Note: Descriptions are shown in the official language in which they were submitted.
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Description
Steam Generator Control Systems
Technical Field
_
This invention relates to control systems and,
more particularly, to novel, improved control systems
for unfired generators (or boilers) of the once-through
type.
Background Art
Conventional steam boilers have a number of
economic shortcomings and cause many operating problems
in combined cycle applications, particularly those of
small capacity using gas turbines in the 4000-25000 Ow
range. Among the major contributors to these drawbacks
are the complex systems utilized to control the
operation of combined cycle power plant boilers Typical
prior art control systems for combined cycle power
plants are disclosed in US. Patent Nos. 3,505,811 to
Underwood and 2,965,765 to Mart et at.
The complex prior art boiler control systems
tend to have large numbers of components that are
subject to malfunction which makes maintenance costs
high and reduces boiler availability. Also, attended
operation may be required for safe and efficient boiler
operation.
The present invention is directed to
overcoming one or more of the problems as set forth
above.
Disclosure of the Invention
In one aspect of the present invention, a
steam generator control system includes an unfired
boiler; a source of thermal energy for the boiler;
I
means for effecting a flow of feed water to the boiler;
and a controller for controlling the operation of the
boiler. The controller includes means operable in a
predictive mode of operation for periodically
calculating the energy available to the boiler from the
thermal energy source and the quantity of dry steam
having a set point temperature which is an assigned or
calculated number of degrees lower than the temperature
of the thermal energy source that can be generated by
the trouncer of the energy to the feed water. The
system also includes means under the direction of the
controller for so modulating the flow of feed water to
the boiler as to supply to the boiler the quantity of
feed water that can be turned into steam of the
specified temperature by the transfer of the thermal
energy thereto.
The present invention provides novel
controllers designed around the philosophy that an
unfired boiler can be so controlled as to efficiently
produce steam of acceptable quality by regulating a
single operating parameter; viz., the flow of feed water
to the boiler. An energy or enthalpy balance is struck
between the ho-t gases supplied to the boiler and steam
at a specified temperature relative to the temperature
of those gases (the approach temperature) because steam
quality and boiler efficiency are closely related to
steam temperature, and the flow of feed water is so
regulated that the steam is produced at the selected
(approach set point) temperature. The herein disclosed
boiler operation controllers are simple, reliable,
inexpensive, and capable of providing safe and
efficient unattended boiler operation.
I
Brief Description of the Drawings
Figure 1 is a schematic view of a combined
cycle power plant with a boiler and illustrating one
embodiment of the present invention;
Figure 2 is a schematic illustration of one
controller which can be employed to control the
operation of the boiler shown in Figure l;
Figure 3 is a schematic illustration of a
subsystem that can be added to the controller of Figure
2 to afford more accurate control over the operation of
the boiler;
Figure 4 shows, graphically, the effect of
different types of control on boiler operation;
Figure 5 shows, schematically, a subsystem
which can be added to the controller of Figure 2 in
applications involving dual pressure boilers to make
the operation of the boiler more efficient; and
Figure 6 is a schematic representation of yet
another subsystem that can be used in conjunction with
that shown in Figure 5 to make the operation of a dual
pressure boiler more efficient.
jest Mode for Carrying Out the Invention
Referring now to the drawing, Figure 1 depicts
a combined cycle power plant 20 which includes: a gas
turbine engine 22 drive connected to an alternator 24;
a boiler 26 in which steam is generated by thermal
energy recovered from the hot gases exhausted from gas
turbine engine 22; and a steam turbine I also drive
connected to alternator 24 and employing the steam
produced in boiler 26 as a motive fluid.
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In power plant 20, steam turbine 28 also
drives the exemplary load; in this example an
alternator 24. However, it can equally well be
employed to drive a load which is different from the
load briny driven by gas turbine engine 22.
For the most part, the components of power
plant 20 are of conventional or otherwise familiar
construction Those components will be described
herein only to the extent necessary for an
10 understanding of the present invention.
The illustrated gas turbine engine is of
conventional configuration; it includes a compressor
30, a combustor 32, a gas producer turbine 34 for
driving compressor 30, and a power turbine 36. Hot
15 gases exhausted from power turbine 36 at a temperature
in the range of 427-4~2C are dueled to, and flow
through, the casing 38 of steam generator 26.
