U.S. patent application number 10/155590 was filed with the patent office on 2003-05-22 for hydrodesulfurization of oxidized sulfur compounds in liquid hydrocarbons.
Invention is credited to DeCanio, Stephen Jude, Levy, Robert Edward, Nero, Vincent Paul, Stavros, Alkis, Sudhakar, Chakka.
Application Number | 20030094400 10/155590 |
Document ID | / |
Family ID | 26852434 |
Filed Date | 2003-05-22 |
United States Patent
Application |
20030094400 |
Kind Code |
A1 |
Levy, Robert Edward ; et
al. |
May 22, 2003 |
Hydrodesulfurization of oxidized sulfur compounds in liquid
hydrocarbons
Abstract
A process for removing sulfur from hydrocarbon streams is
described. The organic sulfur compounds are first oxidized to
create oxidized sulfur in the hydrocarbon stream and then
processing the hydrocarbon stream with hydrogen at
hydrodesulfurization conditions to reduce the sulfur to hydrogen
sulfide, leaving a hydrocarbon gas stream substantially free of
sulfur.
Inventors: |
Levy, Robert Edward;
(Houston, TX) ; Stavros, Alkis; (Kingwood, TX)
; Sudhakar, Chakka; (Katy, TX) ; Nero, Vincent
Paul; (Katy, TX) ; DeCanio, Stephen Jude;
(Katy, TX) |
Correspondence
Address: |
JENKENS & GILCHRIST, A PROFESSIONAL CORPORATION
1100 LOUISIANA
SUITE 1800
HOUSTON
TX
77002-5214
US
|
Family ID: |
26852434 |
Appl. No.: |
10/155590 |
Filed: |
May 23, 2002 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60311646 |
Aug 10, 2001 |
|
|
|
Current U.S.
Class: |
208/222 ;
208/211; 208/219; 208/87; 208/90 |
Current CPC
Class: |
C10G 67/12 20130101 |
Class at
Publication: |
208/222 ; 208/90;
208/87; 208/219; 208/211 |
International
Class: |
C10G 017/02; C10G
001/04; C10G 045/00 |
Claims
1. A process for removing sulfur from organic sulfur compounds of a
feed hydrocarbon stream comprising the steps of: contacting the
hydrocarbon stream with a sufficient amount of an oxidizing agent
at oxidation conditions to oxidize the organic sulfur compounds in
the feed hydrocarbon stream; contacting the feed hydrocarbon stream
containing oxidized organic sulfur compounds with sufficient
amounts of hydrogen at hydrodesulfurization conditions over a
hydrodesulfurization catalyst to produce hydrocarbon stream with
substantially lower sulfur content and a gas stream containing
hydrogen sulfide; and recovering the hydrocarbon stream containing
substantially less sulfur than the feed hydrocarbon.
2. The process of claim 1, wherein oxidizing the organic sulfur
compounds to produce substantially oxidized organic sulfur
compounds comprises the steps of: contacting the hydrocarbon stream
with an aqueous oxidizing agent for oxidizing organic sulfur
compounds comprising: from about 0.5% to about 4.5% hydrogen
peroxide; from about 75 wt % to about 92 wt % of a C.sub.1 to
C.sub.4 carboxylic acid; and water in an amount not to exceed about
25 wt %; and extracting at least part of the oxidized organic
sulfur compounds from the hydrocarbon stream into the aqueous
oxidizer composition; and separating the aqueous oxidizing agent
from the hydrocarbon stream prior to the hydrodesulfurization
step.
3. The process of claim 1 which comprises contacting the
hydrocarbon containing oxidized sulfur compounds in the presence of
a hydrotreating catalyst at a temperature greater than about
100.degree. C., at a pressure greater than about 100 psig, at a
liquid hourly space velocity of from about 0.2 to about 10.0, and
at a gas flow rate of from about 100 to about 5,000 standard cubic
feet per barrel having at least about 70% hydrogen.
4. The process of claim 3, wherein the temperature is from about
100.degree. C. to about 400.degree. C. and the pressure is from
about 100 psig to about 1000 psig.
5. The process of claim 1, wherein the hydrocarbon stream with
substantially lowered sulfur content which is recovered contains
less than about 50 ppm by weight of sulfur.
6. A process for removing sulfur from a hydrocarbon stream boiling
in the diesel full range comprising the steps of: contacting the
hydrocarbon stream containing organic sulfur compounds at a
temperature of from about 90.degree. C. to about 105.degree. C. for
a period of time up to about 15 minutes with an oxidizing agent
comprising: from about 79 wt % to about 89 wt % formic acid, from
about 2 wt % to about 3 wt % hydrogen peroxide, and from about 8 wt
% to about 14 wt % water: in an amount such that the molar ratio of
formic acid to hydrogen peroxide is from about 12:1 to about 60:1,
wherein the amount of oxidizing agent added is such that there is a
stoichiometric excess of hydrogen peroxide over that which is
necessary to oxidize the sulfur present in the hydrocarbon creating
an aqueous phase and a hydrocarbon phase; separating the aqueous
phase and recovering the hydrocarbon phase containing oxidized
sulfur compounds; contacting the recovered hydrocarbon stream
containing the oxidized sulfur compounds with a
hydrodesulfurization catalyst at a temperature of from about
100.degree. C. to about 400.degree. C., at a pressure of from about
100psig to about 1,000 psig, at a liquid hourly space velocity of
from about 0.2 to about 10.0, and at a gas flow rate of from about
100 to about 5,000 standard cubic feet per barrel having at least
70% hydrogen to produce a diesel product stream containing less
than about 5 ppm sulfur and a gas stream containing hydrogen
sulfide; and recovering the diesel product.
7. A process for reducing the sulfur content of a hydrocarbon
stream which comprises the steps of: contacting the hydrocarbon
stream containing the organic sulfur compounds with an effective
amount of an alkaline earth metal peroxide stream which, upon
activation, produces hydrogen peroxide in situ to form a reaction
mixture in which the organic sulfur can be oxidized; and an
effective, activating amount of an acid which reacts with the
peroxide to generate hydrogen peroxide in situ, which reacts with
the organic sulfur present in the hydrocarbon stream to form
organic sulfones and sulfoxides corresponding to the sulfur
compounds in the hydrocarbon stream; recovering a hydrocarbon
stream having substantially all sulfur as oxidized sulfur compounds
from the reaction mixture; hydrotreating the hydrocarbon stream
having substantially all sulfur as oxidized sulfur compounds to
produce a hydrogen sulfide stream and a substantially sulfur free
hydrocarbon product; and recovering the substantially sulfur free
hydrocarbon product.
8. A process for removing sulfur from a hydrocarbon stream
containing organic oxidized sulfur compounds comprising the steps
of: contacting the hydrocarbon stream containing up to about 6 wt %
total sulfur as organic sulfones or sulfoxides with a
hydrodesulfurization catalyst at hydrodesulfurization conditions
with a gas stream containing at least about 70% hydrogen to form a
gas stream containing substantial amounts of hydrogen sulfide and a
hydrocarbon stream substantially free of sulfur.
9. The process of claim 8 wherein hydrodesulfurization conditions
comprises contacting the hydrocarbon containing oxidized sulfur
compounds with a hydrotreating catalyst at a temperature from about
100.degree. C. to about 400.degree. C., at a pressure greater than
about 100 psig, at a liquid hourly space velocity of from about 0.2
to about 10.0, and at a gas flow rate of from about 100 to about
5,000 standard cubic feet per barrel.
10. A process for removing sulfur from a hydrocarbon stream
comprising the steps of: oxidizing the sulfur compounds in the
hydrocarbon stream to produce organic oxidized sulfur compounds
comprising the steps of: contacting the hydrocarbon stream with an
oxidizer composition for oxidizing organic sulfur compounds
comprising from about 0.5% to about 4.5% hydrogen peroxide, from
about 75 wt % to about 92 wt % of a C.sub.1-C.sub.4 carboxylic
acid, water in an amount not to exceed about 25 wt %, and during
such oxidation, extracting at least part of the oxidized organic
sulfur compounds from hydrocarbon in an aqueous spent oxidizer
phase; and recovering the hydrocarbon containing the oxidized
sulfur compounds from the aqueous spent oxidizer; and contacting
the hydrocarbon containing oxidized sulfur compounds with a
hydrotreating catalyst at a temperature greater than about
100.degree. C., at a pressure greater than about 100 psig, at a
liquid hourly space velocity of from about 0.2 to about 10.0, and
at a gas flow rate of from about 100 to about 5,000 standard cubic
feet per barrel having at least about 70% hydrogen to form hydrogen
sulfide gas and a hydrocarbon stream substantially free of sulfur;
and recovering the hydrocarbon stream having a sulfur content of
from about 0.0001% to about 1 wt %.
