COMBINED-CYCLE GAS & STEAM POWER PLANTS Rolf Kehlhofer
CONTENTS Chapter 1 Introduction
1
Chapter 2 Thermodynamic Principles of The Combined-Cycle Plant
5
ChliPtE~r3
System Layouts
17
Chapter 4 Comtlin4~d-Cvde
Plants for
Cogeneration
147
Chl:lptl~r5
Components
."TITr,rll
171
and Automation
40
2fJ7
pennwen
UperlJltil1lg' and Part-Load Behavior
223
Copyright © 1997 by PennWell Publishing Company 1421 South SheridanIP.O. Box 1260 Tulsa, Oklahoma 74101
c..;OJmp:aril,on of The Combined-Cycle Plant Other Thermal Power Stations
241
I@lvilroTtmren·tal Considerations
263
J..)~yel0Plment~ll
Trends
277
Combined-Cycle Already Built
305
ISBN 0-87814-736-5 All rights reserved. No part of this book may be reproduced, stored in a retrieval system, or transcribed in any form or by any means, electronic or mechanical, including photocopying and recording, without the prior written permission of the publisher. Printed in the United States of America.
Chapter 12 Conclusions
353
Conversions
355
Symbols Used
··· .. ···
Indices Used Appendix 1
Chapter 1
357
INTRODUCTION
359 ·
·.. ······· .. · 363
Definition of Terms and Symbols
371
Bibliography
i5Tl
litc~ratUl~e has often suggested combining two or more therCVclE!S within a single power plant. In all cases, the intenincrease efficiency over that of single cycles. Thermal be combined in this way whether they operate or with differing working media. However, a comcycles with different working media is more interoe'CatlSe their advantages can complement one another.
the cycles can be classed as a "topping" and a "botThe first cycle, to which most of the heat is supca,lle~a the "topping cycle." The waste heat it produces lltiliz€~d in a second process which operates at a lower level and is therefore referred to as a "bottoming
seJLectioiTI of the working media makes it possible to process that makes optimum thermodynamic in the upper range of temperatures and returns the environment at as low a temperature level :NolrITlall.y the "topping" and "bottoming" cycles are exchanger.
•• V •..., • ...,I.II
pr,esEmt time, only one combined cycle has found rptance: the combination gas turbine/steam turbine far, plants of this type have burned generally n}]rinc~ip:all~,-liQujidfuels or gases.)
1
2
INTRODUCTION 3
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Fig. 1 is a simplified flow diagram for an installation of this type, in which an open-cycle gas turbine is followed by a stearn process. The heat given off by the gas turbine is used to generate stearn. Other combinations are also possible, e.g., a mercury vapor process or replacing the water with organic fluids or ammonia. The mercury vapor process is no longer of interest today since even conventional stearn power plants achieve higher efficiencies. Organic fluids or ammonia have certain advantages over water in the low temperature range, such as reduced volume flows, no wetness. However, the disadvantages, Le., development costs, environmental impact, etc., appear great enough to prevent their ever replacing the stearn process in a combined-cycle power plant. The discussion that follows deals mainly with the combination of an open-cycle gas turbine with a water/stearn cycle. Certain special applications using closed-cycle gas turbines will also be dealt with briefly.
It therefore is quite reasonable to use the stearn process for
"bottoming cycle." That such combination gas turbine/stearn ..... ,~h; ... '" power plants were not more widely used even earlier clearly been due to the historical development of the gas Only in recent years have gas turbines attained inlet that make it possible to design a very highefJ[icileIllcy cycle. Today, however, the installed power capacity cO]mblmE~<1-cy,clegas turbine/steam turbine power plants worldworld totals more than 30,000 MW.
Why has the combination gas turbine/stearn turbine power plant, unlike other combined-cycle power plants, managed to find wide acceptance? Two main reasons can be given: • It is made up of components that have already proven themselves in power plants with a single cycle. Development costs are therefore low. • Air is a relatively non-problematic and inexpensive medium that can be used in modern gas turbines at an elevated temperature level (above 1000 °C). That provides the optimum prerequisites for a good "topping cycle." The stearn process uses water, which is likewise inexpensive and widely available, but better suited for the medium and low temperature ranges. The waste heat from a modern gas turbine has a temperature level advantageous for a good stearn process.
4
2
5
flow diagram of a combination gas turbine/steam turbine power 4. 5. 6.
Steam turbine Condenser Fuel supply
Chapter 2
PRINCIPLES OF COMBINED-CYCLE PLANT Considerations efficiency is the maximum efficiency of an ideal
(1)
Carnot efficiency Temperature of the energy supplied Temperature of the environment the efficiencies of real processes are lower since involved. A distinction is drawn between enex,er~~eti,c losses. Energetic losses are mainly heat liation and convection), and are thus energy that is pr()c€~ss. Exergetic losses, on the other hand, are incal1se~d by irreverisible processes in accordance with of thermodynamics [1]. major reasons why the efficiencies of real prothan the Carnot efficiency: telmp,er:atllre differential in the heat being supplied great. In a conventional stearn power plant, maximum steam temperature is only about 5
6
PRINCIPLES OF THE COMBINED-CYClE PLANT 7
COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
8IOK (980°F), while the combustion temperature in the boiler is approx. 2000 K. Then, too, the temperature of the waste heat from the process is higher than the ambient temperature. Both heat exchange processes cause losses. The best way to improve the process efficiency is to reduce these losses, which can be accomplished by raising the maximum temperature in the cycle, or by releasing the waste heat at as Iowa temperature as possible. The interest in combined-cycles arises particularly from these two considerations. By its nature, no single cycle can make both improvements to an equal extent. It thus seems reasonable to combine two cycles: one with high process temperatures, and the other with a good cold end. In an open-cycle gas turbine, the process temperatures attainable are very high because its energy is supplied directly to the cycle without heat exchangers. The exhaust heat temperature, however, is also quite high. In the stearn cycle, the maximum process temperature is not very high, but the exhaust heat is returned to the environment on the cold end at a very low temperature. Combining a gas turbine and a stearn turbine thus offers the best possible basis for a high-efficiency thermal process (Table 2-1). The last line in the table shows the "Carnot efficiencies" of the various processes, i.e., the efficiencies that would be attainable if the processes took place without internal exergetic losses. Although that naturally is not the case, this figure can be used as an indicator of the quality of a thermal process. The value shown makes clear just how interesting the combined-cycle power plant is when compared to the single-cycle processes. Even a sophisticated installation such as a reheat stearn turbine power plant has a theroretical Carnot efficiency 10 to 15 points lower
that of a combined-cycle plant. On the other hand, the exlosses in the combined cycle are higher because the tem""''''hu·'''' differential for exchanging heat between the exhausts gas turbine and the water/stearn cycle is relatively great. clear why the differences between the actual efficiattained by a combined-cycle power plant and the other are not quite that large. by Fig. 2-1, which compares the temperature/entropy of the four processes, the combined cycle best utilizes e.IrLPe~ra·tUl:e differential in the heat supplied, even though an additional exergetic loss between the gas and the "h,"OU1''''''
Thermodynamic Comparison of Gas Turbine, Stearn Turbine, and Combined-Cycle Power Plants Gas
Turbine
Steam Power Plant without with Reheat Reheat
CombinedCycle Power Plant
950-1000 (1250 -1340)
640-700 (690-800)
550-630 (530- 675)
950-1000 (1250 -1340)
500-550 (440-530)
320-350 (115 -170)
320-350 (115 -170)
320-350 (115-170)
42-47
45-54
37-50
63-68
8 COMBINED CYCl..E GAS & STEAM TURBINE POWER PLANTS
THERMODYNAMIC PRINCIPLES Of THE COMBINED-CYCLE PLANT 9
2.2 Thermal Efficiency of the Combined-Cycle Plant
Figure 2-1
It was assumed in Section 2.1 that fuel energy is being sup-
plied only in the gas turbine. There are, however, also combinedcycle installations with additional firing in the stearn generator, Le., in which a portion of the heat is supplied directly to the stearn process.
B
A 1320K
800K
Accordingly, the general definition of the thermal efficiency a combined-cycle plant is:
+ PST . 0;T + QsF
_ PGT 17K - .
is no ~upplementary firing in the waste heat boiler supplied QSF = 0), this formula simplifies into:
ENTROPY
_ PGT +
17K -
o
(
(2)
1320K
PST
(3)
QGT
the general case, the efficiencies of the single cycles can denn.ed as follows: the gas turbine process:
810K 810K
(4)
stearn turbine process:
ENTROPY Fig. 2-1:
Temperature/ Entropy Diagrams
A. B. C. D.
Gas turbine Steam turbine without reheat Reheat steam turbine Combined-cycle gas turbine/steam turbine power plant
PST
(5)
QSF + QExh
(6)
~ QGT (1 - l1GT)
THERMODYNAMIC PRINCIPLES Of THE COMBINED-CYCLE PLANT 11
10 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Since the second term of the inequality is equal to K, the inequality reduces to:
Combining these two equations yields:
=.
TJsr
QSF
(7)
.
+ QGT (1 - llGT)
2.2.1 The Effect of Additional Firing in the Waste Heat Boiler on Overall Efficiency Substituting Equations (4) and (7) into Equation (2), one obtains:
TJGT Q<;T TJK
+ TJsr (QSF + Q<;T [1 -
=
TJGT])
(8)
Q<;T + .!2sF
Additional firing in the waste heat boiler improves the overall efficiency of the combined-cycle installation whenever:
o TJK > 0
(9)
o .!2sF
Differentiation of Equation (8) produces the inequality:
o ~K =. 1. 2 oQSF (QGT + QSF)
{
TJGT . QGT ( 0 ~ST 0 QsF
QsF
+ TJST)
.' . [ 0 TJ ST i l (1 )] . (QGT + QSf) - TJST QsF + 0 QSF ~GT TJGT' . (QGT + .!2sF) - TJ Sf QGT (1 - TJGT)}
()
[.!2sF + QGT (1- TJGT)] + TJST>
>
TJGT Q<;T
(11)
+ TJST [.!2sF + QGT (1 .' QGT + QsF
TJGT)]
(12)
. . The term [QSF + QGT (1- lIGT)] is none other than the heat put to the steam cycle. The formula thus becomes:
o ~ST oQSF
. PST> TJK TJST
TJST
(13)
quation (13) means that increasing the additional firing imyes the efficiency of the combined-cycle plant only if it imyes the efficiency of the steam process. The greater the ~~rence is between the efficiencies of the combined-cycle and ~team process, and the lower the temperature is of the heat t to the steam process, the more effective that improve~. will be. For that reason, additional firing is becoming less ess interesting: the efficiency of the combined-cycle instalincreases far more rapidly than that of the steam process, ~",.u.I"GU.1Y increasing the difference (lIK - liST). In view of the ~l(1€~ral;lOIls in Section 2.1, it is generally better to burn the a modern gas turbine, because the heat is supplied to :>ro1ce!,s at a temperature level higher than that in the steam
pr<)blemlS involved in combined-cycle installations with firing are discussed in more detail in Section 3.2 below.
>0
OQsF
TJST
10
This yields:
o ~ST
TJsr' . ooQSF [QsF + QcT (1- TJGT)] > TJK -
Hl:I(MIUV'rl'llAfI,IJIL
12 COMBINED CYCLE CAS & STEAM TURBINE POWER PLANTS
2.2.2 Efficiency of Combined-Cycle Plants without Additional Firing in the Waste Heat Boiler Without additional firing, Equation (8) can be written as follows: (14)
17K
=
TJGT' QGT
+ TJ~T
. QGT (1 - TJGT)
=
TJGT
+
1+
a TJ5T a TJGT
dnST
(1 -
TJGT) -
TJST
(15)
Increasing the gas turbine efficiency improves the overall efficiency only if:
a TJK > 0 a TJGT
(16)
From Equation (15) one obtains:
_ dnsT dnGT
<
1 - TJST 1 - TJST
2-2: Allowable Reduction in Steam Process Efficiency as a Function of Gas Turbine Efficiency (Steam process efficiency = 0.25)
TlOT
Differentiation makes it possible to estimate the effect that a change in efficiency of the gas turbine has on overall efficiency: =
13
0.2
0.3
0.4
0.94
1.07
1.25
TJST (1 - TJGT)
QGT
a TJK a TJGT
PRINCIPLES Of THE COMBINED-CYCLE PLANT
(17)
Improving the gas turbine efficiency is helpful only if it does not cause too great a drop in the efficiency of the steam process. · dnST Table 2-2 shows the maximum allowa ble re d uctlOn- - as a function of the gas turbine efficiency. dnOT This table indicates that the higher the efficiency of the gas turbine, the greater may be the reduction in efficiency of the steam process. The proportion of the overall output being provided by the gas turbine increases, reducing the effect of lower
dnOT ellcy in the steam cycle. But a gas turbine with a maxi~fficiency still does not provide an optimum combinedpHmt. For example- with a constant turbine inlet rature- a gas turbine with a very high pressure ratio atpigher efficiency that a machine with a moderate pres'0. However, the efficiency of the combined-cycle plant second machine is significantly better because the steam pat follows operates far more efficiently with the higher p\gas temperature and produces a greater output. ".2a shows the efficiency of the gas turbine alone as a of the turbine inlet and exhaust temperatures. The maxficiency is reached when the exhaust gas temperatures ~\low. (A low exhaust temperature means a high presiO,)
?h shows the overall efficiency of the combined-cycle e way. Compared to Fig. 2-2a, the optimum point has ""ard higher exhaust temperatures from the gas turto economical considerations, present-day gas turbines llY optimized with respect not to efficiency but to maxe.r density. Fortunately, this optimum coincides fairly ""ith the optimum efficiency of the combined-cycle result- most of today's gas turbines are optimally ombined-cycle installations.
14
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
THERMODYNAMIC PRINCIPLES Of THE COMBINED -CYCiE PLANT •
15
FIgure 2-2 Gas turbines of a more complicated design, Le., with intermediate cooling in the compressor or recuperator, are less suitable for combined cycles. They normally have low exhaust gas temperatures, so that the efficiency of the stearn turbine can only be low. We shall not discuss a reheat gas turbine here since this type of machine has disappeared from the market due to
40 0;0
'1
35
a
30
its complexity. In summary, it may be said that:
25 300
The gas turbine with the highest efficiency does not necessarily produce the best overall efficiency of the combined-cycle plant. The turbine inlet temperature is a far more important fac-
350
400
450
500 OC 550
t2
tor. Similar considerations also apply with regard to the efficiency of the stearn cycle. These, however,are less important because the gas turbine is generally the "standard machine." The exhaust heat available for the stearn process is thuS a given, and the problem lies only in its maximum conversion into mechanical energy (refer on this point to Section 2.3.)
1-t-+~~:::::::L-1100 1000
45
00
b
40 300 350
400
450 t2
500 550 0 ( 600
Efficiency of Gas Turbines in . of the Turbine Inlet and Exhaust GComTbmed.Cycle as emperatures Plants as a alone
efficiency
Chapter 3
SYSTEM LAYOUTS pn)blem in laying out a combined-cycle plant is makuse of the exhaust heat from the gas turbine in boiler. This heat transfer between the "topping" 'b()tt()miing , cycle entails losses (see Section 2). Heat not optimum, either energetically or is limited by three factors: nhvsical
prc)p(~rt:les of
ex,erf~etic
the water and exhaust gaand energetic losses.
eXlch~:mf~er
cannot be infinitely large.
temperature corrosion that can occur at the heat exchanger limits how far the exhaust cooled. first of these considerations that limits thermooptinlUJm utilization of the thermal energy. Fig. 3-1 in temperature that would occur in an "ideal" infinite size, operating without exergy loss. flow times specific heat capacity, must be any given point in order to make such
mc~dlla at
temperature changes in a waste heat boiler RmlO"\irpcl from this' 'ideal heat exchange." Because a constant temperature, a boiler can never eXlchcmg:er." Even with an infinitely large heat exergetic losses can never be equal to zero.
17
18
SYSTEM LAYOUTS
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
In addition to this physical limitation, there is also a chemicallimitation on energetic use of the exhaust gases imposed by low temperature corrosion. This corrosion, caused by sulphur, occurs whenever the exhaust gases are cooled below a certain temperature, the sulphuric acid dewpoint. In a waste heat boiler, the heat transfer on the flue gas side is not as good as on the stearn or water side. For that reason, the surface temperature of the pipes on the flue gas side is approximately the same as the water or stearn temperature. If these pipes are to be protected against an attack of low temperature corrosion, the feedwater temperature must remain approximately as high as the acid dewpoint. Thus, a high stack temperature for the flue gases does no good if the temperature of the feedwater is too low (refer also to Section 5.2). Low temperature corrosion can occur even when burning fuels containing no sulphur if the temperature drops below the water dewpoint.
Combined-cycle plants without additional firing often are made of sever~l gas turbines and waste heat boilers that supply to a smgle stearn turbine. In the following, we generally only of one gas turbine and one waste heat boiler, but la~IOllts can also be adapted for several gas turbines. Because sinlpl1est system is typical of all, it has been discussed more and the other possibilities have then been derived from
",,,,,,Ul.Ll
""",."(1,J..I.,
Single-Pressure System arrangement for a combined-cycle plant is a singlesystem (Fig. 3-3) without special equipment added. This of one or more gas turbines with a single-pressure waste ""Allor a condensing stearn turbine, a water- or air-cooled and a single-stage feedwater preheater in the deThe stearn for the deaerator is tapped from the stearn
3.1 Combined-Cycle Plants without Additional Firing
heat boiler consists of three parts:
In combined-cycle plants without additional firing, all the fuel is burned in the gas turbine. The stearn turbine then utilizes the exhaust heat from the gas turbine, with no additional source of thermal energy. This type of combined-cycle plant is already in widespread use because it is simple and inexpensive and high efficiencies can be attained with modern gas turbines.
preheater (economizer), which is by the flue gases;
The number of systems possible for the steam process in such combined-cycle plants is quite large because attempts have made to improve the quality of the heat exchange between flue gas and the water or stearn by using complex systems. has led to systems that utilize the exhaust heat well both getically and energetically.
19
and
!yakpOlra-tor used can either have forced circulation (as natUJral circulation. Si]rt~],e-]Prl~ssiure System
the heat balance in a typical single-pressure plant having a 70 MW gas turbine. The exhaust generator approx. 35 kg/s (277,200 lb/hr) stearn and 475°C (887 OF). That stearn then drives with an output of 35 MW. Because of the good
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
20
SYSTEM LA YOUTS 21
Figure 3-1
L1 t = CONSTANT I.1.J
0:::: ;::)
EXHAUST GAS
I-
«
0::::
EVAPORATOR
I.1.J
Cl..
L I.1.J
I-
ECONOMIZER
HEAT TRANSFER Fig. 3-1:
TemperatureIHeat Diagram: Ideal Heat Exchange
HEAT TRANSFER Temlperlltur,elH€,at Diagram: Heat Exchange in a Waste Heat Boiler
22
SYSTEM LA YOUTS 23
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Figure 3-3
3:
L
-'t
.vi
<0
-.i
m
a-
N
10
Fig. 3-3: 1 2 3 4 5
Flow diagram of the single-pressure system
Compressor Gas turbine Bypass stack Superheater Evaporator
6 7 8 9 10
Economizer Boiler drum Steam turbine Condenser Steam bypass
11 12 13
Feedwater tank:! deaerator Foodwater pump Condensate pump
(; .0
E
..... .....
"..>c:
a. '<::I
~ ~~
24
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
river-water cooling system, pressure in the condenser is 0.04 bar (0.58 psia), resulting in a gross efficiency of the installation of 45% (Table 3-1, page 30). Noteworthy is the poor energetic utilization of the exhaust heat from the gas turbine. Together with the relatively low live steam data, this produces a fairly modest efficiency in the steam process. Fig. 3-5 shows the energy flow. 45% of the thermal energy supplied is converted into electrical energy. The rest is removed in the condenser (28.3%) or through the stack (25.2%) or is lost elsewhere (1.5%). Fig. 3-6 shows the exergy now of the same plant. The heat that has to be removed in the condenser is only about half that of a conventional steam power plant of the same size. One significant difference between a conventional steam plant and the steam process in a combined-cycle plant lies in the feedwater preheating. A conventional steam plant attains a better efficiency if the temperature of the feed-water is hn)UI:fht to a high level by means of multi-stage preheating. In a bined-cycle power plant, however, the boiler feedwater be as cold as possible, with the limit determined by low perature corrosion: the temperature of the water must not significantly below the dewpoint for sulphuric acid. There two reasons for this difference: • Normally, a conventional steam generator is equipped with a regenerative air preheater that can further utilize the energy remaining in the flue gases after the economizer. There is nothing like that in a waste heat boiler, so that the energy remaining in the exhaust gases after the economizer is lost.
SYSTEM LA YOUTS 25
shown in Fig. 3-7, the smallest temperature differbetwe~n the water and the exhaust gases in the IS on the warmer end of the heat exThat means: the amount of steam production })ossilble does not ~epend on the feedwater temperaIn a conventIOnal steam ge~erator, on the other the smallest temperature dIfference is on the end of. the econ~mizer because the water flow larger In proportIOn to the flue gas flow. As a the amount of steam production possible deon the feedwater temperature. two examples of conventional steam generators feed-water temperatures. It is obvious that with in temperature at the end of the econoavailable for evaporation and superheating is where the feedwater temperature is higharrlOlmt of live steam produced by a conventional In(:re:ase:d by raising the feedwater temperature. of Ambient Conditions Efficiency
here only the effect that different ambient the design point for the installation. How gllm;ens:ioIlled combined-cycle plant behaves will be ::>e.(~tioJll 7, Operating and Part-Load Behavior. Those valid, however, only for the steam turbine remains the same in all cases. Gas turbines ~ta]ld~lrdize:d Le., one given machine is used even ambient conditions. This can be justified a gas turbine that has been optimized for of 15°C (59°F) does not look significantly has been designed for, say, 40°C (104°F). te,rellopi.ng a new machine would thus not be
26
SYSTEM LA YOUTS 27
COMBINED CYCLE CAS & STEAM TURBINE POWER PLANTS
Figure 3-5
E
0-
100%
100 %
0,3%<1--V4 0,2%<1--V3
Ek
V5
GT
30,1 %
33,1% V5 V4
25,2
14,9 %
V6 V1
3,5%
28,3% Fig. 3-5:
Q VI V2 V3 V4 V5 V6 GT ST
V1 1,4%
Energy Flow Diagram for the Single-Pressure Combined-Cycle Plant
Energy input Loss in condenser Loss in stack Loss due to radiation in waste heat boiler Loss in flue gas bypass Loss in generator and radiation, gas turbine Loss in generator and radiation, steam turbine Electricity produced in the gas turbine Electricity produced in the steam turbine
Diagram of the Single-Pressure Combined-Cycle Plant
turbine the gas turbine the steam turbine to the waste heat boiler
prc,dw~ed in prc,dw~ed in
SYSTEM LA YOUTS 29
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
28
Figure 3-7 600,-----------------------,
w a::
:::> t-
«
a:: w
0... ~ W
t-
200
ECONOMIZER
FLUE GAS
10
o o
50
100
150
HEAT TRANSFER Fig. 3-7:
TemperaturelHeat Diagram of the Single-Pressure Boiler with a Pin point of l.5°C (27°F)
70
80
90
HEAT TRANSFER rat\lre/He:at Diagram of a Conventional Steam Generator Available for Evaporation and Superheater of heat supplied (Ql) 79% of heat supplied (Q2) = 63bar = 485 °C
100
SYSTEM LA YOUTS 31
30 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Table 3-1: Main Technical Data of the Single-Pressure Combined-Cycle Plant Gas turbine output Steam turbine output Station service power required Net power output of plant Thermal energy supplied (Diesel fuel) Efficiency of gas turbine Heat contained in exhaust gases lJtilization rate for waste heat energy* Efficiency of the steam process Gross efficiency of the plant Net efficiency of the plant
68600 34000 1 100
kW kW kW
101 500 228000 30.1
kW kW %
157000 63.3 21.7 45.0 44.5
kW % % % %
* 100% utilization if the exhaust gases are cooled down to 15°C (59 OF).
The situation is different on the stearn end of the stearn turbine. The exhaust stearn section designed for a condenser pressure of, say, 0.2 bar (2.9 psia) can no longer function if the pressure is only 0.04 bar (0.58 psia).
Increasing the air temperature reduces the density of the air, and thereby reduces the air mass flow drawn in. n01.IITI'·r consumed by the compressor increases in nrt-.nrwtiion to the intake temperature (in K), without being a corresponding increase in the output the turbine. tl€:ca.use the absorption capacity of the turbine reconstant, the pressure before the turbine is reQUCe(l, since the mass flow decreases as the air t~l:np,eratllre rises. This again reduces the pressure rathe turbine. The same principle applies inof course, to the compressor, but because its less than than of the turbine, the total balnegative. U""'Ull':>
this change in a temperature/entropy diagram. that the exhaust gas temperature becomes higher telup,enatllre increases. This is because the turbine presre,duced while the inlet temperature remains conhl"h!:luir,r of the exhaust gas temperature explains that the air temperature has on the efficiency plant differs from that which it has on the gas turbine alone. the relative efficiencies of the gas turbine and l--C'\,Cle plant as a function of the air temperature, cC)llclitiloflS remaining otherwise unchanged. As it in the air temperature even has a slightly efficiency of the combined-cycle plant, teluper::ttulre in the gas turbine exhaust raithe stearn process (Fig. 3-11) enough to more the reduced efficiency of the gas turbine
"rllnJ\,,,,
The design of the combined-cycle plant is affected mainly the air temperature, air pressure, and cooling water ture. The relative humidity is important only if the water cooling the condenser is recooled in a wet cooling tower. Air Temperature There are three reasons why the air temperature has a influence on the power output and efficiency of an gas turbine:
surprising when one remembers the Car.11ation (1)]. The rise in the final temperature
COMBINED CYCLE CAS & STEAM TURBINE POWER PLANTS
32
SYSTEM LA YOUTS 33
Figure 3-9
3
3' /\
\
\ \
\ \ \
W 0::
::::> t
:COMBINED -CYCLE /
~I
0::
./ 4
w
a.. :L w t-
",/
/
",/ ,,/"
/'
/""
1
ENTROPY LOWER AIR TEMPERATURE --Fig. 3-9: 1-2 2-3 3-4
o
+10
+20
30
40
50
O(
AIR TEMPERATURE
HIGHER AIR TEMPERATURE
TemperaturelEntropy Diagram for a Gas Turbine at Two Different Temperatures
= Compressor = Combustion chamber = Turbine
.l!itllcie'ncy of Gas Turbines and Combined-Cycle Plants as a Air TelnpE'rature
34 COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
Figure 3-11
JIlpression causes a slight increase in the average temperof the heat supplied TWas well. Because most of the exheat is carried off in the condenser, the cold temperature nges only insignificantly. The overall efficiency of the ~d-cycle plant is thus more likely to increase. This bepplies only if the temperature of the water cooling the 1.ltbine condenser remains unchanged. With a cooling an air-cooled condenser, the efficiency of the stearn hanges because the condenser pressure is now different.
120
115
110 >w
V
z
W l"-. l"-. lLJ
105
/
lLJ
>
t-
«
-' lLJ
0:::
100
V
V
95
~
V
90
-20
-10
/
./
o
-~,_
+
10
+
20
/
2ishows how the overall efficiency of the combinedchanges with the air temperature when the cooling ~ing recooled in a wet cooling tower with a constant fuidity in the air of 60%. Fig. 3-13 shows the same r the case with direct air-cooled condensation.
/
lLJ
SYSTEM LA YOUTS 35
r output from the combined-cycle plant reacts quite ~rom its efficiency. Here the reduced flows of air tgases playa more important role than the exhaust ttlre. ..
It()ws how the power outputs of the gas turbine and (i-cycle plant change depending on the air temperl"op-off at higher temperatures is less pronounced ined-cycle plant than for the gas turbine alone.
~,-",._,~-
30
40
50
AIR TEMPERA TURE Fig. 3-11: Relative Efficiency of the Steam Process in Combined-Cycle Plants Function of the Air Temperature Cooling water temperature 20°C (68°F)
eand Site Elevation are normally designed for an air pressure of 1.013 ,iiwhich corresponds approximately to the averrevailing at sea level. A different site elevations ferent average air pressure (Fig. 3-15). <:lfthe air pressure on the efficiency of a gas tur()zero if the temperatures remain unchanged. On
36
SYSTEM LA YOUTS 37
COMBINED CYCLE CAS & STEAM TURBINE POWER PLANTS
the other hand, the power output changes with the air mass flow taken in, which varies in proportion to the intake pressure and thereby also affects the flow of exhaust gas. The exhaust heat available for the stearn process likewise varies in proportion to the air pressure. If one assumes that no change takes place in the efficiency of the stearn process, which corresponds quite well to the real situation, this then causes a similar variation in the power output from the stearn turbine. Because the power outputs of the gas turbine and the stearn turbine vary in proportion to the air pressure, the total power output of the combined-cycle plant varies correspondingly. The efficiency of the plant remains constant, however, since both the thermal energy supplied and the air flow are varying in proportion to the air pressure. Cooling media for the Condenser To condense the stearn, a cooling medium must be used to carry off the waste heat from the condenser. Generally this is water, which has a high specific thermal capacity and good heat transfer properties. Where water is in short supply, cooling can be done in air in a wet cooling tower; where no water is available, an air-cooled condenser or a dry cooling tower are necessary. The temperature of the cooling medium affects the efficiency of the thermal process. The lower that temperature is, the higher the efficiency that can be attained [refer to Equation (1)]. A lower temperature makes possible a lower pressure in the condenser, producing a greater useful enthalpy drop in the stearn turbine. Fig. 3-16 contains typical approximate values for condense pressure as a function of the design temperature for the coolin medium. There are three different cases:
o
+10
+20
30
40
AIR TEMPERATURE Temperature on the Efficiency of Combined-Cycle Plants with Tower Humi,:lity of Air 60%
SYSTEM LA YOUTS 39
38 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Figure 3-13 104
102
-
-~
"'"
100
>w
Z
w
W 98
~
~
I.L. I.L. W
~ 96
'"~
I<:( ....J W
j
'~
COMBINED CYCLE PLANT
a: 94
92 -20
-10
o
+10
+20
30
40
AIR TEMPERATURE
GAS TURBINE
Fig. 3-13: Effect of the Air Temperature on the Efficiency of Combined-Cycle with Direct Air-Cooled Condensation
o
+10
+20
30
40
50°C
AIR TEMPERATURE Output and Efficiency of Gas Turbines and CombinedFunctions of Air Temperature temperature 20°C (68°F)
SYSTEM LA YOUTS
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
40
Figure 3-16
Figure 3-15
100
~
w 0:::
:::>
90
0,4 ,--~r---'----'---"'----'-----'---""" bar
I~
- - - - FRESH WATER COOLING to-..
'" "" '""~
L:.J
0::: 0-
~
0:::
>
....J L:.J
- - DIRECT AIR CONDENSATION - - - WET COOLING TOWER
V) V)
I
41
80
0:::
70
o
400
800
1200
1600
/ /
/
2000
ELEVATION ABOVE SEA LEV El Fig. 3-15: Standard air pressure as a function of elevation 100% = 1.013 bar (14.7 psia)
o
10
20
30
40°C
50
TEMPERATURE OF THE COOLING MEDIUM Values for Selecting the Condenser Pressure for Fresh Water . Tower, and Direct Air Condensation (Air for cooling air-cooled condensation)
42
SYSTEM LA YOUTS 43
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
• direct water cooling • water cooling, with water recooled in a wet cooling tower • direct air cooling The greatest vacuums are attained with direct water cooling, the least with direct condensation with air. In the comparison, it must also be borne in mind that the water temperature is generally lower than that of the air. For the wet cooling tower, a relative air humidity of 60% has been assumed. The Effect of the Most Important Design Parameters on Power Output and Efficiency When dimensioning a combined-cycle plant, the gas design is generally a given, since the gas turbine is a st3cnetardized machine. The free parameters for the design involve the steam nnoc(~ss. and it is mainly these that are discussed below. One must forget, however, that the output of the steam turbine is approx. 30 to 40% of the total power output. Optimization the steam process can therefore only influence that Another important point: The efficiency of the steam is always proportional to the output of the steam turbine, in a plant without additional firing, the thermal energy suppli~' to the steam process is a given. Live Steam Data The selection of the live steam data for a combined-cycle with a single-pressure system is a compromise between op mum energetic and optimum exergetic utilization of the exh heat from the gas turbine. The main determining factor is live steam pressure selected.
Steam Pressure a combined-cycle plant, a high live steam pressure does not nece~;sa:nlJ mean a high efficiency. Fig. 3-17 shows how the efl¢IEm<:y of the steam process depends on the live steam presis striking that the best efficiency is attained even while steam pressure is quite low. pressure does indeed bring an increased efficiency WClttelr/s1;eam cycle due to the greater enthalpy gradient ttlJrbine. The rate of waste heat energy utilization in the however, drops off sharply. The overall effici:SL\~,U,Ll process is the product of the rate of energy the efficiency of the water/steam cycle. There urn at approx. 30 bar (435 psia). eXplains the increased rate of energy utilization in eat boiler: the temperature/heat diagrams are for les with live steam pressures of 15 and 60 bar (203 spectively. At the lower live steam pressure, there aFenergy available for evaporation and superthe evaporation temperature is correspondingly ch point of the evaporator is the same in both surface area of the heat exchanger is therefore As a result, the stack temperature at 15 bar is OF) lower than at 60 bar, which means that the :rgyis being better utilized. til1e.live steam pressure also greatly affects the 1;(jbe removed in the condenser (Fig. 3-19). The teases when pressures are lower since a greater being removed from the exhaust gases and ctricity at a lower efficiency. 'derations can thus make it advisable to raise reabove the thermodynamic optimum. This (jwing advantages:
44
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
• a reduction in the exhaust steam flow, or, if the of the steam turbine remains unchanged, smaller exhaust losses. • a smaller condenser • a reduction of the cooling water requirement Especially in the case of power plants with expensive air-co condensers, this can mean considerably lower costs. Live steam flows greater than that in the example shown the optimum toward higher live steam pressures, since ume flows also are larger. The live steam pressure se.Lectel thus less important for larger steam turbines than for s. installations. For that reason, it is advantageous in larger combined-cycle plants with several gas turbines to select steam pressure that is above the optimum. The reduced flow that results makes it possible to employ piping and with smaller dimensions. The trend is the opposite when of live steam is reduced. The optimum live steam nres~mI'(~ depends on the total amount of live steam: increasing the improves efficiency in the high pressure section of the turbine. With a larger volume flow, longer blades are in the first row, which reduces the edging losses. Live Steam Temperature In contrast to the live steam pressure, raising the live temperature always brings with it a slight increase in (Fig. 3-20). There are two reasons for this impf()v(~ment increased superheating:
• improved thermodynamics of the cycle, • increased steam turbine efficiency due to wetness in the low pressure section.
re(lU(~ed
SYSTEM LA YOUTS 45
an improved efficiency of the water/steam cycle compensates for the slight drop in the rate of rgy utilization. Moreover, for the steam turbine, live steam temperature means less erosion in the cause of the reduced water content in the steam). lire of the gas turbine exhaust gas provides the the live steam temperature. However, a suffiin temperature is necessary between the exhe live steam in order to limit the size of the reover, too high a live steam temperature can roportionate increase in plant costs since a great Ilsive material is required for the piping, the suthe steam turbine. In most cases, however, the perature sets the limit for the live steam tem-
ill a good rate of waste heat energy utilization, .of the feedwater should be kept as low as posadynamic quality of the water/steam cycle reaffected (Fig. 3-21). given in Section 3.1.1, preheating has been ¢stage: the feedwater tankldeaerator. A multiwould improve the efficiency but it has not here because the solutions shown in Sections clearly better. Dividing preheating into sevtimprove the rate of energy utilization in this llre system, which is the greatest disadvantage ~~m. Even with minimum feedwater tempertemperature remains at approx. 200°C (392 ~st energy can be recovered by improving the fer to Sections 3.2 and 3.3).
46
COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
SYSTEM LA YOUTS 47
Figure 3-17 35 --,------r---,--,------r---,-----r70
22 %
STEAM PRESSURE 15 bar
-
STEAM PRESSURE
~WS
60 bar
.........
,
-~---,
34
21
'1ws '1ST
/
/
/ /
1
1_
/ .
-----~
\
/
-TI
33
I!
50
1
i
I
I
"at1;Lre/He,at Diagram of a Single-Pressure Boiler with Live Steam and 60 bar (203 and 855 psig) Respectively
20
30
50
60
70
Fig. 3-17: Effect of the Live Steam Pressure on the Efficiency of the Steam the Rate of Waste Heat Energy Utilization Tlws TlST TlWB
Frs
150 MW
1
32..L--1---+----+---+---+----t--~:>·:>
10
100
HEAT TRANSFER
I I 19
\
TJWB
I 20
I
1---4----
Efficiency of the water/steam cycle Efficiency Of the steam process Rate of Waste Heat Energy Utilization Live steam pressure at the turbine inlet
48
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS SYSTEM LA YOUTS
49
Figure 3-19 115
110
1\\
105
----,------,-----75 %
1\ \
100
:;:;----+-------170
~
""
w
""
95
'lWB
~
90
-------1----+~~--::~~65
~
'lWB_----
~
85
10
20
30
50
60
70
Fig. 3-19: Effect of the Live Steam Pressure on the Waste Heat from a Cond()fis,er Live steam temperature 475°C (875°F) Condenser pressure 0.04 bar (0.58 psia) Live steam pressure Waste heat from condenser
0--+-------1--------1 60 450
400
O(
350
Steam Temperature on the Efficiency of the St p te Heat Energy Utilization earn rocess m.pl~rat;Ur€ at the Turbine Inlet
COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
50
SYSTEM LA YOUTS 51 ndlen~~er
Figure 3-21
23
35--,------,.---r---r----, 80
0/0
°/0
Pressure
condenser pressure has a major influence on the efficithe steam process because the enthalpy drop in the steam \.;1l,(U1j5C:'" sharply (Fig. 3-22). An increase in the pressure decrease in power output. However, plant costs are due to the lower volume flow of exhaust steam and the reduced size of the steam turbine and condenser. of the Waste Heat Boiler parameter in the optimization of a steam cycle ;IpE~ratUl~e difference rating (the "pinch point") of the which affects the amount of steam generated 3-7). By reducing the pinch point, the rate of enin the waste heat boiler can be influenced within However, the surface of the heat exchanger inwhich quickly sets a limit for the utiliza-
"'....l'·t.:ll't
22
"1ST 'lsw
21
'lws
33 -~"-or;:-~f_-_+_--_r_--V 6 5 waste heat boiler should be such that the flue-gas side remains as low as possible. This the power output and efficiency of the gas the pressure ratio in the turbine. In presentloss is approximately 0.8% for each 1% the lost output is recovered in the steam ltXll mlUm rate of recovery is 35 %.
