U.S. patent application number 14/279775 was filed with the patent office on 2014-09-11 for integrated desulfurization and denitrification process including mild hydrotreating and oxidation of aromatic-rich hydrotreated products.
This patent application is currently assigned to Saudi Arabian Oil Company. The applicant listed for this patent is Saudi Arabian Oil Company. Invention is credited to Emad AL-SHAFI, Farhan M. AL-SHAHRANI, Abdennour BOURANE, Omer Refa KOSEOGLU.
Application Number | 20140251873 14/279775 |
Document ID | / |
Family ID | 46198229 |
Filed Date | 2014-09-11 |
United States Patent
Application |
20140251873 |
Kind Code |
A1 |
KOSEOGLU; Omer Refa ; et
al. |
September 11, 2014 |
INTEGRATED DESULFURIZATION AND DENITRIFICATION PROCESS INCLUDING
MILD HYDROTREATING AND OXIDATION OF AROMATIC-RICH HYDROTREATED
PRODUCTS
Abstract
Reduction of sulfur-containing and nitrogen-containing compounds
from hydrocarbon feeds is achieved by first contacting the entire
feed with a hydrotreating catalyst in a hydrotreating reaction zone
operating under mild conditions to convert the labile organosulfur
and organonitrogen compounds. An extraction zone downstream of the
hydrotreating reaction zone separates an aromatic-rich fraction
that contains a substantial amount of the remaining refractory
organosulfur and organonitrogen compounds. The aromatic-lean
fraction is substantially free of organosulfur and organonitrogen
compounds, since the non-aromatic organosulfur and organonitrogen
compounds were the labile organosulfur and organonitrogen compounds
which were initially removed by mild hydrotreating. The
aromatic-rich fraction is oxidized to convert the refractory
organosulfur and organonitrogen compounds to oxidized
sulfur-containing and nitrogen-containing hydrocarbon compounds.
These oxidized organosulfur and organonitrogen compounds are
subsequently removed.
Inventors: |
KOSEOGLU; Omer Refa;
(Dhahran, SA) ; BOURANE; Abdennour; (Ras Tanura,
SA) ; AL-SHAHRANI; Farhan M.; (Thuwal, SA) ;
AL-SHAFI; Emad; (Dhahran, SA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Saudi Arabian Oil Company |
Dhahran |
|
SA |
|
|
Assignee: |
Saudi Arabian Oil Company
Dhahran
SA
|
Family ID: |
46198229 |
Appl. No.: |
14/279775 |
Filed: |
May 16, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
12967199 |
Dec 14, 2010 |
8741127 |
|
|
14279775 |
|
|
|
|
Current U.S.
Class: |
208/212 ;
196/14.52 |
Current CPC
Class: |
C10G 2300/202 20130101;
B01J 2219/00777 20130101; C10G 67/14 20130101; C10G 2300/1096
20130101; C10G 21/27 20130101; C10G 67/12 20130101; C10G 67/04
20130101; C10G 21/00 20130101; C10G 27/04 20130101; C10G 45/22
20130101; B01J 19/006 20130101; C10G 45/02 20130101; C10G 53/04
20130101; B01J 19/18 20130101; C10G 21/16 20130101; C10G 2300/44
20130101; C10G 53/14 20130101; C10G 27/12 20130101; B01J 2219/00768
20130101; C10G 27/14 20130101; C10G 21/20 20130101; C10G 67/0418
20130101 |
Class at
Publication: |
208/212 ;
196/14.52 |
International
Class: |
C10G 45/22 20060101
C10G045/22 |
Claims
1. A method of processing a hydrocarbon feed to remove undesired
aromatic and non-aromatic organosulfur compounds comprising:
subjecting the hydrocarbon feed to a hydrotreating process to
thereby lower the content of labile organosulfur compounds and
produce a hydrotreated effluent; conveying the hydrotreated
effluent and an effective quantity of extraction solvent to an
extraction zone to produce an extract containing a major proportion
of the aromatic content of the hydrotreated effluent and a portion
of the extraction solvent and a raffinate containing a major
proportion of the non-aromatic content of the hydrotreated effluent
and a portion of the extraction solvent; separating at least a
substantial portion of the extraction solvent from the extract and
retaining an aromatic-rich fraction; contacting the aromatic-rich
fraction with an oxidizing agent and an oxidizing catalyst to
convert aromatic organosulfur compounds to oxides.
2. The method of claim 1, wherein the hydrocarbon feed further
includes undesired aromatic and non-aromatic organonitrogen
compounds, the step of subjecting the hydrocarbon feed to a
hydrotreating process also lowers the content of labile
organonitrogen compounds, and the step of contacting the
aromatic-rich fraction with the oxidizing agent and the oxidizing
catalyst also convert aromatic organonitrogen compounds to
oxides.
3. The method of claim 1, wherein the hydrotreating process is
operated at mild operating conditions.
4. The method of claim 3, wherein the hydrotreating process
operates with a hydrogen partial pressure of about 10 bars to about
40 bars.
5. The method of claim 3, wherein the hydrotreating process
operates with a hydrogen partial pressure of about 10 bars to about
30 bars.
6. The method of claim 3, wherein the hydrotreating process
operates with a hydrogen partial pressure of about 20 bars.
7. The method of claim 3, wherein the hydrotreating process
operates with an operating temperature of about 300.degree. C. to
about 400.degree. C.
8. The method of claim 3, wherein the hydrotreating process
operates with an operating temperature of about 300.degree. C. to
about 360.degree. C.
9. The method of claim 3, wherein hydrotreating process operates
with an operating temperature of about 300.degree. C. to about
340.degree. C.
10. The method of claim 3, wherein the hydrogen feed rate in the
hydrotreating process step is from about 100 liters of hydrogen per
liter of oil to about 500 liters of hydrogen per liter of oil.
11. The method of claim 3, wherein the hydrogen feed rate in the
hydrotreating process step is from about 100 liters of hydrogen per
liter of oil to about 300 liters of hydrogen per liter of oil.
12. The method of claim 3, wherein the hydrogen feed rate in the
hydrotreating process step is from about 100 liters of hydrogen per
liter of oil to about 200 liters of hydrogen per liter of oil.
13. The method of claim 1, wherein the oxidizing agent is selected
from the group consisting of hydrogen peroxide, organic peroxides
such as ter-butyl hydroperoxide, peroxo acids, oxides of nitrogen,
oxygen, ozone, and air.
14. The method of claim 1, wherein the oxidizing catalyst is
selected from the group consisting of homogeneous catalysts and
heterogeneous catalysts.
15. The method of claim 14, wherein the oxidizing catalyst includes
a metal from Group IVB to Group VIIIB of the Periodic Table.
16. The method of claim 1, further comprising separating the
oxidizing agent and oxidizing catalyst from the oxidized
aromatic-rich fraction.
17. The method of claim 16, wherein the oxidizing agent is
separated by solvent extraction.
18. The method of claim 1, further comprising recovering a
hydrotreated hydrocarbon product.
19. The method of claim 1, further comprising recovering a
hydrocarbon product subjected to oxidative desulfurization.
20. The method of claim 1, further comprising combining the
aromatic-lean raffinate and the aromatic-rich fraction that has
been subjected to oxidation to provide a reduced-organosulfur
content hydrocarbon product.
21. The method of claim 1, wherein the extraction solvent is
selected from the group consisting of furfural,
N-methyl-2-pyrrolidone, dimethylformamide and
dimethylsulfoxide.
22. The method of claim 1, wherein the extraction solvent is
provided in a solvent to oil ratio of 20:1.
23. The method of claim 1, wherein the extraction solvent is
provided in a solvent to oil ratio of 4:1.
24. The method of claim 1, wherein the extraction solvent is
provided in a solvent to oil ratio of 1:1.
25. The method of claim 1, wherein the extraction zone operates at
a temperature of about 20.degree. C. to about 120.degree. C.
26. The method of claim 1, wherein the extraction zone operates at
a temperature of about 40.degree. C. to about 80.degree. C.
