Note: Descriptions are shown in the official language in which they were submitted.
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SELECTIVE NAPHTHA HYDRODESULFURIZATION WITH HIGH
TEMPERATURE MERCAPTAN DECOMPOSITION
FIELD OF THE INVENTION
[0001] The present invention relates to a multistage process for the
selective
hydrodesulfurization and mercaptan removal of an olefinic naphtha stream
containing a substantial amount of organically bound sulfur and olefins.
BACKGROUND OF THE INVENTION
[0002] Environmentally driven regulatory pressure concerning motor
gasoline ("mogas") sulfur levels have resulted in the widespread production of
less than 50 wppm sulfur mogas in 2004, and levels below 10 wppm are being
considered for later years. In general, this will require deep desulfurization
of
refinery naphtha streams. The largest target of naphtha streams for such
processes are those resulting from cracking operations, particularly those
from a
fluidized catalytic cracking unit which comprise a large volume of the
available
refinery blending stock as well as generally higher sulfur content than the
"non-
cracked" refinery naphtha streams. Naphthas from a fluidized catalytic
cracking
unit ("cat naphthas") typically contain substantial amounts of both sulfur and
olefins. Deep desulfurization of cat naphtha requires improved technology to
reduce sulfur levels without the severe loss of octane that accompanies the
undesirable hydrogenation of olefins.
[0003] Hydrodesulfurization is one of the fundamental hydrotreating
processes of refining and petrochemical industries. The removal of feed
organically bound sulfur by conversion to hydrogen sulfide is typically
achieved
by reaction with hydrogen over non-noble metal sulfided supported and
unsupported catalysts, especially those containing Co/Mo or Ni/Mo. This is
usually achieved at fairly severe temperatures and pressures in order to meet
product quality specifications, or to supply a desulfurized stream to a
subsequent
sulfur sensitive process.
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[0004] Olefinic naphthas, such as cracked naphthas and coker naphthas,
typically contain more than about 20 wt.% olefins. Conventional fresh
hydrodesulfurization catalysts have both hydrogenation and desulfurization
activity. Hydrodesulfurization of cracked naphthas using conventional naphtha
desulfurization catalysts under conventional startup procedures and under
conventional conditions required for sulfur removal, typically leads to an
undesirable loss of olefins through hydrogenation. Since olefins are high
octane
components, it is desirable to retain the olefins rather than to hydrogenate
them to
saturated compounds that are typically lower in octane. This results in a
lower
grade fuel product that needs additional refining, such as isometization,
blending,
etc., to produce higher octane fuels. Such additional refming, or course, adds
significantly to production costs.
[0005] Selective hydrodesulfurization to remove organically bound sulfur,
while minimizing hydrogenation of olefins and octane reduction by various
techniques, such as selective catalysts and/or process conditions, has been
described in the art. For example, a process referred to as SCANfining has
been
developed by ExxonMobil Corporation in which olefinic naphthas are
selectively desulfurized with little loss in octane. U.S. Patent Nos.
5,985,136;
6,013,598; and 6,126,814, disclose various aspects of SCANfining. Although
selective
hydrodesulfurization processes have been developed to avoid significant olefin
saturation and loss of octane, such processes have a tendency to liberate H2S
that
reacts with retained olefins to form mercaptan sulfur by reversion.
[0006] As these refinery hydrodesulfurization catalytic processes are
operated at greater severities to meet the lower sulfur specifications on
products,
the H2S content in the process streams increases, resulting in higher
saturation of
olefins and reversion to mercaptan sulfur compounds in the products.
Therefore,
the industry has sought for methods to increase the desulfurization efficiency
of
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a process while reducing or eliminating the amount of reversion of mercaptan
sulfur compounds in the final product.
[0007] Many refiners are considering combinations of available sulfur
removal technologies in order to optimize economic objectives. As refiners
have
sought to minimize capital investment to meet low sulfur mogas objectives,
technology providers have devised various strategies that include distillation
of
the cracked naphtha into various fractions that are best suited to individual
sulfur
removal technologies. While economics of such strategies may appear favorable
compared to a single processing technology, the complexity of overall refinery
operations is increased and successful mogas production is dependent upon
numerous critical sulfur removal operations. Economically competitive sulfur
removal strategies that minimize olefin saturation and minimize the production
of mercaptan sulfur compounds in the products, as well as decrease the
required
capital investment and operational complexity will be favored by refiners.
