southern regional power committee -...

Special Meeting on PSS related issues held on 21.08.2015

SOUTHERN REGIONAL POWER COMMITTEE BENGALURU

Record Notes of Deliberations of the Meeting on PSS related issues held on 21st August 2015

A Meeting on PSS related issues was held at SRPC, Bengaluru on 21st August

2015. The List of participants is furnished at Annexure-I.

Background Note

Provision for PSS tuning was there in earlier IEGC also. The Enquiry Committee

for grid disturbances constituted by GoI had emphasized on tuning of PSS

(Recommendation 9.9.2). Para 1.4 of Meeting held on 11.03.2014 in MoP to discuss the

Task Force Report is reproduced below:

“Chairman, Task Force informed that the settings of the controllers of the Power

Electronics Devices (PEDs) were done at the time of commissioning of these devices and

were not very effective under the present conditions. It has been recommended by Task

Force that Tuning/re-tuning of Power Electronics Devices (like HVDC Controller, Static

VAR, Compensator etc.) and PSS should be done based on results of studies in the

present network scenarios and the exercise should be repeated every 3-4 years. Task

Force has also recommended that the review and study may be entrusted to independent

agency while retuning of controllers should be entrusted to respective suppliers under

suitable AMC or service contract. It was decided that Powergrid will submit the plan of

action to implement this recommendation and after examination by CEA, the exercise of

study and retuning would be completed by Powergrid in a shortest possible time”

Need for PSS tuning of all major generators had also been raised by SRLDC on a

number of occasions in the recent past keeping in view the sustained oscillations of high

mode and poor damping. In the 27th SRPC Meeting held on 12th May 2015, it was agreed

to constitute a group comprising Members from CTU, SRLDC, Generators & SRPC

Secretariat in respect of PSS tuning.


Clause 5.2(k) of IEGC Regulation is reproduced below:

“All generating stations shall normally have their automatic voltage regulators

(AVRs) in operation. In particular, if a generating unit of over fifty (50) MW size is required

to be operated without its AVR in service, the RLDC shall be immediately intimated about

the reason and duration, and its permission obtained. Power System Stabilizers (PSS)

in AVRs of generating units (wherever provided), shall be got properly tuned by the

respective generating owner as per a plan prepared for the purpose by the CTU/RPC

from time to time. CTU/RPC will be allowed to carry out checking of PSS and further

tuning it, wherever considered necessary.”

CEA (Technical Standards for Connectivity to the Grid) Amendment Regulations,

2013 stipulates the following in respect of PSS:

“ Part II

Connectivity Standards applicable to the generating stations

A. Connectivity Standards applicable to the Generating Stations other than wind and generating stations using inverters

……………..

A1.For Generating stations which are connected on or after the date on which CEA (Technical Standards for Connectivity of the Grid) Regulation, 2007 became effective

( 1 ) The excitation system for every generating unit:-

…………………..

( c ) The Automatic Voltage Regulator of generator of 100 MW and above shall include Power System Stabilizer (PSS)

……………………

A2. For Generating stations which were already connected to the grid on the date on which CEA (Technical Standards for Connectivity of the Grid) Regulation, 2007 became effective

For all thermal generating unit having rated capacity of 200 MW and above and hydro units of having rated capacity of 100 MW and above, the following facilities would be provided at the time of renovation and modernization.

…………………..

( 2 ) Every generating unit of capacity having rated capacity of higher than 100 MW shall have Power System Stabilizer.


……………………”

Summary of Deliberations in the Meeting

It was noted with concern that there was no representation from CTU even though

IEGC envisages role of CTU in PSS tuning. In the Meeting held in MoP cited

above, CTU had been entrusted the works relating to PSS tuning.

It was also noted that TANGEDCO, NTECL, NTPL, KGS, JSWEL, TPCL, NCCPL,

IL&FS & Coastal Energen had not sent their representatives to the Meeting which

was also a matter of concern. KKNPP vide letter dated 20th August 2015

(Annexure-II) had informed that they were not in a position to attend 1st Meeting

on PSS tuning. PSS testing/setting had been carried out on 07th June 2014 and

relevant pages of the test were enclosed.