27. The method of claim 1, wherein the extraction zone operates at
a pressure of about 1 bar to about 10 bars.
28. The method of claim 1, wherein the extraction zone operates at
a pressure of about 1 bar to about 3 bars.
29. An apparatus for processing a hydrocarbon feed containing
undesired organosulfur compounds comprising: a hydrotreating zone
having an inlet in fluid communication with the hydrocarbon feed
and an outlet for discharging hydrotreated effluent; an extraction
zone operable to extract aromatic organosulfur compounds from the
hydrotreated effluent, the aromatic zone extraction including an
inlet for receiving the hydrotreated effluent and an inlet for
receiving extraction solvent, a raffinate outlet for discharging a
raffinate containing a major proportion of the non-aromatic content
of the hydrotreated effluent and a portion of the extraction
solvent, and an extract outlet for discharging an extract
containing a major proportion of the aromatic content of the
hydrotreated effluent and a portion of the extraction solvent; an
oxidation zone containing an oxidation catalyst and an oxidizing
agent, the oxidative desulfurization zone having an inlet in fluid
communication with the extract outlet and an outlet for discharging
oxidized effluent.
Description
RELATED APPLICATIONS
[0001] The present application is a continuation of U.S. Ser. No.
12/967,199 filed Dec. 14, 2010, which is incorporated by reference
herein.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] The present invention relates to integrated oxidation
processes to efficiently reduce the sulfur and nitrogen content of
hydrocarbons to produce fuels having reduced sulfur and nitrogen
levels.
[0004] 2. Description of Related Art
[0005] The discharge into the atmosphere of sulfur compounds during
processing and end-use of the petroleum products derived from
sulfur-containing sour crude oil pose health and environmental
problems. The stringent reduced-sulfur specifications applicable to
transportation and other fuel products have impacted the refining
industry, and it is necessary for refiners to make capital
investments to greatly reduce the sulfur content in gas oils to 10
parts per million by weight (ppmw), or less. In industrialized
nations such as the United States, Japan and the countries of the
European Union, refineries for transportation fuel have already
been required to produce environmentally clean transportation
fuels. For instance, in 2007 the United States Environmental
Protection Agency required the sulfur content of highway diesel
fuel to be reduced 97%, from 500 ppmw (low sulfur diesel) to 15
ppmw (ultra-low sulfur diesel). The European Union has enacted even
more stringent standards, requiring diesel and gasoline fuels sold
in 2009 to contain less than 10 ppmw of sulfur. Other countries are
following in the direction of the United States and the European
Union and are moving forward with regulations that will require
refineries to produce transportation fuels with an ultra-low sulfur
level.
[0006] To keep pace with recent trends toward production of
ultra-low sulfur fuels, refiners must choose among the processes or
crude oils that provide flexibility to ensure that future
specifications are met with minimum additional capital investment,
in many instances by utilizing existing equipment. Conventional
technologies such as hydrocracking and two-stage hydrotreating
offer solutions to refiners for the production of clean
transportation fuels. These technologies are available and can be
applied as new grassroots production facilities are constructed.
However, many existing hydroprocessing facilities, such as those
using relatively low pressure hydrotreaters were constructed before
these more stringent sulfur reduction requirements were enacted and
represent a substantial prior investment. It is very difficult to
upgrade existing hydrotreating reactors in these facilities because
of the comparatively more severe operational requirements (i.e.,
higher temperature and pressure conditions) to obtain clean fuel
production. Available retrofitting options for refiners include
elevation of the hydrogen partial pressure by increasing the
recycle gas quality, utilization of more active catalyst
compositions, installation of improved reactor components to
enhance liquid-solid contact, the increase of reactor volume, and
the increase of the feedstock quality.
[0007] There are many hydrotreating units installed worldwide
producing transportation fuels containing 500-3000 ppmw sulfur.
These units were designed for, and are being operated at,
relatively mild conditions, i.e., low hydrogen partial pressures of
30 kilograms per square centimeter for straight run gas oils
boiling in the range of 180 C..degree.-370.degree. C.
[0008] However, with the increasing prevalence of more stringent
environmental sulfur specifications in transportation fuels
mentioned above, the maximum allowable sulfur levels are being
reduced to no greater than 15 ppmw, and in some cases no greater
than 10 ppmw. This ultra-low level of sulfur in the end product
typically requires either construction of new high pressure
hydrotreating units, or a substantial retrofitting of existing
facilities, e.g., by integrating new reactors, incorporating gas
purification systems, reengineering the internal configuration and
components of reactors, and/or deployment of more active catalyst
compositions. Each of these options represents a substantial
capital investment
[0009] Sulfur-containing compounds that are typically present in
hydrocarbon fuels include aliphatic molecules such as sulfides,
disulfides and mercaptans, as well as aromatic molecules such as
thiophene, benzothiophene and its long chain alkylated derivatives,
and dibenzothiophene and its alkyl derivatives such as
4,6-dimethyl-dibenzothiophene. Aromatic sulfur-containing molecules
have a higher boiling point than aliphatic sulfur-containing
molecules, and are consequently more abundant in higher boiling
fractions.
In addition, certain fractions of gas oils possess different
properties. The following table illustrates the properties of light
and heavy gas oils derived from Arabian Light crude oil:
TABLE-US-00001 TABLE 1 Feedstock Name Light Heavy Blending Ratio --
-- API Gravity .degree. 37.5 30.5 Carbon wt % 85.99 85.89 Hydrogen
wt % 13.07 12.62 Sulfur wt % 0.95 1.65 Nitrogen ppmw 42 225 ASTM
D86 Distillation IBP/5 V % .degree. C. 189/228 147/244 10/30 V %
.degree. C. 232/258 276/321 50/70 V % .degree. C. 276/296 349/373
85/90 V % .degree. C. 319/330 392/398 95 V % .degree. C. 347 Sulfur
Speciation Organosulfur Compounds ppmw 4591 3923 Boiling Below
310.degree. C. Dibenzothiophenes ppmw 1041 2256 C.sub.1-
Dibenzothiophenes ppmw 1441 2239 C.sub.2- Dibenzothiophenes ppmw
1325 2712 C.sub.3- Dibenzothiophenes ppmw 1104 5370
[0010] As set forth above in Table 1, the light and heavy gas oil
fractions have ASTM D86 85 V % points of 319.degree. C. and
392.degree. C., respectively. Further, the light gas oil fraction
contains less sulfur and nitrogen than the heavy gas oil fraction
(0.95 wt % sulfur as compared to 1.65 wt % sulfur and 42 ppmw
nitrogen as compared to 225 ppmw nitrogen).
[0011] Advanced analytical techniques such as multi-dimensional gas
chromatography with a sulfur chemiluminescence detector as
described by Hua, et al. (Hua R., et al., "Determination of
sulfur-containing compounds in diesel oils by comprehensive
two-dimensional gas chromatography with a sulfur chemiluminescence
detector," Journal of Chromatography A, Volume 1019, Issues 1-2,
Nov. 26, 2003, Pages 101-109) have shown that the middle distillate
cut boiling in the range of 170-400.degree. C. contains sulfur
species including thiols, sulfides, disulfides, thiophenes,
benzothiophenes, dibenzothiophenes, and benzonaphthothiophenes,
with and without alkyl substituents.
[0012] The sulfur speciation and content of light and heavy gas
oils are conventionally analyzed by two methods. In the first
method, sulfur species are categorized based on structural groups.
The structural groups include one group having sulfur-containing
compounds boiling at less than 310.degree. C., including
dibenzothiophenes and its alkylated isomers, and another group
including 1-, 2- and 3-methyl-substituted dibenzothiophenes,
denoted as C.sub.1, C.sub.2 and C.sub.3, respectively. Based on
this method, the heavy gas oil fraction contains more alkylated
di-benzothiophene molecules than the light gas oils.
