Turk J Elec Eng & Comp Sci

(2015) 23: 2150 – 2160

c⃝ TUBITAK

doi:10.3906/elk-1302-80

Turkish Journal of Electrical Engineering & Computer Sciences

http :// journa l s . tub i tak .gov . t r/e lektr ik/

Research Article

Central coordination relay for distribution systems with distributed generation

Fatih Mehmet NUROGLU1,∗, Aysen Basa ARSOY2

1Department of Electrical and Electronics Engineering, Faculty of Engineering, Karadeniz Technical University,Trabzon, Turkey

2Department of Electrical Engineering, Faculty of Engineering, Kocaeli University, Kocaeli, Turkey

Received: 12.02.2013 • Accepted/Published Online: 15.08.2013 • Printed: 31.12.2015

Abstract: As distributed generation resources penetrate into distribution systems, protection and service continuity

are becoming major issues. A new approach for protection coordination and higher reliability of a distribution system

with distributed generation is explored in this paper. The concept of central coordination relay (CCR) is developed for

this purpose. After a brief introduction of the design and operating procedures of CCR, the utilization of the proposed

relay on two feeders of a substation in the Kocaeli region of Turkey is simulated using DIgSILENT PowerFactory. The

study results show that CCR can provide better protection coordination and improved reliability indices for distributed

generation systems.

Key words: Central coordination relay, distributed generation, protection, intentional islanding, reliability indices

1. Introduction

Distributed generation resources are being increasingly utilized in electrical distribution systems around the

globe. As technological improvements and the importance of green energy advance, distributed generation

(DG) will play a larger role in distribution systems in terms of quantity and total generation capacity.

DG may bring many advantages such as reduced system losses and improved power quality and reliability

[1]. However, a greater role of DG in distribution systems may lead to system issues, including protection

problems [2]. The main protection issues are overcurrent protection, instantaneous reclosing, ferroresonance,

reduced insulation, transformer connections, and ground faults [3]. Conventional distribution systems are

planned as passive networks that carry power from generation centers to loads through transmission systems

without any generation at the distribution level. With the integration of DG, distribution systems become

active networks. Therefore, conventional feeder protection, especially overcurrent protection coordination, must

be handled with care [4].

Overcurrent protection coordination must satisfy the following conditions during a short-circuit fault [5]:

• The faulted part should be removed as soon as possible.

• The smallest possible part should be disconnected.

• All faults should be cleared within the protection zone.

∗Correspondence: fmn@ktu.edu.tr

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When a short-circuit fault exists on a distribution feeder, the fault current will be fed by both the

substation and DG. This will affect the fault current magnitude, direction, and operation of any existing

recloser [6].

Current standards [7] state that DG should not continue to energize the distribution system or feed the

fault as soon as a short-circuit fault or loss of grid is detected. Due to the presence of DG, a part of the

distribution system could be islanded during a fault. Islanding techniques detecting loss of grid were explored

in [8–11] in order to avoid intentional or unintentional islanding.

Prevention of any type of islanding means discontinuity of DG. By keeping DG in service as much as

possible, intentional islanding could be a powerful means to improve service continuity for distribution systems

[12]. Intentional islanding will also help utilize DG resources more efficiently and in turn maximize the benefits.

An adaptive protection scheme was proposed in [13,14] for distribution systems with a high penetration of DG

by dividing the system into zones with a reasonable load-generation balance. The idea of dividing the system

into zones constitutes the basis for a new approach towards protection and islanding.

The proposed central coordination relay (CCR) brings a new approach to protection coordination of

distribution systems with DG. CCR can detect a short-circuit fault and its location, coordinate the circuit

breakers to clear the minimum portion of the faulted system, and make intentional islanding possible. Although

CCR was originally designed based on the need for protection, it also brings suitable capabilities to manage a

distribution system with DG.

In this paper, the concept of a CCR located on a substation is developed as a new approach for protection

and higher reliability of a distribution system with DG. First, the protection and reliability issues in distribution

systems with DG are reviewed. The procedures of CCR design and operation steps are then briefly presented

and CCR is applied to two feeders of a substation in the Kocaeli area using DIgSILENT PowerFactory. Finally,

the impact of CCR is studied in terms of the reliability indices. It is shown that the proposed relay not only

provides better protection coordination but also improves the reliability of the distribution system with DG in

the case of intentional islanding.

