of them, 0<a<4; B is +1 +2 +3 or +4 charged framework cations
or a combination of them, 0<b<8 n>0 and characterized
by a specified X-ray powder diffraction pattern.
The framework cations can be Mn, Fe, Co, Ni, Cu, Zn, Cd, Mg, and
other elements which can be substituted in the framework; the counter
cations can be Na, K, Cs, Ca, Mg, Sr, and transition metals such
as Ti, V, Cr, Fe, Co, Ni, Cu and Zn. The OMS materials may also
be supported on inert high surface area refractory supports that
are well known to those familiar with the art. These supports include
oxides or hydroxides of Group III or Group IV elements, for example,
alumina, silica, silica-alumina, and clay materials, zirconia, titania,
magnesia, activated carbon, and the like.
The synthesis of OMS-1 has been disclosed in U.S. Pat. No. 5340562.
The metal substituted OMS and OL materials have been disclosed in
U.S. application Ser. No. 08/215496 now abandoned in favor of continuation
U.S. Pat. No. 5702674. The composition of OMS-1 has been disclosed
in U.S. application Ser. No. 08/335154 now U.S. Pat. No. 5545393.
All these are incorporated herein by reference in their entirety.
The support used for making the catalysts of this invention may
exist in any physical form including, but not limited to powder,
pills, granules, pellets, spheres, fibers, monolith, foams, or extrudates.
It may also contain one or more refractory inorganic oxides as minor
components which may arise as a result of using some binding materials
for forming (or shaping) the support material, the total of these
being less than about 20 wt. %.
Catalysts:
The supported catalyst may contain more than one "hydrogenation
suppressor" metal of each Group or it may contain metals from
more than one of the Groups. Alkali metals are the preferred "hydrogenation
suppressor" metals. The metal is typically added as a salt
e.g. sodium acetate, potassium hydroxide, potassium carbonate, K.sub.2
SO.sub.4 magnesium nitrate, La(NO.sub.3).sub.3 potassium sulfide
or polysulfide, or YCl.sub.3 ; and it may be added dry or in the
form of an aqueous or non-aqueous solution or suspension. In general,
any known inorganic, organic or organometallic compounds of the
Group I-A metal can be used as precursors for the Group I-A metal
in the final catalyst. The support which is employed may typically
contain some of these metals e.g. alkali metals such as Na or K,
or Mg, in which case the "hydrogenation suppressor" metal
may not be added deliberately, to prepare the final catalyst.
The "hydrogenation suppressor" is added by deposition
onto the support from aqueous or non-aqueous solutions by any known
deposition technique such as equilibrium adsorption, incipient wetness
impregnation, pore filling, ion exchange, etc. Typically the support
pellet may be impregnated to incipient wetness with an aqueous solution
containing e.g. sodium acetate, potassium acetate, potassium carbonate,
calcium nitrate, etc. and heated in air or inert atmosphere at a
temperature of 100.degree. C.--1000.degree. C.
The so-loaded support may then be further treated to deposit the
remaining catalytic metals, either sequentially or simultaneously,
by various processes known to those skilled in the art, including
ion exchange, pore filling, incipient wetness impregnation, equilibrium
adsorption, etc. from aqueous or non-aqueous media.
Expressed as elemental Group I-B metal, the Group I-B metal can
exist in an amount of 0.01 to 10% by weight of the total catalyst
and preferably about 0.1 to 6% by weight. In general, any known
inorganic, organic or organometallic compounds of the Group I-B
metal can be used as precursors for the Group I-B metal in the final
catalyst. Suitable compounds include, but are not limited to the
nitrate, sulfate, acetate, naphthenate, and chloride of the Group
I-B metal. Copper is the preferred Group I-B metal. The catalyst
may contain more than one of the Group I-B metals.