[0013] In the second method of analyzing sulfur content of
hydrocarbons, and referring to FIG. 1A, the cumulative sulfur
concentrations are plotted against the boiling points of the
sulfur-containing compounds to observe concentration variations and
trends. Note that the boiling points depicted are those of detected
sulfur-containing compounds, rather than the boiling point of the
total hydrocarbon mixture. The boiling point of several refractory
sulfur-containing compounds including dibenzothiophene,
4-methyldibenzothiophene and 4,6-dimethyldibenzothiophene are also
shown in FIG. 1A for convenience. The cumulative sulfur
specification curves show that the aromatic portion contains a
higher proportion of heavier sulfur-containing compounds and a
lower proportion of lighter sulfur-containing compounds as compared
to the fraction containing primarily paraffins and naphthenes.
[0014] Aliphatic sulfur-containing compounds are more easily
desulfurized (labile) using conventional hydrodesulfurization
methods. However, certain highly branched aliphatic molecules can
sterically hinder the sulfur atom removal and are moderately more
difficult (refractory) to desulfurize using conventional
hydrodesulfurization methods.
[0015] Among the sulfur-containing aromatic compounds, thiophenes
and benzothiophenes are relatively easy to hydrodesulfurize. The
addition of alkyl groups to the ring compounds increases the
difficulty of hydrodesulfurization. Dibenzothiophenes resulting
from addition of another aromatic ring to the benzothiophene family
are even more difficult to desulfurize, and the difficulty varies
greatly according to their alkyl substitution, with di-beta
substitution being the most difficult to desulfurize, thus
justifying their "refractory" appellation. These beta substituents
hinder exposure of the heteroatom to the active site on the
catalyst.
[0016] The economical removal of refractory sulfur-containing
compounds is therefore exceedingly difficult to achieve, and
accordingly removal of sulfur-containing compounds in hydrocarbon
fuels to an ultra-low sulfur level is very costly utilizing current
hydrotreating techniques. When previous regulations permitted
sulfur levels up to 500 ppmw, there was little need or incentive to
desulfurize beyond the capabilities of conventional
hydrodesulfurization, and hence the refractory sulfur-containing
compounds were not targeted. However, in order to meet the more
stringent sulfur specifications, these refractory sulfur-containing
compounds must be substantially removed from hydrocarbon fuels
streams.
[0017] The relative reactivity of thiols and sulfides are much
higher than those of aromatic sulfur compounds, as indicated in a
study published in Song, Chunshan, "An overview of new approaches
to deep desulfurization for ultra-clean gasoline, diesel fuel and
jet fuel" Catalysis Today, 86 (2003), pp. 211-263. Mercaptan/thiols
and sulfides are much more reactive than the aromatic sulfur
compounds. It should be noted that non-thiophenic sulfides such as
paraffinic and/or naphthenic are present in diesel range
hydrocarbons as seen from the chromatograph of FIG. 1B.
[0018] The development of non-catalytic processes for
desulfurization of petroleum distillate feedstocks has been widely
studied, and certain conventional approaches are based on oxidation
of sulfur-containing compounds described, e.g., in U.S. Pat. Nos.
5,910,440, 5,824,207, 5,753,102, 3,341,448 and 2,749,284.
[0019] Oxidation processes for heteroatomic compounds, such as
oxidative desulfurization is attractive for several reasons. First,
relatively mild reaction conditions, e.g., temperature from room
temperature up to 200.degree. C. and pressure from 1 up to 15
atmospheres, can often be used, thereby resulting a priori in
reasonable investment and operational costs, especially compared to
hydrogen consumption in hydroprocessing techniques which is usually
expensive. Another attractive aspect of the oxidative process is
related to the reactivity of aromatic sulfur-containing species.
This is evident since the high electron density at the sulfur atom
caused by the attached electron-rich aromatic rings, which is
further increased with the presence of additional alkyl groups on
the aromatic rings, will favor its electrophilic attack as shown in
Table 2 (Otsuki, S. et al., "Oxidative desulfurization of light gas
oil and vacuum gas oil by oxidation and solvent extraction," Energy
Fuels 14:1232-1239 (2000)). Moreover, the intrinsic reactivity of
molecules such as 4,6-DMBT is substantially higher than that of
DBT, which is much easier to desulfurize by
hydrodesulfurization.
TABLE-US-00002 TABLE 2 Electron Density of selected sulfur species
Sulfur Electron K compound Formulas Density (L/(mol min))
Thiophenol ##STR00001## 5.902 0.270 Methyl Phenyl Sulfide
##STR00002## 5.915 0.295 Diphenyl Sulfide ##STR00003## 5.860 0.156
4,6-DMDBT ##STR00004## 5.760 0.0767 4-MDBT ##STR00005## 5.759
0.0627 Dibenzo- thiophene ##STR00006## 5.758 0.0460 Benzo-
thiophene ##STR00007## 5.739 0.00574 2,5-Dimethyl- thiophene
##STR00008## 5.716 -- 2-methyl- thiophene ##STR00009## 5.706 --
Thiophene ##STR00010## 5.696 --
[0020] Certain existing desulfurization processes incorporate both
hydrodesulfurization and oxidative desulfurization. For instance,
Cabrera et al. U.S. Pat. No. 6,171,478 describes an integrated
process in which the hydrocarbon feedstock is first contacted with
a hydrodesulfurization catalyst in a hydrodesulfurization reaction
zone to reduce the content of certain sulfur-containing molecules.
The resulting hydrocarbon stream is then sent in its entirety to an
oxidation zone containing an oxidizing agent where residual
sulfur-containing compounds are converted into oxidized
sulfur-containing compounds. After decomposing the residual
oxidizing agent, the oxidized sulfur-containing compounds are
solvent extracted, resulting in a stream of oxidized
sulfur-containing compounds and a reduced-sulfur hydrocarbon oil
stream. A final step of adsorption is carried out on the latter
stream to further reduce the sulfur level.
[0021] Kocal U.S. Pat. No. 6,277,271 also discloses a
desulfurization process integrating hydrodesulfurization and
oxidative desulfurization. A stream composed of sulfur-containing
hydrocarbons and a recycle stream containing oxidized
sulfur-containing compounds is introduced in a hydrodesulfurization
reaction zone and contacted with a hydrodesulfurization catalyst.
The resulting hydrocarbon stream containing a reduced sulfur level
is contacted in its entirety with an oxidizing agent in an
oxidation reaction zone to convert the residual sulfur-containing
compounds into oxidized sulfur-containing compounds. The oxidized
sulfur-containing compounds are removed in one stream and a second
stream of hydrocarbons having a reduced concentration of oxidized
sulfur-containing compounds is recovered. Like the process in
Cabrera et al., the entire hydrodesulfurized effluent is subjected
to oxidation in the Kocal process.
[0022] Wittenbrink et al. U.S. Pat. No. 6,087,544 discloses a
desulfurization process in which a distillate feedstream is first
fractionated into a light fraction containing from about 50 to 100
ppm of sulfur, and a heavy fraction. The light fraction is passed
to a hydrodesulfurization reaction zone. Part of the desulfurized
light fraction is then blended with half of the heavy fraction to
produce a low sulfur distillate fuel. However, not all of the
distillate feedstream is recovered to obtain the low sulfur
distillate fuel product, resulting in a substantial loss of high
quality product yield.
[0023] Rappas et al. PCT Publication WO02/18518 discloses a
two-stage desulfurization process located downstream of a
hydrotreater. After having been hydrotreated in a
hydrodesulfurization reaction zone, the entire distillate
feedstream is introduced to an oxidation reaction zone to undergo
biphasic oxidation in an aqueous solution of formic acid and
hydrogen peroxide. Thiophenic sulfur-containing compounds are
converted to corresponding sulfones. Some of the sulfones are
retained in the aqueous solution during the oxidation reaction, and
must be removed by a subsequent phase separation step. The oil
phase containing the remaining sulfones is subjected to a
liquid-liquid extraction step. In the process of WO02/18518, like
Cabrera et al. and Kocal, the entire hydrodesulfurized effluent is
subject to oxidation reactions, in this case biphasic
oxidation.
