Control system for single shaft combined cycle gas and steam turbine unit

A method for starting and loading a combined cycle turbine of the type having a gas turbine with a fuel flow control valve and a steam turbine with at least one steam control valve both disposed on a single shaft and having a heat recovery steam generator heated by said gas turbine and connected to supply steam to the steam control valve, the combined cycle turbine having a unified control system and driving a load and also having an auxiliary steam source connected to the steam control valve. The improved method comprises starting and cranking the combined unit by controlling steam from the auxiliary steam source with the steam control valve, initiating and controlling fuel flow to the gas turbine with the fuel flow control valve, initiating combustion, controlling acceleration of the combined unit with the steam control valve, transferring acceleration control of the combined unit to the gas turbine fuel flow control valve, and accelerating the combined unit to rated speed. The method further includes the steps of synchronizing the combined unit to the line, substituting steam from the heat recovery steam generator for that from the auxiliary steam source, and opening said steam control valves to a full open position.

BACKGROUND OF THE INVENTION 
This invention relates generally to an improved method for starting up and 
synchronizing a combined cycle turbine of the type having a gas turbine 
and steam turbine on a single shaft. More particularly, the invention 
relates to a unit startup program and a unit loading program for a 
combined cycle turbine, which is carried out by a unified control system. 
The method includes providing startup from standstill, firing the gas 
turbine, carrying out acceleration control, protecting the steam turbine 
against excessive heating, synchronizing the unit to the line and loading 
the combined cycle turbine in an optimum manner. 
In some large combined cycle power plants the steam turbine and gas turbine 
are solidly coupled on a single shaft to drive a single electrical 
generator. The primary source of energy input to the rotating machine is 
the fuel which is burned in the gas turbine combustors. This shows up 
almost immediately as power delivered by the gas turbine. The waste heat 
from the gas turbine generates steam. This steam is utilized by a steam 
turbine as a secondary source of power input to the rotating train which 
is generated by a heat recovery steam generator (HRSG). While there is 
some time lag before heat from the gas turbine exhaust gas manifests 
itself as a power input source in the form of steam available at the 
turbine control valves, the control of the two sources of energy must be 
coordinated in order to properly control and protect the rotating 
machinery. 
When synchronized with the electrical grid the speed of the machine is 
determined by the frequency of the grid. Of the total mechanical power 
produced from the fuel to drive the generator, approximately two-thirds is 
produced by the gas turbine and one-third by the steam turbine from the 
thermal energy recovered from the gas turbine exhaust. In most cases, all 
of the steam produced by the heat of the gas turbine exhaust is expanded 
through the steam turbine. In other cases, some of the steam is extracted 
from the power cycle for process uses. In the former case, the steady 
state control of electrical output, therefore, is achieved entirely by 
controlling fuel flow, with the steam control valve or valves maintained 
in the fully open position. When not synchronized, on the other hand, 
either fuel flow to the gas turbine, steam flow to the steam turbine, or 
both, must be controlled to control speed, and there is not always a 
direct relationship between the two. 
During startup, before sufficient steam is generated from the heat recovery 
steam generator, under some conditions the control valves to the steam 
turbine may be closed. With no steam flow through the rotating turbine 
blades, excessive "windage" will cause the turbine to overheat. U.S. Pat. 
No. 4,519,207 to Okabe et al has suggested that an ancilliary steam source 
be provided to introduce flow through the steam turbine in a single shaft 
combined cycle to avoid overheating of steam turbine due to windage loss. 
Elaborate startup programs and control systems have been developed for 
starting up steam turbines and gas turbines. Combined cycle units in a 
plant made up of several units, each consisting of gas turbine and steam 
turbine on a separate shaft have been suggested, as described in U.S. Pat. 
No. 4,532,761--Takaoka, issued Aug. 6, 1985. This combined station 
control, therefor, deals with multiple, separately controlled shafts. 
Steam turbines have different startup problems than gas turbines, and the 
control systems have developed separately for the two types of prime 
movers in order to address these problems. This invention relates to a 
single combined cycle unit and its unified control system. 
A gas turbine is incapable of self starting from standstill. Torque from an 
external source is required for cranking to a speed at which ignition can 
occur and then to a higher speed at which operation becomes self 
sustaining and the gas turbine produces sufficient torque to accelerate to 
operating speed. 