"~B
"-. .
20
2--+---+-----ir-----j----r 100
110
120
130
140
t FW Fig. 3-21: Efl'rect of the Feedwater Temperature trw on the Efficiency of Process and Rate of Waste Heat Energy Utilization
ttw
= Feedwater Temperature (Other terms as in Fig. 3-17J
Temperature of the gas turbine exhaust gas is imthe steam cycle. If the turbine inlet COll1st;ant, a gas turbine with a higher exa poorer overall efficiency produces assuming identical compressor and also to Fig. 2-2).
~lPll{,V of
52
SYSTEM LA YOUTS
COMBINED CYCLE GAS &. STEAM TURBINE POWER PLANTS
53
When the gas turbine exhaust temperature is lowered, the thermodynamic quality of the stearn process and the en utilization rate of the waste heat boiler deteriorate (Fig. 3 When evaluating the suitability of a gas turbine for a comhi cycle process then, consideration must be given not only efficiency but also to its exhaust gas temperature.
3.1.2 Single-Pressure System with a Preheatin Loop in the Waste Heat Boiler The major disadvantage of the single-pressure system (Se 3.1.1) is its relatively poor rate at which it utilizes waste energy. The easiest improvement is to use an additional exchanger at the end of the waste heat boiler to recover tional heat for preheating the feedwater. This preheatin must be designed so that temperatures do not drop bela acid dewpoint. It is therefore not possible to send the co sate directly into the boiler. There are two ways to solve this problem: with water a stearn. Fig. 3-25 shows the version using water, in which a is used to bring a large amount of water to a high pressure There must be more water than condensate: too great a. perature rise due to the heat transfer would cause temper to drop below the dewpoint. After being warmed up in t heating loop, the water flows into a flash tank that pro the stearn required for the deaerator. The remainder is ret directly to the feedwater tank. The main disadvantage layout is the great amount of power required to drive t culating pump, since the water must be pressurized to a. 20 bar (290 psi). Fig. 3-26 shows a version in which a low pressure eva generates saturated stearn for the deaerator. In this c power required to drive the pump is quite small, anlorclXiJ
0,15
q.25
0,3 bar
Pc Pressure on the Efficiency of the Steam Process
54
SYSTEM LA YOUTS 55
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Figure 3-23 ....... t . U - - - , . - - - - - - - - . . - - - . . - , - - - - -
80 %
o
5
15
10
r Fig. 3-23: Effect of the Pinch Point of the Waste Heat Boiler on the Eflici
SE T
""'""'+----1----+-----+.50
600
O(
Efficiency of the Steam Process Heat Transfer Pinch Point Process and Rate of Waste Heat Energy Utilization Turbine Exhaust Gas Temperature 'at€~rlslteaJm cycle
SYSTEM LA YOUTS
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
56
57
Figure 3-25
10
Diagram of the Single-Pressure System with a Low I!}vap()rator as a Preheating Loop Fig. 3-25: Simplified Flow Diagram of the Single-Pressure System with Flash as a Preheating Loop 1 2 3 4 5 6 7 8
Compressor Gas turbine Flue gas bypass (optional) Superheater Evaporator Economizer Boiler drum (high pressure) Steam turbine
9 10 11 12 13 14 15 16
Condenser Steam bypass (high pressure) Feedwater tank, de aerator Feed pump (high pressure) Condensate pump Preheating loop (flash system) Booster pumps Flash tank
10 11 12 13 14 15 16 17
Steam bypass (high pressure) Feedwater tank, deaerator Feed pump (high pressure) Condensate pump Preheating loop (low pressure evaporator) Feed pump (low pressure) Boiler drum (low pressure) (optional) Steam bypass (low pressure)
58
SYSTEM LA YOUTS 59
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
10% of that required for the version using water. The evapor ator itself can be of the natural circulation or the forced circul tion type. In this second design, it is sometimes possible to avoid a arate low pressure drum. The feedwater tank then functio as a low-pressure drum, resulting in a simple system since feed pumps or drum level controls are required. However, cause of the two-phase flow, special care must be taken wh designing the piping and the introduction of the water/ste mixture into the feed-water tank. Example of a Single-Pressure Combined-Cycle Plant with a Preheating Loop This is shown in Fig. 3-27, using the same gas turbine the example for the simple single-pressure system (Fig. 3 Table 3-3 lists the main technical data of this system w equipped with a low pressure evaporator. Compared to the simple single-pressure system, it attains nificantly higher stearn turbine output, improving overall ciency by 2.5 %. This is because in this case no stearn is ta from the turbine. As a result, the entire live stearn flow ca pand to the condenser pressure. But the larger volume fl exhaust stearn produced is a certain disadvantage since mensions of the stearn turbine exhaust and the CO]lld4,m~;er be larger.
sts, however, is low compared to the improvement in y. This type of system attains a high efficiency, but still uncomplicated and accordingly low in cost. Even if the aiIls very high levels of sulphur, the feedwater can be to sufficiently high a temperature without any reefficiency worth mentioning. shows the temperature/heat diagram for the waste . The exhaust gases are cooled by approximately an o °C (90 OF) in the preheating loop in order to warm sate to 130°C (266 OF). ain Technical Data of the Single-Pressure ombined-Cycle Plant with a Preheating Loop the gas turbine the steam turbine required from the plant
68000 36800 1 200 104000 228000 30.0 157200 72.5 23.4 46.1 45.6
kW kW kW kW kW %
kW % % % %
exhaust gases are cooled down to 15°C (59 OF)
The increase in the amount of heat to be removed condenser is more than proportional to the increase output. The energy utilization rate of the waste heat by about 15% while the power output from the stearn increases only by 8 %, since the additional exhaust heat is at a low temperature level. The rate for converting it chanical energy (exergy) is therefore modest. The
the combined-cycle plant with a pre~o:Xjrnlat4elythe same way as the simple single"e(~tlOn 3.1.2). We will therefore no treat
60
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
separately the various parameters that depend on the envir ment. Fig. 3-29 shows the effects that the temperatures of and the cooling water have on the power output and efficie of the plant as a whole. It is obvious that a rise in air tern ature causes a reduction in power output and a slight impr ment in overall efficiency. On the other hand, a high temperat for the cooling water affects both parameters negatively.
Effect of the Most Important Design Parameters on Power Output and Efficiency The effect of most parameters is similar to that for the si single-pressure system (See Section 3.1.1).
Live Steam Data The effects of live stearn pressure and live steam telmplera1 on the efficiency of the stearn cycle are practically the for a simple single-pressure system. The optimum live uu,J ....~ . . sure is at approximately the same level. Slight shifts higher pressure can result due to a larger exhaust stearn flow. However, installing a preheating loop in the waste imposes a limit on the minimum live steam pressure. As seen from Fig. 3-30, the flue gas temperature after the omizer drops when the live steam pressure falls. Becaus minimum temperature of the water in the boiler is deter by the sulphuric acid dewpoint, the amount of useful h. the preheating loop is reduced correspondingly. If a high feedwater temperature is required, the live pressure selected must not be too low. Otherwise a po the preheating would have to be done in a low pressure
SYSTEM LA YOUTS
61
SYSTEM LA YOUTS
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
62
63
Figure 3-28 600,..---------------------....,
.........---:----r:-:-----r--,-------,---.115
50
GAS UJ
0::
:::> I-
300
POINT
o
LU
0..
a.
:t: UJ
I-
200
ECONOMIZER
100
.......-~--+-------l-+_-~V~"d_--__+90
PREHEATING LOOP
0 0
50
100
.......-
--+-----+-t------"~~~8
5
HEAT TRANSFER Fig. 3-28: TemperaturelHeat Diagram of a Single-Pressure Waste Heat Preheating Loop
o
+
20
30
40
Pinch Point = 15°C (27°F)
Output ani! Efficiency of Combined-Cycle Plants with a as Functions of the Air and Cooling Water Temperatures
SYSTEM LA YOUTS
COMBINED CYCLE CAS & STEAM TURBINE POWER PLANTS
64
65
extraction steam, thereby reducing the efficiency am cycle because a portion of the steam is not expanded enser pressure.
Figure 3-30 24 0 O(
/
23 0
22 n
210
/
Cl LJ W
-
20 0
19 0
18 0
/
/
17 0 10
/ V
/
"'"
/
V
rPreheating this system uses the waste heat in the exhaust gases condensate, the preheating loop must be so dimenit can supply the heat required for the condensate. heat is available for preheating depends on the live reand the feedwater temperature. Because the dife;mperature must at least be at a certain level if the rjs to take place, the exhaust gases can at best be Illperature from 10 to 30°C (18 to 54 OF) above te;mperature. Fig. 3-31 shows how much heat can a. preheating loop with a temperature difference £.15 °C (27 OF).
/
/ 20
30
40
50
60
70
PLS Fig. 3-30: Flue Gas Temperature after the Economizer as a Function of the Pressure Flue gas temperature after economizer Live steam pressure Gas turbine exhaust gas flow Gas turbine exhaust gas temperature Live steam temperature
e steam temperature affects the efficiency (or the power tthe steam process in the same way as in a simple singlesystem.
288.5kg/s 525°C 480°C
ws the heat required to preheat the feedwater fthe condenser pressure and the feedwater temaverage live steam pressure of 30 bar (420 psig). of Fig. 3-31 and 3-32 shows that problems are pre-heating is done in the preheating loop when essure is very low and a high feedwater temfor. These problems occur whenever the fuel levels of sulphur, which raises the acid dewcuums in the condenser, then, it is often nec-yvpressure preheater heated with extraction the amount of heat needed in the feedwater is defuses the problem of the heat output reh.eating loop in the waste heat boiler.
66
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
A low pressure preheater has a negative effect on the process efficiency because less heat is recovered from the e haust gases. However, the reduced wetness and exit losses i the turbine to a large extent compensate for that negative effe Condenser Pressure The effect of the condenser pressure on the efficiency steam process is similar to that in the simple single-pressure tern, but the change in efficiency is somewhat more pronoun because the exhaust steam flow is about 10 to 15% greate Pinch Point of the Waste Heat Boiler The effect that the pinch point of the waste heat on the efficiency of the steam process is similar to that in pIe single-pressure boiler (cL Section 3.1.1). However, a tion of the pinch point affects not only the surface of evaporator and the economizer but also that of the pn~ne~a: loop. There are two reasons for this: • The flue gas temperature after the economizer reducing the amount of heat available for the preheating loop. • The heat required for feedwater heating increases since a greater flow of feed water is needed for creased steam production. The preheating loop has take up more energy. Other Parameters We will not investigate the effects of the other design eters here because they differ only insignificantly in a simple single-pressure system.
3.l.3 Two-Pressure System A single-pressure system with a preheating loop nH)VlllE ter waste heat utilization than a simple single-pressure Nevertheless, that utilization is neither energetically
SYSTEM LA YOUTS 67
optimum. In many cases, the low pressure evaporator no great expense, produce more steam than required t the feedwater and that excess steam could be conto mechanical energy if it were admitted into the turme suitable point. To do this, the steam turbine must steam admissions: one for high pressure, and another essure steam (two-pressure turbine). shows a system of this type, further equipped with ssure pre-heaters. This not only provides better utile waste heat as mentioned above, but also makes modynamic use of the low pressure steam. A larger .f the low pressure steam can flow into the turbine l()w pressure preheater, while the feedwater is bed in the first section using low quality steam. low pressure steam reaches the turbine, it can be ·heated. The thermodynamic advantage of doing ,is minimal because the pressure drop between ine and the drum is increased. This reduces the generated because the saturation temperature sure evaporator is raised. If the water separation ffective enough, the saturated steam can be sent eturbine.
Itl
W-sulphur or sulphur-free fuels, further improveIn becomes possible. When the dewpoint is low l.lst gases can preheat a more or less significant dwater in a low temperature economizer. Fig. a.mple burning sulphur-free natural gas. The ~~eheated far enough in a deaerator so that above the water dewpoint of the exhaust ga)(122 OF). Because this temperature is so low, e~:place in this case under a vacuum. Following rtk/dearator, all the feedwater is heated in a
68
COMBINED CYCLf GAS & STEAM TURBINE POWER PLANTS
SYSTEM LA YOUTS
69
Figure 3-31 30 MW
25
+------If----+---+---+----1--~..-c:--::;;l
20
140 0 (
15
.• ..p."......-:~--+------r---r--, 130 O( 10
5
0+---1---+---+---+----+---+------1 10
20
30
40
50
60
70
Fig. 3-31: Effect of Live Steam Pressure and Feedwater Temperature on Heat in the Preheating Loop Heat output Feedwater temperature Gas turbine exhaust flow Gas turbine exhaust gas temperature Live steam temperature
288.5 kg/s 525°C 480°C
0,1
0,15
0,2
0,25
q3 bar
Pc to Preheat the Feedwater, as a Function of the Condenser Feedwater Temperature
288.5 kg/s 525°C 48()0C 34.9 kg/s
70
Figure 3-34
Figure 3-33
Fig. 3-33: Simplified Flow Diagram for a Two-Pressure System for Fuels Contain Sulphur 1 2 3 4 5 6 7 8 9
SYSTEM LA YOUTS 71
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Compressor Gas turbine Flue gas bypass (optional) High pressure superheater High pressure evaporator High pressure economizer High pressure boiler drum Steam turbine Condenser
10 11 12 13 14 15 16 17
High pressure steam bypass Feedwater tankJdeaerator High pressure feed pump Condensate pump Low pressure feed pump Low pressure evaporator Low pressure boiler drum Low pressure preheater
Flow Diagram for a Two-Pressure System for Sulphur-Free 10 11 12 13 14 15 16 17 lB
High pressure steam bypass Feedwater tankJdeaerator High pressure feed pump Condensate pump Low pressure feed pump Low pressure evaporator Low pressure boiler drum Low pressure economizer Low pressure steam bypass
72
COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
low pressure economizer to approximately the saturation perature of the low pressure stearn. It is then admitted to low pressure drum. Next, a high pressure feed water pump culates the feedwater for the high pressure evaporator from low pressure drum into the high pressure stearn generator. I this case, too, it is possible to supply the low pressure stearn the turbine either as saturated stearn or as slightly superheate stearn. In addition to this system, there are further variants possiM Most of these are not as good thermodynamically, but offer ce: tain operational advantages. One example is shown in Fig. 3-35, where the high pressu and low pressure feed-water are separated directly after the fe water tank. The low pressure economizer shown in Fig. 3-3 therefore divided into a low pressure economizer for the I pressure feedwater and a high pressure economizer for the step in preheating the high pressure feedwater. This system the following advantages: • better availability, since the high pressure portion c~ remain in operation even if either the low pressure pump or the circulating pump fails • fewer problems with steaming out in the low press economizer during part-load operation. On the other hand, a slight reduction of about 5 % in sure stearn generation must be accepted in most cases. Another possibility that operates without vacuum dea is shown in Fig. 3-36. The deaerator here operates at overpressure. To do this, it requires extraction stearn of quality than that in a system with vacuum deaeration. flows within reasonable limits, the condensate is prehe the feed-water in a water-to-water heat exchanger.
SYSTEM LA YOUTS 73
:most of the feedwater preheating is still being accomplished exhaust gas heat. The boiler feed-water temperature must rop below the water dewpoint (if the fuel is sulphur-free) acid dewpoint (if it contains sulphur). disadvantage here is the reduced efficiency resulting from wing higher quality stearn from the turbine. Moreover, ()ndensation pressure is low, it may become necessary de another low pressure pre-heater heated with exstearn in order to reduce wetness at the end of the turt would reduce the power output slightly further.
s of Two-Pressure Combined-Cycle Plants discuss here examples of two typical two-pressure cycle plants, both based on the same gas turbine as single-pressure systems. The first is designed for burnsecond for burning sulphur-free natural gas. :.Two-pressure system for fuels containing sulphur hows the main technical data for this unit. The mafrom the single-pressure system with a preheatin the 3-stage feedwater preheating. Two preheaters heated with extraction stearn reduce stearn required for the deaearator, which supge amount of excess stearn to the low pressure here it produces additional mechanical energy. pressure has been raised to 60 bar (870 psia) in ~the efficiency of the stearn process. Unlike the ystems, this system is not significantly affected of heat utilization in the high pressure portion tiboiler because the heat that is not utilized is ~ilow pressure portion. Table 3-3 (page 83) technical data of this plant.
SYSTEM U YOUTS 75
74 COMBINED CYCl..E GAS & STEAM TURBINE POWER PUNTS
Figure 3-36 Figure 3-35
18
10
System with Feedwater Used to Preheat Condensate Fig. 3-35: Two-Pressure System with Separate Economizer in the Low Range 10 High pressure steam bypass 1 Compressor 11 Feedwater tankldeaerator 2 Gas turbine 12 High pressure feed pump 3 Flue gas bypass (optional) 13 Condensate pump 4 High pressure superheater 14 Low pressure feed pump 5 High pressure evaporator 15 Low pressure evaporator 6 High pressure economizer 16 Low pressure boiler drum 7 High pressure boiler drum 17 Low pressure economizer 8 Steam turbine 18 Low pressure steam bypass 9 Condenser
10 11 12 13 14 15 16 17 18 19
High pressure steam bypass Feedwater tankldeaerator High pressure feed pump Condensate pump Low pressure feed pump Low pressure evaporator Low pressure boiler drum Low pressure economizer Low pressure steam bypass Feedwater preheater
76
SYSTEM LA YOUTS 77
COMBINED CYCLE GAS &. STEAM TURBINE POWER PLANTS
Figure 3-37 bar
I
°C : kgls
93
39,9
e the system has been improved thermodynamically, er output from the stearn turbine is more than 11 % than that from the simple single-pressure system and an3% greater than that in the system with a pre-heating increase in station service power required only paracts from this gain: net efficiency rises to appro xi%. y the entire increase in efficiency over a singleern with a preheating loop is provided by the thermorovements made to the water/stearn cycle. There ernent worth mentioning in the waste heat utilizaamount of heat to be carried off in the condensor rnewhat so that the dimensions of the stearn turand the condenser may perhaps be somewhat
Fig. 3-37: Heat Balance of the Two-Pressure System for Fuels Containing
is significantly more complex than a system with re turbine and is of interest only if the gain in promises sufficient economic gain. ""o-pressure system for sulphur-free fuels ntains no sulphur, the efficiency of the stearn by increasing the rate of waste heat util¢arn generator. Fig. 3-38 shows the heat balance tburning sulphur-free natural gas. The low presat the end of the waste heat stearn generator to cool the exhaust gases down to practically ~cause the feedwater temperature is then only 9F), the two low pressure preheaters in Exger needed. Otherwise, the design is the same. issomewhat greater however because the ex3..uatural gas firing contain more heat. Table sthe main technical data of this plant.
~~ised
78
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Figure 3-38
SYSTEM LA YOUTS 79 'l'I1,or'o
are two reasons why the efficiency is better than that 1:
Burning natural gas increases efficiency (approx. 40% of the improvement)
~ ·c Ikg/s
Bett€!r utilization of the waste heat (approx. 60% of improvement)
11i1<' 30 mbar 33 138 10,0
'lKl,47,9% PKI' 110,2 HW
Fig. 3-38: Heat Balance of the Two-Pressure System for Sulphur-Free Fuels
its temperature is low, the additional heat absorbed efficiently be converted into work. A large portion of ied off again in the condenser. The exhaust stearn flow turbine and the cooling water system are approximately er than in Example 1, increasing the costs for the plant. I", the improvement in efficiency is great enough so that ease in investment costs is in most cases worthwhile if tee gas is being burned. shows the heat flow diagram for Example 2. Comesimple single-pressure system (See Fig. 3-5), the sharp stack losses (V2) and the significantly greater cons. (VI) are striking. sthe temperature/heat diagram of the stearn genshows, approximately 70% of the heat exchange the high pressure portion and approx. 30% in the rtion. That corresponds approximately to the raSsure and low pressure stearn generation respecient Conditions on J:ld Efficiency ~he effect of the two most important ambient
SYSTEM LA YOUTS 81
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
80
Figure 3-39
Q 100 %
EXHAUST GAS
0, 2 %
Y5
0,6 %
Y3
5T Y2
Y6
LP EVAPORATOR
50
100
150 MW
HEAT TRANSFER
0,5% Di~gram of a Two-Pressure Waste Heat Boiler with
E conomlzer
Y1 38,4% Fig. 3-39: Energy Flow Diagram for the Two-Pressure Combined-Cycle Low Pressure Economizer
Q VI V2 V3 V4 V5 VB GT ST
Energy input Condenser Loss Stack Loss Loss due to Radiation in the Waste Heat Boiler Loss in the Flue Gas Bypass Loss due to the Gas Turbine Generator and Radiation Loss due to the Steam Turbine Generator and Radiation Electricity Produced in the Gas Turbine Electricity Produced in the Steam Turbine
a
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
82
Figure 3-41
eCllmle the improvement is produced by the stearn proshare in the overall power output is greater. Again, of single-pressure systems, the air pressure does effect on the efficiency of the combined-cycle plant. in power output, however, is proportional.
104 0/0
102 -k---~-""£':"'-+---+--+-+--tew
the Most Important Design Power Output and Efficiency
100
98
live stearn data for single-pressure combinednot the same as those for a two-pressure plant. of the low pressure stearn generator which reheat that is not utilized in the high pressure
0
-
SYSTEM LA YOUTS 83
t:'"'"
90
~
94
Technical Data of the Two-Pressure Plant for Fuels ()l1taining Sulphur
92
90 -20
-10
o
30
40
Efficiency
gas turbine steam turbine required the plant
Output Fig. 3-41: Relative Power Output and Efficiency of Two-P",reesr:snu~)ere:rattLres Plants as Functions of the Air and Cooling Water .L'
* 11/110 tA PIP 0 tcw
Reference Relative Efficiency Air Temperature Relative Power Output Cooling Water Temperature
turbine exhaust gases utilization *
68200 38000 1 320 104900 228000 29.9 157400 73.0 24.1 46.6 46.0
kW kW kW kW kW %
kW % % % %
exhaust gases are cooled down to 15°C (59 OF)
84
SYSTEM LA YOUTS
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
85
Table 3-4: Main Technical Data of the Two-Pressure Combined-Cycle Plant for Sulphur-Free Power output of the gas turbine Power output of the steam turbine Station service power reired Net power output of the plant Heat supplied Efficiency of the gas turbine Heat contained in the exhaust gases Rate of waste heat energy utilization rate* Efficiency of the steam process Gross efficiency of the plant Net efficiency of the plant
69400 40800 1 200 109000 230000 30.2 159300 82.4 25.6 47.9 47.4
* 100% Utilization if the exhaust gases are cooled down to 15
Live Steam Pressures Two aspects enter into consideration when selecting pressure and low pressure live steam pressures: • The high pressure steam pressure must be rellatlvf high to attain good exergetic utilization of the heat. • The low pressure steam pressure must be low tain good energetic utilization of the waste Fig. 3-42 shows the efficiency (or the power ou1tPUlt: steam process for the second example as a function pressure live steam pressure. Other parameters changed. Fig. 3-43 shows the same data as a lUllctlOn pressure live steam pressure.
30
40
50
60
70
80 bar
PLS - HP Pressure Steam Pressure on the Efficiency of the Steam
process steam pressure before turbine live steam temperature 475°C steam pressure 3.3 bar gas temperature 52SOC
86
COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
Figure 3-43 26.0.---,----.----r---.---,---,-----,
l-
(/)
25.5+----+---+---t---t--..~r_-___r--___t
t:""
SYSTEM LA YOUTS 87
of the two curves explains the contrary functions pressure and the low pressure evaporators. The purfirst is to generate high quality steam, that of the utilize the remaining waste heat as fully as possible, pe accomplished only if the pressure in the evaportively low. However, there are two reasons why the e low pressure evaporator should not drop below (44 psia): halpy drop available in the turbine becomes 11, and 4Ille flow of steam becomes very large, result()ITespondingly large duct cross-sections. pws the rate of waste heat energy utilization in low pressure live steam pressure.
~.function of the
25 +---+---+---+---I----+---t--___ o 2 4 6 8 12 10
PLS - LP Fig. 3-43: Effect of the Low Pressure Steam Pressure on the Efficiency of Process TlST PLS- LP
Efficiency of steam process Low pressure live steam pressure before turbine High temperature live steam temperature 475°C High pressure live steam pressure 57 bar Low pressure live steam temperature 200"C
e case for single-pressure systems, the live steam oUld here, too, be as high as possible, without ching too closely the gas turbine exhaust gas
re evaporator, to be sure, a higher superheatefficiency slightly (Figure 3-45). However, without a super-heater provides the advantpres~mI'e drop between the evaporator and in all, the lack of superheating is comcompletely. pressure live steam temperature, the difbetween the high pressure steam after pressure steam at the mixing point in into account. If the difference is too ,*l1ne~cess(try thermal stresses within the mapressure steam temperature presents the
88 COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
SYSTEM LA YOUTS
89
Figure 3-44 85
B co 3;
80
t:"
75
o
2
4
6
8
10
12
PlS - lP Fig. 3-44: Effect of the Low Pressure Steam Pressure on the Rate of Waste Utilization
llWB PLS-LP
Rate of waste heat energy utilization Low pressure live steam pressure before turbine High temperature live steam temperature 475°C High pressure live steam pressure 57 bar Low pressure live steam temperature 200"C
160
180
200
220
240
260
0
(
t LS - LP Low Pressure Steam Temperature on the Efficiency of the IPrciceRR steam process live steam temperature live steam temperature live steam pressure gas temperature superheater pressure superheater =ODC
475°C 57 bar 200°C
90
COMBINED CYCLE GAS & STEAM TURBINE POWER
SYSTEM LAYOUTS 91
advantage of a kind of a low' 'reheating, " reducing the erosion due to wetness in the turbine. This consideratio be the reason for installing a low pressure superheater, ularly if the pressure of the high pressure live stearn is hi that in the condenser is low. Feedwater Preheating As in the case of the simple single-pressure system, water temperature greatly affects the efficiency of process since it directly influences the rate of the utilization in the boiler. If it is necessary, in order to low temperature corrosion, to have a high feedwater ature, multi-stage preheating should be provided (1 to 210 sure preheaters and 1 deaerator). Fig. 3-46 shows how feedwater temperature and the number of pre-heaters the efficiency of the stearn process in such a case. Condenser Pressure Fig. 3-47 shows how the condenser pressure affects ciency or the power output of the stearn process in th example. A deterioration in the condenser vacuum has a grea here than with single-pressure systems because the exha flow is greater. In the first example, where feedwate atures are higher, the effect is approximately the the system with a preheating loop, since the exhaust are similar in both cases. Pinch Point of the Waste Heat Boiler The pinch point of the high pressure evaporator tant here than with a single-pressure system bec:au: that is not utilized is recovered in the low pres~;ur'e The loss in power output is due only to the di1JerellC€
100
120
tFW J!'e€idw;~ter
Temperature and the Number of Low Pressure of the Steam Process
the .t:lllCle,ncy
92 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Figure 3-47 1,05,r-----r-------,--------,
1,00 - I - - \ - - - - - I - - - - - - - f - - - - - - - - t
lV)
~
t-
the high pressure and the low pressure steam portions. at reason, it is about half as great as with single-pressure s where the useful pressure drop in the low pressure steam roximately half that of the high pressure steam. For that , the pinch point selected for the low pressure portion also not be too low. mary: With a two-pressure system, the pinch points of high pressure and the low pressure evaporators have effect on the efficiency of the steam proces than with essure systems. If equal economic value is attached to ency, then, the pinch points selected for two-pressure liould be larger than those for single-pressure systems. ideration is purely academic, however, since twoystems are selected only where efficiency is valued d that in turn means low pinch points.
0,95
----
SYSTEM LA YOUTS 93
0790
V)
~
0,85
shows the relative efficiency of the steam process Il of the pinch points of the high and low pressure O,8l H - - -
Exhaust Gas Temperature
0, 75r--t----r---,----t----,---___ q025 0,05 0,1 0,15 0,25 OJ-
Fig. 3-47: Effect of the Condenser Pressure on the Efficiency of the Feedwater temperature
60°C
TlST/TlSTo Relative efficiency of the steam process PC Condenser pressure
Il. in the exhaust gas temperature lowers the effiteam process. This reduction, however, is less pro.than with the single-pressure system (Cf., Fig. 3-24) ¢rgy utilization rate does not drop off as quickly. as turbine exhaust gas temperature is, the more ssure system makes. Fig. 3-49 shows the ratio ficiencies of the two-pressure and the simple .~ocesses as a function of the gas turbine exhaust ~.At a theoretical exhaust gas temperature of ),ithis ratio is pracically equal to 1. This fact ystems that have supplementary firing (refer
94
SYSTEM LA YOUTS 95
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Figure 3-48
1,05.,...----,---.......-----.,-----,-----,,------.,
0,9 ">+_ _--11--_ _4--_ _-+ 15 10 5 o
+-__-+---:::31"'---10
600
0 (
Fig. 3-48: Effect of the Pinch Points of the High Pressure Evaporators on the Efficiency of the Steam Process 'tHP
Pinch point of the high pressure evaporator
'tLP
Pinch point of the low pressure evaporator
ll STlrjSTo Relative efficiency of the steam process
Efllici
96
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
3.1.4 Special Systems In addition to the four systems discussed in Section 3. 3.1.3, there are also others that can at times prove ~""'J"'u~; will cite two examples: • A system with steam or water iI\iection into the turbine to reduce nitrogen oxide emissions • A system using a single waste heat boiler for two turbines The system with steam or water iI\iection is taking on importance as environmental protection regulations be4~orn~ more stringent; the system using a single waste heat two gas turbines is of interest mainly for smaller mctc.tllln1e~ unit power ratings of between 5 and 30 MW. System with Steam or Water Injection into the Gas Turbine Environmental protection laws such as those (,l1rr~'nth fect in the USA, Japan, and in most European countries that the NO x levels in the exhaust be very low. With pres gas turbine combustors, special measures must be take der to maintain these levels. One way to reduce the formation of NO x during co is by lowering the temperature of the flame, since t of the reaction producing NO x is noticeably rapid onl high temperatures. II\iecting water or steam into the can produce the temperature reduction desired 9.1). For gas turbines alone, with no waste heat to iI\iect water but efficiency is lower than with ",,,c:aUl
SYSTEM LAYOUTS 97 )ro>blE~m with
steam iI\iection is finding steam at the suitlevel. Live steam is generally either at too high ssure live steam) or too low (low pressure live steam) e. Depending on the gas turbine and the load involved, lire level required for steam iI\iection is, at least for ustrial gas turbines, between 15 and 25 bar (203 and Using reduced high pressure steam is the simplest and expensive solution but is exergetically undesirable. shows an improved solution which employs a threebiler with a standard high pressure portion, a ressure evaporator for generating the iI\iection steam, pressure portion for preheating the feedwater. The t is relatively complicated. It can be simplified by steam from the turbine (Fig. 3-51), which makes it use the standard systems without additional equip-
er as to which of these two systems is the better must rOm one case to the next. It is certain that the threengement attains a slightly higher efficiency at full osts more. sible disadvantage of a solution employing steam e turbine might be part-load operation in instaleral gas turbines. Unless all the gas turbines are e pressure at the extraction point decreases so most cases inadequate. It thus becomes necesver to live steam, which again negatively affects three-pressure system is better in this regard. :tn, if the amount of iI\iection steam generated ()nly enough live steam need be used to cover age itself. sa comparison between the single-pressure sys~~ter loop without steam iI\iection into the gas s.ame system with iI\iection of extracted steam
SYSTEM LA YOUTS 99
98 COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
Figure 3-50
ng,ement with an extraction turbine for steam injection into the gas 8 3
(OjJti'JnllJ equipment) 2
10 11 12 13 14 15 ill
17 18
Fig. 3-50: System with 3-pressure boiler for Steam Injection into 1 2 3 4 5 6 7 8 9
Compressor Gas turbine Flue gas bypass (optional) High pressure superheater High pressure evaporator High pressure economizer High pressure boiler drum Steam turbine Condenser
10 11 12 13 14 15 ill
17 18
Low pressure pr'eh()at,er Feedwater ta][lki'deael'll High pressure feedwa Condensate pump Low pressure evaporat Low pressure drum Medium-pressure eva. Steam injection line Medium- pressure d
Steam injection Feedwater tankJdeaerator High pressure feedwater pump Condensate pump Low pressure evaporator Low pressure drum Medium-pressure evaporator Steam injection line Medium pressure drum
100 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
or with water iI\iection. This comparison, of course, does in itself possess any absolute validity because the amount steam iI\iected varies with specifications and type of gas 1",,,-1-.;.__ It does, however, show trends. The comparison shows that the system with steam U\J,ect,ic has a slightly higher overall power output and less waste to be dissipated in the condenser than the dry system. This fact indicates that there is less waste heat from the turbine the condenser, which also makes the installation less expensl Dis-advantages, on the other hand, are its lower efficiency the greater amount of additional water required. In some c then, the solution with steam iI\iection can be more econo that the standard solution. The prerequisite for this, how~ is having available a low cost source of additional water. system with water iI\iection has the lowest efficiency but it put is approx. 7 % greater. Water consumption is less by because the water has a better cooling effect than stea Table 3-5: Comparison of the single-pressure system with preheater loop with and without ':",'C'aH~ or water iI\iection, Fuel Oil #2 Injection in the gas turbine NO x emission Gas turbine output Stearn turbine output Heat input Station service power Net power output Net efficiency Waste heat in condenser Additional water required
Water
Stearn
75 73800 38600 255700 1300 111 100 43.5 78900 7.0
75 76000 31200 239500 1200 106500 44.7 61800 10.0
Dry
250 68400 36800 228000 1200 104000 45.6 76100 0.4
%
kW kgls
SYSTEM LAYOUTS
101
drop in efficiency, approx. 2% with steam and alwith water iI\iection explains why all gas turbine manare working on the development of dry low NO x ,<:>+-;,,">'" as presented in Section 10.3 in order to attain low mISSIOn levels without requiring water or steam iI\iection. Iso possible to conceive of a solution that no longer has a.m turbine at all: All of the steam is directed into the ine [69]. Fig. 3-52 shows one such system which could est as a peaking unit in countries where water is plensimple and attains an efficiency higher than that of rbine alone. However, if the steam flow iI\iected is ore than approx. 2 - 4 % of the air mass flow, major ns must be made to the gas turbine, principally moto the compressor. This system is therefore only of ~d interest. Because its efficiency is lower and its mption far greater than with the normal combined nge for its economical application is quite limited. /;lof highly sophisticated systems are being marketed der such names as STIG (Steam-II\iected Gas Turtig, etc. [45], [46]. They all suffer from the disadwater consumption is high, and that their efficiency snot as high as in normal combined-cycle plants. ly require specially designed gas turbines, which iIIliting their acceptance. STIG systems are :ns for smaller cogeneration plants with aerobines. Fig. 3-53 shows one such system, with oiler for two gas turbines. esigned to simplify and reduce the costs of the enever the combined-cycle plant includes sevIt is of interest mainly with smaller gas tursaving is possible with this system whenever J:lerator is provided to serve two gas turbines.
SYSTEM LA YOUTS
102 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
103
The cost reduction is less with larger machines. The advantages of this solution (Fig. 3-54) are: • savings for the evaporator • simpler steam circuit • better efficiency when operating on only one gas turbine. On the other hand, its disadvantage is that every gas t",..h;~· absolutely must be equipped with a flue gas bypass for startand shut-down. In plants where such a bypass is not rot}l£n"UT;, required, a cost increase results which cancels out to a extent the saving effected in connection with the boiler. The reduction in availability can be considered modest the unfired waste heat boiler is a reliable component. In summary, it can be stated that this arrangement is esting only for combined-cycle plants employing small bines that one intends to equip with a flue gas bypass an It is primarily of interest with jet gas turbines having a exhaust gas channel, since these can be built without hig pensive flue gas ducts. The boiler can be placed be1cwleeI gas turbines.
ement without a steam turbine, with 100% steam injection in the gas ill
3.2 Supplementary Fired Combined-Cycle PI (opl;ional equipment)
In an open-cycle gas turbine, only 25-35% of the oxyg tained in the air is used for combustion. The remainder used for an supplementary firing in the steam generator, renders the combined-cycle process even more versaf regard to design, operation, and choice of fuel. Earlier combined-cycle installations generally had sup tary firing. The fact that that is frequently no longe? today can be attributed to progress in the developm~
11 12 13 14 15 ill
Steam injection Feedwater tankldeaerator High pressure feedwater pump Condensate pump Low pressure evaporator Low pressure feedwater pump Low pressure drum
104
SYSTEM LA YOUTS
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
105
Figure 3-53
rr-I I I I I I
I
I I
I
1.:=
-,
4 3
Fig. 3-53: STIG Cycle 1 LP - compressor 2 HP Compressor 3 Gas Turbine
4 5 6
Combustor Steam Turbine Waste Heat boiler
of the principle of a combined-cycle installation with two gas and one waste heat boiler 10 11 12 13 14 15 16 17
High pressure steam bypass Feedwater tank, deaerator High pressure feed pump Condensate pump Preheater loop (low pressure evaporator) Low pressure feed pump Low pressure boiler drum (optional equipment) Low pressure steam bypass
106 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
gas turbine. Thermodynamic interest in supplementary fid decreases as the gas turbine inlet temperature rises (Section 2. Fig. 3-55 (p. 109) shows the efficiency of the combined-cycle cess using the gas turbine inlet temperature as a param The curves are valid for single-pressure steam circuits wi supplementary firing. Older gas turbines had low turbine temperatures. With these machines, an inc.rease in tern ture to 750°C (1382°F) improves overall efficIency. Beyon point, supplementary firing brings increases only in the.' In gas turbines with inlet temperatures in excess of (1832 OF), the gain is negligible even in the lower range. pressure processes, only a slight gain in efficiency can be ac with a supplementary firing to 750°C (1382 OF). vo:mplet, pressure processes, however, attain their maximum when utilizing the waste heat alone. As gas turbine inlet temperatures keep increasing, tance of supplementary firing will diminish even tllrttlll ertheless, the increased operating and fuel fl€~xil)ilitie: combined-cycle with supplementary firing may be an in special cases. Particularly in installations used ation of heat and power, this arrangement makes it control the electrical and thermal outputs se])aI'at4~ly Section 4). Combined-cycle installations with supplementary one of two categories: • units with limited supplementary .. U."UiOJ similar to units without supplementary firinJ~; • units with maximum supplementary firing, most of the oxygen contained in the gas hausts is utilized. This type of power plant the conventional stearn process.
