energies

Article
A Detailed Testing Procedure of Numerical Differential
Protection Relay for EHV Auto Transformer
Umer Ehsan 1,2 , Muhammad Jawad 1, * , Umar Javed 1,3 , Khurram Shabih Zaidi 1 , Ateeq Ur Rehman 4 ,
Anton Rassõlkin 5 , Maha M. Althobaiti 6 , Habib Hamam 7,8,9 and Muhammad Shafiq 10, *

1 Department of Electrical and Computer Engineering, Lahore Campus, COMSATS University Islamabad,
Islamabad 54000, Pakistan; umer.ehsan@yahoo.com (U.E.); umarjaved636@gmail.com (U.J.);
kzaidi@cuilahore.edu.pk (K.S.Z.)
2 National Transmission and Despatch Company Limited, Lahore 54000, Pakistan
3 Riphah College of Science and Technology, Lahore Campus, Riphah International University,
Islamabad 54000, Pakistan
4 Department of Electrical Engineering, Government College University, Lahore 54000, Pakistan;
ateqrehman@gmail.com
5 Department of Electrical Power Engineering & Mechatronics, Tallinn University of Technology,
12616 Tallinn, Estonia; anton.rassolkin@taltech.ee
6 Department of Computer Science, College of Computing and Information technology, Taif University,
P.O. Box 11099, Taif 21944, Saudi Arabia; Maha_m@tu.edu.sa
7 Faculty of Engineering, Uni de Moncton, Moncton, NB E1A 3E9, Canada; habib.hamam@umoncton.ca
8 Spectrum of Knowledge Production & Skills Development, Sfax 3027, Tunisia
9 Department of Electrical and Electronic Engineering Science, School of Electrical Engineering,



University of Johannesburg, Johannesburg 2006, South Africa

 10 Department of Information and Communication Engineering, Yeungnam University, Gyeongsan 38541, Korea
* Correspondence: mjawad@cuilahore.edu.pk (M.J.); shafiq@ynu.ac.kr (M.S.)
Citation: Ehsan, U.; Jawad, M.;
Javed, U.; Shabih Zaidi, K.; Ur
Rehman, A.; Rassõlkin, A.; Althobaiti, Abstract: In power systems, the programmable numerical differential relays are widely used for the
M.M.; Hamam, H.; Shafiq, M. A protection of generators, bus bars, transformers, shunt reactors, and transmission lines. Retrofitting of
Detailed Testing Procedure of relays is the need of the hour because lack of proper testing techniques and misunderstanding of vital
Numerical Differential Protection procedures may result in under performance of the overall protection system. Lack of relay’s proper
Relay for EHV Auto Transformer. testing provokes an unpredictability in its behavior, that may prompt tripping of a healthy power
Energies 2021, 14, 8447. https:// system. Therefore, the main contribution of the paper is to prepare a step-by-step comprehensive
doi.org/10.3390/en14248447 procedural guideline for practical implementation of relay testing procedures and a detailed insight
analysis of relay’s settings for the protection of an Extra High Voltage (EHV) auto transformer.
Academic Editor: Anna Richelli
The experimental results are scrutinized to document a detailed theoretical and technical analysis.
Moreover, the paper also covers shortcomings of existing literature by documenting specialized
Received: 4 November 2021
literature that covers all aspects of protection relays, i.e., from basics of electromechanical domain to
Accepted: 9 December 2021
Published: 14 December 2021
the technicalities of the numerical differential relay covering its detailed testing from different reputed
manufacturers. A secondary injection relay test set is used for detailed testing of differential relay
Publisher’s Note: MDPI stays neutral under test, and the S1 Agile software is used for protection relay settings, configuration modification,
with regard to jurisdictional claims in and detailed analysis.
published maps and institutional affil-
iations. Keywords: current transformers; current measurement; power system protection; power transform-
ers; relays; testing

Copyright: © 2021 by the authors.

Licensee MDPI, Basel, Switzerland. 1. Introduction
This article is an open access article In modern Extra High Voltage (EHV) power networks, the protection of the power
distributed under the terms and system is continuously being upgraded by the replacement of old electromechanical pro-
conditions of the Creative Commons tection relays with the new microprocessor based numerical protection relays known as
Attribution (CC BY) license (https:// Intelligent Electronic Devices (IEDs). Retrofitting of numerical protection relays is essential
creativecommons.org/licenses/by/ and currently an ongoing process throughout power transmission networks. If it is not
4.0/).

Energies 2021, 14, 8447. https://doi.org/10.3390/en14248447 https://www.mdpi.com/journal/energies

Energies 2021, 14, 8447 2 of 21

properly configured and tested or the settings are inappropriate due to lack of its technical
knowledge, then the relay can exhibit unpredictable behavior [1]. Due to the fact, the relay
may not sense faulty conditions at all or may cause tripping in a healthy condition. Such be-
havior of numerical protection relay is highly undesirable and ultimately results in frequent
outages in power systems along with massive revenue loss. To mitigate such undesired
situations and system disturbances, it is necessary to conduct their detailed testing.
The power system under test is a three-phase solidly grounded, with a maximum
nominal phase-to-phase voltage level equal to 500 kV. The generation voltage is less than
or equal to 23 kV and is stepped up to the desired transmission voltage level through
station transformers. The transmission voltage is either 500 or 220 kV. To step down
voltage level from 500 to 220 kV and from 220 to 132 kV, auto transformers are employed.
Moreover, the 132 kV voltage level is stepped down to 11.5 kV through conventional power
transformer. The SLD of the system showing all voltage levels is depicted in Figure 1 [2].
In an existing power system of Pakistan, two differential relays named as main differential
relay and rough balance differential relay are installed for protection of 500 kV/220 kV auto
transformer and 220 kV/132 kV auto transformer, respectively [3]. Through continuous
monitoring of the protection relays, it is ensured that any undesired situation or fault is
dealt with using proper response and the faulty portion is isolated from the healthy system
with high speed, accuracy, selectivity, and reliability.

Figure 1. Single line diagram showing all voltage levels of the power system in Pakistan [2].

In the literature, very few research articles are published that discuss theoretical
details of IEDs and different testing techniques. In [4], theoretical aspects in testing of the
microprocessor based numerical protection relays are discussed. The author discusses
the concepts, such as vector group of transformers, interposing CTs, and zero sequence
filtering in detail. Moreover, the authors also describe the concepts for pickup test and bias
characteristics test. However, the paper lacks a double phase pickup test and harmonic
restraint testing of numerical differential relay that are of vital importance. In [5], a study of
differential relay is presented considering power system disturbances and the behavior of
the numerical differential relay is analyzed in detail; however, its exact threshold settings
and set points are not verified. A novel technique for determining the settings of numerical
differential relay is proposed in [6]. The authors have used a software-based simulator that
utilizes iterations for the determination of settings. Furthermore, enhancement techniques
for power transformer differential protection are described in [7], in which the author
also discussed internal and external fault cases for differential protection and conducted a
simulation testing through real-time digital simulation.
The actuation of transformer differential protection is conditional to the presence
of existing internal transformer faults that may deteriorate a transformer’s health. Sev-
eral methods have been developed to perform condition monitoring of a transformer’s
health [8]. One such method is Frequency Response Analysis (FRA), which deals with
analyzing the frequency response of a transformer on application of signal with frequency
ranging from several hundred to several mega Hertz (low, mid, and high frequency bands)
and compares it with the pre-commissioning or factory testing signal of transformers. In [8],
Energies 2021, 14, 8447 3 of 21

the authors provide comprehensive guidelines for interpretation and evaluation of FRA of
transformers. Moreover, in [9], the authors discuss valuable insight on understanding FRA
signatures and the effect of several transformer faults on FRA signature. The faults include
axial displacement, bushing fault, radial deformation, loss of clamping pressure, inter-disk
fault, and short circuit fault.
To the best of the author’s knowledge, there is no formal guideline and detailed
study available to the research community and power system protection experts that
thoroughly discusses the testing procedures for numerical differential relays as a single
document. Therefore, to fill this literature gap, the main purpose of this research work is to
prepare and compose a step-by-step detailed manual that can provide a complete guideline
for the practical implementation of relay testing procedures and thorough numerical
analysis that one can follow to check the health and functionality of a differential protection
relay installed at EHV auto transformer. A real-time result analysis is performed on the
differential relay installed for protection of 160 MVA, 220/132 kV Auto Transformer located
at 220 kV Grid Station NTDC Kala Shah Kaku, Lahore, Pakistan. The experimental results
are scrutinized to document a detailed theoretical and technical analysis. In light of the
above stated actualities, the main contributions of the paper are:
• Detailed insight analysis of numerical differential relay settings including connec-
tion details, operating principle, and biasing characteristics. Moreover, important
transformer considerations are also discussed.
• A detailed testing procedure of numerical differential relay is conducted through
secondary injection testing with actual settings. The testing results include measure-
ment test, pickup test, trip-time test, stability test, bias characteristics test, 2nd and 5th
harmonic restraints test, and high stage 1 and high stage 2 test.
• A detailed theoretical and technical analysis is conducted and documented to analyze
the practical results.
The remaining paper is organized as follows: Section 2 discusses differential relay ar-
chitecture and differential relay considerations for transformer application briefly. Section 3
focuses towards Matching Current Transformers or Interposing Current Transformers. The
key settings implemented in the relay under test are described in Section 4. Section 5
discusses the testing of differential relay in detail. Section 6 focuses on a result discussion
of the tests performed. The paper is concluded in Section 7 along with future suggestions.

