January 20 – 23, 2009

Welcome to NovaTech

Automate and PreserveElectromechanical Relay Investment

Part 4 of 4:Using the Bitronics® 70 Series to Improve Power Quality

Paul Grabowski

January 20 – 23, 2009

About the Author

Paul Grabowski implemented automation in over 100substations during his 29-year career with PennsylvaniaPower and Light. More recently, Paul spent five yearsas a US protection application engineer for AREVA T&D.He is now a Senior Application Engineer for theBitronics product lines. Paul is a registered ProfessionalEngineer in the State of Pennsylvania.

January 20 – 23, 2009

Introduction

January 20 – 23, 2009

Meeting Automation Requirements

• Technology

• 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

Some Typical Automation Goals

1) Fault Analysis and Recording

2) Improve Local Monitoring and Control

3) Improve Remote Monitoring and Control

4) Monitor Power Quality

5) Provide Protective Function Setting Groups and Backup ProtectiveFeatures

January 20 – 23, 2009

Conclusions from Part 1

• Comparison of costs• Alternative 1 Replace electromechanical relays with microprocessor based relays more costly• Alternative 2 - install microprocessors based non-relay IED such as Bitronics 70 Series• Relay replacement is 3x to 5x as costly

January 20 – 23, 2009

Improvements to Power Quality

using monitoring and recording IEDs

January 20 – 23, 2009

Improvements using Monitoring and Recording IEDs

• Electromechanical relay scheme vs. power quality

• No power quality monitoring available

• Difficulty in finding and correcting problems

• Improvements using monitoring and recording IEDs

• Identify problems

• Determine the source

• Take corrective action

• Improve efficiency reduce costs

• Reduce complaints

January 20 – 23, 2009

Power Quality Issues

• Power quality implies many things to different people• Power provider• Consumer• Regulators

• Focus on power quality issues from the power provider’s viewpoint, 5examples

1) Maintain System Voltage Levels

2) Monitor Voltage Flicker

3) Monitor Harmonic distortion

4) Transformer k-factor

5) Reduce cost of doing business

January 20 – 23, 2009

Example 1

Maintain System Voltage Levels

January 20 – 23, 2009

Unregulated Power System

• Power system with no tap changers or capacitor banks

Vs V

Equivalent Circuit

January 20 – 23, 2009

Unregulated Power System - Equivalent Circuit

• Vs is fixed

• Customer voltage level proportional to

• System impedance

• Load Magnitude

January 20 – 23, 2009

Unregulated power system - customer voltages

Load

CustomerVoltage

Time ofday12 M 12 M12 Noon6 AM 6 PM

• Load fluctuates during the day

• Consequence, voltage at customer point of delivery varies with load

• i.e. With time of day

• Plot of Customer voltage and load over a 24 hour period

January 20 – 23, 2009

Unregulated power system – acceptable voltage levels

CustomerLoad

CustomerVoltage

Time ofday12 M 12 M12 Noon6 AM 6 PM

Acceptablevoltagerange

• Power system voltages must be maintained within a certain range

• Required for customer equipment to operate properly

• Usually mandated by PUC

• Plot of Customer voltage and load

• With acceptable voltage levels

January 20 – 23, 2009

Maintaining Acceptable System Voltage Levels

• Acceptable voltage levels maintained using some form of voltagesupport

• Voltage support

• Load tap changers on transformers

• Capacitor banks

Load Tap

Changers

Capacitor

Banks

January 20 – 23, 2009

Voltage Support

• Usually automated

• Control devices can overridden by remote (supervisory) control

Cap Bank 1

Cap Bank 2

Transformer 1

Transformer 2Customers

Tap ChangerController

Cap BankController

Remote (supervisory)override

Add and remove

capacitors according

to voltage levels

Scheduled

for time of

day operation

Schedule during peak

hours

January 20 – 23, 2009

Tap 2

Effect of automated voltage support

CustomerLoad

CustomerVoltage

Time ofday12 M 12 M12 Noon6 AM 6 PM

Acceptablevoltagerange

SystemVoltage

Time ofday12 M 12 M12 Noon6 AM 6 PM

62kV

64kV

67kV

Tap 5

Tap 2

Tap 9

Cap 1on

Cap 1off

Tap 9

Tap 5Voltageschedule

January 20 – 23, 2009

What can go wrong?

