SECTIONALIZING STUDY OF 132/33 KV GRID SUB STATION DISSERTATION Submitted in partial fulfilment of the requirements of Master of Engineering in Electrical Power Engineering Md. Siddique Hossain Department of Electrical and Electronics Engineering School of Engineering Kathmandu University December 2005
This document is posted to help you gain knowledge. Please leave a comment to let me know what you think about it! Share it to your friends and learn new things together.
Transcript
SECTIONALIZING STUDY OF 132/33 KV GRID SUB STATION
DISSERTATION Submitted in partial fulfilment of the requirements of
Master of Engineering in Electrical Power Engineering
Md. Siddique Hossain
Department of Electrical and Electronics Engineering
School of Engineering
Kathmandu University
December 2005
SECTIONALIZING STUDY OF 132/33 KV GRID SUB STATION
DISSERTATION Submitted in partial fulfilment of the requirements of
Master of Engineering in Electrical Power Engineering
By:
Md. Siddique Hossain
Under supervision of: Mr. Roshan Bhattarai
Assistant Professor Department of Electrical and Electronics Engineering
School of Engineering Kathmandu University
Department of Electrical and Electronics Engineering School of Engineering
Kathmandu University
December 2005
ACKNOWLEDGEMENTS
The end of writing a thesis is the beginning of expressing gratitude to those who have
contributed to it.
First of all I would like to express my deepest thanks to the three people who contributed
most to the thesis. They are Prof. Arne T Holen of NTNU, Asst. Prof. Roshan Bhattarai
and Asst. Prof. Gautam Bajracharya of Kathmandu University. Prof. Holen, taught me
about power system analysis, besides suggested and answered all the questions I posed.
I am very grateful to my supervisor Mr. Roshan Bhattarai, Assistant Professor,
Kathmandu University for his guidance, encouragement and assistance. I also express my
indebted gratitude to Dr. Bhupendra Bimal Chhetri, Course Coordinator of Master of
Electrical Power Engineering and Head of the Department of Electrical and Electronics
Engineering, Kathmandu University for his kind cooperation and continuing support at
any situation over the study periods. I would like to express my thanks to Mr. Morten
Husom, Powel ASA, Norway for giving me suggestions even when he was busy with his
work. Besides, I also thank Mr. Egil Hagen who put the primary idea of collecting data
and making a thesis into my head.
I am grateful to Mr. Faizul Kabir, Deputy Manager, PGCB and Mr. Abaidullah, Asst.
Manager, PGCB, Bangladesh for providing the data and relay guide manuals that I
needed for my project. Apart from this I heartily thank Mr. Arup Kumar Bishwas, Asst.
Engr., REB who has given lot of constructive comments for my dissertation work.
I wish to express my gratitude to the Norwegian Agency for Development Cooperation
(NORAD) for providing me opportunity to take part in this course and financial support
during my Masters period. I would like to express my heartily thanks to my organization
LP Gas Limited, especially Mr. A. Wadud Khan, Ex M.D. and Mr. Md. Fazlur Rahman
Khan, AGM for granting me permission in this course. I wish to convey warmest thanks
to my parents and my wife who gave me endless support and inspiration to continue with
this study at abroad.
Finally, I am thankful to all of my friends and all the staffs of Kathmandu University for
their kind cooperation shown toward me.
ABSTRACT
Since the effects of an unreliable power system transmission can be widespread and affect
millions of people, as well as damage to life and equipment, therefore one of the most
important requirements of electric power system operation is to isolate and disconnect
faulted parts of the system selectively and quickly. This purpose can be achieved by
proper coordination of protective devices. One aim of the research was to make a general
guideline from which proper coordination of transmission system can be developed in
Bangladesh.
This thesis proposes a review of coordination of distance relays for transmission lines of a
real network that is selected for study. The equipment has been upgraded in the network
due to growing demand of power where in most cases it was not planned with protective
device coordination in mind. Another problem is single shoot auto reclosing is used in the
network where the both end breaker will not trip simultaneously if any fault occurs
beyond the zone 1 reach at either end. The report developed in this thesis takes into
account the effect of following issues: load flow, short circuit analysis, protection system
and coordination.
The present load flow and fault currents of the network were calculated by using Net Bas
program and from these results the proper ratings of the protective devices and conductor
are observed. The basic principle of zone settings (Zone1, Zone2 and Zone3) of distance
relays are followed for primary and back-up protection of transmission lines and
coordination curves were made from which proper selectivity between zones of back-up
protection are observed. It has found that some feeders have coordination problem (e.g.
1.1 Background and Motivation ........................................................................................ 1 1.2 Objectives of the Project.............................................................................................. 3 1.3 Scope of the Project ..................................................................................................... 3 1.4 Review of Coordination............................................................................................... 3 1.5 Research Method.......................................................................................................... 4
1.5.1 Data Collection ..................................................................................................... 4 1.5.2 Procedure and Outcome ........................................................................................ 4
1.6 Limitation..................................................................................................................... 4 1.7 Outline of the Thesis .................................................................................................... 5
PROBLEM DEFINITION ...................................................................................................6
2.1 Problem Definition....................................................................................................... 6 2.2 Information for Applying Protection ........................................................................... 7
DESCRIPTION OF NETWORK UNDER STUDY..........................................................8
3.5.1 Distance Relay, Current Transformer and Voltage Transformer........................ 11 3.5.3 Other Protective Relays ...................................................................................... 12
STUDY ASPECT ................................................................................................................13
4.1 Load Flow Studies ..................................................................................................... 13 4.2 Short Circuit Study .................................................................................................... 14 4.3 Coordination Study.................................................................................................... 14
4.3.1 Primary and Back-up Protection......................................................................... 15 4.3.2 System Impedance .............................................................................................. 16 4.3.3 Relay Response ................................................................................................... 17
4.4 Output Data ................................................................................................................ 17 RELAY CHARACTERISTICS.........................................................................................18
5.1 Introduction................................................................................................................ 18 5.2 Types of Distance Relay............................................................................................ 18
5.3 Effect of Arc Resistance ............................................................................................ 22 5.4 Power Swing .............................................................................................................. 22
5.4.1 Effect of Power Swings on the Performance of Distance Relays ....................... 23 5.5 Compensation for Correct Distance Measurement .................................................... 24
5.6 Carrier Aided Protection............................................................................................ 25 METHODOLOGY OF PROTECTION AND COORDINATION ................................26
6.1 Protection with Distance Relays ................................................................................ 26 6.1.1 Relationship between Primary and Secondary Impedances ............................... 26 6.1.2 Choice of Zone 1 Impedance Reach................................................................... 27 6.1.3 Choice of Zone 2 Impedance Reach................................................................... 27 6.1.4 Choice of Zone 3 Impedance Reach................................................................... 28 6.1.5 Choice of Zone 3 Reverse Impedance Reach: .................................................... 29 6.1.6 Choice of Relay Characteristic Angle................................................................. 29 6.1.7 Choice of Resistive Reach of Quadrilateral Characteristic ................................. 29 6.1.8 Co-ordination Criteria ......................................................................................... 29 6.1.9 Time Settings ...................................................................................................... 29 6.1.10 Zone-2 timer setting (TZ2) and Coordination.................................................... 30 6.1.11 Zone-3 Timer Setting (TZ3) and Coordination.................................................. 30 6.1.12 Summary of the Philosophy of Three-Stepped Distance Protection ................ 31 6.1.13 Ground Fault Compensation Setting................................................................. 31 6.1.14 Choice of Zone Setting for Ground Faults........................................................ 32 6.1.15 Mutual Compensation for Parallel Circuit ........................................................ 32 6.1.16 Calculations of Minimum Relay Voltage for a Fault at the Zone 1 Reach....... 32 6.1.17 Practical Applications for Phase and Earth Fault Connection.......................... 33
