power system stability in the new industry environment:...

1529pk - 1

Power System Stability in the New Industry Power System Stability in the New Industry

Environment: Environment: Challenges and SolutionsChallenges and Solutions

presented by: presented by:

Dr. Prabha S. KundurDr. Prabha S. Kundur

Kundur Power Systems Solutions, Inc.Kundur Power Systems Solutions, Inc.

Toronto, OntarioToronto, Ontario

CanadaCanada

Tutorial

Copyright © P. KundurThis material should not be used without the author's consent

1529pk - 2Copyright © P. Kundur

Power System Stability and ControlPower System Stability and Control

Tutorial Outline

1. Brief Introduction to Power System Stability

� Basic concepts

� Classification

2. Examples of Major System Blackouts Caused by Different Forms

of Instability

3. Challenges to Secure Operation of today's Power Systems

4. Major System Blackouts in 2003 and 2004

5. Comprehensive Approach to Enhancing Power System Stability


Power System StabilityPower System Stability

� Refers to continuance of intact operation of power system,

following a disturbance

� Recognized as an important problem for secure system operation

since the 1920s

� Major concern since the infamous November 9, 1965 blackout of

Northeast US and Ontario

� criteria and analytical tools used till now largely based on the

developments that followed

� Presents many new challenges for today's power systems


Power System Stability: Basic ConceptsPower System Stability: Basic Concepts

� Power System Stability denotes the ability of an electric power

system, for a given initial operating condition, to regain a state of

operating equilibrium after being subjected to a physical

disturbance, with all system variables bounded so that the system

integrity is preserved

� integrity of the system is preserved when practically the entire power

system remains intact with no undue tripping of generators or loads

� Stability is a condition of equilibrium between opposing forces:

� instability results when a disturbance leads to a sustained imbalance

between the opposing forces

Ref: IEEE/CIGRE TF Report, "Definition and Classification of Power System Stability",

IEEE Trans. on Power Systems, Vol. 19, pp. 1387-1401, August 2004


Basic Concepts Basic Concepts (cont'd)(cont'd)

� Following a transient disturbance, if the power system is stable it will reach a

new equilibrium state with practically the entire system intact:

� faulted element and any connected load are disconnected

� actions of automatic controls and possibly operator action will eventually

restore system to normal state

� On the other hand, if the system is unstable, it will result in a run-away or

run-down situation; for example:

� a progressive increase in angular separation of generator rotors, or

� a progressive decrease in bus voltages

� An unstable system condition could lead to cascading outages, and a shut-

down of a major portion of the power system


Classification of Power System StabilityClassification of Power System Stability

� Classification into various categories greatly facilitates:

� analysis of stability problems

� identification of essential factors which contribute to instability

� devising methods of improving stable operation

� Classification is based on the following considerations:

� physical nature of the resulting instability

� size of the disturbance considered

� devices, processes, and the time span involved

� We should always keep in mind the overall stability !

� solutions to problems of one category should not be at the

expense of another


Power System Stability

Frequency Stability

Small-Signal Stability

Transient Stability

Short Term Long Term

Large-Disturbance Voltage Stability

Small-Disturbance Voltage Stability

Voltage Stability

Rotor Angle Stability

Consideration for

Classification

Physical Nature/ Main

System

Parameter

Size of Disturbance

Time Span

Short Term

Short Term Long Term


Rotor Angle StabilityRotor Angle Stability

� Ability of interconnected synchronous machines to remain in

synchronism after being subjected to a disturbance

� Depends on the ability to restore equilibrium between electromagnetic

torque and mechanical torque of each synchronous machine

� If the generators become unstable when perturbed, it is as a result of

� a run-away situation due to torque imbalance

� A fundamental factor is the manner in which power outputs of

synchronous machines vary as their rotor angles swing

� Instability that may result occurs in the form of increasing angular

swings of some generators leading to loss of synchronism with other

generators


Transient StabilityTransient Stability

� Term traditionally used to denote large-disturbance angle stability

� Ability of a power system to maintain synchronism when

subjected to a severe transient disturbance:

� influenced by the nonlinear power-angle relationship

� stability depends on the initial operating condition and severity of

the disturbance

� A wide variety of disturbances can occur on the system:

� The system is, however, designed and operated so as to be stable

for a selected set of contingencies

� usually, transmission faults: L-G, L-L-G, three phase


SmallSmall--Signal (Angle) StabilitySignal (Angle) Stability

� Small-Signal (or Small-Disturbance) Stability is the ability of a power

system to maintain synchronism under small disturbances

� disturbance considered sufficiently small if linearization of system

equations is permissible for analysis

� Instability that may result can be of two forms:

� aperidic increase in rotor angle due to lack of sufficient synchronizing

torque

� rotor oscillations of increasing amplitude due to lack of sufficient

damping torque

� In today's practical power systems, SSS problems are usually

associated with oscillatory modes

� local plant mode oscillations: 0.8 to 2.0 Hz

� interarea oscillations: 0.1 to 0.8 Hz


Voltage StabilityVoltage Stability

� Ability of power system to maintain steady voltages at all buses in the

system after being subjected to a disturbance

� A system experiences voltage instability when a disturbance, increase in

load demand, or change in system condition causes:

� a progressive and uncontrollable fall or rise in voltage of buses

in a small area or a relatively large area

� Main factor causing voltage instability is the inability of power system to

maintain a proper balance of reactive power and voltage control actions

� The driving force for voltage instability is usually the load characteristics


ShortShort--Term and LongTerm and Long--Term Voltage StabilityTerm Voltage Stability

� Short-term voltage stability involves dynamics of fast acting load

components such as induction motors, electronically controlled

loads and HVDC converters

� study period of interest is in the order of several seconds

� dynamic modeling of loads often essential; analysis requires

solution of differential equations using time-domain simulations

� faults/short-circuits near loads could be important

� Long-term voltage stability involves slower acting equipment such as

tap-changing transformers, thermostatically controlled loads, and

generator field current limiters

� study period may extend to several minutes


Frequency StabilityFrequency Stability

� Ability to maintain steady frequency within a nominal range

following a disturbance resulting in a significant imbalance

between generation and load

� Instability that may result occurs in the form of sustained

frequency swings leading to tripping of generating units and/or

loads

� In a small "island" system, frequency stability could be of concern

for any disturbance causing a significant loss of load or

generation


Frequency Stability Frequency Stability (cont'd)(cont'd)

