U.S. patent application number 12/371208 was filed with the patent office on 2010-08-19 for post-combustion processing in power plants.
This patent application is currently assigned to General Electric Company. Invention is credited to James Nicolas Adelman, Alan Donn Maddaus, Gregory Paul Wotzak.
Application Number | 20100205964 12/371208 |
Document ID | / |
Family ID | 42558693 |
Filed Date | 2010-08-19 |
United States Patent
Application |
20100205964 |
Kind Code |
A1 |
Maddaus; Alan Donn ; et
al. |
August 19, 2010 |
POST-COMBUSTION PROCESSING IN POWER PLANTS
Abstract
A system and method for configuring a steam turbine in a power
plant to supply steam from a low pressure section of the steam
turbine to a flue-gas processing unit in the power plant.
Inventors: |
Maddaus; Alan Donn;
(Rexford, NY) ; Wotzak; Gregory Paul;
(Schenectady, NY) ; Adelman; James Nicolas;
(Carmel, NY) |
Correspondence
Address: |
GE Energy-Global Patent Operation;Fletcher Yoder PC
P.O. Box 692289
Houston
TX
77269-2289
US
|
Assignee: |
General Electric Company
Schenectady
NY
|
Family ID: |
42558693 |
Appl. No.: |
12/371208 |
Filed: |
February 13, 2009 |
Current U.S.
Class: |
60/645 ; 110/345;
60/648 |
Current CPC
Class: |
F01K 7/22 20130101; F23J
2215/50 20130101; Y02E 20/32 20130101; Y02E 20/326 20130101; Y02P
80/15 20151101; F23J 2219/40 20130101; F01K 17/04 20130101; F23J
15/02 20130101; Y02P 80/154 20151101 |
Class at
Publication: |
60/645 ; 60/648;
110/345 |
International
Class: |
F01K 17/00 20060101
F01K017/00; F01D 15/10 20060101 F01D015/10; F23J 15/00 20060101
F23J015/00 |
Claims
1. A power plant comprising: a boiler configured to combust fuel,
vaporize liquid water into steam, and discharge a combustion
exhaust; a treatment unit configured to process the combustion
exhaust discharged from the boiler; a steam turbine configured to
receive steam from the boiler, wherein the steam turbine comprises
a shaft, an intermediate pressure section, and a low pressure
section, and wherein the steam turbine is configured to provide
steam from the low pressure section to the treatment unit; and a
load coupled to the shaft of the steam turbine and configured to be
driven by the steam turbine.
2. The power plant of claim 1, wherein the treatment unit comprises
a carbon dioxide separation unit.
3. The power plant of claim 2, wherein the carbon dioxide
separation unit comprises a stripper and a reboiler associated with
the stripper, wherein the reboiler is configured to receive steam
from the low pressure section.
4. The power plant of claim 2, comprising a conduit coupling the
low pressure section with a reboiler in the carbon dioxide
separation unit.
5. The power plant of claim 1, wherein the steam turbine comprises
a high pressure section.
6. A method of operating a power plant, comprising: feeding fuel to
a boiler; combusting the fuel in the boiler; discharging a
combustion exhaust from the boiler; processing the combustion
exhaust in a treatment unit; feeding liquid water to the boiler;
vaporizing the liquid water into steam via heat generated by
combusting the fuel; supplying steam from the boiler to a steam
turbine; and supplying steam from a low pressure section of the
steam turbine to the treatment unit.
7. The method of claim 6, wherein processing comprises recovering
carbon dioxide from the combustion exhaust in the treatment
unit.
8. The method of claim 7, wherein supplying steam to the treatment
unit comprises supplying steam from the low pressure section to a
stripper reboiler in the treatment unit.
9. The method of claim 6, wherein feeding and combusting fuel
comprises feeding coal to the boiler and combusting the coal in the
boiler.
10. The method of claim 6, comprising producing electricity via a
generator coupled to a shaft of the steam turbine.
11. A method comprising configuring a steam turbine in a power
plant to supply steam from a low pressure section of the steam
turbine to a flue-gas processing unit, wherein configuring the
steam turbine comprises installing a steam turbine at the power
plant or retrofitting an existing steam turbine disposed at the
power plant.
12. The method of claim 11, wherein retrofitting comprises
replacing or modifying a low pressure section of the steam
turbine.
13. The method of claim 11, wherein a low pressure section of the
configured steam turbine comprises one or more steam extractions
sized collectively to extract 10% to 25%, by weight, of an amount
of steam entering the low pressure section.
