U.S. patent application number 17/076478 was filed with the patent office on 2021-02-11 for removal of olefins from hydrothermally upgraded heavy oil.
This patent application is currently assigned to Saudi Arabian Oil Company. The applicant listed for this patent is Saudi Arabian Oil Company. Invention is credited to Muneef F. AlQarzouh, Ki-Hyouk Choi.
Application Number | 20210040401 17/076478 |
Document ID | / |
Family ID | 1000005170164 |
Filed Date | 2021-02-11 |
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United States Patent
Application |
20210040401 |
Kind Code |
A1 |
Choi; Ki-Hyouk ; et
al. |
February 11, 2021 |
REMOVAL OF OLEFINS FROM HYDROTHERMALLY UPGRADED HEAVY OIL
Abstract
A method for sulfur removal and upgrading comprising the steps
of mixing a heated oil feed and a supercritical water feed in a
feed mixer, allowing conversion reactions to occur in the
supercritical water reactor, reducing the temperature in the
cooling device to produce a cooled fluid, reducing the pressure in
the depressurizing device to produce a discharged fluid, separating
the discharged fluid in the gas-liquid separator to produce a
liquid phase product, increasing the pressure to produce
pressurized liquid product, the pressure of pressurized liquid
product is greater than the critical pressure of water, processing
the pressurized liquid product in the hydration reactor to produce
a hydrated oil stream, separating the hydrated oil stream to
produce an extracted upgraded oil and an oxygenate concentrated
stream, the oxygenate concentrated stream comprises the oxygenates,
and processing the extracted upgraded oil in the hydrotreater to
produce a desulfurized upgraded oil.
Inventors: |
Choi; Ki-Hyouk; (Dhahran,
SA) ; AlQarzouh; Muneef F.; (Dhahran, SA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Saudi Arabian Oil Company |
Dhahran |
|
SA |
|
|
Assignee: |
Saudi Arabian Oil Company
Dhahran
SA
|
Family ID: |
1000005170164 |
Appl. No.: |
17/076478 |
Filed: |
October 21, 2020 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
15893961 |
Feb 12, 2018 |
10870805 |
|
|
17076478 |
|
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
C10G 67/04 20130101;
C10G 31/08 20130101; C10G 31/06 20130101; C10G 53/04 20130101; C10G
69/02 20130101; C10G 53/02 20130101; C10G 67/02 20130101; C10G
55/04 20130101; C10G 9/00 20130101; C10G 2300/202 20130101; C10G
69/06 20130101 |
International
Class: |
C10G 69/02 20060101
C10G069/02; C10G 9/00 20060101 C10G009/00; C10G 53/04 20060101
C10G053/04; C10G 67/04 20060101 C10G067/04; C10G 53/02 20060101
C10G053/02; C10G 69/06 20060101 C10G069/06; C10G 67/02 20060101
C10G067/02; C10G 31/06 20060101 C10G031/06; C10G 55/04 20060101
C10G055/04; C10G 31/08 20060101 C10G031/08 |
Claims
1. A method of sulfur removal and upgrading a feed oil, the method
comprising the steps of: introducing the feed oil and a water feed
to a supercritical water unit, wherein a ratio of the volumetric
flow rate of the feed oil to the water feed is such that there is a
greater amount of water than oil by volume as measured at standard
temperature and pressure (SATP); operating the supercritical water
unit to produce a gas phase product, a water product, and an
upgraded feed oil; introducing the upgraded feed oil to an olefin
converter, wherein the olefin converter operates at a temperature
less than 250 deg C. and a pressure of less than 10 MPa such that
olefins are in the vapor phase; processing the upgraded feed oil in
the olefin converter to produce a reduced olefin stream, wherein
the amount of olefins in the reduced olefin stream is reduced
relative to the amount of olefins in the upgraded feed oil;
introducing the reduced olefin stream to a hydrotreater unit,
wherein the hydrotreater unit comprises a hydrotreating catalyst,
wherein the hydrotreaters unit is at a temperature between 250 deg
C. and 450 deg C. and a pressure between 0.5 MPa and 25 MPa; and
processing the reduced olefin stream in the hydrotreater to produce
a desulfurized upgraded oil.
2. The method of claim 1, wherein the step of operating the
supercritical water unit to produce the gas phase product, the
water product, and the upgraded feed oil comprises the steps of:
increasing a pressure of the feed oil in an oil feed pump to
produce a pressurized oil feed; increasing a temperature of the
pressurized oil feed in an oil feed heater to produce a heated oil
feed; increasing a pressure of the water feed in a water pump to
produce a pressurized water stream; increasing a temperature of the
pressurized water stream in a water heater to produce supercritical
water feed; mixing a heated oil feed and a supercritical water feed
in a feed mixer to produce a mixed stream; introducing the mixed
stream to a supercritical water reactor; allowing conversion
reactions to occur in the supercritical water reactor to produce a
reactor effluent; introducing the reactor effluent to a cooling
device; reducing the temperature of the reactor effluent in the
cooling device to produce a cooled fluid; introducing the cooled
fluid to a depressurizing device; reducing the pressure of the
cooled fluid in the depressurizing device to produce a discharged
fluid; introducing the discharged fluid to a gas-liquid separator;
separating the discharged fluid in the gas-liquid separator to
produce a gas phase product and a liquid phase product; introducing
the liquid phase product to an oil-water separator; and separating
the liquid phase product in the oil-water separator to produce a
water product and an upgraded feed oil.
3. The method of claim 1, wherein the olefin converter can be
selected from the group consisting of a catalytic hydrogenation
unit and a catalytic alkylation unit.
4. The method of claim 1, wherein the olefin converter comprises an
olefin catalyst, wherein the olefin catalyst is selected from the
group consisting of a hydrogenation catalyst and an alkylation
catalyst.
5. The method of claim 1, further comprising the step of
introducing hydrogen gas to the olefin converter.
6. The method of claim 1, wherein the olefin converter is in the
absence of water.
7. The method of claim 1, wherein the hydrotreating catalyst
comprises a metal sulfide, the metal sulfide selected from the
group consisting of cobalt-molybdenum sulfides, nickel-molybdenum
sulfides, nickel tungsten sulfides, and combinations of the
same.
8. The method of claim 1, wherein the liquid hourly space velocity
in the hydrotreater unit is between 0.1 per hour and 5 per
hour.
9. The method of claim 1, wherein the feed oil is selected from the
group comprising petroleum, coal liquid, and biomaterials.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This patent application is a divisional of U.S.
Non-Provisional patent application Ser. No. 15/893,961 filed on
Feb. 12, 2018. For purposes of United States patent practice, the
non-provisional application is incorporated by reference in its
entirety.
TECHNICAL FIELD
[0002] Disclosed are methods for upgrading petroleum. Specifically,
disclosed are methods and systems for removal of olefins from a
supercritical water upgraded petroleum.
BACKGROUND
[0003] Crude oils contain sulfurs that must be removed in order to
meet environmental regulations. Supercritical water processes can
upgrade the crude oils, including removing an amount of sulfur.
