U.S. patent application number 10/153144 was filed with the patent office on 2003-04-17 for use of syngas for the upgrading of heavy crude at the wellhead.
This patent application is currently assigned to Conoco Inc.. Invention is credited to Allison, Joe D..
Application Number | 20030070808 10/153144 |
Document ID | / |
Family ID | 26850215 |
Filed Date | 2003-04-17 |
United States Patent
Application |
20030070808 |
Kind Code |
A1 |
Allison, Joe D. |
April 17, 2003 |
Use of syngas for the upgrading of heavy crude at the wellhead
Abstract
The present system may be used to hydroprocess heavy crude oil
at the wellhead, effectively lowering the viscosity and removing
contaminants such as sulfur, nitrogen and metal contents. The
hydrogen source for hydroprocessing is the separated hydrogen
product from the methane produced from a syngas plant.
Inventors: |
Allison, Joe D.; (Ponca
City, OK) |
Correspondence
Address: |
DAVID W. WESTPHAL
CONOCO PHILLIPS
P.O. BOX 1267
PONCA CITY
OK
74602-1267
US
|
Assignee: |
Conoco Inc.
Houston
TX
|
Family ID: |
26850215 |
Appl. No.: |
10/153144 |
Filed: |
May 21, 2002 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60329673 |
Oct 15, 2001 |
|
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|
Current U.S.
Class: |
166/265 ;
166/90.1 |
Current CPC
Class: |
C10G 49/007 20130101;
E21B 43/164 20130101 |
Class at
Publication: |
166/265 ;
166/90.1 |
International
Class: |
E21B 043/34 |
Claims
What is claimed is:
1. A method for upgrading heavy crude oils at the wellhead
comprising: producing syngas in a syngas-producing process;
separating the syngas into H.sub.2 and CO streams; and injecting
the H.sub.2 stream into a hydroprocessing operation located at the
wellhead.
2. The method according to claim 1 wherein the syngas-producing
operation is of a type selected from the group consisting of CPOX
(catalytic partial oxidation), ATR (autothermal reforming), and
steam reforming processes.
3. The method according to claim 2 wherein the syngas-producing
process is CPOX.
4. The method according to claim 3 wherein a methane-containing gas
and oxygen-containing gas feed is supplied to the CPOX process.
5. The method according to claim 4 wherein the methane-containing
gas is associated gas co-produced from the oil well.
6. The method according to claim 4 wherein the methane-containing
gas is supplied via pipeline from other sources.
7. The method according to claim 1 wherein a hydrogen separation
process separates the syngas into H.sub.2 and CO streams and
optionally co-existing nitrogen streams.
8. The method according to claim 7 wherein the hydrogen separation
process employs membrane separation technology.
9. The method according to claim 1 wherein the hydroprocessing
operation is of a type selected from the group consisting of
hydrogenation, hydrocracking, hydrodenitrogenation,
hydrodemetalization, and hydrodesulfurization processes.
10. The method according to claim 9 wherein the hydroprocessing
operation is hydrodesulfurization.
11. A method for upgrading heavy crude oils at the wellhead
comprising: producing syngas in a syngas-producing process;
separating the syngas into H.sub.2 and CO streams; running the CO
stream in the presence of a water feed through a water gas shift
process to produce a water gas shift product comprising CO.sub.2
and additional H.sub.2; separating the water gas shift product into
H.sub.2 and CO.sub.2 streams; and injecting the H.sub.2 streams
into a hydroprocessing process located at the wellhead.
12. The method according to claim 11 wherein the syngas-producing
process is of a type selected from the group consisting of CPOX
(catalytic partial oxidation), ATR (autothermal reforming), and
steam reforming processes.
13. The method according to claim 12 wherein the syngas-producing
process is CPOX.
14. The method according to claim 13 wherein a methane-containing
gas and oxygen-containing gas feed is supplied to the CPOX
process.
15. The process according to claim 14 wherein the
methane-containing gas is associated gas co-produced from the oil
well.
16. The process according to claim 14 wherein the
methane-containing gas is supplied via pipeline from other
sources.
17. The method according to claim 11 wherein a hydrogen separation
process separates the syngas into H.sub.2 and CO streams and
optionally co-existing nitrogen streams.
18. The method according to claim 17 wherein the hydrogen
separation process employs membrane separation technology.
