SECTIONALIZING STUDY OF 13233 KV GRID SUB Station

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 coordinatio n 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. Kulshi – Baraulia 1 feeder, Baraulia – Kulshi 1 feeder, Sikalbaha2 – Madunaghat feeder) with zones of back-up protection on adjacent feeder which may cause mal-operation during the fault. After reviewing of coordination, the proposed zone and time settings were tabulated for this network. The justifications of the proposed settings were discussed and it is recommended to implement the proposed settings in this network. The pilot relaying schemes are proposed to get high speed relaying which are imperative for transmission line considering a bulk power supply rather than cost. The pilot relaying schemes are also need for successful auto reclosing during transient faults. On the basis of the results, some recommendations for improving the transmission grid stability in terms of coordination analysis were made. TABLE OF CONTENTS LIST OF TABLES .................................................................................................................i LIST OF FIGURES ..............................................................................................................ii GLOSSARY OF ABBREVIATIONS ................................................................................iii INTRODUCTION.................................................................................................................1 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 3.1 Introduction.................................................................................................................. 8 3.2 Grid Sub-Station Description....................................................................................... 8 3.3 Transmission Line and Conductor Information........................................................... 9 3.4 Conductor Impedance ................................................................................................ 10 3.5 Protective Devices...................................................................................................... 10 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 5.2.1 MHO Characteristic ............................................................................................ 19 5.2.2 Offset MHO characteristic .................................................................................. 20 5.2.3 Quadrilateral Characteristic ................................................................................ 21 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 7.3.1 Existing Relay Setting......................................................................................... 36 7.3.2 Calculated/Proposed Impedance Value for Zone Setting ................................... 37 7.3.3 Madunaghat – Hathazari Feeders........................................................................ 38 7.3.4 Madunaghat – Kulshi 1 Feeder ........................................................................... 38 7.3.5 Madunaghat – Kulshi 2 Feeder ........................................................................... 39 7.3.6 Hathazari – Madunaghat Feeders........................................................................ 39 7.3.7 Madunaghat – Sikalbaha2 Feeders ..................................................................... 41 7.3.8 Baraulia - Hathazari Feeders............................................................................... 41 7.3.9 Hathazari - Baraulia Feeders............................................................................... 42 7.3.10 Kulshi – Madunaghat 1 Feeder ......................................................................... 43 7.3.11 Kulshi – Madunaghat 2 Feeder ......................................................................... 43 7.3.12 Halishahar – Sikalbaha2 Feeder........................................................................ 44 7.3.13 Kulshi – Baraulia 1 Feeder ............................................................................... 44 7.3.14 Kulshi – Baraulia 2 Feeder ............................................................................... 44 7.3.15 Kulshi – Halishahar Feeder............................................................................... 45 7.3.16 Baraulia – Kulshi 1 Feeder ............................................................................... 45 7.3.17 Halishahar – Kulshi Feeder............................................................................... 45 7.3.18 Baraulia – Kulshi 2 Feeder ............................................................................... 46 7.3.19 Sikalbaha2 – Halishahar Feeder........................................................................ 46 7.3.20 Sikalbaha2 – Madunaghat Feeder..................................................................... 47 7.3.21 Minimum Relay Voltages for a Fault at the Zone 1 Reach Point ..................... 48 7.3.22 Proposed Time Settings .................................................................................... 49 7.4 Auto Recloser and DEF ............................................................................................. 50 CONCLUSION AND RECOMMENDATIONS ..............................................................51 BIBLIOGRAPHY...............................................................................................................54 APPENDIX A ......................................................................................................................56 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 LIST OF TABLES Table No. 3.1 3.2 3.3 3.4 3.5 5.1 7.1 7.2 7.3 7.4 Caption Page 8 9 10 11 12 25 35 37 48 49 Maximum Load and Transformer Capacity Conductor name and Line length of existing network Impedance and current capacity of conductor Relay type, CT ratio and P.T ratio of the existing network Types and settings of other protective relay Presence of sequence components Zone and time setting of the network Calculated positive sequence impedance for zone setting Minimum relay voltage requirements for measurement of faults The proposed time settings of distance relays for existing network i LIST OF FIGURES Figure No. 4.1 5.1 5.1.a 5.1.b 5.2 5.3 5.4 5.5 6.1 7.1 7.2 7.3 7.4 7.5 7.6 7.7 7.8 7.9 7.10 7.11 Caption Primary and back-up protection MHO Impedance Characteristics MHO characteristic via a phase comparator MHO characteristic via a phase comparator Offset MHO Characteristic Three step quadrilateral characteristic Effect of arc resistance on MHO relay Effect of power surges on distance relays Impedance measured by distance relay Coordination curves of Madunaghat to Baraulia and Kulshi section Coordination curves of Madunaghat to Baraulia and Madunaghat – Sikalbaha2 section Coordination curves of Madunaghat –Kulshi -Baraulia and Kulshi - Halishahar section Coordination curves of Madunaghat-Sikalbaha, Madunaghat –Kulshi- Baraulia and Halishahar section Coordination curves of Madunaghat-Sikalbaha–Halishahar, Madunaghat–Kulshi section. Coordination curves of Madunaghat - Sikalbaha - Halishahar and Kulshi – Halishahar – Sikalbaha2 section Coordination curves of Hathazari - Baraulia - Kulshi section Coordination curves of Kulshi –Baraulia and Madunaghat, and Halishahar-Kulshi section Coordination curves of Madunaghat – Kulshi – Halishahar, Baraulia – Kulshi 1 and Sikalbaha2 – Halishahar section Coordination curves of Sikalbaha2 – Madunaghat – Hathazari and Kulshi Coordination curves of Kulshi – Baraulia – Hathazari – Madunaghat after time grading Page 15 19 19 20 21 21 22 23 26 38 39 40 40 41 42 43 44 46 46 47 ii GLOSSARY OF ABBREVIATIONS Abbreviation BPDB PGCB REB PSMP EPZ KV AAAC MW MVA S/S MCM CB O / km 0 C PTR CTR C.T. P.T./V.T. O/C DEF Tr EHV L-L L-G L-L-G L-L-L PSB TZ KA Full-Form Bangladesh Power Development Board Power Grid Company of Bangladesh Limited Rural Electrification Board Power System Master Plan Export Processing Zone Kilo Volt All Aluminium Alloy Conductor Mega Watt Mega Volt Ampere Sub-Station Million Circular Mils Circuit Breaker Ohm per Kilo Meter Degrees Centigrade Potential Transformer Ratio Current Transformer Ratio Current Transformer Potential/Voltage Transformer Over Current Relay Directional Earth Fault Relay Transformer Extra High Voltage Line to Line Fault Line to Ground Fault Double line to Ground Fault Three Phase Fault Power Swing Blocking Zone Time Setting Kilo Ampere First in page 1 1 1 1 1 3 6 8 8 8 9 10 10 10 12 11 11 11 12 12 12 18 25 25 25 25 28 49 58 iii 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 g overnment 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 1 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 ge nerating 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 protectio n 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 2 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, tabulatio n 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, 3 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 4 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 stud y 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. 5 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 substations 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. 6 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. 7 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 substation are given below: Table 3.1 Maximum Load and Transformer capacity. Name of Grid S/S Madunaghat Hathazari Kulshi Baraulia Sikalbaha2 Halishahar Maximum Load, MW 55 50 98 135 5 100 Transformer Capacity, MVA 1 × 25/41.7 1 × 25/41 2 × 44.1/63 2 × 44.1/63 1 × 28/40 1 × 25/41.7 2 × 25/41.7 2 × 44.1/63 1 × 25/41.7 Source (From) Generating Station Madunaghat Madunaghat Hathazari, Kulshi Generating Station Sikalbaha2, Kulshi Remarks Supplying power to national Grid Supplying power to national Grid The load flow of the network is shown in appendix (A) and (C). 8 3.3 Transmission Line and Conductor Information The conductor name and size, circuit and line length of the network are given in table below. Table 3.2 Conductor name and Line length of existing network. Name of Grid S/S Name of Feeder Conductor Name & Size Line Length, km Madunaghat Hathazari – 1 Hathazari – 2 Kulshi – 1 Kulshi – 2 Sikalbaha2 – 1 Sikalbaha 2– 2 Kulshi Baraulia – 1 Baraulia – 2 Halishahar Madunaghat – 1 Madunaghat - 2 Hathazari Madunaghat – 1 Madunaghat – 2 Baraulia – 1 Baraulia – 2 Baraulia Kulshi – 1 Kulshi – 2 Hathazari – 1 Hathazari – 2 Halishahar Kulshi Sikalbaha2 Sikalbaha2 Madunaghat – 1 Madunaghat - 2 Halishahar Grosbeak, 636 MCM Grosbeak, 636 MCM Grosbeak, 636 MCM Grosbeak, 636 MCM Grosbeak, 636 MCM Grosbeak, 636 MCM Grosbeak, 636 MCM Grosbeak, 636 MCM Grosbeak, 636 MCM Grosbeak, 636 MCM Grosbeak, 636 MCM Grosbeak, 636 MCM Grosbeak, 636 MCM Grosbeak, 636 MCM Grosbeak, 636 MCM Grosbeak, 636 MCM Grosbeak, 636 MCM Grosbeak, 636 MCM Grosbeak, 636 MCM Grosbeak, 636 MCM AAAC Grosbeak, 636 MCM Grosbeak, 636 MCM AAAC 9 9 12.7 12.7 16.1 16.1 12.9 12.9 13.5 12.7 12.7 9 9 12 12 12.9 12.9 12 12 13.5 12.9 16.1 16.1 12.9 Single Single Single Double Double Double Double Double Single Double Double Double Double Double Circuit 9 3.4 Conductor Impedance The positive and zero sequence impedance of conductors are very necessary for distance protection of transmission lines. The impedances of conductor which used in the existing network are given below: Table 3.3 Impedance and current capacity of conductor Name & Size of Conductor Current Capacity, A Stranding Positive & Negative sequence Impedance, r1 = r2 , at 50 0 C O / km Grosbeak, 322 mm2 AAAC, 804 mm 2 Zero sequence Impedance ro O/ km xo O/km x1 = x2 , O / km 790 26/7 0.099 0.385 0.24 0.98 777 61/4 0.0534 0.43 0.106 0.8 Where, r1 is the positive sequence resistance, r2 is the negative sequence resistance, x1 is the positive sequence re4actance, x is the negative sequence reactance, ro is the zero 2 sequence resistance and x is the zero sequence reactance. The ambient temperature is o normally 35 0 C in Bangladesh. 