Susceptibility of 

Nuclear Stations to 

External Faults

Office of Nuclear Regulatory Research

NUREG/CR-7175

BNL-NUREG-98371-2012
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Susceptibility of 

Nuclear Stations 

of External Faults

Manuscript Completed: July 2012

Date Published: September 2014

Prepared by:

Michael Villaran and Meng Yue

Nuclear Science and Technology Department

Brookhaven National Laboratory

Upton, New York 11973-5000

Darrell Murdock, NRC Project Manager

NRC Job Code N6838

Office of Nuclear Regulatory Research

NUREG/CR-7175

BNL-NUREG-98371-2012

iii

ABSTRACT

The offsite electric power supply, delivered via the electrical transmission grid and nuclear 

power plant (NPP) switchyard, is the preferred source of power for normal and emergency NPP 

shutdown. Since the deregulation of the electric power industry, NPP electrical distribution 

systems have become more vulnerable to the effects of external transmission system faults 

because most of those switchyards and transmission lines are no longer owned, operated, or 

maintained by the same companies that own and operate the nuclear plants. Also, with the 

exception of the North America Electric Reliability Corporation (NERC) standard NUC-001-2, 

there is a lack of detailed industry-wide technical standards for (1) the interface between NPPs 

and transmission/subtransmission networks; (2) the protection systems for the interface; and (3) 

the maintenance of the primary and secondary equipment in the interface. 

As part of a research program sponsored by the NRC Office of Nuclear Regulatory Research, 

the effects that electrical faults and other disturbances originating on the electric power grid can 

have on the availability of offsite power sources and the performance of the NPP are studied. A 

review of NPP switchyard configurations, transmission grid interface configurations, and their 

electrical protection systems was undertaken to better understand the dynamics of the 

interconnection between the NPP onsite and offsite power systems. 

Several simulation models were developed based upon actual NPP power distribution systems, 

their transmission system interfaces, and electrical protection systems using power system 

analysis software. An event tree type approach was followed in developing the simulation study 

scenarios and contingencies in the analyses. The importance of maintenance on the response

of the electrical protection systems to external fault events was considered.

Conclusions and observations are presented for improving the response of electrical protection 

systems to an external fault in order to minimize the occurrence of a loss-of-offsite power and 

nuclear plant trip.

v

FOREWORD

The offsite electric power supply, delivered via the electrical transmission grid and nuclear 

power plant (NPP) switchyard, is considered to be the most reliable electric power source for 

safe operation and accident mitigation in nuclear power plants (NPPs). It is also the preferred 

source of power for normal and emergency NPP shutdown. If the loss of the offsite electric 

power system is concurrent with a main turbine trip and unavailability of the onsite emergency 

ac power system, a total loss of ac power occurs, resulting in a station blackout (SBO) condition, 

which is one of the significant contributors to reactor core damage frequency.

Since the deregulation of the electric power industry, NPP electrical distribution systems have 

become more vulnerable to the effects of external transmission system faults because most of 

those switchyards and transmission lines are no longer owned, operated, or maintained by 

companies that have an ownership interest in the nuclear plants. Instead, the switchyards are 

now maintained by local transmission and distribution companies, which may not fully 

appreciate the issues and regulatory requirements associated with NPP safety and security. 

Maintenance practices may also be inconsistent among these companies. In addition, circuit 

breaker components (i.e., relays, contacts, and circuit breaker opening/closing mechanisms) 

and other Transmission and Distribution (T&D) equipment may not have the level of 

maintenance that would be available through a NPP owner/operator. Inadequate maintenance 

of these components could affect the detection and mitigation of faults, which could, in turn, 

delay protective actions at NPPs.

A review of NPP switchyard configurations, transmission grid interface configurations, and their 

electrical protection systems was undertaken to better understand the dynamics of the 

interconnection between the NPP onsite and offsite power systems. In addition, the various 

types of protection systems for the main generators, electrical buses, power transformers, and 

electrical transmission lines were reviewed.

Examples of recent transmission system fault events that resulted in NPP trips and/or Loss of 

Offsite Power (LOOP) were studied in detail to identify the potential system design, operation 

and maintenance vulnerabilities that may have contributed to these outcomes. Several of these 

examples were selected for more detailed study using power system analysis software tools. 

Simulation models were developed using Electric Transient and Analysis Program (ETAP)

software based upon the actual plant distribution systems, switchyard design, and transmission 

system interconnections. An event tree type approach was followed in developing the 

simulation study scenarios and potential contingencies.

The Federal Energy Regulatory Commission (FERC) is the federal agency responsible for the 

regulation of wholesale interstate electric power transactions on the transmission system. In 

this role FERC approves and enforces the electric reliability standards developed by the North 

American Electric Reliability Corporation (NERC). NERC provided input to this report. 

NERC Standard NUC-001-2 specifically requires coordination agreements between the 

operators of nuclear generating stations and transmission owners/operators for the purpose of 

ensuring that reliable sources of offsite power are available for the safe operation and shutdown 

of NPPs. The conclusions and observations in this NUREG/CR will serve as a reference to 

NERC in the future development and revision of standards that address the interface between 

nuclear power plants and the electric power grid.
vi

In light of the above issues, this research evaluates the effects that electrical faults originating 

on the offsite electric power grid can have on the availability of offsite power sources and the 

performance of the NPP. The objectives of this research project are to: 1) develop a better 

understanding of the current power system protection in NPP electrical switchyards, 2) identify 

the electrical system vulnerabilities that contribute to electrical fault propagation into the nuclear 

plant’s switchyard, and 3) serve as a knowledge base for NRC staff to evaluate events that take 

place on the electric transmission system beyond the regulatory reach of the Nuclear 

Regulatory Commission (NRC).
vii

TABLE OF CONTENTS

Section Page

ABSTRACT................................................................................................................................ iii

FOREWORD ..............................................................................................................................v

LIST OF FIGURES ....................................................................................................................ix

LIST OF TABLES........................................................................................................................x

ABBREVIATIONS AND ACRONYMS ........................................................................................xi

EXECUTIVE SUMMARY ......................................................................................................... xiii

ACKNOWLEDGMENTS........................................................................................................... xix

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

1.1 Background......................................................................................................... 1

1.1.1 Deregulation of the Electric Utility Industry .............................................. 2

1.1.2 Operating Experience – Examples of Grid Disturbances Affecting 

NPPs....................................................................................................... 3

1.2 Purpose and Scope ............................................................................................ 5

1.3 Organization of this Report ................................................................................. 6

2 NUCLEAR PLANT OFFSITE POWER SYSTEM .............................................................9

2.1 NPP Electric Power Distribution Systems ........................................................... 9

2.1.1 Onsite Power System.............................................................................. 9

2.1.2 Offsite Power System.............................................................................11

2.2 Switchyard Bus Arrangements...........................................................................12

2.3 Electrical Protection Systems.............................................................................12

2.3.1 Transmission Line Protection Systems...................................................13

2.3.2 Switchyard Bus Protection......................................................................21

2.3.3 Onsite Medium-voltage Bus Protection...................................................24

2.3.4 Power Transformers Protection ..............................................................25

2.3.5 Protection for the Main Generator and Unit-Connected Step-up 

Transformer............................................................................................25

3 ANALYTICAL APPROACH TO STUDYING THE IMPACT OF PROTECTION 

SETTINGS ON NPP RESPONSE TO AN EXTERNAL FAULT......................................27

3.1 Overview............................................................................................................27

3.2 A Generic Approach to Evaluate Impacts of Protection Settings/Schemes on 

NPP Response ..................................................................................................28

3.2.1 An Event Tree Type Approach ...............................................................28

3.2.2 Development of Contingencies...............................................................29

3.2.3 Development of Simulation Scenarios ....................................................30

3.3 Discussion and Remarks ...................................................................................32
viii

4 NPP MODELS AND ANALYSES...................................................................................35

4.1 Overview............................................................................................................35

4.2 ETAP Model Description of NPPs ......................................................................35

4.2.1 Modeling Approach and Assumptions ....................................................35

4.2.2 Overview of the NPP Models..................................................................36

4.3 Scenario Definition, Simulation, and Analysis ....................................................41

4.3.1 Comparison of Grid Responses to Faults at Different Locations.............41

4.3.2 Comparison of Grid Responses to Faults with Different Protection 

Schemes ................................................................................................50

4.3.3 Interactions between Protection Systems of Switchyards Close to 

Each Other.............................................................................................79

4.3.4 Plant Responses to an External Fault with Disabled Zones 1, 2, and 3 

Protection Relays ...................................................................................85

4.4 Summary and Discussions.................................................................................85

5 IMPORTANCE OF PROTECTION SYSTEMS MAINTENANCE....................................89

5.1 Applicability of Maintenance Requirements to Offsite Power Systems ...............89

5.2 NPP Offsite Power Fault Events Affected by Inadequate Maintenance..............90

5.3 Benefits of Improving Offsite Power System Maintenance .................................94

6 SUMMARY AND CONCLUSIONS.................................................................................97

6.1 Summary ...........................................................................................................97

6.2 Conclusions .......................................................................................................98

7 REFERENCES............................................................................................................103

APPENDIX A SCENARIOS FOR COMPARING GRID RESPONSES TO FAULTS AT 

DIFFERENT LOCATIONS FOR PLANTS B AND C.......................................A-1

APPENDIX B DEREGULATION OF THE ELECTRIC UTILITY INDUSTRY.........................B-1

APPENDIX C COMMON SWITCHYARD BUS ARRANGEMENTS......................................C-1

APPENDIX D TYPICAL UNIT-CONNECTED MAIN GENERATOR & TRANSFORMER 

PROTECTION...............................................................................................D-1
ix

LIST OF FIGURES

Figure Page

Figure 1 Typical NPP electrical distribution system.............................................................10

Figure 2 Breaker-and-a-half switchyard with main generators connected in a double-bus, 

double-breaker arrangement.................................................................................13

Figure 3 Typical protective relaying schematic at one end of a high-voltage transmission 

line........................................................................................................................14

Figure 4 A Distance Relaying Scheme................................................................................16

Figure 5 A Permissive Overreaching Relaying Scheme......................................................18

Figure 6 A Directional Comparison Protective Scheme Using Telecommunications ...........19

Figure 7 An Example Transmission Line Protection System ...............................................21

Figure 8 Distribution of faults on the CEGB system [Lindahl–2011] ....................................30

Figure 9 One-line Diagram for Plant A ................................................................................38

Figure 10 One-line Diagram for Plant B ................................................................................39

Figure 11 One-line Diagram for Plant C................................................................................40

Figure 12 CBA-Case-1 for Bus SWYDBus-1 Permanent Fault (Near)...................................43

Figure 13 Plant A-Case-2 for Bus Sub1-1 Permanent Fault (Medium)..................................44

Figure 14 Plant A-Case-3 for Bus Bus20 Permanent Fault (Far)...........................................45

Figure 15 Plant A-Case-4 for Line12 Permanent Fault (Near)...............................................46

Figure 16 Plant A-Case-5 for Line10 Permanent Fault (Far).................................................47

Figure 17 Plant A-Case-6 for Line12 Transient Fault (Near) .................................................48

Figure 18 Plant A -Case-7 for Line10 Transient Fault (Far)...................................................49

Figure 19 Example Scenario 1 for Plant A Model for Distance Relaying ...............................54

Figure 20 Example Scenario 2 for Plant A Model for Distance Relaying with Remote 

Breaker Failure Backup Protection........................................................................55

Figure 21 Example Scenario 3 for Plant A Model for Distance Relaying with Remote 

Breaker Failure Backup Protection........................................................................56

Figure 22 Example Scenario 4 for Plant A Model for Telecommunications-based 

Relaying................................................................................................................57

Figure 23 Example Scenario 5 for Plant A Model for Telecommunications-based 

Relaying with Remote Breaker Failure Backup Protection ....................................58

Figure 24 Example Scenario 6 for Plant A Model for Telecommunications-based 

Relaying with Remote Breaker Failure Backup Protection ....................................59

Figure 25 Example Scenario 1 for Plant B Model for Distance Relaying ...............................61

Figure 26 Example Scenario 2 for Plant B Model for Distance Relaying with Remote 

Breaker Failure Backup Protection........................................................................62

Figure 27 Example Scenario 3 for Plant B Model for Distance Relaying with Remote 

Breaker Failure Backup Protection........................................................................63

Figure 28 Example Scenario 4 for Plant B Model for Telecom-based Relaying.....................64

Figure 29 Example Scenario 5 for Plant B Model for Telecommunications-based 

Relaying with Remote Breaker Failure Backup Protection ....................................65

Figure 30 Example Scenario 6 for Plant B Model for Telecommunications-based Relaying 

with Remote Breaker Failure Backup Protection...................................................66

Figure 31 Example Scenario 1 for Plant C Model for Distance Relaying ...............................68

Figure 32 Example Scenario 2 for Plant C Model for Distance Relaying with Remote 

Breaker Failure Backup Protection........................................................................69

Figure 33 Example Scenario 3 for Plant C Model for Distance Relaying with Remote 

Breaker Failure Backup Protection........................................................................70
x

Figure 34 Example Scenario 4 for Plant C Model for Telecom-based Relaying ....................71

Figure 35 Example Scenario 5 for Plant C Model for Telecommunications-based 

Relaying with Remote Breaker Failure Backup Protection ....................................72

Figure 36 Example Scenario 6 for Plant C Model for Telecommunications-based 

Relaying with Remote Breaker Failure Backup Protection ....................................73

Figure 37 Switchyards of Plant A and a Neighboring Substation...........................................75

Figure 38 Line31 – Scenario 1 for Zone 3 Anticipatory Trip (0.4 Seconds Delay) .................76

Figure 39 Line31 – Scenario 2 for Zone 3 Anticipatory Trip (0.9 Seconds Delay) .................77

Figure 40 Line31 – Scenario 3 for Zone 3 Anticipatory Trip (1.4 Seconds Delay) .................78

Figure 41 Switchyards of Plant A and a Neighboring Substation...........................................79

Figure 42 Example Scenario 1 for Interaction between Protection Schemes of Two 

Switchyards ..........................................................................................................81

Figure 43 Example Scenario 2 for Interaction between Protection Schemes of Two 

Switchyards ..........................................................................................................82

Figure 44 Example Scenario 3 for Interaction between Protection Schemes of Two 

Switchyards ..........................................................................................................83

Figure 45 Example Scenario 4 for Interaction between Protection Schemes of Two 

Switchyards ..........................................................................................................84

Figure A-1 Plant B-Case-1 for Bus EB Permanent Fault (Near) ...........................................A-2

Figure A-2 Plant B-Case-2 for Bus Sub2 Permanent Fault (Medium)...................................A-3

Figure A-3 Plant B-Case-3 for Bus Sub6 Permanent Fault (Far) ..........................................A-4

Figure A-4 Plant B-Case-4 for Line 12 Permanent Fault (Near)............................................A-5

Figure A-5 Plant B-Case-5 for Line 2 Permanent Fault (Medium).........................................A-6

Figure A-6 Plant B-Case-5 for Line 12 Transient Fault (Far).................................................A-7

Figure A-7 Plant B-Case-6 for Line 2 Transient Fault (Near) ................................................A-8

Figure A-8 Plant C-Case-1 for Bus77 Permanent Fault (Near).............................................A-9

Figure A-9 Plant C-Case-2 for Bus Sub1 Permanent Fault (Far) ........................................A-10

Figure A-10 Plant C-Case-3 for Line 3 Permanent Fault (Near) ...........................................A-11

Figure A-11 Plant C-Case-4 for Line 220 32 Permanent Fault (Medium).............................. A-12

Figure A-12 Plant C-Case-5 for Line 220 31 Permanent Fault (Near)...................................A-13

Figure A-13 Plant C-Case-6 for Line 3 Transient Fault (Near)..............................................A-14

Figure A-14 Plant C-Case-8 for Line 220 32 Transient Fault (Medium) ................................ A-15

Figure A-15 Plant C-Case-8 for Line 220 31 Transient Fault (Far)........................................A-16

Figure C-1 Common high-voltage switchyard bus arrangements..........................................C-1

LIST OF TABLES

Table Page

Table 4-1 Scenarios for Comparing Grid Responses to Faults at Different Locations ...........42

Table 4-2 Generic Parameters for Simulating the Responses to a Fault with Different 

Protective Schemes..............................................................................................51

Table D-1 Typical Main Generator & Transformer Protective Devices & Functions .............D-1
xi

ABBREVIATIONS AND ACRONYMS

AAC Alternate AC (source)

AIT Augmented Inspection Team (USNRC) 

AUT Auxiliary Unit Transformer

BF Breaker Failure (protection scheme)

BNL Brookhaven National Laboratory

BWR Boiling Water Reactor

CB Circuit Breaker

CEII Critical Energy Infrastructure Information

CT Current Transformer

DR Distance Relay(ing)

DRBF Distance Relaying Breaker Failure (protection scheme)

EDG Emergency Diesel Generator

EMF Electromotive Force

ETAP Electric Transients Analysis Program

FERC Federal Energy Regulatory Commission

FSAR Final Safety Analysis Report

GDC General Design Criterion (10 CFR 50, Appendix A)

IEC International Electrotechnical Commission

IEEE Institute of Electrical and Electronics Engineers

IN Information Notice (USNRC)

ISO Independent System Operator (electrical transmission system)

LER Licensee Event Report

LOOP Loss Of Offsite Power

LV Low-Voltage

MCC Motor Control Center

MVA Megavolt-Amperes

MV Medium-Voltage

MW Megawatts

NRC Nuclear Regulatory Commission

NERC North American Electric Reliability Corporation

NPIR Nuclear Plant Interface Requirements

NPP Nuclear Power Plant

POTT Permissive Overreaching Transfer Trip

PPS Preferred Power Supply

PR Protective Relay(ing) using telecommunications (pilot relaying)

PRBF telecommunications-based (Pilot Relaying) Breaker Failure protection

PT Potential Transformer

PRA Probabilistic Risk Assessment

PWR Pressurized Water Reactor

RCP Reactor Coolant Pump

RCS Reactor Coolant System

RG Regulatory Guide (USNRC)

SBO Station Blackout

SRP Standard Review Plan (NUREG-0800)

SST Station Startup Transformer

T&D Transmission and Distribution

USNRC United States Nuclear Regulatory Commission

UAT Unit Auxiliary Transformer
xii

VAR Volt-Amperes-Reactive

X/R Ratio Ratio of Reactance to Resistance
xiii

EXECUTIVE SUMMARY

The offsite electric power supply, delivered via the electrical transmission grid and nuclear 

power plant (NPP) switchyard, is considered to be the most reliable electric power source for 

safe operation and accident mitigation in nuclear power plants (NPPs). It is also the preferred 

source of power for normal and emergency NPP shutdown. When offsite power is lost, standby 

power supplies, such as emergency diesel generators, provide onsite emergency alternating 

current (ac) power. If the loss of the offsite electric power system is concurrent with a main 

turbine trip and unavailability of the onsite emergency ac power system, a total loss of ac power 

occurs, resulting in a station blackout (SBO) condition, which is one of the significant 

contributors to reactor core damage frequency.

Since the deregulation of the electric power industry, NPP electrical distribution systems have 

become more vulnerable to the effects of external transmission system faults because most of 

those switchyards and transmission lines are no longer owned, operated, or maintained by 

companies that have an ownership interest in the nuclear plants. Instead, the switchyards are 

now maintained by local transmission and distribution companies, which may not fully 

appreciate the issues and regulatory requirements associated with NPP safety and security. 

Maintenance practices may also be inconsistent among these companies. In addition, circuit 

breaker components (i.e., relays, contacts, and circuit breaker opening/closing mechanisms) 

and other T&D equipment may not have the level of maintenance available through a NPP 

owner/operator. Inadequate maintenance of these components could affect the detection and 

mitigation of faults, which could, in turn, delay protective actions at NPPs.

The current research project, being performed under contract to the United States Nuclear 

Regulatory Commission’s Office of Nuclear Regulatory Research (NRC/RES), takes a detailed 

look at the effects that electrical faults and other disturbances originating on the offsite electric 

power grid can have on the availability of offsite power sources and the performance of the NPP. 

The objectives of this research project are to: 1) develop a better understanding of the current 

power system protection in NPP electrical switchyards and 2) to identify the electrical system 

vulnerabilities that contribute to electrical fault propagation into the nuclear plant’s switchyard.

The purpose of this study is to demonstrate and verify through modeling and simulation that 

precise and faster clearing of faults can in fact limit damage and improve plant ride-through, 

which is one of the main reasons for developing and deploying telecommunication-based relay 

schemes. The practical application of this approach into an existing protection scheme, which 

would be the equivalent of upgrading to a faster protective relay, would of course have to be 

analyzed carefully to take into consideration the coordination of all affected protection system 

timing intervals as well as the effects that the tripping of transmission element(s) can have on 

system stability. The high speed, precision, and reliability of telecommunication-based 

protection now being deployed allows ISOs, utilities, and NPP operators to take advantage of 

the potential improvements that faster clearing times can provide as we have shown in the study.

A review of NPP switchyard configurations, transmission grid interface configurations, and their 

electrical protection systems was undertaken to better understand the dynamics of the 

interconnection between the NPP onsite and offsite power systems. In addition, the various 

types of protection systems for the main generators, electrical buses, power transformers, and 

electrical transmission lines were reviewed.

Examples of recent transmission system fault events that resulted in NPP trips and/or LOOPs 

were studied in detail to identify the potential system design, operation and maintenance 
xiv

vulnerabilities that may have contributed to these outcomes. Several of these examples were 

selected for more detailed study using power system analysis software tools. Simulation 

models were developed using ETAP® power system analysis software based upon the actual 

plant distribution systems, switchyard design, and transmission system interconnections. An 

event tree type approach was followed in developing the simulation study scenarios and 

potential contingencies. Typical protection schemes were assumed for comparison when 

performing the simulation scenario analyses.

In addition, the importance of electrical protection system maintenance on the performance of 

the electrical protection system response to external fault events was considered. Several of 

the recent operating experience examples of significant NPP trip and LOOP that were studied

during this project were the result of inadequate electrical protection system maintenance.

Several of the important observations and conclusions that were identified during the NPP 

reviews and the power systems modeling and analyses conducted for this project are:

• Simulation studies confirmed that the faster an external transmission grid fault could be 

detected and isolated (without compromising the balance between security and 

dependability), the less severe the effect of the transient experienced at the NPP 

switchyard bus. The closer a fault is to the NPP switchyard the greater the effect on the 

NPP.

• Rapid detection and clearing of grid electrical faults helps to minimize the effects of a 

prolonged electrical transient that could lead to a NPP trip. The sudden loss of the 

voltage and real/reactive power support provided by the nuclear plant’s main generator 

is itself a potentially destabilizing event that can potentially lead to an extended 

degradation of system voltage at the NPP switchyard and resulting in a LOOP following 

a trip of the plant. 

• Electrical protection schemes using telecommunications (pilot relay schemes) provided 

the fastest and most reliable protection for transmission line circuits, and per the results 

of the simulation studies, they helped to minimize the effects of external faults as seen 

from the NPP switchyard. Improvements in the performance and reliability of multifunction digital protective devices, together with the lower costs and high reliability of the 

various modern communications links that are currently available, have made relaying 

protection schemes using telecommunications the preferred method for transmission 

protection.

• In general, protective schemes have already been designed and coordinated to detect 

and isolate faults as rapidly as the equipment will allow. It may be possible to adjust the 

settings of existing Zone 2 and Zone 3 protective relays and minimize intentional time 

delays in the protective schemes to achieve a more rapid protection system response. 

In this case, Zone 3 protective schemes will function as an anticipatory trip, as discussed 

in Section 4.3.2.3. As a point of emphasis, consideration of anticipatory Zone 3 

protection schemes must be very carefully analyzed to be balanced against coordination 

with neighboring protection schemes to ensure that disruption to the system is minimized.

Based on the reviews and analyses of the simulation model studies with regard to the effects of 

external electrical faults on nuclear power stations, the following observations are offered to 

maintain the highest reliability of the electric power grid while continuing to maintain and 

improve the safe and reliable operation of nuclear power plants. Any change or actions taken 

on the bases of the conclusions and observations put forward in this document must be 
xv

carefully analyzed for the specific application to assure that the balance between security and 

dependability is not compromised.

• Simulation studies confirmed that the faster an external transmission grid fault could be 

detected and isolated, the less is the effect of the transient experienced at the NPP 

switchyard bus. Reviewing the settings of protective relays and intentional time delays 

in existing electrical protection schemes may be practical to determine whether 

modifications can be made to achieve a more rapid protection system response without 

compromising the balance between security and dependability. In particular, when the 

primary protection scheme fails, the backup scheme becomes critical to isolate the 

fault(s) and the intentionally built-in time delay of the backup scheme significantly 

prolongs the clearing time. Under this situation, if the time delay can be minimized, the 

impact that a fault at or close to the NPP switchyard will have on the normal operation of 

NPPs can be significantly reduced.

• In general, analyzing the impacts that various protection system scenarios will have on 

the ability to meet the Nuclear Power Interface Requirements (NPIRs) presented in 

NUC-001-2 for nuclear power plants may improve the technical basis when altering or 

upgrading existing electrical system protection schemes. Faster fault clearing generally 

results in improved system performance, but this enhancement may only be valid if other 

transmission system elements are not tripped in addition to the faulted element. 

Therefore, careful consideration must be given to the proper setting and coordination of 

the time delays for tripping transmission and switchyard components to ensure a 

balance between security and dependability.

• Electrical protection schemes using telecommunications (pilot relay schemes) provide 

the fastest and most reliable protection for transmission line circuits, and per the results 

of the simulation studies, they helped to minimize the effects of external faults as seen 

from the NPP switchyard. Therefore, incorporating protection schemes using 

telecommunications is an option worth considering when replacing or upgrading existing 

transmission line protection systems, particularly for lines that are in the zone of 

influence of the NPPs.

• The use of electrical protection systems using telecommunications as part of the breaker 

failure and backup protection schemes for NPP switchyards and associated 

transmission circuits may improve the reliability of the protection system. The high 

speed, sensitivity, and reliability of protective relaying using telecommunications in 

backup protection helps to minimize the effects of primary protection failures.

• Reliability in switchyards incorporating the breaker-and-a-half bus arrangement could be 

improved for the most critical transmission circuits and the main generator connection by 

modifying the circuit breaker arrangement for those connections to a full double-bus, 

double-breaker arrangement.

• Incorporating the NPIRs into transmission system studies affecting NPPs as stated in 

NERC Reliability Standard NUC-001-2 may identify and address contingencies that 

require the application of mitigation plans to avoid loss of offsite power events (LOOPs).

• Improving the reliability of primary protection of the NPP switchyard protection systems 

can help them cope with the fault more effectively. This can be achieved by using 

redundant protective equipment such as dual relays, circuit-breakers, and 

telecommunication channels.
xvi

• It also needs to be pointed out that redundancy is often defeated by common cause 

failures even for the redundant equipment of diverse designs. Hence, adjusting the 

settings of existing protection systems to reduce and/or avoid time delays, especially 

those of the backup protection schemes, is still considered necessary and very important 

even while increasing the redundancy of NPP switchyard protection systems.

• Conducting grid transient analyses to identify those relays and contacts that can have a 

significant impact on conditions at the NPP switchyard buses may provide valuable 

insights when reviewing or updating the protection schemes at or near the NPP 

switchyard.

• As a consequence of the above observations, it follows that protection systems and 

equipment in selected nearby switchyards, transmission lines, substations, and large 

generating units (that have been shown by analysis to have a significant impact on 

nearby NPPs), may be subjected to a more frequent and augmented level of inspection, 

testing, and preventive maintenance without compromising the balance between security 

and dependability. This would be in keeping with the offsite power reliability and grid 

stability objectives that NRC, in cooperation with FERC and NERC, has been trying to 

achieve.

• Several recent events examined as part of this study were caused by or exacerbated by 

inadequate protection system maintenance. A comprehensive review of external fault 

events may be worthwhile to update the results of earlier studies that compared grid 

reliability and performance prior to, and after deregulation of the electric utility industry. 

This would help to verify the effectiveness of FERC and NERC efforts to improve grid 

reliability through standards, regulatory enforcement, and cooperative activities with 

NRC. It would also provide a quantitative measure of the current status and 

performance trends of the electrical transmission grid with respect to the negative effects 

of aging T&D components and equipment, overloading of limited existing transmission 

resources, aging degradation electrical protection systems, increased overall demand, 

increased peak demand, and inadequate development of new transmission system 

capacity.

• Efforts to identify necessary changes to the FERC/NERC standards that address 

protective relaying schemes and the nuclear plant interface with the transmission grid

may be worthwhile. Combined efforts from the NRC, FERC/NERC, the nuclear industry, 

and affected transmission system operators could lead to the development of industrywide standards for: 1) the interface between NPPs and the transmission (or 

subtransmission) networks, 2) the electrical protection schemes for the interface, and 3) 

the maintenance of the primary and secondary protection equipment at the interface.

• In this study, blocking of automatic reclosing of circuit breakers in the electrical 

protection zones immediately adjacent to the NPP was found to minimize the risk of 

tripping the NPP due to an uncleared permanent fault. Experience has shown that in 

many applications automatic reclosing, when supervised by a synchronism check relay, 

may improve electrical grid stability and continuity of the offsite power supply by 

improving the availability of stabilizing transmission system elements. In practical 

application, the decision to enable or block automatic reclosing in the vicinity of a NPP 

should be based upon a technical analysis and evaluation of the risks of reclosing into a 

fault versus the risks of prolonged operation with a transmission line out of service.
xvii

• Monitoring the switchyard and transmission line protection system relays and fuses that 

would alert operators of the occurrence of failures in the protection system may lead to a 

more robust level of protection. Several of the operating experience examples of NPP 

trip and LOOP in this study could have been avoided if circuit failures in the protection 

system had been detected immediately and corrected before they were challenged.

• It is important that the NPP switchyards be reviewed and treated differently than the 

regular switchyards/substations in the transmission network in terms of design, 

operation, and maintenance in order to achieve improvement in the reliability of the 

NPPs and subsequently reducing the risk associated with tripping NPPs due to external 

electrical faults.

Since the transmission system and the grid are owned and operated by other entities, it 

is the responsibility of the NPP owners to ensure that NPP design requirements, 

modification, and enhancements required to maintain a reliable and stable electric power 

system including inadvertent trip of NPPs are identified and communicated promptly to 

the respective transmission and grid operating entities.

xix

ACKNOWLEDGMENTS

The authors would like to thank the NRC Program Manager, Darrell Murdock, for his technical 

guidance in the performance of this research program and in the review of this document. We 

would also like to thank Thomas Koshy of the NRC, Frank Koza and his staff at PennsylvaniaNew Jersey-Maryland Interconnection (PJM), along with William Horak, David Diamond, and 

James Higgins of Brookhaven National Laboratory for their technical review and comments on 

this and past documents, as well as their managerial direction and support which enabled the 

successful completion of this research program.

Special thanks and acknowledgment are extended to Dr. Sture Lindahl, of Gothia Power AB, 

Göteborg, Sweden, for his technical insights, comments, and information on nuclear plant 

electrical distribution systems. We also appreciate Dr. Lindahl’s insights and comments 

regarding the effects of electrical faults on nuclear power stations, maintenance and operation 

of switchyards and transmission lines associated with nuclear power stations, and the 

development and analysis of simulation models for NPPs and their grid connections.

The authors wish to express their special thanks and acknowledgement to Robert W. 

Cummings, Director of System Analysis and Reliability Initiatives at NERC, and his staff for their 

insightful technical comments, suggestions, and supporting information on this project.

The authors would like to acknowledge David Burnham of FERC for his technical support and 

guidance on this project.

The authors extend their thanks and acknowledgment to Kenneth Sullivan, Edward Grove, and 

Mano Subudhi of Brookhaven National Laboratory for their technical insights, comments, and 

information on nuclear plant electrical distribution systems. We also appreciate their insights 

and comments regarding maintenance, operation, and aging management of electrical 

distribution equipment.

The authors wish to extend their thanks to Maryann Julian, Donna Storan, Maria Anzaldi, and 

Jean Frejka for their assistance in the preparation of this document and their continued 

administrative support throughout the performance of this research program.

1

1 INTRODUCTION

The offsite electric power supply, delivered via the electrical transmission grid and nuclear 

power plant (NPP) switchyard, is considered to be the most reliable electric power source for 

safe operation and accident mitigation in NPPs. It is also the preferred source of power for 

normal and emergency NPP shutdown. When offsite power is lost, standby power supplies, 

such as emergency diesel generators, provide onsite emergency alternating current (ac) power. 

If the loss of the offsite electric power system is concurrent with a main turbine trip and 

unavailability of the onsite emergency ac power system, a total loss of ac power occurs, 

resulting in a station blackout (SBO) condition [10 CFR 50.63], which is one of the significant 

contributors to reactor core damage frequency.

Since the deregulation of the electric power industry, NPP switchyards have become more 

vulnerable to the effects of external transmission system faults because most of those 

switchyards are no longer owned, operated, or maintained by companies that have an 

ownership interest in the nuclear plants. Instead, the switchyards are maintained by local 

transmission and distribution companies, which may not fully appreciate the issues and 

regulatory requirements associated with NPP safety and security. Maintenance practices may 

also be inconsistent among these companies. In addition, circuit breaker components (i.e., 

relays, contacts, and circuit breaker opening/closing mechanisms) and other T&D equipment 

may not have the level of maintenance available through a NPP owner/operator. Inadequate 

maintenance of these components could affect the detection and mitigation of faults, which 

could, in turn, delay or fail protective actions at NPPs.

