energies
Article
A New Impedance-Based Main and Backup Protection Scheme
for Active Distribution Lines in AC Microgrids
Seyyed Mohammad Nobakhti 1 , Abbas Ketabi 1, *
1
2
*
and Miadreza Shafie-khah 2, *
Department of Electrical and Computer Engineering, University of Kashan, Kashan 8731753153, Iran;
nowbakhti@gmail.com
School of Technology and Innovations, University of Vaasa, 65200 Vaasa, Finland
Correspondence: aketabi@kashanu.ac.ir (A.K.); miadreza.shafiekhah@univaasa.fi (M.S.-k.)
Abstract: Microgrids active characteristics such as grid-connected or islanded operation mode,
the distributed generators with an intermittent nature, and bidirectional power flow in active distribution lines lead to malfunction of traditional protection schemes. In this article, an impedance-based
fault detection scheme is proposed as the main protection of microgrids by applying the proposed
equivalent circuits for doubly-fed lines. In this scheme, relay location data and positive sequence
voltage absolute value of the other end of the line are used. It can detect even high impedance faults
in grid-connected and islanded modes. It is robust against load and generation uncertainties and
network reconfigurations. Low sampling rate and minimum data exchange are among the advantages of the proposed scheme. Moreover, a backup protection scheme based on the conductance
variations is suggested. No requirement for the communication link is a distinguished advantage of
the proposed backup protection scheme. The proposed schemes have been simulated using PSCAD
and MATLAB software and the results confirmed their validity.
Keywords: backup protection; distributed generation; distribution network; fault detection;
impedance-based protection; main protection; microgrid
Citation: Nobakhti, S.M.; Ketabi, A.;
Shafie-khah, M. A New
Impedance-Based Main and Backup
Protection Scheme for Active
Distribution Lines in AC Microgrids.
Energies 2021, 14, 274. https://
doi.org/10.3390/en14020274
Received: 22 November 2020
Accepted: 31 December 2020
Published: 6 January 2021
Publisher’s Note: MDPI stays neutral with regard to jurisdictional claims in published maps and institutional affiliations.
Copyright: © 2021 by the authors. Licensee MDPI, Basel, Switzerland.
This article is an open access article
distributed under the terms and conditions of the Creative Commons Attribution (CC BY) license (https://
creativecommons.org/licenses/by/
1. Introduction
Distributed generators (DGs) interconnected to distribution networks form a type
of power system called microgrid. Generally, microgrid(s) are composed of medium &
low voltage distribution system(s) equipped with DGs and loads, which can operate in
grid-connected and islanded modes in a controlled coordinated way. Increasing reliability
and resilience of power systems mainly is followed by this feature [1,2].
Despite the advantages of microgrids, large-scale implementation of microgrids results
in challenges in their control, conservation, and harmony with the main grid. The traditional protection strategies cannot be applied for microgrids because of bidirectional power
flow in feeders, the existence of looped feeder(s), and significantly decreasing magnitude of
the fault current in the islanded mode especially for the power inverter-interfaced DGs [3].
Also, the operation of reclosers in active distribution networks is challenging.
For a temporary fault in distribution networks, reclosers operate in a fast mode, and isolate
faulty section, for fault self-clearing. However, in the active distribution networks, in order
to ensure the correct operation of automatic reclosing, DGs have to be disconnected entirely before reconnecting. When a DG remains to operate after a fault, there may be two
problems if the utility was reconnected after a short interruption. Firstly, the fault may not
have been cleared because of arc feeding by DG. So, the instantaneous reclosing may not be
succeeded. Second, the frequency may change in the islanded part of the distribution grid
because of active power imbalance. In this case, coupling two asynchronously operating
systems with active sources on both sides of one recloser by reclosing switch results in the
failure of the attempt [4,5].
4.0/).
Energies 2021, 14, 274. https://doi.org/10.3390/en14020274
https://www.mdpi.com/journal/energies
Energies 2021, 14, 274
2 of 24
Thus, new intelligent industrial electronic devices composed with communicationbased protection schemes and synchro-phasor measurement technology present more
active and adaptive practical methods to solve the above-mentioned matters [6]. However,
fault detection using the communication link especially in the backup protection needs
to communicate data with the adjacent lines which increases the volume of required data
exchanges and costs. Moreover, it does not operate in the link disconnection. Therefore,
backup fault detection methods based on one line-end data shall be more valuable.
Generally, there are two classes for microgrids protection schemes. First, schemes that
change the network behavior during the fault in order to correct the operation of conventional protection ones, are called network modifying-based schemes. Second, modified
protection schemes according to microgrids behaviors are named protective strategybased schemes.
1.1. Network Modifying-Based Schemes
By altering grid-connected to islanded mode and vice versa in microgrids, significant
fault current level changes are observed. In [2] modification of grounding strategy was proposed to prevent mal-operation of conventional protection systems, and correct operation
conditions of relays were met by low investment.
External devices such as fault current limiters, flywheels, batteries, ultra-capacitors,
and devices installed between the main grid and microgrid, are used by some protection
strategies for modifying fault level in order to decrease the contribution of fault current
from the main grid. Generally, these schemes are expensive [7–9].
A protection scheme was proposed in [10] for the looped microgrids with conventional protection. By measuring indirectly microgrid impedance, faults were detected.
Then, DGs modified their control for injecting a current proportional to measured microgrid impedance, based on a droop curve. So, DGs nearer to fault injected a relatively bigger
current, and paved the way to elective coordination of relays.
1.2. Protective Strategy-Based Schemes
Protective strategy-based schemes consist of several microgrid protection ones. Adaptive schemes, as a group in this class, include automatic readjustment of relays settings
when microgrid alters from grid-connected mode to islanded mode and vice versa [11,12].
In [1], a protection scheme for radial and looped microgrids in both grid-connected and
islanded modes based on positive sequence impedance using Phasor Measurement Units
(PMUs) with a digital communication system was presented. Yet, updating pickup relays
values based on upstream and downstream tantamount positive-sequence impedances
of any line after a change of microgrid configuration was necessary. Reference [13] describes an adaptive protection system monitoring, in which operating modes of microgrid,
was the basis of relays settings online updating. Communication links were applied for
collecting data from smart electronic devices, and sending data to a central controller for
real-time analysis.
Replacing all existing relays with adaptive ones is expensive. Moreover, communication systems are necessary. Additionally, upgrading the present protection schemes of
distribution systems is required.
In differential-based schemes (as another group) currents arriving and departing
protected zone are compared. If the differential between these currents becomes more
than a preset threshold, these schemes operate. Two main subjects including voltage and
frequency control, also protection were investigated in [14]. In this scheme, differential
relays at two ends of every line were employed. Microgrid in both grid-connected and
islanded operation modes was protected by these relays. Sortomme and et al. in [15]
suggested a differential protection scheme on the basis of principles of synchronized
phasor measurements and microprocessor relays. Here, primary protection for one feeder
was depended on the instantaneous differential protection. If two samples absolute values
were higher than the trip preset threshold, a tripping signal is produced. In [16], on the
Energies 2021, 14, 274
3 of 24
basis of a variable tripping time differential protection, a multi-agent microgrid protection
scheme was proposed. It operated in grid-connected and islanded modes. Furthermore,
in [17], applying discrete Fourier transform, the differential characteristics were extracted
from fault current and voltage and for deciding finally, a decision-tree data mining model
was proposed.
Usually, in the differential schemes synchronized measurements and communication
infrastructures are required, and imbalanced loads and transients may affect protection.
Some voltage-based protection schemes are based on positive sequence component detection of fundamental voltage. In some others, the waveforms of three-phase voltages are
transformed into (d–q) reference frame. A protection technique was proposed in [18] based
on the effect of different fault types on Park components of voltage to protect microgrids.
Variation of the differential angles of bus voltages with the point of common coupling voltage was applied for protection schemes in [19]. Here, measuring synchronously voltages
angles of several buses was needed. This scheme detected faults in the microgrid but did
not the faulty line.
In these schemes, the fault type and the magnitude of voltage droop during fault
affected response time. Therefore, these are mostly dependent on microgrids operation
modes. Voltage fluctuations due to non-fault events in islanded operation mode may lead
to incorrect protection of these schemes.
There are other protection schemes based on overcurrent and symmetrical components.
In [20] a three-stage communication assisted selectivity scheme was suggested. Moreover,
an overcurrent relay characteristic for reducing the operating time of the overcurrent
relay was proposed in [21]. Zamani and et al. in [22] used zero (0) and negative (-)
sequence components of currents in the proposed protection scheme. Besides, in [23],
the voltage unbalances were applied for the overcurrent function enhancement. Generally,
these protection schemes greatly require wide-area communication systems.
Distance protection schemes use impedance or admittance measurements for detecting faults efficiently. Here, if a fault occurred downstream of the bus where DGs were
connected to the grid, the impedance seen by an upstream relay is higher than real fault
impedance. This leads to increase fault distance apparently, because of the increased
voltage owing to an added infeed at the common bus. This may cause incorrect distance
relays performance [24]. The effects of intermediate infeed and fault resistance on the
operation of distance relays in radial distribution feeders were examined in [25]. Moreover,
their combined effect on distance protection was evaluated, and results concerning the
appropriate operation of the relay were described. Reference [26] detected faults using
the inverse-time tripping admittance. Moreover, an impedance differential scheme as the
main protection and an inverse-time low-impedance scheme as backup protection was
suggested in [27]. Moreover, reference [28] proposed a compensation scheme to eliminate
errors caused by faults impedances and infeed currents. In [29], a voltage-free distance
protection scheme compatible with closed-loop structures and inter infeed was suggested.
It was based on measuring negative-sequence currents at relay location and unaffected
by negative-sequence current suppressing converter-connected DGs and fault resistances.
Reference [30] proposed an enhanced scheme based on time delay and zero-sequence
impedance, too.
Independence of fault level change in the grid-connected and islanded modes is the
most significant advantage of these schemes, however, the fault resistance and the infeed
caused by DGs may affect the measured impedance. Moreover, transient currents may lead
to inaccurate measurements.
