U.S. patent application number 14/207688 was filed with the patent office on 2014-09-18 for integrated power generation and carbon capture using fuel cells.
This patent application is currently assigned to EXXONMOBIL RESEARCH AND ENGINEERING COMPANY. The applicant listed for this patent is Timothy Andrew Barckholtz, Paul J. Berlowitz, Frank H. Hershkowitz. Invention is credited to Timothy Andrew Barckholtz, Paul J. Berlowitz, Frank H. Hershkowitz.
Application Number | 20140272618 14/207688 |
Document ID | / |
Family ID | 50397350 |
Filed Date | 2014-09-18 |
United States Patent
Application |
20140272618 |
Kind Code |
A1 |
Berlowitz; Paul J. ; et
al. |
September 18, 2014 |
INTEGRATED POWER GENERATION AND CARBON CAPTURE USING FUEL CELLS
Abstract
Systems and methods are provided for capturing CO.sub.2 from a
combustion source using molten carbonate fuel cells (MCFCs). The
fuel cells are operated to have a reduced anode fuel utilization.
Optionally, at least a portion of the anode exhaust is recycled for
use as a fuel for the combustion source. Optionally, a second
portion of the anode exhaust is recycled for use as part of an
anode input stream. This can allow for a reduction in the amount of
fuel cell area required for separating CO.sub.2 from the combustion
source exhaust and/or modifications in how the fuel cells are
operated.
Inventors: |
Berlowitz; Paul J.; (Glen
Gardner, NJ) ; Barckholtz; Timothy Andrew;
(Whitehouse Station, NJ) ; Hershkowitz; Frank H.;
(Basking Ridge, NJ) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Berlowitz; Paul J.
Barckholtz; Timothy Andrew
Hershkowitz; Frank H. |
Glen Gardner
Whitehouse Station
Basking Ridge |
NJ
NJ
NJ |
US
US
US |
|
|
Assignee: |
EXXONMOBIL RESEARCH AND ENGINEERING
COMPANY
Annandale
NJ
|
Family ID: |
50397350 |
Appl. No.: |
14/207688 |
Filed: |
March 13, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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61788628 |
Mar 15, 2013 |
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61787587 |
Mar 15, 2013 |
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61787697 |
Mar 15, 2013 |
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61787879 |
Mar 15, 2013 |
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61884376 |
Sep 30, 2013 |
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61884545 |
Sep 30, 2013 |
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61884565 |
Sep 30, 2013 |
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61884586 |
Sep 30, 2013 |
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61884605 |
Sep 30, 2013 |
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61884635 |
Sep 30, 2013 |
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61889757 |
Oct 11, 2013 |
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Current U.S.
Class: |
429/410 |
Current CPC
Class: |
C01B 3/16 20130101; C21B
2300/02 20130101; C01B 2203/1247 20130101; H01M 2250/407 20130101;
C01B 2203/0233 20130101; C10G 2/332 20130101; Y02B 90/10 20130101;
H01M 8/04097 20130101; H01M 2008/147 20130101; Y02P 30/00 20151101;
C01B 2203/0405 20130101; C01B 2203/0475 20130101; C01B 2203/066
20130101; H01M 8/04156 20130101; H01M 8/06 20130101; C01B 3/48
20130101; C07C 1/0485 20130101; F02C 3/22 20130101; H01M 8/145
20130101; C01B 2203/02 20130101; C04B 2290/20 20130101; C07C
29/1518 20130101; Y02E 20/14 20130101; C25B 3/02 20130101; C04B
7/367 20130101; H01M 8/04761 20130101; H01M 8/0668 20130101; Y02E
50/10 20130101; C07C 29/152 20130101; C01B 3/50 20130101; C01B
2203/061 20130101; H01M 8/04805 20130101; Y02P 70/50 20151101; C01B
2203/0205 20130101; C01B 2203/0227 20130101; C01C 1/04 20130101;
Y02T 10/12 20130101; C01B 2203/067 20130101; Y02E 20/18 20130101;
C01B 2203/1241 20130101; H01M 8/0687 20130101; H01M 8/0612
20130101; Y02E 20/16 20130101; C01B 2203/046 20130101; C01B
2203/1205 20130101; H01M 8/04 20130101; H01M 8/14 20130101; H01M
8/0637 20130101; H01M 8/0662 20130101; Y02P 10/122 20151101; F02C
6/18 20130101; Y02P 20/129 20151101; C01B 2203/148 20130101; C10G
2/32 20130101; H01M 2250/10 20130101; H01M 2300/0051 20130101; Y02P
20/10 20151101; H01M 8/04014 20130101; C01B 2203/0283 20130101;
C01B 2203/0495 20130101; C01B 2203/00 20130101; C01B 2203/84
20130101; H01M 8/04111 20130101; H01M 8/0631 20130101; H01M 8/0693
20130101; H01M 8/0618 20130101; C01B 2203/062 20130101; C10G 2/34
20130101; H01M 8/04843 20130101; H01M 8/0625 20130101; H01M 8/141
20130101; C01B 2203/86 20130101; C21B 15/00 20130101; H01M 2250/405
20130101; Y02E 60/50 20130101; C01B 3/34 20130101; C01B 2203/068
20130101; C10K 3/04 20130101; C01B 2203/04 20130101; C01B 2203/0415
20130101; Y02P 30/20 20151101 |
Class at
Publication: |
429/410 |
International
Class: |
H01M 8/06 20060101
H01M008/06; H01M 8/14 20060101 H01M008/14 |
Claims
1. A method for capturing carbon dioxide from a combustion source,
the method comprising: introducing a fuel stream and an
O.sub.2-containing stream into a combustion zone; performing a
combustion reaction in the combustion zone to generate a combustion
exhaust, the combustion exhaust comprising CO.sub.2; processing a
cathode inlet stream, the cathode inlet stream comprising at least
a first portion of the combustion exhaust, with a fuel cell array
of one or more molten carbonate fuel cells to form a cathode
exhaust stream from at least one cathode outlet of the fuel cell
array, the one or more molten carbonate fuel cells comprising one
or more fuel cell anodes and one or more fuel cell cathodes, the
one or more molten carbonate fuel cells being operatively connected
to the combustion zone through at least one cathode inlet; reacting
carbonate from the one or more fuel cell cathodes with H.sub.2
within the one or more fuel cell anodes to produce electricity and
an anode exhaust stream from at least one anode outlet of the fuel
cell array, the anode exhaust steam comprising CO.sub.2 and
H.sub.2; separating CO.sub.2 from the anode exhaust stream in one
or more separation stages to form a CO.sub.2-depleted anode exhaust
stream; passing at least a combustion-recycle portion of the
CO.sub.2-depleted anode exhaust stream to the combustion zone; and
recycling at least an anode-recycle portion of the
CO.sub.2-depleted anode exhaust stream to the one or more fuel cell
anodes.
2. The method of claim 1, wherein a fuel utilization in the one or
more fuel cell anodes is about 65% or less.
3. The method of claim 2, wherein the fuel utilization in the one
or more fuel cell anodes is about 30% to about 50%.
4. The method of claim 2, wherein the one or more fuel cell anodes
comprise a plurality of anode stages and the one or more fuel cell
cathodes comprise a plurality of cathode stages, wherein a fuel
utilization in a low utilization anode stage in the plurality of
anode stages is about 65% or less, the low utilization anode stage
corresponding to high CO.sub.2-content cathode stage of the
plurality of cathode stages, the high CO.sub.2-content cathode
stage having a CO.sub.2 content at a cathode inlet as high as or
higher than a CO.sub.2 content at a cathode inlet of any other
cathode stage of the plurality of cathode stages.
5. The method of claim 4, wherein the fuel utilization in the low
utilization anode stage is at least about 40%.
6. The method of claim 4, wherein a fuel utilization in each anode
stage of the plurality of anode stages is about 65% or less.
7. The method of claim 1, wherein the combustion-recycle portion of
the CO.sub.2-depleted anode exhaust stream comprises at least about
25% of the CO.sub.2-depleted anode exhaust stream, and wherein the
anode-recycle portion of the CO.sub.2-depleted anode exhaust stream
comprises at least about 25% of the CO.sub.2-depleted anode exhaust
stream.
8. The method of claim 7, further comprising passing
carbon-containing fuel into the one or more fuel cell anodes.
9. The method of claim 8, further comprising: reforming at least a
portion of the carbon-containing fuel to generate H.sub.2; and
passing at least a portion of the generated H.sub.2 into the one or
more fuel cell anodes.
10. The method of claim 8, wherein the carbon-containing fuel is
passed into the one or more fuel cell anodes without passing the
carbon-containing fuel into a reforming stage prior to entering the
one or more fuel cell anodes.
11. The method of claim 8, wherein the carbon-containing fuel
comprises CH.sub.4.
12. The method of claim 1, wherein the combustion exhaust comprises
about 10 vol % or less of CO.sub.2, the combustion exhaust
comprising CO.sub.2 optionally comprising at least about 4 vol % of
CO.sub.2.
13. The method of claim 1, further comprising recycling a second
portion of the combustion exhaust to the combustion zone, the
second portion of the combustion exhaust comprising CO.sub.2.
14. The method of claim 13, wherein recycling the second portion of
the combustion exhaust to the combustion zone comprises: exchanging
heat between a second portion of the combustion exhaust and an
H.sub.2O-containing stream to form steam; separating water from the
second portion of the combustion exhaust to form an
H.sub.2O-depleted combustion exhaust stream; and passing at least a
portion of the H.sub.2O-depleted combustion exhaust into the
combustion zone.
15. The method of claim 13, wherein the second portion of the
combustion exhaust comprises at least about 6 vol % CO.sub.2.
16. The method of claim 1, wherein the anode exhaust stream, prior
to the separating CO.sub.2 from the anode exhaust stream in one or
more separation stages, comprises at least about 5.0 vol % of
H.sub.2.
17. The method of claim 1, further comprising exposing the anode
exhaust stream to a water gas shift catalyst to form a shifted
anode exhaust stream prior to the separating CO.sub.2 from the
anode exhaust stream in one or more separation stages, a H.sub.2
content of the shifted anode exhaust stream after exposure to the
water gas shift catalyst being greater than a H.sub.2 content of
the anode exhaust stream prior to exposure to the water gas shift
catalyst.
18. The method of claim 1, wherein the combustion-recycle portion
of the CO.sub.2-depleted anode exhaust stream is combined with the
fuel stream prior to passing the combustion-recycle portion of the
CO.sub.2-depleted anode exhaust stream to the combustion zone.
19. The method of claim 1, wherein a cathode exhaust stream has a
CO.sub.2 content of about 2.0 vol % or less.
20. The method of claim 1, wherein separating CO.sub.2 from the
anode exhaust stream in one or more separation stages comprises
cooling the anode exhaust stream to form a condensed phase of
CO.sub.2.
21. The method of claim 20, wherein separating CO.sub.2 from the
anode exhaust stream in one or more separation stages further
comprises separating water from the anode exhaust stream prior to
forming the condensed phase of CO.sub.2.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Ser. Nos.
61/787,587, 61/787,697, 61/787,879, and 61/788,628, all filed on
Mar. 15, 2013, each of which is incorporated by reference herein in
its entirety. This application also claims the benefit of U.S. Ser.
Nos. 61/884,376, 61/884,545, 61/884,565, 61/884,586, 61/884,605,
and 61/884,635, all filed on Sep. 30, 2013, each of which is
incorporated by reference herein in its entirety. This application
further claims the benefit of U.S. Ser. No. 61/889,757, filed on
Oct. 11, 2013, which is incorporated by reference herein in its
entirety.
[0002] This application is related to 25 other co-pending U.S.
applications, filed on even date herewith, and identified by the
following Attorney Docket numbers and titles: 2013EM104-US2
entitled "Integrated Power Generation and Carbon Capture using Fuel
Cells"; 2013EM104-US3 entitled "Integrated Power Generation and
Carbon Capture using Fuel Cells"; 2013EM107-US2 entitled
"Integrated Power Generation and Carbon Capture using Fuel Cells";
2013EM108-US2 entitled "Integrated Power Generation and Carbon
Capture using Fuel Cells"; 2013EM108-US3 entitled "Integrated Power
Generation and Carbon Capture using Fuel Cells"; 2013EM109-US2
entitled "Integrated Power Generation and Carbon Capture using Fuel
Cells"; 2013EM109-US3 entitled "Integrated Power Generation and
Carbon Capture using Fuel Cells"; 2013EM272-US2 entitled
"Integrated Power Generation and Chemical Production using Fuel
Cells"; 2013EM273-US2 entitled "Integrated Power Generation and
Chemical Production using Fuel Cells at a Reduced Electrical
Efficiency"; 2013EM274-US2 entitled "Integrated Power Generation
and Chemical Production using Fuel Cells"; 2013EM277-US2 entitled
"Integrated Power Generation and Chemical Production using Fuel
Cells"; 2013EM278-US2 entitled "Integrated Carbon Capture and
Chemical Production using Fuel Cells"; 2013EM279-US2 entitled
"Integrated Power Generation and Chemical Production using Fuel
Cells"; 2013EM285-US2 entitled "Integrated Operation of Molten
Carbonate Fuel Cells"; 2014EM047-US entitled "Mitigation of NOx in
Integrated Power Production"; 2014EM048-US entitled "Integrated
Power Generation using Molten Carbonate Fuel Cells"; 2014EM049-US
entitled "Integrated of Molten Carbonate Fuel Cells in
Fischer-Tropsch Synthesis"; 2014EM050-US entitled "Integrated of
Molten Carbonate Fuel Cells in Fischer-Tropsch Synthesis";
2014EM051-US entitled "Integrated of Molten Carbonate Fuel Cells in
Fischer-Tropsch Synthesis"; 2014EM052-US entitled "Integrated of
Molten Carbonate Fuel Cells in Methanol Synthesis"; 2014EM053-US
entitled "Integrated of Molten Carbonate Fuel Cells in a Refinery
Setting"; 2014EM054-US entitled "Integrated of Molten Carbonate
Fuel Cells for Synthesis of Nitrogen Compounds"; 2014EM055-US
entitled "Integrated of Molten Carbonate Fuel Cells with
Fermentation Processes"; 2014EM056-US entitled "Integrated of
Molten Carbonate Fuel Cells in Iron and Steel Processing"; and
2014EM057-US entitled "Integrated of Molten Carbonate Fuel Cells in
Cement Processing". Each of these co-pending U.S. applications is
hereby incorporated by reference herein in its entirety.
FIELD OF THE INVENTION
[0003] In various aspects, the invention is related to low emission
power production with separation and/or capture of resulting
emissions via integration of molten carbonate fuel cells with a
combustion power source.
BACKGROUND OF THE INVENTION
[0004] Capture of gases emitted from power plants is an area of
increasing interest. Power plants based on the combustion of fossil
fuels (such as petroleum, natural gas, or coal) generate carbon
dioxide as a by-product of the reaction. Historically this carbon
dioxide has been released into the atmosphere after combustion.
However, it is becoming increasingly desirable to identify ways to
find alternative uses for the carbon dioxide generated during
combustion.
[0005] One option for managing the carbon dioxide generated from a
combustion reaction is to use a capture process to separate the
CO.sub.2 from the other gases in the combustion exhaust. An example
of a traditional method for capturing carbon is passing the exhaust
stream through an amine scrubber. While an amine scrubber can be
effective for separating CO.sub.2 from an exhaust stream, there are
several disadvantages. In particular, energy is required to operate
the amine scrubber and/or modify the temperature and pressure of
the exhaust stream to be suitable for passing through an amine
scrubber. The energy required for CO.sub.2 separation reduces the
overall efficiency of the power generation process.
[0006] In order to offset the power required for CO.sub.2 capture,
one option is to use a molten carbonate fuel cell to assist in
CO.sub.2 separation. The fuel cell reactions that cause transport
of CO.sub.2 from the cathode portion of the fuel cell to the anode
portion of the fuel cell can also result in generation of
electricity. However, conventional combinations of a combustion
powered turbine or generator with fuel cells for carbon separation
have resulted in a net reduction in power generation efficiency per
unit of fuel consumed.
[0007] An article in the Journal of Fuel Cell Science and
Technology (G. Manzolini et. al., J. Fuel Cell Sci. and Tech., Vol.
9, February 2012) describes a power generation system that combines
a combustion power generator with molten carbonate fuel cells.
Various arrangements of fuel cells and operating parameters are
described. The combustion output from the combustion generator is
used in part as the input for the cathode of the fuel cell. This
input is supplemented with a recycled portion of the anode output
after passing through the anode output through a cryogenic CO.sub.2
separator.
[0008] One goal of the simulations in the Manzolini article is to
use the MCFC to separate CO.sub.2 from the power generator's
exhaust. The simulation described in the Manzolini article
establishes a maximum outlet temperature of 660.degree. C. and
notes that the inlet temperature must be sufficiently cooler to
account for the temperature increase across the fuel cell. The
electrical efficiency (i.e. electricity generated/fuel input) for
the MCFC fuel cell in a base model case is 50%. The electrical
efficiency in a test model case, which is optimized for CO.sub.2
sequestration, is also 50%.
[0009] An article by Desideri et al. (Intl. J. of Hydrogen Energy,
Vol. 37, 2012) describes a method for modeling the performance of a
power generation system using a fuel cell for CO.sub.2 separation.
Recirculation of anode exhaust to the anode inlet and the cathode
exhaust to the cathode inlet are used to improve the performance of
the fuel cell. Based on the model and configuration shown in the
article, increasing the CO.sub.2 utilization within the fuel cell
is shown as being desirable for improving separation of CO.sub.2.
The model parameters describe an MCFC electrical efficiency of
50.3%.
[0010] U.S. Pat. No. 7,396,603 describes an integrated fossil fuel
power plant and fuel cell system with CO.sub.2 emissions abatement.
At least a portion of the anode output is recycled to the anode
input after removal of a portion of CO.sub.2 from the anode
output.
[0011] Molten carbonate fuel cells utilize hydrogen and/or other
fuels to generate electricity. The hydrogen may be provided by
reforming methane or other reformable fuels in a steam reformer
that is upstream of the fuel cell or within the fuel cell.
Reformable fuels can encompass hydrocarbonaceous materials that can
be reacted with steam and/or oxygen at elevated temperature and/or
pressure to produce a gaseous product that comprises hydrogen. In
particular, reformable fuel can include, but is not limited to,
alkanes, alkenes, alcohols, aromatics, and/or other carbonaceous
and organic compounds that can be reformed to generate H.sub.2 and
carbon oxides (either CO or CO.sub.2). Alternatively or
additionally, fuel can be reformed in the anode cell in a molten
carbonate fuel cell, which can be operated to create conditions
that are suitable for reforming fuels in the anode. Alternately or
additionally, the reforming can occur both externally and
internally to the fuel cell.
[0012] Traditionally, molten carbonate fuel cells are operated to
maximize electricity production per unit of fuel input, which may
be referred to as the fuel cell's electrical efficiency. This
maximization can be based on the fuel cell alone or in conjunction
with another power generation system. In order to achieve increased
electrical production and to manage the heat generation, fuel
utilization within a fuel cell is typically maintained at 70% to
75%.
[0013] U.S. Published Patent Application 2011/0111315 describes a
system and process for operating fuel cell systems with substantial
hydrogen content in the anode inlet stream. The technology in the
'315 publication is concerned with providing enough fuel in the
anode inlet so that sufficient fuel remains for the oxidation
reaction as the fuel approaches the anode exit. To ensure adequate
fuel, the '315 publication provides fuel with a high concentration
of H.sub.2. The H.sub.2 not utilized in the oxidation reaction is
recycled to the anode for use in the next pass. On a single pass
basis, the H.sub.2 utilization may range from 10% to 30%. The '315
reference does not describe significant reforming within the anode,
instead relying primarily on external reforming.
[0014] U.S. Published Patent Application 2005/0123810 describes a
system and method for co-production of hydrogen and electrical
energy. The co-production system comprises a fuel cell and a
separation unit, which is configured to receive the anode exhaust
stream and separate hydrogen. A portion of the anode exhaust is
also recycled to the anode inlet. The operating ranges given in the
'810 publication appear to be based on a solid oxide fuel cell.
Molten carbonate fuel cells are described as an alternative.
[0015] U.S. Published Patent Application 2003/0008183 describes a
system and method for co-production of hydrogen and electrical
power. A fuel cell is mentioned as a general type of chemical
converter for converting a hydrocarbon-type fuel to hydrogen. The
fuel cell system also includes an external reformer and a high
temperature fuel cell. An embodiment of the fuel cell system is
described that has an electrical efficiency of about 45% and a
chemical production rate of about 25% resulting in a system
coproduction efficiency of about 70%. The '183 publication does a)
not appear to describe the electrical efficiency of the fuel cell
in isolation from the system.
[0016] U.S. Pat. No. 5,084,362 describes a system for integrating a
fuel cell with a gasification system so that coal gas can be used
as a fuel source for the anode of the fuel cell. Hydrogen generated
by the fuel cell is used as an input for a gasifier that is used to
generate methane from a coal gas (or other coal) input. The methane
from the gasifier is then used as at least part of the input fuel
to the fuel cell. Thus, at least a portion of the hydrogen
generated by the fuel cell is indirectly recycled to the fuel cell
anode inlet in the form of the methane generated by the
gasifier.
SUMMARY OF THE INVENTION
[0017] In one aspect, a method for capturing carbon dioxide from a
combustion source is provided. The method can introducing one or
more fuel streams and an O.sub.2-containing stream into a
combustion zone; performing a combustion reaction in the combustion
zone to generate a combustion exhaust, the combustion exhaust
comprising CO.sub.2; processing at least a first portion of the
combustion exhaust with a fuel cell array of one or more molten
carbonate fuel cells to form a cathode exhaust stream from at least
one cathode outlet of the fuel cell array, the one or more fuel
cells each having an anode and a cathode, the molten carbonate fuel
cells being operatively connected to the combustion exhaust through
one or more cathode inlets in the fuel cell array; reacting
carbonate from the one or more fuel cell cathodes with hydrogen
within the one or more fuel cell anodes to produce electricity, an
anode exhaust stream from at least one anode outlet of the fuel
cell array comprising CO.sub.2 and H.sub.2; separating CO.sub.2
from the anode exhaust stream in one or more separation stages to
form a CO.sub.2-depleted anode exhaust stream; passing at least a
first portion of the CO.sub.2-depleted anode exhaust stream to the
combustion zone; and recycling at least a second portion of the
CO.sub.2-depleted anode exhaust stream to one or more of the fuel
cell anodes.
BRIEF DESCRIPTION OF THE DRAWINGS
[0018] FIG. 1 schematically shows an example of a combined cycle
system for generating electricity based on combustion of a
carbon-based fuel.
[0019] FIG. 2 schematically shows an example of the operation of a
molten carbonate fuel cell.
[0020] FIG. 3 shows an example of the relation between anode fuel
utilization and voltage for a molten carbonate fuel cell.
[0021] FIG. 4 schematically shows an example of a configuration for
an anode recycle loop.
[0022] FIG. 5 shows an example of the relation between CO.sub.2
utilization, voltage, and power for a molten carbonate fuel
cell.
[0023] FIG. 6 schematically shows an example of a configuration for
molten carbonate fuel cells and associated reforming and separation
stages.
[0024] FIG. 7 schematically shows another example of a
configuration for molten carbonate fuel cells and associated
reforming and separation stages.
[0025] FIG. 8 schematically shows an example of a combined cycle
system for generating electricity based on combustion of a
carbon-based fuel.
[0026] FIG. 9 schematically shows an example of a combined cycle
system for generating electricity based on combustion of a
carbon-based fuel.
[0027] FIGS. 10-15 show results from simulations of various
configurations of a power generation system including a
combustion-powered turbine and a molten carbonate fuel cell for
carbon dioxide separation.
[0028] FIGS. 16 and 17 show examples of CH.sub.4 conversion at
different fuel cell operating voltages V.sub.A.
DETAILED DESCRIPTION OF THE EMBODIMENTS
[0029] In various aspects, systems and methods are provided for
capturing CO.sub.2 from a combustion source using molten carbonate
fuel cells (MCFCs). The systems and methods can address one or more
problems related to carbon capture from combustion exhaust stream
and/or performing carbon capture using molten carbonate fuel
cells.
[0030] One difficulty with conventional uses of carbon capture
technology in conjunction with a combustion-based power source for
power generation, such as use of molten carbonate fuel cells as
part of a carbon capture scheme, is that the overall efficiency of
the power generation system is reduced. Although molten carbonate
fuel cells can generate electrical power, so that the net power
generated by a system is increased, conventional combinations of
fuel cells with combustion-powered generators result in net lower
power efficiency for the power plant as a whole. In other words,
the electrical power produced (watts) per unit of fuel input (lower
heating value of the fuel, kJ) is reduced. This can be due in part
to additional power or heating requirements for operating the
additional carbon capture components. This can also be due in part
to a lower efficiency of power generation for conventionally
operated fuel cells in comparison with a system such as a
combustion-powered turbine.
[0031] In some aspects, the overall efficiency of a carbon capture
system that includes molten carbonate fuel cells can be improved by
operating the fuel cells at lower anode fuel utilization values.
Conventionally, molten carbonate fuel cells can be operated at a
fuel utilization that balances the heat needed to operate the fuel
cell with the fuel consumed within the cell. The fuel utilization
in conventional fuel cells can typically be made as high as
possible while maintaining this heat balance. By contrast, it has
been determined that, for various types of power system
configurations, reducing the anode fuel utilization of fuel cell
array can allow for improved power generation efficiency for the
overall system.
[0032] Another difficulty with using molten carbonate fuel cells
for separation of CO.sub.2 from an exhaust stream can include the
large area of fuel cells typically required for handling the
exhaust from a commercial scale turbine or other power/heat
generator. Accommodating a commercial scale exhaust flow using
molten carbonate fuel cells can typically involve using a plurality
of fuel cells, rather than constructing a single fuel cell of
sufficient area. In order to deliver the exhaust stream to this
plurality of fuel cells, additional connections can be required in
order to divide the exhaust between the various fuel cells. Thus,
reducing the fuel cell area required to capture a desired amount of
carbon dioxide can provide a corresponding decrease in the number
and/or complexity of flow connections required.
[0033] In some aspects of the invention, the area of fuel cells
required for processing a CO.sub.2-containing exhaust stream can be
reduced or minimized by recycling at least a portion of the anode
exhaust stream back to the anode inlet. Additionally or
alternately, the fuel cells can be operated at lower fuel
utilization. An exhaust stream can be passed into the cathode(s) of
molten carbonate fuel cells. During operation of the fuel cell, the
anode exhaust can be passed through one or more separation stages.
This can include separation stages for removal of H.sub.2O and/or
CO.sub.2. At least a portion of the remaining anode exhaust can
then be recycled to the anode input. In one preferred embodiment,
any recycle of the anode exhaust directly to the cathode can be
avoided. By recycling at least some portion the anode exhaust to
the anode inlet, at least some of the fuel not used on the first
pass through the anode can be utilized in a subsequent pass.
[0034] In addition to or as an alternative to recycling the anode
exhaust to the anode inlet, at least a portion of the hydrogen in
the anode exhaust can be recycled to the combustion zone for a
turbine or other combustion-powered generator/heat source. It is
noted that any hydrogen generated via reforming as part of the
anode loop can represent a fuel where the CO.sub.2 has already been
"captured" by transfer to the anode loop. This can reduce the
amount of CO.sub.2 needing to be transferred from the cathode side
to the anode side of the fuel cell, and therefore can lead to a
reduced fuel cell area.
[0035] An additional or alternative feature that can contribute to
a reduced fuel cell area can be reducing and/or minimizing the
amount of energy required for processes not directly involved in
power generation. For example, the anode reaction in a molten
carbonate fuel cell can combine H.sub.2 with CO.sub.3.sup.2- ions
transported across the electrolyte between cathode and anode to
form H.sub.2O and CO.sub.2. Although the anode reaction environment
can facilitate some reforming of a fuel such as CH.sub.4 to form
H.sub.2, some H.sub.2 can advantageously be present in a fuel in
order to maintain desirable reaction rates in the anode. As a
result, prior to entering the anode itself, fuels (such as natural
gas/methane) are conventionally at least partially reformed prior
to entering the anode. The reforming stage prior to the anode for a
fuel cell can require additional heat in order to maintain a
suitable temperature for reforming.
[0036] In some aspects of the invention, recycling at least a
portion of the anode exhaust to the anode inlet can allow for a
reduced amount of reforming and/or elimination of the reforming
stage prior to the anode inlet. Instead of reforming a fuel stream
prior to entering the anode, the recycled anode exhaust can provide
sufficient hydrogen for the fuel input to the anode. This can allow
the input stream for the anode to be passed into the anode without
passing through a separate pre-reforming stage. Operating the anode
at a reduced level of hydrogen fuel utilization can further
facilitate reducing and/or eliminating the pre-reforming stage by
providing an anode exhaust with increased hydrogen content.
Increasing the hydrogen content can allow a portion of the anode
exhaust to also be used as an input to the turbine combustion zone,
while still having sufficient hydrogen in the feed to the anode
inlet so that pre-reforming can be reduced and/or eliminated.
[0037] Another challenge with using molten carbonate fuel cells can
be due to the relatively low CO.sub.2 content of the exhaust of
properly operated gas turbine. For example, a gas turbine powered
by a low CO.sub.2 content natural gas fuel source can generate an
exhaust, for example, with a CO.sub.2 of about 4 vol %. If some
type of exhaust gas recycle is used, this value can be raised, for
example, to about 6 vol %. By contrast, a typical desired CO.sub.2
content for the input to the cathode of a molten carbonate fuel
cell can be about 10% or more. In some aspects of the invention,
systems and methods are provided herein to allow for increased
CO.sub.2 content in the exhaust gas while still efficiently
operating the gas turbine or other combustion powered generator. In
some aspects of the invention, systems and methods are provided for
improving and/or optimizing the efficiency of carbon capture by the
fuel cell when operated with a cathode exhaust having a low
CO.sub.2 content.
[0038] Still another challenge can include reducing or mitigating
the loss of efficiency in power generation caused by carbon
capture. As noted above, conventional methods of carbon capture can
result in a loss of net efficiency in power generation per unit of
fuel consumed. In some aspects of the invention, systems and
methods are provided for improving the overall power generation
efficiency. Additionally or alternately, in some aspects of the
invention, methods are provided for separating CO.sub.2 in a manner
to reduce and/or minimize the energy required for generation of a
commercially valuable CO.sub.2 stream.
[0039] In most aspects of the invention, one or more of the above
advantages can be achieved, at least in part, by using molten
carbonate fuel cells in combination with a combined cycle power
generation system, such as a natural gas fired combined cycle
plant, where the flue gas and/or heat from combustion reaction(s)
can also be used to power a steam turbine. More generally, the
molten carbonate fuel cells can be used in conjunction with various
types of power or heat generation systems, such as boilers,
combustors, catalytic oxidizers, and/or other types of combustion
powered generators. In some aspects of the invention, at least a
portion of the anode exhaust from the MCFCs can be (after
separation of CO.sub.2) recycled to the input flow for the MCFC
anode(s). Additionally or alternately, a portion of the anode
exhaust from the MCFCs can be recycled to the input flow for the
combustion reaction for power generation. In one embodiment, a
first portion of the anode exhaust from the MCFCs (after separation
of CO.sub.2) can be recycled to the input flow for the MCFC
anode(s), and a second portion of the anode exhaust from the MCFCs
can be recycled to the input flow for the combustion reaction for
power generation. In aspects where the MCFCs can be operated with
remaining (unreacted) H.sub.2 in the anode exhaust, recycling a
portion of the H.sub.2 from the anode exhaust to the anode input
can reduce the fuel needed for operating the MCFCs. The portion of
H.sub.2 delivered to the combustion reaction can advantageously
modify and/or improve reaction conditions for the combustion
reaction, leading to more efficient power generation. A water-gas
shift reaction zone after the anode exhaust can optionally be used
to further increase the amount of H.sub.2 present in the anode
exhaust while also allowing conversion of CO into more easily
separable CO.sub.2.
[0040] In various aspects of the invention, an improved method for
capturing CO.sub.2 from a combustion source using a molten
carbonate fuel cell can be provided. This can include, for example,
systems and methods for power generation using turbines (or other
power or heat generation methods based on combustion, such as
boilers, combustors, and/or catalytic oxidizers) while reducing
and/or mitigating emissions during power generation. This can
optionally be achieved, at least in part, by using a combined cycle
power generation system, where the flue gas and/or heat from
combustion reaction(s) can also be used to power a steam turbine.
This can additionally or alternately be achieved, at least in part,
by using one or more molten carbonate fuel cells (MCFCs) as both a
carbon capture device as well as an additional source of electrical
power. In some aspects of the invention, the MCFCs can be operated
under low fuel utilization conditions that can allow for improved
carbon capture in the fuel cell while also reducing and/or
minimizing the amount of fuel lost or wasted. Additionally or
alternately, the MCFCs can be operated to reduce and/or minimize
the total number and/or volume of MCFCs required to reduce the
CO.sub.2 content of a combustion flue gas stream to a desired
level, for example, 1.5 vol % or less or 1.0 vol % or less. In such
aspects, for the cathode output from the final cathode(s) in an
array sequence (typically at least including a series arrangement,
or else the final cathode(s) and the initial cathode(s) would be
the same), the output composition can include about 2.0 vol % or
less of CO.sub.2 (e.g., about 1.5 vol % or less or about 1.2 vol %
or less) and/or at least about 1.0 vol % of CO.sub.2, such as at
least about 1.2 vol % or at least about 1.5 vol %. Such aspects can
be enabled, at least in part, by recycling the exhaust from the
anode back to the inlet of the anode, with removal of at least a
portion of the CO.sub.2 in the anode exhaust prior to returning the
anode exhaust to the anode inlet. Such removal of CO.sub.2 from the
anode exhaust can be achieved, for example, using a cryogenic
CO.sub.2 separator. In some optional aspects of the invention, the
recycle of anode exhaust to the anode inlet can be performed so
that no pathway is provided for the anode exhaust to be recycled
directly to the cathode inlet. By avoiding recycle of anode exhaust
directly to the cathode inlet, any CO.sub.2 transported to the
anode recycle loop via the MCFCs can remain in the anode recycle
loop until the CO.sub.2 is separated out from the other gases in
the loop.
[0041] Molten carbonate fuel cells are conventionally used in a
standalone mode to generate electricity. In a standalone mode, an
input stream of fuel, such as methane, can be passed into the anode
side of a molten carbonate fuel cell. The methane can be reformed
(either externally or internally) to form H.sub.2 and other gases.