The electrical transmission grid protection system is designed to isolate or clear electrical faults 

as rapidly as possible in order to prevent the propagation of a minor electrical disturbance into a 

more serious and wide-reaching system transient that challenges system stability and affects 

large portions of the transmission grid. Severe system transients can potentially lead to tripping 

of nuclear generating units and/or losses-of-offsite power (LOOPs), which are the preferred 

power source during normal and emergency NPP operation. Mitigating the effects of external 

electrical faults is therefore an important factor in maintaining nuclear plant safety. This study 

will examine electrical protection schemes in NPP switchyards in order to identify ways to more 

rapidly identify and isolate external electrical transmission system faults to improve NPP plant 

safety and help to maintain system stability. Rapid detection and isolation of remote electrical 

faults by the grid electrical protection system without the unnecessary actuation and response of 

the NPP electrical protection system can potentially reduce the number of unnecessary nuclear 

plant trips and/or LOOP events. 

1.1 Background

The current fleet of nuclear power plants designed, built, and licensed prior to deregulation of 

the electric utility industry were exclusively owned and operated by the same utility company 

that owned and operated the NPP switchyard and the local transmission grid. A single utility 

therefore maintained direct control over the nuclear plant operation, the configuration of the 

transmission grid, operation of other nearby non-nuclear generation, the delivery of electric 

power, and the design and coordination of the electrical protection system for the grid, the NPP 

switchyard, and the NPP distribution systems. The single utility operator could thus provide 

assurance that the regulatory requirements for the supply of electric power to the nuclear station 

were satisfied.
2

The design criteria requirements for supply of electric power to NPPs, GDC 17, “Electric power 

systems,” are set forth in Appendix A to 10 CFR 50 [10 CFR 50, Appendix A, GDC 17], which 

states, in part, that:

“An onsite electric power system and an offsite electric power system shall be provided 

to permit functioning of structures, systems, and components important to safety. The 

safety function for each system (assuming the other system is not functioning) shall be 

to provide sufficient capacity and capability to assure that (1) specified acceptable fuel 

design limits and design conditions of the reactor coolant pressure boundary are not 

exceeded as a result of anticipated operational occurrences and (2) the core is cooled 

and containment integrity and other vital functions are maintained in the event of 

postulated accidents...

“Electric power from the transmission network for the onsite electric distribution system 

shall be supplied by two physically independent circuits... Each of these circuits shall be 

designed to be available in sufficient time following a loss of all onsite alternating current 

power supplies... One of these circuits shall be designed to be available within a few 

seconds following a loss-of-coolant accident to assure that core cooling, containment 

integrity, and other vital safety functions are maintained...”

In addition, pursuant to the “station blackout (SBO) rule,” 10 CFR 50.63, “Loss of all alternating 

current power,” licensed NPPs are required to be able to withstand a SBO for a specified 

duration and recover from the SBO [10 CFR 50.63]. NRC Regulatory Guide 1.155 [USNRC RG 

1.155] provides guidance for licensees to use in developing their approach for complying with 

10 CFR 50.63. A series of tables in the RG define a set of pertinent plant and plant site 

parameters that have been found to affect the likelihood of a plant experiencing an SBO event 

of a given duration. Using the tables, a licensee can determine their plant’s relative vulnerability 

to SBO events of a given duration and identify an acceptable minimum SBO coping duration for 

the plant. Typically, NPP coping times range from 4 hours up to 8 hours. The use of an 

alternate ac source was indicated in sites where the coping and recovery of offsite power 

exceeded 4 hours.

1.1.1 Deregulation of the Electric Utility Industry

Following deregulation of the electric utility industry via the National Energy Policy Act of 1992 

and FERC Order 888 in 1996, NRC expressed concerns that, “Deregulation has the potential to 

challenge operating and reliability limits on the transmission system and could affect the 

reliability of the electric power system including the reliability of offsite power to nuclear plants 

[SECY-99-129 – May 1999].” Under a deregulated electric utility industry, the compliance with 

regulatory requirements of GDC 17, for the electric power system, and for 10 CFR 50.63, 

addressing station blackout became dependent on entities that were outside of the direct 

regulatory jurisdiction of the US NRC.

In 2003, NRC Office of Nuclear Regulatory Research (RES) completed an assessment of the 

performance of the electric power grid with respect to its effect on NPPs [Raughley – April 29, 

2003]. The RES assessment compared the performance of the grid before and after 

deregulation of the electric utility industry to identify changes in grid operation and to determine 

the impact that deregulation has had on the supply of electric power to NPPs. Some of the 

major post-deregulation changes in the electric grid related to LOOPs included the following: 

1) “the frequency of LOOP events at NPPs has decreased, 
3

2) the average duration of LOOP events has increased – the percentage of LOOPs longer 

than four hours has increased from approximately 17 percent to 67 percent, 

3) where before LOOPs occurred more or less randomly throughout the year, for 1997-

2001, most LOOP events occurred during the summer, and 

4) the probability of a LOOP as a consequence of a reactor trip has increased by a factor of 

5 (from 0.002 to 0.01).”

NRC continues to address the problems of deregulation and grid reliability through 

• regular interaction with grid regulators, FERC and NERC,

• information notices (e.g., IN 1998-07, IN 2004-15, IN 2005-15, IN 2005-21, IN 2006-06, 

IN 2006-18, IN 2007-14, IN 2008-12), 

• generic letter correspondence (e.g. GL 2006-02), 

• revisions to Chapter 8 (Electric Power) of the Standard Review Plan [NUREG-0800, 

Revision 4, March 2007], 

• the Maintenance Rule [10 CFR 50.65], and 

• regulatory guidance (e.g. RG 1.155, RG 1.180, and RG 1.182). 

In RIS 2004-05, the NRC indicated the importance of grid reliability issues because of the 

impact on plant risk and the operability of the offsite power system.

Combined efforts by the NRC, FERC/NERC, the nuclear industry, and affected transmission 

system operators could lead to the development of industry-wide standards for: 1) the interface 

between NPPs and the transmission (or subtransmission) networks, 2) the electrical protection 

schemes for the interface, and 3) the maintenance of the primary and secondary protection 

equipment at the interface [Lindahl-2011].

Further details on the deregulation of the electric utility industry and the resulting nuclear 

regulatory concerns stemming from this action are described in Appendix B.

1.1.2 Operating Experience – Examples of Grid Disturbances Affecting NPPs

The aforementioned 2003 NRC/RES study assessing the performance of the electric power grid 

with respect to its effect on NPPs [Raughley – April 29, 2003] presented numerous examples of 

grid disturbance events occurring before and after the deregulation of the electric industry up 

through 2001. Since that time, several notable grid transient events have occurred that had a 

significant impact on NPP performance. This subsection describes several of these events.

On August 14, 2003, an electrical power disturbance in the northeastern part of the United 

States caused nine NPPs in the US to trip because of voltage and frequency fluctuations 

experienced in the initial stages of the blackout [Kirby, Kueck, et. al. ORNL 2007]. Eight of 

these plants, along with one other nuclear plant that was already shutdown at the time, 

experienced a loss of offsite power (LOOP). Several of these nuclear plants were located in 

transmission corridors operating at that time under conditions of inadequate reactive power and 

were thus required to supply reactive power at their maximum capability in order to support grid 

voltage. Because the regional power grid was operating at the limits of its capacity and 

capability, the trip of a large nuclear generating unit and the resulting sudden removal of the 

local reactive power support it had been providing to the transmission grid inevitably led to 
4

degradation of voltage at the NPP switchyard below Technical Specification limits. The August 

2003 event, which was initiated by an overgrown tree coming into contact with electrical 

transmission lines, resulted in cascading outages, caused trips of nuclear stations, and disabled 

offsite power supplies. The incident highlighted the importance of the design and maintenance 

practices for NPP switchyard protection systems and demonstrated how the operational 

interaction between the power grid and large nuclear generating units can affect the reliability 

and availability of NPP offsite power sources.

The significance of external transmission system electrical faults affecting the safe operation of 

nuclear power stations is substantial. As an example, the licensee event report (LER) for Event 

Number 40815, "Reactor Trip Due to Loss of Offsite Power," which occurred on June 14, 2004, 

reported the occurrence of a ground fault to one phase (C) of a 230 kilovolt (kV) transmission 

line between two substations located 47 miles from the Palo Verde Nuclear Generating Station. 

That fault cascaded and caused a number of 230kV and 500kV transmission lines to trip 

protectively, leading to concurrent trips of all three Palo Verde units and a loss of all offsite 

power sources to the site [IN 2005-15; LER 40815; & Lindahl – Comments to BNL 9/17/2010].

Another example of a remote transmission line fault resulting in losses of offsite power sources 

occurred on September 15, 2003, at the Peach Bottom Atomic Power Station. In this event,

offsite power to the emergency buses at Peach Bottom Units 2 and 3 was lost for about

16 seconds when two of the three offsite power sources were briefly lost as well as the station 

blackout power source. All four emergency diesel generators (EDGs) automatically started and 

supplied power to the emergency buses. The third offsite power source remained available to 

two of the four non-emergency plant buses throughout the event. Both units automatically 

tripped when power was lost to the reactor protection system motor generator sets. Prior to the 

event, Unit 2 was operating at full power and Unit 3 was operating at 91 percent of full power. It 

was later determined that the loss of offsite power was the result of a lightning strike on a 

transmission line approximately 35 miles northeast of the site that did not clear properly due to 

malfunctions in the protection system [IN 2004-15; AIT 05000277&278/203013; LER 277/2003-

004].

On May 20, 2006, both units of Catawba Nuclear Station tripped automatically from 100% 

power following a LOOP event (See the LER for Event Number 413/2006001, "Loss of Offsite 

Power Event Resulted in Reactor Trip of Both Catawba Units from 100% Power”). That event 

began when an electrical fault occurred within a current transformer associated with one of the 

switchyard power circuit breakers. A second current transformer failure, along with the 

actuation of the bus differential relays associated with both switchyard buses de-energized both 

switchyard buses and separated both of the nuclear units from the grid [IN 2007-14; AIT

05000413&414/2006009].

On February 15, 2007, a breaker failure occurred in the Jocassee Hydroelectric Station 

switchyard causing one phase to fault to ground (see Event Number 43169 and LER 

269/2007001). The Oconee Nuclear Station has two switchyards that contain transmission lines 

that interconnect to other switchyards on the Duke Power Company electric grid. The phase-toground fault was isolated by protective relays at the Oconee 230 kV switchyard, but the 

resulting prolonged (less than 1 second) grid disturbance unexpectedly resulted in a main 

generator lockout, main turbine trip, and bus transfer from normal to startup sources at unit 1 

and unit 2. [LER 269/2007-001]

On February 26, 2008, Turkey Point Nuclear Plant unit 3 and unit 4 automatically tripped from 

100% power due to a momentary power fluctuation caused by grid instabilities. Each reactor 
5

tripped when both channels of safety-related 4 kV bus undervoltage relays actuated after a one 

second time delay. Protection against a momentary grid disturbance is a feature of Turkey 

Point's electrical system; however, the duration of the condition exceeded the time delay 

resulting in the actuation of the 4 kV bus undervoltage relays. The source of the grid 

disturbance was a short circuit to ground on a substation in Dade County, Florida, compounded 

by human error in troubleshooting the substation protection system [LER 250/2008-001-00].

In addition to the aforementioned examples of domestic power transmission grid transient 

events, there have been numerous occurrences outside of the US involving external electrical 

faults that resulted in NPP trips. Notable examples include the Forsmark Nuclear Power Station 

– Unit 1 (Forsmark-1) in Sweden on July 25, 2006, and the Maanshan Nuclear Power Station –

Unit 1 (Maanshan-1) in Taiwan on March 17 and 18, 2001. The Forsmark-1 event was initiated 

by a line-to-line arcing fault on a 400kV disconnect switch that was erroneously opened under 

load during maintenance activity at the offsite 400kV switchyard. The ensuing transient caused 

the generator bus voltage to drop as low as 50 percent of nominal voltage for approximately 300 

milliseconds until power circuit breakers on the high-voltage side of the main transformers 

tripped on low voltage. The load dump caused the main generator bus voltage to surge to 120 

percent of nominal voltage for approximately one second, seriously challenging the voltage 

limits of solid-state UPS systems in multiple redundant reactor safety trains [IN 2006-18; IN 

2006-18, Supplement 1]. 

In the Maanshan-1 incident in Taiwan, fog and misty weather acting on salt-contaminated 

insulators caused the interruption transfer of the normal offsite power source resulting in an 

automatic reactor shutdown and transfer from its preferred 345kV offsite system to the backup 

161kV system on March 17, 2001. Maanshan-1 is a PWR plant designed to and built to US 

standards. On March 18, with the reactor shutdown, the 345kV transmission system serving the 

plant was restored; during subsequent bus transfer operations to realign the plant’s safety 

buses from the 161kV backup to the 345kV preferred source, an insulator failure on the supply 

side of one of the 4160V safety-related switchgear buses resulted in a high-energy arcing fault 

[IN 2002-01, January 8, 2002]. The explosion, fire, and smoke accompanying the energetic 

arcing switchgear fault resulted in a LOOP, loss of one EDG, and extensive damage to the 

switchgear supply breakers and five adjacent switchgear compartments, electrical buses, and 

supply cables [Raughley & Lanik, February 2002; NUREG/CR-6850, October 2007].

1.2 Purpose and Scope

The purpose of this research project is to: 1) develop a better understanding of the current 

power system protection in NPP electrical switchyards and 2) to identify the electrical system 

vulnerabilities that contribute to electrical fault propagation into the nuclear plant’s switchyard

causing plant trips and LOOP.

From the regulatory viewpoint, the tripping of a NPP as a result of distant electrical faults on the 

electrical grid should be avoided for the following reasons: 1) it challenges the safety 

systems/equipment of the NPP and therefore, increases the overall risk and 2) it may worsen 

the electrical transmission grid conditions due to a sudden loss of a significant amount of real 

and reactive power generation. Recent operating experience, including the examples described 

above, has shown that the mitigation of external electrical faults is important to nuclear plant 

safety because external faults can cause nuclear plant trips and have had an adverse effect 

upon the availability of offsite power, which is the preferred source of power for NPP core 

cooling systems for both normal and emergency shutdown. Many electrical grid transient 

events indicate that disturbances originating in the grid often were not identified and isolated 
6

rapidly enough by the grid protection systems, due to various reasons (e.g., failure of protection 

relays), to avoid a nuclear unit trip or a loss of one or both of the offsite power sources.

This study has reviewed the typical configurations of NPP switchyards and their interface with 

the offsite power grid to try to identify significant specific events, categories of events, or other 

factors that may involve similarities to the adverse grid transient events described above in the 

operating experience discussion. Quite often, the response of the NPP switchyard protection 

systems to a persistent external electrical fault is to quickly isolate the switchyard from the grid 

upon sensing the transients; unfortunately, this can have a further destabilizing effect on the 

electric power grid due to the sudden removal of the significant reactive power support provided 

by the nuclear station generator. The result can be further degraded local grid voltage and grid 

voltage instability as the system tries to compensate for the sudden demand for reactive and 

real power. This can lead to losses-of-offsite power sources and potentially cause tripping of 

other nuclear plants connected to the regional grid that is being affected by the transient event 

[Russell & Kueck – Dec 91]. The operation parameters of electrical protection systems 

associated with NPP switchyards and transmission connections were studied to determine 

whether the response of the NPP switchyard protection system can be augmented or improved 

to minimize the number of nuclear plant trips and losses-of-offsite power (LOOPs).

Analytical models were developed for selected nuclear power stations and their grid 

interconnections using the ETAP software tool. These models were then used to study the 

operation of the NPP electrical protection systems during grid transients in order to identify the 

causes, vulnerabilities, unusual configurations, or operational parameters that may have 

contributed to the tripping of the nuclear plant and/or the loss-of-offsite power sources. The 

models were also used to demonstrate the effects of external grid faults and transients on the 

voltage and frequency conditions at the nuclear plant switchyard buses, main generator bus, 

and safety systems buses. The effects of proposed protection system improvements on the 

response of the NPP switchyard protection system to external electrical system faults and 

disturbances were evaluated using sensitivity studies and system simulations.

The purpose of this study is to demonstrate and verify through modeling and simulation that 

precise and faster clearing of faults can in fact limit damage and improve plant ride-through, 

which is the one of the main reasons for developing and deploying telecommunication-based 

relay schemes. The practical application of this approach into an existing protection scheme, 

which would be the equivalent of upgrading to a faster protective relay, would of course have to 

be analyzed carefully to take into consideration the coordination of all affected protection system 

timing intervals as well as the effects that the tripping of transmission element(s) can have on 

system stability. The high speed, precision, and reliability of telecommunication-based 

protection now being deployed allows ISOs, utilities, and NPP operators to take advantage of 

the potential improvements that faster clearing times can provide as we have shown in our 

study.

1.3 Organization of this Report

Section 1 of the report provides brief introductory remarks about the purpose and functional 

requirements of the offsite power system serving a NPP. This includes a discussion of the 

regulatory requirements for NPP offsite electric power systems and a description of the station

blackout rule and its purpose. A condensed history of the deregulation of electric utility industry 

is presented along with a summary of the concerns of NRC about the possible erosion of the 

reliability of the electric power transmission grid and the potential effect that it may have on 

nuclear safety. Several examples are presented of recent incidents in which electrical faults 
7

originating on the transmission grid have had a significant impact on NPP safety, operation, and 

performance.

The offsite power system is described in Section 2. This covers the regulatory requirements of 

the offsite power system, common nuclear plant switchyard bus arrangements, and typical 

electrical protection systems for switchyard buses, transmission lines, power transformers, and 

the main generator. 

Section 3 presents BNL’s approach to studying the impact that the response and timing of the 

electrical protection system can have on the NPP response to external fault events. The event 

fault tree analytical approach is described which involves the creation of sets of contingency 

scenarios, transient simulations to study grid response, identification of grid responses that 

affect NPP performance (plant trips and/or LOOP), and evaluation of potential protection system 

improvements to avoid NPP trips and/or LOOP.

The development and analysis of three selected NPP simulation models are covered in Section 

4. The details of the individual models are described along with the definition of sets of 

analytical scenarios, transient stability simulations that were conducted, and analyses of the 

results of the simulation studies. Transient analyses are presented and the resulting responses 

of the grid and the electrical protection system are demonstrated. In this section a discussion is 

provided of the parameters that are varied to demonstrate the value of proposed protection 

system modifications and improvements.

The importance of rigorous periodic maintenance for electrical protection systems and 

equipment associated with NPPs and their offsite power supplies is emphasized in Section 5. 

During the review of operating experience it was noted that many of the external fault events 

that affected NPPs were directly attributable to or were exacerbated by inadequate transmission 

system maintenance. Consequently, examples are given in this section of inadequate 

maintenance as a cause of external faults events that have affected NPPs. The importance of 

cooperative agreements for operation and maintenance, between nuclear plant operators and 

transmission ISOs is discussed, including the implementation of the NERC/FERC requirements 

for grid reliability as it applies to NPPs.

Section 6 presents a summary and conclusions of the study.

9

2 NUCLEAR PLANT OFFSITE POWER SYSTEM 

This section provides a basic description of the offsite power system of a typical NPP and its 

interface with the electric power transmission grid. The major electrical equipment, the plant 

switchyard arrangement, transmission interconnections, and their electrical protection systems 

are presented. These main electrical system components will be incorporated into the analytical 

models, using the ETAP software, to perform the simulations of the plant electrical distribution 

systems and grid interfaces for several nuclear power stations as described in Sections 3 and 4 

of this report.

The general requirements for nuclear plant electric power systems are presented in General 

Design Criterion (GDC) 17 of Appendix A to 10 CFR 50 [10 CFR 50, Appendix A, GDC-17], 

regarding on-site and offsite power supplies, independence and redundancy, safety functions, 

and design basis accident performance. In addition, certain nuclear station electrical systems 

will often include provisions for an alternate ac (AAC) power source to satisfy the requirements 

of the station blackout (SBO) rule, 10 CFR 50.63, “Loss of all alternating current power,” 

[10 CFR 50.63] which are further described in Regulatory Guide 1.155, “Station Blackout,” [RG 

1.155]. IEEE Std 765-2006 [IEEE Std. 765-2006], “Preferred Power Supply (PPS) for Nuclear 

Generating Stations” provides detailed design criteria for the preferred power supply used in 

NPP electrical supply and distribution systems, and the interface with the NPP’s Class 1E 

distribution system whose criteria are described in IEEE Std. 308-2001 [IEEE Std. 308-2001]. 

In most cases, to satisfy the specific design requirements of GDC 17 and the aforementioned 

regulations and IEEE standards, NPP distribution system configurations will incorporate the 

basic features and characteristics suggested in IEEE Std. 765-1995, with minor variations due 

to plant-specific transmission system interfaces and voltage levels, multiple-unit plants, and the 

incorporation of increased levels of redundancy.

2.1 NPP Electric Power Distribution Systems

The electrical power distribution system in a NPP consists of three interfacing systems: the lowvoltage system, the medium-voltage system, and the high-voltage system. The low-voltage 

system and the medium-voltage system are usually referred to as the onsite power system, as 

described in Chapter 8 of the Standard Review Plan [NUREG-0800], which includes the Class 

1E, redundant, safety-related power systems and standby emergency generators. The offsite 

power system is comprised of the plant’s main generator and its connections to the high-voltage 

power system. A typical NPP electrical distribution system is illustrated in the one-line diagram 

in Figure 1.

2.1.1 Onsite Power System

The low-voltage electrical distribution system in a nuclear power station supplies plant loads 

having operating voltages of 600 V or lower, e.g. 480 V, 240 V, 208 V, and 120 V. The lowvoltage system typically includes 480 V electrical buses that are fed from the medium-voltage 

distribution system via 4160 V/480 V transformers. These 480 V buses supply power to the 

majority of the in-plant electrical equipment.
10

Figure 1 Typical NPP electrical distribution system
11

The medium-voltage distribution system supplies plant loads ranging from 600V up to 35 kV. 

Typically this will include equipment operating at 6.9/13.5 kV, such as the reactor coolant pumps, 

as well as other large plant electrical loads that operate at 4160 V. It also supplies power to the 

low-voltage distribution system. The preferred source of electrical power for the mediumvoltage system can be the output from the plant’s main generator during normal power 

operation, through the unit auxiliary transformer(s), or the offsite power grid, via the startup 

transformer(s), during plant startup or shutdown. In the event of the loss of offsite ac power, onsite emergency diesel generators (EDGs) are used to supply medium-voltage power to selected 

Class 1E safety-related equipment. To satisfy the requirements of the station blackout rule, a 

separate independent SBO generator and/or an alternate ac (AAC) power source may be

included in the system, as shown in Figure 1.

The boundary between the nuclear power station’s onsite power distribution system and the 

offsite power system is the interface of the medium-voltage in-plant distribution system with the 

high-voltage portions of the plant’s distribution system. As seen in Figure 1, this typically occurs 

at the unit auxiliary transformer(s) and the startup transformer(s). Note that the NPP main 

generator and its step-up transformer are considered part of the offsite ac power system as 

described in Section 8.2 of the Standard Review Plan [NUREG-0800]. As described in the SBO 

Rule [10 CFR 50.63], IEEE Std. 765-2006, and Chapter 8 of the Standard Review Plan 

[NUREG-0800] the AAC source(s) for SBO are considered separately for adequacy and 

independence from both the onsite and offsite power systems of the nuclear plant.

2.1.2 Offsite Power System

The offsite power system is comprised of the electric power grid, the NPP high-voltage 

distribution system, and the unit main generator. The high-voltage portions of the nuclear plant 

electrical distribution system include the components in the plant’s switchyard, e.g., power 

circuit breakers, disconnect switches, and buses, and the short transmission link that connects 

the main generator to the electrical transmission grid outside the plant. This system operates at 

very high voltages to minimize current flow and, thus, minimize transmission line losses. 

The output of the plant’s main generator is lower than the transmission grid voltage. Typical 

generator output voltage may be 22 kV to 25 kV. The plant’s main generator typically is 

connected via an isolated-phase bus duct to a main step-up power transformer to match the grid 

operating voltage. The step-up transformer output is fed through high-voltage power circuit 

breakers via a short transmission link to the nuclear plant’s high-voltage switchyard.

The utility power grid is the normal preferred source of offsite power, via two or more physically 

independent transmission circuits to the plant’s medium-voltage distribution system, in 

accordance with GDC 17. In some plant designs, such as the one shown in Figure 1, offsite 

power is delivered to the plant electrical distribution system via a startup auxiliary transformer 

during plant shutdown and startup modes, before the plant is able to supply its own power 

needs; once the unit generator is producing power, the plant can transfer its source of power 

from the startup supply over to its unit generator output bus via a unit auxiliary transformer. In 

other nuclear station designs, plant loads always remain connected to the offsite power sources 

under all plant operating modes, thereby avoiding the need for a manual bus transfer during 

startup and shutdown operations, or a fast bus transfer in the event of a generator trip 

[NUREG/CR-6950 and Mazumdar & Chiramal-Oct 1991].
12

2.2 Switchyard Bus Arrangements

There are four basic switchyard bus arrangements that may be found in nuclear power station 

high-voltage switchyards: 1) the main and transfer bus, 2) the ring bus, 3) the breaker-and-ahalf bus, and 4) the double-bus, double-breaker arrangement. Detailed descriptions of these 

switchyard configurations are provided in Appendix C.

Most NPPs have incorporated either the ring bus or the breaker-and-a-half configuration into 

their basic switchyard arrangements. In the ring bus arrangement, such as the 345kV plant 

switchyard shown in the example NPP electrical distribution system in Figure 1, each circuit 

breaker is shared by adjacent transmission line connections. With this arrangement, it is 

possible to perform maintenance on any circuit breaker without interrupting service to the 

transmission line or transformer on either side of it.

In the breaker-and-a-half switchyard arrangement, for every pair of circuits there are three 

power circuit breakers, with the center circuit breaker being shared by the two circuits in each 

substation bay. This arrangement allows any circuit breaker to be removed from service without 

interrupting service to the circuits in the affected substation bay. Reliability and operational 

flexibility are improved because there is a double feed to every circuit and a fault on either of the 

buses can be isolated without losing any circuit. Another advantage of the breaker-and-a-half 

arrangement is that all switching operations may be accomplished using power circuit breakers.

These two switchyard arrangements are commonly utilized in NPP applications because they 

offer the best combination of operational flexibility, high reliability, and reasonable cost. 

Typically, the cost of a breaker-and-a-half bus arrangement is about the same as an equivalent 

switchyard using a ring bus arrangement and these are about 12%-15% more expensive than 

an equivalent switchyard using a main and transfer bus arrangement [McDonald – 2003].

In special cases where it is necessary to assure higher reliability for one or more extremely 

critical transmission circuits or generator connections in a breaker-and-a half switchyard, the 

switchyard bay(s) containing the critical connections can be modified to a double bus, doublebreaker arrangement. In this way, each of the critical circuits is served by two circuit breakers, 

such as shown in Figure 2. A higher level of reliability and operational flexibility is thus provided 

for the two critical main generator connections in Figure 2 while the overall cost of the 

switchyard is held in check by utilizing the breaker-and-a-half arrangement for the remainder of 

the transmission connections.

2.3 Electrical Protection Systems

The analyses performed for this study concentrate on the electrical protection systems found on 

the offsite power system and how the protective relays and control schemes that comprise 

these systems will respond to external electrical faults. The study will examine how the speed 

and sensitivity of the protection system in the detection and isolation of switchyard and 

transmission system faults can affect the magnitude and duration of the voltage, current, and 

frequency transient conditions that appear at the nuclear station switchyard buses, at the plant’s 

safety-related buses, and at critical non safety-related buses, such as those supplying the 

reactor coolant pump (RCP) motors.
13

Figure 2 Breaker-and-a-half switchyard with main generators connected in a double-bus, 

double-breaker arrangement

This subsection will describe the basic protective relaying and controls for offsite power system 

components, such as the transmission lines, switchyard buses, power transformers, and the 

main generator. The various types of transmission line protection systems will be described in 

the most detail since these devices will be a focus of the analytical study. Some of the onsite 

power system protective devices for the plant’s medium-voltage safety-related buses, and at 

critical medium-voltage non safety-related buses will be discussed briefly with respect to their 

plant safety response.

2.3.1 Transmission Line Protection Systems

Most electrical faults (60% or more, depending on the isokeraunic level) occurring on power 

systems will be located along the transmission lines connecting generating sources to their 

electrical loads. The characteristics of these lines vary in length, configuration, capacity, effect 
14

on grid stability, and importance. Consequently, there are a number of different transmission 

line protection schemes that may be applied to their protection. These may include: 1) 

overcurrent protection schemes, e.g., instantaneous/time-overcurrent or directional 

instantaneous/time-overcurrent protection, typically used for simple radial lines, on 

subtransmission or distribution circuits, or simple transmission loops with a single generating 

source; 2) distance relaying, in which impedance relays, reactance relays, or mho relays are 

applied where the trip settings of these types of relays correspond to the effective impedance of 

the line being protected; and 3) electrical protection systems using telecommunications, in 

which a telecommunications circuit (such as a power line carrier signal, a dedicated wire or fiber 

optic communication link, or a radio transmission signal) is used to compare system conditions 

at both ends of a transmission line to initiate selective high speed clearing of all faults on the 

protected line.

A typical transmission line protection scheme may apply a combination of zone distance 

relaying phase protection and directional ground overcurrent protection, with auxiliary protective 

features such as automatic reclosing or a breaker failure scheme, as presented in Figure 3, 

depicting a typical protective relaying schematic diagram for a transmission line at its substation 

terminus. In this example, an automatic reclosing scheme (Device 79) is included that will, after 

a suitable delay, reclose the circuit breaker that has just been tripped. Experience has shown 

that reclosing transmission and distribution circuits following a protective trip has a success rate 

of 80% on the first attempt and 5% on the second attempt; single-line-to-ground faults have a 

higher reclosing success rate than 3 phase faults [Daume – Feb2007]. The reclose delay 

should be long enough to allow arc deionization at the site of the fault and provide enough time 

for the remote terminal to clear: a suitable reclose delay should at least be greater than (10.5 + 

kV/34.5) cycles [Daume – Feb2007]. The line protection scheme in Figure 3 also includes 

breaker failure protection (Device 50BF). In the event that the local circuit breaker protecting 

the transmission line fails to trip to isolate a fault on line, the breaker failure scheme will initiate 

the tripping of backup circuit breakers at the substation to interrupt the fault current.

Figure 3 Typical protective relaying schematic at one end of a high-voltage 

transmission line
15

2.3.1.1 Distance Relaying Schemes

Distance relays, which calculate the impedance of the line by measuring the voltage and current, 

are the most commonly used relays to protect relatively long transmission lines. Distance relays, 

which may include impedance relays, reactance relays, and mho relays, are usually configured 

to include three sets of relays at each end of a transmission line to provide for three protective 

zones [Kundur 1993 & IEEE Std. C37.113-1999]. Zones 1 and 2 are used to provide the 

primary protection of the transmission line while Zone 3 acts as a remote backup for the 

adjacent line(s). The typical parameter settings for the Zones 1 - 3 relays installed at each end, 

or terminal bus, of the transmission line are the following:

• Zone 1 relays: A Zone 1 relay usually covers from 80% to 90% of the line length or the 

impedance from the bus where the relay is installed, and there is no intentional time 

delay to open the circuit breaker once the fault is detected;

• Zone 2 relays: A Zone 2 relay covers around 120% of the protected line length (i.e., 

beyond the end of the protected line), and a typical time delay of between 0.3 and 0.5 

seconds is set for the relay to open the circuit breaker once the fault is detected. A Zone 

2 relay is mainly used to protect the rest of the line beyond the reach of the Zone 1 

relays and should be adjusted such that it can respond to even an arcing fault at the end 

of the line [Mason 1956].

• Zone 3 relays: A Zone 3 relay overreaches the adjacent transmission line(s) as the 

remote backup for the protection system of the adjacent line(s); a typical 2 second delay 

is set for the Zone 3 relay if the fault occurring on the adjacent line(s) is not cleared in 

time.

Note, Zones 1, 2, and 3 relays located at the two ends of a transmission line reach in the 

opposite direction, i.e., they “look” out onto the transmission line from the two opposite end 

terminals. Therefore, it can be seen that if the Zone 1 relays at both ends of a line fail, the Zone 

2 relays are expected to respond to the uncleared fault (within the range of the Zone 1 relays at 

both ends) and open the circuit breakers after a time delay of between 0.3 and 0.5 seconds. If 

the fault occurred beyond the range of the Zone 1 relay at one end, the failure of the Zone 1 

relay at the other end will lead to the response of the Zone 2 relays at both ends, which will 

again open the circuit breakers after the time delay of between 0.3 and 0.5 seconds. Therefore, 

it is a reasonable assumption that a transmission line fault that was not cleared by the Zone 1 

relays will be cleared within 0.5 seconds (which may include the opening time of the circuit 

breakers) by the Zone 2 relays.

