multi-vendor experiences with iec 61850 installation...
TRANSCRIPT
Copyright © SEL 2008
Multi-vendor Experiences with
IEC 61850 Installation, Testing,
Configuration, Diagnostics, and
Upgrades
David Dolezilek
Schweitzer Engineering Laboratories, Inc.
Practical Uses of IEC 61850 Protocols
and Synchrophasors
GOOSE in a Centralized Remedial Action
Scheme (CRAS)
GOOSE versus hard-wire protective trip
RTU I/O collection via GOOSE
Diagnostics tools for GOOSE “virtual wiring”
Recent Global IEC 61850 installations
Improving RAS with synchrophasors
Remedial Action Schemes
Southern California Edison (SCE)
Tested Digital Communications Speed
Strive to mitigate thermal overload and
instability throughout
transmission territory
13.313
3 4
26.7
8.4
Peer-to-Peer Control
Tim
e (
ms)
RAS Round-Trip
SEL Mirrored Bits® Communications
SEL IEC 61850 GOOSE
Non-SEL IEC 61850 GOOSE
Detect Decide Trip
Performance Criteria: Detect, Calculate,
React 50 ms To / From any Location
Test starts when Monitor
detects Contact Input 1
Monitor chooses action to take
Monitor sends monitor alarm
Central Processor receives
monitor alarm
RAS enabled in Central Processor?
Central Processor chooses
action to take
Central Processor sends
decision alarm
Mitigator receives decision alarm
Mitigator chooses action to take
Mitigator closes trip output contact
Monitor detects mitigation trip output
as Monitor Contact Input 2
Scope measures difference
between Contact Input 1 and 2Yes
Initial Testing Verified Time Budget
Using Three IEDs 740 Km Apart
Next: Arming via SEL an Dell Computers
Multiple Devices Demonstrated for
WECC RAS Committee
Within One
Hour, Five
New
Devices
Were
“Digitally”
Wired
Typical: GOOSE Trip Tansit 1.50 msec
Central Processing Time 2.083 msec
Monitor is 60 miles distant. Mitigators are local to CP.
Mitigation GOOSE transit, subscription, output - 3 msec or 11 msec
Jim Bridger Power Plant
Simultaneous, Independent Operation
DNP Gateway
IEC Logic
Controller
I/O
Modules
IEC Logic
Controller
IEC Logic
Controller
I/O
Modules
I/O
Modules
DNP Gateway
IEC Logic
Controller
I/O
Modules
IEC Logic
Controller
IEC Logic
Controller
I/O
Modules
I/O
Modules
RAS DRAS C
Three Levels
of Voting
Crosspoints Voting
InputInput Input
Input Voting
Output Voting
Output
Jim Bridger Substation
RAS Uses Crosspoint Switch
Crosspoint Switch
f
tCB
Opens
Tripping
Outputs
Trigger
Inputs
X
Trip G2
N5
N4
XN3
XN2
N1
Trip G1
Output RemediationContingency
Trip G3
X
Trip G4
X
Bypass
C1
X
Bypass
C2
X
X
X XX
X
Preloaded and Ready to Go
Designed to Handle Multiple, Closely
Timed Events
N-EventsIN1
N=1
S1
IN6
N=20
S1
IN6
N=6
S2
First Event
Example 1 Example 2
Time (s)
System State
t=5st=0s
PacifiCorp / Idaho Power Remedial Action
Scheme Eliminates Congestion
Stability improvements increase capacity 50%, avoid blackouts
Fastest control
system in the
world
Training / Testing / Playback Simulator
Test Simulator Plugged Into RAS C
Protection-Class Features
Deterministic, high-speed, peer-to-peer
protocol used between RAS controllers
No backplanes to fail
No auxiliary power supplies
MS Windows® NOT used in RAS controller
All controllers embedded
Identical logic in all six controllers
Florida’s International
Drive 1999 Project: Distribution Automation
at Transmission Speeds
Switching With a Recloser…
Manual Switching = 1 hour
Switching w/Recloser = 10 seconds
Recloser + Control Without Communications
…vs. Distribution at Transmission SpeedSEL & S&C for International Drive
SEL-351S + Communications
Smart Switching = 0.1 second
Multivendor IEC 61850
CFE Parque Eolico La Venta
Existing Generators at Wind Farm
Biggest Wind Farm Project in Mexico
CFE expects to generate close to 3 GW
by 2014 in “La Ventosa”
Substation Expansion - New Generators
SEL - MX060018 Project Satisfies
Newest SICLE Design With IEC-61850
SICLE is Spanish Acronym for
“Integrated System For Substation Local
Control”
CFE Specifies SICLE for integration of high
voltage substations, SISCOPROMM for low
voltage
CFE Decided to Build Small but
Meaningful Substation
CFE wanted to prove 61850 was real
Include as many vendors as possible
Add other redundant IEDs in parallel
Demonstrate true functionality on the
network
Prove multi-vendor interoperability
“This is, without any doubt, a great
advancement for the integration of control
and protection systems, and for integration
of the IEC 61850 International standard.”