So, there is a serious requirement for an impedance-based protection scheme with the
minimum effects of infeed, fault impedance, and transient situations on its performance.
In this article, novel main and backup impedance-based protection schemes in microgrids
are proposed. Advantages of the suggested main scheme are:
•
•
Proper operation in both grid-connected and islanded modes
Independence of network reconfigurations
Energies 2021, 14, 274
So, there is a serious requirement for an impedance-based protection scheme with
So, there effects
is a serious
requirement
for an impedance-based
protectionon
scheme
with
the minimum
of infeed,
fault impedance,
and transient situations
its perforthe minimum
infeed,
fault
and transient situations
its performance.
In this effects
article, of
novel
main
andimpedance,
backup impedance-based
protectiononschemes
in
mance. In this
article, novel
main andofbackup
impedance-based
protection
schemes in
microgrids
are proposed.
Advantages
the suggested
main scheme
are:
proposed.
Advantages
of the suggested
main
scheme are:
•microgrids
Proper are
operation
in both
grid-connected
and islanded
modes
4 of 24
••
••
•••
•••
•••
••
Proper operation
in both grid-connected
and islanded modes
Independence
of network
reconfigurations
Independence
of faults
network
reconfigurations
High
impedance
detection
High
impedance
faults
Short
time
Highresponse
impedance
faults detection
detection
Short
response
time
Low
sampling
rate
Short response time
Low
Minimum
data rate
exchange
Low sampling
sampling
rate
Minimum
data
Minimum
data exchange
exchange
Also,
the features
of the backup protection scheme are similar to the main one, exAlso,
the
features
backup
scheme
are
to
the
one,
cept in
the
capability
of
high
fault detection.
Moreover,
the
protection
Also, the features of
of the
theimpedance
backup protection
protection
scheme
aresimilar
similar
tobackup
the main
main
one,exexcept
in
the
capability
of
high
impedance
fault
detection.
Moreover,
the
backup
protection
scheme
does
not
require
data
exchange
and
communication
links,
which
is
a
great
merit.
cept in the capability of high impedance fault detection. Moreover, the backup protection
scheme
not
require
data
exchange
and
links,
is
merit.
Thisdoes
article
Section 2 introduces
sequence
equivalent
scheme
does
notcontains
require the
datafollowing
exchangesections.
and communication
communication
links, which
which
is aa great
great
merit.
This
contains
the
sections.
Section
circuits
forarticle
fault types,
applied
in the proposed
scheme.
In sequence
Section
3,equivalent
main and
This
article
contains
the following
following
sections.protection
Section22introduces
introduces
sequence
equivalent
circuits
in
proposed
protection
In
main
backup
impedance-based
schemes
for
faults detection
in scheme.
the microgrid
are 3,
suggested.
circuits for
for fault
fault types,
types, applied
applied
in the
the
proposed
protection
scheme.
In Section
Section
3,
main and
and
backup
schemes
detection
in
are
suggested.
The
case impedance-based
study
for the implementation
offaults
the proposed
schemes
is
in Section
4. Moreover,
backup
impedance-based
schemesfor
for
faults
detection
in the
the microgrid
microgrid
are
suggested.
The
case
for
the
isisin
4.4.Moreover,
in
Section
5, the
proposed
strategiesof
evaluated
by simulation
in PSCAD
and
The
case study
study
forthe
theimplementation
implementation
ofare
theproposed
proposedschemes
schemes
inSection
Section
Moreover,
in
Section
5,
the
proposed
strategies
are
evaluated
by
simulation
in
PSCAD
and
MATLAB
Finally,strategies
Section 6are
includes
the conclusion.
in Sectionsoftware.
5, the proposed
evaluated
by simulation in PSCAD and MATLAB
MATLAB
software.
Finally,
Section 6the
includes
the conclusion.
software. Finally,
Section
6 includes
conclusion.
2. Modified Equivalent Circuits for Doubly-Fed Lines During Faults
2.Modified
Modified Equivalent
Equivalent Circuits for
for Doubly-Fed
Doubly-Fed Lines During Faults
2.
In this section, an Circuits
equivalent sequence
circuit for doubly-fed distribution lines,
Ininthis
section,
ananequivalent
sequence
circuit
for
doubly-fed
distribution
lines, shown
In
section,
equivalent
sequence
circuit
for
doubly-fed
distribution
lines,
shown
Figure
1, during
short circuit
faults
has
been
discussed
by using
conventional
in
Figure
1,
during
short
circuit
faults
has
been
discussed
by
using
conventional
equivalent
shown in Figure
1, during
equivalent
sequence
circuits.short circuit faults has been discussed by using conventional
sequence circuits.
equivalent
sequence circuits.
A
I
A A
IB B
IB B
line
line
IA
Figure 1. Doubly-fed line.
Figure
Figure1.
1.Doubly-fed
Doubly-fedline.
line.
In the following, simplified positive sequence (SPS), simplified negative sequence
the
following,
simplified
positive
sequence
simplified
negative
sequence
(SNS)In
and
sequence
(SZS) equivalent
circuits
used in the
proposed
proIn
thesimplified
following,zero
simplified
positive
sequence (SPS),
(SPS),
simplified
negative
sequence
(SNS)
and
simplified
zero
sequence
(SZS)
equivalent
circuits
used
in
the
proposed
tection
strategy are introduced.
As shown
Figure 2,circuits
K represents
fault
< proK<
(SNS) and
zero sequence
(SZS) in
equivalent
used in
the location
proposed(0protectection
strategy
introduced.
shown
in
Figure
2, represents
K represents
fault
location
<K
<
tion
areare
introduced.
AsAs
shown
inLL
Figure
2, K
fault
location
(0 (0
<K
< 1)
1)
andstrategy
“i”
is replaced
by 3P (three-phase),
(line-to-line),
DLG (double-line-to-ground)
1)
and
is replaced
(three-phase),
LL
(line-to-line),
DLG
(double-line-to-ground)
and
“i”“i”
is(single
replaced
by by
3P 3P
(three-phase),
LLthe
(line-to-line),
(double-line-to-ground)
and
and
SLG
line-to-ground)
based on
fault
type.DLG
Positive
sequence by “1”, negaand
SLG
(single
based
onby
the
fault
type.
Positive
sequence
“1”,
SLGsequence
(single
line-to-ground)
based
on the
fault
type.
Positive
byZby
“1”,
negative
tive
by line-to-ground)
“2”, and zero
sequence
“0”
subscript
will sequence
be indexed.
l and
Znegal0 are
tive
sequence
by and
“2”,
and sequence
zero
“0”
subscript
will
be
Z
l
and
Z
l0 are
are
sequence
by “2”,
zero
by “0”by
subscript
will be Z
indexed.
Zt1,n
and
Z
are
positive
positive
and
zero
sequence
linesequence
impedance
respectively.
t,i, Z
t0,i,indexed.
V
,V
t2,i
and
V
t0,i
l
l0
and
zero
sequence
line
impedance
respectively.
Z
,
Z
,
V
,V
and
V
are
sequence
positive
and
zero
sequence
line
impedance
respectively.
Z
t,i
,
Z
t0,i
,
V
t1,n
,V
t2,i
and
V
t0,i
are
sequence equivalent impedances and voltages that
for fault
types dist,i will
t0,ibe explained
t1,n t2,i
t0,i
equivalent
impedances
and voltages
will be
explained
fault types
distinctively.
sequence
equivalent
impedances
andthat
voltages
that
will be for
explained
for fault
types distinctively.
tinctively.
+
+
IA1
IA1
VA1-Vt1,i
VA1--Vt1,i
-
(1-K)Zl
(1-K)Zl
KZl
KZl
IB1
IB1
+
+
+
-V
+
VB1 t1,i
VB1--Vt1,i
Zt,i
Zt,i
VA2-Vt2,i
VA2--Vt2,i
-
(a)
(a)
IA0
IA0
VA0-Vt0,i
VA0--Vt0,i
Zt0,i
Zt0,i
+
-
(1-K)Zl0
(1-K)Zl0
(1-K)Zl
(1-K)Zl
KZl
KZl
IB2
IB2
+
+
VB2-V
t2,i
VB2-V
- t2,i
Zt,i
Zt,i
-
KZl0
KZl0
+
IA2
IA2
(b)
-
(b)
IB0
IB0
+
+
VB0-V
t0,i
VB0-V
- t0,i
(c )
-
(c )
Figure2.2.(a)
(a)SPS
SPScircuit;
circuit;(b)
(b)SNS
SNScircuit;
circuit;(c)
(c)SZS
SZScircuit.
circuit.
Figure
Figure 2. (a) SPS circuit; (b) SNS circuit; (c) SZS circuit.
2.1. Three-Phase Faults
In this fault, three phases are connected to ground through resistance Rf . The equivalent circuit as shown in Figure 3 includes only the positive sequence.
Energies 2021, 14, x FOR PEER REVIEW
5 of 23
2.1. Three-Phase Faults
Energies 2021, 14, 274
In this fault, three phases are connected to ground through resistance Rf. The equiv2.1.
Three-Phase
Faults in Figure 3 includes only the positive sequence.
alent circuit as shown
5 of 24
In this fault, three phases are connected to ground through resistance Rf. The equivalentIA1
circuit as shown in(1-K)Z
Figure 3 includes
only the positive sequence.
IB1
KZl
l
+
IA1
VA1
KZl
Rf
IB1 +
VB1
(1-K)Zl
+-
+-
VB1
Rf
VA1
Figure
3. SPS equivalent circuit for 3P fault.
-
Comparing
Figure
3 and
Figure
2, the SPS equivalent circuit for this type of fault is
Figure
3.3.SPS
circuit
for
3P
Figure
SPSequivalent
equivalent
circuit
for
3Pfault.
fault.
obtained:
ComparingFigure
Figures32and
andFigure
3, the SPS
equivalent
circuit for
this type
of fault
Comparing
2, the
SPS equivalent
circuit
for this
typeisofobtained:
fault is
Z
=
R
(1)
obtained:
t ,3 P
f
Zt,3P = Rf
(1)
ZVt ,3 P ==R0f
(1)
(2)
t 1,3P
Vt1,3P
=0
(2)
Due
zero
Vt 1,3P
= 0sequence
(2)
Dueto
tothe
theabsence
absenceof
ofthe
thenegative
negativeand
and
zero
sequencecomponents
componentsin
inthis
thisfault
faulttype,
type,
there
are
no
SNS
and
SZS
circuits.
there are no SNS and SZS circuits.
