June 27, 2013

Kirk Robbins

Senior Staff Engineer

Progress with Open Phase Detection

Background

• In January 2012, Byron Unit 2 experienced an open phase with ground on the C-phase for the system auxiliary transformers (SATs) combined lead. − The cause was a failed under hung insulator that resulted in an open phase with

ground on the C-phase transformer lead. − Existing relay protection schemes were not designed to detect this condition. − Both divisions of safety equipment were adversely impacted. − This event was significant because it revealed a design vulnerability where an open

phase or open phase grounded condition would not be detected by the existing protective relaying.

• To address this vulnerability a project team was assembled to develop a scheme that would detect the open phase or open phase with a ground. − An innovative microprocessor based relaying scheme capable of reliably detecting

and isolating an open phase/open phase grounded condition before it can adversely impact plant equipment or operations.

− The protective relaying has been deployed in “alarm only” mode at seven units with balance of the fleet to be deployed throughout 2013 and early 2014.

− Lessons learned are openly shared with the industry via NEI working group.

2

Exelon Algorithm Implementation

3

OPD Scheme Single Line for Byron

4

Technical Challenges

• Algorithm was originally developed with a 2 second time delay for coordination with existing switchyard protection schemes. − This resulted in potentially losing important plant equipment due to transient. − Time delay reduced to 0.5-0.8 seconds to coordinate with in-plant protection devices

and zone 2 protection. • Algorithm parameters are highly dependent on analytical models.

− Obtaining the data necessary for a detailed model is difficult. • Algorithm is applicable only to wye-wye-wye, wye-wye-delta, wye-wye-wye-delta winding

configurations. • Algorithm is not effective for an autotransformer if the source is a delta connection.

− This impacts two of the Mid Atlantic sites.

5

Continuing Algorithm Development

• Exelon has entered into a collaborative agreement with Dominion Generation and Schweitzer Engineering Laboratories (SEL) to develop a solution for other winding configurations (delta-wye, wye-delta, wye-delta-delta and delta-delta-delta).

• Preliminary proof of concept testing has been completed with positive results for delta-wye configuration. Two solutions appear viable: − Current only solution

• Appears to be independent of system characteristics. • Depends only on inherent relay characteristics to detect the open phase or open

phase with ground. • Plant specific proof of concept testing is in progress to demonstrate viability.

− Voltage solution • Appears to be more sensitive to power system characteristics. • Specific algorithm is being developed utilizing negative sequence voltage.

− Development of both a voltage algorithm and a current algorithm allows flexibility in design. • A choice can be made based on existing sensors.

• Development is ongoing throughout 2013 to support installations in 2014 and 2015.

6

Open Phase - Current Only Low or No load

Phase Current Magnitudes With 2% Excitation Over Time (Cycles) Fault Occurs at 15 Cycles

7

Fault occurs

Open Phase - Current Only Low or No load

Difference in Ratio of Second Order Harmonic Current to Fundamental Current Between Successive Samples Over Time (Cycles)

8

Fault occurs

Open Phase - Current Only Low or No load

Counter Output Over Time (Cycles) Counts Up if Difference Exceeds a Predetermined Threshold

9

Fault occurs

Open phase detected

Open Phase - Current Only With Load

SEL Open Phase Detection – Phase A Identical Logic Exists for Remaining Phases

10

Open Phase With Ground - Current Only Low or No load

Phase Current Over Time (Cycles) Fault Occurs at 15 Cycles

11

Fault occurs

Open Phase With Ground - Current Only Low or No load

Ratio of 3rd Order Harmonic Current to Fundamental Current Over Time (Cycles) In The Faulted Phase

12

Fault occurs

13

Deployment Status

• Fleet implementation schedule is based on operational impact from a single phase event and ability to remove transformers from service during maintenance outages

• Relays have been deployed at the following stations • Byron Unit 2 (October 2012) • Byron Unit 1 (November 2012) • Dresden Unit 3 (November 2012) • Braidwood Units 1 (January 2013) • Braidwood Units 2 (January 2013) • LaSalle Unit 2 (February 2013) • Quad Cities 1 (April 2013)

• Remaining site installations scheduled throughout 2013 and early 2014 • Trip functions will be enabled after a successful monitoring period that includes an outage

period

Performance Monitoring

• A monitoring period of at least 6 months has been established to verify the relay performs as expected. − Allows verifying relay performance during expected system and plant operations and

transients. − To date there have been no misoperations of the relay.