SYSTEM LA YOUTS
107
Combined-Cycle Plants with Limited Supplementary Firing upplementary firing heats the exhausts gas to at most o °C (1472 to 1672 OF). The arrangement of the stearn used is similar to that of installations without supplefiring. Up to temperatures of 750°C (1382 OF), simple at boilers can be used, without cooling of the combusbers. Beyond that point, a cooling similar to that used nventional stearn generator is necessary. used are oil or gas. With a simple waste heat boiler ed combustion chambers, gas is the best fuel because radiation and ease of ignition. shows that the efficiency attains a maximum at a of 750°C (1382 OF). .b~cause the heat exchange in the economizer is op°C since the curves for flue gas and water temparallel. The exchange of heat can therefore take :minimum loss of exergy. Fig. 3-56 (p. 110) shows .re/heat diagrams for temperatures of 500° (932° OF), and 1000°C (l832°F) after supplementary firthe temperature curves in the economizer are 'th the minimum difference in temperature on end. This pattern is the same as that for a waste h()ut supplementary firing (refer to Sect. 1). At gther hand, the minimum difference in tempera from the water end-is at the inlet to the pattern corresponds to hat of a conventional
~Hafter the supplementary firing)
::tfter the supplementary firing is the limit case f~rence in temperature along
the entire econthat the exhausts can practically be cooled water temperature, thereby eliminating the UTe evaporators (Sections 3.1.2 and 3.1.3).
108
COMBINED CYCLE CAS & STEAM TURBINE POWER PLANTS
SYSTEM LA YOUTS
109
Unlike conventional power plants, the feedwater telmr:leratlll' here depends solely on the sulphuric acid dewpoint (Section 5. Thermodynamic improvement by multi-stage preheating higher temperatures serves no purpose. This pattern co:rr€:SDOh4 to that of combined-cycle plants without a supplementary waste heat boiler. Example of a Combined-Cycle Unit with Limited Supplementary Firing
Fig. 3-57 shows the heat balance of a typical combinedplant with supplementary firing to 750°C (1382 OF). Once the gas turbine is the same 70 MW machine as that used examples without supplementary firing. The intended f sulphur-free natural gas, which produces results optimu regard to efficiency. Natural gas has the further advantag it can be burned easily in a waste heat boiler without a combustion chamber. With oil, even that is more probl (Section 5.2). The basic arrangement for this installatio same as that for the purely one-pressure system in 3.1.1. the fuel contains no sulphur, the feedwater temperat be reduced to 60°C (140°F). Deaeration therefore tak under a vacuum. Fig. 3-58 shows the corresponding TemperaturelHeatd One can see the optimum temperature pattern in the eco resulting in a low stack temperature. This is the reas low pressure evaporator would bring not further impr ization of the waste heat energy at full load. At part 10 ever, or when the supplementary firing is switched off, temperature rises. For installations that are frequently at part loads, it can thus make economic sense to s7~ rangement with a preheater loop. The same consid~r applies to plants with a temperature after supplem lower than 750°C (1382 OF) at their design point.
A.1,05
---+-----t---\
1500
2000 ·C
of the refired combined-cycle installation as a function of the mperature after supplementary firing and gas turbine inlet e of the combined-cycle plant of the combustor inlet temperature temper:atUl:e after supplementary firing
110
COMBINED CYCLE CAS & STEAM TURBINE POWER PLANTS
SYSTEM LA YOUTS
Figure 3-56
600.....-------.------,a 500
t
t 400 1300i--~
~==t=====s::~
200
100~-----l------'I
o
0,5
1,
800 ...--------,-------, b
°
700+-~
~ 0
600t--~--f-----___I
t
1
500~--~""'-:-f--:-----'
......
It -'
----iIo-
Fig. 3-56: TemperaturelHeat diagram for 500° (932°F), 750° (1382°F) (l832°F) (c) after supplementary firing Temperature in °C Heat exchanged Flue gas Water/Steam
~
"
-'
'" '"
...... -.0
200+---------l-----~~1
Q./WB
~
t:""a:
~LJ"I
~N
COLJ"l
"-
t Q/Qk A B
~
co~
400 +-----~ 300 ~~==t=~
'"" ,A '" "-"1 '° "" """ °
x:
~
~ r--
COm
100+-----+------"1 1,0 o 0,5 100 "v ( 90 0 80 0 70 0 60 0 t 50 0 40,/\ 'v B 300 20 ~ 10 o 1,0 0,5
~
a
.J:)
e
LJ"I
m
".x 0..
LJ"I
<0' <0
N
111
112 COMBINED CYCLE GAS & STEAM TURBINE POWER
Figure 3-58 10ClJ-r---------------------
113
tdifference in comparison to combined-cycle upplementary firing lies in the live stearn data. Ot~h flue gas temperature brings these up to 84 d 525°C (977 OF), thereby improving the effim process. ed-cycle plants without supplementary firing, have practically no effect here on the rate waste heat energy. Accordingly, the criteria data can be similar to those used for convens.The main technical data of this example 3-6 below.
lJ.J
0:: :::l I-
< e:;
SYSTEM LAYOUTS
400
0-
302°( EVAPORATOR
:.E lJ.J
I-
rbine output and condenser waste heat are red to combined-cycle plants without suplIe increased efficiency of the stearn turbine to attain an overall efficiency almost equiwo-pressure combined-cycle plant discussed
100
o
50
100
150
HEAT TRANSFER Fig. 3-58: TemperaturelHeat Diagram of a Combined-Cycle InstallaticlIl Limited Su pplementary Firing
¢.hnical Data of the Combined-Cycle h Limited Supplementary Firing
e (LHV) ementary firing unit (LHV) rbine usts
Natural 69100 78300 2 100 145300 230000 79600 30.0 159300 32.9 47.6 46.9
gas kW kW kW kW kW kW % kW % % %
SYSTEM LA YOUTS
114 COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
The Influence of Ambient Conditions on Power Output and Efficiency If the temperature after supplementary firing is constant, the
effects of air pressure and air temperature are similar to those in installations without supplementary firing. These two desigr{ parameters have a very pronounced influence on the power out put, but the efficiency remains to a large extent unaffected. Because the steam turbine is providing a greater portion the total power output, the temperature of the condenser co ing medium has a stronger effect on the overall power out and the overall efficiency. Its effect on the steam process al is similar to that in plants without supplementary firing 3-22). However, because of the higher live steam data, of enthalpy drop is slightly reduced. The Influence of the Most Important Design Parameters on Power Output and Efficiency Flue gas Temperature after Supplementary Firing
The temperature after the supplementary firing is important design parameter because it strongly inJ[luenCl power output and the design of the plant. Fig. 3-59 shows how relative power output and eft'icieJ pend on the temperature after supplementary firing. tom limit, 525°C (977 OF), represents utilization of the waste heat alone. Two different systems have been the diagrams: • a single-pressure system (Fig. 3-57) • a two-pressure system (Fig. 3-34)
ee natural gas. When burning oil, the paths of the curves for e single-pressure system would not be significantly changed, t there would be less difference between the single and ()-pressure systems (Section 3.6). e should note the decreasing difference between the effiies of single and two-pressure systems as the flue gas temre after supplementary firing increases. The curve in Fig. ()nfirms that the two-pressure process provides no advan.()yer the single-pressure process at temperatures above 1882 OF). Here, too, the improvement at low flue gas tem~s is greater with the two-pressure process. It makes no e. at all for the steam turbine whether this flue gas temis attained directly from the gas turbine or by means .rt\entary firing. The results indicated in Section 3.1.3 ~()re also valid for installations with supplementary fir-
);lows another reason why the machine behaves in ./;IIere, the rate of energy utilization in the singlecess continues to rise as the temperature after the firing increases, up to 750°C (1382 OF). This is il'easi.ng stack temperature and the increasing tembetween the steam generator inlet and outof thermal energy utilization increases as the improvement possible with a twoDe4~OIll1es continually smaller.
for a combined-cycle plant with supple750°C (1382 OF) are comparable to those turbine plant with the same power outh,... h; .... The live steam temperatures have to the pressure, according to values power plants. As is the case in A
The basis for comparison is the single-pressure out supplementary firing. Calculations assume
115
SYSTEM LA YOUTS
116 COMBINED CYCLE GAS & STEAM TURBINE POWER
plants, efficiency increases steadily with of waste heat utilization at 750°C (1382°F) ....+.,...., firing is practically unaffected by the live reduction in exergy losses at higher live ...."'t·..... l'.p directly affects overall efficiency of the
lStt;Ulll
Figure 3-59
PK
117
180.------,r---,---,----,---% 160 -t---t---f---+--::;p~=-----.J
~E F 140 -t----+--+---:~=-+--~--l
120 -t------i~c--+--+---~--I 100 '"f-l!I1""--t---f---+----t-------I.
106 -r-------il----+---f----+-----0/0 -SINGLE PRESSU - - TWO-PRESSURE 104 '"t"a;c::------il----+---f-----f---------
'ilK
--
'Il RE F10 2 -r--------i-----I7iC----.-+-----=~k:-------
ycle plants without supplementary firing, the efeedwater greatly influences the efficiency as a whole. Because it directly affects the rate 'zation in the stearn generator, the tempera1<1 be as low as possible. If the risk of low tem1.l.makes it necessary to preheat to a higher preheating should take place in several stages. when burning oil, a two to three-stage pre\.lId be employed to reach the required 110 4, OF). The efficiency of a power station is, 'by the higher feedwater temperature. temperature for the flue gas (after suppleessthan 750°C (1382 OF), a system with a prea reasonable way to make optimum use of 1.2). The more often the unit is run at part becomes.
100 +-tI1"""'--t-----l---+---l--------900 600 700 800 500
tSF Fig. 3-59: Effect of the Temperature after Supplementary Efficiency of the Combined-Cycle Plant and on the Utilization PKIPREF Relative power output of the combined-cycle plant T1JJllREF Relative efficiency of the combined-cycle plant llWB
tsF *
Rate of utilization of waste heat energy Flue gas temperature after supplementary firing Reference = Plant without supplementary firing (fi?!;o(",19~
ired combined-cycle plants, the increased power output being provided by the stearn ~ondenser pressure is of more importance de plants which merely utilize the waste .machines where the live stearn data are low. e>enthalpy drop in the turbine is greater the relative effect of a change in condenser
118 COMBINED CYClE GAS & STEAM TURBINE POWER P
pressure is less pronounced. More detailed in:fOl~m;atio] effect it has on the power output of the steam t-l1,.. h;·.... obtained from [1]. It should be noted, however, cycle plants have a greater exhaust steam flow ventional steam power plants with the same steam put, since there is less preheating of the tf'I"r1',W:>Itl"" reason, the condenser pressure exerts a greater mtluE~l1 power output from the steam turbine.
3.2.2 Combined-Cycle Plants with M~lXimlJ111 Supplementary Firing The basic idea for combined-cycle plants with()ut ited supplementary firing in the waste heat the best possible use of the gas turbine's waste with maximum supplementary firing, the point of not the gas turbine but the conventional steam was to provide a prior gas turbine in order to imnr()1 ency of the large conventional power station. In gas turbine is- stated with some exaggerationproved air blower with an air heater built in. " to provide electricity. This approach is reflected in the ratio of the steam and the gas turbines. Depending on the air, this is between 4 and 10, as compared to cycle plants without supplementary firing. The steam process is consequently almost the a conventional steam power plant. In most a unit with steam reheating and multi-stage water heating. The number of possible systems available is tically all known steam processes can be -"1'--r-r
SYSTEM LAYOUTS
119
between the outputs of the steam turbine and be varied at will, either by increasing the in the steam generator using an additional only part of the oxygen remaining in ex,h.a1Llst gas. The example shown in Fig. 3-60 fl"rhinp and a steam turbine with reheat. In a the regenerative air pre-heater usurexltil:>n:al steam generators is superfluous beflue gas is being used as the combustion leratllre would therefore be very high if waste not being used for feed water heating. flow to flue gas flow is much greater than Due to considerations of exergy only a should be directed through the econoheat€~a with flue gas. The rest flows as nortel:lm-hleal;ea high pressure preheaters. The part-flow economizer is therefore ideal water and steam temperatures run (Fig. 3-61). Sl1lpllUI'-fI'ee natural gas, the energy is the even better use by using a second partlow pressure portion of the feed water J.~€~m(mt is advantageous, however, only if exl1au.sts is very low (Fig. 3-62). J.Stallatilofls with maximum supplementary l\lipped with a fresh air fan which makes steam process even when the gas turThis increases the availability of the efficiency in operation of the fan is is only used as an emergency opergreat importance here.
120 COMBINED CYCLE GAS & STEAM TURBINE POWER
SYSTEM LAYOUTS
Figure 3-60
~ t:: CONSTANT
HEAT TRANSFER Fig. 3-60 1 2 3 4 5 6 7
Arrangement of a Combined-Cycle Plant with MElXiInuJm Firing
Compressor Gas Turbine Flue gas bypass Superheater Steam generator Intermediate superheater Part-flow preheater
8 9 10 11 12 13 14
Steam turbine Condenser Low pressure economizer Feedwater tankJdeaerator Feed pumps Condensate pumps High Pressure preheater
121
122 COMBINED CYClE CAS & STEAM TURBINE POWER
Figure 3-62
SYSTEM LA YOUTS
123
large supplementary firing in combined cycle systems gas turbine inlet temperatures causes efficiency to tion 2). For that reason, combined-cycle plants with supplementary firing are only of slight importance comparison to simple combined-cycle installations they two advantages: can be burned in the stearn generator good part-load efficiency.
of these considerations is a true advantage only where of gas or oil available at a low price from the gas latively slight. In other cases, it is generally a better <1 either a combined-cycle plant utilizing only the or a conventional coal-burning power station.
bar
• C kg/s
144 217
~ KL = 45,3% ~KL= 354,8 MW
Fig. 3-62; Example of a Combined-Cycle Plant with Maximum Firing (coal)
tion might be a case calling for peaking operation turbine and base load operation of the stearn turgement of this type possesses the advantage that waste heat from the gas turbine without a special iler. ge of good part-load behavior is also valid only tent because combined-cycle plants without suping also attain high part-load efficiencies if they l/gas turbines (refer to Section 7). t::tges of units with maximum supplementary firred to simple units utilizing merely the heat conhaust gas are considerable: '¢iency tment costs required installations, more difficult to operate ,especially if the stearn generator is
124 COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
For these reasons, this type of plant will not be dis:cussEld further detail here. However, the example below can nr,nniA a basis for comparison with the other arrangements. Example of a Combined-Cycle Plant with Maximum Supplementary Firing This example is also based on the same 70 MW gas turb Its power output is lower here because there is a greater sure drop in the exhaust gases in the steam generator. Th turbine burns natural gas, the steam generator coal. Due to maximum possible utilization of the oxygen in t hausts (excess air co-efficient = 1.3), however, a high 0 plant output of approx. 340 MW is attainable. The stea cess has a simple reheating, a seven-stage regenerative water preheater, and a high pressure part-flow economize main technical data for it are shown in Table 3-7. Table 3-7: Main Technical Data of the Combined-Cycle Plant with Maximum Supplementary Firing Gas turbine output Steam turbine output Station service power (not including feed pumps)* Net power output Heat input to gas turbine (natural gas) (LHV) Heat input to the supplementary firing unit (coal)(LHV)
SYSTEM LA YOUTS
125
gas-fired steam generator, a net efficiency of approx. be attained by adding a low pressure part-flow econthe steam cycle. Because the power output from the ·. . .·lho'T1"" is so high, the heat flow to be dissipated in the is practically as great as that in a conventional steam This therefore makes the selectioH of a site more with a simple combined-cycle plant, far more
Ambient Conditions and of Design Parameters comtlin~ed-·cycle plants
without supplementary firtelup,er£llture strongly affects the overall power outthose cases where the oxygen in the exhausts utilliz:ed without employing an additional fresh air of the cooling medium in the condenser is in units without supplementary firing beturbine is larger. However, the greater enthalpy steam turbine partially compensates for this.
......,h ...·""
apply to selection of the steam plant design for conventional steam power plants. Due units, turbines with reheat systems are gen-
of Conventional Steam Power
Efficiency of the gas turbine Heat contained in gas turbine exhaust gases Efficiency of the steam process Gross efficiency of the plant Net efficiency of the plant * Steam turbine used to drive the feed pump
older steam power plants into combinedas "repowering" - is one interesting to continue using at least parts of older have become uneconomical. In this pronorm.ally replaced with gas turbines and ~tlitGlble for such an action are steam turD()WE~r stations which have relatively low
IT .... ~ . ."...
126 COMBINED CYCLE GAS & STEAM TURBINE POWER
SYSTEM LAYOUTS
127
live stearn data quite well adaptable for combined-cYcle lations. These 20-to-25-year old stearn turbines generall have a considerable service life expectancy left, but thei ers are often ready for scrapping. Fig. 3-63 and 3-64 show the example of a conventiona turbine plant, before and after such a conversion. From inal installation, it was possible to reuse the ponents: • • • • • •
2
building stearn turbine and generator condenser main cooling system main transformer for the stearn turbine the high voltage equipment
5
4 The following parts were dismantled: • boiler • • • • •
piping and fittings feedwater preheaters condensate pumps feed water pumps control equipment
This list can vary from one case to another. however- as in the example- it makes sense components which can be continued in use pense. All parts with only a slight value rernaiW~ scrapped, for such elements frequently cause tra costs and negatively affect the availability installation. The feedwater pre-heating system because it must, for a combined-cycle plant, be
before Conversion to a Combined-Cycle Plant 5 6 7
Condenser Feed pump Condensate pumps
128 COMBINED CYCLE GAS & STEAM TURBINE
PO'WS:D
Figure 3-64
SYSTEM LA YOUTS
129
steam power plant because of thermodyThus, in most cases, no extraction points the steam turbine, which increases the turbine. However, the generator and be able to handle this additional power cases that can lead to restrictions. the. significant gain in efficiency that can be ering. The power output of the plant as been tripled. A supplementary firing could er output because the gas turbine exhausts £,fY\Tp·rinC1 a portion of the heat demand of
10
Fig. 3-64: Combined-Cycle Plant with Existing Steam Turbine 1 2 3 4 5 6 7 8
Gas Turbine Compressor Flue gas bypass Superheater Evaporator Economizer Drum Steam Turbine
9
ill 11
12 13 14 15
16
Condenser Steam bypass Feedwater tankJdeaerator HP Feedwater pump
of a steam power plant before repowering to a combined-cycle
before repowering
after repowering
30300 32000
102 200 35000 68400 1200 228000 44.8
r plant earn turbine turbine
1 700 107000 28.3
LP evaporator LP Feedwater pump LP drum
kW kW kW kW kW %
supplernelntc:try firing in repowering is the the live steam data of the origdesign of the gas turbine has been stanlimits on the amount of steam that can do not necessarily lie close to the design turbine.
\a<:lap1~at:ionto
130 COMBINED CYCLE CAS & STEAM TURBINE POWER P
Another approach to repowering can be used with dern steam power plants equipped with reheat steam To improve the efficiency of such a unit, the freshai be replaced in supplying the oxygen needed for comb installing a new gas turbine before the existing stea tor. Here, the existing steam boiler continues in use , be adapted to its new operating mode. The modificatio are due mainly to the much higher temperature of bine exhausts (approx. 500 °CI 932 of as compared to 1572 - 662 of for the fresh air after an air pr,ehleat;er) parts that must be modified are the: • burners • fresh air ducts • perhaps the reheater A waste heat recovery system must be installed generator to handle most of the condensate and ing. The complete plant appears similar to those 3-60 and 3-62. The major problems that arise with this type are in connection with: a) space availability for installation of the and the waste heat recovery system b) adaptation of the boiler and the overall cept to the new mode of operation For steam power plants that burn gas or oil, one very interesting possibility for raising ef1ficie: than 10% and power output by 20 to 30% at vestment costs. With coal-burning units, there economic gain because the conversion itself is there is less improvement in efficiency.
SYSTEM LAYOUTS
131
Cycle Installations with Ie Gas Turbines [63 to 68] operate either in an open-cycle or a closedclosed-cycle process is, however, much less an the open-cycle. Fig. 3-65 shows the simconsisting of compressor, heater, turbine, ticallY, the medium can be any gas, bU~ alIlsthat have been built employ air. HelIum 1t~rpossible media, with helium in particular fdr nuclear power stations. the gas turbine can be raised by employing systems, e.g., a recuperator, compressor colling, or the like. However, as was the Ie gas turbines, the simpler arrangements ost suitable ones. ge of the closed-cycle gas turbine is the great selection of the fuel. In addition to oil or fuel can also be used. Its main disadvantage pplied to the process via a heat exchanger, bine inlet temperature to levels lower than as turbines. According to [64], efficiencies i:>.Ll'JU•. u be attainable. Fig. 3-66 shows the way of the combined-cycle process depends pres~mr'e ratio and the gas turbine inlet temp()terlti~:tl application
involves nuclear power reactors (high temperature reactors act,ors.). In these plants, the gas would be in reactor. The maximum process temperthe highest process temperatures attaintoday at 950°C (1742 OF).
ll.-C~OOlea
132 COMBINED CYClE GAS & STEAM TURBINE POWER
SYSTEM LAYOUTS
133
Figure 3-65
3
50
--+---1
150 1
4
Fig. 3-65: The Closed-Cycle Gas Turbine 1 Compressor 2 Gas turbine
3 4
Heater Cooler
3.0
4.0
5.0
6.0
IT Efficiency of a Combined-Cycle Plant with a Closedon the Compressor Pressure Ratio and the Inlet Gas Turbine (as in [64])
134 COMBINED CYCLE GAS & STEAM TURBINE POWER
The use of combined-cycle plants with cl()se,a-~cYc~le bines can be considered for the following applica'tions: • burning coal in a fluidized bed • high temperature reactors. Fig. 3-67 shows one possible arrangement with combustion, a closed-cycle air or helium gas turbine, sequent reheating steam process. A combined-cycle a high temperature reactor, helium turbine, and can be seen in Fig. 3-68. In neither case can a COJmnl€ be expected in the near future because the te(~hllOll()l economic hurdles are too great.
3.5 Pressurized Steam Generators As one final combination we should mention a a pressurized steam generator. This type of nn,7'JC>'" fall into one of two categories: • installations witI: a simple charging group, w or may not prOVIde (a small amount of) electr power • in~tallations with gas turbines and subsequent mIzers Fig. 3-69 shows the diagram of the principle empl first of these arrangements. Power plants like this quite early: the more than 100 Velox boilers built 'by veri operate in this way. However, such installati real future (at least for oil or gas-burning plants) cannot provide any genuine thermodynamic adv conventional steam plants. The gas turbine is ope a very low temperature level because it is using t from the steam generator as a working mediuIrh is being made of the high temperature potentialdi machine, and its power output is for that reason pI' Typical efficiencies of such units are in the rang
SYSTEM LAYOUTS
135
n.. . rl~lnT advantage is the small, compact steam genof the higher pressure and the greater speed gas, the heat transfer is better than in a conConsequently, the surface required haJlge is smaller, and that theoretically should s.of the installation. s an installation of the second type. Here, unp employing a simple charging group, advantE{high gas inlet temperature. The steam I'~places the gas turbine combustor. Net effi46% are within the range of possibility. That ngement should also have no thermodynamic n compared to combined-cycle plants with eritary firing. But even these values are ssed by simple combined-cycle plants withfiring which today exceed 50%. The quesS as to whether there will be any economic ilor gas-fired plant of this type in the future. wer efficiency, it has the following further riicompared to the combined-cycle plant with eat boiler: t¢m requiring a special steam generator perator ration of the gas turbine and steam t cost compared to the simple plant thas the following advantages: erator- though this advantage is ed out by the subsequent economizer r the steam process possible because a.ge capacity of the steam generator.
SYSTEM LAYOUTS
136 COMBINED CYCLE GAS & STEAM TURBINE POWER
Figure 3-67 3
2
1
2
4
5
6 6
7
7
Fig. 3-67: Combined-Cycle Plant with Closed-Cycle Gas Turbine Combustion 1 2 3 4 5
Compressor Gas turbine Heater Cooler Waste heat
6 7 8 9 10
Steam turbine Condenser Feedwater tank/deaerator Feed pumps Condensate pumps
Heactor with Helium Gas Turbine Followed by a 6 7 8 9 10
Steam turbine Condenser Feedwater tank/deaerator Feed pumps Condensate pumps
137
138 COMBINED CYCLE GAS & STEAM TURBINE POWER
SYSTEM LAYOUTS
139
Figure 3-69
I' I
rr=-----I I
5
5
1
2
7
3
Fig. 3-69: Arrangement Employing a Pressurized Steam Ge:nerato,r Charging Group 1 2 3 4 5
Charging group (Gas turbine) Steam turbine High pressure preheater Low pressure preheater Steam generator
6 7 8 9 10
Economizer Condenser Feedwater tallkJde;aer'atl)r Feed pumps Condenser
mployilng a Pressurized Steam Generator with Gas Ilb!!equellt Economizer 6 7 8 9 10
Economizer Condenser Feedwater tank/deaerator Feed pumps Condenser
140 COMBINED CYCLE GAS & STEAM TURBINE POWER PLAN
The balance is more likely to be on the negative side oil or gas-fired plant. Plants with pressurized stearn generators could neverl still become very interesting in the future because they a possibility of burning coal cleanly in a pressurized fl bed combustor (PFBC). Refer to Section 10 below forf information about such plants.
3.6 Summary and Evaluation of the Various Arrangements Possible In our evaluation of the various arrangements poss will omit from consideration systems with closed-cycl bines or pressurized stearn generators because they a of academic interest only. The following six example compared below:
SYSTEM LA YOUTS
141
of Power Output and Efficiency the Various Systems SinglePressure
SinglePressure, Preheater Loop
2-Pressure Fuel with Sulphur
101.5
104.5
104.9
109.0
145.3
348.8
44.5
45.6
46.0
47.4
46.9
44.6 1)
2-Pressure Limited Maximum Fuel with Aux. Aux. no Sulphur Firing Firing
68.6
68.4
68.2
69.4
69.1
66.8
34.0
36.8
38.0
40.8
78.3
288.0
30.1
30.0
29.9
30.2
30.0
29.0
21.7
23.4
24.1
25.6
32.9
40.4
Oil
Oil
Oil
Gas
Gas
Gas
Gas
Coal
• the single-pressure sytem (Fig. 3-4) • the single-pressure system with a preheater IOQ 3-27)
228.0
228.0
230.0
230.0
230.0
0
0
0
79.6
551.5
• the two-pressure system for fuels containing (Fig. 3-37) • the two-pressure system for fuels containing phur (Fig. 3-38) • the combined-cycle plant with limited su]ppJleIl firing (Fig. 3-57) • the combined-cycle plant with maximum tary firing (Fig. 3-60) All arrangements are based on the same gas approx. 70 MW and are as a result directly cOlmp,ar.:tbl,
ST Steam turbine
Suppl. Supplementary
steam generator with a low pressure part-flow econo
point is the high net efficiency of the gasThe unit with limited supplementary far behind: its efficiency is less only by . Its power output, however, is about 40% "'''':;;aJ.LL turbine produces about twice as much emleIllt can be of interest whenever a higher ttaLin::tbl.e with utilization of the waste heat the specific investment costs reto be lower than those for the two-pres-
~v~tl"m
142 COMBINED CYCLE GAS & STEAM TURBINE POWER
sure system. But this type of plant is more complex become less and less attractive in the future as gas temperatures continue to increase. The net efficiency of the combined-cycle with maxi plementary firing is poor, but it can cover 70% of quirements with coal, which is frequently an adVaJlta Efficiency is only one of the important criteria on the selection of a power plant. A second is the is difficult in a Handbook of this type to provide Only comparative prices are possible. The basis for is in all cases the simple single-pressure system ative prices are valid as specific prices for Ul.,t.auat.1V comparable power rating (Table 3-10).
SYSTEM LA YOUTS 1'"\r1~J:lTlt
143
consideration is the amount of cooling wa-
()nlP2Lrt~,on AHt11T,t>l"I
e
of the Amount of Cooling Water for the Various Arrangements
SinglePressure, Preheater Loop
2-Pressure Fuel with Sulphur
76.1
74.6
88.4
133.4
670
1810
1780
2105
3180
15940
104.0
104.9
109.0
145.3
348.8
17.4
17.0
19.3
21.9
46.5
2-Pressure Limited Maximum Fuel with Supp!. Supp!. no Sulphur Firing Firing (Coal)
Table 3-10: Comparison of Specific Prices for the Various Systems, in % SinglePressure
Relative price
100·
Single2-Pressure Pressure, Fuel with Preheater Sulphur Loop
101-103
105-108
2-Pressure Limited Fuel with Supp!. no Sulphur Firing
106-110
103-110
• Basis for comparison
The higher specific price for the unit with a com rating when employing maximum supplementar to the fact that a steam plant is more expensivet bine, which means that the relative price for iriS1; a proportionally large steam component will be This is especially true for a plant with a coal-bu' today usually requires installation of a sulphur from the exhaust gases.
df the cooling water: 10°C (l8°F)
tage of the single-pressure system by itself cooling water requirement. The other ts without supplementary firing need bere water per installed MW because in these ditionallow exergy heat is being supplied .from the exhaust gas. Because this energy ble into mechanical energy, it must in large ce again in the condenser. a.mount of cooling water required, the ",ith maximum supplementary firing turns tequires proportionally three times as much lants without supplementary firing. But re with a reheating steam plant than with installation, and consequently the amount ).tired is large.
144 COMBINED CYCLE GAS & STEAM TURBINE POlwtl:
Flexibility in fuel selection also plays an nYlnr....... Present-day gas turbines can only handle liquid ble 14).
SYSTEM LAYOUTS
145
process depends on the gas turbine fuel used for supplementary firing. Table deJ.im~s in this regard.
Table 3-12: Possible Gas Turbine Fuels a) Standard Fuels
Natural gas Diesel oil
b) Special liquid fuels
Methanol Crude Heavy oil, Oil shale oil
c) Special gas fuels
SinglePressure, Preheater Loop
2-Pressure Fuel with Sulphur
Diesel oil, gas, etc.
Diesel oil, gas, etc.
No-Sulphur Diesel fuel oil, gas, Gas, Diesel oil
Synthetic gas Blast furnace gas Coal gas, with calorific value
Note: The use of categories b) and c) is limited, because may be burned depends on their exact chemical type of gas turbine involved. Generally, industri with large combustors are better able to
2-Pressure Limited Maximum Fuel with Supp!. Supp!. no Sulphur Firing Firing
Diesel oil, gas, etc. Coal, Gas Heavy oil
Stem with a low pressure economizer is suitfuel with a very low or no sulphur level. sits advantage due to the higher feedwater to avoid low temperature corrosion. lld efficiency of the system with a preheater y unaffected by changes in the feedwater reason, it is equally suitable for all gas turphur fuels, however, its efficiency is lower pressure system. In such cases, it should be efficiency is not the critical factor. ~
unit with maximum supplementary firing fburning solid fuels as well. This additional ¢overlooked when considering its disadvan¢ts, especially its high investment costs and
146 COMBINED CYClE GAS & STEAM TURBINE
POWI:1l
The installations without supplementary firing are portance today. Their advantages include: 48
high efficiency
48
a simple steam process
48
low investment costs
48
quick installation
48
simple operation and maintenance.
INED-CYCLE PLANTS COGENERATION
Particular trump cards of such plants are their low live steam data (Table 3-15). These pIa high availability ratings and provide easy operatio nance. Table 3-15: Comparison of Steam Process Data Various Systems Discussed in SinglePressure
SinglePressure, Preheater Loop
2-Pressure Fuel with Sulphur
Reheat
no
no
no
no
Live stearn pressure,bar
37
37
60
60
Live stearn temperature, °C
480
480
480
480
Feedwater temperature, °C
130
130
130
60
1
3
1
No. of feedwater pre-heaters
Chapter 4
mic advantage of a combined-cycle applies a power plant that produces power alone, 'ch provide heat or process steam as well. diagram of such an installation with a
sU]Jeriority of the combined-cycle plant nnUT~.r plant is even more pronounced in it is in plants used only to generate hpf.wppn the average heat input to the pro~Xh.austs is greater in a combined-cycle plant plant. plants have to supply heat at the same in temperature drop is the same in loss in combined-cycles is smaller be.a,VCU.l<1U.l\:: is larger (Fig. 4-2). in~'f1_,(""('It:>
installations can be considered
with a backpressure turbine with an extraction/condensing waste heat boiler (Fig. 4-4)
147
148 COMBINED CYCLE GAS & STEAM TURBINE POWER
COMBINED-CYCLE PLANTS fOR COGENERATION
Though the gas turbine with a waste heat boiler is nd a genuine combined-cycle plant (it operates without a ste bine), it can be viewed as a limit case. All installation equippped with supplementary firing, which might ev considerable advantage for the cogeneration process it offers a much greater design and operating flexibi available with waste heat utilization alone. The prod stearn or thermal energy can be controlled independen electrical power output because the gas turbine assum of the power output and the auxiliary firing handles the stearn or heat generation. Cogeneration plants ca sified into three categories as follows: • industrial power stations to supply process ste industrial plants • thermal power stations to supply thermal ener district heating systems • power plants coupled to seawater desalinatio
4.1 Industrial Power Stations
2
Wherever both electrical power and process steam it is thermodynamically and generally also econo to produce both products in a single plant. The number of possible solutions is large becau is a "special case." As an example, we will cite It with a single pressure level for the process steaITl. ses involved are more complicated but the basicc remain unchanged. One important core paramet ration plants is the power coefficient, the ratio be trical power and the thermal energy produced [ One characteristic of the combined-cycle plant imum value for this power coefficient. It is theref to be suitable for processes where a relatively gr. power must be generated.
the Principle of a Combined-Cycle Plant used for 5 6 7 8
Steam reducing station Supplementary firing Flue gas bypass Backpressure steam turbine
149
150 COMBINED CYClE CAS & STEAM TURBINE POWER P
PLANTS FOR COCENERA TlON
Figure 4-2
700
O( 600 8
500
LLJ
a:::
400
:::::> t-
«
Power Plant with Extraction/ Condensing Steam
a:::
g:
300
6 7 8 9
L LLJ
t-
Supplementary firing Flue gas bypass Backpressure steam turbine Condenser
200
100 5
o COMBINEDCYCLE PLANT Fig. 4-2:
Comparison of the Temperature Drop of COimbine,d-y, Steam Turbine Power Plants
A
Temperature drop available in a backpressure Temperature drop available in the industrial Temperature drop available in a condensing
B A+B
5 6 7
Steam reducing station Supplementary firing Flue gas bypass
151
152
COMBINED CYCLE GAS & STEAM TURBINE PO'WI~11
Example of a Combined-Cycle Industrial ... 0-.,.,........... Just as we did for power generation alone, we further considerations here on one given example, a gas-burning plant with supplementary firing, eq( the same 70 MW gas turbine as our other example~, pressure turbine (absolute backpressure 3.5 bar). Fig. 4-5 contain the main technical data for this 1.1
MBINED-CYClE PLANTS FOR CO GENERA nON
153
level of the process stearn and the power coefof importance for design, because the pressure t¢am directly affects the enthalpy drop in the he higher the pressure, the less electricity is -fj\shows the effect on the overall output of the ure is very high, the use a stearn turbine beIe since its pressure differential is then too e, the stearn process reduces to a waste heat
The Effect of the Most Important Design Con As with combined-cycle plants used for genera alone, the air temperature is of particular import for power output. In industrial processes, the dem generally does not depend on the ambient tern reSUlt, one is often compelled to select the temperature for design purposes. Table 4-1: Main Technical Data of the vOmO'ln€!(J Industrial Power Plant Fuel Gas turbine power output Backpressure steam turbine power output Station service power Net power output of the plant Heat input to the gas turbine (LHV) Heat input to the supplementary firing (LHV) Process steam flow Process steam pressure Thermal energy of process steam Rate of fuel utilization Power coefficient Electrical yield Efficiency of power production
iCient of the plant is affected mainly by three
giIuel supplied directly to the boiler pe condensing portion of an itdensing turbine vel of the process stearn Itg makes it possible to lower the power co~.his capability is limited because lowering \lce the thermodynamic advantages of the ombined-cycle plants should be employed ~()efficientis high. That feature must not, ed as a disadvantage since for industries wer coefficients it is often a better idea eded from the connected grid and to genefitional stearn generators. Fig, 4-7 shows '¢ient depends on the temperature after , g, turbine offers greater design and direction of higher power coefficients. the turbine makes it possible to inproduced at the cost of process stearn procedure works out unfavorably on
154
COMBINED CYCLE GAS &. STEAM TURBINE POWER
PLANTS fOR CO GENERA TlON
155
Figure 4·5
..........- . - - - . - - - - - - . - - - - - - 1 0 , 9 0
~+__--+_-----__t_-----_+
0,80
0,70 w
a..