Due to the absence of the negative and zero sequence components in this fault type,
2.2.
there
are no SNSFaults
and SZS circuits.
2.2.Line-to-Line
Line-to-Line
Faults
In
line-to-line(LL)
(LL)fault,
fault,two
two
lines
connected
through
resistance
Rfequiv. The
In the line-to-line
lines
are are
connected
through
resistance
Rf . The
2.2.
Line-to-Line
Faults
equivalent
circuit
contains
positive
and negative
sequences
as shown
in Figure
4.
alent
circuit
contains
positive
and negative
sequences
as shown
in Figure
4.
In the line-to-line (LL) fault, two lines are connected through resistance Rf. The
equivalent
positive
sequences as shown in Figure 4.
IA1 circuit
(1-K)Zl and Inegative
B1
KZcontains
l
+
VA1
IA1
KZl
Rf
IB1
(1-K)Zl
IB2 VB1
+
VA2
(1-K)Zl
IB2
VB1
+-
+-
VA1
+
(1-K)Zl
IA2
KZl
IA2
KZl
Rf
+
VB2
+-
+-
VA2
VB2
Figure
4.4.Sequence
Figure
Sequenceequivalent
equivalentcircuits
circuitsfor
forLL
LLfault.
fault.
-
the
circuit
FigureBy
4. maintaining
Sequence
equivalent
circuitssequence
for LL fault.
By
maintaining
the positive
positive
sequence
circuit and
and converting
converting the voltage VA2
series
A2 series
with
the
voltage
VB2Vseries
withwith
(1-K)Z
their
corresponding
dependent
current
withKZ
KZl and
the
voltage
(1 l−toK)Z
their corresponding
dependent
B2 series
l and
l to
By maintaining
the
circuit
and
converting
theequivalent
voltage
Vcircuit
A2 series
sources
parallel
thepositive
impedance,
and then
simplifying,
the SPS
is
current
sources with
parallel
with
thesequence
impedance,
and
then
simplifying,
the
SPS equivalent
with
KZisl and
theZvoltage
series
with
(1-K)Z
l
to
their
corresponding
dependent
current
obtained
where
t,LL
and VZB2
t1,LL
are
defined
as
follows:
circuit
obtained
where
and
V
are
defined
as
follows:
t,LL
t1,LL
sources parallel with the impedance, and then simplifying, the SPS equivalent circuit is
Z t ,LL== RRas
+K
K((11−
−K
Zll
(3)
K))Z
(3)
obtained where Zt,LL and Vt1,LL areZdefined
t,LL
f f+follows:
(
)
(
)
+KK
K
Vt1,LL
===(1R1−
)V( 1A2− +
) Z l B2
VZ t ,LL
+ KV
f− K V
t1,LL
A2
B2
(4)
(3)
(4)
Similarly, by maintaining the negative sequence circuit and simplifying, SNS circuit is
Similarly, by maintaining theVnegative
circuit and simplifying, SNS circuit
= 1 −sequence
K VA 2 + KV
(4)
t1,LL
B2
obtained, in which:
is obtained, in which:
Vt2LL = (1 − k)VA1 + K.VB1
(5)
Similarly, by maintaining the
negative sequence circuit and simplifying, SNS circuit
(5)
V
=
1
−
k
V
+
K.
V
is obtained,
in which:
It should
be mentioned that the SZS circuit does not exist in this fault type.
It should be mentioned that the SZS circuit does not exist in this fault type.
(5)
2.3. Single-Line-to-Ground V
Faults = 1 − k V + K. V
ItSingle-line-to-ground
should be mentioned (SLG)
that the
SZSoccurs
circuitwhen
does not
in connected
this fault type.
fault
oneexist
line is
to the ground
through resistance Rf . Figure 5 depicts the sequence equivalent circuits for this fault.
Energies 2021, 14, x FOR PEER REVIEW
6 of 23
2.3. Single-Line-to-Ground Faults
Energies 2021, 14, 274
6 of 24
Single-line-to-ground (SLG) fault occurs when one line is connected to the ground
through resistance Rf. Figure 5 depicts the sequence equivalent circuits for this fault.
IA1
(1-K)Zl
KZl
IB1
+
+
VA1
VB1
-
-
IA2
(1-K)Zl
KZ l
IB2
+
+
VA2
VB2
-
-
IA0
(1-K)Zl0
KZ l0
3Rf
IB0
+
+
VA0
VB0
-
-
Energies 2021, 14, x FOR PEER REVIEW
7 of 23
Figure
Figure5.5.Sequence
Sequenceequivalent
equivalentcircuits
circuitsfor
forSLG
SLGfault.
fault.
By
Bymaintaining
maintainingthe
thepositive
positivesequence
sequencecircuit
circuitand
and simplifying
simplifyingtwo
two other
other sequence
sequence
circuits,
way
SNS
and
SZS
are
attained:
circuits,SPS
SPSisisobtained
obtainedand
andby
bythe
thesame
same
way
SNS
and
SZS
are
attained:
3K ( 1 − K ) Z l 0 + 4R f
M=
(14)
3K
1
−
K
Z
+
Z
+
5R
(
)(
)
=
3R
+
K
1
−
K
Z
+
Z
(6)
ZZ
=
3R
+
K
1
−
K
Z
+
Z
(6)
(
)(
)
l
l
0
f
t,SLG
ff
ll
t ,SLG
ll0
0
(
)(
)
( 1 +− KV)A0Z) −+ RK(VB2 + VB0 )
Vt1,SLG
1 − K)(3K
VA2
Vt 1,SLG==−(
N− =1 − K VA 2 + VA 0 l− K f VB2 + VB0
3KK()(1V
−A1
K )(
+ )Z−
) + 5R
Vt2,SLG = −(1 −
+ ZVlA0
l 0 K(VB1f + VB0 )
(
)(
)
(
)
(
)(
)
(
)
Vt 2 ,SLG = − 1 − K VA1 + VA 0 − K VB1 + VB0
Zt0,SLG in
= 3R
Similarly SZS circuit is achieved
which:
f + 2K(1 − K)Zl
(7)
(7)
(15)
(8)
(8)
(9)
Z1t 0 −
= 3RA1
+ 2K ( 1)−−
K)Z
Vt0,SLG = −(
(Vl B1 + VB2 )
,SLGK)(V
Kf 1+−VKA2
Z l +K
3R
f
Z t 0 ,DLG =
2.4. Double-Line-to-Ground
V Faults
= − 1− K V + V 2 − K V + V
(
)
)
(
)
(
(9)
(10)
(16)
(10)
t 0 ,SLG
A1
A2
B1
B2
Double-line-to-ground (DLG) fault takes place when two lines are connected through
1− K
K
resistance Rf and every line
is connected
through
the ground. Figure
6
(17)
=
+ resistance
Vt 0 ,DLG
VA1 + VA 2this
VB1 + VBto
2
2.4.
Double-Line-to-Ground
Faults
2 this fault.
2
shows
sequence equivalent
circuits for
Double-line-to-ground (DLG) fault takes place when two lines are connected
through resistance Rf and every line is connected through this resistance to the ground.
IA16 showsKZ
IB1
f /3 fault.
Figure
sequence
equivalent
forRthis
(1-K)Zl circuits
l
Zt,DLG, Vt1,DLG and Vt2,DLG will be determined
based on the SNS and SPS equivalent
+
+
circuits as follows:
VA1
VB1
(
(
-
IA2
+
VA2
-
KZl
Z t ,DLG =
)(
)
(
)
)
( 3K ( 1 − K )- Z l 0 + 4R f ) ( 3K ( 1 − K ) Z l + R f )
+
3
3IB2
( 3K ( 1 − RKf)(/3Z l + Z l 0 ) + 5R f )
(1-K)Z
l
Rf
(11)
Vt 1,DLG = M ( ( 1 − K ) VA 2 + KVB2 ) + N ( ( 1 − K ) VA0 + KVB0 )
(12)
Vt 2 ,DLG = M ( ( 1 − K ) VA1 + KVB1 ) + N ( ( 1 − K ) VA0 + KVB0 )
(13)
+
VB2
-
IA0
IB0
(1-K)Zl0
KZl0
where M and N are defined as follows:
4Rf /3
+
+
VA0
VB0
-
-
Figure 6.
6. Sequence
equivalent circuits
circuits for
for DLG
DLG fault.
fault.
Figure
Sequence equivalent
3. Proposed Protection Scheme for Distribution Lines
3.1. Main Protection Scheme
In the previous section, SPS, SNS and SZS equivalent circuits were obtained for the
fault types. UsingY-Δ transform, SPS and SNS circuits can be redesigned as Figure 7, as
followed:
Energies 2021, 14, 274
7 of 24
Zt,DLG , Vt1,DLG and Vt2,DLG will be determined based on the SNS and SPS equivalent
circuits as follows:
Zt,DLG =
Rf
(3K(1 − K)Z0 + 4Rf )(3K(1 − K)Zl + Rf )
+
3
3(3K(1 − K)(Z1 + Z10 ) + 5Rf )
(11)
Vt1,DLG = M((1 − K)VA2 + KVB2 ) + N((1 − K)VA0 + KVB0 )
(12)
Vt2,DLG = M((1 − K)VA1 + KVB1 ) + N((1 − K)VA0 + KVB0 )
(13)
where M and N are defined as follows:
M=
3K(1 − K)Zl0 + 4Rf
3K(1 − K)(Zl + Zl0 ) + 5Rf
(14)
N=
3K(1 − K)Zl + Rf
3K(1 − K)(Zl + Zl0 ) + 5Rf
(15)
Similarly SZS circuit is achieved in which:
K(1 − K)Zl + 3Rf
2
(16)
K
(1 − K)
(VA1 + VA2 ) + (VB1 + VB2 )
2
2
(17)
Zt0,DLG =
Vt0,DLG =
3. Proposed Protection Scheme for Distribution Lines
3.1. Main Protection Scheme
In the previous section, SPS, SNS and SZS equivalent circuits were obtained for the
fault types. UsingY-∆ transform, SPS and SNS circuits can be redesigned as Figure 7,
as followed:
Energies 2021, 14, x FOR PEER REVIEW
8 of 23
Zt,i
ZI,i = KZl +
(18)
1−K
K(1 − K)Z2l
ZII,iR=
Zl Moreover,
+
(19)
sequence line impedance angle for
f=0.
