U.S. patent application number 11/177809 was filed with the patent office on 2006-07-13 for naphtha desulfurization process.
Invention is credited to Edward S. Ellis, Thomas R. Halbert, Gordon F. Stuntz.
Application Number | 20060151359 11/177809 |
Document ID | / |
Family ID | 37401140 |
Filed Date | 2006-07-13 |
United States Patent
Application |
20060151359 |
Kind Code |
A1 |
Ellis; Edward S. ; et
al. |
July 13, 2006 |
Naphtha desulfurization process
Abstract
This invention relates to a process for selectively
desulfurizing naphtha. More particularly, a low sulfur naphtha feed
containing less than 500 wppm sulfur is hydrodesulfurized using a
hydrodesulfurization catalyst and a hydrogen treat gas containing
at least about 50 vppm hydrogen sulfide followed by mercaptan
removal or conversion.
Inventors: |
Ellis; Edward S.; (Basking
Ridge, NJ) ; Halbert; Thomas R.; (Baton Rouge,
LA) ; Stuntz; Gordon F.; (Baton Rouge, LA) |
Correspondence
Address: |
EXXONMOBIL RESEARCH AND ENGINEERING COMPANY
P.O. BOX 900
1545 ROUTE 22 EAST
ANNANDALE
NJ
08801-0900
US
|
Family ID: |
37401140 |
Appl. No.: |
11/177809 |
Filed: |
July 8, 2005 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60643624 |
Jan 13, 2005 |
|
|
|
Current U.S.
Class: |
208/209 |
Current CPC
Class: |
C10G 67/06 20130101;
C10G 25/00 20130101; B01J 37/20 20130101; B01J 35/002 20130101;
C10G 2400/02 20130101; B01J 23/882 20130101; C10G 67/10 20130101;
C10G 45/08 20130101; C10G 19/02 20130101; B01J 35/1061
20130101 |
Class at
Publication: |
208/209 |
International
Class: |
C10G 45/00 20060101
C10G045/00 |
Claims
1. A process for hydrodesulfurizing a low sulfur naphtha feedstock,
which process comprises: a) contacting the feedstock containing
less than about 500 wppm sulfur, based on feedstock, and greater
than about 20 wt. % olefins, based on feedstock, in a first
reaction stage under hydrodesulfurization conditions including a
hydrogen treat gas provided that the hydrogen treat gas contains at
least about 50 vppm of hydrogen sulfide, based on hydrogen, and
provided that the hydrogen sulfide may be in the form of a
precursor spiking agent in at least one of the feedstock or
hydrogen treat gas, with a catalyst comprising at least one Group
VIB metal and at least one Group VIII metal on an inorganic
refractory support material to yield a first stage reaction product
having less than about 50 wppm non-mercaptan sulfur, based on
reaction product, and a mercaptan sulfur to non-mercaptan sulfur
ratio of greater than 1:1; and b) passing the first stage product
to a second stage wherein mercaptan sulfur is at least partially
removed or converted from the first stage product to obtain a
second stage product having a reduced amount of mercaptan
sulfur.
2. The process of claim 1 wherein the hydrogen treat gas contains
at least about 100 vppm hydrogen sulfide.
3. The process of claim 2 wherein the hydrogen treat gas contains
at least about 200 vppm hydrogen sulfide.
4. The process of claim 1 wherein the spiking agent is at least one
of carbon disulfide, thiophene, mercaptan, organic sulfide, dialkyl
disulfide, diaryl disulfide and organic polysulfide.
5. The process of claim 4 wherein the spiking agent is dimethyl
sulfide or dimethyl disulfide.
6. The process of claim 1 wherein the catalyst comprises: (a) about
1 to about 10 wt. % MoO.sub.3; (b) about 0.1 to about 5 wt. % CoO;
(c) a Co/Mo atomic ratio of about 0.1 to about 1.0; (d) a median
pore diameter of about 75 .ANG. to about 175 .ANG.; (e) a MoO.sub.3
surface concentration in g MoO.sub.3/m.sup.2 of about
0.5.times.10.sup.-4 to about 3.times.10.sup.-4; (f) an average
particle size diameter of less than about 2.0 mm; (g) a metal
sulfide edge plane area of from about 760 to about 2800 .mu.mol
oxygen/g MoO.sub.3 as measured by oxygen chemisorption; and (h) an
inorganic refractory support material.
