concurrent lectures part 1

7/29/2019 Concurrent Lectures Part 1

http://slidepdf.com/reader/full/concurrent-lectures-part-1 1/254

Calculating Constant Source Fault Values

by Jason Buneo, Megger



Outline

• Introduction• Power System Model

• A-B-C Fault

• A-B Fault

• A-G Fault



Introduction

• Expectations – Mho Characteristic

– Symmetrical Components

– Lots of Trigonometry

– Examples



Power System Model

21

Single Source Power System Model

Zone 1 Protection



How Do You Calculate Constant

Source Values?

Simple Way:•Determine your source impedance…or guess.

•Choose your test angle.

•Calculate your test impedance at the test angle.

•Calculate the test quantities for voltage and current.

Weak System Strong System



A-B-C FaultSystem Parameters:

Positive Sequence Line Impedance: ZL = 5 Ω

Positive Sequence Line Angle: ZLAng = 80°

Zone 1 Reach: Z Lmag = 1.74

Nominal Voltage: V n = 63 .5V

Nominal Voltage Angle: V nAng = 0

Source Impedance: 20% of Line Impedance Z S = 1 Ω

Source Angle: Z SAng = 80°



Zs1 ZL1

VR1 VF1

Zs2 = Zs1

VR2 VF2

IR1

IR2

Zs0

VR0 VF0

IR0

ZL0

ZL2 = ZL1

Negative

and Zero

Sequence

Networks

are notused for

ABC

Faults.

Positive

Sequence

NetworkVs

A-B-C Fault



A-B-C Fault: Calculate Test Impedance

ImImIm

ReReRe

Im

Re

Im

Re

)sin(*

)cos(*

)sin(*

)cos(*

sL

alsalLal

sAngsMags

sAngsMagals

LAngLMagL

LAngLMagalL

ZZRadius

ZZRadius

ZZZ

ZZZ

ZZZ

ZZZ

+=

+=

=

=

=

=

2

2

tan

2

ImIm

ReRe

Re

Im1

ImImIm

ReReRe

2

Im

2

Re

sL Y

alsalLX

alAng

Ang

Angle

sLAng

alsalLalAng

al

Mag

ZZC

ZZC

Comp

CompComp

ZZComp

ZZComp

RadiusRadiusRadius

+=

+=

=

+=

+=

+=

−




ImImIm

ReReRe

Im

Re

Im

Re

)sin(*

)cos(*

)sin(*

)cos(*

sL

alsalLal

sAngsMags

sAngsMagals

LAngLMagL

LAngLMagalL

ZZRadius

ZZRadius

ZZZ

ZZZ

ZZZ

ZZZ

+=

+=

=

=

=

=

2

2

tan

2

ImIm

ReRe

Re

Im1

ImImIm

ReReRe

2

Im

2

Re

sL Y

alsalLX

alAng

Ang

Angle

sLAng

alsalLalAng

al

Mag

ZZC

ZZC

Comp

CompComp

ZZComp

ZZComp

RadiusRadiusRadius

+=

+=

=

+=

+=

+=

−

6983.29848.07135.1

4757.01736.03021.0

9848.0)80sin(*1

1736.0)80cos(*1

7135.1)80sin(*74.1

3021.0)80cos(*74.1

Im

Re

Im

Re

Im

Re

=+=

=+=

==

==

==

==

Radius

Radius

Z

Z

Z

Z

al

s

als

L

alL

3643.02

)9848.0(7135.1

06425.02

)1736.0(3021.0

00.804757.0

6983.2tan

3699.12

6983.24757.0

1

22

=−+

=

=−+=

==

=+=

−

Y

X

Angle

Mag

C

C

Comp

Radius




)cos(*)cos(* AngleCompRadius TestAngleRadiusX += )sin(*)sin(* AngleCompRadius TestAngleRadius Y +=

3021.0)80cos(*3699.1)80cos(*3699.1 =+=X7135.1)80sin(*3699.1)80sin(*3699.1 =+= Y

Ω=+=+= 7399.17135.13021.02222 YXZ Tot

°−−

=== 00.803021.0

7135.1

tantan

11

X

Y

ZAng



A-B-C Fault: Calculate Test QuantitiesNow that we have the Impedance Ztot, where do we go from here?

Calculating Current and Voltage Values

Positive Sequence Values Only

[ ][ ]α α

21

relay

c

b

a

VVV

V

=

⎥⎥

⎥

⎦

⎤

⎢⎢

⎢

⎣

⎡

[ ][ ]α α

2

11

a

c

b

a

III

I

=

⎥⎥

⎥

⎦

⎤

⎢⎢

⎢

⎣

⎡



Test Current Ia

°

°−−

−=−=−=

===

===

=+=+=

=+=+=

=+=+=

80800

17.237399.2

5.63

00.804757.0

6983.2tantan

7399.26983.24757.0

6983.29848.07135.1

4757.01736.03021.0

1

1

1

Re

Im1

222

Im

2

Re

ImImIm

ReReRe

ExpandAngnAngAnga

ExpandMag

nMag

Maga

alExpand

Expand

ExpandAng

ExpandalExpandExpandMag

sLineExpand

alsalLinealExpand

ZVI

A

Z

VI

Z

ZZ

ZZZ

ZZZ

ZZZ



Test Current Ib

°−− −=−

==

=+−=+=

===

−===

=−+=+=

===

=

2077.21

9246.7tantan

17.239246.777.21

9246.7)160sin(*17.23)sin(*

77.21)160cos(*17.23)cos(*

160)80(120*2*217.2317.23*1*

1

Re

Im1

222

Im

2

Re

Im

Re

1

2

1

2

1

2

albPos

bPosbAng

bPosalbPosbMag

bPosAngbPosMagbPos

bPosAngbPosMagalbPos

AngaAngbPosAng

MagaMagbPosMag

abMag

III

AIII

III

III

IIII

II

α

α

α



Test Current Ic

°−− ===

=+=+=

===

===

=−+=+=

===

=

407492.178933.14tantan

17.238933.147492.17

8933.14)40sin(*17.23)sin(*

7492.17)40cos(*17.23)cos(*

40)80(120

17.2317.23*1*

1

Re

Im1

222

Im

2

Re

Im

Re

1

1

1

alcPos

cPoscAng

cPosalcPoscMag

cPosAngcPosMagcPos

cPosAngcPosMagalcPos

AngaAngcPosAng

MagaMagcPosMag

acMag

III

AIII

III

III

II

II

II

α

α

α



Test Voltage Va

°−− ===

=+=+==−=−=

=−=−=

======

=+−=+=

===

===

===

−=

033.40

0tantan

33.40033.40

000

33.4017.235.63

0)0sin(*17.23)sin(*17.23)0cos(*17.23)cos(*

08080

17.231*17.23*0)0sin(*5.63)sin(*

5.63)0cos(*5.63)cos(*

*****)*(*****

1

ReRe

ImRe1

Re

222

ImRe

2

ReReRe

ImReImImRe

ReReReReRe

ReReImRe

ReReReRe

1Re

1Re

Im

Re

1Re

allay

lay

layAng

layallaylayMag

layPosnlay

allayPosalnallay

layPosAnglayPosMaglayPos

layPosAnglayPosMagallayPos

sAngAngalayPosAng

sMagMagalayPosMag

nAngnn

nAngnaln

sanlay

V

VV

VVVV

VVV

VVV

VVVVVV

ZIV

ZIVVVV

VVV

ZIVV



Test Voltage Vb

°−− =

−

−==

=−+−=+=−===

−===

=+=+====

=

60

165.20

92.34tantan

32.40)92.34(165.20

92.34)240sin(*33.40)sin(*

165.20)240cos(*33.40)cos(*

2400)120*2()*2(33.4033.40*1*

***********

1

Re

Im1

222

Im

2

Re

Im

Re

Re

2

Re

2

Re

2

albPos

bPosbAng

bPosalbPosbMag

bPosAngbPosMagbPos


layAngbPosAng

layMagbPosMag

layb

V

VV

VVVV

VVV

VVV

VVVV

VV

α

α

α



Test Voltage Vc

°−− −=

−

==

=+−=+====

−===

=+=+====

=

60

165.20

92.34tantan

32.40)92.34(165.20

92.34)120sin(*33.40)sin(*

165.20)120cos(*33.40)cos(*

120012033.4033.40*1*

***********

1

Re

Im1

222

Im

2

Re

Im

Re

Re

Re

Re

alcPos

cPoscAng

cPosalcPoscMag

cPosAngcPosMagcPos


layAngcPosAng

layMagcPosMag

layc

V

VV

VVVV

VVV

VVV

VVVV

VV

α

α

α



A-B-C Fault Test Quantities

The angles need one last adjustment. Remember:

If IReal or VReal > 0 and IIm or VIm >0 then the angle is tan-1 Imaginary/Real

If IReal or VReal < 0 and IIm or VIm > 0 then you need to add 180 to the angle.

If IReal or VReal < 0 and IIm or VIm < 0 then you need to add 180 to the angle.If IReal or VReal > 0 and IIm or VIm < 0 then you need to add 360 to the angle.

This correction will keep your values in the correct quadrant.

Ia Ib Ic Va Vb Vc

Magnitude 23.17A 23.17A 23.17A 40.33V 40.32V 40.32V

Angle‐80°

‐20° 40° 0° 60°

‐60°

Ia Ib Ic Va Vb Vc

Magnitude 23.17A 23.17A 23.17A 40.33V 40.32V 40.32V

Angle ‐80° ‐160° 40° 0° 60° ‐60°



Zs1

ZL1

VR1 VF1

Zs2 = Zs1

VR2 VF2

IR1

IR2

Zs0

VR0 VF0

IR0

ZL0

ZL2 = ZL1

Zero Sequence

Networks are not

used for AB Faults.

Positive andNegative

Sequence

Network

Vs

A-B Fault



A-B Fault: Calculate Test Impedance

Ω=+=+= 7399.17135.13021.02222 YXZ Tot

°−− === 00.80

3021.0

7135.1tantan 11

X

YZAng

Impedance is the same as an A-B-C Fault.



A-B Fault: Calculate Test Quantities

[ ] ⎥⎦

⎤

⎢⎣

⎡=

⎥⎥

⎥

⎦

⎤

⎢⎢

⎢

⎣

⎡

2

2

1 1

1

α α

α α

a

c

b

a

I

I

I

I

Positive and Negative Sequence Components

[ ] ⎥⎦

⎤⎢⎣

⎡=

⎥⎥⎥

⎦

⎤

⎢⎢⎢

⎣

⎡2

2

Re1

1

α α

α α

lay

c

b

a

V

V

VV



Test Current Ia

8660.0)120sin(*1)sin(*5.0)120cos(*1)cos(*

9848.0)80sin(*1)sin(*

1736.0)80cos(*1)cos(*

7135.1)80sin(*74.1)sin(*

302.0)80cos(*74.1)cos(*

55)120sin(*5.63)sin(*

75.31)120cos(*5.63)cos(*

Im

Re

Im

Re

Im

Re

Im

Re

===−===

===

===

===

===

===

−===

AngMag

AngMagal

sAngsMags

sAngsMagals

LineAngLineMagLine

LineAngLineMagalLine

nAngnMagLine

nAngnMagalLine

ZZZ

ZZZ

ZZZ

ZZZ

VVV

VVV

α α α

α α α



Test Current Ia

( ) ( )

( ) ( )

22018040180

52.11

4080120

52.114798.5

5.63

00.809514.0

3966.5tantan

4798.53966.59514.0

3966.59848.07135.1*2*2

9514.01736.03021.0*2*2

12

12

1

1

1

Re

Im1

222Im

2Re

ImImIm

ReReRe

=+=+=

==

=−=−=

===

===

=+=+=

=+=+=

=+=+=

−−

AngaAnga

MagaMaga

ExpandAngnAngAnga

ExpandMag

nMag

Maga

alExpand

Expand

ExpandAng

ExpandalExpandExpandMag

sLineExpand

alsalLinealExpand

II

IIZVI

Z

VI

Z

ZZ

ZZZ

ZZZ

ZZZ



Test Current Ia

°−− −=−

==

=−+=+=

−=−+−=+=

=+=+=

−===

===

−===

===

=+=+=

===

=+=+=

===

+=

5082.12

28.15tantan

94.19)28.15(82.12

28.15)94.3(34.11

82.1282.102

94.3)340sin(*52.11)sin(*

82.10)340cos(*52.11)cos(*

34.11)280cos(*52.11)sin(*

2)280cos(*52.11)cos(*

340220120

52.1152.11*1*

28040)120*2(*2

52.1152.11*1*

**********

1

Re

Im1

222

Im

2

Re

ImImIm

ReReRe

Im

Re

Im

Re

2

2

1

2

1

2

21

2

ala

aaAng

aalaaMag

aNegaPosa

alaNegalaPosala

aNegAngaNegMagaNeg

aNegAngaNegMagalaNeg

aPosAngaPosMagaPos

aPosAngaPosMagalaPos

AngaAngaNegAng

MagaaNegMag

AngaAngaPosAng

MagaMagaPosMag

aaa

I

II

AIII

III

III

III

III

III

III

II

II

II

II

III

α

α

α

α

α α



Test Current Ib

°−− −=

−

==

=+−=+=

=+=+=

−=−+−=+=

===

−===

===

−===

=+=+====

=+=+=

===

+=

50

82.12

28.15tantan

94.1928.1582.12

28.1534.1194.3

82.12)2(82.10

34.11)460sin(*52.11)sin(*

2)460cos(*52.11)cos(*94.3)160sin(*52.11)sin(*

82.10)160cos(*52.11)cos(*

460220120*2*2

52.1152.11*1*

16040120

52.1152.11*1*

**********

1

Re

Im1

222

Im

2

Re

ImImIm

ReReRe

Im

Re

Im

Re

2

22

2

1

1

2

2

1

alb

bbAng

balbbMag

bNegbPosb

albNegalbPosalb

bNegAngbNegMagbNeg

bNegAngbNegMagalbNeg

bPosAngbPosMagbPos


AngaAngbNegAng

MagaMagbNegMag

AngaAngbPosAng

MagaMagbPosMag

aab

I

II

AIII

III

III

III

IIIIII

III

II

II

II

II

III

α

α

α

α

α α



Test Current Ic

0

0

=

=

cAng

cMag

I

I



Test Voltage Va

03.6096.25

03.45tantan

97.5103.4596.25

03.4597.955

96.25)79.5(75.3197.9)120sin(*52.11)sin(*

76.5)120cos(*52.11)cos(*

1208040

52.111*52.11*

*****)*(*****

1

ReRe

ImRe1

222

ImRe

2

ReRe

ImReImIm

ReReReRe

ReReImRe

ReReReRe

1Re

1Re

1Re

−=−

==

=+−=+=

=−=−=

−=−−−=−=

===

−===

=+=+=

===

−=

−−

allay

lay

PosAng

layallayPosMag

layPosnPos

allayPosalnalPos



sAngAngalayPosAng

sMagMagalayPosMag

sanlayPos

V

VV

VVV

VVV

VVVVVV

VVV

ZIVZIV

ZIVV



Test Voltage Va

97.9)480sin(*52.11)sin(*

76.5)480cos(*52.11)cos(*

48080180220180

52.111*52.11*

***********

ReReIm

ReReRe

2

2

1Re

===

−===

=++=++=

===

−=

layNegAnglayNegMagNeg

layNegAnglayNegMagalNeg

sAngAngaNegAng

sMagMagaNegMag

salayNeg

VVV

VVV

ZIV

ZIV

ZIV



Test Voltage Va

°−− −=−

==

=−+=+=

−=−+=+=

=−+=+=

−===

−======

===

=+=+=

===

=++=

===

+=

17.1221.46

97.9tantan

27.47)97.9(21.46

97.9)97.9(0

21.46)76.5(97.51

97.9)600sin(*52.11)sin(*

76.5)600cos(*52.11)cos(*0)360sin(*97.51)sin(*

97.51)360cos(*97.51)cos(*

600480120

52.1152.11*1*

360120240*2

97.5197.51*1*

**********

1

Im

Re1

222

Im

2

Re

ImImIm

ReReRe

Im

Re

Im

Re

22

ReRe

2

a

ala

aAng

aalaaMag

aNegaPosa

alaNegalaPosala

aNegAngaNegMagaNeg

aNegAngaNegMagalaNeg

aPosAngaPosMagaPos

aPosAngaPosMagalaPos

NegAngAngaNegAng

NegMagMagaNegMag

PosAngAngaPosAng

PosMagMagaPosMag

layNeglayPosa

V

VV

VVVV

VVV

VVV

VVV

VVVVVV

VVV

VV

VV

VV

VV

VVV

α

α

α

α

α α



Test Voltage Vb

°−− =

−

−==

=−+−=+=

−=+−=+=

−=+−=+=

===

===

−===

−===

=+=+====

=+=+=

===

+=

18.72

465.14

45tantan

26.47)00.45(465.14

00.45000.45

465.1452.11985.25

0)720sin(*52.11)sin(*

52.11)720cos(*52.11)cos(*

00.45)240sin(*97.51)sin(*

985.25)240cos(*97.51)cos(*

720480120*2*2

52.1152.11*1*

240120120

97.5197.51*1*

***********

1

Re

Im1

222

Im

2

Re

ImImIm

ReReRe

Im

Re

Im

Re

Re

Re

Re

Re

Re

2

Re

alb

bbAng

balbbMag

bNegbPosb

albNegalbPosalb

bNegAngbNegMagbNeg


bPosAngbPosMagbPos


layAngbNegAng

layNegbNegMag

layAngbPosAng

layPosbPosMag

layNeglayPosb

V

VV

VVVV

VVV

VVV

VVV

VVVVVV

VVV

VV

VV

VV

VV

VVV

α

α

α

α

α α



Test Voltage Vc

°−−

−=−==

=+−=+=

=+=+=

−=−+−=+=

+=

02.6072.31

55

tantan

49.635572.31

5597.903.45

72.31)76.5(96.25

**********

1

Re

Im1

222

Im

2

Re

ImImIm

ReReRe

ReRe

alc

c

cAng

calccMag

NegPosc

alNegalPosalc

layNeglayPosc

V

V

V

VVVV

VVV

VVV

VVV



A-B Fault Test Quantities


If IReal or VReal > 0 and IIm or VIm >0 then the angle is tan-1 Imaginary/Real

If IReal or VReal < 0 and IIm or VIm > 0 then you need to add 180 to the angle.