2. Differential Relay
Figure 2a shows the single line diagram for connections of differential relay based
on Kirchhoff’s current law [10]. In Figure 2a, the current transformers are used as current
sensors that essentially stepdown current with high fidelity [11]. The relay receives input
from CTs, and continuously monitors and compares current. If any mismatch is observed
beyond the defined setting, then the trip command is initiated, which isolates the protected
object from the power system. Differential relay compares the magnitude and phase angle
of the currents available at its terminals and remains stable if the vector sum of compared
currents is less than the threshold setting in its internal differential coils [5]. Figure 2b
explains the single-phase schematic drawing for basic operating principle of the differential
relay. The comparison or vector sum is performed in the differential coil C of the relay
and resultant current is called differential current Idi f f . The Idi f f is zero if vector sum of
currents from side A (I A ) and side B (IB ) is zero. The minimum value of the differential
current Idi f f at which the relay operates is controlled by a setting called Idi f f pickup. A
minute spill current normally flows through the relay due to the CT errors and losses [12].
In Figure 2b, the restraining coils A and B are also called biasing coils. As the cur-
rent through protected equipment increases, for example in case of through fault, spill
current increases proportionally. The relay may operate during through fault due to spill
current since the Idi f f pickup was the only setting of the differential relay, which is highly
undesirable. To mitigate this issue, restraining or biasing is provided based on the loading
condition of the protected object through restraining coils, and their setting results in
Energies 2021, 14, 8447 4 of 21

percentage bias characteristics (slope characteristics) of the relay, which essentially results
in restraining the operation of the relay [13]. The restraint (biasing) characteristics provide
stability to the differential relay during normal and through fault scenarios; therefore, the
differential relays are called percentage biased differential relays.

Figure 2. Differential protection relay: (a) single line diagram with connections [10] and (b) basic operating principle [13].

3. Transformers
A transformer is a static electric machine and works on electromagnetic induction
principles. It is used to transfer power from one voltage level to another one while
maintaining electrical isolation between different voltage levels and can be controlled by
varying the number of turns of each winding. However, the voltage per turn ratio remains
constant across its windings. The nominal current of each winding can be calculated by
using Equation (1) [4].

Power RatingKVA
Inom = √ (1)
3 × Ph − Ph Voltage ratingKV

The transformers occupy less geographical area that makes them well suited to be
protected through differential protection. The differential protection has a very crisp and
well-defined zone of protection. The zone of protection is between the CTs that are feeding
the differential relay. Some important considerations regarding transformers must be
considered before further delving into application of differential relay for the protection of
transformers. In a nutshell, the transformer differential relay must cater for the following
characteristics of a transformer.
• Differential relay should cater Vector Group of Transformer [14,15], Zero Sequence
Current Flows [16], On Load Tap Changers [17], and must not initiate tripping dur-
ing normal operation of transformer including energization of transformer (Inrush
Current [18,19]), over fluxing [20], and tap changer operation.
• Differential relay should remain stable during through fault even if the CT saturation
of one or more CTs occur [21,22].
• Differential relay should only initiate tripping during in-zone fault (fault inside pro-
tection zone of differential relay [23]).

4. Matching Current Transformers of Interposing Transformers

When no fault occurs in the differential protection zone during normal operation
of a transformer, the current in differential coils of the differential relay should be equal
in magnitude but with 180-degree phase shift. However, secondary currents from CTs
mostly differ in magnitude and phase angle; therefore, the secondary currents cannot be
directly applied to the differential coils of the relay and are conditioned and modified before
applying to them so that the relay remains stable (ideally Idi f f = 0) during the transformer’s
normal operation. The conditioning and matching of CT secondary currents are performed
through Matching Current Transformers (MCT) or Interposing CT [4]. The matching CTs
also performs zero-sequence filtering whenever required in the secondary circuit.
Energies 2021, 14, 8447 5 of 21

Figure 3a shows the connection diagram of the differential relay with two windings of
the transformer. The transformer under consideration is 220/132/11 kV, 160/160/30 MVA
auto transformer with vector group Yna0 + d11. High voltage side (primary winding)
terminals are marked as A, B, and C while the secondary winding terminals (132 kV side)
are marked as Am, Bm, and Cm. The neutral terminal is grounded and marked as O.
Tertiary winding terminals (11 kV side) are marked as a, b, x, and c. Tertiary delta is
unloaded, kept close through external jumper between terminal x and terminal c and is not
wired to the differential relay. The external jumper between terminals x and c is connected
to ground.
The secondary side of both main CTs is star connected and the star point is towards
the auto transformer and is grounded at one point only. The secondary CT circuit from 220
and 132 kV side terminates into the current elements of the differential relay as shown in
Figure 3a. The dotted box marked as “D” inside differential relay contains MCTs, restrain-
ing coils, differential coils, and harmonic restraining coils. In modern differential relays,
all such coils are implemented through an algorithm. Matching CT’s configuration and
vector group depends on transformer under protection and may vary from manufacturer
to manufacturer as per their protection design. Figure 3b shows the inside architecture
of the dotted box D from Figure 3a [24]. The red (R), yellow (Y), blue (B), and neutral
(N) currents from HV CT secondary side is shown as IHV sec− R , IHV sec−Y , IHV sec− B , and
IHV sec− N , respectively. Similarly, for the LV CT secondary side they are shown as ILV sec− R ,
ILV sec−Y , ILV sec− B , and ILV sec− N , respectively. Both HV and LV side MCT is in star–delta–
star configuration. The delta winding traps the zero-sequence current. In this particular
case, both HV and LV MCT are used for magnitude compensation and phase introduced
by them will be 0. MCT configurations for relay type P642 under different vector groups of
transformers are as follows.

Figure 3. Differential relay circuit [24]: (a) connection diagram with two windings of transformer, and (b) matching CTs,
restraining coils, and differential coils implemented in differential relay through algorithm.

4.1. HV MCT
Transformer HV side matching CTs, irrespective of transformer’s vector group under
protection are of either star–delta–star or star–star configuration. Star–delta–star configu-
ration is used for magnitude compensation and zero sequence filtering whereas star–star
configuration performs magnitude compensation only.
Energies 2021, 14, 8447 6 of 21

4.2. LV MCT
If the main transformer has a vector group of YyX or DdX (where X is any even integer
from 0 to 11 indicating phase shift between HV and LV windings), then LV MCT will be
star–star Z (when zero sequence current filtering is disabled) or star–delta–star Z (when
zero sequence current filtering is enabled). The Z is the phase shift introduced by LV MCT
for the compensation of phase shift introduced by the vector group of the main transformer.
The delta is only introduced when zero sequence current filtering is required. Similarly, if
the main transformer has vector group of YdX or DyX (where X is any odd integer from 1
to 11 showing phase shift between primary and secondary winding), then LV MCT will be
star–delta Z. LV MCT provides necessary phase compensation in addition to the magnitude
compensation and zero-sequence filtering (if required). Table 1 shows different vector
groups of transformer and corresponding LV MCT configuration with required phase shift
when the vector group of transformers under protection is YyX, DdX, YdX, or DyX.

Table 1. LV MCT vector group configuration for transformers: (A) with vector group YyX or DdX,
(B) transformers with vector group YdX or DyX.

(A) VG YyX or DdX (B) VG YdX or DyX

Sr. No. Transformer LV MCT Vector Transformer HV MCT Vector
Vector Group Group Vector Group Group
1 Yy0 or Dd0 Yy0 Yd1 or Dy1 Yd11
2 Yy2 or Dd2 Yy10 Yd3 or Dy3 Yd9
3 Yy4 or Dd4 Yy8 Yd5 or Dy5 Yd7
4 Yy6 or Dd6 Yy6 Yd7 or Dy7 Yd5
5 Yy8 or Dd8 Yy4 Yd9 or Dy9 Yd3
6 Yy10 or Dd10 Yy2 Yd11 or Dy11 Yd1

5. Settings Implemented in Differential Relay

The S1 Agile software is used for implementation of settings in differential relay P642
(Make: Alstom [24]) [25]. The CT ratio data, transformer data, and differential relay settings
implemented in the differential relay are shown in Tables 2–4, respectively. In Table 4, the
setting ‘T1 CT’ with address ‘0A.100 corresponds to HV side CT and setting of HV CT ratio
is 1200:1. The setting ‘Polarity’ is set to ‘standard’ that shows the star point of HV CT is
towards transformer. Moreover, the setting ‘T2 CT’ with address ‘0A.140 corresponds to LV
side CT and setting of LV CT Ratio is also 1200:1. The setting ‘Polarity’ is set to ‘standard’
that shows the star point of the LV CT is towards the transformer.

Table 2. CT data implementation in differential relay on 220 kV GS KSK 160 MVA transformer T2.000.

CT and VT Ratios Value Address (C.R)

Aux’ VT Location HV 0A.02
Aux’ VT Primary 220.0 kV 0A.07
Aux’ VT Sec’ y 110.0 V 0A.08
T1 CT 0A.10
Polarity Standard 0A.11
Primary 1200 A 0A.12
Secondary 1.000 A 0A.13
T2 CT 0A.14
Polarity Standard 0A.15
Primary 1200 A 0A.16
Secondary 1.000 A 0A.17
Energies 2021, 14, 8447 7 of 21

Table 3. Auto transformer implementation in relay.

CT and VT Ratios Value Address (C.R)

Winding Type Auto 30.02
HV CT Terminals 01 30.03
LV CT Terminals 10 30.04
Ref Power S 160.0 MVA 30.07
HV Connection Y-Wye 30.08
HV Grounding Grounded 30.09
HV Nominal 220.0 kV 30.0A
HV Rating 160.0 MVA 30.0B
Percentage Reactance 25.00% 30.0C
LV Vector Group 0 30.0D
LV Connection Y-Wye 30.0E
LV Grounding Grounded 30.0F
LV Nominal 132.0 kV 30.10
LV Rating 160.0 MVA 30.11
Match Factor CT1 2.858 30.20
Match Factor CT2 1.715 30.21
Phase Sequence Standard ABC 30.5E

Table 3 corresponds to auto transformer data implemented in the differential relay.

