U.S. patent application number 11/100308 was filed with the patent office on 2005-12-29 for naphtha hydroprocessing with mercaptan removal.
Invention is credited to Davis, Timothy J., Ellis, Edward S., Greeley, John P., Hilbert, Timothy L..
Application Number | 20050284794 11/100308 |
Document ID | / |
Family ID | 34967805 |
Filed Date | 2005-12-29 |
United States Patent
Application |
20050284794 |
Kind Code |
A1 |
Davis, Timothy J. ; et
al. |
December 29, 2005 |
Naphtha hydroprocessing with mercaptan removal
Abstract
This invention relates to the hydroprocessing of naphtha with
removal of mercaptan from product. Naphtha feedstock is
hydrotreated and hydrocracked. Sulfur-containing contaminants,
notably C.sub.5+ recombinant mercaptans, are then selectively
removed from the hydrocracked naphtha by selective extraction or
adsorption.
Inventors: |
Davis, Timothy J.;
(Sterling, VA) ; Hilbert, Timothy L.; (Fairfax,
VA) ; Ellis, Edward S.; (Basking Ridge, NJ) ;
Greeley, John P.; (Annandale, NJ) |
Correspondence
Address: |
EXXONMOBIL RESEARCH AND ENGINEERING COMPANY
P.O. BOX 900
1545 ROUTE 22 EAST
ANNANDALE
NJ
08801-0900
US
|
Family ID: |
34967805 |
Appl. No.: |
11/100308 |
Filed: |
April 6, 2005 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60582112 |
Jun 23, 2004 |
|
|
|
Current U.S.
Class: |
208/89 ; 208/108;
208/212 |
Current CPC
Class: |
C10G 65/12 20130101;
C10G 45/02 20130101; C10G 61/06 20130101; C10G 61/04 20130101; C10G
63/04 20130101; C10G 2400/02 20130101; C10G 47/00 20130101 |
Class at
Publication: |
208/089 ;
208/108; 208/212 |
International
Class: |
C10G 067/02; C10G
069/02 |
Claims
1. A process for removing C.sub.5+ mercaptans from a hydrotreated
naphtha which comprises: (a) hydrotreating a naphtha feed in at
least one hydrotreating step under catalytic hydrotreating
conditions to form a hydrotreated naphtha, (b) conducting at least
a portion of the hydrotreated naphtha to a cracking zone and
hydrocracking the hydrotreated naphtha with a hydrocracking
catalyst under hydrocracking conditions to form a hydrocracked
naphtha and C.sub.5+ recombinant mercaptans, and (c) separating
C.sub.5+ recombinant mercaptans from hydrocracked naphtha by
selective extraction or adsorption.
2. The process of claim 1 wherein the selective extraction
comprises contacting the hydrocracked naphtha and C.sub.5+
recombinant mercaptans with a composition comprising water, alkali
metal hydroxide, cobalt phthalocyanine sulfonate and
alkylphenols.
3. The process of claim 2 wherein the composition comprises a first
and second phase.
4. The process of claim 3 wherein the first phase contains
dissolved alkali metal alkylphenylate, dissolved alkali metal
hydroxide, dissolved sulfonated cobalt phthalocyanine and water and
the second phase contains water and dissolved alkali metal
hydroxide.
5. The process of claim 2 wherein the contacting is under
substantially anaerobic conditions.
6. The process of claim 3 wherein the first and second phases are
substantially immiscible.
7. The process of claim 3 wherein the first phase is separated into
an upgraded naphtha and an extractant containing recombinant
C.sub.5+ mercaptans.
8. The process of claim 7 wherein the extractant is contacted with
an oxidizing amount of oxygen and the recombinant mercaptans are
oxidized at least in part to disulfides.
9. The process of claim 1 wherein the naphtha feed is fractionated
into a lower boiling fraction containing mercaptans and a higher
boiling fraction containing sulfur heterocyclic compounds prior to
hydrotreating.
