transmission line protection using pott scheme a …

TRANSMISSION LINE PROTECTION USING POTT SCHEME

A Project

Presented to the faculty of the Department of Electrical and Electronic Engineering

California State University, Sacramento

Submitted in partial satisfaction of

the requirements for the degree of

MASTER OF SCIENCE

in

Electrical and Electronic Engineering

by

Adewunmi Oluwademilade Taiwo

SPRING

2019

ii

© 2019


ALL RIGHTS RESERVED

iii


A Project

by


Approved by:

__________________________________, Committee Chair

Mahyar Zarghami

__________________________________, Second Reader

Tracy Toups

____________________________

Date

iv

Student: Adewunmi Oluwademilade Taiwo

I certify that this student has met the requirements for format contained in the University

format manual, and that this project is suitable for shelving in the Library and credit is to

be awarded for the project.

___________________, Graduate Coordinator ___________________

Preetham Kumar Date

Department of Electrical and Electronic Engineering

v

Abstract

of


by


Statement of Problem

Permissive Overreaching Transfer Trip (POTT) is a scheme that enables fast

tripping of breakers at the local and remote end of a protected equipment. POTT schemes

are typically used for high voltage line protection against faults in areas with coordination

and power stability issues. Three-phase fault is the most severe type of fault that can

occur and fast tripping at high voltages is paramount for personnel safety, to avoid

equipment destruction, and fires. POTT schemes require a secure form of

communication between both relays (local and remote).

Sources of Data

For this project, I followed guidelines provided by Pacific Gas and Electric

(PG&E) Transmission Line Protection Manual and Relay Application Guideline. I used

Aspen software package to model the power system (transmission lines and buses). I also

performed analyses such as fault-duty study, relay-setting testing, and coordination study

using Aspen. I used Mathcad to create relay-setting using PG&E guidelines. In general,

the settings depend on the fundamentals of POTT scheme, the fault-duty study, and the

vi

current transformer (CT) and voltage/potential transformer (PT) ratios. I used Microsoft

Visio to model other diagrams and figures required to better explain how the POTT

scheme works.

Conclusions Reached

POTT scheme is an effective scheme for fast tripping. It requires a secure form of

communication between both relays (local and remote) protecting the equipment. Using

relevant manuals, guidelines and papers, I modelled and set relays to protect a 230kV line

using a POTT scheme. I also provided Phase distance and Ground overcurrent settings

for SEL-411L relays.

_______________________, Committee Chair

Mahyar Zarghami

_______________________

Date

vii

ACKNOWLEDGEMENTS

I must show my utmost gratitude to the System Protection group at PG&E for the

opportunity to learn from them, to use their system, and to follow their protection

guidelines. This project would not be possible without the help of Protection engineers in

the West Sacramento office.

To my mom Adejoke Taiwo, thank you for your love, patience and for sacrificing

a lot to help me understand the fundamentals of mathematics. I would not be an engineer

today without you. To my dad Adekunle Taiwo, thank you for your constant love, advice,

and encouragement to purse my career goal.

I would like to thank God for the wisdom, knowledge, strength and favor to be

where I am today. In God I found strength to persevere against all odds.

Finally, I would like to thank my project advisor Mahyar Zarghami of the

Electrical and Electronics Department at California State University, Sacramento. He has

helped me greatly to achieve academic success.

viii

TABLE OF CONTENTS

Page

Acknowledgements………………………………………………………………..........vii

List of Tables………………………………………………………………………...….. x

List of Figures ………………………………………………………………………..... xi

Chapter

1. INTRODUCTION ....................................................................................................1

2. WHAT IS A FAULT AND WHY DO WE NEED PROTECTION? .........................3

Fault on Power System .........................................................................................3

Symmetrical Faults ...................................................................................3

Unsymmetrical Faults ...............................................................................4

Why Do We Need Protection Against Faults? ......................................................5

3. THE SYSTEM SET UP ...........................................................................................8

The System ...............................................................................................8

Important Components for System Protection ...........................................9

4. LINE PROTECTION ............................................................................................. 12

Overcurrent Protection............................................................................ 13

Distance Protection ................................................................................. 14

5. POTT SCHEME TRANSMISSION LINE PROTECTION..................................... 16

Working Principle of Pott Scheme ..................................................................... 16

In Section Fault ...................................................................................... 18

ix

Out of Section Fault................................................................................ 18

Advantages of POTT Scheme ................................................................. 19

Disadvantages of POTT Scheme............................................................. 20

6. RELAY SETTINGS ............................................................................................... 21

Transformer Ratios and Line Impedance ............................................................ 21

Selecting Current Transformer Ratio (CTR) ........................................... 21

Selecting Potential Transformer Ratio (PTR) .......................................... 22

Line Impedance ...................................................................................... 23

Phase and Ground Relay Settings ....................................................................... 24

Phase Distance Settings .......................................................................... 24

Ground Directional Overcurrent Settings ................................................ 27

Substation A ........................................................................................ 27

Substation B ........................................................................................ 32

7. SIMIULATION RESULTS .................................................................................... 36

In Section Fault ...................................................................................... 36

Out of Section Fault................................................................................ 42

8. CONCLUSION ...................................................................................................... 46

Appendix A. ................................................................................................................. 48

Appendix B. ................................................................................................................. 52

References ..................................................................................................................... 56

x

LIST OF TABLES

Tables Page

1. System Attributes ………………………………………..……………………. 22

2. Transmission Line Attributes …………………………………………………. 23

3. Phase Distance protection settings for local and remote relays ……….……… 25

4. Ground Directional Overcurrent relay settings summary for Relay A …….…. 31

5. Ground Directional Overcurrent relay settings summary for Relay B ………. 34

xi

LIST OF FIGURES

Figures Page

1. Types of Symmetrical Faults ................................................................................4

2. Types of Unsymmetrical Faults ............................................................................5

3. System Setup .......................................................................................................8

4. Zones of Protection Illustration .......................................................................... 15

5. Permissive Overreaching Transfer Trip Scheme ................................................. 17

6. In-section fault on protected line ........................................................................ 18

7. Out-of-section fault on protected line ................................................................. 19

8. Mho Circle of Phase Distance relay .................................................................... 26

9. Inverse Overcurrent Relay Curve (U1) for relays at Sub A ................................. 31

10. Very Inverse Overcurrent Relay Curve (U3) for relays at Sub B ......................... 35

11. Aspen Oneliner Simulation of applied SLG fault ................................................ 36

12. SEL SynchroWave file of Line relay at Sub A for in-section SLG Fault ............. 37

13. SEL SynchroWave file of Line relay at Sub B for in-section SLG Fault ............. 38

14. Aspen Oneliner Simulation of applied LL fault .................................................. 39

15. SEL SynchroWave file of Line relay at Sub A for in-section LL Fault ............... 40

16. SEL SynchroWave file of Line relay at Sub B for in-section LL Fault ................ 41

17. SEL SynchroWave file of Line relay at Sub A for out-of-section LL Fault ......... 43

18. SEL SynchroWave file of Line relay at Sub B for out-of-section LL Fault ......... 44

1

1. INTRODUCTION

Our electric power system comprises of several components to enable the

generation, transmission, and distribution of power. The AC power system is typically a

three-phase system, in which three sinusoidal voltages with the same amplitude and 120°

of phase-shift are generated. This power is then transmitted over long distances using

high voltage power lines and cables and is further distributed to customers using low

voltage power lines.