Power rating of both HV and LV winding is set to 160 MVA. The HV and LV connection of
the auto transformer are in ‘Y’. The HV nominal voltage rating and LV nominal voltage
rating are 220 and 132 kV, respectively. The neutral of HV and LV winding is considered as
‘grounded’. Figure 4 shows the graphical differential characteristics or bias characteristics
implemented for the testing. The setting ‘Trans Diff’ is set to ‘enabled’, which means that
the differential protection function is enabled in the relay. In Table 4 and Figure 4, the
current IS1 is pick-up setting of the differential relay. Setting ‘K10 in Table 4 and Figure 4
is the percentage slope for the slope 2 of differential characteristics. The slope provides
restraining of differential protection operation in case of spill current occurrence due to the
tap changing operation, CT errors, and through faults. The differential relay must remain
stable and must not initiate tripping during through faults. However, the CT errors may
result in larger mismatched current or spill current or differential current as defined in
Figure 2b, which depends on fault intensity. In such cases, the restraining to differential
operation is provided through slope setting ‘K1 = 30%’. Slope is the ratio of change in
differential current to the change in bias current.

Figure 4. Differential characteristics or bias characteristics implemented in relay.

Energies 2021, 14, 8447 8 of 21

Table 4. Differential protection settings implementation in relay.

CT and VT Ratios Value Address (C.R)

Trans Diff Enabled 31.01
Set Mode Advanced 31.02
IS1 150 × 10−3 PU 31.03
K1 30.00% 31.04
IS2 2.000 PU 31.05
K2 60.00% 31.06
tDIFF LS 0s 31.07
IS − CTS 250 × 10−3 PU 31.08
IS − HS1 4.000 PU 31.10
HS2 Status Enabled 31.11
IS − HS2 6.000 PU 31.12
Zero seq. filt. HV Enabled 31.20
Zero seq. filt. LV Enabled 31.21
2nd harmonic blocked Enabled 31.28
Ih ( 2 ) % > 15.00% 31.29
Cross blocking Enabled 31.2A
CT-Sat and No-Gap Enabled 31.2B
5th harmonic blocked Enabled 31.33
Ih ( 5 ) % > 40.00% 31.34
Circuitry fail Disabled 31.40

In Table 4, the setting IS2 marks the start of slope 3, as shown in Figure 4. The slope 3
provides restraining of differential protection, during through fault, even if the main CT is
saturated. The setting ‘K20 in Table 4 and Figure 4 defines the percentage slope setting for
slope 3. The setting ‘IS − HS1 ’ in Table 4 and Figure 4 monitors the operational peak of the
differential current. Beyond setting ‘IS − HS1 ’, the 2nd harmonic restrain cannot restrain
differential relay operation. Therefore, the setting should be kept higher than expected
peak magnetizing current. Setting ‘IS − HS1 ’ only results in tripping if the peak value of the
differential current exceeds ‘IS − HS1 ’ setting and operating point lies in trip region of the
bias characteristics. If differential current exceeds the setting ‘IS − HS2 ’, as shown in Table 4
and Figure 4, the differential relay causes tripping regardless of biasing characteristics and
harmonic components. The differential relay continuously calculates Idi f f and Ibias current
through HV and LV secondary currents at its terminals. If the calculated Idi f f and Ibias
currents end up in the tripping region, the differential relay will initiate tripping as per the
defined algorithm. Setting ‘Zero sequence filtering, HV’ and ‘Zero sequence filtering LV’
set to ‘Enabled’ will result in the elimination of zero sequence current components through
HV and LV MCTs. The 2nd, 5th harmonic blocking are set at 15% and 40%, respectively.

6. Testing of Differential Relay

6.1. Test Apparatus
Testing of the differential relay is conducted through a six current source secondary
injection universal relay test set connected to the relay, as shown in Figure 5a,b. The settings
and configuration of the relay is performed through S1 Agile Software, and the computer
is used for reference setting and result monitoring. The relay trip contact is used as stop
contact for the test set.

6.2. Measurement Test

A measurement test is performed to ascertain that the relay is reading the current at
its terminals accurately. Through the measurement test, the correctness of CT ratios and
measurement of differential and restraining current is determined (in pu). The nominal
current or full load current at primary and secondary side of the transformer is calculated
using Equation (1) as Inom.pri = 420 A and Inom. sec = 700 A. The CT ratio at primary and
secondary side of the transformer is computed as [4]:
Energies 2021, 14, 8447 9 of 21

Rated Primary Current 1200

CT Ratio = = = 1200 (2)
Rated Secondary Current 1

Inom.pri 420
Inom.pri. sec = = = 0.35 (3)
CT Ratio 1200
Inom. sec 700
Inom. sec . sec = = = 0.58 (4)
CT Ratio 1200
Referring to Figure 2b, the differential current is computed as vector sum of currents
flowing through it as [4]:
→ →
Idiff = I1 + I2 (5)

where I1 and I2 are the secondary current of HV MCT and LV MCT, respectively, that are
→ →
shown as IA and IB in Figure 2b. The I1 and I2 are vector quantity currents flowing in the
differential coil. Restraining current or bias current provides restrain to the differential relay
operation [26]. The bias current is based on the loading of the transformer and hampers
the operation of the relay. However, the bias current computation in differential relay
differs in different makes and models, and even the same manufacturer may have different
mathematical equation for its computations. Bias current is computed in Equation (6) as
follows [4]:
|I |+|I2 |
Ibias = 1 (6)
2
Both the differential and bias currents are measured as per unit quantities, where per
unit value is the ratio of actual and base values. The base value is the rated secondary
current of the main CTs that in our case is taken as 1A. Whereas, the HV MCT ratio and LV
MCT ratio are automatically calculated by differential relay as 2.858 and 1.715, respectively,
using Equation (7) [4].

Isec ondary
HV MCT Ratio or LV MCT Ratio = a = (7)
Iprimary

Referring to Figure 6a and using HV MCT Ratio, we can illustrate that upon the
injection of balanced three phase nominal HV secondary current (0.35A) into correspond-
ing relay current elements with no current injection into LV side relay current elements,
current equal to 1A flows in secondary of HV MCT, resulting in flow of Idi f f = 1 pu
using Equation (5) and Ibias = 0.5 pu using Equation (6). In Figure 6a, the phase shift
of three phases is shown through clock convention, where 0 corresponds to 0◦ , 4 corre-
sponds to −120◦ , and 8 corresponds to −240◦ . Therefore, in order to thoroughly verify
the HV side relay elements measurement, HV secondary current corresponding to the
different loading conditions is simulated and then by computing HV primary current
values. Moreover, the differential current and bias current are compared with observed val-
ues. Tables 5 and 6 record the measurement results of the HV side relay current elements.
Referring to Figure 6b and LV MCT Ratio, the injection of balanced three phase nominal
LV secondary current (0.58A) into corresponding relay current elements with no current
injection into HV side relay current elements, the current equal to 1A flows in secondary of
the LV MCT, resulting in flow of Idiff = 1 pu using Equation (5) and Ibias = 0.5 pu using
Equation (6). In Figure 6b, the clockwise phase shift of three phases is shown, where 6, 10,
and 2 correspond to −180◦ , −300◦ , and 60◦ . Tables 5 and 6 record the measurement results
of the LV side relay current elements.
Energies 2021, 14, 8447 10 of 21

Figure 5. Test bench with differential relay, test set, and computer: (a) schematic diagram, (b) pictorial view of hard-
ware setup.

Figure 6. Three phase balanced current injection and resulting differential and bias currents in per unit (pu) for: (a) HV
nominal secondary and (b) LV nominal secondary.

Table 5. Primary current observed by relay for different percentage loading of: (A) transformer HV side in terms of HV
secondary current and (B) transformer LV side in terms of LV secondary current.

(A) Transformer HV Side (B) Transformer LV Side

Percentage Calc. HV Calc.
Loading HV Sec. LV Sec.
Primary Obs. HV Primary (A) LV Primary Obs. LV Primary (A)
Current (A) Current (A)
Current (A) Current (A)
20% 0.07 84 84.4 84.3 84.7 0.116 139.92 140.8 140.5 141
40% 0.14 168 169.7 168.5 169.1 0.2332 279.84 280.1 280.7 281.3
60% 0.21 252 252.6 254.1 253.1 0.3498 419.76 421 421.8 421.1
80% 0.28 336 338.1 340.2 339.8 0.4664 559.68 564 564.4 564.3
100% 0.35 420 421.9 424.3 422.2 0.583 699.6 707.9 706.7 706.3
Energies 2021, 14, 8447 11 of 21

Table 6. Differential and bias current measured by relay for different percentage loading of: (A) transformer HV side and
(B) transformer LV side.

(A) Transformer HV Side (B) Transformer LV Side

Percentage
Differential Current (pu) Bias Current (pu) Differential Current (pu) Bias Current (pu)
Loading
Calc. Obs. (Avg) Calc Obs. Calc. Obs. (Avg) Calc. Obs.
20% 0.2 0.201 0.1 0.101 0.2 0.202 0.1 0.102
40% 0.4 0.406 0.2 0.202 0.4 0.404 0.2 0.202
60% 0.6 0.608 0.3 0.303 0.6 0.603 0.3 0.302
80% 0.8 0.811 0.4 0.405 0.8 0.809 0.4 0.403
100% 1 1.01 0.5 0.505 1 1.02 0.5 0.506

6.3. Pickup Test

A pickup test is performed to check the setting IS1 in differential relay and con-
ducted separately from HV side and LV side relay elements. From Figure 6a, the pickup
computes the minimum differential current that initiate relay tripping. For pickup test,
Equations (8) and (9) compute the 3-phase HV side and LV side secondary currents related
the pickup setting Is1 [5]. By injecting the secondary current (Equation (8)) to the HV side
while keeping LV side to zero, the relay should pick up and trip as per setting. Similarly, if
the current (Equation (9)) is injected to the LV side relay elements, the relay should pick up
and tripping as per setting while keeping HV side to zero. The HVnom sec and LVnom sec are
the nominal secondary CT currents for HV and LV sides.

