U.S. patent application number 12/425861 was filed with the patent office on 2010-10-21 for method and system for operating a steam generation facility.
Invention is credited to Kowshik Narayanaswamy, Ajit Singh Sengar.
Application Number | 20100263605 12/425861 |
Document ID | / |
Family ID | 42980023 |
Filed Date | 2010-10-21 |
United States Patent
Application |
20100263605 |
Kind Code |
A1 |
Sengar; Ajit Singh ; et
al. |
October 21, 2010 |
METHOD AND SYSTEM FOR OPERATING A STEAM GENERATION FACILITY
Abstract
A method for operating a steam generation facility includes
inducing a motive force on water by channeling steam into at least
one eductor to form a steam-driven cooling fluid stream. The method
also includes channeling the steam-driven cooling fluid stream to
at least one attemperator. The method further includes channeling
steam from at least one steam source to the at least one
attemperator. The method also includes injecting the steam-driven
cooling fluid stream into the steam channeled through the at least
one attemperator to facilitate cooling the steam channeled from the
at least one steam source.
Inventors: |
Sengar; Ajit Singh;
(Bangalore, IN) ; Narayanaswamy; Kowshik;
(Bangalore, IN) |
Correspondence
Address: |
JOHN S. BEULICK (17851);ARMSTRONG TEASDALE LLP
7700 Forsyth Boulevard, Suite 1800
St. Louis
MO
63105
US
|
Family ID: |
42980023 |
Appl. No.: |
12/425861 |
Filed: |
April 17, 2009 |
Current U.S.
Class: |
122/31.1 |
Current CPC
Class: |
F22G 5/18 20130101; F22G
5/123 20130101 |
Class at
Publication: |
122/31.1 |
International
Class: |
F22B 1/08 20060101
F22B001/08 |
Claims
1. A method for operating a steam generation facility, said method
comprising: inducing a motive force on water by channeling steam
into at least one eductor to form a steam-driven cooling fluid
stream; channeling the steam-driven cooling fluid stream to at
least one attemperator; channeling steam from at least one steam
source to the at least one attemperator; and injecting the
steam-driven cooling fluid stream into the steam channeled through
the at least one attemperator to facilitate cooling the steam
channeled from the at least one steam source.
2. A method in accordance with claim 1, wherein inducing a motive
force on water by channeling steam comprises channeling a first
portion of superheated steam from at least one high-pressure
superheater.
3. A method in accordance with claim 2, wherein injecting the
steam-driven cooling fluid stream into the steam channeled through
the at least one attemperator comprises channeling a second portion
of superheated steam from the at least one high-pressure
superheater.
4. A method in accordance with claim 3, wherein injecting the
steam-driven cooling fluid stream into the steam channeled through
the at least one attemperator comprises channeling quenched steam
to at least one intermediate-pressure superheater.
5. A method in accordance with claim 4, wherein channeling quenched
steam to at least one intermediate-pressure superheater comprises
channeling quenched steam to a steam condensing unit.
6. A method in accordance with claim 1, further comprising inducing
a motive force on water by channeling water from at least one
condensate pump to the at least one eductor.
7. A method in accordance with claim 6, wherein channeling water
from at least one condensate pump comprises channeling water from
at least one steam condensing unit.
8. An attemperation system comprising: at least one eductor coupled
in flow communication with at least one water source and at least
one steam source, said at least one eductor configured to channel
steam from the at least one steam source to induce motive forces on
water channeled from the at least one water source; and at least
one attemperator coupled in flow communication with said at least
one eductor, said at least one attemperator configured to receive
water channeled from said at least one eductor and steam channeled
from the at least one steam source.
9. An attemperation system in accordance with claim 8, wherein said
at least one eductor is coupled in flow communication with at least
one high-pressure superheater.
10. An attemperation system in accordance with claim 8, wherein
said at least one attemperator is coupled in flow communication
with at least one high-pressure superheater.
11. An attemperation system in accordance with claim 8 further
comprising at least one of: at least one first valve coupled in
flow communication between the at least one water source and said
at least one eductor; at least one second valve coupled in flow
communication between the at least one steam source and said at
least one eductor; and at least one third valve coupled in flow
communication between the at least one steam source and said at
least one attemperator.
12. An attemperation system in accordance with claim 11, wherein
each of said first valve, said second valve, and said third valve
are automatically-operable and are operably synchronized with each
other.
13. An attemperation system in accordance with claim 8 further
comprising at least one of: a high-pressure portion of said
attemperation system; an intermediate-pressure portion of said
attemperation system; and a low-pressure portion of said
attemperation system.
