U.S. patent application number 12/063175 was filed with the patent office on 2010-06-03 for condensation method.
This patent application is currently assigned to GEA Energietechnik GmbH. Invention is credited to Michael Herbermann, Andras Mikovics, Heinz Wienen, Raimund Witte.
Application Number | 20100132362 12/063175 |
Document ID | / |
Family ID | 36650820 |
Filed Date | 2010-06-03 |
United States Patent
Application |
20100132362 |
Kind Code |
A1 |
Herbermann; Michael ; et
al. |
June 3, 2010 |
CONDENSATION METHOD
Abstract
A condensation method is described according to which exhaust
steam from a turbine (1) of a condensation power plant is supplied
to an air-cooled condenser (3) for condensation. The condensate (K)
obtained in the condenser (3) is preheated in a condensate heating
stage (6) prior to its supply to an evaporator upstream of the
turbine (1) by means of a feed pump. The condensate (K) is heated
by a partial steam flow (T) of the turbine (1). A degasifier (8) is
mounted in parallel to the condensate heating stage (6) for
degasifying the makeup feed water (W).
Inventors: |
Herbermann; Michael;
(Gladbeck, DE) ; Witte; Raimund; (Dortmund,
DE) ; Wienen; Heinz; (Velen, DE) ; Mikovics;
Andras; (Bochum, DE) |
Correspondence
Address: |
HENRY M FEIEREISEN, LLC;HENRY M FEIEREISEN
708 THIRD AVENUE, SUITE 1501
NEW YORK
NY
10017
US
|
Assignee: |
GEA Energietechnik GmbH
44809 Bochum
DE
|
Family ID: |
36650820 |
Appl. No.: |
12/063175 |
Filed: |
June 27, 2006 |
PCT Filed: |
June 27, 2006 |
PCT NO: |
PCT/DE06/01097 |
371 Date: |
February 7, 2008 |
Current U.S.
Class: |
60/688 |
Current CPC
Class: |
F01K 9/00 20130101; F28B
1/06 20130101; F28B 9/08 20130101; F28B 9/10 20130101 |
Class at
Publication: |
60/688 |
International
Class: |
F28B 3/00 20060101
F28B003/00 |
Foreign Application Data
Date |
Code |
Application Number |
Aug 25, 2005 |
DE |
10 2005 040 380.8 |
Claims
1.-7. (canceled)
8. A condensation method, comprising the steps of: feeding water
from an evaporator to a turbine of a condensation power plant;
conducting an exhaust steam flow from the turbine through a
condensate heating stage; condensing the exhaust steam flow in an
air-cooled condenser to produce a condensate flow; heating the
condensate flow, before being transferred into a condensate
collecting tank, in the condensate heating stage by means of the
turbine exhaust steam flow conducted through the condensate heating
stage; and feeding a partial steam flow exiting the condenser to a
degasifier for heating cold makeup feed water tank.
9. The condensation method of claim 8, wherein the air-cooled
condenser operates in dephlegmator mode.
10. The condensation method of claim 8, wherein the air-cooled
condenser includes first heat exchanging elements operating in
condenser mode and second heat exchanging elements operating in
dephlegmator mode.
11. The condensation method of claim 8, further comprising the step
of transforming the condensate flow to form drops when undergoing
the heating step.
12. The condensation method of claim 11, wherein the transforming
step includes the step of conducting the condensate flow across
formed bodies.
13. The condensation method of claim 12, wherein the transforming
step includes the step of arranging the formed bodies in the form
of a cascade.
14. The condensation method of claim 8, further comprising the step
of atomizing the condensate flow to form drops.
15. A condensation method, comprising the steps of: conducting
exhaust steam from a turbine through a first condensate heating
stage, thereby condensing a portion of the exhaust steam;
condensing a remaining portion of the exhaust steam in an
air-cooled condenser to produce a first condensate; feeding the
first condensate back to the first condensate heating stage for
heating the condensate by means of the exhaust steam flowing
through the first condensate heating stage; and diverting a partial
steam flow exiting the condenser to a second heating stage for
heating incoming cold makeup feed water and producing a second
condensate.