If IReal or VReal < 0 and IIm or VIm < 0 then you need to add 180 to the angle.If IReal or VReal > 0 and IIm or VIm < 0 then you need to add 360 to the angle.

This correction will keep your values in the correct quadrant.

Ia Ib Ic Va Vb Vc

Magnitude 19.94A 19.94A 0A 47.27V 47.26V 63.49V

Angle‐50°

‐50° 0°

‐12.17° 72.19°

‐60.02°

Ia Ib Ic Va Vb Vc

Magnitude 19.94A 19.94A 0A 47.27V 47.26V 63.49V

Angle 310 30 0° 347.83 252.19 119.98



A-G FaultSystem Parameters:

Positive Sequence Line Impedance: ZL = 5 Ω

Positive Sequence Line Angle: ZLAng = 80°

Zone 1 Reach: Z Lmag = 1.74Nominal Voltage: V n = 63 .5V

Nominal Voltage Angle: V nAng = 0

Source Impedance: 20% of Line Impedance Z S = 1 Ω

Source Angle: Z SAng = 80°

Zero Sequence Magnitude Compensation: K 0M = 0.991

Zero Sequence Angle Compensation: K 0 = -8.56



Zs1 ZL1

VR1 VF1

Zs2 = Zs1

VR2 VF2

IR1

IR2

Zs0

VR0 VF0

IR0

ZL0

ZL2 = ZL1

Positive,

Negative,

and Zero

Sequence

Networks

Vs

A-G Fault



A-G Fault: Calculate Test ImpedanceThe k0 factor is now

introduced. This is the

compensation due to the extra

ground impedance seen bythe relay.



A-G Fault: Calculate Test Impedance

LAngNewsAng

LinesMag

AngLAngLAngNew

MagLineNew

AM

AMAng

AMAMMag

ZZZZ

ZeroCompZZ

ZeroCompZZ

kk

kkZeroComp

kkkkZeroComp

==

+==

+=

++=

−

*2.0

*

))cos(*(1

)sin(*tan

))sin(())cos(1(

00

001

2

00

2

00




°

−

=

Ω=

=−+=

==

−=−+

−=

=−+−+=

8278.60

1

8278.60)1722.19(80

4452.398.1*74.1

1722.19))56.8cos(*991.0(1

)56.8sin(*991.0tan

98.1))56.8sin(*991.0()))56.8cos(*991.0(1(

1

22

sAng

sMag

LAngNew

New

Ang

Mag

Z

ZZ

Z

ZeroComp

ZeroComp




al

Ang

al

Mag

News

alNewalsal

LAngNewNewNew

LAngNewNewalNew

sAngsMags

sAngsMagals

Radius

RadiusComp

RadiusRadiusRadius

ZZRadius

ZZRadius

ZZZ

ZZZ

ZZZ

ZZZ

Re

Im1

2

Im

2

Re

ImImIm

ReReRe

Im

Re

Im

Re

tan

2

)sin(*

)cos(*

)sin(*

)cos(*

−=

+=

+=

+=

=

=

=

=




X YZ

YXZ

CompAngleRadius TestAngleRadius Y

CompAngleRadius TestAngleRadiusX

Ang

Tot

MagMag

MagMag

1

22

tan

)sin(*)sin(*

)cos(*)cos(*

−=

+=

+=

+=

°− ==

Ω=+=

=+=

=+=

77.60167.2

8726.3tan

43.48726.3167.2

8726.3)77.60sin(*2189.2)77.60sin(*2189.2

167.2)77.60cos(*2189.2)77.60cos(*2189.2

1

22

Ang

Tot

Z

Z

Y

X



A-G Fault: Calculate Test Quantities

[ ]⎥⎥

⎥

⎦

⎤

⎢⎢

⎢

⎣

⎡

=

⎥⎥

⎥

⎦

⎤

⎢⎢

⎢

⎣

⎡

2

2

1

1

1

111

α α

α α a

c

b

a

I

I

I

I

Positive, Negative, and Zero Sequence Components

[ ]⎥⎥⎥

⎦

⎤

⎢⎢⎢

⎣

⎡

=

⎥⎥⎥

⎦

⎤

⎢⎢⎢

⎣

⎡

2

2

Re

1

1

111

α α

α α lay

c

b

a

V

V

V

V



Adjustments for k0

)sin(*

)cos(*

)sin(*

)cos(*

)sin(*

)cos(*

/

)sin(*

)cos(*

Im

Re

Im

Re

Im

Re

Im

Re

AngMag

AngMagal

sAngsMags

sAngsMagals

LineMagLine

LineMagalLine

Mag TotLineMag

LineAngnLine

LineAngnalLine

ZZZ

ZZZ

TestAngleZZ

TestAngleZZZeroCompZZ

VVV

VVV

α α α

α α α

=

=

=

=

=

==

=

=



More Adjustments for k0

al

Ang

alMag

AngMag

AngMagal

K

K K

K K K

kkK kkK

kK

Re

Im1

2

Im

2

Re

00Im

00Re

0

tan

)0sin(*1)sin(**3)0cos(*1)cos(**3

*****1)*3(*****

−=

+=

+=+=

+=



Final Adjustments for k0

AngAngtAng

MagMagtMag

al

Ang

alMag

al

Ang

alMag

AngMag

AngMagal

sL

alsalLal

sLinet

CompZZ

CompZZ

CompCompComp

CompCompComp

Z

ZZ

ZZZ

K K CompK K Comp

ZZZ

ZZZ

K ZZZ

+=

+=

=

+=

=

+=

+=+=

+=

+=++=

−

−

Re

Im1

2

Im

2

Re

Re

Im1

2

Im

2

Re

Im

Re

ImImIm

ReReRe

tan

tan

)sin(*)0sin(*2

)cos(*)0cos(*2

*****)2(*)(*****



Test Current Ia, Ib, and Ic

0

0

*3

**********

1

1

1

1

1

=

=

=

=

−=

=

=

c

b

AngaaAng

MagaaMag

tAngnAngAnga

thMag

nMag

Maga

th

na

I

I

II

II

ZVI

Z

VI

Z

VI



Test Voltage Va

allay

lay

layAng

layallaylayMag

layPosnlay

allayPosalnallay



sAngAngalayPosAng

sMagMagalayPosMag

nAngnn

nAngnaln

sanlayPos

V

VV

VVV

VVV

VVV

VVV

VVV

ZIV

ZIV

VVV

VVV

ZIVV

ReRe

ImRe1

Re

2

ImRe

2

ReReRe

ImReImImRe

ReReReReRe

ReReImRe

ReReReRe

1Re

1Re

Im

Re

1Re

tan

)sin(*

)cos(*

*

)sin(*

)cos(*

*****)*(*****

−=

+=

−=

−=

=

=

+=

=

=

=

−=



Test Voltage Va

)sin(*

)cos(*180

**

*****)*******

)sin(*

)cos(*

180

*

*****)******

ReReImRe

ReReReRe

1Re

1Re

1Re

ReReImRe

ReReReRe

1Re

1Re

1Re

layZeroAnglayZeroMaglayZero

layZeroAnglayZeroMagallayZero

AngsAngAngalayZeroAng

MagsMagMagalayZeroMag

salayZero

layNegAnglayNegMaglayNeg

layNegAnglayNegMagallayNeg

sAngAngalayNegAng

sMagMagalayNegMag

salayNeg

VVV

VVVK ZIV

K ZIV

K ZIV

VVV

VVV

ZIV

ZIV

ZIV

=

=

+++=

=

−=

=

=++=

=

−=



Test Voltage Va

ala

alayAng

aalaaMag

layZerolayNeglayPosa

allayZeroallayNegallayPosala

layZerolayNeglayPosa

V

VV

VVV

VVVVVVVV

VVVV

Re

Im1

Re

2

Im

2

Re

ImReImReImReIm

ReReReReReReRe

ReReRe

tan

**********

−=

+=

++=

++=

++=



Test Voltage Vb

alb

bbAng

balbbMag

layZerobNegbPosb

allayZeroalbNegalbPosalb

bNegAngbNegMagbNeg


bPosAngbPosMagbPos


layAngNegAngbNegAng

layMagNegMagbNegMag

layAngPosAngbPosAng

layMagPosMagbPosMag

layZerolayNeglayPosb

V

VV

VVV

VVVV

VVVV

VVV

VVVVVV

VVV

VV

VV

VV

VV

VVVV

Re

Im1

2

Im

2

Re

ImReImImIm

ReReReReRe

Im

Re

Im

Re

Re

Re

Re

Re

2

ReReRe

2

tan

)sin(*

)cos(*)sin(*

)cos(*

*

)*2(

*

**********

−=

+=

++=

++=

=

=

=

=

+=

=

+=

=

++=

α

α

α

α

α α



Test Voltage Vc

alc

ccAng

calccMag

layZerobNegbPosc

allayZeroalcNegalcPosalc

cNegAngcNegMagcNeg

cNegAngcNegMagalcNeg

cPosAngcPosMagcPos


layAngNegAngcNegAng

layMagNegMagcNegMag

layAngPosAngcPosAng

layMagPosMagcPosMag

layZerolayNeglayPosb

V

VV

VVV

VVVV

VVVV

VVV

VVVVVV

VVV

VV

VV

VV

VV

VVVV

Re

Im1

2

Im

2

Re

ImReImImIm

ReReReReRe

Im

Re

Im

Re

Re

Re2

Re

Re

ReRe

2

Re

tan

)sin(*

)cos(*)sin(*

)cos(*

)*2(

*

*

**********

−=

+=

++=

++=

=

=

=

=

+=

=

+=

=

++=

α

α

α

α

α α



A-G Fault Test Quantities


If IPosReal or VPosReal > 0 and IPosIm or VPosIm >0 then the angle is tan-1 Imaginary/Real

If IPosReal or VPosReal < 0 and IPosIm or VPosIm > 0 then you need to add 180 to the angle.

If IPosReal or VPosReal < 0 and IPosIm or VPosIm < 0 then you need to add 180 to the angle.

If IPosReal or VPosReal > 0 and IPosIm or VPosIm < 0 then you need to add 360 to the angle.

ANYTIME YOU SEE TAN-1 YOU NEED TO DO THESE CORRECTIONS!!!

Ia Ib Ic Va Vb Vc

Magnitude A A A V V V

Angle ° ° ° ° ° °

Ia Ib Ic Va Vb Vc

Magnitude A A A V V V

Angle ° ° ° ° ° °



Email me at:

[email protected]



End-to-End Testing

Chris Werstiuk, Manta Test Systems

End-to-End Testing



Chapter 1Introduction to End-to-End Testing

End-to-end testing is considered to be the ultimate test for protective relay protection schemes with

two or more relays who communicate trip and blocking information with each other. These schemesare designed to provide more accurate fault detection to more quickly isolate faults from the rest of

the electrical system. End-to-end testing can provide the most realistic fault simulations to prove relay

protection schemes before placing them into service and this test technique is becoming more and

more popular, especially as the National Electrical Reliability Council (NERC) and other regulatory

agency standards are becoming more stringent. One excerpt from the NERC requirements includes

the following text that almost requires end-to-end testing to be performed on every new installation

“At installation, the acceptance test should be performed on the complete relay scheme in addition to

each individual component so that the adequacy of the scheme is verified.”

This seminar will introduce the theory and practice of end-to-end relay testing from the relay tester’s

perspective. The following descriptions in this section will provide an overview of end-to-end testing

followed by detailed information for the most commonly applied protective schemes.

1. What is End-to-End Testing?End-to-End Testing uses two or more test-sets at multiple locations to simulate a fault at every

end of a transmission line simultaneously to evaluate the entire protective relay scheme as a

whole. This test technique used to require specialized knowledge and equipment to perform, butthe modern test-sets of today make it a relatively simple task. Review figure 1 for an overview of

the equipment and personnel required for a typical end-to-end test using a simple transmission

line with two ends or, as they’re sometimes called, nodes. It is possible to have a system with

three or more nodes which simply adds another location to the test plan.

End-to-End Testing



TS

TS

21

Z3

21

Z2

21

Z1

RLY-1

TX1

RX1

21

Z3

21

Z2

21

Z1

RLY-2

TX1

RX1

TS TS

TS

TS

GPS

ANTENNA

COMM

GPS

ANTENNA

TIME = 0:0:0TIME = 0:0:0

Figure 1: End-to-End Testing Summary

The following components are necessary for the relay tester to perform a successful end-to-end

test for an in-service application:

1. A relay test-set for each location with a minimum of:

¾ three voltage channels

¾ three current channels

¾ at least one programmable output to simulate breaker status or other external signals

¾ at least one programmable input to detect trip or breaker status signals

¾ An internal GPS clock (Some test-sets allow for other time signal synchronizations suchas IRIG) or an external GPS clock with output signal and an additional test-set start input.

¾ Waveform playback or fault state/state simulator with at least 3 states available.

2. Some test-sets require a computer to control the test-set playback or state functions

3. A computer and software to download and display event records obtained from the relay

after each test.

4. At least one relay tester at each location with some form of communication between the two

locations such as telephone or over-network communication. It is possible, but not

recommended, for one person to perform all tests if the relay, relay test-sets, andcommunication systems have all been configured properly.

5. A setting file, waveform, or detailed description of the specific test scenarios.

6. An understanding of the relay protection scheme and what the expected result for each test

should be.

End-to-End Testing

The relay testers at each end of the line perform the following steps when performing an end-to-



y p g p p g

end test:

1. Obtain test cases from the engineer and review them to find obvious errors and determine

what the expected results should be.2. Isolate the equipment under test

3. Connect appropriate input and output connections.

4. Connect test equipment to replace Current Transformer (CT)/Potential Transformer (PT)

connections.

5. Setup GPS antenna and apply GPS time as test-set reference. (Or use other reference such asIRIG, if required)

6. Communicate with remote testers and apply meter test on all sides and verify correct results.

7. Communicate with remote sides and determine which test plan will be used for test

8. Load test case into all test-sets9. Place all circuit breakers in the correct positions or ensure circuit breaker contacts are

properly simulated by the test-set.

10. Communicate start time with all sides and initiate test.

11. Review targets for correct operation and download all event records. Review event records

for correct operation, if required.

12. Repeat from step 7-11 for all test cases.

2. Why Do We Perform End-to-End Testing?The most effective transmission line protection using today’s technologies is achieved by

installing protective relays at each end of the line that constantly trade information about the

power system through a communication channel. Any disturbance is communicated to the other

relays which will cause the protection to operate more quickly depending on the protection

scheme used and the apparent location of the fault. These protection schemes, when applied

correctly, can make the transmission line protection more reliable and more selective than is

possible with a single relay or a series of relays that cannot communicate.

While it is possible to test each of the individual components separately, many problems canonly be detected when the entire scheme is tested as a whole. It is possible to test one side at a

time which can give the tester a reasonable sense that the scheme will operate successfully on a

proven relay settings, but many problems with communication-assisted protection occur when

the fault changes directions or by incorrectly defined communication delays which are inherent

in the system. These problems can only be detected by properly applied end-to-end testing or a

review of an incorrect relay operation after a fault.

End-to-end testing could be considered daunting a decade ago; but advances in relay testing

technology and personal computers have reduced the complexity to a couple of extra steps for areasonably experienced relay tester.