• Transformer taps• Tap changer not following schedule• Transformer taps mismatched

• Capacitor bank scheme• Failed cans• Capacitor bank turning on or off incorrectly

• Use monitoring and recording IED such as 70 series to detect• Displays can show data locally• Recorders can document problems• Remote (Supervisory) monitoring and control• Have tap changer/capacitor controllers read and act on data from 70 series

January 20 – 23, 2009

Tap Changer not Following Schedule

• The taps should change at specified times• Analyze with 70 Series Trend and Disturbance recorders• The voltage changes seen should match the schedule

Transformer 1

Transformer 2

Tap ChangerController

BusVoltage

Schedule

70 Trend

kV

kV

Time

Time

Trouble!!

January 20 – 23, 2009

Transformer taps mismatched

• When designed, the transformers will have matching taps documented• E.G. Transformer #1 tap #5 = Transformer #2 Tap #5• This may not always be the case

• The taps should match on all the transformers• Different taps result in VARs circulating between transformers

Transformer 1

Transformer 2

Tap ChangerController

VARsTap 5

Tap 2

HighcirculatingVAR flow

Local Display

Remote(Supervisory)

Data

Use in tapchangercontroller

70 Series

January 20 – 23, 2009

Tap Changer not Following Schedule

• Tap position monitoring

Transformer 1

Transformer 2

Tap ChangerController

Tappositions

Tappositions

SupervisoryStatus from 70

Series

DNP Points

BI:4 Tr1 Tap#6

BI:5 Tr2 Tap#7

Trouble!!

Tap positions monitored usingDigital I/O or Transducer inputs

January 20 – 23, 2009

Capacitor Bank Failed Elements

• Capacitor bank construction

• Many capacitive elements in parallel with a relatively low voltage rating

• Connect many of these parallel groups in series to achieve the desired voltagelevel

Vrelay

Bus

• Failed can detection

• Usual way to determine if elements failis with voltage relay at center point inbank

• Failures on both sides of tap pointcancel out

• Reduces sensitivity

January 20 – 23, 2009

Capacitor Bank Failed Elements, cont’d

• 70 Series has impedance measurements

• Use impedance measurement to detect failure

• Use measurements when new to establish base impedance

• When can fails, impedance change indicates can failure

Bus

Z = V/I

January 20 – 23, 2009

Capacitor Bank Failed Can Example

January 20 – 23, 2009

Capacitor Bank Failed Can Example, cont’d

January 20 – 23, 2009

Capacitor Bank Controller not Following Schedule

• Cap bank should only auto close during peak hours

• Verification• Cap amps in the 70 Series trend record• Status of cap bank CB for remote (supervisory) monitoring and

in records

Cap bankamps

Cap in autoschedule

70 Trend

In

amps

Time

Time

Cap Bank 1

Cap Bank 2

Customers

Cap BankController

Add and removecapacitors according to

voltage levels

Schedule during peakhours

Automode

Out

Cap should not beon here

January 20 – 23, 2009

Example 2

Voltage Flicker

January 20 – 23, 2009

Voltage Flicker

January 20 – 23, 2009

Voltage Flicker, cont’d

• Voltage flicker

• Repetitive voltage dip on a power system

• Objectionable?

• When the magnitude and frequency of occurrence becomeexcessive as perceived by a person

• Subjective, depends on individual

January 20 – 23, 2009

Measuring flicker

• Flicker curve used by North American Utilities

• Called GE curve

January 20 – 23, 2009

Voltage Flicker Standards

• IEEE P1453/D9, June 2004

• Attempts to measure and deal with flicker has resulted in this Standard beingadopted

• IEC 61000-4-15 was adopted and approved for use in IEEE Recommended Practice1453

• Don’t use previous curves as per IEEE P1453 D9

January 20 – 23, 2009

Voltage flicker standards, cont’d

• IEEE P1453 D9 recommends table A-1 in standard• Uses IEC 61000-4-15 to calculate irritation curve

• Shown on graph below

January 20 – 23, 2009

Voltage Flicker Standards, cont’d

• Two statistical quantities have been defined to measure flicker

• Pst and Plt

• Pst – Perception short term

• A measure of the short term perception obtained for one 10-minute interval

• Calculation details in standard

• Use individual sources with a short duty cycle

• Plt – Perception long term

• A measure of long-term perception of flicker obtained for a 2-hour period.

