Gunter Klefenz
Automatic Control
of
Steam Power Plants
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CIP-Kurztitelaufnahme der Deutschen Bibliothek
Klefenz, Gunter:
Automatic control of steam power plants / by
Gunter Klefenz. Transl. from German by Vladimir F.
Tomek. - 3., rev. ed. - Mannheim; Wien;
Zurich: Bibliographisches Institut, 1986.
Einheitssacht.: Die Regelung von DampfkraftWerken <engl.>
Preface to the English Edition
The lively demand from foreign countries made it seem sensible to publish
an English edition additionally to the French edition. Thus, the third
revised edition of 1981 was translated by Dr. Vladimir F. Tomek, Dublin,
to whom Iwould like to express my sincere gratitude for an excellent
translation. Only the bibliography has been expanded by the subject lit¬
erature written in English.
ISBN 3-411-01699-X
In conclusion, grateful acknowledgement is due to the publishing company
for their pleasant cooperation as well as for the care taken with the lay-out
of this book.
Minden, February, 1986
G. Klefenz
Preface to the 3rd Revised Edition
In comparison with the preceeding edition, the 3rd edition has been thor¬
oughly revised. This had become necessary due to the amount of new
knowledge gained over the last ten years. Substantial supplementary chan¬
ges have been introduced in the areas of unit control, combustion control,
and feedwater control. A review of bled-off steam control for rapid release
of power has been incorporated for the first time, and the chapter on
combined heat-and-power plants has been expanded. The passage dealing
with the simulation of the drum level controlled systems has been com¬
pletely re-written. Finally, the bibliographical references have been supple¬
mented by the incorporation of important new publications on power
plant control.
All rights reserved, including
of this publication may be those of translation. No part
reproduced, stored in a retriev¬
al system, or transmitted, in
any form or by any means,
electronic, mechanical, photocopying,
recording, or other¬
wise, without the prior written permission
of the publish¬
er. This also applies to the use
of the publication for
educational purposes, such as preparation of course
notes.
© Bibliographisches Institut,
Zurich 1986
Printed in Germany by Druckerei
Speyer;
bound by Pilger-Druckerei GmbH,Krembel,
Speyer
ISBN
Iwould like to thank in particular Mr. Rainer Seidel for the valuable sug¬
gestions and discussions, as well as for proofreading the revised manuscript.
Further, Iam grateful to the publishers who were always willing to
accomodate my requirements.
Minden. August, 1981
3-411-01699-X
i
G. Klefenz
Preface
Preface to the 1st Edition
It would be impossible to imagine our present highly technological era
without power stations. At the same time, a modern power station which
does not rely on automatic control is almost impossible to think of. This
is because automation is a necessary condition for safe operation which
minimizes material fatigue and can be conducted with minimum staff,
enabling efficient management of a plant.
The present book is intended to provide a survey of the current situation
in power station control, as well as to facilitate an introduction into this
particular field for students, plant engineers, and control technologists.
The latter point is the main reason why particular emphasis has been put
on descriptive representation, and why the text is accompanied by signal
flow diagrams (= block diagrams) in addition to the many control loop
diagrams. Basic knowledge of the fundamentals of control and plant engi¬
neering techniques had to be assumed. There is practically no mathema¬
tical description. Instead, the text provides rules-of-thumb and graphical
methods for a sufficiently accurate determination of the various control
characteristics, both dynamic and static. These are particularly important
in the planning stages where it is often necessary to estimate control
dynamics from only a few design data. Generally, for preliminary calcu¬
lations particular accuracy is not demanded.
As to the arrangement of this book, power plants are at first considered
as a unit. This is followed by individual descriptions of turbine controls
and boiler controls. Naturally, the main part of the book is dedicated to
boilers. An explanation of all the essential boiler control loops is followed
by a discussion of the pertinent signal flow diagrams of the controlled
systems. The relevant references to technical literature are listed at the
end of each section.
All the views expressed in the individual sections of the book are predo¬
minantly those of the control engineer. It is realised that architectural
considerations should have preference if the object happens to be the
construction of a plant. Unfortunately, such conflicting views can be
touched upon only briefly. The interested reader is referred to the rele¬
vant literature.
7
As regards the symbols used in the book, it should be mentioned that as
far as possible current standards are being adhered to. However, in order
to avoid misunderstandings, some deviations have become unavoidable.
Iam grateful to Director, Mr. G. Pressler, for accepting the book for
inclusion in the Control Engineering Series, which is published by him.
Iwould also like to express particular thanks to Mr. W. Opitz for his help
in proofreading the manuscript as well as for the many indications of
possible improvements. Finally, Iwould like to gratefully acknowledge
the endeavour of the publishers to meet all my wishes.
Minden, March, 1971
G. Klefenz
r
Table of Contents
. 11
Introduction
13
Basic Design of a Power Plant
13
2.1 Unit Arrangement
14
2.2 Busbar Arrangement
17
Main Control Objectives
27
Generator Control
32
Turbine Control
34
Load
Isolated
Supplying
5.1 Nonreheat Turbine
37
Grid
Power
a
to
Connected
5.2 Nonreheat Turbine
40
5.3 Single-Reheat Turbine
44
5.4 Accessory Turbine Controls
46
5.5 Sliding Pressure Operation
50
Unit Master Control
57
a
Control of Boilers on Busbar
62
Boiler Control
62
8.1 Types of Boilers
62
Boiler
8.1.1 Natural Circulation
64
Boiler
8.1.2 Forced Circulation
64
8.1.3 Benson Boilers
66
8.1.4 Sulzer Boilers
68
8.2 Control Loops
74
Loop
Control
Pressure
Steam
8.2.1 Live
83
Control
Loop
Flow
Air
8.2.2
99
8.2.3 Furnace Draught Control Loop
100
8.2.4 Steam Temperature Control Loop
109
8.2.5 Feedwater Control Loop
130
8.2.6 Reheat Steam Temperature Control Loop
134
8.2.7 Other Control Loops
138
8.3 Signal Flow Diagrams of Controlled Systems
8.3.1 Steam Pressure Controlled System in a Drum Boiler. . 139
8.3.2 Steam Pressure Controlled System in a Benson
150
Boiler
8.3.3 Steam Pressure Controlled System in a Sulzer Boiler . 155
158
8.3.4 Steam Temperature Controlled System
173
8.3.5 Level Controlled System in a Drum Boiler
10
_______
Table of Contents
8.4
Signal Flow Diagram
of «a wvuouii
Benson jDuner
0
Boiler
InclllHinor Controls
Cr»n +*•/-*!
Including
8.5 Quality of Control
9 Combined Heat-and-Power Plant (CHP
Plant)
e
10 Nuclear Power Plants
10.1 Types of Reactors
10.2 Control in Nuclear Power Stations
10.3 Dynamic Behaviour of Nuclear
Reactors
11 Appendix
11.1 Symbols
11.2 Bibliography
11.3 Subject Index
ana a Turbine,
and
turbine,
180
183
191
196
196
198
202
212
212
217
247
1 Introduction
Power plants are used to convert the raw energy available in nature into
electrical energy. When the conversion has as an intermediate stage the
production of thermal energy contained in steam, we talk about steam
power plants.
In a steam power plant the first step is the conversion of raw chemical
energy into thermal energy. This process takes place in the so-called boiler
or steam generator. The thermal energy is then transported by the carrier
steam into the turbine where it is changed into mechanical energy.
Finally, the mechanical energy is transformed into electrical energy in
the generator (Fig. 1).
Turbine
Boiler
Raw
energy
5
U
Thermal
energy
h
Generator
Mechanical
energy
Electrical
energy
as carrier)
Fig. 1
Scheme of a steam power plant.
Power plants may be designed to produce as their main product some
form of thermal energy, and not necessarily electrical energy. The heatand-power plants provide steam needed for district heating, while many
industrial plants (primarily power plants in the chemical industry) are
used to produce process steam. In all such power stations the electrical
energy is, to a certain degree, only a by-product. These variations in
energy production give one possibility of classifying the power plants.
They can be divided into:
— condensing power plants (for pure power production), and
— heat-and-power plants (primarily for heat production).
Another frequently used classification criterion is the fuel which is fired.
The main distinction is made between fossil and nuclear fuels. Fossil fuels
can in turn be subdivided into solid fuels (coal, brown coal, etc.), liquid
12
1Introduction
fuels (oil), and gaseous fuels (blast furnace gas, natural gas, etc.)- It is
likewise possible, and also customary, to combine the individual fuels.
As will be shown in more detail later, the above quoted characteristics
are essential for control. Other criteria, such as the size of the plant, etc.,
are only of minor importance, and will not be discussed.
2 Basic Design of a Power Plant
It appears expedient to start with a description of the most important plant
designs; discussion will, however, be limited to such features as are neces¬
sary for the synthesis of the respective control loops. The two basic types
of plant to be distinguished for control purposes are the unit arrangement
(containing a single turbine and usually only one boiler), and the arrange¬
ment using a common live steam range (with one or more turbines and
several steam generators, all units interconnected).
2.1 Unit Arrangement
At present, the unit arrangement is the most common in use. As can be
seen from Fig. 2, in a unit power plant the boiler, the turbine, the genera¬
tor, and all the auxiliaries are combined to form a unit.
1
2
3
4
5
6
7
8
9
10
11
Boiler
Turbine
Generator
Condenser
Condensate pump
Low pressure preheater
Feedwater storage tank
Feedwater pump
High pressure preheater
Main transformer
Transformer for station
consumption
Fig. 2
Basic design of a unit power plant.
14
15
2.2 Busbar Arrangement
2 Basic Design of a Power Plant
Since the auxiliaries in each block also have a fully independent consump¬
tion, it is possible to operate each unit independently of other units in the
station.
In large units of 300 or more MW, a unit may also consist of two boilers
feeding one turbine. This is sometimes called the 'blending unit arrange¬
ment' or the 'twin-boiler blending system'.
Simple units have several advantages, even though a trip of one part of the
plant may bring about total outage. For details and a full description of
these advantages, which lie beyond the scope of this book, one should
consult the pertinent technical literature (for instance, [11]). In this book
will be mentioned only the most important facts from the point of view
of automatic control. To begin with, there is the problem of steam re¬
heating. Since in the unit arrangement there is an unequivocal coupling
between the turbine and the reheater, and since the reheater is always ex¬
pected to admit the right amount of steam in proportion to the supplied
heat, the effect of disturbances is reduced making the reheat steam tempe¬
rature easier to control. Another point to consider is that the feedwater
control is also favourably influenced. Since feedwater pumps are always
associated with only one specific boiler, it is possible to control the speed
of the pumps, and to minimize throttling losses across feedwater valves;
in some cases the losses can be fully eliminated by omitting the control
valves altogether. The third advantage of the unit arrangement is that it is
particularly suitable for load control. As will be seen later, it is possible
to optimise load control by a specific co-ordination of the boiler and the
turbine. With such an arrangement it is also possible to apply variable
pressure control.
2.2 Busbar Arrangement
In the past, the prevalent layout was based on the'busbar arrangement
shown on Fig. 3. Among the main reasons quoted for this approach were
the low operational safety and the limited controllability of average steam
generators. The characteristic of the busbar arrangement which is also
known as the 'common live steam line arrangement', is that all boilers
feed, in parallel, a common live steam line, and are themselves supplied
from a common feedwater collecting line.
Among the various disadvantages of the arrangement described (such as
high specific unit costs, complicated heat distribution, increased danger of
1 Boiler
2 Turbine
3 Generator
4 Condenser
5 Condensate pump
6 Low pressure preheater
7 Feedwater storage tank
8 Feedwater pump
9 High pressure preheater
10 Main transformer
11 Transformer for station
consumption
Fig. 3
Basic structure of a power plant with a steam
and feedwater busbar.
-—
-
r
-
its Adverse effects
feedwater pollution, etc.) it is also necessary to mention
arrangement (see Section
on automatic control. In contrast to the unit
load control. It is a con¬
with
are
2.1), the main difficulties experienced
follow the overall load
they
that
so
siderable problem to bias the boilers
relative individual
their
changing
variations, without, at the same time,
is con¬
arrangement
busbar
the
disadvantages,
loading. In spite of all the
industrial
in
and
stations,
power
sistently applied in two areas: In isolated
steam.
power stations primarily designed to produce process
for ensuring the avail¬
It certainly appears logical to use the range system
isolated power stations
rare
relatively
the
in
ability of the necessary energy
to a large grid
connected
not
stations
i.e.
installed in small utility plants,
In this situa¬
consumer.
a
particular
to
only
system but supplying power
cause a si¬
necessarily
instance,
for
not,
tion, the loss of a boiler should
either
be
can
load
the
of
share
lost
multaneous loss of a turbine. The
can be
boiler
stand-by
a
or
picked up by the boilers still in operation,
brought in.
16
2 Basic Design of a Power Plant
In industrial power stations which are primarily designed
to provide proc¬
ess steam, the arrangement appears to represent a
logical development
of standard practice. With several small boilers
steaming in parallel, it is
only natural to use a common main line from
which the individual de¬
mands can be satisfied.
Boiler of the topping plant
Topping turboset (primary high-pressure
turbine exhausting into the mediumpressure plant)
Boilers of the medium-pressure plant
Condensing turboset (medium-pressure
plant)
3 Main Control Objectives
At all times, power plants must provide the load required by the consumer,
in other words, the main task of control is to match the energy generated
to the energy consumed. In this respect it is immaterial whether the
energy is produced in the form of pure electrical power (as in stations
providing load for large power supply grids), or in the form of combined
power and heat (as in industrial power stations or district heating plants).
Further, the produced energy must have the required quality, i.e. electrical
power must be provided with a given voltage and frequency, while thermal
energy must be supplied in the form of steam with a given temperature
and pressure. The twin control objectives are represented on the simplified
control flow diagrams shown on Fig. 5 and Fig. 6. However, it should be
pointed out already at this stage, that it would not be practicable to try
and implement these simple forms in practice, since the quality of control
that could be achieved would not be high.
r"
i
Fig. 4
b-©-
Basic structure of topping high pressure plant.
In this context the topping high-pressure
plants should also be mentioned.
The topping arrangement is used to improve
the economy of old mediumpressure plants which have been in operation
for some time. As shown on
Fig. 4, the required effect is achieved by
supplying high-pressure steam
into the old medium-pressure line,
using a back-pressure turbine.
Finally, it should be noted that the busbar system
can frequently be found
in district heating (power-and-heat)
plants.
References: [3] [11] [83] [92] [194] [243] [275]
.J
Fig. 5
Basic control objectives in a condensing power station
isolated from the power grid.
Fig. 5 illustrates, in a highly simplified form, the main control tasks in a
condensing power plant designed for the exclusive production of electri¬
city, and operating in isolation from the network. The symbols used in the
diagram mostly follow DIN 2481 (December, 1954). The terminal voltage
u ist kept constant by changes in the excitation currents in the field
winding of the synchronous generator. At the same time, the control of
the turbine speed n keeps the frequency of the produced electrical power
at the set point (i.e. maintains reference speed).
2 Klefenz A
_
3 Main Control Objectives
3 Main Control Objectives
In this case, the controlling element for the turbine speed control is the
energy supplied to the boiler in the form of fuel. A change in the con¬
sumption of electrical energy causes at first a change of voltage and of
speed, then the controllers intervene, and, finally, in the new steady state,
the equilibirum between consumption and production is established at an
appropriately changed fuel flow level.
As has been already pointed out, such simple configurations (as shown in
Figures 5 and 6) have severe limitations. These are caused by the following
two factors: Firstly, electrical energy cannot be stored in any substantial
quantity, and, as a result, must be produced when needed and not before.
This means that whenever it is necessary to prevent a drop of frequency to
unacceptable levels due to an energy deficit (caused, for instance, by an
extended energy expenditure), very fast control loops must be applied.
Unfortunately, the speed control loop as shown on Fig. 5 is by no means
fast. The reaction of the control circuit (which starts with the fuel-handling equipment and continues through the heat release in the furnace,
steam production, and the acceleration of the turboset to the output ter¬
minals of the transformer) is always rather sluggish. This is due to unavoid¬
able storage processes and to the resistance to change which varies with
each type of the boiler and type of fuel. The inherent inertia makes it
impossible to remedy a frequency drop resulting from an increased load
demand by an instantaneous change in the steam production. Fortunately,
the situation can be redressed by turning the already mentioned detrimen¬
tal storage effect into an advantage. However, to achieve this it is neces¬
sary to modify the control diagram: The new control loop in which the
delays in establishing the actual change in the steam production are reduced
by way of by-passing the accumulation capacities, is shown in principle on
Fig. 7.
18
Z
Fig. 6
Basic control objectives in a power station
designed for producing process steam.
Fig. 6 shows, once again in the form of a highly simplified diagram, the
basic control tasks in an industrial power plant which is primarily intended
for providing process steam. The state of the steam, i.e. its pressure and
temperature, is to be kept constant. The temperature d is controlled by
injecting a variable quantity of attemperation water into the steam down¬
stream of the back-pressure turbine. The deviations of the steam pressure
P from the set point are equalized by controlled changes in the fuel firing
rate. Should, for instance, too much steam be withdrawn by consumers,
pressure P would drop, and the controlling element would increase the
fuel flow into the steam generator. The control action would continue
until a new balance between consumption and production of steam is
established, and pressure has again reached its original value. In a control
loop of this kind it is, of course, not possible to provide special turbine
controls, since the system would become over-controlled. It is, therefore,
assumed that the generator is connected to the power grid. The effect of
such a measure will be discussed later.
It
i
Fig. 7
19
r*-i
j
®u
-Hf
L.
Simplified control scheme of a condensing power plant
isolated from the power grid.
In Fig. 7, the original slow speed control loop is split into two loops, a fast
speed control loop and a slow pressure control loop. The mode of action
is as follows: The speed, and with it the frequency, is now controlled by
changing the opening of the turbine throttle valve. The action is very fast,
well maintaining the frequency desired.
20
3 Main Control Objectives
3 Main Control Objectives
The rapid changes in the flow of steam to the turbine are made possible by
the fact that steam can be temporarily stored during load decreases, and
withdrawn from the boiler during load increases. Unfortunately, such use
of boiler storage causes steam pressure variations. As a countermeasure,
the steam pressure should be introduced as an extra control variable, its
variations controlling the fuel flow. This would cause the turbine to respond
quickly to all load consumption requirements, while the steam generator
would follow slowly, the steam pressure control being affected by the in¬
herent inertia of the boiler.
A further possibility to solve the problem of maintaining constant frequen¬
cy is that of establishing a link with the power grid, which is, at present,
but for a few exceptions the common approach. In such a system many
power stations and many consumer units are linked together to form a
large electrical network. The advantages are obvious: Should an individual
power plant fail, the taking-up of the lost load by the remaining units can
provide an uninterrupted continuation of supply to all consumers; the
changes of the load, even though it remains dependent on consumption,
become somewhat less pronounced. Frequency can be maintained con¬
stant with relative ease since the system contains quickly reacting units
(e.g. hydro-electric power plants) which respond to disturbances with mi¬
nimum delay, while the remaining more sluggish units can adjust their
contribution gradually.
The variations in controllability of power plants resulted in the formation
of various proposals as to the control of the power supply system: The
following text illustrates this point. Two unit blocks linked to a common
consumer system will be used as an example. In the discussion, the voltage
control does not have to be dealt with since it is not affected by the
considered modes of operation.
a) Both Units Take Part in Frequency Control
(Variable Load Operation)
For this mode of operation both block power plants are equipped with
control instrumentation corresponding to Fig. 7. However, two typical
cases are to be distinguished:
In the first case, the speed controllers are structured as purely proportional
controllers. This is in agreement with one of the basic rules of control
engineering, according to which (for reasons of stability) it is not allowed
to use two or more controllers with proportional plus integral action for
controlling the same controlled variable.
21
50 Hz
Fig. 8
Control characteristic of a turboset with a P-controlIer.
Nl = load of unit No. 1
IV2 = load of unit No. 2
/= frequency
In each block, the use of P controllers results in a control characteristic
similar to the one given in Fig. 8.
The control characteristic reproduces the relationship between frequency
and the unit electrical output. For the case of a proportionally acting
speed controller, the characteristic considered here is a down-sloping
straight line. The gradient is determined by the proportional band xp ad¬
justed on the controller. Due to the particularly favourable time behaviour
of the con trolled system, a very small xp can be chosen (for instance,
"
2.5„Jflz. Since xp is mostly stated as a percentage value, with the nominal
frequency of 50 Hz as reference value, xp = 5%). As can be seen from Fig.
8, each load change is coupled with a frequency change. For example, for
the same adjustments that were used for obtaining the characteristic in
Fig. 8, a change in the consumer load of AN 20% would give a lowering
of frequency of
f
y- K>
(1)
Af=~
xp
AN
50Hz
100%
100%
m
= -0,25 Hz
In the equation, m = 2 is the number of blocks taking part in the exercise.
Naturally, the frequency can be again increased to 50 Hz by re-adjusting
the set point setter. This would produce a parallel shift of the control
characteristic, as is demonstrated in Fig. 9. It is evident that any frequency
can be associated with any particular load by a simple shift of the set
point.
0<j1
r
3 Main Control Objectives
3 Main Control Objectives
22
t
50 Hz
Shift of the control characteristic of a turboset,
caused by a change in the set point.
Fig. 9
/
Ahxunequal adjustment of the two set points would result in an unequal
loading of the two power stations (see Fig. 10). However, grid load changes
would be covered proportionally, i.e. each unit would contribute its pro¬
portional share.
Should the two blocks be required to coastrrbtrte to the total load each at
a different rate, different xp settings would be needed. Fig. 11 shows, for
example, that due to a smaller xp, the speed controller for block No. 1
would tend to make block No. 1 contribute more than block No. 2.
23
In the second case, one of the blocks has a proportional plus integral speed
controller, while the other is still fitted with a proportional controller. In
steady state, this arrangement is adequate for keeping the frequency al¬
ways exactly at the same set value. The block with the P-controller does
not participate permanently in load changes, since automatic control
always returns its electrical' output to the originally set value. It does,
however, temporarily participate in maintaining frequency. This is a typi¬
cal example of a frequency supporting operation which is extremely
important, and should be applied in power systems as a matter of policy.
An increased number of power plants contributing to frequency control
will improve the quality of the performance as well as make the system
more stable. In the above situation, the frequency controlling power sta¬
tion can be considered analogous to the fast reacting hydro-electric plants,
particularly the pumped-storage plants, while the plant fitted with a pro¬
portional speed controller corresponds to the thermal power stations. The
load set points of these thermal power stations are adjusted according to
a time-table obtained from the daily load variation curves. This is done so
as to enable the frequency controlling stations to keep the frequency at
the set point.
\
b) A Power Plant Unit Does Not Participate in Frequency Control
(Constant Load Operation)
50 Hz
0
Fig. 10
N,
N;
100V.
N
Differently set control characteristics of two turbosets.
1
Xp,
Xp;
UaNz-*
Fig. 11
Control characteristics with different xp settings.
Both block power plants discussed in paragraph a) were of the so-called
active type, i.e. they were taking part in maintaining constant frequency.
On the other hand, a passive (or inactive) block does not take part in such
activity. As shown on Fig. 12 and Fig. 13, passive blocks can be applied
according to two basic diagrams. In these or such diagrams block No. 1 is
always active, block No. 2 passive.
In the alternative presented on Fig. 12, the steam pressure upstream of the
turbine of the block No. 2 is kept constant by the turbine throttle valves.
This prevents any utilisation of boiler storage: The turbine feeds into the
system only so much power as is produced by the boiler. Since fuel flow
to the boiler is normally adjusted at a constant value, the boiler evaporation
rate, and subsequently also the generator output, remain constant. The
changes in frequency cause no changes in power production.
The total load change required by the consumer side must be raised by the
active blocks. The calculation of the resulting change in frequency A f,
caused by a load change of AN = 20%, gives for the same proportional
r
_
5 Main Control Objectives
24
I
3 Main Control Objectives
25
mode of operation should be full load (which is, of course, constant; i.e.
the units are passive).
f-® HZ]-
1
-00-
OD-
Fig. 12
Basic control scheme: One unit active,
one unit passive
band for speed control as was used before (5%) a frequency decrease of
0.5 Hz. A comparison with the previously calculated value for the case
when both power plant blocks participated in maintaining constant fre¬
quency, shows that the original decrease of — 0.25 Hz has been doubled.
This confirms the extremely important conclusion that in any electrical
system as many power plants as possible should participate in frequency
control. Only in this manner can the frequency be kept within narrow
limits. Further, only in this manner is it also possible to guarantee the sta¬
bility of large electrical systems, as well as to guard against the situation
where the failure of a specific part of a power system releases a chain re¬
action which then overloads the tie-line to the neighbouring system. Such
an overloading may result in a spontaneous separation of the two systems,
which further increases the probability of a total collapse of the first
system.
Participation in frequency control should be extended even to the relative¬
ly inert brown coal fired power plants, since as the installed capacity in¬
creases, the share of the storage power stations pÿcgdes more and more into
the background. The increasing contribution by nuclear power plants
brings no relief, since, due to initial high capital expenditure, their (revalent
Fig. 13
Basic control scheme: One unit active,
one unit passive.
Fig. 13 depicts another variant of a passive unit application. This time, the
turboset of block No. 2 is equipped with load control, i.e. the delivered
electrical energy is controlled by turbine inlet valves, and the load is deter¬
mined by the set point setter. In this case, an increased or a decreased
delivery of power can be achived only by adjusting the set point setter.
In contrast to the alternative shown on Fig. 12, the boiler is controlled in
the same manner as if it were in an active unit. In operation, the fuel flow
is automatically adjusted so that the steam pressure at the boiler outlet is
kept constant. This steam pressure serves as a measure of the imbalance
between the boiler steam output and the steam taken up by the turbine.
V
T". t
\W- J
The main difference between the passive units presented in Figures 12 and
13, consists in the unit shown on Fig. 13 being faster in following an im¬
posed load change than the unit on Fig. 12.
The reason for this being that the passive unit on Fig. 13 uses the boiler
storage capacity.ÿThis comes aboutjwhen upon increasing the load set
point, the turbine inlet valves open so wide that the new load is reached
r
26
v
3 Main Control Objectives
i-cÿ'
A
behaviour of the controlled sy¬
quickly. Due the favourable
time
to
very
stem, this process is very fast. The required increase of steam flow is
brought about at the expense of boiler storage. This in turn causes the
steam pressure to drop accordingly, while the pressure controller ensures
that the storage is again refilled, and that more steam per time unit is pro¬
duced as power increases. In contrast to this, in the scheme on Fig. 12,
the load increase must be initiated by an increase of energy in the fuel
supplied. The steam pressure rises in dependence on the inertia of the
firing and steam producing processes, and the pressure controller tends to
open the turbine inlet valves accordingly. All this means that an actually
increased steam production is a precondition to a load increase. Due to its
sluggish behaviour, such circuit is at present only very rarely applied. Instead, preference is given to fast reacting arrangements for load control.
As already explained in the preceeding chapter, one of the main control
tasks is to maintain a constant,synchronous gerjemor terminal voltage both
latter approach has the additional advantage of being easily extended
- The
shouldjhe needTtnsg* In order make the unit participate in frequency
to
3 ÿcontrol, it is sufficient to introduce an additional frequency measurement,
tÿderive)from it a suitable signal, and to let this signal affect the set point
/for load control. The result is one of the most frequent control techniques
,( which will be discussed in some detail later.
ÿ3
Finally, to complete this sub-section, it should be mentioned that naturally
all turbines are equipped with speed control, even if it,is not shown in the
diagrams. In all these cases the speed controller acts as a safety device
against excessive speed. This can be achieved, for instance, by adjusting the
set point in such manner that the controller can start acting only when the
speed limit is exceeded.
References: [3] [11] [66] [76] [83] [93] [117]
dgrAc, - c
J[iV£
ÿ•-1
4 Generator Control
J
under normal operating conditions and under fiauIt}/o ndit ions. This re¬
quires control of the excitation, and the respective control loop is presented
in simplified form on Fig. 14. The control variable is the output voltage Ug
of the excitation system the impedance (seen 'looking into' the network
at the machine terminal) and/ or the generator reactive output act as distur¬
bances. The DC voltage which is applied to the generator field winding
(i.e. the exciter output), can be produced by various methods. There are
many options: The exciter voltage regulators can be electromechanical,
solid-state, based on a rotating amplifier or a magnetic amplifier, etc.,
while the excitation control systems are manufactured with DC generator/
commutator exciters, alternator/rectifier exciters, compound/rectifier
exciters, potential-source/rectifier exciters, etc. The most frequently em¬
ployed are exciters driven directly by the shaft of the main synchronous
generator (i.e. of the DC generator/commutator type). Further, it is neces¬
sary to differentiate between the various interconnections of the field and
the armature: There are, for instance, self-excited and separately excited
machines, etc. Unfortunately, the various aspects of generator are too many
and too diverse to be satisfactorily dealt with in this publication, and the
readeris referred to special technical literature. Here the principles of ge¬
nerator control will be explained with the aid of Fig. 14; the scheme re¬
presents an exciter mounted on the main generator shaft, the exciter being
separately excited and having its output fed into the rotor of the synchroi
r
,i.i
-0—
"=•9-—©
[™]
-<i>
Fig. 14
Control scheme of voltage control
of a synchronous generator.
ue
-©
ie
—
r
4 Generator Control
4 Generator Control
28
29
nous machine through slip rings. The generator terminal voltage u is
compared with a reference voltage, and the resulting error voltage is fed
into the amplifier of a P or PI acting controller. In accordance with the
control deviation the controller adjusts the excitation of the exciter E
which in turn provides the excitation voltage ue.
The static relationship between the excitation current ie and the generator
voltage u is shown in the form of a diagram on Fig. 15. The thick line re¬
presents the idling (no-load) characteristic, to the left and to the right of
which are short sections of other characteristics corresponding to different
loads. (Note that lagging, i.e. inductive loads, require overexcitation,
whereas leading, i.e. capacitive loads, call for underexcitation.) Each cos ÿ
is associated with a different characteristic. The diagram also illustrates
the well known fact that a change in excitation may not only influence
the voltage, but also the reactive power: In fact, if a generator is connected
to a large and, from the point of voltage, stiff system, then a change in
excitation will affect only the generator reactive output.
idling characteristic
capacitive
cos/=0
0 inductive
load characteristics
u
us
i
L
Fig. 15
voltage
voltage set point
generator current
exciter current
Idling and load characteristics of a synchronous generator.
An insight into the dynamic behaviour of the synchronous generator can
be obtained from the transfer functions in Fig. 16. What Fig. 16 primarily
shows is the time behaviour of the voltage u following a sudden load change.
This load change is the result of a change in the network impedance 3,
providing the excitation voltage Ug remains constant. A raise in load (or a
decrease in impedance) is, in the first instance, followed by a sudden drop
of the terminal voltage u, accompanied, since there is no initial change in
the flux, by an equally sudden increase in the excitation current ie. Sub¬
sequently, the strength of the field slowly falls along a curve determined
by a time constant. Meanwhile voltage behaves in a like manner, and,
similarly, the excitation current gradually reverts to its original value.
Fig. 16
Transfer functions of a synchronous generator.
Following a load decrease, all these processes would develop in the opposite
direction. The mentioned time constant lies approximately between one
and twenty seconds, depending on the output of the machine, on its design,
on its speed of rotation, and on its current load.
In large turbogenerators with several hundred MVA it is necessary to assume
a time constant of 20 seconds. The difficulty with control of these sets is
that, following a load change, the output voltage of the excitation system
must be very quickly adjusted. This is so because only a rapid application
of a high excitation voltage can arrest the decay of the induced field cur¬
rent, and then build it up again in the shortest possible time. It follows that
the quality of control predominantly depends on the dynamics of the cho¬
sen exciter arrangement. Separately-excited machines have shorter time
constants than self-excited ones, and this makes them preferable from the
control point of view. Fig. 17 shows a block diagram corresponding to the
control scheme of Fig. 14. Blocks 1 and 2 represent the generator, 3 and 4
V
4 Generator Control
4 Generator Control
the exciter. The letter 3 stands for load impedance which, in this case, is
the main disturbance.
The dotted line in the diagram indicates the path of the generator current
signal iwhich appears to move the set point by combining with it in the
manner of an auxiliary signal. This measure is needed when several gene¬
rators work together to supply the entire load of a power system, or in the
case of several interconnected power systems. Such multi-area operation
causes problem which are in principle quite similar to those that have been
already encountered in the loading of parallel power stations, and were
discussed in chapter 3.
In practice, any parallel operation of the kind described above can be
achieved by means of a suitable type of cross-current compensation. Such
a method employs a resistor or an impedance in the voltage measuring
circuit. A current proportional to the reactive current delivered by the
generator is fed through the device, to produce a small load dependent
voltage which is added to the terminal voltage. This gives a slight droop
to the voltage held by the regulator on reactive loads, and causes the de¬
sired change in the characteristic (reactive currents are divided in proportion
to load currents). Another method is not to use a PI controller but a P
controller with the proportional band chosen so that it corresponds to the
desired characteristic. In the latter case the generator current signal i
would be superfluous.
30
In order to achieve stability of generators operating in parallel it is neces¬
sary to use a type of open loop control which will correct the characteristics
of the individual generators. Such control will adjust all the prescribed re¬
lationships between the various generator variables, i.e. between the reactive
and active current, between the reactive current and voltage, etc. Again,
the ultimate aim is to have possibly all generators provided with excitation/
voltage regulating systems which will enable them to share the kVAr of the
group load on a proportionate basis. Note that to enable the AC generators,
operating in parallel, to share the kW of a group load on a proportionate
basis, the turbines must be provided with suitable governors, as load
sharing is not a function of the generator excitation/voltage regulating
system. (Any adjustment of field excitation changes the kilovars, whereas
prime mover characteristics must be adjusted to change the kilowatts).
31
In conclusion, a few words will be said about the actual instrumentation
used in practice. Originally, electromechanical regulators were used, and
some are still in service; they are generally not suitable for machines of
about 75 MW and above owing to the high field current required for the
main exciter. The voltage reference in these regulators was provided either
by the spring tension against which the solenoid was to act, or by the use
of relays as voltage sensitive elements. Voltage sensitive quick-response
contacts were used to insert exciter field resistance elements in various
combinations (series, bridges, etc.). This is, for instance, the basis for the
design of the well known Tirrill controller, which is a vibrating-contact
regulator. Purely electrically operated controllers have been introduced
relatively recently. They use directly operated magnetic or electronic ro¬
tating amplifiers which, in turn, supply the control voltage for the exciters.
References: [3] [4] [92] [182] [190] [202] [222] [225] [226] [238] [239]
[240] [296] [303] [305] [309] [318]
-ÿo-
»s
controller
1, 2 generator
3, 4 exciter
u generator voltage
ue exciter voltage
uy controller output voltage
i
us
(control variable)
generator voltage set point
generator current
3
load impedance
<+;
Fig. 17
Signal flow diagram of a voltage control loop of a synchronous generator.
ÿ\
r
dc
5 Turbine Control
should the control stage be already fully commited, directly to either the
first stage chamber or to a stage situated even further back. This is indi¬
cated on the diagram by dotted lines.
5 Turbine Control
The basic principles of turbine control have been already commented upon
in Chapter 3. The most important controlled variable is speed or rather
frequency, followed by electrical power or load (the megawatt-frequency
control channel); next in order of importance is steam pressure. The
following text will be devoted to a more detailed discussion of turbine
control. However, particulars will be mentioned only when such informa¬
tion should prove important for the description of the basic behaviour of
the plant. Unfortunately, there is not enough scope to look into safety
arrangements such as tripping mechanisms and other limit-value controls.
t fixed guide
ÿ wheel
nozzles
I First
1 stage
I
" chamber'
Curtis
wheel
In what follows let us first consider the point of application of turbine
control. To this effect, the electrical power Nwill be expressed as follows:
(2)
33
2nd runner
wheel
N= mD Ah
ÿ
where
mD =
Ah =
steam flow
steam enthalpy drop
Equation (2) shows that there are two possibilities to change the turbine
electrical power. This can be done either by adjusting the steam flow
(= the so-called nozzle group control governing) or by varying the enthalpy
drop (= the so-called throttle governing). In practice, of course, it would
be very difficult to find the two methods in pure form. Steam flow and
enthalpy changes always occur together. In theory, the difference between
the two methods can be explained with the aid of Fig. 18. In the upper
part of the figure is a schematic presentation of nozzle group control
governing which is, at present, the prevalent method for practical applica¬
tion. The nozzles are divided into groups under the control of separate
valves which operate in sequence. Pure steam flow control without thrott¬
ling losses occurs only when the steam flows through fully open valves.
