U.S. patent application number 12/295099 was filed with the patent office on 2009-12-31 for methods and systems for gasifying a process stream.
Invention is credited to Marco J. Castaldi, John P. Dooher, Klaus S. Lackner.
Application Number | 20090320368 12/295099 |
Document ID | / |
Family ID | 38625494 |
Filed Date | 2009-12-31 |
United States Patent
Application |
20090320368 |
Kind Code |
A1 |
Castaldi; Marco J. ; et
al. |
December 31, 2009 |
Methods and Systems for Gasifying a Process Stream
Abstract
Methods and systems for gasifying process streams are described.
In some embodiments, a method for gasifying a process stream
includes gasifying the process stream in a first chamber to
generate one or more product gases, transporting at least a portion
of the one or more product gases to a second chamber, combusting at
least a portion of the one or more product gases in the presence of
one or more catalysts in the second chamber to generate a heat
energy, and indirectly providing the heat energy from the second
chamber to the first chamber as a primary heat source to drive
gasification of the process stream.
Inventors: |
Castaldi; Marco J.;
(Yonkers, NY) ; Dooher; John P.; (Garden City,
NY) ; Lackner; Klaus S.; (Dobbs Ferry, NY) |
Correspondence
Address: |
WIGGIN AND DANA LLP;ATTENTION: PATENT DOCKETING
ONE CENTURY TOWER, P.O. BOX 1832
NEW HAVEN
CT
06508-1832
US
|
Family ID: |
38625494 |
Appl. No.: |
12/295099 |
Filed: |
March 30, 2007 |
PCT Filed: |
March 30, 2007 |
PCT NO: |
PCT/US07/08033 |
371 Date: |
February 26, 2009 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60788238 |
Mar 31, 2006 |
|
|
|
60846063 |
Sep 20, 2006 |
|
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Current U.S.
Class: |
48/76 ;
48/203 |
Current CPC
Class: |
C10J 3/00 20130101; H01M
8/0612 20130101; C01B 2203/047 20130101; Y02P 30/00 20151101; C01B
2203/0405 20130101; C01B 2203/043 20130101; H01M 8/0681 20130101;
Y02E 60/50 20130101; C10J 2300/0916 20130101; H01M 8/0643 20130101;
C10J 2300/0973 20130101; C01B 3/505 20130101; C01B 2203/0283
20130101; C10J 2300/0969 20130101; C10J 2300/093 20130101; C10J
2300/1807 20130101; C01B 2203/0495 20130101; C10J 2300/1223
20130101; H01M 8/0668 20130101; C10J 2300/1246 20130101; Y02E 20/18
20130101; C10J 2300/1646 20130101; C01B 3/56 20130101; C10J 2200/09
20130101; C01B 2203/86 20130101; C10J 2300/1215 20130101; C10J 3/84
20130101 |
Class at
Publication: |
48/76 ;
48/203 |
International
Class: |
C10J 3/68 20060101
C10J003/68; C10J 3/00 20060101 C10J003/00 |
Claims
1. A method for gasifying a process stream, the method comprising:
providing a process stream including a fuel source; applying a
primary heat source to a first chamber containing the process
stream; gasifying the process stream in the first chamber so as to
produce a gasified process stream including one or more product
gases; conducting at least a portion of the one or more product
gases to a second chamber; combusting the at least a portion of the
one or more product gases in the presence of one or more catalysts
in the second chamber to generate a heat energy; and conducting the
heat energy from the second chamber to the first chamber so as to
provide the primary heat source.
2. A method according to claim 1, wherein the one or more product
gases include at least one of hydrogen, carbon monoxide, and
combinations thereof.
3. A method according to claim 1, further comprising: before
gasifying the fuel source, mixing an amount of water with the
process stream.
4. A method according to claim 3, wherein the water to fuel source
molar ratio of the amount of water ranges from about 0.7 to about
1.0.
5. A method according to claim 2, wherein the one or more product
gases include hydrogen, and the method further comprises:
separating substantially all of the hydrogen from the process
stream; and generating a consumable energy with at least a portion
of the hydrogen.
6. A method according to claim 3, further comprising: separating
substantially all of the water from the process stream; and prior
to gasifying, mixing at least a portion of the water with the
process stream.
7. A method according to claim 2, further comprising: dividing the
process stream, which includes an amount of carbon monoxide, into
first and second process streams each of which includes a portion
of the carbon monoxide from the process stream before it is
divided; and generating a consumable energy with at least a portion
of the carbon monoxide contained in at least one of the first and
second process streams.
8. A method according to claim 7, further comprising: mixing oxygen
with at least one of the first and second process streams to
prepare the at least one of the first and second process streams
for combustion.
9. A method according to claim 7, wherein the portion of the carbon
monoxide in the second process stream is from about 20 to about 60
percent by weight of the carbon monoxide contained in the process
stream before it is divided.
10. A method according to claim 9, wherein the carbon monoxide in
the second process stream is from about 30 to about 50 percent by
weight of the carbon monoxide contained in the process stream
before it is divided.
11. A method according to claim 1, further comprising: generating
carbon dioxide while combusting at least a portion of the one or
more product gases; and gasifying a portion of the carbon dioxide
with the process stream.
12. A method according to claim 11, wherein the portion of the
carbon dioxide gasified is from about 0 to about 50 percent by
weight of the carbon dioxide generated while combusting at least a
portion of the one or more product gases in the presence of the one
or more catalysts.
13. A method according to claim 1, wherein gasifying the process
stream is driven substantially from the heat energy generated from
combusting at least a portion of the one or more product gases in
the presence of one or more catalysts.
14. A method according to claim 1, wherein the fuel source is at
least one of coal, a biomass, and combinations thereof.
15. A method according to claim 1, wherein gasifying the fuel
source includes a maximum temperature of about 850 degrees
Celsius.
16. A method according to claim 1, wherein combusting the one or
more product gases includes a maximum temperature of about 1300
degrees Celsius.
17. A system for gasifying a process stream, the system comprising:
a first chamber for gasifying the process stream to produce a
gasified process stream including at least one of one or more
product gases, water, and particulates, the gasification chamber
including sidewalls; a primary heat source for heating the first
chamber; and a second chamber for combusting the process stream,
said second chamber in fluid communication with the first chamber
and at least a portion of the process stream, the second chamber
including one or more portions that are in thermal communication
with respective ones of the sidewalls of the gasification chamber,
the second chamber including interior surfaces having a coating
formed from one or more catalysts, the second chamber being
configured to combust at least a portion of the process stream to
generate a heat energy that serves as the primary heat source and
is provided to the first chamber via the one or more portions that
thermally communicate with the first chamber.
