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Steam Generators for the Next Generation of Power Plants
Aspects of Design and Operating Performance
Dr. J. Franke, R. Kral and E. Wittchow
Siemens AG, Power Generation Group KWU
Introduction
The requirements to be met by the next generation of power plants are subject to various criteria
depending on regional considerations. Whereas efficiency together with environmental protection,
availability and power generating costs head the list of priorities in the highly industrialized
countries, investment costs and financing are becoming increasingly important factors in the
growth countries. Steam generators, as the most costly component and the component of
fundamental importance to power plant availability, play a significant role in both cases. Against
this background, Table 1 summarizes various development tasks which may give rise to new
design and operating solutions for future steam generators.
Table 1: Development tasks for steam generators.
Adaptation to process with high power plant efficiency
•
Improved materials for supercritical steam conditions
•
Minimization of exhaust gas loss
•
Utilization of exhaust gas heat for heating condensate and feed water
Meeting increasingly stringent requirements for operating behaviour
•
Low part loads with high steam temperatures
•
Start-up process with low service life consumption despite shorter start-up times
•
Low material stress even with large and rapid load changes
•
Minimization of NOx-emissions with simultaneous increase in combustion efficiency
Reducing investment costs
•
•
•
Simplified combustion chamber tubing
Reduced and simplified start-up system
Optimized thermodynamic design
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Adapting the Steam Generator to the Power Plant Process
Figure 1 shows the correlation between main steam conditions (MS conditions) and the semi-net
heat rate of a steam power plant. The semi-net heat rate in this context is the net heat rate
corrected for the auxiliary power requirement for the turbine-driven feed pump. The lines of equal
heat rate on this diagram refer to a 700 MW unit with single reheat and a condenser pressure of
0.04 bar. Intervals between lines of equal heat rate correspond to 100 kJ/kWh.
Main steam pressure upstream of turbine [bar]
When considering Fig. 1 we are
400
confronted
360
by
the
following
100kJ/kWh
question: given the same heat
320
rate, for example, should main
280
steam
240
parameters
of
220
bar/610°C or 300 bar/580°C be
200
selected? This question regarding
160
540
560
580
600
620
640
660
680
700
720
the
correct
main
steam
Main steam temperature upstream of turbine [°C]
Figure 1:
Lines of constant heat consumption (half net) for various main steam conditions.
parameters is answered by the
degree
of
material
stress
sustained by the most highly stressed thick-walled component, i.e. the main steam header.
Studies performed in this field have produced interesting results, as discussed below.
Table 2:
Materials for steam generators with high steam temperatures.
Components
Membrane wall
Superheater tubes
Headers
Material
13CrMo4 4
7CrMoVTiB9 10
HCM 12
X3CrNiMoN17 13
Esshete 1250
TP 347 H FG
Alloy 617
Alloy 625
P 91
E 911 / NF 616
NF 12
TP 347 H FG
Alloy 617 modified
Possible
5
Temperature at 10
creep resistance at
100 mm²/(s.t.p.)
515 °C
580 °C
600 °C
630 °C
640 °C
655 °C
∼ 690 °C
∼ 740 °C
590 °C
615 °C
645 °C
655 °C
∼ 700 °C
materials
for
future
steam generators are listed in
Table 2. This consists of materials
which are either already proven,
are currently being developed or
are under discussion. Figure 2
5
shows the 10 hours creep fatigue
values, based on VdTÜV material
specifications, for a number of
materials which are suitable for
main
steam
information
headers.
supplied
for
The
the
material NF12, a ferritic steel with a 12 % chrome content, which is still in development, is based
5
on a published anticipated value of "100 N/mm² at 650°C (10 h)". Straight line curves for the
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same level of material stress, i.e. same fatigue life, are plotted for these materials in Fig. 3. and
provide information on possible MS pressure and MS temperature combinations at the turbine
inlet. These values apply to MS headers with a 1.8 ratio of outside to inside diameter, a ligament
efficiency of 0.8, and take appropriate design margins for pressure and temperature into account.
The different gradients of the straight line curves reflect the corresponding profiles of the material
strength curves in the relevant
Creep resistance [MPa]
temperature range in a simplified
200
180
160
140
120
100
1
80
2
3
4
5
1
X20
2
P91
3
NF616
4
NF12
5
TP 347H FG
6
Alloy 617
form; other sizes of headers result
in a minor parallel displacement of
the straight line curves for the
same level of material stress. On
6
the basis of this, the level of
60
material stress sustained by a P91
40
20
500
550
600
650
700
750
800
Temperature [Cº]
Figure 2:
Creep resistance (105 h) of several highly heat-resistant
materials for steam generators.
header, for example, is the same
at main steam conditions of 250
bar/595°C and 350 bar/568°C.