Zt,i Figure 9 shows the magnitude and
angle of ZII,LL will be equal to the positive sequence line impedance, in normal conditions.
Zt,i
However during faults, its angle Z
variations
are low. Moreover,
its magnitude variation
is
(20)
III,i = (1 − K).Zl +
K
low, except in small Rf.
IA1
+
VA1-Vt1,i
ZIII,i
ZI,i
(a)
IA2
IB1
ZII,i
+
+
VB1-Vt1,i
VA2-Vt2,i
-
-
IB2
ZII,i
+
ZIII,i
ZI,i
VB2-Vt2,i
-
(b)
Figure 7.
7. Transformed
Transformed (a)
(a) SPS and
and (b) SNS circuit to equivalent delta.
Figure
Figures 8 and 9 show Rf -ZI,LL and Rf -ZII,LL curves for LL fault in several fault locations.
According to Figure 8, the magnitude of ZI,LL increases by increasing Rf , therefore in normal
conditions where Rf is infinite, ZI,LL is infinite and its angle is zero, But when a fault occurs,
its magnitude decreases drastically and its angle increases up to positive sequence line
impedance angle for Rf =0. Moreover, Figure 9 shows the magnitude and angle of ZII,LL
will be equal to the positive sequence line impedance, in normal conditions. However
during faults, its angle variations are low. Moreover, its magnitude variation is low, except
in small Rf .
These facts are true for other fault types. The proposed fault detection scheme is based
on high reduction in ZI,i during the fault, compared to normal conditions.
+
IA1
IA1
VA1+-Vt1,i
VA1-V
- t1,i
-
Energies 2021, 14, 274
IB1
IB1
ZII,i
ZII,i
ZIII,i
ZIII,i
ZI,i
ZI,i
(a)
(a)
+
VB1+-Vt1,i
+
IA2
IA2
VB1-V
- t1,i
VA2+-Vt2,i
VA2-V
- t2,i
-
-
IB2
IB2
ZII,i
ZII,i
ZIII,i
ZIII,i
ZI,i
ZI,i
(b)
(b)
+
VB2+-Vt2,i
VB2-V
- t2,i
-
8 of 24
Figure 7. Transformed (a) SPS and (b) SNS circuit to equivalent delta.
Figure 7. Transformed (a) SPS and (b) SNS circuit to equivalent delta.
Figure 8.
I,LL curve for several fault location.
Figure
8.RRf-Z
f -ZI,LL curve for several fault location.
Figure 8. Rf-ZI,LL curve for several fault location.
Figure 9. Rf-ZII,LL curve for several fault location.
Figure 9. Rf-ZII,LL curve for several fault location.
Figure 9. Rf -ZII,LL curve for several fault location.
These facts are true for other fault types. The proposed fault detection scheme is
These
factsreduction
are true in
forZI,iother
fault
The
proposed
fault detection
is
based
onapplying
high
during
thetypes.
fault,
compared
to normal
conditions.
By
KCL and
KVL
in
SZS
and Figure
7 circuits,
(21)–(23)
arescheme
obtained.
In these
basedBy
onapplying
high reduction
in ZKVL
I,i during
the and
fault,Figure
compared
to normal
conditions.
KCL
and
in
SZS
7
circuits,
(21)–(23)
are
obtained.
equations Vt1,i , Vt2,i and Vt0,i are functions of K, Rf , the sequence voltages in theInline ends
applyingVKCL
and
KVL
SZS
and Figure
(21)–(23)
are obtained.
In
t1,i, Vt2,i
and
Vt0,iinare
functions
of K,7Rcircuits,
the sequence
voltages
in the line
theseByequations
and
the sequence
lineand
impedances.
Moreover,
Kf,and
Rf are substituted
by line
ZI,i and ZII,I
Vt0,i are functions
of K, RKf, and
the sequence
voltages in
these
Vt1,i, Vt2,i line
ends equations
and the sequence
impedances.
Moreover,
Rf are substituted
bythe
ZI,i and
according
tosequence
(18) and line
(19).impedances.
Obviously,Moreover,
some of these
will not by
be Zused
due to the
ends
and the
K andequations
Rf are substituted
I,i and
absence of zero or negative sequences for some fault types.
IA1 =
V − Vt1,n
VA1 − VB1
+ A1
ZII,n
ZI,n
V − Vt2,n
VA2 − VB2
+ A2
ZII,n
ZI,n
V − VA0 + K.Zl0 .IA0
VA0 − Vt0,n − K.Zl0 .IA0 − Zt0,n . IA0 + B0
=0
(1 − K).Zl0
IA2 =
(21)
(22)
(23)
As stated earlier, in normal conditions, ZI,i tends to be a real large number. If the
absolute value of VB1 is extracted from (21)–(23) and equals with its value sent from end
B, and ZII,i is replaced by its normal condition value (Zl ), an equation will be obtained in
terms of ZI,i . By assuming ZI,i as a real number (as in normal conditions), two values can
be obtained for ZI,i . one is negative that is ineligible and the other is infinite in normal
conditions, and limited and positive during the fault. It is clear that during the fault, ZII,i is
not exactly equal to Zl , So calculated ZI,I will include some errors. These can be ignored
Energies 2021, 14, 274
9 of 24
because, in normal conditions, ZI,i is infinite and it is greatly reduced when a fault with
limited resistance occurs. So, some errors for this value during the fault, it is acceptable.
The Fault Detection Index (FDIi ) is defined as follows:
Ci
FDIi = log
(24)
ZI,i
where Ci is a constant coefficient and considered a little greater than ZI,i in high impedance
fault near the end B.
In normal conditions FDIi is negative. It may become positive transiently for external
faults. Hence, positive FDIi for consecutive M samples shall indicate fault occurrence.
Therefore, in order to command the switches of terminal A, data including sequence
voltages and currents of terminal A and the absolute value of the positive sequence voltage
of terminal B are required. Sending minimum data from the other side of the line (only one
parameter) reduces the amount of transmitted data. However, in the protection schemes
so far, such as [27] it is usually necessary to send at least two parameters (magnitude
and angle). So, data exchange reduces by 50% in the proposed scheme. Each line has
two relays, one at the beginning and one at the end of the line. Therefore, in networks
with a large number of lines, the data exchange volume will increase and this reduction is
valuable. Moreover, the communication system may is used to exchange data in addition
to the protection system data. Therefore, reducing the data exchange volume in the
proposed protection system can make it possible to use the communication system in other
applications.
The nonlinearity of the line parameters often affects transient state studies. In distribution lines, due to the resistance is large compared to the reactance, the transient state
is damped quickly. Therefore, the non-linearity of the line parameters does not affect
the proposed scheme, which uses phasor quantities. Moreover, leakage current due to
Energies 2021, 14, x FOR PEER REVIEW
10 of 23
insulators is very low and it does not affect the correct performance of the proposed scheme.
However, because the proposed main protection scheme is capable to detect high resistance
faults, if the leakage current increases due to pollution of insulators or their insulation
Moreover,
in [27]
3 plans
to detect
low,
medium,
andin
high
problems, the
thescheme
schemepresented
may detect
it asincluded
a fault and
command
trip.
The
flowchart
Figure
resistance
fault,
but
the
proposed
scheme
detects
all
fault
by
one
plan.
10 explains this scheme.
m=0
Measurment of VA ,I A , VB1
no
Calculate FDI i
FDI i >0
no
yes
m=m+1
m=M
yes
Fault detection
Figure 10. Flowchart of the proposed main protection scheme.
Figure 10. Flowchart of the proposed main protection scheme.
3.2. Backup
Protectionmain
Scheme
The proposed
protection scheme can detect all types of faults, but the scheme preIn [27],
theonly
reactance
seen from
the beginning
the lineand
was
applied for
fault
desented
in [27]
could detect
single-phase
to theofground
two-phase
ones.
Moreover,
tection.
Under
normal conditions,
the positive
impedance
seen
from
the
bethe scheme
presented
in [27] included
3 plans sequence
to detect low,
medium,
and
high
resistance
ginning
ofthe
theproposed
line may scheme
be different
depending
on one
operation
fault, but
detects
all fault by
plan. modes of the microgrid
(grid-connected or islanded) and, transition direction of the active and reactive power in
the line. These different pre-fault conditions affect the during the fault impedance seen
from the beginning of the line, when the fault is not solid. Therefore, the scheme proposed in [27] performed well for very low fault resistance, but it seriously is challenged
for fault resistance partial increasing.
In the distribution line in Figure 11, “DG” and “load” represent DGs total power and
yes
Fault detection
Energies 2021, 14, 274
Figure 10. Flowchart of the proposed main protection scheme.
10 of 24
3.2. Backup Protection Scheme
[27], the
reactance
seen from the beginning of the line was applied for fault de3.2. In
Backup
Protection
Scheme
tection.InUnder
normal
conditions,
thethe
positive
sequence
seen from
thedetection.
be[27], the reactance seen from
beginning
of the impedance
line was applied
for fault
ginning
of
the
line
may
be
different
depending
on
operation
modes
of
the
microgrid
Under normal conditions, the positive sequence impedance seen from the beginning of the
(grid-connected
or islanded)
and, transition
direction
of the
active
and reactive
power in or
line may be different
depending
on operation
modes
of the
microgrid
(grid-connected
the
line.