14. A steam generation facility comprising: at least one water
source; at least one steam source; at least one eductor coupled in
flow communication with said at least one water source and said at
least one steam source, said at least one eductor configured to
channel steam from said at least one steam source to induce motive
forces on water channeled from said at least one water source; and
at least one attemperator coupled in flow communication with said
at least one eductor, said at least one attemperator configured to
receive water channeled from said at least one eductor and steam
channeled from said at least one steam source.
15. A steam generation facility in accordance with claim 14,
wherein said at least one water source comprises at least one of at
least one condensate extraction pump and a steam condensing
unit.
16. A steam generation facility in accordance with claim 14,
wherein said at least one steam source comprises a heat recovery
steam generator (HRSG).
17. A steam generation facility in accordance with claim 16,
wherein said HRSG comprises at least one of: at least one
high-pressure superheater; at least one intermediate-pressure
superheater; and at least one low-pressure superheater.
18. A steam generation facility in accordance with claim 14 further
comprising at least one of: at least one first valve coupled in
flow communication between said at least one water source and said
at least one eductor; at least one second valve coupled in flow
communication between said at least one steam source and said at
least one eductor; and at least one third valve coupled in flow
communication between said at least one steam source and said at
least one attemperator.
19. A steam generation facility in accordance with claim 18,
wherein each of said first valve, said second valve, and said third
valve are automatically-operable and are operably synchronized with
each other.
20. A steam generation facility in accordance with claim 14 further
comprising at least one of: a high-pressure portion of said
attemperation system; an intermediate-pressure portion of said
attemperation system; and a low-pressure portion of said
attemperation system.
Description
BACKGROUND OF THE INVENTION
[0001] The embodiments described herein relate generally to steam
generation facilities and, more particularly, methods and systems
for attemperating steam within steam generation facilities.
[0002] At least some known steam generation facilities, such as,
combined cycle plants, include at least one steam generator. At
least some known steam generators are heat recovery steam
generators (HRSGs) that are coupled in flow communication with a
heat source, a water source, and a plurality of steam turbine
components, such as high-pressure, intermediate-pressure, and
low-pressure turbines. In operation, the HRSG receives water and
heat and boils the water to generate high-temperature,
high-pressure steam for use in driving the turbines, which in turn
drive devices, such as generators and pumps. In the event of a
steam turbine trip, at least of a portion of steam residing in
portions of the HRSG is channeled to other portions of the HRSG or
other components, such as a steam condensing device. During such
channeling, steam may contact components that may not be designed
and/or fabricated for continuous exposure to such high-temperature,
high-pressure steam.
[0003] In at least some of these known steam generation facilities,
the steam is attemperated to reduce the effects of contact with the
steam. For example, such attemperation is typically achieved with
dedicated attemperation devices that are coupled in flow
communication with oversized, joint-usage, high- to
intermediate-pressure feedwater pumps. Such feedwater pumps provide
sufficient positive pressure to overcome steam pressures to achieve
the desired attemperation substantially throughout a full range of
operating conditions. However, such oversizing typically includes
increased capital and operating costs.
[0004] In other known steam generation facilities, such
attemperation may be achieved with low-pressure water pumps.
Generally, one in such facilities, low-pressure water pump is
operated continuously with a second low-pressure water pump in a
standby condition. Generally, a single, low-pressure water pump
creates sufficient head pressure to overcome steam pressure for at
least partially achieving a desired attemperation. However, because
of lower discharge pressures, often a plurality of such
low-pressure water pumps must be used to generate sufficient
attemperating water flow to fully achieve desired attemperation.
Typically, as such, a period of time is required to enable the
second low-pressure water pump to achieve sufficient pumping
capacity after a turbine trip to enable the desired attemperation
to be achieved. The addition of redundant low-pressure water pumps
increases capital costs associated with facility installations and
increases the time delay before a desired attemperation of the
high-pressure, high-temperature steam being channeled from the HRSG
may be achieved. Moreover, continuous operation of the more
low-pressure water pumps increases operational costs, such as
auxiliary power usage and maintenance costs associated with such
equipment.
BRIEF DESCRIPTION OF THE INVENTION
[0005] This Brief Description is provided to introduce a selection
of concepts in a simplified form that are further described below
in the Detailed Description. This Brief Description is not intended
to identify key features or essential features of the claimed
subject matter, nor is it intended to be used as an aid in
determining the scope of the claimed subject matter.