14. The method of claim 11, wherein configuring the steam turbine
comprises reducing stage size subsequent to the steam extraction
correlative with an amount of steam to be extracted via the steam
extraction.
15. The method of claim 11, wherein the flue-gas processing unit
comprises a carbon dioxide separation unit.
16. The method of claim 15, comprising configuring a stripper
reboiler in the carbon dioxide separation unit to receive steam
from the low pressure section.
17. A steam turbine comprising: a shaft; a high pressure section;
an intermediate pressure section; a low pressure section configured
with a steam extraction to provide steam to a flue-gas processing
unit.
18. The steam turbine of claim 17, wherein the flue-gas processing
unit comprises a carbon dioxide separation unit, and the steam
extraction comprises a plurality of steam extractions sized
collectively to provide at least an amount of steam required for
operation of a stripper reboiler in the carbon dioxide separation
unit.
19. The steam turbine of claim 17, wherein at least one stage in
the low pressure section downstream of the steam extraction is
reduced in size correlative to an amount of steam extracted via the
steam extraction.
20. The steam turbine of claim 17, wherein the steam extraction
comprises a plurality of steam extractions sized collectively to
extract 10% to 25%, by weight, of an amount of steam entering the
low pressure section.
Description
BACKGROUND OF THE INVENTION
[0001] The present invention relates generally to power plants.
More particularly, the invention is directed to sourcing a supply
of steam for use in flue-gas treatment.
[0002] Power plants may combust various fuels, such as coal,
hydrocarbons, bio-mass, waste products, and the like, in boilers,
for example, to generate steam and electricity. Exhaust streams
(i.e., flue gas) of such combustion processes may be treated to
neutralize or remove various compounds, such as sulfur oxides,
nitrogen oxides, and particulate matter, prior to discharge of the
flue gas to the environment. These downstream processes may include
post-combustion carbon capture systems. For example, a compound
that may be separated from the flue gas is carbon dioxide
(CO2).
BRIEF DESCRIPTION OF THE INVENTION
[0003] An aspect of the present invention is a power plant having:
a boiler to combust fuel, vaporize liquid water into steam, and
discharge a combustion exhaust; a treatment unit to process
combustion exhaust discharged from the boiler; a steam turbine to
receive steam from the boiler and having a shaft, an intermediate
pressure section, and a low pressure section, wherein the steam
turbine is configured to provide steam from the low pressure
section to the separation unit; and a load coupled to the shaft of
the steam turbine and configured to be driven by the steam turbine
to generate electricity.
[0004] An aspect of the present invention is a method of operating
a power plant, including: feeding liquid water and fuel to a
boiler; combusting the fuel in the boiler to generate steam;
discharging a combustion exhaust from the boiler; supplying steam
from the reboiler to a steam turbine; processing the combustion
exhaust in a treatment unit; and supplying steam from a low
pressure section of the steam turbine to the separation unit.
[0005] An aspect of the present invention is a method including
configuring a steam turbine in a power plant to supply steam from a
low pressure section of the steam turbine to a flue-gas processing
unit in the power plant, wherein configuring the steam turbine
involves installing a steam turbine at the power plant or
retrofitting an existing steam turbine disposed at the power
plant.
[0006] An aspect of the present invention includes a steam turbine
having at least a shaft, an intermediate pressure section, and a
low pressure section with a steam extraction to provide steam to a
flue-gas processing unit.
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] 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:
[0008] FIG. 1 is a schematic flow diagram of an exemplary power
plant in accordance the present techniques;
[0009] FIG. 2 is a schematic flow diagram of an exemplary CO2
separation unit in accordance the present techniques;
[0010] FIG. 3 is a simplified cross-section of an exemplary low
pressure section of a steam turbine in accordance with the present
techniques;
[0011] FIG. 4 is a diagrammatical representation of exemplary
configurations for a low pressure section of a steam turbine in
accordance the present techniques;
[0012] FIG. 5 is a cross-section of an exemplary low pressure
section of a steam turbine in accordance the present techniques;
and
[0013] FIG. 6 is a flow diagram of an exemplary method in
accordance with the present techniques.
DETAILED DESCRIPTION OF THE INVENTION
[0014] One or more specific embodiments of the present invention
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.
[0015] When introducing elements of various embodiments of the
present invention, 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. Any examples of operating parameters are not
exclusive of other parameters of the disclosed embodiments.
