U.S. patent application number 12/848002 was filed with the patent office on 2012-02-02 for systems and methods for co2 capture.
This patent application is currently assigned to General Electric Company. Invention is credited to Douglas Carl Hofer, Narendra Digamber Joshi, Parag Prakash Kulkarni.
Application Number | 20120023947 12/848002 |
Document ID | / |
Family ID | 44759405 |
Filed Date | 2012-02-02 |
United States Patent
Application |
20120023947 |
Kind Code |
A1 |
Kulkarni; Parag Prakash ; et
al. |
February 2, 2012 |
SYSTEMS AND METHODS FOR CO2 CAPTURE
Abstract
The present disclosure relates to the separation of CO.sub.2
from a gas mixture. The CO.sub.2 may be removed by cooling the gas
mixture such that the CO.sub.2 can be removed as a solid or liquid.
In various embodiments the gas mixture from which the CO.sub.2 is
removed may include exhaust gases generated as part of a combustion
process, such as may be employed in a power generation process,
though the gas mixture may be any gas mixture that includes
CO.sub.2.
Inventors: |
Kulkarni; Parag Prakash;
(Niskayuna, NY) ; Hofer; Douglas Carl; (Clifton
Park, NY) ; Joshi; Narendra Digamber; (Schenectady,
NY) |
Assignee: |
General Electric Company
Schenectady
NY
|
Family ID: |
44759405 |
Appl. No.: |
12/848002 |
Filed: |
July 30, 2010 |
Current U.S.
Class: |
60/693 ; 110/300;
62/617 |
Current CPC
Class: |
F23J 15/06 20130101;
Y02E 20/32 20130101; F23J 2215/50 20130101; B01D 53/002 20130101;
F23J 15/006 20130101; Y02C 10/12 20130101; Y02C 20/40 20200801;
Y02E 20/30 20130101; Y02E 20/363 20130101; B01D 2257/504 20130101;
Y02E 20/16 20130101; B01D 2258/0283 20130101; Y02E 20/326 20130101;
Y02E 20/18 20130101 |
Class at
Publication: |
60/693 ; 62/617;
110/300 |
International
Class: |
F23J 15/06 20060101
F23J015/06; F25J 3/00 20060101 F25J003/00 |
Claims
1. A power-generating system comprising: a boiler suitable for
combusting air and fuel to provide heat to a steam cycle interfaced
with the boiler, wherein an exhaust gas containing CO.sub.2 is
generated when air and fuel are combusted; a first cooling stage
configured to receive the exhaust gas from the boiler and to cool
the exhaust gas such that some or all of the water or other
impurities is removed from the exhaust gas; a second cooling stage
configured to receive the exhaust gas after the exhaust gas leaves
the first cooling stage and to cool the exhaust gas; a first
expansion component configured to expand the exhaust gas after the
exhaust gas leaves the second cooling stage so that the exhaust gas
is sufficiently reduced in temperature that CO.sub.2 drops out of
the gas mixture as a liquid or solid; and a CO.sub.2 separation
stage configured to separate the solid or liquid phase CO.sub.2 to
generate a CO.sub.2 lean gas mixture.
2. The power-generating system of claim 1, wherein the boiler
operates with combustion gasses at high pressure.
3. The power-generating system of claim 1, comprising a first
compressor component configured to compress air entering the
boiler.
4. The power-generating system of claim 1, comprising a second
compressor component configured to compress exhaust gas between the
first cooling stage and the second cooling stage.
5. The power-generating system of claim 1, comprising a third
cooling stage configured to receive the exhaust gas after the
exhaust gas leaves the second cooling stage and to cool the exhaust
gas prior to the exhaust gas entering the first expansion
component.
6. The power-generating system of claim 1, wherein one or more of
the cooling stages comprise a heat exchanger.
7. The power-generating system of claim 1, wherein the CO.sub.2
separation stage comprises one or more of a vapor-solid separator
or a vapor-liquid separator.
8. The power-generating system of claim 1, comprising a liquefying
component configured to apply pressure and heat to the separated
CO.sub.2 to convert the CO.sub.2 to a liquid phase if not already
in a liquid phase.
9. The power-generating system of claim 8, wherein the liquefying
component comprises one or more of a posimetric pump or a solid
compressor.
10. The power-generating system of claim 8 wherein the application
of pressure and heat to the separated CO.sub.2 is thermally
integrated with the cooling of the exhaust gas.
11. The power-generating system of claim 1, comprising a second
expansion component configured to receive and expand the CO.sub.2
lean gas mixture after the CO.sub.2 lean gas mixture is heated by
one or both of a heat exchanger associated with the steam cycle or
the boiler.
12. A power-generating system comprising: a turbine engine
configured to combust air and fuel and to generate an exhaust gas
containing CO.sub.2 when the air and fuel are combusted; one or
more heat exchangers configured to receive the exhaust gas
generated by the turbine engine and to cool the exhaust gas; an
expansion component configured to expand the exhaust gas after the
exhaust gas leaves at least one of the first heat exchangers such
that the temperature of the exhaust gas is reduced; and a CO.sub.2
separation stage configured to separate solid or liquid phase
CO.sub.2 from the exhaust gas to generate a CO.sub.2 lean gas
mixture.
13. The power-generating system of claim 12, wherein at least one
of the heat exchangers comprise a heat recovery steam
generator.
14. The power-generating system of claim 12, wherein some or all of
the water or other impurities is removed from the exhaust gas upon
the exhaust gas being cooled by the one or more heat
exchangers.
15. The power-generating system of claim 12, wherein the turbine
engine comprises a gas turbine engine.
16. The power generating system of claim 12, wherein at least one
of the one or more heat exchangers comprises an intercooler.
17. The power generating system of claim 12, wherein the CO.sub.2
lean gas mixture is provided as an input to the turbine engine.
18. The power generating system of claim 12, wherein the CO.sub.2
lean gas mixture is used to cool one or more inlets, heat
exchangers or intercoolers of the power-generating system.