Depending on the types of faults (e.g., three phase, phase-to-phase, phase-to-ground, and 

double phase-to-phase) to be covered by the distance relaying, the number of relays at each 

end of the line changes. In general, one set of relays is provided for phase faults and one for 

ground faults, respectively [Kundur 1993].

For distance relaying, if a fault occurs near one end of the line (i.e., less than 20% of the 

distance of the line from that end), the fault should be cleared at the near end instantaneously, 

i.e., without any intentional time delay, but with a time delay of between 0.3 and 0.5 seconds at 

the far end bus. The reason for this is that the difference of the measured impedances for faults 

near a bus but on different sides of the bus, e.g., faults F2 and F3 in Figure 4.
16

Figure 4 A Distance Relaying Scheme

To summarize the protective response of a distance relaying scheme, the fault F1will be cleared 

instantaneously by Zone 1 relays at both ends. The fault F2 will be cleared instantaneously by 

Zone 1 relays at end B and with a time delay of between 0.3 and 0.5 seconds by Zone 2 relays 

at end A. For the fault F3 between ends B and C, the Zone 2 relays at end A will respond to it 

with a time delay of between 0.3 and 0.5 seconds if it is not cleared by the protection relays of 

line BC. For the fault F4 , the Zone 3 relays at end A will clear it with a time delay of around 2.0 

seconds if it is not cleared by the protection relays of line BC.

Note, for fault F4 , Zone 3 relays at bus A will clear the fault after 2 seconds of its occurrence if 

the primary relays (Zone 1 and Zone 2 relays) at bus A are failed. This apparently has more 

severe impact than a case where the time delay of Zone 3 relays at bus A is shorter. Reducing 

the time delay effectively makes the protection devices operate in a less coordinated manner 

but may benefit the capability of fault rejection in the sense that primary relays of line BC may 

malfunction. This anticipatory trip scheme of Zone 3 relays will be further discussed and 

demonstrated in Section 4.

From the above description, it is easy to conclude that, in case of no breaker failure protection 

scheme if the circuit breakers and/or Zone 1 relays at the near end should fail:

1. the fault clearing time for the fault F2 is between 0.3 and 0.5 seconds because the fault 

has to be cleared by the zone relays at end A and the Zone 2 relays at end C (CBs 

and/or Zone 1 relays on line AB near B fail); 

2. the fault clearing time for fault F3 is also between 0.3 and 0.5 seconds because it has to 

be cleared by Zone 2 relays at end A and the Zone 2 relays at end C (CBs and/or Zone 

1 relays on line BC near B fail);

Similarly, it can be further concluded that, in case of no breaker failure protection scheme, if the 

circuit breakers at both ends of the protected line fail:

3. the clearing time of fault F1 (or F4 ) is around 2 seconds.

If simultaneous high-speed tripping at both ends is required or in an application where a 

distance relaying scheme is very difficult to apply (e.g., a very short transmission line), a 

telecommunications-based relaying scheme, with telecommunication channels between the 

Z1

Z2

Z3

Z3

Z2

Z1

A B C

F1 F2 F3 F4

D
17

relaying equipment at the two ends of the protected line, is a more suitable choice. This 

scheme will be discussed in detail in the next subsection.

2.3.1.2 Electrical Protection Schemes Using Telecommunications

The high speed simultaneous clearing of all line terminals provided by an electrical protection 

scheme using telecommunications (pilot relaying) has a number of important advantages. The 

possibility of electrical overload damage to transmission line conductors, and to all components 

of the transmission line, in general, is minimized by rapid isolation of the fault. The fast clearing 

of faults by the telecommunications-based relaying also helps to improve transmission grid 

stability by minimizing the magnitude and duration of transient events. High speed clearing of 

transmission line faults provided by telecommunications-based relaying in turn permits rapid 

reclosing, which if successful, also helps to improve transmission grid stability and to minimize 

the adverse effects caused by electrical disturbances on the power system.

The principle of operation for telecommunications-based relaying is that the circuit breakers at 

all ends of the protected lines will trip for an internal fault but will not (i.e., the tripping is blocked) 

for an external fault. Whether a fault is internal or external is determined by the relays at both 

ends of the protected line using either the directional comparison (by using distance relays and 

directional relays) or phase comparison (by comparing the relative phase displacement of 

currents entering and leaving the protected line). Due to the fast development of modern 

communication technologies and reductions in costs, protective relaying using 

telecommunications has become increasingly popular in transmission system protection. The 

high speed and reliability of telecommunications links are an important part of achieving the 

rapid fault clearing times offered by telecommunications-based protection schemes. Signal 

propagation time in these systems is typically only a very small part of the overall clearing time 

for most applications. For example, if a power line carrier signal over the transmission line is 

used for communication, each 186 miles of transmission line will only introduce about 1 ms 

delay [GER-3965] (note, this 1 ms is only a minor part of the operating time of a 

telecommunication-based protection system). Dedicated fiber optic communication links or 

radio signal transmission can potentially yield even faster communications.

A number of electrical transmission protection schemes using telecommunications links have 

evolved in the industry. The most important of these schemes include: 1) intertripping 

underreach protection, 2) permissive overreach protection, 3) accelerating underreach 

protection, 4) permissive overreach protection, 5) blocking overreach protection, 6) deblocking 

overreach protection [CIGRE JWG 34/35.11-2001 & Lindahl-2011]. Some of these are 

described in the following subsections.

2.3.1.2.1 A Permissive Overreaching Scheme

An example of the permissive overreaching scheme is described in [Kundur 1993], which is 

similar to the distance relaying scheme. The differences between the permissive overreaching 

scheme and the aforementioned distance relaying are that: 1) the permissive overreaching 

scheme does not have Zone 3 relays and 2) if a fault occurred, such as F2 shown above in 

Figure 4, the circuit breakers at both ends of the protected line will be tripped without any 

intentional time delay, i.e., circuit breakers at both ends will be opened at high speed. 

This permissive overreaching scheme is better illustrated in the example presented in Figure 5. 

The fault F1 is picked up by Zone 1 relays at both ends and will be tripped immediately and no 
18

communication is involved. The fault F2 is picked up by the Zone 1 relays at end B and the 

circuit breakers will trip instantaneously. The fault F2 is also picked up by the Zone 2 relays at 

both ends and permissive signals will be sent to each other. The Zone 2 relays will trip the 

circuit breakers at end A upon receiving the permissive signal (the communication channel time 

is usually less than 20 ms). The Zone 2 relays at end A picks up the fault F3 but will not open 

the circuit breakers since the Zone 2 relays at end B is not picked up and do not send any 

permissive signal to the Zone 2 relays at end A. However, the Zone 2 relays at end A will trip 

the circuit breakers if fault F3 lasts more than 0.4 seconds (e.g., if the circuit breakers of line BC

near B fail to open). Fault F4 will only be picked up by protection relays of line BC.

1. Therefore, for fault, F1 failures of Zone 1 relays at both ends have very minor impact on 

the clearing time because Zone 2 relays will trip the circuit breakers almost 

instantaneously (with a delay of communication channel time). 

2. A time delay of around 0.4 seconds is expected if both zones 1 and 2 relays at both 

ends fail for fault F2 in case of no breaker failure protection scheme.

Figure 5 A Permissive Overreaching Relaying Scheme

2.3.1.2.2 Blocking-type Relaying Scheme

A blocking-type relaying scheme is the most preferable of the telecommunications-based

relaying methods and the directional comparison scheme, shown in Figure 6 is the most popular 

application of this approach. An example of telecommunications-based blocking-type protection

with a directional comparison scheme is also presented in [Kundur 1993]. By default, the relays 

will trip the breakers once an internal fault is detected unless a blocking signal is received for a 

blocking-type relaying scheme. In general, the Zone 1 and Zone 2 relay settings are similar to 

the permissive overreaching relaying scheme previously shown in Figure 5 except that the 

Zone 2 relays will trip if a blocking signal is not received within 25 ms (the communication 

channel time). The Zone 3 relays, which are reverse blocking directional relays set in a 

direction opposite to the protected line to detect whether the fault is external or internal, will 

generate and send a blocking signal to the Zone 2 directional relays at the remote end once it is 

determined that the fault is external to the protected line. The Zone 2 relays will trip anyway 

irrespective of any blocking signal if the fault lasts for more than 0.4 seconds.

As shown in Figure 6, fault F1 will be detected and cleared by Zone 1 relays at both ends A and 

B ( and ). Fault F2 will be cleared by Zone 1 relays at end B ( ) and Zone 2 relays at 

end A ( ) after 25 ms since there is no blocking signal from Zone 3 relays of end B

A Z1B Z1B Z1

A Z2

Z2

Z1

A B C

F1 F2 F3

Z1

Z2

F4
19

Figure 6 A Directional Comparison Protective Scheme Using Telecommunications

( ). Note, the same fault is also seen by Zone 2 relays at end C ( ) but relays tripping 

will be blocked by the Zone 3 relays at end B watching the opposite direction of line BC ( ), 

unless the fault lasts more than 0.4 seconds. Although the Zone 2 relays at end A ( ) sees 

fault , they will not trip since they are blocked by the Zone 3 relays at end B ( ) watching 

the opposite direction of line AB.

1. Therefore, for fault F1 , failures of Zone 1 relays at both ends have very minor impact on 

the clearing time because Zone 2 relays will trip the circuit breakers almost 

instantaneously (with a delay of communication channel time). 

2. A time delay of around 0.4 seconds is expected if both zones 1 and 2 relays at both 

ends fail for fault F2 in case of no breaker failure protection scheme.

Blocking overreach protection systems have been one of the most frequently applied schemes 

in the past but more recently a potential disadvantage of this type of protection system has been 

observed more and more. There is a risk that the blocking signal, particularly when the signal is 

transmitted over a power line carrier link, can be interrupted by disturbances resulting from 

electrical faults or transients on adjacent transmission lines. As a result, there is the chance 

that the blocking signal transmitted over a functional transmission line can be interrupted by an 

adjacent line disturbance causing the overreaching protection to actuate and inadvertently trip 

the healthy transmission line. [Lindahl-2001]

2.3.1.3 Breaker Failure Backup Protection

Breaker failure protection schemes were not considered in the above discussions. Breaker 

failure protection is relied on to take appropriate action to clear a fault when the circuit 

breaker(s) that is expected to clear the fault fails to do so [IEEE C37.119-2005]. A breaker 

failure protection can either be a local backup (i.e., on the same substation or busbar as the 

primary protection) or a remote backup protection. A local breaker failure protection receives a 

signal directly from the protection relays at the same busbar or substation as the faulted circuit 

breaker and needs only to wait for the breaker (the faulted one) interrupting time to trip the local 

backup breakers.

For a remote breaker failure protection, an intentional time delay (usually 0.5 seconds or 30 

cycles) has to be set before the remote backup breakers are opened without a communication 

channel. Also, a separate set of relays has to be installed at the substation or the busbar where 

B Z3

C Z2C Z2 '

3

B Z

A Z2

F3

B Z3

A Z1

A Z2

B Z3

A Z3

B Z2

B Z1

A B C

F1 F2 F3

C Z1

A Z1

C Z2

'

3

B Z
20

the impaired breaker is located in order to detect the fault and signal the remote circuit breakers 

to trip [IEEE C37.119-2005]. 

A communication channel that can directly send trip signals generated by the local relays at the 

busbar or substation of the impaired breaker(s) to the remote breakers can be used in remote 

breaker failure protection scheme and allows for high speed remote clearing. With the 

assistance of the communication channel, the breaker failure timer setting does not need to be 

as long as 0.5 seconds. Instead, it is typically assumed to be 90 ms for a 2-cycle circuit breaker 

and 150 ms for a 3-cycle circuit breaker [Kundur 1993].

For a typical distance relaying scheme, as shown in Figure 4, a communication-based remote 

breaker failure protection is unnecessary considering the time delay setting of between 0.3 and 

0.5 seconds for the Zone 2 relays. For the telecomunications-based protection scheme like the 

directional comparison blocking scheme shown in Figure 6, breaker failure at any end will cause 

the fault clearing time near that end to be delayed for a sum of communication channel time and 

the intentional time delay between 90 ms and 150 ms. In addition, depending upon the 

remedial trips specified in a particular breaker failure scheme, a larger number of components 

need to be tripped as a result of the breaker failure. An example of such a breaker failure 

scheme can be found in [Kundur 1993] and further details will not be discussed here.

2.3.1.4 An Example Transmission Line Protection System

A modern transmission line protection system is often equipped with duplicated distance and/or 

differential protection relays [Lindahl-2011], as shown in Figure 7.

Block 1 in Figure 7 represents the first main protection zone, Main 1, while Block 2 represents

the second main protection zone, Main 2. One core of the common current transformer feeds 

Main 1 and another core feeds Main 2. A common voltage transformer feeds both Main 1 and 

Main 2 but there are two separately fused groups. One group feeds Main 1 and the other one 

feeds Main 2. Block 3 represents the teleprotection equipment for Main 1 while Block 4 

represents the teleprotection equipment for Main 2. Block 5 represents the telecommunication 

equipment for Main 1 while Block 6 represents the telecommunication equipment for Main 2.

The network owner may use: (1) power line carrier links, (2) radio links, (3) microwave links, or 

(4) fiber optical links for the transfer of information between the terminals of a transmission line. 

Often there are two telecommunication links between the terminals of a transmission line. If 

there are two telecommunication links, Main 1 uses one link while Main 2 uses the other one. 
21

Figure 7 An Example Transmission Line Protection System

A breaker failure protection element is included in the line protection system. Such a protection

system provides instantaneous trip of the line circuit-breakers even if one element in the

protection system fails to operate. The fault clearing time will be about 80 milliseconds for

close-up faults and about 100 milliseconds for faults near the remote end if the line circuitbreakers operate correctly. The fault clearing time may range from 200 to 250 milliseconds if 

one of the line circuit-breakers fails to operate. The backup clearing time depends on the delay 

in the breaker failure protection. The setting of the delay in the breaker failure protection is the 

result of balancing the advantage of having a short backup clearing time and the risk of having 

an unwanted operation when the circuit-breaker operates and interrupts the current.

The delay of Zone 2 and Zone 3 may not be as important in such a protection system as that in 

the protection systems without redundancy. However, redundancy is often defeated by 

common cause failures even for the redundant equipment of diverse designs. Hence, adjusting 

the settings of existing protection systems, especially those time delay of the secondary and/or 

backup protection systems or the breaker failure schemes, is still considered necessary and 

valuable.

2.3.2 Switchyard Bus Protection 

The most sensitive and reliable method for the protection of switchyard buses is differential 

protection. The basic principle in this approach is to measure the net flow of current into and 

away from the station bus that is being protected. The net current measured by the differential 

protection relays will balance out to zero for all conditions unless a fault condition exists 

anywhere on the station bus within the zone of the monitoring current transformers. This 

method is very reliable and can operate very fast. Details of the application of bus differential 

relaying to actual station switchyard bus protection can be found in several sources on the 

subject, such as the Westinghouse “Applied Protective Relaying” [Blackburn, et. al. – 1976],

General Electric’s “The Art and Science of Protective Relaying” [Mason – 1956], and IEEE Std. 

C37.234-2009, “IEEE Guide for Protective Relay Applications to Power Systems Buses” [IEEE 

C37.234-2009].
22

Electrical protection specialists recommend that duplicate bus protection be provided in 

substations using the double-bus, double-breaker arrangement and the breaker-and-a-half 

arrangement. This is necessary to avoid the severe consequences that might occur in the event 

of a bus fault at a substation with a non-redundant bus protection scheme, should the bus fault 

be combined with a failure to operate of the non-redundant bus protection system. The bus 

fault would then be detected by Zone 2 protection of the distance relays in the adjacent 

substations and would therefore not be cleared for perhaps 450 to 500 milliseconds. All 

transmission lines connected to the substation would be tripped at their remote ends to finally 

clear the fault. [Lindahl – 2011]

The type and location of the current transformers must be considered when establishing the 

protection coverage for substation buses. Dead-tank circuit breakers, in which the circuit 

breaking mechanism is contained within the enclosure tank that is connected to electrical 

ground, are usually equipped with a pair of bushing current transformers. With this CT 

arrangement, overlapping protection zones at the bushing transformers provide complete 

coverage for the substation buses. Live-tank circuit breakers, where the enclosure is at line 

potential, are not usually equipped with bushing CTs instead being used in conjunction with 

single freestanding current transformers. It is possible, particularly on substations using the 

main and transfer bus arrangement, to incur a fault between the freestanding CT and the circuit 

breaker that could initiate primary protection zone tripping of all circuit breakers in the substation 

without interrupting the fault. The fault would then not be cleared until the backup protection 

initiates and opens remote circuit breakers. [Lindahl – 2011]. 

A potential vulnerability in the bus protection of substations using the double-bus, doublebreaker arrangement was identified by B. Svensson in 2005 [Svensson-2005 and Lindahl-2011] 

related to freestanding current transformers as discussed above. There is a small risk in this 

bus arrangement that a single fault occurring between the circuit breaker and the freestanding 

current transformer combined with a failure to operate of the circuit breaker would trip out the 

entire substation. Breaker failure protection would correctly trip all circuit breakers in the 

substation. However, because of the location of the fault, fault current would continue to flow 

via the transmission line to the adjacent remote substation until Zone 2 transmission line 

protection tripped the line at the remote adjacent substation end. Depending on the time-delay 

setting of breaker failure protection, the backup clearing time would be on the order of 400 

milliseconds before the remote line end circuit breaker trips. Comparative reliability studies 

between the double-bus, double-breaker arrangement and the breaker-and-a-half arrangement, 

performed by Gothia Power AB in Sweden, have indicated that for certain NPP switchyard 

configurations, the breaker-and-a-half arrangement can be more reliable [Lindahl-2011].

In addition to the station bus differential relaying, the switchyard bus and circuit breakers will 

also fall into the various overlapping protective zones for the transmission lines that originate in 

the switchyard. These transmission line protective zones were described previously in 

subsection 2.3.1.

Most nuclear plant switchyards will incorporate a breaker failure protection scheme for the 

circuit breakers connected to the switchyard bus, as described above in subsection 2.3.1.3. 

The failure of a switchyard circuit breaker to trip in the presence of an electrical fault on any of 
23

the feeders into or out of the switchyard is a severe challenge to the power grid with several 

adverse consequences:

• it can have a severe impact on power system stability, 

• can exacerbate the damage to electrical conductors and equipment caused by a fault,

• can spread the effects of a fault-related outage to a larger area of the transmission 

system, and 

• can lengthen the outage time required to implement repairs and restore service due to 

excessive damage.

Normally, transmission line relaying located at the switchyard will detect a fault on the line and 

actuate the trip coil of the local circuit breaker. Should the circuit breaker at the plant switchyard 

fail to operate, the breaker failure relaying will detect continued fault current and initiate a retrip 

signal to the second trip coil of the breaker (if so equipped). After a time delay (equal to the 

normal trip time of the local circuit breaker), breaker failure relaying also will initiate trip signals 

to adjacent local circuit breakers at the switchyard, to remote circuit breakers at the far end of 

the faulted line, and any other remedial actuations associated with the specific application.

Stability analyses for some system configurations may indicate that the maintenance of system 

stability demands rapid clearing time for transmission faults in proximity to the NPP substation. 

In some cases, the clearing time resulting from the actuation of backup protection schemes, 

such as beaker failure protection, is longer than the clearing time necessary to maintain system 

stability [Lindahl-2011]. This condition is addressed in IEEE Std C37.119-2005, “Guide for 

Breaker Failure Protection of Power Circuit Breakers” [IEEE C37.119-205] as follows:

In those cases where stability studies show that the critical clearing time is less than the 

shortest backup clearing time attainable with high-speed breaker failure protection 

schemes, the only solution may be to install two identical breakers in series, with both 

breakers being tripped simultaneously by the protection schemes. With this arrangement, 

and fully redundant protection schemes, instrument transformers, and control power 

sources, it can be assumed that at least one of the breakers will successfully interrupt 

the fault. Thus, the total clearing time will be the same as the primary clearing time, and

no breaker failure scheme is necessary.

The NERC report, “Technical Paper on Protection System Reliability-Redundancy of Protection 

System Elements” [NERC-Jan 2009], compiled by the System Protection and Control 

Subcommittee of NERC, states:

Breaker Failure clearing time is a mode of operation that considers the Protection

System to be fully functional and will operate as designed and intended. However, it 

also considers that a breaker needed to isolate the fault failed to operate (remained 

closed or stuck). Planning engineers determine the critical clearing time for stuck 

breaker and/or breaker failure conditions. The protection engineer will account for this 

time when designing the breaker failure relaying protection. For example, the planning 

engineer might determine that the critical breaker failure clearing time is 12 cycles and 

this might result in the protection engineer setting the breaker failure timer at 8 cycles (2 

cycles for relay time, 8 cycles for the breaker failure timer, and 2 cycles for breaker 

tripping). In some cases the protection engineer may determine that the critical clearing 

time cannot be achieved without compromising security of the Protection System. In 

such cases, the planning engineer must design the electric system around this constraint 
24

(e.g., installing two breakers in series to eliminate the breaker failure contingency or 

constructing additional transmission elements to improve system performance, thereby 

increasing the critical clearing time) [Lindahl-2011].

Consequently, in such cases as described above where the fault clearing time, and in particular 

the response of the backup protection, is determined to be a critical factor in system stability, 

“...the installation of two circuit breakers in series would reduce the backup clearing time to 

approximately 100 milliseconds, which is very desirable for transmission (subtransmission) lines 

connected to NPP substations” [Lindahl-2011].

2.3.3 Onsite Medium-voltage Bus Protection

One of the main areas studied in this research program is the effect that external faults can 

have on conditions at the onsite medium-voltage buses. Specifically, this will include voltage 

and frequency at the plant’s safety-related buses and at critical non-safety buses, such as the 

reactor coolant pump buses. This subsection describes some of the bus protection features 

that are applied on these buses.

Each division of the Class 1E medium voltage system is provided with an independent scheme 

for the detection of degraded voltage and loss of voltage detected directly from the bus that is 

connected to the standby power source. Degraded voltage relays (DVRs) will sense 

degradation of the voltage on the preferred power supply and should initiate an alarm in the 

NPP main control room to alert the operators of the condition. The operator’s response to this 

alarm will vary according to specific system design and plant operating philosophy. If the DVRs 

sense that the voltage of the preferred power supply has degraded to an unacceptable level, i.e., 

the Technical Specifications allowable values and time delays for degraded voltage function and 

loss of voltage function, the affected preferred power source shall be disconnected from the 

Class 1E buses.

Considerations regarding the selection of DVR setpoints and operator responses to degraded 

voltage conditions are discussed in various technical articles, such as “A Discussion of 

Degraded Voltage Relaying for Nuclear Generating Stations” [Kueck, et. al. – 1998], [SRP BTP 

8-6], and [RIS 2011-12]. (note that IEEE Std. 741-2007, Annex A, discusses degraded voltage 

protection in NPPs but this standard has not been endorsed by the USNRC.) Note: Alarms 

setpoints associated with DVR actuation (dropout) indicates voltages well below normal grid 

voltages and are generally indicative of a collapsing grid such that operator actions are limited. 

Alarm setpoints set at higher voltages (associated with grid normal voltage) would allow 

operators time to actually take actions concerning voltage recovery to prevent separation from 

the offsite power system.

Similarly, some plants may include overvoltage sensing relays on the preferred power supply to 

monitor for the occurrence of excessively high voltage on the Class 1E buses. The overvoltage 

monitoring relays typically initiate an alarm in the main control room, but no automatic actions 

are initiated.

Critical non-safety buses, such as the power supply bus to the reactor coolant pumps (RCPs) 

may be monitored for degraded voltage and/or frequency. These degraded power conditions 

can affect the capability of the RCPs to supply rated flow and could potentially cause a reactor 

trip. In particular, PWR plants cannot tolerate much voltage and frequency variations from 

nominal values since it can cause flow-biased reactor trips. Typically, monitoring for these 
25

parameters will initiate an alarm in the main control room to alert the operators to the condition, 

but no automatic actions are initiated.

2.3.4 Power Transformers Protection

Typical protection and control relaying for the unit auxiliary transformers (UATs) and the station 

startup transformers (SSTs) include differential relaying, sudden pressure relaying, hot spot 

alarms, and loss of cooling alarms. The isolated phase bus duct feeds directly to the primary 

side of the UAT at the output voltage level of the main generator. Because of the close 

proximity of the high output main generator (and associated high available fault current), and the 

excellent physical protection afforded by the isolated phase bus duct, there is no circuit breaker 

on the primary side of the UAT. Phase overcurrent, ground overcurrent, and bus differential 

relaying provide fault protection for the isolated phase bus up to the primary side terminals of 

the UAT. Transformer differential and sudden pressure relaying protect the UAT against 

internal faults. UAT faults will cause a main generator trip, opening of the generator output 

circuit breaker at the high-voltage switchyard, and opening of the MV supply breaker (on the 

secondary side of the UAT) after a time delay to prevent spurious tripping of the main generator. 

[NUREG/CR-6950 and IEEE C37.91-2008]

The SSTs are connected via disconnect switches to a local terminal overhead bus structure 

which in turn is supplied from the main switchyard by way of a short length of overhead 

transmission line. This interconnecting line is protected by phase overcurrent relaying and 

differential relaying from the switchyard circuit breaker to the primary side of the SST. 

Transformer differential and sudden pressure relaying protect the SST against internal faults. 

Internal SST faults and faults on the short overhead interconnecting transmission line from the 

switchyard will cause a trip of the high-voltage circuit breaker at the station high-voltage 

switchyard. The station electrical distribution system is protected from overvoltage surges 

originating on the external transmission grid, the station switchyard, or the short overhead 

interconnecting transmission line by lightning arresters located at the primary (high-voltage) side 

of each of the startup transformers. [NUREG/CR-6950 and IEEE C37.91-2008]

The medium-voltage feeder cables from the secondary side of the UATs and SSTs, typically 

consisting of multiple paralleled power cables (for example, 2 - 3/C #750 MCM cables), are 

routed through metallic conduits and cable raceways to the individual medium-voltage 

switchgear enclosures. Fault protection for the UAT and SST feeder cables is provided by 

telecommunications-based differential relaying and/or overcurrent relaying. [NUREG/CR-6950]

2.3.5 Protection for the Main Generator and Unit-Connected Step-up Transformer

In most nuclear power stations, the main generator is linked to its unit-connected step-up 

transformer via isolated phase bus duct with no automatic power circuit breaker between them. 

Consequently, the electrical protection scheme for the main generator and the unit transformer 

will treat these components together as a unit. For example, current differential relaying will be 

provided for the main generator and main transformer separately to detect internal faults, but a 

differential monitoring scheme may also be applied that encompasses both the generator and 

its transformer together. 

Typical NPP main generator and output transformer protection, operating, and control relaying 

devices and their functions are tabulated in Appendix D, Table D-1, for a 1525 MW generator at 

a BWR plant. These devices protect the generator against problems such as, internal faults in 

the generator winding, overload, overheating of windings and bearings, overspeed, phase 
26

sequence, directional power flow, loss of excitation, motoring, and single-phasing or unbalanced 

operation [NUREG/CR-6950].

Some of these problems do not require tripping of the generator since adjustments may be 

made by station operators while the unit is operating to correct the off-normal condition. In a 

unit-connected generating station, electrical faults occurring at the generator output bus, main 

generator transformer, main switchyard, and unit-connected auxiliary transformers (i.e., those 

faults occurring between the generator and the circuit breakers at main switchyard) will usually 

require prompt tripping of the main generator.

The electric power output from the main generator is typically transmitted to the main generator 

step-up transformers and the unit auxiliary transformers via isolated phase bus ducts. In an 

isolated phase bus duct, the bus conductor for each phase is enclosed in an individual metal 

housing separated from the other adjacent conductor housings by an air space. The bus may 

be self-cooled or, more typically for the high output NPP generators, forced-cooled by circulating 

air, gas, or liquid. Because of this physical arrangement, phase-to-phase bus faults cannot 

occur unless there is catastrophic damage inflicted on the entire bus duct structure. Phase-toground faults within the bus duct are detected by main generator protective relaying, isolated 

phase bus differential relaying, and directional overcurrent relaying at the switchyard. Even with 

the isolated phase bus duct, there always a minute chance that an electrical fault could occur at 

the termination enclosures at the main generator, step-up transformer(s), and auxiliary 

transformers. The nuclear power station electrical distribution system is protected from lightning 

and transient overvoltage surges originating on the external transmission grid or the station 

switchyard by lightning arresters located at the high voltage side of the main generator output 

transformer.
27

3 ANALYTICAL APPROACH TO STUDYING THE IMPACT OF 

PROTECTION SETTINGS ON NPP RESPONSE TO AN EXTERNAL 

FAULT

3.1 Overview

The objectives of the electrical protection systems in NPPs are to: (1) detect and isolate external 

transmission grid faults as quickly as possible; (2) maintain the availability of both offsite ac 

power sources (or at least one) to the nuclear plant during the transmission system protective 

response; and (3) minimize the grid transient to the NPP to the extent that NPP protective 

relaying is not actuated resulting in a trip or any other protective action. 

It is desirable that the protection system in a NPP switchyard isolate faults as rapidly as possible 

so that the nuclear station can ride through transients caused by faults external to the NPP 

switchyard without a nuclear unit trip. It is thus suggested that protective relaying at NPP 

substations/switchyards and associated transmission lines be treated differently than 

transmission line and substation relaying on the general transmission grid because a longer 

clearing time for a fault at or near the NPP switchyard has more negative impact on the system 

operation. The protective logic and schemes proposed to achieve these objectives, which may 

differ from the basic objectives of traditional transmission system protection logic and protection 

schemes, must be constrained by the requirements of the nuclear plant operational 

requirements and the design basis accident analyses for the plant.

Transmission system equipment and substation configurations at NPP switchyards may also 

incorporate design features to improve the reliability and response time of the power system 

and the electrical protection system. These may include: dual voltage check and synchrocheck 

equipment at both ends of lines originating at the NPP substation; breaker-and-a-half or doublebus, double-breaker bus arrangements; and dual series power circuit breakers to assure rapid 

fault clearing times and improve system stability. In addition, upgrading to newer high-speed 

protection system equipment and redundant transmission system equipment and component 

configurations can also improve reliability and fault clearing times. These improvements and 

upgrades may include: redundant substation bus protection schemes; redundant high-speed 

digital transmission line protection; redundant telecommunications channels for transmission 

line protection systems; dual breaker failure protection schemes; redundant independent dc 

power control power; and redundant circuit breaker trip coils. The overall goal of these 

upgrades is to assure that, when required, the protection system will initiate a trip signal to at 

least one of the two circuit breaker trip coils within 20 ms for faults in close proximity to the NPP 

substation and within 30 ms for remote faults, even if a single element of the electrical 

protection system fails to operate [Lindahl - 2011]. 

An analytical approach is proposed in this study in order to verify the hypothesis that shortening 

the delay time of the primary and backup protection systems in the switchyard and/or the 

neighboring substations can significantly reduce the chance of NPP tripping without affecting 

the protective performance across the rest of the grid. The approach is implemented by 

evaluating the impacts of varying the settings and/or schemes of the protection systems in the 

switchyard and/or neighboring transmission network of a NPP and its responses to faults 

occurring in the switchyard or nearby transmission systems. 
28

3.2 A Generic Approach to Evaluate Impacts of Protection 

Settings/Schemes on NPP Response

3.2.1 An Event Tree Type Approach

A general approach has been proposed to perform the detailed study based on the plant models. 

An initial state is assumed for the NPP as the starting point. Subsequently, one additional 

component failure is considered each time. Availability of individual systems that are needed for 

mitigating the fault may change the impact that the event will have on NPPs and the offsite 

power system. 

A reasonable assumption for the initial state of NPPs can be a steady-state at full power 

operation without any failure. For each of the selected sets of power system components that 

are considered critical to the normal grid operation, faults may be postulated. The grid 

responses can then be evaluated under the postulated faults by considering the availability and 

settings of the required protection and control systems. The steady-state of NPP post-fault 

response directly reflects the performance of the protection/control systems.

The suggested approach is similar to the event tree (ET) method used in probabilistic risk 

assessment (PRA) and the faults and abnormal conditions are characterized by the conditions 

and events below [Lindahl 2010]:

Operating state of the power system, such as: (a) all relevant power system components 

are in service, (b) one generating unit is out of service, (c) one busbar is out of service, 

(d) one network (system) transformer is out of service, or (e) one transmission line is out 

of service.

Fault location, such as (a) generator faults, (b) generator step-up transformer faults, (c) 

busbar faults, or (e) line faults.

Fault type or failure mode of components [Lindahl, 2010], such as: (a) three-phase faults, 

(b) phase-to-phase-to-earth faults, (c) phase-to-phase faults, (d) phase-to-earth faults, 

(e) no power system fault.

Operation and failure modes of the protection system, such as: (a) correct operation of 

all elements in the protection system, (b) failure to operate of one protective relay, (c) 

failure to operate of a tele-protection channel, or (d) unwanted operation of a protection 

system.