10. The process of claim 1 wherein hydrotreating conditions include
temperatures of from 150.degree. C. to 400.degree. C., pressures of
from 790 to 20786 kPa, a liquid hourly space velocity of 0.1 to 10,
and a hydrogen to feed ratio of from 89 to 1780
m.sup.3/m.sup.3.
11. The process of claim 1 wherein the adsorption is by
chemisorption using metals or metal oxides.
12. The process of claim 11 wherein the metals are from Groups 7-12
of the IUPAC periodic table.
13. The process of claim 12 wherein the metals include at least one
of Ni, Co, Cu, Pt, Zn, Mn, and Cd.
14. The process of claim 1 wherein the adsorption is by physical
adsorption using molecular sieves.
15. The process of claim 14 wherein the molecular sieve is a
zeolite.
16. The process of claim 1 wherein the adsorption is by physical
adsorption using ion-exchange resins.
17. The process of claim 2 wherein the selective extraction
comprises a single phase.
18. A process for removing C.sub.5+ mercaptans from a hydrotreated
naphtha which comprises: (a) hydrotreating a naphtha feed in at
least one hydrotreating step under catalytic hydrotreating
conditions to form a hydrotreated naphtha, (b) conducting at least
a portion of the hydrotreated naphtha to a cracking zone and
hydrocracking the hydrotreated naphtha with a hydrocracking
catalyst under hydrocracking conditions to form a hydrocracked
naphtha and C.sub.5+ recombinant mercaptans, (c) contacting at
least a portion of hydrocracked naphtha with a first phase of a
treatment composition having at least two phases, said treatment
composition containing water, alkali metal hydroxide, cobalt
phthalocyanine sulfonate, and alkyl phenols, wherein (i) the first
phase contains dissolved alkali metal alkylphenylate, dissolved
alkali metal hydroxide, water and dissolved sulfonated cobalt
phthalocyanine, and (ii) the second phase contains water and
dissolved alkali metal hydroxide, and (d) separating from the first
phase an upgraded naphtha having less mercaptans than the
hydrocracked naphtha from step (b).
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims benefit of U.S. Provisional Patent
Application Ser. No. 60/582,112 filed Jun. 23, 2004.
FIELD OF THE INVENTION
[0002] This invention relates to the hydroprocessing of naphtha
with removal of mercaptan from product. More particularly, naphtha
feedstock is hydrotreated and hydrocracked. Sulfur-containing
contaminants are then selectively removed from the naphtha.
BACKGROUND OF THE INVENTION
[0003] 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 by 2004 with possible further reductions mandated in the
future. The feedstocks for motor gasoline are typically
catalytically cracked naphthas that contain substantial amounts of
sulfur and olefins.
[0004] 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.
[0005] One method for addressing the loss of octane problem is by
sequential hydrotreating following by selective cracking. Naphtha
is first hydrotreated which results in some octane loss. Octane is
then restored by selective cracking using an intermediate pore
zeolite such as ZSM-5, either alone or in combination, with other
zeolites.
[0006] Another method for addressing the loss of octane problem is
to fractionate cracked gasoline into a lower boiling fraction and a
higher boiling fraction. The lower boiling fraction is desulfurized
using a non-hydroprocessing step such as mercaptan removal by
extraction. Removal of mercaptans from the lower boiling fraction
can be accomplished by other means including hydroprocessing. The
higher boiling fraction is hydrotreated and octane loss is
addressed by treatment with a catalyst of acidic functionality
followed by a final hydrotreatment to remove any mercaptans
formed.
[0007] It would be desirable to have a method for removing sulfur
contaminants from naphtha while minimizing the octane loss that
accompanies hydrogenation.
SUMMARY OF THE INVENTION
[0008] It has been discovered that a naphtha feed can be
hydrotreated and mercaptans removed from the hydrotreated naphtha
without the need for a further hydrotreatment step and with
improved octane value and yield. Accordingly, the present invention
comprises a process for removing C.sub.5+ mercaptans from a
hydrotreated naphtha which comprises:
[0009] (a) hydrotreating a naphtha feed in at least one
hydrotreating step under catalytic hydrotreating conditions to form
a hydrotreated naphtha,
[0010] (b) conducting at least a portion of the hydrotreated
naphtha to a cracking zone and hydrocracking the hydrotreated
naphtha with a hydrocracking catalyst under hydrocracking
conditions to form a hydrocracked naphtha and C.sub.5+ recombinant
mercaptans,
[0011] (c) separating C.sub.5+ recombinant mercaptans from
hydrocracked naphtha by selective extraction or adsorption.