In other ranges, i.e. when the control valves for one or more of the nozzle
groups are only partially open, the particular steam flows are always more
or less throttled.
Generally, additional valves (the overload valves) are installed to make it
possible to reach full load even under conditions of somewhat reduced
steam pressure. These valves admit steam either to extra nozzles, or,
Fig. 18
Nozzle group control governing and throttle governing
of steam turbines.
With throttle governing, the total steam consumption is controlled by
throttling at only one point. This is shown in the lower part of Fig. 18.
However, instead of a single common valve, large steam throughputs may
require the application of two or more valves in parallel and these would
open in sequence.
The next sub-sections will deal with the most essential turbine control
schemes. To begin with, it will be assumed that only constant pressure
units are involved, i.e. that the boilers are controlled so that their outlet
steam pressure is kept constant.
References: (187] [226] [236] [237] [245] [258] [267] [268] [269] [272]
[276] [302] [305] [306]
3 Klefenz
r
r
5 Turbine Control
34
5. 1Nonreheat Turbine Supplying IsolatedLoad
5.1 Nonreheat Turbine Supplying Isolated Load
deviation from the equilibirum state causes a commensurate adjustment
of-the turbine control valves. Depending on the relative strength with
which the frequency and load signals are brought in, a specific inclined
characteristic is obtained. This characteristic is similar to the one that can
be obtained in alternative 1 by taking advantage of the setting of the pro¬
portional band of the P controller. As in alternative 1, the characteristic
can be shifted by adjusting the set point setter. It is evident that in alter¬
native 2 it is always possible to reach the nominal 50 Hz frequency regard¬
less of the current load.
The main features of turbine speed control have already been indicated in
Fig. 7 in Chapter 3. Fig. 19 now shows two alternatives in more detail.
Alternative 1 is the classical speed control. The difference between the set
point and the speed signals forms the input of a proportional controller
which in turn actuates the turbine inlet valves. The proportional band of
the controller can be kept rather narrow (approximately 2 to 4 Hz) due
to the favourable time behaviour of the controlled system. This has the
effect that speed, or rather the frequency, does not fluctuate too strongly
in dependence on load. Moreover, by adjusting the set point setter it is
possible to associate with each load any nominal speed, as is shown in Fig.
9. With the speed controller in operation, integral action is avoided for
reasons of stability. This is so because in some caces the controlled systems
have no self-regulation.
The dynamic performance will now be explained with the aid of the signal
flow diagram on Fig. 20. (The diagram has certain peculiarities of presen¬
tation which are dealt with in the opening statement of sub-section 8.3.)
The adjustment of the turbine inlet valves, y, causes the turbine drive
power Na to adapt with some delay: The transient response curve is that
of a 1st order system with a time constant 7) . The difference between
the turbine drive power (= power requirement) NA , and the power N
which is being delivered by the generator to the consumer, is used to accele
rate both the turboset and the connected motors. This occurs in the
transition time TA . The power Ntaken up by the consumer is composed
of the power requirementJVvo and a frequency dependent feedback Ny.
The amplification factor Vv (which is the consumer gain) lies between 0
and 4, its actual numerical value depending on the type of consumer units.
For instance, Vy = 0 indicates a speed governed drive (i.e. a genuine ohm's
consumer), Vv = 3 .. 4 is typical for pump and fan drives, etc.
While alternative 1 was prevalently applied during the period when
mechanical/hydraulic governors were used, alternative 2 presents a method
that became feasible only through the introduction of electrical governors.
In alternative 2, the load signal, the frequency signal, and the set point
signal are combined at the input of a proportional-integral controller. A
j
ÿ
---
The frequency dependent consumption of power by specific consumer-ÿ"
groups has, to a certain degree, a self-regulating effect. A deficiencyln the
power produced lowers the frequency, and also results in lowering the
power taken up by consumers. However, this self-regulating effect should
not be overestimated. Even if it used to be quite efficacious in the past,
it has been recently strongly reduced by the constantly growing parti¬
cipation of speed controlled drives. In a middle sized power supply grid,
a gain of Vy = 1 is currently all that can be assumed.
-<&*-
Alternative 1
-
ED
n(ÿ) (ÿ>i
For large turbosets of 100 MW to 300 MW, the order of magnitude of the
delay time constant T) is 0. 15 seconds. As to the transition time TA, it is
generally accepted that for its calculation it is sufficient to consider only
the turboset. This simplification has the advantage that it deals with the
most unfavourable case which arises when the set is working without a
consumer; this occurs, for instance, either during the bringing up of the
load of the set, or during thesheddingÿof the load\
Alternative 2
Fig. 19
35
Alternatives of speed control in a turbine
supplying isolated load.
j.
I
r
5. 1Nonreheat Turbine Supplying Isolated Load
5 Turbine Control
34
5.1 Nonreheat Turbine Supplying Isolated Load
35
deviation from the equilibirum state causes a commensurate adjustment
of-the turbine control valves. Depending on the relative strength with
which the frequency and load signals are brought in, a specific inclined
characteristic is obtained. This characteristic is similar to the one that can
be obtained in alternative 1 by taking advantage of the setting of the pro¬
portional band of the P controller. As in alternative 1, the characteristic
can be shifted by adjusting the set point setter. It is evident that in alter¬
native 2 it is always possible to reach the nominal 50 Hz frequency regard¬
less of the current load.
The main features of turbine speed control have already been indicated in
Fig. 7 in Chapter 3. Fig. 19 now shows two alternatives in more detail.
Alternative 1 is the classical speed control. The difference between the set
point and the speed signals forms the input of a proportional controller
which in turn actuates the turbine inlet valves. The proportional band of
the controller can be kept rather narrow (approximately 2 to 4 Hz) due
to the favourable time behaviour of the controlled system. This has the
effect that speed, or rather the frequency, does not fluctuate too strongly
in dependence on load. Moreover, by adjusting the set point setter it is
possible to associate with each load any nominal speed, as is shown in Fig.
9. With the speed controller in operation, integral action is avoided for
reasons of stability. This is so because in some caces the controlled systems
have no self-regulation.
The dynamic performance will now be explained with the aid of the signal
flow diagram on Fig. 20. (The diagram has certain peculiarities of presen¬
tation which are dealt with in the opening statement of sub-section 8.3.)
The adjustment of the turbine inlet valves, y, causes the turbine drive
power Na to adapt with some delay: The transient response curve is that
of a 1st order system with a time constant T\ . The difference between
the turbine drive power (= power requirement) NA , and the power N
which is being delivered by the generator to the consumer, is used to accele¬
rate both the turboset and the connected motors. This occurs in the
transition time TA. The power Ntaken up by the consumer is composed
of the power requirement Ny0 and a frequency dependent feedback Ny.
The amplification factor Vv (which is the consumer gain) lies between 0
and 4, its actual numerical value depending on the type of consumer units.
For instance, Vy =0 indicates a speed governed drive (i.e. a genuine ohm's
consumer), Vv = 3 • 4 is typical for pump and fan drives, etc.
While alternative 1 was prevalently applied during the period when
mechanical/hydraulic governors were used, alternative 2 presents a method
that became feasible only through the introduction of electrical governors.
In alternative 2, the load signal, the frequency signal, and the set point
signal are combined at the input of a proportional-integral controller. A
•
----
The frequency dependent consumption of power by specific consumerÿ
groups has, to a certain degree, a self-regulating effect. A deficiency in the
power produced lowers the frequency, and also results in lowering the
power taken up by consumers. However, this self-regulating effect should
not be overestimated. Even if it used to be quite efficacious in the past,
it has been recently strongly reduced by the constantly growing parti¬
cipation of speed controlled drives. In a middle sized power supply grid,
a gain of Vv = 1 >s currently all that can be assumed.
-©•*-
Alternative 1
<?
0-
;:
-0-
,
ÿ
4 kl
For large turbosets of 100 MW to 300 MW, the order of magnitude of the
delay time constant 7\ is 0.15 seconds. As to the transition time TA, it is
generally accepted that for its calculation it is sufficient to consider only
the turboset. This simplification has the advantage that it deals with the
most unfavourable case which arises when the set is working without a
consumer; this occurs, for instance, either during the bringing up of the
load of the set, or during theÿheddirqfof the load\
Alternative 2
Fig. 19
Alternatives of speed control in a turbine
supplying isolated load.
3*
1
>Jr
5 Turbine Control
36
nlf)
5.2 Nonreheat Turbine Connected to a Power Grid
Fig. 20
Signal flow diagram of a turboset without a reheater,
supplying an isolated load.
The simplified scheme provides some kind of an answer to the rather diffi¬
cult question of how should be constantly changing number of consumer
units be incorporated into the calculations. As in other respects, the theo¬
retical design of the controllers has to be based on the least favourable
case, which happens to be represented by the lowest TA. This transition
time TA can be obtained from:
Since the speed of a turboset connected to a large power supply grid is
fixed by the frequency of the system, little emphasis is given to speed
control. Instead, its place is taken up by load control. As has been already
explained in paragraph 3, in this type of control it is necessary to distin¬
guish between two modes of operation, passive and active. In passive
operation (see case 1, Fig. 21) the set supplies a constant load, as adjusted
on the set point setter, independently of the frequency of the system.
In active operation (see case 2, Fig. 21) the set participates in maintaining
the frequency at its nominal value; the load set point is shifted by the
frequency according to the appropriate characteristic. In modem plants
the response sensitivity of the frequency measuring device is approxi¬
mately 5 mHz, which means that the basic requirement for frequency
support is fully met.
limit values (entry)
Ta = 4tt
(3)
where
I
N0
2
1' "0
N0
ÿ
r
—Eh~
. . mass moment of inertia
. . nominal speed
. . nominal load
H r— ©
selector ~
device
|
limiting of speed
of change
N('
case 1
The order of magnitude of TA is 10 seconds, and the value is only margin¬
ally dependent on the size of the machine. The transfer function of the
speed control system then reads:
(4)
An(s)
Ay(s)
where
set point
_ _ i£_
(i +
7VS)-(i+pÿ-s) '
s . . the Laplace operator.
limit values I [limiting of speed
(entry)
ÿi—
-ED* —D~
selector
device
Should the turbine control be investigated together with boiler control,
the effect of the various refinements in the above calculation would be
minima. This means that in comparison to TA/Vy, Tx could be neglected.
What would remain is a 1st order delay system with a time constant
[of change
.
case 2
TJVy.
Fig. 21
The alternatives of load control for a turboset
connected to a power system.
/J
m
38
5 Turbine Control
5. 2 Nonreheat Turbine Connected to a Power Grid
39
The control scheme on Fig. 21 contains the following modules:
— A speed limiter for the change of load. The load set point itself may be
adjusted as quickly as convenient. However, the set point signal must
be prevented from changing more rapidly than the plant could cope
with. This is why the signal is routed through the limiting module lo¬
cated downstream of the set point setter. In addition, the limiter can
receive signals which would block any set point change should at least
one of the boundary values be attained. These signals are issued by some
superimposed device such as a stress monitor or a unit control station.
Tn
— Instead of using signals from a set point setter located in the thermal
control room, remote set point guidance signals can be used. Such sig¬
nals can originate, for instance, in the central load dispatching centre.
— A selector device which is located upstream of the controller can acco¬
modate further limiting signals. Via such a module, limiting signals from
steam pressure (before the turbine) or from turbine speed can be brought
into the control loop.
It is not possible to present the dynamic behaviour of the above control
system in a form which would be as simple as that for the isolated load
case. The reason for this is that nowadays it is necessary to take into con¬
sideration the slip, system self-regulation, and other factors. The complete
signal flow diagram for a set connected to the system is shown on Fig. 22.
It differs from the diagram shown on Fig. 20 in that it contains additional
restoring torques due to the slip s which is the difference between turbine
speed and system frequency. The slip signal acts, in the direction shown,
both via the proportional block KD and via the resetting time block TR.
In this manner it provides a direct damping moment (via KD ), as well as a
which is being fed into the system (via
signal equal to the surplus load
Tr). The sum of the surplus load Nn and the user load ATV0 + Ny equals
the load iVproduced by the generator. In its turn, the surplus load ATN
acts via the system gain block KN on system frequency. Strictly speaking,
the time lag involved in this action (TN) depends on the kind of consumer
devices connected to the system, as well as on the loading of the network.
However, since such factors are difficult to evaluate, it is expedient to
assume a proportional relationship with no delays.
In large generators, the order of magnitude of the damping constant KD
is 25. The resetting time TR varies between approximately 1.7 ms at noload operation, and 2 ms at nominal load. The dimensional gain element
jKn relating the load A7Vn to the frequency correction Af, depends on
Fig. 22
Signal flow diagram of a turboset without a reheater,
connected to the power grid.
the ratio of the machine load to the frequency of the system load. For a
very large power supply grid which is practically stiff, the value Kn = 0
should be used (i.e. load changes cause no frequency changes). In the
other extreme case of an isolated load, K equals infinity. After appro¬
priate modifications this leads to the signal flow diagram shown on
Fig. 20.
In the case of a stiff system the signal flow diagram can be reduced — see
the reduced diagram in Fig. 23. A further simplification is possible leading
to the simplified diagram in Fig. 23. It is based on the knowledge of the
transfer function describing the behaviour of the load Nn following a
change of the turbine power requirement NA , which reads:
(5)
AAfN(.r)
aata(s)
*
y= i+ÿdÿRSÿRÿA1
The insertion of numerical values leads to:
(6)
1
-
AATA(S)
2 '
1 + 0,05 s + 0,02 s1
I
5.3 Single-Reheat Turbine
5 Turbine Control
40
T,
41
ÿA
IP/LF
Fig. 24
reduced diagram
simplified diagram
Fig. 23
Signal flow diagram of a turboset without a reheater,
connected to a stiff power supply grid.
If the turbine control is examined together with the essentially more inert
boiler control, the above fine points are of minor importance, and it is
adequate to represent the controlled system as a simple P element without
delay.
Principle design of a turbine with reheater.
The adjustment of the position y of the nozzle control valve produces
almost instantaneously a certain part a of the total operating power A/a
in the HP stage of the turbine. The value a is calculated as follows:
(7)
a=
Ah l
A/ij
A /i2
where A hi is the enthalpy drop in the FIP stage, and A h2 the drop in in
the IP/LP stages. In practice, a lies between 7 and j.
B
5.3 Single-Reheat Turbine
In turbines with reheat the steam leaving the high-pressure stage is once
more heated in the so-called reheater (generally to the same temperature
as the live steam leaving the boiler) tfaFterwards, it is led to the turbine
intermediate-pressure and low-pressure steam valves (seej<ig. 24). The
control is performed in the same manner as control for machines without
reheating, displayed on Fig. 19 and Fig. 21. Certain peculiarities, such as
behaviour at minimum load, will be discussed in the next section.
The reheater influences the dynamics of control to a considerable degree.
This is because the volume of the reheater acts as a substantial storage,
the consequence of which being that the intermediate-pressure and lowpressure stages of the turbine participate in load changes only with a
delay. This can be seen from the signal flow diagram on Fig. 25.
Fig. 25
Signal flow diagram of a turbine with a reheater,
connected to a system.
5.3 Single-Reheat Turbine
5 Turbine Control
42
This means that the motive power produced in the IP/LP stages amounts
to (1 — a) of the total production. It is produced with a certain delay given
by the fact that before the steam enters the IP/LP stages it must flow
through the reheater, i.e. the delay equals the required charging time of
the reheater volume. The relevant time constant Tzo is calculated using
the relationship:
TlZU
(8)
_- 1+
X
I K
2*
Fig. 27
43
Simplified signal flow diagram of a turbine with a reheater, connected to
a ÿtlThpower supply grid.
'"ZU
'"ZU
As has already been explained, if we wish to re-examine the turbine control
where
adiabatic coefficient
systemiolely in relation to the whole steam generating plant, we can
mZ(j reheater steam flow
disregard the small time constants, and arrive at simplified signal flow
diagrams such as are shown on Figures 26 and 27. The corresponding
transfer functions are:
mZ\j steam mass stored in reheater
For isolated load:
For superheated steam k ÿ 1.3, i.e.
(10)
Tzu 555 0>9 • wzu
"!ZU
(9)
For operation as part of a power grid system:
,yÿr'
Tz o
equals approximately 15 seconds, which means that it is the dominant
Cj j \
time constant.
nlfl
-B
—
f vB
Simplified signal flow diagram of a turboset with a reheater, supplying an
isolated load.
ann(i)
Ay(s)
Finally, the conversion of the (1 - a) share into motive power is effected
in the IP/LP stages of the turbine with the time constant T2. The time
constant T2 is very small, similarly to the time constant T\ (« 0. 15 s.),
and afhounts)to approx. 0.25 seconds. The remaining blocks of the signal
flow diagram have already been discussed in sub-section 5.2.
Fig. 26
_
mt&.K- _ '"Tz""
l + a • 7z<j
l + Tz\] S
ÿ
*
We should remember that already in operation are double-reheat turbines,
where the steam is being returned to the boiler from downstream of the
intermediate-pressure stage (and not only from downstream of the highpressure stage). After being reheated for the second time, the steam is
finally completely expanded in the low pressure stage. The introduction
of a second delay disimproves the control conditions even further, and
the signal flow diagrams are to be extended'accordingly.,
It should be pointed out that, in turbines with reheat, control valves are
installed also upstream of the intermediate-pressure stage of the turbine.
These valves are open when the unit operates with boiler load above
minimum. If the-unit load drops below minimum boiler load, the excess
steam must be diverted/via high-pressure and low-pressure reducing
stations. Under suchconditions, in order to achieve the lowering of power
of the IP and LP stages, it is necessary to throttle the steam flow upstream
x of the intermediate-pressure stage, while the reheat steam pressure is kept
constant by the low-pressure reducing stations.
/
/
_g
5 Turbine Control
44
•
5.4 Accessory Turbine Controls
5.4 Accessory Turbine Controls
. I
Jl—
This section will briefly cpVer some of the turbine controls that are gener¬
ally applied to complementÿthe main control loops.
As the first in this group it is the inlet steam pressure governing system that
should be mentioned. However, as this particular scheme has already been
shown in Fig. 12 as alternative 2, and discussed in the accompanying text,
no further details will be given. Its countefparl, the back-pressure control
(see Fig. 28) is quite similar but for the controlled variable which in this
case is the exhaust steam pressure of the turbine, i.e. the pressure in the
plant steam network. The steam consumption in the back-pressure system
determines both the turbine steam throughput, and the produced electrical
power.
Fig. 29
4
(D-
When using the bled steam pressure control, both speed control and load
control affect the nozzle valves in the opposite direction to the
pass-out
valves, whereas in the case of 'steam-grid' pressure control both control
points are influenced in the same direction. This makes it possible,
in the
I
I
I
-©
A
Fig. 28
Basic scheme for bled steam pressure control.
!-ÿ
Basic scheme of back-pressure control.
?
rrrEbf-'-i
'I
N(ÿ) fÿ>
11
Among further possibilities is the bled,steam pressure control, and the
.? combined steam/power grid control. Figures 29 and 30 show the respecY yctive control diagrams. One of those control loops is required if steam for
d c use in the plant is being_withdrawn from discharge (or bleeding)-po«rtsprovided in the turbine casing'. Their application is aimed at preventing
the mass flow of the processsteam to pass out through the openings at
uncontrolled and variable pressure (which itself is a function of steam
flow). In the simpler bled steam pressure control, according to Fig. 29,
there are, on the process side, interactions with controls acting on the
nozzle valves, such as speed control or load control. These often have an
unfavourable effect requiring an undesirably strong damping of one of
the control loops.
This is the reason for giving preference to the steam-grid type control loop
(Fig. 30) which leads to an extensive decoupling.
/
9
Fig. 30
P
Basic scheme for combined steam/power grid.
45
0..ÿ'" <"
46
/
ÿ
\***I
5.5 Sliding Pressure Operation
5 Turbine Control
latter casefto perform load changes without the bled steam pressure being
appreciably affected, and to eliminate pass-out pressure fluctuations
without a noticeable effect on load.
When using the above methods,th£_dynamics of the controlled system
accuracy, from its static
'turbine' can be derive d. with
L
behaviour.
A further kind of supplementary turbine control is the 'import/export
power' control. The term stands for control of a specified energy flow
between an industrial power plant with its own consumer network, and
the general grid. It can, for instance, cover contractual inputs and outputs
of electrical power. The control scheme is built similarly to the schemes
for the already discussed load controls (see Fig. 21). Therefore, further
discussion would be superfluous
47
sufficient
Reference: [211]
T".
0
"
<
,
.-CUtÿ7
5.5 Sliding Pressure Operation
/
In recently built plants one can find increasingly more often the so-called
sliding pressure operation, when the pressure upstream of the turbine is
not kept constant but'varies pmpbrnonaHy'ÿvith load. The main advantage
of this mode of operation is that it minimizes temperature variations and
thermal stresses in the turbine, which in turn allows_faster load changes
without exceeding the turbine capacity to(stfStain fatigue) It is unfortu¬
nate that, on the other hand, the utilization of the steam storage in the
boilerjsj5recludecl) so that the already inert steam generator experiences
rrther delays during each load change. These are caused by the necessary
'
loading and unloading of the storage.
The so-called natural sliding pressure operationjsÿcharacterized either by
wide open turbine input valves, or by their igbseneeÿLoad changes can be
effected only by steam pressure variations. In the simplest case, it is
sufficient either t o (re mrftely adjust the firing rate in the boiler (open-loop
y) ÿ'" control), or to build a control loop along the lines suggested in Fig. 3 1.
This figure also contains the characteristic P = f(rhj) ) which reflects the
above conditions, and which is, with good approximation, a straight line.
'
The main disadvantage of this approach lies in the fact that the total inertia
of the boiler is introduced into the load control loop. This means that
demand fluctuations cannot be counteracted quickly enough. Since the
Fig. 31
Natural sliding pressure operation.
storage capacity of the steam generator is not made use of, the system has
no instantaneous reserve available, and an affective support of frequency
is not possible.
/
/
/
Should fast load changes be required, a compromise between sliding pressure
operation would have to be made. In actual operation, the turbine inlet
valves would then be temporarily engaged in control (exactly as in constant
pressure operation) only to return to the original fully open position when¬
ever steam pressure reaches the new value required by the variable pressure
operation. The scheme for this type of pressure control is shown in Fig.
32. Here, the turbine control structure follows the already discussed guide¬
lines. The boiler steam pressure control is executed as constant steam pres¬
sure control but the set point is made variable. The signal changing the
steam pressure set point is derived from the steam flow; generally, it is
programmed from load demand. The two system elements built into the
path of the steam flow signal (one with the inscription PTX , the other with
the sign of a characteristic) have the following task: In order to give the
turbine valves greater participation in load changes, the turbine inlet valves
must have a certain reserve with regard to their opening. Accordingly, in
the stationary state the valves are not fully open, but could allow, for in¬
stance, only 90% of full load steam flow (see the diagram on Fig. 32). Even
with this partly limited opening if is possible for the pressure to be increased
to the maximum value Pmax. In such a situation (i.e. with the pressure
remaining constant), a further increase in load would require a wider open¬
ing of the inlet valves.
Operations of this kind are marked by a characteristic similar to the one for
modified sliding steam pressure, shown in Fig. 32. Naturally, pressure can¬
not be made to drop to zero. Once a fixed minimum value is reached it is
held constant, and, from this point on, control is performed by the
throttling action of the valves. The steam pressure set point must be made
5 Turbine Control
/
ÿ F
l"D
5.5 Sliding Pressure Operation
<|)Ns
f-0HEF ,f*Eh
j
ÿ
Pmox
Fig. 32
1
&
Modified sliding pressure operation.
is no throttling. In other words, one must take care that the overload valve
(or the last nozzle group) is really closed, the remaining nozzle groups
being fully open. Due to such difficulties there are schemes where the
open loop control is replaced by closed loop control, with the valve posi¬
tion yj as the control variable. The signal from a PI controller with a wide
proportional band and a large integral action time constant, multiplies the
pressure set point signal, and continues the correcting action until the
desired position for yr is attained. However, from the point of view of
automatic control engineering, the pure open loop control solution is pref¬
erable due to fewer interactions.
References: [3] [11] [53] [54] [55] [60] [61] [64] [69] [83] [92] [146]
[147] [157] [158] [159] [161] [227] [270] [293]
0/rÿ"
yV1"1 A
ÿ
49
to follow thispressure characteristic exactly. This is done by the element
with the respective sign of the characteristic. The system element marked
with the letters PTX represents a delay element of the 1st order; its func¬
tion is to prevent the steam pressure set point from following immediately
all the changes in the load set point, which possibly could cause serious
overfiring. The combustion process is namely affected by a practically
permanent presence of a feedforward signal (i.e. auxiliary disturbance
signal from the load set point, nqlshown in Fig. 32) which adjusts firing
according to load changes. jMoreoyer, it is necessary to fill up the storage
w hichliacl~alreaclyTieen drawn upon1during the constant pressure opera¬
tion (signal from steam pressure). Should at this stage appear a signal in¬
stantaneously following the steam flow, firing changes, as already pointed
out, would become inadmissibly large. This is the reason for the delayed
introduction of the steain pressure set point signal.
As already described in the previous paragraph, in order to make the
storage capacity of the boiler available for exploitation, it is necessary to
provide a certain reserve in the opening of the turbine inlet valves. For
this purpose, one of the nozzle groups (usually the last) can be used. Then
all the nozzle group valves except one are fully open, with the valve for
the reserve being fully closed.
An even more frequent method for coping with this problem is to use an
overload valve (see also Fig. 18).
A specific problem arises if the circuit according to Fig. 32 is used: Here
it is necessary to make certain that the open loop control of the pressure
set point is realized in such manner that under stationary conditions there
4 Klefenz
6 Unit Master Control
Such an arrangement has to disadvantage that during load changes boiler
storage is not brought into play; as a result, changes in produced power
are almost exclusively determined by the inertia of the boiler. The impor¬
tance of the capability of the boiler to store energy in the form of steam
pressure, has already been discussed several times; the fact that it cannot
be used to achieve rapid load responses is sufficient reason for not re¬
commending the application of such an arrangement.
6 Unit Master Control
/lr
The term unit has already been explained in paragraph 2. Unit master
control simply signifies a super-imposed load-control system coordinating
the operations of the boiler and of the turbine, i.e. a system in which
control signals for the regulation of the boiler's firing rate and the posi¬
tioning of the turbine valves are developed simultaneously. This coordina¬
tion is necessary in order to prevent the overloading of one part of the
plant. For instance, the turbine cannot take up unlimited load but must
take into consideration the inertia of the firing of the steam generator,
which determines the follow-up ability of the boiler. Of course, there also
must be the possibility of totally decoupling the main plant parts during
turbine-alternator disturbances. The individual variants of coordinated
control will now be explained on the basis of the diagram on Fig. 33.
Case II: Only connections a and d are used. Steam pressure is controlled
by adjustments of fuel flow, while changes in the position of the turbine
inlet valves control the produced power. This control scheme allows the
exploitation of boiler storage, thus facilitating fast load changes. It is
therefore a solution that meets the current requirements. However, one
feature is still missing. Namely the above mentioned coordination between
the turbine and the boiler, which would take into account the interactions
between the two parts.
ÿ
5ÿ
S!>
"
v
Fig. 33
Universal scheme of coordinated unit control.
The controller R1 is the steam pressure controller with PI or PID control
action. R2 is the fuel controller, built as a PI controller. R3 is the posi¬
tioner (P controller) for the turbine valves. Finally, the controller R4
performs the function of a power output controller, and has, generally,
a PI control action. Possible connections between the individual controllers
are indicated by dotted lines a, b, c, and d.
Case I: Connections b and c are used; this is the classical approach in which
the positioning of the turbine valves is controlled by the pressure of the
superheated steam, while the power to be supplied to the system (the
megawatt output) is determined by control action on the firing rate.
51
t Case III: Connections a, b, and d are used. In addition to the main control
loops described under Case II, a coordinating link is provided between
these, in the form of connection b. In this case, following a load increase,
a signal using the path b will prevent the further opening of turbine valves
should steam pressure decrease too much. The opening will be limited
regardlesshgj whether the action is initiated by reason of the load change
being too fast, by the boiler being prevented from complying with the
increased demand due to some disturbance, or by any other reasonTTrT
practice, the path b is used when certain construction and process de¬
pendent limits are to be ÿnforcÿtL ÿAsÿexglajned above, a further opening
of the turbine valves is prevented, and the valves might even be made to
close, if the steam pressure drops below a specified minimum value.) The
described arrangement represents a definite improvement over Case II.
Case IV: All connections are used. This is the most universal arrangement
which permits optimum control of the thermal power unit. The connection
c has primarily the task of providing a feedforward signal for the fuel
controller, which is fairly standard practice with coordinated control
systems. It can, for instance, be used to make the fuel flow change in the
required direction immediately following a load change. The path shown
in Fig. 33 is therefore to be taken only as a symbolical representation. In
reality, the signal c could be a signal from the load set point, from the
actual load, or, frequently, from the steam flow, and could include fre¬
vV\
quency trim.
4*
\
<0
loeJL
52
- ÿboi
53
6 Unit Master Control
6 Unit Master Control
There is an arrangement that almost exactly corresponds to Fig. 33. This
is the so-called DEB-Method (Direct Energy Balance Method) which is
primarily used in the United States. In DEB the controllers R1 and R4
act jointly and continuously on the controllers R2 and R3, which auto¬
matically brings about coordination within the thermal unit. However,
power stations in Continental Europe give preference to arrangements
which guarantee the fastest possible load changes under any conditions:
The connections a and d are in permanent form, while c is replaced by a
load demand pilot signal (disturbance-variable compensation), sometimes
trimmed by transient and steady-state corrections, and b acts only as a
limiting signal. Such an arrangement is shown in Fig. 34. The feedforward
signal, in this case, is the steam flow signal mD which is proportional to
the electrical output of the station. The arrangement according to Fig. 34
is naturally valid only for constant pressure operation. A modification
according to Fig. 34.1 is necessary if variable pressure operation is to be
considered. There are two important additional items to be mentioned.
Firstly, since the turbine valves are almost 100% open, it is possible,
following a load increase, to achieve at first only such a rise in the steam
flow as will correspond to the actual extent of throttling. This would
render the proportional feedforward operation inadequate, and the unit
would only very slowly reach the new desired output. For this reason the
Ciuiwic'
ÿ
power output set point is used instead of the steam flow, both for the
y, feedforward operation and as a command signal for the steam pressure set
point. The PTX element (delay of the first order) is again applied for
dynamic adaptation. Secondly/as regards the manipulation of the pres¬
/\y
sure set point, it is necessary to keep in mind that, for the reasons given
above, it is the steam flow that must be the decisive factor under steady
state conditions. With this in mind, the steam flow signal and the power
output set point signal are compared in a maximum signal selector, where
the set point signal is somewhat weakened, so that in steady state the
steam flow signal can win through,. . (__
*Dt ÿ
£
—
©
ÿ
—|
pi
-ED~
-d)
---
0-4
'
Fig. 34
Coordinated constant pressure unit control.
ÿ
The unit load set point in Figures 34 and 34.1 is shown in a simplified
manner. In fact, it is executed exactly like the set point in Fig. 21, Alt. 2:
Here we have the possibility of introducing various limiting signals, as
well as that of remote control by,the load dispatcher.
Present unit control tends towards relieving the plant operators of detailed
decisions on rates of load change, on maximum and minimum unit loads,
etc. The aim is to leave those decisions to a central unit(guidance device
which is capable of collecting all the necessary information.
1
I
ÿ
-
' *V
P|
mD
(ÿ )NS
1 MQ X I
1
H
V-EEH
ÿ
7)—|—j/J
j
n? L
IpidI
1 1
4* —
L.
ÿ
-@—
N
Fig. 34.1 Coordinated sliding pressure unit control.
6 Unit Master Control
54
6 Unit Master Control
Data to be assembled would concern:
A unit manager of this kind is also of considerable value in automatic
run-ups and run-downs, since it enables the plant to perform these opera¬
tions with optimum speed. An example of centrally coordinated control
is shown on Fig. 35. The unit control computer receives all the necessary
information regarding:
— availability of feedwater pumps,
— number of available coal mills or oil burners,
— availability of F.D. and I.D. fans,
— state of preheaters,
— thermal stress in the turbine,
— thermal stress in boiler parts at risk (e.g. heavy-walled headers),
— checking orjlimit positions of control valves such as
attemperatiort valves.
On the basis of all such information the unit guidance computer (boiler/
turbine coordinator) can determine whether the target load can be
produced, and, if so, with what gradient can the load be ramped to the
new state.
-trO—
ÿ
by-pass controller
i—
—E]—
remote set point
computer
::
computer
unit
load margin
ordinatoi
turbine
load margin
cnteria
T<§h
J
J i ! 1
fuel flow
controller
Fig. 35
55
Unit control incorporating a unit coordinator
The load can then be automatically guided at optimum speed toward the
target value, or that permitted by limiting factors. In the case of an
accident, such as a breakdown of an F.D. fan, which would not allow the
unit to remain at its current load level, the unit would be automatically
run back to the permissible load value, i.e. to a safe level.
— steam pressure,
— steam pressure set point,
— steam flow,
— power output,
— power set point (local or remote),
— frequency,
— factor AN/Af (required if frequency supporting operation is to be
performed),
the state of boiler auxiliaries,
regarding
— various criteria
the state of turbine auxiliaries,
various
regarding
criteria
—
— boiler load margin,
— turbine load margin, etc.
The above data is used in calculating control signals for fuel handling
equipment, turbine valves, high-pressure by-pass stations, etc., and the
information is fed to the respective controllers. The boiler load margin
(i.e. the amount by which the load can be quickly changed without en¬
dangering the boiler) is determined from supervision data obtained for
the relevant boiler parts. To this effect, stresses are calculated from tem¬
perature measurements on heavy-walled headers; the difference between
the calculated and the permissible values is then used to obtain the free
margin for a fire or load change. Similarly to the stress calculating in¬
strument for the boiler there is also one for the turbine. The latter device
uses the characteristic wall temperatures in the wheel chamber of the
high-pressure stage of the turbine, together with the current steam pres¬
sures, for the calculation of the free margin of thermal stress. The calcu¬
lated value is then translated into load margin for the turbine. Instruments
of this kind are generally called turbine (or boiler) stress evaluators.
Until quite recently, such unit coordinators have been constructed with
analogue modules. Lately digital technology in the form of microcomputers
has infiltrated power stations, and so the required computing as well as
logical combinations and decisions, which constitute a superimposed part
56
6 Unit Master Control
of free programming and unit control, will be carried out by a digital
computer.
References: [3] [7] [14] [26] [30] [33] [56] [76] [83] [90] [92] [146]
[147] [189] [191] [192] [195] [209] [210] [212] [217]
[228] [233] [242] [248] [260] [262] [267] [268] [269]
[271] [292] [298]
7 Control of Boilers on a Busbar
The main features of busbar system operation are described in section 2.2.
The section also contains comments on the main disadvantages of such
systems from the point of view of control.
When comparing the busbar system with a single boiler, we find additional
control loops unique for parallel boiler operation. The following text will
cover some of the most common schemes for load control. To make it
simple it will be assumed that only two boilers are participating. This is
not a serious limitation since at any time the number can be easily in¬
creased.
The objective of load control is to regulate the energy input into the in¬
dividual steam generators so that consumer steam requirements are met.
An unequivocal measure of the balance between steam production and
consumption (offtake) is the range pressure. Any unbalance causes its
deviation from the set point, making this particular parameter the most
suitable controlled variable for load control.
Z
z
—'<
©
Pc
?"
I
[n]
Fig. 36
Load control for
busbar system operation.
Alternative 1
$
.r.J
i
©T
<i)i
7 Control of Boilers on a Busbar
7 Control of Boilers on a Busbar
Fig. 36 shows a typical variation of range pressure control. The steam
pressure deviation signal forms the input to the main controller which has
PI or PID action. The controller output signal branches out, and continues
becoming the input signal for the fuel controllers of individual boilers.
With such a set-up any pressure deviation will change both fuel inputs
simultaneously. This would avoid any paralleling difficulties if the boilers
were identical and designed to carry an equal load. In practice, however,
the proportionate contribution of the boilers varies. The extent to which
the individual boilers are affected depends on the setting of the trimming
modules or ratio adjusters A that bias the respective signals. In general, it
is assumed that the boilers contribute to load changes in the ratio of their
maximum steam outputs. However, it is not difficult to imagine that there
may be reasons for treating one of the boilers with extra consideration.