The H.sub.2 can then be reacted with carbonate ions that have
crossed the electrolyte from the cathode in the fuel cell to form
CO.sub.2 and H.sub.2O. For the reactions in the anode of the fuel
cell, the rate of fuel utilization is typically about 70% or 75%,
or even higher. In a conventional configuration, the remaining fuel
in the anode exhaust can be oxidized (burned) to generate heat for
maintaining the temperature of the fuel cell and/or external
reformer, in view of the endothermic nature of the reforming
reaction. Air and/or another oxygen source can be added during this
oxidation to allow for more complete combustion. The anode exhaust
(after oxidation) can then be passed into the cathode. In this
manner, a single fuel stream entering the anode can be used to
provide all of the energy and nearly all of the reactants for both
anode and cathode. This configuration can also allow all of the
fuel entering the anode to be consumed while only requiring
.about.70% or .about.75% or slightly more fuel utilization in the
anode.
[0042] In the above standalone method, which can be typical of
conventional systems, the goal of operating a molten carbonate fuel
cell can be generally to efficiently generate electric power based
on an input fuel stream. By contrast, a molten carbonate fuel cell
integrated with a combustion powered turbine, engine, or other
generator can be used to provide additional utility. Although
high-efficiency power generation by the fuel cell is still
desirable, the fuel cell can be operated, for instance, to improve
and/or maximize the amount of CO.sub.2 captured from an exhaust
stream for a given volume of fuel cells. This can allow for
improved CO.sub.2 capture while still generating power from the
fuel cell. Additionally, in some aspects of the invention, the
exhaust from the anode(s) of the fuel cell(s) can still contain
excess hydrogen. This excess hydrogen can advantageously be used as
a fuel for the combustion reaction for the turbine, thus allowing
for improved efficiency for the turbine.
[0043] FIG. 1 provides a schematic overview for the concept of some
aspects of the invention. FIG. 1 is provided to aid in
understanding of the general concept, so additional feeds,
processes, and or configurations can be incorporated into FIG. 1
without departing from the spirit of the overall concept. In the
overview example shown in FIG. 1, a natural gas turbine 110 (or
another combustion-powered turbine) can be used to generate
electric power based on combustion of a fuel 112. For the natural
gas turbine 110 shown in FIG. 1, this can include compressing an
air stream or other gas phase stream 111 to form a compressed gas
stream 113. The compressed gas stream 113 can then be introduced
into a combustion zone 115 along with fuel 112. Additionally, a
stream 185, including a portion of the fuel (hydrogen) present in
the exhaust from anode 130, can also be introduced into the
combustion zone 115. This additional hydrogen can allow the
combustion reaction to be operated under enhanced conditions. The
resulting hot flue or exhaust gas 117 can then be passed into the
expander portion of turbine 110 to generate electrical power.
[0044] After expansion (and optional clean up and/or other
processing steps), the expanded flue gas can be passed into the
cathode portion 120 of a molten carbonate fuel cell. The flue gas
can include sufficient oxygen for the reaction at the cathode, or
additional oxygen can be provided if necessary. To facilitate the
fuel cell reaction, fuel 132 can be passed into the anode portion
130 of the fuel cell, along with at least a portion of the anode
exhaust 135. Prior to being recycled, the anode exhaust 135 can be
passed through several additional processes. One additional process
can include or be a water-gas shift reaction process 170. The water
gas-shift reaction 170 can be used to react H.sub.2O and CO present
in the anode exhaust 135 to form additional H.sub.2 and CO.sub.2.
This can allow for improved removal of carbon from the anode
exhaust 135, as CO.sub.2 can typically be more readily separated
from the anode exhaust, as compared to CO. The output 175 from the
(optional) water-gas shift process 170 can then be passed through a
carbon dioxide separation system 140, such as a cryogenic carbon
dioxide separator. This can remove at least a portion of CO.sub.2
147 from the anode exhaust, typically as well as a portion of the
water 149 also. After removal of at least a portion of the CO.sub.2
and water, the recycled anode exhaust can still contain some
CO.sub.2 and water, as well as unreacted fuel in the form of
H.sub.2 and/or possibly a hydrocarbon such as methane. In certain
embodiments of the invention, a portion 145 of the output from the
CO.sub.2 separation stage(s) can be recycled for use as an input
stream to anode 130, while a second portion can be used as input
185 to the combustion reaction 115. Fuel 132 can represent a
hydrogen-containing stream and/or a stream containing methane
and/or another hydrocarbon that can be reformed (internally or
externally) to form H.sub.2.
[0045] The exhaust from the cathode portion 120 of the fuel cell
can then be passed into a heat recovery zone 150 so that heat from
the cathode exhaust can be recovered, e.g., to power a steam
generator 160. After recovering heat, the cathode exhaust can exit
the system as an exhaust stream 156. The exhaust stream 156 can
exit to the environment, or optional additional clean-up processes
can be used, such as performing additional CO.sub.2 capture on
stream 156, for example, using an amine scrubber.
[0046] One way of characterizing the operation of a fuel cell can
be to characterize the "utilization" of various inputs received by
the fuel cell. For example, one common method for characterizing
the operation of a fuel cell can be to specify the (anode) fuel
utilization for the fuel cell.
[0047] In addition to fuel utilization, the utilization for other
reactants in the fuel cell can be characterized. For example, the
operation of a fuel cell can additionally or alternately be
characterized with regard to "CO.sub.2 utilization" and/or
"oxidant" utilization. The values for CO.sub.2 utilization and/or
oxidant utilization can be specified in a similar manner. For
CO.sub.2 utilization, the simplified calculation of
(CO.sub.2-rate-in minus CO.sub.2-rate-out)/CO.sub.2-rate-in can be
used if CO.sub.2 is the only fuel component present in the input
stream or flow to the cathode, with the only reaction thus being
the formation of CO.sub.3.sup.2-. Similarly, for oxidant
utilization, the simplified version can be used if O.sub.2 is the
only oxidant present in the input stream or flow to the cathode,
with the only reaction thus being the formation of
CO.sub.3.sup.2-.
[0048] Another reason for using a plurality of fuel cells can be to
allow for efficient fuel cell operation while reducing the CO.sub.2
content of the combustion exhaust to a desired level. Rather than
operating a fuel cell to have a high (or optimal) rate of CO.sub.2
utilization, two (or more) fuel cells can be operated at lower fuel
utilization rate(s) while reducing the combustion to a desired
level.
[0049] During conventional operation of a fuel cell, such as
standalone operation, the goal of operating the fuel cell can be to
generate electrical power while efficiently using the "fuel"
provided to the cell. The "fuel" can correspond to either hydrogen
(H.sub.2), a gas stream comprising hydrogen, and/or a gas stream
comprising a substance that can be reformed to provide hydrogen
(such as methane, another alkane or hydrocarbon, and/or one or more
other types of compounds containing carbon and hydrogen that, upon
reaction, can provide hydrogen). These reforming reactions are
typically endothermic and thus usually consume some heat energy in
the production of hydrogen. Carbon sources that can provide CO
directly and/or upon reaction can also be utilized, as typically
the water gas shift reaction (CO+H.sub.2O=H.sub.2+CO.sub.2) can
occur in the presence of the fuel cell anode catalyst surface. This
can allow for production of hydrogen from a CO source. For such
conventional operation, one potential goal of operating the fuel
cell can be to consume all of the fuel provided to the cell, while
maintaining a desirable output voltage for the fuel cell, which can
be traditionally accomplished by operating the fuel cell anode at a
fuel utilization of about 70% to about 75%, followed by combusting
(such as burning) the remaining fuel to generate heat to maintain
the temperature of the fuel cell. The fuel utilization can be
measured in terms of the total enthalpy of the fuel used in the
fuel cell reactions divided by the enthalpy of the fuel entering
the fuel cell.
[0050] In a molten carbonate fuel cell, the transport of carbonate
ions across the electrolyte in the fuel cell can provide a method
for transporting CO.sub.2 from a first flow path to a second flow
path, where the transport method can allow transport from a lower
concentration (the cathode) to a higher concentration (the anode),
which can thus facilitate capture of CO.sub.2. Part of the
selectivity of the fuel cell for CO.sub.2 separation can be based
on the electrochemical reactions allowing the cell to generate
electrical power. For nonreactive species (such as N.sub.2) that
effectively do not participate in the electrochemical reactions
within the fuel cell, there can be an insignificant amount of
reaction and transport from cathode to anode. By contrast, the
potential (voltage) difference between the cathode and anode can
provide a strong driving force for transport of carbonate ions
across the fuel cell. As a result, the transport of carbonate ions
in the molten carbonate fuel cell can allow CO.sub.2 to be
transported from the cathode (lower CO.sub.2 concentration) to the
anode (higher CO.sub.2 concentration) with relatively high
selectivity. However, a challenge in using molten carbonate fuel
cells for carbon dioxide removal can be that the fuel cells have
limited ability to remove carbon dioxide from relatively dilute
cathode feeds. The voltage and/or power generated by a carbonate
fuel cell can start to drop rapidly as the CO.sub.2 concentration
falls below about 2.0 vol %. As the CO.sub.2 concentration drops
further, e.g., to below about 1.0 vol %, at some point the voltage
across the fuel cell can become low enough that little or no
further transport of carbonate may occur and the fuel cell ceases
to function. Thus, at least some CO.sub.2 is likely to be present
in the exhaust gas from the cathode stage of a fuel cell under
commercially viable operating conditions.
[0051] The amount of carbon dioxide delivered to the fuel cell
cathode(s) can be determined based on the CO.sub.2 content of a
source for the cathode inlet. One example of a suitable
CO.sub.2-containing stream for use as a cathode input flow can be
an output or exhaust flow from a combustion source. Examples of
combustion sources include, but are not limited to, sources based
on combustion of natural gas, combustion of coal, and/or combustion
of other hydrocarbon-type fuels (including biologically derived
fuels). Additional or alternate sources can include other types of
boilers, fired heaters, furnaces, and/or other types of devices
that burn carbon-containing fuels in order to heat another
substance (such as water or air). To a first approximation, the
CO.sub.2 content of the output flow from a combustion source can be
a minor portion of the flow. Even for a higher CO.sub.2 content
exhaust flow, such as the output from a coal-fired combustion
source, the CO.sub.2 content from most commercial coal-fired power
plants can be about 15 vol % or less. More generally, the CO.sub.2
content of an output or exhaust flow from a combustion source can
be at least about 1.5 vol %, or at least about 1.6 vol %, or at
least about 1.7 vol %, or at least about 1.8 vol %, or at least
about 1.9 vol %, or at least greater 2 vol %, or at least about 4
vol %, or at least about 5 vol %, or at least about 6 vol %, or at
least about 8 vol %. Additionally or alternately, the CO.sub.2
content of an output or exhaust flow from a combustion source can
be about 20 vol % or less, such as about 15 vol % or less, or about
12 vol % or less, or about 10 vol % or less, or about 9 vol % or
less, or about 8 vol % or less, or about 7 vol % or less, or about
6.5 vol % or less, or about 6 vol % or less, or about 5.5 vol % or
less, or about 5 vol % or less, or about 4.5 vol % or less. The
concentrations given above are on a dry basis. It is noted that the
lower CO.sub.2 content values can be present in the exhaust from
some natural gas or methane combustion sources, such as generators
that are part of a power generation system that may or may not
include an exhaust gas recycle loop.
Operation of Anode Portion and Anode Recycle Loop
[0052] In various aspects of the invention, molten carbonate fuel
cells can be operated under conditions that allow for lower fuel
utilization in the anode portion of the fuel cell. This can be in
contrast to conventional operation for fuel cells, where the fuel
utilization can be typically selected in order to allow a 70% or
more of the fuel delivered to the fuel cell to be consumed as part
of operation of the fuel cell. In conventional operation, almost
all of the fuel can be typically either consumed within the anode
of the fuel cell or burned to provide sensible heat for the feed
streams to the fuel cell.
[0053] FIG. 3 shows an example of the relationship between fuel
utilization and output power for a fuel cell operating under
conventional (stand-alone) conditions. The diagram shown in FIG. 3
shows two limiting cases for operation of a fuel cell. One limiting
case includes the limit of operating a fuel cell to consume an
amount of fuel (such as H.sub.2 or methane reformed into H.sub.2)
that approaches 100% of the fuel delivered to the fuel cell. From
an efficiency standpoint, consumption of .about.100% of the fuel
delivered to a fuel cell would be desirable, so as not to waste
fuel during operation of the fuel cell. However, there are two
potential drawbacks with operating a fuel cell to consume more than
about 80% of the fuel delivered to the cell. First, as the amount
of fuel consumed approaches 100%, the voltage provided by the fuel
cell can be sharply reduced. In order to consume an amount of fuel
approaching 100%, the concentration of the fuel in the fuel cell
(or at least near the anode) must almost by definition approach
zero during at least part of the operation of the fuel cell.
Operating the anode of the fuel cell with a fuel concentration
approaching zero can result in a decreasingly low driving force for
transporting carbonate across the electrolyte of the fuel cell.
This can cause a corresponding drop in voltage, with the voltage
potentially also approaching zero in the true limiting case of
consuming all fuel provided to the anode.
[0054] The second drawback is also related to relatively high fuel
utilization values (greater than about 80%). As shown in FIG. 3, at
fuel utilization values of about 75% or less, the voltage generated
by the fuel cell has a roughly linear relationship with the fuel
utilization. In FIG. 3, at about 75% fuel utilization, the voltage
generated can be about 0.7 Volts. In FIG. 3, at fuel utilization
values of about 80% or greater, the voltage versus utilization
curve appears to take on an exponential or power type relationship.
From a process stability standpoint, it can be preferable to
operate a fuel cell in a portion of the voltage versus utilization
curve where the relationship is linear.
[0055] In the other limiting case shown in FIG. 3, the voltage
generated by a molten carbonate fuel cell shows a mild increase as
the fuel utilization decreases. However, in conventional operation,
operating a fuel cell at reduced utilization can pose various
difficulties. For example, the total amount of fuel delivered to a
conventionally operated fuel cell operated with lower fuel
utilization may need to be reduced, so that whatever fuel remains
in the anode exhaust/output stream can still provide the
appropriate amount of heat (upon further combustion) for
maintaining the fuel cell temperature. If the fuel utilization is
reduced without adjusting the amount of fuel delivered to the fuel
cell, the oxidation of the unused fuel may result in higher than
desired temperatures for the fuel cell. Based at least on these
limiting case considerations, conventional fuel cells are typically
operated at a fuel utilization of about 70% to about 75%, so as to
achieve heat balance with complete utilization of the fuel.
[0056] An alternative configuration can be to recycle at least a
portion of the exhaust from a fuel cell anode to the input of a
fuel cell anode. The output stream from an MCFC anode can include
H.sub.2O, CO.sub.2, optionally CO, and optionally but typically
unreacted fuel (such as H.sub.2 or CH.sub.4) as the primary output
components. Instead of using this output stream as a fuel source to
provide heat for a reforming reaction, one or more separations can
be performed on the anode output stream in order to separate out
the CO.sub.2 from the components with potential fuel value, such as
H.sub.2 and/or CO. The components with fuel value can then be
recycled to the input of an anode.
[0057] This type of configuration can provide one or more benefits.
First, CO.sub.2 can be separated out from the anode output, such as
by using a cryogenic CO.sub.2 separator. Several of the components
of the anode output (H.sub.2, CO, CH.sub.4) are not easily
condensable components, while CO.sub.2 and H.sub.2O can be
separated individually as condensed phases. Depending on the
embodiment, at least about 90 vol % of the CO.sub.2 in the anode
output can be separated out to form a relatively high purity
CO.sub.2 output stream. After separation, the remaining portion of
the anode output can correspond primarily to components with fuel
value, as well as reduced amounts of CO.sub.2 and/or H.sub.2O. This
portion of the anode output after separation can be recycled for
use as part of the anode input, along with additional fuel. In this
type of configuration, even though the fuel utilization in a single
pass through the MCFC(s) may be low, the unused fuel can be
advantageously recycled for another pass through the anode. As a
result, the single-pass fuel utilization can be at a reduced level,
while avoiding loss (exhaust) of unburned fuel to the
environment.
[0058] Additionally or alternatively to recycling a portion of the
anode exhaust to the anode input, another configuration option can
be to use a portion of the anode exhaust as an input for a
combustion reaction for a turbine or other combustion power source.
The relative amounts of anode exhaust recycled to the anode input
and/or as an input to the combustion zone can be any convenient or
desirable amount. If the anode exhaust is recycled to only one of
the anode input and the combustion zone, the amount of recycle can
be any convenient amount, such as up to 100% of the portion of the
anode exhaust remaining after any separation to remove CO.sub.2
and/or H.sub.2O. When a portion of the anode exhaust is recycled to
both the anode input and the combustion zone, the total recycled
amount by definition can be 100% or less of the remaining portion
of anode exhaust. Otherwise, any convenient split of the anode
exhaust can be used. In various embodiments of the invention, the
amount of recycle to the anode input can be at least about 10% of
the anode exhaust remaining after separations, for example at least
about 25%, at least about 40%, at least about 50%, at least about
60%, at least about 75%, or at least about 90%. Additionally or
alternately in those embodiments, the amount of recycle to the
anode input can be about 90% or less of the anode exhaust remaining
after separations, for example about 75% or less, about 60% or
less, about 50% or less, about 40% or less, about 25% or less, or
about 10% or less. Further additionally or alternately, in various
embodiments of the invention, the amount of recycle to the
combustion zone (turbine) can be at least about 10% of the anode
exhaust remaining after separations, for example at least about
25%, at least about 40%, at least about 50%, at least about 60%, at
least about 75%, or at least about 90%. Additionally or alternately
in those embodiments, the amount of recycle to the combustion zone
(turbine) can be about 90% or less of the anode exhaust remaining
after separations, for example about 75% or less, about 60% or
less, about 50% or less, about 40% or less, about 25% or less, or
about 10% or less.
[0059] Any H.sub.2 present in the anode exhaust can represent a
fuel that can be combusted without generating CO.sub.2. Because at
least some H.sub.2 can be generated as part of the anode portion of
the fuel cell(s), the CO.sub.2 generated during reforming can be
primarily removed by the CO.sub.2 separation stage(s) in the anode
portion of the system. As a result, use of H.sub.2 from the anode
exhaust as part of the fuel for the combustion reaction can allow
for a situation where the CO.sub.2 generated from "combustion" of
the fuel can be created in the anode portion of the system, as
opposed to having to transport the CO.sub.2 across the
membrane.
[0060] Recycle of H.sub.2 from the anode exhaust to the combustion
reaction can provide synergistic benefits for a turbine (or other
combustion system) that include an exhaust gas recycle (EGR)
configuration. In an EGR configuration, a portion of the
CO.sub.2-containing exhaust gas from the combustion reaction can be
recycled and used as part of the input gas flow to the turbine.
During operation of a combustion-powered turbine, an input gas flow
of an oxidant (such as air or oxygen-enriched air) can be
compressed prior to introduction into the combustion reaction. The
compressors used for the input flows to the combustion reaction can
tend to be volume limited, so that a similar number of moles of gas
can be compressed, typically regardless of the mass of the gas.
However, gases with a higher mass can tend to have higher heat
capacities and/or can allow for greater pressure ratios across the
expander portion of a turbine. A CO.sub.2-enriched exhaust stream
can provide a convenient source of a gas stream with higher
molecular weight components that can allow for improved conversion
of the energy from the combustion reaction into electric power from
the turbine. Although introducing a CO.sub.2-enriched stream into
the combustion reaction can provide some benefits, there can be
effective limits to the amount of the CO.sub.2-enriched stream that
can be added without significantly (negatively) impacting the
combustion reaction. Since the CO.sub.2-enriched stream does not
itself typically contain "fuel", the stream can largely act as a
diluent within the combustion reaction. As a result, the amount of
recyclable CO.sub.2 can be limited based, at least in part, on
maintaining the conditions in the combustion reaction within an
appropriate flammability window.
[0061] Recycle of H.sub.2 from the anode exhaust can complement an
EGR configuration in one or more ways. First, combustion of H.sub.2
may not directly result in generation of CO.sub.2. Instead, as
noted above, the CO.sub.2 generated when the H.sub.2 is produced
can be generated in the anode loop. This can reduce the amount of
CO.sub.2 needing to be transferred from cathode to anode for a
given level of power generation. Additionally, H.sub.2 can also
have the benefit of modifying the operation of the combustion
source, such as through modifying the flammability window, so that
higher concentrations of CO.sub.2 can be tolerated while still
maintaining a desired combustion reaction. Being able to expand the
flammability window can allow for increased concentrations of
CO.sub.2 in the combustion exhaust, and therefore increased
CO.sub.2 in the input to the cathodes of the fuel cell.
[0062] The benefit of being able to increase the CO.sub.2
concentration in the input to the fuel cell cathode can be related
to the nature of how a molten carbonate fuel cell operates. As
detailed below, there can be practical limits in the amount of
CO.sub.2 separable by an MCFC from a cathode exhaust stream.
Depending on the operating conditions, an MCFC can lower the
CO.sub.2 content of a cathode exhaust stream to about 2.0 vol % or
less, e.g., about 1.5 vol % or less or about 1.2 vol % or less. Due
to this limitation, the net efficiency of CO.sub.2 removal when
using molten carbonate fuel cells can be dependent on the amount of
CO.sub.2 in the cathode input. For a combustion reaction using
natural gas as a fuel, the amount of CO.sub.2 in the combustion
exhaust can correspond to a CO.sub.2 concentration at the cathode
input of at least about 4 vol %. Use of exhaust gas recycle can
allow the amount of CO.sub.2 at the cathode input to be increased
to at least about 5 vol %, e.g., at least about 6 vol %. Due to the
increased flammability window that can be provided when using
H.sub.2 as part of the fuel, the amount of CO.sub.2 added via
exhaust gas recycle can be increased still further, so that
concentrations of CO.sub.2 at the cathode input of at least about
7.5 vol % or at least about 8 vol % can be achieved. Based on a
removal limit of about 1.5 vol % at the cathode exhaust, increasing
the CO.sub.2 content at the cathode input from about 5.5 vol % to
about 7.5 vol % corresponds to a .about.50% increase in the amount
of CO.sub.2 that can be captured using a fuel cell and transported
to the anode loop for eventual CO.sub.2 separation.
[0063] The amount of H.sub.2 present in the anode output can be
increased, for example, by using a water gas shift reactor to
convert H.sub.2O and CO present in the anode output into H.sub.2
and CO.sub.2. Water is an expected output of the reaction occurring
at the anode, so the anode output can typically have an excess of
H.sub.2O relative to the amount of CO present in the anode output.
CO can be present in the anode output due to incomplete carbon
combustion during reforming and/or due to the equilibrium balancing
reactions between H.sub.2O, CO, H.sub.2, and CO.sub.2 (i.e., the
water-gas shift equilibrium) under either reforming conditions or
the conditions present during the anode reaction. A water gas shift
reactor can be operated under conditions to drive the equilibrium
further in the direction of forming CO.sub.2 and H.sub.2 at the
expense of CO and H.sub.2O. Higher temperatures can tend to favor
the formation of CO and H.sub.2O. Thus, one option for operating
the water gas shift reactor can be to expose the anode output
stream to a suitable catalyst, such as a catalyst including iron
oxide, zinc oxide, copper on zinc oxide, or the like, at a suitable
temperature, e.g., between about 190.degree. C. to about
210.degree. C. Optionally, the water-gas shift reactor can include
two stages for reducing the CO concentration in an anode output
stream, with a first higher temperature stage operated at a
temperature from at least about 300.degree. C. to about 375.degree.
C. and a second lower temperature stage operated at a temperature
of about 225.degree. C. or less, such as from about 180.degree. C.
to about 210.degree. C. In addition to increasing the amount of
H.sub.2 present in the anode output, the water-gas shift reaction
can also increase the amount of CO.sub.2 at the expense of CO. This
can exchange difficult-to-remove carbon monoxide (CO) for carbon
dioxide, which can be more readily removed by condensation (e.g.,
cryogenic removal), chemical reaction (such as amine removal),
and/or other CO.sub.2 removal methods.
[0064] In some aspects of the invention, all or substantially all
of the anode output stream remaining after separation of (portions
of) the CO.sub.2 (and H.sub.2O) can be recycled for use as an input
for the fuel cell anode(s) and/or as a fuel input for the
combustion-powered generator. Thus, for the portion of the anode
output stream that remains after a water-gas shift reaction,
removal of CO.sub.2, and/or removal of H.sub.2O, at least about 90%
of the remaining content can advantageously be used as either an
input for the fuel cell anode(s) or as a fuel input for the
combustion powered generator. Alternatively, the anode output
stream after separation can be used for more than one purpose, but
recycle of any portion of the anode output stream for use as a
direct input to a cathode and/or as an input to an oxidizer for
heating of the fuel cell can advantageously be avoided.
[0065] FIG. 4 shows an example of the anode flow path portion of a
generator/fuel cell system according to the invention. In FIG. 4,
an initial fuel stream 405 can optionally be reformed 410 to
convert methane (or another type of fuel) and water into H.sub.2
and CO.sub.2. Alternatively, the reforming reaction can be
performed in a reforming stage that is part of an assembly
including both the reforming stage and the fuel cell anode 420.
Additionally or alternately, at least a portion of fuel stream 405
can correspond to hydrogen gas, so that the amount of reforming
needed to provide fuel to the anode 420 can be reduced and/or
minimized. The optionally reformed fuel 415 can then be passed into
anode 420. A recycle stream 455 including fuel components from the
anode exhaust 425 can also serve as an input to the anode 420. A
flow of carbonate ions 422 from the cathode portion of the fuel
cell (not shown) can provide the remaining reactant needed for the
anode fuel cell reactions. Based on the reactions in the anode 420,
the resulting anode exhaust 425 can include H.sub.2O, CO.sub.2, one
or more components corresponding to unreacted fuel (H.sub.2, CO,
CH.sub.4, or others), and optionally one or more additional
non-reactive components, such as N.sub.2 and/or other contaminants
that are part of fuel stream 405. The anode exhaust 425 can then be
passed into one or more separation stages 430 for removal of
CO.sub.2 (and optionally also H.sub.2O). A cryogenic CO.sub.2
removal system can be an example of a suitable type of separation
stage. Optionally, the anode exhaust can first be passed through a
water gas shift reactor 440 to convert any CO present in the anode
exhaust (along with some H.sub.2O) into CO.sub.2 and H.sub.2 in an
optionally water gas shifted anode exhaust 445.
[0066] An initial portion of the separation stage(s) 430 can be
used to remove a majority of the H.sub.2O present in the anode
exhaust 425 as an H.sub.2O output stream 432. Additionally or
alternately, a heat recovery steam generator system or other heat
exchangers independent of the cryogenic separation system can be
used to remove a portion of the H.sub.2O. A cryogenic CO.sub.2
removal system can then remove a majority of the CO.sub.2 as a high
purity CO.sub.2 stream 434. A purge stream (not shown) can also be
present, if desired, to prevent accumulation of inert gases within
the anode recycle loop. The remaining components of the anode
exhaust stream can then be used either as a recycled input 455 to
the inlet of anode 420 or as an input stream 485 for a combustion
powered turbine.
[0067] Conventionally, at least some reforming is performed prior
to any fuel entering a fuel cell. This initial/preliminary
reforming can be performed in a reformer that is external to the
fuel cell(s) or fuel cell stack(s). Alternatively, the assembly for
a fuel cell stack can include one or more reforming zones located
within the stack but prior to the anodes of the fuel cells in the
stack. This initial reforming typically converts at least some fuel
into hydrogen prior to entering the anode, so that the stream that
enters the anode can have sufficient hydrogen to maintain the anode
reaction. Without this initial reforming, in certain embodiments,
the hydrogen content in the anode can be too low, resulting in
little or no transport of CO.sub.2 from cathode to anode. By
contrast, in some embodiments the fuel cell(s) in a fuel cell array
can be operated without external reforming, i.e., based only on
reforming within the anode portion of the fuel cell, due to
sufficient hydrogen being present in the recycled portion of the
anode exhaust. When a sufficient amount of H.sub.2 is present in
the anode feed, such as at least about 10 vol % of the fuel
delivered to the anode in the form of H.sub.2, the reaction
conditions in the anode can allow for additional reforming to take
place within the anode itself, which, depending on flow path, can
reduce and/or eliminate the need for a reforming stage external
(prior) to the anode input(s) in the methods according to the
invention. If the anode feed does not contain a sufficient amount
of hydrogen, the anode reaction can stall, and reforming activity
and/or other reactions in the anode can be reduced, minimized, or
halted entirely. As a result, in embodiments where the amount of
H.sub.2 present in the anode feed is insufficient, it may be
desirable (or necessary) for there to be a reforming stage external
(prior) to the anode input(s).
Operation of Cathode Portion
[0068] In various aspects according to the invention, molten
carbonate fuel cells used for carbon capture can be operated to
improve or enhance the carbon capture aspects of the fuel cells, as
opposed to (or even at the expense of) enhancing the power
generation capabilities. Conventionally, a molten carbonate fuel
cell can be operated based on providing a desirable voltage while
consuming all fuel in the fuel stream delivered to the anode. This
can be conventionally achieved in part by using the anode exhaust
as at least a part of the cathode input stream. By contrast, the
present invention uses separate/different sources for the anode
input and cathode input. By removing the link between the
composition of the anode input flow and the cathode input flow,
additional options become available for operating the fuel cell to
improve capture of carbon dioxide.
[0069] One initial challenge in using molten carbonate fuel cells
for carbon dioxide removal can be that the fuel cells have limited
ability to remove carbon dioxide from relatively dilute cathode
feeds. FIG. 5 shows an example of the relationship between 1)
voltage and CO.sub.2 concentration and 2) power and CO.sub.2
concentration, based on the concentration of CO.sub.2 in the
cathode input gas. As shown in FIG. 5, the voltage and/or power
generated by a carbonate fuel cell can start to drop rapidly as the
CO.sub.2 concentration falls below about 2.0 vol %. As the CO.sub.2
concentration drops further, e.g., to below 1.0 vol %, at some
point the voltage across the fuel cell can become low enough that
little or no further transport of carbonate may occur. Thus, at
least some CO.sub.2 is likely to be present in the exhaust gas from
the cathode stage of a fuel cell, pretty much regardless of the
operating conditions.
[0070] One modification of the fuel cell operating conditions can
be to operate the fuel cell with an excess of available reactants
at the anode, such as by operating with low fuel utilization at the
anode, as described above. By providing an excess of the reactants
for the anode reaction in the fuel cell, the availability of
CO.sub.2 for the cathode reaction can be used as a/the rate
limiting variable for the reaction.
[0071] When operating MCFCs to enhance the amount of carbon
capture, the factors for balancing can be different than when
attempting to improve fuel utilization. In particular, the amount
of carbon dioxide delivered to the fuel cells can be determined
based on the output flow from the combustion generator providing
the CO.sub.2-containing stream. To a first approximation, the
CO.sub.2 content of the output flow from a combustion generator can
be a minor portion of the flow. Even for a higher CO.sub.2 content
exhaust flow, such as the output from a coal-fired combustion
generator, the CO.sub.2 content from most commercial coal fired
power plants can be about 15 vol % or less. In order to perform the
cathode reaction, this could potentially include between about 5%
and about 15%, typically between about 7% and about 9%, of oxygen
used to react with the CO.sub.2 to form carbonate ions. As a
result, less than about 25 vol % of the input stream to the cathode
can typically be consumed by the cathode reactions. The remaining
at least about 75% portion of the cathode flow can be comprised of
inert/non-reactive species such as N.sub.2, H.sub.2O, and other
typical oxidant (air) components, along with any unreacted CO.sub.2
and O.sub.2.
[0072] Based on the nature of the input flow to the cathode
relative to the cathode reactions, the portion of the cathode input
consumed and removed at the cathode can be about 25 vol % or less,
for example about 10 vol % or less for input flows based on
combustion of cleaner fuel sources, such as natural gas sources.
The exact amount can vary based on the fuel used, the diluent
content in the input fuel (e.g., N.sub.2 is typically present in
natural gas at a small percentage), and the oxidant (air) to fuel
ratio at which the combustor is operated, all of which can vary,
but are typically well known for commercial operations. As a
result, the total gas flow into the cathode portions of the fuel
cells can be relatively predictable (constant) across the total
array of fuel cells used for carbon capture. Several possible
configurations can be used in order to provide an array of fuel
cells to enhance/improve/optimize carbon capture. The following
configuration options can be used alone or in combination as part
of the strategy for improving carbon capture.
[0073] A first configuration option can be to divide the
CO.sub.2-containing stream between a plurality of fuel cells. The
CO.sub.2-containing output stream from an industrial generator can
typically correspond to a large flow volume relative to desirable
operating conditions for a single MCFC of reasonable size. Instead
of processing the entire flow in a single MCFC, the flow can be
divided amongst a plurality of MCFC units, usually at least some of
which are in parallel, so that the flow rate in each unit can be
within a desired flow range.
[0074] A second configuration option can be to utilize fuel cells
in series to successively remove CO.sub.2 from a flow stream.
Regardless of the number of initial fuel cells to which a
CO.sub.2-containing stream can be distributed to in parallel, each
initial fuel cell can be followed by one or more additional cells
in series to further remove additional CO.sub.2. Similar to the
situation demonstrated in FIG. 3 for the H.sub.2 input to the
anode, attempting to remove CO.sub.2 within a stream in a single
fuel cell could lead to a low and/or unpredictable voltage output.
Rather than attempting to remove CO.sub.2 to a desired level in a
single fuel cell, CO.sub.2 can be removed in successive cells until
a desired level can be achieved. For example, each cell in a series
of fuel cells can be used to remove some percentage (e.g., about
50%) of the CO.sub.2 present in a fuel stream. In such an example,
if three fuel cells are used in series, the CO.sub.2 concentration
can be reduced (e.g., to about 15% or less of the original amount
present, which can correspond to reducing the CO.sub.2
concentration from about 6% to about 1% or less over the course of
three fuel cells in series).
[0075] In another configuration, the operating conditions can be
selected in early fuel stages in series to provide a desired output
voltage while the array of stages can be selected to achieve a
desired level of carbon capture. As an example, an array of fuel
cells can be used with three fuel cells in series. The first two
fuel cells in series can be used to remove CO.sub.2 while
maintaining a desired output voltage. The final fuel cell can then
be operated to remove CO.sub.2 to a desired concentration.
[0076] In still another configuration, there can be separate
connectivity for the anodes and cathodes in a fuel cell array. For
example, if the fuel cell array includes fuel cathodes connected in
series, the corresponding anodes can be connected in any convenient
manner, not necessarily matching up with the same arrangement as
their corresponding cathodes, for example. This can include, for
instance, connecting the anodes in parallel, so that each anode
receives the same type of fuel feed, and/or connecting the anodes
in a reverse series, so that the highest fuel concentration in the
anodes can correspond to those cathodes having the lowest CO.sub.2
concentration.
Hydrogen or Syngas Capture
[0077] Either hydrogen or syngas can be withdrawn from the anode
exhaust as a chemical energy output. Hydrogen can be used as a
clean fuel without generating greenhouse gases when it is burned or
combusted. Instead, for hydrogen generated by reforming of
hydrocarbons (or hydrocarbonaceous compounds), the CO.sub.2 will
have already been "captured" in the anode loop. Additionally,
hydrogen can be a valuable input for a variety of refinery
processes and/or other synthesis processes. Syngas can also be a
valuable input for a variety of processes. In addition to having
fuel value, syngas can be used as a feedstock for producing other
higher value products, such as by using syngas as an input for
Fischer-Tropsch synthesis and/or methanol synthesis processes.