Normally, these gases will be exhausted to atmosphere
through stack 40 at a temperature of about 112C.
20 The heat thus recovered in steam generator 26 is 21-25%
higher than can be recovered in the unfired boilers
heretofore employed in combined cycle power plants.
The boiler 26 illustrated in Figure 1 has a
once-through, dual pressure configuration. It includes
25 a steam generating module 42 which, in one actual
boiler design in accord with the principles of the
present invention, is made up of forty steam generating
circuit assemblies each including a high pressure tube
46 and a low pressure tube 48. In each ox these tubes
30 a phase change of water to saturated steam and a change
from saturated steam to superheated steam occurs in a
continuous flow path extending from the inlet 50 (or
52) to the outlet 54 (or 56) of the tube as the water
flows downwardly through the -tube in efficient,
35 counterfoil relationship to the flow of the hot gas
.: .
I
turbine engine exhaust gases. Thus, different regions
in each tube function as a feed water heater, as a
vaporizer, and as a superheater.
High pressure steam generated in tubes 46 of
boiler 26 slows into the high pressure section of dual
pressure steam turbine engine 28, and low pressure
steam flows into the low pressure section of the
turbine.
A number of desirable attributes such as
reduced maintenance and operating costs, simplification
of automatic operation, and elimination of
possibilities for operator error are obtained by the
use of corrosion resistant materials in boiler 26,
thereby eliminating the need for controlling pi and for
chemically and/or mechanically controlling the
dissolved oxygen content of the boiler feed water. To
this end, tubes 46 and 48 are made of such a material,
typically a nickel-chromium-iron containing, high
temperature and corrosion resistant alloy.
Steam exhausted from turbine 28 flows into a
conventional condenser 62 where the steam is
condensed. This component may be, as examples, a water
or air cooled condenser of conventional design
Condensate accumulates in hot well 64 which
contains the small inventory of feed water needed for
boiler 26.
That only a small inventory of feed water is
needed to operate boiler 26 is of considerable
practical importance. The large mass of saturated
water contained in the drums of a conventional boiler,
and eliminated in the novel boilers disclosed herein
is a safety hazard and has produced widespread
legislation requiring attended operation of steam
boilers. By eliminating this large mass of saturated
water, the requirement for attended operation can also
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be eliminated. This is cost effective and, also,
facilitates remote, unattended operation of combined
cycle power plant 20.
From hot well I the condensed steam is
circulated by condensate pump 66 to a condensate
polisher 68. were, dissolved solids are removed from
the condensate which is then pumped to steam generator
26 by feed water pump 70 through a modulating type flow
control valve 72. This valve is controlled by a system
lo embodying the principles of the present invention, and
discussed in detail hereinafter, which matches the
feed water flow rate to the enthalpy in the hot gases
supplied to the steam generator from gas turbine 22.
us indicated above, it has unexpectedly been
found that the fabrication of those boiler components
wetted by aqueous fluids eliminates the need for
chemically removing dissolved oxygen from the feed water
supplied to boiler 26 or for controlling the pi of the
feed water. However, physical removal of dissolved
gases as by hot well decoration will typically be
necessary to maintain an adequate pressure drop across
the system. Hot well decoration is effected by a
vacuum pump 78 connected to hot well 64 through
condenser 62. Oxygen evacuated from the hot well and
condenser by the vacuum pump typically contains
appreciable amounts of entrained water. Consequently,
the evacuated air is pumped into a conventional
separator 80. Air is discharged from separator 80 to
atmosphere, and water is returned through trap 82 from
separator 80 to condenser 62.
One of the important advantages of the steam
generators disclosed herein is that the requirement for
make-up of feed water is nominal. For example one
boiler of the type disclosed herein is planned to
produce 6,998 kilograms of team per hour at one
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exemplary design point. Make-up water requirements for
this boiler are less than 2.4 liters per hour. In
contrast, make-up water requirements for a conventional
slowdown boiler of comparable capacity are about 170
liters per hour.
Such make-up water as is required is first
circulated through a demineralize 84 to remove
dissolved and suspended solids from the water and then
supplied to hot well 64 through make-up water line 86.
Referring still to the drawing, Figures 2 and
3 show, schematically, one flow control system (or flow
controller) 88 in accord with the principles of the
present invention for regulating the flow of feed water
to boiler 26 by modulating the flow of the Editor
through flow control valve 72.