Presentation made by SRLDC on LFO is at Annexure- III. SRLDC presentation on

Testing of PSS and Experience in NR is at Annexure- IV. Need for PSS tuning in

damping inter-area and local mode of oscillation was highlighted.

Presentation made by NTPC is at Annexure-V.

It was noted that PSS facility was not available in few of the units. In some of the

units it was not enabled / bypassed. PSS was set at default setting by their OEMs.

It was noted that Step Response Test had not been carried out by most of the

generators during last 2 years except NTPC.

On a query, NTPC informed that it was difficult to carry out Step Response Test in

AVR while it was easier in DVR.

Step Response Test is carried with PSS in disabled condition. Thereafter, the Step

Response Test is carried with PSS enabled state. Output curves of both Step

Responses are then compared to establish the effectiveness of damping provided

by PSS.


‘NERC standard for PSS’ and extract from ‘ERCOT Nodal Operating Guide

regarding System Operation and Control Requirement’ is given at Annexure-VI &

VII respectively.

UPCL stated that they had the PSS facility and their OEM was requesting for data

on grid parameter for PSS tuning.

Recommendations finalized in the Meeting:

All utilities to furnish the data/information in respect of PSS as per enclosed format

(Annexure-VIII) by 30th September 2015. Step Response Test schedule (phased

manner) also needs to be furnished by 30th September 2015 to ensure that all the

eligible units are tested and tuned before 31st August 2016. Another Meeting (one

day before PCSC Meeting ) in October 2015 would be held to finalize further action

plan.

It was decided to constitute a group comprising of the members from NTPC, KPCL

(Hydro), UPCL, CTU, SRLDC and SRPC to analyze the date of PSS tuning

submitted by various generating stations and also the periodicity of PSS tuning.

Identified utilities were requested to submit the nominations for the PSS group by

30th September 2015.

PSS settings would be set to dampen mode with oscillations within the range of 0.2

Hz to 2 Hz. The above group would define the damping limits for monitoring

purpose.

NTPC suggested that Step Response Test for PID of AVR at no load was very

much essential before carrying out the retuning activity.

All generating units with capacity over 50 MW, for which PSS have not been tuned

or Step Response Test has not been carried out during last 24 months, should do

so within next 12 months and submit result of Step Response Test to

SRPC/SRLDC/CTU.


If PSS has been tuned or Step Response Test has been carried out during last 24

months, the generating company would submit the results of Step Response Test

to SRPC/SRLDC/CTU within one month.

If results of Step Response Test indicate sufficient damping, generating company

would perform next Step Response Test after 3 years or at the time of major

overhaul of the unit, whichever is earlier.

Generating company would arrange for retuning of PSS, if Step Response Test

indicates insufficient damping or oscillations.

All new units with capacity over 50 MW must carry out PSS tuning before

declaration of Date of Commercial Operation (COD). A report along with model

parameters shall be submitted to CTU/SRLDC/SLDC/SRPC.

SRLDC will observe and analyze the change in the grid condition based on the

output of the PMUs and inform the concerned generating company if un-damped

oscillations beyond agreed pre-defined limits are observed. On receipt of the

information, the generating company would arrange for retuning of PSS within a

time frame of 3 months.

In some of the generating units it may not be feasible to tune PSS. Details of such

units (COD date, capacity, OEM, reasons as to why PSS cannot be tuned etc.)

would be furnished by the generating company. These would be discussed in

OCC/TCC/SRPC and if there is general agreement that PSS tuning was not

feasible, the matter would be taken up by generating company with Hon’ble CERC

for seeking exemption for those units.

PSS shall be kept in service (“On” or energized and performing as designed by the

manufacturer). PSS could be taken out under intimation to SLDC/SRLDC along

with technical justification i.e. for short duration of one week. Exemption beyond

one week needed to be taken up with Hon’ble CERC/SERC.


Retuning of PSS could be covered in AMC/Service Contract preferably entrusted

to the respective supplier.