The Group VI-B metal may be tungsten or more preferably molybdenum--present
in the final catalyst in amount of 0.1-40 wt %, preferably 0.5-30
wt % say 6 wt % for Mo and preferably 15 wt % for W. In general,
any known inorganic, organic or organometallic compounds of the
Group VI-B metal can be used as precursors for the Group VI-B metal
in the final catalyst. Suitable compounds include, but are not limited
to the oxide, acetate, naphthenate, dialkyldithiocarbamate, ammonium
salts such as ammonium heptamolybdate or ammonium metatungstate,
ammonium tetrathiomolybdate, molybdo-and tungsto-phosphoric acids,
carbonyl compounds, and chloride of the Group VI-B metal. Molybdenum
is the preferred Group VI-B metal. The catalyst may contain more
than one of the Group VI-B metals. Compounds such as potassium molybdate
may be used as the precursor for molybdenum, with the added advantage
in this case that the "hydrogenation suppressor" metal
potassium is also incorporated into the catalyst at the same time.
The non-noble Group VIII metal may preferably be nickel Ni or more
preferably cobalt Co--present in the final catalyst in amount of
0.1-15 wt %, preferably 0.1-10 wt %, say 2 wt %. In general, any
known inorganic, organic or organometallic compounds of the Group
VIII metal can be used as precursors for the Group VIII metal in
the final catalyst. Suitable compounds include, but are not limited
to the nitrate, sulfate, acetate, naphthenate, dialkyldithiocarbamate,
ammonium salts, carbonyl compounds, sulfate, sulfamate, and chloride
of the Group VIII metal. Cobalt is the preferred Group VIII metal.
The catalyst may contain more than one of the Group VIII metals.
The Group VI-B metal may be loaded onto the catalyst support from
a preferably aqueous solution of ammonium heptamolybdate or of ammonium
metatungstate. The Group VIII metal may be loaded onto the catalyst
support from a preferably aqueous solution of nickel nitrate or
of cobalt nitrate. However, in general, any known and easily available
inorganic, organic or organometallic compounds of the Group VI-B
and Group VIII metals may be used as precursors for the Group VI-B
and Group VIII metals in the final catalyst.
Though the sequence in which the various metals are deposited on
the support is not critical, it is preferred to deposit the "hydrogenation
suppressor" metal first, followed by the Group VI-B metal,
and thereafter the Group VIII metal together with the Group I-B
metal is deposited, with a drying and preferably calcining steps
in between. In another embodiment, the Group VI-B metal and the
"hydrogenation suppressor" metal is deposited simultaneously
onto the support in a single step from an aqueous or non-aqueous
solution. After the drying or calcining step, the Group VIII metal
and the Group I-B metal are deposited simultaneously onto the support
bearing the Group VI-B metal and the "hydrogenation suppressor"
metal, followed by the final drying or calcining step. In yet another
embodiment, the Group VI-B metal is deposited first, followed by
the Group VIII metal together with the Group I-B metal in the second
step, which is followed by the deposition of the "hydrogenation
suppressor" metal in the final deposition step. All the catalytic
metal components may also be deposited on the support in just one
step. For example, an aqueous solution prepared by dissolving potassium
nitrate, ammonium molybdate, copper (II) nitrate, and cobalt (II)
nitrate in water may be used to deposit the catalytic metals on
the support in just one step. The metals deposited support may then
be dried and optionally calcined.
When aqueous solutions are used to deposit the catalytic metals
either individually or more than one at the same time, the pH values
of the aqueous solutions may be adjusted to desired values before
metals deposition. As is well known to those skilled in the art,
the pH of an aqueous solution containing catalytic metals may need
adjusting to a desired value before it is used for metals deposition
on a catalyst support.
In a preferred embodiment, the support is contacted with an aqueous
solution of potassium carbonate in amount sufficient to fill the
pores to incipient wetness. The so-treated support is dried at 20.degree.
C.-150.degree. C., say 115.degree. C. for 16-24 hours, say 20 hours
followed by calcination in air or inert atmosphere at 200.degree.
C.-650.degree. C., say 250.degree. C., for 2-6 hours, say 3 hours.
The dried product contains say, 2 wt % of K.
Thereafter the support bearing potassium is contacted with an aqueous
solution of Group VI-B metal e.g. ammonium heptamolybdate tetrahydrate
in amount sufficient to fill the pores to incipient wetness. The
material is then dried at 20.degree. C.-150.degree. C., say 115.degree.