2. Protection, islanding, and reliability issues in distributed generation systems

The conventional overcurrent protection schemes in distribution systems are based on the fact that power flows

from substations to feeders. As DG is introduced into the system, the existing protection scheme may not

hold anymore. The presence of DG changes the power flow direction, increases short-circuit fault currents,

and interferes with the recloser’s action [15]. Determining the short-circuit fault location and coordinating the

protection devices may become more difficult in a system with DG. Currently the common protection practice

in a distribution system with the presence of DG is to trip the DG first during a short-circuit fault. The next

step is letting the conventional overcurrent protection schemes clear the fault. To be able to have DG react

first, the protective relay parameters of DG should be set accordingly. The relays will be more sensitive to

any disturbance in the system. Due to the sensitive tuning, this approach may cause unwanted DG trips. For

example, in the case of a short-circuit fault on an adjacent feeder, the DG source will feed the fault. The relay

will see the fault current but will not be able to differentiate it because of the short time setting. It will produce

a trip signal to the circuit breaker. Even a disturbance on the power system will cause the DG to trip.

Islanding is another protection issue requiring careful attention. When utility support is lost, there may

be an islanded area if the disconnected part of the system has a DG source. Intentional or unintentional islanded

areas may cause some problems such as load and generation imbalances, voltage and frequency instability, lack

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of protection, and impaired safety [16]. In order to achieve intentional islanding, there must be some equipment

implemented such as a communication system, the ability for DG to operate in voltage and frequency mode,

and a synchronization system for reconnection after islanding.

Power system reliability can be defined as the degree to which the performance of the elements in a bulk

system results in electricity being delivered to customers within accepted standards and in the amount desired.

The degree of reliability may be calculated in terms of the frequency, duration, and magnitude of adverse effects

on the electric supply. There are many indices for measuring reliability. The two most commonly used are the

system average interruption frequency index (SAIFI) and system average interruption duration index (SAIDI),

as defined in IEEE Standard 1366 [17].

SAIFI and SAIDI are defined by the following equations:

SAIFI =

∑Ni

NT, (1)

SAIDI =

∑ri ×Ni

NT, (2)

where i is an interruption event, N i is the number of interrupted customers for each interruption event, r i is

customer minutes of interruption, and NT is total number of customers served.

3. Central coordination relay design

A CCR is designed to overcome short-circuit protection issues due to the presence of DG in a distribution

system. Because of its communication nature, it is sited at the substation. A CCR consists of subsystems

such as a processor, memory, input, and output. It gathers the states of utility grids, generators, and circuit

breakers (CBs) through the communication line system. After the processor detects and locates the short-circuit

fault, it sends trip signals to suitable CBs. In the meantime, the CCR sends signals to the DG units within

the area to have their operating mode changed to voltage and frequency control modes if any islanding exists.

A distribution line carrier system can be used to provide communication between the CCR and the system

components.

In order to make intentional islanding possible, the system has to be reconfigured. For reconfiguration,

design procedures are set as shown in Figure 1. The details of design and operation procedures were given in

[5]. The implementation of these procedures in the Kocaeli area substation will be covered in Section 4.

When dividing a system into islanded areas, a set of rules can be defined as follows:

• An area has to have at least one DG unit.

• Within the area, total generation must be greater than total load.

• The areas have to be divided by remotely controlled circuit breakers.

• DG units must have voltage and frequency control devices.

• Synchronous reconnection has to be checked before restoring the grid.

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G1 G1 M1 M2 M3Fault

Location

1 0 + - 0 Area 1

1 1 + + 0 Area 1

G1 G2 M1 M2 M3Fault

LocationK1 K2 K3

1 0 + - 0 Area 1 O - O

1 1 + + 0 Area 1 O O -

Figure 1. CCR design flow chart.

Determining the short-circuit fault location is an essential task for the CCR. Therefore, the next step in

the flow chart is to identify fault areas divided by the remotely controlled CBs. The fault areas are defined as

follows:

• The part from the grid to the beginning of feeders.

– If there is an islanded area on the feeder:

∗ Each islanded area.

∗ The remaining part divided by CBs from the islanded areas.

– If there is no islanded area on the feeder: the part divided by CBs on the feeder.

Based on the defined fault areas and a possible short-circuit fault in each area, the table of the fault

locator and the table of the CBs’ opening are constructed. As seen from the table, the generator status and the

overcurrent flow directions determine the actions in the tables. These tables are very important for the CCR

to locate any short-circuit fault occurring within the protected area.