These
different
pre-fault
conditions
affect
the
during
the
fault
impedance
seen difislanded) and, transition direction of the active and reactive power in the line. These
from the beginning of the line, when the fault is not solid. Therefore, the scheme proferent pre-fault conditions affect the during the fault impedance seen from the beginning
posed in [27] performed well for very low fault resistance, but it seriously is challenged
of the line, when the fault is not solid. Therefore, the scheme proposed in [27] performed
for fault resistance partial increasing.
well for very low fault resistance, but it seriously is challenged for fault resistance partial
In the distribution line in Figure 11, “DG” and “load” represent DGs total power and
increasing.
total load, in downstream of bus B, respectively. DG positive sequence admittance is YG1
In the distribution line in Figure 11, “DG” and “load” represent DGs total power
and load positive sequence admittance is YD1. So, the equivalent positive sequence adand total load, in downstream of bus B, respectively. DG positive sequence admittance is
mittance Yeq1 is:
YG1 and load positive sequence admittance is YD1 . So, the equivalent positive sequence
admittance Yeq1 is:
Yeq1 = YD1 + YG1 = G eq1 + jBeq1
(25)
Yeq1 = YD1 + YG1 = Geq1 + jBeq1
(25)
where, the real and imaginary parts of Yeq1 are named Geq1 and Beq1. Moreover, positive
where, the
real and seen
imaginary
parts
of Yeq1 are named
Geq1
and Beq1 . Moreover, positive
sequence
admittance
from bus
A, represented
by Ytot1 is
considered:
sequence admittance seen from bus A, represented by Ytot1 is considered:
Ytot1 = Gtot1 + jBtot1
(26)
Ytot1 = Gtot1 + jBtot1
(26)
Gtot1 and Btot1 are real and imaginary part of Ytot1.
A
...
IA
line
B
DG
Load
Figure
Network
with
lumped
downstream.
Figure11.
11.
Network
with
lumped
downstream.
Gtot1 and Btot1 are real and imaginary part of Ytot1 .
In normal conditions, ignoring line impedance, Ytot1 is equal to Yeq1 , and according to
Geq1 and Beq1 values, it may be at any point of the complex coordinate system.
If a fault with resistance Rf occurred at line AB, regardless of the line impedance and
Yeq1 changes during the fault, Rf becomes parallel to Yeq1 , so Ytot1 moves to the right at
complex coordinate plane. By a lower Rf , admittance Ytot1 will move further to the right at
complex coordinate plane. This conductance variation is defined as Conductance Variation
Index (CVI) which is a basis for proposed fault detection scheme. CVI is shown in Figure 12
and obtained as follows:
CVI = Gtot1 − Geq1
(27)
In normal conditions, CVI is zero, and it increases during faults. By setting an appropriate threshold for CVI, the fault will be detected. Threshold value should be set in
order not to recognize connecting a large load as a fault by protection system. Therefore,
considering Sload,max as maximum sudden load increase, the threshold value CVIthr is
obtained as follows:
Sload,max
CVIthr = 2
(28)
VLL,rated
where VLL,rated is rated line to line voltage of the network.
In grid-connected mode, DGs inject constant powers and their output powers do
not change as the load increases, so Yeq1 remains constant. However in islanded mode,
as the network load increases, the power outputs of the DGs increase for supplying the
added load. So, if Yeq1 is at the left half of the complex coordinate plane, the absolute value
of Yeq1 increases, and it moves to the left at the complex plane, so there is not possible
to detect load adding as a fault. Moreover, if Yeq1 is at the right half of the complex
Energies 2021, 14, 274
If a fault with resistance Rf occurred at line AB, regardless of the line impedance and
Yeq1 changes during the fault, Rf becomes parallel to Yeq1, so Ytot1 moves to the right at
complex coordinate plane. By a lower Rf, admittance Ytot1 will move further to the right at
complex coordinate plane. This conductance variation is defined as Conductance Variation Index (CVI) which is a basis for proposed fault detection scheme. CVI is shown11inof 24
Figure 12 and obtained as follows:
CVI = Gand
− Geq1 to the left at the complex(27)
plane, the absolute value of Yeq1 decreases,
plane,
tot1 it moves
accordingly, mal-operation of backup protection system shall be impossible, too
Im
Geq1
Gtot1
Re
Yeq1
Ytot1
CVI
Figure12.
12. Definition
Definition of
of CVI.
Figure
CVI.
In normal
conditions,
CVIdownstream
is zero, and of
it increases
faults.
Byitsetting
an exceed
apSo,
by changing
the load
the relay, during
CVI varies
but
does not
propriate
threshold
CVI, theGfault
will
be
detected.
Threshold
value
should
be
set
in
its
threshold.
In thisfor
situation,
should
be
updated
to
G
for
the
next
calculations.
eq1
tot1
Energies 2021, 14, x FOR PEER REVIEW
12 of 23
order not to
a large
as a fault
by protection
system. Therefore,
Moreover,
if recognize
the fault isconnecting
tripped by
mainload
protection,
before
backup protection
operation,
considering
Sload,max
as maximum
load
the isthreshold
value
CVIthr13.
is obthen
Geq1 should
be updated.
Thesudden
flowchart
of increase,
this scheme
described
in Figure
In this
tained
as
follows:
flowchart, ε represents the measurement error, and ∆Gtot1 is the difference between the
backup protection. Moreover, because of Geq1updating, this scheme
is robust against
value
of Gtot1 and its value in the previous sample. N is the number of samples during
network reconfigurations.
S load ,max
which the backup protection is waiting
the
CVIfor
= main protection operation.
(28)
thr
2
VLL,rated
Start
where VLL,rated is rated line to line voltage of the network.
In grid-connectedn=0
mode, DGs inject constant powers and their output powers do not
change as the load increases, so Yeq1 remains constant. However in islanded mode, as the
f=0
network load increases, the power outputs of the DGs increase for supplying the added
load. So, if Yeq1 isMeasurment
at the leftof half
of the complex coordinate plane, the absolute value of Yeq1
V A, IA
no
increases, and it moves to the left at the complex plane, so there is not possible to detect
load adding as a fault. Moreover, if Yeq1 is at the right half of the complex plane, the abG tot1
f=1
yes of Yeq1Calculate
solute value
decreases, and it moves to the left at the complex plane, accordingly,
no
mal-operation of backup protection system shall be impossible, too
|ΔGtot1|< ε
Geq1=Gtot1
So, by changing the
load downstream
of the relay, CVI varies but it does not exceed
its threshold. In this situation,
Geq1 should be updated to Gtot1 for the next calculations.
yes
Moreover,
if the fault is tripped by main protection, before backup protection operation,
no
ε
f=0
then Geq1|CVI|<
should
be updated.
The yes
flowchart of this scheme is described in Figure 13. In
this flowchart, ε represents
the measurement error, and ΔGtot1 is the difference between
no
the value of Gtot1 and its value in the previous sample. N is the number of samples during
Calculate CVI
which the backup protection is waiting for the main protection operation.
no
It is notable
that in high resistance faults,
CVI may don’t reach its threshold or DGs
no
CVI>CVI
controllers may be able tothrcompensate for the impedance changes due to the fault, so,
CVI will not be able toyesdetect high resistance faults, but, compared to the scheme proposed in [27], it performs better in presence fault resistance. Moreover, the elimination of
n=0
yes
the communication link is a great advantage of this scheme and makes it appropriate for
no
S=CVI
|CVI-S|< ε
yes
n=n+1
n=N
yes
Fault is detected
Figure
13.13.
Flowchart
of backup
protection
scheme.
Figure
Flowchart
of backup
protection
scheme.
4. Case Study
To evaluate the proposed scheme, an active distribution network 50 Hz in Figure 14
was simulated in PSCAD and calculated in MATLAB [27]. The network consists of two
0.4 kV and 10 kV subnets connected to the 35 kV main network through a transformer.
Energies 2021, 14, 274
12 of 24
It is notable that in high resistance faults, CVI may don’t reach its threshold or DGs
controllers may be able to compensate for the impedance changes due to the fault, so, CVI
will not be able to detect high resistance faults, but, compared to the scheme proposed
in [27], it performs better in presence fault resistance. Moreover, the elimination of the
communication link is a great advantage of this scheme and makes it appropriate for
backup protection. Moreover, because of Geq1 updating, this scheme is robust against
network reconfigurations.
4. Case Study
To evaluate the proposed scheme, an active distribution network 50 Hz in Figure 14
13 two
of 23
simulated in PSCAD and calculated in MATLAB [27]. The network consists of
0.4 kV and 10 kV subnets connected to the 35 kV main network through a transformer.
The fault level in the coupling point with the utility is 500 MVA and R/X ratio is 0.1.
DG1 The
is a battery-energy-storage
systemand
(BESS)
with a nominal
of 200are0.38
kVA, DG2
is
positive sequence resistance
inductance
of the 10power
kV feeder
Ω/km
a
100
kVA
combined
cool,
heat,
and
power
(CCHP)
and
DG3
is
a
photovoltaic
cell
with
and 1.432 mH/km, respectively and zero sequence ones are0.76 Ω/km and 4.2 mH/km.
a nominal
of 50
kVA.generator
Positive and
negative
resistance
There
is a power
600 kVA
diesel
(DG4)
at thesequence
end of this
feeder.and
Theinductance
loads 7 toof9
0.4 kV lines
are kVA,
0.32 Ω/km
andand
0.261
and
zero sequence
1.1 Ω/km and
powers
are 100
500 kVA
500mH/km,
kVA with
power
factor 0.85ones
lag,are
respectively.
0.955The
mH/km.
The loads
1 to 6 powers
are 40
kVA, 20 kVA,
40 kVA, 40
5 kVA
low-voltage
subsystem
can form
a microgrid,
continuing
to kVA,
energize
0.4and
kV
25
kVA
with
power
factor
0.9
lag,
respectively.
