Guidelines for Generator Stability
Model Validation Testing
IEEE Task Force on Generator Model Validation Testing of the Power System Stability
Subcommittee*
Abstract— This paper constitutes the final report of the IEEE
Task Force on Generator Model Validation Testing, which
was created in 2002 and served under the Power System
Stability Subcommittee. The objective of the TF was to
provide technical guidance to utilities undertaking testing and
modeling of generation facilities. This paper outlines accepted
industry methods for establishing dynamic models for
generators and their control systems.
II. SIMULATION MODELS
Power system planning and operational studies require the
simulation of the response of synchronous machines and
their respective control systems. For these studies it is
essential that the control systems of the synchronous
machines be modeled in sufficient detail (see [1]). The
desired models must be suitable for representing the actual
equipment performance for large, severe disturbances as
well as for small perturbations. To obtain accurate
simulations, not only must the models be of an adequate
level of detail, but the values of the parameters in the
models must also correspond to actual field values.
Index Terms—generator modeling, model validation, field
testing of power plants
I. INTRODUCTION
Few people disagree that good quality simulation models
of power system equipment is beneficial to all power
system participants. There are, however, differing opinions
on the required level of detail, best methods to obtain data,
and frequency of verification. The goal of this paper is not
to prescribe one answer to any of these issues. Rather, it is
to identify a body of available techniques and describe the
benefits and drawbacks of each, to help industry
participants determine the best approach for their types of
equipment, capabilities and objectives.
The equipment to be tested and modeled includes the
generator and its control systems; excitation systems,
power system stabilizers and turbine governors. Protective
relay coordination with equipment capabilities and control
system limiters is equally important and is discussed in
detail in appropriate standards [2-11, 62].
To some extent, the model structures used in system
studies are intended to facilitate the use of field test data as
a means of obtaining model parameters. The models are,
however, reduced order models and they do not necessarily
represent all of the control loops on any particular system.
In some cases, the model may represent a substantial
reduction, resulting in large differences between the
structure of the model and the physical system. Model
structures are shown in the references [2, 7, 12, 13 and 14].
The purpose of the model validation is to ensure the proper
performance of the control systems and validate the
computer models used for stability analysis.
Specific goals include the measurement and verification of
the following:
• generator reactive capability
• generator dynamic model data
• excitation system, stabilizer and limiter models
• turbine/governor models
• coordination between protective devices, control system
limiters and equipment capability
Useful models should be valid for frequency deviations of
+/-5% from rated frequency and oscillation frequencies up
to about 3 Hz. Voltage deviations are typically between
95% and 105% for steady-state generator operation, but the
models must be capable of representing large-signal
disturbance performance. The models discussed here
would not normally be adequate for use in studies of sub
synchronous resonance or other shaft torsional interaction
problems. Slow-acting control and limiter functions (such
as tap-changing transformers and generator field current
limiters) that may come into play in long term dynamic
performance studies are required for some studies and are
included.
In addition to obtaining model data, the tests performed to
gather this information may uncover latent defects that
could lead to inappropriate unit response during system
disturbances, thereby improving the reliability of the unit
and the power system.
III. REVIEW OF EXISTING DATA AND MODELS
*Task Force Members: Les Hajagos (chair), Joel
Barton, Roger Berube, Murray Coultes, Jim Feltes, Gary
Lanier, Shawn Patterson, Les Pereira, Pouyan Pourbeik,
Alex Schneider, Robert Thornton Jones
Prior to undertaking a testing program, a thorough review
should be made of existing simulation models,
manufacturer’s data sheets, and control and protective
1
equipment tunable settings. Priority should be given to
testing parameters which are tunable, or which may have
been changed by refurbishment, maintenance or
replacement. Often, new excitation or governing controls
are installed without corresponding changes to simulation
models. Conversely, some model parameters, such as unit
inertia, may be fixed by the system design, and once
measured or calculated, may not change except by
equipment modification. Examples of model parameters to
be validated are shown in Table 1.
themselves to application in the field to installed
equipment. With the increasing usage of sophisticated
computer-based design tools, detailed commissioning tests
of this type are often only performed as type tests on the
initial design.
Some common mistakes that may be found in existing
database models are as follows:
A. Set by Reactances,
Limits,
design (not
changed
unless
Time
Exciter time
rebuilt)
Constants,
constant,
•
•
•
•
•
TABLE 1. MODEL PARAMETERS
Conditions
Use of typical or bid data rather than as-built data.
Incorrect scaling of data based on changes to
ratings, most commonly up-rating of unit apparent
power
Use of saturated instead of unsaturated generator
parameters
Inertia not including the contribution of the
turbine
Exclusion of features such as reactive current
compensation in excitation systems
Generator
Exciter
Power Governor
System
Stabilizer
Input
type(s)
Water
Starting
Time,
No Load
Gate,
Inertia,
Voltage
sensing time
constant,
Full Load
Gate,
Saturation
Saturation
(rotating
exciter)
Turbine
Power
Fractions,
Maximum
Power,
IV. DESCRIPTION OF TESTING AND VALIDATION METHODS
Dead band,
This section will focus on the testing methods generally
employed to determine model parameters for generators,
excitation systems, and governors.
Turbine
damping,
B. Tunable
Existing methodologies for generator testing can be
broadly divided into two categories:
•
•
Voltage
Regulator
Gains,
Time
Constants,
Time-response tests, involving step changes to
controller set points, partial load rejections and
other disturbance techniques with the machine
operating at pre-defined conditions [16, 17, 18,
19, 20, 29, 30]; and
Reactive
Compensation
Gains,
Time
Time
Constants, Constants,
Limits
Limit Levels
Frequency response tests conducted with the unit
at standstill [21, 22] or in operation.
These methodologies are well established and can produce
accurate models. The major drawbacks are associated with
the time the machine is unavailable for normal commercial
operation (economics) and the technical problems that may
arise during the tests. In some cases the technical problems
are associated with the discovery of latent defects. In this
case, although problems may arise during testing, this is
considered preferable to the consequences that could occur
during an actual system disturbance.
Droop,
Gains,
Rate
Limits
A. Synchronous Generator Tests
Historically, manufacturers performed sudden short circuit
tests to determine dynamic synchronous generator
parameters. These test procedures are specified in IEEE
Standard 115-1995 [4]. These tests provide only the d-axis
transient and sub-transient constants. In addition, they do
not include measurement of field current during the short
circuit tests and consequently the field circuit is not
specifically identified. The limitations of these procedures
for providing data suitable for stability studies have been
recognized for some time.
