IEEE C37 101 2006 GUIDE FOR GENERATOR GROUND PROT

C37.101 TM IEEE Guide for Generator Ground Protection IEEE Power Engineering Society Sponsored by the Power System Relaying Committee s version REDLINE REDLINE es from act chang ! Shows ex us version the previo ! Sh IEEE 3 Park Avenue New York, NY 10016-5997, USA 15 November 2007 m the pr e ou xact cha s e n ow fro vi g es IEEE Std C37.101™-2006 (Revision of IEEE Std C37.101-1993/Incorporates IEEE Std C37.101-2006/Cor1:2007) Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. This is a Redline Document produced by Techstreet, a business of Thomson Reuters. This document is intended to provide users with an indication of changes from one edition to the next. It includes a full-text version of the new document, plus an indication of changes from the previous version. Redlines are designed to save time and improve efficiencies by using the latest software technology to find and highlight document changes. More professionals are using valuable new technologies like redlines, to help improve outcomes in a fastpaced global business world. Because it may not be technically possible to capture all changes accurately, it is recommended that users consult previous editions as appropriate. In all cases, only the current base version of this publication is to be considered the official document. 445 Hoes Lane, Piscataway, NJ 08854 USA | http://standards.ieee.org | Tel. +1 732-981-0060 Fax +1 732-562-1571 Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Redline Processing Notes: 1. Red Text - Red strikethrough text denotes deletions. 2. Blue Text - Blue underlined text denotes modifications and additions. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. IEEE Std C37.101™-2006 (Revision of IEEE Std C37.101-1993/Incorporates IEEE Std C37.101-2006/Cor1:2007) IEEE Guide for Generator Ground Protection Sponsor Power System Relaying Committee of the IEEE Power Engineering Society Approved 15 September 2006 IEEE-SA Standards Board Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Abstract: The guide is intended to assist protection engineers in applying relays and relaying schemes for protection against stator ground faults on various generator grounding schemes. The existing guide is outdated due to rapid technology development. Hence, the revised guide includes new stator ground protection principles that have evolved with the use of new technologies in relay designs. Additional application examples are included, and other issues raised by the users are also addressed. The guide is not intended for the selection of generator or ground connection schemes. Keywords: generator grounding method, grounding scheme, hybrid ground protection, subharmonic injection scheme The Institute of Electrical and Electronics Engineers, Inc. 3 Park Avenue, New York, NY 10016-5997, USA Copyright © 2007 by the Institute of Electrical and Electronics Engineers, Inc. All rights reserved. Published 15 November 2007. Printed in the United States of America. Corrections were made to Equations (A.1), (A.2), (A.3), and (A.4) as required by IEEE Std C37.101-2006/Cor1:2007. IEEE is a registered trademark in the U.S. Patent & Trademark Office, owned by the Institute of Electrical and Electronics Engineers, Incorporated. Print: PDF: ISBN 0-7381-5247-1 SH95583 ISBN 0-7381-5248-X SS95583 No part of this publication may be reproduced in any form, in an electronic retrieval system or otherwise, without the prior written permission of the publisher. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. IEEE Standards documents are developed within the IEEE Societies and the Standards Coordinating Committees of the IEEE Standards Association (IEEE-SA) Standards Board. The IEEE develops its standards through a consensus development process, approved by the American National Standards Institute, which brings together volunteers representing varied viewpoints and interests to achieve the final product. Volunteers are not necessarily members of the Institute and serve without compensation. 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Comments on standards and requests for interpretations should be addressed to: Secretary, IEEE-SA Standards Board 445 Hoes Lane Piscataway, NJ 08854 USA Authorization to photocopy portions of any individual standard for internal or personal use is granted by the Institute of Electrical and Electronics Engineers, Inc., provided that the appropriate fee is paid to Copyright Clearance Center. To arrange for payment of licensing fee, please contact Copyright Clearance Center, Customer Service, 222 Rosewood Drive, Danvers, MA 01923 USA; +1 978 750 8400. Permission to photocopy portions of any individual standard for educational classroom use can also be obtained through the Copyright Clearance Center. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Introduction This introduction is not part of IEEE Std C37.101-2006, IEEE Guide for Generator Ground Protection. IEEE Std C37.101 was initially published in 1981. It was subsequently revised in 1985 and 1993, and reaffirmed in 2000. The guide is designed for the ground protection of typical steam, hydraulic, and combustion-turbine generators. Any scheme that is judged to be a good alternative practice for generator ground protection is included in the guide. New schemes that have been applied are added to the guide. In this revision, several areas are improved. Among the most notable are the following: — Insertion of definition in Clause 3 and addition of Glossary in Annex C. — Revised subclause (7.18) on Scheme 18 for including presently available optional schemes. — New subclause (7.20) on Scheme 20 for accidental solid neutral grounding. — New subclause (7.21) on Scheme 21 for alternative scheme for increasing the sensitivity of ground current. — New subclause (7.22) on Scheme 22 for hybrid ground protection (switching low- and highresistance schemes) for initial ground fault detection with higher sensitivity to an external fault of the generator and switching to a high-resistance scheme for a generator ground fault. — New clause (Clause 8) on miscellaneous schemes for ground overcurrent relay locations and the associated benefits. — Revised clause (Clause 9) on protective device function numbers for all device numbers. — Revised subclause (A.3.5) on third harmonic detection schemes for example third harmonic measurements. — Incorporate corrections to Equations (A.1), (A.2), (A.3), and (A.4) as required by IEEE Std C37.1012006/Cor1:2007. Notice to users Errata Errata, if any, for this and all other standards can be accessed at the following URL: http:// standards.ieee.org/reading/ieee/updates/errata/index.html. Users are encouraged to check this URL for errata periodically. Interpretations Current interpretations can be accessed at the following URL: http://standards.ieee.org/reading/ieee/interp/ index.html. Patents Attention is called to the possibility that implementation of this standard may require use of subject matter covered by patent rights. By publication of this standard, no position is taken with respect to the existence or validity of any patent rights in connection therewith. The IEEE shall not be responsible for identifying patents or patent applications for which a license may be required to implement an IEEE standard or for conducting inquiries into the legal validity or scope of those patents that are brought to its attention. iv Copyright © 2007 IEEE. All rights reserved. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Participants IEEE Std C37.101-2006 At the time this standard was completed, the working group had the following membership: Joe T. Uchiyama, Chair Ratan Das, Vice Chair Mike Reichard, Co-Vice Chair Munnu Bajpai Zeeky Bukhala Stephen P. Conrad Albert Darlington Everett Fennell Dale Finney Jon Gardell Wayne Hartmann Rai Marttila Charles Mozina Robert D. Pettigrew Kim Sungsoo Sahib Usman W. Phil Waudby Joseph Wilson Murty V.V.S. Yalla The following members of the individual balloting committee voted on this standard. Balloters may have voted for approval, disapproval, or abstention. William J. Ackerman Butch Anton Ali Al Awazi Saber Azizi-Ghannad Michael P. Baldwin Paul D. Barnhart G. J. Bartok Martin F. Best Wallace B. Binder, Jr. Thomas H. Blair Stuart H. Bouchey Steven R. Brockschink Gustavo A. Brunello Stephen P. Conrad Tommy P. Cooper Randall P. Crellin Ratan Das Kevin E. Donahoe Mark M. Drabkin Paul R. Drum Donald G. Dunn W. A. Elmore Gary R. Engmann Rabiz N. Foda Carl J. Fredericks Jeffrey G. Gilbert Stephen E. Grier J. Travis Griffith Randall C. Groves Copyright © 2007 IEEE. All rights reserved James H. Gurney Ajit K. Gwal Roger A. Hedding Adrienne M. Hendrickson Lee S. Herron Ajit K. Hiranandani Jerry W. Hohn David A. Horvath Dennis Horwitz James D. Huddleston, III David W. Jackson Brian K. Johnson Paul R. Johnson, Jr. James H. Jones Joseph L. Koepfinger Jim Kulchisky Solomon Lee Jason Jy-Shung Lin Lisardo Lourido William G. Lowe William Lumpkins G. L. Luri O. P. Malik Keith N. Malmedal Michael J. McDonald Nigel P. McQuin Gary L. Michel Kimberly Y. Mosley Jerry R. Murphy Michael S. Newman Charles Kamithi Ngethe T. W. Olsen Ralph E. Patterson Carlos A. O. Peixoto Allan D. St. Peter Robert D. Pettigrew Percy E. Pool Louie J. Powell, Jr. Madan S. Rana Michael A. Roberts Charles W. Rogers M. S. Sachdev Steven Sano Robert L. Seitz David Singleton Veselin S. Skendzic James E. Smith Peter B. Stevens Charles R. Sufana Richard P. Taylor S. Thamilarasan Demetrios A. Tziouvaras C. L. Wagner W. Phil Waudby James W. Wilson, Jr. Luis E. Zambrano Donald W. Zipse Ahmed F. Zobaa v Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. When the IEEE-SA Standards Board approved this standard on 15 September 2006, it had the following membership: Steve M. Mills, Chair Richard H. Hulett, Vice Chair Don Wright, Past Chair Judith Gorman, Secretary Mark D. Bowman Dennis B. Brophy William R. Goldbach Arnold M. Greenspan Robert M. Grow Joanna N. Guenin Julian Forster* Mark S. Halpin Kenneth S. Hanus William B. Hopf Joseph L. Koepfinger* David J. Law Daleep C. Mohla T. W. Olsen Glenn Parsons Ronald C. Petersen Tom A. Prevost Greg Ratta Robby Robson Anne-Marie Sahazizian Virginia C. Sulzberger Malcolm V. Thaden Richard L. Townsend Walter Weigel Howard L. Wolfman *Member Emeritus Also included are the following nonvoting IEEE-SA Standards Board liaisons: Satish K. Aggarwal, NRC Representative Richard DeBlasio, DOE Representative Alan H. Cookson, NIST Representative IEEE Std C37.101-2006/Cor1:2007 At the time IEEE Std C37.101-2006/Cor1:2007 was completed, the working group had the following membership: Joe T. Uchiyama, Chair Ratan Das, Vice Chair Mike Reichard, Co-Vice Chair Munnu Bajpai Zeeky Bukhala Stephen P. Conrad Albert Darlington Everett Fennell vi Dale Finney Jon Gardell Wayne Hartmann Rai Marttila Charles Mozina Robert D. Pettigrew Kim Sungsoo Sahib Usman W. Phil Waudby Joseph Wilson Murty V.V.S. Yalla Copyright © 2007 IEEE. All rights reserved. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. The following members of the individual balloting committee voted on this corrigendum. Balloters may have voted for approval, disapproval, or abstention. William J. Ackerman Gary E. Arnston Ali Al Awazi G. J. Bartok David C. Beach Kenneth C. Behrendt Wallace B. Binder, Jr. William G. Bloethe Oscar E. Bolado Stuart H. Bouchey Steven R. Brockschink Gustavo A. Brunello Stephen P. Conrad Tommy P. Cooper Louis m. Coronado Ratan Das F. A. Denbrock Gary L Donner Paul R. Drum Ahmed F. Elneweihi Gary Engmann Jonathan D. Gardell Jeffrey G. Gilbert Jalal Gohari Manuel Gonzalez Copyright © 2007 IEEE. All rights reserved Stephen E. Grier Randall C. Groves Steve Hamilton Roger A. Hedding Hamidreza Heidarisafa Gary A. Heuston Jerry W. Hohn David A. Horvath James D. Huddleston, III R. Jackson Brian K. Johnson Gerald F. Johnson Joseph L. Koepfinger Jim Kulchisky Raluca E. Lascu Keith N. Malmedal Omar S. Mazzoni Michael J. McDonald Gary L. Michel Dean H. Miller Jerry R. Murphy Michael S. Newman Joe W. Nims T. W. Olsen Allan D. St. Peter Christopher J. Pettigrew Robert D. Pettigrew Bruce Pickett Louie J. Powell, Jr. Madan S. Rana Michael A. Roberts Charles W. Rogers Steven Sano Bartien Sayogo James E. Smith Peter B. Stevens Richard P. Taylor S. Thamilarasan James E. Timperley Demetrios A. Tziouvaras Joe T. Uchiyama John A. Vergis W. Phil Waudby James W. Wilson, Jr. Larry E. Yonce Richard C. Young Ahmed F. Zobaa vii Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. When the IEEE-SA Standards Board approved this corrigendum on 26 September 2007, it had the following membership: Steve M. Mills, Chair Robert M. Grow, Vice Chair Don Wright, Past Chair Judith Gorman, Secretary Richard DeBlasio Alex Gelman William R. Goldbach Arnold M. Greenspan Joanna N. Guenin Julian Forster* Kenneth S. Hanus William B. Hopf Richard H. Hulett Hermann Koch Joseph L. Koepfinger* John Kulick David J. Law Glenn Parsons Ronald C. Petersen Tom A. Prevost Narayanan Ramachandran Greg Ratta Robby Robson Anne-Marie Sahazizia Virginia C. Sulzberger Malcolm V. Thaden Richard L. Townsend Howard L. Wolfman *Member Emeritus Also included are the following nonvoting IEEE-SA Standards Board liaisons: Satish K. Aggarwal, NRC Representative Alan H. Cookson, NIST Representative Don Messina IEEE Standards Program Manager, Document Development Matthew Ceglia IEEE Standards Program Manager, Technical Program Development viii Copyright © 2007 IEEE. All rights reserved. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Contents 1. Overview.............................................................................................................................................. 1 1.1 Scope............................................................................................................................................ 1 1.2 Purpose......................................................................................................................................... 1 1.3 Description of the guide............................................................................................................... 2 2. Normative references ........................................................................................................................... 2 3. Definitions, acronyms, and abbreviations............................................................................................ 2 3.1 Definitions.................................................................................................................................... 2 3.2 Acronyms and abbreviations........................................................................................................ 3 4. Summary of protection schemes.......................................................................................................... 3 5. Generator connections ......................................................................................................................... 7 5.1 Example use of Table 1................................................................................................................ 9 6. Generator grounding methods.............................................................................................................. 9 6.1 6.2 6.3 6.4 6.5 6.6 6.7 6.8 6.9 7. Method I—Effective high-resistance ground with a distribution transformer........................... 10 Method II—High-resistance ground with a neutral ground resistor.......................................... 10 Method III—Low-resistance ground with a neutral ground resistor ......................................... 10 Method IV—Low-reactance ground with a neutral ground reactor .......................................... 11 Method V—Resonant ground with a ground fault neutralizer .................................................. 11 Method VI—High-resistance ground with a delta-grounded-wye transformer......................... 11 Method VII—Medium-resistance ground with a delta-grounded-wye transformer.................. 12 Method VIII—Ungrounded ....................................................................................................... 12 Method IX—Hybrid ground (switching low resistance to high resistance) .............................. 12 Protective schemes............................................................................................................................. 12 7.1 Scheme 1—Ground overvoltage (complete shutdown)............................................................. 13 7.2 Scheme 2—Ground overvoltage (permissive shutdown) .......................................................... 15 7.3 Scheme 3—Ground overvoltage exceed rated relay voltage (alarm and time-delay shutdown) .............................................................................................. 16 7.4 Scheme 4—Ground overvoltage exceed rated relay voltage (alarm) ........................................ 16 7.5 Scheme 5S—Start-up ground overvoltage (complete shutdown).............................................. 17 7.6 Scheme 6—Ground fault neutralizer (alarm and time-delay shutdown) ................................... 18 7.7 Scheme 7—Grounded wye-broken-delta VTs with ground overvoltage (complete shutdown).................................................................................................................. 20 7.8 Scheme 8S—Start-up grounded wye-broken-delta VTs with ground overvoltage (complete shutdown).................................................................................................................. 21 7.9 Scheme 9—Secondary-connected CT, time-delay ground overcurrent (complete shutdown).................................................................................................................. 21 7.10 Scheme 10—Primary-connected CT, time-delay ground overcurrent (complete shutdown).................................................................................................................. 22 7.11 Scheme 11—Instantaneous ground overcurrent (alarm and/or complete shutdown)................ 23 7.12 Scheme 12—Generator leads ground overcurrent (complete shutdown) .................................. 24 Copyright © 2007 IEEE. All rights reserved ix Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. 7.13 Scheme 13—Three-wire generator leads with window CT, instantaneous ground overcurrent (complete shutdown) .............................................................................................. 25 7.14 Scheme 14—Four-wire generator leads with window CT, instantaneous ground overcurrent (complete shutdown) .............................................................................................. 26 7.15 Scheme 15—Generator percentage differential (complete shutdown)...................................... 27 7.16 Scheme 16—Current-polarized directional overcurrent relay................................................... 27 7.17 Scheme 17—Generator percentage differential relay on delta-connected generator (complete shutdown).................................................................................................................. 28 7.18 Scheme 18—100% stator winding ground protection schemes ................................................ 29 7.19 Scheme 19—Alternate stator winding protection with high-impedance relays ........................ 36 7.20 Scheme 20—Generator neutral overcurrent protection for an accidental solid ground fault .... 37 7.21 Scheme 21—Directional ground fault protection for high-resistance ground bus connected generators (multi-ground) .................................................................................. 38 7.22 Scheme 22—Hybrid ground protection for high-resistance grounded bused generator and ungrounded distribution system .......................................................................................... 39 8. Miscellaneous considerations ............................................................................................................ 40 9. Protective device function numbers................................................................................................... 42 Annex A (informative) Stator ground protection for a high-resistance grounded generator......................... 44 Annex B (informative) Ground protection example to determine the percent coverage of a high-impedance differential relay .................................................................................................. 58 Annex C (informative) Glossary.................................................................................................................... 61 Annex D (informative) Bibliography............................................................................................................. 64 x Copyright © 2007 IEEE. All rights reserved. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. IEEE Guide for Generator Ground Protection 1. Overview 1.1 Scope The guide is intended to assist protection engineers in applying relays and relaying schemes for protection against stator ground faults on various generator grounding schemes. The existing guide is outdated due to rapid technology development. Hence, the revised guide includes new stator ground protection principles that have evolved with the use of new technologies in relay designs. Additional application examples are included, and other issues raised by the users are also addressed. The guide is not intended for the selection of generator or ground connection schemes. The recommendations made pertain to typical generator installations. However, sufficient background information relating to protection requirements, applications, and setting philosophy is given to enable the reader to evaluate the need to select and apply suitable protection for most situations. Differential relaying will not detect stator ground faults on high-impedance grounded generators. The high impedance normally limits the fault current to levels considerably below the best practical sensitivity of the differential relaying. Separate ground fault protection is then provided. 1.2 Purpose The guide was prepared, in part, to cover new areas due to rapid technology development. The working group has made revision and expansion of the earlier version to include those areas. In addition, the protective function discussed in this guide may be implemented with a multifunction microprocessor-based protection system (digital system). The protection philosophy, practices, and limits are essentially identical to those of the implementation using discrete component relays. The algorithms used to perform some of the protection functions may be different, but should produce equal or better protection. However, the performance and capability of the digital systems may be superior due to improved frequency response (bandwidth) and thresholds (pickup settings). Other additional features may be available from these systems, like digital fault recording, that enhance the functionality. The improved frequency response and multiple settings groups may be beneficial, especially for start-up protection where older relays needed to be blocked from operation and additional dedicated start-up protective relays are traditionally applied. The startup relays may not be required with the use of the microprocessor-based protection. 1.3 Description of the guide Recommended protective schemes and the arrangements to which they may be applied are indicated in Table 1. The use of this table is described in Clause 4 with supporting information provided in subsequent clauses. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Annex A (informative) provides examples of ground overcurrent and overvoltage relay settings for the various protective schemes and the setting coordination with voltage transformer (VT) secondary fuses. Annex B (informative) provides an example of a procedure used to determine the percent coverage of a highimpedance differential relay. Annex C (informative) is a glossary (definitions) of terms related to grounding protection. Annex C is a bibliography of available literature on the ground-fault problem from which source material was drawn. Annex D (informative) is a bibliography of available literature concerning the generator ground fault protection from which source material was drawn. The methods employed for grounding and fusing the secondary circuits of VTs and the methods for grounding (CT) secondary circuits are not generally the same for all installations. For this reason no secondary fuses or ground points are indicated in the illustrated figures in Table 1 and various schemes. However, all current and VT secondary circuits shall be grounded in a way that is consistent with accepted practices for personnel safety. The quantitative units of voltages and currents are expressed in root mean square (rms) values in this guide. 