[0008] Consequently, there is a need in the art for technology that will
reduce the cost and complexity of hydrotreating olefinic naphthas to low
levels
of sulfur content while either reducing the amount of mercaptans formed or by
providing an economical process to destroy the mercaptans that are formed as a
resultant of the hydrotreating process. There is a need in the industry for a
process to reduce these product mercaptan levels while meeting higher sulfur
reduction specifications, minimizing the saturation of olefins, and reducing
the
loss of octane in the final product.
SUMMARY OF THE INVENTION
[0009] In accordance with the present invention, there is provided a
process
for hydrodesulfiirizing olefinic naphtha feedstream and retaining a
substantial
amount of the olefins, which feedstream boils in the range of about 50 F (10
C)
to about 450 F (232 C) and contains organically bound sulfur and an olefin
content of at least about 5 wt.%, which process comprises:
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a) hydrodesulfurizing the olefinic naphtha feedstream in a first
reaction stage in the presence of a hydrogen-containing treat gas and a
hydrodesulfurization catalyst, at first hydrodesulfurization reaction
conditions
including temperatures from about 450 F (232 C) to about 800 F (427 C),
pressures of about 60 to about 800 psig, and hydrogen-containing treat gas
rates
of about 1000 to about 6000 standard cubic feet per barrel, to convert a
portion
of the elemental and organically bound sulfur in said olefinic naphtha
feedstream
to hydrogen sulfide to produce a first reactor effluent stream which has a
reduced total sulfur content;
b) conducting said first reactor effluent stream to an H2S removal
zone wherein a stripping agent, such as steam or an amine solution, is
utilized to
remove substantially all of the H2S from said first reactor effluent stream to
produce a stripped effluent stream;
c) conducting said stripped effluent stream to a second reaction
stage in the presence of a hydrogen-containing treat gas and a
hydrodesulfurization catalyst, at second hydrodesulfurization reaction
conditions
including temperatures from about 450 F (232 C) to about 800 F (427 C),
pressures of about 60 to about 800 psig, and hydrogen-containing treat gas
rates
of about 1000 to about 6000 standard cubic feet per barrel, to convert a
potion of
the remaining elemental and organically bound sulfur in said stripped effluent
stream to hydrogen sulfide to produce a second reactor effluent stream which
has
a reduced total sulfur content; and
d) conducting said second reactor effluent stream to a mercaptan
decomposition reaction stage in the presence a mercaptan decomposition
catalyst, at reaction conditions including temperatures from about 500 F (260
C)
to about 800 F (427 C), and pressures of about 60 to about 800 psig, to
decompose at least a portion of the mercaptans to produce a mercaptan
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decomposition reactor product with a lower mercaptan sulfur content than that
of
said second reactor effluent stream.
[0010] In a
second embodiment of the present invention, there is provided a
process for hydrodesulfurizing olefinic naphtha feedstream and retaining a
substantial amount of the olefins, which feedstream boils in the range of
about
50 F (10 C) to about 450 F (232 C) and contains organically bound sulfur and
an olefin content of at least about 5 wt.%, which process comprises:
a) hydrodesulfurizing the olefinic naphtha feedstream in a first
reaction stage in the presence of a hydrogen-containing treat gas and a
hydrodesulfurization catalyst, at first hydrodesulfurization reaction
conditions
including temperatures from about 450 F (232 C) to about 800 F (427 C),
pressures of about 60 to about 800 psig, and hydrogen-containing treat gas
rates
of about 1000 to about 6000 standard cubic feet per barrel, to convert a
portion
of the organically bound sulfur to hydrogen sulfide to produce a first reactor
effluent stream which has a reduced total sulfur content;
b) conducting said first reactor effluent stream to an H2S removal
zone wherein a stripping agent, such as steam or an amine solution, is
utilized to
remove substantially all of the H2S from said first reactor effluent stream to
produce a stripped effluent stream;
c) conducting said stripped effluent stream to a mercaptan
decomposition reaction stage in the presence of a hydrogen-containing treat
gas
and a mercaptan decomposition catalyst, at reaction conditions including
temperatures from about 500 F (260 C) to about 800 F (427 C), pressures of
about 60 to about 80 psig, and hydrogen-containing treat gas rates of about
1000
to about 6000 standard cubic feet per barrel, to convert at least a portion of
the
non-mercaptan organic and elemental sulfur compounds and decompose at least
a portion of the mercaptans to produce a mercaptan decomposition reactor
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product with a lower mercaptan sulfur content than that of said first reactor
effluent stream.
