FP_A.1_EGAT_AN EXPERIENCE IN POWER SYSTEM STABILIZER
TUNING AND TEST FOR HONGSA POWER PLANT
Rome Woraphan, Electricity Generating Authority of Thailand, (66)24366242, [email protected]
Suphot Jitlikhit, Electricity Generating Authority of Thailand, (66)243662241, [email protected]
Rassamee Youpanich, Hongsa Power Plant, [email protected]
1. ABSTRACT
The large three units of Hong-sa Power Plant (Hong-sa Power Co., HPC in Lao PDR.), 630 MW (741
MVA) 3 units shall be fed to The National (EGAT) grid by two circuit radial lines, 168 kms long. According to
the EGAT’s Grid Code and PPA (Power Purchasing Agreement) criteria that the newcomer power plant have to
present suitable damping for the power oscillation by the Power System Stabilizer (named PSS) embedded in
the AVR (Automatic Voltage Regulator) to avoid poor damping or divert of power oscillations or partial
blackout due to power line tripped. Because HPC was newcomer, the PSS pre-setting by simulation study shall
be done prior to actual test on the EGAT Grid, both local and inter-area mode type of power oscillations.
This paper presents the result of PSS tuning studied by EGAT, proposed the HPC to compare with the
EPC Contractor (CNEEC, China National Electric Equipment Corporation) and consider implementing, and
then the actual test and fine tuning were performed. The paper also presents the accepted results that the three
units HPC PSS model and parameters, i.e. phase compensated (lead/lag), dynamic gain are suitable for damping
power oscillations to meet the acceptance criteria of the EGAT’s PPA that was done in February 2016.
KEYWORDS: Power system stabilizer, PSS, Phase compensated, Oscillation damping
2. INTRODUCTION
Typically, high volumes of electrical power flow can cause electrical systems stability weak. If a large
disturbances, such as a sudden change of load in transmission line (and/or generator side), or small signal
disturbances such as changing of transformer tap (or from any control mode of power apparatus) are applied to
weak system. That may cause a swing or oscillations of electrical power in system. The power system stabilizer
(PSS) installed on power plants can be used for damp out the oscillation of the power happened. The PSS injects
an addition signal to the excitation control of synchronous generator through the AVR (Automatic Voltage
Regulator), to attenuate generator-rotor oscillations. However the PSS must be tuned to work in response to
these particular oscillations. By increasing the damping ratio, the PSS attenuates the oscillation to be steady
soon.
The PSS is used to damp out the power oscillations, which was originally worked of the PSS used to
increase the damping of the power oscillation mode locally (local area mode) due to an oscillation in this mode
are often characterized by the control and operation of the power plant side. But in the current issue of power
oscillation between areas (inter-area mode) due to transmission line is interconnected with the flow of power
between regions increased. Without minimizing the oscillation of the power of this inter area mode, may result
of the expansion of protection equipments operate more and more until both the transmission system and power
plant are active and caused power outages over a wide area (black out). Thus tuning the PSS to get the right
conditions or suitable damping can increase the good damping. To minimize the impact of fluctuations of the
electrical system in the same area (Local area mode) and the areas (Inter-area mode), which will increase the
stability of the power system to a higher by overall.
To create the damping ratio, PSS must build ratio of the electrical torque in phase with the speed of the
rotor. It depends on any type of input signal of PSS, however any input must be compensated by PSS for gain
and phase to work together with exciter, generator and all electrical system properly
The Frequency Response method for tuning the PSS will use Bode diagram for measuring the
frequency response in the form of the display and Gain and Phase Margin of its system. By adjust the
parameters to compensate for the phase by phase lag of AVR (exciter and generator) and phase lead of PSS.
2.1 Power oscillation
2.1.1. Local mode oscillation
The swing on the same area or sometimes referred to as “local area oscillation” occurs at a frequency
of approximately 1-2 Hz, which is the result of the High Initial Response excitation system mostly used in
current power plants. Due to its high gain, particular gain and operation condition cause rapid change in
excitation and generator voltage. This will effects on generator-rotor synchronizing torque or torque angle result
the negative damping in turbine speed torque. As a result, generator-rotor will swing up and oscillate.