[0016] Combustion product gases (e.g., flue gases) in power plants
and other facilities may be exhausted to the outside air. Flue
gases are produced when coal, oil, natural gas, wood, or other fuel
is combusted in an industrial furnace, a power plant's
steam-generating boiler, or other combustion device. Flue gas may
be composed of carbon dioxide (CO.sub.2) and water vapor, as well
as nitrogen and oxygen remaining from the intake combustion air. It
may also contain a relatively small percentage of pollutants, such
as particulate matter, carbon monoxide, nitrogen oxides, sulfur
oxides, and the like.
[0017] The present technique may provide for an efficient source of
steam for the processing and treatment of post-combustion streams
(i.e., flue gas) in power plants and other facilities. Steam may be
employed in the processing of flue gas in a variety of ways, such
as in the regeneration of solvent for the absorption of CO2 from
power-plant flue gas in CO2 removal systems. One source of steam is
intermediate pressure exhaust of a steam turbine in the power
plant. Another source, in accordance with aspects of the present
technique, is to supply steam from a low-pressure section of the
steam turbine.
[0018] The steam turbine system in a power plant may be configured
or modified to supply steam. Such steam may be provided, for
example, to where the flue gas or combustion exhaust gas is
treated, such as where carbon dioxide is extracted from the flue
gas of the plant. In general, the present technique may provide a
solution to the source of steam energy for post-combustion carbon
capture systems and other post-combustion systems. The technique
may provide increased efficiency and decreased power loss for the
power plant and the post-combustion system. In addition, the
technique may beneficially provide for new designs of steam
turbines and retrofits of steam turbines.
[0019] Referring to FIG. 1, a power plant 10 is depicted. The power
plant 10 may be an independent power plant, or a power plant at
utility or industrial site, for example. A steam line 12 is routed
from the low pressure section 14 of a steam turbine 16 to provide
steam 12 to a CO2 separation unit 18 (e.g., to a stripper reboiler
in unit 18) and/or to other flue-gas treatment units 19. The power
plant 10 includes a boiler 20 supplied with fuel 22 and boiler feed
water 24. The fuel 22 may include coal, biofuel, heavy oil, waste
products, and other combustible fuels. The boiler feed water 24 may
be treated water, such as demineralized water, and may include
condensed steam returned from the steam turbine 16. Lastly, it
should be noted that the term "boiler" employed in the present
discussion may refer to typical boilers, as well as to combustion
and and/or steam generating vessels or equipment, in general.
[0020] In the boiler 20, the fuel 22 is combusted, such as in a
furnace of the boiler 20. Heat from the combustion vaporizes or
boils the boiler feed water 24 in the boiler 20, and steam 25 is
generated and supplied to the steam turbine 16. Combustion exhaust
26 (i.e., flue gas) exits from the boiler 20. As indicated, the
combustion exhaust 26 may include nitrogen, oxygen, CO2, nitrogen
oxides, sulfur oxides (e.g., sulfur dioxide or SO2), and
particulate matter. The nitrogen oxides may be derived from the
nitrogen in the ambient air used in the combustion and from any
nitrogen-containing compounds in the fuel 22. The sulfur oxides are
generally derived from sulfur-containing compounds in the fuel 22.
The particulate matter may be composed of small particles of solid
materials and small liquid droplets.
[0021] The combustion exhaust 26 may be processed in a variety of
exemplary treatment processes, which are represented by treatment
unit 19. In treatment units 19, certain compounds of the combustion
exhaust 26, such as the sulfur oxides, nitrogen oxides, and so
forth, may be altered or removed in scrubbers, bag filters,
electrostatic precipitators, activated carbon, catalytic reduction
systems, calcium-based reagent treaters, and so on. In one example,
sulfur trioxide (SO3) is converted to sulfur dioxide (SO2). In
another example, SO2 is removed form the exhaust 26. Flue gas
treatment has become a focus of electric utilities and industrial
operations due to air quality standards. As companies seek to
comply with air quality regulations and to use more economical fuel
sources, the need for effective flue gas treatment options has
increased. However, it should be emphasized that the present
technique is not limited to satisfying any particular standard or
regulation.
[0022] In the depicted embodiment of FIG. 1, steam 12 may be
supplied to one or more treatment units 19. The CO2 separation unit
18 is separately depicted and, as mentioned, receives steam 12 from
the steam turbine 26 in the illustrated embodiment. However, again,
it should be emphasized that steam 12 from steam turbine 16 may be
supplied to other treatment units 19 and other users of steam
within the power plant. Such supply of steam 12 may improve the
efficiency of the power plant 10.