If the lines plotted in Fig. 1 and the straight line curves for ferritic chrome steels shown in Fig. 3
are now combined in Fig. 4, it is possible to mark the main steam conditions for every material
which will produce the lowest heat rate for a certain header size assuming the same level of
material stress. Combination of these points then produces a curve with optimum steam conditions
for these chrome steels.
Main steam pressure upsteam of turbine [bar]
This method was used to ascertain
400
the optimum main steam conditions
Do /Di =1.8
fv
=0.8
360
for the individual material groups
320
(Fig. 5). Allowing for the material
280
strength values given in Fig. 2, the
240
optimum main steam conditions are
Alloy 617
200
X 20
P 91
NF 616
NF 12
within
TP 347H FG
160
540
560
580
600
620
640
660
680
700
720
the
indicated
range.
Austenitic steel was included here
Main steam temperature upstream of turbine [°C]
Figure 3:
Lines of equal material stress
for given main steam header dimensions.
for reference purposes only as it is
now rarely used for thick-walled
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components because of its unfavorable characteristics with regard to operating flexibility. The
same method can also be used in principle for the main steam line and produces two interesting
results:
• Main steam pressures of around 300 bar upstream of the turbine should not be exceeded even
with the newly developed chrome steels. This also applies to high-temperature projects which
necessitate use of nickel-based alloys, such as the Advanced 700°C PF Power Plant which is
being discussed as part of the THERMIE project.
• Taking investment costs for the HP feed heater train and for a major part of the steam
generator into consideration, cost-effective main steam pressures are below the optimum
values given in Fig. 5.
Main steam pressure upstream of turbine [bar]
Main steam pressure upstream of turbine [bar]
360
Da / Di = 1.8
=0.8
fv
320
NF 12
E 911/
NF 616
320
100kJ/kWh
Alloy 617
X 20
280
240
240
Ferritic
X 20
200
540
560
P 91
580
E911/
NF616
600
NF 12
620
640
660
200
540
560
580
Further development of materials
600
620
Ni-based
material
640
660
Further development of processes
and components
0,6
48
47
46
45
250 bar
540/
560ºC
44
167 bar
538/
538ºC
1.5
X20
X20
270 bar
580/
600ºC
285 bar
600/
620ºC
300 bar
625/
640ºC
1.6
0.7
0,6
0,8
Double
reheat
0,4
Steam
turbine
efficiency
Auxiliary
power
requirements
Waste heat
utilization
in steam
generator
Boiler
efficiency
Pressure
losses
(vertical
tubing
0.6
1.3
Water /
steam
cycle
Fuel:
bituminous coal
Condenser pressure:
0.04 bar
41
P 91
E 911/
NF 616
NF 12
Ni-based
720
The optimum main steam
conditions
300 bar
700/
720ºC
700
Figure 5:
Optimum main steam conditions
with given main steam header dimensions.
50
49
680
Main steam temperature upstream of turbine [°C]
51
42
Austenitic
Main steam temperature upstream of turbine [°C]
Figure 4:
Optimum main steam conditions for ferritic chromium steels
with given main steam header dimensions.
43
TP 347H FG
P 91
Optimum
main steam
conditions
280
360
identified
in
these studies will then
produce
the
net
efficiencies
shown
in
Fig. 6 subject to further
advances in the field of
materials
development.
Net efficiencies in the
region
of
50
%
are
feasible in conjunction
Figure 6:
Measures for increasing efficiency
of steam power plants.
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with appropriate process engineering measures and component improvements.
It is also necessary to examine the arrangement of heating surfaces in the flue gas path. Hightemperature corrosion and steam-side scaling become increasingly significant in heat exchanger
tubes at steam temperatures above 600 °C. Measurements published by the CEGB in 1988 show
that maximum corrosion occurs in
-9
Material thinning rate [10 m/h]
austenitic
at
wall
temperatures of between 650 and
1400
50
700°C and that rates of material
1200
40
thinning rise with increasing flue gas
1000
30
640
800
20
700 °C
temperatures
(Fig.
considerations
are
7).