However, further treatment of the supercritical water upgraded oil
to meet specifications and regulations is required. Further
treatment is required to reduce the concentration of sulfur. A
hydrotreater can be coupled to the supercritical water process to
treat the supercritical water upgraded oil stream as shown in FIG.
1.
[0004] A hydrotreater, using a catalyst and hydrogen, can be used
to remove heteroatoms, such as sulfur and nitrogen, from a
petroleum stream, ranging from light naphtha to heavy residue. Over
the catalyst, hydrogen is supplied to hydrocarbon molecules for
hydrogenation and hydrogenolysis, such as saturation,
hydrodesulfurization, hydrodenitrogenation, hydrodeoxygenation, and
hydrodemetallization. The hydrodesulfurization and
hydrodenitrogenation reactions produce hydrogen sulfide and
ammonia, respectively.
[0005] However, petroleum, including supercritical water upgraded
oil, contains poisons and inhibitors. One inhibitor is nitrogen
compounds that can strongly adsorb on the active sites where
hydrodesulfurization occurs and retard reaction progress. Aromatics
can also inhibit the functionality of the catalyst, although to a
lesser extent than the nitrogen compounds. Due to an abundance of
aromatics in feedstocks, aromatics can be regarded as "everlasting"
inhibitors for hydrotreating. In most petroleum feeds, the nitrogen
concentration is less than 0.1 wt % nitrogen, while the aromatic
concentration can be between 10 weight percent (wt %) and 90 wt %.
Hydrogen sulfide and ammonia can also be inhibitors. Finally,
olefins present in petroleum streams are inhibitors in
hydrotreating reactions. Olefins can compete against sulfur
compounds for active catalyst sites, such that olefins can be
adsorbed on the same active sites and sulfur compounds.
Additionally, hydrogenation of olefins occurring during
hydrotreatment can have a high exothermicity, which can increase
reactor temperature.
SUMMARY
[0006] Disclosed are methods for upgrading petroleum. Specifically,
disclosed are methods and systems for removal of olefins from a
supercritical water upgraded petroleum.
[0007] In a first aspect, a method for sulfur removal and
upgrading. The method includes the steps of mixing a heated oil
feed and a supercritical water feed in a feed mixer to produce a
mixed stream, introducing the mixed stream to a supercritical water
reactor, allowing conversion reactions to occur in the
supercritical water reactor to produce a reactor effluent,
introducing the reactor effluent to a cooling device, reducing the
temperature of the reactor effluent in the cooling device to
produce a cooled fluid, introducing the cooled fluid to a
depressurizing device, reducing the pressure of the cooled fluid in
the depressurizing device to produce a discharged fluid,
introducing the discharged fluid to a gas-liquid separator,
separating the discharged fluid in the gas-liquid separator to
produce a gas phase product and a liquid phase product, feeding the
liquid phase product to a pump, increasing the pressure of liquid
phase product to produce pressurized liquid product, where the
pressure of pressurized liquid product is greater than the critical
pressure of water, introducing the pressurized liquid product to a
hydration reactor, where the pressurized liquid product includes
water, processing the hydration reactor to produce a hydrated oil
stream, wherein the hydrated oil stream includes water and
oxygenates, introducing the hydrated oil stream to an extraction
unit, separating the hydrated oil stream to produce an extracted
upgraded oil and an oxygenate concentrated stream, where the
oxygenate concentrated stream includes the oxygenates and water,
feeding the extracted upgraded oil to a hydrotreater, and
processing the extracted upgraded oil in the hydrotreater to
produce a desulfurized upgraded oil.
[0008] In certain aspects, the hydration reactor includes a
hydration catalyst. In certain aspects, the hydration catalyst is
selected from the group consisting of a solid acid catalyst, a
heteropolyacid, a zeolite, a titanium dioxide, an alumina, and
combinations of the same. In certain aspects, the hydration reactor
is selected from a CSTR, a tubular reactor, a vessel-type reactor,
and combinations of the same. In certain aspects, the hydration
reactor is at a temperature between 300 deg C. and 374 deg C. In
certain aspects, the hydrated oil stream includes a decreased
amount of olefins relative to the pressurized liquid product. In
certain aspects, the desulfurized upgraded oil includes a decreased
amount of sulfur relative to the heated oil feed.
[0009] In a second aspect, a method for sulfur removal is provided.
The method includes the steps of introducing a mixed stream to a
supercritical water reactor, the mixed stream includes
supercritical water and hydrocarbons, allowing conversion reactions
to occur in the supercritical water reactor to produce a reactor
effluent, introducing the reactor effluent to a cooler, reducing
the temperature of the reactor effluent in the cooling device to
produce a cooled effluent, introducing the cooled effluent to a
hydration reactor, processing the cooled effluent in the hydration
reactor to produce a hydrated effluent, introducing the hydrated
effluent to a cooling device, reducing the temperature of the
hydrated effluent in the cooling device to produce a cooled treated
effluent, introducing the cooled treated effluent to a
depressurizing device, reducing the pressure the cooled treated
effluent in the depressurizing device to produce a depressurized
effluent, introducing the depressurized effluent to a gas-liquid
separator, separating the depressurized effluent in the gas-liquid
separator to produce a vapor product and a liquid product, feeding
the liquid product to an oil-water separator, separating the liquid
product in the oil-water separator to produce an upgraded oil and
an oxygenated water, wherein the oxygenated water includes
oxygenates, introducing the upgraded oil to a hydrotreater unit,
and processing the upgraded oil in the hydrotreater unit to produce
a desulfurized upgraded oil.
[0010] In certain aspects, the method further includes the steps of
introducing the oxygenated water to an oxygenates separator, and
separating the oxygenated water in the oxygenates separator to
produce a separated water and an oxygenates stream, where the
oxygenates stream includes a concentration of oxygenates. In
certain aspects, the method further includes the steps of mixing
the oxygenates stream and a water feed in a feed mixer to produce
an oxygenated water feed, where the oxygenated water feed includes
oxygenates, introducing oxygenated water feed to a water pump,
increasing the pressure of the oxygenated water feed to produce a
pressurized water stream, introducing the pressurized water stream
to a decomposition reactor, where the temperature in the
decomposition reactor is between 550 deg C. and 600 deg C.,
facilitating the decomposition of oxygenates in the pressurized
water stream to produce a heated water feed, wherein the
decomposition of oxygenates converts the oxygenates to non-olefinic
compounds, and mixing the heated water feed with a feed oil to
produce the mixed stream. In certain aspects, the residence time in
the decomposition reactor is at least 10 seconds. In certain
aspects, the concentration of oxygenates in oxygenates stream is at
least 10 wt %.
[0011] In a third aspect, a method of sulfur removal and upgrading
a feed oil is provided. The method includes the steps of
introducing the feed oil and a water feed to a supercritical water
unit, operating the supercritical water unit to produce a gas phase
product, a water product, and an upgraded feed oil. The method
further includes the steps of introducing the upgraded feed oil to
an olefin converter that operates at a temperature less than 250
deg C. and a pressure of less than 10 MPa such that olefins are in
the vapor phase, processing the upgraded feed oil in the olefin
converter to produce a reduced olefin stream, where the amount of
olefins in the reduced olefin stream is reduced relative to the
amount of olefins in the upgraded feed oil, introducing the reduced
olefin stream to a hydrotreater unit that includes a hydrotreating
catalyst, and processing the reduced olefin stream in the
hydrotreater to produce a desulfurized upgraded oil.