The
shunt
capacitor
is
20
kVAr.
feeders during islanded mode operation. The control of BESS or CCHP switches from
positive
sequence voltage
resistance
and
inductance
the 10 kV
are 0.38
Ω/km
P-Q The
to v-f
for supporting
and
frequency
butofbecause
of feeder
PV system
nature,
it
and
1.432
mH/km,
respectively
and
zero
sequence
ones
are
0.76
Ω/km
and
4.2
mH/km.
maintains P-Q control regardless of grid-connected or islanded mode operation. MoreoThere
is output
a 600 kVA
dieselofgenerator
(DG4)
the end ofisthis
feeder.
to 9times
powers
ver, the
current
DG during
faultatconditions
limited
toThe
1.5(1loads
and 7half)
of
are
100
kVA,
500
kVA
and
500
kVA
with
power
factor
0.85
lag,
respectively.
rated current.
Energies 2021, 14, x FOR PEER REVIEW
was
Utility
Grid
35kV
10kV
0.4kV
DG1
Brk13
Brk14
Relay location
G
A
Line4
100m
Brk10
Brk3
Line3
100
E
Load8
Line8
3km
Brk6
Load7
Brk2
Load4
Line5
200m
DG2
Brk12
B
Load3
Brk11
Line1
200m
D
Brk5
H
Brk1
Feeder1
Line7
3km
Brk4
Feeder2
Shant Capacitor
Feeder3
Feeder4
Brk9
Load1
Line2
100m
Brk7
C
F
I
Brk8
Line6
100m
Load9
Load5
Load2
DG3
DG4
Load6
Figure 14.
Case study
study system.
system.
Figure
14. Case
The low-voltage
subsystem
can form
a microgrid, continuing to energize 0.4 kV
5. Evaluation
of the Proposed
Protection
Schemes
feeders during islanded mode operation. The control of BESS or CCHP switches from P-Q
In this case study, protection of line 4 is more difficult compared to others, because it
to v-f for supporting voltage and frequency but because of PV system nature, it maintains
is
connected
to the main
grid and DG1 or
in islanded
upstream,
and operation.
DG2 and DG3
downstream.
In
P-Q control regardless
of grid-connected
mode
Moreover,
the output
the
islanded
in v-f
controltoand
DG3
P-Qtimes
control.
So, ifcurrent.
the procurrent
of DGmode,
duringDG2
faultoperates
conditions
is limited
1.5(1
andinhalf)
of rated
posed schemes protect line 4 accurately, it will protect other lines properly.
5.1. Main Protection Scheme Evaluation
To evaluate the proposed protection scheme, different faults with different fault resistances at line 4 were studied. Moreover, faults at lines 3 and 5 are investigated for its
performance in external faults. The fault occurs at t = 10 s and the sampling frequency is
Energies 2021, 14, 274
13 of 24
5. Evaluation of the Proposed Protection Schemes
In this case study, protection of line 4 is more difficult compared to others, because it
is connected to the main grid and DG1 in upstream, and DG2 and DG3 downstream. In the
islanded mode, DG2 operates in v-f control and DG3 in P-Q control. So, if the proposed
schemes protect line 4 accurately, it will protect other lines properly.
5.1. Main Protection Scheme Evaluation
To evaluate the proposed protection scheme, different faults with different fault
resistances at line 4 were studied. Moreover, faults at lines 3 and 5 are investigated for its
performance in external faults. The fault occurs at t = 10 s and the sampling frequency is
200 Hz.
Ci should be set in order to be positive for the highest intended fault resistance at the
end of the line. Therefore considering faults at 90% of line 4 and fault resistance 50 ohm,
C3P , CDLG , CLL, and CSLG were obtained 550, 330, 550, and 1640 respectively.
Figure 15 shows FDI3P curve for a three-phase fault with a fault resistance 0.01 ohm
at 50% of line 4 and 10% of line 5 in the grid-connected mode. When a fault happens at
line 4, FDI3P raises quickly and remains positive. However, when a fault occurs at 10%
of line 5, FDI3P increases transiently and droops rapidly. Considering all fault types with
different resistances at different locations, M (number of samples in which FDIi should
remain positive) was equal to 6.
Tables 1–4 show FDIi values of the relay at beginning of line 4 after 6 consecutive positive samples, and response time of the proposed scheme for fault resistance 0.01 to 50 ohm.
of 23
For the faults at line 4, FDIi was positive constantly, and trip command was generated14after
6 consecutive positive samples for Brk4 to disconnect the faulty line. Moreover, for external
faults (in adjacent lines), FDIi remains negative or becomes transiently positive, and then
the
trip command
is not
Similarly, M
this(number
scheme can
be implemented
the
relay
i should
different
resistances
atgenerated.
different locations,
of samples
in whichfor
FDI
atremain
the endpositive)
of line 4was
to command
equal to 6.Brk5. Therefore, Brk4 and Brk5 disconnect the faulty line.
Energies 2021, 14, 274
1
4
0
2
-1
FDI
FDI
3P
3P
3
1
-2
0
-3
-1
9.95
10
10.05
10.1
10.15
-4
9.95
10
10.05
10.1
10.15
time(sec)
time(sec)
(b)
(a)
Figure
Figure15.
15.FDI
FDI
forthree-phase
three-phasefault
faultwith
withresistance
resistance0.01
0.01ohm
ohminingrid-connected
grid-connectedmode
modeatat(a)
(a)50%
50%ofofline
line4 4(permanently
(permanently
3P3Pfor
positive)(b)
(b)10%
10%ofofline
line5 5(transiently
(transiently
positive).
positive)
positive).
Unlike
the transmission
lines, because
of a short
distanceof
between
data sending
and
Tables1–4
show FDIi values
of the relay
at beginning
line 4 after
6 consecutive
receiving
in and
distribution
presence
in transmitted
data is
rare, and0.01
usually,
positive points,
samples,
responselines
timenoise
of the
proposed
scheme for fault
resistance
to 50
itohm.
is notFor
investigated.
Moreover,
due
to
short
lines
in
distribution
networks,
fault
location
the faults at line 4, FDIi was positive constantly, and trip command was generdetermination
is not applicable.
ated after 6 consecutive
positive samples for Brk4 to disconnect the faulty line. Moreover,
Normally,
in the
circuit
faults
the or
pre-fault
line
currents posiare
for external faults
(in short
adjacent
lines),
FDIinvestigations,
i remains negative
becomes
transiently
ignored
because
the
fault
current
is
high.
However,
for
high
impedance
faults,
it
is
not
tive, and then the trip command is not generated. Similarly, this scheme can be implehigh
compared
the loads
and4may
affect the Brk5.
performance
of the
protection
mented
for thetorelay
at thecurrents,
end of line
to command
Therefore,
Brk4
and Brk5
system.
So,
In
order
to
investigate
the
effect
of
loads
and
DGs
currents
on
the
performance
disconnect the faulty line.
of the Unlike
proposed
impedance
faults
detection
another
pre-fault
condition
thehigh
transmission
lines,
because
of a scheme,
short distance
between
data
sendingwas
and
considered.
In
this
case,
loads
in
the
microgrid,
i.e.,
loads
1
to
6,
were
considered
receiving points, in distribution lines noise presence in transmitted data is rare,doubled
and usuand
3 was
Moreover,Moreover,
to investigate
fault inception
angle effect,networks,
the initiation
ally,DG
it is
not off.
investigated.
duethe
to short
lines in distribution
fault
π
time
of
fault
was
considered
10.005
s
(fault
inception
angle
was
rad).
2
location determination is not applicable.
t Perf.
I3P
Prot. Zone
ocation
- Fault res.
n Mode
Table 1. Performance of the proposed main scheme in 3P faults
Energies 2021, 14, 274
14 of 24
Islanded
3P-0.01Ω
3P-1Ω
3P-10Ω
3P-50Ω
TP: Transiently positive.
Resp. Time (ms)
3P-50Ω
Correct Perf.
3P-10Ω
FDI3P
3P-1Ω
Inside the Prot. Zone
Grid-connected
3P-0.01Ω
Fault Location
Fault Type- Fault Res.
Operation Mode
Table 1. Performance of the proposed main scheme in 3P faults.
10% of Line 4
Yes
3.94
3
30
50% of Line 4
Yes
4.06
3
30
90% of Line 4
Yes
3.21
3
35
10% of Line 3
No
TP
3
-
10% of Line 5
No
TP
3
-
10% of Line 4
Yes
2.69
3
30
50% of Line 4
Yes
2.43
3
30
90% of Line 4
Yes
1.72
3
30
10% of Line 4
Yes
1.7
3
30
50% of Line 4
Yes
1.44
3
30
90% of Line 4
Yes
0.74
3
35
10% of Line 4
Yes
1
3
30
50% of Line 4
Yes
0.75
3
35
90% of Line 4
Yes
0.05
3
50
10% of Line 4
Yes
4.63
3
30
50% of Line 4
Yes
4.21
3
30
90% of Line 4
Yes
3.46
3
30
10% of Line 3
No
TP
3
-
10% of Line 5
No
TP
3
-
10% of Line 4
Yes
2.69
3
30
50% of Line 4
Yes
2.44
3
30
90% of Line 4
Yes
1.73
3
30
10% of Line 4
Yes
1.69
3
30
50% of Line 4
Yes
1.44
3
30
90% of Line 4
Yes
0.74
3
30
10% of Line 4
Yes
1
3
30
50% of Line 4
Yes
0.74
3
35
90% of Line 4
Yes
0.04
3
45
Energies 2021, 14, 274
15 of 24
Islanded
DLG-0.01Ω
DLG-1Ω
DLG-10Ω
DLG-50Ω
TP: Transiently positive.
Resp. Time (ms)
DLG-50Ω
Correct Perf.
DLG-10Ω
FDIDLG
DLG-1Ω
Inside the Prot. Zone
Grid-connected
DLG-0.01Ω
Fault Location
Fault Type- Fault Res.
Operation Mode
Table 2. Performance of proposed main scheme in DLG faults.