......
0,60 ......
......
r.. . . . . . .
PC
0,50
IJl
o
N'l1Jl.__-+--H----H--h 0""
=----l------+-------+O,40 30 bar 20 10 p PS Steam Pressure on the Electrical Power Output of the
Ie Plant
156
COMBINED CYCLE GAS & STEAM TURBINE POWER
Figure 4-7
1,1
w a..
0, 9
-t----+~---t---+_---!-.........
0,8
-t----+--~:----+_---!- .........
0,7
- t - - - - + - - - - t - - - - . : l " + . . - - - - ! -.......
OMBINED-CYCLE PLANTS fOR CO GENERA HON
157
ciency. As shown in Fig. 4-8, when the power eases, this indicator approaches asymptotically the combined-cycle plant used to generate power ns that the backpressure turbine represents the rcogeneration. As soon as the power coefficient §, one moves away from that optimum. To the Il1um is the case with mixed process stearn proion of the process stearn is being produced in e/turbine and the remainder in a stearn generaeefficiency of power production drops off ra-
st· Important Parameters the design data, it is necessary to distinguish d an unfired waste heat boiler. With suppleeshould select live stearn data similar to those earn power plants. Just as for plants used to ,the feedwater temperature must be as low attain a good utilization of the heat in the
0,6 ; - - - - + - - - - t - - - + _ - - - ! -
0, 5 -t----+---~---+----+ 500 600 700 800
tSF Fig. 4-7:
Effect of the Temperature after the ~Ul)phJmEmtl'lryjfiri Coefficient (*Case without Supplementary
PC tEl"
Power Coefficient Flue gas temperature after supplementary firing
ntary firing, the live stearn data should be o criteria similar to those indicated in Secteam pressure should, however, be higher high enthalpy drop between the live stearn I'n' This is especially true if a relatively high ired for the process stearn. Poorer heat utilis loss must be regained in a low pressure such low pressure systems are used only rocess stearn. Generally it is not worthw.~."\V. pressure stearn into the turbine because differential available between the low presstearn.
1S8 COMBINED CYClE CAS & STEAM TURBINE pnlWI~D
Fig. 4-9 shows a system employing an unfired waste heat boiler and a backpressure turbine. The stearn is fed directly into the process stearn system. sure economizer shown is of interest only when bur free fuel. In oil-burning plants, one should employ a lar to that in Section 3.1.2 (single-pressure system heater loop).
BINED-CYClE PLANTS fOR COCENERA HON
.....---,----,----,--~I90
80 010
When designing a cogeneration power plant, tfi. ways that for given economic conditions its design be simpler and less expensive than that for a power generates power alone. Thus, for example, the effi turbine can be a bit poorer because the losses in are recovered energetically in the form of additional.
Other design criteria for district heating power heat output and the water temperatures, which bient temperatures. The system used must operating flexibility, but must not become too too expensive. In particular, no district heating should ever be designed for extreme conditions: operation would be questionable.
>w z ~
70 w
LL. LL. LU
.....J
« 60 w
a:::
---
4.2 District Heating Power Plants Generally, district heating power plants produceh at temperatures lower than those in industrial pow uallevels are between 80 and 150°C (176 and 302 stearn is used to heat the water, it can, for exerg be helpful in larger installations, to break down th two or even three stages. Fig. 4-10 shows the te hot water and stearn in a I-stage and a 3-stage only one stage is used, all the stearn must be higher pressure level, which means that the tainable is less than that with a 3-stage sv~gte~m.
1S9
I-
w
--
LU .....J W
50
........---+---+-----t---+-+ 40 1,5
2,0
2,5
3,0
POWER COEFFICIENT Coeflicient on the Electrical Efficiency and Electrical
160 COMBINED CYClE GAS & STEAM TURBINE
PLANTS fOR CO GENERA nON
161
Figure 4-9
3
2
)1 STEAM 3
100 0/0 HEAT EXCHANGE Fig. 4-9: 1 2 3 4
Combined-Cycle Industrial Power Plant with Boiler
Waste heat boiler Gas turbine Steam user Feedwater tank/deaerator
5 6 7 8
"'U.'A_'''''O<
Pressure reducing Supplementary Flue gas bypass Backpressure steam
of I-stage and 3-stage heating of the hot water
162 COMBINED CYCLE GAS & STEAM TURBINE POWER
Example of a Combined-Cycle Power Plant for District Heating In district heating power plants, independent contlrol tricty and heat production is generally not required. plants are usually integrated into large grids so that stations can take over adjusting the electrical power to the demand. The only output parameter that mu lated is the heat output. For that reason, the design bined-cycle plant should be simple, which means w supplementary firing in the waste heat boiler. Fig. the arrangement and heat balance of a typical an extraction/backpressure turbine. Table 4-2 technical data. Table 4-2: Main Technical Data of the Heating Power Plant Fuel Gas turbine output Steam turbine output Station service power Net power output District heating water return temperature District heating water supply temperature Heating output Heat input (LHV) Rate of fuel utilization (LHV) Power coefficient Electrical yield (LHV)
COlml)in,ed-C~
69400 23700 1 000 92 100 1
109 230
COMBINED-CYCLE PLANTS fOR CO GENERA HON
163
depicted is based on a single-pressure stearn prooincrease the rate of utilization of the waste heat lowed by a heating circuit heated by the flue gas. ~shown, this circuit is built as a closed system. l()ying the district heating water directly would but it would mean greater problems in operation. bm the example shown, the stearn turbine could which would provide a ~nexibility. Whether or not such an added ineworthwhile depends mainly on the value atItional electricity which could be produced. §ystem using an extraction/condensing turbine.
hI condensing turbine,
, even a
complete two-pressure system could eprerequisites for this however would be that be attached to the electrical power produced 'ct heating water supply temperature be low Would be a reasonable enthalpy drop between §team and the heating condenser(s). Important Ambient Conditions eters lants for district heating, the strong effect ture has on the power output is more likely rsince maximum output is demanded when est. strial power plants, the temperature level plied affects the power output of the stearn son, the temperatures selected for the disould be as low as possible. The design temcompromise between maximum electrical sfor transportation of the heat.
a
164
COMBINED CYCLE GAS & STEAM TURBINE POWER
As in combined-cycle industrial power plants, the pressure should also be higher than in power plants generation alone. Levels of between 40 and 70 bar psig) are typical for optimum design of installations plementary firing.
4.3 Power Plants Coupled with Seawater Desalinization Units Combination of a power station with a seawater unit is one especially interesting application for Combined-cycle plants are outstandingly well sutted pose because such power plants are generally countries and ideal fuels for combined-cycle in~,taIla1 therefore easily available at a reasonable cost. Larger seawater desalinization plants are always use the multi-stage "multiflash" process. One slgnitic nical requirement imposed by the process of such is that the maximum temperature of the water limited. The reason for this is the way in which treated to prevent CaC03 deposits. Generally the volves treatment with polysulphate or sulphuric With polysulphate, the maximum temperature water can be heated is 90°C (194 OF); with SU.LptlUr'iC: °C (248 OF). The resulting heating steam pressures 1 and 2.5 bar (14 and 36 psia), which provide for a combined cycle plant because the usable in the back-pressure steam turbine is high, ensu:rin.~ trical output.
COMBINED-CYCLE PLANTS fOR COGENERATION
165
ed-cycle plants used with seawater desalinization ctrical power output and the flow of process steam oIled independently of one another. A supplementherefore recommended. Fig. 4-13 shows the prineheat balance of such a power station. 'ation process is based on a "Multiflash" system awater is treated with polysulphate. The heating eis 1.2 bar (approx. 17 psia) and the specific heat 50 kJ/kg (108 Btu/lb) distillate. This corresponds o a 20-stage desalinization plant. The main techshown in Table 4-3. of this type becomes very interesting if the value electrical yield is high. Even if the process heat tire loss, the electrical efficiency reaches approxa value is attained in a conventional steam only electricity is being produced. The is less suitable if the ratio between fresh power must be high. The power coefficient In such a case, either the additional steam desalini,zation unit must be supplied from an different type of power plant must be chocoefficients can be attained using steam turbines. However, the significant only a negligible amount of cooling wa,rolce~;s is lost and the unit becomes more com-
166
COMBINED CYCLE CAS & STEAM TURBINE POWER P
PLANTS fOR COCENERA HON
167
Table 4-3: Main Technical Data for the Cornbined-C Plant Coupled to a Seawater Desalinizat Air temperature Fuel Gas turbine output Steam turbine output Station service power
.-t -0'"
Heat input to the gas turbine (LHV) Heat input to the supplementary firing (LHV) Rate of fuel utilization Power coefficient Electrical yield
~
0
New power output of the plant Process steam flow Distilled water flow Process steam pressure
;::l
rJl rJl (1)
....
0.
~
"
oj
.-t
..a .....
~ ~ .~
..,~
r-
>: oj
p:;
In
....(1)
CD In~
~
In
0
p..
00 00 -0
.-t
0
VI -0
~ CD
VI
cD
~ ~
.....
In 0-
~ ~
VI 0-'" 0
b1J
.S .., oj (1)
::t1 (1)
II
II
U
)£::1: >. 0. . 0 .,j
"
CD
N
(1)
~VI oN
>:
:.0
..... U"l
80
Co) oj
'0
..:ll
(1)
0.>:
8:0 oj .... ~
;::l
PilE-<
...... ...... CD
..;.
U"l
biJ ~
.-t
rrl
..-
~ ..... U"I
r-
0 U"I
..a 0
r-
168
COMBINED CYClE GAS & STEAM TURBINE POWER
COMBINED-CYCLE PLANTS fOR CO GENERA HON
Figure 4-12
4
4
4
bar
I
~
Fig. 4-12: Combined-Cycle Heating Power Plant with Extracti(m}ICoIldeIl Turbine 1 Heating circuit 2 Heaters 3-4 Heating condensers
5 6
Preheaters Condenser
Pee = 247.8 MW OPS= 283 MW COl:nbinecl-C~~cle
6 7 8 9
Power Plant Coupled with a Seawater Feedwater tank Pressure reducing stations Supplementary firing Fresh air fan
169
Chapter 5
COMPONENTS
in the most important component in the comturbine power plant. The combined-cycle to become a competitive thermal process of the rapid development in the direction of inlet temperatures.
",,~a"'Ll
de'veJ.opmEmt in the turbine, there has also been the compressor. Today the compressor can mass flows and higher pressure ratios, maka""."'UL considerably higher power outputs and costs and improve efficiency. historical development of maximum air flows temperatures. Inlet temperatures are higher in industrial gas turbines. In a jet turbine, lornirlaIllt role: procurement and maintenance than with stationary gas turbines, where overhauls are demanded. For that reahigher inlet temperatures and greater pf()gress:ed more rapidly injet turbines than lltl)lIl,eS can be classified into one of three cat-
fllT'hi-r,,,,,,
derived from stearn turbine
171
172 COMBINED CYCLE GAS & STEAM TURBINE POWER
• industrial gas turbines derived originally from technology
COMPONENTS
173
Technical Data of the Most Common Turbines Available on the Market
• the aero-derivative turbine, consisting of a jet e followed by a power turbine The last of these is normally a two-shaft turbine iable speed for the compressor and the driving turbi an advantage with regard to part-load efficiency since th of air taken in is reduced due to the lower speed. advantage when operating with a generator, howey there is no compressor braking the power turbine shedding. Two-shaft turbines are usually used or pump drives, where the operating speed of bine is also variable. On the other hand, tln'hil,"'':;:' two types are practially always built as MlllU'e-::>naII when used to drive a generator with an output to 20 MW. Fig. 5-2 to 5-4 show typical modern each of the three main types. One important fact is that the machines have dardized. As a result, they can be built as stock possible shorter lead-times and lower prices. tlecal11SE:; dardization, there are only a few types of m,leIllIl on the market and it is never possible to buy an power capacity. However, the advantages hr{)l1cU, ardization outweigh this consideration. Table 5-1 shows the characteristic data of m()ClE~rI1 used for combined-cycle installations.
1 - 150 28 - 35 10 - 18 950 - 1150 480 - 570 30 - 500
MW %
°C °C kgls
definition. Actual hot gas temperatures are 100 360 OF) higher, depending on the amount of ~qulired for the turbine.
ern with gas turbines lies in how fast their deen progressing. They are developed primarily rbine alone. But because fuel costs are also attempt is being made to make a correspondgas turbine efficiency and to reduce the specirequired for them. As a result, turbine inlet erisen very quickly, which has not in the past Hive effect on availability. tifue, this situation has changed and gas tura very high reliability. They can therefore base-load or medium-load combined-cycle the same high availability as conventional er plants. pplications, fouling in the compressor and fer concern. Compressor fouling occurs beoperates in an open cycle, drawing in air eaned completely. Turbine fouling becomes ch "dirty" fuels as crude or residual oils
COMPONENTS
174 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
o
,. 0,
o
Fig. 5-1:
Historical Trends in Gas Turbine Inlet Temperatures the Years
Note:
The gas turbine inlet temperature indicated is the ture before the first stage of the turbine. The inlet by ISO is 150 to 250°C lower in modern gas tUI·birles. temperatures reached in jet engines.
175
176
COMBINED CYClE GAS & STEAM TURBINE POWER
Figure 5-3
23
Fig. 5-3: 1 2 4 5 6 7 8 9
10 11 12 13
Diagram of an Aero-Derivative Turbine
Intake housing Starting shaft Acoustic hood Base frame for gas generator Transition housing connecting gas generator and power turbine Power turbine Diffuser and exhaust housing Auxiliaries and ancillaries Power clutch Base frame for power turbine and driven machines Mechanically driven lube oil pump for power turbine and driven machines Machine-mounted AC generator (optional equipment
14
15 16
17 18
19 ~
21
Z>23 2A 25
Electrically powered lube power turbine and DC powered lube oil the power turbine Oil intake pipe, with str Oil vapor extraction oil motor Switch-over twin lube Constant pressure Lube and hydraulic generator Lube oil tank for gas air/oil heat generator Cooling air fan, Cooling air fan, motor Fuel control
COMPONENTS
177
COMPONENTS
178 COMBINED CYCLE GAS & STEAM TURBINE POWER
Compressor fouling is countered by installing an air system that is suited to the environment at the plant filters most frequently employed are self-cleaning or 2-stage filters. The first of these is particularly ;:)UJlIA.JLJle. climates. It is helpful in a base-load plant to oversize in order to limit the rate of fouling. It is, however, impossible to keep the compressor clean. The fouling that results causes losses in oU1tPtlt ciency that are greater in single-cycle gas tm'biIles combined-cycle plants. This is due to the fact that in cycle plants, some of the losses can be recovered in cycle. Typical degradation after 1000 - 2000 hours in on a clean fuel: • Reduction in output from the combined-cycle 3to6%
• Reduction in efficiency of the 2 to 3 %
coml)in.ed,-c~ycle
Two types of cleaning can be used to help rpc"o"pr a) a "dry" cleaning, using nutshells or rice b) washing The second of these methods is more suita])le dern gas turbines because it is more efficient age to protective coatings on the compressor it requires shutting down and cooling the enlgm.e to wash at low speed- typically ignition SD,eec:I' chine cold. The machine must therefore be for approx. 24 hours. The compressor wa,Shimg with the gas turbine at full load, but this low-speed washing.
179
the turbine is due mainly to the ash contained in in the additives used to inhibit high temperature TUlrbJine fouling is unavoidable, but it can be held selecting the correct type of additives. It is less peaking or medium-load operation because of effect produced by start-up and shut-down. ·ad~l.ticln in
combined-cycle plants after 1000 - 2000 tion on heavy or crude oil: in output from the combined-cycle plant efficiency of the combined-cycle plant as]ling of the cold turbine and compressor makes ~C()VE~r from 50 to 80% of these losses. )rrlosi.on problems were one of the major causes Because of the use of better blading maproblems of this nature have today pracWI1P11P"er uncleaned fuels are being burned, :()nlta:ining vanadium or sodium, it is necessary T\ri"',,~'nt high temperature corrosion. The adare based on magnesium, chromium, or
are the links connecting the gas and the are three main types: without supplementary firing with supplementary firing with maximum supplementary firing
COMPONENTS
180 COMBINED CYCLE GAS & STEAM TURBINE POWER PtA
As can be seen from Section 3, the first of these most interesting and the remarks that follow then~f(llrp trate mainly on it.
5.2.1 Waste Heat Boilers without Supplementary Firing A waste heat boiler without supplementary firing a heat exchanger. However, the requirements imlPos,e eration in a combined-cycle installation pose spE~ci::tl that are often underestimated. In particular, nr."'ulcl",.... made to accommodate the short start-up time of the Even so, the waste heat boiler is a simple com}:)Orlel1lt reliability and availability. Waste heat boilers without supplementary firing according to two principles: • stearn generators with forced circulation type), • stearn generators with natural circulation Either type of waste heat boiler can be used cycle plant. A forced circulation boiler has ad'va]1taL~~ that render it especially suitable for cOlnbin(~d-cy,cle • minimum space requirements arising from design • fast, easy start-up • suitability for designs with a low pinch • less sensitivity to steaming out in the The main advantage of a natural circulation pumps are needed.
\.;U\.;UJlal-J.UH
181
UID waste heat boiler IDust fulfill the followingcontradietory-conditions: of waste heat utilization must be high (high y);
lOsses on the flue gas side must be low in orvent losses in power output and efficiency turbine :rature corrosion must be prevented re gradient permissible during start-up must ly difficult to meet the first two of these cone time. Because of the low temperature, the s place- transfer by means of radiation is completely by convection. Since the differUre between the exhaust gas and the water mall in order to attain a good rate of waste surfaces required for the heat exchange are ean large pressure losses unless the speed elow, which would again increase the size e surface. However, this problem can be by using small-diameter finned tubes. Ansmall tube diameter is the small amount of ator. This means that the thermal capacity -vors quick changes in load. "lers being built today have very low pinch ure drops on the flue gas side. Values of Jat pressure losses of 25 to 30 mbar (10 inable. kal modem forced-circulation waste heat
.rrtent, with the heat exchangers susel structure
182
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANT:
COMPONENTS
• circulating pumps to assure constant circulation within the evaporator • drum hung directly on the stearn generator • finned tubes used for all heat exchange surfaces Low Temperature Corrosion When designing waste heat boilers, one must take vent or at least to restrict low temperature corrosion. all surfaces in contact with the flue gas must be at ature above or only slightly below the sulphuric When burning a sulphur-free fuel, the limit is detel'fui the water dewpoint. Because the heat transfer on the flue gas side is on the water side, by a factor of approximately assumed that the temperature of the metal in same as the water or stearn temperature. The ur<:li-".,. ture should therefore nowhere be below the de when the flue gas temperature is very high. It however, to drop slightly below the dewpoint for because the rate of corrosion in that range re:ma~irtl 5-6 [taken from Ref. 97] shows the relationship due to corrosion and the temperature and conc,en'liI phuric acid in the flue gas. Points worth noting hand, the maximum between 100 and 130 °C and, on the other, the rapid increase when the below the water dewpoint. The acid rI",,·.. rn,o;r,'Ithe following factors: • the amount of sulphur contained in the • the excess air in the combustion • the rate of conversion X of 802 into • the amount of water contained in the
Heat Boiler without Supplementary Firing
183
184
COMBINED CYClE CAS & STEAM TURBINE POWER
Figure 5-6
185
te of conversion X from 802 to 803 depends on the type llrbine. Normal values are between 1 and 8%. Fig. 5-7 .om Ref. 97] shows how the acid dewpoint depends on ur content of the fuel, the rate of conversion X, and air coefficient.
a
I
corrosion attack is not rapid if the temperature only y below the dewpoint, and the surface temperature is also a few degrees higher than the water temfeedwater temperature with fuels that contain sul5 to 10°C (9 to 18 OF) below the theoretical acid
80
120 At
--=--.-..- to
Fig. 5-6:
COMPONENTS
A2
Material Loss due to Corrosion, as a Function of Ternperat:ure Concentration of Sulphuric Acid Acid dewpoints Concentration of sulphuric acid Material loss
lphur-free fuels, the feedwater temperature must circumstances be below the water dewpoint beI"apid increase in the rate of corrosion as soon as rature falls below that limit. y,suitable precautions (selection of materials, ad.eit possible to operate heat exchangers at temthe acid dewpoint. However, the effectiveness economics of such measures are questionable tional heat obtained is low in value due to its 'ctes guidelines for feedwater temperatures. n of Feedwater Temperatures 140 - 145°C 110 - 130 °C 50 - 60°C
COMPONENTS
186 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Figure 5-7
187
um design of a Waste Heat Boiler
10 2 ....---.----.-----..,.----........-------.........--.. %
s·x
n designing a waste heat boiler, one should strive for an m between cost and gain. The cost depends mainly on exchange surface installed. The indicator generally used inch point of the evaporator (the minimum difference rature between the water and the flue gas). As can be Fig. 3-22, the area of the evaporator increases exponenhe temperature differential decreases, while the instearn generation is only linear. For that reason, the tselected is the critical factor determining the heatOin installations where a high value is attached to the pinch point is 10 to 15 K (18 to 27 OF); where .
1 :x;change surface constitutes 40 to 50 % of the total r, while the other 50 to 60% remain practically the size of the surface. In an extreme case, too change surface can cause pressure losses on the be such that the resulting reduction in power iency of the gas turbine is greater than the power by the stearn turbine. A pressure drop of 10 reduces the power output and efficiency by apa portion of this loss can be recovered in the
120
l"ation [105] In affecting design of the waste heat boiler
Fig. 5·7:
Acid Dewpoint as a Function of the 8ulphur Content Conversion from 802 to 803, and the excess air
TS 8 X A.
Acid dew points 8ulphur content of fuel Rate of conversion from 802 to 803 Excess air ratio
'tlpof the gas turbine. The rapid expansions start-up can be accommodated taking suit'Qns such as suspension of the tube bundles,
the rate of loading arises from the drum.
art possible, the walls of the drum should
188 COMBINED CYCLE GAS & STEAM TURBINE POWER
be as thin as possible, which can be done provided live stearn pressure is low. Optimum stearn pressures for installations without tary firing are low, 30 to 70 bar (420 to 1000 psig), advantage for quick start-up. Another operating problem is the volumetric ChanJ1: the evaporator during start-up. The large n;1Pforo,n.r>"", volume between water and stearn at low and mediuIn cause large amounts of water to be expelled from th ator at the start of the evaporation process. The dru able to take up most of this water since otherwise amount of water would be lost through the emergEl of the drum during each start-up. The gross volume of should therefore- depending on starting time and a water loss- be 1.5 to 2.5 times as great as the vol aporator stearn in normal operation. This problem of change can be held within bounds by employing r so that at least no steaming out occurs in the eco improve part-load efficiency and behavior of the co plant, it is possible to operate the boiler at varial:H The system is generally operated at a lower pr the steam turbine load is lower than at full load. accomplished by employing sliding pressure ope Chap. 7). For example, for half-load for the powe whole, the waste heat boiler in a system with 2 and 1 steam turbine can be operated with only 0 turbines running at full load. The live steam. sliding pressure operation is only half as great load, which causes the volume flows in the e superheater, and in the live steam duct to dOll in operation is still at full load while the conn bine is at full load.) One consequence of this re steam pressure at part load is that some of the
COMPONENTS
189
tn the economizer. In order to keep this within onomizer is generally so dimensioned that the the outlet is slightly under-cooled at full load. ~between the feedwater temperature and its sa~rature is known as the "approach temperait causes a reduction in the amount of steam QuId be kept as small as possible, typically 5 to
Heat Boiler with Limited fuentary Firing fOperation of a waste heat boiler with limited 'ng is the same as that for the unfired boiler. designs available for the firing itself. Units a gas temperature of approx. 750°C (1382 lementary firing can be built with simple duct ~q\.liring cooled combustion chamber walls (Fig. icularly well suited to burning natural gas, 'sno problem in attaining a uniform temperfter the burners and the radiation to the walls hamber is low. For that reason, most of the l.lction bum natural gas. There are systems goil but because they involve major problems, eridea to look for a different solution whenOlume of oil must be burned. A cooled comith oil burners such as that used in generators is one good method of providing .iFig. 5-9 shows how it is constructed. The fa natural circulation portion, used to cool ber, and a forced circulation portion. In ~ssary throttling of the flue gas flow, it may ythe burners directly with cooling air from
190 COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
COMPONENTS
Figure 5-8
6
5
Fig. 5-8:
Principle of a Waste Heat Boiler with Limited SUIPpl,em'~l1j;1 Uncooled Combustion Chamber
1 Economizer 2 Evaporator 3 Superheater
4 Supplementary firing 5 Circulating pump 6 Drum
IIlIIlJ 1'1 1'1 1'1 L'J' with Limited Supplementary Firing and Cooled with forced circulation with natural circulation (Combustion chamber)
191
192 COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
If the burners are supplied directly with flue gas, the flow of the flue gas must be throttled down by approx. 30 mbar (8 to 12 in. WG), corresponding to the pressure through the burner. This reduces the power output of turbine by approx. 1.5%.
The great advantage of supplementary firing with cOloled bustion chambers lies in its operating flexibility. The the supplementary firing can be varied within a broad and the maximum temperature is no longer restricted (1382 OF). This system thus is particularly ideal for cOJl4erlE whenever a broad control range is required for the proce flow at various gas turbine loads. Fig. 5-10 shows another system with 2-stage firing the output of the supplementary firing of waste heat uncooled combustion chambers can be increased. gas is heated after the gas turbine in a first stage ature not to exceed 750°C (1382 OF). This is 11~IIn.u,,£>r1 ing in a first heat exchanger (e.g., evaporator or The exhaust gases can then be reheated in a sec:on.<1 tary firing before they flow through the final sec:tlo,n heat boiler.
5.2.3 Steam Generator with Maximum Supplementary Firing With this type of stearn generator, the exhaust gas turbine are used primarily as oxygen Ca]rriE~rs. tent of the exhausts is small in comparison to firing in the boiler. It is therefore no longer a waste heat boiler. The design of a stearn generator of this type tical to that of a conventional boiler, except generative air preheater. The gas turbine eXJlaU at a temperature of 480 to 550°C (896 to
COMPONENTS
193
her heating superfluous. Therefore, in order to make Ie to cool the exhaust gas after the stearn generator to temperature, an additional economizer is provided es over a portion of the feedwater preheating from erative preheating. The best arrangement divides the between the economizer and the high pressure feed en the fuel is gas, an additional low pressure partmizer improves efficiency. The fuel burned in the e oil, gas, or pulverized coal. Fig. 5-11 shows an exmore detailed information, see Ref. [102].
Turbine turbine used for a modern combined-cycle instalpIe machine with relatively low live stearn data. S the following main characteristics:
times are of particular importance because the ~lants are often used as medium-load units with
shut-downs. These features are required above s without supplementary firing. With a fired s that arise are similar to those in conventional fits. a stearn turbine used for a combined-cycle inSupplementary firing. This is a single-cylinder '1;hdouble exhaust section. Because the turs~ding pressure operation, no control stage ./There are likewise no extraction points begof the feedwater takes place in the waste designing such a stearn turbine, one must re'.Ye stearn temperature is lower during parttder to maintain an approximately constant
194 COMBINED CYCLE GAS & STEAM TURBINE POWER
COMPONENTS
Figure 5-10
6
5 Fig. 5-10: Principle of the Waste Heat Boiler with 2-Stage SU!lpleIl:l 1 Economizer 2 Evaporator 3 Superheater
4 Supplementary Firing 5 Circulating pump 6 Drum
GeIleTlltor with Maximum Supplementary Firing
195
196
COMBINED CYCLE CAS & STEAM TURBINE POWER PLANTS
Figure 5-12
COMPONENTS
197
at the end of the turbine, it is best to reduce the live Dr,es~;ur'e parallel to the load. Sliding pressure operation suited to this purpose. features of a stearn turbine for a combined-cycle compared below with those of a turbine for a convenplant:
·...... ",Ar
Combined-Cycle
Conventional Steam Plant
30-80 450 - 520
140 - 250
'Qleed points anst steam flow, kgIMWs
520 - 540
Yes
No 0- 1
6 - 8
1
0.6 - 0.7
of the gas or stearn turbines used in combinedecoupled directly to turbogenerators (2-pole genits with ratings less than 20 MW, however, high used that require a reduction gear. In that ~rat.ors are more economical. There would be three merators that could be considered for combined-
g¢11eI:at4ors with an open-circuit cooling sys¢tL4eratoll"S with an closed-circuit cooling sys-
open.-circllit air cooling are best with regard recluilreI1n.erlts, but problems can arise with Generator with closed-circuit air cool-
198 COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
COMPONENTS
ing are being built today for capacities up to appox. 200 M These machines are reasonable in cost and problem-free in 0 ation. The full-load efficiency of modern air-cooled turboge ators is quite high. Hydrogen-cooled generators do, in fact, a even higher efficiencies (particularly at part loads) than air-c machines. However, they require additional auxiliaries and itoring equipment, are more complicated in design, and, as suIt, more expensive. Fig. 5-13 shows a generator with closed-circuit air coolin ter is used to cool the air and can, in turn, be cooled back with air. These machines are well-suited for use with gas steam turbines with power capacities of up to 200 MVA. For outputs, or if a very high part-load efficiency is required, gen cooling must be selected. [100]
s
til '">. "' r:n
'\
00
C,)
~~
5.5 Electrical Equipment The single-line diagram of a combined-cycle power pIa ilar to that of a conventional power station containing turbines. Fig. 5-14 shows an example in which the co cycle plant consists of two gas turbines and one steam
~
I I
The power required for station service can be takenei each of the gas turbines or the steam turbine separa gas turbines can, by themselves, also supply the po auxiliaries of the steam portion. In combined-cycle several gas turbines, each group of two gas turbines nectedjointly to a three-winding transformer, produc particularly for the high voltage switchgear. Combined with an output less than approx. 100 MW generally a medium-voltage. All their auxiliaries are equipped age motors.
5.6 Control Equipment The control equipment is the nervous system of Its tasks are the control and protection of the iIl~
bll
.S
til
0
U ..c1
'""'
.~
h 0
'"t1l"'
'"
~
bll 0
..0 ;::l
'"
Eo< "0
I
I
"0
I
I
cp: ,
(J)
I I
bJ
~
10
00
C,)
,:..
:.:i!
's,
>.
Eo<
....M
J., ciJ ~
199
COMPONENTS 201
200 COMBINED CYCLE GAS & STEAM TURBINE POWER
Figure 5-14
4
+-r-r
10
10
-1----
6
6
-+--
duisit;iOll. It must provide assurance of safe and reliable . Because the standard gas turbine is supplied as a fully d machine, the steam process should likewise be corresautomated so as to achieve a certain degree of stannin operation of the plant as a whole, thereby reducing operator error. For this reason, the control and autoems of a combined-cycle plant form a relatively comeven though the process itself is fairly simple. Modern de plants generally have electronic control systems. and decentralized structure for the open and closedsystems is best adapted to the logic of the whole proies planning, makes it possible to commission the and raises the availability of the power station. If:\l1l-lclon controls as an example, Fig. 5-15 shows the fhi,en'lrchic system of this type. A highly automated system encompasses three hierarchic levels: all individual drives are controlled and mondevices in the switchgear act directly on the relays. These signals are sent both to the logical the drive level and to the higher hierarchic
11
group level, the individual drives for one comprocess are gathered together into functional control circuit on this level encompass interfh,.. switches and preselection of drives. ExfUllct;iOllal groups are:
8
rHU
12
12
Fig. 5-14: Typical Single-Line Diagram for a Combined-Cycle 1 2 3 4 5,
Gas turbine generator Steam turbine generator or 3' Gas turbine block transformer(s) Steam turbine block transformer 6, 7 Station service transformers
8 9 10 11 12
lItc:lU<1es the logical control circuits that link to one another. These include, for examstarting equipment for gas and steam tur-
202 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
bines or overriding logical controls that coordinate the operati() of the gas turbines, boilers, and stearn turbine in fully automat installations. As in conventional plants, process computers are today pI ing an important role in combined-cycle installations, since'\; can supply operators with valuable information needed to ~ optimum operation and maintenance. Some of the tasks t over by process computers here are sequencing events, k~ long-term records and statistics, optimization of the heat of the intervals between cleanings and overhauls, etc.
5.7 Other Components In addition to the major components mentioned combined-cycle power plant also includes much more and many other systems similar to those in convlen1;iOlll: power stations. For example: • condenser • cooling system • feedwater tank / deaerator • • • •
feed pumps condensate pumps piping and fittings condenser ejector system
• water treatment plant • compressed air supply • flue gas bypass • stearn turbine bypass Three different cooling systems can be cOlrlSicier'ei cycle plants:
COMPONENTS 203
direct cooling using river or seawater indirect cooling with a wet cooling tower d.irect air cooling in an air condenser the last of these three, no cooling water is required. Inair cooling requires additional water to replace evaporadrain losses. The amount needed is approximately equal fthe condensate. The first variant with direct water coolires water in an amount approximately 40 to 50 times than that of the condensate. mbined-cycle plants are equipped with flue gas bypasses ycle operation of the gas turbine(s), the design and ls.for the flue gas damperCs) playa special role. This meet the following requirements: provide a tight seal both to the boiler and to ass stack. tart-up or shut-down, it must take over the of the firing in a conventional boiler. ;;lpility must be high. If it malfunctions, the gas and the boiler go out of service. parate dampers are provided for the bypass (}the boiler, they must be interlocked with her so they can never both be closed sisly. a flue gas damper with only one flap valve. shut off either the boiler or the bypass stack. both paths can never be closed at the same
204 COMBINED CYClE CAS & STEAM TURBINE POWER PLANTS
COMPONENTS 205
Figure 5-15
z
o
..... 0« ~
o
..... ::::>
«
lL.
o
SCOPE OF MOTOR DRIVES Fig. 5-15: Hierarchic Structure of the Control and Automation
5-16: Typical Flue Gas Damper
Chapter 6
CONTROL AND AUTOMATION very power plant must cover the demand of an electrical grid er in part or completely. The equipment discussed below is in modern combined-cycle installations not only regulate ir power output but also to assure the safe start-up and own of the plants and their proper dynamic behavior.
he Concept of Closed-Loop Control d Operation osed-loop controls for a power station can be grouped into main control circuit which adjusts the output of plant to demand; condary control circuits which maintain the imfit process parameters within permissible limits. ols for levels, temperatures, or pressure are likeincluded among these. gically, this leads to the hierarchic structure of the 1 system already mentioned in Section 5.6 .
..cycle plants consisting of several gas turbines and ine, there are several possible way to adjust the ower plant: output of the gas turbines is adjusted the stearn and the gas turbines are ad-
208
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
CONTROL AND AUTOMATION 209
The first method is generally applied for plants without plementary firing because varying the steam turbine load duces only a temporary effect. Over the longer range, the from the steam turbine automatically adjusts to the amount heat being supplied by the gas turbine. It is, however, sometim suggested that a load or frequency control of the steam turbO be provided in plants without supplementary firing to han sudden increases or decreases in load. Additional complicati and the poorer efficiencies at full and part loads, and expec· the fact that the gas turbine(s) generate(s) approx. two-t of the total power output, argue generally for a solution out a control for the steam turbine power output. Fig. 6-1 shows the design of the closed-loop load controls the output of the steam turbine is not controlled. The entir cycle is operating with purely sliding pressure; the st bine inlet valves are fully open. This is the mode of best suited for high part-load efficiencies and low the steam turbine exhaust during low-load operation. level control is not absolutely necessary because the put of the plant can be adjusted by changing the the individual gas turbine controls. The output of the gas turbine is controlled by amount of fuel supplied. In the upper load ~cUI'5<:;, times also be adjusted by varying the amount iable guide vanes in the first stage of the COmI)reSS( used to accomplish this. With a system of this t inlet temperature remains constant between 80% load. Below that level, the temperature in order to protect the last turbine stage atures. If supplementary firing has been idea to equip the steam turbine with a process then operates in a manner similar tional steam plant.
"I
)
!P/f
I
--t--rfl---tI
GTR
~
~
I
~
: };Plf
-t-i T, I M
I
,---..J
, lnJ
GTR
I
IT,
KAR
L~L~ Condtrol System with no Steam Turbine Load Control l oa controls inlet temperature
CONTROL AND AUTOMATION 211
210 COMBINED CYCLE CAS & STEAM TURBINE POWER PLANTS
Fig. 6-2 shows one possible design for the closed-loop COlltfiOls: • The turbine inlet valve regulates the power output of the stearn turbine. • The amount of stearn generated is varied to fit demand by adjusting the supplementary firing in order to maintain a constant live stearn pressure. A control system of this type can be of advantage "'1"0.... & fairly large jumps and changes in power plant load are The stearn turbine is then capable of taking over a the load surges. This affects the service life of the gas t positively because it reduces the changes in load and th changes in temperature in that turbine. Up to this point, no distinction has been made betwe and frequency control systems. In principle, the remarks valid for both. However, one must bear in mind that' per load range, the gas turbine can be switched overt ature control. In that case, neither fluctuations in freq load have any influence on the plant: it is controlle the turbine inlet temperature. In conclusion, it can be said that combined-cycle very well suited to rapid load changes. The gas ttl extremely quickly because their time constant is", soon as the fuel valve opens, more added power}) able on the shaft. Gas turbine load jumps of upt sible, but they cannot be recommended sincet detrimental for the life expectancy of the turbiri change in load produces thermal stresses in the cause of the change in turbine inlet tempet:l.t
6.1.2 Secondary Closed Control Loq Fig. 6-3 shows the essential closed cont]~ol quired in a combined-cycle process wtth(>ut
maintain safe operating conditions. These will be described below:
is normally a three-element control system which forms the feedwater and live stearn flows and the level the drum. This signal is used to position the feedwater 1valve. Low pressure drums are often equipped only with -element control that uses only the level within the drum s a signal.