[0012] In certain aspects, the step of operating the supercritical
water unit to produce the gas phase product, the water product, and
the upgraded feed oil includes the steps of mixing a heated oil
feed and a supercritical water feed in a feed mixer to produce a
mixed stream, introducing the mixed stream to a supercritical water
reactor, allowing conversion reactions to occur in the
supercritical water reactor to produce a reactor effluent,
introducing the reactor effluent to a cooling device, reducing the
temperature of the reactor effluent in the cooling device to
produce a cooled fluid, introducing the cooled fluid to a
depressurizing device, reducing the pressure of the cooled fluid in
the depressurizing device to produce a discharged fluid,
introducing the discharged fluid to a gas-liquid separator,
separating the discharged fluid in the gas-liquid separator to
produce a gas phase product and a liquid phase product, introducing
the liquid phase product to an oil-water separator, and separating
the liquid phase product in the oil-water separator to produce a
water product and an upgraded feed oil. In certain aspects, the
olefin converter can be selected from the group consisting of a
catalytic hydrogenation unit and a catalytic alkylation unit. In
certain aspects, wherein the hydrotreating catalyst includes a
metal sulfide, the metal sulfide selected from the group consisting
of cobalt-molybdenum sulfides, nickel-molybdenum sulfides, nickel
tungsten sulfides, and combinations of the same. In certain
aspects, the feed oil is selected from the group includes
petroleum, coal liquid, and biomaterials.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] These and other features, aspects, and advantages of the
scope will become better understood with regard to the following
descriptions, claims, and accompanying drawings. It is to be noted,
however, that the drawings illustrate only several embodiments and
are therefore not to be considered limiting of the scope as it can
admit to other equally effective embodiments.
[0014] FIG. 1 provides a process diagram of a prior art
process.
[0015] FIG. 2 provides a process diagram of an embodiment of the
process.
[0016] FIG. 3 provides a process diagram of an embodiment of the
process.
[0017] FIG. 4 provides a process diagram of an embodiment of the
process.
[0018] FIG. 5 provides a process diagram of an embodiment of the
process.
[0019] FIG. 6 provides a process diagram of an embodiment of the
process.
[0020] In the accompanying Figures, similar components or features,
or both, may have a similar reference label.
DETAILED DESCRIPTION
[0021] While the scope of the apparatus and method will be
described with several embodiments, it is understood that one of
ordinary skill in the relevant art will appreciate that many
examples, variations and alterations to the apparatus and methods
described here are within the scope and spirit of the
embodiments.
[0022] Accordingly, the embodiments described are set forth without
any loss of generality, and without imposing limitations, on the
embodiments. Those of skill in the art understand that the scope
includes all possible combinations and uses of particular features
described in the specification.
[0023] Described here are processes and systems for sulfur removal.
Advantageously, the sulfur removal processes can convert olefins
from a supercritical water product to oxygenates utilizing the
water present in the supercritical water process. Oxygenates in the
supercritical water product can be extracted and mixed with the
feed water before being introduced to the supercritical water
reactor and converted to aromatics. Advantageously, the oxygenates
can be converted to aromatics in the supercritical water reactor
minimizing the loss of hydrocarbons. Advantageously, the sulfur
removal process combines a supercritical water unit, a method for
removing olefins, and a hydrotreater to produce an upgraded oil
product with a reduced sulfur content. Advantageously, the reduced
sulfur upgraded oil product can be used as a low sulfur marine fuel
and as a feedstock for steam cracker where light olefins, such as
ethylene, propylene, butenes, and combinations of the same, can be
produced.
[0024] Hydrocarbon reactions in supercritical water upgrade heavy
oil and crude oil containing sulfur compounds to produce products
that have increased light fractions. Supercritical water has unique
properties making it suitable for use as a petroleum reaction
medium where the reaction objectives can include conversion
reactions, desulfurization reactions denitrogenation reactions, and
demetallization reactions. Supercritical water is water at a
temperature at or greater than the critical temperature of water
and at a pressure at or greater than the critical pressure of
water. The critical temperature of water is 373.946.degree. C. The
critical pressure of water is 22.06 megapascals (MPa).
Advantageously, at supercritical conditions water acts as both a
hydrogen source and a solvent (diluent) in conversion reactions,
desulfurization reactions and demetallization reactions and a
catalyst is not needed. Hydrogen from the water molecules is
transferred to the hydrocarbons through direct transfer or through
indirect transfer, such as the water gas shift reaction.
[0025] Without being bound to a particular theory, it is understood
that the basic reaction mechanism of supercritical water mediated
petroleum processes is the same as a free radical reaction
mechanism. Radical reactions include initiation, propagation, and
termination steps. With hydrocarbons initiation is the most
difficult step. Initiation requires the breaking of chemical bonds.
Thermal energy creates radicals through chemical bond breakage.
Supercritical water creates a "cage effect" by surrounding the
radicals. The radicals surrounded by water molecules cannot react
easily with each other, and thus, intermolecular reactions that
contribute to coke formation are suppressed. The cage effect
suppresses coke formation by limiting inter-radical reactions.
Supercritical water, having low dielectric constant, dissolves
hydrocarbons and surrounds radicals to prevent the inter-radical
reaction, which is the termination reaction resulting in
condensation (dimerization or polymerization). Because of the
barrier set by the supercritical water cage, hydrocarbon radical
transfer is more difficult in supercritical water as compared to
compared to conventional thermal cracking processes, such as
delayed coker, where radicals travel freely without such
barriers.
[0026] Sulfur compounds released from sulfur-containing molecules
can be converted to H.sub.2S, mercaptans, and elemental sulfur.
Without being bound to a particular theory, it is believed that
hydrogen sulfide is not "stopped" by the supercritical water cage
due its small size and chemical structure similar to water
(H.sub.2O). Hydrogen sulfide can travel freely through the
supercritical water cage to propagate radicals and distribute
hydrogen. Hydrogen sulfide can lose its hydrogen due to hydrogen
abstraction reactions with hydrocarbon radicals. The resulting
hydrogen-sulfur (HS) radical is capable of abstracting hydrogen
from hydrocarbons which will result in formation of more radicals.
Thus, H.sub.2S in radical reactions acts as a transfer agent to
transfer radicals and abstract hydrogen.
[0027] As used throughout, "external supply of hydrogen" refers to
the addition of hydrogen to the feed to the reactor or to the
reactor itself. For example, a reactor in the absence of an
external supply of hydrogen means that the feed to the reactor and
the reactor are in the absence of added hydrogen, gas (H.sub.2) or
liquid, such that no hydrogen (in the form H.sub.2) is a feed or a
part of a feed to the reactor.