David Lancha, Project Manager, IBERINCO
Proven. Reliable.
Complete.
World’s First Multisupplier
IEC 61850 System in Service
Since 2006
Wind Farm Under Construction
50BF
50BF
51PHS
87T
51PHS
51NHS
51NLS
87B
RD
50BF
79
21PP
87L
La Venta II Substation
Protection Requirements
Design #1 Used IEC 61850 Part 5, SEL Methods
in IEDs, IEC 61850 in SCADA Gateway
SEL-451-4
SEL-451
SEL-451-4
SEL-451
SEL-387E
SEL-451-4
SEL-451
SEL-311L
SEL-421
SEL-487B
SEL-3351
SEL-3351
SEL-3332
SEL-3332
230KV Line
LVD93100
230KV
Autotransformer
LVD92010
230KV Tie
LVD97010
230KV Bus
Diff
LVDDB9
Redundant
HMI
Redundant
SCADA
Gateway
Information Processor Serves DNP/Conitel as
SCADA Gateway and OPC to HMIs
CFE Requested IEC 61850 in all IEDs
SEL-421 – Distance
SEL-311L – Current Differential
SEL-451 – Distribution
SEL-387E – Transformers
SEL-487B – Buses
SEL-451-4 – Bay Control
SEL-3351 Rugged Computer
SEL ACSELERATOR Architect –
Substation Configuration Language
(SCL) Engineering SoftwareSEL-710 – Motors
SEL-2411 – Automation
Controller SEL-751A – Feeders
Meet CFE Substation Protection
Requirements Using IEC 61850
Conventional wiring and IEC 61850 GOOSE
Test performance of conventional wiring vs.
GOOSE for protection functions
Determine if all relays will interoperate and
perform as desired
IEDs approved by CFE
Design #2 Used IEC 61850 Part 8,9 in the IEDs IEC 61850 From SEL for Every Application in Bays
SEL-451-4
SEL-451
SEL-451-4
SEL-451
SEL-387E
SEL-451-4
SEL-451
SEL-311L
SEL-421
SEL-487B
SEL-3351
SEL-3351
SEL-3332
SEL-3332
230KV Line
LVD93100
230KV
Autotransformer
LVD92010
230KV Tie
LVD97010
230KV Bus
Diff
LVDDB9
Redundant
HMI
Redundant
SCADA
Gateway
Next CFE Chose to Demonstrate Multi-
vendor Interoperability
System integrates devices from multiple
vendors
SEL Siemens
GE ZIV
RuggedCom Team ARTECHE
Other vendors invited but did not have
IEC 61850 available or not approved by CFE
Two Different Engineering Groups
Working in Parallel to Integrate IEDs
HMI LN reporting and bay level
GOOSE IEC 61850 integration
being done by Iberdrola
SCADA Gateway LN reporting and
station level GOOSE IEC 61850
integration being done by SEL
New Products for CFE : Bay Control, SCADA
Gateway, and IEC 61850
SEL Scope: Panel Design for Parque Eolico
“Wind Farm” and Intertie Substation
Design #3 Used IEC 61850 Part 8,9 in the IEDs Added IEC 61850 Devices From Other Vendors
SEL-451-4
SEL-451 SEL-451
SEL-387E
SEL-451
SEL-311L
SEL-421
SEL-487B
SEL-3332
230KV Line
LVD93100
230KV
Autotransformer
LVD92010
230KV Tie
LVD97010
230KV Bus
Diff
LVDDB9
Redundant
HMI
Redundant
SCADA
Gateway
GE F650 BC
Siemens 7SJ62
GE F60
Siemens 7SJ61
ZIV BC
GE T60
GE F35 GE L90
ZIV HMI
ZIV HMI
ZIV CPT
Panels Ready for Installation
System Architecture
Router
+ Firewall
Remote HMI
RuggedCom
Fiber-Optic
Ring
DNP
Conitel
SW-4
SW-5
SW-3
SW-1
SW-2
GE F650 BC
SEL-451 50BF, 25, 27
SEL-387E
GE T60 87T
GE F60 50, 51HS
GE F35 50, 51TZ
Siemens 7SJ62 50, 51LS
Siemens 7SJ61 50, 51N
SEL-451-4 BC
SEL-451 50BF, 25, 27
ZIV 6MCV BC
SEL-421 21, 67
SEL-279H 79
SEL-451 50BF, 25, 27
GE L90 87L
SEL-311L
SEL-487B 87BGPS
ZIV CPT ZIV HMI ZIV HMI
SEL-3332
SCADA Gateway
SEL Construction, Factory Acceptance
Test (FAT), Training, Commissioning
IEC 61850 SCL Replaces Wired
Connections With Logical Connections
GOOSE Messages for Protection
CFE wanted to see performance comparison between wired and GOOSE
