HYDRODESULFURIZATION OF OXIDIZED SULFUR COMPOUNDS IN LIQUID
HYDROCARBONS
FIELD OF THE INVENTION
This invention relates to a process for the removal of sulfur from liquid hydrocarbons by
hydrptreating the liquid hydrocarbon containing oxidized sulfur compounds.
BACKGROUND OF THE INNENTION
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.
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.
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.
As disclosed in U.S. Patent Application Serial No. 09/654,016 the 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.
U.S. Patent No. 6,171,478 (Cabrera, et al.) discloses a desulfurization process of a
hydrocarbonaceous oil. The hydrocarbonaceous oil is treated in a hydrodesulfurizationunit 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 streamhaving areduced 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 ofMolecular Catalysis A: chemical 117(1997), 397-
403.
A subsequently issued U. S . Patent 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
hyαrodesulfurization 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 hydrodesulfurization reactor.
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
effectivenessofexistmghydrodesuifurizationurώ^ 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
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
hydrocarboninthehydrotreater, 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.
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 ofless hydrogenation ofthe olefins. The hydrotreater catalyst maybe any suitable
hydrotreating catalyst. The conditions ofthe hydrotreater are common and well known operating
parameters; such as a temperature of from about 100 ° C to about 400 ° 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.
Alternatively, a process for reducing the sulfur in hydrocarbon liquids containing organic sulfur
compounds comprises sending substantially the entire hydrocarbon stream through ahydrotreater 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 ofthe 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 ofthe 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 maybe 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.
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 ofthe
oxidized sulfur compounds occurs but leaves the majority ofthe 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
% ofthe sulfur, followed by oxidation ofthe 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.
This invention has dramatic implications for achieving ultra-low sulfur (zero to 50 ppm,
d endingonmeregulatoryrequ ements)hydrocarbonproductscost-effectivelybymal ngbetteruse
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.
First, an oxidation process could be placed in the refinery process flowupstream 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 ofthe product stream.
One variation of this configuration would be to oxidize the sulfur in the entire crude oil stream, either
at the front-end ofthe refinery or as part ofthe crude production process (at a gathering station or
crude shipment terminal) . Another variation would be to oxidize the lighter fractions ofthe 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.
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 areduced amount of organic sulfur compounds that
would subsequently be oxidized. The combination ofthe 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 sulflir would be oxidizedin the downstream oxidation unit, separatedfromthehydrocarbonstrearn
and recycled back to the hydrotreater. As an alternative to an extensive separation ofthe oxidized
sulflir for recycle, a second hydrodesulfurization reactor may be utilized to do the final sulfur removal.
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.
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 ofthe conditions ofthe hydrotreater are:
a temperature range of about 100°C to about 400°C; a pressure range from about 100 psig to about
l,000psig; 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
ofthe 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.
Hydrocarbon streams in a refinery contain arange 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 ofthe
hydrotreating, the formulation ofthe catalyst and many other factors related to the design and operation
ofthe unit. If oxidized sulfur compounds are produced by an oxidation reaction, such as the one
described in U.S. Patent Application SerialNo.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.
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 ofthe inventors hereof to abandon any part ofthe
concepts of this invention with respect to the oxidation ofthe organic sulfur in crude oils, refinery
intermediate streams or hydrocarbon products, whether they be fuels, chemical feedstocks or other.
BRIEF DESCRIPTION OF THE DRAWINGS
The following drawings to aid in the consideration ofthe description ofthe process of this
invention show the main operating features ofthe 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 ofthe successful operation ofthe process described
herein. Those skilled in the refinery art will know and understand how to incorporate such equipment
into the process.
Fig. 1 shows a process block flow diagram of an embodiment ofthe desulfurization of a
hydrocarbon stream by the processes of oxidation of organic sulfur in the hydrocarbon followed by
hydrodesulfurization ofthe oxidized organic sulfur.
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.