Large combined cycle steam and gas turbines on a single shaft require a 
very large cranking device for starting. The prior art has suggested a 
separate starting motor for the combined unit or, if the combined unit is 
driving a generator, using the generator as a motor to crank the combined 
unit. 
A conventional gas turbine startup program controls the cranking device and 
the sequential operations involved with the startup. A typical program is 
as follows: 
(1.) Beginning with the fuel stop valve closed, the cranking device 
accelerates the unit to 25-30% of rated speed and holds for several 
minutes to purge the exhaust system combustible gases. 
(2.) Speed is reduced to 10-15% of rated for light off. The fuel stop valve 
is opened, a fixed fuel flow is admitted and ignition initiated. 
(3.) After light off, fuel flow is reduced to warm up level for one minute. 
(4.) The cranking device is then set for maximum torque and the fuel flow 
command is programmed to increase on a predetermined schedule. 
An error signal is the difference between a reference or desired value of 
an operating condition and the actual measured value of the operating 
condition. The gas turbine control system utilizes several such error 
signals to develop several fuel command signals which are applied to a 
"minimum value gate". The small fuel flow command generated by the startup 
fuel schedule is selected by the minimum value gate unless temperature or 
other limitations have a smaller fuel command signal. As speed approaches 
the governor setpoint, the speed error requires the smallest fuel command 
and becomes the controlling signal. An integrated gas turbine control 
system providing for open loop programmed start-up control with a number 
of closed loop constraints simultaneously controlling the gas turbine in 
accordance with operating conditions such as temperature, speed and 
acceleration is described in U.S. Pat. No. 3,520,133 issued July 14, 1970 
to Daniel Johnson and Arne Loft. 
A steam turbine, on the other hand, is self-starting as soon as steam is 
admitted through the control valve, but due to need to allow temperatures 
to equalize in the rotor and shell, startup programs have been developed 
for starting and loading a steam turbine in accordance with allowable 
thermal stress in a controlled manner as disclosed in U.S. Pat. No. 
3,561,216--Moore, issued Feb. 9, 1971. Combining acceleration and speed 
control through the use of a minimum value gate are shown in U.S. Pat. No. 
3,340,883--Peternel, issued Sept. 12, 1967. 
Unified control systems have been proposed for single shaft combined cycle 
plants with supplemental firing of fuel in the heat recovery steam 
generator which attempted to force a programmed load split between the gas 
turbine and the steam turbine, such a system being disclosed in U.S. Pat. 
No. 3,505,811 to F. A. Underwood issued Apr. 14, 1970. However, improved 
thermodynamic performance can be achieved by designing the system so that 
the steam valve operates in the full open position. In this way, the steam 
turbine accepts the total generation capacity of the steam generator over 
the entire load range without responding to small or slow speed variations 
which would require steam valve adjustment. 
As load is increased on the gas turbine, more heat energy will flow with 
the exhaust gas to the HRSG where it will cause an increase in steam flow 
to the steam turbine. This will cause the steam pressure to rise so that 
the steam turbine will absorb this flow without any control action. A 
reduction in gas turbine load will, in similar manner, result in a reduced 
steam flow to the steam turbine. Thus, the steam turbine will follow the 
load changes on the gas turbine with some time delay. 
While this provides optimum thermodynamic performance under steady state or 
slowly varying load changes, disturbances in steady or quasi-steady 
operation may occur. Two of these will be discussed in the following, (1) 
Proportional control, and (2) Power load unbalance control: 
(1.) A gradual rise in shaft speed above rated speed will cause the gas 
turbine speed control to reduce fuel flow and hence power to the shaft in 
a proportional manner with speed rise. According to the present invention, 
as long as the shaft speed is below a preset value, the steam turbine will 
only respond by a reduced output as the steam flow from the HRSG is 
reduced. 
A rise in combined shaft speed above the preset value will cause the steam 
valves to go closed in a manner proportional to the speed rise. This will 
reduce the steam flow to minimum flow level and hence shut off the steam 
flow as a contributor to excessive overspeed. 