14

Byron Relay Response to L-L Fault on Transmission System

15

Byron Relay Response to Unit Trip and Fast Transfer From UAT

16

Summary

• Installation continues implementing the algorithm Exelon developed in 2012. • Collaborative Agreement with Dominion and Schweitzer Engineering Laboratories to

develop additional algorithms as needed. • Technical challenges continue as conceptual designs are implemented. • Relay performance has been satisfactory throughout the range of operating conditions.

• Questions?

17

1

FENOC - - Beaver Valley State Estimation

For Open Phase Faults John S. Flaherty, Jr. P.E.

Dr. George Kusic kusic@engr.pitt.edu

Power Systems Consultants, Inc University of Pittsburgh

Brief History: BV’s 2007 Event • At BVPS in 2007, during a non-routine walk-down, it

was discovered that the A-phase conductor of a 138-kV offsite power circuit was disconnected in the switchyard.

• The break occurred between an offsite feeder breaker and a Unit 1 SSST.The SSST was unloaded at the time, and the condition was undetected for 26 days.

• Modified revenue metering connections to eliminate the failure mode identified in the root cause analysis.

• Added guidance to operating procedures to help operators better identify an open-phase condition. 2

Events That Led To BV Initiative • In January 2012, Byron Unit 2 experienced the loss

of a single-phase conductor in its offsite power supply.

• The failure was not detected by the under-voltage protection scheme and resulted in inadequate voltage being supplied to safety-related equipment.

• In response to the associated INPO Event Report (IER 12-14),BVPS launched initiative to design and developing and open conductor detection scheme that reliably ensures the operability of offsite power sources. 3

BV- Corrective Action Program • CR-2012-02616 written to address and track engineering

activity for open phase issues This CR documents a review of Beaver Valley’s undervoltage protection scheme with respect to design vulnerabilities identified at Byron The CR also addresses the recommendations outlined in IER L2-12-14.

• CA-2012-02616-4 Issued to perform a study to evaluate the effect of a single-phase open circuit in the offsite power supply)

• CA-2012-02616-3 Issued to develop the conceptual design for a modification to detect and automatically respond to a single-phase open circuit in an offsite power supply. (State Estimation and Syncrophasor Technologies) 4

Detection of BV Open Conductors by

State Estimation (Nuclear Plant Extra Monitor)

Dr. George Kusic kusic@engr.pitt.edu

Power Systems Consultants, Inc (PSC)

Advantages of State Estimation • ‘Smoothed’ Values for Currents, Voltages, Real and

Reactive Power which uses EVERY measurement on the entire network.

• Redundancy to Replace ‘LOST’ Measurements

• ‘BAD DATA’ detection to Avoid False Alarms

• It is an Independent System Monitor with results

presented to the Computer System for corrective action. All normal plant functions and Protective Relay devices are UNTOUCHED.

State Estimation is the first step in FUTURE • FAST FAULT DETECTION <= 1 Millisecond

A data ‘snapshot’ from a power system is an almost instantaneous set of measured voltages, currents, real power flow, reactive power flow from all conductors of 3-phase transmission lines and points of power introduction or use (Called a bus of the power system).

The electrical quantities are assumed to change slowly with time, such that the snapshot has negligible data error due to time skew from the initial data point to the final data point. An earth power system can obtain 32 bit data from HUNDREDS OF THOUSANDS of measurement points in less than 1.0 second for a ‘snapshot’.

UTILITY PRESENTATION TO DISPATCHER OF ‘SMOOTHED’ STATE ESTIMATOR RESULTS

Ia

Ib

Ic

dak

dck

dbk

dab

dac

dbc

Point k

Ik = -Ia-Ib-Ic

Flux a

Three-phaseimpedance

Ib

Ia

Ic

Xab

apE

bpE

aqE

bqE

cqEc

pE

Xab

Xac

Xaa

Xcc

Xbb

CONDUIT or EARTH

SELF AND MUTUAL INDUCTANCES OF 3-PHASE CONDUCTORS

CONDUIT

Iik

Vi

Pik

≡ Real power flow from bus i towards bus k (Watts or p.u.)