7. The process of claim 1 wherein the olefins content is at least
about 30 wt. %, based on feedstock.
8. The process of claim 1 wherein the hydrodesulfurization
conditions include temperatures of from about 232 to about
371.degree. C., pressures (total) of from about 1480 to about 2514
kPa, liquid hourly space velocities of from about 0.1 to about 15,
and hydrogen treat gas rates of from about 36 to about 1780
m.sup.3/m.sup.3.
9. The process of claim 1 wherein mercaptan sulfur is removed by
caustic extraction.
10. The process of claim 9 wherein caustic extraction uses an
iron-based catalyst that is soluble in caustic, or in the
alternative supported on a support, to oxidize mercaptans.
11. The process of claim 1 wherein the mercaptan sulfur is
extracted to an aqueous treatment solution and converted to
mercaptides.
12. The process of claim 11 wherein the aqueous treatment solution
combines alkali metal hydroxide, alkylphenols, sulfonated cobalt
pthalocyanine, and water.
13. The process of claim 12 wherein the aqueous treatment solution
forms two substantially immiscible phases which are a less dense,
homogeneous, top phase of dissolved alkali metal hydroxide, alkali
metal alkylphenylate, and water, and a more dense, homogeneous,
bottom phase of dissolved alkali metal hydroxide and water.
14. The process of claim 13 wherein the two immiscible phase are
combined with first stage product and allowed to settle.
15. The process of claim 1 wherein mercaptan sulfur is removed by
adsorption.
16. The process of claim 1 wherein the feedstock has a boiling
range from about 18.degree. C. to about 221.degree. C.
17. The process of claim 1 wherein the first reaction stage for
hydrodesulfurization is preceded by a diolefin reactor.
Description
FIELD OF THE INVENTION
[0001] This invention relates to a process for selectively
desulfurizing naphtha. More particularly, a low sulfur naphtha feed
is hydrodesulfurized using a hydrodesulfurization catalyst and a
hydrogen treat gas containing hydrogen sulfide followed by
mercaptan removal or conversion.
BACKGROUND OF THE INVENTION
[0002] Environmental regulations covering the sulfur content of
fuels for internal combustion engines are becoming more stringent
with regard to allowable sulfur in fuels. It is anticipated that
motor gasoline sulfur content may need to meet a sulfur limit of 30
wppm with possible further mandated reductions. The feedstocks for
motor gasoline are typically catalytically cracked naphthas, which
contain substantial amounts of sulfur and olefins.
[0003] A common method for reducing the sulfur content of
feedstocks is by hydrotreating using catalysts that convert
sulfur-containing species to hydrogen sulfide. The extent to which
hydrotreating lowers the sulfur content of the hydrotreated product
is typically dependent on the catalyst and hydrotreating
conditions. For any given hydrotreating catalyst, the more severe
hydrotreating conditions would be expected to reduce the sulfur
content to the greater extent. However, such severe hydrotreating
conditions normally result in a loss of molecules contributing to
desirable octane properties either by cracking to non-fuel
molecules or hydrogenation of olefins to molecules having lower
octane rating. As the hydrotreating catalyst ages, it normally
becomes necessary to adjust reaction conditions to maintain an
acceptable catalyst activity. However, such adjustments result in
further loss of desirable molecules contributing to high octane.
This then results in increased production costs to produce high
octane fuels because of the need to boost octane through added
process steps such as isomerization, blending or addition of octane
boosting additives.
[0004] One approach to addressing the problems associated with
conventional hydrotreating is to use selective
hydrodesulfurization, i.e., hydrodesulfurizing a feed with
selective catalysts, selective process conditions, or both, to
remove organosulfur while minimizing hydrogenation of olefins and
octane reduction. For example, ExxonMobil Corporation's
SCANfining.RTM. process selectively desulfurizes cat naphthas with
little or no loss in octane number. U.S. Pat. Nos. 5,985,136;
6,013,598; and 6,126,814, all of which are incorporated by
reference herein, disclose various aspects of SCANfining.RTM..