[0011] In a preferred embodiment, the feedstreams to the
hydrodesulfurization reactor and mercaptan decomposition stages will be in the
vapor phase.
[0012] In another preferred embodiment, a portion of the hydrogen-
containing treat gas to said first, second and mercaptan decomposition
reaction
stages is comprised of a portion of the gas removed from said first reactor
effluent stream in said H2S removal zone.
[0013] In still another preferred embodiment, the heat from at least a
portion of said first reactor effluent is utilized to heat at least a portion
of said
olefinic naphtha feedstream prior to contact with said first reaction stage.
[0014] In still another preferred embodiment, the heat from at least a
portion of said mercaptan decomposition reactor product is utilized to heat at
least a portion of said olefinic naphtha feedstream prior to contact with said
first
reaction stage.
[0015] In still another preferred embodiment, the total sulfur content of
said
mercaptan decomposition reactor product stream is less than about 1 wt.% of
the
total sulfur content of said olefinic naphtha feedstream.
[0016] In still another preferred embodiment, the mercaptan sulfur content
of said mercaptan decomposition reactor product stream is less than about 10
wt.% of the mercaptan sulfur content of said first reactor effluent stream.
BRIEF DESCRIPTION OF THE DRAWINGS
[0017] FIGURE 1 depicts a first preferred process scheme for practicing the
present invention, wherein the olefinic naphtha feedstream is subjected to two
hydrodesulfurization reaction stages with an intermediate H2S removal step
which is then followed by a final mercaptan decomposition reaction stage.
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[0018] FIGURE 2 depicts a second preferred process scheme for practicing
the present invention, wherein the olefinic naphtha feedstream is subjected to
one hydrodesulfurization reaction stage followed by an H2S removal step which
is then followed by a final mercaptan decomposition reaction stage.
DETAILED DESCRIPTION OF THE INVENTION
[0019] Feedstocks suitable for use in the present invention are olefinic
naphtha boiling range refinery streams that typically boil in the range of
about
50 F (10 C) to about 450 F (232 C). The term "olefinic naphtha stream" as
used herein are those naphtha streams having an olefin content of at least
about 5
wt.%. Non-limiting examples of olefinic naphtha streams include fluid
catalytic
cracking unit naphtha (FCC catalytic naphtha or cat naphtha), steam cracked
naphtha, and coker naphtha. Also included are blends of olefinic naphthas with
non-olefinic naphthas as long as the blend has an olefin content of at least
about
wt.%.
[0020] Olefinic naphtha refinery streams generally contain not only
paraffins, naphthenes, and aromatics, but also unsaturates, such as open-chain
and cyclic olefins, dienes, and cyclic hydrocarbons with olefinic side chains.
The olefinic naphtha feedstock can contain an overall olefins concentration
ranging as high as about 60 wt.%, more typically as high as about 50 wt.%, and
most typically from about 5 wt.% to about 40 wt.%. The olefinic naphtha
feedstock can also have a diene concentration up to about 15 wt.%, but more
typically less than about 5 wt.% based on the total weight of the feedstock.
High
diene concentrations are undesirable since they can result in a gasoline
product
having poor stability and color. The sulfur content of the olefinic naphtha
will
generally range from about 300 wppm to about 7000 wppm, more typically from
about 1000 wppm to about 6000 wppm, and most typically from about 1500 to
about 5000 wppm. The sulfur will typically be present as organically bound
sulfur. That is, as sulfur compounds such as simple aliphatic, naphthenic, and
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aromatic mercaptans, sulfides, di- and polysulfides and the like. Other
organically bound sulfur compounds include the class of heterocyclic sulfur
compounds such as thiophene and its higher homologs and analogs. Nitrogen
will also be present and will usually range from about 5 wppm to about 500
wppm.
[0021] As previously mentioned, it is highly desirable to remove sulfur
from olefinic naphthas with as little olefin saturation as possible. It is
also
highly desirable to convert as much as possible of the organic sulfur species
of
the naphtha to hydrogen sulfide with as little mercaptan reversion as
possible.
The level of mercaptans in the product stream has been found to be directly
proportional to the concentration of both hydrogen sulfide and olefinic
species at
the hydroconversion reactor outlet, and inversely related to the temperature
at
the reactor outlet.