11. A process for removing sulfur from a sulfur containing cracked
naphtha without substantially hydrogenating the olefins of the
cracked naphtha comprising the steps of: oxidizing the sulfur
compounds in the cracked naphtha to produce oxidized organic sulfur
compounds; and then hydrodesulfurizing the oxidized organic sulfur
compounds to produce a hydrogen sulfide stream and a substantially
sulfur free naphtha product.
12. The process of claim 11, wherein oxidizing the sulfur compounds
to produce oxidized organic sulfur compounds comprises the steps
of: contacting the sulfur containing cracked naphtha with an
effective amount of an aqueous oxidizer composition comprising:
from about 0.5% to about 4.5% hydrogen peroxide; from about 75 wt %
to about 92 wt % of a C.sub.1-C.sub.4 carboxylic acid; and water in
an amount not to exceed about 25 wt %; and during such oxidation,
extracting at least some of the oxidized organic sulfur compounds
from the cracked naphtha into the aqueous oxidizer composition.
13. The process of claim 11 wherein hydrotreating the naphtha
comprises contacting the naphtha containing oxidized sulfur
compounds with a hydrotreating catalyst at a temperature from about
100.degree. C. to about 400.degree. C., at a pressure greater than
about 100 psig, at a liquid hourly space velocity of from about 0.2
to about 10.0, and at a gas flow rate of from about 100 to about
5,000 standard cubic feet per barrel having at least about 70%
hydrogen.
14. The process of claim 13, wherein oxidizing the sulfur compounds
in the naphtha to produce an oxidized organic naphtha stream
comprises the steps of: contacting the sulfur containing naphtha
with an effective amount of an aqueous oxidizer composition
comprising: from about 0.5% to about 4.5% hydrogen peroxide; from
about 75 wt % to about 92 wt % of a C.sub.1-C.sub.4 carboxylic
acid; and water in an amount not to exceed about 25 wt %; and
during such oxidation, extracting at least some of the oxidized
organic sulfur compounds from the cracked naphtha into the aqueous
oxidizer.
15. A process for removing organic sulfur from crude oil
comprising; oxidizing the organic sulfur in the crude oil stream
containing organic sulfur compounds to produce an oxidized sulfur
containing crude stream; distilling the oxidized sulfur containing
crude stream containing the oxidized sulfur to produce a light
distillate, a medium distillate, a heavy distillate and a reduced
crude; hydrotreating the light distillate to produce low sulfur
gasoline and a hydrogen sulfide gas stream; hydrotreating the
medium distillate to produce desulfurized diesel and heating oil
and a hydrogen sulfide gas stream; and hydrotreating the heavy
distillate to produce a desulfurized reduced crude feed stream to a
fluid catalytic cracker feed and a hydrogen sulfide gas stream;
separating the hydrogen sulfide gas stream from the desulfurized
gasoline, diesel, and heating oil; and cracking the reduced crude
feed stream to produce low sulfur gasoline and low sulfur diesel
and heating oil.
16. A process for removing sulfur from a crude oil stream to form
low sulfur hydrocarbon products comprising the steps of; distilling
the crude stream to produce a light distillate, a medium
distillate, a heavy distillate and a reduced crude; cracking the
heavy distillate to produce a cracked naphtha stream; oxidizing the
light distillate, medium distillate and cracked naphtha to produce
an oxidized product stream; separating the oxidized product stream
to produce a gasoline stream and diesel stream; hydrotreating the
gasoline to produce low sulfur gasoline and a gas stream containing
hydrogen sulfide; hydrotreating the diesel stream to produce low
sulfur diesel and heating oil and a gas stream containing hydrogen
sulfide; and recovering the gasoline, diesel and heating oil as low
sulfur product streams.
17. A process for refining a crude oil stream containing sulfur to
produce low sulfur hydrocarbon products comprising the steps of;
distilling the crude stream to produce a light distillate, a medium
distillate, a heavy distillate and a reduced crude the sulfur in
the; oxidizing the sulfur containing compounds in the light
distillate, the medium distillate, and the heavy distillate to
produce an oxidized gasoline, an oxidized diesel and heating oil;
and an oxidized feed stream, respectively; hydrotreating the
oxidized gasoline to produce low sulfur gasoline; hydrotreating the
oxidized diesel and heating oil to produce low sulfur diesel and
heating oil; hydrotreating the oxidized feed stream to a feed
stream; and cracking and separating the feed stream into a low
sulfur gasoline and a low sulfur diesel/heating oil.
Description
PRIOR RELATED APPLICATIONS
[0001] This application claims priority to U. S. Provisional
Application No. 60/311,646 filed on Aug. 10, 2001, which is
incorporated in its entirety by reference herein.
FEDERALLY SPONSORED RESEARCH STATEMENT
[0002] Not applicable.
REFERENCE TO MICROFICHE APPENDIX
[0003] Not applicable.
FIELD OF THE INVENTION
[0004] This invention relates to a process for the removal of
sulfur from liquid hydrocarbons by hydrotreating the liquid
hydrocarbon containing oxidized sulfur compounds.
BACKGROUND OF THE INVENTION
[0005] The presence of sulfur in hydrocarbons has long been a
significant problem from the exploration, production,
transportation, and refining all the way to the consumption of
hydrocarbons as a fuel, especially to power automobiles and trucks.
As government regulations throughout the world increasingly
restrict sulfur levels in fuels, the problem of sulfur reduction is
being felt by producers, refiners, transporters and marketers of
the full range of fuel products, from gasoline and diesel fuel to
jet fuel, kerosene, heating oil and heavier fuels. In Western
Europe, North America, Japan and other industrial nations the
sulfur restrictions on gasoline and on-highway diesel fuel are
moving to the ultra-low levels of 50, 30, 15 or even 10 ppm.
Consequently, producers, refiners and marketers are seeking
low-cost technologies for producing ultra-low sulfur products, with
maximum use of existing facilities.
[0006] The process technology for removing sulfur that is in almost
universal use today is hydrotreating, sometimes referred to as
hydrodesulfurization. Hydrotreating, as used herein, is a process
whose primary purpose is to reduce the sulfur and/or nitrogen
content without significantly changing the boiling range of the
feed. Sulfur is eliminated as hydrogen sulfide and nitrogen as
ammonia in hydrotreating. While there are many variations and
improvements, this technology requires high temperature and
pressure in a hydrogen environment and employs solid catalysts.
This process successfully causes the destruction of the majority of
the sulfur compounds in hydrocarbons, including most of the
thiophenic compounds. However, the sulfur in substituted
dibenzothiophenes (DBT), especially those having steric hindrance
of the sulfur, is particularly difficult to remove and requires
high severity hydrotreaters having pressures well in excess of 500
psi. Achieving ultra-low sulfur levels requires that most of these
difficult-to-hydrotreat compounds be removed, which could drive
many refiners to install new hydrotreaters or carry out expensive
revamps of their existing hydrotreaters.
[0007] One of the largest components of the gasoline pool are
cracked naphthas which supply 90% of the sulfur in the gasoline
pool. The sulfur in cracked naphthas is relatively easy to remove
by hydrotreating. However, hydrotreating the cracked naphtha stream
also hydrogenates olefins in the cracked naphtha to paraffins. The
octane rating of paraffins is substantially lower than that of
olefins, therefore the octane rating of the gasoline product ends
up about 10 points lower than the cracked naphtha feed. The
resulting gasoline product would be an ultra-low sulfur product,
but would not meet the octane rating necessary to be part of the
gasoline pool. The decrease in octane rating is unacceptable due to
the large percentage of the gasoline pool that the cracked naphtha
contributes. Therefore a process for removing the sulfur from a
cracked naphtha stream to produce an ultra-low sulfur product while
maintaining the octane rating is needed. Cracking may be thermal
cracking, hydrocracking, catalytic cracking, or any known cracking
process to one skilled in the art.
