Transformer Protection Fundamentals

© ABB Group October 27, 2015 | Slide 1

Relion. Thinking beyond the box.Designed to seamlessly consolidate functions, Relion relays are smarter, more flexible and more adaptable. Easy to integrate and with an extensive function library, the Relion family of protection and control delivers advanced functionality and improved performance.

This webinar brought to you by the Relion® product family Advanced protection and control IEDs from ABB


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Transformer protection fundamentalsOctober 27, 2015

ABB protective relay school webinar series



Presenter

Bob Wilson

Bob graduated from Purdue University and joined Westinghouse Electric Corp. After receiving a Masters degree in Electrical Engineering from Carnegie Mellon University, Bob was a Systems Analysis Engineer responsible for software designed to automate system-wide coordination. He then transferred to Kansas City where he assumed the role of District Engineer and eventually moved to the Houston area where he currently resides.

In his current role as Regional Technical Manager, he supports ABB’s Substation Automation and Protection Division, providing technical support to customers throughout the South Central United States. Bob is a senior member of IEEE and has authored and presented several papers in power system protection at a variety of technical conferences throughout the United States. He is a Registered Professional Engineer in the states of Pennsylvania and Texas.


Learning objectives

Transformer basics

Transformer winding connections

Basic differential protection

Basic differential protection settings

Differential measurement issues

Complementary protection functions


Transformer protection

Transformer basics







Power transformer:

1. HV side bushings2. LV side bushings3. Load tap changer4. Load tap changer

operating device5. Control panel6. Oil thermometer7. Gas relay8. Radiators9. Oil conservatorN. Neutral bushings

Transformer basicsConstruction


Power transformer

Iron core

HV voltage winding

LV voltage windingMV voltage winding

Transformer basicsConstruction


Transformer basicsDifferent winding arrangements


Winding failures

Turn-to-turn insulation failure

Moisture

Deterioration

Internal and external faults Mechanical and insulation integrity

Tap changer failures

Mechanical

Electrical

Short circuit

Oil leak

Overheating

Transformer basicsTypes of failures


Bushing failures

Aging, contamination, and cracking

Flashover due to animals

Moisture

Low oil

Core failures

Core insulation failure

Ground strap burned away

Loose clamps, bolts, wedges



Miscellaneous failures

Bushing current transformer failure

Metal particles in oil

Damage in shipment

External faults

Poor tank weld

Overvoltages

Overloads


Cause of Transformer Failures* %

Winding failure 55

Tap changer failures 21

Bushing failures 10

Terminal board failures 6

Core failures 2

Miscellaneous failures 6

All causes 100

*IEEE Guide

Transformer basicsCause of failures



Transformer basics







( ) ssmhppp InIIn-In =+

This quantity cannot be directly measured

Single-phase transformer


Considerations for three-phase transformers

Winding connections

Number of windings

Core construction and operating characteristics

Three-phase transformer


No connections High voltage bushings

H1, H2, H3 => system A, B, C H0 if neutral provided

Low voltage bushings X1, X2, X3 => system A, B, C X0 if neutral provided

Tertiary Third winding Y1, Y2, Y3 => system A, B, C

Turns ratio - N High-to-low

Basic Three-phase transformer


ANSI standard

High voltage reference leads the low voltage reference by 30O

High voltage reference is in phase with low voltage reference


No phase shift Effective turns ratio = N Same applies for delta - delta

connection Auto-transformers

Wye-wye connected transformer


ANSI Standard ConnectionsHigh Voltage Low Voltage

High voltage reference phase voltage leads the low voltage reference phase voltage by 30O

Wye-delta Delta-wye


Phase shift H1 leads X1 by 30O

Effective turns ratio

3Nn =

Wye-delta connected transformer


Phase shift H1 leads X1 by 30O

Effective turns ratio

3Nn =

Delta-wye connected transformer



Transformer basics







IA-1IB-1IC-1 IA-3

IB-3IC-3

IA-2IB-2IC-2

Winding-3 Inputs(3-Winding units only)