Under normal conditions, the power system is considered safe, but there are

events that can threaten the safety of the system. A fault in the power system can cause

dangerous and unsafe conditions. When a fault occurs, the voltage and current in the

system is disturbed. We tend to see a depression in voltage and sudden spike in current

which is as a result of decrease in impedance at the fault location. A sudden and sustained

spike in current can have devastating effects such as destruction of power equipment.

This can be avoided by tripping the faulted equipment.

Tripping of power equipment is the process of disconnecting the equipment from

the power sources and isolating the fault. This is accomplished using combined action of

circuit breakers, relays, potential transformers, current transformers, and in some case

communication channels. It is important to understand that when we have high voltages,

a sudden depression and huge spike in current can be very devastating. Therefore, fast

tripping to isolate the fault is crucial. Pilot schemes enable fast tripping.

2

Pilot schemes are communication-assisted schemes between the local and remote

relays to protect a power system equipment. There are several pilot schemes but for the

purpose of this project we focus on POTT scheme.

Permissive Overreaching Transfer Tripping (POTT) is a type of pilot scheme that

requires a secure communication channel to enable fast tripping. This permissive tripping

is done by both local and remote relays. When a relay sees a fault in its zone of

protection, it sends out a permission signal through communication channels to other

relays protecting the line telling them to trip instantaneously if they also see a fault in the

forward direction. A permissive trip will only occur when all relays protecting the line

agree that the fault is on the protected line (in-section) and not on another line (out-of-

section).

3

2. WHAT IS A FAULT AND WHY DO WE NEED PROTECTION?

Fault on Power System

The electric power system operates with all equipment carrying the normal

allocated load current and voltages [2]. The system under normal conditions operates

within predetermined limits which can be disrupted by a disturbance. A fault is a

disturbance in an electric circuit that affects the normal delivery of power. A short circuit

fault causes a sudden spike in current and depression in voltage as a result of a low

impedance path created between phases or phase(s) to ground. The flow of high fault

current through the faulted equipment can cause catastrophic damages. Short circuit

currents can be classified into:

Symmetrical Faults

Unsymmetrical Faults

Symmetrical Faults

A fault involving all three phases is a symmetrical fault. Three phase fault occurs

when three equal fault impedance is applied to the three phases. Since the three phases

are balanced and equal fault impedance is applied, the resulting fault currents and

voltages on all phases are balanced. A symmetrical fault is the most severe fault that can

occur because it involves all three phases. There are two types of symmetrical faults;

three phase to ground (3LG), and three phase fault.

4

(a) Three-phase to ground fault (b) Three-phase fault

Figure 1: Types of Symmetrical Faults

Unsymmetrical Faults

Unlike symmetrical faults, unsymmetrical faults do not involve all three phases.

Unsymmetrical faults causes an unbalance in the system. This can occur as a result of

lighting, animal interference, wind, temperature, tree branches and so much more. This

makes unsymmetrical faults more common. There are three types of unsymmetrical

faults:

Single Line to Ground (SLG) Fault

Line to Line (LL) Fault

Double Line to Ground (LLG) fault

(a) Single Line to Ground fault (b) Line to Line Fault

5

(c) Double Line to Ground Fault

Figure 2: Types of Unsymmetrical Faults

Why Do We Need Protection Against Faults?

As explained in previous sections, a fault causes high current flowing through the

faulted equipment and decreased bus voltages. What does this mean to an equipment?

Electrical components in the power system are rated based on the maximum current such

equipment can withstand before they are damaged. Take for example, a three phase 100

MVA 60 Hz system, with a 230 kV transmission line which uses a 477 Hawk 26/7 ASCR

conductor with a current ampacity of 655 A. The normal current flowing through the

system is calculated at 251 A. A three phase to ground fault occurs on the line with a

fault current of 11,500 A. This is 17.5 times the rated current that can flow through the

conductor. As a result, this fault can cause a fire that can destroy properties in its vicinity.

Protection against faults prevents catastrophic events from happening. It gives us

the ability to quickly isolate the faulted component from the rest of the system. With the

6

faulted component isolated, no current flows through it, thus eliminating the risk of

equipment damage and stabilizes the power system.

When it comes to power system protection, we are concerned about the following

attributes:

Reliability

o Security

o Dependability

Selectivity

Speed

Simplicity

Economics

Reliability focuses on the ability of the protection scheme to operate properly. We

say the protection system is secure when breakers do not trip when they should not, and

dependable when breakers trip when they are expected to. Selectivity is the ability to trip

the minimal amount of protection devices to clear a fault. Selectivity is done to endure

that there’s no miscoordination of the protective devices. Miscoordination is when the

backup protection operates faster than the primary protection. When this happens,

unaffected equipment (i.e. transformer, lines) are isolated from the power system. This

causes unnecessary loss of power delivery.

When it comes to protection speed, the faster the better. This is important to

minimize the damaging effect of a fault and to ensure system stability. Keeping the

protection scheme simple and easy to follow is important to ensure that any engineer or

technician can determine what went wrong when the scheme does not work as expected.

7

Economics plays a major part when deciding what protection scheme to apply. In other

words, do not go for an expensive scheme when a cheaper one works just as fine.

8

3. THE SYSTEM SET UP

The System

This project focuses on the protection of a 230kV transmission line using a POTT

scheme. Figure 3 shows the single-line diagram of the protected line connected between

Substation A and Substation B.

Substation A has two step-down transformers from 230kV to 115kV. This

substation is fed from three sources, 230kV substations E, G and F and feeds five 230kV

substations B, D, H, I, and J. Substation B has two step-down transformers from 230kV

to 115kV. This substation is fed from 4 sources, 230kV substations A, D, K and B and

feeds two 230kV substations C and L.

For this project, let us call the protected line “Sub A – Sub B 230kV Line”. The

transmission line is an electrical conductor cable that enables the flow of power from one

point to another. There are several types of electrical cable used in power transmission

Figure 3: System Setup

9

such as: All Aluminum Conductor (AAC), All Aluminum Alloy Conductor (AAAC),

Aluminum Conductor Steel Reinforced (ACSR) etc. This transmission line is 28.5 miles

long. The line conductor type is ACSR which is great for long distances because of the

steel reinforcement.

