U.S. patent application number 11/286580 was filed with the patent office on 2007-05-24 for selective naphtha hydrodesulfurization with high temperature mercaptan decomposition.
Invention is credited to Jeffrey M. Dysard, Edward S. Ellis, John P. Greeley, Thomas R. Halbert, William J. III Tracy.
Application Number | 20070114156 11/286580 |
Document ID | / |
Family ID | 38052405 |
Filed Date | 2007-05-24 |
United States Patent
Application |
20070114156 |
Kind Code |
A1 |
Greeley; John P. ; et
al. |
May 24, 2007 |
Selective naphtha hydrodesulfurization with high temperature
mercaptan decomposition
Abstract
A process for the selective hydrodesulfurization of olefinic
naphtha streams containing a substantial amount of organically
bound sulfur and olefins. The olefinic naphtha stream is
selectively desulfurized in a first hydrodesulfurization reaction
stage. This effluent stream is then contacted with a stripping
agent in a H.sub.2S removal zone, such as steam or an amine
solution, to remove H.sub.2S from the effluent stream, thereby
reducing the H.sub.2S partial pressure of the process stream. The
process stream is then subjected to a second desulfurization
reaction stage followed by a mercaptan decomposition stage to
reduce the content of mercaptan sulfur in the final product stream.
In a second embodiment, the effluent stream from the first
hydrodesulfurization reaction stage, after being subjected to the
H.sub.2S removal zone, is fed directly to the mercaptan
decomposition stage where total sulfur content and mercaptan sulfur
content are reduced in the final product stream.
Inventors: |
Greeley; John P.;
(Annandale, NJ) ; Ellis; Edward S.; (Basking
Ridge, NJ) ; Halbert; Thomas R.; (Baton Rouge,
LA) ; Tracy; William J. III; (Burke, VA) ;
Dysard; Jeffrey M.; (Michigan City, IN) |
Correspondence
Address: |
ExxonMobil Research & Engineering Company
P.O. Box 900
1545 Route 22 East
Annandale
NJ
08801-0900
US
|
Family ID: |
38052405 |
Appl. No.: |
11/286580 |
Filed: |
November 23, 2005 |
Current U.S.
Class: |
208/208R |
Current CPC
Class: |
C10G 2300/202 20130101;
C10G 2300/4006 20130101; C10G 2300/1044 20130101; C10G 2300/301
20130101; C10G 69/02 20130101; C10G 2300/807 20130101; C10G 65/04
20130101; C10G 67/02 20130101; C10G 2300/207 20130101; C10G
2300/4012 20130101 |
Class at
Publication: |
208/208.00R |
International
Class: |
C10G 45/00 20060101
C10G045/00; C10G 17/00 20060101 C10G017/00 |
Claims
1. A process for hydrodesulfurizing an olefinic naphtha feedstream
and retaining a substantial amount of the olefins, which feedstream
boils in the range of about 50.degree. F. (10.degree. C.) to about
450.degree. F. (232.degree. C.) and contains organically bound
sulfur and an olefin content of at least about 5 wt. %, which
process comprises: a) hydrodesulfurizing said 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.degree. F. (232.degree. C.) to about
800.degree. F. (427.degree. 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 total sulfur content lower than that of said
olefinic naphtha feedstream; b) conducting said first reactor
effluent stream to an H.sub.2S removal zone wherein a stripping
agent is utilized to remove substantially all of the H.sub.2S 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.degree.
F. (232.degree. C.) to about 800.degree. F. (427.degree. 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 at least a portion of the elemental and
organically bound sulfur in said olefinic naphtha feedstream to
hydrogen sulfide to produce a second reactor effluent stream which
has a total sulfur content lower than that of said stripped
effluent stream and some amount of mercaptan sulfur; and d)
conducting said second reactor effluent stream to a mercaptan
decomposition reaction stage in the presence of a mercaptan
decomposition catalyst, at mercaptan decomposition reaction
conditions including temperatures from about 500.degree. F.