This would have to be done by manipulating the biasing adjusters, thus
making it possible to achieve any desired proportional participation in
energy production. If and when adjusting such a bias, it should be remem¬
bered that the loop gain of the total control loop should, as far as possible,
remain unchanged. The fact that each adjustment of A changes the gain
in the corresponding sub-loop can lead to difficulties, unless specific pre¬
cautions are taken. These precautions consist of balancing the reduction
in the share of the total gain in the one sub-loop by an equal increase in
the other sub-loop, so as to revert again to optimum conditions.
conveyed, the controller receives a (false) signal from the speed measuring
device.
58
Two additional set point setters marked T are included in the control
diagram on Fig. 36. They provide another means of trimming the output
power of the boilers. Such trimming consists in pre-setting the two basic
fuel flows, the adjustment affecting the ratio of the boiler loads. One dis¬
advantage of this arrangement is that the accuracy with which the load is
distributed between the two boilers depends upon the accuracy with
which the energy flows into these boilers are measured. There is no prob¬
lem with oil and gas firing; however, undesirable long-term errors can
accumulate in the load distribution when dealing with coal firing where
one has to depend on substituted measured quantities, e.g. on the speed
of the coal feeder — see Fig. 36.
An obvious remedy would be to provide each boiler with a separate steam
flow controller, which would eliminate both real and unreal heating value
fluctuations. Under the term 'unreal heating value fluctuations' are
understood such disturbances as bridging of coal in the bunker. If this
does occur the coal feeder continues running, and although no coal is
59
This brings us to the control scheme according to Fig. 37 (Alternative 2).
Here each boiler has a steam flow controller with the set point guided by
a superimposed steam pressure controller. Proportionate biasing as well
as trimming, in the already described form, is likewise possible.
Fig. 37
Load control for busbar system operation.
Alternative 2
The advantage, in this alternative, of having a load distribution independent
of fluctuations of the heating value, is to be viewed in contrast to a very
definite disadvantage concerning process dynamics. Let us consider an in¬
creased load demand by the consumers: At first, steam pressure drops
below set point, causing the set points of the steam flow controllers to
increase. The rise is effected by a change in the output signal of the steam
pressure controller. As a consequence, fuel flows increase in accordance
with the steam flow set point rise. This is as it should be, but, unfortunate¬
ly, the steam flow control loops behave contrary to expectations. Namely,
the increased steam flow, enforced under the above circumstances,
manifests itself as an increase of the steam flow signal which, since it is
applied to the input of the fuel flow controller with a negative sign, acts
60
7 Control of Boilers on a Busbar
7 Control of Boilers on a Busbar
61
against the output signal of the pressure controller. This means that the
increased steam flow will tend to reduce fuel flow.
measures, Alternative 1 would have better dynamics than Alternative 2,
which is the reason why it should be preferred.
Since both effects act against each other, in order to achieve a fast in¬
crease in firing it is necessary to make the influence of the signal from the
steam pressure side appropriately more important. The limiting factor here
is loop stability, i.e. a too energetic adjustment of the controller is not
Finally, another alternative should be discussed, one that is limited to dram
boilers. This is Alternative 3, and is presented on Fig. 38.
allowed.
In contrast to the change in demand, the controllers behave quite diffe¬
rently during disturbances originating in the fuel supply (such as the al¬
ready mentioned bridging of coal). During a reduction of the fuel flow
both signals (i.e. the steam pressure and the steam flow signal) act as
required; since both steam pressure and steam flow decrease simultane¬
ously, the signals tend to support each other in increasing the fuel flow.
It is evident that an attempt should be made to implement some compro¬
mises in the design and the setting of the controllers. Without such extra
Fig. 38
Load control for busbar system operation.
Alternative 3
Alternative 3 consists of each boiler being equipped with a drum pressure
controller, the set point of which is guided by the superimposed range
pressure controller. The considerable advantage of such a control arrange¬
ment rests in its very favourable dynamic behaviour. The drum pressure
controller and the range pressure controller show the same reaction to all
kinds of disturbances, so that real optimization of all the controllers in¬
volved is a distinct possibility. Since each drum pressure controller can be
optimized independently, there are advantages even if an inert and a fast
boiler have to be used together. (For example, one boiler may be coal fired
while another is oil fired). Independent optimization allows faster load
changes than were possible in Alternatives 1 and 2. This means, in effect,
that the faster boiler can temporarily take over part of the load of the
more sluggish one, which in other arrangements is either not possible to
the same degree or not possible at all. Certainly, in Alternatives 1 and 2
control must be consistent with the behaviour of the slowest boiler.
Unfortunately, Alternative 3 also has its disadvantages, which becomes
evident during steady-state operation. If the boilers are not uniformly
loaded, the respective load shares shift with load, since there is a quadratic
relationship between the rise in drum pressure and load. However, this
disadvantage cannot be considered too serious, since, in general, the con¬
trolled boilers carry an evenly distributed load. In any case, the conditions
are easier to judge than in the case of mutually biased boilers.
References: [3] [83] [92] [127] [187] [194] [243] [275]
8.1 Types of Boilers
•
8 Boiler Control
Under discussion in this chapter is the control of conventionally fired steam
generators. Conventional fuels are understood to include coal (black and
brown), oil, and gas (natural gas, blast furnace gas, refinery gas, coke oven
gas). Control of nuclear power plants will be dealt with in a separate chapter
since the application of nuclear energy as well as its control are based on
concepts generally different from those used in conventional power stations.
economiser
Fig. 39
Circulation Boilers
(Drum Boilers)
Once-Through Boilers
(Forced-Flow Boilers )
Natural Circulation Forced Circulation Benson Boilers Sulzer Boilefs
Boilers - (La Mont)
Boilers
While in the once-through boilers the liquid (water, steam) flows through
the boiler in a direct line, in the circulation boilers considerable circulation
in the area of the evaporator takes place.
References: [187] [188] [217]
8.1.1 Natural Circulation Boilers
The most widespread drum boiler is the natural circulation boiler, shown
in outline on Fig. 39.
superheater
r evaporator (riser tubes)
8.1 T ypes of Boilers
Since the type of boiler used decisively influences the control scheme to
be applied, it is the main steam generator types that will be introduced first.
Only such properties as are important for control will be looked into. One
basic classification of the boilers is possible in the following manner:
63
Basic scheme of a
natural circulation boiler.
feedwater pump
Here the feedwater pump forces the water through the economiser into
the drum. From there it is supplied to the lower furnace wall headers
through a system of mostly unheated downcomer tubes. Steam is gener¬
ated as the water rises through the furnace wall riser tubes exposed to
heat radiation. The water/steam mixture is then transferred to the boiler
drum. The circulation is maintained by the difference in the densities in
the downcomers and in the risers, and is evidently caused by gravitation;
this is the reason why the boilers are known as natural circulation boilers.
Steam is separated from the steam/water mixture in the drum, and leaves
the boiler through the superheater section.
From the point of view of control technology the drum boiler is charac¬
terised by the following features:
— The water level in the drum is an unequivocal measure of the feedwater
which must be supplied to the boiler.
— The drum strictly separates the evaporator from the superheater areas,
this being advantageous from the point of view of the reaction of
steam temperature control to disturbances. Changes in the feedwater
flow have no effect on steam temperatures.
The storage capacity which depends on the content of the drum as well
as of the recirculation tubes, is relatively large, so that during load
changes the inertia of firing can be successfully counteracted.
— In general, since the drum keeps the evaporation end point locally
fixed, the live steam temperature cannot be maintained at set point if
the load drops below 40 to 50% of maximum rating.
Reference: [194]
—
8 Boiler Control
64
8.1 Types of Boilers
65
8.1.2 Forced Circulation Boilers
In a natural circulation boiler the flow through the evaporator part is
maintained by the difference between the specific gravity of the water in
the downcomers, and that of the water/ steam mixture in the risers. On the
other hand, in forced circulation boilers the natural circulation is sup¬
ported by a circulation pump (see Fig. 40). This boiler type is also known
by the name of the LaMont boiler. The advantage of these boilers is that
the circulation is guaranteed also under relatively high pressures when the
density of water closely approaches that of saturated steam. From the
control engineering point of view there are no apparent differences bet¬
ween the LaMont and the natural circulation boiler, which means that the
points mentioned in section 8. 1.1 are also fully valid for the forced
circulation drum boilers.
r superheater
ÿ
evaporator
r economiser
) feedwater pump
Fig. 41
Basic scheme of a Benson boiler
Reference: f2 17]
superheater
evaporator
J circulation pump
i
•
economiser
(T) feedwater pump
Fig. 40
8.1.3
Basic scheme of a forced circulation boiler.
Benson Boilers
Benson boilers are a sub-group of the forced-flow (once-through) boilers.
The basic scheme is shown on Fig. 41. Here the liquid is being forced
without any detour straight through the economiser, evaporator, and
superheater. The control enigneering consequences are as follows:
— The maintenance of the correct relationship between the feedwater
supply and the heat supply is problematic in that we do not have an
unequivocal indicator of how the required feedwater supply is met.
The evaporation boundaries are not fixed. They shift with load and
with any imbalance between firing rate and feedwater flow. The re¬
sulting increases and decreases of the heat accumulated in the eva¬
porator section of the boiler, accompanied by fluctuations of the
heating surface area, cause disturbances in steam temperature control.
The shifting of the initial and of the end points of evaporation is out¬
lined in Fig. 42 which illustrates the theoretical case of uniform heating
and uniform flow in the pipework. A load increase to full load (Case
d) moves the starting point and the end point of evaporation away from
the point of entry to the boiler, and reduces the length of the evaporator
section. The increase of steam pressure, which in turn increases boiling
temperature, makes it necessary to extend the pre-heating zone. Further,
higher pressure reduces the latent heat, thus bringing about the shorte¬
ning of the evaporator. These are general rules from which, however,
there appear in practice many more or less serious deviations, usually
associated with the variations in the construction of the combustion
chamber. The amount and distribution of the steam admitted to the
pipes as well as the state of the fire which may change with load, have
a decisive influence on the process in the evaporation zone, and, there¬
fore, also on the dynamic behaviour of the evaporator.
— The storage capacity is considerably smaller than it is in dram boilers
(approximately j to -|), thus making steam pressure control more
demanding.
5 Klefenz
8.1 Types of Boilers
8 Boiler Control
66
67
economiser j evaporator ; superheater
U-L, --j
superheater
w////////ÿ/Mm° o°n° A30
W/MssA
I
<>
J L2
I
H
-
t3<t.
-
->
-
01
evaporator *
l4< t,
water separator
('bottle')
| U-L<—Ai
Fig. 42
Schematic representation of the processes in the evaporator
of a Benson boiler.
economiser
a) Division between the economises evaporator, and superheater at
partial load.
b) Changed division following an increase in feedwater flow;
Starting point partial load a).
c) Changed division following an increase in fire power;
Starting point partial load a).
d) Changed division following a transition to full load.
— Due to the fact that the size of the heating surface can be varied de¬
pending on boiler load, it is possible to reach the full load steam tem¬
perature even at partial loads. All that is necessary is that care be taken
to ensure a sufficient increase in the superheater heating surface, and
that can be achieved by appropriately raising the feedwater flow.
— Benson boilers can operate with practically any steam pressure, since
no circulation difficulties can occur. Supercritical pressure operation
(P> 221.2 bar) is likewise possible. For the control engineer, super¬
critical operation causes no specific problems, and control can be de¬
signed along the same lines as for subcritical boilers. Further, the al¬
ready mentioned variable pressure control is possible with a Benson
boiler.
-
feedwater pump i
Fig. 43
Basic scheme of a Sulzer boiler.
structural feature is that in contrast to the Benson boiler the economiser
and evaporator pipes run continuously between the entry and the exit
points without interposed headers.
This results in there being only one input and one output header. As re¬
gards control, this feature is, however, of secondary importance in com¬
parison to the water separator which exercises a decisive influence on the
dynamic behaviour of the whole boiler, in addition to its original task of
salt separation. In connection with this it should be noted that the socalled bottle which is currently more frequently found in Benson boilers,
does by no means perform the same function as the Sulzer water separator.
The Benson separator functions, as will be subsequently explained, only
during start-ups and low-load operation. In normal operation it is either
dry (i.e. slightly superheated) or wet. The control of a Sulzer boiler is
characterised as follows:
8.1.4 Sulzer Boilers
— The level in the separator, or the moisture at the outlet of the separator,
are, similarly to the level in a drum boiler, an unequivocal measure of
the balance between the feedwater flow and the firing power. This makes
feedwater control in a Sulzer boiler simpler to manage than in a Benson
The Sulzer boiler (or the Sulzer monotube steam generator) is another
forced circulation boiler. It differs from the Benson boiler in that a
separator is interposed between the evaporator and the superheater (see
Fig. 43). This separator is often referred to as 'the bottle'. A further
— The separator localizes the evaporation end point. Since the shifting
of this point is no longer possible, the disturbing interaction with the
superheater, and, in particular, with the superheater temperature,
becomes irrelevant.
References: [197] [261] [3201
boiler.
5*
68
8 Boiler Control
8.2 Control Loops
69
— The storage capacity is somewhat larger than in a Benson boiler.
— Since, as in a drum boiler, the superheater heating surface does not
change with load, problems arise, from the static point of view, with
the main steam temperature control at low loads.
References: [11] [63] [199] [213] [214] [230] [259] [287] [288] [289]
8.2 Control Loops
The detailed discussion of the individual control loops will be preceded
by a short introduction giving a review of the main control loops in the
various boiler types.
The four main control loops in a dram boiler are shown on Fig. 44. The
main steam pressure controller, also known as the firing controller, is
marked as Rl. The deviations of the main steam pressure from the set
point cause the controller to increase or decrease the fuel flow in parallel
with the accompanying combustion air flow. This affects the evaporation
rate which, in turn, restores the steam pressure to its set point value. R2
denotes the furnace pressure controller, also called the furnace draught
controller. The task of this loop is to keep a certain draught in the furnace,
in order to prevent leakage of the flue gases into the boiler house,
through the not completely impervious boiler walls. Deviations from the
set point lead to a corresponding increase or decrease of the rate of re¬
moval of the flue gas. In Fig. 44 the controller maintains the draught by
acting on the control vanes of the I.D. fan that transports the gases from
the boiler to the stack.
With increasing frequency boiler walls are found becoming seal welded
(this leads to the so-called membrane walls) so that firing operation can
be carried out at positive pressure. In such cases draught control can na¬
turally be expended with.
The controllers Rl and R2 are sometimes considered together under the
collective name of 'external control'. This is in contrast to 'internal
control' which is particularly concerned with the control of fluids, i.e.
with processes within the boiler pipes and tubes.
Accordingly, internal control includes the temperature and the feedwater
controllers. R3 symbolizes the main steam temperature controller. In the
diagram it is assumed that temperature is controlled by injecting feedwater
Fig. 44
Main control loops of a drum boiler
into the steam (spray type cooling, attemperation), such method being
most frequently used. In large boilers several such control loops are in¬
stalled in series. The fourth main control loop in a dram boiler is the drum
water level control (R4), also called feedwater control. Following a de¬
viation of the drum level from the set point, the feedwater flow into the
boiler is more or less throttled. For this purpose it is possible to use
either the feedwater control valve (as, for instance, in Fig. 44), or the
feedwater pump, or both methods combined.
Since there is no difference between the control of a natural circulation
boiler and a forced circulation boiler, forced circulation boilers need not
be dealt with separately.
Next in line for discussion are the main control loops of a Benson boiler
(see Fig. 45). The external control is the same as is the corresponding
control in the drum boiler which has been discussed in reference to Fig.
44. Rl is again the main steam pressure controller, and R2 the furnace
70
8 Boiler Control
I
z
--
3;
Fig. 45
'a-o-
1
Main control loops of a Benson boiler.
draught controller. With regard to internal control, the main steam tem¬
perature controller R3 is also applied in the same manner as it would be
in a dmm boiler. On the other hand, the concept of feedwater control is,
out of necessity, different. One must remember that there is no water
level signal: Here lies the real difficulty of Benson boiler control. The
feedwater supply must be controlled so that the disturbances of the fire/
water equijibrium in the boiler are minimal, and that the attemperator
water flows stay within the control range at all times. The last requirement
represents a very important boundary condition that must be met. As has
already been explained, it is possible to arbitrarily shift the evaporation
end point (and thereby also the superheater heating surface) by a change
in the feedwater flow.
8.2 Control Loops
71
This might lead to widely differing requirements on the attemperation
water flows if the main steam temperature is to be kept at the set point
even when the feedwater flow changes. On the other hand, it is evident
that the above effect can be put to use for maintaining the attemperation
water flows within the required control range by an adjustment of the
feedwater flow.
The problem of keeping the attemperation flows within range has many
solutions the one shown in Fig. 45 represents the most frequently used
approach. R4 is a flow rate controller for feedwater flow, which receives
a feedforward set point signal from the steam flow. However, the steam
flow signal does not combine with the feedwater flow signal in a 1:1 ratio,
but is somewhat weakened by the ratio adjuster A. The effect of this is
that the feedwater flow entering the evaporator is always slightly less than
the main steam flow at the outlet of the boiler. This imbalance must be
made good by the attemperation water flow supplied to the boiler. Such
a mode of control can be considered as attemperation-water-flow/feedwater-flow ratio control, even though the controlled variable is not
measured. Here the ratio of the attemperation water flow to the feedwater
flow repleaces what would otherwise be the drum level which with Benson
boilers is non-existent.
The reheated steam temperature control loop which can be found in
practically all large units, is generally regarded to be the fifth main control
loop. From the many possible variants the one chosen for Fig. 45 is based
on the presence of a heat exchanger between the high pressure stage and
the intermediate pressure stage.
High pressure steam gives off part of its heat to the intermediate pressure
steam. This transfer of heat can be varied for control purposes using a by¬
pass duct equipped with a control valve, and installed on the high pres¬
sure side. Should the reheated steam temperature deviate from the set
point, the controller R5 would change the opening of the by-pass valve.
The main control loops of a Sulzer boiler are shown on Fig. 46. The ex¬
ternal control (controllers R1 and R2) corresponds to the external controls
of a drum boiler or of a Benson boiler, and therefore need not be discussed
further. Likewise, the main steam temperature control system (R3) is
conceived according to the principles already described.
Because of the presence of the water separator, located at the outlet of the
subcritical evaporator, the feedwater controller (R4) is necessarily diffe¬
rent from its counterpart in the Benson boiler. The fact that the separator
8 Boiler Control
72
i
Fig. 46
Main control loops of a Sulzer monotube boiler.
fixes the evaporation end point, would make the steam moisture upstream
of the evaporator a suitable variable for determining the actual feedwater
flow that has to be provided. Unfortunately, no measuring method for
steam moisture is available for practical application, and replacement
variables have to be found. One possibility is to control the level in the
separator, simultaneously ensuring that the mass of deposits blown down
from the separator is proportional to load. This is due to the following
relationship:
(12)
mA
1-X = >"D + mA
j
+ JUD
mA
where
X
= steam content
1 - X = moisture
rh\
m.j)
= blow-down water flow
= steam flow from the separator into the super¬
heater
8.2 Control Loops
73
If rhÿ/mA is held constant, then the moisture (1 — x) is also constant. It
is evident that this can be achieved only through the cooperation of con¬
trollers R4 and R6. Controller R4 controls the water level by changing
the feedwater flow, with the set point varying as function of load. The
purely proportional controller R6 then regulates the blow-down making
it proportional to the load dependent level. The valve characteristic is so
designed that the blow-down flow is proportional to the valve position.
The controller R5 is the reheat steam temperature controller. From the
various possibilities of controlling the reheat steam temperature, the
variant chosen for Fig. 46 is one which is often found in Sulzer boilers,
and which uses the so-called Triflux heat exchanger together with water
injection into the high pressure zone. With this method the reheat steam
is directed through a heat exchanger where it exchanges heat with high
pressure steam. Further, the heat exchanger itself is heated by flue gas.
This three- flow heat exchanger (the Triflux) is basically a system of
concentric tubes with high pressure steam flowing on the inside, and the
reheat steam in the shell. The heat absorption by reheat steam, as well as
its heat release, can be adjusted by injecting feedwater into the high pres¬
sure steam upstream of the Triflux. This whole process is controlled by
controller R5 which ensures that steam temperature at the reheater
outlet is kept constant.
Following this summary of the most important control loops, the ensuing
sections will deal in more detail with the variations of these loops.
References: [3] [18] [37] [83] [92] [188] [191] [196] [204] [206] [215]
[216] [217] [244] [266] [273] [274] [295] [297] [314]
8.2. 1Live Steam Pressure Control Loop
8 Boiler Control
74
75
8.2.1 Live Steam Pressure Control Loop
As can be gathered from the prece«ding comments, steam pressure control
does not depend on the boiler type, and therefore can be dealt with in a
general manner. The control variable is the thermal energy released in the
burning process, and this energy is determined by the fuel flow and the
matching combustion air flow. Only the control of fuel flow will be dealt
with in this sub-section; air flow control will be treated separately in the
next sub-section (8.2.2). Due to the use of various fuels as well as due to
the divers furnace constructions, there are naturally many variations of
control; from these only the most typical will be dealt with. First in line
are the oil fired boilers. Their control scheme is presented on Fig. 47. It
shows a cascade control loop with a PID steam pressure controller super¬
imposed on a fuel flow controller. Here the main disturbance is the steam
flow leaving the boiler, mD . A feedforward compensation seems indi¬
cated, with the steam flow signal acting as the disturbance variable. Ge¬
nerally this signal acts proportionally on the fuel flow controller. Should
more than one oil control valve be needed — and there is the possibility
of having a separate valve for each burner level — it would be advanta¬
geous to use a superimposed total-oil-flow controller in addition to the
individual flow controllers. This way changes in the number of operating
burner groups would have only a limited effect on the rest of boiler
controls.
The controls for gas and for pulverized coal firing are structured along very
similar lines. Fig. 48 shows a scheme for pulverized coal firing using a
direct firing system where coal and air pass directly from the mill to the
to
»-
air flow control
Fig. 47
Control scheme for oil firing.
air flow control
Fig. 48
Control scheme for pulverized coal firing.
burners, and the desired firing rate is a function of the rate of pulveri¬
zation. Only two mills are shown, but should more mills be needed, the
scheme could be accordingly extended. The output signal of a PID steam
pressure controller, combined with a steam flow feedforward signal, pro¬
vides the set point for a cascaded PI main speed controller. The output of
this master controller is fed to as many parallel P controllers as there are
mills. The P controllers adjust the positioning levers of the torque variators
which serve as variable speed gears for controlling the rate of feed (mostly
PIV-gears).
The speed of the coal feeders is assumed to be a measure of the coal flow
into the boiler. Unfortunately, this signal does not reflect the disturbances
caused by variations in the heating value of coal, nor those caused by in¬
terruptions of the coal flow such as might occur following the bridging
of coal in the bunker.
\
76
8 Boiler Control
ÿj1
8.2.1 Live Steam Pressure Control Loop
p
ÿ—©
to combustion
air control
to combustion
*"air control
I
to combustion
air control
(oil firing)
£n
(coal firing)
to further mills
The superimposed master pressure controller with steam flow (rhÿ) feed¬
forward compensation, provides the demand .signal for the cascaded total
fuel flow controller. The output of the latter controller is led in parallel
to two P controllers which in turn act on the oil control valve and on the
feeder control gear. In the method outlined by the diagram both fuels are
burned in parallel, i.e. each load change causes an adjustment of both oil
and coal flows. Another possibility is to bum fuels in sequence: For in¬
stance, for low loads only coal and no oil is burned. Oil gets to be used
only when the capacity of the coal mills is fully exhausted ; then it con¬
tinues to support firing until full load is reached. This sequential burning
of the fuels can be achieved by providing a negative bias acting on the set
point of the oil flow controller (in the scheme it is marked by dotted
lines). Such a negative signal keeps the oil control valve shut or just barely
open, until a time when the fuel flow controller output signal rises above
the negative bias, and the oil flow controller receives a positive signal to
open. The problems of automatic burner management, and namely of
keeping a minimum oil flow for the burners in operation, have been
omitted from the scheme for the sake of clarity.
mD
Fig. 49
Control scheme for firing mixed fuels (coal and oil).
PID
Before such disturbances can be corrected, they must first become effective
as changes in steam pressure. Unfortunately, in practice there is still no
applicable coal flow measurement that would allow for an auxiliary coal
flow controller to deal with this situation.
Another disturbance-variable in steam pressure control is, of course, the
main steam flow. To deal with it, a signal corresponding to the steam flow
is applied as a feedforward signal at the input of the coal feeder speed
controller. In this manner, as a result of steam flow changes, these con¬
trollers receive signals which give them an impetus in the right direction
before any changes in steam pressure are detected.
The next example (Fig. 49) deals with firing mixed fuels. Here coal and
oil can be burned, either without preference, or in a specified order. The
build up of the diagram is in principle the same as that of the previously
discussed schemes.
77
Mm
to combustion
air control-* —
(oil firing)
Fig. 50
1 combustion *air control
f
(gas firing) I
Control scheme for firing mixed fuels (preferentially gas and oil).
8 Boiler Control
8.2. 1Live Steam Pressure Control Loop
If there are several separately controlled oil burner levels it is advisable to
replace the master fuel controller (common to both fuels) by two parallel
controllers, one for the total oil flow, and one for the sum of the feeder
speeds. This would have the advantage that all disturbances on the oil
side, such as taking a burner out of service, etc., would be corrected by
the oil firing alone, and would have no effect on the coal side. A corres¬
ponding consideration naturally applies to coal control.
results in the output signal from the gas pressure controller becoming
stronger than the one from the steam pressure controller. Consequently,
a minimum signal selector blocks the former signal, and
only the latter
signal is switched through. Further increase in gas pressure has no
effect
on the gas flow which is kept at a value corresponding to boiler load.
78
burn
It occurs quite frequently that one fuel is given priority in order to
waste
of
burning
the
be
would
case
typical
A
available.
as much of it as is
and
utilized
profitably
be
should
which
gas
furnace
gases, such as blast
control
not just flared to atmosphere. But here the main problem for boiler
smooth
A
possible
strongly
fluctuate.
may
available
is that the amount
transition from one fuel to the other is therefore particularly important,
if the disturbances of steam production are to be avoided. One possible
solution to this problem can be that suggested by Fig. 50. If we start with
the assumption that no gas is available, the result would be the activation
of steam pressure control on the oil side in the manner already described
in connection with Fig. 47. Here a low limit is provided to guarantee a
minimum oil flow under any circumstances. This is particularly important,
because an extinction of the oil flame in conditions where there is plenty
of gas must be prevented at all cost. Upon the start of the gas flow, the
gas pressure PG will rise and the gas pressure controller act via a minimum
selector on the gas flow controller. The other signal to the selector comes
from the steam pressure controller and corresponds to boiler load; it must
at the beginning be stronger than the signal coming from the gas pressure
controller, which starts from zero. Thus the gas pressure controller keeps
increasing the set point of the gas flow controller as long as the gas flow
into the furnace is below that available. This meets the requirement that
the total amount of gas be burned in preference to oil. The oil flow is
gradually reduced in proportion to the increasing gas flow. To by-pass the
need of reducing the oil flow via the steam pressure control system, the
oil flow controller receives a signal directly from the gas flow. As regards
the respective polarities, the command signal for the oil flow controller
is diminished by the amount representing the gas flow, thus reducing the
oil flow itself. In this manner, any change in the gas flow is immediately
corrected by the oil flow, without the steam pressure control loop being
brought in.
If the gas supply exceeds the demand determined by the boiler load, the
following happens: Oil flow is reduced to the pre-set minimum value. This
79
In Fig. 50, a further set point signal having a negative sign is added to the
input of the gas flow controller. The reason for this is primarily as follows:
By definition, the signal provided by the superimposed controller corre¬
sponds to boiler load. It follows therefore that as long as there is enough
gas, the signal is equal to the gas flow from which the constant
basic oil
flow value has been subtracted. As a result, the above negative set point
signal (or, rather, the negative fixed command signal) corresponds to the
minimum oil flow signal pre-set on the already mentioned minimum
limiter.
In conclusion one more common scheme for firing mixed fuels will be
dis¬
cussed. This one is particularly suitable for plants having a common
primary air control, and where two kinds of fuel are burned without
pre¬
ference. In the schemes that have been discussed so far it was assumed
that the combustion air is controllable for each fuel separately. However,
furnaces exist where air is brought to the oil and natural gas burners from
a common wind box. The burners are so adjusted that each
receives the
same air flow. This demands a control scheme like that on Fig. 51. The
command signal generated by the superimposed master control (PID
steam pressure controller plus proportional feedforward steam flow com¬
pensation) is again equal to the total fuel flow demand. It is simultane¬
ously used in parallel as the command variable for the total combustion
air flow. The actual command signal for the oil flow controller is
obtained
by multiplying the fuel flow demand signal by the ratio Zq/Z, where Zq
is the number of oil burners actually in operation, and Z is the
total
number of installed oil and gas burners.
The actual command signal for the gas burners is produced by a corre¬
sponding method which uses multiplication by ZG/Z instead of by Zq/Z
(Zg being the number of gas burners in operation). In this manner, the
boiler load is divided between the two kinds of fuels in the ratio of the
numbers of operating oil/gas burners. A change in this ratio can be effected
only through a modification of the term Zq/Zg . All the burners are
inevitably proportionally loaded. Should a burner be put in or taken out
of service, the appropriate correction does not depend on the action of
80
8.2.1 Live Steam Pressure Control Loop
8 Boiler Control
81
control. Fig. 52 shows a variant with a correction of the fuel flow control,
while a correction of the air flow control will be mentioned in sub-section
8.2.2.
•+*mo
<d~4
E»J
jr_
zf-ÿ
\
to combustion
ÿair control
— z#
i»]
to the blade-type regulating
t
damper-controller
cyclone 2
:oil
r natural gas
Fig. 5 1
Control scheme for firing mixed fuels (common air).
the steam pressure control loop, but is immediately provided by the fast
action of the fuel flow control loop. This is so because the multiplication
factors Zq/Z and Zq/Z in the feedforward signals change immediately
following any burner switching (either in or out). For example, with five
oil and five gas burners in operation, the relevant amounts are
100%
oil flow, and jq • 100% gas flow. Following the removal of one oil burner,
the feedforward signals change to • 100% oil flow and • 100% gas
flow, the share of the lost burner being proportionately covered by all of
the remaining burners.
cyclone 1
ÿ
The final example will deal with the control of coal firing in cyclonefurnaces. Here the circumstances are slightly different from those already
described for pulverised coal firing (see Fig. 48) in that on multi-cyclone
installations it is particularly important to maintain correct conditions in
each cyclone-furnace. The combustion process as well as the melting of
ash to slag react very sensitively to any deviations from optimum excess
air, making a continuous oxygen correction a necessity. The automatic
02 correction can intervene both in fuel flow control and in air flow
Fig. 52
Control scheme of a cyclone furnace.
The command signal from the superimposed master steam pressure control¬
ler is led, after having been divided, to the coal flow controllers of the two
cyclones. The oxygen content is measured downstream of each cyclone,
and the corresponding signal is connected to the input of the 02-correction
controller. The resulting correcting signal then multiplies the command
signal to the coal flow controller, thus varying the ratio between the com¬
bustion air flow and the coal flow. Should the quality of the burned coal
change, the fuel/air ratio is, after one correction, optimal for all load ranges.
6 Klefenz
82
8 Boiler Control
8.2.2 A ir Flow Control Loop
The reason why a correction using a multiplier is preferred to one using
an adder is that the latter requires certain action at each load change even
with an unchanging quality of coal.
References: [3] [7] [18] [83] [92] [103] [189] [201] [217] [220] [233]
[235] [241] [257] [263] [273] [278] [289] [298] [304] [315]
[319]
The control scheme for a travelling grate stoker will be discussed in sub¬
section 8.2.2. Since in this kind of control the action of the steam pres¬
sure controller starts with combustion air, the topic appropriately falls
under the title of air flow control. The reason for adjusting combustion
air flow prior to fuel flow can be found in the improved dynamics of the
process. In contrast to an increased grate speed, an increased supply of
air (in ratio to the coal supply on the travelling grate) is followed imme¬
diately by an increased heat flow, so that steam production is quick to
change.
The sub-section will be concluded by a few basic comments on the con¬
troller parameters. In this respect, one has to distinguish between constant
pressure plants and variable pressure plants. In constant pressure plants
the adjustment is unequivocal to the extent that the control parameters
(proportional band, integral action time, derivative action time) can re¬
main constant independently of boiler load. The optimum proportional
band strongly depends on the storage capacity of the boiler, but since
with constant pressure operation the capacity remains practically constant,
the proportional band can also be kept unchanged over the full load range.
As to the integral action time, although it might be advisable to effect a
re-optimization after each load change the optimum is found to be so flat
that continuous adjustments of the integral time constant are not only
not critical, but appear quite superfluous. In controlled variable-pressure
plants, however, conditions are quite different.
In these plants storage is strongly dependent on load, and this means that
the proportional band of the steam pressure controller should not be kept
constant. Its adjustment is effected by the so-called open loop adaptive
control where the feedforward signal is generally derived from the steam
flow signal or some other load proportional signal. Whether the storage
capacity increases or decreases with load depends on the design of the
boiler. Whatever the case may be, the proportional band must be adjusted
in proportion to the reverse value of the boiler storage capacity, i.e. it
should decrease with an increase in the storage, and vice versa. As to the
integral action time, the setting may be left constant over the full load
range as in constant pressure operation. Experiments with the derivative
action time have shown that the derivative action can remain independent
on load without substantially deviating from optimum.
8.2.2
83
Air Flow Control Loop
There are many types of air flow control loops, this multiplicity being
necessary due to the different modes of firing, to'"divers arrangements of
the burners, as well as to the various possibilities of air duct location and
distribution. As a result, only the most typical arrangements can be dis¬
cussed in the following text. However, the examples chosen here can be
easily used, with but minor modifications, to match practically all current
conditions. The combustion air flow controls which correspond to the fuel
controls covered in sub-section 8.2.1 will be discussed first.
Fig. 47 shows a control scheme for oil firing. The corresponding air flow
control scheme is represented on Fig. 53. The command signal for the oil
flow controller, which is the output signal of the steam pressure controller,
serves simultaneously as the command signal for the air flow controller.
Such an arrangement has the advantage that both oil and air flows are
corrected in parallel, this being the unconditional requirement for optimum
firing with a possibly constant minimum 02 content in flue gas. This
control concept should always be striven for. If its implementation proves
difficult, as in the case of separate control of individual burner levels, then
various feedforward signals at the input of the air flow controller should
be used in an attempt to achieve the best possible synchronization.
In Fig. 53, the ratio adjuster A maintains the correct ratio of oil flow to
air flow. Marked by a dotted line is a frequently needed fixed command
signal which causes a shift in the characteristic to ensure that air flow
would not drop below the minimum level even when oil flow ceases (Fig.
54). It is often claimed that if a near-stoichiometric combustion is to be
achieved, an automatic correction from the 02 content in flue gas or from
smoke density offers a substantial advantage. However, such statements
should be qualified as follows: It is essential for each individual burner to
operate under optimum combustion conditions if optimum operation of
the steam generator is to be attained. It is a proven fact that unburned
fuel particles from one burner are not normally burned by other burners.
6*
Cesser"T
etescÿi"
84
L el./ ' "b "b f"J
'
5 Boiler Control
8.2.2 Air Flow Control Loop
from steam pressure controller
to oil
controller
s
-
i
!
$
-V
4*-
Or
Fig. 53
Control scheme for combustion air in oil firing.
This means that each burner should be adjusted individually, thus ensuring
a correct oil/air ratio, a satisfactory atomisation, the simultaneous arrival
of fuel and combustion air at the burner tip (which is dynamically im¬
portant), and the fulfilment of all other necessary conditions.
longer optimal. The 02 trim is able to optimize the operation only when
the combustion process is satisfactory on all burners, and when the sam¬
pling point is so located that the sample is fully representative for the
whole area and over the whole loa4 range. Due to the flue gas stratifica¬
tion and to the danger of tratrip ait ih-leakage, this remains a difficult
problem to solve. From the point of view of process dynamics, it must
be acknowledged that the introduction of the new zirconium probes has
at least considerably shortened the time span between the change in the
air flow and the generation of the corresponding signal in the 02 meter,
i.e. improved the time behaviour of the loop. While formerly delay times
of 20—30 seconds were not rare, nowadays only the flue gas distance/
velocity lag and the measuring time constant of 1—3 seconds are to be
taken into consideration. In spite of this improvement the 02 controller
cannot be set for particularly fast action, since it is only a superimposed
trimming device. This means that it cannot be very helpful during fast
load changes where the only important aspect is the quality of the dynamic
synchronisation of the oil flow and the air flow controllers, i.e. continuous
maintenance of the proper ratio when the oil flow and the corresponding
air flow reach the burner tips, which may prove rather difficult.