6.2 Maximum Source Impedance at Madunaghat and ..................................................... 33 Sikalbaha2 (for real case)................................................................................................. 33
DISCUSSION ON PROTECTION AND COORDINATION STUDY..........................34
7.1 Introduction................................................................................................................ 34 7.2 Discussion on Load flow and Short Circuit Analysis ................................................ 34 7.3 Discussion on Coordination Study............................................................................. 35
Single Line Diagram.................................................................................................... 56 A.6 Some important protection terminology ............................................................... 59
APPENDIX B ......................................................................................................................60
Short Circuit Analysis Results ..................................................................................... 60 APPENDIX C......................................................................................................................65
Power Flow Analysis Results ...................................................................................... 65 APPENDIX D......................................................................................................................67
D.1 Zone Setting Results ............................................................................................. 67 D.2 Calculation of Maximum Source Impedance at.................................................... 92 Madunaghat and Sikalbaha2 (for real case) ................................................................. 92
APPENDIX E ......................................................................................................................93
E.1ROUTINE TEST RECORD................................................................................... 93
i
LIST OF TABLES Table No. Caption Page 3.1 Maximum Load and Transformer Capacity 8 3.2 Conductor name and Line length of existing network 9 3.3 Impedance and current capacity of conductor 10 3.4 Relay type, CT ratio and P.T ratio of the existing network 11 3.5 Types and settings of other protective relay 12 5.1 Presence of sequence components 25 7.1 Zone and time setting of the network 35 7.2 Calculated positive sequence impedance for zone setting 37 7.3 Minimum relay voltage requirements for measurement of faults 48 7.4 The proposed time settings of distance relays
for existing network 49
ii
LIST OF FIGURES Figure No. Caption Page
4.1 Primary and back-up protection 15 5.1 MHO Impedance Characteristics 19 5.1.a MHO characteristic via a phase comparator 19 5.1.b MHO characteristic via a phase comparator 20 5.2 Offset MHO Characteristic 21 5.3 Three step quadrilateral characteristic 21 5.4 Effect of arc resistance on MHO relay 22 5.5 Effect of power surges on distance relays 23 6.1 Impedance measured by distance relay 26 7.1 Coordination curves of Madunaghat to Baraulia
and Kulshi section 38 7.2 Coordination curves of Madunaghat to Baraulia and Madunaghat – Sikalbaha2 section 39 7.3 Coordination curves of Madunaghat –Kulshi -Baraulia and Kulshi - Halishahar section 40 7.4 Coordination curves of Madunaghat-Sikalbaha,
Madunaghat –Kulshi-Baraulia and Halishahar section 40 7.5 Coordination curves of Madunaghat-Sikalbaha–Halishahar, Madunaghat–Kulshi section. 41 7.6 Coordination curves of Madunaghat - Sikalbaha - Halishahar and Kulshi – Halishahar – Sikalbaha2 section 42 7.7 Coordination curves of Hathazari - Baraulia - Kulshi section 43 7.8 Coordination curves of Kulshi –Baraulia and Madunaghat, and Halishahar-Kulshi section 44 7.9 Coordination curves of Madunaghat – Kulshi – Halishahar, Baraulia – Kulshi 1 and Sikalbaha2 – Halishahar section 46 7.10 Coordination curves of Sikalbaha2 – Madunaghat – Hathazari
and Kulshi 46 7.11 Coordination curves of Kulshi – Baraulia –
Hathazari – Madunaghat after time grading 47
iii
GLOSSARY OF ABBREVIATIONS
Abbreviation Full-Form First in page
BPDB Bangladesh Power Development Board 1 PGCB Power Grid Company of Bangladesh Limited 1 REB Rural Electrification Board 1 PSMP Power System Master Plan 1 EPZ Export Processing Zone 1 KV Kilo Volt 3 AAAC All Aluminium Alloy Conductor 6 MW Mega Watt 8 MVA Mega Volt Ampere 8 S/S Sub-Station 8 MCM Million Circular Mils 9 CB Circuit Breaker 10 O / km Ohm per Kilo Meter 10 0 C Degrees Centigrade 10 PTR Potential Transformer Ratio 12 CTR Current Transformer Ratio 11 C.T. Current Transformer 11 P.T./V.T. Potential/Voltage Transformer 11 O/C Over Current Relay 12 DEF Directional Earth Fault Relay 12 Tr Transformer 12 EHV Extra High Voltage 18 L-L Line to Line Fault 25 L-G Line to Ground Fault 25 L-L-G Double line to Ground Fault 25 L-L-L Three Phase Fault 25 PSB Power Swing Blocking 28 TZ Zone Time Setting 49 KA Kilo Ampere 58
1
Chapter 1 INTRODUCTION
1.1 Background and Motivation
Access to sustainable energy is identified as an important factor in alleviating poverty.
Major portion of the total population in Bangladesh do not have access to electricity. The
per capita electricity conjugation reflects the development of a country. At present only
20% of the population is served with electricity and per capita electricity consumption is
only 95 units (2000-2001). So, to provide reliable and quality electricity to the people is a
big challenge for our government.
From the beginning, Bangladesh Power Development Board (BPDB) was engaged with
Generation, Transmission and Distribution of electricity. Now there are other two
organizations named 1) Rural Electrification Board (REB) 2) Dhaka Electric Supply
Authority (DESA) are also involved to dis tribute the electricity. In 1996, Power Grid
Company of Bangladesh (An enterprise of BPDB) has formed to transmit the reliable and
quality bulk power through transmission line from one end to other end of the country.
With power demand growing rapidly (10% annually from 1974-1994; 7% annually from
2002-2003), Bangladesh's Power System Master Plan (PSMP) projects a required
doubling of electric generating capacity by 2010 and government committed to provide
affordable and reliable electricity to all citizens by 2020. In addition to, Chittagong is the
port city and a famous trade centre in Bangladesh. Most of the big industries and EPZ are
situated in the Chittagong city. In these circumstances, the uninterrupted power supply is
imperative for this city. Due to growing demand of power the load has been increased in
the grid system through distribution line. However, most electrical power transmission
and distribution systems are not planned with protective device coordination in mind. A
supply system can be designed for minimum losses and minimum upfront investment and
yet fail miserably in the proper coordination of the protective devices. As a result
equipment failures within the system can easily result in the shutdown of the entire plant
or substation. The objective of this collaborative project is to develop a maximum
protection of equipment, transmission lines and a consistence statistical framework for
2
evaluating year-to-year variation of transmission service quality and stability performance
indicators.
The power systems are usually large, complex and, in many ways, nonlinear systems. The
post-fault phenomena in a power system are dynamic in nature and dependent on the grid
connection and load flows in different parts of the grid. Thus the fault analysis and
protection coordination of a power system is a difficult task.
Transmission line protection has a central role in power system protection because
transmission lines are vital elements of a network which connects the generating plants to
the load centres. Since the consequence of power outage of a high voltage line is far more
serious than that of a distribution or sub transmission line, the protection of the bulk
power transmission line is generally more elaborate, with greater redundancy, and is also
more expensive [1]. The transmission system operators try to keep the security of the grid
at as high a level as possible. The resources for that are always limited. Most benefit from
the existing resources can be received if the decisions in investments, maintenance and
operation prove to be correct.
One of the most important requirements of electric power system operation is to isolate
and disconnect faulted parts of the system selectively and quickly. As a side benefit of a
coordination study the interrupting ratings of all protective equipment, conductors, and
switches are checked for adequacy. Inadequate equipment ratings can result in either
extensive damage to the equipment during faults and system operation and may introduce
hazards to plant operating personnel.
The main idea of the study is to obtain short circuit and load flow data for the existing
ring network sub-station and to acquire skill necessary for protective device coordination,
proposed the best protection and coordination through a case study. This report is about a
project conducted as part of the fulfilment of the requirements for the course in Master of
Electrical Power Engineering (MEPE) conducted by the department of School of
Engineering, Kathmandu University, Nepal and collaboration with Norwegian University
of Science and Technology, NTNU, Norway.
This project report is a small work out based on the requirement, the power system
analysis and protective device coordination for the safe and reliable power supply of the
3
Power Grid Company of Bangladesh Limited (PGCB), Bangladesh who are solely
responsible for transmission of electric power in Bangladesh at voltage levels 230 KV,
132 KV and 66 KV. In Bangladesh, the generating stations are located at different parts
of the country, which are interconnected by grid networks. In fact, this project work is not
sufficient to coordinate all protective devices for whole interconnected network. This
project deals with a portion of national grid networks which is supplying power in
Chittagong zone of Bangladesh.