[0008] As disclosed in U.S. patent application Ser. No.
09/654,016the difficult-to-hydrotreat thiophenic sulfur compounds
are readily oxidized in a novel process that converts these
compounds to the corresponding sulfones and sulfoxides. In this
process, the desulfurization is ultimately achieved by removing the
sulfoxides and sulfones from the hydrocarbon product through a
series of chemical processing steps. The reference gives no details
on the methods for ultimate disposal of the sulfoxides and
sulfones.
[0009] U.S. Pat. No. 6,171,478 (Cabrera, et al.) discloses a
desulfurization process of a hydrocarbonaceous oil. The
hydrocarbonaceous oil is treated in a hydrodesulfurization unit and
then reacted with an oxidizing agent. The effluent stream from the
oxidation zone is treated to decompose the oxidizing agent before
separation of the oxidized sulfur from the hydrocarbon. The
resulting product streams from the process include a stream
containing oxidized sulfur compounds and a hydrocarbonaceous oil
stream having a reduced concentration of sulfur compounds. The '478
patent does not disclose a suitable method for disposing the stream
containing oxidized sulfur compounds. The concept of first
hydrotreating a hydrocarbon feed containing sulfur compounds
followed by an oxidation step to facilitate the removal of hard to
hydrotreat thiophenic compounds was described earlier by Frances M.
Collins et al. in the Journal of Molecular Catalysis A: chemical
117(1997), 397-403.
[0010] A subsequently issued U.S. Pat. 6,277,271 (Kocal) described
a process of the '478 patent mentioned above that included the step
of recycling the oxidized sulfur compounds to the
hydrodesulfurization reactor to increase the hydrocarbon recovery
from the process. In this particular patent the series of
separation steps as described in Cabrera '478 continued to be
necessary even though the hydrocarbon bound to the oxidized sulfur
is now recovered as a hydrocarbon product and the sulfur removed as
hydrogen sulfide from the hydrodesulfirization reactor.
[0011] Against the foregoing background, in order to achieve the
predicted low sulfur levels in fuels and other hydrocarbon
products, there is a need to develop a process that can maximize
the effectiveness of existing hydrodesulfurization units with
minimal or no modification. Additionally, there is a need for
processes for convenient treatment of hydrocarbons having oxidized
sulfur compounds to remove and dispose of the sulfur without
hydrocarbon yield loss and without the expensive and often
inefficient steps of solvent extraction and distillation and the
like.
SUMMARY OF THE INVENTION
[0012] It has been discovered that the conventional
hydrodesulfurization process for removal of sulfur compounds in
hydrocarbon streams can be used to hydrotreat entire hydrocarbon
streams containing oxidized sulfur compounds as well. In the case
of hydrocarbon streams containing organic sulfur compounds, such as
dibenzothiophenes, some of the organic sulfur is converted to
hydrogen sulfide and hydrocarbon in the hydrotreater, to an extent
dependent on the severity of the hydrotreating conditions. In the
case of hydrocarbon streams containing oxidized sulfur compounds,
such as dibenzothiophene sulfones, virtually all of the sulfur
compounds can be converted to hydrogen sulfide and desulfurized
hydrocarbon product in the hydrotreater, even at mild hydrotreating
conditions. Hydrotreating of hydrocarbon streams containing both
non-oxidized and oxidized sulfur compounds results in a product
stream containing substantially no oxidized sulfur compounds and a
reduced level of non-oxidized sulfur compounds.
[0013] It has been discovered that by sending a stream of
hydrocarbon liquids containing oxidized sulfur compounds through a
conventional hydrotreater, the sulfur in the oxidized sulfur
compounds is reduced and removed as hydrogen sulfide. If the
hydrocarbon liquid has other organic sulfurs present, the reaction
in the hydrotreater also removes the sulfur from them depending on
the types of organic sulfur present and the conditions of the
hydrotreater. The resulting hydrocarbon stream would be
substantially free of oxidized sulfur compounds and have a low
level of residual organic sulfur compounds. The hydrotreater may
operate at hydrotreating conditions such as those commonly found in
use in today's refineries. If the only sulfur present is oxidized
organic sulfur compounds, the operating conditions can be even
milder. The milder conditions result in equivalent capacity and
gives the additional advantage of less hydrogenation of the
olefins. The hydrotreater catalyst may be any suitable
hydrotreating catalyst. The conditions of the hydrotreater are
common and well known operating parameters; such as a temperature
of from about 100.degree. C. to about 400.degree. C.; a pressure of
from about 100 psig to about 1,000 psig; a liquid hourly space
velocity (LHSV) from about 0.2 to about 10.0; and a gas flow of
from about 100 to about 5,000 SCFB (standard cubic feet per barrel)
containing at least about 70% hydrogen.
[0014] Alternatively, a process for reducing the sulfur in
hydrocarbon liquids containing organic sulfur compounds comprises
sending substantially the entire hydrocarbon stream through a
hydrotreater to produce a reduced sulfur hydrocarbon stream and
then oxidizing the reduced sulfur hydrocarbon stream; to produce a
hydrocarbon stream with the sulfur being present as oxidized sulfur
compounds. The sulfur removed in the hydrotreater from the
hydrocarbon liquid depends on the types of organic sulfur present
and the conditions of the hydrotreater. The resulting hydrocarbon
stream has a reduced sulfur level. The hydrotreater operates at
conditions commonly found in today's refineries, to perform the
routine hydrodesulfurization reactions. The hydrotreater catalyst
may be any suitable hydrodesulfurization catalyst at the operating
conditions of the hydrotreater as generally stated above. After
exiting the hydrotreater, the reduced sulfur level hydrocarbon is
reacted with an oxidation agent to oxidize those organic sulfur
compounds not affected by the hydrodesulfurization reaction (like
substituted dibenzothiophenes). The oxidation of these sulfur
compounds produces the corresponding sulfones in the product
stream. The product stream may be further processed to physically
remove the sulfones. Alternatively, the product stream containing
the oxidized sulfur compounds is recycled to a hydrotreater. Thus,
a hydrocarbon product with ultra low levels of sulfur can be
produced.
[0015] Cracked naphtha also contains significant amounts of sulfur.
Contrary to the prior art practice of removing this sulfur by
hydrotreating, if processing begins by first oxidizing the organic
sulfur in the cracked naphtha stream and then feeding the cracked
naphtha stream containing the oxidized sulfur to a hydrotreater,
the sulfur is easily removed and hydrogenation of olefins is
substantially avoided thus maintaining the octane rating. By first
oxidizing the sulfur compounds in the cracked naphtha stream, the
resulting oxidized sulfur, usually sulfones, can be more easily
hydrotreated at relatively mild hydrotreating conditions, to remove
the sulfur from the oxidized sulfur compounds. In conventional
operation, the hydrotreater not only hydrodesulfurizes the cracked
naphtha, but also hydrogenates the olefins in the cracked naphtha.
By operating the hydrotreater at milder process conditions, such as
when compared to the case when the sulfur compounds are not
oxidized, hydrodesulfurization of the oxidized sulfur compounds
occurs but leaves the majority of the olefins unaffected (not
hydrogenated). By not hydrogenating the olefins, the product from
the process has substantially the same octane rating as the usual
cracked naphtha hydrotreater feed. Alternatively, the cracked
naphtha may also be hydrotreated first at mild conditions which
minimizes the olefin saturation in order to remove 50-80% of the
sulfur, followed by oxidation of the remaining sulfur compounds to
sulfones/sulfoxides. This stream of oxidized naphtha can be (a)
hydrotreated at mild conditions to desulfurize it further to the
desired very low sulfur level, without significant olefin
saturation; or (b) subjected to a separation process to separate
the oxidized sulfur compounds followed by recycling this stream
containing oxidized sulfur compounds in to the hydrotreater. Either
way, the sulfur is removed and the hydrocarbon added to the low
sulfur product, without substantial octane loss.