[0006] In one aspect, a method for operating a steam generation
facility is provided. The method includes inducing a motive force
on water by channeling steam into at least one eductor to form a
steam-driven cooling fluid stream. The method also includes
channeling the steam-driven cooling fluid stream to at least one
attemperator. The method further includes channeling steam from at
least one steam source to the at least one attemperator. The method
also includes injecting the steam-driven cooling fluid stream into
the steam channeled through the at least one attemperator to
facilitate cooling the steam channeled from the at least one steam
source.
[0007] In another aspect, an attemperation system is provided. The
system includes at least one eductor coupled in flow communication
with at least one water source and at least one steam source. The
at least one eductor is configured to channel steam from the at
least one steam source to induce motive forces on water channeled
from the at least one water source. The system also includes at
least one attemperator coupled in flow communication with the at
least one eductor. The at least one attemperator is configured to
receive water channeled for the at least one eductor and steam
channeled from the at least one steam source.
[0008] In another aspect, a steam generation facility is provided.
The facility includes at least one water source and at least one
steam source. The facility also includes at least one eductor
coupled in flow communication with the at least one water source
and the at least one steam source. The at least one eductor is
configured to channel steam from the at least one steam source to
induce motive forces on water channeled from the at least one water
source. The facility also includes at least one attemperator
coupled in flow communication with the at least one eductor. The at
least one attemperator is configured to receive water channeled for
the at least one eductor and steam channeled from the at least one
steam source.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] The embodiments described herein may be better understood by
referring to the following description in conjunction with the
accompanying drawings.
[0010] FIG. 1 is a schematic block diagram of an exemplary steam
generation facility;
[0011] FIG. 2 is a schematic block diagram of an exemplary
attemperation system using an eductor that may be used with the
steam generation facility shown in FIG. 1; and
[0012] FIG. 3 is a flow diagram illustrating an exemplary method of
operating the steam generation facility shown in FIGS. 1 and 2.
DETAILED DESCRIPTION OF THE INVENTION
[0013] FIG. 1 is a schematic block diagram of an exemplary steam
generation facility 100. In the exemplary embodiment, steam
generation facility 100 includes at least one steam generator, that
is, a heat recovery steam generator (HRSG) 102. HRSG 102 is coupled
in flow communication with a gas turbine exhaust manifold 104 and a
residual heat exhaust stack 106. Also, in the exemplary embodiment,
HRSG 102 includes a plurality of water-steam element bundles 108
and a plurality of water-steam separation units 110. Bundles 108
and units 110 are coupled in flow communication in an orientation
that facilitates heating water (not shown) from subcooled
conditions to superheated steam conditions within bundles 108,
while separating water (not shown) from steam (not shown) within
separation units 110. Bundles 108 include at least one
high-pressure (HP) superheater, that is, a first HP superheater
(HPSH-1) 111 that is coupled in flow communication with a second HP
superheater (HPSH-2) 113. Bundles 108 also include at least one
intermediate-pressure (IP) superheater, that is, a first IP, or
reheat superheater (RHSH-1) 115 coupled in flow communication with
a second IP, or reheat superheater (RHSH-2) 117. Bundles 108
further include at least one low-pressure (LP) superheater (LPSH)
131. Each superheater 111, 113, 115, 117, and 131 is described in
more detail below with respect to configuration and functionality
within steam generation facility 100. Water and steam are heated to
superheated conditions via heat transfer from hot gases 112
channeled from gas turbine exhaust manifold 104 through HRSG 102.
Stack 106 is coupled in flow communication with HRSG 102 to enable
cooled exhaust gases 114 to be exhausted via stack 106.
[0014] Steam generation facility 100 also includes a steam turbine
system 120. In the exemplary embodiment, system 120 includes a
high-pressure (HP) steam turbine 122 that is coupled to HRSG 102,
or more specifically, HPSH-2 113, via at least one HP admission
control valve 124. Also, in the exemplary embodiment, steam turbine
system 120 includes an intermediate-pressure (IP) steam turbine 126
that is coupled to HRSG 102, or more specifically, RHSH-2 117, via
at least one IP admission control valve 128. Moreover, in the
exemplary embodiment, steam turbine system 120 includes a
low-pressure (LP) steam turbine 130 that is coupled in flow
communication with IP steam turbine 126 and that is coupled to LPSH
131 within HRSG 102 via at least one LP admission control valve
132.
[0015] In the exemplary embodiment steam generation facility 100
also includes a combined condensate-feedwater system 140. In the
exemplary embodiment, system 140 includes any number of condensate
booster pumps, condensate pumps, feedwater booster pumps, feedwater
pumps, deaerating units, piping, valving, and any other components
known in the art (none shown) that enables steam generation
facility 100 to function as described herein. Also, in the
exemplary embodiment, system 140 is coupled in flow communication
with HRSG 102 and with a steam condensing unit 142.