Although selective hydrodesulfurization processes have been
developed to avoid significant olefin saturation and loss of
octane, H.sub.2S liberated in the process can react with retained
olefins to form mercaptan sulfur by reversion. Such mercaptans are
often referred to as "recombinant" or "reversion" mercaptans.
[0005] A special situation is created when the feed naphtha has a
low sulfur content. While such low sulfur feeds may appear to be
more desirable if the target is a lower sulfur containing motor
gasoline product, there is a further consideration relating to
catalyst activity. Hydrotreating catalysts used for
hydrodesulfurization are normally used in a sulfided state.
Sulfided catalysts are generally more stable with regard to
catalyst deactivation as compared to their non-sulfided
counterparts. The use of such catalysts in a low sulfur feed may
lead to catalyst deactivation with attendant loss in catalyst
activity and selectivity.
[0006] There is a need in the art to stabilize hydrotreating
catalyst activity used with low sulfur feeds to minimize costly
turnarounds associated with catalyst deactivation.
SUMMARY OF THE INVENTION
[0007] It has been discovered that a low sulfur naphtha feed can be
hydrodesulfurized while maintaining catalyst activity. The present
invention relates to a process for hydrodesulfurizing a low sulfur
naphtha feedstock, which process comprises: contacting the
feedstock containing less than about 500 wppm sulfur, based on
feedstock, and greater than about 20 wt. % olefins, based on
feedstock, in a first reaction stage under hydrodesulfurization
conditions including a hydrogen treat gas provided that the
hydrogen treat gas contains at least about 50 vppm of hydrogen
sulfide, based on hydrogen, provided that the hydrogen sulfide may
be in the form of a precursor spiking agent in at least one of the
feedstock or hydrogen treat gas, with a catalyst comprising at
least one Group VIB metal and at least one Group VIII metal on an
inorganic refractory support material to yield a first stage
reaction product having less than about 50 wppm non-mercaptan
sulfur, based on reaction product, and a mercaptan sulfur to
non-mercaptan sulfur ratio of greater than 1:1; and passing the
first stage product to a second stage wherein mercaptan sulfur is
at least partially removed or converted from the first stage
product to obtain a second stage product having a reduced amount of
mercaptan sulfur.
[0008] In another embodiment, the present invention relates to a
process for hydrodesulfurizing a low sulfur naphtha feedstock,
which process comprises: contacting the feedstock containing less
than about 500 wppm sulfur and greater than about 20 wt. % olefins,
based on feedstock, in a first reaction stage under
hydrodesulfurization conditions including a hydrogen treat gas
provided that the hydrogen treat gas contains at least about 50
vppm of hydrogen sulfide, based on hydrogen, with a catalyst
comprising: (a) about 1 to 10 wt % MoO.sub.3; (b) about 0.1 to 5
wt. % CoO; (c) a Co/Mo atomic ratio of about 0.1 to 1.0; (d) a
median pore diameter of about 75 .ANG. to 175 .ANG.; (e) a
MoO.sub.3 surface concentration in g MoO.sub.3/m.sup.2 of about
0.5.times.10.sup.-4 to 3.times.10.sup.-4; (f) an average particle
size diameter of less than about 2.0 mm; (g) a metal sulfide edge
plane area of from about 760 to 2800 .mu.mol oxygen/g MoO.sub.3 as
measured by oxygen chemisorption; and (h) an inorganic refractory
support material; and passing the first stage product to a second
stage wherein mercaptan sulfur is at least partially removed or
converted from the first stage product to obtain a second stage
product having a reduced amount of mercaptan sulfur.
BRIEF DESCRIPTION OF THE DRAWING
[0009] The FIGURE is a graph showing RCA HDS vs. days on oil for a
low sulfur feed and a DMDS-spiked higher sulfur feed.