CFE chose to test breaker failure protection scheme using GOOSE
Primary protection trip
Breaker failure relay retrip
Breaker failure relay trip
Breaker failure trip reception by bus differential relay
Trip to all breakers in bus
Customer Factory Acceptance Test
GOOSE Retrip Operation 12.5ms Faster
Than Parallel Hardwire at La Venta
GOOSE Breaker 21 TRIP A
Wired Contact Breaker 21 TRIP A
12.5 ms Difference
Between Inputs
86FI Operation: GOOSE 8 ms Faster
CFE Project Results
Retrip test; GOOSE three-fourths cycle faster
Breaker failure scheme; GOOSE half-cycle
faster – wiring scheme still has to go through
physical lockout (86) relay, which adds 6 to 8 ms
Configuration and troubleshooting made simpler
with sequential events recorder (SER) and
event reports
Traffic did not affect performance of SEL
devices
Project Engineering Revealed
Necessary Communication Parameters
Time synch method - chose SNTP
Sacraficed accuracy to use Ethernet
Changed back to IRIG later
Number of client associations – chose 6
Two redundant HMIs
Remote and local engineering workstations
Two redundant SCADA gateways
Interlock and Automation Projects
Dictated GOOSE Requirements
Number of outgoing GOOSE messages -
eight
Number of incoming GOOSE messages - 16
Number of incoming GOOSE bits
Bay control – 128
Relay –16, 128 depending on application
Parque Eolico La Venta II
PP&L Modernized
From PLCs to IEDs
Eliminate programmable devices
Digital transducers
PLCs
Eliminate other components
24 Vdc supplies
Interface relays
External fault detectors
Streamline, Reduce
Complexity With
IEC 61850 Design
Reduce Hardware Components With
IEC 61850 Design
Design Computers
Substation
PLCs & Comm.
Processor
Bay
PLCsRelays
Metering
IEDs
Ethernet
SwitchesSER Total
PLC 3 5 22 24 16 4 1 75
NGS 3 1 0 24 0 2 0 30
Display Redundant Data Sources via HMI
L2 P disagrees with other IEDs Faulty L2 P manually removed
Using IEC 61850 Methods for RTU
Replacement and Distributed Automation
RTU Vendor Went AWOL
No New Units, No Product Support
Over 400 pad-mounted switchgear in service
50 to 100 new each year
Three switch configurations controlling
one to six circuit taps or “ways”
Desire to simplify configuration, add
engineering access, and improve logic
Numerous I/O Configurations Must Fit
in Fixed Small Space
DNP3 serial over radio to SCADA Master
changing to DNP3 / TCP in future
RTU Real-Time Values via Internal and
External Communications Connections
RTU Replacement Network Could Also
Connect I/O of Relays and Meters
Example system database
32 AC analog inputs
2 DC analog inputs
24 digital inputs
16 digital outputs
192.168.0.15 192.168.0.25 192.168.0.30
192.168.0.20
SCADA
Master
DNP3 Serial
Ethernet
SwitchGOOSE Messages
PAC_MASTER
PAC_Slave_A PAC_Slave_B PAC_Slave_C
Data Flow Acts the Same as Distributed
RTU I/O Panels But Performs Better
SCADA Master
Field Inputs
GOOSE Inputs
DNP3 Response
DNP3 Command
Contact Output
GOOSE Outputs
Multi-vendor Configuration Requires
Stand-Alone Tool Specifically for 61850
Alternate traditional UCA2 method of
proprietary settings makes multi-
vendor systems difficult
Configure IED via International Standard
Substation Configuration Language, SCL
Start with IED capability
description, ICD file
Create configured IED
description, CID file
Edit only what you
choose
No accidental changes
Minimize verification
testing
Load File in IED, or Send to Colleague Via