[0078] In various aspects, the anode exhaust can have a ratio of
H.sub.2 to CO of about 1.5:1 to about 10:1, such as at least about
3.0:1, or at least about 4.0:1, or at least about 5.0:1, and/or
about 8.0:1 or less or about 6.0:1 or less. A syngas stream can be
withdrawn from the anode exhaust. In various aspects, a syngas
stream withdrawn from an anode exhaust can have a ratio of moles of
H.sub.2 to moles of CO of at least about 0.9:1, such as at least
about 1.0:1, or at least about 1.2:1, or at least about 1.5:1, or
at least about 1.7:1, or at least about 1.8:1, or at least about
1.9:1. Additionally or alternately, the molar ratio of H.sub.2 to
CO in a syngas withdrawn from an anode exhaust can be about 3.0:1
or less, such as about 2.7:1 or less, or about 2.5:1 or less, or
about 2.3:1 or less, or about 2.2:1 or less, or about 2.1:1 or
less. It is noted that higher ratios of H.sub.2 to CO in a
withdrawn syngas stream can tend to reduce the amount of CO
relative to the amount of CO.sub.2 in a cathode exhaust. However,
many types of syngas applications benefit from syngas with a molar
ratio of H.sub.2 to CO of at least about 1.5:1 to about 2.5:1 or
less, so forming a syngas stream with a molar ratio of H.sub.2 to
CO content of, for example, about 1.7:1 to about 2.3:1 may be
desirable for some applications.
[0079] Syngas can be withdrawn from an anode exhaust by any
convenient method. In some aspects, syngas can be withdrawn from
the anode exhaust by performing separations on the anode exhaust to
remove at least a portion of the components in the anode exhaust
that are different from H.sub.2 and CO. For example, an anode
exhaust can first be passed through an optional water-gas shift
stage to adjust the relative amounts of H.sub.2 and CO. One or more
separation stages can then be used to remove H.sub.2O and/or
CO.sub.2 from the anode exhaust. The remaining portion of the anode
exhaust can then correspond to the syngas stream, which can then be
withdrawn for use in any convenient manner. Additionally or
alternately, the withdrawn syngas stream can be passed through one
or more water-gas shift stages and/or passed through one or more
separation stages.
[0080] It is noted that an additional or alternative way of
modifying the molar ratio of H.sub.2 to CO in the withdrawn syngas
can be to separate an H.sub.2 stream from the anode exhaust and/or
the syngas, such as by performing a membrane separation. Such a
separation to form a separate H.sub.2 output stream can be
performed at any convenient location, such as prior to and/or after
passing the anode exhaust through a water-gas shift reaction stage,
and prior to and/or after passing the anode exhaust through one or
more separation stages for removing components in the anode exhaust
different from H.sub.2 and CO. Optionally, a water-gas shift stage
can be used both before and after separation of an H.sub.2 stream
from the anode exhaust. In an additional or alternative embodiment,
H.sub.2 can optionally be separated from the withdrawn syngas
stream. In some aspects, a separated H.sub.2 stream can correspond
to a high purity H.sub.2 stream, such as an H.sub.2 stream
containing at least about 90 vol % of H.sub.2, such as at least
about 95 vol % of H.sub.2 or at least about 99 vol % of
H.sub.2.
[0081] In some aspects, a molten carbonate fuel cell can be
operated using a cathode input feed with a moderate or low CO.sub.2
content. A variety of streams that are desirable for carbon
separation and capture can include streams with moderate to low
CO.sub.2 content. For example, a potential input stream for a
cathode inlet can have a CO.sub.2 content of about 20 vol % or
less, such as about 15 vol % or less, or about 12 vol % or less, or
about 10 vol % or less. Such a CO.sub.2-containing stream can be
generated by a combustion generator, such as a coal-fired or
natural gas-fired turbine. Achieving a desired level of CO.sub.2
utilization on a cathode input stream with a moderate or low
CO.sub.2 content can allow for use of a lower content CO.sub.2
stream, as opposed to needing to enrich a stream with CO.sub.2
prior to using the stream as a cathode input stream. In various
aspects, the CO.sub.2 utilization for a fuel cell can be at least
about 50%, such as at least about 55% or at least about 60%.
Additionally or alternately, the CO.sub.2 utilization can be about
98% or less, such as about 97% or less, or about 95% or less, or
about 90% or less, or alternatively can be just high enough so that
sufficient CO.sub.2 remains in the cathode exhaust to allow
efficient or desired operation of the fuel cell. As used herein,
CO.sub.2 utilization may be the difference between the moles of
CO.sub.2 in the cathode outlet stream and the moles of CO.sub.2 in
the cathode inlet stream divided by the moles of CO.sub.2 in the
cathode inlet. Expressed mathematically, CO.sub.2
utilization=(CO.sub.2(cathode in)-CO.sub.2(cathode
out))/CO.sub.2(cathode in).
Operating Strategies
[0082] As an addition, complement, and/or alternative to the fuel
cell operating strategies described herein, a molten carbonate fuel
cell (such as a fuel cell assembly) can be operated with increased
production of syngas (or hydrogen) while also reducing or
minimizing the amount of CO.sub.2 exiting the fuel cell in the
cathode exhaust stream. Syngas can be a valuable input for a
variety of processes. In addition to having fuel value, syngas can
be used as a raw material for forming other higher value products,
such as by using syngas as an input for Fischer-Tropsch synthesis
and/or methanol synthesis processes. One option for making syngas
can be to reform a hydrocarbon or hydrocarbon-like fuel, such as
methane or natural gas. For many types of industrial processes, a
syngas having a ratio of H.sub.2 to CO of close to 2:1 (or even
lower) can often be desirable. A water gas shift reaction can be
used to reduce the H.sub.2 to CO ratio in a syngas if additional
CO.sub.2 is available, such as is produced in the anodes.
[0083] One way of characterizing the overall benefit provided by
integrating syngas generation with use of molten carbonate fuel
cells can be based on a ratio of the net amount of syngas that
exits the fuel cells in the anode exhaust relative to the amount of
CO.sub.2 that exits the fuel cells in the cathode exhaust. This
characterization measures the effectiveness of producing power with
low emissions and high efficiency (both electrical and chemical).
In this description, the net amount of syngas in an anode exhaust
is defined as the combined number of moles of H.sub.2 and number of
moles of CO present in the anode exhaust, offset by the amount of
H.sub.2 and CO present in the anode inlet. Because the ratio is
based on the net amount of syngas in the anode exhaust, simply
passing excess H.sub.2 into the anode does not change the value of
the ratio. However, H.sub.2 and/or CO generated due to reforming in
the anode and/or in an internal reforming stage associated with the
anode can lead to higher values of the ratio. Hydrogen oxidized in
the anode can lower the ratio. It is noted that the water gas shift
reaction can exchange H.sub.2 for CO, so the combined moles of
H.sub.2 and CO represents the total potential syngas in the anode
exhaust, regardless of the eventual desired ratio of H.sub.2 to CO
in a syngas. The syngas content of the anode exhaust (H.sub.2+CO)
can then be compared with the CO.sub.2 content of the cathode
exhaust. This can provide a type of efficiency value that can also
account for the amount of carbon capture. This can equivalently be
expressed as an equation as
Ratio of net syngas in anode exhaust to cathode CO.sub.2=net moles
of (H.sub.2+CO).sub.ANODE/moles of (CO.sub.2).sub.CATHODE
[0084] In various aspects, the ratio of net moles of syngas in the
anode exhaust to the moles of CO.sub.2 in the cathode exhaust can
be at least about 2.0, such as at least about 3.0, or at least
about 4.0, or at least about 5.0. In some aspects, the ratio of net
syngas in the anode exhaust to the amount of CO.sub.2 in the
cathode exhaust can be still higher, such as at least about 10.0,
or at least about 15.0, or at least about 20.0. Ratio values of
about 40.0 or less, such as about 30.0 or less, or about 20.0 or
less, can additionally or alternately be achieved. In aspects where
the amount of CO.sub.2 at the cathode inlet is about 6.0 volume %
or less, such as about 5.0 volume % or less, ratio values of at
least about 1.5 may be sufficient/realistic. Such molar ratio
values of net syngas in the anode exhaust to the amount of CO.sub.2
in the cathode exhaust can be greater than the values for
conventionally operated fuel cells.
[0085] As an addition, complement, and/or alternative to the fuel
cell operating strategies described herein, a molten carbonate fuel
cell (such as a fuel cell assembly) can be operated at a reduced
fuel utilization value, such as a fuel utilization of about 50% or
less, while also having a high CO.sub.2 utilization value, such as
at least about 60%. In this type of configuration, the molten
carbonate fuel cell can be effective for carbon capture, as the
CO.sub.2 utilization can advantageously be sufficiently high.
Rather than attempting to maximize electrical efficiency, in this
type of configuration the total efficiency of the fuel cell can be
improved or increased based on the combined electrical and chemical
efficiency. The chemical efficiency can be based on withdrawal of a
hydrogen and/or syngas stream from the anode exhaust as an output
for use in other processes. Even though the electrical efficiency
may be reduced relative to some conventional configurations, making
use of the chemical energy output in the anode exhaust can allow
for a desirable total efficiency for the fuel cell.
[0086] In various aspects, the fuel utilization in the fuel cell
anode can be about 50% or less, such as about 40% or less, or about
30% or less, or about 25% or less, or about 20% or less. In various
aspects, in order to generate at least some electric power, the
fuel utilization in the fuel cell can be at least about 5%, such as
at least about 10%, or at least about 15%, or at least about 20%,
or at least about 25%, or at least about 30%. Additionally or
alternatively, the CO.sub.2 utilization can be at least about 60%,
such as at least about 65%, or at least about 70%, or at least
about 75%.
[0087] As an addition, complement, and/or alternative to the fuel
cell operating strategies described herein, a molten carbonate fuel
cell can be operated so that the amount of reforming can be
selected relative to the amount of oxidation in order to achieve a
desired thermal ratio for the fuel cell. As used herein, the
"thermal ratio" is defined as the heat produced by exothermic
reactions in a fuel cell assembly divided by the endothermic heat
demand of reforming reactions occurring within the fuel cell
assembly. Expressed mathematically, the thermal ratio
(TH)=Q.sub.EX/Q.sub.EN, where Q.sub.EX is the sum of heat produced
by exothermic reactions and Q.sub.EN is the sum of heat consumed by
the endothermic reactions occurring within the fuel cell. Note that
the heat produced by the exothermic reactions corresponds to any
heat due to reforming reactions, water gas shift reactions, and the
electrochemical reactions in the cell. The heat generated by the
electrochemical reactions can be calculated based on the ideal
electrochemical potential of the fuel cell reaction across the
electrolyte minus the actual output voltage of the fuel cell. For
example, the ideal electrochemical potential of the reaction in a
MCFC is believed to be about 1.04V based on the net reaction that
occurs in the cell. During operation of the MCFC, the cell will
typically have an output voltage less than 1.04 V due to various
losses. For example, a common output/operating voltage can be about
0.7 V. The heat generated is equal to the electrochemical potential
of the cell (i.e. .about.1.04V) minus the operating voltage. For
example, the heat produced by the electrochemical reactions in the
cell is .about.0.34 V when the output voltage of .about.0.7V. Thus,
in this scenario, the electrochemical reactions would produce
.about.0.7 V of electricity and .about.0.34 V of heat energy. In
such an example, the .about.0.7 V of electrical energy is not
included as part of Q.sub.EX. In other words, heat energy is not
electrical energy.
[0088] In various aspects, a thermal ratio can be determined for
any convenient fuel cell structure, such as a fuel cell stack, an
individual fuel cell within a fuel cell stack, a fuel cell stack
with an integrated reforming stage, a fuel cell stack with an
integrated endothermic reaction stage, or a combination thereof.
The thermal ratio may also be calculated for different units within
a fuel cell stack, such as an assembly of fuel cells or fuel cell
stacks. For example, the thermal ratio may be calculated for a
single anode within a single fuel cell, an anode section within a
fuel cell stack, or an anode section within a fuel cell stack along
with integrated reforming stages and/or integrated endothermic
reaction stage elements in sufficiently close proximity to the
anode section to be integrated from a heat integration standpoint.
As used herein, "an anode section" comprises anodes within a fuel
cell stack that share a common inlet or outlet manifold.
[0089] In various aspects of the invention, the operation of the
fuel cells can be characterized based on a thermal ratio. Where
fuel cells are operated to have a desired thermal ratio, a molten
carbonate fuel cell can be operated to have a thermal ratio of
about 1.5 or less, for example about 1.3 or less, or about 1.15 or
less, or about 1.0 or less, or about 0.95 or less, or about 0.90 or
less, or about 0.85 or less, or about 0.80 or less, or about 0.75
or less. Additionally or alternately, the thermal ratio can be at
least about 0.25, or at least about 0.35, or at least about 0.45,
or at least about 0.50. Additionally or alternately, in some
aspects the fuel cell can be operated to have a temperature rise
between anode input and anode output of about 40.degree. C. or
less, such as about 20.degree. C. or less, or about 10.degree. C.
or less. Further additionally or alternately, the fuel cell can be
operated to have an anode outlet temperature that is from about
10.degree. C. lower to about 10.degree. C. higher than the
temperature of the anode inlet. Still further additionally or
alternately, the fuel cell can be operated to have an anode inlet
temperature that is greater than the anode outlet temperature, such
as at least about 5.degree. C. greater, or at least about
10.degree. C. greater, or at least about 20.degree. C. greater, or
at least about 25.degree. C. greater. Yet still further
additionally or alternately, the fuel cell can be operated to have
an anode inlet temperature that is greater than the anode outlet
temperature by about 100.degree. C. or less, such as by about
80.degree. C. or less, or about 60.degree. C. or less, or about
50.degree. C. or less, or about 40.degree. C. or less, or about
30.degree. C. or less, or about 20.degree. C. or less.
[0090] As an addition, complement, and/or alternative to the fuel
cell operating strategies described herein, a molten carbonate fuel
cell (such as a fuel cell assembly) can be operated with an excess
of reformable fuel relative to the amount of hydrogen reacted in
the anode of the fuel cell. Instead of selecting the operating
conditions of a fuel cell to improve or maximize the electrical
efficiency of the fuel cell, an excess of reformable fuel can be
passed into the anode of the fuel cell to increase the chemical
energy output of the fuel cell. Optionally but preferably, this can
lead to an increase in the total efficiency of the fuel cell based
on the combined electrical efficiency and chemical efficiency of
the fuel cell.
[0091] In some aspects, the reformable hydrogen content of
reformable fuel in the input stream delivered to the anode and/or
to a reforming stage associated with the anode can be at least
about 50% greater than the amount of hydrogen oxidized in the
anode, such as at least about 75% greater or at least about 100%
greater. In various aspects, a ratio of the reformable hydrogen
content of the reformable fuel in the fuel stream relative to an
amount of hydrogen reacted in the anode can be at least about
1.5:1, or at least about 2.0:1, or at least about 2.5:1, or at
least about 3.0:1. Additionally or alternately, the ratio of
reformable hydrogen content of the reformable fuel in the fuel
stream relative to the amount of hydrogen reacted in the anode can
be about 20:1 or less, such as about 15:1 or less or about 10:1 or
less. In one aspect, it is contemplated that less than 100% of the
reformable hydrogen content in the anode inlet stream can be
converted to hydrogen. For example, at least about 80% of the
reformable hydrogen content in an anode inlet stream can be
converted to hydrogen in the anode and/or in an associated
reforming stage, such as at least about 85%, or at least about
90%.
[0092] As an addition, complement, and/or alternative to the fuel
cell operating strategies described herein, a molten carbonate fuel
cell (such as a fuel cell assembly) can also be operated at
conditions that can improve or optimize the combined electrical
efficiency and chemical efficiency of the fuel cell. Instead of
selecting conventional conditions for maximizing the electrical
efficiency of a fuel cell, the operating conditions can allow for
output of excess synthesis gas and/or hydrogen in the anode exhaust
of the fuel cell. The synthesis gas and/or hydrogen can then be
used in a variety of applications, including chemical synthesis
processes and collection of hydrogen for use as a "clean" fuel. In
aspects of the invention, electrical efficiency can be reduced to
achieve a high overall efficiency, which includes a chemical
efficiency based on the chemical energy value of syngas and/or
hydrogen produced relative to the energy value of the fuel input
for the fuel cell.
[0093] In some aspects, the operation of the fuel cells can be
characterized based on electrical efficiency. Where fuel cells are
operated to have a low electrical efficiency (EE), a molten
carbonate fuel cell can be operated to have an electrical
efficiency of about 40% or less, for example, about 35% EE or less,
about 30% EE or less, about 25% EE or less, or about 20% EE or
less, about 15% EE or less, or about 10% EE or less. Additionally
or alternately, the EE can be at least about 5%, or at least about
10%, or at least about 15%, or at least about 20%. Further
additionally or alternately, the operation of the fuel cells can be
characterized based on total fuel cell efficiency (TFCE), such as a
combined electrical efficiency and chemical efficiency of the fuel
cell(s). Where fuel cells are operated to have a high total fuel
cell efficiency, a molten carbonate fuel cell can be operated to
have a TFCE (and/or combined electrical efficiency and chemical
efficiency) of about 55% or more, for example, about 60% or more,
or about 65% or more, or about 70% or more, or about 75% or more,
or about 80% or more, or about 85% or more. It is noted that for a
total fuel cell efficiency and/or combined electrical efficiency
and chemical efficiency, any additional electricity generated from
use of excess heat generated by the fuel cell can be excluded from
the efficiency calculation.
[0094] In various aspects of the invention, the operation of the
fuel cells can be characterized based on a desired electrical
efficiency of about 40% or less and a desired total fuel cell
efficiency of about 55% or more. Where fuel cells are operated to
have a desired electrical efficiency and a desired total fuel cell
efficiency, a molten carbonate fuel cell can be operated to have an
electrical efficiency of about 40% or less with a TFCE of about 55%
or more, for example, about 35% EE or less with about a TFCE of 60%
or more, about 30% EE or less with about a TFCE of about 65% or
more, about 25% EE or less with about a 70% TFCE or more, or about
20% EE or less with about a TFCE of 75% or more, about 15% EE or
less with about a TFCE of 80% or more, or about 10% EE or less with
about a TFCE of about 85% or more.
[0095] As an addition, complement, and/or alternative to the fuel
cell operating strategies described herein, a molten carbonate fuel
cell (such as a fuel cell assembly) can be operated at conditions
that can provide increased power density. The power density of a
fuel cell corresponds to the actual operating voltage V.sub.A
multiplied by the current density I. For a molten carbonate fuel
cell operating at a voltage V.sub.A, the fuel cell also can tend to
generate waste heat, the waste heat defined as (V.sub.O-V.sub.A)*I
based on the differential between V.sub.A and the ideal voltage
V.sub.O for a fuel cell providing current density I. A portion of
this waste heat can be consumed by reforming of a reformable fuel
within the anode of the fuel cell. The remaining portion of this
waste heat can be absorbed by the surrounding fuel cell structures
and gas flows, resulting in a temperature differential across the
fuel cell. Under conventional operating conditions, the power
density of a fuel cell can be limited based on the amount of waste
heat that the fuel cell can tolerate without compromising the
integrity of the fuel cell.
[0096] In various aspects, the amount of waste heat that a fuel
cell can tolerate can be increased by performing an effective
amount of an endothermic reaction within the fuel cell. One example
of an endothermic reaction includes steam reforming of a reformable
fuel within a fuel cell anode and/or in an associated reforming
stage, such as an integrated reforming stage in a fuel cell stack.
By providing additional reformable fuel to the anode of the fuel
cell (or to an integrated/associated reforming stage), additional
reforming can be performed so that additional waste heat can be
consumed. This can reduce the amount of temperature differential
across the fuel cell, thus allowing the fuel cell to operate under
an operating condition with an increased amount of waste heat. The
loss of electrical efficiency can be offset by the creation of an
additional product stream, such as syngas and/or H.sub.2, that can
be used for various purposes including additional electricity
generation further expanding the power range of the system.
[0097] In various aspects, the amount of waste heat generated by a
fuel cell, (V.sub.0-V.sub.A)*I as defined above, can be at least
about 30 mW/cm.sup.2, such as at least about 40 mW/cm.sup.2, or at
least about 50 mW/cm.sup.2, or at least about 60 mW/cm.sup.2, or at
least about 70 mW/cm.sup.2, or at least about 80 mW/cm.sup.2, or at
least about 100 mW/cm.sup.2, or at least about 120 mW/cm.sup.2, or
at least about 140 mW/cm.sup.2, or at least about 160 mW/cm.sup.2,
or at least about 180 mW/cm.sup.2. Additionally or alternately, the
amount of waste heat generated by a fuel cell can be less than
about 250 mW/cm.sup.2, such as less than about 200 mW/cm.sup.2, or
less than about 180 mW/cm.sup.2, or less than about 165
mW/cm.sup.2, or less than about 150 mW/cm.sup.2.
[0098] Although the amount of waste heat being generated can be
relatively high, such waste heat may not necessarily represent
operating a fuel cell with poor efficiency. Instead, the waste heat
can be generated due to operating a fuel cell at an increased power
density. Part of improving the power density of a fuel cell can
include operating the fuel cell at a sufficiently high current
density. In various aspects, the current density generated by the
fuel cell can be at least about 150 mA/cm.sup.2, such as at least
about 160 mA/cm.sup.2, or at least about 170 mA/cm.sup.2, or at
least about 180 mA/cm.sup.2, or at least about 190 mA/cm.sup.2, or
at least about 200 mA/cm.sup.2, or at least about 225 mA/cm.sup.2,
or at least about 250 mA/cm.sup.2. Additionally or alternately, the
current density generated by the fuel cell can be about 500
mA/cm.sup.2 or less, such as 450 mA/cm.sup.2, or less, or 400
mA/cm.sup.2, or less or 350 mA/cm.sup.2, or less or 300 mA/cm.sup.2
or less.
[0099] In various aspects, to allow a fuel cell to be operated with
increased power generation and increased generation of waste heat,
an effective amount of an endothermic reaction (such as a reforming
reaction) can be performed. Alternatively, other endothermic
reactions unrelated to anode operations can be used to utilize the
waste heat by interspersing "plates" or stages into the fuel cell
array in thermal communication but not in fluid communication with
either anodes or cathodes. The effective amount of the endothermic
reaction can be performed in an associated reforming stage, an
integrated reforming stage, an integrated stack element for
performing an endothermic reaction, or a combination thereof. The
effective amount of the endothermic reaction can correspond to an
amount sufficient to reduce the temperature rise from the fuel cell
inlet to the fuel cell outlet to about 100.degree. C. or less, such
as about 90.degree. C. or less, or about 80.degree. C. or less, or
about 70.degree. C. or less, or about 60.degree. C. or less, or
about 50.degree. C. or less, or about 40.degree. C. or less, or
about 30.degree. C. or less. Additionally or alternately, the
effective amount of the endothermic reaction can correspond to an
amount sufficient to cause a temperature decrease from the fuel
cell inlet to the fuel cell outlet of about 100.degree. C. or less,
such as about 90.degree. C. or less, or about 80.degree. C. or
less, or about 70.degree. C. or less, or about 60.degree. C. or
less, or about 50.degree. C. or less, or about 40.degree. C. or
less, or about 30.degree. C. or less, or about 20.degree. C. or
less, or about 10.degree. C. or less. A temperature decrease from
the fuel cell inlet to the fuel cell outlet can occur when the
effective amount of the endothermic reaction exceeds the waste heat
generated. Additionally or alternately, this can correspond to
having the endothermic reaction(s) (such as a combination of
reforming and another endothermic reaction) consume at least about
40% of the waste heat generated by the fuel cell, such as consuming
at least about 50% of the waste heat, or at least about 60% of the
waste heat, or at least about 75% of the waste heat. Further
additionally or alternately, the endothermic reaction(s) can
consume about 95% of the waste heat or less, such as about 90% of
the waste heat or less, or about 85% of the waste heat or less.
DEFINITIONS
[0100] Syngas: In this description, syngas is defined as mixture of
H.sub.2 and CO in any ratio. Optionally, H.sub.2O and/or CO.sub.2
may be present in the syngas. Optionally, inert compounds (such as
nitrogen) and residual reformable fuel compounds may be present in
the syngas. If components other than H.sub.2 and CO are present in
the syngas, the combined volume percentage of H.sub.2 and CO in the
syngas can be at least 25 vol % relative to the total volume of the
syngas, such as at least 40 vol %, or at least 50 vol %, or at
least 60 vol %. Additionally or alternately, the combined volume
percentage of H.sub.2 and CO in the syngas can be 100 vol % or
less, such as 95 vol % or less or 90 vol % or less.
[0101] Reformable fuel: A reformable fuel is defined as a fuel that
contains carbon-hydrogen bonds that can be reformed to generate
H.sub.2. Hydrocarbons are examples of reformable fuels, as are
other hydrocarbonaceous compounds such as alcohols. Although CO and
H.sub.2O can participate in a water gas shift reaction to form
hydrogen, CO is not considered a reformable fuel under this
definition.
[0102] Reformable hydrogen content: The reformable hydrogen content
of a fuel is defined as the number of H.sub.2 molecules that can be
derived from a fuel by reforming the fuel and then driving the
water gas shift reaction to completion to maximize H.sub.2
production. It is noted that H.sub.2 by definition has a reformable
hydrogen content of 1, although H.sub.2 itself is not defined as a
reformable fuel herein. Similarly, CO has a reformable hydrogen
content of 1. Although CO is not strictly reformable, driving the
water gas shift reaction to completion will result in exchange of a
CO for an H.sub.2. As examples of reformable hydrogen content for
reformable fuels, the reformable hydrogen content of methane is 4
H.sub.2 molecules while the reformable hydrogen content of ethane
is 7 H.sub.2 molecules. More generally, if a fuel has the
composition CxHyOz, then the reformable hydrogen content of the
fuel at 100% reforming and water-gas shift is n(H.sub.2 max
reforming)=2x+y/2-z. Based on this definition, fuel utilization
within a cell can then be expressed as n(H.sub.2 ox)/n(H.sub.2 max
reforming) Of course, the reformable hydrogen content of a mixture
of components can be determined based on the reformable hydrogen
content of the individual components. The reformable hydrogen
content of compounds that contain other heteroatoms, such as
oxygen, sulfur or nitrogen, can also be calculated in a similar
manner.
[0103] Oxidation Reaction: In this discussion, the oxidation
reaction within the anode of a fuel cell is defined as the reaction
corresponding to oxidation of H.sub.2 by reaction with
CO.sub.3.sup.2- to form H.sub.2O and CO.sub.2. It is noted that the
reforming reaction within the anode, where a compound containing a
carbon-hydrogen bond is converted into H.sub.2 and CO or CO.sub.2,
is excluded from this definition of the oxidation reaction in the
anode. The water-gas shift reaction is similarly outside of this
definition of the oxidation reaction. It is further noted that
references to a combustion reaction are defined as references to
reactions where H.sub.2 or a compound containing carbon-hydrogen
bond(s) are reacted with O.sub.2 to form H.sub.2O and carbon oxides
in a non-electrochemical burner, such as the combustion zone of a
combustion-powered generator.
[0104] Aspects of the invention can adjust anode fuel parameters to
achieve a desired operating range for the fuel cell. Anode fuel
parameters can be characterized directly, and/or in relation to
other fuel cell processes in the form of one or more ratios. For
example, the anode fuel parameters can be controlled to achieve one
or more ratios including a fuel utilization, a fuel cell heating
value utilization, a fuel surplus ratio, a reformable fuel surplus
ratio, a reformable hydrogen content fuel ratio, and combinations
thereof.
[0105] Fuel utilization: Fuel utilization is an option for
characterizing operation of the anode based on the amount of
oxidized fuel relative to the reformable hydrogen content of an
input stream can be used to define a fuel utilization for a fuel
cell. In this discussion, "fuel utilization" is defined as the
ratio of the amount of hydrogen oxidized in the anode for
production of electricity (as described above) versus the
reformable hydrogen content of the anode input (including any
associated reforming stages). Reformable hydrogen content has been
defined above as the number of H.sub.2 molecules that can be
derived from a fuel by reforming the fuel and then driving the
water gas shift reaction to completion to maximize H.sub.2
production. For example, each methane introduced into an anode and
exposed to steam reforming conditions results in generation of the
equivalent of 4 H.sub.2 molecules at max production. (Depending on
the reforming and/or anode conditions, the reforming product can
correspond to a non-water gas shifted product, where one or more of
the H.sub.2 molecules is present instead in the form of a CO
molecule.) Thus, methane is defined as having a reformable hydrogen
content of 4 H.sub.2 molecules. As another example, under this
definition ethane has a reformable hydrogen content of 7 H.sub.2
molecules.
[0106] The utilization of fuel in the anode can also be
characterized by defining a heating value utilization based on a
ratio of the Lower Heating Value of hydrogen oxidized in the anode
due to the fuel cell anode reaction relative to the Lower Heating
Value of all fuel delivered to the anode and/or a reforming stage
associated with the anode. The "fuel cell heating value
utilization" as used herein can be computed using the flow rates
and Lower Heating Value (LHV) of the fuel components entering and
leaving the fuel cell anode. As such, fuel cell heating value
utilization can be computed as
(LHV(anode_in)-LHV(anode_out))/LHV(anode_in), where LHV(anode_in)
and LHV(anode_out) refer to the LHV of the fuel components (such as
H.sub.2, CH.sub.4, and/or CO) in the anode inlet and outlet streams
or flows, respectively. In this definition, the LHV of a stream or
flow may be computed as a sum of values for each fuel component in
the input and/or output stream. The contribution of each fuel
component to the sum can correspond to the fuel component's flow
rate (e.g., mol/hr) multiplied by the fuel component's LHV (e.g.,
joules/mol).
[0107] Lower Heating Value: The lower heating value is defined as
the enthalpy of combustion of a fuel component to vapor phase,
fully oxidized products (i.e., vapor phase CO.sub.2 and H.sub.2O
product). For example, any CO.sub.2 present in an anode input
stream does not contribute to the fuel content of the anode input,
since CO.sub.2 is already fully oxidized. For this definition, the
amount of oxidation occurring in the anode due to the anode fuel
cell reaction is defined as oxidation of H.sub.2 in the anode as
part of the electrochemical reaction in the anode, as defined
above.
[0108] It is noted that, for the special case where the only fuel
in the anode input flow is H.sub.2, the only reaction involving a
fuel component that can take place in the anode represents the
conversion of H.sub.2 into H.sub.2O. In this special case, the fuel
utilization simplifies to (H.sub.2-rate-in minus
H.sub.2-rate-out)/H.sub.2-rate-in. In such a case, H.sub.2 would be
the only fuel component, and so the H.sub.2 LHV would cancel out of
the equation. In the more general case, the anode feed may contain,
for example, CH.sub.4, H.sub.2, and CO in various amounts. Because
these species can typically be present in different amounts in the
anode outlet, the summation as described above can be needed to
determine the fuel utilization.
[0109] Alternatively or in addition to fuel utilization, the
utilization for other reactants in the fuel cell can be
characterized. For example, the operation of a fuel cell can
additionally or alternately be characterized with regard to
"CO.sub.2 utilization" and/or "oxidant" utilization. The values for
CO.sub.2 utilization and/or oxidant utilization can be specified in
a similar manner.
[0110] Fuel surplus ratio: Still another way to characterize the
reactions in a molten carbonate fuel cell is by defining a
utilization based on a ratio of the Lower Heating Value of all fuel
delivered to the anode and/or a reforming stage associated with the
anode relative to the Lower Heating Value of hydrogen oxidized in
the anode due to the fuel cell anode reaction. This quantity will
be referred to as a fuel surplus ratio. As such the fuel surplus
ratio can be computed as (LHV
(anode_in)/(LHV(anode_in)-LHV(anode_out)) where LHV(anode_in) and
LHV(anode_out) refer to the LHV of the fuel components (such as
H.sub.2, CH.sub.4, and/or CO) in the anode inlet and outlet streams
or flows, respectively. In various aspects of the invention, a
molten carbonate fuel cell can be operated to have a fuel surplus
ratio of at least about 1.0, such as at least about 1.5, or at
least about 2.0, or at least about 2.5, or at least about 3.0, or
at least about 4.0. Additionally or alternately, the fuel surplus
ratio can be about 25.0 or less.
[0111] It is noted that not all of the reformable fuel in the input
stream for the anode may be reformed. Preferably, at least about
90% of the reformable fuel in the input stream to the anode (and/or
into an associated reforming stage) can be reformed prior to
exiting the anode, such as at least about 95% or at least about
98%. In some alternative aspects, the amount of reformable fuel
that is reformed can be from about 75% to about 90%, such as at
least about 80%.
[0112] The above definition for fuel surplus ratio provides a
method for characterizing the amount of reforming occurring within
the anode and/or reforming stage(s) associated with a fuel cell
relative to the amount of fuel consumed in the fuel cell anode for
generation of electric power.
[0113] Optionally, the fuel surplus ratio can be modified to
account for situations where fuel is recycled from the anode output
to the anode input. When fuel (such as H.sub.2, CO, and/or
unreformed or partially reformed hydrocarbons) is recycled from
anode output to anode input, such recycled fuel components do not
represent a surplus amount of reformable or reformed fuel that can
be used for other purposes. Instead, such recycled fuel components
merely indicate a desire to reduce fuel utilization in a fuel
cell.
[0114] Reformable fuel surplus ratio: Calculating a reformable fuel
surplus ratio is one option to account for such recycled fuel
components is to narrow the definition of surplus fuel, so that
only the LHV of reformable fuels is included in the input stream to
the anode. As used herein the "reformable fuel surplus ratio" is
defined as the Lower Heating Value of reformable fuel delivered to
the anode and/or a reforming stage associated with the anode
relative to the Lower Heating Value of hydrogen oxidized in the
anode due to the fuel cell anode reaction. Under the definition for
reformable fuel surplus ratio, the LHV of any H.sub.2 or CO in the
anode input is excluded. Such an LHV of reformable fuel can still
be measured by characterizing the actual composition entering a
fuel cell anode, so no distinction between recycled components and
fresh components needs to be made. Although some non-reformed or
partially reformed fuel may also be recycled, in most aspects the
majority of the fuel recycled to the anode can correspond to
reformed products such as H.sub.2 or CO. Expressed mathematically,
the reformable fuel surplus ratio
(R.sub.RFS)=LHV.sub.RF/LHV.sub.OH, where LHV.sub.RF is the Lower
Heating Value (LHV) of the reformable fuel and LHV.sub.OH is the
Lower Heating Value (LHV) of the hydrogen oxidized in the anode.