Winding-1 Inputs

Winding-2 Inputs

Typical transformer phase differential configuration

X/1

N:1 (Phase shift δ)

M:1 (Phase shift φ)

Y/1

Z/1

Y or ∆

Y or ∆

Y or ∆

Transformer differential protection


IA-1IB-1IC-1 IA-3

IB-3IC-3

IA-2IB-2IC-2


Winding-1 Inputs

Winding-2 Inputs

Zone of protection defined by current transformers (CT’s)

X/1



Y/1

Z/1

Y or ∆

Y or ∆

Y or ∆



IA-1IB-1IC-1 IA-3

IB-3IC-3

IA-2IB-2IC-2


Winding-1 Inputs

Winding-2 Inputs

Non-trip zone for phase differential protection

X/1



Y/1

Z/1

Y or ∆

Y or ∆

Y or ∆



IA-1IB-1IC-1 IA-3

IB-3IC-3

IA-2IB-2IC-2


Winding-1 Inputs

Winding-2 Inputs

Ideally what comes in equals what goes out:IIN = IOUT

X/1



Y/1

Z/1Y or ∆

IIN

IOUT

+



IA-1IB-1IC-1 IA-3

IB-3IC-3

IA-2IB-2IC-2


Winding-1 Inputs

Winding-2 Inputs

Transformer differential protection is generally quite simple, but requires the correct application and connection of current transformers and an understanding of the power transformer winding connections, characteristics and operation.

X/1



Y/1

Z/1

Y or ∆

Y or ∆

Y or ∆

IIN IOUT



R R

RR

RR

O

O

O

Ia

Ib

Ic

nIa

nIb

nIc

n(Ia-Ic)

n(Ib-Ia)

n(Ic-Ib)

n(Ia-Ic)/CT2

n(Ib-Ia)/CT2

n(Ic-Ib)/CT2

Ia/CT1

Ib/CT1

Ic/CT1

25 MVA69kV 13.8kVCT1=250/5 CT2=1200/5

A

B

C



( )303

3

92.10458.13*3

10*25

2.20969*3

10*25

jL

H

eAI

AI

−⋅==

==

( )30.136.4240/1046

.118.450/2.209j

LSec

HSec

eupAIupAI

−⋅===

===

upeIII jLSecHSecDIFF .52.011 30

=−=+= − ==> TRIP!

Tap settingsCT secondary currents

Rated primary currents

Differential current



R R

RR

RR

O

O

O

Ia

Ib

Ic

nIa

nIb

nIc

n(Ia-Ic)

n(Ib-Ia)

n(Ic-Ib)

n(Ia-Ic)/CT2

n(Ib-Ia)/CT2

n(Ic-Ib)/CT2

Ia/CT1

Ib/CT1

Ic/CT1

25 MVA69kV 13.8kVCT1=250/5 CT2=1200/5

A

B

C


IA’= I1 + I2 + I0

IA’ nIA’

nIA’= nI1 + nI2 + nI0

nI0= n(Ia-Ic) + n(Ib-Ia) + n(Ic-Ib) = 0

IA’≠ nIA’


R R

RR

RR

O

O

O

Ia

Ib

Ic

nIa

nIb

nIc

n(Ia-Ic)

n(Ib-Ia)

n(Ic-Ib)

n(Ia-Ic)/CT2

n(Ib-Ia)/CT2

n(Ic-Ib)/CT2

(Ia-Ic)/CT1

(Ib-Ia)/CT1

(Ic-Ib)/CT1

A

B

C

CT1=250/5 69kV 25 MVA 13.8kV CT2=1200/5

Ia/CT1

Ic/CT1


IA= I1 + I2

IA

nIA

nIA= nI1 + nI2

Change CT connections from wye to delta


Issues

Tap setting

Phase Shift

( ) ( )( )30

30

.136.4240/1046

.124.750/2.209j

LSec

jHSec

eupAIeupAI

−

−−

⋅===

⋅==⋅= j30e3

011 3030=−=+= −− jj

LSecHSecDIFF eeIII ==> NO TRIP!