3 − Phase Pickup current f or HV side = IS1 × HVnom sec (8)

3 − Phase Pickup current f or LV side = IS1 × LVnom sec (9)

During testing, the gradual current increase is observed till relay pick up threshold and
compared with the calculated value. Moreover, the respective current is gradually decreased
until the relay drops off. Equations (10) and (11) are used for single phase pickup current in-
jection calculation for HV and LV sides, respectively, while Equations (12) and (13) are used
for two phase pickup current injection calculation for HV and LV sides, respectively [5].

1 Ph. Pickup current for HV side = IS1 × HVnom sec × MF (10)

1 Ph. Pickup current for LV side = IS1 × LVnom sec × MF (11)

2 Ph. Pickup current for HV side = IS1 × HVnom sec (12)
2 Ph. Pickup current for LV side = IS1 × LVnom sec × MF (13)
where MF is the multiplying factor where applicable that depends on the MCT configuration
and zero sequence current filtering (enabled or disabled) status. For Equations (10)–(13), the
MF is computed using sequence current (I0 , I1 , and I2 ) given in Ref. [5]. Using [5], it is
apparent that MF value in Equations (10) and (11) is 32 , while in Equation (13) the MF is
1. Table 7 shows the single, double, and three phase testing results where the acceptable
range for pick-up observed is computed using the following range formula given in [24] as
0.9 × Pickup Calc. − 1.1 × Pickup Calc, and for drop-off observed, the range I defined as
0.9 × Pickup Calc. to 1.0 × Pickup Calc. Table 7 illustrates that for both HV and LV sides,
all the pickup observed, and drop-off observed values for single, double, and three phase
pickup tests are within the aforementioned ranges.
Energies 2021, 14, 8447 12 of 21

Table 7. Single, double, and three phase pickup and drop-off test of differential relay.

HV Side LV Side
Sr. No. Pickup Pickup Drop off Pickup Pickup Drop off
Calc. (A) Obs. (A) Obs. (A) Calc. (A) Obs. (A) Obs. (A)
Single Phase Pickup Test
R 0.078 0.078 0.073 0.131 0.133 0.123
Y 0.078 0.079 0.074 0.131 0.131 0.122
B 0.078 0.08 0.072 0.131 0.130 0.124
Double Phase Pickup Test
RY 0.0525 0.052 0.048 0.0874 0.087 0.082
YB 0.0525 0.051 0.047 0.0874 0.087 0.081
BR 0.0525 0.051 0.048 0.0874 0.086 0.081
Three Phase Pickup Test
RYB 0.0525 0.052 0.048 0.0874 0.088 0.082

Figure 7a shows the waveform for HV side Blue phase ( IC_1) observed pickup current
(0.08 A)). Before the injection of observed pickup current, transformer rated currents are
applied as pre-fault to the differential relay. The pre-fault current values read by relay are
419.6 A ( RMS) for primary side and 698.6 A ( RMS) for secondary side. The fault current
in IC_1 measured by relay is 105.5 A ( RMS), secondary current = 105.5 1200 = 0.087 A). The
injected secondary current generates Idi f f = 0.149 according to graph which is very close
to the pickup setting of relay (0.15 pu).
Figure 7b shows the waveform for LV side yellow phase ( IB_2) observed pickup
current (0.131 A). Before the injection of observed pickup current, transformer rated
currents are applied as pre-fault to differential relay. The pre-fault current values read by
relay are 421.9 A ( RMS) for primary side and 693.9 A ( RMS) for secondary side. The fault
current in IB_2 measured by relay is 168.7 A ( RMS), secondary current = 168.71200 = 0.140 A).
The injected secondary current generates Idi f f = 0.149 as per graph, which is very close to
the pickup setting of relay (0.15 pu).
Figure 7c shows the waveform for HV side three phase ( I A_1, IB_1, IC_1) observed
pickup current (0.052 A). Before the injection of observed pickup current, transformer
rated currents are applied as pre-fault to differential relay. The pre-fault current values
read by relay are 417.3 A ( RMS) for primary side and 696.2 A ( RMS) for secondary side.
The fault currents I A_1, IB_1, IC_1 measured by relay are 69.78 A ( RMS), secondary
current = 69.78
1200 = 0.058 A. The injected secondary current generates Idi f f = 0.149 as per
graph, which is close to pickup setting of relay (0.15 pu).
Figure 7d shows the waveform for LV side three phase ( I A_2, IB_2, IC_2) observed
pickup current (0.088 A). Before the injection of observed pickup current, transformer
rated currents are applied as pre-fault to differential relay. The pre-fault current values
read by relay are 414.9 A ( RMS) for primary side and 698.5 A ( RMS) for secondary side.
The fault current I A_2, IB_2, IC_2 measured by relay is 103.15 A ( RMS), secondary
current = 103.15
1200 = 0.085 A). The injected secondary current generates Idi f f = 0.151 as per
graph, which is close to pickup setting of relay (0.15 pu).

6.4. Trip Time Test

The trip time test is performed to measure the time from inception of fault till relay
trips. The recommendation is to test trip time at 5.0 × HV Pickup Calc. [24]. The results of
trip time test are recorded using three-phase current injection into HV side relay current
elements 5.0 × HV Pickup Calc., which is 0.2625 A. The acceptable range is 30–35 ms, while
observed is 27 ms. The simulation and analysis performed in Section 6.9 explicitly discuss
the trip time test of numerical differential relay.
Energies 2021, 14, 8447 13 of 21

Figure 7. Cont.
Energies 2021, 14, 8447 14 of 21

Figure 7. Pickup and drop-off test of differential relay: (a) HV side blue phase, (b) LV side yellow phase, (c) HV side three
phase, (d) LV side three phase.

6.5. Stability Test

During through fault, the relay must remain stable and must not initiate tripping.
Ideally, the bias current increases but the differential current remains low (near to zero).
Practically, some differential current may be observed (due to CT saturation); however, the
relay remains stable due to bias characteristics. The stability test is performed by simulating
the condition for through fault. The condition can be simulated by simultaneously applying
nominal HV and LV secondary currents at respective relay current elements. Table 8
presents the differential and bias currents measurements by the relay when 5 times of
balanced HV and LV nominal secondary currents are applied at relay terminals.