The LHV of the hydrogen oxidized in the anode may be calculated by
subtracting the LHV of the anode outlet stream from the LHV of the
anode inlet stream (e.g., LHV(anode_in)-LHV(anode_out)). In various
aspects of the invention, a molten carbonate fuel cell can be
operated to have a reformable fuel surplus ratio of at least about
0.25, such as at least about 0.5, or at least about 1.0, or at
least about 1.5, or at least about 2.0, or at least about 2.5, or
at least about 3.0, or at least about 4.0. Additionally or
alternately, the reformable fuel surplus ratio can be about 25.0 or
less. It is noted that this narrower definition based on the amount
of reformable fuel delivered to the anode relative to the amount of
oxidation in the anode can distinguish between two types of fuel
cell operation methods that have low fuel utilization. Some fuel
cells achieve low fuel utilization by recycling a substantial
portion of the anode output back to the anode input. This recycle
can allow any hydrogen in the anode input to be used again as an
input to the anode. This can reduce the amount of reforming, as
even though the fuel utilization is low for a single pass through
the fuel cell, at least a portion of the unused fuel is recycled
for use in a later pass. Thus, fuel cells with a wide variety of
fuel utilization values may have the same ratio of reformable fuel
delivered to the anode reforming stage(s) versus hydrogen oxidized
in the anode reaction. In order to change the ratio of reformable
fuel delivered to the anode reforming stages relative to the amount
of oxidation in the anode, either an anode feed with a native
content of non-reformable fuel needs to be identified, or unused
fuel in the anode output needs to be withdrawn for other uses, or
both.
[0115] Reformable hydrogen surplus ratio: Still another option for
characterizing the operation of a fuel cell is based on a
"reformable hydrogen surplus ratio." The reformable fuel surplus
ratio defined above is defined based on the lower heating value of
reformable fuel components. The reformable hydrogen surplus ratio
is defined as the reformable hydrogen content of reformable fuel
delivered to the anode and/or a reforming stage associated with the
anode relative to the hydrogen reacted in the anode due to the fuel
cell anode reaction. As such, the "reformable hydrogen surplus
ratio" can be computed as
(RFC(reformable_anode_in)/(RFC(reformable_anode_in)-RFC(anode_out)),
where RFC(reformable_anode_in) refers to the reformable hydrogen
content of reformable fuels in the anode inlet streams or flows,
while RFC (anode_out) refers to the reformable hydrogen content of
the fuel components (such as H.sub.2, CH.sub.4, and/or CO) in the
anode inlet and outlet streams or flows. The RFC can be expressed
in moles/s, moles/hr, or similar. An example of a method for
operating a fuel cell with a large ratio of reformable fuel
delivered to the anode reforming stage(s) versus amount of
oxidation in the anode can be a method where excess reforming is
performed in order to balance the generation and consumption of
heat in the fuel cell. Reforming a reformable fuel to form H.sub.2
and CO is an endothermic process. This endothermic reaction can be
countered by the generation of electrical current in the fuel cell,
which can also produce excess heat corresponding (roughly) to the
difference between the amount of heat generated by the anode
oxidation reaction and the carbonate formation reaction and the
energy that exits the fuel cell in the form of electric current.
The excess heat per mole of hydrogen involved in the anode
oxidation reaction/carbonate formation reaction can be greater than
the heat absorbed to generate a mole of hydrogen by reforming. As a
result, a fuel cell operated under conventional conditions can
exhibit a temperature increase from inlet to outlet. Instead of
this type of conventional operation, the amount of fuel reformed in
the reforming stages associated with the anode can be increased.
For example, additional fuel can be reformed so that the heat
generated by the exothermic fuel cell reactions can be (roughly)
balanced by the heat consumed in reforming, or even the heat
consumed by reforming can be beyond the excess heat generated by
the fuel oxidation, resulting in a temperature drop across the fuel
cell. This can result in a substantial excess of hydrogen relative
to the amount needed for electrical power generation. As one
example, a feed to the anode inlet of a fuel cell or an associated
reforming stage can be substantially composed of reformable a)
fuel, such as a substantially pure methane feed. During
conventional operation for electric power generation using such a
fuel, a molten carbonate fuel cell can be operated with a fuel
utilization of about 75%. This means that about 75% (or 3/4) of the
fuel content delivered to the anode is used to form hydrogen that
is then reacted in the anode with carbonate ions to form H.sub.2O
and CO.sub.2. In conventional operation, the remaining about 25% of
the fuel content can be reformed to H.sub.2 within the fuel cell
(or can pass through the fuel cell unreacted for any CO or H.sub.2
in the fuel), and then combusted outside of the fuel cell to form
H.sub.2O and CO.sub.2 to provide heat for the cathode inlet to the
fuel cell. The reformable hydrogen surplus ratio in this situation
can be 4/(4-1)=4/3.
[0116] Electrical efficiency: As used herein, the term "electrical
efficiency" ("EE") is defined as the electrochemical power produced
by the fuel cell divided by the rate of Lower Heating Value ("LHV")
of fuel input to the fuel cell. The fuel inputs to the fuel cell
includes both fuel delivered to the anode as well as any fuel used
to maintain the temperature of the fuel cell, such as fuel
delivered to a burner associated with a fuel cell. In this
description, the power produced by the fuel may be described in
terms of LHV(el) fuel rate.
[0117] Electrochemical power: As used herein, the term
"electrochemical power" or LHV(el) is the power generated by the
circuit connecting the cathode to the anode in the fuel cell and
the transfer of carbonate ions across the fuel cell's electrolyte.
Electrochemical power excludes power produced or consumed by
equipment upstream or downstream from the fuel cell. For example,
electricity produced from heat in a fuel cell exhaust stream is not
considered part of the electrochemical power. Similarly, power
generated by a gas turbine or other equipment upstream of the fuel
cell is not part of the electrochemical power generated. The
"electrochemical power" does not take electrical power consumed
during operation of the fuel cell into account, or any loss
incurred by conversion of the direct current to alternating
current. In other words, electrical power used to supply the fuel
cell operation or otherwise operate the fuel cell is not subtracted
from the direct current power produced by the fuel cell. As used
herein, the power density is the current density multiplied by
voltage. As used herein, the total fuel cell power is the power
density multiplied by the fuel cell area.
[0118] Fuel inputs: As used herein, the term "anode fuel input,"
designated as LHV(anode_in), is the amount of fuel within the anode
inlet stream. The term "fuel input", designated as LHV(in), is the
total amount of fuel delivered to the fuel cell, including both the
amount of fuel within the anode inlet stream and the amount of fuel
used to maintain the temperature of the fuel cell. The fuel may
include both reformable and nonreformable fuels, based on the
definition of a reformable fuel provided herein. Fuel input is not
the same as fuel utilization.
[0119] Total fuel cell efficiency: As used herein, the term "total
fuel cell efficiency" ("TFCE") is defined as: the electrochemical
power generated by the fuel cell, plus the rate of LHV of syngas
produced by the fuel cell, divided by the rate of LHV of fuel input
to the anode. In other words, TFCE=(LHV(el)+LHV(sg
net))/LHV(anode_in), where LHV(anode_in) refers to rate at which
the LHV of the fuel components (such as H.sub.2, CH.sub.4, and/or
CO) delivered to the anode and LHV(sg net) refers to a rate at
which syngas (H.sub.2, CO) is produced in the anode, which is the
difference between syngas input to the anode and syngas output from
the anode. LHV(el) describes the electrochemical power generation
of the fuel cell. The total fuel cell efficiency excludes heat
generated by the fuel cell that is put to beneficial use outside of
the fuel cell. In operation, heat generated by the fuel cell may be
put to beneficial use by downstream equipment. For example, the
heat may be used to generate additional electricity or to heat
water. These uses, when they occur apart from the fuel cell, are
not part of the total fuel cell efficiency, as the term is used in
this application. The total fuel cell efficiency is for the fuel
cell operation only, and does not include power production, or
consumption, upstream, or downstream, of the fuel cell.
[0120] Chemical efficiency: As used herein, the term "chemical
efficiency", is defined as the lower heating value of H.sub.2 and
CO in the anode exhaust of the fuel cell, or LHV(sg out), divided
by the fuel input, or LHV(in).
[0121] Neither the electrical efficiency nor the total system
efficiency takes the efficiency of upstream or downstream processes
into consideration. For example, it may be advantageous to use
turbine exhaust as a source of CO.sub.2 for the fuel cell cathode.
In this arrangement, the efficiency of the turbine is not
considered as part of the electrical efficiency or the total fuel
cell efficiency calculation. Similarly, outputs from the fuel cell
may be recycled as inputs to the fuel cell. A recycle loop is not
considered when calculating electrical efficiency or the total fuel
cell efficiency in single pass mode.
[0122] Syngas produced: As used herein, the term "syngas produced"
is the difference between syngas input to the anode and syngas
output from the anode. Syngas may be used as an input, or fuel, for
the anode, at least in part. For example, a system may include an
anode recycle loop that returns syngas from the anode exhaust to
the anode inlet where it is supplemented with natural gas or other
suitable fuel. Syngas produced LHV (sg net)=(LHV(sg out)-LHV(sg
in)), where LHV(sg in) and LHV(sg out) refer to the LHV of the
syngas in the anode inlet and syngas in the anode outlet streams or
flows, respectively. It is noted that at least a portion of the
syngas produced by the reforming reactions within an anode can
typically be utilized in the anode to produce electricity. The
hydrogen utilized to produce electricity is not included in the
definition of "syngas produced" because it does not exit the anode.
As used herein, the term "syngas ratio" is the LHV of the net
syngas produced divided by the LHV of the fuel input to the anode
or LHV (sg net)/LHV(anode in). Molar flow rates of syngas and fuel
can be used instead of LHV to express a molar-based syngas ratio
and a molar-based syngas produced.
[0123] Steam to carbon ratio (S/C): As used herein, the steam to
carbon ratio (S/C) is the molar ratio of steam in a flow to
reformable carbon in the flow. Carbon in the form of CO and
CO.sub.2 are not included as reformable carbon in this definition.
The steam to carbon ratio can be measured and/or controlled at
different points in the system. For example, the composition of an
anode inlet stream can be manipulated to achieve a S/C that is
suitable for reforming in the anode. The S/C can be given as the
molar flow rate of H.sub.2O divided by the product of the molar
flow rate of fuel multiplied by the number of carbon atoms in the
fuel, e.g. one for methane. Thus, S/C=f.sub.H20/(f.sub.CH4 X #C),
where f.sub.H20 is the molar flow rate of water, where f.sub.CH4 is
the molar flow rate of methane (or other fuel) and #C is the number
of carbons in the fuel.
[0124] EGR ratio: Aspects of the invention can use a turbine in
partnership with a fuel cell. The combined fuel cell and turbine
system may include exhaust gas recycle ("EGR"). In an EGR system,
at least a portion of the exhaust gas generated by the turbine can
be sent to a heat recovery generator. Another portion of the
exhaust gas can be sent to the fuel cell. The EGR ratio describes
the amount of exhaust gas routed to the fuel cell versus the total
exhaust gas routed to either the fuel cell or heat recovery
generator. As used herein, the "EGR ratio" is the flow rate for the
fuel cell bound portion of the exhaust gas divided by the combined
flow rate for the fuel cell bound portion and the recovery bound
portion, which is sent to the heat recovery generator.
[0125] In various aspects of the invention, a molten carbonate fuel
cell (MCFC) can be used to facilitate separation of CO.sub.2 from a
CO.sub.2-containing stream while also generating additional
electrical power. The CO.sub.2 separation can be further enhanced
by taking advantage of synergies with the combustion-based power
generator that can provide at least a portion of the input feed to
the cathode portion of the fuel cell.
[0126] Fuel Cell and Fuel Cell Components: In this discussion, a
fuel cell can correspond to a single cell, with an anode and a
cathode separated by an electrolyte. The anode and cathode can
receive input gas flows to facilitate the respective anode and
cathode reactions for transporting charge across the electrolyte
and generating electricity. A fuel cell stack can represent a
plurality of cells in an integrated unit. Although a fuel cell
stack can include multiple fuel cells, the fuel cells can typically
be connected in parallel and can function (approximately) as if
they collectively represented a single fuel cell of a larger size.
When an input flow is delivered to the anode or cathode of a fuel
cell stack, the fuel stack can include flow channels for dividing
the input flow between each of the cells in the stack and flow
channels for combining the output flows from the individual cells.
In this discussion, a fuel cell array can be used to refer to a
plurality of fuel cells (such as a plurality of fuel cell stacks)
that are arranged in series, in parallel, or in any other
convenient manner (e.g., in a combination of series and parallel).
A fuel cell array can include one or more stages of fuel cells
and/or fuel cell stacks, where the anode/cathode output from a
first stage may serve as the anode/cathode input for a second
stage. It is noted that the anodes in a fuel cell array do not have
to be connected in the same way as the cathodes in the array. For
convenience, the input to the first anode stage of a fuel cell
array may be referred to as the anode input for the array, and the
input to the first cathode stage of the fuel cell array may be
referred to as the cathode input to the array. Similarly, the
output from the final anode/cathode stage may be referred to as the
anode/cathode output from the array.
[0127] It should be understood that reference to use of a fuel cell
herein typically denotes a "fuel cell stack" composed of individual
fuel cells, and more generally refers to use of one or more fuel
cell stacks in fluid communication. Individual fuel cell elements
(plates) can typically be "stacked" together in a rectangular array
called a "fuel cell stack". This fuel cell stack can typically take
a feed stream and distribute reactants among all of the individual
fuel cell elements and can then collect the products from each of
these elements. When viewed as a unit, the fuel cell stack in
operation can be taken as a whole even though composed of many
(often tens or hundreds) of individual fuel cell elements. These
individual fuel cell elements can typically have similar voltages
(as the reactant and product concentrations are similar), and the
total power output can result from the summation of all of the
electrical currents in all of the cell elements, when the elements
are electrically connected in series. Stacks can also be arranged
in a series arrangement to produce high voltages. A parallel
arrangement can boost the current. If a sufficiently large volume
fuel cell stack is available to process a given exhaust flow, the
systems and methods described herein can be used with a single
molten carbonate fuel cell stack. In other aspects of the
invention, a plurality of fuel cell stacks may be desirable or
needed for a variety of reasons.
[0128] For the purposes of this invention, unless otherwise
specified, the term "fuel cell" should be understood to also refer
to and/or is defined as including a reference to a fuel cell stack
composed of set of one or more individual fuel cell elements for
which there is a single input and output, as that is the manner in
which fuel cells are typically employed in practice. Similarly, the
term fuel cells (plural), unless otherwise specified, should be
understood to also refer to and/or is defined as including a
plurality of separate fuel cell stacks. In other words, all
references within this document, unless specifically noted, can
refer interchangeably to the operation of a fuel cell stack as a
"fuel cell". For example, the volume of exhaust generated by a
commercial scale combustion generator may be too large for
processing by a fuel cell (i.e., a single stack) of conventional
size. In order to process the full exhaust, a plurality of fuel
cells (i.e., two or more separate fuel cells or fuel cell stacks)
can be arranged in parallel, so that each fuel cell can process
(roughly) an equal portion of the combustion exhaust. Although
multiple fuel cells can be used, each fuel cell can typically be
operated in a generally similar manner, given its (roughly) equal
portion of the combustion exhaust.
[0129] "Internal reforming" and "external reforming": A fuel cell
or fuel cell stack may include one or more internal reforming
sections. As used herein, the term "internal reforming" refers to
fuel reforming occurring within the body of a fuel cell, a fuel
cell stack, or otherwise within a fuel cell assembly. External
reforming, which is often used in conjunction with a fuel cell,
occurs in a separate piece of equipment that is located outside of
the fuel cell stack. In other words, the body of the external
reformer is not in direct physical contact with the body of a fuel
cell or fuel cell stack. In a typical set up, the output from the
external reformer can be fed to the anode inlet of a fuel cell.
Unless otherwise noted specifically, the reforming described within
this application is internal reforming.
[0130] Internal reforming may occur within a fuel cell anode.
Internal reforming can additionally or alternately occur within an
internal reforming element integrated within a fuel cell assembly.
The integrated reforming element may be located between fuel cell
elements within a fuel cell stack. In other words, one of the trays
in the stack can be a reforming section instead of a fuel cell
element. In one aspect, the flow arrangement within a fuel cell
stack directs fuel to the internal reforming elements and then into
the anode portion of the fuel cells. Thus, from a flow perspective,
the internal reforming elements and fuel cell elements can be
arranged in series within the fuel cell stack. As used herein, the
term "anode reforming" is fuel reforming that occurs within an
anode. As used herein, the term "internal reforming" is reforming
that occurs within an integrated reforming element and not in an
anode section.
[0131] In some aspects, a reforming stage that is internal to a
fuel cell assembly can be considered to be associated with the
anode(s) in the fuel cell assembly. In some alternative aspects,
for a reforming stage in a fuel cell stack that can be associated
with an anode (such as associated with multiple anodes), a flow
path can be available so that the output flow from the reforming
stage is passed into at least one anode. This can correspond to
having an initial section of a fuel cell plate not in contact with
the electrolyte and instead can serve just as a reforming catalyst.
Another option for an associated reforming stage can be to have a
separate integrated reforming stage as one of the elements in a
fuel cell stack, where the output from the integrated reforming
stage can be returned to the input side of one or more of the fuel
cells in the fuel cell stack.
[0132] From a heat integration standpoint, a characteristic height
in a fuel cell stack can be the height of an individual fuel cell
stack element. It is noted that the separate reforming stage and/or
a separate endothermic reaction stage could have a different height
in the stack than a fuel cell. In such a scenario, the height of a
fuel cell element can be used as the characteristic height. In some
aspects, an integrated endothermic reaction stage can be defined as
a stage that is heat integrated with one or more fuel cells, so
that the integrated endothermic reaction stage can use the heat
from the fuel cells as a heat source for the endothermic reaction.
Such an integrated endothermic reaction stage can be defined as
being positioned less than 5 times the height of a stack element
from any fuel cells providing heat to the integrated stage. For
example, an integrated endothermic reaction stage (such as a
reforming stage) can be positioned less than 5 times the height of
a stack element from any fuel cells that are heat integrated, such
as less than 3 times the height of a stack element. In this
discussion, an integrated reforming stage and/or integrated
endothermic reaction stage that represent an adjacent stack element
to a fuel cell element can be defined as being about one stack
element height or less away from the adjacent fuel cell
element.
[0133] In some aspects, a separate reforming stage that is heat
integrated with a fuel cell element can correspond to a reforming
stage associated with the fuel cell element. In such aspects, an
integrated fuel cell element can provide at least a portion of the
heat to the associated reforming stage, and the associated
reforming stage can provide at least a portion of the reforming
stage output to the integrated fuel cell as a fuel stream. In other
aspects, a separate reforming stage can be integrated with a fuel
cell for heat transfer without being associated with the fuel cell.
In this type of situation, the separate reforming stage can receive
heat from the fuel cell, but the decision can be made not to use
the output of the reforming stage as an input to the fuel cell.
Instead, the decision can be made to use the output of such a
reforming stage for another purpose, such as directly adding the
output to the anode exhaust stream, and/or for forming a separate
output stream from the fuel cell assembly.
[0134] More generally, a separate stack element in a fuel cell
stack can be used to perform any convenient type of endothermic
reaction that can take advantage of the waste heat provided by
integrated fuel cell stack elements. Instead of plates suitable for
performing a reforming reaction on a hydrocarbon fuel stream, a
separate stack element can have plates suitable for catalyzing
another type of endothermic reaction. A manifold or other
arrangement of inlet conduits in the fuel cell stack can be used to
provide an appropriate input flow to each stack element. A similar
manifold or other arrangement of outlet conduits can additionally
or alternately be used to withdraw the output flows from each stack
element. Optionally, the output flows from a endothermic reaction
stage in a stack can be withdrawn from the fuel cell stack without
having the output flow pass through a fuel cell anode. In such an
optional aspect, the products of the exothermic reaction can
therefore exit from the fuel cell stack without passing through a
fuel cell anode. Examples of other types of endothermic reactions
that can be performed in stack elements in a fuel cell stack can
include, without limitation, ethanol dehydration to form ethylene
and ethane cracking.
[0135] Recycle: As defined herein, recycle of a portion of a fuel
cell output (such as an anode exhaust or a stream separated or
withdrawn from an anode exhaust) to a fuel cell inlet can
correspond to a direct or indirect recycle stream. A direct recycle
of a stream to a fuel cell inlet is defined as recycle of the
stream without passing through an intermediate process, while an
indirect recycle involves recycle after passing a stream through
one or more intermediate processes. For example, if the anode
exhaust is passed through a CO.sub.2 separation stage prior to
recycle, this is considered an indirect recycle of the anode
exhaust. If a portion of the anode exhaust, such as an H.sub.2
stream withdrawn from the anode exhaust, is passed into a gasifier
for converting coal into a fuel suitable for introduction into the
fuel cell, then that is also considered an indirect recycle.
Anode Inputs and Outputs
[0136] In various aspects of the invention, the MCFC array can be
fed by a fuel received at the anode inlet that comprises, for
example, both hydrogen and a hydrocarbon such as methane (or
alternatively a hydrocarbonaceous or hydrocarbon-like compound that
may contain heteroatoms different from C and H). Most of the
methane (or other hydrocarbonaceous or hydrocarbon-like compound)
fed to the anode can typically be fresh methane. In this
description, a fresh fuel such as fresh methane refers to a fuel
that is not recycled from another fuel cell process. For example,
methane recycled from the anode outlet stream back to the anode
inlet may not be considered "fresh" methane, and can instead be
described as reclaimed methane. The fuel source used can be shared
with other components, such as a turbine that uses a portion of the
fuel source to provide a CO.sub.2-containing stream for the cathode
input. The fuel source input can include water in a proportion to
the fuel appropriate for reforming the hydrocarbon (or
hydrocarbon-like) compound in the reforming section that generates
hydrogen. For example, if methane is the fuel input for reforming
to generate H.sub.2, the molar ratio of water to fuel can be from
about one to one to about ten to one, such as at least about two to
one. A ratio of four to one or greater is typical for external
reforming, but lower values can be typical for internal reforming
To the degree that H.sub.2 is a portion of the fuel source, in some
optional aspects no additional water may be needed in the fuel, as
the oxidation of H.sub.2 at the anode can tend to produce H.sub.2O
that can be used for reforming the fuel. The fuel source can also
optionally contain components incidental to the fuel source (e.g.,
a natural gas feed can contain some content of CO.sub.2 as an
additional component). For example, a natural gas feed can contain
CO.sub.2, N.sub.2, and/or other inert (noble) gases as additional
components. Optionally, in some aspects the fuel source may also
contain CO, such as CO from a recycled portion of the anode
exhaust. An additional or alternate potential source for CO in the
fuel into a fuel cell assembly can be CO generated by steam
reforming of a hydrocarbon fuel performed on the fuel prior to
entering the fuel cell assembly.
[0137] More generally, a variety of types of fuel streams may be
suitable for use as an input stream for the anode of a molten
carbonate fuel cell. Some fuel streams can correspond to streams
containing hydrocarbons and/or hydrocarbon-like compounds that may
also include heteroatoms different from C and H. In this
discussion, unless otherwise specified, a reference to a fuel
stream containing hydrocarbons for an MCFC anode is defined to
include fuel streams containing such hydrocarbon-like compounds.
Examples of hydrocarbon (including hydrocarbon-like) fuel streams
include natural gas, streams containing C1-C4 carbon compounds
(such as methane or ethane), and streams containing heavier C5+
hydrocarbons (including hydrocarbon-like compounds), as well as
combinations thereof. Still other additional or alternate examples
of potential fuel streams for use in an anode input can include
biogas-type streams, such as methane produced from natural
(biological) decomposition of organic material.
[0138] In some aspects, a molten carbonate fuel cell can be used to
process an input fuel stream, such as a natural gas and/or
hydrocarbon stream, with a low energy content due to the presence
of diluent compounds. For example, some sources of methane and/or
natural gas are sources that can include substantial amounts of
either CO.sub.2 or other inert molecules, such as nitrogen, argon,
or helium. Due to the presence of elevated amounts of CO.sub.2
and/or inerts, the energy content of a fuel stream based on the
source can be reduced. Using a low energy content fuel for a
combustion reaction (such as for powering a combustion-powered
turbine) can pose difficulties. However, a molten carbonate fuel
cell can generate power based on a low energy content fuel source
with a reduced or minimal impact on the efficiency of the fuel
cell. The presence of additional gas volume can require additional
heat for raising the temperature of the fuel to the temperature for
reforming and/or the anode reaction. Additionally, due to the
equilibrium nature of the water gas shift reaction within a fuel
cell anode, the presence of additional CO.sub.2 can have an impact
on the relative amounts of H.sub.2 and CO present in the anode
output. However, the inert compounds otherwise can have only a
minimal direct impact on the reforming and anode reactions. The
amount of CO.sub.2 and/or inert compounds in a fuel stream for a
molten carbonate fuel cell, when present, can be at least about 1
vol %, such as at least about 2 vol %, or at least about 5 vol %,
or at least about 10 vol %, or at least about 15 vol %, or at least
about 20 vol %, or at least about 25 vol %, or at least about 30
vol %, or at least about 35 vol %, or at least about 40 vol %, or
at least about 45 vol %, or at least about 50 vol %, or at least
about 75 vol %. Additionally or alternately, the amount of CO.sub.2
and/or inert compounds in a fuel stream for a molten carbonate fuel
cell can be about 90 vol % or less, such as about 75 vol % or less,
or about 60 vol % or less, or about 50 vol % or less, or about 40
vol % or less, or about 35 vol % or less.
[0139] Yet other examples of potential sources for an anode input
stream can correspond to refinery and/or other industrial process
output streams. For example, coking is a common process in many
refineries for converting heavier compounds to lower boiling
ranges. Coking typically produces an off-gas containing a variety
of compounds that are gases at room temperature, including CO and
various C1-C4 hydrocarbons. This off-gas can be used as at least a
portion of an anode input stream. Other refinery off-gas streams
can additionally or alternately be suitable for inclusion in an
anode input stream, such as light ends (C1-C4) generated during
cracking or other refinery processes. Still other suitable refinery
streams can additionally or alternately include refinery streams
containing CO or CO.sub.2 that also contain H.sub.2 and/or
reformable fuel compounds.
[0140] Still other potential sources for an anode input can
additionally or alternately include streams with increased water
content. For example, an ethanol output stream from an ethanol
plant (or another type of fermentation process) can include a
substantial portion of H.sub.2O prior to final distillation. Such
H.sub.2O can typically cause only minimal impact on the operation
of a fuel cell. Thus, a fermentation mixture of alcohol (or other
fermentation product) and water can be used as at least a portion
of an anode input stream.
[0141] Biogas, or digester gas, is another additional or alternate
potential source for an anode input. Biogas may primarily comprise
methane and CO.sub.2 and is typically produced by the breakdown or
digestion of organic matter. Anaerobic bacteria may be used to
digest the organic matter and produce the biogas. Impurities, such
as sulfur-containing compounds, may be removed from the biogas
prior to use as an anode input.
[0142] The output stream from an MCFC anode can include H.sub.2O,
CO.sub.2, CO, and H.sub.2. Optionally, the anode output stream
could also have unreacted fuel (such as H.sub.2 or CH.sub.4) or
inert compounds in the feed as additional output components.
Instead of using this output stream as a fuel source to provide
heat for a reforming reaction or as a combustion fuel for heating
the cell, one or more separations can be performed on the anode
output stream to separate the CO.sub.2 from the components with
potential value as inputs to another process, such as H.sub.2 or
CO. The H.sub.2 and/or CO can be used as a syngas for chemical
synthesis, as a source of hydrogen for chemical reaction, and/or as
a fuel with reduced greenhouse gas emissions.
[0143] In various aspects, the composition of the output stream
from the anode can be impacted by several factors. Factors that can
influence the anode output composition can include the composition
of the input stream to the anode, the amount of current generated
by the fuel cell, and/or the temperature at the exit of the anode.
The temperature of at the anode exit can be relevant due to the
equilibrium nature of the water gas shift reaction. In a typical
anode, at least one of the plates forming the wall of the anode can
be suitable for catalyzing the water gas shift reaction. As a
result, if a) the composition of the anode input stream is known,
b) the extent of reforming of reformable fuel in the anode input
stream is known, and c) the amount of carbonate transported from
the cathode to anode (corresponding to the amount of electrical
current generated) is known, the composition of the anode output
can be determined based on the equilibrium constant for the water
gas shift reaction.
K.sub.eq=[CO.sub.2][H.sub.2]/[CO][H.sub.2O]
[0144] In the above equation, K.sub.eq is the equilibrium constant
for the reaction at a given temperature and pressure, and [X] is
the partial pressure of component X. Based on the water gas shift
reaction, it can be noted that an increased CO.sub.2 concentration
in the anode input can tend to result in additional CO formation
(at the expense of H.sub.2) while an increased H.sub.2O
concentration can tend to result in additional H.sub.2 formation
(at the expense of CO).
[0145] To determine the composition at the anode output, the
composition of the anode input can be used as a starting point.
This composition can then be modified to reflect the extent of
reforming of any reformable fuels that can occur within the anode.
Such reforming can reduce the hydrocarbon content of the anode
input in exchange for increased hydrogen and CO.sub.2. Next, based
on the amount of electrical current generated, the amount of
H.sub.2 in the anode input can be reduced in exchange for
additional H.sub.2O and CO.sub.2. This composition can then be
adjusted based on the equilibrium constant for the water gas shift
reaction to determine the exit concentrations for H.sub.2, CO,
CO.sub.2, and H.sub.2O.
[0146] Table 1 shows the anode exhaust composition at different
fuel utilizations for a typical type of fuel. The anode exhaust
composition can reflect the combined result of the anode reforming
reaction, water gas shift reaction, and the anode oxidation
reaction. The output composition values in Table 1 were calculated
by assuming an anode input composition with an about 2 to 1 ratio
of steam (H.sub.2O) to carbon (reformable fuel). The reformable
fuel was assumed to be methane, which was assumed to be 100%
reformed to hydrogen. The initial CO.sub.2 and H.sub.2
concentrations in the anode input were assumed to be negligible,
while the input N.sub.2 concentration was about 0.5%. The fuel
utilization U.sub.f (as defined herein) was allowed to vary from
about 35% to about 70% as shown in the table. The exit temperature
for the fuel cell anode was assumed to be about 650.degree. C. for
purposes of determining the correct value for the equilibrium
constant.
TABLE-US-00001 TABLE 1 Anode Exhaust Composition Uf % 35% 40% 45%
50% 55% 60% 65% 70% Anode Exhaust Composition H.sub.2O %, wet 32.5%
34.1% 35.5% 36.7% 37.8% 38.9% 39.8% 40.5% CO.sub.2 %, wet 26.7%
29.4% 32.0% 34.5% 36.9% 39.3% 41.5% 43.8% H.sub.2 %, wet 29.4%
26.0% 22.9% 20.0% 17.3% 14.8% 12.5% 10.4% CO %, wet 10.8% 10.0%
9.2% 8.4% 7.5% 6.7% 5.8% 4.9% N.sub.2 %, wet 0.5% 0.5% 0.5% 0.4%
0.4% 0.4% 0.4% 0.4% CO.sub.2 %, dry 39.6% 44.6% 49.6% 54.5% 59.4%
64.2% 69.0% 73.7% H.sub.2 %, dry 43.6% 39.4% 35.4% 31.5% 27.8%
24.2% 20.7% 17.5% CO %, dry 16.1% 15.2% 14.3% 13.2% 12.1% 10.9%
9.7% 8.2% N.sub.2 %, dry 0.7% 0.7% 0.7% 0.7% 0.7% 0.7% 0.7% 0.7%
H.sub.2/CO 2.7 2.6 2.5 2.4 2.3 2.2 2.1 2.1 (H.sub.2--CO.sub.2)/
0.07 -0.09 -0.22 -0.34 -0.44 -0.53 -0.61 -0.69 (CO + CO.sub.2)
[0147] Table 1 shows anode output compositions for a particular set
of conditions and anode input composition. More generally, in
various aspects the anode output can include about 10 vol % to
about 50 vol % H.sub.2O. The amount of H.sub.2O can vary greatly,
as H.sub.2O in the anode can be produced by the anode oxidation
reaction. If an excess of H.sub.2O beyond what is needed for
reforming is introduced into the anode, the excess H.sub.2O can
typically pass through largely unreacted, with the exception of
H.sub.2O consumed (or generated) due to fuel reforming and the
water gas shift reaction. The CO.sub.2 concentration in the anode
output can also vary widely, such as from about 20 vol % to about
50 vol % CO.sub.2. The amount of CO.sub.2 can be influenced by both
the amount of electrical current generated as well as the amount of
CO.sub.2 in the anode input flow. The amount of H.sub.2 in the
anode output can additionally or alternately be from about 10 vol %
H.sub.2 to about 50 vol % H.sub.2, depending on the fuel
utilization in the anode. At the anode output, the amount of CO can
be from about 5 vol % to about 20 vol %. It is noted that the
amount of CO relative to the amount of H.sub.2 in the anode output
for a given fuel cell can be determined in part by the equilibrium
constant for the water gas shift reaction at the temperature and
pressure present in the fuel cell. The anode output can further
additionally or alternately include 5 vol % or less of various
other components, such as N.sub.2, CH.sub.4 (or other unreacted
carbon-containing fuels), and/or other components.
[0148] Optionally, one or more water gas shift reaction stages can
be included after the anode output to convert CO and H.sub.2O in
the anode output into CO.sub.2 and H.sub.2, if desired. The amount
of H.sub.2 present in the anode output can be increased, for
example, by using a water gas shift reactor at lower temperature to
convert H.sub.2O and CO present in the anode output into H.sub.2
and CO.sub.2. Alternatively, the temperature can be raised and the
water-gas shift reaction can be reversed, producing more CO and
H.sub.2O from H.sub.2 and CO.sub.2. Water is an expected output of
the reaction occurring at the anode, so the anode output can
typically have an excess of H.sub.2O relative to the amount of CO
present in the anode output. Alternatively, H.sub.2O can be added
to the stream after the anode exit but before the water gas shift
reaction. CO can be present in the anode output due to incomplete
carbon conversion during reforming and/or due to the equilibrium
balancing reactions between H.sub.2O, CO, H.sub.2, and CO.sub.2
(i.e., the water-gas shift equilibrium) under either reforming
conditions or the conditions present during the anode reaction. A
water gas shift reactor can be operated under conditions to drive
the equilibrium further in the direction of forming CO.sub.2 and
H.sub.2 at the expense of CO and H.sub.2O. Higher temperatures can
tend to favor the formation of CO and H.sub.2O. Thus, one option
for operating the water gas shift reactor can be to expose the
anode output stream to a suitable catalyst, such as a catalyst
including iron oxide, zinc oxide, copper on zinc oxide, or the
like, at a suitable temperature, e.g., between about 190.degree. C.
to about 210.degree. C. Optionally, the water-gas shift reactor can
include two stages for reducing the CO concentration in an anode
output stream, with a first higher temperature stage operated at a
temperature from at least about 300.degree. C. to about 375.degree.
