2019 Innovations in Power and Advanced Computing Technologies (i-PACT)

Impact Assessment of DG in Radial Distribution

Networks
Arya Christy C.B1 Sreena Sreekumar2 Savier J.S3
Dept. of Electrical Engineering Dept. of Electrical Engineering Dept. of Electrical Engineering
College of Engineering, Trivandrum College of Engineering, Trivandrum College of Engineering Trivandrum
aryachristy@gmail.com sreenasuresh.cet@gmail.com savier− js@yahoo.com

Abstract—Integration of new energy sources in to existing current can be expected in this situation. The rise in the short
grid may creates some major issues in the system, especially in circuit level and change in the direction of fault current flow in
protection co-ordination. This paper concentrate on the impact the distribution network influences the protection coordination
analysis of radial distribution network due to the insertion of
Distributed Generation (DG). Different protection issues with between relays installed in the distribution network(DN), and
DGs are focused here with co-ordinated radial power flow. A thus disturb the functionality, selectivity and reliability of
new methodology which reduces the effect of DG in protection protection schemes [3]. In this context, the impact of DG
coordination of the existing system is proposed. In this adaptive on the utility protection system deserves intensive research
scheme, various protection co-ordination settings are provided in for the smooth, steady functioning of the system. A number
different locations of DG with different configurations of network.
A portion of IEEE 13 node radial distribution test feeder is of protection issues such as mis-coordination, blinding of
used to verify this proposed methodology. Electrical equivalent protection devices, reverse power flow, unintentional islanding
of 3 bus systems is also used for the analytical derivation of key and false tripping are reported in literature.
parameters under faulted condition.
Index Terms—Adaptive protection scheme, Distribution Gen- Optimized settings of protection coordination devices are
eration , protection relay coordination,Over current protection
devices. needed in the DG connected system [4]. For this, time of
operation of the protection relays has been optimized by
I. I NTRODUCTION using different optimization techniques. Several conventional
methods and newly developed artificial intelligence methods
Demand for electrical energy is increasing day by day.To can be applied for this. Conventional technique-like trial
meet this demand, new technologies called distributed and error method shows the range of parameter settings
energy sources are introduced in the system. They include for different operating condition. The artificial intelligence
renewable energy sources such as PV, wind, fuel cells, techniques such as smart adaptive scheme are highly efficient
biomass etc.Insertion of DGs in the existing networks in manipulating and optimizing the parameters for protection
enhances the grid reinforcement, reduces power losses coordination in DG connected network [5] .
and on-peak operating costs, and improve the voltage
profiles and load factors [1]. This condition improves the This paper focuses on the effect of DG in protection co-
reliability of power supply provided to the customers. In ordination of distribution network. An adaptive protection
spite of these new possibilities, this new energy sources scheme is developed for minimizing the effect arising due to
near to the customers creates operating challenges in the DG. For DG connected network, change in magnitude and
system. DG implementation in system can produce some direction of fault current is observed. A portion of IEEE 13
major issues in the distribution network, since the existing Node [6] test feeder is used for this analysis. The system is
distribution systems are designed for the radial power flow simulated in ETAP software environment and different scenar-
in one direction. DG insertion may affect or violate existing ios had been carried out to test the newly proposed scheme.
planning and operation practices [2]. The integration of The structure of the paper is organized as follows.Section II
distributed generation and other storage devices in the radial discusses the various protection problems with DGs in radial
network will alter the contemporary practice of having a distribution network. This section utilises equivalent circuit
unidirectional power flow which remarkably affects the of 3 bus test system feeder for studying the DG impact in
coordination of protection devices utilised in the system. short circuit level at different locations. Section III describe the
test system,IEEE 13 node test feeder. Section IV explains the
By adding DGs in existing feeders, the nominal or fault algorithm for newly developed over current protection scheme
current through the feeder is redistributed. This may affect for DG interconnection. Following this section, verification of
the load current and fault current through the over current new scheme with composite results are provided. The paper
protection devices (OCPDs). Increase or decrease of the fault is concluded in the last section along with future scope of
research in this area.