[0016] Steam generation facility 100 also includes a steam bypass
system 150. In the exemplary embodiment, steam bypass system 150
includes an HP bypass pressure control valve (PCV) 152 that is
coupled in flow communication with HRSG 102, or more specifically,
HPSH-2 113. Also, in the exemplary embodiment, steam bypass system
150 includes an IP bypass PCV 154 that is coupled in flow
communication with HRSG 102, or more specifically, RHSH-2 117.
Moreover, in the exemplary embodiment, steam bypass system 150
includes a LP bypass PCV 156 that is coupled in flow communication
with HRSG 102. Also, in the exemplary embodiment, system bypass
system 150 includes at least one condensate extraction pump (CEP)
158 that is coupled in flow communication with steam condensing
unit 142.
[0017] Steam bypass system 150 also includes an attemperation
system 160. In the exemplary embodiment, attemperation system 160
includes an HP portion 162 that is coupled in flow communication
with HP PCV 152. Also, in the exemplary embodiment, attemperation
system 160 includes an IP portion 164 that is coupled in flow
communication with IP PCV 154. Further, in the exemplary
embodiment, attemperation system 160 includes an LP portion 166
that is coupled in flow communication with LP PCV 156. Each portion
162, 164, and 166 is coupled in flow communication with CEP 158.
Attemperation system 160 and associated portions 162, 164, and 166
are described in more detail below.
[0018] In the exemplary embodiment, steam generation facility 100
is a combined cycle electric power generation facility.
Alternatively, steam generation facility 100 may be any facility
that enables attemperation system 160 to function as described
herein. Also, in the exemplary embodiment, facility 100 includes at
least one steam generator, i.e., HRSG 102. Alternatively, facility
100 may include any type of steam generator that enables
attemperation system 160 to function as described herein.
[0019] During operation of steam generation facility 100, hot
exhaust gases 112 are channeled from gas turbine exhaust manifold
104 through HRSG 102. As gases 112 flow about water-steam element
bundles 108, heat is transferred from gases 112 to water and/or
steam flowing through bundles 108. As heat is transferred from
gases 112, such gases 112 are cooled prior to being exhausted via
stack 106.
[0020] Also, during operation, subcooled water (not shown) is
channeled from steam condensing unit 142 to HRSG 102 via combined
condensate-feedwater system 140. Subcooled water receives heat
transferred from cooled exhaust gases 114 and the temperature of
such subcooled water is elevated. The water temperature increases
as it flows through successive water-steam element bundles 108,
wherein the water is eventually heated to saturation conditions. As
steam is formed within the saturated water, the steam and water are
separated via separation units 110, wherein water is returned to
bundles 108 for subsequent heating and steam formation, while steam
is channeled to subsequent bundles 108 to receive additional heat
transfer to superheated steam conditions. Specifically, steam that
is at least partially superheated is channeled to HPSH-1 111, prior
to being channeled to HPSH-2 113, to form high-pressure (HP)
superheated main steam (not shown). In the exemplary embodiment,
such superheated HP main steam has thermodynamic conditions
including, but not limited to, temperatures and pressures that
enable operation of steam generation facility 100 as described
herein.
[0021] Superheated HP main steam is channeled to HP admission
control valve (ACV) 124 for admission to HP steam turbine 122. Heat
energy within the superheated HP main steam is transferred to
rotational kinetic energy within HP steam turbine 122. Superheated
intermediate pressure (IP) exhaust steam (not shown) is channeled
from HP steam turbine 122 to HRSG 102, or more specifically, to
RHSH-1 115, for subsequent reheating. In the exemplary embodiment,
such IP exhaust steam has thermodynamic conditions including, but
not limited to, temperatures and pressures that enable operation of
steam generation facility 100 as described herein.
[0022] IP exhaust steam is channeled to RHSH-1 115, prior to being
channeled to RHSH-2 117 to form intermediate-pressure (IP)
superheated reheat steam (not shown). In the exemplary embodiment,
such superheated IP reheat steam has thermodynamic conditions
including, but not limited to, temperatures and pressures that
enable operation of steam generation facility 100 as described
herein.
[0023] Superheated IP reheat steam is channeled to IP admission
control valve (ACV) 128 for admission to IP steam turbine 126. Heat
energy within the superheated IP reheat steam is transferred to
rotational kinetic energy within IP steam turbine 126. Superheated
low pressure (LP) exhaust steam (not shown) is channeled from IP
steam turbine 126 to LP turbine 130. Moreover, superheated LP steam
from LPSH 131 is channeled to LP steam turbine 130 via LP ACV 132.