Operation and failure modes of the circuit-breakers, such as: (a) correct operation of all 

circuit breakers, (b) failure to interrupt the fault current in all three phases, (c) failure to 

interrupt the fault current in one phase, or (d) unwanted operation of a circuit-breaker.

The approach in fact suggests that the analysis be performed in an exhaustive manner. 

Depending on the level of detail of the analysis, i.e., treating the protection system as an entity 

or decomposing the protection system further into relays, circuit breakers, and communication 

channels, etc., when considering failure modes, the analysis can be of completely different 

complexity. As can be easily seen, the branches of the event tree, i.e., the number of scenarios, 

can be expanded exponentially with consideration of more options and/or failure modes of the 

protection systems and will soon make the evaluation very different to handle. Therefore, it is 
29

necessary to limit the scenarios to be included in the study. Some engineering judgment has to 

be exercised for this purpose. The selection of contingencies should be based on: (1) 

susceptible components, (2) failure rate of the power system components, (3) properties of the 

power system components, (4) design of the protection systems, (5) the probability of failure to 

operate of protective relays, tele-protection channels, and circuit-breakers, and (6) frequency of 

unwanted operation of protective relays or circuit-breakers.

In this study, the number of scenarios that need to be included is further limited by considering 

the goal and scope of the study and a simplified generic approach is adopted. Starting from the 

normal state of an NPP, a component fault is assumed to each of the selected grid components 

(mainly the high voltage components). The conventionally equipped control systems such as,

turbine governors and power system stabilizers, are assumed available all the time but the 

major issue here is to evaluate the grid responses for different fault clearing times that are 

directly related to the protection schemes/settings. 

Therefore, the proposed approach for this study includes: (1) creation of a set of contingency 

scenarios (i.e., a fault in transient analysis), which represent the progressively degraded grid 

conditions as a result of the fault occurrence and malfunction of the associated protection relays 

of concern for the NPP normal operation; (2) performing transient simulation to obtain the grid 

responses; (3) review of the grid transient responses, especially the measurements at places 

where a degraded voltage or frequency condition or other conditions (e.g., a reverse power flow 

at a generator) might cause a reactor trip; and (4) identify and evaluate potential feasible 

changes of the protection settings that will isolate the faults more quickly and delay the reactor 

trip such that the reactor is more likely to ride-through the fault without violating the operational 

requirements in plant technical specifications. 

The implementation of the approach heavily relies on the NPP model that contains sufficient 

details to capture both the NPP onsite distribution network and the neighboring transmission 

network nearby the NPP, which will be elaborated in Section 4. The details of the approach are

further discussed in the following sections.

3.2.2 Development of Contingencies

To implement the proposed approach, the first step is to identify all the credible component 

faults that pertain to the study. As an example, the distribution of faults that occurred during a 

five-year period on the CEGB (Central Electricity Generating Board, UK) system [Lindahl-2011]

is shown in Figure 3-1, where it can be seen that more 60% of the faults are associated with 

overhead transmission lines and cables. The percentage of faults on transmission lines in the 

US should be higher because the isokeraunic level in the US is between 10 and 100 

thunderstorm-days per year while it ranges only from 5 to 10 in England and Wales[Lindahl2011] . Therefore, the faults of interest are mainly related to the transmission grid and the NPP 

switchyards, i.e., faults at high voltage levels. Faults of interest are all assumed to be 

permanent ones, i.e., the faults will persist unless being isolated by the protection systems. 

The major components include the generators, transformers, bus bars, and transmission lines. 

Each type of component may have different failure modes. A generation unit may experience a 

three-phase or a phase-to-ground fault, a loss of generation (or deletion of the generator), or a 

loss of excitation system. 

It is assumed that a generator step-up transformer consists of three single-phase transformers 

connected to the generator by means of an isolated phase bus duct. Each phase conductor is 
30

enclosed by an individual metal housing separated from adjacent conductor housings by an air 

space. This means that a three-phase fault on the generator side (or the primary side) winding 

or on the isolated phase bus duct is not a credible fault. It is assumed that phase-to-phase-toearth faults and phase-to-phase faults on the primary winding of the generator step-up 

transformer are less severe than and covered by the umbrella of a three-phase fault on the 

generator terminal. However, a three-phase fault at the secondary winding, i.e., the side of the 

switchyard, is a credible fault.

Figure 8 Distribution of faults on the CEGB system [Lindahl–2011]

A busbar and transmission line may undergo a three-phase, a single-phase-to-ground, or a 

phase-to-phase-to-ground fault. For a transmission line fault, the location of the fault may also 

be variable along the transmission line.

For a generator fault or a transformer fault on the generator side, clearing the fault always 

means that the generator has to be taken offline, which will directly lead a turbine trip and thus a 

NPP tripping event. For a transformer fault on the switchyard side, it may be considered the 

same type of faults as the switchyard busbar faults and are thus covered by the busbar fault 

scenarios to be studied. Since the purpose of this study is to study how to improve the fault ridethrough capability of a NPP, only the faults of busbars and transmission lines will be further 

studied in detailed. 

These credible component faults are considered the single contingencies that must be 

evaluated in the study.

3.2.3 Development of Simulation Scenarios

The N-1 criterion is required to be satisfied in power system design. The single contingencies 

identified in Section 3.2.2 or sometimes even double contingencies would not cause any issue 

with the grid operation provided that the associated protected systems work properly. On the 

other hand, high order failures are less likely to occur simultaneously. Therefore, the major 

challenge is a single contingency combined with the failure of the primary protection system or 
31

by the failure-to-operate of a circuit-breaker [LER 40815, AIT 05000277&278/2003013], which 

not only prolongs the fault clearing time, but also leads to disconnection of more components 

and makes the power system even weaker. Many NPP tripping events are caused by such 

combinations (see Section 1.1.3). The failure of the protection system is the major consideration 

in developing the contingency simulation scenarios for the study.

When developing simulation scenarios, typical protection relaying schemes are assumed for 

faulted transmission lines and busbars such as, distance relaying and telecommunicationsbased relaying, and will guarantee transient stability of the system upon a single contingency. 

The single contingencies are considered Type I scenarios in this study. The protection system 

failure then needs to be included in the simulation of the single contingencies, which are 

considered the Type II scenarios in this study. Based on different protection schemes, the fault 

clearing time and the extra components that have to be isolated will be different and need to be 

accounted for. As a potential improvement to the existing protection schemes, breaker failure 

protection is assumed to be available and will also be included in the simulation. The additional 

failure of the breaker failure protection scheme constitutes Type III scenarios, which basically 

assume that all the components that are immediately connected to the faulted component will 

be isolated within a certain time period determined by the protection schemes/settings.

The scenario development process indicates that the critical variables that must be considered, 

regardless of the types of component faults and protection schemes, are the fault-clearing times 

of various protective relays and circuit breakers that are determined by utility-specific practices 

and the circuit breakers that must be opened. Including these critical variables in simulation 

gives the grid responses for different types of scenarios. Accounting for these variables in 

scenario simulation is equivalent to modeling the relaying schemes and the actual settings and 

the current/voltage measurements used to detect a fault and open the circuit breakers in the 

right places.

Depending on the transmission voltage level, there are generically accepted values for faultclearing times that vary with voltage levels. Take a typical distance relaying protection scheme 

as an example: in the faulted zone, the normal relay times range from 1 to 2 cycles and circuit 

breaker times range from 2 to 4 cycles on high voltage and extra-high voltage transmission 

systems. For the Zone 2 protection that overreaches the faulted zone, their relays are generally 

set to trip after a time delay of a typical value between 0.3 and 0.5 seconds. For effective 

protection system time coordination, usually a 2.0-second-delay is set for the Zone 3 protective 

relays. Therefore, if the utility-specific protection settings are not available, the above generic 

distance relaying settings can be used in the study and the results are not expected to deviate 

too much from the protection system response that would actually occur.

For a transmission line with distance relaying scheme, Type I scenario considers just the fault 

with the correct operation of the relays and circuit breakers. The Type II scenario considers the 

additional breaker failure (failure of the breaker at the near end bus is preferred in the study 

since failure of clearing fault at near end bus has a more severe impact on the system and the 

response of the remote backup while the Type III scenario will simulate the grid responses after 

isolating of all components that are immediately connected to the faulted line after two seconds 

delay). Scenarios can be created for other types of relaying schemes of transmission lines and 

busbars. 

In order to bound the number of cases that had to be considered, the detailed evaluations 

performed in this study were limited to Type III scenarios because of the exponentially 

increasing number of scenarios and an assumption that higher order failures are much less 
32

likely to occur simultaneously. Note, Type I scenarios should not have any negative impact on 

the normal NPP operation, according to plant FSARs. Performing Type I scenarios is 

considered a part of the model validation process as well as providing the basis for 

understanding and building upon our analyses of Type II and III scenarios. 

3.3 Discussion and Remarks

Note, the proposed approach is a natural solution to the unavailability of the details of the 

utility/plant-specific settings for their protection systems across the transmission grid. It is also 

believed that, even with all of the actual settings, not every single type of power system relay 

and/or circuit breaker model is available in a particular power system simulation software. In 

addition, since we are interested in how the fault clearing time may affect the NPP responses, 

knowing all of setting information and modeling every single protective relay and/or circuit 

breaker becomes unnecessary. More importantly, sensitivity studies of the response times of 

protection relays in different zones can be and were performed. 

Since the majority of the grid-related NPP events [LER 40815, AIT 05000277&278/2003013] are 

due to combinations of a single contingency and failure of protection system relays, the first step 

of the proposed approach for each NPP that we are evaluating is to create: (a) basic single 

contingencies, Type I scenarios, i.e., a complete set of single contingency scenarios for all of 

the high-voltage level faults, which will be cleared by the primary/backup protections in the 

faulted zone according to the their settings; (b) Type II scenarios, i.e., variations of Type I 

scenarios containing the same contingencies that are not cleared by the protection systems due

to the breaker failure in the faulted zones but instead are picked up by the breaker failure 

backup protections of the immediate neighboring zones; and (c) Type III scenarios, i.e., the 

scenarios with the same single contingencies but the faults are cleared after a sufficient long 

time delay by isolating all the components that are immediately connected to the faulted 

component. For both Types II and III scenarios, additional components have to be tripped as 

well as the faulted one in the simulation.

If the settings of the time delays for protective relaying in zones that are close to the NPP 

switchyard are reduced, the impact of the faults occurring in transmission system nearby NPPs 

can be reduced. Even if one of the primary offsite power supplies has to be disconnected in 

order to isolate the fault, the alternate offsite power source may still be maintained to minimize

the chance of tripping the NPP. In this study we are proposing that in the overall approach to 

transmission system protection, NPP switchyards be considered as a special case compared to 

transmission substations located away from the NPP. 

An example is the ongoing project of refurbishing and upgrading of two NPP substations in 

Sweden [Lindahl – 2011]. A double-bus double-breaker arrangement with disconnecting circuitbreakers will be used in the two ongoing projects. This will be the standard arrangement, which 

will replace the double-bus single-breaker arrangement that was used previously, in all NPP 

substations when refurbishing, or building new, substations in Sweden. The protection system 

will be upgraded as follows:

• Dual busbar protection systems will replace single busbar protection systems

• New dual digital line protections will replace line protection systems consisting of one 

electromechanical line protection system and one static line protection system or one 

first generation digital line protection system
33

• Dual teleprotection channels will replace single (common for both Main 1 and Main 2 line 

protection system) teleprotection channels

• Dual circuit-breaker failure protections will be used

• Dual DC systems completely isolated from each other and with some degree of physical 

separation will be used as previously

• Circuit-breakers with two trip-coils will be used as previously

The philosophy is that the line protection system should issue a trip signal to at least one

of the two trip coils of the associated circuit-breaker within 20 milliseconds for close-up

faults, and within 30 milliseconds for remote faults even if one element of the protection

system fails to operate.

In general, by reducing fault clearing time at or near the NPP substation we hope to achieve a 

reduction in the number of reactor trips while reducing the number of losses of offsite power 

sources during transmission system transients. More specifically, in order to reduce the fault 

clearing times, fast response relays/breakers, telecommunications-based protective relaying, 

and breaker failure backup protection are obviously preferred. In keeping with the philosophy of 

upgrading the reliability and protection system response times at NPPs, the relatively small cost 

of including the breaker failure protection element in a modern protection system terminal is 

easily justified. For Zone 2, Zone 3, or breaker failure backup protection, time delay is 

intentionally built into the relay setting in order to coordinate with each other and with the Zone 1 

protection. To address the issue of Zone 1 protection failure, more cost-effective options could 

be: (1) a reduction in the built-in time delays in the Zone 2 relays; (2) an anticipatory trip by the 

Zone 3 relays, i.e., significantly decrease the time delay of the Zone 3 relay settings; (3) a 

shorter time delay in the breaker failure backup protection; and (4) a more comprehensive and 

rigorous maintenance program, on an optimized scheduled frequency, including rigorous 

inspection, test, calibration, etc., to reduce the failure probability of the protective devices at the 

NPP switchyards. The rationales behind the first three options is that, regardless of the issues 

of (1) the potential racing between Zone 1 and Zone 2 and Zone 3 protection and/or (2) the 

potential disconnection of more components between the NPP switchyard and the fault location, 

the impact of primary protection failure can be less severe. Even if the primary offsite power 

supply is lost due to tripping of extra components, the chance of the alternative offsite power 

supply being available could be high. Also note that an anticipatory Zone 3 trip scheme, 

depending on the settings of time delay relative to those of primary relays, does not have to trip 

more components than necessary when primary protective relays function properly. Utilities 

may be more receptive to the concept of modifying protection settings at the NPP switchyards 

for not requiring the changes to the rest of the transmission system protection schemes that are 

traditionally used by individual utilities.

The simulation tool ETAP provides the capability of simulating a large number of pre-defined 

scenarios in a batch mode, based on the fault scenario Types I, II, and III discussed previously, 

and generating reports for each scenario, as defined. The various scenarios have to be created 

manually within the simulation model as we consider the occurrences of faults at each possible 

location in the power transmission grid around the nuclear plant.

35

4 NPP MODELS AND ANALYSES

4.1 Overview

Realistic models of NPPs are needed for performing the study of the electrical responses. The 

plant models were created using ETAP software developed by Operations Technology Inc. 

(OTI) based on electrical system information from various sources including the Federal Energy 

Regulatory Commission (FERC), NPP Final Safety Analysis Reports (FSARs), plant inspection 

reports and documentation, individual plant examinations (IPEs), information obtained from the 

Internet, and other sources. A total number of three plant models, designated A, B, and C in this 

report, were created. Based on the approach proposed in Section 3, a set of Types I, II, and III 

scenarios have been defined for each of the plant models. Example results of the typical 

scenarios are shown and briefly discussed for each plant model.

The general modeling approach and assumptions that are used throughout the studies are 

discussed and an overview of modeling selected NPPs is provided in Section 4.2. Section 4.3 

focuses on defining and simulating scenarios and analyzing the simulation results. In Section 

4.3.2, the faults for both buses and lines at different distances from the NPP switchyards of the 

selected plant models are evaluated to determine the severity of their impacts. The comparison 

of grid responses to faults under different protection schemes is studied in detail in Section 4.3.2. 

Section 4.3.2.1 describes parameters for generic protection schemes including distance relaying 

(DR), distance relaying with breaker failure protection (DRBF), protective relaying using 

telecommunications (PR), and telecommunications-based breaker failure protection (PRBF). A

set of scenarios is defined for each of the three NPP plant models. The simulation results of 

these scenarios are presented in Section 4.3.2.2. An anticipatory Zone 3 protection scheme is 

evaluated in Section 4.3.2.3 by a simulation using Plant B as an example. More scenarios are 

postulated and analyzed without simulation in Section 4.3.2.4 but these analyses also provide 

important insights on how to improve the performance of NPP switchyards by identifying the 

most critical circuit breaker(s) under certain fault conditions. A preliminary study of the 

interaction between two NPP switchyards that are electrically close to each other is performed 

in Section 4.3.3. The modeling and simulation studies are summarized in Section 4.4.

4.2 ETAP Model Description of NPPs

4.2.1 Modeling Approach and Assumptions

The following general assumptions were made in modeling the NPPs for this study:

1. The scope of an NPP model includes the NPP 480V or above distribution network (both 

class 1E and non-class 1E), generators, switchyards, all offsite power supplies, 

neighboring substations and generating units (both nuclear and non-nuclear units 

nearby);

2. All 4kV or above voltage level buses and generation of an NPP are modeled in detail;

3. The onsite distribution network is modeled down to the voltage level that is immediately 

below the 4 kV buses, which could be 480 V or 600 V depending on the plant’s design.

4. All 480V (or 600 V) or below voltage level buses and the associated loads powered by a 

4kV or 13 kV bus are aggregated based on the observation that losses of these loads or 

faults at these buses do not lead to a reactor trip. Where exact loads were unknown, 

bus loading was estimated from information that was available for an equivalent plant.
36

5. All loads are grouped according to type (e.g., inductive motors or static loads);

6. In general, neighboring substations are modeled as buses that are powered by a utility 

grid except in the model that was used for studying the interaction between protection 

systems of multiple NPPs. The rest of the power system, the utility grid, is modeled as 

short-circuit capacity (steady-state basis) of utility supply [IEEE Std. 399, Brown Book];

7. Sub-transient generator models are used and the generators are assumed to be 

equipped with necessary control systems including excitation, turbine governor, and 

power system stabilizers;

8. The switchyard of a substation is assumed to be of a breaker-and-a-half configuration 

when performing transient analyses unless other bus and circuit breaker arrangement 

information is available;

9. Typical parameter values were used if system-specific information could not be 

obtained. Typical parameter values include 1) the typical short-circuit capacity of a 

220 kV utility can be between 4,000 and 10,000 MVA with an X/R ratio of 20 [IEEE Std 

399-1997, “IEEE Recommended Practice for Industrial and Commercial Power Systems 

Analysis (Brown Book)]; 2) a damping ratio of 5% [Kundur 1993]; (3) an inertia constant 

between 4 and 10 seconds for a 4-pole 1,800 rpm thermal unit, and between 2 and 4 

seconds for a hydraulic unit [Kundur 1993]; 4) the sample data for various control 

systems associated with a generator provided by ETAP; and 5) bundled 2,500 kcmil 

conductors for 230 kV cables [Seman 1995].

In general, this study used these assumptions when detailed information about the specific NPP 

distribution network and grid was not available. Aggregating the low voltage loads (and 

separating the dynamic and static loads) is a common practice in simulation studies of power 

systems. The difference in the system responses between the load aggregation and separate 

modeling of various loads is trivial based on some preliminary simulation results performed in 

this study. The breaker-and-a-half switchyard described in Section 2.2 is commonly adopted in 

NPP designs. Although the specific plant and utility grid data differ from each other, it is 

anticipated that these assumed data, based on general principles in power engineering, will not 

deviate significantly from the typical data that have been widely adopted in power industries. 

4.2.2 Overview of the NPP Models

For the Plant A model, the switchyard is of a breaker-and-a-half configuration. A portion for the 

switchyard of each of nearby NPPs (i.e., plants D and E) including one generator of each NPP 

has been modeled in order to study the interactions between switchyards of different NPPs that 

are close to each other. The two 1,450 MW generation units at Plant A are modeled in detail. 

Each generator is connected to the switchyard via two 750 MVA transformers. The generator 

also provides power supply to the onsite load during normal operation. The 4.16 kV Class 1E 

buses of each unit may also be powered from 4.16 kV Class 1E buses of the other unit. There 

are four 6.9 kV RCP pumps for each unit. Four emergency diesel generators are connected to 

four 4.16 kV buses (two for each unit). Note, the onsite distribution network and load of plants D

and E are not explicitly modeled considering the purpose of this study. The nearby substations 

are also modeled either as a switchyard or a single bus. For the substations, the neighboring 

generation units are modeled as a single generator with an aggregated generating capacity, as 

shown in Figure 4-1.
37

Plant B consists of three generation units with a capacity of 1,560 MVA each. A single 525 kV 

switchyard of a breaker-and-a-half configuration interfaces the transmission network with the 

NPP. Each generator terminal bus (24 kV) is connected to the switchyard via a main 

transformer and feeds partial onsite loads including 13.8 kV reactor coolant pumps (RCPs) via a

unit auxiliary transformer while the majority of the distribution network for a single unit is 

supplied by the offsite power system via a startup transformer connected to the switchyard. 

Note, the startup transformers can cross feed each other via bus transfer. There are a total 

number of eleven (11) 525 kV transmission lines from the neighboring substations to the Plant B

switchyard. Four generators of a total capacity of 3,130 MVA near the NPP were modeled. In 

addition, two utility grids of 230 kV and 525 kV, respectively, were modeled to power the 

neighboring substations. The detailed model of Plant B is shown in Figure 4-2.

Plant C model has two 1,112 MW generation units; each with a 500 kV switchyard of a ring-bus 

configuration, as shown in Figure 4-3. The two switchyards are cross-connected to each other. 

The majority of the non-safety related loads for each unit including two 13.8 kV RCPs are 

powered by one generation unit. In case of the generation unit tripping, a bus transfer can 

continue to power the non-safety related loads from the offsite power system via the start-up 

transformer. In general, the two offsite power supplies (one of 230 kV and another one of 500 

kV) provide the ac power source to the safety-related loads of the two units, respectively. The 

two power supplies cross-tie to each other at the secondary and tertiary windings of the startup 

transformers with the circuit breakers normally open. In case of loss of one offsite power supply, 

the safety-related loads can be cross-fed by the other one. Four 2.6 MW emergency diesel 

generators are shared by the distribution network of the two units. A total number of four 

generators including a hydro plant near the Plant C plant were included in the model. Five 500 

kV transmission lines are connected to the two switchyards from the transmission network.

All of models were created using ETAP software. The detailed parameters for all of the 

components and control systems utilized in the simulation model cannot all be shown here, 

which, in general, are typical values for the type of component/control systems that are 

extracted from manufacturers' data and provided as part of the ETAP software package. Based 

on detailed system information and data collected from various sources such as FERC and 

plant documentation, the models developed in this study are expected to be very close to the 

operating NPPs and the grid.

Note that the generator output circuit breakers shown in the model do not represent actual 

circuit breakers in the plants that are modeled. In other words, these breakers will not be 

opened in any of the simulation studies if the installation of such breakers on the specific 

generators is not confirmed. In addition, it is understood that a switchyard with breaker-and-ahalf configuration has three breakers and five disconnected switches (disconnect switches are 

not modeled in our study) per switchyard bay. In the ETAP model for this kind of switchyard, 

sometimes five breakers were modeled. The reason is that a bus must be inserted between two 

breakers in order to connect to another bus, and a bus cannot be connected without a breaker 

(or a transmission line) between them. When performing simulation, attention has been paid to 

