ETAP Simulations of Adaptive Overcurrent Protection Scheme for

Distribution Network with Microgrids

Paul Jacob Palayil

1,2 a

, Ishan Desai

1,2 b

and Divyesh Mangroliya

1,2 c

Parul Institute of Engineering & Technology, Parul University, P.O. Limda, Vadodara, Gujarat, India

Department of Electrical Engineering, Faculty of Engineering and Technology, Parul University, India

ishan.desai@paruluniversity.ac.in, divyesh.mangroliya@paruluniversity.ac.in

Keywords: Microgrids, Distributed Generation, Adaptive over Current Protection, Protection Coordination, ETAP.

Abstract: A microgrid (MG) includes Distributed Energy Resources (DER), controllable load with adequate protection

scheme in an Electrical Power Distribution System. Renewable energy sources (RES) is expected to provide

efficient, low cost and clean energy with decentralized generation, storage and local consumption with MG.

In this paper an Adaptive Over Current Relays (AOCR) scheme in distribution networks (DN) considering

intermittency of Distributed Generation (DG) operations using a fuzzy logic controller (FLC) is proposed.

The onsite study included actual verification of protection scheme, the impact of DG on protection system

and protection coordination. A part of the IEEE 44 nodes radial distribution test feeder is taken for modelling

& simulating the proposed AOCR using Electrical Transient Analyzer Program (ETAP) software

environment.

1 INTRODUCTION

1.1 Background

Distributed generation can be defined as “small-scale

generating units located close to the loads that are

being served” [Nadarajah et.al, 2017]. Given the

business, regulatory and policy push, decreasing

product prices, the penetration level of DG will

consistently increase [Romero, 2017]. The benefits

shall include: network reliability & resilience,

reduction of grid congestion and peak loads, improve

the operation and stability of regional grids,

transmission loss & generation cost reduction,

postponement of investments in network expansion,

and lowering capital investment costs [Nascimento

et.al, 2016]. 3 types of microgrids are; remote, grid

connected and networked.

1.2 Challenges of MG Protection

Integrating DG causes the existing DN to lose its

radial power flow and traditional relay settings may

https://orcid.org/0000-0002-9972-1814

https://orcid.org/0000-0002-6955-5210

https://orcid.org/0000-0001-8525-4330

work incorrectly and become inadequate. Issues such

as: increase in short circuit level, bidirectional power

flow, voltage & frequency fluctuation etc. affect the

protective relays performance and power quality

issues [Bhise et.al, 2017]. Some of the consequences

are like false tripping, under and overreach, blinding

of relays and islanding [Tian et.al, 2016] require fast

& accurate OC and Earth fault Protective schemes.

1.3 Proposed Solution under Study

Several schemes have been introduced to alleviate the

impact of integrating DG in DNs [Saad et.al, 2017],

the best being adaptive protection scheme (APS). For

this project, an APS based on FLC is proposed

2 LITERATURE REVIEW

2.1 Power System Protection

“The objective of electrical system protection and

130

Palayil, P., Desai, I. and Mangroliya, D.

ETAP Simulations of Adaptive Overcurrent Protection Scheme for Distribution Network with Microgrids.

DOI: 10.5220/0011073700003203

In Proceedings of the 11th International Conference on Smart Cities and Green ICT Systems (SMARTGREENS 2022), pages 130-138

ISBN: 978-989-758-572-2; ISSN: 2184-4968

coordination are to;

- Limit the extend and duration of service interruption

whenever equipment failure, human error or adverse

natural events occur on any portion of the system

-Minimize damage to the system components

involved in the failure” (IEEE 242-2001)

Rapid disconnection of faulted apparatus limits

the amount of damage to it and prevents the effects of

fault from spreading into the system (Juan et.al,

2011). It can be classified into apparatus protection

and system protection. ANSI numbers, according to

their functions also classifies them.

2.2 Over Current and Earth Fault

Relays

Overcurrent relays are classified as follow:

1. Instantaneous Overcurrent Relays:

2. Definite Time Overcurrent Relays:

3. Inverse Time Overcurrent Relays (IDMT):

There are several types of inverse-time curves, which

are mathematically modeled under the IEC,

ANSI/IEEE standards and manufacturer policies as;

𝑡

𝑇𝑀𝑆  𝛽



𝐼

𝑠





𝛼

1

𝐿

(1)

where: t is the operating time in seconds,

I is the fault current level at the secondary side of

current transformer,

is the current setting expressed at the secondary side

of current transformer

L, α, β, are constants are as in Table 1.