[0028] As used throughout, "external supply of catalyst" refers to
the addition of catalyst to the feed to the reactor or the presence
of a catalyst in the reactor, such as a fixed bed catalyst in the
reactor. For example, a reactor in the absence of an external
supply of catalyst means no catalyst has been added to the feed to
the reactor and the reactor does not contain a catalyst bed in the
reactor.
[0029] As used throughout, "external supply of oxygen gas" refers
to the addition of molecular oxygen gas to the feed to the reactor
or to the reactor itself. For example, a reactor in the absence of
an external supply of oxygen gas means that the feed to the reactor
and the reactor are in the absence of added oxygen, gas (O.sub.2)
or liquid, such that no oxygen (in the form O.sub.2) is a feed or a
part of a feed to the reactor.
[0030] As used throughout, "atmospheric residue" or "atmospheric
residue fraction" refers to the fraction of oil-containing streams
having an initial boiling point (IBP) of 650 deg F., such that all
of the hydrocarbons have boiling points greater than 650 deg F. and
includes the vacuum residue fraction. Atmospheric residue can refer
to the composition of an entire stream, such as when the feedstock
is from an atmospheric distillation unit, or can refer to a
fraction of a stream, such as when a whole range crude is used.
[0031] As used throughout, "vacuum residue" or "vacuum residue
fraction" refers to the fraction of oil-containing streams having
an IBP of 1050 deg F. Vacuum residue can refer to the composition
of an entire stream, such as when the feedstock is from a vacuum
distillation unit or can refer to a fraction of stream, such as
when a whole range crude is used.
[0032] As used throughout, "asphaltene" refers to the fraction of
an oil-containing stream which is not soluble in a n-alkane,
particularly, n-heptane.
[0033] As used throughout, "heavy fraction" refers to the fraction
in the petroleum feed having a true boiling point (TBP) 10% that is
equal to or greater than 650 deg F. (343 deg C.), and alternately
equal to or greater than 1050 deg F. (566 deg C.). Examples of a
heavy fraction can include the atmospheric residue fraction or
vacuum residue fraction. The heavy fraction can include components
from the petroleum feed that were not converted in the
supercritical water reactor. The heavy fraction can also include
hydrocarbons that were dimerized or oligomerized in the
supercritical water reactor due to either lack of hydrogenation or
resistance to thermal cracking.
[0034] As used throughout, "light fraction" refers to the fraction
in the petroleum feed that is not considered the heavy fraction.
For example, when the heavy fraction refers to the fraction having
a TBP 10% that is equal to or greater than 650 deg F. the light
fraction has a TBP 90% that is less than 650 deg F. For example,
when the heavy fraction refers to the fraction having a TBP 10%
equal to or greater than 1050 deg F. the light fraction has a TBP
90% that is less than 1050 deg F.
[0035] As used throughout, "light naphtha" refers to the fraction
in the petroleum feed having a boiling point less 240 deg C.
[0036] As used throughout, "distillate" refers to the hydrocarbon
fraction lighter than the distillation residue from an atmospheric
distillation process or a vacuum distillation process.
[0037] As used throughout, "coke" refers to the toluene insoluble
material present in petroleum.
[0038] As used throughout, "cracking" refers to the breaking of
hydrocarbons into smaller ones containing fewer carbon atoms due to
the breaking of carbon-carbon bonds.
[0039] As used throughout, "upgrade" means one or all of increasing
API gravity, decreasing the amount of impurities, such as sulfur,
nitrogen, and metals, decreasing the amount of asphaltene, and
increasing the amount of distillate in a process outlet stream
relative to the process feed stream. One of skill in the art
understands that upgrade can have a relative meaning such that a
stream can be upgraded in comparison to another stream, but can
still contain undesirable components such as impurities.
[0040] As used throughout, "conversion reactions" refers to
reactions that can upgrade a hydrocarbon stream including cracking,
isomerization, alkylation, dimerization, aromatization,
cyclization, desulfurization, denitrogenation, deasphalting, and
demetallization.
[0041] As used throughout, "poison" means compounds that reduce
catalyst activity permanently.
[0042] As used throughout, "inhibitor" refers to compounds that
reduce catalyst activity temporally.
[0043] As used throughout "oxygenate" refers to hydrocarbons
containing oxygen such as alcohols and aldehydes.
[0044] The following embodiments, provided with reference to the
figures, describe the upgrading process.
[0045] Referring to FIG. 2, a general process flow diagram of a
sulfur removal upgrading process is described.
[0046] Feed oil 5 and water feed 2 can be introduced to
supercritical water unit 100. Feed oil 5 can be any crude oil
source derived from petroleum, coal liquid, biomaterials, and
gas-to-liquid (GTL) products. Examples of feed oil 5 can include
whole range crude oil, reduced crude oil, atmospheric distillates,
atmospheric residue, vacuum distillates, vacuum residue, refinery
streams, produced oil, hydrocarbon streams from upstream
operations, decanted oil, streams containing C10+ oil from an
ethylene plant, liquefied coal, and biomass derived hydrocarbons,
such as bio fuel oil. In at least one embodiment, feed oil 5 can
include a whole range crude oil and a distillation residue from
crude oil. The whole range crude oil can be any crude oil having an
API gravity between 22 and 50 and alternately between 24 and 40 and
a total sulfur content between 0.05 wt % and 4 wt % sulfur. An
example of a whole range crude oil having an API gravity of 24 and
a 3.6 wt % sulfur content is Manifa Crude Oil. An example of a
whole range crude oil having an API gravity of 40 and a total
sulfur content of 1.0 wt % is Arab Extra Light. The distillation
residue from crude oil can be any residue stream from crude oil
having an API gravity in the range between -1 and 22 and
alternately between 2.5 and 20.5. The total sulfur content of the
distillation residue from crude oil can be between 1.5 wt % and 7.5
wt % and alternately between 2.1 wt % and 6.5 wt %. An example of a
distillation residue from a crude oil is a vacuum residue of a
Manifa Crude Oil having an API gravity of 2.5 and 6.5 wt %. An
example of a distillation residue from a crude oil is an
atmospheric residue of an Arab Extra Light having an API gravity of
20.5 and 2.1 wt %. "Reduced crude oil" can also be known as "topped
crude oil" and refers to a crude oil having no light fraction, and
would include an atmospheric residue stream or a vacuum residue
stream. "Refinery streams" can include "cracked oil," such as light
cycle oil, heavy cycle oil, and streams from a fluid catalytic
cracking unit (FCC), such as slurry oil or decant oil, a heavy
stream from hydrocracker with a boiling point greater than 650 deg
F., a deasphalted oil (DAO) stream from a solvent extraction
process, and a mixture of atmospheric residue and hydrocracker
bottom fractions. In at least one embodiment, feed oil 5 is in the
absence of olefins.
[0047] Water feed 2 can be any demineralized water having a
conductivity less than 1.0 microSiemens per centimeter (.mu.S/cm),
alternately less 0.5 .mu.S/cm, and alternately less than 0.1
.mu.S/cm. In at least one embodiment, water feed 2 is demineralized
water having a conductivity less than 0.1 .mu.S/cm.