2.1.2. Inter-area mode oscillation
The swing of power between occurred at a frequency of approximately 0.1 to 0.8 Hz. oscillations with
a frequency lower than the local mode frequency. The power oscillation may be occurred if there is any change
in the dynamic system or failure in any part of power system or other of nearby system has changed as well. It
can be said that the characteristics of the swing area as a result of the interaction of the interconnected area or
between the generation area connected by.
2.2 Structure of PSS
The PSS is a device used to improve the properties of dynamic's electric power system, using its output
signal to compensate for gain and phase by adding to the AVR. The PSS takes one or more signals from turbine
rotor speed, generator frequency, electrical power, or accelerating power to input of the PSS. The detailed works
by the General PSS Figure 1 are summarized below.
Fig.1 General model of PSS
1. Gain block (K) will determine the magnitude of damping ratio of the PSS.
2. Washout to filter high frequency (high pass filter) allows high frequencies to pass through the PSS
dictated by the time constant Tw.
3. Phase compensation block will make the appropriate offset to phase lead characteristic of lagging
between the input of the exciter generator electrical torque, as Figure 1 shows PSS general model with the single
first order block diagram, which practically first order transfer function block will range from two or more. In
order to compensate for the phase the system needs to lead typically, the phase compensation should be covered
frequencies from 0.1 Hz to 2.0 Hz which phase characteristic to be compensated will change according to the
changing conditions of the electrical system.
4. Input signal of PSS is available in many forms, such as different rates of speed, rotor speed deviation
(Δω), electrical power (Pe), and acceleration power (Pa) when the main function of the PSS is to control the
swing of the rotor of generator. However, it has been found that the use of frequencies as input signal is highly
sensitive to changes occurring in the transmission system and are sensitive to higher frequencies when the
electrical system are weak condition which may affect the control to compensate the electric torque of the
generator. It could say that, the frequency is more sensitive to swings of the areas (inter area oscillation) [8, 10].
Recently, the most PSS use 2 types input signal from rotor speed (ω) and electrical power (Pe), because
if the input of PSS was from speed signal only, in practice, problem occurs with noise in the detecting signal.
Thus, using both input signal, speed (ω) and electrical power (Pe) is the easier and more effective fast response
enough.
2.3 PSS model IEEE type PSS2A
This paper presents the experiences in PSS Model IEEE Standard 421.5 type PSS2A which is 2 type
input PSS, rates of change in speed of the rotor (Δω) and rates of change in electrical power (ΔPe).
Fig 2 PSS model IEEE Std. 421.5 type PSS2A
Figure 2, point A and B, signals are from rotor speed (ω) and electric power (Pe) input to each filters
to make the rate of change in rotor speed and the rate of change in electrical power respectively.
Fig 3 High pass and Low pass filter of rotor speed input
Figure 3, from point A to point C, there are 2 stages of high pass filter and 1 stage of low pass filter to a
synthetic average speed level for a signal to change the speed of the rotor (Δω) and eliminate high frequency
interference (noise) with parameters Tw1, Tw2 and T6 is the time constant filter.
Fig 4 High pass filter and Integrator of electric power input
Figure 4, from point B to point F, there are 2 stages of high pass filter and 1 stage of integrator to create
a synthesized signal a change of electric power (ΔPe) and the Integrator to determine the rate of change of
power, the inertia on the part of the integrator, Ks2 is equal T7 / 2H, Tw3 and Tw4 a time constant of high pass
filter and T7 is the time constant of low pass filter on the Integrator.
Fig 5 Ramp tracking filter
Figure 5, the point D will be adder between Δω and ΔPe / 2H, which results signal ΔPm / 2H fed to
ramp tracking filter. In practice if without this filter, then the signal is composed of Torsional oscillation of
mechanical power (ΔPm) changes slowly. To prevent the signal changes in step and to reduce noise from
Torsional frequencies therefore required ramp tracking filter. Then subtract ΔPm / 2H signal with ΔPe / 2H
signal result will be point G which is based on the relationship between the change in acceleration (ΔPa) and the
rate of change of rotor speed of change Δω represent by equation 2.1.