Important Components for System Protection

For line protection using POTT scheme, we need a current transformer (CT),

potential/voltage transformer (PT), line relays, line circuit breaker, and communication

channel.

Current Transformers (C.T.) are used to reduce high currents to a lower current

value that can be used by the relay and monitoring devices. The alternating current (AC)

that flows through the primary winding of the CTs is proportional to the current on the

secondary winding by the turns ratio the windings [1]. Typically, CTs have a turns ratio

of primary current (Ip) to secondary current of 5A (Ip/5A). CTs deliver 0 to 5A of

secondary current that is proportional to the primary current. CTs are important for the

overcurrent function of the protection relay.

Potential/Voltage Transformers (PTs) are used to reduce high voltages to lower

voltages and work as an instrument transformer. PTs step down the primary voltage to a

secondary voltage of about 0 to 120 volts. PT provide a direction reference for relays.

They are also used for distance relay protection. Using the output of a CT and a PT, the

relay can calculate the apparent line impedance which is used in distance protection.

10

Protective relays are electromechanical, or microprocessor based devices that

calculates the decision to trip circuit breakers. A relay receives input signals from the

secondary side of CTs and PTs and can open or close the circuit breaker’s contact.

Microprocessor relays are more advanced than electromechanical relays and can

perform several mathematical functions. For this project, we will be using a

microprocessor line relay. SEL-411L relays are produced by Schweitzer Engineering

Laboratories (SEL) and have advanced line differential, distance and overcurrent

protection, automation, and control capabilities.

Although this relay has very advanced capabilities, this project would focus only

on the relay settings for distance and overcurrent protection and their comparison to

POTT scheme. This report will not cover line differential protection or mirrored bits

communication available in the SEL-411L relay.

Circuit breakers are used to manually or automatically de-energize or energize

power system equipment such as transmission or distribution lines, transformers,

generator, and buses. They act based on the command signals sent by the protective

relays. The circuit breakers on power lines usually have their contacts closed using

normal operations and opened when isolating or de-energizing the line.

Communication channel is a medium by which data transfers from one point to

another. In power system protection, communication channels are used to enable fast

tripping of circuit breakers when a fault is within the specified zone of protection. For

example, for line protection, the communication channel transfers data between the relays

at both end of the lines (relays are usually at the substation).

11

Communication channels help in improving the speed, security, dependability,

and sensitivity of protective relays [2]. There several types of communication channels in

power system protection such as power line carrier (PLC), leased telephone wire, spread

spectrum radio, fiber optics, and microwave.

12

4. LINE PROTECTION

There are several types of protection schemes that focus on some of the protection

attributes discussed in the previous section. Protection schemes are chosen based on the

type of electric equipment being protected, the amount of fault current, the frequency of

faults occurring in the location of the equipment and several other factors. Two group of

protection schemes important to this project: Non-pilot and Pilot protection line

schemes.

Non-pilot protection schemes do not require communication devices. These

schemes focus on the fault current and bus voltage at the location of the local breaker.

Pilot protection schemes require communication devices between the local and remote

end of the protected equipment. Protection devices at either ends require information

from the other end to make tripping decisions. Pilot schemes are used to increase

protection speed. These schemes are considered to have instantaneous tripping.

Depending on the availability of a CT and/or PT, here are common types of

protection that can be applied to the protected line:

Overcurrent Protection

Distance Protection

13

Overcurrent Protection

Overcurrent protection uses current from a CT to determine if a fault has occurred

and if tripping is required. Overcurrent protection requires a current threshold (pickup

value) to be set in the relay. When the current seen by the relay is over the pickup value,

the relay either issues an instantaneous trip or a timed delayed trip depending on how

much current is seen. For time-overcurrent protection (TOC) the time it takes the relay to

issue a trip is determined by the selected time dial (TD) and time-overcurrent curve.

Overcurrent protection can be directional or non-directional. When it is

directional, information from PT is required for the relay to determine where the fault has

occurred if it is in the forward or reverse direction. If the fault is in the reverse direction,

the directional overcurrent relay will not issue a trip signal, to enable other protection

devices to operate.

Depending on the type of fault, we can have a Phase Overcurrent relay protection

and Ground Overcurrent relay protection. Phase overcurrent relay protection is used to

protect the electric equipment from phase faults such as three phase faults or line to line

faults. Ground Overcurrent relay protection is used to protect against ground faults such

as SLG, and LLG.

14

Distance Protection

Distance protection is a type of protection that uses the apparent impedance seen

by the relay to determine if a fault has occurred and if tripping is required. Distance

relays need current (from CT) and voltage information (from PT) to calculate the

apparent impedance [2]. If the calculated impedance is not within the prescribed zones of

protection, the relay will not issue for a trip. There can be several numbers of protection

zones, typically transmission line protection uses three or four zones.

In line (transmission or distribution), Zone 1 is set to protect the primary line.

This is typically set to cover ≤ 85% of the line length and provides the fastest protection

with no intentional time delay. Zone 1 is not set to see the full length of the line because

of PT and CT errors that make it difficult to ensure that the relay does not trip for a fault

that is not on the protected line.

Zone 2 is set to see faults that are not on the protected line but with some time

delay margin that enables the protection on the other line to trip. Zone 2 relays are

usually set as backup protection for adjacent lines. This zone is typically set to 120% of

the primary line impedance. Zone 3 can be set to see faults further than Zone 2 in the

forward direction or can be set to protect against fault in the reverse direction of the relay.

Zone 3’s application depends on the protection requirement of the line and surrounding

lines.

Like overcurrent relays, distance relays can be set to protect against phase faults

(Phase distance element) or to protect against ground faults (Ground distance element).

15

For transmission line, we typically set phase distance relay as the standard and use

ground distance relay when the need arises. Relays these days are microprocessor based

and have several protection elements in them. Elements just need to be enabled or

disabled depending on application.

Figure 4: Zones of Protection Illustration

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5. POTT SCHEME TRANSMISSION LINE PROTECTION

Permissive Overreaching Transfer Trip (POTT) is a type of communication aided

(pilot) protection scheme. Pilot schemes are used to ensure faster clearing time

(instantaneous) and better selectivity which is often a requirement for high voltage lines

[4]. Pilot schemes are great because they ensure the following attributes [4]:

Faster tripping helps ensure that the system does not experience stability problems

as a result of the disturbance or fault.

Faster tripping ensures that there’s no coordination problems for the protected

equipment because the primary protection has no intentional delay.

Working Principle of Pott Scheme

The term “Permissive” implies that permission must be given for this scheme to

function. Using the communication medium, when a local relay detects that a fault has

occurred on the protected line, it tells the remote relay (and vice versa) that it can trip

faster (instantaneous) if the remote relay also detects a fault in the forward direction [3].