C. for 16-24 hours, say 20 hours followed by calcination at 200.degree.
C.-650.degree. C., say 250.degree. C. for 2-6 hours, say 3 hours
in air or inert atmosphere.
Thereafter the support bearing potassium and molybdenum is contacted
with an aqueous solution made up of a Group VIII metal e.g. cobalt
(II) nitrate hexahydrate and a Group I-B metal e.g. copper (II)
nitrate trihydrate in amount sufficient to fill the pores to incipient
wetness. The support bearing the Group I-A metal, Group VI-B metal,
the Group VIII metal, and the Group I-B metal is dried at 20.degree.
C.-150.degree. C., say 115.degree. C. for 16-24 hours, say 20 hours
followed by calcination at 200.degree. C.-650.degree. C., say 300.degree.
C. for 2-6 hours, say 3 hours in air or inert atmosphere.
The desired selective HDS of the charge cracked naphtha according
to this invention is accomplished by use of a catalyst prepared
from a "manganese oxide octahedral molecular sieve" support,
which has deposited thereon 1-40 wt % of Group VI-B metal, 0.1-15
wt % of non-noble Group VIII metal, optionally 0.01-20 wt % of one
or more "hydrogenation suppressor" metals selected from
the group consisting of Group I-A, Group II-A, Group III-B, and
the Lanthanides, and optionally 0.01-10 wt % of Group I-B metal,
based on the final catalyst weight. The catalysts of the present
invention may also contain additional promoters known to those skilled
in the art of hydrotreating, such as phosphorus, boron or fluoride,
at 0.01% to 4% by weight, calculated as elemental phosphorus, boron
or fluorine respectively, based on the final catalyst weight.
The catalytic metals may be deposited on the support, in the form
of inorganic, organic or organometallic compounds of the metals,
either sequentially or simultaneously, by various processes known
in the art including incipient wetness impregnation, equilibrium
adsorption etc., from aqueous or non-aqueous media, or from vapor
phase using volatile compounds of the metals. The catalysts can
also be prepared by solid state synthesis techniques such as, for
example, grinding together the support and the metal compounds in
a single step or in multiple steps, with suitable heat treatments,
followed by subsequent extrusion or pelletizing, drying and calcination.
It is to be noted that in the as-prepared catalysts, the catalytic
metals exist as oxides or as partially decomposed or partially reacted
metal compounds.
Process:
The catalyst, prepared as described, may then be sulfided to a
significant extent, preferably after loading into the hydrodesulfurization
reactor. The catalyst sulfiding may be accomplished using any method
known in the art such as, for example, by heating the catalyst in
a stream of hydrogen sulfide in hydrogen or by flowing an easily
decomposable sulfur compound such as carbon disulfide, di-t-nonylpolysulfide
(TNPS) or dimethyl disulfide with or without a hydrocarbon solvent,
over the catalyst at elevated temperatures up to, but not limited
to 500.degree. C. at atmospheric or higher pressures, in the presence
of hydrogen gas for 2-24 hours, say 3 hours.
Alternatively, the catalyst sulfiding may also be effected by the
sulfur compounds present in the hydrocarbon charge to be hydrotreated.
The catalyst may also be presulfided outside the reactor, suitably
passivated and then loaded into the reactor.
Ex-situ sulfiding may be accomplished using any of the known techniques
described in literature. If sufficient amount of sulfur is incorporated
into the catalyst using one of these ex-situ presulfiding techniques,
activation of the catalyst might be accomplished by heating the
catalyst in hydrogen flow in the reactor itself.
The product of the selective HDS is substantially desulfurized
naphtha retaining high olefins content, and sulfur products consisting
essentially of hydrogen sulfide. Generally, the desulfurized naphtha
has a substantially reduced concentration, generally less than about
20% and preferably less than about 10% of the original thiohydrocarbon
concentration present in the charge naphtha feedstock. The olefin
content in the product desulfurized naphtha is generally at least
about 50 v % and typically about 50-80 v % or higher, of the olefin
content originally present in the naphtha feedstock. The desulfurized
naphtha thereby retains a significant octane value as compared with
the original octane value of the naphtha.