18. A system according to claim 17, wherein the one or more product
gases include at least one of hydrogen, carbon monoxide, and
combinations thereof.
19. A system according to claim 17, further comprising: an oxygen
supply in fluid communication with the second chamber.
20. A system according to claim 18, further comprising: a separator
for separating the hydrogen from the process stream.
21. A system according to claim 17, further comprising: a separator
for separating water from the process stream.
22. A system according to claim 18, further comprising: at least
one of a divider for dividing the process stream or a separator for
separating carbon monoxide from the process stream.
23. A system according to claim 22, further comprising: at least
one of a fuel cell, a gas turbine engine, or an internal combustion
engine capable of generating a consumable energy in the form of
electricity from at least a portion of the carbon monoxide.
24. A system according to claim 17, wherein the one or more
catalysts include one or more of precious group metals,
hexaaluminates, spinels, zeolites, base metal formulations, and
combinations thereof.
25. A system according to claim 17, wherein the first chamber and
the second chamber are modular.
26. A system according to claim 17, wherein the process stream
includes a fuel source including at least one of coal and a
biomass.
27. A catalytic reaction gasifier for gasifying a process stream,
the gasifier comprising: a housing including one or more inlets and
one or more outlets; a combustion chamber defined within the
housing, the combustion chamber including a plurality of interior
surfaces; one or more catalysts positioned within the combustion
chamber; and a gasification chamber separate from but positioned so
as to be in thermal communication with the combustion chamber, the
gasification chamber including a first end and a second end, the
first end being operably connected with the one or more inlets for
receiving the process stream and the second end being operably
connected with the one or more outlets.
28. A gasifier according to claim 27, wherein the gasification
chamber includes at least one tube that extends through the
combustion chamber thereby allowing the gasification chamber to
thermally communicate with the combustion chamber.
29. A gasifier according to claim 27, wherein the combustion
chamber includes at least one tube that extends through the
gasification chamber thereby allowing the gasification chamber to
thermally communicate with the combustion chamber.
30. A gasifier according to claim 27, wherein the process stream
includes a fuel source including at least one of coal and a
biomass.
31. A gasifier according to claim 27, wherein the combustion
chamber and the gasification chamber are configured so that a
portion of heat energy generated in the combustion chamber heats
the gasification chamber thereby gasifying the process stream into
a process stream containing hydrogen.
32. A gasifier according to claim 31, further comprising: at least
one separator for separating hydrogen, particulates, water, or
carbon monoxide from the process stream.
33. A gasifier according to claim 31, wherein the one or more
outlets include a first outlet for exhausting gases from the
combustion chamber, a second outlet for exhausting solid wastes
from the gasification chamber, a third outlet for exhausting
gaseous wastes from the gasification chamber, and a fourth outlet
for exhausting hydrogen from the gasification chamber.
34. A gasifier according to claim 27, wherein the one or more
inlets include a first inlet for receiving the fuel source and a
second inlet for receiving carbon monoxide, oxygen, or a
combination thereof.
35. A gasifier according to claim 27, wherein the one or more
catalysts are selected from the group consisting of precious group
metals, hexaaluminates, spinels, zeolites, base metal formulations,
and combinations thereof.
Description
CROSS REFERENCE TO RELATED APPLICATION(S)
[0001] This application claims the benefit of U.S. Provisional
Application Nos. 60/788,238, filed Mar. 31, 2006, and 60/846,063,
filed Sep. 20, 2006, each of which is incorporated by reference as
if disclosed herein in its entirety.
BACKGROUND
[0002] Various types of gasifiers are known in industry. A variety
of fixed bed, fluidized bed, and entrained flow gasifiers have been
in use for decades. In fixed bed gasifiers, a gasification agent
such as steam, oxygen, and/or air flows through a fixed bed of fuel
source, e.g., coal or biomass, thereby gasifying the fuel source.
In fluidized bed gasifiers, the fuel source is fluidized in
oxygen/air and steam. The gas throughput of fluid bed gasifiers is
higher than for fixed bed gasifiers, but not as high as for
entrained flow gasifiers. In entrained flow gasifiers, a slurry of
particulates and fluids is gasified with oxygen.
[0003] In the majority of gasifiers used, the heat required for the
endothermic gasification reactions is supplied by partial oxidation
of the feedstock, which usually occurs in the same reaction chamber
where the gasification takes place. This is typically the case for
the state of the art entrained flow gasifiers, which tend to have
the highest throughput/size ratio of any conventional gasification
scheme. However, this approach is feedstock dependant and requires
detailed analysis to optimize the product gas composition.
[0004] Fixed bed and fluidized bed gasifiers, typically have lower
outlet temperatures, e.g., below the ash slagging temperatures,
than single stage entrained gasifiers. At lower gasifier outlet
temperatures, more methane from coal devolatization survives, which
results in a loss in hydrogen output and is typically 10-15 percent
of the coal's carbon content at 400-500 psig.
[0005] Some gasifier designs use two stages to improve gasifier
cold gas efficiency, to reduce the sensible heat in the product
gas, and to lower the oxygen requirements. In a two stage entrained
gasifier, however, the coal fed to the second stage reduces the
outlet temperature and there is some methane survival in the
syngas. Hence, a conventional gasifier will generally not have the
performance ability and versatility of a modular catalytic
combustion system having a separate gasification section.
SUMMARY
[0006] Methods for gasifying a process stream are disclosed. In
some embodiments, the method includes the following: providing a
process stream including a fuel source; applying a primary heat
source to a first chamber containing the process stream; gasifying
the process stream in the first chamber so as to produce a gasified
process stream including one or more product gases; conducting at
least a portion of the one or more product gases to a second
chamber; combusting the at least a portion of the one or more
product gases in the presence of one or more catalysts in the
second chamber to generate a heat energy; and conducting the heat
energy from the second chamber to the first chamber so as to
provide the primary heat source.
[0007] A system for gasifying a process stream is disclosed. In
some embodiments, the system includes the following: a first
chamber for gasifying the process stream to produce a gasified
process stream including at least one of one or more product gases,
water, and particulates, the gasification chamber including
sidewalls; a primary heat source for heating the first chamber; and
a second chamber for combusting the process stream, said second
chamber in fluid communication with the first chamber and at least
a portion of the process stream, the second chamber including one
or more portions that are in thermal communication with respective
ones of the sidewalls of the gasification chamber, the second
chamber including interior surfaces having a coating formed from
one or more catalysts, the second chamber being configured to
combust at least a portion of the process stream to generate a heat
energy that serves as the primary heat source and is provided to
the first chamber via the one or more portions that thermally
communicate with the first chamber.