Heat energy within the superheated LP steam is transferred to
rotational kinetic energy within LP steam turbine 130. LP exhaust
steam (not shown) is channeled from LP steam turbine 130 to steam
condensing unit 142 for recycling through the thermodynamic cycle
described herein. Operation of bypass system 150 and embedded
attemperation system 160 are described in more detail below.
[0024] FIG. 2 is a schematic block diagram of an exemplary
attemperation system 160 using an eductor 172 that may be used with
steam generation facility 100. In the exemplary system 160 is
embedded within steam bypass system 150 and includes three
individual portions: an HP portion 162, an IP portion 164, and a LP
portion 166 (each shown in FIG. 1).
[0025] In the exemplary embodiment, HP portion 162 includes at
least one high-pressure (HP) eductor 172 that is coupled in flow
communication with condensate extraction pump (CEP) 158 via a first
valve. In the exemplary embodiment, the first valve is a
high-pressure (HP) bypass temperature control valve (TCV) 174.
Eductor 172 includes a converging-diverging nozzle 173 that enables
the use of at least a portion of HP superheated main steam to
induce a motive force on cooling water for steam quenching as
described in more detail below. HP portion 162 also includes a
second valve, i.e., a high-pressure control valve (HPCV) 176, that
couples HP eductor 172 in flow communication with second
high-pressure superheater (HPSH-2) 113, and that facilitates
control of steam flow through HP portion 162. A third valve, i.e.,
HP bypass PCV 152, works in combination with HP eductor 172 and
HPCV 176 to provide pressure and temperature control within steam
generation facility 100, while facilitating the reduction of
unnecessary expenditure of thermal storage within HRSG 102, and
thereby facilitating a subsequent near-term restart of turbine
system 120. HP portion 162 also includes at least one HP
attemperator 178 that is coupled in flow communication with HP
bypass PCV 152, HP eductor 172, HP steam turbine 122, and first
reheat superheater (RHSH-1) 115. In the exemplary embodiment, HP
bypass PCV 152, HP bypass TCV 174, and HPCV 176 are
automatically-operable and are operably synchronized with each
other as described in more detail below.
[0026] During operation, in the exemplary embodiment, only one CEP
158 is continuously in service and is used for channeling subcooled
condensate water 170 from steam condensing unit 142 at
thermodynamic conditions including, but not limited to,
temperatures and pressures that enable operation of steam
generation facility 100 as described herein. Alternatively, all
CEPs 158 are removed from service until HP portion 162 is placed in
service, at which time, at least one CEP 158 is placed in service
in operational synchronization with HP bypass PCV 152, HP bypass
TCV 174, and HPCV 176. Therefore, attemperation system 160
facilitates reducing auxiliary power usage associated with steam
generation facility 100 by reducing the amount of idle service
associated CEPs 158. Furthermore, attemperation system 160
facilitates reducing capital costs of constructing steam generation
facility by reducing a need for redundant CEPs 158 and by reducing
excess feedwater pumping capacity.
[0027] Also, during operation, in the exemplary embodiment, HP ACV
124 is opened to enable steam to flow (not shown) from HPSH-2 113
to HP steam turbine 122. Moreover, in operation, in the exemplary
embodiment, HP bypass PCV 152, HP bypass TCV 174, and HPCV 176 are
each closed. Therefore, at least initially, there is substantially
no steam flow and no water flow through HP eductor 172 and/or HP
attemperator 178. Alternatively, HPCV 176 is at least partially
opened to enable a substantial continuous flow of HP steam and
condensate water through eductor 172 and attemperator 178, thereby
facilitating a further reduction in auxiliary power usage.
[0028] Further, in operation, in the event of a steam turbine
system 120 trip wherein a substantially instantaneous removal of
steam turbine system 120 from service occurs, including HP steam
turbine 122, and the rapid closing of HP ACV 124. As such, a
buildup of superheated steam pressure within HPSH-1 111 and HPSH-2
113, as well as other portions of HRSG 102 coupled in flow
communication with HPSH-1 111 and HPSH-2 113 occurs. Moreover, an
increasing pressure transient occurs in conjunction with a
substantial reduction in cooling fluid flow through HRSG 102.
During such operation, the injection of hot exhaust gases 112 from
gas turbine exhaust manifold 104 may not be reduced, thereby
facilitating an increasing temperature transient in HRSG 102. As
such, during operation, in the exemplary embodiment, steam bypass
system 150, including embedded attemperation system 160, is placed
in service to facilitate reducing the associated increasing
pressure transient within HRSG 102. Specifically, HP bypass PCV
152, HP bypass TCV 174, and HPCV 176 are moved from a closed
position to an at least partially open position.