(2.) In the event of sudden loss of full electrical load, the above 
described proportional action may not occur fast enough to limit the speed 
rise of the unit to a value that will not cause the overspeed trip to 
activate, typically at 110% rated speed. Modern fossil fired steam 
turbines use a power-load unbalance system to control overspeed to a value 
below that of the setting of the overspeed trip. This permits the unit to 
experience a load rejection, yet remain running under speed control at or 
near synchronous speed. Thus, the unit can, if desired, continue to carry 
station auxiliary load and also be in a condition for prompt 
resynchronizing with the system. Such power load unbalance systems are 
shown in U.S. Pat. No. 3,198,954 in the name of M. A. Eggenberger et al 
issued Aug. 3, 1965 or in U.S. Pat. No. 3,601,617 to DeMello et al issued 
Aug. 24, 1971. 
Accordingly, one object of the present invention is to provide an improved 
method for starting, synchronizing and loading a single shaft combined 
cycle turbine. 
Another object of the invention is to provide an improved unified control 
system for coordinating controlled startup, synchronization and loading of 
a single shaft combined cycle plant, including transfer of control between 
steam turbine and gas turbine. 
SUMMARY OF THE INVENTION 
Briefly stated, the invention is practiced by carrying out an improved 
method for starting and loading a combined cycle turbine of the type 
having a gas turbine with a fuel flow control valve and a steam turbine 
with at least one steam control valve both disposed on a single shaft and 
having a heat recovery steam generator heated by said gas turbine and 
connected to supply steam to the steam turbine control valve, the combined 
cycle turbine having a unified control system and driving a load and also 
having an auxiliary steam source connected to the steam control valve. The 
improved method comprises starting and cranking the combined unit by 
controlling steam from the auxiliary steam source with the steam control 
valve, initiating and controlling fuel flow to the gas turbine with the 
fuel flow control valve, initiating combustion, controlling acceleration 
of the combined unit with the steam control valve, transferring 
acceleration control of the combined unit to the gas turbine fuel flow 
control valve, and accelerating the combined unit to rated speed. 
Preferably, the transfer method includes utilization of an acceleration 
reference controlling position of the steam control valve which is set 
lower than an acceleration reference for the fuel flow control valve. The 
method further includes the steps of synchronizing the combined unit to 
the line, substituting steam from the heat recovery steam generator for 
that from the auxiliary steam source, and opening said steam control 
valves to a full open position.

DESCRIPTION OF THE PREFERRED EMBODIMENT 
Referring to FIG. 1 of the drawing, a gas turbine 2 is connected in tandem 
with a steam turbine 4 to a load, such as generator 6. The hot exhaust gas 
from gas turbine 2 flows through a heat recovery steam generator (HRSG) 8, 
which supplies steam to steam turbine 4. The entire system is controlled 
by a unified control system designated 10. 
The elements of gas turbine 2 are an expander 12, an air compressor 14, and 
a combustion chamber 16 supplied with fuel through a fuel stop valve 17 
and a fuel control valve 18. Steam turbine 4 comprises a high pressure 
section 20 and a lower pressure section 22 (combined intermediate pressure 
and low pressure section). "Primary" throttle steam from HRSG 8 flows 
through a stop valve 24, and control valves 26, to the inlet of the high 
pressure steam turbine section 20. A supplementary flow of "secondary" 
steam at a lower pressure level from HRSG 8 is admitted through a 
secondary steam valve 28, where it joins steam which has been expanded 
through turbine section 20 and before entering the reheater. 
Heat recovery steam generator 8 has associated with it a high pressure 
steam drum 30, low pressure steam drum 32, and contains banks of steam 
generating, superheating, reheating and feed water heating tubes which may 
vary in arrangement from one power plant to another. The disclosed 
arrangement includes high pressure superheat section 34, reheater section 
36, high pressure steam generating tubes 38, low pressure superheat tubes 
40, and low pressure steam generating tubes 42. 
The control system 10 includes means for sensing operating conditions of 
the combined cycle plant. These include a speed sensor 44 responsive to 
speed of a toothed wheel 46. The speed sensor 44 also serves as an 
acceleration sensitive device, since the speed signal may be 
differentiated with respect to time. Main steam pressure ahead of control 
valves 26 is measured by a steam pressure sensor 47. A measurement 
representing power input of the steam turbine is carried out using another 
steam pressure sensor 48 measuring steam pressure at the I. P. turbine 
inlet. Measurement of load is carried out using a kilowatt sensor 50 which 
is responsive to current and voltage on the generator output lines. 