To sum up, it can be stated that in oil firing an 02 controller presents but
few advantages. It can prove useful in steady state operation providing all
burners are in good working order and the 02 measurement is truely
representative. However, for 02 control during load changes it is of little
consequence. Similar considerations apply to trimming based on a smoke
density signal. Due to the many disadvantages, expenditure on the provision
of a smoke meter would be difficult to justify.
air flow
oil flow
Fig. 54
85
Characteristic air-flow/oil-flow.
It should be possible to evaluate the effectiveness of automatic oxygen
correction (trimming) on the basis of the following considerations: If, for
example, one burner fails to operate satisfactorily due to insufficient
atomisation, the 02 meter will establish that there is a deviation from set
point, and the 02 controller will attempt to correct the error. However,
such an action would not be proper with regard to the remaining burners
which, although in perfect order, would receive an air flow which is no
The structure of combustion air control with an automatic 02 correction
is shown on Fig. 55. The signal from the 02 meter (or from the smoke
density meter) is compared with the set point, and the deviation is brought
to the input of a PI controller. The output signal from this controller acts
via a multiplier on the feedforward command signal to the air flow con¬
troller. This is basically equivalent to making the action of the adjuster A
in Fig. 53 automatic. In practice, it is expedient to severely limit the in¬
fluence of this correction to some 10—15%, in order to avoid excessively
large and possibly false interventions following disturbances in the 02
correction channel.
Very low excess air firing as occurs with oil and gas, runs the increased risk
of air deficiency following control actions caused by load changes or dis-
86
8.2.2 Air Flow Control Loop
8 Boiler Control
from steam pressure controller
I
to oil
ÿ
controller
or smoke
density
Fig. 55
Control scheme for combustion air in oil firing,
with Oj correction.
turbances of air supply. To offset this the safety oriented scheme according
to Fig. 55.1 has proved commendable. Here the command signal from the
master steam pressure controller is sent to the fuel flow and air flow
controllers in parallel. The minimum and maximum selectors then ensure
that no air deficiency occurs: The minimum selector upstream of the fuel
flow controller compares the signal from the steam pressure controller
with the air flow signal, and applies the lower one as the command variable
for the fuel flow controller. On the air side, the command signal is
compared with the fuel flow signal in a maximum selector, and the higher
signal is let through. In this manner it is established that enough combus¬
tion air is available at all times. Should some disturbance on the air side
cause the air flow to the burners to diminish, then the minimum selector
would immediately cut down the fuel flow to an acceptable level.
On the other hand, should some disturbance cause an increase of the fuel
flow, the maximum selector would likewise increase the air flow. This kind
of scheme calls for the addition of an auxiliary signal to the air flow signal
in order to adjust the amount of excess air and effect the desired 02 cor¬
rection whenever the need arises (see Fig. 55.1).
Next in line for discussion is the combustion air flow control when in¬
corporated into a pulverised-coal direct-firing system (see Fig. 56). The
corresponding fuel flow control scheme as shown on Fig. 48 is particularly
suitable for the rather inert firing systems, such as are currently used in
brown coal and lignite fired plants, where frequent firing disturbances
87
occur. With coal firing, it is not possible to use the same command signal
for both fuel and air flow (in the manner suggested with oil firing), be¬
cause the feeder speed does not represent a true measure of the heat in¬
put into the combustion chamber. A reasonable substitute air flow com¬
mand signal can be devised if the following points are considered: Un¬
doubtedly, in steady state, the steam flow leaving the boiler provides an
adequate alternative for the required combustion air flow command
signal, since it is proportional to the heat input into the boiler. Unfortuna¬
tely, in transient states, the situation is not so simple. The steam flow that
is withdrawn from the boiler fully corresponds neither to the amount of
the actually produced steam, nor to the pulverised coal flow directly
entering the furnace. The first discrepancy is due to changes in the accu¬
mulation of mass and energy in the boiler, while the second may possibly
be caused by the overriding influence of the steam pressure controller.
from steam
pressure controller
~l
jJL
|Mox 1
O2 correction_ jTT
ÿ
dÿJ!@
r/n a
'
Fig. 55.1 Control scheme for oil firing.
The considerations should further include the already mentioned need for
a technologically justified extra amount of excess air at low loads.
Finally, the effect of the fluctuating feedwater temperature ds (for instance,
following a feed-heater outage) should be also taken into account. (The
two latter points will be again omitted from further discussions for reasons
of simplification.)
88
--
8 Boiler Control
£jl
f
—
pressure controller
j
—j>
I
[7]
J
—
to steam
1
I—-H
I [ÿ] | v[ÿl]
j" hf -t-L-4j
<2ÿÿ !|
k
feedwater
temperature
for feedwater temperature changes) is the only signal determining the total
combustion air flow. In transient conditions, the mass of the steam taken
in by, or released from the boiler storage, is taken into account by the
application of the signal representing the derivative of the steam pressure.
Similarly, the signal representing the derivative of the sum of the feeder
speeds compensates for the inherent inertia of the coal input devices.
1
r?
A I
89
8.2.2 Air Flow Control Loop
J
i
air flow
load disturbance
steam flow
coal flow into
tfieTurnace
-d)
°-5 xlS -
[m]
air flow
firing rate disturbance
4
0,3i
J
t(min)
change in calorific value of coal
coal flow into the furnace
• • ij r y
0
K0'' v
tlmin)
secondary air
Fig. 56
Control scheme for combustion air in pulverized coal firing.
Fig. 57
It can be proved that the total air flow command signal VL can be best
expressed by the following equation:
(13)
VL=(Kl-K4-»s).mD+K2ÿ + K3 d~~ + Ks .
at
at
This equation forms the basis of the air flow control scheme on Fig. 56.
The command signal is derived from the steam flow mD , the steam pres¬
sure P, and the sum of the feeder speeds
Under steady state conditions,
all the time derivatives are zero, so that the steam flow signal (corrected
Time behaviour of air flow for various air flow control
configurations.
Fig. 57 illustrates the behaviour of the total air flow control for a load
step change and for a step disturbance in firing (change in calorific value,
in feeder speed, etc.). Curve No. 1 represents the air flow which, as seen,
practically matches the coal flow, both for load disturbances and firing
disturbances. The result is compared with the results of two other schemes.
If correction by the derivative of the steam pressure is not made use of,
the resulting curves are denoted by 2.
90
8.2.2 Air Flow Control Loop
8 Boiler Control
The corresponding scheme is quite often applied, and it appears that the
performance is satisfactory providing fuel flow delays are not excessive,
and disturbances of the firing rate not too frequent. Should a scheme be
chosen that is similar to the one shown for oil firing on Fig. 53 and which
has been already discussed (i.e. should the primary air and speed of the
feeders be controlled in parallel by a signal from the steam pressure con¬
troller), the result would be approximated by curves No. 3. For load changes
the dynamic response appears to be quite satisfactory, but since a deviation
from the set point caused by firing disturbances remains uncorrected under
steady state conditions, the configuration appears unsuitable for coal firing.
the measuring error amounts to. If it is a question of only 1 or 2%, the
correction would probably not be justified.
Besides direct-fired systems there are also bin-storage systems where the
coal and air from the pulverisers are separated in cyclones, and the coal is
then stored in bins. In these cases the steam pressure scheme and the com¬
bustion air flow scheme are exactly the same. A special description of binstorage systems would therefore be superfluous.
The scheme on Fig. 56 is based on the assumption that a single positioning
of the trimming flaps and dampers always guarantees a correct distribution
of the secondary air flows to all burners.
The combustion air flow control includes the mill air flow control which
is also known as primary air flow control. In this kind of control the cold
'tempering' air and the hot air are mixed together, before transporting the
pulverised coal from the mills to the burners. There are two main control
tasks: Firstly, the primary air flow VLP must be kept adequately high to
ensure the transport of the pulverised fuel; secondly, the temperature i?s
in the mill classifier must be kept constant. The mill classifier temperature
is controlled by variations in the amount of the added cold air. To this
effect, the classifier temperature is measured and compared with the set
point. The system deviation is then acted upon by a PI controller which
changes the position of the cold air control damper (see Fig. 56). The
total primary air flow is controlled by another damper located downstream
of the mixing point for the hot and the cold air. The primary air flow
control scheme is somewhat dependent on the type of mills. Fig. 56 shows
common arrangement. In it the feeder speed n is the master commond
signal for the primary air flow controller. A fixed command signal (= con¬
stant bias) is often added to ensure a minimum flow of primary air. More¬
over, the primary air flow control can be sometimes overridden by a rate
signal derived from the feeder speed. The idea is to activate the mill
storage capacity when the load starts to change, so as to arrive at the new
firing rate sooner. The resulting control action gives the impression that
the inertia of the mills has been temporarily reduced, while, in fact, use
is made of the pulverised coal storage in the mill.
—
While there is only one total combustion air flow control system, a primary
air flow control must be installed for each mill.
The air flow measurements on the hot side of the air heater must be cor¬
rected for temperature variations in order to keep the measuring errors
small. Just how necessary this is depends on the change of air temperature
(in degrees) caused by a given load variation, i.e. on how many per cent
91
®
—i
— 11
LS
Fig. 58
Control scheme for combustion air in a pulverised-coal
firing system.
8 Boiler Control
8.2.2 Air Flow Control Loop
There exist, of course, more sophisticated arrangements, usually based on
automatically controlled dampers installed in secondary air ducts. These
dampers can further be applied in order to maintain the necessary carrierair pressure in the entire load range. In some plants the latter problem is
tackled by the application of primary air fans with vane control. Another
solution would be to enforce the necessary air pressure by the throttling
action of secondary air dampers. A possible variant of the latter control is
shown on Fig. 58, where, for reasons of clarity, primary air flow control
and classifier temperature control are omitted. Here the approach is si¬
milar to the one used in Fig. 56 and which has already been mentioned in
connection with total air flow control. Each secondary air flow control
damper forms part of a flow control loop which receives its command
signal from the speed of the associated feeder. This makes it possible,
should be need arise, to bias the coal mills. The air pressure PL is measured,
then compared with a constant or load dependent set point, and the dif¬
ference is used as input to a PI controller. The output signal of this con¬
troller is then used to modify (via multipliers) the command signals of the
secondary air flow controllers. Its effect disappears when pressure reaches
the set point value. In this manner, the required primary air pressure is
assured.
all cost to prevent air defficiency, which might easily occur due to the effect
of an unexact derivative signal during downward control.
92
Firing of mixed fuels is the next subject for discussion. The first point
under consideration is the firing of coal and oil, the control scheme for
which is represented by Fig. 49. Here the establishment of the right amount
of air is particularly problematic since no exact measuring signal for coal
flow is available. One possibility is to use an approach similar to the one
already discussed in connection with simple coal firing, and namely to
consider the steam flow mD as a measure for the total combustion air
flow Vql + 2 Vrl- This would lead to the control scheme shown on Fig.
59. Naturally, the command signal for the total air flow can be again
overridden, while the oil flow signal riiQ is being taken into account in the
manner shown. The correct distribution of the total air flow between the
oil and coal burners is achieved by using an independent air flow controller
for oil-air, this controller being in receipt of an exact command signal.
The signal has two components — a signal corresponding to the oil flow
rho , plus a derivative signal which causes the proper dynamic adaptation
of the air flow V(jL.
The respective derivative module is often designed as a unipolar unit, i.e.
its output varies only between zero and the maximum. The intention is at
1
from command
signal for oil
controllers
En
I
-0-
93
.
——
ÿ
I
—r— 4
?
EV,
KL
<
En
I V0L
L
g—
m—.1
nmn
Ji
Fig. 59
Control scheme for combustion air in a pulverized coal
and oil firing furnace.
Coal air flow is determined by the difference between the total air flow and
the oil air flow. Further division into primary and secondary air is again
effected, as has already been explained, by the primary air flow control.
A fundamentally different approach to combustion air flow control, which
applies to oil/gas firing, is presented on Fig. 60. As the scheme shows, the
F.D. fans keep the pressure downstream of the air heaters constant. The
pressure control loop is accompanied by air flow control loops operating
8 Boiler Control
8.2.2 Air Flow Control Loop
under command signals from the relevant fuel flow controllers, and pro¬
viding the required oil-air and gas-air flows. From the point of view of
dynamics, this arrangement is not particularly satisfactory. It has the further
disadvantage that the feeder speed is a somewhat unreliable measure for the
coal flow, causing large and lasting deviations from the desired fuel/ air ratio.
The command signals are derived from the current command signals of the
respective fuel flow controllers. This meets the basic requirement that
there should be a maximum of parallel controlling of fuel flow and air
flow. The desired excess air for the oil burners and the gas burners can be
set by the ratio adjusters Aq and AG . The primary pressure PL in the air
duct downstream of the F.D. fans is controlled to ensure that the fans
provide the total supply of air for the combustion of the individual fuels.
The measuring point is located downstream of the fans but before the
duct branches out to provide air for the combustion of the individual
fuels. (Note that, as an example, Fig. 60 shows two fans operating in
parallel, instead of only one fan shown in the other examples.) The control
keeps Pl at a constant value. The two slave P controllers that actuate the
inlet vanes of the F.D. fans receive a command signal from a master PI
controller. In order to prevent undue losses in the butterfly gates when¬
ever there is a drop in the flow, it is feasible to reduce the pressure set
point with a decrease of load. This can be attained by connecting a loadproportional signal to the input of the air pressure controller.
94
from the command signal of
the oil flow controller
95
In addition, the gas air flow controller receives a negative fixed command
signal. Naturally, this is required only if the gas flow controller likewise
receives such a signal, as was the case in the control loop on Fig. 50.
from the command signal of
the gas flow controller
Fig. 60
Control scheme for combustion air control in an oil/gas
fired furnace.
The air flow control scheme shown on Fig. 60 forms the counterpart to the
control scheme for firing a mixture of gas and oil, which is illustrated on
Fig. 50. It contains two flow control loops, one for the total oil-air flow
Vol, and the other for the total gas-air flow Vgl-
The next topic for discussion concerns the air flow control in a cyclone
furnace starting with the variant in which the 02 corrective control (02
trim) affects the fuel flow control (see Fig. 52). According to the scheme
shown on Fig. 61, the pressure of the primary air upstream of the airheater
is controlled so that a constant value PL is maintained. If required, the set
point for this control loop can be made variable with load. The secondary
air flow VlS receives the same command signal as the fuel flow, this
being possible because of the 02 trim. Blade-type regulating dampers are
used as control elements. Control aimed at optimum 02 content can
benefit from the addition of the derivative of the command signal to the
controller input, as well as from temperature-compensation of the air flow
measurement. The derivative signal is connected with a negative sign,
which means that the secondary air flow can be arbitrarily delayed so that
dynamically it fits the coal flow entering the cyclone. The control of the
primary air is performed along the same lines as has already been described.
The temperature ds is kept at a constant value by an appropriate amount
of cold air.
96
8 Boiler Control
8.2.2 Air Flow Control Loop
The primary air flow VLP is likewise kept constant but for the exception
of load changes: During the load changes the adjustment of the set point
which changes the constant control pattern, is caused by variations in the
derivative signal from the feeder speed n (which is load dependent).
secondary air flow controller (which controls the blade-type regulating
97
dampers).
command signal
n
ÿ"for cyclone 2
from the
command signal
foi fuel flow
load
load
Fig. 62
Fig. 61
Control scheme for combustion air in a cyclone furnace.
Fig. 62 shows another variant of the cyclone furnace firing. It differs from
the above discussed scheme in that direct-firing mills are used, and that
due to faster control action it is appropriate to introduce the 02 trim into
the combustion air flow control.
When the 02 content deviates from the set point, the output signal of the
trimming controller acts via a multiplier on the command signal to the
Control scheme for a cyclone furnace.
Last to be included in this sub-section dealing with air flow control is the
travelling grate stoker. This method of firing was taken out of sub-section
8.2.1 dealing with steam pressure control, for the simple reason that the
air flow control is of particular importance in maintaining steam pressure
at a pre-determined value. Concerning steam production, the dynamic
behaviour of this kind of firing is characterised by the fact that any action
confined solely to fuel flow (i.e. to the speed of the grate) causes intoler¬
able delays in the actual firing rate. If, however, the air flow is adjusted
first of all, the fire output will immediately change since there is a con¬
stant coal supply lying on the grate.
7 Klefenz
99
8 Boiler Control
8.2.3 Furnace Draught Control Loop
The corresponding control scheme is shown on Fig. 63. The steam pressure
controller signal, together with the steam flow feedforward signal, act on
the air flow controller. The grate speed n is somewhat delayed following
the air flow VL. The ratio adjuster A is used to determine the ratio of the
air flow to the grate speed, and, therefore, in the last analysis, that of coal
to air. The setting of this adjuster naturally depends on the quality of coal
and on the depth of the fuel bed on the grate. It must therefore be manu¬
ally corrected whenever these factors change. Such a mode of operation is
acceptable because grate stokers work with a substantial amount of excess
air, and exact regulating of this amount is neither possible nor needed.
References: [3] [7] [83] [92] [103] [107] [184] [186] [198] [207] [217]
[229] [232] [233] [263] [282] [283] [289] [298] [300] [301]
[315] [316]
98
P
©
Fig. 63
f
J*I
Control scheme for travelling grate stokers.
Finally, it should be mentioned that for smaller travelling grate boilers the
control scheme does not have to be as elaborate as the one on Fig. 63, and
that adequate results can be obtained with simpler arrangements. In some
cases it is even possible to dispense with the derivative action of the steam
pressure controller, or to get by without the supporting (secondary) air
flow controller.
8.2.3 Furnace Draught Control Loop
With regard to escaping gases, it is necessary, except in gas-tight welded
boilers, to maintain a moderate negative pressure (vacuum) both in the
furnace and in the flue gas ducts. This is the objective of the so-called
furnace pressure control which, strictly speaking, is suction control. An
alternative name frequently used instead of furnace pressure control is
'induced draught control' (or simply draught control) which is derived
from the controlling element being the induced draught fan (I.D. fan).
Draught control is not necessary in boilers with membrane-wall furnaces,
since such boilers can be operated under positive pressure. There is no
danger of the flue gas escaping into the boiler house.
In general, the control can be built in a very simple manner. A PI control¬
ler with disturbance variable feedforward (which mostly uses a signal
from the air flow controlling element) in most cases offers a satisfactory
solution. To illustrate this, Fig. 64 shows a furnace pressure control loop
using an I.D. fan with vane control. A signal corresponding to the furnace
pressure Pp is brought to a PI controller that adjusts the fan vanes in de¬
pendence on the deviation of the pressure signal from the set point. The
feedforward disturbance-variable signal is used directly (= proportional
action), and is derived from the position Hof the control vanes of the
forced draught (F.D.) fan. A signal from an air-flow meter is also frequent¬
ly used to serve as an alternative feedforward disturbance signal. However,
it has become apparent that this signal comes too late, due to the delay
in the measuring instrument. Better success, i.e. a more exact maintenance
of the furnace draught, can be achieved if the I.D. fan vanes are propor¬
tionally adjusted in parallel with the F.D. fan vanes changing position. In
order to arrive at the best possible parallel adjustment of the two sets of
fans, it is necessary to make certain that the maximum possible speed with
which the I.D. fan inlet vanes move, is never lower than that for the F.D.
fan inlet vanes. Otherwise, large pressure deviations become unavoidable
for purely theoretical reasons.
100
8 Boiler Control
8.2.4 Steam Temperature Control Loop
—<p—
<D
J
5"
Fig. 64
Control scheme for furnace draught control.
Large boilers usually have two I.D. fans, and their control loop can be
structured similarly to the loop shown on Fig. 64. A superimposed master
controller commanding two positioners is used.
Certain plants are equipped with I.D. fans with speed control. However,
due to the large rotating masses and the resulting inertia, this type of
control cannot be recommended. A limited improvement is possible by
using speed control in combination with flue gas swivel damper adjustment.
In this case, the dampers are positioned first (fast action), and then con¬
fined within a favourable control range by the gradual adjustment of the
speed of the L.D. fans (delayed action).
As regards the overall temperature characteristic of a boiler, the relative
proportions of radiant and convective superheater surfaces are normally
designed to produce an increased heat flux and a rising level of the final
outlet steam temperature with increasing boiler load. It follows that one
possibility of keeping the outlet steam temperature constant is the use of
a more or less intensive cooling (Fig. 65). In this respect, it is not necessary
to differentiate between drum and Benson boilers. Although in a Benson
boiler it is possible to use feedwater to affect the outlet steam temperature
by shifting the end point of evaporation, the method cannot be effectively
applied for any fast correction of disturbances. The dynamics of the con¬
trolled system are not favourable for such an action. The solution rests in
applying the same method for a Benson boiler as is used for drum boilers,
and namely that of effecting cooling between individual superheater
sections. Naturally, the feedwater flow in a Benson boiler is also used for
the purpose of adjusting the outlet steam temperature. However, as will
be explained in the following sub-section, the action of the feedwater flow
must necessarily be very slow-acting in order to contain the temperature
within the control range.
The common method consists of dividing the superheater into a number
of stages relative to the size of the unit, and to install interstage attemperators (i.e. coolers). Depending on the size of the boiler and the required
quality of control, up to three desuperheaters may be arranged in series.
In the absolute majority of boilers the cooling is done by injecting feedwater directly into the steam. The off-take point for the attemperation
water should, whenever possible, be downstream of the feedwater control
valve. This positioning is helpful because it causes the load-dependent
pressure drop accross the boiler to become the driving force for the attem¬
peration water. If, for example, the load should increase, more attempe¬
ration water will be provided even without the intervention of control.
References: [3j [71 [83] [92] [106] [196] [208] [221] [249] [264] [279]
[291] [298] [312] [313] [317]
i3a . . outlet temperature
cooling
without control
ds . . temperature set point
8.2.4 Steam Temperature Control Loop
100% boiler load
The principal objective of live steam temperature control consists of
maintaining constant steam temperature at the boiler outlet.
101
Fig. 65
Temperature characteristic of a drum boiler, i.e. of a boiler
with a constant evaporation end point.
--
8 Boiler Control
102
- - ----
It is evident that the above measure supports control because it is in
agreement with the already mentioned characteristic (Fig. 65).
-tjx-
©
fuel flow
4
Ep [°]
ÿ
n-
Fig. 66
f
—ohl—
boiler lo
Control scheme for steam temperature control.
Fig. 66 shows a typical steam temperature control loop with attemperation. The controlled variable is the superheater outlet temperature i?a,
while the superheater inlet temperature i?e serves as a secondary (auxiliary)
variable. The secondary control loop is necessary for the correction of
temperature disturbances originating in superheaters located upstream of
the measuring point for #e. The controlled system in this loop has, in
comparison to the controlled system in the primary (main) loop, a very
favourable dynamic behaviour. The disturbances are largely corrected, and
consequently do not enter the final superheater.
Incorporation of a feedforward disturbance compensation signal into the
scheme may prove an advantage for the following reason: It often occurs
that during a load rise the boiler is strongly overfired for the purpose of
keeping the steam pressure within a relatively narrow range (see sub¬
section 8.2.1). The result is a severe heating disturbance which affects the
superheater, and this disturbance can be effectively counteracted by the
mentioned disturbance compensation.
8.2.4 Steam Temperature Control Loop
103
To this effect, a signal proportional to the fuel flow, is brought via a dervative (D) unit to the input of the secondary controller. Fig. 66 also shows
the application of a second auxiliary signal, the boiler load signal, which
should perform the following function : The set point for the temperature
downstream of the cooler, i?e, should vary in agreement with the tempe¬
rature characteristic of the superheater. This means that should the
heating-up process intensify with rising load, the set point for the super¬
heater inlet temperature i?e would have to decrease as a function of load,
in order to keep the steam outlet temperature $a constant. Generally,
these set point changes can be handled by the master PI controller. How¬
ever, the process can be effectively speeded up if the set point variations
are taken up by the mentioned load proportional signal.
In the cascade control loop shown on Fig. 66, the secondary controller
is a proportional controller, while the master controller has proportional
and integral action. This is a well proven arrangement which combines
good stability and control quality with a reasonable outlay on instrumen¬
tation. It is not necessary to equip the master controller with differen¬
tial action, since due to the inertia of the controlled process the improve¬
ment in control quality would not be particularly impressive. The often
used PI/PI cascade is, with regard to control quality, practically equivalent
to the P/PI cascade. In the former case, however, there exists the danger
of inadequate stability due to the two integral elements arranged in
series.
Triple-cascade arrangements were tried out, the additional auxiliary
variable being the temperature measured in the middle of the superheater.
It turned out that the attainable minor improvements did not justify the
extra expense. Only in one case has such application been found signifi¬
cant, namely when the superheater is divided into a radiation and a con¬
vection section. Since the radiation superheater strongly reacts to heating
changes, the introduction of an additional auxiliary variable could prove
successful.
For this very reason boiler designers are advised never to implement a
radiant superheater as the last superheater in line. The introduction of a
further temperature sensor cannot, of course, be considered an excuse for
leaving out the thermometer downstream of the first attemperator. As
has already been demonstrated, the latter is necessary to compensate, via
an auxiliary signal, for the disturbances originating in the primary super¬
heater.
104
8 Boiler Control
By the use of efficient digital computers, which is possible nowadays,
algorithms of modern control theory can be applied. Presently, state con¬
trollers are tested on temperature controlled system in practical operation.
Since the individual states, these are steam temperatures along the super¬
heater pipes, are not measurable (high cost), a so-called observer is used.
The observer is nothing else than a model of a superheater where the states
are continuously adapted to the actual states by feedback. The control
results having obtained to this date are very promising, so that possibly
in the near future larger superheaters having the same control quality can
be built. This would mean a substantial cost reduction on the part of the
boiler construction.
The following is important with regard to the variation of the controller
parameters: In the secondary loop the problem is basically one of taking
into account the blend of the various contributions. Accordingly, the
system dimensional gain, expressed as the ratio of the temperature t?e to
the lift of the control valve, is load dependent, i.e. with increasing load
the gain diminishes. Strictly speaking, this would require an increase in the
controller gain with load. However, there are two reasons why this require¬
ment can be disregarded. Firstly, the dynamics of the auxiliary loop are
very favourable, so that the closed loop gain and therewith the quality of
control can be pushed very high. Secondly, as has already been mentioned,
with the attemperation water pipe properly positioned downstream of
the feedwater control valve, the injection pressure is proportional to the
pressure drop in the superheater, thus increasing with boiler load. This
produces an automatic disturbance feedforward action from the steam
output of the boiler, which by-passes the controller and acts directly by
means of the control valve.
In the primary control loop, the controlled system (with the superheater
inlet temperature as the input variable, and the outlet temperature as the
output variable) has a constant gain, and a virtually load-independent
ratio of effective dead time to build-up time. It follows that the controller
gain must likewise be constant over the entire load range. However, the
integral component of the controller action behaves quite differently.
Since the effective dead time decreases proportionally with an increase in
the steam flow, this being an inversely proportional relationship, it is in
the interest of optimisation to reduce the integral action time with rising
boiler load. Of course, since the optimum is rather flat, it is possible to get
away with a constant integral action time in the load range of 50— 100%.
Only if the boiler were to operate under automatic control at still lower
8.2.4 Steam Temperature Control Loop
105
loads, it would be recommended to make the integral action time auto¬
matically dependent on load. Such an approach is characteristic for
adaptive system.
Fig. 67 illustrates a steam temperature control scheme where, for the
cooling of steam, a heat exchanger is used instead of a spray attemperator.
Since in both cases problems are identical, the control structures appear
much the same. There is, however, the difference of the time response of
the inner loop being less favourable in the latter case, due to the inertia
of the heat exchanger.
In dram boilers, a frequent variation of the above approach consists in the
heat exchanger being located in the drum. In this case, a part of the steam
flow is led through a coil condenser installed in the drum, and there it is
cooled by the water/ steam mixture that the drum contains.
ÿ—
©
fuel flow
Oj] [°]
l_
—
—6-ÿ
boiler load
HZH
Fig. 67
Control scheme of steam temperature control.
Attention has already been drawn to the fact that, for the sake of good
steam temperature control in large boilers, it may prove necessary to
divide the superheater into several stages, in order to create two or three
dynamically favourable control loops. When a boiler has two parallel
paths, then it is, of course, necessary to install the mentioned two or
three control loops in series in each path. This means that a steam gene-
8 Boiler Control
8.2.4 Steam Temperature Control Loop
rator may have six or more live steam temperature control loops. The
arrangement of the loops in series leads to problems. A particularly im¬
portant point is to have all controllers operating in proper control range.
In order to retain the second attemperation spray water flow, mE2 > within
the control range during a rise in boiler load, it is necessary to reduce the
set point for the steam temperature i7al upstream of the second attempera¬
tion. From the static point of view, the variation of the spray water flow
mE2 with load is kept under control by the strength of the set point
adjusting signal which is a steam flow proportional signal acting at the in¬
put of the 1st attemperation controller. In forced circulation boilers the
general objective is to maintain a constant ratio of spray water flow to
feedwater flow. This implies a linear increase of the spray water flow with
steam flow, i.e. the temperature difference across the attemperator should
remain approximately constant, which requires the temperature i?ai to be
lowered in parallel with #e2
106
For this two distinct solutions are possible. Either the set points of the
controllers are marshalled by command signals so as to correspond to the
static characteristics of the individual superheaters, or all loops are brought
together to form a multiple cascade in which each control loop provides
the set point for the preceding loop. The two principles will be explained
with the help of Figures 68 and 69. Fig. 68 shows the variant with the
variable set points. Each loop is built up along the already discussed lines.
The final superheater is, as can be seen from the temperature diagram, a
convective superheater, i.e. the heat flux increases with load.
107
ÿ
Should another attemperation be installed upstream in series, the require¬
ments would be similar to those discussed above.
fuel flow
boiler load
1 00% boiler load
boiler load
boiler load
Besides the variations presented in Figures 68 and 69, there are, of course,
other methods of maintaining spray water flows within the control range.
100 % boiler load
Fig. 68
Another solution to the problem is presented on Fig. 69. The final spray
is kept within the control range by maintaining a constant temperature
difference ($al — i?e2) across the attemperator. To this effect, the con¬
troller for the temperature t?aI receives a command signal consisting of
the command signal for the temperature i?e2 together with a constant
value signal. Should, for instance, the boiler outlet temperature #a2 in¬
crease above the set point, the controller would lower the temperature
i?e2. The current desired temperature difference At? = t?al — t?e2 can be
adjusted by manipulating the already mentioned constant value. Should
the boiler be equipped with another attemperation, the described arrange¬
ment could be accordingly expanded. In Benson boilers the command
signal for the temperature downstream of the first attemperator, i?eJ ,
serves a second purpose, namely that of acting as correcting signal for
feedwater control, as will be explained in the next sub-section.
Control scheme for steam temperature control with two spray
attemperators in series.
One of them is to measure the temperature difference across the attem¬
perator, and then apply it as the controlled variable. In this case, a follow
up controller is used. Another possibility is to control the position of the
attemperation control valve by a control loop located immediately up¬
stream of the valve ;its set point can be either constant or variable.
The basic difference between the various control schemes can be summed
up as follows: While the arrangements corresponding to Fig. 69 are very
108
8 Boiler Control
8.2.5 Feedwater Control Loop
advantageous from the static point of view (the spray flows are always in
control range regardless of the superheater characteristics and the fire
situation), they may cause difficulties from the dynamic point of view.
This is in the nature of cascade loops where the primary loop necessarily
reacts more slowly than the secondary loop.
109
8.2.5 Feedwater Control Loop
In contrast to the control loops discussed so far, feedwater control varies
depending on the type of boiler with which it is used. A drum boiler re¬
quires a different feedwater control scheme from a Benson boiler which
again differs in this respect from a Sulzer boiler. The term 'feedwater
control' is not quite correct, but will be retained in this book because of
its general use. The feedwater flow is actually only the manipulated
variable for the drum level control in a drum boiler, for the attemperationwater/feedwater ratio control in a Benson boiler, etc.
Let us first consider the drum boiler. The amount of water in the drum
offers a perfect measure for the supplied feedwater flow. This is the reason
for the introduction of drum level control which can be found in three
basic variants. The simplest kind is the so-called one-element control shown
on Fig. 70.
PI
to further
controllers
Fig. 69
Control scheme for steam temperature control with two
or more spray attemperators connected in series.
This means that with long chains of control loops it may not be possible
to adjust such optimum settings as would be achievable if the superheater
stages were controlled individually. In contrast, however, the above con¬
siderations do not apply to arrangements which are based on Fig. 68 where
each temperature control loop can be dynamically optimized.
References: [3] [7] [38] [83] [84] [85] [92] [105] [189] [201] [217]
[219] [220] [262] [288] [304] [319]
Fig. 70
Control scheme for feedwater control in a drum boiler
(one-element control).
A signal corresponding to the level L is compared to the set point, and the
difference is brought to the input of a PI controller. This controller reduces
the control deviation by positioning the feedwater control valve.
This being the simplest kind of level control, it is particularly suitable for
small boiler units because of its low price, as well as for plants with only
minor disturbances (load changes) and for plants that have no exacting
demands on control quality.
110
8.2.5 Feedwater Control Loop
8 Boiler Control
111
„v.j
The last case had to be specifically mentioned because the time behaviour
of the controlled level system can be, on occasions, rather unfavourable.
Thus, for example, an increased infliix of cold water into the drum causes
condensation of steam bubbles in the drum water, and this may consider¬
ably delay the final effect of the change in supply on the drum level. L W
There are times when control action must even take into account the
possibility of a tranlitory change in the direction of the movement of the
drum water level. Such a change occurs, for instance, following an increase
in the feedwater flow, when the level at first actually drops due to thÿ,..,
mentioned cooling ('shrinkage'), and starts rising only afterwards. The
same effect takes place when the load is reduced because the drum pres¬
sure momentarily increases. On the other hand, when the demand for
steam increases due to a rise in loading, the increased steam flow causes
a fall in pressure which, in turn, leads to the expansion of the submerged
steam volume in the drum and in the risers. The water swells, and the
drum water level actually momentarily rises ('swell). As a result, the drum
level signal causes an initial reduction of feedwater flow, and this cannot
be the desired action. It is obvious that control could be improved by the
introduction of a feedforward disturbance signal from the steam flow.
Such a solution is shown on Fig. 71. It implements the so-called two-ele¬
ment control which differs from one-element control in that the feedwater control valve receives a signal from the steam flow, and this leads to
a proportional anticipatory action. As the steam flow increases, the valve
opens even further, and vice versa. However, the scheme is seldom used,
because a much better one differing only very slightly, offers itself in the
form of the three-element control (see Fig. 72).
Fig. 72
Control scheme for feedwater control in a drum boiler
(three-element control).
The feedwater flow measurement is generally available, and from it a con¬
trol signal can be derived without incurring additional cost. The applica¬
tion of this feedwater flow signal mg thus offers the possibility of cor¬
rectly controlling the amount of feedwater during load changes, i.e.
during disturbances of the steam flow. For instance, should the steam
flow increase by 10%, the signal comparison at the input of the controller
would also immediately increase the feedwater flow by 10%. In contrast
to two-element control, this happens independently on the valve characte¬
ristic. Because the fine matching of the drum level to the set point cannot
be guaranteed solely on the basis of equality of the steam flow and the
feedwater flow, the drum level deviation is also applied to the input of
the PI controller. It follows that the control loop remains in steady state
only when in addition to the steam flow being equal to the feedwater
flow, there is no level control deviation.
The disadvantage of such an arrangement is that measurement errors in the
steam flow and feedwater flow determination produce a constant level
displacement. Consequently, if a shift from the set point (caused, for in¬
stance, by non-standard steam flow measurement) cannot be tolerated, a
slightly modified scheme according to Fig. 73 would be preferable.
Fig. 71
Control scheme for feedwater control in a drum boiler
(two-element control).