'~nal from
ye stearn temperature control: e of the low flue gas temperatures, no control of the temperature is absolutely necessary with unfired waste rs. If such a control is provided, it serves more as a n as an actual control. Its purpose is generally to remperature peaks under extreme operating conditions aking operation. For that reason, the cooling often after the superheater and not between two portions rheater as in a conventional stearn generator. Norpressure feedwater is injected into the live stearn team down to the required temperature. However deposits in the turbine, it is necessary to operat~ t~ fully demineralized water. This is impossible in rIal plants, which means that the temperature of In must be controlled either by mixing it with satextracted after the drum or by means of a heat
~rature control
extending over a broad load range rely waste-heat boiler operation because the turtemperatures drop off rapidly during part-load turbine. In plants with supplementary firare more like those of a conventional stearn elevated gas temperatures are possible in
CONTROL AND AUTOMATION 213
212 COMBINED CYCLE CAS &. STEAM TURBINE POWER PLANTS
6-3
Figure 6-2
I I
I
I
p
I I
--I
I
-=t-~
I I
I
I
I
I I I
BLC -LP
I I I I
JOLC-LP
I I
l
I Pit
IL_
I
:PIf
GTR
I
~
ntI t\ 11
GTR DTR p/f
T1 Ps KAR
L_
I I I
l
I
r
I
P
I
I
I
I
I I
I
rlGTR
-~ ir;=---r I ~ 11 I
L_.J
P
I
:I.Pff
I -
Fig. 6-2:
I
-r7fj---t--I
I
I
L_~
Principle of Load Control System with Steam Live steam pressure controls Gas turbine load control Steam turbine load control Load/frequency Limit for gas turbine inlet temperature Load setpoint Overall load control
I ~Il......~-r----': IL_@__ J ~ J TBC
r~::M----I>'
HLCC§f---...J L
_
Loops in a Combined-Cycle Plant without Supplementary drum level control system re drum level control system e emergency control drain re emergency control drain rature control 1, feedwater tank feedwater tank
214
CONTROL AND AUTOMATION 215
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
these cases, it is important that the temperatures of the stearn and the superheater tubes be maintained within safe limits. To do this, the superheater is divided into two or three sections with water injected between them.
• stearn turbine control valves • stearn turbine bypass • starting valve • flue gas bypass
c. Feedwater temperature: In order to keep low temperature corrosion within ac(~er;~talJl bounds, the feedwater temperature must not, even in the load range, drop significantly below the acid or water r1"""T~'''' On the other hand, this temperature must be as low as poss in order to assure good utilization of the heat available. It is th fore recommended that the feedwater temperature be hel a more or less constant level corresponding approximate
~acticallY all
combined. am turbine modern b . cyc1e p 1ants are eqUIpped with ypass, WhICh can provide several advantages: .flexible operation during st rt 1irip , or quick changes in lo:d -up, shut-down, turbine :h,orter start-up times yironmental acceptability (since less stearn escapes).
the acid dewpoint.
ed-~Ycle plants ~ith repowered conventional stearn tur-
Whenever stearn is being extracted from a turbine bleed the deaerator must be heated at part loads by using reduc stearn (back-up stearn). In plants with a preheater loop waste heat boiler, the opposite problem occurs during operation of the gas turbines: more low pressure erated than required. This excess energy must be dissip:at by increasing the pressure, which reduces the am,OUll" generated, or by directing the excess low pressure condenser.
en. ave a startmg duct instead of the stearn turbine urmg start-up, this directs the stearn either across the ~o the atmosphere, or into a starting condenser.
d. Live stearn pressure: If the stearn turbine is in sliding pressure op,er2LtiO uous control for the the live stearn pressure beco ous. However, such a control is necessary for conditions such as start-up, shut-down, or H'(UJ.ILU." pressure operation, on the other hand, the gaged at all times.
How this control is accomplished delJerlds of the power plant. In principle one or se'veJral components can be used to control the
i~a: bYP~~.iS frequently omitted due to economical in , speCI lcally for the following reasons:
ga: bypass often leaks, and a certain amount g ~usi be accepted. In addition to that flow e ~it't urther loss due to radiation. The total ~ew dampers, may amount to be5 :.nd 2% of the energy contained in the exe
bypass is fairly expensive. there are also many advantages in having flue gas bypass:
216
CONTROL AND AUTOMATION 217
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
• greater flexibility in operation • increased availability, since the gas t~1fbi~e can c~m tinue in operation even when the bOIler IS unavaIlable • reduced risk of explosion within the boiler be~ause the gas turbine can be lit off in bypass operatIOn Table 6-1 shows which live steam pressure control systems its are used for the various modes of operation of a comt>inel cycle plant with an unfired heat recovery boiler. Table 6-1: Various Control Systems Used to Regulate Live Steam Pressure Type of Operation
Steam Bypass
Steam Turbine Control Valves
+ +
+ +
Start-up Shut-down Normal operation (sliding pressure)
+ +
Normal operation (fixed pressure) Operation at low load Steam turbine switch-off or trip Waste heat boiler switch-off Gas turbine trip
+ + +
• if provided; + in operation, - not in operation
Combined-cycle plants with supplementary ally operated with a fixed live steam operation, pressure is held constant by to the boiler. The steam turbine takes over sure only in such special cases as start-up, tary firing shut-down, etc. e. Level in feedwater tank and These are controlled by regulating the cycle make-up water. What level is assigI1@t
ot particularly important: the selection depends on the size of he two tanks. f.
Other control loops
Other control loops, such as those for lube oil and control oil ssure, etc. will not be discussed here.
Start-Up and Shut-Down of the Combined-Cycle Plant bined-cycle power plants are usually started up and shut to a large extent automatically. It must therefore be posoperate the controls for units to be activated during startshut-down from the central control room. Whether the ds are to be issued to the individual drives or drive groups erating staff or from a higher-level automatic starting must be decided on a case-by-case basis. In base-load ns that operate with only a few starts, full automation am process is not an absolute necessity. The starting differs depending on whether or not the plant has bypass. with a flue gas bypass sbypass is provided, the gas turbine can be started , and loaded practically independently of the steam on as the gas turbine is on line, the steam process up. However, it is also possible to switch on the while the gas turbine is in load operation. The J:"S are used to adjust the heat supply to the requireaste heat boiler. It may be necessary to place a flue gas temperature during a cold start of the if the superheater cannot handle the full flue with()Ut being cooled. The steam turbine can as the steam data are high enough, which the steam must have reached about 40 to and by1superheated by at least 50 to 80
218
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
The bypass stack is used for light-off of the gas turbine. If the flue gas damper closes 100% tight, no purging of the waste boiler is required prior to start-up since no fuel can get into boiler even if fuel system malfunctions should occur. If the gas damper is not 100% tight, it is best to purge the boiler beJtore starting the gas turbine, particularly after a malfunction or overhaul. Until the steam turbine takes over the full steam flow, excess steam flows across the steam turbine bypass or the st ing valve. If supplementary firing has been provided, it m not be lit until the gas turbine is at full load and the steam bine has taken over the entire steam flow. With the supple tary firing on, the steam process can then be further 10 The plant is shut down by shedding load from the gas tu (or first, from the supplementary firing). Once the flue perature has reached a prescribed minimum level, the st bine is shut down. The boiler and the gas turbine are unloaded and shut off. The bypass damper must be the boiler damper closed before shutting down the b. Plants without a flue gas bypass Here attention must be paid to the steam process
CONTROL AND AUTOMA TlON 219
6.2 Dynamic Behavior
Th~ dynamic b~havior of modern combined-cycle plants is char-
ften~~d by theIr short start-up times and quick load ch pablhty. ange
bove .all, the ~as t~rbine can be started and loaded quickly. ause Its reactlOn tIme is also short, it is capable of following k changes and surges in load. Generally, load changes are tuated only ~y adjusting the turbine inlet temperature. As ~lt, everY,maJor change in load reduces the life expectancy gas turbmes more than would be the case for a steam turIf there are variable guide vanes at the compressor inlet d~ce the thermal stresses in the upper load range becaus~ d IS regulated with a constant turbine inlet temperature. ~r: one factor negatively affecting expected service life ~lS temp~rature is, on an average, higher than that in employmg only throttling of the fuel supply. ~m process with an unfired waste heat boiler has 1
dat~. It is therefore quite capable of following t~: -up times of the gas turbine. However, the steam turhe waste heat boiler must be designed to withstand ses.
ing the gas turbine since the entire flow of flue gas p
the boiler. Particularly during a cold start of the waste the gas turbine must not be loaded at full speed or temperature change in the boiler drum would excee mum level permissible. A second minor problema. light-off of the gas turbine, during which a high pe the flue gas temperature. In order to prevent explosions, it can be advisaq with oil-fired gas turbines, to purge the boiler }) the gas turbine. This is done by operating the g3$ nition speed for a few minutes, without ignitiIlg the start-up and shut-down of combined-cycle without flue gas bypasses are very similar.
ombined-cycle plants with ratings between 100 and be started within the following times: (after 8 to 14 hr. at standstill): 20 to 50 : 60 to 120 minutes turbines are already at full load after 10 to o~ the power output is already available after m a cold start.
CONTROL AND AUTOMATION 221
220 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Fig. 6-4 shows the example of a 120 MW combined-cycle plant which can be brought to full load in an little as 26 minutes after 14 hours at standstill, and that with a normal start of the
Figure 6-4
turbine. Because the time constant of a combined-cycle plant is low, the plant is well suited to handling quick changes in loa When used in grids that often call for larger changes in load however, special precautions must be taken because the ste turbine cannot make any sudden jumps in load during slidi pressure operation. The entire surge must therefore be acc() modated by the gas turbine, and that can, over the long raIl mean severe stressing. Operating the steam turbine at a fixed pressure improve situation somewhat. Equipping the waste heat boiler with plementary firing to increase the portion of the surge th be taken up by the steam turbine is another possibility. ever, since it increases the share of the share nf1,rti'Al1 reacts more slowly, it does not make the plant more
f1..p 10
1S
Start of a 120 MW Combined-Cycle Plant turbine output turbine output turbine exhaust temperature turbine output speed pressure live steam pressure pressure live steam temperature pressure live steam flow pre,ssure live steam pressure pressure live steam temperature live steam flow pressure
Chapter 7
OPERATING AND PART-LOAD BEHAVIOR way in which a power plant responds to changes in its e conditions (ambient conditions, part load) is of great imce both for its economy and its safe operation. It is thereportant to have precise knowledge of both the steady-state dynamic operating behavior of the plant. tical calculation of the dynamic behavior is costly and . For that reason, one frequently limits himself to opperience in other similar plants or to estimates. A more lation of the behavior would certainly be advantageis usually omitted due to considerations of time and Cases, however, the calculations of steady-state operpart-load behavior should be completed.
U sed for Calculations tion of the steady-state part-load and operating besteam portion in a combined-cycle plant differs rom that for a conventional steam plant. The difve mainly the boiler and the operating mode of waste heat boiler, the heat is transfered mainly vection, while in a conventional boiler it takes iation. pine of a combined-cycle plant functions most g the sliding pressure - sliding temperature pro"uncontrolled." The steam data are deter-
223
224
OPERA TlNG AND PART-LOAD BEHA WOR 225
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
mined only by the exhaust flow and exhaust temperature of the gas turbine and by the swallowing capacity of the steam turbine. In contrast, a conventional plant is generally operated at a fixed pressure, Le., the live steam pressure and temperature remain constant. That simplifies calculations because the steam pressure and the steam temperature are known in advance. The steam turbine and the boiler can therefore be considered independent of one another. Calculations for the gas turbine are no problem since one is dealing with standard machines for correction curves are available to account for changes in bient conditions and for part-load operation. Statement of the Problem Calculating the operating behavior of an installation dir'ec1tlj from the geometry of that unit would be very time-consumi The process can, however, be simplified by referring all val to the thermodynamic data at the design point. If that de point is known, general equations (the Law of Cones, heat t fer law, etc.) can be used to reduce the calculation proble a reasonable number of equations, without the necessi considering the dimensions of the unit itself. A brief stl1 the details of the method for calculation described in Ref. can be found in the Appendix to this Chapter.
striking, but the efficiency of the combined cycle is approximately 50% higher at every point than that of the gas turbine. In other words: the ratio between the outputs of the gas turbine and the steam turbine remains approximately constant across the entire range of loads. Fig. 7-2 shows the curves for power outputs and live steam data. These calculations have been based on purely sliding pressure eration above 50% load. Below that point, the live steam presre is held constant by means of the steam turbine inlet valves. .e striking point shown in Fig. 7-1 is the quick deterioration fficiency at part loads. This is due to load control of the gas ine (by changing the turbine inlet temperature). At part-load single-shaft machines, the flow of intake air remains prac"':( constant. When the load is reduced, the turbine inlet temure drops. This also lowers the average temperature of the eing supplied and thus the efficiency. Improvements could ined by: duci~g
the amount of air taken in during part-load ratIOn talling several gas turbines
'r flow can be reduced by:
lling variable inlet guide vanes in the compressor
7.2 Part-Load Behavior A careful economic evaluation must also give consi<:i to the part-load behavior of a power plant. Power plal.1 also have as high an efficiency as possible at part-Ioad~ dern combined-cycle plants without supplementary fi efficiency of the plant as a whole depends mainly ficiency of the gas turbine. Fig. 7-1 shows the efficiency curves for a gas combined-cycle plant, based on the full-load ef:l:iCle gas turbine. The similarity of the paths of these
eating the intake air two-shaft machines
it machines are available only for low ratings: they the disadvantages cited in Section 5.1. Compressors Ie inlet guide vanes are offered for use in cornbinedby several suppliers of gas turbines. Using this power output can be rduced to approx. 80 to 85% ~nge in the turbine inlet temperature. Below that ttemperature must be reduced to avoid overheat~• turbine stag~
226
OPERA TING AND PART-LOAD BEHAVIOR 227
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Figure 7-2
Figure 7-1
200 _----.----.-----r-----,
r------,..-----r------,-----,..---.,..-_
0.60 0.55
--+-:=-~1---+0.50 PST 0.45
150 ...!----t----+------:::.;;;;;t'......,.-==-----t
PGT
+----/---+---4----+----1--1-,0.40
'1G T100 100 -I-_ _~L--_...~~----i-___ 110 0/.
jl---+----jL--4-100
50 +----f.:J~_+---+_--___r_- _____
90 I-I-----+----+---.I/C.-----!-------j~--+---l-
/
o
/
100
S
50 40 100 110
+_--t---+---i-----I-----+----+.
80 %
Part-load Efficiency of the Gas Turbine and the COTIllbuled·,q Combined-cycle plant Gas turbine Base load Peak load
PIPGT100 Relative power output T1/T1GT100 Relative efficiency
*
60
150
20
G
70 PLSo
______-__t----.~__t--~L----j---___1f---l-
50
PI PGT 100 Fig. 7-1:
PLS PLSo
80 PLS
Reference 100% load of gas turbine
Outputs and Live Steam Data of a Combined-Cycle Plant at Part
power output of the combined-cycle plant turbine output to gas turbine output live steam pressure temperature
228
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
OPERA TlNG AND PART-LOAD BEHA VlOR
229
Figure 7-3
Fig. 7-3 shows the part-load efficiency of a combined-cYcle plant with variable inlet guide vanes. There is a perceptible im~ provement over the entire load range as compared to turbine employing temperature control alone. The advantage of preheat ing the intake air is that there are no particular difficulties .• doing it. This increases the efficiency of a combined-cycle pIa (refer to Section 7.3), but, of course, a source of heat is requir Fig. 7-4 shows an example where the air is preheated us' low pressure steam from a waste heat boiler. Fig. 7-5 shows efficiency of a plant employing intake air preheating. In the per load range, the efficiency here is even better than with iable inlet guide vanes, but this system has the disadvantage its effectiveness drops off when the ambient temerature is The air can only be heated to approx. 50 - 55°C (122 - 13 without exceeding the limit imposed by compressor surg To make an even greater improvement in part-load effie! a design employing several gas turbines should be use combined-cycle plant. This makes it possible to shut d dividual gas turbines at part loads. The other gas turbi run at a higher load and a higher inlet temperature, erts a positive effect on the overall efficiency. Fig. the part-load efficiency of a plant with four gas one steam turbine. The load of the plant as a whole as follows: • down to 75%, there is a parallel reduction in all four gas turbines • at 75 % one gas turbine is shut down • down to 50%, there is a parallel reduction the three remaining gas turbines • at 50%, a second gas turbine is shut down • etc.
110
I R-IGV
100
90
~
0
........... ~ .......
~...-'" ....
~
...
...
-------
./
V
60
90
100 % 110
......-- (( PLANT WITH VAR IABLE IGV -- (( PLANT WITHOUT VAR IABLE IG V Efficiency of a Combined-Cycle Plant with Variable Inlet in the Compressor e efficiency of the combined-cycle plant e power output of the combined-cycle plant inlet guide vales the variable inlet guide vane control
230
OPERATING AND PART-LOAD BEHAVIOR 231
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Figure 7-5
Figure 7-4
11 0 .---r----r---,------,--~-----. R-APC 0/0 100 -r---t--+---b--0Il!===F---sJ.-~~
90 r-----:71:::...----:.:<""'4---+---+---+----I
3
" 7-4 : F 19.
Combl"ned-cycle Plant with Preheating of Gas Turbine Inlet Air
1-17:
refer to Fig. 29 preheater Control valve for air preheater
18
19
70 t---t---t---+---+---+----I
60
90
100 % 110
CC PLANT WITH AIR PREHEATER CONTROL CC PLANT WITHOUT AIR PREHEATER CONTROL Efficiency of a Combined-Cycle Plant with Preheating of Gas Inlet Air efficiency of the combined-cycle plant power output of the combined-cycle plant gas turbine air preheater control
232
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
OPERA TlNG AND PART-LOAD BEHA VlOR
233
this mode of operation, the efficiency at 75 %, 50 %, and load is practically as high as that at full load.
Figure 7-6
The Effect of Ambient Temperatures 100+----
90 L
11K 11Ko
.1 Effect of the Air Temperature
--A-+--I-+-+++-t--,-
70-l--I--J----.-!--i---t---i-----r-60-l---+---t---t--i---r--
the design point, the air temperature exerts a great influover the power output of the gas turbine and the combinedplant. The behavior of the plant designed responds to es in the air temperature in a way similar to that described ion 2. In particular, efficiency increases slightly here, too, air temperature rises while the vacuum within the conremains constant (refer to Fig. 3-9). When, instead of river ith a constant temperature, air is used either directly ectly to condense the stearn, the efficiency of the cycle es as the temperature rises. In that case, the behavior ger comparable to that indicated by the curves in Secince the stearn turbine designed for this case has been d for a given condenser pressure.
oling Water Temperature
50.!---+--+---t---t-----80 40 60 20 o PKI PKo Fig. 7-6:
Part-load Efficiency of a Combined-Cycle Plant with Four
PKJP:Ko
Relative power output of the combined-cycle plant Relative efficiency of the combined-cycle plant Number of gas turbines in operation Base load Peak load
TJK/TJKO 1...4 GT G S
in the cooling water temperature affects the volume haust stearn. Quite quickly, the exhaust stearn volo longer is correctly adapted to the size of the tur. This either increases exit losses when the falls or, if the temperatures are higher, increases r pressure, thereby reducing the enthalpy drop in he operating behavior is thus quite different from in Section 2, in which the size of the turbine is lalJlvl::U to the temperature of the cooling water. effect of the cooling water temperature on the power output of a stearn process.
234 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Figure 7-7 1.008...---.-----y--.-----,--,-,__
1.006L-L----4--+--+--t--r
1.00 ltL-t---I--+--j-----tJt-----y-
1.002L-+----t---+--~-r-___t_____
IlK 'lKo
1.00 ol--+--+--~F---r--I ____
0. 998 L
-L---l---+---t---t_____
0.996 L-L.---I-----i---+----r---3
4
6
B
10
few Fig. 7-7:
Effect of Cooling Water Temperature on the Efficiency cycle Plant (Operating Performance)
tCW
Cooling water temperature
OPERA TlNG AND PART-LOAD BEHA VlOR 235
Aceptance Tests and Commissioning 1 Acceptance Tests cceptance tests for a combined-cycle plant are always a speproblem because the gas turbine, waste heat boiler, and steam ine all interact upon one another. It is therefore best to award racts for combined-cycle plants to a single general contracho will assume responsibility for supplying the entire plant turnkey or a semi-turnkey basis and who guarantees the r output and efficiency of the plant as whole. For combinedplants, it is easier in any event to measure the values gued for overall plant performance than those for each maponent indiVidually. The amount of waste heat supplied 'Waste heat boiler by the gas turbine, in particular, cannot sured accurately. When overall values are guaranteed, I flow, electrical output, and ambient conditions of the lant must be measured. These are quantities which can mined with relative exactness.
hnical values guaranteed for a power plant or one of ¢omponents are valid only if all ambient or design conas defined. Suitable correction curves must be used r any deviations. Thus, for example, the effect that perature has on the power output and efficiency of e must be measured and - if need be- correction de. ntional power stations and for gas turbines, the meor corrections are described in the standards (e.g., IUN, etc.). No standards have yet been established -cycle plants. We will therefore indicate below one tion to this problem that has proven useful. is that a limit must be defined around the plant components and systems supplied by a given
236
COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
contractor are included, and only those components and systems All others for which he is not responsible are excluded. The guaranteed values must clearly define the ambient or desi~ conditions for which they are valid, Le., the conditions as m sured at the limit defining his responsibility. In the case combined-cycle plant used for power generation only and plied on a turnkey basis, such values and the marginal tions to be defined might be as follows: a. Guaranteed values e Overall power output of the combined-cycle plant
OPERATING AND PART-LOAD BEHAVIOR
237
way, one takes into account the fact that the model for calculations is, strictly speaking, valid only for the etical (guaranteed) installation, not for the installation as ually has been built. This method is especially suitable if uteI' programs are used for making the corrections, since can best calculate the behavior of the theoretical plant. standards, however, recommend a second, reverse pro. The values measured are corrected to the design conof the guarantee, since in many cases, guarantees must for several load points. In a contract, it is best to make for this fact by using a guaranteed weighted average
e efficiency b. Design or Ambient Conditions for the Guarantees e Air temperature e Air pressure e Relative humidity e Cooling water temperature, and flow (if cooling pumps are supplied by another party) e Frequency e Power factor of the generators e Voltage c. Comparison between Measured and GUlar:an1Gee:d Two different methods can be used for doing this. the values measured are compared with those guar2mt' lows: e Correction of the guaranteed values to the conditions at the time of measurement e Comparison of the data measured with rected guarantees
e marginal conditions are generally used for all load tone can scarcely assume that the ambient conditions il will actually remain unchanged while all load points measured. The theoretically correct procedure thus athematically and contractually to unsolvable probculating the average value measured. On the other the procedure indicated in the standards is used , (fpoints are corrected to warranty conditions. There blem in comparing guarantees with measurements. tical arguments favoring the first of these procecountered by recognizing that the ambient condi~ct the theoretical and the actual plants in similar ~edure in the standards is therefore not incorrect.
ill ambient conditions must remain within bounds a,sllf('~ments. This is another reason why the corvalid both for the theoretical and for the acnot cause significant error.
OPERA TlNG AND PART-LOAD BEHA VIOR 239
238 COMBINED CYCLE GAS &. STEAM TURBINE POWER PLANTS
Correction of the Measured Power Output of a Combined-Cycle Plant It has proven to be a good idea to correct the power outP11ts
of the gas turbine and the stearn turbine separately. For the g turbine, the usual correction curves are used to take into accourl. the effects produced by air temperature, air pressure, rotation speed, etc. The power output measured for the stearn turbine is correc using curves that show the indirect effects of air temperat air pressure, and gas turbine speed on the stearn process the direct effect of the cooling water temperature. To calc these curves, it is best to use a computer model which simu the stearn process as a whole (refer to Section 7.1). Chan the data of the ambient air produce changes in the gas t exhaust data and these latter affect the power output stearn turbine. The advantage of this procedure is that it can, adaptations, be used even if the gas turbine is put tion at a somewhat earlier date than the stearn ing to the standards, both the gas turbine and the must be measured as new machines. That necessarily a certain time interval will separate the gas turbine measurements. To demonstrate that the guarantees have been aranteed power output is compared with the nOWE~r sured and corrected. The power output, measured and corrected, is lows:
PI< -Corr
PST-Corr
+ PGT-Corr
rrection of the Measured Efficiency a Combined-Cycle Plant he guaranteed efficiency of a combined-cycle plant without plementary firing may be written in the form: 17K
PST
GAR =
+
L; P GTi . =
L; Qc;Ti
PK L; QcTi
(19)
compare the measurements, the heat flow supplied must rrected. The measured and corrected efficiency is then obfrom the equation:
_
.... CORR -
L;
PK CORR . QcT - CORRi
(20)
good idea to present the correction curves for gas tursuch a way that the heat input can be corrected directly
simportant whether or not the waste heat boiler is ""ith a flue gas bypass. If so, the gas turbine can be pendent of the stearn process. Moreover, an earlier g of the gas turbine is quite conceivable, since stanturbines have a shorter lead time than stearn tur.are designed and built on a case-by-case basis. ioning of the stearn tubine can be similiar to that ()nal stearn turbine plant, with the flue gas dampcing the boiler firing. If there is no flue gas byl.lrbine and the waste heat boiler must be put into llel to one another. The gas turbine cannot start has been mape ready for it and, inversely, the tart until there is flue gas available for it.
240
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Otherwise the commissioning of the gas turbine ar: d the steam processes is similar to that of conventional installat~ons. attention must be paid to coordinating the operatl.n g mod~ the waste heat boiler, the gas, and the steam turbmes. ThIS even more particularly the case in fully automated plants.
Chapter 8
COMPARISON OF THE COMBINED-CYCLE PLANT WITH OTHER THERMAL POWER STATIONS ions 2 and 3 show that combined-cycle plants are thermoically attractive. Thermodynamics does, indeed, play an ant role in selection of the type of power plant, but it e only criterion for decision. Such other factors as price, mental impact, fuel availability, etc. must also be taken ount. following, we will compare the combined-cycle plant I' thermal processes in order to determine those cases t is actually of interest. competition comes at present from steam and gas er plants and that situation will not change in the For smaller to medium power outputs, however, er plant can also be a genuine alternative. The high modern diesel engines is comparable to that of a Ie plant with the same power rating. Up to a power 30 MW, it is thoroughly conceivable that diesel ight be the optimum choice. On the other hand, -vver capacities, the diesel plant loses its attracinvestment and maintenance costs are higher ll'combined-cycle plant, without compensating groviding greater fuel flexibility. The diesel enqesirable from an environmental point of view re difficult to attain low emission levels with r NOx and ~J1burned hydrocarbons. 241
242 COMBINED CYCLE GAS & STEAM TURBINE POWER PUNTS
The comparison below is restricted to the following types of power stations: • steam turbine plants • gas turbine plants • combined-cycle plants The main range of ratings under consideration is between
o
COMPARISON IF THE COMBINED-CYCLE PUNT 243
~~~:~~~~~r~n;:itydfactor) and on the load factor of the plant
, ,pen s on the load the 0 t" ' plant availability (refer to 8 1 C p:ra mg tIme desired, 1l11erlC€~d b h . . . . apital costs are also iny t e mterest incurred while the plant is being built.
4)
Th:f:i~~;~f~C fuel co~ts are i~versely proportional to the avery of the mstallatIOn This average efr . t, however, be confused with ~he thermal fr . ICIency must d . It is defined as follows: e ICIency at rated
and 500 MW. Combined-cycle plants with a smaller power output can, course, be built, but they are less interesting for power ge ration alone because their relative costs increase as the poW' rating decreases. They are best used mainly for industrial or trict heating power stations, but even for these applications, minimum economical size is approx. 10 MW.
8.1 Economy Every industrial plant strives to keep production costs as possible, and power plants are no exception in this political factors and environmental protection legislation certain limits on this goal, but economy of operation the most important criterion when selecting what type plant to build. The costs for producing electricity in a power clude three types of costs: • capital costs • fuel costs • operation and administrative costs The first of these depends on the price and the rate for the plant, on interest, or on the desired
(21)
()per is operating efficiency which take . t owing losses: ' s m 0 account the start-up and shut-down losses higher fuel consumption for part-load operatIOn . . Iscellaneous other heat d fouling, aging, operato:~rr~~e~~{losses, e.g., due ating and admistrative costs include: qllstant costs of operati d d sts, insurance, etc.) on an a mmistration (staff 0
iable costs of operation a d ' . lacement parts, etc.) n repaIr (mamtenance, :is used for comparisons of economy is generally a lue ~ompanson. The various costs for a power station :~ dIfferent times. For that reason, for financial caley are corrected to a single reference time who h the date of starting into commercial are referred to as "present value". 0
operatio~. Th~~e
COMBINED CYClE CAS & STEAM TURBINE POWER PLANTS
244
The simplified formula used to figure the present value
= TCR
+
P + U
TNj YF 0
_ 11 '11 0
0
0
'11
in which: TCR
Total capital requirement to be written off (Present v of all expenditures during the period of construction commissioning, such as the price of the plant, const;rl tion interest, etc.); in monetary units Equivalent utilization time at rated power outout. per annum; TNj = energy generated during the vided by the rated output price of fuel, in monetary units per kW hr. Average plant efficiency Annuity factor in Va; l/J
q-1 1- q-n
q
1+ Z
Z
interest rate
n
Amortization period in years
P
Rated power output in kW
U
Operating and adminstrative costs, in(~lUidiI1lg insurance, in monetary units per annum
The power production costs can be derived value using the following formula: YEL
=
PV TNj P 'If 0
01 Comparison of efficiency today's fuel prices, the thermal efficiency is the crucial facfor installations operated at medium and base load. For that on, high efficiency is a prerequisite for having an economplant.
all expenses is: PV
COMPARISON If THE COMBINED-CYClE PLANT 245
0
Below we will discuss and compare the most tors affecting the economy of a power plant for of station.
. 8-1 shows how the thermal efficiency at rated load for pes of power plant under consideration depends on the output. Stearn turbine plants have been further broken plants with and without reheating. reheating stearn plants have not been considered beare seldom constructed. Among the combined-cycle those without or with only limited supplementary shown. makes clear the thermodynamic superiority of the Surpassed by far are the gas turbines which, high turbine inlet temperature of approx. 1100 °C attain an efficiency of 30% to 35%.
iency, price is the most important criterion for se8.-2 shows how the specific investment costs for the
of power plant depend on their power output. valid for a turnkey installation including machine not as workshop, offices, staff facilities, and have been based on 1988 price levels and and do not include interest during data shown merely indicate trends: approbe taken in applying them, since very the price of a power plant: erection site, the political situation, impediments to regulations, etc.
COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
246
Figure 8-1
COMPARISON IF THE COMBINED-CYClE PLANT 247
Figure 8-2 1 600 -r--,-----r----r---r----.-_----.
~ 1400
50
-t----l---
1200 --t----+--
40 >-
u Z
L:.J U I..L. I..L.
L:.J
..... W z
30
100 20
o
200
300
400
500 MW
OUTPUT 1150)
100
200
300
400
OUTPUT Fig. 8-1:
Comparison of the Thermal Efficiencies of Various
CC ST-R ST-NR
Combined-cycle plant Reheat steam turbine plant Non-reheat steam turbine plant
of the Investment Costs Required for Various Types of Power basis: 1988) led··cycle plant turbine plant, coal-fired turbine plant, oil or gas-fired steam turbine pfllnt, oil or gas-fired power plant
248
COMPARISON If THE COMBINED-CYCLE PLANT 249
COMBINED CYCLE CAS & STEAM TURBINE POWER PLANTS
This diagram clearly shows the low investment costs re<:}Ulrec for the gas turbine, which have contributed significantly to wide-spread acceptance. Stearn power stations are significantly more expensive a combined-cycle power plant. A coal-burning plant, for ex pIe, costs two to three times as much as a combined-cycle with the same power output. Modern combined-cycle plants are therefore simpler and less expensive than stearn units. Nuclear power plants have not been included in this rison because the investment costs required for them are dependent upon political and other local consilde:ra"tions.
8.1.3 Comparison of Operating and Administrative Costs At today's fuel costs, the operating and admi.nii3trativl affect the economy of a power plant only slightly. only to 5 to 10% as much as the fuel costs. Because of the simplicity of the gas turbine, it is erating and maintenance costs even if it requires more than a stearn turbine alone. Little staff and m,tlnteIlar quired. A stearn power plant requires more staff nance costs are higher. Combined-cycle plants fall two extremes: units without supplementary like a gas turbine plant, and those with m,lximllm tary firing more like a stearn turbine power
8.1.4 Comparison of Availability The availability of a power plant greatly aft"eC1~S Whenever a unit is down, the electricity must ated in another power station or- if there is
e- purchased from another electric utility. In both cases, the placement energy is more expensive than that generated by plant itself, since capital costs are incurred whether the plant running or not. o values for availability can be stated that will be valid for ses since such factors as preventive maintenance and op'ng mode make a huge difference. However, according to known statistics, all the plants under consideration have ~r availabilities when used under the same operating cons, [406] ~al
figures for the time availability of well-designed and ined plants are as follows:
s turbine plants (gas-fired)
88 - 95 %
m turbine plants (oil or gas-fired)
85 - 90 %
turbine plants (coal-burning)
80 - 85 %
ined-cycle plants (gas-fired)
85 - 90 %
'Sures are valid for plants operated at base load; they lower for peaking or medium-load machines because .~rt-ups and shut-downs greatly reduce life expectancy .••• e and therefore increase the scheduled maintenance ()utage rates. factors determining plant availability are:
f
the major components of the plant as a whole, especially of the betw"ep.n systems <>p1er3,tioln (base, medium, or peak load) and skill of the operating and mainte-
250 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
COMPARISON If THE COMBINED-CYCLE PLANT 251
8.1.5 Comparison of Construction Time The time required for construction affects the economy unit. The longer it takes, the larger the capital rqeuirement be written off, since construction interest, price increases materials, insurance, and taxes during the construction pe add to the price of the plant. Fig. 8-3 shows the amount of time required to build the ious types of power plants. The gas turbine, because of its dardized design, can be built with the shortest lead time, has encouraged its widespread acceptance. More time is up to the completion of a combined-cycle plant. One ca ever, commission the gas turbines prior to the stearn p so that from 60 to 70% of the power output is availabl the same time as would be required for a gas turbine pow~ This is a great advantage over a conventional stearn pow which can deliver power only after two to four years
8.1.6 Comparison of Economy The diagrams below show the effects of the mosti parameters on the economy of a power plant: 1. Fig. 8-4 to 8-6: Dependence of Cost of Power
on Fuel Prices, for 50, 200, and 500 MW pla,nt~ 2. Fig. 8-7 to 8-9: Dependence of Cost of Dr,,;.,"">"' on the Equivalent Utilization Time, for 50, MW plants 3. Fig. 8-10: Dependence of Cost of Power Annuity Factor, for a 200 MW plant. A combined-cycle power plant has less fuel stearn power plant. The question can therefore an oil or gas burning combined-cycle plant is
100
200
300
400
500 MW
OUTPUT of the Construction Time for Various Types of Power Plants Imed-c:vcle plant turbine plant, coal-fired plant, oil or gas-fired power plant
252
COMPARISON If THE COMBINED-CYCLE PLANT 253
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Figure 8-4
ST-NR
15
ST-RC GT ST-NR
~
GT
ST-R
kWh
C(
..... Vl
-f.-------.L...---j---4=---------:;A
a 10
u
/
z a
.....
/
0::
l!J
C(
/
/
/
Z l!J l;)
0:: l!J
3 a
a..
5
o
o
5 PRICE OF FUEL
· 8-4 : F Ig. CC
of Power Generation Costs on Price of Fuel
Dependence of Power Generation Costs on Price
Combined-cycle plant Gas turbine plant ST-NR Non-reheat steam turbine plant Power rating = 50 MW Annuity factor =11% Equivalent utilization time H = 4000 hr per annum
GT
5 PRI CE OF FUE L
turbine plant (oil or gas) turbine plant (coal) =200 MW =11% =4000 hr per annum
J&L
10 MBT U
254
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
COMPARISON If THE COMBINED-CYCIE PLANT 255
Figure 8-6
15
\.
~ kWh
\
10
/
~ l/)
/
0 LJ
z
/
0
t-
«
c::: \.LJ
Z
/
\.LJ ~
0:::
\.
/
/
/
5
\.LJ
ST-NR
3 0
s----r---T--j----+--+-==~+-=;::::::=-1CC
0...
o
Fig. 8-6:
o
5 PRICE OF FUEL
Dependence of Power Generation Costs on the Price
CC Combined-cycle plant GT Gas turbine plant ST-R Reheat steam turbine plant (oil or gas) ST-RC Reheat steam turbine plant (coal) Power rating = 500 MW Annuity factor = 11% Equivalent utilization time H = 4000 hr per annum
2000 3000 4000 5000 EQUIVALENT UTILIZATION TIME
6000
GT
7000+
of Power Generation Costs on Equivalent Utilization Time
turbine plant =50MW =1J8 $3/106 Btu (LHV) =I1%
256
COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
COMPARISON If THE COMBINED-CYClE PLANT 257
Figure 8-8 2 0 ~--,---,-,---,---'----"T"--,,----'---"---I
\ \
US~
kWh
\
..... V! 0 \..J
Z
"-
10
0
f=
c:: w Z w
'-
1.9
ex: w 3: 0 n.