[0048] Water feed 2 and feed oil 5 can be processed in
supercritical water unit 100 to produce upgraded feed oil 10.
Supercritical water unit 100 can be described with reference to
FIG. 3 and reference to FIG. 2.
[0049] Feed oil 5 can be passed to oil feed pump 106. Oil feed pump
106 can be any type of pump capable of increasing the pressure of
feed oil 5. In at least one embodiment, oil feed pump 106 is a
diaphragm metering pump. The pressure of feed oil 5 can be
increased in oil feed pump 106 to produce pressurized oil feed 116.
The pressure of pressurized oil feed 116 can be greater than the
critical pressure of water, alternately between 23 MPa and 35 MPa,
and alternately between 24 MPa and 30 MPa. Pressurized oil feed 116
can be introduced to oil feed heater 108.
[0050] Oil feed heater 108 can be any type of heat exchanger
capable increasing the temperature of pressurized oil feed 116.
Examples of heat exchangers capable of being used as oil feed
heater 108 can include an electric heater, a fired heater, and a
cross exchanger. In at least one embodiment, oil feed heater 108
can be cross exchanged with reactor effluent 125. The temperature
of pressurized oil feed 116 can be increased in oil feed heater 108
to produce heated oil feed 118. The temperature of heated oil feed
118 can be less than the critical temperature of water and
alternately less than 250 deg C. Maintaining the temperature of
heated oil feed 118 at less than 300 deg C. reduces the formation
of coke in heated oil feed 118 and in supercritical water reactor
120.
[0051] Water feed 2 can be introduced to water pump 102. Water pump
102 can be any type of pump capable of increasing the pressure of
water feed 2. In at least one embodiment, water pump 102 is a
diaphragm metering pump. The pressure of water feed 2 can be
increased in water pump 102 to a pressure greater than the critical
pressure of water, alternately to a pressure between 23 MPa and 35
MPa, and alternately between 24 MPa and 30 MPa, to produce
pressurized water stream 112. Pressurized water stream 112 can be
passed to water heater 104.
[0052] Water heater 104 can be any type of heat exchanger capable
of increasing the temperature of pressurized water stream 112.
Examples of heat exchangers that can be used as water heater 104
can include an electric heater and a fired heater. The temperature
of pressurized water stream 112 can be increased in water heater
104 to produce supercritical water feed 114. The temperature of
supercritical water feed 114 can be equal to or greater than the
critical temperature of water, alternately greater than 380 deg C.,
alternately between 374 deg C. and 600 deg C., and alternately
between 380 deg C. and 550 deg C.
[0053] Heated oil feed 118 and supercritical water feed 114 can be
passed to feed mixer 110. Feed mixer 110 can be any type of mixing
device capable of mixing a petroleum stream and a supercritical
water stream. Examples of mixing devices suitable for use as feed
mixer 110 can include a simple tee, ultrasonic device, static
mixer, an inline mixer, and impeller-embedded mixer. The ratio of
the volumetric flow rate of heated oil feed 118 to supercritical
water feed 114 can be between 1:10 and 10:1 at standard temperature
and pressure (SATP), alternately between 1:5 and 5:1 at SATP, and
alternately between 1:1 and 1:3. In at least one embodiment, the
ratio of the volumetric flow rate of heated oil feed 118 to
supercritical water feed 114 is such that there is a greater amount
of water than oil by volume at SATP. Heated oil feed 118 and
supercritical water feed 114 can be mixed to produce mixed stream
115. The pressure of mixed stream 115 can be greater than the
critical pressure of water. The temperature of mixed stream 115 can
depend on the temperatures of supercritical water feed 114 and
heated oil feed 118. In at least one embodiment, controlling the
temperature of supercritical water feed 114 controls the
temperature of mixed stream 115. The temperature of mixed stream
115 can be maintained at equal to or less than the desired reaction
temperature in supercritical water reactor 120. In at least one
embodiment, mixed stream 115 is less than the temperature in
supercritical water reactor 120 to avoid shocking the hydrocarbons
in heated oil feed 118 when heated oil feed 118 is mixed with
supercritical water feed 114. Mixed stream 115 can be introduced to
supercritical water reactor 120.
[0054] Supercritical water reactor 120 can include one or more
reactors in series. Supercritical water reactor 120 can be any type
of reactor capable of allowing conversion reactions. Examples of
reactors suitable for use in supercritical water reactor 120 can
include tubular-type vertical reactor, tubular type horizontal
reactor, vessel-type reactor, CSTR-type, and combinations of the
same. In at least one embodiment, supercritical water reactor 120
includes a tubular-type vertical reactor, which advantageously
prevents precipitation of reactants and products. Supercritical
water reactor 120 can include an upflow reactor, a downflow
reactor, and a combination of an upflow reactor and downflow
reactor. In at least one embodiment, supercritical water reactor
120 is in the absence of an external supply of catalyst. In at
least one embodiment, supercritical water reactor 120 is in the
absence of an external supply of hydrogen.
[0055] The temperature in supercritical water reactor 120 can be
maintained in the range between the critical temperature of water
and 450 deg C., alternately in the range between 380 deg C. and 450
deg C., alternately in the range between 400 deg C. and 450 deg C.,
and alternately in the range between 390 deg C. and 450 deg C. The
temperature in supercritical water reactor 120 is maintained in the
range of between the critical temperature of water and 450 deg C.
to suppress the formation of coke in supercritical water reactor
120, which can occur at temperatures greater than 450 deg C. The
pressure in supercritical water reactor 120 can be maintained at a
pressure greater than the critical pressure of water, alternately
in the range between 23 MPa and 35 MPa, and alternately between 24
MPa and 30 MPa. The residence time of the reactants in
supercritical water reactor 120 can between greater than 5 seconds,
and alternately greater than 1 minute. The residence time is
calculated by assuming that the density of the reactants in
supercritical water reactor 120 is the same as the density of water
at the operating conditions of supercritical water reactor 120.
[0056] The reactants in supercritical water reactor 120 can undergo
conversion reactions to produce reactor effluent 125. Reactor
effluent 125 can be introduced to cooling device 130.
[0057] Cooling device 130 can be any type of heat exchange device
capable of reducing the temperature of reactor effluent 125.
Examples of cooling device 130 can include double pipe type
exchanger and shell-and-tube type exchanger. In at least one
embodiment, cooling device 130 can be a cross exchanger with
pressurized oil feed 116. The temperature of reactor effluent 125
can be reduced in cooling device 130 to produce cooled fluid 135.
The temperature of cooled fluid 135 can be between 10 deg C. and
200 deg C. and alternately between 30 deg C. and 150 deg C. Cooled
fluid 135 can be introduced to depressurizing device 140.
[0058] Depressurizing device 140 can be any type of device capable
of reducing the pressure of a fluid stream. Examples of
depressurizing device 140 can include a pressure let-down valve, a
pressure control valve, and a back pressure regulator. The pressure
of cooled fluid 135 can be reduced to produce discharged fluid 145.