� In a large interconnected system, frequency stability could be of

concern only following a severe system upset resulting in the

system splitting into islands

� Depends on the ability to restore balance between generation and

load of island systems with minimum loss of load and generation

� Generally, frequency stability problems are associated with

inadequacies in equipment responses, poor coordination of

control and protection systems


Examples of Major System Blackouts Caused by Examples of Major System Blackouts Caused by

Different Forms of InstabilityDifferent Forms of Instability

1. November 9, 1965 blackout of Northeast U.S. and Ontario

2. April 19, 1972, blackout of Eastern Ontario

3. July 2, 1996 disturbance of WSCC (Western North

American Interconnected) System

4. August 10, 1996 disturbance of WSCC system

5. March 11, 1999 Brazil blackout

1529pk - 16

November 9, 1965 Blackout of November 9, 1965 Blackout of

Northeast U.S. and OntarioNortheast U.S. and Ontario

Copyright © P. Kundur


November 9, 1965 Blackout of NE U.S. and OntarioNovember 9, 1965 Blackout of NE U.S. and Ontario

� Clear day with mild weather; load levels in the region normal

� Problem began at 5:16 p.m.

� Within a few minutes, there was a complete shut down of electric

service to:

� virtually all of the states of New York, Connecticut, Rhode Island,

Massachusetts, Vermont

� parts of New Hampshire, New Jersey and Pennsylvania

� most of Ontario

� Nearly 30 million people were without power for about 13 hours


North American Eastern Interconnected SystemNorth American Eastern Interconnected System


Events that Caused the 1965 BlackoutEvents that Caused the 1965 Blackout

� The initial event was the operation of a backup relay (zone 3)

at Beck GS in Ontario near Niagara Falls

� opened circuit Q29BD, one of five 230 kV circuits connecting

Beck GS to load centers in Toronto and Hamilton

� Prior to opening of Q29BD, the five circuits were carrying

� 1200 MW of Beck generation, and

� 500 MW import from Western NY State on Niagara ties

� Loading on Q29BD was 361 MW at 248 kV;

The relay setting corresponded to 375 MW


Events that Caused the 1965 Blackout Events that Caused the 1965 Blackout (cont'd)(cont'd)


Events that Caused the 1965 Blackout Events that Caused the 1965 Blackout (cont’d)(cont’d)

� Opening of circuit Q29BD resulted in sequential tripping of the

remaining four parallel circuits

� Power flow reversed to New York: total change of 1700 MW

� Generators in Western New York and Beck GS lost synchronism,

followed by cascading outages: Transient (Angle) Instability !

� After about 7 seconds from the initial disturbance

� system split into several separate islands

� Eventually most generation and load lost due to the inability of

islanded systems to stabilize: Frequency Instability !


Formation of Reliability CouncilsFormation of Reliability Councils

� Northeast Power Coordinating Council (NPCC) formed in January 1966

� to improve coordination in planning and operation among utilities

� first Regional Reliability Council (RRC) in North America

� Other eight RRCs formed in the following months

� National/North American Electric Reliability Council (NERC)

established in 1968

� Detailed reliability criteria were developed;

Procedures for exchange of data and conducting stability studies were

established

� Many of these developments have had an influence on utility practices

worldwide; still largely used !


Special Protections Implemented after the 1965 BlackoutSpecial Protections Implemented after the 1965 Blackout

� ∆∆∆∆P Relays on Niagara Ties

� trip Niagara ties to NY when ∆∆∆∆P exceeds set value;cross-trip St. Lawrence ties to NY

� in place until mid 1980s

� Underfrequency load shedding (UFLS) throughout the

interconnected system

� beginning of the use of UFLS by the industry

1529pk - 24

April 19, 1972 Blackout of April 19, 1972 Blackout of

Eastern OntarioEastern Ontario



April 19, 1972 Disturbance: Eastern OntarioApril 19, 1972 Disturbance: Eastern Ontario

� Incident:

� 230 kV lines east of Toronto tripped due to communication malfunction;

ties to New York at St. Lawrence tripped

� generation rich island formed in eastern Ontario (G=3900 MW, L=3000 MW)

� frequency rose to 62.5 Hz and then dropped to 59.0 Hz due to speed

governor

� underfrequency load shedding !

� frequency rose to 62.6 Hz and dropped to 58.7 Hz

� stabilized at 60.8 Hz with 1875 MW generation

� Frequency Instability !

� Source of problem: overspeed controls associated with prime-mover

governors of Pickering “A:” NGS


MHC Turbine Governing System with Auxiliary MHC Turbine Governing System with Auxiliary

GovernorGovernor


Transient Response of Nuclear Units with Auxiliary Transient Response of Nuclear Units with Auxiliary

GovernorGovernor


Transient Response of Nuclear Units with Auxiliary Transient Response of Nuclear Units with Auxiliary

Governor OutGovernor Out--ofof--ServiceService

1529pk - 29

July 2, 1996 WSCC / WECC July 2, 1996 WSCC / WECC

(Western North American (Western North American

Interconnected System) Interconnected System)

DisturbanceDisturbance



WSCC July 2, 1996 DisturbanceWSCC July 2, 1996 Disturbance

� Started in Wyoming and Idaho area at 14:24:37

� Loads were high in Southern Idaho and Utah;

High temperature around 38°C

� Heavy power transfers from Pacific NW to California

� Pacific AC interties - 4300 MW (4800 rating)

� Pacific HVDC intertie - 2800 MW (3100 capacity)


WSCC July 2, 1996 Disturbance WSCC July 2, 1996 Disturbance (cont'd)(cont'd)



� LG fault on 345 kV line from Jim Bridger 2000 MW plant in

Wyoming to Idaho due to flashover to a tree

� tripping of parallel line due to relay misoperation

� Tripping of two (of four) Jim Bridger units as stability control; this

should have stabilized the system

� Faulty relay tripped 230 kV line in Eastern Oregon

� Voltage decay in southern Idaho and slow decay in central Oregon


WSCC July 2, 1996 Disturbance WSCC July 2, 1996 Disturbance (cont’d)(cont’d)

� About 24 seconds later, a long 230 kV line (Amps line) from western

Montana to Southern Idaho tripped, due to zone 3 relay operation

� parallel 161 kV line subsequently tripped

� Rapid voltage decay in Idaho and Oregon

� Three seconds later, four 230 kV lines from Hells Canyon generation to

Boise tripped

� Two seconds later, Pacific intertie lines separated

� Cascading to five islands 35 seconds after initial fault

� 2.2 million customers experienced outages; total load lost 11,900 MW

� Voltage Instability!!!