5
o-l---+--+---+--+---+--+----" o
1000
2000
3000
4000
5000
EQUIVALENT UTILIZATION TIME " 88 F Ig. -:
Dependence of Power Ckneration Costs on Equivalent
2000
3000
4000
5000
EQUIVALENT UTILIZATION TIME of Power Ckneration Costs on the Price of Fuel
cc
Combined-cycle plant GT Gas turbine plant ST-R Reheat steam turbine plant (oil or gas) ST-RC Reheat steam turbine plant (coal) Power rating = 200 MW 6 Fuel Price = US $3/10 Btu (IJIV) Annuity factor
=11%
6000
turbine plant (oil or gas) turbine plant (coal) =500MW 6 = USt$3/1O Btu (lJIV)
=11%
7000 --':!-
a
258
COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
Figure 8-10
13
-r----r---,------,.----r-----,--....,
US~
kWh 10
-!-----+--+-----:::ii'.re---+---t--i
----
t-
V')
o
LJ
ffi 3
o
0...
8
10
12
14
ANNUITY FACTOR
'Y
Fig. 8-10: Dependence of Power Generation Costs on the Annuity CC Combined-cycle plant GT Gas turbine plant ST.R Reheat steam turbine plant (oil or gas) ST-RC Reheat steam turbine plant (coal) Power rating = 200 NfW 6 Fuel Price =US $3110 Btu (LHV) Equivalent utilization time H = 4000 hr per annum
COMPARISON IF THE COMBINED-CYClE PLANT 259
a stearn power station that burns a less expensive fuel, e.g., Fig. 8-11 shows the difference in the price of fuel between oMW combined-cycle plant and a coal-burning reheat stearn er plant of the same size, as a function of the equivalent tion time. If the actual fuel price differential is above the , the coal-fired unit produces electricity cheaper; if it is the curve, the combined-cycle is better. It must be statthat it is generally easier to obtain a permit to build gas-fired plant or a combined-cycle plant than to build stearn turbine plant, particularly one that burns coal. ollowing conclusions can be drawn from these diagrams: enever oil or gas is being burned in a power sta, the combined-cycle plant is more economical n the stearn power plant. short utilization periods (a peaking plant), the gas ine is most economical. At today's fuel prices, limit is at about 1000 to 2000 hr per annum for plants. Even when burning crude oil at a price (US) per barrel, the limit is around 1000 to hr per annum. ntional stearn power plants are suitable for use l-lmrning base load or possibly medium-load plants. However, the price differential bethe coal and the gas turbine fuel must be suffi(approx. $3-6 US per GJ or MBtu). .eOI-C'VCJle plants with maximum supplementary of interest if there is only a small or oil available at favorable terms, of the fuel requirement can be covered for the supplementary firing.
the fuel and the corresponding type of power not only by short-term economic consideaccordance with political criteria and assump-
260 COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
tions about long-term developments in the prices for the various possible fuels. In this regard, the following aspects can become important in selecting the type of power station to be built: • long-term availability of the fuel at a reasonable cost e risk of a supply shortage due to political interference, such as war, boycott, etc. • political opposition to nuclear power plants • environmental protection The result of all these factors may well be that the fuel selected is may be one other than that which appears best at the of plant construction. The long-term source of fuel can be taken into account to a limited extent, by including in the calculations of eClDn()mic costs an estimated price increase for the fuel during the expectE~d service life of the unit. However such estimates should be dIed with care. In any case, the greater the fuel flexibility the plant chosen, the less the risk from possible increases in prices. Table 8-1 lists the fuels that can be burned in the various po plants today. The fuel flexibility of combined-cycle plants is less of stearn power plants. Some gas turbines can burn or crude, provided the machine is designed to do so. Ind gas turbines are more suitable than those derived from nology. It is easier to burn special fuels in gas turbines combustors than in those with several smaller com[ms:tOJrs annular combustor, since the latter are more sensitive to in flame length, radiation, etc.
COMPARISON If THE COMBINED-CYClE PLANT 261
A second requirement for burning heavy oil or crude in a gas turbine is the correct treatment of the fuel, generally by means of washing and dosing with additives. These steps make it possible to remove or inhibit elements that cause high temperature corrosion, such as vanadium, sodium, etc. The specific problems involved with the burning of coal in a combined-cycle plant are dealt with in more detail in Section 9.2. able 8-1: Various Types of Power plants and the Fuels They can Burn Gas Turbine
Combined-cycle without sup. firing
Combined-Cycle with sup. firing
Steam power plant
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes 1)
Yes 1)
Yes 2)
Yes
Yes 1)
Yes 1)
Yes 2)
Yes
No
No
No
Yes
No
No
Yes 3)
Yes
No
No
No
Yes
No
No
No
Yes
Yes 4)
Yes 4)
Yes 4)
Yes
gas Yes 4)
Yes 4)
Yes 4)
Yes
Yes 4)
Yes 4)
Yes 4)
Yes
or crude cannot be burned in every gas turbine. Generally a fuel unit is required. to the gas turbine. In the supplementary firing, however, be burned just as well as in a conventional steam generator. in the supplementary firing. generally be used as gas turbine fuels. However, adaptations are required if the heat value is low.
262 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Figure 8-11
Chapter 9
20 -.-----,-----,,--,----r--r---,--,----,
ENVIRONMENTAL CONSIDERATIONS
J!tl MBfU
15 +----1--\--~-+--+--+---t---t-___
-'
w
:::> "-
"0
w
w Z
impac~t of any
power plant upon its environment must be low as possible, but striking a reasonable relationship the cost and the results obtained should serve as a guideen for those responsible for making and enforcing the ns. The following emissions from a power station directly e environment:
10
ncts of combustion (exhausts and ash) heat
L:.J
c:
W l.L. l.L.
Cl W W
a: a..
can include the following components: H20, N2' , C02, CO, CnHn (unburned hydrocarbons, UHC), fly ash, heavy metals, chlorides, etc.
5
o-l----l---+---+--+---t---r-..____ o 1000 2000 3000 4-000 5000 EO.IVALENT UTILISATION TIME Fig. 8-11: Permissible Difference Between the Price of Fuel for Plant and That for a Steam Power Plant Annuity Factor
=11%
of these are harmless; the others can impact the environment. Their concentraion in the exupon the composition of the fuel and the type question. However, a high efficiency always i.ti'velv since the proportion of emissions per unit produced drops off. plant is beneficial because of its high effiexcess air coefficients customary in gas turcomplete combustion, Le., a very unburned elements such as CO or unburned
264
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
hydrocarbons. The large air flows have the further advantage of strongly diluting the pollutants. For these reasons, a combined-cycle plant is quite well "U.1L'CU for use in heavily populated areas. Particularly when the burned is natural gas, the only toxic emissions contained in exhausts are NO and N02. The NO x (NO + N 0 2) level is th most important environmental problem with gas turbines becaus NO generates nitric acid (H2N03) in the atmosphere, and thi tog~ther with sulphuric acid (H2S04) is one of the factors respon ible for acid rain.
9.1 Reduction of N Ox Emissions NO is produced in large quantities only at very high te ITl ature\evels. The NO x concentrations at the equilibrium sh in Fig. 9-1 as a function of the air temperature are attaine? after a very long time. The situation in a gas turbine comB is quite different, first, because a combustion actually take~ and , second , because residence times at high temperatu . fairly limited. The major factors affecting NO x productIO combustor are thus:
rt
• the excess air ratio of the combustion ( A ) • the temperature of the air after the compre~SOI., which, in turn, depends on the pressure ratIO, • the duration of the combustion As can be seen from Fig. 9-1, NO x is formed onl)' temperatures are high, such as those found in the fl combustor. The temperature of this flame depends cess air ratio A; as shown in Fig. 9-2, it is hil~h4~st of stoichiometric combustion ( A = 1). Fig. 9-3 also shows how concentrations of excess air ratio ( A ) and the compressor __ ~~r." ...,,,,
ENVIRONMENTAL CONSIDERA TlONS 265
<:lent that a peak is reached with a factor A of approx. 1.2. Bew that level, the flame temperature is higher but there is less ygen available to form NO x , since most of it is used for the mbustion. Above that level, NO x decreases because an overJ,mdance of air within the flame lowers the flame temperature. ¢ry low excess air ratios are beneficial from the point of view Px formation but are very detrimental to efficiency and cause roduction of large amounts of CO and unburned hydrocar(URC). wally, gas turbine combustors operate with an excess air f approx. 1 at full load, ensuring a good, stable combus.er the entire load range. Obviously, NO x emissions will high unless special precautions are taken. Typically, NO x II the exhaust gases after mixing with the cooling and air are in the range from 120 to 300 vppm. plest way to reduce the NOx concentration is to cool rwhich can easily be accomplished by iI\iecting water illto it. Fig. 9-4 shows the reduction factors for NO x hich can be attained as a function of the amount of ~.am iI\iected, indicated by the coefficient n, the rathe flows of water or steam and fuel. At a ratio ical reduction factor is approx. 5 with water, and steam. Steam is less efficient than water because takes place outside the flame. ne1m()Q, it is possible to attain NOx levels in the dry a gas-fired gas turbine or a combined-cycle vppm. In some cases, even 25 vppm is attain-
iI\iection is a simple way to reduce emissions, the following disadvantages:
266 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
ENVIRONMENTAL CONSIDERA nONS 267
Figure 9-1
14 12 E
~10 >
0 0 0
..... 8 x X
0
z
6
o
~ ~ a: CO a:
4
<::>
2
«
['-.0 o I....J
0 0
500
1000
1500
2000
TEMPERATURE Fig. 9-1:
NOx Equilibrium as a Function of Air Temperature
CO
W
0::)
LL
10000
C~
•.•.•.••••••.• :.'...
N
'.'.'.:....~>: . :.::·.-:~::)
.... iIO. ~
d
"'S ~
...................................... ..................................
~ I
~
c::l'I <::Ii:J
8 ~ I:l:l
~
S t"")
o !"'I'\
~
-1"
0.
/ 00
•••
o. . ..
•
~Vl
·:'0·7 ...:::.1 .
., .•
. _ ..
0
; ; . : : .::: .•.·.. 0•.·.· ..0..•.. .
;i ~
. --
.......................... -
~ Vl
.
••••••
~
_ _.. _
_
e
.
=0 I:l:l
~
!"'I'\
."
100
I
:
o
!
!
!
I
I
I
0.5
0.8
0.7
0.8
O. 9
'1
I
1 1
I
17
,
I
1. 4
13
~
~
2:
Vi
75 75
60
56
40
50
~
:s=0 o
42
31
23 25
o
15
~,... ~
8 o
0.2 5 O. 5 WATER TO FUEL RATIO
IlIIIIIill Fig. 9-4:
steam Injecti on
O. 75
~ Water Injection
NOx Reduction Factor as a Function of the Water or Steam to Fuel Ratio
1.0
~~ ~
:::j
o 2:
Vl
N
c::l'I
1.0
270 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS 41& 41&
Large amounts of demineralized water are required. The efficiency of the combined-cycle plant is lower, particularly if water injection is used.
The fact that the output capability of the same plant is higher, especially with water injection, only partly compensates for disadvantages. Fig. 9-5 shows how steam and water injection affect the put and efficiency of a combined-cycle plant, as a function the ratio of water to fuel, n. With a ratio n = 1, the changes in output and efficiency from those in a normal dry cle without injection may be considered as typical: Table 9-1: Output and Efficiency of a Combined-Cycle with Water or Steam Injection, as Compared the Same Plant without Injection Change in Efficiency, % Water injection, Steam injection,
n
1
- 4.8 %
n
1
- 1.9 %
In all cases the fuel is natural gas and a two-pressure cycle is
With steam injection, the cycle is similar to the exan:lpll in Fig. 3-50, but there is a dual steam admission into A 3-pressure cycle as shown in Fig. 3-49 would rorlll ....."·.· in efficiency caused by the steam injection but the in most cases, be offset by the additional costs of plant (refer also to Section 3.1.4).
These disadvantages of steam or water injection all builders of gas turbines toward development of combustor with which the NOx levels aU;aul1a])I¢i
ENVIRONMENTAL CONSIDERA nONS 271
those with injection systems Secti . ore detailed information abo~t th on 10.3 provIdes further, dry low NO combustors. ese combustors, referred to x orne local regulations e g th . C Ii . • ' . ., ose m a fornla T k ~e NOx emission levels much lower tha 40 or 0 yo, res, it is generally necessary to install n d v~pm. In these exhaust system These sy t k a re uctlOn system in .. . s ems nown as "8 1 . sReduction" (SCR) ..' e ectIve Cat. systems, lIuect ammonia (NH ). lIst gases before a catalyst and 3 mto the f the NO f h can thereby remove approx x rom t em The h . . follows: . c emIcal reactions involved
+
+ --~
7 N2
+ 12 H2 0
~C~::a~h::~t:~:;ell-proven systems, but they entail the tft~~t:~s~~:~~~~h (equal to about 20%
of the
ement costs are h'gh (th r is between 4 an~ 8 y e I)fe expectancy of the ears . lyst must be installed in the center of th .ssure eyaporator of the waste heat b '1 e IS reactIOn functions 01 er, tween 300 and 4000CPr(50P72erly only at tempera.. . and 752 OF). ()f ammonia is necessary.
y is slightly lower because of th . in the waste heat b i l e mcreased loss .. 0 er.
jia typical SCR system for installation in a heat stems in cOIlJ' unc t·IOn wIth . steam or wate . . te h . r IIlJecC meally possible to attain an NO Ie l' ¢s from b' x ve m a c0ll( med-cycle plant of less than 10 ·i••• ·
272 COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
Figure 9-5
ENVIRONMENTAL CONSIDERA TlONS 273
P/Po
108 106
104
102 8
'"
.;.>
rn
£:
100
~ C) ~ ~
98
0
·z u
.g
'"
p::
96
.~ .;.>
...0 a:l
.;.>
a:l
C)
94
'"
.~ .;.> u
'"
a; U1
92
(0
cf,
bil ~
'1/'1 Fig. 9-5:
Output and Efficiency of the Combined-cycle Plant as a or Steam Injection
ENVIRONMENTAL CONSIDERA HONS 275
274 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
vppm. Catalytic reduction can also be used in conventional steam plants, but the minimum level of NO x attainable is higher, andat least in a coal-burning plant- much higher.
9.2 SOx Emissions The concentrations of 802 and 803 produced depend U"k~~'.~.1 on the quality of the fuel. Because gas turbines generally u clean fuels, this is less of a problem in combined-cycle pIa than in coal-burning power stations. The latter plants can, ho ever, be equipped with scrubbers which reduce sulphur e sions by approximately 90% by converting the 80 2 into pI of Paris. A similar system could in theory be installed aft combined-cycle plant as well, but it would be much too ex sive due to the high excess air. The use of a fuel with a 10 phur content is therefore a less costly solution.
9.3 Waste Heat Rejection Another environmental problem is the waste heat that power station supplies to the environment. Here, too, tIl efficiency of the combined-cycle plant is an advantage any given amount of primary energy, a greater amount tricity or steam is being produced, which reduces the of waste heat remaining. In addition to the quantity of waste heat, however, in which that heat is given off the the environment' portant. The effect is less if the power plant heats stead of giving off its heat to a river or the sea. One disadvantage of a steam power plant is that it$ can best be dissipated with water. It can, of course, off to the air, but the expense involved (cooling cooled condenser) is greater. A combined-cycle]> advantage over a steam plant in that it requires much cooling water.
Table 9-2 shows the amounts of waste heat t . sir)at,ed, as percentages of the prima ene . hat must be dIShave not been tak' .ry rgy mput. Cooling towen mto consIderation i e th considered as being cooled WI'th' . ., water. e condenser flver or' sea .A gas turbine requires practicall . Iltributed greatly to its wid y ~o cooling water, which has esprea acceptance in water-poor 9-2: Comparison of the Heat to be Dissipated as Percentages of the Energy input Gas Turbine
Combined-Cycle Plant
68-75
27-14
10-14
o
28-38
52-56
Steam Power Plant without reheat with reheat 10-15 44-52
stack losses
'~e
Immissions
nvironm.ental p.roblem is noise, but this can be solved msulatIOn available today Th the same f 11 . e costs are apor a types of power plant installations.
Chapter 10
DEVELOPMENTAL TRENDS in trends in development are in three directions: toward increased efficiency and power output of the gas turbine ward the use of coal in combined-cycle plants jyv'ard attaining lower NO x emission levels without ter or stearn injection (dry low NO x combustors) t of these trends is a continuation of the development led to the break-through of the combined-cycle plant st few years. mpt to use fuels other than oil or natural gas in ycle plants or gas turbines is not new. Development ¢entrating mainly on the utilization of coal in plants tegrated Coal Gasification Combined-Cycle (IGCC) ed Fluidized Bed Combustor (PFBC) plants.
¢effect of a high gas turbine inlet temperature on of a gas turbine or a combined-cycle plant has 'scussed in Section 2 (refer to Fig. 2-2). It seems qk for further improvement mainly in the direc.;;ts inlet temperatures, which has become possidevelopment of new materials and improved .«Research projects here are concerned mainly it cooling of the hot gas path of the gas turbine. ¢ooling technologies, for example, employing 277
DEVELOPMENTAL TRENDS 279
278 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
water or steam cooling systems, do not yet appear close to a stage of development where they could be used in a real gas turbine. For these reasons, work at present is concentrating on the development of new materials, e.g., ;y I superalloys, oxide dispersion strength (ODS) alloys, directionally solidified (DS) blades, and of more efficient air-cooling systems employing • improved film cooling • impingement cooling The use of ceramic materials in gas turbines, mainly for ing, still appears far from ready for commercial application cause of the very low reliability that must be expected with blades. Ceramics are presently being used only for certain in the hot gas path of a few gas turbines. Parallel to this, improvements are also being made to the pressor. The advantages offered by the higher gas temper cannot by fully exploited only if the pressure ratio of th chine is increased to an appropriate level. High unit ratin. also being attained by increasing the air flow through tIl. pressor. With modern blading, compressors are able to volume flows that seemed utopian just a few years ag the use of transonic stages, it is already possible to attai valent outputs and pressure ratios with many fewer co stages. With these improvements, combined-cycle efficienci than 50% are already being attained. Gas turbines power capacities of more than 200 MW for 50 Hz a and 150 MW for 60 Hz applications mean lower c combined-cycle power plants will become even ing for large power stations. It can be expected combined-cycle plants will, within the next 10 ficiencies of 52 to 55% or more (LHV).
10.2, Coal Gasification ,Fluid· l z ed B ed Combustion ThIS development is directed at m k " ' . a I~g It possIble to use coal ave been suggested and :e I-CYcle Installations. Two paths m c ose to commercial realization:
~irectly or indirectly in co b'med
• autothermal coal gasification • pressurized fluidized-bed combustion
.2.1 A Combined Cycle Plant with Coal Gasification egasifi~ation of coal is a very old technology B f
was mtroduced on the market , . . , e ore natduce fuel gas for distribution' ,c~al gasifIcatIOn was used frequently in the chern' I mdur an areas. It is also used uce raw materials fO/cCahema~ PIetrochemical industries Ica processes. er~al
coal gasification is based on partial comb . al ill order to generate the heat required for th~:~on rocess Itself, in which the coal is conve SIvyith water, into H CO CO rted, generally S tions involved ar;; , 2, CH4, H2 , and H2 0 . The --~
--~ --~ --~
CO + H2 2 CO CH4 CH4 + H2 O
~. overall
reaction is endothermic, the coal m t b ..The o x y g ' us e •.t•.• h.. . . en reqUITed for combustion to take place e gaSIfIer by iniect' , h er aIr . or oxygen into ~v mg elt processes can therefore be classified either as: . which produce a gas with a low caltYPIcally 5000 to 6000 kJ/kg (100 to 120
280
DEVElOPMENTAL TRENDS 281
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
2) oxygen-blown gasifiers, which produce a gas with a medurn calorific value, typically 15,000 kJ/kg (or 330 Btu/scf), approx. one-third the calorific value of natural gas. Either type of gasifier can be employed in combined-cycle plications; the advantages and disadvantages of each will cussed further below. Table 10-1 shows the composition of typical gas ob1taiIled the two different gasification processes. Table 10-1: Typical Composition of Gas, in % by vo]"uITl.e Natural Gas (Reference)
60 30
CO H2 O CO2 N2 CH4
Coal Gasification Air-bl Oxygen-blown
10 90
3 2 5
Relative heating value
1 (Reference)
1/3
Adiabatic flame temperature
2100 °C (3812 OF)
2300 °C (4172 OF)
In addition to this general classification based ium used for oxidation, a distinction must also on the flow pattern in the gasifier itself. types: 1) fixed bed gasifiers with cOlun1ter-cllrr1ent
2) fluidized bed gasifiers with bubbling 3) entrained bed gasifiers with
10-1 shows the working principle of these various types. .e gasifiers which are closest to large-scale commercial applilion for combined-cycles are of either the fixed-bed type (BritGas-Lurgi slagging gasifier) or the entrained-bed type (Texaco, 11, Dow, Prenflow), both oxygen-blown. ~ifiers can also
be classified according to their operating pres, Le., whether they operate at atmospheric pressure or at erpressure. Only the second of these types is of interest mbined-cycle plant applications because the gas pressure inlet to the gas turbine must be at least 20 bar (290 psia). ~t reason, gasifiers for combined-cycle plants typically opt 20 to 30 bar (275 to 420 psig). Table 10-2 shows the clas'cm of the major gasification processes. sification is particularly interesting from the point of is far easier to obtain a very clean leaning fuel gas than by cleaning the combustion gas 9al-fired boiler. The main reasons for this are:
~mission control. It
volume flow of the coal gas to be treated is less 1 % that of the exhaust gas from the boiler. hemically much easier to remove H28 than 802, makes it economically feasible to remove more 9% of the sulphur, as compared to only 90% in tubber of a coal-fired boiler. er pollutants, Le., heavy metals, chlorides, etc., removed in the gasification process. byproduct of the desulphurization process except in a fluidized bed gasifier, sulphur, which is easy to transport and to desulphurization processes, 5 to 10 times product is produced, since the sulphur into molecules of products like gypsum.
"'3
~
(tI
8~
~ .....
~
MAJOR COAL GASIFICATION SYSTEMS
0I
~
~
British Gas! Lurgi
Texaco
Shell
Prenflo
DOW
KRW
HT Winkler
°2
62
°2
°2
°2
°2!air
°2!air
Coal gas heating value
Mlltu
Mlltu
Mlltu
Mlltu
Mlltu
Mlltu!LBtu
Mlltu!LBtu
Type of gasifier
Fixed bed
Entrained bed
Entrained bed
Entrained bed
Entrained bed
Fluidized bed
Fluidized bed
Cocurrent flow
Cocurrent flow
Cocurrent flow
Cocurrent flow
BUbbling or circulating flow
Bubbling or circulating flow
1400 - 1700
1400 - 1700
1400 - 1700
1400 - 1700
850 - 900
850 - 900
Countercurrent flow
Raw gas temperature LOCI
500 - 600
S Ii
Oxidant
Flow pattern
2:
~ I"'-
".,
s;: V> ~
V>
~ ~
e
Compatible with gas turbine requirements
Gasifier pressure
~
~
Raw gas COOling: - syngas cooler - quench
No Yes
Yes Yes
Yes Yes
Yes Yes
Yes Yes
Yes (Yes)
2)
Yes (Yes)
~
2)
~
0
§
is also referred to as a gasification heat recovery generator. gasifiers, no quenching is required if hot gas clean-up is provided.
~
2: ~
~ .....
OQ,
TO GAS CLEAN-UP
""i ==
(tI
~
o I
~
l!tc
"O6''O~ -;)e ~
"
fiCfb'''Ql
~ ~
lb
0
~
~
•
•
~
"'"
"
9 ()
0
lQ
'" '"b
I
ASH SLUDGE
<::l
C <:I
0 ~.
o~~~ Vf\o~ :~ __;-
"l(
~ ~
ASH or SLAG
!
FIXED BED COUNTER - PLOW
J
~
SLAG
I ENTRAINED
FLO~J
PARALLEL - FLOW
ASH AND GYPSUM IFLUIDIZED BED]
~
I"'-
o
~
~
Fig. 10-1: Design Principles of the Main Types of Gasifiers
~
I"'-
~
~
Sl N
~
284
DEVELOPMENTAL TRENDS 285
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
5) Most oxygen-blown gasifiers produce unleachable slag. Waste disposal is far easier than with the ash produced by coal-fired boilers.
generated in the gasification plant, which demonstrates clearly the importance of integrating the gasification process into the combined-cycle plant.
For all these reasons, it is clear that coal gasification may be very interesting for power generation in the future: it is most promising method to produce a truly clean co:al-burning
The gas in the coal bed of a fixed-bed gasifier is cooled to a uch lower temperature because of the countercurrent flow fthe gas and the coal. Heat recovery after the gasifier is theree far less important, and such plants therefore usually gente only a very limited amount of low pressure stearn. Fig. :3 shows an example of a coal-fired combined-cycle plant usritish Gas-Lurgi slagging gasifiers. It can be seen quite clearly the degree of integration is far less important here than the Shell gasifier.
plant. Coal gasification can be either a system integrated into a combined-cycle plant, or a non-integrated system, with the sification and combined-cycle plants quite distant from one other. Only the first of these two possibilities appears rea interesting at present, since integration, with its good utilizat of the waste heat generated in the gasification process, v greatly improves the overall efficiency of the entire syste One major consideration when designing an integrated fication combined-cycle plant (IGCC) is the temperature at the gas is to be cleaned. All successful industrial systems used today work at near ambient temperatures, which that the coal gas must be cooled down after it leaves th ifiers. If the gas was very hot, it is important that this be recovered efficiently. One of the main differences b fixed-bed gasifiers and entrained-bed gasifiers is that temperature of the former is typically approx. 500 t~ (900 - 1100 OF) and that of the latter approx. 1500 °Ce This is why entrained-bed gasifiers are equipped with ers to generate either saturated or superheated high steam. This steam is then used in the combined-cysl generate more power. The example shown in Fig. 10-2 is a typical IGCC on a Shell entrained bed gasifier unit. The steam~. the gasifiers and that from the heat-recovery ste~ of the combined-cycle plant both flow through tIl sure section of the steam turbine. About 40% of
~systems used
to clean the gas are quite similar in both calle difference is that the gas produced in a fixed-bed gaspntains tars and phenol which must be separated out and d to the gasifier. This is not true with an entrained-bed because of the much higher process temperature which the heavy hydrocarbons. 10-3 provides the main technical data of the IGCC plant Fig. 10-2, using a 150 MW ABB gas turbine, with an of 34 % under ISO conditions. Main Technical Data of IGCC Plants
value of the coal gas rization rate
output output IIllj)ticlll for auxiliaries
entrained bed Illinois No. 6 12 500 kJlkg (290 Btu/scf) 99 % ~ 135 rnglGJ (75 vpprn) MW 577 173 MW 110 MW 33 MW 250 MW 43.3 %
------------DEVELOPMENTAL TRENDS 287
286 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
These figures show the efficiency that can be expecte~ from an IGCC plant employing commercially proven components m 1988. To reduce the NO emissions to the low level indicated for these x two plants, the fuel gas is mixed with water vapor. The costs such a plant are in approximately the same range as those modern coal-fired units with scrubbers and de-NO x systems.
Two fairly large IGCC plants already built demonstrate that t is a proven technology. The first of these is the 100 MW Co water plant in California, a demonstration plant that h~ been erating since 1984 with a Texaco gasifier. Altho~gh t~s.pla~t an efficiency of only 31.3%, the main purpose m bmldmg It not to achieve the highest efficiency possible, but to show the integration of coal gasification and a combined-cycle ~lant actually work. The second of these is at the Dow chemIcal in Plaquemine, LA, with a total output of approx. 160 M,¥ One very interesting feature of IGCC plants is their pot for phased or staged construction, Le., an IGCC plant can pleted in two or three steps: Step 1: Step 2: Step 3:
the gas turbine portion conversion to a combined-cycle plant coal gasification
The advantage of this method for building an IGCC course, the relatively small capital requirement for steps. Larger investments do not have to be made when economical and operation considerations of the gas-fired plant into a coal-fired unit. It can be expected that the efficiencies of IGCC year 2000 will be between 46 and 48% (LHV) due to improvements:
• gas turbines with higher inlet temperatures • dry low NO x combustors • hot gas clean-up introduction of cleaning systems operating at 400 to 500 to 932 OF) would improve the outlook for air-blown gasAt present, this type of gasifier is at a disadvantage because e larger exergetic and energetic losses that occur during coolof the gas prior to the gas treatment. The gas flow is approxely three times as great as in the case of oxygen-blown gasifiers. oon as the fuel gas only needs to be cooled down to 400 to , that disadvantage will be greatly reduced. Air-blown ation systems obviously have the advantage that no air sepplant is needed. other field for possible application of coal gasification could ogeneration of power and chemical raw materials in the ant (e.g., power and methanol).
Pressurized Fluidized Bed Combustion ~ystems (PFBC) a behind pressurized fluidized bed combustion systems quite different from that on which the IGCC is based. ·fication, one will want to burn coal cleanly, utilizing ges of the gas-fired combined-cycle plant. Essentially, using gas turbines with a high turbine inlet temperl1trast to this, PFBC takes its point of departure from steam power plants. e knows, subsequent flue gas desulphurization and is very involved and expensive. For that reason, ¢ds, both atmospheric and pressurized, desulphurplished by reaction of the sulphur with limestone bustion. Since the temperature must not exceed (1652 OF), relatively little NO x is produced as well.
N 00 00
"%j
.....
~t'e 8 ~
tl:l
~
o
~
I
N
e3 (j
(3 I"1"l
LOW LEVEL
~ Vl
WASTE IEAT PICKUP
_111~ I
Qe Vl
I
~
I I I I I I
SULPHUR
~ """l
c::::a
tl:l
~
I"1"l "tI
1
sATuRAmRI
",1 __ -.J
o
~
STEAM TURBINE
~
~
(;l
~
~t'e
,....
o I
~
LOW LEVEL
WASTE HEAT
I~
PICKUP
I I 02 SLAG
I
I
0
I"1"l
G)
SATURATOR
I
~
0
~ :2: ~
r-
;;i I"1"l
GAS TURBIN E
~
0
Vl
Fig. 10-3: ISCC Plant Based on a Fixed Bed Gasifier (BGC-Lurgi)
N
00 1.0
290
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
This process is presently being used in many boilers with fluidized beds that operate at atmospheric pressure. Because the maximum power density permissible is quite low, the dimensions of fluidized beds of this type become very large, even for low stearn ge:nelration outputs. This quickly gave birth to the idea of operating the tire process at an overpressure, which provides the following vantages:
DEVELOPMENTAL TRENDS 291
Figure 10-4
0:
LW
III
Z
LLI
0
~ U
• The dimensions of the fluidized bed and the stearn generator are reduced approximately proportional to the pressure.
Q)
s:l
:e
~
• The efficiency of the overall plant can be raised by using a gas turbine as the charging unit.
~
;::l
+'
as
'" Q)
S
At present there are two different types of PFBC plant, ing in the inlet temperature to the gas turbine:
Q)
Eo< ~
j
as {J
1) PFBC plants with a low temperature gas turbine, i. the turbine inlet temperature is approx. 450 - 500°C (8 - 932 OF), or just high enough so that the gas turbine capable of driving a compressor (Fig. 10-4).
.~ +'
s:l
as
15::
""" Q)
P=l
2) PFBC plants with a high temperature gas turbine. Int case, the turbine is located directly after the flui •. bed and is driven by exhaust gas with temperatur approx. 800 to 850°C (1572 - 1662 OF). This means the turbine produces a greater amount of poweri cess of that needed to drive the compressor (Fig. Plants of the first type are not true combined-cycle pI cause the gas turbine is only a charging unit. The principl§ is exactly the same as in power plants of 50 years ago W equipped with BBC Velox boilers (refer to Section 3.5) dynamically, such a plant is equivalent to a conventi turbine power plant.
""" Q)
N
~
~ """ Q)
N
'C
;::l rJl rJl
£ f
0 ..... 0:
« --
bil ~
DEVELOPMENTAL TRENDS 293 292 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Figure 10-5
the other hand, PFBC plants with a high temperature gas ;urlbinLe attain efficiencies of 43 to 44%, i.e., significantly above of the steam power plant. The major technical problem with type of plant is obtaining effective filtration of the flue gas temperature level of 850 to 900°C (1572 to 1662 OF).
Q)
c
:0
:;
t-
The principal advantage of this type of plant may be the relative ease with which dust may be removed from the flue gas, VY.lLJL'-~L. at temperatures of 450 to 500 °C (842 - 932 OF), is not likely be too problematic.
...-...lI----:c::===t
E
III
Q)
en
ore information about this will become available in the early when operating experience with the first PFBC plants from (the present Asea Brown Boveri) has been gathered and and. The main technical data of this type of plant are as follows: net power output turbine output am turbine output
t efficiency
80
MW
17
MW
67 MW 42.5 %
CD
"E'" o c
8
w
agram in Fig. 10-5 shows the principle of operation of this lant; Fig. 10-6 shows details of the pressurized fluidized
r. The flue gas is cleaned in 2-stage cyclones, since no erature filters are yet available for commercial appli.s means that the flue gas must then be cleaned in electers after the economizer. evelopment of such plants may attain efficiencies of to 45 % by using larger units and steam cycles with 've steam data. ~
of the PFBC plant are assuredly its coml:l,nd its potential efficiency, which is from 5 to 10% a conventional steam power plant. Disadvantages, lve the neces.<;ity of flue gas scrubbing at high tem-
DEVELOPMENTAL TRENDS
294 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
peratures and the fact that the gas turbine is of a special design which cannot fully utilize the high temperature potential avail~ able with modern gas turbines because of restrictions on the tem perature within the fluidized bed. Then 000- unlike in plants wit a low temperature gas turbine, the economizer in a plant wit a high temperature gas turbine operates at atmospheric pressuI' because it is situated after the gas turbine. This affects the comp ness of the plant. Suggestions for using the full temperature potential of turbine do, of course, exist, but whether or not they can be alized commercially is an open question, since they make the p more complicated and problematic. These are based on part' gasifying the coal or directing it through a pyrolysis before plying it to the fluidized bed. The gas produced thereby is btl following the fluidized bed to bring the gas turbine inlet te ature to the levels usual for normal turbines. Overall efficie of 48 to 50% should be attainable with such systems. How the PFBC process might make a breakthrough on th ket in competition to IGCC and conventional steam power is a question that remains to be answered. If success is a, in the first four large-scale plants currently under constr the prospects for the process could well be very good. In addition to these two types of installations with gas~ there are also suggestions for using a hot air turbine. has been shown in Section 3.4 with a closed-cycle Similar systems employing an open air-process have gested. In both cases, the air is used as the medium to cool bed. It thereafter expands in the turbine before being bustion air in the open process.
295
e advantage of these arrangements is that the turbine is opon a clean medium. Their disadvantage, however, is the surface area required for the atmospheric fluidized bed. A er problem lies in selection of the material for the fluidized ooling tubes, which are not as efficiently cooled. The heat fer coefficient of air is lower than that of water or steam.
Dry Low NO x Combustors as shown in Section 9.1, the methods commonly used toreduce NOx emissions are indeed effective, but they entail dvantages: water consumption .eduction in the efficiency of the combined-cycle t
larly in the case of base-load installations, this impacts on plant economy. Moreover, the high rate of water on is not unproblematic from an environmental point r these reasons, various development projects are currogress, directed toward reducing NOx emissions by the combustion technology. Theoretically, there are that such development can take: ~n-Iean combustion
()... < 1)
l1-rich combustion ()... > 1) ows the dependence of the NOx concentrations on ·iratio. Only a small amount of NOx can form in an ()mbustion, despite the high flame temperature, be§carcely any oxygen available for that to happen. rder to attain a complete combustion, there must llow-up combustion stage in which there is almost to the lower temperature. This approach is (lx)(lernsteam generators and is referred to as "staged
296
DEVELOPMENTAL TRENDS 297
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
For gas turbines, however, because of the high overall excess air ratio (A = 3 to 3.5), a different and more effective procedure is being applied: combustion with excess air. This functions on the same principle as reduction by means of steam or water injection: the large amount of excess air effectively cools the flame. The procedure is subject to limits due to cOll..",iderations of flame stability. With excess air ratios A of approx. 3, the combustio becomes very poor and the flame is completely extinguished.
Figure 10-6
This represents no problem while the gas turbine is at full loa because there is not enough air available for the burner any for the excess air ratio to exceed Z.O significantly. The rem' air is required to cool the hot parts and the turbine blading. is, however, a major problem at part loads.
1.-H--12
For the combustion actually to take place at the desired ex air ratio, the air and fuel must be mixed homogenously wit another. For that reason, the burners used with this proce are referred to as "premix" burners. Fig. 10-7 shows a typic ample. The air and the natural gas are premixed in a tub are burned downstream from the swirl basket, which is I at the end of the premixing tube and is used to hold the The basic problems involved with this type of burner can seen immediately from this example:
--+-+-1---11
• It is very difficult to burn liquid fuel, since m.i.xing comes problematic. • There is a risk of back-flash, I.e., that the combu will take place even in the premixing zone. This sytem operates very well with natural gas, the air temperature is not too high, which means sure ratio of the gas turbine must be less than anIwoX'. With gases with a higher flame propagation speed, gen (HZ) or carbon monoxide (CO), this procedure
6
7 ABB Pressurized Fluidized Bed Boiler
298 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
DEVElOPMENTAL TRENDS 299
be employed due to that factor. This type of burner has scarcely ever worked well with liquid fuels.