For a permissive trip to occur, all relays acting as the primary protection of the

line must agree that a fault has indeed occurred on the line [3]. This implies that both the

local and remote relays share information and would require transmitter and receiver

devices at both ends.

17

An “Overreaching” element (typically Zone 2) is set to see past the protected line

and encroaches into the adjacent lines [3]. This is done to ensure that the line is 100%

protected. Transfer Trip (‘TT”) is the signal that is sent by at least one relay to the other

relays to allow tripping when the overreaching element (RO) element picks up for a fault.

POTT scheme requires that the RO element picks up, keys a transfer trip channel

and only trips the circuit breaker when it receives a permissive trip signal from the

remote terminal [5]. A secure communication channel is very important for this scheme

to function properly. When the communication channel is compromised, the scheme is

not effective, and we need contingency schemes (like non-pilot) in place for such

instances.

Figure 5: Permissive Overreaching Transfer Trip Scheme

18

In Section Fault

For a fault on the protected line, we would expect the POTT scheme to work as

shown in Figure 5 below. At both ends, the RO element picks up and keys the transfer

trip channel. Both relays receive permissive trip signals. With both the RO element and

permissive trip signal received, the relays will issue a POTT scheme trip for both Breaker

A and B.

Figure 6: In-section fault on protected line

Out of Section Fault

For a fault not on the protected line, we would expect the POTT scheme to work

as shown in Figure 6 below. For a fault placed on a transmission line behind Breaker A,

the RO element of the relay at Breaker B would pick up while that of Breaker A would

not. Relay B key the transfer trip channel but would not receive a permissive trip signal.

19

Relay A would receive a permissive trip signal but would not key the transfer trip

channel. Because no relay has both RO element picked up and permissive signal

received, the Breaker A and B would not trip via the POTT scheme

Figure 7: Out-of-section fault on protected line

Advantages of POTT Scheme

POTT scheme is very secure because it will not issue for false tripping when an

external fault occurs. It is easy to understand because the scheme is simple and not

complicated. It is easy to construct; POTT scheme requires a directional element that can

be set for three zones (i.e. distance protection) [4].

20

Disadvantages of POTT Scheme

POTT scheme relies on a secure communication channel. A compromised

communication channel means this scheme would not produce a pilot trip for a fault on

the protected line. Due to this concern, power line carrier is not an advised

communication channel for pure POTT scheme protection [4]

21

6. RELAY SETTINGS

Transformer Ratios and Line Impedance

For this project, we will be setting SEL-411L relays at both terminals. This relay provides

us with several protection options. For the POTT scheme protection, we will be enabling

Phase Distance and Ground Overcurrent elements.

Phase distance relays should protect the line from any type of fault. Due to the

unpredictable ground impedance that can occur during a SLG fault, phase distance

elements might not be sensitive to this fault. Ground overcurrent elements was set to

provided protection against SLG faults which is the most common fault that occurs on

power lines. To successfully set the relays, we need to determine transformer ratios for

CT and PT:

Current Transformer Ratio (CTR)

Potential Transformer Ratio (PTR)

Selecting Current Transformer Ratio (CTR)

Current transformers come from manufactures with either single ratio or multi-

ratio. When the CT has multiple ratios available, a selection can be made to best fit our

need. To avoid thermal issues with CT, CT ratio should be set higher than the maximum

emergency loading of the protected equipment (i.e. Transmission line) [4]. The CT ratio

22

selected should keep the maximum secondary fault current that can occur on the

protected equipment to a minimum value (PG&E guideline is 50 A to 100 A) [4].

Table 1: System Attributes

Line to Line Voltage (KV) 230

Maximum Loading 1378 A

This conductor has a highest California ISO (CALISO) rating of 1378A during

summer peak loading. As mentioned in previous section, the relay needs a secondary

current of about 5A therefore, the CT converts primary currents to 5 A secondary. The

available CT ratios are 300:5, 400:5, 500:5, 800:5, 1100:5, 1200:5, 1500:5, 1600:5, and

2000:5. Given this information, we will be selecting a CT ratio of 1600/5 which gives

reasonable margin to the maximum loading.

Selecting Potential Transformer Ratio (PTR)

The relay requires an input of about 120 V which means the systems high voltage

of 230kV has to be stepped down considerably to be used by the relay. With a 230kV, a

PTR ratio of 2000 will provide 115 V on the secondary side of the transformer, which is

sufficient. The system is designed to withstand a change of ± 10% in voltage.

Transmission lines do not typically have overvoltage protection because alarms would go

off during this conditions and system operators would rectify the issue.

23

Line Impedance

The line impedance was provided by PG&E’s Aspen Oneliner model of its system

and is presented in Table 2 below.

Table 2: Transmission Line Attributes

Line Length 28.5 miles

Positive Sequence Impedance (Z1) 0.00514 + j0.04101 per unit

Zero Sequence Impedance (Z1) 0.01943 + j0.13154 per unit

The given per unit impedance values are in primary bases and therefore we need

find the impedance used by the relay by converting to secondary bases as shown below:

ZBase = KVLL

2

MVAbase

= (230×103)

2

100×106 = 529 Ω

Zratio = k = PTR

CTR =

2000

(1600

5)

= 6.25

Z1,pri=ZBase× √0.005142 +0.04101 2 =21.8 Ω

Z0,pri =ZBase× √0.01943 2 +0.13154 2 = 70.34 Ω

Z1,sec=Z1,pri

k=

21.8

6.25=3.49824 Ω; Z1,ANGLE= tan-1 (

0.04101

0.00514) =82.86°

Z0,sec=Z0,pri

k=

70.34

6.25=11.25435 Ω; Z0,ANGLE= tan-1 (

0.13154

0.01943) =81.6°

24

With the above calculations, the line impedance date input to the relay is:

Z1,MAG=3.49824 Ω; Z1,ANGLE= 82.86°

Z0,MAG=11.25435 Ω; Z0,ANGLE= 81.6°

Phase and Ground Relay Settings

Using the PG&E system model on Aspen Oneliner, several fault simulations were

performed to find the maximum and minimum short circuit currents, voltages, and

impedance. The results of this simulations can be found in Appendices A and B.

Phase Distance Settings

For phase distance protection, we will be setting 3 zones of protection. Zone 1

will be set to 85% of the minimum line impedance with no intentional time delay [6].

Zone 2 will be set to overreach the line (RO element) at 120% of the maximum line

impedance with 20 cycle delay for coordination with upstream and downstream relays

[6]. Zone 2 serves as the RO pick up element for POTT scheme and would trip after a

specified time delay in a situation when the communication channel is compromised.