Tap settingsCT secondary currents

Differential current



Transformers with delta and wye windings Phase shift and magnitude (√3) compensation must

be applied Zero sequence currents for external ground faults

must be blocked Solution

Conventional differential protection CT on the wye side connected in delta CT on delta side connected in wye

Numerical protection Connect all winding CTs in wye Apply compensating factors and I0 filtering

Vendor Specific



Compensation factors for numerical relays

HIGH LOWANGLE

(H leads L)

30 0

0 0

30 0

0 0

330 0

COMPENSATINGFACTOR

H L

1 1

1 1

1

1

1

1

3

3

3 REFERENCE

3 0 0

60 090 0

120 0

150 0

180 0

210 0

240 0

270 0

300 0

330 0

ANGLE HV LEADS LV

Transformer connections

330 0 3

*ANSIAll CT'S assumed wye connected


*

*



Transformer basics







Example:Transformer data:

25MVA (Max); 69 kV to 13.8/7.967 Grd Y; Xt=7%CT1=250/5CT2=1200/5

1. Phase shift is 30 degrees, low side CF = √32. High side current 209.2(A) and low side current 1046(A)

)(924.104510*8.13*3

10*25

)(184.20910*69*3

10*25

3

6

3

6

AI

AI

L

H

==

==

Differential protection settings


3. Through fault current:

4. CT ratio: CT1=250/5 = 50 and CT2 = 1200/5 = 2405. Secondary current

IH (sec) = 209.2/50=4.18(A) IL (sec) = 1046/240=4.36(A)

6. Relay current at maximum load are: high side = 4.18 (A) low side = 4.36*√3 = 7.55 (A)

7. Tap settings are 4.2 (A) and 7.5 (A)

)(942,1407.0*10*8.13*3

10*25

)(298807.0*10*69*3

10*25

3

6

3

6

AI

AI

L

H

==

==



8. Set harmonic restraint method9. Select a linear percentage slope of 30% for

transformer with +/- 10% load tap changer 10. Select minimum operating current of 0.3pu with +/-

10% load tap changer 11. Set 87H (unrestrained) to 6.0 [times Tap]



0 1 2 3 4 5 6 7 8

1

2

3

4

5

6

IRES in pu

I DIF

Fin

pu

Operating Region

Unrestrained Operating Region

Restraining Region

IOP - MIN



0 1 2 3 4 5 6 7 8

1

2

3

4

5

6

IRES in pu

I DIF

Fin

pu


IOP - MIN0

1

1

• Margin• LTC Range • Max difference in HV & LV

CT error for min. thru-fault• Excitation Current

5-10%10%

20%

IOP - MIN

Operating Region

2%



0 1.25 2 3 4 5 6 7 8

1

2

3

4

5

6

IRES in pu

I DIF

Fin

pu

Operating Region


LTC Range - 10%

Max difference in HV & LV CT error for max. thru-fault - 20%

Margin - 5-10%



Example:

CT error = +/- 10%LTC variation = 10%Excitation current at rated voltage = 1.4%Margin = 5%

Relay minimum operating current setting:(CT error)@HV side+(CT error)@LV side +LTC + Ie +Margin = 0.1+0.1 +0.1+0.02 + 0.05=0.37 pu

Relay slope setting:

(CT error)@HV side+(CT error)@LV side +LTC + Margin = 0.1+0.1 +0.1+0.05 = 35%



0.1

1

10

100

0.1 1 10 100

I - Larger Restraint Current in Per Unit of Tap

I -O

pera

te C

urre

nt in

Per

Uni

t of T

ap

HU 35%

HU 30%

IopTH

IopMIN

Westinghouse HU electro-mechanical relay characteristic




1 32 4 5

1

2

3

4

5

6

6IRES in pu

I DIF

F in

pu

m2

Region 3Region 2Region 1

m3


IUNRES

Operating Region

Restraining Region

IOP-MIN%100⋅

∆∆

=RES

DIFF

IIm

% Slope



If LTC position is monitored improved sensitivity can be provided

In this case the minimum operate current setting and slope can be set in the range of 0.15-0.25 pu.