[0023] In the exemplary CO2 separation unit 18, the CO2 is
separated from the exhaust 26, as indicated by reference numeral
30. The CO2 may be further processed, such as being compressed and
sequestered. Further, an exhaust 32 may exit the CO2 separation
unit and be discharged to the environment. On the other hand, the
exhaust 32 may be further processed prior to discharge to the
environment or elsewhere.
[0024] The steam 25 provided by the boiler 20 is fed to the steam
turbine 16 at the high pressure section 34. In a general case, the
steam turbine 16 also includes an intermediate pressure section 36,
the low pressure section 14, and a shaft 38. A load 40, such as a
generator, is driven by a shaft 38 to produce electricity. In
operation, the steam 25 may be fed initially to the high pressure
section 34. Steam is generally also fed from the high pressure (HP)
section 34 to the intermediate pressure (IP) section 36, as
indicated by reference numeral 42. The steam from the HP section 34
may be sent through a reheater 43 prior to entry to the IP section
36. It should be noted that alternate configurations (not depicted)
of steam turbine 16 may not include a high pressure section 34, for
example, if the available pressure of the inlet steam 25 is low. In
this alternate case, the steam 25 from the boiler may be fed to the
IP section 36, and the reheater 43 not employed.
[0025] In the illustrated embodiment, steam is further fed to the
low pressure (LP) section 14 from the IP section 36, as indicated
by reference numeral 44. It should be emphasized that the present
technique is not limited to steam turbines having a particular
number of sections or configuration. For example, the present
technique may apply to steam turbines having only two sections
(e.g., an IP section and a LP section). Further, the steam turbine
may have multiple sections in parallel at the same pressure.
[0026] Steam 46 exiting the LP section 14 is fed to a condenser 48
where the steam is condensed. The condensed steam may be pumped via
pump 50 as recovered boiler feed water 52 to the boiler 20. The
boiler feed water system (not depicted) may include a variety of
heat exchangers and other equipment to process and heat the water
52 prior to its entry to the boiler 20 as boiler feed water 24. In
addition, as appreciated by the skilled artisan, the steam turbine
16 may be equipped with appropriate instruments and alarms to
monitor operating conditions including speed, vibration, shell and
rotor expansions, steam and metal temperatures, rotor straightness,
turning gear operation, and various steam, oil, and hydraulic
system pressures. Tools, lifting bars, and related items may be
employed for erection and maintenance of the steam turbine 16.
Moreover, in general, there are a variety of emission control
technologies for steam systems. Such technologies may include
flue-gas recirculation, low excess firing, combustion control,
using low nitrogen fuel oil, inserting water/steam to lower NOx,
selective non-catalytic reduction, selective catalytic reduction,
and others.
[0027] In sum, the present technique provides extraction of steam
from a number of points in the LP section 14 of the steam turbine
16 in order to provide steam 12 to flue-gas treatment units (e.g.,
units 18 and 19). In certain embodiments, steam 12 is fed to the
CO2 separation unit 18, such as to a stripper reboiler in the unit
18. In one such example, the steam 12 may be beneficially supplied
at temperatures and pressures effective for operation of the
stripper reboiler. In other words, the operating pressures and
temperatures of the LP section steam may be relatively close or in
sync with the demands of the CO2 stripper reboiler. This is in
contrast to alternate approaches of sourcing the steam (e.g., used
for the stripper unit) via a slipstream of steam from the exhaust
of the IP pressure section 36 of a steam turbine 16. Unfortunately,
in configuring or retrofitting a steam turbine 16 to supply such IP
steam, the IP steam may exceed the pressure and temperature
effective for operation of the steam boiler. Thus, while retrofits
cost may be relatively low with use of IP steam, the operation may
be inefficient
[0028] FIG. 2 depicts an exemplary CO2 separation system 18 that
may utilize steam 12 from the LP section 14 of the steam turbine
16. It should be stressed that system 18 is only given as an
example, and that employment other CO2 separation units or flue-gas
treatment units, generally, may be afforded benefits from the
present technique. As appreciated by the skilled artisan, various
licensable technologies and other technologies exist for CO2
separation systems. Moreover, the system 18 may vary in size,
depending on the amount of incoming CO2, which may depend, for
example, on the size of the boiler 20 and number of boilers 20, the
types of fuels 22 fed to the boilers 20, and so on. The size of the
CO2 system 18 may be relatively small (e.g., a skid-mounted unit)
or may be larger, ranging up to a size of 5000 metric tons CO2 or
greater per day recovered.