***

Annexure- III SRLDC Presentation on LFO

Monitoring and Analysis of Oscillations in Southern Regional Grid of India using

Synchrophasor data

2

Contents

• Introduction

• Low Frequency Oscillations

• Detection of LFO using Synchrophasors

• Case Study I

• Case Study II

• Case Study III

• Miscellaneous

• Conclusion

3

Introduction

• Synchrophasor pilot projects have been taken up in all regional grids that have enhanced wide area visualization.

• Dynamic behavior of power system can be viewed which was previously possible only through Disturbance Records.

4

Introduction – Complexity of grid

5

Introduction – Synchrophasor projects

6

Total no of PMUs - 63

Nos.

Region wise PMUs:

NR - 14 Nos

WR - 16 Nos

ER - 12 Nos

SR - 13 Nos

NER - 08 Nos

Low Frequency Oscillations

• Small signal instability is due to insufficient damping torque leading to LFO.

• Oscillatory modes that are well damped may get excited during any small disturbance.

• These oscillations may cause protective equipment to maloperate, fatigue to mechanical parts of generator and reduce transfer capability.

• Classified as Inter-area mode (0.1-1 Hz), local mode and intra-plant mode (1-2.5 Hz).

7

Detection of LFO using Synchrophasors

• System operators cannot detect LFO using SCADA due to the low refresh rate.

• Local modes were only seen as hunting in generators or through simulation studies.

• Phasor measurement units (PMU) that send time tagged data at a rate of 25-50 frames/sec enable operator to visualize the dynamics over a wide area.

• Tools and techniques are in development for the detection of analyzing various power system phenomenon including LFO.

8

Case Study I - Tripping of evacuating lines of generator

9

Line Trip Time

400 kV Vallur-NCTPS-1 02:43

400 kV Vallur-NCTPS-2 03:24

400 kV Vallur-Alamathy-1 03:58

400 kV Vallur-Alamathy-2 03:58

400 kV Vallur-KVPT-2 03:58

3:52 3:58

Unit Trip Time

NCTPS Unit 1 and 2 03:53

Vallur Unit 1 and 2 04:50

20-04-2014

PMU plots

10 10

Station recorder


PMU plot of active power in the

400 kV Kolar-Sriperumbudur line Station Recorder plot from Vallur

OMS Analysis

11 11

PSSE Studies


OMS Engine results PSSE Study results

Case Study II – Spontaneous Oscillations

• Low frequency oscillations across the Indian Grid seen through PMU data in the early hours on 9th-12th Aug 2014.

• Hunting in several of the generating plant in Eastern, Western and Northeastern region.

• Oscillations were observed in HVDC power order and several transmission lines.

• Mode shapes and dominant mode had to be found to determine the likely epicenter.

• The mode spread through the national grid was found.

12

13 13


14 14


Dominant Mode frequency:

9-11th Aug - 0.75 Hz

12th Aug - 0.6 Hz

Coherent groups were obtained from

the OMS Analysis. ER and WR were in

phase with phase shift of -300 to 300.

Southern Region was almost in phase

opposition with that of ER region.

Case Study III – Equipment failure in Gen Station

• Spurious activation of overspeed limiting gear - causing variation in pressure in SV valve, hunting and subsequent oscillations.

• MW output varied between 20-120 MW for 29 secs.

• SPS signal was sent when rate of change of flow (due to the oscillations) went above the setting.

• Analysis showed oscillations with a frequency of 0.23 Hz and damping ratio varying from -5 % to 13 %.

15

PMU plots

16 16

PMU plots


PMU plot of Raichur-Sholapur PMU plot of frequency

06-05-2014

OMS Analysis – Frequency

17 17

OMS Analysis – MW


OMS Engine results OMS Engine results

Miscellaneous

• Local Modes of Oscillation Observed in Thrissur on 26th October 2014.

• None of the generating stations around Thrissur including hydro and thermal stations reported any hunting.

• OMS analysis revealed that the frequency was 1.1 Hz and was not observed beyond Tirunelveli (Hence local mode) as can be seen from the mode energy comparison.