[0029] More specifically, in operation, HP bypass TCV 174 opens
enough to enable subcooled condensate water 170 to be channeled
from steam condensing unit 142 to eductor 172 at thermodynamic
conditions including, but not limited to, temperatures and
pressures that enable operation of steam generation facility 100 as
described herein, via CEP 158. Also, HPCV 176 opens sufficiently to
enable a first portion of HP superheated main steam 171 to be
channeled from HPSH-2 113 to HP eductor 172 at thermodynamic
conditions including, but not limited to, temperatures and
pressures that enable operation of steam generation facility 100 as
described herein. HP bypass PCV 152 and HPCV 176 modulate in
operational synchronization with each other to facilitate
maintaining HP bypass steam pressure and temperature at values
substantially similar to, or below, pressures and temperatures
within RHSH-1 115. Steam 171 channeled into eductor 172 via HPCV
176 expands into eductor 172 to facilitate inducing a venturi
effect therein, wherein a velocity of steam 171 flow increases and
a pressure drop is induced. The induced pressure drop "draws" water
170 flowing via HP bypass TCV 174 into eductor 172, and at least a
portion of kinetic energy of steam 171 is transferred to water 170,
thus inducing a motive force on water 170. Steam 171 and water 170
mix within nozzle 173 to form a steam-driven cooling fluid stream
175 that is channeled towards HP attemperator 178 at thermodynamic
conditions including, but not limited to, temperatures and
pressures that enable operation of steam generation facility 100 as
described herein, i.e., to facilitate cooling superheated steam 171
channeled from HPSH-2 113.
[0030] Also, during operation, HP bypass PCV 152 shifts open
sufficiently to permit channeling a second portion of HP
superheated main steam 177 from HPSH-2 113 to HP attemperator 178
at thermodynamic conditions including, but not limited to,
temperatures and pressures that enable operation of steam
generation facility 100 as described herein. Attemperator 178
receives superheated steam 177 via HP bypass PCV 152 and
steam-driven cooling fluid stream 175 from HP eductor 172.
Moreover, superheated steam 177 is quenched by injecting
steam-driven cooling fluid stream 175 into superheated steam 177 to
form a quenched steam 179 that is channeled from HP attemperator
178 to RHSH-1 115, thus facilitating cooling of superheated steam
177 channeled from HPSH-2 113. Quenched steam 179 is also channeled
through RHSH-1 115 and RHSH-2 117 towards IP portion 164 of
attemperation system 160, as described in more detail below.
[0031] IP portion 164, in the exemplary embodiment, includes at
least one intermediate-pressure (IP) attemperator 188 that is
coupled in flow communication with condensate extraction pump (CEP)
158 via a first valve, i.e., an intermediate-pressure (IP) bypass
temperature control valve (TCV) 184. IP attemperator 188 is also
coupled in flow communication with IP bypass PCV 154. IP bypass PCV
154 facilitates controlling pressures and temperatures within steam
generation facility 100, while reducing unnecessary expenditures of
thermal storage within HRSG 102, thereby facilitating a subsequent
near-term restart of turbine system 120. IP attemperator 188 is
also coupled in flow communication with steam condensing unit 142.
In the exemplary embodiment, IP bypass PCV 154 and IP bypass TCV
184 are each automatically-operable and are operably synchronized
with each other as discussed in more detail below. Moreover, in the
exemplary embodiment, IP bypass PCV 154 and IP bypass TCV 184 are
each automatically-operable and are operably synchronized with HP
bypass PCV 152, HP bypass TCV 174, and HPCV 176.
[0032] During operation, in the exemplary embodiment, similar to
the operation described above for HP portion 162, only one CEP 158
is continuously in service to channel subcooled condensate water
from steam condensing unit 142 up to IP bypass TCV 184.
Alternatively, all CEPs 158 are removed from service until IP
portion 164 is placed in service, wherein at least one CEP 158 is
placed in service in operational synchronization with IP bypass PCV
154 and IP bypass TCV 184.
[0033] Also, during operation, in the exemplary embodiment, IP ACV
128 is opened to enable steam to flow (not shown) from RHSH-2 117
to IP steam turbine 126. Further, in operation, in the exemplary
embodiment, IP bypass PCV 154 and IP bypass TCV 184 are each
closed. Therefore, at least initially, there is substantially no
steam flow and/or water flow through IP attemperator 188.