[0029] Interest in recovery of CO2 from flue gases may be propelled
by multiple factors including the merchant CO2 market, renewed
interest in enhanced oil recovery (EOR), and the desire to reduce
greenhouse gas emissions. Carbon dioxide may be used in the food
industry in carbonated beverages, brewing, and flash drying. Its
industrial uses include enhanced oil recovery (EOR), welding,
chemical feedstock, inert gas, firefighting, and solvent extraction
as a supercritical fluid. It is an ingredient in medical oxygen,
where in low concentrations CO2 acts as a breathing stimulant. Flue
gases have long been a source of CO2 for the merchant CO2 market,
and typically more so in remote locations where by-product CO2
sources are unavailable, for example. In the simplest case, fuel is
combusted to produce flue gas. CO2 is then extracted from the flue
gas using a solvent, and heat from the upstream combustion process
to support the heat required for the CO2 capture.
[0030] In the illustrated embodiment of FIG. 2, the exhaust 26 from
the boiler 20 may be fed to an absorber 72 in the CO2 separation
system 18. The exhaust 26 may be fed to the absorber 72 at the
discharge pressure (e.g., at or near atmospheric pressure, less
than 30 psia, etc.) from the boiler (minus any hydraulic losses in
the piping or in the treatment units 19). On the other hand, the
exhaust 26 may be pressurized prior to entering the stripper 72,
either for the CO2 removal or pressurized in an upstream treatment
unit 19, and the like. The carbon dioxide content of incoming
exhaust 26 (flue-gas) is generally up to 30 volume %, depending,
for example, on the fuel 22 employed in the boiler 20. The exhaust
26 may have been cooled, pretreated for removal of particulates and
impurities such as SOx and NOx, and so on.
[0031] In the CO2 separation system 18, solvent 74 rich in CO2 may
exit the bottom of the absorber 72 and be delivered via pump 76 to
a stripper 77. Solvent 78 lean in CO2 exits a bottom portion of the
stripper 77 and is fed back to an upper portion of the absorber 72.
The absorber 72 and stripper 77 may incorporate a variety of
internal components, such as trays, packing, supports, and so on.
The absorber 72 is configured to absorb CO2 (e.g., via
countercurrent flow) from the entering exhaust 26. The stripper 77
is configured to remove the CO2 from the solvent. Make-up solvent
80 may be fed to the absorber 72. The sizes of the absorber 72 and
stripper 77 may generally be a function of the amount of CO2 to be
removed, and may be sized (e.g., height, diameter, etc.) according
to various engineering design equations. Moreover, it should be
noted that a single stripper 77 may server multiple absorbers 72,
for example.
[0032] The solvent may be a solution or dispersion, typically in
water, of one or more absorbent compounds, that is, compounds which
in water create an absorbent fluid that compared to water alone
increases the ability of the fluid to preferentially remove carbon
dioxide from the exhaust 26. Examples of such compounds are well
known in this art and can readily be ascertained by the
practitioner. Examples for the solvent include organic amines,
alkanolamines, diethyanolamine (DEA), monethanolamine (MEA) and
other primary amines, hindered amines, piperazine, pyrrolidine,
methyldiethanolamine (MDEA), diethyanolamine (DEA),
disoprpanolamine (DIPA), triethyanolamine (TEA), potassium
carbonate, sodium hydroxide, ammonia, various weak acid-alkali
salts, etc. Inhibitors may be included in the solvent to inhibit
degradation of the solvent.
[0033] The absorber 72 can be of any construction typical for
providing gas-liquid contact and absorption. In certain examples,
the absorber 72 may operate at slightly above ambient pressure. The
temperature in the absorber 72 can vary, depending on the
technology and solvent employed. In one example with an absorber 72
employing an alkanolamine solvent, the temperature in the absorber
72 ranges form 40.degree. C. to 45.degree. C. at the top of the
absorber 72 to 50.degree. C. to 60.degree. C. at the bottom of the
absorber 72. Optionally, a mist eliminator at the top of the
absorber 72 traps entrained solvent in the absorber vent gas
(exhaust 32), which may be essentially enriched nitrogen. The CO2
from the exhaust 26 is preferentially absorbed by the solvent
(i.e., the percentage of the carbon dioxide in the incoming exhaust
26 that is absorbed is greater than the percentage of other gases
present in the exhaust 26), producing a CO2-enriched liquid solvent
stream 74 which, as mentioned, emerges from the bottom of the
absorber 72 and is fed to the rich solvent pump 76.