Loss of voltage control following

the tripping of the Amps line

Time in Seconds


TSAT was Used to Replicate Disturbance TSAT was Used to Replicate Disturbance

in Time Domainin Time Domain

MEASURED RESPONSE

SIMULATED RESPONSE

1529pk - 37

August 10, 1996 WSCC August 10, 1996 WSCC

(WECC) Disturbance(WECC) Disturbance



WSCC August 10, 1996 DisturbanceWSCC August 10, 1996 Disturbance

� High ambient temperatures in Northwest;

high power transfer from Canada to California

� Prior to main outage, three 500 kV line sections from lower Columbia

River to load centres in Oregon were out of service due to tree faults

� California-Oregon Interties loaded to 4330 MW north to south

� Pacific DC Intertie loaded at 2680 MW north to south

� 2300 MW flow from British Columbia

� Main outage: Ross-Lexington 230 kV line at 15:47:36

� Growing 0.23 Hz interarea oscillations caused tripping of lines

resulting in formation of four islands

� Small-Signal Oscillatory Instability !


August 10th, 1996 WSCC EventAugust 10th, 1996 WSCC Event


Malin - Round Mountain MW Flow

2300

2400

2500

2600

2700

2800

2900

3000

0 3 6 9 12 16 19 22 25 28 31 34 37 40 43 47 50 53 56 59 62 65 68 71 74

Time in Seconds

WSCC August 10, 1996 Disturbance WSCC August 10, 1996 Disturbance (cont'd)(cont'd)


As a result of the undamped

oscillations, the system split

into four large islands

Over 7.5 million customers

experienced outages ranging

from a few minutes to nine

hours! Total load loss 30,500

MW

WSCC August 10, 1996 Disturbance WSCC August 10, 1996 Disturbance (cont'd)(cont'd)


TSAT was Used to Replicate Disturbance in TSAT was Used to Replicate Disturbance in

Time DomainTime Domain

MEASURED RESPONSE

SIMULATED RESPONSE


Sites Selected for PSS ModificationsSites Selected for PSS Modifications

San Onofre

(Addition) Palo Verde

(Tune existing)


Power System StabilizersPower System Stabilizers

With existing controls

Eigenvalue = 0.0597 + j 1.771

Frequency = 0.2818 Hz

Damping = -0.0337

With PSS modifications

Eigenvalue = -0.0717 + j 1.673

Frequency = 0.2664

Damping = 0.0429


Design of HVDC ModulationDesign of HVDC Modulation

� HVDC intertie shown (as expected) to have low participation in the

mode of interest (0.23 Hz interarea oscillations)

� Often however, HVDC can be modulated to improve damping, provided

adequate input signal is found and proper compensator is designed

� SSAT used to examine frequency response for several potential input

signals

� Frequency response magnitude identified local bus frequencyas

having good operability/controllability of the mode of interest

� Frequency response phase used to design compensator which

provides proper modulation signal to HVDC controls

� TSAT and SSAT used to verify modulation performance


TSAT Verification of Effectiveness of HVDC TSAT Verification of Effectiveness of HVDC

ModulationModulation

Without HVDC Modulation

Eigenvalue = 0.0597 + j 1.771

Frequency = 0.2818 Hz

Damping = -0.0337

With HVDC Modulation

Eigenvalue = -0.108 + j 1.797

Frequency = 0.2859

Damping = 0.0602

1529pk - 48

March 11, 1999 Brazil March 11, 1999 Brazil

BlackoutBlackout



March 11, 1999 Brazil BlackoutMarch 11, 1999 Brazil Blackout

� Time: 22:16:00h, System Load: 34,200 MW

� Description of the event:

� L-G fault at Bauru Substation as a result of lightning causing a bus

insulator flashover

� the bus arrangement at Bauru such that the fault is cleared by opening

five 440 kV lines

� the power system survived the initial event, but resulted in instability

when a short heavily loaded 440 kV line was tripped by zone 3 relay

� cascading outages of several power plants in Sao Paulo area, followed

by loss of HVDC and 750 kV AC links from Itaipu

� complete system break up: 24,700 MW load loss; several islands

remained in operation with a total load of about 10,000 MW

� Transient instability followed by voltage problems


March 11, 1999 Brazil Blackout March 11, 1999 Brazil Blackout (cont'd)(cont'd)

� Measures to improve system security:

� Joint Working Group comprising ELECTROBRAS, CEPEL and ONS staff

formed

� organized activities into 8 Task Forces

� Four international experts as advisors

� Remedial Actions:

� power system divided into 5 security zones: regions with major

generation and transmission system;

emergency controls added for enhancing stability

� improved layout and protection of major EHV substations

� improved maintenance of substation equipment and protection/control

equipment

� improved restoration plans

1529pk - 51

Challenges to Secure Operation of Challenges to Secure Operation of

Today's Power SystemsToday's Power Systems



Limitations of Traditional Approach to Power Limitations of Traditional Approach to Power

System StabilitySystem Stability

� Focus largely on one aspect of stability: "transient stability"

� Deterministic approach for system security assessment

� System designed and operated to withstand

� loss of any single element preceded by a fault

� referred to as N-1 criterion

� Analysis by time-domain simulation of selected operating

conditions

� scenarios based on judgment/experience

� Operating limits based on off-line studies

� system operated conservatively within pre-established limits

� "Adhoc Approach" to application of power system stability

controls


Challenges to Secure Operation of Today's Challenges to Secure Operation of Today's

