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, rome.w@egat.co.th

Suphot Jitlikhit, Electricity Generating Authority of Thailand, (66)243662241, suphot.j@egat.co.th

Rassamee Youpanich, Hongsa Power Plant, Rassamee_Y@Hongsapower.com

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)