[0034] Further, in operation, in the event of a steam turbine
system 120 trip, substantially instantaneous removal of steam
turbine system 100 from service, including IP steam turbine 126,
the rapid closure of IP ACV 128. As such a buildup of superheated
steam pressure within RHSH-1 115 and RHSH-2 117, as well as other
portions of HRSG 102 coupled in flow communication with RHSH-1 115
and RHSH-2 117 occurs. Moreover, quenched steam 179 from HP portion
162 is also channeled through RHSH-1 115 and RHSH-2 117. An
increasing pressure transient occurs in conjunction with a
substantial reduction in cooling fluid flow (not shown) through
HRSG 102. As such, injection of hot exhaust gases 112 from gas
turbine exhaust manifold 104 may not be reduced, thereby
facilitating an increasing temperature transient in HRSG 102. In
operation, in the exemplary embodiment, steam bypass system 150,
including embedded attemperation system 160, is placed in service
to facilitate reducing the associated increasing pressure transient
within HRSG 102. Specifically, IP bypass PCV 154 and IP bypass TCV
184 are at least partially opened.
[0035] More specifically, in operation, IP bypass TCV 184 is opened
sufficiently to enable a portion of subcooled condensate water 170,
i.e., a cooling fluid stream 185 to flow from steam condensing unit
142 towards IP attemperator 188 via CEP 158. Also, during
operation, IP bypass PCV 154 is opened to enable a portion of IP
superheated reheat steam 187 to be channeled from RHSH-1 115 to IP
attemperator 188. Attemperator 188 receives superheated steam 187
via IP bypass PCV 154 and cooling fluid stream 185 from IP bypass
TCV 184. Superheated steam 187 is quenched by injecting cooling
fluid stream 185 into superheated steam 187, thereby forming a
quenched steam 189 that is channeled from IP attemperator 188 to
steam condensing unit 142, and thereby cooling superheated steam
187 channeled from RHSH-2 117.
[0036] LP portion 166, in the exemplary embodiment, includes at
least one low-pressure (LP) attemperator 198 that is coupled in
flow communication with condensate extraction pump (CEP) 158 via a
first valve, i.e., a low-pressure (LP) bypass temperature control
valve (TCV) 194. LP attemperator 198 is also coupled in flow
communication with LP bypass PCV 156. LP bypass PCV 156 facilitates
controlling pressures and temperatures within steam generation
facility 100, while reducing unnecessary expenditures of thermal
storage within HRSG 102, thereby facilitating a subsequent
near-term restart of turbine system 120. LP attemperator 198 is
also coupled in flow communication with steam condensing unit 142.
In the exemplary embodiment, LP bypass PCV 156 and LP bypass TCV
194 are each automatically-operable and are operably synchronized
with each other as discussed further below. Moreover, in the
exemplary embodiment, LP bypass PCV 156 and LP bypass TCV 194 are
each automatically-operable and are operably synchronized with HP
bypass PCV 152, HP bypass TCV 174, and HPCV 176. Furthermore, in
the exemplary embodiment, LP bypass PCV 156 and LP bypass TCV 194
are each automatically-operable and are operably synchronized with
IP bypass PCV 154 and IP bypass TCV 184.
[0037] During operation, in the exemplary embodiment, similar to
the operation described above for IP portion 164, only one CEP 158
is continuously in service to channel subcooled condensate water
170 from steam condensing unit 142 to LP bypass TCV 194.
Alternatively, all CEPs 158 are removed from service until LP
portion 166 is placed in service, wherein at least one CEP 158 is
placed in service in operational synchronization with LP bypass PCV
156 and LP bypass TCV 194.
[0038] Also, during operation, in the exemplary embodiment, LP ACV
132 is opened to enable steam to flow (not shown) from LPSH 131 to
LP steam turbine 130. Further, in operation, in the exemplary
embodiment, LP bypass PCV 156 and LP bypass TCV 194 are each
closed. Therefore, at least initially, there is substantially no
steam flow and/or water flow through LP attemperator 198.
[0039] Further, in operation, in the event of a steam turbine
system 120 trip, substantially instantaneous removal of steam
turbine system 100 from service, including LP steam turbine 130,
the rapid closure of LP ACV 132. As such a buildup of superheated
steam pressure within LPSH 131, as well as other portions of HRSG
102 coupled in flow communication with LPSH 131 occurs. An
increasing pressure transient occurs in conjunction with a
substantial reduction in cooling fluid flow through HRSG 102. As
such, injection of hot exhaust gases 112 from gas turbine exhaust
manifold 104 may not be reduced, thereby facilitating an increasing
temperature transient in HRSG 102. In operation, in the exemplary
embodiment, steam bypass system 150, including embedded
attemperation system 160, is placed in service to facilitate
reducing the associated increasing pressure transient within HRSG
102. Specifically, LP bypass PCV 156 and LP bypass TCV 194 are at
least partially opened.