19. The power generating system of claim 12, comprising: a
compressor disposed between a first heat exchanger and a second
heat exchanger, wherein the compressor is configured to receive the
exhaust gas from the first heat exchanger and to compress the
exhaust gas prior to entering second heat exchanger.
20. The power generating system of claim 12, comprising: at least
one air drying system configured to dry air entering the turbine
engine or configured to dry the exhaust gas entering the expansion
component.
21. The power generating system of claim 12, comprising: an inlet
heat exchanger configured to cool air entering the turbine
engine.
22. The power generating system of claim 12, wherein at least one
heat exchanger is configured to receive the exhaust gas at a
pressure of about 1.1 bar to about 10 bar and to cool the exhaust
gas prior to the exhaust gas entering a downstream heat
exchanger.
23. The power generating system of claim 12, comprising: a natural
gas circuit positioned to cool at least one heat exchanger, wherein
natural gas approaches the heat exchanger to be cooled in a
liquefied state and moves away from the heat exchanger in a
gasified state.
24. The power-generating system of claim 12, comprising a
liquefying component configured to apply pressure and heat to the
separated CO.sub.2 to convert the CO.sub.2 to a liquid phase if not
already in a liquid phase.
25. The power-generating system of claim 24, wherein the liquefying
component comprises one or more of a posimetric pump or a solid
compressor.
26. The power-generating system of claim 12 wherein the application
of pressure and heat to the separated CO.sub.2 is thermally
integrated with the cooling of the exhaust gas.
27. A cooling system comprising: a CO.sub.2 separation system
configured to remove some or all of the CO.sub.2 from an exhaust
gas stream generated by a combustion process to generate a CO.sub.2
lean gas stream; one or more conduits positioned to route the
CO.sub.2 lean gas stream to one or more components of a system or
machine, wherein the one or more components are at a temperature
greater than the CO.sub.2 lean gas stream such that the one or more
components are cooled by the CO.sub.2 lean gas stream.
28. The cooling system of claim 27, wherein the one or more
components comprise heat exchangers for removing heat from the
exhaust gas stream.
29. The cooling system of claim 27, wherein the one or more
components comprise heat exchangers or air inlets for reducing the
temperature of air entering a turbine engine that generates the
exhaust gas stream.
Description
BACKGROUND OF THE INVENTION
[0001] The subject matter disclosed herein relates to systems and
methods for separating CO.sub.2 and/or other gaseous species from a
gas mixture, such as a gas mixture resulting from a combustion
process.
[0002] Power generating processes that are based on combustion of
carbon containing fuel produce carbon dioxide (CO.sub.2) as a
byproduct. Typically the CO.sub.2 is one component of a mixture of
gases that result from or pass unchanged through the combustion
process. It may be desirable to capture or otherwise remove the
CO.sub.2 and/or other components of this gas mixture to prevent the
release of these gases into the environment and/or to utilize these
gases in the power generation process or in other processes.
[0003] Unfortunately, CO.sub.2 capture (as well as the capture of
other gaseous combustion byproducts) can be energy intensive as
well as capital intensive. For example, amine processes used to
capture CO.sub.2 may require installation of the capital equipment
associated with the amine system (which may result in an 80%
increase in the cost of the system) and may be costly and energy
intensive to operate. Further, to the extent that the captured
CO.sub.2 is compressed, the energy and capital requirements may be
increased even further. In addition, such CO.sub.2 capture
processes are typically associated with substantial water usage
(i.e., a large water footprint). As a result, these capture and
removal processes may be expensive and/or infeasible to perform
using existing technologies.
BRIEF DESCRIPTION OF THE INVENTION
[0004] With the foregoing background in mind, the present
disclosure describes a cryogenic CO.sub.2 separation method that
relies on the principle of cooling the gas mixtures to separate
CO.sub.2 as liquid or solid and thus making it easier to separate
from other gas mixtures.
[0005] In a first embodiment, a power-generating system is
provided. The power-generating system includes a boiler suitable
for combusting air and fuel to provide heat to a steam cycle
interfaced with the boiler. An exhaust gas containing CO.sub.2 is
generated when air and fuel are combusted. The power-generating
system also includes a first cooling stage configured to receive
the exhaust gas from the boiler and to cool the exhaust gas such
that some or all of the water is removed from the exhaust gas and a
second cooling stage configured to receive the exhaust gas after
the exhaust gas leaves the first cooling stage and to cool the
exhaust gas. The power-generating system also includes a first
expansion component configured to expand the exhaust gas after the
exhaust gas leaves the second cooling stage so that the exhaust gas
is sufficiently reduced in temperature that CO.sub.2 drops out of
the gas mixture as a liquid or solid. The power-generating system
also includes a CO.sub.2 separation stage configured to separate
the solid or liquid phase CO.sub.2 to generate a substantially
CO.sub.2 lean gas mixture.
[0006] In a second embodiment, a power-generating system is
provided. The power-generating system includes a turbine engine
configured to combust air and fuel and to generate an exhaust gas
containing CO.sub.2 when the air and fuel are combusted. The
power-generating system also includes one or more heat exchangers
configured to receive the exhaust gas generated by the turbine
engine and to cool the exhaust gas. The power-generating system
also includes an expansion component configured to expand the
exhaust gas after the exhaust gas leaves at least one of the first
heat exchangers such that the temperature of the exhaust gas is
reduced. The power-generating system also includes a CO.sub.2
separation stage configured to separate solid or liquid phase
CO.sub.2 from the exhaust gas to generate a CO.sub.2 lean gas
mixture.