2. Normative references The following referenced documents are indispensable for the application of this document. For dated references, only the edition cited applies. For undated references, the latest edition of the referenced document (including any amendments or corrigenda) applies. This standard shall be used in conjunction with the following publication. When the following standards are superseded by an approved revision, the revision shall apply. IEEE Std C37.2-1991,™, IEEE Standard Electrical Power System Device Function Numbers and Contact Designations.1, 2 IEEE Std C37.102™-1987, IEEE Guide for AC Generator Protection. IEEE Std C62.92.2™ 1989, IEEE Guide for the Application of Neutral Grounding in Electrical Utility Systems, Part II—Grounding of Synchronous Generator Systems. (ANSI). 3. Definitions, acronyms, and abbreviations 3.1 Definitions For the purposes of this guide, the following terms and definitions apply. The Glossary in Annex C and The Authoritative Dictionary of IEEE Standards Terms [B46]3 should be referenced for terms not defined in this subclause. 1IEEE publications are available from the Institute of Electrical and Electronics Engineers, Inc., 445 Hoes Lane, Piscataway, NJ 08854, USA (http://standards.ieee.org/). 2The IEEE standards or products referred to in this clause are trademarks of the Institute of Electrical and Electronics Engineers, Inc. 3The numbers in brackets correspond to those of the bibliography in Annex D. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. 3.1.1 hybrid ground protection scheme: A combination of low-resistance and high-resistance schemes. This scheme has initially a high sensitivity to detect ground faults with a low-resistance scheme and is switched over to a high-resistance grounding scheme after an internal generator ground fault is detected and the generator breaker is opened (Scheme 22). 3.1.2 phantom tertiary winding: This is a tertiary winding of autotransformer, however, the tertiary winding leads are not brought out of the transformer tank. This is for the purpose of third harmonic suppression, and the rating is usually 10% of the full transformer rating (Scheme 12). 3.2 Acronyms and abbreviations IOC/IOV relays instantaneous overcurrent/instantaneous overvoltage relays TOC/TOV relays time overcurrent/time overvoltage relays GFN ground fault neutralizer GSU transformer generator step-up transformer CT current transformer VT voltage transformer 4. Summary of protection schemes A summary of recommended protective schemes is given in Table 1, which is a matrix of generator connections, generator grounding methods, and the scheme numbers that identify the protective schemes. The following explanation has been prepared as an aid for its use. Across the top of the table, heading the sixseven columns (A–G), are one-line diagrams covering most, if not all, of the significant variations of generator-transformer-bus circuit breaker arrangements that might be encountered in a present-day electric utility or industrial power system. These diagrams are discussed in Clause 5 of this guide. Vertically, along the left side of the table, heading the eight nine rows (I– IX), are one-line diagrams of approved grounding methods for electric generators covered in IEEE Std C62.92. 24 as explained in clause 5. These diagrams will be explained and discussed subsequently. The individual boxes in table 1 list by scheme number (1, 2,Clause 6. Scheme numbers (1, 2, 3, etc.) listed in Table 1 (in the individual boxes) are different applicable ground fault protective schemes that apply for a given generator connection(columns in the table) and a given grounding method (rows in the table). For example, the box under column E and row III indicates that protective Schemes 10, 11, 14, 15, 16, 19, and 20 may be applied for single-phase-to-ground fault protection of a wye-connected generator. The neutral is grounded through a lowhigh resistance, and the main leads are connected directly to a grounded system through a circuit breaker. Those boxes that are crossed out and contain no protection scheme numbers (and are marked with a long dash) represent cases that are either not practical or not recommended. For example, under column D, a deltaconnected generator has no neutral available, so boxes under column D (associated with rows I, II, III, IV, and V) are crossed out. Also, the box under column E (and associated with row V) is crossed out because the use of a resonant grounding method, in the neutral of a wye-connected generator directly connected to a grounded system, is a misapplication. 4Information on references can be found in Clause 2. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. The protective scheme numbers in the boxes refer to protective schemes that are completely illustrated and described in Clause 7 of this guide. In some boxes, there are some numbers that are followed by the suffix S, such as 5S in box D-VI. The suffix S indicates that the protective scheme represented by that scheme number designation is suitable for use only when the machine is running and disconnected from the system, but with field excitation applied. This type of protection utilizes protective devices that are not tuned to normal system frequency, so that they offer sensitive protection over a wide range of frequencies. Thus, schemes designated with the suffix S are suitable for the protection of machines during start-up and shutdown. Protective scheme numbers without the suffix S represent schemes that are indexedexpected to provide protection only during operation at rated frequency. For example, in the case of the generator connection illustrated in the diagram of column A with the grounding connection of row I, Scheme 8S is intended to detect any single-phase-to-ground fault in the generator or its leads during start-up or shutdown procedures while field excitation is applied, but with the main circuit breaker open. In the box D-VIII, the protective scheme represented by Scheme 17 is intended for protection during the time that the main breaker is closed and the machine is running normally. In general, start-up and shutdown protection for single-phase-to-ground faults is indicated only in those applications where a high-impedance grounded or an ungrounded generator is connected directly to a grounded system, or where excitation is applied to a machine early in the start-up cycle or is removed late in the shutdown cycle. This start-up and shutdown protection is generally not intended to coordinate properly with system protection. For this reason, it should be removed from service at the time the unit is synchronized to the system. This is usually performed automatically when the main breaker is closed. 1IEEE publications are available from the Institute of Electrical and Electronics Engineers, 445 Hoes Lane, P.O. Box 1331, Piscataway, NJ 08855- 1331, USA. 2Information on references can be found in clause 2 The protective scheme numbers in Table 1 are arranged in the boxes with the running protective schemes listed first, and the start-up protective schemes, where they apply, listed last.later. Within each box, the schemes within the brackets are the most widely used. The remainders of the schemes are listed in numerical sequence. It should be recognized that the bracketed recommendations are based on the anticipated performance of the schemes and not on other factors that might relate to the integrity of the generator itself. For example, while Schemes 1 and 7 in box A-I could provide essentially the same order of protection for generator single- phaseto-ground faults, the fact that Scheme 7 requires voltage transformersVTs on the generator leads may reduce the overall reliability of the generator. Scheme 1 might be more desirable than Scheme 7, but they are both indicated in the table to have the same order of merit as far as the protection afforded for single-phase-to-ground faults is concerned. No attempt is made in Table 1 to indicate primary or backup schemes. It is suggested that descriptions of all schemes applicable to a given situation be considered, and, unless overriding circumstances dictate otherwise, that one of the bracketed schemes be used for the primary protection, and another high-rated scheme be used for backup or alternate protection. The generator connections illustrated in column F are very similar to those in column A. The difference is only in the use of low-side circuit breakers in the diagram of column F. A comparison of the applicable protective schemes between columns A and F will indicate that they are nearly all the same. Because of the low-side circuit breakers in the diagrams of column F, field excitation might normally be applied to the unit when it is turning at, or very near to, rated speed. Under these conditions, the need for start-up or shutdown protection is minimized. Clause 6 describes grounding methods I through IX. The different grounding methods are shown in the column along the left hand side of the row in Table 1. The diagrams in the column are intended to indicate the different grounding methods and the means for interfacing with the protective relay schemes. The diagram in row I have has both a neutral point N and a ground point in the primary circuit, as do those in rows II through V. The point N in the grounding method diagram connects to the point N in the generator connection diagram with which it is applied. For example, if any of the grounding methods I through V is used with any generator connection Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. illustrated in columns A, B, E, or F, the generator neutral N in question is grounded through the neutral connection shown in the grounding method diagram. In the case of the delta-connected machines of columns C and D, no neutral point exists, so grounding method VI or VII should be used. This includes a wye-broken delta-connected distribution-transformer bank with a secondary resistor. The wye (Y) windings are connected to the associated-generator main leads. Row VIII indicates an ungrounded machine that is grounded only through the system to which it may be connected. Finally, row IX indicates a hybrid ground machine that is grounded as a combination of high resistance and low resistance. Initially, the low-resistance grounding scheme provides great sensitivity for detecting a ground fault in the area of a feeder(s), and the generator bus, then, switches over to the high- resistance grounding scheme to greatly limit the ground current for the generator stator windings during internal ground faults. In Table 1, the diagram for grounding methods also indicates the interface between the primary circuits and the protective schemes. An example of this is that grounding method I shows a distribution transformer with and a secondary resistor. In series with the secondary of the distribution transformer is a current-transformer CT primary winding. The secondary winding of this CT terminates at terminals labeled R and S. A currentoperated relay, connected to these two terminals, will measure the current in the resistor during a ground fault in the generator stator or its associated circuits. In this same diagram, the resistor is connected across terminals designated X and Y If the operating coil of a voltage relay is connected to these terminals, it will measure the voltage developed across the resistor (which is proportional to the current through the resistor) during ground faults in the generator stator winding or its associated circuits. Again, in grounding method I, the CT in the neutral lead of the generator ground connection (in series with the primary winding of the distribution transformer) has its secondary winding terminating at points W and Z. A current-operated relay, connected to these terminals, will measure the current in the generator neutral during ground faults in the generator stator winding or its associated circuits. The terminal points R, S, X, Y, W, and Z are the interface connections to the protective schemes. The same is true in grounding methods II through VI. Reference to these connections will show that not all the grounding methods provide the same opportunities for protection. For example, in method IV, only a neutral CT is indicated with secondary connections to terminals W and Z. The diagrams for each of the protective schemes in Clause 7 indicate to which terminalthe specific interface points (R, S, W, etc.) they connect..). For example, protective Scheme 1 will be found to have input connections labeled X and Y. This indicates that protective Scheme 1 is always connected to terminals X and Y, regardless of the grounding method with which it is used. Similar comments apply to the other protective schemes and the interfacing terminal designations. Many of the protective functions discussed in this guide may be implemented with a multifunction microprocessor-based protection system (digital system). The protection philosophy, practices, and limits are similar to those of discrete component relays. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. 5. Generator connections The six seven different classes of generator connections illustrated in Table 1 are intended to be representative of connections commonly used today. While the connections of the two diagrams in column A are different, the arrangementsArrangements are such that the same protective schemes may be applied to bothmore than one generator connection. The criteria here is that a single-phase-to-ground fault in a generator will neither produce any significant zero-sequence current or voltages in the system, nor will a similar fault in the system produce any significant zero-sequence quantities in the generator circuit. Table 2 shows the comparison of neutral ground methods and summary of the third harmonic current generation levels for Scheme 18 (see Powell [B35]). In connection A, if two units are paralleled on one transformer delta winding (as in the case of a crosscompound machine or machines with two stator windings per phase), the same kind of protective schemes could be used as if only one unit were connected to the transformer. In general, for these applications, only one neutral is grounded. Where machines are connected to separate low-voltage transformer windings, each unit is grounded separately and has its own protective scheme. If tripping is employed, each protective scheme should initiate shutdown of all generators connected to a common transformer. The generator connections of column B indicate that the unit step-up transformer may be any autotransformer, with either a wound-delta tertiary or a phantom tertiary. In either case, the autotransformer provides a direct zero-sequence connection between the generator and the system so that the system grounding will provide zerosequence current for ground faults in the generator. Also, the generator will provide zero-sequence current for faults on the system. It is important to recognize in connection B that the wound or phantom tertiary of the main transformer will be a source of ground fault current for generator faults. With this arrangement, even with the generator neutral ungrounded and the main circuit breaker open, substantial and potentially destructive fault current could flow for a ground fault in the stator when the generator is running with field excitation applied. Furthermore, there may be neutral stability concerns if there is no physical tertiary winding in the autotransformer. For these reasons, the use of an autotransformer to interconnect a generator to its host system should be approached with caution. Connection C is similar to A, except that the generator(s) is connected in delta (∆) rather than in wye (Y). Here, as in connection A, the delta-connected winding of the power transformer provides zero-sequence isolation between the generator and the system. Such delta-connected generator units have no neutral available so that grounding is obtained by the use of a scheme as illustrated in Table 1, method VI. In general, one type of common grounding equipment is employed regardless of the number of generator units that are connected to a given transformer winding. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Table 1—Generator connections, generator grounding methods, and protective scheme numbers Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. The circuit arrangements of connection D and E indicate generators connected directly to the system bus without any interposing step-up transformers. In general, these may be relatively small generators, and they will be connected to a solid or low impedance grounded system. As indicated in Table 1, the delta machine of connection D requires the scheme of method VI or VII for grounding while that of connection E uses a suitable neutral grounding method. In these applications, each machine has individual protection. The circuit arrangements in the diagrams of connection F are the same as those in A except that the former utilize individual generator circuit breakers on the low side of the power transformer banks. Here again, the delta-wye (∆-Y) connections of the transformers provide zero-sequence isolation between the generators and the system. In general, each generator will have individual grounding and protection. While the low-side circuit breakers permit switching of individual generators, the protective schemes available cannot distinguish between faults in the different generators connected to a common delta winding. However, if different timedelay settings are utilized on the individual ground relays, the units will be sequentially tripped until the fault is cleared. This will establish the fault location. For this reason, a fault in any one machine may result in the loss of all generators connected to a common delta winding. Table 2—Comparison of neutral ground methods Type of neutral grounding Ungrounded generator Solidly grounded generator Fault current characteristics of grounding method 0A Magnitude of expected third harmonics current None Comments 0 A for the first ground fault, but the second ground fault will develop similar fault current level with solidly grounded method. IΦ G > I 3 Φ Appreciable A phase-to-ground fault current level (IΦG) may be significantly greater than three-phase fault current level (I3Φ). Low-resistance grounded generator 400 A ~ 1200 A Appreciable Appreciably reduced ground fault current by a reactance. Medium-resistance grounded generator 200 A ~ 400 A Appreciable A variation of low-resistance grounding method will further reduce the ground fault current level. High-resistance grounded generator 10 A ~ 25 A Negligible, small A phase-to-ground fault current is fed by all capacitors on the generator and generator bus. Low-reactance grounded generator I3 Φ ≥ I Φ G Appreciable A phase-to-ground fault current level (IΦG) is nearly equal or less than a threephase fault current level (I3Φ). Appreciable The first ground fault current level will be 200 A ~ 400 A with low-resistance grounding, and 10 A ~ 25 A after switched to a high-resistance grounding scheme. Hybrid grounded generator 10 A ~ 25 A (high resistance) and 200 A ~ 400 A (low resistance) Connection G depicts the situation, often found in industrial applications, where a generator is directly connected to a common bus. Local facility loads are also connected to this bus. When the generator is not connected, the local loads are powered from the power transformer and the ground source is supplied by the grounded wye of the transformer. When the generator is connected, there are two sources of ground fault current, the generator and the transformer. In many cases both ground sources have ground resistors in the neutral to limit the magnitude of the ground fault current. If the transformer source is disconnected, the Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. generator can supply power to some or all of the local facility loads. In this case the generator provides the ground source for the local facility electrical system. In some cases the generator voltages are much higher (e.g 22 kV, 27 kV) than the suitable local loads’ voltage. In this case the unit auxiliary transformer(s) is usually connected to the generator bus to feed the local loads. Coordination of the generator ground protection with the auxiliary load ground protection can be disregarded as long as the auxiliary transformer connection, usually a delta-wye-grounded connection, does not provide a path for circulation of the generator ground current for ground fault on the auxiliary bus side of the auxiliary transformer. A variation of connection G may be found in instances in which overhead distribution circuits are served directly from a generator bus. Often, these applications involved either hydroelectric or gas-turbine generators installations. It is the fact that overhead circuits originate atthese buses that leads to the desire that the system neutral be effectively grounded. Since generators cannot normally be solidly grounded (due to the large magnitude ground fault current), these applications often involve low-reactance grounding of the generator neutral. A critical requirement is that the relaying system provides selective ground fault detection for any of these operating permutations. 5.1 Example use of Table 1 Table 1 is a list of possible combinations of grounding methods and possible types of relay schemes. NOTE—The figures in Table 1 are shown only for reference. Details of the respective figures and schemes can be found in Clause 7.5 If the generator (Y stator windings) connected to the delta windings of the generator step-up (GSU) transformer, the grounding methods I, II, or V from Table 1 can be used. If the selected grounding method is I, then the most widely used relay schemes are Scheme 1 (overvoltage relay), Scheme 7 (overvoltage relay), Scheme 10 (overcurrent relay), and Scheme 18 (100% ground fault detection relay). In addition, it is possible to apply one of Schemes 2, 3, 4, 6, 9, 11, 20, 5S, or 8S. 6. Generator grounding methods This guide describes protection for five of the six generator grounding categories methods described in IEEE Std C62.92.2 The six methods are as follows: 1) Effectively grounded 2) Low inductance reactance grounded 3) Low resistance grounded 4) Resonant grounded 5) High resistance grounded 6) Ungrounded NOTE—The selection of these generator grounding methods is beyond the scope of this guide. For the advantages/ disadvantages of these six generator grounding methods, refer to IEEE Std C62.92.2. An effectively grounded system is a form of low inductance grounded system and is not considered in this guide. The guide considers distribution transformer and high resistance grounding as a single category. This Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. guide lists them as separate grounding methods since each requires a different type of protective scheme. The protection for two additional methods of grounding, high resistance and medium resistance grounding transformer grounded, is explained in this guide. The following nineeight grounding methods (including ungrounded systems) considered in this guide are as follows: a) High resistance grounded (distribution transformer grounded) generator b) High resistance grounded (neutral resistor grounded) generator c) Low resistance grounded (neutral resistor grounded) generator d) Low reactance grounded (neutral reactor grounded) generator e) Resonant grounded (GFN grounded) generator f) High resistance grounded (grounding transformer grounded) generator g) Medium resistance grounded (grounding transformer grounded) generator h) Ungrounded generator 5.1 Method I: High resistance grounded (distribution transformer grounded) Grounding method I utilizes a distribution transformer with a primary voltage rating equal to, or greater than, the line to neutral voltage rating of the generator, with a secondary rating of 120 V or 240 V. The distribution transformer should have sufficient overvoltage capability so that it does not saturate on phase to ground faults with the machine operated at 105% rated voltage. Secondary resistors are usually selected so that for a single phase to ground fault at the terminals of the generator, the power dissipated in the resistor is equal to, or greater than, the zero sequence reactive volt amperes in the zero sequence capacitive reactance of the generator windings, its leads, and the windings of the transformers that are connected to the generator terminals. This arrangement is considered to be high-resistance grounding, and it limits the maximum single-phase-to-ground fault current to a value in the range of approximately 3 to 25 primary amperes. This is not of sufficient magnitude to operate standard generator differential relays. In general, the W-Z current 5Notes in text, tables, and figures are given for information only and do not contain requirements needed to implement the standard. NOTE—The designation of W Z, R S, etc., in the following grounding methods refer to Table 1. 