A NEW APPROACH FOR TRANSFORMER DIFFERENTIAL PROTECTION

7/29/2019 A NEW APPROACH FOR TRANSFORMER DIFFERENTIAL PROTECTION

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A NEWAPPROACHOR TRANSFORMERROUNDIFFERENTIALROTECTION

Dr. Tevfik Sezi

Sieme ns Power Transmission and Distribution, LLCDistribution Automation Division

P.O. Box 29503Raleigh, NC 27626-0503 USA

Abstract-Existing electromechanical grou nd differentialprotection relays are impaired in the event of CT aturation.They might trip when the fault is external (or not trip when thefault is internal) unless the configuration and settings aredesigned very carefully. In addition, inrush effects can alsocause wrong protection behavior. Simulations and fieldobservations have revealed that the phase angle differencebetween the ground current and zero sequence current, incombination with the ratio of their magnitudes, can b e used to

identify precisely a transformer grou nd fault. Theseobservations were used for the development of a new numericaltransformer differential protective relay. Simulations and testresults have shown that the new solution correctly detects awider range of phenomena that would indicate an intern al fault,while remaining able to not tr ip in the event of a n external fault.

Ke y Words-Power distribution pro tect ion, power systemprotection, power transformer protection, power transmissionprotection,protection, protective relaying.

I. INTRODUCTION

This paper describes a new approach for transformer

ground differential protection, also known as restricted

ground fault protection. The algorithm described has been

implemented in a new numerical transformer differentialrelay to obtain better protection coverage for transformers

and shunt reactors than the classical solutions. Extensive

simulations and field tests have prov en th e reliability of the

implemented algorithms. The new solution does not require

any external auxiliary CTs, and the settings are very simple.

11.CLASSICALOLUTIONS

Phase-current differential protection schemes for

transformers are not sensitive enough to detect an internal

phase-to-ground fault if the fault is located near the neutral

point of the transformer. Also, it is difficult to de tect a grou nd

fault if the transformer is resistance- or reactance-grounded,

since the ground current will be limited.One classical solution for detecting an internal ground fault

is to u se a high-impedan ce differential-current relay (Fig. 1).

This solution is also often used as a compromise solution for

providing differential protection to a grounded delta-wye

transformer bank when no delta-side CT's are available (or

A B C

Fig. 1. Conventional Ground Differential Protection Scheme Using a

High-Impedance Differential Relay.

convenient). This is a common situation for distribution and

industrial ties with the delta as the high-voltage side and

protected by fuses.

An alternative classical solution is to use a directional

overcurrent relay or a p roduct relay. This is often done if the

characteristics or CT ratios of the CTs are not suitable for

using a high-impedance differential relay. This solution is

particularly applicable when the ground current is limited orwhen a sensitive ground CT is used. Fig. 2 shows two

different operating principles that use a directional

overcurrent relay. In one case, an aux iliary curren t balancing

autotransformer is used, in the other case an aux iliary l:N

current transformer.

1



iG

. -- -.

Directional Overcu rrent Relay withAuxilialy Current Transformer

,I

,8

Fig. 2.Ground Differential Protection Scheme Using a Directional Overcurrent Relay with Either anAuxiliary CT (left dashed-line box) or an A utotransformer (right dashed-line box).

If the directional overcurrent relay solution is used, therelay has a directional unit that operates as a product unit.

The overcurrent unit itself is non-directional and operates

only in response to the amplitude of the current. In Fig. 2, it isshown as the coil without an indicated polarity. This non-

directional unit has an inverse time characteristic, but

operates only if the directional unit operates.

In an y classical solution, the relay operates if the product

of the amplitude of the ground current, the amplitude of the

zero sequence current, and the cosine of the phase angle

between the two currents exceeds a certain limit. For any

particular current amplitudes, the m aximum operating torque

occurs if the phase angle between the two currents is O",

while the maximum restraining torque occurs if the phase

angle is 180". Zero torque occurs at k90". With the classical

protection scheme, detailed consideration must be given to

ensuring that the relay w ill operate correctly even if no zerosequence current is present [11.

111. THENEW LGORITHM

The new, low-impedance ground differential protectionalgorithm is based on Kirchoff's law. The inform ation

provided to the algorithm is sampled values of the phasecurrents and the ground current.

Using the known phase and ground CT ratio information

(specified as relay settings), the sampled current values are

normalized relative to the nominal current of the protected

transformer winding, In. This simply means that the unit of

measure for all currents is In, not amperes. Then, the

quantities used by the algo rithm are calculated:

A . Calculated Quantities

The restraining current, ZR , is the scalar sum of the separate

amplitudes of the measured phase and grou nd currents. It is a

measure of the total amount of current flowing through the

transformer, regardless of whether the currents are balanced.