Fig. 3 a shows a process block flow diagram of an alternate embodiment of a process for
desulfurizing a crude stream using oxidation before hydrotreaters.
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
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.
A hydrocarbon stream containing organic sulfur is oxidized first and then hydrotreated to
produce an ultra low sulfur product. The hydrocarbon stream maybe 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 ofwhich are significantly hydrocarbon
soluble. Further, the disposition ofthe sulfones produced from such processes remains a problem.
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 inU. S . Patent Serial Nos.6, 171 ,478 (acetic acid/hydrogen
peroxide); 3,551,328 (organic peracids/metal catalyst); 5,958,224 (peroxometal); 5,310,479 (formic
acid/hydrogen peroxide); and 6,160,193 (Caro's acid), and U.S. Patent Application Serial
No.09/654,016 (carboxylicacid/hydrogen peroxide), all ofwhich 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.
In the practice ofthis 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 ofthe 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, Sept. 27, 1999, pages 50-62, under the headings of Ηydrocracking 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 may
be 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
NHt 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 VTB 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 ofthe hydroprocessing catalyst required for the process ofthe present invention
is generally dictated by the reactor system utilized for practicing the invention.
Since hydrotreating catalysts of only reasonable catalytic activity are required for the process
ofthe 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 ofthe hydrotreating process disclosed herein include a temperature
range from about 100 ° C to about 400 ° C and preferably ranging from about 150 ° C to about 380 ° 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 directlyused for blending
into the respective product streams. The hydrotreating conditions are dictated by the feed stream and
the quality ofthe product stream desired.
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 ofthe 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 ofthe product. Nowhere in the art is
this result taught.
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 ofthe
process of this invention, a feed 10 is fed to an oxidation section 20. The feed 10 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, mercaptaris, 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.
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 ofthe properties ofthe
feed stream and availability ofthe 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.
The oxidation section 20 may be 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 ofhydrocarbon. The sulfiir 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.
The hydrocarbon exiting the oxidation reactor 20 through line 30 and is introduced into
hydrotreater 50. The hydrotreater 50 preferably may be 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 maybe as follows: a temperature ranging
from about 100°C to about 400 °C and preferably ranging from about 150°C to about 380°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 100 to 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 ° C to about 380 ° C and a pressure from about 200 to about 500 psig.
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 ofthe 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 hydVodesulfurization 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.
In a preferred embodiment, the oxidation reaction carried out in the oxidation section 20 is as
described in U.S. Patent Application SerialNo.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, - C 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 ° C to about 130 ° 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 ofthe invention has, not only
a low amount of water, but also small amounts of hydrogen peroxide with the - C4 carboxylic acid
being the largest constituent as described in the aforementioned patent application (see 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 Cλ to C4 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 ofthe 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.
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 section20 may include any oxidative process described above, known orunknown, 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 ofthe feed shifts the boiling point ofthe sulfur compounds
higher. This shift in the boiling point ofthe 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 ofthe 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 ofthe hydrotreaters 50 that accomplish the hydrodesulfurization to desired product qualities.
After hydrotreating, the light distillate 140 becomes a low sulfur gasoline 180. The low sulfiir 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 ofthe 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.
Figs.3 a and 3b depict selected, but not exhaustive examples of alternative embodiments for
realizing the advantages ofthe present invention. Figs.3 a 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.
In Fig.3 a, 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 ofthe existing crude unit to produce these
standard refinery streams according to the product mix ofthe 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 similarto 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 tht do not substantially react with olefins (i.e. no octane loss). The
oxidant described in U.S. Patent Application Serial 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
dieselfractioninline330. 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
inline330, 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 deteraiine the operating conditions which produce product streams ofthe desired
specifications.