[0040] More specifically, in operation, LP bypass TCV 194 is opened
sufficiently to enable subcooled condensate water 170, i.e., a
cooling fluid stream 195 to flow from steam condensing unit 142
towards LP attemperator 198 via CEP 158. Also, during operation, LP
bypass PCV 156 is opened to enable a portion of LP superheated
steam 197 to be channeled from LPSH 131 to LP attemperator 198.
Attemperator 198 receives superheated steam 197 via LP bypass PCV
156 and cooling fluid stream 195 from LP bypass TCV 194.
Superheated steam 197 is quenched by injecting cooling fluid stream
195, thereby forming a quenched steam 199 that is channeled from LP
attemperator 198 to steam condensing unit 142, and thereby cooling
superheated steam 197 channeled from LPSH 131.
[0041] FIG. 3 is a flow diagram illustrating an exemplary method
200 of operating steam generation facility 100 (shown in FIGS. 1
and 2). In the exemplary embodiment, a motive force is induced 202
on water 170 (shown in FIG. 2) by channeling steam 171 (shown in
FIG. 2) into at least one eductor 172 (shown in FIG. 2), thereby
forming steam-driven cooling fluid stream 175 (shown in FIG. 2). In
addition, steam-driven cooling fluid stream 175 is channeled 204
into at least one attemperator 178 (shown in FIG. 2). Moreover,
steam 177 (shown in FIG. 2) is channeled 206 from at least one
steam source, that is, HPSH-2 113 (shown in FIGS. 1 and 2) to at
least one attemperator 178. Method 200 also includes injecting 208
steam-driven cooling fluid stream 175 into steam 177, channeled
through at least one attemperator 178, to facilitate cooling steam
177, channeled from at least one steam source, such as, HPSH-2
113.
[0042] In the exemplary embodiment, channeling 210 high-pressure
(HP) superheated steam 171 from at least one HP superheater, i.e.,
HPSH-2 113 to at least one eductor 172. Method 200 also includes
channeling 212 HP superheated steam 171 from HPSH-2 113 to
attemperator 178 (shown in FIG. 2) to facilitate cooling a second
portion 177 of HP steam (shown in FIG. 2).
[0043] Water 170 is channeled 214 from at least one condensate
extraction pump 158 and/or at least one steam condensing unit 142
to at least one eductor 172. Method 200 also includes channeling
216 quenched steam 179 to an IP superheater, i.e., RHSH-1 115 (both
shown in FIG. 2) and/or channeling quenched steam 189 and/or 199
(both shown in FIG. 2) to steam condensing unit 142.
[0044] Described herein are exemplary embodiments of methods and
systems that facilitate operating a steam generation facility.
Specifically, an attemperation system, embedded within a steam
bypass system, both as described herein, facilitates controlling
pressures and temperatures within portions of the steam generation
facility in the event of significant transients within the
facility. Such pressure and temperature control reduces channeling
high-pressure, high-temperature steam through components that may
not be designed and/or fabricated for continuous exposure to such
high-temperature, high-pressure steam. Also, the attemperation
system as described herein facilitates reducing a size of
high-pressure and/or intermediate pressure boiler feedwater pumps
by relying on lower-pressure condensate extraction pumps to
overcome steam pressures to achieve the desired attemperation
substantially throughout a full range of operating conditions.
Moreover, the attemperation system as described herein facilitates
reducing auxiliary power usage associated with the steam generation
facility by reducing idle service of low-pressure water pumps.
Further, the attemperation system as described herein facilitates
reducing capital costs of constructing the steam generation
facility by reducing a need for redundant low-pressure water pumps.
Moreover, the attemperation system as described herein facilitates
reducing excess feedwater pumping capacity, thus reducing capital
and operational costs. Also, the attemperation system as described
herein channels sufficient attemperating water flow after a
significant transient to enable the desired attemperation of the
high-pressure, high-temperature steam being channeled from the HRSG
to be achieved with little to no time delay.
[0045] The methods and systems described herein are not limited to
the specific embodiments described herein. For example, components
of each system and/or steps of each method may be used and/or
practiced independently and separately from other components and/or
steps described herein. In addition, each component and/or step may
also be used and/or practiced with other assembly packages and
methods.
[0046] While the invention has been described in terms of various
specific embodiments, those skilled in the art will recognize that
the invention can be practiced with modification within the spirit
and scope of the claims.
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