Alternately, generator current alone may be measured as a rough indication 
of load. Steam turbine metal temperature is measured by one or more 
sensors such as 52. Only a representative number of sensors are shown in 
FIG. 1, a great many more being used in actual practice. 
Steam bypass valves 54, 56 and an auxiliary, separately fired steam 
generator 58 with auxiliary steam inlet valve 60 are shown, it being 
understood that in actual practice a great many more valves and auxiliary 
devices would be necessary. Instead of an auxiliary steam generator, 
another source of auxiliary steam to the inlet valve 60 could be the heat 
recovery steam generator of another combined cycle turbine. 
All of the steam admission valves 24, 28, 60 are provided with actuators to 
position the valves in response to signals from a unified control system 
10. The gas turbine fuel valve 18 determines the rate of fuel flow to the 
gas turbine in response to a fuel flow command signal. 
The rotating members of steam turbine sections 20 and 22 are solidly 
coupled by a rigid (non-flexible) coupling and, in turn, the steam turbine 
4 is solidly coupled to the generator 6 by a rigid coupling. The rotating 
members of gas turbine 2 are solidly coupled to the rotating members of 
steam turbine 4 by means of rigid couplings, and the system is provided 
with a single thrust bearing for all of the tandem-connected shafts 
referred to hereinafter as a "single shaft". Thus the rotating members are 
coupled together, and the gas and steam turbines operate as a single unit 
under control of unified control system 10. 
Although it is not a required feature of the invention, FIG. 1 illustrates 
a steam turbine in which the conventional intercept reheat valve and the 
reheat stop valve have been eliminated. A valveless steam conduit 62 
directly connects the outlet of steam reheater section 36 with the inlet 
of lower pressure steam turbine section 22. Steam flowing through conduit 
62 consists of expanded steam from the outlet of the high pressure turbine 
section 20 and supplementary steam flowing through supplementary steam 
valve 28 from the low pressure superheat tubes 40. In some plants having 
only a single pressure level HRSG, the supplementary steam would not be 
generated or added to steam entering the reheater 36. The invention is 
also useful in combined cycle plants where steam is generated at three 
different pressures, all being admitted to the steam turbine. 
Referring now to FIG. 2 of the drawing, the unified control system 10 of 
FIG. 1 is illustrated in block diagram form. The upper part of the diagram 
above line 62 comprises the portion of the control which results in an 
output signal 64 in the form of a fuel flow command signal to the gas 
turbine fuel flow control valve (18 in FIG. 1). The means by which the 
fuel flow rate to the gas turbine is controlled by this signal is not 
material to the present invention. For example, the fuel flow command 
signal may cause fuel pressure to vary or may deliver fuel at a controlled 
rate as well as to divide it into equal portions for the combustion 
chambers as disclosed in U.S. Pat. No. 2,936,028 issued to J. B. Gatzmeyer 
et al on May 10, 1960, or in the aforementioned U.S. Pat. No. 3,520,133 to 
Johnson and Loft, or may operate a servo valve to adjust flow by bypassing 
a fuel pump feeding a flow divider as shown in U.S. Pat. No. 
3,738,104--Rosa issued June 12, 1973. 
The lower part of FIG. 2 represents the steam turbine portion of the 
control, which results in a steam flow command signal to the steam valves 
representing a desired valve position. There may be a number of steam 
valves controlled by the signal according to a schedule of opening and 
closing, the number of such valves being immaterial to the present 
invention. These are represented by the single control valve 26 leading to 
the high pressure turbine shown in FIG. 1 and referred to simply as a 
"control valve". 
A number of operating conditions of the combined cycle plant are input to 
the control system, such as a speed signal 68 representing actual turbine 
speed (sensor 44 in FIG. 1), a main pressure signal 70 (sensor 47 in FIG. 
1), steam turbine shell metal temperature 72 (sensor 52 in FIG. 1), and a 
power-load unbalance input signal 74 (FIG. 4). Additional preselected or 
variable set points or reference signals are generated by digital computer 
programs designated as a unit startup program 76, a unit loading program 
78, and a steam turbine startup program 80. 
One output of the steam turbine startup program 80 is to a steam control 
valve set point generator 82 providing a control valve set point signal 84 
to position the controlling steam control valves between 0% and 100% open. 
A second output from the steam turbine startup program 80 is a selectable 
speed reference signal 86 representing a desired steam turbine speed As 
will be explained, the steam turbine reference may be used to control 
shaft speed for various intermediate speeds used in the gas turbine 
start-up cycle. 