It is calculated according to equations (1) an d (2):

2



where N is the number of samples taken during each power

system cycle, while iA(k) , iB(k), i&). and i&) are the

sampled and normalized values of the phase and ground

currents.

The fundamental vector of the ground current, IC. is

calculated using Fourier analysis:

IG ( n ) =J[Re(lG (n>)r [Im(IG (n))r ( 3 )

(4)k

N

2 N- 1

Re(lG(n))=- c i ~n-k)cOs(2n-)N k= O

Two calculated current vectors, Id and I d ' , re the major

compo nents of the new algorithm:

1.0

0.8

0.6

0.4

0 .2

0.00 30 60 9 120 15 0 180

EXTENDEDTRIP AREA q (degrees) --3

Fig. 3. Trip area for I : 11; =1

i: =iA iB+ic=3 i0 (7)

Both quantities are calculated using the Fourier-analysisalgorithm described in equations (3), (4), and (5) .

The differential current, ID , is by definition the amplitude

of the vector-difference of the measured ground current and

the calculated zero sequence current. By convention, any

current. flowing into the protected equ ipment is considered to

have a positive magnitude; so I D is calculated using the

following equation:

B. Fault Detection

The new algorithm detects that a fault has occurred if thedifferential current, ID , exceeds a relay setting (indicating that

the ground current and zero sequence current differ too

much), or if the restraining current, ZR,exceeds another relay

setting (indicating that the total amount of current flowing

through the transformer is too high). Once a fault has been

detected, further analysis occurs. As with the classical

solution, the question to be answered is whether the fault isinternal (requiring a trip) or external (not requiring a trip).

C. Trip Decision

In theory, an external fault can be easily recognized sincethe calculated quantities Zd and I d ' will have equal

magnitudes and a phase angle difference of cp=90°. Inreality, inrush effects or CT-saturation may distort the

measured currents. CT-saturation can affect both the

perceived amplitudes of the fundamental current vectors andthe phase angle between them.

0 30 60 99 120 150 180

EXTENDEDTRIP AREA q ( d e w s ) --f

Fig. 4. rip area for I(;/10"=2.

0 30 60 9 O A 120 15 0 180

EXTENDEDTRIP AREA rp (degrees)+Fig.5 . Trip area for 1; /1 =4 ,



Classical Trip Area: The algorithm calculates a value

called the "sta bilization current," I STAB:

zSTAB =Ii; -iyl-l~; ( 9 )

Vector analysis can show that the amplitude of the

stabilization current, ISTAB, will be negative if the phase angle

cpbetween lo and l o is in the range -90" I p 5 90". In this

case, the fault is internal, so a trip is appropriate if the

amplitude of a calculated "operating current," Zop , is above a

minimum level (a relay setting):

l o p =I ; (if -90" I cp I90") (10)

Trip if l o p 2 Z T , . ~ ~ - ET (if -90" I p I 90") (1 1)

Extended Trip Area: The new algorithm extends the trip

area to recognize internal faults that the classical solution

will fail to respond to, while still avoiding an improper trip if

the fault is external.If the phase angle cp is in the range 90 I p 52 70 " (outside

the classical trip area), the magnitude of Z ~ T A B will be

positive. In this case, the new algorithm still bases the trip

decision on the amplitude of the operating current, l o p , but

calculates l o p differently:

lop =1; - o l S TAB (if 90" 5 p 5 270") (12)

Trip if l o p 2 ZTrip-SET (if 90" I cp 5 2 7 0 " ) (13)

where ko , the "stabilization factor," is a relay setting used to

adjust the sensitivity of the protection when 90" I cp 5 2 7 0 " .Note that when cp is in that range, lop is a function of four

quantities: the amplitudes of the currents l o and l o , he

phase angle between them , and the stabilization factor, ko:

l o p = f ( k o , c p , Z ~ , l ~ ) (14)

Since only the ratio of l o to I O is of interest, one can

imagine graphing l o p as a three-dimensional surface where

the dimensions correspond to l o p l l o (the normalized value

of Zop ) , cp . an d l o l l o . Different values of IQ wouldcorrespond to different plotted surfaces. Figures 3, 4, and 5

show as graphs three cross-sections of such a plot. Each

graph corresponds to one value of Z o l l o ,with the vertical

axis corresponding to Zop/Zo and the horizontal axis

corresponding to cp . (Only the range 0" 5 p I 180" needs to

be shown because of phase-angle symmetry). The different

curves plotted correspond to different values of ko (a setting).The interpretation of these graphs will now be explained.