978-1-5386-8190-9/1/$31.00 ©2019 IEEE 1

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 2019 Innovations in Power and Advanced Computing Technology (i-PACT)

II. PROTECTION ISSUES WITH DG phase short circuit current contribution includes both the grid
and DG contribution to fault point. Current contribution by
For reliable operation of DG connected system,DG must
grid and DG to three phase short circuit in per-unit Igrid ,Idg
be suitably co-ordinated with the operational philosophy
can be expressed as:
of the network. DG is attached to the network through th
interconnection point called point of common coupling(PCC). Ugrid
This PCC should be protected properly in order to avoid Igrid = (1)
Zsource + Zl12
damage to both side DG equipments and utility. Proper
Udg
co-ordination of protection devices are needed for this. Idg = (2)
Protection coordination in simple radial DN is quite simple Zl23 + Zdg
as the network has a single source [7] and thus fault current B. System 2
direction is unidirectional. Introduction of DG may cause
Another system is formed by changing fault point and DG
bi-directional power flow and complexity in network topology.
location as shown in figure 3. Electrical equivalent of the
The setting and characteristics of protective devices should
subsystem is also included here in figure 4.
change according to the new topology.

For analysing the impacts of DG, analytical expressions

are derived for parameters which influence the protection
co-ordination. Expression for various current components
at different DG positions in equivalent three bus system is
shown below

A. System 1
Test feeder of 3-bus system with various protective devices
Fig. 3. Fault point lies after DG bus
is shown in figure 1. In the system, specific fault is created in
bus2 with DG of fixed capacity in bus3.

Fig. 1. Fault point lies in between main feeder bus and DG bus
Fig. 4. Electrical equivalent of figure3
An electric equivalent of the above system is shown in
figure.This equivalent circuit used for deriving expressions of Assuming that Usource and Udg are equal, thevenin equivalent
key parameters is given in figure 2. In this figure, Zl12 and voltage Uth is , Uth = Usource = Udg So the grid contri-
Zl23 are line impedances of line 1-2 and line 2-3 in per unit. bution to three phase short circuit in per-unit Igrid and total
Zsource is the source-impedance. The per-unit voltages of three phase short circuit fault current in per-unit,I3ph can be
the grid and DG are denoted as Usource and Udg . Total three expressed as:
Zdg
Igrid = Uth
Zdg (Zsource + Zl12 + Zl23 ) + Zl23 (Zsource + Zl12 )
(3)

Zdg + Zsource + Zl12

I3ph = Uth
Zdg (Zsource + Zl12 + Zl23 ) + Zl23 (Zsource + Zl12 )
(4)
C. System 3
In system 3, as shown in figure 5 two different feeders
Fig. 2. Electrical equivalent of figure1
connected to common point in the grid is shown. Fault
occurs at feeder 1 and DG is located in feeder 2. Electrical

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 2019 Innovations in Power and Advanced Computing Technology (i-PACT)

of feeder 1, which is not acceptable.From this, protection

issues related to DG interconnection can be tabulated as in
Table I. These issues [8] are directly or indirectly related to
each other. Changes in short circuit level is the main cause of
protection mis-co-ordination.

TABLE I
P ROTECTION ISSUES IN DG CONNECTED SYSTEM

No. Effect due to DG Issues in protection system

1 Change in direction of Network topology changes
fault current. Bidirectional fault current flow
Fig. 5. Fault on feeder 1 and DG at feeder 2.
2 Increase or decrease in Lose of sensitivity and
fault current level. selectivity of protection device.
3 Rise in nominal current False tripping of protective device
flow
4 Reduced grid current. Blinding of protection
5 Fault current level lesser Variation in tripping time
than instantaneous pick up value.

III. T EST SYSTEM

The study case system is a portion of IEEE 13 nodes test
feeder. System model created in ETAP software is presented in
figure 7. The system is incorporated with following distributed
Fig. 6. Electrical equivalent of figure5. generating sources, such as:
• Node 611: Synchronous Generator(DG1) 750kW at
4.16kV.
equivalent of the above system is shown in figure 6. • Node 692: Synchronous Generator(DG2) 500kW at

For this system, Usource and Udg are assumed to be equal,and 4.16kV.
the thevenin equivalent voltage is Uth = Usource = Udg . • Node 675: 3 units of Wind Turbine Generator (WTG1)

