Background, Automation Goals and Using the Bitronics · PDF fileBackground, Automation Goals...

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


• Analog control systems

• Sync check, Cap bank control, Tap changer

• Limited in scope

• Modifications costly


• 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


• 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)


• 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


• Trend record (Measurement values) Fault

Fault

Max RMS IB

Avg RMS IB

Min RMS IB

January 20 – 23, 2009


• Trend record (Measurement values)

Fault

January 20 – 23, 2009


• 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


• B&C phase fault distance

January 20 – 23, 2009


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

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.

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