prevention and mitigation of cascading outages in power...

Prevention and Mitigation of Cascading Outages in Power Grids Using Synchrophasor-based

Wide-Area Measurements

Kai SunProject Manager

Grid Operations, Planning & Renewable IntegrationEmail: [email protected] Tel: 650-8552087

May 8, 2012 @ Stanford University

Content

•Cascading outages (impacts, causes, new h ll d l ti )challenges and solutions)

• Intelligent system separation utilizing synchrophasors

•Situational awareness utilizing wide-area S tuat o a a a e ess ut g de a eameasurements (DOE demonstration project)

•Conclusions•Conclusions

2© 2012 Electric Power Research Institute, Inc. All rights reserved.

Blackouts of Power GridsDate Area Impacts Durationp

Nov 9, 1965 North America (NE) 20,000+MW, 30M people 13 hrs

Jul 13, 1977 North America (NY) 6,000MW, 9M people 26 hrs

Dec 22, 1982 North America (W) 12, 350 MW, 5M people

Jul 2-3, 1996 North America (W) 11,850 MW, 2M people 13 hrs

Aug 10 1996 North America (W) 28 000+MW 7 5M people 9 hrsAug 10, 1996 North America (W) 28,000+MW, 7.5M people 9 hrs

Jun 25, 1998 North America (N-C) 950 MW, 0.15MK people 19 hrs

Mar 11, 1999 Brazil 90M people hrs

Aug 14, 2003 North America (N-E) 61,800MW, 50M people 2+ days

Sep 13, 2003 Italy 57M people 5-9 hrs

S 23 2003 S d & D k 5M l 5 hSep 23, 2003 Sweden & Denmark 5M people 5 hrs

Nov 4, 2006 Europe 15M households 2 hrs

Nov 10, 2009 Brazil & Paraguay 17,000MW, 80M people, 18 states 7hrs


states

Feb 4, 2011 Brazil 53M people, 8 states

Sep 8, 2011 US & Mexico (S-W) 4,300MW, 5M people 12hrs

970 MW lossCauses of a blackout

2 100 MW l

Blackout event in Aug. 19961 Initial events (15:42:03):

11 600 MW loss

2,100 MW loss1. Initial events (15:42:03):Short circuit due to tree contact -> Outages of 6 transformers and lines

2 Vulnerable conditions (minutes) 11,600 MW loss

15,820MW loss

2. Vulnerable conditions (minutes)Low-damped oscillations-> Outages of generators and tie-lines

3. Blackouts (seconds)3. Blackouts (seconds)Grid separated into islands -> Loss of 24% load

Malin-Round Mountain #1 MW

1300

1400

1500

0 252 H ill ti0 276 Hz oscillations

15:42:03 15:48:5115:47:36Can we do anything to stop cascade?


200 300 400 500 600 700 8001100

1200

Time in Seconds

0.264 Hz oscillations3.46% Damping

0.252 Hz oscillationsDamping 1%

0.276 Hz oscillationsDamping>7%

to stop cascade?

New Challenges from Integration of Renewables

1. Reliability and congestion issues with long-distance power transmissionpower transmission

Legend:

• Wind

• People


New Challenges from Integration of Renewables(cont’)( )

2. More uncertainties in real-time operation

Mismatch in supply d d dInaccuracy in short-term

forecastingand demand curves


New Challenges from Integration of Renewables(cont’)( )

3. Changing the grid’s dynamics

From OG&E synchrophasor presentation

Better monitoring applications are needed at the t l f l ti it ti l


control room for real-time situational awareness

Synchrophasor based Wide-Area Measurement System (WAMS)

Oscillation Mode Analysis


Prevention of Cascading Outages

• Limitations:– Too many system conditionsOffline probabilistic anal sis on

• Power System Stability Assessment:y y

– Combinatorial explosion of N-k contingencies

Inaccuracy in simulation models

Offline probabilistic analysis on system vulnerabilities and

potential cascading outages

Simulation-based contingency analysis

– Inaccuracy in simulation models

4600

Real-time stability analysis using id t

4000

4200

4400

4600 Observed COI Power (Dittmer Control Center)

Measured

wide-area measurements

4000

4200

4400

4600 Simulated COI Power (initial WSCC base case)

SimulationSimulation-based approach


0 10 20 30 40 50 60 70 80 90

4000

Time in Seconds

+Measurement-based approach

Intelligent System Separation

RestorationBlackstart

I iti l tI iti l tInitial eventsInitial events

I t lli t tiCascading blackouts


Intelligent separationCascading blackouts

Key Questions on System Separation

Q i NQuestion Nature

WHERE Network optimization(locations)