Z1MP = 0.85× ZP

k = 2.98 Ω sec Z1PD = 0 cycle

Z2MP = 1.2× ZP

k = 4.2 Ω sec Z2PD = 20 cycles

25

Zone 3 is set to see in the reverse direction and to equal the Zone 2 element of the

remote end. This ensures that the relay overreaches (sees farther) than the forward-

looking Zone 2 element of the remote terminal [6]. Zone 3 is set to confirm that relay is

operating properly and that the fault is indeed behind the relay. Zone 3 can also be set as

backup protection for a bus fault.

Z3MP =

RemoteZ2MP × (𝑅𝑒𝑚𝑜𝑡𝑒 𝑃𝑇𝑅𝐶𝑇𝑅𝑅𝐸𝑀𝑂𝑇𝐸

)

k = 4.2 Ω sec Z2PD = 20 cycles

Where:

ZP = Impedance of the line

Z1MP = Maximum impedance that would trigger Zone 1 protection



Z1PD = Time delay for Zone 1



Table 3: Phase Distance protection settings for local and remote relays

PT ratio 2000

CT ratio 320

Zone 1 (Forward) 2.98 Ω sec

Zone 2 (Forward) 4.2 Ω sec

Zone 3 (Reverse) 4.2 Ω sec

Zone 1 time delay 0 cycle

Zone 2 time delay 20 cycles

Zone 3 time delay 20 cycles

26

Since Phase distance uses the impedance of the line, the same settings would be

applied to relays at both ends of the line.

Figure 8: Mho Circle of Phase Distance relay

Mho circles shows the R-X boundary of the protection zones. The maximum

impedance reach for each zone, the relay characteristics angle (RCA) and the maximum

torque angle (MTA) is used to generate the Mho circles. The positive sequence

impedance angle of the line is typically set as the MTA. The RCA is used to calculate the

maximum load that could cause the relay to operate and is usually set to 90°. The

diameter of each circle is impedance boundary set for each zones. During the normal

27

operation of the system, the load impedance is usually high enough to not encroach into

the mho circles.

Ground Directional Overcurrent Settings

For ground protection, we will be setting ground overcurrent elements instead of

distance elements. This is because for high impedance in-section faults, ground distance

relays are less likely to see the fault [4]. The Ground Directional Time Overcurrent

element is set to 50% of the minimum fault current for a fault on the remote bus with all

sources, parallel lines in and the strongest local source out [5]. 50 and 51 are the IEE

standard device numbers for Instantaneous overcurrent relay and AC time overcurrent

relays respectively.

Substation A

Using the simulation results in Appendix A, the calculations below was done to

determine the appropriate directional ground times and instantaneous overcurrent

settings.

Ground Directional Timed Overcurrent settings [6]:

Using the minimum ground fault current (Min3I0), the pickup value is calculated as:

28

51G = 0.5×Min3I0

CTR = 1.59 Asec

Select 51G = 1.5 Asec

For coordination with upstream and downstream relays, we selected Inverse Overcurrent

Curve (U1). 51C = U1.

Where:

Min3I0 = Minimum ground fault current

51G = Minimum current pickup value for Ground Timed Overcurrent protection

CTR = Current Transformer Ratio

51C = Time-Overcurrent curve

The time dial is set for > 0.33 sec (20 cycles) fastest clearing of the remote bus fault. This

allows for coordination [6].

Using the SEL Curve U1 equation provided by SEL-411L instruction manual

MG = Max3I0

51P01 × CTR= 5.158

TimeGfault = 0.7 s

TDGMAXFAULT=

TimeGfault

0.0226 + 0.0104

M0.02 − 1

= 2.09

Select 51TD = 2.2

29

Where:

Max3I0 = Maximum ground fault current

MG = Multiples of pickup

TimeGfault = Desired fastest clearing time

TD_GMAX_FAULT = SEL Time Dial element

51TD = Inverse Time Overcurrent 01 Time Dial

The 51G setting serve as the RO pick up element for POTT scheme. It also serves

backup protection in a situation where the communication channel is compromised, or

the POTT scheme is cut out.

Ground Directional Instantaneous Overcurrent settings [6]:

The Ground Directional Instantaneous Current element is set to about 120% to

130% of the highest remote bus fault with no intentional time delay [6]. To get this, put a

fault on the remote bus with a strong source at the local bus or parallel line out [5].

50𝐺 = 1.2 × 𝑀𝑎𝑥3𝐼0

𝐶𝑇𝑅= 9.29 𝐴𝑠𝑒𝑐

Select 50G = 9.5 Asec 50GD = 0 cycle

30

Where:


50G = Minimum current pickup for Ground Instantaneous Overcurrent protection

50GD = Time delay


To make these relays directional, we need to provide a reference point for

polarization. Polarization provides a reference point by which the relay can tell if the

current is going in (forward) or going out (reverse). Ground directional overcurrent

relays are typically polarized using either the negative sequence voltage or the zero

sequence voltage from the remote end. Refer to Appendix A for polarization quantities.

For the Ground Directional Element settings, SEL Application guide AG2016-14

suggests the following settings [6]:

Forward Directional Overcurrent Pickup (50FP) = 0.5

Forward Directional Z2 Threshold (Z2F) = -0.3

Reserve Directional Z2 Threshold (Z2R) = 0.3

Positive-Sequence Restraint Factor, I2/I1 (a2) = 0.1

Zero-Sequence Restraint Factor, I2/I0 (k2) = 0.2

31

Table 4: Ground Directional Overcurrent relay settings summary for Relay A

CT ratio 320

Time Dial 2.2

Overcurrent Curve U1

Timed Overcurrent pick up (Asec) 1.5

Instantaneous Overcurrent pick up (Asec) 9.5

Figure 9: Inverse Overcurrent Relay Curve (U1) for relays at Sub A

10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7

10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)

SECONDS

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TIME-CURRENT CURVES By

For No.

Comment Date

1

1. Ground relay LINE A- LINE B GROC SEL3xx/5xxMI TD=2.2

SUB A 230.kV - SUB B 230.kV L SUB A - B

CTR=1600/5 Pickup=1.5A Inst=3040A TP@ 5.0=0.7491s

32

Figure 9 above shows the inverse overcurrent relay curve (U1) which was

selected. The operating time (Y axis) is inversely proportional to the current (X axis). The

more current the relay sees the faster it issues a trip. The curve can be selected to be

steeper (inverse to extremely inverse curve). The straight section of the plot is the

minimum current that would trigger an instantaneous trip (which we selected to be 3,040

Apri or 9.5 Asec).

Substation B

Using the simulation results in Appendix B, the calculations below was done to

determine the appropriate directional ground times and instantaneous overcurrent

settings.

Ground Directional Timed Overcurrent settings [6]:

Using the minimum ground fault current (Min3I0), the pickup value is calculated as:

51G= 0.5×Min3I0

CTR = 1.59 Asec

Select 51G = 1.5 Asec

5IC = U3.