[0034] Pump 76 compresses the carbon dioxide enriched liquid
absorbent stream 74 to a pressure which is sufficient to enable the
stream 74 to reach the top of stripper 77 at the desired pressure
(e.g., up to 15 psia, 5 psia to 30 psia, 35 psia or greater, and so
on). The CO2-rich stream 74 may be preheated in the countercurrent
heat exchanger 79 by the hot regenerated or lean solvent 78 (e.g.,
heated to a temperature of 100 to 110.degree. C.) and is
subsequently fed to the top portion of the stripper 77.
Alternatively, this stream can be heated before it is compressed in
pump 76. The stripper 77 may be a pressurized unit in which carbon
dioxide is recovered from the carbon dioxide enriched liquid
solvent stream 74. As indicated, the pressures in the stripper 77
(and in the reboiler 82) may be maintained (e.g., at 35 psia or
more). In one example, the solvent employed includes
monoethanolamine, and the pressure in the stripper 77 and reboiler
82 is maintained in the range of 40 to 55 psia.
[0035] The stripper 77 generally incorporates a reboiler 82 which
receives a portion of lean liquid solvent 78 exiting the bottom
portion of the stripper 77. The reboiler 82 vaporizes the liquid
solvent and provides solvent vapor 84 back to the stripper 77. A
single stripper may include more than one reboiler 82. In the
illustrated embodiment, the reboiler 82 receives steam from the low
pressure section 14 of stream turbine 16 (see FIG. 1). In one
example, vapor (and gas) 86 exiting the top of the stripper 77 is
fed through an overhead condenser 88. A portion of the stream 86 is
condensed and fed back as reflux 90 to the stripper 77. The reflux
90 may be routed through an accumulator vessel, a pump, and so
forth, prior to entry into the stripper 77. Separated CO2 30 is
removed from the condenser 88 for recovery. Again, the CO2 stream
30 may be compressed, for example, to facilitate recovery and
storage. Lastly, as mentioned, a heat exchanger 79 may provide for
cross-exchange of the rich solvent 74 and the lean solvent 78. Such
cross-exchange may provide improved efficiency via providing heat
from lean solvent 78 to the rich solvent 74.
[0036] In general, it should be noted that gas-liquid absorption
systems may be used in the removal of carbon dioxide from
power-plant flue gases. Gas-liquid contactors, such as an absorber
72, are used to selectively absorb carbon dioxide from combustion
or flue gases produced by utility and industrial plants. The flue
gas is usually counter-currently contacted with an absorption fluid
(e.g., solvent), such that carbon dioxide is selectively absorbed
in the absorption fluid. This carbon-dioxide rich solvent is heated
and directed to a stripper unit, such as stripper 77, which
operates at an elevated temperature in order to remove carbon
dioxide from the solvent. Energy is provided to the stripper to
elevate the temperature in the stripper 77 to facilitate transport
of the carbon dioxide to the gaseous phase for transfer to
sequestration processes. It should be emphasized that other unit
operations and systems other than gas-liquid absorption systems may
be employed separate CO2 from flue gas. Such alternate systems may
also benefit from lower pressure steam (e.g., 30-70 psig at about
230-250.degree. F. or higher) found as LP steam and not need higher
pressure steam, such as with IP steam.
[0037] As mentioned, a source for the steam used by the stripper 77
can be a slipstream of steam from the exhaust of the IP section
(e.g., section 36 in FIG. 1) of the power-plant steam turbine 16.
Beneficially, supply of steam from the IP section 36 (e.g., from
stream 44) may be a relatively straightforward retrofit. However,
as indicated, sourcing steam from the IP section 36 of a steam
turbine may result in a significant loss of efficiency (e.g.,
greater than 1%) and power (e.g., greater than 10 MW) for the total
power plant because the pressure and temperature of the IP steam 44
may exceed the requirement of the flue-gas treatment process. Thus,
again, the present technique advantageously provides for extraction
of steam from one or more points in the LP section 14 of the steam
turbine 16 in order to provide steam to a stripper reboiler 82 at
temperatures and pressures which are closer to those effective for
the stripper reboiler 82. The amount of steam extracted (e.g., in
pounds per hour) may be at least an amount required for operation
of an exemplary stripper reboiler 82 (which may include taking into
account the pressure and temperature of the steam, the operating
pressure and temperature of the stripper, the lean-rich
cross-exchanger approach temperature, the stripper reflux rate, and
so forth). In one example for a carbon separation system employing
an inhibited MEA as the solvent, the amount of steam utilized by
the reboiler 82 is in the range of 3,000,000 to 4,000,000 Btu's per
ton of CO2 recovered. The affected stages of the LP section 14 of
the steam turbine 16 may be designed to enable efficient extraction
of this steam 12. Such design may address balancing and sizing of
the stages in the LP section 14. Further, the extractions may be
designed to additionally supply LP turbine extraction steam for
other uses than flue-gas treatment, such as for heating boiler feed
water, and so forth.