[0024] Levy et al. PCT Publication WO03/014266 discloses a
desulfurization process in which a hydrocarbon stream having
sulfur-containing compounds is first introduced to an oxidation
reaction zone. Sulfur-containing compounds are oxidized into the
corresponding sulfones using an aqueous oxidizing agent. After
separating the aqueous oxidizing agent from the hydrocarbon phase,
the resulting hydrocarbon stream is passed to a
hydrodesulfurization step. In the process of WO03/014266, the
entire effluent of the oxidation reaction zone is subject to
hydrodesulfurization.
[0025] Gong et al. U.S. Pat. No. 6,827,845 discloses a three-step
process for removal of sulfur- and nitrogen-containing compounds in
a hydrocarbon feedstock. All or a portion of the feedstock is a
product of a hydrotreating process. In the first step, the feed is
introduced to an oxidation reaction zone containing peracid that is
free of catalytically active metals. Next, the oxidized
hydrocarbons are separated from the acetic acid phase containing
oxidized sulfur and nitrogen compounds. In this reference, a
portion of the stream is subject to oxidation. The highest cut
point identified is 316.degree. C. In addition, this reference
explicitly avoids catalytically active metals in the oxidation
zone, which necessitates an increased quantity of peracid and more
severe operating conditions. For instance, the H.sub.2O.sub.2:S
molar ratio in one of the examples is 640, which is extremely high
as compared to oxidative desulfurization with a catalytic
system.
[0026] Gong et al. U.S. Pat. No. 7,252,756 discloses a process for
reducing the amount of sulfur- and/or nitrogen-containing compounds
for refinery blending of transportation fuels. A hydrocarbon
feedstock is contacted with an immiscible phase containing hydrogen
peroxide and acetic acid in an oxidation zone. After a gravity
phase separation, the oxidized impurities are extracted with
aqueous acetic acid. A hydrocarbon stream having reduced impurities
is recovered, and the acetic acid phase effluents from the
oxidation and the extraction zones are passed to a common
separation zone for recovery of the acetic acid. In an optional
embodiment of U.S. Pat. No. 7,252,756, the feedstock to the
oxidation process can be a low-boiling component of a hydrotreated
distillate. This reference contemplates subjecting the low boiling
fraction to the oxidation zone.
[0027] None of the above-mentioned references describe a suitable
and cost-effective process for desulfurization of hydrocarbon fuel
fractions with specific sub-processes and apparatus for targeting
different organosulfur compounds. In particular, conventional
methods do not separate a hydrocarbon fuel stream into fractions
containing different classes of sulfur-containing compounds with
different reactivities relative to the conditions of
hydrodesulfurization and oxidative desulfurization. Conventionally,
most approaches subject the entire gas oil stream to the oxidation
reactions, requiring unit operations that must be appropriately
dimensioned to accommodate the full process flow.
[0028] Aromatic extraction is an established process used at
certain stages of various refinery and other petroleum-related
operations. In certain existing processes, it is desirable to
remove aromatics from the end product, e.g., lube oils and certain
fuels, e.g., diesel fuel. In other processes, aromatics are
extracted to produce aromatic-rich products, for instance, for use
in various chemical processes and as an octane booster for
gasoline.
[0029] U.S. Pat. No. 5,021,143 discloses a process in which a feed
is fractionated into a light naphtha, a medium naphtha and a heavy
naphtha. Aromatics are extracted from the heavy naphtha fraction
using a selective liquid solvent, and the aromatic-lean raffinate
is mixed with the kerosene or diesel pool. The aromatic-rich
extract is regenerated by contacting with light petrol so as to
produce an aromatic-rich petrol product.
[0030] U.S. Pat. No. 4,359,596 discloses a process in which
aromatics are extracted from hydrocarbon mixtures such as
isomerization process streams, catalytic cracking naphthas, and
lube stocks. Liquid salts, such as quaternary phosphonium and
ammonium salts of halides, acids or more complex anions are used as
extraction liquids.
[0031] U.S. Pat. Nos. 4,592,832, 4,909,927, 5,110,445 5,880,325 and
6,866,772 disclose various processes for upgrading lube oils. In
particular, these processes use various solvents to extract
aromatics.
[0032] With the steady increase in demand for hydrocarbon fuels
having an ultra-low sulfur level, a need exists for an efficient
and effective process and apparatus for desulfurization. As far as
the present inventors are aware, it has not previously been
suggested to combine well-established aromatic extraction
technology with desulfurization of hydrocarbon fuels, and in
particular with integrated desulfurization including hydrotreating
and oxidative desulfurization.
[0033] Accordingly, it is an object of the present invention to
desulfurize and denitrify a hydrocarbon fuel stream containing
different classes of sulfur-containing and nitrogen-containing
compounds having different reactivities utilizing reactions
separately directed to labile and refractory classes of
sulfur-containing and nitrogen-containing compounds.
[0034] It is a further object of the present invention to produce
hydrocarbon fuels having reduced sulfur and nitrogen levels by
removal of labile organosulfur and organonitrogen compounds in a
feedstream using hydrotreating under relatively mild conditions
followed by targeted removal of refractory organosulfur and
organonitrogen compounds using oxidation.
[0035] As used herein, the term "labile organosulfur compounds"
means organosulfur compounds that can be easily desulfurized under
relatively mild hydrotreating pressure and temperature conditions,
and the term "refractory organosulfur compounds" means organosulfur
compounds that are relatively more difficult to desulfurize under
mild hydrotreating conditions. Likewise, the term "labile
organonitrogen compounds" means organonitrogen compounds that can
be easily denitrified under relatively mild hydrotreating pressure
and temperature conditions, and the term "refractory organonitrogen
compounds" means organonitrogen compounds that are relatively more
difficult to denitrify under mild hydrotreating conditions.
[0036] Additionally, as used herein, the terms "mild hydrotreating"
and "mild operating conditions" (when used in reference to
hydrotreating) means hydrotreating processes operating at
temperatures of 400.degree. C. and below, hydrogen partial
pressures of 40 bars and below, and hydrogen feed rates of 500
liters per liter of oil, and below.
SUMMARY OF THE INVENTION
[0037] The above objects and further advantages are provided by the
apparatus and process of the invention for removal of undesired
aromatic and non-aromatic organosulfur and organonitrogen
compounds, both refractory and labile, which utilizes mild
hydrotreating of a fuel stream to remove labile organosulfur and
organonitrogen compounds and oxidation of an aromatic-rich fraction
of the hydrotreated intermediate product to remove refractory
organosulfur and organonitrogen compounds.
[0038] According to the present invention, a cost-effective
apparatus and process for reduction of sulfur and nitrogen levels
of hydrocarbon streams includes integration of hydrotreating with
an oxidation reaction zone, in which the hydrocarbon
sulfur-containing compounds are converted by oxidation to compounds
containing sulfur and oxygen, such as sulfoxides or sulfones, and
the hydrocarbon nitrogen-containing compounds are converted by
oxidation to compounds containing nitrogen and oxygen. The oxidized
sulfur-containing and nitrogen-containing compounds have different
chemical and physical properties, which facilitate their removal
from the balance of the hydrocarbon stream. Oxidized
sulfur-containing and nitrogen-containing compounds can be removed
by extraction, distillation and/or adsorption.
[0039] The present invention comprehends an integrated system and
process that is capable of efficiently and cost-effectively
reducing the organosulfur and organonitrogen content of hydrocarbon
fuels. The cost of hydrotreating is minimized by operating under
relatively mild temperature and pressure conditions conforming to
the capabilities of existing prior art hydrotreating apparatus and
systems. For instance, deep desulfurization of hydrocarbon fuels
according to the present invention effectively optimizes use of
integrated apparatus and processes, combining mild hydrotreating
(such as hydrodesulfurization) and oxidation (such as oxidative
desulfurization). Most importantly, using the apparatus and process
of the present invention, refiners can adapt existing hydrotreating
equipment and run such equipment under mild operating conditions.