Summary of oscillation modes in SR

Mode frequency Damping Nature Type of Oscillation Particular incident

0.2-0.25 Hz Generally stable with good damping ratio

Inter-area mode Tripping of units such as Vallur, Hunting in Kothagudem Units

0.7 Hz Very low damping (negative too)

Inter-area mode Generator connected by long line (Vallur)

0.58-0.75 Hz Low damping ratio Inter-area mode Spontaneous in nature due to low load response

1.1-1.2 Hz Low damping Local Mode Local modes in and around Thrissur

Conclusion

• From the case studies illustrated we could see how PMU data have enabled in detecting LFO, and also provide an alert to system operator.

• Customized applications of synchrophasors in the operation as well as planning domain are being developed for further exploitation of the technology.

• Make and online application for detecting LFO and determine the mode shape and energy real time.

• Detect dynamic behavior intuitively through their patterns and help alert the operator.

22

Annexure- IV SRLDC presentation(PSS Testing & NR experience)

Power System Stabilizer Testing

Indian Scenario

In Section 5.2.(k) of the Indian Electricity Grid Code (IEGC)

• “All generating units shall normally have their automatic voltage regulators (AVRs) in operation. In particular, if a generating unit of over fifty (50) MW size is required to be operated without its AVR in service, the RLDC shall be immediately intimated about the reason and duration, and its permission obtained. Power System Stabilizers (PSS) in AVRs of generating units (wherever provided), shall be got properly tuned by the respective generating unit owner as per a plan prepared for the purpose by the CTU/RPC from time to time. CTU /RPC will be allowed to carry out checking of PSS and further tuning it, wherever considered necessary”

Experience of Other Region NORTHERN REGION

Initial Steps

• A group comprising one member each from NRPC,CTU,NRLDC,

NTPC & BHEL was formed in 27th TCC/30th NRPC meeting held

on Feb 2014.

• Two meetings on 16th July 2014 & 05th Sept 2014 were held to

analyse the data submitted by various generating stations & also

the periodicity of PSS tuning.

• Continuous follow up on the recommendations given by the

group is taken up in NRPC OCC/TCC meetings.

Discussions held

• BHEL: PSS might require to be re-tuned due to network changes in vicinity of generator

• NTPC: PSS tuning is done in the presence of OEM at the time of Capital overhaul, which is carried out periodically once in a every 3 years.

• NHPC: In case of units with Digital AVR, Step Response Test can be carried out using in-house expertise and presence of OEM may not be required

• NRPC: No shutdown is required for conducting Step Response Test

Recommendations of the Group

• All generating units with capacity over 50 MW would perform Step Response Test for their generating units every year and will submit result to NRPC, NRLDC and CTU

• The generating units for which PSS has not been tuned in last three years will carry out Step Response Test within six month and will submit report to NRPC,NRLDC and CTU.

• NRLDC will observe and analyze output of PMUs and will inform the generating Company concerned if oscillations are observed

• Generating Companies would perform PSS tuning if Step Response Test indicates insufficient damping or oscillations are observed by NRLDC

Basics of PSS

Excitation system with AVR and PSS

Basic Function of PSS :

• To add damping to the generator rotor oscillations by controlling its excitation using

auxiliary stabilizing signals.

• Stabilizer produces a component of electrical torque in phase with rotor speed

deviations for damping

PSS-Components

• Gain

It should be computed at the frequency of oscillations and should

be enough to make damping co-efficient positive

Damping increases with an increase in gain up to a point

Delta-Omega stabilizer: Due to the effect of the torsional filter, the

stability of the "exciter mode" becomes an overriding consideration

Delta-P-Omega stabilizer: Exciter mode stability is not a problem,

and a considerably higher value of gain is acceptable

PSS-Components

• Stabilizing Signal Washout

High pass filter which blocks the interference of PSS during regular function

of exciter during steady state operation

Time constant TW should be high enough to allow signals associated with

oscillations in rotor speed to pass unchanged

For systems with dominant inter area oscillations set TW to about 10s

TW of less than 5s results in significant phase lead at low frequencies

associated with inter area oscillations

PSS-Components

• Lead – Lag Compensator

It provides appropriate phase-lead to compensate for the phase lag

between exciter input and generator electrical torque.