3.5 Protective Devices Speedy elimination of a fault by the protection system requires correct operation of a number of subsystems of the protection system. The protection system can be subdivided into three subsystems. They are Circuit Breakers (CB), Transducers (T) and Relays (R). The specification and type of these subsystems of the existing network are given below. The manufacturer and specifications of CB is tabulated in Appendix (A). 10 3.5.1 Distance Relay, Current Transformer and Voltage Transformer Table 3.4 Relay type, CT ratio and P.T ratio of the existing network Name of Grid S/S Name of Feeder Positive sequence Z1 Madunaghat End Hathazari – 2 Kulshi – 1 Kulshi – 2 Sikalbaha2 – 1 Sikalbaha 2– 2 Kulshi End Madunaghat-1 Madunaghat-2 Baraulia – 1 3.57 5.384 5.384 6.384 6.384 5.384 5.384 5.135 69.5 76.1 76.1 75.5 75.5 76.1 76.1 75.3 9.12 12.86 12.44 13.26 16.32 12.44 12.44 10.63 76.3 76.3 76.3 76.1 76.1 75.8 75.8 76.1 SHPM101 SHPM101 SHPM101 SHPM101 SHPM101 LZ32 LZ41a REL 316*4 Baraulia – 2 Halishahar Hathazari End Madunaghat-1 Madunaghat-2 Baraulia – 1 Baraulia – 2 Baraulia End Kulshi – 2 Hathazari – 1 Hathazari – 2 Halishahar End Sikalbaha2 End Kulshi Sikalbaha2 Madunaghat-1 Madunaghat-2 Halishahar Sikalbaha 1 Madunaghat Source Source 5.135 4.776 4.776 5.722 5.58 6.384 6.384 5.58 6.2 12.8 75.3 75.2 75.2 75.3 82.9 75.5 75.5 82.9 85 85 10.63 9.89 9.89 9.89 10.41 13.26 13.26 10.41 76.1 70.1 70.1 76.1 82.4 76.1 76.1 82.4 Kulshi – 1 5.135 5.722 3.57 3.57 4.776 4.776 5.135 75.3 75.3 69.5 69.5 75.2 75.2 75.3 10.63 9.89 9.12 9.12 9.89 9.89 10.63 76.1 76.1 76.3 76.3 70.1 70.1 76.1 SHPM101 LZ41a SHPM101 SHPM101 SHPM101 SHPM101 REL 316*4 SHPM101 SHPM101 SHPM101 LZ41a SHPM101 SHPM101 SHPM101 SHPM101 800/5 800/5 800/5 800/5 800/5 400/5 400/5 800/5 132000/110 132000/110 132000/110 132000/110 132000/110 132000/110 132000/110 132000/110 800/5 800/5 600/1 600/1 600/1 600/1 800/5 132000/110 132000/110 132000/110 132000/110 132000/110 132000/110 132000/110 800/5 400/5 800/5 400/5 400/5 400/5 800/5 800/5 132000/110 132000/110 132000/110 132000/110 132000/110 132000/110 132000/110 132000/110 Hathazari – 1 3.57 Line Parameter (Primary ohm) Zero Sequence Angle 0 69.5 Relay Information Relay type CTR (A) PTR, V Z0 9.12 Angle 0 76.3 SHPM101 800/5 132000/110 11 3.5.3 Other Protective Relays 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 Madunaghat End Relay used 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) 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) E/F relay (67G), GEC, USA. Auto reclosing (79R1) , NTJ-20, Japan Voltage relay, CV-5-D, Japan (For all feeders) 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) E/F relay (67G), GEC, USA. Auto reclosing (79R1) , NTJ-20, Japan Voltage relay, CV-5-D, Japan (For all feeders) E/F relay (67G), GEC, USA. Auto reclosing (79R1) , NTJ-20, Japan Voltage relay, CV-5-D, Japan (For all feeders) Tr 1 O/C (51& 51G), Japan (Primary) Differential relay (87), Japan Tr 1 O/C relay(51& 51G), Japan (Secondary) Tr 2 O/C relay (51& 51G), Japan (Primary) Differential relay (87), Japan Tr 2 (Secondary) O/C relay(51& 51G), Japan Relay Setting Inst. 0.45s, P.S-1.0, D.S-0.2 P.S -120, D.S -10 Kulshi End 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) Inst. 0.45s, P.S-1.0, D.S-0.2 P.S -120, D.S -10 Inst. 0.45s, P.S-1.0, D.S-0.2 P.S -120, D.S -10 Hathazari End Baraulia End Halishahar End Inst. 0.45s, P.S-1.0, D.S-0.2 P.S -120, D.S -10 Inst. 0.45s, P.S-1.0, D.S-0.2 P.S -120, D.S -10 Inst. 0.3 s, P.S - 3.75, D.S -5 % =35 P.S - 5, D.S – 3.75 Inst. 0.3 s, P.S - 3.75, D.S -5 % =35 P.S - 5, D.S – 3.75 Sikalbaha2 End Kulshi Grid 12 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]. 13 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. 14 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. Relay A operating time STI B Time A C TA TB CBA CBB Fault Figure 4.1 Primary and back- up protection Consider a fault in section B-C as shown in figure. When a fault occurs, both the primary relay R and the back- up relay R , start operating simultaneously. In case the primary B A 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 15 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. 16 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. 17 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 types1) 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. 18 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. JX T3 T2 T1 R Figure 5.1 MHO Impedance Characteristics 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. JIX IZr Stable Trip V3 θ S1 V1 S2 P IR Figure 5.1.a MHO characteristic via a phase comparator Voltage to Relay = V Current to Relay = I Replica Impedance = Zr Trip condition: ∠ S1 – S2 = θ < 900 Where, S2 = IZr - V S1 = V 19 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 JX Zr Stable Trip Z3 θ S1 Z1 S2 R Figure 5.1.b MHO characteristic via a phase comparator V = IZ S2 ∝ IZr – V ∝ Zr - Z S1 ∝ V ∝ Z. Angle between (Zr – Z3 ) and Z3 < 900 or > - 900 Angle between (Zr – Z1 ) and Z1 > 900 or < - 900 Trip 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. 20 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. X Z S1 S2 -Z Figure 5.2 Offset MHO Characteristic Trip Condition, ∠ S1 – S2 = θ < 900 . R 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. X Zone 3 Zone 2 Zone 1 R Figure 5.3 Three step quadrilateral characteristic 21 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. X Zl F F Z f R f ZF+R Zf + R R Figure 5.4 Effect of arc resistance on MHO relay 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 22 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 fa ult 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 RX diagram, Figure 5.5. It is evident from the figure that the relay characteristic occupying greater area on the R diagram remains under the influence of the power surge for a -X greater period and hence, it is more affected by power surges. X Power Surges Impedance Relay Reactance Relay R MHO Relay Figure 5.5 Effect of power surges on distance relays 23 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 a-b phase pair b-c phase pair c-a phase pair Voltage Vab Vbc Vca Current Ia – Ib Ib – Ic 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 a - Phase b - Phase c - Phase Voltage Va Vb Vc Current Ia + 1/3 (K-1)Ires Ib + 1/3 (K-1)Ires 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 24 Table 5.1 presence of sequence components Fault L-G L-L L-L-G L-L-L Positive sequence Yes Yes Yes Yes Negative sequence Yes Yes Yes No Zero sequence Yes No Yes 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. 25 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. I1 /I2 Zp IR VR V1 /V2 Figure 6.1 Impedance measured by distance relay V2 V V1 ZR = R = I IR I FP × 2 I1 VFP × I1 V I C.T.ratio = FP × 2 = Zp × = ZS V1 I FP V.T.ratio V2 26 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 protectio n (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. 27 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 ma y 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. 28 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 29 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: Zone 1: Zone 2: TZ1 = Instantaneous. TZ2 = TZ1 (down) + CB (down) + Z2 (reset) + Margin (In general, selective time interval is 0.25s – 0.5s) Zone 3: TZ3 = TZ2 (down) + CB (down) + Z3 (reset) + Margin (In general, selective time delay is 0.4s – 1s) Where upper and lower zones overlap e.g. zone 2 up sees beyond zone 1 down, the upper and lower zone time delays will need to be coordinated e.g. TZ2 (up) to exceed TZ2 (down) [5]. Zone 3 reverse: The time setting is same as zone 3 time delay. 6.1.10 Zone-2 timer setting (T Z2) and Coordination The coordination issue here is that, the second zones of all primary/back-up pairs either never interact or if they do, the time delay of back- up relay exceed that of the primary relay by a coordination time interval (MCI). The coordination is completed at the end of the first round of determining timer setting values if none of the relays have second zone delays greater than minimum coordination interval defined for distance relays. If any of the relays has an increased second zone time delay, we compute second time and modify the delays accordingly to achieve system coordination. 6.1.11 Zone-3 Timer Setting (T Z3) and Coordination The Zone-3 timers of all back-up pairs should coordinate among themselves. The zone-3 timer (T-3) is set equal to T-2 plus minimum coordination interval. Each back-up pair is taken and checked for coordination, if it does not coordinate, then either 30 Zone -3 timer setting is modified or little coordination interval is sacrificed. If still it does not coordinate, then relay parameters are changed or it is replaced with another one. 6.1.12 Summary of the Philosophy of Three-Stepped Distance Protection Step First step Purpose Primary protection Reach 80 to 90 % of line section Operating time Instantaneous i.e. no intentional time delay Remarks Avoids loss of selectivity with protection with next zone in case of maximum overreach. * Provides primary protection to part of line left out of first step and provides some back-up protection to the bus and the next line. * Shortest adjoining line is to be considered. * If the longest adjoining line is considered, then it causes loss of selectivity. Second step Primary protection of remaining 20 to 10 % and back-up protection of some portion of adjacent line. 100 % of line under consideration + 50 % of shortest adjoining line Tins + Selective time interval = T2 Third step Back-up protection 100 % of line under consideration + 100 % of longest line + 10 to 20% extra. T2 + Selective time interval = T3 * Idea to provide full backup to the adjoining line, even in case of maximum underreach. * Longest adjoining line has to be considered. If shortest adjoining line is considered then the longer adjoining line will not get back-up protection. 6.1.13 Ground Fault Compensation Setting Ground loop impedance of line ZLE = (1 + KN) ZL1 Where, KN (residual compensation factor) = = Compensation Setting ZN = KN × Zph Where, Zph is the relay coarse reach. 2ZL1 + ZL0 . 3 Eq. 1 ZL0 - Z L1 3ZL1 Eq. 2 Eq. 3 31 [Also there are some attenuator factors (K factor) in some supplier relay manuals to set ZN] With this compensation the relay will measure Z (positive sequence impedance of the L1 line) irrespective of the number and position of system earthing points. 