Similarly, one output from the unit loading program 78 is to a gas turbine 
speed governor set point generator 88. One output provided from set point 
generator 88 is a speed reference signal 90 representing a desired shaft 
speed selected to be between 95% to 107% of rated speed. 
Outputs from the unit startup program 76 include a time scheduled output 
value 92 supplied to the steam turbine startup program, startup fuel 
schedule signal 94 designed to provide certain limiting functions 
necessary to gas turbine starting, a steam turbine acceleration reference 
signal 96 and a gas turbine acceleration reference signal 98. 
Several called for values of gas turbine fuel flow are selected by a gas 
turbine acceleration control 100 and a gas turbine speed control 102, a 
gas turbine exhaust temperature control 104 and a number of other 
miscellaneous controls which are represented by the single block 106. The 
outputs from these controlling functional devices may call for widely 
varying values of gas turbine fuel flow. They are supplied to a minimum 
value gate 108, together with startup schedule 94. A minimum value gate 
selects only the one of the applied input signals which will result in the 
lowest gas turbine fuel flow control signal, as described in the 
aforementioned U.S. Pat. No. 3,520,133 to Johnson and Loft. A minimum 
value gate may be an electronic analog device selecting the lowest analog 
input signal. Conversely, it may be a computer program subroutine which 
continuously examine digital values representing the outputs of the 
several control devices and selects the lowest digital number by an 
algorithm well-known in the art. 
Since combustion in the gas turbine cannot be sustained if the fuel flow 
falls below a minimum value, a settable minimum fuel flow control 110 
provides an output to a gas turbine maximum value gating device (or 
algorithm) 112 along with an input from the gas turbine minimum value gate 
108. 
Turning to the steam turbine portion of the controls, a steam turbine 
acceleration control 114, a steam turbine speed control 116 and steam 
turbine control valve set point generator 82 all provide input to a steam 
turbine minimum value gate 118. Similar to the gas turbine minimum fuel 
control, the steam turbine includes a steam turbine minimum flow 
controller 120 which ensures a minimum steam flow through the control 
valves. The minimum steam flow serves to cool the steam turbine when 
running at rated speed under gas turbine fuel control, and during transfer 
from auxiliary to steam from the HRSG. 
The signal from steam turbine minimum value gate 118 and minimum flow 
controller 120 are applied to a steam turbine maximum value gate 122. The 
output 66 from the maximum value gate 122 sets the position of the control 
valves. 
In accordance with one aspect of the present invention, the steam turbine 
acceleration reference signal 96 supplied to the steam turbine 
acceleration control and the gas turbine acceleration reference signal 98 
supplied to the gas turbine acceleration control are selectively set by 
the unit startup program 76 such that the steam turbine acceleration 
reference signal is lower by a selectable amount than the gas turbine 
acceleration reference signal 98. It is by this means that transfer of 
control under acceleration of the combined unit is accomplished by 
shifting control from the steam turbine control valve to the gas turbine 
fuel flow control valve, as will be explained. 
The signal from the gas turbine speed control 102 is obtained by summing a 
gas turbine speed reference signal 90 with a gas turbine actual speed 
signal 68 in a summing device 124 to obtain a speed error signal. The 
signal from the gas turbine acceleration control 100 is obtained by 
comparing a gas turbine acceleration reference signal 98 with a time 
derivative or rate of change of speed signal 68 so as to provide an 
acceleration error signal. 
Similarly, the steam turbine speed control sums an actual turbine speed 68 
with a reference turbine speed 86 in a summing device 126 to provide a 
speed error signal. The steam turbine acceleration control 114 compares an 
acceleration reference signal 96 with a time derivative or rate of change 
of turbine speed so as to obtain an acceleration error signal. The 
foregoing obtaining of differentiated speed signals and comparisons in the 
minimum value gates for the respective controls can be accomplished 
through analog electronic devices as explained in the aforementioned U.S. 
Pat. Nos. 3,520,133 and 3,340,883. Alternatively, the summations and 
gating may take place through well known techniques by implementation in a 
digital computer program. 