C. and a second lower temperature stage operated at a temperature
of about 225.degree. C. or less, such as from about 180.degree. C.
to about 210.degree. C. In addition to increasing the amount of
H.sub.2 present in the anode output, the water-gas shift reaction
can additionally or alternately increase the amount of CO.sub.2 at
the expense of CO. This can exchange difficult-to-remove carbon
monoxide (CO) for carbon dioxide, which can be more readily removed
by condensation (e.g., cryogenic removal), chemical reaction (such
as amine removal), and/or other CO.sub.2 removal methods.
Additionally or alternately, it may be desirable to increase the CO
content present in the anode exhaust in order to achieve a desired
ratio of H.sub.2 to CO.
[0149] After passing through the optional water gas shift reaction
stage, the anode output can be passed through one or more
separation stages for removal of water and/or CO.sub.2 from the
anode output stream. For example, one or more CO.sub.2 output
streams can be formed by performing CO.sub.2 separation on the
anode output using one or more methods individually or in
combination. Such methods can be used to generate CO.sub.2 output
stream(s) having a CO.sub.2 content of 90 vol % or greater, such as
at least 95% vol % CO.sub.2, or at least 98 vol % CO.sub.2. Such
methods can recover about at least about 70% of the CO.sub.2
content of the anode output, such as at least about 80% of the
CO.sub.2 content of the anode output, or at least about 90%.
Alternatively, in some aspects it may be desirable to recover only
a portion of the CO.sub.2 within an anode output stream, with the
recovered portion of CO.sub.2 being about 33% to about 90% of the
CO.sub.2 in the anode output, such as at least about 40%, or at
least about 50%. For example, it may be desirable to retain some
CO.sub.2 in the anode output flow so that a desired composition can
be achieved in a subsequent water gas shift stage. Suitable
separation methods may comprise use of a physical solvent (e.g.,
Selexol.TM. or Rectisol.TM.); amines or other bases (e.g., MEA or
MDEA); refrigeration (e.g., cryogenic separation); pressure swing
adsorption; vacuum swing adsorption; and combinations thereof. A
cryogenic CO.sub.2 separator can be an example of a suitable
separator. As the anode output is cooled, the majority of the water
in the anode output can be separated out as a condensed (liquid)
phase. Further cooling and/or pressurizing of the water-depleted
anode output flow can then separate high purity CO.sub.2, as the
other remaining components in the anode output flow (such as
H.sub.2, N.sub.2, CH.sub.4) do not tend to readily form condensed
phases. A cryogenic CO.sub.2 separator can recover between about
33% and about 90% of the CO.sub.2 present in a flow, depending on
the operating conditions.
[0150] Removal of water from the anode exhaust to form one or more
water output streams can also be beneficial, whether prior to,
during, or after performing CO.sub.2 separation. The amount of
water in the anode output can vary depending on operating
conditions selected. For example, the steam-to-carbon ratio
established at the anode inlet can affect the water content in the
anode exhaust, with high steam-to-carbon ratios typically resulting
in a large amount of water that can pass through the anode
unreacted and/or reacted only due to the water gas shift
equilibrium in the anode. Depending on the aspect, the water
content in the anode exhaust can correspond to up to about 30% or
more of the volume in the anode exhaust. Additionally or
alternately, the water content can be about 80% or less of the
volume of the anode exhaust. While such water can be removed by
compression and/or cooling with resulting condensation, the removal
of this water can require extra compressor power and/or heat
exchange surface area and excessive cooling water. One beneficial
way to remove a portion of this excess water can be based on use of
an adsorbent bed that can capture the humidity from the moist anode
effluent and can then be `regenerated` using dry anode feed gas, in
order to provide additional water for the anode feed. HVAC-style
(heating, ventilation, and air conditioning) adsorption wheels
design can be applicable, because anode exhaust and inlet can be
similar in pressure, and minor leakage from one stream to the other
can have minimal impact on the overall process. In embodiments
where CO.sub.2 removal is performed using a cryogenic process,
removal of water prior to or during CO.sub.2 removal may be
desirable, including removal by triethyleneglycol (TEG) system
and/or desiccants. By contrast, if an amine wash is used for
CO.sub.2 removal, water can be removed from the anode exhaust
downstream from the CO.sub.2 removal stage.
[0151] Alternately or in addition to a CO.sub.2 output stream
and/or a water output stream, the anode output can be used to form
one or more product streams containing a desired chemical or fuel
product. Such a product stream or streams can correspond to a
syngas stream, a hydrogen stream, or both syngas product and
hydrogen product streams. For example, a hydrogen product stream
containing at least about 70 vol % H.sub.2, such as at least about
90 vol % H.sub.2 or at least about 95 vol % H.sub.2, can be formed.
Additionally or alternately, a syngas stream containing at least
about 70 vol % of H.sub.2 and CO combined, such as at least about
90 vol % of H.sub.2 and CO can be formed. The one or more product
streams can have a gas volume corresponding to at least about 75%
of the combined H.sub.2 and CO gas volumes in the anode output,
such as at least about 85% or at least about 90% of the combined
H.sub.2 and CO gas volumes. It is noted that the relative amounts
of H.sub.2 and CO in the products streams may differ from the
H.sub.2 to CO ratio in the anode output based on use of water gas
shift reaction stages to convert between the products.
[0152] In some aspects, it can be desirable to remove or separate a
portion of the H.sub.2 present in the anode output. For example, in
some aspects the H.sub.2 to CO ratio in the anode exhaust can be at
least about 3.0:1. By contrast, processes that make use of syngas,
such as Fischer-Tropsch synthesis, may consume H.sub.2 and CO in a
different ratio, such as a ratio that is closer to 2:1. One
alternative can be to use a water gas shift reaction to modify the
content of the anode output to have an H.sub.2 to CO ratio closer
to a desired syngas composition. Another alternative can be to use
a membrane separation to remove a portion of the H.sub.2 present in
the anode output to achieve a desired ratio of H.sub.2 and CO, or
still alternately to use a combination of membrane separation and
water gas shift reactions. One advantage of using a membrane
separation to remove only a portion of the H.sub.2 in the anode
output can be that the desired separation can be performed under
relatively mild conditions. Since one goal can be to produce a
retentate that still has a substantial H.sub.2 content, a permeate
of high purity hydrogen can be generated by membrane separation
without requiring severe conditions. For example, rather than
having a pressure on the permeate side of the membrane of about 100
kPaa or less (such as ambient pressure), the permeate side can be
at an elevated pressure relative to ambient while still having
sufficient driving force to perform the membrane separation.
Additionally or alternately, a sweep gas such as methane can be
used to provide a driving force for the membrane separation. This
can reduce the purity of the H.sub.2 permeate stream, but may be
advantageous, depending on the desired use for the permeate
stream.
[0153] In various aspects of the invention, at least a portion of
the anode exhaust stream (preferably after separation of CO.sub.2
and/or H.sub.2O) can be used as a feed for a process external to
the fuel cell and associated reforming stages. In various aspects,
the anode exhaust can have a ratio of H.sub.2 to CO of about 1.5:1
to about 10:1, such as at least about 3.0:1, or at least about
4.0:1, or at least about 5.0:1. A syngas stream can be generated or
withdrawn from the anode exhaust. The anode exhaust gas, optionally
after separation of CO.sub.2 and/or H.sub.2O, and optionally after
performing a water gas shift reaction and/or a membrane separation
to remove excess hydrogen, can correspond to a stream containing
substantial portions of H.sub.2 and/or CO. For a stream with a
relatively low content of CO, such as a stream where the ratio of
H.sub.2 to CO is at least about 3:1, the anode exhaust can be
suitable for use as an H.sub.2 feed. Examples of processes that
could benefit from an H.sub.2 feed can include, but are not limited
to, refinery processes, an ammonia synthesis plant, or a turbine in
a (different) power generation system, or combinations thereof.
Depending on the application, still lower CO.sub.2 contents can be
desirable. For a stream with an H.sub.2-to-CO ratio of less than
about 2.2 to 1 and greater than about 1.9 to 1, the stream can be
suitable for use as a syngas feed. Examples of processes that could
benefit from a syngas feed can include, but are not limited to, a
gas-to-liquids plant (such as a plant using a Fischer-Tropsch
process with a non-shifting catalyst) and/or a methanol synthesis
plant. The amount of the anode exhaust used as a feed for an
external process can be any convenient amount. Optionally, when a
portion of the anode exhaust is used as a feed for an external
process, a second portion of the anode exhaust can be recycled to
the anode input and/or recycled to the combustion zone for a
combustion-powered generator.
[0154] The input streams useful for different types of
Fischer-Tropsch synthesis processes can provide an example of the
different types of product streams that may be desirable to
generate from the anode output. For a Fischer-Tropsch synthesis
reaction system that uses a shifting catalyst, such as an
iron-based catalyst, the desired input stream to the reaction
system can include CO.sub.2 in addition to H.sub.2 and CO. If a
sufficient amount of CO.sub.2 is not present in the input stream, a
Fischer-Tropsch catalyst with water gas shift activity can consume
CO in order to generate additional CO.sub.2, resulting in a syngas
that can be deficient in CO. For integration of such a
Fischer-Tropsch process with an MCFC fuel cell, the separation
stages for the anode output can be operated to retain a desired
amount of CO.sub.2 (and optionally H.sub.2O) in the syngas product.
By contrast, for a Fischer-Tropsch catalyst based on a non-shifting
catalyst, any CO.sub.2 present in a product stream could serve as
an inert component in the Fischer-Tropsch reaction system.
[0155] In an aspect where the membrane is swept with a sweep gas
such as a methane sweep gas, the methane sweep gas can correspond
to a methane stream used as the anode fuel or in a different low
pressure process, such as a boiler, furnace, gas turbine, or other
fuel-consuming device. In such an aspect, low levels of CO.sub.2
permeation across the membrane can have minimal consequence. Such
CO.sub.2 that may permeate across the membrane can have a minimal
impact on the reactions within the anode, and such CO.sub.2 can
remain contained in the anode product. Therefore, the CO.sub.2 (if
any) lost across the membrane due to permeation does not need to be
transferred again across the MCFC electrolyte. This can
significantly reduce the separation selectivity requirement for the
hydrogen permeation membrane. This can allow, for example, use of a
higher-permeability membrane having a lower selectivity, which can
enable use of a lower pressure and/or reduced membrane surface
area. In such an aspect of the invention, the volume of the sweep
gas can be a large multiple of the volume of hydrogen in the anode
exhaust, which can allow the effective hydrogen concentration on
the permeate side to be maintained close to zero. The hydrogen thus
separated can be incorporated into the turbine-fed methane where it
can enhance the turbine combustion characteristics, as described
above.
[0156] It is noted that excess H.sub.2 produced in the anode can
represent a fuel where the greenhouse gases have already been
separated. Any CO.sub.2 in the anode output can be readily
separated from the anode output, such as by using an amine wash, a
cryogenic CO.sub.2 separator, and/or a pressure or vacuum swing
absorption process. Several of the components of the anode output
(H.sub.2, CO, CH.sub.4) are not easily removed, while CO.sub.2 and
H.sub.2O can usually be readily removed. Depending on the
embodiment, at least about 90 vol % of the CO.sub.2 in the anode
output can be separated out to form a relatively high purity
CO.sub.2 output stream. Thus, any CO.sub.2 generated in the anode
can be efficiently separated out to form a high purity CO.sub.2
output stream. After separation, the remaining portion of the anode
output can correspond primarily to components with chemical and/or
fuel value, as well as reduced amounts of CO.sub.2 and/or H.sub.2O,
Since a substantial portion of the CO.sub.2 generated by the
original fuel (prior to reforming) can have been separated out, the
amount of CO.sub.2 generated by subsequent burning of the remaining
portion of the anode output can be reduced. In particular, to the
degree that the fuel in the remaining portion of the anode output
is H.sub.2, no additional greenhouse gases can typically be formed
by burning of this fuel.
[0157] The anode exhaust can be subjected to a variety of gas
processing options, including water-gas shift and separation of the
components from each other. Two general anode processing schemes
are shown in FIGS. 6 and 7.
[0158] FIG. 6 schematically shows an example of a reaction system
for operating a fuel cell array of molten carbonate fuel cells in
conjunction with a chemical synthesis process. In FIG. 6, a fuel
stream 605 is provided to a reforming stage (or stages) 610
associated with the anode 627 of a fuel cell 620, such as a fuel
cell that is part of a fuel cell stack in a fuel cell array. The
reforming stage 610 associated with fuel cell 620 can be internal
to a fuel cell assembly. In some optional aspects, an external
reforming stage (not shown) can also be used to reform a portion of
the reformable fuel in an input stream prior to passing the input
stream into a fuel cell assembly. Fuel stream 605 can preferably
include a reformable fuel, such as methane, other hydrocarbons,
and/or other hydrocarbon-like compounds such as organic compounds
containing carbon-hydrogen bonds. Fuel stream 605 can also
optionally contain H.sub.2 and/or CO, such as H.sub.2 and/or CO
provided by optional anode recycle stream 685. It is noted that
anode recycle stream 685 is optional, and that in many aspects no
recycle stream is provided from the anode exhaust 625 back to anode
627, either directly or indirectly via combination with fuel stream
605 or reformed fuel stream 615. After reforming, the reformed fuel
stream 615 can be passed into anode 627 of fuel cell 620. A
CO.sub.2 and O.sub.2-containing stream 619 can also be passed into
cathode 629. A flow of carbonate ions 622, CO.sub.3.sup.2-, from
the cathode portion 629 of the fuel cell can provide the remaining
reactant needed for the anode fuel cell reactions. Based on the
reactions in the anode 627, the resulting anode exhaust 625 can
include H.sub.2O, CO.sub.2, one or more components corresponding to
incompletely reacted fuel (H.sub.2, CO, CH.sub.4, or other
components corresponding to a reformable fuel), and optionally one
or more additional nonreactive components, such as N.sub.2 and/or
other contaminants that are part of fuel stream 605. The anode
exhaust 625 can then be passed into one or more separation stages.
For example, a CO.sub.2 removal stage 640 can correspond to a
cryogenic CO.sub.2 removal system, an amine wash stage for removal
of acid gases such as CO.sub.2, or another suitable type of
CO.sub.2 separation stage for separating a CO.sub.2 output stream
643 from the anode exhaust. Optionally, the anode exhaust can first
be passed through a water gas shift reactor 630 to convert any CO
present in the anode exhaust (along with some H.sub.2O) into
CO.sub.2 and H.sub.2 in an optionally water gas shifted anode
exhaust 635. Depending on the nature of the CO.sub.2 removal stage,
a water condensation or removal stage 650 may be desirable to
remove a water output stream 653 from the anode exhaust. Though
shown in FIG. 6 after the CO.sub.2 separation stage 640, it may
optionally be located before the CO.sub.2 separation stage 640
instead. Additionally, an optional membrane separation stage 660
for separation of H.sub.2 can be used to generate a high purity
permeate stream 663 of H.sub.2. The resulting retentate stream 666
can then be used as an input to a chemical synthesis process.
Stream 666 could additionally or alternately be shifted in a second
water-gas shift reactor 631 to adjust the H.sub.2, CO, and CO.sub.2
content to a different ratio, producing an output stream 668 for
further use in a chemical synthesis process. In FIG. 6, anode
recycle stream 685 is shown as being withdrawn from the retentate
stream 666, but the anode recycle stream 685 could additionally or
alternately be withdrawn from other convenient locations in or
between the various separation stages. The separation stages and
shift reactor(s) could additionally or alternately be configured in
different orders, and/or in a parallel configuration. Finally, a
stream with a reduced content of CO.sub.2 639 can be generated as
an output from cathode 629. For the sake of simplicity, various
stages of compression and heat addition/removal that might be
useful in the process, as well as steam addition or removal, are
not shown.
[0159] As noted above, the various types of separations performed
on the anode exhaust can be performed in any convenient order. FIG.
7 shows an example of an alternative order for performing
separations on an anode exhaust. In FIG. 7, anode exhaust 625 can
be initially passed into separation stage 760 for removing a
portion 763 of the hydrogen content from the anode exhaust 625.
This can allow, for example, reduction of the H.sub.2 content of
the anode exhaust to provide a retentate 766 with a ratio of
H.sub.2 to CO closer to 2:1. The ratio of H.sub.2 to CO can then be
further adjusted to achieve a desired value in a water gas shift
stage 730. The water gas shifted output 735 can then pass through
CO.sub.2 separation stage 740 and water removal stage 750 to
produce an output stream 775 suitable for use as an input to a
desired chemical synthesis process. Optionally, output stream 775
could be exposed to an additional water gas shift stage (not
shown). A portion of output stream 775 can optionally be recycled
(not shown) to the anode input. Of course, still other combinations
and sequencing of separation stages can be used to generate a
stream based on the anode output that has a desired composition.
For the sake of simplicity, various stages of compression and heat
addition/removal that might be useful in the process, as well as
steam addition or removal, are not shown.
Cathode Inputs and Outputs
[0160] Conventionally, a molten carbonate fuel cell can be operated
based on drawing a desired load while consuming some portion of the
fuel in the fuel stream delivered to the anode. The voltage of the
fuel cell can then be determined by the load, fuel input to the
anode, air and CO.sub.2 provided to the cathode, and the internal
resistances of the fuel cell. The CO.sub.2 to the cathode can be
conventionally provided in part by using the anode a) exhaust as at
least a part of the cathode input stream. By contrast, the present
invention can use separate/different sources for the anode input
and cathode input. By removing any direct link between the
composition of the anode input flow and the cathode input flow,
additional options become available for operating the fuel cell,
such as to generate excess synthesis gas, to improve capture of
carbon dioxide, and/or to improve the total efficiency (electrical
plus chemical power) of the fuel cell, among others.
[0161] In a molten carbonate fuel cell, the transport of carbonate
ions across the electrolyte in the fuel cell can provide a method
for transporting CO.sub.2 from a first flow path to a second flow
path, where the transport method can allow transport from a lower
concentration (the cathode) to a higher concentration (the anode),
which can thus facilitate capture of CO.sub.2. Part of the
selectivity of the fuel cell for CO.sub.2 separation can be based
on the electrochemical reactions allowing the cell to generate
electrical power. For nonreactive species (such as N.sub.2) that
effectively do not participate in the electrochemical reactions
within the fuel cell, there can be an insignificant amount of
reaction and transport from cathode to anode. By contrast, the
potential (voltage) difference between the cathode and anode can
provide a strong driving force for transport of carbonate ions
across the fuel cell. As a result, the transport of carbonate ions
in the molten carbonate fuel cell can allow CO.sub.2 to be
transported from the cathode (lower CO.sub.2 concentration) to the
anode (higher CO.sub.2 concentration) with relatively high
selectivity. However, a challenge in using molten carbonate fuel
cells for carbon dioxide removal can be that the fuel cells have
limited ability to remove carbon dioxide from relatively dilute
cathode feeds. The voltage and/or power generated by a carbonate
fuel cell can start to drop rapidly as the CO.sub.2 concentration
falls below about 2.0 vol %. As the CO.sub.2 concentration drops
further, e.g., to below about 1.0 vol %, at some point the voltage
across the fuel cell can become low enough that little or no
further transport of carbonate may occur and the fuel cell ceases
to function. Thus, at least some CO.sub.2 is likely to be present
in the exhaust gas from the cathode stage of a fuel cell under
commercially viable operating conditions.
[0162] The amount of carbon dioxide delivered to the fuel cell
cathode(s) can be determined based on the CO.sub.2 content of a
source for the cathode inlet. One example of a suitable
CO.sub.2-containing stream for use as a cathode input flow can be
an output or exhaust flow from a combustion source. Examples of
combustion sources include, but are not limited to, sources based
on combustion of natural gas, combustion of coal, and/or combustion
of other hydrocarbon-type fuels (including biologically derived
fuels). Additional or alternate sources can include other types of
boilers, fired heaters, furnaces, and/or other types of devices
that burn carbon-containing fuels in order to heat another
substance (such as water or air). To a first approximation, the
CO.sub.2 content of the output flow from a combustion source can be
a minor portion of the flow. Even for a higher CO.sub.2 content
exhaust flow, such as the output from a coal-fired combustion
source, the CO.sub.2 content from most commercial coal-fired power
plants can be about 15 vol % or less. More generally, the CO.sub.2
content of an output or exhaust flow from a combustion source can
be at least about 1.5 vol %, or at least about 1.6 vol %, or at
least about 1.7 vol %, or at least about 1.8 vol %, or at least
about 1.9 vol %, or at least greater 2 vol %, or at least about 4
vol %, or at least about 5 vol %, or at least about 6 vol %, or at
least about 8 vol %. Additionally or alternately, the CO.sub.2
content of an output or exhaust flow from a combustion source can
be about 20 vol % or less, such as about 15 vol % or less, or about
12 vol % or less, or about 10 vol % or less, or about 9 vol % or
less, or about 8 vol % or less, or about 7 vol % or less, or about
6.5 vol % or less, or about 6 vol % or less, or about 5.5 vol % or
less, or about 5 vol % or less, or about 4.5 vol % or less. The
concentrations given above are on a dry basis. It is noted that the
lower CO.sub.2 content values can be present in the exhaust from
some natural gas or methane combustion sources, such as generators
that are part of a power generation system that may or may not
include an exhaust gas recycle loop.
[0163] Other potential sources for a cathode input stream can
additionally or alternately include sources of bio-produced
CO.sub.2. This can include, for example, CO.sub.2 generated during
processing of bio-derived compounds, such as CO.sub.2 generated
during ethanol production. An additional or alternate example can
include CO.sub.2 generated by combustion of a bio-produced fuel,
such as combustion of lignocellulose. Still other additional or
alternate potential CO.sub.2 sources can correspond to output or
exhaust streams from various industrial processes, such as
CO.sub.2-containing streams generated by plants for manufacture of
steel, cement, and/or paper.
[0164] Yet another additional or alternate potential source of
CO.sub.2 can be CO.sub.2-containing streams from a fuel cell. The
CO.sub.2-containing stream from a fuel cell can correspond to a
cathode output stream from a different fuel cell, an anode output
stream from a different fuel cell, a recycle stream from the
cathode output to the cathode input of a fuel cell, and/or a
recycle stream from an anode output to a cathode input of a fuel
cell. For example, an MCFC operated in standalone mode under
conventional conditions can generate a cathode exhaust with a
CO.sub.2 concentration of at least about 5 vol %. Such a
CO.sub.2-containing cathode exhaust could be used as a cathode
input for an MCFC operated according to an aspect of the invention.
More generally, other types of fuel cells that generate a CO.sub.2
output from the cathode exhaust can additionally or alternately be
used, as well as other types of CO.sub.2-containing streams not
generated by a "combustion" reaction and/or by a combustion-powered
generator. Optionally but preferably, a CO.sub.2-containing stream
from another fuel cell can be from another molten carbonate fuel
cell. For example, for molten carbonate fuel cells connected in
series with respect to the cathodes, the output from the cathode
for a first molten carbonate fuel cell can be used as the input to
the cathode for a second molten carbonate fuel cell.
[0165] For various types of CO.sub.2-containing streams from
sources other than combustion sources, the CO.sub.2 content of the
stream can vary widely. The CO.sub.2 content of an input stream to
a cathode can contain at least about 2 vol % of CO.sub.2, such as
at least about 4 vol %, or at least about 5 vol %, or at least
about 6 vol %, or at least about 8 vol %. Additionally or
alternately, the CO.sub.2 content of an input stream to a cathode
can be about 30 vol % or less, such as about 25 vol % or less, or
about 20 vol % or less, or about 15 vol % or less, or about 10 vol
% or less, or about 8 vol % or less, or about 6 vol % or less, or
about 4 vol % or less. For some still higher CO.sub.2 content
streams, the CO.sub.2 content can be greater than about 30 vol %,
such as a stream substantially composed of CO.sub.2 with only
incidental amounts of other compounds. As an example, a gas-fired
turbine without exhaust gas recycle can produce an exhaust stream
with a CO.sub.2 content of approximately 4.2 vol %. With EGR, a
gas-fired turbine can produce an exhaust stream with a CO.sub.2
content of about 6-8 vol %. Stoichiometric combustion of methane
can produce an exhaust stream with a CO.sub.2 content of about 11
vol %. Combustion of coal can produce an exhaust stream with a
CO.sub.2 content of about 15-20 vol %. Fired heaters using refinery
off-gas can produce an exhaust stream with a CO.sub.2 content of
about 12-15 vol %. A gas turbine operated on a low BTU gas without
any EGR can produce an exhaust stream with a CO.sub.2 content of
.about.12 vol %.
[0166] In addition to CO.sub.2, a cathode input stream must include
O.sub.2 to provide the components necessary for the cathode
reaction. Some cathode input streams can be based on having air as
a component. For example, a combustion exhaust stream can be formed
by combusting a hydrocarbon fuel in the presence of air. Such a
combustion exhaust stream, or another type of cathode input stream
having an oxygen content based on inclusion of air, can have an
oxygen content of about 20 vol % or less, such as about 15 vol % or
less, or about 10 vol % or less. Additionally or alternately, the
oxygen content of the cathode input stream can be at least about 4
vol %, such as at least about 6 vol %, or at least about 8 vol %.
More generally, a cathode input stream can have a suitable content
of oxygen for performing the cathode reaction. In some aspects,
this can correspond to an oxygen content of about 5 vol % to about
15 vol %, such as from about 7 vol % to about 9 vol %. For many
types of cathode input streams, the combined amount of CO.sub.2 and
O.sub.2 can correspond to less than about 21 vol % of the input
stream, such as less than about 15 vol % of the stream or less than
about 10 vol % of the stream. An air stream containing oxygen can
be combined with a CO.sub.2 source that has low oxygen content. For
example, the exhaust stream generated by burning coal may include a
low oxygen content that can be mixed with air to form a cathode
inlet stream.
[0167] In addition to CO.sub.2 and O.sub.2, a cathode input stream
can also be composed of inert/non-reactive species such as N.sub.2,
H.sub.2O, and other typical oxidant (air) components. For example,
for a cathode input derived from an exhaust from a combustion
reaction, if air is used as part of the oxidant source for the
combustion reaction, the exhaust gas can include typical components
of air such as N.sub.2, H.sub.2O, and other compounds in minor
amounts that are present in air. Depending on the nature of the
fuel source for the combustion reaction, additional species present
after combustion based on the fuel source may include one or more
of H.sub.2O, oxides of nitrogen (NOx) and/or sulfur (SOx), and
other compounds either present in the fuel and/or that are partial
or complete combustion products of compounds present in the fuel,
such as CO. These species may be present in amounts that do not
poison the cathode catalyst surfaces though they may reduce the
overall cathode activity. Such reductions in performance may be
acceptable, or species that interact with the cathode catalyst may
be reduced to acceptable levels by known pollutant removal
technologies.
[0168] The amount of O.sub.2 present in a cathode input stream
(such as an input cathode stream based on a combustion exhaust) can
advantageously be sufficient to provide the oxygen needed for the
cathode reaction in the fuel cell. Thus, the volume percentage of
O.sub.2 can advantageously be at least 0.5 times the amount of
CO.sub.2 in the exhaust. Optionally, as necessary, additional air
can be added to the cathode input to provide sufficient oxidant for
the cathode reaction. When some form of air is used as the oxidant,
the amount of N.sub.2 in the cathode exhaust can be at least about
78 vol %, e.g., at least about 88 vol %, and/or about 95 vol % or
less. In some aspects, the cathode input stream can additionally or
alternately contain compounds that are generally viewed as
contaminants, such as H.sub.25 or NH.sub.3. In other aspects, the
cathode input stream can be cleaned to reduce or minimize the
content of such contaminants.
[0169] In addition to the reaction to form carbonate ions for
transport across the electrolyte, the conditions in the cathode can
also be suitable for conversion of nitrogen oxides into nitrate
and/or nitrate ions. Hereinafter, only nitrate ions will be
referred to for convenience. The resulting nitrate ions can also be
transported across the electrolyte for reaction in the anode. NOx
concentrations in a cathode input stream can typically be on the
order of ppm, so this nitrate transport reaction can have a minimal
impact on the amount of carbonate transported across the
electrolyte. However, this method of NOx removal can be beneficial
for cathode input streams based on combustion exhausts from gas
turbines, as this can provide a mechanism for reducing NOx
emissions. The conditions in the cathode can additionally or
alternately be suitable for conversion of unburned hydrocarbons (in
combination with O.sub.2 in the cathode input stream) to typical
combustion products, such as CO.sub.2 and H.sub.2O.
[0170] A suitable temperature for operation of an MCFC can be
between about 450.degree. C. and about 750.degree. C., such as at
least about 500.degree. C., e.g., with an inlet temperature of
about 550.degree. C. and an outlet temperature of about 625.degree.
C. Prior to entering the cathode, heat can be added to or removed
from the combustion exhaust, if desired, e.g., to provide heat for
other processes, such as reforming the fuel input for the anode.
For example, if the source for the cathode input stream is a
combustion exhaust stream, the combustion exhaust stream may have a
temperature greater than a desired temperature for the cathode
inlet. In such an aspect, heat can be removed from the combustion
exhaust prior to use as the cathode input stream. Alternatively,
the combustion exhaust could be at very low temperature, for
example after a wet gas scrubber on a coal-fired boiler, in which
case the combustion exhaust can be below about 100.degree. C.
Alternatively, the combustion exhaust could be from the exhaust of
a gas turbine operated in combined cycle mode, in which the gas can
be cooled by raising steam to run a steam turbine for additional
power generation. In this case, the gas can be below about
50.degree. C. Heat can be added to a combustion exhaust that is
cooler than desired.
Fuel Cell Arrangement
[0171] In various aspects, a configuration option for a fuel cell
(such as a fuel cell array containing multiple fuel cell stacks)
can be to divide the CO.sub.2-containing stream between a plurality
of fuel cells. Some types of sources for CO.sub.2-containing
streams can generate large volumetric flow rates relative to the
capacity of an individual fuel cell. For example, the
CO.sub.2-containing output stream from an industrial combustion
source can typically correspond to a large flow volume relative to
desirable operating conditions for a single MCFC of reasonable
size. Instead of processing the entire flow in a single MCFC, the
flow can be divided amongst a plurality of MCFC units, usually at
least some of which can be in parallel, so that the flow rate in
each unit can be within a desired flow range.
[0172] A second configuration option can be to utilize fuel cells
in series to successively remove CO.sub.2 from a flow stream.
Regardless of the number of initial fuel cells to which a
CO.sub.2-containing stream can be distributed to in parallel, each
initial fuel cell can be followed by one or more additional cells
in series to further remove additional CO.sub.2. If the desired
amount of CO.sub.2 in the cathode output is sufficiently low,
attempting to remove CO.sub.2 from a cathode input stream down to
the desired level in a single fuel cell or fuel cell stage could
lead to a low and/or unpredictable voltage output for the fuel
cell. Rather than attempting to remove CO.sub.2 to the desired
level in a single fuel cell or fuel cell stage, CO.sub.2 can be
removed in successive cells until a desired level can be achieved.
For example, each cell in a series of fuel cells can be used to
remove some percentage (e.g., about 50%) of the CO.sub.2 present in
a fuel stream. In such an example, if three fuel cells are used in
series, the CO.sub.2 concentration can be reduced (e.g., to about
15% or less of the original amount present, which can correspond to
reducing the CO.sub.2 concentration from about 6% to about 1% or
less over the course of three fuel cells in series).
[0173] In another configuration, the operating conditions can be
selected in early fuel stages in series to provide a desired output
voltage while the array of stages can be selected to achieve a
desired level of carbon separation. As an example, an array of fuel
cells can be used with three fuel cells in series. The first two
fuel cells in series can be used to remove CO.sub.2 while
maintaining a desired output voltage. The final fuel cell can then
be operated to remove CO.sub.2 to a desired concentration but at a
lower voltage.
[0174] In still another configuration, there can be separate
connectivity for the anodes and cathodes in a fuel cell array. For
example, if the fuel cell array includes fuel cathodes connected in
series, the corresponding anodes can be connected in any convenient
manner, not necessarily matching up with the same arrangement as
their corresponding cathodes, for example. This can include, for
instance, connecting the anodes in parallel, so that each anode
receives the same type of fuel feed, and/or connecting the anodes
in a reverse series, so that the highest fuel concentration in the
anodes can correspond to those cathodes having the lowest CO.sub.2
concentration.
[0175] In yet another configuration, the amount of fuel delivered
to one or more anode stages and/or the amount of CO.sub.2 delivered
to one or more cathode stages can be controlled in order to improve
the performance of the fuel cell array. For example, a fuel cell
array can have a plurality of cathode stages connected in series.
In an array that includes three cathode stages in series, this can
mean that the output from a first cathode stage can correspond to
the input for a second cathode stage, and the output from the
second cathode stage can correspond to the input for a third
cathode stage. In this type of configuration, the CO.sub.2
concentration can decrease with each successive cathode stage. To
compensate for this reduced CO.sub.2 concentration, additional
hydrogen and/or methane can be delivered to the anode stages
corresponding to the later cathode stages. The additional hydrogen
and/or methane in the anodes corresponding to the later cathode
stages can at least partially offset the loss of voltage and/or
current caused by the reduced CO.sub.2 concentration, which can
increase the voltage and thus net power produced by the fuel cell.
In another example, the cathodes in a fuel cell array can be
connected partially in series and partially in parallel. In this
type of example, instead of passing the entire combustion output
into the cathodes in the first cathode stage, at least a portion of
the combustion exhaust can be passed into a later cathode stage.
This can provide an increased CO.sub.2 content in a later cathode
stage. Still other options for using variable feeds to either anode
stages or cathode stages can be used if desired.
[0176] The cathode of a fuel cell can correspond to a plurality of
cathodes from an array of fuel cells, as previously described. In
some aspects, a fuel cell array can be operated to improve or
maximize the amount of carbon transferred from the cathode to the
anode. In such aspects, for the cathode output from the final
cathode(s) in an array sequence (typically at least including a
series arrangement, or else the final cathode(s) and the initial
cathode(s) would be the same), the output composition can include
about 2.0 vol % or less of CO.sub.2 (e.g., about 1.5 vol % or less
or about 1.2 vol % or less) and/or at least about 1.0 vol % of
CO.sub.2, such as at least about 1.2 vol % or at least about 1.5
vol %. Due to this limitation, the net efficiency of CO.sub.2
removal when using molten carbonate fuel cells can be dependent on
the amount of CO.sub.2 in the cathode input. For cathode input
streams with CO.sub.2 contents of greater than about 6 vol %, such
as at least about 8%, the limitation on the amount of CO.sub.2 that
can be removed is not severe. However, for a combustion reaction
using natural gas as a fuel and with excess air, as is typically
found in a gas turbine, the amount of CO.sub.2 in the combustion
exhaust may only correspond to a CO.sub.2 concentration at the
cathode input of less than about 5 vol %. Use of exhaust gas
recycle can allow the amount of CO.sub.2 at the cathode input to be
increased to at least about 5 vol %, e.g., at least about 6 vol %.