this issue to avoid any violation.
38

Figure 9 One-line Diagram for Plant A

Bus56

525 kV

Sub6-1

525 kV

Bus62

525 kV

Bus61

525 kV

Sub6-2

525 kV

Bus63

525 kV

Bus64

525 kV

Bus59

525 kV

Bus58

525 kV

Bus57

525 kV

Bus65

24 kV

Bus71

6.9 kV 1TA

6.9 kV

CB190

1ATC 7.5 MVA

CB225

CB203

RCP1A

9000 HP

CB191

Lump18

0.75 MVA

CB294

CB148

Open

BOPMotors11

5000 HP

CB288

Lump19

0.75 MVA

T35 1.5 MVA

CB204

CB117

T13 1200 MVA

Gen8

1180 MW

T43 1200 MVA

CB119

CB120

CB122

CB124

CB130

CB131

CB129 CB125

CB127

Woodleaf

5000 MVAsc

CB136

CB128 CB115

Sub6-1

525 kV

Bus62

525 kV

CB128

CB127

Bus61

525 kV

CB125

Sub6-2

525 kV

Bus56

525 kV

CB115

CB117

Bus57

525 kV

CB119

CB122

Bus58

525 kV

CB120

CB124

Bus59

525 kV

Bus64

CB131

525 kV

CB130

CB129

Bus63

525 kV

Gen8

1180 MW

T13 1200 MVA

Bus65

24 kV

Woodleaf

5000 MVAsc

CB136

Bus67

24 kV

1TA

6.9 kV Bus716.9 kV

CB148

Open

1ATC 7.5 MVA

RCP1A

9000 HP

CB190 CB191

CB203 CB204

CB225

BOPMotors11

5000 HP

CB288 CB294

Lump18

0.75 MVA

Lump19

0.75 MVA

T35 1.5 MVA

T43 1200 MVA

1ETA

4.16 kV

1ELXA

0.6 kV

Bus88

0.6 kV

1ELXC

0.6 kV

Bus84

4.16 kV

1FTA

4.16 kV

CB160

Open

Lump4

0.1 MVA

CB200

Mtr9

500 HP

CB186

Open

CB159

CB157 CB156

CB158

Lump1

0.1 MVA

Mtr12

365 HP

CB167

T22

1.5 MVA

CB169

Lump2

0.1 MVA

CB168

T21

1.5 MVA

Mtr13

365 HP

CB315

Open

CB314

Open

T20

1.5 MVA

CB166

EDG1

8.7 MW

CB172

Open

Mtr1

5000 HP

CB185

Open

CB265

Open

Bus84

4.16 kV

1ETA

4.16 kV 1FTA4.16 kV

CB156 CB157

CB158 CB159

CB160

Open

T20

1.5 MVA

1ELXA

0.6 kV

Lump1

0.1 MVA

1ELXC

0.6 kV

Lump2

0.1 MVA

T21

1.5 MVA

T22

1.5 MVA

Bus88

0.6 kV

CB166 CB167 CB168

CB169 Lump4

0.1 MVA

EDG1

8.7 MW

CB172

Open

Mtr1

5000 HP Mtr9

500 HP

CB185

Open

CB186

Open

Mtr12

365 HP Mtr13365 HP

CB200

CB265

Open

CB314

Open

CB315

Open

Bus98

Bus73

6.9 kV

Bus26

22 kV

Bus86

13.8 kV

Bus7

230 kV

SWYDBus-2

230 kV

SWYDBus-1

230 kV

Bus3

230 kV

Bus4

230 kV

Bus14

230 kV

Bus13

230 kV

Bus15

230 kV

Bus16

230 kV

Bus6

230 kV

Bus37

230 kV

Sub1-1 230 kV Bus32

230 kV Bus33

230 kV

Sub1-2

230 kV

Bus38

230 kV

Bus20

525 kV

Bus66

525 kV

Bus46

525 kV

Sub7-1

525 kV

Bus42

525 kV

Bus43

525 kV

Sub7-2 525 kV

Bus47

525 kV

Bus50

24 kV

Bus48

525 kV

Bus45

525 kV

GenBus1

24 kV

GenBus2

24 kV

Bus39230 kV

Bus8

230 kV

Bus36

230 kV

Bus34

230 kV Bus35

230 kV

Bus5

230 kV

Bus25

22 kV

Bus75

1TB

6.9 kV Bus766.9 kV 1TD

6.9 kV

Bus100

bus74

6.9 kV 2TA

6.9 kV

Bus27

22 kV

Bus10

230 kV

Bus9

230 kV

Sub2

230 kV

Bus12

230 kV

Bus11

230 kV

Bus79

6.9 kV

Bus101

2TB

6.9 kV

Bus29

22 kV

1TC

6.9 kV

Bus99

Bus24

22 kV

Lump22

1.5 MVA

CB5

Unit1

1450 MW

CB71 CB66

CB68

CB149

Open

Lump20

0.75 MVA

CB194

RCP1B

9000 HP

CB193

CB210

CB70

CB208

Lump34

1.75 MVA

T37

3.5 MVA

BOPMotors13

5000 HP

CB321

CB150

Open

RCP1C

9000 HP

CB195

CB11

CB10 CB13

CB14

Unit2

1450 MW

CB76

CB214

RCP2B

9000 HP

CB269 CB274

CB74

CB152

Open

Lump36

0.75 MVA

T39 1.5 MVA

BOPMotors21

5000 HP

CB318

CB213

2T2B

70/35/35 MVA

CB28

CB15

U1

5000 MVAsc

CB27

CB12

T10-2A 750 MVA

CB73

CB75

2T2A

70/35/35 MVA

CB212

RCP2A

9000 HP

CB247

Lump25

0.75 MVA

CB248 CB230

T8 7.5 MVA

CB231

CB291

CB207

1T1A

70/35/35 MVA

CB209

Lump35

1.5 MVA

T38 3 MVA

BOPMotors14

5000 HP

CB322

CB151

Open

RCP1D

9000 HP

CB198 CB289

1ATD

7.5 MVA

CB290

CB205

1T2A

70/35/35 MVA 1T2B70/35/35 MVA

CB67

CB64

T4-1B 750 MVA

CB6

CB88

CB87 CB86

CB91 CB90

CB95

CB7

CB9

CB97

Gen7

730 MW

T10

800 MVA

CB105

Gen6

1772.6 MW

T5

1800 MVA

CB104

CB107

CB47

CB108

Gen5

886.3 MW

T4

900 MVA

CB106 CB102

5000 MVAsc

GeorgiaPower

CB100

CB101

CB113

CB103

CB306

CB134

Gen9

1180 MW

T17

1200 MVA

CB46

CB45

T2

1000 MVA

CB96

Line16

CB84 CB83

CB82

CB89

CB4

CB17

CB19

CB20

CB21 CB18

CB16 CB1

CB2

CB3 CB8

T5-1A

750 MVA

CB65

Lump16

20 MVA

CB211

1ATE

45 MVA

CB69

1T1B

70/35/35 MVA

CB206

BOPMotors12

5000 HP

CB319 T36 3 MVA

Bus98

Bus75

Bus24

22 kV

SWYDBus-1

230 kV

Bus3

230 kV

SWYDBus-2

230 kV

Bus4

230 kV

CB1

CB2

CB3

Bus6

230 kV

Bus5

230 kV

CB4

CB6

CB5

Bus8

230 kV

Bus7

230 kV

CB7

CB9

CB8

Bus10

230 kV

CB10

Bus9

230 kV

CB12

CB11

Bus12

230 kV

Bus11

230 kV

CB13

CB15

CB14

CB16

Bus14

230 kV

Bus13

230 kV

CB18

CB17

Bus16

230 kV

Bus15

230 kV

CB19

CB21

CB20

Sub2

230 kV

CB27 CB28

U1 5000 MVAsc Sub1-1 230 kV

Line16

Bus20

525 kV

T2

1000 MVA CB45

CB46

CB47

T4-1B 750 MVA T5-1A

750 MVA

Unit1

1450 MW

CB64 CB65

1T2B

70/35/35 MVA

Bus25

22 kV

CB66

CB67

1T2A

70/35/35 MVA

CB68

1T1B

70/35/35 MVA

CB69

1T1A

70/35/35 MVA

CB70

Bus26

22 kV

CB71

Bus29

22 kV T10-2A 750 MVA

Unit2

1450 MW

CB73

2T2B

70/35/35 MVA

Bus27

22 kV

CB76

CB74

2T2A

70/35/35 MVA

CB75

Sub1-2

230 kV

CB82

CB83 CB84

Bus32

230 kV Bus33

230 kV

CB88

CB87 CB86

Bus35

230 kV

Bus34

230 kV

CB89

Bus37

230 kV

Bus36

230 kV CB91 CB90

Bus39230 kV

Bus38

230 kV

CB95

CB97

CB96

Sub7-1

525 kV

Bus42

525 kV

CB100

CB101

Bus43

525 kV

CB102

Sub7-2 525 kV

Bus46

525 kV

CB103

CB105

Bus45

525 kV

CB104

CB108

Bus48

525 kV

CB107

Bus47

CB106

525 kV

Gen5

886.3 MW

T4

900 MVA

Bus50

24 kV

5000 MVAsc

GeorgiaPower

Gen6

1772.6 MW

T5

1800 MVA

GenBus1

24 kV

T10

800 MVA

Gen7

730 MW

GenBus2

24 kV

CB113

Bus66

525 kV

CB134

Gen9

1180 MW

T17

1200 MVA

1TB

6.9 kV Bus736.9 kV bus74

6.9 kV 1TC6.9 kV Bus766.9 kV 1TD6.9 kV 2TA6.9 kV Bus796.9 kV 2TB6.9 kV

CB149

Open

CB150

Open

CB151

Open CB152

Open

CB153

1ATD

7.5 MVA

1ATE

45 MVA

Bus86

13.8 kV

RCP1B

9000 HP

RCP1C

9000 HP RCP1D

9000 HP

CB193 CB194 CB195 CB198

CB205 CB206 CB207 CB208 CB209 CB210 CB211 CB212 CB213 CB214

T8 7.5 MVA

RCP2A

9000 HP

CB230 CB247 CB248

CB231

RCP2B

9000 HP

CB269 CB270 CB274

Lump16

20 MVA

CB289 CB290 CB291

Lump20

0.75 MVA

Lump22

1.5 MVA

Lump25

0.75 MVA

CB306

T36 3 MVA T37

3.5 MVA

Lump34

1.75 MVA

Bus99

T38 3 MVA

Bus100

Lump35

1.5 MVA

T39 1.5 MVA

Bus101

Lump36

0.75 MVA

BOPMotors21

5000 HP

CB318

BOPMotors12

5000 HP

CB319

BOPMotors13

5000 HP

CB321

BOPMotors14

5000 HP

CB322

Bus44

6.9 kV

Bus31

4.16 kV

1ETB

4.16 kV

Bus94

0.6 kV

Bus93

0.6 kV

Bus92

0.6 kV

Bus87

4.16 kV

1FTB

4.16 kV

Bus72

6.9 kV

Bus21

4.16 kV

2ETA

4.16 kV

Bus70

0.6 kV

Bus60

0.6 kV

Bus51

0.6 kV

Bus74

4.16 kV

2FTA

4.16 kV

CB223 CB227

CB236

Open

Lump10

0.1 MVA

CB234

Open

Mtr16

500 HP

CB235

Open

CB233

CB232 CB246

CB245

Lump11

0.1 MVA

Mtr18

365 HP

CB237

T9

1.5 MVA

CB238

Lump12

0.1 MVA

CB239

T11

1.5 MVA

Mtr17

365 HP

CB311

Open

CB310

Open

T12

1.5 MVA

CB242

EDG3

8.7 MW

CB243

Open

Mtr19

3000 HP

CB244

Open

CB267

Open

CB224

CB222

T6 7.5 MVA

CB221

CB202

CB163

Open

Lump9

0.1 MVA

CB188

Open

Mtr11

500 HP

CB189

Open

CB162

CB161 CB165

CB164

Lump7

0.1 MVA

Mtr14

365 HP

CB180

T27 1.5 MVA

CB181

Lump8

0.1 MVA

CB182

T28

1.5 MVA

Mtr15

365 HP

CB309

Open

CB308

Open

T29

1.5 MVA

CB179

Mtr3

5000 HP

CB187

Open

EDG2

8.7 MW

CB201

Open

CB266

Open

CB226

CB228

T7 7.5 MVA

CB229

Bus87

4.16 kV

1ETB

4.16 kV 1FTB4.16 kV

CB165 CB161

CB164 CB162

CB163

Open

T29

1.5 MVA

Bus94

0.6 kV

Lump7

0.1 MVA

Bus92

0.6 kV

Lump8

0.1 MVA

T28

1.5 MVA

T27 1.5 MVA

Bus93

0.6 kV

CB179 CB180 CB182

CB181 Mtr3

5000 HP Lump9

0.1 MVA

CB187

Open

CB188

Open

Mtr11

500 HP

CB189

Open

Mtr14

365 HP Mtr15365 HP

CB201

Open

EDG2

8.7 MW

CB202

T6 7.5 MVA

CB221

Bus21

4.16 kV

CB222

CB223 CB224

CB229 T7 7.5 MVA

CB228

Bus31

4.16 kV

CB226 CB227

Bus74

4.16 kV

2ETA

4.16 kV 2FTA4.16 kV

CB246 CB232

CB245 CB233 CB236

Open

T12

1.5 MVA

Bus70

0.6 kV

Lump11

0.1 MVA

Bus51

0.6 kV

Lump12

0.1 MVA

T11

1.5 MVA

T9

1.5 MVA

Bus60

0.6 kV

CB242 CB237 CB239

CB238 Lump10

0.1 MVA

EDG3

8.7 MW

CB243

Open

Mtr19

3000 HP Mtr16

500 HP

CB244

Open

CB235

Open

Mtr18

365 HP Mtr17

365 HP

CB234

Open

CB266

Open

CB267

Open

Bus44

6.9 kV Bus72

6.9 kV

CB308

Open

CB309

Open

CB310

Open

CB311

Open

Sub5

230 kV

Sub4

230 kV

Bus18

230 kV

Bus17

230 kV

Sub3

230 kV

Bus28

22 kV

Bus82

6.9 kV 2TC6.9 kV

Bus103

Bus81

6.9 kV

Bus102

CB81

Lump33

0.75 MVA

Open

Lump37

1.5 MVA

T40 3 MVA

BOPMotors22

5000 HP

CB320

CB215

CB80

CB216

Lump3

1.75 MV

T41 3.5 MVA

BOPMotors23

5000 HP

CB323

CB154

Open

RCP2C

9000 HP

CB275 CB277

CB217

2T1A

70/35/35 MVA

2T1B

70/35/35 MVA

CB79

CB78

T13-2B

750 MVA

CB54

T3

800 MVA CB61 CB56

U2

5000 MVAsc CB57

CB55

CB139

T18

1500 

CB142 CB143

U3

5000 MVAsc CB144

CB22

CB23

CB33

CB24

CB30 Sub1-2 CB147Open

CB34

CB35

CB140

Bus18

230 kV

Bus17

230 kV

CB22

CB24

CB23

Sub4

230 kV

CB30

CB33 CB34

CB35

Sub1-2

Sub3

230 kV

CB54

CB55

CB57

CB56

T3

800 MVA CB61

U2

5000 MVAsc

T13-2B

750 MVA

CB78

2T1B

70/35/35 MVA

CB79

2T1A

70/35/35 MVA

CB80

Bus28

22 kV

CB81

Sub5

230 kV

CB139

CB140

CB144

CB143

T18

1500 

CB142

U3

5000 MVAsc

CB147Open

Bus81

6.9 kV Bus826.9 kV 

2TC

6.9 kV

Open

CB154

Open

CB215 CB216 CB217 

RCP2C

9000 HP

CB275 CB277

Lump33

0.75 MVA

Lump37

1.5 MVA

T40 3 MVA

Bus102

T41 3.5 MVA

Bus103

Lump3

1.75 MV

BOPMotors22

5000 HP

CB320

BOPMotors23

5000 HP

CB323

2ETB

4.16 kV

ED

8.

Open2ETB

4.16 kV 

Open

ED

8.
39

Figure 10 One-line Diagram for Plant B

AE-NAN-S07

13.8 kV

o

Bus88

525 kV

EB

525 kV

Bus77525 kV

Bus80

525 kV

WB

525 kV

Bus81

525 kV

Bus76

525 kV

o

o o

Bus78

525 kV o o

Bus93

525 kV

Bus92

525 kV

o

o

2E-NAN-S01

13.8 kV

Bus111

0.48 kV

2E-NAN-S03

13.8 kV

Bus132

4.16 kV

2E-PBA-S03 4.16 kV

2E-NAN-S05

13.8 kV

Bus137

13.8 kVo Bus82

o

o

Bus139 13.8 kV

1E-NAN-S05

13.8 kV

o

Bus85

525 kV

Bus84

525 kV

o o

Bus106

525 kV

Bus107

525 kV

o

1E-NAN-S03

13.8 kV 1E-NAN-S01

13.8 kV

Bus100 0.48 kV o o

o

o

o

o

1E-NAN-S02

13.8 kV

Bus108 0.48 kV

o

1E-NAN-S04

13.8 kV

1E-NAN-S06

13.8 kV

Bus115

4.16 kV

1E-PBB-S04

4.16 kV

Bus116

4.16 kV

1E-PBA-S03 4.16 kV

1E-NBN-S02 4.16 kV

o

1E-NBN-S01 4.16 kV

o

Bus112

24 kV

o

o

o

Bus15 o

Bus87

525 kV

o

Bus91

525 kV

Bus90

525 kV

o o

o

Bus119

4.16 kV

o

Bus110

525 kV

Bus109 525 kV

o

o

o o

CB942

LineFuture1

Line9

CB9108

Line11

CB9105

CB9102

Line10

CB932

CB938

CB431

2E-NBN-X01

15 MVA

CB432

CB922

Line13

CB925

CB928

Line7

CB660

Load14

1 MVA

Load15

1 MVA Load16

1 MVA

CB915

CB918

Line6

CB657

87

CB392 1E-MAN-X01

1533 MVA

CB653

G31

1403.19 MW

32

CB654

DisconnectionLink1

CB378

1E-NBN-X01

15 MVA

CB380

Mtr140

4030 HP

O CR

CB535

27/ 59

CB384 Open

Mtr141

4030 HP

O CR

27/ 59

CB536

CB381

1E-NBN-X02

15 MVA

CB379 CB360

1E-NBN-X03

10 MVA

CB539

CB390

Open

1E-PEA-G01 5.5 MW

CB398

Open

CB400 CB401 CB402 CB580

27/ 59

Open

CB359 CB391

Open

1E-PEB-G02 5.5 MW

CB399

Open

CB406 CB408 CB410 CB581

Open

27/ 59

CB388

CB544

1E-NBN-X04

10 MVA

CB389

AE-NAN-W01B

CB395

Open

Load17

1 MVA Load18

3.5 MVA

Load19

1 MVA

Load20

1 MVA

CB429

CB394

CB383

Open

Mtr182

25400 HP

O CR O CR

CB608

Lump104

5 MVA Mtr193

250 HP

CB626

T70

15 MVA

CB387

CB625

27/ 59 27/ 59

87 CB549

1E-MAN-X02

140/70/70 MVA

27/ 59 27/ 59

CB386

Mtr180

25400 HP

O CR O CR

CB606

Lump98

5 MVA

O CR

Mtr187

250 HP

O CR

27/ 59

CB614

T58

15 MVA

CB613 CB357

Open AE-NAN-S07

CB424

CB397

[CL1]

CB998

CB992

Line15

CB995

Line24

CB988

CB982

Line16

CB985

CB428 CB396

Open

AE-NAN-W01A

CB639

87

CB393

AE-NAN-X01

84/42/42 MVA

CB640

CB449

CB448

CB450

Open

CB445

Open

2E-PEA-G01

5.6 MW

CB461

Open

CB466 CB463 CB465 CB582

Open

27/ 59

CB460

CB545

2E-NBN-X03

10 MVA

CB459

CB458

AE-NAN-S07

CB457

Open

Lump105

5 MVA Mtr194

250 HP

27/ 59

CB628

T71

15 MVA

CB456

CB627

27/ 59 27/ 59

G21

1403.19 MW

32

CB661 Line8

CB935

Line14

CB972

CB650

CB975

Line17

Line18

CB945

CB948 CB908

CB905

CB902 CB912

Line12

1E-NAN-S05[CL1]

A-E-NEN-G01A

3.5 MW

CB426

Open

A-E-NEN-G01B

3.4 MW

CB427

Open

2E-NAN-S03

CB468

Open

3E-MAN-S03

CB503

Open CB425 Open

1E-NAN-S03

27/ 59

Bus82

Bus15

Bus112

24 kV

EB

525 kV

WB

525 kV

CB902

CB905

CB942

CB945

CB948

CB972

CB975

Bus77525 kV

Bus76

525 kV

Bus78

525 kV

Bus80

525 kV

Bus81

525 kV

CB908

CB982

CB985

CB988

Bus84

525 kV

Bus85

525 kV

CB912

CB915

CB918

Bus88

525 kV

Bus87

525 kV

CB922

Bus91

525 kV

Bus90

525 kV

CB925

CB928

CB932

Bus93

525 kV

Bus92

525 kV

CB935

CB938

CB992

CB995

CB998

Bus107

525 kV

Bus106

525 kV

CB9102

CB9105

CB9108

Bus110

525 kV

Bus109 525 kV

1E-MAN-X01

1533 MVA

1E-MAN-X02

140/70/70 MVA

1E-NAN-S01

13.8 kV

1E-NAN-S03

13.8 kV

CB357

Open

1E-NBN-X03

10 MVA

1E-PBA-S03 4.16 kV

CB359

CB360

1E-NAN-S02

13.8 kV 1E-NAN-S0413.8 kV

1E-NBN-X01

15 MVA

1E-NBN-X02

15 MVA

1E-NBN-S01 4.16 kV

CB378 CB379

CB380 CB381

1E-NBN-S02 4.16 kV

CB383

Open

CB384 Open

CB386

CB387

1E-NBN-X04

10 MVA

1E-PBB-S04

4.16 kV

CB389

CB388 CB390

Open

Bus115

4.16 kV Bus116

4.16 kV

CB391

Open

AE-NAN-X01

84/42/42 MVA CB392

CB393

1E-NAN-S06

13.8 kV

CB394

CB395

Open 1E-NAN-S05

13.8 kV

CB396

Open

AE-NAN-W01A AE-NAN-W01B

Load14

1 MVA

Load15

1 MVA Load16

1 MVA

CB397

[CL1]

1E-NAN-S05[CL1] Load17

1 MVA Load18

3.5 MVA

1E-PEA-G01 5.5 MW

CB398

Open

1E-PEB-G02 5.5 MW

CB399

Open

CB400 CB401 CB402 CB406 CB408 CB410

DisconnectionLink1

AE-NAN-S07

1E-NAN-S03

CB424

AE-NAN-S07

13.8 kV

A-E-NEN-G01A

3.5 MW A-E-NEN-G01B

3.4 MW

CB425 Open

CB426

Open

CB427

Open

Load19

1 MVA

Load20

1 MVA

CB428 CB429

2E-NAN-S01

13.8 kV

2E-NAN-S03

13.8 kV

CB457

Open

2E-NBN-X03

10 MVA

2E-PBA-S03 4.16 kV

CB460

CB459

Bus119

4.16 kV

CB456

CB445

Open

Bus132

4.16 kV

CB450

Open

CB448

2E-PEA-G01

5.6 MW

CB461

Open

CB466 CB463 CB465

CB458

CB449

Bus137

13.8 kV Bus139 13.8 kV

AE-NAN-S07

2E-NAN-S03

CB468

Open

2E-NAN-S05

13.8 kV

3E-MAN-S03

LineFuture1

CB503

Open

G21

1403.19 MW G311403.19 MW

Line9

Line10

Line11

Line12

Line13

Line14

Line15

Line16

Line17

Line18

Mtr140

4030 HP

CB535

Mtr141

4030 HP

CB536 CB539

CB540

CB544 CB545

CB549

CB580 CB581 CB582

Line6 Line7

Line8

Line24

Mtr180

25400 HP

CB606 CB608

Mtr182

25400 HP

T58

15 MVA

CB613

CB614 Bus100 0.48 kV

Lump98

5 MVA Mtr187

250 HP

T70

15 MVA

CB625

CB626 Bus108 0.48 kV

Lump104

5 MVA Mtr193

250 HP

CB628

Lump105

5 MVA Mtr194

250 HP

Bus111

0.48 kV

CB627

T71

15 MVA

CB639 CB640

CB650

CB653 CB654

CB657

CB660

CB661

2E-PGA-L35 0.48 kV 2E-PGA-L33 0.48 kV 2E-PGA-L31 0.48 kV

1E-PGB-L32

0.48 kV 1E-PGB-L34 0.48 kV 1E-PGB-L36 0.48 kV 1E-PGA-L35 0.48 kV 1E-PGA-L33 0.48 kV 1E-PGA-L31 0.48 kV

Lump80

0.5 MVA

CB358

Open

Mtr122

250 HP

CB362

CB403

T44

750 kVA

Lump81

0.5 MVA

CB364

Open

Mtr123

250 HP

CB366

CB404

T45

750 kVA

Lump82

0.5 MVA

CB368

Open

Mtr124

250 HP

CB370

CB405

T46

750 kVA

Mtr174

1500 HP

Lump83

0.5 MVA

CB374

Open

Mtr125

250 HP

CB375

CB407

T47

750 kVA

Lump84

0.5 MVA

CB376

Open

Mtr126

250 HP

CB377

CB409

T48

750 kVA

Lump85

0.5 MVA

CB382

Open

Mtr127

250 HP

CB385

CB411

T49

750 kVA

Mtr175

1500 HP

Mtr128

250 HP

CB511

Lump86

0.1 MVA

CB510

CB467

Open

T62

750 kVA

Lump87

0.1 MVA

CB512

Open

Mtr129

250 HP

CB513

CB462

T60

750 kVA

Lump88

0.1 MVA

CB514

Open

Mtr130

250 HP

CB515

CB464

T61

750 kVA

Mtr176

1500 HP

1E-PGA-L31 0.48 kV

T44

750 kVA

T45

750 kVA

T46

750 kVA

CB403

1E-PGA-L33 0.48 kV

CB404

1E-PGA-L35 0.48 kV

CB405

1E-PGB-L36 0.48 kV

T47

750 kVA

T48

750 kVA

T49

750 kVA

CB407

1E-PGB-L34 0.48 kV

CB409

1E-PGB-L32

0.48 kV

CB411

2E-PGA-L31 0.48 kV

T62

750 kVA

T60

750 kVA

T61

750 kVA

CB467

2E-PGA-L33 0.48 kV

CB462

2E-PGA-L35 0.48 kV

CB464

Lump80

0.5 MVA

Mtr122

250 HP

CB358

Open

CB362

Lump81

0.5 MVA

Mtr123

250 HP

CB364

Open

CB366

Lump82

0.5 MVA

Mtr124

250 HP

CB368

Open

CB370

Lump83

0.5 MVA

CB374

Open

CB375

Mtr125

250 HP

Lump84

0.5 MVA

CB376

Open

CB377

Mtr126

250 HP

Lump85

0.5 MVA

CB382

Open

CB385

Mtr127

250 HP

Lump86

0.1 MVA

CB511 CB510

Open

Mtr128

250 HP

Lump87

0.1 MVA

CB512

Open

CB513

Mtr129

250 HP

Lump88

0.1 MVA

CB514

Open

CB515

Mtr130

250 HP

Mtr174

1500 HP

Open

Mtr175

1500 HP

Open

Mtr176

1500 HP

Open

Bus148

Sub2

525 kV

o

o

Sub5

525 kV

o

o

Sub3 525 kV

Bus94 o

o

Bus118

24 kV

o

o

o

Bus125

4.16 kV

2E-NAN-S04

13.8 kV

2E-NAN-S06

13.8 kV

Bus140

13.8 kVo

o

o

Bus138

13.8 kV 

3E-NAN-S05

13.8 kV

3E-MAN-S03

13.8 kV 3E-NAN-S01

13.8 kV

Bus117 0.48 kV

o

Bus135

4.16 kV

3E-PBA-S03 4.16 kV

3E-NBN-S01

4.16 kV

o

Bus

24 

o

Bus96

Sub4 525 kV

Bus95

2E-NAN-S02

13.8 kV

Bus113 0.48 kV

o

o

Bus120 4.16 kV

o o

2E-PBB-S04

4.16 kV

Sub1

525 kV

o

o

Bus143 230 kV

Sub6

230 kV

Bus142

Sub11 230 kV

Sub10 230 kV Bus147

Sub9 230 kV Bus146

Sub8 230 kV Bus145

Sub7 230 kV

Bus144

CB589

T76 3000 MVA

CB670 Line25 CB588 CB587

CB586

CB593

T77

3000 MVA

CB671 Line26 CB592 CB591

CB590

CB597

T78

3000 MVA

CB672 Line27 CB596 CB595

CB594

CB601

T79

3000 MVA

CB673 Line28 CB600 CB599

CB598

CB674 Line29 CB604 CB603

CB602

U12

10000 MV

CB668

CB497 CB496 Line2 CB669

T75 3000 MVA

CB372

CB369

CB367

CB365

CB363 CB371

CB436

Open

2E-PEB-G02 5.5 MW

CB437

Open

CB439 CB441 CB443 CB583

Open

27/ 59

CB444

Mtr142

4030 HP

27/ 59

O CR

CB433

Open

Mtr143

4030 HP

O CR

CB541

27/ 59

CB434

2E-NBN-X02

15 MVA

CB435

87

27/ 59 27/ 59

CB455

Mtr184

25400 HP

O CR O CR

CB610

Lump106

5 MVA Mtr195

250 HP

27/ 59

CB630

T72

15 MVA

CB629 CB454

Open

Line22

CB662

CB332

CB352 CB353

CB328

Line23 CB663

G11

1403.19 MW

32

C

CB316

3E-N

15 M

CB318

Mtr144

4030 HP

O CR

CB542

27/ 59

CB487

3E-NBN-S03

10 MVA

CB547

CB473

Open

3E-PEA-G01

5.5 MW

CB489

Open

CB494 CB491 CB493 CB584

Open

27/ 59

CB488 

27/ 59 27/ 59

CB484

Mt

254

Lump107

5 MVA Mtr196

250 HP

27/ 59

CB632

T73

15 MVA

CB631 CB485

Open AE-NAN-S07

CB486

CB476

[CL3]

CB477 CB478

Open

CB452

SW5

CB641

87

CB447

AE-NAN-X02

84/42/42 MVA

CB642

SW6

CB451 Open

CB453

CB446

2E-NBN-X04

10 MVA

CB546

Mtr183

25400 HP

O CR O CR

CB609

2E-MAN-X02

140/70/70 MVA

CB552

SW4

CB656 CB655

87

2E-MAN-X01

1533 MVA

CB430

CB356

CB355 

CB373

CB354

Line19 CB504

Line20 CB507

Line21 CB508

Line30 CB649

CB334

CB361

CB605

T80

3000 MVA

3E-NAN-S05[CL3]

Bus148

Bus147

Bus146

Bus144

Bus145

Bus143

Bus96

Bus95 Bus94

Sub4 525 kV

CB328

CB332

CB334

CB369

CB367

CB365

CB363

CB361

Sub1

525 kV

CB371

Sub2

525 kV

CB372

Sub5

525 kV

CB373

Sub3 525 kV CB356

CB355

CB354

CB353 CB352

Bus118

24 kV

2E-MAN-X01

1533 MVA

2E-MAN-X02

140/70/70 MVA

2E-NAN-S02

13.8 kV 2E-NAN-S0413.8 kV

2E-NBN-X01

15 MVA

2E-NBN-X02

15 MVA

CB431 CB435

CB432

CB434

Bus120 4.16 kV

CB454

Open

CB433

Open

CB455

2E-NBN-X04

10 MVA

2E-PBB-S04

4.16 kV

CB444

CB446

Bus125

4.16 kV

CB436

Open

AE-NAN-X02

84/42/42 MVA

CB430

CB447

2E-NAN-S06

13.8 kV

CB453

CB451 Open

SW5 SW6

2E-PEB-G02 5.5 MW

CB437

Open

CB439 CB441 CB443

SW4

CB452

Bus138

13.8 kV Bus140

13.8 kV

Bus

24 

G11

1403.19 MW

3E-NAN-S01

13.8 kV

3E-MAN-S03

13.8 kV

CB485

Open

3E-NBN-S03

10 MVA

3E-PBA-S03 4.16 kV

CB488

CB487

3E-N

15 M

3E-NBN-S01

4.16 kV

CB316 

CB318 

CB484 

CB473

Open

Bus135

4.16 kV

3E-NAN-S05

13.8 kV

CB478

Open

CB476

[CL3]

3E-NAN-S05[CL3]

3E-PEA-G01

5.5 MW

CB489

Open

CB494 CB491 CB493 

CB486

CB477 

AE-NAN-S07

CB496

230 kV

Sub6

CB497

CB504 

CB507 

CB508

Line19

Line20

Line21

Mtr142

4030 HP Mtr143

4030 HP

CB541

Mtr144

4030 HP

CB542

CB546

CB547 

CB552

Line2

CB583 CB584 

Line22

Line23

CB589 CB588

Sub7 230 kV

CB587

CB586

Line25

CB593 CB592 CB591

CB590

Line26

Sub8 230 kV

CB597 CB596 CB595

CB594

Line27

Sub9 230 kV

Line28 CB601 CB600 CB599

CB598 Sub10 230 kV

CB605 CB604 CB603

CB602

Line29

Sub11 230 kV

Mtr183

25400 HP

CB609

Mtr184

25400 HP

CB610

Mt

254

Lump106

5 MVA Mtr195

250 HP

Bus113 0.48 kV

CB629

CB630

T72

15 MVA T73

15 MVA

Mtr196

250 HP

Bus117 0.48 kV

CB631

CB632

Lump107

5 MVA 

CB641 CB642 

CB649 Line30 

CB655 CB656 

C

CB662

CB663

T75 3000 MVA CB668

230 kV

Bus142

U12

10000 MV

T76 3000 MVA

T77

3000 MVA

T78

3000 MVA

T79

3000 MVA

T80

3000 MVA

CB669

CB670

CB671

CB672

CB673

CB674

3E-PGA-L35 0.48 kV 3E-PGA-L33 0.48 kV 3E-PGB-L31 0.48 kV

2E-PGB-L32

0.48 kV 2E-PGB-L34 0.48 kV 2E-PGB-L36 0.48 kV

Mtr131

250 HP

CB517

Lump89

0.1 MVA

CB516

CB438

Open

T53

750 kVA

Lump90

0.1 MVA

CB518

Open

Mtr132

250 HP

CB519

CB440

T54

750 kVA

Lump91

0.1 MVA

CB520

Open

Mtr133

250 HP

CB521

CB442

T55

750 kVA

Mtr177

1500 HP

Lump92

0.1 MVA

CB522

Open

Mtr134

250 HP

CB523

CB495

T66

750 kVA

Lump93

0.1 MVA

CB524

Open

Mtr135

250 HP

CB525

CB490

T64

750 kVA

Lump94

0.1 MVA

CB526

Open

Mtr136

250 HP

CB527

CB492

T65

750 kVA

Mtr178

1500 HP

2E-PGB-L36 0.48 kV

T53

750 kVA

T54

750 kVA

T55

750 kVA

CB438

2E-PGB-L34 0.48 kV

CB440

2E-PGB-L32

0.48 kV

CB442

3E-PGB-L31 0.48 kV

T66

750 kVA

T64

750 kVA

T65

750 kVA

CB495

3E-PGA-L33 0.48 kV

CB490

3E-PGA-L35 0.48 kV

CB492

Lump89

0.1 MVA

Mtr131

250 HP

CB517 CB516

Open

Lump90

0.1 MVA

Mtr132

250 HP

CB518

Open

CB519

Lump91

0.1 MVA

Mtr133

250 HP

CB520

Open

CB521

Lump92

0.1 MVA

Mtr134

250 HP

CB522

Open

CB523

Lump93

0.1 MVA

Mtr135

250 HP

CB524

Open

CB525

Lump94

0.1 MVA

Mtr136

250 HP

CB526

Open

CB527

Open

Mtr177

1500 HP

Mtr178

1500 HP

Open 
40

Figure 11 One-line Diagram for Plant C

Bus31

Bus112

22 kV

o

Bus 2A01

13.8 kV

Bus21

0.48 kV

Bus 2A02

13.8 kV

Bus22

0.48 kV

2 SU Bus

13.8 kV

Bus141

4.16 kV

E12

4.16 kV

Bus157

4.16 kV

Bus154

4.16 kV

Bus25

13.8 kV

Bus92

500 kV

Bus93 500 kV

Bus3

500 kV

Bus91

500 kV

Bus90

500 kV

Bus11

500 kV

Bus12

500 kV

Bus87

Bus13

500 kV

500 kV

Bus77500 kV

Bus80

500 kV

o

Sub9

230 kV

Bus28

230 kV

Mtr2 9000 HP

CB70

Mtr3 7200 HP

CB71

CB67

Mtr1 9000 HP

CB69

Mtr4 14400 HP

CB72

Gen10

2.6 MW CB705

Open

CB53

CB640

SU & Emer Aux Trans 2

135 MVA

CB393

CAP6

100000 kvar

CB121

Line5 CB9

CB40 CB113

Line7

CB55 CB245

CB128

Line6

O CR

CB905

CB412

CB235

CB137

CB205

CB225

CB44

CB45

CB35

CB138

CB25 CB15

CB65

Gen9

2.6 MW CB697

Open

CB724

CB663

Open CB736

CB695

Open CB696Open

CB729 CB726 CB727 CB725 CB728

CB735

Open

CB730

CB704

Open CB703Open

T75

10 MVA Mtr206 3850 HP

CB743

Open

CB660

CB544

CB723

2 Emer Aux Trans

135 MVA

CB659 CB80

CB82

Open

Lump5

6 MVA

CB100

Mtr11 750 HP

CB99

CB98

T10

12 MVA

CB97

CB83 Open

Lump2

6 MVA

CB95

Mtr10 750 HP

CB96

CB94

T9

12 MVA

CB93

CB68

T7

135/67.5/67.5 MVA

CB549

G6

1112 MW

32

CB111 CB122

Unit 2 Main Trans

1170 MVA

CB392

Bus31

Bus28

230 kV

Bus112

22 kV

CB235

CB905

Bus77500 kV

Bus80

500 kV

CB245

CB205

CB225

Bus87

500 kV

CB25

Bus91

500 kV

CB35

Bus90

500 kV

CB45

CB15

Bus93 500 kV

Bus92

500 kV

CB65

CB55

Unit 2 Main Trans

1170 MVA

E12

4.16 kV

CB392

CB393

2 SU Bus

13.8 kV

CB412

G6

1112 MW

CB544

CB549

Line6

CB640

2 Emer Aux Trans

135 MVA

CB659

CB660

T75

10 MVA

Bus141

4.16 kV

CB663

Gen9

2.6 MW

Bus154

4.16 kV

CB697

Open

CB695

Open CB696Open

Gen10

2.6 MW

Bus157

4.16 kV

CB705

Open

CB703

Open CB704Open

CB723

CB724 CB725 CB726 CB727 CB728 CB729 CB730

CB735

Open

CB736

Mtr206 3850 HP

CB743

Open

T5 1000/500/500 MVA

Sub9

230 kV

CB9

CB40

Bus3

500 kV

Bus11

500 kV

Bus12

500 kV

Bus13

500 kV

CB44

Line5

Line7

SU & Emer Aux Trans 2

135 MVA

CB53

Bus 2A02

13.8 kV

CB67

T7

135/67.5/67.5 MVA

Bus 2A01

13.8 kV

CB68

Mtr1 9000 HP

CB69

Mtr2 9000 HP

CB70

Mtr3 7200 HP

CB71

Mtr4 14400 HP

CB72

Lump2

6 MVA

CB80

CB82

Open CB83 Open

Bus21

0.48 kV

T9

12 MVA

CB93

CB94

CB95

Mtr10 750 HP

CB96

Lump5

6 MVA

Bus22

0.48 kV

T10

12 MVA

CB97

CB98

CB100

Mtr11 750 HP

CB99

Bus25

13.8 kV CB111

CB113

CB121

CB122

CAP6

100000 kvar

CB128

CB137

CB138

E124

0.48 kV Bus153

4.16 kV

E32

4.16 kV

Bus145

0.48 kV

E43

4.16 kV

Bus150

4.16 kV

E42

4.16 kV

Bus147

0.48 kV

E22

4.16 kV

Bus143

0.48 kV

Mtr199 375 HP

CB664

Lump110

0.75 MVA

CB665

CB666

T76

10 MVA Mtr207 3850 HP

CB744

Open

E4

2.6 MW

CB686

Open

CB674

Open

Mtr201 375 HP

CB676

Lump112

0.75 MVA

CB677

CB678

T78

10 MVA

CB738

Mtr209 3850 HP

CB746

Open

CB684

Open CB685Open

CB739

Mtr210 3850 HP

CB747

Open

E3

2.6 MW CB692

Open

CB668

Mtr200 375 HP

CB670

Lump111

0.75 MVA

CB671

CB672

T77

10 MVA

CB737

Open

Mtr208 3850 HP

CB745

Open

CB693

Open CB694Open

Mtr198 375 HP

CB662

Lump109

0.75 MVA

CB661

CB388

E124

0.48 kV

Lump109

0.75 MVA

Mtr198 375 HP

CB661 CB662

CB666

E22

4.16 kV

Open

T76

10 MVA

Bus143

0.48 kV

Lump110

0.75 MVA

Mtr199 375 HP

CB665 CB664

CB672

E32

4.16 kV

E3

2.6 MW

CB668

T77

10 MVA

Bus145

0.48 kV

Lump111

0.75 MVA

Mtr200 375 HP

CB671 CB670

CB678

E42

4.16 kV

E4

2.6 MW

CB674

Open

T78

10 MVA

Bus147

0.48 kV

Lump112

0.75 MVA

Mtr201 375 HP

CB677 CB676 CB682

E43

4.16 kV

Bus149

0.48 kV

Bus150

4.16 kV CB684

Open CB685Open

CB686

Open

Bus153

4.16 kV

CB692

Open

CB693

Open CB694

Open

CB737

Open

CB738 CB739

CB744

Open

Mtr207 3850 HP

Mtr208 3850 HP

CB745

Open

Mtr209 3850 HP

CB746

Open

Mtr210 3850 HP

CB747

Open

E13

4.16 kV

Bus165

4.16 kV

Bus163

13.8 kV

230 kV

Bus19

Bus20

Bus167

Bus166

22 kV

Bus 3A01

13.8 kV

Bus23

0.48 kV

B

Sub2

500 kV

Bus10

500 kV Sub3 500 kV

Sub1

500 kV Bus126

Bus1

500 kV

Bus2

Bus4

o o

Sub5

230 kV

Sub6

230 kV

Sub4

230 kV

T82

10 MVA

CB27 Line 220 

CB26 Line 220 

CB22 Line 220 01 CB

CB8

CB12

Line 220 05 CB11

CB21 Line 220 32

CB17

CAP3

161000 kvar

U8

5000 M

CB20

Line 220 33 CB19

CAP1

161000 kvar

CB54

O CR

Line3

O CR

CB66

Line 5010 CB120

G2 1134 MW T2

1500 MVA

CB2

G3 1134 MW T3

1500 MVA

CB36

CB3

CB38

Line 5007 CB119

G1 852 MW T50

1500 MVA

CB506

CB32

CB39

Line8 CB61

CB62

CB63

U6

10000 MVAsc

CB37 CB34 CB118

Line 5012

CB722

Mtr5 9000 HP

CB73

Mtr6 7200 HP

CB74

CB84

CB87 Open

Lump6

6 MVA

CB104

Mtr12 750 HP

CB103

CB102

T11

12 MVA

CB101

CB75

CB

CB721

Unit 3 Main Trans

1170 MVA

CB720

Mtr14 16350 HP

CB110

Lump8

5 MVA

CB716

SU & Emer Aux Trans 3

500 MVA

CB4

CB5

CB59

CB57

SU Trans 343

135 MVA

CB56

CB715 CB91

Open

CB714

T83

135 MVA

CB731

CB741 CB699

Open

CB718 CB733 CB713 CB732 CB717 CB734 CB719

CB707 CB742

Open

Mtr213 3850 HP

CB750

Open

CB64

Bus20

230 kV

Bus19

Bus126

Sub1

500 kV

Line 5007

CB506 T50

1500 MVA

G1 852 MW

CB699

E13

4.16 kV

CB707

T82

10 MVA

Bus163

13.8 kV

CB715

CB713

CB716

T83

135 MVA

CB714

CB717 CB718 CB719

Bus165

4.16 kV

Bus167

Bus166

22 kV

Unit 3 Main Trans

1170 MVA

CB720

CB721CB722

CB731 CB732 CB733 CB734

CB741

CB742

Open

Mtr213 3850 HP

CB750

Open

Sub2

500 kV Line 5012

Bus2

Bus1

500 kV

Line 5010

CB2 T2

1500 MVA

G2 1134 MW

Bus4 CB3 T3

1500 MVA

G3 1134 MW

Line3

CB4

CB5

Sub4

230 kV

CB8

Sub6

230 kV

CB11

CB12

Line 220 05

CB17

Sub5

230 kV

CB19

CB20

CB21

Line 220 33

Line 220 32

CB22CB

Line 220 01

CB27

CB26

Line 220 

Line 220 

CB32

CB34

CB36

Bus10

500 kV

CB39

CB37

CB38

SU & Emer Aux Trans 3

500 MVA

CB54

CB57

CB56

SU Trans 343

135 MVA

CB59

CB61

Sub3 500 kV

CB62

CB63

CB64

CB66

Line8

B

Bus 3A01

13.8 kV

CB75

Mtr5 9000 HP

CB73

Mtr6 7200 HP

CB74

CB

CB84

CB87 Open

CB91

Open

Lump6

6 MVA

Bus23

0.48 kV

T11

12 MVA

CB101

CB102

CB104

Mtr12 750 HP

CB103

CB110

Mtr14 16350 HP Lump8

5 MVA

CAP1

161000 kvar

CAP3

161000 kvar

U6

10000 MVAsc

CB119

CB118

CB120

U8

5000 M

E33

4.16 kV

Bus152

0.48 kV

E23

4.16 kV

Bus156

0.48 kV

Bus159

0.48 kV

Mtr205 375 HP

CB708

Lump118

0.75 MVA

CB709

CB710

Mtr204 375 HP

CB700

Lump117

0.75 MVA

CB701

CB702

T81

10 MVA Mtr212 3850 HP

CB749

Open

Mtr202 375 HP

CB681

Lump114

0.75 MVA

CB683

T79

10 MVA

CB680

Open

Mtr203 375 HP

CB689

Lump116

0.75 MVA

CB690

CB691

T80

10 MVA

CB740

Open

Mtr211 3850 HP

CB748

Open

CB688

CB683

CB680

Open

CB681

Mtr202 375 HP

Lump114

0.75 MVA

T79

10 MVA

CB691

E33

4.16 kV

T80

10 MVA

Bus152

0.48 kV

Lump116

0.75 MVA

Mtr203 375 HP

CB690 CB689

CB688

CB702

E23

4.16 kV

T81

10 MVA

Bus156

0.48 kV

Lump117

0.75 MVA

Mtr204 375 HP

CB701 CB700

Open

CB710

Bus159

0.48 kV

Mtr205 375 HP

Lump118

0.75 MVA

CB708 CB709

CB740

Open

Mtr211 3850 HP

CB748

Open

Mtr212 3850 HP

CB749

Open
41

4.3 Scenario Definition, Simulation, and Analysis

4.3.1 Comparison of Grid Responses to Faults at Different Locations

In this section, sets of scenarios are defined for the individual plant models representing the 

same type of faults at different locations measured in terms of distance from the switchyards. 