Accordingly, hydrocarbon fuels are economically desulfurized and
denitrified to very low levels.
[0040] Deep desulfurization and denitrification of hydrocarbon
feedstreams is achieved by first contacting the entire fuel stream
with a catalyst, such as a hydrodesulfurization catalyst, in a
hydrotreating reaction zone operating at mild conditions to convert
labile organosulfur and organonitrogen compounds. An aromatic
separation zone downstream of the hydrotreating reaction zone
separates the hydrotreated effluent to obtain a first fraction,
which is a relatively aromatic-lean fraction, and a second
fraction, which is a relatively aromatic-rich fraction.
[0041] Since aromatic extraction operations typically do not
provide sharp cut-offs between the aromatics and non-aromatics, the
aromatic-lean fraction contains a major proportion of the
non-aromatic content of the initial feed and a minor proportion of
the aromatic content of the initial feed, and the aromatic-rich
fraction contains a major proportion of the aromatic content of the
initial feed and a minor proportion of the non-aromatic content of
the initial feed. The amount of non-aromatics in the aromatic-rich
fraction, and the amount of aromatics in the aromatic-lean
fraction, depend on various factors as will be apparent to one of
ordinary skill in the art, including the type of extraction and the
number of theoretical plates in the extractor, the type of solvent
and the solvent ratio.
[0042] The aromatic compounds that pass to the aromatic-rich
fraction include aromatic organo sulfur compounds, such as
benzothiophene, dibenzothiophene, benzonaphtenothiophene, and
derivatives of benzothiophene, dibenzothiophene and
benzonaphtenothiophene. Various non-aromatic organosulfur compounds
that may have been present in the initial feed, i.e., prior to
hydrotreating, include mercaptans, sulfides and disulfides.
[0043] In addition, certain organonitrogen compounds having
aromatic moieties also pass with the aromatic-rich fraction.
Further, certain organic nitrogen compounds, paraffinic or
naphthenic nature, may have polarities causing them to be extracted
and remain in aromatic-rich fraction.
[0044] As used herein, the term "major proportion of the
non-aromatic compounds" means at least greater than 50 wt % of the
non-aromatic content of the feed to the extraction zone, preferably
at least greater than about 85 wt %, and most preferably greater
than at least about 95 wt %. Also as used herein, the term "minor
proportion of the non-aromatic compounds" means no more than 50 wt
% of the feed to the extraction zone, preferably no more than about
15 wt %, and most preferably no more than about 5 wt %.
[0045] Also as used herein, the term "major proportion of the
aromatic compounds" means at least greater than 50 wt % of the
aromatic content of the feed to the extraction zone, preferably at
least greater than about 85 wt %, and most preferably greater than
at least about 95 wt %. Also as used herein, the term "minor
proportion of the non-aromatic compounds" means no more than 50 wt
% of the feed to the extraction zone, preferably no more than about
15 wt %, and most preferably no more than about 5 wt %.
[0046] The aromatic-rich fraction contains a majority of the
remaining refractory organosulfur compounds, including
4,6-dimethyldibenzothiophene and its derivatives. The aromatic-lean
fraction is substantially free of organosulfur compounds, since the
non-aromatic organosulfur and organonitrogen compounds are mainly
labile organosulfur compounds which were removed in the mild
hydrotreating step. The aromatic-rich fraction is contacted with an
oxidizing agent and an active metal catalyst in an oxidation
reaction zone to convert the refractory organosulfur and
organonitrogen compounds into oxidized organosulfur and
organonitrogen compounds. These oxidized organosulfur and
organonitrogen compounds are subsequently removed, by extraction
and, optionally, by adsorption, to produce a hydrocarbon product
stream that contains a reduced level of organosulfur and
organonitrogen compounds, or sent to different product pools,
depending on the refinery requirements. The two streams, i.e., the
effluent from the hydrotreating reaction zone and the effluent from
the oxidation reaction zone, can be combined to provide a
hydrocarbon product containing a reduced level of organosulfur and
organonitrogen compounds. Alternatively, the two streams can be
separately maintained, for instance, if aromatic extraction is
contemplated in downstream refinery operations for other
purposes.
[0047] The inclusion of an aromatic separation zone in an
integrated system and process combining hydrotreating and oxidative
desulfurization/denitrification allows a partition of the different
classes of sulfur-containing and nitrogen-containing compounds
according to their respective reactivity factors, thereby
optimizing utilization of the different types of heteroatom removal
processes and hence resulting in a more cost effective process. The
volumetric/mass flow through the oxidation reaction zone is
reduced, since only the aromatic-rich fraction of the original
feedstream containing refractory sulfur-containing and
nitrogen-containing compounds is subjected to the oxidation
process. As a result, the requisite equipment capacity, and
accordingly both the capital equipment cost and the operating
costs, are minimized. In addition, the total hydrocarbon stream is
not subjected to oxidation reactions, thus avoiding unnecessary
oxidation of organosulfur and organonitrogen compounds that are
otherwise handled using mild hydrotreating, which also minimizes
the extraction and adsorption capacity needed to remove these
oxidized organosulfur and organonitrogen compounds.
[0048] Furthermore, product quality is improved by the integrated
process of the present invention since undesired side reactions
that would result from oxidation of the entire feedstream under
generally harsh conditions are avoided.
BRIEF DESCRIPTION OF THE DRAWINGS
[0049] The foregoing summary, as well as the following detailed
description of preferred embodiments of the invention will be best
understood when read in conjunction with the attached drawings. For
the purpose of illustrating the invention, there are shown in the
drawings embodiments which are presently preferred. It should be
understood, however, that the invention is not limited to the
precise arrangements and apparatus shown. In the drawings, the same
numeral is used to refer to the same or similar elements, in
which:
[0050] FIG. 1A is a graph showing cumulative sulfur concentrations
plotted against boiling points indicating the boiling points of
sulfur-containing aromatic compounds;
[0051] FIG. 1B is a graphic representation of the relative
reactivities of various compounds in the hydrodesulfur process with
the increase in size of the sulfur-containing molecule;
[0052] FIG. 2 is a schematic diagram of an integrated system and
process of the present invention that includes an aromatic
extraction zone between a hydrotreating zone and an oxidation
zone;
[0053] FIG. 3 is a schematic diagram of a separation apparatus for
removing oxidized organosulfur and organonitrogen compounds from an
aromatic-rich portion of the hydrotreated products according to the
system and process of the present invention; and
[0054] FIGS. 4-9 show various examples of apparatus suitable for
use as the aromatic extraction zone.
DETAILED DESCRIPTION OF THE INVENTION
[0055] The present invention comprehends an integrated process to
produce hydrocarbon fuels with reduced levels of organosulfur and
organonitrogen compounds. The process includes the following
steps:
[0056] a. contacting the hydrocarbon stream in its entirety with a
hydrotreating catalyst in a hydrotreating reaction zone under mild
operating conditions;
[0057] b. subjecting the effluent hydrotreated stream to an
aromatic extraction zone to obtain a first fraction and a second
fraction;
[0058] c. the first, generally aromatic-lean, fraction, is
substantially free of organosulfur and organonitrogen compounds
since the labile organosulfur and organonitrogen compounds were
converted during the hydrotreating step;
[0059] d. the organosulfur compounds in the second, generally
aromatic-rich, fraction are primarily refractory organosulfur
compounds, including benzothiophenes e.g., long chain alkylated
benzothiophenes, dibenzothiophenes and alkyl derivatives, e.g.,
4,6-dimethyldibenzothiophene, and the organonitrogen compounds in
the second, generally aromatic-rich, fraction are primarily
refractory organonitrogen compounds; this second fraction is
contacted with an oxidizing agent and a metal catalyst in an
oxidation reaction zone to convert the organosulfur compounds into
oxidized sulfur-containing compounds and to convert organonitrogen
into oxidized nitrogen-containing compounds; and
[0060] e. the oxidized sulfur-containing and nitrogen-containing
compounds are subsequently removed in a separation zone, by
oxidation product removal processes and apparatus that include
extraction, distillation, adsorption, or combined processes
comprising one or more of extraction, distillation and
adsorption.