Qik ≡ Reactive power flow from bus i towards bus k (Volt-Amperes-Reactive, VARS, or p.u.) ≡ Line current (Either r.m.s. or SAMPLED

≡ Line to neutral voltage at the bus (Volts r.m.s. or SAMPLED)

LINE MEASUREMENTS or INJECTION MEASUREMENTS

SIGNALS AVERAGED OVER SEVERAL CYCLES

Pi ≡ Bus real power injection (Watts or p.u.) Qi ≡ Bus real power injection (Watts or p.u.)

ASSUMPTIONS POWER DISTRIBUTION in A NUCLEAR PLANT TO PUMPS, BOILERS, STANDBY and EMERGENCY GENERATION, ETC. HAVE SHORT LENGTH LINES WITH LARGE CONDUCTORS. BUS-TO-BUS IMPEDANCES ARE SMALL FOR SAFETY AND LOW LOSSES MULTI-FEED and MULTI-LOOP SUPPLIES ARE TYPICAL. THE TOPOLOGY IS COMPACT AND MULTI-LOOPED THERE IS EXTENSIVE METERING OF VOLTAGES, CURRENTS, POWER FLOW, and SIGNALS for PROTECTIVE CIRCUITS -- WITH BOTH rms AND INSTANTANEOUS TIME SAMPLED VALUES.

L1 345 kV

L2 L3

L4

L5 L6

L9

L10

L8

L7

L11 L12

L14

L15

M

G

22 kV BUS

4.16 kV BUSES

Locations with existing measurements of V, MW, MVARS

4KVS-1A 4KVS-1B 4KVS-1C

SSST1A

SSST1C SSST1D

SSST1B

TYPICALMOTORLOAD

138kV

4KVS-1D

BEAVER VALLEY GENERATION PLANT DISTRIBUTION SYSTEM

No measurements or ‘lost’ measurements at remote bus

STATE ESTIMATOR RESULTS p.u., 20 MVA Number of measurements = 86 ************************* BUS SUMMARY ********************************* AC STATE MEASUREMENTS BUS VOLTAGE, ANGLE meas NORM ERR Zhat 138KV 1.0926 -4.6186 SSST1A 1.0851 -4.6980 Voltage p.u. 1.0850 0.0001 1.0851 4KVSA 1.0714 -4.5659 MW p.u. -0.4167 0.0000 -0.4167 MVAR p.u. 0.1562 0.0000 0.1562 Voltage p.u. 1.0712 0.0001 1.0714 4KVSB 1.0894 -4.8738 MW p.u. -0.7292 0.0000 -0.7292 MVAR p.u. 0.5208 0.0000 0.5208 Voltage p.u. 1.0893 0.0002 1.0894

p.u. Voltage at 138 kV bus calculated by ‘smoothed’ State Estimation including line flows at SSA1A and SSST1B

L1

138 kV

345 kV

L2 L3

L4

L5 L6

L10L7

-- OPEN --

L15G

22 kV BUS

SSST1A SSST1B

-0.66 MW

-0.66 MW0.66 MW

-2.4 MVAR0.66 MW2.5 MVAR

10 MVAR -2.4 MVAR

BAD DATA DETECTED

******************************* LINE FLOW SUMMARY ************************** # 1 138KV V= 1.096 p.u. MEAS. NORM. Zhat FROM TO ERR. 138KV SSST1A MW 0.0327 0.0015 0.0342 BAD DATA detected for this measurement 28 138KV SSST1A MVAR 0.5000 0.2163 0.2859 138KV SSST1A V 1.0905 0.0053 1.0958 138KV SSST1B MW -0.0327 0.0013 -0.0340 138KV SSST1B MVAR -0.1211 0.0253 -0.0958 138KV SSST1B V 1.0905 0.0053 1.0958 # 2 SSST1A V= 1.079 p.u. MEAS. NORM. Zhat FROM TO ERR. SSST1A 138KV MW -0.0327 0.0012 -0.0338 BAD DATA detected for this measurement 31 SSST1A 138KV MVAR -0.1202 0.1622 -0.2814 SSST1A 138KV V 1.0833 0.0044 1.0789 SSST1A 4KVSA MW 0.0007 0.0010 -0.0003 SSST1A 4KVSA MVAR 0.1775 0.0173 0.1602 SSST1A 4KVSA V 1.0833 0.0044 1.0789 SSST1A 4KVSB MW 0.0320 0.0005 0.0314 SSST1A 4KVSB MVAR -0.0573 0.0161 -0.0733 SSST1A 4KVSB V 1.0833 0.0044 1.0789