Table 1: IEC Constants.

Time Current Characteristics (TCC)- “Selectively

coordinated” back up relay will wait for primary

devices “should” sense, operate and clear the fault.

BuffBook(IEEE242‐2001)‐MinimumCTIs

Table 2: Minimum CTI’s.

Relay settings assumed to be field-tested and calibrated.

CS – Clear space between curves with upstream minimum-

melting curve adjusted for pre-load.

Some manufacturers may also recommend a safety factor.

Consult manufacturers’ time-current curves.

4. Directional Overcurrent Relays (DOCR): Three

conditions must be satisfied for its operation: current

magnitude, time delay and directionality (Bayliss

et.al, 2007).

Figure 1: TCC.

2.3 Setting of over Current Relays

Based on system requirements, the pickup current of

the relay is adjusted by plug bridge for required

number of tapping in the coil with equation:

𝐶𝑢𝑟𝑟𝑒𝑛𝑡 𝑆𝑒𝑡𝑡𝑖𝑛𝑔 

𝑃𝑖𝑐𝑘𝑢𝑝 𝐶𝑢𝑟𝑟𝑒𝑛𝑡

𝑅𝑎𝑡𝑡𝑒𝑑 𝑆𝑒𝑐𝑜𝑛𝑑𝑎𝑟𝑦 𝐶𝑢𝑟𝑟𝑒𝑛𝑡 𝑜𝑓 𝐶𝑇

 100%

(2)

2.4 Coordination of Overcurrent

Relays

Selective coordination of protective devices needed

so that the fundamental protective functions are met

under the required attributes of protective relaying,

which are sensitivity, selectivity, reliability, and

speed (Ibrahim et.al, 2016).

In numerical relays there is no overrun, and

therefore the CTI can be as low as 0.2 s (Shih et.al,

2016).

Unlike the Over Current Relays, the Earth Fault

relays do not respond to the 3 phase or L-L Faults.

One earth fault relay is adequate to provide protection

for all types of earth faults. To provide sensitive

protection, it use zero sequence current and it is

mandatory to keep the pick-up current (min 15%)

above the maximum unbalance factor of 10%. To do

setting and coordination, only L-G faults are

considered.

Logic Coordination methods uses modern relays and

fast communication channels, the relay setting and

coordination involves primarily following steps:

ETAP Simulations of Adaptive Overcurrent Protection Scheme for Distribution Network with Microgrids

131

Figure 2: Logic coordination.

a) Identify all possible primary-backup relay pairs.

b) Decide the correct sequence of relay coordination.

c) Decide the pickup value and hence PSM for

relays.

d) Compute the TMS to meet the coordination.

e) Validation of the results.

2.5 Steps for Coordination Study

A) Develop a SLD of the system under study.

B) Determine normal, emergency and temporary

operating configurations of the system

C) Carry out the load flow analysis to determine the

minimum pick up settings of various devices

D) Carry out the short circuit analysis to determine;

1.Maximum and Minimum momentary single phase

and 3 phase short circuit currents

2. Maximum and Minimum interrupting duty 3 phase

short circuit currents

3. Maximum and Minimum ground fault currents

E) Collect the characteristics of the devices: TCC

curves & settings range from manufacturers.

F) Collect the thermal limit curves for devices

G) Determine the range of adjustments on the settings

of upstream or downstream overcurrent relays.

2.6 Impact of DG Integration on

Protection Coordination

MG changes the original DN topology, fault current

& bidirectional flow of currents depends on fault

location, capacity and number of DGs.

False Tripping and Loss of Coordination.

The definition of protection coordination loss can

be taken as “violation of CTI constraint between the

primary and backup relays” (Shih et.al, 2017).

Protection Blinding. Also known as protection

under- reach since the actual reach of the feeder relay

is decreased due to fault current contribution from the

DG (Korres et.al, 2016).

Nuisance Tripping of Feeder.

Islanding Operation.

2.7 Adaptive Protection Coordination

Scheme

In APS, continuous monitoring of operational and

topological changes of the network is ensured.

Communication has a major role in an adaptive

relaying (Wan et.al, 2010). Modern relays can switch

between multiple groups of time current characteristic

curves based on the system operating conditions. The

non-communication based APS relays respond

immediately based on pre-calculated settings

configured in it against different DN network

topology.