(260.degree. C.) to about 800.degree. F. (427.degree. C.), and
pressures of about 60 to about 800 psig, to decompose at least a
portion of the mercaptan sulfur to produce a mercaptan
decomposition reactor product stream with a mercaptan sulfur
content lower than that of said second reactor effluent stream.
2. The process of claim 1, wherein said olefinic naphtha
feedstream, and the stripped effluent stream are in the vapor phase
prior to contacting said first and second reaction stages.
3. The process of claim 2, wherein said second reactor effluent
stream is in the vapor phase prior to contacting said mercaptan
decomposition reaction stage.
4. The process of claim 3, wherein said stripping agent is selected
from the group consisting of steam and an amine solution.
5. The process of claim 1, wherein 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.
6. The process of claim 5, wherein 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.
7. The process of claim 1, wherein said hydrodesulfurization
catalysts utilized in said first and second reaction stages are
comprised of at least one Group VIII metal oxide and at least one
Group VI metal oxide.
8. The process of claim 7, wherein said hydrodesulfurization
catalysts utilized in said first and second reaction stages are
comprised of at least one Group VIII metal oxide selected from Fe,
Co and Ni, and at least one Group VI metal oxide, selected from Mo
and W.
9. The process of claim 8, wherein said metal oxides are deposited
on a high surface area support material.
10. The process of claim 9, wherein said high surface area support
material is alumina.
11. The process of claim 1, wherein said mercaptan decomposition
catalyst is comprised of a refractory metal oxide in an effective
amount to catalyze the decomposition of said mercaptan sulfur
resistant to H.sub.2S.
12. The process of claim 11, wherein said mercaptan decomposition
catalyst is comprised of materials selected from alumina, silica,
silica-alumina, aluminum phosphates, titania, magnesium oxide,
alkali and alkaline earth metal oxides, alkaline metal oxides,
magnesium oxide, faujasite that has been ion exchanged with sodium
to remove the acidity, and ammonium ion treated aluminum
phosphate.
13. The process of claim 12, wherein said mercaptan decomposition
catalyst is comprised of materials selected from alumina, silica,
and silica-alumina.
14. The process of claim 13, wherein said mercaptan decomposition
catalyst possesses substantially no hydrogenation activity.
15. The process of claim 1, wherein said first and second
hydrodesulfurization reaction conditions include temperatures from
about 500.degree. F. (260.degree. C.) to about 675.degree. F.
(357.degree. C.), pressures of about 200 to about 500 psig, and
hydrogen-containing treat gas rates of about 1000 to about 3000
standard cubic feet per barrel.
16. The process of claim 15, wherein said first and second
hydrodesulfurization reaction conditions include pressures of about
250 to about 400 psig.
17. The process of claim 16, wherein said mercaptan decomposition
reaction conditions include temperatures from about 550.degree. F.
(288.degree. C.) to about 700.degree. F. (371.degree. C.), and
pressures of about 150 to about 500 psig.
18. The process of claim 17, wherein the total sulfur content of
said third reactor product stream is less than about 1 wt. % of the
total sulfur content of said olefinic naphtha feedstream.
19. The process of claim 18, wherein 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.
20. A process for hydrodesulfurizing an olefinic naphtha feedstream
and retaining a substantial amount of the olefins, which feedstream
boils in the range of about 50.degree. F. (10.degree. C.) to about
450.degree. F. (232.degree. C.) and contains organically bound
sulfur and an olefin content of at least about 5 wt. %, which
process comprises: a) hydrodesulfurizing said 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.degree. F. (232.degree. C.) to about
800.degree. F. (427.degree. 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 at least 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 total sulfur content lower than
that of said olefinic naphtha feedstream; b) conducting said first
reactor effluent stream to an H.sub.2S removal zone wherein a
stripping agent is utilized to remove substantially all of the
H.sub.2S from said first reactor effluent stream to produce a
stripped effluent stream; and 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 mercaptan decomposition reaction conditions including
temperatures from about 500.degree. F. (260.degree. C.) to about
800.degree. F. (427.degree. 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 decompose at least a
portion of the mercaptan sulfur and convert at least a portion of
the elemental and organically bound sulfur to produce a mercaptan
decomposition reactor product stream with a mercaptan sulfur
content less than that of said first reactor effluent stream.