6.6. Bias Test

Referring to the bias characteristics shown in Figure 4, testing of bias characteristics
includes testing all three slopes. For each slope, two points are considered on the graph,
near to the boundary of trip and restrain region. The current injections that correspond to
the selected points are injected in the relay and its behavior is recorded. Figure 8 shows the
points selected on Figure 4. Using Equations (5) and (6), the currents I1 and I2 shown in
Figure 6a,b, respectively, are calculated for each point selected on Figure 8. Moreover, the
IHV sec and ILV sec corresponding to I1 and I2 , respectively, are calculated in amperes. The 3-
phase IHV sec and ILV sec with angles shown in the stability test are applied simultaneously
to the corresponding relay elements. The behavior of relay (Trip/No Trip) is recorded, and
Idi f f and Ibias measured by relay is compared with the computed value of selected point.
To illustrate this phenomenon, recorded results are shown in Table 9.
Figure 9a shows the waveform of currents corresponding to Point ‘B’ mentioned in
Table 9. Before the injection of currents corresponding to Point ‘B’, transformer rated cur-
rents are applied as pre-fault to differential relay. The pre-fault current values read by relay
are 414.9 A ( RMS) for primary side and 698.6 A ( RMS) for secondary side. The injected
three phase HV and LV fault currents into relay result into Idi f f = 0.18 pu and Ibias = 0.40 pu.
The observed Idi f f and Ibias from relay are in accordance with the Idi f f and Ibias of Point ‘B’
as apparent from Figure 8.
Figure 9b shows the waveform of currents corresponding to Point ‘F’ mentioned in Table 9.
The injected three phase HV and LV fault currents into relay result into Idi f f = 1.26 pu and
Ibias = 3.0 pu. The observed Idi f f and Ibias from relay are in accordance with the Idi f f and
Ibias of Point ‘F’ as apparent from Figure 8.
 relay
jected 414.9 A
arethree (𝑅𝑀𝑆)jected
phase relay
HV for primary
are
andthree414.9
LVside A
phase (𝑅𝑀𝑆)
and HV
fault 698.6
forand
currents A (𝑅𝑀𝑆)
primary LV side
into for
fault 698.6 side.
secondary
andcurrents
relay result Ainto
(𝑅𝑀𝑆)
into 𝐼 relay
The for=secondary
in- result into side. 𝐼The in-
=
relay
jected are 414.9
0.18 pu and 𝐼
three A (𝑅𝑀𝑆) relay
= 0.400.18
phase HV for
pu. pu
jected primary
are
and
Theand 414.9
three
LV𝐼 side
observed A (𝑅𝑀𝑆)
and
= 0.40
fault
phase 698.6
for
𝐼 pu.and
currents
HV A (𝑅𝑀𝑆)
primary
The𝐼 observed
and intoLV side
for
relayand
fault
from relay𝐼 698.6
secondary A (𝑅𝑀𝑆)
side.
andin𝐼 accordance
result
currents
are into 𝐼
The
into =
for
in-
relay secondary
result side.
into
from relay are in accordance 𝐼 in-
The =
0.18
withputhe
jected and𝐼 𝐼 and
three = 0.40
phase pu.
HV0.18
jected
𝐼 with pu and
and
of The
Point
the 𝐼 ‘B’𝐼 as
threeLV
observed and = 0.40
phase
fault 𝐼𝐼
apparent pu.
currents
HV and
of and
from 𝐼 Figure
The
Point into
LV
observed
‘B’ fromrelay
fault
as 8. 𝐼 are
relay
apparent result
currents
and
from into
in Figureinto𝐼
𝐼accordance
from =
relay result into
8. relay are in accordance 𝐼 =
0.18
with puthe and
𝐼 𝐼 9band
Figure = 0.40
𝐼 the
shows pu.
0.18 pu
theand
The
of waveform
withPoint
Figure 𝐼 𝐼9b
observed
‘B’ asof =
and 0.40
𝐼𝐼 the
apparent
shows
currents pu.
and
from
of The𝐼Figure
Point
waveform observed
‘B’from
corresponding as to𝐼Point
relay
8. apparent
of currents are
and
from 𝐼accordance
‘F’inmentioned
Figure
corresponding from 8. torelay
in Pointare
‘F’in accordance
mentioned in
with the
Energies 𝐼
2021,
Figure 14,
9b and
8447
shows
Table 9. The injected three 𝐼 the of
with Point
the
waveform
Figure
Tablephase 𝐼‘B’
9. TheHV as
9bofand
shows 𝐼
apparent
currents
injected
and LV the
threeof
fromPointFigure
corresponding
waveform
faultphase ‘B’
currents as8.
of
HV and apparent
currents
to
into LVPoint
relay from
fault‘F’ Figure
corresponding
result mentioned
currents 8.
into 𝐼into = in
torelay result into 𝐼
Point ‘F’ mentioned in15 of 21
=
1.26Figure
Table pu and9b
9. The shows
𝐼injected= 3.0 the
pu.
1.26
three waveform
Table Figure
pu
phase
The and 𝐼9bof
9.observed
The
HV shows
currents
injected
and LVthe
=𝐼 3.0 pu. corresponding
three
fault
and waveform
The𝐼currents
phase HVof
observed
from intocurrents
to Point
𝐼 relay
and
relay LV are corresponding
‘F’accordance
fault
result
andin 𝐼 mentioned
currents
into
from𝐼 relay
into= relay
in
to
with Point ‘F’
are inresult into 𝐼 with
mentioned
accordance =
in
1.26
the pu
Table 𝐼 andand
9. The 𝐼 𝐼 = 3.0
injected ofpu.1.26
three
Table
the 𝐼 pu
phase
The
Point 9. and
TheHV
observed
‘F’ asand 𝐼 𝐼 𝐼= 3.0
injected
and
apparent LV pu. Figure
three
fault
and
offrom
Point 𝐼‘F’ observed
phase
Thecurrents HV
asfrom
8. into
and
relay
apparent 𝐼 are
relay
LVfromfault
result
and
inFigure𝐼 currents
into
accordance 𝐼 into
fromwith
8. = relay result into
relay are in accordance with𝐼 =
1.26
the 𝐼pu and and𝐼 𝐼 = 3.0
of pu.
1.26
the
Point The𝐼pu
‘F’ and
observed
as 𝐼
and 𝐼
apparent =𝐼 3.0
from
of pu.
and
Point 𝐼
The
Figure‘F’observed
asfrom
8. apparent 𝐼
relay are and
from
Table 8. Stability test results when 5 times of nominal HV secondary and LV secondary currentsin 𝐼
accordance
Figure from
8. with
relay are in accordance
is applied. with
Stability test 𝐼Table
theresults and
when 5𝐼 times
8. Stability oftestthe
ofPoint 𝐼‘F’ as
nominal
results and
when
HV 5 𝐼timesof
apparent
secondary fromPoint
ofand Figure
LV‘F’
nominal as8.apparent
secondary
HV secondary
currentsfrom
andis LVFigure
applied.
secondary8. currents is applied.
Current
ability test results
TableApplied
when at oftest
8. 5Stability
times Current
nominal
results
HV Applied
when at and
secondary
5 times of nominal
LV secondary
HV secondary
currentsand
is applied.
LV secondary currents is applied.
at HV Current
ability testCurrent
Applied
HV
results
Table Applied
Side
when 5attimes
8. RelayHV
at LV
Stability Current
oftest
nominal Applied
LV Side
results Relay at LV Idiffsecondary
Calc.
HV (pu) Ibiasis Calc. 𝑰𝒃𝒊𝒂𝒔 Obs.
(pu) Idiff Obs.is(pu) 𝑰𝒃𝒊𝒂𝒔
IbiasObs.
Obs. (pu)
tents
HV Current
Current Applied
Applied at HV
at LV 𝑰𝒅𝒊𝒇𝒇HV
Current
when
secondary
Calc. 5(pu)
Applied
times
at
of
𝑰and
LV
nominal
LV
𝒃𝒊𝒂𝒔 𝑰Calc.
𝒅𝒊𝒇𝒇 Calc.
(pu)secondary
currents
𝑰(pu)
𝒅𝒊𝒇𝒇 Obs.
and
𝑰𝒃𝒊𝒂𝒔 applied.
LV secondary
(pu)
Calc.𝑰(pu) currents
𝑰𝒅𝒊𝒇𝒇
Obs. Obs. (pu)applied.
𝑰 Obs.
SideSide
Relay Elements
Relay
Elements
Elements Side Elements
Relay Elements 𝒃𝒊𝒂𝒔(pu) (pu)
𝒃𝒊𝒂𝒔
tnts
HVCurrentCurrentApplied
Applied at HV 𝑰𝒅𝒊𝒇𝒇 Calc.
at LV Current Applied(pu)at LV 𝑰𝒅𝒊𝒇𝒇(pu)
𝑰𝒃𝒊𝒂𝒔 Calc. Calc.𝑰𝒅𝒊𝒇𝒇
(pu)Obs. 𝑰𝒃𝒊𝒂𝒔 (pu) 𝑰𝒅𝒊𝒇𝒇 Obs. (pu) 𝑰
Calc.𝑰 (pu)Obs. Obs.
Side
SideRelay
Relay
1.75∟0° Elements
Elements
2.915∟180°
1.75 0◦ Side
𝑰𝒅𝒊𝒇𝒇Relay
2.915∟180°Elements
Calc.180
2.915 ◦
(pu) 𝑰𝒅𝒊𝒇𝒇 (pu)
𝑰𝒃𝒊𝒂𝒔 Calc. Calc.𝑰𝒅𝒊𝒇𝒇
(pu)Obs. 𝑰𝒃𝒊𝒂𝒔(pu)Calc. (pu)(pu)
𝒃𝒊𝒂𝒔
𝑰𝒅𝒊𝒇𝒇 Obs. (pu) 𝒃𝒊𝒂𝒔 (pu)
nts Side Side
Relay
Relay
1.75∟0°Elements
2.915∟180°Elements
◦ Side Relay Elements
2.915∟180° ◦ (pu) (pu)
1.75 240
1.75∟240°
2.915∟60° 2.915
0.0 60
2.915∟60° 5.0 0.00.0 0.012 5.0 5.0 5.04 0.012 0.012 5.04 5.04
1.75∟0°
2.915∟180°
1.75 120 ◦ 2.915∟180°
2.915 300 ◦
1.75∟240°
2.915∟60°
1.75∟120°
2.915∟300° 2.915∟60°
0.0
2.915∟300° 5.0 0.0 0.012 5.0 5.04 0.012 5.04
1.75∟240°
2.915∟60°
1.75∟120°
2.915∟300° 2.915∟60°
0.0
2.915∟300° 5.0 0.0 0.012 5.0 5.04 0.012 5.04
1.75∟120°
2.915∟300°
Idiff (pu) 2.915∟300°
Idiff (pu) J J
Idiff (pu) Idiff (pu) Point A : (0.4 , 0.12)I Point A : (0.4 , 0.12)
J I J
IdiffS2(pu) Idiff (pu) Point
PointA B: (0.4
: (0.4 , 0.12)
, 0.18) PointBA::(0.4
Point (0.4, ,0.18)
0.12)
Is-H = 6.0 Is-H S2 = 6.0
J I J I
Point
PointABC: :(0.4 (1.2 0.12)
, 0.18) Point
PointA (0.4
CB::(1.2 0.12)
(0.4,,0.33)
0.18)
Is-HS2 = 6.0 Is-HS2 = 6.0 H I H , 0.33) I
Point
Point B
C D : :(0.4
(1.2
(1.2, 0.18)
0.33) Point
PointDBC::(0.4(1.2,,0.18)
0.33)
Is-H H G HG0.39)
, (1.2 0.39)
Is-HS2S1==6.0
4.0 Is-HS2S1 = 6.0
4.0 Point CE: :(1.2
HG PointD (3.0H, ,0.33)
0.39)
1.15)
G
Point
PointECD: :(3.0
(1.2 0.33)
(1.2, ,1.15)
0.39)
Is-HS1 = 4.0 Is-HS1 = 4.0 F Point
PointEDF:::(3.0(1.2
(3.0,, ,1.15)
0.39)
1.25) Point
PointFDE:::(3.0
(1.2
(3.0,,,1.25)
0.39)
1.15)
Is-HS1 = 4.0 Is-HS1 = 4.0 F E Trip G Point
PointEFGF : (3.0 G
1.15)
:E(10, ,1.25)
5.2) Point
PointEGF :: (3.0
(3.0,,,5.2)
(10 1.15)
1.25)
Trip
Trip
Region F E RegionTrip Point
PointFGH F:: (3.0
:(10 1.25)
E(10, ,5.2)
5.6) Point
PointFHG:::(3.0 1.25)
(10,,5.6)
(10 5.2)
0.6 0.6
Trip
Region Trip
E Region Point
PointGHI : (10 (12 , 5.2)
E 5.6)
6.4) Point
PointGIH: :(12
:(10
(10, ,6.4)
,5.2)
5.6)
0.6 0.6
Region D Region D Point PointHI J: ::(12
(10
(12, ,6.4)
, 5.6)
6.8) Point
PointHJI :::(12
(10,,,6.8)
(12 5.6)
6.4)
0.6 D C 0.6 DC Point IJ : (12 , 6.4)
IS1 = 0.15 B IS1 =C0.15 B 6.8) Point
PointIJ::(12 (12, ,6.4)
6.8)
BA D Restraining Region AB C Point J : (12
DRestraining Region, 6.8) Point J : (12 , 6.8)
IS1 = 0.15 IS1 =C0.15 C
A
B Restraining BA
Region Restraining Region
IS1 = 0.15 IS1 = 0.15
A0.4 0.5 Restraining
1.2
A
Region
0.4 100.5 12Restraining
11.0 1.2 Region
IS2=2.0 3.0 7.666 IS2=2.0 3.0 7.666 10 11.0 12
0.4 0.5 1.2 0.5 121.2IbiasIS2(pu)
0.410 11.0
IS2=2.0 3.0 7.666 =2.0 3.0 7.666 10 11.0 12 Ibias (pu)
Figure 8. Differential characteristics or bias characteristics with selected points.
0.4 0.5 1.2 0.5 121.2IbiasIS2
0.410 11.0
IS2=2.0 3.0 7.666 (pu)
=2.0 3.0 7.666 10 11.0 12 Ibias (pu)
Figure 8. Differential characteristics
Figure 8. Differential
6.7.orThe 2nd and Ibias
or bias characteristics
characteristics
with
5th Harmonic (pu)
or selected
bias characteristics
points.
Restraint Test Iwith
bias (pu)
selected points.
Figure 8. Differential characteristics
Figure 8. Differential
bias characteristics
characteristics
withorselected
bias characteristics
points. with selected points.
Figure 8. Differential
6.7. The 2nd and 5thcharacteristics
Figure
6.7. The8.
Harmonic orIn-rush