[0061] Referring now to FIG. 2, an integrated desulfurization and
denitrification apparatus 12 according to the present invention is
schematically illustrated. Apparatus 12 generally includes a
hydrotreating reaction zone 18, an extraction zone 22, an oxidation
zone 44 and a separation zone 48. Hydrocarbon feedstock 14 is mixed
with a hydrogen stream 16 and is introduced to the hydrotreating
reaction zone 18 and into contact with a hydrotreating catalyst
under mild operating conditions. Extraction zone 22 is an aromatic
extraction unit, examples of which are described in more detail
below. The hydrocarbon stream 14 is preferably a middle distillate
boiling in the range of about 180.degree. C. to about 400.degree.
C., typically containing up to about 3 wt % sulfur, although one of
ordinary skill in the art will be appreciated that other
hydrocarbon streams can benefit from the practice of the system and
method of the present invention. The hydrotreating catalyst can be,
for instance, an alumina base containing cobalt and molybdenum, as
is known in hydrodesulfurization operations.
[0062] As will be understood by one of ordinary skill in the art,
"mild" operating conditions is relative and the range of operating
conditions depend on the feedstock being processed. According to
the present invention, these mild operating conditions as used in
conjunction with hydrotreating a mid-distillate stream, i.e.,
boiling in the range of about 180.degree. C. to about 370.degree.
C., include: a temperature of about 300.degree. C. to about
400.degree. C., and preferably about 320.degree. C. to about
380.degree. C.; a reaction pressure of about 20 bars to about 100
bars, and preferably about 30 bars to about 60 bars; a hydrogen
partial pressure of below about 55 bars, and preferably about 25
bars to about 40 bars; a feed rate of about 0.5 hr.sup.-1 to about
10 hr.sup.-1, and preferably about 1.0 hr.sup.-1 to about 4
hr.sup.-1; and a hydrogen feed rate in certain embodiments of about
100 liters of hydrogen per liter of oil (L/L) to about 500 L/L, in
further embodiments about 100 L/L to about 300 L/L, and in
additional embodiments about 100 L/L to about 200 L/L.
[0063] The resulting hydrodesulfurized hydrocarbon stream 20 is
substantially free of unconverted labile organosulfur compounds
including aliphatic sulfur-containing compounds and thiophenes,
benzothiophenes and their derivatives, and is substantially free of
unconverted labile organonitrogen compounds. This stream 20 is
passed to the aromatic extraction zone 22 to separate a first,
aromatic-lean, fraction as raffinate stream 28 from a second,
generally aromatic-rich, fraction as extract stream 36. Extraction
zone 22 can be any suitable aromatic extraction apparatus operating
on the basis of solvent extraction. A solvent feed 24 is introduced
into the aromatic extraction zone 22. Various non-limiting examples
of apparatus suitable for the aromatic extraction zone 22 are
described in further detail below.
[0064] Stream 28 contains a major proportion of the non-aromatic
content of the initial feed, which now has a reduced level of
organosulfur and organonitrogen compounds, and a minor proportion
of the aromatic content of the initial feed. In addition,
extraction solvent can also exist in stream 28, e.g., in the range
of about 0 wt % to about 15 wt % (based on the total amount of
stream 28), preferably less than about 8 wt %. In operations in
which the solvent existing in stream 28 exceeds a desired or
predetermined amount, solvent may be removed from the hydrocarbon
product, for example, using a flashing or stripping unit 30 or
other suitable apparatus. The essentially solvent-free, low sulfur
content and low nitrogen content hydrocarbon product 32 can be
recovered separately or in combination with the fraction 52 that
has been subjected to oxidation zone 44 and separated in the
separation zone 48. Solvent 34 from the flashing or stripping unit
30 can be recycled to the aromatic extraction zone 22, e.g., via a
surge drum 26. Initial solvent feed or make-up solvent can be
introduced via stream 27.
[0065] Stream 36 from the aromatic extraction zone 22 generally
includes a major proportion of the aromatic content of the initial
feedstock and a minor proportion of the non-aromatic content of the
initial feedstock. This aromatic content includes aromatic
organosulfur compounds such as thiophene, benzothiophene and its
long chain alkylated derivatives, and dibenzothiophene and its
alkyl derivatives such as 4,6-dimethyl-dibenzothiophene,
benzonaphtenothiophene and its alkyl derivatives. Further, the
aromatic-rich stream includes aromatic organonitrogen compounds
such as acridine, 1-methyl-1-H-indole, quinoline, and their
derivatives.
[0066] In addition, extraction solvent can also exist in stream 36,
e.g., in the range of about 70 wt % to about 98 wt % (based on the
total amount of stream 36), preferably less than about 85 wt %. In
operations in which the solvent existing in stream 36 exceeds a
desired or predetermined amount, solvent can be removed from the
hydrocarbon product, for example, using a flashing unit 38 or other
suitable apparatus. Solvent 42 from the flashing unit 38 can be
recycled to the extraction zone 22, e.g., via a surge drum 26. The
essentially solvent-free and aromatic-rich hydrocarbon product 40
is passed to the oxidation zone 44 to be contacted with an
oxidizing agent and one or more catalytically active metals. The
oxidizing agent can be an aqueous oxidant such as hydrogen
peroxide, organic peroxides such as ter-butyl hydroperoxide, or
peroxo acids, a gaseous oxidant such as oxides of nitrogen (e.g.,
nitrous oxide), oxygen, air, ozone, or combinations comprising any
of these oxidants. The oxidation catalyst can be selected from one
or more homogeneous or heterogeneous catalysts having metals from
Group IVB to Group VIIIB of the Periodic Table, including Mn, Co,
Fe, Cr and Mo.
[0067] The aromatic-rich fraction, the oxidizing agent and the
oxidation catalyst are maintained in contact for a period of time
that is sufficient to complete the oxidation reactions, generally
from about 5 to about 180 minutes, in certain embodiments about 15
to about 90 minutes and in further embodiments about 15 minutes to
about 30 minutes. The reaction conditions of the oxidation zone 44
include: an operating pressure of about 1 bar to about 30 bars, in
certain embodiments about 1 bar to about 10 bars and in further
embodiments at about 1 bar to about 3 bars; and an operating
temperature of about 20.degree. C. to about 300.degree. C., in
certain embodiments about 20.degree. C. to about 150.degree. C. and
in further embodiments about 45.degree. C. to about 60.degree. C.
The molar feed ratio of oxidizing agent to sulfur is generally
about 1:1 to about 100:1, in certain embodiments about 1:1 to about
30:1, and in further embodiments about 1:1 to about 4:1. In
oxidation zone 44, at least a substantial portion of the aromatic
sulfur-containing compounds and their derivatives contained in the
aromatic-rich fraction are converted to oxidized sulfur-containing
compounds, i.e., sulfones and sulfoxides, and oxidized
nitrogen-containing compounds, and discharged as oxidized
hydrocarbon stream 46.
[0068] Stream 46 from the oxidation zone 44 is conveyed to the
separation zone 48 to remove the oxidized compounds as discharge
stream 50 and obtain a hydrocarbon stream 52 that contains a
reduced level of sulfur, preferably an ultra-low level of sulfur,
i.e., less than 15 ppmw, and a reduced level of nitrogen. Streams
32 and 52 can be combined to provide a hydrocarbon product 41 that
contains an ultra-low level of sulfur. Alternatively, the two
streams 32 and 52 can be separately maintained.
[0069] Stream 50 from the separation zone 48 can be passed to a
sulfones and sulfoxides handling unit (not shown) to recover
hydrocarbons free of sulfur, for example, by cracking reactions,
thereby increasing the total hydrocarbon product yield.
Alternatively, stream 50 can be passed to other refining processes
such as coking or solvent deasphalting.