The pressure of discharged fluid 145 can be less than the critical
pressure of water, alternately less than 2 MPa, and alternately 0.2
MPa.
[0059] Discharged fluid 145 can be introduced to gas-liquid
separator 150. Gas-liquid separator 150 can be any type of
separation device capable of separating a fluid stream into gas
phase and liquid phase. The temperature of gas-liquid separator 150
can be maintained at a temperature between 10 deg C. and 150 deg C.
The pressure in gas-liquid separator 150 can be between ambient
pressure and 0.2 MPa. Discharged fluid 145 can be separated to
produce gas phase product 13 and liquid phase product 155. Liquid
phase product 155 can be introduced to oil-water separator 160.
[0060] Oil-water separator 160 can be any type of separation device
capable of separating a fluid stream into a hydrocarbon containing
stream and a water stream. Oil-water separator 160 can include a
settling chamber, an API separator, and a combination of a settling
chamber and an API separator. Liquid phase product 155 can be
separated in oil-water separator 160 to produce upgraded feed oil
10 and water product 15. The conditions in oil-water separator 160
can be designed to minimize the amount of water in upgraded feed
oil 10. Oil-water separator 16 can contain less than 0.3 wt %
water. Upgraded feed oil 10 contains upgraded hydrocarbons relative
to feed oil 5.
[0061] Returning to FIG. 2, upgraded feed oil 10 can be introduced
to olefin converter 200 along with hydrogen gas 22. Hydrogen gas 22
can include molecular hydrogen.
[0062] Olefin converter 200 can be any type of unit capable of
converting olefins in the presence of an external supply of
hydrogen. Examples of olefin converter 200 include a catalytic
hydrogenation unit and a catalytic alkylation unit. Olefin
converter 200 can operate in the absence of water. Olefin converter
200 can include an olefin catalyst. The olefin catalyst can be
selected from a hydrogenation catalyst and an alkylation catalyst.
The hydrogenation catalyst can convert olefins by saturating the
olefins to form alkanes. The hydrogenation catalyst can include
precious metals, such as palladium supported on activated carbon.
However, precious metal catalysts, such as platinum and palladium,
can be permanently poisoned by the presence of sulfur. The
alkylation catalyst can be any type of catalyst capable of
consuming olefin to form alkylated aromatics. Examples of the
alkylation catalyst can include solid acid catalyst and
zeolite-based catalyst. Upgraded feed oil 10 can be processed in
olefin converter 200 to produce reduced olefin stream 20.
Minimizing the amount of water in upgraded feed oil 10 improves
performance in olefin converter 200 when the olefin catalyst is a
hydrogenation catalyst, because water can poison a hydrogenation
catalyst. In embodiments where olefin converter 200 is a catalytic
hydrogenation unit containing a hydrogenation catalyst, olefin
converter 200 can be operated a temperature less than 250 deg C.
and alternately less than 200 deg C. and a pressure of less than 10
MPa, such that the naphtha-range fraction with a boiling point less
than 220 deg C. is in the vapor phase. Olefin saturation occurs in
the vapor phase while many of the sulfur compounds stay in the
liquid phase. Olefin saturation is an exothermic reaction, which
can increase the temperature in olefin converter 200. Olefin
converter 200 is in the absence of water. Reduced olefin stream 20
can be introduced to hydrotreater unit 300.
[0063] Advantageously, olefin converter 200 removes olefins from
upgraded feed oil 10 and reduces the amount of olefins in reduced
olefin stream 20 relative to upgraded feed oil 10. In at least one
embodiment, the amount of olefins in upgraded feed oil 10 can be
reduced by at least 80 wt % in reduced olefin stream 20. Having a
reduced amount of olefins means that reduced olefin stream 20 can
exhibit less inhibition of the hydrotreating catalyst in
hydrotreater unit 300 as compared to upgraded feed oil 10 and feed
oil 5. Removing olefins upstream of hydrotreater unit 300 can
reduce the opportunity for olefins to recombine with hydrogen
sulfide to produce thiols and thiophenes.
[0064] Reduced olefin stream 20 can be processed in hydrotreater
unit 300 to produce desulfurized upgraded oil 30. Hydrotreater unit
300 can be any type of processing unit capable of removing sulfur
from a hydrocarbon stream. In at least one embodiment, upgrading
reactions can occur in hydrotreater unit 300 in addition to
desulfurization reactions. Hydrotreater unit 300 can include
hydrotreating catalyst.
[0065] The hydrotreating catalyst can be selected based on the
feedstock type, such as light or heavy, and the desired
specifications of the product. For example, a hydrotreating
catalyst for a heavy residue has an increased pore size and reduced
surface area, due to the increased pore size, than a hydrotreating
catalyst for a light distillate, such as naphtha, kerosene and gas
oil. The increased pore size accommodates the larger molecules in
the heavy residue. The hydrotreating catalyst can include metal
sulfides and a support. Examples of metal sulfides can include
cobalt-molybdenum sulfides (CoMoS), nickel-molybdenum sulfides
(NiMoS), nickel-tungsten sulfides (NiWS), and combinations of the
same. Examples of supports can include alumina based supports. The
alumina based supports can include alumina, silica, and zeolites.
The hydrotreating catalyst can include promoters, such as boron and
phosphorous. In at least one embodiment, a hydrodemetallization
(HDM) catalyst can be added as a first layer in hydrotreater unit
300 or can be employed in a separate reactor as part of
hydrotreater unit 300. The temperature in hydrotreater unit 300 can
be in the range between 250 deg C. and 450 deg C. The pressure in
hydrotreater unit 300 can be in the range between 0.5 MPa and 25
MPa. The liquid hourly space velocity (LHSV) can be in the range
between 0.1 per hour (hr.sup.-1) and 5 hr.sup.-1.
[0066] Desulfurized upgraded oil 30 can be further treated.
Desulfurized upgraded oil 30 can be treated to separate gases, such
as hydrogen, hydrogen sulfide, and gaseous hydrocarbons from the
liquid hydrocarbons. Additional treatment steps can include
separation, cooling, pressure reduction and combinations of the
same. The liquid hydrocarbons in desulfurized upgraded oil 30 have
reduced amounts of sulfur, reduced amounts of nitrogen, increased
API, and greater amounts of distillate relative to feed oil 5.
[0067] An embodiment of the sulfur removal upgrading process is
described with reference to FIG. 4 and FIGS. 2 and 3. Liquid phase
product 155 can be introduced to pump 170. Pump 170 can increase
the pressure of liquid phase product 155 to produce pressurized
liquid product 570. The pressure of pressurized liquid product 570
can be greater than the critical pressure of water and alternately
between 23 MPa and 25 Mpa. Pressurized liquid product 570 can be
introduced to hydration reactor 250.
