January 20 – 23, 2009
Automate a Substation and Preserve the Electromechanical Relay Investment
Part One of Four
Background, Automation Goals and Using the Bitronics 70 Series for
Fault Analysis
Paul Grabowski
Bitronics® Senior Application Engineer
January 20 – 23, 2009
About the Author
Paul Grabowski implemented automation in
over 100 substations during his 29-year
career with Pennsylvania Power and Light.
More recently, Paul spent five years as a US
protection application engineer for AREVA
T&D. He is now a Senior Application Engineer
for the Bitronics product lines. Paul is a
registered Professional Engineer in the State
of Pennsylvania.
January 20 – 23, 2009
Contents for Part One
• The Electromechanical Relay Scheme and its Limitations
• Typical Automation Goals
• Methods for Achieving Automation Goals
• Using the Bitronics 70 Series IED for Fault Analysis
• Conclusions
• Future Webinars for Parts Two, Three and Four of this Series
January 20 – 23, 2009
The Electromechanical Relay System and its Limitations
January 20 – 23, 2009
Electromechanical Relay Scheme Advantages
• From a protection point of view, why change tomicroprocessor based relays?
• Electromechanical relays
• Are durable
• High quality construction last for decades
• Operate correctly
• Provide same protective functions as microprocessor basedrelays
• Simplicity of function
• Simplicity in setting
• From a protection point of view, keepelectromechanical relays.
January 20 – 23, 2009
Electromechanical Relay Scheme Limitations
• New requirements for protection and control systems have evolved
• Monitoring and recording
• Communications
• Multiple protective setting functions and groups
• These requirements are referred to as “automation”
• Limitation
• Lack of automation capabilities
January 20 – 23, 2009
Forces Driving Automation
• Monitoring and recording• Operations & Maintenance
• Load system closer to maximum capability• Determine frequency of maintenance
• Planners• Tracking load growth to plan new facilities and upgrades
• Management• Justify capital needs
• Regulators• Allow rate increases and other capital improvements
• Customer interaction• Negative impact on power system
January 20 – 23, 2009
Forces Driving Automation (cont’d)
• Communications• Remote monitoring• Load shedding and restoration• Allow multiple departments to access system data
• Multiple protective setting functions and groups• Provide multiple protective functions in one relay• Multiple setting groups allow abnormal operating setups
January 20 – 23, 2009
Meeting Automation Requirements
• Microprocessor based technology provides a solution
• Two alternatives
1) Install microprocessor based relays
- Replace electromechanical relays
OR
2) Install microprocessor based recording and monitoring IEDs
- Such as the Bitronics 70 Series
- Allows retention of electromechanical relay scheme
Realize substantial cost savings
January 20 – 23, 2009
Typical Automation Goals
January 20 – 23, 2009
Some Typical Automation Goals
1) Fault Analysis and Recording
2) Improve Local Monitoring and Control
3) Provide/Improve Remote Monitoring and Control
4) Monitor Power Quality
5) Provide Protective Function Setting Groups and Backup ProtectiveFeatures
January 20 – 23, 2009
Goal 1 - Fault Analysis and Recording
• Current scheme – limitations
• Cannot monitor relay performance
• Correct vs. incorrect operations
• Relay failures
• Fault conditions
• Analysis and recording in an electromechanical substation
• Without a Fault recorder/SOE recorder
• Depends on targets
• Detailed analysis and recording non-existent
• Obsolescent fault recorder/Separate SOE recorder
• Doesn’t meet current needs
• Lacks communication features
• Fault records and SOE log in separate devices