Power SystemsPower Systems

� Power Systems are large complex systems covering vast

geographic areas

� national/continental grids

� highly nonlinear higher order system

� Many processes whose operations need to be coordinated

� millions of devices requiring harmonious interplay

� Increasing use of Wind Power for generation of electricity

� requires careful consideration in integration with power grids

cont'd


Challenges to Secure Operation of Today's Power Challenges to Secure Operation of Today's Power

SystemsSystems (cont'd)(cont'd)

� Complex modes of instability

� global problems

� different forms of instability: rotor angle, voltage, frequency

� "Deregulated" market environment

� many entities with diverse business interests

� system expansion and operation driven largely by economic drivers

� lack of coordinated planning


Example of a Complex Mode of InstabilityExample of a Complex Mode of Instability

A transmission line fault causes transient instability of a

remote area:

� Sensitive to conditions in the faulted area

� Nature of the stability problem is not readily apparent


North American Western Interconnected SystemNorth American Western Interconnected System


Case ACase A

� 4-cycle fault on Palo Verde - Devers line (Arizona-California)

� Alberta to B.C. transfer 500 MW

� East of River interface flow 7300 MW

Note: power flow conditions considered for this study as unusual,

and do not represent present operating conditions


BPA Bus VoltageBPA Bus Voltage


BC Hydro Bus Voltage Near Alberta TieBC Hydro Bus Voltage Near Alberta Tie


Rotor Angles in B.C. and AlbertaRotor Angles in B.C. and Alberta


Case BCase B

� East of River interface flow reduced to 7000 MW

(from 7300 MW for Case A)


BC Hydro and Alberta Bus VoltagesBC Hydro and Alberta Bus Voltages


Rotor Angles in B.C. and AlbertaRotor Angles in B.C. and Alberta


North American Western Interconnected SystemNorth American Western Interconnected System


Major Power System Blackouts in 2003 Major Power System Blackouts in 2003

and 2004and 2004


Blackouts in 2003 and 2004Blackouts in 2003 and 2004

We had several wake up calls since 2003:

� August 14, 2003 blackout of North East USA and Ontario

� 63,000 MW load loss affecting 50 million people

� September 23, 2003 blackout of South Sweden and East Denmark

� 6,500 MW load loss affecting 4 million people

� September 28, 2003 blackout of Italy

� 50,000 MW load unsupplied affecting 60 million people

� August 12, 2004 blackout of three Australian States: Queensland,

NSW and Victoria

� load loss 1,000 MW


August 14, 2003 Blackout of Northeast US August 14, 2003 Blackout of Northeast US

and Canadaand Canada


14 August 2003 Blackout of Northeast US 14 August 2003 Blackout of Northeast US -- CanadaCanada

� Approximately 50 million people in 8 states in the US and

2 Canadian provinces affected

� 63 GW of load interrupted (11% of total load supplied by Eastern

North American Interconnected System)

� During this disturbance, over 400 transmission lines and 531

generating units at 261 power plants tripped

� For details refer to: "Final Report of Aug 14, 2003 Blackout in the

US and Canada: Causes and Recommendations", US-Canada

Power System Outage Task Force, April 5, 2004. www.NERC.com


NERC Regions Affected: MAAC, ECAR, NPCCNERC Regions Affected: MAAC, ECAR, NPCC


Conditions Prior to BlackoutConditions Prior to Blackout

� Electricity demand high but not unusually high

� Power transfer levels high, but within established limits and

previous operating conditions

� Planned outages of generating units in the affected area: Cook

2, Davis Bess plant, East Lake 4, Sammis 3 and Monroe 1

� Reactive power supply problems in the regions of Indiana and

Ohio prior to noon

� Operators took actions to boost voltages

� voltages within limits

� System operating in compliance with NERC operating policies

prior to 15:05 Eastern Daylight Time


Blackout Started in MidwestBlackout Started in Midwest


Sequence of EventsSequence of Events

� The Midwest ISO (MISO) state estimator and real-time contingency

analysis (RTCA) software not functioning properly from 12:15 to 16:04

� prevented MISO from performing proper "early warning" assessments

as the events were unfolding

� At the First Energy (FE) Control Center, a number of computer

software problems occurred on the Energy Management System

(EMS) starting at 14:14

� contributed to inadequate situation awareness at FE until 15:45

� The first significant event was the outage of East Lake generating unit

#5 in the FE system at 13:31:34

� producing high reactive power output

� voltage regulator tripped to manual on overexcitation

� unit tripped when operator tried to restore AVR


East Lake 5 Trip: 1:31:34 pmEast Lake 5 Trip: 1:31:34 pm

ONTARIO

2

1

ONTARIO


� Initial line trips in Ohio, all due to tree contact:

� Chamberlin-Harding 345 kV line at 15:05:41

� Hanna-Juniper 345 kV line at 15:32:03

� Star-South Canton 345 kV line at 15:41:35

� Due to EMS failures at FE and MISO control centers, no proper

actions (such as load shedding) taken

� Critical event leading to widespread cascading outages in Ohio

and beyond was tripping of Sammis-Star 345 kV line at 16:05:57

� Zone 3 relay operation due to low voltage and high power flow

� Load shedding in northeast Ohio at this stage could have

prevented cascading outages that followed

Sequence of Events Sequence of Events cont'dcont'd


� Tripping of many additional 345 kV lines in Ohio and Michigan by

Zone 3 (or Zone 2 set similar to Zone 3) relays

� Tripping of several generators in Ohio and Michigan

� At 16:10:38, due to cascading loss of major lines in Ohio and

Michigan, power transfer from Canada (Ontario) to the US on the

Michigan border shifted

� power started flowing counter clockwise from Pennsylvania through

New York and Ontario into Michigan

� 3700 MW of reverse power flow to serve loads in Michigan and Ohio,

which were severed from rest of interconnected system except Ontario

� Voltage collapsed due to extremely heavy loadings on transmission

lines

� Cascading outages of several hundred lines and generators leading

to blackout of the region

Sequence of EventsSequence of Events


End of CascadeEnd of Cascade

Areas Affected by the Blackout

Serv ice maintained

in some area

Some Local Load

Interrupted


Primary Causes of BlackoutPrimary Causes of Blackout(as identified by the US(as identified by the US--Canada Outage Task Force)Canada Outage Task Force)