DETAILED DESCRIPTION OF THE INVENTION
[0010] The feedstock used in the present process are naphthas
having a low sulfur content and an olefins content of at least
about 20 wt. %, preferably at least about 30 wt. %, based on
feedstock. By "low sulfur" is meant a feed containing less than
about 500 wppm sulfur, based on feed. The cat naphtha feeds
employed are those having a boiling range from about 18.degree. C.
to about 221.degree. C. (65.degree. F. to 430.degree. F.). The
naphtha can be any stream predominantly boiling in the naphtha
boiling range and containing olefins, for example, a thermally
cracked or a catalytically cracked naphtha. Such streams can be
derived from any appropriate source, for example, they can be
derived from the fluid catalytic cracking ("FCC") of gas oils and
resids, from delayed or fluid coking of resids, and from steam
cracking and related processes. Such naphtha typically contains
hydrocarbon species such as paraffins, olefins, naphthenes, and
aromatics. These naphthas also typically contain species having
heteroatoms such as sulfur and nitrogen. Heteroatom species
include, for example, mercaptans and thiophenes. Significant
amounts of such heteroatom species may be present.
[0011] FCC cat naphtha typically contains 20 to 40 wt. % olefins,
based on the weight of the cat naphtha. Of these olefins, C.sub.5
olefins are typically present as 20%. to about 30% of the total
amount of olefins, and combined C.sub.5 and C.sub.6 olefin content
is typically about 45% to about 65% of the total C.sub.5+ olefins
present.
[0012] The cat naphtha feed may be separated by methods such as
splitting and fractionation in order to provide at least a light
cat naphtha fraction and a heavy cat naphtha fraction. The
separation cut point between the light and heavy fraction is
regulated so that a substantial amount of the mercaptan and olefins
having fewer than six carbons ("C.sub.6.sup.-") are present in the
light fraction and a substantial amount of the thiophene and the
olefins having 6 or more carbons ("C.sub.6.sup.+") are present in
the heavy fraction.
[0013] Accordingly, the cut point is regulated so that light
fraction boils in the range of about 18.degree. C. to about
74.degree. C. (65.degree. F. to 165.degree. F.), preferably from
about 18.degree. C. to about 66.degree. C. (65.degree. F. to
150.degree. F.), and more preferably in the range of about
18.degree. C. to about 46.degree. C. (65.degree. F. to 115.degree.
F.). The heavy fraction may have a boiling point in the range of
about 74.degree. C. to about 221.degree. C. (165.degree. F. to
430.degree. F.), preferably about 79.degree. C. to about
221.degree. C. (175.degree. F. to 430.degree. F.). Those skilled in
the art are aware that hydrocarbon separations having precise cut
points are difficult to obtain and, consequently, some overlap in
the boiling points of the light and heavy fractions may occur near
the cut point. Even so, the light fraction will typically contain
more than 50% of the C.sub.5 olefins contained in the cat naphtha
feed. The heavy fraction will typically contain more than 50% of
the C.sub.6 olefin contained in the cat naphtha feed. For an FCC
cat naphtha, about 10 wt. % to about 40 wt. % of the total weight
of the cat naphtha is in the light fraction and about 90 wt. % to
about 60 wt. % of the total weight of the cat naphtha is in the
heavy fraction.
[0014] The light fraction can be processed to remove sulfur while
preserving the olefin content to maintain octane number.
Accordingly, the light fraction is desulfurized via a
non-hydrotreating process (i.e., a process employing no more than
50 psig (446 kPa) hydrogen partial pressure) to remove sulfur
species such as mercaptan. The desulfurized light fraction has a
sulfur content of less than about 500 wppm, preferably less than 50
wppm, based on the weight of the light fraction. A substantial
portion of the olefins in the light fraction (mostly C.sub.5
olefins and some C.sub.6 olefins) can be preserved during sulfur
removal. Preferably more than 75% of the C.sub.5 olefins are
retained following sulfur removal, more preferably more than 90%,
based on the total weight of C.sub.5 olefins in the light fraction.