• May not be able to upgrade
January 20 – 23, 2009
Goal 1 - Fault Analysis and Recording (cont’d)
• Improvements with automation• Multiple recorders in one unit
• Waveform (oscillography)• Disturbance• Trend• SOE
• Allow detailed analysis• Did relays operate?• Did they operate correctly?• Causes• Other system problems
January 20 – 23, 2009
Goal 2 – Improve Local Monitoring
• Current scheme - limitations
• Electromechanical meters
• Non-linear
• Drift
• Shared metering
• Limited monitoring available
• Improvements with automation
• Improve indication and monitoring, digital vs. analog
• Simultaneous monitoring of three phase quantities
• Additional quantities to monitor
• Recalibration not required
• Remove paper chart recorder
January 20 – 23, 2009
Goal 2 – Improve Local Control
• Current scheme - limitations
• Analog control systems
• Sync check, Cap bank control, Tap changer
• Limited in scope
• Modifications costly
• Improvements with automation
• Digital control
• Better resolution and accuracy
• Reduce cost for new features
• Controls in software vs. hardware
January 20 – 23, 2009
Goal 3 – Improve Remote Monitoring and Control
• Current scheme - limitations
• Without SCADA
• No remote monitoring
• High cost for initial installation
• Existing SCADA
• Limited monitoring capability
• Protocol limitations – proprietary protocols
• Communications limitations
• No ability to add advanced features
January 20 – 23, 2009
Goal 3 – Improve Remote Monitoring and Control (cont’d)
• Improvements with automation
• Provide SCADA capability
• RTU vs. Ethernet network approach
• Reduced installation costs
• Enhanced monitoring capability
• Open protocols
• High speed and capacity over Ethernet
• Noise tolerant using fiber
January 20 – 23, 2009
Goal 4 – Monitor Power Quality
• Power quality issues from the power provider’s viewpoint
• Items impacting power systems at all voltage levels
• Large motor loads
• Voltage flicker
• Large SCR type equipment
• Harmonic injection
• Large inductive loads
• Increase losses
• Higher operating costs
January 20 – 23, 2009
Goal 4 – Monitor Power Quality (cont’d)
• Current scheme – limitations
• Monitoring equipment is minimal
• Difficulty in finding and correcting problems
• Improvement - continuously monitor the power system
• Identify problems
• Determine the source
• Take corrective action
• Find customer causing the problems
• Improve efficiency reduce costs
January 20 – 23, 2009
How to Achieve Automation Goals
January 20 – 23, 2009
Two Major Options
1 - Install microprocessor based relays
• Replace electromechanical relays
2 - Install Bitronics 70 Series monitoring and recording IED
• Retain electromechanical relays
• Both have desired monitoring, recording and communicationscapabilities
• Evaluate and compare
January 20 – 23, 2009
Evaluation – Install Microprocessor Based Relays
• Option 1
• Install microprocessor based relay in same location as electromechanical relays
• Cut relay into current, voltage & control circuits
• Option 2
• Install microprocessor based relay in new panel
• Install new panel in existing open space in control cubicle
• Reroute current, voltage and control circuits
• Option 3
• Same as option 2
• Expand Control cubicle
January 20 – 23, 2009
Evaluation – Install Bitronics 70 Series
• Retain electromechanical relays andscheme
• Option 1
• Install Bitronics 70 series microprocessor basedmonitoring and recording IEDs
• Cut the 70 series IED into the existing currentand voltage circuits
• Option 2 and 3 not required
• Compact size device
January 20 – 23, 2009
Evaluation – Install Bitronics 70 Series, cont’d
• Bitronics 70 series hardware
• Main unit with transducer footprint
• Separate displays
• Main unit
• Fits behind panel
• 3 rack units high
• Width 8.5” to 13”