[0022] Figure 1 is a simple flow scheme of the first preferred embodiment
for practicing the present invention. Various ancillary equipment, such as
compressors, pumps, heat exchangers and valves is not shown for simplicity
reasons.
[0023] In this first embodiment, an olefinic naphtha feed (1) and a
hydrogen-containing treat gas stream (2) are contacted with a catalyst in a
first
hydrodesulfurization reaction stage (3) that is preferably operated in
selective
hydrodesulfurization conditions that will vary as a function of the
concentration
and types of organically bound sulfur species of the feedstream. By "selective
hydrodesulfurization" we mean that the hydrodesulfurization reaction stage is
operated in a manner to achieve as high a level of sulfur removal as possible
with as low a level of olefin saturation as possible. It is also operated to
avoid as
much mercaptan reversion as possible. Generally, hydrodesulfurization
conditions for both of the hydrodesulfurization reaction stages include:
temperatures from about 450 F (232 C) to about 800 F (427 C), preferably from
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about 500 F (260 C) to about 675 F (357 C); pressures from about 60 to about
800 psig, preferably from about 200 to about 500 psig, more preferably from
about 250 to about 400 psig; hydrogen feed rates of about 1000 to about 6000
standard cubic feet per barrel (scf/b), preferably from about 1000 to about
3000
scf/b; and liquid hourly space velocities of about 0.5 hfl to about 15 hfl,
preferably from about 0.5 hfito about 10 hfl, more preferably from about 1 hr-
1
to about 5 hr. It is preferred that the feedstream to the first and second
reaction
stages as well as the mercaptan destruction reaction stage be in the vapor
stage
when contacting the catalyst. The terms "hydrotreating" and
"hydrodesulfurization" are sometimes used interchangeably herein.
[0024] This first hydrodesulfurization reaction stage can be comprised of
one or more fixed bed reactors each of which can comprise one or more catalyst
beds of the same, or different, hydrodesulfurization catalyst. Although other
types of catalyst beds can be used, fixed beds are preferred. Non-limiting
examples of such other types of catalyst beds that may be used in the practice
of
the present invention include fluidized beds, ebullating beds, slurry beds,
and
moving beds. Interstage cooling between reactors, or between catalyst beds in
the same reactor, can be employed since some olefin saturation can take place,
and olefin saturation as well as the desulfurization reaction are generally
exothermic. A portion of the heat generated during hydrodesulfurization can be
recovered by conventional techniques. Where this heat recovery option is not
available, conventional cooling may be performed through cooling utilities
such
as cooling water or air, or by use of a hydrogen quench stream. In this
manner,
optimum reaction temperatures can be more easily maintained. It is preferred
that the first hydrodesulfurization stage be configured in a manner and
operated
under hydrodesulfurization conditions such that from about 40% to 100%, more
preferably from about 60% to about 95% of the total targeted sulfur removal is
reached in the first hydrodesulfurization stage.
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[0025] Preferred hydrotreating catalysts for use in both the first and
second
hydrodesulfurization reaction stages are those that are comprised of at least
one
Group VIII metal oxide, preferably an oxide of a metal selected from Fe, Co
and
Ni, more preferably selected from Co and/or Ni, and most preferably Co; and at
least one Group VI metal oxide, preferably an oxide of a metal selected from
Mo
and W, more preferably Mo, on a high surface area support material, preferably
alumina. Other suitable hydrotreating catalysts include zeolitic catalysts, as
well
as noble metal catalysts where the noble metal is selected from Pd and Pt. It
is
within the scope of the present invention that more than one type of
hydrotreating catalyst be used in the same reaction vessel. The Group VIII
metal
oxide of the first hydrodesulfurization catalyst is typically present in an
amount
ranging from about 0.1 to about 20 wt.%, preferably from about 1 to about 12%.
The Group VI metal oxide will typically be present in an amount ranging from
about 1 to about 50 wt.%, preferably from about 2 to about 20 wt.%. All metal
oxide weight percents are on support. By "on support" we mean that the
percents are based on the weight of the support. For example, if the support
were to weigh 100 g. then 20 wt.% Group VIII metal oxide would mean that 20
g. of Group VIII metal oxide is on the support.