In order to illustrate the functional working of the speed control 116 for 
the steam turbine, FIGS. 3(a) and 3(b) show in functional block diagram 
and graph the output (control valve position) with variation in speed. A 
selected set point, here 105% of rate of speed is compared with actual 
speed in a summing device 126. A steam turbine speed control 116 includes 
means to select the gain or change in valve position with change in speed 
or speed setpoint, represented by logic block 128 and to limit the signal, 
represented by function generator indicated in block 130. As shown in FIG. 
3(b), a variation in speed of the unit with a set point of 105% and with a 
speed regulation of 2% results in a steam turbine valve moving from a full 
open position at 103% of rated speed to a full closed position at 105% of 
rated speed (see line 132). On the same graph of FIG. 3(b), a dot dash 
line 134 represents a gas turbine fuel flow control signal with a speed 
governor set point also at 105% of rated speed, but with a regulation of 
5%. Because of a wider or broader regulation of the gas turbine speed 
control, gas turbine fuel flow varies from full flow at 100% of rated 
speed to minimum fuel flow at 105% of rated speed. With this type of joint 
speed control, the gas turbine alone will control speed up to 103% of 
rated speed with the steam control valves in wide open position, 
whereafter between 103% and 105% of rated speed, the steam valves will 
close as well as a continued reduction of gas turbine fuel. 
Reference to FIG. 3(c) of the drawing illustrates a simplified time versus 
acceleration curve. Actual acceleration of the unit is illustrated by 
curve 136. The gas turbine acceleration reference signal 98 and the steam 
turbine acceleration signal 96 are both compared with the actual 
acceleration 136 and the respective difference values are acceleration 
error signals. At point A, the steam turbine acceleration controller 
begins to limit steam turbine valve opening and hence controls 
acceleration with a constant acceleration error signal AF. At point B, the 
gas turbine begins to create positive net torque and to accelerate the 
unit. At point C, the steam turbine control valve is closed to its minimum 
flow position, as required by the steam turbine acceleration controller. 
At point D, the gas turbine acceleration controller 100 begins to limit 
gas turbine fuel flow with a constant acceleration error signal DG. At 
point E, the gas turbine speed controlled 102 takes over as actual 
acceleration drops to zero. In this manner, combined cycle unit control is 
shifted from the steam turbine controller to the gas turbine controller. 
A power-load unbalance system, shown in block diagram in FIG. 4, is 
incorporated in the program of the unified control system 10. The system 
receives as input three signals; one is an electrical signal 140 from 
sensor 50 indicative of generator electrical power output, the second is a 
steam turbine stage pressure signal 142 from pressure sensor 48 indicative 
of the mechanical power produced by the steam turbine, and the third is a 
fuel flow signal 144 from the command for the fuel flow control valve 18 
indicative of mechanical power produced by the gas turbine. Since the 
power output and two power input measurements are all in different 
dimensional quantities, they are normalized to a dimensionless number 
representing a percentage of what they would be under rated conditions, 
e.g. the actual turbine stage pressure is divided by rated turbine stage 
pressure, the actual fuel flow command signal (less the minimum fuel) is 
divided by the command signal for full load rated fuel flow (less the 
minimum fuel), etc. Secondly, in the case of the two mechanical power 
measurements, they are each multiplied by another scaling factor 
reflecting the relative contribution of the steam turbine and the gas 
turbine under rated conditions. For example, the steam turbine power input 
might carry a weight of 1/3 and the gas turbine power input a weight of 
2/3. The scaling operations are indicated by block 146 for the electrical 
power signal 140; block 148 for the steam turbine stage pressure signal 
142; block 150 for the gas turbine fuel flow signal 144. 
The two power input signals and the load signal are algebraically summmed 
in a summing device 152. The output from summing device 152 is supplied to 
a comparator device 154, in a lower logic branch, which provides an output 
in the event that the mismatch of power of the combined steam and gas 
turbine over power output of the generator is greater than a selected 
threshold quantity, here selected as 0.4 per unit or 40%. In the upper 
logic branch, a signal proportional to generator current is differentiated 
with respect to time as shown in logic block 156. In actual practice, this 
is implemented in a digital computer program by a suitable algorithm, 
although it could also be implemented in a discriminator network. The rate 
of load change is subjected to a comparison in logic device 158, which 
provides an output in the event that the time rate of change of power 
output is less than a selected negative rate. The outputs from the two 
comparator devices 154, 158 are supplied to a logical AND 160 which, in 
turn, provides an output signal to a latch 162. The latch output signals 
various control devices to take rapid action to reduce the power input. 