In this arrangement the level L is always kept at the set point regardless
of the disturbances. The steam flow signal mD becomes the variable set
point of the secondary controller for feedwater flow mg- This set point
is further trimmed by the output signal of the superimposed level con¬
troller which corrects all the inconsistencies in the steam and the feedwater flow signals.
8 Boiler Control
8.2.5 Feedwater Control Loop
Next for discussion is the feedwater flow control in a Benson boiler. The
signal that Benson boilers lack is the basic signal which is used in drum
boilers as a measure of the correct feedwater flow and of the proper
amount of feedwater in the boiler, i.e. the drum level signal. In replace¬
ment, the ratio of the attemperation water flow to the feedwater flow is
used.
5% of the feedwater flow missing. Thus, in steady state the attemperation
water flow must equal 5% of the feedwater flow. On the whole, the arran¬
gement gives satisfactory results, even though it still leaves much to be
112
113
desired as regards process dynamics. Some of the deficiencies can be elim¬
inated by installing additional features (see Fig. 75) which consist of three
rate signals, derived from the steam flow, from the temperature down¬
stream of the evaporator, and from the fuel flow.
Control scheme for feedwater control in a drum boiler
(three-element control).
As has already been explained, it is possible, from the static point of view,
to control the steam temperature by means of feedwater flow. However,
in order to obtain dynamically favourable control results, it is further
necessary to introduce spray attemperation control. Thus attemperation
becomes the main method for controlling steam temperature, while con¬
trol of the feedwater input is used only for maintaining the attemperation
water flow within the control range. This can be achived by using as the
controlled variable for feedwater control the ratio of attemperation water
flow to feedwater flow.
A very simple approach is shown on Fig. 74. A feedwater flow controller
receives a command signal from the steam flow. The signal is not applied
fully (100%) but is reduced by a fraction corresponding to the attempe¬
ration water flow. Therefore, if only 95% of the feedwater flow signal
is permitted to pass through by the ratio adjuster A, then there is always
ÿ
Fig. 74
=i
Control scheme of feedwater control in a Benson boiler.
The first signal makes it possible to override the feedwater flow signal
during load changes and thus to counteract the tendency of the evapora¬
tion end point to wander. The primary function of the temperature signal
from downstream of the evaporator is to promptly reflect all changes in
the fire, and just as expeditiously to adjust the feedwater flow. The signal
8 Klefenz
114
8 Boiler Control
contributes to the stabilization of the feedwater flow control if it is lo¬
cated downstream of, and possibly close to, the evaporation end point,
this being a dynamically favourable location. Unfortunately, a dynamical¬
ly favourable temperature signal of this kind is frequently not available
(planned location may not be suitable). In such a case, pre-control of
feedwater flow following a change of fire can be taken over by a signal
derived from the fuel flow. This means that the three rate signals indicated
on Fig. 75 are mutually complementary. Usually only after commissioning
of the steam generator can it be established which of the three signals
should be the dominant one, and to what extent, if any, the remaining
two signals are to be brought in for support. Should, for instance, the
temperature signal prove to be dynamically unfavourable, it could be
completely rejected by the commissioning engineer, and replaced (for precontrol during fire changes) by the derivative of the fuel flow signal.
—
— -ED
|
Fig. 75
8.2.5 Feedwater Control Loop
115
flow. Generally, the measurement of the feedwater flow causes no diffi¬
culties. However, the steam flow measurement may require a correction
for pressure, which is, of course, a must in variable pressure units.
In practice the frequently used control schemes are those in which the
ratio of the attemperation water flow to feedwater flow is directly
measured, and the measurement is used for the correction of the ratio
of steam flow to feedwater flow.
Fig. 76
Control scheme for feedwater flow control in a Benson boiler.
1
Control scheme of feedwater control in a Benson boiler.
With this kind of control diagram it is always understood that the feed-
water flow is measured downstream of the branching-off point for the
attemperation flow.
It is in the nature of such a scheme that the ratio of the attemperation
water flow to the feedwater flow, as maintained by control, depends on
the accuracy of the measurement of the steam flow and the feedwater
The basic lay-out is illustrated by Fig. 76. As to the optimization of the
correcting PI controller, it should be mentioned that due to the unfa¬
vourable time behaviour of the controlled system (i.e. from the adjust¬
ment of the feedwater flow to its effect, via temperature control, on the
attemperation flow) both the proportional band and the integral action
time must be set very high. This causes the control to act as an integral
controller with a large integral time constant.
It follows that the controller can maintain the precise ratio mÿ/rhs only
in steady state. No assistance can be expected in transient states, such as
would prevent, for example, the evaporation end point from temporarily
8*
8 Boiler Control
8.2.5 Feedwater Control Loop
wandering in the wrong direction. Under certain circumstances, there may
even be drawbacks caused by the fact that the correcting controller inte¬
grates all temporary deviations from the set point. Some of these deviations
are indispensable and their correction could lead to unsatisfactory adjust¬
ment of the feedwater flow. For example, some temperature control re¬
quires that during a load increase the ratio mE/ms temporarily lies above
the set point. This the correcting controller registers as a fault, and
(erroneously) adjusts the ratio of the steam flow to the feedwater flow.
This incorrect action must later be cancelled, thus leading to further
disturbances of the balance between water and fire.
within the control range by control action on the preceding attempera¬
tion spray, which maintained a constant temperature difference across
the final attemperator. This cascade structure can be extended up to the
feedwater flow level, i.e. the feedwater flow can be used to maintain a
constant temperature difference across the first attemperator. This is
shown on Fig. 77, the chosen example being a boiler with only one spray
cooler. Initially, the feedwater flow controller receives a feedforward
signal from load. This signal can be derived either from the steam flow, or
from the electrical power, or from the power set point. The ratio of the
load signal to the feedwater flow signal is corrected in a multiplier by a
signal from a PI temperature difference controller. The respective tempe¬
rature difference is established from the measured temperature #al up¬
stream of the attemperator and the set point for the temperature i?e2 down¬
stream of the attemperator. In order to stabilize this rather inert control
loop, the same approach as before is used — the temperature t?el or the
enthalpy of the steam downstream of the evaporator becomes the auxil¬
iary variable.
116
9.2
~xr~
3»2
pi i
1
—©
A3
[jo
-f
$
—
Fig. 77
no—&•—[*>—
Control scheme of feedwater control in a Benson boiler.
A further scheme for feedwater control is presented on Fig. 77. It repre¬
sents an evolution from the scheme for steam temperature control shown
on Fig. 69. In the latter scheme, the final attemperation spray was held
117
In the schemes so far discussed it was the feedwater valve that played the
role of the controlling element. With large boiler units, however, the trend
is to avoid a significant pressure drop across the feedwater control valve by
using one or more feedwater pumps with speed regulation for control. In
principle, the same control schemes are possible. Generally, both the feedwater control valve and the speed-controlled pumps are installed. Fig. 78
illustrates the control of a boiler with two feedwater systems. Each
system has its own feedwater flow control assembled according to one of
the already discussed schemes. In order to keep a low throttling loss across
the valves, the speed of the feed pumps is adjusted in a way that would
allow one of the valves to remain practically fully open. The residual
throttling is needed to give the possibility of a fast increase of feedwater
flow by fully opening both valves. In the control scheme shown, this task
is solved in the following manner: The lift Hof both valves is measured,
and the higher one is chosen by a maximum selector. The selected signal
is then compared with the set point, and the difference is applied to the
feed-pump controller.
In the case of a deviation from set point, the speed of the pumps is ad¬
justed by the action of the secondary P controller. The arrangement on
Fig. 78, which applies to two electrical pumps, can easily be extended to
three or more electrical pumps as well as to turbine driven pumps.
118
8.2.5 Feedwater Control Loop
8 Boiler Control
iÿVT+l
119
E2
P( 1)
(+)
-.1
I
Max
maximum selector
J
Fig. 78
Scheme for control of feedwater pumps.
One variant of the above pump control consists of using signals derived
from the pressure drop across the valves instead of signals derived from
the valve positions. Of course, in the latter case the selector unit must
choose and pass-on the lower of the two differential pressure signals. In
this manner a minimum pressure difference will be maintained across one
of the valves. Finally, it should be noted that both secondary controllers
shown in Fig. 78 could also be replaced by two Pi-acting flow controllers
for the two partial flows discharged by the pumps.
A fundamentally different structure of feedwater control based on variable
speed pumps is shown on Fig. 79. The actual feedwater control operates
as already described above; the control signal acts on the controllable
hydraulic couplings of the pumps (or on the inlet valves if turbopumps are
involved), and the distribution of the feedwater flow into the individual
systems is regulated by the so-called trimming or biasing control.
Fig. 79
Scheme for feedwater control with speed controlled feed pumps.
The trimming control keeps one of the feedwater control valves fully open
at all times. End position contacts are provided for the possibility of a
change-over. The secondary controller of the cascade ensures that a change
of feedwater flow in one system is simulteneously accompanied by a
corresponding change in the other.
With the position of the switch corresponding to that indicated in Fig. 79,
the control valve in system 1 tends to open in parallel with an increase of
the water flow mS2. This arrangement of the feedwater control circuit
plays an important part in avoiding instability on the feedwater side. Con-
120
8 Boiler Control
8.2.5 Feedwater Control Loop
trol systems without this feature have often been observed to undergo
swinging of the two systems in opposite directions, i.e. with the total feedwater flow remaining constant, the water flows rh$l and
2 were
swinging in reverse. The primary controller ensures that the attemperation
water flows in both systems are equal by biasing the feedwater flows. For
instance, when the switch is in the indicated position, rhsi will increase
with a simultaneous decrease in rhs2 whenever the spray water flow mE1
increases due to the shifting of the fire. It is recommended to give the
superimposed controller only P action, since in the interest of the desired
approximate equality of the attemperation-water/ feedwater ratios, the
attemperation water flows should not be equal. The alternative polarity
indicated in Fig. 79 should make it clear that polarity changes depend on
which feedwater valve is to be activated. Should the left-hand side valve be
acted upon (corresponding to the indicated position of the switch), the
un-bracketed polarity signs should be used; the reverse applies for the
right-hand side valve. This mode of operation may appear rather compli¬
cated at first, but is quite easy to implement with the use of a switching
controller (a three-position controller). The polarity reversal can then be
performed at the controller outlet where valve motors are actuated. A so¬
lution with a continuous controller is also possible: Connected to the
output of a PI controller would be two positioners acting in opposite di¬
rections, and operating in sequence so that one valve would start to close
only when the other is fully open, and vice versa.
In a further variant, the control of temperature downstream of the eva¬
porator replaces the control which maintains the attemperation water
flows in the two systems equal. Naturally, a point must be chosen for the
temperature measurement where it is certain that the steam is always
Fig. 80
Scheme for low-load and start-up feedwater control
in a Benson boiler.
slightly superheated.
Let us now consider the low-load operation arrangement in a Benson boiler.
With the lowering of load in a once- through boiler the danger exists that
the required flow situation in the evaporator (i.e. the approximately ba¬
lanced admission flows in parallel tubes) cannot be guaranteed. It is there¬
fore necessary to maintain a certain minimum water flow (approx. 30%)
through the evaporator, regardless of the currently withdrawn steam flow.
The corresponding control scheme for such an operation, which is also
applied during start-ups, is shown on Fig. 80. To separate water and steam
from the mixture leaving the evaporator a vessel is inserted at its outlet.
The separated water is again returned into the feedwater flow at a point
upstream of the economiser. This is effected via a recirculation pump and
a recirculation control valve. Such an arrangement enables more water to
flow through the evaporator than is fed to the boiler. In the actual scheme,
the level L in the separator is controlled by the recirculation control valve.
Here importance is attached to the application of the feedforward distur¬
bance signal from load, mD, since due to the limited volume of the sepa¬
rator it is not that easy to control the level. Further, there may be stabi¬
lity problems originating in the plant; these will be discussed in sub¬
section 8.3.3. They can cause a relatively sluggish level control, in the
8 Boiler Control
8.2.5 Feedwater Control Loop
course of which the application of the feedforward steam flow disturbance
signal generally proves helpful. The polarity of this disturbance signal must,
of course, be such that recirculation would diminish with an increase in
load. The pre-set minimum flow through the evaporator must be main¬
tained. To this end a maximum selector effects a comparison of the
command variable for the feedwater flow controller with the set point
for the minimum feedwater flow. Should the command variable drop
below the minimum set point, the feedwater flow controller would pro¬
vide a constant feedwater flow corresponding to nismjn- The separator is
equipped with an additional drain for dealing with a sudden swell of water.
The P acting controller has therefore only a limiting function. If the level
increases beyond a specified maximum value, the drain valve begins to
open. This prevents water from entering the superheater.
The final topic of this sub-section is the feedwater flow in a Sulzer boiler.
Due to the presence of the water separator and the resulting establishment
of the evaporation end point, it is possible, as in a drum boiler, to find
simple and, at that, dynamically favourable control signals for feedwater
flow control. The preferable desired value would be the steam moisture
at the outlet of the evaporator.
122
F&
123
A3
In Fig. 80 the controlling element for feedwater flow is marked as a valve.
This stands also for all other possibilities of influencing feedwater flow,
such as the use of a low load control valve, or of controllable feed pumps.
To complete the description of control in Benson boilers, a brief mention
should be made of the so-called auxiliary heating surface. As can be seen
from Fig. 81, the term denotes a tube coil located in the furnace, through
which passes a limited amount of feedwater.
This partial flow is taken of the main stream with the help of a throttling
device (marked as a valve) with a very low pressure loss.
It was presumed that in this arrangement the measured temperature diffe¬
rence A# would provide a signal representing a reliable measure for the
heat released in the furnace. It was judged that a suitable construction
would provide a dynamically favourable response to the fire and feedwater
changes, and that the feedwater flow in a Benson boiler could then be con¬
trolled with such a signal. Unfortunately, with only a few exceptions,
practical experience has proved contrary. The variable Ad has seldom been
a useful measure for heating, since the results become falsified by the
dirtying-up, fire shifting, evaporation, and such like. Dynamics likewise
leave much to be desired. In the few cases when the Ad signal was actually
applied, it was mostly only its time derivative form that was used for anti¬
cipatory action. In modem power plants the auxiliary heating surface has
consequently disappeared.
Fig. 81
Auxiliary heating surface.
Unfortunately, so far no method has been found for directly measuring
the steam moisture content in actual plants, and indirect measurements
must be used. There are two possibilities in a Sulzer boiler. The first
variant uses the temperature at the separator inlet; this is the so-called
'multiple-thermostat method' or 'evaporator pilot tubes method'. The
second variant uses the level of water in the separator.
In the original method the controlled variable used is the temperature of
the slightly superheated steam in one of the parallel evaporator tubes. To
this effect, the flow through the relevant tube is lowered by throttling on
the inlet side. The resulting degree of superheating then serves as a useful
measure for the heat absorbed by the evaporator, i.e. of the ratio of com¬
bustion intensity to feedwater flow. Therefore, the respective temperature
serves as the controlled variable signal. This control scheme is shown on
Fig. 82.
8 Boiler Control
124
8.2.5 Feedwater Control Loop
125
to increase the pilot tube temperature with rising load. This is the reason
why the set point is not determined by a fixed command signal, but made
variable by the application of the steam flow signal. In addition, it is neces¬
sary to undertake measures which will ensure stability over the whole range.
Since the gain of the controlled system is strongly load dependent (decreases
with increasing boiler load), it follows that the controller gain must likewise
maximum
selector
be adjusted in dependence on load. In Fig. 82 the finely dotted line leading
to the temperature controller suggests that the controller gain must increase
with load.
A proportionally acting level controller is installed to take care of the dis¬
charge of the residual moisture segregated in the separator. In the case of
a serious disturbance of the fire/water equilibrium in the boiler, a large
amount of water can separate, giving rise to an overflow. A second discharge
controller (not shown in Fig. 82) is installed to deal with such possibility,
and it activates a large discharge valve; its set point lies above the set point
of the level controller that is normally in operation.
Fig. 82
Scheme for feedwater flow control in a Sulzer boiler.
In practice, not one but several tubes are equipped with temperature sen¬
sors. This has the advantage that during normal operation the throttled
tube can be replaced by another one. This arrangement proves likewise
expedient if, under certain circumstances, a shifting of the fire causes one
of the throttled tubes to receive too little heat while another one is
overheated.
is chosen by a
Consequently, if the maximum guide-line temperature
maximum selector, a reliable controlled variable signal is available. This
signal is compared with the set point, and the deviation is fed into a PI
controller. This controller, in turn, modifies the set point of the feedwater
flow controller so that the deviation is eliminated. The flow controller
further receives a disturbance signal derived from the steam flow mD ,
which instantly and perfectly adjusts the feedwater flow during load
changes. In order to keep the residual moisture constant, it is necessary
A further variant, predominant in modern plants, is shown on Fig. 83.
In this case, the measure for the fire /water equilibrium in the boiler is the
level L in the separator. A deviation of this level from the set point would
accordingly change the set point of the feedwater flow controller, just as
in the above mentioned variant.
Anticipatory action is again provided by the disturbance variable mD. As
has already been explained in section 8.2, it is necessary to raise the level
whenever load increases, in order to achieve, with the help of a propor¬
tionally acting discharge controller, a blow-down flow that would likewise
rise with increasing load.
The equation (12) has already proven that in order to achieve a constant
moisture content, the relationship between the steam flow and the blowdown flow must be kept constant. Therefore, a signal proportional to the
steam flow is applied to the level controller to ensure the continuous ad¬
justment of the set point.
If required, the two schemes shown on Figures 82 and 83 can be combined.
In the resulting cascade the feedwater flow controller receives the command
signal from the pilot tube temperature controller which, in turn, obtains
its set point from the superimposed level controller.
8 Boiler Control
126
8.2.5 Feedwater Control Loop
127
it adapts itself freely to pump characteristics and relevant pressure drops.
The system is so designed that circulation amounts to approximately
130 to 150% of full load flow, and is virtually independent of boiler load.
n
*-S normal
S normal
Fig. 83
Scheme for feedwater flow control in a Sulzer boiler.
One of the latest types of boilers is one that fits somewhere between the
once-through forced-flow boiler and the forced circulation flow boiler. It
is, in fact, a once- through forced-flow boiler with superimposed circulation.
The main reason for the development of this type of boiler can be found
in the continuously increasing difficulty of maintaining the stability of
water flow distribution in the parallel tubes of both the economiser and
the evaporator. To find a solution to this problem has become more acute
with operation shifting towards increasingly low partial loads, with the
wide application of the variable-pressure start-up, and with the increasing
use of welded furnaces carrying the implied arrangement of tubes. All
this suggests an artificial increase of flow through the furnace. Considering
this problem it is necessary to distinguish between boilers in which the
increase is required only for the low load range, and those in which the
requirement applies up to full load. One possible scheme designed for
low load operation is shown on Fig. 80. Another scheme which assumes
circulation throughout the entire load range, is presented on Fig. 83.1.
The circulation water flow is reintroduced into the main stream beyond
the economiser. The flow through the evaporator is not controlled, rather
Scheme for feedwater control in a once-through forced-flow boiler.
Circulation in the entire load range.
The three-element control according to Fig. 83. 1 has proved quite effective.
The circulation control valve is normally fully open, since the level lies
above the set point L$ of the pertinent P controller. The level deviation
acts upon the feedwater flow valve, while the steam flow leaving the sepa¬
rator, mD , provides an anticipatory disturbance signal. Modifications are
possible, and the application of derivatives of the fuel flow and the steam
flow (again in the form of anticipatory signals) has been tested in practice.
To prevent the complete emptying of the separator, whenever a pre-set
minimum level is reached it triggers the action of a P controller which
closes the valve downstream of the circulation pump. On hand are, of
course, the already discussed blow-down controllers which guard against
overfeeding. These are not shown on Fig. 83.1.
8 Boiler Control
8.2.5 Feedwater Control Loop
All the arrangements discussed in connection with Benson boilers can be
also applied in supercritical Benson boilers. On the other hand, no schemes
based on water level can be applied in supercritical Sulzer boilers since
they do not use a water separator at supercritical pressures (the steam and
water phases are not present together). There the principal controlled
variable is derived from the temperature at the end of the transition zone
(which corresponds to the evaporator in subcritical units). An outlet cor¬
responding to the blow-down pipe is available, but it is normally closed,
and serves only for carrying away surplus water during heavy disturbances.
with the 100% pump, controller 2 with either one or both 60% pumps
depending on which are in operation. The controllers 3, 4, and 5 are the
actual limiting curve controllers that act on the speed of the respective
pumps via minimum value selector units. The use of selectors guarantees
the effectiveness of this type of control. The limiting curve for each pump
as well as the lower pressure limit are derived from the feedwater pressure
Ps, and the characteristic is formed in the respective function generator
(6, 7, or 8). The output of these generators is compared with the current
feedwater flow, and the differences become the inputs for the limiting
curve controllers. If there is a feedwater valve which is normally fully
open, then it can be used for throttling whenever feedwater pressure drops
excessively. In this manner action can be undertaken before the limiting
curve is reached. If, for any of the pumps, the difference between the
actual flow and the flow derived from the limiting curve drops to Am,
controller 9 starts throttling. To achieve this, a minimum selector will
choose the smallest deviation from the limiting curve. The action of con¬
troller 9 increases the resistance of the system. As a consequence, speed
increases via feedwater control, thus driving the pumps out of the danger
128
129
zone.
References: [3] [7] [18] [59] [83] [92] [104] [108] [114] [189] [201]
[213] [259] [262]
60"/.
Fig. 83.2 Scheme for feed-pump control.
If the pumps are to be used for control, their pressure must not fall below
a load dependent limit. To this effect they are protected by 'limiting curve
control' illustrated on Fig. 83.2. To demonstrate how the control works
when several pumps are involved, let us assume that one 100% pump and
two 60% pumps are installed. In the diagram, controllers 1 and 2 are feedwater flow controllers, described in the preceding text. Controller 1 is used
9 Klefenz
130
8.2.6 Reheat Steam Temperature Control Loop
8 Boiler Control
13 1
8.2.6 Reheat Steam Temperature Control Loop
The task of this control loop is to maintain constant steam temperature at
the outlet of the reheater. As the reheaters are located towards the outlet
of the boiler, i.e. in the cooler part of the gas path, they have a charac¬
teristic distinctly reflecting convection heat transfer. In other words, their
heating up increases with boiler load. As already explained when discussing
temperature control of high pressure steam, such a characteristic makes it
possible to control temperature by injecting feedwater. The control con¬
cept thus corresponds to Fig. 66. However, it must be pointed out that it
would be a serious mistake to locate the spray attemperator at the inlet
of the reheater in view of the size of the reheater and the bad process
dynamics connected with it. Effective control requires that attemperation
be moved out as far as possible in the direction of the reheater outlet. Due
to the danger of water drops reaching the turbine, and, above all, because
of the increased heat consumption, injecting water into the reheater is not
a particularly popular process. When investigating other methods the use
of heat exchangers should be considered in the first place. In these units,
heat is basically transferred from high pressure steam to low pressure
steam. Figures 84 and 85 show two possibilities of control. According to
Fig. 84, the adjustment is performed in the reheat (i.e. low pressure) path:
The control determines how much of the total flow by-passes the heat
exchanger. The polarity is chosen so that a stronger action (application
of a plus signal) implies more cooling. In all aspects the cascade used is
the same as that described for attemperation control of high pressure
steam (see Fig. 67).
load
Fig. 84
high-pressure steam
Scheme for reheat steam temperature control
by means of a heat exchanger.
by
heat exchanger which is itself heated by flue gas. Control is effected
Triflux;
the
of
injecting water into the high-pressure steam side upstream
this then influences the temperature of the reheat steam. The control
already
scheme which is conceived similarly to the schemes that have
been discussed, is shown on Fig. 86.
The auxiliary control variable is the temperature downstream of the mixing
point, and the set point is again adjusted by boiler load, possibly by steam
flow. It is also recommended to use a feedforward disturbance compensa¬
tion from the fuel flow, in the manner shown on Fig. 66.
high-pressure steam
In the variant according to Fig. 85, the correcting action affects the highpressure steam path. Otherwise, the scheme is the same as that on Fig.
84. From the point of view of process dynamics the controlled by-pass on
the reheat steam side should be given preference above the one on the
high-pressure steam side.
A three-flow heat exchanger, the so-called Triflux, can be traced back to
a patent by the company Gebriider Sulzer A.G. In it the heat exchange
between the high-pressure steam and the reheat steam takes place in a
Fig. 85
9*
Scheme for reheat steam temperature control
by means of a heat exchanger.
132
8 Boiler Control
8.2.6 Reheat Steam Temperature Control Loop
The control scheme for gas by-passing is shown on Fig. 87. Here the backpass of the boiler is partitioned. The flue gas swivel dampers which are
operated either successively or so that they rotate in opposite directions,
vary the heating of the reheater. A simple PI controller, with a propor¬
tional anticipatory signal from boiler load, is adequate to control the out¬
let temperature. Of course, the adverse effect of the heating surfaces that
have to be accomodated in the other part of the pass, is noticeable.
high-pressure
steam
Fig. 86
Scheme for reheat steam temperature control
by means of the Triflux.
Besides heat exchanger and attemperator control, other measures are often
undertaken to influence the heat absorption of the reheaters; these can be
flue gas by-passing, flue gas recirculation, and tilting of burner nozzles.
Satisfactory results can be obtained with flue gas by-passing if the whole
reheater (or at least its end part) lies in the range of influence.
- -load
_J
Fig. 87
133
Scheme for reheat steam temperature control
by means of a flue gas by-pass.
During flue gas recirculation one part of the flue gas flow at the boiler out¬
let is branched off and returned to the furnace (or to a location just up¬
stream of the furnace) in order to increase heat supply to the heating sur¬
faces. In spite of quite favourable results when this type of control is in
operation, secondary effects render the method less than satisfactory. The
heaviest argument on the negative side is that affected are not only the
reheater heating surfaces but also all other heating surfaces. In addition,
surfaces heated by radiation are affected by the supplied heat even more
rapidly and more vigorously than the reheater surfaces which are heated
by convection. This means that whenever flue gas recirculation is used
to control reheat steam temperature, other loops, such as the final steam
temperature control loop and the steam pressure control loop, are severely
disturbed. This is the reason why flue gas recirculation is predominantly
applied only in an open-loop mode where the flue gas flow is adjusted
according to boiler load. In such an operation, the recirculation flow must
be raised with decreasing load, in order to counteract the convection heat
transfer characteristic of the reheater. The actual temperature control can
be performed by either a spray attemperator or a heat exchanger.
The use of burner tilting for control is not recommended for reasons simi¬
lar to those that apply to flue gas recirculation. Burner nozzle adjustment
would not only affect the heat absorption of reheater surfaces, but of all
other heating surfaces as well. Tilting burners are therefore primarily
employed only for static corrections after large load changes, or when
heating surfaces become dirty.
Finally, it should be mentioned that repeated use is made of combining
the above described control methods. For example, control using flue gas
dampers (Fig. 87) can be supplemented by attemperation control. With
such a combination the attemperator controls the reheat outlet tempera¬
ture as before, but its set point is set higher than the set point for flue gas
134
8.2. 7 Other Control Loops
8 Boiler Control
135
recirculation control. The spray then acts as an emergency measure, i.e.
only during positive control deviations of considerable magnitude.
References: [3] [7] [83] [84] [85] [92] [105] [214] [217]
$r-Gh;-*
A
j
9
L
[m]
8.2.7 Other Control Loops
The preceding sub-section dealt with the main control loops of a steam
generating unit. There are, of course, other control loops which, on the
whole, pose no problems in the area of control technology, and therefore
need not be discussed in the context of this book. The controllers used
in the auxiliary loops are basically simple pressure, level, and temperature
controllers, generally equipped with PI action but quite often only with
simple P action. To mention just a few such applications, there are the
sundry control loops in the milling plant; temperature control loops on
oil heaters; atomiser steam pressure control loops on oil burners; air
temperature control loops; as well as various control loops in the feedwater system. The following discussion will consider the control of pres¬
sure reducing stations, and the so-called condensate flow stop control.
Fig. 88
using the usual 30-second or even 60-second stroke time. An additional
requirement is that the outlet steam must be cooled in order to match the
temperature level downstream of the respective turbine part. Desuperheating is effected by an injection of water, either directly into the re¬
ducing valve (Fig. 88), or into a separate cooler (Fig. 89). The tempera¬
ture controller is built-up as a PI controller; an anticipatory action from
the position of the reducing valve is useful.
Reducing stations can be operated in two modes, either as over-flow
stations or as back-pressure stations. Accordingly, there are two basic
control schemes illustrated on Figures 88 and 89. Fig. 88 shows an over¬
flow reducing station installed in parallel to the high- and low-pressure
stage of the turbine, and serving as a means of protection against excessive
pressure. Here the valve is normally closed, since the set point is adjusted
slightly higher than the operating pressure. Should, however, the pressure
Pv rise above the set point, the initial reaction would be that a rapid
traverse motor (with a positioning time of approximately 5 seconds) would
quickly open the reducing valve.
The high-speed opening is mandatory because the pressure increases very
rapidly upon load rejection. Following the initial action, control is taken
over by standard PI control which maintains the inlet pressure constant
Control scheme for an over-flow reducing station.
-ED— A
n-
\k
Fig. 89
Control scheme for a back-pressure reducing station.
8. 2. 7 Other Control Loops
8 Boiler Control
136
This anticipatory action causes the water injection valve to react instan¬
taneously following the initial response of the reducing station. It follows
that reducing stations in plants operating with variable pressure should
not have a fixed set point. The reason is that in situations when the fastresponse mode is currently used at low loads (i.e. at low steam pressures),
the steam pressure would first have to be radically increased before the
station could respond. Such a waste of energy can be avoided by making
the set point variable with load. A simple method is to replace the up¬
stream pressure Py by the current deviation (or actuating signal) of the
steam pressure controller (= firing controller), and to use as the set point
the deviation signal at which the station should open. As long as the
actual deviation remains below the set value, the controller keeps the
station closed. On the other hand, the reducing station always opens
when the set deviation is exceeded, independently of load and therefore
also independently of steam pressure.
9
Fig. 89.1
to
137
not required, and can be omitted - see Fig. 89. In all other aspects the
control is conceived along the exact lines as suggested for the over-flow
station.
One possibility of achieving fast load increases is the exploitation of the
boiler storage capacity. This has already been discussed in preceeding
sub-sections. A further useful measure which is, however, not as produc¬
tive, is throttling or even shutting off the bled steam flows on the turbine
side. This approach makes use of the possibility to expand in the turbine,
after the closure of the extraction points, the bled-steam flows which are
not extracted. The increase in power can then be used during fast load
raises. The manner in which the shut-down of the preheaters takes place
affects the dynamic performance. Basically, it is possible to draw on the
bled steam intended for high-pressure preheaters as well as low-pressure
ones. If there is a choice, the taking out of service of low-pressure heaters
is more advantageous. It causes no disturbances in the loading of the steam
generator, and can take place independently of other measures. An
example of such a control, which is sometimes called condensate flow
stop control, in a unit which uses natural variable pressure operation, is
presented on Fig. 89. 1. The water that accrues in the condenser is fed
via a condensate roughing pump 6 into a condensate storage tank 3. This
vessel serves as a buffer storage for the condensate delivered by the speedcontrolled main condensate pump 5. In plants that are not equipped with
a separate condensate storage, it may be possible to use the condenser
itself as a form of limited storage. By varying the speed of the main pump
it is possible to vary the condensate flow between 30% and 150% of the
nominal value. This has the effect that a certain amount of the bled-off
steam condenses in the low-pressure preheaters 2, and thus leads to a
decrease or increase of load. The control works as follows: An increase in
the load set point N$ reduces, via the derivative module 10, the set point
for the condensate flow controller 7 ; this action leads to the required fast
increase of load. The inserted limiter 9 has the task of changing the strength
of the applied signal in dependence on load, while simultaneously limiting
its absolute amplitude.
Scheme for condensate flow stop control.
Somewhat different considerations apply to back-pressure reducing sta¬
tions where a constant steam flow is let through, for instance, as process
steam. Here the anticipatory action in the temperature control loop is
The rest of the scheme represents a three-element level control in the feedwater tank 1. The level controller 4 is adjusted for slow action to allow
the condensate flow stop control to take effect. For the same reason the
steam flow signal is applied with a delay (PT[ — module 8). In this manner
it takes only a few seconds (the interval is a function of the stroke time)
139
8 Boiler Control
8.3 Signal Flow Diagrams of Controlled Systems
to achieve load increases amounting to 3 to 5% of the currently produced
load. This increased load can be maintained for several minutes, depending
on the available storage capacity for the condensate, i.e. on the water
supply in the feedwater tank.
This does not exclude, in cases of expediency, the occasional use of re¬
ference variables as might occur in the calculations, particularly if such
calculations are performed with the help of an analogue computer. The
marked variables are, in fact, deviations from a specific stationary state,
this being acceptable because dynamic behaviour is customarily described
by linearised models. Strictly speaking, it follows that it would be pre¬
ferable to write An instead of n. However, the A symbol is generally left
out for the sake of simplicity.
138
References: [3] [35] [83] [92] [132] [140] [224]
8.3 Signal Flow Diagrams of Controlled Systems
The following sub-sections deal with the dynamics of the main systems of
the control loops covered in section 8.2. The most effective approach is
to use signal flow diagrams (also known as block diagrams), since these
not only indicate the transfer characteristics marked into the individual
blocks, but also, and above all, facilitate the recognition of the systemdependent couplings and interactions.
The scope of this book does not call for a detailed description of the
dynamic behaviour of controlled systems in a steam generator. In this
respect the reader is advised to consult specialised literature listed in the
references. However, provided are such approximations as have proved
useful by tests on operating boilers. In addition, the text gives guidelines
for approximate calculations of the various constants contained in the
diagrams. Particular importance is attached to determining all the required
factors and time constants from design and construction data. Whenever
a simple approach does not work, available empirical values are indicated.
Each individual sub-section deals with the respective controlled system of
a specific control loop. However, it should be understood that there is al¬
ways interaction with other control loops. Whether this can be disregarded
or not (i.e. to what extent can the individual control loops be considered
independent on the rest of the plant), must be decided with the aim of the
investigation in mind. For approximate calculations it is generally possible
to consider the loops as decoupled. To provide an insight into the effects
of interaction, a signal flow diagram of the entire plant will be discussed
in section 8.4.
As regards graphic representation, the following general comment applies:
In order to make the diagrams more vivid, the lines of action are marked
by the respective physical variables, such as pressure, temperature, etc.
In order not to overload the signal flow diagrams by too many blocks,
another simplification is used: Whenever possible, pure gain amplifications
(steady state gains, proportionality factors) are not represented by inde¬
pendent blocks, but are appended to the neighbouring time behaviour
blocks. For example, a block with a first order lag is characterised not
only by its time constant T, but also by the steady -state gain K.
8.3. 1 Steam Pressure Controlled System in a Drum Boiler
Fig. 90 shows the signal flow diagram of a controlled steam pressure system
in a drum boiler. For this example, pulverised coal firing with direct firing
mills has been chosen, so that feeder speed n would appear as the control
variable.
Blocks 1, 2, and 3 represent the firing equipment. The symbol mK indicates
the pulverised coal flow that reaches the furnace. Block 1 symbolizes the
transportation lag, block 2 the effect of storage in the mill. If faster beater
wheel mills are involved, a single 1st order time lag is generally adequate.
With large inertia mills it is, under some circumstances, necessary to add
another lag. Block 3 reflects the influence of a change in the mill air flow
VLP on the pulverised coal discharge. Block 4 represents the conversion of
5 signifies
mK into the heat flow Q (i.e. into heat release), while block
the delay of heat transfer into evaporator tubes.
Since the heat flow which arrives at the inside of the tubes, causes an
almost immediate change in steam production, it is possible to equate the
signal at the output of block 5 with the produced steam flow rhe. The
blocks 6, 7, and 8 describe the economiser. In the first instance, the firing
affects the water temperature at the economiser outlet (represented by
blocks 6 and 7), the steam production being influenced only subsequently.
140
8 Boiler Control
8.3 Signal Flow Diagrams of Controlled Systems
"B i
generally insignificant, and can be neglected. Besides, the storage capacity
of the superheated steam is small in comparison to the storage capacity of
the evaporator part. This makes it possible to combine the storage capacities
and to represent them by a single block. It also leads to a simplified signal
flow diagram according to Fig. 91. Note, however, that in this diagram oil
firing and not pulverised coal firing is assumed.