The developed scenarios are defined in Table 4-1. For each plant model, both permanent and 

transient faults are defined for the selected lines. For buses, only permanent faults are defined 

since the selected buses are all part of the switchyard buses. Failed bus will be taken over by 

the other bus for a breaker-and-a-half configuration. Therefore, permanent faults for these 

buses should not make any difference from the transient faults as long as the failed bus is 

isolated. For plants of breaker-and-a-half configuration switchyards, i.e., Plant A and Plant B 

models, the frequency and voltage at the two buses of the switchyards are plotted in the figures. 

For the plant of a ring-bus configuration switchyard, i.e., Plant C model, the frequency and 

voltage at two of the ring buses are plotted in the figures.

The simulation results for Plant A Cases 1 - 6 are shown in Figures 4-4 through 4-10. The 

voltage and frequency transients at two switchyard buses SWYDBus-1 and SWYDBus-2 were 

plotted such that the responses to faults at different distances from the switchyard can be 

compared meaningfully. The simulation results for the rest of the scenarios defined in Table 4-1 

can be found in Figures A-1 through A-15 Appendix A. 
42

Table 4-1 Scenarios for Comparing Grid Responses to Faults at Different Location

Plant 

Models

Bus Permanent 

Faults (3-phase)

Line Permanent 

Faults (50% three 

phase)

Line Transient 

Faults (50% three 

phase)

Fault Clearing Actions Distance 

the Plant

Plant A SWYDBus-1 Fault cleared after 0.08

(s)

Near 

Sub1-1 Medium 

Bus 20 Far 

Line 12 Open CB49 and CB 50 

after 0.08 (s)

Near 

Line 10 Open CB47 and CB109 

after 0.08 (s)

Far 

Line 12 Fault cleared after 0.08

(s)

Near 

Line 10 Far 

Plant B EB Fault cleared after 0.08

(s)

Near 

Sub2 Medium 

Sub6 Far 

Line 12 Open CB361 and CB414 

after 0.08 (s)

Near 

Line 2 Open CB496 and CB669 

after 0.08 (s)

Far 

Line 12 Fault cleared after 0.08

(s)

Near 

Line 2 Far 

Plant C Bus 77 Fault cleared after 0.08

(s)

Near 

Sub 1 Far 

Line 3 Open CB64 and CB 54 

after 0.08 (s)

Near 

Line 220 32 Open CB17 and CB21 

after 0.08 (s)

Medium 

Line 220 31 Open CB27 and CB28 

after 0.08 (s)

Far 

Line 3 Fault cleared after 0.08

(s)

Near 

Line 220 32 Medium 

Line 220 31 Far 
43

Figure 12 CBA-Case-1 for Bus SWYDBus-1 Permanent Fault (Near)
44

Figure 13 Plant A-Case-2 for Bus Sub1-1 Permanent Fault (Medium)
45

Figure 14 Plant A-Case-3 for Bus Bus20 Permanent Fault (Far)
46

Figure 15 Plant A-Case-4 for Line12 Permanent Fault (Near)
47

Figure 16 Plant A-Case-5 for Line10 Permanent Fault (Far)
48

Figure 17 Plant A-Case-6 for Line12 Transient Fault (Near)
49

Figure 18 Plant A -Case-7 for Line10 Transient Fault (Far)
50

From the simulation results shown in Figures 4-4 through 4-10 (also the simulation results of 

similar cases for Plants B and C, as shown Figures A-1 through A-15), it can be concluded that 

it is generally true that for a fault originated in the transmission network, the closer the fault is to 

the NPP switchyard, the more severe impact it has on the NPP. While this might be well-known, 

it may not be common for a NPP switchyard owner or a transmission network owner to 

recognize that a different or a tighter protection scheme is warranted for the NPP switchyard or 

transmission lines/substations nearby a NPP switchyard considering the fact that a utility tends 

to use the uniform protective schemes settings across the entire network owned by the utility. 

The performance variation of different protective schemes/settings becomes obvious in the next 

section, especially when an additional breaker failure is considered following a fault occurrence. 

Note, a transmission line fault followed by the failure of the protection system is not rare at all, 

e.g., see Section 1.1.3.

Also, note that none of the fault scenarios indicates that the NPP will be challenged under the 

faulted conditions considered above. This also partially serves the purpose of validating the 

NPP plant models created in the study.

4.3.2 Comparison of Grid Responses to Faults with Different Protection 

Schemes

4.3.2.1 Parameters for Generic Protective Schemes

The scenarios of interest are developed to study the grid responses to individual faults under 

different protection schemes. As shown in Section 4.3.1, the closer the faults originated in the 

transmission network to the NPP switchyard, the more severe are the impacts that a longer fault 

clearing time has on the plant responses. Therefore, clearing the faults with minimum or without 

any intentional time delay becomes critical in order to reduce the NPP susceptibility to the 

external faults. 

For transmission line protection schemes, as described in Section 2, the primary protection 

relaying scheme using telecommunications does not have any intentional time delay once an 

internal fault is detected. The only intentional time delay is built into the remote breaker failure 

protection scheme, which is also considered to be required for protective relaying coordination. 

For a telecommunication-based remote breaker failure backup scheme, this time delay is very 

small, i.e., around 90 ms, as shown in Section 2. Considering the severity of the impact of the 

fault that is near the NPP switchyard, the postulation is that it is therefore ideal to apply the 

telecommunications-based protective relaying in conjunction with the telecommunications based 

breaker failure backup schemes on the transmission lines at and/or near the NPP switchyard, 

as will be shown in this section.

The parameters used in the study for different protection schemes are summarized in Table 4-2. 

The parameters defined in the table are generic and can be basically applied to develop 

scenarios that can be simulated to compare the performance evaluation of the protection 

schemes for different plant models. 
51

Table 4-2 Generic Parameters for Simulating the Responses to a Fault with Different 

Protective Schemes

Protective Types Near End Bus 

Clearing Time(s)

Far End Bus 

Clearing Time(s)

Near End 

Breaker Failure

Remote Backup 

Breaker(s) 

Opening Time(s)

Distance Relaying (DR) 0.08 0.58 None --

Distance Relaying with 

Breaker Failure Protection

(DRBF)

0.58 -- Yes 0.58

Telecom-based protective

Relaying (PR) 0.08 0.1 None

Protective Relaying with 

Telecommunication-based 

Breaker Failure Protection

(PRBF)

0.19 -- Yes 0.1

Table 4-2 provides generic parameters for simulating the responses to a fault with the 

transmission line and/or with the failure of an additional breaker at one end (the near end) of the 

transmission line for different protection schemes that are popular in HV/EHV transmission 

protection. The clearing time in the table refers to the total time it takes for the circuit breakers to 

actuate and clear a fault after the fault has occurred. Note, the fault assumed here is detectable 

by the near end Zone 1 relays and the far end Zone 2 relays, e.g., a fault at 90% of the line 

length. The reason we are interested in this type of faults is that a transmission line fault near a 

bus is more severe than the fault in the middle of a transmission line because the power flow at 

the bus will be almost totally blocked for the former case. If the fault is detectable by both of the 

Zone 1 relays at the two ends of a transmission line, e.g., a fault at 50% of the line length, the 

time it takes to clear the fault is different. This kind of situation is not considered in this study. 

Also note, if multiple lines are connected to one end of a transmission line, that end has multiple 

circuit breakers. Failure of each breaker may have to be considered due to the different effects it 

may have, as will be illustrated in Examples 2, 3, 5, and 6 in Section 4.3.2.2.

4.3.2.2 Example Scenario Definition for NPP Models and Simulation Results

Three sets of example scenarios were developed for the three NPP models and the simulation 

results are presented and briefly discussed in this section.

A set of example scenarios was developed to simulate the grid responses to a 90% three-phase 

transmission line (Line 13 of a length of 24.5 miles in the model) fault with the switchyard bus 

SWYDBus-1 of Plant A as the near end bus of the fault under different assumptions of 

protection schemes. The fault is assumed to occur at 0.2 seconds.

In the first example, it is assumed that a distance relaying scheme (DR) is used with three 

protection zones defined. The fault at the near end bus (bus 14) is assumed to be cleared in 80 

ms (relay time 30 ms plus circuit breaker clearing time 50 ms), i.e., the circuit breakers CB16 

and CB18 are opened at 0.28 seconds. Since the fault is out of the reach of the Zone 1 relays at 

bus 14, the fault is detected by the Zone 2 relays at substation Sub3 in the model and will be 

cleared with an intentional time delay of 0.5 seconds, i.e., CB54 is opened at 0.78 seconds. The 

frequency and voltage transients at buses SWYDBus-1 and Sub3 are shown in Figure 4-11.
52

The second example assumes a remote breaker failure protection scheme (no communication 

channel) as a backup protection of the distance relaying scheme, i.e., DRBF scheme. In this 

simulation, it is assumed that circuit breaker CB16 fails (CB18 still opens correctly) to open such 

that the fault cannot be cleared at the near end in time. The fault will still be cleared at the far 

end bus Sub3 at 0.78 seconds since the Zone 2 relays there are not affected. The relays of the 

breaker failure protection scheme, which are installed also on bus 14, detect the fault and send 

trip signals to circuit breakers CB1, CB4, CB7, CB10, CB13, CB 19, and CB22. After an 

intentional time delay of around 0.5 seconds, i.e., at 0.78 seconds, CB16 and CB18 will trip to 

clear the fault. Note, since many circuit breakers are tripped and bus SWYDBus-1 is lost, the 

induced transient might be severe although the other bus SWYDBus-2 is capable of taking over 

immediately. The switchyard bus responses are shown in Figure 4-12.

The third example is similar to the second one but with the assumption of CB18 failure instead 

of CB16. In this situation, CB17, as the remote backup circuit breaker for CB18 failure, will be 

tripped with an intentional time delay of 0.5 seconds. Note, another transmission line, line 12, is 

also connected and will be affected. Since distance scheme is assumed here, it is expected that 

the Zone 2 relay at the other end of line 12, bus Sub5, will detect the fault current and trip the 

circuit breaker CB140 with an intentional time delay of 0.5 seconds. This is a less severe 

scenario, although fewer numbers of breakers are tripped, compared to the second one 

because tripping circuit breakers CB17 and CB140 will cause a loss of another transmission line, 

line 12, between buses Bus13 and Sub5 in the Plant A model. The simulation results are shown 

in Figure 4-13.

Example 4 assumes a protective relaying scheme using telecommunications (PR) for the 

transmission line 13 between bus 14 and Sub3 in the Plant A-R0 model. The Zone 1 relays at 

bus 14 will detect the fault and open the circuit breakers CB16 and CB18 to clear the fault at 

near end at 0.28 seconds. In the mean time, the Zone 2 relays at bus Sub3 also detect the fault 

immediately and will open circuit breaker CB54 after an intentional time delay of 20 ms (this 

time delay is to accommodate the communication time of the tripping signal or blocking signal 

depending on whether it is a permissive or blocking-type protection scheme). Therefore, the 

fault at the far end will be cleared at 0.3 seconds. The switchyard bus responses are shown in 

Figure 4-14.

In Example 5, a communication-based remote breaker failure protection scheme, i.e., PRBF 

scheme, is adopted. In this example, breaker CB16 is assumed to fail to open and breaker 

CB18 will still open at 0.28 seconds. The far end fault will still be cleared at 0.3 seconds, the 

same as that in example 3. The Zone 1 relays at bus 14 detect the fault and send a trip signal to 

the remote backup circuit breakers CB1, CB4, CB7, CB10, CB13, CB19, and CB22 via 

communication channels. Again, a 20 ms communication time and an intentional time delay of 

90 ms are assumed. Therefore, CB1, CB4, CB7, CB10, CB13, CB 19, and CB22 will open at 

0.39 seconds. See Figure 4-15 for detailed switchyard bus responses. 

Similar to Examples 2 and 3 for the distance relaying schemes, a variation of Example 4 is to 

fail circuit breakers CB18 while CB16 still opens at 0.28 seconds. CB17 is one of the remote 

backup breakers for CB18 and therefore, will be opened at 0.39 seconds. Note, the circuit 

breaker CB140 at the other end of line 12 also serves as the backup breaker for CB18. A 

protective relaying scheme using telecommunications is also assumed for line 12. This fault is 

anticipated to be detected by the Zone 2 relays at bus Sub5 and thus the circuit breaker CB140 

is expected to be opened by these relays at 0.39 seconds. Again, this causes a loss of line 12, 

between buses Bus13 and Sub5 in the Plant A model and is a more severe scenario than 

Example 5.
53

In a summary, the frequency and voltage responses at buses SWYDBus-2 and SWYDBus-1 are 

shown in Figures 4-11 through 4-16. The resulting performance variations for each of the 

proposed example protection schemes are evident in the accompanying figures.

The bus frequency and voltage plots for Example 1 are shown in Figure 4-11. Figure 4-11

shows that, under the conventional distance relaying scheme, the magnitude of the deviation is 

acceptable and the transient responses after clearing the line 13 fault are quickly dampened out. 

Note, there is no failure associated with the protection system for line 13.

Example 2 results are shown in Figure 4-12 for the frequency and voltage responses at the 

selected buses SWYDBus-1 and SWYDBus-2. While some oscillations of frequency and 

voltage level are observed at bus SWYDBus-2, i.e., the far end of line 13, the oscillations will be 

suppressed, as shown in the figure. The switchyard bus SWYDBus-1 is isolated, as expected. 

The oscillations at bus SWYDBus-2, although dampened out eventually, are significantly more 

severe, especially in the beginning of the transient, where the frequency deviation at the bus is 

also severe. The voltage responses at the bus are also significantly degraded in terms of 

oscillation magnitude. 

For Example 3, the responses shown in Figure 4-13 at buses SWYDBus-1 and SWYDBus-2 are 

apparently worse compared to Example 2 results although in Example 2. However, it can be 

seen that each of the cases presents a significant challenge to the NPP by inspecting the 

frequency and voltage responses are the switchyard buses.

Example 4 results are shown in Figure 4-14, where the improved responses are obvious 

compared to those shown in Figure 4-11 under distance relaying scheme. The responses for 

the Example 4 scenario and the Example 5 scenario (Figure 4-15) are similar to each other. 

Although the responses for Examples 5 and 6 (Figure 4-16) are worse than that in Example 4, 

as expected, much better responses are observed than those in Examples 2 and 3. In all cases, 

the oscillations of both frequency and voltage are quickly removed, which indicates that the NPP 

will experience no significant issue and should be able ride through the transmission line fault 

and the primary protection failure.
54

Figure 19 Example Scenario 1 for Plant A Model for Distance Relaying
55

Figure 20 Example Scenario 2 for Plant A Model for Distance Relaying with Remote 

Breaker Failure Backup Protection
56

Figure 21 Example Scenario 3 for Plant A Model for Distance Relaying with Remote 

Breaker Failure Backup Protection
57

Figure 22 Example Scenario 4 for Plant A Model for Telecommunications-based 

Relaying
58

Figure 23 Example Scenario 5 for Plant A Model for Telecommunications-based 

Relaying with Remote Breaker Failure Backup Protection
59

Figure 24 Example Scenario 6 for Plant A Model for Telecommunications-based 

Relaying with Remote Breaker Failure Backup Protection
60

Similar scenarios are defined for line 13 (44 miles) of Plant B model and line 5007 (105 miles) of 

Plant C model. 

For line 13 of Plant B fault with DR scheme, CB922 and CB925 (near end) and CB332 (far end) 

will open 0.08 s and 0.58 s after the fault, respectively. This is called Example 1 for Plant B

model. 

For the DRBF scheme, it is first assumed that CB922 fails and CB925 still open correctly. As the 

remote breaker failure backup, CB902, CB912, CB932, CB942, CB972, CB982, CB992, and 

CB9102 will open after 0.58 seconds of the fault occurrence. The far end circuit breaker CB332 

also open 0.58 seconds after the fault. This is indicated as Example 2 for Plant B model.

In Example 3 for Plant B model, the DR scheme is still used but it is assumed that CB925 fails 

to open. As the breaker failure backup, CB928 and CB660 will be opened 0.58 seconds after 

the fault occurrence. Opening CB660 will lead to a loss of power supply to the onsite 525 

kV/13.8 kV transformer AE-NAN-X01 that supplies power to 13.8 kV buses 2E-NAN-S05 and 

3E-NAN-S06. The power will be provided by their backup power supply via bus switching 

scheme. A typical bus switching time is assumed to be 5 cycles or around 80 ms [Trehan 2003]. 

Therefore, 0.66 seconds after the fault, circuit breakers CB396 and CB450 will be closed to 

continue the power supply to buses 2E-NAN-S05 and 3E-NAN-S06 (See Figure 4-2).

In Example 4, the PR scheme is used. Therefore, CB922 and CB925 (near end) and CB332 (far 

end) will open 0.08 s and 0.3 s after the fault, respectively. Example 5 assumes the PR scheme 

with remote breaker failure backup. It is also assumed that CB922 fails to open. Therefore, 

CN925 will open at 0.28 seconds. CB332 still opens at 0.3 seconds. CB902, CB912, CB932, 

CB942, CB972, CB982, CB992, and CB9102 will open after 0.19 seconds of the fault 

occurrence, i.e., 0.39 seconds.

In Example 6, CB925 is assumed to fail instead. CB922 and CB332 will open at 0.28 and 0.3 

seconds, respectively. CB928 and CB660 will also open, similar to Example 3, but at 0.39 

seconds. In the mean time, CB396 and CB450 will close 0.08 seconds (the bus switching time) 

after the opening of CB660.

The frequency and voltage responses at the two switchyard buses EB and WB for the six 

examples scenarios are shown in Figures 4-17 through 4-22. Note that in Example scenarios 2 

and 3, i.e., under DRBF scheme, both frequency and voltage responses of the switchyard buses 

are unacceptable due to continuous oscillations. While it is understood that the response in the 

simulation model may deviate the response that might occur at the real plant, it is certain that 

additional breaker failure under a distance relaying scheme may pose much more significant 

challenge to the NPP. For the protective relaying scheme using telecommunications, on the 

other hand, none of the three scenarios raise any issue to the plant operation, as shown in 

Figures 4-20 through 4-22.
61

Figure 25 Example Scenario 1 for Plant B Model for Distance Relaying
62

Figure 26 Example Scenario 2 for Plant B Model for Distance Relaying with Remote 

Breaker Failure Backup Protection
63

Figure 27 Example Scenario 3 for Plant B Model for Distance Relaying with Remote 

Breaker Failure Backup Protection
64

Figure 28 Example Scenario 4 for Plant B Model for Telecom-based Relaying
65

Figure 29 Example Scenario 5 for Plant B Model for Telecommunications-based 

Relaying with Remote Breaker Failure Backup Protection
66

Figure 30 Example Scenario 6 for Plant B Model for Telecommunications-based 

Relaying with Remote Breaker Failure Backup Protection
67

Finally, six scenarios are defined for Line 5007 of Plant C model. For 105 mile Line 5007 

between buses Bus93 and Sub1, a 90% three phase fault occurs near Bus93, one of the ring 

buses of the Plant C switchyard. The near end circuit breakers are CB15 and CB65 while the far 

end breaker is CB119.

For Example 1, a DR is assumed. Therefore, CB15 and CB65 will open around 80 ms after the 

fault occurrence and the far end CB119 will open at 0.78 seconds. Two of the switchyard buses 

are selected and the frequency and voltage responses of theirs are shown in Figure 4-23. With 

the prompt fault clearing at the near end, the NPP should not have any issue with its normal 

operation.

Example 2 uses the DRBF scheme and one of the near end circuit breakers CB15 is assumed 

to fail. CB65 and CB119 will open at 0.28 and 0.78 seconds, respectively. As the remote 

breaker failure backup, CB25, CB205, and CB235 at the switchyard will open after 0.5 seconds 

delay. The two switchyard bus responses are shown in Figure 4-24.

Example 3 again uses DRBF scheme but the failure of CB65 is assumed here. CB15 and 

CB119 will open at 0.28 and 0.78 seconds. The backup breakers for the failure of CB65 are 

CB4, CB5, and CB55, which will be opened also 0.78 seconds. The responses are shown in 

Figure 4-25. The degraded grid responses for Example scenarios 2 and 3 are clear compared to 

Example 1 results.

For Example 4, the near end circuit breakers CB15 and CB65 will open at 0.28 seconds and the 

far end CB119 will be opened at 0.3 seconds.

In Example 5, the PRBF scheme is used and one of the near end breakers CB15 is assumed to 

fail. CB65 will open at 0.28 seconds while CB119 opens at 0.3 seconds. The remote backup 

breakers for CB15 are CB25, CB205, and CB235, which will be opened at 0.39 seconds.

Example 6 again assumes PRBF scheme and CB65 is assumed to fail to open. CB15 will be 

opened at 0.28 seconds and CB119 still opens at 0.3 seconds. The remote backup circuit 

breakers CB4, CB5, and CB55 are opened at 0.39 seconds, as scheduled.

The switchyard buses responses for Examples 4, 5, and 6 are shown in Figures 4-23 to 4-28.

A review of all of the example scenarios for the three plants indicates that the same conclusions 

can be drawn, i.e., the tighter protective schemes at the NPP switchyard will enhance the 

capability of the NPP to ride through the faults originated in the transmission grid. Considering 

the impact severity of the faults at different distances from the NPP switchyard, as shown in 

Section 4.3.1, making the protective schemes nearby a NPP tighter will serve the same purpose.
68

Figure 31 Example Scenario 1 for Plant C Model for Distance Relaying
69

Figure 32 Example Scenario 2 for Plant C Model for Distance Relaying with Remote 

Breaker Failure Backup Protection
70

Figure 33 Example Scenario 3 for Plant C Model for Distance Relaying with Remote 

Breaker Failure Backup Protection
71

Figure 34 Example Scenario 4 for Plant C Model for Telecom-based Relaying
72

Figure 35 Example Scenario 5 for Plant C Model for Telecommunications-based 

Relaying with Remote Breaker Failure Backup Protection
73

Figure 36 Example Scenario 6 for Plant C Model for Telecommunications-based 

Relaying with Remote Breaker Failure Backup Protection
74

The range of a tighter protective scheme is plant-specific. A simulation of scenarios similar to 

those defined in Section 4.3.1 in an exhaustive manner would need to be performed to evaluate 

the effect of tighter protective system settings. However, the number of scenarios needed to be 

simulated should not be very difficult to handle as the effects of faults that are relatively far from 

the NPP switchyard should not be very different.

The focus of this section is on the evaluation of protection schemes for transmission lines. For 

bus protection, similar scenarios can be defined. As indicated in Section 2, a differential relaying 

scheme is most commonly used for a bus protection. For any internal fault, it is desired that the 

bus be isolated instantaneously without any intentional time delay. If one of the breakers fails, 

its backup breaker(s) may be activated by the differential relays at the bus with intentional time 

delay that changes, e.g., a short time delay for a telecommunications-based breaker failure 

backup scheme.

4.3.2.3 Anticipatory Trip of Zone 3 Relays

In this section, an investigation of anticipatory trip by reducing the time delay of Zone 3 relays of 

the faulted zone and tripping the breakers connected to the switchyard is presented. As 

indicated in Section 2.3.1.1, e.g., in Figure 2-4, if fault F4 were not cleared by the primary 

protection (i.e., the Zone 1 and Zone 2 protection) of line BC, Zone 3 relays at bus A will open 

the breaker near bus C at line BC after approximately two seconds of the fault occurrence. The 

anticipatory Zone 3 protection is similar to the concept of a Zone 3 protection but with a 

probably much shorter time delay. Note that the purpose of having two seconds delay is to 

coordinate with the primary protection of line BC. Reduction in the time delay means a loss (or 

a partial loss) of this coordination between them. Compared to the breaker failure backup 

protection scheme, an anticipatory Zone 3 protection has the advantage that it does not trip 

additional components. Furthermore, if the Zone 3 protection relays were installed at 

switchyard buses watching only the adjacent lines providing offsite power, a reduced time delay 

with Zone 3 relays to isolate the fault with the adjacent line(s) will certainly alleviate the adverse 

effect of the primary protection failure. Note that the anticipatory trip of Zone 3 is similar to the 

breaker failure backup protection scheme in the sense that Zone 3 relays may trip extra 

components. 

Scenarios are developed here by using Plant B as an example system. To better illustrate the 

concept, a postulated transmission line of a length 10 miles, Line31, is added between bus 

Sub3 and bus Bus86 in Figure 4-2. A 10% three-phase fault is postulated for Line31 at 0.2 

seconds. It is also postulated that Zone 1 and Zone 2 relays at Sub3 are watching Line31. In 

this scenario, Zone 2 relays at Bus93 cannot reach the fault and Zone 3 relays at Bus93 

becomes critical in terms of fault clearing (see the diagram in Figure 4-29 for the configuration 

of the components involved). Considering a typical protection scheme using 

telecommunications as shown in Figure 5, scenarios with different time delays, namely 1.4, 0.9, 

and 0.4 seconds, with the Zone 3 relays installed at Bus93 are developed and simulated. Note, 

the minimum delay of 0.4 seconds is selected because the Zone 2 relaying at Sub3, if it 

functions properly, will open breaker CB355 to isolate the fault if the fault lasts longer than 0.4 

seconds. Therefore, three scenarios of an anticipatory Zone 3 trip correspond to, by assuming 

that Zone 1 relays at Bus86 work properly (i.e., CB500 opens at 0.28 seconds), the opening of 

circuit breakers CB932 and CB935 at 1.6, 1.1, and 0.6 seconds, respectively. These three 

scenarios are indicated as Line31-Scenario 1, 2, and 3, respectively. The voltage and 

frequency responses at switchyard buses EB and WB are shown in Figures 4-30 through 4-32.

The simulation results show that, with anticipatory Zone 3 relays enabled at the switchyard, 
75

Figure 37 Switchyards of Plant A and a Neighboring Substation

reducing the time delay can significantly improve the switchyard bus responses. Note, if time 

delay is set longer than 0.4 seconds, the Zone 3 relay does not trip components that do not 

have to even if the primary protective relays function properly.

4.3.2.4 More Postulated Scenarios without Simulation

This section discusses some additional postulated scenarios. For these scenarios, simulation is 

not necessary and analyses are provided based on the one-line diagram of the plant model. It 

is well-known that a turbine trip will lead to a reactor trip directly. A turbine trip could be 

immediately caused if the generator has to be taken off-line. Taking the switchyard of the Plant 

B model as an example, generator G31 is connected to the switchyard between two circuit 

breakers CB915 and CB918. A postulated scenario is a three-phase 90% fault with Line 12 

followed by the failure of breaker CB915 when attempting to clear the fault. An immediate effect 

of this breaker failure is that the generator G31 will directly feed the fault. It is very likely that the 

generator will soon be taken offline by its protection systems, e.g., the generator negative phase 

sequence relays or volts per Hertz relays described in Section 2 and Appendix D. The above 

analysis of this postulated scenario implies that the middle circuit breaker CB915 (and the 

relay(s) associated with it) is critical and needs to be highly reliable in order to enhance the fault 

ride-through capability of the generator. Breakers CB935 and CB985 play the same role as they 

are connected to generators G21 and G11, respectively. CB918, CB938, and CB988 can be 

used to isolate the fault with bus WB and their failure may result in the same impact on the 

generator operations. This can be seen from Figure 4-2. 

Similar analysis can be performed for a ring-bus configuration switchyard, e.g., the Plant C 

model. Circuit breakers CB905 and CB245 that are connected to generator G6.
76

Figure 38 Line31 – Scenario 1 for Zone 3 Anticipatory Trip (0.4 Seconds Delay)
77

Figure 39 Line31 – Scenario 2 for Zone 3 Anticipatory Trip (0.9 Seconds Delay)
78

Figure 40 Line31 – Scenario 3 for Zone 3 Anticipatory Trip (1.4 Seconds Delay)
79

4.3.3 Interactions between Protection Systems of Switchyards Close to Each 

Other

As shown in the Plant A model (Figure 4-1), another switchyard of breaker-and-a-half 

configuration with buses Sub1-1 and Sub1-2 is directly connected to the switchyard of Plant A. 

There are four transmission lines between the two switchyards. In particular, line 11 and line 12 

share the three circuit breakers CB1, CB2, and CB3 in the Plant A switchyard while other end of 

line 11 is connected to CB87 and CB88, and line 23 is connected to CB82 and CB83. See 

Figure 4-33 for this portion of the Plant A model. 

Figure 41 Switchyards of Plant A and a Neighboring Substation
80

The interaction between the two switchyards is illustrated by using a postulated scenario of a 

90% fault (with near end circuit breakers CB2 and CB3) with line 11 followed by a failure of 

breaker CB2 while the rest of the associated breakers open properly according to the adopted 

protection scheme. If a breaker failure protection scheme is available, the backup breakers for 

the failed CB2 are CB1, CB82, and CB83. Opening CB82 and CB83 will remove line 12 from 

the model. This actually indicates that the postulated scenario, i.e., a line fault plus a breaker 

failure will lead to a loss of two transmission lines connecting the two switchyards in the manner 

shown in Figure 4-33. Note, such an issue does not exist for other two transmission lines, line 7 

and line 8. Depending on how much the transmission system power delivery relies on these two 

transmission lines, this loss might have severe impact on the plant operation. A more detailed 

study of this scenario might become necessary.