2.8 Fuzzy Logic Control

It provides an inference structure as means for

converting linguistic strategy into control actions and

thus offers a high-level computation (Sivanandan

et.al, 2007). FLC belongs to the class of “intelligent

control,” which uses knowledge-based decision-

making employing techniques of fuzzy logic (Karray

et.al, 2004) for the control actions.

There are three commonly used types of fuzzy

system (Altas, 2017),

a) Mamdani fuzzy system

b) Takagi-Sugeno (TKS) fuzzy system

c) Tsukamoto fuzzy system

A zero-order Sugeno fuzzy model is functionally

equivalent to a radial basis function network under

certain minor constraints.

The use of FLC has increased rapidly in power

systems for load/frequency control, bus bar voltage

regulation, stability, load estimation, power flow

analysis, parameter estimation, protection systems

and many other fields.

2.9 Review on Techniques Used to

Mitigate the Impact of DG

Penetration on Protection Relays

Coordination

Various solutions proposed are;

 Disconnecting the DGs immediately after fault

detection by S. Conti, 2009

 Limiting the capacity of installed DGs

(Chaitusaney et.al, 2008)

 Modifying the protection system by installing

non-communication-based approach by adding more

protective devices like multi-function devices &

reclosers (Hamed Funmilayo and K. L. Butler-Purry,

2009).

 Installing the fault current limiters (FCLs) to

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preserve or restore the original relay settings (Kim &

Elmitwally et.al, 2016).

 Employing fault ride through control strategy of

inverter based DGs (Naderi et.al, 2017)

 To avoid miscoordination of IDMT relays for

synchronous-DG, W. Xu et.al, 2014 used a solid-

state-switch-based field discharge circuit to limit the

generator’s fault current.

 Abbas Esmaeili et.al. 2016 used optimal

programming of fault current limiters using two-stage

stochastic model.

 E. Ebrahimi et al, 2014 used fault ride through

approach for IBDG; Control strategy was proposed

and applied to the voltage source converter (VSC) so

that the protection coordination remains unchanged.

 R. Sitharthan et.al, 2016 used an APS for MG by

utilizing microprocessor-based over current relays.

They also used auto reclosers, through which the

proposed APS recovers faster from the fault and

increase the consistency of the MG as result.

 Rahmati and Dimassi, 2014 proposed an APS

that uses a least square algorithm to determine the

Thevenin circuit equivalent using local

measurements in off-line information regarding

varying short-circuit levels caused by DER infeed.

APS using differential evolution algorithm (DE)

on DOCR & ABC algorithm coordination used

automatic online re-adjustment of settings for

different MG topologies results from dispatch or

natural conditions.

Data mining and analytics or “Big Data” can play

a vital role in modern MG. Main areas of

Computational Intelligence (CI) methods, ANN’s,

PSO algorithms etc. can be used for AP Solutions.

FLCs allows larger solution space and find

applications in areas that derive inferences from

uncertain and undefined data of renewable energy

based DGs (Sampath, 2015).

3 METHODOLOGY

3.1 APS based on Pre-calculated

Settings

The AOCR can be programmed for simulation with

Automatic setting groups (SG) design. By auto

selecting the mode of operations, with proper

protection and restoration control logic the MG

switchgears can be controlled automatically. Through

the Etap- real time, all necessary inputs for the event

table of all relay pairs matching the mode of operation

and the location of the fault can be made.

The IEC standard inverse characteristic equation

3 of overcurrent relay (Juan et.al,2011) to use;

𝑡





0.14  𝑇𝑀𝑆



𝐼



𝐼









1

(3)

Where: TMS is the time multiplier setting of the relay,

is the fault current seen by the relay, I

pickup

is the

pickup current of the relay. TMS and I

pickup

should be

determined in a special range as follows:

𝑇𝑀𝑆

min

≤𝑇𝑀𝑆≤𝑇𝑀𝑆

max

pickup min

≤𝐼𝑃≤ I

pickup max

To ensure the selectivity, the operating time of

Backup Relays (𝑡

𝑏

) should have enough delay time

from Primary relays (𝑡

𝑝

) as CTI:

𝑡

𝑏

−𝑡

𝑝

≥𝐶𝑇𝐼

3.2 APS based on Real Time

Calculated Settings

Adaptive protection is “an online activity that

modifies the preferred protective response to a change

in system conditions or requirements in a timely

manner by means of externally generated signals or

control action” (Rockefeller, 1988). The required

settings are updated in online manner as per variation

in fault current levels seen by relays during changing

network conditions (IEEE, 2014).

Figure 3: Flow chart of the proposed AOCR for MG.