10% of Line 4
Yes
3.75
3
30
50% of Line 4
Yes
3.7
3
30
90% of Line 4
Yes
2.79
3
40
10% of Line 3
No
TP
3
-
10% of Line 5
No
Negative
3
-
10% of Line 4
Yes
2.69
3
30
50% of Line 4
Yes
2.42
3
30
90% of Line 4
Yes
1.7
3
30
10% of Line 4
Yes
1.69
3
30
50% of Line 4
Yes
1.44
3
30
90% of Line 4
Yes
0.74
3
40
10% of Line 4
Yes
1
3
30
50% of Line 4
Yes
0.74
3
35
90% of Line 4
Yes
0.05
3
50
10% of Line 4
Yes
4.48
3
30
50% of Line 4
Yes
3.85
3
30
90% of Line 4
Yes
2.96
3
30
10% of Line 3
No
TP
3
-
10% of Line 5
No
TP
3
-
10% of Line 4
Yes
2.69
3
30
50% of Line 4
Yes
2.43
3
30
90% of Line 4
Yes
1.72
3
30
10% of Line 4
Yes
1.69
3
30
50% of Line 4
Yes
1.44
3
30
90% of Line 4
Yes
0.73
3
30
10% of Line 4
Yes
1
3
30
50% of Line 4
Yes
0.74
3
30
90% of Line 4
Yes
0.04
3
40
Energies 2021, 14, 274
16 of 24
Islanded
LL-0.01Ω
LL-1Ω
LL-10Ω
LL-50Ω
TP: Transiently positive.
Resp. Time (ms)
LL-50Ω
Correct Perf.
LL-10Ω
FDILL
LL-1Ω
Inside the Prot. Zone
Grid-connected
LL-0.01Ω
Fault Location
Fault Type- Fault Res.
Operation Mode
Table 3. Performance of the proposed main scheme in LL faults.
10% of Line 4
Yes
4.47
3
30
50% of Line 4
Yes
3.82
3
30
90% of Line 4
Yes
2.92
3
40
10% of Line 3
No
TP
3
-
10% of Line 5
No
Negative
3
-
10% of Line 4
Yes
2.69
3
30
50% of Line 4
Yes
2.43
3
30
90% of Line 4
Yes
1.72
3
40
10% of Line 4
Yes
1.69
3
30
50% of Line 4
Yes
1.44
3
30
90% of Line 4
Yes
0.74
3
40
10% of Line 4
Yes
1
3
30
50% of Line 4
Yes
0.74
3
35
90% of Line 4
Yes
0.05
3
50
10% of Line 4
Yes
4.54
3
30
50% of Line 4
Yes
3.93
3
30
90% of Line 4
Yes
2.99
3
30
10% of Line 3
No
TP
3
-
10% of Line 5
No
TP
3
-
10% of Line 4
Yes
2.69
3
30
50% of Line 4
Yes
2.43
3
30
90% of Line 4
Yes
1.72
3
30
10% of Line 4
Yes
1.69
3
30
50% of Line 4
Yes
1.44
3
30
90% of Line 4
Yes
0.74
3
30
10% of Line 4
Yes
1
3
30
50% of Line 4
Yes
0.74
3
30
90% of Line 4
Yes
0.04
3
40
Energies 2021, 14, 274
17 of 24
Islanded
SLG-0.01Ω
SLG-1Ω
SLG-10Ω
SLG-50Ω
Resp. Time (ms)
SLG-50Ω
Correct Perf.
SLG-10Ω
FDISLG
SLG-1Ω
Inside the Prot. Zone
Grid-connected
SLG-0.01Ω
Fault Location
Fault type- Fault Res.
Operation Mode
Table 4. Performance of the proposed main scheme in SLG faults.
10% of Line 4
Yes
4.5
3
30
50% of Line 4
Yes
3.91
3
30
90% of Line 4
Yes
3.08
3
35
10% of Line 3
No
TP
3
-
10% of Line 5
No
TP
3
-
10% of Line 4
Yes
2.69
3
30
50% of Line 4
Yes
2.43
3
30
90% of Line 4
Yes
1.73
3
35
10% of Line 4
Yes
1.69
3
30
50% of Line 4
Yes
1.44
3
30
90% of Line 4
Yes
0.74
3
45
10% of Line 4
Yes
1
3
30
50% of Line 4
Yes
0.75
3
35
90% of Line 4
Yes
0.07
3
45
10% of Line 4
Yes
4.53
3
30
50% of Line 4
Yes
3.97
3
30
90% of Line 4
Yes
3.02
3
35
10% of Line 3
No
TP
3
-
10% of Line 5
No
TP
3
-
10% of Line 4
Yes
2.69
3
30
50% of Line 4
Yes
2.43
3
30
90% of Line 4
Yes
1.73
3
35
10% of Line 4
Yes
1.69
3
30
50% of Line 4
Yes
1.44
3
35
90% of Line 4
Yes
0.74
3
35
10% of Line 4
Yes
0.99
3
35
50% of Line 4
Yes
0.74
3
35
90% of Line 4
Yes
0.05
3
50
TP: Transiently positive.
The results in Table 5 show the correct performance of the proposed scheme in the new
pre-fault conditions. So, this scheme is robust against loads and generation uncertainties,
and fault inception angle variations.
In order to evaluate the performance of the proposed scheme in transient situations
due to load changes, a 30 kVA load was added to the bus E att = 10 s. According to
corresponding FDI3P curves in Figure 16, connecting this load did not make a permanent
positive FDI3P , and the performance of the protection system was not challenged.
Energies 2021, 14, 274
18 of 24
18 of 23
Yes
0.029
3
90% of Line 4
Yes
0.029
3
0.027
Yes
Yes
0.014
Yes
0.035
Yes
0.038
Yes
0.037
Yes
Yes
0.027
Yes
3
0.029
0.029
3
0.027
3
0.014
3
0.035
3
0.038
DLG-50Ω
LL-50Ω3P-50Ω
90% of Line 490% of Line
Yes 4
DLG-50Ω
90%
of
Line
SLG-50Ω
90% of Line 4
Yes 4
3P-50ΩLL-50Ω
90% of Line 490% of Line
Yes 4
SLG-50Ω
90% of Line 4
DLG-50Ω
90% of Line 4
Yes
3P-50Ω
90% of Line 4
LL-50Ω
90% of Line 490% of Line
Yes 4
DLG-50Ω
LL-50Ω
90%
of
Line
SLG-50Ω
90% of Line 4
Yes 4
SLG-50Ω
90% of Line 4
0.5
0.037
3
0.027
Correct Perf.
FDIi Correct Perf.
Fault Location
FDI
Inside the Prot. Zonei
3P-50Ω
Fault type-Fault Res.
Table 5. Performance of the proposed main scheme in new pre-fault conditions.
Resp. Time (ms)
90% of Line 4
Fault Location
Inside the Prot. Zone
Fault Type-Fault Res.
Operation Mode
Islanded
Grid-connected
Grid-con
Operation Mode
Islanded
nected
Table 5. Performance of the proposed main scheme in new pre-fault conditions.
50
Resp. Time (ms).
Energies 2021, 14, 274
50








50 50
45 50
50 50
45
40
50
40 40
50 40
50
1
0
0
-0.5
FDI
FDI
3P
3P
-1
-1.5
-2
-2.5
-1
-2
-3
-3
10
10.1
10.2
time(sec)
(a)
10.3
-4
10
10.1
10.2
10.3
time(sec)
(b)
Figure
FDI
load
change
bus
E in
grid-connected
mode
(negative)
islanded
mode
(transiently
positive).
Figure
16.16.
FDI
forfor
load
change
at at
bus
E in
(a)(a)
grid-connected
mode
(negative)
(b)(b)
islanded
mode
(transiently
positive).
3P 3P
the proposed
can detect all fault types correctly in grid-connected
5.2.Therefore,
Backup Protection
Schemescheme
Evaluation
and islanded modes. Moreover, the results show its response time is 30 to 50 ms, which its
Since, for the faults with resistance, the pre-fault conditions affect during the fault
average is 32.8 ms. This indicates the operation of the proposed main scheme is almost
impedance, fault types at lines 4 and 5 with fault resistance 2 ohm have been studied in
34% faster than other ones such as [27]. Moreover, the low sampling rate (200 Hz) is one
several pre-fault conditions in order to evaluate the backup protection scheme. The
advantage of this scheme.
conductance seen from bus A has been measured. The pre-fault conditions were considered
as follows:
5.2.
Backup
Protection Scheme Evaluation
The maximum sudden load change in the low voltage distributed network was asSince, for the faults with resistance, the pre-fault conditions affect during the fault
sumed 30 KVA with power factor 0.9 lag. Considering this load change, CVIthr was obimpedance, fault types at lines 4 and 5 with fault resistance 2 ohm have been studied in
tained 0.1875.
several pre-fault conditions in order to evaluate the backup protection scheme. The conIf a fault occurs at lines 4 or 5 and their relays fail to recognize fault within 50 ms in
ductance seen from bus A has been measured. The pre-fault conditions were considered as
their main zones, the relay at the beginning of line 4 will detect the fault in the backup
follows:
zone and will command a trip. However, if relays detect the fault in the main zones and
The maximum sudden load change in the low voltage distributed network was
command
trip,with
the relay
at the
beginning
line 4 will see
changeCVI
after the
first
assumed
30 aKVA
power
factor
0.9 lag. of
Considering
thisanother
load change,
thr was
one
in
a
time
shorter
than
50
ms
and
will
be
reset.
So,
N
must
be
greater
than
M,
thereobtained 0.1875.
fore,
was occurs
considered
40 4equivalent
to 200
ms, fail
which
is the normal
response
If aitfault
at lines
or 5 and their
relays
to recognize
fault within
50 time
ms infor
backup
The
performance
of the proposed
backup
protection
scheme
and the
their
mainschemes.
zones, the
relay
at the beginning
of line 4 will
detect
the fault in
the backup
reactance-based
one
explained
in
[27],
have
been
compared
in
Tables
6–9.
zone and will command a trip. However, if relays detect the fault in the main zonesResults
and
showed that
different
pre-fault
not 4affect
command
a trip,
the relay
at the conditions
beginning did
of line
will the
see accurate
another performance
change after of
thethe
proposed
backup
scheme.