MEROX.TM. and EXTRACTIVE MEROX.TM., Universal Oil Products, Des
Plaines, Ill., are suitable processes for removing sulfur while
preserving olefin content, as are sulfur absorption processes set
forth, for example, in U.S. Pat. No. 5,843,300. It should be noted
that such processes are representative, and that any
non-hydrotreating process capable of removing sulfur to a level
lower than 500 ppm can be employed. The preparation of low sulfur
naphthas is further described in U.S. published application
20020084211, which is incorporated herein by reference.
[0015] Hydrodesulfurization catalysts are those containing at least
one Group VIB metal (based on the Periodic Table of the Elements
published by the Sargent-Welch Scientific Company) and at least one
Group VIII metal on an inorganic refractory support material.
Preferred Group VIB metals include Mo and W and preferred Group
VIII metals are non-noble metals including Ni and Co. The terms
"hydrotreating" or "hydrodesulfurization" may be considered as
interchangeable. The amount of metal, either individually or as
mixtures, ranges from about 0.5 to 35 wt. %, based on catalyst. In
the case of mixtures, the Group VIII metals are preferably present
in amounts of 0.5 to 5 wt. % and the Group VIB metals in amounts of
from 5 to 30 wt. %. The hydrodesulfurization catalysts may also be
bulk metal catalysts wherein the amount of metal is 30 wt. % or
greater, based on catalyst.
[0016] Any suitable inorganic oxide support material may be used
for the hydrotreating catalyst. Non-limiting examples of suitable
support materials include: alumina, silica, silica-alumina,
titania, calcium oxide, strontium oxide, barium oxide, magnesium
oxide, carbon, zirconia, diatomaceous earth, lanthanide oxides
including cerium oxide, lanthanum oxide, neodynium oxide, yttrium
oxide and praesodynium oxide, oxides of chromium, thorium, uranium,
niobium and tantalum, tin oxide, zinc oxide, and aluminum
phosphate. Preferred supports are alumina, silica, and
silica-alumina. More preferred is alumina.
[0017] A preferred catalyst which exhibits high
hydrodesulfurization activity while minimizing olefin saturation is
a Mo/Co catalyst having the following properties, including (a) a
MoO.sub.3 concentration of about 1 to 10 wt. %, preferably about 2
to 8 wt. %, and more preferably about 4 to 6 wt. %, based on the
total weight of the catalyst; (b) a CoO concentration of about 0.1
to 5 wt. %, preferably about 0.5 to 4 wt. %, and more preferably
about 1 to 3 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 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, more preferably
from about 1.times.10.sup.-4 to about 2.times.10.sup.-4; 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.
[0018] Hydrodesulfurization (HDS) of the low sulfur naphtha
feedstocks may be carried out under the following conditions:
temperatures of from 232 to 371.degree. C. (450 to 700.degree. F.),
preferably 260 to 329.degree. C. (500 to 625.degree. F.), pressure
(total) of from 1480 to 2514 kPa (200 to 350 psig), preferably 1480
to 2169 kPa (200 to 300 psig), liquid hourly space velocities of
from 0.1 to 15, preferably 0.5 to 10, and hydrogen treat gas rates
of from 36 to 1780 m.sup.3/m.sup.3 (200 to 10,000 scf/B),
preferably 178 to 540 m.sup.3/m.sup.3 (1000 to 3000 scf/B).
[0019] In the usual HDS process with feeds containing greater than
500 wppm sulfur, hydrogen sulfide would be stripped from hydrogen
treat gas as HDS creates hydrogen sulfide from sulfur-containing
species in the feed. The hydrogen sulfide is then treated as a
contaminant and stripped from the hydrotreated feed. In the case of
a low sulfur feed, applicants have discovered that using hydrogen
treat gas that contains at least about 50 vppm hydrogen sulfide
based on hydrogen treat gas, preferably at least about 100 vppm,
more preferably at least about 200 vppm, stabilizes the HDS
catalyst against deactivation. The hydrogen sulfide may be provided
directly by a spiking agent added either directly to the hydrogen
treat gas or to the feedstock. Spiking agents which may serve as a
hydrogen sulfide precursor include at least one of carbon
disulfide, thiophene, mercaptan, organic sulfide, dialkyl
disulfide, diaryl disulfide and organic polysulfide, preferably
dimethyl sulfide or dimethyl disulfide. While not wishing to be
bound to any theory, the typical feed to the HDS process contains
greater than 500 wppm sulfur. Thus for the typical feed, there is
sufficient hydrogen sulfide created by the HDS process to maintain
the activity of the sulfided HDS catalyst during the HDS process.