ETAP Simulations of Adaptive Overcurrent Protection Scheme for Distribution Network with Microgrids

133

The adaptive relay connected to the network will

firstly do an auto-calibrate. After that, the parameters

of I

pickup

, Time Dial Setting (TDS) and the fault

current will be preset to zero. Following, it will do a

Newton–Raphson method of load flow analysis &

Short Circuit Analysis by IEC 60909 Std. Then, it will

calculate the I

pickup

with required (1.5 times for

example) safety margin (Sung et.al, 2013). However,

if there is a change in configuration i.e. DG

connections, the same is

communicated

through the

relay which results in a new set of parameters for

pickup

and TDS.

The next step is identifying the fault and its

location by using the overcurrent equation, which is

denoted by “(1)” in the algorithm. The principle of

overcurrent protection is shown;

> I

pickup

(4)

In the overcurrent principle, the “Normal Condition”,

where there is no fault, relay will not trip circuit

breakers (CB). “(T)” is the representation of the

second condition, which is the short-circuit or fault

condition. When I

is greater the I

pickup

, after

determining the mode of protection, it issues a

command for the right CB to trip. Once the fault is

cleared, it will restore to the original condition. It

continues to do the same process for the next iteration

where N = N + 1.

3.3 APS Algorithm in the Distribution

Network

The above flow chart can be coded in Fuzzy logic

controller for real time use. With SCADA, the Fuzzy

Logic Designer application for Microgrid Central

Controller (MGCC) makes the IED’s completely

adaptive. The application needs the power network’s

model for load flow calculation as well as

measurement integration for collecting online data by

using communication protocols. Real-time simulation

uses the execution of new solutions in monitoring, the

control system, and automation.

3.4 AOCR Block Diagram

Figure 4: AOCR block diagram.

4 SIMULATIONS SET UP

4.1 Site Data

In this study, the IEEE 44 bus radial feeder existing

DN is adopted. ETAP software (Etap 21.0.1 version)

is used to draw the detailed SLD, simulate the LFA,

SC & CTI studies. Relays like SE P122/ P139, Tr -

O/C & E/F, busbar/ feeder management protection, all

existing Switchgears and devices were site verified.

Numbering of buses and sources done, the master

SLD finalized before create a site SLD for the

simulations. All required permits, tools, methodology

secured, on-site verifications assisted by an expert.

4.2 Description of ETAP Simulation

Set Up

All required analysis was performed in a personal

computer with an Etap dongle and in the 9-bus

subnetwork (MG model). The new feature in the

SCADA system is the state estimation concept which

is used by the ETAP real-time application. It supports

the advancement of the information and automation

schemes for autonomous protections.

SGs features were identified with the help of Etap

simulations as per Figure 4.2 with 2 DG’s for 4 loads

connected to “Chiller bus 7” which is designed as the

emergency backup chillers to cater the critical loads.

Figure 5: Summary DN data.

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5 ETAP SIMULATION RESULTS

VERIFIED OF SELECTED IEEE-

9 BUS SUBSYSTEM

5.1 Load Flow Analysis Reports

5.1.1 LFA by Adaptive Newton Raphson

Method

Figure 6: LFA.

5.1.2 LFA Report Summary of Generation,

Load and Demand

Table 3: LFA.

Description MW MVar MVA %PF

Total Demand-

Source

(

Swin

2.97 1.80 3.48 85.6Lag

Total Motor Load

2.38 1.47 2.80 85.0Lag

Total static Load

0.59 0.37 0.70 85.0Lag

Apparent Loss

0.003 -0.041

System Mismatch

0 0

No. of iterations 01

5.2 Short Circuit Analysis Reports

SCA by IEC 60909 Standard of selected network

carried out, for simplicity we have taken the reading

of 3 phase faults. With different SG’s the values of

Fault Current (KA) are found to be different and is

tabulated in Table 4.

5.3 Protection Coordination

Simulations

CTI Simulation with Fault Creation -Grid mode

(Curve settings verifications by ETAP 21.0.1 software

(Star Coordination option). The response sequence to

the fault simulation for SG #1 was given below.

Figure 7: SG 1 Fault simulation- relays response Sequence.

Figure 8: SG 1Fault simulation - relays response Report.

For each simulations the curve settings reviewed and

corrected for sequence and t

. A standard inverse

IEC curve is used to carry out the automatic

coordination of overcurrent protections (IEC & IEEE,

2009). Figure 9 below shows the CTI of relays

operation with Fault Simulation with SG #3 (PG +

2DG’s).