[0008] A catalytic reaction gasifier for gasifying a process stream
is disclosed. In some embodiments, the gasifier includes the
following: a housing including one or more inlets and one or more
outlets; a combustion chamber defined within the housing, the
combustion chamber including a plurality of interior surfaces; one
or more catalysts positioned within the combustion chamber; and a
gasification chamber separate from but positioned so as to be in
thermal communication with the combustion chamber, the gasification
chamber including a first end and a second end, the first end being
operably connected with the one or more inlets for receiving the
process stream and the second end being operably connected with the
one or more outlets.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] The drawings show embodiments of the disclosed subject
matter for the purpose of illustrating the invention. However, it
should be understood that the present application is not limited to
the precise arrangements and instrumentalities shown in the
drawings, wherein:
[0010] FIG. 1 is a schematic diagram of a system according to some
embodiments of the disclosed subject matter;
[0011] FIG. 2 is a cross-sectional view of a gasifier device
according to some embodiments of the disclosed subject matter;
[0012] FIG. 3 is a diagram of a process according to some
embodiments of the disclosed subject matter;
[0013] FIG. 4 is a graph of the simulation results for hydrogen
production and energy required versus the percentage of carbon
dioxide recycled to the catalytic combustion chamber for systems
and methods device according to some embodiments of the disclosed
subject matter;
[0014] FIG. 5 is a graph of the simulation results for hydrogen
production and energy required versus the percentage of carbon
dioxide recycled to the catalytic combustion chamber for systems
and methods device according to some embodiments of the disclosed
subject matter;
[0015] FIG. 6 is a graph of the simulation results for hydrogen
production and energy required versus the percentage of carbon
dioxide recycled to the catalytic combustion chamber for systems
and methods device according to some embodiments of the disclosed
subject matter;
[0016] FIG. 7 is a graph of the simulation results for water and
methane versus the percentage of carbon dioxide recycled to the
catalytic combustion chamber for systems and methods according to
some embodiments of the disclosed subject matter;
[0017] FIG. 8 is a graph of the simulation results for hydrogen
production and energy required versus the percentage of carbon
dioxide recycled to the catalytic combustion chamber for systems
and methods device according to some embodiments of the disclosed
subject matter;
[0018] FIG. 9 is a schematic diagram showing how heat is generated
in a catalytic combustion chamber designed in accordance some
embodiments of the disclosed subject matter; and
[0019] FIG. 10 is a schematic diagram showing how heat is generated
in a prior art combustion chamber.
DETAILED DESCRIPTION
[0020] The disclosed subject matter of the present application
relates to systems, methods, and devices that can be used to gasify
a process stream containing a fuel source. Gasification is a
process that converts a fuel source, such as coal, petroleum,
petroleum coke, and biomass, into carbon monoxide and hydrogen.
[0021] The systems, methods, and devices according to the disclosed
subject matter utilize heat energy produced from combusting gases
produced during the gasification of the fuel source to drive the
gasification process. Gasification of the fuel source is generally
conducted in the presence of one or more catalysts. A supplemental
heat energy source is typically used to initiate the gasification
process. However, the heat energy produced during combustion of the
gases produced during the gasification is used as the primary
energy source for driving gasification after it has commenced. The
use of catalytic combustion, which can provides reaction and heat
transfer rates that are significantly greater than those generated
by bulk combustion used in conventional indirectly heated
gasification schemes, allows the efficient use of indirect heating
for entrained flow configurations, e.g., coal/biosolids+steam
and/or CO.sub.2, for a wide range of scales and applications.
[0022] Carbon monoxide and hydrogen can be separated from the gases
generated in the gasification process to generate electricity.
Carbon dioxide generated during the combustion of the gasification
gases can be recycled for gasification with the fuel source or
contained as a sequestration-ready source of carbon dioxide.
Alternately, hydrogen can be recycled and catalytically combusted
with air to provide the required heat without carbon dioxide
generation.
[0023] Referring now to the drawings and in particular to FIG. 1,
one embodiment of the disclosed subject matter is a system 20 for
gasifying a fuel source 22. System 20 includes a gasification
chamber 24 in fluid and thermal communication with a combustion
chamber 26.
[0024] Fuel source 22, which is typically coal or a biomass, but
can alternatively be other combustible materials, is gasified in a
first chamber, e.g., gasification chamber 24, to produce a process
stream 28. Process stream 28 includes at least one of one or more
product gases, water, and particulates, e.g., ash. As used herein,
process stream 28 is used in reference to a dynamic process stream
that is altered as it travels through system 20. One or more
product gases (not shown) can include at least one of hydrogen,
carbon monoxide, and combinations thereof. A primary heat source 30
is indirectly applied to gasification chamber 24 to heat the
gasification chamber and drive the gasification of process stream
28. The components illustrated in FIG. 1 are not drawn to scale and
may be sized according to the requirements of a particular
application or as determined by one skilled in the art.
[0025] A second chamber, e.g., combustion chamber 26, which is
separate from but in fluid communication with gasification chamber
24 to receive a portion of process stream 28, includes one or more
portions 32 that thermally communicate with the gasification
chamber. Combustion chamber 26 is configured to combust at least a
portion of process stream 28 to generate a heat energy 34. After
the gasification process has commenced, heat energy 34 indirectly
serves as primary heat source 30 and thermally communicates with
gasification chamber 24 via one or more portions 32 that are common
to or coextensive with respective ones of sidewalls 35 of the
gasification chamber. An auxiliary heat source (not shown) can be
used to begin the gasification of fuel source 22.
[0026] Combustion chamber 26 also includes interior surfaces 40
having a coating (not shown) disposed thereon and formed from one
or more catalysts (not shown). Examples of suitable catalysts
include the following: one or more precious group metal formulation
catalysts such as rhuthenium, rhodium, palladium, osmium, iridium,
platinum, and the like; one or more hexaaluminates such as
AxB.sub.(1-x)Al.sub.11O.sub.18, where A can be Rh or Ni, and B can
be La, Mn, or Sr, barium hexaaluminate, manganese hexaaluminate,
platinum-barium hexxaaluminate, and the like; one or more spinel
catalysts such as CuCr.sub.2O.sub.4,
MnFe.sub.1.95Ru.sub.0.05O.sub.4, MnCO.sub.2O.sub.4, and the like;
one or more zeolite catalysts such as lovdarite and those sold
under the trademarks YZSM-5, LINDE ZEOLITE-A, PENTASILS, and the
like; and one or more base metal formulation catalysts such as Cu,
Co, Fe, Ni, and the like.