Differential
bias
Restraint
2nd 5thcurrent
Test and
and characteristics over
characteristics
Harmonic with fluxing
orselected
Restraintbias of transformers
characteristics
points.
Test results
with selected in increased 2nd harmonic
points.
6.7. The 2nd and 5th Harmonic 6.7.over
Theand
Restraint
2nd 5th and harmonic
Test
5thtransformers
Harmonic current components, respectively. Once the harmonic contents are
In-rush current and In-rushfluxing currentof and overRestraint fluxing
resultsof Test
intransformers
increased 2nd results
harmonic in increased 2nd harmonic
6.7. The 2nd and 5th Harmonic6.7. The Restraint
2nd and
detected asTest
5thper Harmonic
threshold Restraint
setting, Test
the relay’s operation is restrained. The2nd restraining of relay
andIn-rush
5th harmoniccurrent and
current
andover In-rush
fluxing
components,
5th harmonic current
of transformers
and over
respectively.
current components,fluxing
results
Once theinofrespectively.
increased
transformers
harmonic 2nd
contents
Onceresults
harmonic
arein
the increased
harmonic
de- contents harmonic
are de-
and In-rush
5thas harmoniccurrent and
current over
and operation
In-rush
fluxing
components,
5th harmonic current
ofis tested
transformers
and
respectively.
current by simultaneously
over fluxing
results
components,
Once of
in injecting
transformers
increased
the harmonic
respectively. fundamental
2nd
contents results
harmonic in component
increased of
2nd current
harmonic (must
de- be
tected per threshold tected
setting, astheperrelay’sthreshold operation setting, istherestrained.
relay’s operation
The restraining isOnce are
the
restrained.
of de-
harmonic
relay contentsofare
The restraining relay
and 5thasharmonic higher than I and kept constant during test), and 2nd or 5th harmonic component de- into
tected
operation per testedcurrent
is threshold and components,
setting,
tected5thas
by simultaneously
operation harmonic
the per
isrelay’s respectively.
threshold
tested current
di f f
operation
injecting components,
setting,
by simultaneously isOnce
fundamental theinjecting
restrained.
the relay’s harmonic
respectively.
The
componentoperation contents
restraining
of is
fundamental Once are
the
restrained.
current of de-
harmonic
relay
(must
component contents
The restraining
of currentof are relay
(must
tected as per threshold setting,
tected relay
astheper current element. By increasing the 2nd or 5th harmonic component, the percentage
operation
be higher isthan
tested 𝐼 by andsimultaneously
operation
be higher
kept isrelay’s
than
constant threshold
tested𝐼 during
injecting operation
by and setting,
keptisand
simultaneously
fundamental
test), restrained.
the2nd
constantrelay’s
component operation
Theharmonic
injecting
or
during
5th restraining is
fundamental
of current
test), and restrained.
of(must
component
2nd relay The
component
or 5th restraining
harmonic of current of (must
component relay
setting is injecting
verified from Table 4 atcomponent address 31.29 and 31.34, respectively. Results are given in
operation
be higher
into is
relaythan
current 𝐼 element.
tested by simultaneously
and operation
bekept
into higher
By
relay is
constant
increasing tested
than during
current 𝐼 element.
by
the and simultaneously
2nd fundamental
test),kept
or and
By5th constant injecting
2nd or during
increasing
harmonic 5th
the fundamental
harmonic
2ndtest),
component, of
or 5thcurrent
andcomponent
the 2nd
harmonic (must
component
or 5th
percent- of
harmonicthe
component, current
component(must
percent-
be higher than 𝐼 element.
and be higher
kept Table than
constant 10. 𝐼during and test),
kept and constant
2nd
into
age relay current
setting is verified into
age
from By relay
increasing
setting
Table current
is
4 at the
verified element.
address 2nd from or By
5th
31.29Table increasing
harmonic
and atoraddress
431.34, during
5th
the harmonic
component,
2nd test),
respectively. or 5th
31.29 and component
the
and 2nd
harmonic or are
percent-
Results
31.34, 5th harmonic the
component,
respectively. component
percent-
Results are
into
age relay
setting
given current
in Table 10.element.
is verified into
ageBy
from
given relay
increasing
setting
Table
in current
Table4 is
at the
verified element.
address
10. 2nd fromorBy
31.29 5th increasing
Table
andharmonic
31.34,
4 at the
component,
address 2nd 31.29
respectively. or 5ththe harmonic
and percent-
Results 31.34, are component,
respectively. the percent-
Results are
6.8. High Stage 1 and High Stage 2 Test
age
givensetting
in Table is verified
10. from
age
given setting
Table
in Table 4isatverified
addressfrom
10. 31.29Table and 31.34,
4 at address respectively.31.29 and Results31.34, arerespectively. Results are
To verify high stage 1 tripping, the differential protection must remain unblocked
given in Table
6.8. High Stage10. 1 and High given
6.8.Stage
High in Table
2Stage
Test 110.and HighI Stage>2ITest
once the condition − HS1 is fulfilled. The testing is performed per phase for HV
6.8. High Stage 1 and High
To verify high stage 1To 6.8.
Stage
High 2 Test
tripping,Stage
verify 1
high
the and HighdiStage
differential
stage
ff
1 tripping, 2 STest the
protection differential
must remain protection
unblocked must remain unblocked
6.8. High Stage 1high and High 6.8.
Stage
Highside relay
2verify
Stage
Test the elements
1high
and High Stage only. 2 Testresults
The of high stage 1 test for setting given in Table 4 are
onceTo theverify
condition stage 𝐼 once >1 𝐼tripping,
To
the−𝐻 condition
recorded is fulfilled.
in Table 𝐼 stage
differential > 𝐼1Moreover,
The
11. −protection
testing𝐻 is
tripping, themust
the differential
is fulfilled.
performed
settings remain
The per
‘Itesting
S − protection
unblocked
phase
H S1is
’ for must
performed
and HV‘I S − H remain
per
S2 ’ phase
are unblocked
forby
tested HVtesting
sideTo
once the verify
condition
relay high𝐼stage
elements only. > 1𝐼The
once
side −
the
relay 𝐻
tripping,
To verify
condition
results
points elements the
high
isG,fulfilled.
of
H and high𝐼only.
differential
stageI,TheJ,>respectively,
stage 1𝐼testing
The 1−protection
tripping,𝐻 is
results
test for the
of must
isperformeddifferential
fulfilled.
setting
as high
shown remain
The
stageper
given protection
testing
1phaseunblocked
intest
in Figure Tablefor
isTable
for
8. must
performed
4HV
setting
are remain
12 given perinphase
records unblocked
Table
the for
test HV for
4results
are
once
side the condition
relay
recorded elements
in Table 11. 𝐼only. >The
once
side𝐼 the
Moreover,
recorded −
relay𝐻condition
results
points in is
G,fulfilled.
elements
the ofH,high
Table
settings I,𝐼and
11. only.‘𝐼The
stage >
Moreover, 𝐼𝐻
J.−The1−test
testing 𝐻and isis‘𝐼
’results
for
the performed
fulfilled.
of−high
setting
settings 𝐻 ’‘𝐼 The
given−per
stage
are 𝐻testing
inphase
1’test
tested Table
and is
for
byfor performed
HV
− 𝐻 ’ are
4 setting
are
‘𝐼testing per
giventestedphase by for
in Table 4HV
are
testing
side relay
recorded inelements
Table 11.only.
points G, H and I, J, respectively,sideThe
Moreover, relay
recorded
points G, H results
theelements
in as
Figure of
Table
settings
and shownhigh
I,10a11.only.
‘𝐼stage −
Moreover,
J, respectively,
in Figure
shows 𝐻
The1 test
’results
and for
the
the8.waveform‘𝐼
Table − 𝐻
setting
of high
settings
as shown ’ given
12 records
of stage
‘𝐼
are − 𝐻in
1
tested
incurrents
Figure test
’Table
and
by for 4
testing
‘𝐼
the8.corresponding
test
Table −
results 𝐻
setting
are ’
12 recordsgiven
are in
tested Table
the test
to Point by 4 are
testing
‘H’results
mentioned
recorded
points G, in
for points HG, Table
andH, I,11.and Moreover,
recorded
J, respectively,
points
J.
for inG,
points the
inH
G,
TableasTable
settings
and
shown
H, 12. 11.
I, I,andJ, in
The ‘𝐼 − 𝐻 ’ 8.
Moreover,
respectively,
J.Figure
injected andthe
Table
as
three −
‘𝐼settings
shown
12𝐻 records
phase ’ ‘𝐼
are
in
HV − 𝐻the’ test
tested
Figure
and and
8.
LV ‘𝐼 −12
byTable
testing
results
fault 𝐻 records
’ are tested
currents into by testing
the relay
test results
result into
points G, H
for points G,and I,and
H, I,showsJ, respectively,
J.points IdiG,f f H=
for waveform
points as
G, and
shown
H, I,I, J,&respectively,
and inIthe Figure
J.bias = 10.0 8. Table
as of shown12 records
in Figure theIdi 8.
testTable
results 12 records ‘H’the testinresults
Figure 10a the Figure 10a5.6 pu
ofshows
currents corresponding
waveform pu. The toobserved
currentsPoint corresponding
‘H’ f f and Ibias
mentioned toinfrom
Pointrelay are
mentioned accordance
in
for points
Table 12. G,
Figure The H,injected
10a I, and J.the
shows for
three
Table points
waveform
Figure
with
phase
12. The G,the HVH,
10aof I,
injected
and
ff
and
Idicurrents
shows andLV J.the
threeI corresponding
fault
biaswaveform
of
phase Point
currents HV of
‘H’into
andto
currents
as Point
apparent
relay
LV ‘H’
faultcorresponding
result mentioned
from
currents
into 𝐼
Figureintoin=
to8. Point
relay ‘H’
result mentioned
into 𝐼 =
in
TableFigure
12. The 10a shows three
injected the waveform
Table Figure
phase12. The HV 10a
Figure of shows
currents
injected
and 10b LVshows the
threecorresponding
fault waveform
currents
phase HV
the waveform of
into currents
torelay
and Point
LV ‘H’
corresponding
fault
result
of currents mentioned
currents
into 𝐼 into
corresponding = relay
in
to Point result
‘H’Point
to into‘I’𝐼mentioned
mentioned =
in
Table 12. The injected three Tablephase 12.Table
in TheHVinjectedand The
12. LVthree fault
injectedphase
currents HVinto
three and
phase relay
LVHV fault
result
and currents
into 𝐼 into=
LV fault relay result
currents into intorelay𝐼 result = into
Idi f f = 6.4 pu & Ibias = 12.0 pu. The observed Idi f f and Ibias from relay are in accordance
with the Idi f f and Ibias of Point ‘I’ as apparent from Figure 8.
Energies 2021, 14, 8447 16 of 21