• Calculated from the average of consecutive Pst values

• Use for sources with long & variable duty cycle and multiple sources

• Refer to IEEE P1453/D9, June 2004

January 20 – 23, 2009

Perception values for irritation

Pst = 1.00 per unit

Pst >= 1.00 per unit

Plt >= 1.00 per unit

A problem exists when

January 20 – 23, 2009

Voltage Flicker - Causes

• Processes that draw large repetitive currents

• Large motor loads• Motors from 100 hp to 1000 hp and larger• Frequent starts or operation near stall• Types of loads

• Rock crushers• Recycling plants• Ski resorts

• Welding operations

• Others

January 20 – 23, 2009

Voltage Flicker – Contributing factors

• Dependent on where the flicker producing load occurs in the power system

Generation &Transmission

Sub-Transmission

Distribution

Vs

Equivalent Circuit

January 20 – 23, 2009

Voltage Flicker – Contributing factors, cont’d

• Equivalent circuit

1. Change in voltage from process

Total system impedance Zsystem

Magnitude of inrush current I

= Vs – V = Vs – ( I * Zsystem)V

Proportional toV

Is seen by Customers on supply line to processV

VsV

Other Customers

Customer with flicker

producing process

I

2.

3.

January 20 – 23, 2009

Voltage Flicker – Improvements

• Monitoring and recording IED such as Bitronics 70 series has features todetect and measure voltage flicker

• Measurements in the 70 Series

• Voltage and current

• Voltage flicker measurements

• Based on the standard

• Pst

• Plt

January 20 – 23, 2009

Voltage Flicker – Improvements

• Use the measurements

• In Trend recorder for continuous monitoring

• To trigger Disturbance and Waveform records (more detailed analysis)

• In user configurable Supervisory points lists

• To cross trigger other IEDs

January 20 – 23, 2009

Trend record example to detect condition

Item 1

Item 2

January 20 – 23, 2009

Trend record example to detect condition

Avg PST VAN2 = 3.642

Avg PST VBN2 = 0.289

Avg PST VCN2 = 0.371

Avg PLT VAN2 = 0.000

Avg PLT VBN2 = 0.000

Avg PLT VCN2 = 0.000

January 20 – 23, 2009

Example 3

Harmonic Distortion

January 20 – 23, 2009

Basic Concepts

• Loads on an ac system

• Linear

• Non-linear

• Linear load

• Current is proportional to the voltage and impedance

• Current follows envelope of the voltage waveform

• Examples

• Resistive heaters

• Incandescent lamps V

I

January 20 – 23, 2009

Basic Concepts, cont’d

• Non-Linear load

• Current is not with the voltage during each half cycle

• Current and voltage have non-sinusoidal waveforms

• Non-linear load examples

• Variable Frequency Drives

• Switching mode power supplies

• Battery Chargers

• Electronic ballasts

• Induction furnacesV

I

January 20 – 23, 2009

Harmonics - Effect on Transformers

• Increased losses in the iron core

• Eddy losses and hysteresis

• Proportional to I2 and f2

• Results in excessive heating

• Results of excessive heating

• Transformer failure

• Requires transformer with a higher rating

• More costly

• Requires De-rating existing transformers

• Next example, transformer k-factor for transformer de-rating is discussed

January 20 – 23, 2009

Harmonics – Effect on Motors

• Increased losses in the iron core• Eddy losses and hysteresis• Proportional to I2 and f2

• Results in excessive heating

• Torsional oscillation on the motor shaft• Excessive vibration• Vibration near natural frequency of the motor can damage motor

January 20 – 23, 2009

Harmonics – Effect on Capacitors

• Typically designed to operate at 110% of rated voltage and 135%of their KVAR ratings.

• Capacitive reactance is inversely proportional to frequency

• They act as a sink to harmonics on the power system

• Results in overloading the capacitor bank

• Greater chance of exceeding design values causing failure

January 20 – 23, 2009

Harmonics – Effect on system

Industrial customerinjecting harmonics

Generation/Transmission

systems

Residentialcustomers

• Harmonic effects seen by all customers on line

• How many devices can be adversely affected?

• Symptom – increasing equipment failures for no apparent reason –harmonics?????

Commercial landother industrials

DistributionCap Banks

How many motorsand transformers?

How many?