[0027] System 20 can also include a hydrogen separator 42 for
separating hydrogen from process stream 28. Separated hydrogen can
be stored in a hydrogen storage tank 44 and/or utilized as an
energy source in other processes, such as a proton exchange
membrane fuel cell (not shown in FIG. 1).
[0028] System 20 can also include a particle separator 46 such as a
cyclone or the like for separating particulate matter such as ash
from process stream 28. The separated particulate matter can be
disposed of using conventional means. In certain embodiments,
particle separator 46 can also remove some water in addition to
removing particulates from the process stream 28.
[0029] System 20 can also include a water separator 48 for
separating water 50 from process stream 28. Separated water 50 can
be recycled in system 20 by mixing it with fuel source 22 before
introduction to gasification chamber 24. An additional source of
water, a make-up water supply 52, can also be included in system 20
to supplement separated water 50 as necessary.
[0030] System 20 can also include a divider 54 for dividing process
stream 28 after water is separated from the process stream. Divider
54 can be used to adjustably divide the process stream into first
and second process streams, a process stream 28' and a process
stream 28'', respectively, both of which are primarily made-up of
carbon monoxide after process stream 28 has passed through
hydrogen, particle, and water separators 42, 46, and 48,
respectively. In some of the embodiments, divider 54 merely divides
process stream 28 in to various portions. However, in other
embodiments, divider 54 may serve as a carbon monoxide filter to
remove only carbon monoxide from process stream 28. Process stream
28' can be utilized in one or more power generating systems such
as, but not limited to a gas turbine engine, an internal combustion
engine, a solid oxide fuel cell (SOFC) 56, and/or other similar
power generating systems known by those of ordinary skill in the
art. SOFC 56 typically produces electricity and sequestration-ready
carbon dioxide. Process stream 28'' can be recycled directly to
combustion chamber 26 for catalytic combustion or mixed with an
oxygen supply 58 at a mixer 60 and then recycled to the combustion
chamber. Combustion chamber 26 generally produces
sequestration-ready carbon dioxide, which can be stored in a carbon
dioxide holding tank 62 and either disposed of using conventional
means or recycled back to gasification chamber 24.
[0031] In some embodiments, system 20 is designed to be modular. As
a modular system, the specific components of system 20 can vary
from those illustrated and FIG. 1 but generally include some or all
of gasification chamber 24, combustion chamber 26, hydrogen
separator 42, particle separator 46, water separator 48, and
divider 54. In addition, the components that make-up system 20 can
be individually skid-mounted, individually self-contained, and
generally designed to be connected in the field.
[0032] Referring now to FIG. 2, a modular catalytic reaction
gasifier 70 for gasifying a fuel source, such as, but not limited
to, coal, a biomass, and/or other combustible materials selected by
those skilled in the art, is disclosed. Gasifier 70 includes a
housing 72, which includes wall partitions 73 that define a
combustion chamber 74, and one or more tubes 75 that define a
separate gasification chamber 76 that is positioned in thermal
communication with the combustion chamber. Combustion chamber 74
and gasification chamber 76 are configured so that a portion of
heat energy (not shown) generated in the combustion chamber
indirectly heats the gasification chamber thereby gasifying the
fuel source into a process stream containing hydrogen. Housing 72
includes a first inlet 78 for allowing the fuel source to enter
gasification chamber 76 and a second inlet 80 for allowing carbon
monoxide, oxygen, or a combination thereof to enter combustion
chamber 74. Housing 72 also includes a one or more outlets
including a first outlet 82 for exhausting gases from combustion
chamber 74, a second outlet 84 for exhausting solid wastes from
gasification chamber 76, a third outlet 86 for exhausting gaseous
wastes from the gasification chambers, and a fourth outlet 88 for
exhausting hydrogen from the gasification chambers.
[0033] As discussed above with respect to system 20 and combustion
chamber 26, combustion chamber 74 generally includes a plurality of
exterior surfaces 89 and interior surfaces 90. Interior surfaces 90
typically include a coating deposited thereon that is substantially
made-up of one or more catalysts. Similar to system 20 and
combustion chamber 26, examples of acceptable catalysts include
precious group metals, hexaaluminates, spinels, zeolites, base
metal formulations, and combinations thereof.
[0034] As discussed above, in some embodiments, gasification
chamber 76 is typically made-up of one or more tubes 75 that extend
through combustion chamber 74. Each of one or more tubes 75
includes a first end 94 that is generally operably connected with
first inlet 78 and a second end 96 that is generally operably
connected with one or more of the outlets of housing 72. Each of
one or more tubes 75 includes a sidewall 97 that is common to and
in thermal communication with interior surfaces 90 of combustion
chamber 74. In some embodiments, second end 96 can be flared, which
would serve to increase the space between the ash particles and
tube walls, while resulting in a "jet" of particles down the center
of the flared section. Each of one or more tubes 75 generally
includes an exterior surface 98 having a coating deposited thereon
that is substantially made-up of one or more catalysts similar of
the same as those coating interior surfaces 90 of combustion
chamber 26.
[0035] Energy transfer to the reactants can be accomplished by
indirect radiation in systems and methods according to the
disclosed subject matter. Using coal as the fuel source, if the
walls of one or more tubes 75 operate at 1200K and the coal
particles are about 20 micron and remain cold due to endothermic
reactions, e.g., particle surface temperature is approximately
500K, the energy transfer to the particle via radiation can be
about 100 kW/m2. The transfer of this energy can result in a 20
micron spherical coal particle completely reacting on the order
0.5-1.0 seconds. Therefore, it is possible to transfer enough
energy to sustain the gasification reaction, which was assumed to
need about 150 kJ/mol with reasonable particle residence times.
These residence times are roughly the same as that observed in
conventional coal gasifiers.
[0036] When operating with coal, slagging issues can be at least
partially addressed orienting gasification chamber 76 in a
particular manner. For example, if the ash fusion temperature is
below 1000 degrees Celsius, gasification chamber 76 can be designed
in a vertical configuration to allow slag to run down the walls.