If EGR is increased when using natural gas as a fuel to produce a
CO.sub.2 concentration beyond about 6 vol %, then the flammability
in the combustor can be decreased and the gas turbine may become
unstable. However, when H.sub.2 is added to the fuel, the
flammability window can be significantly increased, allowing the
amount of exhaust gas recycle to be increased further, so that
concentrations of CO.sub.2 at the cathode input of at least about
7.5 vol % or at least about 8 vol % can be achieved. As an example,
based on a removal limit of about 1.5 vol % at the cathode exhaust,
increasing the CO.sub.2 content at the cathode input from about 5.5
vol % to about 7.5 vol % can correspond to a .about.10% increase in
the amount of CO.sub.2 that can be captured using a fuel cell and
transported to the anode loop for eventual CO.sub.2 separation. The
amount of O.sub.2 in the cathode output can additionally or
alternately be reduced, typically in an amount proportional to the
amount of CO.sub.2 removed, which can result in small corresponding
increases in the amount(s) of the other (non-cathode-reactive)
species at the cathode exit.
[0177] In other aspects, a fuel cell array can be operated to
improve or maximize the energy output of the fuel cell, such as the
total energy output, the electric energy output, the syngas
chemical energy output, or a combination thereof. For example,
molten carbonate fuel cells can be operated with an excess of
reformable fuel in a variety of situations, such as for generation
of a syngas stream for use in chemical synthesis plant and/or for
generation of a high purity hydrogen stream. The syngas stream
and/or hydrogen stream can be used as a syngas source, a hydrogen
source, as a clean fuel source, and/or for any other convenient
application. In such aspects, the amount of CO.sub.2 in the cathode
exhaust can be related to the amount of CO.sub.2 in the cathode
input stream and the CO.sub.2 utilization at the desired operating
conditions for improving or maximizing the fuel cell energy
output.
[0178] Additionally or alternately, depending on the operating
conditions, an MCFC can lower the CO.sub.2 content of a cathode
exhaust stream to about 5.0 vol % or less, e.g., about 4.0 vol % or
less, or about 2.0 vol % or less, or about 1.5 vol % or less, or
about 1.2 vol % or less. Additionally or alternately, the CO.sub.2
content of the cathode exhaust stream can be at least about 0.9 vol
%, such as at least about 1.0 vol %, or at least about 1.2 vol %,
or at least about 1.5 vol %.
Molten Carbonate Fuel Cell Operation
[0179] In some aspects, a fuel cell may be operated in a single
pass or once-through mode. In single pass mode, reformed products
in the anode exhaust are not returned to the anode inlet. Thus,
recycling syngas, hydrogen, or some other product from the anode
output directly to the anode inlet is not done in single pass
operation. More generally, in single pass operation, reformed
products in the anode exhaust are also not returned indirectly to
the anode inlet, such as by using reformed products to process a
fuel stream subsequently introduced into the anode inlet.
Optionally, CO.sub.2 from the anode outlet can be recycled to the
cathode inlet during operation of an MCFC in single pass mode. More
generally, in some alternative aspects, recycling from the anode
outlet to the cathode inlet may occur for an MCFC operating in
single pass mode. Heat from the anode exhaust or output may
additionally or alternately be recycled in a single pass mode. For
example, the anode output flow may pass through a heat exchanger
that cools the anode output and warms another stream, such as an
input stream for the anode and/or the cathode. Recycling heat from
anode to the fuel cell is consistent with use in single pass or
once-through operation. Optionally but not preferably, constituents
of the anode output may be burned to provide heat to the fuel cell
during single pass mode.
[0180] FIG. 2 shows a schematic example of the operation of an MCFC
for generation of electrical power. In FIG. 2, the anode portion of
the fuel cell can receive fuel and steam (H.sub.2O) as inputs, with
outputs of water, CO.sub.2, and optionally excess H.sub.2, CH.sub.4
(or other hydrocarbons), and/or CO. The cathode portion of the fuel
cell can receive CO.sub.2 and some oxidant (e.g., air/O.sub.2) as
inputs, with an output corresponding to a reduced amount of
CO.sub.2 in O.sub.2-depleted oxidant (air). Within the fuel cell,
CO.sub.3.sup.2- ions formed in the cathode side can be transported
across the electrolyte to provide the carbonate ions needed for the
reactions occurring at the anode.
[0181] Several reactions can occur within a molten carbonate fuel
cell such as the example fuel cell shown in FIG. 2. The reforming
reactions can be optional, and can be reduced or eliminated if
sufficient H.sub.2 is provided directly to the anode. The following
reactions are based on CH.sub.4, but similar reactions can occur
when other fuels are used in the fuel cell.
[0182] (1) <anode
reforming>CH.sub.4+H.sub.2O=>3H.sub.2+CO
[0183] (2) <water gas
shift>CO+H.sub.2O=>H.sub.2+CO.sub.2
[0184] (3) <reforming and water gas shift
combined>CH.sub.4+2H.sub.2O=>4H.sub.2+CO.sub.2
[0185] (4) <anode H.sub.2
oxidation>H.sub.2+CO.sub.3.sup.2-=>H.sub.2O+CO.sub.2+2e.sup.-
[0186] (5)
<cathode>1/2O.sub.2+CO.sub.2+2e.sup.-=>CO.sub.3.sup.2-
[0187] Reaction (1) represents the basic hydrocarbon reforming
reaction to generate H.sub.2 for use in the anode of the fuel cell.
The CO formed in reaction (1) can be converted to H.sub.2 by the
water-gas shift reaction (2). The combination of reactions (1) and
(2) is shown as reaction (3). Reactions (1) and (2) can occur
external to the fuel cell, and/or the reforming can be performed
internal to the anode.
[0188] Reactions (4) and (5), at the anode and cathode
respectively, represent the reactions that can result in electrical
power generation within the fuel cell. Reaction (4) combines
H.sub.2, either present in the feed or optionally generated by
reactions (1) and/or (2), with carbonate ions to form H.sub.2O,
CO.sub.2, and electrons to the circuit. Reaction (5) combines
O.sub.2, CO.sub.2, and electrons from the circuit to form carbonate
ions. The carbonate ions generated by reaction (5) can be
transported across the electrolyte of the fuel cell to provide the
carbonate ions needed for reaction (4). In combination with the
transport of carbonate ions across the electrolyte, a closed
current loop can then be formed by providing an electrical
connection between the anode and cathode.
[0189] In various embodiments, a goal of operating the fuel cell
can be to improve the total efficiency of the fuel cell and/or the
total efficiency of the fuel cell plus an integrated chemical
synthesis process. This is typically in contrast to conventional
operation of a fuel cell, where the goal can be to operate the fuel
cell with high electrical efficiency for using the fuel provided to
the cell for generation of electrical power. As defined above,
total fuel cell efficiency may be determined by dividing the
electric output of the fuel cell plus the lower heating value of
the fuel cell outputs by the lower heating value of the input
components for the fuel cell. In other words, TFCE=(LHV(el)+LHV(sg
out))/LHV(in), where LHV(in) and LHV(sg out) refer to the LHV of
the fuel components (such as H.sub.2, CH.sub.4, and/or CO)
delivered to the fuel cell and syngas (H.sub.2, CO and/or CO.sub.2)
in the anode outlet streams or flows, respectively. This can
provide a measure of the electric energy plus chemical energy
generated by the fuel cell and/or the integrated chemical process.
It is noted that under this definition of total efficiency, heat
energy used within the fuel cell and/or used within the integrated
fuel cell/chemical synthesis system can contribute to total
efficiency. However, any excess heat exchanged or otherwise
withdrawn from the fuel cell or integrated fuel cell/chemical
synthesis system is excluded from the definition. Thus, if excess
heat from the fuel cell is used, for example, to generate steam for
electricity generation by a steam turbine, such excess heat is
excluded from the definition of total efficiency.
[0190] Several operational parameters may be manipulated to operate
a fuel cell with excess reformable fuel. Some parameters can be
similar to those currently recommended for fuel cell operation. In
some aspects, the cathode conditions and temperature inputs to the
fuel cell can be similar to those recommended in the literature.
For example, the desired electrical efficiency and the desired
total fuel cell efficiency may be achieved at a range of fuel cell
operating temperatures typical for molten carbonate fuel cells. In
typical operation, the temperature can increase across the fuel
cell.
[0191] In other aspects, the operational parameters of the fuel
cell can deviate from typical conditions so that the fuel cell is
operated to allow a temperature decrease from the anode inlet to
the anode outlet and/or from the cathode inlet to the cathode
outlet. For example, the reforming reaction to convert a
hydrocarbon into H.sub.2 and CO is an endothermic reaction. If a
sufficient amount of reforming is performed in a fuel cell anode
relative to the amount of oxidation of hydrogen to generate
electrical current, the net heat balance in the fuel cell can be
endothermic. This can cause a temperature drop between the inlets
and outlets of a fuel cell. During endothermic operation, the
temperature drop in the fuel cell can be controlled so that the
electrolyte in the fuel cell remains in a molten state.
[0192] Parameters that can be manipulated in a way so as to differ
from those currently recommended can include the amount of fuel
provided to the anode, the composition of the fuel provided to the
anode, and/or the separation and capture of syngas in the anode
output without significant recycling of syngas from the anode
exhaust to either the anode input or the cathode input. In some
aspects, no recycle of syngas or hydrogen from the anode exhaust to
either the anode input or the cathode input can be allowed to
occur, either directly or indirectly. In additional or alternative
aspects, a limited amount of recycle can occur. In such aspects,
the amount of recycle from the anode exhaust to the anode input
and/or the cathode input can be less than about 10 vol % of the
anode exhaust, such as less than about 5 vol %, or less than about
1 vol %.
[0193] Additionally or alternately, a goal of operating a fuel cell
can be to separate CO.sub.2 from the output stream of a combustion
reaction or another process that produces a CO.sub.2 output stream,
in addition to allowing generation of electric power. In such
aspects, the combustion reaction(s) can be used to power one or
more generators or turbines, which can provide a majority of the
power generated by the combined generator/fuel cell system. Rather
than operating the fuel cell to optimize power generation by the
fuel cell, the system can instead be operated to improve the
capture of carbon dioxide from the combustion-powered generator
while reducing or minimizing the number of fuels cells required for
capturing the carbon dioxide. Selecting an appropriate
configuration for the input and output flows of the fuel cell, as
well as selecting appropriate operating conditions for the fuel
cell, can allow for a desirable combination of total efficiency and
carbon capture.
[0194] In some embodiments, the fuel cells in a fuel cell array can
be arranged so that only a single stage of fuel cells (such as fuel
cell stacks) can be present. In this type of embodiment, the anode
fuel utilization for the single stage can represent the anode fuel
utilization for the array. Another option can be that a fuel cell
array can contain multiple stages of anodes and multiple stages of
cathodes, with each anode stage having a fuel utilization within
the same range, such as each anode stage having a fuel utilization
within 10% of a specified value, for example within 5% of a
specified value. Still another option can be that each anode stage
can have a fuel utilization equal to a specified value or lower
than the specified value by less than an amount, such as having
each anode stage be not greater than a specified value by 10% or
less, for example, by 5% or less. As an illustrative example, a
fuel cell array with a plurality of anode stages can have each
anode stage be within about 10% of 50% fuel utilization, which
would correspond to each anode stage having a fuel utilization
between about 40% and about 60%. As another example, a fuel cell
array with a plurality of stages can have each anode stage be not
greater than 60% anode fuel utilization with the maximum deviation
being about 5% less, which would correspond to each anode stage
having a fuel utilization between about 55% to about 60%. In still
another example, one or more stages of fuel cells in a fuel cell
array can be operated at a fuel utilization from about 30% to about
50%, such as operating a plurality of fuel cell stages in the array
at a fuel utilization from about 30% to about 50%. More generally,
any of the above types of ranges can be paired with any of the
anode fuel utilization values specified herein.
[0195] Still another additional or alternate option can include
specifying a fuel utilization for less than all of the anode
stages. For example, in some aspects of the invention fuel
cells/stacks can be arranged at least partially in one or more
series arrangements such that anode fuel utilization can be
specified for the first anode stage in a series, the second anode
stage in a series, the final anode stage in a series, or any other
convenient anode stage in a series. As used herein, the "first"
stage in a series corresponds to the stage (or set of stages, if
the arrangement contains parallel stages as well) to which input is
directly fed from the fuel source(s), with later ("second,"
"third," "final," etc.) stages representing the stages to which the
output from one or more previous stages is fed, instead of directly
from the respective fuel source(s). In situations where both output
from previous stages and input directly from the fuel source(s) are
co-fed into a stage, there can be a "first" (set of) stage(s) and a
"last" (set of) stage(s), but other stages ("second," "third,"
etc.) can be more tricky among which to establish an order (e.g.,
in such cases, ordinal order can be determined by concentration
levels of one or more components in the composite input feed
composition, such as CO.sub.2 for instance, from highest
concentration "first" to lowest concentration "last" with
approximately similar compositional distinctions representing the
same ordinal level.)
[0196] Yet another additional or alternate option can be to specify
the anode fuel utilization corresponding to a particular cathode
stage (again, where fuel cells/stacks can be arranged at least
partially in one or more series arrangements). As noted above,
based on the direction of the flows within the anodes and cathodes,
the first cathode stage may not correspond to (be across the same
fuel cell membrane from) the first anode stage. Thus, in some
aspects of the invention, the anode fuel utilization can be
specified for the first cathode stage in a series, the second
cathode stage in a series, the final cathode stage in a series, or
any other convenient cathode stage in a series.
[0197] Yet still another additional or alternate option can be to
specify an overall average of fuel utilization over all fuel cells
in a fuel cell array. In various aspects, the overall average of
fuel utilization for a fuel cell array can be about 65% or less,
for example, about 60% or less, about 55% or less, about 50% or
less, or about 45% or less (additionally or alternately, the
overall average fuel utilization for a fuel cell array can be at
least about 25%, for example at least about 30%, at least about
35%, or at least about 40%). Such an average fuel utilization need
not necessarily constrain the fuel utilization in any single stage,
so long as the array of fuel cells meets the desired fuel
utilization.
Applications for CO.sub.2 Output after Capture
[0198] In various aspects of the invention, the systems and methods
described above can allow for production of carbon dioxide as a
pressurized fluid. For example, the CO.sub.2 generated from a
cryogenic separation stage can initially correspond to a
pressurized CO.sub.2 liquid with a purity of at least about 90%,
e.g., at least about 95%, at least about 97%, at least about 98%,
or at least about 99%. This pressurized CO.sub.2 stream can be
used, e.g., for injection into wells in order to further enhance
oil or gas recovery such as in secondary oil recovery. When done in
proximity to a facility that encompasses a gas turbine, the overall
system may benefit from additional synergies in use of
electrical/mechanical power and/or through heat integration with
the overall system.
[0199] Alternatively, for systems dedicated to an enhanced oil
recovery (EOR) application (i.e., not comingled in a pipeline
system with tight compositional standards), the CO.sub.2 separation
requirements may be substantially relaxed. The EOR application can
be sensitive to the presence of O.sub.2, so O.sub.2 can be absent,
in some embodiments, from a CO.sub.2 stream intended for use in
EOR. However, the EOR application can tend to have a low
sensitivity to dissolved CO, H.sub.2, and/or CH.sub.4. Also,
pipelines that transport the CO.sub.2 can be sensitive to these
impurities. Those dissolved gases can typically have only subtle
impacts on the solubilizing ability of CO.sub.2 used for EOR.
Injecting gases such as CO, H.sub.2, and/or CH.sub.4 as EOR gases
can result in some loss of fuel value recovery, but such gases can
be otherwise compatible with EOR applications.
[0200] Additionally or alternately, a potential use for CO.sub.2 as
a pressurized liquid can be as a nutrient in biological processes
such as algae growth/harvesting. The use of MCFCs for CO.sub.2
separation can ensure that most biologically significant pollutants
could be reduced to acceptably low levels, resulting in a
CO.sub.2-containing stream having only minor amounts of other
"contaminant" gases (such as CO, H.sub.2, N.sub.2, and the like,
and combinations thereof) that are unlikely to substantially
negatively affect the growth of photosynthetic organisms. This can
be in stark contrast to the output streams generated by most
industrial sources, which can often contain potentially highly
toxic material such as heavy metals.
[0201] In this type of aspect of the invention, the CO.sub.2 stream
generated by separation of CO.sub.2 in the anode loop can be used
to produce biofuels and/or chemicals, as well as precursors
thereof. Further additionally or alternately, CO.sub.2 may be
produced as a dense fluid, allowing for much easier pumping and
transport across distances, e.g., to large fields of photosynthetic
organisms. Conventional emission sources can emit hot gas
containing modest amounts of CO.sub.2 (e.g., about 4-15%) mixed
with other gases and pollutants. These materials would normally
need to be pumped as a dilute gas to an algae pond or biofuel
"farm". By contrast, the MCFC system according to the invention can
produce a concentrated CO.sub.2 stream (-60-70% by volume on a dry
basis) that can be concentrated further to 95%+(for example 96%+,
97%+, 98%+, or 99%+) and easily liquefied. This stream can then be
transported easily and efficiently over long distances at
relatively low cost and effectively distributed over a wide area.
In these embodiments, residual heat from the combustion source/MCFC
may be integrated into the overall system as well.
[0202] An alternative embodiment may apply where the CO.sub.2
source/MCFC and biological/chemical production sites are
co-located. In that case, only minimal compression may be necessary
(i.e., to provide enough CO.sub.2 pressure to use in the biological
production, e.g., from about 15 psig to about 150 psig). Several
novel arrangements can be possible in such a case. Secondary
reforming may optionally be applied to the anode exhaust to reduce
CH.sub.4 content, and water-gas shift may optionally additionally
or alternately be present to drive any remaining CO into CO.sub.2
and H.sub.2.
[0203] The components from an anode output stream and/or cathode
output stream can be used for a variety of purposes. One option can
be to use the anode output as a source of hydrogen, as described
above. For an MCFC integrated with or co-located with a refinery,
the hydrogen can be used as a hydrogen source for various refinery
processes, such as hydroprocessing. Another option can be to
additionally or alternately use hydrogen as a fuel source where the
CO.sub.2 from combustion has already been "captured." Such hydrogen
can be used in a refinery or other industrial setting as a fuel for
a boiler, furnace, and/or fired heater, and/or the hydrogen can be
used as a feed for an electric power generator, such as a turbine.
Hydrogen from an MCFC fuel cell can further additionally or
alternately be used as an input stream for other types of fuel
cells that require hydrogen as an input, possibly including
vehicles powered by fuel cells. Still another option can be to
additionally or alternately use syngas generated as an output from
an MCFC fuel cell as a fermentation input.
[0204] Another option can be to additionally or alternately use
syngas generated from the anode output. Of course, syngas can be
used as a fuel, although a syngas based fuel can still lead to some
CO.sub.2 production when burned as fuel. In other aspects, a syngas
output stream can be used as an input for a chemical synthesis
process. One option can be to additionally or alternately use
syngas for a Fischer-Tropsch type process, and/or another process
where larger hydrocarbon molecules are formed from the syngas
input. Another option can be to additionally or alternately use
syngas to form an intermediate product such as methanol. Methanol
could be used as the final product, but in other aspects methanol
generated from syngas can be used to generate larger compounds,
such as gasoline, olefins, aromatics, and/or other products. It is
noted that a small amount of CO.sub.2 can be acceptable in the
syngas feed to a methanol synthesis process, and/or to a
Fischer-Tropsch process utilizing a shifting catalyst.
Hydroformylation is an additional or alternate example of still
another synthesis process that can make use of a syngas input.
[0205] It is noted that one variation on use of an MCFC to generate
syngas can be to use MCFC fuel cells as part of a system for
processing methane and/or natural gas withdrawn by an offshore oil
platform or other production system that is a considerable distance
from its ultimate market. Instead of attempting to transport the
gas phase output from a well, or attempting to store the gas phase
product for an extended period, the gas phase output from a well
can be used as the input to an MCFC fuel cell array. This can lead
to a variety of benefits. First, the electric power generated by
the fuel cell array can be used as a power source for the platform.
Additionally, the syngas output from the fuel cell array can be
used as an input for a Fischer-Tropsch process at the production
site. This can allow for formation of liquid hydrocarbon products
more easily transported by pipeline, ship, or railcar from the
production site to, for example, an on-shore facility or a larger
terminal
[0206] Still other integration options can additionally or
alternately include using the cathode output as a source of higher
purity, heated nitrogen. The cathode input can often include a
large portion of air, which means a substantial portion of nitrogen
can be included in the cathode input. The fuel cell can transport
CO.sub.2 and O.sub.2 from the cathode across the electrolyte to the
anode, and the cathode outlet can have lower concentrations of
CO.sub.2 and O.sub.2, and thus a higher concentration of N.sub.2
than found in air. With subsequent removal of the residual O.sub.2
and CO.sub.2, this nitrogen output can be used as an input for
production of ammonia or other nitrogen-containing chemicals, such
as urea, ammonium nitrate, and/or nitric acid. It is noted that
urea synthesis could additionally or alternately use CO.sub.2
separate from the anode output as an input feed.
Integration Example: Applications for Integration with Combustion
Turbines
[0207] In some aspects of the invention, a combustion source for
generating power and exhausting a CO.sub.2-containing exhaust can
be integrated with the operation of molten carbonate fuel cells. An
example of a suitable combustion source is a gas turbine.
Preferably, the gas turbine can combust natural gas, methane gas,
or another hydrocarbon gas in a combined cycle mode integrated with
steam generation and heat recovery for additional efficiency.
Modern natural gas combined cycle efficiencies are about 60% for
the largest and newest designs. The resulting CO.sub.2-containing
exhaust gas stream can be produced at an elevated temperature
compatible with the MCFC operation, such as 300.degree.
C.-700.degree. C. and preferably 500.degree. C.-650.degree. C. The
gas source can optionally but preferably be cleaned of contaminants
such as sulfur that can poison the MCFC before entering the
turbine. Alternatively, the gas source can be a coal-fired
generator, wherein the exhaust gas would typically be cleaned
post-combustion due to the greater level of contaminants in the
exhaust gas. In such an alternative, some heat exchange to/from the
gas may be necessary to enable clean-up at lower temperatures. In
additional or alternate embodiments, the source of the
CO.sub.2-containing exhaust gas can be the output from a boiler,
combustor, or other heat source that burns carbon-rich fuels. In
other additional or alternate embodiments, the source of the
CO.sub.2-containing exhaust gas can be bio-produced CO.sub.2 in
combination with other sources.
[0208] For integration with a combustion source, some alternative
configurations for processing of a fuel cell anode can be
desirable. For example, an alternative configuration can be to
recycle at least a portion of the exhaust from a fuel cell anode to
the input of a fuel cell anode. The output stream from an MCFC
anode can include H.sub.2O, CO.sub.2, optionally CO, and optionally
but typically unreacted fuel (such as H.sub.2 or CH.sub.4) as the
primary output components. Instead of using this output stream as
an external fuel stream and/or an input stream for integration with
another process, one or more separations can be performed on the
anode output stream in order to separate the CO.sub.2 from the
components with potential fuel value, such as H.sub.2 or CO. The
components with fuel value can then be recycled to the input of an
anode.
[0209] This type of configuration can provide one or more benefits.
First, CO.sub.2 can be separated from the anode output, such as by
using a cryogenic CO.sub.2 separator. Several of the components of
the anode output (H.sub.2, CO, CH.sub.4) are not easily condensable
components, while CO.sub.2 and H.sub.2O can be separated
individually as condensed phases. Depending on the embodiment, at
least about 90 vol % of the CO.sub.2 in the anode output can be
separated to form a relatively high purity CO.sub.2 output stream.
Alternatively, in some aspects less CO.sub.2 can be removed from
the anode output, so that about 50 vol % to about 90 vol % of the
CO.sub.2 in the anode output can be separated out, such as about 80
vol % or less or about 70 vol % or less. After separation, the
remaining portion of the anode output can correspond primarily to
components with fuel value, as well as reduced amounts of CO.sub.2
and/or H.sub.2O. This portion of the anode output after separation
can be recycled for use as part of the anode input, along with
additional fuel. In this type of configuration, even though the
fuel utilization in a single pass through the MCFC(s) may be low,
the unused fuel can be advantageously recycled for another pass
through the anode. As a result, the single-pass fuel utilization
can be at a reduced level, while avoiding loss (exhaust) of
unburned fuel to the environment.
[0210] Additionally or alternatively to recycling a portion of the
anode exhaust to the anode input, another configuration option can
be to use a portion of the anode exhaust as an input for a
combustion reaction for a turbine or other combustion device, such
as a boiler, furnace, and/or fired heater. The relative amounts of
anode exhaust recycled to the anode input and/or as an input to the
combustion device can be any convenient or desirable amount. If the
anode exhaust is recycled to only one of the anode input and the
combustion device, the amount of recycle can be any convenient
amount, such as up to 100% of the portion of the anode exhaust
remaining after any separation to remove CO.sub.2 and/or H.sub.2O.
When a portion of the anode exhaust is recycled to both the anode
input and the combustion device, the total recycled amount by
definition can be 100% or less of the remaining portion of anode
exhaust. Otherwise, any convenient split of the anode exhaust can
be used. In various embodiments of the invention, the amount of
recycle to the anode input can be at least about 10% of the anode
exhaust remaining after separations, for example at least about
25%, at least about 40%, at least about 50%, at least about 60%, at
least about 75%, or at least about 90%. Additionally or alternately
in those embodiments, the amount of recycle to the anode input can
be about 90% or less of the anode exhaust remaining after
separations, for example about 75% or less, about 60% or less,
about 50% or less, about 40% or less, about 25% or less, or about
10% or less. Further additionally or alternately, in various
embodiments of the invention, the amount of recycle to the
combustion device can be at least about 10% of the anode exhaust
remaining after separations, for example at least about 25%, at
least about 40%, at least about 50%, at least about 60%, at least
about 75%, or at least about 90%. Additionally or alternately in
those embodiments, the amount of recycle to the combustion device
can be about 90% or less of the anode exhaust remaining after
separations, for example about 75% or less, about 60% or less,
about 50% or less, about 40% or less, about 25% or less, or about
10% or less.
[0211] In still other alternative aspects of the invention, the
fuel for a combustion device can additionally or alternately be a
fuel with an elevated quantity of components that are inert and/or
otherwise act as a diluent in the fuel. CO.sub.2 and N.sub.2 are
examples of components in a natural gas feed that can be relatively
inert during a combustion reaction. When the amount of inert
components in a fuel feed reaches a sufficient level, the
performance of a turbine or other combustion source can be
impacted. The impact can be due in part to the ability of the inert
components to absorb heat, which can tend to quench the combustion
reaction. Examples of fuel feeds with a sufficient level of inert
components can include fuel feeds containing at least about 20 vol
% CO.sub.2, or fuel feeds containing at least about 40 vol %
N.sub.2, or fuel feeds containing combinations of CO.sub.2 and
N.sub.2 that have sufficient inert heat capacity to provide similar
quenching ability. (It is noted that CO.sub.2 has a greater heat
capacity than N.sub.2, and therefore lower concentrations of
CO.sub.2 can have a similar impact as higher concentrations of
N.sub.2. CO.sub.2 can also participate in the combustion reactions
more readily than N.sub.2, and in doing so remove H.sub.2 from the
combustion. This consumption of H.sub.2 can have a large impact on
the combustion of the fuel, by reducing the flame speed and
narrowing the flammability range of the air and fuel mixture.) More
generally, for a fuel feed containing inert components that impact
the flammability of the fuel feed, the inert components in the fuel
feed can be at least about 20 vol %, such as at least about 40 vol
%, or at least about 50 vol %, or at least about 60 vol %.
Preferably, the amount of inert components in the fuel feed can be
about 80 vol % or less.
[0212] When a sufficient amount of inert components are present in
a fuel feed, the resulting fuel feed can be outside of the
flammability window for the fuel components of the feed. In this
type of situation, addition of H.sub.2 from a recycled portion of
the anode exhaust to the combustion zone for the generator can
expand the flammability window for the combination of fuel feed and
H.sub.2, which can allow, for example, a fuel feed containing at
least about 20 vol % CO.sub.2 or at least about 40% N.sub.2 (or
other combinations of CO.sub.2 and N.sub.2) to be successfully
combusted.
[0213] Relative to a total volume of fuel feed and H.sub.2
delivered to a combustion zone, the amount of H.sub.2 for expanding
the flammability window can be at least about 5 vol % of the total
volume of fuel feed plus H.sub.2, such as at least about 10 vol %,
and/or about 25 vol % or less. Another option for characterizing
the amount of H.sub.2 to add to expand the flammability window can
be based on the amount of fuel components present in the fuel feed
before H.sub.2 addition. Fuel components can correspond to methane,
natural gas, other hydrocarbons, and/or other components
conventionally viewed as fuel for a combustion-powered turbine or
other generator. The amount of H.sub.2 added to the fuel feed can
correspond to at least about one third of the volume of fuel
components (1:3 ratio of H.sub.2:fuel component) in the fuel feed,
such as at least about half of the volume of the fuel components
(1:2 ratio). Additionally or alternately, the amount of H.sub.2
added to the fuel feed can be roughly equal to the volume of fuel
components in the fuel feed (1:1 ratio) or less. For example, for a
feed containing about 30 vol % CH.sub.4, about 10% N.sub.2, and
about 60% CO.sub.2, a sufficient amount of anode exhaust can be
added to the fuel feed to achieve about a 1:2 ratio of H.sub.2 to
CH.sub.4. For an idealized anode exhaust that contained only
H.sub.2, addition of H.sub.2 to achieve a 1:2 ratio would result in
a feed containing about 26 vol % CH.sub.4, 13 vol % H.sub.2, 9 vol
% N.sub.2, and 52 vol % CO.sub.2.
Exhaust Gas Recycle
[0214] Aside from providing exhaust gas to a fuel cell array for
capture and eventual separation of the CO.sub.2, an additional or
alternate potential use for exhaust gas can include recycle back to
the combustion reaction to increase the CO.sub.2 content. When
hydrogen is available for addition to the combustion reaction, such
as hydrogen from the anode exhaust of the fuel cell array, further
benefits can be gained from using recycled exhaust gas to increase
the CO.sub.2 content within the combustion reaction.
[0215] In various aspects of the invention, the exhaust gas recycle
loop of a power generation system can receive a first portion of
the exhaust gas from combustion, while the fuel cell array can
receive a second portion. The amount of exhaust gas from combustion
recycled to the combustion zone of the power generation system can
be any convenient amount, such as at least about 15% (by volume),
for example at least about 25%, at least about 35%, at least about
45%, or at least about 50%. Additionally or alternately, the amount
of combustion exhaust gas recirculated to the combustion zone can
be about 65% (by volume) or less, e.g., about 60% or less, about
55% or less, about 50% or less, or about 45% or less.
[0216] In one or more aspects of the invention, a mixture of an
oxidant (such as air and/or oxygen-enriched air) and fuel can be
combusted and (simultaneously) mixed with a stream of recycled
exhaust gas. The stream of recycled exhaust gas, which can
generally include products of combustion such as CO.sub.2, can be
used as a diluent to control, adjust, or otherwise moderate the
temperature of combustion and of the exhaust that can enter the
succeeding expander. As a result of using oxygen-enriched air, the
recycled exhaust gas can have an increased CO.sub.2 content,
thereby allowing the expander to operate at even higher expansion
ratios for the same inlet and discharge temperatures, thereby
enabling significantly increased power production.
[0217] A gas turbine system can represent one example of a power
generation system where recycled exhaust gas can be used to enhance
the performance of the system. The gas turbine system can have a
first/main compressor coupled to an expander via a shaft. The shaft
can be any mechanical, electrical, or other power coupling, thereby
allowing a portion of the mechanical energy generated by the
expander to drive the main compressor. The gas turbine system can
also include a combustion chamber configured to combust a mixture
of a fuel and an oxidant. In various aspects of the invention, the
fuel can include any suitable hydrocarbon gas/liquid, such as
syngas, natural gas, methane, ethane, propane, butane, naphtha
diesel, kerosene, aviation fuel, coal derived fuel, bio-fuel,
oxygenated hydrocarbon feedstock, or any combinations thereof. The
oxidant can, in some embodiments, be derived from a second or inlet
compressor fluidly coupled to the combustion chamber and adapted to
compress a feed oxidant. In one or more embodiments of the
invention, the feed oxidant can include atmospheric air and/or
enriched air. When the oxidant includes enriched air alone or a
mixture of atmospheric air and enriched air, the enriched air can
be compressed by the inlet compressor (in the mixture, either
before or after being mixed with the atmospheric air). The enriched
air and/or the air-enriched air mixture can have an overall oxygen
concentration of at least about 25 volume %, e.g., at least about
30 volume %, at least about 35 volume %, at least about 40 volume
%, at least about 45 volume %, or at least about 50 volume %.
Additionally or alternately, the enriched air and/or the
air-enriched air mixture can have an overall oxygen concentration
of about 80 volume % or less, such as about 70 volume % or
less.
[0218] The enriched air can be derived from any one or more of
several sources. For example, the enriched air can be derived from
such separation technologies as membrane separation, pressure swing
adsorption, temperature swing adsorption, nitrogen plant-byproduct
streams, and/or combinations thereof. The enriched air can
additionally or alternately be derived from an air separation unit
(ASU), such as a cryogenic ASU, for producing nitrogen for pressure
maintenance or other purposes. In certain embodiments of the
invention, the reject stream from such an ASU can be rich in
oxygen, having an overall oxygen content from about 50 volume % to
about 70 volume %, can be used as at least a portion of the
enriched air and subsequently diluted, if needed, with unprocessed
atmospheric air to obtain the desired oxygen concentration.
[0219] In addition to the fuel and oxidant, the combustion chamber
can optionally also receive a compressed recycle exhaust gas, such
as an exhaust gas recirculation primarily having CO.sub.2 and
nitrogen components. The compressed recycle exhaust gas can be
derived from the main compressor, for instance, and adapted to help
facilitate combustion of the oxidant and fuel, e.g., by moderating
the temperature of the combustion products. As can be appreciated,
recirculating the exhaust gas can serve to increase CO.sub.2
concentration.
[0220] An exhaust gas directed to the inlet of the expander can be
generated as a product of combustion reaction. The exhaust gas can
have a heightened CO.sub.2 content based, at least in part, on the
introduction of recycled exhaust gas into the combustion reaction.
As the exhaust gas expands through the expander, it can generate
mechanical power to drive the main compressor, to drive an
electrical generator, and/or to power other facilities.
[0221] The power generation system can, in many embodiments, also
include an exhaust gas recirculation (EGR) system. In one or more
aspects of the invention, the EGR system can include a heat
recovery steam generator (HRSG) and/or another similar device
fluidly coupled to a steam gas turbine. In at least one embodiment,
the combination of the HRSG and the steam gas turbine can be
characterized as a power-producing closed Rankine cycle. In
combination with the gas turbine system, the HRSG and the steam gas
turbine can form part of a combined-cycle power generating plant,
such as a natural gas combined-cycle (NGCC) plant. The gaseous
exhaust can be introduced to the HRSG in order to generate steam
and a cooled exhaust gas. The HRSG can include various units for
separating and/or condensing water out of the exhaust stream,
transferring heat to form steam, and/or modifying the pressure of
streams to a desired level. In certain embodiments, the steam can
be sent to the steam gas turbine to generate additional electrical
power.