6.1.14 Choice of Zone Setting for Ground Faults The ground impedance reach is typically set the same as the phase reach unless there is a grounding transformer on the protected line, significant mutual impedance with a parallel line, or other special application needs [6]. 6.1.15 Mutual Compensation for Parallel Circuit If the overhead line circuits are supported on the same tower there is mutual inductive coupling between the two circuits. The positive and negative sequence coupling between the two feeders are negligible. The zero seque nce coupling on the other hand can be strong and its effect can not be ignored because it will cause a distance relay to underreach or overreach depending on the zero sequence current flow in the parallel circuit. . Mutual impedance ZM causes relay to underreach by a factor I HO ZM . . I GO 2ZL1 + ZL0 Where, IHO is the mutual zero sequence current and IGO is the fault current in the faulted circuit. A distance relay can be mutually compensated by measuring the zero sequence current flowing in the parallel circuit. Mutual compensation factor KM = Z m0 Z L1 Eq. 4 6.1.16 Calculations of Minimum Relay Voltage for a Fault at the Zone 1 Reach Relay voltage for a phase fault = Impedance to zone 1 reach point×Secondary voltage of VT Overallsourcetofaultimpedance Eq. 5 Relay voltage for a ground fault = Ground loop impedance to zone 1 reach point × Secondary voltage of VT Overall source to fault ground loop impedance × 1.732 Eq. 6 32 6.1.17 Practical Applications for Phase and Earth Fault Connection The set of three phase fault measuring elements, energized with phase-phase current from the delta connected secondary windings of auxiliary C.T’s and with phase voltage, measure positive-sequence impedance for all phase faults. The set of three earth-fault measuring elements, energized with phase currents and phase- neutral voltages and with residual compensation, measure positive-sequence impedance for all earth faults [7]. 6.2 Maximum Source Impedance at Madunaghat and Sikalbaha2 (for real case) 1) Maximum source impedance at Madunaghat grid is when 400 MW source at Madunaghat is switched out, only one 30 MW source at Sikalbaha2 is switched in and only one of the parallel line between Madunaghat and Sikalbaha is switched in. Maximum Madunaghat positive sequence impedance = 18.72 ∠81.8 [Ref. Appendix D.2] 2) Maximum source impedance at Sikalbaha2 grid is when both 30 MW sources at Sikalbaha2 are switched out, 400 MW source at Madunaghat is switched in and only one of the parallel line between Madunaghat and Sikalbaha is switched in. Maximum Sikalbaha2 positive sequence impedance = 2.705 + j18.94 [Ref. Appendix D.2] 33 Chapter 7 DISCUSSION ON PROTECTION AND COORDINATION STUDY 7.1 Introduction The load flow and short circuit study has performed mainly for coordinatio n study of the existing network, in addition to calculate the present load flow and fault levels. Therefore, in this project work, the main discussion has done about coordination analysis of distance relays. 7.2 Discussion on Load flow and Short Circuit Analysis Load flow and short circuit analysis help to select proper ratings of the equipment and the protective devices. From the load flow analysis which is shown in appendix ( ), the C existing line conductors are sufficient to carry the maximum load current. In case of Kulshi grid S/S, the capacity of both of the transformers is 41/63 MVA. The transformer T1 and T2 of this grid are loaded 90 % during the peak load with cooling system (ONAF) running condition. So, it is not problem for present situation but in the near future the capacity of this transformer should be upgraded if the growing demand of load is consider (annually growth 7%). From present load flow study, it can be seen that, the heaviest line is Kulshi - Madunaghat line where each of the circuits is carrying current 391 Amperes. Therefore, if any one of the line of Madunaghat-Kulshi feeder trips, healthy circuit will may overloaded, but in this case partial load can share via Hathazari – Baraulia lines. During the overload condition the distance relays will not be tripped. During normal load condition of the network the impedance seen by a distance relay is outside the tripping zone (Zone 3). It will not be affected for short length of lines i.e. for existing network. But, on a very long line where the length of the line in miles exceeds the system KV, the impedance characteristic may have to be made so large as to involve the normal load point. 34 The existing maximum three phase faults at different locations are nearly same to calculated fault current. Therefore the ratings of the protective devices and equipment are sufficient of the network. When a fault occurs in between of the protected line section, there is a contribution of the fault current from another Bus Bar or from healthy circuit in case of parallel line which may trip unaffected breaker. In general, parallel circuits do not affect the operation of main zones of distance protection, although they may alter considerably the back-up performance which can be seen in coordination curves. Since MHO relays inherently a directional and all other E/F relays are used of this network are directional, they will not see the fault behind of the relays except zone 3 reverse setting of distance relay. But it has to be considered that unaffected relay will cause tripping during fault current contribution from adjacent feeder. It has found that, there is no mal-operation of the relays when their feeder contributes the fault current during the fault on adjacent feeder. The contribution of the fault currents to the affected feeder are given in Appendix (B). 7.3 Discussion on Coordination Study From the existing zone settings and calculated zone settings of distance relays are shown in table below, we found that, the impedances setting for zone 1, zone 2, zone 3 and zone 3 (reverse) are nearly same except Hathazari – Baraulia 1 and Hathazari – Baraulia 2 feeders. There are some variations between existing and proposed impedance settings because in some cases the existing value of relay settings calculated as 85% of the protected line for zone 1 which is also correct. The relay type, CT and VT ratio are given in Table 3.5 in chapter 3. The zone 3 (reverse) settings are same as calculated reverse zone 3 settings. The detail discussion and justification of existing and proposed settings are given below in feeder basis. 35 7.3.1 Existing Relay Setting Table 7.1 Zone and time setting of the network Name of Grid S/S Name of Feeder Zone 1 Imp, O Secondary Zone Setting Zone2 Imp, Zone3 Imp, Zone3 (Rev) Imp, Time Step Setting TZ1 In TZ2 In Second TZ3 In Second O O Secondary Secondary O Second Secondary Madunaghat End Hathazari – 1 Hathazari – 2 0.3744 0.3744 0.72 0.72 1.1520 1.1520 0.09 0.09 0 0 0.4 0.4 0.8 0.8 Name of Grid S/S Name of Feeder Zone 1 Imp, O Secondary Zone Setting Zone2 Imp, Zone3 Imp, Zone3 (Rev) Imp, Time Step Setting TZ1 In TZ2 In Second TZ3 In Second O O Secondary Secondary O Second Secondary Madunaghat End Kulshi – 1 Kulshi – 2 Sikalbaha2-1 Sikalbaha 2-2 Madunaghat-1 Madunaghat-2 Baraulia – 1 Baraulia – 2 Halishahar Madunaghat-1 Madunaghat-2 Baraulia – 1 Baraulia – 2 Kulshi – 1 Kulshi – 2 Hathazari – 1 Hathazari – 2 Kulshi Sikalbaha2 Madunaghat-1 Madunaghat-2 Halishahar 0.285 0.5405 0.341 0.341 0.2857 0.5405 0.58 0.5824 0.6061 1.512 1.512 1.512 1.512 0.58 0.5824 0.45 0.45 0.6061 0.62 0.34 0.34 0.6 0.5 0.98 0.58 0.58 0.4762 0.9091 0.97 0.9520 1.0526 3.08 3.08 3.08 3.08 0.98 0.9520 0.76 0.76 1.0526 1.175 0.55 0.55 1.0 0.77 1.51 0.872 0.872 1.6 1.6 1.5 1.512 1.6 4.9 4.9 5.04 5.04 1.6 1.512 1.0 1.0 1.6 1.8 0.7 0.7 1.622 0.06 0.13 0.08 0.08 0 0 0 0 0.1 0.1 0.03 0 0.1 0 0 0 0 0.03 0 0 0 0.1 0 0 0 0 0.4 0.4 0.4 0.4 0.6 0.6 0.3 0.4 0.6 0.4 0.4 0.4 0.4 0.3 0.4 0.4 0.4 0.6 0.4 0.4 0.4 0.4 0.8 0.8 0.8 0.8 1.2 1.2 0.6 0.8 1.2 0.8 0.8 0.8 0.8 0.6 0.8 0.8 0.8 1.2 0.8 0.8 0.8 0.8 Kulshi End 0.14 0.3850 0.3850 0.399 0.399 0.14 0.1 0.1 0.14 0.08 0.08 0.15 Hathazari End Baraulia End Halishahar End Sikalbaha2 End Where, TZ1 is the time setting for zone 1, TZ2 is the time setting for zone 2, and TZ3 is the time setting for zone3. 36 7.3.2 Calculated/Proposed Impedance Value for Zone Setting Table 7.2 Calculated positive sequence impedance for zone setting Name of Grid S/S Name of Feeder Zone 1 Imp, O Secondary Zone2 Imp, Zone3 Imp, Zone3 (Rev) Imp, Zone Setting O O O Angle Secondary Secondary Secondary Madunaghat End Hathazari – 1 Hathazari – 2 Kulshi – 1 Kulshi – 2 Sikalbaha2-1 Sikalbaha 2-2 0.374 0.374 0.27 0.53 0.339 0.339 0.792 0.792 0.504 0.988 0.576 0.576 0.456 0.91 1.0 0.988 1.08 3.08 3.08 3.6 3.6 1.02 1.04 0.816 0.816 1.052 1.176 0.544 0.544 1.02 1.26 1.26 0.768 1.508 0.864 0.864 0.85 1.69 1.48 1.508 1.64 5.04 5.04 5.58 5.58 1.58 1.508 1.2 1.2 1.55 1.792 0.736 0.736 1.62 0.09 0.09 0.06 0.13 0.08 0.08 70 70 80 80 80 80 76 76 76 Kulshi End Madunaghat-1 0.27 Madunaghat-2 0.538 Baraulia – 1 Baraulia – 2 Halishahar 0.547 0.541 0.57 0.13 75 76 Hathazari End Madunaghat-1 1.428 Madunaghat-2 1.428 Baraulia – 1 Baraulia – 2 1.872 1.872 0.547 0.541 0.499 0.499 0.572 0.594 0.350 0.350 0.45 0.45 70 70 75 75 76 Baraulia End Kulshi – 1 Kulshi – 2 Hathazari – 1 Hathazari – 2 0.13 0.12 0.12 75 75 75 76 Halishahar End Sikalbaha2 End Kulshi Sikalbaha2 0.14 0.08 0.08 0.15 85 80 80 85 Madunaghat-1 0.339 Madunaghat-2 0.339 Halishahar 0.6 37 7.3.3 Madunaghat – Hathazari Feeders The existing zone settings of the relays for both Madunaghat – Hathazari 1 and 2 feeders are accurate. Although, from the calculated zone settings [Ref. Table 7.2], it is evident that, the zone 3 setting can be set to reach up to 1.26 ohm to provide complete back-up protection and cover underreach which may arise due to arc fault resistance or transducers errors. Considering the zone and time settings depicted in the coordination curve, Figures 7.1 and 7.2, the discrimination between the zones of back-up protection with relays on adjacent feeders, Hathazari -Baraulia (1 & 2) are sufficient. There is no possibility of maloperation during the fault. Coordination Curve 1 0.8 0.6 0.4 0.2 0 -0.2 -0.4 -0.6 -0.8 -1 Distance Madu-Hat 1 Hat - Bar 1 Madu-Kul 1 Hat-Madu1 Bar - Hat1 Time Figure 7.1 Coordination curves of Madunaghat to Baraulia and Kulshi section 7.3.4 Madunaghat – Kulshi 1 Feeder From the calculated zone setting [Ref. Table 7.2], it can be seen that, the existing zone settings of the relay at Madunaghat end are accurate. It provides back- up protection on adjacent feeders, Kulshi – Baraulia (1 & 2) and Kulshi - Halishahar without the risk of mal-discrimination. In case of Kulshi – Halishahar feeder there is unnecessarily higher time grading at Kulshi end relay between zone 1, zone 2 and zone 3. The time interval between zone 1, zone 2 and zone 3 may keep lower than existing setting (0.1 s, 0.4 s and 0.8 s for zone1, zone 2 and zone 3 respectively). 38 From the line length of the existing network and coordination curve [Ref. Table 3.2 and Figure 7.3], it is evident that, Madunaghat – Kulshi and Kulshi – Baraulia feeder length is 12.7 km and 12.9 km respectively and both of this lines are almost equal i.e. adjacent line is not short. Therefore, according to article 6.1.3, Zone 2 setting may not need to be increased slightly, to avoid sequential or time delayed clearance of the fault at the terminal remote from the fault. In this case, Kulshi end relay (Kulshi – Baraulia 1) time setting can be set as same as Madunaghat end relay (Madunaghat – Kulshi1). Coordination Curve 1.2 0.8 0.4 Time 0 -0.4 -0.8 -1.2 Distance Madu-Hat 2 Hat-Madu 2 Madu-Sikal2 Hat - Bar 2 Bar - Hat 2 Figure 7.2 Coordination curves of Madunaghat to Baraulia and Madunaghat – Sikalbaha2 section. 