[0012] In a preferred embodiment, the selective extraction includes
contacting the hydrocracked naphtha and C.sub.5+ recombinant
mercaptans with a composition comprising water, alkali metal
hydroxide, cobalt phthalocyanine sulfonate, and alkylphenols and
having at least two phases, the first phase containing dissolved
alkali metal alkylphenylate, dissolved alkali metal hydroxide,
water and dissolved sulfonated cobalt phthalocyanine and the second
phase containing water and dissolved alkali metal hydroxide.
[0013] Another embodiment for removing mercaptans from a
hydrotreated naphtha comprises:
[0014] (a) hydrotreating a naphtha feed in at least one
hydrotreating step under catalytic hydrotreating conditions to form
a hydrotreated naphtha,
[0015] (b) conducting at least a portion of the hydrotreated
naphtha to a cracking zone and hydrocracking the hydrotreated
naphtha with a hydrocracking catalyst under hydrocracking
conditions to form a hydrocracked naphtha and C.sub.5+ recombinant
mercaptans,
[0016] (c) contacting at least a portion of hydrocracked naphtha
and C.sub.5+ recombinant mercaptans with a first phase of a
treatment composition having at least two phases, said treatment
composition containing water, alkali metal hydroxide, cobalt
phthalocyanine sulfonate, and alkyl phenols, wherein
[0017] (i) a first phase contains dissolved alkali metal
alkylphenylate, dissolved alkali metal hydroxide, water and
dissolved sulfonated cobalt phthalocyanine, and
[0018] (ii) a second phase contains water and dissolved alkali
metal hydroxide, and
[0019] (d) separating an upgraded naphtha having less recombinant
mercaptans than the hydrocracked naphtha.
[0020] In a preferred embodiment, the first and second phases are
substantially immiscible and the first phase is separated into an
upgraded naphtha and an extractant containing recombinant
mercaptans. In another embodiment, hydrocracked naphtha and
C.sub.5+ recombinant mercaptans are contacted with a first phase of
a treatment composition having at least two phases under
substantially anaerobic conditions. In yet another embodiment, the
extractant containing recombinant mercaptans is contacted with an
oxidizing amount of oxygen wherein the mercaptan is oxidized to
disulfide. In another embodiment, the naphtha feed is first
fractionated into a lower boiling fraction containing mercaptans
and a higher boiling fraction containing sulfur heterocyclic
compounds prior to the hydrotreating step.
DETAILED DESCRIPTION OF THE INVENTION
[0021] The feedstocks used in the present process comprise
petroleum fractions boiling in the gasoline boiling range. Such
feeds include fluid catalytically cracked (FCC) naphthas, steam
cracked naphthas and coker naphthas boiling from about 65.degree.
F. to 480.degree. F. (18.degree. C. to 221.degree. C.) as
determined by ASTM D-86. Such naphthas include light cracked
naphthas, intermediate cracked naphthas, heavy cracked naphthas and
full range naphthas. Naphthas typically contain paraffins, olefins,
naphthenes and aromatics as well as heteroatom species containing
nitrogen and sulfur. Olefin contents of naphthas can range up to 60
wt. %, based on naphtha with typical olefin contents in the range
from 5 to 40 wt. %. Sulfur contents of naphthas may range from 50
to greater than 5000 ppmw, based on naphtha. Nitrogen contents for
these feeds are typically less than 500 ppmw. Olefin, nitrogen and
sulfur contents may be determined by standard analytical
techniques.