However, most coals can have ash fusion temperatures well above
1000 degrees Celsius. If this is the case, although ash deposition
on surfaces (not shown) of gasification chamber 76 can cause
problems, there are certain effects that will limit the amount of
ash that is deposited to the surfaces of one or more tubes 75.
First, since the walls are hot and the core gas is cold, a driving
force will push the particles (ash) toward the center (also known
as the Soret effect). Second, evaporation of volatiles off the coal
particle surface facing the hot wall of one or more tubes 75 can be
significantly faster than the evaporation of volatiles off the coal
particle surface facing the center. Therefore, there can be a
volume expansion of gases near the hot walls of one or more tubes
75 forcing the ash particles to the center.
[0037] Housing 72 can also include a carbon monoxide separator 100
and a hydrogen separator 102 for separating both carbon monoxide
and hydrogen from the process stream after it exits gasification
chamber 76. Carbon monoxide separator 100 generally includes a
polymeric membrane, ceramic membrane, filter, or other suitable
means. Hydrogen separator 102 is typically a palladium membrane or
similar. Pressure swing absorption can also be used to separate
hydrogen from the process stream.
[0038] In the embodiment illustrated in FIG. 2, gasification
chamber 76 is in the form of tubes that extend through combustion
chamber 74. However, although not illustrated, in other
embodiments, the combustion chamber can include at least one tube
that extends through the gasification chamber.
[0039] Referring now to FIG. 3, another aspect of the disclosed
subject matter is a method 200 for gasifying a fuel source. The
fuel source can be combustible materials such as, but not limited
to, coal, biomass, and/or other combustible materials selected by
those skilled in the art. For example, biomass such as, but not
limited to, leaves, garden wastes, wood chips, waste paper,
municipal solid wastes, agricultural waste (e.g., switch grass,
wheat straw, etc.), animal wastes (e.g., chicken, cow, sheep, dog,
etc. litter), treated sewage sludge, grease, waste oils, and/or
other combustible biomass.
[0040] In some embodiments, the fuel source utilized is coal. For a
process stream including a mixture of coal and water, the mixture
can be gasified in a gasification chamber according to reaction
[1]:
C+H.sub.2OCO+H.sub.2 [1]
[0041] Reaction [1] involves reforming carbon by steam and can be
referred to as a steam reforming (SR) reaction. In order to gain
the benefits related to catalytic conversion, which are discussed
later, systems and methods of the disclosed subject matter include
SR reactions that are carried out at temperatures of less than 1000
degrees Celsius. For example, the SR reaction can be carried out at
temperatures between 600-1000 degrees Celsius. Alternatively, the
SR reaction can be carried out at temperatures between 700-900
degrees Celsius. More particularly, the SR reaction can be carried
out at temperatures between 800-850 degrees Celsius.
[0042] At 210, a determination is made whether to mix a portion of
water with the fuel source before gasifying the fuel source. If
water is added, the method continues at 212 where the water is
mixed with the fuel source to develop a process stream 214. If coal
is selected as the fuel source, any suitable ratio of water to coal
can be utilized. For example, water can be mixed with coal at a
particular ratio to obtain a slurry having a suitable viscosity. In
some embodiments, a viscosity of from about 20 centipoises to about
500 centipoises can be utilized. In certain embodiments, a
viscosity of from about 100 to 200 centipoises can be utilized.
Water can also be mixed with coal at a particular ratio to obtain a
desired energy conversion efficiency. Water can also be mixed with
coal at a particular ratio to obtain a desired syngas output
capacity. Coal particle size ranging from approximately 20 .mu.m to
250 .mu.m can be utilized. As discussed in greater detail below
with respect to the simulation results, typically, the portion of
water is mixed with the fuel source so that a water to fuel source
ratio ranges from about 0.7 to about 1.0. At 216, process stream
214 is gasified in a first chamber. A primary heat source 218,
which is discussed further below, is generally applied to the first
chamber to carry out the gasification process.
[0043] After gasification, process stream 214 generally contains
one or more product gases, including carbon monoxide and hydrogen,
particulate matter including ash, impurities, and/or unreacted fuel
source, e.g., coal, and water. At 220, hydrogen is separated from
process stream 214. A portion of the hydrogen can be used to
generate a consumable energy such as, but not limited to,
electricity. At 222, particulate matter is separated from a
hydrogen-depleted process stream 214. At 224, water is separated
from a hydrogen and particulate matter depleted process stream 214.
A separated water stream 226 can then optionally be mixed with the
fuel source at 212 and gasified at 216.
[0044] At 228, process stream 214, which primarily includes carbon
monoxide, is divided according to predetermined ratios. Optionally,
process stream 214 can be further processed before to refine the
carbon monoxide present in the stream prior to division of the
stream.
[0045] A first portion 230 is divided from process stream 214 and
forwarded to an energy producing process such as, but not limited
to, a SOFC at 232 to produce consumable energy such as, but not
limited to, electricity and sequestration-ready carbon dioxide.
However, any suitable power-generating systems can be utilized in
systems and methods according to the disclosed subject matter, as
will be readily apparent to one of ordinary skill in the art. The
remaining portion of process stream 214, a second portion 234, can
be mixed at 236 with a predetermined amount of oxygen 238. In some
embodiments, second portion 234 of the carbon monoxide is generally
about 20 to about 60 percent of the carbon monoxide contained in
the process stream. In another embodiment, second portion 234 of
the carbon monoxide is generally about 30 to about 50 percent of
the carbon monoxide contained in the process stream.
[0046] At 240, at least a portion of second portion 234, which can
include a portion of oxygen 238, is combusted in a second chamber
in the presence of one or more catalysts to generate a heat energy
242. In an embodiment where coal is selected as the fuel source,
the catalytic combustion reaction can be represented by reaction
[2]:
2CO+O.sub.22CO.sub.2. [2]
[0047] Heat energy 242 is generally indirectly applied from the
second chamber to the first chamber as primary heat source 218 to
gasify process stream 214. It is preferred that the gasification of
second portion 234 is substantially driven from heat energy 242,
which is generated from combusting at least a portion of the one or
more product gases, which generally include carbon monoxide, in the
presence of one or more catalysts. A maximum temperature while
combusting second portion 234, which includes one or more product
gases, is about 1300 degrees Celsius.
[0048] Carbon dioxide 244 is typically generated while combusting
at least a portion of the one or more product gases, e.g., second
portion 234. The carbon dioxide that is generated can be
sequestration-ready. At least a portion of carbon dioxide 244 can
be recycled by gasifying it with process stream 214. Alternately,
hydrogen can be recycled and catalytically combusted with air to
provide the required heat without carbon dioxide generation.