7.3.5 Madunaghat – Kulshi 2 Feeder From the calculated zone setting and coordination curve [Ref. Table 7.2 and Figure 7.4 respectively], it is clear that, the existing zone settings of the relay at Madunaghat end are accurate. There is proper discrimination between zones of back-up protection on adjacent feeders. For, Kulshi – Halishahar feeder and Kulshi – Baraulia feeder the relay can be set as described above [Ref. section 7.3.4, line 7.3.6 Hathazari – Madunaghat Feeders Since the CT’s and P.T’s ratio are same for both feeders, the zone settings of both relays are same. From Table 7.1 and 7.2, it is evident that, the zone settings of both feeders are accurate. But in case of zone 3 setting, it can be extend up to 5.04 ohm to provide full back-up on adjacent feeders and to cover maximum underreach during the fault. 39 From the coordination curves [Ref. Figures 7.1 and 7.2], the selectivity between zones of protection with relays on adjacent feeders is sufficient. So, there is no possibility of maloperation during the fault on adjacent feeders. Coordination Curve Madu-Kul 1 Kul-Madu1 Kul - Hal 1.5 1.2 0.9 0.6 0.3 0 -0.3 -0.6 -0.9 -1.2 -1.5 Kul-Bar 1 Bar-Kul 1 Madu-Hat Time Distance Figure 7.3 Coordination curves of Madunaghat –Kulshi -Baraulia and Kulshi – Halishahar section Coordination Curve Madu-Kul 2 Kul-Madu 2 Kul - Hal 1.5 1.2 0.9 0.6 0.3 0 -0.3 -0.6 -0.9 -1.2 -1.5 Distance Kul-Bar 2 Bar-Kul 2 Madu-Sikal2 Time Figure 7.4 Coordination curves of Madunaghat-Sikalbaha, Madunaghat – Kulshi – Baraulia and Halishahar section 40 7.3.7 Madunaghat – Sikalbaha2 Feeders Since the CT’s and P.T’s ratio are same for both circuits, the zone settings of both relays are same. accurate. Considering the time settings depicted in the coordination curves [Ref. Figures 7.5 and 7.6], the selectivity between the zones of back- up protection on adjacent feeder, Sikalbaha2 - Halishahar is sufficie nt. There is no possibility of mal-operation during the fault on Sikalbaha2 – Halishahar line. From Table 7.2, it is evident that, the zone settings for both feeders are Coordination Curve 0.9 0.6 0.3 0 Time Madu-Sikal2-1 Sikal2 - Madu1 Kul - Hal Sikal2- Hal Hal-Sikal2 -0.3 -0.6 -0.9 -1.2 -1.5 Distance Figure 7.5 Coordination curves of Madunaghat-Sikalbaha–Halishahar, Madunaghat – Kulshi section. 7.3.8 Baraulia - Hathazari Feeders The zone settings for both feeders (Baraulia – Hathazari 1 & 2) are same due to same CT’s, P.T’s ratios and distance. From the existing and calculated tables [Ref. Table 7.1 and Table 7.2], it is clear that, the existing zone settings are accurate. From the coordination curves [Ref. Figures 7.1 and 7.2], the time delay between the zones of back-up protection with relays on adjacent feeder (Hathazari –Madunaghat) are same. If the adjoining line is so short, it is better an increase in the time setting of zone 2 on the longer feeder to discriminate with zone 2 on the shorter feeder to avoid encroaches on the zone 2 relays on the shorter feeder. Since, the adjoining feeder (Hathazari – Madunaghat) is not so short, there is no loss of selectivity with zone 2 on the shorter feeder. But for 41 safe side, the operating time of zone 2 and zone 3 settings at Baraulia end relays can be adjusted with some additional time for selectivity (say, 0.5 s for zone 2 and 0.9 s for zone 3). Coordination Curve 0.9 0.6 0.3 0 -0.3 -0.6 -0.9 -1.2 -1.5 Madu-Sikal2-2 Sikal2 - Madu2 Kul - Hal Sikal2- Hal Hal-Sikal2 Time Distance Figure 7.6 Coordination curves of Madunaghat - Sikalbaha - Halishahar and Kulshi – Halishahar – Sikalbaha2 section. 7.3.9 Hathazari - Baraulia Feeders From the existing settings and calculated settings [Ref. Table 7.1 and 7.2], it is clear that, the zone settings of Hathazari – Baraulia feeder is completely wrong. The line length between Hathazari and Madunaghat sub-station is 9 km where Hathazari to Baraulia is 12 km. But the data of zone settings provided by PGCB are same for all feeders i.e. Hathazari – Madunaghat and Hathazari – Baraulia which are not correct (It may be data error or settings error). From calculated zone settings [Ref. Table 7.2], zone 1, zone 2 and zone 3 can be set to reach 1.872, 3.6 and 5.58 respectively. Therefore, it is recommended that, the zone settings impedance of Hathazari – Baraulia feeder i.e. relay reach should be set as same as proposed zone settings [Ref. Table 7.2]. Considering the time settings depicted in the coordination curves, Figure 7.7, it is clear that, there is discrimination between zones of back- up protection on adjacent feeder (Baraulia – Kulshi 1 & 2). 42 7.3.10 Kulshi – Madunaghat 1 Feeder Considering the time settings [Ref. Figures 7.3 and 7.4], it is evident that, there is selectivity to provide back-up protection on adjacent feeders. Since, the adjacent feeder (Madunaghat – Hathazari) line length is short; there is an increase in the time setting of zone 2 with zone 2 on the shorter feeder to avoid mal-discrimination. Hat - Bar Bar - Kul 1 Bar - Hat Kul-Bar 2 Coordination Curve 0.9 0.6 0.3 Time 0 -0.3 -0.6 -0.9 Distance Bar - Kul 2 Kul-Bar 1 Figure 7.7 Coordination curves of Hathazari - Baraulia - Kulshi section A C.T. ratio 400/5 is used for this feeder while it is 800/5 for Kulshi – Madunaghat 2 feeder. From the existing data, zone 3 setting of the relay at Kulshi end is 1.6 ohm which is same as zone 3 setting of Kulshi – Madunaghat 2 feeder. Therefore, the zone 3 existing setting is not correct for this feeder, since the CT ratios are different (May be it was data error or setting error as collected from PGCB). Therefore, it is recommended that, the zone 3 setting can be set to reach 0.85 ohm. Zone1 and zone 2 relay settings are accurate of this feeder. 7.3.11 Kulshi – Madunaghat 2 Feeder The existing zone settings of this feeder are accurate. From the coordination curves [Ref. Figures 7.3 and 7.4], it is evident that, there is discrimination between zones of protection on adjacent feeders. 43 7.3.12 Halishahar – Sikalbaha2 Feeder Considering the coordination curves [Ref. Figures 7.5 and 7.6], it can be seen that, there is proper selectivity between zones of back-up protection on adjacent feeders. From Table 7.2, it can be also seen that, the existing zone settings are properly maintained. There is no possibility of mal-operation during the fault on Sikalbaha2 – Hathazari line. 7.3.13 Kulshi – Baraulia 1 Feeder From the coordination curve [Ref. Figure 7.7], the zone 2(up) back-up protection from Kulshi end of circuit 1 relay has time delay only 0.15 second from zone 1(down) time setting i.e. with adjacent feeder Baraulia - Hathazari. But for zone 2, the operating time has to be delayed so as to be selective with zone 1(down) as described in chapter 6. Therefore, due to loss of selectivity, there is possibility to trip Kulshi circuit 1 end relay unnecessarily, if any fault occurs on Baraulia to Hathazari line. So, it is recommended that, the zone 2 time setting at Kulshi end relay set to time delay 0.4 s. The existing zone settings are accurate. Kul-Madu Hal - Kul Kul-Bar 2 Coordination Curve 1.5 1.2 0.9 0.6 0.3 0 -0.3 -0.6 -0.9 -1.2 -1.5 Distance Kul-Bar 1 Hal - Kul Time Figure 7.8 Coordination curves of Kulshi –Baraulia and Madunaghat, and Halishahar - Kulshi section. 7.3.14 Kulshi – Baraulia 2 Feeder From the calculated zone setting table and coordination curve [Ref. Table 7.2 and Figure 7.7], it is clear that, there is proper discrimination between zones of back-up protection on adjacent feeders. 44 7.3.15 Kulshi – Halishahar Feeder From the calculated zone settings [Ref. Table 7.2], the zone settings of this feeder are accurate. From the coordination curve [Ref. Figure 7.6], it can be seen that, there is selectivity between zone 2 of Kulshi end relay and Halishahar end (Halishahar – Sikalbaha2) relay. But there is unnecessarily, additional time delay for the zone 2 of this feeder. The time interval of the zone 2 can be set 0.4 s. 7.3.16 Baraulia – Kulshi 1 Feeder If the relay at Kulshi end does not operate properly during the fault between the Madunaghat to Kulshi section, the zone 2(up) back- up protection from Halishahar end will operate properly (Figure 7.8). From the coordination curve [Ref. Figure 7.3], the zone 2(up) back-up protection from Baraulia end of circuit 1 rela y has time delay only 0.15 second from zone 1(down) time setting. But for zone 2, the operating time has to be delayed so as to be selective with zone 1(down) as described in section 6.1.9. Therefore, due to loss of selectivity, there is possibility to trip Baraulia circuit 1 end breaker unnecessarily, if any fault occurs on Kulshi to Madunaghat line. So, it is recommended that, the zone 2 time setting of Baraulia circuit 1 end relay should be set to time delay 0.4s -0.6s. In addition to, there is overlapping between zone 3 and zone 2 of Kulshi – Madunaghat feeders. Therefore, there is loss selectivity with zone 2 of Kulshi - Madunaghat lines i.e. any fault occurs within zone 2 reach of Kulshi – Madunaghat lines thereby it may trip Baraulia end breaker unnecessarily. There is loss of selectivity with zone 2 of Kulshi – Halishahar feeder which is depicted in coordination curve [Ref. Figure 7.9]. So, the zone 3 delay time should be made long enough to be selective with the zone 2 of adjoining line sections. A 0.8s s interval is recommended. 7.3.17 Halishahar – Kulshi Feeder The existing zone settings are accurate of this feeder. From Coordination curve [Ref. Figure 7.8], it is evident that, there is discrimination between zones of back-up protection on adjacent feeders. If the relay at Kulshi end does not operate properly during the fault 45 between the Madunaghat to Kulshi section and Kulshi to Baraulia section, the zone 2(up) back-up protection from Halishahar end will operate properly (Figure 7.8). Coordination Curve Madu-Kul Bar-Kul 1 Hal - Kul Kul - Hal Sikal2- Hal 1.5 1.2 0.9 0.6 Time 0.3 0 -0.3 -0.6 -0.9 -1.2 -1.5 Distance Figure 7.9 Coordination curves of Madunaghat – Kulshi – Halishahar, Baraulia – Kulshi 1 and Sikalbaha2 – Halishahar section 7.3.18 Baraulia – Kulshi 2 Feeder The existing zone settings are accurate of this feeder. From coordination curve [Ref. Figure 7.4], it is evident that, there is discrimination between zones of back-up protection on adjacent feeders. Coordination Curve 1 0.8 Time 0.6 0.4 0.2 0 Distance Sikal2 - Madu Madu-Hat Madu-Kul Figure 7.10 Coordination curves of Sikalbaha2 – Madunaghat – Hathazari and Kulshi 7.3.19 Sikalbaha2 – Halishahar Feeder 46 From calculated zone settings [Ref. Table 7.2], it is evident that, the existing settings are accurate of this feeder. From Coordination curve [Ref. Figure 7.9], there is selectivity with zone 2 and zone 3 of adjacent feeder (Halishahar – Kulshi). Coordination Curve 1 0.8 Time 0.6 0.4 0.2 0 Distance Bar - Hat Kul - Bar Hat - Mad Figure 7.11 Coordination curves of Kulshi – Baraulia – Hathazari – Madunaghat after time grading 7.3.20 Sikalbaha2 – Madunaghat Feeder From calculated zone settings [Ref. Table 7.2], it can be seen that, the existing settings are accurate for both feeders. Considering time setting depicted in the coordination curve, Figure 7.10, it is evident that, there is overlapping with zone 3 of Madunaghat – Hathazari feeder. Since, the adjacent line (Madunaghat – Hathazari) is short, zone 3 delay time should be made long enough to be selective with the zone 3 of adjoining line section to avoid sequential or time delayed clearance of the fault at the terminal remote from the fault. Although, it seems there is discrimination between zones 2 of back-up protection on adjacent feeder, but according to article 6.1.3, it may need to be increased slightly. A 0.5s interval is recommended for zone 2 and 1.0s for zone 3. 