email to Add Future IED Subscriptions
“Best Practice” Provides Contextual
Names – Generic Names Less Useful
Best practice provides specific names whenever possible
Exceptions include generic logic points, unnamed contact I/O
Generic Specific
Use Unique Name and Revision ControlAsk IED Directly to Verify Present Configuration
Solicit identification report from IED
IED name reveals file name and revision
ConfigVersion reveals default SCL file that
configuration was developed with
IED GOOSE Reports Are Essential
Review receive and
transmit configuration
Quickly review network
settings
Analyze GOOSE statistics
and diagnostics
Immediately pinpoint
source of problem
Identification (ID) Reports Provide
Source / Destination of “Virtual Wiring”Mismatched Configuration Explains Failure
ID shows incorrect revision of PAC configuration
Once corrected, GOOSE report shows correct
revision as part of GOOSE reference name
Analyze Contents With Knowledge
of Configuration File
Failed GOOSE, Other Alarms Displayed
and Sent via Email, Voice, Text Message
Cigre
Multi-
vendor
System
of 12
Vendor
IEDs
Support 8 Unique GOOSE Publications,
16 Subscriptions, 24 for Complex
Interlocking
SEL-451-4
Sisco software
IED on PC
GE D60Siemens
6MD669
Areva
P444
Siemens
7SA525
Siemens
BC1703
GE
F650
Toshiba
GRZ100
ZIV
IRV-ATeam
Arteche
SEL-421
Second Generation Modernization
Began in 2006
Complete modernization
of 30 substations ranging
in voltage level from
13.8 kV to 138 kV
Elektro Network
Includes IEC 61850,
Telnet, FTP, and
SEL Protocols
Substations:
Guarujá 2 – first modernized substation energized June 12
2007 – seven complete
2008 – eight complete Sao Paulo State,
Brazil
Guarujá 2
Guarujá 3
Fiber Optics Replace Copper
KONYA Industrial Park
Chooses SEL and IEC 61850
500 large to mid-size electricity-dependent
tenants: plastics, machinery, pharmaceuticals
Park management responsible for infrastructure:
electricity, gas, water, traffic, security
One 100 MW transformer and three 33 kV
tie lines from National Grid
65 MW maximum demand increasing by 15%
every year
SEL-2407
GPS-Receiver
Clock
Front-End 1
Substation
Computing
Station 1
Front-End 2
Substation
Computing
Station 2 Station 3 Station 4 Station 5 Station 6 Station 7 Station 8
3 Tie Lines (6 Future)
6 x SEL-311L
Server 1 Operator
Station 1
42-Inch LCD
Monitors
SEL-3401
GPS-Clock
54 SEL-751A Relays and 38 SEL-311L Relays
Server 2Operator
Station 2
Switch
8 Switching Stations, 99 Feeders
Switch
Printers
Control Center
Manages 165
Distribution
Substations
24 km redundant fiber-optic ring
Future distribution automation additions
Use Modern Communications for
Diagnostics – FTP, Telnet, email
GEESE Migrate to Africa
Stations Include IEC 61850 MMS and GOOSE
City Power Pennyville – 19 bays , 2 bus
sections, 3 transformers
City Power Khanyisa – similar to above with
36 bays
City of Cape Town – 2 complete substations
Nelson Mandela Bay Municipality
Three new substations in 2008
Each based on IEC 61850
City Power Johannesburg
Harley Street Substation
Control Center
IEC 60870-5-101
Fdr 29Fdr 1
SEL
SEL-1102
SEL-2410SEL-2410
Switch Switch
SEL-1102 Gateway, 2 SEL-2410s, 36 Bays With SEL-451 Relays
Electricity of Vietnam (EVN)
State-owned utility established 1995
Generation, transmission, and distribution
for whole country
4 transmission
companies
79,800 km of
distribution lines