Cost
therefore
not
always the only criterion on which to
10
0
materials
Gas temperature [°C]
60
580
600
620
640
660
Tube wall temperature [°C]
Figure 7:
High temperature corrosion
in austenitic heat exchange surfaces.
base
the
arrangement
of
final
superheater heating surfaces in the
flue gas path.
Improved Utilization of Exhaust Heat
Feedwater temperatures will remain at around 280°C to 300°C in future. Because of
thermodynamic considerations and the problems associated with the dew point of sulfuric acid,
this places strict limits on any further reduction in the flue gas temperature to below 120°C which
can be achieved through use of larger air heater heat exchange surfaces. One potential solution to
this problem is the heat recovery system in which the flue gases are cooled to 80 °C directly
upstream of the flue gas desulfurization plant. With this process, either the flow of flue gases
through the air heater is decreased or the flow of air increased. In both cases, the slopes of the
temperature curves plotted for flue gas and air converge because some of the heat output is
transferred to the water-steam cycle (Fig. 8). In a coal-fired steam generator without a high-dust
DeNOx system, this can be implemented with a gasside air heater bypass with feedwater and
condensate heating surfaces. However, a hot gas recirculation system is useful in steam
generators with high-dust DeNOx systems in order to prevent fouling of the feedwater and
condensate heating surfaces with corrosive ammonium hydrogen sulfate, which is difficult to
remove.
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This heat recovery system allows efficiency improvements of up to 0.6 percentage points in hardcoal-fired power plants and in excess of 1 percentage point in lignite-fired plants due to the larger
Combustion
air
340 °C
HP
heater
Flue
gas
380 °C
specific flue gas flows. It
Temperature [°C]
400
Air heater,
Bypass heater
Indu- Flue gas
ced- cooler
draft
Air heater
120 °C
LP
heater
93 °C
300
only appropriate for power
Feedwater
200
100
42 °C
Condensate
plants which do not use flue
gas heat to reheat the flue
gases downstream of the flue
125 °C
Flue gas
cooler
however, that this system is
Flue gas
Air
Bypass
heater
should be borne in mind,
80 °C
38 °C
Figure 8:
Exhaust gas heat recovery system
Configuration and temperature profile in air heater.
gas desulfurization system,
i.e. where the flue gases are
discharged via the cooling
tower.
Design and Process Engineering Measures to Improve Operating Performance
Use of rifled tubes for water walls of the combustion chamber can significantly improve operating
performance. Rifled tubes have two important advantages over smooth tubes:
1. At pressures below 200 bar, heat transfer is so efficient that the tubes are safely cooled even at
extremely low mass flow densities. The difference between smooth tubes and rifled tubes is
particularly evident in terms of their impact on tube wall temperatures in areas of high heat flux
in the burner region, for example (Fig. 9).
2. The amount of heat transferred from the inner wall surface to the fluid is also higher in the
pressure range between 210 and 220 bar that is unfavorable for heat transfer. Given the same
boundary conditions, the same wall temperatures as in a smooth tube are achieved at about
half the mass flow density.
Use of rifled tubes for the water walls therefore allows the "BENSON minimum load" to be reduced
from the previous value of 35 % (smooth tubes) to 20 %. This permits the operating range with
high main steam temperatures to be extended downwards without necessitating additional control
and changeover actions. Thanks to this low "BENSON minimum load", night-time or weekend
shutdowns with their associated increased life expenditure are no longer necessary, even for
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intermediate peaking duty. This is an important advantage particularly for the future generation of
high-temperature plants.
A "BENSON minimum load" of 20 % simultaneously means that the mass flow rate through the
evaporator during startup can be reduced to 20 %. Transition to BENSON mode operation can
therefore already take place at 20 % load; rapid elevation of main steam temperature up to the
necessary conditions for turbine rolloff for a warm or a hot start takes less time and entails lower
startup losses than previously.
A superheater bypass is worth thinking about again for high-temperature plants. This reduces dips
in main steam temperature during the initial startup phase and supports the main steam
temperature setpoint controller while the plant is being run up to temperature. This reduces
material stresses throughout the power plant unit during startup.
Main steam
temperature [°C]
Inner wall temperature [°C]
Smooth tube Rifled tube
500
Upper limit curve
400
Minimum BENSON
load
380
[%]
Mass flux
[kg/m²s]
External heat flux [kW/m²]
Pressure
[bar]
360
35
20
700
200
Lower limit curve
250
700
200
Temperature
difference [K]
340
40
320
Fluid
300
Max. allowable
temperature difference
Burner range
280
-40
0.2
0.3
0.4
0.5
0.6
0.7
0.8
Steam fraction [-]
Figure 9:
Tube wall temperatures in burner area at low loads.