16. The condensation method of claim 15, wherein the second heating
stage includes a degasifier for degassing the makeup feed
water.
17. The condensation method of claim 15, further comprising the
step of extracting gases forming in the condenser, first and second
condensate heating stages, and degasifier.
18. The condensation method of claim 16, wherein the second heating
stage includes an excess steam condenser for condensing excess
steam exiting the condenser during the extracting step by incoming
cold makeup feed water.
19. The condensation method of claim 15, further comprising the
step of feeding the second condensate back to the first condensate
heating stage.
Description
[0001] The invention relates to a condensation method according to
the features set forth in the preamble of claim 1.
[0002] The efficiency of a power plant is a crucial factor in
relation to cost-effectiveness in particular when newly designed
power plants are involved. Many efforts have thus been undertaken
to optimize steam power processes in thermal power plants. Special
attention is hereby directed to the condensation system. In
particular, the potential with respect to the power plant
efficiency is not yet optimized when air-cooled condensers are
involved, as oftentimes used in the event of water deficiency at
the site of the power plant. Air-cooled condensers have the basic
drawback that the dry air temperature can be utilized only. In
addition, subcooling of the condensate is greater than when
water-cooled surface condensers and especially small exhaust steam
pressures are involved.
[0003] Air-cooled condensers have normally two condensation stages.
A first condensation stage involves a condensation of about 80-90%
of exhaust steam of a turbine. Process-based parameters, such as,
e.g., fluctuating outside temperatures, render a 100% condensation
virtually impossible so that a second condensation stage for
condensation of residual steam is always necessary. For that
reason, air-cooled condensers are oftentimes combined with one
other and operated in condenser mode and dephlegmator mode, with
the condensation in dephlegmator mode being intended for
condensation of residual steam, i.e. forming the second
condensation stage.
[0004] The obtained condensate is typically fed directly to a
condensate collector tank. Thereafter, the condensate is fed to a
degasifier for addition of refined makeup feed water to replace
leakage losses and for subsequent supply via a feed pump to an
evaporator upstream of the turbine. As the condensate in the
degasifier has to be heated to boiling temperature again for
degasification, the energy balance is adversely affected when the
condensate has been excessively subcooled beforehand because it
requires realization of increased energy supply through use of
primary fuels. Efforts have thus been undertaken to keep subcooling
as little as possible so as to minimize the use of primary fuels.
At the same time, efforts are made to maintain a smallest possible
energy amount for condensation of the turbine exhaust steam.
[0005] The invention is based on the object to provide a
condensation method in which subcooling of the condensate is
minimized to improve the power plant efficiency.
[0006] This object is attained by a condensation method having the
features set forth in claim 1.
[0007] An essential feature of the method according to the
invention resides in the heating of the condensate flow obtained in
the condenser in an especially provided condensate heating stage
before introduction into a condensate collector tank. Heating of
the condensate flow is effected by the turbine exhaust steam within
the condensate heating stage. At the same time, the partial steam
flow exiting the condenser is fed to a degasifier in which the
partial steam flow cools makeup feed water and fully condenses
itself.
[0008] A condensate heating stage provided in addition to a
degasifier permits the configuration according to the invention to
significantly minimize condensate subcooling and thus to reduce the
need for primary fuels. Model computations have shown that
subcooling of the condensate can be reduced from about 1-6 K as
determined for an air-cooled condenser of conventional type to
about 0.5 K in relation to the temperature in saturation state
downstream of the turbine. The power plant efficiency rises in
dependence on the reduction of subcooling. When a 600 MW power
plant is involved, the thermal efficiency may be improved by up to
25%, a value that should not be ignored when considering power
plant dimensions.
[0009] The method according to the invention uses the thermal
energy of the turbine exhaust steam flow significantly more
efficiently as it is not released to the environment by the
condensers but a major part thereof flows into the condensate, i.e.
it is substantially retained in the heat cycle. The reduced energy
losses result in the desired improvement of the power plant
efficiency. As the subcooled condensate is heated, part of the
turbine exhaust steam flow is condensed at the same time so that
less exhaust steam enters the condenser. The condensers may thus be
sized smaller in some circumstances.
[0010] Advantageous configurations of the inventive idea are the
subject matter of the subclaims.