For any particular combination of I O , l o an d ko values,

the value of the operating current, l o p , is affected by cp (the

phase angle between lo and l o ) in the following way . If cp

is +90", the am plitude of the stabilization current, ISTAB, will

be zero, and equation (12) will yield the same value as

equation (lo), the classical solution. However, as the phase

k0

oo

4.05657

2.03603

1.36603

1.03372

angle cp increases into the range 90"Icp 5270° , t he

stabilization current ZSTAB will become larger, and so th e

operating current l o p will become smaller (equation 12).

If cp is in the range -90" I cp I 90", then Zop is equal to I o

(by definition). T his is the same behavior as for the classical

protection solution, so the area is labeled the "Classical Trip

Area."

The new algo rithm extends the area in which a trip will be

allowed. Unlike the classical solution, a trip can still occur

even if cp is greater than 90" (further to the right on the

graph). It is very important to realize that the curved

boundary of the extended trip area moves while the relay is

operating. At all times, the instantaneous values of the

normalized operating current value, Zopl l o , and the phase

angle,cp, will plot to a point somewhere on the curve

corresponding to the value of the "stabilization factor," ko. In

Figures 3,4 , and 5, the curved bound ary of the extended trip

area is plotted for several values of ko.Compare Figures 3, 4 , and 5 to see how as the ratio of I O

to 10 increases the extended trip area becomes larger. This

is appropriate since a larger ratio means that the measured

ground current is becoming much larger than the calculated

zero sequen ce current. Hence, it is more likely that the fault is

internal than that it is external, even if CT saturation is

distorting the value of the perceived phase angle betw een the

currents.

For an y given combination of the stabilization factor, ko ,

and ratio of the current amplitudes, Z o / l o , here exists a

maximum phase angle cp~m t which the operating currentl o p reaches the value zero. If the phase angle pis greater

than q ~ m ,he operating current l o p would be negative. To

handle this, the algorithm changes any negative value for l o p

to zero, so no trip occurs.

Table 1 lists the corresponding value of cp~mor values of

kowhen Z o l Z o =1:* $

(PIMAX

90"

100"

110"

120"

130"

TABLEI

VALUESOF THE MAXIMUMHASE ANGLE, f p ~ u ,ORRESPONDING TO

DIFFERENTALUES OFTHESTABLIZATlON FACTOR,k0, HEN 1; / I f f =1.

D. econd Harmonic Restraint

The amplitude of the second harmonic of the differential

current, I D (equation 8). is calculated to detect the effect of

inrush. If this amplitude exceeds a corresponding setting

(typically 15% of the fundam ental value of Io),he trip signal

4



will be blocked. But, if an internal fault with CT-saturation

occurs during inrush, the trip signal must no t be blocked. This

situation is handled by disabling second-h armonic blocking if

the magnitude of the fundamental component of the

differential current ID exceeds a separate setting (typicallyten-times the nominal current of the transformer winding that

the ground differential algorithm is pro tecting).

Evolving Faults

operating point during po wer cyc les. If an external fault with

The algorithm is able to track the dynamic motion of the 0.0 2.5 5.0 7.5cycles .+

1.0

0.5

CT saturation occurs, the algorithm will correctly not trip.

However, if the motion of the operating point indicates that

an internal fault is evolving (specifically, if the operating

point moves from the blocking area into the tripping area and

remains there for two pow er cycles), the algorithm will issue

a trip signal..Z::- ,r .

y 'Ii ! d b P. .

.... .i

-Iv. TESTING ND AN EXAMPLE

The new g round differential algorithm has been implem ented

in a new numerical transformer differential relay. EMTPsimulation tests and field experience have demonstrated the

high reliability of the algorithm. External, internal, andevolving fault test cases were conducted. Both single-phase

and multiple-phase faults were considered. Simulations have

shown high stability of the algorithm in the case oftransformer inrush.

Figures 6, 7, an d 8 show results for a simu lated fault with

saturation of phase CTs. Thus, th e zero sequence current is

distorted. The groun d current CT is not saturated.

Fig. 6 , shows the calculated values of the normalized

currents lo a n d l o ' ; ig . 7 shows the normalized values ofthe stabilization current ISTAB and the operating current l o p ;

and Fig. 8 shows the calculated value of the phase angle cp .

Shortly after the start of the transformer inrush, the

distortion of the calculated zero sequence current is so severe

that the phase opposition of the two currents IO and lo gets

lost. Thus, a positive stabilization current occurs. Since the

stabilization current is positive (in the trip area), the absolute

value of the phase angle between the two p hasors is less than

go", so a transition from the block area to the trip area occurs.