1.2 Objectives of the Project
A sectionalizing study analyzes the impacts of short circuits and equipment failures
within a facility and determines the effects on the facility operation. Informed decisions
can then be made as to the changes necessary for the system. The main goal of this
project is to make general guidelines for protection coordination from which the
transmission protection system will be improved in Bangladesh.
The main objectives are fault calculation, recommendation for protection coordination
proposal, coordination of existing systems, coordination of proposed systems,
coordination curves, justification of protective devices proposed for line, tabulation of
fault analysis, tabulation of Coordination results and Analysis and recommendations.
1.3 Scope of the Project
The scope of the project involves with: Maximizes power system selectivity by isolating
faults to the nearest protective devices, Identification of maximum and minimum
momentary short-circuit current, Identification of ground fault current at major buses,
Identification of existing coordination problem of the system, Identification of optimum
coordination and protection of the system, Identification of proper ratings of the
protective devices.
1.4 Review of Coordination
In power system, small changes in loading conditions occur continually. The power
system must adjust to these changing conditions and continue to operate. Therefore,
4
sometimes it has to upgrade the equipment and system protective devices. A new or
revised coordina tion study should be made when the available short circuit current from
the power supply is increased, new large loads are added or existing equipment is
replaced with larger equipment, a fault shuts down a large part of the system and
protective devices are upgrade.
1.5 Research Method
1.5.1 Data Collection The initial phase included data collection of the network that is selected for a case study.
All data collected from PGCB Ltd. of Bangladesh.
1.5.2 Procedure and Outcome
The load flow study and short circuit analysis has carried out with the help of Net Bas
program. The coordination study and analysis has done manually. The coordination
curves were prepared by Microsoft Excel and illustrated adequate clearing times between
series devices. Zone 1, Zone 2 and Zone 3 are the computational methods for distance
relay used in this project. Manufacturer’s guidelines also followed for distance relay
settings.
The outcome of the project has tabulated and written in the form of report.
Recommendations were made for the best protection of the grid network in Bangladesh.
A general report provided to improve the protection system as well as to review of the
coordination of the system by implementing this information.
1.6 Limitation
1. Due to software constraint, the coordination study has done manually. Therefore,
the coordination curves were made by Microsoft Excel where the time in y axis is
given as a negative value to make the curve for both end relay of the protected
line. In practice it will be positive value. It is not possible to calculate the earth
fault current by using Net Bas program, that is why, existing earth fault current
5
were tabulated. In addition to, the phase fault current calculated by Net Bas are at
different busbar locations. It is not possible to calculate the fault current in
between of the protected line section. Therefore, artificial node has created
between the protected line sections to find out the fault current at a particular
distance which has given post- fault voltage zero at node point. In practice, this
post-fault voltage is not zero.
2. Due to time constraint and insufficient data (number of power interruptions,
duration of interruptions and affected consumer etc and data was not organized.),
the reliability analysis are skipped of the existing network. In addition to,
transformer protection is reviewed only for Kulshi grid sub-station due to same
cause, but the basic principle is same for transformer protection of another grid
sub-station. The network that is selected for case study is modified slightly for
insufficient data.
1.7 Outline of the Thesis
After the introduction, Chapter 2 describes the problem definition of the existing network
for which the sectionalizing study needs to be done. Chapter 3 presents the existing
network protection system and those details that are needed for this study. Some aspects
of the transmission system protection are presented in Chapter 4.
Chapter 5 describes the relay characteristics that are used in the existing network. Chapter
6 discusses about the methodology of the protection coordination where all factors are
included that is important for coordination. Based on this methodology the zone settings,
minimum relay voltage during the fault and compensation factor are calculated.
The discussion on load flow analysis, short circuit analysis and coordination is presented
in Chapter 7. In this Chapter the justifications of proposed settings are also described.
Conclusion and Recommendations are presented in Chapter 8.
6
Chapter 2 PROBLEM DEFINITION
2.1 Problem Definition
In Bangladesh, the national transmission grid voltage levels are 230KV, 132KV and 66
KV. The single line diagram of the network is shown in appendix (A), where all grid sub-
stations are at voltage levels 132 KV except Hathazari grid sub-station at voltage levels
230 KV and 132 KV. The transmission lines are overhead lines with Grosbeak and
AAAC conductors and are supported on steel tower. All power transformers and
equipment are out door type. Each of sub-station is contain with main and auxiliary bus
bar. The system mainly protected with distance relay, directional earth fault relay,
percentage differential relay, over current relay, circuit breakers, etc.
With such a network, the problem is how to maintain a safe, reliable and efficient energy
supply by ensuring that transmission line and equipment are well protected in the event of
fault. Protection system must recognize the existence of a fault and initiate circuit breaker
operation to disconnect faulted facilities of the system selectively and quickly. The
actions required assure minimum disruption of electrical services and limit damage in the
faulted equipment. This can only be achieved if the protective devices are well
coordinated. Although, the existing network was coordinated when it was installing but it
should be reviewed of coordination as causes described in chapter 1. [Ref. article 1.4]
The equipment has been upgraded in the network due to growing demand of power where
in most cases it was not planned with protective device coordination in mind. Therefore,
there is loss of selectivity between upstream and downstream protective devices.
Another problem is single shoot auto reclosing is used in the network where the both end
breaker will not trip simultaneously if any fault occurs beyond the zone 1 reach at either
end . Therefore, there is chance to jeopardize of the successful recloser of the existing
system which may reduce the power stability and may start generator from drifting apart
of the network. In this circumstance this study needs to be done for proper coordination.
7
2.2 Information for Applying Protection
One of the most difficult aspects of applying protection is often an accurate statement of
protection requirements or problem. The following checklist of information is required
for application of protection.
A single line diagram for applications documenting the system to be studied are
necessary, Appendix (A) showing the location of grid sub-stations, maximum load,
voltage and current level of the network. System grounding and arc fault resistance are
also necessary for studying ground fault protection. Impedance and connection of power
equipment, system frequency, voltage and currents are important for study that are
documented in chapter 3 and Appendix (A). Existing protection problems of the network
which is highlighted under chapter 2 and 7. Operating procedures and practices are
illustrated in chapter 5 and 6 for coordination study. System fault study is important for
power system protection applications. For phase fault protection, a three-phase fault study
is required while for ground fault protection, a single line to ground fault study is
required. System fault study is covered in chapter 7 and Appendix B. The required data
on system under study that are transformer ratings and impedance data, protective devices
ratings including momentary and interrupting duty as applicable, characteristics curves
for protective device, CT ratios, excitation curve and winding resistance, P.T ratios of the
system, conductor sizes and length and sequence impedance of the conductor and source.
These are documented in chapter 3.
The following information shall be included in the tabulation:
a. Bus identification.
b. Location identification.
c. Voltage
d. Manufacturer and type of equipment.
e. Device rating.
These are also documented in chapter 3 and Appendix A.
8
Chapter 3 DESCRIPTION OF NETWORK UNDER STUDY
3.1 Introduction
The transmission network that is selected for study of 132/33 KV grid sub-stations
protection in Chittagong zone of Bangladesh under Power grid company of Bangladesh
Limited (An enterprise of BPDB). This network is a mesh connected network which
consists with Madunaghat, Hathazari, Kulshi, Baraulia, Halishahar and Sikalbaha grid
sub-stations. This network is delivering power in Chittagong zone and national grid as
well. There are two generating power plants of total capacity 460 MW are feeding power
at Madunaghat and Sikalbaha sub-station.
The single line diagram of the network is shown in appendix (A).
3.2 Grid Sub-Station Description
The maximum load, transformer capacity, source information and load flow of each sub-
station are given below:
Table 3.1 Maximum Load and Transformer capacity.