Flow controller 88 employs the above-discussed
strategy of recovering the maximum amount of thermal
energy from the hot gases supplied to boiler 26 without
adjusting the flow of fuel to or otherwise predicating
the operation of gas turbine engine 22 on conditions in
the boiler; that is, the operation of boiler 26 is
subordinated or slaved to the operation of the gas
turbine engine.
This strategy can be followed and safe,
efficient operation of boiler 26 obtained in an
extremely simple fashion by controlling only the flow
of feed water to the boiler, this control being so
effected as to maintain only one parameter within
specified limits. This parameter is the approach
temperature of boiler 26 which is defined as the
temperature of the hot gases supplied to the boiler
minus the temperature of the high pressure steam
generated in the boiler.
Controller 88 achieves this goal by
calculating the energy available from the hot gases
supplied to boiler 26 and the maximum amount of steam
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that can thereby be produced within the foregoing
constraint and adjusting feed water flow valve 72
accordingly.
The energy added to the feed water to generate
steam equals the energy recoverable from the gas
turbine engine exhaust gases. Because outlets 54 and
56 (see Figure 1) are fixed restrictions, that energy
balance can be approximated by:
(C TOW hug) Wow = Was Gas gas
10 where:
CpFW = the average specific heat of
steam on the water side of the
boiler at design point,
TO out Tin = the increase
from feed water temperature to
steam outlet temperature,
hug = the latent heat of vaporization
of water,
IT gas = the change in temperature of
turbine exhaust gases in the
boiler,
Wow = the mass flow of feed water
through the boiler,
W = the mass flow of hot gas
gas
supplied to the boiler from the
gas turbine engine as
calculated from measured
operating parameters of gas
turbine engine 22, and
Gas = the specific heat of the hot
gases supplied to the boiler.
Certain set points were established to
optimize the generation of steam in the boiler 26 of
combined cycle power plant 20. The first was that the
54
g
temperature of the gas leaving the boiler should be
221 F. Thus, Togas = Togas - 221 F, where
Togas is the temperature of the gas being supplied to
boiler 26 and is a measured parameter. The specific
heats Gas and CpFw were assigned average values of
Gas = 0.25 and CpF~ = 0.53~. The water inlet
temperature, Tin, is relatively constant and was
assigned an average value of 92 F.
With the foregoing, the feed water equation can
be rewritten as follows:
gas (Togas 221 F) Gas (2)
CPFW ( HP gas fog
The term hug is relatively constant and was
replaced by an assigned value. As CpF~ and Tin are
relatively constant, values assigned to these
parameters were multiplied together and added
algebraically to the value assigned to hug. The
resulting figure was 920.
As discussed above, the maximum amount of dry
steam (within constraints) can be produced if Top,
the outlet steam temperature, is kept within a
specified number of degrees of Togas. This
difference, termed the approach temperature, Tarp =
T -- T
yes HP-
The expression (Top - Togas) is preferably
replaced by one which takes the wanted approach
temperature into account, and is:
HP SET POINT gas i ASP
where Tarp is an assigned value or is calculated
from Togas
Thus with all assigned values substituted, the
feed water flow control algorithm becomes:
0~25 gas (Togas 221) (3)
O o 538 Top SET POINT
-1 0 - ~2~7~
The only variables in the open loop,
predictive mode of operation afforded flow controller
88 by the feed water flow control algorithm (3) are the
mass flow and temperature of the gases supplied to
boiler 26.
The mass flow of exhaust gases available from
turbine 22 (Was) is proportional to the speed of gas
producer turbine 34 for any given ambient temperature
of the air introduced into compressor 30.
Consequently, controller 88 is designed to convert the
speed and ambient air temperature information from
sensor 90 and 92 into a mass flow value. This can be
done with a conventional function generator 94 designed
to make the calculations shown in graphical fashion in
Figure 2. The Was value and the gas temperature
(measured by a sensor 96 such as a thermocouple) are
transmitter to calculation block 98 as is the selected
TOP SET POINT. Calculation block 98 solves
the equation or algorithm I discussed above,
generating a feed water flow signal WIFE. This signal
is transmitted to the (typically) electropneumatic
actuator (not shown) of feed water flow valve 72 to
regulate the flow of feed water to boiler 26 in accord
with the operating strategy discussed above.