19. The method according to claim 11 wherein the hydroprocessing
process is of a type selected from the group consisting of
hydrogenation, hydrocracking, hydrodenitrogenation,
hydrodemetalization, and hydrodesulfurization processes.
20. The method according to claim 19 wherein the hydroprocessing
process comprises a hydrodesulfurization process.
21. The method according to claim 11 further comprising feeding the
product CO.sub.2 into a carbon dioxide compressor.
22. The method according to claim 21 wherein the compressed
CO.sub.2 is injected into the formation via injection wells to
facilitate movement of the crude oil to the producing wellhead.
23. A method for upgrading heavy crude oils at the wellhead
comprising: producing syngas in a syngas-producing process running
at CPOX favorable conditions with a methane-containing gas and
oxygen-containing gas feed; separating the syngas into H.sub.2 and
CO streams; and injecting the H.sub.2 stream into a hydroprocessing
process located at the wellhead.
24. A method for upgrading heavy crude oils at the wellhead
comprising: producing syngas in a syngas-producing process running
at CPOX favorable conditions with a methane-containing gas and
oxygen-containing gas feed; separating the syngas into H.sub.2 and
CO streams; running the CO stream in the presence of a water feed
through a water gas shift process to produce a water gas shift
product comprising CO.sub.2 and additional H.sub.2; separating the
water gas shift product into H.sub.2 and CO.sub.2 streams; and
injecting the H.sub.2 streams into a hydroprocessing process
located at the wellhead.
25. A system for upgrading heavy crude oils at the wellhead
comprising: providing a syngas-producing process running at CPOX
favorable conditions with a methane-containing gas and
oxygen-containing gas feed to produce syngas; providing a hydrogen
separation process, wherein the syngas is separated into H.sub.2
and CO streams; and providing a hydroprocessing process located at
the wellhead, wherein the H.sub.2 stream is injected.
26. A system for upgrading heavy crude oils at the wellhead
comprising: providing a syngas-producing process running at CPOX
favorable conditions with a methane-containing gas and
oxygen-containing gas feed to produce syngas; providing a first
hydrogen separation process, wherein the syngas is separated into
H.sub.2 and CO streams; providing a water gas shift process with a
water feed and a recycle means for running the CO stream to the
water gas shift process, wherein the water gas shift process
produces a water gas shift product comprising additional H.sub.2
and CO.sub.2; providing a second hydrogen separation process,
wherein the water gas shift product is separated into additional
H.sub.2 and CO.sub.2 streams; and providing a hydroprocessing
process located at the wellhead, wherein the H.sub.2 streams are
injected.
Description
TECHNICAL FIELD OF THE INVENTION
[0001] The present invention relates to a process for the
preparation of synthesis gas, i.e., a mixture of carbon monoxide
and hydrogen, from natural gas. More particularly, this invention
relates to a method for maximizing the hydrogen production in
syngas. Still more particularly, the present invention relates to
upgrading crude oil at the wellhead to utilize co-produced natural
gas and increase the ease of transportation of the crude by
reducing the viscosity and sulfur, nitrogen, and other
contaminants.
BACKGROUND OF THE INVENTION
[0002] Large quantities of methane, the main component of natural
gas, are available in many areas of the world, and natural gas is
predicted to outlast oil reserves by a significant margin. However,
most natural gas is situated in areas that are geographically
remote from population and industrial centers. The costs of
compression, transportation, and storage make its use economically
unattractive. To improve the economics of natural gas use, much
research has focused on the use of methane as a starting material
for the production of higher hydrocarbons and hydrocarbon liquids,
which are more easily transported and thus more economical. The
conversion of methane to hydrocarbons is typically carried out in
two steps. In the first step, methane is converted into a mixture
of carbon monoxide and hydrogen (i.e., synthesis gas or syngas). In
a second step, the syngas is converted into hydrocarbons.
[0003] This first step, the preparation of synthesis gas from
natural gas, is well known in the art and usually referred to as
syngas conversion. The amount of hydrogen and carbon in syngas
depends on the process technology, feedstock, and the operating
conditions used in its manufacture. Synthesis gas can be made from
a wide variety of feedstocks including natural gas, liquefied
petroleum gas (LPG), oil, coal and petroleum coke. Processes for
converting these materials to syngas are steam methane reforming,
CO.sub.2 reforming, auto thermal reforming and partial oxidation or
gasification using either air or pure oxygen.