Name of Grid S/S
Maximum Load, MW
Transformer Capacity, MVA
Source (From)
Remarks
Madunaghat 55 1 × 25/41.7 1 × 25/41
Generating Station
Hathazari 50 2 × 44.1/63 Madunaghat Supplying power to national Grid
Other protective relays are also used to protect the existing network properly. Some of
important relays are summarized in Table 3.6.
Table 3.5 Types and settings of other protective relays
Name of Grid S/S
Relay used Relay Setting
Madunaghat End
E/F relay (67G), GEC, USA. Auto reclosing relay (79R1) , NTJ-20, Japan Voltage relay, CV-5-D, Japan Synchronizing relay (same for all feeders)
Inst. 0.45s, P.S-1.0, D.S-0.2
P.S -120, D.S -10
Kulshi End E/F relay (67G), GEC, USA. Auto reclosing (79R1), NTJ-20, Japan Voltage relay, CV-5-D, Japan (For all feeders) Auto reclosing relay, PR5iq, BBC (for Kulshi - Madunaghat 1)
Inst. 0.45s, P.S-1.0, D.S-0.2
P.S -120, D.S -10
Inst. 0.15s, P.S-1.0, D.S-0.2
P.S -120, D.S -10 (E/F relay time setting for Kulshi –
Baraulia 2) Hathazari End
E/F relay (67G), GEC, USA. Auto reclosing (79R1) , NTJ-20, Japan Voltage relay, CV-5-D, Japan (For all feeders)
Inst. 0.45s, P.S-1.0, D.S-0.2
P.S -120, D.S -10
Baraulia End E/F relay (67G), GEC, USA. Auto reclosing (79R1) , NTJ-20, Japan Voltage relay, CV-5-D, Japan (For all feeders) Auto reclosing (79R1) , PR5iq, BBC (for Baraulia - Madunaghat 1)
Inst. 0.45s, P.S-1.0, D.S-0.2
P.S -120, D.S -10
Halishahar End
E/F relay (67G), GEC, USA. Auto reclosing (79R1) , NTJ-20, Japan Voltage relay, CV-5-D, Japan (For all feeders)
Inst. 0.45s, P.S-1.0, D.S-0.2
P.S -120, D.S -10
Sikalbaha2 End
E/F relay (67G), GEC, USA. Auto reclosing (79R1) , NTJ-20, Japan Voltage relay, CV-5-D, Japan (For all feeders)
Inst. 0.45s, P.S-1.0, D.S-0.2
P.S -120, D.S -10
Tr 1 (Primary)
O/C (51& 51G), Japan Differential relay (87), Japan
Inst. 0.3 s, P.S - 3.75, D.S -5 % =35
Tr 1 (Secondary)
O/C relay(51& 51G), Japan P.S - 5, D.S – 3.75
Tr 2 (Primary)
O/C relay (51& 51G), Japan Differential relay (87), Japan
Inst. 0.3 s, P.S - 3.75, D.S -5 % =35
Kulshi Grid
Tr 2 (Secondary)
O/C relay(51& 51G), Japan P.S - 5, D.S – 3.75
13
Chapter 4 STUDY ASPECT
4.1 Load Flow Studies
Load flow study is the determination of voltage, current, active and reactive power at
different locations of a network. By using a computer program, starting with system
operating under normal condition, the flow in all branches can be quickly computed for
compression with all other cases, present and future. Some changes that can be introduced
individually or in combination, to determine the effect on the system are: To take any line
or transformer out of service, Addition of new load to any branches or any buses,
Addition of new lines, Removal, adding or shifting of generation to any buses, Changes
of conductor size, Changes of transformer size and Upgrade of protective devices.
So, load flow studies are essential in planning the future expansion, best operation of the
system, and security of the system. In this project work, load flow analysis has been
carried out with the help of Net Bas program.
Load flow can have an adverse effect on relay performance, but most probably the
majority of applications are made and settings calculated where load flow is either
assumed to be zero or considered in a cursory manner. However, there are certain relays
and schemes where load flow must be comprehensively analyzed to permit a viable
application. In other cases load flow may be neglected and the relay system will perform
properly until a contingency situation arise that causes an incorrect relay operation
attributable to the effects of load flow.
An ideal distance relay sees an apparent impedance equal to the positive sequence
impedance from the relay location to the fault location. There are many factors that
conspire against a realization of such an ideal distance relay. Load flow coupled with
fault arc resistance / ground fault impedance can result in overreach for line-end faults
and incorrect directional action for close- in reverse faults [2].
14
4.2 Short Circuit Study
There are two types of short circuit studies of interest to the power engineer. The first
determines the first –cycle (momentary) and contact-parting (interrupting) short circuit
current duties (i.e. asymmetrical rms or peak currents) at the buses of the power system,
which are used to select the short circuit withstand and interrupting capabilities of
switchgear. The second type of study determines the subtransient and transient short
circuit currents that an overcurrent protective device will sense in order to initiate the
prompt removal of the affected portion of the power system by its circuit interrupter.
These short circuit currents are necessary to properly select the instantaneous and time
delay settings of the overcurrent protective scheme [3].
Although, virtually distance relay is independent of fault current, but fault current is
necessary for measuring the fault distance from the relaying point.
In this study, short circuit calculations that have been carried out with the help of Net Bas
program. But it is not possible to calculate the ground fault current by using the present
version of Net Bas program.
4.3 Coordination Study
The basic role of the protection scheme is to sense faults and isolate these faults by
opening all incoming current paths. However, the protection scheme must be selective so
that only faulted element is removed i.e. isolated. Therefore, a coordination study
maximizes power system selectivity by isolating faults to the nearest protective device, as
well as helping to avoid nuisance operations. One of the main topics of concern
protection engineers is the proper coordination behaviour of different relay units so as to
avoid relay mal-operation. Before arriving at proper relay coordination and relay settings,
several factors have to be taken into account and several consequences are to be
considered which are described in chapter 6. In fact, for proper coordination, it is better to
follow the relay manual guides which are provided by manufacturers.
15
4.3.1 Primary and Back-up Protection
A power system is divided into various zones for its protection. There is a suitable
protective scheme for each zone; it is the duty of the primary relays of that zone to isolate
the faulty element. The primary protection is the first line to defence. If the primary
protection fails to operate, there is a back-up protective scheme to clear the fault as a
second line to defence.
The causes of failures of primary protection could be due to failure of the CT/VT or relay,
or failure of the circuit breaker. The back-up protection should also preferably be located
at a place different from where the primary protection is located. Further, the back-up
protection must wait for the primary protection to operate, before using the trip command
to its associated circuit breakers. In other words, the operating time of the back-up
protection must be delayed by an appropriate amount over that of the primary protection.
Thus the operating time of the back-up protection should be equal to the operating time of
primary protection plus the operating time of the primary circuit breaker.
Consider the radial transmission system shown in figure in below. Relay B, provides
primary protection to the line section B-C. Relay A with circuit breaker CBA provides
back-up protection to the section B-C.
Consider a fault in section B-C as shown in figure. When a fault occurs, both the primary
relay RB and the back-up relay RA, start operating simultaneously. In case the primary
protection operates successfully, the line B-C gets de-energized but the loads on buses A
and B remain unaffected. Therefore, the back-up protection resets without issuing trip
Relay A operating time
C STI
CBB
TA
TB
Fault CBA
A Time
Figure 4.1 Primary and back-up protection
B
16
command. However, in case the primary protection fails to operate, the back-up relay
which is monitoring the fault, waits for the time in which the primary would have cleared
the fault and the issues the trip command to its allied circuit breakers.
Therefore, back-up relaying time > primary fault clearing time.
TA > TB + CBB (breaker operating time)
In general, there are three types of back-up relays.
a) Remote back-up
b) Relay back-up
c) Breaker back-up
Remote back-up:
When back-up relays are located at a neighbouring station, they backup the entire primary
protective scheme which includes the relay, circuit breaker, PT, CT and other elements, in
case of the primary protective scheme. It is the cheapest and simplest form of back-up
protection and is widely used back-up protection for transmission line.
Relay back-up:
This is kind of a local back-up in which an additional relay is provided for back-up
protection. It trips the same circuit breaker if the primary relay fails and this operation
takes place without delay. Though such a back-up is costly, it can be used where remote
back-up is not possible.