The study can be carried on by defining example scenarios similar to the approach described in 

Section 4.3.2.2, i.e., by assuming different types of protection schemes.

Example 1 assumes that a DR scheme is adopted. For the fault that occurred at 0.2 seconds, 

CB2 and CB3 will open at 0.28 seconds and CB87 and CB88 open at 0.78 seconds. The 

resulting frequency and voltage responses at buses SWYDBus-1 and SWYDBus-2 are shown in 

Figure 4-34. 

In Example 2, a DR scheme is again used and a breaker failure backup scheme is available, 

which means that CB3 will open promptly at 0.28 seconds and CB87 and CB88 open at 0.78 

seconds. The backup circuit breakers CB1, CB82, and CB83 will be opened by the near end 

relay of line 11 with an intentional time delay of 0.5 seconds, i.e., they open at 0.78 seconds. 

See Figure 4-35 for the Plant A switchyard bus responses.

Example 3 is similar to Example 1 except that a PR is used here. Therefore, CB2 and CB3 still 

open at 0.28 seconds and CB87 and CB88 will open at 0.3 seconds. The simulation results are 

shown Figure 4-36.

Finally, A PR and a breaker failure backup scheme are assumed in Example 4. The opening 

times are 0.28 seconds for CB3, 0.3 seconds for CB87 and CB88, and 0.39 seconds for CB1, 

CB82, and CB83. The switchyard bus responses can be seen in Figure 4-37.

The switchyard bus responses in Example 2 indicate that the NPP operation may be 

significantly challenged for the distance relaying protection scheme. However, from the design 

point of the view, the arrangement of the connection of line 11 and line 12 may need to be 

avoided because the postulated scenario here suggests that two lines may be lost.
81

Figure 42 Example Scenario 1 for Interaction between Protection Schemes of Two 

Switchyards
82

Figure 43 Example Scenario 2 for Interaction between Protection Schemes of Two 

Switchyards
83

Figure 44 Example Scenario 3 for Interaction between Protection Schemes of Two 

Switchyards
84

Figure 45 Example Scenario 4 for Interaction between Protection Schemes of Two 

Switchyards
85

4.3.4 Plant Responses to an External Fault with Disabled Zones 1, 2, and 3 

Protection Relays

In the previous sections, the plant responses to a fault when first or second or third zone 

protection is disabled were not studied. The past experiences have shown that many NPP trip 

events were caused by a single fault and the (inadvertently) disabled zone protection relays. 

Section 1.1.2 provides such an example event that occurred to the Peach Bottom Atomic Power 

Station on September 15, 2003. Examples 1 and 4 defined for each plant in Section 4.3.2.2 are 

actually equivalent to scenarios where Zone 1 protection relays at both ends of a transmission 

line are (inadvertently) disabled for the 90% 3-phase transmission line faults. In the first 

example, the protection relays are distance type while the relays are telecommunication-based 

in the fourth example. The faults are subsequently picked up by Zone 2 protection relays. The 

simulation results for example scenarios 1 and 4 of each plant indicate that, in this kind of 

situation, i.e., disabling Zone 1 protection relays, the transmission line fault was cleared 

effectively by the Zone 2 protection relays and does not have severe impact on the response, as 

expected. If protection relays of Zones 1 and 2 (and possibly Zone 3) were disabled, the fault 

impact could be much more significant (an example is shown below) and can potentially cause 

a plant trip, as confirmed by the NPP operating experience.

A scenario is briefly described here using Plant A as an example. The same fault discussed in 

example 1 for Plant A is assumed. The switchyard bus responses were simulated and are 

shown in Figure A-16 assuming that Zones 1, 2, and 3 protection relays were disabled. The fault 

was cleared by the neighboring Zone 2 protection relays that have to open a number of circuit 

breakers including CB1, CB4, CB7, CB10, CB13, CB19, CB22, CB20, (the breakers for 

SWYDBus1), CB140 (the breaker for bus Sub5), CB3, CB5, CB8, CB11, CB14, CB17, CB20, 

and CB23 (the breakers for SWYDBus2) after an intentional time delay of 0.5 seconds. The 

simulation is not necessary because this will cause a loss of the entire switchyard and the all the 

reactors have to be tripped. The fault is close to the NPP switchyard and is extremely 

detrimental to the NPP if all of Zones 1, 2, and 3 protection is disabled.

4.4 Summary and Discussions

As seen in Section 4.3.1, for a fault originated in the transmission network, the closer the fault is 

to the NPP switchyard, the more severe impact it has on the NPP. While this might be wellknown, it may not be common for a NPP switchyard owner or a transmission network owner to 

recognize that a different or a tighter protection scheme is warranted for the NPP switchyard or 

transmission lines/substations nearby the NPP switchyard considering the fact that a utility 

tends to use the uniform protective schemes settings across the entire network owned and 

operated by the utility.

The performance variation of adopting different protective schemes/settings is significant, as 

shown by the simulation results presented in Section 4.3.2, especially when an additional 

breaker failure is considered following a fault occurrence. This clearly indicates that a tighter 

protective system applied at the NPP switchyard or the grid components close to the switchyard 

can enhance the fault ride-through capability of a NPP while the existing protection systems for 

the rest of the grid remain untouched. Therefore, it is desirable that the protection systems for 

the NPP switchyard be designed such that the backup clearing by the secondary protection 

system is instantaneous (e.g., without any intentional delay the backup clearing time can be less 

than 100 ms) even if one element of the protection system fails to operate and less than Zone 2 

time (e.g., less than 200 ms) even if one circuit-breaker fails to operate. If the critical clearing 
86

time is longer than the backup clearing time it may be necessary to install dual circuit-breaks in 

series to reduce the likelihood of protection system malfunction due to the circuit-breaker failure. 

The analysis performed in Section 4.3.2.3 shows that simply making the circuit breaker 

associated with the main generator and another grid component more reliable (e.g., by 

incorporating a double-bus-double-breaker structure into the breaker-and-a-half configuration, 

as shown in Section 2) in most cases can certainly improve the fault ride-through capability of a 

NPP.

While the analyses performed in Section 4.3.2 for this study show that the impact of protection 

system failures can be mitigated by minimizing the fault clearing time of backup protection 

systems, in actual practice, the effect that these protection system responses can have on 

overall power system stability and operating characteristics must also be analyzed. For 

example, the change in system impedance that results from disconnecting one or more system 

elements at a nuclear power plant may have an effect on the unit stability and system 

performance that is more severe than an extended fault clearing time. In some cases, 

disconnecting two or more elements at the NPP switchyard can result in unit instability even 

without the presence of a fault.

Another protection scheme is to use the anticipatory Zone 3 scheme, i.e., tripping selected 

healthy components that are connected to the faulted transmission line by using the Zone 3 

relays at the terminals of the faulted line. The anticipatory Zone 3 scheme will be beneficial 

when the primary protection system and the remote breaker failure backup protection fail since, 

otherwise, a much longer time delay is anticipated to clear the fault. However, this might be 

considered overly conservative because failures of both the primary and the backup protection 

are not always encountered and the tripping of healthy components may also adversely affect 

the normal operation of the grid. Based on this consideration, the anticipatory Zone 3 protection 

scheme is not included in the study.

The interaction between two NPP switchyards that are electrically located in close proximity to 

each other on the transmission grid is illustrated in subsection 4.3.3 by using a postulated 

scenario of a 90% fault of a transmission line followed by a breaker failure. The postulated 

scenarios shows that if a breaker failure protection scheme is available, the line fault plus the 

breaker failure will lead a loss of two transmission lines connecting the two switchyards in the 

manner shown in Figure 4-33. This kind of design may need to be reviewed carefully.

Reclosing is often used in transmission systems for the purpose of maintaining system integrity 

by reconnecting the isolated components back to the grid after a brief time delay provided that 

the fault is of the transient-type. Again, the selection of time delay settings of when to perform a 

reclosing is a utility-specific process. The reclosing issue is not studied in this report because 

we are focusing on the permanent-type faults. Attempts at reclosing will eventually fail under 

these kinds of fault situations. Therefore, in this study, blocking of automatic reclosing of circuit 

breakers in the electrical protection zones immediately adjacent to the NPP was found to 

minimize the risk of tripping the NPP due to an uncleared permanent fault. However, 

experience has shown that in many applications automatic reclosing, when supervised by a 

synchronism check relay, may improve electrical grid stability and continuity of the offsite power 

supply by improving the availability of stabilizing transmission system elements. Consequently, 

in practical application, the decision to enable or block automatic reclosing in the vicinity of a 

NPP should be based upon a technical analysis and evaluation of the risks of reclosing into a 

fault versus the risks of prolonged operation with a transmission line out of service.
87

The results in Section 4.3.4 are consistent with many of the past operating experiences, which

the cause of NPP trip or LOOP or blackout was found to be caused by inadvertently disabling 

some of the protective relays (maintenance errors). One of possible solutions is still the idea of 

having tighter protection schemes, i.e., by reducing the intentional time delay of the Zone 2 or 

Zone 3 relays. In this case, if the neighboring Zone 2 protection relays are actuated with a 

shorter time delay, the plant responses should be improved. Another potential solution is to 

install online monitoring devices on the more important relays and warn the load dispatcher or 

NPP operators.

The models used for the simulation are different and yet still show the same trends in terms of 

the plant responses to the faults at different locations. This indicates that the results obtained 

here should be somewhat independent of plant-specific models and can be generalized.

89

5 IMPORTANCE OF PROTECTION SYSTEMS MAINTENANCE

The general requirements for nuclear plant electric power systems are stated in 10CFR50-

Appdx A GDC-17, as they apply to the onsite and offsite power sources, their independence 

and redundancy, safety functions, and performance during design basis events. Furthermore, 

10CFR50.63, the station blackout rule requires plants to establish coping strategies for events 

involving the loss of preferred offsite power sources concurrent with a turbine trip and the 

unavailability of the onsite emergency ac power system.

During the review of operating experience regarding fault events that affected NPPs, it was 

noted that inadequate maintenance was frequently a cause or major contributor to the event. 

Personnel or maintenance/relay testing errors also caused blackout and disabled primary and/or 

backup protection design features. Circuit breaker failure, relay failures, setpoint drift or 

incorrectly set relays, wiring degradation, and degraded connectors were some of the conditions 

described that could be addressed by improved maintenance activities.

As shown by the analyses in Section 4, failure of protection system components, which is often 

caused by inadequate maintenance, was found to be a significant contributor to prolonging fault 

clearing time. This sometimes resulted in tripping of backup protection systems, which caused 

the loss of larger sections of the electrical system, that would otherwise not have been required 

had the primary protection system functioned properly.

5.1 Applicability of Maintenance Requirements to Offsite Power 

Systems

10CFR50-Appdx A GDC-18, “Inspection and testing of electric power systems,” requires that 

the electric power systems important to safety be designed in such a way as to permit the 

appropriate periodic inspection and testing of important areas and features, such as wiring, 

insulation, connections, and switchboards, to assess the continuity of the systems and the 

condition of their components. Specifically, GDC-18 states, in part, that:

“The systems shall be designed with a capability to test periodically (1) the operability 

and functional performance of the components of the systems, such as onsite power 

sources, relays, switches, and buses, and (2) the operability of the systems as a whole 

and, under conditions as close to design as practical, the full operation sequence that 

brings the systems into operation, including operation of applicable portions of the 

protection system, and the transfer of power among the nuclear power unit, the offsite 

power system, and the onsite power system.”

In addition, 10CFR50.65, the maintenance rule, requires that licensees “monitor the 

performance or condition of structures, systems, or components...in a manner sufficient to 

provide reasonable assurance that these structures, systems, or components...are capable of 

performing their intended functions.” Periodic inspection, monitoring, and functional testing is

accomplished for the onsite power distribution system, main generator and step-up transformer, 

and auxiliary transformers, that are included as part of the licensing basis of the NPP, through 

technical specifications surveillance testing and periodic preventive maintenance programs.

However, those structures, systems, and components comprising the offsite power system in 

the NPP switchyard, transmission lines, and external power grid, in general, reside outside of 

the jurisdiction of NRC regulatory requirements. As discussed previously in subsection 1.1.2
90

(and Appendix B), the deregulation of the electric utility industry raised concerns about 

maintaining the reliability of the power grid as the preferred power source for NPPs in a postderegulation environment in which the NPP, its switchyard, and the electrical transmission grid 

might be owned, operated, and maintained by different entities. The independent transmission 

system operators might not fully appreciate the regulatory requirements for offsite power 

sources as applied to NPPs and the operating and maintenance priorities of the independent 

transmission system operators would not necessarily coincide with those of the NPPs that they 

serviced.

The Federal Energy Regulatory Commission (FERC) is the federal agency responsible for the 

regulation of wholesale interstate electric power transactions. In this role it approves as 

mandatory and enforces the electric reliability standards developed by the North American 

Electric Reliability Corporation (NERC). As described in Appendix B of this report, NERC 

Standard NUC-001-2 specifically requires coordination agreements between the operators of 

nuclear generating stations and transmission owners/operators for the purpose of ensuring that 

reliable sources offsite power are available for the safe operation and shutdown of NPPs. 

These agreements identify nuclear plant interface requirements (NPIRs) which include 

operations and maintenance coordination activities, such as identification of maintenance 

requirements for equipment not under the ownership or control of the nuclear generating station 

operator and coordination of testing, calibration, and maintenance of onsite and offsite power 

supply systems and related components [NUC-001-02].

The documentation and implementation of programs specifically focused on the maintenance of 

all protection systems affecting the reliability of the bulk transmission grid are addressed in 

NERC Standard PRC-005-2, “Protection System Maintenance” [PRC-005-2]. While NUC-001-2 

directly covers the interface requirements between the electrical transmission system and 

nuclear power plants, the specific protection system maintenance activities governed by PRC005-2 are equally important because of the critical role that reliable and efficient operation of the 

interfacing transmission grid protection system can play in supporting the safe and reliable

operation of nuclear power plants.

5.2 NPP Offsite Power Fault Events Affected by Inadequate 

Maintenance

The analyses presented in Section 4 of this report, demonstrate that the rapid identification and 

isolation of transmission system electrical faults by the electrical protection systems was of key 

importance in minimizing the effects of grid transients on a NPP. The more rapid the response

of the protection system, the more likely it was for the protective relaying to minimize the 

magnitude and duration of electrical disturbances cause by external faults. This in turn serves 

to further improve power system stability by maintaining local grid voltage and VAR support.

The Section 4 analyses show that if the protection system operates as designed, the adverse 

effects of external faults on nuclear plant performance can be minimized. A critical factor in 

ensuring the rapid and reliable operation of the electrical protection system is good maintenance. 

Thus, the benefit of frequent rigorous periodic inspection, maintenance, calibration and 

functional testing is that it provides assurance that the grid protection systems, backup 

protection systems, reclosing relaying schemes, and breaker failure protection schemes will 

operate as designed when challenged by an electrical fault or other grid transient event.
91

Several of the external grid events, in Subsection 1.1.3, that propagated into widespread power 

system disturbances that significantly affected NPPs, could in fact have been completely 

avoided, or at least mitigated, if adequate periodic calibration and functional testing of the 

transmission grid electrical protection systems had been taking place. That is, the protection 

systems, as designed, would probably have been able to minimize or, completely avoid, the 

resulting nuclear plant trips and losses-of-offsite power, had they operated correctly.

For example, the external fault event at the Palo Verde Nuclear Generating Station (PVNGS) on 

June 14, 2004 was initiated by single-line-to-ground failure on a contaminated phase conductor 

insulator string along the 230kV West-Wing to Liberty transmission line approximately 47 miles 

from the plant. The breaker at the remote end of the line tripped. The protective relaying 

scheme at the near end substation received a transfer trip signal actuating an auxiliary relay 

(Westinghouse, Type AR) in the tripping scheme for the two breakers connected to the faulted 

line. The AR relay had two redundant pairs of contacts connected to two redundant trip coils in 

the breaker at each end of the faulted line. Unfortunately, both pairs of contacts were actuated 

by a single non-redundant lever arm in the AR relay and only one or two of the contacts for the 

remote end breaker made up. Due to misalignment of the AR relay contacts, the near end 

breaker did not receive a trip signal and the line fault persisted for approximately 38 seconds as 

the fault cascaded into the protective tripping of a number of 230kV and 525kV transmission 

lines, which ultimately led to the Loss of Offsite Power (LOOP) at the Palo Verde switchyard and 

the tripping of all three nuclear units. [IN2005-15, and PVNGS LER 50-528/2004-006-00] Thus, 

the root causes for the event were improperly adjusted contacts in the non-redundant AR relay 

tripping scheme design. At least one, and perhaps both, of these inadequacies could have 

been detected by more frequent and rigorous protection system inspection and maintenance.

Another example, affecting the Peach Bottom Atomic Generating Station (PBAGS), occurred on 

September 15, 2003 when a lightning strike on one phase of a 230kV transmission line, 

approximately 35 miles northeast of the plant, arced to ground for more than 2.5 seconds

damaging the insulator [IN 2004-15]. The fault condition was cleared upon the second attempt 

at automatic reclosing when the line was re-energized and did not trip out in spite of the thermal 

damage to the insulator. The two independent protection schemes provided to isolate faults of 

this type had failed to function. The NRC Augmented Inspection Team report [AIT 

05000277&278/2003013] noted that:

“The primary and backup protection from the directional ground fault relay used fault 

current and locally generated polarizing voltage to determine fault condition. The 

primary relay utilized a signal from the bus potential device and the backup relay utilized 

a signal from the line potential device. The primary protection circuit was found to have a 

mechanically failed fuse and the backup protection circuit had a loose connection on a 

screw terminal block.

“Because the primary and backup protection in the faulted zone did not isolate the fault,

the faulted condition was sensed at a greater distance and the automatic isolation

expanded to a larger zone. The system outage spread through several other

substations for periods up to 4 hours and 43 minutes. The Nottingham substation did

not isolate the spread at that substation because the directional ground relay protection

was not activated when the new protective relay system was put into service.”

The cascading trips that spread throughout the grid resulted in a loss of 3 of the 4 offsite power 

sources supplying the PBAGS site as well as the power source designated for station blackout 

recovery, for more than 16 seconds, causing both nuclear units to trip automatically. The 
92

mechanically failed fuse and loose connection on the backup protection circuit for the faulted 

transmission line would have been detected by timely periodic inspection and maintenance for 

the protection system. Similarly, more frequent inspection and maintenance would have 

detected the inactive directional ground relay protection at the Nottingham substation that could 

have stemmed the further spread of the disturbance.

A LOOP and two-unit trip from full power occurred at the Catawba Nuclear Generating Station 

on May 20, 2006 as a result of an initial phase-to-ground fault on a current transformer (CT) in 

the 230kV switchyard associated with the Unit 1A main step-up transformer differential 

protection followed almost immediately by a second CT fault on the switchyard bus differential 

protection CT [IN 2007-14]. The Catawba switchyard is configured in a breaker-and-a-half 

arrangement and is protected by a bus differential protection scheme. It was subsequently 

determined by the NRC Augmented Inspection Team [AIT 05000413&414/2006009] that certain 

switchyard bus differential relay tap settings were set at a value too low to handle the fault 

currents experienced during this transient. Modifications to the original switchyard bus 

differential relay tap settings were made by the relay engineering department in 1979 and again 

in 1981. However, as a result of inadequate maintenance/modification procedures and human 

error, the correct revised settings were never properly implemented at the Catawba switchyard 

protective relaying [IN 2007-14 and AIT 5000413 & 414/2006009].

The AIT determined that:

“If the actual relay settings in the switchyard had been set appropriately, the event would

have been limited to the actuation of main step-up transformer 1A differential protective

relaying and...[one] bus differential protective relaying to address the fault on the Xphase of the CT associated with PCB 18. Actuation of the main step-up transformer 2B

differential protective relaying would have occurred to address the fault on the Y-phase

of the CT associated with PCB 23.”

This would have limited the effects of the transient such that:

“...both units would have runback to 48% main generator electrical output. In 

combination with the number of transmission lines available, the design of the 

switchyard should have prevented Units 1 and 2 from losing offsite power.”

On February 15, 2007, the failure of a power circuit breaker in the Jocassee Hydro Station 

switchyard caused a single-line-to-ground failure, that was detected and isolated by relaying at 

the Oconee Nuclear Station switchyard. However, the resulting prolonged (less than 1 second) 

grid disturbance led to a trip of Oconee Units 1 and 2. A wiring design error on the loss-ofexcitation relays caused a main generator lock-out, turbine trip, and bus transfer from normal to 

startup sources on Oconee Units 1 and 2. Both reactors were subsequently tripped by the 

reactor coolant pump power monitors, which correctly sensed the voltage transient and resultant 

power sag. Incorrect settings on the auxiliary switch fast contacts of the normal main feeder 

bus breakers caused a slow bus transfer of 4160 volt loads on Oconee Unit 1, leading to a loss 

of normal feedwater flow. This necessitated reactor cool down to Mode 4, which was 

accomplished by procedure with emergency feedwater and atmospheric dump valves. [LER 

269/2007-01-01] 

The licensee reported in the LER analysis of the event [LER 269/2007-01-01] that protection 

system errors had remained undetected since their original installation:
93

“A properly designed protective relaying scheme should have enabled the units to 

withstand a switchyard transient of this magnitude and duration. However, a wiring 

design error in the loss-of-excitation relay (40-1) caused the relay to trip the Unit 1 and 2 

generators and turbines through the generator lockout scheme. A latent design error 

existed in this relay and its leads were installed according to this error at initial 

installation (i.e., rolled leads). Had this error not been present, testing has shown that the 

relay would not have tripped the unit.

“The slow bus transfer was caused by incorrect setting of the fast contacts located on 

the auxiliary switches on the Main Feeder Bus Normal Breakers (N-Breakers). This error 

has been present since original installation. The incorrect setting caused the fast

contacts to operate slower than designed. The slower operation of the fast contacts 

prevented completion of a fast transfer in less than 60 milliseconds as designed.”

On August 25, 2007, both Unit 1 and Unit 2 at the Catawba Nuclear Station experienced a 

voltage dip of approximately 0.462 second duration when a main step-up transformer at a 

merchant generating plant connected to Duke's 230kV grid faulted. The transformer differential 

protection at the merchant plant failed to isolated the faulted equipment. Electrically, the faulted 

transformer was three switchyards away from the Catawba switchyard. The electrical grid 

disturbance caused all four Emergency Diesel Generators (EDGs) to start but ran unloaded, as 

designed, because the condition existed for less than the 8.5 seconds required for separation 

from offsite power. After an hour and a half, the local transmission operator notified the plant 

that the faulted transformer had been isolated from the transmission system and the plant’s 

EDGs were secured and returned to standby. [LER 413/2007-003-00] 

The response of plant equipment to this electrical grid disturbance was as expected. The 

transmission system relaying also operated as designed. Failure of the local protection at the 

merchant generating plant to detect and promptly isolate the faulted transformer produced an 

unbalanced system disturbance that was of a large enough magnitude and duration to actuate 

degraded grid protection at the Catawba plant, that was three switchyards away from the 

initiating disturbance.

In an event on February 26, 2008, Turkey Point Nuclear Plant units 3 and 4 automatically 

tripped from 100% power due to a momentary power fluctuation caused by grid instabilities. 

Each reactor tripped when both channels of safety-related 4 kV bus undervoltage relays 

actuated after a one second time delay. Protection against a momentary grid disturbance is a 

feature of Turkey Point's electrical system; however, the duration of the condition exceeded the 

time delay resulting in the actuation of the 4 kV bus undervoltage relays. The source of the grid 

disturbance was a short circuit to ground on a substation in Dade County, Florida, compounded 

by human error in troubleshooting the substation protection system [LER 250/2008-001-00].

Finally, on August 14, 2003, an electrical power disturbance in the northeastern part of the 

United States caused nine NPPs in the US to trip as a result of voltage and frequency 

fluctuations experienced in the initial stages of the blackout [Kirby, Kueck, et. al. ORNL 2007]. 

Eight of these plants, along with one other nuclear plant that was already shutdown at the time, 

experienced a loss of offsite power (LOOP). Several of these nuclear plants were located in 

transmission corridors operating at that time under conditions of inadequate reactive power and 

were thus required to supply reactive power at their maximum capability in order to support grid 

voltage. As a consequence of the regional power grid operating at the limits of its capacity and 

capability, the trip of a large nuclear generating unit and the resulting sudden removal of the 

local reactive power support it has been providing to the transmission grid inevitably led to the 
94

degradation of voltage at the NPP switchyard below Technical Specification limits. The August 

2003 event, which was initiated by an overgrown tree coming into contact with electrical 

transmission lines, resulted in cascading outages, caused trips of nuclear stations, and disabled 

offsite power supplies. The incident highlighted the importance of the design and maintenance 

practices for NPP switchyard protection systems and demonstrated how the operational 

interaction between the power grid and large nuclear generating units can affect the reliability 

and availability of the nuclear plants' offsite power sources.

These selected examples demonstrate the importance of the proper operation of the electric 

protection equipment on grid transmission lines, transmission grid substations, and nuclear 

plant switchyards. Several of these grid disturbance events originated at physically remote 

locations away from the nuclear plants, but had a significant electrical impact that affected 

nuclear plant performance and the integrity of their offsite power sources. Consequently, it is 

suggested that the electrical protection systems serving transmission lines, substations, nuclear 

plant switchyards, and local generating units (both nuclear and non-nuclear) that are shown, 

through power system analysis (See Regulatory Issue Summary 2004-05 and Regulatory 

Guides 1.160 and 1.182) and operating experience, to have a significant influence on the 

reliability and integrity of the offsite power sources and electric grid conditions at the NPP 

switchyard buses be considered for augmented periodic inspection, calibration, and 

maintenance.

5.3 Benefits of Improving Offsite Power System Maintenance

When one considers the tremendous cost of a single NPP trip event in terms of the immediate 

lost generation revenue, cost of more expensive replacement generation for the duration of the 

outage, additional challenges to nuclear safety systems, additional challenges and wear on 

electrical transmission system equipment in response to the transient, and the potential 

damaging effects of widespread electrical grid disturbance, it is easy to see that measures to 

reduce the occurrence of NPP trips and loss-of-offsite power events would be extremely 

beneficial.

As seen in the examples provided in subsection 5.2 above, inadequate inspection and 

maintenance of electrical protection systems serving transmission lines, substations, nuclear 

plant switchyards, and local generating units (both nuclear and non-nuclear) that had a 

significant influence on electrical conditions at the switchyard buses of NPPs can lead to 

unnecessary LOOPs and plant trips. Incorrect relay settings, damaged or degraded protection 

systems, design inadequacies, and other protection system malfunctions would be revealed by 

more rigorous and more frequent protection system inspection, calibration and functional testing, 

and preventive maintenance. Many of the LOOPs and plant trips, such as those in the above 

examples, would otherwise have been avoided if the existing properly-designed protection 

systems had operated as originally intended. 

The analytical examples presented in Section 4 of this report clearly demonstrate that the more 

rapidly the protection system can identify the occurrence of an electrical fault and isolate it, the 

lesser the magnitude of the disturbance and the shorter the duration of the transient as 

experienced at the nuclear plant switchyard buses. Therefore, it is of utmost importance that 

the electrical protection systems operate as designed to assure that faults are detected and 

cleared as rapidly as possible. It is suggested, that in some cases it may be possible to reduce 

the time delays for backup protection or breaker failure schemes to reduce or mitigate the 

effects of electrical transient events. By minimizing the magnitude and duration of a disturbance 

at the NPP switchyard, it may even be possible to allow the plant to remain on line, or “ride 
95

through,” some disturbances to maintain the beneficial voltage and VAR support the nuclear 

plant generator is supplying to the grid, thereby contributing to the overall stability of the 

transmission system.

A critical factor, therefore, in ensuring the rapid and reliable operation of the electrical 

protection system is good maintenance. Thus, the benefit of frequent rigorous periodic 

inspection, maintenance, and calibration and functional testing is that it provides assurance that 

the grid protection systems, backup protection systems, reclosing relaying schemes, and 

breaker failure breaker protection schemes will operate as designed when challenged by an 

electrical fault or other grid transient event. Of course, an evaluation should be made of the 

benefits of an increased schedule of maintenance activities against the risk of potential system 

trips resulting from carrying out this maintenance work.

It is suggested that the NPP switchyards, and the transmission lines, critical nearby electrical 

substations, and nearby generating units that support the offsite power supply to NPPs be given 

priority consideration with regards to reliability importance, operating activities, and periodic 

protection system inspection, maintenance, and testing. This is justified by analytical examples 

in Section 4 that demonstrate the importance of protection system timing on the effects of 

external fault events on NPP performance, reliability of offsite power, and local grid voltage and 

VAR support.

It should be noted that NERC Standard PRC-005-2, “Protection System Maintenance” [PRC005-2], was approved by the NERC Board of Trustees on November 7, 2012 and is awaiting 

follow on regulatory action by FERC. PRC-005-2 consolidates several previous NREC 

protection system standards and incorporates the findings and recommendations of the NERC 

System Protection and Control Task Force report “Protection System Maintenance,” 

(September 13, 2007). By considering frequency-based as well as performance-based 

approaches to protection system maintenance programs, PRC-005-2 seeks to strike an 

optimum balance between security and dependability. Once approved for implementation by 

FERC, PRC-005-2, together with the interfacing requirements of NUC-001-2 should help to 

improve transmission grid protection system maintenance practices and potentially avoid or 

mitigate the types of problems described in subsection 5.2. 

The case for effective protection system maintenance is strongly insinuated by the several 

examples examined as part of this study, although a comprehensive review of external 

transmission system fault events was not performed as part of this study. It is suggested that a 

thorough review of external fault events be performed in the future to update earlier studies that 

compared grid reliability and performance prior to, and after deregulation of the electric utility 

industry. This would help to verify whether FERC and NERC efforts to improve grid reliability 

through standards such as NUC-001-02, regulatory enforcement, and cooperative activities with 

NRC, have in fact achieved measurable improvements. Counter to these efforts, however, are 

the negative effects of aging T&D components and equipment, overloading of limited existing 

transmission resources, aging degradation electrical protection systems, increased overall 

demand, increased peak demand, and inadequate development of new transmission capacity. 

An updated comprehensive review and assessment of grid related disturbances that affected 

NPPs would provide a quantitative measure of the trends in transmission grid and offsite power 

reliability and external faults effects.

97

6 SUMMARY AND CONCLUSIONS

6.1 Summary

The important observations and conclusions that were identified during the NPP reviews and 

the systems modeling and analyses in this study are summarized below:

• Most of the NPP switchyards reviewed used the breaker-and-a-half bus arrangement 

which provides a high level of reliability and flexibility. The most critical circuits were 

modified to a full double breaker arrangement in some applications to provide an even 

higher level of reliability. See subsection 2.2 and 4.3.2.4.

• The primary switchyard bus protective scheme was the current differential protection 

scheme with various breaker failure schemes typically serving as backup.

• Circuit breakers at the switchyard terminals of departing transmission line circuits were 

incorporated into the overlapping protective zones of the transmission lines. They were 

protected by electrical protection schemes using telelcommunications or distance 

relaying. The switchyard circuit breakers were also generally incorporated into breaker 

failure protection schemes for the individual transmission lines.

• Simulation studies confirmed that the faster an external transmission grid fault could be 

detected and isolated, the lesser is the effect of the transient experienced at the NPP 

switchyard bus. The closer a fault is to the NPP switchyard the greater the effect on the 

NPP.

• Rapid detection and clearing of grid electrical faults helps to minimize the effects of a 

prolonged electrical transient that could lead to a NPP trip. The sudden loss of the 

voltage and real/reactive power support provided by the nuclear plant’s main generator 

is itself a destabilizing event that can potentially lead to an extended degradation of 

system voltage at the NPP switchyard and resulting in a LOOP following a trip of the 

plant.

• In general, protective schemes have already been designed and coordinated to detect 

and isolate faults as rapidly as the equipment will allow. It may be possible to adjust the 

settings of existing Zone 2 and Zone 3 protective relays and minimize intentional time 

delays in the protective schemes to achieve a more rapid protection system response. 

In this case, Zone 3 protective schemes will function as an anticipatory trip, as discussed 

in Section 4.3.2.3. As a point of emphasis, consideration of anticipatory Zone 3 

protection schemes must be very carefully analyzed to be balanced against coordination 

with neighboring protection schemes to ensure that disruption to the system is minimized. 

• A more effective approach is to perform more frequent and rigorous inspection, 

preventive maintenance, and testing of the most critical protection system components 

to assure that they will function as designed when required. 

• Electrical protection schemes using telecommunications (pilot relay schemes) provided 

the fastest and most reliable protection for transmission line circuits, and per the results 

of the simulation studies, they helped to minimize the effects of external faults as seen 

from the NPP switchyard. Improvements in the performance and reliability of multifunction digital protective devices, together with the lower costs and high reliability of 

various modern telecommunications links that are currently available, have made the 
98

telecommunications-based electrical protection schemes the preferred method for

transmission protection, particularly for lines that are associated with NPPs.