In practice two or more first order blocks may be used to achieve the

desired phase lead

For systems with dominant inter area oscillations ,use one of the phase

compensation blocks to provide phase lag at low frequencies

Classification

Based on input given to PSS:

Speed-based

Frequency- based

Power-based

Integral of Accelerating Power based

Single input

Dual input

Single input PSS model- Speed based

The limitation of this type of stabilizer is the need to use a torsional filter as direct

measurement of shaft speed is used.

Limit on the maximum stabilizer gain

Dual Input– Accelerating Power based

HIGH PASS

FILTERS

HIGH PASS

FILTERS

SPEED

POWER

RAMP

TRACKING

FILTER

GAIN & PHASE

LEAD

• No need for a torsional filter in main stabilizing path

• Higher stabilizer gain

Integral of Pa

PSS Commissioning & Testing

• Suitability of tuning of any PSS is checked in both the time and frequency domains.

• Test procedure in time domain – Small voltage step change is injected into the AVR voltage reference block

• Test procedure in frequency domain – 200mHz – 3 Hz, random noise injection is made to the AVR voltage reference

• Comparison is made between performance ‘with’ and ‘without’ the PSS in service

• Stability of PSS gain setting is also assessed by increasing the gain in stages to 3 times the proposed setting. This increase is carried out gradually while monitoring the generator for any signs of instability

Parameters to be recorded

• Terminal Voltage

• Excitation current

• Active Power Output of the Unit

• Reactive Power Output of the Unit

• PSS output

International Practices

WECC:

• Generator Operators shall have PSS in service 98% of all

operating hours for synchronous generators equipped with

PSS

• For excluding PSS out of service hours, generator operators

must provide date of outage & submit the supporting

documents that applies.

• Generators Operators shall provide quarterly reports to the

compliance monitor

ERCOT :

• The Generation Resource(>10 MW) shall establish PSS settings

to dampen modes with oscillations within the range of 0.2 Hz to 2

Hz.

• At least every five years, Generation Entities shall conduct

performance tests on PSS settings or verify PSS performance

based on operational data. If PSS equipment characteristics are

modified, the Generation Entity shall conduct a performance test

within 30 days of the modification

Test Results KARCHAM WANGTOO : 4 x 250 MW

Step test of Unit #1

operating at 250 MW Unit # 2 operating in parallel @ 150 MW

Case

ID

Dt: 12-04-

2013

Time

Unit

position

Unit in which

step rise in AVR

Vref was given

PSS of

#1 PSS of

#2

Plots

taken

from

1A 18:33:05.893 #1 : 250

MW

#2: 150

MW

#3: Nil

# 4: Nil

# 1 ON ON # 1

1B 18:38:20.803 # 1 ON OFF # 1

1C 18:41:40.253 # 1 OFF OFF # 1

1D 18:33:05.893 # 1 ON ON # 2

Response of Unit # 1

Step input on # 1, PSS-1 & PSS-2 OFF

Active Power

Reactive Power Output

Field Current

PSS contribution

Terminal Voltage


Step input on #1, PSS-1 ON, PSS-2 OFF


Step input on # 1, PSS-1 & PSS-2 both ON

Field Current

Active Power

Terminal Voltage

Reactive Power Output

PSS contribution


Step input on # 1, PSS-1 & PSS-2 both ON

Response of Wangtoo Unit-2 and 4 (Total 550

MW) when 400 kV Wangtoo-Abdullapur-1

carrying 275 MW was opened

400 kV Wangtoo-Jhakri D/C line was open

and Baspa HEP generation was Nil

Case ID Dt: 12-04-

2013

Time

Switching

operation of 400

kV Wangtoo-

Abdullapur-I

PSS of

#1 PSS of

#2

Plots

taken

from

P 11:46:38.157

#1: Nil

#2: 275

MW

#3: Nil

#4: 275

MW

Close to Open ON ON #2

Q #4

R 11:47:46.878 Open to Close ON ON

#2

S #4

T 11:56:28.766 Close to Open OFF OFF

#2

U #4

V 11:57:57.699 Open to Close OFF OFF

#2

W #4


PSS-2 OFF, PSS-4 OFF


PSS-2 ON, PSS-4 ON


PSS-2 OFF, PSS-4 OFF


PSS-2 ON, PSS-4 ON

As observed from PMU data at NRLDC

Test Results RAJPURA THERMAL POWER PLANT : 2 x 700 MW

Way forward for SR

• All generating units (>50 MW) shall inform SRPC/SRLDC when

last PSS tuning was done.