[0007] In a third embodiment, a cooling system is provided. The
cooling system includes a CO.sub.2 separation system configured to
remove some or all of the CO.sub.2 from an exhaust gas stream
generated by a combustion process to generate a CO.sub.2 lean gas
stream. The cooling system also includes one or more conduits
positioned to route the CO.sub.2 lean gas stream to one or more
components of a system or machine. The one or more components are
at a temperature greater than the CO.sub.2 lean gas stream such
that the one or more components are cooled by the CO.sub.2 lean gas
stream.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] These and other features, aspects, and advantages of the
present invention will become better understood when the following
detailed description is read with reference to the accompanying
drawings in which like characters represent like parts throughout
the drawings, wherein:
[0009] FIG. 1 is a flowchart depicting steps in the removal of
CO.sub.2 from a gas mixture in accordance with aspects of the
present disclosure;
[0010] FIG. 2 is a block diagram of a turbine system in accordance
with aspects of the present disclosure;
[0011] FIG. 3 is a block diagram of a system for processing a gas
mixture to remove CO.sub.2 in accordance with aspects of the
present disclosure;
[0012] FIG. 4 is a block diagram of one embodiment of a power
generation system including CO.sub.2 separation in accordance with
aspects of the present disclosure;
[0013] FIG. 5 is a block diagram of a second embodiment of a power
generation system including CO.sub.2 separation in accordance with
further aspects of the present disclosure;
[0014] FIG. 6 is a block diagram of a further embodiment of a power
generation system including separation of CO.sub.2 as a liquid in
accordance with further aspects of the present disclosure;
[0015] FIG. 7 is a block diagram of one embodiment of a
turbine-based system including CO.sub.2 separation in accordance
with aspects of the present disclosure;
[0016] FIG. 8 is a block diagram of a second embodiment of a
turbine-based system including CO.sub.2 separation in accordance
with further aspects of the present disclosure;
[0017] FIG. 9 is a block diagram of an air drying system in
accordance with further aspects of the present disclosure;
[0018] FIG. 10 is a block diagram of a third embodiment of a
turbine-based system including CO.sub.2 separation in accordance
with further aspects of the present disclosure;
[0019] FIG. 11 is a block diagram of a fourth embodiment of a
turbine-based system including CO.sub.2 separation in accordance
with further aspects of the present disclosure; and
[0020] FIG. 12 is a block diagram of a fifth embodiment of a
turbine-based system including CO.sub.2 separation in accordance
with further aspects of the present disclosure.
DETAILED DESCRIPTION OF THE INVENTION
[0021] One or more specific embodiments will be described below. In
an effort to provide a concise description of these embodiments,
all features of an actual implementation may not be described in
the specification. It should be appreciated that in the development
of any such actual implementation, as in any engineering or design
project, numerous implementation-specific decisions must be made to
achieve the developers' specific goals, such as compliance with
system-related and business-related constraints, which may vary
from one implementation to another. Moreover, it should be
appreciated that such a development effort might be complex and
time consuming, but would nevertheless be a routine undertaking of
design, fabrication, and manufacture for those of ordinary skill
having the benefit of this disclosure.
[0022] When introducing elements of various embodiments disclosed
herein, the articles "a," "an," "the," and "said" are intended to
mean that there are one or more of the elements. The terms
"comprising," "including," and "having" are intended to be
inclusive and mean that there may be additional elements other than
the listed elements.
[0023] The present disclosure provides for the cryogenic separation
(method 10) of CO.sub.2 12 and/or sulfur species 14 from a gas
mixture 16, as depicted in FIG. 1. As discussed herein, the gas
mixture 16 may be a flue gas or other exhaust gas mixture resulting
from a combustion process (such as may be associated with a coal or
natural gas fired power plant), a syngas generated by a
gasification or reforming plant, natural gas extracted from a well,
or any other gas mixture that contains CO.sub.2 or other gas
components where separation is warranted.
[0024] In certain embodiments, the gas mixture 16 is cooled (block
18), such as below the typical stack temperatures and, in response
to the cooling, drop out water 20, other impurities or pollutants
14, and CO.sub.2 12 sequentially. Various impurities or pollutants
14 that may be removed or reduced by the approaches discussed
herein include, but are not limited to SO.sub.2, NO, NO.sub.2,
C.sub.2H.sub.x, H.sub.2S unburnt hydrocarbons (UHC), mercury
particulates, and arsenic, and so forth. The cooling may be
achieved by various suitable approaches, such as an external vapor
compression cycle or by expansion of the gas mixture. The CO.sub.2
12 can be condensed as a liquid or as a solid, depending on the
operating pressure and/or temperature, and may be initially
separated out from the gas mixture 16 using a suitable separation
device, such as a vapor-solid separator, or a vapor-liquid
separator (e.g., a filter, cyclone, column packed with inert
substance, and so forth). In embodiments where the CO.sub.2 12 is
separated in a solid form, the CO.sub.2 12 may be compressed and/or
heated (such as in a posimetric pump or screw compressor) to
achieve a phase change to liquid CO.sub.2 12. The liquid CO.sub.2
12 can then, in certain embodiments, be pumped at high pressure
(e.g., approximately 150 bar) such as may be used for carbon
sequestration. Further, in certain implementations, the separated
CO.sub.2 12 may be used to improve the efficiency of the overall
process through one or more recuperative cooling processes.
[0025] With the foregoing in mind and turning now to the drawings,
FIG. 2 is a block diagram of a turbine system 30, such as may be
used to generate power. As will be appreciated, the turbine system
30 may be suitable for use in a large-scale facility, such as a
power plant for generating electricity that is distributed via a
power grid to a city or town, or in a smaller-scale setting, such
as part of a vehicle engine or small-scale power generation system.
That is, the turbine system 30 may be suitable for a variety of
applications and/or may be scaled over a range of sizes.
[0026] In the depicted example, the turbine system 10 includes a
fuel injector 32, a fuel supply 34, and a combustor 36. The fuel
supply 34 may vary, depending on the embodiment, and may correspond
to mechanisms suitable for delivering a fuel or fuel mixture,
(e.g., a liquid fuel and/or gas fuel, such as natural gas or
syngas) to the turbine system 10 through the fuel injector 32 into
the combustor 36. As discussed below, the fuel injector 32 is
configured to inject and mix the fuel with compressed air.