In the case of low sulfur feeds, there may be insufficient hydrogen
sulfide present to maintain catalyst activity of the sulfided HDS
catalyst and hence the catalyst may undergo deactivation.
[0020] In one embodiment, the HDS reactor may be preceded by a
diolefin reactor. The purpose of the diolefin reactor is to convert
diolefins to monoolefins. Diolefins may be subject to a
polymerization reaction and such polymerization reactions may be
avoided by partially saturating the diolefin to a monoolefin. A
preferred catalyst for the saturation reaction is sulfided
Ni/Mo.
[0021] The hydrogen sulfide in the processed naphtha, whether
present by direct addition to the hydrogen treat gas or liberated
in the process, can react with retained olefins to form mercaptan
sulfur by reversion. Such mercaptans are often referred to as
"recombinant" or "reversion" mercaptans. In the present process,
such mercaptans are removed or converted.
[0022] Caustic extraction is a non-hydrotreating process capable of
extracting mercaptan sulfur. Commercially available process include
MEROX.TM. or EXTRACTIVE MEROX.TM., Universal Oil Products, Des
Plains, Ill., and those offered by Merichem, Houston, Tex. Such
processes use an iron-based catalyst that is soluble in caustic, or
in the alternative supported on a support, to oxidize mercaptans.
Mercaptans in the naphtha are converted to sodium salts which, in
the presence of a catalyst, are oxidized to form disulfides. The
disulfides are not soluble in the caustic solution and can be
separated therefrom. Examples of other catalysts that can be used
for mercaptan removal include phthalocyanine and metal
chelates.
[0023] The conditions for the extraction step utilized herein can
be easily selected by the skilled artisan. Preferably, the
conditions utilized will be those described in U.S. Pat. No.
4,626,341 herein incorporated by reference. For example, the
conditions employed in the extraction zone may vary greatly
depending on such factors as the nature of the hydrocarbon stream
being treated and its mercaptan content, etc. The skilled artisan
can readily select such conditions with reference to the applicable
art. However, in general, the mercaptan extraction may be performed
at a temperature above about 15.degree. C. (60.degree. F.) and at a
pressure sufficient to ensure liquid state operation.
[0024] Another method for reducing the sulfur content of a liquid
hydrocarbon is by the extraction of the acidic species such as
mercaptans, particularly reversion mercaptans, from the hydrocarbon
to an aqueous treatment solution where the mercaptans subsist as
mercaptides, and then separating a treated hydrocarbon
substantially reduced in mercaptans from the treatment solution
while curtailing treatment solution entrainment in the treated
hydrocarbon. Preferably, the extraction of the mercaptans from the
hydrocarbon to the treatment solution is conducted under anaerobic
conditions, i.e., in the substantial absence of added oxygen.
[0025] The treatment solution may be prepared by combining alkali
metal hydroxide, alkylphenols, sulfonated cobalt pthalocyanine, and
water. The amounts of the constituents may be regulated so that the
treatment solution forms two substantially immiscible phases, i.e.,
a less dense, homogeneous, top phase of dissolved alkali metal
hydroxide, alkali metal alkylphenylate, and water, and a more
dense, homogeneous, bottom phase of dissolved alkali metal
hydroxide and water. An amount of solid alkali metal hydroxide may
be present, preferably a small amount (e.g., 10 wt. % in excess of
the solubility limit), as a buffer, for example. When the treatment
solution contains both top and bottom phases, the top phase is
frequently referred to as the extractant or extractant phase. The
top and bottom phases are liquid, and are substantially immiscible
in equilibrium in a temperature ranging from about 27.degree. C. to
about 66.degree. C. (80.degree. F. to 150.degree. F.) and a
pressure range of about ambient (zero psig) to about 1480 kPa (200
psig). The phases formed for a treatment solution formed from
potassium hydroxide, water, and alkylphenols may be represented by
phase diagrams.