(2.1)
Fig 6 PSS Gain and Phase compensator
Figure 6, from the point G to the point H is the stabilizer Gain (Ks1) and Phase compensator (lag and
lead) is used for adjusting the output signal of the PSS signal output, from the H to the limit with generator
terminal voltage limiter to avoid PSS built over-output, the point I is added to the signal input to the AVR.
3. PSS tuning techniques by simulation for Hongsa Power Plant (HPC: Hongsa Power Company)
3.1 System Modeling
The model system used for fine-tuning the PSS parameters in this paper uses the general model
SMIB (Single Machine Infinite Bus). Which will result the frequency response of the model is more accurate
than a network model. SMIB will not be disrupted due to the operation of the control devices in other power
plants.
Fig. 7 Model SMIB for HPC unit
Fig. 8 Generator static excitation IEEE type ST1A
Figure 7 shown SMIB model the 1 of 3 unit thermal power plant HPC, with a 750 MVA generator
was suppose to be loaded with 630 MW and 0.0 MVAR (1.0 + j0.0 pu.), where the operating point is highest of
a system gain while the system still remains stable. The generator excitation system with a static excitation
IEEE type ST1A as shown in Figure 8 for the model parameters of generator derived from actual load rejection
test.
AVR/Exciter Parameters Values
TC1 1 s
TC 0.025 s
TB 0.025 s
TB1 1 s
TA 0.025 s
KA 500
VAMX 8.7 pu
Table 1 AVR & Exciter parameters
3.2 Verification of AVR Performance
The model to determine the properties of the AVR will be the first step in the process of fine-
tuning the parameters of the PSS, which begins with a test AVR step response by the small step voltage to the
summing point of AVR reference to see results. The response from the AVR terminal voltage (Vt) and field
voltage (Efd) simulation results show that the AVR system response to changes in 3% no load and synchronized
to grid step response as figure 9 and 10 respectively, which shows clearly that the AVR system of generator
terminal voltage can be controlled completely.
Fig. 9 Inject 3% Step on AVR Set point at generator no-load
Fig. 10 Inject 3% Step on AVR Set point while generator on grid
3.3 Phase Compensator Tuning
A technique to compensate the phase lag of overall generator connected to the network, by phase
(time constant) adjustment, will result in a change in electrical torque to be in phase with the change of the rotor
speed. This phase lag depends on the generator operating point and power system parameters. According to the
criteria of WECC [5] for the oscillation frequency from 0.1 to 1.0 Hz, PSS tuning in the phase compensation
should not exceed ± 30 degrees and the Gain margin should not be lower than 6 dB but not exceed 10 dB. For
this case, the result of simulation using the selected time constants (Table 2) for phase compensation showing by
Bode diagram show frequency response as Figure 11 and 12 respectively.
Time Constant T1 T2 T3 T4
Setting value (S) 0.1 0.02 0.1 0.02
Table 2 Selected time constant for phase compensation
Fig. 11 Bode (Frequency response) diagram
Fig. 12 Gain Margin Test for Kpss = 4 [blue], 8 [green] and 12 [red]
3.4 Gain Tuning
The value of the damping is dependent on Gain of PSS (Kpss) response to the particular
frequency. The Kpss should be set to be optimal that makes the damping maximum but not be over-damping to
make the electrical system worsen. For determining the appropriate Kpss margin should be increase Kpss step
by step until the system begins to swing both the voltage and power (system hunted). In this case, the result
show in Fig. 12 found the Kpss at 8 and 12 results the system began unstable. To considering where the system
remains stable, so it can select the Kpss by 1/3 times following to the terms of WECC [5, 6], so Kpss is
approach to 4.