47 7.3.21 Minimum Relay Voltages for a Fault at the Zone 1 Reach Point Table7.3 Minimum relay voltage requirements for measurement of faults Name of Grid S/S Madunaghat Name of Feeder Minimum relay voltage for a phase fault, V (Zone 1 reach point) 14.38 14.38 19.51 19.27 23.51 23.51 17.07 16.07 17.73 12.31 12.32 8.63 8.63 15.85 15.85 15.16 17.36 12.63 12.63 17.18 14.62 23.11 23.11 20.96 Minimum relay voltage for a ground fault, V (Zone 1 reach point) 10.366 10.366 13.79 13.39 16.505 16.505 11.247 10.97 11.679 8.01 8.013 5.63 5.63 10.98 10.98 9.87 9.618 8.436 8.436 11.7 9.13 16.28 16.28 10.344 Kulshi Hathazari Baraulia Halishahar Sikalbaha2 Hathazari – 1 Hathazari – 2 Kulshi – 1 Kulshi – 2 Sikalbaha2 – 1 Sikalbaha 2– 2 Baraulia – 1 Baraulia – 2 Halishahar Madunaghat – 1 Madunaghat - 2 Madunaghat – 1 Madunaghat - 2 Baraulia – 1 Baraulia – 2 Kulshi – 1 Kulshi – 2 Hathazari – 1 Hathazari – 2 Kulshi Sikalbaha2 Madunaghat – 1 Madunaghat - 2 Halishahar For all distance relays that are used for a network is required minimum relay voltages to measure phase faults and ground faults. SHPM 101 (GEC, England), REL 316*4 (ABB, Switzerland) and LZ type distance relays are used of the network that is selected for case study. For ±5 % reach accuracy with the zone 1 multiplier setting set to unity QUADRAMHO (SHPM) requires at least 2.05 volts for ground fault measurement or at least 3.55 volts for phase fault measurement. In case of REL 316*4 the minimum voltage requires at least 2.8 volts for ground fault measurement and 4 volts for phase fault measurement. The maximum zone 1 multiplier is 1.122 in case of Madunaghat – Kulshi circuit 1 for this network. Thus the required voltages for ±5 % reach accuracy are: 1.122 × 2.05 = 2.5 volts for ground faults (for SHPM 101 relay) 48 1.122 × 3.55 = 4.33 volts for phase faults (In case of SHPM 101) Both voltage requirements are met in this network [Ref. Table 7.3] 7.3.22 Proposed Time Settings Table7.4 The proposed time settings of distance relays for existing network Name of Grid S/S Name of Feeder TZ1 In Second Time Setting (TZ) TZ2 In Second TZ3 In Second Madunaghat End Hathazari – 1 Hathazari – 2 Kulshi – 1 Kulshi – 2 Sikalbaha2-1 Sikalbaha 2-2 0 0 0 0 0 0 0.1 0.1 0.03 0 0.1 0 0 0 0 0.03 0 0 0 0.1 0 0 0 0 0.4 0.4 0.4 0.4 0.4 0.4 0.6 0.6 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.5 0.5 0.6 0.4 0.5 0.5 0.4 0.8 0.8 0.8 0.8 0.8 0.8 1.2 1.2 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.9 0.9 1.2 0.8 1.0 1.0 0.8 Kulshi End Madunaghat-1 Madunaghat-2 Baraulia – 1 Baraulia – 2 Halishahar Hathazari End Madunaghat-1 Madunaghat-2 Baraulia – 1 Baraulia – 2 Baraulia End Kulshi – 1 Kulshi – 2 Hathazari – 1 Hathazari – 2 Halishahar End Kulshi Sikalbaha2 Sikalbaha2 End Madunaghat-1 Madunaghat-2 Halishahar 49 7.4 Auto Recloser and DEF About 80-85% of faults on overhead transmission lines are transient in nature. These faults disappear if the line CB’s are tripped mo mentarily to isolate the line and permits the arc to extinguish. Therefore, single shot Auto Reclosing are used to increase the stability and prevents the generators from drifting apart of the network. But if we see the coordination curves (reach characteristics) at both the ends of the protected line, it can be easily seen that only 60% of the line gets high speed distance protection (In case of 85 % of protected line setting, 70 % gets high speed). The remainder 40% - 30 % of the line length falls in the zone 2 region which is delayed one. If there is a fault on existing system beyond the zone 1 reach of protected line, the line CB’s at both ends will not be tripped and reclosed simultaneously. Therefore, there will be an effective reduction in the dead time which may jeopardize the chances of a successful reclosure. So, a carrier based distance schemes or a temporary extension of zone 1 can be employed for simultaneous tripping of CB’s at both ends. Pilot relaying with carrier signal is widely used for the protection of transmission line. In case of pilot relaying, the carrier transmitter injects the carrier information into the line at approximately the speed of light. Apparently, the time settings of DEF (67G) relay of the existing network are correct which used for relay back up during grounds faults. Although the time setting of E/F relay is instantaneous but the time interval is made long enough [Ref. Table 3.6], therefore it will response if the zone 2 of distance relay fails to trip. Due to time constraint, it was not possible to review of coordination of DEF’s which are used at different locations. It also needs to review of coordination of O/C relays between 33 KV (downstream) sides and 132 KV (upstream) sides. 50 Chapter 8 CONCLUSION AND RECOMMENDATIONS The coordination was made for a real 132/33 KV grid transmission network, besides the load flow and short circuit analysis are both taken into account. The coordination curves were made for this network from which the loss of selectivity between adjacent feeders can be observed. Where long feeders are followed by short feeders, it has taken care to ensure discrimination between the zones of back-up protection on adjacent feeders. The operating time settings of zone 2 and zone 3 are made long enough to be selective with zone 2 and zone 3 of adjacent line section and basic principle are considered to ensure selectivity for proper coordination. The minimum relay voltage at the zone 1 reach point of this network which is require for proper measurement of phase and ground faults are measured. The proposed zone settings and time settings are tabulated in chapter 7 for this network. The justification of proposed settings for this network are discussed in chapter 7.After scrutinizing, it is recommended that, existing relay settings should be set according to proposed settings thereby it would be possible to get optimum protection by using the existing relay. In case of REL 316*4 and LZ relays, there are no offset MHO facilities. Therefore some buses are not getting zone back up protection behind the relaying point and proper power swing blocking. This study proposes the proper coordination of relay thereby relay mal-operation will not be happened during the fault. It will be increased the availability of power in terms of reliability of the network. Carrier aided pilot relaying schemes are proposed for the successful reclosing of the network during the transient fault. It will be increased the power stability and prevent the generators from drifting apart. 51 The reliability analysis of a transmission network and the effect of power swing on relay performance are further scopes of this study. After going through the above analysis it is recommended to do the following for existing network: 1. In case of Madunaghat – Hathazari (1 & 2) feeders, the zone 3 setting can be set to reach up to 1.26 ohm to provide complete back-up protection on adjacent feeders and cover underreach which may arise due to arc fault resistance or transducers errors. 2. In case of zone 3 setting of Hathazari – Madunaghat (1 & 2) feeders, it can be extending up to 5.04 ohm. 3. The existing zone settings of Hathazari – Baraulia (1 & 2) feeders should be adjusted in accordance with proposed zone settings. 4. The operating time of zone 2 and zone 3 settings at Baraulia end relays (Baraulia – Hathazari feeder) can be adjusted with some additional time for selectivity. A 0.5 s for zone 2 and 0.9 s for zone 3 is recommended. 5. The existing zone 3 setting of Kulshi – Madunaghat 1 feeder should be set to reach 0.85 ohm. 6. The zone 2 time setting at Kulshi end relay of Kulshi – Baraulia 1 circuit should be set to time delay 0.4 s. A 0.8 s time interval is recommended for zone 3. 7. A 0.5s time interval is recommended for zone 2 and 1.0s for zone 3 settings of Sikalbaha2 – Madunaghat feeders. 8. The zone 2 and zone 3 time settings of Baraulia circuit 1 end relay of Baraulia – Kulshi 1 feeder should be set to time delay 0.4s and 0.8 s respectively to avoid unnecessary tripping when fault occurs on Kulshi- Madunaghat or Kulshi – Halishahar feeder. 9. There is unnecessarily additional time delay for the zone 2 of Kulshi – Halishahar feeder. The time interval of the zone 2 and zone 3 can be set 0.4 s and 0.8 s respectively. 10. Since there is no facility of reverse zone 3 setting in LZ32 and LZ411 type of distance relays, it should be replaced by modern distance relays to get optimum protection. 52 11. For perfect auto reclosing of the network, The CB’s of both ends should trip simultaneously. In this case, carrier aided pilot relaying schemes should be provided. 12. Since the main aim is to provide optimum protection of the network and thereby increases the stability and reliability of the system, it is highly recommended to afford pilot relaying schemes to achieve high speed protection. 13. As far my knowledge, PGCB was not preparing the coordination curve s of the existing network, therefore it is recommended that, the coordination curve should be prepared from which it would be possible to see whether there is proper selectivity between zones of protection on adjacent feeder or not. 14. For successful application of protection devices, a standard test sheets should be prepared for all routine test, a suggested record sheet for routine test of distance relay is given in appendix (E). 53 BIBLIOGRAPHY 1) William D. Stevenson, Jr., Elements of Power System Analysis, McGraw-Hill Book Company, Fourth Edition, 1982. 2) G.E. Alexander, J.G. Andrichak, W.Z. Tyska and S.B. Wilkinson, Effects of Load Flow on Relay Performance, GEC, 39th Annual Texas A&M Relay Conference, April 14-16, 1986. 3) Herbert A. Fleck and Frank J. Mercede, Using Short-Circuit Currents to perform a Protective Device Coordination Study, IEEE Industry Application Magazine, 2000. 4) Instruction Manual of QUADRAMHO relay, SHPM 101 types, GEC Measurements, England. 5) J.B Royle, Analysis and Protection of Power System Course, T & D, Energy Automation & Information, England. 6) Instruction Manual of REL 316*4, REL 512, ABB Application Note, Switzerland. 7) F E Wellman in collaboration with H.G. Bell and J.W. Hodgkiss, The Protective Gear Handbook, Sir Isaac Pitman and Sons Ltd, London, 1968. 8) Badri Ram and D N Vishwakarma, Power System Protection and Switchgear, Tata McGraw-Hill Publishing Company Limited, New Delhi, 1995. 9) B Ravindranath and M Chander, Power System Protection and Switchgear, New Age International (P) Limited, New Delhi, 2003. 10) Y.G. Paithankar and S.R. Bhide, Fundamentals of Power System Protection, Prentice-Hall of India Private Limited, New Delhi, 2003. 