Approximately 40% ofthe gasoline pool is made up of cracked naphthas produced in either
thermal or catalytic cracking units. More than 90% ofthe 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 ofthe desulfurized
cracked naphtha. It is a particular advantage ofthe present invention that this process to remove sulfur
from cracked naphtha irririimizes the hydrogenation ofthe 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
ofthe ranges mentioned above. These milder reactor conditions preserve the octane rating ofthe
cracked naphtha by not saturating the olefins present in the feed. The embodiment shown in Fig.3 a
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 ofthe 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.
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 crudeinto light distillate inconduit 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 ofthe 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 exitingthroughline 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 ofthe existing
process units are well within the skill in the art requiring little or no experimentation to produce product
streams ofthe desired specifications.
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 may be subsequently sent to a suitable hydrotreater for
hyαVodesulfurizationto remove substantially all sulfur from the stream and recover the hydrocarbon,
previously part ofthe 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.
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 ofthe low levels of sulfur,
approaching zero, that are obtainable through the combined practice ofthe 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.
The foregoing results are further demonstrated by the following examples, which are offered
for purposes of illustration ofthe practice of this invention and for the understanding; not for the
limitation thereof.
EXAMPLES
Unless otherwise stated, the following general experimental procedure applies to all ofthe
examples. The feed was a sulfur-containing liquid hydrocarbon containing oxidized organic sulfur
compounds.
EXAMPLE 1
An alumina supported Ni-Mo hydrosulfurization catalyst from Criterion Catalyst Company,
Houston, TX, in the form of 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 ofthe experiments.
The reactor tube had no internal structures. 30 cc of catalyst was loaded in the center ofthe reactor,
undiluted. The rest ofthe length ofthe 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.
The catalyst was presulfided at 350 ° C before the catalytic reaction. A 2 weight % solution of
acommercially available sulfiding agent TPS-37 inhexadecane, available from Atofina Chemicals,
Philadelphia, PA, was used for sulfidingthe catalyst. TPS-37 contains 37% sulfur by weight. The
catalyst was heated from room temperature to 350 ° 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 ofhydrogen gas was maintained through the reactor. The temperature ofthe reactor was held
at350°Cfor3 hours, and then thereactorwas cooled to roomtemperature. The sulfiding solution and
hydrogen flows were maintained until the temperature ofthe reactor reached about 200° C. Only
hydrogen flow was maintained afterwards.
A solution of dibenzothiophene sulfone (DBT suffone)containing a 250 ppm concentration of
sulfur in phenyl hexane solvent was prepared using a commercially available sample ofDBT 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
ofthe experiments and were analyzed using standard GC-MS analysis procedures. Results are shown
in Table 1.
Table 1
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% ofthe DBT sulfones are converted to the
corresponding thiophenes, thus sulfur is still present in the product. Therefore, the milder conditions
ofthe 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 °C and 250 psig pressure. The conditions depend on the purpose
and nature ofthe feed stream and demonstrate the flexibility ofthe 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
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 ofthe sulfur in like samples.
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 ofthe sulfiding solution was about 90 g/hr.
In order to stabilize the activity ofthe 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 °C, at a pressure of 400 psig, while hydrogen was flowing at 600 cc/min. At the end ofthe 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 °C when the diesel flow was cut off The hydrogen flow was continued
until the reactor was cooled down to about 100°C and the reactor was sealed off.
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 °C and 300°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.
Table 2
At the end ofthe run the reactor was cooled down to about 100°C in a similar way as
before and was sealed off.
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.
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
stabihzation, two product sample cuts were taken 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 and were analyzed for sulfur by X-ray fluorescence
(XRF). The results are presented in Table 3 below.
Table 3
Table 4 provides the comparison ofthe results from the hydrotreating experiments using
LAGO and oxidized 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.
Table 4
The foregoing description ofthe invention and the specific examples described demonstrate
the benefits ofthe hydrotreating of oxidized sulfur compounds. The above-described description is
offered for purposes of disclosing the advantages ofthe 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 ofthe claims appended hereto. Accordingly, such modification, variations
and adaptations ofthe above-described process and compositions are to be construed within the
scope ofthe claims which follow.