Table 9. Test results of bias characteristics for points selected in Figure 11a.

Point I1 (pu) I2 (pu) IHV sec (A) ILV sec (A) Idiff obs. (pu) Ibias obs. (pu) Trip/No Trip
A 0.46 0.34 0.161 0.198 0.12 0.404 No trip
B 0.49 0.31 0.171 0.180 0.18 0.404 Trip
C 1.36 1.03 0.478 0.603 0.33 1.213 No trip
D 1.39 1.00 0.488 0.586 0.39 1.213 Trip
E 3.57 2.42 1.251 1.413 1.16 3.028 No trip
F 3.62 2.37 1.269 1.384 1.26 3.031 Trip

Table 10. Results of 2nd and 5th harmonic restraint test.

Relay Current Current Injected (A) 2nd Harm. Block 2nd Harm. Block 5th Harm. Block 5th Harm. Block
Element 50 Hz Th. Setting (%) Obs.% Th. Setting% Obs.%
IHV sec R 0.5 15 14.6 40 41.1
IHV sec Y 0.5 15 14.6 40 40.9
IHV sec B 0.5 15 14.2 40 40.4

Table 11. Test results of effect of setting ‘IS − HS1 ’ and 2nd harmonic component on differential protection status.

Idiff Current Applied (A)

HV Side Relay Element 2nd Harmonic Current Differential Protection Status
(per Unit) (50 Hz)
3.6 1.9 14.7% Blocked
Red
4.10 2.16 ≥14.7% Unblocked
3.6 1.9 14.8% Blocked
Yellow
4.10 2.16 ≥14.8% Unblocked
3.6 1.9 14.8% Blocked
Blue
4.10 2.16 ≥14.8% Unblocked

Table 12. Test results of bias characteristics for points selected in accordance with setting ‘IS − HS1 ’
and ‘IS − HS2 ’ in Figure 11a.

Point I1 (pu) I2 (pu) IHV sec (A) ILV sec (A) Idiff Obs. (pu) Ibias Obs. (pu) Trip/No Trip
G 12.6 7.4 4.41 4.31 5.23 10 No Trip
H 12.8 7.2 4.48 4.19 5.63 10.0 Trip
I 15.2 8.8 5.32 5.13 6.44 12 Trip
J 15.4 8.6 5.39 5.01 6.84 12 Trip

Figure 9. Cont.
Energies 2021, 14, 8447 17 of 21

Figure 9. Waveforms of bias characteristics for points selected in Figure 11a: (a) point B, (b) point F.

Figure 10. Waveforms of bias characteristics for points selected in accordance with setting ‘IS − HS1 ’
and ‘IS − HS2 ’ in Figure 11a: (a) point H, (b) point I.

6.9. Simulation Results and Discussion

In addition to testing, the numerical relays also generate time stamped waveforms and
measurements as standard format COMTRADE [27]. Such waveform can provide impor-
tant insight into pre-fault conditions, fault inception, post-fault conditions, and behavior
of relay under real-time fault situations. Few current waveforms from COMTRADE files
Energies 2021, 14, 8447 18 of 21

generated by relay for trip time test and bias characteristics test (point D) are displayed for
discussion. Current waveforms for trip time test (fault current applied for extended time
regardless of relay trip) and bias characteristic test at point D (fault current applied with
nominal currents as pre-fault) in Figure 8 are presented in Figures 8a and 11b, respectively.
The waveforms are plotted through SEL SynchroWAVE Event [28]. Figure 11a shows relay
reads Red Phase Primary Current (IA_1_1.sec) as 307A (RMS), which is approximately
equal to 315A, as per discussed calculations. Similarly, Red Phase Differential Current
(IA_DIFF) is observed as Idi f f = 0.7540 pu and Red Phase Bias Current (IA_BIAS) is ob-
served as Ibias = 0.3783 pu. Observed values of Red Phase Differential Current (IA_DIFF)
and Red Phase Bias Current (IA_BIAS) are as per calculations discussed. The calculated val-
ues of Red Phase Differential Current and Red Phase Bias Current being Idi f f = 0.75 pu and
Ibias = 0.375 pu, respectively. Figure 11b shows transformer red phase currents calculated
by relay (IA_1_1.sec corresponds to HV side red phase current, IA_2_1.sec corresponds
to LV side red phase current, IA_DIFF corresponds to red phase differential current, and
IA_BIAS corresponds to red phase bias current) when point D in Figure 8 is simulated with
nominal currents as pre-fault. The brown and purple color cursor shows HV side, LV side,
Idi f f and Ibias currents of red phase at pre-fault and fault values, respectively. Pre-Fault Red
Phase Primary currents of HV side and LV side calculated by relay are 440A (RMS) and
690A (RMS), respectively. The calculated primary current values are close to actual nominal
current of HV side (420A) and LV side (700A). During pre-fault, Idi f f and Ibias currents
of red phase are calculated by relay as Idi f f = 0.008 pu and Ibias = 1.010, respectively.
Pre-fault values of Idi f f and Ibias calculated by relay are very close to actual calculated
values of Idi f f and Ibias given as Idi f f = 0 pu and Ibias = 1.0 pu. Fault values of Idi f f and
Ibias calculated by relay, shown in Figure 11b, are Idi f f = 0.3949 pu and Ibias = 1.2263. Fault
values of Idi f f and Ibias calculated by relay are very close to actual calculated values of Idi f f
and Ibias for point D given as Idi f f = 0.39 pu and Ibias = 1.2 also shown in Figure 8.

Figure 11. Waveform of: (a) Red Phase Current, Idi f f and Ibias of red phase for fault simulated in trip time test, (b) HV and
LV Red Phase Current, Idi f f and Ibias for point D of Figure 8.
Energies 2021, 14, 8447 19 of 21

7. Conclusions and Future Work

In this paper, a complete procedural guideline for the practical implementation of
numerical differential relay testing procedures was prepared and composed for insight anal-
ysis of relay settings for the protection of an EHV 220/132 kV auto transformer. Moreover,
based on the experimental results, a detailed technical and theoretical analysis including
connection details, operating principle, and biasing characteristics was also performed. A
secondary injection relay test set was used for the detailed testing of numerical differential
relay. For this purpose, a “six current source secondary injection universal relay test set”
was connected to the relay. Keeping in view of the prepared formal procedural guideline,
the real-time implementation of relay was performed, which gives a detailed insight study
that can be helpful for the research community and power system protection experts in
understanding the basic principles, operation, and testing of numerical differential relays.
The tests used to monitor a relay’s health include measurement test, pickup test, trip-time
test, stability test, bias characteristics test, 2nd and 5th harmonic restraints test, and high
stage 1 and high stage 2 test. The testing results were then critically analyzed from theo-
retical and practical perspectives to insure the relay’s satisfactory performance. Table 13
tabulates the summarized results of relay testing with the final remarks presented against
each test. The testing results of the differential relay under consideration are satisfactory
and indicate the sound health and appropriate functionality of relay.

Table 13. Summarized results of differential relay testing.