1. Inadequate understanding of the power system requirements:

� First Energy (FE) failed to conduct rigorous long-term planning

studies and sufficient voltage stability analyses of Ohio control area

� FE used operational criteria that did not reflect actual system

behaviour and needs

� ECAR (East Central Area Reliability Council) did not conduct an

independent review or analysis of FE's voltage criteria and operating

needs

� Some NERC planning standards were sufficiently ambiguous that FE

could interpret them in a way that resulted in inadequate reliability for

system operation

cont'd


Causes of Blackout Causes of Blackout cont'dcont'd

2. Inadequate level of situation awareness:

� FE failed to ensure security of its system after significant

unforeseen contingencies

� FE lacked procedures to ensure that its operators were

continually aware of the functional state of their critical

monitoring tools

� FE did not have adequate backup tools for system monitoring

3. Inadequate level of vegetation management (tree trimming)

� FE failed to adequately manage tree growth into transmission

rights-of-way

� resulted in the outage of three 345 kV lines and one 138 kV

line

cont'd


Causes of Blackout Causes of Blackout cont'dcont'd

4. Inadequate level of support from the Reliability Coordinator

� due to failure of state estimator, MISO did not become aware of

FE's system problems early enough

� did not provide assistance to FE

� MISO and PJM (Regional Transmission operator) did not have in

place an adequate level of procedures and guidelines for dealing

with security limit violations due to a contingency near their

common boundary

1529pk - 83

September 23, 2003 Blackout of Southern September 23, 2003 Blackout of Southern

Sweden and Eastern DenmarkSweden and Eastern Denmark



The Transmission Grid in the Nordic CountriesThe Transmission Grid in the Nordic Countries


Blackout of 23 September 2003 in Southern Sweden Blackout of 23 September 2003 in Southern Sweden

and Eastern Denmarkand Eastern Denmark

� Pre-disturbance conditions:

� system moderately loaded

� facilities out of services for maintenance:

� 400 kV lines in South Sweden

� 4 nuclear units in South Sweden

� 3 HVDC links to Germany and Poland

� The first contingency was loss of a 1200 MW nuclear unit in

South Sweden at 12:30 due to problems with steam valves

� increase of power transfer from the north

� system security still acceptable

cont'd



and Eastern Denmark and Eastern Denmark (cont'd)(cont'd)

� Five minutes later (at 12:35) a disconnector damage caused a

double busbar fault at a location 300 km away from the first

contingency

� resulted in loss of a number of lines in the southwestern grid and

two 900 MW nuclear units

� At 12:37, voltage collapse in the eastern grid section south of

Stockholm area

� isolated southern Sweden and eastern Denmark system from

northern and central grid


The Blackout in Southern Sweden and Eastern The Blackout in Southern Sweden and Eastern

Denmark, September 23, 2003Denmark, September 23, 2003

TenhultStrömma

Horre d

Söderåsen

Barsebäck

Hemsjö

Simpevarp

Nybro

K imstad

G lan

Kolstad

Hallsberg

Breare d Alvesta

The voltage collapse

Ma intenance work

The fault in Horred

Line outages due to:

TenhultStrömma

Horre d

Söderåsen

Barsebäck

Hemsjö

Simpevarp

Nybro

K imstad

G lan

Kolstad

Hallsberg

Breare d Alvesta


Ma intenance work

The fault in Horred



Ma intenance work

The fault in Horred


Voltage Collapse

Isolated Subsystem


The Blackout in Southern Sweden and Eastern The Blackout in Southern Sweden and Eastern

Denmark, September 23, 2003Denmark, September 23, 2003

The blacked-out area after the grid separation at 12.37


� The isolated system had enough generation to cover only about 30%

of its demand

� voltage and frequency collapsed within a few seconds, blacking out the

area

� Impact of the blackout:

� loss of 4700 MW load in south Sweden

� 1.6 million people affected

� City of Malmo and regional airports and rail transportation without

power

� loss of 1850 MW in eastern Denmark

� 2.4 million people affected

� City of Copenhagen, airport and rail transportation without power

� Result of an (n-3) contingency, well beyond "design contingencies"


and Eastern Denmark and Eastern Denmark cont'dcont'd

1529pk - 90

September 28, 2003 Blackout of ItalySeptember 28, 2003 Blackout of Italy



Italian System Blackout of 28 September 2003Italian System Blackout of 28 September 2003

� Predisturbance conditions (Sunday, 3:00 am):

� total load in Italy was 27,700 MW, with 3638 MW pump load

� total import from rest of Europe was 6651 MW

� Sequence of events:

� a tree flashover caused tripping of a major tie-line between Italy and

Switzerland (Mettlen-Lavorgo 380 kV line) at 03:01:22

� Sychro-check relay prevented automatic and manual reclosure of line due

to the large angle (42°) across the breaker

� resulted in an overload on a parallel path

� attempts to reduce the overload by Swiss transmission operators by

network change was not successful

� at 03:21 import by Italy was reduced by 300 MW but was not sufficient to

mitigate the overload of a second 380 kV line (Sils-Soazza), which tripped

at 03:25:22 due to sag and tree contact


� the cascading trend continued and the power deficit in Italy was such

that the ties to France, Austria and Slovania were tripped

� the outages left the Italian system with a power shortage of 6400 MW

� the frequency decay could not be controlled adequately by under-

frequency load shedding

� over the course of several minutes, the entire Italian System collapsed at

3:28:00

� The blackout affected about 60 million people

� total energy not delivered 180 GWh

� worst blackout in the history of Italy

� power was restored after 3 hours in the northern area and during the

same day for most of Italy

Italian System Blackout of 28 September 2003 Italian System Blackout of 28 September 2003 cont'dcont'd

1529pk - 93

What Can We Do To Prevent What Can We Do To Prevent

Blackouts?Blackouts?