[0070] Referring to FIG. 3, one embodiment of a process for
removing oxides such as sulfoxides and sulfones contained in
effluent from oxidation zone 44 is shown, although alternative
processes for removing sulfoxides and sulfones can be employed.
Stream 46 containing oxidized hydrocarbons, water and catalyst is
introduced into a decanting vessel 54 to decant water and catalyst
as discharge stream 56 and separate a hydrocarbon mixture stream
58. Stream 56 which can include a mixture of water (e.g., from the
aqueous oxidant), any remaining oxidant and soluble catalyst, is
withdrawn from the decanting vessel 54 and can be recycled to the
oxidation zone 44 (not shown in FIG. 3), and the hydrocarbon stream
58 is passed to the separation zone 48. The hydrocarbon stream 58
is introduced into one end of a counter-current extractor 60, and a
solvent stream 62 is introduced into the opposite end. Oxidized
sulfur-containing and/or nitrogen-containing compounds are
extracted from the hydrocarbon stream with the solvent as
solvent-rich extract stream 64.
[0071] The solvent stream 62 can include a selective solvent such
as methanol, acetonitrile, any polar solvent having a Hildebrandt
value of at least 19, and combinations comprising at least one of
the foregoing solvents. Acetonitrile and methanol are preferred
solvents for the extraction due to their polarity, volatility, and
low cost. The efficiency of the separation between the sulfones
and/or sulfoxides can be optimized by selecting solvents having
desirable properties including, but not limited to boiling point,
freezing point, viscosity, and surface tension.
[0072] The raffinate 66 is introduced into an adsorption column 68
where it is contacted with an adsorbent material such as an alumina
adsorbent to produce the finished hydrocarbon product stream 52
that has an ultra-low level of sulfur, which is recovered. The
solvent-rich extract 64 from the extractor 60 is introduced into a
distillation column 70 for solvent recovery via the overhead
recycle stream 72, and the oxidized sulfur-containing and/or
nitrogen-containing compounds, including sulfones and/or
sulfoxides, are discharged as stream 50.
[0073] The extraction zone 22 can be any suitable solvent
extraction apparatus capable of partitioning the effluent 20 from
the hydrodesulfurization zone into a generally aromatic-lean stream
28 and a generally aromatic-rich stream 36. Selection of solvent,
operating conditions, and the mechanism of contacting the solvent
and effluent 20 permit control over the level of aromatic
extraction. For instance, suitable solvents include furfural,
N-methyl-2-pyrrolidone, dimethylformamide or dimethylsulfoxide, and
can be provided in a solvent to oil ratio of about 20:1, in certain
embodiments about 4:1, and in further embodiments about 1:1. The
aromatic extraction unit 22 can operate at a temperature in the
range of about 20.degree. C. to about 120.degree. C., and in
certain embodiments in the range of about 40.degree. C. to about
80.degree. C. The operating pressure of the aromatic extraction
unit 22 can be in the range of about 1 bar to about 10 bars, and in
certain embodiments, in the range of about 1 bar to 3 bars. Types
of apparatus useful as unit 22 of the present invention include
stage-type extractors or differential extractors.
[0074] An example of a stage-type extractor is a mixer-settler
apparatus 404 schematically illustrated in FIG. 4. Mixer-settler
apparatus 404 includes a vertical tank 442 incorporating a turbine
or a propeller agitator 444 and one or more baffles 446. Charging
inlets 448, 450 are located at the top of tank 442 and outlet 454
is located at the bottom of tank 442. The feedstock to be extracted
is charged into vessel 442 via inlet 448 and a suitable quantity of
solvent is added via inlet 450. The agitator 444 is activated for a
period of time sufficient to cause intimate mixing of the solvent
and charge stock, and at the conclusion of a mixing cycle,
agitation is halted and, by control of a valve 456, at least a
portion of the contents are discharged and passed to a settler 458.
The phases separate in the settler 458 and a raffinate phase
containing an aromatic-lean hydrocarbon mixture and an extract
phase containing an aromatic-rich mixture are withdrawn via outlets
462 and 464, respectively. In general, a mixer-settler apparatus
can be used in batch mode, or a plurality of mixer-settler
apparatus can be staged to operate in a continuous mode.
[0075] Another stage-type extractor is a centrifugal contactor.
Centrifugal contactors are high-speed, rotary machines
characterized by relatively low residence time. The number of
stages in a centrifugal device is usually one, however, centrifugal
contactors with multiple stages can also be used. Centrifugal
contactors utilize mechanical devices to agitate the mixture to
increase the interfacial area and decrease the mass transfer
resistance.
[0076] Various types of differential extractors (also known as
"continuous contact extractors,") that are also suitable for use as
unit 22 of the present invention include, but are not limited to,
centrifugal contactors and contacting columns such as tray columns,
spray columns, packed towers, rotating disc contactors and pulse
columns.
[0077] Contacting columns are suitable for various liquid-liquid
extraction operations. Packing, trays, spray or other
droplet-formation mechanisms or other apparatus are used to
increase the surface area in which the two liquid phases (i.e., a
solvent phase and a hydrocarbon phase) contact, which also
increases the effective length of the flow path. In column
extractors, the phase with the lower viscosity is typically
selected as the continuous phase, which, in the case of aromatic
extraction unit 22, is the solvent phase. In certain embodiments,
the phase with the higher flow rate can be dispersed to create more
interfacial area and turbulence. This is accomplished by selecting
an appropriate material of construction with the desired wetting
characteristics. In general, aqueous phases wet metal surfaces and
organic phases wet non-metallic surfaces. Changes in flows and
physical properties along the length of an extractor can also be
considered in selecting the type of extractor and/or the specific
configuration, materials or construction, and packing material type
and characteristics (i.e., average particle size, shape, density,
surface area, and the like).
[0078] A tray column 504 is schematically illustrated in FIG. 5. A
light liquid inlet 550 at the bottom of column 504 receives liquid
hydrocarbon, and a heavy liquid inlet 552 at the top of column 504
receives liquid solvent. Column 504 includes a plurality of trays
544 and associated downcomers 546. A top level baffle 547
physically separates incoming solvent from the liquid hydrocarbon
that has been subjected to prior extraction stages in the column
504. Tray column 504 is a multi-stage counter-current contactor.
Axial mixing of the continuous solvent phase occurs at region 548
between trays 544, and dispersion occurs at each tray 544 resulting
in effective mass transfer of solute into the solvent phase. Trays
544 can be sieve plates having perforations ranging from about 1.5
to 4.5 mm in diameter and can be spaced apart by about 150-600
mm.
[0079] Light hydrocarbon liquid passes through the perforation in
each tray 544 and emerges in the form of fine droplets. The fine
hydrocarbon droplets rise through the continuous solvent phase and
coalesce into an interface layer 558 and are again dispersed
through the tray 544 above. Solvent passes across each plate and
flows downward from tray 544 above to the tray 544 below via
downcomer 546. The principle interface 560 is maintained at the top
of column 504. Aromatic-lean hydrocarbon liquid is removed from
outlet 554 at the top of column 504 and aromatic-rich solvent
liquid is discharged through outlet 556 at the bottom of column
504. Tray columns are efficient solvent transfer apparatus and have
desirable liquid handling capacity and extraction efficiency,
particularly for systems of low-interfacial tension.
[0080] An additional type of unit operation suitable for extracting
aromatics from the hydrocarbon feed is a packed bed column. FIG. 6
is a schematic illustration of a packed bed column 604 having a
hydrocarbon inlet 650 and a solvent inlet 652. A packing region 646
is provided upon a support plate 644. Packing region 646 comprises
suitable packing material including, but not limited to, Pall
rings, Raschig rings, Kascade rings, Intalox saddles, Berl saddles,
super Intalox saddles, super Berl saddles, Demister pads, mist
eliminators, telerrettes, carbon graphite random packing, other
types of saddles, and the like, including combinations of one or
more of these packing materials. The packing material is selected
so that it is fully wetted by the continuous solvent phase. The
solvent introduced via inlet 652 at a level above the top of the
packing region 646 flows downward and wets the packing material and
fills a large portion of void space in the packing region 646.