Alternatively, the fuel supply 34 may be suitable for delivering
coal or other solid and/or particulate fuel materials to the
combustor 36 via a suitable fuel injector 32.
[0027] The combustor 36 ignites and combusts the fuel-air mixture,
and then passes hot pressurized exhaust gas into a turbine 38. As
will be appreciated, the turbine 38 includes one or more stators
having fixed vanes or blades, and one or more rotors having blades
which rotate relative to the stators. The exhaust gas passes
through the turbine rotor blades, thereby driving the turbine rotor
to rotate. Coupling between the turbine rotor and a shaft 39 will
cause the rotation of the shaft 39, which is also coupled to
several components throughout the turbine system 10, as
illustrated. Eventually, the exhaust of the combustion process may
exit the turbine system 10 via an exhaust outlet 40.
[0028] A compressor 42 includes blades rigidly mounted to a rotor
which is driven to rotate by the shaft 39. As air passes through
the rotating blades, air pressure increases, thereby providing the
combustor 36 with sufficient air for proper combustion. The
compressor 42 may intake air to the turbine system 10 via an air
intake 44. Further, the shaft 39 may be coupled to a load 46, which
may be powered via rotation of the shaft 39. As will be
appreciated, the load 46 may be any suitable device that may use
the power of the rotational output of the turbine system 10, such
as a power generation plant or an external mechanical load. For
example, the load 46 may include an electrical generator, a
propeller of an airplane, and so forth. The air intake 44 draws air
50 into the gas turbine system 10 via a suitable mechanism, such as
a cold air intake. The air 50 then flows through blades of the
compressor 42, which provides compressed air 52 to the combustor
36. In particular, the fuel injector 32 may inject the compressed
air 52 and fuel 34, as a fuel-air mixture 54, into the combustor
36. Alternatively, the compressed air 52 and fuel 34 may be
injected directly into the combustor for mixing and combustion.
[0029] With the foregoing in mind, an example of a system 80 for
treating the gas mixture 16 exiting the turbine system 30 is
depicted in FIG. 3. In accordance with this example, the gas
mixture 16 may be a flue gas from a power generation plant. In such
an embodiment, the flue gas may have 10%-15% moisture content and a
temperature of approximately 200.degree. F. (i.e., approximately
93.degree. C.) upon entering the system 80. The gas mixture 16 may
be initially cooled (block 84), such as by a heat exchanger, such
that some or all (e.g., 50% to 100%) of the water 20 is removed
from the gas mixture 16. The removed water 20 may undergo
subsequent treatment (block 86) and/or may be utilized in the
overall process, such as being introduced as part of a steam cycle
or coolant loop associated with the power generation process.
[0030] In one embodiment, the gas stream leaving the cooling block
84 is at about -10 C to -30 C such that additional water 20 and/or
impurities 14 are removed from the gas mixture. This gas stream
may, in the depicted example, undergo compression, such as in
compressor 88, after which the temperature may increase, such as to
about 200.degree. F. to about 500.degree. F. (i.e., about
93.degree. C. to about 260.degree. C.). This gas stream may
subsequently be cooled again (block 90), by a heat exchanger or
other suitable cooling mechanism. In one embodiment, the cooled gas
mixture is at about -30 C to -80 C. The gas mixture may undergo
expansion, such as in a turbine 94 where work is extracted, and may
exit the expansion process at a reduced temperature, e.g., about
-80 c to -135 C. At these temperatures and at partial pressures of
CO.sub.2 below 5.2 bar the CO.sub.2 may be in a solid phase, while
at partial pressures of CO.sub.2 above 5.2 bar the CO.sub.2 may be
in a liquid phase. The liquid or solid-phase CO.sub.2 12 may be
separated out (block 96) such as by a sweeping solid particles in a
settling tank or by using a suitable separation device, such as a
cyclone or vapor liquid separator. In embodiments where the
CO.sub.2 12 is separated in a solid form, the CO.sub.2 12 may be
compressed (block 100) (such as in a posimetric pump or screw
compressor) to achieve a phase change to liquid CO.sub.2.
[0031] In certain embodiments, the CO.sub.2 12 may be recycled
(i.e., recirculated), as depicted by line 108 and used to improve
the freeze process efficiency and thereby increase CO.sub.2
concentration. In other embodiments, liquid CO.sub.2 recovered by
the processes discussed herein may be used as a working fluid in a
bottoming cycle. In one such embodiment where the liquid CO.sub.2
is used as a working fluid, the exhaust from a heat recovery steam
generator (HRSG) may be used as a heat source with respect to the
CO.sub.2 and the cooled exhaust air from a condenser as may be used
as a heat sink with respect to the CO.sub.2. That is, in such an
embodiment different respective aspects of the process that undergo
complementary heating and cooling may be thermally integrated. For
example, as depicted in FIG. 3 and other embodiments, heat
generated as a by-product of one or more of the cooling and/or
CO.sub.2 separation stages may be removed by and used to heat the
separated CO.sub.2 to turn a portion of this CO.sub.2 from a solid
to a liquid, thereby facilitating cooling at the cooling stage (by
removing unwanted heat) and liquefaction of the solid CO.sub.2. In
such an embodiment, energy consumption of the process may be
reduced. Further, the separated CO.sub.2 may be used to enhance
aspects of the power generation process (such as providing
cooling), and/or used for other processes, such a carbonation or to
enhance oil recovery in from existing wells.
