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Title:
CONDENSATION METHOD
Kind Code:
A1
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)
Application Number:
12/063175
Publication Date:
06/03/2010
Filing Date:
06/27/2006
Assignee:
GEA Energietechnik GmbH (44809 Bochum, DE)
Primary Class:
International Classes:
F28B3/00
View Patent Images:
Attorney, Agent or Firm:
Henry, Feiereisen Llc Henry Feiereisen M. M. (708 THIRD AVENUE, SUITE 1501, NEW YORK, NY, 10017, US)
Claims:
1. 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:

The invention relates to a condensation method according to the features set forth in the preamble of claim 1.

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.

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.

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.

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.

This object is attained by a condensation method having the features set forth in claim 1.

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.

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.

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.

Advantageous configurations of the inventive idea are the subject matter of the subclaims.

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.

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.

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.

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.

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.

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.

The invention will now be described in greater detail with reference to the figures schematically showing exemplary embodiments.

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.

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.

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.

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.

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.

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.

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 ηth=P/(Qin+ΔQin), wherein nth is the efficiency, P is the turbine output, Qin is the heat input, and ΔQin is the added heat for condensate heating. The following values are realized when a 600 MW power plant is involved:

CondensatetK° C.38.5038.0037.0036.0035.0034.0033.00
Temperature
CondensateΔtKK0.501.002.003.004.005.006.00
Subcooling
CondensatehKKJ/kg161.28159.19155.01150.83146.65142.47138.29
enthalpy
ExhaustQabMW800.26801.26802.57804.11805.66807.20808.74
Heat
Added HeatΔQinMW0.000.772.313.865.406.948.48
for Heating
Condensate
Efficiencyηth%42.8542.8342.7842.7342.6842.6442.59
Change inΔηth%0.000.020.070.120.160.210.28
Efficiency

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° 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

    • 1—turbine
    • 2—turbine exhaust steam flow
    • 3—condenser
    • 4—heat exchanger element operated in condenser mode
    • 5—heat exchanger element operated in dephlegmator mode
    • 6—condensate heating stage
    • 7—line
    • 8—degasifier
    • 9—condenser
    • 10—air extraction
    • 11—excess steam condenser
    • K—condensate
    • K1—condensate
    • K2—condensate
    • K3—condensate
    • T—partial steam flow
    • T1—partial steam flow
    • T2—excess steam
    • W—makeup feed water