[0016] This invention has dramatic implications for achieving
ultra-low sulfur (zero to 50 ppm, depending on the regulatory
requirements) hydrocarbon products cost-effectively by making
better use of existing hydrodesulfurization units. There are at
least two basic configurations for implementing this invention and
many variations of each that could be envisioned by those skilled
in the art.
[0017] First, an oxidation process could be placed in the refinery
process flow upstream of an existing hydrotreating unit. Then the
advantage exists that oxidized sulfur compounds need not be removed
from the hydrocarbon stream. Rather, the entire hydrocarbon stream
effluent from the oxidation reactor, containing the oxidized sulfur
compounds, could be fed to the existing hydrotreater, where the
oxidized sulfur would be easily reduced to a hydrogen sulfide gas
stream to desulfurize the stream to ultra-low sulfur levels with
the hydrocarbon-now free of its sulfur-become part of the product
stream. One variation of this configuration would be to oxidize the
sulfur in the entire crude oil stream, either at the front-end of
the refinery or as part of the crude production process (at a
gathering station or crude shipment terminal). Another variation
would be to oxidize the lighter fractions of the crude oil after a
straight run distillation to separate the higher boiling residual
hydrocarbon from more useful products, such as naphtha, diesel,
fuel oil or gasoline blend components. These lighter fractions,
containing oxidized sulfur compounds, would then be sent to one or
more existing hydrotreaters.
[0018] Second, an oxidation process could be installed downstream
of an existing hydrotreating unit. In this configuration, after the
oxidation step, the oxidized sulfur compounds would normally be
separated from the hydrocarbon stream and combined with the feed to
the existing hydrotreater. The hydrotreater would substantially
eliminate the oxidized sulfur from the hydrocarbon stream
containing the oxidized sulfur and produce a stream containing a
reduced amount of organic sulfur compounds that would subsequently
be oxidized. The combination of the existing hydrotreater and the
downstream oxidation process would produce a hydrocarbon stream
having ultra-low sulfur levels. One variation of this combination
would provide for debottlenecking of an existing hydrotreater. The
severity of conditions in the hydrotreater could be relaxed
somewhat, allowing it to process a larger volume of hydrocarbon and
allow more organic sulfur compounds to pass through to the
oxidation reactor. Although the product from the hydrotreater would
contain more sulfur than in conventional practice, this sulfur
would be oxidized in the downstream oxidation unit, separated from
the hydrocarbon stream and recycled back to the hydrotreater. As an
alternative to an extensive separation of the oxidized sulfur for
recycle, a second hydrodesulfurization reactor maybe utilized to do
the final sulfur removal.
[0019] Those skilled in refining technology would be able to
readily design a variety of systems involving various combinations
of existing hydrotreaters and added oxidation reactors to achieve a
broad slate of ultra-low sulfur hydrocarbon products.
[0020] The hydrotreaters referred to above may operate at
conventional hydrotreating conditions, those commonly found in
refineries today for desulfurization, or at milder conditions. The
hydrotreater catalyst may be any suitable hydrotreating catalyst.
Examples of the conditions of the hydrotreater are: a temperature
range of about 100.degree. C. to about 400.degree. C.; a pressure
range from about 100 psig to about 1,000 psig; a liquid hourly
space velocity (LHSV) ranging from about 0.2 to about 10.0; and a
gas flow range from about 100 to about 5,000 standard cubic feet
per barrel (SCFB) having at least about 70% hydrogen. When the
hydrotreater is operated at conditions usual in the refinery absent
to pre-oxidation of the sulfurs, it has been surprisingly
discovered that the rate of throughput to the reactor can be
increased. Equivalent production is realized at milder temperatures
and pressure. These lower temperatures and pressure conditions
produce the extra advantage of preserving the olefin content of the
hydrocarbon stream in the case of cracked naphtha feeds.
[0021] Hydrocarbon streams in a refinery contain a range of organic
sulfur compounds and have a total sulfur content from about zero
(up to about 2 ppm) up to about 6% (60,000 ppm) or sometimes more.
The compounds include, but are not limited to mercaptans, sulfides
and thiophenes (including benzothiophene, dibenzothiophene and a
wide range of substituted dibenzothiophenes). The compounds also
may include complex structures found in crude oils and residues,
such as asphaltenes, resins and heavy waxes. When these streams are
processed in hydrodesulfurization units, the level of sulfur is
reduced by an amount dependent on the specific sulfur compounds
present, the severity of the hydrotreating, the formulation of the
catalyst and many other factors related to the design and operation
of the unit. If oxidized sulfur compounds are produced by an
oxidation reaction, such as the one described in U.S. patent
application Ser. No. 09/654,016, incorporated by reference, or
other sulfur oxidation processes within the art, then the sulfur in
those oxidized sulfur compounds is substantially completely
converted to hydrogen sulfide in a subsequent hydrotreating unit,
regardless of whether the oxidized compounds are processed in
admixture with non-oxidized sulfur compounds, or not.
[0022] While the following describes this invention in some detail,
it must be understood by those skilled in the art that there is no
intention on the part of the inventors hereof to abandon any part
of the concepts of this invention with respect to the oxidation of
the organic sulfur in crude oils, refinery intermediate streams or
hydrocarbon products, whether they be fuels, chemical feedstocks or
other.
BRIEF DESCRIPTION OF THE DRAWINGS
[0023] The following drawings to aid in the consideration of the
description of the process of this invention show the main
operating features of the refinery involved. Of course those
skilled in the refinery art understand that miscellaneous equipment
such as pumps and valves, heat exchangers, sensors, instrumentation
and the like are all part of the successful operation of the
process described herein. Those skilled in the refinery art will
know and understand how to incorporate such equipment into the
process.
[0024] FIG. 1 shows a process block flow diagram of an embodiment
of the desulfurization of a hydrocarbon stream by the processes of
oxidation of organic sulfur in the hydrocarbon followed by
hydrodesulfurization of the oxidized organic sulfur.
[0025] FIG. 2 shows a process block flow diagram of an alternate
embodiment of a process for desulfurizing a crude stream using
oxidation before an existing crude distillation unit.
[0026] FIG. 3a shows a process block flow diagram of an alternate
embodiment of a process for desulfurizing a crude stream using
oxidation before hydrotreaters.
[0027] FIG. 3b shows a process block flow diagram of an alternate
embodiment of a process for desulfurizing a crude stream using
separate oxidation units before hydrotreaters.
DETAILED DESCRIPTION OF THE INVENTION
[0028] The invention summarized above will be more completely
described as set forth hereinafter. Sulfur can be substantially
completely removed from hydrocarbon streams such as fuels,
gasolines, oils and various distillation products by oxidizing the
organic sulfur compounds in the hydrocarbon followed by a
hydrodesulfurization step which operates on substantially the
entire flow stream. Accordingly, there is no requirement that the
oxidized sulfur compounds be separated from the hydrocarbon prior
to the hydrodesulfurization step which is substantially
quantitative. It works equally effectively on oxidized sulfur
species produced from the oxidation treatment of crude oils and
crude oil fractions or heavy crudes diluted with aromatic solvents.
The oxidized organic sulfur compounds normally are in the form of
organic sulfones and sulfoxides which are easily reacted to give
off hydrogen sulfide.
[0029] A hydrocarbon stream containing organic sulfur is oxidized
first and then hydrotreated to produce an ultra low sulfur product.
The hydrocarbon stream may be any crude oil or fraction thereof.
The oxidation of such a hydrocarbon stream produces a hydrocarbon
stream containing corresponding sulfones of certain organic sulfurs
in the feed which also may contain sulfur compounds that were not
oxidized due to the oxidation method and conditions employed. The
oxidation of a hydrocarbon stream has been discussed in prior art
followed by often-complicated separation steps to remove the
relatively small amounts of oxidized sulfur in the forms of
sulfones, many of which are significantly hydrocarbon soluble.
Further, the disposition of the sulfones produced from such
processes remains a problem.
[0030] The hydrocarbon stream containing oxidized sulfur compounds
may be obtained by any suitable oxidative methods, known and
unknown, for oxidizing sulfur in hydrocarbon products and crude
streams such as, for example, those found in U.S. Pat. No.