Note that the tests and methodologies defined in equipment
standards [3 through 11, 60] are not specifically designed
to determine model parameters, but generally to specify a
desired level of performance and usually a methodology to
measure that performance. While these tests can give very
useful information for deriving parameters, it is not their
main focus to determine the complete set of parameters
needed. In addition, many of the tests are designed to be
performed by the manufacturers and do not lend
Several different testing and analytical methods have been
proposed and used to obtain better models. These include:
2
•
Enhanced sudden short-circuit tests
•
Partial load rejection tests
•
reactances, this test can be used to determine those
generator parameters. Figure 1 shows a typical response
for this test.
Frequency response tests
o
Standstill frequency response
o
Open-circuit frequency response
o
On-line frequency response
26
24
Terminal Voltage (kV)
•
Analysis of design data, e.g., finite element
analysis.
These improved methods of obtaining
characteristics are briefly discussed below.
machine
22
20
18
16
14
12
1) Enhanced Short Circuit Tests
0
5
10
15
20
25
30
T im e ( S e c o n d s )
References [33] and [34] describe improved methods of
utilizing results from sudden short-circuit tests to determine
more accurate d-axis parameters. The most important
feature of these methods is the utilization of rotor current
measurements during the short circuit tests to identify the
field circuit characteristics more accurately.
Fig. 1. Typical response for d-axis test showing decay in
terminal voltage
Data is generally recorded using digital recording
equipment. This allows direct comparison of measurements
with simulations. Simulations are performed and the
generator model parameters are adjusted iteratively to
produce a match. The advantage of this approach is that its
setup is relatively simple and it does not require a high
degree of training to execute. Some of the drawbacks with
this approach include the need for a manual exciter control
that maintains constant field voltage, and the need to
overcome plant controls that may prevent completely
unloading the unit or operating at a low off-line voltage for
an extended period.
Among the disadvantages of the short-circuit approach are:
the inability to provide q-axis parameters, the necessity for
subjecting the machine to a severe shock imposed by the
sudden short circuit and the complexity of setting up this
test.
2) Partial Load Rejection Tests
Partial load rejection tests are among the most commonly
employed means of validating generator model parameters
for in-service generating units. They have been performed
on hundreds of units and regional testing programs, such as
the ongoing program in the WECC [15], have been
primarily accomplished with these techniques. This method
is one of the simplest approaches to developing an
adequate equivalent circuit model, or for verifying
manufacturer’s data.
If power angle can be measured, the q–axis parameters can
be measured in a manner similar to that used in the test
employed for the d-axis. By matching the power angle
relative to terminal voltage with the power factor angle, the
steady state conditions for the q-axis test are represented by
the phasor diagram shown in Figure 2, which reveals that
the armature current is aligned with the quadrature axis.
This requires a generator output in the neighborhood of 10
percent of rated output and a reactive power absorption of
a few percent of rated. As in the d-axis test, the generator
is brought to the desired loading, excitation placed on
manual and the main generator breaker is opened, resulting
in a response in terminal voltage. Since the unit is
producing real power, the partial load rejection will cause a
rise in generator speed and hence care must be taken to
select the initial loading to limit over speed and also the
resulting voltage change.
The load rejection dynamic tests are selected to provide a
simple and safe disturbance to excite the response of the
unit and, as much as possible, limit the set of parameters
affecting the response to simplify the derivation process.
The usual approach is a series of load rejection tests with
the unit initially carrying partial load. This approach is an
extension of the work documented in References [17, 18,
35, and 36]. References [19, 20, 23, 31 and 37] give more
details on the application of such tests and the procedures
involved.
The initial conditions for the load rejections are selected to
isolate specific parameters. Two tests are needed to
determine, respectively, the parameters of the generator’s d
and q axes.
To determine d-axis parameters, the generator is dispatched
on-line at approximately rated voltage, no active power
output, and absorbing reactive power. This results in a
steady state condition where the generator armature current
is completely aligned with the direct axis. With the
excitation system in manual (field voltage) control, the
main generator breaker is opened which results in decay in
terminal voltage. As the generator dynamic response is
only a function of the generator d-axis time constants and
3
This technique has been extensively used on round rotor
generators [48, 49, 50, and 51]. In addition, it is now part
of IEEE standard No.115-1995 [4]. SSFR testing can be
performed either in the factory or during a maintenance
outage on a unit. Other utilities have begun using these
techniques on hydro generators. Reference [52] gives
details of the SSFR test procedures and method of
analyzing data. Details of models developed from SSFR
tests on three large units are given in reference [50].
q axis
~
jX q I
~
I
The advantage of this approach is that it can be performed
during outages, thus eliminating lost commercial operating
time. The disadvantage is that there is that a high level of
expertise is required to perform the test properly and
analyze the results.
δ
~
V
~
Ra I
b) Open Circuit Frequency Response (OCFR)
Open circuit frequency response testing allows
confirmation of some of the SSFR data in the middle of the
frequency range for the d-axis only [48]. For this test, the
unit is operated on open circuit at reduced voltage. The
field is excited at various frequencies and the field to stator
frequency response measured. The differences between
this response and the equivalent one from the standstill
tests gives some indication of rotational effects.
d axis
Fig. 2. Phasor diagram for quadrature axis test
In practice, load rejection tests may be repeated to
characterize the dynamic response for the excitation system
and turbine/governor if generator field voltage and
governor signals are monitored. Although this approach
simplifies testing since it does not require a detailed
knowledge of each Manufacturer’s control design, it has
some drawbacks. In particular on newer systems, on-line
and off-line response may not be identical as the systems
may switch state depending on the status of the generator
breaker. Also these tests are not likely to fully exercise all
parts of the model and provide sufficient data for complete
model verification. They may however be useful as part of
a re-verification process once detailed models have been
developed.
The test is normally done at more than one voltage to
examine saturation effects. By conducting the test with
various signal amplitudes, slot wedge conduction effects
can be assessed.
c) On Line Frequency Response (OLFR)
In many respects, on line frequency response testing is the
"proof of the pudding" as far as small signal verification
machine models is concerned. Here the machine is being
tested under the same conditions as the model is expected
to perform, although over a restricted operating range.
For this test, the machine is operated near rated (or at
reduced) load preferably over substantial impedance to the
system. The excitation is modulated either by sinusoidal or
random noise. Components are resolved on the two axes
and data similar to that of the SSFR tests is used to derive a
model.
3) Frequency Response Tests
a) Standstill Frequency Response (SSFR)
In the SSFR technique, all tests are conducted with the unit
at rest and disconnected from the bus. The rotor must be
aligned to two particular positions with respect to the stator
during the tests; because of this, it is normally only
performed on round-rotor (thermal) generators. The stator
is excited by a low level source over the range of
frequencies from 1 mHz to 1 kHz. The frequency
responses from the stator winding with the field open and
shorted are analyzed to derive the parameters for a higher
order d- and q-axis model.
The frequency range of usable data in this test is more
limited than that of the SSFR tests, but the SSFR data is
expected to be good at the frequency extremes. The OLFR
testing allows the middle of the frequency range to be filled
in with data for both axes that include rotational effects.