End-to-End Testing

3 How does it work?



3. How does it work?Most system disturbances occur within 1 millisecond and modern protective relays must be able

to detect faults within this time frame to be effective. Practical experience has shown that twotest-sets must start within 10 microseconds of each other to provide reliable results. This causes a

problem for multiple relay testers at multiple locations because it is nearly impossible for two

relay testers at two different locations to press start within 10 µs. One way to synchronize the

start time of two test-sets would be to connect some sort of dedicated communication means

such as a pilot wire (short distances only) or dedicated fiber-optic connection between the two

remote test-sets but this method requires forethought and additional costs to the installer. These

dedicated circuits could also become obsolete if the system configuration changes in the future

so this method is rarely available. The remote relay testers could use the power system itself to

synchronize the two test-sets but this method could add up to 1 ms or 22° error to the test whichis not within the 10 µs tolerance required for consistent results. It would be difficult to determine

whether the protective system operated because of a problem, or the difference between start

times.

End-to-end testing became a viable test technique for everyone when the U.S. Armed Forces

allowed non-military access to the time signals sent by a system of satellites which comprise the

Global Positioning System (GPS). This system operates by obtaining the time signal and general

location of at least four satellites and comparing the differences between time and distance to

determine the antenna’s location within a few meters. Time can be synchronized within 1 µs

anywhere that 4 satellites are available. Most modern test equipment can specify synchronization

within 2 µs which is within the maximum allowable time delay by a factor of 5.

Once two test-sets have synchronized time sources, at least two fault states are applied with

information from a fault simulator program. The first fault state provides a pre-fault conditionwhich would be the normal current, voltage, and phase angle for the transmission line under test.

After a pre-determined time, both test-sets would switch to the second state simultaneously

which simulates a fault. It is important to note that every side of the transmission line will havedifferent values depending on the location of the fault and the power sources around the

transmission line. It is vital that the correct fault simulations be applied to the correct relays.

These fault states could be combined into one file, typically COMTRADE (I.E.E.E. standard

IEEE C37.111 for waveform files), and played back into the relay or created using fault

information and manually entered into fault simulations. If the fault has been properly simulated

at all locations simultaneously, the protective relays should operate as if a fault occurred on the

system. The results are evaluated to ensure the protective relays and communication equipment

is functioning correctly as a unit.

It is also important to note that different test-set manufacturers and test-set models may be

synchronized to the same time source but may not start outputting the test at the same moment

due to internal time delays and/or external I/O time delays, if used. Always consult with the relay

test-set manufacturers if two different models of test-sets will be used for end-to-end testing on

li t d t i if ti f t t b li d Diff t d l f th

End-to-End Testing

4 Whereshould I performEnd to End Testing?



4. Where should I perform End-to-End Testing?End-to-end testing should be performed whenever it would be beneficial to test an entire

protection scheme in real-time to make sure the all equipment will operate correctly whenrequired. This test technique need not be limited to transmission lines but could be applied to all

of the feeders in a substation by installing a test-set at each feeder’s protective relay and starting

a fault simulation to be played into all relays simultaneously to ensure that the scheme works as

intended.

5. When Should I Perform End-to-End Testing?End-to-end testing appears to be mandated by the NERC requirement quoted earlier and all new

installations with remote communication between relays should be tested via end-to-end testing.

This test technique can also be a useful and effective maintenance test if end-to-end testing was

performed during the relays’ commissioning. There can be no more effective way of ensuring

the entire protection scheme than re-playing the same number of tests into the protection system

and observing the same results. Performed correctly, using this test technique for maintenance

tests can be more efficient as well.

Chapter 2Detailed End-to-End Testing ProceduresThis section will provide more detailed information about each step of the end-to-end testing

procedure described as:

1. Obtain and Review Test Cases2. Isolate Equipment Under Test

3. Connect Appropriate Input and Output Connections.

4. Connect Test Equipment To Replace CTs/PTs

5. Setup GPS Antenna

6 A l M T

End-to-End Testing

1 Obt i dR i T tC



1. Obtain and Review Test Cases

End-to-end testing usually performs many different test cases simulating faults at various

locations along and around the transmission line using a mix of the most common fault types

(Phase to Neutral, Phase to phase, and three-phase). Some additional test cases are performed

outside the protected zone also to ensure that the relay will not trip.

The traditional distance protection settings for a distance relay are as follows and displayed in

figure 2 assuming a 10Ω transmission line:

¾ Zone-1 = 80% of the transmission line with no intentional delay.

¾ zone-2 = 125% of the transmission line with approximately a 20 cycle delay

¾ Zone-3 = Site specific percentage in the reverse direction.

TS

21Z3

21

Z2

21

Z1

RLY-1

TX1

RX1

RLY-1 ZONE 1

RLY-1 ZONE 2

RLY-2 ZONE 2

RLY-1 ZONE 3 RLY-2 ZONE 3

RLY-3 ZONE 1

RLY-3 ZONE 3

RLY-4 ZONE 2

RLY-4 ZONE 3

TS

21

Z3

21

Z2

21

Z1

RLY-3

TX1

RX1

TS

21

Z3

21

Z2

21

Z1

RLY-2

TX1

RX1

TS

21Z3

21

Z2

21

Z1

RLY-4

TX1

RX1

RLY-3 ZONE 2

RLY-4 ZONE 1

RLY-2 ZONE 1

TSTS TS TS

TS TSTSTS

Figure 2: Typical Distance Protection Settings

A typical series of tests verifies the relays’ operation at key locations along the transmission line

slightly above and below the pickup settings for each zone. For example, the first two tests

would be performed at 75% (7.5Ω) and 85% (8.5Ω) from RLY-1 to test the zone #1 protection

of RLY-1. The second two tests would be performed at 75% and 85% from RLY-2 or 1.5Ω and

2.5Ω from RLY-1 to test zone-1 protection of RLY-2. Another 4 tests would be performed to

test the zone-2 protection of both relays at 120% and 130% from relays RLY-1 and RLY-2.Another two to four tests are performed to test zone-3 if zone-3 is enabled. A final test can be

performed to ensure that the relays will not operate due to a sudden phase reversal when a fault

occurs on one of two parallel lines.

1 23 5 4 7 8 116910

End-to-End Testing

While it is possible to manually calculate all of these points on a radial (only one source)

transmission line knowing the line length and settings these manual calculations do not include



transmission line knowing the line length and settings, these manual calculations do not include

the source impedance which will affect the pre-fault, fault values, and relay operation. The

calculations become very complicated when the transmission line has more than one source

available. These complications make test-case creation beyond the average relay tester and test

cases should be supplied by the design engineer. The design engineer should have the electrical

system modeled by a power system simulator and it should be relatively easy for them to choose

the test case parameters and export the results as a waveform or fault-state data. The test cases

should be submitted to the testing team with a description of the expected results for each test,another reason why this information should be supplied by the design engineer.

Each test case can be supplied to the relay tester as a single file containing waveform data for

both relays or as separate files for each relay under test. It is very important that the channels or

files are labeled correctly to ensure the correct parameters are applied at each location during thetest. Contact the relay test-set manufacturer to learn how to play waveform files and choose theappropriate channels.

Waveform data can be the simplest way to perform end-to-end testing when everything is

working properly. There are additional benefits to waveform testing such as simulating system

distortions that typically occur during a real fault such as transients, DC offset, or CVT

distortions. The design engineer exports the data into COMTRADE format for each test case and

sends the files to the relay tester. The relay testers open the file in their respective test-sets, check

to ensure the correct channels are used, and run the tests. If the relays respond correctly, the relaytesters save the data and move on to the next test. However, it can be difficult for two relay

testers at two different locations to troubleshoot problems in the test plan itself because they

cannot compare the two waveforms side-by-side to find any gross errors.

Supplying test cases as data can be tedious for the design engineer and the relay tester depending

on the system modeling software used and the intended test-set. Ideally, the design engineer

exports the data as a file like the waveform method described previously and that file is imported

into the test-set without difficulty. This ideal situation is often not the case and some

intermediary software may be required for the conversion process. The information could also be

manually entered into the test-set software. This method provides better documentation of the

tests and allows the relay testers at different locations to quickly compare the test cases to find

gross errors; but it can be more time consuming and prone to simple conversion errors.

End-to-End Testing

An example test case with identical parameters is shown below using both methods.



RLY-1

Values Angle Values Angle Values Angle Values Angle

VA 132.79 0 110.9 -1 132.79 0 66.4 0.0 55.5 -1.0 66.4 0.0

VB 132.79 -120 110.9 -121 132.79 -120 66.4 -120.0 55.5 -121.0 66.4 -120.0

VC 132.79 120 110.9 119 132.79 120 66.4 120.0 55.5 119.0 66.4 120.0

IA 200 -10 4452 -81 0 0 0.50 -10.0 11.13 -81.0 0.00 0.0

IB 200 -130 4452 159 0 0 0.50 -130.0 11.13 159.0 0.00 0.0

IC 200 110 4452 39 0 0 0.50 110.0 11.13 39.0 0.00 0.0

RLY-2


VA 132.79 0 119.17 -1 132.79 0 66.4 0.0 59.6 -1.0 66.4 0.0

VB 132.79 -120 119.17 -121 132.79 -120 66.4 -120.0 59.6 -121.0 66.4 -120.0

VC 132.79 120 119.17 119 132.79 120 66.4 120.0 59.6 119.0 66.4 120.0

IA 200 170 4784 -81 0 0 0.33 170.0 7.97 -81.0 0.00 0.0

IB 200 50 4784 159 0 0 0.33 50.0 7.97 159.0 0.00 0.0

IC 200 -70 4784 39 0 0 0.33 -70.0 7.97 39.0 0.00 0.0

Load from Bus t o Lin e (SOURCE BUS for Prefault)

Load from L ine to Bus (LOAD BUS for Prefault)

PRE FAULT FAULT 1 Post Fault

Secondary

Test Set

Secondary

Test Set

Secondary Test

Set

Aspen OutputPre Fault

Aspen OutputFault 1

Aspen OutputFault 2

Aspen OutputPost Fault

FAULT 1Secondary

Test Set

Post FaultSecondary Test

Set

Secondary

Test Set

Aspen Output

Pre Fault PRE FAULT

Aspen Output

Fault 1

Aspen Output

Fault 2

Aspen Output

Post Fault

Figure 4: Example Test Plan using Raw Data

Figure 5: RLY-1 Test Case as Waveform

End-to-End Testing

Always perform a quick check of the test voltage and current angle when reviewing the test

cases Pre-fault and un-faulted voltages in fault states should have similar phase angles on both



cases. Pre fault and un faulted voltages in fault states should have similar phase angles on both

ends. Pre-fault current and out-of-zone current phase angles should be opposite or approximately

180º from each other. Faults on the transmission line should have similar phase angles. The

following pre-fault vectors and waveforms are typical for a properly configured pre-fault

condition.

Figure 7: RL Y-1 Pre-Fault Vectors Figure 8: RL Y-2 Pre-Fault Vectors

Figure 9: RLY-1 Internal Fault Vectors Figure 10: RLY-2 Internal Fault Vectors

Fi 11 RLY 1 E t l F lt V t Fi 12 RLY 2 E t l F lt V t

End-to-End Testing

RLY-1 Ia@-20 degrees RLY-1 Ia@-85 degrees



RLY-2 Ia@ 160 degrees

RLY-1 Va@ 0 degrees

RLY-2 Va@ 0 degrees

Figure 13: Pre-Fault Waveform

RLY-2 Ia@ -84 degrees

RLY-1 Va@ -1 degrees


Figure 14: Internal Fault Waveform

RLY-1 Ia@-82 degrees

RLY-2 Ia@ 98 degrees



Figure 15: External Fault Waveform

2. Isolate Equipment Under TestAn ideal end-to-end test requires the transmission line to be completely isolated by disconnect

switches outside the zone of protection. This allows the circuit breakers to operate in order to

prove the entire protective scheme as shown in the following figure.

TS

21

TS

21

TS TS

TS TS

TS

21

TS

TS

TS

21

TS

TS

End-to-End Testing

It is possible to perform end-to-end tests without isolating the line but special care must be taken

to ensure that the circuit breakers remain closed throughout the test and that backup protection



g p p

systems are available. Online end-to-end testing is performed by isolating the primary protection

via test switches while the backup protection remains online, providing protection for the

transmission line while the tests are performed. Simulating breaker status contacts is required

and often difficult as test switches may not be available for breaker status inputs to the relay

depending on the location and local utility standards. After the primary protection is tested, it is

carefully placed back into service and the process is repeated for testing the backup protection.

3. Relay Input / Output ConnectionsCarefully review the drawing to make sure all output contacts are accounted for and open any

test switches, panel circuit breakers, fuses, etc. necessary to prevent unintended equipment

operation. The circuit breaker position, relay operation, or metering values applied during testingcould have unforeseen consequences in an external plant-wide logic controller causing

embarrassing and expensive outages if appropriate measures are not taken.

There are several ways to connect relay output contacts to the test-set depending on the test-set

and the field connections. The simplest connection applies the test-set input contacts directly

across the relay’s output contacts. With test switches, this is a simple task as shown in figure 17.

TS-52-5-DC1 switches A and B are opened and the test-set input is connected at the test

switches or on the relay itself. Test switches are nice but not always available, and a test-set

input can be connected across the contact without test switches as shown on the right side of Figure 17. Check with the test-set manufacturer before attempting this connection. Some relay

manufacturer inputs are polarity sensitive and may need to be reversed if the test-set senses the

contact is closed when it is actually open. If the circuit breakers will operate during the test, the

test switches should be closed to allow the trip signal to operate the circuit breaker’s trip coil.

Open the test switches if the breaker is not intended to operate during the test.

R1TRIP

50+51

E2

F2

TS-52-5-DC1

4

3

TB1-7TD

TS-52-5-DC1

1

2

TB1-6

RELAY TEST SET

+ Timer

Input

R8

SELF

TEST

E12

F12

R7

AUX

50+51+27

E11

F10

RSD

TB1-3

TB1-5TB1-4

RELAY TEST SET

+ Timer

Input

125V+

End-to-End Testing

contact in the following figures is connected in parallel with the “DCS close” contact. If the DCS

contact closes when the test switches are closed, the relay input will sense contact closure. This



problem is easily solved by opening either of the test switches. One wire must be removed when

no test switches are provided. Figure 18 displays the different options when contacts are

connected in parallel.

R2

CLOSE

PB

E3

F3

8

7

5

6

TB1-8

DCS1

DCS

CLOSE

DCS2

TB1-9

TS-52-5

DC1

TS-

52-5

DC1

RELAY TEST SET

+ Timer

InputCLOSED

STATUS R2

CLOSE

PB

E3

F3

8

7

5

6

TB1-8

DCS1

DCS

CLOSE

DCS2

TB1-9

TS-

52-5

DC1

TS-

52-5

DC1

RELAY TEST SET

+ Timer

InputOPEN

STATUS

R2CLOSE

PB

E3

F3

8

7

TB1-8

DCS1

DCS

CLOSE

DCS2

TB1-9

TS-52-5

DC1

RELAY TEST SET

Timer

InputOPEN

STATUS R2CLOSE

PB

E3

F3

TB1-8

DCS1

DCS

CLOSE

DCS2

TB1-9

RELAY TEST SET

Timer

InputOPEN

STATUS++

Figure 18: Test-set Input Connections with Contact in Parallel

Most test-set manufacturers also allow voltage-monitoring inputs to reduce wiring changes whentesting. Instead of monitoring whether a contact is closed or open, the voltage-monitoring option

determines that the contact is closed when the measured voltage is above the test-set’s defined

setpoint. The test-set assumes the contact is open if the measured voltage is below the setpoint.

Another connection is required when using voltage-detecting, test-set inputs when the correct

contact state is necessary. Any of the test-set connections in figure 19 can be used when voltage

is required for contact sensing.

Starting from the left, The R2 timer is connected between TB1-9 and TB3-6 (negative circuit)

with closed output contact test switches. When R2 and “DCS close” are open, the voltage

between the two terminals should be negligible and the relay will detect an open contact. When

R2 or “DCS close” closes, the relay will detect 125VDC across the contacts and the test-set will

detect a closed contact Be wary of this connection because the circuit breaker will close if the

End-to-End Testing

applications) Obviously this connection will only work when the DC system is grounded at the

midpoint, as most DC systems are. This connection is also safe as the connected 86-5 lockout



will not operate when the contact is operated.

125Vdc

CT#4DC PANEL A

R3AUX

27

E4

F4R2CLOSE

PB

E3

F3

R1

TRIP

50+51

E2

F2

12

11

8

7

4

3

52-5

9

10

5

6

1

2

TB1-6DC+

DC-

TB1-8

DCS1

DCS

CLOSE

DCS2

TB1-9

43AUTO

52

53

11

86-5

13

SR

Y

LS

b

Y

M

LS b

3 7 8

4

1

52-5

TOC

2

TB3-3

TB3-4

CS

CLOSE

16

17

43MANUAL

22

21

1

52-5

TOC

2

TB3-5

G

+

-

TB3-3

TB3-6

TB3-11

G

F

86-5

C

B

86-5

E2

F2

4

3

1

2

TB1-10

TS-52-5-DC1

TS-52-5-DC1

TS-86-1

TS-86-1

TB1-11

TS-52-5-DC1

TS-52-5-DC1

TRIP

a

18

TB3-9

17

TB1-7

CSTRIP

11

18

TS-52-5

DC1

TS-52-5

DC1RELAY TEST SET

TimerInput

+

RELAY TEST SET

TimerInput

+

R2

R3

RELAY TEST SET

TimerInput

+

R1

Figure 19: Test-set Input Connections in DC Circuit

NEVER apply the following connection in a trip circuit unless there will be no negative results if

the circuit is completed and operates. Some test-set sensing contacts have a low impedance and

will complete the circuit.