• SLDC may coordinate with the state generating stations (>50

MW) regarding the PSS tuning.

• The generating units for which PSS has not been tuned in last

three years will plan the step response test in coordination with

their OEM and inform SRPC/CTU regarding the same.

Thank You

Annexure- V

NPTC Presentation

Static Excitation

DC AC

Controlled Rectifier

Main Generator

Brushless Excitation

Main Generator

Diode Bridge

(rotating)

Field

Winding AC generator

R R

R

S

S S S

N

S

R

Permanent

Magnet

Generator

R: Rotating Member

S: Stationary Member

Control Signals

From Regulator

Delta

Power

Increased

Excitation

X: Line Reactance

V: Bus Voltage

E: Gen Voltage

P: Power

Power Vs Delta Curve

POWER SYSTEM STABILITY

Power System Instability: Loss of Synchronism

A M/c loses synchronism with the rest of the system, its

Rotor runs at a higher or lower speed w.r. t system frequency:

Causes a) Failure of or Weak excitation system

or b) delayed system fault clearances

or c) transient fault / change in system condition

or d) Failure of governor.

Slip betwn stator field (system freq) & rotor field results in

large fluctuations in power o/p, current & Voltages.

The ability of a PS to maintain stability depends to a large

extent on the control available on the system to damp the

electromechanical oscillations.

DTe = TS Dd + TD Dw

Synchronizing + Damping Torque

Change in Elect

Torque following a

distrurbance =

SSS (Small Signal / Steady State Stability): depends

on a) Initial operating condition, b) strength of the

transmission system, c) Excitation control etc.

With automatic

control

SSS Without automatic

control

Classical Steady

State Stability

Dynamic Stability

Ability of PS to maintain synchronism after

severe disturbance.

Transient

Stability

Dd Dw

DTS

o t Dd

Stable

Positive TS

Positive TD

DTD

DTe

o t Dd

Non Oscillatory

Instability

Negative TS

Positive TD

DTD

DTe

Dd

DTS

Dw

Response of Steady State Stability (small signal stability)

with Manual Excitation (Efd constant)

Lack of Synchronizing torque cause an aperiodic drift in d

Dd Dw

DTS

o t Dd

Stable

Positive TS

Positive TD

DTD

DTe

Dd

Response of Steady State Stability (small signal stability)

with Excitation on AVR(Efd variable)

o t

Dd

Oscillatory

Instability

Positive TS

Negative TD DTD

DTe

DTS

Dw

Lack of sufficient damping torque cause oscillatory instability.

In today’s power system, SSS is largely a problem of

insufficient damping of oscillation. Oscillations of

concern:

Local mode (M/c –system mode): Unit swinging w.r.t

rest of the system.

Interarea modes: Two or more groups are swinging.

Control modes: Generating unit with other control.

Poorly tuned exciters, speed governors, HVDC

converters, SVC are the causes of such mode of

instability.

Torsional modes: SSO- TG shaft system rotational

components. Causes excitation control, speed

governor, HVDC controllers, Series Capacitor

compensated lines.

Multi-machine Systems-Relative motion

Many Swing Modes (0.2 – 2 Hz)

Intra-plant

Inter-area

local

0.5 1.0 1.5 2.0 2.5 3.0 0

Time in sec

d

Transient Stability:

Stable

First Swing

instability: poor Ts

Stable in First Swing but becomes

unstable due to growing

oscillation in post fault condition

which may have poor SSS

Transient stability:

Generator will be transiently stable on the first swing: If the retarding

torque after the fault clearing is sufficient enough to make up for the

acceleration during the fault and the generator moves back to a stable

operating point.