4. Determination of the PSS tuning for HPC
4.1 Resulting from 3% AVR Step Response Test
After adjust the tuning Gain margin (Kpss = 4) and Phase compensation (T1 = T3 = 0.1S, T2 =
T4 = 0.02S) based on the requirements in article as above, then take those results with simulation using the
“Matlab” program to test and verifies the effect by making a 3% AVR step response, hypothetical conditions
system normally operating point at terminal voltage (Vt) = 1.0 pu., power (P) = 1.0 pu. and reactive power (Q) =
0.125 pu. And perform step voltage to 1.03 pu. to see the results of AVR response. Figure 13 comparisons of
PSS on and off condition. In case the PSS is off while the AVR step signal was injected; 1.3 Hz. of power
oscillations was occurred more than 2 cycles. And while the PSS is on status, it can reduce the oscillation within
1cycle, in accordance with the requirements of WECC [5], IEEE PSS Tuning Tutorial Course [6] and IEEE Std.
421.5 [7]. This selected parameter set was effective to use for actual at the HPC power plant that able to reduce
the power oscillation for “local mode”.
Fig. 13 Response in 3% AVR step response test at PSS on [blue] and PSS off [red] status
4.2 Resulting from transmission line switching (Inter area mode)
Again, the PSS simulation test perform for lower frequency than “local mode” by disconnect 1 of
2 circuits 500 kV transmission line (4wire x1272 MCM ACSR, a distance of about 168 km), assuming that the
system is normal operating point at terminal voltage (Vt) = 1.0 pu., power (P) = 1.0 pu. and reactive power (Q)
= 0.125 pu. Figure 14 comparative cases of PSS in service and PSS out of service found that in cases without
PSS while upon disconnecting 1circuit, the system would have to swing the power with 0.8 Hz oscillation in
several cycles. And the event has occurred while with PSS can reduce power oscillation within about 2-3 cycles.
Fig. 14 Response in 1 of 2 circuits switching test at PSS on [blue] and PSS off [red]
4.3 Implement and actual field test at HPC (using PSS studied parameters)
The results obtained by fine-tuning parameters PSS under article above (Gain and Phase tuning
method) can be used as a pre-setting for the Hong-sa power plant (HPC) 741 MVA, 630 MW. The test perform
to verifies the response of the AVR and PSS to reduce the power oscillation tested at 2% AVR step response in
PSS on and PSS off by pre-condition for generator with active power> 80%, Vt = 100% and Q. <20%, the test
results demonstrated that the swing of power at a frequency of 1.3Hz or similar results to simulation study. Test
results show that the actual test for HPC unit1 as figure 15 and 16 respectively.
Fig. 15 Response in 2% AVR step response test at PSS off for HPC unit1
Fig. 16 Response in 2% AVR step response test at PSS on for HPC unit1
The results of the actual field test that had better slightly tune T1, T3 and T4 (lead- lag compensator)
and T8, T9 (ramp tracking filter time constant) so that PSS can create ratio of the electrical torque keep in-phase
with the generator-rotor speed change to enhance the damping ratio reduced the power oscillation. Table 3
shows the PSS parameters comparison between the simulation study and the final setting at site tuning.
Table 3 PSS parameters compare the simulation study with actual site tuning
Description ParameterSimulation
Study
Tuned
Setting
First stabilizer input code ICS1 1 1
First remote bus number REMBUS1 0 0
Second stabilizer input code ICS2 3 3
Second remote bus number REMBUS2 0 0
Ramp tracking filter order M 5 5
Ramp tracking filter order N 1 1
Washout time constant Tw1 6 6
Washout time constant Tw2 6 6
Filter time constant T6 0 0
Washout time constant Tw3 6 6
Filter time constant Tw4 0 0
Washout time constant T7 6 6
Gain KS2 0.83 0.83
Gain KS3 1 1
Ramp tracking filter time constant T8 0.5 0.6
Ramp tracking filter time constant T9 0.03 0.12
Stabilizer Gain KS1 4 4
Phase lead time constant T1 0.1 0.15
Phase lag time constant T2 0.02 0.02
Phase lead time constant T3 0.1 0.3
Phase lag time constant T4 0.02 0.03
Output limits VSTMAX 0.1 0.1
Output limits VSTMIN -0.1 -0.1
Generator Apparent Power MBASE 741 741
ตารางท่ี 5 แสดงคา่เปรียบเทียบพารามิเตอร์ท่ีไดจ้ากการ Simulation Study และ Field Test
Test results in the “inter area mode” with the transmission switching, since the simulation study
found when one circuit was opened to create a disturbance to the power. The swing system takes a swing at a
frequency which is different from the “local mode” frequency that is approximately 0.8 Hz. due to the size of
the transmission lines are large enough and not too long, the resistance or impedance is slightly low, according
to a study from the Hongsa - Nan (HSA - NA) distance of about 168 kms.