In one exemplary controller embodying the
principles of the present invention, the input data for
the feed water flow control equation is collected at a
rate of ten times per second, and Wow is recalculated
after each update in the input data. The significant
result of updating the input data and recalculating
Wow at this frequency is that the feed water flow rate
is for all practical purposes based on a prediction
rather than results at the boiler input. This is
important because the transit time of the water through
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the boiler is measured in minutes; and, if output
results were the only control factor, regulation of the
feed water flow would be based on obsolete data.
Figure 4 shows, graphically, the effect on
steam temperature (and thus steam quality) of a
temperature change in the hot gases supplied to boiler
26. In the case of a rapid drop in the exhaust gas
temperature and no feed water control, the steam
temperature will drop; and the steam will rapidly
lo become saturated (undesirable) as shown by curve 100.
On the other hand, if the feed water flow is
regulated by the predictive flow control equation
discussed above, the feed water flow will be decreased
as the gas temperature drops as shown by curve 102. As
a result, the steam temperature will stabilize at a
temperature approaching the selected set point as shown
by curve 104.
Even better control over the generation of
steam in boiler 26 can be gained in some circumstances
by adding to the open loop, predictive mode flow
control discussed above the feedback loop 106 shown in
Figure I. Typically, this closed loop mode of control
will be made operator selectable.
The closed loop, feedback mode of control is
employed to compensate for inherent drifts in the
predictive flow control equation (drift factors may
cause significant errors in the predictive equation).
Drift may be caused by, for example,
miscalibration of valve 72, fouling of steam generating
tubes 46 and 48, inaccuracies in the mass flow
calculation made by function generator 94, and signific
variations in TEXT from the assigned value.
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In the closed loop mode of boiler control a
corrected feed water flow rate and a Editor flow
correction factor WCLcF are generated in accord with
the equations:
FWTOTAL FOE WCLCF
and
WCLCF = -[(TOGAS TARP) TOP] KCLCF
where:
FATUITY = the newly computed feed water
flow including the closed
loop correction, in lb/hr,
Top a the measured high pressure
outlet steam temperature, and
KCLCF = a gain coefficient for
converting temperature to
feed water flow.
The gain coefficient is assigned a value of
4 lb/hr/F,
Tarp = 80 if TOGAS 720,
and
The reason for adopting a variable approach temperature
is that a fixed approach temperature does not guarantee
a sufficient margin of superheat when gas turbine
engine 22 is operating under part load
The steam output temperature, Top, is
measured by any desired technique, for example by a
thermocouple, and summed i an adder 108 with
TOP SET POINT.
This produces an error signal which is
converted as by a conventional PI controller 110 into a
control signal compatible with that generated in
function generator 98. This latter signal is inverted
in inventor 112 and summed with the predictive
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Editor flow (Wow) signal in adder 114, producing
the new feed water flow comlnand signal (Fly TOTAL for
operating the electropneumatic actuator of feed water
flow control valve 72.
Curve 116 in Figure 4 shows how the feed water
flow is regulated when the closed loop correction
factor is used in conjunction with the predictive flow
value to control valve 72. In the same Figure, curve
117 shows that this combination of predictive and
closed loop modes of operation can be taken advantage
ox to maintain the steam output temperature at the
selected set point.
It is of course theoretically possible to
control future flow solely by the use of a feedback
loop as shown in Figure 2 without simultaneously
employing predictive flow control. However, Figure 4
makes it clear that this will not provide the desired
results; viz., the generation of dry steam and the
maximum recovery of thermal energy (which requires that
JO the steam temperature be maintained as closely as
possible to the steam temperature set point). If the
gain in the feedback control is set low, the result of
a change in gas temperature as shown in Figure 4 is
over damping as indicated by curves 118 and 119, and the
steam rapidly becomes saturated. On the other hand, if
a high gain feedback correction signal is employed to
control the feed water flow, oscillation occurs as
indicated by curves 1~0 and 122; and unstable,
inefficient boiler operation with periodic generation
of saturated steam is the result.
It is preferred, in feed water flow control
systems employing the principles of the present
invention, that the actual feed water flow be measured
and that any differences between the measured and
command values be employed to correct the feed water
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flow. A subsystem for accomplishing this function in
controller 88 is illustrated in Figure 3 and identified
by reference character 128.