Where:

Min3I0 = Minimum ground fault current

51G = Minimum current pickup value for Ground Timed Overcurrent protection

33


51C = Time-Overcurrent curve

Using the SEL Curve U3 equation provided by SEL-411L instruction manual

MG = Max3I0

51P01 × CTR= 5.158

TimeGfault = 0.4 s

TDGMAXFAULT=

TimeGfault

0.0963 + 3.88

M𝐺2 − 1

= 1.95

Select 51TD = 2

Where:


MG = Multiples of pickup

TimeGfault = Desired fastest clearing time

TD_GMAX_FAULT = SEL Time Dial element

51TD = Inverse Time Overcurrent 01 Time Dial

Ground Directional Instantaneous Overcurrent settings [6]:

The Ground Directional Instantaneous Current element is set to about 120% to

130% of the highest remote bus fault with no intentional time delay [6]. To get this, but a

fault on the remote bus with a strong source at the local bus or parallel line out.

34

50𝐺 = 1.2 × 𝑀𝑎𝑥3𝐼0

𝐶𝑇𝑅= 10.92 𝐴𝑠𝑒𝑐

Select 50G = 11 Asec 50GD = 0 cycle

Where:


50G = Minimum current pickup for Ground Instantaneous Overcurrent protection

50GD = Time delay


Table 5: Ground Directional Overcurrent relay settings summary for Relay B

CT ratio 320

Time Dial 2

Overcurrent Curve U3

Timed Overcurrent pick up (Asec) 1.5

Instantaneous Overcurrent pick up (Asec) 11

Ground directional overcurrent relays are typically polarized using either the

negative sequence voltage or the zero sequence voltage from the remote end. Refer to

Appendix B for polarization quantities.

35

Figure 10: Very Inverse Overcurrent Relay Curve (U3) for relays at Sub B

Figure 10 above shows the very inverse overcurrent relay curve (U3) which was

selected. The operating time (Y axis) is inversely proportional to the current (X axis). The

U3 curve is steeper than the U1 curve. This implies that for the same amount of current,

the time overcurrent relay using the U3 curve would trip faster than U1 curve. The

straight section of the plot is the minimum current that would trigger an instantaneous trip

(which we selected to be 3,520 Apri or 11 Asec)

10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7

10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)

SECONDS

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TIME-CURRENT CURVES By

For No.

Comment Date

1

1. Ground relay LINE A - LINE B GROC SEL-VI TD=2

SUB B 230.kV - SUB A 230.kV L SUB A - B

CTR=320:1 Pickup=1.5A Inst=3520A TP@ 5.0=0.5159s

36

7. SIMIULATION RESULTS

In Section Fault

We will be analyzing a phase to ground fault (AG) placed at about 10% of the line

from Sub A. Without using a POTT scheme, as shown in Figure 11, the directional

instantaneous ground overcurrent line relay at Sub A would issue for the tripping of

Breaker A with no time delay. It typically takes a high voltage circuit breaker about 0.1

seconds to trip and isolate a fault.

The directional timed ground overcurrent line relay at Sub B would pick up and

issue for the tripping of Breaker B after a time delay of 0.563 second. The time delay plus

the time it takes the breaker to open results in an actual tripping time of 0.653 second.

Figure 11: Aspen Oneliner Simulation of applied SLG fault

With a POTT scheme, we can see in Figure 12 and Figure 13 that both relays’ RO

element would pick up (50G2), both would key the transfer trip channel (KEY), and both

would receive a permissive trip signal (PTRX). The line breakers clear the fault on the

37

line in about 0.1 seconds at both ends. So rather than waiting for 0.653 second to clear the

single phase to ground fault, by using a POTT scheme we can clear the fault much faster.

About half a second might seem irrelevant to us, but in the protection world, this is a

huge deal. This difference could prevent power stability issues or area blackouts due to

cascading fault events.

Figure 12: SEL SynchroWave file of Line relay at Sub A for in-section SLG Fault

38

Figure 13: SEL SynchroWave file of Line relay at Sub B for in-section SLG Fault

Next, we analyze how a POTT scheme compares to the Zone 1 (Z1) and Zone 2

(Z2) phase distance protection of the transmission line. For this analyzes, a phase to

phase fault (LL) was placed at about 10% of the line from Sub A. Without using a POTT

scheme, as shown in Figure 14, the phase distance Z1 element at Sub A would issue for

the tripping of Breaker A without a time delay. The Z2 phase distance element at Sub B

would pick up and issue for the tripping of Breaker B after a time delay of 20 cycles

(0.333 second).

39

Figure 14: Aspen Oneliner Simulation of applied LL fault

With a POTT scheme, we can see in Figure 15 and Figure 16 that both relays’ RO

element would pick up, both would key the transfer trip channel (KEY), and both would

receive a permissive trip signal (PTRX). The line breakers clear the fault on the line in

about 0.1 second at both ends. The POTT scheme supersedes the Zone 2 time delay of

0.333 second and clears the fault faster.

40

Figure 15: SEL SynchroWave file of Line relay at Sub A for in-section LL Fault

41

Figure 16: SEL SynchroWave file of Line relay at Sub B for in-section LL Fault

The POTT scheme would operate the same way for a 3LG, LL, and LLG fault.

The only difference would be the magnitude of the fault current. The when the fault is

outside the Z1 protection of the relay, the POTT scheme would supersede the preselected

Z2 time delay and would trip the circuit breaker faster.

42

Out of Section Fault

For an out of section fault as explained in section 5, we do not expect the relays to

operate via the POTT scheme. Figure 17 and Figure 18 helps us visualize what happens

when a fault is placed on Bus B and then reversed and placed on Bus A. With a phase to

phase fault (LL) occurring at Bus B, we expect the RO element to pick up at Sub A but

not at Sub B. When the reversal occurs, we expect the RO element to pick up at Sub B

but not at Sub A. Let’s analyze the waveforms below.

Figure 17 below is the waveform observed from relay A. During the first few

cycles we placed a fault on the 230kV Bus at Sub B. We observe that the RO element

(Z2P) picks up (sees the fault). The relay keys the transfer trip channel but does not

receive a permissive trip signal from relay B.

The fault is then reversed and placed on the 230kV Bus at Sub A. The RO

element does not see the fault because the fault is in the reverse direction. To confirm the

direction, we can see that the Z3P element picks up since it is looking in the reverse

direction. Relay A receives a permissive trip signal from relay B but does not key the

transfer trip channel. As a result, Breaker A does not trip for the fault.

43

Figure 17: SEL SynchroWave file of Line relay at Sub A for out-of-section LL Fault

Figure 18 below is the waveform observed from relay B. During the first few

cycles we placed a fault on the 230kV Bus at Sub B. We observe that the RO element

(Z2P) does not pick up because the fault is behind the relay. To confirm the direction, we

can see that the Z3P element picks up since it is looking in the reverse direction. The

relay receives a permissive trip signal from relay A but does not key the transfer trip

channel.