[0038] The LP sections 14 of exemplary steam turbines 16 have a
number of stages, generally ranging from about 5 stages to about 40
stages. Moreover, as indicated, steam turbines 16 may have one or
more LP sections 14 in series and/or parallel. Extraction of steam
12 from the LP section 14 may be from one or more places or stages
of the LP section 14, such as in up to four stages or more. The
casing of the LP pressure section(s) 14 may be modified or tapped
into to extract or bleed the steam 12. Pipe, valves, and various
pipe fittings may be used to extract or bleed the steam 12 from the
casing of various stages of the LP section 14. Such piping and
fittings may be sized and design based on the hydraulic
requirements, for example, to supply steam 12 to unit 18 and/or
treatment units 19. In the design, construction, and/or retrofit of
the LP section 14, stages subsequent to steam 12 extraction or
bleed points, may be smaller due to the subsequent lower flow of
steam through the LP section. Beneficially, smaller subsequent
stages in the LP section may reduce the cost to manufacture the LP
section because less material (i.e., metal) is utilized.
[0039] FIG. 3 is a simplified cross-section of an exemplary LP
section 14A of a steam turbine 16. The LP section 14 has two steam
extractions 98 for supplying LP steam 12 to a flue-gas treatment
unit. While two extractions 98 are depicted, the LP section 14A may
instead be configured with only one steam extraction 98 or more
than two steam extractions 98. The LP section 14A has an inlet 100
for the introduction of IP steam 44 from the IP section 36 of the
steam turbine 16. An inlet control valve 102 manipulates the
introduction of the IP steam 44. The steam extractions 98 may be
configured to remove steam just downstream of a stage 104 (depicted
as vertical lines). The LP section 14A may also have one or more
extraction control valves 106 to control the amount and/or pressure
of steam extracted at one or more of the steam extractions 98. The
amount of steam extracted from the LP section 14A may also be
controlled by control valves disposed on piping (not depicted)
downstream of the steam extractions 98. Lastly steam 46 may
discharge from the LP section 14A via an exhaust (not depicted) to
be condensed for re-use as boiler feed water.
[0040] FIG. 4 depicts exemplary alternative configurations 110 of a
LP section 14 of steam turbine 16. The configurations 110 are
illustrated in the form of a simple flow schematic. The first
configuration 112 is single flow and the second configuration 114
is double flow (two elements). In the double flow, a typical flow
scheme is for the steam to enter at the center of the section and
to flow outward. The last two configurations 116 and 118 depicted
are four flow (four element) and six flow (six element),
respectively. It is common for double flow and multiple double flow
configurations 114, 116, and 118 to be constructed from double flow
elements, while the single flow configuration 112 may utilize one
half of a horizontally symmetric double flow element, for example.
It should e noted that a three or five flow LP sections, and the
like, may be constructed from appropriate combinations for single
and double flow elements, and so on. Lastly, the elements with the
configurations may be interconnected at least via a shaft 40.
[0041] FIG. 5 depicts diagrammatical representations of valves and
extractions on a cross-section of an example LP section 14B of the
steam turbine 16. In this example, the LP section 14B is a double
flow element. In the illustrated embodiment, the LP section 14B has
three steam extractions 98 for supplying LP steam to a flue-gas
treatment unit and three additional steam extractions 98 for other
uses, such as for use in heating boiler feed water. It should be
clarified that depicted LP section 14B as well as with the present
techniques, in general, that the LP section 14 has certain steam
extractions 98 as a utility for flue-gas treatment, which are not
specified for other uses, such as in the treatment of boiler feed
water. The total amount of steam extracted from the LP section 14B
via extractions 98 may be in the range of 10% to 25%, by weight, of
the steam entering and flowing through the LP section 14B, for
example.
[0042] In this example, the extractions 98 are symmetrically
arranged. However, symmetry of the extractions is not generally
required, but may pose advantages in design of the LP turbine.
Additional extractions 98 or fewer number of extractions 98 may
exist, depending on the requirements of the cycle including the
flue gas treatment system, for example. In a multiple LP element
arrangement such as with the configurations 116 and 118 of FIG. 4,
a differing number and arrangement of extractions 98 for each
element may be implemented.