21. The process of claim 20, wherein said olefinic naphtha
feedstream is in the vapor phase prior to contacting said first
reaction stage.
22. The process of claim 21, wherein said stripped effluent stream
is in the vapor phase prior to contacting said mercaptan
decomposition stage.
23. The process of claim 22, wherein said stripping agent is
selected from the group consisting of steam and an amine
solution.
24. The process of claim 20, wherein 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.
25. The process of claim 24, wherein 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.
26. The process of claim 20, wherein said hydrodesulfurization
catalyst utilized in said first reaction stage is comprised of at
least one Group VIII metal oxide and at least one Group VI metal
oxide.
27. The process of claim 26, wherein said hydrodesulfurization
catalyst utilized in said first reaction stage is comprised of at
least one Group VIII metal oxide selected from Fe, Co and Ni, and
at least one Group VI metal oxide, selected from Mo and W.
28. The process of claim 27, wherein said metal oxides are
deposited on a high surface area support material.
29. The process of claim 28, wherein said high surface area support
material is alumina.
30. The process of claim 20, wherein said mercaptan decomposition
catalyst is comprised of a refractory metal oxide in an effective
amount to catalyze the decomposition of said mercaptan sulfur
resistant to H.sub.2S.
31. The process of claim 30, wherein said mercaptan decomposition
catalyst is comprised materials selected from alumina, silica,
silica-alumina, aluminum phosphates, titania, magnesium oxide,
alkali and alkaline earth metal oxides, alkaline metal oxides,
magnesium oxide, faujasite that has been ion exchanged with sodium
to remove the acidity, and ammonium ion treated aluminum
phosphate.
32. The process of claim 31, wherein said mercaptan decomposition
catalyst is comprised of materials selected from alumina, silica,
and silica-alumina.
33. The process of claim 32, wherein said mercaptan decomposition
catalyst possesses substantially no hydrogenation activity.
34. The process of claim 20, wherein said first
hydrodesulfurization reaction conditions include temperatures from
about 500.degree. F. (260.degree. C.) to about 675.degree. F.
(357.degree. C.), pressures of about 200 to about 500 psig, and
hydrogen-containing treat gas rates of about 1000 to about 3000
standard cubic feet per barrel.
35. The process of claim 34, wherein said first
hydrodesulfurization reaction conditions include pressures of about
250 to about 400 psig.
36. The process of claim 35, wherein said mercaptan decomposition
reaction conditions include temperatures from about 550.degree. F.
(288.degree. C.) to about 700.degree. F. (371.degree. C.), and
pressures of about 150 to about 500 psig.
37. The process of claim 36, wherein 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.
38. The process of claim 37, wherein 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.
Description
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.
[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 isomerization,
blending, etc., to produce higher octane fuels. Such additional
refining, 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. Pat. Nos. 5,985,136; 6,013,598;
and 6,126,814, all of which are incorporated herein by reference,
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 H.sub.2S 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 H.sub.2S 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 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 hydrodesulfurizing olefinic naphtha feedstream and
retaining a substantial amount of the olefins, which feedstream
boils in the range of about 50.degree. F. (10.degree. C.) to about
450.degree. F. (232.degree. C.) and contains organically bound
sulfur and an olefin content of at least about 5 wt. %, which
process comprises: [0010] 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.degree. F. (232.degree. C.) to about
800.degree. F. (427.degree. 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; [0011] b)
conducting said first reactor effluent stream to an H.sub.2S
removal zone wherein a stripping agent, such as steam or an amine
solution, is utilized to remove substantially all of the H.sub.2S
from said first reactor effluent stream to produce a stripped
effluent stream; [0012] 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.degree. F. (232.degree. C.) to about 800.degree. F.