[0049] Using a personal computer, simulations of the systems and
methods of the disclosed subject matter have been performed using a
simulator application sold under the 5 trademark ASPEN. Flow sheets
were programmed to study the effect of changing the water to carbon
molar ratio (S/C) and the effect of the amount of or percentage by
weight of carbon dioxide generated in equation [1] above that is
recycled into the gasification chamber (R). Similar to system 20 in
FIG. 1, the simulations utilized a gasification chamber, a
catalytic combustion chamber, and processes for separating carbon
monoxide and carbon dioxide. To simplify calculations, coal was
assumed to be a bituminous coal that does not contain sulfur or
generate ash. A moisture or water separator and a hydrogen
separator were combined as one unit and a cool down heat exchanger
was inserted between the gasification chamber and water/hydrogen
separator to drop the temperature from the gasification chamber
outlet to a typical temperature for a separation unit. The
water/hydrogen separator, carbon monoxide separator, and carbon
dioxide separator were modeled as ideal separators.
[0050] In the simulations described herein, hydrogen production
rate (kg/hr) and energy (MJ/hr) were calculated as a function of
the relative amount of carbon monoxide recycled to the catalytic
combustion chamber versus the SOFC (COR). For example, if 40
percent by weight of the carbon dioxide generated in equation [1]
is recycled to the catalytic combustion chamber, the COR=0.4.
[0051] Simulation 1: No recycling of carbon dioxide to catalytic
combustion chamber (R=0). In this first simulation, equal molar
amounts of water and C were fed into the gasification chamber
(i.e., S/C=1.0) and the amount of carbon dioxide recycled to the
catalytic combustion chamber was set to zero (i.e., R=0). As shown
in FIG. 4, hydrogen production rate remains constant at about 0.84
kg/hr for 0.5 kmol/hr of coal regardless of the COR value. The
energy required to run the gasification chamber exceeds the energy
generated by the catalytic combustion chamber if not enough carbon
monoxide is recycled to the catalytic combustion chamber. The
results show that about 48% of the carbon monoxide generated by
reaction [1] above can be sent to the catalytic combustion chamber
(versus 52% to the SOFC) to run the gasification chamber without
additional energy. Analysis shows that from the 52% carbon monoxide
provided to the SOFC, about 13.5 kW of electricity can be generated
by a typical SOFC from one kmol of coal. This translates to about
1,000,000 kd/day of hydrogen produced assuming a 100 MWe SOFC
utilizing about 50% of the carbon monoxide generated by equation
[1] in the gasification chamber.
[0052] Simulation 2: 25 percent of carbon dioxide recycled to
catalytic combustion chamber (R=0.25). One option available in the
systems and methods of the disclosed subject matter is the
possibility of recycling a portion of the carbon dioxide that is
produced in the catalytic combustion chamber to the gasification
chamber. As shown in FIG. 5, if 25% of the carbon dioxide is
recycled to the gasification chamber, more hydrogen is produced as
compared to when 0% carbon dioxide is recycled to the gasification
chamber. Moreover, less carbon monoxide needs to be recycled to the
catalytic combustion chamber to generate enough power to run the
gasification chamber without additional input of energy.
[0053] Simulation 3: 50 percent of carbon dioxide recycled to
catalytic combustion chamber (R=0.5). Referring now to FIG. 6, if
50% of the carbon dioxide is recycled to the gasification chamber,
more hydrogen is produced at low carbon monoxide recycle ratios,
but rapidly decreases to value below that of R=0 and R=0.25 as COR
increases. Moreover, even less carbon monoxide needs to be recycled
to the catalytic combustion chamber than R=0.25 to allow the
catalytic combustion chamber to generate enough power to run the
gasification chamber without additional input of energy.
[0054] Without being bound by theory, the following reactions shown
in Table 1 along with the enthalpies of each reaction can be
considered to understand the results of the simulation between R=0,
R=0.25, and R=0.5 for S/C=1.0.
TABLE-US-00001 TABLE 1 Primary reactions taking place in the
gasification chamber Name of Reaction Reaction .DELTA.H (kJ/mol)
Steam Reforming (SR) C + H.sub.2O CO + H.sub.2 +175 Boudouard C +
CO.sub.2 2CO +173 Water-Gas Shift (WGS) CO + H CO.sub.2 + H.sub.2
-41 Methanation 2C + 2H.sub.2O CH.sub.4 + CO.sub.2 +105
[0055] Referring now to FIG. 7, in the absence of carbon dioxide
recycle to the gasification chamber, SR reaction is the primary
reaction taking place although some methanation reaction occurs.
The amount of methane and water generally remains constant. This
can be because the temperature of the reformer is fixed and
additional heat generated or required factors into the heat balance
calculations. Hence, the reactions occurring in the gasification
chamber do not change with varying amounts of carbon monoxide in
the catalytic combustion chamber.
[0056] However, with the introduction of carbon dioxide into the
gasification chamber, the Boudouard reaction, which has a slightly
lower enthalpy of reaction than the SR reaction, appears to be
favored. The Boudouard reaction generates two carbon monoxide
molecules for each carbon (coal) molecule reacted with carbon
dioxide. The carbon monoxide can then be shifted to hydrogen by the
WGS reaction, which is exothermic and, hence, more efficient than
the SR reaction, which can explain the lower energies requirement
observed for the same amount of carbon monoxide supplied to the
combustion chamber with increasing values of R (see FIG. 6). An
overall reduction for energy required in the gasification chamber
can also allow more yield of hydrogen.
[0057] As shown in FIG. 7, less methane is produced when R=0.25 as
compared to R=zero. Particularly, at about carbon monoxide split
ratios of 0.4 and greater, a condition is achieved where methane
production is effectively zero whereas water production increases
even faster. FIG. 5 shows that the maximum hydrogen production
occurs at COR values of about 0.4 and 0.5. This occurs because at
COR values greater than about 0.4, additional carbon dioxide begins
to hinder the WGS reaction as water production dramatically
increases and hydrogen production decreases.
[0058] Referring again to FIG. 6, the effect of increasing the
carbon dioxide recycle ratio to 0.5 for S/C=1.0 is illustrated.
