a new approach for transformer differential protection
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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.
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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):
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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 ,
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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
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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.
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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.
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A B C
OptionalResistoror Reactor
Figure 1
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Optional Resistor
Directional Overcurren t Relay withAuxiliary Current Transformer
Figure 2
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60 9 1 120 150 180u.u
0 30
EXTENDEDTRIP AREA cp (degrees)+
Figure 4
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Figure 5
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k0
03
4.05657
2.03603
1.36603
1.03372
Table 1
(PMAX
90"
100"
110"
1 0"
130"
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1 -
0-
I?
-1
-2
-
-I; 1;-Y
0.0 2.5 5.0 7.5
cycles -+
Figure 6
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2.5 5.0 7.5cycles -*
Figure 7
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LUU
150
100
50
--.
Figure 8
I I
15