[0004] The ratio of hydrogen to carbon monoxide can range as low as
0.6 with CO.sub.2 reforming of natural gas or partial oxidation of
petroleum coke to as high as 6.5 with steam methane reforming. When
hydrogen is the desired product, the reforming reaction can be
followed by the well-known water gas shift reaction (WGS) shown in
Equation 1.
CO+H.sub.2OCO.sub.2+H.sub.2 (1)
[0005] The WGS essentially converts all the carbon monoxide in the
raw syngas to carbon dioxide, thereby maximizing the quantity of
hydrogen produced. The shift reaction can likewise be avoided and
the quantity of carbon monoxide maximized by selecting a feedstock
with a higher carbon to hydrogen ratio or recycling carbon dioxide
through the process. Although carbon monoxide can be maximized,
hydrogen cannot be eliminated and is an inevitable by-product of
the process.
[0006] Current industrial use of methane as a chemical feedstock
proceeds by the initial conversion of methane to carbon monoxide
and hydrogen by either steam reforming, which is the most
widespread process, or by dry reforming. Steam reforming currently
is the major process used commercially for the conversion of
methane to synthesis gas, proceeding according to Equation 2.
CH.sub.4+H.sub.2OCO+3H.sub.2 (2)
[0007] Although steam reforming has been practiced for over five
decades, efforts to improve the energy efficiency and reduce the
capital investment required for this technology continue.
[0008] The catalytic partial oxidation (CPOX) of hydrocarbons,
e.g., natural gas or methane to syngas is also a process known in
the art. While currently limited as an industrial process, partial
oxidation has recently attracted much attention due to significant
inherent advantages, such as the fact that significant heat is
released during the process, in contrast to steam reforming
processes.
[0009] In catalytic partial oxidation, natural gas is mixed with
air, oxygen-enriched air, or oxygen, and introduced to a catalyst
at elevated temperature and pressure. The partial oxidation of
methane yields a syngas mixture with a H.sub.2:CO ratio of 2:1, as
shown in Equation 3.
CH.sub.4+1/2O.sub.2CO+2H.sub.2 (3)
[0010] This ratio is more useful than the H.sub.2:CO ratio from
steam reforming for the downstream conversion of the syngas to
chemicals such as methanol and to fuels. The partial oxidation is
also exothermic, while the steam reforming reaction is strongly
endothermic. Furthermore, oxidation reactions are typically much
faster than reforming reactions. This allows the use of much
smaller reactors for catalytic partial oxidation processes. The
syngas in turn may be converted to hydrocarbon products, for
example, fuels boiling in the middle distillate range, such as
kerosene and diesel fuel, and hydrocarbon waxes by processes such
as the Fischer-Tropsch Synthesis.
[0011] The selectivities of catalytic partial oxidation to the
desired products, carbon monoxide and hydrogen, are controlled by
several factors, but one of the most important of these factors is
the choice of catalyst composition. Typically, catalyst
compositions have included precious metals and/or rare earths. The
large volumes of expensive catalysts needed by prior art catalytic
partial oxidation processes have placed these processes generally
outside the limits of economic justification.
[0012] For successful operation at commercial scale, the catalytic
partial oxidation process must be able to achieve a high conversion
of the methane feedstock at high gas hourly space velocities, and
the selectivity of the process to the desired products of carbon
monoxide and hydrogen must be high. Such high conversion and
selectivity must be achieved without detrimental effects to the
catalyst, such as the formation of carbon deposits ("coke") on the
catalyst, which severely reduces catalyst performance.
[0013] Accordingly, the economic evaluation for selection of a
syngas process depends upon the required hydrogen to carbon
monoxide molar ratio, availability and cost of hydrocarbon
feedstocks and catalysts, availability and cost of oxygen and
carbon dioxide, the cost of utilities and credits available for
export steam and sale of excess hydrogen or carbon monoxide
coproduct. This analysis is complex and highly site dependent.
Typically, petrochemical applications of syngas require a ratio of
hydrogen to carbon monoxide of either 1:1 or 2:1. Commercial
processes for syngas yield much higher ratios; therefore,
separation technology, by-product credits and production techniques
that can adjust the hydrogen to carbon monoxide ratio are important
aspects of syngas production.