Fig. 91
Fig. 90
Signal flow diagram of a steam pressure controlled system
in a drum boiler with forced withdrawal of steam (with a
load controlled turbine).
Block 8 characterizes the change in the economiser outlet temperature
caused by variations of the feedwater flow ms. The representation of the
economiser shown on Fig. 90 is valid only when there is no evaporation.
If the boiler has an economiser with evaporation, blocks 6, 7, and 8 must
be replaced by a structure corresponding to an evaporator with a fixed
evaporation end point (see Fig. 97).
Blocks 9, 10, 11, and 12 simulate pressure dynamics, i.e. the conversion
of the produced steam flow me into the output pressure P, under the
assumption of a forced withdrawal of steam (as is always the case with
modern units with an active turbine). The storage capacity of the water
in the evaporator and in the drum area, which is capable of boiling, the
storage capacity of steam, and that of the metal masses, is represented
by block 9, while the storage capacity of the superheated steam is denoted
by block 12. The pressure drop between the drum pressure PK and the
steam outlet pressure P is reproduced in a linearised form by block 10.
The block 11 reflects the delaying effect of the metal masses, the so-called
thermal inertia. The steam flow withdrawn from the turbine, mD, becomes
the disturbance variable.
For approximate calculations a further simplification of the above signal
flow diagram is possible. The effect of the economiser (blocks 6, 7, 8) is
141
Signal flow diagram of a controlled steam pressure system
in a drum boiler with forced steam withdraval (e.g. via
a load-controlled turbine).
Since the oil flow riiQ follows the correcting action of the control valve
practically without delay, it is possible to use mg directly as the control
variable. In the case of pulverised coal firing blocks 1, 2, 3 from Fig. 90
would, naturally, have to precede block 1 in Fig. 91.
In other respects, block 1 corresponds to block 4 and represents the heat
release, while block 2 corresponds to block 5 and implies the time delay
accompanying the heat flow through the tube walls. Block 3 is the con¬
centrated storage capacity, and block 4 corresponds to a combination of
blocks 10 and 11.
An attempt at a precise calculation of the characteristic values for the in¬
dividual blocks from the design data is almost always accompanied by
serious difficulties. These have their origin in the complexity of the com¬
bustion process, in the intricacy of the heat transfer conditions, as well as
in the need to use a very demanding computing procedure. An explanation
of the pertinent computing methods must be left to specialised literature,
and cannot be made the subject of this book. On the other hand, an effort
will be made to present recommended values and guide figures, as well as
formulae leading to approximate values which have proved useful in the
calculations of practical problems.
Blocks 1 to 4 in Fig. 90, and block 1 in Fig. 91, are not to be determined
by approximate formulae. As will be shown later, it is more expedient to
establish the respective characteristic values through the application of
8 Boiler Control
142
guide values for the total effective dead time Tu. Block 2 in Fig. 91 is
characterised by the time constant Tq which can be approximately calcu¬
lated as follows:
,14)
8.3 Signal Flow Diagrams of Controlled Systems
where
10
8(eJ-©J)
or
<>5>
Formula (14) is recommended if heat is transferred primarily by radiation,
formula (15) is recommended if radiation and convection participate in
the same order of magnitude. In the latter case it is necessary to insert for
aa a replacement heat transfer coefficient which can be obtained from the
heat flow transfered into the tube and the mean temperature difference
between the combustion chamber and the tube. The meaning of the
individual symbols is as follows:
Ce
specific heat of iron
mE
iron mass of the evaporator
!?e
©E
mean tube wall temperature of the evaporator
$g
saturated steam temperature
0p
absolute furnace temperature
C
radiation coefficient (evaporator/furnace)
Fa
effective outer heating surface of the evaporator (tube/flue gas)
Fi
inner heating surface of the evaporator (liquid/tube)
aa
a,
outer heat transfer coefficient for the evaporator (tube/flue gas)
absolute mean tube wall temperature of the evaporator
m
PK0
drum pressure
mi —mo
(17)
S = ÿK1 - pK2
This calculation method is somewhat time consuming, and is therefore
used only with a computer. For estimates it is sufficient to use approxi¬
mate methods, two of which will be described below. Using any one of
these methods it is necessary to have a clear idea as to the location of
storage. For this purpose, there are three distinct areas in a boiler to be
distinguished: The water space (from the entry of feedwater practically
to the beginning of boiling), the boiling space (space filled with water/
steam mixture at saturation temperature), and the superheat space. The
water space contributes to the storage (i.e. accumulator) capacity only
insignificantly. On the other hand, a very important share comes from
the boiling space, the contributing components being the water heated
to boiling point, the saturated steam, and the iron mass. In addition,
superheated steam also provides a certain contribution. The total storage
capacity is therefore composed of:
inner heat transfer coefficient for the evaporator (liquid/ tube)
Ts=SPko
n
umax
storage capacity (accumulation capacity) of the boiler
The storage capacity of the boiler, S, denotes the mass (in kg) of steam
released during a pressure drop of 1 bar, and is usually given in kg/bar.
There are several methods for the calculation of this parameter. In the
exact method, the content of the working medium in the total tube
system, is determined, under constant heating, for two pressures PK1 and
Pk2- In practice, the respective contents, m.\ and m2 , can be obtained by
first determining the density of water or steam as function of the tube
length, and then integrating it with respect to this length. The storage
capacity can then be calculated from:
Block 3 is an integral element, and is, accordingly, defined by the integral
action time constant:
(16)
S
maximum steam flow
mn
Umax
«>£->*> 2
To =
143
(18)
Syi
storage capacity of boiling water
Sy2
storage capacity of saturated steam
SE
SD
storage capacity of the iron masses in the boiling space
storage capacity of superheated steam
S = SV1 +SV2 +(Se)+Sd-
mr
144
8 Boiler Control
The average capacity SE of the iron masses was put into brackets to indi¬
cate that both accumulation and release of the iron storage heat are
affected by time delay. The decision on whether SE is to be considered
or not depends on the problem to be solved.
The following equations are used for the calculation of the individual
8.3 Signal Flow Diagrams of Controlled Systems
145
VE ~ one half of the volume of iron of the evaporator, in addition
to 1/3 of the volume of the iron of the drum in drum boilers.
The factors required for the multiplication of the individual volumes in
order to obtain storage capacities, are calculated as follows:
components:
(19)
SVi = a VVl
(20)
SV2=0.VV2
(22.1)
•
a =
3p'
n
dP
PO
SE =y-VE
(22)
SD
=8- VD.
(22.3)
3P
3l?s
pe
7 = dP
volume of saturated steam
Vq
volume of superheated steam
volume of water at boiling temperature
3P
r0
p'o ' r0
II
/
PO ~ Po
(22.4)
5 =
ÿ
PO
r0
p'o r0
ÿ
Ceo
r0
(with minimum superheat)
3P
PmO
PO
(the more superheated the steam,
the better the approximation)
volume of iron in the boiling space
r kg ]
Lm3- barj
6
If no details about the above volumes are known, the following values can
be used as first approximations:
Tyj
~
in forced-flow once-through boilers, approximately one half
of the volume of the evaporator;
ss
in drum boilers, approximately 2/3 of the volume of the
evaporator, plus 1/3 of the volume of the tubes feeding the
drum, plus 1/4 of the water content of the drum;
I
5
\\V
U
\;\
3
2
V"V2 = in forced-flow once-through boilers, approximately one half
Y
a
1-
P
of the volume of the evaporator;
%
II
1
p0 - PO
'
3Pn
where
VVi
VV2
VE
II
/
PO ~~ PO
ÿ
3P
(21)
II
p0 - PO
dh" p0n
+ -
tip
1
3/1
0
in drum boilers, approximately 1/3 of the volume of the
evaporator, plus 2/3 of the volume of the tubes feeding the
drum, plus the steam volume in the drum;
Fig. 92
10 Kiefenz
Evaporator storage characteristics.
146
8 Boiler Control
8.3 Signal Flow Diagrams of Controlled Systems
The coefficients ot,fS, and 7 depend purely on steam pressure,
and can be
presented in the form of a diagram, as shown on Fig. 92.
For higher pres¬
sures, the calculation of the coefficients is no longer accurate
enough, and
the storage capacity should be calculated by the
method mentioned first.
With superheated steam the storage capacity depends also
on steam tem¬
perature. For this reason it is recommended to use a
step-wise approach,
an average density pm being applied in the individual
steps.
The symbols used in equations 22.1 to 22.4 have the
/
p
II
following meaning:
density of water at boiling temperature
104
(24)
S=
147
kg
t/h
Pk
0,38
kg/bar
t/h
mr
In drum boilers, the main location of storage capacity is the evaporator
and the drum. The superheated steam does not generally contribute more
than 10 to 20% of the total. This contrasts with forced-circulation oncethrough boilers where storage capacity of superheated steam amounts to
approximately one half, and with high-pressure boilers where it amounts
to even more than one half of the total storage capacity.
In conclusion, attention will be drawn to a condition which can make the
calculation of storage capacity rather problematic, particularly in forcedflow boilers fired with a mixture of fuels. The problem arises with the
position of the fire in the furnace. Generally, following a change in fuel
-constituents, particularly if they are as dissimilar as coal and gas, a shift
of the fire is most difficult to avoid. This is unfortunate since the shift
tends to be accompanied by a change in the length of the evaporator (in
forced-flow boilers). Thus in spite of a constant boiler load, a change can
take place in the storage capacity, as well as in the time behaviour of the
p
density of saturated steam
Pm
average density of superheated steam
Pe
density of iron
H
h"
enthalpy of water at boiling temperature
r
latent heat
P
steam pressure
system.
saturated steam temperature
In general, in fixed pressure boilers, storage capacity is dependent on load
only to a small degree. On the other hand, the dependence can be quite
substantial in variable pressure plants.
CE
enthalpy of saturated steam
specific heat of iron
The second, and somewhat less accurate, method is
recommended when
there are virtually no design data available, and at least
roughly approxi¬
mated estimates would be of help. However, it applies only
to forced-flow
boilers, and is based on an equation derived from the averages of
many
measured and calculated values of the past. It is as follows:
The last block in the signal flow diagram on Fig. 91 still to be considered
is block 4. It was formed by a combination of blocks 10 and 11 of Fig.
90. Block 10 characterizes the delayed storage caused by thermal inertia.
The respective gain of the proportional element can be calculated in a
dimensionless form from:
rth »?D0
SK ' p0
'
(23)
8-fc±-W
(24.1)
•<„.
A similar formula has been derived for drum boilers (Equation
(24)).
However, due to differences in circulation there exists an even greater
degree of uncertainty as to its accuracy.
*th =
where Tth is the thermal inertia that can be calculated by equation (26).
Block 11 reflects the pressure drop in the superheater. This, of course,
changes with the square root of load, but for simulation it is often quite
adequate to linearize the parabola for the load range under consideration.
10*
148
8 Boiler Control
,"-r*ik.
For block 4, the proportional oontrol factor can be obtained by adding the
proportional control factor for block 10 to the reciprocal value of the factor
for block 11.
P Am
8.3 Signal Flow Diagrams of Controlled Systems
time response is obtained with pulverised coal firing using direct firing
mills with a constant mill air flow.
type of firing
oil or gas firing
a) Transient response to a
change in the control
variable
Amn
b) Transient response to a
change in the disturbance
variable.
Fig. 93
149
Tu[ s]
5. . 10
pulverised coal firing,
bin storage system
20 . . 30
pulverised coal firing,
direct-fired system,
mill-air feedforward control
20 . . 30
pulverised coal firing,
direct-fired system,
no feedforward control
30 ... 60
Transient responses (step responses) of the steam pressure
controlled system.
In conclusion, some comments will be made on transient responses, and
selected guide values will be stated.
Fig. 93 shows under a) the transient response to a change in the control
variable, i.e. the development in time of the pressure P following a step
change of the fuel flow mB. Under b) is shown the transient response to
a change in the disturbance variable, i.e. the development in time of the
pressure P following a step change of the steam flow mD .The transient
response to a change in the correcting or manipulated variable (a) is
characterised by the effective dead time Tu as well as by its integral ascent
which is in turn a function of the storage capacity S. The constant K re¬
presents the static relationship between the fuel flow and the produced
steam flow. The magnitude of the effective dead time Tu depends very
much on the type of fuel and on the type of firing, as can be seen from
the following table containing some guidance values. The shortest effective
dead times can be achived with oil and gas firing, while the most sluggish
Naturally, a considerable influence is borne by the type of mill used. The
lower values indicated in the table can be achieved with high-speed pul¬
verizers where the circulation between the mill and the classifier results
in only a small accumulation of material. In slag tab boilers effective dead
times of 50 seconds and more must be assumed.
With the help of the above guide values it is now possible to determine the
still missing time constant of the firing process, which is needed for pre¬
liminary calculations of control processes. To this effect, the already cal¬
culated blocks are simulated on an analogue computer, the basic arrange¬
ment being supplemented by block 1 (see Fig. 91). The time constant is
then varied so long as the effective dead time differs from the recom¬
mended figure. The process stops when the guide value is reached. If the
applied signal flow diagram corresponds to Fig. 90, the process for deter¬
mining time constants of blocks 2 and 3 is the same. The estimate of the
dead time for block 1 corresponds quite well to the time needed for the
transport of coal from the feeder into the furnace.
\
8.3 Signal Flow Diagrams of Controlled Systems
8 Boiler Control
150
Listed below are a few reference values for the storage capacities of in¬
dividual boiler types.
boiler type
S [kg/bar]
drum boiler
130 .. . 180
Ts[ s]
15 1
variable size and the shifting of the evaporator. Fig. 94 shows the respec¬
tive signal flow diagram, where pulverised coal firing is assumed.
Blocks 1, 2, and 3 represent the firing equipment. These blocks have been
already described in sub-section 8.3.1 together with block 4 (heat release)
and block 5 (heat transfer into tubes).
150 bar; 500 t/h
dmm boiler
250 .. . 300
140 ... 250
170 bar; 1000 t/h
drum boiler
195 bar; 1900 t/h
%
once-through boiler
60 ...80
600
ÿIP-
190 bar; 500 t/h
once-through boiler
140 .. . 180
60 . .. 130
200 bar; 1000 t/h
once-through boiler
Fig. 94
Signal flow diagram of a steam pressure controlled system in
a Benson boiler with forced steam withdrawal (e.g. via a
load-controlled turbine), and including the effect of feedwater.
150. . . 180
210 bar; 1800 t/h
The above values show only the order of magnitude. For dynamic analysis
it is recommended to calculate the storage capacities by one of the methods
given earlier on.
References: [6] [12] [19] [83] [94] [97]
8.3.2 Steam Pressure Controlled System in a Benson Boiler
The signal flow diagram of a Benson boiler differs from the diagram of a
drum boiler primarily in two points. Firstly, the role of the feedwater
flow is vital, and secondly, additional storage processes occur due to the
Block 6 stands for the economiser, and reflects the delaying effects of the
feedwater flow rh$, or the heating Q, on the starting point of evaporation
Xy3. The evaporator is simulated by blocks 7, 8, 9, and 10. In this group
block 8 represents the dynamics of the action of the feedwater flow
changes and of the heating changes on the length of the evaporator, AXy.
Simultaneously, block 9 reflects storage processes during the shift of the
starting point of evaporation. Furthermore, in blocks 8 and 9, both
transient responses which are in themselves rather complicated, are
approximated by straight lines. The development in time of the evapo¬
ration end point Xye is obtained by adding up the signals for the eva¬
poration starting point and the evaporation length. Block 11 displays the
storage capacity of the evaporator, block 12 the delayed storage process
caused by thermal inertia, block 13 the pressure drop at the superheater,
and block 14 the storage capacity of the superheated steam.
152
153
8 Boiler Control
8.3 Signal Flow Diagrams of Controlled Systems
As in previous examples, the signal flow diagram is designed for the typical
case of forced steam withdrawal. The controlled system is without selfregulation (astatic), i.e. following a change of the feeder speed n and feedwater flow ms, the outlet pressure P does not tend towards a new stationary
value, but continuously moves away from its original condition. In other
words, the outlet pressure is proportional to the integral of the input signal.
The same happens when the steam outflow mD is changed during a con¬
stant feed supply and constant feedwater flow.
value of the time constant is determined in order to satisfy the guide value
for the effective dead time Tu (see the respective table). As regards block
2, the equation for the time constant Tq was also given in sub-section 8.3.1
(Equation (15)). The expression of the delay denoted by block 3 is based
on the fact that the volume of the evaporation zone changes with varia¬
tions of the feedwater flow, or with the heating. It is evident that in this
case the storage process is mechanical, and it is possible to use equation
(25) to approximate its time constant Tw:
If it is possible to disregard the influence of the economiser, i.e. of the
shifting of the starting point of evaporation, the presentation can be
simplified. Further, the non-linear block 8 can be replaced, in the interest
of easier manipulation, by a linear element. These changes lead to the
signal flow diagram on Fig. 95, which is, in order to provide some variety,
again conceived for oil firing. Blocks 1 and 2 correspond to blocks 4 and 5
in Fig. 94. Block 8 is replaced by the two blocks, 3 and 4, each of the two
representing a 1st order delay. In contrast to the drum boiler, blocks 5
and 8 (corresponding to blocks 11 and 14 of Fig. 94) cannot be combined,
since in a Benson boiler the evaporator storage (block 5) is not substan¬
tially larger than the superheater storage (block 8).
The characteristic values of the individual blocks of Fig. 95 can be ob¬
tained from design data in the following manner:
ÿ
Tw = (v -v') m
(25)
"
where
V
volume of the evaporator
v'
spec, volume of saturated water
v"
spec, volume of saturated steam
m
mass flow of the water/steam mixture (boiler load)
The second delay simulated by block 4, is caused by thermal storage in the
iron mass, where local changes of the evaporation process, namely the
change of volume and the shift of the evaporation zone, cause temperature
changes. The corresponding time constant Tth can be calculated from:
mt
CC • »l£
7th = Cp
(26)
•
m
where
Fig. 95
Signal flow diagram of a controlled steam pressure system (incl.
the effect of feedwater) in a Benson boiler with forced steam
withdrawal (e.g. via a load-controlled turbine).
The time constant characteristic for block 1 (equivalent blocks for coal
firing are blocks 1 to 4 in Fig. 94) can be expediently established by the
method already described in sub-section 8.3.1 for drum boilers. Here the
CE
spec, heat of iron in the evaporator
mE
mass of iron in the evaporator
cp
spec, heat of the mixture steam/water
Block 5 is determined by the integral action time constant T$ i- Ana¬
logically to the time constant T$ (see equation (16)), Tsi is determined
by the following equation:
8 Boiler Control
154
Sv PkO
'
TS1 =
(27)
™D0
8.3 Signal Flow Diagrams of Controlled Systems
155
Finally, part (c) shows the transient response to a change in the steam
flow that is withdrawn from the boiler, this being a disturbance variable.
The curve shows the same PI character as was the case in drum boilers.
where
ÿSv = Svi + Sy2 + SE
storage capacity of the evaporator
Pk0
pressure in the evaporator
mD0
maximum steam flow
a) Transient response to a change in the
correcting variable (fuel flow), with
feedwater flow constant.
A similar equation is used to calculate the integral action time constant
for block 8, namely
»B=ms
(28)
TS2 =
SDP
Am 3 = Amg
™D0
'
U-Tu
where
.
SD
storage capacity of the superheated steam
P
outlet steam pressure
The calculation of the various storage capacities has been dealt with in
detail in sub-section 8.3.1. Blocks 6 and 7 are equivalent to blocks 10 and
11 in Fig. 90, and have already been explained there.
The various resulting transient responses are displayed in a qualitative
manner on Fig. 96. Part (a) shows the development in time of steam pres¬
sure, following a step change in the fuel flow (accompanied by a correspnding change in the air flow). In contrast to the pertinent function for a
drum boiler, pressure in a Benson boiler tends to reach a new stationary
value. The reason for this being that since the feedwater flow has not
changed, there cannot be a continuous production of extra steam. A tem¬
porary increase of the mentioned parameters just tends to shift the level
of pressure. Only a fuel flow adjustment accompanied by a feedwater flow
adjustment can result in a lasting change in the produced steam flow mE,
while the steam pressure exhibits integral characteristics (see Fig. 96b).
The step response is characterised by the effective dead time Tu and the
storage capacity S (for guide values see the relevant tables in sub-section
8.3.1).
b) Transient response to a change in the
correcting variable (fuel flow), with
a simultaneous change in the feedwater
flow.
Amp
VLi
Fig. 96
s
c) Transient response to a change in the
disturbance variable (steam flow).
Transient responses of a steam pressure controlled system
in a Benson boiler.
References: [2] [6] [19] [21] [58] [70] [72] [75] [79] [83] [95] [102]
[154] [163] [167]
8.3.3 Steam Pressure Controlled System in a Sulzer Boiler
As in a Benson boiler, the adjustment of the feedwater flow in a Sulzer
boiler plays a very important role, and, therefore, must be taken into
account in the signal flow diagram of the steam pressure control system.
1
8.3 Signal Flow Diagrams of Controlled Systems
8 Boiler Contro I
156
A further complication is caused by the existence of the water separator
which, as already explained, fixes the evaporation end point so that not
only steam me but also water mSa leave the evaporator.
157
Blocks 11, 12, 13, and 14 have already been explained in detail in sub¬
section 8.3.1. Block 11 represents the storage capacity of the evaporator,
block 12 the delay in storage due to thermal inertia, block 13 the pressure
drop in the superheater, and block 14 the storage capacity of the super¬
heater.
The signal flow diagram is again conceived for a forced withdrawal of
steam, i.e. when the turbine operates with load control. Typically, the
disturbance variable % corresponds to a change in the steam flow being
mAb
Sa
withdrawn.
1=
x Va
mD
Fig. 97
Signal flow diagram of a steam pressure controlled System
(inclusive of the effect of feedwater) in a Sulzer boiler, with
forced steam withdrawal (e.g. via a load-controlled turbine).
The individual relationships can be observed in the signal flow diagram on
Fig. 97. Oil firing was assumed, thus making the oil flow mQ the correcting
(or manipulated) variable. Block 1 once again denotes the heat release, and
block 2 the heat transfer into tubes. Block 3 simulates the delaying in¬
fluence of the economiser on the shift of the evaporation starting point
Xya. Blocks 8 and 9 indicate the rather complicated time behaviour (here
represented by straight lines) of the evaporator in relation to the shifting
evaporation starting point. Block 8 represents the influence of the evapo¬
rator on the separated water flow mSa, while block 9 specifies its influence
on the produced steam flow rhe. Blocks 4 and 5 show the time behaviour
of the evaporator with respect to feedwater flow changes ms, blocks 6 and
7 show the same with respect to changes in the heating, Q. Block 10 is a
pure integrator and simulates the time behaviour of the level in the sepa¬
rator in response to changes in the separated water flow msa and in the
blow-down water flow mAb-
With a Sulzer boiler a simplification of the steam pressure control system
diagram is naturally even more difficult than it was with a Benson boiler.
However, for a rough approximation it is possible to consider the following
points: It can be accepted that feedwater flow and fire (heat input) are
controlled by the control system concurrently. If this is so, then the in¬
fluence of the shift of the evaporation starting point can be disregarded.
In addition, blocks 5 and 7 complement each other, so that steam pro¬
duction can start without delay. All this leads to the thoroughly simplified
signal flow diagram displayed on Fig. 98. However, the diagram is useful,
as has already been made abundantly clear, only for very approximate
estimations.
The calculation of the characteristic values for the individual blocks from
design data has already been fully dealt with in the preceding sub-sections,
and will not be repeated.
Fig. 98
Simplified signal flow diagram of a steam pressure controlled
system in a Sulzer boiler, with forced steam withdrawal.
When calculating characteristic values for the blocks of Fig. 97, it is re¬
commended to consult specialized literature. The transient responses to
8 Boiler Control
8.3 Signal Flow Diagrams of Controlled Systems
changes in the correcting and disturbance variables appear to correspond
to those indicated in Fig. 96b and 96c.
Block 1 is a first order delay, and represents the effect of a steam flow
disturbance on the outlet steam temperature. Block 2 is also a first order
delay, and simulates the consequences of a fire disturbance. Block 3
shows the relationship between the inlet and the outlet temperature. This
lastly mentioned transient response is a rather complicated high order
function the character of which very much depends on the design of the
superheater.
158
References: [6] [25] [58] [72] [75] [79] [83] [97] [149]
8.3.4 Steam Temperature Controlled System
159
1
When considering systems for steam temperature control it is not necessary
to differentiate between a superheater and a reheater. The signal flow dia¬
grams as well as the formulae presented in this sub-section apply, therefore,
in like manner to any kind of heater. The basic signal flow diagram is dis¬
played on Fig. 99. The superheater outlet steam temperature to be con¬
trolled is marked t?a. The variables that influence this outlet temperature
are the steam flow mD, the heating Q, as well as the inlet temperature i?e.
In general, mD and Q are disturbances, while $e is a correcting variable
since it can be changed by attemperation water flow. Unfortunately, the
signal flow diagram in the form it is presented here is not particularly
suitable for computer simulation.
Fig. 100 Simplified signal flow diagram of a steam temperature controlled
system (superheater).
Fig. 101 shows a multitude of possible transient responses. Two characte¬
ristic values distinguish the transient response pertinent to a superheater:
The factor xD fixes the form of the function, while TR determines the
time scale. The two factors are defined as follows:
aiÿi
(29)
cD ' mD '
IZI
Fig. 99
Signal flow diagram of a steam temperature controlled system
Tr=!ÿ)
Fj
(30)
x
aj •
where
(superheater).
Should one wish independently to examine either a steam flow disturbance
or a heating disturbance, difficulties might arise with reaching limits in the
integrating block. Fortunately, this awkward situation can be overcome by
changing the diagram to a simplified form. Fig. 100 represents a good
approximate solution in this respect. Note that since dead time (which is
the time needed by the steam to pass through the superheater) is insigni¬
ficant in comparison to other delays in the system, it is ignored in Fig. 100.
ttj
inner heat transfer coefficient (tube/steam)
F\
inner tube surface
Cq
spec, heat of steam
Ce
spec, heat of tube material
rhD
steam flow
iron mass of the superheater
160
8 Boiler Control
8.3 Signal Flow Diagrams of Controlled Systems
16 1
In general, superheaters show xD factors between 6 and 12. As regards
their time behaviour, there are several possibilities of simulation. In this
respect, a connection in series of n 1st order delay elements with identical
time constants, has proved adequate.
Fig. 101 Standardized transient responses of superheaters.
Once the two characteristic values, the form factor and the time factor,
are calculated from the design data, the transient response can be derived
from Fig. 101.
r-o,5
-1000
o
i
T<
Fig. 102 Standardized transient responses of superheaters.
Should the time standardization be based on
(31)
Tsr - Tr *D
(32)
Tsr - cD tnD
Fig. 103 Diagram for determining characteristic values for a
superheater simulation.
'
n
CE ' mE
Tu
•
T
then the difference between the individual time functions would become
even more pronounced, as can be seen from Fig. 102.
Tr
XD
11 Klefenz
number of 1st order elements
effective dead time
build-up time
time constant of the 1st order elements
time factor for standardization
form factor
8. 3 Signal Flow Diagrams of Controlled Systems
8 Boiler Control
162
The required number (n) of the elements, as well as the value of the com¬
mon time constant T can be obtained from the diagram on Fig. 103. The
procedure is as follows: The calculated value of xD is used to find the
relationship Tu/TR (which is the standardized effective dead time) using
the curve in the lower part of Fig. 103. Since TR is also known (see Equa¬
tion (30)), Tu can be directly calculated. The curve in the upper part of
Fig. 103 is then used for finding the number n of the 1st order elements
(left-hand side ordinate, rounding-off required), as well as the ratio Tu/T
where Tu is again the effective dead time, and T the time constant to be
found.
Since Tu has already been calculated, T can be also determined. The ratio
Tu/Tg (= effective dead time vs. build-up time) which approximately
characterizes the transient response (see Fig. 104), can be established on
the right-hand side ordinate.
At the same time, the gain in the equation (34) can be calculated from
lis 40
=
ÿ=
(35)
-
It can be seen that the gain is equal to the warm-up span of the super¬
heater. The index 0 marks the stationary state before the disturbance
occured.
The disturbance time constant can be obtained from the transition time
TzQ ' and the gain qz
.
Tzq =
(36)
with the transition time and the gain defined by
_
CE mE
zq - k. F
m
(37)
i
'
ÿRmO ~ flmO
1 Glted
1:
(38)
rL
Fig. 104 Characteristic values for a superheater simulation.
V, =
*
=
ÿeo
*
flaO
The meaning of the symbols is as follows:
In all the considerations, up till now the gain has been assumed to equal
one. This is to a certain extent correct. However, a more exact figure can
be obtained from the ratio of specific heats at the input and output of
the superheater:
(33)
fjj ÿ .
=
Ce
specific heat of the tube material
mg
mass of iron in the heated part of the superheater, inch
relevant headers and tubes upstream of the temperature
measuring point
k
heat transfer coefficient (flue gas/steam)
F
effective heating surface (outside surface)
Subsequently, only transient responses to disturbances will be considered
(see Fig. 100). To this effect, the following calculations are needed:
i?Rm0
mean flue gas temperature in the superheater area
#mo
mean steam temperature in the superheater
Block 2 demonstrates the time behaviour of the outlet temperature
following a change in the heat flux Q. This can be represented accurately
enough by a 1st order delay with the transient response given by
i?a0
#eo
temperature of steam leaving the superheater
(34)
163
Ai3a(s)
lÿZO
—— = -ÿ1 + Tzq «
4g(s)
ÿ
temperature of steam entering the superheater
Finally, block 1 simulates the reaction of the outlet temperature to changes
in the steam flow mD ,which in this case are disturbances (see Fig. 100).
11*
164
8 Boiler Control
8.3 Signal Flow Diagrams of Controlled Systems
For approximation the actual time behaviour can be replaced by a first
order delay:
velocity, the following dependences on boiler load, i.e. on the steam flow
mD, can be formulated:
(39)
ÿZnio
Atfa(f)
1+
a«dW
rZniD
(43)
' ÿf
The gain
(40)
(44)
1
V,ZmD
AmD/niD0
is calculated from the difference between VZQ and the gain obtained from
the static superheater characteristic (shown on Fig. 105):
(41)
VZ mD VZQ ~ ™D0
~
•
(\Omj) )
/ mD0
"DO
moo)
I/mD_|-0,2
lB_
=
Tro
Udo /
1D_=
165
8
Equation (43) shows that * d > ar|d, as a result, also the ratio Tu/Tg slightly
decreases with increasing load (see Fig. 103). At the same time, according
to equation (44) the time factor TR decreases with increasing load quite
and TR the
significantly. Because of the simultaneous decrease of
effective dead time Tu changes almost proportionally with the inverse of
load:
(45)
™.
Tu0
md
The load dependence of the disturbance time constant can be expressed
with sufficient accuracy by:
(46)
Fig. 105 Static characteristic of a superheater.
The disturbance time constant can then be calculated by equation (42):
(42)
T_
.u — CE
—
1Zmn -
•
CD ' '«D
It should be pointed out that the gain has been established as a positive
value. A raise in the steam flow is, however, accompanied by a decrease
of the outlet temperature. All this has been taken into account in the
signal flow diagram shown in Fig. 100 by the introduction of a minus
sign at the appropriate summation point. (A variable having a minus sign
goes through with a sign reversal.)
It follows from the various equations that the transient response of a
superheater to changes in both correcting variables and disturbance
variables is determined by the characteristics y-u and TR. Considering
that the heat transfer coefficient cq changes with 0.8 power of the steam
f*TZO
-
mD
For disturbances of the steam flow, the relationship given by equation
(46) follows directly from equation (42). As to the corresponding time
constant for firing disturbances, it should be noted that the heat transfer
coefficient changes with 0.65 power of the flue gas velocity, and that, on
top of that, the gain increases with rising heat supply.
It has been already mentioned in sub-section 8.2.4 that in most cases
temperature is controlled by an attemperator located upstream of the
superheater. It follows that the signal flow diagram on Fig. 100 should
be complemented by the inclusion of a simulation of such a cooler. Since
its very modest time delay can be disregarded in comparison with the
rather inert behaviour of the superheater, it is necessary to consider only
the various gains. The designations used in the following equations are
based on Fig. 106. The process gains which relate changes in the attemup¬
peration spray water flow mE , as well as in the steam temperature
stream of the cooler, to the steam temperature t?2 downstream of it, can
be calculated as follows:
8 Boiler Control
166
(47)
(48)
v
aÿ2
——— =
AmE/mE0
Al?l
--
8.3 Signal Flow Diagrams of Controlled Systems
i
'"EO ' (*20 - *E0>
cp2
ÿ
167
:-,
m2o
cp2 ' "*20
The letter h denotes enthalpy. The index 0 again refers to the original
state. The gain in the equation (47) is specified in grad Celsius per %
change of flow, while in the equation (48) it is expedient to express it in
grad per grad. It would cause no difficulties should the need arise to write
down the gains in a completely dimensionless form. This could be done
by referring the values to the temperatures #i0 and i>2o-
If there are considerable masses of iron between the attemperator and the
superheater, for instance in the form of connecting pipes and headers,
then it is necessary to provide still another delay element.
Fig. 107 Simplified signal flow diagram of a steam temperature
controlled system (superheater).
Blocks 3.1 to 3.n simulate the time behaviour between the inlet and the
outlet temperature, in accordance with the method already described in
connection with Fig. 104. The superheated parts between the cooler and
the superheater inlet are reproduced by block 4.
m2
CP2
*2
ÿr
m,
-•
--Tzq
—
Fig. 106 Attemperator.
-TZÿd*1
The calculation can be performed with the help of equations (29) and (30),
and using Fig. 101. In general, what will be produced is a transient response
corresponding to ÿo-values between 0.5 and 1.0.
Complementing the signal flow diagram of Fig. 100 with all that has been
mentioned since, would result in Fig. 107. The blocks 1 and 2 again
demonstrate the effect of changes in steam flow and in heating on the
outlet temperature i?a.
Fig. 108 Transient response of a steam temperature controlled system.
a) Transient response to a change in nig (= correcting variable).
Transient response to a change in bj (= disturbance variable).
b) Transient response to a change in Q (= disturbance variable)
c) Transient response to a change in nig) (= disturbance variable)
168
8 Boiler Control
The proportional control factor determined by equation (48) is displayed
as block 5, while that calculated by equation' (47) as block 6.
The next point for discussion are the transient responses to correcting and
disturbance variables, illustrated by Fig. 108. The transient response to a
change in a correcting variable is presented in part a). It indicates the
development of outlet temperature i?a resulting from a step change in the
attemperation water flow mg .The response is characterised, as already
explained, by the effective dead time Tu and the build-up time Tg. If the
superheater is well designed from the dynamic point of view, Tu equals
approximately 30 seconds, while the approximate value for Tg is 150 se¬
conds. However, it should be noted that neither Tu nor Tg can be
directly measured. This is due to the non-negligible time constant of the
temperature sensors, which amounts to some 20 seconds and is caused
by the required heavy pocket for steam temperature measurements. Na¬
turally, time constants of this magnitude would considerably distort the
establishment of the transient response. Such has not been the case with
the previously discussed transient responses, where but for the exception
of temperature measurements it is generally not necessary to take into
account the time constants of the primary elements (sensors for the
measurement of pressure, flow, level, etc.). Consequently, if either meas¬
urements are to be evaluated, or any dynamic investigations performed,
the signal flow diagram according to Fig. 107 must be supplemented so
as to incorporate the effect of the time delays in the temperature sensors.
For this end, a delay element of the 1st order is inserted behind the signal
position !?a ; its output then corresponds to the measured outlet tempera¬
ture. Of course, the measuring point for the inlet temperature i3e must be
treated in the same manner. As to its location, the first order delay ele¬
ment must not be placed directly into the signal path leading to block
3.1;its place is in a separate signal path branch leading from i?e.
8.3 Signal Flow Diagrams of Controlled Systems
already mentioned superheater with dynamically favourable
ÿZQ lies between 100 and 130 seconds.
Part b) shows the transient response to a disturbance of the heating, QThe outlet temperature changes, with good approximation, in conformity
with a 1st order delay characterised by the time constant TZq. For the
characteristics,
Part c) follows to show the transient response following a
change of the
steam flow % (= disturbance). With the exception of
the sign, the develop¬
ment of t?a is very similar to that resulting from a
disturbance of heating.