44

Figure 18: SEL SynchroWave file of Line relay at Sub B for out-of-section LL Fault

The fault is then reversed and placed on the 230kV Bus at Sub A. The RO

element (Z2P) picks up (sees the fault). The relay keys the transfer trip channel but does

not receive a permissive trip signal. As a result, Breaker B does not trip for the fault.

Since both relays’ RO element did not pick up, key the transfer trip channel and

receive a permissive trip signal from the other end during the same cycles, the POTT

scheme did not operate for the out of section fault.

This fault test was done to mimic how the relays should operate when there’s a

close-in fault at a breaker on a parallel line. For a close in fault on a parallel line’s

45

breaker, these relays can experience a current direction reversal when the said breaker

opens to clear the fault.

For all out of section faults (3LG, LLG, LL, SLG), the POTT scheme would

operate the same and would not issue for a trip. The only difference would be that for a

SLG fault, the ground overcurrent relay would pick up rather than the phase distance

relay.

46

8. CONCLUSION

Faults on the electric equipment can have very devastating effects. Faults are

disturbances on the power system that cause changes in normal operations such as

changes in current and voltage. A huge increase in current flowing through electrical

equipment can result in overloading, fires and can threaten personnel safety. Changes in

voltage levels can result in power stability issues and system wide blackout. It is very

important that we isolate a faulted equipment from the rest of the power system and cut

off all sources feeding the fault.

Circuit breakers can be used to isolate faulted equipment from the power system.

Circuit breakers rely on relays to make calculations, determine if a fault has occurred on

the protected equipment, and to signal the breaker to isolate the equipment. Relays

depend on Current transformers, Potential transformers and user defined settings to

determine if a fault has occurred and if the breaker needs to trip the fault. A relay can

operate based on two main types of protection schemes; non-pilot and pilot schemes.

Pilot schemes are protection settings that require communication from relays on

both ends of the protected equipment. Pilot schemes are used to ensure selectivity and

fast tripping. Pilot schemes are typically implemented in areas with power stability issues

or relay coordination issues with upstream or downstream relays. POTT is a type of pilot

scheme that can be used for transmission line protection.

Permissive overreaching transfer trip (POTT) is a secured protection scheme that

enables protective circuit breakers to trip faster for a fault on the protected line

47

(conductor). POTT scheme would not issue for a trip when the fault is not on the

protected line. A relay using POTT protection must be set to have an overreaching

element that sees beyond the protected line. When the overreaching element (typically

Zone 2 protection) picks up for a fault, it keys a transfer trip channel but would not trip

the breaker unless it receives a permissive trip signal from the remote end relay.

POTT scheme depends on a very secure communication channel between the

local and remote relays. If the communication channel gets compromised, the POTT

scheme would not operate, and a backup non-pilot protection should be used.

Communication channel security should be considered before deciding on what type of

channel can be used for this scheme.

48

Appendix A

Simulations and Settings for Line Relay Substation A

1. Aspen Simulation Results

Table: Remote Bus & Line End Faults

Imin3ph≔2863•Apri 3LG @ Sub B, Sub E-Sub A 230kV Line Out

Imax3ph ≔ 4216 • Apri 3LG @ Sub B, Sub D − Sub B 230kV Line Out

ZPmin ≔ 21.9 Ωpri 3LG @ Sub B

ZPmax ≔ 21.9 Ωpri 3LG @ Sub B

Min3I0= 1016 • Apri SLG @ Sub B, Sub B − Sub C 230kV Line Out

Max3I0= 2476 • Apri SLG close in end open on Sub D - Sub B 230kV Line ,

Sub B Bank #2 Out

Iminfphase≔2412•Apri SLG @ Sub B, Sub B – Sub C 230kV Line Out

Imaxfphase = 4216•Apri SLG @ Sub B, Sub D – Sub B 230kV Line Out

Iclosein_min_3ph = 13902•Apri 3 Ph Close in fault with Sub E - Sub A 230kV Line

Out

Iclosein_min_f_phase = 13902•Apri 1 Ph-Gnd Close in fault with Sub A - Sub D 230kV

Line Out

Iclosein_min3I0 = 13166•Apri

Table: Reverse Currents

Imax3ph_rev = 3573•Apri 3LG @ Sub A, Sub D – Sub B 230kV Line out

Max3I0REV= 2905 • Apri SLG @ Sub A, Sub A – Sub D 230kV Line out

ImaxfphaseREV=3573•Apri 3LG @ Sub A, Sub D – Sub B 230kV Line out

Table: Polarizing Quantities

V0 = 7.4 •Vpri SLG @ Sub B

V2 = 9.6 • Vpri SLG LEF to Sub B

49

2. Pilot Settings

ECOMM = POTT

TX_IDPORT1 = 1

RX_IDPORT1 = 2

The pilot (POTT) forward ground overcurrent pickup is set to less than or equal to 50%

of the minimum fault value.

50G2P = 0.5×Min3I0

CTR = 1.59 Asec

Select 50G2P = 1.5 Asec

50G2P = 480 Apri

3. Coordination Checks for Phase Distance Relay

Check of coordination with Upstream Terminals (N-1 POTT Out):

1. Lines into Sub B:

Sub B - Sub K: ok. Zone 2 only sees 1% of Sub B - Sub K line

Sub D - Sub B: ok. Zone 2 only sees 12% of Sub D - Sub B line

Sub B - Sub L: ok. Zone 2 only sees 2% of Sub B - Sub L line

Sub B - Sub C: ok. Zone 2 only sees 2% of Sub B - Sub C line

Sub M - Sub B: ok. Zone 2 only sees 3% of Sub M - Sub B line

2. Sub A Bank 1 and Bank 2

ok. Zone 2 does not see beyond instantaneous zone of Bank 1 and Bank 2

50

Check of coordination with Downstream Terminals:

Sub F - Sub A: ok. Zone 2 reach of Sub F only sees 4% of Sub A - Sub B line

Sub G - Sub A: ok. Zone 2 reach of Sub G only sees 2% of Sub A - Sub B line

Sub E - Sub A: ok. Zone 2 reach of Sub E only sees 6% of Sub A - Sub B line

Sub A - Sub D: ok. Zone 2 reach of Sub D only sees 2% of Sub A - Sub B line

Sub A - Sub H: ok. Zone 2 reach of Sub H only sees 4% of Sub A - Sub B line

Sub A - Sub I: ok. Zone 2 reach of Sub I only sees 4% of Sub A - Sub B line

Sub A - Sub J: ok. Zone 2 reach of Sub J only sees 6% of Sub A - Sub B line

4. Coordination Checks for Directional Ground Overcurrent Relays



Sub B - Sub K: ok. Does not see beyond IT zone of line relay

Sub D - Sub B: ok. Does not see beyond IT zone of line relay

Sub B - Sub L: ok. Does not see beyond IT zone of line relay

Sub B - Sub C: ok. Does not see beyond IT zone of line relay

Sub M - Sub B: ok. Does not see beyond IT zone of line relay




Sub F - Sub A: ok. Does not see beyond IT zone of line relay

Sub G - Sub A: ok. Does not see beyond IT zone of line relay

51

Sub E - Sub A: ok. Does not see beyond IT zone of line relay

Sub A - Sub D: ok. Sub K line relay trips in 4 seconds for fault beyond IT zone of