[0014] Presently, heavy crude oil presents processing problems in
refineries due to high viscosities, sulfur, nitrogen, and metal
contents. Because of environmental requirements, steps are often
taken at the refinery to upgrade these crude oils by reducing their
viscosity and contaminants. Treatment strategies range from
blending lighter crudes with heavier crudes to hydroprocessing.
These strategies, though effective, are expensive because they
require additional intermediates, such as hydrogen, to be produced.
Therefore, there exists a need for a method of upgrading heavy
crude oil with an already existing hydrogen source.
SUMMARY OF THE INVENTION
[0015] The present invention relates to hydrotreating at the
wellhead, using hydrogen produced from methane through the syngas
process. As defined herein, the term "hydrotreating" is intended to
be synonymous with the term "hydroprocessing," which involves the
reaction of hydrocarbons at operating conditions with hydrogen,
usually in the presence of a catalyst. Included within the
processes intended to be encompassed by the term "hydroprocessing"
are hydrocracking, aromatic hydrogenation, ring-opening, and
hydrorefining, or hydrodesulfurization, hydrodenitrification, and
hydrodemetalation. As will be recognized, one common attribute of
these processes, and the reactions being effected therein, is that
they are all "hydrogen-consuming," and are, therefore, exothermic
in nature. Although hydroprocessing may be applied to any
hydrocarbon feedstock, it is particularly applicable, though less
easily applicable, to heavier feedstocks such as residua, vacuum
and atmospheric gas oils, coal and shale liquids, etc., since these
feedstocks typically contain higher concentrations of less easily
removed contaminants.
[0016] Additionally, the term "catalytic partial oxidation", or
CPOX, when used in the context of the present syngas production
methods, in addition to its usual meaning, can also refer to a net
catalytic partial oxidation process, in which hydrocarbons
(comprising mainly methane) and oxygen-containing gases (i.e.
oxygen, oxygen-enriched air, air) are supplied as reactants and the
resulting product stream is predominantly the partial oxidation
products CO and H.sub.2, rather than the complete oxidation
products CO.sub.2 and H.sub.2O. For example, the preferred
catalysts serve in the short contact time process of the invention,
which is described in more detail below, to yield a product gas
mixture containing H.sub.2 and CO in a molar ratio of approximately
2:1. Although the primary reaction mechanism of the process is
partial oxidation, other oxidation reactions may also occur in the
reactor to a lesser or minor extent. As shown in Equation (2), the
partial oxidation of methane yields H.sub.2 and CO in a molar ratio
of 2:1.
[0017] As explained above, syngas technology can be shifted to
produce larger amounts of hydrogen by varying the H.sub.2:CO ratio
and additionally converting the remaining CO to CO.sub.2 and
additional H.sub.2 using the water gas shift reaction. Utilization
of the hydrogen from methane allows for a use of an otherwise
wasted resource. Additionally, the produced CO.sub.2 from the water
gas shift reaction can be injected into the formation as a CO.sub.2
flood.
[0018] In a preferred embodiment of the present invention, a method
for upgrading heavy crude oils at the wellhead includes producing
syngas in a syngas-producing process, separating the syngas into
H.sub.2 and CO streams, and injecting the H.sub.2 stream into a
hydroprocessing operation located at the wellhead. A
hydroprocessing operation located at the wellhead is preferably
within 100 miles of the wellhead, more preferably within 10 miles
of the wellhead, and most preferably within a mile of the
wellhead.
[0019] In an alternate embodiment of the present invention, a
method for upgrading heavy crude oils at the wellhead includes
producing syngas in a syngas-producing process, separating the
syngas into H.sub.2 and CO streams, running the CO stream in the
presence of a water feed through a water gas shift process to
produce a water gas shift product of CO.sub.2 and additional
H.sub.2, separating the water gas shift product into H.sub.2 and
CO.sub.2 streams, and injecting the H.sub.2 streams into a
hydroprocessing process located at the wellhead.
BRIEF DESCRIPTION OF THE DRAWINGS
[0020] For a more detailed understanding of the present invention,
reference is now made to the accompanying figures, FIG. 1 and FIG.
2, which are schematic illustrations of first and second systems,
respectively, constructed in accordance with the present
invention.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0021] Because of the shrinking world supply of oils, oil
processors are faced with the necessity of utilizing heavy
feedstocks that are highly contaminated with sulfur, nitrogen and
metal contents. In the processing of these feedstocks, it is very
desirable to remove as much of the contaminants as early in the
refining of these feedstocks as possible, so that downstream
catalysts do not suffer build-up and consequent reduced activity.