OPERATION 
The unit startup program schedules the entire startup after a start command 
by sequentially setting the proper acceleration reference 96, 98, the 
startup fuel reference 94 and commands 92 to the steam turbine startup 
program 80, based on input of shaft speed and preprogrammed logic. 
The steam turbine startup program implements the commands from the unit 
startup program by issuing speed setpoint values 86 to the steam turbine 
speed control and raise/lower commands to the steam turbine valve setpoint 
generator 82, based on limitations imposed by the turbine metal 
temperatures related to startup steam conditions as determined by inlet 
pressure and temperature. 
The startup and loading of a combined cycle turbine with the new control 
features will now be described with emphasis on the steam turbine control 
and its interaction with the gas turbine control. 
Prior to the startup, the steam turbine valve setpoint 84 is set at zero 
and the output of the steam turbine minimum value gate 118 is, therefore, 
also zero. The steam turbine minimum flow control 120 is also set at zero, 
because the speed is at zero. Thus, the steam flow command signal is zero 
and the controlling steam admission (control) valve(s) 26 are closed. The 
steam turbine stop valve(s) 24 will be opened when the unit control system 
is reset prior to initiation of a start sequence. 
When a "start" command is given, the unit startup program will set the 
maximum acceleration allowed for the initial steam start to the steam 
turbine acceleration control 114, and send a gas turbine "purge" speed 
reference signal to the steam turbine startup program. This program will 
then, if steam conditions and turbine metal temperatures are acceptable, 
adjust the setpoint 86 to the steam turbine speed control to the purge 
speed level and begin to raise the steam turbine valve setpoint 84 in a 
rate limited manner towards a maximum allowed steam flow for startup. 
(This flow will, for example, be determined by the capacity of the 
auxiliary steam source 58 whose supply valve 60 is open.) This action will 
begin to open the steam turbine control valves 26 through the steam 
turbine minimum value gate, since both the output of the steam turbine 
acceleration control 114 and steam turbine speed control 116 will 
initially go to their upper limits. This is because the speed is constant 
(no actual acceleration) and near zero (low actual speed, since turning 
gear speed equals a few RPM)at the time of the "start" command. 
Due to the breakaway friction and large inertia of the combined gas and 
steam turbine shaft, the steam turbine control valves 26 will need to open 
a considerable amount, before the shaft begins to accelerate as a result 
of the torque generated by the steam flowing through the steam turbine. 
Shortly, thereafter, the speed is likely to rise so rapidly that the steam 
turbine acceleration control 114 becoming limiting and reduces the steam 
turbine valve opening through the steam turbine minimum value gate 118. 
The shaft speed will then continue to rise at the acceleration rate 
selected by the steam turbine acceleration reference until the speed 
approaches the "purge" speed reference set for the steam turbine speed 
control. At this time, the steam turbine speed control will take over 
control by reducing its output speed error signal to the steam turbine 
minimum value gate until it becomes limiting. Shortly thereafter, the 
shaft will be running in a steady mode at the reference "purge" speed. 
The unit startup program 76 will determine that purge speed has been 
reached and begin to time out the required length for purging of the 
entire gas turbine and HRSG gaspath. After the purge time has elapsed, the 
unit startup program will send a command to the steam turbine startup 
program to reduce the speed reference 86 to "ignition" speed which is 
lower than the "purge" speed. The new speed will be reached by the steam 
turbine speed control closing the steam valves sufficiently for a speed 
decay followed by stabilization at the new level. 
The unit startup program will now initiate a conventional ignition and 
warmup sequence as used for a simple cycle gas turbine. In addition to 
carrying out a programmed fuel flow command to increase on a programmed 
schedule, the unit startup program supplies an acceleration reference 98 
to the gas turbine acceleration control 100. The unit startup program will 
also send a command to the steam turbine startup progam to raise the speed 
reference to near rated (i.e., 95% of rated). This will result in the 
reopening of the steam turbine control valves to their maximum startup 
flow position as both the steam turbine acceleration control 114 and steam 
turbine speed control 116 will demand a higher valve opening. The shaft 
will now begin to accelerate under full steam turbine startup torque. 