Breaker back-up:
This is also kind of a local back-up is necessary for a bus bar system where a number of
circuit breakers are connected to it. When a protective relay operates in response to a fault
but the circuit breaker fails to trip, the fault is treated as a bus bar fault. In such a
situation, it becomes necessary that all other circuit breakers on that bus bar should trip.
4.3.2 System Impedance The impedance of the power system may be divided into two parts. Firstly, the impedance
behind the relaying point, including the generators, feeders, transformers, etc., forms the
source impedance. The second part is the impedance to the fault in front of the relaying
point, which is governed by the geometrical arrangement, size, shape, spacing and
material of the conductors. Generally, this impedance data are provided by manufacturers.
Both of this impedance must be known to determine the faults levels and setting of the
relays.
17
4.3.3 Relay Response
To find the reaction of a relay to a system disturbance the voltages and currents at the
relaying point must be determined. This may be done practically, using a network
analyzer or theoretically. In this study, the fault currents and post-fault voltages at
different buses have been determined by Net Bas Program where minimum relay voltage
at the fault point calculated by hand calculation due to unavailable of software program.
4.4 Output Data
Results are calculated for each sub-stations relay and tabulated with appropriate station
names. The tables and appendix display the following:
1. Pre fault voltages, system nominal voltages are used in this study.
2. Minimum relay voltage
3. Total three phase bus fault current
4. Phase to phase fault currents.
5. Line current contribution for each bus fault for three phase faults.
6. Relay zone and time settings.
7. Short circuit results
8. Summary of load flow
9. Ground faults compensation factor.
18
Chapter 5 RELAY CHARACTERISTICS
5.1 Introduction
The reach and operating time of the over-current relay depend upon the magnitude of
fault current and the fault current at a particular location depends upon the type of fault
and the source impedance. Since neither the type of fault nor the source impedance is
predictable, the reach of the over current relay keeps on changing depending upon the
source conditions and the type of fault. Thus even though the relays are set with great
care, since their reach is subject to variations, they are likely to suffer from loss of
selectivity. Such a loss of selectivity can be tolerated to some extent in the low voltage
distribution system. However in high voltage or EHV interconnected system, loss of
selectivity can lead to danger to the stability of the power system, in addition to large
disruptions to loads. Therefore, over-current relay can not provide adequate protection in
high voltage systems. Distance relay is not bound by the same limitations as overcurrent
protection.
5.2 Types of Distance Relay
The most important and versatile family of relays is the distance relay group. It includes
the following major types-
1) Impedance relays
2) Reactance relays
3) MHO relays
4) Angle impedance relays
5) Quadrilateral relays etc.
The network that is selected for a case study of 132/33 KV grid sub-stations, where
MHO and Quadrilateral types of distance relays are being used as a primary and back-up
protection of transmission lines and busbars. Therefore, the characteristics of MHO relay
and Quadrilateral relay are discussed only in this study. Besides that, E/F over current
relay and Differential relay characteristics are also included in brief.
19
5.2.1 MHO Characteristic
The MHO characteristic, as seen on the impedance polar diagram, is a circle whose
diameter is the relay impedance setting vector, such that the characteristic passes through
the origin of the impedance diagram, as shown in Figure 5.1. The MHO relay is therefore
directional.
The MHO characteristic is commonly generated via a phase comparator which compares
the phase of S1 and S2 as illustrated in Figure 5.1.a.
Voltage to Relay = V
Current to Relay = I
Replica Impedance = Zr
Trip condition: ∠ S1 – S2 = θ < 900
Where, S2 = IZr - V
S1 = V
R
JX
Figure 5.1 MHO Impedance Characteristics
T1
T2
T3
S1
V3
IZr
IR
JIX
S2 Trip
V1 Stable
Figure 5.1.a MHO characteristic via a phase comparator
P
θ
20
If the point P lies within the circle, the phase angle between S1 and S2 is less than 900
(900 > ∠ S1 – S2). If P lies outside the circle, the phase angle is greater than 900 (900 < ∠
S1 – S2).
If we divide all vectors in above figure by I, the resulting vector diagram will be as shown
in Figure 5.1.b
V = IZ
S2 ∝ IZr – V ∝ Zr - Z
S1 ∝ V ∝ Z.
Angle between (Zr – Z3) and Z3 < 900 or > - 900 Trip
Angle between (Zr – Z1) and Z1 > 900 or < - 900 Restrain
MHO characteristic relays are very popular due to their simplicity. Compared with
directionalised impedance characteristic distance relay, a MHO characteristic relay is less
sensitive to operation due to power swing and load encroachment but it has lower
resistive coverage in the impedance plane.
5.2.2 Offset MHO characteristic
Where it is required that a distance relay element has some ability to see faults on the
busbar behind the relaying point, to provide local back-up protection for uncleared busbar
faults or to allow tripping for 3-phase faults close to the relaying point during line
energisation, then offset MHO characteristic is commonly used for distance relay Zone 3
elements.
R
JX
S1
S2 Trip
Zr
Z3
Z1 Stable
Figure 5.1.b MHO characteristic via a phase comparator
θ
21
An offset MHO characteristic can be produced via phase comparator as depicted in
Figure 5.2. With an offset MHO characteristic, the forward and reverse reach can be set
independently.
Trip Condition, ∠ S1 – S2 = θ < 900 .
5.2.3 Quadrilateral Characteristic
A quadrilateral relay is suitable for long as well as short lines. This relay characteristics
would allow the ground fault resistive reach to be increased or decreased independently
of the forward reach and source impedance behind relay so that the required ground fault
resistive coverage can be achieved.
Figure 5.2 Offset MHO Characteristic
S1
S2 R
X
Z
-Z
R
X
Zone 1
Zone 2
Zone 3
Figure 5.3 Three step quadrilateral characteristic
22
5.3 Effect of Arc Resistance
If a flashover from phase to phase or phase to ground occurs, an arc resistance is
introduced into the fault path which is appreciable at higher voltages. The arc resistance is
added to the impedance of the line and hence, the resultant impedance which is seen by
distance relays is increased. In case of ground faults, the earth resistance is also
introduced into the fault path.
The arc resistance is treated as pure resistance in series with the line impedance, where
reactive component is negligible.
Figure 5.4 shows the effect of arc resistance on a MHO relay. The characteristics angle of
the relay is the same as the characteristic angle f of the line. For a fault at the point F, the
actual line impedance up to fault is Zf but the impedance measure the by the relay is (Zf +
R). That is why, this shows that arc resistance causes underreach and relay fails to
operate.
5.4 Power Swing
In an interconnected power system, under steady state condition, all the generators run in
synchronism. There is a balance between the load and generation. This state is
characterized by constant rotor angles. However, when there is a disturbance in the
system, say, shedding of a large chunk of load, changes in direction of power flow or
sudden removal of faults, the system has to adjust to the new operating conditions. In
X
Figure 5.4 Effect of arc resistance on MHO relay
ZF+R
F R
Zl
R
Zf + R
F
f
Zf
23
order to balance the generation with the load, the rotors need to take on new angular
positions. Because of the inertia of the rotating system and their dynamics, the rotors
slowly reach their new angular positions in an oscillatory manner and which occurs, in a
rather slow oscillatory manner, subsequent to some large disturbance is known as power
swing. During rotor swings, the rotor angle changes and the current flowing through the
line also changes which currents are heavy.
5.4.1 Effect of Power Swings on the Performance of Distance Relays
During power swings, the current ‘seen’ by the relay is also changing. Therefore, the
impedance measured by the relay also varies on that period. Thus, a power surge ‘seen’
by the relay appears like a fault which is changing its distance from the relay location. In
the case of a transient power swing it is obviously important that the distance relay should
not trip.
The characteristic of some important distance relay and power surge are shown on the R-
X diagram, Figure 5.5. It is evident from the figure that the relay characteristic occupying
greater area on the R-X diagram remains under the influence of the power surge for a
greater period and hence, it is more affected by power surges.