In this subsystem, the flow of steam from
boiler 26 is measured and converted to a measured
feed water flow rate in function generator 130. This
signal is summed with the feed water flow command signal
Wow or WIFE TOTAL in adder 132. The resulting error
signal is converted to a new feed water flow command
signal in a fast response (POD) controller 134; and the
new command signal is utilized to operate the
electropneumatic actuator of feed water flow control
valve 72.
As discussed above, the illustrated boiler 26
is of the dual pressure type, including as it does two
independent circuits composed respectively of tubes 46
and 48 in which steam is generated at high and low
pressures. Optimal operation of a boiler within he
principles of the present invention can be furthered by
splitting the dual pressure feed water flow between the
tubes 46 and 48 in accord with a particular flow split;
viz., that obtained by dividing the high pressure steam
flow by the low pressure steam flow.
A subsystem designed to provide this
additional degree of control is illustrated in Figure 5
and identified by reference character 138.
As in the case of predictive feed water flow,
the feed water split or ratio can be determined from the
ambient temperature of the air supplied to gas turbine
engine compressor 30 and the speed of gas producer
turbine 34. The values of these two parameters,
obtained from sensors 90 and 92, are combined into a
flow split signal by function generator 140 in accord
with the calculations shown graphically in Figure 5.
This flow split or ratio signal is applied to the
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operator (again typically electropneumatic) of a flow
proportioning valve 142 in series with feed water flow
control valve 72 (see Figure 1) to proportion the flow
of feed water between the high and low pressure steam
generating tubes 46 and 48 in boiler 26.
Also, in the case of dual pressure boiler,
boiler operation is preferably further optimized by
employing feedback to correct the feed water Flow split
signal.
Specifically, as shown in Figure 5, the
controller for a dual pressure boiler may have an input
a Top SET POINT which is analogous to, and
provided for essentially the same purposes as, the
TOP SET POINT discussed above; viz., to insure an
adequate degree of superheat in the low pressure steam
and maximum recovery of the heat from the hot gases on
which boiler 26 is operated.
In the feedback mode of operation, which again
is preferably operator selectable, the temperature of
the low pressure steam is measured as by a
thermocouple, and the resulting signal is summed with
that representing Top SETpoINT
The resulting error signal is converted to a
control signal in PI controller 144, and is inverted in
inventor 146. This produces a signal which is combined
with the feed water flow split command signal from
function generator 140 in adder 148, producing a
command signal which is, again, applied to the actuator
of proportioning valve 142.
Still another degree of refinement, and
increase in boiler performance, can be obtained in the
case of a dual pressure boiler by comparing the actual
split of feed water with the predictive flow split and
adjusting flow proportioning valve 142 accordingly.
This subsystem is shown in Figure 6 and identified by
reference character 150.
715~L
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In the illustrated subsystem, the flow of high
pressure and low pressure steam from boiler 26 are
measured and signals indicative of the resulting mass
flows converted to a flow split value in function
5 generator 152 in accord with the equation:
Split FEW LPFW HP ( 6)
LUFF LO
where:
WLPFW = the low pressure
steam flow,
and
FEW LOW = the high pressure
steam flow.
The resulting signal is summed with the flow
split command signal from function generator 1~0 or
adder 1~8 in adder 154, producing an error signal which
is converted to a command signal in POD controller
156. That signal is inverted in inventor 158 and, as
discussed previously, applied to the actuator of flow
proportioning valve 142.
It is reiterated, in conjunction with the
foregoing detailed description of the invention, that
the novel feed water flow controllers described herein
are across-the-board applicable to once through,
unfired boilers. In particular, as the control
strategy involves only an energy or enthalpy balance
between the hot gases supplied to the boiler and steam
generated in the boiler, and as the only variable
inputs to the controller can be measured or calculated
gas temperature and mass flow) or can be assigned
constant values, it will be readily apparent to the
reader that the principles of the present invention are
applicable independent of the source of the waste heat.
The invention may be embodied in other
specific forms without departing from the spirit or
essential characteristics thereof. The present
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embodiment is therefore to be considered in all
respects as illustrative and not restrictive, the scope
of the invention being indicated by the appended claims
rather than by the foregoing description; and all
changes which come within the meaning and range of
equivalency of the claims are therefore intended to be
embraced therein.