6.1 Method I—Effective high resistance ground with a distribution transformer This grounding method utilizes a distribution transformer that provides high resistance in the primary circuit with a small resistance in the secondary of the distribution transformer. The primary of the distribution transformer is connected between the generator neutral and ground. The ground resistance value (R) is generally extremely small (< 1 Ω); however, the imposed ohmic value to the primary circuit becomes extremely high resistance value (in the order of kilohm. See A.1.1). The high resistance is N2R where N is the turn ratio and R is the ohmic value of a resistor in the secondary. The grounding equipment should be rated in accordance with IEEE Std C62.92.2 or Annex A of this guide. This arrangement is considered to be high resistance grounding, and it limits the maximum single phase to ground fault current to a value in the range of approximately 3 A to 25 A primary amperes. current, which is not of sufficient magnitude to operate standard generator differential relays. In general, the W Z CT will have a ratio of unity, and the R S CT ratio is usually selected so that its secondary current will be approximately equal to the primary current in the generator neutral. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. A generator system grounded through a distribution transformer with a secondary resistor has certain characteristics that may have the following desirable features: — Mechanical stresses and fault damage are limited during phase to ground faults by restricting fault current. — Transient over voltages are limited to safe levels. — The grounding device is more economical than direct insertion of a neutral resistor. However, a disadvantage of this high resistance grounding scheme is that surge protective equipment must be selected on the basis of higher temporary overvoltages during ground faults. NOTE—In general, the voltage rating of electrical equipment is selected on the basis of the grounding reference point. If electrical equipment is installed near the ground point (grounded scheme), the equipment may be selected on based a phase to ground voltage. However, if the equipment is installed far from the ground reference point (non grounded scheme), the equipment may be selected based on the phase to phase voltage. The grounding effect of a high resistance ground scheme is a similar overvoltage phenomenon to a non grounded scheme. The electrical equipment needs to be selected based on the phase to phase voltage. 6.2 Method II—High resistance ground with a neutral ground resistor This method of grounding is functionally equivalent to the method described in 6.1. In this method, the resistor is sized directly to limit the single phase to ground fault current to the same magnitude as in the method in 6.1 without the use of a distribution transformer. However, the voltage transformer voltage ratings are the resistor rating is selected on the same basis as those for the distribution transformer in method 6.1 (see Annex A for an example). The W Z CT ratio is generally selected to be unity. 6.3 Method III—Low resistance ground with a neutral ground resistor Method III illustrates a low resistance grounding arrangement. This type of grounding method permits fault current many times higher (400 A ~ 1200 A primary current) than those produced by methods described in 6.1 and 6.2. In the case of low resistance grounding methodsthis method, the single phase to ground fault current is high enough to operate the standard generator differential relays for faults in the stator, except for those near the neutral end of the machine. The main advantage of low resistance grounding is the ability of the neutral resistance to limit ground fault current to a moderate value while limiting the transient overvoltages to 2.5 times the phase to ground voltage or less. However, Surge arresters with maximum continuous overvoltage (MCOV) capability that can tolerate full line to line voltage until the generator is tripped are required. The current through a neutral resistor can be limited to any value, but usually it ranges from about several hundred amperes to about 1.5 times the normal rated generator current. The lower limit may be based on the sensitivity of the generator ground differential relays. The upper limit of 1.5 times normal rated current is related to the loss in the resistor during single phase to ground faults. A value of 1.5 times normal current through a neutral resistor gives a power loss of 50% of the power rating (kVA) of the generator. The main disadvantages of low resistance grounding is the cost of the grounding resistor and the possibility of iron lamination burning from the higher ground fault current. 6.4 Method IV—Low inductance reactance ground with a neutral ground reactor Method IV illustrates a low inductive reactance grounding arrangement. This type of grounding method permits fault current many times higher than those produced by methods described in 6.1 and 6.2. In the case of low inductive reactance grounding methods, the single phase to ground fault current is high enough to operate some generator differential relays for faults in the stator, except for those near the neutral end of the machine. In general, the reactance value of low reactance grounding method is selected to suppress a phase to ground fault current into approximately three phase fault current level. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. NEMA standards do not require that standard generators have the mechanical bracing required to sustain operation with their neutrals solidly grounded. Low reactance grounding is often selected in applications where system planning considerations call for effective grounding (as defined in Annex C) of the system neutral. Note that effective grounding of generators through the use of low reactance neutral grounding reactors requires special consideration of both ground fault magnitudes, and potentially also of third harmonic current circulation. 6.5 Method V—Resonant ground with a ground fault neutralizer[GFN]) This grounding method illustrates the ground fault neutralizer (GFN) arrangement. In this grounding method, a distribution type transformer with a ratio selected, as in method 6.1, is used with a secondary reactor. The ohmic value of this secondary reactor is selected so that, when reflected into the primary circuit, its reactance is equal to one third of the zero sequence capacitive reactance of the circuit from (and including) the generator, to (and including) the delta windings of the associated power transformers. This type of grounding limits the single phase to ground fault current to values that will not sustain an arc. It is applicable only where the zero sequence capacitive reactance of the circuit does not change significantly for different system conditions. This method may not be readily applied to units arranged as in column F of Table 1, such as when low side breakers are applied. In general, the resonant grounding method suppresses a phase to ground fault current in less than 1 A primary current. In the grounding methods described in 6.1 through 6.5, the neutral CT is shown to be connected between the fault limiting device and ground. This CT could be located on either side of the fault limiting device depending on the preference of the user. The insulation level of the CT should be compatible with the possible voltage to which it may be exposed. 6.6 Method VI—High resistance ground with a delta grounded wye transformer This grounding method uses three distribution transformers whose primary windings are connected to the generator leads in a wye configuration, while the secondary are connected in broken delta configuration with a resistor. These transformers must have their primary voltage rating equal to the line to line voltage of the generator. Secondary voltage is commonly 120 V or 240 V. As in the case of I, the resistor is selected so that, for a single phase to ground fault at the terminals of the generator, the power dissipated in the resistor is equal to, or greater than, the three phase zero sequence reactive volt amperes in the zero sequence capacitance of the generator windings, its leads, and the windings of the transformers connected to the generator terminals. The total capacity of the three transformers must be 1.732 times the watt dissipation of the resistor, and the voltage applied to the resistor is 1.732 times the transformer rated secondary voltage. The grounding equipment should be rated according to IEEE Std C62.92.2. This grounding method used on ungrounded systems such as those having delta connected generators and power transformers. In general, a high resistance grounding method will suppress the phase to ground fault current in a range of 10 A to 25 A primary current. 6.7 Method VII—Medium resistance ground with a delta grounded wye transformer This grounding method uses either a zig zag transformer or a wye delta transformer. The primary windings of these are connected to the generator leads with a resistor connected from the transformer neutral to ground. The effective grounding impedance is selected to provide sufficient current for selective ground relaying. The medium resistance grounding method is a variation of low resistance grounding (400 A to 1200 A primary current) and provides a phase to ground fault current in a range of 200 A to 400 A primary current. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. 6.8 Method VIII—Ungrounded Finally, If no grounding of any sort is employed on the leads or neutral of the generator, this is termed ungrounded and is listed in row VIII of Table 1. The advantages of this class are essentially the same as for high resistance grounding except that the maximum fault current is somewhat less through the leakage capacitances. A disadvantage is that excessive transient overvoltages may result from switching operations or intermittent faults. In grounding methods I through V, the neutral current transformer is shown to be connected between the fault limiting device and ground. This current transformer could be located on either side of the fault limiting device depending on the preference of the user. The insulation level of the current transformer should be compatible with the possible voltage to which it may be exposed. 6.9 Method IX—Hybrid ground (switching low resistance to high resistance) If the power system is designed to operate either with both sources in parallel or with either source being independent, then the hybrid system shown in Scheme 22 provides a good alternative. The generator has both low and high resistance grounding schemes. Under normal operating conditions, the generator has medium ground fault current (200 A to 400 A primary current) that is governed by the medium resistance grounding scheme. This helps ground fault detection on a local feeder by an instantaneous overcurrent relay and eliminates unnecessary shutdown of the generator as well as other local loads. If a ground fault is detected in the generator zone, the protection trips the low resistance ground source. Simultaneously, the medium resistance grounding scheme is switched to a high resistance scheme to limit the fault current (10 A to 25 A primary current) and the core burning associated with it, also preventing any transient overvoltage condition from occurring. Refer to Figure 22 and Clause 7 for further explanation of Scheme 22. 7. Protective schemes The protective schemes listed (by number) in Table 1 are described in this clause along with their suitability for the grounding methods discussed in Clause 6. The electrical characteristics of the relays represented by the device function numbers in the figures illustrating each scheme are defined in Clause 9. Protective schemes that are used to protect generators employing high-resistance and resonant grounding methods (grounding methods I, II, V, and VI) are generally sensitive enough to detect phase-to-ground faults in the secondary circuits of VTs connected to the generator leads. If the wye-connected secondary circuit of these VTs is grounded at one of the phase leads rather than at the neutral point, and if the neutral point is not wired out, the possibility of a phase-to-neutral fault is extremely remote. If this is the case, the relays employed in these protective schemes need not be coordinated with the VT secondary fuses. However, coordination with the primary fuses is still required. 3The numbers in brackets correspond to those of the bibliography sources in annex C. For ground fault neutralizer GFN grounding, the primary neutral connections of the two sets of wyewyeconnected generator VTs are tied together and to the generator neutral using an insulated conductor. The secondary neutrals are grounded at the VT cubicle. Grounding of the primary neutral connections at the cubicle is not used since the resulting phase-to-ground inductive reactance comprising the magnetizing branch of the VTs would detune the resonant circuit consisting of the generator system capacitance to ground and the neutral reactor. A complete discussion of VT fusing is given in the IEEE Committee Report [B43] and A.4. Usually, a generator is clearedisolated without any intentional delay once the ground fault is detected. The risk of continuing operation with low-impedance grounding is extensive core damage, while the risk with highimpedance grounding is the possibility of a second fault. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. The majority of existing generators having resonant grounding methods are not tripped immediately, but an alarm is actuated and an orderly shutdown is started. Field experience of over 574 unit-years with generators (since 1951) has shown no cases of a second fault developing even though there have been at least seven ground faults, all of which were allowed to exist during a delayed tripping (see Gulachenski [B39]). When immediate tripping is used, it includes the main and field circuit breakers and the turbine stop valve or gates. Because a sudden, complete shedding of load can be a severe shock to the mechanical systems of the unit, including the steam system, it is sometimes preferred to employ an orderly shutdown rather than an immediate trip. In such cases, upon detection of a stator ground fault, the generator is either automatically or manually unloaded at a safe rate before tripping the circuit breakers. All the protective schemes that follow, except Schemes 2, 3, 4, and 6, indicate complete and immediate shutdown of the unit. Schemes 2, 3, and 4 illustrate three possible variations in the shutdown procedures that may be employed to effect an orderly shutdown. While the use of these schemes can significantly increase the possibility of extensive damage to the generator, they can be used where necessary. However, they should only be used in conjunction with high-resistance or resonant- grounding methods where ground fault current is significantly limited. In some instances, such as in cross compound machines, field excitation is applied as these machines are brought up to speed. In these applications, or where field excitation is permitted to remain on the unit as it is shut down, additional protection may be required during these periods. Schemes intended for use in such applications are designated with the suffix S (protection for during a start-up). Table 1 indicates where these schemes may be applied when necessary. 7.1 Scheme 1—Ground overvoltage (complete shutdown) This protective scheme 1 (see Figure 1) may be used for single-phase-to-ground fault detection on highresistance grounded generators that are connected to the system through delta-wye-connected GSU transformers. Table 1 indicates that this includes grounding methods I and II for wye-connected generators and grounding method VI for delta-connected generators. All three of these grounding methods (I, II, and VI) limit the available fault current to extremely low levels (less than 25 A primary current) for single-phase-to-ground faults in the generator stator windings, the generator leads, and the delta windings of the associated GSU transformers. The voltage measured across the grounding resistors at terminals X-Y provides an indication of the existence of a fault in this zone. Fault detection in these applications is achieved by connecting the operating circuit of a very sensitive overvoltage relay (device 59) across terminals X-Y. The magnitude of the voltage seen by this device depends on the fault location and the ratio of the distribution transformer in the case of grounding methods I, II, and VI, or the ratio of the voltage transformer in the case of grounding method II. For the case of grounding method I, a single-phase-to-ground fault at the generator terminals will produce full phase-to-neutral voltage across the primary of the distribution transformer. For the case of grounding method II, this same fault will produce the same voltage across the neutral resistor. For the case of grounding method VI, the phasorvector sum of the phase-to-ground voltages applied to the primary windings of the three distribution transformers during a single-phase-to-ground fault at the terminals of the generator will be equal to three times the full phase-to-neutral voltage of the generator. In every case, the voltage appearing at the terminals of the operating circuit of device 59 will be the primary voltage divided by the VT ratio or the distribution transformer ratio. Since the voltage rise from the generator neutral to its terminals is uniformly distributed, the voltage appearing across the grounding device for a single-phase-to-ground fault on a stator winding will be roughly proportional to the distance from the neutral as a percentage of the total winding. The voltage pick up setting of device 59 shall be high enough so that it will not operate on fundamental frequency voltages produced by normal system imbalances or the third harmonic voltages generated by the machine under all-load conditions. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Harmonic generation in a generator is dependent on many factors, such as slot spacing, variation in reluctance that occurs at various pole positions, and pole pitch. Manufacturing difficulties and their associated costs generally prohibit the design of machines whose waveform contains no third harmonic. The nature of third harmonic voltages are generated equally in each of the three phases, and these harmonic voltages are in phase. Hence, the machine neutral-to-ground voltage will contain a third harmonic voltage. Figure 1—Ground overvoltage (complete shutdown) Relays that are intended to detect fundamental frequency voltage between machine neutral and ground cannot be allowed to respond to this third harmonic voltage. These relays must then be desensitized to the harmonics or be set above the combined harmonic voltage. Other relays (devices 27 and 27TH) use this third harmonic voltage for neutral-to-ground fault detection. These relays must be set so that these relays remain picked up on the minimum third harmonic voltage in the normal operation. In general, the fundamental tuned overvoltage relays are available that make it possible to safely set device 59 to detect single-phase-to-ground faults as close as 2% to 10% from the neutral end of the winding, depending on the ratio of the voltage or the distribution transformers that are used. To ensure that the relay will not operate on the system imbalance, the relay voltage should be measured at machine full load before putting the scheme in service. Phase-to-ground faults on the transmission system produce zero-sequence voltage in the grounded-wyeconnected high-voltage winding of the main powerGSU transformer. This voltage is capacitively coupled to the generator zero-sequence network by the interwinding capacitance of the transformer. If the transformer is solidly grounded, the zero-sequence voltage in the wye-connected winding will be quite low. Due to the low impedance of the generator grounding device is small in comparison to that of the interwinding capacitance, most of this voltage will be across the transformer interwinding capacitance and very little of it across the generator grounding device. Phase-to-ground faults on the station service distribution system will also be capacitively coupled to the generator zero-sequence network. However, because the auxiliary transformer is relatively small capacity (kVA), which means high positive- and negative-sequence impedances, and the distribution voltage is low, coupled zero-sequence voltage from this source seldom causes a problem, even though these systems are typically low- resistance grounded. If the main power transformer is not solidly grounded, or the effect of inter winding coupling cannot be evaluated, some short time delay should be used to prevent false generator trips for faults on the transmission system. In any case, time delay will be required to coordinate with the generator-voltage transformer fuses for phase-to-ground faults in the VTs or their secondary leads. Annex A provides an example of relay-fuse coordination. Device 59 should be capable of withstanding the maximum applied voltage for the time required to shut down the generator. During a ground fault, device 59 operates and energizes a lockout relay, which is device 86. The lockout relay initiates a complete shutdown, which includes tripping the main and field breakers, and closing the turbine stop valves of steam-turbine generators or wicket gates of hydro-turbine generators. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. For the case of either two separate generators or a cross-compound unit where each is connected directly to a separate delta winding of a common step-up transformer, separate relays are required. Each relay should shut down both machinesgenerators. For the case of parallel connected cross-compound generators, or generators with double stator windings, only one stator winding is normally grounded and only one relay is required. When two or more generators, having their own low-side circuitunit breaker, are connected to the same transformer primary delta winding, each machine is usually grounded so thatand have one relay is required for each generator. Each relay trips solely its associated unit. In other cases, it is advisable to provideuse a protective scheme such as that illustrated in Scheme 7 and to include the protection of the transformer delta windings. This relay should(device 59) on the generator bus should initiate to trip the transformer high side and all the generator low-side unit breakers. In such applications, a ground fault in any machine or the deltawinding of the GSU transformer will be detected by all the ground relays on each generator so that complete selectivity is not generally possible. Some users apply all the generator relays at the same pickup setting but adjusted to operate with different time delays. The Scheme 7 relay is set less sensitively and with the longest time delay. If a fault occurs in the protected zone, the generators are tripped in sequence until the faulted unit is removed. The remaining units, if any, are permitted to continue in service. If the fault is in the transformer delta winding, all the units and the transformers are ultimately tripped. This type of application often helps to pinpoint the fault location. As an alternate method, all generator ground relays may be set alike. For some faults in the generator windings, the relay associated with the faulted generator will operate to clear the unit before any of the others can trip. However, for faults near the terminals of a generator, this approach can result in tripping all units. A third approach is to supervise the tripping of the relay in the broken delta with the auxiliary contact of the generator breakers, such as in Scheme 8S. For faults in either generator, only the generators are tripped. For faults on the bus or in the transformer, the broken-delta relay trips the transformer high-side breakers after both generator breakers trip. In general, the overvoltage relay employed in protective Scheme 1 will not provide sensitive protection at frequencies significantly below rated frequency. Thus, if field excitation will be applied during the periods when the machine is brought up to speed or shut down, a protective scheme similar to that described under Scheme 5S or 8S should be considered in addition to Scheme 1. The major advantage of Scheme 1 is that, due to its sensitive relay settings, ground faults in the stator may be detected to within 2% of the neutral point. The major disadvantage of this scheme is that it can respond to faults in the VT primary and secondary circuits, and total coordination with the associated fuses may not be possible. An example related to the application of Scheme 1, including coordination between the VT fuses and the protective relay, is provided in Annex A. 7.2 Scheme 2—Ground overvoltage (permissive shutdown) Scheme 2 (see Figure 2), a variation of Schemes 1 and 7, utilizes the same 59 and 86 devices and settings, but tripping of the main unit breaker (52) and field circuit breaker (41) is supervised by position switches on the turbine stop valves. The advantage of this scheme is that it prevents full load rejection with its accompanying during overspeed condition. Its disadvantages are that it permits longer fault duration and the additional complexity of its tripping circuits. This arrangement may result in considerably more than rated voltage applied to the 59 device for a prolonged period of time. Because of this prolonged time delay, a “b” contact on device 86 is employed to interruptinserted for interrupting the circuit of the overvoltage relay as shown in Figure 2. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Figure 2—Ground overvoltage (permissive shutdown) 7.3 Scheme 3—Ground overvoltage exceed rated relay voltage (alarm and time- delay shutdown) Scheme 3 (see Figure 3), a variation of Schemes 1 and 7, utilizes the same overvoltage relay but provides for an immediate alarm with a prolonged time-delay trip. If device 59 cannot continuously withstand the maximum voltage to which it may be subjected during a single -phase-to-ground fault at the generator terminals, then this scheme shall be modified by the inclusion of a 59H device as in the case of Scheme 4, shown in Figure 4. If a more orderly shutdown is desired, device 86 is connected to trip the turbine stop valve, which in turn, by way of a valve position switch, trips the main and field breakers as in Scheme 2. Figure 3—Ground overvoltage exceed relay rated voltage (alarm and time-delay shutdown) 7.4 Scheme 4—Ground overvoltage exceed rated relay voltage (alarm) Scheme 4 (see Figure 4), a variation of Schemes 1 and 7, utilizes the same 59 device but provides only for an alarm. Because this arrangement may result in considerably more than rated voltage applied to device 59 for an extended period of time, an additional, less sensitive, but higher rated 59H device is also employed. The 59 relay should be set exactly as in Scheme 1 or 7. Device 59H should be set to pick up at voltage level below the continuous rating of device 59. Also, the continuous rating of the 59H device shall be capable of continuously withstanding the voltage to which it will be subjected for a single-phase-to-ground fault at the generator terminals. With this arrangement, if the fault voltage on device 59 exceeds its capabilities, the 59H device will operate to insert a resistor and reduce the voltage on device 59 to a safe value. NOTE—If device 59 can withstand the maximum fault voltage to which it may be continually exposed, a 59H device is not required. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Figure 4—Ground overvoltage exceed relay rated voltage (alarm) 7.5 Scheme 5S—Start-up ground overvoltage (complete shutdown) As indicated by the suffix S, Scheme 5S (see Figure 5) is intended for stator ground fault detection during the time that the protected machine is disconnected from the system and running with field excitation applied. It serves a particularly important function when ground fault protection is applied to high-resistance or resonantgrounded wye or delta-connected units (see Table 1), because the single-phase-to-ground fault protection normally provided for these applications is relatively insensitive except at frequencies at or near rated value at or near the fundamental frequency. Device 59S used in this scheme 5S, should have a relatively constant voltsper-hertz response down to its dc pickup. As a result, the relay will be more voltage sensitive as the frequency is decreased. Such a device will tend to provide the same level of protection over a wide range of frequencies as the generator is brought up to speed or shut down while maintaining an essentially constant volts per hertz. The operating coil circuit of the sensitive instantaneous overvoltage relay (device 59S) may be connected to terminals indicated as X-Y across the grounding resistor (methods I and VI), VT (method II), or reactor (method II) as illustrated in Table 1. The relay operating circuit is connected by way of an auxiliary switch (52/b) on the associated circuit breaker, so that the protection is in service only during the time that the circuit breaker is open. In ring bus and breaker-and-a-half arrangements, auxiliary switches from the two associated high voltage breakers and the motor-operated disconnect switch shall be configured in such a way that the relay is armed when the unit is disconnected from the high voltage system even if the unit breakers have been closed to reestablish the bus arrangement. Because the ground fault protection afforded by in this scheme is availableeffective only during those periods that when the generatorunit breaker(s) is open, there is no need for coordination with other protective devices during external faults. Also, the relatively constant volts-per-hertz sensitivity of the relay tends to provide immunity to small magnitudes of third harmonic voltages that might be present during start-up and shutdown procedures. The combination of these two effects permits the use of a sensitive setting on device 59S. Typical pickup settings are in the range of 3% to 5% of the maximum voltage that can be developed for a solid singlephase-to-ground fault at the terminals of the generator. A relay setting example is given in Annex A. If the 59S device is not capable of withstanding the maximum voltage to which it may be subjected for the time duration required to shut down the unit, some arrangement should be used to de-energize 59S after device 86 has operated. A contact on device 86 could serve this purpose. This scheme has the advantage of providing high speed sensitive protection during start-up and shutdown procedures that may otherwise not be obtainable. It has the minor disadvantage that it will generally not coordinate with VT fuses. However, because the machine is not loaded during the period of time thatwhen this protection is in service, this limitation should not be a major consideration. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Figure 5—Start-up ground overvoltage (complete shutdown) 7.6 Scheme 6—Ground fault neutralizer overvoltage—(alarm and time-delay orderly shutdown) Scheme 6 (see Figure 6) is generally employed for the protection of units that are grounded by means of the ground-fault neutralizer (GFN) method GFN scheme. This is indicated as grounding method V in Table 1. The GFN scheme of grounding limits the single-phase-to-ground fault current in the machine stator windings and connected equipment to magnitudes so low (0.45 A primary current) that an arc cannot be maintained. This grounding method significantly restricts fault damage so that long time delays, permitting orderly shutdown of faulted units, are deemed justifiable. However, it should be recognized that this grounding scheme in no way alters the probability of a second ground fault occurring prior to shutdown. A second fault could produce high fault current. Protective This scheme is a variation of protective Scheme 1. It employs the same 59 device as Scheme 1. Because of the absence or near absenceextremely small magnitude (0.45 A primary current) of fault current, device 59 only operates an alarm. However, because device 59 may not be able to withstand prolonged operation with significant overvoltage applied, device 59H is included. Device 59H is an instantaneous overvoltage relay that is not as sensitive as device 59 and can withstand higher voltages continuously. Device 59H is set to pick up at a voltage level somewhat below the continuous rating of device 59. An increase in voltage readings across the neutralizing reactor indicates insulation deterioration and a probable incipient fault. Operation of 59H inserts a resistor in series with the recording voltmeter to change the scale so that the higher fault voltage can be recorded. Because of the higher setting, operation of device 59H indicates a fault that is significantly remote from the neutral of the generator. For such a fault, both the 59 and 59H devices pick up and sound an alarm. However, device 59H energizes auxiliary relay 59X, which in turn de-energizes the voltage operating circuit of device 59 and energizes a timer 2, and continues the alarm. The device 59X will alarm continuously. The timer, set to operate in approximately 1 hour, is intended to permit an operator to effectinitiate an orderly shutdown of the unit before any automatic action is takenshutdown by way of device 86. The recording voltmeter in this scheme monitors the small but discernible zero-sequence voltage that is always present across the neutralizing reactor. Reductions in this voltage (from normal readings) indicate short circuits to ground at or near the generator neutral terminal. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. The addition of an undervoltage relay with a 180 Hz pass filter or a third harmonic undervoltage relay (27TH) will provide protection for faults at or near the generator neutral terminals. The complete protection of the generator winding is accomplished in conjunction with the device 59H. Figure 6—GFN overvoltage (alarm and time-delay orderly shutdown) Another advantage of this scheme is the ability to detect much higher resistance faults than Scheme 1 with the same relay setting. This is because the zero-sequence network impedance of the GFN is 30 to 50 times greater than the resistance used in high-resistance grounding (methods I, II, and VI). This arises from the parallel tuned circuit comprising the neutral reactor and the capacitance of the generator system whereby the resulting impedance (Ro in ohms) is a high pure resistance that can be estimated from the relationship shown in Equation (1): Ro (Ω) = [(3KXL)/2] (1) where XL K RL is the inductive reactance of the neutral reactor is the reactor coil X/R ratio = XL/RL is the resistance of the neutral reactor The example in Annex D (see Gulachenski [B39]) demonstrates how effective the resonant grounding system is in reducing the magnitude of generator phase-to-ground fault current to values for which stator iron damage is not expected to occur. Also illustrated in Gulachenski [B39] is how the resonant grounding system can detect much higher resistance faults than can the neutral resistor grounding system. The results are summarized in Table 3. Table 3—Comparison of the sensitivity of Scheme 1 and Scheme 6 Maximum fault current Maximum value of fault resistance detected with 59 device set for 5.4 V Resistor grounded Resonant neutral grounded Scheme 1 Scheme 6 7.95 A 66 900 Ω 0.45 A 3 574 000 Ω Additional examples for calculating high-resistance grounding and resonant grounding can be found in Annexes A and B of IEEE Std C62.92.2. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Along with these desirable features, there are severalsome features that may be considered undesirable: — If automatic tripping is used, coordination with generator VT fuses may not be possible. The VT secondary wiring faults may cause ground indications where wye-wye-connected generator VTs are used. Coordination can be achieved by various methods (see IEEE Committee Report [B43]). — — For GFN grounding, the primary neutrals of the three wye-wye connected VTs are tied together and to the generator neutral using an insulated conductor. Grounding at the VT cubicle is not used since the resulting phase-to-ground inductive reactance comprising the magnetizing branch of the VT would detune the resonant circuit consisting of the generator system capacitance-to-ground and the neutral reactor. High zero-sequence voltages on the generator system are possible if too high a reactor coil constant is selected for the neutralizer. Also, if surge protective equipment is used on the generator, it must be selected on the basis of possible higher temporary overvoltages during ground faults. Voltages can be kept to within reasonable limits by selecting a value of reactor coil constant in a range from 10 to 50 without excessively reducing the sensitivity of the fault detection system (see Khunkhun, Koepfinger, and Haddad [B40]). 7.7 Scheme 7—Grounded wye-broken-delta VTs with ground overvoltage (complete shutdown) This protective scheme 7 should not be confused with grounding method VI illustrated in Table 1. Grounding method VI employs three distribution transformers connected grounded wye-broken-delta with a resistor in the broken-delta circuit. This grounding arrangement acts to provide a high-resistance ground for delta-connected generator, its (the impedances of 59 relay coil, the secondary leads and the primary VT secondary windings instead of an additional grounding resistor) for the two transformers delta-connected generator. On the other hand, the ground fault detection illustrated in Scheme 7 is intended to detect ground faults in the generator stator windings and the associated circuits rather than to provide a ground for the system. Protective Scheme 7 (see Figure 7) is a variation of protective Scheme 1. It employs the same 59 device as Scheme 1, and all comments regarding settings, sensitivities, advantages, and disadvantages made in Scheme 1 apply equally to Scheme 7. The basic difference in the two schemes is that in Scheme 1, a fault is sensed by the voltage across the neutral-grounding device, whereas in Scheme 7, the voltage measured across the broken-delta secondary windings of the VT provides this indication. For example, during a single-phase-to-ground fault on the generator leads, the phasor vector sum of the phase-to-ground voltages applied to the primary windings of the three VTs will be equal to three times the phase-to-neutral voltage of the generator. The voltage appearing at the terminals of the 59 device operating circuit will be the vector sum voltage divided by the VT ratio. Protective Scheme 7 could be used instead of Scheme 1 in any system using grounding methods I and II, and generator connections A and F (delta-grounded wye-connected GSU). Its use is generally limited to the case where two one or more machines, each with its own low-side circuit breaker, are connected to the same transformer primary GSU transformer’s delta winding. Scheme 1 is usually used for the individual machine protection, while Scheme 7 is used for the protection of the delta transformer winding and a generator(s), the associated bus(es), and the GSU’s delta windings. This application is discussed under Scheme 1, and a relay setting example is given in Annex A. As Figure 7 indicates, device 59 is connected to a separate set of the broken-delta secondary windings of the VTs, whose primaries are connected to the generator terminals. If such separate secondary windings are not available, a set of auxiliary VTs, connected grounded wye-broken-delta, may be used in conjunction with the Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. normally available wye-connected windings of the VTs. It should be noted that full line-to-line voltage appears across each VT during a ground fault; therefore, they shall be rated accordingly. A loading resistor may be placed across the broken delta to prevent possible ferroresonance. See IEEE Std C37.102 for further discussions on ferroresonance problems concerning VTs. Figure 7—Wye-broken-delta VTs with ground overvoltage relay (complete shutdown) 7.8 Scheme 8S—Start-up grounded wye-broken-delta VTs with ground overvoltage (complete shutdown) Scheme 8S (see Figure 8) is identical in the purpose and function to Scheme 5S, except that it is used when Scheme 7 (grounded wye-broken-delta VTs without an additional grounding resistor) is used instead of Scheme 1 for the primary ground fault protection. As indicated by the suffix S, it is intended for stator ground fault detection during the time that the protected machine is disconnected from the system and running with field excitation applied. The function 59S should be reasonably accurate between 25% and 100% of nominal frequency. Figure 8—Start-up grounded wye-broken-delta VTs with ground overvoltage relay (complete shutdown) Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. 7.9 Scheme 9—Secondary-connected CT, time-delay ground overcurrent (complete shutdown) Scheme 9 (see Figure 9) may be used for single phase-to-ground fault detection on generators that are connected to the transmission system through delta-wye connected transformers. They may be wye-connected generators that are high-resistance grounded through distribution transformers (grounding method I) or deltaconnected generators that use wye-delta grounding transformers (grounding method VI). This scheme measures the current through the secondary resistor (instead of the voltage across the resistor as in Scheme 1) to detect generator ground faults. A very inverse time-delay overcurrent relay is connected to the secondary terminals R-S of a CT, which is connected in series with the resistor. If a 5 kV to 15 kV class CT with a relaying accuracy classification C100 or higher at the ratio is used in this scheme, the CT will provide a conservatively rated current source.be conservative application. The CT ratio is usually selected so that the current in the relay is approximately equal to the current in the neutral of the generator or in the neutral of the grounding transformer. The overcurrent relay used in scheme 9 is, by design, very sensitive to harmonics, while the overvoltage relay of Scheme 1 is not. Therefore, the overcurrent relay must be set somewhat less sensitively than the Scheme 1 voltage relay. Refer to A.3.4 in Annex A for Scheme 9 relay settings. However, the disadvantage of a leeksless sensitive relay is offset by the fact that the overcurrent relay will provide some protection at reduced frequencies, while the tuned overvoltage relay will not. Scheme 9 is essentially a variation of Scheme 1 and the application discussion for Scheme 1 also applies to Scheme 9. Annex A provides an example of relay setting calculations and VT fuse coordination for both schemes. Figure 9—Secondary-connected CT, time-delay ground overcurrent (complete shutdown) 7.10 Scheme 10—Primary connected CT, time-delay ground overcurrent (complete shutdown) Scheme 10 (see Figure 10) is a variation of Scheme 9 except that the CT supplying current to the generator ground relay is connected in the neutral of the generator or the neutral of the grounding transformer instead of being in series with the resistor in the secondary circuit. This scheme may be used with a wide variety of grounding methods such as high resistance (grounding methods, I, II, and VI), low resistance (grounding method III), low reactance (grounding method IV), and tuned reactance (grounding method V). If the generator being protected is isolated from the network by the delta winding of the generator step-up transformer, and if the grounding impedance is high so that the maximum ground fault is limited to 25 A primary or less, then the same principles of protection described under Schemes 1 and 9 are applicable to Scheme 10. In this scheme, a CT with a 5/5 ratio should be used so that the current in the relay is approximately equal to the current in the neutral of the generator or in the neutral of the grounding transformer. A setting calculation example similar to that for Scheme 9 of Annex A will apply. Scheme 10 may be applied in conjunction with Scheme 1 and will provide an excellent backup for the failure of device 59 or its associated auxiliary tripping relay 86. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Certain low-impedance grounding applications of Scheme 10 may permit ground fault current of hundreds or even thousands of amperes. This is particularly true in those cases in which the generator is connected to the system, as in column E in Table 1. If grounding method III is utilized, it may mean that the generators are the only source of ground fault current on the system, and the generator grounding resistors may be sized to limit the maximum ground fault to some value less than the maximum phase-to-phase fault. If so, the generator neutral CT ratio will be relatively high (typically 400/5), and the generator ground relay shall be coordinated with the other system ground relays. This method will permit sensitive high-speed ground relaying for feeder faults, but has the disadvantage of allowing the possibility of serious generator damage. These same comments apply generally to column B if the machine is grounded using method IV. Since there is a direct path for zero-sequence current from the generator neutral through the autotransformer to the system, the generator ground relay should be set somewhat less sensitively. This prevents operations for system faults. Since the fault- current levels may be high, this results in considerable damage when a ground occurs near the high-voltage terminals of the unit being protected. This damage may be reduced if a Scheme 11 instantaneous ground overcurrent unit is included as an integral part of the generator overcurrent ground relay. Figure 10—Primary-connected CT, time-delay ground overcurrent (complete shutdown) 7.11 Scheme 11—Instantaneous ground overcurrent (alarm and/or complete shutdown) Scheme 11 (see Figure 11) includes an extended range instantaneous overcurrent relay that may be used in conjunction with either Scheme 9 or 10. When used in conjunction with Scheme 9, this device will provide for high-speed tripping of all ground faults in the transformer delta windings and bus work connected to the generator terminals. It also provides high-speed protection for all faults in the first 50% to 70% of the generator stator winding, measured from the high-voltage end of the machine. Thus, device 50H may be valuable in limiting machine damage, particularly in the case of nearly simultaneous ground faults on two different phases. However, if it is desired to coordinate the generator ground relaying with the generator VT fuses, Scheme 11 may have to be connected to the alarm only. This will still serve the purpose of assisting in the determination of fault location, since any fault that does not operate Scheme 11 is probably located inside the generator itself, and not in any externally connected equipment. To prevent incorrect operation for faults on the high-voltage side of the generator main step-up transformer, device 50H should be set for not less than three times the Scheme 9 overcurrent relay tap setting. This may require an extended range relay. If device 50H is connected to trip, it should be connected to the same auxiliary tripping relay as device 51 of Scheme 9. It should be noted that on most generators, even when a ground fault is detected and tripped high speed, ground fault current will continue to flow for several seconds, due to the slow rate of generator voltage decay. If the fault is external to the generator, however, and a generator breaker is provided (column F), then operation of Scheme 11 will isolate and clear the fault. This could prove to be of great value in preventing machine damage in the case of a phase-to-phase-to-ground fault in a main step-up or station service transformer. If Scheme 11 is used in conjunction with Scheme 10, it should, in general, be used for alarm purposes only, particularly in those cases where the generator ground relay shall be coordinated with other ground relays external to the generator protective zone. For example, if the generators of column E are grounded using Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. method III, the time overcurrent relay 51 of Scheme 10 may be set somewhat insensitively so as to coordinate properly with feeder ground relays. If so, some restricted faults may not be detected, and the generator ground relay will not trip. Device 50L of Scheme 11 can usually be set to detect these faults. When relay initiates an alarm is received (due to a Scheme 11 relay operation, the operator may take an action as necessary. When device 50L is applied in this manner, it will not only detect faults near the generator neutral that may not be sensed by device 51 of Scheme 10, but will also serve as an alarm for feeder faults. This may be useful in some instances, particularly in the case of a stuck breaker. These same comments apply generally to other generator connections, such as in column B, where the machine is not isolated front from the system by means of the delta winding of a generator step-up transformer. Figure 11—Instantaneous ground overcurrent (alarm and/or complete shutdown) 7.12 Scheme 12—Generator leads ground overcurrent (complete shutdown) Protective Scheme 12 (see Figure 12) may be used for ground fault protection for high- or medium-resistance grounded generators that are connected at generator voltage to an otherwise grounded system. Table 1 indicates that this Scheme is appropriate for wye-connected generators that are grounded using grounding methods I, II, VII, and VIII, and for delta-connected generators that use grounding methods VI, VII, and VIII. Scheme 12 may also be used for ground fault detection in ungrounded generators (grounding method VIII) that are connected to the system through an autotransformer with either a wound delta tertiary or a phantom tertiary, which is an apparent tertiary that a transformer manifests as the result of its core configuration. Relaying Scheme 12 consists of an instantaneous and an inverse time overcurrent relay. The relays are supplied with residual current from CTs in each phase of the generator leads. The CTs are sized to carry generator fullload current and are positioned on the generator side of the generator synchronizing breaker. The fault current detected by this scheme is the system contribution to a generator fault and not the contribution from the generator itself. Since the generator will contribute very little to a ground fault, there will be considerable difference in the relay current for a ground fault on opposite sides of the CTs. Therefore, a directional relay is not necessary. When the unit is operating while disconnected from the system, the ground fault current is limited by the high-resistance grounding method. It is not feasible to attempt to recognize a ground fault in the zone under this condition with an overcurrent relay supplied from residually connected CTs sized to carry generator full-load current. Also the relay may not see the fault at all because of the CT location in the circuit. Consequently, some other type of fault detection for use during start-up and shutdown must be provided. Relay scheme numbers with the S suffix shown in Table 1 can be used for this application. Two conditions must be satisfied when determining the settings for these relays. First, with the three individual CTs summed, some lack of symmetry is inevitable. This false residual current should be considered when selecting and setting the overcurrent relays. The relays should coordinate for the maximum expected value of residual current during an external system phase fault with maximum in feed from the generator. Second, the relays should coordinate for ground-current contribution due to the generator zone capacitance during an external system ground fault. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. The pickup of the instantaneous relay 50L 50G must be set above the maximum current possible from either of the aforementioned. This restriction does not apply to the inverse time overcurrent relay 51L51G because of its time-delay characteristics. The instantaneous relay will be set less sensitively and will operate faster than the time overcurrent relay. The advantage of Scheme 12 is that the three separate CTs may also be used for other relays, either in the phase or residual circuit. Figure 12—Generator leads ground overcurrent (complete shutdown) 7.13 Scheme 13—Three-wire generator leads with window CT, instantaneous ground overcurrent (complete shutdown) This relay scheme (see Figure 13) is a variation of Scheme 12 but makes use of a window-type CT that surrounds the phase leads to the generator. This limits the scheme to relatively small generators based on the availability of window CT sizes. The CT measures the ground (zero-sequence) current in the generator leads during a ground fault. Unbalanced current in the generator leads that do not contain any ground (zerosequence) current will not appear in the CT output. This type of application has the advantage of allowing a CT ratio less than the CT rating required to carry generator full load. Another important advantage is that a window CT is subject to negligible secondary residual error current. The CT window should be physically sized to be no larger than needed to accommodate the generator leads. This reduces any error current to a negligible value from flux unbalance in the ct. Experience indicates that precise centering of the generator leads in the centroid of the CT is not critical. With the system grounded, and the generator ungrounded or high-resistance grounded, the generator will contribute very little or no ground fault current to an external fault. Therefore, the instantaneous relay device 50G can be set safely to a low value. A medium accuracy class CT with a ratio of 50/5 or 100/5 is typical. An instantaneous relay setting of 10 A to 15 A, secondary current, has been found to be secure for ungrounded generators. A slightly higher setting may be required for a high-resistance grounded generator. For a ground fault on the generator side of this ct, the grounded system will provide current to operate the instantaneous relay. In this case, CT output results from the ground current in one generator lead producing flux in the CT that is not balanced out by the corresponding flux produced by current in the other generator leads. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Figure 13—Three-wire generator leads window CT, instantaneous ground overcurrent (complete shutdown) The ability of this scheme to recognize ground faults at various locations in the generator stator, relative to the generator neutral, is related to the type of system grounding. For example, if the system limits the available ground current to 400 A primary current, and if the instantaneous relay is set for 10 primary A secondary current, the relay can see a generator stator winding fault to within 2.5% of the neutral. If the available ground fault current from the system is higher, the relay can see generator stator faults even closer to the neutral. However, it is important to note that the instantaneous relay is essentially a definite time device while heating at the fault is proportional to I2t. Thus, the higher the available fault current, the greater will be the damage to the generator for ground faults near the generator terminals. During external ground faults, capacitive ground current (zero-sequence current) will flow in the relay. The capacitance between the CT and the generator is usually small, but it should be considered. This may have an influence on the relay’s pickup, and therefore, it would affect the sensitivity of the scheme. The major capacitances to ground considerations are cables, buses, surge capacitors, and the generator windings. If this capacitive ground current is significant, a time overcurrent relay, device 51G, should be used. This will provide the same primary ampere sensitivity with a short time delay. It is important to note that window type CTs (sometimes called doughnut CTs) used in this type of application do not have much iron. The purpose for that is to keep the physical size of the CT small, so as to fit into certain space limitations in switchgear. As a result, such CTs have a poor saturation characteristic. It is necessary to test such a CT in combination with its associated relay to determine the primary ampere pickup sensitivity of the package. For example, one supplier’s package, which consists of an instantaneous plunger type relay and a 10/1 turns ratio window CT, is guaranteed to pick up at 15 A primary current with the relay set for 0.5 A, secondary. Ideally, the primary ampere pickup is (0.5 A) (10/1) = 5 A, primary current. It is very important to note that when a high burden time delay overcurrent relay is used, the published time current characteristics of the relay are not valid for this application. Here again, device 51G and the CT should be tested as a system to determine its actual time-current characteristics. This is particularly important when coordinating a device 51G relay with backup ground relays so that for ground faults in the generator, device 51G will operate first. The backup ground relays usually are connected to higher accuracy CTs that permit the published time- current characteristic curves to be followed. 7.14 Scheme 14—Four-wire generator leads with window CT, instantaneous ground overcurrent (complete shutdown) This relay scheme (see Figure 14), often referred to as a generator self-balancing differential ground relay scheme, makes use of a window-type CT that surrounds the generator phase leads and the generator neutral lead. This scheme is similar in principle to Scheme 13 with its CT application restrictions, but is applicable to low-resistance as well as high-resistance grounded generators. The generator neutral lead passes through the CT, so that point N is toward the generator breaker side of the CT. Point N is then connected to the particular Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. method of generator neutral grounding. With this arrangement, the CT output to device 50G is a measure of the ground current coming from the system and the generator for a ground fault in the generator. For a ground fault in the system external to the generator, current will not flow in device 50G and the relay can safely be set to a low value. Figure14—Four-wire generator leads window CT, instantaneous ground overcurrent (complete shutdown) 7.15 Scheme 15—Generator percentage differential (complete shutdown) Protective Scheme 15 (see Figure 15) is the conventional generator percentage differential protection for phaseto-phase faults. If the generator is connected to a solidly grounded system—either directly or through an autotransformer—these differential relays will generally detect phase-to-ground fault within 10% to 15% of the generator neutral windings. Either a fixed or variable percentage differential relay may be used. Figure 15—Generator percentage differential (complete shutdown) 6.16 Scheme 16: Generator ground differential using product type relay Protective scheme 16 utilizes a product type overcurrent relay in a ground differential arrangement. The relay is connected to receive differential current in its operating coil circuit, and generator neutral 3I0 current in its polarizing circuit. The differential comparison is biased to assure that a positive restraint exists for an external fault even though the current transformers, RCN and RCL have substantially different performance characteristics. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. 7.16 Scheme 16—Current-polarized directional overcurrent relay Protective Scheme 16 (see Figure 16) utilizes a current-polarized directional overcurrent relay. The operating coil sees differential current of the phase CT’s residual and the neutral CT, with an auxiliary CT used to match ratios. The neutral CT also provides current for the polarizing coil to ensure operation for only ground faults. The auxiliary transformer uses a 1.1 or 1.2 factor to “overcorrect” the mismatch between phases and neutral CT ratios. The factor biases the system in the non-trip direction to assure that there is restraining “torque” to prevent misoperation for external faults where unequal CT performance could cause a false residual current. An auxiliary transformer factor of 1 can be used where analysis shows that unequal CT performance will be negligible. This scheme provides excellent security against misoperation for external faults and provides very sensitive detection of internal ground faults, without a high operating coil burden. Figure 16—Generator ground differential using product type relay 7.17 Scheme 17—Generator percentage differential relay on delta-connected generator (complete shutdown) Protective Scheme 17 (see Figure 17) is the conventional differential protection for a delta-connected generator. If the generator is connected to a solidly grounded system that ensures sufficient ground current to reliably operate the differential relays, no other ground fault protection is required. However, if under contingency system conditions, sufficient ground current cannot be ensured, differential protection should be supplemented by sensitive ground fault protective schemes such as Scheme 12 or 13. Scheme 5S or 8S may be used to detect generator grounds when the machine is running with its circuit breaker open and isolated from the grounded system. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. 7.18 Scheme 18—100% stator winding ground protection schemes Ground-fault relays for the complete protection of the generator stator winding This subclause describes relaying schemes for the detection of ground faults in the generator stator that may go undetected using the schemes described previously. Some provide complete wincingwinding coverage while others perform a complementary function to other schemes described. The importance of detecting ground faults close to the neutral point of the generator is not dependent on the need to trip because of fault current magnitude, since it may be negligible and will not, in general, cause immediate damage. If a second ground fault occurs, severe damage may be sustained by the machine because this may result in a short-circuit current not limited by the grounding impedance. This condition is aggravated if the first ground fault occurs close to, or at, the neutral of the generator, because all ground relays operating from the neutral point voltage or current become inoperative. Furthermore, if the second ground fault occurs in the same winding, the generator differential relay may also become inoperable since this condition can be regarded as an internal turn-to-turn fault. Though the negative sequence overcurrent or backup overcurrent relays will detect this fault, they are so slow that they will not prevent serious thermal damage. Even though a relay applied to detect this fault was to be instantaneous, mechanical deformation of the winding would still be expected. The schemes now in use for the detection of all stator ground faults are the following: a) ThirdCombination of fundamental and third harmonic neutral voltages b) Third harmonic terminal residual voltage by wye-ground broken-delta VTs c) Third harmonic voltage comparator d) Adaptive third harmonic level detector e) Neutral or residual voltage injection (comparator injection and measurement voltages) Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. f) Neutral subharmonic voltage injection (measurement of voltage and current) Some generators are designed to avoid the generation of triplen third harmonics, and. therefore, none of the third harmonic schemes described here may be applied to protect them. Since the generation of third harmonics contents varies with generator conditions, such as the loads (MVA), the real power (MW), and the reactive power (Mvar) as indicated in Modolf and Linders [B20], the relay settings should be based on the actual third harmonic measurement. The examples of third harmonic measurements are included in A.3.5.1 (835 MW steam turbine generator) and A.3.5.2 (50 MW cogeneration unit). There are often differences in the tripping philosophy for 100% relays versus other ground- fault relays with respect to the fault location. These practices consider the amount of ground fault current flowing and the capability of the machine to cope with the fault current. Some utilities may elect to trip the machine regardless of the location of the ground fault in the stator winding or the size of the machine. Others may trip large baseload units with the conventional ground fault relay only, and alarm with the relay that detects faults in the neutral region, so as to permit inspection and possible repair during normal shutdown for maintenance. This election to “alarm only” for faults in the neutral region accepts the risk of much greater damage that would occur in the event that a second ground fault occurred, and is done in the interests of keeping an important machine in service. However, all ground-faults must be considered serious, and it is recommended that immediate tripping be initiated. 7.18.1 Scheme 18a—Combination of 60 Hz overvoltage (59G) and 180 Hz undervoltage (27TH) relays This scheme shown in Figure 18 and Figure 19 uses an undervoltage relay 27TH to supplement the overvoltage relay 59G of Scheme 1. The third harmonic undervoltage relay detects an absence of third harmonic voltage at the generator neutral resulting from a fault near the neutral or failure of the neutral transformer. The 27TH and 59G relays must be filtered to prevent fundamental or third harmonic voltages respectively from affecting operation. The 27TH relay should, if not self-protecting, include circuitry to protect its coil from sustained overvoltage. This scheme offers the advantage of not requiring any additional high -voltage equipment other than that needed for conventional ground- fault detection schemes for single- stator generators. The scheme can also be used for cross-compound and split-winding machines by adding a second VT and third harmonic relay to monitor the voltage at the neutral of the ungrounded stator winding. The scheme provides protection when the main breaker is open, provided that the terminal voltage is above the pickup of the supervisory relay 59C. Supervision is required during start-up and shutdown either with a breaker contact or an undervoltage relay so that the relay is disabled when the generator is off-line. Some generators provide very low levels of third harmonic voltage when the generator is lightly loaded. In order to improve the security of this scheme, an under power relay (device 32) can supervise the third harmonic neutral undervoltage relay. This absence of 100% coverage until relay 59 C picks up is a disadvantage of this scheme. The settings of the 27TH and 59G relays should be analyzed to ensure overlap for all fault locations. Typically, not more than 1% of third harmonic voltage with reference to rated voltage is needed to provide adequate overlap. Third harmonic voltage is a function of load. Normally 10% to 30% of the stator winding from the neutral point towards the machine terminal can be protected by the 27TH relay. Device 27TH operates for opens or short circuits of primary or secondary windings of the neutral grounding transformer but will not detect an open grounding resistor. 7.18.2 Scheme 18b—Third harmonic terminal residual voltage relay at the generator terminal This scheme, shown in Figure 20 and Figure 21, is similar to Scheme 18a except that it utilizes third harmonic voltage at the machine terminals. This is supplied by a wye-grounded broken-delta transformer, which can be wye-wye for digital relays. Upon the occurrence of a generator neutral ground, the third harmonic voltage available at the line terminals of the generator becomes elevated. The accompanying overvoltage is used to operate a relay used in this application and must be set in such a way as to be unresponsive to the maximum Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. third harmonic voltage appearing at this point during normal system operation. An advantage of this scheme is that it will also detect ground faults on the bus or in the delta winding when the generator disconnect is open. However, the need for a three-phase VT on the machine terminals is a disadvantage. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. 7.18.3 Scheme 18c—Third harmonic voltage comparator Like Scheme 18a, this scheme supplements the conventional 95% relay to provide 100% coverage for ground faults in the generator stator winding. This scheme was also designed primarily for high-impedance grounded machines. This scheme, shown in Figure 22 and Figure 23, utilizes the fact that the third harmonic residual voltage at the terminals of a machine increases, while the third harmonic voltage at the neutral decreases, for a fault near the neutral. The ratio of the third harmonic residual voltage to the neutral third harmonic content may be nearly constant for all load conditions on many unfaulted machine. The slight variation in this ratio may necessitate a reduced sensitivity setting. Overlap between the two relay functions 59GN and 59D will exist. The settings for both relays should be determined during field testing in conjunction with commissioning. The third harmonic differential relay 59D detects ground faults near the neutral as well as at the terminal. Relay 59GN, which measures the fundamental frequency neutral voltage, detects a fault in the upper portion of the winding as well as overlapping much of the winding covered by 59D. The (comparator) relay sensitivity is least for a fault near the middle of the windings. At some point on the winding, the difference between the neutral and terminal third harmonic voltages is equal to the relay setting. Double ground faults tend to reduce the sensitivity for the differential relay, and multi-winding machines offer application difficulties that require careful consideration. Figure 22—Third harmonic ratio comparator (discrete relays) Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Figure 23—Third harmonic ratio comparator (multifunction relay) The need for multiple VTs and the requirement for field tests during commissioning to determine relay settings are among this scheme’s disadvantages. However, this scheme has the advantage of providing the optimum 100% coverage for high-impedance grounded machines. 