This
scheme
could
detect
fault
types
downstream
of
the
first one in a time shorter than 50 ms and will be reset. So, N must be greater than relay
M,
in both grid-connected and islanded modes and did not command trip for the fault at
upstream of the relay (at line 3) and adding load 30 kVA at the end of line 5. According to
Energies 2021, 14, 274
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therefore, it was considered 40 equivalent to 200 ms, which is the normal response time
for backup schemes. The performance of the proposed backup protection scheme and the
reactance-based one explained in [27], have been compared in Tables 6–9. Results showed
that different pre-fault conditions did not affect the accurate performance of the proposed
backup scheme. This scheme could detect fault types downstream of the relay in both
grid-connected and islanded modes and did not command trip for the fault at upstream of
the relay (at line 3) and adding load 30 kVA at the end of line 5. According to these results,
the reactance-based scheme in [27] performed correctly for 60% and, the proposed scheme
detected faults for 100% of cases.
load
Islanded
3P
DLG
LL
SLG
load
Correct Perf. of
Scheme in [27].
SLG
Correct Perf. of
Proposed Scheme
LL
Fault Recog. by the
Proposed Scheme
DLG
CVI
Grid-connected
3P
Fault/Load Location
Fault Type/Load
Operation Mode
Table 6. Backup protection performance in pre-fault conditions “a”.
10% of Line 3
0.01
No
3
3
90% of Line 4
0.49
Yes
3
7
90% of Line 5
0.47
Yes
3
7
10% of Line 3
−0.04
No
3
3
90% of Line 4
1.38
Yes
3
7
90% of Line 5
1.22
Yes
3
7
10% of Line 3
0
No
3
3
90% of Line 4
0.92
Yes
3
7
90% of Line 5
0.83
Yes
3
7
10% of Line 3
−0.03
No
3
3
90% of Line 4
0.57
Yes
3
7
90% of Line 5
0.33
Yes
3
7
100% of Line 5
0.17
No
3
3
10% of Line 3
−0.16
No
3
3
90% of Line 4
0.33
Yes
3
7
90% of Line 5
0.31
Yes
3
7
10% of Line 3
−0.55
No
3
3
90% of Line 4
0.90
Yes
3
3
90% of Line 5
0.80
Yes
3
3
10% of Line 3
−0.37
No
3
3
90% of Line 4
0.59
Yes
3
7
90% of Line 5
0.53
Yes
3
3
10% of Line 3
−0.23
No
3
3
90% of Line 4
0.42
Yes
3
3
90% of Line 5
0.23
Yes
3
7
100% of Line 5
0.11
No
3
3
Energies 2021, 14, 274
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load
Islanded
3P
DLG
LL
SLG
load
(a)
(b)
(c)
(d)
Correct Perf. of
Scheme in [27].
SLG
Correct Perf. of
Proposed Scheme
LL
Fault Recog. by the
Proposed Scheme
DLG
CVI
Grid-connected
3P
Fault/Load Location
Fault Type/Load
Operation Mode
Table 7. Backup protection performance in pre-fault conditions “b”.
10% of Line 3
0
No
3
3
90% of Line 4
0.46
Yes
3
7
90% of Line 5
0.44
Yes
3
7
10% of Line 3
−0.03
No
3
3
90% of Line 4
1.30
Yes
3
3
90% of Line 5
1.13
Yes
3
7
10% of Line 3
−0.03
No
3
3
90% of Line 4
0.86
Yes
3
7
90% of Line 5
0.76
Yes
3
7
10% of Line 3
−0.03
No
3
3
90% of Line 4
0.55
Yes
3
7
90% of Line 5
0.31
Yes
3
7
100% of Line 5
0.16
No
3
3
10% of Line 3
−0.16
No
3
3
90% of Line 4
0.32
Yes
3
7
90% of Line 5
0.30
Yes
3
7
10% of Line 3
−0.52
No
3
3
90% of Line 4
0.80
Yes
3
7
90% of Line 5
0.78
Yes
3
3
10% of Line 3
−0.37
No
3
3
90% of Line 4
0.59
Yes
3
7
90% of Line 5
0.52
Yes
3
7
10% of Line 3
−0.23
No
3
3
90% of Line 4
0.42
Yes
3
7
90% of Line 5
0.22
Yes
3
7
100% of Line 5
0.11
No
3
3
Loads and DGs properties were considered similar to Section 4.
Loads powers in the microgrid were doubled compared to condition “a”.
Loads powers in the microgrid were halved compared to condition “a”.
Loads powers were similar to condition “a” but DG2 and DG3 were disconnected.
Energies 2021, 14, 274
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load
Islanded
3P
DLG
LL
SLG
load
Correct Perf. of
Scheme in [27].
SLG
Correct Perf. of
Proposed Scheme
LL
Fault Recog. by the
Proposed Scheme
DLG
CVI
Grid-connected
3P
Fault/Load Location
Fault Type/Load
Operation Mode
Table 8. Backup protection performance in pre-fault conditions “c”.
10% of Line 3
0
No
3
3
90% of Line 4
0.49
Yes
3
7
90% of Line 5
0.47
Yes
3
7
10% of Line 3
−0.03
No
3
7
90% of Line 4
1.37
Yes
3
3
90% of Line 5
1.23
Yes
3
3
10% of Line 3
−0.02
No
3
3
90% of Line 4
0.92
Yes
3
7
90% of Line 5
0.84
Yes
3
7
10% of Line 3
−0.02
No
3
3
90% of Line 4
0.57
Yes
3
7
90% of Line 5
0.34
Yes
3
3
100% of Line 5
0.18
No
3
3
10% of Line 3
−0.16
No
3
3
90% of Line 4
0.33
Yes
3
7
90% of Line 5
0.32
Yes
3
7
10% of Line 3
−0.53
No
3
3
90% of Line 4
0.88
Yes
3
3
90% of Line 5
0.79
Yes
3
7
10% of Line 3
−0.37
No
3
3
90% of Line 4
0.60
Yes
3
3
90% of Line 5
0.54
Yes
3
3
10% of Line 3
−0.24
No
3
3
90% of Line 4
0.42
Yes
3
3
90% of Line 5
0.23
Yes
3
7
100% of Line 5
0.11
No
3
3
Energies 2021, 14, 274
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load
Correct Perf. of
Scheme in [27].
SLG
Correct Perf. of
Proposed Scheme
LL
Fault Recog. by the
Proposed Scheme
DLG
CVI
Grid-connected
3P
Fault/Load Location
Fault Type/Load
Operation Mode
Table 9. Backup protection performance in pre-fault conditions “d”.
10% of Line 3
0
No
3
3
90% of Line 4
0.50
Yes
3
3
90% of Line 5
0.42
Yes
3
3
10% of Line 3
0
No
3
3
90% of Line 4
1.42
Yes
3
3
90% of Line 5
1.26
Yes
3
3
10% of Line 3
0
No
3
3
90% of Line 4
0.95
Yes
3
3
90% of Line 5
0.88
Yes
3
3
10% of Line 3
0
No
3
3
90% of Line 4
0.85
Yes
3
3
90% of Line 5
0.77
Yes
3
3
100% of Line 5
0.17
No
3
3
6. Conclusions
Despite microgrids’ numerous advantages, their development and extension in distribution networks have made serious challenges for network protection systems, and fault
detection is challenged by traditional methods.
In this article, by reconfiguring sequence equivalent circuits for the faults types in
distribution and transmission lines, new equivalent circuits for positive, negative, and zero
sequences are presented. These circuits are called simplified positive sequence (SPS), simplified negative sequence (SNS), and simplified zero sequence (SZS) circuits. Then, by applying star to delta transform, the proposed circuits are converted to equivalent delta
ones. The impedances in these circuits were estimated approximately using the voltages
and currents measured at the ends of the line. The Significant change in one of these
impedances during the faults is the basis of the proposed main protection scheme for the
active distribution lines in microgrids. In this scheme, indexFDI is proposed for faults detection in both grid-connected and islanded modes, and because it is based on impedance,
fault level changes due to the microgrid operation modes (islanded and grid-connected)
or loads changes, do not affect its performance. Its average response time shows its fast
performance. Voltage and current at beginning of the line and absolute value of positive
sequence voltage send from the end of the line are used in this scheme. Therefore, at least
50% of the communication system is released. High impedance faults detection capability
and low sampling rate are among the advantages of the proposed scheme. Robustness
against network reconfigurations, correct performance in presence of infeed, transient
situations, and load and generation uncertainties are capabilities of the proposed scheme.
Also, CVI based on the conductance variation has been proposed for downstream
lines backup protection in grid-connected and islanded modes. No requirement to any
communication link is a distinguished advantage of this scheme, so if the communication
link is disconnected or the main protection is failed, it will be capable to protect the network.
Moreover, it is independent of pre-fault conditions.
Energies 2021, 14, 274
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The proposed schemes have been simulated using PSCAD and MATLAB software
and the results have confirmed their accuracy.
Author Contributions: Conceptualization, S.M.N. and A.K.; Methodology, S.M.N. and A.K.; Software, S.M.N.; Validation, S.M.N. and A.K.; Supervision, A.K.; Writing—original draft preparation
S.M.N.; Writing—review & editing, A.K., M.S.-k. All authors have read and agreed to the published
version of the manuscript.
Funding: Not applicable.
Institutional Review Board Statement: Not applicable.
Informed Consent Statement: Not applicable.
Data Availability Statement: All data are given in the paper. Separately there is no other data.
Acknowledgments: Miadreza Shafie-khah acknowledges the support by the Business Finland
through SolarX Research Project, 2019–2021, under Grant 6844/31/2018.
Conflicts of Interest: The authors declare no conflict of interest.
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