Factors Impacting on System SecurityFactors Impacting on System Security

Regulatory Framework

Governments, Reliability Councils

Business Structure

Owning and operating entities; Financial

and contractual arrangements

Physical System

Integrated Generation,

Transmission, Distribution

System


Comprehensive Approach to Enhancing System Comprehensive Approach to Enhancing System

StabilityStability

� Impractical to achieve 100% reliability of power systems

� Good design and operating practices could significantly minimize

the occurrence and impact of widespread outages

� Reliability criteria: risk-based security criteria

� Improved protective relaying

� Robust stability controls

� Coordinated emergency controls

� Comprehensive stability assessment: analytical tools and models

� Real-time system system monitoring and control

� Wide-spread use of distributed generation

� Reliability Management System

� Good vegetation management


Reliability CriteriaReliability Criteria

� At present, systems designed and operated to withstand loss of any

single element preceded by single-, double-, or three-phase fault

� referred to as "N-1 criterion"

� formulated nearly 40 years ago after the 1965 blackout

� Need for using risk-based security assessment criteria

� consider multiple outages

� account for probability and consequences of instability

� Built-in overall strength or robustness best defense against

catastrophic failures !


Improved Protective RelayingImproved Protective Relaying

� State-of-the-art protective relaying for generating units and

transmission lines

� adaptive relaying

� Replacement of zone 3 and other backup relaying on important

lines with improved relaying

� Improved protection and control at power plants to minimize unit

tripping for voltage and frequency excursions

� Protective relay improvements to prevent tripping of critical

elements on overload

� control actions to relieve overload


Robust Stability ControlsRobust Stability Controls

� Greater use of stability controls

� excitation control (PSS), FACTS, HVDC, secondary voltage control

� multi-purpose controls

� multiple controllers

� Coordination, integration and robustness present challenges

� good control design procedures and tools have evolved

� Hardware design should provide

� high degree of functional reliability

� flexibility for maintenance and testing

� Industry should make better use of controls !


Emergency Controls for Extreme ContingenciesEmergency Controls for Extreme Contingencies

� Contingencies more severe than normal design contingencies

� multiple contingencies

� can occur anywhere on the system in any form

� Currently, emergency controls used to protect against some

� generator tripping, load shedding, dynamic breaking, controlled

system separation, transfer tap-changer blocking

� Need for a systematic approach to cover against all likely extreme

contingencies


"Defense Plan" Against Extreme Contingencies: "Defense Plan" Against Extreme Contingencies:

Coordinated Emergency ControlsCoordinated Emergency Controls

� Judicious choice of emergency controls

� protection against different scenarios

� identification of scenarios based on past experience, knowledge of

unique characteristics of system, probabilistic approach

� Coordination of different emergency control schemes

� complement each other

� act properly in complex situations

� Response-based emergency controls should generally be preferred

� "self-healing" power systems

� Need for advancing this technology !


Examples of Examples of ResponseResponse--BasedBased Emergency Control Emergency Control

SchemesSchemes

1. Scheme for prevention of voltage collapse in Eastern Ontario

� fully automated and coordinated emergency controls for voltage

stability

2. Transient Excitation Boosting

� for enhancing transient (angle) stability of systems with dominant

interarea swing


Example 1: Prevention of Voltage Collapse in Example 1: Prevention of Voltage Collapse in

Eastern OntarioEastern Ontario

� Implemented in early 1980s to cope with delays in building 500 kV

line

� Under high load conditions, loss of a major 230 kV line leads to

voltage collapse of Ottawa area

� A coordinated scheme consisting of fast line reclosure, load

rejection, shunt capacitor switching, and transformer ULTC

blocking


Example 1: Example 1: (cont'd)(cont'd)

The coordinated scheme:a) Fast reclosure of major lines (1.3s)

� first line of defense

b) Load rejection (1.5s)

� 9 blocks, 750 MW; armed by operator

� voltage/time dependent

c) Shunt capacitors switching (1.8 to 8.0s)

� 36 banks in 17 TSs


d) Transformer ULTC blocking at 14 TSs


� unblocked when voltage recovers



� Coordination provided by appropriate selection of voltage and

time settings

� triggered by voltage drop magnitude and duration

� Following a contingency, depending on the severity (power flow,

line outage), only the required level of control action provided


1300 MW

1374 MW


ResponseResponse--Based Emergency ControlsBased Emergency Controls

Example 2: Transient Excitation BoostingExample 2: Transient Excitation Boosting

� In situations with dominant interarea swing, PSS reduces

excitation after the first local mode swing

� Improvements in TS achieved by keeping excitation at ceiling

until highest composite swing

� increase in internal voltage

� increase in voltage also increases power consumed by area load


Block Diagram of TSEC SchemeBlock Diagram of TSEC Scheme


Effect of TSEC on Transient StabilityEffect of TSEC on Transient Stability



� Transient Excitation Boosting, TSEC, applied to four major plants

in Ontario:

� Nanticoke (4000 MW), Bruce A and B (6000 MW), Lennox (2000 MW)

� signal proportional to angle swing

� integrated with PSS and coordinated with terminal voltage limiter

� In effect, a nonlinear adaptive closed loop control

� may use local or remote signals

� imposes little duty on equipment


Comprehensive Stability Analysis ToolsComprehensive Stability Analysis Tools

� Powerful analytical tools have been developed capable of

comprehensive analysis for system design and operation:

� all forms of stability

� large systems with detailed models

� complementary use of time-domain and modal analysis

� automated procedures for considering large number of scenarios

� Industry gradually shifting to the use of new tools

� Lack of widespread understanding and appreciation for the use of

eigenvalue based modal analyses techniques


StateState--ofof--thethe--Art Art OnOn--LineLine Dynamic Security Dynamic Security

Assessment (DSA)Assessment (DSA)

� Practical tools have been developed with the required accuracy, speed

and robustness

� a variety of analytical techniques integrated

� distributed hardware architecture using low cost PCs

� integrated with energy management system

� Capable of assessing rotor angle stability and voltage stability

� determine critical contingencies automatically

� security limits/margins for all desired energy transactions

� identify remedial measures

� The industry has yet to take full advantage of these developments !