January 20 – 23, 2009

Harmonic Distortion - Definitions

• Refer to Guide for Applying Harmonic Limits on Power Systems,P519A/D6, January, 1999

Where:

magnitude of individual harmonic

components (rms volts)

h = harmonic order

nominal system rms voltage

(rms volts)

Vh =

Vn =

magnitude of individual harmonic

components (rms amps)

h = harmonic order

maximum demand load current (rms

amps)

Ih =

IL =

Voltage Distortion Defined Total Demand Distortion Defined

January 20 – 23, 2009

Responsibilities

• The Guide for Applying Harmonic Limits

• Specifies responsibilities for utilities and utility customers regarding harmonics

• Utility customers

• Focus on load, use TDD

• Recommended TDD limits are provided

• Utilities

• Focus on voltage, use THD

• The THD should be less than 5%

January 20 – 23, 2009

Harmonics – Improvements

• Monitoring and recording IED such as Bitronics 70 series has features tomonitor harmonics

• Measurements

• Voltage Distortion (THD)

• Also has even and odd THD

• Current distortion (THD and TDD)

• Also has even and odd THD and TDD

• All harmonic RMS voltages from 0 to 63rd

• All harmonic RMS currents from 0 to 63rd

• Phase angles for all of the above

January 20 – 23, 2009

THD Measurements in the 70 Series

• The following compares the THD calculations in the 70 series compared to theguide.

IEEE Guide 70 Series

January 20 – 23, 2009

THD Measurements in the 70 Series

• The following compares the THD calculations in the 70 series compared to theguide.

70 Series

January 20 – 23, 2009

TDD Measurements in the 70 Series

• The following compares the TDD calculations in the 70 series compared to theguide.

IEEE Guide 70 Series

January 20 – 23, 2009

Harmonics – Using the 70 Series Measurements

• In Trend recorder for continuous monitoring

• To trigger Disturbance and Waveform records (more detailed analysis)

• In user configurable Supervisory points lists

• To cross trigger other IEDs

January 20 – 23, 2009

Trend record example to detect condition

January 20 – 23, 2009

Trend record example to detect condition, line graph

January 20 – 23, 2009

Trend record example to detect condition, circular graph

January 20 – 23, 2009

Waveform record example to zero in on condition

January 20 – 23, 2009

Example 4

Transformer k-Factor

January 20 – 23, 2009

Effect of harmonics on transformer operation

• Transformers subjected to harmonics• Experience increased losses due to harmonics• Result in additional heating as compared to 60Hz rating

• Consequence of heating due to harmonics• Transformer must be de-rated• Or, higher rated transformer must be installed

• Covered in detail ANSI/IEE standards• C57.110-1986• IEEE recommended practice for establishing transformer capability when supplying

non-sinusoidal load currents

January 20 – 23, 2009

fh2

x PEC-R (pu)

Heating effect of Harmonics

• From ANSI/IEEE Standard C57.110-1986

Imax (pu) =PLL-R (pu)

Imax (pu) = maximum permissible rms non-sinusoidal load current (pu)

Where

PLL-R (pu) = load loss density under rated conditions

PEC-R (pu) = winding eddy current loss under rated conditions

1 +fh

2 * h2

fh = harmonic current distribution factor for harmonic h

h = harmonic number

(pu) = per unit of rated rms load current

January 20 – 23, 2009

Application

• Monitoring and recording IEDs such as 70 series have capability tomeasure effects

• 70 series details• Measures k-factor• The k-factor is defined as follows

Where h = harmonic number (1 through 63)

Ih = magnitude of the hth harmonic (1st through 63rd)

January 20 – 23, 2009

Comparing 70 series calculation with standard

fh2

x PEC-R (pu)

Imax (pu) =PLL-R (pu)