End-to-End Testing

DC+



R1TRIP

50+51

E2

F2

4

3

1

2

DC-

G

F

C

B

TS-52-5-DC1

TS-52-5-DC1

TB1-7

RELAY TEST SET

Timer

Input

+

R1

3

Figure 20: Dangerous Test-set Input Connection in Trip Circuit

Always review the manufacturer’s literature when performing digital input testing because relayscan be unforgiving when not correctly connected and cause some embarrassing and expensive

smoke to be released. These connections should also be carefully compared to the application to

ensure they are connected properly before applying voltage to the circuit. Figures 21, 22 and 23show some typical examples of input connections from different relay manufacturers.

Figure 21 from the Beckwith Electric M-3310 manufacturer’s bulletin displays the connections

for relay input connections. The field input contact is “dry” and the sensing voltage is supplied

by the relay itself. Any external voltage connected in this circuit could damage the relay. The

test-set dry output contact or jumper would be connected between terminals 10 and 11 to

simulate an IN 1 input.

Figure 22 from the SEL 311C manufacturer’s bulletin shows that this relay requires “wet”

inputs. An external voltage must be connected before the relay will detect input operation.

End-to-End Testing



Figure 21: M-3310 Relay Input Connections Figure 22: SEL 311C Input Connections

The GE Multilin SR-750 relays can have “wet” or “dry” contacts connected as shown in Figure

23 from the manufacturer’s bulletin. Relays that can accept both styles of input contacts are more

prone to damaging connection errors and the site and manufacturer’s drawings should be

compared to ensure no errors have been made.

Figure 23: GE/Multilin SR-750 Input Connections

When testing, the test-set output is connected across the actual contact used in the circuit to

prevent unintentional damage when applying incorrect test voltages. If the in-service contact is

closed, the contact needs to be isolated by opening test switches or temporarily removing wiring

in order to test both input states.

C1

DC

1

2

C2IN1 IN2

39

41

TB2-2

TB2-3

TS-52-5-DC2

5

6

TB2-4

SPARE

52A

52-5

RLY-12

125Vdc

CT#3

DCPANELA

DC+

RELAY TEST SET

Test

Output

+

End-to-End Testing

4. Connect Test Equipment to Replace CTs/PTsConnect the test-set to simulate the CT and PT inputs as shown in figure 25. All CT test switches



Connect the test set to simulate the CT and PT inputs as shown in figure 25. All CT test switches

have been opened to short the CT inputs, and an isolating device has been inserted between the

CT clips to isolate the top from the bottom.

Always pay attention to the PT connections and triple check that the test-set is connected to the

relay side of the test switch. Incorrect connections could back-feed the connected PTs and apply

a dangerous voltage to the high-side of the PTs.

OA OB OC

TO 4160V BUS

CT's 123-124-1253-3000: MR

SET 2000:5

C200

1A1

1B1

1C1

1C0

52-5

X2

X2

X2

X5

X5

X5

4

8

12

3

7

11

1

5

9

G7 H7

G8 H8

G9 H9

G5 H5 G6 H6

VT8

4200:120V

15 17 19

16 18 20

1A2

1B2

1C2

MULTILIN SR-750

1A3

1B3

1C3

OA OB OC

CABLE FROM XFMR-2

OA

OB

OC

TS-52-5-AC

A Phase Volts

B Phase Volts

C Phase Volts

N Phase Volts

A Phase Amps

B Phase Amps

C Phase Amps

+

+

+

RELAY TEST SET

Magnitude Phase AngleTest Volts

Test Volts

Test Volts

AØ Test Amps

BØ Test Amps

CØ Test Amps

0°

-120° (240°)

120°

0°

-120° (240°)

120°

+ Timer

InputElement

Output

- Timer

Input

+DC Supply -

+

Alternate Timer Connection

A

This

DWG

2

6

A

This

DWG

1C0

8

ISOLATING DEVICE

RLY-12

Figure25: ExampleAC Test-set Connections

End-to-End Testing

5. Setup GPS AntennaMost test-sets require at least 4 GPS satellite signals to guarantee accuracy. The antenna must be



q g g y

mounted in a fairly open area with a clear view of the open sky, especially the southern horizon.

Mounting the antenna on top of a truck in the parking lot usually works well. Change the test-setsettings to use the GPS clock as its reference signal and wait for the GPS status to indicate that

the test-set has been synchronized to the GPS signals. This can take up to 30 minutes the first

time it is applied at a location depending on the test-set. Subsequent synchronizations shouldn’t

require such a long delay. Become familiar with a GPS error message by disconnecting the test-

set from the antenna after GPS synchronization in order to recognize a loss-of-synchronization

problem if it occurs during the test.

If open sky is not available, some test-sets will allow synchronization to the substation’s IRIG

signal. A substation’s IRIG signal is another timing standard that uses a GPS clock connected toa large antenna that converts the GPS time to an IRIG signal. The IRIG signal is connected to all

of the protective relays, fault recorders, and other devices inside the substation to ensure all

devices will record the same time if an event occurs to help with post-fault analysis.

6. Apply Meter TestA meter test should be the first test performed whenever a digital relay is tested. Meter tests

prove that the analog-to-digital converters are working inside the relay, the CT and PT ratios

have been setup correctly, and that the test-set to relay connections are correct. It is important tonotify all nodes before starting a meter test to prevent trip signals from all connected relays.

Perform two single-phase tests to prove that each phase of the test-set is connected to the correct

phase of the relay. Apply single-phase, nominal current and voltage to the relay. Monitor the

relay’s metering function from the front panel or relay software and ensure that the voltage and

current are measured on the correct phase. Apply current and voltage to another phase and

ensure that the correct phases are displayed. If the relay monitors zero-sequence voltage and/or

current, record the zero-sequence values on the test sheet. When single-phase current/voltage is

applied, the zero-sequence value should match the applied value. Zero sequence componentscannot occur in delta connected systems and there will be no zero-sequence measurements for

delta connected PTs. This test could be repeated for the third phase, but once two phases have

been verified, the following three-phase tests can be used for all other measurements.

End-to-End Testing

Apply three-phase, nominal current and voltage to the relay, record the metering results on the

test sheet, and compare them to the CT and PT ratios. If the relay also displays phase angles,

record these values and ensure that they are in the correct phase relationship. Do not assume that



record these values and ensure that they are in the correct phase relationship. Do not assume that

a three-phase, phase-angle measurement can be used in place of the single-phase tests above.

The relay uses its own reference for phase angles which can be misleading. For example, if allthree-phases were rolled to the next position (AØ to BØ, BØ to CØ, CØ to AØ) the test-set and

the relay would both indicate the correct phase angles for each phase (AØ=0º, BØ=-120º,

CØ=120º) but AØ current/voltage from the test-set would be injected into BØ of the relay. Also,

the test-set and the relay could use different references when displaying phase angles that can beconfusing as shown in Figure 26. For example, the phase relationships displayed by a

GE/Multilin SR-750 would be 0º, 120º, 240º LAG. A SEL relay with the same settings and

connection would display 0º, -120º, 120º. If the relay monitors positive sequence components,

record the current and voltage values on the test sheet. The positive sequence value should matchthe applied current and voltage and the negative sequence and zero-sequence voltages should bealmost zero.

180-180

0

3 3 0

- 3 0

270-90

90

3 0 0

- 6 0

2 1 0

- 1 5 0

2 4 0 - 1 2 0

3 0

6 0

1 5 0

1 2 0

Van

Vbn

Vbn

LEADING PHASE ANGLES

180-180

0

3 0

90

270-90

6 0

1 5 0

1 2 0

3 3 0

- 3 0

3 0 0 - 6 0

2 1 0

- 1 5 0

2 4 0

- 1 2 0

Van

Vbn

Vbn

LAGGING PHASE ANGLES

Figure 26: Phase Angle Relationships

Watt and VAR measurements can also help determine if the correct connections have been

made. When three-phase, balanced current and voltage is applied; maximum Watts and almost

zero VARs should be measured. Rotate all three currents by 90º and maximum VARs and almost

zero Watts should be measured. Any connection problems will skew the Watt and VAR values

and should be corrected.

If the relay monitors negative sequence, reverse any two phases and record the negative

sequence values. The negative sequence value should be equal to the applied value and the

positive sequence and zero-sequence values should be nearly zero. Some relays display 3x the

negative sequence values. In this case, the negative sequence value will be three times the

End-to-End Testing



Figure 27: Example Metering Test Sheet

End-to-End Testing

7. Apply Test PlanThe end-to-end tests begin after all nodes have reported that their meter tests have been

l d f ll All d d l d h i i



completed successfully. All nodes agree on a test case to run and load their respective test cases

into the test-sets. An example test case for two nodes is shown in the following figures.RLY-1


VA 132.79 0 57.74 -4 132.79 0 66.4 0.0 28.9 -4.0 66.4 0.0

VB 132.79 -120 138.9 -123 132.79 -120 66.4 -120.0 69.5 -123.0 66.4 -120.0

VC 132.79 120 138 123 132.79 120 66.4 120.0 69.0 123.0 66.4 120.0

IA 200 -10 15195 -83 0 0 0.50 -10.0 37.99 -83.0 0.00 0.0

IB 200 -130 235 -89 0 0 0.50 -130.0 0.59 -89.0 0.00 0.0

IC 200 110 236 -79 0 0 0.50 110.0 0.59 -79.0 0.00 0.0

RLY-2


VA 132.79 0 120.1 -1 132.79 0 66.4 0.0 60.1 -1.0 66.4 0.0

VB 132.79 -120 132.2 -119 132.79 -120 66.4 -120.0 66.1 -119.0 66.4 -120.0

VC 132.79 120 132.4 119 132.79 120 66.4 120.0 66.2 119.0 66.4 120.0

IA 200 170 1658 -80 0 0 0.33 170.0 2.76 -80.0 0.00 0.0

IB 200 50 235 91 0 0 0.33 50.0 0.39 91.0 0.00 0.0

IC 200 -70 236 101 0 0 0.33 -70.0 0.39 101.0 0.00 0.0

Load from Bus to Line (SOURCE BUS for Prefault)

Load from L ine to Bus (LOAD BUS for Prefault)


Secondary

Test Set

Secondary

Test Set

Secondary Test

Set

Aspen OutputPre Fault

Aspen OutputFault 1

Aspen OutputFault 2

Aspen OutputPost Fault

PRE FAULT FAULT 1 Post FaultSecondary

Test Set

Secondary

Test Set

Secondary Test

Set

Aspen Output

Pre Fault

Aspen Output

Fault 1

Aspen Output

Fault 2

Aspen Output

Post Fault

Figure 28: Example Test Plan 2 with raw Data

Figure 29: Example RLY-1 Waveform Test Plan 2

End-to-End Testing

After the test cases are loaded into the test-sets, a start time is decided upon. Different test-sets

have different methods to initiate a test. The test-set manufacturer should be contacted to

determine the correct method to initiate a test and whether some lead time should be added to



ensure correct test case simulations when two different test-set models are used. The test

countdown should be initiated after all nodes report that they are ready and the start signals aresynchronized for the same start time. Watch the test-set and relay metering, if possible, during

the test to ensure the test-set started correctly and injected the correct values. If any nodes report

a malfunction, the problem should be corrected and the test should be run again.

(Hint: It’s often a good idea to reset all fault recorder and sequence of event records inside the

relay between tests to make sure that only the test in question is available to prevent confusion

after several tests have been performed)

8. Evaluate ResultsAfter the test case has been injected into all nodes simultaneously, the relay targets at each node

should be recorded and compared to the test case description to ensure the relays have responded

correctly. All event and sequence-of-event records should also be downloaded. Some engineers

will review the event records from all relays to review the relays’ reaction to the fault, and others

will assume correct operation based on correct targeting and time delays for trips. If everything

works correctly, all nodes can move on to the next test case and inject it into the relay.

A perfectly executed series of end-to-end tests is rare and there is often some troubleshootinginvolved. Here are some common problems which could cause an incorrect test result:

¾ Waveform Playback

o Was the correct waveform loaded at all nodes?

¾ State Simulator Playback

o Check the hard copy report of simulation to data in test-set

¾ Is the same pre-fault duration applied at all nodes?

¾ Are the same phases faulted at all nodes?

¾ Are the phase angle references correct at all nodes?

¾ Did the playback start at the correct time at all nodes? (Look at relay event records)

¾ Were all AC channels recorded in the relay event records? (Test lead fell off, etc)

¾ Are communication channels active during test?

¾ Were the circuit breakers or circuit breaker simulators closed before the test?

9. Return Protection System to ServiceThe protection system should be returned or placed into service after all test cases have been

executed. Make sure that all event recorder, event records, and as-left relay settings have been

downloaded and are available for off-site review before beginning the procedure to return therelays into service. All event recorder, event records, min/max, and other history related data

inside the relay should be erased to prevent confusion when troubleshooting faults after the

relays have been placed in-service. All test equipment should be disconnected from the relays

and any wiring removed during the test should be replaced. The CT, PT, and input test switches

End-to-End Testing

A) Cover LetterThe cover letter should describe the project, provide a brief history, and (most importantly)

list of all comments during the test This letter summarizes all of the test sheets and should be



list of all comments during the test. This letter summarizes all of the test sheets and should be

written with non-electrical personnel in mind. Ideally, this document could be reviewed yearsfrom the testing date with a clear understanding of what tests were performed and their

results. Any comments should be clearly explained with a brief history of any actions

performed and the status at the time of the letter. Organize comments in order of importanceand by relay or relay type if the same comment applies to multiple relays. An example

comment is “The current transformer ratio on drawing A and the supplied relay settings did

not match. The design engineer was contacted and the correct ratio of 600:5 was applied to

the relay settings and confirmed in the field. No further action is required.”

B) Test SheetThe test sheet should clearly show all the test results, including a printout of event and

sequence-of-event records for each test to show what tests were performed and the relays’

responses. A digital copy of all test cases should also be included in the report to allow

maintenance personnel in the future to replay the same tests into the relay and evaluate their

response during maintenance intervals.

C) Final SettingsThe final, as-left settings should be documented at the end of the test sheet. A digital copy

should also be saved, and all relay settings for a project should be made available to the client

or design engineer for review and their final documentation. Setting files should be in the

relay’s native software and in a universal format such as word processor or pdf file to allow

the design engineer to make changes, if required, and allow anyone else to review the settings

without special software.



End-to-End Testing



Chapter 3Common Protection Schemes

The following sections are intended to provide a basic understanding of the most common protection

schemes tested via end-to-end testing. Distance protection settings can be generalized in percentage

of the line they are protecting for the most part and it is important to understand the logic behind basic

distance protection before reviewing the protection schemes.

TS

21Z3

21

Z2

21

Z1

RLY-1

TX1

RX1

RLY-1 ZONE 1

RLY-1 ZONE 2

RLY-2 ZONE 2


RLY-3 ZONE 1

RLY-3 ZONE 3

RLY-4 ZONE 2

RLY-4 ZONE 3

TS

21

Z3

21

Z2

21

Z1

RLY-3

TX1

RX1

TS

21

Z3

21

Z2

21

Z1

RLY-2

TX1

RX1

TS

21Z3

21

Z2

21

Z1

RLY-4

TX1

RX1

RLY-3 ZONE 2

RLY-4 ZONE 1

RLY-2 ZONE 1

TSTS TS TS

TS TSTSTS

Figure 31: Typical Distance Protection Settings

Zone-1 protection is typically set at 80% of the transmission line with no intentional time delay. It is

not set at 100% of the transmission line because the line impedance used for protective relaying is a

calculation based on the size of wire and distance of the transmission line. There are many other

End-to-End Testing

An average person might think that two protective relays with zone-1 elements set at 80% of the line

towards each other provides 100% protection of the transmission line with redundant protection on

the inner 60% by the overlapping zones of protection would be enough. The utility industry is always

concerned with reliability and stability which requires 100% redundancy on all transmission lines



concerned with reliability and stability which requires 100% redundancy on all transmission lines.

Zone-2 protection is set beyond (approximately 120%) the transmission line. It is possible that therelay will trip if a fault occurs on another line which would cause a larger system disruption than

necessary and could impact the system stability for the entire region so a 20 cycle time delay is

usually added to delay a zone-2 trip. This time delay is intended to give the remote equipment a

chance to operate before the zone-2 element trips for a fault outside the intended zone of protection.Zone-2 has a twofold benefit, redundant protection for the transmission line and backup protection for

external equipment.