Once the completion of the design flow chart is confirmed, the initialization of the system is performed

by gathering several data through the communication lines. The initialization provides the information about

which unit and breakers are on service. The operation of the CCR is depicted in the flow chart given in Figure

2. The gathered data are compared with the table of CB openings. A trip signal is created and applied to the

selected CBs based on its logic. If an islanded area exists, the CCR sends a signal to the DG units to change

its control from power factor mode to voltage and frequency mode.

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Figure 2. CCR operation flow chart.

3.1. Application of CCR

The central coordination relay is applied to two 34.5-kV feeders at a substation in Kocaeli that is chosen

because of its load and generation diversity. In this section, information about the two-feeder system is given

first. Islanding and fault areas are then defined, and the tables of the fault locator and CB openings are

generated based on Figure 1. Upon completion of the design, the CCR will operate according to the flow chart

shown in Figure 2.

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3.2. Distribution system information

The selected substation operated by SEDAS is located in the Kocaeli area. The feeders connected to the

substation have some small-scale generation and heavily industrial loads along with residential loads. Having

generation on a loaded distribution feeder represents a typical DG system, which makes the substation a perfect

candidate for the CCR application. The substation connected to a 154-kV transmission system through two

100-MVA transformers has seventeen feeders on it. According to 2006 data, the total capacity of DG is 77.1

MW. Feeders 6 and 16 are chosen for this application because feeder 16 has a heavy industrial load and two DG

resources while feeder 6 has one DG resource and a light load as compared with feeder 16. Feeder 6 has a DG

unit of 2.3 MVA and a total load of 7.07 MW. Feeder 16 has two DG units and a total load of 16.13 MW. Thetotal generation capacity is 11.5 MVA. These two feeders are modeled in DIgSILENT PowerFactory simulation

software. Figure 3 shows the system modeled and simulated.

3.3. Defining islanded and fault areas

According to the set of rules defined in the previous section, one islanded area on feeder 6 and two islanded

areas on feeder 16 are composed. As shown in Figure 3, area 1.2, area 1.3, and area 2.2 are the islanded areas.

After composing the islanded areas, defining the fault areas is important to locate the fault. Figure 3

also shows the fault areas on the feeders with dotted lines. As seen in the figure, the system could be divided

into seven fault areas: area 1.1, area 1.2, area 1.3, area 1.4, area 2.1, area 2.2, and area bus bar. The areas are

divided by the CBs. Table 1 shows the generation and load data for the areas.

Table 1. Fault areas.

Feeder Fault areasTotal generation Total Total load Total numbercapacity (MVA) number of DGs (MW) of loads

Feeder 16

Area 1.1 0 0 4.49 14Area 1.2 7 1 6.13 10Area 1.3 4.5 1 4.30 2Area 1.4 0 0 1.21 8

Feeder 6Area 2.1 0 0 5.17 2Area 2.2 2.3 1 1.90 3

For constructing a table of CB openings, reference currents and possible fault current directions are

marked on the single-line diagram on Figure 4. Let us assume there is a short-circuit fault in each fault area

separately for each individual case. All the measurements of current directions and amplitudes are taken at the

location of CBs. A fault and the directions of the currents corresponding to the same fault are shown in the

same color. For example, a possible fault occurrence in area 1.4 is shown in blue. Due to the fault, all the fault

currents that could flow to the CBs are also shown in blue. This is completed for each area.

The data of fault areas, the directions of the fault currents, and the status of the utility grid and DG

units are used for the fault locator table. For each row it is determined which CBs should open in order to

clear the fault and maximize service continuity. The result is added to each row to compose the table of circuit

breaker openings as shown in Table 2. In the table, G, M, and CB stand for generator status (1: on, 0: off),

measured current direction (+: same as reference, -: opposite to reference, 0: no current flow), and circuit

breaker status, respectively.

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Figure 3. The system model of feeders 6 and 16 with fault areas.

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Figure 4. Current directions.

Table 2. Table of circuit breakers openings.