[0222] After passing through the HRSG and optional removal of at
least some H.sub.2O, the CO.sub.2-containing exhaust stream can, in
some embodiments, be recycled for use as an input to the combustion
reaction. As noted above, the exhaust stream can be compressed (or
decompressed) to match the desired reaction pressure within the
vessel for the combustion reaction.
Example of Integrated System
[0223] FIG. 8 schematically shows an example of an integrated
system including introduction of both CO.sub.2-containing recycled
exhaust gas and H.sub.2 or CO from the fuel cell anode exhaust into
the combustion reaction for powering a turbine. In FIG. 8, the
turbine can include a compressor 802, a shaft 804, an expander 806,
and a combustion zone 815. An oxygen source 811 (such as air and/or
oxygen-enriched air) can be combined with recycled exhaust gas 898
and compressed in compressor 802 prior to entering combustion zone
815. A fuel 812, such as CH.sub.4, and optionally a stream
containing H.sub.2 or CO 187 can be delivered to the combustion
zone. The fuel and oxidant can be reacted in zone 815 and
optionally but preferably passed through expander 806 to generate
electric power. The exhaust gas from expander 806 can be used to
form two streams, e.g., a CO.sub.2-containing stream 822 (that can
be used as an input feed for fuel cell array 825) and another
CO.sub.2-containing stream 892 (that can be used as the input for a
heat recovery and steam generator system 890, which can, for
example, enable additional electricity to be generated using steam
turbines 894). After passing through heat recovery system 890,
including optional removal of a portion of H.sub.2O from the
CO.sub.2-containing stream, the output stream 898 can be recycled
for compression in compressor 802 or a second compressor that is
not shown. The proportion of the exhaust from expander 806 used for
CO.sub.2-containing stream 892 can be determined based on the
desired amount of CO.sub.2 for addition to combustion zone 815.
[0224] As used herein, the EGR ratio is the flow rate for the fuel
cell bound portion of the exhaust gas divided by the combined flow
rate for the fuel cell bound portion and the recovery bound
portion, which is sent to the heat recovery generator. For example,
the EGR ratio for flows shown in FIG. 8 is the flow rate of stream
822 divided by the combined flow rate of streams 822 and 892.
[0225] The CO.sub.2-containing stream 822 can be passed into a
cathode portion (not shown) of a molten carbonate fuel cell array
825. Based on the reactions within fuel cell array 825, CO.sub.2
can be separated from stream 822 and transported to the anode
portion (not shown) of the fuel cell array 825. This can result in
a cathode output stream 824 depleted in CO.sub.2. The cathode
output stream 824 can then be passed into a heat recovery (and
optional steam generator) system 850 for generation of heat
exchange and/or additional generation of electricity using steam
turbines 854 (which may optionally be the same as the
aforementioned steam turbines 894). After passing through heat
recovery and steam generator system 850, the resulting flue gas
stream 856 can be exhausted to the environment and/or passed
through another type of carbon capture technology, such as an amine
scrubber.
[0226] After transport of CO.sub.2 from the cathode side to the
anode side of fuel cell array 825, the anode output 835 can
optionally be passed into a water gas shift reactor 870. Water gas
shift reactor 870 can be used to generate additional H.sub.2 and
CO.sub.2 at the expense of CO (and H.sub.2O) present in the anode
output 835. The output from the optional water gas shift reactor
870 can then be passed into one or more separation stages 840, such
as a cold box or a cryogenic separator. This can allow for
separation of an H.sub.2O stream 847 and CO.sub.2 stream 849 from
the remaining portion of the anode output. The remaining portion of
the anode output 885 can include unreacted H.sub.2 generated by
reforming but not consumed in fuel cell array 825. A first portion
845 of the H.sub.2-containing stream 885 can be recycled to the
input for the anode(s) in fuel cell array 825. A second portion 887
of stream 885 can be used as an input for combustion zone 815. A
third portion 865 can be used as is for another purpose and/or
treated for subsequent further use. Although FIG. 8 and the
description herein schematically details up to three portions, it
is contemplated that only one of these three portions can be
exploited, only two can be exploited, or all three can be exploited
according to the invention.
[0227] In FIG. 8, the exhaust for the exhaust gas recycle loop is
provided by a first heat recovery and steam generator system 890,
while a second heat recovery and steam generator system 850 can be
used to capture excess heat from the cathode output of the fuel
cell array 825.
[0228] FIG. 9 shows an alternative embodiment where the exhaust gas
recycle loop is provided by the same heat recovery steam generator
used for processing the fuel cell array output. In FIG. 9, recycled
exhaust gas 998 is provided by heat recovery and steam generator
system 950 as a portion of the flue gas stream 956. This can
eliminate the separate heat recovery and steam generator system
associated with the turbine.
[0229] In various embodiments of the invention, the process can be
approached as starting with a combustion reaction for powering a
turbine, an internal combustion engine, or another system where
heat and/or pressure generated by a combustion reaction can be
converted into another form of power. The fuel for the combustion
reaction can comprise or be hydrogen, a hydrocarbon, and/or any
other compound containing carbon that can be oxidized (combusted)
to release energy. Except for when the fuel contains only hydrogen,
the composition of the exhaust gas from the combustion reaction can
have a range of CO.sub.2 contents, depending on the nature of the
reaction (e.g., from at least about 2 vol % to about 25 vol % or
less). Thus, in certain embodiments where the fuel is carbonaceous,
the CO.sub.2 content of the exhaust gas can be at least about 2 vol
%, for example at least about 4 vol %, at least about 5 vol %, at
least about 6 vol %, at least about 8 vol %, or at least about 10
vol %. Additionally or alternately in such carbonaceous fuel
embodiments, the CO.sub.2 content can be about 25 vol % or less,
for example about 20 vol % or less, about 15 vol % or less, about
10 vol % or less, about 7 vol % or less, or about 5 vol % or less.
Exhaust gases with lower relative CO.sub.2 contents (for
carbonaceous fuels) can correspond to exhaust gases from combustion
reactions on fuels such as natural gas with lean (excess air)
combustion. Higher relative CO.sub.2 content exhaust gases (for
carbonaceous fuels) can correspond to optimized natural gas
combustion reactions, such as those with exhaust gas recycle,
and/or combustion of fuels such as coal.
[0230] In some aspects of the invention, the fuel for the
combustion reaction can contain at least about 90 volume % of
compounds containing five carbons or less, e.g., at least about 95
volume %. In such aspects, the CO.sub.2 content of the exhaust gas
can be at least about 4 vol %, for example at least about 5 vol %,
at least about 6 vol %, at least about 7 vol %, or at least about
7.5 vol %. Additionally or alternately, the CO.sub.2 content of the
exhaust gas can be about 13 vol % or less, e.g., about 12 vol % or
less, about 10 vol % or less, about 9 vol % or less, about 8 vol %
or less, about 7 vol % or less, or about 6 vol % or less. The
CO.sub.2 content of the exhaust gas can represent a range of values
depending on the configuration of the combustion-powered generator.
Recycle of an exhaust gas can be beneficial for achieving a
CO.sub.2 content of at least about 6 vol %, while addition of
hydrogen to the combustion reaction can allow for further increases
in CO.sub.2 content to achieve a CO.sub.2 content of at least about
7.5 vol %.
Alternative Configuration--High Severity NOx Turbine
[0231] Gas turbines can be limited in their operation by several
factors. One typical limitation can be that the maximum temperature
in the combustion zone can be controlled below certain limits to
achieve sufficiently low concentrations of nitrogen oxides (NOx) in
order to satisfy regulatory emission limits. Regulatory emission
limits can require a combustion exhaust to have a NOx content of
about 20 vppm or less, and possible 10 vppm or less, when the
combustion exhaust is allowed to exit to the environment.
[0232] NOx formation in natural gas-fired combustion turbines can
be a function of temperature and residence time. Reactions that
result in formation of NOx can be of reduced and/or minimal
importance below a flame temperature of about 1500.degree. F., but
NOx production can increase rapidly as the temperature increases
beyond this point. In a gas turbine, initial combustion products
can be mixed with extra air to cool the mixture to a temperature
around 1200.degree. F., and temperature can be limited by the
metallurgy of the expander blades. Early gas turbines typically
executed the combustion in diffusion flames that had stoichiometric
zones with temperatures well above 1500.degree. F., resulting in
higher NOx concentrations. More recently, the current generation of
`Dry Low Nox` (DLN) burners can use special pre-mixed burners to
burn natural gas at cooler lean (less fuel than stoichiometric)
conditions. For example, more of the dilution air can be mixed in
to the initial flame, and less can be mixed in later to bring the
temperature down to the .about.1200.degree. F. turbine-expander
inlet temperature. The disadvantages for DLN burners can include
poor performance at turndown, higher maintenance, narrow ranges of
operation, and poor fuel flexibility. The latter can be a concern,
as DLN burners can be more difficult to apply to fuels of varying
quality (or difficult to apply at all to liquid fuels). For low BTU
fuels, such as fuels containing a high content of CO.sub.2, DLN
burners are typically not used and instead diffusion burners can be
used. In addition, gas turbine efficiency can be increased by using
a higher turbine-expander inlet temperature. However, because there
can be a limited amount of dilution air, and this amount can
decrease with increased turbine-expander inlet temperature, the DLN
burner can become less effective at maintaining low NOx as the
efficiency of the gas turbine improves.
[0233] In various aspects of the invention, a system integrating a
gas turbine with a fuel cell for carbon capture can allow use of
higher combustion zone temperatures while reducing and/or
minimizing additional NOx emissions, as well as enabling DLN-like
NOx savings via use of turbine fuels that are not presently
compatible with DLN burners. In such aspects, the turbine can be
run at higher power (i.e., higher temperature) resulting in higher
NOx emissions, but also higher power output and potentially higher
efficiency. In some aspects of the invention, the amount of NOx in
the combustion exhaust can be at least about 20 vppm, such as at
least about 30 vppm, or at least about 40 vppm. Additionally or
alternately, the amount of NOx in the combustion exhaust can be
about 1000 vppm or less, such as about 500 vppm or less, or about
250 vppm or less, or about 150 vppm or less, or about 100 vppm or
less. In order to reduce the NOx levels to levels required by
regulation, the resulting NOx can be equilibrated via thermal NOx
destruction (reduction of NOx levels to equilibrium levels in the
exhaust stream) through one of several mechanisms, such as simple
thermal destruction in the gas phase; catalyzed destruction from
the nickel cathode catalyst in the fuel cell array; and/or assisted
thermal destruction prior to the fuel cell by injection of small
amounts of ammonia, urea, or other reductant. This can be assisted
by introduction of hydrogen derived from the anode exhaust. Further
reduction of NOx in the cathode of the fuel cell can be achieved
via electrochemical destruction wherein the NOx can react at the
cathode surface and can be destroyed. This can result in some
nitrogen transport across the membrane electrolyte to the anode,
where it may form ammonia or other reduced nitrogen compounds. With
respect to NOx reduction methods involving an MCFC, the expected
NOx reduction from a fuel cell/fuel cell array can be about 80% or
less of the NOx in the input to the fuel cell cathode, such as
about 70% or less, and/or at least about 5%. It is noted that
sulfidic corrosion can also limit temperatures and affect turbine
blade metallurgy in conventional systems. However, the sulfur
restrictions of the MCFC system can typically require reduced fuel
sulfur levels that reduce or minimize concerns related to sulfidic
corrosion. Operating the MCFC array at low fuel utilization can
further mitigate such concerns, such as in aspects where a portion
of the fuel for the combustion reaction corresponds to hydrogen
from the anode exhaust.
Operating the Fuel Cell at Low Voltage
[0234] The conventional fuel cell practice teaches that molten
carbonate and solid oxide fuel cells should be operated to maximize
power density. The ability to maximize power density can be limited
by a need to satisfy other operating constraints, such as
temperature differential across the fuel cell. Generally, fuel cell
parameters are selected to optimize power density as much as is
feasible given other constraints. As an example, FIG. 6-13 of the
NETL Fuel Cell Handbook and the discussion surrounding FIG. 6-13
teach that operation of a fuel cell at low fuel utilization is
hindered by the decrease in fuel conversion that occurs as the fuel
utilization is decreased. Generally, a higher operating voltage
V.sub.A is desired to increase power density.
[0235] An aspect of the invention can be to operate the fuel cell
at low fuel utilization, and to overcome the problem of decreased
CH.sub.4 conversion by decreasing the voltage. The decreased
voltage can increase the amount of heat available for use in the
conversion reactions. In various aspects, the fuel cell can be
operated at a voltage V.sub.A of less than about 0.7 Volts, for
example less than about 0.68 V, less than about 0.67 V, less than
about 0.66 V, or about 0.65 V or less. Additionally or
alternatively, the fuel cell can be operated at a voltage V.sub.A
of at least about 0.60, for example at least about 0.61, at least
about 0.62, or at least about 0.63. In so doing, energy that would
otherwise leave the fuel cell as electrical energy at high voltage
can remain within the cell as heat as the voltage is lowered. This
additional heat can allow for increased endothermic reactions to
occur, for example increasing the CH.sub.4 conversion to
syngas.
[0236] A series of simulations were performed to illustrate the
benefits of operating a molten carbonate fuel cell according to the
invention. Specifically, the simulations were performed to
illustrate the benefit of running the fuel cell at lower voltage
across different fuel utilizations. The impact of running the fuel
cell at lower voltage and low fuel utilization is shown in FIGS. 16
and 17. FIG. 16 illustrates a model of the fuel cell in a
representation analogous to FIG. 6-13 of the NETL Fuel Cell
Handbook. The simulations used to produce the results shown in FIG.
16 were run at a constant CH.sub.4 flow rate. FIG. 16 shows the
conversion 1620 that can occur at different fuel utilization 1610
percentages for different operating voltages. At high voltage
(0.8V) 1650, as the fuel utilization is decreased, the CH.sub.4
conversion also appeared to be decreased to a low level. As the
voltage is lowered (to 0.7V, 1640, and 0.6V, 1630), the CH.sub.4
conversion at each fuel utilization point modeled appeared to be
higher than the corresponding conversion at 0.8V. While FIG. 16
shows only a few percentage increase in CH.sub.4 conversion, the
impact can actually be quite substantial, as illustrated in FIG.
17.
[0237] The simulations used to produce the results shown in FIG. 17
were not performed at a constant flow rate of CH.sub.4, but at a
constant fuel cell area instead. In FIG. 17, the same operation of
the fuel cell was illustrated not on a percentage of CH.sub.4
conversion basis, but on an absolute flow rate of CH.sub.4 for a
fixed fuel cell area. The x-axis 1710 shows the fuel utilization
and the y-axis 1720 shows normalized CH.sub.4 conversion. Plot 1730
shows simulated results produced at 0.6V. Plot 1740 shows the
simulated results produced at 0.7V. Plot 1750 shows the simulated
results produced at 0.8V. As the fuel utilization is decreased, and
especially as the voltage is decreased, the current density
appeared to be increased by more than a factor of 5 for the data
shown in FIGS. 16 and 17. As such, the power density can be
increased by lowering the operating voltage under operating
conditions consistent with aspects of the invention. The increased
power density and lower voltage seems to be contrary to the affect
achieved during conventional operations, where lower operating
voltage typically results in lower power density. As shown in FIG.
17, the impact on total CH.sub.4 conversion appeared significant:
much higher conversion of CH.sub.4, measured as an absolute flow
rate, was achieved at lower fuel utilization when the voltage was
decreased.
Additional Embodiments
[0238] Embodiment 1. A method for capturing carbon dioxide from a
combustion source, the method comprising: introducing a fuel stream
and an O.sub.2-containing stream into a combustion zone; performing
a combustion reaction in the combustion zone to generate a
combustion exhaust, the combustion exhaust comprising CO.sub.2;
processing a cathode inlet stream, the cathode inlet stream
comprising at least a first portion of the combustion exhaust, with
a fuel cell array of one or more molten carbonate fuel cells to
form a cathode exhaust stream from at least one cathode outlet of
the fuel cell array, the one or more molten carbonate fuel cells
comprising one or more fuel cell anodes and one or more fuel cell
cathodes, the one or more molten carbonate fuel cells being
operatively connected to the combustion zone through at least one
cathode inlet; reacting carbonate from the one or more fuel cell
cathodes with H.sub.2 within the one or more fuel cell anodes to
produce electricity and an anode exhaust stream from at least one
anode outlet of the fuel cell array, the anode exhaust steam
comprising CO.sub.2 and H.sub.2; separating CO.sub.2 from the anode
exhaust stream in one or more separation stages to form a
CO.sub.2-depleted anode exhaust stream; passing at least a
combustion-recycle portion of the CO.sub.2-depleted anode exhaust
stream to the combustion zone; and recycling at least an
anode-recycle portion of the CO.sub.2-depleted anode exhaust stream
to the one or more fuel cell anodes.
Embodiment 2
[0239] The method of Embodiment 1, wherein a fuel utilization in
the one or more fuel cell anodes is about 65% or less (e.g., about
60% or less).
Embodiment 3
[0240] The method of Embodiment 2, wherein the fuel utilization in
the one or more fuel cell anodes is about 30% to about 50%.
Embodiment 4
[0241] The method of claim Embodiment 2, wherein the one or more
fuel cell anodes comprise a plurality of anode stages and the one
or more fuel cell cathodes comprise a plurality of cathode stages,
wherein a low utilization anode stage in the plurality of anode
stages has an anode fuel utilization of 65% or less (such as about
60% or less), the low utilization anode stage corresponding to high
utilization cathode stage of the plurality of cathode stages, the
high utilization cathode stage having a CO.sub.2 content at a
cathode inlet as high as or higher than a CO.sub.2 at a cathode
inlet of any other cathode stage of the plurality of cathode
stages.
Embodiment 5
[0242] The method of Embodiment 4, wherein the fuel utilization in
the low utilization anode stage is at least about 40%, (e.g., at
least about 45% or at least about 50%).
Embodiment 6
[0243] The method of Embodiment 4, wherein a fuel utilization in
each anode stage of the plurality of anode stages is about 65% or
less (e.g., about 60% or less).
Embodiment 7
[0244] The method of any of the above embodiments, wherein the
combustion-recycle portion of the CO.sub.2-depleted anode exhaust
stream comprises at least about 25% of the CO.sub.2-depleted anode
exhaust stream, and wherein the anode-recycle portion of the
CO.sub.2-depleted anode exhaust stream comprises at least about 25%
of the CO.sub.2-depleted anode exhaust stream.
Embodiment 8
[0245] The method of Embodiment 7, further comprising passing
carbon-containing fuel into the one or more fuel cell anodes, the
carbon-containing fuel optionally comprising CH.sub.4.
Embodiment 9
[0246] The method of Embodiment 8, further comprising: reforming at
least a portion of the carbon-containing fuel to generate H.sub.2;
and passing at least a portion of the generated H.sub.2 into the
one or more fuel cell anodes.
Embodiment 10
[0247] The method of Embodiment 8, wherein the carbon-containing
fuel is passed into the one or more fuel cell anodes without
passing the carbon-containing fuel into a reforming stage prior to
entering the one or more fuel cell anodes.
Embodiment 11
[0248] The method of any of the above embodiments, wherein the
combustion exhaust comprises about 10 vol % or less of CO.sub.2
(e.g., 8 vol % or less of CO.sub.2), the combustion exhaust
optionally comprising at least about 4 vol % of CO.sub.2
Embodiment 12
[0249] The method of any of the above Embodiments, further
comprising recycling a second portion of the combustion exhaust to
the combustion zone, the second portion of the combustion exhaust
optionally comprising at least about 6 vol % CO.sub.2.
Embodiment 13
[0250] The method of Embodiment 12, wherein recycling the second
portion of the combustion exhaust to the combustion zone comprises:
exchanging heat between a second portion of the combustion exhaust
and an H.sub.2O-containing stream to form steam; separating water
from the second portion of the combustion exhaust to form an
H.sub.2O-depleted combustion exhaust stream; and passing at least a
portion of the H.sub.2O-depleted combustion exhaust into the
combustion zone.
Embodiment 14
[0251] The method of any of the above embodiments, wherein the
anode exhaust stream, prior to the separating CO.sub.2 from the
anode exhaust stream in one or more separation stages, comprises at
least about 5.0 vol % of H.sub.2 (e.g., at least about 10 vol % or
at least about 15 vol %).
Embodiment 15
[0252] The method of any of the above embodiments, further
comprising exposing the anode exhaust stream to a water gas shift
catalyst to form a shifted anode exhaust stream prior to the
separating CO.sub.2 from the anode exhaust stream in one or more
separation stages, a H.sub.2 content of the shifted anode exhaust
stream after exposure to the water gas shift catalyst being greater
than a H.sub.2 content of the anode exhaust stream prior to
exposure to the water gas shift catalyst.
Embodiment 16
[0253] The method of any of the above Embodiments, wherein the
combustion-recycle portion of the CO.sub.2-depleted anode exhaust
stream is combined with the fuel stream prior to passing the
combustion-recycle portion of the CO.sub.2-depleted anode exhaust
stream to the combustion zone.
Embodiment 17
[0254] The method of any of the above embodiments, wherein a
cathode exhaust stream has a CO.sub.2 content of about 2.0 vol % or
less (e.g., about 1.5 vol % or less or about 1.2 vol % or
less).
Embodiment 18
[0255] The method of any of the above embodiments, wherein
separating CO.sub.2 from the anode exhaust stream in one or more
separation stages comprises: optionally separating water from the
anode exhaust stream to form an optionally H.sub.2O-depleted anode
exhaust stream; cooling the optionally H.sub.2O-depleted anode
exhaust stream to form a condensed phase of CO.sub.2.
EXAMPLES
[0256] A series of simulations were performed in order to
demonstrate the benefits of using an improved configuration for
using a fuel cell for CO.sub.2 separation. The simulations were
based on empirical models for the various components in the power
generation system. The simulations were based on determining steady
state conditions within a system based on mass balance and energy
balance considerations.
[0257] For the combustion reaction for the turbine, the model
included an expected combustion energy value and expected
combustion products for each fuel component in the feed to the
combustion zone (such as C.sub.1-C.sub.4 hydrocarbon, H.sub.2,
and/or CO). This was used to determine the combustion exhaust
composition. An initial reforming zone prior to the anode can be
operated using an "idealized" reforming reaction to convert
CH.sub.4 to H.sub.2. The anode reaction was modeled to also operate
to perform further reforming during anode operation. It is noted
that the empirical model for the anode did not require an initial
H.sub.2 concentration in the anode for the reforming in the anode
to take place. Both the anode and cathode reactions were modeled to
convert expected inputs to expected outputs at a utilization rate
that was selected as a model input. The model for the initial
reforming zone and the anode/cathode reactions included an expected
amount of heat energy needed to perform the reactions. The model
also determined the electrical current generated based on the
amount of reactants consumed in the fuel cell and the utilization
rates for the reactants based on the Nernst equation. For species
that were input to either the combustion zone or the anode/cathode
fuel cell that did not directly participate in a reaction within
the modeled component, the species were passed through the modeled
zone as part of the exhaust or output.
[0258] In addition to the chemical reactions, the components of the
system had expected heat input/output values and efficiencies. For
example, the cryogenic separator had an energy that was required
based on the volume of CO.sub.2 and H.sub.2O separated out, as well
as an energy that was required based on the volume of gas that was
compressed and that remained in the anode output flow. Expected
energy consumption was also determined for a water gas shift
reaction zone, if present, and for compression of recycled exhaust
gas. An expected efficiency for electric generation based on steam
generated from heat exchange was also used in the model.
[0259] The basic configuration used for the simulations included a
combustion turbine combine including a compressor, a combustion
zone, and an expander, similar to the arrangement in FIG. 8. In the
base configuration, a natural gas fuel input 812 was provided to
the combustion zone 815. The natural gas input included .about.93%
CH.sub.4, .about.2% C.sub.2H.sub.6, .about.2% CO.sub.2, and
.about.3% N.sub.2. The oxidant feed 811 to the compressor 802 had a
composition representative of air, including about 70% N.sub.2 and
about 18% O.sub.2. After passing through the expander 806, a
portion 892 of the combustion exhaust gas was passed through a heat
recovery steam generation system 890 and then recycled to the
compressor 802. The remainder of the combustion exhaust 822 was
passed into the fuel cell cathode. After passing through the fuel
cell cathode, the cathode exhaust 824 exited the system. Unless
otherwise specified, the portion of the combustion exhaust 892
recycled back to the combustion zone was .about.35%. This recycled
portion of the combustion exhaust served to increase the CO.sub.2
content of the output from the combustion zone. Because the fuel
cell area was selected to reduce the CO.sub.2 concentration in the
cathode output to a fixed value of .about.1.45%, recycling the
combustion exhaust was found to improve the CO.sub.2 capture
efficiency.
[0260] In the base configuration, the fuel cell was modeled as a
single fuel cell of an appropriate size to process the combustion
exhaust. This was done to represent use of a corresponding
plurality of fuel cells (fuel cell stacks) arranged in parallel
having the same active area as the modeled cell. Unless otherwise
specified, the fuel utilization in the anode of the fuel cell was
set to .about.75%. The fuel cell area was allowed to vary, so that
the selected fuel utilization results in the fuel cell operating at
a constant fuel cell voltage of .about.0.7 volts and a constant
CO.sub.2 cathode output/exhaust concentration of .about.1.45 vol
%.
[0261] In addition to the chemical reactions, the components of the
system had expected heat input/output values and efficiencies. For
example, the cryogenic separator had an energy that was required
based on the volume of CO.sub.2 and H.sub.2O separated out, as well
as an energy that was required based on the volume of gas that was
compressed and that remained in the anode output flow. Expected
energy consumption was also determined for a water gas shift
reaction zone, if present, and for compression of recycled exhaust
gas. An expected efficiency for electric generation based on steam
generated from heat exchange was also used in the model.
[0262] The basic configuration used for the simulations included a
combustion turbine combine including a compressor, a combustion
zone, and an expander. In the base configuration, a natural gas
fuel input was provided to the combustion zone. The natural gas
input included .about.93% CH.sub.4, .about.2% C.sub.2H.sub.6,
.about.2% CO.sub.2, and .about.3% N.sub.2. The oxidant feed to the
compressor had a composition representative of air, including about
70% N.sub.2 and about 18% O.sub.2. After passing through the
expander, a portion of the combustion exhaust gas was passed
through a heat recovery steam generation system and then recycled
to the compressor. The remainder of the combustion exhaust was
passed into the fuel cell cathode. After passing through the fuel
cell cathode, the cathode exhaust exited the system. Unless
otherwise specified, the portion of the combustion exhaust recycled
back to the combustion zone was .about.35%. This recycled portion
of the combustion exhaust served to increase the CO.sub.2 content
of the output from the combustion zone. Because the fuel cell area
was selected to reduce the CO.sub.2 concentration in the cathode
output to a fixed value of .about.1.45%, recycling the combustion
exhaust was found to improve the CO.sub.2 capture efficiency.
[0263] In the base configuration, the fuel cell was modeled as a
single fuel cell of an appropriate size to process the combustion
exhaust. This was done to represent use of a corresponding
plurality of fuel cells (fuel cell stacks) arranged in parallel
having the same active area as the modeled cell. Unless otherwise
specified, the fuel utilization in the anode of the fuel cell was
set to .about.75%. The fuel cell area was allowed to vary, so that
the selected fuel utilization results in the fuel cell operating at
a constant fuel cell voltage of .about.0.7 volts and a constant
CO.sub.2 cathode output/exhaust concentration of .about.1.45 vol
%.
[0264] In the base configuration, an anode fuel input flow provided
the natural gas composition described above as a feed to the anode.
Steam was also present to provide a steam to carbon ratio in the
input fuel of .about.2:1. Optionally, the natural gas input can
undergo reforming to convert a portion of the CH.sub.4 in the
natural gas to H.sub.2 prior to entering the anode. When a prior
reforming stage is present, .about.20% of the CH.sub.4 could be
reformed to generate H.sub.2 prior to entering the anode. The anode
output was passed through a cryogenic separator for removal of
H.sub.2O and CO.sub.2. The remaining portion of the anode output
after separation was processed depending on the configuration for
each Example.
[0265] For a given configuration, a variety of values could be
calculated at steady state. For the fuel cell, the amount of
CO.sub.2 in the anode exhaust and the amount of O.sub.2 in the
cathode exhaust was determined. The voltage for the fuel cell was
fixed at .about.0.7 V within each calculation. For conditions that
could result in a higher maximum voltage, the voltage was stepped
down in exchange for additional current, in order to facilitate
comparison between simulations. The area of fuel cell required to
achieve a final cathode exhaust CO.sub.2 concentration of
.about.1.45 vol % was also determined to allow for determination of
a current density per fuel cell area.
[0266] Another set of values were related to CO.sub.2 emissions.
The percentage of CO.sub.2 captured by the system was determined
based on the total CO.sub.2 generated versus the amount of CO.sub.2
(in Mtons/year) captured and removed via the cryogenic separator.
The CO.sub.2 not captured corresponded to CO.sub.2 "lost" as part
of the cathode exhaust. Based on the amount of CO.sub.2 captured,
the area of fuel cell required per ton of CO.sub.2 captured could
also be determined
[0267] Other values determined in the simulation included the
amount of H.sub.2 in the anode feed relative to the amount of
carbon and the amount of N.sub.2 in the anode feed. It is noted
that the natural gas used for both the combustion zone and the
anode feed included a portion of N.sub.2, as would be expected for
a typical real natural gas feed. As a result, N.sub.2 was present
in the anode feed. The amount of heat (or equivalently steam)
required for heating the anode feed for reforming was also
determined A similar power penalty was determined based on the
power required for compression and separation in the cryogenic
separation stages. For configurations where a portion of the anode
exhaust was recycled to the combustion turbine, the percentage of
the turbine fuel corresponding to H.sub.2 was also determined.
Based on the operation of the turbine, the fuel cell, and the
excess steam generated, as well as any power consumed for heating
the reforming zone, compression, and/or separation, a total net
power was determined for the system to allow for a net electrical
efficiency to be determined based on the amount of natural gas (or
other fuel) used as an input for the turbine and the anode.
[0268] FIGS. 10, 11, and 12 show results from simulations performed
based on several configuration variants. FIG. 10 shows
configurations corresponding to a base configuration as well as
several configurations where a portion of the anode output was
recycled to the anode input. In FIG. 10, a first configuration (1a)
was based on passing the remaining anode output after the carbon
dioxide and water separation stage(s) into a combustor located
after the turbine combustion zone. This provided heat for the
reforming reaction and also provided additional carbon dioxide for
the cathode input. Configuration 1a was representative of a
conventional system, such as the aforementioned Manzolini
reference, with the exception that the Manzolini reference did not
describe recycle of exhaust gas. Use of the anode output as a feed
for the combustor resulted in a predicted fuel cell area of
.about.208 km.sup.2 in order to reduce the CO.sub.2 content of the
cathode output to .about.1.45 vol %. The amount of CO.sub.2 lost as
part of the cathode exhaust was .about.111 lbs CO.sub.2/MWhr. Due
to the large fuel cell area required for capturing the CO.sub.2,
the net power generated was .about.724 MW per hour. Based on these
values, the amount of fuel cell area needed to capture a fixed
amount of CO.sub.2 could be calculated, such as an area of fuel
cell needed to capture a megaton of CO.sub.2 during a year of
operation. For Configuration 1a, the area of fuel cell required was
.about.101.4 km.sup.2*year/Mton-CO.sub.2. The efficiency for
generation of electrical power relative to the energy content of
all fuel used in the power generation system was .about.58.9%. By
comparison, the electrical efficiency for the turbine without any
form of carbon capture was .about.61.1%.
[0269] In a second set of configurations (2a-2e), the anode output
was recycled to the anode input. Configuration 2a represented a
basic recycle of the anode output after separation to the anode
input. Configuration 2b included a water gas shift reaction zone
prior to the carbon dioxide separation stages. Configuration 2c did
not include a reforming stage prior to the anode input.
Configuration 2d included a reforming stage, but was operated with
a fuel utilization of .about.50% instead of .about.75%.
Configuration 2e was operated with a fuel utilization of .about.50%
and did not have a reforming stage prior to the anode.
[0270] Recycling the anode output back to the anode input, as shown
in Configuration 2a, resulted in a reduction of the required fuel
cell area to .about.161 km.sup.2. However, the CO.sub.2 loss from
the cathode exhaust was increased to .about.123 lbs CO.sub.2/MWhr.
This was due to the fact that additional CO.sub.2 was not being
added to the cathode input by the combustion of anode exhaust in a
combustor after the turbine. Instead, the CO.sub.2 content of the
cathode input was based only on the CO.sub.2 output of the
combustion zone. The net result in Configuration 2a was a lower
area of fuel cell per ton of CO.sub.2 captured of .about.87.5
km.sup.2*year/Mton-CO.sub.2, but a modestly higher amount of
CO.sub.2 emissions. Due to the reduced fuel cell area, the total
power generated was .about.661 MW. Although the net power generated
in Configuration 2a was about 10% less than the net power in
Configuration 1a, the fuel cell area was reduced by more than 20%.
The electrical efficiency was .about.58.9%.
[0271] In Configuration 2b, the additional water gas shift reaction
zone increased the hydrogen content delivered to the anode, which
reduced the amount of fuel needed for the anode reaction. Including
the water gas shift reaction zone in Configuration 2b resulted in a
reduction of the required fuel cell area to .about.152 km.sup.2.
The CO.sub.2 loss from the cathode exhaust was .about.123 lbs
CO.sub.2/MWhr. The area of fuel cell per megaton of CO.sub.2
captured was .about.82.4 km.sup.2*year/Mton-CO.sub.2. The total
power generated was .about.664 MW. The electrical efficiency was
.about.59.1%.
[0272] Configuration 2c can take further advantage of the hydrogen
content in the anode recycle by eliminating the reforming of fuel
occurring prior to entering the anode. In Configuration 2c,
reforming can still occur within the anode itself. However, in
contrast to a conventional system incorporating a separate
reforming stage prior to entry into the fuel cell anode,
Configuration 2c relied on the hydrogen content of the recycled
anode gas to provide the minimum hydrogen content for sustaining
the anode reaction. Because a separate reforming stage was not
required, the heat energy was not consumed to maintain the
temperature of the reforming stage. Configuration 2c resulted in a
reduction of the required fuel cell area to .about.149 km.sup.2.
The CO.sub.2 loss from the cathode exhaust was .about.122 lbs
CO.sub.2/MWhr. The area of fuel cell per ton of CO.sub.2 captured
was .about.80.8 km.sup.2*year/Mton-CO.sub.2. The total power
generated was .about.676 MW.