Free hydrogen decreases more rapidly than R=0.25 because, as
discussed above, the concentration of carbon dioxide into the
gasification chamber increases twice as fast compared to the case
of 25% recycle. For this scenario, although the COR is less for the
catalytic combustion chamber to operate the gasification chamber,
the amount of hydrogen generated is less than the 25% recycled
case, but still more than the baseline. If the amount of hydrogen
produced is less important than the amount of energy needed, then
opting for a 50% carbon dioxide recycle can enable the generation
of about 30% more power compared to 25% recycle with a 10% less
hydrogen production. For example, if the objective is to generate
clean power by combusting the carbon monoxide and hydrogen in an
Integrated Gasification Combined Cycle (IGCC) configuration, then a
50% carbon dioxide recycle is likely desired. If, however, the
objective is to generate large amounts of hydrogen for distribution
or fuel cell applications, then a carbon dioxide recycle of 25% is
likely desired.
[0059] Simulation 4: Relative ratio of water to coal supplied to
the gasification chamber (S/C=0.7, 1.0, and 1.5). FIG. 8
illustrates the results of various S/C values for a 25% carbon
dioxide recycle (R=0.25). Of the conditions investigated, S/C=1.5
gave the highest hydrogen generation rates. The amount of carbon
monoxide to be recycled to the catalytic combustion chamber (i.e.,
COR value) was the same as that of the results obtained for S/C=1.0
and R=zero (see FIG. 4) with nearly 37% more hydrogen production.
Conversely, compared to S/C=1.0 and R=0.25, about 15% more hydrogen
can be generated while using about 10% more carbon monoxide for
combustion.
[0060] Still referring to FIG. 8, a steam to carbon ratio of 0.7 is
the least favorable from an energy requirement and hydrogen
production standpoint. Effectively, enough steam may not exist to
generate significant amounts of hydrogen and the major gasification
reaction occurring is the Boudouard reaction. It is, however, very
energy efficient. Hence, if the goal is to gasify carbon for energy
generation, then low S/C values with high R values are generally
desired.
[0061] For S/C ratio of greater than 1.0, a slipstream of product
carbon monoxide can be shifted to carbon dioxide+hydrogen via the
WGS reaction in a downstream shift reactor with the excess water
(above the 1-1 water/carbon molar ratio). The hydrogen can be
diffused away leaving a carbon dioxide stream, which can be
combined with the upstream for sequestration.
[0062] Systems and methods according to the disclosed subject
matter include indirectly heating the reactor to provide the
necessary heat in an entrained flow configuration, e.g., coal,
biosolids, and/or steam and/or carbon dioxide, using heat from a
form of catalytic combustion. Patent catalytic partial oxidation of
the coal or biosolids is accomplished using reaction path, whereby
a recycled product gas, e.g., carbon monoxide, is catalytically
oxidized to produce the necessary heat to produce the product
gases.
[0063] Direct catalytic partial oxidation of a solid feedstock,
i.e., coal or biosolids, is generally not feasible. In order to
catalytically combust solid carbon, a reaction path in which some
product gas from an endothermic reaction such as, but not limited
to, the Buodouard reaction, CO.sub.2+C-2CO is catalytically
combusted(CO+1/2CO.sub.2+catalyst-CO.sub.2+heat) to drive the
endothermic reaction, yielding catalytic partial oxidation of the
solid feedstock, i.e., C(solid)+1/2O.sub.2+catalyst-CO.
[0064] In addition, the geometry of at least one system according
to the disclosed subject matter, which produces a high
surface/volume ratio, maximizes the heat transfer between the
combustor and the gasification reactor, and lends itself to not
only large scale power generation, but also to mass produced small
scale gasification systems including even micro reactor gasifiers.
Systems according to the disclosed subject matter are suited for
modular configurations and can be part of a biorefinery when
biomass is used as the feedstock. Systems according to the
disclosed subject matter allow for easier adjustment of the
operating parameters for differing feedstock's than in a
conventional oxygen or air blown gasifier, which cannot be utilized
effectively for certain biomass feedstock.
[0065] Systems and methods according to the disclosed subject
matter can produce a sequestration ready stream of carbon dioxide,
separate from the product gases. In a conventional oxygen blow
gasifier, there is typically a portion of carbon dioxide mixed with
the product gases.
[0066] Systems and methods according to the disclosed subject
matter provide a gasification process that generates hydrogen and
carbon monoxide, which can be used to produce consumable energy
such as, but not limited to, electricity. In addition, carbon
monoxide generated during the gasification of coal can be
partitioned so that a portion of the carbon monoxide is utilized to
drive the gasification reaction. Moreover, only one fuel source,
e.g., coal or a biomass, is required to produce both the hydrogen
and the heat needed to drive the system, thereby eliminating or
reducing the need for secondary fuel sources, such as, but not
limited to, methane and the like, to provide the necessary heat to
drive the gasification reaction.
[0067] As described above, systems and methods according to the
disclosed subject matter can provide a unique reactor design that
can operate at sufficiently low and uniform temperatures due to
catalytic oxidation of product gases and allow the use of
conventional materials and technologies in various processes of the
present application, such as, but not limited to, hydrogen
separation.
[0068] Moreover, systems and methods of the disclosed subject
matter allow a wide variation in product gas composition to be
obtained in a controlled fashion. Regardless of the product gas
composition, separate sequestration ready carbon dioxide stream can
be produced.
[0069] In addition, systems and methods of the disclosed subject
matter require less oxygen to obtain specific hydrogen/carbon
monoxide ratios in the product gases than in conventional single
stage oxygen blown gasifier due to the catalytic combustion of the
product gases.
[0070] Systems and methods of the disclosed subject matter allow
improved plant efficiencies over standard gasification techniques.
For example, economic gasification of low rank high moisture coals
that have maximum dry solids contents of around 50% is likely
possible.
[0071] Systems and methods of the disclosed subject matter can be
produced in multiple small units as well as large central plants
because heat transfer properties can be enhanced at small scales.
As a result, a wide range of economical applications such as, but
not limited to, a bench top operation are possible.
[0072] Catalytic combustion of carbon monoxide to carbon dioxide or
hydrogen to water using air or oxygen provides several benefits.
For example, utilizing catalysis to achieve the conversion of
carbon monoxide to carbon dioxide and energy utilizing catalysis
can allow the systems and methods of the disclosed subject matter
to 1) operate outside homogeneous flammability regimes, 2) generate
heat on the surface of the catalyst (as opposed to the gas phase),
and 3) produce little or no emission gases.