The algorithm recognizes that C T saturation is present if the

stabilization current is po sitive for a short time, then becom es

negative for a longer time. In other cases, there may be

several transitions between the block area and the trip area.

For this reason, the trip signal is delayed if a transition from

the block area to the trip area is detected. Th e timer is reset

after each block-to-trip area transition. A trip signal is only

possible if the stabilization current is positive for a specified

delay time and the operating current remains above the

threshold value. T he delay time is ad justable, with the defaultvalue being 2 cycles. Thus, no trip occurs in the example

shown.

**

Fig. 6. Normalized Currents 1; and 10 During a Fault

2.5 5.0 7.5

cycles

Fig. 7. Stabilization Current, ISTAB. and Operating Current, Zop.

200 ' I

150 -

100

50

v

-

0.0 2.5 5.0 7.5

cycles -

Fig. 8. Phase Angle cp During a Fault

V. CONCLUSION

The presented algorithm is highly sensitive, regardless of

the phase angle between the currents Id an d I d ' . Asexplained earlier in this paper, with increasing phase angle

classical product relay w ill require higher curren t amplitudes

to generate the necessary torque for a trip. Thus, the

sensitivity of a classical relay decreases as the phase angle

grows. In typical applications, no trip is possible for phase

angles greater than 85". With the extended trip area, internal

faults causing heavy C T saturation problems will be detected.

5



In addition, many time consuming commissioning tests and

fine adjustments necessary for the classical ground-

differential solutions using directional overcurrent relays are

avoided.

VI. REFERENCES

J.L. Blackburn, Protective Relaying: Principles andApplications, 2nd Edition. New York: Marcel Dekker, 1998.

C.H. Einvall and J.R. Linders, “A Three-phase DifferentialRelay for Transformer Protection,” IEEE Transactions onPAS, Vol. PAS-94, No. 6, Nov/Dec 1975.

W.A. Elmore, editor, Protective Relaying Theory andApplications. New York: Marcel Dekker, 1994.

L.F. Kennedy and C.D. Hayward, “Harmonic-Current-Restrained Relays for Differential Protection,” AlEETransactions, Vol. 57, pp. 262-266, 1938.

O.P. Mal& P.K. Dash, and G.S. ope, “Digital Protection ofPower Transformer,” Paper No. A76 191-7 IEEE PES 19 76Winter Power Meeting , New York.

C.A. Mathews, “An Improved Transformer DifferentialRelay,” AlEE Transactions, Vol. 73, Part 111, pp. 645-650,1954.

J.A. Sykes, “A New Technique for High-speed TransformerFault Protection Suitable for Digital ComputerImplem entation,” IEEE paper No. C72 429-9, Summer PowerMeeting of PES, 1972.

J.A. Sykes and I.F. Morrison, “A Proposed Method forHarmonic-Restraint Differential Protection for PowerTransformers,” IEEE Transactions on PAS, Vol. PAS-9 1, No .3, pp. 1260-1272,1972.

VII. BIOGRAPHY

Dr. Tevfik Sezi (M’ 997) was born

in 1953 in Adana, Turkey. He studiedpower electronics at the Technical

University of Berlin (Germany),

obtaining his Ph.D . (Dr.-Ing.) in 1 985

after being an assistant professor there

from 198 0 to 1985. His research

areas have included frequency

variable drives, protection algorithms,

and optimized software structures for

protective relays. He has been with

Siemens since 1985, working as a development engineer for

protective relays from 1985 to 1996, and was responsible for

the relay development department between 1993 and 1996.

He holds several patents on protection algorithms. Since

August 1996 he has been in the United States as ProductManage r for Protective Relays.

6



A B C

OptionalResistoror Reactor

Figure 1

7



Optional Resistor

Directional Overcurren t Relay withAuxiliary Current Transformer

Figure 2

8





60 9 1 120 150 180u.u

0 30

EXTENDEDTRIP AREA cp (degrees)+

Figure 4

10



Figure 5

11



k0

03

4.05657

2.03603

1.36603

1.03372

Table 1

(PMAX

90"

100"

110"

1 0"

130"

12



1 -

0-

I?

-1

-2

-

-I; 1;-Y

0.0 2.5 5.0 7.5

cycles -+

Figure 6

13



2.5 5.0 7.5cycles -*

Figure 7

14



LUU

150

100

50

--.

Figure 8

I I

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A NEW APPROACH FOR TRANSFORMER DIFFERENTIAL PROTECTION