Zone-3 protection in non-communication schemes is usually applied to provide backup protection for

external equipment. It can be applied with very large resistances in the forward direction with a longtime delay (60 cycles) to minimize system disturbances in case of equipment failure. It can also be

applied in the reverse direction with a similar time delay as backup protection for relays in the reverse

direction.

1. Direct Transfer Trip (DTT) Scheme

The direct transfer trip scheme is the simplest of the communications schemes and allows a trip

signal to be sent to all relays. If the correct trip signal is detected on one relay, a trip signal issent to all the other relays. A very secure communication channel is required for a DTT scheme

to prevent noise on the communication channel from causing an unintended trip. End-to-end

testing is not required for this communication scheme.

2. Direct Under-reaching Transfer Trip (DUTT)The direct under-reaching transfer trip scheme is very similar to the DTT scheme described

above and uses the zone-1 protective element in each relay to send a DTT signal. Any relay that

detects a Zone-1 fault will send a trip signal to all the other relays in the scheme. A very secure

communication channel is required for a DTT scheme to prevent noise on the communication

channel from causing an unintended trip. End-to-end testing is not required for this

communication scheme.

3. Permissive Over-Reaching Transfer Trip (POTT)The permissive over-reaching transfer trip scheme uses zone-2 elements from up to three relays

to determine if a fault has occurred on a transmission line. This scheme has distance zone-1

protection set at 80% of the line in both relays RLY-1 and RLY-2. Zone-2 protection is set at

120% of the line with a time delay of 20 cycles to provide backup protection for other relays. If azone-2 fault pickup is detected by both relays (test cases 1 and 2), the fault must be located

inside the scheme’s zone of protection because the two zone-2 settings only overlap across the

transmission line itself. Both relays will trip almost instantaneously after a small time delay is

applied to prevent communication errors that can cause nuisance operations

End-to-End Testing

If the communication scheme is not enabled, the following figures indicate the outcomes of a

standard battery of end-to-end tests assuming that the outside protective relays fail to operate for

out-of-zone faults.1 23 5 4 7 8 116910

RLY RLY



RLY-1 ZONE 1

RLY-1 ZONE 2

RLY-2 ZONE 2


RLY-2 ZONE 1

RLY

-1

RLY

-2

Figure 32: End-to-End Test Simulations

Test RLY-1 RLY-2

1 Trip Zone-1 in 0 cycles Trip Zone-2 in 20 cycles







8 No trip Trip Zone-3 in 60 cycles

9 Trip Zone-3 in 60 cycles No trip10 No trip No trip

11 No trip No trip

Figure 33: End-to-End Test Results with no Communication Scheme Applied

The following figure indicates the results of a POTT communication scheme operating correctly

assuming that the outside equipment does not operate for out-of-zone faults.

Test RLY-1 RLY-2

1 Trip Zone-1 in 0 cycles Trip Zone-2 in <3 cycles

2 Tr ip Zone-2 in <3 cycles Trip Zone-1 in 0 cycles







9 Trip Zone-3 in 60 cycles No trip10 No trip No trip

11 No trip No trip

Figure 34: End-to-End Test Results with POTT Communication Scheme Applied

End-to-End Testing

Zone-3 protection is set in the reverse direction and is reaches beyond the zone-2 protection at -

30% of the line with a time delay of 60 cycles to provide backup protection for other relays.

Zone-3 is not necessary for the POTT scheme to work for faults on the transmission line but is

used to prevent nuisance trips during sudden current reversals on parallel lines by blocking the



p p g p y g

communication-assisted trip scheme if a sudden current reversal is detected. Sudden current-reversal can occur on some installations such as parallel lines as shown in figure 35. All four

breakers are closed and a fault occurs in zone-1 of RLY-1. The current flows through each

breaker as shown by the arrows. RLY-4 zone-2 is picked-up and sends a permissive signal to

RLY-3. When breaker-1 opens, the current suddenly reverses through RLY-3 and RLY-4 whichstarts a race. Will RLY-4 detect the sudden reversal first and stop sending the permissive trip to

RLY-3 before RLY-3 detects a zone-2 pickup? If not, RLY-3 will have a permissive signal from

RLY-4 and detect a zone-2 fault which will cause a communication-assisted trip and de-energize

the healthy feeder.

1

RLY

-1

RLY

-2

RLY

-3

RLY

-4

RLY-1 - Zone 1 RLY-2 - Zone 2

RLY-4 - Zone 2RLY-3 - Zone 3

1

RLY

-1

RLY

-2

RLY-3

RLY-4

RLY-2 - Zone 2

RLY-4 - Zone 3RLY-3 - Zone 2

Figure 35: Current Reversal Example

The current-reversal protection is tested by simulating a current-reversal as shown in the

following figures

End-to-End Testing

RLY-1 Load from Bus to Li ne (SOURCE BUS for Prefault)

Aspen Output

Pre Fault

Aspen Output

Fault 1

Aspen Output

Fault 2

Aspen Output

Post Fault

Secondary Test

PRE FAULT FAULT 1 FAULT 2 Post Fault

Secondary Secondary Secondary Test



Values Angle Values Angle Values Angle Values AngleVA 132.79 0 134.52 0 134.6 0 132.79 0 66.4 0.0 67.3 0.0 67.3 0.0 66.4 0.0

VB 132.79 -120 67.3 180 105 -130 132.79 -120 66.4 -120.0 33.7 180.0 52.5 -130.0 66.4 -120.0

VC 132.79 120 67.3 180 104.6 129 132.79 120 66.4 120.0 33.7 180.0 52.3 129.0 66.4 120.0

IA 200 -10 24 -85 25 -85 200 -10 0.50 -10.0 0.06 -85.0 0.06 -85.0 0.50 -10.0

IB 200 -130 1860 9 1463 -171 200 -130 0.50 -130.0 4.65 9.0 3.66 -171.0 0.50 -130.0

IC 200 110 1858 -172 1465 10 200 110 0.50 110.0 4.65 -172.0 3.66 10.0 0.50 110.0

RLY-2


VA 132.79 0 133.4 0 133.4 0 132.79 0 66.4 0.0 66.7 0.0 66.7 0.0 66.4 0.0

VB 132.79 -120 114.9 -126 68.2 -173 132.79 -120 66.4 -120.0 57.5 -126.0 34.1 -173.0 66.4 -120.0

VC 132.79 120 113.3 125 66.15 173 132.79 120 66.4 120.0 56.7 125.0 33.1 173.0 66.4 120.0

IA 200 170 24 95 25 95 200 170 0.33 170.0 0.04 95.0 0.04 95.0 0.33 170.0

IB 200 50 1860 -171 1463 9 200 50 0.33 50.0 3.10 -171.0 2.44 9.0 0.33 50.0

IC 200 -70 1858 8 1465 -170 200 -70 0.33 -70.0 3.10 8.0 2.44 -170.0 0.33 -70.0

Load from Lin e to Bus (LOAD BUS for Prefault)

Set

Aspen Output

Post Fault

Test Set Test Set Set

Secondary Test

Set

PRE FAULT FAULT 1 FAULT 2 Post Fault

Secondary

Test Set

Secondary

Test Set

Secondary Test

Set

Aspen Output

Pre Fault

Aspen Output

Fault 1

Aspen Output

Fault 2

Figure 36: Current Reversal Test Plan

End-to-End Testing

4. Directional Comparison Unblocking (DCUB)The directional comparison unblocking scheme is essentially the same as the POTT scheme

described previously. The DCUB uses a power line carrier channel that uses one phase of the



power system itself as a communication channel. Communicating over the power line is lesssecure because the signals may not transmit across a faulted transmission line and power system

disruptions can cause noise. A guard signal is sent under normal conditions to indicate that

communication channels are intact. If one relay detects a zone-2 fault, the guard signal is

dropped and a trip signal is sent. The other relay will trip almost immediately (after a small

communications delay) if it detects; a zone-2 fault, a dropped guard signal, and a trip signal.

5. Permissive Under-reaching Transfer Trip (PUTT)The permissive under-reaching transfer trip scheme uses the zone-1 element from one relay and

the zone-2 element from a second relay to determine if a fault has occurred on a transmission

line or outside the scheme’s zone of protection. This scheme has distance zone-1 protection set at

80% of the line in both relays RLY-1 and RLY-2. Zone-2 protection is set at 120% of the line

with a time delay of 20 cycles to provide backup protection for other relays. If a zone-1 fault is

detected by one relay (test cases 1 and 2) and a zone-2 fault pickup is detected by the other relay,

the fault must be located inside the scheme’s zone of protection because the zone-1 and oppositezone-2 settings only overlap across the transmission line itself. The zone-1 relay will trip

instantaneously and the zone-2 relay will trip after a small time delay is applied to prevent

communication errors that can cause nuisance operations.

This scheme will not trip on sudden phase reversals because the zone-1 does not reach beyond

the transmission line and will not operate for faults outside the zone. Zone-3 protection is not

required for this scheme other than back-up protection, if desired.

If the communication scheme is not enabled, the following figure indicates the outcomes of the

standard battery of end-to-end tests assuming that the outside equipment does not operate for

out-of-zone faults.

End-to-End Testing

RLY-1 ZONE 1

1 23 5 4 7 8 116910RLY

-1

RLY

-2



RLY-1 ZONE 2

RLY-2 ZONE 2


RLY-2 ZONE 1


Test RLY-1 RLY-2



3 Trip Zone-1 in 0 cycles Trip Zone-1 in 0 cycles4 Trip Zone-1 in 0 cycles Trip Zone-1 in 0 cycles





9 Trip Zone-3 in 60 cycles No trip

10 No trip No trip

11 No trip No trip

Figure 38: End-to-End Test Results with no Communication Scheme Applied

The following figure indicates the results of a PUTT communication scheme operating correctly

assuming that the outside equipment does not operate for out-of-zone faults.

Test RLY-1 RLY-2

1 Trip Zone-1 in 0 cycles Trip Zone-2 in <3 cycles

2 Tr ip Zone-2 in < 3 cycles Trip Zone-1 in 0 cycles







10 No trip No trip

11 No trip No trip

Figure 39: End-to-End Test Results with PUTT Communication Scheme Applied

End-to-End Testing

6. Directional Comparison Blocking (DCB)The directional comparison unblocking scheme is unique among the protection schemes

described in this section because a blocking signal is used if a fault is detected in the reverse



direction. This scheme has distance zone-1 protection set at 80% of the line in both relays RLY-1 and RLY-2. Zone-2 protection is set at 120% of the line with a time delay of 20 cycles to

provide backup protection for other relays. Zone-3 protection is set in the reverse direction and is

set beyond the zone-2 protection at -30% of the line with a time delay of 60 cycles to provide

backup protection for other relays.

Zone-1 protection will operate instantaneously if a zone-1 fault is detected by either relay. If a

zone-2 fault is detected by one relay and the other relay does not detect a zone-3 trip (test cases 1

and 2) the first relay will assume that the fault is between 80-100% of the transmission line, is

inside the designated zone of protection, and will trip almost instantaneously. A small time delay(< 6 cycles) will be applied to compensate for communication delays between relays and prevent

nuisance operations. If a zone-2 fault is detected by one relay and the other relay detects a zone-3

fault (test cases 7 and 6), a blocking signal will be sent to the first relay which will determine

that the fault is outside the zone of protection and the normal zone-2 timer will trip the breaker if

outside relays do not isolate the fault first.

If the communication scheme is not enabled, the following figure indicates the outcomes of the

standard battery of end-to-end tests.

RLY-1 ZONE 1

RLY-1 ZONE 2

RLY-2 ZONE 2


RLY-2 ZONE 1

1 23 5 4 7 8 116910RLY

-1

RLY

-2


Test RLY-1 RLY-2










10 No trip No trip

11 No trip No trip

End-to-End Testing

The following figure indicates the results of a POTT communication scheme operating correctly.

Test RLY-1 RLY-2

1 Trip Zone-1 in 0 cycles Tr ip Zone-2 in <6 cycles

2 Tr ip Zone-2 in <6 cycles Trip Zone-1 in 0 cycles









10 No trip No trip

11 No trip No tripFigure 42: End-to-End Test Results with DCP Communication Scheme Applied

The DCB communication scheme speeds the tripping time for faults on the transmission and still

provides backup protection for faults outside of the zone. While this scheme may seem to be the

ideal solution for transmission line protection and does increase dependability, the unblockingnature and communication time delays inherent in the scheme can reduce the security of the

protection scheme by causing nuisance trips under certain conditions. If a fault occurs outside

the zone of protection the following actions must be completed before the remote zone-2 elementtime delay elapses or the communication scheme is useless:

¾ A reverse fault must be detected

¾ A blocking signal must be sent through the communications equipment

¾ The remote relay must receive the blocking signal

When the external fault is cleared, the remote zone-2 protection must reset before the local zone-

3 protection resets or a nuisance trip will occur. Also, the local zone-3 reverse pickup must be

greater than the zone-2 pickup settings or the remote zone-2 protection will operate in the

difference between the two settings.

End-to-End Testing

7. Pilot Wire ProtectionPilot wire protection uses a relay located at each end of a transmission line that passes the three-

phase CT secondary current through filters to convert the three-phase inputs into a signal that



can be transmitted through a two-conductor pilot wire. The voltage or current signal passingthrough the pilot wire is connected to restraint and operating coils that operate as simple

differential relays to provide the same characteristic as standard current differential relays

simplified in the following figure. The relays measure and compare the current entering the zone

of protection to the current leaving the zone of protection. The difference between the signals is

the differential current. If the ratio between the differential current and restraint current exceeds

the relay’s setpoint, the relays will trip.

RESTRAINT

Iop

RESTRAINT

FAULT CURRENT = 4000 A

400:5 400:5

Iop = 50A + 50A = 100AIop/Irestraint = 100 A / 50A = 2

Iop/Irestraint = 200% > 25% setting = TRIP

87 = 25 % RESTRAINT SETTING

RESTRAINT

Iop

RESTRAINT

EXTERNAL FAULT CURRENT = 8000 A

400:5 400:5

Iop = 100A + -100A = 0AIop / Irestraint = 0 A / 100A = 0

Iop/Irestraint = 0% < 25% setting = NO TRIP

87 = 25 % RESTRAINT SETTING

50 A50 A 50 A 50 A 100 A100 A 100 A 100 A


Figure 43: Simplified Pilot Wiring Operation

Faults that occur between the two relays will cause a trip and faults outside the zone will not tripas per the following chart. The zone protection shown in figure 44 would be provided by backup

protection.

RLY-1 ZONE 1

RLY-1 ZONE 2

RLY-2 ZONE 2RLY-1 ZONE 3 RLY-2 ZONE 3

RLY-2 ZONE 1

1 23 5 4 7 8 116910RLY

-1

RLY

-2


Test RLY-1 RLY-2

1 Trip 87 in 0 cycles Trip 87 in 0 cycles





6-11 No trip No trip

Figure 45: End-to-End Test Results with Pilot Wire Scheme Applied

End-to-End Testing

8. Phase/Charge Comparison ProtectionPhase/charge comparison protection uses a simple overcurrent device to initiate a trip that can be

blocked if the comparison relays detect that the fault is external to the zone of protection. Each

l d bl ki i l t th th l d i iti ½ l f th f



relay sends a blocking signal to the other relay during every positive ½ cycle of the waveformand sends a trip signal every negative half cycle if the measured current is greater than the

setpoint. A fault occurring on the transmission line will cause the phase angles for both relays to

be in-phase if dual sources are present and both relays will send a trip signal on the negative ½

cycle with no blocking signal. If only one side has a source, there will be no current on the

opposite side to send a blocking signal and the relays will trip. If the fault occurs outside the

zone, the current phasors will be in opposition and the relays will not trip because a blocking

signal appears to negate every trip signal.FAULT CURRENT = 4000 A

400:5 400:5


* = RLY-1 AND RLY-2 BLOCK# = RLY-1 AND RLY-2 TRIP

RELAY TRIPS

TX1

RX1

TX1

RX1*

#

* = RLY-1 AND RLY-2 BLOCK# = RLY-1 AND RLY-2 TRIP

RELAY TRIPS

*

#

400:5 400:5

TX1

RX1

TX1

RX1

$ = RLY-1 BLOCK* = RLY-2 ATTEMPTS TRIP

# = RLY-2 BLOCK

@ = RLY-1 ATTEMPTS TRIPTRIP BLOCKED

*

#

EXTERNAL FAULT CURRENT = 8000 A

$

@

$ = RLY-1 BLOCK* = RLY-2 ATTEMPTS TRIP

# = RLY-2 BLOCK

@ = RLY-1 ATTEMPTS TRIPTRIP BLOCKED

*

#$

@

Figure 46: Phase/Charge Comparison Example of Operation

Faults that occur between the two relays will cause a trip and faults outside the zone will not trip

as per the following chart. The zone protection shown in figure 47 would be provided by backup

protection.