The disadvantage of this test is that it requires testing on an
operating unit connected to the system, possibly under
special system or unit conditions. In addition, it does not
provide large signal response information. Care must be
exercised to avoid exciting critical unit or system
frequencies.
Because the tests are conducted at very low flux levels, the
results must be corrected to bring them from the "toe" of
the saturation curve to normal unsaturated levels. This is
done by minor adjustment of the mutual reactance in each
axis.
Details of OLFR measurement techniques and model
identification procedure are given in reference [53].
Reference [54] gives results of OLFR tests on two large
4
thermal generators and improved models developed from
the tests.
generator is critical to power system reliability and can be
affected by many different factors within the plant.
In reference [55], models for three large generators based
on SSFR and OLFR tests are validated by comparing the
results of simulations with measured responses involving
line switching. For one of the generators; the models
derived from short circuit tests and decrement tests are also
validated. The results show that models derived from
frequency response measurements are generally superior.
A. Voltage and Reactive Capability
There is often confusion about the actual reactive
capability of generators and the relationship between
voltage and reactive power limits during staged testing and
during actual power system disturbances.
Utility-scale generators supplied in North America are
typically designed to operate continuously without derating for operating voltages between 95% and 105% of the
nameplate voltage. Sustained operation outside of these
limits is not recommended and staged tests should not be
conducted beyond these limits. Station and unit service
loads fed from the generator should be capable of
continuous operation at voltage levels corresponding to this
range of generator terminal voltage. If a unit is not capable
of operating within the 95% to 105% range because a
station service voltage level restriction is reached first, this
needs to be corrected in order to be compliant.
d) Calculation of Parameters from Design Data
References [56, 57] describe improved generator models
developed from design information.
Reference [58]
presents more recent work using finite element analysis.
Generator manufacturers use these methods almost
exclusively today, rather than tests, when supplying model
data for their products.
Work done on two and three dimensional finite element
models in the steady-state have shown good agreement
with measured results. In addition, two dimensional finite
element models have been developed which provide
frequency response data that compares well with measured
results. The degree to which conduction occurs across slot
wedges appears to have a significant effect on the model at
higher frequencies. The significance of rotational effects
and the effect of disturbance amplitude on the model
require additional investigation.
Excluding voltage restrictions, the reactive output
capability of a generator will be affected by some or all of
the following factors:
•
•
•
•
•
•
This approach requires detailed involvement by the
Manufacturer and may not be possible for older units
unless original design material is still readily available.
Each generator’s reactive capability is depicted in a
capability curve, such as the one shown in Figure 3. This
curve plots physical limitations, such as stator and rotor
heating limits, in the (MW, MVAr) plane. By maintaining
operation within the limits depicted on the capability curve,
the unit’s continuous ratings will be respected.
V. REACTIVE CAPABILITY TESTING
Generator steady state measurements normally consist of
tests to either determine or validate the synchronous
reactances and saturation data associated with the generator
and tests to confirm the reactive capability of the unit
including auxiliaries. The modeling tests involve:
•
•
field winding thermal limits
stator winding thermal limits
stator core-end overheating limits
excitation output capability
excitation limiter settings
relay operating characteristics (e.g. loss-ofexcitation relay settings)
Prior to performing reactive capability tests it is important
to understand the difference between the conditions that
exist during staged tests and those that exist during actual
system events when the generator may be called upon to
operate at the extremes of its reactive capability. During
normal operation under Automatic Voltage Regulator
(AVR) control, the Operator sets the AVR reference to
achieve a specific reactive power or terminal voltage level.
If the power system voltage drops, the AVR control will
respond by boosting excitation resulting in reactive power
output from the unit to the system (i.e. lagging power
factor operation). The converse is true if the system voltage
rises. If the generator voltage is maintained near rated by
AVR action, then the limits to be respected will be those
shown on the capability curve. Under test conditions, the
situation is different. Unless the Utility can intentionally
lower nearby system voltage levels, over-excited operation
is normally achieved by raising the unit’s voltage set point.
Reactive power will then flow from the unit to the system.
The limits shown on the capability curve must still be
Off-line measurements to measure the opencircuit saturation curve of the generator
On-line measurement of generator terminal
quantities at different active and reactive power
levels
The off-line measurements are used to generate/validate the
saturation coefficients for the generator. The measured ac
terminal conditions of the generator are used to calculate
generator field current and rotor angle and this is then
compared against the measured values to validate the
synchronous reactances. These tests are normally only
required when a generator is first registered or after
significant changes have been made.
Many ISOs and Reliability Organizations also require that
Utilities confirm compliance with minimum levels of
lagging and leading reactive capability or identify the
physical operating limits of the unit. These tests are
required regularly since the reactive capability of each
5
respected, however, it is most possible that the generator or
auxiliary bus voltages will reach their maximum allowed
values before the stator or rotor capabilities are reached for
either over-excited or under-excited operation and possibly
for both.
A
•
Obtain a copy of the latest reactive capability
curve for the unit under test and become familiar
with each of the limitations.
•
Ensure that all voltages and currents monitored
during the test on the station Human Machine
Interface (HMI) accurately represent the quantities
measured from the primary PTs and CTs. Spot
checks should be conducted using a calibrated
meter of each station service bus voltage and the
current levels on any critical load.
•
Ensure that recent calibration records are available
for protective relays (O/C, O/V, U/V) on any
critical loads and unit service buses.
•
Calibrate any relays that do not have recent
calibration records.
OVEREXCITATION R EGION
B
MVARS
S UP PLIED
S AF E OPERATION
Most of the measurements involve use of existing station
transducers and therefore do not introduce any risks other
than those normally associated with working in a
generating station environment. During the course of these
tests the unit will be run at the extremes of its normal
continuous capability and all participating staff should be
vigilant for any sign of potential problems such as
overheating. It is recognized that Operators may not be
called upon to operate units at the limits of their reactive
capability on a routine basis and may require the support of
their Engineering Staff to properly prepare for these tests.
POWER IN M W
10
MVARS
ABS ORBED
REACTIVE PO WER IN MVAR
50
50
85 MW
100
C
D
50
UNDER EXC ITATION R EGION
C. Measurements and Operation
The on-line measurements are performed with the unit
synchronized to the electrical network and operating at a
specified active power load. In some cases the number of
measurements is minimal. An active power level close to
rated power is specified and the generator reactive power is
adjusted until both extremes of operation are reached. In
other cases, the ISO or Reliability Organization may
require that measurements be performed at several different
active power levels.