[0011] It is sufficient in the method according to the invention to
operate the first condensation stage, i.e. the air-cooled
condenser, exclusively in the dephlegmator mode because a
degasifier which is anyway required in the steam power process can
be utilized as second condensation stage for condensation of excess
steam. The structure of the air-cooled condenser is thereby
simplified. The method according to the invention is, of course,
also applicable in condensers which have heat exchanging elements
operating in condenser mode as well as dephlegmator mode.
[0012] When the condensers operate fully in dephlegmator mode, a
large portion of the exhaust steam of the turbine becomes already
condensed. Still, the partial steam flow exiting the condenser
spontaneously adjusts for thermodynamic reasons such that a
sufficient volume flow is provided in the degasifier. When the
condensers operate in the dephlegmator mode, the turbine exhaust
steam flow is effectively routed to the degasifier via the
condenser and exits as partial steam flow. If in some circumstances
the partial steam flow exiting the condenser were inadequate in
order to sufficiently heat the cooler makeup feed water, it is
possible to supply a further partial steam flow of the turbine
exhaust steam flow directly, i.e. not the path taken via the
condenser. The degasifier may require more heat in particular when
greater amounts of refined makeup feed water are added into the
material cycle. As the makeup feed water has normally a
significantly lower temperature as the condensate, the energy
balance of a condensation power plant is advantageously affected
when the partial exhaust steam flow from the condenser is utilized
to degasify the makeup feed water or at least to contribute
thermally to degasification.
[0013] The makeup feed water is degasified predominantly,
preferably exclusively, in the thus provided degasifier. As the
condensate flow heats up in the condensate heating stage,
process-based gases may escape; the heated condensate contains
however very little inert gases so that small gas amounts are
encountered within the condensate heating stage. Like in a
dephlegmator and a degasifier, the gases can be removed by
suction.
[0014] In the event, air extraction causes also extraction of
excess steam from the degasifier, it is possible in accordance with
a further development of the invention to condense this excess
steam also by makeup water. This, too, heats the makeup water.
[0015] The heated makeup feed water from the degasifier is fed
preferably also to the condensate heating stage so that the makeup
feed water is heated in two stages. The condensate flow from the
condenser although sufficient to condense part of the turbine
exhaust steam flow, a complete condensation of the partial steam
flow exiting the condenser is, however, virtually impossible for
reasons of the energy balance. Condensation of the partial steam
flow can be absolutely ensured by a sufficient quantity of colder
makeup feed water.
[0016] Provisions are made to contact the condensate in drop shape
with the turbine exhaust steam flow in order to improve the heat
transfer within the condensate heating stage. This may be realized
by conducting the condensate across formed bodies and causing it to
contact the turbine exhaust steam flow in countercurrent flow. The
formed bodies may hereby be arranged in the form of a cascade. In
principle, the provision of a cascade-like disposition of metal
sheets without use of formed bodies is, of course, also
conceivable. What is crucial is the optimization of the heat
transfer from turbine exhaust steam flow onto the subcooled
condensate. In this context, it has been considered especially
considered useful, when the condensate is atomized for drop
formation. Thus, the condensate can be introduced into the
condensate heating stage with the aid of nozzles. Drops of
subcooled condensate form condensation germs of low temperature
within the condensate heating stage so that the condensation of the
turbine exhaust steam flow is accelerated while the temperature of
the condensate is raised in an energetically beneficial manner.
[0017] The invention will now be described in greater detail with
reference to the figures schematically showing exemplary
embodiments.
[0018] FIG. 1 shows a greatly simplified steam power process of a
thermal power plant, having a turbine 1 for feeding turbine exhaust
steam flow 2 to a condenser 3 via a line. The condenser 3 involves
an air-cooled condenser with heat exchanger elements 4 operated in
condenser mode and heat exchanger elements 5 operating in
dephlegmator mode. A major part of the turbine exhaust steam flow
condenses within the condenser 3.