[0026] Preferred catalysts for both the first and second
hydrodesulfurization
stage will also have a high degree of metal sulfide edge plane area as
measured
by the Oxygen Chemisorption Test as described in "Structure and Properties of
Molybdenum Sulfide: Correlation of 02 Chemisorption with
Hydrodesulfurization Activity," Si. Tauster et al., Journal of Catalysis 63,
pp.
515-519 (1980). The Oxygen Chemisorption Test involves edge-plane area
measurements made wherein pulses of oxygen are added to a carrier gas stream
and thus rapidly traverse the catalyst bed. For example, the oxygen
chemisorption will be from about 800 to 2,800, preferably from about 1,000 to
2,200, and more preferably from about 1,200 to 2,0001.tmol oxygen/gram
Mo03.
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[0027] The most preferred catalysts for the first and second
hydrodesulfurization zone can be characterized by the properties: (a) a Mo03
concentration of about 1 to 25 wt.%, preferably about 2 to 18 wt.%, and more
preferably about 4 to 10 wt.%, and most preferably 4 to 8 wt.%, based on the
total weight of the catalyst; (b) a Co0 concentration of about 0.1 to 6 wt.%,
preferably about 0.5 to 5.5 wt.%, and more preferably about 1 to 5 wt.%, also
based on the total weight of the catalyst; (c) a Co/Mo atomic ratio of about
0.1 to
about 1.0, preferably from about 0.20 to about 0.80, more preferably from
about
0.25 to about 0.72; (d) a median pore diameter of about 60 A to about 200 A,
preferably from about 75 A to about 175 A, and more preferably from about 80
A to about 150 A; (e) a Mo03 surface concentration of about 0.5 x 104 to about
3 x 104 g Mo03/m2, preferably about 0.75 x 10-4 to about 2.5 x 104 g Mo03/m2,
more preferably from about 1 x 104 to 2 x 104 g Mo03/m2; and (f) an average
particle size diameter of less than 2.0 mm, preferably less than about 1.6 mm,
more preferably less than about 1.4 mm, and most preferably as small as
practical for a commercial hydrodesulfurization process unit.
[0028] The hydrodesulfurization catalysts used in the practice of the
present
invention are preferably supported catalysts. Any suitable refractory catalyst
support material, preferably inorganic oxide support materials, can be used as
supports for the catalyst of the present invention. Non-limiting examples of
suitable support materials include: zeolites, alumina, silica, titania,
calcium
oxide, strontium oxide, barium oxide, carbons, zirconia, diatomaceous earth,
lanthanide oxides including cerium oxide, lanthanum oxide, neodynium oxide,
yttrium oxide, and praesodymium oxide; chromia, thorium oxide, urania, niobia,
tantala, tin oxide, zinc oxide, and aluminum phosphate. Preferred are alumina,
silica, and silica-alumina. More preferred is alumina. Magnesia can also be
used for the catalysts with a high degree of metal sulfide edge plane area of
the
present invention. It is to be understood that the support material can also
contain small amounts of contaminants, such as Fe, sulfates, silica, and
various
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metal oxides that can be introduced during the preparation of the support
material. These contaminants are present in the raw materials used to prepare
the
support and will preferably be present in amounts less than about 1 wt.%,
based
on the total weight of the support. It is more preferred that the support
material
be substantially free of such contaminants. It is an embodiment of the present
invention that about 0 to 5 wt.%, preferably from about 0.5 to 4 wt.%, and
more
preferably from about 1 to 3 wt.%, of an additive be present in the support,
which additive is selected from the group consisting of phosphorus and metals
or
metal oxides from Group IA (alkali metals) of the Periodic Table of the
Elements.
[0029] Returning now to the Figure 1 hereof, the total effluent product
from
the first hydrodesulfurization reaction stage (4) is conducted to an H2S
removal
zone (6). In this zone, a stripping agent such as a steam or an amine solution
(5)
is contacted with the first reactor effluent to remove substantially all of
the H2S
from the effluent stream (7). This H2S removal zone operates at substantially
the
same pressure as the first hydrodesulfurization reaction stage pressure. The
H2S
stripped product stream (8) from the H2S removal zone and a hydrogen-
containing treat gas (9) is then contacted with a catalyst in a second
hydrodesulfurization reaction stage (10) that is also preferably operated at
selective hydrodesulfurization conditions. Generally, the hydrodesulfurization
conditions of the second stage reaction include similar temperature ranges,
pressure ranges, treat gas ranges, liquid hourly space velocities ranges,
catalyst
properties, catalyst characteristics and catalyst compositions, reactor
configurations, and heat recovery configurations as described for the first
reaction stage above. The reactor effluent (11) from the second reaction stage
is
then contacted with a catalyst in a mercaptan decomposition reaction stage
(12).