[0022] With regard to olefin and sulfur contents of naphtha
feedstocks, lighter cracked naphthas (lower boiling naphthas)
typically have the highest amounts of olefins and highest amounts
of mercaptan sulfur compounds whereas heavy cracked naphthas have
the least amounts of olefins and the highest amounts of
heterocyclic sulfur compounds such as thiophenes. The removal of
sulfur compounds from the various naphtha feeds is a function of
the type of sulfur compounds. For the lighter mercaptans (C.sub.4
or less) typical in lower boiling naphthas, extraction or other
non-hydrogenation methods can be employed for removal.
Hydroprocessing options are also available for lighter mercaptans.
For heterocyclic sulfur compounds, hydrotreatment is a generally
accepted means of removal by hydrogenating heterocyclic sulfur
compounds to hydrogen sulfide.
[0023] In the present process, the feedstock may be separated into
a lower boiling fraction and a higher boiling fraction, if desired.
The lower boiling fraction is relatively rich in olefins and
mercaptan sulfur compounds while the higher boiling fraction
relatively poor in olefins and relatively rich in heterocyclic
sulfur compounds. By relatively rich is meant that, of the amount
of the compounds of interest present in the original feedstock,
those compounds of interest are predominantly found in the fraction
in question. In the case of olefins present in the feed, such
olefins will predominantly concentrate in the lower boiling
fraction upon fractionation of the feed. In the case of mercaptan
sulfur compounds, such mercaptans will predominantly concentrate in
the lower boiling fraction upon fractionation of the feed. By
relatively poor is meant that of the amount of compounds of
interest, e.g. olefins, present in the original feedstock, then
those compounds of interest are not predominantly found in the
fraction in question.
[0024] The distillation cut point between the lower and higher
boiling fractions may vary to optimize the process. The exact
numerical value of the cut point will vary according to the sulfur
distribution, type of sulfur compounds present, olefin content and
distribution, as well as the final product specifications.
Normally, the cut point should be selected to keep the sulfur
compounds which cannot be readily removed by extraction, i.e.,
heterocyclic sulfur compounds, in the higher boiling fraction so
that they may be removed by hydrodesulfurization but some of the
mercaptans may be included in the higher boiling fraction as well
since they may be removed under mild hydrotreatment conditions,
although this may result in a loss of the high octane olefins from
the front end of the feed. Higher cut points will be preferred in
order to minimize the amount of feed which is passed to the
hydrotreater. Usually, the cut point will be in the range from
about 100.degree. F. to 230.degree. F. (about 38.degree. C. to
110.degree. C.) and in most cases will be in the range from about
140.degree. F. to 180.degree. F. (about 60.degree. C. to 82.degree.
C.), since the sulfur which is present in components boiling below
about 150.degree. F. (about 65.degree. C.) is mostly in the form of
mercaptans which may be removed by non-hydrogenative extractive
processes, for example, the extractive Merox.RTM. process. The
sulfur compounds in the higher boiling fractions, specifically the
thiophenes and substituted thiophenes are not, however, amenable to
removal by these conventional sweetening processes such as
Merox.RTM. although they may be removed by hydrogenative
processing. A cut point in the range 140.degree. F. to 180.degree.
F. (60.degree. C. to 82.degree. C.) will suffice to put the
thiophene in the heavy cut. Higher cut points between the two
fractions may, however, be used in order to decrease the magnitude
of any yield loss across the hydrogenation step of the process. For
example, a cut point of about 230.degree. F. (about 110.degree. C.)
will leave thiophene in the lower boiling cut but give a better
yield across the hydrogenation step.
[0025] The mercaptans present in the lower boiling fractions are
typically in the C.sub.1 to C.sub.4 range. These mercaptans can be
removed by conventional extraction processes such as Merox.RTM..
These conventional extraction processes may employ techniques based
on caustic extraction or extraction using cresylates.
[0026] Caustic extraction may also be accomplished using the
MEROX.TM. and EXTRACTIVE MEROX.TM. processes which are available
from UOP Products, Des Plains, Ill. In these processes, oxidation
of the caustic phase is accomplished using an iron group-based
catalyst. Phase transfer catalysts may be added to the extraction.