[0019] The obtained condensate K exits the condenser 3 and is fed
to a condensate heating stage 6 in which the subcooled condensate K
is contacting the turbine exhaust steam flow 2. The condensate K is
heated so that a partial steam flow of the turbine exhaust steam
flow 2 condenses before entry of the turbine exhaust steam flow K
into the condenser 3 via the line 7 and is directly fed back into
the material cycle as part of the condensate K3.
[0020] Further provided is a degasifier 8 to which a partial steam
flow T from the condenser 3 is fed. The partial steam flow T is
condensed by supply of colder makeup feed water W and degassed at
the same time. The degasifier 8 serves effectively as a downstream
second condensate heating stage. The condensate K from the
degasifier 8 is fed to the condensate heating stage 6 in which the
subcooled condensates K, K1 are utilized to condense part of the
turbine exhaust steam flow 2.
[0021] The exemplary embodiment of FIG. 2 differs from the one in
FIG. 1 primarily by the operation of the condenser 9 exclusively in
dephlegmator mode. This can be seen on the steam entry at the lower
peripheral area of the condenser 9.
[0022] A further difference resides in the provision of an excess
steam condenser 11 also as second condensation stage in addition to
the degasifier 8. The excess steam condenser 11 is provided to
completely condense excess steam T2, which is highly enriched with
inert gases when exiting the condenser 9, by using makeup feed
water W. This has the effect that the makeup feed water W heats up
and blends with the condensate from the excess steam. The mixture
is fed as condensate flow K2 to the condensate heating stage 6.
[0023] Both exemplary embodiments include an air extraction 10 to
remove air from the material flow. The air extraction 10 is
connected to the condensers 9 operating exclusively in dephlegmator
mode and the heat exchanger elements 5 operating in dephlegmator
mode, respectively, as well as to the condensate heating stage 6
and to the degasifier 8 and the excess steam condenser 11,
respectively. The entire condensate K3 is fed to a condensate
collector tank, not shown in greater detail.
[0024] FIG. 3 illustrates the computed change of the thermal
efficiency of the process (in %), plotted over the condensate
subcooling (in K). The basis for the values listed in this diagram
is a calculation governed by the formula
.eta.th=P/(Qin+.DELTA.Qin), wherein nth is the efficiency, P is the
turbine output, Qin is the heat input, and .DELTA.Qin is the added
heat for condensate heating. The following values are realized when
a 600 MW power plant is involved:
TABLE-US-00001 Condensate tK .degree. C. 38.50 38.00 37.00 36.00
35.00 34.00 33.00 Temperature Condensate .DELTA.tK K 0.50 1.00 2.00
3.00 4.00 5.00 6.00 Subcooling Condensate hK KJ/kg 161.28 159.19
155.01 150.83 146.65 142.47 138.29 enthalpy Exhaust Qab MW 800.26
801.26 802.57 804.11 805.66 807.20 808.74 Heat Added Heat
.DELTA.Qin MW 0.00 0.77 2.31 3.86 5.40 6.94 8.48 for Heating
Condensate Efficiency .eta.th % 42.85 42.83 42.78 42.73 42.68 42.64
42.59 Change in .DELTA..eta.th % 0.00 0.02 0.07 0.12 0.16 0.21 0.28
Efficiency
[0025] The following parameters are constant in this computation:
turbine output 600 MW, exhaust steam mass flow 369 kg/s, exhaust
steam enthalpy 2330 kJ/kg, exhaust steam pressure 7 kPa, saturated
steam temperature 39.degree. C., heat input 1400.26 Mw. The
advantage of the method according to the invention is expressed by
enabling a substantial reduction in the subcooling of the
condensate to thereby improve the efficiency.
REFERENCE SYMBOLS
[0026] 1--turbine [0027] 2--turbine exhaust steam flow [0028]
3--condenser [0029] 4--heat exchanger element operated in condenser
mode [0030] 5--heat exchanger element operated in dephlegmator mode
[0031] 6--condensate heating stage [0032] 7--line [0033]
8--degasifier [0034] 9--condenser [0035] 10--air extraction [0036]
11--excess steam condenser [0037] K--condensate [0038]
K1--condensate [0039] K2--condensate [0040] K3--condensate [0041]
T--partial steam flow [0042] T1--partial steam flow [0043]
T2--excess steam [0044] W--makeup feed water
* * * * *