Transformer basics







Zero sequence current

Transformer inrush

CT saturation

Overvoltage (over-excitation)



R R

RR

RR

O

O

O

Ia

Ib

Ic

nIa

nIb

nIc

n(Ia-Ic)

n(Ib-Ia)

n(Ic-Ib)

n(Ia-Ic)/CT2

n(Ib-Ia)/CT2

n(Ic-Ib)/CT2

(Ia-Ic)/CT1

(Ib-Ia)/CT1

(Ic-Ib)/CT1

A

B

C

CT1=250/5 69kV 25 MVA 13.8kV CT2=1200/5

Ia/CT1

Ic/CT1

Zero sequence elimination

IA= I1 + I2

IA

nIA

nIA= nI1 + nI2

Change CT connections from wye to delta


The peak value of the magnetizing current is generally higher for smaller transformers

Duration of the inrush current is longer for the larger transformers

Switching instant

The maximum inrush current will happen when the transformer is switched at voltage zero transition

Statistical data indicates every 5th or 6th transformer energization will result in high values of the inrush

Inrush currentInfluencing factors


Energizing side Inductance is function of geometry. Low voltage winding that

is wound closer to the magnetic core has less impedance than the outer winding. Consequently, energizing the transformer from the LV winding will cause more inrush than energizing from the HV winding.

Typical values: LV side: magnitude of inrush current is 10-20 times the rated

current

HV side: magnitude of inrush current is 5-10 times the rated current

Remanence (residual flux) in the core Higher remanence results in the higher inrush

Impedance of the system Energizing from lower source impedance results in the higher

inrush Highest inrush generally at generating plants

Inrush currentInfluencing factors

Harmonic analysis-typical

Transformer Inrush Current

Internal Fault Current

Differential current due to:

Component Internal Fault CT Saturation Magnetic Inrush

Peak 145% 126% 244%

DC 38 0 58

Fund. 100 100 100

2nd 9 4 63

3rd 4 32 22

4th 7 9 5

5th 4 2 32

6th 6 1 4

7th 2 3 3

Internal Fault Current with CT Saturation

Values in % of fundamental© ABB Group October 27, 2015 | 52


Protection commonly uses 2nd harmonic value in % of fundamental to distinguish between inrush current and short circuit current

Short circuit current has only a small 2nd harmonic

Inrush current has significant 2nd harmonic

Minimum % 2nd harmonic and maximum peak on inrush occur when the transformer is energized at voltage-angle = 0º

Protection engineers should set relaying based on data provided by the transformer manufacturer

Inrush current


CT saturation

Waveform restraint – designed to detect the 2nd harmonic wave form, differentiate it from saturated CT secondary current, and block tripping

Adaptive 2nd harmonic operation

Setting

2nd harmonic always in

Conditional 2nd harmonic

Logic to detect when 2nd harmonic restraint is applied

Transformer energization

CT saturation on external faults

How to avoid delayed trips for an internal fault that saturates a CT?

Overvoltage/overexcitation current

Ie

0 90 180 360 540 720

Total Flux

Transformer Magnetizing

Characteristics

S

0 90 180 360 540 720

Over E

xcitation Current

ZS (saturated) Overexcitation waveform produces predominately high odd harmonics 3rd, 5th, 7th, etc.

Typical % of fundamental

2nd = 0

3rd = 70 (*never use)

4th = 0

5th = 30

6th = 0

7th = 2

* 3rd harmonics are a prevalent quantity on the power system produced from many sources


Over-excitation exists if the per unit V/Hz exceeds the design limit of transformer

Voltage exceeds 105% at full load or 110% no load at rated frequency

The frequency goes below 95% (fl) to 90% (nl) of rated at rated voltage

Use manufacturer’s V/Hz – Time curve

How to detect over-excitation?