Removing contaminants also makes a higher quality final product
that is less corrosive and less polluting when combusted.
[0022] Referring now to FIG. 1, one embodiment of the present
system 100 preferably includes a syngas plant 10, a hydrogen
separation unit 20, and a hydroprocessing plant 30. Methane and
oxygen-containing gas stream 11 is fed into syngas plant 10 and
reacts with a suitable catalyst to form a stream of hydrogen and
carbon monoxide 12. Hydrogen and carbon monoxide stream 12 is fed
into hydrogen separation unit 20, where it is separated into carbon
monoxide export stream 13 and hydrogen stream 14. Hydrogen stream
14 is injected into hydroprocessing plant 30, located at the
wellhead.
[0023] Referring now to FIG. 2, an alternate embodiment of the
present system 200 preferably includes a syngas plant 10, a first
hydrogen separation unit 20, a water gas shift reactor 40, a second
hydrogen separation unit 50, and a hydroprocessing plant 30. In
some embodiments, system 200 further includes a carbon dioxide
compressor 60. Methane and oxygen stream 11 is fed into syngas
plant 10 and reacts with a suitable catalyst to form a stream of
hydrogen and carbon monoxide 12. Hydrogen and carbon monoxide
stream 12 is fed into first hydrogen separation unit 20, where it
is separated into carbon monoxide stream 13 and hydrogen stream 14.
Carbon monoxide stream 13 may either exit system 200 as export
steam 13b or comprise carbon monoxide feed stream 13a for water gas
shift reactor 40. In the latter embodiment, carbon monoxide stream
13a is recycled into water gas shift reactor with water feed 21
under water gas shift favorable conditions to produce hydrogen and
carbon dioxide stream 22. Hydrogen and carbon dioxide stream 22 is
fed into second hydrogen separation unit 50, where it is separated
into carbon dioxide stream 23 and hydrogen stream 24. Hydrogen
streams 14 and 24 are injected into hydroprocessing plant 30,
located at the wellhead. Carbon dioxide stream 23 may either exit
system 200 as export steam 23b or comprise carbon dioxide feed
stream 23a for carbon dioxide compressor 60. The compressed
CO.sub.2 may then be injected into the wellhead to further upgrade
the heavy oil.
[0024] In some embodiments, system 200 may include a syngas plant
10, a hydrogen separation unit 20, a water gas shift reactor 40,
and a hydroprocessing plant 30. In these embodiments, the hydrogen
separation unit separates both the hydrogen-carbon monoxide and the
hydrogen-carbon dioxide streams into a hydrogen stream and a carbon
monoxide-carbon dioxide stream. A carbon dioxide removal process
such as membrane separation or an amine system may be utilized to
separate the carbon monoxide from the carbon dioxide.
[0025] In some embodiments, the methane from the methane and
oxygen-containing stream is associated gas. Associated gas is
herein defined as gas co-produced from the same oil field or same
wellhead being treated. In other embodiments, the methane from the
methane and oxygen-containing stream is supplied via pipeline from
other sources.
[0026] Process of Producing Syngas
[0027] A feed stream comprising a hydrocarbon feedstock and an
oxygen-containing gas is contacted with a suitable syngas catalysts
in a reaction zone maintained at partial oxidation-promoting
conditions of temperature, pressure and flowrate, effective to
produce an effluent stream comprising carbon monoxide and hydrogen.
Preferably a millisecond contact time reactor is employed. The
hydrocarbon feedstock may be any gaseous hydrocarbon having a low
boiling point, such as methane, natural gas, associated gas, or
other sources of light hydrocarbons having from 1 to 5 carbon
atoms. The hydrocarbon feedstock may be a gas arising from
naturally occurring reserves of methane which contain carbon
dioxide. Preferably, the feed comprises at least 50% by volume
methane, more preferably at least 75% by volume, and most
preferably at least 80% by volume methane.
[0028] The hydrocarbon feedstock is in the gaseous phase when
contacting the catalyst. The hydrocarbon feedstock is contacted
with the catalyst as a mixture with an oxygen-containing gas,
preferably pure oxygen. The oxygen-containing gas may also comprise
steam and/or CO.sub.2 in addition to oxygen. Alternatively, the
hydrocarbon feedstock is contacted with the catalyst as a mixture
with a gas comprising steam and/or CO.sub.2.