The DG contribution to three phase short circuit in per-unit, 100kW each at 4.16kV.
Idg can be calculated as: With this DG units, several configurations of the network are
possible. Here, 5 configurations are considered for analysis.
Zgrid
Idg = Uth 1. Power Grid without DG.
Zl2 (Zsource + Zl2 + Zdg ) + Zgrid (Zdg + Zl2 ) 2. Power Grid with DG1 alone.
(5)
3. Power Grid with DG2 alone.
For system 1, system 2 and system 3, Zdg is:
4. Power Grid with WTG1 alone.
 SB 5. Power Grid with DG2 and WTG1.
Zdg = Xdg . (6)
Sdg A. Impacts of different configurations

where, Xdg
is the subtransient reactance of the DG , SB is Relay coordination is done for feeder shown in figure
the base MVA of system and Sdg is DG capacity . 7.TCC curves for fault at node 611 are shown in figure.
8. For each configurations impacts of DG in protection are
D. summary of DG impact studied. Fault current level and direction of fault current may
In system 1, fault current is flowing in both direction with vary in each configurations. The tripping sequence of relays
respect to the fault point. So bidirectional relays are required to for each configuration are studied. Drastic change in the
sense the reverse current flow. But grid contribution current to tripping sequence of these relays for different configurations
fault point is unaffected by DG. For system 2, grid contribution may affect the co-ordination of these devices. Such a lose of
current to fault point may vary with DG and its location. This coordination can be seen in figure 9. An adaptive protection
may affect the sensitivity and selectivity of relay attached with system [9] is the only solution for eliminating these issues.
the system.Lesser value of grid contribution current due to The following criterion should be fulfilled for this adaptive
DG affects the feeder end relay operation.(here in system 2, protection schemes such as each DG unit should be protected
relay1 is affected). Concerned relay won’t trip for fault or relay properly, device settings should be changed according to the
will trip after a long time delay. Impact of System 3 can be fault current level [10] and system configurations, velocity of
considered as an example of false tripping. For large value of operation of protective device should be adjusted according to
DG current contribution to the fault point, feeder 2 trips instead the fault condition.

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 2019 Innovations in Power and Advanced Computing Technology (i-PACT)

Fig. 9. Faulted bus 684 for system configuration 2

Fig. 7. Single line diagram of study case system. TABLE II

T RIP C URRENT S ETTING OF R ELAY

Trip Current (A) setting

Relay Conf.1 Conf.2 Conf.3 Conf.4 Conf.5
R1 3499 3499 3758 3758 4084
R1dir. - 650.4 - - -
R2 3499 3499 3758 3758 4084
R2dir. - 650.4 - - -
R3 3750 3750 4134 4050 4430
R3dir. - 645.6 - - -
R4 3750 3750 4134 4050 4430
R4dir. - 645.6 - - -
R5 3849 3849 4254 3849 4254
R5dir. - - - 343.2 343.2
R6 3849 3849 4254 3849 4254
R6dir. - - - 343.2 343.2
R7 3980 3980 4254 3978 3978
R7dir. - - 438 343.2 776.4
R8 3980 3980 3499 3499 3499
R9 3980 3980 3499 3499 3499
R10 3980 3980 3499 3499 3499
R11 3980 3980 3758 3499 3499
R12 146.4 146.4 146.4 146.4 146.4

dination.
Fig. 8. TCC curves of relays lie between node 611 to 671 and node 671 to 8. Verify protection coordination for each configurations.
650 9. As per stored data of relay settings, select appropriate
settings for each configurations.

IV. A LGORITHM FOR NEW SCHEME V. R ESULTS AND DISCUSSIONS

Table II and III show results of units 50 for all relays
Steps to follow for new methodology :
at every configuration. Table.IV contains the results of time
1. Execute short circuit analysis of the system with out DG. multiplier setting(TMS) for all relays for all the five configu-
2. Set OCR at appropriate locations based on maximum rations.
fault current through lines Figure 10 shows tripping sequence of reprogrammed relays
3. Select and apply protection coordination methods. that operate for system configuration of DG1 alone for faulted
4. insert DG in the system bus 611 in one line diagram. TCC shown in figure 11 are for
5. Identify type of DG and define DG protection scheme. reprogrammed bidirectional R1, R2, R3 and R4 relays using
6. Apply short circuit analysis for each configurations. new methodology. Here R1, R2, R3 and R4 are bidirectional
7. If percentage change of fault current is more, change PS relays. Figures 12 and 14 are tripping sequences of repro-
50 settings. grammed relays that operate for system configurations3,4.
7. Based on fault current flow, at each node provide bidi- TCC of different configurations 2, 3, 4, 5 are shown in figures
rectional relays and adjust TMS values for proper coor- 11, 13, 15 and 16. In each configurations, bidirectional relays