V/Hz relay using the VT input from the primary

Differential relay with fifth harmonic current restraint can be used if VT unavailable …Apply blocking or tripping with caution !

Over-excitation detection



Transformer basics







Ground differential protection (87G) - REF

Restricted Earth Fault (REF) Protects only the wye-grounded

transformer winding for all internal ground faults Idiff = IN + 3I0 Ires = Max(Ia, Ib, Ic, IN), I1

A directional criteria is also applied in order to increase stability against heavy external faults with CT saturation

Circuit Breaker

Optional Z

I0

I0

I0

3I0

X

Circuit Breaker

Optional Z

I0

I0

I0

3I0

X

3I0 3I0

3I0 3I0

6I0

0

Internal Fault

External Fault

Turn-to-turn fault detection Turn-to-turn fault

Usually involves a small number of adjacent turns

A small unbalance in primary to secondary turns ratio,

(Np-Nt)/Ns

Undetectable with normal differential protection

High current in shorted turns (Np-Nt)Ip + NtIt + NsIs = 0 Not measurable (no access)

Sudden Pressure Relay (SPR) Slow Tendency to mis-operate Block on thru-fault current

Negative sequence differential

Np Np

Np - Nt

NsNs Ns

Nt

Negative sequence differential protection

Negative sequence current for external fault Relative phase between them is 180 degrees

Relay

E2f

Z2S1 Z2S2

I2S1 I2S1 I2S2

I2S1 I2S1Negative Sequence Zero

Potential

I2diff = 0

Negative sequence differential protection

Negative sequence current for internal fault Relative phase between them is 0 degrees

Relay

E2f

Z2S1 Z2S2

I2S1 I2S2

I2S1 I2S2Negative Sequence Zero

Potential

I2diff = I2S1 + I2S2


Overcurrent protection coordination

Through fault protection

C57.109-1985 considers both thermal and mechanical effects for through fault (external faults)

Category I transformer ==> thermal effect is considered

Category II and III transformer ==> thermal effect is considered; mechanical effect depending on the frequency of external fault

Category IV transformer ==> thermal and mechanical effect is considered

Category Single phase (Minimum nameplate kVA)

Three phase (Minimum nameplate kVA)

I 5-500 15-500 II 501-1667 501-5000 III 1668-10,000 5001-30,000 IV Above 10,000 Above 30,000


Transformer capability curve

Category I

Category II and III with low fault frequency

Overcurrent protection

Fuse

Overcurrent relays


Transformer capability curve

Category II and III with high fault frequency

Category IV

High speed differential protection

Backup overcurrent protection



R

TransformerProtection

FeederProtection

Fuse

Recloser

XX

X

Infrequent Fault Zone Frequent Fault Zone

Fault cleared by feeder protection

Fault cleared by transformer differential or primary side device

Fault cleared by transformer primary or optional secondary main breaker device





Time-overcurrent protection

Inverse time characteristic relay provides the best coordination

Pickup settings of 200 to 300% of the transformer’s self-cooled ratings

Fast operation is not possible (coordination with other relays)

Instantaneous protection

Fast operation on heavy internal faults

Settings 125% of the maximum through fault (low side 3Φ fault)

Settings should be above the inrush current


This webinar brought to you by the Relion® product family Advanced protection and control IEDs from ABB

Relion. Thinking beyond the box.Designed to seamlessly consolidate functions, Relion relays are smarter, more flexible and more adaptable. Easy to integrate and with an extensive function library, the Relion family of protection and control delivers advanced functionality and improved performance.


Thank you for your participation

Shortly, you will receive a link to an archive of this presentation.To view a schedule of remaining webinars in this series, or for more

information on ABB’s protection and control solutions, visit:

www.abb.com/relion

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Transformer Protection Fundamentals

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