[0030] This mercaptan decomposition reaction stage can be comprised of
one or more fixed bed reactors, each of which can comprise one or more
catalyst
beds of the same, or different, mercaptan decomposition catalyst. Although
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other types of catalyst beds can be used, fixed beds are preferred. Non-
limiting
examples of such other types of catalyst beds that may be used in the practice
of
the present invention include fluidized beds, ebullating beds, slurry beds,
and
moving beds. The mercaptan decomposition catalysts suitable for use in this
invention are those which contain a material that catalyzes the mercaptan
reversal back to H2S and olefins. Suitable mercaptan decomposition catalytic
materials for this process include refractory metal oxides resistant to sulfur
and
hydrogen at high temperatures and which possess substantially no hydrogenation
activity. Catalytic materials which possess substantially no hydrogenation
activity are those which have virtually no tendency to promote the saturation
or
partial saturation of any non-saturated hydrocarbon molecules, such as
aromatics
and olefins, in a feedstream under mercaptan decomposition reaction stage
conditions as disclosed in this invention. These catalytic materials
specifically
exclude catalysts containing metals, metal oxides, or metal sulfides of the
Group
V, VI, or VIII elements, including but not limited to V. Nb, Ta, Cr, Mo, W,
Fe,
Ru, Co, Rh, Ir, Ni, Pd, and Pt. Illustrative, but non-limiting, examples of
suitable catalytic materials for the mercaptan decomposition reaction process
of
this invention include materials such as alumina, silica, both crystalline and
amorphous silica-alumina, aluminum phosphates, titania, magnesium oxide,
alkali and alkaline earth metal oxides, alkaline metal oxides, magnesium oxide
supported on alumina, faujasite that has been ion exchanged with sodium to
remove the acidity and ammonium ion treated aluminum phosphate.
[0031] Generally, the mercaptan decomposition reaction stage conditions
include: temperatures from about 500 F (260 C) to about 800 F (427 C),
preferably from about 550 F (288 C) to about 700 F (371 C); pressures from
about 60 to about 800 psig, preferably from about 150 to about 500 psig;
hydrogen feed rates of about 1000 to about 6000 standard cubic feet per barrel
(scf/b), preferably from about 1000 to about 3000 scf/b; and liquid hourly
space
velocities of about 0.5 hfl to about 15 hfl, preferably from about 0.5 hfl to
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about 10 hfl, more preferably from about 1 hfl to about 5 hfl. In this
mercaptan decomposition reaction stage, organic and elemental sulfur
compounds and mercaptan sulfur compounds are converted with a minimal
amount of olefin saturation resulting in a final product stream (13) with
properties of a reduced organic and elemental sulfur content, reduced
mercaptan
content and minimal octane reduction.
[0032] Figure 2 is a simple flow scheme depicting a second preferred
embodiment for practicing the present invention. Again, various ancillary
equipment, such as compressors, pumps, heat exchangers and valves are not
shown for simplicity reasons.
[0033] In this second embodiment, an olefinic naphtha feed (1) and a
hydrogen-containing treat gas stream (2) are contacted with a catalyst in a
first
hydrodesulfurization reaction stage (3) that is preferably operated in
selective
hydrodesulfurization conditions that will vary as a function of the
concentration
and types of organically bound sulfur species of the feedstream. Generally,
the
hydrodesulfurization conditions of the first reaction stage in Figure 2
utilizes
similar temperature ranges, pressure ranges, treat gas ranges, liquid hourly
space
velocities ranges, catalyst properties, catalyst characteristics and catalyst
compositions, reactor configurations, and heat recovery configurations as
described for the first reaction stage in Figure 1, above. The total effluent
product from the first hydrodesulfurization reaction stage (4) is conducted to
an
H2S removal zone (6). In this zone, a compound such as a steam or an amine
solution (5) is contacted with the first reactor effluent to substantially
remove all
of the H2S from the effluent stream (7). This H2S removal zone operates at
substantially the same pressure as the first hydrodesulfurization reaction
stage
pressure. The H2S stripped product stream (8) from the H2S removal zone and a
hydrogen-containing treat gas (9) is then contacted with a catalyst in a
mercaptan
decomposition reaction stage (10).