(427.degree. 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
[0013] 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.degree. F. (260.degree. C.) to about
800.degree. F. (427.degree. C.), and pressures of about 60 to about
800 psig, to decompose at least a portion of the mercaptans to
produce a mercaptan decomposition reactor product with a lower
mercaptan sulfur content than that of said second reactor effluent
stream.
[0014] 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.degree. F. (10.degree.
C.) to about 450.degree. F. (232.degree. C.) and contains
organically bound sulfur and an olefin content of at least about 5
wt. %, which process comprises: [0015] 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.degree.
F. (232.degree. C.) to about 800.degree. F. (427.degree. 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; [0016] b) conducting said first
reactor effluent stream to an H.sub.2S removal zone wherein a
stripping agent, such as steam or an amine solution, is utilized to
remove substantially all of the H.sub.2S from said first reactor
effluent stream to produce a stripped effluent stream; [0017] 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.degree. F. (260.degree. C.) to about 800.degree. F.
(427.degree. 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 product with a lower mercaptan
sulfur content than that of said first reactor effluent stream.
[0018] In a preferred embodiment, the feedstreams to the
hydrodesulfurization reactor and mercaptan decomposition stages
will be in the vapor phase.
[0019] 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 H.sub.2S
removal zone.
[0020] 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.
[0021] 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.
[0022] 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.
[0023] 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
[0024] FIG. 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 H.sub.2S removal step which is then followed
by a final mercaptan decomposition reaction stage.
[0025] FIG. 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 H.sub.2S removal step which is then followed by a
final mercaptan decomposition reaction stage.
DETAILED DESCRIPTION OF THE INVENTION
[0026] Feedstocks suitable for use in the present invention are
olefinic naphtha boiling range refinery streams that typically boil
in the range of about 50.degree. F. (10.degree. C.) to about
450.degree. F. (232.degree. 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 5 wt. %.
[0027] 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 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.
[0028] 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.
[0029] FIG. 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.
[0030] 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.degree. F. (232.degree. C.) to
about 800.degree. F. (427.degree. C.), preferably from about
500.degree. F. (260.degree. C.) to about 675.degree. F.
(357.degree. 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 hr.sup.-1 to about 15 hr.sup.-1, preferably from about
0.5 hr.sup.-1 to about 10 hr.sup.-1, more preferably from about 1
hr.sup.-1 to about 5 hr.sup.-1. 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.
[0031] 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.
[0032] 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.
[0033] 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," S. J. Tauster et al., Journal of Catalysis 63, pp.
515-519 (1980), which is incorporated herein by reference. 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 2,000
.mu.mol oxygen/gram MoO.sub.3.
[0034] The most preferred catalysts for the first and second
hydrodesulfurization zone can be characterized by the properties:
(a) a MoO.sub.3 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 CoO 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 .ANG. to about 200 .ANG.,
preferably from about 75 .ANG. to about 175 .ANG., and more
preferably from about 80 .ANG. to about 150 .ANG.; (e) a MoO.sub.3
surface concentration of about 0.5.times.10.sup.-4 to about
3.times.10.sup.-4 g MoO.sub.3/m.sup.2, preferably about
0.75.times.10.sup.-4 to about 2.5.times.10.sup.-4 g
MoO.sub.3/m.sup.2, more preferably from about 1.times.10.sup.-4 to
2.times.10.sup.-4 g MoO.sub.3/m.sup.2; 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.
[0035] 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 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.
[0036] Returning now to the FIG. 1 hereof, the total effluent
product from the first hydrodesulfurization reaction stage (4) is
conducted to an H.sub.2S 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 H.sub.2S from the effluent stream (7). This H.sub.2S
removal zone operates at substantially the same pressure as the
first hydrodesulfurization reaction stage pressure. The H.sub.2S
stripped product stream (8) from the H.sub.2S 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).