[0273] The electrical efficiency was .about.60.2%. Based on the
simulation results, eliminating the reforming step seemed to have
only a modest impact on the required fuel cell area, but the
electrical efficiency appeared to be improved by about 1% relative
to Configuration 2b. For an industrial scale power generation
plant, an efficiency improvement of even only 1% is believed to
represent an enormous advantage over the course of a year in power
generation.
[0274] In Configuration 2d, reforming was still performed to
convert .about.20% of the methane input to the anode into H.sub.2
prior to entering the anode. Instead, the fuel utilization within
the anode was reduced from .about.75% to .about.50%. This resulted
in a substantial reduction of the required fuel cell area to
.about.113 km.sup.2. The CO.sub.2 loss from the cathode exhaust was
.about.123 lbs CO.sub.2/MWhr. The area of fuel cell per ton of
CO.sub.2 captured was .about.61.3 km.sup.2*year/Mton-CO.sub.2. The
total power generated was .about.660 MW. The electrical efficiency
was .about.58.8%. Based on the simulation results, reducing the
fuel utilization provided a substantial reduction in fuel cell
area. Additionally, in comparison with Configurations 2b and 2e,
Configuration 2d unexpectedly provided the lowest fuel cell area
for achieving the desired level of CO.sub.2 removal.
[0275] Configuration 2e incorporated both the reduced fuel
utilization of .about.50% as well as elimination of the reforming
stage prior to the anode inlet. This configuration provided a
combination of improved electrical efficiency and reduced fuel cell
area. However, the fuel cell area was slightly larger than the fuel
cell area required in Configuration 2d. This was surprising, as
eliminating the reforming stage prior to the anode inlet in
Configuration 2c reduced the fuel cell area in comparison with
Configuration 2b. Based on this, it would have been expected that
Configuration 2e would provide a further reduction in fuel cell
area relative to Configuration 2d. In Configuration 2e, the
CO.sub.2 loss from the cathode exhaust was .about.124 lbs
CO.sub.2/MWhr. The area of fuel cell per ton of CO.sub.2 captured
of .about.65.0 km.sup.2*year/Mton-CO.sub.2. The total power
generated was .about.672 MW. The electrical efficiency was
.about.59.8%. It is noted that Configuration 2d generated only 2%
less power than Configuration 2e, while the fuel cell area of
Configuration 2d was at least 6% lower than Configuration 2e.
[0276] The simulation results for Configurations 2b-2e provide a
comparison of how reducing the anode fuel utilization can impact
the total electrical efficiency in a power generation system. Even
though reducing the fuel utilization to .about.50% in Configuration
2d led to a reduction in fuel cell area relative to Configuration
2b, the reduced anode fuel utilization also appeared to result in a
reduction in electrical efficiency from .about.59.1% to
.about.58.8%. This was in general agreement with conventional views
on fuel utilization for molten carbonate fuel cells, where high
fuel utilization values can be used to allow for efficient use of
fuel delivered to the system. In the simulations for Configurations
2b-2e, in order to achieve an improvement in total electrical
efficiency, the low fuel utilization can be combined with reducing
and/or eliminating the amount of reforming, as shown in
Configuration 2e.
[0277] FIG. 11 shows simulation results for additional
configurations that included recycle of at least a portion of the
anode exhaust to the combustion zone for the turbine.
[0278] In FIG. 11, Configuration 1b was similar to Configuration 1a
(shown in FIG. 10), but also included a water-gas shift reaction
stage prior to the CO.sub.2 separation stages. Thus, Configuration
1b was representative of a conventional system, such as the
aforementioned Manzolini reference, with the exceptions that the
Manzolini reference did not describe a water-gas shift reaction
stage or recycle of exhaust gas. The required fuel cell area to
achieve a CO.sub.2 concentration in the cathode exhaust of -1.45%
was -190 km.sup.2. The amount of CO.sub.2 lost as part of the
cathode exhaust was -117 lbs
[0279] CO.sub.2/MWhr. The area of fuel cell per ton of CO.sub.2
captured was -97.6 km.sup.2*year/Mton-CO.sub.2. The total power
generated was -702 MW. The electrical efficiency was -59.1%.
[0280] Configurations 3a, 3b, and 3d correspond to configurations
where the anode output was used as an input for the combustion zone
of the turbine. In these configurations, the H.sub.2 content of the
anode output was available for use as a fuel in the turbine
combustion zone. This appeared to be advantageous, as the
carbon-containing fuel used to generate the H.sub.2 was generated
in the anode recycle loop, where the majority of the resulting
CO.sub.2 can be removed via the cryogenic separation stages. This
could also result in a reduction of the amount of carbon containing
fuel delivered to the combustion zone, but the reduction in
carbon-containing fuel in the combustion zone could also result in
the reduction of the CO.sub.2 concentration in the input to the
cathode.
[0281] Configuration 3a was a configuration similar to
Configuration 1a, but with recycle of the anode exhaust to the
combustion zone. The required fuel cell area to achieve a CO.sub.2
concentration in the cathode exhaust of -1.45% was -186 km.sup.2.
The amount of CO.sub.2 lost as part of the cathode exhaust was -114
lbs CO.sub.2/MWhr. The area of fuel cell per ton of CO.sub.2
captured was -100.3 km.sup.2*year/Mton-CO.sub.2. The total power
generated was -668 MW. The electrical efficiency was -59.7%.
Relative to Configuration 1a, Configuration 3a had a lower total
amount of CO.sub.2 generated (-2.05 Mtons/year for Configuration 1a
vs..about.1.85 Mtons/year for Configuration 3a). This was believed
to be due to the reduced amount of carbon-containing fuel delivered
to the combustion zone. However, this also appeared to result in a
reduced CO.sub.2 concentration delivered to the cathode input,
which caused the model to show a reduced efficiency of CO.sub.2
removal for Configuration 3a. As a result, the net amount of
CO.sub.2 exiting in the cathode exhaust was comparable for
Configuration 1a and Configuration 3a. However, Configuration 3a
appeared to have several advantages relative to Configuration 1a.
First, Configuration 3a required a lower fuel cell area, so that
the system in Configuration 3a would likely have a reduced cost.
Additionally, the system in Configuration 3a appeared to have
improved electrical efficiency, which can indicate lower fuel
usage, even after adjusting for the different power output of the
configurations.
[0282] Configuration 3b was similar to Configuration 3a, but also
included a water gas shift reaction zone prior to the cryogenic
separation stages. The required fuel cell area to achieve a
CO.sub.2 concentration in the cathode exhaust of .about.1.45% was
.about.173 km.sup.2. The amount of CO.sub.2 lost as part of the
cathode exhaust was .about.124 lbs CO.sub.2/MWhr. The area of fuel
cell per ton of CO.sub.2 captured was .about.96.1
km.sup.2*year/Mton-CO.sub.2. The total power generated was
.about.658 MW. The electrical efficiency was .about.59.8%.
Configuration 3b appeared to have increased CO.sub.2 emission via
the cathode exhaust. This was believed to be due to the additional
hydrogen delivered to the combustion zone, which can result in a
corresponding reduction in the amount of CO.sub.2 the combustion
exhaust used for the cathode input. However, the fuel cell area was
further reduced.
[0283] Configuration 3d was similar to Configuration 3b, but the
anode fuel utilization was reduced from .about.75% to .about.50%.
The required fuel cell area to achieve a CO.sub.2 concentration in
the cathode exhaust of .about.1.45% was .about.132 km.sup.2. The
amount of CO.sub.2 lost as part of the cathode exhaust was
.about.128 lbs CO.sub.2/MWhr. The area of fuel cell per ton of
CO.sub.2 captured was .about.77.4 km.sup.2*year/Mton-CO.sub.2. The
total power generated was .about.638 MW. The electrical efficiency
was .about.60.7%. Based on the simulation results, reducing the
fuel utilization in the anode appeared to result in a substantial
improvement in electrical efficiency relative to Configuration 3b.
This was believed to be due to the additional hydrogen delivered to
the combustion zone for the turbine. For comparison, the electrical
efficiency of the turbine without any carbon capture was
.about.61.1%. Thus, the combination of recycling anode exhaust to
the combustion zone and lower fuel utilization appeared to allow an
electrical efficiency to be achieved approaching the efficiency
without a carbon capture system.
[0284] FIG. 12 shows simulation results for additional
configurations including recycle of at least a portion of the anode
exhaust to both the combustion zone for the turbine and to the
anode inlet. Configurations 4d, 4e, and 4f represent configurations
where the remaining anode exhaust after separation (removal) of
CO.sub.2 and H.sub.2O was divided evenly between recycle to the
anode input and recycle to the combustion zone for the turbine. In
order to provide sufficient hydrogen for both the anode input and
the combustion zone, the anode fuel utilization in Configurations
4d and 4e was set to .about.50%. Configurations 4d and 4e both
included a water gas shift reaction zone prior to the separation
stages. Configuration 4d included a separate reforming stage for
reforming .about.20% of the additional fuel input to the anode
prior to the fuel entering the anode. Configuration 4e did not
include a reforming stage prior to the fuel entering the anode
input. Configuration 4f was similar to Configuration 4e, with the
exception that the anode fuel utilization in Configuration 4f was
.about.33%, as opposed to the .about.50% in Configuration 4e.
[0285] Configuration 4d appeared to show the benefits of recycling
the anode exhaust to both the anode input and the combustion zone.
Relative to Configuration 2d,
[0286] Configuration 4d appeared to provide an electrical
efficiency about a full percentage point greater. Relative to
Configuration 3d, Configuration 4d provided a reduced fuel cell
area. In Configuration 4d, the required fuel cell area to achieve a
CO.sub.2 concentration in the cathode exhaust of .about.1.45% was
.about.122 km.sup.2. The amount of CO.sub.2 lost as part of the
cathode exhaust was .about.126 lbs CO.sub.2/MWhr. The area of fuel
cell per ton of CO.sub.2 captured was .about.63.4
km.sup.2*year/Mton-CO.sub.2. The total power generated was
.about.650 MW. The electrical efficiency was .about.59.9%.
[0287] Removing the pre-reforming stage in Configuration 4e
appeared to provide further benefits. The required fuel cell area
to achieve a CO.sub.2 concentration in the cathode exhaust of
.about.1.45% was .about.112 km.sup.2. The amount of CO.sub.2 lost
as part of the cathode exhaust was .about.126 lbs CO.sub.2/MWhr.
The area of fuel cell per ton of CO.sub.2 captured was .about.63.4
km.sup.2*year/Mton-CO.sub.2. The total power generated was
.about.665 MW. The electrical efficiency was .about.61.4%. It is
noted that the electrical efficiency was actually greater than the
efficiency of the turbine without any type of carbon capture
(-61.1%).
[0288] Reducing the anode fuel utilization in Configuration 4f
appeared to provide still further benefits with regard to both
reducing fuel cell area and increasing electrical efficiency. The
required fuel cell area to achieve a CO.sub.2 concentration in the
cathode exhaust of .about.1.45% was .about.86 km.sup.2. The amount
of CO.sub.2 lost as part of the cathode exhaust was .about.126 lbs
CO.sub.2/MWhr. The area of fuel cell per ton of CO.sub.2 captured
was .about.50.6 km.sup.2*year/Mton-CO.sub.2. The total power
generated was .about.654 MW. The electrical efficiency was
.about.62.4%. It is noted that the electrical efficiency is
actually greater than the efficiency of the turbine without any
type of carbon capture (61.1%).
[0289] Configurations 5d, 5e, and 5f were similar to Configurations
4d, 4e, and 4f, with the exception that the exhaust gas recycle
rate in Configurations 5d, 5e, and 5f was increased to .about.45%.
Configurations 5d, 5e, and 5f had similar fuel cell areas and
appeared to provide similar electrical efficiency, as compared to
Configurations 4d, 4e, and 4E However, the net amount of CO.sub.2
allowed to leave the system via the cathode exhaust was reduced by
about 15% to about 20%, when the exhaust gas recycle rate was
increased from about 30% to about 45%.
[0290] FIG. 13 shows results from simulations performed based on
several configuration variants and alternative operating
conditions. The simulations of FIG. 13 took into account more
factors than the simulations explained previously with reference
FIG. 10. Otherwise, the simulations shown in FIG. 13 were similar
to the simulations shown in FIG. 10, with a few variations added.
For example, each case was simulated at about 0.65 volts in
addition to the about 0.7 volts used in the FIG. 10 simulations. In
addition, a case with 0% EGR was added to each configuration. FIG.
13 shows configurations corresponding to a base configuration as
well as several configurations where a portion of the anode output
was recycled to the anode input. Unless noted, the exhaust gas
recycle was about 35% for the simulated results shown in FIG. 10.
In FIG. 13, each configuration was run with either .about.35% or 0%
EGR as shown.
[0291] In addition to different configurations and alternative
operating conditions, FIG. 13 shows additional parameters that were
not shown in FIG. 10. For example, FIG. 13 includes the approximate
fuel utilization, approximate steam to carbon ratio, EGR recycle %,
whether or not water gas shift reactors were present in the
configuration to process the anode exhaust, the approximate
internal reforming %, the approximate CO.sub.2 concentration in the
cathode inlet, and the approximate O.sub.2 content in the cathode
exhaust.
[0292] In FIG. 13, a first configuration (O) shown in column 1304
was based on passing the remaining anode output after the carbon
dioxide and water separation stage(s) into a combustor located
after the turbine combustion zone. This provided heat for the
reforming reaction and also provided additional carbon dioxide for
the cathode input. Configuration 0 did not include EGR.
Configuration 0 provided a useful base case for comparison with
other simulations that did not include EGR. Configuration 0 was
representative of a conventional system, such as the aforementioned
Manzolini reference. Use of the anode output as a feed for the
combustor resulted in a predicted fuel cell area of -185 km.sup.2
in order to reduce the CO.sub.2 content of the cathode output to
-1.5 vol %. The amount of CO.sub.2 lost as part of the cathode
exhaust was -212 lbs
[0293] CO.sub.2/MWhr. Due to the large fuel cell area required for
capturing the CO.sub.2, the net power generated was -679 MW per
hour. Based on these values, the amount of fuel cell area needed to
capture a fixed amount of CO.sub.2 could be calculated, such as an
area of fuel cell needed to capture a megaton of CO.sub.2 during a
year of operation. For Configuration 0, the area of fuel cell
required to capture a megaton was -113.9
km.sup.2*year/Mton-CO.sub.2. The efficiency for generation of
electrical power relative to the energy content of all fuel used in
the power generation system was -57.6%.
[0294] In FIG. 13, a second base configuration (1a) shown in column
1306 was based on passing the remaining anode output after the
carbon dioxide and water separation stage(s) into a combustor
located after the turbine combustion zone. This provided heat for
the reforming reaction and also provided additional carbon dioxide
for the cathode input. Configuration 1a was representative of a
conventional system, such as the aforementioned Manzolini
reference, with the exception that the Manzolini reference did not
describe recycle of exhaust gas. Use of the anode output as a feed
for the combustor resulted in a predicted fuel cell area of -215
km.sup.2 in order to reduce the CO.sub.2 content of the cathode
output to -1.5 vol %. The amount of CO.sub.2 lost as part of the
cathode exhaust was -148 lbs CO.sub.2/MWhr. Due to the large fuel
cell area required for capturing the CO.sub.2, the net power
generated was -611 MW per hour. Based on these values, the amount
of fuel cell area needed to capture a fixed amount of CO.sub.2
could be calculated, such as an area of fuel cell needed to capture
a megaton of CO.sub.2 during a year of operation. For Configuration
1a, the area of fuel cell required to capture a megaton was -114.2
km.sup.2*year/Mton-CO.sub.2. The efficiency for generation of
electrical power relative to the energy content of all fuel used in
the power generation system was -51.2%. Base case 1a may be
compared to base case 0 to show a result of adding exhaust gas
recycle at -35%.
[0295] In FIG. 13, a third base configuration (1b) shown in column
1308 was based on passing the remaining anode output after the
carbon dioxide and water separation stage(s) into a combustor
located after the turbine combustion zone. This provided heat for
the reforming reaction and also provided additional carbon dioxide
for the cathode input. Base case 1b included water gas shift
reactors to process the anode exhaust prior to carbon dioxide and
water separation stage(s). Configuration 1b was representative of a
conventional system, such as the aforementioned Manzolini
reference, with the exceptions that the Manzolini reference did not
describe recycle of exhaust gas or water gas shift reactors. Use of
the anode output as a feed for the combustor resulted in a
predicted fuel cell area of .about.197 km.sup.2 in order to reduce
the CO.sub.2 content of the cathode output to .about.1.5 vol %. The
amount of CO.sub.2 lost as part of the cathode exhaust was
.about.147.5 lbs CO.sub.2/MWhr. Due to the large fuel cell area
required for capturing the CO.sub.2, the net power generated was
.about.609 MW per hour. Based on these values, the amount of fuel
cell area needed to capture a fixed amount of CO.sub.2 could be
calculated, such as an area of fuel cell needed to capture a
megaton of CO.sub.2 during a year of operation. For Configuration
1b, the area of fuel cell required to capture a megaton was
.about.107.6 km.sup.2*year/Mton-CO.sub.2. The efficiency for
generation of electrical power relative to the energy content of
all fuel used in the power generation system was .about.52.1%. Base
case 1b may be compared to base case 1a to show a result of adding
water gas shift reactors. Base case 1b may be compared to base case
0 to show a result of adding water gas shift reactors and
.about.35% exhaust gas recycle.
[0296] In a second set of configurations (2a-2e), the anode output
was recycled to the anode input. Configuration 2a represented a
basic recycle of the anode output after water and carbon dioxide
separation to the anode input. Configuration 2b included a water
gas shift reaction zone prior to the carbon dioxide separation
stages. Configuration 2c did not include a reforming stage prior to
the anode input. Configuration 2d included a reforming stage, but
was operated with a fuel utilization of .about.50% instead of
.about.75%. Configuration 2e was operated with a fuel utilization
of .about.50% and did not have a reforming stage prior to the
anode. Configuration 2g included a reforming stage and was similar
to configuration 2b and 2d, but operated with a fuel utilization of
.about.30%.
[0297] Three variations on the 2a configuration were simulated. The
2a simulation results shown in column 1310 were based on a
configuration that included EGR, while the simulation results shown
in column 1312 were based on a configuration that did not include
EGR. The simulation results shown in column 1312 were based on a
configuration that did not include EGR and an operating voltage of
about 0.65 was maintained. In the simulations of column 1310 and
1312 an operating voltage of about 0.65 was maintained.
[0298] Recycling the anode output back to the anode input, as shown
in Configuration 2a, resulted in a reduction of the required fuel
cell area as compared to the relevant base case. In column 1310 the
required fuel cell area was .about.174 km.sup.2, in column 1312 the
required fuel cell area was .about.169 km.sup.2, and in column 1310
the required fuel cell area was .about.131 km.sup.2. As can be
seen, the lowered voltage resulted in a lower fuel cell area.
[0299] The 2a configuration changed the CO.sub.2 emissions from the
cathode exhaust. In column 1310 the CO.sub.2 emissions were
.about.141 lbs CO.sub.2/MWhr, in column 1312 the CO.sub.2 emissions
were .about.217.9 lbs CO.sub.2/MWhr, and in column 1314, the
CO.sub.2 emissions were .about.141 lbs CO.sub.2/MWhr.
[0300] In Configuration 2b, a water gas shift reaction zone was
included to process that anode outlet flow prior to water and
carbon dioxide removal. Three variations on the 2b configuration
were simulated. The 2b simulation results shown in column 1316 were
based on a configuration that included EGR, while the simulation
results shown in column 1318 were based on a configuration that did
not include EGR. The simulation results shown in column 1320 were
based on a configuration that did not include EGR and an operating
voltage of about 0.65 was maintained. In the simulations of column
1316 and 1318 an operating voltage of about 0.65 was
maintained.
[0301] In Configuration 2b, the additional water gas shift reaction
zone increased the hydrogen content delivered to the anode, which
reduced the amount of fuel needed for the anode reaction. Including
the water gas shift reaction zone in Configuration 2b resulted in a
required fuel cell area of .about.168 km.sup.2 in column 1316,
.about.164 km.sup.2 in column 1318, and .about.129 km.sup.2 in
column 1320. The CO.sub.2 loss from the cathode exhaust was
.about.143 lbs CO.sub.2/MWhr in column 1316, was 217.5 lbs
CO.sub.2/MWhr in column 1318, and was 218.7 lbs CO.sub.2/MWhr in
column 1320. The area of fuel cell per megaton of CO.sub.2 captured
was .about.101.1 km.sup.2*year/Mton-CO.sub.2 in column 1316, was
.about.114.9 km.sup.2*year/Mton-CO.sub.2 in column 1318, and was
.about.90.1 km.sup.2*year/Mton-CO.sub.2 in column 1320.
[0302] Configuration 2c can take further advantage of the hydrogen
content in the anode recycle by eliminating the reforming of fuel
occurring prior to entering the anode. In Configuration 2c,
reforming can still occur within the anode itself. However, in
contrast to a conventional system incorporating a separate
reforming stage prior to entry into the fuel cell anode,
Configuration 2c relied on the hydrogen content of the recycled
anode gas to provide the minimum hydrogen content for sustaining
the anode reaction. Because a separate reforming stage was not
required, the heat energy was not consumed to maintain the
temperature of the reforming stage.
[0303] Four variations on the 2c configuration were simulated. The
2c simulation results shown in columns 1322 and 1324 were based on
a configuration that included EGR, while the simulation results
shown in columns 1326 and 1328 were based on a configuration that
did not include EGR. The simulation results shown in columns 1322
and 1326 were based on a simulation where an operating voltage of
about 0.70 was maintained. The simulation results shown in columns
1324 and 1328 were based on a simulation where an operating voltage
of about 0.65 was maintained.
[0304] Configuration 2c resulted in a required fuel cell area of
.about.161 km.sup.2 for column 1322, .about.126 km.sup.2 for column
1324, .about.157 km.sup.2 for column 1326, and .about.126 km.sup.2
for column 1328. The CO.sub.2 loss from the cathode exhaust was
142.5 lbs CO.sub.2/MWhr for column 1322, 143.5 lbs CO.sub.2/MWhr
for column 1324, 223.7 lbs CO.sub.2/MWhr for column 1326, and 225.5
lbs CO.sub.2/MWhr for column 1328.
[0305] In Configuration 2d, reforming was still performed to
convert .about.20% of the methane input to the anode into H.sub.2
prior to entering the anode in similar arraignment to configuration
2b. In contrast with 2b, the fuel utilization within the anode was
reduced from .about.75% to .about.50%.
[0306] Four variations on the 2d configuration were simulated. The
2d simulation results shown in columns 1330 and 1332 were based on
a configuration that included EGR, while the simulation results
shown in columns 1334 and 1336 were based on a configuration that
did not include EGR. The simulation results shown in columns 1330
and 1334 were based on a simulation where an operating voltage of
about 0.70 was maintained. The simulation results shown in columns
1332 and 1336 were based on a simulation where an operating voltage
of about 0.65 was maintained.
[0307] Configuration 2e incorporated both the reduced fuel
utilization of .about.50% of 2d as well as elimination of the
reforming stage prior to the anode inlet of 2c. Four variations on
the 2e configuration were simulated. The 2e simulation results
shown in columns 1338 and 1340 were based on a configuration that
included EGR, while the simulation results shown in columns 1342
and 1344 were based on a configuration that did not include EGR.
The simulation results shown in columns 1338 and 1342 were based on
a simulation where an operating voltage of about 0.70 was
maintained. The simulation results shown in columns 1340 and 1344
were based on a simulation where an operating voltage of about 0.65
was maintained.
[0308] In Configuration 2g, reforming was still performed to
convert .about.20% of the methane input to the anode into H.sub.2
prior to entering the anode in similar arraignment to configuration
2b and 2d. In contrast with 2b and 2d, the fuel utilization within
the anode was reduced from .about.75% or .about.50% to
.about.30%.
[0309] Column 1350 describes results of a simulation performed with
a configuration similar to the configuration shown in FIG. 9. In
FIG. 9, the EGR 998 first goes through the cathode and then HRSG
854. A base case simulation for this configuration was performed.
The simulated results from the base case are shown in column 1309.
In contrast to the base case, the simulated results of column 1350
were based on a fuel utilization of .about.50% rather than
.about.75%. In addition, the simulated results of column 1350 were
based on a configuration where reforming was still performed to
convert .about.20% of the methane input to the anode into H.sub.2
prior to entering the anode in a similar arraignment to
configuration 2b and 2d.
[0310] FIG. 14 shows results from simulations performed based on
several configuration variants and alternative operating
conditions. The simulations of FIG. 14 took into account more
factors than the simulations explained previously with reference
FIG. 11. Otherwise, the simulations shown in FIG. 14 were similar
to the simulations shown in FIG. 11, with a few variations added.
For example, each case was simulated at about 0.65 volts in
addition to the about 0.7 volts used in the FIG. 11 simulations. In
addition, a case with 0% EGR was added to each configuration. FIG.
14 shows configurations corresponding to a base configuration as
well as several configurations where a portion of the anode output
was recycled to the combustion zone for the turbine. Unless noted,
the exhaust gas recycle was .about.35% for the simulated results
shown in FIG. 11. In FIG. 14, each configuration was run with
either .about.35% or 0% EGR as shown.
[0311] In addition to different configurations and alternative
operating conditions, FIG. 14 shows additional parameters that were
not shown in FIG. 11. For example, FIG. 14 includes the approximate
fuel utilization, approximate steam to carbon ratio, EGR %, whether
or not water gas shift reactors were present in the configuration
to process the anode exhaust, the approximate internal reforming %,
the approximate CO.sub.2 concentration in the cathode inlet, and
the approximate O.sub.2 content in the cathode exhaust.
[0312] FIG. 14 shows simulation results for additional
configurations that included recycle of at least a portion of the
anode exhaust to the combustion zone for the turbine. In FIG. 14,
Configuration 1b (column 1404) was similar to Configuration 1a
(column 1406), but also included a water-gas shift reaction stage
prior to the CO.sub.2 separation stages. Thus, Configuration 1b was
representative of a conventional system, such as the aforementioned
Manzolini reference, with the exceptions that the Manzolini
reference did not describe a water-gas shift reaction stage or
recycle of exhaust gas. For the 1b configuration, the required fuel
cell area to achieve a CO.sub.2 concentration in the cathode
exhaust of .about.1.45% was .about.197 km.sup.2. The amount of
CO.sub.2 lost as part of the cathode exhaust was .about.147 lbs
CO.sub.2/MWhr. The area of fuel cell per ton of CO.sub.2 captured
was .about.107.6 km.sup.2*year/Mton-CO.sub.2. The total power
generated was .about.609 MW. The electrical efficiency was
.about.52.1%.
[0313] Configurations 3a, 3b, and 3d correspond to configurations
where the anode output was used as an input for the combustion zone
of the turbine. In these configurations, the H.sub.2 content of the
anode output was available for use as a fuel in the turbine
combustion zone. This appeared to be advantageous, as the
carbon-containing fuel used to generate the H.sub.2 was generated
in the anode recycle loop, where the majority of the resulting
CO.sub.2 can be removed via the cryogenic separation stages. This
could also result in a reduction of the amount of carbon containing
fuel delivered to the combustion zone, but the reduction in
carbon-containing fuel in the combustion zone could also result in
the reduction of the CO.sub.2 concentration in the input to the
cathode.
[0314] Configuration 3a was a configuration similar to
Configuration 1a, but with recycle of the anode exhaust to the
combustion zone. Four variations on the 3a configuration were
simulated. The 3a simulation results shown in columns 1410 and 1412
were based on a configuration that included EGR, while the
simulation results shown in columns 1414 and 1416 were based on a
configuration that did not include EGR. The simulation results
shown in columns 1410 and 1414 were based on a simulation where an
operating voltage of about 0.70 was maintained. The simulation
results shown in columns 1412 and 1416 were based on a simulation
where an operating voltage of about 0.65 was maintained.
[0315] Column 1410 shows the simulated results produced from a
configuration most similar to the 1a base case shown in column
1406. The required fuel cell area to achieve a CO.sub.2
concentration in the cathode exhaust of .about.1.45% was .about.179
km.sup.2. The amount of CO.sub.2 lost as part of the cathode
exhaust was 150.4 lbs CO.sub.2/MWhr. The area of fuel cell per ton
of CO.sub.2 captured was -416.3 km.sup.2*year/Mton-CO.sub.2. The
total power generated was .about.599 MW. The electrical efficiency
was .about.55.5%. Relative to Configuration 1a, Configuration 3a
had a lower total amount of CO.sub.2 captured (-1.88 Mtons/year for
Configuration 1a vs. .about.1.54 Mtons/year for Configuration 3a).
This was believed to be due to the reduced amount of
carbon-containing fuel delivered to the combustion zone. However,
this also appeared to result in a reduced CO.sub.2 concentration
delivered to the cathode input, which caused the model to show a
reduced efficiency of CO.sub.2 removal for Configuration 3a.
Configuration 3a appeared to have several advantages relative to
Configuration 1a. First, Configuration 3a required a lower fuel
cell area, so that the system in Configuration 3a would likely have
a reduced cost. Additionally, the system in Configuration 3a
appeared to have improved electrical efficiency, which can indicate
lower fuel usage, even after adjusting for the different power
output of the configurations.
[0316] Configuration 3b was similar to Configuration 3a, but also
included a water gas shift reaction zone prior to the cryogenic
separation stages. Four variations on the 3b configuration were
simulated. The 3b simulation results shown in columns 1418 and 1420
were based on a configuration that included EGR, while the
simulation results shown in columns 1422 and 1424 were based on a
configuration that did not include EGR. The simulation results
shown in columns 1418 and 1422 were based on a simulation where an
operating voltage of about 0.70 was maintained. The simulation
results shown in columns 1420 and 1424 were based on a simulation
where an operating voltage of about 0.65 was maintained.
[0317] As with the simulations shown in FIG. 11, configuration 3b
appeared to have increased CO.sub.2 emission via the cathode
exhaust. This was believed to be due to the additional hydrogen
delivered to the combustion zone, which can result in a
corresponding reduction in the amount of CO.sub.2 the combustion
exhaust used for the cathode input. However, the fuel cell area was
further reduced.
[0318] Configuration 3d was similar to Configuration 3b, but the
anode fuel utilization was reduced from .about.75% to .about.50%.
Four variations on the 3d configuration were simulated. The 3d
simulation results shown in columns 1426 and 1428 were based on a
configuration that included EGR, while the simulation results shown
in columns 1430 and 1432 were based on a configuration that did not
include EGR. The simulation results shown in columns 1426 and 1430
were based on a simulation where an operating voltage of about 0.70
was maintained. The simulation results shown in columns 1428 and
1432 were based on a simulation where an operating voltage of about
0.65 was maintained.
[0319] Configuration 3g was similar to Configuration 3b, but the
anode fuel utilization was reduced from .about.75% to
.about.30%.
[0320] Column 1436 describes results of a simulation performed with
a configuration similar to the configuration shown in FIG. 9. In
FIG. 9, the EGR 998 first goes through the cathode and then HRSG
854. A base case 1a' simulation for this configuration was
performed. The simulated results from the base case 1a' are shown
in column 1309 in FIG. 13. In contrast to the base case, the
simulated results of column 1436 were based on a fuel utilization
of .about.50% rather than .about.75%. In addition, the simulated
results of column 1436 were based on a configuration where
reforming was still performed to convert .about.20% of the methane
input to the anode into H.sub.2 prior to entering the anode in a
similar arraignment to configuration 3b and 3d.
[0321] FIG. 15 shows results from simulations performed based on
several configuration variants and alternative operating
conditions. The simulations of FIG. 15 took into account more
factors than the simulations explained previously with reference
FIG. 12. Configurations 4d and 4e represent configurations where
the remaining anode exhaust after separation (removal) of CO.sub.2
and H.sub.2O was divided evenly between recycle to the anode input
and recycle to the combustion zone for the turbine. In order to
provide sufficient hydrogen for both the anode input and the
combustion zone, the anode fuel utilization in Configurations 4d
and 4e was set to .about.50%. Configurations 4d and 4e both
included a water gas shift reaction zone prior to the separation
stages. Configuration 4d included a separate reforming stage for
reforming .about.20% of the additional fuel input to the anode
prior to the fuel entering the anode. Configuration 4e did not
include a reforming stage prior to the fuel entering the anode
input.
[0322] Four variations on the 4d configuration were simulated. The
4d simulation results shown in columns 1510 and 1512 were based on
a configuration that included EGR, while the simulation results
shown in columns 1514 and 1516 were based on a configuration that
did not include EGR. The simulation results shown in columns 1510
and 1514 were based on a simulation where an operating voltage of
about 0.70 was maintained. The simulation results shown in columns
1512 and 1516 were based on a simulation where an operating voltage
of about 0.65 was maintained.
[0323] Five variations on the 4e configuration were simulated. The
4e simulation results shown in columns 1520 and 1522 were based on
a configuration that included about a 35% EGR, while the simulation
results shown in columns 1524 and 1526 were based on a
configuration that did not include EGR. The 4e simulation of column
1528 was a configuration that included about a 45% EGR. The
simulation results shown in columns 1520, 1524, and 1528 were based
on a simulation where an operating voltage of about 0.70 was
maintained. The simulation results shown in columns 1522 and 1526
were based on a simulation where an operating voltage of about 0.65
was maintained.
[0324] Configuration 4f was similar to Configuration 4e, with the
exception that the anode fuel utilization in Configuration 4f was
.about.33%, as opposed to the .about.50% in Configuration 4e. Four
variations on the 4e configuration were simulated. The 4f
simulation results shown in columns 1530 and 1532 were based on a
configuration that included about a 35% EGR, while the simulation
results shown in columns 1534 and 1536 were based on a
configuration that did not include EGR. The simulation results
shown in columns 1530 and 1534 were based on a simulation where an
operating voltage of about 0.70 was maintained. The simulation
results shown in columns 1532 and 1536 were based on a simulation
where an operating voltage of about 0.65 was maintained.
[0325] Column 1538 describes results of a simulation performed with
a configuration similar to the configuration shown in FIG. 9. In
FIG. 9, the EGR 998 first goes through the cathode and then HRSG
854. A base case 1a' simulation for this configuration was
performed. The simulated results from the base case 1a' are shown
in column 1309 in FIG. 13. In contrast to the base case, the
simulated results of column 1538 were based on a fuel utilization
of .about.50% rather than .about.75%. In addition, the simulated
results of column 1538 were based on a configuration where
reforming was still performed to convert .about.20% of the methane
input to the anode into H.sub.2 prior to entering the anode in a
similar arraignment to configuration 4b and 4d.
[0326] Although the present invention has been described in terms
of specific embodiments, it is not so limited. Suitable
alterations/modifications for operation under specific conditions
should be apparent to those skilled in the art. It is therefore
intended that the following claims be interpreted as covering all
such alterations/modifications as fall within the true spirit/scope
of the invention.
* * * * *