Phase transfer catalysts are known additives which facilitate
transport of a reactive anion from an aqueous phase to an organic
phase in which it might ordinarily be insoluble. Examples of phase
transfer catalysts include quaternary ammonium and quaternary
phosphonium salts, e.g., a quaternary ammonium hydroxide such as
tetraalkyl ammonium hydroxide. Phase transfer catalysts are
typically used in the absence of oxygen during the extraction
step.
[0027] If the naphtha feed is fractionated, the higher boiling
fraction is hydrotreated under hydrotreating conditions to
desulfurize and denitrogenate this fraction. If the naphtha feed is
not fractionated, then the naphtha feed may be directly
hydrotreated under hydrotreating conditions. Hydrotreating
catalysts are well known in the art and may include at least one
Group 6, Group 9 or Group 10 metal, based on the IUPAC periodic
table format having Groups 1-18. Preferred metals include at least
one of Ni, Mo, Co or W on a refractory support such as silica,
alumina, silica-alumina or titania. Preferred combinations of
metals include Ni--Mo or Co--Mo. The amount of metal, either
individually or in combination is from about 0.5 to 35 wt. %, based
on catalyst. Hydrotreating conditions include temperatures of from
150.degree. C. to 400.degree. C., preferably 200.degree. C. to
350.degree. C., pressures of from 790 to 20786 kPa (100 to 3000
psig), preferably 2170 to 13891 kPa (300 to 2000 psig), a liquid
hourly space velocity of 0.1 to 10, preferably 0.1 to 5 and a
hydrogen to feed ratio of from 89 to 1780 m.sup.3/m.sup.3 (500 to
10000 SCF/B), preferably 178 to 890 m.sup.3/m.sup.3 (1000 to 5000
SCF/B). The hydrotreating conditions may be adjusted to achieve
target sulfur and nitrogen levels. These adjustments are known in
the art of hydrotreating.
[0028] The hydrotreated naphtha fraction is then conducted to a
cracking zone in which the hydrotreated naphtha fraction is
contacted with an acidic cracking catalyst thereby increasing the
octane number of this hydrocracked naphtha fraction. In this step,
lower octane components such as n-paraffins and heavy paraffins are
selectively cracked to higher octane products such as lighter
paraffins and olefins. These catalysts have sufficient acidic
functionality to bring about the desired cracking reactions to at
least partially restore octane loss during hydrotreating.
[0029] The catalysts for this selective cracking step are
intermediate pore zeolites having a Constraint Index between 2 and
12. See U.S. Pat. No. 4,784,745 for a description of measuring the
Constraint Index, which reference is incorporated herein. Examples
of suitable intermediate pore zeolites include ZSM-5 (U.S. Pat. No.
3,702,886), ZSM-11 (U.S. Pat. No. 3,709,979), ZSM-12 (U.S. Pat. No.
3,832,449), ZSM-22 (U.S. Pat. No. 4,556,827), ZSM-23 (U.S. Pat. No.
4,076,842), ZSM-35 (U.S. Pat. No. 4,016,245), ZSM-48 (U.S. Pat. No.
4,397,827), ZSM-57 (U.S. Pat. No. 4,046,685), MCM-22 (U.S. Pat. No.
4,962,256), MCM-56 (U.S. Pat. No. 5,632,697) and Offretite.
[0030] Other suitable catalysts are large pore zeolites having a
Constraint Index up to 2. Examples of suitable large pore zeolites
include zeolite beta, mordenite, zeolite X, zeolite L, zeolite Y,
USY, REY, dealuminized Y and ZSM-4.
[0031] Another measure of a sufficient acid activity to have the
desired cracking activity is the catalyst's alpha value. Alpha
values are described in U.S. Pat. No. 4,016,218. A catalyst's alpha
value can be controlled by known techniques such as the Si/Al
ratio, steaming, steaming followed by dealumination and
substituting framework aluminum with other metals. In the present
process, catalysts for the cracking zone have alpha values greater
than 20, preferably 20 to 800, more preferably 50 to 200.