6,171,478 (acetic acid/hydrogen peroxide); U.S. Pat. No. 3,551,328
(organic peracids/metal catalyst); U.S. Pat. No. 5,958,224
(peroxometal); U.S. Pat. No. 5,310,479 (formic acid/hydrogen
peroxide); and U.S. Pat. No. 6,160,193 (Caro's acid), and U.S.
patent application Ser. No. 09/654,016 (carboxylic acid/hydrogen
peroxide), all of which are incorporated in their entirety herein
by reference. All those processes disclose methods for producing a
hydrocarbon stream containing oxidized organic sulfur compounds.
The oxidation reaction may be described as contacting the
hydrocarbon stream containing the organic sulfur compounds with an
effective amount of an alkaline earth metal peroxide stream which,
upon activation by an effective amount of an acid stream, produces
hydrogen peroxide in situ to form a reaction mixture in which the
organic sulfur present in the hydrocarbon stream reacts to form
organic sulfones and sulfoxides corresponding to the sulfur
compounds in the hydrocarbon stream.
[0031] In the practice of this invention a hydrocarbon stream
containing oxidized sulfur compounds is hydrotreated in a
conventional hydrotreater. The hydrodesulfurization catalyst used
herein is not essential to the practice of the invention and can be
any commercially available hydroprocessing catalyst known to one
skilled in the art. Suitable hydroprocessing catalysts include
those disclosed in Oil & Gas Journal, Sep. 27, 1999, pages
50-62, under the headings of "Hydrocracking catalysts," "Mild
hydrocracking catalysts," "Hydrotreating/hydrogenation/- saturation
catalysts," and "Hydrorefining catalysts." The hydroprocessing
catalysts for use herein are well known and preferably deposited on
an inorganic oxide carrier material of either synthetic or natural
origin. Preferred carrier materials maybe selected from alumina,
silica-alumina, activated carbon, silica, titania, magnesia and
mixtures thereof. Particularly, the hydrodesulfurization catalyst
can comprise, consist of, or consist essentially of a Group VIII
metal selected from the group consisting of iron, cobalt, nickel,
ruthenium, rhodium, palladium, osmium, iridium, platinum, and
combinations of any two or more thereof, and a Group VIB metal
selected from the group consisting of chromium, molybdenum,
tungsten, and combinations of any two or more thereof. Preferably,
the hydrodesulfurization catalyst comprises cobalt and molybdenum.
Catalytic promoters including but not limited to phosphorus,
halogens, silica, zeolite, and alkali and alkaline earth metal
oxides that are known to those in the art may also be present in
the catalyst. Emerging commercial hydroprocessing catalysts are
also suitable as catalysts for this purpose. The particle size or
shape of the hydroprocessing catalyst required for the process of
the present invention is generally dictated by the reactor system
utilized for practicing the invention.
[0032] Since hydrotreating catalysts of only reasonable catalytic
activity are required for the process of the present invention, in
order to lower the costs, refinery spent (or used) hydroprocessing
catalysts may also be utilized advantageously in this process with
respect to some feed streams. A fixed bed reactor system is the
preferred reactor system, even though other kinds of reactor
systems known to those knowledgeable in the art for hydroprocessing
purposes can also be utilized to conduct the present process. The
process conditions of the hydrotreating process disclosed herein
include a temperature range from about 100.degree. C. to about
400.degree. C. and preferably ranging from about 150.degree. C. to
about 380.degree. C.; a pressure range from about 100 psig to about
1,000 psig and preferably ranging from about 200 psig to about 500
psig; a liquid hourly space velocity (LHSV) range from about 0.2 to
about 10.0; and a gas flow range from about 100 to about 5,000 SCFB
(Standard cubic feet per barrel) having at least about 70%
hydrogen. Other gases such as nitrogen, natural gas and fuel gas
may also be present along with hydrogen. Those skilled in refinery
operations are able to readily select conditions which would be
successful. The product hydrocarbon oil from the process, after
removing the dissolved hydrogen sulfide by methods that are
generally practiced, and well known in the art, is directly used
for blending into the respective product streams. The hydrotreating
conditions are dictated by the feed stream and the quality of the
product stream desired.
[0033] In addition to providing a simple method for processing sour
crudes to achieve almost sulfur free, motor fuels other advantages
of this invention become evident. Oxidized sulfur compounds do not
have to be separated since they can be reacted in the hydrotreater
in the presence of the entire hydrocarbon stream to create a
hydrogen sulfide gas stream which is easy to dispense of. Also, the
organic moiety to which the sulfur was attached becomes part of the
product. Nowhere in the art is this result taught.
[0034] This invention is adaptable to many refinery process
configurations but only a few will be discussed here. Those skilled
in the art will perceive many other permutations and conbinations
of process based upon this description. Referring to FIG. 1 showing
a general block diagram of the process of this invention, a feed 10
is fed to an oxidation section 20. The feed may be any hydrocarbon
stream that contains organic un-oxidized and/or oxidized sulfur
compounds. The hydrocarbon stream may be, but is not limited to,
crude oil, bottom residues from an atmospheric and vacuum
distillation tower (with or without a suitable diluent), fractions
from a crude distillation tower such as diesel fuel, gasoline,
kerosene, and other hydrocarbon streams within a refinery. The
sulfur compounds often found in hydrocarbon streams include, but
are not limited to, thiophenic sulfur compounds, benzo and dibenzo
thiophenes, mercaptans, sulfides and polysulfides. Asphaltenes and
resins often present in crude oil or refinery bottom streams are
also likely to have sulfur as a part of some complicated
hydrocarbon structure.
[0035] The oxidized sulfur compounds include, but are not limited
to, sulfones and sulfoxides. If the feed 10 is a crude oil or a
hydrocarbon having a particularly high viscosity which renders it
difficult to pump, then it may preferably be diluted by adding
another hydrocarbon stream. This diluent often is a distillate
hydrocarbon stream produced in a crude oil distillation unit or a
mixture of low-viscosity hydrocarbon streams. The diluent may also
be well-head condensate liquids from natural gas produced from the
field where the sulfur removal processing unit is located; or any
other suitable miscible material may be used as a diluent. The
diluent is selected based upon the requirements of the properties
of the feed stream and availability of the diluent. The diluent
reduces the total sulfur concentration in the feed 10 and is
recovered and goes through the process as hydrocarbon product. If
the diluent stream itself contains sulfur compounds, these are
removed in the practice of this invention. Recovered diluent would
then have a lowered sulfur content. The feed 10 may have a sulfur
content from about 0.005 (50 ppm) to about 5 wt % and is charged to
the oxidation reactor 20.
[0036] The oxidation section 20 maybe any known as set forth in the
prior art mentioned above or unknown yet to be discovered oxidation
processes suitable for use to oxidize sulfur compounds and/or
nitrogen compounds in the presence of hydrocarbon. The sulfur
containing hydrocarbon fed through line 10 is contacted with an
oxidizing solution which oxidizes the sulfur compounds to their
corresponding sulfones or sulfoxides. Within the oxidation section
20 are methods for separating the hydrocarbon phase containing
oxidized sulfur compounds from an aqueous phase containing the
oxidizing agent. These processes normally include, for example,
liquid-liquid separation, liquid-liquid extraction, solid-liquid
separation, distillation, or combinations thereof.
[0037] The hydrocarbon exiting the oxidation reactor 20 through
line 30 and is introduced into hydrotreater 50. The hydrotreater 50
preferably maybe an existing hydrotreater. The conditions of the
hydrotreater 50 are dependent on the feed entering it. Those
skilled in the art will be able to select proper conditions for the
hydrotreater 50 as required to meet the product standards desired.
An example of conditions appropriate for the hydrotreater 50 may be
as follows: a temperature ranging from about 100.degree. C. to
about 400.degree. C. and preferably ranging from about 150.degree.