Fig. 3. Capability curve and steady-state measurement
points (100 MVA, 0.85 PF Unit)
For typical transformer reactance levels and constant
system voltage conditions it will normally not be possible
to measure both the lagging and leading reactive power
limits if these correspond to typical levels of 0.9 pf lagging
and 0.95 pf leading. In some cases the transmission system
Operator will be able to adjust other reactive resources
sufficiently to allow the full range of testing but this is not
typical. It may also be possible to dispatch other units
within the same Plant to obtain the desired range. This is
most effective when multiple units are connected together
at their low-voltage terminals, sharing a common
Generator Step-Up transformer.
At each load level, the generator field excitation is varied
to change the reactive power output. The measurement
points would be selected based on the generator capability
curve and any other limits such as excitation system limits,
generator ac terminal voltage limits (typically 95% to
105% of rated) and auxiliary supply voltage. Figure 3
depicts typical measurement points superimposed on the
unit capability curve.
Regardless of which limits are reached the Utility should
be prepared to supplement these measurements with
calculations based on the steady-state representation of the
generator. These can be used to establish the actual
reactive capability of the generator over the full operating
voltage range.
As noted earlier, each jurisdiction may have specific
requirements however a typical reactive capability test
would include up to five different reactive load levels to
allow for extrapolation of results to limiting output
conditions.
B. Prerequisites and Preparation
Station personnel are responsible for the following
preparation:
•
•
•
6
unity power factor
over-excited (reactive power = 50% of maximum
over-excited requirement)
over-excited (reactive power = up to100% of
maximum over-excited requirement)
•
•
simulation software to be used. Standard models [2] should
be used where possible.
under-excited (reactive power = 50% of maximum
under-excited requirement)
under-excited (reactive power = up to 100% of
maximum under-excited requirement)
For model validation purposes, normally two distinct types
of tests are required: open-circuit or on-line dynamic
response tests that allow confirmation of the closed-loop
response of the Automatic Voltage Regulator (AVR),
Power System Stabilizer (PSS) and selected limiters, and
off-line tests used to measure detailed transfer functions or
measure limiter operating characteristics.
Local guidelines will dictate quantities that should be
monitored. Not all measurements will be required or
available on all units. Station metering is acceptable as
long as it has been maintained in reasonable calibration.
The source of each measurement should be noted along
with the test data. The following is a typical list of points to
be monitored on a conventional round rotor generator
connected to a steam turbine:
•
•
•
•
•
•
•
The following is a brief overview of the types of tests
performed, based on the unit operating condition. Each of
these tests is described in more detail in the following subsections, along with specific examples of equipment
connections and results. Excitation system testing
techniques are discussed in detail in [3].
ac terminal voltage
active and reactive power (generator gross)
generator field voltage and current (excitation
system)
generator stator temperature (average and
maximum measurement)
generator core temperature (average and
maximum measurement)
station ambient and unit cooling temperatures
unit service bus voltages if these are fed from a
Unit Service Transformer and are therefore
subject to change during the course of the test.
Hydroelectric units normally require fewer measurements
since unit service voltage issues stator core-end heating are
rarely a factor.
•
Off-line tests are performed on individual
modules within the excitation system while it is
energized from test supplies and isolated from the
field winding.
•
Open Circuit tests are performed with the
generator on open circuit running at rated speed.
•
On-Line tests are performed with the generator
synchronized to the grid and operating at a variety
of active and reactive power load levels.
A. Off-Line Tests
During the off-line tests, the exciter is energized using a
test supply, and test signal generator outputs are substituted
for the normal input signals (e.g. three-phase ac voltage
input to the voltage regulator, dc millivolt source in place
of field current shunt feedback). Individual modules or
sub-modules are isolated and tested separately to validate
the derived transfer functions. Step response and frequency
response techniques are normally used to measure the
small signal performance. Non-linearities in the electronic
controls, such as limits, can be measured at this stage by
inputting large signal changes at selected inputs.
The unit is normally operated under AVR excitation
control throughout the test. An Operator should monitor
the unit to maintain relatively constant reactive output in
the event that system conditions change during the course
of the test. MVAr control loops can also be enabled for
this period, as long as they are voltage-supervised, to
prevent voltage from moving outside of the required limits.
If any tests reveal problems with over or under-excited
operation, the excitation should be adjusted to restore unity
power factor operation, or operation at rated terminal
voltage. The choice of operating level will depend on the
nature of the problem (i.e. voltage or reactive current).
Testing of limiter and protective relay operating settings,
associated with the excitation system, can also be
performed at this stage using test sources as inputs. This is
important since it is not practical to operate the unit on-line
at the high excitation levels necessary to reach the typical
limiter settings. Testing is complicated with excitation
limiters since it involves verifying that once engaged, the
limiter is capable of controlling the excitation level in a
stable fashion. For summing limiters this involves the
complex interaction with other control loops such as the
AVR and PSS. For this reason, excitation limiter testing is
normally performed in two stages. First the operating limit
characteristic (e.g. field current or reactive output points at
which the limiters take over control) is measured during
off-line tests through secondary signal injection. Once the
limit characteristic is known, the limit is temporarily
adjusted to lower limit settings that permit the limiter to be
The station service load fed from the unit under test should
match normal operating conditions for the maximum
continuous load level.
VI. EXCITATION SYSTEM TESTS
The testing of excitation systems to validate their
performance specifications and to construct models can be
a time consuming task. The best time to do this testing is in
conjunction with the commissioning of a new unit. At this
time manufacturers' data are normally available, and a
manufacturer’s representative is normally on site. The
manufacturer may provide schematic or block diagrams for
the equipment, which is a good starting point. Target
simulation models should be chosen to match the
7
engaged during open-circuit operation or on-line operation
at low active and reactive power load levels. Under these
controlled conditions, the control-loop dynamics can be
measured with minimal risk to the unit or power system.
systems, the exciter is normally equipped with a built-in
facility for introducing controlled step changes to the
voltage reference signal. On a system equipped with a
magnetic amplifier, the signal may be applied as a current
injection into a spare winding. On older systems such as
those equipped with discontinuous regulators, the signal
may be introduced by altering the three-phase PT feedback
signals at the AVR input. This approach can also be used
on more modern systems if detailed design information or
interfacing software is unavailable. This technique has the
added advantage of explicitly including the terminal
voltage transducer in the forward path of the disturbance.
A new class of test sets that combine static and dynamic
closed-loop simulating capability may allow both types of
tests to be performed during outages reducing the need for
some or all of the on-line tests. These test sets simulate the
dynamic response of the generator and power system.
Prior measurements or a detailed representation of the
generator is necessary for this approach to be used with
confidence to verify dynamic regulator and limiter
response.
Another step response test can also be accomplished by
transferring from constant field (manual) control mode to
the AVR mode with a small unbalance between the set
points. This method has the advantage of not requiring
equipment to inject a change in AVR reference.