[0073] First, the ability of the catalyst to operate outside the
flammability regime normally needed by homogeneous systems allows
for thermal efficiency gains. For example, to maintain a stable
homogenous flame, temperatures near 2000 degrees Celsius are
typically needed. However, combustion and heat transfer materials
generally cannot withstand temperatures greater than 1250 degrees
Celsius and usually are required to be kept below 1000 degrees
Celsius. This necessitates the use of secondary (dilution) air to
cool the combustion products to temperatures that the heat
exchanger materials can withstand which results in one direct loss
of efficiency.
[0074] Second, the ability of the catalyst generate heat on its
surface during the carbon monoxide to carbon dioxide conversion
allows for efficient heat transfer to the gasification reaction.
The heterogeneous reaction requires one or both of the reactants to
be adsorbed on the surface of the catalyst. In the case of carbon
monoxide oxidation, carbon monoxide molecule is strongly adsorbed
to the catalyst surface, which then reacts with oxygen to generate
carbon dioxide. During this reaction, there is a heat release on
the surface of the catalyst, which is transferred to the
gasification reaction. FIG. 9 shows a conceptual depiction of the
systems and methods of the disclosed subject matter where the heat
release can occur on the catalyst. Referring now to FIG. 10, this
is contrasted with conventional indirectly heated homogeneous
gasification systems that are known in the prior art, where the
heat release can occur in the bulk.
[0075] The heat transfer across the catalyst support and the metal
substrate can be nearly 1000 times faster than the heat transfer
that occurs across the momentum boundary layer. Calculations
indicate that the primary mechanism of heat transfer from the metal
surface to the gasification reaction likely occurs via radiation.
The coal particles, which can be considered a black body, can be
maintained at a temperature close to that of the gasification
reaction conditions, i.e., approximately 600K, while the surface of
the metal substrate can be nearly 1200K. Hence, there can be a
considerable driving force for radiative heat transfer.
[0076] This is in contrast to the homogeneous system where the heat
release is in the bulk flow of the combustion side. In that case,
the heat must be transferred through the momentum boundary layer,
then through the metal heat exchanger, and finally into the
gasification reaction. This is a much slower and less efficient
process.
[0077] Systems and methods according to the disclosed subject
differ from fixed bed, fluidized bed, and multi-stage gasifiers.
For example, simulation of a conventional single stage entrained
flow gasifier with the same feed conditions produces slightly less
than 0.7 kg/hr and requires twice as much oxygen as compared to
Simulation 1 above. In addition, there is about 15% carbon dioxide
in the conventional gasifier product stream as compared to about
1.5% carbon dioxide in Simulation 1 above. Because of the reduced
oxygen requirements of the systems and methods according to the
disclosed subject, economic gasification of low rank coals with
high moisture contents can be feasible.
[0078] The ability of systems and methods according to the
disclosed subject to operate the carbon monoxide combustion
reaction at near stoichiometric conditions allows conversion of the
carbon monoxide to carbon dioxide to occur with minimum dilution of
nitrogen if air is used. If oxygen is used from an air separation
unit, this can permit minimum oxygen usage with no need for excess
oxygen. Therefore, the air separation unit can be properly sized to
supply just the right amount of oxygen.
[0079] It has also been shown that catalytic combustion likely has
the ability to interrupt NOx formation pathways and not allow
carbon based emissions, such as, but not limited to, carbon
monoxide and unburned hydrocarbons (UHC) to be released. Therefore,
for embodiments according to the disclosed subject matter where
oxygen is used to combust the carbon monoxide to carbon dioxide, it
is likely that there will be no gas phase emissions. This is in
contrast to a homogeneous system where NOx, especially thermal and
fuel bound NOx, are routinely formed.
[0080] Systems and methods according to the disclosed subject
matter can be up or down due to their catalytic nature. Systems and
methods according to the disclosed subject matter can scale with
gas velocity because the heat transfer aspects (i.e. radiation) can
be very insensitive to geometric scaling parameters. Scalability
can be done in at least two ways. First, systems according to the
disclosed subject matter can be replicated many times over,
effecting economies of mass production. Second, systems according
to the disclosed subject matter can also be scaled up in the
traditional sense. This is likely easier than scaling up other
types of systems where heat loss must be considered.
[0081] Systems and methods according to the disclosed subject
matter offer a modular design. Modular designs allow for rapid
development cycles and the ability to swap modules in and out upon
technological advances. Incremental construction of energy
conversion facilities, and therefore incremental investment, can
open the door for groups like developing nations who are excluded
in the case of single large-scale investments. Higher reliability
can result from the use of systems in which the failing of one
component among thousands has a negligible effect. Modular scaling
can allow for a flexible response to shortages. The development of
automated controls and maintenance systems can provide efficient
responses in these areas, as well as in standard operation. Central
housing in large plants can be effective in applying the modular
approach. Less materials, controls, and operation and maintenance
can be required than an equivalent energy output from a number of
dispersed modules and the central plant can have an enhanced
flexibility to respond to changes. Individual units can include
fuel-conditioning models, which, for example, can convert coal,
coal slurries, biomass, or orimulsion into a syngas. Upstream units
can prepare the input fuel; downstream energy conversion units can
combust or electrochemically generate electric power. Other units
can be designed to create specialty fuels like methanol, ultra
clean Fischer Trospch diesel, or hydrogen.
[0082] Catalyst science has not evolved to the point where an
a-priori prediction about performance of a given formulation can be
given. Therefore, it is a benefit of the systems and methods of the
disclosed subject matter that they can be easily and cheaply
modified to accept new formulations as they are being developed. A
modular approach can afford this in two significant ways. First, as
the reactor train is being moved from an exhausted part of the tar
sand field to a more fertile one, new catalysts can be quickly and
easily installed, thus adding little, if any, downtime to the
transfer. Second, as new formulations are being developed, they can
be tested in-situ and compared directly against the ones already in
operation. If the new catalysts yield different product
compositions, in the overall system operation, this will not amount
to a significant change in ultimate product quality.
[0083] Because catalytic systems are like living systems, their
performance changes with time. One can develop a startup scheme
where a bank of a given number of units is initially brought on
line to satisfy a given demand. As those units age, new units can
continuously be brought on line without having to bring the entire
system offline. Therefore, there can be a continuous replacement
scheme of these reactors with the net production being
unchanged.
[0084] Although the disclosed subject matter has been described and
illustrated with respect to embodiments thereof, it should be
understood by those skilled in the art that features of the
disclosed embodiments can be combined, rearranged, etc., to produce
additional embodiments within the scope of the invention, and that
various other changes, omissions, and additions may be made therein
and thereto, without parting from the spirit and scope of the
present application.
* * * * *