G1.2

G1.3

G2.2

M1.1

M1.2

M1.3

M1.4

M2.1

M2.2

MS

Fau

ltlocation

CBS

CB1.1

CB1.2

CB1.3

CB1.4

CB2.1

CB2.2

CBG1.2

CBG1.3

CBG2.2

1 1 + -

Area 1.1

O O O O1 0 + - O O O O0 1 + - O O O O0 0 + 0 O O1 1 + -

Area 1.2

O O O1 0 + 0 O O0 1 + - O O0 0 + 0 O

0 +Area 1.3

O1 + O O

+ Area 1.4 O1 + -

Area 2.1O O

0 + 0 O1 -

Area 2.2O O

0 0 O1 1 1 - - +

Bus bar

O O O O O1 0 1 - - + O O O O O0 1 1 - - + O O O0 0 1 0 - + O O1 1 0 - 0 + O O O O1 0 0 - 0 + O O O O0 1 0 - 0 + O O0 0 0 0 0 + O

For interpreting the first row, the fault location is determined in fault area 1.1 when G1.2 and G1.3 are

on, M1.1 is in the same direction, and M1.2 is in the opposite direction. The CCR then sends trip signals to

CB1.1, CB1.2, CB1.3, and CB1.4 in order to clear the fault.

After the CCR is put into operation, in the case of a phase to ground short-circuit fault on the line ‘Hat

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18.F1’, the CCR receives the measured current direction at M1.4 as a ‘+’ signal. The CCR then compares this

signal to find the appropriate row in the table of circuit breaker openings and sends a signal to clear the fault by

opening the breaker of CB1.4. After the fault is cleared, the CCR resumes operation for the rest of the system.

4. Reliability assessment

SAIFI and SAIDI are good indications of the reliability of a system. In order to see the impact of the CCR on

reliability, those indices are computed for both situations, with and without CCR application for the same period.

Tables 3 and 4 tabulate the interruption data of the system for the two cases based on the feeder interruption

records between October 2007 and September 2008. It should be noted that the records of interruptions in terms

of frequency, duration, and location are kept monthly at the selected substation by the Turkish Electricity

Transmission Corporation (TEIAS). In conventional protection manner, the feeder breaker opens when any

fault occurs on the feeder, causing all the loads to be interrupted. However, the CCR implementation can

allow service continuity for some part of the feeder by keeping DG units in service. Table 4 is constructed by

transforming the record in the case of CCR implementation in terms of the same fault location, frequency, and

duration for each interruption.

Table 3. Interruption data for feeders without CCR.

NT = 39 Na1 na1 Ts1Feeder 16 34 32 769Feeder 6 5 8 790

Table 4. Interruption data for the fault areas with CCR.

Fault Area Ny* Ni nari(min)

Area 1.1 13 21 18 420Area 1.2 11 19 8 214Area 1.3 2 2 0 0Area 1.4 8 8 6 135Area 2.1 3 3 8 790Area 2.2 2 2 0 0*Ny: Number of customers within the fault areas.

Based on the data given in Tables 3 and 4, the reliability indices of SAIFI and SAIDI are calculated for

both cases. Computed indices are compared in Table 5.

Table 5. Comparison of the indices.

SAIFI SAIDI (min)Without CCR 28.92 771.7With CCR 15.43 418.9Percentage of the two cases 53% 54%

As can be seen from Table 5, both indices are reduced to half of their previous values with the CCR

implementation. This result shows that CCR not only provides protection coordination but also increases the

usage of the generation capacity against faults, thereby improving service continuity.

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5. Conclusion

This paper proposes a way of allowing intentional and controllable islanding in a distribution system with DG.

A central coordination relay is developed for an adaptive protection scheme and improved reliability of the

system. The designing and operating principles of the CCR sited on a substation are introduced to a system

divided into islanded areas. It gathers and monitors breaker and generator status, current magnitudes, and

directions at breaker points, then locates short-circuit faults based on the measured data and configures the

network. The operation of the relay is based on the input data measures and takes action depending on the

fault location and generator and breaker status.

The design and application of CCR were implemented on selected distribution system feeders in the

Kocaeli region using the DIgSILENT PowerFactory simulation tool. With the use of CCR, adaptive protection

is obtained against any faults by locating faults and creating islanded areas, and the system reliability is

considerably improved with the availability of some DG sources against faults within the system.

Acknowledgement

This work was supported by the Scientific and Technological Research Council of Turkey (TUBITAK) under

Grant 105E105. The substation data were provided by the Turkish Electricity Transmission Corporation

(TEIAS), 5th Transmission Facilities and Business Group Management, for the time period between October

2007 and September 2008.

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