B. Open–Circuit Tests
Open circuit tests are performed at rated speed and rated
voltage with the generator remaining on open circuit. The
open circuit tests normally consist of the following stages:
•
Terminal V
(pu)
1.00
Dynamic tests (time-response or frequencyresponse) of the closed-loop AVR. The measured
data can be compared with simulations performed
using the block diagram model.
simulated
measured
0.99
0.98
200
Field
(Vdc)
•
Steady-state measurements of the exciter and
generator quantities. This is often performed
concurrent with the main exciter and/or generator
saturation characteristic measurements.
Dynamic tests of the excitation limiters. The overexcitation limiters, which normally operate to
limit terminal voltage, generator field current
and/or exciter output current, can be tested on
open-circuit, by lowering the limit set points to the
open-circuit operating levels. The unit's operation
is then forced into the limit set point, by injection
of a test signal into the AVR or firing circuit or by
simply increasing the AVR setpoint until the limit
is reached.
150
100
50
0
520
Field
(Adc)
•
Figure 4 presents a response typical of the changes in
terminal voltage that are obtained in the excitation system
tests.
510
500
0
2
4
6
8
10
Time (seconds)
One of the most common of the open circuit tests is the
AVR step response test. This test is specifically identified
in many North American regulatory compliance procedures
for confirmation of excitation system response. As a
minimum, generator terminal voltage, generator field
voltage, or pilot exciter field voltage for brushless systems,
should be measured during the application of a step change
signal that will produce a 1% to 2% change in the terminal
voltage reference. This test is performed by injecting a
small, short duration change in the AVR reference level.
This causes the generator terminal voltage level to change
suddenly and provides a good measure of the overall
response of the excitation system.
Fig. 4. Typical step response of static excitation system
An alternative to AVR step response tests are load
rejections with the unit absorbing reactive power [20].
Upon opening of the generator circuit breaker, the
excitation system will respond to the step change in
reactive current in a manner similar to that seen for a step
test. The AVR response in the opposite direction can be
tested with the unit producing reactive power. The amount
of reactive power produced or absorbed prior to opening
the circuit breaker will determine the magnitude of the
AVR response. This method also has the advantage of not
requiring any equipment to inject a change in AVR
reference, but requires the coordination involved in a load
rejection. On some digital systems care must be exercised
in interpreting results since AVR or limiter dynamic
settings or setpoints may be switched when the ac breaker
is opened.
The type of exciter will dictate the method used to inject
the AVR reference step change. On analog-electronic
systems, the signal is normally applied as a low-voltage
(e.g. 0-12 Vdc) signal applied to the input of an
operational-amplifier summing-junction. On modern digital
8
C. On–Line Tests
On-line tests are performed with the generator
synchronized to the grid and operating at different active
and reactive power levels. Among the tests performed with
the unit on-line, are the following:
•
•
•
important to have accurate measurements of the phase
relationship between the generator terminal quantities and
the stabilizer signals. Any transducers or amplifiers used
for this process must be scrutinized to ensure that they do
not introduce unnecessary filtering and associated phase
lag in the frequency range of interest, 0.1 Hz to 10 Hz.
Analog electronic hardware is being superseded by digital
measurement systems, which incorporate the transducer
functions with the data storage and analysis software.
Steady-state measurements of exciter and
generator quantities. These measurements
supplement the open-circuit measurements, and
can be performed over a wide range of generator
field current levels and are normally performed at
the same time as reactive capability testing
In many cases, some or all of the required signals are
directly available from the stabilizer itself, as these
quantities are used in the stabilizing signal generation.
Prior to investing in specialized transducers it is
worthwhile to review the manufacturer’s manuals and
schematics showing the available test points.
Dynamic tests (time-response and frequencyresponse) of the closed-loop AVR. Many of these
tests would only be required during
commissioning or on units equipped with power
system stabilizers.
Two types of tests are normally performed: time-domain
and frequency-domain. For the time-domain tests, the
quantities should be recorded with a bandwidth of at least
50 to 100 Hz to ensure that higher-frequency components
in some of the signals (e.g. turbine shaft torsional
components in the speed signal) are captured. For the
frequency-domain tests a transfer function analyzer is very
useful. It should be capable of generating the required
disturbance signal (e.g. swept-sine, pseudo-random binary
noise sequences, etc.) and of performing input/output
transfer functions of any pair of signals. At one time, these
pieces of equipment were only available to small numbers
of specialists; however with the proliferation of computer
and DSP-based test equipment, they should be widely
available to most utilities.
Dynamic tests of the excitation limiters and other
features. All of the limiters and other features that
are not operational on open circuit (e.g. UEL,
RCC) are tested at this stage.
Dynamic measurement of the field current limiter operation
is typically performed with reduced limit settings as
described in the earlier sections on off-line testing. Settings
are reduced to avoid excessive bus voltage and stator
current during the performance of the test. Limit levels are
reduced, and a terminal voltage step is applied which
forces the field current into the new limit.
Care must be taken when tuning the UEL dynamic
performance under all circumstances, but particularly when
it is used in conjunction with a power system stabilizer.
When testing and calibrating UELs, several factors must be
considered, all of which suggest performing dynamic tests
with reduced settings (e.g. with reactive power settings
closer to zero). Low bus voltage will result from operation
at extreme under excited levels and should be avoided. In
some cases, where there is limited margin between the
UEL and loss-of-excitation relay or generator core-end
overheating characteristic, there is the possibility of
entering one of these regions if the limiter does not
function as expected.
Stabilizer testing must validate several different model
parameters: gains, time constants, limits and calibration of
measurement transducers.
If detailed models exist from commissioning tests or
studies, simple step response tests may suffice to confirm
continued validity of an existing model. For equipment
where no model exists, bench tests to confirm transducer
calibrations and output limits may be required, as the
required operating ranges of inputs and outputs may be
impossible to test with the equipment in service on line.
Transfer function tests will likely also be necessary for
various stages of the stabilizer characteristic, requiring
access to internal stabilizer signals and appropriate
isolation transducers, with suitable bandwidth as discussed
above. As with excitation systems, the techniques and
details are discussed in the reference [3, 24, 25 and 26].
D. Power System Stabilizers
The techniques used to test the AVR and power system
stabilizer (PSS) mirror the techniques that are used in their
simulation and tuning. That is, we seek to measure the
required compensation characteristics, measure the effect
of the settings on the closed-loop response and finally
perform special measurements which could alert us to
possible side-effects of the AVR and PSS settings during
both normal and disturbance operating conditions.
References [24 to 26] describe various aspects of testing of
these controls.
VII. GOVERNOR TESTS
A. Permanent Droop:
The extent to which each generating unit responds to
system frequency variations is determined by its permanent
droop setting, within its turbine limits. In most
jurisdictions, the governor droop and speed sensing dead
band are required to be confirmed by test.