[0037] 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 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 H.sub.2S 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.
[0038] Generally, the mercaptan decomposition reaction stage
conditions include: temperatures from about 500.degree. F.
(260.degree. C.) to about 800.degree. F. (427.degree. C.),
preferably from about 550.degree. F. (288.degree. C.) to about
700.degree. F. (371.degree. 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 hr.sup.-1 to about 15
hr.sup.-1, preferably from about 0.5 hr.sup.-1 to about 10
hr.sup.-1, more preferably from about 1 hr.sup.-1 to about 5
hr.sup.-1. 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.
[0039] FIG. 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.
[0040] 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 FIG.
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 FIG. 1, above. The total effluent
product from the first hydrodesulfurization reaction stage (4) is
conducted to an H.sub.2S 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 H.sub.2S
from the effluent stream (7). This H.sub.2S removal zone operates
at substantially the same pressure as the first
hydrodesulfurization reaction stage pressure. The H.sub.2S stripped
product stream (8) from the H.sub.2S removal zone and a
hydrogen-containing treat gas (9) is then contacted with a catalyst
in a mercaptan decomposition reaction stage (10).
[0041] The mercaptan decomposition conditions of the mercaptan
decomposition reaction stage in this configuration (see FIG. 2) are
the same as described for the mercaptan decomposition reaction
stage in the first embodiment, above (see FIG. 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 FIG. 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.
[0042] The following examples are presented to illustrate the
invention.
EXAMPLE 1
[0043] In this example, the process configuration utilized is shown
in FIG. 1. The hydrogen treat gas rates, shown as streams (2) and
(9) in FIG. 1, are 2,000 standard cubic feet per barrel (scf/b).
The amount of H.sub.2S removal in the H.sub.2S reaction zone (6) is
modeled utilizing an H.sub.2S removal step to remove free and
dissolved H.sub.2S from the process stream at the first
hydrodesulfurization reaction pressures (327 psig). Any stripping
agent utilized in the art to facilitate H.sub.2S removal, such as
steam or an amine solution, can be utilized and is shown as stream
(5). The H.sub.2S or H.sub.2S 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.
TABLE-US-00001 TABLE 1 1st HDS 2nd HDS Mercaptan Removal Stage
Stage Stage (3) (10) (12) Temperature (.degree. F.) 535 525 625
Pressure (psig) 327 327 327
[0044] TABLE-US-00002 TABLE 2 First Second Third Reactor Stripped
Reactor Reactor Olefinic Effluent Effluent Effluent Product
Feedstream Stream Stream Stream Stream (1) (4) (8) (11) (13) 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 HDS reactors and no mercaptan
removal would result in a RON loss of 5.0 and a MON loss of
1.8.
EXAMPLE 2
[0045] In this example, the process configuration utilized is shown
in FIG. 2. The hydrogen treat gas rates, shown as streams (2) and
(9) in FIG. 2, are 2,000 standard cubic feet per barrel (scf/b).
The amount of H.sub.2S removal in the H.sub.2S reaction zone (6) is
modeled utilizing an H.sub.2S removal step to remove free and
dissolved H.sub.2S from the process stream at the
hydrodesulfurization reaction pressures (327 psig). Any stripping
agent utilized in the art to facilitate H.sub.2S removal, such as
steam or an amine solution, can be utilized and is shown as stream
(5). The H.sub.2S or H.sub.2S 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.
TABLE-US-00003 TABLE 3 1st HDS Mercaptan Removal Stage Stage (3)
(12) Temperature (.degree. F.) 535 625 Pressure (psig) 327 327
[0046] TABLE-US-00004 TABLE 4 First Second Reactor Stripped Reactor
Olefinic Effluent Effluent Product Feedstream Stream Stream Stream
(1) (4) (8) (11) Sulfur (wppm) 1900 62 62 10 Mercaptan (wppm) -- 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.
* * * * *