Figure 5.5 Effect of power surges on distance relays
MHO Relay
Reactance Relay
R
Power Surges
Impedance Relay
X
24
The MHO relay having the least area on the R-X diagram is least affected. The
impedance relay characteristic has more area than the MHO relay but lesser area than a
reactance relay.
5.5 Compensation for Correct Distance Measurement
Although the same relays are employed for both phase to phase and three phase faults,
they do not measure the same impedance between the fault point and the relay location
for each type of fault unless proper compensation provided. If a distance relay is
energized by line to line voltage and line current, the impedance seen by the relay will be
2Z1 for a phase to phase fault and v3Z1∠300 for a three phase fault. If the relay is fed with
phase voltage and phase current, the impedance seen is (Z1 + Z2 + Z3)/3 for a line to
ground fault. But it depends on the number of sources and the number of earthed neutral
available at the time. To measure the same impedance for phase to phase and three phase
faults, the measuring unit is energized by line to line voltage and the difference between
the currents in the corresponding two phases as given below:
Relay Voltage Current
a-b phase pair Vab Ia – Ib
b-c phase pair Vbc Ib – Ic
c-a phase pair Vca Ic – Ia.
For phase faults to ground faults, the measuring units are energized by phase to neutral
voltage and corresponding phase current, plus a fraction of the residual current.
Relay Voltage Current
a - Phase Va Ia + 1/3 (K-1)Ires
b - Phase Vb Ib + 1/3 (K-1)Ires
c - Phase Vc Ic + 1/3 (K-1)Ires
Where = Z0/Z1 and Ires = Ia + Ib + Ic = 3I0.
The following table shows presence of sequence components in various faults
25
Table 5.1 presence of sequence components
Fault Positive sequence Negative sequence Zero sequence
L-G Yes Yes Yes
L-L Yes Yes No
L-L-G Yes Yes Yes
L-L-L Yes No No
From the above table it can be seen that positive sequence component is the only
component which is present during all faults.
5.6 Carrier Aided Protection
The carrier current protection capable of providing high speed protection for the whole
length as well as it initiates circuit breakers to trip simultaneously at both ends. In a
carrier scheme, the carrier signal can be used to prevent the operation of the relay which
is called carrier blocking scheme. When the carrier signal is employed to initiate tripping,
the scheme is called a carrier inter tripping or transfer tripping scheme.
There are two important operating techniques employed for carrier current protection
namely the phase comparison technique and directional comparison technique.
26
Chapter 6 METHODOLOGY OF PROTECTION AND COORDINATION
6.1 Protection with Distance Relays
The conventional distance relay uses three distance measuring units. The protected zone
of the first unit is called the first zone of protection. It is high speed unit and is used for
the primary protection of the protected line. Its operation is instantaneous, about 1 to 2
cycles. The protected zone of second unit is called the second zone of protection. The
setting of the second unit is so adjusted that it operates the relay even for arching faults at
the end of the line. The third zone of protection is provided for full back-up protection of
the adjoining line.
6.1.1 Relationship between Primary and Secondary Impedances
Relays are calibrated in secondary ohms of the sequence impedance of the line.
Figure 6.1 Impedance measured by distance relay
ZR = R
R
VI
=
2FP
1
2FP
1
VV ×
VI
I ×I
= FP
FP
VI
×
1
2
1
2
IIVV
= Zp × C.T.ratioV.T.ratio
= ZS
IR
VR
I1/I2
V1/V2
Zp
27
Where, ZR is the relay impedance, VFP is the fault voltage at the fault point, IFP is the fault
current at the fault point, Zp is the positive sequence impedance of the line and ZS is the
secondary positive sequence impedance of the line.
Relay calibration, characteristics and setting calculations are in terms of secondary
impedance.
6.1.2 Choice of Zone 1 Impedance Reach
Although in most applications the reach accuracy of the relay distance comparators is ±
5%, greater errors can occur as a result of voltage and current transformer errors and
inaccuracies in line data from which the relay settings are calculated. To prevent the
possibility of relays tripping instantaneously for faults in the next line, it is usual to set the
zone 1 reach of the relay to 80% - 90% of the protected line section and relay on zone 2 to
cover the remaining 20% of the line. With a signal aided distance protection scheme
arrangement, the zone 2 distance comparators could provide fast tripping at both ends of
the line for end-zone faults. If the zone 1 extension scheme is used, it is usual practice to
set the zone 1 extension to 150% of the normal zone 1 reach.
6.1.3 Choice of Zone 2 Impedance Reach
The principle purpose of the second zone unit of a distance relay is to provide protection
(able to cover bus faults also) for the rest of the line beyond the reach of the first zone
unit. As a general rule, the Zone 2 impedance reach is set to cover the protected line plus
50% of the shortest adjacent line. The reasoning behind the value of 50% is that Zone 2
should cover at lest 20% of the adjacent line, even in the presence of typical additional
infeed at the remote terminal of the protected line. One case of additional infeed at the
remote line terminal occurs when the protected line is paralleled by another line. When a
fault occurs in the adjacent line, approximately equal currents will flow in each of the
parallel lines. The relay on the protected line looking towards the fault will see impedance
which will be the sum of the protected line impedance plus twice the impedance of the
adjacent line to the fault. If the Zone 2 reach is set to cover 50% of the adjacent line
impedance, then in this parallel infeed case, Zone2 will effectively cover 25% of the
adjacent line.
28
In most situations, if the relay reaches at lest 20% into the adjacent line, then faults at the
remote terminal of the protected line will be well within Zone 2 reach and so fast
operation of the Zone 2 comparators will be achieved. This is important if signal aided
tripping schemes are used.
In some situations where the protected line is long and the adjacent line is short, then a
50% reach into the adjacent line will only be a very small overreach of the protected line.
If the protected line is paralleled by another line, then it may be that the zero sequence
mutual coupling between the two lines will be sufficient to prevent the zone 2
comparators from seeing a ground fault at the remote terminal of the line until the remote
circuit breaker trips, preventing ground fault current flowing in the healthy parallel
circuit. In such a case the Zone 2 setting may need to be increased slightly to avoid
sequential or time delayed clearance of the fault at the terminal remote from the fault.
In a parallel line situation, a fault on one line which is cleared sequentially can cause a
fault current reversal in the healthy line. If the Zone 2 settings are greater than 150% of
the protected line impedance and the Permissive Overreach or blocking scheme is being
used, then a fault current reversal in the healthy circuit could cause that circuit to be
incorrectly tripped unless special steps are taken. The Permissive Overreach and Blocking
schemes both have current reversal guards incorporated to prevent such mal-operations.
6.1.4 Choice of Zone 3 Impedance Reach
The Zone 3 forward reach should normally be set to cover the protected line section, plus
the longest adjacent section, plus 25% of a third section, to provide an overall time
delayed back-up protection (able to cover bus faults also at the bus between the two
lines). The reverse Zone 3 offset provides back-up protection for the bus bars behind the
relay and would typically be set to 25% of the Zone 1 setting. The forward Zone 3 reach
should be set to minimum unless the Power Swing Blocking facility (PSB) is also being
used [4].
The choice of zone impedance reach is summarized in a Table below.
29
6.1.5 Choice of Zone 3 Reverse Impedance Reach:
The principle purpose of the zone 3 reverse setting is to provide protection on the busbar
behind the relaying point. The zone 3 reverse reach should normally be set to cover 20% -
25% of the protected line behind the relay.
6.1.6 Choice of Relay Characteristic Angle
Maximum accuracy and sensitivity is obtained by setting the relay angle θPH equal to or to
the nearest setting above the line positive sequence angle ∠Z1, and θN equal to or to the
nearest value above ∠KNZ1 where KN is the neutral compensation factor.
6.1.7 Choice of Resistive Reach of Quadrilateral Characteristic
The resistive reach should be set (if necessary) to cover the desired level of ground fault
resistance, which would comprise arc resistance and tower footing resistance. In addition
to ensure Zone 1 reach accuracy the resistive reach should not be set greater than 15 times
the Zone 1 ground loop reach.