The hydrogen sulfide may be removed from the product desulfurized
naphtha using any effective procedure including those presently
known in the art. Typical sulfur removing procedures include, among
others: gas sparging, such as with hydrogen or nitrogen; caustic
scrubbing; amine treating; sorption; flashing or the like, in addition
to the conventional gas-liquid separation.
Desulfurized naphtha containing very low sulfur content can be
produced by the process of the present invention. Depending upon
the initial sulfur content, feedstock, HDS conditions and other
factors influencing sulfur removal, the desulfurized naphtha will
generally have less than about 300 preferably less than about 200
and most preferably less than about 125 weight parts per million
(wppm) sulfur.
Most of the diolefins and other gum forming components present
in the charge naphtha are also substantially eliminated during the
process of this invention, thereby increasing the storage stability
of the product desulfurized naphtha. In most cases, the product
desulfurized naphtha may be water-white in color.
DESCRIPTION OF PREFERRED EMBODIMENTS
Practice of the process of this invention will be apparent to those
skilled in the art from the following wherein all parts are parts
by weight unless otherwise stated. An asterisk (*) indicates a control
example.
Synthesis of Mg-OMS-1 and [M]-OMS-1 (M=Fe, Cu, Co, and Cr):
The preparation of OMS-1 supports was accomplished as follows:
60 mL of a 5.0M NaOH solution was added dropwise to a vigorously
stirred 40 mL mixture of 0.5M MnCl.sub.2 and 0.1M MgCl.sub.2 to
form suspension in a plastic flask at room temperature. 40 mL of
0.2M KMnO.sub.4 solution was added dropwise to the vigorously stirred
suspension, and the stirring stopped upon completion of this addition.
The plastic flask was sealed and aged at 35.degree. C. for 2 days
before filtration and washing of the solid powder with distilled
deionized water (DDW). The filtration residue was ion-exchanged
by contact with 200 mL of 1.0M MgCl.sub.2 solution overnight at
room temperature, and the exchanged material was filtered and washed
with DDW. The material was transferred to an autoclave along with
some water, and was kept at 150.degree. C. for 2 days. The final
product was filtered and washed, and then dried at 110.degree. C.
overnight. To synthesize substituted [M]-OMS-1 materials, where
M=Fe, Cu, Co, and Cr, the only difference in the preparation followed
was that 8 mL of 0.1M solution of the transition metal salt was
added to the mixture of MnCl.sub.2 and MgCl.sub.2.
Synthesis of K-OMS-2 and [M]-OMS-2 (M=Fe, Ni, and Cu):
The pH of a solution prepared by dissolving 10.14 g of MnSO.sub.4.H.sub.2
O in 120 g H.sub.2 O, was adjusted from 5 to 1 using concentrated
HNO.sub.3. A solution made of 8.8 g of KMnO.sub.4 in 300 g H.sub.2
O was added dropwise to the first solution while stirring in a round
bottom flask equipped with a stirring rod, thermometer, and condenser.
The final pH was readjusted to 1. The mixture was refluxed overnight
(.sup..about. 18 hrs). The solid product was filtered and washed
with water using a Buchner funnel. The final solid product was placed
in an oven to dry overnight at .sup..about. 110.degree. C. The product
contained 56.5% Mn and 4.34% K, and had the OMS-2 structure.
OMS-2 materials doped with Cu, Ni, and Fe were synthesized by refluxing
a mixture of KMnO.sub.4 MnSO.sub.4 and the corresponding metal
nitrates in aqueous solution. A typical preparation was as follows:
5.89 g of KMnO.sub.4 in 10 mL of water was added to a solution of
8.8 g of MnSO.sub.4.H.sub.2 O in 30 mL of water and 3 mL of concentrated
HNO.sub.3. Solutions of CuSO.sub.4 or Fe(NO.sub.3).sub.3 were added
to obtain a total concentration of Cu.sup.2+ or Fe.sup.3+ of 0.01
0.1 and 0.37M. The solutions were refluxed overnight, filtered,
washed, and dried at 110.degree. C. overnight.