0
25
50
Time [min]
Figure 10:
Typical startup behaviour on cold start
with forecasting load margin computer.
Instrumentation and Control Measures for Improved Operating Performance
There is also still scope for I&C measures to significantly enhance the steam generator's operating
performance. Out of the measures listed in Table 3, this report will be looking at only the newly
developed predictive load-margin computer and the combustion diagnostics system.
The load-margin computers used to date make insufficient allowance for the significant thermal
inertia of thick-walled components during startup, and stress limits are frequently exceeded. Wall
temperature measurements are also subject to considerable time lags.
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Table 3:
I & C measures for improved operating behaviour.
Forecasting load margin computer
Steam temperature behaviour is calculated in advance with a model, from
which setpoints for steam temperatures pressure and output are determined.
Condensate throttling for frequency stabilization
Step changes in unit load are transferred to the steam generator only as a
continuous load change.
New feedwater control
Accounting for evaporator storage behaviour prevents unnecessary
temperature changes at the evaporator outlet on load changes.
Improved main steam pressure control on start-up
Smooth transition from pressure increase to maintaining constant pressure
prevents temperature fluctuations.
Combustion diagnosis
Measurement and evaluation of spectral lines in combustion chamber enables
determination of flame temperatures and gas concentrations and analysis of
combustion process.
The predictive load-margin
computer uses a computer
model which predicts future
differential temperature and
thermal stresses from the
measured variables steam
temperature,
steam
pressure and steam mass
flow for set time intervals
(Fig.
10),
producing
continuously
a
updated
forecast.
The
maximum
permitted
temperature
is
calculated from the results of this forecast by means of parameter variation. The temperature
computed in this way is used to control the setpoints for steam temperature, pressure and firing
rate resulting in a straightforward startup and shutdown strategy with minimized material stresses.
Not only the water-steam cycle but also the combustion process is likely to see further
improvements in operating performance. The keyword here is combustion diagnostics.
Besides visual observation of the flame pattern, the quality of the combustion process has always
been evaluated to date by measurement of input parameters - air flow and delivery rate of coal
feeder system - and by analysis of the flue gases (O2, CO, NOx) at the steam generator outlet.
Combustion processes are optimized during the planning phase using simulated computer models
and by specialist teams during commissioning and subsequent operation. None of these methods,
however, has ever involved acquisition and subsequent evaluation of metrological data on the
combustion process.
The combustion diagnostics system developed by Siemens now fills this gap (Fig. 11). Special
cameras - one camera per burner - measure the spectral lines of the gas in the furnace. A
software program uses this data to compute temperatures and gas concentrations, so producing
an analysis of the combustion process.
The major advantages this gives the operator are self-evident:
• The commissioning phase for the combustion system, which generally takes several months to
complete, can be shortened considerably.
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• Burner and classifier settings are easily adjusted to match the burnout behavior of different
types of coal; material thinning of furnace walls resulting from CO spiking is avoided.
• Low NOx operation, even during dynamic processes, reduces costs for NH3 and catalyst
consumption.
• It may also be possible to reduce the total excess air requirement because all burners can now
be supplied with the correct air flow with greater precision than previously.
The suitability of this innovative
Standard Control
New Measurement
Sensor
Operation
Observation
Evaluation
Combustion
Analysis
Boiler
technology
been
power plants. As the next step it is
combustion
into
Air Control
Damper
already
demonstrated in a number of
planned
Closed-Loop Control
has
the
to
integrate
this
diagnostics
system
combustion
control
system. This would allow it to
initiate automatic actions to control
Figure 11:
Combustion Diagnosis
Optical Measurement with Combustion Analysis.
air distribution if changes in the
combustion process are required.
Reduced Investment Costs
Increased power plant efficiency achieved by raising main steam parameters and/or by installing a
heat recovery system entails a higher level of investment. However, this additional outlay can be
offset by various cost-reducing factors, some of which will be discussed below.
One interesting cost-cutting option is the provision of vertical tubing for water walls of the
combustion chamber (Fig. 12). Membrane walls of this type with rifled tubes are considerably
easier and therefore more cost effective to manufacture and install than water walls with spiralwound, smooth tubing. This is in addition to the operating advantages discussed earlier and
illustrated in Fig. 10.