[0032] In certain embodiments, the remaining gas mixture 106 is a
CO.sub.2 lean, dry exhaust gas (i.e., an exhaust gas that is
substantially free or reduced in water and CO.sub.2, as well as
SO.sub.2 in certain embodiments) which may consist primarily of
N.sub.2. In addition, the remaining gas mixture 106 will also
typically be reduced in O.sub.2 content. As discussed herein, the
remaining gas mixture 106 may be utilized for a variety of purposes
within the power generation system. For example, the remaining gas
mixture 106 may be used as a desiccant to dry air going into a gas
turbine engine or coal fired burner involved in the power
generation process. Likewise, the remaining gas mixture 106 may be
used directly as an input to the combustion process (i.e., fed to
the turbine or burner in conjunction with ambient air) to reduce
the O.sub.2 content in the air, thereby reducing NOx emissions.
[0033] Further, to the extent that the remaining gas mixture 106 is
a suitable temperature, it may be used to cool one or more parts of
the power generation system. For example, in certain embodiments
CO.sub.2 lean, cold gas may be used to cool the inlet air provided
to the combustion process, to dump heat from cooling water, to
treat high pressure steam before sending the steam to an expander
for electricity generation, and so forth.
[0034] Further, the remaining gas mixture 106, if under pressure,
may be expanded (block 104) to extract additional work. For
example, in implementations where the remaining gas mixture 106 is
at 1.5 to 5 bar of pressure or greater, an expansion may be
performed to extract additional work. In one such embodiment, the
remaining gas mixture 106 may be provided to an expander at about
-30 to -80 C and at a pressure above ambient. After expansion (and
work extraction), the remaining gas mixture may be at about -70 to
-130 C and ambient air pressure. Conversely, in embodiments where
the remaining gas mixture 106 is less than 1.5 bar of pressure, the
expansion step may be omitted.
[0035] With the foregoing in mind, specific examples and
embodiments are provided to further discussion. It should be
appreciated that the provided examples are intended to illustrate
certain of the possible implementations and are not intended to
limit the scope of the present disclosure. As will be appreciated,
the present approaches may be applicable to the separation of
CO.sub.2 (or other gaseous components) from a gas mixture in a
variety of different contexts, including contexts other than those
discussed herein.
[0036] Turning now to FIG. 4, an example is depicted of a CO.sub.2
separation system used in conjunction with a boiler, such as a
high-pressure boiler, that may be used in a power plant. For
example, the boiler may be a coal-fired or other combustion boiler
for use in a power generation plant or system. In one such
embodiment, flue-gas desulfurization (FGD) components typically
present in the system may be replaced by heat exchangers used in
the present cryogenic approach. In such an approach, SO.sub.2 as
well as CO.sub.2 will be removed by cryogenic processes as opposed
to those processes typically used in flue-gas desulfurization. In
this example, air 120 and fuel 122 (e.g., coal) are introduced into
a boiler 124, where the air 120 and fuel 122 are combusted. As a
byproduct of this combustion process, a gas mixture 106 (e.g., flue
gas) exits the boiler 124. In other embodiments, the boiler 124 may
be a heat recovery steam generator (HRSG) used in a process in
which CO.sub.2 containing hot gases (such as exhaust gases) are
used to generate steam or provide process heat. In such embodiments
the CO.sub.2 containing hot gases that provide heat to the HRSG may
be processed in accordance with the approaches discussed
herein.
[0037] The gas mixture 106 is cooled (block 84), such as using a
heat exchanger, and some or all of the water 20 drops out. In
certain embodiments, other impurities, such as SO.sub.2 14, may
also be completely or partially removed at this stage. As discussed
above, the water 20 may be treated and/or used in the power
generation process, such as in the water circuit discussed below.
The gas mixture 106 may pass through a compressor 88 before being
cooled (block 90), such as via a heat exchanger. In this cooling
step additional water 20 and/or impurities (e.g., SO.sub.2 14), if
present, may be removed. However, as will be appreciated, both the
water 20 and SO.sub.2 14 components of the gas mixture may be
removed prior to the gas mixture 106 undergoing compression at
compressor 88.
[0038] In the depicted example the gas mixture may pass through a
heat exchanger 128, such as an air-to-air heat exchanger, before
undergoing expansion (block 94), such as in a turbine where work is
extracted. In one embodiment, the heat exchanger 128 may reduce the
temperature of the gas mixture 16 to less than 32.degree. F. (i.e.,
less than 0.degree. C.) before undergoing expansion at block 94.
After exiting the expansion step, the CO.sub.2 12 may be in a
liquid or solid phase, and thus may, in one implementation, be
mechanically separated out (block 96). For example, in one
embodiment the solid phase CO.sub.2 12 may be separated out from
the gas mixture 16 by a cyclone-type device. The solid-phase
CO.sub.2 may then be compressed (block 100) such as by a posimetric
pump or a solid compressor, so that the CO.sub.2 enters a liquid
phase which may be pumped.
[0039] In the depicted embodiment, the remaining gas mixture 106
(such as an N.sub.2 gas mixture) is cold and dry, such as at about
-100.degree. F. (i.e., about -74.degree. C.). This remaining gas
mixture 106 may be used to remove heat from a cooling water circuit
(depicted by dotted lines 132) that removes heat from the boiler
124 and drives a steam turbine 134. For example, the remaining gas
mixture 106 may be used in a condenser 136 or other heat removal
mechanism to cool the water or other coolant in the cooling circuit
132. Upon removing heat from the cooling circuit, the remaining gas
mixture 106 may be at a temperature of about 100.degree. F. (i.e.,
about 37.degree. C.).
[0040] In one embodiment, the remaining gas mixture 106 may be
further used to cool the boiler 124. In such an embodiment, the
remaining gas mixture absorbs rejected or radiated heat from the
boiler 124, heating the remaining gas mixture 106 to about
300.degree. F. to about 500.degree. F. (i.e., about 148.degree. C.
to about 260.degree. C.). The heated remaining gas mixture 106 may
then be expanded (block 104), such as via a turbine, to extract
additional work.
[0041] Turning to FIG. 5, in certain embodiments it may useful to
condense the CO.sub.2 directly from the gas mixture as a liquid, as
opposed to a solid, thereby avoiding mechanical separation of the
solid CO.sub.2 and pressurization or compression of the solid
CO.sub.2 to a liquid form. Such embodiments may be implemented by
maintaining the gas stream at a suitably high pressure.