6.1.8 Co-ordination Criteria
Three broad categories for coordination criteria are defined as follows,
Desired design criteria: These are the existing criteria which will result in desired
operation of the relay system.
Minimum Criteria: These are the criteria adopted when the desired criteria can not be
achieved. This is achieved through back-up relay operating time being relaxed i.e. allow
back-up relay not to operate for some low fault currents.
Enhanced criteria: These are the criteria designed to produce optimum results. It might
include consideration of additional fault at mid-line for the purpose of relay coordination.
6.1.9 Time Settings
A fully coordinated result for distance relays should indicate the impedance setting values
for all the three zones in terms of various impedance taps available on the relays and also
the timer setting associated with second and third zone relays. The definite-distance
30
method of time grading are used of the existing network which has the advantage of high
speed fault clearance compared to distance/time method.
In ideal situation Zone time coordination is given below:
BARAULIA 129.282 11.934 1.344 HALISHAHAR 129.438 13.146 1.591 ---------------------------------------------------------------------------------------------------- Sum 11.451 B.3 Contribution of fault current during fault at Madunaghat Grid:
----------------------------------------------------------------------------------------------- Sum 10.492 B.7 Contribution of fault current during fault at Halishahar Grid:
Total electrical losses : 4.263 9.926 0.000 (No-load losses)
Max. voltage drop : 33 KV BUS : 4.39 %
Heaviest loaded line : KULSHI - MADUNAGHAT : 49.51 %
Heaviest loaded T2 : KULSHI - 33 KV BUS : 89.51 %
67
APPENDIX D
D.1 Zone Setting Results
Madunaghat - Sikalbaha2, Circuit 1
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.341 76.1 2 The relay coarse reach: Zph 0.32 80 3 required Zone 1 multiplier setting: 1.067 4 Actual Zone 1
Setting 0.339 80
Selecting Zone 2 Setting 1 Required zone 2 reach : Secondary 0.598 2 required Zone 2 multiplier setting: 1.867 3 Actual zone 2
setting: 0.576 80
Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 0.854 (forward) 2 required Zone 3 multiplier setting: 2.669 3 Actual zone 3
forward setting: 0.864 80
4 Required zone 3 reach: Secondary 0.085 (reverse) 5 required Zone 3 multiplier setting: 0.265 6 Actual zone 3
reverse setting: 0.08 80
68
Madunaghat - Sikalbaha2, Circuit 2
For phase to Phase Faults
Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.341 76.1 2 The relay coarse reach: Zph 0.32 80 3 required Zone 1 multiplier setting: 1.067 4 Actual Zone 1
Setting 0.339 80
Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 0.598 2 required Zone 2 multiplier setting: 1.867 3 Actual zone 2
setting: 0.576 80
Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 0.854 (forward) 2 required Zone 3 multiplier setting: 2.669 3 Actual zone 3
forward se tting: 0.864 80
4 Required zone 3 reach: Secondary 0.085 (reverse) 5 required Zone 3 multiplier setting: 0.265 6 Actual zone 3
reverse setting: 0.08 80
69
Madunaghat – Hathazari, Circuit 1
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: 0.382 69.5 2 The relay coarse reach: Zph 0.36 70 3 required Zone 1 multiplier setting: 1.060 4 Actual Zone 1
Setting 0.374 70
Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 0.795 2 required Zone 2 multiplier setting: 2.208 3 Actual zone 2
setting: 0.792 70
Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 1.272 (forward) 2 required Zone 3 multiplier setting: 3.533 3 Actual zone 3
forward setting: 1.260 70
4 Required zone 3 reach: Secondary 0.094 (reverse) 5 required Zone 3 multiplier setting: 0.260
6 Actual zone 3
reverse setting: 0.09 70
70
Madunaghat – Hathazari, Circuit 2
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: 0.382 69.5 2 The relay coarse reach: Zph 0.36 70 3 required Zone 1 multiplier setting: 1.060 4 Actual Zone 1
Setting 0.374 70
Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 0.795 2 required Zone 2 multiplier setting: 2.208 3 Actual zone 2
setting: 0.792 70
Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 1.272 (forward) 2 required Zone 3 multiplier setting: 3.533 3 Actual zone 3
forward setting: 1.260 70
4 Required zone 3 reach: Secondary 0.094 (reverse) 5 required Zone 3 multiplier setting: 0.260
6 Actual zone 3
reverse setting: 0.09 70
71
Madunaghat – Kulshi, Circuit 1
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.269 76.1 2 The relay coarse reach: Zph 0.24 80 3 required Zone 1 multiplier setting: 1.122 4 Actual Zone 1
Setting 0.269 80
Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 0.507 2 required Zone 2 multiplier setting: 2.114 3 Actual zone 2
setting: 0.504 80
Selecting Zone 3 Setting 1 Required zone 3 reach:Secondary 0.764 (forward) 2 required Zone 3 multiplier setting: 3.183 3 Actual zone 3
forward setting: 0.768 80
4 Required zone 3 reach:Secondary 0.067 (reverse) 5 required Zone 3 multiplier setting: 0.280 6 Actual zone 3
reverse setting: 0.06 80
72
Madunaghat – Kulshi, Circuit 2
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: 0.538 76.1 2 The relay coarse reach: Zph 0.52 80 3 required Zone 1 multiplier setting: 1.036 4 Actual Zone 1
Setting 0.530 80
Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 1.015 2 required Zone 2 multiplier setting: 1.952 3 Actual zone 2
setting: 0.988 80
Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 1.528 (forward) 2 required Zone 3 multiplier setting: 2.938 3 Actual zone 3
forward setting: 1.508 80
4 Required zone 3 reach: Secondary 0.133 (reverse) 5 required Zone 3 multiplier setting: 0.255 6 Actual zone 3
reverse setting: 0.13 80
73
Hathazari - Baraulia, Circuit 1
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 1.908 75.2 2 The relay coarse reach: Zph 1.8 75 3 required Zone 1 multiplier setting: 1.060 4 Actual Zone 1
Setting 1.872 75
Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 3.667 2 required Zone 2 multiplier setting: 2.037 3 Actual zone 2
setting: 3.600 75
Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 5.590 (forward) 2 required Zone 3 multiplier setting: 3.105 3 Actual zone 3
forward setting: 5.580 75
4 Required zone 3 reach: Secondary 0.468 (reverse) 5 required Zone 3 multiplier setting: 0.260 6 Actual zone 3
reverse setting: 0.45 75
74
Hathazari - Baraulia, Circuit 2
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 1.908 75.2 2 The relay coarse reach: Zph 1.8 75 3 required Zone 1 multiplier setting: 1.060 4 Actual Zone 1
Setting 1.872 75
Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 3.667 2 required Zone 2 multiplier setting: 2.037 3 Actual zone 2
setting: 3.600 75
Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 5.590 (forward) 2 required Zone 3 multiplier setting: 3.105 3 Actual zone 3
forward setting: 5.580 75
4 Required zone 3 reach: Secondary 0.468 (reverse) 5 required Zone 3 multiplier setting: 0.260 6 Actual zone 3
reverse setting: 0.45 75
75
Hathazari - Madunaghat, Circuit 1
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 1.431 69.5 2 The relay coarse reach: Zph 1.4 70 3 required Zone 1 multiplier setting: 1.022 4 Actual Zone 1
Setting 1.428 70
Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 3.051 2 required Zone 2 multiplier setting: 2.179 3 Actual zone 2
setting: 3.080 70
Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 4.944 (forward) 2 required Zone 3 multiplier setting: 3.531 3 Actual zone 3
forward setting: 5.040 70
4 Required zone 3 reach: Secondary 0.357 (reverse) 5 required Zone 3 multiplier setting: 0.255 6 Actual zone 3
reverse setting: 0.35 70
76
Hathazari - Madunaghat, Circuit 2