7.18.4 Scheme 18d—Adaptive third harmonic level detector This scheme (see Figure 24) is similar to Scheme 18c in that both the third harmonic voltage at the neutral and the third harmonic voltage of the residual at the terminals are used in the scheme shown in Figure 24 to cover the winding near the neutral. The two voltages are used to derive the third harmonic source voltage of the generator (E3SOURCE) by vector combination of the signals. The third harmonic voltage at the neutral and that of the residual voltage at the terminal are continuously compared with the derived E3SOURCE to detect a ground in the first 15% of the windings near the neutral. The detection scheme indicates a fault in its zone of coverage if the third harmonic voltage at the neutral is less than 15% of E3SOURCE and if one-third of the residual third harmonic at the terminals exceeds 85% of E3SOURCE. Under ideal conditions, the two comparisons are equivalent, but it has been established in practice that the two comparisons behave differently over the MW and Mvar operating range of typical generator installations. To maximize the sensitivity at low levels of E3SOURCE while maintaining security, it is advantageous to “AND” the results of the two comparisons. This approach in effect utilizes adaptive undervoltage overvoltage level detectors, where the setting level adapts to the level available relaying signal, i.e., the magnitude of E3SOURCE. It is imperative that the detectors are blocked when the third harmonic source voltage is less than some minimum value, below which the voltage signals are considered unreliable for relaying. A level of 0.75% of the rated phase-to- neutral voltage of the generator is considered to be secure. Successful application of this approach requires that the third harmonic voltage at the neutral and one-third of the residual third harmonic voltage at the terminals under normal conditions do not encroach on the undervoltage and overvoltage detector levels of 15% and 85% of E3SOURCE, respectively. If the accepted practices are followed in choosing the value of the grounding resistor (see 6.1 and A.1.1 for an example), theoretically the voltage level at the neutral is approximately equal to one-third of the residual voltage level, which means that both of the measured levels are at approximately 50% of E3SOURCE and are, therefore, well removed from the threshold levels of the detectors. Published measurements (see Marttila ]), however, indicate that the levels can vary in a wide range of 10% to 80%. While the 80% level approaches the threshold level, the neutral voltage was secure, varying in the range 50% to 85%. This illustrates the benefit of “ANDING” the outcome of the two detectors. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Like Scheme 18c, 100% coverage is achieved in conjunction with a fundamental neutral overvoltage detector. Healthy overlap can exist between the neutral overvoltage and third harmonic under/overvoltage detector coverage, but this can be affected by the allowable sensitivity of the neutral overvoltage detector. The appropriateness of the setting for the neutral overvoltage detector should be confirmed with the measurements during the commissioning procedure. With the approach taken, no settings are required for the third harmonic. However, it may be desirable to make measurements of the third harmonic levels on the generating unit to determine the levels of the third harmonics, as previously mentioned. This method has only been used in highresistance grounded installations. The requirement for multiple VTs is a disadvantage. However, this scheme has the advantage of providing predictable coverage of the winding down to very low levels of third harmonic voltage. In addition to a grounded stator, the scheme detects other abnormal grounding conditions, such as an open disconnect switch at the neutral or a shorted grounding resistor. Furthermore, the detection is effective as soon as the excitation is applied and the machine is near synchronous speed. This covers the period prior to synchronizing to the system. Figure 24—Adaptive third harmonic level detector 7.18.5 Scheme 18e—Subharmonic voltage injection (comparison of injected and measured signals) This Scheme, shown in Figure 25, using a voltage injection at the neutral or residually in the broken-delta VT secondary, can detect ground faults anywhere in the stator winding of the generator, including the neutral point. Full ground fault protection is available when the generator is on turning gear and during start- up if the injected voltage source does not originate from the generator. Certain schemes inject a coded signal at a subharmonic frequency that can be synchronized with the system frequency (e.g., 12.5 Hz for a 50 Hz system, and 15 Hz for a 60 Hz system). When compared to other injection schemes, this coding improves the security of the relay system without sacrificing dependability. For proper relay performance, the scheme is dependent on a reliable subharmonic source. The use of subharmonic frequencies may offer improved sensitivities due to the higher impedance path of the generator capacitances at these frequencies. Such frequencies are not normally present at the generator neutral. The economic penalty associated with providing and maintaining a reliable subharmonic source and injection equipment is a disadvantage. The major advantage of neutral injection schemes is that they provide 100% ground fault protection Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. independent of the 95% ground fault protection schemes, including when the generator is on turning gear and during start-up. In addition, some of these injection schemes are self-monitoring and most have sensitivity independent of load current, system voltage, and frequency. In applying neutral injection schemes, consideration should be given to the additional neutral transformer where required. This transformer should be designed so as not to interfere with the insulation coordination of the generator system. NOTE 1—Low pass or notch tuned for 15 Hz. Relay inputs filtered for sensitivity at subharmonic injection frequency. NOTE 2—Re >= 4.5 Rp. NOTE 3—Subharmonic injection applied (15 Hz). NOTE 4—“b” contact of 86G is used to de-energize the 86G coil after its operation. Figure 25—Subharmonic voltage injection at neutral 7.18.6 Scheme 18f—Subharmonic voltage injection (measuring voltage and current) This scheme (see Figure 26) is employed in conjunction with Schemes 18a, b, c, or d. Schemes using subharmonic current injection at the generator neutral can detect ground faults anywhere in the stator winding of the generator, including the delta windings of the generator step-up transformer (GSU). Full ground fault protection can be provided without the field being energized, such as when the generator is on turning gear and during initial start-up with the independent subharmonic voltage supply. Certain schemes inject a coded signal at a subharmonic frequency that can be synchronized with the system frequency (e.g.,12.5 Hz for a 50 Hz system, or 15 Hz for a 60 Hz system). This coding improves the security of the relay system without sacrificing dependability. The scheme shown in Figure 26 uses voltage and current measurements in the secondary circuit of the generator grounding transformer. The voltage and current measurements are derived from the injected signal as it is placed across the generator grounding transformer secondary. In this manner, the reflected impedance of the generator, bus-work, and delta winding of the GSU is measured. If a ground fault is not present anywhere in the generator zone, the impedance measured is the natural capacitive coupling to ground of the entire generator zone. If a ground fault develops, the impedance becomes less than natural capacitive coupling values, and alarm and/or trip set points are applied. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. The use of subharmonic frequencies may offers improved sensitivity to high impedance ground faults due to the greater impedance exhibited by generator zone lumped capacitance at these lower frequencies. Such frequencies are not normally present at the generator neutral circuit without subharmonic injection. Figure 26—100% stator ground fault detection by subharmonic voltage injection The major advantage of neutral subharmonic injection schemes is that they provide 100% ground fault protection even when the generator is not in service and during initial start-up prior to application of the field. In addition, this scheme does not have the potential disadvantage of non-operation or misoperation due to values of load current, system voltage, and frequency. The major disadvantage of a neutral injection scheme is the economic penalty associated with providing and maintaining reliable subharmonic source and injection coupling equipment. In addition, caution should be exercised when servicing an off-line machine, for if the injection voltage remains energized during service, hazardous voltages will be present at the generator terminals. Due to this safety concern, the injector system is typically supplied from the generator vts. With the injector being supplied by the generator VTs, if the generator is taken off-line with the VTs racked out and grounded, no injection quantity can be produced. 7.19 Scheme 19—Alternate stator winding protection with high-impedance relays Protection for single-phase-to-ground faults in the stator winding may be provided by utilizing high- impedance differential relays. While the high-impedance differential relay is normally associated with bus protection, synchronous generator applications, although limited in number, have been successfully implemented. Scheme 19a, shown in Figure 27, uses three high-impedance relays, device 87H, to provide protection for both multiphase faults and single-phase-to-ground faults. Schemes 19b and 19c, shown in Figure 28 and Figure 29, use a single high-impedance relay to detect ground faults only. Two alternate connections are shown—the first one uses all phase-current transformers on both sides of the machine; the second uses a neutral CT on the neutral side of the machine. Since the voltage pickup level of a high-impedance differential relay is calculated to prevent operation for worst-case CT saturation conditions during an external fault, excellent security is provided. The minimum primary current required for operation on an internal fault is easily calculated, and from this value the percent coverage of the stator winding from output bushings to neutral point can be determined. The percent coverage Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. for ground faults is dependent upon the grounding impedance. The example in Annex B illustrates a procedure used to determine the percent coverage. 7.20 Scheme 20—Generator neutral overcurrent protection for an accidental solid ground fault A variation of Scheme 11 may be used in those installations where the neutral grounding equipment is located at some distance from the generator neutral. Here, the possibility exists that the neutral could accidentally become solidly grounded before it reaches the grounding equipment. If a phase-to-ground fault then occurs in the generator or associated bus duct, the current-limiting benefits of the neutral grounding equipment will be lost, and a high magnitude of fault current will be present. In such a situation, an overcurrent relay connected to a relatively high-ratio CT, located close to the generator neutral connection as shown in Figure 30, will provide detection. This relay will also provide protection in the event that the secondary of the neutral grounding transformer becomes short circuited, thus bypassing the neutral voltage relay. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Figure 30—Neutral ground fault overcurrent protection for high-impedance grounded generators An instantaneous relay, or one with a few cycles of time delay, would be appropriate for this application. A time overcurrent relay may be considered if selective tripping is required for a generator connected to a bus feeding several loads. The sensitivity of the relay is not critical due to the magnitude of fault current present. Although differential protection will detect this type of fault, there could be certain portions of the bus duct associated with a unit-connected generator that are covered by only a single differential scheme. In such an instance, the overcurrent relay will provide excellent backup protection. 7.21 Scheme 21—Directional ground fault protection for high-resistance ground bus connected generators (multi-ground) In general, the selectivity of stator ground fault in multiple high-resistance grounded generators is extremely difficult. However, this scheme, shown in Figure 31, with the directional ground overcurrent relay (device 67N) allows selective direction of stator ground faults on high-impedance grounded generators, which are bussed together. In this scheme the CT ratio of window CTs can be as small as a 10 (= 50 A/5 A). Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Figure 31—Directional ground protection for multiple high-impedance ground bus connected generators 7.22 Scheme 22—Hybrid ground protection for high-resistance grounded bused generator and ungrounded distribution system In industrial applications, mainly feeding the local loads (paper mills, steel mills, chemical plants, etc.) and transmitting the excess power to utility system, many generators are directly connected to a bus that services local loads. Figure 32 illustrates this type of configuration. Hybrid grounding can be applied or retrofitted to an existing low-impedance grounded scheme on these types of generators. The generator is both high-impedance and low-impedance grounded. Under normal operating conditions, both generator ground sources are operated in parallel. For a ground fault on the industrial system, the ground fault current contribution from the generator will typically be almost entirely from the low- impedance (suppressed ground fault current to a range of 200 A to 400 A primary current) source. This provides the required level of system ground current for proper ground relay operation, allowing the generator to supply the local load when the utility system is unavailable (breaker connected to GSU transformer open). When there is a ground fault in the generator stator windings or associated bus connection to the generator breaker, the ground differential (87GN) will operate to initiate a unit shutdown. As part of the generator tripping, the ground interruption device in series with the low-impedance grounding resistor is tripped. This leaves the generator through only the high-impedance path that typically reduces ground fault current to the range of 3 A to 10 A primary current. This greatly reduces stator ground fault damage during generator “coast down.” Studies (see Powell [B34]) have shown that major damage occurs after generator tripping during this coast down period. Reducing fault current during this period greatly reduces stator ground fault damage. If the power system is designed to operate either with both sources in parallel or with either source being independent, then the hybrid system shown in Scheme 22 will provide a ground protection. The generator is both low grounded and high-resistance grounded. Under normal condition, the system obviously is lowresistance grounded by the generator. If the ground fault is in the generator zone itself, the devices 87GN and/or 50G relay trips the low-resistance ground source. Since the high-resistance ground source is also connected to the generator, the generator grounding is switched to high-resistance grounding and thereby prevents any transient overvoltage condition. Due to a low-resistance grounding scheme prior to switching to a highresistance scheme, 50G will detect a ground fault in the distribution system and isolate the fault by tripping the Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. local load breaker instantaneously. Special care must be taken with regard to the specification and application of the switching device associated with this scheme. If an auxiliary transformer (delta connection towards generator bus) is installed for feeding local loads in Scheme 22, the generator’s ground source will be isolated from the loads. Consequently, Schemes 18a, 18b, 18c1, 18c2, 18e, or 18f can be applied. 8. Miscellaneous considerations There are some other considerations associated with a generator grounding protections such as the location of CT at a neutral. There are three possible CT locations, as shown in cases A, B, and C in Figure 33. Cases A and B are commonly used in Schemes I, II, III, and IV. Case C is used commonly in Schemes I and VI. In case A, this scheme will provide backup ground fault protection and can detect an inadvertent ground of the neutral distribution transformer. The CT needs to be considerably small ratio (e.g., 50 A/5 A or 100 A/5 A) and fully rated to generator voltage. In case B, this scheme is a variation of the previous scheme except the CT can be a 600 V class. Case C is another method to provide backup ground protection. In this scheme, the 3I0 current is in the order of some hundreds of amperes and can provide great sensitivity. However, cases B and C have the disadvantage of loss protection during a ground fault on the primary of the distribution transformer. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Case A: Backup ground overcurrent protection—CT between neutral grounding transformer and stator windings Case B: Backup ground overcurrent protection—CT located between neutral grounding transformer and ground-mat Case C: Backup ground overcurrent protection—CT in secondary circuit of neutral grounding transformer Figure 33—Different CT locations (A, B, C) at generator neutral for ground fault protection Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. 9. Protective device function numbers All of the different protection schemes, illustrated in this document, utilize protective relays that are represented or designated by device function numbers. It is the purpose of this clause to define, in broad terms, the following required characteristics of the relays designated by these numbers. Specific definitions for device numbers are found in IEEE Std C37.2. 1) Device 02. A dc operated auxiliary timing relay. The range of adjustment, if any, should be selected to accommodate the desired time delay. 2) Device 11G. A generator multifunction packaged relay. 3) Device 27. An instantaneous undervoltage supervisor relay. 4) Device 27THD. An instantaneous third harmonic undervoltage relay used for a differential relay 5) Device 27TH. An instantaneous third harmonic undervoltage relay. 6) Device 50G. An instantaneous ground overcurrent relay that is designed in coordination with the associated toroidal CT to have a very sensitive pickup capability. 7) Device 50H. An instantaneous overcurrent relay. There is no need to desensitize this device to third harmonic current because of its relatively high pickup setting. 8) Device 50L. A standard instantaneous overcurrent relay. Its range of pickup adjustment is such that it can be set to pick up above any false residual current resulting from CT saturation during faults beyond the generator main circuit breaker. 9) Device 51. A sensitive time overcurrent relay. The time delay is inversely related to the magnitude of the input current. The sensitivity of this relay and its CT to fundamental current will detect single- phaseto-ground faults in the generator stator winding to within a few percent of the distance to the neutral of the winding. The sensitivity of this relay to third harmonic current should be such that the maximum third harmonic current that flows in the generator should not cause it to operate. This relay should be capable of coordinating with the primary and secondary fuses that are used with any VTs connected to the generator leads, where such coordination is desired. Examples of fuse and relay coordination are found in Annex A. 10) Device 51G. A non-directional ground time overcurrent relay. It is usually a summation of three- phase current or residual current. 11) Device 51I. A time-delayed overcurrent device that is only sensitive to lower than fundamental frequencies. 12) Device 51L. A standard time overcurrent relay. The time delay is inversely related to the magnitude of the input current. The pickup range is such that the relay can be set to pick up above any false residual current resulting from CT saturation during faults beyond the main circuit breaker of the generator. 13) Device 51N. A neutral ground overcurrent relay that is usually connected to the neutral point of a set of CT. 14) Device 59GT. A time-delay overvoltage relay that is designed to be very sensitive to fundamental frequency voltage but insensitive to third and higher harmonics. The sensitivity to fundamental frequency voltage should enable the device to detect single-phase-to-ground faults to within a few percent of the distance to the neutral end of the winding. In general, the relay will not be suitable to detect faults at, or very close to, the neutral point. Because this relay will be able to detect phase-toground faults in the primary and secondary circuits of any VT connected between the generator leads and ground, the time delay associated with it should be suitable to coordinate with the VT primary and secondary fuses. In some cases, because of the sensitivity of this relay, it may not be able to withstand, for a prolonged period, the maximum value of voltage to which it may be exposed in the event of a single-phase-to-ground fault at the generator terminals. This should be investigated if this device is used for alarm purposes, or if the tripping is delayed by some external time delay for any reason. 15) Device 59. An ordinary instantaneous overvoltage relay that has a pickup range of 50% to 70% of nominal terminal voltage. Its purpose is to monitor fundamental frequency voltage at the terminals of Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. the generator to determine when the main generator breaker has closed or when field excitation has been applied. 16) Device 59THD. An instantaneous third harmonic overvoltage relay used for a differential relay. 17) Device 59H. An overvoltage relay with no intentional time delay required. It should have a pickup range at a fundamental frequency voltage somewhat lower than the continuous rating of the associated 59 device. It should not operate as a result of the maximum zero-sequence harmonic voltage present during normal conditions. The purpose of the 59H device is to protect the associated device 59 during a singlephase-to-ground fault that produces voltage in excess of its continuous rating. 18) Device 59GI. A ground instantaneous overvoltage relay that is very sensitive to the fundamental frequency voltage and to somewhat lower frequencies, but insensitive to the third and higher harmonics. See device 59 for additional information. 19) Device 59S. A protection provided against a phase-to-ground fault(s) during the time that the generator is not connected to the system. This includes those intervals when the machine is being brought up to speed or being shut down, with field excitation applied. During these periods, the machine voltage magnitude and frequency will be below normal. For this reason the 59S device should have a pickup characteristic that is essentially proportional to frequency. Because the relay is only in service when the main circuit breaker of the machine is open, no coordination with other protective devices is required, and a high speed, sensitive relay may be applied. A device having a constant volts/hertz pickup is desirable for this application. 20) Device 59TH. A third harmonic instantaneous overvoltage relay sensitive to the third harmonic component. 21) Device 59X. An ac-operated, self-reset multi-contact auxiliary relay. 22) Device 64G. A generator ground relay. 23) Device 67N. A directional ground overcurrent relay. 24) Device 86. A hand reset, multi-contact, dc-operated auxiliary relay (lockout relay). 25) Device 87. A conventional generator percentage differential relay. 26) Device 87H. A high-impedance phase or ground differential relay, whose sensitivity is independent of the load current and requires no coordination with external relays and devices. 27) Device 87N. A sensitive, short-time, product-type time overcurrent relay with two coils: an operating coil and a polarizing coil. The relay operates when the current in the two coils have the proper relative phase angle and magnitude of the product of the current in the two coils exceeds the pickup setting. 