Worst Residual 0.2163 Detected at Measurement 28

STATE ESTIMATOR RESULTS Values in p.u. 20 MVA, 22 kV

0.5 p.u. == 10MVAR

OPEN CONDUCTOR DETECTED AT INPUT TO TRANSFORMER SSST1A, BUS #4

POSSIBLE CAUSES OF ‘bad data’ 1) There is a fault on the power system, such as an open-circuit. 2) Failure in a) Step-down transformer b) rms converter c) A/D converter 3) The data point was taken during a transient. 4) A glitch has occurred in data acquisition, transfer to/from data bank.

1) If the point is bad for several scans, verify the reading by another transducer. Take corrective action to repair the transducer.

ACTIONS UPON DETECTION OF ‘bad data’ 1) If there are multiple ‘bad data’ points, alarm the operator to take immediate corrective action at the location of the data readings 2) If the ‘bad data’ repeats for several scan cycles, remove the ‘worst’ and repeat scans for the next worst ‘bad data’. 3) If there is only a single bad data point, and it repeatedly is identified as the only ‘bad data’ point for several scans, issue a repair/check notice.

18

1) State Estimation is an independent system monitor that does not disrupt normal protective relaying. 2) State Estimation is essential for bad data detection and replacement of ‘lost’ measurements. 3) ‘Smoothed’ values of voltages, currents and power flow are presented to operators within the plant 4) Safety, reliability, and daily operation of the plant are increased versus a protective relay “false trip” vulnerability. 5) Open phase conductor can be detected whenever the State Estimator is executed. (Power systems periodically run the State Estimator every 1.0 Second)

CONCLUDING REMARKS

Future PMU’s & Synchrophasors • With the advent of modern transmission system Phasor

Measurement Units (PMU), the synchronized electrical measurements (Syncrophasors) can speed the SE algorithm

• If synchrophasor measurements are enabled at BV via new Digital Fault Recorders, the ~4 degree phase angle differences around the BV supply network provide suitable differences for State Estimation input data

• Synchrophasors allow the Phase Angle of currents and voltages to be measured and employ both data in the

State Estimator. PSC computer code is the only State Estimator that now incorporates current measurements.

SE Going Forward Plan at BV • Plant Health Committee (PHC) presentation delivered

in May for PSC (Dr. Kusic) to perform Feasibility Study resulted in PHC approval With Acceptable Fleet Value Rating.

• Request For Engineering Services (RES) submitted and approved by Electrical/I&C Management.

• Future Action: Funding approval For Feasibility Study With PSC to address CA 2012-02616-3.

• CONTACT JOHN FLAHERTY FOR FENOC DETAILS (Cell Phone 412-512-1003)

1

Challenges in Open-Phase Detection

Roy Lyon Southern Nuclear

Fleet Design Engineering

June 27, 2013

2

Introduction • Existing protection schemes in the industry (nuclear and

non-nuclear) were not designed to specifically detect open phase events, but they are sometimes effective.

• Most open-phase conditions can be detected by conventional relaying.

• Some open-phase conditions present very difficult detection challenges.

• The following slides show various open-phase conditions and possible detection attributes.

3

Open-Phase Detection Map

Open Phase

4

Condition 1 – HS Open, 75% Load, 2000Ω Fault Condition

Pre-Event 1

Load 75% 75% Fault Ω ====> None 2000 SY A amps 79.4 0 SY B amps 79.4 152 SY C amps 79.4 182 HS A amps 79.4 37 HS B amps 79.4 152 HS C amps 79.4 182 HS Neut amps 0 192 HS I0 amps 0 64 HS I1 amps 79.4 100 HS I2 amps 0 72 HS %I2/I1 0% 72% HS NEMA I % 0% 70% HS %V2/V1 0% 39%

Condition Pre-

Event 1 Load 75% 75% Fault Ω ====> None 2000 LS A amps 2116 794 LS B amps 2116 3474 LS C amps 2116 3495 LS Neut amps 0 0 LS %I2/I1 0% 67% LS NEMA I % 0% 69% LS %V2/V1 0% 33% A-B volts 118.6 61 B-C volts 118.6 110 C-A volts 118.6 100