ETAP Simulations of Adaptive Overcurrent Protection Scheme for Distribution Network with Microgrids

135

With different SG’s the values at which the relays

tripped are found to be different and the obtained

information tabulated as Table 4. The highlighted

values set in the same relay with the same fault but in

different configuration of sources clearly

demonstrates the needs for APS.

Table 4: CTI Report Summary.

SG #

Configuration

Relay

Pair

Fault

Current

(KA)

pickup (A)

T1 in ms

1 PG Source only

R 16-

R2F18

R1F18

7.83

184

790

784

0.1

0.12

0.15

2 PG+ 1DG

R 16-

R2F18

R1F18

9.31

184

1100

784

0.1

0.12

0.15

3 PG+ 2DG

R 16-

R2F18

R1F18

10.89

184

1540

784

0.1

0.12

0.15

Island- 1DG (not

used for AOCR

settings)

R 16-

R2F18

DGR3

1.48

184

320

312

0.1

0.12

0.14

4 Island - 2DG

R 16-

R2F18

DGR3

3.06

184

620

0.1

0.12

0.14

Figure 9: SG 3 CTI of relays response Sequence.

From different analysis done for combinations of

power sources with its optimum curve settings of

relay pairs the input values for relay programming

established. The relay R2F18 selected being common

to all SGs for the adaptive settings.

6 AOCR FUNCTIONAL

VERIFICATION

We used SE P139 relay, 4 Automatic Settings Groups

programmed with Pre-Calculated values of pick up

and Time dial derived from Fault Simulations and

CTI settings respectively. The Relay PLC

programming (Easergy Studio V9.3.1-SE) also

defined the relay pairs for CB’s control actions. The

existing DN panels were set up for HIL tests by

secondary injection method. The relay test block

wired properly, connected the Omicron CPC 100 test

kit and relay control established through ethernet.

Figure 10: HIL Set up.

The results of L-L SC simulation results recorded as;

Figure 11: AOCR L-L Fault Simulation.

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136

Detailed system generated reports like File

Information, Analog Summary, Events/Sensors

Activity Log and Summary downloaded.

Also, results of L-E Fault response graph recorded as;

Figure 12: AOCR L-E Fault Simulation.

7 CONCLUSION AND FUTURE

SCOPE

The adaptiveness of the relay functions verified

against programmed values. An algorithm has been

proposed for the AOCR to implement in Microgrids

with SCADA and Etap real time. Since IEC-61850

supplies appropriate peer-to-peer connection between

distributed IEDs, by using ‘generic object-oriented

substation events’ (GOOSE) technology, we may

achieve any data transmission through the network

within 4ms, so this protocol is being used in all

modern grids DNs [Tian et.al, 2016]. AOCR with

technologies such as AI and IoT, which uses real-time

values expected to have widespread use in future MG.

ACKNOWLEDGMENT

My sincere thanks to Er. Dhafi Rashid Al Marri, ED-

Engineering, HMC, Doha, Qatar for his guidance.

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APPENDIX

Tools and Components Referred during

Study

1. MG Controllers

SEL- PowerMAX with RTAC, SEL 3555, 3560

and 651R

SE - Ecostructure Power, Micom P40 easergy

series

Opus 1 solutions – GridOS-DER EMS

GE – U90+ Multilin

2. Overcurrent protection devices for MG

Controllers

SE -P139/ GE -P14D/ Micom P446

Siemens - Siprotech/ Reyrolle 7SR/ ABB – REF

615

3. MG Simulation tools

EMTP & ETAP Realtime

MATLAB/Simulink -Java Agent Development

Environment

DigSilent/ Opal RT/ Siemens PSS/ DER –CAM

EPRI –OpenDSS/ GridLAB -D

4. Plug and Play type DER’s

Eaton - Heila Edge (Solar)

Cat BDP 250 (ESS invertor)

Alpha structure (Carlyle and SE)/ Bloom Energy

Siemens

5. Communication and compliance needs

IEEE 2030.7 & 8, IEC 61850 -9.2LE, Modbus,

RS232/485, IEEE 1547/242/C 37, IEC 61439 (LV)/

62271 (HV) for SWGR & Controls

6. Other Desirable Controller features

PLC compatibility, Load sharing/Shedding,

Voltage/frequency regulation, Power and PF

control, SER/Oscillography recorder, Short and

open circuit protection, Trip and close controls,

Self-diagnosis/self-calibrations

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