RLY-1 ZONE 1

RLY-1 ZONE 2

RLY-2 ZONE 2


RLY-2 ZONE 1

1 23 5 4 7 8 116910

RLY

-1

RLY

-2


Test RLY-1 RLY-2

1 Trip 87 in 0 cycles Trip 87 in 0 cycles 2 Trip 87 in 0 cycles Trip 87 in 0 cycles




End-to-End Testing

9. Line DifferentialLine differential relays have up to three relays connected at the ends of a transmission line that

compare the magnitudes and phasors for all phases as well as the negative and zero sequence

t t d t i if f lt th t i i li t id th f



components to determine if a fault occurs on the transmission line or outside the zone of protection. These relays require a high-speed and secure communication medium such as fiber

optics in order to transfer all of the collected data to allow each relay to perform its own

calculations and provide high-speed tripping.

Traditional current differential relays calculate the ratio of differential to restraint current and if

the ratio is greater than a simple slope setting, the relay will trip. This slope characteristic works

well when applied to generators, buss, and transformers; but a transmission line has a very

different characteristic due to its operating parameters and the wide variety of faults that can

occur on a transmission line.

Modern line differential protection uses a characteristic called the alpha plane. The alpha plane

graphs the vector ratio of remote current to local current calculated for each phase current as well

as the negative and zero sequence currents. The example test plan in figures 49 and 51 is plotted

on the Alpha plane graph using the calculations in figure 50 and 52. Remember that these

calculations use complex or vector math. The graph in figure 53 shows the alpha plane.

Calculated values shown inside the shaded area are in the restrained region and the relays will

not trip. Values outside the restrained area are in the trip region and the relays will trip.

End-to-End Testing

RLY-1


VA 132.79 0 110.9 -1 132.79 0 66.4 0.0 55.5 -1.0 66.4 0.0

VB 132 79 120 110 9 121 132 79 120 66 4 120 0 55 5 121 0 66 4 120 0

Secondary

Test Set

Aspen Output

Pre Fault PRE FAULT

Aspen Output

Fault 1

Aspen Output

Fault 2

Aspen Output

Post Fault FAULT 1Secondary

Test Set

Post FaultSecondary Test

Set




VB 132.79 -120 110.9 -121 132.79 -120 66.4 -120.0 55.5 -121.0 66.4 -120.0

VC 132.79 120 110.9 119 132.79 120 66.4 120.0 55.5 119.0 66.4 120.0

IA 200 -10 4452 -81 0 0 0.50 -10.0 11.13 -81.0 0.00 0.0

IB 200 -130 4452 159 0 0 0.50 -130.0 11.13 159.0 0.00 0.0IC 200 110 4452 39 0 0 0.50 110.0 11.13 39.0 0.00 0.0

RLY-2


VA 132.79 0 119.17 -1 132.79 0 66.4 0.0 59.6 -1.0 66.4 0.0VB 132.79 -120 119.17 -121 132.79 -120 66.4 -120.0 59.6 -121.0 66.4 -120.0

VC 132.79 120 119.17 119 132.79 120 66.4 120.0 59.6 119.0 66.4 120.0

IA 200 170 4784 -81 0 0 0.33 170.0 7.97 -81.0 0.00 0.0

IB 200 50 4784 159 0 0 0.33 50.0 7.97 159.0 0.00 0.0

IC 200 -70 4784 39 0 0 0.33 -70.0 7.97 39.0 0.00 0.0

Aspen Output

Pre Fault

Aspen Output

Fault 1

Aspen Output

Fault 2

Aspen Output

Post Fault

Load from Line to B us (LOAD BUS for Prefault)


Secondary

Test Set

Secondary

Test Set

Secondary Test

Set

Figure 49: Test Case #1 Values

Pre-Fault Fault 1

2

1

[email protected]@180

0.50@ 10RLY

RLY

I IA

I α

−

−

= = =

−

o

o

o

2

1


0.33@ 130RLY

RLY

I IB

I α

−

−

= = =

−

o

o

o

2

1

0.33@ 70

[email protected]@110RLY

RLY

I

IC I α

−

−

−

= = =

o

o

o

2

1

8.0@ 810.72@0

11.1@ 81RLY

RLY

I IA

I α

−

−

−

= = =

−

o

o

o

2

1

[email protected]@0

11.1@159RLY

RLY

I IB

I α

−

−

= = =

o

o

o

2

1

8.0@39

[email protected]@39RLY

RLY

I

IC I α

−

−

= = =

o

o

o

Figure 50: Test Case #1 Alpha Plane Calculations

End-to-End Testing

RLY-1


VA132.79 0 57.74 -4 132.79 0 66.4 0.0 28.9 -4.0 66.4 0.0

VB 132 79 120 138 9 123 132 79 120 66 4 120 0 69 5 123 0 66 4 120 0

Aspen Output

Pre Fault

Aspen Output

Fault 1

Aspen Output

Fault 2

Aspen Output

Post Fault PRE FAULT FAULT 1 Post FaultSecondary

Test Set

Secondary

Test Set

Secondary Test

Set




VAVB 132.79 -120 138.9 -123 132.79 -120 66.4 -120.0 69.5 -123.0 66.4 -120.0

VC 132.79 120 138 123 132.79 120 66.4 120.0 69.0 123.0 66.4 120.0

IA 200 -10 15195 -83 0 0 0.50 -10.0 37.99 -83.0 0.00 0.0

IB 200 -130 235 -89 0 0 0.50 -130.0 0.59 -89.0 0.00 0.0

IC 200 110 236 -79 0 0 0.50 110.0 0.59 -79.0 0.00 0.0

RLY-2


VA 132.79 0 120.1 -1 132.79 0 66.4 0.0 60.1 -1.0 66.4 0.0VB 132.79 -120 132.2 -119 132.79 -120 66.4 -120.0 66.1 -119.0 66.4 -120.0

VC 132.79 120 132.4 119 132.79 120 66.4 120.0 66.2 119.0 66.4 120.0

IA 200 170 1658 -80 0 0 0.33 170.0 2.76 -80.0 0.00 0.0

IB 200 50 235 91 0 0 0.33 50.0 0.39 91.0 0.00 0.0

IC 200 -70 236 101 0 0 0.33 -70.0 0.39 101.0 0.00 0.0

Aspen Output

Pre Fault

Aspen Output

Fault 1

Aspen Output

Fault 2

Aspen Output

Post Fault

Load from Li ne to Bus (LOAD BUS for Prefault)


Secondary

Test Set

Secondary

Test Set

Secondary Test

Set

Figure 51: Test Case #2 Values

Pre-Fault Fault 1

2

1


0.50@ 10RLY

RLY

I IA

I α

−

−

= = =

−

o

o

o

2

1


0.33@ 130RLY

RLY

I IB

I α

−

−

= = =

−

o

o

o

2

1

0.33@ 70 [email protected]@110

RLY

RLY

I IC

I α

−

−

−

= = =

o

o

o

2

1

2.76@ 800.072@3

37.99@ 83RLY

RLY

I IA

I α

−

−

−

= = =

−

o

o

o

2

1


0.59@ 89RLY

RLY

I IB

I α

−

−

= = =

−

o

o

o

2

1

0.39@101 [email protected]@ 79

RLY ALPHA

RLY

I IC

I

−

−

= = =

−

o

o

o

2

1

0.66@ 78.40 [email protected]

13.06@ 83RLY

ALPHA

RLY

I I

I

−

−

−

= = =

−

o

o

o

2

1

1.07@ 80.62 [email protected]

12.44@ 83.0RLY

ALPHA

RLY

I I

I

−

−

−

= = =

−

o

o

o


End-to-End Testing

IMAG (Iremote/Ilocal)



Iprefault

Ifault 1

RESTRAINT

REGION

TRIP

REGION

IAfault 2

I0fault 2I2fault 2

IBfault 2ICfault 2

REAL (Iremote/Ilocal)


End-to-End Testing

While it is possible to test the characteristics of the alpha plane, end-to-end testing is designed to

apply real faults and observe reactions. With this in mind, the simple differential philosophy of

“only trip when fault is between the two relays” still applies with the new characteristic and the

following results will occur when the standard battery of tests are applied.1 23 5 4 7 8 116910

RLY-1

RLY-2



RLY-1 ZONE 1

RLY-1 ZONE 2

RLY-2 ZONE 2


RLY-2 ZONE 1

-1 -2


Test RLY-1 RLY-2






6 No trip No trip

7 No trip No trip

8 No trip No trip9 No trip No trip

10 No trip No trip

11 No trip No trip

Figure 55: End-to-End Test Results with Line Differential Scheme Applied

End-to-End Testing



Chapter 4Conclusion

End-to-end testing requires additional software to create test plans, modern test equipment, and good

communication between the relay testers at each end. Once these three items have been resolved, end-to-

end testing simply requires a few extra test procedures when all the protective relays, communication

equipment, and relay settings are working properly.

The details of the different communication schemes (POTT, PUTT, etc) can be confusing, but all the

schemes provide the same results as per the following chart.

RLY-1 RLY-2 RLY-1 RLY-2 RLY-1 RLY-2

Trip 87 in 0

cycles

Trip 87 in 0

cycles RLY-1 RLY-2 RLY-1 RLY-2

1Trip Zone-1

in 0 cycles

Trip Zone-2

in <3 cycles

Trip Zone-1

in 0 cycles

Trip Zone-2

in <3 cycles

Trip Zone-1

in 0 cycles

Trip Zone-2

in <6 cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

2Trip Zone-2

in <3 cycles

Trip Zone-1

in 0 cycles

Trip Zone-2

in < 3 cycles

Trip Zone-1

in 0 cycles

Trip Zone-2

in <6 cycles

Trip Zone-1

in 0 cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

3Trip Zone-1

in 0 cycles

Trip Zone-1

in 0 cycles

Trip Zone-1

in 0 cycles

Trip Zone-1

in 0 cycles

Trip Zone-1

in 0 cycles

Trip Zone-1

in 0 cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

4Trip Zone-1

in 0 cycles

Trip Zone-1

in 0 cycles

Trip Zone-1

in 0 cycles

Trip Zone-1

in 0 cycles

Trip Zone-1

in 0 cycles

Trip Zone-1

in 0 cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

5Trip Zone-1

in 0 cycles

Trip Zone-1

in 0 cycles

Trip Zone-1

in 0 cycles

Trip Zone-1

in 0 cycles

Trip Zone-1

in 0 cycles

Trip Zone-1

in 0 cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

Trip 87 in 0

cycles

6Trip Zone-3

in 60 cycles

Trip Zone-2

in 20 cycles

Trip Zone-3

in 60 cycles

Trip Zone-2

in 20 cycles

Trip Zone-3

in 60 cycles

Trip Zone-2

in 20 cycles No trip No trip No trip No trip No trip No trip

7Trip Zone-2

in 20 cycles

Trip Zone-3

in 60 cycles

Trip Zone-2

in 20 cycles

Trip Zone-3

in 60 cycles

Trip Zone-2

in 20 cycles

Trip Zone-3


8 No tripTrip Zone-3

in 60 cycles No trip

Trip Zone-3


Trip Zone-3


9Trip Zone-3


Trip Zone-3


Trip Zone-3

in 60 cycles No trip No trip No trip No trip No trip No trip No trip

10 No trip No trip No trip No trip No trip No trip No trip No trip No trip No trip No trip No trip

11 No trip No trip No trip No trip No trip No trip No trip No trip No trip No trip No trip No trip

Pilot Wire Phase Comparison L ine DifferentialPOTT PUTT DCB

Figure 56: End-to-End Test Results with All Schemes

End-to-End Testing



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End-to-End Testing



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End-to-End Testing



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GE Power Management (1601-0089-P2 (GEK-113317A)) D60 Line Distance Relay: Instruction Manual Markham, Ontario, Canada, www.geindustrial.com

GE Power Management (1601-0090-N3 (GEK-113280B)) T60 Transformer Management Relay: URSeries Instruction Manual Markham, Ontario, Canada, www.geindustrial.com

Beckwith Electric Co. Inc. M-3420 Generator Protection Instruction Book

Largo, FL, www.beckwithelectric.com

Beckwith Electric Co. Inc. M-3425 Generator Protection Instruction Book Largo, FL, www.beckwithelectric.com

Beckwith Electric Co. Inc. M-3310 Transformer Protection Relay Instruction Book Largo FL www beckwithelectric com

End-to-End Testing

A I i l (B ll i 1 FMS 7/99) T FMSS ifl h M t dT tS it h



Avo International (Bulletin-1 FMS 7/99) Type FMS Semiflush-Mounted Test Switches

Cutler-Hammer Products (Application Data 36-693) Type CLS High Voltage Power Fuses

Pittsburg, Pennsylvania

GE Power Management, PK-2 Test Blocks and Plugs

After the fault…now what? A technician’s perspective on Trip fault analysis. (PowerPoint

presentation

should

only

provide

visuals)

This

is

a

subject

that

is

best

taught

when

the

students are drawn in and not sitting reading power point slides. Quick visuals to draw the students into



g g p p

the example are more important then specifics of that example. Diversion from lecture to have students line up simple faults to vectors and solving a problem as a group allow experienced students to help the newer student sitting next to them.

I. You enter the sub after a transmission line trips, maybe trips and recloses – now what. II. What it used to be:

a. Lights off…good b. Lights on…good lets go get coffee…Story of Meridian – cogen – CJ Line reclose. c. “It’s been doing that for 20 years.”

i. Example of space shuttle doing cold launches – we did it before – must be ok. ii. A lot of companys have operated that way: BP, the coal mines in WV, UTAH,

Chili

d. People used to be very tolerant of unreliable electricity…then we were cursed with: i. The alarm clock ii. The VCR iii. The CPU iv. Ugh!!!!

III. “The best time to find your stuff is broken is during a “good” trip” a.

Usually

engineering

disasters

are

a

series

of

bad

practices

developed

over

time

b. The grid is actually very forgiving of bad workmanship but the cost when it adds up is

not pleasant. (pictures of engineering/utility disasters) c. With the combination of old and new equipment the best “tactical” view is the relay

IV. Lets first review…what do transmission faults look like a. WHY do we need to know this. If you see current go high on an osligraph –that’s the

fault right? (use the mile hi to altrurs line trip on Ir when load transferred after hilltop line trip as example)

i. Show PPT slide with 3 phase from mile hi to alturus



1. What fault is this? (class should say 3 phase at a glance – good trip right?)

ii. Now show vectors iii. Now tell class about hilltop line trip. Note that the trip was I residual. It was set

too sensitive for the lines purpose and we changed the settings. b. First allow them time to draw it on their paper then show PPT slides c. 2 phase d. Phase to ground e. Three phase

V. Now that you walk in what do you look at (develop this section as discussion. Be open to student concepts that make sense.) a. TARGETS

i. What if you have relay target without breaker count 1. Did a breaker not trip and the squirrel blew clear or blew a downstream

fuse (district lineman got the overtime and you deserved it :.) ii. Targets vs. reclosure blocking relay (50/51)

1. What if two trips, good to lockout but no 51 targets? 2. What if B phase only trip with 4 relays? 3 relays?

iii. Targets vs. reported fault location/type (zone targets) iv. Draw 1 line of Klamath with three lines and two circuit switchers (explain that

the transformer has diff and neutral OC and the bus has no bus protection and all relays are electromechanical. Now have 3L40 fail and the three lines go on zone 2. Is this a reasonable response? Found transformer neutrals not tripped – I neutral not sensitive enough

1. PPT Hilltop 230KV breaker 1L12 (time till BFR????) 2. 2 cycle 3. 5 cycle 4. Reclose time if available

c. DFR: (especially nifty if you have electromechaincals)



i. What is the advantage of the DFR 1. Extended records (CJ Line RX, electromechanicals) PPT 2. Nearby device values 3. 3L8 PPT

a. That’s a mechanical failure (terry yells) note current b. (terry says its relays) show TIR value

4. RX failure on CJ line d. SER:

i. Also available in other microprocessor relays ii. Did the station sequence/coordinate properly. iii. Did the right phase trip. iv. Remember that CJ Reactor PPT

a. We can now time out the BFR timing and watch the line trip and see how long it took between phases, and time till recovery.

e. HISTORY: i. Trip count cards (do we have a history of B to ground?)

1. Malin 3L179 with cows going by. (PPT) ask them what do they see weird to start with

2. Story of Bly sub 69KV fault (make example quick) 3. Shop records (history of trips on FPR type J..115KV..make example

quick) f. SCADA:

i. Reports of other trips (example of 69KV and 115KV trip at Fishole under built going to 3 phase) (make example quick but draw it up on the board)

g. LIGHT BULBS AND ANNUNCIATORS:

2. Then show event report and ask what kind of fault PPT 3. Tell them down stream motors, etc smoked all over. 4. Then tell what you found at the LTC open circuit and boomed! 5. Then draw in the delta wound transformers downstream.

II Loss of Power Line carrier at Chiloquin 1 DUTT t i i 230KV li PLC



1. DUTT tripping 230KV line PLC 2. Show EVE PPT 3. Ask if there seems to be a problem 4. Describe event and how it bypassed standard test switch testing that comm.