Even the time constant
has approximately the same magnitude as
Tzq. However, it would be wrong to conclude that, since during a load
adjustment both heating and steam flow change, there
would be practically
no effect on steam temperature, and the positive and
negative deviations
would cancel each other. Changes in heating and in steam flow
do not
affect the superheater synchronously. As can be gathered
from the signal
flow diagrams, a considerable time delay exists between the
change in the
fuel supply and the change in the flow of heat, Q. Even should
the fuel
flow change instantaneously with the change in the steam flow
(brought
about by the turbine), Q would still act with a time delay;
temperature
changes are evidently unavoidable. On top of that, the steam pressure
con¬
troller may temporarily over-control the fuel flow in order to
re-fill the
storage which had been partly depleted during load changes.
Bearing all
this in mind it should not be assumed that the effects of changes
in
heating and in steam flow can compensate one another.
The final point to deal with concerns the approximate
calculation of heat
exchangers for temperature control. Attention has already been drawn
to
the two main control modes in sub-section 8.2.6. A controlled
by-pass is
either on the side of the steam the temperature of which is to be main¬
tained (see Fig. 84), or on the other side (see Fig. 85). Naturally, the
signal
flow diagrams differ accordingly.
TzmD
c3
Part a) of Fig. 108 also illustrates the time behaviour of the inlet tempe¬
rature !?e. It is easy to recognize a curve typical for low xD values.
A possible disturbance by the temperature , which is the steam tempe¬
rature upstream of the attemperator, is also incorporated into part a);
this is done for the simple reason that the transient response is the same
as for a change of mE.
169
c
*4
*2
2
/
-
/
i TO
I
1P,
Fig. 109 Heat exchanger as a control element for temperature
control.
170
8 Boiler Control
Fig. 109 explains the notations used in the following text. The controller
actsupon the three-way valve which affects the temperature i?3 by changing
the distribution of the steam flow between the heat exchanger and the by¬
pass. The pertaining signal flow diagram is on Fig. 110. A slight change of
the flow m through the heat exchanger varies, in the first approximation,
the temperature i?2 at the outlet according to a 1st order transient reponse
(block 1); the temperature drops as the flow rises. The temperature i?3
downstream of the mixing point is influenced in two ways: Firstly, i?3
changes with variations in $2 (the relationship is demonstrated by block 2),
and, secondly, it changes with variations in the ratio of the "cold" by-pass
steam flow to the "hot" steam flow through the heat exchanger. The last
relationship is represented by block 3. Should the flow m passing through
the heat exchanger increase, the by-pass flow would automatically decrease.
The combined effect would cause an increase in i?3 . The time behaviour
of the individual variables is shown on Fig. 111.
8.3 Signal Flow Diagrams of Controlled Systems
ratio downstream of the mixing point. This makes
such an arrangement
particularly suitable for temperature control of reheat
steam.
The following equations can be used for
approximating individual blocks
in the signal flow diagram on Fig. 110:
Block 1:
A 02
A m/m0 =
(49)
_ O
-
"0 • («?20 ~
1 n)
ÿ20 - flip
1+
ÿ40 + ÿ50 ~ <?I0 - 0
20
Here m is the Nusselt exponent, which can be put
approximately equal to
0.8. The time constant of the transient response is
given by:
(50)
rp
_ CE my.
'
2
cm m0
where
Fig. 110 Simplified signal flow diagram of the heat exchanger
displayed on Fig. 109.
mE
mass of iron
CE
specific heat of iron
cm
mean specific heat of heated steam
mo
flow of heated steam before change
Block 2 :
Ad3' _ c2
(51)
Ai92
c3
where
Fig. Ill Transient responses of a heat exchanger with by-pass
according to Fig. 109.
The very favourable time behaviour of temperature d3 in response to
changes in m ,can be traced back to the immediate change in the mixing
171
Ci
specific heat of steam downstream of the heat exchanger
C3
specific heat of steam downstream of the mixing point
Block 3 :
(52)
'
_ cm - (ÿ20 - i?i nl
A mlm0
c3
8. 3 Signal Flow Diagrams of Controlled Systems
8 Boiler Control
172
173
The corresponding transient response is shown on Fig.l 14. A comparison
with the transient response of the arrangement on Fig. 109 shows a less
favourable time behaviour. The control action on temperature #3 is effec¬
ted with a considerable delay.
m
References: [1] [6] [16] [20] [23] [28] [32] [34] [36] [39] [40] [41]
[42] [44] [45] [47] [48] [83] [91] [93] [96] [98] [99] [100]
[101] [118] [150]
for temperature
Fig. 112 Heat exchanger used as correcting element
control.
via a heat exchanger is
The second possibility of controlling temperature
valve which
three-way
the
upon
shown on Fig. 112. The controller acts
the control
on
dependence
in
changes the flow mH of the heating steam
to tempe¬
is
identical
which
deviation. This influences the temperature t?2
diagram
flow
signal
simplified
The
rature #3 , and which is to be controlled.
time
the
by
characterised
delay
(Fig. 113) consists simply of one 1st order
gain:
following
the
by
as
well
constant calculated in equation (50), as
(53)
Afl3
_
CHm ' mHQ - (ÿ40 - ÿ50)
c3 ' m0
1ÿ
heat exchanger
Fig. 113 Simplified signal flow diagram of a
according to Fig. 112.
8.3.5 Level Controlled System in a Drum Boiler
The main problem in setting up a signal flow diagram for a level control¬
led system in a drum boiler can be found in the inhomogeneous contents
of the evaporator and the drum. The filling consists of water at boiling
temperature, pervaded by steam bubbles. Since the volume fraction of
the steam bubbles is quite considerable, the mean specific weight of the
contents is very strongly dependent on the proportion of steam. This, of
course, means that the steam content also strongly influences the level in
the drum. The steam content itself depends, in turn, on the load factor
of the boiler, on the changes in feedwater flow, and on feedwater tem¬
perature.
This is the reason for the famous phenomenon that in spite of an increased
supply of water, the water level initially falls. The phenomenon can be
traced back to the fact that part of the heat has to be used for heating up
the extra feedwater, thus causing a decrease in steam content. This is
followed by a temporary reduction of the total volume of the water/
steam mixture, accompanied by an ebb in the level.
exchanger with
Fig. 114 Transient response of a heat
according to Fig. 112.
by-pass
from Fig. 112. The symbol cHm represents the
The used notation is taken
mean specific heat of the heating steam.
In the case of an increase in fire output more water evaporates; the volume
of steam increases, the water/steam mixture is driven out of the evaporator,
and the drum water level temporarily rises.
Fig. 115 shows the system under consideration. It consists of an economiser, a drum, and an evaporation/circulation system. The individual
symbols have the following meanings:
8.3 Signal Flow Diagrams of Controlled Systems
8 Boiler Control
174
175
water flow, ms, and of the enthalpy downstream of
the economiser, /ise,
on the evaporation starting point, or on the length of
the evaporator, AXV.
Block 5 is the corresponding influence of heating on the length
of the
evaporator. A change in this length causes water expulsion
out of the
evaporator, the time behaviour corresponding to block
7.
ms feedwater flow into economiser
rhsz feedwater flow out of economiser
mD
steam flow out of drum
Qe
Qv
heat flow into economiser
L
level in the drum
ÿSE
enthalpy downstream of economiser
Pw
pressure in evaporator
ms
heat flow into evaporator
m0
h
i
Eco
evaporator
a drum boiler.
Fig. 115 Plant scheme of a level controlled system in
setting up a signal flow
Two separate schemes must be distinguished when
which is the
.scheme
first
diagram for a controlled level system. In the
the boiling
to
up
standard one, water is not heated in the economiser
supercolled
less
or
more
a
in
point, and, therefore, is fed into the drum
so much
receiving
state. The second scheme is based on the economiser
As a
boundaries.
its
within
heat that partial evaporation already occurs
economiser
the
at
steam
result, there is saturated water and saturated
outlet.
feed. Block 1
Fig. 116 demonstrates the first scheme, that of supercooled
evaporator,
the
into
flow
heat
Qv
symbolizes the relationship between the
the
establishes
2
Block
and the water expelled from the evaporator, niwvthe
and
,
rhÿj
drum,
the
into
flow
integral relationship between the water
corresponding con¬
mass of water in the drum, tfVr- Block 3 denotes the
effect of the feedthe
reflect
9
version into drum level L. Blocks 4, 6, and
Fig. 116 Signal flow diagram of a level controlled system
in a drum
boiler, with supercooled drum feed.
Water expulsion can, of course, also be caused by pressure
changes in the
evaporator. This relationship is shown by block 8. Block 10
and 11 re¬
present the economiser, and reflect the time behaviour of
the enthalpy
downstream of the economiser, caused by changes in feedwater flow,
in heat flow, into the economiser.
or
A substantially more complicated signal flow diagram
arises when there
is an economiser with partial evaporation. The complication
is caused in
this case by the necessity to take into account the effects of
feedwater
flow and heat flow on the flow of the saturated water leaving
the econo¬
miser, as well as on the shift of the evaporation starting point.
The
corresponding blocks have already been described in connection
with
Fig. 97. The sum of the outputs from blocks 4, 6, and 8
forms the water
176
8 Boiler Control
8. 3 Signal Flow Diagrams of Controlled Systems
flow downstream of the economiser, and becomes the input signal ms of
Fig. 116.
177
Block 1 .
(54)
Kul =1
(55)
Ku2
m0
1+0
T*
mwT0
xa0 + 0
2
Vn
(56)
*
(57)
Tj.2 =
U0 - V0
T'
r
Block 2:
(58)
Pv
Fig. 117 Signal flow diagram of a level controlled system in a drum
boiler, with supercooled drum feed.
Kx
rh(\
=
-
™wT0
Block 3:
(59)
K3 =1
4
where one half of the dram diameter has been chosen as the related variable
for the drum level.
Blocks 10 and 11 can be dropped, since enthalpy downstream of the eco¬
nomiser corresponds to saturated water enthalpy, and, as a result, is con¬
sidered constant.
For preliminary calculations it is recommended to start with the standard
case, particularly because it has superior dynamic behaviour, and should
therefore always be aimed at.
For this purpose it is expedient to transform the signal flow diagram so
that it will correspond to Fig. 117. In the transformed diagram blocks
9, 10, and 11 have been omitted since the influence of enthalpy down¬
stream of the economiser is of minor importance. On the other hand,
blocks 1 and 7 have been split into two in order to facilitate their mathe¬
matical treatment. Individually, the blocks are calculated as indicated
below, with the inputs and outputs being relative (i.e. per-unit) variables:
Block 4:
(60)
K4
/in - h,sO
,l0 ~ /!s0
Block 5:
(61)
Ks
h0 ~ fh0
»0 - 1ho
Block 6:
(62)
12 Klefenz
rt6
kfr
Z0 »»0 " v0
•
8 Boiler Control
178
8. 3 Signal Flow Diagrams of Controlled Systems
Block 7:
(63)
lTUfji mass
-ÿ7.2 — Zq
T* I1 - Xa0
m0
2
mwTO
FV0
(65)
ÿ
( u0 ~ vo) ' ">0
In
1
( -—
+2
+ÿ
ÿ
\ xa0 +
(1 - Xa0)l>0 +
\
/
Kf
'o - uo
\
/
J *a0
— „
2
*ao\ ,
«*>+(!" — )«*>
3/i' \
3ft"
/
I">DVO ~ + '"WVO 3p I pVO
'
'
mwT0 ' ("0 - fto)
myjV
mass of water in the evaporator
Xa
steam content at evaporator outlet
Z
revolutions per minute
VpR inner volume of the downcomers
xaovo
Block 8 :
(66)
water in the drum
mDV mass of steam in the drum
K1A — Z0
(64)
179
In conclusion, here is the explanation of the characteristic transient response
shown on Fig. 119. The response to a change in the correcting variable may
show a pronounced effective dead time (of the order of 10 to 20 seconds).
Quite frequently the level may even first start to move in the opposite
direction to the one it will eventually take. For example: Following an
increase in the feedwater flow the level may temporarily drop. The less
supercooled is the feedwater entering the drum, the less unfavourable, from
the control point of view, is the time behaviour of this non-minimum phase
system. The behaviour following a raise in the heat flux, i.e. following a
load increase, is quite similar. Here the level temporarily increases, only
to subsequently gradually fall off.
Fig. 118 Transient response.
The transient responses of blocks 7.2 and 8 correspond to the time func¬
tion shown on Fig. 118. For practical application, the actual function can
be substituted by a first order function.
t
Fig. 119 Transient response of a level controlled system
to a correcting or disturbance variable,
in a drum boiler with supercooled feed.
The variables in equations (54) through (66), the meanings of which have
not yet been explained, are:
12*
180
8 Boiler Control
8.4 Signal Flow Diagram of Interacting Control Loops
This effect cannot be compensated by design measures. A good control of
pressure, maintaining it at a pre-set value, is always helpful.
References: [6] [83] [128] [130]
8.4
Signal flow Diagram of a Benson Boiler and a Turbine,
Including Controls
Section 8.3 covered the signal flow diagrams of the individual controlled
systems of a steam generator. In this section, it will be shown on an
example how the partial control systems are coupled together.
The most important controllers are included in the diagram in order to
demonstrate how the control loops interact. A Benson boiler and a tur¬
bine with reheat, feeding a large grid, were chosen to represent a typical
unit. Fig. 120 shows the complete signal flow diagram. AO the five main
control loops are displayed, namely the control loops for steam pressure,
feedwater, main steam temperature, reheat steam temperature, and load.
To simplify the diagram, only one attemperator is assumed for tempe¬
rature control. An expansion to two or three attemperators in series
should cause no problems.
The steam pressure control loop is formed by blocks 18, 19, 13, 24, 27,
32, 34, 31, and 33. The controlled system itself corresponds to Fig. 95,
with blocks 6 and 7 combined into a new block 27, and need not be dis¬
cussed here in detail. Block 31 is the PID steam pressure controller, and
block 33 represents the application of the disturbance signal from steam
flow. The controller is, in accordance with all other controllers, presented
in an idealized form. This is permissible, since in comparison with the
relatively large time constants of the controlled system, it is quite feasible
to neglect the positioning time of the actuator, as well as all the time
constants of the controller.
o3
The control scheme in Fig. 75 has been chosen as an example of feedwater
control. The feedwater controller is represented by blocks 9, 10, 11, and 12.
Blocks 10 and 11 denote the application of the derivative of the tempe¬
rature signal from downstream of the evaporator. In this context, block
11 simulates the dynamics behaviour of the temperature sensor. This is
necessary because in contrast to all other sensors, the time behaviour of
the temperature sensor cannot be neglected. A 1st order delay with a
Fig. 120 Signal flow diagram of a Benson boiler with a reheat turbine
and control.
181
8 Boiler Control
8.5 Quality of Control
time constant of approximately 20 seconds (if thermocouples are used)
is enough for the simulation. With resistance thermometers the time
constant is approximately between 40 and 50 seconds.
frequency fluctuations in the system. In Fig. 120, the deviation from the
required frequency of 50 Hz is denoted by f. As already explained in
chapter 5, the set point Ns is corrected during frequency increases. The
third important variable which brings disturbances into the system, is the
calorific value Hu of the fuel. While there is no need to consider changes
in the calorific value in oil and natural gas fired boilers, it would be a
mistake not to consider them in the case of coal furnaces (particularly
those firing brown coal). The concern is not so much about changes of the
182
The main steam temperature control loop is composed of blocks 16, 17,
23, 26, 22, 25, 28, and 21. The system itself is arranged as in Fig. 107,
while the cascade circuit according to Fig. 66 has been chosen for control.
In the diagram, blocks 22 and 23 represent the temperature sensors for
temperatures downstream of the cooler and at the boiler outlet.
The fourth control loop is the reheat steam temperature control loop,
reproduced by blocks 1, 2, 3, and 5. Block 2 simulates the temperature
sensor, while block 1 is used for the application of a disturbance signal
from the steam flow. In the assumed mode of control the reheat tempe¬
rature is regulated by the flue gas vanes: The position of these vanes is
denoted by Yzd .
The change in the distribution of flue gas affects not only the reheater
(block 5), but also the superheater part. The time behaviour associated
with superheated steam is reflected by block 6. The location where, in
the signal flow diagram, the retroactive signal impacts on the main steam
part, depends on the actual arrangement of the heating surfaces. In the
example in hand, it is assumed that affected is the temperature upstream
of the cooler, !?veThe load control loop is the last of the main control loops to be discussed.
It is formed by blocks 35, 36, 37, and 38. Blocks 35 and 36 represent the
controlled system (see also Fig. 27), while blocks 37 and 38 represent the
control device. Block 35 simulates the proportionally acting high pressure
stage of the turbine, block 36 the low pressure stage which operates with
some delay due to the effect of the reheater. Both outlet signals are summated, giving the turbine power N. yT *s the opening of the turbine inlet
valves.
The steam flow rhD can be obtained from this value (FT) by multiplying
it by a figure proportional to steam pressure P.
The system can be put out of balance by the action of several variables.
Firstly, there is the load set point Ns for the plant, which is being varied
according to a prescribed time-schedule. The actual load must follow Ns
as closely as possible and with a minimum delay. During this operation the
permissible tolerances of the other controlled variables must not be
exceeded. Another variable that can cause difficulties is that resulting from
183
real calorific value, but rather about changes of the so-called unreal calorific
value, which cause quite a few disturbances. The latter include irregular
coal feed caused, for instance, by the bridging of coal in the bunker.
As can be plainly seen from Fig. 120, control of a power generating unit
represents a rather complex multivariable system with many interactions.
As a result, for theoretical examinations, whether aimed at optimization
of control or at the establishment of control accuracy, it is always neces¬
sary to have an exact idea as to the extent the individual control loops
can be considered independent on the total system.
References: [20] [49] [51] [121] [122] [123] [126] [133] [134] [143]
[148] [172] [174] [179]
8.5 Quality of Control
Designing power plant control often involves the choice of design variables
that ensure the desired transient behaviour of the system. In this context
it is of interest to know what maximum control deviation can be expected
following a disturbance, and how the control process is expected to settle
with time.
The desired output is often defined as the best that can be obtained, where
the word "best" can have several connotations mostly denoting minimum
overshoot, minimum settling time, and minimum tendency towards per¬
sistent oscillations. Besides these requirements widely accepted in industry,
there are performance criteria (indices, figures of merit) which attempt to
express quality of control as a single number. These criteria are basically
integral forms of squared error, absolute error, etc., and employ a
weighting factor of some kind. They have the advantage that they can be
easily manipulated in theoretical investigations. On the other hand, they
8 Boiler Control
8.5 Quality of Control
have the disadvantage that the "best" aimed at may not be particularly
suitable as a general index of quality in practice. One of the most useful
among those that have been considered appears to be the so-called ITAE
criterion (ITAE = Integral of Time Multiplied Absolute Error). This
criterion is particularly recommended for cases when the optimisation has
to be based solely on visual observations of the control process.
attached in the preceding chapters to the derivation of the simplest possible
signal flow diagrams for the individual controlled systems.
184
To specify the control quality criterion is not enough. In a multivariable
system it is just as important to specify all the controlled variables which
it is most vital to optimize. In power generation, these are: The boiler
outlet pressure, the main steam temperature, the reheat steam tempera¬
ture, and the electrical power. For instance, it would not be particularly
judicious to specify very narrow tolerances for level control in a drum
boiler, since this would heavily strain the feed pumps. The protection of
the pumps is important enough to warrant allowances for the increased
fluctuations of the water level.
Further, it is necessary to have a clear understanding of the expected dis¬
turbances and manipulating variables, as well as of their development in
time, i.e. whether they are step shaped, of the ramp type, etc. In a power
plant, the dominant disturbance is the load the unit has to produce; there¬
fore, the overall control must be optimised for variable command control
of the load set point. However, this does not exclude some of the control
loops from being preferrably optimised for the effect of particular other
disturbances.
If one considers the complex structure of the signal flow diagram of a
steam generator (see Fig. 120), it becomes evident the dynamic investi¬
gations can be successfully managed only with the help of electronic
computers. Both analogue and digital computers are suitable.
185
There are three basic methods of dynamic analysis. In the first method the
complete unit, i.e. the boiler and the turbine, are simulated on a computer.
This inherently very exacting method is primarily required for very accurate
studies, such as, for instance, for finding or testing a new control concept,
or for the examination of a new boiler structure with regard to its dynamic
behaviour. Such an exacting method would seldom be needed for the
determination of control quality. The second method which is quite fre¬
quently employed, consists of independently simulating the individual
control loops on a computer. Its advantage is that small to medium com¬
puters are adequate for the task, and that it is not too time-consuming.
Naturally, when using this method it is important to be all the time aware
of the effects of simplifications. In assessing control quality, all simplifi¬
cations must stay on the safe side, so that the designer is protected against
unpleasant surprises later on when the plant becomes operational. Further,
it is essential that the main effects of the disturbances on the respective
control loops are realized and appropriately simulated. The third, and at
the same time the simplest method consists of making use of rules-ofthumb and of diagrams, from which the maximum control deviation can
be inferred. With this kind of approach, no data regarding the time
behaviour of the controlled process are, of course, obtainable.
The great advantage of an analogue computer is its high computing speed,
while the digital computer has an enormous capacity allowing an un¬
limited realization of non-linearities. The originally simpler programming
of the analogue computers has recently been overtaken by the creation of
block oriented programming languages for digital computers.
Regardless of the availability of a computer it is necessary to understand
that possibilities are not boundless. Due to the necessary simplifications,
the mathematical model of a physical system is always only an approxi¬
mation of reality. Simplifications are unavoidable, being caused on one
hand by limiations of computing power, and on the other hand by theo¬
retical difficulties. This is the reason why such great importance has been
.20
0
0,4
0j6
V> Tu
Fig. 121 Per-unit (reference) maximum control deviation of the outlet
steam temperature, in dependence on the ratios TJT2 and T/Tu.
8 Boiler Control
8.5 Quality of Control
The respective diagrams have been produced through systematic investiga¬
tion using an analogue computer, while an effort was made to use only the
data already available in design stage. Figure 121 is such a diagram, and it
is intended for use in approximating the accuracy achievable in steam tem¬
perature control. The diagram refers to control of the superheater outlet
temperature by attemperation water flow injected at the superheater inlet
(compare with the control diagram on Fig. 66). On the abscissa is marked
the ratio of the effective dead time Tu to the disturbance time constant
Tz ;on the ordinate the per-unit maximum control deviation. As the para¬
meter distinguishing the curves serves the ratio T/Tu, where T is the
time interval during which the disturbance acts (the disturbance is
assumed to have the form of a ramp function). For instance, for a 20% load
change with a gradient of 5%/min., T would be 4 minutes. Accordingly,
the curve T/Tu = 0 refers to step disturbances. The remaining characte¬
ristic values can be calculated from the already given equations. In this
manner, it is possible to obtain Tu from Fig. 103 after the form factor y.D
had been calculated by equation (29). The disturbance time constant Tz
can be found with the help of equations (36, 37, 38) and the gain Vz from
equation (35). Az is the disturbance expressed in %.
or 48. Strictly speaking, therefore it should be used only for approximate
calculations of drum boilers. Tests proved, however, that if the diagram
is used for forced-flow boilers, reasonably good results are obtained.
186
Similarly, it is then possible to calculate the maximum control deviation
Mmax. It is recommended that such an estimate of the expected quality
of control be obtained at the earliest opportunity, and possibly still in the
design stage of the steam generator. At such an early stage it might still
prove feasible to improve the quality of control by structural changes in
the design of the unit.
The diagram on Fig. 122 is intended for use in approximating the control
deviation in a steam pressure control loop. On the abscissa (x-axis) is
Tu mD ,on the ordinate (y-axis) the
marked the characteristic value
ÿ
per-unit maximum pressure control deviation APmax which is referred to
the disturbance amplitude Az. The characteristic value on the abscissa is
composed of the effective dead time Tu , of the maximum steam flow
%max as well as °f the storage capacity S. Indications as to the way of
determining these characteristic values can be found in sub-section 8.3.1.
Another variable which affects the control quality is the pressure drop
from the point marking the end of saturated steam to boiler outlet. This
variable is introduced as a parameter.
.
The diagram applies only to step disturbances. It has been calculated for
a drum boiler (Fig. 91) with steam pressure control according to Fig. 47
187
Naturally, a special computer study is always preferable, if the effort can
be justified within the framework of the total project, and if the required
technical data are available.
2z
[bar/%]
0
100
200
300
V"Dmax [ s k9/s "I
ÿ
S
[ kg/ bar J
Fig. 122 Per-unit (reference) maximum control deviation of the outlet
steam pressure, in dependence on the characteristic value
Tu- m pmax
S
What can be done if the calculated control accuracy does not meet the
requirements? The dynamic behaviour of a control loop, and, as a result,
the achievable control quality, is given by the time behaviour of both the
controlled system and the controlling instrumentation. This means that
an improvement of control quality can be based on an improvement of
the dynamic behaviour of either component. As for the controller, two
options are available: To adjust control parameters, and/or to choose a
better control scheme. The first point, namely the optimization of the
controller, is a basic pre-requisite for each calculation, and does not have
8 Boiler Control
8.5 Quality of Control
to be considered any further. On the other hand, the second point needs
system to be corrected even before they reach the final superheater. The
basic injection must be sufficient enough (corresponding to several degrees
Celsius) to counteract possible negative temperature deviations.
188
careful checking. An improvement can be often achieved by the choice
of a different control structure, by the inclusion of disturbance compen¬
sation, by the use of auxiliary control loops or of derivative elements,
etc. Should all the possibilities in this respect be exhausted, the only
remaining option would be to improve system dynamics by suitable design
changes on the boiler. There are certain indications that should be held in
mind when designing steam generators. As to what these are, let us con¬
sider the following example: As can be seen from Fig. 121, the effective
dead time Tu should be as small as possible, the disturbance time constant
Tz as large as possible, and the gain Vz possibly small. Fig. 102 shows
that Tu decreases with reduction of the time factor TSR, and equation
(32) provides the information that this factor is decisively affected by the
mass of iron in the superheater.
Consequently, the effective dead time can be decreased by reducing the
mass of iron, i.e. by making the superheater smaller. The same conclusion
can be arrived at from Fig. 103 when equation (30) is used for calculating
the time factor Tr . In order to achieve good control, Tu should not exceed
30 to 40 seconds. The rule-of-thumb in this case is that such favourable
values are achieved whenever the weight of iron (in tons) is kept at or
below 10% of the steam flow (expressed in tons per hour). For instance,
the final superheater of a 400 t/h boiler should not contain more than
40 tons of iron in all.
In general, the reduction of the superheater is accompanied by a reduction
of Vz. As can be seen from equation (35), Vz is proportional to the tem¬
perature raise in the superheater. It can be said that temperature raises in
the range of 30 °C to 50 °C should be aimed at. The disturbance time
constant Tz can be influenced only to a very limited extent, since it is to
a certain degree, fixed by the other two parameters. The largest Tz values
can be achieved with a convective superheater. Should the final super¬
heater consist of both radiant and convective sections, then the convective
part should be located at the outlet.
It appears from what has been said above that large boilers should have
more than one (generally two or three) attemperators connected in series;
this would make it possible to subdivide the superheater into several
dynamically favourable sections.
Further, it is important that enough spray water be provided, particularly
for the final attemperator. This will enable disturbances entering the
189
What has been said applies not only to final steam temperature control,
but also to reheat steam temperature control. Here, however, the attemperation is not desirable due to the loss of efficiency, and heat exchangers
are, from the point of view of automatic control, quite acceptable.
The point to remember is that control is satisfactory only when the heat
exchangers are not located at the cold end of the reheater but rather
towards its outlet, so that the subsequent (intermediate) superheater part
is relatively short. From the dynamic point of view, particularly favourable
are cross-flow heat exchangers where the heating high-pressure steam
flows inside the tubes of a tube bank while the reheat steam flows across
the tubes on the outside. It should be mentioned that a controlled by-pass
on the side of the reheat steam is to be preferred to one on the high-pres¬
sure steam side (compare Fig. 111 and 114).
Good results can be also achieved with flue gas swivel dampers, if the
whole reheater is located in the damper controlled gas pass. During the
installation it is important to make the dampers move with sufficient ease.
Unfortunately, a certain side-effect on the high-pressure surfaces cannot
be avoided, and for this reason, the surfaces have to be arranged in such a
manner as to minimize this effect.
Control which uses either tilting burners or flue gas recirculation is to be
avoided, primarily because of the above mentioned undesirable side-effect
on high-pressure steam surfaces.
As regards the steam pressure control system, it follows from Fig. 122 that
control improves with the reduction of effective dead time Tu and with
the increase of storage capacity S. Satisfactory results can be achieved with
effective dead times of up to 30 seconds. The dead time depends on the
time behaviour of the mills, as well as on the time behaviour of steam ge¬
neration. Particularly suitable are high-speed beater mills with a negligible
circulation storage in the mill and in the classifier. The apparent effective
dead time of sluggish mills can be reduced by suitable control of pressure
in the classifiers, i.e. by activating the coal dust deposited in the mill. Of
course, conditions must be such as to permit a sufficiently high pressure
change.
190
8 Boiler Control
Using mixed fuels the fastest possible firing process (for instance, the
burning of gas or oil) should be chosen for control, while coal firing should
be reserved for base load firing.
The time behaviour of steam generation can be influenced by arranging
the burners with respect to the evaporator. The fire in the furnace must
be situated so that it fully sweeps the evaporator surfaces; a fire that
strikes too high is as damaging as were the formerly common residual
evaporators.
The drum boilers have, due to their substantially higher storage capacity,
a certain advantage over the Benson boilers. In this respect, the forcedflow boilers with superimposed recirculation fit somewhere between the
two.
Storage capacity is determined by boiler design, and cannot be chosen at
will. It has been noted that high-pressure units have the disadvantage of
a lower storage capacity than low-pressure ones.
Before concluding attention will once again be drawn to the necessity
of perfect control of combustion air. This implies the availability of a
good flow measurement as well as the application of forced-draught and
induced-draught fans with inlet guide vane control. If mixed fuels are
burned, it is important to make sure that there is an independent control
system for combustion air flow for each fuel.
The above list of tips on enhancing control could be expanded further,
were it not for space limitations which prohibit the inclusion of more
material. Let us only emphasize the importance of securing the coopera¬
tion of a control engineer already in the planning stages of a power plant
project.
References: [43] [48] [52] [74] [83] [109] [168] [183] [193] [200]
[205] [217] [218] [231] [246] [253] [254] [255] [256]
[284] [285] [294] [310] [311] [321]
9 Combined Heat-and-Power Plant (CHP Plant)
Combined heat-and-power plants are also known as CHP plants, combined
district heating plants, cogeneration plants, etc. This chapter will deal with
such kind of control in these plants as does not come under the heading
of standard boiler control.
The characteristic of a combined heat-and-power plant is that heat is pro¬
duced simultaneously with electrical energy from a single fuel source. This
means that in contrast to pure heating stations there is an important
coupling between electricity and heat production. Thermal energy is pro¬
duced primarily for heating purposes and for providing hot water. Heated
water is used as the preferable heat-carrying medium, unless situations
arise where the consumer acutally needs steam or where the use of steam
is more economical. (Compare with section 2.2: Common range arrange¬
ment with the supply of process steam.) In general, the design exit (or
outflow) data for supply water are 2-10 bar and 80-150 °C. The circu¬
lation water flow is kept approximately constant, and is reduced only
when the minimum exit temperature of the supply water has been reached.
The return water temperature should be kept as low as possible in order
to keep down the cost of heat production for a given number of consu¬
mers, as well as transportation costs (minimum pipe size, water flow rates,
and pumping costs). The aim is to achieve a return temperature of water
not exceeding 50 °C.
Either back-pressure or condensing steam turbines can be used. In the
currently no longer popular simple back-pressure mode, the produced
electricity depends totally on the heat load; the less heat is used by the
consumers, the less electrical energy is produced. This unwanted feature
can be overcome by the application of extraction back-pressure turbines
(i.e. condensing turbines with controlled extraction pressure). These are
more versatile than other types, and can be loaded to full throughput
capacity independently of the demand on heat production. Ideally, the
turbines would be back-pressure/pass-out machines with a condensing
section.
CHP plants have very complex and variable possibilities of design too many
to be dealt with in detail in this book. Fortunately, as regards control this
does not appear to be such a serious handicap, since the actual control loops
9 Combined Heat-and-Power Plant
9 Combined Heat-and-Power Plant
are relatively simple and constantly recurring. The main control objective
is to regulate the exit temperature of the supply water so that the water at
consumer location is always available at as high a temperature as required.
is adequately supplied, a minimum pressure difference at the furthest index
point is maintained so that in accordance with the control deviation a pres¬
sure difference controller acts on the speed of the water supply circulating
pump (or pumps).
192
To this effect the set point has to follow a command signal derived from
the ambient temperature and wind velocity, as well as from the heat re¬
quired in dependence on the time of the day, and the distance/velocity
lag of the heat transfer between the places of production and consump¬
tion. Further, the pumping system (consisting of circulation pumps,
booster pumps, etc.) must be controlled so as to provide a sufficiently
high pressure at the furthest index point of the hot water grid by over¬
coming the delivery resistance head, in other words to safeguard the
supply. To this effect, either a) the pressure in a location directly up¬
stream of the consumer is measured and maintained at a constant value,
or b) the outgoing pressure head at the power station is controlled, with
adjustments of the set point used to equalize the pressure drops in the
piping system. However, in a system with mains of different lengths going
to different parts of the system, this may not be enough to provide the
necessary heat flow in an awkward consumer location. If the network
topography is unfavourable, for best results it may be necessary to main¬
tain a minimum pressure drop across the heating equipment of the respec¬
tive consumer (see A p in Fig. 123). Such a pressure difference could be
measured directly at the location in question, but only if its value is not
affected by changing operating conditions. In the latter case, differential
pressure measurements should be taken at a number of consumer points
particularly near the tail end of the piping system. Automatic control then
maintains constant the lowest value obtained with the help of a minimum
selector. It is advantageous if the lay-out of the district heating plant is
such that the circulating water flow is not subject to wide variations,
making consideration of changes in dead time unnecessary.
193
Fig. 123 Control scheme of a remote heating part of a district heating plant.
NS
i
Fig. 123 illustrates a possible scheme for the remote (heating) part of a
CHP plant, containing the essential control loops. For the sake of clarity
the lay-out is simplified; only one heat exchanger is marked in each loop
while, in reality, there may be two or three connected in series. Also
omitted are such components of the plant as storage tanks and equalizing
tanks, connecting pipework, etc. The diagram includes two closed water
flow systems, the lower one for hot tap water supply, the upper one for
heating. In the hot water loop the outflow supply water temperature Dw
is kept constant. To this effect, automatic control adjusts the flow which
by-passes a heat exchanger. In order that even the most remote consumer
Fig. 124 Control scheme of a district heating plant.
13 Klefenz
194
195
9 Combined Heat-and-Power Plant
9 Combined Heat-and-Power Plant
A further controller acts upon the speed of the return pump(s), thus
keeping the absolute pressure P constant. (In no part of the return water
main must the pressure exceed the value given by the design pressure
condition of consumer heating equipment.)
Feedforward signals from disturbances are not required because the change
of the disturbance variables is usually very slow. Real difficulties may only
be expected with the thoroughly coupled control loops for pressure and
for pressure difference. But even these can be mastered by careful opti¬
mization of the controllers. These should be adjusted in relation to each
other. Should there occur considerable fluctuations of the flow of water
through the heat exchanger, it is necessary, in order to maintain a con¬
stant control loop amplification, to ensure that the controller gain changes
in dependence on these fluctuations. Since the gain of the controlled
system rises with a decreasing water flow, the controller gain must, in
this situation, decrease.
One part of the water flow branches out at the outlet of the first heat ex¬
changer (which is the lower one in Fig. 123), and by flowing through the
second (higher) exchanger is brought to the temperature needed for
heating purposes. This temperature is not kept at a constant value, but is
made variable in dependence on outdoor temperature. Among the possible
variants of water temperature control for this type of plant, the one selected
for the example uses the flow of bled steam (extraction steam) into the heat
exchanger. All heat exchangers are naturally equipped with condensate
level controls which take care of the removal of the condensate. This
control is, however, not shown. In order to safeguard the supply of hot
water even for distant consumers, the pressure differences are again kept
constant by the variation of the speed of circulating pumps.