[0029] Preferably, the methane-containing feed and the
oxygen-containing gas are mixed in such amounts to give a carbon
(i.e., carbon in methane) to oxygen (i.e., atomic oxygen) ratio
from about 1.25:1 to about 3.3:1, more preferably, from about 1.3:1
to about 2.2:1, and most preferably from about 1.5:1 to about
2.2:1, especially the stoichiometric ratio of 2:1.
[0030] The process is operated at atmospheric or superatmospheric
pressures, the latter being preferred. The pressures may be from
about 100 kPa to about 12,500 kPa, preferably from about 130 kPa to
about 10,000 kPa.
[0031] The process is preferably operated at catalyst temperatures
of from about 600.degree. C. to about 1,200.degree. C., preferably
from about 700.degree. C. to about 1,100.degree. C. The hydrocarbon
feedstock and the oxygen-containing gas are preferably pre-heated
before contact with the catalyst.
[0032] It will be understood that the selection of a catalyst or
catalyst system requires many technical and economic
considerations. The process of selecting a precious metal catalyst
can be broken down into components. Key catalyst properties include
high activity, high selectivity, high recycle capability and
filterability. Catalyst performance is determined mainly by the
precious metal component. A metal is chosen based both on its
ability to complete the desired reaction and its inability to
complete an unwanted reaction. Typical catalysts used in CPOX
include metals from Group 6B, 7B, & 8B of the periodic table
associated with promoters from Groups 1B through 8B, Groups 1A
through 5A, and metals from the Lanthanide group.
[0033] Generally, catalysts are supported on a carrier material or
support. The catalyst support may be any of a variety of materials
that a catalytically active material is coated on. The catalyst
support preferably allows for a high degree of metal dispersion.
The choice of support is largely determined by the nature of the
reaction system. The support catalyst is preferably stable under
reaction and regeneration conditions. Further, it preferably does
not adversely react with solvent, reactants, or reaction
products.
[0034] Suitable supports include activated carbon, alumina, silica,
silica-alumina, silicon carbide, carbon black, TiO.sub.2,
ZrO.sub.2, CaCO.sub.3, and BaSO.sub.4, or stabilized forms of the
aforementioned materials. Preferably, the catalytically active
material is supported on either zirconia, stabilized zirconia, or
alumina.
[0035] It will be understood that alternative choices of support
may be made without departing from the preferred embodiments of the
present invention by one of ordinary skill in the art. A support
preferably favorably influences any of the catalyst activity,
selectivity, recycling, refining, material handling reproducibility
and the like. Properties of a support include surface area, pore
volume, pore size, distribution, particle size, attrition
resistance, acidity, basicity, impurity levels, and the ability to
promote metal-support interactions. Metal dispersion increases with
surface support area. Support porosity influences metal dispersion
and distribution, metal sintering resistance, and intraparticle
diffusion of reactants, products and poisons. Smaller support
particle size increases catalytic activity but decreases
filterability. The support preferably has desirable mechanical
properties, attrition resistance and hardness. For example, an
attrition resistant support allows for multiple catalyst recycling
and rapid filtration. Further, support impurities preferably are
inert. Alternatively, the support may contain promoters that
enhance catalyst selectivity.
[0036] The catalysts used may be prepared by any of the methods
known to those skilled in the art. By way of illustration and not
limitation, such methods include impregnating the catalytically
active compounds or precursors onto a support, extruding one or
more catalytically active compounds or precursors together with
support material to prepare catalyst extrudates, and/or
precipitating the catalytically active compounds or precursors onto
a support. Accordingly, supported catalysts may be used in the form
of powders, particles, pellets, monoliths, honeycombs, packed beds,
foams, and aerogels.
[0037] The hydrocarbon feedstock and the oxygen-containing gas may
be passed over the catalyst at any of a variety of space
velocities. Space velocities for the process (weight hourly space
velocity), stated as normal liters of gas per kilogram of catalyst
per hour, are from about 20,000 to about 100,000,000 NL/kg/h,
preferably from about 50,000 to about 50,000,000 NL/kg/h. It is
preferred that the residence time on the catalyst is about 10
milliseconds or less. Although, for ease in comparing with other
syngas production systems, space velocities at standard conditions
have been used to describe the present invention, it is well
recognized in the art that residence time is the inverse of space
velocity and that the disclosure of high space velocities equates
to low residence times on the catalyst. Under these operating
conditions a flow rate of reactant gases is preferably maintained
sufficient to ensure a residence time of no more than 10
milliseconds with respect to each portion of reactant gas in
contact with the catalyst. The product gas mixture emerging from
the reactor is harvested and directly routed into hydrogen
separation unit.