[0032] In addition to the zeolite, catalysts typically contain a
binder material which may be any suitable refractory material such
as silica, alumina, silica-alumina, silica-zirconia and
silica-titania. The cracking zone catalyst may also contain a metal
hydrogenation function. Examples of such metals include those of
Groups 8, 9 and 10, with Groups 9 and 10 being preferred. Mixtures
of such metal are also included. Preferred metals include at least
one of Ni, Co, Pd or Pt, with Ni being especially preferred.
[0033] Hydrocracking conditions for octane improvement include
temperatures of from 150.degree. C. to 482.degree. C., preferably
177.degree. C. to 427.degree. C., pressures of from 446 to 10444
kPa (50 to 1500 psig), preferably 2170 to 6996 kPa (300 to 1000
psig), liquid hourly space velocities of from 0.5 to 10 hr.sup.-1,
preferably 1 to 6 hr.sup.-1, and hydrogen treat gas rates of from 0
to 890 m.sup.3/m.sup.3 (0 to 5000 scf/B), preferably 17.8 to 445
m.sup.3/m.sup.3 (100 to 2500 scf/B).
[0034] A disadvantage of the hydrocracking step to help restore
octane is that the reaction conditions are such that any olefins
present may react with hydrogen sulfide to form mercaptans. These
mercaptans are known as reversion or recombinant mercaptans and are
usually heavier mercaptans such as C.sub.5+ mercaptans.
[0035] Recombinant mercaptans in the C.sub.5+ range cannot be
effectively removed by the conventional extraction techniques used
for lighter mercaptans. In the present process, such recombinant
mercaptans are removed without the need of further hydrotreatment
steps. Instead of further hydrotreatment steps, an aqueous
treatment solution may be formed from water, dissolved alkali metal
hydroxide, dissolved sulfonated cobalt phthalocyanine, and
dissolved alkali metal alkylphenylate. The hydrocracked naphtha
fraction containing mercaptans is contacted with this treatment
solution. The contacting may be under anaerobic conditions, i.e.,
in the essential absence of oxygen. While not wishing to be bound
by any theory or model, it is believed that the presence of
sulfonated cobalt phthalocyanine in the treatment solution lowers
the interfacial energy between the aqueous treatment solution and
the naphtha, which enhances the rapid coalescence of the
discontinuous aqueous regions in the naphtha thereby enabling more
effective separation of the treated naphtha from the treatment
solution. This in turn allows the use of high hydroxide
concentration treatment solutions, which have higher extractant
power for C.sub.5 and higher molecular weight mercaptans (reversion
mercaptans) than conventional treatment solutions.
[0036] Thus, the reduction in mercaptan reversion achieved by a
process that includes using a hydrocracking step followed by
mercaptan extraction, which produces a naphtha product useful in
forming gasoline both low total sulfur and mercaptan sulfur, while
preserving the olefins valuable for octane number. At
technologically important deep desulfurization levels, e.g., 90-100
wt. % feed sulfur removal, particularly with relatively high sulfur
content naphtha feeds (e.g., >1000-7000 wppm sulfur), the
contribution of sulfur from reversion mercaptans to the total
sulfur, can be significant. Therefore, the control of mercaptan
formation is necessary to reach sulfur levels of less than about
150 wppm, especially less than about 30 wppm.
[0037] The treatment solution may be prepared by combining alkali
metal hydroxide, alkylphenols, sulfonated cobalt phthalocyanine,
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 80.degree. F. to
about 150.degree. F. and a pressure range of about ambient (zero
psig) to about 200 psig.
[0038] In one embodiment, the two-phase treatment solution may be
contacted with the hydrocracked naphtha and allowed to settle.
Treated, hydrocracked naphtha settles above the top phase and
separates from the top phase. Alternatively, the treatment solution
may be separated into a top and bottom phase following which
hydrocracked naphtha is contacted with the top phase. The top phase
may be regenerated and recycled to the process for re-use.