Fig. 17 Shown transmission line (Thailand northern part) MM3- NA to HSA (Lao PDR) 172 Kms.
For the actual field test, the transmission line extends from the study to disconnect the
transmission line Mae moh 3 - Nan (MM3 - NA) circuit, one of the existing two circuits switching open and
close to achieve the swing of power interact in “inter area mode” when disconnect the line MM3 - NA out one
circuit will occur. According to a study of the power swing is 0.8 Hz and the grid actually oscillation was
similar to the simulation study. It was the swing of the power flow in HSA-NA transmission line at the study
while the line was open and closed. The value of PSS parameter after fine tuning able to damp out the
oscillation power in transmission lines or “inter are” within 2-3 cycles from normal swing naturally but without
the PSS will be of 10 cycles.
Fig. 18 Line MM3-NA Switching Open with PSS on
520.0 530.0 540.0 550.0 560.0 570.0 580.0 590.0 600.0
0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160
Po
we
r (M
W)
Time (mSec)
"Open" 1 out of 2 Line
(Line MM3-NA)
HSA (Lao PDR)
Nan
Mae moh 3
Fig. 19 Line MM3-NA Switching closed with PSS on
5. Conclusion
By comparison, the simulation and field test and found frequency response technique is a method that
is effective for the use of fine-tuning the parameters of the PSS, which has made the output voltage of generator
remained stable and able to reduce the oscillation of the generator rotor will affect the cause of the power swing
or power oscillation in the electrical power system. The parameters can be tuned the PSS track the oscillation
angle of the generator rotor and the PSS outputs a signal in the form of the compensated signal (Vs) to the AVR
for enhancing the damping ratio in the power system. The simulation study and the actual field test for this
experience in the PSS tuning for Hong-sa thermal power plant conducted by WECC [5] was completely meets
the requirement of PPA (Power Purchasing Agreement) of both HPC and EGAT.
6. References
[1] Andrea Angel Zea, “Power System Stabilizer for the Synchronous Generator Tuning and
Performance Evaluation”, Master of Science Thesis, Deparment of Energy and Environment,
Division of Electric Power Engineering, Chalmers University of Technology, G’oteborg, Sweden,
2013.
[2] Dr. A. Murdoch, S. Vetakaraman, R.A. Lawson and W.R. Pearson, “Integral of Accelerating
Power Type PSS Part 1-Theory, Design and Tuning Methodology” IEEE Transaction and Energy
Conversion, Vol.14, No. 4 December 1999.
[3] Prabha Kundur, “Power Stability and Control, 1994.
[4] Jeonghoon Shin, Suchul Nam, Jaegul Lee, Seungmook Baek, Youngdo Choy and Taekyun Kim
“A Practical Power System Stabilizer Tuning Method and its Verification in Field Test”, Journal
of Electrical Engineering & Technology Vol. 5, No. 3, pp. 400~406, 2010
[5] “Power System Stabilizer Tuning Guidelines and Power System Stabilizer Design and
Performance Criteria”, Western Electricity Coordinating Council (WECC), April 23, 2004.
[6] “Power System Stabilizer via Excitation Control IEEE Tutorial Course”, IEEE Power Engineering
Society Committee Meeting, Tempa, Florida, June 2007
[7] “Recommended Practice for Excitation System Models for Power System Studies”, IEEE Std.
421.5-1992.
[8] P. Kundur, M. Klein, G.J. Rogers, M.S. Zywno, “Application of Power System Stabilizers For
Enhancement Of Overall System Stability”, IEEE Transactions on Power Systems, Vol. 4, No. 2,
May 1989.
520.0 530.0 540.0 550.0 560.0 570.0 580.0 590.0 600.0
0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160
Po
we
r (M
W)
Time (mSec)
"Close" Line (Line MM3-NA)