EXAMPLE I
In this invention Example, the catalyst was prepared by impregnating
to incipient wetness 17.6 parts of a manganese oxide octahedral
molecular sieve OMS-1 in the form of 20.times.40 mesh particles,
with 7.1 parts of deionized water containing 2.4 parts of ammonium
heptamolybdate.4H.sub.2 O and 0.31 parts of anhydrous potassium
carbonate, at ambient temperature. The particular OMS-1 material
sample used as catalyst support for the catalyst of this example
contained 12.1% by wt. of magnesium and 36.8% by wt. of manganese,
had a B.E.T. (Brunauer-Emmett-Teller) surface area of approximately
35 m.sup.2 /g, and was prepared by following the general procedure
presented above. After heating in air at 130.degree. C. for 85 hours
and cooling to ambient temperature, the material was impregnated
to incipient wetness by contact with 6.5 parts of deionized water
containing 2.0 parts of cobalt (II) nitrate.6H.sub.2 O. The resulting
material was heated in air at 200.degree. C. for 24 hours and was
cooled to ambient temperature. The final catalyst, which we shall
refer to as Catalyst-I, contains nominally 6 wt % Mo, 1 wt % K,
and 2 wt % Co.
EXAMPLE-II* (COMPARATIVE)
In this comparative example, a gamma alumina supported Co-Mo-K
catalyst was prepared as follows:
80 parts of 1/16" gamma alumina extrudates from Engelhard
were impregnated to incipient wetness with a solution made up of
2.5 parts of anhydrous potassium carbonate in 55 parts of deionized
water. After heating in air at 130.degree. C. for 24 hours and cooling
to ambient temperature, 1/2 of the dried material was impregnated
to incipient wetness by contact with an aqueous solution made up
of 3.6 parts of ammonium heptamolybdate.4H.sub.2 O and 13.5 parts
of cobalt (II) nitrate.6H.sub.2 O in 24 parts of deionized water.
The resulting material was heated in air at 200.degree. C. for 65
hours and was cooled to ambient temperature. The final catalyst,
which we shall refer to as Catalyst-II*(Comp), contains nominally
4 wt. % Mo, 2 wt. % K, and 6 wt. % Co.
EXAMPLE-III* (COMPARATIVE)
The catalyst of this comparative example is an alumina supported
Co-Mo catalyst commercially available from Criterion Catalyst Company
under the trade name "Criterion 544SH". It was used after
crushing into 20.times.40 mesh particles. The catalyst possesses
a B.E.T. surface area of 320 m.sup.2 /g, a pore volume of 0.47 cc/g,
and contains 5.3 wt % Mo and 1.7 wt % Co. We shall refer to this
catalyst as Example-III*(Comp).
EXAMPLE-IV* (COMPARATIVE)
A stacked bed of two commercially available alumina supported Co-Mo
catalyst extrudates was the catalyst of this comparative example.
These two catalysts are available from Criterion Catalyst Company
under the trade names "Criterion 444" and "Criterion
447" respectively. The stacked bed is arranged in such a way
that the reactants contact the Criterion 447 catalyst first. The
Criterion 447 catalyst contains 15.5 wt % MoO.sub.3 and 4.5 wt %
CoO. The Criterion 444 catalyst contains 14.5 wt % MoO.sub.3 and
4.0 wt % CoO. We shall refer this stacked bed catalyst system as
Example-IV*(Comp). This stacked bed catalyst system is a highly
recommended catalyst system for "selective hydrodesulfurization"
of cracked naphthas, by conventional means.
CATALYST EVALUATION
The above-described catalysts were evaluated for their HDS and
olefin hydrogenation (HYD) activities in a conventional hydrotreating
reactor system using techniques well known to those familiar with
the art. In a typical experiment, 25 cc of the catalyst was loaded
into a 50 cm long stainless steel hydrotreating reactor of 21 mm
inner diameter. It was heated by a four zone furnace, the temperature
of each zone being controlled independently. A 6.4 mm O.D. stainless
steel thermowell was placed axially throughout the length of the
reactor, facilitating precise measurement of the temperature inside
the catalyst bed at any point.