C. to about 380.degree. C.; a pressure ranging from about 100 psig
to about 1,000 psig and preferably ranging from about 200 psig to
about 500 psig; a liquid hourly space velocity (LHSV) ranging from
about 0.2 to about 10.0; and a gas flow ranging from about 100to
about 5,000 SCFB (standard cubic feet per barrel) having at least
about 70% hydrogen. A most preferred range of operating conditions
for the hydrotreater 20 are a temperature from about 200.degree. C.
to about 380.degree. C. and a pressure from about 200 to about
500psig. Other gases such as nitrogen, natural gas and fuel gas may
also be in the gas stream along with the hydrogen. The hydrotreater
50 produces a hydrocarbon stream substantially free of sulfur
compounds, and sulfur exits as hydrogen sulfide gas through line
40. Line 60 contains the hydrocarbon stream substantially free of
any sulfur containing compounds. Since the hydrodesulfurization of
the oxidized organic sulfur in the hydrocarbons proceeds at less
strenuous conditions than are normally present in a typical
hydrodesulfurization reactor, it is possible to use less vigorous
hydrodesulfurization conditions in the reactor 50. The result is to
achieve a substantially sulfur-free (0-15 ppm) hydrocarbon and an
additional stream of oxidized sulfur compounds.
[0038] In a preferred embodiment, the oxidation reaction carried
out in the oxidation section 20 is as described in U.S. patent
application Ser. No. 09/654,016, which is incorporated by reference
in its entirety herein. Within the oxidation section 20, the feed
entering through line 10 is preferably contacted with an oxidizing
solution containing hydrogen peroxide, a C.sub.1-C.sub.4 carboxylic
acid, and a maximum of about 25 percent water. The total amount of
hydrogen peroxide in the oxidizing solution is greater than about
two times the stoichiometric amount of peroxide necessary to react
with the sulfur in the reduced hydrocarbon stream 10, considering
that the reactor 20 may be run as a single unit or as a staged
reactor with split streams being used, or as a countercurrent
contact flow. The reaction within the oxidation section 20 is
carried out at a temperature from about 50.degree. C. to about
130.degree. C. for less than about 15 minutes contact time at close
to, or slightly higher than atmospheric pressure, at optimum
conditions. The preferred oxidizing solution used in the practice
of the invention has, not only a low amount of water, but also
small amounts of hydrogen peroxide with the C.sub.1-C.sub.4
carboxylic acid being the largest constituent as described in the
aforementioned patent application (see Ser. No. 09/654,016). Where
fuel products are involved, the oxidizing solution preferably has a
concentration of hydrogen peroxide, which is consumed in the
reaction, ranging from about 0.5% to about 4.5% by weight, and most
preferably from about 2 to about 3 wt %. The same may not be true
where the feed is a crude stream or a rough cut distillation
product. Some routine experimentation well within the skill of a
refinery engineer would be needed in order to determine the optimum
oxidizing solution concentrations. The water content is limited to
less than about 25 wt %, but preferably between about 8 and about
20%, and most preferably from about 8 to about 14 wt %. The
oxidation/extraction solution contains from about 75 wt % to about
92 wt % of a C.sub.1 to C.sub.4 carboxylic acid, preferably formic
acid, and preferably 79 wt % to about 89 wt % formic acid. The
molar ratio of acid, preferably formic acid, to hydrogen peroxide
is at least about 11 to 1 and from about 12 to 1 to about 70 to 1
in the broad sense, and preferably from about 20 to 1 to about 60
to 1. Of course, in the event that the oxidizing section is
constructed downstream of an existing hydrodesulfurization reactor,
in order to oxidize the organic sulfur containing hydrocarbons
which are difficult to remove by hydrodesulfurization, a second
desulfurization reactor may be placed downstream of the oxidation
reactor in order to avoid the necessity of building and operating
equipment to make the separation of oxygenated sulfur hydrocarbon
compound. This, of course, would be an economic consideration but
well within the pervue of those of ordinary skill in the art. The
oxygenation reactor would be operated in substantially the same
manner as that discussed above for the existing hydrotreater
50.
[0039] FIG. 2 is an alternative embodiment that utilizes existing
refinery process units along with an oxidation section to produce
desulfurized hydrocarbon products. The feed 10 is a
sulfur-containing crude oil. As stated, if heavy, viscous or has
high sulfur content, a diluent can be appropriately used. The
oxidation section 20 may include any oxidative process described
above, known or unknown, that produces a hydrocarbon stream
containing oxidized organic sulfur compounds 70. In a preferred
embodiment, the oxidation section 20 is placed before an existing
crude distillation tower 130 to pre-treat the organic sulfur and
nitrogen in the crude oil stream. The oxidation section 20 produces
the hydrocarbon containing oxidized sulfur and nitrogen compounds
70. The oxidation section 20 may be integrated into a refinery or
may be used at a remote production site to upgrade crude oil before
being sent to the refinery. The hydrocarbon stream containing
oxidized sulfur compounds 70 is processed in existing refinery
processes. The oxidation of the feed shifts the boiling point of
the sulfur compounds higher. This shift in the boiling point of the
sulfur compounds shifts the distribution of oxidized organic sulfur
compounds 70 into different distillation fractions relative to
un-oxidized sulfur compounds. This shift in the boiling point means
that the lighter fractions from the crude distillation tower have a
reduced total sulfur concentration which may eliminate the
hydrotreating process or the hydrotreating process may operate
under relatively milder conditions. The hydrocarbon containing
oxidized organic sulfur compounds 70 is fractionated in the crude
distillation tower 130 into, but not limited to, for example, a
light distillate 140, a middle distillate 150, a heavy distillate
160, and a reduced crude 170. Those skilled in the art of
distillation can specify the operating conditions of the crude
distillation tower 130 to produce these well known refinery crude
fractions. The light distillate 140, the middle distillate 150, and
the heavy distillate 160 are sent to existing hydrotreaters 50. The
existing hydrotreaters 50 operate at existing conditions to remove
the sulfur in the oxidized sulfur compounds and residual
non-oxidized sulfur compounds with minimal hydrocarbon loss with
the sulfur being easily removed as hydrogen sulfide and the
nitrogen as ammonia. Those skilled in the art of hydrotreating will
be able to select conditions of the hydrotreaters 50 that
accomplish the hydrodesulfurization to desired product qualities.
After hydrotreating, the light distillate 140 becomes a low sulfur
gasoline 180. The low sulfur gasoline 180 has a sulfur content
ranging from about 0 to about 50 ppm. After hydrotreating, the
middle distillate 150 becomes a low sulfur diesel/heating oil 190.
The low sulfur diesel/heating oil 190 has a sulfur content ranging
from about 0 to about 15 ppm. After hydrotreating, the heavy
distillate 160 becomes a feed 200 to an existing fluid catalytic
cracking unit 210 which produces a low sulfur gasoline 220 and a
low sulfur diesel/heating oil 230 to combine with the low sulfur
gasoline 180 and the low sulfur diesel/heating oil 190,
respectively. Those skilled in the art can determine the operating
conditions of the fluid catalytic cracking unit 210 to achieve the
desired products. In an alternate embodiment, if there is no
hydrotreater 50 to pre-treat the heavy distillate 160 prior to the
catalytic cracker 210, the exit streams 220 and 230 are combined
with streams 140 and 150, respectively, and fed to the appropriate
hydrotreater 50. The reduced crude 170 is sent to existing
conversion units, which one skilled in the art can determine.
[0040] FIGS. 3a, 3b, and 3c depict selected, but not exhaustive
examples of alternative embodiments for realizing the advantages of
the present invention. FIGS. 3a and 3b show oxidation downstream of
a crude unit, but upstream of a hydrotreater. This arrangement
allows the oxidized sulfones to be treated by the hydrotreater, to
release hydrogen sulfide and to produce low sulfur fuel
products.
[0041] In FIG. 3a, the feed 10 is a crude oil fed to the existing
crude unit 130. The existing crude unit 130 produces a light
distillate 140, a heavy distillate 160 and a reduced crude 170.