The selection of phase compensation is critical to the
proper functioning of the stabilizer. As a result it is
9
Permanent droop is often set through a calibrated
adjustment with an indication of the actual value. While
this calibration is often reasonably accurate, permanent
droop should be measured directly as a confirmation,
especially on older mechanical units where changes may
have been made to governor components.
Frequency
(Hz)
60.04
60.02
60.00
59.98
59.96
This measurement may be performed without the benefit of
any special equipment. The simplest approach is described
below.
95
Gate
(%)
With the unit operating off-line, apply excitation such that
the unit is operating close to rated terminal voltage. Adjust
the speed reference to different settings above speed noload (e.g. +/-4 % in 1% increments) and tabulate the unit’s
frequency versus reference setting. In cases where the
speed reference does not have marked settings this will
sometimes involve adding temporary markings to dials or
gear wheels.
94
93
92
Deadband
(Hz)
0.04
Synchronize the unit and adjust the speed reference to the
values above speed-no-load that were tabulated in the
previous step. Tabulate the final gate or fuel valve position
and active power versus speed reference setting.
0.02
0
-0.02
-0.04
Plot the measured off line speed and on line feedback
signal used for permanent droop for corresponding speed
reference settings. The slope of this curve at any point is
the permanent droop. The average slope over the entire
operating range is usually quoted as the droop value.
0
500
1000 1500 2000 2500 3000 3500
Time (seconds)
Fig. 5. Governor Deadband
Clearly in this case the unit's deadband is well within the
required limits. Care must be taken in interpreting this
kind of curve to ensure that there is sufficient ambient
frequency variation to make a reasonable assessment.
This test is equally applicable to hydraulic and thermal
turbine governors.
Although in theory it is possible to introduce very small
reference changes in modern electronic or digital governors
this is rarely an effective method of assessing the overall
deadband.
B. Deadband:
The other quantity that is most frequently requested for all
governors is deadband. Deadband is defined as the largest
frequency change for which the governor does not respond.
This can obviously be difficult to assess, especially if
system frequency doe not change sufficiently during online monitoring. One method of evaluating governor
deadband is to simulate the response of the governor to
system frequency changes using the known governor droop
and time constants. The "ideal" simulated response is then
subtracted from the actual measured response and
converted to equivalent frequency as shown in in the
"deadband" plot of Figure 5.
C. Hydraulic Governor Dynamic Tests
For hydraulic turbines, it is necessary to provide governor
compensation for stable off-line and islanded speed
governing. Testing this compensation should be performed
on a routine basis as well as following any major
maintenance outage.
The following is a simplified test description suitable for
use with most mechanical-hydraulic governors for
hydraulic turbines. The test equipment requirements may
be quite modest: gate position transducer, hand tools, stop
watch, multimeter capable of measuring frequency.
Prior to testing, tabulate as-found settings and adjust, if
necessary, to match any recommended settings.
Connect slide wire or other transducer to produce a voltage
signal proportional to servomotor position.
Operate the unit on line with the speed reference at a
calibrated setting (e.g. 2% above speed-no-load). On units
with small versus large system settings, operate with the
small system (damped) settings.
10
Tabulate or record the initial gate position and rapidly
change the speed reference to a new (calibrated) position.
Allow the gates to settle to a new steady-state position and
tabulate the final gate opening. On mechanical systems,
adjust the needle valve opening as required to obtain the
recommended reset time.
that many governors switch modes or set-points when the
unit synchronizing breaker opens. As a result, on many
units neither on-line dynamics nor droop can be validated
from a load rejection test. In this case, some means of
disturbing the speed reference or one of the feedback
signals must be employed with the unit operating on-line as
described above.
To obtain a record of the transient response of the
governor, follow the steps outlined above and use a
slidewire mounted on the wicket gate servomotor to obtain
a voltage proportional to gate position as shown in Figure
6.
D. Thermal Unit Testing and Modeling
Whereas there is a long history of tuning and testing
hydraulic generator governors, there has been less focus on
testing of steam and gas turbines for tuning and model
validation. For operating security limit studies, the focus
has moved to overall plant frequency response.
0.45
The use of detailed thermal governor models has not
produced load and frequency response simulations which
match measured system events. Reference [14] presents the
development of a new turbine-governor modeling approach
that correctly represents thermal units that have
demonstrated unresponsive characteristics such as “base
loaded” units, or as units with load-controllers. This
approach focuses on the use of data collected from station
recorders during actual events rather than staged tests.
0.40
Gate Position (pu)
simulated
measured
0.35
0.30
0.25
E. Combined-cycle power plant tests and models
The reader should refer to [12] for a more detailed account
of combined cycle power plants.
0.20
0.15
0
5
10
15
From the perspective of the electrical generator(s), its
excitation system, associated supplementary controls,
limiters, etc. a combined cycle power plant is no different
than any other similarly size thermal unit. The key
difference is in the turbine controls since the plant consists
of the combination of both gas (Brayton) and steam
(Rankine) thermodynamic cycles.
20
Time (seconds)
Fig. 6. Mechanical Governor Damped Response
New governing systems are almost exclusively of the
electro-hydraulic design. The flyball head speed sensing
system is replaced by speed probes or frequency input
circuits and frequency-to-voltage converter circuitry. The
gate position feedback signal is obtained from a rotational
or linear displacement transducer. In some cases electrical
power is used in place of gate position for on-line
regulation purposes. The speed reference, measured speed
and droop feedbacks are combined electronically, either
with analog circuitry or using a digital implementation.
Modern combined-cycle power plants use digital turbine
controls. In these systems, governor droop is typically
implemented as a constant relationship between turbine
speed and generator electrical power (in units of megawatts
per Hertz). An intentional deadband is often programmed
into the controls, to prevent constant motion of the fuel
valve.
For multi-shaft units this droop setting is
implemented in the governor controls of the individual gas
turbines. The effective droop of the entire plant is a
combination of the gas turbine response and the subsequent
dependence of steam turbine power on gas turbine output.
The steam turbine output follows the gas turbine, with a
large time constant associated with the heat-recovery
steam-generator (the steam turbine is typically operated
with valves wide open – under sliding pressure control).
The droop of the gas turbine(s) may be measured by
plotting the steady-state variation in power versus the
governor speed reference and thus determining the slope of
this line [12]. For single-shaft units the governor droop
can be, but is not necessarily, implemented as a
relationship between the total electrical power of the unit to
shaft speed.
In this case, speed reference step response tests may be
initiated and recorded in the same way as they are
performed for analog electronic or digital voltage
regulators, and the same precautions, recording, and
analysis techniques apply.
Appropriate simulation models may be found in references
[13 and 39]. Testing techniques for governor dynamic
tuning and modeling may be found in references [40-47].