All the catalysts were presulfided before contacting the cracked
naphtha feed. After purging off of oxygen from the reactor, 200
cc/min of a sulfiding gas consisting of 10 vol % H.sub.2 S in hydrogen
was passed through the catalyst bed for 15 min at room temperature
at 1 atmosphere pressure. With the sulfiding gas flowing, the temperature
of the catalyst bed was increased to 350.degree. C. in about 2 hours,
and kept at the sulfidation temperature of 350.degree. C. for 3
hours. The temperature of the reactor was then lowered to the reaction
temperature, with the sulfiding gas still flowing. At this point,
a back pressure of about 100 psig was applied to the reactor, and
the cracked naphtha flow was started at the desired flow rate. Once
the liquid passes beyond the catalyst bed, the flow of the sulfiding
gas was cut off, the flow of pure hydrogen gas was started at the
desired rate, and the reactor pressure was increased to 300 psig.
The actual hydrotreating reaction was considered to have started
at this point in time. The reactor effluent was condensed by passing
it through a condenser maintained at about 5.degree. C. in front
of a high pressure gas liquid separator.
For each reaction condition, after about 20 hours on stream, 3
liquid product samples were collected for analysis at one hour intervals.
It was found be sufficient to attain steady state activities under
the reaction conditions employed. One large sample was also collected
for measuring the octane numbers of the hydrotreated product at
5-8 hours on stream.
The catalysts were evaluated for processing two batches of full
range fluid catalytic cracked naphtha having the properties and
composition shown in Table 4. The boiling point distributions for
these two naphthas were essentially same. Even though full range
FC cracked naphtha was used to show the advantages of this invention,
as described earlier, the present invention is applicable for processing
other kinds of naphthas such as coker naphthas, and in general is
applicable for any naphthas which contain >5 v % olefin concentration.
chnique ASTM D2622. The product samples were carefully sparged
ultrasonically at about 5.degree. C. to remove the dissolved H.sub.2
S prior to the XRF measurement. The concentration of olefins as
volume % in the feed and product samples were measured by PIONA
(Paraffins, Isoparaffins, Olefins, Naphthenes, Aromatics) technique
using Gas Chromatography. The PIONA technique is widely used in
the petroleum industry for this purpose.
The experimental results of various catalyst evaluations for the
hydrodesulfurization of full range fluid catalytic (FC) cracked
naphtha which distinguish the present invention from prior art are
recorded in Table 5. Presented in Table 5 are the catalyst number
and description, temperature of the catalyst bed in .degree.C.,
product sulfur concentration in wppm (parts per million by weight),
% HDS (hydrodesulfurization), % HYD (olefins hydrogenated) during
the catalytic process, and the "Selectivity Factor", defined
as the ratio of Log[fraction sulfur remaining] to Log[fraction olefins
remaining], which is a function of % HDS level. The selectivity
factors of different catalysts must be compared at same or similar
% HDS level, in order to rank them for their selectivity for the
selective HDS of cracked naphtha. The larger the selectivity factor,
the better the catalyst is for minimizing olefin saturation and
therefore for minimizing the octane loss in the process.
A careful observation of the results presented in Table 5 reveal
the following:
1. The manganese oxide octahedral molecular sieve supported catalyst
of the present invention is a highly selective catalyst for the
"selective hydrodesulfurization" of cracked naphtha with
attendant minimum olefin saturation. It is significantly more selective
than the commercially available conventional alumina supported Co-Mo
catalysts, or experimental alumina supported Co-Mo-K catalysts.
Significantly lower olefin saturation translates into significantly
lower octane loss in the catalytic HDS process for desulfurizing
cracked naphthas.
2. Though the catalyst of the present invention is slightly less
active for HDS compared to the conventional catalysts, its HDS activity
is more than adequate for most applications.
3. At the present time, the Best Mode seems to be that of Example
I for the selective HDS of fluid catalytic cracked naphtha.
Although this invention has been illustrated by reference to specific
embodiments, it will be apparent to those skilled in the art that
various changes and modifications may be made which clearly fall
within the scope of the invention. |