[0026] A two-phase treatment solution is combined with the
hydrocarbon to be treated and allowed to settle. Following
settling, less dense treated hydrocarbon is located above the top
phase, and may be separated. Alternatively, the top and bottom
phases are separated before the top phase (extractant) contacts the
hydrocarbon. All or a portion of the top phase may be regenerated
following contact with the hydrocarbon and returned to the process
for re-use. For example, the regenerated top phase may be returned
to the treatment solution prior to top phase separation, where it
may be added to either the top phase, bottom phase, or both.
Alternatively, the regenerated top phase may be added to the either
top phase, bottom phase, or both subsequent to the separation of
the top and bottom phases.
[0027] With very light material in the feed stream, this may be
impractical and the extraction is performed with a vapor phase feed
stream. The pressure may range from atmospheric up to 6996 kPa
(1000 psig) or more, but a pressure in the range of from about 1100
to 2485 kPa (145 to about 348 psig) is preferred.
[0028] Once the petroleum stream having organo sulfur and
mercaptans removed therefrom is separated from the used extractant
mixture, the used extractant mixture can be recycled to extract a
fresh petroleum containing mercaptan or hydroprocessed petroleum
stream or regenerated to remove mercaptans and the base.
Regeneration of the spent base can occur using either steam
stripping as described in The Oil and Gas Journal, Sep. 9, 1948,
pp. 95-103, or oxidation followed by extraction into a hydrocarbon
stream.
[0029] Typically regeneration of the mercaptan-containing used
extractant is accomplished by mixing the stream with an air stream
supplied at a rate which provides at least the stoichiometric
amount of oxygen necessary to oxidize the mercaptans in the caustic
stream. The air or other oxidizing agent is well admixed with the
base, and the mixed-phase admixture is then passed into the
oxidation zone. The oxidation of the mercaptans is promoted through
the presence of a catalytically effective amount of an oxidation
catalyst capable of functioning at the conditions found in the
oxidizing zone. Several suitable catalytic materials are known in
the art.
[0030] Preferred as a catalyst is a metal phthalocyanine such as
cobalt phthalocyanine or vanadium phthalocyanine, etc. Higher
catalytic activity may be obtained through the use of a polar
derivative of the metal phthalocyanine, especially the monosulfo,
disulfo, trisulfo, and tetrasulfo derivatives. The preferred
oxidation catalysts may be utilized in a form which is soluble or
suspended in the alkaline solution or it may be placed on a solid
carrier material. If the catalyst is present in the solution, it is
preferably cobalt or vanadium phthalocyanine disulfonate at a
concentration of from about 5 to 1000 wppm, based on solution.
Carrier materials should be highly absorptive and capable of
withstanding the alkaline environment. Activated charcoals have
been found very suitable for this purpose, and either animal or
vegetable charcoals may be used. The carrier material is to be
suspended in a fixed bed, which provides efficient circulation of
the caustic solution. Preferably the metal phthalocyanine compound
comprises about 0.1 to 2.0 wt. % of the final composite.
[0031] The oxidation conditions utilized include a pressure of from
atmospheric to about 6996 kPa (1000 psig). This pressure is
normally less than 600 kPa (72.5 psig). The temperature may range
from ambient to about 95.degree. C. (203.degree. F.) when operating
near atmospheric pressure and to about 205.degree. C. (401.degree.
F.) when operating at superatmospheric pressures. In general, it is
preferred that a temperature within the range of about 38 to about
80.degree. C. is utilized.
[0032] To separate the mercaptans from the base, the pressure in
the phase separation zone may range from atmospheric to about 2170
kPa (300 psig) or more. The temperature in this zone is confined
within the range of from about 10 to about 120.degree. C. (50 to
248.degree. F.), and preferably from about 26 to 54.degree. C. The
phase separation zone is sized to allow the denser caustic mixture
to separate by gravity from the disulfide compounds. This may be
aided by a coalescing means located in the zone. The above
describes one possible method for regenerating used extractant.