Techs do. (fault cleared at remote end before time delay in busted PLC would PU)..ask if Zone two should hardly every happen (yes in some cases of step distance..but what if always..Alturus SVEC 69KV line and it magically ended)

III Hilltop line far side didn’t trip 1. Draw line with Breakers and PT 2. Show EVE PPT 3. Other end tripped? See voltage after the trip.



Note: I couldn’t get our copier to scan our dot matrix SER report soI copied it word for word just for you.



A 21:14:50.074 # 348 CS 11L2 BPA Manual Trip Applied (TX)

A 21:14:50.916 # 392 PCB 4019 C ph Open (52B)

A 21:14:50.917 # 354 50/62BF2 Relay Fail (62AL2)

A 21:14:50.918 # 500 PCB 4019 B Ph Open (52B)

A

21:14:50.919

#

496

PCB

4591

A

PH

Open

(AVR

16).

.

.

A 21:56:56.174 # 281 PCB 4019 Manual Close Applied (TIR‐

218)N 21:56:56:221 # 499 PCB 4019 A Ph Closed (52b)

N 21:56:56:222 # 500 PCB 4019 B Ph Closed (52b)

N 21:56:56.224 # 501 PCB 4019 C Ph Closed (52b)



10 02/08/10 08:12:07.946 CA T +17.49 1 TIME ZONE2 EN A C 51

13 01/30/10 12:08:54.833 CA +16.93 1 SOTF ZONE2 EN A C

14

01/30/10

12:08:53.760

CA

T

+17.43

1

TIME

ZONE2

EN

A

C

5117 01/28/10 11:43:08.787 CA +17.20 1 SOTF ZONE2 EN A C

18 01/28/10 11:43:07 714 CA T +17 55 1 TIME ZONE2 EN A C 51




20 01/25/10 13:17:55.330 CA +16.69 1 SOTF ZONE2 EN A C


25 12/23/08 12:54:48.573 CA +16.92 1 SOTF ZONE2 EN A C

26 12/23/08 12:54:47.484 ABC T +17.29 1 TIME ZONE2 EN A B C 51

29 12/16/08 12:05:26.650 CA +16.63 1 SOTF ZONE2 EN A C




PHASOR DIAGRAMS II

Fault AnalysisRon Alexander – Bonneville Power Administration

For any technician or engineer to understand the characteristics of a power system, the use of phasors and polarity are essential. They aid in the understanding and analysis of how thepower system is connected and operates both during normal (balanced) conditions, as well asfault (unbalanced) conditions. Thus, as J. Lewis Blackburn of Westinghouse stated, “a soundtheoretical and practical knowledge of phasors and polarity is a fundamental and valuable

”



resource.”

A

C

BBalanced System

A

C

B

Unbalanced System

With the proper identification of circuits and assumed direction established in a circuit diagram(with the use of polarity), the corresponding phasor diagram can be drawn from either calculatedor test data. Fortunately, most relays today along with digital fault recorders supply us withrecorded quantities as seen during fault conditions. This in turn allows us to create a phasor diagram in which we can visualize how the power system was affected during a fault condition.

FAULTS

Faults are unavoidable in the operation of a power system. Faults are caused by:

• Lightning

• Insulator failure

• Equipment failure

• Trees

• Accidents

• Vandalism such as gunshots

•Fires

• Foreign material

Faults are essentially short circuits on the power system and can occur between phases and

As previously instructed by Cliff Harris of Idaho Power Company: Faults come uninvited andseldom leave voluntarily. Faults cause voltage to collapse and current to increase. Faultvoltage and current magnitude depend on several factors, including source strength, location of fault, type of fault, system conditions, etc. Faults must be isolated from the power systemquickly in order to minimize damage to equipment, the environment, or the power system in

general, as well as to eliminate the hazard to people. Fault angle is the angle of the faultcurrent relative to it’s respective voltage. The angle of the fault current (PF) is determined for phase faults by the nature of the source and connected circuits up to the fault location. For ground faults, you also must consider the type of system grounding.



Typical fault angles on open wire transmission lines are:

7.2-23kV = 20-45˚ lag23-69kV = 45-75˚ lag69-230kV = 60-80˚ lag230kV and up = 75-85˚ lag

For faults on transmission lines, this angle is a function of the characteristics of the transmissionline. High voltage transmission lines generally utilize large conductors, which characteristicallyhave high inductance and low resistance. Thus the fault angle (current lagging voltage) will behigh, usually in the range of 70-85˚. Lower voltage transmission lines usually employ smaller conductor, with higher resistance than larger conductors. Typical line fault angles are in the 40-

70˚ range. Fault resistance, especially with grounded faults, needs to also be taken intoconsideration too as caused by tower footings, tree limbs, ground, arc length through air, or other factors can also influence the fault angle.

Key points on making phasor diagrams from J. Lewis Blackburn’s Protective Relaying –Principles and Application, Chapter 3:

Common pictorial form for representing electrical and magnetic phasor quantities uses theCartesian coordinates with x (the abscissa) as the axis of the real quantities and y (the ordinate)as the axis of imaginary quantities. (see figures below)

+jX

+R

+Y

+X +P

Impedance Current & Voltage Power

+Q



In normal practice, the phasor represents the rms maximum value of the positive half cycle of the sinusoid unless otherwise specifically stated.

Phasors, unless otherwise specified, are used only within the context of steady state alternatinglinear systems.

The term “phasor” can also be applied to impedance, and related complex quantities that arenot time dependent.

While represented as phasors, the impedance and power “phasors” do not rotate at systemfrequency.

The international standard is that phasors always rotate in the counterclockwise direction.However, as a convenience, on the diagrams the phasor is always shown “fixed” for the givencondition.

Phasor diagrams require a circuit diagram. The phasor diagram… has a indeterminate or vague meaning unless it is accompanied by a circuit diagram.

The assumed directions and polarities are not critical, as the phasor diagram will

confirm if the assumptions were correct, and provide the correct magnitudes andphase relations.These two complementary diagrams (circuit and phasor) are preferably keptseparate to avoid confusion and errors in interpretation.

Nomenclature for Current and Voltage: ‘Unfortunately there is no standard nomenclature for current and voltage, so confusion can exist among various authors and publications. Thenomenclature in [Blackburn’s] book has proven to be flexible and practical over many years of use, and it is compatible with power system equipment polarities.

Current and Flux. The direction [of current or flux] is that assumed to be the flow during thepositive half cycle of the sine wave.

Th i l b i t i i t d i t t i i t f

Voltage: Voltages can be either drops or rises. Much confusion can result by not clearlyindicating which is intended or by mixing the two practices in circuit diagrams. This can beavoided by standardizing on one and only one practice. As voltage drops are far more commonthroughout the power system, all voltages are shown and always considered to be drops from ahigher voltage to a lower voltage. This convention is independent of whether the letter V or E is

used for the voltage.Voltages (always drops) are indicated by either (1) a letter designation with doublesubscripts, or (2) a small plus (+) indicator shown at the point assumed to be at arelatively high potential.It may be helpful to consider current as a “through” quantity and voltage as an“ ” tit



“across” quantity.

Phasor and Phase Rotation “Phasor” and “phase rotation” are two entirely different terms,although they almost look alike. AC phasors are always rotating counterclockwise at the systemfrequency.

In contrast, phase rotation or phase sequence refers to the order in which thephasors occur as they rotate counterclockwise. The standard sequence today is a, b,c; A, B, C; 1, 2, 3; or in some areas R, S, T.

CLASSROOM LESSONS:

Let’s try applying what we have learned by drawing in the classroom a phasor diagram for eachof the given fault types. We can make a diagram for pre-fault, fault, and post-fault. This is anopen discussion!

SINGLE PHASE FAULTS

Single phase faults are the most common. When viewing the faulted line, the phase voltagecollapses and its current increases while also lagging the voltage by some value



collapses, and its current increases while also lagging the voltage by some value.

Pre-Fault Fault



Post-Fault

3 PHASE FAULTS

A 3 phase fault reduces all three voltages and causes a large increase and usually highlylagging fault current symmetrically in all three phases. The angle of the lag is determined by thesystem.



Now, let’s reverse our thinking and write in on the above graph what you think a three-phasefault would look like.

Use these values:

Voltages shrink from 115kv to 54kV line – ground. What phase angles might they be at???

Current increases from of about 200A to what??? And what phase angles might they be at???

This is a real 3 phase fault. What do you see? Is it different than what you predicted? Why?



Pre-Fault Fault



Post-Fault

PHASE TO PHASE FAULTS

Phase to phase faults are sometimes the most difficult to understand. The faulted phasevoltages (i.e.: b and c phases) collapse from their normal position and the phase angles canswing toward each other. During that time, current magnitudes increase as one current will lag

the faulted phase to phase voltage value (Vbc) while the other phase current will be 180˚

out.



Pre-Fault Fault



Post-Fault

SUMMARY NOTES FOR PHASORS AND IN-SERVICE READINGS

INTRODUCTION TO PHASORS Phasor Notation

A standard naming convention for phasors (labeling and short hand notation) is as follows:(1) Voltage phasor notation subscript labels signify a head minus tail instantaneous voltagedifference (potential drop between point 1 and point 2). e.g., point A and point B.(2) Current phasor notation subscript labels signify a tail towards head instantaneous currentdirection (current flowing from point 1 to point 2). e.g., point A to point B.The following are examples of phasor labeling and its corresponding shorthand notation.



Notation is V A − VN = V AN

Notation is V A − VO = V AO

Notation is V AN − VBN = V AB

Notation is current flow from V AN to VBN = I AB

Note: V A and I A are short hand for V AN and I AN (the wye equivalent voltage and current).

Although the above naming convention is now considered standard, somewhat anyway, a fewtextbooks show subscript notation reverse. That is, V AO is shown as VOA or V AB is shown as VBA.This reverse notation simply means they go tail to head when naming the voltage vectors(phasors). The “O” subscript is just indicating the opposite end (or origin) of the vector.

Even though there are two basic ways of assigning double subscript notation, which addsconfusion, both formats are correct if all your vectors are assigned against the same referencedirection. Why are they both valid? This is because AC measurements oriented against the

negative half of a sinusoidal wave look identical to those oriented against the positive half. Inother words, if you connect your test circuit reference up reverse, and take all your readingsreverse, the phasor readings would be the same as if they were all referenced and takenforward. Unfortunately, the confusion doesn’t stop here.

Some text books will show notation indicating the direction of voltage rise for generating sourcesand the direction of voltage drop for loads, but utilize a different character symbol (E or V) for the type of voltage. For example, ENA for a generator source and V AN for a load connected to

the generator. “E” being an EMF source and “V” being a voltage drop. You may also findsubscripts (such as for V AO) described as V AA´ or V Aa .

A few textbooks use (open arrows) for voltage phasors and (closed arrows) for

N V A

O V A

B V A

AI

B

In assigning subscript notation, it may help to think of how you would instrument and measurethe circuit with a voltmeter, ammeter, and phase angle meter. Since the inputs of your measurement instruments represent an actual resistive load, they generate the sameinstantaneous voltage across their terminals as the system being measured. The instantaneousdirection across the phase angle meter terminals will align with the instrument polarity markings

(if current and voltage leads are connected correctly). Because of this, you can verify your diagram and notation labels by visualizing how you would connect test leads to take “in-service”

measurements. For voltage, you would want to visualize this as your red (±) “polarity” lead fromyour test set, or phase angle meter, goes to the first subscript character and black “non-polarity”lead goes to the second character. (This is analogous to a DC voltage measurement). For

current, connections to the test instrument would be such that current flowed into the red (±)“ l it ” l d f th fi t b i t t ti d t th bl k “ l it ” l d t th d



“polarity” lead from the first subscript notation and out the black “non-polarity” lead to the secondnotation character. (This is also analogous to DC as a current measurement). For current leadconnections, you would be inserting a low resistance shunt between the notation subscripts.From a voltage only point of view, the measurement for current ends up looking the same as for voltage, since you have to break open the circuit and insert a burden that develops a voltage inyour test instrument. An additional note: When measuring DC values with a DC meter, red to

positive and black to negative would read as a positive voltage (analogous to 0° AC), and a

reversed connection would read negative (analogous to 180° AC). For a DC meter, DCindication is also a mathematical difference in potential (red input “minus” black input =measured voltage).

In summary, the double subscript labeling convention for voltage is voltage drop from point A topoint B (V AB), and current is labeled for direction as flowing from point A to point B (I AB). For example, I AN is current flowing from point A to point N and is said to be flowing from phase A tothe Neutral connection. Please note that line current is truly phase-to-neutral current for wyeconnected systems, and is also the current of an “equivalent wye” in delta connected systems.This is why I A can be short hand for I AN when talking line current.

Coordinate Grids

Most utilities, such as BPA, also have a convention for drawing phasors on an “x - y” coordinategrid. Except for the positive direction of reactive power, they follow standard academicconvention. Even so, if you prefer to explain power with positive reactive power pointing up, asdone in academic textbooks, your vector mathematics will take the form of S = V I * for plotting

Volt-Amps. “S” is apparent power, and “∗” means to conjugate the current phasor angle beforemultiplying voltage and current vectors. Conjugate means to reverse the sign of the phasor angle (change to + if -, or to - if +). To eliminate the need for changing the sign of an angle, andmaking extra calculations, phasor drawings indicate reactive power flow as positive when

pointing down.

Using this style of power flow coordinates allow the vector direction of current to describe thedirection of real and reactive power flow (“+” OUT; “ ” IN) Pointing inductive power flow

+jX

+R

+Y

+X +P

Impedance Current & Voltage Power

+Q



A quick comment about in-service measurements that is related to plotting phasors oncoordinate grids. Try to maintain a single source as your reference for a complete set of in-

service readings. This will assure that everything measured is comparable against any other measurement, since they will all have a common reference. Of course, this is not alwayspossible, because of physical distance between measurement points (such as measurements attwo different substations). In cases where different references are used, and a phasor comparison is needed between the two sets of measurements, the reference sources will needto be linked by an independent but verifiable quantity. This is typically done by selecting acommon power system phase voltage, such as “A” phase, because larger utilities maintaincommon connections (per phase) across the entire network of 115 kV through 500 kV systems.On lower kV systems, you are not going to find yourself so lucky, so watch what you use as a

measurement reference.

Plotting Phasors From In-Service Measurements

Use a similar standard convention when describing “phasor” vectors, because it will keep youfrom making a directional error if you stick to only one convention. Phasor notation is based onmeasuring system quantities at a substation and treating each measurement as if it were for aload. The connection point of your voltage is your reference, and all current measurements are

taken assuming current flow away from the voltage reference point (i.e., all the lines connectedto a substation bus). Because a power system is bi-directional, meaning power flow can beeither forward or reverse, system current is also. You must “assume” a standard direction for allmeasurements, take all measurements as if voltage and current are existing in the assumeddirection, and let the readings tell you which way currents are actually flowing. Current “OUT”

will be in-phase with voltage and current “IN” will be 180° out-of-phase. Basically, you treatevery line connected to a bus as a load, regardless of whether you know it is or isn’t.

Here is a case in point:If in-service readings were taken on both ends of a transmission line, and done correctly by twoindividuals, the values recorded on the in-service test forms would show both ends have per phase voltages of nearly the exact same magnitude and phase angle. The current

than previously described for in-service measurements of a transmission line connected to asubstation bus. If you think about a transmission line as a single piece of power systemequipment, with two system connections, you should realize that current flow was assumed intothe device. You should also realize that taking in-service readings on a three terminal linewould also have the assumed current flow inward from all three terminals.

Drawing, or plotting, a current vector requires special care when comparing them againstvoltage vectors. You draw a current vector against a voltage vector such that the current

phasor points in the same direction as the voltage phasor when there is a 0° phase difference

(such as for current into a purely resistive load). In visualizing an in-phase measurement (0° difference), think of a current phasor as pointing in the same direction as the voltage phasor when measuring current into and the voltage across a resistor In this case voltage across is



when measuring current into and the voltage across a resistor. In this case, voltage across isalso the voltage drop created by current flowing through the resistor. When loads are not purelyresistive (resistance plus reactance), it is the “real” portion of the rectangular components for the

AC voltage and current phasors that will be in phase. Basically, for phasor drawings of any loadwith an assumed direction of current flow into the load, the real component of current is drawnto point in the same direction as the real component of the voltage created by the current flow.Be aware that, when plotting phasors using rectangular coordinates, the “real” component of

voltage and current will be in phase for current into a load, but will be 180° “out” if current iscoming from a source.

PHASOR MATH:

In order to calculate reactance (Vars), Impedance, and more, here are some points toremember:

Formulas for Z, I, V, P, Q, VA, PF, and RF in AC:Basic relationships

V=IZ,Volt-Amps=VI

Z = Impedance in ohmsIn addition:

P.F. = COS θ

Real Power

P = VI cos θ, units Watts

Reactive Power

Q = VI sinθ, units Var (VA reactive)Lagging load (positive vars)Leading load (negative vars)

Pythagorean Theorem: c² = a² + b²



Pythagorean Theorem: c = a + b

Vectors may be expressed either in rectangular or polar coordinates.