WHEN(ti i )

Nonlinear system (timing) stability

HOW( t l)

Implementation of t l t t i(control) control strategies


Three-Step Approach

• Offline Studies (daily ~ yearly)S h h iti ( t )– Synchrophasors siting (near generators)

– Separation point optimization– Validation of a control-strategy table

Where

HowHow

Offline procedure

• Online Monitoring (every second)Identify most vulnerable grid interface based on the shape WhereWhere– Identify most vulnerable grid interface based on the shape of the dominant oscillation mode

– Predict the timing of instability on the interface WhenOnline

software

WhereWhere

• Real-Time Control (milliseconds)– Perform a control strategy matching the current condition How


gy g

WHERE to Separate Generation Coherency

1. Cluster generators into coherent groups (by EPRI DYNRED software)

2 R d th t k b h thSlow mode

y

2. Reduce the network by graph theory (weak connection) Fast mode(strong connection)


WHEN to Separate

• Modal analysisIdentify the dominant oscillation mode by synchrophasors– Identify the dominant oscillation mode by synchrophasors

– Predict a vulnerable grid interface from the mode’s shape (phasing)

k

k

t

M tki

“Phase Clock” on mode i

M

ikiki

t

kikk teAtki

ki

ki

1

10 )cos()(

2

Monitored O ill ti Phasing


Monitored variable

Oscillation frequency

Phasing (mode shape)

WHEN to Separate (cont’) PMU1PMU2

• Stability analysis Area 2Area 1

– Estimate the state of a simplified model about the interface

– Predict instability using the energy function of the model

State estimation on a simplified modelBoundary of Stability

vEquilibrium point


Example: 179-bus System

System loses stability after 6 line outages

1 256

California-Oregon Intertie3

4

Intertie


“Phase Clock” about

Example: 179-bus System (cont’)

1Phase Clock about

0.2Hz mode

Strategy 1-234

3

4

5

1-2 (120-160s)1-3 (120-160s)1-4 (120-160s)1-2 (160-200s)1-3 (160-200s)

Dominant mode

T

0.2Hz0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 1.1 1.20

1

2

3

Frequency (Hz)

1-4 (160-200s)

FFT

420.26

0.28

Hz)

1-21-31-4

Frequency of the mode

2

40 60 80 100 120 140 160 180 2000.16

0.18

0.2

0.22

0.24

Ti ( )

Freq

uenc

y (H

Time (s)

60

120

180

ce (d

eg.)

Phasing (shape) on the mode


3 Strategy 14-2340 60 80 100 120 140 160 180 200-180

-120

-60

0

Time (s)

Pha

se D

iffer

ence

1-21-31-4

Example: 179-bus System (cont’)

180

.)

• Perform strategy 1-234 once the angle distance exceeds a threshold

90

Diff

eren

ce (d

eg

1-23414-23

angle distance exceeds a threshold • Shed 4.9% system load

40 80 120 160 200 2100

Time (s)

Pha

se D

140

160

180

e (d

eg.)

1-23414-23

Time (s)

60

80

100

120

nge

Diff

eren

ce


40 80 120 160 200 21040

60

Time (s)

A

Synchrophasor-based Situational Awareness and Decision Supportpp

Online Monitoring Real-time Stability Assessment

RiskKey

Dominant oscillation modePhase Clock on

the mode Simplified model on the interface Time

Interface

Phasor dataPhasor data

Risk & ControlScenario 1

Scenario 2Scenario N

Control Timing

Look-Up Table

Control Action


Visualization at Control RoomInterconnected Power System

Control Action

DOE Synchrophasor Demonstration Project (DOE Grant #DE-OE0000128; 2009-2012)( ; )

Real-time PMU Data (IEEE C37.118)

Online Event Detection

• Phase 1 (research) Near Real-Time

Event ReplayLocation ofDisturbance

Early Warning of Grid Instability

• Phase 2 (software development)Ph 3

p y

Power System Wide-Area

y

• Phase 3 (demonstration at TVA in 2012)

yVisualization


)