Other methods known to the skilled artisan may also be
employed.
[0033] An alternative method for removing mercaptans is adsorption.
The adsorption process typically involves adsorption followed by
desorption to remove any adsorbed contaminant and regeneration of
the adsorbent. Adsorbents include activated carbon optionally
including a catalyst, aluminas such as SELEXSORB.TM. manufactured
by ALCOA, zeolites and combinations thereof. Typical zeolites used
as adsorbents are those containing relatively large pores (greater
than 6 .ANG.). Examples include faujasite, offretite, mordenite,
zeolites X, Y and L, and zeolite beta. In batch operation, the
adsorbent bed is contacted with the mercaptan-containing stream.
The adsorbent bed becomes progressively saturated with pollutant
and will normally be regenerated by contacting with hot gas. The
pollutants are carried of with the hot gas and the adsorbent is
recycled back to the adsorbent bed for further removal of
pollutant. The adsorption process can also be continuous. In this
process, the contaminant adsorbent is continuously adsorbed in one
or more stages and the adsorbent regenerated and recycled. Such
processes are described in U.S. Pat. No. 5,730,860 and U.S.
Published Application 20020043501 herein incorporated by
reference.
[0034] The adsorbent may be regenerated or desorbed by heating in
one or more stages in the presence of a gas such as hydrogen or
hydrogen-containing gas, nitrogen or other gas, which will not
interfere with the adsorbing properties of the adsorbent. The spent
adsorbent is typically contacted with gas heated to a temperature
sufficient to cause desorption of adsorbed pollutants. The heated
gas may be in counter- or cross-current flow to the spent
adsorbent. The heated gas containing desorbed pollutants is sent to
recovery zone where gas is separated and recycled to the
regeneration zone and the regenerated adsorbent recycled to the
adsorption zone.
[0035] The following non-limiting example serves to illustrate the
invention.
EXAMPLE
[0036] A SCANfining.RTM. pilot unit was loaded with catalyst RT-225
which is commercially available from Exxon Mobil Coporation. The
RT-225 catalyst contains 4.5 wt. % MoO.sub.3 and 1.2 wt. % CoO, on
an alumina support. The catalyst was in a quadralobe shape and had
a catalyst size of 1.3 mm. After a preliminary drying at
399.degree. C. (750.degree. F.) for 3 hours, the catalyst was
loaded in a pilot unit and further dried at 371.degree. C.
(700.degree. F.) for 6 hours. The catalyst was then sulfided using
a 10 vol. % H.sub.2S in H.sub.2 mixture at an initial temperature
of 93.degree. C. (200.degree. F.) and a final temperature of
343.degree. C. (650.degree. F.).
[0037] The catalyst was then activated using a straight run naphtha
and a heavy cat naphtha used for catalyst break-in. Two feeds were
then prepared for the low sulfur and high sulfur runs. The low
sulfur feed was a naphtha blend having a total sulfur content of
about 30 wppm, based on feed. The high sulfur feed had a total
sulfur content of about 550 wppm and was prepared by spiking a low
sulfur feed with dimethyl disulfide (DMDS). DMDS decomposes to
H.sub.2S under reaction conditions.
[0038] The low sulfur and high sulfur feeds were then added to the
pilot unit under the following conditions: temperatures from 274 to
285.degree. C. (525 to 545.degree. F.), pressure of 1894 kPa (260
psig), LHSV of 4 hr.sup.-1, and treat gas rate of 214
m.sup.3/m.sup.3 (1200 scf/b).
[0039] The hydrodesulfurization (HDS) relative catalyst activity
(RCA) for the low sulfur feed shows a higher deactivation rate when
compared to the DMDS-spiked high sulfur feed. This is shown in the
FIGURE, which is a graph showing RCA vs. days on oil for the
respective feeds. As can be seen from the FIGURE, the low-sulfur
feed shows nearly twice the deactivation as the DMDS-spiked feed.
This means that the spiked feed will have a much longer run length
than the low-sulfur feed.
* * * * *