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 1.431 69.5 2 The relay coarse reach: Zph 1.4 70 3 required Zone 1 multiplier setting: 1.022 4 Actual Zone 1
Setting 1.428 70
Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 3.051 2 required Zone 2 multiplier setting: 2.179 3 Actual zone 2
setting: 3.080 70
Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 4.944 (forward) 2 required Zone 3 multiplier setting: 3.531 3 Actual zone 3
forward setting: 5.040 70
4 Required zone 3 reach: Secondary 0.357 (reverse) 5 required Zone 3 multiplier setting: 0.255 6 Actual zone 3
reverse setting: 0.35 70
77
Baraulia - Hathazari, Circuit 1
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.509 75.2 2 The relay coarse reach: Zph 0.48 75 3 required Zone 1 multiplier setting: 1.060 4 Actual Zone 1
Setting 0.499 75
Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 0.875 2 required Zone 2 multiplier setting: 1.822 3 Actual zone 2
setting: 0.816 75
Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 1.232 (forward) 2 required Zone 3 multiplier setting: 2.567 3 Actual zone 3
forward setting: 1.200 75
4 Required zone 3 reach: Secondary 0.125 (reverse) 5 required Zone 3 multiplier setting: 0.260 6 Actual zone 3
reverse setting: 0.12 75
78
Baraulia - Hathazari, Circuit 2
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.509 75.2 2 The relay coarse reach: Zph 0.48 75 3 required Zone 1 multiplier setting: 1.060 4 Actual Zone 1
Setting 0.499 75
Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 0.875 2 required Zone 2 multiplier setting: 1.822 3 Actual zone 2
setting: 0.816 75
Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 1.232 (forward) 2 required Zone 3 multiplier setting: 2.567 3 Actual zone 3
forward setting: 1.200 75
4 Required zone 3 reach: Secondary 0.125 (reverse) 5 required Zone 3 multiplier setting: 0.260 6 Actual zone 3
reverse setting: 0.12 75
79
Baraulia - Kulshi, Circuit 2
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.547 75.3 2 The relay coarse reach: Zph 0.52 75 3 required Zone 1 multiplier setting: 1.052 4 Actual Zone 1
Setting 0.541 75
Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 1.020 2 required Zone 2 multiplier setting: 1.962 3 Actual zone 2
setting: 1.040 75
Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 1.525 (forward) 2 required Zone 3 multiplier setting: 2.933 3 Actual zone 3
forward setting: 1.508 75
4 Required zone 3 reach: Secondary 0.135 (reverse) 5 required Zone 3 multiplier setting: 0.260 6 Actual zone 3
reverse setting: 0.13 75
80
Kulshi - Baraulia, Circuit 2
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.547 75.3 2 The relay coarse reach: Zph 0.52 75 3 required Zone 1 multiplier setting: 1.052 4 Actual Zone 1
Setting 0.541 75
Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 1.002 2 required Zone 2 multiplier setting: 1.926 3 Actual zone 2
setting: 0.988 75
Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 1.479 (forward) 2 required Zone 3 multiplier setting: 2.844 3 Actual zone 3
forward setting: 1.508 75
4 Required zone 3 reach: Secondary 0.135 (reverse) 5 required Zone 3 multiplier setting: 0.260 6 Actual zone 3
reverse setting: 0.13 75
81
Sikalbaha2 - Halishahar, Circuit
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.596 82.4 2 The relay coarse reach: Zph 0.6 85 3 required Zone 1 multiplier setting: 0.993 4 Actual Zone 1
Setting 0.600 85
Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 1.041 2 required Zone 2 multiplier setting: 1.736 3 Actual zone 2
setting: 1.020 85
Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 1.578 (forward) 2 required Zone 3 multiplier setting: 2.630 3 Actual zone 3
forward setting: 1.620 85
4 Required zone 3 reach: Secondary 0.150 (reverse) 5 required Zone 3 multiplier setting: 0.250 6 Actual zone 3
reverse setting: 0.15 85
82
Halishahar - Sikalbaha2
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.596 82.9 2 The relay coarse reach: Zph 0.56 85 3 required Zone 1 multiplier setting: 1.064 4 Actual Zone 1
Setting 0.594 85
Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 1.110 2 required Zone 2 multiplier setting: 1.983 3 Actual zone 2
setting: 1.176 85
Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 1.750 (forward) 2 required Zone 3 multiplier setting: 3.126 3 Actual zone 3
forward setting: 1.792 85
4 Required zone 3 reach: Secondary 0.148 (reverse) 5 required Zone 3 multiplier setting: 0.265 6 Actual zone 3
reverse setting: 0.14 85
83
Kulshi - Madunaghat, Circuit 1
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.27 76.1 2 Actual Zone 1
Setting: Z1PH 0.27 76 Selecting Zone 2 Setting
1 Required zone 2 reach: Secondary 0.456 3 Actual zone 2
setting: Z2PH 0.456 76 Selecting Zone 3 Setting
1 Required zone 3 reach: Secondary 0.85 (forward)
3 Actual zone 3
forward setting: 0.85 76
Kulshi - Madunaghat, Circuit 2
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.538 76.1 2 Actual Zone 1
Setting: Z1PH 0.538 76 Selecting Zone 2 Setting
1 Required zone 2 reach: Secondary 0.91 3 Actual zone 2
setting: Z2PH 0.91 76 Selecting Zone 3 Setting
1 Required zone 3 reach: Secondary 1.69 (forward) 3 Actual zone 3
forward setting: 1.69 76
84
Kulshi – Halishahar
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.608 76.3 2 Actual Zone 1
Setting: Z1PH 0.57 76 Selecting Zone 2 Setting
1 Required zone 2 reach: Secondary 1.037 3 Actual zone 2
setting: Z2PH 1.08 76 Selecting Zone 3 Setting
1 Required zone 3 reach: Secondary 1.679 (forward) 3 Actual zone 3
forward setting: 1.64 76
Halishahar – Kulshi
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.608 76.3 2 Actual Zone 1
Setting: Z1PH 0.572 76 Selecting Zone 2 Setting
1 Required zone 2 reach: Secondary 1.03 3 Actual zone 2
setting: Z2PH 1.052 76 Selecting Zone 3 Setting
1 Required zone 3 reach: Secondary 1.67 (forward) 3 Actual zone 3
forward setting: 1.55 76
85
Kulshi - Baraulia, Circuit 1
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.547 75.3 2 Actual Zone 1
Setting: Z1PH 0.547 75 Selecting Zone 2 Setting
1 Required zone 2 reach: Secondary 1.0 3 Actual zone 2
setting: Z2PH 1.0 75 Selecting Zone 3 Setting
1 Required zone 3 reach: Secondary 1.48 (forward) 3 Actual zone 3
forward setting: 1.48 75
Baraulia - Kulshi, Circuit 1
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.547 75.3 2 Actual Zone 1
Setting: Z1PH 0.547 75 Selecting Zone 2 Setting
1 Required zone 2 reach: Secondary 1.02 3 Actual zone 2
setting: Z2PH 1.02 75 Selecting Zone 3 Setting
1 Required zone 3 reach: Secondary 1.58 (forward) 3 Actual zone 3
forward setting: 1.58 75
86
Sikalbaha2 - Madunaghat, Circuit1
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.341 75.5 2 The relay coarse reach: Zph 0.32 80 3 required Zone 1 multiplier setting: 1.067 4 Actual Zone 1
Setting 0.339 80
Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 0.546 2 required Zone 2 multiplier setting: 1.706 3 Actual zone 2
setting: 0.544 80
Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 0.725 (forward) 2 required Zone 3 multiplier setting: 2.265 3 Actual zone 3
forward setting: 0.736 80
4 Required zone 3 reach: Secondary 0.085 (reverse) 5 required Zone 3 multiplier setting: 0.265 6 Actual zone 3
reverse setting: 0.08 80
87
Sikalbaha2 - Madunaghat, Circuit2
For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.341 75.5 2 The relay coarse reach: Zph 0.32 80 3 required Zone 1 multiplier setting: 1.067 4 Actual Zone 1
Setting 0.339 80
Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 0.546 2 required Zone 2 multiplier setting: 1.706 3 Actual zone 2
setting: 0.544 80
Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 0.725 (forward) 2 required Zone 3 multiplier setting: 2.265 3 Actual zone 3
forward setting: 0.736 80
4 Required zone 3 reach: Secondary 0.085 (reverse) 5 required Zone 3 multiplier setting: 0.265 6 Actual zone 3