[0042] For example, in one such embodiment air 120 is introduced to
the boiler 124, such as a high pressure boiler, at increased
pressure, such as by operation of a compressor 140. By performing
the combustion at higher pressure, flue gas compression may be
avoided or reduced. For example, flue gas may be kept above or near
the triple-point of CO.sub.2 such that the CO.sub.2 can be
subsequently condensed as a solid instead of a liquid. In one such
example, the air 120 may be introduced to the boiler 124 at
increased pressure, so that the compression step between the first
and second cooling steps may be omitted and, likewise, the heat
exchanger operation prior to the expansion step 94 of FIG. 4 may be
omitted. Further, as depicted in FIG. 6, the system of FIG. 5 may
be further modified to omit the expansion step 94. In one such
embodiment, CO.sub.2 12 may be collected in a liquid phase at a
CO.sub.2 separation stage 97.
[0043] In FIG. 7 an alternative embodiment is depicted in the
context of an air cycle machine for CO.sub.2 capture in the context
of a natural gas combined cycle. As will be appreciated, such an
implementation may also be used in the context of other fuel types.
In the depicted example, discussion of certain aspects may be
omitted to focus on those aspects related to CO.sub.2 separation
and/or capture.
[0044] For example, turning to FIG. 7, a gas turbine engine 160 is
depicted to which air 120 is provided at ambient temperature and
pressure for combustion. In the depicted embodiment, the air 120
initially enters a low pressure compressor 162 which compresses the
air 120, thereby increasing the temperature of the air, such as to
about 300.degree. F. (i.e., about 148.degree. C.). In the depicted
example, the air 120 may then pass through an intercooler 164 which
reduces the temperature of the air 120, such as to about
120.degree. F. (i.e., about 48.degree. C.). The cooled air 120 may
then be passed though a high pressure compressor 166, after which
the air temperature may be about 750.degree. F. (i.e., about
398.degree. C.). The compressed air 120, along with a fuel stream
122, may then enter a combustor 168 where the air 120 and fuel 122
are combusted. The exhaust gas mixture 16 produced by the
combustion process may pass through one or more turbines, such as
high pressure turbine 170 and/or low pressure turbine 172 which act
to generate power. Upon exiting the gas turbine engine 160, the gas
mixture 16 may be about 800.degree. F. to about 1,100.degree. F.
(i.e., about 426.degree. C. to about 593.degree. C.). The gas
mixture 16 may pass through a heat exchanger, such as the depicted
heat recovery steam generator (HRSG) 174 that includes a
water/steam cycle 176 that acts to cool the gas mixture 16 and
recover heat energy that may be used to perform additional work.
For example, the steam cycle interfaced by the HRSG 174 may include
a steam turbine power plant drive by the heat generated by the gas
turbine engine 160.
[0045] Upon exiting the HRSG 174 (or other heat exchanger), the
temperature of the gas mixture 16 is reduced, such as to about -10
C and a portion of the water 20 may drop out as a liquid. The gas
mixture 16 may be further cooled upon passage through a heat
exchanger 178, which may lower the temperature of the gas mixture
16 to about -30 C, thereby forcing some or all of the remaining
water 20 out of the gas mixture 16. In the depicted example, the
gas mixture 16 may pass through a second low pressure compressor
180 where the gas mixture 16 is pressurized, thereby increasing the
temperature, such as to about 300.degree. F. to about 400.degree.
F. (i.e., about 148.degree. C. to about 204.degree. C.). The
compressed gas mixture 16 may then pass through a second
intercooler 182 where the temperature of the gas mixture is
lowered, such as to about -30 to -80 C. In one embodiment, external
refrigeration may be employed to achieve this additional cooling.
The gas mixture 16 may then undergo an expansion (block 184) where
work may be extracted after which the remaining gas mixture 106 may
be at a temperature of -70 to -130 C and the CO.sub.2 12 may be in
a liquid or solid phase suitable for separation (block 188) from
the gas mixture, such as by a suitable separation mechanism (i.e.,
settling tanks with sweeps, cyclones, and so forth). In the
depicted implementation, the separated CO.sub.2 is in a solid phase
and is compressed (block 190), such as by a posimetric pump and/or
solid compressor, to yield a liquid phase CO.sub.2 product.
[0046] The remaining gas mixture 106, which may be primarily dry
N.sub.2, may be used to cool the air inlet of the gas turbine
engine 160 or as an input to the gas turbine engine 160 to improve
the efficiency of the system and to reduce the formation of NOx
(e.g., NO, NO.sub.2, and so forth) in the combustion process. In
addition, the remaining gas mixture 106 may be used to cool one or
more of the heat exchanger components of the system, such as the
heat exchanger 178 used to cool the gas mixture 16 upon exiting the
HRSG 174.
[0047] Turning to FIGS. 8 and 9, a further embodiment of an
approach to CO.sub.2 capture which utilizes an air drying system is
depicted in FIG. 8. An example of a suitable air drying system is
depicted in FIG. 9 for reference. In the depicted system of FIG. 8,
the ambient air 120 is initially dried, such as by a desiccant air
drying system 200, and cooled, such as by heat exchanger 204,
before being provided to the gas turbine engine 160. In one such
embodiment, the air 120 leaving the heat exchanger 204 and entering
the gas turbine engine 160 is at about -10.degree. F. to about
-20.degree. F. (i.e., about -23.degree. C. to about -29.degree.
C.). Such cooled air should be relatively dense relative to air at
ambient temperature and thus may provide an increase in power
generated by the gas turbine engine 160. As discussed with respect
to FIG. 7, the air 120 is combusted with fuel 122 in the gas
turbine engine 160. In one embodiment, the exhaust gas mixture 16
leaving the gas turbine engine is at about 800.degree. F. (i.e.,
about 426.degree. C.) before entering the HRSG 174, where the gas
mixture is further cooled such that some or all of the water 20
drops out in liquid form.