11) M V Deshpande, Switchgear and Protection, Tata McGraw-Hill Publishing Company Limited, New Delhi, 1991. 54 12) L.P Singh, Digital Protection, New Age International (P) Limited, New Delhi, Second Edition, 1997. 13) Arne T Holen, Power System Analysis, Norwegian University of Science and Technology, Spring 2005. 14) Edward Wilson Kimbark, Power System Stability, Volume II, IEEE Press Power Systems Engineering Series, John Wiley & Sons Inc., Publication, 2004. 15) Bharat Heavy Electricals Limited, Handbook of Switchgear, Tata McGraw-Hill Publishing Company Limited, New Delhi, 2005. 16) V.K. Mehta, Principles of Power System, S. Chand & Company, Ltd, New Delhi,1995 17) Gunter G. Seip, Electrical Installations Handbook, Part 1, Siemens, Germany. 18) G.E Alexander and J.G. Andrichak, Application of Phase and Ground Distance Relays to Three Terminal Lines, MULTILIN, GE Protection & Control. 19) Demetrios A. Tziouvaras and Daqing Hou, Out-of-Steps Protection Fundamentals and Advancements, Schweitzer Engineering Laboratories, Inc. USA. 20) http://www.geindustrial.com/multilin/notes/artsci/art14.pdf, Line Protection with Distance Relays, Chapter 14. 21) http://www.adb.org/AnnualMeeting/2002/Seminars/presentations/iqbal_presentati on.pdf 22) http://www.bpdb.gov.bd/xmission_line.htm 23) http://www.eng-tips.com/viewthread.cfm?qid=133396&page=1 24) http://www.aeso.ca/files/AIES_Protection_Standard_Revision_0_2004-12-01.pdf 25) www.selinc.com/transpg.htm 26) http://xnet.rrc.mb.ca/janaj/differential_protection.htm 55 APPENDIX A Single Line Diagram HATHAZARI MADUNAGHAT SIKALBAHA 2 SIKALBAHA 1 KULSHI HALISHAHAR BARAULIA 33 KV BUS Figure A.1 Single line diagram of the existing Network HATHAZARI 130.560 kV 0.000 mvar 0.989 pu MADUNAGHAT 132.000 kV 184.146 mvar 1.000 pu SIKALBAHA 2 131.605 kV 0.000 mvar 0.997 pu SIKALBAHA 1 11.264 kV 35.000 mvar 1.024 pu KULSHI 129.842 kV 0.000 mvar 0.984 pu BARAULIA 129.296 kV 0.000 mvar 0.980 pu 33 KV BUS 31.553 kV 0.000 mvar 0.956 pu HALISHAHAR 129.453 kV 0.000 mvar 0.981 pu Figure A.2 Single line diagram with voltage level 56 A.3 Busbar Configuration of Grid S/S HATHAZARI 362 A MADUNAGHAT 362 A 55 A SIKALBAHA 2 SIKALBAHA 1 391 A KULSHI 391 A 55 A 382 A 110 A 90% 81% 242 A 242 A 92 A 92 A HALISHAHAR BARAULIA 33 KV BUS A.4 Single line diagram with current level of different line sections 57 A.5 Manufacturer and specification of Existing Circuit Breaker Name of Grid S/S Name of Feeder Manufacturer & Type of CB Breaker Specification Rated Voltage, KV Normal Current, A S/C Breaking Current, KA Madunaghat End Hathazari – 1 Hathazari – 2 Kulshi – 1 Kulshi – 2 Sikalbaha2 – 1 Sikalbaha 2– 2 Kulshi End Madunaghat – 1 Madunaghat - 2 Baraulia – 1 Baraulia – 2 Halishahar Hathazari End Madunaghat – 1 Madunaghat - 2 Baraulia – 1 Baraulia – 2 Baraulia End Kulshi – 1 Kulshi – 2 Hathazari – 1 Hathazari – 2 Halishahar End Kulshi Sikalbaha2 Sikalbaha2 End Madunaghat – 1 Madunaghat - 2 Halishahar Siemens, Germany, 3AQ1 EG, (SF6 ) Fuji electric, Japan, BAP 514, (SF6 ) Siemens, Germany, 3AQ1 EG, (SF6 ) Siemens, Germany, 3AQ1 EG, (SF6 ) S & S, Switzerland, HGF 112/1, (SF6 ) BBC, Switzerland, ELF SF2-1, (SF6 ) BBC, Switzerland, ELF SF2-1, (SF6 ) S & S, Switzerland, HGF 112/1, (SF6 ) Fuji electric, Japan, BAP 514, (SF6 ) S & S, Switzerland, HGF 112/1, (SF6 ) S & S, Switzerland, HGF 112/1, (SF6 ) BBC, Switzerland, ELF SF2-1, (SF6 ) Siemens, Germany, 3AQ1 EG, (SF6 ) Fuji electric, Japan, BAP 514, (SF6 ) Fuji electric, Japan, BAP 514, (SF6 ) Siemens, Germany, 3AQ1 EG, (SF6 ) S & S, Switzerland, HGF 112/1, (SF6 ) S & S, Switzerland, HGF 112/1, (SF6 ) S & S, Switzerland, HGF 112/1, (SF6 ) Siemens, Germany, 3AQ1 EG, (SF6 ) Siemens, Germany, 3AQ1 EG, (SF6 ) Fuji electric, Japan, BAP 514, (SF6 ) Fuji electric, Japan, BAP 514, (SF6 ) Siemens, Germany, 3AQ1 EG, (SF6 ) 145 145 145 145 145 145 145 145 145 145 145 145 145 145 145 145 145 145 145 145 145 145 145 145 3150 1200 3150 3150 2500 2000 2000 2500 1200 2500 2500 2000 3150 1200 1200 3150 2500 2500 2500 3150 3150 1200 1200 3150 31.5 31.5 31.5 31.5 31.5 31.5 31.5 31.5 31.5 31.5 31.5 31.5 31.5 31.5 31.5 31.5 31.5 31.5 31.5 31.5 31.5 31.5 31.5 31.5 58 A.6 Some important protection terminology Discrimination or Selectivity: Discrimination or selectivity is the attribute of protective gear whereby only the faulty part of the electrical system is disconnected [7]. Sensitivity: Sensitivity is a function of the volt ampere input to protective device to cause operation, or in other words a measure of the burden of the device at its setting; the lower the burden the higher is the sensitivity [7]. Stability: Stability is the attribute of a protective device whereby it remains passive under all conditions, whether of fault or otherwise, except those that specially call for its operation [7]. Setting: The value of the actuating quantity (current, voltage, power, etc.) at which the relay set to operate. Operating time: It is the time which elapses from the instant at which the actuating quantity exceeds the relays pick-up value to the instant at which the relay closes its contacts [8]. Reset time: It is the time which elapses from the moment the actuating quantity falls below its reset value to the instant when the relay comes back to its normal position. Overshot time: The time during which stored operating energy is dissipated after the characteristic quantity has been suddenly restored from a specified value to the value which it had at the initial position of the relay [9]. Reach: This term is mostly used in connection with distance relays. The reach of a relay is the maximum distance a fault can be from the relay to cause operation [7]. In other words it is the maximum length of the line up to which the relay can protect. Overreach: Sometimes a relay may operate even when a fault point is beyond its present reach (i.e. protected length). This phenomenon is called overreach. Underreach: Sometimes a relay may fail to operate even when the fault point is within its reach, but it is at the far end of the protected line. This phenomenon is called underreach. 59 APPENDIX B Short Circuit Analysis Results B.1 Summary of fault current level: Data set: MADUNAGHAT. Year of calculation 2005. --------------------------------------------------------------Largest short-circuit current. Node Voltage Un(kV) 3-phase Ieff(kA) 2-phase Ieff(kA) Capacity Sk(MVA) Cosphi ---------------------------------------------------------------------------------------------------------33 KV BUS BARAULIA HALISHAHAR HATHAZARI KULSHI SIKALBAHA 1 SIKALBAHA 2 33.000 132.000 132.000 132.000 132.000 11.000 132.000 24.521 11.542 9.747 12.859 12.594 16.301 75.571 11.815 21.236 9.995 8.441 11.137 10.907 14.117 65.447 10.232 1401.562 2638.758 2228.447 2940.040 2879.397 3726.816 1439.826 2701.311 0.130 0.077 0.088 0.057 0.059 0.004 0.102 0.069 MADUNAGHAT 132.000 --------------------------------------------------------------------------------------------------------Max 75.571* 65.447 3726.816 Min 9.747 8.441* 1401.562 B.2 Contribution of fault current during fault at Kulshi Grid: Data set: MADUNAGHAT. Year of calculation 2005. ------------------------------------------------------------Largest short-circuit current. Short-circuit in : KULSHI Power to Node Node name Fault location: MADUNAGHAT MADUNAGHAT BARAULIA Voltage (kV) Pre Fault 129.820 132.000 132.000 129.282 Fault 0.000 31.360 31.360 11.934 fault location kA 12.594 3.586 3.586 1.344 Short-circuit capacity MVA 2879.40 Voltage prior to fault: 129.820 kV --------------------------------------------------------------------------------------------------- 60 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: Data set: MADUNAGHAT. Year of calculation 2005. --------------------------------------------------------------Largest short-circuit current. Short-circuit in : MADUNAGHAT Voltage prior to fault : 132.000 kV Power to Node Node name Fault location: Generator: KULSHI KULSHI HATHAZARI HATHAZARI Voltage (kV) Pre Fault 132.000 132.000 129.820 129.820 130.554 130.554 Fault 0.000 132.000 0.862 0.862 0.229 0.229 5.710 5.710 fault location kA 16.301 14.871 0.099 0.099 0.037 0.037 0.515 0.515 Short-circuit capacity MVA 3726.82 -------------------------------------------------------------------------------------- SIKALBAHA 2 131.600 SIKALBAHA 2 131.600 ---------------------------------------------------------------------------------------B.4 Contribution of fault current during fault at Sikalbaha2 Grid: Data set: MADUNAGHAT. Year of calculation 2005. ---------------------------------------------------------------Largest short-circuit current. Short-circuit in : SIKALBAHA 2 Voltage prior to fault : 131.600 kV Power to Node Node name Fault location: MADUNAGHAT Voltage (kV) Pre Fault 131.600 132.000 Fault 0.000 41.193 fault location kA 11.815 3.716 Short-circuit capacity MVA 2701.31 --------------------------------------------------------------------------------------------- 61 HALISHAHAR MADUNAGHAT SIKALBAHA 1 SIKALBAHA 1 129.438 132.000 11.264 11.264 18.917 41.193 2.089 2.089 1.954 3.716 0.679 0.679 ------------------------------------------------------------------------------------------------Sum 10.745 B.5 Contribution of fault current during fault at Hathazari Grid: Data set: MADUNAGHAT. Year of calculation 2005. ----------------------------------------------------------------Largest short-circuit current. Short-circuit in : HATHAZARI Power to Node Node name Fault location: MADUNAGHAT BARAULIA BARAULIA MADUNAGHAT Voltage (kV) Pre Fault 130.554 132.000 129.282 129.282 132.000 Fault 0.000 28.729 9.989 9.989 28.729 fault location kA 12.859 4.636 1.209 1.209 4.636 Short-circuit capacity MVA 2940.04 Voltage prior to fault : 130.554 kV ------------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------------Sum 11.690 B.6 Contribution of fault current during fault at Baraulia Grid: Data set: MADUNAGHAT. Year of calculation 2005. ------------------------------------------------------------Largest short-circuit current. Short-circuit in : BARAULIA Power to Node Node name Fault location: HATHAZARI KULSHI Voltage (kV) Pre Fault 129.282 130.554 129.820 Fault 0.000 22.714 22.179 fault location kA 11.542 2.749 2.497 Short-circuit capacity MVA 2638.76 Voltage prior to fault : 129.282 kV ----------------------------------------------------------------------------------------- 62 KULSHI HATHAZARI 129.820 130.554 22.179 22.714 2.497 2.749 ----------------------------------------------------------------------------------------------Sum 10.492 B.7 Contribution of fault current during fault at Halishahar Grid: Data set: MADUNAGHAT. Year of calculation 2005. ------------------------------------------------------------Largest short-circuit current. Short-circuit in : HALISHAHAR Voltage prior to fault: 129.438 kV Power to Node Node name Fault location: SIKALBAHA 2 KULSHI Voltage (kV) Pre Fault 129.438 131.600 129.820 Fault 0.000 38.816 40.150 fault location kA 9.747 4.010 4.859 Short-circuit capacity MVA 2228.45 ----------------------------------------------------------------------------------------------- -----------------------------------------------------------------------------------------------Sum 8.869 B.8 Contribution of fault current during fault at 33 KV Bas : Data set: MADUNAGHAT. Year of calculation 2005. ---------------------------------------------------------------Largest short-circuit current. Short-circuit in : 33 KV BUS Power to Node Node name Fault location: KULSHI KULSHI Voltage (kV) Pre Fault 27.236 129.820 129.820 Fault 0.000 68.063 68.063 fault location kA 24.521 11.146 11.146 Short-circuit capacity MVA 1401.56 Voltage prior to fault : 27.236 kV ---------------------------------------------------------------------------------------- ---------------------------------------------------------------------------------------Sum 22.292 63 B.9 FAULT LEVEL OF DIFFERENT GRID SUBSTATIONS Name of Grid S/S Pre Fault Voltage, KV Existing Three Phase Current, KA Calculated Three Phase Current, KA 16.30 12.86 11.815 12.59 11.54 9.747 Existing Earth Current, KA MADUNAGHAT HATHAZARI SIKALBAHA 2 KULSHI BARAULIA HALISHAHAR 132 132 132 132 132 132 13.6 15.3 10.6 13 13.5 9.9 12.2 15 9.4 10.2 11 6.7 64 APPENDIX C Power Flow Analysis Results C.1 Power flow in line sections Node From Node To Loadflow MW MVAr Power loss kW kVAr Curr. Load A 389 389 361 361 52 52 381 240 240 91 91 109 (%) 50 50 46 46 7 7 49 31 31 12 12 14 -------------------------------------------------------------------------------------------------------MADUNAGHAT - KULSHI MADUNAGHAT - KULSHI MADUNAGHAT - HATHAZARI MADUNAGHAT - HATHAZARI 80.653 37.823 80.653 37.823 74.573 35.829 74.573 35.829 5.103 5.103 574.86 1431.29 574.86 1431.29 351.08 792.25 351.08 792.25 13.77 -979.76 13.77 -979.76 300.67 1445.03 206.71 206.71 55.44 55.44 MADUNAGHAT - SIKALBAHA 2 10.905 MADUNAGHAT - SIKALBAHA 2 10.905 SIKALBAHA 2 - HALISHAHAR HATHAZARI - BARAULIA HATHAZARI - BARAULIA KULSHI KULSHI KULSHI - BARAULIA - BARAULIA - HALISHAHAR 76.232 41.985 49.222 22.928 49.222 22.928 18.518 18.518 24.112 9.147 9.147 4.442 32.88 -672.24 32.88 -672.24 42.60 -579.52 --------------------------------------------------------------------------------------------------------- C.2 Power flow in two-winding transformers Node From Node Til Loadflow MW MVAr Power loss kW kVAr No-ld.l kW 0 0 0 0 TD. Load (%) 0.0 0.0 0.0 0.0 (%) 81 81 90 90 ---------------------------------------------------------------------------------------------------------------SIKALBAHA 1 - SIKALBAHA 2 SIKALBAHA 1 - SIKALBAHA 2 KULSHI KULSHI - 33 KV BUS - 33 KV BUS 30.000 17.500 30.000 17.500 49.505 25.024 49.505 25.024 275.85 1379.23 275.85 1379.23 504.77 2523.84 504.77 2523.84 ---------------------------------------------------------------------------------------------------------------- 65 Summary 8 node Total generation : : MW 447.263 443.000 0.000 4.263 0.962 4.263 2.702 1.561 Mvar 219.146 209.220 0.000 9.926 -------------------------------------------------------------Total voltage ind. load : Total voltage dep. load : Total transmission losses: Losses in percent of load: Total loss in 16 sect. : Total loss in Total loss in 12 LK : 4 T2 : ------------------------------------------------------------- ---------------------------------------------------------------------------------------9.926 0.000 (No-load losses) 2.119 7.806 0.000 ---------------------------------------------------------------------------------------Data set : MADUNAGHAT. Year of calculation 2005. ------------------------------------------------------------- C.3 Summary : MW Generation MADUNAGHAT Total generation Total voltage ind. load Total voltage dep. load : : : : 387.883 447.263 443.000 0.000 2.702 1.561 4.263 Mvar 187.229 219.146 209.220 0.000 2.119 7.806 0.000 9.926 0.000 (No-load losses) : - MADUNAGHAT : - 33 KV BUS 4.39 % 49.51 % Total losses in line sections : Total losses in T2 Total electrical losses Max. voltage drop Heaviest loaded line Heaviest loaded T2 : : : 33 KV BUS : KULSHI : KULSHI : 89.51 % 66 APPENDIX D D.1 Zone Setting Results Madunaghat - Sikalbaha2, Circuit 1 For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 Required zone 1 reach: Secondary The relay coarse reach: Zph required Zone 1 multiplier setting: Actual Zone 1 Setting Angle 0 0.341 76.1 2 0.32 80 3 1.067 4 0.339 80 Selecting Zone 2 Setting 1 2 Required zone 2 reach : Secondary required Zone 2 multiplier setting: Actual zone 2 setting: Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) required Zone 3 multiplier setting: Actual zone 3 forward setting: 4 Required zone 3 reach: Secondary (reverse) required Zone 3 multiplier setting: Actual zone 3 reverse setting: 0.598 1.867 3 0.576 80 0.854 2 2.669 3 0.864 0.085 80 5 6 0.265 0.08 80 67 Madunaghat - Sikalbaha2, Circuit 2 For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 Required zone 1 reach: Secondary The relay coarse reach: Zph required Zone 1 multiplier setting: Actual Zone 1 Setting Angle 0 0.341 76.1 2 0.32 80 3 1.067 4 0.339 80 Selecting Zone 2 Setting 1 2 Required zone 2 reach: Secondary required Zone 2 multiplier setting: Actual zone 2 setting: 0.598 1.867 3 0.576 80 Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) required Zone 3 multiplier setting: Actual zone 3 forward se tting: 4 Required zone 3 reach: Secondary (reverse) required Zone 3 multiplier setting: Actual zone 3 reverse setting: 0.854 2 2.669 3 0.864 0.085 80 5 0.265 6 0.08 80 68 Madunaghat – Hathazari, Circuit 1 For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 Required zone 1 reach: The relay coarse reach: Zph required Zone 1 multiplier setting: Actual Zone 1 Setting Angle 0 0.382 69.5 2 0.36 70 3 1.060 4 0.374 70 Selecting Zone 2 Setting 1 2 Required zone 2 reach: Secondary required Zone 2 multiplier setting: Actual zone 2 setting: 0.795 2.208 3 0.792 70 Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) required Zone 3 multiplier setting: Actual zone 3 forward setting: 4 Required zone 3 reach: Secondary (reverse) required Zone 3 multiplier setting: 1.272 2 3.533 3 1.260 0.094 70 5 0.260 6 Actual zone 3 reverse setting: 0.09 70 69 Madunaghat – Hathazari, Circuit 2 For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 Required zone 1 reach: The relay coarse reach: Zph required Zone 1 multiplier setting: Actual Zone 1 Setting Angle 0 0.382 69.5 2 0.36 70 3 1.060 4 0.374 70 Selecting Zone 2 Setting 1 2 Required zone 2 reach: Secondary required Zone 2 multiplier setting: Actual zone 2 setting: 0.795 2.208 3 0.792 70 Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) required Zone 3 multiplier setting: Actual zone 3 forward setting: 4 Required zone 3 reach: Secondary (reverse) required Zone 3 multiplier setting: 1.272 2 3.533 3 1.260 0.094 70 5 0.260 6 Actual zone 3 reverse setting: 0.09 70 70 Madunaghat – Kulshi, Circuit 1 For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 Required zone 1 reach: Secondary The relay coarse reach: Zph required Zone 1 multiplier setting: Actual Zone 1 Setting Angle 0 0.269 76.1 2 0.24 80 3 1.122 4 0.269 80 Selecting Zone 2 Setting 1 2 Required zone 2 reach: Secondary required Zone 2 multiplier setting: Actual zone 2 setting: 0.507 2.114 3 0.504 80 Selecting Zone 3 Setting 1 Required zone 3 reach:Secondary (forward) required Zone 3 multiplier setting: Actual zone 3 forward setting: 4 Required zone 3 reach:Secondary (reverse) required Zone 3 multiplier setting: Actual zone 3 reverse setting: 0.764 2 3.183 3 0.768 0.067 80 5 0.280 6 0.06 80 71 Madunaghat – Kulshi, Circuit 2 For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 Required zone 1 reach: The relay coarse reach: Zph required Zone 1 multiplier setting: Actual Zone 1 Setting Angle 0 0.538 76.1 2 0.52 80 3 1.036 4 0.530 80 Selecting Zone 2 Setting 1 2 Required zone 2 reach: Secondary required Zone 2 multiplier setting: Actual zone 2 setting: 1.015 1.952 3 0.988 80 Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) required Zone 3 multiplier setting: Actual zone 3 forward setting: 4 Required zone 3 reach: Secondary (reverse) required Zone 3 multiplier setting: Actual zone 3 reverse setting: 1.528 2 2.938 3 1.508 0.133 80 5 0.255 6 0.13 80 72 Hathazari - Baraulia, Circuit 1 For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 Required zone 1 reach: Secondary The relay coarse reach: Zph required Zone 1 multiplier setting: Actual Zone 1 Setting Angle 0 1.908 75.2 2 1.8 75 3 1.060 4 1.872 75 Selecting Zone 2 Setting 1 2 Required zone 2 reach: Secondary required Zone 2 multiplier setting: Actual zone 2 setting: 3.667 2.037 3 3.600 75 Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) required Zone 3 multiplier setting: Actual zone 3 forward setting: 4 Required zone 3 reach: Secondary (reverse) required Zone 3 multiplier setting: Actual zone 3 reverse setting: 5.590 2 3.105 3 5.580 0.468 75 5 0.260 6 0.45 75 73 Hathazari - Baraulia, Circuit 2 For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 Required zone 1 reach: Secondary The relay coarse reach: Zph required Zone 1 multiplier setting: Actual Zone 1 Setting Angle 0 1.908 75.2 2 1.8 75 3 1.060 4 1.872 75 Selecting Zone 2 Setting 1 2 Required zone 2 reach: Secondary required Zone 2 multiplier setting: Actual zone 2 setting: 3.667 2.037 3 3.600 75 Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) required Zone 3 multiplier setting: Actual zone 3 forward setting: 4 Required zone 3 reach: Secondary (reverse) required Zone 3 multiplier setting: Actual zone 3 reverse setting: 5.590 2 3.105 3 5.580 0.468 75 5 0.260 6 0.45 75 74 Hathazari - Madunaghat, Circuit 1 For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 Required zone 1 reach: Secondary The relay coarse reach: Zph required Zone 1 multiplier setting: Actual Zone 1 Setting Angle 0 1.431 69.5 2 1.4 70 3 1.022 4 1.428 70 Selecting Zone 2 Setting 1 2 Required zone 2 reach: Secondary required Zone 2 multiplier setting: Actual zone 2 setting: 3.051 2.179 3 3.080 70 Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) required Zone 3 multiplier setting: Actual zone 3 forward setting: 4 Required zone 3 reach: Secondary (reverse) required Zone 3 multiplier setting: Actual zone 3 reverse setting: 4.944 2 3.531 3 5.040 0.357 70 5 0.255 6 0.35 70 75 Hathazari - Madunaghat, Circuit 2 For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 Required zone 1 reach: Secondary The relay coarse reach: Zph required Zone 1 multiplier setting: Actual Zone 1 Setting Angle 0 1.431 69.5 2 1.4 70 3 1.022 4 1.428 70 Selecting Zone 2 Setting 1 2 Required zone 2 reach: Secondary required Zone 2 multiplier setting: Actual zone 2 setting: 3.051 2.179 3 3.080 70 Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) required Zone 3 multiplier setting: Actual zone 3 forward setting: 4 Required zone 3 reach: Secondary (reverse) required Zone 3 multiplier setting: Actual zone 3 reverse setting: 4.944 2 3.531 3 5.040 0.357 70 5 0.255 6 0.35 70 76 Baraulia - Hathazari, Circuit 1 For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 Required zone 1 reach: Secondary The relay coarse reach: Zph required Zone 1 multiplier setting: Actual Zone 1 Setting Angle 0 0.509 75.2 2 0.48 75 3 1.060 4 0.499 75 Selecting Zone 2 Setting 1 2 Required zone 2 reach: Secondary required Zone 2 multiplier setting: Actual zone 2 setting: 0.875 1.822 3 0.816 75 Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) required Zone 3 multiplier setting: Actual zone 3 forward setting: 4 Required zone 3 reach: Secondary (reverse) required Zone 3 multiplier setting: Actual zone 3 reverse setting: 1.232 2 2.567 3 1.200 0.125 75 5 0.260 6 0.12 75 77 Baraulia - Hathazari, Circuit 2 For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 Required zone 1 reach: Secondary The relay coarse reach: Zph required Zone 1 multiplier setting: Actual Zone 1 Setting Angle 0 0.509 75.2 2 0.48 75 3 1.060 4 0.499 75 Selecting Zone 2 Setting 1 2 Required zone 2 reach: Secondary required Zone 2 multiplier setting: Actual zone 2 setting: 0.875 1.822 3 0.816 75 Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) required Zone 3 multiplier setting: Actual zone 3 forward setting: 4 Required zone 3 reach: Secondary (reverse) required Zone 3 multiplier setting: Actual zone 3 reverse setting: 1.232 2 2.567 3 1.200 0.125 75 5 0.260 6 0.12 75 78 Baraulia - Kulshi, Circuit 2 For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 Required zone 1 reach: Secondary The relay coarse reach: Zph required Zone 1 multiplier setting: Actual Zone 1 Setting Angle 0 0.547 75.3 2 0.52 75 3 1.052 4 0.541 75 Selecting Zone 2 Setting 1 2 Required zone 2 reach: Secondary required Zone 2 multiplier setting: Actual zone 2 setting: 1.020 1.962 3 1.040 75 Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) required Zone 3 multiplier setting: Actual zone 3 forward setting: 4 Required zone 3 reach: Secondary (reverse) required Zone 3 multiplier setting: Actual zone 3 reverse setting: 1.525 2 2.933 3 1.508 0.135 75 5 0.260 6 0.13 75 79 Kulshi - Baraulia, Circuit 2 For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 Required zone 1 reach: Secondary The relay coarse reach: Zph required Zone 1 multiplier setting: Actual Zone 1 Setting Angle 0 0.547 75.3 2 0.52 75 3 1.052 4 0.541 75 Selecting Zone 2 Setting 1 2 Required zone 2 reach: Secondary required Zone 2 multiplier setting: Actual zone 2 setting: 1.002 1.926 3 0.988 75 Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) required Zone 3 multiplier setting: Actual zone 3 forward setting: 4 Required zone 3 reach: Secondary (reverse) required Zone 3 multiplier setting: Actual zone 3 reverse setting: 1.479 2 2.844 3 1.508 0.135 75 5 0.260 6 0.13 75 80 Sikalbaha2 - Halishahar, Circuit For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 Required zone 1 reach: Secondary The relay coarse reach: Zph required Zone 1 multiplier setting: Actual Zone 1 Setting Angle 0 0.596 82.4 2 0.6 85 3 0.993 4 0.600 85 Selecting Zone 2 Setting 1 2 Required zone 2 reach: Secondary required Zone 2 multiplier setting: Actual zone 2 setting: 1.041 1.736 3 1.020 85 Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) required Zone 3 multiplier setting: Actual zone 3 forward setting: 4 Required zone 3 reach: Secondary (reverse) required Zone 3 multiplier setting: Actual zone 3 reverse setting: 1.578 2 2.630 3 1.620 0.150 85 5 0.250 6 0.15 85 81 Halishahar - Sikalbaha2 For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 Required zone 1 reach: Secondary The relay coarse reach: Zph required Zone 1 multiplier setting: Actual Zone 1 Setting Angle 0 0.596 82.9 2 0.56 85 3 1.064 4 0.594 85 Selecting Zone 2 Setting 1 2 Required zone 2 reach: Secondary required Zone 2 multiplier setting: Actual zone 2 setting: 1.110 1.983 3 1.176 85 Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) required Zone 3 multiplier setting: Actual zone 3 forward setting: 4 Required zone 3 reach: Secondary (reverse) required Zone 3 multiplier setting: Actual zone 3 reverse setting: 1.750 2 3.126 3 1.792 0.148 85 5 0.265 6 0.14 85 82 Kulshi - Madunaghat, Circuit 1 For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 2 Required zone 1 reach: Secondary Actual Zone 1 0.27 Angle 76.1 0 Setting: Z1PH Selecting Zone 2 Setting 1 3 Required zone 2 reach: Secondary Actual zone 2 0.27 76 0.456 setting: Z2PH Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) Actual zone 3 forward setting: 0.456 76 0.85 3 0.85 76 Kulshi - Madunaghat, Circuit 2 For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 2 Required zone 1 reach: Secondary Actual Zone 1 0.538 Angle 76.1 0 Setting: Z1PH Selecting Zone 2 Setting 1 3 Required zone 2 reach: Secondary Actual zone 2 0.538 76 0.91 setting: Z2PH Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) Actual zone 3 forward setting: 0.91 76 1.69 3 1.69 76 83 Kulshi – Halishahar For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 2 Required zone 1 reach: Secondary Actual Zone 1 0.608 Angle 76.3 0 Setting: Z1PH Selecting Zone 2 Setting 1 3 Required zone 2 reach: Secondary Actual zone 2 0.57 76 1.037 setting: Z2PH Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) Actual zone 3 forward setting: 1.08 76 1.679 3 1.64 76 Halishahar – Kulshi For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 2 Required zone 1 reach: Secondary Actual Zone 1 0.608 Angle 76.3 0 Setting: Z1PH Selecting Zone 2 Setting 1 3 Required zone 2 reach: Secondary Actual zone 2 0.572 76 1.03 setting: Z2PH Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) Actual zone 3 forward setting: 1.052 76 1.67 3 1.55 76 84 Kulshi - Baraulia, Circuit 1 For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 2 Required zone 1 reach: Secondary Actual Zone 1 0.547 Angle 75.3 0 Setting: Z1PH Selecting Zone 2 Setting 1 3 Required zone 2 reach: Secondary Actual zone 2 0.547 75 1.0 setting: Z2PH Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) Actual zone 3 forward setting: 1.0 75 1.48 3 1.48 75 Baraulia - Kulshi, Circuit 1 For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 2 Required zone 1 reach: Secondary Actual Zone 1 0.547 Angle 75.3 0 Setting: Z1PH Selecting Zone 2 Setting 1 3 Required zone 2 reach: Secondary Actual zone 2 0.547 75 1.02 setting: Z2PH Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) Actual zone 3 forward setting: 1.02 75 1.58 3 1.58 75 85 Sikalbaha2 - Madunaghat, Circuit1 For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 Required zone 1 reach: Secondary The relay coarse reach: Zph required Zone 1 multiplier setting: Actual Zone 1 Setting Angle 0 0.341 75.5 2 0.32 80 3 1.067 4 0.339 80 Selecting Zone 2 Setting 1 2 Required zone 2 reach: Secondary required Zone 2 multiplier setting: Actual zone 2 setting: 0.546 1.706 3 0.544 80 Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) required Zone 3 multiplier setting: Actual zone 3 forward setting: 4 Required zone 3 reach: Secondary (reverse) required Zone 3 multiplier setting: Actual zone 3 reverse setting: 0.725 2 2.265 3 0.736 0.085 80 5 0.265 6 0.08 80 86 Sikalbaha2 - Madunaghat, Circuit2 For phase to Phase Faults Selecting Zone 1 Setting Ohms 1 Required zone 1 reach: Secondary The relay coarse reach: Zph required Zone 1 multiplier setting: Actual Zone 1 Setting Angle 0 0.341 75.5 2 0.32 80 3 1.067 4 0.339 80 Selecting Zone 2 Setting 1 2 Required zone 2 reach: Secondary required Zone 2 multiplier setting: Actual zone 2 setting: 0.546 1.706 3 0.544 80 Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary (forward) required Zone 3 multiplier setting: Actual zone 3 forward setting: 4 Required zone 3 reach: Secondary (reverse) required Zone 3 multiplier setting: Actual zone 3 reverse setting: 0.725 2 2.265 3 0.736 0.085 80 5 0.265 6 0.08 80 87 Ground Fault Compensation Setting: Magnitude Kn = 0.517 (51% compensation) Angle 1.3 1 Madunaghat - Hathazari 1 Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.2 0.572 75.98 75 71.7 2 Madunaghat - Hathazari 2 Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.2 0.572 75.98 75 71.7 3 Madunaghat – Sikalbaha2 - 1 Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.116 0.454 75.98 85 81.26 4 Madunaghat - Sikalbaha2 - 2 Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.116 0.454 75.98 85 81.26 5 Madunaghat – Kulshi 1 Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.108 0.376 75.98 85 81.4 6 Madunaghat - Kulshi 2 Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.216 0.744 75.98 85 81.4 88 Ground Fault Compensation Setting: Magnitude Kn = 0.517 (51% compensation) Angle 1.3 1 Hathazari – Baraulia 1 Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.912 2.77 75.98 80 76.6 2 Hathazari – Baraulia 2 Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.912 2.77 75.98 80 76.6 3 Hathazari - Madunaghat 1 Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.708 2.13 75.98 75 71.65 4 Hathazari - Madunaghat 2 Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.708 2.13 75.92 75 71.65 5 Kulshi – Madunaghat 1 Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.108 0.376 75.98 85 81.4 6 Kulshi - Madunaghat 2 Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.216 0.744 75.98 85 81.4 89 Ground Fault Compensation Setting: Magnitude Kn = 0.517 (51% compensation) Angle 1.3 1 Baraulia - Hathazari 1 Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.212 0.709 75.98 80 76.48 2 Baraulia - Hathazari 2 Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.212 0.709 75.98 80 76.48 3 Baraulia - Kulshi1 Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.3 0.88 75.98 80 76.72 4 Baraulia – Kulshi 2 Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.216 0.755 75.98 80 76.4 5 Kulshi – Baraulia 1 Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.3 0.88 75.98 80 76.72 6 Kulshi - Baraulia 2 Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.216 0.755 75.98 80 76.4 90 Ground Fault Compensation Setting: Magnitude Kn = 0.517 (51% compensation) Angle 1.3 1 Sikalbaha2 – Madunaghat 1 Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.116 0.454 75.98 85 81.27 2 Sikalbaha2 - Madunaghat 2 Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.116 0.454 75.98 85 81.27 3 Kulshi – Halishahar Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.304 0.912 75.98 80 77.35 4 Halishahar – Kulshi Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.304 0.912 75.98 80 77.35 5 Sikalbaha2 – Halishahar Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.3 0.9 75.98 90 86.68 6 Halishahar - Sikalbaha2 Ground loop impedance: Actual Compensation setting Zn Coarse Ground loop setting: 0.603 0.3 0.892 75.98 90 86.6 91 D.2 Calculation of Maximum Source Impedance at Madunaghat and Sikalbaha2 (for real case) 1) Maximum source impedance at Madunaghat grid is when 400 MW source at Madunaghat is switched out, only one 30 MW source at Sikalbaha2 is switched in and only one of the parallel line between Madunaghat and Sikalbaha is switched in. Maximum Madunaghat positive sequence impedance = 2 × (0.54 + j6.17) + 16.1 ×(0. 0992 + j0.385) = 1.08 + j12.34 + 1.59 + j6.198 = 2.67 + j 18.53 = 18.72 ∠81.8 2) Maximum source impedance at Sikalbaha2 grid is when both 30 MW sources at Sikalbaha2 are switched out, 400 MW source at Madunaghat is switched in and only one of the parallel line between Madunaghat and Sikalbaha is switched in. Maximum Sikalbaha2 positive sequence impedance; = 1.115 + j12.75 + 1.59 + j6.198 = 2.705 + j18.94 3) Maximum Madunaghat zero sequence impedance; = 1.08 + j12.34 + 16.1× (0.24 + j0.985) = 4.94 + j28.19 4) Maximum Sikalbaha2 zero sequence impedance; = 1.115 + j12.75 + 16.1× (0.24 + j0.985) = 4.97 + j28.6 92 APPENDIX E E.1ROUTINE TEST RECORD DISTANCE RELAYS RELAY PATTERN………………. SERIAL NO……………… MAKER………………... INSTALLED ON…………………….. CIRCUIT AT………………….. SUBSTATION SETTINGS: Date Secondary Impedance Zone 1 Zone 2 Zone 3 Curve No. Terminal Nos. Rheostats B C Set by A RESULTS OF TESTS: Date Test Engineer Zone 1 Volts Amp. Zone 2 Volts Amp. Zone 3 Volts Amp. Notes Notes: Suggested record sheet for routine tests [4]. 93