Detection Possibilities: • SY & HS Amps • HS Neutral Amps • HS I0 Amps • HS I2 Amps • HS % I2/I1 • HS NEMA I % • HS % V2/V1 • LS % I2/I1 • LS NEMA I % • LS % V2/V1 • LS DGV (2 of 3)

5

Condition 2 – HS Open, 75% Load, No Fault Condition

Pre-Event 2

Load 75% 75% Fault Ω ====> None None SY A amps 79.4 0 SY B amps 79.4 120 SY C amps 79.4 140 HS A amps 79.4 0 HS B amps 79.4 120 HS C amps 79.4 140 HS Neut amps 0 124 HS I0 amps 0 41 HS I1 amps 79.4 87 HS I2 amps 0 46 HS %I2/I1 0% 53% HS NEMA I % 0% 100% HS %V2/V1 0% 22%

Condition Pre-

Event 2 Load 75% 75% Fault Ω ====> None None LS A amps 2116 1175 LS B amps 2116 2783 LS C amps 2116 2915 LS Neut amps 0 0 LS %I2/I1 0% 47% LS NEMA I % 0% 49% LS %V2/V1 0% 18% A-B volts 118.6 85 B-C volts 118.6 114 C-A volts 118.6 112

Detection Possibilities: • HS Neutral Amps • HS I0 Amps • HS I2 Amps • HS % I2/I1 • HS NEMA I % • HS % V2/V1 • LS % I2/I1 • LS NEMA I % • LS % V2/V1

6

Condition 3 – HS Open, 5% Load, 2000Ω Fault Condition

Pre-Event 3

Load 5% 5% Fault Ω ====> None 2000 SY A amps 5.7 0 SY B amps 5.7 49.2 SY C amps 5.7 55.7 HS A amps 5.7 47.9 HS B amps 5.7 49.2 HS C amps 5.7 55.7 HS Neut amps 0 152 HS I0 amps 0 50.6 HS I1 amps 5.7 6 HS I2 amps 0 3.7 HS %I2/I1 0% 62% HS NEMA I% 0% 6% HS %V2/V1 0% 28%

Condition Pre-

Event 3 Load 5% 5% Fault Ω ====> None 2000 LS A amps 311 143 LS B amps 311 423 LS C amps 311 493 LS Neut amps 0 0 LS %I2/I1 0% 62% LS NEMA I % 0% 59% LS %V2/V1 0% 28% A-B volts 122 75 B-C volts 122 121 C-A volts 122 118

Detection Possibilities: • HS Neutral Amps • HS I0 Amps • HS % I2/I1 • HS % V2/V1 • LS % I2/I1 • LS NEMA I % • LS % V2/V1

7

Xfmr. Sec. Conditions A & B – 5% Load, No Fault Should there be a automatic protective trip for Condition A or B? If so, what detection attribute should be used? Note: • The percentage of negative/positive

sequence current (% I2/I1) is much less than the 15% value that IEEE C37.96 lists as a typical motor protective setpoint.

• Voltage unbalance is between the NEMA acceptable value of 1% and the unacceptable value of 5%.

• There is no significant detectable difference in the two sets of transformer secondary data for Conditions A & B.

Condition Pre-

Event A B Load 5% 5% 5% Fault Ω ====> None None None LS A amps 311 294 296 LS B amps 311 313 332 LS C amps 311 331 308 LS Neut amps 0 0 0 LS %I2/I1 0% 7% 6.7% LS NEMA I % 0% 6% 5% LS %V2/V1 0% 2.5% 2.4% A-B volts 122 118 118 B-C volts 122 122 122 C-A volts 122 123 118

8

Xfmr. Pri. Conditions A & B – 5% Load, No Fault Condition

Pre-Event A B

Load 5% 5% 5% Fault Ω ====> None None None SY A amps 5.7 0 6.5 SY B amps 5.7 9.3 4.4 SY C amps 5.7 10 11 HS A amps 5.7 0 6.5 HS B amps 5.7 9.3 4.4 HS C amps 5.7 10 11 HS Neut amps 0 16 16 HS I0 amps 0 5.4 5.1 HS I1 amps 5.7 5.7 5.7 HS I2 amps 0 0.4 0.4 HS %I2/I1 0% 7.0% 6.7% HS NEMA I% 0% 100% 49% HS %V2/V1 0% 2.6% 2.5%