At the low ignition speed and even as the shaft begins to accelerate, the 
gas turbine produces no positive torque, and full control of speed and 
acceleration is via the steam control valves positioned by the lowest of 
the demands from the steam turbine acceleration control 114, the steam 
turbine speed control 116, and the steam turbine valve setpoint 82. Above 
approximately one half of rated speed, the torque produced by the gas 
turbine begins to become significant, and thereafter rises rapidly with 
speed, resulting in higher acceleration than with steam induced torque 
alone. 
As the acceleration increases above the steam turbine acceleration 
reference, the steam turbine acceleration control 114, using its steam 
turbine acceleration reference 96, which is set lower than the reference 
98 of the gas turbine acceleration control 100, will now commence to close 
the steam turbine valves through a signal to the steam turbine minimum 
value gate 118, and the combined shaft will accelerate solely under the 
control of the gas turbine acceleration control 100 (which is providing 
the lowest fuel flow control signal to the gas turbine minimum value gate 
108). As the combined shaft reaches rated speed, the gas turbine speed 
control will take over and regulate near rated speed. This sequence is 
illustrated in FIG. 3(c). 
At this time, the steam turbine speed control (with a reference slightly 
lower than rated) will call for the steam valves to be closed, which will 
be the lowest value arriving at the steam turbine minumum value gate and, 
hence, the output of this gate will continue to be effective to close the 
steam valves, even though the steam turbine acceleration control 114 will 
begin to call for steam valve opening as the acceleration decreases. The 
resulting steam flow command will, therefore, be determined by the steam 
turbine minimum flow control 120, which will be supplying the largest 
input to the steam turbine maximum value gate. The final result of these 
control actions is that the combined shaft is running at rated speed 
completely controlled by the gas turbine speed control 102, the steam 
turbine is idling with only cooling flow passing through it, as controlled 
by the steam turbine minimum flow control 120, sufficient to cool the 
steam turbine. The steam turbine control reference 86 is set at less than 
rated and the steam turbine valve setpoint is still at maximum startup 
flow. 
"Synchronization" consists of connecting the generator 6 to the electrical 
output grid, whereafter, the speed of the turbines is fixed by the grid 
electrical frequency. After the unit has been synchronized, the steam 
turbine valve setpoint 84 is reduced to zero and the steam turbine speed 
reference is raised to maximum (i.e., 105% of rated) after which the steam 
supply is transfered from auxiliary source 58 to the HRSG 8. The steam 
flow command before transfer is still determined by the steam turbine 
minimum flow control 120 through the steam turbine maximum value gate 122 
sufficient to maintain steam turbine cooling. 
When steam from the HRSG is available at sufficient flow rate as determined 
by steam pressure measurements, a command will be given by the steam 
turbine startup program 80, which will then automatically raise the steam 
valve setpoint 84. The setpoint will be increased to fully open the steam 
valve at a rate determined under constraint of steam turbine metal 
temperature, steam pressure and temperature. At the end of this procedure, 
the steam control valves 26 and 28 will be fully open and the steam valve 
and turbine will accept all the steam from the HRSG at the pressure 
required for the flow to pass through the turbine where it is expanded to 
the condenser while delivering energy to the shaft. 
Operation of the improved power load unbalance system is as follows. When 
the sum of the input powers of the steam turbine and gas turbine exceeds 
the generator electrical output power by a fixed amount, it is an 
indication of imminent rapid speed rise. When further, the rate of change 
of load is negative and less than a selected value, it is an indication 
that the unbalance is not due to load variation or oscillation. 
Coincidence of both such conditions in the power-load unbalance system 
will initiate immediate fast closing of the turbine steam control valve 
26, through a special fast closing input device on the valve actuator, and 
also set the control valve set point 84 and fuel control setpoints 94 to 
zero position. This will cause the steam flow command signal to be 
completely overridden by the fast closing device, and it will cause the 
fuel flow to the gas turbine to be rapidly reduced to minimum fuel flow. 
The power-load unbalance system will reset automatically once the 
initiating condition has disappeared and the steam flow command signal 
will again take over control of the valve position. The control valve 
setpoint remains at zero, however, until the machine has been 
resynchronized and is ready to be loaded as described for startup of the 
unit. 
While there has been described what is considered to be the preferred 
embodiment of the invention, other modifications will occur to those 
skilled in the art, and it is desired to include in the appended claims 
all such modifications which fall within the true spirit and scope of the 
invention.