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[0034] The mercaptan decomposition conditions of the mercaptan
decomposition reaction stage in this configuration (see Figure 2) are the same
as
described for the mercaptan decomposition reaction stage in the first
embodiment, above (see Figure 1 and associated detailed description). The
mercaptan decomposition reaction conditions include similar temperature
ranges, pressure ranges, treat gas ranges, liquid hourly space velocities
ranges,
catalyst properties, catalyst characteristics and catalyst compositions,
reactor
configurations, and heat recovery configurations as described for the
mercaptan
decomposition reaction conditions described in the first embodiment, above
(see
Figure 1 and associated detailed description). In this mercaptan decomposition
reaction stage, organic and elemental sulfur compounds and mercaptan sulfur
compounds are converted with a minimal amount of olefin saturation resulting
in
a final product stream (11) with properties of a reduced organic and elemental
sulfur content, reduced mercaptan content and minimal octane reduction.
[0035] The following examples are presented to illustrate the invention.
Example 1
[0036] In this example, the process configuration utilized is shown in
Figure 1. The hydrogen treat gas rates, shown as streams (2) and (9) in Figure
1, are 2,000 standard cubic feet per barrel (scf/b). The amount of H2S removal
in the H2S reaction zone (6) is modeled utilizing an H2S removal step to
remove
free and dissolved H2S from the process stream at the first
hydrodesulfurization
reaction pressures (327 psig). Any stripping agent utilized in the art to
facilitate
H2S removal, such as steam or an amine solution, can be utilized and is shown
as
stream (5). The H2S or H2S rich compound is then removed from the process via
stream (7). The conditions and resulting product qualities are predicted based
on a kinetic model developed from a pilot plant database are shown in Tables 1
and 2 below.
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Table 1
1st MS 2nd HDS Mercaptan Removal
Stage Stage Stage
(3) (10) (12)
Temperature ( T) 535 525 625
Pressure (psig) 327 327 327
Table 2
Olefinic First Stripped Second Reactor Third
Reactor
Feedstream Reactor Effluent Effluent Stream Product
Stream
= Effluent Stream
(1) Stream (8) (11) (13)
(4)
Sulfur (wppm) 1900 180 180 14 10
Mercaptan 76 76 9 5
(wPPm)
Bromine No. 67.0 55.6 55.6 44.3 44.0
(cg/g)
RON 92.0 87.7
MON 80.0 78.5
This process will result in a total hydrodesulfurization of 99.5% with an
overall
RON loss of 4.3 and MON loss of 1.5. By comparison, a similar design utilizing
two BIDS reactors and no mercaptan removal would result in a RON loss of 5.0
and a MON loss of 1.8.
Example 2
[0037] In this example, the process configuration utilized is shown in
Figure 2. The hydrogen treat gas rates, shown as streams (2) and (9) in Figure
2, are 2,000 standard cubic feet per barrel (scf/b). The amount of H25 removal
in the H2S reaction zone (6) is modeled utilizing an H2S removal step to
remove
free and dissolved H25 from the process stream at the hydrodesulfurization
reaction pressures (327 psig). Any stripping agent utilized in the art to
facilitate
H25 removal, such as steam or an amine solution, can be utilized and is shown
as
stream (5). The H25 or H25 rich compound is then removed from the process via
stream (7). The conditions and resulting product qualities are predicted based
on a kinetic model developed from a pilot plant database are shown in Tables 3
and 4 below.
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Table 3
1st HDS Mercaptan Removal
Stage Stage
(3) (12)
Temperature ( F) 535 625
Pressure (psig) 327 327
Table 4
Olefinic First Reactor Stripped Second Reactor
Feedstream Effluent Effluent Product Stream
Stream Stream
(1) (4) (8) (11)
Sulfur (wppm) 1900 62 62 10
Mercaptan (vvppm) 55 55 3
Bromine No. (cg/g) 67.0 46.3 46.3 46.3
RON 92.0 88.3
MON 80.0 78.7
This process will result in a total hydrodesulfurization of 99.5% with an
overall
RON loss of 3.7 and MON loss of 1.3. By comparison, a similar design utilizing
two HDS reactors and no mercaptan removal would result in a RON loss of 5.0
and a MON loss of 1.8.