[0043] In FIG. 5, the LP section 14B has an outer casing 130 (or
exhaust hood) and inner casing 132. The LP section 14B is situated
around a shaft 40. has an inlet 134 for introduction of IP turbine
steam 44 from the IP section 36 of the steam turbine 16. An inlet
control valve 136 may be included to admit the desired amount of
steam to the LP section 14B, with a balance of steam from the IP
turbine section 36 going to the flue-gas treatment unit, for
example. The steam extractions 98 may be configured to remove steam
just downstream of a stage 138. The LP section 14B may have one or
more extraction control valves 140 to control the amount and/or
pressure of the steam extracted at one or more of the steam
extractions 98. The amount of steam extracted may also be
controlled by control valves disposed on piping (not depicted)
downstream of the steam extractions 98. Further, steam may
discharge from the LP section 14B via an exhaust 142 on each end to
the double flow section, to be condensed for reuse as boiler
feedwater.
[0044] FIG. 6 depicts a method 160 of operating a power plant
having a boiler, steam turbine, and one or more flue-gas treatment
units (e.g., a CO2 separation unit). Fuel, such as coal (e.g.,
pulverized coal), waste products, biomass, and/or hydrocarbons, is
combusted in the boiler to generate steam (blocks 162 and 164). The
steam from the boiler is feed through a steam turbine to drive the
steam turbine (block 166). Electricity is generated via the steam
turbine such as by driving a generator via steam pressure and with
the steam turbine shaft (block 168). Exhaust from the boiler, which
may contain various compounds (e.g., CO2) to be removed prior to
discharged to the environment, is feed through one or more flue-gas
treatment units (e.g., a CO2 separation unit), where compounds
(e.g., CO2) are altered or separated from the combustion exhaust
(block 170). Steam from the low-pressure section of the steam
turbine may be fed to one or more of the units (e.g., the CO2 unit)
to facilitate separation of compounds (e.g., CO2) from the exhaust
(block 172).
[0045] In summary, the present technique may be directed to an
exemplary power plant having a boiler configured to combust fuel,
vaporize liquid water into steam, and discharge a combustion
exhaust (e.g., flue gas). The boiler provides steam to a steam
turbine for generating electricity. The steam turbine may have two
sections (e.g., IP section and LP section), three sections (e.g.,
HP section, IP section, and LP section), and so on. In certain
embodiments, the steam turbine is configured to provide steam from
the LP section to a flue-gas treatment unit, such as to a carbon
dioxide separation unit. The LP steam may be supplied to a stripper
reboiler in the separation unit, as discussed above, for example. A
conduit may couple the LP section of the steam turbine with a
stripper reboiler in a carbon dioxide separation unit.
[0046] Configuring the steam turbine to supply steam from a low
pressure section of the steam turbine to a flue-gas treatment or
processing unit may include installing a steam turbine at the power
plant or retrofitting an existing steam turbine disposed at the
power plant. Retrofit may involve replacing or modifying a low
pressure section of the steam turbine. The low pressure section of
the configured steam turbine comprises one or more steam
extractions sized collectively to extract 10% to 25%, by weight, of
the total steam entering the low pressure section. Other exemplary
ranges, by weight, for steam extracted from the total steam through
the LP section 14B include 5% to 30%, 12% to 22%, and 15% to 20%,
and so on.
[0047] The one or more steam extractions may be uncontrolled or
controlled extractions, or a combination thereof. The steam turbine
may be configured such that the size of stages subsequent to a
steam extraction is reduced correlative with an amount of steam to
be extracted via the steam extraction.
[0048] In operation of the power plant, fuel (e.g., coal) is fed to
the boiler and combusted in the boiler. A combustion exhaust is
discharged from the boiler and processed in one or more treatment
units. Liquid water is fed to the boiler and is vaporized into
steam via heat generated by combusting the fuel. Steam is supplied
from the boiler to a steam turbine. The steam may be supplied to a
IP section or HP section of the steam turbine, for example. Steam
is then supplied from a LP section of the steam turbine to one or
more treatment units of the combustion exhaust. In one example,
processing of the combustion exhaust includes recovering carbon
dioxide from the combustion exhaust in the treatment unit.
[0049] While only certain features of the invention have been
illustrated and described herein, many modifications and changes
will occur to those skilled in the art. It is, therefore, to be
understood that the appended claims are intended to cover all such
modifications and changes as fall within the true spirit of the
invention.
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