Once individual parameters have been identified, to the
extent possible, an overall test can be performed to verify
the correct performance of the model. Load rejection tests
are one method used for this purpose. It should be noted
11
Off-line speed and on-line power response to step-changes
in the governor reference input may be used to validate the
time constants and rate limits associated with the gas
turbine fuel valve and turbine [12].
In addition,
particularly for multi-shaft units, the time constant
associated with the heat-recovery steam-generator may be
estimated by effecting a change in the gas turbine power
and recording the corresponding response in the power
output of the steam turbine. During this test the steam
valves should be kept wide open (in sliding pressure mode)
and the gas turbine kept in its new steady-state condition
for many minutes while the steam turbine is allowed to
fully respond. The gas turbine(s) in many modern
combined-cycle power plants will have an outer-loop
megawatt controller that will act to maintain a pre-selected
megawatt output level on the gas turbines as specified by
the operator. This control loop will effectively override the
initial response of the turbine droop-governor in the event
of a system disturbance bringing the unit’s output back to
the pre-selected level [12, 14]. Ideally, this loop should be
disabled on units participating in primary frequency
regulation.
Validation of tunable settings (Table 1, B) should be
performed periodically (e.g. following a major unit outage)
as determined by experience with the particular equipment
in use and every time a change or upgrade is made. The
history of the equipment, such as component failures and
the need for adjustments should be used to determine when
re-testing of a model may be warranted.
Validation of equipment characteristics set by design
(Table 1, A) are typically only performed during
commissioning or at the start of a test program. Simple reverification tests may be performed occasionally or when
evidence of changes to unit behavior occurs.
Rotating Equipment –Most generator and rotating exciter
model data is fixed by design. Generator inertia will not
change unless generator or turbine modifications are made,
and thus repeated testing is not a necessity. Generator
rewinding is not expected to introduce changes to the
generator impedances; however periodic reactive capability
tests and confirmation of the open circuit saturation
characteristic will reveal unexpected reductions in unit
capability, for instance, shorted rotor turns, or control
system automation enforcement of operational limits.
Reactive capability verification is mandatory in many
jurisdictions.
The maximum power output of a gas turbine, whether in
combined-cycle power plants or operated as simple-cycle
units, is dependant on both the operating speed of the unit
and ambient air conditions [12, 27 and 28]. In some
applications, inlet-air may be kept at near constant
conditions by air-conditioning units to minimize variations
in the turbine capability due to ambient conditions – this is
done at the expense of overall plant efficiency. Where
such inlet-air conditioning is not performed and the gas
turbine capability varies significantly with ambient
conditions, manufacturer data should be sought to estimate
the turbine megawatt capability under various ambient and
frequency conditions for system studies.
Closed-Loop Controls –Whenever the controls are
modified or upgraded a new model may be needed and
model validation testing will need to be performed.
Equipment technology plays a large role in determining the
necessity and frequency of testing.
Older mechanical or magnetic amplifier equipment is more
likely to be refurbished, has fewer calibrated settings and is
more susceptible to drift than more modern equipment, and
hence should be tested following major outages.
Both analog electronic and digital electronic equipment
rely on input and output electronics which require
calibration and may exhibit drift. In these cases, equipment
history may provide the best guide for frequency of testing.
VIII. TIMING OF VALIDATION TESTING
Timely validation of computer models is necessary to
ensure their continued validity. Equipment wear, upgrading
and refurbishment, component drift, adjustments to settings
and configuration management all contribute to possible
changes in the dynamic response of the unit. Guidelines for
frequency of model validation testing are summarized
below.
Digital electronic equipment may have drift-free settings,
but may be subject to change control issues (modification
of settings), which should be periodically checked. This
equipment typically has both data logging and testing
facilities built-in, which remove two of the barriers to reverification tests.
Model validation testing should be part of equipment
commissioning. If model validation was not performed
during commissioning then it should be done as soon as
practical.
IX. AMBIENT MONITORING
The concept of an ambient test methodology involves
passive monitoring of generator or system events rather
than active testing. In this case, the recorded responses of
normal or abnormal system or plant events may provide
sufficient data for model validation.
The measured responses to actual power system
disturbances should be compared with simulations
performed using the models, and differences used to
prioritize testing. If no modifications have been made to
the equipment since the last model validation test, then
repeat model validation testing need only be performed if
measured responses to system disturbances disagree with
model predictions.
In conventional dynamic performance testing, specialized
equipment is temporarily connected to the equipment being
tested and the unit is then subjected to some form of
12
artificial step change in one of its input signals in order to
observe the response.
Differences between dynamic responses at different
operating levels can be simulated.
For ambient testing, the design concept of the equipment
would be more task-specific, hopefully reducing its cost to
the point that it could be left connected to the unit for
longer periods or even permanently. This test equipment
would record unit operation under normal operating
conditions and buffer the data for post-event retrieval, or
possibly trigger the capture of data when system conditions
are such that dynamic performance can be adequately
measured and evaluated.
Other functions, such as over excitation limiters, may be
tested by simulating the input signal with the machine shut
down.
Step responses with the generator operating at rated speed,
not synchronized are a good check on the dynamic
performance of the voltage regulator/exciter. A change in
the generator voltage of approximately 1-2% should be
sufficient. An exception is some older voltage regulators
that had different gains for different-sized errors; in such
cases, a larger step may be necessary to check the alternate
gain. In either case, the size of the step should be increased
gradually from zero to avoid unsafe conditions.
It is hoped that the development of an ambient test
methodology would fulfill some of the objectives of
equipment performance testing without incurring the costs
and risks associated with scheduled testing.
Step response tests are also required to check the dynamic
performance on load. As with the open-circuit tests, the
size of the step should be increased gradually from zero.
Ambient testing methods are presently evolving and not yet
fully established methods, although their use has already
proved valuable in some cases [14, 60 and 61], and are
being encouraged as acceptable means of model validation
[32].
If frequency response tests are done with the generator
synchronized, care must be taken to avoid shaft torsional
frequencies. The generator manufacturer can usually
provide the necessary information.
One area where ambient measurements have provided
useful results is in governor droop and dead band
assessment. High-resolution measurement of system
frequency and measurement of unit output (gate position,
fuel valve position and/or active power) are required, but at
low sampling rate (see Figure 5). System frequency
disturbance data may then be analyzed to confirm that the
unit meets system requirements for frequency response.
Care must be taken when performing load rejection tests to
ensure that an over speed condition is not reached. This
can be done by simple calculations prior to the test, based
on the expected unit inertia and governor response.
XI. RECOMMENDED BUILT-IN TEST FACILITIES IN NEW
EQUIPMENT
With most generator excitation control systems now being
implemented using digital technology, opportunities exist
to design equipment with useful features to aid the
validation testing process.
X. PREPARATION, TEST SET-UP AND PRECAUTIONS TO BE
TAKEN DURING TESTING
Testing should be undertaken with knowledge of available
industry standards where possible, such as those listed in
the references [2-11, 40].