Remaining void space is filled with droplets of the hydrocarbon
liquid which rise through the continuous solvent phase and coalesce
to form the liquid-liquid interface 660 at the top of the packed
bed column 604. Aromatic-lean hydrocarbon liquid is removed from
outlet 654 at the top of column 604 and aromatic-rich solvent
liquid is discharged through outlet 656 at the bottom of column
604. Packing material provides large interfacial areas for phase
contacting, causing the droplets to coalesce and reform. The mass
transfer rate in packed towers can be relatively high because the
packing material lowers the recirculation of the continuous
phase.
[0081] Further types of apparatus suitable for aromatic extraction
in the system and method of the present invention include rotating
disc contactors. FIG. 7 is a schematic illustration of a rotating
disc contactor 704 known as a Scheiebel.RTM. column commercially
available from Koch Modular Process Systems, LLC of Paramus, N.J.,
USA. It will be appreciated by those of ordinary skill in the art
that other types of rotating disc contactors can be implemented as
an aromatic extraction unit included in the system and method of
the present invention, including but not limited to Oldshue-Rushton
columns, and Kuhni extractors. The rotating disc contactor is a
mechanically agitated, counter-current extractor. Agitation is
provided by a rotating disc mechanism, which typically runs at much
higher speeds than a turbine type impeller as described with
respect to FIG. 4.
[0082] Rotating disc contactor 704 includes a hydrocarbon inlet 750
toward the bottom of the column and a solvent inlet 752 proximate
the top of the column, and is divided into number of compartments
formed by a series of inner stator rings 742 and outer stator rings
744. Each compartment contains a centrally located, horizontal
rotor disc 746 connected to a rotating shaft 748 that creates a
high degree of turbulence inside the column. The diameter of the
rotor disc 746 is slightly less than the opening in the inner
stator rings 742. Typically, the disc diameter is 33-66% of the
column diameter. The disc disperses the liquid and forces it
outward toward the vessel wall 762 where the outer stator rings 744
create quiet zones where the two phases can separate. Aromatic-lean
hydrocarbon liquid is removed from outlet 754 at the top of column
704 and aromatic-rich solvent liquid is discharged through outlet
756 at the bottom of column 704. Rotating disc contactors
advantageously provide relatively high efficiency and capacity and
have relatively low operating costs.
[0083] An additional type of apparatus suitable for aromatic
extraction in the system and method of the present invention is a
pulse column. FIG. 8 is a schematic illustration of a pulse column
system 804, which includes a column with a plurality of packing or
sieve plates 844, a light phase, i.e., solvent, inlet 850, a heavy
phase, i.e., hydrocarbon feed, inlet 852, a light phase outlet 854
and a heavy phase outlet 856.
[0084] In general, pulse column system 804 is a vertical column
with a large number of sieve plates 844 lacking down comers. The
perforations in the sieve plates 844 typically are smaller than
those of non-pulsating columns, e.g., about 1.5 mm to about 3.0 mm
in diameter.
[0085] A pulse-producing device 870, such as a reciprocating pump,
pulses the contents of the column at frequent intervals. The rapid
reciprocating motion, of relatively small amplitude, is
superimposed on the usual flow of the liquid phases. Bellows or
diaphragms formed of coated steel (e.g., coated with
polytetrafluoroethylene), or any other reciprocating, pulsating
mechanism can be used. A pulse amplitude of 5-25 mm is generally
recommended with a frequency of 100-260 cycles per minute. The
pulsation causes the light liquid (solvent) to be dispersed into
the heavy phase (oil) on the upward stroke and heavy liquid phase
to jet into the light phase on the downward stroke. The column has
no moving parts, low axial mixing, and high extraction
efficiency.
[0086] A pulse column typically requires less than a third the
number of theoretical stages as compared to a non-pulsating column.
A specific type of reciprocating mechanism is used in a Karr Column
which is shown in FIG. 9.
[0087] The addition of an aromatic extraction zone into the
apparatus and process of the invention that integrates a
hydrotreating zone and an oxidation zone uses low cost units in
both zones as well as more favorable conditions in the
hydrotreating zone, i.e., milder pressure and temperature and
reduced hydrogen consumption. Only the aromatic-rich fraction is
oxidized to convert the refractory sulfur-containing and
nitrogen-containing compounds. This results in more cost-effective
desulfurization and denitrification of hydrocarbon fuels,
particularly removal of the refractory sulfur-containing and
nitrogen-containing compounds, thereby efficiently and economically
producing fuel products having reduced sulfur and nitrogen
content.
[0088] The present invention offers distinct advantages when
compared to conventional processes for deep desulfurization of
hydrocarbon fuel. For example, in certain conventional approaches
to deep desulfurization, the entire hydrocarbon stream undergoes
both hydrodesulfurization and oxidative desulfurization, requiring
reactors of high capacity for both processes. Furthermore, the high
operating costs and undesired side reactions that can negatively
effect certain desired fuel characteristics are avoided using the
process and apparatus of the present invention. In addition,
operating costs associated with the removal of the oxidized
sulfur-containing compounds from the entire feedstream are
decreased as only a portion of the initial feed is subjected to
oxidative desulfurization.
Example
[0089] A straight run (SR) gas oil was hydrotreated in a fixed bed
reactor at 30 Kg/cm2 hydrogen partial pressure, 340.degree. C., a
liquid hourly space velocity of 1.44 h.sup.-1 and at a hydrogen to
oil ratio of 280 Liters/Liters. The properties of the SR gas oil
are given in Table 3. The sulfur content of the gas oil was reduced
from 13,000 ppmw to 662 ppmw.
TABLE-US-00003 TABLE 3 SR Gas Hydrotreated Property Unit Method Oil
Product Density @ 15.6.degree. C. Kg/Lt ASTM D4052 0.850 0.850
Sulfur wt % ASTM D4294 1.3 0.0662 Nitrogen ppmw 178 91 Aromatics wt
% 31.5 29.5 Paraffins and wt % 68.5 70.5 Naphthenes Distillation
ASTM D2892 IBP .degree. C. 52 53 5 wt % .degree. C. 186 187 10 wt %
.degree. C. 215 213 30 wt % .degree. C. 267 262 50 wt % .degree. C.
304 299 70 wt % .degree. C. 344 338 90 wt % .degree. C. 403 397 95
wt % .degree. C. 426 420 100 wt % .degree. C. 466 463
[0090] The hydrotreated gas oil was then passed to a
counter-current aromatic extraction unit to separate the products
into an aromatic-rich fraction and an aromatic-lean fraction. The
extractor was operated at 60.degree. C., atmospheric pressure and
at a solvent-to-diesel ratio of 1.1/1.0 using furfural as
solvent.
[0091] The aromatic-lean fraction yield was 68 wt % and contained
61 ppmw of sulfur and 10.5 wt % aromatics, and was passed to a
diesel pool. The aromatic rich fraction yield was 32 wt % and
contained 80 wt % aromatics and 600 ppmw of sulfur.
[0092] The aromatic rich fraction was oxidized at 75.degree. C.
under atmospheric pressure for 2 hours using hydrogen peroxide as
oxidant at a ratio of H.sub.2O.sub.2/S of 10, and using 0.5 wt %
sodium tungsten as a catalyst along with acetic acid. The oxidation
by-products, mostly sulfones, were removed by an extraction and
adsorption step. The final aromatic fraction, which contained less
than 10 ppmw of sulfur after oxidation, extraction and adsorption
steps, was then sent to the diesel pool and combined with the
aromatic-lean fraction. The final gas oil fraction contained less
than 50 ppmw of sulfur.
[0093] The method and apparatus of the present invention have been
described above and in the attached drawings; however,
modifications will be apparent to those of ordinary skill in the
art and the scope of protection for the invention is to be defined
by the claims that follow.
* * * * *