[0038] Process of Separating Hydrogen from Syngas/WGS Product
[0039] A preferred method for hydrogen separation employs pressure
swing adsorption. At a high partial pressure, solid molecular
sieves can absorb a greater quantity of certain gaseous components
than others and absorb some compounds more strongly than others.
For example, hydrogen is adsorbed less strongly than carbon
monoxide and carbon dioxide, and the strength of adsorption of
carbon monoxide and carbon dioxide increases with increasing
molecular weight. As a result, at elevated pressures, hydrocarbons
and other impurities are absorbed from a hydrogen-rich stream and
most of the hydrogen passes through the system, leaving the
impurities behind. Very high purity hydrogen can be produced this
way. The hydrogen-rich stream can then be piped to a
hydroprocessing unit. When the pressure on the system is reduced,
the impurities adsorbed at high pressure are released from the
solid adsorbent and purged.
[0040] Process of Upgrading Heavy Oil
[0041] In some embodiments of the present invention,
hydrodesulfurization is the preferred process for removing
undesirable compounds. In hydrodesulfurization, oil is combined
with high-purity hydrogen, vaporized, and then passed over a
catalyst such as tungsten, nickel, or a mixture of cobalt and
molybdenum oxides supported on a carrier material such as alumina.
Hydrodesulfurization is performed according to methods known to one
of ordinary skill in the art. A general description of major
considerations involved in performing hydrodesulfurization, and
more generally hydrorefining, is given by W. S. Bland and R. L.
Davidson, Petroleum Processing Handbook, Chapter 3 (1967).
Operating temperatures are usually between 260.degree. C. and
425.degree. C. (500.degree. F. and 800.degree. F.) at pressures of
14 to 70 kilograms per square centimeter (200 to 1,000 pounds per
square inch). Operating conditions are set to facilitate the
desired level of sulfur removal without promoting any change to the
other properties of the oil.
[0042] The sulfur in the oil is converted to hydrogen sulfide,
which is removed from the circulating hydrogen stream by absorption
in a solution such as diethanolamine. The solution can then be
heated to remove the sulfide and reused. The hydrogen sulfide
recovered is useful for manufacturing elemental sulfur of high
purity.
[0043] Hydrodenitrification, a common process for removing nitrogen
compounds and hydrodemetalation, a common process for removing
metal contents, generally follow the same requirements as
hydrodesulfurization.
[0044] CO.sub.2 Flooding
[0045] According to some embodiments of the present invention, the
CO product stream is fed into a water gas shift plant in the
presence of water and operated at water gas shift favorable
conditions. After the CO product has gone through the WGS, there
will be CO.sub.2 remaining. This CO.sub.2 can be used to
additionally upgrade the heavy oil; it is known to inject carbon
dioxide, either alone or in conjunction with natural gas, either at
high pressure or containing sufficient petroleum gases in the vapor
phase to perform tertiary oil recovery. The carbon dioxide can
greatly improve tertiary recovery, but the effort is not economical
unless very large quantities of carbon dioxide are available at a
reasonable price. Conventionally, most of the successful projects
of this type depend on tapping and transporting (by pipeline)
carbon dioxide from underground reservoirs. However, because
CO.sub.2 is a biproduct of our desired method to maximize hydrogen
content, the cost is essentially the cost of separation of the
hydrogen from the CO.sub.2.
[0046] While the preferred embodiments of the invention have been
shown and described, modifications thereof can be made by one
skilled in the art without departing from the spirit and teachings
of the invention. The embodiments described herein are exemplary
only, and are not intended to be limiting. For example, while CPOX
is preferably employed to produce syngas, any syngas-producing
technology such as autothermal reforming (ATR) and steam reforming
could be utilized. Many variations and modifications of the
invention disclosed herein are possible and are within the scope of
the invention. Accordingly, the scope of protection is not limited
by the description set out above, but is only limited by the claims
which follow, that scope including all equivalents of the subject
matter of the claims. The disclosures of all patents, patent
applications, and publications cited herein are incorporated by
reference.
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