Sub B line relay

Sub A - Sub H: ok. Does not see beyond IT zone of line relay

Sub A - Sub I: ok. Does not see beyond IT zone of line relay

Sub A - Sub J: ok. Does not see beyond IT zone of line relay

52

Appendix B

Simulations and Settings for Line Relay Substation B

1. Aspen Simulation Results

Table: Remote Bus & Line End Faults

Imin3ph≔2270•Apri 3LG @ Sub A, Sub B - Sub K 230kV Line Out

Imax3ph ≔ 3573 • Apri 3LG @ Sub A, Sub D - Sub B 230kV Line Out

ZPmin ≔ 21.9 Ωpri 3LG @ Sub A

ZPmax ≔ 21.9 Ωpri 3LG @ Sub A

Min3I0= 1502 • Apri SLG @ Sub A, Sub E - Sub A 230kV Line Out

Max3I0= 2912 • Apri SLG close in end open on Sub A - Sub J 230kV Line,

Sub A -Sub B 230kV Line Out

Iminfphase≔1938•Apri SLG @ Sub A, Sub E - Sub A 230kV Line Out

Imaxfphase = 3573•Apri 3LG @ Sub A, Sub D - Sub B 230kV Line Out

Iclosein_min_3ph = 9245•Apri 3 Ph Close in fault with Sub D - Sub B 230kV Line

Out

Iclosein_min_f_phase = 9570•Apri 1 Ph-Gnd Close in fault with Sub A - Sub D 230kV

Line Out

Iclosein_min3I0 = 13166•Apri

Table: Reverse Currents

Imax3ph_rev = 4216•Apri 3LG @ Sub B, Sub D - Sub B 230kV Line Out

Max3I0REV= 2123 • Apri SLG @ Sub B, Sub D - Sub B 230kV Line Out

ImaxfphaseREV= 4216•Apri 3LG @ Sub B, Sub D - Sub B 230kV Line Out

Table: Polarizing Quantities

V0 = 5.4 •Vpri SLG LEF Sub A

V2 = 11.6 • Vpri SLG LEF to Sub A

53

2. Pilot Settings

ECOMM = POTT

TX_IDPORT1 = 2

RX_IDPORT1 = 1

The pilot (POTT) forward ground overcurrent pickup is set to less than or equal to 50%

of the minimum fault value.

50G2P = 0.5×Min3I0

CTR = 2.35 Asec

Select 50G2P = 1.5 Asec

50G2P = 480 Apri

3. Coordination Checks for Phase Distance Relay



Sub F - Sub A: ok. Zone 2 only sees 6% of Sub F - Sub A line

Sub G - Sub A: ok. Zone 2 only sees 1% of Sub G - Sub A line

Sub E - Sub A: ok. Zone 2 only sees 7% of Sub E - Sub A line

Sub A - Sub D: ok. Zone 2 only sees 4% of Sub A - Sub D line

Sub A - Sub H: ok. Zone 2 only sees 1% of Sub A - Sub H line

Sub A - Sub I: ok. Zone 2 only sees 6% of Sub A - Sub I line

Sub A - Sub J: ok. Zone 2 only sees 3% of Sub A - Sub J line

54




Sub B - Sub K: ok. Zone 2 reach of Sub K only sees 8% of Sub A - Sub B line

Sub D - Sub B: ok. Zone 2 reach of Sub D only sees 2% of Sub A - Sub B line

Sub B - Sub L: ok. Zone 2 reach of Sub L only sees 18% of Sub A - Sub B line

Sub B - Sub C: ok. Zone 2 reach of Sub C only sees 6% of Sub A - Sub B line

Sub M - Sub B: ok. Zone 2 reach of Sub M only sees 6% of Sub A - Sub B line

4. Coordination Checks for Directional Ground Overcurrent Relays



Sub F - Sub A: ok. Does not see beyond IT zone of line relay

Sub G - Sub A: ok. Does not see beyond IT zone of line relay

Sub E - Sub A: ok. Does not see beyond IT zone of line relay

Sub A - Sub D: ok. Sub K line relay trips in 4 seconds for fault beyond IT zone of

Sub B line relay

Sub A - Sub H: ok. Does not see beyond IT zone of line relay

Sub A - Sub I: ok. Does not see beyond IT zone of line relay

Sub A - Sub J: ok. Does not see beyond IT zone of line relay

55


ok. Will miscooordinate for a N-2 condition with Sub A Bank 1 &2 high side relays

when differential relays are cut out and Sub A - Sub D line is out.


Sub B - Sub K: ok. Sub K line relay trips in 2 seconds for fault beyond IT zone of

Sub B line relay

Sub D - Sub B: ok. Does not see beyond IT zone of line relay

Sub B - Sub L: ok. Does not see beyond IT zone of line relay

Sub B - Sub C: ok. Does not see beyond IT zone of line relay

Sub M - Sub B: ok. Does not see beyond IT zone of line relay

56

REFERENCES

[1] “Current Transformer Basics and Current Transformer Theory,” Basic Electronics

Tutorials, 05-Oct-2018. [Online]. Available:

https://www.electronics-tutorials.ws/transformer/current-transformer.html.

[Accessed: 04-Feb-2019].

[2] Electrical4U, “Distance Relay or Impedance Relay Working Principle

Types,” Electrical4U, 01-Sep-2018. [Online]. Available:

https://www.electrical4u.com/distance-relay-or-impedance-relay-working-principle-

types/. [Accessed: 20-Feb-2019].

[3] “Understanding Permissive Over-Reaching Transfer Trip (POTT) Communication

Assisted Trip Schemes Video,” Valence Electrical Training Services, 06-Mar-2018.

[Online]. Available: https://relaytraining.com/understanding-permissive-over-

reaching-transfer-trip-pott-communication-assisted-trip-schemes-video/. [Accessed:

08-Mar-2019].

[4] Pacific Gas and Electric Relay App Guide

[5] Pacific Gas and Electric Transmission Protective Relay Setting Manual

[6] Pacific Gas and Electric Line Relay Setting Calculations Mathcad file

transmission line protection using pott scheme a …

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