The BENSON boiler with vertical tubing, which has attracted major interest worldwide, is supplied
by BENSON licensees with the usual function-based warranties. An expert's report commissioned
by a bank in connection with the financing of a specific project also rates this concept positively in
comparison with conventional water wall designs.
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Moreover, use of rifled tubes - regardless of whether the water walls are spirally or vertically tubed
- means that the startup system can be dimensioned for a 20 % evaporator flow rate. Circulating
pumps are no longer necessary provided that an adequate water inventory can be stored for the
startup procedure. Since it is known from previous experience that steam pressure is generally
between 60 and 120 bar prior to a warm or hot start, cheap, rugged centrifugal pumps of standard
design and dimensioned for pressures of up to 130 bar can be used in other cases, irrespective of
the type of evaporator tubing and the BENSON minimum load, instead of expensive circulating
pumps with wet-rotor motors. These pumps, which are installed in a secondary loop, merely have
to be fitted with an additional safety valve (Fig. 13).
Turbine
35% minimum
BENSON output
Turbine
20% minimum
BENSON output
Mass flux reduction
from 2000 to 1000 kg/m2s
flow characteristic
as in drum boilers:
increased heat input to an individual
tube increases throughput in that tube
Cost-effective fabrication
and assembly
Minimum BENSON output: 20%
Simple startup system for
20% evaporator throughput
Reduced slagging
on combustion chamber walls
Figure 12:
Vertical tube combustion chamber for BENSON steam generators
Principle and characteristics.
Figure 13:
Startup systems for BENSON steam generators.
A standard feature of two-pass steam generators of American or Japanese design is the inclusion
of widely spaced platen walls to form part of the furnace heating surfaces. Only when the flue
gases come into contact with heating surfaces with a transversal spacing of less than 300 to
400 mm is it necessary for the average flue gas temperature to have decreased to around 50 K
below the ash softening point. By bringing the central European approach into line with this design
philosophy it would be possible to raise the temperature of the flue gases as they enter the platen
heating surfaces, thereby reducing investment costs. One particular reason for the apparent
feasibility of this approach is that improved combustion due to finer coal pulverization and more
highly differentiated admixture of air is known to reduce the tendency of the platen heating
surfaces to become clogged with slag.
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Other potential methods of reducing costs which have already been proposed by other parties are
included only briefly here:
• Avoidance of excessive design margins
• Economizer with externally ribbed tubes
• Simplified platform design and construction
• Single-train air and flue gas path
• Warranties to be restricted to most frequently burned coal types (e.g. acceptance of load
restrictions when burning adverse types of coal)
Summary
The purpose of this paper is to demonstrate that state-of-the-art steam generator technology still
has considerable potential for further development which can be exploited for the steam
generators of the next generation of power plants (Fig. 14). This applies not only to the steam
generators themselves but also to their integration into the power plant process.
Startup system
for 20% output
Optimum combination of
main steam pressure and
main steam temperature
Additional implementation of intelligent
I&C systems
Combustion
diagnosis
Rifled combustion
chamber tubes
Vertical tube
combustion
chamber
Finned economizer
tubes
Heat recovery
system
Figure 14:
Features of modern steam generators
Summary.
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References
|1|
Naoi, H., Ohgami, M., Mimura, H., Fujita, T.: Mechanical properties of 12Cr-W-CO ferritic
steels with high creep rupture strength. Materials for Advanced Power Engineering 1994.
Liege October 3 - 6, 1994
|2|
Meadowcroft, D. B.: An introduction to fireside corrosion experience in the Central
Electricity Generating Board.
Werkstoffe und Korrosion 39, 45 - 48 (1988)
|3|
Griem, H., Köhler, W. and Schmidt, H.: Heat Transfer, Pressure Drop and Stresses in
Evaporator Water Walls - From Experiment to Design.
VGB Kraftwerkstechnik 79 (1999), Vol. 1, p.
|4|
Franke, J., Köhler, W. and Wittchow, E.: Evaporator Designs for BENSON Boilers, State of
the Art and Latest Development Trends.
VGB Kraftwerkstechnik 73 (1995), Number 4.
|5|
Franke, J., Cossmann, R. and Huschauer, H.: BENSON Steam Generator with VerticallyTubed Furnace, Large-Scale Test under Operating Conditions Demonstrates Safe Design.
VGB Kraftwerkstechnik 73 (1993) Vol. 4, pp. 353 - 359
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