[0068] Hydration reactor 250 can be any process unit capable of
hydrating olefins with water. Examples of hydration reactor 250 can
include catalytic hydration unit and non-catalytic near critical
water (NCW) hydration unit. In at least one embodiment, hydration
reactor 250 is a NCW hydration unit. The reactor in hydration
reactor 250 can be any reactor capable of allowing a hydration
reaction to occur. Examples of the reactor in hydration reactor 250
can include a CSTR, a tubular reactor, a vessel-type reactor, and
combinations of the same. The temperature in hydration reactor 250
can be between 300 deg C. and 374 deg C. and alternately 350 deg C.
and 370 deg C. The pressure in hydration reactor 250 can be greater
than the critical pressure of water and alternately between 23 MPa
and 25 MPa. The residence time in hydration reactor 250 can be
between 1 minute and 120 minutes and alternately between 30 minutes
and 60 minutes. Advantageously, near-critical water has a greater
ion dissociation constant (Kw) than liquid water. The Kw of
near-critical water is 11, whereas the Kw for water at room
temperature is about 14 and the Kw for supercritical water is about
20. The greater Kw of near-critical water results in abundant
hydrogen ions (H+) and hydroxide ions (OH-) for use in the
hydration reactions.
[0069] Hydration reactor 250 can include a hydration catalyst. The
hydration catalyst can be any type of catalyst stable at the
operating conditions in hydration reactor 250 and capable of
hydrating olefins to form oxygenates. The hydration catalyst can
include a solid acid catalyst, a heteropolyacid (HPA), a zeolite,
titanium dioxide, alumina, and combinations of the same. The
hydration catalyst does not include a homogeneous catalyst, such as
nitric acid and sulfuric acid, because homogeneous catalysts
require complicated handling and separation processes.
[0070] Hydration reactor 250 can include hydrating reactions in the
presence of oxygen. The water in pressurized liquid product 570 can
serve as the oxygen source. In at least one embodiment, hydration
reactor 250 is in the absence of an external supply of oxygen gas.
In at least one embodiment, hydration reactor 250 is in the absence
of an external water supply.
[0071] Advantageously, positioning the hydration reactor 250 before
separation of liquid phase product 155 into an oil stream and a
water stream provides the water necessary for hydration reaction
250 and additional water is not provided to hydration reactor
250.
[0072] Hydration reactor 250 can allow hydration reactions to occur
to produce hydrated oil stream 25. Hydrated oil stream 25 contains
upgraded oil, water, oxygenates, and combinations of the same.
Hydrated oil stream 25 can be introduced to extraction unit
400.
[0073] Extraction unit 400 can be any type of unit capable of
separating the oxygenates in hydrated oil stream 25 from the
upgraded oil to produce extracted upgraded oil 40 and oxygenate
concentrated stream 45. Oxygenate concentrated stream 45 contains
an amount of the water and an amount of the oxygenates present in
hydrated oil stream 25. Oxygenate concentrated stream 45 contains
greater than 99.7 wt % water. Examples of extraction unit 400 can
include a vessel containing a settling chamber, an API separator,
and combinations of the same. Extraction unit 400 can use the water
present in hydrated oil stream 25 as an extracting solvent.
[0074] Extracted upgraded oil 40 can be introduced to hydrotreater
unit 300 to produce desulfurized upgraded oil 30 as described with
reference to FIG. 2.
[0075] An embodiment of the sulfur removal upgrading process can be
described with reference to FIG. 5 and FIGS. 2-4. Reactor effluent
125 can be introduced to cooler 630. Cooler 630 can be any heat
exchanger capable of reducing the temperature of reactor effluent
125 to produce cooled effluent 635. Examples of cooler 630 can
include a double pipe type exchanger and shell-and-tube type
exchanger. The temperature of reactor effluent 125 can be reduced
in cooler 630. The temperature of cooled effluent 635 can be
between 300 deg C. and 374 deg C. and alternately between 350 deg
C. and 370 deg C. Cooled effluent 630 can be introduced to
hydration reactor 250.
[0076] Cooled effluent 635 can be hydrated in hydration reactor 250
to produce hydrated effluent 640. Hydrated effluent 640 can be
introduced to cooling device 135.
[0077] Cooling device 135 can reduce the temperature of hydrated
effluent 640 to produce cooled treated effluent 645. Cooled treated
effluent 645 can be at a temperature between 10 deg C. and 200 deg
C. and alternately between 30 deg C. and 150 deg C. Cooled treated
effluent 645 can be introduced to depressurizing device 140.
[0078] The pressure of cooled treated effluent 645 can be reduced
to produce depressurized effluent 650. Depressurized effluent 650
can be at a pressure less than the critical pressure of water,
alternately less than 2 MPa, and alternately 0.2 MPa. Depressurized
effluent 650 can be introduced to gas-liquid separator 150.
[0079] Gas-liquid separator 150 can separate depressurized effluent
650 into vapor product 613 and liquid product 655. Vapor product
613 can contain reduced amounts of light olefins, such as ethylene
and propylene, compared to a gas product downstream of conventional
supercritical water process because olefins are hydrated to
alcohols. Vapor product 613 can contain an amount of light
alcohols, such as ethanol. Liquid product 655 can be introduced to
oil-water separator 160.
[0080] Oil-water separator 160 can separate liquid product 655 into
upgraded oil 610 and oxygenated water 615. Oxygenated water 615 can
contain oxygenates, water, and combinations of the same. In at
least one embodiment, oxygenated water 615 contains alcohols,
aldehydes, oxygenates, and combinations of the same. The amount of
oxygen in oxygenated water 615 can be in the range between 0.1 wt %
and 5 wt %. Upgraded oil 610 can be introduced to hydrotreater unit
300.
[0081] Advantageously, the sulfur removal upgrading process
described with reference to FIG. 5 shows that the heat and pressure
in the supercritical water reactor can be used in the hydration
reactor resulting in a process with increased efficiency.
[0082] An embodiment of the sulfur removal upgrading process can be
described with reference to FIG. 6 and FIGS. 2-5. Oxygenated water
615 is introduced to oxygenates separator 700. Oxygenates separator
700 can be any type of separator capable of separating a fluid into
two fluid streams. In at least one embodiment, oxygenates separator
700 is a distillation unit. Oxygenates separator 700 can separate
oxygenated water 615 into separated water 715 and oxygenates stream
705.
[0083] Oxygenates stream 705 can contain water, an amount of the
oxygenates present in oxygenated water 615, and combinations of the
same. The oxygenates concentration present in oxygenates stream 705
is at least 10 wt % and alternately between 10 wt % and 40 wt %.
Oxygenates separator 700 can be an extractor. The oxygenates
concentration in oxygenates stream 705 can be at least 10 wt % to
reject non-hydrocarbon impurities such as minerals, alkali
chloride, and solid particles, into the water of separated water
715. Separated water 715 can contain non-hydrocarbon impurities,
water, and combinations of the same.
[0084] Oxygenates stream 705 can be mixed with water feed 2 in feed
mixer 750 to produced oxygenated water feed 702. Feed mixer 750 can
be any type of mixing unit capable of mixing two fluid streams
together. Oxygenated water feed 702 can be introduced to water pump
102. The pressure of oxygenated water feed 702 can be increased in
water pump 102 to produce pressurized oxygenated stream 712. The
pressure of pressurized oxygenated stream 712 can be greater than
the critical pressure of water, alternately to a pressure between
23 MPa and 35 MPa, and alternately between 24 MPa and 30 MPa.
Pressurized oxygenated stream 712 can be introduced to
decomposition reactor 704.