Dynamic Security Assessment Tools Developed and Dynamic Security Assessment Tools Developed and

Used by Powertech for System Design and OperationUsed by Powertech for System Design and Operation

� Powerful set of complementary programs:

� flexible and detailed models

� alternative and efficient solution techniques

� Transient (Angle) Stability Assessment: TSAT

� Small-Signal (Angle) Stability Assessment: SSAT

� Voltage Stability Assessment: VSAT

� Frequency Stability Analysis: LTSP *cont'd

LTSP currently not maintained/supported*


Powertech DSA Tools Powertech DSA Tools (cont'd)(cont'd)

� Automated procedures for:

� contingency screening and ranking

� consideration of a large number of scenarios

� stability limit search

� power flow dispatch

� determination of stability margins

� identifying remedial measures for maintaining stability and

increasing stability margins

� Significant savings in computation and engineering times

1529pk - 115

OnOn--Line Voltage Stability Assessment ToolLine Voltage Stability Assessment Tool

(VSAT)(VSAT)



Key Elements of VSATKey Elements of VSAT

� Interface with EMS; Model Initialization

� Contingency screening and selection

� Determination of secure operating region

� using static analysis

� Determination of remedial actions

� Fast time-domain simulation

� validation and checking


Contingency Selection ModuleContingency Selection Module

� Impractical to consider every conceivable contingency

� A limited number (typically 20) critical contingencies determined

for detailed studies

� Performance Indices based on a few power flow solutions and

reactive reserve not reliable

� A fast screening method used:

� based on exact margin to voltage collapse and full power flow

solutions

� number of power flow solutions 1.2 to 2.0 times number of

contingencies

� Supplemented with user-specified contingencies


Fig. 4 Automatic Critical Contingency Selection


Security Computation ModuleSecurity Computation Module

� Engine for voltage stability analysis

� static analysis with detailed models

� Secure region is defined by a number of Coordinates (SRCs)

� key system parameters: MW generation, area load, interface

transfers, etc.

� Voltage security determined by

� voltage stability margin

� MVAr reserves of key reactive sources

� post-contingency voltage decline

� Modal analysis of powerflow Jacobian matrix identifies areas prone

to instability

� Specialized powerflow dispatcher and solver to quickly search for

stability limit


Modelling:� generator capability curves

� governor response, economic dispatch, AGC

� nonlinear loads

� control of ULTCs, switched shunts, etc.

Inputs and Outputs:

� Inputs

� list of contingencies produced by screening and ranking (+user defined)

� base case powerflow from state estimator

� definition of SCRs

� voltage security criteria and definition of parameter of stress

� Output

� secure region in secure region space


Secure Operating RegionSecure Operating Region


Remedial Measures ModuleRemedial Measures Module

� Determines necessary remedial measures to

� ensure sufficient stability margins

� expand the secure region

� Preventative control actions:

� taken prior to a contingency

� caps/reactor switching, generation redispatch, voltage rescheduling

� Corrective (emergency) control actions:

� applied following a contingency

� load shedding, generator runback, transformer tap changer blocking

� Ranking of each remedial measure using:

� sensitivity analysis

� user-defined priorities


Ranking and Applying Remedial MeasuresRanking and Applying Remedial Measures

� Objective is to identify the most effective remedial measures to give

the desired stability margin

� Obtain solved power flow case for the most severe contingency

� gradually introduce the effect of the contingency

� bus injection compensation technique

� Compute the sensitivities of reactive power (or bus voltage) to

different control measures

� rank the remedial measures

� Apply controls one at a time in order of ranking until power flow

solves for the most severe contingency


Expanding the Secure Region: Remedial MeasuresExpanding the Secure Region: Remedial Measures


Fast TimeFast Time--Domain Simulation ModuleDomain Simulation Module

� Determines the essential dynamic phenomena without step-by-step

numerical integration

� when chronology of events significant

� for validating the effect of remedial measures

� Focuses on the evolution of system dynamic response driven by

slow dynamics

� transformer tap changers, field current limiters, switched caps

� Captures the effects of fast dynamics by solving associated steady

state equations


� The complete set of differential/algebraic equations of a power

system has the following general form:

Where:

X = state vector

V = bus voltage vector

I = current injector vector

Y = network admittance matrix

Z = variables associated with the slow

control devices including ULTCs, loads, switchable reactors

and capacitors, and field current limiters

Mathematical FormulationMathematical Formulation

( )Z,V,XfX =&

( )Z,V,XIYV =


Mathematical FormulationMathematical Formulation

� At each equilibrium point, Z=Zi and the system operating condition

is obtained by solving the following set of nonlinear algebraic

equations:

� As time progresses, the slow control devices operate and the

values of Z change. The above set of nonlinear algebraic equations

is solved every time the values of Z change.

( )

( )i

i

ZV,X,IYV

ZV,X,f0

=

=


Powerflow

Solver

VSAT StructureVSAT Structure

1529pk - 131

Transient Stability Assessment Tool (TSAT)Transient Stability Assessment Tool (TSAT)



Transient Stability Assessment (TSA)Transient Stability Assessment (TSA)

� Time-domain simulations essential

� modeling detail and accuracy

� Sole dependence on time-domain simulations has severe limitations

� high computational burden

� no stability margin/sensitivity information

� requires considerable human interaction

� Supplementary techniques for speeding up and automating overall

process

� Methods available for deriving useful indices

� Transient Energy Function (TEF)

� Signal Energy Analysis

� Extended Equal Area Criterion (EEAC)