Rectangular Polar

R + jX Z ∠θ° R = Z cos θ Z = √(R2 + X2) jX = jZ sin θ θ = arc tan (X/R)

or tan-1 (X/R)

The equivalent value of the operator j is √-1. Therefore, assuming a vector of +1∠0° or unity atzero angle, multiplying:

by j rotates it counter clockwise to a position of 1∠90°,

by j2 = √-1 x √-1 = -1 rotates from original position to 1∠180°,

and j3 = -1 x j or 270° from the original position.

Rectangular Coordinate Math:

Adding & Subtracting (easy)

R

jXL

Z

θ

Examples of math using rectangular coordinates: Addition: Subtraction: Multiplication:

4 + j2 4 + j2 4 + j2-2 - j3 -2 - j3 -2 - j3

2 - j1 6 + j5 - j12 - j26

-8 - j4

-8 - j16 - j26 (since j2 = -1)-2 - j16 is the product.

Polar Coordinate Math:



Multiplication (easy)

Division (easy)

Examples of math converting rectangular to polar coordinates:

4 + j2 = A∠θ1 -2 - j3 = B∠θ2

A = √(42+22) = √20 = 4.48 B = √(-22+-32) = √13 = 3.61

θ1 = arc tan (2/4) = arc tan 0.5 = 26.5° θ2 = arc tan (-3/-2) = arc tan 1.5 = 56.3°

A = 4.48∠26.5° B = 3.61∠(56.3° + 180°)

Alternate example of polar to rectangular, and rectangular to polar conversion (referencing

graph below):

P ⇒ Rx = r cosθ y = r sinθ

R ⇒ P

θ = tan-1( y/x )

°∠=°+°∠°∠°∠ 30200)1020(20)x(10=1020x2010

°∠=°−°∠=°∠

°∠105.0)1020(20)/10(

1020

2010

References for previous oscillography:

Single phase fault:



Three phase fault (on the 500kV system, C phase opens late):



Phase to phase fault (b-c phase):



Never to be overlooked are the acknowledgements and assistance by:

• Protective Relaying Principles and Applications by J. Lewis Blackburn

• Bonneville Power Administration System Protection and Control Branch

• Steve Laslo, BPA Technical Training

• Richard Becker, BPA Electrical Engineer

• Cliff Harris, Idaho Power Company



PMUs and SynchrophasorsGalina S. Antonova, ABB Inc.



Long term

Voltage Collapses



Protection SCADA /EMS

0.001 sec. 0.01 0.1 1 10 100

WAMPC(System Emergency Control)

Short-circuits

Long term

stability

Cascade Tripping

Blackouts



A phasor is a complex number that representsthe phase and magnitude of an AC waveform



.

Xm cos (2 π 60 t + φ) Xm / 2 e jφ

-1

-0.5

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Start of the second

v

v(t ) = 2 V cos (ω 0 t + ϕ)



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Source: The Wide Area View: Synchrophasors An Intelligent Utility Reality

Webcast, PJM SynchroPhasor Technology Deployment, July 8, 2010

!#



Power System

$

GPS Satellite Time Synchronization

2 2



APPLICATIONS

. . . data displayand real time

control actions

`

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ETHERNET

Streaming synchrophasordata on the network to thePDC for archiving . . .

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2 2

2

PMU

WAMS

LocalMeasurement

- Bus Voltages- Line Currents- Frequency

df/dt

PDC- Monitoring- Supervision- Data Archive- Data Server

Substation GPS

System Operations

2



Control andProtection

Applications

- State Calculation- Voltage Stability- Line Thermal Mon- More . . .--

Control andProtective

Actions

- df/dt- More . . .- Binary Inputs

WAPS / WACS

- Data Server

CommunicationNetwork

IEEE 1344C37.118Local

Control Applications- Over/under Voltage- Overcurrent- Over/under Freq- Positive df/dt- Negative df/dt- Invented Functions- Binary Outputs

Feedback Control

SCADAEMS

RTU

Analog andStatus Data

Control

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TransmissionLine

GPS Time InputPMU Functions

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InstrumentTransformer Circuits

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PDC for archiving . . .

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. . . data displayand real time

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APPLICATIONS

ETHERNET

2 22

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• Analog

– Analog Microwave channels

– Leased Telephone Lines– Multiplexer voice channels

• Digital

– Digital Microwave channels– Leased Digital Data Service

– Multiplexer data channels



p

• Dedicated Fiber Optic Cable

– Singlemode Fiber

– Multimode Fiber

• Power Line Carrier (PLC)

– ON / OFF Carrier– Frequency Shift Carrier (FSK)

The power line is already there!

It originates and terminates at the desired locations

The power line is a robust medium that is designed forreliable service

Under complete control of the utility

d i l i h li f l



• Increased signal attenuation may occur at the line fault,

or adjacent to a line fault• Noise levels may increase at the fault, disguising the

valid signal

• The high frequency PLC signal must be coupled to thepower line

– Tuner, traps, CCVT’s

•Single Function,– Once specific function performed

• ON / OFF for distance DCB schemes

• FSK for distance POTT schemes or transfer trip (BFR)• Phase comparison relaying (ON / OFF or FSK)

• Voiceor telemetry



Voice or telemetry

•Multifunction Single Sideband (SSB)– Capable of handling several functions simultaneously

– Protective relaying and voice, telemetry, data (SCADA)

•AM Keyed (ON / OFF)



•FSK Frequency Shift Keying

Line Trap Line Trap

CouplingCapacitor

CouplingCapacitor

230 KV / 80 Mile Line

400 Ohms

470 Ohms 400 Ohms

216 Ohms

400 Ohms 471 Ohms

216 Ohms

400 Ohms

Bus Impedance700 Ohms

Bus Impedance600 Ohms

(3) Line Impedance@ 240 Ohms

(3) Line Impedance@ 240 Ohms



On / Off Carrier

FSK Carrier

RFHybrids

Line Tuner

On / Off Carrier

FSK Carrier

RFHybrids

Line Tuner

• The range of characteristic line impedance is from 200 to800 ohms

Line Trap

Depending upon the length, andtermination, a tap can present a low

impedance at the carrier frequency



Transmitter

Line TunerImpedance Matching Transformer

SWR Meter

Line Impedance is determined by:

•Line Resistance•Line Inductance•Capacitance•Conductor Radius•Height Above the ground•Phase Separation

•Line Taps•Coupling method

• When a transmission line is terminated with an impedance that isnotequal to the characteristic impedance of the transmission line, not all of the power is absorbed by the termination

• Part of the power is reflected back, so that phase addition and

subtraction of the incident, and reflected waves create a voltagestanding wave pattern on the transmission line



Transmitter

Line TunerIncident Wave

Reflected Wave

Voltage Standing Wave

Transmitter #1Reflected Power

Line TunerImpedance Matching Transformer

SWR Meter

Ten percent or less



Transmitter #2Reflected Power

X

•Impulse

–Discrete – irregular or periodic–Superimposed or random

–Predominant on power lines

•Sources–Lightning



–Disconnect switches–Circuit breakers

–Line faults

–Rotating machinery–Arc furnaces

CC CC

INSULATED SINGLECONDUCTOR LEAD-IN

Measure He

re

Signal to Noise Ratio determined atthe receiver terminal



Carrier

Transmitter

LINE TUNER

COAX CABLE COAX CABLE

LTULTU

Carrier

Receiver

You can only improve the SNR with a larger transmitter signal, orbetter line tuning

•Noise levels for 34.5 kV and 230 – 345 kV

•More noise at higher voltage levels

230 KV

to345 kV

34.5 KVto

161 kV

AdverseWeather

-10

-20

-30

NoiseLevel(d )



230KVto

345 kV

34.5KVto

161 kV

FairWeather

-40

-50

(dBm)

100 kHz 200 kHz 300 kHz

Frequency

•Noise levels for 500 – 765 kV

•More noise at higher voltage levels

765 kV

AdverseWeather

0

-10



500 kV

765 kV

500 kV

Weather

FairWeather

-20

-30

-40

NoiseLevel(dBm)

100 kHz 200 kHz 300 kHzFrequency

AM Carrier Channel Losses

Coaxial Cable 0.1 dBLine Tuner 2.2 dB

Shunt Losses (Bus) 2.7 dBLine attenuation 7.0 dB

Fair Weather Losses 12.0 dB



Poor Weather Losses 13.5 dB

40

30

20

10

0

-10 P o w e r L e v e l d B m

10 Watt TX level

28 dBm Rx Level (40dBm - 12 dB Loss Fair Weather )

d d h l l

26.5 dBm Rx Level (40dBm - 13.5 dB Loss Poor Weather )

x

x



14

Note:The signal to noise ratio is determined atthe coupling capacitor at the receiving terminal.The signal and noise are equally attenuated bythe losses at the receiving terminal. Typical valuesobtained from IEEE PLC Guide / ANSI/IEEE Std 643-1980

-20

-30

-400 10 20 30 40 Path Attenuation

-18 dBm Adverse Weather noise level

Fair Weather S/N Ratio 63 dB[28 dB - (-35) = 63.0dB]

-35 dBm Good Weather noise level

Poor Weather S/N Ratio 44.5 dB[26.5 dB - (-18) = 44.5dB]

FSK Carrier Channel Losses



Fair Weather Losses 16.6 dB

Coaxial Cable 0.1 dB

Line Tuner 2.2 dBShunt Losses (Bus) 2.7 dBLine attenuation 13.6 dB

Poor Weather Losses 18.6 dB

40

30

20

10

0

-10 P o w e r L e v e l

d B m

1 Watt TX level (30 dBm)

13.4 dBm Rx Level (30dBm – 16.6 dB Loss Fair Weather )

11.4 dBm Rx Level (30dBm – 18.6 dB

Loss Poor Weather )

x

x



15

Note:

The signal to noise ratio is determined atthe coupling capacitor at the receiving terminal.The signal and noise are equally attenuated bythe losses at the receiving terminal. Typical valuesobtained from IEEE PLC Guide / ANSI/IEEE Std 643-1980

10

-20

-30

-400 10 20 30 40 Path Attenuation

-19 dBm Adverse Weather noise level@ Receiver Terminal

Fair Weather S/N Ratio 63 dB[13.4 dB - (-36) = 49.4dB] -36 dBm Good Weather noise level

@ Receiver Terminal

Poor Weather S/N Ratio 44.5 dB[11.4 dB - (-19) = 30.4dB]

•Phase to ground

•Phase to phase

•Mode1– Threephasecoupling



Mode 1 Three phase coupling

CC CC

LINE TUNER LINE TUNER

A

B

C

COAX CABLE



LTULTU



Carrier

Equipment

COAX CABLE COAX CABLE

Carrier

Equipment

Phase to ground is the simplest, and most frequently used because it utilizes the minimum

amount of equipment, and is fairly efficient.

It has the disadvantage of having greater signal attenuation if the soil has poor conductivity.

TuningElements

More efficient.

Better dependability as it



18

Line Tuner

Line Tuner

TuningElements

BalanceTransformer

Better dependability as itcan withstand a singlephase to ground faults.

It is not affected by poorground conductivity.

A

B

C

Line Tuner

TuningElements

TuningElements

BalanceTransformer



19

Line Tuner

Line Tuner

TuningElements

BalanceTransformer

InvertedPolarity

•Most efficient coupling technique, because itprovides the lowest losses.

•It also provides the greatest channeldependability, because it can withstand bothsingle phase to ground and phase to phase line



faults.•Not affected by poor ground conductivity.

•Most expensive technique.

•Coupling

•Transpositions

•Tapped lines•Fault Attenuation



•Carrier Frequency–Greater losses at higher frequency

•Line Construction

–Bundled conductors have lower losses

•Coupling method



•Line transpositions–A single transposition can cause as much as 6 dBloss

•Weather conditions–Frost or rain can double line attenuation

•Insulator leaka e

System Loss Calculations

Transmitter path coupling & shunt losses

Local Coaxial Cable 0.1 dBLocal Coupling Capacitor 2.2 dB

Local Shunt Loss 2.7 dB

Line Attenuation 7.0 dbSignal Loss onto transmission line 12.0 dB

Signal Level on line 40 dBm (10 Watts) – 12 db =28 dBm (631 mw)

Fair Weather Noise Level –35 dBm Fair S/N Ratio = 28 – (-35) =63 dB

Adverse Weather Noise Level –18 dBm Adverse S/N Ratio = 28 – (-18) =46 dB

Receiver path coupling & shunt losses



Receiver path coupling & shunt losses

Remote Coaxial Cable 0.1 dBRemote Coupling Capacitor 2.2 dB

Remote Shunt Loss 2.7 dBTotal system losses 17 dB

Received Signal Strength 40 dBm (10 Watts) – 17 db =23 dBm (200 mw)

ANSI/IEEE Std 643-1980

TX

TX

Hyb

Unidirectional

TX

RX

SkHyb

Bi-directional

FrequencyShift

NominalBandwidth

ChannelDelay

UnidirectionalChannel

Spacing

BidirectionalChannel

Spacing100 HZ 200 HZ 12 ms 500 HZ 1000 HZ250 HZ 500 HZ 7 ms 1250 HZ 2500 HZ500 HZ 1000 HZ 5 ms 2500 HZ 5000 HZ



2 4 4 . 9

k H z

2 4 5 . 0

k H z

2 4 5 . 1

k H z

2 4 5 . 4

k H z

2 4 5 . 5

k H z

2 4 5 . 6

k H z

500 HzSpacing

2 4 4 . 9

k H z

2 4 5 . 0

k H z

2 4 5 . 1

k H z

2 4 5 . 9

k H z

2 4 6 . 0

k H z

2 4 6 . 1

k H z

1000 HzSpacing

• A transformer tappedtoalinemay causeattenuationtothesignal



A transformer tapped to a line may cause attenuation to the signal

• The length of the tap line to the transformer may be near thequarter-wavelength of the carrier.– When a tap line is not trapped or is terminated into a power transformer, and is one

quarter wavelength of the carrier frequency in length or odd multiples thereof, themaximum out-of-phase reflected signal will occur. This reflected energy will be out

of phase with the transmitted signal and can cause signal cancellation.

• Provides high impedanceat carrier frequencies andnegligible impedance atpower frequency

• Must be designed to carryfault current

• Tuning:



• Tuning:– Single or dual frequency

– Adjustable or fixedbandwidth

– High pass

Inductance Blocking Frequency Band (kHz)

(mH) Impedance

(Ohms) 1 2 3 4

0.2

0.3

400 200 - 500 160 - 300 130 - 200 100 - 150600 250 - 500 200 - 330 160 - 230 130 - 170

400 150 - 500 140 - 400 120 - 300 90 - 200

400 100 - 500 80 - 300 60 - 120 40 - 60

600 200 - 500 160 - 300 120 - 180 100 - 140



0.5400 100 500 80 300 60 120 40 60

600 130 - 500 110 - 300 80 - 150 70 - 110

Voltage (kV) Capacitance Range (pF)

69 10,000 - 37,500115 6,000 - 47,500138 5,000 - 38,100161 4,300 - 30,500230 3,000 - 22,800



345 2,150 - 15,200500 1,400 - 10,100

Larger values of the coupling capacitors provide greater frequency bandwidth



.Grounding Switch

Surge Arrester

Optional Drain Coil

Coupling Capacitor (Xc @ f 0)

Transmission Line

TunerCabinet

60 Hz Blocking Capacitor



30

.Impedance MatchingTransformer

Adjustable Inductance

To/From PLC Terminal

.

Grounding Switch

Surge Arrester

Optional Drain Coil

Tune to block F2 Tune to block F1

To / From CCVT

Parallel Tuning Units



Impedance MatchingTransformers

F1

Tune to pass F1

F2

Tune to pass F2 Series Tuning Units

•RF Hybrids•Balanced Combiner

•High Power Combiner•Band Pass Filter



•To minimize

– Intermodulation

–Loading influences•Separation TX/TX or TX/RX

Transmission Line

Trap

Tuner

CouplingCapacitor

OutdoorCoax Cable



33

Indoor

HybridL/C Filter

To / From PLC Terminal Equipment

~~~or or

PORT 1

PORT 3

PORT 2“LINE”

PORT 4DUMMYLOAD

Tx-1

Tx-2



• Input to any port is split and appears at the two adjacentports

• Dummy load impedance must be adjusted to balance Port

2 impedance• No output appears at the opposite port



Provides isolation between transmitters and receivers

To / From

Line TunerK

Hyb

TX

RX

50 Ohm

50 Ohm

Transhybrid

Loss 40 dB

0.5 dB loss

13.5 dB loss



36

The Skewed Hybrid presents 0.5 dB of loss in the transmitting path, and13.5 dB of loss in the receiver path.Hybrids can provide greater then 40 dB of transhybrid loss when operatinginto the specified output impedance.

1. Measure and record the transmitter level at the transmitter port

2. Measure and record the level of the transmitter frequency at the receiver port.

Adjustment Procedure

2 Transmitters + 2 Receivers

Tuner



Rx1

Rx2

Tx1 Tx2

SK

R

concurrent lectures part 1

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