[0085] Decomposition reactor 704 can be any type of reactor capable
of increasing the temperature of pressurized oxygenated stream 712
and facilitating the decomposition of oxygenates present in
pressurized oxygenated stream 712 to produce hot oxygenated water
714. Examples of decomposition reactor 704 can include coiled tube
reactor and straight tubular reactor. Decomposition reactor 704 can
operate at a temperature between 550 deg C. and 600 deg C. At the
temperatures in decomposition reactor 704, oxygenates can be
dehydrated to olefins, which are then converted to non-olefinic
compounds. The pressure in decomposition reactor 704 can be
controlled by the outlet pressure of water pump 102 and
depressurizing device 140. Non-olefinic compounds can include
aromatics, paraffins, and combinations of the same. At the
temperatures in supercritical water reactor 120 aromatic formation
from oxygenates does not occur. Water heater 104 is operated at 550
deg C. and 600 deg C. to decompose the oxygenates and increase
aromatization. The residence time in decomposition reactor 704 can
have a residence time of at least 10 seconds.
EXAMPLES
[0086] Examples. The Example was conducted by a lab scale unit with
a system as shown in FIG. 6 with reference to FIG. 3. Feed oil 5
was a whole range Arabian Heavy crude oil. Water feed 2 was a
demineralized water having a conductivity of 0.55 .mu.S/cm.
[0087] Feed oil 5 was pumped at a rate of 0.3 liters per hour
(L/hour) in oil feed pump 106, a diaphragm pump. The temperature of
pressurized oil feed 116 was increased in oil feed heater 108 to
produce heated oil feed 118 at a temperature of 60 deg C. Oil feed
heater 108 was an electric heater.
[0088] Water feed 2 was pumped at a rate of 1.2 L/hour in water
pump 102, a diaphragm pump. The temperature of pressurized water
stream 112 was increased in water heater 104 to produce
supercritical water feed 114 at a temperature of 590 deg C. Water
heater 104 was an electric heater.
[0089] The pressure of the sulfur removal process was regulated at
3,901 pounds per square inch (psig) (26.9 mega pascals (MPa)) by
depressurizing device 140, a back pressure regulator.
[0090] The ratio of the volumetric flow rate of oil to the
volumetric flow rate of water was 0.25 to 1 at SATP. The streams
were mixed in feed mixer 110 and mixed stream 115 was introduced to
supercritical water reactor 120.
[0091] Supercritical water reactor 120 was three tubular reactors
arranged in series, each having an internal volume of 160
milliliter (ml). The flow direction in each reactor was downflow.
The temperature in supercritical water reactor 120 was 420 deg C.,
measured by thermocouples at the end of each reactor, such that the
internal fluid temperature was measured by thermocouple located at
the end of each reactor. And each reactor was maintained at the
same temperature. Residence time of mixed stream 115 in
supercritical water reactor 120 was 3 minutes (0.0497 hours). The
residence time was calculated by assuming the density of water at
420 deg C. and 3,901 psig was 0.15547 grams per milliliter (g/ml)
and the total flow rate of water at 420 deg C. and 3,901 psig was
9.65 L/hour, and where the feed oil was assumed to have the same
density of water at the reaction conditions.
[0092] The temperature of reactor effluent 125 was reduced in
cooling device 130 to a temperature of 360 deg C. Cooled fluid 135
was introduced to hydration reactor 250.
[0093] Hydration reactor 250 was a CSTR with a catalyst basket
attached to the agitator and an internal volume of 1,000 ml. The
reaction temperature was 360 deg C. The hydration catalyst in the
catalyst basket was a pellet-type ZSM-5 having a 3 to 5 millimeter
(mm) size. The catalyst basket had a volume of 250 ml. The agitator
speed was 600 revolutions per minute (rpm). The residence time was
24 minutes (assuming the density was the density of water at 360
deg C. and 3,901 psig, 0.600 g/ml, and the total flow rate was 2.5
L/hour). The temperature of hydrated oil stream 25 was reduced in
cooling device 130 to a temperature of 63 deg C. The pressure of
cooled treated effluent 645 was reduced in depressurizing device
140 to ambient pressure. Depressurized effluent 650 was separated
in gas-liquid separator 150 to produce vapor product 613 and liquid
product 655. Gas-liquid separator 150 was a 500 ml cylinder. Liquid
product 655 was separated into upgraded oil 610 and oxygenated
water 615. The organic compounds in the oxygenated water were
extracted using n-hexane and analyzed.
[0094] In a comparative test run, reactor effluent 125 was cooled
to 65 deg C., depressurized to ambient pressure and then separated
into gas, oil, and water streams. The oil streams were
analyzed.
[0095] The results of each run are in Table 1.
TABLE-US-00001 TABLE 1 Composition of Streams from the Example.
Sulfur Removal Feed Oil Comparative Run Process API Gravity 26.7
32.2 31.7 Sulfur Content 2.9 2.4 2.4 (wt %) Olefin Content 0 1.36
0.27 (vol %) Oxygenate 0 0 1.23 Content (wt %)
[0096] The oxygenate content was measured in oxygenated water 615.
The oxygenates in the oxygenated water were primarily mono alcohol,
ranging from C5 to C15. In the comparative run, without the
hydration step, 1.36 wt % of olefins would enter a hydrotreating
unit. In contrast, in the sulfur removal process with a hydration
step, following separation of oxygenated water 615, the amount of
olefins in upgraded oil 610 is less than 0.27 wt %. Advantageously,
the reduced amounts of olefins in upgraded oil 610 can be
beneficial in further treatment processes.
[0097] Although the present invention has been described in detail,
it should be understood that various changes, substitutions, and
alterations can be made hereupon without departing from the
principle and scope of the invention. Accordingly, the scope of the
present invention should be determined by the following claims and
their appropriate legal equivalents.
[0098] There various elements described can be used in combination
with all other elements described here unless otherwise
indicated.
[0099] The singular forms "a", "an" and "the" include plural
referents, unless the context clearly dictates otherwise.
[0100] Optional or optionally means that the subsequently described
event or circumstances may or may not occur. The description
includes instances where the event or circumstance occurs and
instances where it does not occur.
[0101] Ranges may be expressed here as from about one particular
value to about another particular value and are inclusive unless
otherwise indicated. When such a range is expressed, it is to be
understood that another embodiment is from the one particular value
to the other particular value, along with all combinations within
said range.
[0102] Throughout this application, where patents or publications
are referenced, the disclosures of these references in their
entireties are intended to be incorporated by reference into this
application, in order to more fully describe the state of the art
to which the invention pertains, except when these references
contradict the statements made here.
[0103] As used here and in the appended claims, the words
"comprise," "has," and "include" and all grammatical variations
thereof are each intended to have an open, non-limiting meaning
that does not exclude additional elements or steps.
* * * * *