Condition A: Open Phase Condition B: 2.5% Voltage Unbalance

(Not considered unusual) Detection Possibilities (Xfmr. Primary): • HS Amps (Lack of current in a phase) • HS NEMA I % (Current unbalance)

9

Condition C – HS Open, No Fault, No Load Condition

Pre-Event C

Load 0% 0% Fault Ω ====> None None SY A amps 0.22 0 SY B amps 0.22 0.38 SY C amps 0.22 0.38 HS A amps 0.22 0 HS B amps 0.22 0.38 HS C amps 0.22 0.38 HS Neut amps 0 0.66 HS I0 amps 0 0.22 HS I1 amps 0.22 0.22 HS I2 amps 0 0 HS %I2/I1 0% 0% HS NEMA I% 0% 100% HS %V2/V1 0% 0.1%

Condition Pre-

Event C Load 0% 0% Fault Ω ====> None None LS A amps 0 0 LS B amps 0 0 LS C amps 0 0 LS Neut amps 0 0 LS %I2/I1 0% 0% LS NEMA I % 0% 0% LS %V2/V1 0% 0.1% A-B volts 122 122 B-C volts 122 122 C-A volts 122 122

Detection Possibilities: •HS NEMA I % Applicable only if there is detectable current (which is questionable).

10

Condition D – Two HS Open, 5% Load, No Fault Condition

Pre-Event D

Load 5% 5% Fault Ω ====> None None SY A amps 5.7 0 SY B amps 5.7 0 SY C amps 5.7 23 HS A amps 5.7 0 HS B amps 5.7 0 HS C amps 5.7 23 HS Neut amps 0 23 HS I0 amps 0 7.6 HS I1 amps 5.7 7.6 HS I2 amps 0 7.6 HS %I2/I1 0% 100% HS NEMA I% 0% 100% HS %V2/V1 0% 99%

Condition Pre-

Event D Load 5% 5% Fault Ω ====> None None LS A amps 311 413 LS B amps 311 413 LS C amps 311 826 LS Neut amps 0 0 LS %I2/I1 0% 100% LS NEMA I % 0% 25% LS %V2/V1 0% 99% A-B volts 122 2.7 B-C volts 122 99 C-A volts 122 101

Forsmark Event -Detection Possibilities: •HS % I2/I1 •HS NEMA I % •HS % V2/V1 •LS % I2/I1 •LS NEMA I % •LS % V2/V1 •LS DGV (2 of 2)

11

Observations • Heavy to moderately loaded transformers with

an open phase can be detected and reliably protected with conventional relay schemes.

• Reliable open-phase detection for very lightly loaded or unloaded transformers has not yet been developed, but usually such conditions are not immediately detrimental.

• An open-phase condition such as the Forsmark event (two open phases) appears easily detectable by all conventional degraded grid relaying schemes.

12

Observations (Cont.)

• Detection during a very low or no load condition is challenging and can lead to a false indication.

• Immediate disconnection may not be required for low negative sequence current conditions. An alarm may be more beneficial (i.e. no unnecessary LOOP) if the condition can be investigated and remediated in a controlled manner without loss of safety functions.

13

Observations (Cont.) • Class 1E bus voltages and currents are not

definitive indications of an open-phase event in all circumstances.

• Transformer primary-side currents can be an effective indication of an open-phase event for any detrimental condition.

14

Comments or Questions?

OVERVIEW PRESENTED BY TAMATHA WOMACK, TVA

Industry Strategy to the Open-Phase Condition

Summary Strategy for Open-Phase Condition

Industry development of the strategy to the Open-Phase Condition consists of three phases:

Detection

Consequences

Protection

Strategy Descriptions

Detection: Develop a method to simulate event Evaluate available software tools Develop an analytical model Determine model requirements Identify what electrical parameters CAN be detected

Consequences: Develop criteria Determine the consequences on equipment Develop criteria to limit negative consequences

Protection: Develop a protective relay scheme Protect against negative consequences Prevent spurious operation

Strategy Responsibilities

Detection Phase Concerted Effort - ETAP Nuclear Utility Users Group (NUUG)

Independent Effort - Individual Station (EMTP-RV and PSCAD)

Consequences Phase NEI Task Force

Protection Phase IEEE (NPEC and PRC)

EPRI

Individual Station