Stability depends on :

1) Excitation controllers

2) Fault clearing time

3) Power angle of the transmission system at the time of fault

4) Severity of disturbances

Fast excitation system can improve Transient Stability.

Small Signal Stability:

Undamped MW oscillation after a disturbances.

Excitation system has the potential cause SS instability.

Compensation from PSS is the solution.

SEE AVR Block Diagram

AVR Block Diagram - Example

(1+sT1)

(1+sT2)

S Vref

Measured Terminal

Voltage

+

-

+

Stabilizing / Limiting Signals

To

Thyristor

Bridge

K

CONTROLLER

(example)

S

+ +

Stabilizing / Limiting Signals

(alternative summing point)

AVR

STATIC EXCITATION SYSTEM

_

Structure of PSS: PSS-2B

Power system stabiliser

• Stabilisation signal =f(∆Pe, ∆f)

∆Pe = change in Electric power

∆f = change in frequency

• The slip signal ∆f follows ∆Pe with a phase delayed by 90 Deg.

• A good damping is obtained if electrical power is varied in phase with load angle

• By applying proper weighting factors( k1,k2) and then adding together the signals ∆Pe and ∆f , an overall stabilising signal can be produced.

∂ ∆Pe

∆f

Resultant

stalising signal k1

k2

Power system stabilizer

• The optimum weighting factors k1 and k2 for a synchronous generator working to a power network depend on its operating point at any moment and the external reactance of the network.

• Selection of a compromise setting is good enough to attain stability in all operating points and for all expected external reactances.

Power system stabiliser

• The PSS stabilisation signal is imposed on AVR only if all the following prequisites are met • Generator on line

• Generator power output >30%

• Generator voltage > 90%

Slip Stabilizing ADAPTER

• The slip stabilizing signal is formed from the sum of generator active power signal and the generator frequency signal. The amplification and mixing ratio for the two signals are referred to as the weighting.

• The stability of the synchronous m/c operating on a network depends on operating point of the m/c and the expected external reactance Xe of the network.

• If the network conditions do not permit the use of compromise setting the PSS adaptor provides a solution

Xe Identification

• The complete operating range of the m/c is divided into six operating sub ranges

• The weighting factors are determined for the six sub ranges and for three different (expected) external reactances Xe

• Total 18 operating sub ranges under consideration

• For each sub range the optimum weighting factors are determined and are stored in table of parameters. The resultant signal is then issued to regulator.

Xe Identification

xe1

xe2

xe3

p1

p2

q1 q2 q3

Xe Identification

• The PSS adapter assess the operating point of the machine and the instantaneous value of external reactance.

• Once this has been done, the corresponding weighting factors are read from the stored table and are transferred to the voltage regulator.

Step Response Test

Frequency Response Test

1920

1930

1940

1950

1960

1970

1980

1990

2000

2010

2020

14.9 15.9 16.9 17.9 18.9 19.9 20.9 21.9

t, с

P, МВтоптимальная настройка

PSS на всех генераторах отключены

оптимальная настройка, PSS генератораBHEL отключен

Character of damping of large post-accident oscillations at emergency

outage of one circuit of Overhead line-765 kV SIPAT-SEONI (Scheme 1 →

Scheme 5). Conditions 1. The equivalent JSC Electrosila’s generator

(РgΣ=1980 MW, QgΣ=1230 MV*A)

Name of the Utility:

Status as on:

Name of

the

Station

Unit

No.

Type(Hydro/

Coal/Gas/Die

sel/Nuclear

IC in

MW

Date of

Commer

cial

Operatio

n(CoD)

AVR or

DVR

PSS

Availabili

ty

(Yes/No)

PSS in

service

or not

Whether

exempted

by ERC

Date of

last Step

Response

Test

Date of Step

Response Test

report furnished to

CTU/SRLDC/SRPC

Date of next

Step Response

Test as per

Generator

Date of next

Step response

Test (in case

insufficient

damping)

Name of

AMC/OEM

for PSS

Status of PSS Tuning of generators of capapcity above 50 MWAnnexure- VIII

southern regional power committee -...

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