[0048] In the depicted embodiment, the gas mixture 16 is compressed
in a low pressure compressor 180 and subsequently cooled by an
intercooler 182. In the depicted implementation, the gas mixture 16
is also passed through a second air drying system 210 before
undergoing expansion (block 184) where work may be extracted. As
discussed with respect to FIG. 7, upon being expanded, the gas
mixture may be at a temperature and pressure where the CO.sub.2 is
in a solid or liquid form and amenable to separation (block 188)
from the gas mixture, such as by mechanical or other suitable
approaches. In the depicted embodiment, the remaining gas mixture
106, which may be at about -70 C to -130 C may be used to cool the
heat exchanger 204 (which may form part of the air inlet of the gas
turbine engine 160) through which air 120 passes to enter the gas
turbine engine 160 and/or to cool one or more of the disclosed
intercoolers. In certain embodiments, as discussed above, to the
extent the separated CO.sub.2 12 is in a solid phase, the CO.sub.2
may be compressed (block 190), such as using a posimetric pump or
solid compressor, to a liquid phase.
[0049] With respect to FIG. 9, an example of a desiccant air drying
system, such as depicted at blocks 200 and 210 of FIG. 8, is
depicted in greater detail. In this example, air 120 passes through
an air contactor 220 where the air 120 comes in contact with a
suitable desiccant material 222 that circulates through the air
contactor 220. In one embodiment, the desiccant material 222 is a
liquid desiccant, such as a salt solution (e.g., lithium bromide,
calcium chloride, lithium chloride, and so forth) or other suitable
desiccant. In one such implementation, the desiccant 222 enters the
air contactor 220 at about 60.degree. F. (i.e., about 15.degree.
C.) but is heated while in contact with the air 120. In the air
contactor 220, moisture from the air 120 is absorbed by the
desiccant material 222, thereby drying the air 120 and increasing
the water content of the desiccant 222. In the depicted embodiment,
the dried air 120 proceeds to a subsequent process stage (such as
the heat exchanger 204 or expander 184 of FIG. 8).
[0050] The desiccant 222, after contacting the air 120, is
increased in temperature (such as to about 75.degree. F. (i.e.,
about 23.degree. C.) and water content. The desiccant 222 is
processed to remove the absorbed water content, allowing the
desiccant 222 to be reused in the air drying process. In the
depicted example, the desiccant 222, such as a liquid desiccant, is
pumped (such as via pump 226) through a first heat exchanger 228.
The heat exchanger 228 acts to heat the moist desiccant 222
traveling through one portion of the heat exchanger 228 while
cooling the dried desiccant 222 traveling through a different
portion of the heat exchanger 228. As a result, the moist desiccant
leaving the heat exchanger 228 is heated to a temperature of about
150.degree. F. (i.e., about 65.degree. C.).
[0051] In the depicted example, the partially heated desiccant 222
may be further heated in a second heat exchanger 230 which utilizes
hot gas turbine exhaust 232 (such as prior to the exhaust gas 232
passing through the HRSG) to further heat the desiccant 222. For
example, in one embodiment, the heated desiccant is at a
temperature of about 200.degree. F. to about 300.degree. F. (i.e.,
about 93.degree. C. to about 148.degree. C.). The heated desiccant
222 may then be routed through a contactor boiler 236 through which
ambient air 240 is passed so as to contact the heated desiccant
222. The ambient air 240 absorbs moisture from the heated desiccant
222 such that the desiccant 222 leaving the contactor boiler 236 is
dry, i.e., has little or no moisture content. In one example, the
desiccant 222 leaving the contactor boiler 236 is at about
200.degree. F. to about 300.degree. F. (i.e., about 93.degree. C.
to about 148.degree. C.).
[0052] The desiccant 222 may then, in one implementation, be pumped
(such as via pump 240) through the heat exchanger 228 discussed
above such that the heat of the dried desiccant is used to heat the
moist desiccant leaving the air contactor 220. As a result of this
heat exchange, the dried desiccant is in turn cooled and exits the
heat exchanger 228 at a lower temperature, such as about
100.degree. F. (i.e., about 37.degree. C.). In one embodiment, the
desiccant 222 may be further cooled, such as via a third heat
exchanger 242 which uses a coolant 244, such as cooling water from
cooling towers, to extract heat from the desiccant 222. In such an
embodiment, the desiccant 222 may be at a temperature of about
60.degree. F. (i.e., about 15.degree. C.) after exiting the heat
exchanger 242. The dried and cooled desiccant 222 may then be
reused to dry air 120 passing through the air contactor 220.
[0053] In another embodiment the implementation discussed above
with respect to FIG. 7 may be modified such that the system is
operated at higher pressure downstream of the gas turbine engine
160. For example, in the depicted embodiment of FIG. 10, air 120 is
provided to the gas turbine engine 160 at ambient temperature and
pressure for combustion. In this embodiment, the exhaust gas
mixture 16 leaving the gas turbine engine 160 is not fully expanded
and, as a result, does not need to be compressed downstream. For
example, in one such embodiment the gas mixture 16 leaving the gas
turbine engine 160 is at a temperature of about 1,100.degree. F.
(i.e., about 593.degree. C.) and at a pressure between 1.1 bar and
10 bar (e.g., 2 bar to 6 bar or 5 bar). At such a temperature and
pressure, the steam turbine of the steam cycle 176 (interfaced via
the HRSG 174) may operate at a higher efficiency. Further, in one
such implementation, the flue gas is kept near or above the triple
point of CO.sub.2 so that there is no subsequent flue gas
compression step. In one such example, the CO.sub.2 may be
subsequently condensed as a liquid instead of a solid due to the
flue gas being maintained at a higher pressure.