A Practical Tool for TSAA Practical Tool for TSA

� Overall architecture similar to that of VSA

� Time-domain program, with detailed models and efficient solution

techniques, forms simulation engine

� EEAC used for screening contingencies, computing stability margin,

stability limit search, and early termination of simulation

� “Prony analysis” for calculation of damping of critical modes of

oscillation

� A powerflow dispatcher and solver for finding the stability limit

� a fully automated process

� No modeling compromises;

can handle multi-swing instability


EEACEEAC

� Integrates the dynamic response in the multimachine space, and

maps the resultant trajectory into a set of one-machine-infinite-bus

planes

� By applying complementary cluster center of inertia (CCCI)

transformations

� Keeps all dynamic information in the multimachine space

� Stability analysis can be quantitatively performed for the image OMIB

systems

� Has the same accuracy and modeling flexibility

� Fast, quantitative


EEACEEAC

� Loss of transient stability in a power system always starts in a

binary splitting of generators:

� Critical cluster of generators

� Rest of the system

� At any given point in the

time-domain trajectory of

the system, the system

can be visualized as a

one-machine-infinite-bus

(OMIB) system


EEACEEAC

� The classical equal area criterion can be extended to the visual OMIB

system

Stability margin of the system is defined as

( )

( )

>−

<−

=η

da

a

ad

ad

d

ad

AAA

AAx

AAA

AAx

unstable is system the if100

stable is system the if100

Thus, -100 ≤ η ≤ 100, and

η> 0 if the system is stable

η ≤ 0 if the system is unstable

η can be used as a stability index


Use of EEAC TheoryUse of EEAC Theory

� Contingency screening

� stability margin gives an indication of the relative severity

� Corrective measures for maintaining secure system operation

� critical cluster of generators (CCG) provides valuable information

� Power transfer limit search

� stability limit can be determined in four iterations using stability margin

� each iteration involves a detailed simulation and computation of stability

index


Results Results -- Test SystemTest System

System description

� BC Hydro system� 1430 buses

� 186 generators� 4 HVDC links

Interface

� GMS and PCN output

� Base case transfer = 3158 MW

Contingency

� Three phase fault at GMS 500 kV bus

� Tripping of one of two 500 kV lines from GMS to WSN


Limit Search ResultsLimit Search Results


Speed Enhancement: Parallel ProcessingSpeed Enhancement: Parallel Processing

� Code parallelization

� differential equations easily parallelized, but not network equations

� speed-ups limited by serial slowdown effect

� up to 7 times speed-up can be achieved with 20-30 processors

� not an effective way

� Conventional serial computers offer much faster computational

per-CPU

� For multiple contingencies

� perform initialization only once

� run contingencies on multiple processors - one processor per

contingency


TSAT StructureTSAT Structure

Powerflow

Dispatcher

Time-Domain

Simulation

Stability

Indices

Increase

Transfer

Remedial

Measures

Must Run

Contingencies

Transaction

Definitions

Security Limit?

Sufficient

Margin?

STOP

Yes

Yes

No

Full

Contingency List

Solved Powerflow

+

Dynamic Data

Contingency Screening &

Ranking (EEAC)

No


Computational Performance of DSAComputational Performance of DSA

� Target cycle time from capture of state estimation to completion

of security assessment for all specified transactions:

� 20 minutes

� TSA and VSA functions performed in parallel

� distributed processing on separate CPUs

� This can be readily achieved with low cost PCs


Computational Speed of DSA Computational Speed of DSA (cont'd)(cont'd)

Voltage Stability Assessment:- screening 300 contingencies 20.0 secs

- detailed security analysis 1.2 secswith 20 critical contingencies

- one transfer limit search 12.0 secs

Transient Stability Assessment:

- screening 100 contingencies 75.0 secs- 10 second simulations with 75.0 secs

10 critical contingencies

- one transfer limit search 120.0 secs- total time for complete assessment < 5 mins

Power System model with 4655 buses, 156 generators, using 1.7 GHz,

Pentium 4 PC with 256 MB memory


Future Trends in DSA: Intelligent SystemsFuture Trends in DSA: Intelligent Systems

� Knowledge base created using simulation of a large number cases and

system measurements

� Automatic learning, data mining, and decision trees to build intelligent

systems

� Fast analysis using a broad knowledge base and automatic decision making

� Provides new insight into factors and system parameters affecting stability

� More effective in dealing with uncertainties and large dimensioned problems

� We just completed a PRECARN project: "POSSIT"


DSA Using Intelligent SystemsDSA Using Intelligent Systems


RealReal--Time Monitoring and Control: Time Monitoring and Control:

An Emerging TechnologyAn Emerging Technology

� Advances in communications technology have made it possible to

� monitor power systems over a wide area

� remotely control many functions

� Research on use of multisensor data fusion technology

� process data from different monitors, integrate and process information

� identify phenomenon associated with impending emergency

� make intelligent control decisions

� A fast and effective way to predict onset of emergency conditions and

take remedial actions

The ultimate "self-healing" power system !


Distributed Generation (DG)Distributed Generation (DG)

� Offer significant economic, environmental and security benefits

� Microturbines

� small, high speed power plants

� operate on natural gas or gas from landfills

� Fuel Cells

� combines hydrogen with oxygen from air to generate electricity

� hydrogen may be supplied from an external source or generated inside

fuel cell by reforming a hydrocarbon fuel

� Not vulnerable to power grid failure due to system instability or

natural calamities

� protection and controls should be designed so that units continue to

operate when isolated from the grid


Reliability Management SystemReliability Management System

� Roles and responsibilities of individual entities

� well chosen, clearly defined and properly enforced

� Coordination of reliability management

� Need for a single entity with overall responsibility for security of

entire interconnected system

� real-time decisions

� System operators with high level of expertise in system stability

� phenomena, tools


SummarySummary

1. The new electricity supply industry presents increasing challenges for

stable and secure operation of power systems

2. State-of-the-art methods have advanced our capabilities significantly

� comprehensive stability analysis tools

� automated tools for system planning/design

� on-line Dynamic Security Assessment (DSA)

� coordinated design of robust stability controls

3. Industry is yet to take full advantage of these developments

cont'd


SummarySummary (cont'd)(cont'd)

4. Future directions will be to explore new techniques which can

better deal with growing uncertainties and increasing

complexities of the problem

� risk-based security assessment

� intelligent systems for DSA

� "self-healing" power systems

� real-time monitoring and control

5. Wide-spread use of distributed generation could be a cost

effective means of minimizing the impact of power grid failures

power system stability in the new industry environment:...

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