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 2019 Innovations in Power and Advanced Computing Technology (i-PACT)

TABLE III
U NIT 50 PARAMETERS

OC 50 setting
Relay Conf.1 Conf.2 Conf.3 Conf.4 Conf.5
R1 17.49 17.49 18.79 18.79 20.42
R1.dir - 3.25 - - -
R2 17.49 17.49 18.79 18.79 20.42
R2.dir - 3.25 - - -
R3 18.75 18.75 20.67 20.25 22.15
R3.dir - 3.73 - - -
R4 18.75 18.75 20.67 20.25 22.15
R4.dir - 3.73 - - -
R5 12.83 12.83 14.18 12.83 14.18
R5.dir - - - 1.44 1.44
R6 12.83 12.83 14.18 12.83 14.18
R6.dir - - - 1.44 1.44
R7 13.26 13.26 14.18 13.26 13.26
R7.dir - - 1.46 1.44 2.59
R8 7.96 7.96 6.99 6.99 6.99
R9 7.96 7.96 6.99 6.99 6.99
R10 7.96 7.96 6.99 6.99 6.99 Fig. 10. Tripping sequence of conf.2 for new setting.
R11 7.96 7.96 6.99 6.99 6.99
R12 1.46 1.46 1.46 1.46 1.46

TABLE IV
TMS FOR DIFFERENT CONFIGURATIONS

Time Multiplying Setting

Relay Conf.1 Conf.2 Conf.3 Conf.4 Conf.5
R1 0.05 0.08 0.05 0.05 0.05
R1.dir - 0.383 - - -
R2 0.18 0.133 0.18 0.72 0.18
R2.dir - 0.326 - - -
R3 0.31 0.181 0.31 0.72 0.31
R3.dir - 0.267 - - -
R4 0.39 0.317 0.39 0.72 0.35
R4.dir - 0.209 - - -
R5 0.14 0.05 0.063 0.56 0.05
R5.dir - - - - 0.14
R6 0.21 0.18 0.088 0.088 0.088
R6.dir - - - 0.061 0.123
R7 0.36 0.297 0.21 0.21 0.35
R7.dir - - 0.14 0.083 0.218
R8 0.42 0.3512 0.31 0.42 0.32
R9 0.58 0.456 0.42 0.456 0.43
R10 0.658 0.532 0.52 0.56 0.52 Fig. 11. TCC of relays in conf.2
R11 0.76 0.632 0.63 0.66 0.52
R12 0.78 0.73 0.66 0.69 0.66

are used whenever reversal of fault current direction occurs.In

the case of configuration 3, only relay R7 has the ability of bi-
directional power flow. Similarly in configuration 4, node 675
has a DG unit. It creates bidirectional fault current flow for
faults at node 671 and 692. Figure.17 shows TCC curves of
relay R7 at different system configurations. The reprogrammed
curve of relay shows the adaptive performance of protective
relays.

VI. C ONCLUSIONS
In this work,impact of different configurations of system
with DGs on protection system is analyzed. Crucial parameters Fig. 12. Tripping sequence of conf.3 for new reprogrammed setting.
which affect the protection system in DG connected systems
are analytically derived in this paper. An adaptive methodology
is proposed in which the instantaneous over current relay

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 2019 Innovations in Power and Advanced Computing Technology (i-PACT)

Fig. 13. TCC of reprogrammed relays in conf.3 Fig. 16. TCC of reprogrammed relays in conf.5

Fig. 14. Tripping sequence of conf.4 for new setting.

Fig. 17. TCC curve of reprogrammed relay R7 in all 5 configurations.

plug settings(PS 50 settings) and TMS values are adaptively

changed to reduce the impact of DGs. DG penetration level
also affect the protection co-ordination of distribution network.
Protection impact analysis with varying DG penetration levels
can be a significant area of future research.

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