Performance Testing Using Simulated or Real Synchrophasor Data

Separation

ContingenciesPMU_Config.XML

strategies

DSA Tool

Models

g

PMU_Data.CSV

SQL database

HistoricalData

Software A li ti

PMU data stream in IEEEC37 118 E

Application


IEEEC37.118 Energy ManagementSystem data

Tests on Simulated WECC PMUs


Separating the grid when risk=100%

Island 1Island 1

Island 2


Frequencies before ControlFrequencies before Control Frequencies after SeparationFrequencies after Separation

Tests on Simulated TVA PMU Data


Conclusions

•Online situational awareness and decision support applications are important for grid operators toapplications are important for grid operators to prevent or mitigate cascading outages

•Wide area synchrophasor measurements would•Wide-area synchrophasor measurements would enable next-generation grid monitoring applications

•Technologies to help prevent cascading outages areTechnologies to help prevent cascading outages are such as – System reduction (topological and dynamical)y ( p g y )– Signal processing– Data mining


References

[1] K. Sun, D. Zheng, Q. Lu. Splitting Strategies for Islanding Operation of Large-scale Power Systems Using OBDD-based Methods, IEEE Trans. Power Systems, vol.18, May 2003

[2] Q. Zhao, K. Sun, et al, A Study of System Splitting Strategies for Island Operation of Power System: A Two-phase Method Based on OBDDs, IEEE Trans. Power Systems, vol.18, Nov 2003

[3] K. Sun, D. Zheng, et al, Searching for Feasible Splitting Strategies of Controlled System Islanding, IEE Proceedings Generation, Transmission & Distribution, vol.153, Jan 2006

[4] K. Sun, D. Zheng, Q. Lu, A Simulation Study of OBDD-based Proper Splitting Strategies for Power Systems under Consideration of Transient Stability, IEEE Trans. Power Systems, vo.l.20, Feb 2005

[5] M. Jin, T. S. Sidhu, K. Sun, A New System Splitting Scheme Based on the Unified Stability Control Framework, IEEE Trans. Power Systems, vol. 22, Feb 2007y

[6] K. Sun, S. Likhate, V. Vittal, et al, An Online Dynamic Security Assessment Scheme using Phasor Measurements and Decision Trees, IEEE Trans. Power Systems, vol. 22, Nov 2007.

[7] R. Diao, V. Vittal, K. Sun, et al, Decision Tree Assisted Controlled Islanding for Preventing Cascading Events, IEEE PES PSCE, Seattle, 2009, , ,

[8] K. Sun, S. Lee, P. Zhang, An Adaptive Power System Equivalent for Real-time Estimation of Stability Margin using Phase-Plane Trajectories, IEEE Trans. Power Systems, vol. 26, May 2011.

[9] K. Sun, K. Hur, P. Zhang, A New Unified Scheme for Controlled Power System Separation Using Synchronized Phasor Measurements, IEEE Trans. Power Systems, vol. 26, No. 3, Aug. 2011


Synchronized Phasor Measurements, IEEE Trans. Power Systems, vol. 26, No. 3, Aug. 2011

Q&A

Kai SunPh 650 855 2087Phone: 650-855-2087E-Mail: [email protected]


NERC Categories of Contingencies

• Most utilities manually select Category D C

o

contingencies to simulate:– Loss of a key

substation

onsequenc

Unlikely Credible– Outages of tie lines– Outages close to a

generation/load pocket

ce Index

Unlikely and

Extreme consequences

Credible and

Unacceptable

generation/load pocket

CredibleUnlikely0D

Credible and

Acceptable

Unlikely and

Acceptable

0Generator Outage

N-1 Line Outage

N-2 Line Outage

Deterministic Criteria

Category of ContingenciesAB

C


Likelihood IndexExtreme Events

When System is Stressed (e.g. Storm Approaching), the likelihood may increase

Northeast Coherent Generation Groups


From NPCC (Northeast Power Coordinating Council) Study Results

1 PG=28.3GWPL=26.4GW

Building a strategy table

P =12 5GW

Total load: 60.8GW• 7 potential separation points• 6 strategies (2 islands):

24

PG=12.5GWPL=10.6GW

g ( )1-234, 2-134, 3-124, 4-12312-34, 14-23

• 12 potential islands 2PG=5.1GWPL=6.4GW

12 potential islands• Validate control actions by

simulationsShed ShedIsland ShedLoad Island Shed

Load

1 0 23 7.3%

2 3 6% 34 1 5%2 3.6% 34 1.5%

3 3.8% 124 0

4 0 123 4.1%


3PG=15.5GWPL=17.4GW

12 0 234 4.9%

14 0 134 0

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