Figure 10-7
There are a few gas turbines from various manufacturers in comerdal operation that have dry low NOx combustors of this type, rating on gas only.
~FUEl AIR
FUEL FOR PREMIX OPERATION
\
\
FUEl FOR DIFFUSION
Fig. 10-7:
Premix Burner
. 10-8 shows a combustor of this type equipped with 36 burnsimilar to that in Fig. 10-7; Fig. 10-8 shows a photograph of burners viewed from below, with the swirl baskets of the 36 ers that are used to contain the flames. This combustor is ted on a 70 MW gas turbine. 36 burners were selected in to solve the problem of part-load operation. To prevent the air ratio in the burners from becoming too high at part loads, extinguishing the flame, the burners can be switched on in groups. Fig. 10-9 shows the loads at which the various are switched on or off, and the corresponding changes in llcentrations in the exhausts. In all, there are five groups rs in this combustor: Fig. 10-10 shows how they are conthe fuel end and controlled with a single control valve. other solutions to the problems at part load, such as, a more or less progressive switch-over from premix to normal diffusion combustion, or the installation of on the burner which allows more or less air to escape n the load involved. This also makes it possible to ashigh excess air ratio and a stable flame. combustion technology, there are large gas turbines operation with NOx emissions ranging, in gas-fired full load, between 25 and 75 vppm at 15% 02, de¢ design. Further development of this type of burner in the direction of even lower emission levels and, :ltd greater fuel flexibility. Of particular importance, epossible in the future to burn liquid fuels and coal Iich in H2 or CO.
DEVELOPMENTAL TRENDS 301
300 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
So-called "surface burners" represent another path toward NOx reduction in which use is made of a different parameter to achieve low NO emission levels, viz. time. The placing of several very x small flames over a large surface area makes the residence time within the flame very short, leaving little time for NO x to form. The major problem in this case is keeping the residence time as short as possible while still maintaining a good combustion that does not produce large amounts of carbon monoxide (CO) and burned hydrocarbons (URC).
Figure 10-8
Fig. 10-11 is a typical annular combustor that operates on t
°
principle, used as equipment for a gas-fired 45 MW turbine. can see the swirl baskets used to hold the small flames. In all, the are 200 swirl baskets installed on the ring. Theoretically, this co bustor could also be fired on oil. NO x emission levels in the hausts at full load are in the range from approx. 50 to 80
Fig. 10-8: Dry Low NO x C ambllstor: Principle
= DEVElOPMENTAL TRENDS 303
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
302
Figure 10-10 Figure 10-9
o
GAS
o
ppm Iv I UHC} 1 ppm(v) CO wet 39 ppmlv I NOx
2
27
3
2
4 350 5
150 65 910 690 8 12
~
::)
0 0:
4
c;)
0:
w
z
0:
::)
CD
.... 0
o
255 509 11
3
3
43 2 245 27
2
0:
2 120 36
w
5 Diffusion burners
4
4
4
4
CD
:2:
~ Premi x burners 7
8
9
10
11
0 0
10 Dry Low NOx Combustor: Principle of Fuel Flow Control and Grouping of
Fig. 10-9: Dry Low NOx Combustor: Dependence of the NOx Concentration Turbine Load
304
COMBINED CYCLE GAS & STEAM TUR
BINE POWER PLANTS
Chapter 11
Figure 10-11
SOME TYPICAL COMBINED-CYCLE PLANTS ALREADY BUILT .1 Combined-Cycle Plants without Supplementary Firing .1 The 120 MW Combined-Cycle Plant of the NEWAG at Korneuburg (Austria) gas-burning combined-cycle plant began operation in 1980. 1-1 shows the principle on which it was built. It consists 80 MW gas turbine and a 45 MW 2-pressure steam tur.Because very good use is made of the waste heat from the rbine, a net efficiency of 46.6% is attained in base-load 'on. Table 11-1 shows the main technical data. Fig. 10-11: Annular Combustor
"th Swirl Basket Burners
WI
nit was constructed within an existing machine building ce an older combined-cycle plant. Fig. 11-2 shows the ig. 11-3 the machine building with the gas and stearn
bined-cycle plant is being used to cover medium loads ed and shut-down daily. It therefore has fully autools which, after 14 hours at standstill, bring the plant qad again within approx. 26 minutes. eration of the gas turbine alone scarcely enters into 11, the plant was built without a flue gas bypass. Howaste heat boiler is designed to permit operation of e at full load even while the boiler itself is dry.
305
306
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
SOME TYPICAL COMB INED-CYCLE PLANTS ALREADY BUILT 307
Figure 11-1
r] J:
1 Fig. 11-1: Design Principle used for the 120 MW Combined-Cycle Plant at Korneu 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19
Vapor condenser High pressure feedwater pumps 38 Deaerator/mixi~g 39 High pressure resuperator Extraction steam 40 High pressure drum Support steam 41 High pressure circulating pump Feedwater tan 42 High pressure evaporator Boiler wa 43 High pressure superheater BoHer wat 44 High pressure steam line Replacem 45 Low pressure water separator Starting 46 Low pressure trip valve Opera 47 High pressure trip valve River 48 Steam turbine Main 49 Steam turbine generator River 50 High pressure and low pressure Aire 51 bypass gene Bypass control valves Steam 52 Injection steam heater Gast 53 Injection water pump Air co 54 Condenser 36 Gas tur 55 Condensate pumps 37
20 Gas turboset 21 Waste heat boiler 22 Steam turboset 23 Air intake filter 24 TurhocomprcSBOr 25 Fuel supply line 26 Combustor 27 Gas turbine 28 Gas turbine generator 29 Exhaust sound damper 30 Stack rain damper Low pressure feedwater pumps 31 Low pressure feedwater control 32 valve 33 Low pressure economizer 34 Low pressure drum Low pressure circulating pump 35 Low pressure evaporator Low pressure superheater Low pressure steam line
E3 "1
308 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Figure 11-3
SOME TYPICAL COMBINED-CYCLE PLANTS ALREADY BUILT 309
Table 11-1: Main Technical Data of the 120 MW Combined-Cycle Plant at Korneuburg
Air temperature ooling water temperature liS turbine power output at base load
am turbine power output tion service power power output efficiency enser pressure temperature ressure feedwater temperature rbine exhaust gas flow bine exhaust gas temperature bine inlet temperature ssure live steam data live steam flow live steam data live steam flow
Natural gas 10°C 8 °C 81.1 MW 48.7 MW 1.0 MW 128.8 MW 46.6 % 0.036 bar 95°C 58 °C 363 kgls 491°C 945 °C 33 bar 438°C 43 kgls 4.4 bar 182°C 7.9 kgls
lje Tunghsiao Combined-Cycle Plant the TPC, Taiwan [26]
. f th 120 MW Combined-cycle Fig. 11-3: Machme room 0 e
siao combined-cycle plant consists of three blocks, power capacity of approx. 300 MW. The unit detail here is the third of these blocks, but blocks one $imilar in construction. The entire plant has been ·•• • ce 1982. Fig. 11-4 shows the principle of the structallation, which consists of three 60 MW gas tur-
310
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
.SOME TYPICAL COMBINED-CYCLE PLANTS ALREADY BUILT
FIgure 11-4
311
bines and a 95 MW single-pressure steam turbine and is capable of burning either residual or diesel fuel. Economic consideratons lend special interest to the burning of residual. The oil is washed and dosed with additives for combustion so as to prevent high temperature corrosion. Table 11-2 contains the main technical data. The gas turbines and the waste heat boilers are built outd()of's. the gas turbines in a light enclosure (Fig. 11-5). On the hand, the steam turbine is accommodated in a conventional m chine building. Table 11-2: Main Technical Data for the Tunghsiao Combined-Cycle Plant, Unit 3
Fuel Air temperature Cooling water temperature Gas turbine power output at base load Steam turbine power output
32.2 29.4 3 x 60.1 95.3
Station service power Net power output of the plant Net efficiency of the plant (LHV)
rbine ator ater tank/deaerator essure feed pumps ressure feed pumps essure evaporator
Condenser pressure Stack temperature Feedwater temperature Gas turbine exhaust gas flow Gas turbine exhaust gas temperature
r
evaporator
Gas turbine inlet temperature Live steam flow Live steam data (at base load) Low pressure steam flow
Design Principle of th e T ungh' Slao Combined-Cycle Plant (Unit 3)
3
11 12 13 14 15 16 17 18 19
a>
Superheater High pressure drum High pressure circulating pump Bypass flap valves Bypass stack Steam turbine Generator Condenser Condensate pumps Steam bypasses
312 COMBINED CYCLE GAS & STEAM
TURBINE POWER PLANTS
Figure 11-5
SOME TYPICAL COMBINED-CYCLE PLANTS ALREADY BUILT 313
11.1.3 The 1200 MW Trakya Combined-Cycle Plant TEK, Turkey [111] The Trakya combined-cycle plant of this Turkish utility comfour 300 MW units, each having two gas turbines and one turbine. The gas turbines are rated at 95 MW under site nditions. The stearn turbine, with a single casing and two low essure exhausts, is rated at 110 MW, Fig. 11-6 shows the cycle plant, which is a typical dual pressure cycle.
. d Waste Heat Boilers at the Fig. 11-5: Layout of the Gas Turbmes an 't 3) · d -Cycle Power Plant eD m Comb me 1 2
Gas turbine Control block
3 4
Bypass Waste heat boiler
ne interesting feature of this plant is that the condenser is led with a dry cooling tower built on the Hungarian Heller ciple. The condenser is therefore not a surface heat exger: the stearn is condensed by mixing it with cooling waTable 11-3 shows the main technical data. 11-3: Main Technical Data for one 300 MW unit of the 1200 MW Trakya Combined-Cycle Plant Base load 15
flow steam temperature : steam pressure steam flow steam temperature : ~eam pressure
Peak load 15 natural gas 2 x 97.5 2 x 104.5 105 118 3.6 3.7 296.4 323.3 49 50 86.5 93 477 498 49.4 53.9 20.5 20 197 197 4.9 5.2 98 99 51 51
°C MW MW MW MW %
kg/sec
°C bar kg/sec
°C bar
°C °C
314 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
SOME TYPICAL COMBINED-CYCLE PLANTS ALREADY BUILT 315
pressure live steam flow pressure live steam data
11.1.4 The 1090 MW Combined-Cycle Power Plant at Higashi-Nigata, Japan The 1090 MW Higashi-Nigata combined-cycle plant owned Tohuku Electric comprises two blocks, each with three 133 gas turbines and one 196 MW stearn turbine. The plant is on vaporized liquid natural gas (LNG) and is operated as a
150 64.7 500 44.1 5.9
w pressure live steam flow w pressure live steam data
kg/sec bar °C
kg/sec bar saturated 0.043 bar 109°C
load unit. The plant has a dual pressure steam cycle condenser is cooled directly with sea water. NO emissions are less than 15 vppm. In order to """"""u. low :level, the gas turbines have been equipped with NO combustors which reduce the NO x concentration to ap 75 ~ppm. The emissions are then further reduced in th~. tive catalytic reduction (SCR) system installed in the heat ery stearn generator. Table 11-4 shows the main technic of this plant.
Table 11-4: Main Technical Data of One Unit of the) Higashi-NIgata Combined Cycle Power PI Fuel Air temperature Cooling water temperature Gas turbine power output Steam turbine power output Station service power Power output of the plant Efficiency of the plant (LHV)
LNG - 1
°C
+ 18°C 133 195.5 19.9 1090
MW
48.5
%
MW MW MW
. 11-7 shows the general layout of the power plant and Fig. a view of it.
Combined-Cycle Plants with Supplementary Firing 1 Lausward Power Station of the Stadtwerke Duesseldorf AG, Germany 20 MW combined-cycle block consists of a 60 MW gas turMW gas turbine, and a 300 MW reheat steam turbine. into operation between 1974 and 1976. The gas turbines ural gas or light heating oil, and the steam generators nateavy, or light heating oil, individually or in any mixture esired. and 11-10 show the structural design of the plant, which ed up and shut-down fully automatically. Each gas a 100% capacity flue gas bypass, making single-cycle ossible. At any given time, one of the two gas turbines ~()mbined-cycle operation along with the stearn genthe other is available for solo operation in the upper range or as a standby unit. The exhaust gas heat can o a district heating system heat exchanger. But it is to operate the steam process by itself since the steam ~quipped with a fresh air fan. Table 11-5 shows the t data and Fig. j l1-11a and b the general layout. /
316
COMBINED CYCl.E CAS & STEAM TURBINE POWER PLANTS
SOME TYPICAL COMBINED-CYCl.E PLANTS ALREADY BUnT 317
Figure 11-7
Figure 11-6
. 11 6 Design Principle of the Trakya Combined-Cycle Plant (1 Unit) -: F Ig. 1 2
3 4
Gas turbine Steam turbine lIP drum LP drum
5 6 7
Deaerator/feedwater tank Mixing Condenser Cooling tower
E L1'l
:;;
co ~(
(
318 COMBINED CYCLE CAS & STEAM TURBINE POWER PLANTS
SOME TYPICAL COMBINED-CYCLE PLANTS ALREADY BUILT 319
Figure 11-8
Piping Diagram for the 420 MW Combined-Cycle Power Plant at
Fig. 11-8: View of the Higashi-Nigata Combined-Cycle
m generator pressure superheater ter turbogroup nser pressure reducing station pressure reducing station r safety valves and damper sate pumps cleaning unit cooler
12 13 14 15 16 17 18 19 ID 21 22
Condensate tank with replacement water deaerator Low pressure feedwater heater Feedwater tank with spray deaerator Feedwater pumps High pressure feed water heater Part-flow economizers Full-flow economizer Flash-box Start-up flash-box Boiler start-up flash system Boiler circulating pump
COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
320
SOME TYPICAL COMBINED-CYClE PLANTS ALREADY BUILT 321
Table 11-5: Main Technical Data of the Combined-Cycle Plant at Lausward Air temperature Gas turbine power output (bypass operation) turbine power output (combined-cycle operation) am turbine power output
oc
5 74/83
MW
62nO
MW
300
MW
steam flow
236
kgls
steam data
188
bar
540 40.6
OC OC
data at outlet from reheater
32 enser pressure rbine exhaust temperature (combined-cycle operation) bine exhaust gas flow ine inlet temperature r output when burning oil (LHV) ency, in best point, burning oil
540 0.028 415/452 378 890/935 34.9 43.8
OC bar OC kgls
OC MW %
The 750 MW Power Plant Gersteinwerk, Block K, VEW, Germany
QMW combined-cycle plant consists of a gas-burning tur-
Fig. 11-10: Flue Gas/Air Flow Diagram of the 420 MW Combined-Cycle Lausward Z:l 2A
25
a> 'lJ
a3 2)
00 32 33
Steam air preheater Fresh air ventilation fan Fresh air duet to steam generator Silencer Burners Flue gas duet Stack Gas turbines 1 and 2 Gas turbine exhaust duct to steam generator Gas turbine exhaust stack for single-cycle operation
3i
35 ffi
'37 ~ ~
40
Gas turbine exhaust duct gas heat exchanger (to be i Steam heated heat district heating Gas turbine exhaust gas exchanger for district District heating system Flue gas duct to main installed later) Hydraulically Sealing air supply
wed by a coal-burning forced-circulation stearn genera.eheat stearn turbine. Two fresh air fans make it possible, 'ctions on load, to operate the stearn process by itself, e gas turbine. One of the fresh air fans also supplies 6mbined-cycle operation to the stearn generator burner, xygen level in the gas turbine exhausts is not sufficient ill generation. flue gas is sent to a desulphurization unit after it generator. The uncleaned portion is mixed with
322
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
the cleaned to attain a stack temperature of approx. 70°C. The power plant is cooled using a natural circulation wet cooling tower.
SOME TYPICAL COMBINED-CYCLE PLANTS ALREADY BUILT 323
Figure ll-lla
Fig. 11-12 shows the principle of design and Fig. 11-13 the layout. Table 11-6 contains the most important technical data.
29
Table 11-6: Main Technical Data (Combined-Cycle Operation, of the power Plant Gersteinwerk, Block K Fuel for gas turbine Fuel for steam generator Air temperature Relative humidity Gas turbine power output Steam turbine power output Net power plant output Net efficiency of the installation (LHV) Gas turbine exhaust gas flow Gas turbine exhaust gas temperature Gas turbine inlet temperature Live steam flow Live steam data before turbine Live steam data after reheater, before turbine Condenser pressure Auxiliary fan supply capacity
10 80 112.5 656 711
40.85 503.4 481 950 495.5 186 530 40 530 0.066
°C %
MW MW MW Layout of the 420 MW Combined-Cycle Plant at Lausward erator
14 Feedwater tank with
re
spray deaerator
15 Feeclwater pumps 16 High pressure feed water heater 17 Part-flow economizers 1 and 2 18 Fun-flow economizer 22 Boiler circulating pump 23 Steam air preheater 24 Fresh air ventilation fan 25 Fresh air duct to steam generator
26 27 28 29 30 31
Mumer Air enclosure
Flue gas duct Stack Gas turbines 1 and 2
Air intake shaft; for gas turbine
This plant was designed to allow later rol\lnU,,,r,,;nn coal gasification system, with the gas produced gas turbine and the char in the boiler.
32 Gas turbine exhaust duct to steam 33 34
generator Gas turbine exhaust stack for single-cycle operation Gas turbine exhaust duct to exhaust gas heat exchanger (to be
installed later) 35 Steam heated heat 36
exchanger for district heating Gas turbine exhaust gas heat exchanger for
district heating (to be tnstalled later) 39 Hydraulically operated dampers
40 Sealing air supply
41
Steam turbogroup
42
Gas t urbogrou p transformers Station service transformers Control room Machine hall crane Gas turbine machine hall crane Machine hall Boiler room with water section and electrical section Gas turbine machine hall Reducing station for natural gas
transfonncr
43 44 45 46 47 48 49 50
324
COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
SOME TYPICAL COMBINED-CYCLE PLANTS ALREADY BUILT 325
Figure 11-12 Figure ii-iib
6
8
8
-0
a ~ "'
;:l
......., oj
oj
~ oj
p:; ~;., u
.. 0
0'-1/
.,:, Q)
~0'
o +L-IL-----.-.+
.0
~
~ 0
u
~
0 C'1
""...c:..., Q)
'-
...,0
g
;.,
.... oj
.1:i .-<
.-<
~
.-<
bil ~
Principle of the 75- MW Unit, Block K, at the
7 8 9 10 11
Part-flow economizer Steam turbine Condenser Low pressure feedwater heater Feedw~er tank! deaerJor
12 1'3 14 15 16
~rsteinwerk Power
Feed pumps Condensate pumps High pressure feedwater heater Air preheater Condensate tank
326 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
11.2.3 Hemweg Unit 7, EB Amsterdam, the Netherlands (Repowering) [l12] This plant is a very interesting example of the repowering an existing steam turbine plant. Unlike the example discussed Section 3.3, the boiler here has be reused in the new regime. weg 7 formerly was a modem 500 MW stearn turbine plant wi reheat, fired either with natural gas or heavy oil. To increase t efficiency of this plant, which uses relatively expensive fuels, has been converted into a combined-cycle plant. The resulting p is similar to that with maximum supplementary firing in the as presented in Section 3.2.2, but with one major dilleI'en Neither the boiler, nor the stearn turbine, nor the feedwater ing system was originally designed for operation with a bine instead of an air blower and regenerative air pr4ch<~a Modifications of both the boiler and the feedwater he:ltiI1l~ tern were therefore necessary. The following changes made on the boiler to allow it to operate on hot gas tUl~bil).E hausts instead of preheated air: • new ducts to the burners • new wind box with gas burners • additional new low and high pressure ec()nCmulZelrs Fig. 11-14 shows the thermal diagram of the Hp.mVlTp.l1. bined cycle after repowering, Fig. 11-15 the layout of The main technical data before and after the (,()lnv,:>r~i()n in Table 11-7.
SOME TYPICAL COMBINED-CYClE PLANTS ALREADY BUILT 327
11-7: Main Technical Data of the Hemweg 7 Power Plant Before Repowering for gas turbine for steam generator temperature turbine power output m turbine power output on service power fficiency of the plant (LHV) llrbine inlet temperature urbine exhaust temperature urbine exhaust flow earn flow earn data before steam turbine
°C MW MW MW %
oil/gas 15 500 13.5 41.3
°C °C kgls kgls bar
°C bar
414.9 177.5 535 0.035
After Repowering natural gas oil/gas 15 134.9 464 8.7 45.9 1070 534 506 344.4 161 535 0.036
328 COMBINED CYCLE CAS & STEAM TURBINE POWER PLANTS
11.3 Combined-Cycle Plants for Cogeneration
SOME TYPICAL COMBINED-CYCLE PLANTS ALREADY BUILT 329
Figure 11-13
11.3.1 Pegus Unit 12, Utrecht, the Netherlands The Pegus Unit 12 combined-cycle plant in the Netherlands is one of the most modern combined-cycle plants. It has been conceived as a cogeneration plant suplying heat to three ditlereIlt district heating systems and power to the grid. The most esting feature of this plant is that despite its being a CO~~eI1lef(l tion plant, it is capable of supplying power alone during summer, at the extremely high efficiency of nearly 52 %. Fig. shows the principle of design of the plant, which includes 150 MW gas-burning industrial gas turbine equipped with a low NO x combustor that produces less than 50 vppm of without the injection of water or steam. Fig. 11-17 sho model of the 150 MW gas turbine. The energy in the exhaust gas is recovered in a so];.>hi.sticl 3-pressure boiler, with the steam from the high pressure being reheated. The intermediate pressure steam is used steam turbine. The low pressure steam is produced by fl high pressure water and is used for feedwater heating deaerator, with the excess being piped to the steam turbirt hot water from the flash system is either used for the heating systems or, in summer, to heat condensate. The steam turbine has three casings. The steam exp the high pressure turbine is reheated in the mediate pressure turbine has a second admission mediate pressure steam and three extractions heating steam to four district heating condensers. is not extracted is fed to the low pressure tUl:biJlle, signed to operate at optimum efficiency even being extracted.
Layout of the 75- MW Unit Block K at th Ge t ' k ' e rs emwer Power Plant am generator am turbogroup ridenser turbogroup I crushers pumps
7 8 9
ill 11 12
E-filter Desulphurization unit Intake duct Fresh air ventilation Gypsum storage Stack
13 14 15 ill
Gas turbogroup transformer Steam turbogroup 10 kV switchgear Low voltage SWitchgear
330
COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS SOME TYPICAL COMBINED-CYCLE PLANTS ALREADY BUILT 331
Figure 11-14
Figure 11-15
.., s:: cd
p:; ~ u
~
..,:,
s::
~
a
0
C)
J
t-
..,
III
'8
~
.!!!
i
.-g
Fig, 11-15: Layout of the Hemweg Unit 7 Combined-Cycle Plant
f Gl
,t:
c:
...
0
c:
..
:e.. !!!.. 31
:;:)
Gl
'c
Q.
E
:.s
Q,
c:
Gl
c:
"0
U
:;:)
. .. .... 'S
~
lI)
III
...
C)
c:
Cl I:»
:;:)
c:
:;:)
E E III Gl
III Gl
C/)
C/)
N
l')
c:
Gl
"0 c: 0
0
.. c: Q,Oo
c:
Gl
III Gl
~
c0
:;:)
. =. ...: :.s. .. .. :;:)
f
II.
Q."& I:»Q:
0
~
~
'j(
IXl
c(
It)
II)
:;:)
Q.
E 1:»';::; E :;:)
:;:).5 f
"0
c: ::
0
U
w
Q. -'
I"-
0
U
0
Q.
"0
- ....
';::; 0 "0
Gl Gl
III I:» III
-c:o :;:).-
.!! Q. 0.~ ~ ~ '0 "0 __ I) IXl
W
:::t:
00
Ol
... 0
332
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
SOME TYPICAL COMBINED-CYCLE PLANTS ALREADY BUILT 333
Table 11-8 lists the main technical data of this plant.
Figure 11-16
Fig. 11-18 shows the dry low NOx combustor for the gas tur-
G
bine. This has 54 burners which operate on the premixing principle, Le., air and natural gas are mixed together before they enter combustor. Groups of these burners must be switched off at load in order to maintain an excess air ratio low enough to on'"I1'·''' good combustion. Fig. 11-19 shows the layout of the power which is entirely an indoor installation. Main Technical Data of the Pegus Unit 12 Combined-Cycle Cogeneration Plant
6
Fig. 11-16: Design Principle of the Pegus Unit 12 Combined-Cycle Plant 1 2 3
Gas turbine 4 Steam turbine Waste heat boiler 5 Heating condensers Deaerator/feedwater tank
6 7
Condenser Flash tank
temperature ing water temperature turbine power output turbine power output n service power net electrical output ectrical yield (LHV) eat output ng temperature, heating water g temperature, heating water fuel utilization (LHV) ine exhaust temperature ine exhaust flow e inlet temperature flow pressure temperature
°C °C MW MW MW MW % MW
°C °C %
°C kgls
°C kgls bar
°C
Maximum Heating Output
Maximum Electrical Output
natural gas 0 4 153.5 59.7 2.1 211.1 45.65 180.6 65
natural ga'i 15 20 141.4 84.6 2.7 223.3 51.74
la5 84.7 520.1 529.1 1070 54.8 69.5 490
51.74 524.6 505.4 1070 53.5 68 490
334 COMBINED CYCLE CAS & STEAM TURBINE POWER PLANTS
11.3.2 The Combined-Cycle Gas and Steam Turbine Cogeneration Plant, Unit 10, at PEGUS, in Utrecht, the Netherlands (Repowering) [50] This combined-cycle plant started operation in late 1978. It is equipped with two 30 MW gas turbines and one 40 MW extraction/condensing turbine. One important feature is the steam turbine, which was built as long ago as 1959 as a two-cvlind.~r condensing turbine. During the repowering, an extraction installed between the high pressure and the low pressure casings. This makes it possible to operate either as a heating plant or as a straight condensing plant (Fig. 11-20). The exhausts both the two gas turbines are supplied to two single-pressure w heat boilers. At the end of the boilers, there is a heating I which recovers the heat that remains downstream from the ste generator. This is used partly for district heating and partly feedwater preheating. Because the fuel burned is sulphur-~ gas, the exhausts can be cooled to 100°C (212 OF). For the technical data, refer to Table 11-9.
SOME TYPICAL COMBINED-CYCLE PLANTS ALREADY BUILT 335
Table 11-9: Main Technical Data of the Combined-Cycle Cogeneration Plant, Unit 10, at PEGUS, Utrecht
Air temperature Gas turbine power output Steam turbine power output 'r0tal electrical power output lectrical yield (LHV) eat output of heating condenser e;at output of heat exchanger heat output ming temperature, heating water going temperature, heating water of fuel utilization (LHV) rbine exhaust temperature bine exhaust flow rbine inlet temperature team flow am data
°C MW MW MW %
MW MW MW °C °C %
°C kgls °C kgls bar/DC °C
Maximum Heating Output
Maximum Electrical Output
Natural gas 0 2 x 30.8 26
Natural gas 0 2 x 30.8 38 99.6 40.9
87.6 35.9 79.8 31.8 111.6 65 95 81.8 519 2 x 158 945 2 x 19 38/645 100
0 18.6 18.6 65 95 41.5 519 2 x 158 945 2 x 19 38/465 100
336
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Figure 11-17
SOME TYPICAL COMBINED-CYCLE PLANTS ALREADY BUILT 337
Figure 11-18
Fig. 11-18: Dry Low NOx Combustor
338 COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
Figure 11-19
SOME TYPICAL COMBINED-CYCLE PLANTS ALREADY BUILT 339
A comparison of the data for maximum heating output with those for maximum electrical output shows the great flexibility of this installation. In winter, it provides heat and electricity at an energetic utilization rate of 82% and in summer it produces electricity at an afficiency of approx. 41 %. Fig. 11-21 shows the layout of the power plant. The gas tur-
bines and the waste heat boilers are installed in the converted boiler house of the former stearn plant. Fig. 11-22 shows one of he two gas turbines, Fig. 11-23 the repowered stearn turbine with e new extraction and cross-over pipes.
1.3.3 The Combined-Cycle Cogeneration Plant H 4/5 of Elektromark AG at Hagen, Germany his plant is another interesting example of the cogeneration eat and electricity, The 220 MW combined-cycleplant started operation in 1981. It consists of two gas-burning 75 MW gas ines, two two-pressure waste heat boilers, and one extraccondensing turbine (Fig. 11-24). It supplies process stearn at and 4.5 bar (170 and 50 psig) to a paper mill and district 'ng water at a max. temperature of 110°C (230 OF) to a large ing plant nearby. Provision has been made for expansion additional district heating in the future, heat boilers each have a high pressure and a low stearn generator with a economizer and a superheater. pressure stearn is fed either into the process stearn systhe stearn turbine. Table 11-10 shows the data at the of the installation. The overall layout of the entire that shown in Fig. 11-25. Fig. 11-26 shows a genof the power station.
340
COMBINED CYCLE CAS & STEAM TURBINE POWER PLANTS
SOME TYPICAL COMBINED-CYCLE PLANTS ALREADY BUILT 341
Figure 11-21
Figure 11-20
o 16
Fig. 11-20: Design Principle of the 100 MW Combined-Cycle Cogeneration Unit 10, at PEGUS, Utrt-'Cht 1 2 3
4 5 6
Gas turbine Waste heat boiler Heating loop Steam turbine Steam turbine condenser Condensate pumps
7 8 9
10 11
12
13 Heating Condenser 14 Hot condensate pumps 15 Heater Preheater Recirculating pumps 16,17 Feedwater tank! deaerator
Feed pumps Steam Steam heating District water
10 !
20 !
30 I
meters
Layout of the 100 MW Combined-Cycle Cogeneration Plant, Unit 10, at PEGUS, Utrecht
342 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Figure 11-22
SOME TYPICAL COMBINED-CYCLE PLANTS ALREADY BUILT 343
Figure 11-23
Steam turbine for the 100 MW Combined-Cycle Cogeneration Plant at PEGUS, Utrecht
Fig. 11-22: Gas turbine for the 100 MW Combined-Cycle Cogeneration at PEGUS, Utrecht
344 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Figure 11-24
Figure 11-25
2
2
Fig. 11-24: Design Principle of the 220 MW Combined-Cycle Cogeneration Hagen 1 2 3 4, 5
Gas turbines Waste heat boilers Steam turbine Steam users
SOME TYPICAL COMBINED-CYCLE PLANTS ALREADY BUILT 345
6 7 8
Condenser Reducing station Auxiliary condenser
5
10
-25: Layout of the 220 MW Combined-Cycle Cogeneration Plant at Hagen 5 6 7 8
Auxiliary condenser Main transformers Low voltage switchgear Feedwater and boiler circulating pumps
9 10 11
Water treatment unit Batteries Auxiliary boiler
COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
SOME TYPICAL COMBINED-CYCLE PLANTS ALREADY BUILT 347
Table 11-10: Main Technical Data of the Combined-Cycle Cogeneration Plant at Hagen
electrical power to the grid and generates 31.5 kgls (250,000 lb/hr) of wet steam (85% quality) at 70 bar (1000 psig). This process steam is used for enhanced oil recovery, Le., it is injected into the ground to increase the production from the oil wells located around the power plant.
346
Fuel Air temperature Gas turbine power output Steam turbine power output Total electrical power output Electrical yield (LHV) Process steam flow (12.8 bar) Process steam flow (4.5 bar) Process heat Rate of energy utilization (LHV) Gas turbine exhaust temperature Gas turbine exhaust flow Gas turbine inlet temperature High pressure live steam flow High pressure live steam pressure High pressure live steam temperature Low pressure live steam flow Low pressure live steam pressure Low pressure live steam temperature Low pressure feedwater temperature
Natural gas 15°C 2 x 76.6 MW 72.1 MW 225.3 MW 42.2 % 2.8 34.7 93.7 59.8 500
2 x 365 945 2 x 40.3 40.8 470 2 x 10.4
Stack temperature
11.3.4 The 100 MW Combined-.C~cle Plant AES-Placerita, CalifornIa, USA [1 The 100 MW combined-cycle plant built at L-'la,Cell'lT,GI near Los Angeles is a typical example of a US Co,gelrrel built under the PURPA law (Public Utility Re~~l;:;lt( Act), which was passed with the intention of cogeneration of heat and power. The plant SUl)plies
Fig. 11-27 shows the thermal diagram of the combined cycle.
The plant has two gas-fired gas turbines rated at 43 MW under site conditions. Under normal operating conditions, steam is injected into the combustor to reduce NOx emissions. In case of mergency, water injection is also possible. The exhaust from one f the gas turbines is directed to a heat recovery boiler which nerates the 85% quality process steam (steam ir\iection boiler), hUe the flue gas from the other is used to generate superheated am in a normal dual pressure boiler (steam electric boiler). Both pressure and low pressure steam are expanded in the ressure condensing steam turbine. An interconnecting duct es it possible to control the process steam flow. If less prosteam is required, some of the flue gas from the first gas ine is ducted over to the steam electric boiler. The cooling is cooled back down in a forced-draft wet cooling tower. e extremely low emission levels from this power plant are 'nly its most interesting feature: The concentration of NO x dry exhaust had to be held below 7 vppm at 15% 02. The on of steam or water into the combustor is not by itself 'ent to attain this Iowa level. Selective catalytic reduction systems had to be installed in both boilers. These systems ammonia to convert the NOx into nitrogen and water. The cal reactions have already been indicated in Section 9.1. e catalytic reduction works properly and with good conefficiency only within a temperature window of about (662 OF). If the temperature drops below 250 to 300°C 572 oF), the reaction is too slow. Above 400 to 450 °c ~42 OF) the ammonia is converted into NO x . The SCR un-
348 COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
SOME TYPICAL COMBINED-CYClE PLANTS ALREADY BUILT 349
its therefore must be installed in the evaporators of the heat recovery boilers, thereby dividing them into two sections.
Table 11-12: Main Technical Data of the AES Placerita Combined-Cycle Plant
A catalytic converter for CO has also been installed in each boiler to reduce by oxidation the emission of carbon monoxide from less than 10 vppm to approx. 1 vppm after the turbine. The basic
Fuel Air temperature Relative humidity Gas turbine power output Steam turbine power output Station service power Net power output Process steam flow Process steam conditions High pressure: Live steam flow Live steam pressure Live steam temperature w pressure: Live steam flow 've steam conditions ondenser pressure
reaction here is
Expensive acoustical precautions were taken to reduce noise levels at 240 m (800 ft) to less than 39 dbA, including the use of a cooling tower with low speed fans, special building large silencers on the gas turbines, etc. Table 11-11 shows the levels of the most important pollu1t;an:t~ after the gas turbines and after the boilers. Table 11-11: Emission levels from the AES Placerita After the gas turbines NOx (dry, 15% 02)
CO UHC (Particulates) Noise
38
7
< 10 <2
< 2 < 1 39 dbA at 800 ft
Table 11-12 summarizes the main technical data for Fig. 11-28 shows its layout.
temperature urbine inlet temperature llrbine exhaust temperature rbine exhaust flow
°C % MW MW MW MW
kgls bar kgls bar
°C
natural gas 24 26.7 2 x 43.8 15.0 2.6 100 31.5 70 bar / 85% quality 24.4 41.4 475
kgls bar bar
4.9 5.3 bar / saturated 0.082
°C °C °C
115/123 1085 535 2 x 167
kgls
350
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Figure 11-26
SOME TYPICAL COMBINED-CYCLE PLANTS ALREADY BUILT 351
Figure 11-27
Design Principle of the AES Placerita Combined-Cycle Plant 21 SCR catalytic converter
Fig. 11-26: View of the 220 MW Combined-Cycle
22 Ammonia injection Z:l SI-boiler feedwater pream turboset heater turbine (GT) 2i SE-boiler feedwater pumps rbocompressor 25 Condensate return pump turbogenerator a> Stack silencer poration cooler 'Zl SE-boiler HP economizer intake silencer (Part 2) bustion chamber 2B SE-boiler economizer 1 feed (Part 1) m injection ::9 SE-boiler HP evaporator perheater :D SE-boiler HP superheater m injection 31 SE-boiler LP economizer r injection ::Q SE-boiler LP evaporator ust silencer 33 SE-boiler HP drum ate isolator 3i SE-boiler LP drum lating damper 35 SE-boiler HP feedHer economizer water pumps :J) SE-boiylr LP feediler steamer catalytic converter water pumps
:J7 SE-boiler feed water :E ffi 40 41 42
43 44 45
46 47 48 49
00
tank Deaerator/feedheater Replacement water Steam turbine (ST) ST turbogenerator HP stop and control valve LP stop and control valve Bleed steam line Back-up steam bypass to deaerator Back-up steam bypass to steam injection HP steam bypass sect LP steam bypass section Steam condenser Condensate pumps
352
COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Figure 11-28
Chapter 12
\0
CONCLUSIONS
\~11 r--l --~ I
\L--=:::::=======n .............,
0'
to' 32' ..,'
Fig. 11-28: Layout of the AES Placerita Combined-Cycle Plant Gas turboset building 7 Chemical treatment area 8 ST transformer and auxSI-boiler iliary transformer area SE-boiler Steam turboset build- 9 GT transformers 10 Substations ing 11 Warehouse and workshop 5 Control building 12 Exhaust gas silencers 6 Cooling tower area
1 2 3 4
13 Cross-duct for 14 NOx water pumps 1'5 Ammonia tank 16 EnvironrnerltaJ
The thermodynamic advantages of the combined-cycle plant over simple gas or stearn processes and its great potential for development will favor its increased use in the future. Systems employing waste heat utilization alone will stand in the foreround in the future, since only they can fully exploit the high emperature potential of the gas turbine. For that reason, instaltions with maximum supplementary firing will further lose in portance. The combined-cycle plant without supplementary firing has e following advantages: • high efficiency
Efficiencies of more than 50% can be attained. • low investment costs Because 2/3 of the output is produced in a gas turbine and only 1/3 in a simple stearn process, the investment costs required are approx. 30% less than those for a conventional stearn power plant. small amount of water required The amount of cooling water required is only about 40 to 50% as much as for a stearn plant. great operating flexibility The simple stearn process makes it possible to start-up nd shut-down the plants quickly, which also affects fficiency in a positive direction (reduced start-up lpsses) hased installation .I3ec ause the gas turbines can go into operation much ooner than the stearn process, expansion in stages is
354 COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
possible. This makes it possible to adjust to the growth in demand for energy in a grid. In a third step, coal gasification can be installed if there is too sharp an increase in the price of gas or oil. e simplicity of operation A combined-cycle plant without supplementary firing is significantly simpler to run than a conventional stearn plant. Moreover, because combined-cycle plants are generally operated fully automatically, they are also especially suitable for use where operating staff is less experienced. e low environmental impact Gas-burning combined-cycle plants in particular are ideally suitable for use in heavily populated regions because of their high efficiency and their low emission levels for pollutants. In particular, the very low nitrogen oxide levels of clean combined-cycle plants will be one of their most attractive features. Furthermore, gas-fired combined-cycle plants produce per kWh only 40% of the C02 produced by a coal-fired plant. e advantages for cogeneration of heat and electricity The good thermodynamic properties of the cOJmblinE~d cycle are highly desirable here. Electrical yields of more than 40% are quite common in heating or strial power plants with a backpressure turbine. The limited fuel flexibility of the combined-cycle greatest disadvantage for use in countries where oil in short supply. However, combined-cycle plants with sification or PFBC plants could in the future become an alternative to conventional coal-fired stearn power flue gas scrubbing. Net efficiencies of more than tainly be attained, which would permit the sound and economical use of coal in a comtlined·-cy·C!E
CONVERSIONS Conversion of the main units used Multiply
by
to obtain
bar Btu Kelvin ft gal (US)
14.504 1.055 1.8 0.30480 3.7854 2.54 0.94781 2.20046 0.26417 3.2808 1.0936 0.068948
psi kJ °Rankine m I cm Btu lb US gal ft
yd bar
nversion formulas into
Formula:
of
(9/5)OC + 32 5/9 (OF - 32)
°C °C
K + 273
ent: ficien.cies cited in this book are in all cases based on the Heatmg Value (LHV).