[0039] The treatment solution may also be prepared to produce a
single liquid phase of dissolved alkali metal hydroxide, alkali
metal alkylphenylate, sulfonated cobalt pthalocyanine, and water
provided the single phase formed is compositionally located on the
phase boundary between the one-phase and two-phase regions of a
ternary phase diagram. In other words, the top phase may be
prepared directly without a bottom phase, provided the top-phase
composition is regulated to remain at the boundary between the
one-phase and two-phase regions of the dissolved alkali metal
hydroxide-alkali metal alkylphenylate-water in the ternary-phase
diagram. The phase diagram is further described in U.S. Published
Application 2003/0052045 incorporated herein by reference. The
compositional location of the treatment solution may be ascertained
by determining its miscibility with the analogous aqueous alkali
metal hydroxide. The analogous aqueous alkali metal hydroxide is
the bottom phase that would be present if the treatment solution
had been prepared with compositions within the two-phase region of
the phase diagram. As the top phase and bottom phase are
homogeneous and immiscible, a treatment solution prepared without a
bottom phase will be immiscible in the analogous aqueous alkali
metal hydroxide. The single-phase treatment is then contacted with
the hydrocarbon. After the treatment solution has been used to
contact the hydrocarbon, it may be regenerated for re-use, as
discussed for two-phase treatment solutions, but no bottom phase is
present in this embodiment. Such a single-phase treatment solution
is also referred to as an extractant, even when no bottom phase is
present.
[0040] The total sulfur amount in the naphtha product may be
reduced by removing sulfur species such as disulfides from the
extractant. Therefore, one may treat a naphtha feed by the
extraction of the mercaptans from the naphtha to an aqueous
treatment solution where the mercaptans subsist as water-soluble
mercaptides and then converting the water-soluble mercaptides to
water-insoluble disulfides. The sulfur, now in the form of
hydrocarbon-soluble disulfides, may then be separated from the
treatment solution and conducted away from the process so that a
treated naphtha substantially free of mercaptans and of reduced
sulfur content may be separated from the process. Alternatively, a
second hydrocarbon may be employed to facilitate separation of the
disulfides and conduct them away. The process may be operated so
that the flow of the treatment solution is cocurrent to naphtha
flow, countercurrent to naphtha flow, or a combination thereof.
[0041] Mercaptan adsorption is a non-hydrotreating means of
removing mercaptans from feeds and products. It is preferred that
hydrotreated effluent from step one be stripped of hydrogen sulfide
and ammonia prior to the adsorption step. In one embodiment,
mercaptans are adsorbed by means of chemisorption using metals or
metal oxides. Metals may be from Groups 7-12 of the IUPAC periodic
table and include at least one of Ni, Co, Cu, Pt, Zn, Mn, and Cd,
which metals or metal oxides may be supported on a porous carrier
such as clay, carbon or metal oxides such as alumina. The metals or
metal oxides adsorb sulfur by chemisorption, typically by formation
of metal sulfides. Another form of adsorbent is based on adsorbents
that physically adsorb mercaptans. This class of adsorbents
typically utilizes molecular sieves as the adsorbent. Examples of
this type of adsorbent include crystalline metal silicates and
zeolites of the faujasite family such as zeolites X and Y, zeolite
A and mordenite. Adsorbents may include metal exchanged forms with
metals from Groups 1-12. U.S. Pat. No. 5,843,300 is an example of
the use of metal-exchanged zeolites. Adsorption can also be
accomplished by ion-exchange resins. In the adsorption technique,
the naphtha effluent from the HDS reactor is contacted with
adsorbent usually in the form of a fixed bed. In the case of
mercaptans that are removed by physical techniques, it may be
possible to regenerate the adsorbent by heating, reduced pressure,
stripping or some combination thereof to desorb the mercaptans.
Those adsorbents that function by chemisorption are typically
replaced when spent as they are non-regenerable or very difficult
to regenerate. Contacting with adsorbent is normally at ambient
temperatures for physical adsorbents whereas chemisorption operates
at elevated temperatures of 70.degree. C. up to 500.degree. C.
* * * * *