Sr. No. Test Performed Observations Remarks

1 Measurement Test Comparison of meas. and calc. values Satisfactory
Single, double, and three phase pickup test results lie in acceptable
2 Pickup Test Satisfactory
range specified in [24]
The observed trip time lies in acceptable range (30 to 35 ms)
3 Trip Time Test Satisfactory
specified in [24]
4 Stability Test Observed Idi f f and Ibias values are comparable to calc. values Satisfactory
Bias characteristics test result for test points shown in Figure 8 are
as per respective region (trip/restrain). Additionally, the obs. Idi f f
5 Bias Characteristics Test Satisfactory
and Ibias currents of relay are comparable to calc. Idi f f and Ibias
shown in Figure 8.
2nd and 5th Harmonic Observed 2nd and 5th harmonic restraint test results are
6 Satisfactory
Restraint Test comparable to the corresponding setting thresholds
High Stage 1 and High High Stage 1 and 2 test results for test points shown in Figure 8 are
7 Satisfactory
Stage 2 Test as per respective region (trip/restrain)

If the behavior of relay deviates from the applied settings in such a way that the
deviation is greater than the allowed tolerance by manufacturer and it is made sure again
that the testing procedure followed is proper and comprehensive and the relay settings
under test are properly understood by testing engineer, then proceedings can be made
to declare the relay unhealthy. Moreover, diagnosis can also be made through testing to
determine whether any analogue, input/output module, CPU module, or power supply
module is faulty. After identification and replacing the faulty module with the healthy one,
the relay is to be tested again to ensure its healthiness.
In future, a detailed manual will be prepared which will include comprehensive
testing procedural guidelines for understanding the complex design, features, and working
of the numerical distance protection relay used for the protection of EHV transmission lines.

Author Contributions: Conceptualization, U.E., M.J. and U.J.; methodology, K.S.Z., A.U.R. and
A.R.; validation, M.M.A., H.H. and M.S.; formal analysis, U.E., M.J. and U.J.; investigation M.M.A.,
H.H. and M.S.; resources, K.S.Z., A.U.R. and A.R.; data curation, M.M.A., H.H. and M.S.; writing—
original draft preparation, U.E., M.J. and U.J.; writing—review and editing, M.M.A., H.H. and M.S.,
visualization, K.S.Z., A.U.R. and A.R.; supervision, K.S.Z., A.U.R. and A.R.; project administration
M.M.A., H.H. and M.S. All authors have read and agreed to the published version of the manuscript.
Energies 2021, 14, 8447 20 of 21

Funding: This work was supported by Taif University Researchers Supporting Project Number
(TURSP-2020/328), Taif University, Taif, Saudi Arabia.
Institutional Review Board Statement: Not applicable.
Informed Consent Statement: Not applicable.
Data Availability Statement: As all the hardware testing were performed on differential relay
installed for protection of 160 MVA, 220/132 kV Auto Transformer located at 220 kV Grid Station
NTDC Kala Shah Kaku, Lahore, Pakistan. Due to the privacy policy of the national grid, the data
cannot be shared openly.
Acknowledgments: We deeply acknowledge Taif University for supporting this research through
Taif University Researchers Supporting Project Number (TURSP-2020/328), Taif University, Taif,
Saudi Arabia.
Conflicts of Interest: The authors declare no conflict of interest.

References
1. Bak, C.L.; Hansen, M.L.; Nissen, J.O. Distance protection in 150/60 kV transformer 60 kV feeders: Two real blackout case studies.
J. Eng. 2018, 2018, 802–806. [CrossRef]
2. Khan, S.S.; Mehmood, K.T.; Hashmi, M.W.; Rafiq, M.A.; Sheikh, M.F. Power stability of 500/220/132 kV grid station system on
single-line-to-ground fault at 500 kv transmission lines. Sci. Int. J. 2015, 27, 3995–3999.
3. Akhmedova, O.; Soshinov, A.; Gazizov, F.; Ilyashenko, S. Development of an Intelligent System for Distance Relay Protection
with Adaptive Algorithms for Determining the Operation Setpoints. Energies 2021, 14, 973. [CrossRef]
4. Verzosa, Q.; Lee, W.A. Testing Microprocessor-Based Numerical Transformer Differential Protection. IEEE Trans. Ind. Appl. 2017,
53, 56–64. [CrossRef]
5. Rocha, D.C.G.; Batista, W.H.; Coelho, A.L.M.; Araujo, M.R. Practical approach to testing the transformer differential protection
for internal and external faults, CT saturation and inrush transients. J. Eng. 2018, 2018, 1239–1244. [CrossRef]
6. Andreev, M.; Suvorov, A.; Ruban, N.; Ufa, R.; Gusev, A.; Askarov, A.; Kievets, A.; Bhalja, B.R. Setting determination for numerical
transformer differential protection via its detailed mathematical model. IET Gener. Transm. Distrib. 2020, 14, 1962–1972. [CrossRef]
7. Sevov, L.; Khan, U.; Zhang, Z. Enhancing Power Transformer Differential Protection to Improve Security and Dependability.
IEEE Trans. Ind. Appl. 2017, 53, 2642–2649. [CrossRef]
8. Al-Ameri, S.M.; Kamarudin, M.S.; Yousof, M.F.M.; Salem, A.A.; Siada, A.A.; Mosaad, M.I. Interpretation of Frequency Response
Analysis for Fault Detection in Power Transformers. Appl. Sci. 2021, 11, 2923. [CrossRef]
9. Al-Ameri, S.M.; Kamarudin, M.S.; Yousof, M.F.M.; Salem, A.A.; Banakhr, F.A.; Mosaad, M.I.; Abu-Siada, A. Understanding the
Influence of Power Transformer Faults on the Frequency Response Signature Using Simulation Analysis and Statistical Indicators.
IEEE Access 2021, 9, 70935–70947. [CrossRef]
10. Javed, U.; Mughees, N.; Jawad, M.; Azeem, O.; Abbas, G.; Ullah, N.; Chowdhury, M.S.; Techato, K.; Zaidi, K.S.; Tahir, U. A
systematic Review of Key Challenges in Hybrid HVAC-HVDC Grids. Energies 2021, 14, 5451. [CrossRef]
11. So, E.; Verhoeven, R.; Simons, B.; Parks, H.V.; Angelo, D. A High-Precision Current Transformer for Loss Measurements of EHV
Shunt Reactors. IEEE Trans. Instrum. Meas. 2019, 68, 1680–1687. [CrossRef]
12. Medeiros, R.P.; Costa, F.B. A Wavelet-Based Transformer Differential Protection with Differential Current Transformer Saturation
and Cross-Country Fault Detection. IEEE Trans. Power Deliv. 2018, 33, 789–799. [CrossRef]
13. Ji, T.; Mo, C.; Zhang, L.L.; Wu, Q.H. Duty Cycle-Based Differential Protection Scheme for Power Transformers. IEEE Trans. Power
Deliv. 2021. [CrossRef]
14. Prodan, C.; Rata, G. Apparatus for determining the clock hour figure of the vector group of the electrical transformers. In
Proceedings of the IEEE International Conference and Exposition on Electrical and Power Engineering (EPE), Iasi, Romania,
18–19 October 2018; pp. 0259–0263.
15. Zhang, Z.; Mo, M.; Wu, C. Three-phase distribution transformer connections modeling based on matrix operation method by
phase-coordinates. EURASIP J. Wirel. Commun. Netw. 2021, 2021, 66. [CrossRef]
16. Saeed, H.; Kamel, M.; Karrar, A.; Eltom, A.H.; Bowman, M. On-Site Low Voltage Determination of Zero-Sequence Impedances for
Power Transformers. IEEE Trans. Power Deliv. 2020, 35, 1048–1057. [CrossRef]
17. Xu, H.; Domínguez-García, A.D.; Sauer, P.W. Optimal Tap Setting of Voltage Regulation Transformers Using Batch Reinforcement
Learning. IEEE Trans. Power Syst. 2020, 35, 1990–2001. [CrossRef]
18. Mitra, J.; Xu, X.; Benidris, M. Reduction of Three-Phase Transformer Inrush Currents Using Controlled Switching. IEEE Trans. Ind.
Appl. 2020, 56, 890–897. [CrossRef]
19. Ge, W.; Zhao, J.; Wang, Y. Analysis of the residual flux influence on inrush current and electromagnetic force in large power
transformer. J. Eng. 2019, 2019, 2426–2429. [CrossRef]
20. Gunda, S.K.; Dhanikonda, V.S.S.S.S. Discrimination of Transformer Inrush Currents and Internal Fault Currents Using Extended
Kalman Filter Algorithm (EKF). Energies 2021, 14, 6020. [CrossRef]
Energies 2021, 14, 8447 21 of 21

21. Zheng, T.; Huang, T.; Ma, Y.; Zhang, Z.; Liu, L. Histogram-Based Method to Avoid Maloperation of Transformer Differential
Protection Due to Current-Transformer Saturation under External Faults. IEEE Trans. Power Deliv. 2018, 33, 610–619. [CrossRef]
22. Shah, A.M.; Bhalja, B.R.; Patel, R.M.; Bhalja, H.; Agarwal, P.; Makwana, Y.M.; Malik, O.P. Quartile Based Differential Protection of
Power Transformer. IEEE Trans. Power Deliv. 2020, 35, 2447–2458. [CrossRef]
23. Magrin, F.; Tavares, M.C. Increasing sensitivity for transformer protection using incremental differential. J. Eng. 2018,
2018, 1209–1215. [CrossRef]
24. GE Grid Solutions, P642: Transformer Protection IED, Technical Manual. Available online: https://www.gegridsolutions.com/
app/viewfiles.aspx?prod=P64X&type=3 (accessed on 15 August 2021).
25. MiCOM S1 Agile Engineering Tool Suit (1.3.1), Alstom Grid. Available online: https://www.gegridsolutions.com/multilin/
catalog/engineering-tool-suite.htm (accessed on 5 August 2021).
26. Ameli, A.; Ghafouri, M.; Zeineldin, H.H.; Salama, M.M.A.; El-Saadany, E.F. Accurate Fault Diagnosis in Transformers Using an
Auxiliary Current-Compensation-Based Framework for Differential Relays. IEEE Trans. Instrum. Meas. 2021, 70, 1–14.
27. IEEE Draft Standard for Common Format for Transient Data Exchange (COMTRADE) for Power Systems. In IEEE PC37.111/D4,
January 2012 (IEC 60255-24 Ed.2); IEEE: Manhattan, MY, USA, 2012; pp. 1–72.
28. SEL-5030 SynchroWAVE Acselerator QuickSet Software, Schweitzer Engineering Laboratories, Inc. Available online: https:
//selinc.com/products/5030/ (accessed on 10 August 2021).