28) Device 87NH. Single element high-impedance differentials relay measuring the residual ground differential quantity. The relay sensitivity is independent of load current and requires no coordination with external relays and devices. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Annex A (informative) Stator ground protection for a high-resistance grounded generator A.1 Examples The following example illustrates two methods of calculating the resulting fault voltages and currents in a resistance type grounded generator and selecting distribution transformer. The two methods are as follows: a) Actual measurement method and symmetrical components analysis method b) Phasor diagram analysis Sample calculations for a GFN application, including a comparison of performance (ability to limit fault current and sensitivity to fault resistance) against resistance type grounding are illustrated in this annex. Additional examples for calculating high-resistance grounding and resonant grounding can be found in Annexes A and B of IEEE Std C62.92.2. A 974 MVA, 22 kV generator is unit-connected to a 345 kV transmission bus and grounded through a distribution transformer as shown in figure A.1. The phase-to-ground capacitive reactance of the generator, transformers, leads, and associated equipment is 6780  per phase. The distribution transformer is rated 13 280 V – 240 V. The secondary resistor is 0.738 . The secondary resistance reflected to the primary circuit is (R secondary) · (turns - ratio)2.   Rn = 0.738 · (13280/240)2 = 2260  A.1 Symmetrical components solution With symmetrical components, phase-to-ground faults are calculated by connecting the positive, negative, and zero- sequence networks in series as shown in a) of figure A.2 and solving for I0. Thus, the equivalent positive and negative sequence impedances of the system and the zero-sequence impedance of the generator are extremely small, as compared to the neutral resistor equivalent circuit and the distributed zero-sequence capacitance, and therefore can be neglected. For a unit-connected generator, the zero-sequence network is open at the delta winding of the power transformers and consists of the generator neutral resistor and the phase-to-ground capacitance of the generator windings and associated equipment. The equivalent circuit will then be that shown in b) of figure A.2. I0=I0n + I0c where is the total zero-sequence fault current I0 is the zero-sequence current flowing in the neutral resistor I0n is the zero-sequence current flowing in the distributed capacitance I0c The total fault current If is equal to 3I0, which is equal to In + Ic. The current through the generator neutral for a single phase-to-ground fault at the generator terminals is Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. The fault-current contribution from the capacitance is where –jX c  Xc Elg is the generator phase-to-neutral voltage Elg equals 22 000/ 3 = 12 700 V Rn equals 2260  In = 12 700/2260 = 5.62 A I c = j ---- 6780 --- = J5.62 A 12 700  3 I f = 5.62 + j5.62 = 7.95 45 A Is  is the generator neutral current multiplied by the turns ratio of the distribution transformer. This current flows in the distribution transformer secondary wiring and through the resistor. I s = 5.62  13 280 ---------------- = 311 A 240 The voltage across the secondary resistor is VR = IsR = 311 · 0.738 = 229.5 V The KVA rating of the grounding transformer is KVA = Is · transformer secondary voltage rating (kV) = 311 · 0.240 = 74.65 Therefore, select a 75 KVA transformer. A.2 Phasor diagram analysis The single line diagram for the equivalent phase-to-ground capacitance of the generator windings, bus duct, and generator step-up transformers is shown in a) of figure A.3. In a balanced three-phase system, the neutral current will be zero, as illustrated in b) of figure A.3. The capacitive current in each phase is Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. The sum of the current is Ic= Icx + Icy + Icz  I c = 1.87 90 + 1.87 330  + 1.87 210  =0 If we place a line-to-ground fault on phase X between the generator stator terminal and the bushing of the generator step-up transformer, the equivalent circuit will be shown in c) and d) of figure A.3. To obtain the fault current If, the following loop equations may be written: E x – l 1  –jX c  + I 2  –jX c  – E y = 0 E x – E y – l 1  –jX c  + I 2  –jX c  = 0 E y + l 1  –jX c – I 2  –jX c  – I2  –jX c  – E z = 0 E y – E z + l 1  –jX c  – 2I 2  –jX c  = 0 –I 3 R n –E x = 0 Adding equations A2 and B2 ExEzI2 (jXc) = 0 I2 Ex – E z ----------------c Substituting for I2 in equation A2 From c and d of figure A.3 If = I1  I3 Icy = I2  I1 Icz =  I2 E x = 12 700 0  V Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. E y = 12 700 240 V E z = 12 700 120  V Rn = 2 260  Xc = 6 780  The current in generator neutral is From d) of figure A.3 the total fault current is the sum of the capacitive and neutral current. Figure A.3e) illustrates the phase relationships of the current. The current through the primary of the grounding transformer is 5.62 A. The secondary voltage is 229.5 V, and the resistor current is 311 A. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. A.1.1 Actual measurement method The following is a sample calculation of neutral grounding transformer for the high-resistance grounding methods I (see 6.1) and II (see 6.2). Equipment data: 1450 MVA, 24 kV generator (Cgen) ........ 0.230 µF Surge bank (Csb) .....................................0.125 µF GSU transformer (Cgsu) .......................... 0.004 µF Auxiliary transformer (Caux) ................... 0.001 µF ISO-phase bus (Cbus) .............................. 0.007 µF The capacitive reactance-to-ground (Xcg) seen at the neutral is equal to the parallel combination of the capacitive reactance-to-ground of all three phases, which is one-third of 7200 Ω and equals 2400 Ω, as shown in Equation (A.1): (A.1) A 24 000 V/240 V distribution transformer is used to ground the generator neutral. Therefore, the secondary resistor must be calculated so that the effective neutral resistance is equal to or less than Rn(= 2400 Ω), as shown in Equation (A.2): Turns ratio, N = 24 000 V/240 V = 100 (A.2) The exact value of resistance is not critical. Equipment capacitive tolerances and the resistance change due to temperature rise cause this calculation to be only an estimate. The conservative approach for lower transient overvoltages is with a greater I2R loss or higher generator fault current. Reducing the ohmic value of the secondary resistor to reduce transient overvoltage may tend to increase damage resulting from ground faults. A slightly smaller resistor could be selected based upon operational practice of the resistor and the rated transformer capacity (kVA). The maximum neutral voltage is assumed to be phase-to-ground voltage (= Vgen L–L /√ 3). Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. The power rating of the resistor (PR) can be calculated using full transformer voltage as shown in Equation (A.3): PR = I2R = 5772 × 0.24 W = 79.9 kW (A.3) The thermal rating of the transformer is calculated using full transformer voltage and Equation (A.4): Transformer rating (kVA) = Vsec rated × Isec max (A.4) The basis for the transformer rating is the thermal rating current (Isec max). This value is the current through the neutral device during a ground fault condition. Implicit in the thermal current rating is a continuous duty multiplying de-rating factor. Grounding resistors must be rated to withstand the full thermal current. Grounding transformers can be rated on a short-time basis. For example, the 10 min overload de-rating factor of a grounding transformer following no-load is approximately 2.6 (use emergency loads following no-load). The de-rated grounding transformer size = 138 kVA/2.6 = 53 kVA. A 50 kVA transformer is adequate for this application. A.1.2 Symmetrical components method A 975 MVA, 22 kV rated generator is unit-connected to a 345 kV transmission bus and grounded through a distribution transformer as shown in Figure A.1. The phase-to-ground capacitive reactance of the generator, transformers, leads, and associated equipment is 6780 Ω per phase. The distribution transformer primary and secondary windings are rated 13 280 V and 240 V (or 13 280 V/240 V). The secondary resistor is 0.738 Ω. The secondary resistance reflected to the primary circuit is (Rsecondary) × (turns ratio)2. See Equation (A.5). Rn = (Rsecondary) × (turns ratio)2 = (0.738 Ω)(13 280 V/240 V)2 = 2260 Ω (A.5) With symmetrical components, phase-to-ground faults are calculated by connecting the positive, negative, and zero-sequence networks in series as shown in Figure A.2 and solving for I0 for a fault at the GSU terminal. Thus, the equivalent positive and negative sequence impedances of the system and the zerosequence impedance of the generator are extremely small, as compared to the neutral resistor equivalent circuit and the distributed zero-sequence capacitance, and therefore can be neglected. For a unit-connected generator, the zero-sequence network is open at the delta winding of the power transformers and consists of the generator neutral resistor and the phase-to-ground capacitance of the generator windings and associated equipment. The equivalent circuit will then be that shown in Figure A.3 and Equation (A.6). I0 = I0n + I0c (A.6) where I0 is the total zero-sequence fault current I0n is the zero-sequence current flowing in the neutral resistor I0c is the zero-sequence current flowing in the distributed capacitance Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Figure A.1—Typical generator ground protection single line diagram The total fault current If is equal to 3I0, which is equal to In + Ic. The current through the generator neutral for a single-phase-to-ground fault at the generator terminals is shown in Equation A.7 Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. The fault current contribution from the capacitance is shown in Equation (A.8): Ic = 3I0c = 3Elg/(–jXc) = j3Elg/Xc (A.8) where Elg = the generator phase-to-neutral voltage Elg = (22 000 V)/√ 3 = 12 700 V Rn = 2260 Ω In = 12 700 V/2260 Ω = 5.62 A Ic = j (12 700 V × 3)/(6780 Ω) = j5.62 A If = 5.62 A + j5.62 A = 7.95∠45° A Is equals the generator neutral current multiplied by the turns ratio of the distribution transformer. This current flows in the distribution transformer secondary wiring and through the resistor as shown in Equation (A.9): Is = 5.62 A × (13 280 V/240 V) = 311 A (A.9) The voltage across the secondary resistor is shown in Equation (A.10): VR = Is × R = 311 A × 0.738 Ω = 229.5 V (A.10) The kVA rating of the grounding transformer is shown in Equation (A.11): (Is) × (transformer secondary voltage rating, kV) = 311A × 0.240 kV = 74.65 kVA (A.11) Therefore, a 75 kVA transformer is selected. NOTE—Some users have been applying a de-rating factor. A.2 Phasor diagram analysis The single-line diagram for the equivalent phase-to-ground capacitance of the generator windings, bus duct, and generator step-up transformers is shown in Figure A.4. In a balanced three-phase system, the neutral current will be zero, as illustrated in Figure A.5. The capacitive current in each phase is shown in Equation (A.12), Equation (A.13), and Equation (A.14): Icx = Ex/(–jXc) = (12 700 ∠0° V)/(6780 Ω ∠–90°) = 1.87 ∠90° A (A.12) Icy = Ey/(–jXc) = (12 700 ∠240° V)/(6780 Ω ∠–90°) = 1.87∠330° A (A.13) Icz = Ez/(–jXc) = (12 700 ∠120° V)/(6780 Ω ∠–90°) = 1.87 ∠210°A (A.14) The sum of the current is shown in Equation (A.15): Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Ic = Icx + Icy + Icz If we place a line-to-ground fault on phase X between the generator stator terminal and the bushing of the generator step-up transformer, the equivalent circuit will be as shown in Figure A.6 and Figure A.7. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. To obtain the fault current If, the following loop equations may be written: Ex – I1 (–jXc) + I2(–jXc) – Ey = 0 (A.16) Ex – Ey – I1(–jXc) + I2(–jXc) = 0 (A.17) Ey + I1(–jXc) – I2(–jXc) – I2(–jXc) – Ez = 0 (A.18) Ey – Ez + I1(–jXc) – 2I2 (–jXc) = 0 (A.19) –I3Rn – Ex = 0 (A.20) I3 = –Ex/Rn (A.21) Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Adding Equation (A.17) and Equation (A.19), results in Equation (A.22): Ex – Ez – I2 (–jXc) = 0 (A.22) I2 = (Ex – Ez)/(–jXc) (A.23) Substituting I2 from Equation (A.23) in Equation (A.17), and deriving I1 is shown in Equation (A.24): I1 = (2Ex – Ey – Ez)/(–jXc) = (3Ex)/(–jXc) (A.24) From Figure A.6 and Figure A.7, we derive Ic in Equation (A.25) in the following calculations: If = I l – I3 Icy = I2 – I1 Icz = I2 Ex = 12 700 ∠0° V Ey = 12 700 ∠240° V Ez = 12 700 ∠120° V Rn = 2260 Ω Xc = 6 780 Ω Icy = I2 – I1 = (Ex – Ez)/(–jXc) – (2Ex – Ey – Ez)/(–jXc) = (Ey – Ex)/(–jXc) = = (12 700 ∠240° – 12 700 ∠0° V )/(6780 ∠–90°Ω) = 3.24 ∠300° A Icz = –I2 = (Ez – Ex)/(–jXc) = = (12 700 ∠120° – 12 700 ∠0° V)/(6780 ∠–90°Ω ) = 3.24 ∠240° A Ic = Icy + Icz = 3.24 ∠300° A + 3.24 ∠240° A = 5.62 ∠270° A (A.25) The current in generator neutral is shown in Equation (A.26): In = –I3 = Ex/Rn = (12 700∠0° V)/(2260∠0° Ω) = 5.62 ∠0° A (A.26) From Figure A.7, the total fault current is the sum of the capacitive and neutral current is shown in Equation (A.27): If = I1 – I3 = 3Ex/(–jXc)+ Ex/Rn = 3 (12 700 ∠0° V )/(6780 ∠–90°Ω ) + (12 700 ∠0° V)/(2260 ∠0°Ω ) Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. (A.27) = 5.62 ∠90° A + 5.62 ∠0° A = 7.95 ∠45° A Also, from Figure A.6, we get the following [see Equation (A.28)]: If = In – Ic = 5.62 ∠0° A – 5.62∠270° A = 5.62 ∠0° A + 5.62 ∠90° A = 7.95 ∠45° A (A.28) Figure A.8 illustrates the phase relationships of the current. The current through the primary of the grounding transformer is 5.62 A. The secondary voltage is 229.5 V, and the resistor current is 311 A. Figure A.8—Phase-to-ground fault capacitive reactance phasor diagrams with current relationships during fault A.3 Relay applications A.3.1 Scheme 1 relay settings The relay (device 59) is a low pickup time-delayed voltage relay designed to be for insensitive to third harmonic voltages. The relay is rated 67 V continuously and 140 V for 2 min and should be set at 5.4 V pickup and. The relay setting is a tap of 5.4 V pickup with No. 10 time dial. From Figure A.1, the generator voltage is uniformly distributed along its stator winding (generator voltage [0 V at the neutral and VLN = 12 700 V (= 22 000/√3) to the ground at its terminals), the voltage across the relay] will be proportionalimposed to the percentile of the winding that is faulted stator windings. The 59 relay with a setting (pickup = 5.4 V setting) will detect single-phase-to-ground faults to within 5.4 ---------  97.65% [= 100 = 2.35% 29.5 Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. of the generator neutral, or 97.65% (229.5 V – 5.4 V)/(229.5 V)] of the stator winding measuredwindings from the terminals will be protected. The fault current for single-phase-to-ground faults on the unprotected 2.35% of the winding will be 0.0235 · 7.95 = 0.187 A and will decrease to zero at the neutral.. [Voltage imposed to the relay = VLN/N = 12 700 V/(13 280/240) = 229.5 V.] A.3.2 Scheme 5S relay settings If Scheme 5S is applied to provide protection during warm-up, the relay selected should be a plunger type relay with a 7 V to 16 V pickup range. The relay is set at 7 V. At 60 Hz and rated generator voltage, this setting protects 97% of the winding. During warmstart-up, the machine is operating at reduced frequency and voltage. The amount of the winding protected will vary with generator voltage; however, because a plunger type relay has essentially constant volts per hertz characteristic, maximum stator protection will be obtained. A.3.3 Scheme 7 relay settings In this scheme, voltage transformersVTs with two secondary windings rated 24 000 V to 120 V/120 V are connected grounded wye-grounded wye-broken delta. For a fault at the generator terminals, E0 = 12 700 V. The voltage across the overvoltage relay connected in the broken delta will be 3E0/N = (3 × 12 700 V)/200 = 191 V. This application will require that the relay has a continuous rating of 199 V. If the relay is set at 24 V pickup and 10 time dial, this relay will coordinate closely with the primary-voltage transformer fuses and will detect singlephase-to-ground faults to within (24 V/191 V) × 100 = 12.6% of neutral end of stator windings. The primary current at relay pickup will be 1.0 A (= 12.6% ·of 7.95 = 1.0A). This is satisfactory for a backup relay to Scheme 1. A.3.4 Scheme 9 relay settings Scheme 9, using an overcurrent relay scheme, may be used instead of Scheme 1. The grounding transformer has a ratio of 13 280 V to 240, or V (or N = 13 280 V/240 V = 55.3 to 1.). A 250-to-5 current transformer A/5 A (50:1) rating CT will provide relay current approximately equal to the generator neutral current. As calculated earlier, the maximum generator neutral fault current is 3I0 = 5.62 A primary current. This will produce 311 A in the secondary resistor, and 3I0/N = 311 A/50 = 6.2 A, secondary current, in the ground overcurrent relay. The overcurrent relay should be set as sensitively as possible without introducing the possibility of false tripping. When the unit is on-line, there will be a small neutral current due to system unbalance and generated harmonics, principally by the third harmonics. This neutral current will vary directly with generator load so the maximum relay current will flow when the machine is operating at full load. This current can be expected to be less than 0.5 A. Actual For the reference, actual field measurements on 29 hydro and 59 thermal units ranging in size from 1a range of generator 5 MW to 950 MW, showed relay current from 0.1 A to 0.6 A with a mean value of 0.3 A. For the suitability of relay settings, it is important that the ground relay operating coil current be measured with the unit running at or near full load. This value relay coil current should not exceed 75% of the ground relay setting. Assuming a maximum operating current of 0.3 A, the generator ground overcurrent relay may be set at 0.5 A pickup. This setting will provide protection for all, but (0.5 · 100A/6.2 A) × 100 = 8.1% of the generator winding from the neutral or 91.9% of the winding from the generator terminal will be protected. Since a voltage may exist at the generator neutral when a fault occurs on the high-voltage side of the generator step- up transformer, some time delay should be provided for the time overcurrent unit. Otherwise, the machine will be incorrectlywould have to be manually tripped for a transmission system fault. A time dial Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. setting of 3.5 to 4.0 will usually prove to be adequate if a very inverse characteristic relay is used. A.3.5 Scheme 18 relay setting In this scheme, the third harmonic voltage measurement at the no-load and the full-load condition are recommended for the best relay performances. The setting of third harmonic undervoltage element (device 27TH) is approximately 50% of the third harmonic measurement value (adequate third harmonic generation is required at least two-times greater than the minimum tap setting). However, smaller generator (approximately 15 MVA power generation or below) may not have the adequate third harmonic generation, and consequently this scheme is not suitable. A.3.5.1 180 Hz voltage measurement (492 MVA steam turbine generator) Table A.1 and Figure A.9 show the third harmonic voltages of a 492 MVA, 20 kV steam turbine generator, with a VT ratio of 166.7:1 (= 20 000 V/120 V) at terminal and the distribution transformer ratio of 60:1 (= 14 400V/240 V). Table A.1—Third harmonic parameters of a large steam turbine generator Real power (MW) Reactive power (Mvar) A-phase voltage prim(V) B-phase voltage prim(V) C-phase voltage prim(V) V3@terminal: mean-value primary voltage (V) V@neutral primary voltage (V) 0 0 66.0 69.7 64.2 66.6 18.9 80 30 80.7 84.3 88.0 84.3 52.4 98 23 89.8 93.5 97.2 93.5 56.8 126 19 104.5 119.2 117.3 113.7 81.1 147 15 128.3 130.2 122.8 127.1 94.0 174 20 135.7 143.0 141.2 l39.9 108.2 201 19 165.0 161.3 155.8 160.7 117.9 227 15 179.7 179.7 181.5 180.3 146.4 384 30 242.0 238.3 236.5 239.0 191.3 408 25 242.0 249.3 240.2 243.8 198.9 447 27 265.8 247.5 251.2 254.8 207.5 482 20 276.8 276.8 258.5 270.7 217.0 Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Figure A.9—Third harmonic voltages of a large steam turbine generator The third harmonic voltage data indicates this generator unit has adequate third harmonic generation. The third harmonic undervoltage element should be set below the minimum measured value of 18.9 V. The typical setting in this case is 9.5 V (50% of the minimum measured value). Since the desired margin of two times tap setting was not available, forward power supervision is required. This will result in not protecting the generator during start-up. A.3.5.2 180 Hz voltage measurement (50 MVA steam turbine generator) Table A.2 and Figure A.10 show the third harmonic voltages of a 50 MVA, 13.8 kV cogeneration generator, with a VT ratio of 60 at the terminal and the distribution transformer ratio of 120 (= 14 400 V/120 V). The third harmonic data indicates that this generator produced fluctuating third harmonic voltage, and Scheme 18a is not suitable. Hence, this generator needed to consider Schemes 18c, 18d, 18e, or 18f for alternate 100% stator ground protection. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Table A.2—Third harmonic parameters of a medium steam turbine generator Real power (MW) 0 4 V3@neutral 180 Hz primary (V) 159.6 — V3@neutral design estimate secondary (V) 1.455 — V3@neutral measurement secondary (V) 1.33 (1.90) 10 181.2 1.652 1.45 20 159.6 1.455 1.33 24 12.0 30 139.7 1.274 1.20 40 131.4 1.191 1.10 38 50 — 135.5 — — 1.235 (0.10) 0.90 1.13 Figure A.10—Third harmonic parameters of a medium steam turbine generator Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. A.4 Relay and VT fuse coordination The sensitive relaying used to detect phase-to-ground faults on the generator stator winding will also detect phase-to-ground faults on the secondary leads of the VTs, if the VTs are Y-Y connected with both neutrals grounded. Figure A.1 shows the VTs protected with 0.5 A current-limiting fuses. Current-limiting fuses are not required for the maximum phase-to-phase fault current of 7.55 A calculated in this example; however, phase-tophase fault current exceeds by far the interrupting rating of an ordinary VT fuse of this size. Resistors in series with ordinary 0.5 A VT fuses may be used to limit multiphase fault current to within the interrupting rating of the fuse. Figure A.11 shows both relay and fuse time-current characteristics plotted in terms of total phase-to-ground fault current at the generator terminals or the primary terminals of the VT. Since the VT ratio in this example is 24 000 V/120 V, secondary fuse characteristics are plotted on the basis that 200 A secondary current represents 1 A primary current. The voltage relays of protection Schemes 1, 5S, and 7 have voltage-time characteristics. In order to plot these characteristics in Figure A.11, the voltage shall be mapped to equivalent primary ground fault current. In this example, the fault at the generator terminals was 7.95 A and relay voltage 229.5 for Schemes 1 and 5S. The ratio of relay volts to primary ground fault current is 28.9 V to 1 A. This same ratio holds for fault current less than maximum. In Scheme 7, the relay voltage is 191 for the maximum ground fault current of 7.95 A. The ratio for this relay is 24 V to 1 A. In Scheme 9, the relay current is 6.3 A for a maximum ground fault current of 7.95 A. The ratio of relay current to total ground current is 0.78 to 1. Using the aforementioned ratios, the relay and fuse characteristics are plotted on a common current base shown in Figure A.11. For problems associated with VT grounding on ground fault neutralizers using Scheme 6, see IEEE Committee Report [B43]. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Figure A.11—Relay and VT fuse coordination curve A.5 Typical third harmonic voltage levels under balanced conditions Figure A.4 in the previous clause illustrates a typical installation with the total capacitance of the windings, the bus, and transformer lumped into one capacitor per phase at the terminals. This equivalent representation is satisfactory in the analysis of the 60 Hz voltages under phase-to-ground fault conditions. When determining the 180 Hz voltage under normal balanced conditions, the result is somewhat more accurate and would tend toward agreeing with measurements, if the generator stators winding capacitance is divided into lump elements, one at the neutral end and the other at the terminal end for each phase. Without surge capacitors at the terminals, the total capacitance can be divided such that the capacitance at the terminals is somewhat higher, typically CTERMINALS = 1.3 × CNEUTRAL (i.e., the stator winding is represented as a pi-equivalent, and the transformer and bus capacitances are added to the terminals). Figure A.12 shows a one-line diagram of the 180 Hz zero-sequence network where X represents one-half of the winding capacitive reactance per phase, and Rn is the neutral resistance. Rn is in terms of the winding capacitance, where the value has been determined according to the total capacitance of the windings, bus, and transformer, as per the previously mentioned practice. The capacitive reactance at the terminals in terms of the winding capacitive reactance is shown to be smaller by the factor 1.3 as stated. The 180 Hz voltages under normal conditions can be obtained from Figure A.12 and are as shown in Equation (A.29) and Equation (A.30): 180 Hz voltage at the terminal VP = (0.52 ∠–19° ) × ESOURCE (A.29) 180 Hz voltage at the neutral VN = (0.54 ∠–18.4° ) × ESOURCE (A.30) The result is favorable to the scheme described as “adaptive third harmonic level detector” because under normal conditions, encroachment into the operating area is not expected according to this analysis. If surge capacitors are connected to the generator terminals, the effect is to further remove the normal voltage conditions away from the operating levels of the detection, thereby enhancing security of the detector scheme. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Figure A.12—Third harmonic equivalent circuit of a high-resistance grounded generator installation Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Annex B (informative) Ground protection example to determine the percent coverage of a high-impedance differential relay The following example illustrates a procedure used to determine the percent coverage of a high-impedance differential relay. A diesel generator with a terminal voltage of 4.16 kV and rated at 4.085 1 MVA (subtransient reactance Xd” = 5.0% on the generator base, or 0.2118 Ω) is protected by using high-impedance differential relays connected per figure 18a. The one-line diagram is shown in Figure B.1 together with the pertinent impedance values. Figure B.1—One-line diagram for Scheme 19 The generator neutral is grounded through a 6 Ω resistor that limits ground- fault current to approximately 400 A. The bushing CTs have a ratio of 240 (= 1200/5), and their secondary excitation curve is shown in Figure B.2. The high-impedance relay setting is based on assuring that the relay will not operate for the maximum external fault at the generator terminals assuming that the terminal CTs saturate completely and that the neutral CTs do not saturate at all. The voltage that appears across the junction point of the paralleled CTs for this worst case condition is equal to the loop resistance times the secondary fault current, as shown in Equation (B.1) (B.1) where VJ is the junction voltage RS is the dc resistance of fault CT secondary windings and leads = 0.66 Ω RL is the single conductor dc resistance of CT cable from junction point to fault CT = 0.397 Ω P is 1 for 3 Φ fault, and 2 for Φ-to-ground fault IF is the primary rms fault current (phase value) Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. CTR is the CT ratio = 1200 A/5 A or 240 Since the differential relays are connected to provide both phase fault and ground fault protection, and the ground fault current is limited to approximately 400 A, the maximum fault that must be considered is a threephase fault at the terminals of the generator. a) The primary RMSthree-phase fault current derives by a per unit (pu) method, as shown in amperes isEquation (B.2): IF (3-phase) = (1 pu voltage)/(Xd” in pu) = 1/(0.04995) = 20.02 pu (B.2) = [IF (3-phase)] [base current per pu] = [20.02 pu] [4085 kVA/(4.16 kV/√ 3)] = 11 350 A b) The maximum expected three-phase fault current derives with a conventional method that is the generator voltage dividing by the generator subtransient reactance, as shown in Equation (B.3): IF = (generator voltage)/(subtransient reactance) = (4160 V/√ 3)/(0.2116 Ω)] = 11 350 A (B.3) Figure B.2—Secondary excitation curve for the example of Scheme 19 Evaluating Equation (B.1) with the fault current IF yields Equation (B.4): Vj = (RS + P RL)[IF /N] = (0.66 + 1(0.397))(11 350/240) = 50 V (B.4) Assuming a 50% safety margin, the relay voltage setting is shown in Equation (B.5): VR = 1.5 (50 V) = 75 V (B.5) Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Now that a secure pickup setting has been determined, the minimum internal fault current required to trip the high-impedance differential relay must be calculated with Equation (B.6): IMIN = CTR [Σ (Ie )x + Ir + I1] and x = 1,2,3,......n (B.6) where IMIN is the minimum internal fault current n is the integer number of parallel CTs (n is 2 in this example) Ie is the secondary excitation current of each CT at 75 V Ir is the current in relay at 75 V I1 is the current in voltage limiting non linear resistor at 75 V CTR is the CT ratio = 1200 A/5 A or 240 From the secondary excitation curve of Figure B.2, Ie = 0.03 A at 75 V. Given that litea typical impedance of the relay operating circuit is 1700 Ω, then Ir = 75 V/(1700 Ω) = 0.044 A (B.7) This example assumes that the relay used has a voltage limiting nonlinear resistor connected across the relay operating coil. I1 is determined from curves provided by the manufacturer (I1 ≅ 0.01 A). Evaluating Equation (B.6) yields: IMIN = (240)[2(0.03) + 0.044 + 0.01] = 27.4 A The percentage of the stator winding covered is determined by (B.8) (1 – 27.4 A/400 A) × 100% ≅ 93% (B.9) where IMIN = 27.4 A and the maximum ground fault current at the terminals of the generator = 400 A. Therefore, ground faults in 93% of the stator windings can be detected. With the generator breaker closed, fault contribution from the system to the generator ground fault will increase the percentage coverage. The fault contribution from the system creates additional relay operating voltage. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Annex C (informative) Glossary The following definitions are taken from The Authoritative Dictionary of IEEE Standards Terms, Seventh Edition [B46], except as noted. For the purposes of this guide, the terms and definitions in this clause will apply. The Authoritative Dictionary should be referenced for terms not defined in this clause. ground: A conducting connection, whether intentional or accidental, by which an electric circuit or equipment is connected to the earth or to some conducting body of relatively large extent that serves in place of the earth. It is used for establishing and maintaining the potential of the earth or approximately that potential, on conductors connected to it to and from the earth. ground bushing: An accessory device designed to electrically ground and mechanically seal a de-energized power cable terminated with an elbow. grounded conductor: A conductor that is intentionally grounded, either solidly or through a non- interrupting current-limiting device. ground current: Current flowing in the earth or in a grounding connection. ground detector relay: A relay that operates on failure of electrical apparatus insulation to ground. A relay is connected in the secondary circuit of CTs with a suffix G or N (as 51G or 51N) for an ac time overcurrent relay. grounded: Connected to earth or to some extended conducting body that serves instead of the earth, whether the connection is intentional or accidental. grounded circuit: A circuit in which one conductor or point (usually the neutral conductor or neutral point of transformer or generator windings) is intentionally grounded, either solidly or through a non-interrupting current-limiting grounding device. grounded, effectively: Grounded through a sufficiently low impedance (inherent or intentionally added, or both) so that the coefficient of grounding does not exceed 80%. NOTE—The coefficient of grounding is the ratio (ELG/ELL) expressed as a percentage at a selected location, during a lineto-ground fault power-frequency voltage (ELG) to the line-to-line voltage (ELL) that shall be obtained with the fault removed. grounded neutral system: A system in which the neutral is connected to ground, either solidly or through a resistance or reactance of low value. ground fault: An insulation fault between a conductor and ground or frame. ground fault circuit interrupter: A device intended for the protection of personnel that functions to interrupt the electric current to the load within an established period of time when a fault current to ground exceeds some predetermined value that is less than that required to operate the overcurrent protective device of the supply current. ground fault neutralizer grounded: Reactance grounded through such values of reactance that during a fault between one of the conductors and earth, the rated-frequency current flowing between the unfaulted conductors Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. and earth shall be substantially equal. ground fault protection of equipment: A system intended to provide protection of equipment from damaging line-to-ground arcing fault currents by operating to cause a disconnecting means to open all ungrounded conductors of the faulted circuit. This protection is provided at current levels less than that required to protect conductors from damage through the operation of a supply circuit overcurrent device. ground, impedance (impedance grounded) neutral system: A system whose neutral point(s) are grounded through impedance (to limit ground fault currents). grounding conductor (wire): The conductor that is used to establish a ground and that connects equipment, device, wiring system, or another conductor (usually the neutral conductor) with the grounding electrode or electrodes. grounding connection: A connection used in establishing a ground and consists of a grounding conductor, a grounding electrode, and the earth (soil) that surrounds the electrode or some conductive body that serves instead of the earth. grounding device: An impedance device used to connect conductors of an electric system to ground for the purpose of controlling the ground current or voltages to ground, or a non-impedance device used to temporarily ground conductors for the purpose of the safety of workers. grounding switch: A mechanical switching device by means of which a circuit or piece of apparatus may be electrically connected to ground. grounding system (ground grid): All interconnected grounding connections in a specific area. grounding transformer: A transformer intended primarily to provide a neutral point for grounding purpose. ground mat: A system of bare conductors, on or below the surface of the earth, connected to a ground or a ground grid to provide protection from dangerous step and touch voltage. ground protection: A method of protection in which faults to ground within the protected equipment are detected irrespective of system phase conditions. ground relay: A relay that by its design or application is intended to respond primarily to system ground faults. ground-return current: The vector sum of the currents in all ungrounded conductors on the electric supply line (line residual current). ground, solidly: Connected directly through an adequate ground connection in which no impedance has been intentionally inserted. ground wire: See: grounding conductor (wire). harmonic: A sinusoidal component of a periodic wave or quantity having a frequency that is an integral multiple of the fundamental frequency. For example, a component, the frequency of which is twice the fundamental frequency, is called a second harmonic. harmonic-restraint relay: A restraint relay that is so constructed that its operation is restrained by harmonic components of one or more separate input quantities. subharmonic: A sinusoidal quantity having a frequency that is integral submultiples of the fundamental Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. frequency of a periodic quantity to which it is related. For example, a waveform with frequency half the fundamental frequency of another waveform is called the second subharmonic of the later waveform. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Annex D (informative) Bibliography D.1 Analysis of ground fault transients [B1] ABB Electric Transmission & Distribution Reference Book. Raleigh: ABB Inc., 1950, pp. 643–650. [B2] Alacchi, J., “Zero-Sequence Versus Residual Ground-Fault Protection,” Power, vol. 115, no. 10, p. 97, Oct. 1971. [B3] Johnson, A. A., “Grounding Principles and Practices,” Electrical Engineer, vol. 64, pp. 92–99, Mar. 1945. [B4] Peterson, H. A., “Critical Analysis of Rotating Machine Grounding Practice,” General Electric Review, April 1942. [B5] Peterson, H. A., Transients in Power Systems. New York: Wiley, 1951. [B6] Waters, M., and Willheim, R., Neutral Grounding in High-Voltage Transmission, Part 2. New York: Elsevier Publishing Co, 1956, pp. 266–649. D.2 Generator protection [B7] Elmore, W. A. (Editor, ABB) Protective Relaying Theory and Applications. Marcel Dekker Inc., 2004, pp. 117–143. [B8] Gantner, J., “New Developments in the Protection of Large Turbo-Generators,” IEEE, pp. 64–70, Mar. 1975. [B9] Gantner, J., and Wanner, R., “The Protection of Very High Power Turbo-Generators in Relation to the Protection of the System and Back-Up Protection,” CIGRE, vol. 34-08, pp. 1–8, Aug./Sept. 1972. [B10] Mason, C. R., The Art and Science of Protective Relaying. New York: Wiley, 1956, pp. 209–214. [B11] Stadler, H., “New Developments on Generator Protection,” Brown Boveri Review, vol. 53, no. 11/12, pp. 791–794, 1966. [B12] Wanner, R., “Protection of Large Generators,” Brown Boveri Review, vol. 58, no. 7, pp. 257–264, 1971. [B2] Johnson, A. A, “Grounding Principles and Practices,” Electrical Engineer, vol. 64, pp. 92-99, Mar. 1945. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. [B3] Peterson, H. A, Transients in Power Systems. New York: Wiley, 1951. [B4] Peterson, H. A., “Critical Analysis of Rotating Machine Grounding Practice,” General Electric Review, April 1942. [B5] Waters, M. and Willheim, R. Neutral Grounding in High-Voltage Transmission, Part 2. New York: Elsevier Publishing Co, pp. 266-649, 1956. [B6] Gantner, J., “New Developments in the Protection of Large Turbo-Generators,” IEE, pp. 64-70, Mar. 1975. [B7] Gantner, J. and Wanner, R., “The Protection of Very High Power Turbo-Generators in Relation to the Protection of the System and Back-Up Protection,” CIGRE, vol. 34-08, pp. 1-8, Aug./Sept. 1972. [B8] Mason, C. R., The Art and Science of Protective Relaying. New York: Wiley, 1956, pp. 209-214. [B9] Stadler, H., “New Developments on Generator Protection,” Brown Boveri Review, vol. 53, no. 11/12, pp. 791- 794, 1966. [B10] Wanner, R., “Protection of Large Generators,” Brown Boveri Review, vol. 58, no. 7, pp. 257-264, 1971. [B11] Warrington, A. R. Van C., Protective Relays, Their Theory and Practice, Vol. 1. London: Chapman & Hall, Ltd., 1968, p. 181. [B14] Zurowski, E., “The Protection of Large Power Station Generating Units,” Siemens Review, Feb. 1965. D.3 Generator ground fault protection [B15] AIEE Committee Report, “Present Day Grounding Practices on Power Systems,” AIEE Transactions on Power Apparatus and Systems, vol. 66, pp. 1525-1548, 1947. [B16] Berman, J., Kripsky, A.., and Skalka, M., “Protection of Large Alternators Connected to Step-Up Transformers Against the Consequences of Earth Faults in the Stator Winding,” CIGRE, 34-02, 1972. [B17] Electrical Transmission and Distribution Reference Book. East Pittsburgh, PA: Westinghouse Electric Corporation, East Pittsburgh, PA, 1950, pp. 655 665. [B18] Gross, E. T. B., “Ground Relaying of Generators in Unit Connection,” Electrical Engineering, vol. 72, p. 115, Feb. 1973. [B19] Marttila, R. J., “Design Principles of a New Generator Stator Ground Relay for 100% Coverage of the Stator Winding,” IEEE Transactions on Power Delivery, vol. PWRD-1, pp. 41-–51, Oct. 1986. [B20] Modolf, Stien, and Linders, J. R., “Ground Fault Protection of the Complete Generator Winding,” Fourth Annual Western Protective Relay Conference, October 18-20, 1977. [B21] Pazmandi, L., “Stator Earth Leakage Protection for Large Generators,” CIGRE, 34-01, 1972. [B22] Pope, J. W., “A Comparison of 100% Stator Ground Fault Protection Schemes for Generator Stator Windings,” IEEE Transactions on Power Apparatus and Systems, vol. 103, pp. 832–840, Apr. 1984. [B23] Pope, J. W., and Griffin, C.H., “Generator Ground Fault Protection Using Overcurrent and Undervoltage Relays,” IEEE Transactions on Power Apparatus and Systems, vol. 101, pp. 4490–4501, Dec. 82. 1982. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. [B24] Rajk, M. N., “Ground Fault Protection of Unit Connected Generators,” AIEE Transactions on Power Apparatus and Systems, vol. 77, pt. III, pp. 1082–1094, 1958. [B25] Stadler, H., “Earth Leakage Protection of Alternator,” Brown Boveri Review, vol. 31, pp. 392– 400,1944. D.4 Neutral grounding [B23] IEEE Std 32-1972 (Reaff 1984), IEEE Standard Requirements, Terminology, and Test Procedure for[B26] Berger, I. B., and Johnson, A. A., “Y-Connected Potential Transformers as Generator Neutral Grounding Devices. [B24] IEEE Std C62.92.1-1987, IEEE Guide for the Application of Neutral Grounding in Electrical Utility Systems, Part I—Introduction. [B25] Berger, I. B. and Johnson, A. A., “Y-Connected Potential Transformers as Generator Neutral Grounding Devices,” IEEE Transactions on Power Apparatus and Systems, vol. 73, pp. 341–345, Jan./Feb. 1954. [B27] Brown, P. G., Johnson, I. B., and Stevenson, J. R., “Generator Neutral Grounding: Some Aspects of Application for Distribution Transformer with Secondary Resistor and Resonant Types,” IEEE Transaction on Power Apparatus and Systems, vol. 97, no. 3, pp. 683 694, May/Jun. 1978. [B27] Johnson, A. A., “Generator Grounding,” Electric Light and Power, Mar. 1952. [B28] IEEE Std 32™-1972 (Reaff 1984), IEEE Standard Requirements, Terminology, and Test Procedures for Neutral Grounding Devices.6, 7 [B28] Johnson, I. B. and Stevenson, J. R., “Neutral Grounding and Prevention of Neutral Instability,” IEEE Transactions on Power Apparatus and Systems, vol. 92, p. 341, Jan./Feb. 1973 6IEEE publications are available from the Institute of Electrical and Electronics Engineers, Inc., 445 Hoes Lane, Piscataway, NJ 08854, USA (http://standards.ieee.org/). [B29] Teichmann, H. T, “Improved Maintenance Approach for Large Generator Armature Windings Subject to Insulation Migration,” IEEE Transactions on 7The IEEE standards or products referred to in this clause are trademarks of the Institute of Electrical and Electronics Engineers, Inc. [B29] IEEE Std 142™-1991, IEEE Recommended Practice for Grounding of Industrial and Commercial Power Apparatus and Systems, vol. 91, pp. 1234-1238, Jul./Aug. 1973 (IEEE Green Book). [B30] IEEE Std C62.92.1™-2000, IEEE Guide for the Application of Neutral Grounding in Electrical Utility Systems, Part I—Introduction. Webb, C. E., “Determining the Rating of a Generator Neutral Grounding Reactor,” Industrial Power Systems, General Electric Co., Dec. 1970. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. C.5 Resonant grounding [B31] AIEE Committee Report, “Guide for Application of Ground-Fault Neutralizers,” AIEE Transactions on Power Apparatus and Systems, vol. 72, pp. 183-190, Apr. 1953 [B31] IEEE Working Group Report, “Grounding and Ground Fault Protection of Multiple Generator Installation on Medium-Voltage Industrial and Commercial Power Systems,” IEEE Transactions on Industry Applications, vol. IAS-39, no. 6, Nov. /Dec. 2003. [B32] Johnson, A. A., “Generator Grounding,” Electric Light and Power, Mar. 1952. Gulachenski, E. M., and Courville, E. W., “New England Electric's 39 Years of Experience With ResonantNeutral Grounding of Unit-Connected Generators,” IEEE Transactions on Power Delivery, vol. 6, pp. 1016-1024, Jul. 1991. [B33] Khunkhun, K .Johnson, I. B., and Stevenson, J. R., “Neutral Grounding and Prevention of Neutral Instability,” IEEE Transactions on Power Apparatus and Systems, vol. 92, p. 341, Jan./Feb. 1973. [B34] Powell, L. J., “Impact of System Grounding Practices on Generator Fault Damage,” IEEE Transactions on Industrial Applications, vol. 37, Jan./Feb. 2001, pp. 218–222. [B35] Powell, L. J. S., Koepfinger, J. L., and Haddad, M. V., “Resonant Grounding (Ground Fault Neutralizer) of a Unit Connected Generator,” IEEE Transactions on Power Apparatus and Systems, vol. PAS-96, pp. 550559, 1977.., “Influence of Third Harmonic Circulating Currents in Selecting Neutral Grounding Devices,” IEEE Industry Applications, vol. IA-9, Nov./Dec. 1973, pp. 672–679. [B34] Tomlinson, H. R., “Ground-Fault Neutralizer Grounding of Unit Connected Generators,” AIEE Transactions on Power Apparatus and Systems 72, pt. III953-966, Oct. 1953 C.6 Synchronous generators [B35] ANSI C50.10-1990, American National Standard General Requirements for Synchronous Machines. C.7 Voltage transformers [B36] Teichmann, H. T., “Improved Maintenance Approach for Large Generator Armature Windings IEEE Committee Report, “Potential Transformer Application on Unit Connected Generators,” Subject to Insulation Migration,” IEEE Transactions on Power Apparatus and Systems, vol. 91, pp. 24-28, Jan./Feb. 19721234–1238, Jul./Aug. 1973. [B37] Webb, C. E., “Determining the Rating of a Generator Neutral Grounding Reactor,” Industrial Power Systems, General Electric Co., Dec. 1970. D.5 Resonant grounding [B38] AIEE Committee Report, “Guide for Application of Ground-Fault Neutralizers,” AIEE Transactions on Power Apparatus and Systems, vol. 72, pp. 183–190, Apr. 1953. [B39] Gulachenski, E. M., and Courville, E. W., “New England Electric’s 39 Years of Experience With Resonant Neutral Grounding of Unit-Connected Generators,” IEEE Transactions on Power Delivery, vol. 6, pp. 1016–1024, Jul. 1991. [B40] Khunkhun, K. J. S., Koepfinger, J. L., and Haddad, M. V., “Resonant Grounding (Ground Fault Neutralizer) of a Unit Connected Generator,” IEEE Transactions on Power Apparatus and Systems, vol. PAS96, pp. 550–559, 1977. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. [B41] Tomlinson, H. R., “Ground-Fault Neutralizer Grounding of Unit Connected Generators,” AIEE Transactions on Power Apparatus and Systems, vol. 72, pt. III, pp. 953–966, Oct. 1953. D.6 Synchronous generators [B42] ANSI C50.10-1990, American National Standard for Rotating Electrical Machinery—General Requirements for Synchronous Machines.8 8ANSI publications are available from the Sales Department, American National Standards Institute, 25 West 43rd Street, 4th Floor, New York, NY 10036, USA (http://www.ansi.org/). D.7 Instrument transformers [B43] IEEE Committee Report, “Potential Transformer Application on Unit Connected Generators,” IEEE Transactions on Power Apparatus and Systems, vol. 91, pp. 24–28, Jan./Feb. 1972. [B44] IEEE Std C57.13™-1993, IEEE Standard Requirements for Instrument Transformers. [B45] Mason, C. R., “Preventing Generator Relay Operations when a Potential Transformer Blows,” General Electric Co., vol. 19, Oct. 1957. See also IEEE Std 142-1991 [B29]. D.8 General [B46] IEEE 100, The Authoritative Dictionary of IEEE Standards Terms, Seventh Edition. New York: Institute of Electrical and Electronics Engineers, Inc. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply. Authorized licensed use limited to: UNIVERSIDADE DE BRASILIA. Downloaded on October 11,2018 at 18:39:37 UTC from IEEE Xplore. Restrictions apply.

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