[0054] Upon exiting the HRSG 174, the temperature of the gas
mixture 16 is reduced and a portion of the water 20 may drop out as
a liquid. The gas mixture 16 may be further cooled upon passage
through a heat exchanger 178, which may lower the temperature of
the gas mixture 16, thereby forcing some or all of the remaining
water 20 out of the gas mixture 16. In the depicted example, the
gas mixture 16 is still at pressure (e.g., about 5 bar) and may
pass through a second intercooler 182 where the temperature of the
gas mixture is lowered. The gas mixture 16 may then undergo an
expansion (block 184) where work may be extracted. Upon expansion
the gas mixture 16 is sufficiently cool that the CO.sub.2 12 may be
in a liquid or solid phase (depending on the pressure) suitable for
separation (block 188) from the gas mixture 16, such as by a
suitable separation mechanism (i.e., settling tanks with sweeps,
cyclones, and so forth). In one implementation, the separated
CO.sub.2 is in a solid phase and is compressed (block 190), such as
by a posimetric pump and/or solid compressor, to yield a liquid
phase CO.sub.2 product. In other implementations, the gas mixture
16 is at sufficient pressure that the CO.sub.2 12 is condensed out
as a liquid.
[0055] Further, as previously discussed, the remaining gas mixture
106, which may be primarily dry N.sub.2, may be used to cool the
air inlet of the gas turbine engine 160 or as an input to the gas
turbine engine 160 to improve the efficiency of the system and to
reduce the formation of NO in the combustion process. In addition,
the remaining gas mixture 106 may be used to cool one or more of
the heat exchanger components of the system, such as the heat
exchanger 178 used to cool the gas mixture 16 upon exiting the HRSG
174.
[0056] Turning to FIG. 11, in an embodiment where liquefied natural
gas (LNG) is available, a regas and air cycle machine may be
employed in the system for CO.sub.2 capture. In the depicted
embodiment of FIG. 11, the natural gas combined cycle
implementation depicted with respect to FIG. 8 is modified to
include an exhaust drier 260 (as discussed with respect to FIG. 9)
downstream from the HRSG 174 but upstream of the second low
pressure compressor 180. In one such implementation, the remaining
gas mixture 106 (primarily dry N.sub.2) is at a temperature of
about -100.degree. F. (i.e., about -74.degree. C.) and may be used
to cool the second intercooler 182 and/or the exhaust drier
260.
[0057] In addition, a liquefied natural gas (LNG) circuit 264 is
depicted with respect to the second intercooler 182 which assists
in cooling the gas mixture 16 as it passes through the second
intercooler 182 and, in the process heating or gasifying the LNG in
the circuit 264. For example, in one embodiment, the natural gas
(NG) approaches second intercooler 182 in a liquid state, such as
at a temperature of about -160.degree. F. (i.e., about -106.degree.
C.). In this example, the liquefied natural gas absorbs heat from
the exhaust gas 16 via the interface with the second intercooler
182 and leaves the interface with the second intercooler 184 at a
higher temperature and in a gasified state.
[0058] In an additional embodiment, the present approaches to
CO.sub.2 capture may be integrated in a combined cycle power
generation scheme, as depicted in FIG. 12. In the depicted
embodiment, the air 120 is initially cooled prior to entering the
gas turbine engine 160, such as via heat exchanger 204, which may
be provided as an inlet air cooler in certain implementations. In
one such example, the largest volume compressor stages are present
in the gas turbine engine 160 portion of the combined cycle.
[0059] In the depicted embodiment, the exhaust gas mixture 16
exiting the gas turbine engine 160 is not fully expanded and may,
therefore, be at a pressure of about 1.5 bar to about 5 bar when
entering the HRSG 174. In one such embodiment, the increased gas
turbine exhaust pressure may reduce the volume flow and length of a
low swirl burner present in gas turbine engine 160. The gas mixture
16, after exiting the HRSG 174, may pass through a heat exchanger
178, such as an air-to-air heat exchanger, prior to undergoing an
expansion step, such as at expander 184. In one embodiment, the
temperature of the gas mixture 16 leaving the heat exchanger 178
and entering the expander 184 is less than about 32.degree. F.
(i.e., about 0.degree. C.). As discussed in other embodiments, upon
being expanded, the gas mixture 16 may be at a temperature and
pressure where the CO.sub.2 is in a solid or liquid form and
amenable to separation (block 188) from the gas mixture, such as by
mechanical or other suitable approaches. In the depicted
embodiment, the remaining gas mixture 106, which may be at about
-100.degree. F. (i.e., about -73.degree. C.) may be used to cool
the heat exchanger 178 and/or the heat exchanger 204 (which may
form part of the air inlet of the gas turbine engine 160) through
which air 120 passes to enter the gas turbine engine 160 and/or to
cool one or more of the disclosed intercoolers.
[0060] As will be appreciated, the approaches discussed herein may
be used in a variety of contexts to capture CO.sub.2, and are not
limited to those examples discussed herein. For example, cryogenic
processes as discussed herein may be utilized to replace CO.sub.2
(and potentially H.sub.2S) removal in certain types of power
production plants, such as a plant based on an integrated
gasification combined cycle as may be used to produce power from
syngas derived from coal. In such an example, CO.sub.2 may be
frozen or condensed on gasification such that the cooled syngas
drops out water, CO.sub.2, and H.sub.2S. Likewise, the present
approaches may be applied in other contexts to remove CO.sub.2 from
exhaust gases or other gas mixtures, regardless of the manner in
which the gas mixture is derived or produced.
[0061] This written description uses examples to disclose the
invention, including the best mode, and also to enable any person
skilled in the art to practice the invention, including making and
using any devices or systems and performing any incorporated
methods. The patentable scope of the invention is defined by the
claims, and may include other examples that occur to those skilled
in the art. Such other examples are intended to be within the scope
of the claims if they have structural elements that do not differ
from the literal language of the claims, or if they include
equivalent structural elements with insubstantial differences from
the literal languages of the claims.
* * * * *