Those skilled in the art will be able to determine the operating
conditions of the existing crude unit to produce these standard
refinery streams according to the product mix of the refinery and
the crude oil stream for which it was designed. The reduced crude
170 is sent to existing conversion processes, which one skilled in
the art will be able to determine. The heavy distillate 160 is sent
to the existing fluid catalytic cracking unit 210 which produces a
cracked stream in line 300. The cracked stream 300 has properties
similar to the light distillate 140. The cracked stream 300 and the
light distillate 140 are combined and sent to the oxidation section
20. The oxidation section may employ any oxidation reaction
sequence and agent as mentioned previously which produces a
hydrocarbon reaction mixture containing oxidized sulfur and
nitrogen compounds which exit in line 70. Preferably, the oxidation
reaction sequences are those that do not substantially react with
olefins (i.e. no octane loss). The oxidant described in U.S. patent
application Ser. No. 09/654,016 is incorporated herein by reference
for all purposes. The hydrocarbon stream containing oxidized sulfur
and nitrogen compounds in line 70 is sent to a product splitter 310
resulting in a gasoline fraction in line 320 and a diesel fraction
in line 330. Those skilled in the art will be able to determine the
operating conditions of the product splitter 310 to achieve the
product desired streams. The gasoline in line 320 and the diesel in
line 330, still containing the oxidized sulfur and nitrogen
compounds, are sent to existing hydrotreater that operate to
produce ultra-low sulfur and low nitrogen products from the
respective feed streams, releasing gaseous hydrogen sulfide and
ammonia. The existing hydrotreaters 50 produce the low sulfur
gasoline in product line 180 and the low sulfur diesel/heating oil
in product line 190. Those skilled in the art will be able to
determine the operating conditions which produce product streams of
the desired specifications.
[0042] Approximately 40% of the gasoline pool is made up of cracked
naphthas produced in either thermal or catalytic cracking units.
More than 90% of the sulfur in the entire gasoline pool comes from
the sulfur present in the cracked naphthas, such as, for example,
mercaptans, sulfides, thiophenes and polysulfides. By desulfurizing
the cracked naphthas, an ultra-low sulfur blendstock for gasoline
is produced. Under conventional refinery practice, it is very easy
to hydrotreat the cracked naphthas to remove sulfur, but in the
process, the olefins in the cracked naphtha are hydrogenated to
paraffins, reducing the value as a gasoline component, since
olefins have a higher octane rating than paraffins. This
hydrogenation of olefins to paraffins significantly reduces the
octane number of the desulfurized cracked naphtha. It is a
particular advantage of the present invention that this process to
remove sulfur from cracked naphtha minimizes the hydrogenation of
the olefins, thereby maintaining the octane number. The oxidized
sulfur compounds, i.e. sulfones, can be removed by hydrotreating
the corresponding unoxidized sulfur compounds at significantly
milder reaction conditions at the lower end of the ranges mentioned
above. These milder reactor conditions preserve the octane rating
of the cracked naphtha by not saturating the olefins present in the
feed. The embodiment shown in FIG. 3a as described above shows this
advantage. The gasoline from line 320 is hydrodesulfurized in the
existing hydrotreater 50 at significantly milder process conditions
than typical hydrotreaters. The resulting desulfurized gasoline in
product line 180 is an ultra-low sulfur blendstock to a pool for
gasoline blending whose octane rating is almost equal to that of
the gasoline being fed to the process. The hydrogen requirements
for the existing hydrotreater 50 are reduced since only a slight
amount of hydrogen is consumed in olefin hydrogenation, which
provides an additional economic benefit. Those skilled in the art
will be able to determine the operating conditions which produce
product streams of the desired specifications.
[0043] In the alternative embodiment shown in FIG. 3b, the feed in
stream 10 is crude oil fed to the existing crude unit 130. The
existing crude unit 130 divides the crude into light distillate in
conduit 140, a middle distillate in conduit 150, a heavy distillate
in conduit 160 and a reduced crude stream 170. Those skilled in the
art will be able to determine the conditions of the existing crude
unit to produce these standard well-known refinery streams. The
reduced crude steam 170 is sent to existing conversion processes
for further processing, as one skilled in the art will be able to
determine. The distillate streams are sent to separate oxidation
sections 20. The oxidation sections are operated using any
oxidation process, which oxidizes the organic sulfur compounds to
the effluent containing the oxidated sulfur. The oxidation sections
20 are tailored for the particular feed stream it oxidizes. The
organic sulfur compounds in the light distillate in line 140 are
oxidized in the oxidation section 50, light distillate stream 440
which contains oxidized sulfur compounds is fed to an existing
hydrotreater 50, where the oxidized sulfur compounds are reacted
with hydrogen to remove the sulfur as hydrogen sulfide gas, to
produce the desulfurized gasoline exiting through line 180.
Similiarly, the middle distillate in line 150 and the heavy
distillate in line 160 are subjected to the oxidation and
hydrodesulfurization, in the oxidation section 20 and the
hydrotreater section 50, to produce low sulfur streams in lines 190
and 200 respectively. The desulfurized heavy distillate in line 200
is fed to a conventional, probably existing, fluid catalytic
cracking unit 210 which produces the low sulfur gasoline in line
220 and the diesel/heating oil in line 230 which are combined with
the desulfurized gasoline in line 180 and the desulfurized
diesel/heating oil in line 190, respectively. The specific
operating conditions of the existing process units are well within
the skill in the art requiring little or no experimentation to
produce product streams of the desired specifications.
[0044] Any stream containing organic sulfur in it either before or
from a crude distillation unit can be run through the oxidation
step of this invention to produce a hydrocarbon effluent stream
which contains oxidized organic sulfur compounds that maybe
subsequently sent to a suitable hydrotreater for
hydrodesulfurization to remove substantially all sulfur from the
stream and recover the hydrocarbon, previously part of the sulfur
compound, to the stream of useful hydrocarbon, for processing to
produce a substantially sulfur free product. Some feed streams
could be hydrotreated and then oxidized with the oxidized sulfur
compounds being separated and recycled to the hydrotreater. These
streams include, but are not limited to, vacuum gas oil, combined
coker distillates, combined fluid catalytic cracking (FCC)
distillates, combined (or separate) coker and FCC-cracked
distillates, combined (or separate) coker and FCC-cracked naphtha,
whole crude, and straight run distillate fractions. However, if
there is a desire to avoid the separation of two hydrocarbon
streams, usually by an extraction process, a second hydrotreater
could be used, or the treatment sequence changed, to place the
oxidation step prior to hydrotreating, thus avoiding the
inefficiencies inherent in separation processing.
[0045] By employing both the oxidation and hydrotreating processes
in various sequences, a product stream substantially free of sulfur
is possible with substantially no hydrocarbon yield loss. With the
current prospect of regulations reducing the maximum sulfur content
of fuels, such as gasoline or diesel fuel, to 5 to 50 ppm or less,
the practice of this invention provides a relatively inexpensive
and very beneficial disposal practice for sulfur. This is
particularly so in view of the low levels of sulfur, approaching
zero, that are obtainable through the combined practice of the
oxidation and hydrotreating processes. Those skilled in the art of
refinery operations can readily select a process flow through the
refinery that would produce extremely low sulfur content
products.
[0046] The foregoing results are further demonstrated by the
following examples, which are offered for purposes of illustration
of the practice of this invention and for the understanding; not
for the limitation thereof.
EXAMPLES
[0047] Unless otherwise stated, the following general experimental
procedure applies to all of the examples. The feed was a
sulfur-containing liquid hydrocarbon containing oxidized organic
sulfur compounds.
Example 1
[0048] An alumina supported Ni-Mo hydrosulfurization catalyst from
Criterion Catalyst Company, Houston, Tex., in the form of {fraction
(1/16)}' extrudates was used in a tubular fixed bed reactor. A
stainless steel laboratory reactor having 19 mm inner diameter and
40 cm length was used for all of the experiments. The reactor tube
had no internal structures. 30 cc of catalyst was loaded in the
center of the reactor, undiluted. The rest of the length of the
reactor was packed with glass beads and glass wool. The reactor was
heated with a four-zone clamshell furnace, each zone independently
controllable by electronic temperature programmer/controllers. The
reactor effluent went through a gas-liquid separator and entered a
collection vessel at reactor pressure, from which samples were
withdrawn.