When testing such systems the commissioning engineer is
normally able to see the intended settings displayed on
either a built-in display or on a laptop computer. However,
simply examining settings in this way can only be
considered as a quick and easy check to ensure that the
system has correctly retained programmed settings.
If offline exciter or PSS tests are planned, preparation is
required to safely energize the various exciter test supplies.
The ease with which voltage regulator functions can be
enabled in this state varies from machine to machine, but
the tester should be prepared to deal with numerous
interlocks that will have to be bypassed to permit shutdown
testing.
Built in test features should normally include the ability to
assign analog input and output signals to the inputs and
outputs of the various internal stages of the control system.
This allows separate verification of the operation of each
stage and facilitates confirmation of the time constants and
gains.
Some tests must be done with the generator running. In
these cases, personnel who are familiar with this type of
testing should be present. Dangerous voltages are present
in the generator field circuit where transducers need to be
connected. Care should be taken to avoid introducing noise
into high gain circuits when test leads are connected or
disconnected.
It can be very useful to have an internal signal generator
incorporated into the equipment. The internally generated
signal may then be used as an alternative to an analog test
signal generated using separate equipment. It should be
possible to easily adjust the frequency, amplitude and wave
shape of the internally generated signal.
The dynamic performance of some equipment, such as
under excitation limiters, will probably have to be tested
with the generator on load. It is often advisable to reduce
the limiter setting for this test to avoid possible instability
or tripping generator auxiliaries on low voltage.
Another ideal use of digital technology to aid validation
testing is the addition of data recording facilities that
enable sampled waveforms to be viewed on laptop
13
computers. When this is provided it should be possible to
save the sampled data for later reference. This facility
should be provided with flexibility to allow signals to be
recorded from various stages in the control system, with
various sampling periods and with various archiving and
triggering options.
XIII. CONCLUSIONS
This paper outlines the general approach and guidelines for
field testing of generating equipment for the purpose of
deriving and verifying parameters for computer simulation
models of the power plant equipment. This document is a
brief outline of the methodologies used. The reader should
refer to the many references outline through the discussion
for further detail on the testing procedures and techniques.
While it is recommended that the internal recording and
signal generation features should be incorporated into
equipment, on occasions it may be necessary to use
separate signal injection and data recording equipment to
provide independent verification of the operation of
excitation control equipment.
XIV. ACKNOWLEDGEMENTS
The working group would like to thank the many
participants who contributed to this effort both at
committee meetings and via email correspondence.
XII. DEVELOPMENT OF CRITERIA FOR DETERMINING A
MINIMUM THRESHOLD UNIT SIZE FOP PERFORMING
TESTING
XV. REFERENCES:
Typically, units connected to a wholesale market grid tend
to be large. Smaller units are often connected into local
distribution systems, which typically do not have the same
requirements for equipment performance testing.
However, for every rule, there is an exception and some
small units or stations can be found connected directly to
wholesale market grids. In some cases, the cost of periodic
performance testing of these smaller stations could
adversely affect the economic viability of continued
operation within the market. At the same time, the smaller
the units, the less the impact they have on overall system
performance.
Therefore as unit size decreases a) the benefits to the
market from performance testing decreases while b) the
cost of these tests per MWhr delivered increases. Clearly,
at some threshold of unit size, performance testing is no
longer viable.
The cost of conducting testing can be quantified relatively
easily. This includes the actual cost of staff engaged to
conduct the testing plus the lost opportunity cost of not
having bid the unit optimally into the market. It should be
kept in mind, however, that these costs might be reduced in
the re-verification phase of testing. For instance, suitably
trained/knowledgeable local site staff might be substituted
for testing specialists. Also, lost opportunity costs might
be reduced as testing schedules are shortened.
[1]
Byerly R.T. and Kimbark, E.W. Ed., Stability of Large Electric
Power Systems. New York: IEEE Press, 1974.
[2]
IEEE 421.5-2005 Recommended Practice for Excitation System
Models for Power System Stability Studies - models
[3]
IEEE 421.2-1990 Guide for Identification, Testing and Evaluation of
the Dynamic Performance of Excitation Control Systems - testing
[4]
IEEE Std 115-1995 IEEE Guide: Test Procedures for Synchronous
Machines
[5]
IEEE Std 67-1990 IEEE Guide for Operation and Maintenance of
Turbine Generators
[6]
IEEE Std 492-1999 IEEE Guide for Operation and Maintenance of
Hydro Generators.
[7]
IEEE Std 1110-1991 IEEE Guide for Synchronous Generator
Modeling Practices in Stability Analyses - models; testing
[8]
ANSI Std. C50.10-1977 General Requirements for Synchronous
Machines
[9]
ANSI Std. C50.12-1982 Requirements for Salient-Pole Synchronous
Generators for Hydraulic Turbine Operations
[10] ANSI Std. C50.13-1989 Cylindrical-Rotor Synchronous Generators
[11] ANSI Std. C50.14-1977 Requirements for Combustion Gas Turbine
Driven Cylindrical Rotor Synchronous Generator.
[12] CIGRE Technical Brochure 238, Modeling of Gas Turbines and
Steam Turbines in Combined-Cycle Power Plants, December 2003.
[13] "Dynamic Models for Steam and Hydro Turbines in Power System
Studies", IEEE Committee Report, IEEE Trans, Vol PAS-92, NovDec 1973, pp. 1904-1915.
[14] L. Pereira, J. Undrill, D. Kosterev, D. Davies, and S. Patterson, “A
New Thermal Governor Modeling Approach in the WECC”, IEEE
Trans. PWRS, May 2003, pp 819-829.
More difficult is the assessment of the impact on overall
system reliability, especially in trying to express this in
terms of a financial benefit. Generally, system impact can
be taken as meaning the impact on the complete system
within the market operator’s jurisdiction and beyond.
However, in some cases, what might be considered a noncritical unit on such a system wide basis might be critical
on a local basis.
[15] Generator Test Guidelines, WSCC Control Work Group and
Modeling & Validation Work Group, March 1997.
[16] L. N. Hannett and J. W. Feltes, "Testing and Model Validation for
Combined-Cycle Power Plants," in Proc. 2001 IEEE Power
Engineering Society Winter Meeting Conf., pp. 664-670, vol. II.
[17] F. P. de Mello and J. R. Ribeiro, “Derivation of Synchronous
Machine Parameters from Tests”, IEEE Trans. on Power Apparatus
and Systems, vol. 96, no. 4, pp. 1211-1218, July/August 1977.
More work is required by both generators and market
operators to determine a suitable threshold for unit size,
below which performance testing is not required.
[18] Determination of Synchronous Machine Stability Study Constants
Volume 3. EPRI EL-1424, Palo Alto, CA, June 1980.
14
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16