SYMBOLS USED TlWB Tlc C
Rate of heat utilization in waste-heat boiler Carnot efficiency Velocity
dl
Outside diameter of a tube or pipe
d2 f
Inside diameter of a tube or pipe Frequency
h
Enthalpy
~h
Difference in enthalpy Isentropic efficiency
TlIS k
m
Heat flow coefficient Mass flow
n
Rotational speed Nusselt number Power output Pressure Power coefficient Difference in pressure Pressure loss on flue gas end in waste-heat boiler Polytropic efficiency Polytropic efficiency for dry steam Prandtl number Heat flow Heat flow, amount of heat Reynolds number Surface area Temperature in K
357
358
t
b.t V 11
X
a 11 11
r A A ~ P
COMBINED CYClE CAS & STEAM TURBINE POWER PLANTS
Temperature in °C Difference in temperature Loss Specific volume Steam content of the wet steam Heat transfer coefficient Efficiency Dynamic viscosity Pinch point of the evaporator Excess air coefficient Heat conductance Average absorption capacity of the turbine Density
INDICES USED Air Outlet from a heat exchanger or feedwater heater Cooling water Inlet to a heat exchanger or feed water heater Economizer Exhaust gases Flue gas Gas turbine Heater High pressure Combined-cycle plant / Waste-heat boiler At the generator terminals Low pressure Live steam Medium pressure Process steam Steam Supplementary firing Steam turbine, steam process Supplied Waste-heat boiler Water/steam circuit Design point Gas turbine inlet Gas turbine outlet Flue gas temperature after supplementary firing Stage group of a turbine: inlet Stage group of a turbine: outlet 359
u,
Zza::LZ •. gz;;;;:; £
APPENDIX I CALCULATION OF THE OPERATING PERFORMANCE OF COMBINED-CYCLE INSTALLATIONS (Refer to Section 7.1) 1. Equations for the heat exchangers
The equations of energy, impulse, and continuity are used to calculate the steady-state behavior of economizers. The contiequation comes down in the steady state to: ~m =
O.
(24)
The impulse equation can be simplified into:
!1p
=
(geometry)
(25)
~AUTC"TC'''' because the pressure losses both in the economizer
in the evaporator has a negligible influence on the energy ations, the assumption (26)
lid. In this case, the pressures along the heat exchanger reconstant, on both the gas and water sides. The energy equaa small section dx of a heat exchanger, which can be approximately as a tube, can be written as follows: =
k· !1t .
1t .
d . dx.
(27)
361
APPENDIX I 363
362 COMBINED CYCLE CAS & STEAM TURBINE POWER PLANTS
If it is assumed that the heat transfer coefficient k remains
constant over the entire length of the heat exchanger (economizer or evaporator), Equation 27 becomes:
12 =
L
k· S J/::,.1 (x).
(28)
o
L
l
In the general case, the expression /::,.1 (x) cannot be integrated. The heat exchanger must therefore be dealt with in the small element.
At the design point, Equations (30) and (31) become:
t2sJ
=
t2sJ =
k o ' S . /::"tmo· in SO' /::,.h
SO
(32)
=
in Go
'
/::,.h Go .
(33)
Dividing Equation (30) by Equation (32) and Equation (31) by (33) yields the formulas: (34)
In the special cases of a heat exchanger with counter or allel flow, however, integration is possible assuming that specific heat capacities of both media along the heat ex,cn:anlser remain constant.
(35) Subtracting Equation (35) from (34) produces:
The result of the integration is the logarithmic average for the difference in temperature, which can be written in form: L
J/::,.1 (x)
o
-
This average value can also be used for a recuperator or evaporator. The heat exchangers do not, in fact, operate in cordance with an ideal counterflow principle, but the errors main negligible.
ko . in G . /::,.h G k . in Go . /::,.h Go
is the non-dimensional, global equation of heat transfer the heat exchanger. If, in addition, Equation (31) is taken consideration and the heat flow coefficient k is known, a '.Y"'~VU' of equations is obtained that defines the heat exchanger.
can be calculated using the following equation: 1
Substituting Equation (29) into Equation (28) yields:
12 =
_1_ aG
k· S· /::"t m .
From Equation (24), the amount of heat exchanged can pressed as follows:
Q
=
in . /::,.h S S
mG'
/::,.h G ·
(36)
·
+ -.!!L In !!J.. + 2A
d2
d2
d1 .
(37)
as
owever, the relative values k/k o appear in the heat transfer lURtlO][1. From this: _1_ + d1 aGo d2 . aS o k (38) K- k o _1_ +41 aG d2 . as
APPENDIX I
364 COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
The heat transfer coefficients on the gas end of the economizer and the evaporator ( alG) are from 0.1 to 0.01 times as large as those on the stearn end ( aI S). Moreover, both values always shift in the same direction ( + +, - ) For these reasons, the following relationship may be used:
365
By substituting mG/S for cG QG' one obtains:
Re =
mG'
'fJG'
d1 S .
(45)
Then, substituting this expression into Equation (43), the geometric parameters disappear:
(39) (46)
The ai-value on the gas end can be calculated as follows using the Nusselt number:
If the mass flow is constant, all that remains is:
(40)
(47)
Here , C , m , and n are constants that depend mainly upon the geometry involved. From this, the following expression is obtained:
For m, one can use 0.57 for pipes that are offset from and 0.62 for pipes that are lined up with one another.
aG =
C'.
AG .
Rem . p,n.
If this is substituted into Equation (39), the geometric COJrrstan' C' disappears:
Rem . p,n ARm Go' eo' PrR' 0 AG .
K
=
For gases, the Prandtl number is almost exactly a cOJrrsta,. Therefore:
AG
'fJG
m
The value of the expression ~ . (~) , Go
'fJG
does not vary greatly and depends practically only on the propof the gas. It can be replaced with the following approxation:
1 - (7 0
-
7) . 5 . 10-4
(48)
are 7 the average gas temperatures along the heat exin the design and operating point. This produces for the value of K : (49)
For the Reynolds number, the following expression
Re =
CG . PG .
'fJG
d1
equation, only m deBends to a slight extent on the geoof the boiler. r
366 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
It is more complicated to calculate an exact value for K in the case of a superheater because the heat transfer on the stearn end is poorer than that in the evaporatl)r.
When all of these equations have been obtained for all parts of the boiler, the waste-heat boiler has been defined mathematically. Similar equations can also be formulated for calculating the condenser. When calculating the economizer and the evaporator of a drum boiler, the problem arises that the state of the feedwater at the inlet to the drum is not clearly defined. For that reason, two different cases must be considered: • The feedwater is supplied with stearn at its entry into the drum (partial stearn out in the economizer) • The feedwater is undercooled at its exit from the economizer and must be heated to saturation temperature in the drum. 3. The Steam Turbine Most stearn turbines in combined-cycle plants operate in ing pressure operation and generally have no control stage nozzle groups. This simplifies calculations, because sin:ml.ati.O: of the control stage and the inlet valves is fairly co]mplucat(~c A portion of a stearn turbine with no extraction is delm,eet one equation for its absorption capacity and one for its ency. The absorption capacity is approximately using the of Cones. In general, according to Ref. [1]: (50)
ms m so
111 . Pa
APPENDIX I 367
In stearn turbines, the pressure ratio is always very small. This makes it possible to replace the quadratic expression with 1. The ratio of the absorption capacities is likewise close to 1. What remains is then:
ms
=
/-;;::-;;;;;-.
11 PaD'
m so
(51)
Va
At a constant rotational speed, the efficiency of a stage depends only upon the enthalpy drop involved. In part-load operation, however, no relatively great change occurs in that gradient except in the last stages. Because this means that the greatest portion of the machine is operating at a constant efficiency, it can be assumed that the polytropic efficiency remains constant. The turbine efficiency is calculated in the same way for the design point. The following formulas are used to calculate efficiency: For parts of the turbine operating in the superheated zone: 1JpoL tr.
=
constant
(52)
parts in the saturated stearn: 1J
po
I =
1J
poL tr.
-
(1 -
X a)
+ (1 2
-
X a)
(53)
polytropic efficiency selected should be such that the depower output is once again actually attained in the design t. following equation is used to determine the adiabatic ef-
Mo' PaD (54)
368 COMBINED CYCLE CAS & STEAM TURBINE POWER PLANTS
These equations make it possible to establish the expansion line of the steam turbine. The power output of the steam turbine can be determined from this by allowing for dummy piston, exhaust, generator, and mechanical losses. The dummy piston losses in single-flow reaction turbines are approx. proportional to the live steam pressure, and are typically between 400 to 600 kW. Mechanical losses range from 150 to 250 kW and exhaust losses at full load are generally in the range of 20 to 35 kJ/kg steam. 4. Solving the System of Equations
Taken together, all the equations in the waste-heat boiler, the steam turbine, etc. produce a system which can only be solved by iteration. The following values are known: • thermodynamic data in the design point • the marginal conditions for the particular operation to be calculated (exhaust data for the gas turbine, cooling water data, etc.) • oper'lting mode of the feedwater tank (sliding or pressure) • Gas and Steam Tables The following information must be found: • behavior of the steam circuit Fig. Appendix-l shows the method used for solution. One with the superheater, inputting into the computer a first mate for live steam temperature and pressure. Using the of Cones and the energy equation, one can then live steam flow and the gas temperature following the heater. Next, from the heat transfer equation, a new live steam temperature can be determined. This is
,"-a,JL,"-UU"',,.,
APPENDIX I
369
for further iteration. The procedure is repeated until all three equations have been fulfilled. The energy and heat transfer equations for the economizer and the evaporator can be used to determine a second approximation for live steam pressure. If the feedwater tank is in sliding pressure operation, a first estimate for feedwater temperature is also necessary.
The new value obtained for live steam pressure is then used to continue calculation of the superheater and the turbine until all equations for the boiler and the Law of Cones agree. The next step is to calculate the preheating of the feedwater. This is usedif the pressure in the feed water tank varies- to find a new approximation for feedwater temperature. The boiler is then recalculated, using this new value. Finally, the condenser pressure and extraction flow are determined in another iteration. Then, this information, one can determine the power output of steam turbine.
370 COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
Figure Appendix-l
DEFINITION OF TERMS AND SYMBOLS 1. APPROXIMATION P FD , t
FDr
It sW )
rI
The selection of terms and symbols below has been based on national and international definitions and expanded- where it appeared necessary- with additional terms and symbols. The selection wa<; adapted to the special technical requirements of this book.
I I I
+ I
I I 1
Term
Symbol Unit
Definition
Annual service hours Tann. (Annual operating time)
hr/yr
Number of hours per year (operating time per year) during which a unit (or a group of units) was or is to be operated, continuously or with interruptions
Annual utilization time TNj for nominal output (utilization time, utilization hours)
hr/yr
The annual utilization time for nominal output is obtained by dividing the operating output during the operating period by the nominal power output.
Approach temperature
K
Undercooling of the feedwater at the inlet to the boiler drum (difference between actual temperature of feed water and saturation)
ST
The quotient obtained by dividing the work available Pv·Tv by the nominal work
Fig. Appendix 1: Calculation of Operating and Part-Load Behavior: Solving the System of Equations
371
372 COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
DEfiNITION Of TERMS AND SYMBOLS 373
Term
Symbol Unit
Definition
Term
Symbol Unit
Definition
Availability (time)
llT
The availability (time) of a power station or power plant unit is obtained by dividing the availability (the sum of operating time plus time at readiness) by the nominal time:
Power coefficient
PC
The flow coefficient of a plant cogenerating heat and electricity is obtained by dividing the net electrical power generated in a given time span by the usable heat generated in that same time span, both limited to the limit of the plant
"Bottoming cycle"
A thermal process that operates in the lower range of temperature, following after a high temperature process
Efficiency of power generation
In cogeneration plants, the ciency of power generation obtained by dividing the eIE~ctl1c al power output by the arrloumt additional fuel supplied. ditional fuel is required electricity is being nr'[)ChlN>,rl addition to the process heat.
Efficiency of the steam process
II ST
The efficiency of the steam cess is obtained by dividing electrical power output of steam turbine by the heat plied to the steam process with waste heat tion alone, it can be the formula:
Efficiency of the steam/ water cycle
II
The efficiency of the water cycle is obtained ing the electrical output steam turbine generator amount of heat supplied water or steam in the bo
or
a
Exergy
E(e)
Exhaust loss of the steam turbine
kWs/kJ
kJ/kg
kJ/kg
The maximum technological work obtainable from a system in accordance with the Second Law of Thermodynamics if the system is brought reversibly into equilibrium with its environment. Non-recoverable losses due to kin etic energy in the exhaust steam of the turbine The forced outage rate of power stations, power plant blocks, or their components is obtained by dividing their outage time due to malfunction by the sum of the operating time plus outage time due to malfunction:
enerator output SW
kWs/kJ
PGEN
kW (kVA)
The generator output of a power station or a power plant block is the power available at the generator terminals. The generator output is the gross output. PGEN
=
PGROSS
DEFINITION OF TERMS AND SYMBOLS
374 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
Term
Symbol Unit
Heat output
kW
r
Rate of fuel utilization l1n
Rate of waste heat utilization
Tl
WB
Rate of work utilization l1AE
Term
Symbol Unit
K
The minimum difference in temperature between the exhaust gas and the water or steam is a waste boiler.
kJ/kJ
The rate of fuel utilization in plant cogenerating heat electricity is equal to the tient obtained by dividing sum of net electrical power usable heat generated in a time span by the energetic valent of the fuel supplied same time span. The quotient obtained by ing the heat supplied to the ter or steam by the waste available to the waste heatb The rate of work utilizllticln production capacity in time span is the Qwotil~nt production in that time vided by the work same unit could have
Definition with the full production capacity continually in operation.
The heat output to cover nonblock-connected heat demand, e.g., heat supplied to a district heating system Standard environmental conditions per ISO: Total air temperature 15°C Total air pressure 1.013 bar Relative humidity 60 %
ISO conditions
Pinch point of a waste heat boiler
Definition
375
The two work measurements must be of the same type, gross or net. Reliability (time)
The reliability (time) is obtained by dividing the operating time by the sum of operating time plus outage time due to malfunctions:
Station service power
PE1G(EL) kW
The station service power of a power station or power plant block is the amount of power required to drive all motor-driven block auxiliaries and ancillaries (power consumption of the motors), plus the electrical losses in station service transformers and electrical transmission losses within the power station.
Thermal efficiency
Tl
The thermal efficiency of a power station or a power plant block generating electricity alone is obtained by dividing the electrical power output by the amount of energy supplied.
"Topping cycle"
kl
A thermal process operating in the upper range of temperatures, followed by a low temperature process. The energy losses due to wetness in the wet steam section of the turbine
BIBLIOGRAPHY 1. General Literature and Studies (1)
Traupel, W. : Thermische Turbomaschinen, Springer Verlag.
(2)
Knizia, K. : Die Thermodynamik des Dampfprozesses, 3rd. Ed., Vol. I, Springer Verlag
(3)
Buxman, J. : Combined Cycles for Power Generation, von Karman Institute Lecture Series, 1978-6.
(4)
Wunsch, A.: Combined Gas/Stearn Turbine Power Plants: The Present State of Progress and Future Developments, Brown Boveri Review 65 1978 (10), pp. 646 _ 655.
(5)
Foster-Pegg, R.W.: Stearn Bottoming Plants for Combined Cycles, Journal of Engineering for Power, April, 1978.
(6)
Schueller, K.H.: Kombinierte Dampf-Gas-Prozesse, BBC Nachrichten, Oct.! Nov., 1959.
(7)
Gasparovic, N.: Fluide und Kreisprozesse fur Warmekraftanlagen mit grossen Einheitsleistungen, Brennstoff Warme Kraft, Vol. 21 (1969), pp. 347 _ 359. Zickhut, W.: 1st der Dbergang auf einen Zweikreisprozess bei thermischen Kraftwerken wirtschaftlich sinnvoll? Brennstoff Warme Kraft, Vol. 22 (1970), pp. 561 _ 568. Mills, Rob. G.: A Thermodynamic Analysis of the Combined Stearn Turbine - Gas Turbine Power Cycle, Thesis presented at the ETH, 1957.
378 COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
BIBLIOGRAPHY 379
(10)
Seippel, C., Bereuter, R: ZurTechnik kombinierter Dampfund Gasturbinenanlagen, Brown Boveri Mitt. 47 1960 (12) pp. 788 - 799.
(19)
Hiibner, R: Kombikraftwerke - umweltfreundliche LOsung des Energieproblems, Elektrische Energie-Technik, Vol. 23 (1978), No.6.
(11)
Auer, W.P.: Praktische Beispiele der Abwarmeverwertung von Gasturbinen in kombinierten Anlagen, Brown Boveri Mitt. 47 1960 (12), pp. 800 - 825.
(20)
Gasparovic, N.: Spitzenstromerzeugungin GaslDampfanlagen, Elektrizitatswirtschaft No. 24, Vol. 78 (1979).
(21) (12)
Bruckner, H., Wittchow, E.: Kombinierte GaslDampfturbinenprozesse: Wirtschaftliche Stromerzeugung aus Gas und Kohle, Brennstoff Wax-me Kraft, Vol. 31 (1979), No.5, pp. 214 - 218.
Watzel, G.V.P., Essen: Beeinflussung des LeistungsverhaItnisses zwischen Gas- und Dampfturbine bei kombinierten Prozessen, Brennstoff Warme Kraft, Vol. 22 (1970), No. 12.
(22)
Krieb, K.H., Ratzeburg, W.: Dbersicht iiberneue Kraftwerkstechnologien, Technische Mitteil. No.3, Vol. 71, March, 1978.
(13)
Dibelius, G., Pitt, R, Ziemann, N.: Die Gasturbine irn Wandel technologischer u. wirtschaftlicher Entwicklungen, VGB Kraftwerkstechnik, 61 (1981), No.2, pp. 75 -82. (23)
(14)
Charlier, J., Bruckner, H.: Combined Gas/Stearn Turbine Power Plants with Supplementary Firing, Kraftwerk Union.
Timmermanns, A.P.J.: Combined Cycles and Their Possibilities, von Karman Institute Lecture Series 1978-6.
(24)
Pfenninger, Dr. H.: Das kombinierte Dampf-/GasturbinenKraftwerk zur Erzeugung elektrischer Energie, Brown Boveri Mitt. 60 1974 (9), pp. 389 - 397.
Buchet, E.: Les centrales a cycle combine gaz-vapeur, Revue Generale de therrnique, No. 233, May, 1981, pp. 391 - 404.
(25)
Gusso, R, Moscogiuri, G.: Combined Production of Thermal and Electric Power by Means of Gas Turbines and Combined Cycles, Quaderni Pignone 25.
Huhle, D.: Combined-Cycle Plants for Generating Economical Medium-Load Power, Brown Boveri Review 61,1974 (1), pp. 9 - 15.
(26)
Huhle, D.: Combined Gas/Stearn Turbine Power Station Tungshiao 3 + 4, Turbomachinery International, July/August, 1979.
(27)
Schonweitz, B.: Der 420-MW-Kombiblock des Kraftwerkes Lausward, BBC Nachrichten 1977, No.7.
(28)
Mayer, M.: GUD - An Unfired Combined Cycle Approach to Energy Utilization, ASME Publication 79-GT-131, 1979.
(15)
(16)
(17)
Todd, D.: The Future of the Combined Cycle, Turh<)m:a" chinery International, April, 1978.
(18)
Gasparovic, N.: GaslDampf-Anlagen mit Zw'ei<:lrulckdaJmpfsystem als optimale Kraftwerke zur Deckung der last, Elektrizitatswirtschaft No.3, Jan. 31, 1977.
BIBLIOGRAPHY
380 COMBINED CYClE GAS & STEAM TURBINE POWER PLANTS
(40)
Ikeda, K., Arakawa, T., Wada, A.: 140 MW Combined Cycle Plant for Repowering Kawasaki Power Plant, the Japanese National Railways.
Timmermanns, M., Guiette, J.L., Klees, P., Harmel, P., Germeau, J.P., Fontaine, B.: Cycles Thermodynamiques Combines Gaz/Vapeur Aspects Theoriques Applications Pratiques et Aspects d'Exploitation, AIM Liege, Centrales Electriques modernes - 1978.
(41)
Farmer, R: Repowering nets ESB Ireland 42 % efficiency, Gas Turbine World, May, 1981, pp. 24 - 30.
Sakai, Inui, Tokanaga: Combined Cycle Power Plant "HITSTAG", Hitachi Review, Vol. 27 (1978), No.4.
(42)
Wunsch, A, Mayrhofer, M.: Power Plants for the Medium Output Range, Criteria Governing the Choice of the Optimum Plant, Brown Boveri Review 65, 1978 (10), pp. 656 - 663.
(43)
Morris & Wilson, Leyland, Watson & Noble: Combined Cycle Power Generation, New Zealand Energy Research and Development Committee, Report No. 14, Oct., 1976.
(44)
Tomlinson, L.O., Snyder, R.W.: Optimization of STAG Combined Cycle Plants, Presentation at the American Power Conference, Chicago, Ill., Apr. 29 May 1, 1974.
(45)
Frutschi, H. U., Plancherel, A.: Comparison of Combined~ Cycles with Steam Injection and Evaporisation Cycles, 1988 ASME Cogen-Turbo IGTI, Vol. 3.
(46)
Foster-Pegg, R.W., P.E., The Steam-Turbocharged Gas Turbine, (Unpublished paper, March 27, 1987). Address: 806 Columbia Ave., Cape May, N.J.
(47)
Hofer, P.: Combined Cycle Yields Top Efficiency, Turbomchinery, March, 1981, pp. 30 - 42.
(48)
Knizia, K. et al.: Erweiterung des Kraftwerkes Gersteinwerk urn 4 x 400 MW, Brennstoff Wax-me Kraft, Vol. 23 (1971), No. 12, pp. 503 - 512.
(29)
Gard, M. Brestancia Repowering Plant Increases Output and Efficiency, General Electric International Gas Turbine Reference Library, SOAC7603.
(30)
(31)
(32)
Mills, Dr. RG.: Development and Testing of a Modular Gas Turbine/Steam Combined Cycle, CIMAC, 14th International Congess on Combustion Engines.
(33)
Wadman, B.: New High Efficiency Combined-Cycle System , Diesel/Gas Turbine World-wide, Jul./Aug., 1980.
(34)
Cooper, V., Duncan, R: Baseload Reliability in a Combustion Turbine? EPRI Journal, June, 1978.
(35)
Abels, J.-P.: La centrale a cycle combine de SOCOLIE a Angleur, Revue ACEe, 2.80.
(36)
Elsasser, RF.: Das kombinierte Daml)fi~raft-'GasttlrbinEm Kraftwerk "Marbach III" der EVS, El(~ktrizjitat;sw'irt:sclllatt 70 (1971), No. 15.
(37)
Venouil, R, Lasiaille, R: Centrale thermique de sur-Seine, La Technique moderne 60, 1968 (12), pp. - 10 and 61, 1969 (7), pp. 237 - 246.
(38)
(39)
.'181
Lohle, H.: Derkombinierte bach der Neckarwerke- Auslegung, Fahrweise Betriebsbewahrung, VGB Kraftwerkstechnik 53 No.9. Mori, Y., Iwata, K., Kimura, H.: Design of Model:TI bined Cycle Power Plant, Technical Review,
382 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
(58)
Design Principles and Operational Experience of the Combined Cycle District Heating Power Maticu Mertaniemi Cimag 81, Helsinki. '
(59)
Gubser, H.R: Combined Gas/Stearn Turbine Power Station for District Heating in Utrecht, Brown Boveri Review 65, 1978 (10), pp. 687 - 690.
Malewski & Holldorff: Combined Cycles for Pipeline Compressor Drives Using Heat, ASME Publication 79-GM-162.
(60)
Kehlhofer, R.: A Comparison of Power Plants for Cogeneration of Heat and Electricity, Brown Boveri Review 67, 1980 (8), pp. 504 - 511.
Lang, RP., Chase, D.L.: Stearn and Gas Turbine Combined C~cle Equipment Currently Available for Natural Gas Pipelmes, ASME Publication 79-GM-114.
(61)
Schuller, K.H.: Keizkraftwerke, Handbuchreihe "Energie", Vol. 7, Chapter 4.
(62)
Schiiller, K.H.: Industriekraftwerke, Handbuchreihe "Energie" Vol. 7, Chapter 5.
2. Combined-Cycle Plants for Cogeneration (49)
(50)
(51)
(52)
BIBLIOGRAPHY 383
Schneider, A., Unseld, Dr. H.: Ein kombiniertes Gasturbinen-Darnpfkraftwerk fill industrielle Versorgung, Energie, Vol. 27, No.3, March 1975.
Loffel, H., Schauff, P.: Wirtschaftlichkeit eines Gasturbinenkombiblocks mit Abhitzekessel zur Energieversorgung eines Chemiewerkes, Brennstoff Warme Kraft, Vol. 31 (1979), No.3.
3. Closed-Cycle Gas Turbines and Special Systems
(53)
Kehlhofer, R: Combined Gas/Stearn Turbine Power Plants for the Cogeneration of Heat and Electricity, Brown Boveri Review 65, 1878 (10), pp. 680 - 686.
(63)
Keller, Oechslin, Haas, Frutschi, Christ: Geschlossene Gasturbinen fur aIle Brennstoffe, Escher Wyss Mitt. No.1 1969. '
(54)
Resing, Dr. J.C.: Energiebesparing door toepassing stadsverwarming bij de NV Pegus te Utrecht, de in~~enle"lll" 36, No. 36, Sept. 8, 1977.
(64)
Borman.n, H., Buxmann, J.: Kombinierte Kraftwerksprozesse mIt geschlossener Gas- und Dampfturbine Brennstoff Warme Kraft, Vol. 33 (1981), No.5. '
(55)
Frei, D.: Gasturbinen zur Prozessverbesserung inclustrilel ler Warmekraftwerke, Separate print, TR, Sulzer
(65)
Buxmann, J., Bormann, H.: The Closed Cycle Gasturbine/Steamturbine, von Karman Institute Lecture Series, 1978-6.
(56)
Blad, J. Operation of a Combined District Heating Power Production Scheme with a Combined Cycle Gas bine , von Karman Institute Lecture Series 78/6.
(66)
S~mler, 1.: Closed cycle plant promises 50 % cycle effiCIency on coal, Gas Turbine World, May, 1980.
(57)
Schoch, P., Franz, B.: Erweiterung des Kraftwerkes Munchen urn eine Gas-/Dampfturbinen-Heizkrafta111 VGB Kraftwerkstechnik, Vol. 59 (1979), No. 11.
(67)
Kinney, C.A.: Closed Cycle Gas Turbine Heater Program Final Report, Summary, prepared for the U.S. Dept. of Energy under Contract EF-77-01- 2611.
BIBLIOGRAPHY 385
384 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
(68)
· Ivan G., P .E ... The Reheat-Gas-Turbine Combined Rlce CYcl~, Turbomachinery International, July-/Aug. 1981.
(69)
Schroder, H.J.: Die Gasturbine mit Zusatzdampf aus eigener Abwarme, MTZ, Vol. 19, No.2, Feb. 1958.
4. Coal Gasification, Fluidized Bed Combustion, and Charged Boilers (70)
Gluckman, M.H., Fox, G.R, Ahnez, D.J., S~ah, R:..: C~m bined cycle integrated with second generatlOn.gasiflcatlOn systems, Turbomachinery International, Apnl, 1981, pp. 33-41.
(71)
Fichtner, K.: Kohlevergasung, Dbersicht uber die Verfahrenstechnik und Bewertung der grundlegenden Verfahren , VGB Kraftwerkstechnik 61, No.2, Feb. 1981.
(72)
(73)
(74)
(75)
(76)
Mezzedini, V.: Integrated Coal Gasification Combined Cycle Plant, Diesel & Gas Turbine Worldwide. Stasa, F .L., Osterle, F.: The Thermodynamic P€:rf()I.'m~ln<~e of Two Combined Cycle Power Plants Integrated wlth Coal Gasification Systems, Journal of Eng. for Power, 103, July, 1981. Peterson, J.R, Lucke, V.H.: Commercial Powerplant sign Development for the Coal Fired Combined Cycle, bustion, Jan. 1979, pp. 29 - 36. Haselbacher, Dr.H., Basler, B., Luthi, H.: "The '-' .....,,~~~ tion to Gas Turbine Interface," Institute of EnergyConference, Harrowgate, England.
Energy Conversion Alternatives Study (ECAS) - ~UlmIIl Report. Report No. NASA TM-73781.
(77)
AUf, RK., Tomlinson, L.O.: Gas Turbine Heat Recovery Systems and the Future Utilization of Coal Derived Fuels, CIMAC - Congress, 1981.
(78)
Hoy, H.R, Roberts, A.G., Jack, A.R: Pressurized Fluidized Bed Combustion of Coal for Combined Cycle Systems, Modern Power Systems, April 1981, pp. 25 - 30.
(79)
Luthi, H., Hofe, T.: "A Study for the Application of SHELL's Proven Coal Gasification Technology Integrated with the ASEA BROWN BOVERI State of the Art Gas Turbine Type 13E into a 250 MW Gasification Combined Cycle (GCC) Module," 23rd Intersociety Energy Engineering Conference, Denver, USA, 1988. Paper No. 88 92 75.
(80)
Kehlhofer, R, Thompson, B.R., Greil, C.: "Coal Gasification Combined Cycle Plants- A Clean Way from Coal to Electricity," VGB Congress, Strassbourg, France, 1986.
(81)
Heins, G.L., Gurski, P.S.: A low Btu coal gasification process for utility application, Modern Power Systems, April, 1981, pp. 37-40.
(82)
Petzel, H.K., Meenzen, P.: Voelklingen prototype coal plant will give lowest pollution, Modern Power Systems, April, 1981, pp. 33-35.
(83)
Pfenninger, H., Yannakopoulos, G.: Stearn Power Stations with Pressure- Fired Boilers, Brown Boveri Review 62, 1975 (7,8), pp. 309-317.
(84)
Meyer-Kahrweg, H.: Betriebserfahrungen mit den aufgeladenen Dampferzeugern von 340 tlh Dampfleistung, Vortrag, VGB Conference "Dampfkessel und Dampfkesselbetrieb," 1975.
(85)
Dorstwitz, U., Wien, H.: Die KDV-AnlageLuenen, Sammelband VGB Confetence, "Kohlevergasung in der Energietechnik", VGB-TB 201 (1979).
386 COMBINED CYCLE GAS &. STEAM TURBINE POWER PLANTS
(86)
Miiller, R.: Kohleveredlung zu Gas und Fliissigtreibstoffen, Siemens- Energietechnik 2 (1980), No.7, pp. 227 - 235.
(87)
Pillai, K.K., Repowering with PFBC for efficiency, emissions and heat rate improvement, EPRI 1988 seminar on Fluidized-Bed Combustion Technology for Utility Application, Palo Alto, CA, May 3-5, 1988.
(88)
Pillai, K.K., "Downtown Stockholm site for first PFBC power plant," Modern Power Systems, July, 1988.
BIBLIOGRAPHY 387
(96)
Todd, D.M.: Design and Application of Heat Recovery Steam Generators, Nederlandsche electrolasch maatschappij, Leyden.
(97)
Lampert, D.: Low-Temperature Corrosion in Feed-Heaters Heated by Flue Gas, Brown Boveri Review 65, 1978 (10), pp. 691 - 695.
(98)
Bruckner, H., Wittehow , K: Kombinierte DampfGasturbinen Prozesse: Einfluss auf Auslegung und Betrieb der Dampferzeuger, Energie und Technik 24 (1972), No. 5, pp. 147 - 152. Schwarzenbach, H., Koch, K: Dampfturbinen, Handbuchreihe "Energie", Vol.3, Chapter 7.
5. Components and Plant Description (89)
Endres, Dr. W., Gasturbine, Handbuchreihe "Energie", Vol. 3, Chapter 6.
(99)
(90)
Endres, J.P.: Vergleichsgrundlagen bei Gasturbinen verschiedener Auslegung, Energie, Vol. 30, No.9, Oct., 1978, pp. 309-314.
(100) Haase, Neidhofer: Elektrische Maschinen, Handbuchreihe "Energie", Vol. 4, Chapter 2.
(91)
Bitterlich, K: Einfliisse der Thermodynamik kombinierter Dampf-Gas Prozesse auf die Konstruktion der Dampferzeuger, VDI 1971, No. 11, pp. 693-697 and 13, pp. 814-818.
(101) Gratzki: Messen und Regeln, Handbuchreihe "Energie" , Vol. 4, Chapter 6. (102) Braun: Dampferzeuger, Handbuchreihe "Energie", Vol, 5, Chapter 3. 6. Performance
(92)
Pickhardt, K.F.: Abhitzekessel hinter Gasturbinen, gie, Vol. 30, No.9, Sept., 1978.
6. Operating Performance
(93)
Jaekel, G.: Warmeaustauscher in kraftwerken, Energie, Vol. 28, No.1, Jan. 1976.
(103) Kehlhofer, R.: Calculation of Part-Load Operation of Combined Gas/Steam Turbine Plants, Brown Boveri Review 65, 1978 (10), p. 679.
(94)
Leikert, K.: Feuerungen fur Dampferzeuger hinter turbinen, Separate Print, Techn.Mitteilungen, No. Vulkan Verlag, Essen, 1976, pp. 103 - 108.
(95)
Gericke, B.: Der natiirliche Wasserumlauf in At.hi1;ze(1a:o ferzeugem, BrennstoffWarme Kraft, Vol. 39,1979,
(104) Gericke, B.: An- u. Abfahrprobleme bei Abhitzesystemen insbesondere hinter Gasturbinen, Brennstoff Wiirrne Kraft, Vol. 32, (1980=, No. 11. (105) Latzel, W., Wilhelm, H.: Nichtlineare Simulationsprobleme bei Umschaltvorgangen an einem Kraftwerksblock im Kombibetrieb, Report, BBC- Mannheim.
388 COMBINED CYCLE GAS & STEAM TURBINE POWER PLANTS
(106) Lampert, D.: The Effect of the Structure of Combined Gas/Steam Turbine Plants Upon Their Reliability, Brown Boveri Review 65, 1979 (2), pp. 133 ffg. (107) Koch, H., Briihweiler, E., Strittmatter, W., Sponholz, H.J.: The Development of a Dry Low NO x Combustion Chamber and the Results Achieved. International Congress on Combustion Engines, CIMAC, Oslo, June 3-7, PaperTl. (108) NASA Conference Publication 2078, Premixed prevaporized Combustor Technology Forum, NASA-CP-2078, Jan. 1979. (109) Lefebvre, A.H., ed.: Lean Premixed-Prevaporized Combustion. Workshop held at NASA Lewis Research Center, NASA CP-2016, Jan. 1977. (110) Aoyama, K., Mandai, S. (Mitsubishi Heavy Industries): Development of a Dry Low NOx Combustor for a 120 MW Gas Turbine, Modern Power System, Nov., 1984. (111) Gecek, M., Reisner, J.: "Turkey Installs Major CombinE~d Cycle Plant," Gas Turbine development, May 1987, 29 - 39. (112) Aerni, A., Kehlhofer, R., Kotschenreuther, H.: Inc:re:::LSiIl@ the Economy of Fossil-fired Stearn Power Plants by version to Combined-Cycle Plants, Separate Print, Kraftwerkstechnik, Vol. 67, No.3, March 1987, pp. - 215. (113) Jungers, G., Kehlhofer, R., Plancherel, A.: AES Pla'cer:it;;l.... Economical Power Generation with Minimum 1<'... "; ...",, mental Impact, ASME, New York.