• Depth 7” or 9” deep
• Display
• Fits in 4” round meter cutout
January 20 – 23, 2009
Cost Comparison
• Install Microprocessor based relays
• Example
• Microprocessor based relay cost = $8,000
• Total project cost in existing space = $18,000
• Control house expansion or new panel = $ unknown
• Long term outages = $ unknown
• Install Bitronics 70 Series
• Cost is low compared to microprocessor based relay
• Monitoring and recording IED = $ 2,000
• Total project cost = $ 6,000
• Short term outages = $ minimal
• Conclusion
• Relay replacement is 3x to 5x as costly
January 20 – 23, 2009
70 Series – What do You Get?
• Advanced monitoring and recording
• 128 samples per cycle
• More samples than most microprocessor relays
• Resolution provides ability to differentiate underlying cause
• Features equal to or better than microprocessor based relays
January 20 – 23, 2009
Bitronics 70 Series Features
• Recorders• 2 Waveform recorders• 2 Disturbance recorders• 1 Trend Recorder• 2 Voltage fluctuation tables• 1 SOE log
• I/O• Digital I/O• Transducer Inputs
January 20 – 23, 2009
Bitronics 70 Series Features (cont’d)
• SCADA Node
• Protocols available
• DNP3.0
• MODBUS
• UCA2
• IEC61850
• Communications
• Serial RS232 and RS485
• Ethernet
January 20 – 23, 2009
Using the 70 Series
to Monitor Relay Performance
Under Fault Conditions
January 20 – 23, 2009
70 Series Fault Analysis Tools
• 70 series recorders
• 2 Waveform recorders
• 2 Disturbance recorders
• 1 Trend Recorder
• 2 Voltage fluctuation tables
• 1 SOE log
• Use one or more recorders for analysis
• Multiple recorders often needed to complete the picture
• Exception; Voltage fluctuation tables not used
January 20 – 23, 2009
70 Series Fault Analysis Examples
• Analyze Fault Details
• Relay appears to operate correctly
• Find Distance to Fault
• Verify and Correct Nuisance Alarms
• Identify a fault vs. normal Condition
• Verify operation of other equipment
January 20 – 23, 2009
Analyze Fault Details
• Waveform record (Input signals)
IA phase
IB phase
IC phaseFault
initiation
Fault duration
CB “a”
switch
About the Author
January 20 – 23, 2009
Analyze Fault Details, cont’d
• Disturbance record (Measurement values)
Max RMS IA
Fault
initiation Fault duration
CB “a”
switch
Max RMS IB
Max RMS IC
January 20 – 23, 2009
Analyze Fault Details, cont’d
• Trend record (Measurement values) Fault
Fault
Max RMS IB
Avg RMS IB
Min RMS IB
January 20 – 23, 2009
Analyze Fault Details, cont’d
• Trend record (Measurement values)
Fault
January 20 – 23, 2009
Analyze Fault Details, cont’d
• SOE Log ties it all together
January 20 – 23, 2009
Relays appear to operate correctly
• Relays appear to operate correctly
• How do I know?
January 20 – 23, 2009
Find Distance to Fault
RA
RB
RC
RA
RB
RC
DIO#0 In 1
DIO#0 In 2
DIO#0 In 3
Bitronics
70 Series
• Add fault distance to electromechanical scheme
January 20 – 23, 2009
Find Distance to Fault (cont’d)
• A phase fault distance
January 20 – 23, 2009
Find Distance to Fault (cont’d)
• B&C phase fault distance
January 20 – 23, 2009
Find Distance to Fault (cont’d)
Local Display
January 20 – 23, 2009
Verify and Correct Nuisance Alarms
January 20 – 23, 2009
Verify and Correct Nuisance Alarms (cont’d)
January 20 – 23, 2009
Verify and Correct Nuisance Alarms (cont’d)
M572
3 B
us
Faulted
winding
M
Customer’s
Point of Delivery
January 20 – 23, 2009
Fault vs. Normal Condition
M871
345kV-66kV
66kV
3 B
us
CB trips after
closing
January 20 – 23, 2009
Fault vs. Normal Condition (cont’d)
• Legitimate fault or normal operation?
IA phase
IB phase
IC phase
January 20 – 23, 2009
Fault vs. Normal Condition (cont’d)
• Analyze conditions that cause trips
• Avoid lengthy outages
IA phase
2nd harmonic
fundamental
January 20 – 23, 2009
Verify operation of other equipment
M871
3 B
us3 pole CB
January 20 – 23, 2009
• Poles not synchronized
Verify operation of other equipment, cont’d
IA phase
IB phase
IC phase
A&B
phase
open
C phase
open
January 20 – 23, 2009
• Auxiliary switches issues
Verify operation of other equipment, cont’d
IA phase
IB phase
IC phase
CB a switch
CB b switch
January 20 – 23, 2009
• Auxiliary switches issues
Verify operation of other equipment, cont’d
IA phase
IB phase
IC phase
CB a switch
CB b switch
January 20 – 23, 2009
Conclusions and Future Webinars
January 20 – 23, 2009
Conclusions
• Electromechanical relay schemes
• Provide adequate protection
• Lack monitoring and recording features now required
• Achievement of new monitoring and recording requirements
• Relay replacement not necessary
• Instead, consider Bitronics 70 Series monitoring and recording IED
• Meets new requirements
• Significant cost savings
• Four major areas for achieving requirements
• Part 1 Fault analysis and recording
January 20 – 23, 2009
Future Webinars
• Part Two – Improve local monitoring and control February 2009
• Part Three – Improve remote monitoring and control April 2009
• Part Four – Improve power quality monitoring June 2009
January 20 – 23, 2009
Questions?
Thank you.