A third, and at the same time a rather common variant of the exit water
temperature control, is based on controlled accumulation of the conden¬
sate in heat exchangers. It is obvious that in this variant there cannot
operate a condensate level controller. Instead, the temperature control
deviation acts directly on the condensate drain valve via a separate con¬
troller. If the temperature is too high, the drain valve throttles quite sub¬
stantially. This causes the condensate level to rise; this in turn diminishes
the heating surface, and reduces steam condensation. Eventually, a new
equilibrium state with a higher condensate level is reached, this being in
agreement with the reduced heat requirements.
Pressure in the mains network can be also maintained by establishing a
steam space over the surface of the water in one of the equalizing tanks.
The necessary steam is obtained from a reducing station connected to a
suitable section of the steam line, and the steam influx is controlled so
as to maintain pressure in the water grid.
Depending on the plant concept, other temperature and pressure control
loops can be used. If secondary grids are in operation, which is typical
for indirect systems, booster and conversion stations should be installed
between the CHP plant and the consumers. However, none of the control
loops in remote heating plants cause any insurmountable difficulties,
and, in general, proportional-integral controllers are quite satisfactory.
In general, there is no need to simulate these control loops. Should the
need unexpectedly arise, the problems would be broadly similar to any
heat exchanger problems. The methods with which the respective solutions
could be attempted were discussed in sub-section 8.3.4. As for the calcula¬
tions relating to heat exchangers controlled by condensate accumulation,
it is necessary to refer the reader to specialised literature.
In a heat-and-power plant the production of electricity and the remote
heating process ififluence one another. Following an increase of the power
set point, the power controller ensures that the turbine produces more
power by opening the nozzle valves. Simultaneously, more heat is supplied
for district heating, causing the temperature controller to act in the oppo¬
site direction. Conversely, an increase in heat supply to the district heating
system is followed by an increased production of electrical energy. It would
therefore be appropriate to isolate the two coupled control loops, pos¬
sibly by the application of measures shown in Fig. 124. Let us imagine
that following an increased demand the energy controller causes nozzle
valves to open. In such a case, the proportional element 1 would some¬
what throttle the extraction steam. On the other hand, should more heat
be needed, then not only more extraction steam would be let in, but
simultaneously the proportional element 2 would open the nozzle valves
wider. It can be said that this principle, with suitable variations, is appli¬
cable to other variants of heat-and-power plant control.
References: [3] [27] [83] [91] [92] [93] [185] [187] [234] [247] [281]
[299] [307]
13*
10.1 Types of Reactors
10 Nuclear Power Plants
This chapter concerns the essential differences between the automatic
control of nuclear power plants and that of conventional power plants.
The starting point to be dealt with is the assumption that the only diffe¬
rence between these plants is simply in the firing; that nuclear fuel is
'burned up' in one and fossil fuel in the other. However, from the simple
fact that it is either chemical energy or nuclear energy that is converted
into thermal energy, appreciable differences originate between the two
kinds of plant. The plants differ in design as well as in time behaviour,
which necessarily affects control.
A substantial dissimilarity appears to exist already in the storage of fuel:
While 'fuel' is stored in the reactor over the years, it has to be continuously
brought to the conventional boiler. When, in addition, one realizes that
the release of nuclear energy is possible in fractions of seconds, it becomes
evident that with nuclear plants precautionary technological measures
must be implemented and these affect both design and control. Moreover,
in a conventional plant the fuel is supplied for combustion in a gaseous or
quasi-gaseous state, and is burned in a relatively large furnace. On the other
hand, in the reactor, energy is released in the solid fuel, and that in a very
small volume. In fossil fuel fired boilers the heat transferring medium is the
flue gas which is at high temperature and low pressure, while in a nuclear
generator gas, water, and even liquid metal find application, and are used
under various pressures and temperatures. This is another reason why the
actual steam generator in a nuclear power plant bears so little similarity
to the conventional boiler, the only exception being the gas-cooled reactor.
Steam generators for other reactor types deviate from tradition, and ac¬
tually are heat exchangers.
References: [187] [188] [203] [223] [265] [277] [280] [286] [290] [308]
197
doubt, from the economic point of view the most important is the lightwater reactor (LWR), which comes in two versions, namely as a boilingwater reactor (BWR) and as a pressurized-water reactor (PWR). The
simplified plant diagrams of the two types are shown in Fig. 125 under
a) and b). In a nuclear power plant using a boiling-water reactor, the
steam produced is directly conducted to a saturated steam turbine. The
plant is therefore of a single-loop type. In a pressurized-water reactor,
on the other hand, a two-loop system is necessary. Here the required
saturated steam is produced in one and possibly more heat exchangers.
a) boiling-water reactor
£
-©
i®
¥
£
b) pressurized-water reactor
-©
c) gas-cooled reactor
-©-
Fig. 125 Fundamental structure of a nuclear power plant.
10.1 Types of Reactors
An attempt to list here all the possible types of power reactors would be
too involving. Instead, the types that will be dealt with are only those
that have already gained some prominence in operation. Without any
Gas-cooled reactors must be mentioned next, and, particularly, the two
main designs. The first design (GCR, AGR, HWGCR) uses carbon dioxide
for cooling. Due to the limited core gas outlet temperature, saturated steam
must be produced in a heat exchanger, exactly as in the already described
pressurized-water reactor. The second design (HTGR, AVR, THTR) covers
the so-called high temperature reactors where helium is used as the cooling
10 Nuclear Power Plants
10.2 Control in a Nuclear Power Station
gas. The substantially higher gas temperature makes it possible to produce
superheated steam in a forced-circulation once-through boiler (see Fig.
125c).
of water circulating in the reactor. An increased circulation diminishes
the volume of bubbles and therefore increases reactivity. However, water
circulation serves as the correcting variable only in the upper load range
(above 60%). In the lower load range, the insertion or withdrawal of
control rods are used instead. Further, it is necessary to control the level
L in the reactor vessel. This is performed by three-element control which
is sufficiently known from applications in conventional plants.
198
Finally, attention should be drawn to the research and development pro¬
gramme in the so-called fast breeder reactors (FBR). It remains to be seen
how successful this type will become. Currently, a fast breeder is cooled
by liquid sodium, which necessitates three heat transport systems con¬
nected in series (primary and secondary coolant circuits plus steam circuit).
199
10.2 Control in a Nuclear Power Station
Discussion of the basic properties of control in a nuclear power plant will
be limited to the three reactor types introduced in section 10.1. Since
nuclear power plant control is a relatively new science, the control designs
that are being applied in practice may differ from the designs correspon¬
ding to the guidelines given below.
Fig. 126 shows a control scheme of a boiling-water reactor. The plant is
equipped with a turbine with controlled inlet steam pressure. Steam pro¬
duction is governed by load control. At first glance the diagram looks
like a retrograde step in comparison with conventional power plants.
However, the justification for such an approach becomes clear once
allowance is made for the speed with which steam production changes,
following the adjustment of the correcting variable (which in this case
happens to be either the throughput of the circulating water, or the in¬
sertion or withdrawal of control rods). The speed of steam production
in a boiling-water reactor is of a higher order of magnitude (steam is pro¬
duced in just a few seconds) than in coal fired steam generators. In ad¬
dition, it is possible to fully exploit the advantages of controlling steam
pressure upstream of the throttle valve. This makes it possible in a
boiling-water reactor to keep steam pressure very accurately constant,
which is particularly important in neutralizing the effects of pressure
fluctuations on chain reactions in the reactor, and subsequently on the
production of power.
The controls work as follows: On changing the set point for electrical
energy N$ , or that for the variation of grid frequency f, a PID controller
changes the set point of the steam flow controller. In its turn, the steam
flow controller governs the speed of the pumps thus changing the flow
Fig. 126 Fundamental scheme of a nuclear power plant
with a boiling-water reactor.
Outside these main control loops there are naturally many subordinate
loops, as well as various limiting and blocking circuits. The scope of this
discussion does not call for their detailed explanation.
The next point are the principles of control of a pressurized-water reactor
power plant. Its control scheme is shown on Fig. 127.
The turbine, as in a conventional plant, is equipped with load control in¬
corporating the effect of grid frequency.
The required reactor load in the upper load range (above 50% MCR) is
controlled by the control rods in such a manner as to keep the average
temperature of the cooling agent, i\m , constant. (The average tempe¬
rature being the average of the inlet and the outlet temperatures.) This is
as follows: When the turbine increases the withdrawal of power from the
steam generator, the average temperature of the coolant drops, and the
reactor is stimulated to a higher power production by the repositioning
of control rods.
200
10 Nuclear Power Plants
10.2 Control in a Nuclear Power Station
201
The third kind of reactor is a helium-cooled high-temperature reactor. Its
control is illustrated by the basic scheme on Fig. 128. The turbine load
is again controlled in the already familiar manner.
---
-0
czO
boric acid
demineralized water
Fig. 127 Fundamental control scheme of a nuclear power plant
with a pressurized-water reactor.
Control rods are kept within the control range by additions of boron,
or demineralized water for chemical shim control, which are in turn
measured out by a separate controller. The introduction of small amounts
of these chemicals into the coolant or the moderator influences reactivity.
This has the same effect as when the so-called shim rods bring reactor
power approximately to the specified level.
A side-effect of keeping the average temperature of the cooling agent
constant is that both steam pressure and steam temperature decrease with
the increasing load. However, this does not apply to loads below 50%,
where the average coolant temperature is reduced in a manner which
allows for steam temperature and steam pressure to remain constant.
Another controlled variable in the pressurized-water reactor is the pres¬
sure Pic of the coolant. It has to be kept within narrow limits since boiling
must be prevented at all cost. A heated pressurizer is connected to the
reactor coolant loop to make the task easier. As to the control itself, there
are three control variables which act in sequence. These are: The heating
of the pressurizer by an electric heater, the cooling of the pressurizer by a
cold auxiliary spray, and the releasing of gas from the pressurizer via a
release unit. The level L in the pressurizer is kept constant by controlling
the volume withdrawal from the cooling loop.
r
Fig. 128 Fundamental control scheme of a nuclear power plant
with a high-temperature reactor.
The flow of the coolant through the reactor embodies the control variable
for the steam pressure PD. A negative deviation of this pressure from the
set point causes an increase in the speed of the helium blower. The set
point for the neutron flux 4> is adjusted by a signal derived from the steam
temperature $d : it may lead to a corrective action of the control rods.
The helium temperature #k at the outlet of the steam generator is kept
constant by control action on the feedwater flow ms- This control
simultaneously maintains gas pressure.
A feedforward disturbance signal from the load set point is sent to the
feedwater control as well as to the neutron flux control and the steam
pressure control. Other aspects of control need not be discussed since the
boiler in question is a Benson boiler and its control has been fully covered
at an earlier stage.
Due to gas temperature being sufficiently high, superheated steam is pro¬
duced in the boiler. The relatively high gas temperature (approx. 750 °C)
makes it possible to use a reheater. This is not shown in Fig. 128, since
the pertinent reheat steam control offers nothing new.
10.3 Dynamic Behaviour of Nuclear Reactors
10 Nuclear Power Plants
202
Xj
10.3 Dynamic Behaviour of Nuclear Reactors
For analytical treatment of control problems in a nuclear power plant it
is necessary to have a mathematical model of the nuclear reactor. In
contrast to the conventional steam generators fired with fossil fuels, where
combustion processes as well as supply processes (such as milling of coal,
etc.) can only be conceived with difficulty, nuclear desintegration (i.e. the
release of energy) can be exactly described by equations. Reactor kinetics
are generally so complicated that they can best be described by time- and
space-dependent differential equations. However, for simplified controltechnological investigations it appears sufficient to perform the calcula¬
tions independently on spatial coordinates, i.e. independently of the con¬
figuration of the reactor. If this approach is adopted, then ordinary diffe¬
rential equations (67) and (68) can be used to describe the time dependent
behaviour of the neutron density n. In the context of control, the neutron
density is representative of the neutron flux <f>, i.e. of the released heat
energy:
£
(67)
-
fe(l -Ifc)-1 T1 + 2
J
i
i
Xi -Cj+S,
- Vcj.
(68)
production rate of neutrons
k
effective multiplication factor
I
effective lifetime of a neutron = mean time for a neutron to
be removed from the reactor
ft
fraction of delayed neutrons of the f-th type = fraction of
precursors of the f-th type produced in fission, compared to
the total production of prompt neutrons and precursors of
all types
;
removal rate of neutrons
Ci
number of precursors of the f-th type (varying in time)
m
number of precursor types = number of delayed neutron
Although there are approximately 20 types of delayed neutrons, generally
only six are distinguished. For automatic control investigations it is even
sufficient to combine the six types into a single one. This approach will
be used in the following text, particularly since it also improves the clarity
of the treatment. It should be emphasized that the simulation of all six
types would cause no difficulties. The condensation of the m types is
described by the following equations:
m
independent source rate
0= 2ft,
(69)
t
=
X-
(70)
p
n
m
Customarily, the reactivity p is used in place of the multiplication factor.
The relationship between these two parameters is given by
P=k-
The steady state of a reactor when the neutron density n remains constant,
is characterised by fe = 1, and p = 0. The steady state is also known as
'critical'. This is why reactors are classified as sub-critical and super-critical,
the definitions being as follows:
k < 1 sub-critical reactor
p = negative
k = 1 critical reactor
p = 0; chain reaction is sustained
k > 1 super-critical reactor
p = positive
It follows that in practice k must always be approximately equal to one.
As a result, also l/k ~ I, and equations 67 and 68 change to:
(72)
types
S
mean decay rate of precursors of the f-th type (in each group
the precursors decay exponentially with a characteristic halflife that determines the rate of emission of delayed neutrons).
(71)
Here the symbols are as follows:
203
(73)
f=
£=
n + X- c + S,
X c.
ÿ
204
10 Nuclear Power Plants
10.3 Dynamic Behaviour of Nuclear Reactors
205
These two equations completely describe the neutron kinetics. A repre¬
sentation in the form of a signal flow diagram is shown on Fig. 129. The
input variables into the system are the reactivity p and the independent
source rate,S. The neutron density n is the output variable.
The signal flow diagram on Fig. 129 will be used in discussing the time
behaviour of the neutron density n for the various operational modes.
t
a) The independent source plays a vital part during start-ups.
Fig. 130 Transient response of neutron density
in a sub-critical reactor during start-up.
1 . decrease of the negative reactivity
2 . . increase of the negative reactivity
.
Equilibrium before the change :
(74)
p0
. n0 + S -1= 0.
Equilibrium in the first instant after the change:
(75)
(p0 + Ap) • (n0 + An) + S I - (1 An =0,
ÿ
ÿ
It therefore follows that:
(76)
T=i
Fig. 129 Simplified signal flow diagram of neutron kinetics.
If the reactor is sub-critical, with p a negative value, then it behaves,
following a step change in reactivity, as a proportional module. A very
fast change at the beginning is followed by a considerably slower approach
to the new steady state. An explanation based on the signal flow diagram
is very simple.
In the original steady state the variables p0 • n0 and S- Iare in equilibrium,
since, due to the factor k = 0, the feedback shown in the lower part of
Fig. 129 is nil. A change in p0 by the small amount Ap, while p remains
negative, is followed by a very fast change in n. The amplitude of this
change, An, is determined by the sum of the two negative feedbacks
existing in the first instant, and can be calculated as follows:
A"
-Ap.
The very fast rise of An is called the 'prompt jump', since it is based ex¬
clusively on the prompt neutrons. The delayed neutrons, or, more pre¬
cisely, the neutrons originating with a delay, do not yet participate.
The prompt jump is followed by a much slower change in neutron den¬
sity. The slowing down is caused by the fading away of the feedback with
, which acts via the factor j3.
A
The new steady state is then once more described by equation (74) with
the time constant
p0 and riQ replaced by the new values px and /ij .
b) The independent source can be disregarded once the neutron density
leaves the start-up range. Three ranges have to be distinguished depending
on the magnitude of the reactivity p. According to the signal flow dia¬
gram, a negative reactivity step, applied to a steady-state for which p = 0,
initially leads to the behaviour described in a) as the prompt jump. This
is then followed by a slow decrease to nil, the speed of the reduction
being determined by the fading feedback. It is evident that them is no new
equilibrium at fixed level of neutron density (see Fig. 131).
10 Nuclear Power Plants
206
c) The application of a positive reactivity step for which, however,
10.3 Dynamic Behaviour of Nuclear Reactors
(78)
T, =ÿf
(79)
t2=-
Ap<0,
makes the reactor super-critical. It can be deduced from the signal flow
diagram that at first there must occur a prompt jump corresponding to
equation (76). This is so because the positive feedback (the upper path
in Fig. 129) and the negative feedback (the lower path in Fig. 129),
counteract each other, the increment An Ap being smaller than the in¬
crement An 0 of the negative feedback. At first, it appears that the
tendency is to reach a new steady state.
ÿ
ÿ
r
Ap
__
—
-_
Ap = 0
Ap < 0
Fig. 131 Transient responses of the neutron density
with a negligible source.
However, this stage is soon followed by a permanent rise in the neutron
density (see Fig. 131), which increases as the negative feedback fades
away, i.e. as the delayed neutrons become active. After all, the fact that
it is at all possible to come to grips with the control of nuclear reactors
can be attributed to the phenomenon of delayed neutrons. Of course, if
these neutrons are to be made use of, it is necessary to ensure that Ap is
never larger than 0 (see also paragraph d).
An approximate solution of equations (72) and (73) in the time domain
reads as follows:
with
n(t) =
It can be seen from equation (77) that the transient response consists of
a quickly fading part together with a slowly exponentially rising part.
The rise is characterised by the so-called reactor period Tl , which is the
amount of time a reactor takes to change its neutron level (i.e. its power
output) by the factor of e = 2.718.
An approximate solution in the frequency domain leads to a transient
response described by the following equation:
> |3
p > Ap > 0
(77)
207
jÿ-p ((].et/Tl -p e" r/7"a)
•
m
/om
*5<i> = _?0_
*•«ÿ»
K)
(ÿÿ**»•)
'
It is obvious that equation (80) represents a PI transfer element with a
1st order delay. This means that for approximate calculations, the si¬
mulation according to Fig. 129 can be replaced by a simple PI function.
d) If the change in reactivity exceeds 0,
AP > 0,
then the delayed neutrons no longer play a part in sustaining the chain
reaction. The reactor is supercritical solely because of the prompt neutrons.
This state is called prompt supercritical. As can be seen from the signal
flow diagram (Fig. 131), the neutron density rises both exponentially and
very quickly, since the positive feedback strongly predominates. The
reactor period then amounts to:
(81)
Ty = L.
Control technology is no longer adequate for keeping the reactor under
control. As a result, this operating range has to be avoided at all cost.
A comparison between the time behaviour of the 'firing' in a nuclear
reactor and the time behaviour of the conventional firing in a boiler,
highlights two basic features of the reactor. Firstly, the reactor responds
to a command signal (change in reactivity) by a step load change, i.e.
immediately and without effective dead time.
208
10 Nuclear Power Plants
Secondly, the increase of load is astatic (there is no self-regulation).
-<ey
—
T =1
QK =P
1_
/
K = aR
tb. kb
10.3 Dynamic Behaviour of Nuclear Reactors
increased or decreased by the already described feedbacks, depending on
the sign of the partial reactivity coefficients aM , aB, etc. In general, the
time behaviour of the feedbacks can be simulated by delay elements of
the first order with time constants TM , TB , etc. However, the admissibi¬
lity of such a simplification must be considered in each and every case.
As an example, let us approximately calculate the transient response of
the inner feedback based on the temperature of the moderator. A liquid
moderator in the reactor core, with a volume of VM, has a constant input
and a very small but constant flow mM - If the mo¬
temperature of
derator is thermally well insulated from the reactor parts, then the average
(= arithmetic average of the inlet and outlet
moderator temperature
temperatures) which determines the reactivity, is determined solely by the
absorbed radiation energy per time unit. The latter is again proportional
to the reactor load, in other words, to neutron density. This leads to the
following equations:
5
(82)
Fig. 132 Simplified signal flow diagram of a nuclear reactor
in operating range.
209
ÿ
Kn-n=mM (hMa - hMe) + VM Pm cM ÿ ,
p = aM •
(83)
•
ÿ
ÿ
•
.
where:
On the one hand, there is a very good response to a change in the command
signal; on the other hand, the danger persists that a failure of the control
system or an error by the operator, can cause the released energy to in¬
crease extremely quickly and out of all bounds. Such a danger has to be
nullified by an extensive safety system. In addition, the following circum¬
stances may be of help: Once reactors reach the so-called load range, the
increased heating manifests itself by the appearance of thermal feedbacks
that are generally negative (most power reactors have negative temperature
coefficients). This changes an astatic system into a static one. Besides the
thermal feedback from the fuel, the coolant, and the moderator, it is also
possible to distinguish feedbacks caused by changes in the pressure and in
the volume of bubbles. (Note that pressure coefficients are usually posi¬
tive, and refer to pressure changes in gas-cooled reactors. The void coeffi¬
cients, which are usually negative, refer to bubble formation in the
boiling-water reactors, and to voids in the sodium-cooled reactors.) The
inclusion of the above features extends the signal flow diagram. The new
structure is shown on Fig. 132. The input variable of the system is now
the reactivity ps as determined by the regulating rods. It can be either
Kn • n total energy released from fission, per time unit
5
fraction of the fission energy released in the moderator
mM
ÿMa
moderator flow
moderator enthalpy at the outlet
ÿMe
moderator enthalpy at the inlet
Vm
moderator volume
Pm
moderator density
cm
average true specific heat (heat capacity) of the moderator
ÿMa
moderator temperature at the outlet
#Me
moderator temperature at the inlet
average moderator temperature
"M
14 Klefenz
moderator temperature coefficient of reactivity
211
10Nuclear Power Plants
10.3 Dynamic Behaviour of Nuclear Reactors
If the aim is to find the deviation from steady state, equations (82) and
(83) will change into:
As has been discovered by observation, the inner feedbacks have still
another favourable effect which can be stated as follows: In a reactor
without any inner feedback (pure neutron kinetics) the system gain
would be proportional to the level of load, i.e. to the neutron density.
However, the thermal feedback makes the system gain practically inde¬
pendent of load level, so that the gain of the controller may also stay
constant.
Finally, the following list of the orders of magnitude of the individual
parameters which appear in the signal flow diagrams, should make it
easier for the control engineer to obtain a numerical idea of the dynamic
process in the reactor. However, should investigations concentrate on the
behaviour of a specific reactor, then the characteristic values pertinent
to the particular plant must be established. This is necessary due to the
unfortunate pronounced scatter of characteristic values from one reactor
to another.
210
(84) 5
(85)
ÿ
Kn An = mM . cM (Afla - Ai?e) + VM Pm cM
ÿ
•
ÿ
•
dAiSM
ÿ
df
Ap = aM • Ai?m .
When combining equations (84) and (85), Laplace transformation leads
to a transient response of the type
(86)
rsp (s)
An (sj
_
~ <*M
1 + 7m ' J
This is a delay element of the first order, with the following characteristic
values:
(87)
6
Km = 2 cM mM
ÿ
(88)
_ PM
Suggested approximate values:
ÿ
•
Km ~ 2 mM
•
lmax
The inner thermal feedbacks which occur in the operational range funda¬
mentally change the transient behaviour of the reactor. Since in the power
plant reactor the sum of all these feedbacks has a negative sign, the
system without self-regulation, i.e. the astatic system (see Fig. 131),
changes into a system with self-regulation, i.e. a static one (see Fig. 133).
This self-stabilizing effect to a considerable extent facilitates control. In
addition to these inner feedbacks there are cooling loops with their heat
exchangers or steam generators, which act as further feedbacks and also
bear a stabilizing influenze.
[Lcm
ne2Utsr0"S 1J
cm
ÿmaxÿlO13
•
_
10 i
r neutrons 1
[neutrons
J
cm3
• s
p > ap > o
0
r-3
« 7,5 -10-
l
«10-3
X
« 8 • 10-2 [s-1 ],
aM
= - 2 10 4 [grad
aB
Fig. 133 Transient response of the neutron density of a nuclear
reactor in operational range.
neutrons
3
cm
io8
•
[s],
1
]
- 2 • 10 5 [grad '].
References: [6] [31] [89] [91] [110] [111] [170] [173]
14*
11.1 Symbols
11 Appendix
11.1 Symbols
The following list contains the most frequently used signs and notations.
Importance has been attached to adhering to the symbols that had al¬
ready been introduced in technical literature. However, this has made it
unavoidable for some symbols to cover two variables. Since the symbols
are always used in different areas, a mistake is barely possible.
n
neutron density (nuclear reactors)
N
power, energy
P
pressure
Q
selfregulating factor, reciprocal gain
Q
heat flow, heat flux, heat flow rate
r
latent heat
s
Laplace transform operator
S
storage capability, capacity
S
independent source rate (nuclear reactors)
t
time
T
time constant
c
specific heat
c
concentration of precursors (nuclear reactors)
f
frequency
area
Tu
T,
effective dead time
F
h
enthalpy
u
voltage
H
position, lift
V
specific volume
i
electrical current
V
volume
I
mass inertia moment
V
gain, amplification
k
heat transfer coefficient
V
volume flow
k
multiplication factor (nuclear reactors)
proportional band
K
constant
I
effective lifetime of a neutron
XP
*Va
*Ve
end point of evaporation
L
m
level
y
valve position
mass
z
number of . .
m
mass flow
Z
revolutions per minute (rpm)
m
Nusselt exponent
3
impedance
m
number of types of precursors (nuclear reactors)
a
heat transfer coefficient
n
speed
a
fraction, factor
build-up time, rise time
starting point of evaporation
213
11Appendix
214
11.1 Symbols
215
moderator-temperature coefficient (nuclear reactors)
O
oil
T
turbine
P
P
factor
s
set point, set value
th
thermal
fraction of delayed neutrons (nuclear reactors)
S
feedwater
u
circulating water
7
factor
S
saturated steam
0
nominal state, original
S
factor
S
classifier
A
deviation, difference
A
deviation from original value or state
d
temperature
0
absolute temperature
steady state
adiabatic exponent = ratio of specific heat at constant pres¬
sure to that at constant volume
D
form factor
X
mean decay rate of precursors (nuclear reactors)
p
density
p
reactivity (nuclear reactors)
<f>
neutron flux (nuclear reactors)
X
steam content
The graphical symbols applied in the diagrams were taken from the DIN
Standards No. 2481 and 19 226, and from the VDI/VDE Guideline No.
3527. In addition, the following have been introduced:
f
ED
controller; marked is the dynamic
transfer behaviour
P proportional element
I integral element
D derivative element
Suffixes
a
output
G
gas
B
fuel
K
coal
D
steam
K
coolant
e
input
L
air
E
iron
LP
primary air
E
spray (attemperation) water
LS
secondary air
F
furnace
m
mean, average
/
/-
controller; marked is the static
transfer behaviour
ratio adjuster, bias
multiplier
set point setter
11Appendix
216
With regard to control schemes the direction in which the signals operate,
i.e. the directional flow of the signals, is made easily recognizable by the
application of signs. The following rules apply:
+
A rising signal or a rising measured value cause the control
element to open, or the command signal to rise.
—
A rising signal or a rising measured value cause the control
element to close, or the command signal to decrease.
11.2 Bibliography
[1]
Acklin u. Laubli, F.: Berechnung des dynamischen Verhaltens von Warmeaustauschern mit Hilfe von Analogrechengeraten.
Techn. Rundschau Sulzer, Forschungsheft I960 Dampfkesselbau.
Example:
X,'
V
-(s
I
Gil
i.
i
ojo
If Xi rises, the command signal x2
decreases.
If the set point is increased, x2 rises
as well.
If the command signal x2 rises, the
valve opens.
If the measured variable x3 rises, the
valve closes.
[2]
Adams, J. u. Clark, D.R. u. Louis, J.R. u. Spanbauer, J.P.:
Mathematische Nachbildung der Dynamik der Durchlaufkessel.
Archiv fur Energiewirtschaft (1966), 7, 277/292.
[3]
Bleisteiner, G. u. v.Mangoldt, W.: Handbuch der Regelungstechnik.
Springer-Verlag, Berlin/Gottingen/Heidelberg 1961.
[4]
Bodefeld, Th. u. Sequenz, H.: Elektrische Maschinen.
Springer-Verlag, Wien 1952.
[5]
Bouchard, R.: Betriebsoptimierung grofier Dampfkraftwerke.
BWK 18 (1966) 11, S. 562/567.
[6]
Cermak, J., Peterka, V. u. Zavorka, J.: Dynamika
regulavanych soustav v tepelne energetice a chemii (Dyna¬
mik von Regelstrecken in der warmetechnischen Energieerzeugung und in der Chemie). Academia-Verlag, Prag 1968.
1
-tM-
Diekers, W. u. Valder, L.: Vergleichende Untersuchungen
von Bensonkessel-Regelschaltungen .
Schoppe & Faeser, Techn. Mitt. (1959) 4, 135/146.
[8]
DIN 2481: Warmekraftanlagen. Dez. 1954.
[9]
DIN 19226: Regelungstechnik und Steuerungstechnik.
Mai 1968.
218
11Appendix
[10]
DIN 5492: Formelzeichen der Stromungsmechanik.
November 1965.
[11]
Dolezal, R.: Durchlaufkessel, Vulkan-Verlag Dr. Classen,
Essen.
11.2 Bibliography
219
[21 ]
Frensch, J.: Uber das dynamische Verhalten von Bensonkesseln bei Lastschwankungen.
Brennst.-Warme-Kraft 9 (1957), 1 1, 517/523.
[22]
Friedewald, W. u. Mork,P. u. Zwetz, H.: Einsatz von
Dampfkraftwerken im Netzbetrieb als regelungstechnische
Aufgabe.
ETZ81 (1960), 185/193.
[12]
Dolezal, R. : Zeitverhalten des Verdampfers eines Wasserrohrkessels mit Umlauf bei Druckanderungen.
Warme 75 (1969) 2/3,44/46.
[13]
DoleZal, R. : Unterdriickung der regellosen Schwankungen
des Luftiiberschusses im Feuerraum.
Mitteilungen der VGB (1968) 48, S. 346.
[23]
Friedewald, W. und Zwetz, H.: Regelung der Temperaturen
im Wasser-Dampf-System von Bensonkesseln.
Regelungstechnik 13 (1965) 2, S. 62/68.
[14]
Doleial, R : Wege zu einer raschen Leistungssteigerung im
Block mit Zwischenuberhitzung.
Mitteilungen der VGB (1963) 82, 21/36.
[24]
Gartner, R.: Regelung in der elektrischen Energieversorgung.
Regelungstechnik 13 (1965) 2, S. 49/57.
[15]
Dolezal, R.: Betriebsverhalten des Zwangsdurchlaufkessels
mit unterkritischem Druck bei Lastanderungen.
Mitteilungen der VGB (1 960) 69, 413/423.
[25]
Gerber, H.: Der Suizer-Einrohrdampferzeuger als Regelaufgabe.
Techn. Rdsch. Sulzer 51 (1969) 1, S. 27/37.
[16]
Dolezal, R.: Analyse des dynamischen und statischen Verhaltens als Hilfsmittel zur richtigen Gestaltung einer Ein-
[26]
Grasme, P.: Das Ausfahren steiler Lastspitzen durch
Dampfkraftwerke mit Zwischenuberhitzung.
ETZ81 (1960) A 6, 193/203.
[27]
Haase, M.: Einfluft der Kraft-Warme-Kopplung auf die
Kraftwerkstechnik.
Mitteilungen der VGB 49 (1969) 5,312/319.
[28]
Planus, B.: Vereinfachte Nachbildung des Regelverhaltens
eines Dampfiiberhitzers am Analogrechner.
Regelungstechnik 13 (1965) 1, 14/20.
[29]
Herbrik, R. u. Vofi, K.: Digitale Simulation der Regelsysteme von Dampferzeugern mit Hilfe blockorientierter
Programmiersprachen.
Brennst.-Warme-Kraft 21 (1969) 1, 13/16.
[30]
Hillesheim, J. u. Burger, R.: Betriebserfahrungen mit
Zwangsdurchlaufkesseln fiir Braunkohle und Vergleiche
mit anderen Kesselbauarten.
BWK 16(1964) 10, S. 470/497.
spritzanlage.
Brennst.-Warme-Kraft 17 (1965) 11, 523/529.
[17]
[18]
Franke, H. u. Stolle, W.: Zwangsdurchlaufkessel im Blockbetrieb.
Schoppe & Faeser Techn. Mitt. (1957), 3, 78/88.
Frensch, J. u. Klefenz, G.: Universell anwendbare Reglerschaltung fur Bensonkessel.
Schoppe & Faeser Techn. Mitt. (1961) 2, 57/65.
[19]
Frensch, J. u. Klefenz, G.: Die Dynamik der Dampferzeugung im Bensonkessel.
Brennst.-Warme-Kraft 13 (1961), 532/537.
[20]
Frensch, J.: Uber das dynamische Verhalten von Heiftdampf-Uberhitzern.
Schoppe & Faeser Techn. Mitt. (1 960) 3, 66/72.
220
[31 ]
[32]
[33]
11.2 Bibliography
11Appendix
Hocker, K.H. u. Weimer, K.: Lexikon der Kern- und Reak-
tortechnik.
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Mathias, G.: Die Auswirkung von Unempfindlichkeiten
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VGB Kraftwerkstechnik 54 (1974) 6, 390/395.
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Sekoguchi, K.: Analyses and Field Tests of Once-through
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[310]
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J
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246
[313]
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11Appendix
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DIN 19 226 (English Translation): Control Engineering — Defi¬
nitions and Terms.
May, 1968.
11.3 Subject Index
A
air flow control 83
attemperation (injection, spray) control
102
attemperation-water/feedwater control
115
auxiliary heating surface 122
B
back-pressure control 44
back-pressure station 134
back-pressure turbine 18
Benson boiler 62,64,70
boiler (steam generator) control 62
boiler load margin 54, 55
boiling water reactor 197,199
burner tilting control 132
busbar arrangement 14
busbar control 57
c
calorific value variation 58
circulation boiler 62
condensate flow stop control 136
condensing power plant 11,19
constant load operation 23
control by upstream pressure 23
control characteristics 21
convection characteristic 101
critical reactor 203
cyclone firing 81,95
D
Direct Energy Balance Method 52
district heating plant 191
drum boiler 62, 68
drum level control 109
E
evaporation end point 65
external control 68
I
F
feed-pump control 118,128
feedwater flow control 109
flue gas by-passing 132
flue gas recirculation 132
forced-circulation boiler 62, 64
forced-flow 62, 64, 66
forced-flow boiler with circulation 121
fossil fuels 11
frequency supporting operation 23
fuel flow control 74
furnace draught control 99
G
gas cooled reactor 197, 201
generator control 27
grid control 44
grid operation 20
grid self-regulation 38
H
heat- and -power plant, CHP plant
11, 191
heat exchanger controlled system
169
I
import/export power control 46
industrial power plant 11, 16, 18
internal control 68
isolated power plant 15, 17, 19, 34
L
LaMont boiler 62, 64
level control 109
level controlled system 173
live steam temperature control 100
load control 37
load margin 54, 55
low-load operation arrangement 120
248
11Appendix
M
mill-air control 90
moisture in steam 72
steam pressure control 74,139
steam pressure controlled system,
Benson boiler 150
steam pressure controlled system,
drum boiler 139
N
steam pressure controlled system,
Sulzer boiler 155
natural circulation boiler 62
neutron kinetics 204
normal load operation 20
nozzle group control (governing) 32
nuclear power plant 196
o
steam temperature controlled
system 158
storage capacity 143
subcritical reactor 203
Sulzer boiler 62,66,71
supercritical operation 128
supercritical pressure 66
supercritical reactor 203
O2 controller 84
O2 correction 81, 84, 95
one-element control 109
once-through boiler 62
outlet pressure (pass-out pressure)
control 44
overflow station 134
pressure reducing station 134
pressurized water reactor 197,200
process steam 11,18
prompt supercritical reactor 207
quality of control 183
R
reactor kinetics 202
reheater 40
reheat steam temperature control
130
three-element control 111
throttle governing 32
topping set 16
travelling grate stoker (firing)
82, 97
transient time 36
Triflux 73,131
trimming 118
turbine control 32
turbine load margin 54
turbine stress evaluator 55
two-element control 110
u
unit arrangement 13
unit control 50
unit coordinator 54
unit guidance device 53
variation of controller parameters
82, 104, 125
sliding pressure operation 46
slip 38
smoke density meter 85
speed controlled system 36
W
water seperator 66, 72, 121, 124