Growing Electricity Demand
Forecasted growth 17% per annum until 2025
0
100
200
300
400
500
600
1995 2000 2005 2010 2015 2020 2025
Production
Sales
Tera
watt-H
ours
First Phase – Substation Modernization
Began in 1999
First computerized 220 kV substation
commissioned in Ho Chi Minh City
This success resulted in digitizing more
substations through 2003
Early Substation Modernization
Conventional protection and control using
DNP3 serial and hardwired connections
Problems with incompatibilities between
multiple manufacturers’ IEDs
Second Phase – Standardization
To improve IED compatibility, EVN issued
specification for substation automation based
on UCA2
Based on this, first large-scale substation
automation system (SAS) was implemented
220 kV Thu Duc Substation
Upgraded
Protection
System
Architecture
220 kV
66 kV Busbar
Phase 1 Phase 3
Phase 2
220 kV
110 kV
Phase 1 Phase 3 Phase 2
Third Phase – IEC 61850
IEC 61850 Part 10 approved Oct. 2005
EVN standardized for future projects –
new and retrofit
All 500 kV
backbone
substations
upgraded by
2010
New System Requirements
Dual redundant fiber-optic LAN with no
single point of failure
IEC 61850 for all substation communication
IEC 60870-5-101 for SCADA
Host 1 Host 2Engineering
(Bridge to SCADA)HIS Server Router to WAN
Backup
IED
Backup
IED
Main
IED
Main
IED
Bay
Devices
Bay
Devices
Main
NIM
Backup
NIM
Bay CubicleBay Cubicle
Bay Cubicle
Option 2
Option 1
LAN 1
LAN 2
GPS Clock
Backup
IED
Main
IED
Bay
Devices
Fiber-Optic
Ethernet
100 Mbps
Standard System Hardware Architecture
Computerized Control and Monitoring
Local HMI,
engineering console,
and historian
Redundant system
servers running on
Windows® 2000 or Linux®
Old Protection Panels Replaced
Microprocessor-based relays perform
protection, control, and monitoring
Outdoor Cubicles Reduce Cabling
Existing Copper Cabling Binh Long Substation
Copper
Cabling
Reduced
@STATION System Overview
HMI1 HMI2ENG
HISGW
LAN / WAN
Primary Equipment
Meter
Hardware
Connections
Relays / BCUs
IEC 61850
Legacy Device GatewayRugged Computing Platform
SCADA Gateway
Test Results
User Interface FeatureRequired by
EVNTested
Display Response Time < 1 s < 1 s
Data Entry Response Time < 1 s < 1 s
Display Update Rate < 2 s < 2 s
Update Completion Rate < 1 s < 1 s
Test Results
User Interface FeatureRequired by
EVNTested
Alarm/Event
Response Time< 1 s < 1 s
Alarm Acknowledge/
Delete Time< 2 s < 2 s
Report and Logbook
Response Time< 0.5 min < 0.5 min
Display Color Printout
Response Time< 0.5 min < 0.5 min
User Interface FeatureRequired by
EVNTested
Console Inhibit Time for
Display Hardcopy< 2 s < 1 s
Analog Data
Collection Rate– < 2 s
Status Indication
Collection Rate– < 1 s
Failover Time Between
Main 1 and Main 2– 0 s
GOOSE Exchange Time < 10 ms < 8 ms
Test Results
Benefits of IEC 61850 SAS
Faster system integration with IED
interoperability
Reduction of copper cabling and
hardwiring GOOSE for peer-to-peer data exchange
Outdoor cubicles adjacent to feeder or bay
System malfunctions reduced by nearly
50%
What is a Synchrophasor?
v(t)
0
A
wt2
A
Reference
Time Waveform
and Phasor Representation
Absolute Time Synchronization Has
Fundamentally Changed the World
GPS RCVR
PMU 1
A B
Satellite
GPS RCVR
PMU 2
IRIG-B IRIG-B
Mag/Ang Mag/Ang
Direct State Measurement
SYNCHROPHASORS
GPS provides common time reference
Measure state vector
Measure currents, too
Synchronously!