1 +fh

2 * h2

January 20 – 23, 2009

• No total or 3 phase k-factor

• Measured for each of the three phases of current and the neutral

• K – factor Amps A

• K – factor Amps B

• K – factor Amps C

• K – factor Amps N

• K-factor is a ratio of amps/amps on a per phase basis

• It does not indicate actual load

• k-factor is harmonic dependent and not load dependent

Notes on the k-Factor in the 70 Series

January 20 – 23, 2009

Accessing k-factor from the 70 Series Recorders

• Waveform record for transformer inrush shown below

January 20 – 23, 2009

Accessing k-factor from the 70 Series Recorders, cont’d

• Graph of harmonics for transformer inrush• A phase current shown

January 20 – 23, 2009

Accessing k-factor from the 70 Series Recorders, cont’d

• Disturbance Record with k-factor A phase

Avg k-factor Amps A1 = 485%

Avg k-factor Amps B1 = 1434%

Avg k-factor Amps C1 = 988%

Avg RMS Amps A1

Avg RMS Amps B1

Avg RMS Amps C1

January 20 – 23, 2009

Accessing k-factor from the 70 Series Recorders, cont’d

• Disturbance Record with k-factor A phase

Avg k-factor Amps A1 = 4.85

Avg k-factor Amps B1 = 14.34

Avg k-factor Amps C1 = 9.88

Avg RMS Amps A1

Avg RMS Amps B1

Avg RMS Amps C1

In decimal format ( % / 100)

January 20 – 23, 2009

Accessing k-factor from the 70 Series Protocols

• Measurement available in DNP, Modbus, IEC61850

• Read from Supervisory or control system

• DNP mapping shown

January 20 – 23, 2009

Example 5

Reduce cost of doing business

January 20 – 23, 2009

Typical Power System

CustomerLoad

Generation BillingMeter

January 20 – 23, 2009

System Losses

• Power delivered to customer is less than that generated

Customer

Load

Generation

Power In Power Out

Billing

Meter

I2* R losses

Power In = Power Out + I2 * R Losses

January 20 – 23, 2009

Cost of doing business

• Total cost to generate power cannot be recovered

Customer

Load

Generation

Power In Power Out

Billing

Meter

I2* R losses

Power In = Power Out + I2 * R Losses

$$ generated power = $$ Power to customer + $$ I2 * R losses

Cost of doing businessRecoverable

January 20 – 23, 2009

Lagging power factor loads increase I2R Losses

• For a fixed kW demand,• line current is proportional to lagging power factor

• Line losses increase with lagging power factor• Losses vary exponentially as I2

• Cost that cannot be recovered

Customer

Load

Generation

Power In Power Out

Billing

Meter

I2* R losses

Power In = Power Out + I2 * R Losses

January 20 – 23, 2009

Example, Loads with varying power factor

CustomerLoad

GenerationT&D System

10MVA transformer & 1 mile12kv conductor

Losses for Powerfactor = 1.00

Losses for Powerfactor = 0.900 lagging

2500kW Load $5,000 / year $22,000 / year

5000kW Load $27,000 / year $106,000 / year

Assumed energy cost = $0.10 / kWHr

Addedcost

$17,000 / year

$79,000 / year

January 20 – 23, 2009

Reactive support for lagging loads

• Power lines with large amounts of lagging power factor load increasecosts

• Doubling the kW load for a given power factor increases costsdramatically

• I2 * R losses vary as square of current flow• Cost of losses proportional to I2

• Reduce losses by improving power factor

• May take one of two forms• Utility provides cap banks• Large customers required to meet minimum power factor requirements

January 20 – 23, 2009

Improvements with Monitoring and Recording IEDs

• Monitoring and recording IEDs such as the 70 series

• Allow monitoring of power factor and kVAR flows

• Establish a base line for a proper operating system

• Provide indication that something is wrong via remote (Supervisory)monitoring and local metering

• Failure of utility cap banks

• Indicate a customer has added substantial lagging power factor load

• Indicate a customer’s VAR compensation has failed

January 20 – 23, 2009

Conclusions

January 20 – 23, 2009

Conclusions

• Electromechanical relay schemes

• Provide adequate protection

• Lacks remote monitoring and control features required and desired

• Improving power quality monitoring can be provided by Bitronics 70

Series monitoring and recording IED

• Allows retention of the Electromechanical relays

• Helps to identify problems

• Allows monitoring effectiveness of the solution

• Reduce customer complaints

• Reduce PUC reviews and fines

• Reduce operating costs

January 20 – 23, 2009

Don’t forget

• This presentation focuses on using the 70 series to improve powerquality monitoring

• This is only part of the automation picture

• In addition, you get• Fault recording and monitoring• Improved local monitoring and control• Improved remote monitoring and control

January 20 – 23, 2009

Where do I find these Webinar Presentations

• They are available on the NovaTech web site.

January 20 – 23, 2009

Part Four of Four

Using the Bitronics 70 Series

to Improve Power Quality Monitoring

The End