[0049] The catalyst was presulfided at 350.degree. C. before the
catalytic reaction. A 2 weight % solution of a commercially
available sulfiding agent TPS-37 in hexadecane, available from
Atofina Chemicals, Philadelphia, Pa., was used for sulfiding the
catalyst. TPS-37 contains 37% sulfur by weight. The catalyst was
heated from room temperature to 350.degree. C. in about two hours
time while the sulfiding solution was sent through the reactor at
60 g/hr, at a pressure of about 100 psig, while a flow of 600
cc/min of hydrogen gas was maintained through the reactor. The
temperature of the reactor was held at 350.degree. C. for 3 hours,
and then the reactor was cooled to room temperature. The sulfiding
solution and hydrogen flows were maintained until the temperature
of the reactor reached about 200.degree. C. Only hydrogen flow was
maintained afterwards.
[0050] A solution of dibenzothiophene sulfone (DBT
sulfone)containing a 250 ppm concentration of sulfur in phenyl
hexane solvent was prepared using a commercially available sample
of DBT sulfone. This solution was used as the "feed" for the
hydrotreating experiments. The experiment was done at 4 different
reaction conditions. The hydrogen flow rate and the "feed" flow
rate were kept constant for all the four experiments. The "feed"
flow rate was 60 g/hr. At each reaction condition, the product
collected during the first 1 hour was rejected. Hourly liquid
product samples were collected from each of the experiments and
were analyzed using standard GC-MS analysis procedures. Results are
shown in Table 1.
1TABLE 1 Experiment Reaction-conditions Observations 1 350.degree.
C. and 500 psig 100% conversion of DBT sulfone. No DBT or DBT
sulfone were detected in product, indicating complete
hydrodesulfurization. Biphenyl, the main reaction product of DBT
sulfone was detected. Some solvent hydrogenation observed. 2
300.degree. C. and 500 psig 100% conversion of DBT sulfone. No DBT
or DBT sulfone were detected in product, indicating complete
hydrodesulfurization. Biphenyl, the main reaction product of DBT
sulfone was detected. 3 250.degree. C. and 200 psig 100% conversion
of DBT sulfone. Approximately 25% DBT and 75% Biphenyl, were
produced. 4 200.degree. C. and 200 psig 100% conversion of DBT
sulfone. However, approximately 50% DBT sulfone was converted into
DBT, which is a sulfur compound. The remaining DBT sulfone was
converted into biphenyl. This indicates less hydrodesulfurization
(HDS) under these extremely mild reaction conditions.
[0051] The above experiments show oxidized sulfur compounds are
converted under all reactor conditions. In Examples 1 and 2, all
DBT sulfones were removed and no sulfur products were detected in
the product after gas separation to remove the hydrogen sulfide. In
Experiments 3 and 4, at much milder conditions, approximately 25 to
50% of the DBT sulfones are converted to the corresponding
thiophenes, thus sulfur is still present in the product. Therefore,
the milder conditions of the hydrotreater may convert the oxidized
sulfur compounds but not all the sulfur from the hydrocarbon
product. Surprisingly, 75% of DBT sulfones can be hydrodesulfurized
at relatively mild reaction conditions of 250 .degree. C. and 250
psig pressure. The conditions depend on the purpose and nature of
the feed stream and demonstrate the flexibility of the process of
this invention such that those skilled in the art may adapt same to
use in the alternative embodiments described above as well as
variants thereof.
Example 2
[0052] This example is to provide guidance to the selection of
operating parameters for the hydrogenation of oxidized organic
sulfur compounds with comparison to the results for direct
hydrotreating of the sulfur in like samples.
[0053] An alumina supported Co-Mo catalyst from Criterion Catalyst
Company, in the form of 1.6 mm trilobe shaped extrudates was used
in the tubular fixed bed reactor system as described in Example 1
was loaded, undiluted. The reactor was packed with 40 cc of
catalyst and alpha alumina beads. The procedure for presulfiding
the catalyst as described in Example 1 was followed except that the
flow rate of the sulfiding solution was about 90 g/hr.
[0054] In order to stabilize the activity of the catalyst before
test samples are hydrotreated, an atmospheric gas oil containing
1.4 weight percent sulfur was hydrotreated over the sulfided
catalyst for approximately 9 hours at a liquid hourly space
velocity (LHSV) of 3.0, at a temperature of 350.degree. C., at a
pressure of 400 psig, while hydrogen was flowing at 600 cc/min. At
the end of the 9 hours, the flow was switched to a finished diesel
fuel containing approximately 300 ppm sulfur under identical
reaction conditions and was continued for another two hours before
the reactor was cooled down in hydrogen flow. Product samples were
periodically withdrawn and were analyzed for their sulfur content
in order to assure that the catalyst had attained stable activity.
The reactor was cooled to about 200.degree. C. when the diesel flow
was cut off. The hydrogen flow was continued until the reactor was
cooled down to about 100.degree. C. and the reactor was sealed
off.
[0055] A light atmospheric gas oil (LAGO) test sample containing
435 ppm total sulfur was used as the reactant feed. The pressure,
liquid flow rate, and hydrogen flow rate were kept constant at 400
psig, 100 g/hr, and 600 cc/min, respectively, at two different
temperatures, 250.degree. C. and 300.degree. C. Product samples
were withdrawn at both these conditions, ultrasonicated for 15-20
minutes to expel the dissolved hydrogen sulfide, and were analyzed
for sulfur by X-ray fluorescence (XRF) (ASTM D-2622). The results
are presented in Table 2 below.
2TABLE 2 Temp (C) Feed Sulfur Content (ppm) Product Sulfur Content
(ppm) 250 435 198 300 435 77 and 60
[0056] At the end of the run the reactor was cooled down to about
100.degree. C. in a similar way as before and was sealed off.
[0057] The feed was switched to an oxidized LAGO sample. The
oxidized LAGO sample was prepared by starting with the same LAGO
used above. The LAGO was oxidized using hydrogen peroxide aqueous
solution in the presence of formic acid catalyst. The excess
peroxide and formic acid were removed by repeated washing with a
mild basic solution. The "oxidized LAGO" was dried. The oxidized
LAGO contains less sulfur 320 ppm, than the starting LAGO due to
the removal of some sulfur compounds with the aqueous phase and
during the washing.
[0058] The hydrotreating experiments with the oxidized LAGO were
conducted at four different temperatures with the other parameters
remaining the same; that is, a pressure of 400 psig, a flow rate of
100 g/hr, and a hydrogen flow rate of 600 cc/min. At each
temperature, after an hour of stabilization, two product sample
cuts were at half an hour intervals before the temperature was
increased to the next higher test temperature. Product samples were
ultrasonicated for 15-20 minutes to expel the dissolved hydrogen
sulfide for sulfur by X-ray fluorescence (XRF). The results are
presented in Table 3 below.
3TABLE 3 Temp (C) Feed Sulfur Content (ppm) Product Sulfur Content
(ppm) 225 320 155 and 153 250 320 109 and 103 275 320 88 and 79 300
320 64 and 55
[0059] Table 4 provides the comparison of the results from the
hydrotreating experiments using LAGO and oxidize LAGO feeds. It can
be seen from the results presented in Table 4 that sulfur removal
by conventional catalytic hydrodesulfurization from oxidized middle
distillates is not only possible, but also is easier than sulfur
removal from the parent unoxidized middle distillate feed. From the
foregoing information, the expectation of sulfur removal from the
various parameters can be predicted. Those of ordinary skill in the
art will be guided toward the determination of parameters for
particular feeds and loadings of sulfur.
4 TABLE 4 Feed Sulfur Product Sulfur % Sulfur Content (ppm) Content
(ppm) Removal Temp Oxidized Oxidized Oxidized (C) LAGO LAGO LAGO
LAGO LAGO LAGO 225 320 153 52.2 250 435 320 198 103 54.5 67.8 300
435 320 60 55 86.2 82.8
[0060] The foregoing description of the invention and the specific
examples described demonstrate the benefits of the hydrotreating of
oxidized sulfur compounds. The above-described description is
offered for purposes of disclosing the advantages of the instant
invention for use in desulfurizing the aforementioned fuel oils.
Having been taught such process by the above discussion and
examples, one of ordinary skill in the art could make modifications
and adaptations to such process without departing from the scope of
the claims appended hereto. Accordingly, such modification,
variations and adaptations of the above-described process and
compositions are to be construed within the scope of the claims
which follow.
* * * * *