Every second
Every cycle
Synchrophasors Provide a “Snapshot”
of the Power System
P= |V1| |V2|sinФ / X Ф= sin-1(PX / |V1| |V2|)
V1∠0 V2 ∠ФP→
Increase Stable
Power Transfer
Relays Are Right for Synchrophasors
Phasor measurement and control unit
(PMCU) ≥ PMU
Minimal incremental cost
Reduced current and voltage connections
High-accuracy measurements
High reliability and availability
Future control applications
Relays are everywhere
What Operators Did Not See Aug. 14th
64 Minutes
Utilities Are Operating Closer to the Edge
MarginMargin
1.0 1.3 1.5 1.7PU Nominal Load
1.0
0.5
0.0
Operating
Point
Bifurcation
Point
Long Island: Monitor Angles Between
Transmission Distribution Buses to
Detect & Prevent Voltage Collapse
X)θcos(2
V)θsin(1S
2
2
smax
ZL = R + jXVS 0
Vr
S = P + jQ
Apply Remote Synchronizing
115 kV
Bus
230 kV
Bus
13.8 kV
Bus
SEL-421
SEL-421
Improved View:
Synchroscope
and Freq Plot
make it easier
for operators
“The MRI of Power Systems”
NERC press release on Florida outage Feb. 26,
2008:
Synchrophasors are “Like the MRI of bulk power
systems”
SCE Uses C37.118 From
Relays and PMU
SCADA
Master
DNP3
IEEE C37.118
Information
Processor
Harris 5000/6000,
IEC 60870-103,
Modbus, SEL Fast
Message, Telegyr
8979, Conitel 2020,
CoDeSys, OPC, …
Distributed Generation Creates
Islanding Problems
Transmission
Network
DG
SEL-3378
Synchrophasors Detect and Correct
Islanding Problems
Defensive Strategies Working Group
New York State Reliability Council
NYSRC asked SEL to propose solutions
Mitigate impact of major disturbances on the
New York electric system
Blackout mitigation and prevention
Separate into “islands” using transmission
system fault protection relays
Canada
SEL Synchrophasor Total
Potential Worldwide!
North America
142,085 units
South America
15,903 units
Europe / Asia
4,115 units
Africa / Middle East
5,085 units
Asia
Pacific
45,793 units
Real-World Example – Line Repair
Error Detection
Relay-to-Relay
Synchrophasors for
Generator Shedding
Synchrophasors Make
CFE’s Grid Smarter
115 kV Network
400 kV
900 MW
AngosturaTapachula
City
400 kV
Southern Region Load
SabinoChicoasen
National
System
400 kV
Load Shedding Based on Angle
SynchrophasorsTrip
Generator
Detect and Control Adaptive Islanding
Transmission
Network
SEL-451
Relay / PMU
SEL-3378 SVP
Unintentional
Islanding
Distribution
Network
SEL-451
Relay / PMU
Over Angle Protection Holds System
Together
Area 1
Heavy
Load
Area2
Link 1
Link 2
Area 3
Light
LoadTrip
Generation
SEL-421 SEL-421Synchrophasors
(Chicoasen – Angostura) > 5° Trip Generation
Today: Most Processing Is at the Master
Finds topology
Purges bad data
Estimates stateMaster
RTU RTU
Asynchronous
Scan
~5 seconds per scan
. . . can have partial
information from
two or more
physical systems –
due to faults, switching,
swinging, tap changes.
One Utility’s View of Several Data
Streams
Bus Voltage
Line
MVA
Frequency
Instantaneous
Phase Angles
Trended
Phase Angles
PMU ID
Local Calculation of Line Temperature
Improves Power Transfer Reliability
+ +
Line Temperature = f (Ambient Temp, Current, Line Orientation, Season)
IEEE Synchrophasors Compatible
With IEC 61850 Networks Possible Future GOOSE or 9-2 Extension
IEEE C37.118,
Telnet, tunneled
serial
Verify CT wiring,
phase rotation,
settings
Determining the State of a Power System
4
3
2
1
34
232
231
12
V
V
V
V
I
I
I
I
Y
I12 I34
I231
I232
V1 V4V3V2
State Vector
Traditional RAS Clearing Time Budget
Relay I/O Module Computer I/O Module Relay Breaker
1 Cycle0 Cycle-1 Cycle
Relay
Detects
Fault
Relay Trips/
Asserts Contact
Output
RAS Controller
Issues Gen
Breaker Trip
2 Cycles
Relay Receives
Trip Command
and Trips Gen
Breaker
Breaker Trip
Time
3 Cycles 6 Cycles
Total RAS Clearing Time
SVP RAS Clearing Time ¾ Cycle Faster
Improving RAS with Synchrophasors
Direct state measurement is now practical
because of the widespread availability of
Synchrophasors
The SVP performs local direct state
measurement and control
Wide area RAS schemes are improved
because synchrophasors reduce the amount
of information communicated to the master
station
What Does a Future “Worst-Case
Scenario” Look Like?
Detect potential unstable operating conditions
Control islanding
Detect system oscillation before criticality
Minimize problems automatically
Synchrophasors Empower the Future