• The use of telecommunications-based relaying as part of the breaker failure and backup 

protection schemes for NPP switchyards and associated transmission circuits is also 

highly desirable. The high speed, sensitivity, and reliability of telecommunications-based

relaying in backup protection helps to minimize the effects of primary protection failures.

6.2 Conclusions

The purpose of this study is to demonstrate and verify through modeling and simulation that 

precise and faster clearing of faults can in fact limit damage and improve plant ride-through, 

which is one of the main reasons for developing and deploying telecommunication-based relay 

schemes. The practical application of this approach into an existing protection scheme, which 

would be the equivalent of upgrading to a faster protective relay, would of course have to be 

analyzed carefully to take into consideration the coordination of all affected protection system 

timing intervals as well as the effects that the tripping of transmission element(s) can have on 

system stability. The high speed, precision, and reliability of telecommunication-based 

protection now being deployed allows ISOs, utilities, and NPP operators to take advantage of 

the potential improvements that faster clearing times can provide as we have shown in our 

study.

A review of NPP switchyards and protection systems was performed as part of this project. 

Design features and configurations identified in the review were used to develop simulation 

models, using ETAP® power system analysis software tools, for several NPP distribution 

systems, their high voltage switchyards, and their transmission interfaces with the electric power 

grid. Based on the reviews and analyses described herein on the effects of external electrical 

faults on NPPs, the following conclusions are offered to maintain the highest reliability of the 

electric power grid while continuing to maintain and improve the safe and reliable operation of 

nuclear power plants:

• Simulation studies confirmed that the faster an external transmission grid fault could be 

detected and isolated, the less is the effect of the transient experienced at the NPP 

switchyard bus. Reviewing the settings of protective relays and intentional time delays 

in existing electrical protection schemes may be practical to determine whether 

modifications can be made to achieve a more rapid protection system response without 

compromising the balance between security and dependability. In particular, when the 

primary protection scheme fails, the backup scheme becomes critical to isolate the 

fault(s) and the intentionally built-in time delay of the backup scheme significantly 

prolongs the clearing time. Under this situation, if the time delay can be minimized, the 

impact that a fault at or close to the NPP switchyard will have on the normal operation of 

NPPs can be significantly reduced.

In general, analyzing the impacts that various protection system scenarios will have on 

the ability to meet the NPIRs presented in NUC-001-2 for nuclear power plants may 

improve the technical basis when altering or upgrading existing electrical system 

protection schemes. Faster fault clearing generally results in improved system 

performance, but this enhancement may only be valid if other transmission system 

elements are not tripped in addition to the faulted element. Therefore, careful 

consideration must be given to the proper setting and coordination of the time delays for
99

tripping transmission and switchyard components to ensure a balance between security 

and dependability.

• Electrical protection schemes using telecommunications (pilot relay schemes) provide 

the fastest and most reliable protection for transmission line circuits, and per the results 

of the simulation studies, they helped to minimize the effects of external faults as seen 

from the NPP switchyard. Therefore, incorporating protection schemes using 

telecommunications is an option worth considering when replacing or upgrading existing 

transmission line protection systems, particularly for lines that are in the zone of 

influence of the NPPs.

• The use of electrical protection using telecommunications as part of the breaker failure 

and backup protection schemes for NPP switchyards and associated transmission 

circuits may improve the reliability of the protection system. The high speed, sensitivity, 

and reliability of protective relaying using telecommunications in backup protection helps 

to minimize the effects of primary protection failures.

• Reliability in switchyards incorporating the breaker-and-a-half bus arrangement could be 

improved for the most critical transmission circuits and the main generator connection by 

modifying the circuit breaker arrangement for those connections to a full double-bus, 

double-breaker arrangement.

• Improving the reliability of primary protection of the NPP switchyard protection systems 

can help them cope with the fault more effectively. This can be achieved by using 

redundant protective equipment such as dual relays, circuit-breakers, and 

telecommunication channels.

• Incorporating the NPIR into transmission system studies affecting NPPs as stated by 

NERC Reliability Standard NUC-001-2 may identify and address contingencies that 

require the application of mitigation plans to avoid loss of offsite power events (LOOPs).

• It also needs to be pointed out that redundancy is often defeated by common cause 

failures even for the redundant equipment of diverse designs. Hence, adjusting the 

settings of existing protection systems to reduce and/or avoid time delays, especially 

those of the backup protection schemes, is still considered necessary and very important 

even while increasing the redundancy of NPP switchyard protection systems.

• Conducting grid transient analyses to identify those relays and contacts that can have a 

significant impact on conditions at the NPP switchyard buses may provide valuable 

insights when reviewing and/or updating the protection schemes at or near the NPP 

switchyard.

• As a consequence of the above observations, it follows that protection systems and 

equipment in selected nearby switchyards, transmission lines, substations, and large 

generating units (that have been shown by analysis to have a significant impact on 

nearby NPPs), may be subjected to a more frequent and augmented level of inspection, 

testing, and preventive maintenance. 

• Several recent events examined as part of this study were caused by or exacerbated by 

inadequate protection system maintenance. A comprehensive review of external fault 
100

events may be worthwhile to update the results of earlier studies that compared grid 

reliability and performance prior to, and after deregulation of the electric utility industry. 

This would help to verify the effectiveness of FERC and NERC efforts to improve grid 

reliability through standards, regulatory enforcement, and cooperative activities with 

NRC. It would also provide a quantitative measure of the current status and 

performance trends of the electrical transmission grid with respect to the negative effects 

of aging T&D components and equipment, overloading of limited existing transmission 

resources, aging degradation electrical protection systems, increased overall demand, 

increased peak demand, and inadequate development of new transmission system 

capacity.

• Efforts to identify necessary changes to the FERC/NERC standards that address 

protective relaying schemes and the nuclear plant interface with the transmission grid

may be worthwhile. Combined efforts from the NRC, FERC/NERC, the nuclear industry, 

and affected transmission system operators could lead to the development of industrywide standards for: 1) the interface between NPPs and the transmission (or 

subtransmission) networks, 2) the electrical protection schemes for the interface, and 3) 

the maintenance of the primary and secondary protection equipment at the interface.

• In this study, blocking of automatic reclosing of circuit breakers in the electrical 

protection zones immediately adjacent to the NPP was found to minimize the risk of 

tripping the NPP due to an uncleared permanent fault. Experience has shown that in 

many applications automatic reclosing, when supervised by a synchronism check relay, 

may improve electrical grid stability and continuity of the offsite power supply by 

improving the availability of stabilizing transmission system elements. In practical 

application, the decision to enable or block automatic reclosing in the vicinity of a NPP 

should be based upon a technical analysis and evaluation of the risks of reclosing into a 

fault versus the risks of prolonged operation with a transmission line out of service.

• Monitoring the switchyard and transmission line protection system relays and fuses that 

would alert operators to the occurrence of failures in protection system circuits may 

enhance the reliability of the protection system. Several of the operating experience 

examples of NPP trip and LOOP in this study could have been avoided if circuit failures 

in the protection system had been detected immediately and corrected before they were 

challenged.

• It is important that the NPP switchyards be reviewed and treated differently than the 

regular switchyards/substations in the transmission network in terms of design, 

operation, and maintenance in order to achieve improvement in the reliability of the 

NPPs and subsequently reducing the risk associated with tripping NPPs due to external 

electrical faults.

• Since the transmission system and the grid are owned and operated by other entities, it 

is NPP owners' responsibilities to ensure that NPP design requirements, modification, 

and enhancements required to maintain a reliable and stable electric power system 

including inadvertent trip of NPPs are identified and communicated promptly to the 

respective transmission and grid operating entities.

Three detailed analytical models of nuclear plant electrical systems, switchyards, and their 

interfacing connections with the local electric power transmission grid were developed as part of 
101

this project to study effects of electrical transients and other disturbances on the NPP 

performance. One of these models also included interconnections with two other nuclear 

generating stations so that detailed analysis of the electrical interactions between nearby 

nuclear units could be undertaken. The models were developed using the ETAP® power 

system analysis software. The simulations provide accurate representations of actual NPP 

configurations and power grid interconnections, and as such, have provided important insights 

into the effects of electrical faults on the performance of plant safety systems and other critical 

non-safety equipment.

The three NPP simulation models developed for this project, along with detailed in-plant 

electrical distribution models for a BWR plant and a PWR plant developed previously for an 

earlier project [NUREG/CR-6950], are very powerful simulation tools that can be used to study a 

variety of important contemporary power grid degradation issues affecting NPPs. Among these 

issues that can be studied are:

• Electric power transmission grid reliability performance and the effect on offsite power 

sources, 

• Interactions between multiple NPPs under transient conditions,

• Interactions between NPPs and large non-nuclear generating stations under transient 

conditions,

• NPP operational considerations during overloaded grid conditions,

• Power quality issues with offsite power sources, and 

• Distribution system performance during sustained grid undervoltage and underfrequency 

conditions

• Class 1E motor starting during off-normal grid conditions

• Class 1E motor starting during off-normal plant operating configurations

• Arcing fault studies (medium-voltage and low-voltage) and the development of improved 

switchgear energetic fault/fire damage models

• Verification of reliability assumptions for the Class 1E electrical system

• Effects of aging degradation on electrical system grounding performance

Power system analyses using these detailed power system simulation models would be quite 

beneficial in evaluating the performance of nuclear plant electrical distribution systems under a 

variety of power system contingencies, plant operating configurations, and plant operating 

conditions as noted above.

103

7 REFERENCES

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[USNRC RG 1.155] Regulatory Guide 1.155, “Station Blackout.”

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104

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GENERATING STATION,” US NRC, June 1, 2005.

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MAINTENANCE,” US NRC, July 21, 2005.

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UNIT 1, IN SWEDEN,” US NRC, August 17, 2006.

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[GL 2006-02] NRC Generic Letter GL 2006-02, “GRID RELIABILITY AND THE 

IMPACT ON PLANT RISK AND THE OPERABILITY OF OFFSITE 

POWER,” US NRC, February 1, 2006.

[10 CFR 50.65] Title 10 of the Code of Federal Regulations, Part 50.65 

“Requirements for monitoring the effectiveness of maintenance at 

nuclear power plants.”

[NUREG-0800, Revision 4, March 2007]

US NRC NUREG-0800, “Standard Review Plan,” Chapter 8, 

“Electric Power,” Revision 4, March 2007.

[USNRC RG 1.160] Regulatory Guide 1.160, “Monitoring the Effectiveness of 

Maintenance at Nuclear Power Plants,” Revision 2, March 1997.

[USNRC RG 1.182] Regulatory Guide 1.182, “Assessing and Managing Risk Before 

Maintenance,” May 2000.

[RIS 2004-05] US NRC Regulatory Issue Summary 2004-05, “Grid Reliability and 

the Impact on Plant Risk and the Operability of Offsite Power,” 

April 15, 2004.
105

[Kirby, Kueck, et. al. ORNL 2007]

B. Kirby, J. Kueck, et. al., Nuclear Generating Stations and 

Transmission Grid Reliability,” ORNL, 2007.

[LER 40815] US NRC Licensee Event Report (LER) 50-528/2004-006-00, 

“Loss of Offsite Power – Three Unit Trip,” Palo Verde Nuclear 

Generating Station, June 14, 2004.

[Lindahl – Comments to BNL - 9/17/2010]

Lindahl, Sture, Comments to "Description of NPP Modeling and 

Analytical Approach to Studying Impacts of Protection Settings on 

NPP Responses to External Faults," September 17, 2010.

[AIT 05000277&278/2003013]

US NRC Augmented Inspection Team Report, “NRC Augmented 

Inspection Team (AIT) 05000277/2003013 and

05000278/2003013, and Preliminary White Finding - Peach 

Bottom Atomic Power Station,” December 18, 2003.

[AIT 05000413 & 414/2006009] 

US NRC Augmented Inspection Team Report, “Catawba Nuclear 

Station - NRC Integrated Inspection Report 05000413/2006003 

and 05000414/2006003,” July 28, 2006.

[LER 277/2003-004-00] US NRC Licensee Event Report (LER) 50-277/2003-004-0, “Units 

2 and 3 Automatic Scrams Resulting from an Off-Site Electrical 

Grid Disturbance,” Peach Bottom Atomic Power Station, Units 2 & 

3, September 15, 2003.

[LER 269/2007-001-01] US NRC Licensee Event Report (LER) 50-269/2007-001-01, “Dual 

Unit Trip from Jocassee Breaker Failure,” Oconee Nuclear Station, 

Unit 1, February 15, 2007.

[LER 250/2008-001-00] US NRC Licensee Event Report (LER) 50-250/2008-001, “Human 

Error Causes Grid Disturbance Resulting in a Dual Unit Trip,” 

Turkey Point Unit 3, February 26, 2008.

[IN 2006-18] NRC Information Notice IN 2006-18, “SIGNIFICANT LOSS OF 

SAFETY-RELATED ELECTRICAL POWER AT FORSMARK, 

UNIT 1, IN SWEDEN,” US NRC, August 17, 2006.

[IN 2006-18, Supplement 1] NRC Information Notice IN 2006-18, Supplement 1, 

“SIGNIFICANT LOSS OF SAFETY-RELATED ELECTRICAL 

POWER AT FORSMARK, UNIT 1, IN SWEDEN,” US NRC, 

August 10, 2007.

[Raughley & Lanik, February 2002]

W. Raughley and G. Lanik, “Operating Experience Assessment -

Energetic Faults in 4.16 kV to 13.8 kV Switchgear and Bus Ducts 

that Caused Fires in Nuclear Power Plants 1986–2001,” US NRC, 

February 2002.
106

[NUREG/CR-6950, October 2007]

NUREG/CR-6950, “Effects of Switchgear Aging on Energetic 

Faults,” Brookhaven National Laboratory for NRC/RES, October 

2007.

[Russell & Kueck – Dec 91] 

W. Russell & J. Kueck, “Considerations for Improving the 

Reliability of the Off-Site Power Supply for Nuclear Generating 

Stations,” IEEE Transactions on Energy Conversion, Vol. 6, No. 4, 

December 1991.

Section 2 – Distance relaying, protection systems using telelcommunications, and 

breaker failure:

[10 CFR 50, Appendix A, GDC 17]

Title 10 of the Code of Federal Regulations, Part 50, Appendix A, 

“General Design Criteria for Nuclear Power Plants,” Criterion 17 -

Electric Power Systems.

[10 CFR 50.63] Title 10 of the Code of Federal Regulations, Part 50.63 “Loss of all 

alternating current power.”

[USNRC RG 1.155] Regulatory Guide 1.155, “Station Blackout.”

[IEEE Std. 765-2006] IEEE Std. 765-2006, “Preferred Power Supply (PPS) for Nuclear 

Generating Stations,” Institute of Electrical and Electronics 

Engineers, New York, 2006.

[IEEE Std. 308-2001] IEEE Std. 308-2001, “Standard Criteria for Class 1E Power 

Systems for Nuclear Generating Stations,” Institute of Electrical 

and Electronics Engineers, New York, 2001.

[NUREG-0800, Revision 4, March 2007]

US NRC NUREG-0800, “Standard Review Plan,” Chapter 8, 

“Electric Power,” Revision 4, March 2007.

[NUREG/CR-6950, October 2007] 

NUREG/CR-6950, “Effects of Switchgear Aging on Energetic 

Faults,” Brookhaven National Laboratory for NRC/RES, October 

2007.

[Mazumdar & Chiramal, Oct 1991] 

S. Mazumdar & M. Chiramal, “Bus Transfer Practices at Nuclear 

Plants,” IEEE Transactions on Power Delivery, Vol. 6, No. 4, 

October 1991.

[MacDonald 2003] McDonald, John D., “Electric Power Substations Engineering,” 

CRC Press, New York, 2003.
107

[Daume – Feb 2007] J. Daume, “High Voltage Transmission Practices,” Presentation, 

Bonneville Power Association, February 2, 2007.

[GER-3965] G. E. Alexander and J. G. Andrichak, Evaluating Line Relaying 

Schemes in Terms of Speed, Security and Dependability, GER3965, GE Power Management.

[Kundur 1993] P. Kundur, Power System Stability and Control, McGraw-Hill, Inc, 

1993.

[IEEE Std. C37.113-1999] IEEE Std. C37.113-1999 “Guide for Protective Relay Applications 

to Transmission Lines,” Institute of Electrical and Electronics 

Engineers, New York, 1999.

[CIGRE JWG 34/35.11-2001] 

“Protection Using Telecommunications,” Technical Brochure No. 

192, CIGRE JWG 34/35.11, Paris 2001.

[Lindahl-2011] S. Lindahl, SLi-2011-009, Version B, “Comments to Susceptibility 

of Nuclear Stations to External Faults,” May 18, 2011.

[IEEE C37.91-2008] IEEE Std C37.91-2008, “Guide for Protecting Power 

Transformers,” Institute of Electrical and Electronics Engineers, 

New York, May 30, 2008.

[IEEE PC37.119-2005] IEEE Std 37.119-2005, “Guide for Breaker Failure Protection of 

Power Circuit Breakers,” Institute of Electrical and Electronics 

Engineers, New York, 2005.

[IEEE Std. C37.234-2009] IEEE Std. C37.234-2009, “Guide for Protective Relay Applications 

to Power System Buses,” Institute of Electrical and Electronics 

Engineers, New York, 2009.

[Mason 1956] C. Russell Mason, “The Art and Science of Protective Relaying.” 

Engineering Planning and Development Section, General Electric 

Co., John Wiley & Sons, New York, 1956.

[Blackburn, et. al. – 1976] J. L. Blackburn, et. al., “Applied Protective Relaying,” 

Westinghouse Electric Corp., Relay Instrument Division, Newark, 

NJ, 1976.

[Svensson, B.] “Tolkning av SvKFS 2005:2 relaterat till påbörjat projekt Puls för 

effekthöjning av O3 (Interpretation of the regulation SvSKFS 

2005.2 related to Project Puls for the power uprating of 

Oskarshamn 3),” slide presentation at Svenska Kraftnöt (Swedish 

National Grid), January 2006.

[NERC-Jan 2009] “NERC Technical Paper on Protection System Reliability –

Redundancy of Protection System Elements,” North American 

Electric Reliability Corporation, Princeton, New Jersey, January 

2009.
108

[IEEE Std. C37.91-2008] IEEE Std. C37.91-2008, “Guide for Protective Relay Applications 

to Power Transformers,” Institute of Electrical and Electronics 

Engineers, New York, 2008.

[SRP BTP 8-6] US NRC NUREG-0800, Chapter 8, “Standard Review Plan for the 

Review of Safety Analysis Reports for Nuclear Power Plants: LWR 

Edition — Electric Power,” Rev. 4, February 2012.

[RIS 2011-12] US NRC, “NRC Regulatory Issue Summary 2011-12 Adequacy of 

Station Electric Distribution System Voltages,” Revision 1, 

December 29, 2011.

[Kueck, et. al. – 1998] J. Kueck, et. al., “A Discussion of Degraded Voltage Relaying for 

Nuclear Generating Stations,” IEEE, 1998.

[Jancauskas – 1994] J. R. Jancauskas, “A Recommended Approach for Calculating 

Degraded Voltage Relay Setpoints for Nuclear Generating 

Stations,“ IEEE Transactions on Energy Conversion, Vol. 9, No. 1, 

March 1994.

Section 3 – Analytical Approach to Studying the Impacts of Protection Settings on NPP 

Responses to External Faults

[Lindahl – 2010] S. Lindahl, Comments to “Description of NPP Modeling and 

Analytical Approach to Studying Impacts of Protection Settings on 

NPP Responses to External Faults," September 17, 2010.

[Lindahl – 2011] S. Lindahl, SLi-2011-009, Version B, “Comments to Susceptibility 

of Nuclear Stations to External Faults,” May 18, 2011.

Section 4 – NPP Models and Analyses

[IEEE Brown Book] IEEE Std. 399-1990, “IEEE Recommended Practices for Power 

System Analysis,” Institute of Electrical and Electronics Engineers, 

New York, 1990.

[Kundur 1993] P. Kundur, Power System Stability and Control, McGraw-Hill, Inc, 

1993.

[Seman 1995] G. W. Seman, C. Katz, and S. V. Pancholi, “Evaluation of 230 kV 

HPFF Pipe-type Cable with Wrinkled and Creased Insulating 

Tapes,” IEEE Transactions on Power Delivery, Vol. 10, No. 1, Jan, 

1995.

[Trehan 2002] N. K. Trehan, “Fast Bus Transfer Scheme and Its Performance in 

Nuclear Power Generating Stations,” SNPS Paper P-3-1, Norfolk, 

Virginia, 2002.
109

Section 5 – Importance of Protection Systems Maintenance

[10 CFR 50, Appendix A, GDC 17]

Title 10 of the Code of Federal Regulations, Part 50, Appendix A, 

“General Design Criteria for Nuclear Power Plants,” Criterion 17 -

Electric Power Systems.

[10 CFR 50, Appendix A, GDC 18]

Title 10 of the Code of Federal Regulations, Part 50, Appendix A, 

“General Design Criteria for Nuclear Power Plants,” Criterion 18 –

Inspection and testing of electric power systems.

[10 CFR 50.65] Title 10 of the Code of Federal Regulations, Part 50.65 

“Requirements for monitoring the effectiveness of maintenance at 

nuclear power plants.”

[NUC-001-2] North American Electric Reliability Corporation (NERC) Standard, 

NUC-001-2, “Nuclear Plant Interface Coordination,” August 2009.

[PRC-005-2] North American Electric Reliability Corporation (NERC) Standard, 

PRC-005-2, “Protection System Maintenance,” approved by the 

NERC Board of Trustees, November 7, 2012. Awaiting FERC 

action.

[IN 2005-15] NRC Information Notice IN 2005-15, “Three-Unit Trip and Loss of 

Offsite Power at Palo Verde Nuclear Generating Station,” US NRC, 

June 1, 2005.

[LER 40815] US NRC Licensee Event Report (LER) 50-528/2004-006-00, 

“Loss of Offsite Power – Three Unit Trip,” Palo Verde Nuclear 

Generating Station, June 14, 2004.

[IN 2004-15] NRC Information Notice IN 2004-15, “Dual-Unit Scram at Peach 

Bottom Units 2 and 3,” US NRC, July 22, 2004.

[AIT 05000277&278/2003013] 

US NRC Augmented Inspection Team Report, “NRC Augmented 

Inspection Team (Ait) 05000277/2003013 and 05000278/2003013, 

and Preliminary White Finding - Peach Bottom Atomic Power 

Station,” December 18, 2003.

[IN 2007-14] NRC Information Notice IN 2007-14, “Loss Of Offsite Power and 

Dual-Unit Trip at Catawba Nuclear Generating Station,” US NRC, 

March 30, 2007.

[AIT 05000413 & 414/2006009] 

US NRC Augmented Inspection Team Report, “Catawba Nuclear 

Station - NRC Integrated Inspection Report 05000413/2006003 

and 05000414/2006003,” July 28, 2006.
110

[LER 269/2007-001-01] US NRC Licensee Event Report (LER) 50-269/2007-001-01, “Dual 

Unit Trip from Jocassee Breaker Failure,” Oconee Nuclear Station, 

Unit 1, February 15, 2007.

[LER 250/2008-001-00] US NRC Licensee Event Report (LER) 50-250/2008-001, “Human 

Error Causes Grid Disturbance Resulting in a Dual Unit Trip,” 

Turkey Point Unit 3, February 26, 2008.

[Kirby, Kueck, et. al. ORNL 2007]

B. Kirby, J. Kueck, et. al., “Nuclear Generating Stations and 

Transmission Grid Reliability,” ORNL, 2007.
A-1

APPENDIX A SCENARIOS FOR COMPARING GRID RESPONSES 

TO FAULTS AT DIFFERENT LOCATIONS FOR 

PLANTS B AND C

(Scenarios Plant B Cases 1 - 7 and Plant C Cases 1 - 8 Defined in 

Table 4-1)
A-2

Figure A-1 Plant B-Case-1 for Bus EB Permanent Fault (Near)
A-3

Figure A-2 Plant B-Case-2 for Bus Sub2 Permanent Fault (Medium)
A-4

Figure A-3 Plant B-Case-3 for Bus Sub6 Permanent Fault (Far)
A-5

Figure A-4 Plant B-Case-4 for Line 12 Permanent Fault (Near)
A-6

Figure A-5 Plant B-Case-5 for Line 2 Permanent Fault (Medium)
A-7

Figure A-6 Plant B-Case-5 for Line 12 Transient Fault (Far)
A-8

Figure A-7 Plant B-Case-6 for Line 2 Transient Fault (Near)
A-9

Figure A-8 Plant C-Case-1 for Bus77 Permanent Fault (Near)
A-10

Figure A-9 Plant C-Case-2 for Bus Sub1 Permanent Fault (Far)
A-11

Figure A-10 Plant C-Case-3 for Line 3 Permanent Fault (Near)
A-12

Figure A-11 Plant C-Case-4 for Line 220 32 Permanent Fault (Medium)
A-13

Figure A-12 Plant C-Case-5 for Line 220 31 Permanent Fault (Near)
A-14

Figure A-13 Plant C-Case-6 for Line 3 Transient Fault (Near)
A-15

Figure A-14 Plant C-Case-8 for Line 220 32 Transient Fault (Medium)
A-16

Figure A-15 Plant C-Case-8 for Line 220 31 Transient Fault (Far)
B-1

APPENDIX B DEREGULATION OF THE ELECTRIC UTILITY 

INDUSTRY

1 As part of the ongoing national trend to deregulate major interstate industries, the National 

Energy Policy Act of 1992 allows for the competitive sale of electricity on the open market 

and for individual customers to choose their electric supplier. The Federal Energy 

Regulatory Commission (FERC) is the regulatory body responsible for the regulation of 

wholesale interstate electric power transactions. 

More specifically, FERC issued Order No. 888, “Promoting Wholesale Competition Through 

Open Access Non-discriminatory Transmission Services by Utility Companies, Recovery of 

Stranded Costs by Public Utilities and Transmitting Utilities,” in 1996 that required both utility 

generators and non-utility generators (merchant power plants) to have open access to the 

electric transmission grid [FERC Order No. 888]. Further, FERC Order No. 889, “Open Access 

Same-time Information System (OASIS) Rule and Standards of Conduct,” guaranteed equal 

access rights to all parties who wish to use the transmission grid [FERC Order No. 889].

The North American Electric Reliability Corporation (NERC) is responsible for the reliable 

operation of the integrated electric transmission grid in North America. Ten Regional Reliability 

Councils have been established under NERC consisting of generation and transmission electric 

utilities, independent power producers, power marketers, and federal power agencies in the US, 

Canada, and northern Mexico. NERC, through the regional member reliability councils, 

manages the decentralized operation of the generation in individual operating areas to assure: 

the adequacy and reliability of the transmission grid, the ability of the regional generation to 

meet system demand, and the fulfillment of electric power exchange obligations [Trehan – Jan 

2000]. NERC is responsible for assuring the implementation of FERC regulatory requirements 

among its regional reliability councils.

Specifically, with regard to the electric power transmission grid interface with NPPs, NERC 

Standard, NUC-001-2, “Nuclear Plant Interface Coordination,” requires the coordination 

between nuclear plant operators and transmission entities (transmission, distribution, and 

generation owners, operators, and reliability coordinators) for the purpose of ensuring the safe 

operation and shutdown of NPPs [NERC Std. NUC-001, Rev 2 – Aug 2009]. The standard 

requires formal agreements to be put in place between nuclear plant operators and transmission 

entities regarding electric grid reliability requirements, technical interface requirements,

communications, operations and maintenance coordination, and transmission grid planning. 

The implementation of NUC-001-2 assures that the offsite electric power requirements are 

satisfied for the safe operation and shutdown of a NPP and for the recovery from nuclear station 

blackout (SBO), as established in GDC 17 and 10 CFR 50.63, respectively. In addition, the 

standard is intended to address nuclear plant licensing requirements regarding the interface 

between the nuclear plant and the electric power transmission grid that are included as part of 

the licensing design basis of the plant and are statutorily mandated for operation of the plant. 

B.1 Nuclear Regulatory Concerns

APPENDIX A Following deregulation of the electric utility industry via the National 

Energy Policy Act of 1992 and FERC Order 888 in 1996, NRC 

expressed concerns that, “Deregulation has the potential to 
B-2

challenge operating and reliability limits on the transmission system 

and could affect the reliability of the electric power system including 

the reliability of offsite power to nuclear plants [SECY-99-129 – May 

1999].” Under a deregulated electric utility industry, compliance with 

the regulatory requirements of GDC 17 for the electric power 

system, and for 10 CFR 50.63, addressing station blackout, would 

be dependent on entities that aree outside of the direct regulatory 

jurisdiction of the US NRC.

The NRC’s concerns regarding the effects of electric utility industry deregulation on nuclear 

plant safety are summarized in SECY-99-129 [SECY-99-129 – May 1999], which states, in part:

Many utilities are now divesting themselves of their generating units and the 

transmission systems are coming under the control of a new system control 

entity or an independent system operator. In addition, a power market has 

emerged to sell electricity. The fact that utilities may no longer have direct 

control of the offsite power supplies and transmission system could decrease the 

reliability of the grid and increase the time to restore electric power following a 

loss of offsite power (LOOP).

The deregulation of the electric power industry could be an important concern in 

the evaluation of potential SBO accidents at NPPs. The expected frequency of 

the LOOP, the probable time needed to restore offsite power, and the 

redundancy and reliability of the emergency ac power sources are key factors in 

the determination of risk from potential SBO accidents. As deregulation 

proceeds it is anticipated that more entities will enter the electrical power 

generation and transmission business resulting in a potential decrease in the 

reliability of the offsite power system during the transition period.

In 2003, NRC Office of Nuclear Regulatory Research (RES) completed an assessment of the 

performance of the electric power grid with respect to its effect on NPPs [Raughley – April 29, 

2003]. The RES assessment compared the performance of the grid before and after 

deregulation of the electric utility industry to identify changes in grid operation and to determine 

the impact that deregulation has had on the supply of electric power to NPPs. The prederegulation period considered included events from 1985–1996 [Raughley – June 30, 1999] 

and the post-deregulation period studied covered the 5-year period from 1997-2001. The final 

report, “Operating Experience Assessment-Effects of Grid Events on Nuclear Power Plant 

Performance” validated several of the NRC’s concerns expressed in SECY-99-129. Some of 

the major post-deregulation changes in the electric grid related to LOOPs included the following: 

1) the frequency of LOOP events at NPPs has decreased, 2) the average 

duration of LOOP events has increased – the percentage of LOOPs longer than 

four hours has increased from approximately 17 percent to 67 percent, 3) where 

before LOOPs occurred more or less randomly throughout the year, for 1997-

2001, most LOOP events occurred during the summer, and 4) the probability of a 

LOOP as a consequence of a reactor trip has increased by a factor of 5 (from 

0.002 to 0.01).
B-3

NRC continues to address the problems of deregulation and grid reliability through regular 

interaction with FERC and NERC [Inside NRC – Sept.14, 2009], information notices (e.g., 

IN 1998-07, IN 2004-15, IN 2005-15, IN 2005-21, IN 2006-06, IN 2006-18, IN 2007-14, and 

IN 2008-12), generic regulatory correspondence (e.g. GL 2006-02), revisions to Chapter 8 

(Electric Power) of the Standard Review Plan [NUREG-0800, Revision 4, March 2007], the 

Maintenance Rule [10 CFR 50.65], and regulatory guidance (e.g. RG 1.155, RG 1.180, and 

RG 1.182).

In RIS 2004-05, the NRC indicated the importance of grid reliability issues because of the 

impact on plant risk and the operability of the offsite power system. The RIS summarized the 

regulatory requirements GDC-17, the maintenance rule, the SBO rule, and plant technical 

specifications regarding the operability of offsite power.

B.2 References

[FERC Order No. 888] FERC Order No. 888, “Promoting Wholesale Competition Through 

Open Access Non-discriminatory Transmission Services by Utility 

Companies, Recovery of Stranded Costs by Public Utilities and 

Transmitting Utilities,” 1996.

[FERC Order No. 889] FERC Order No. 889, “Open Access Same-time Information 

System (OASIS) Rule and Standards of Conduct,” 1996.

[Trehan – Jan 2000] N. Trehan, “The Impact of System Security in an Open Market on 

Nuclear Power Generating Stations,” January 2000.

[NERC Std. NUC-001, Rev 2 – Aug 2009]

NERC Standard, NUC-001-2, “Nuclear Plant Interface 

Coordination,” August 2009.

[SECY-99-129 – May 1999] ”Effects of Electric Power Industry Deregulation on Electric Grid 

Reliability and Nuclear Safety,” US NRC, May11, 1999.

[Raughley – June 30, 1999] W. Raughley, “The Effects of Deregulation of the Electric Power 

Industry on The Nuclear Plant Offsite Power System: An 

Evaluation,” US NRC, ML003743741, June 30, 1999.

[Raughley – April 29, 2003] W. Raughley, “Operating Experience Assessment-Effects of Grid 

Events on Nuclear Power Plant Performance,” US NRC, 

ML031220116, April 29, 2003.

[Inside NRC – Sept.14, 2009]“NRC, FERC Agree to Cooperate on Grid Cybersecurity Issues,” 

Inside NRC, Sept.14, 2009.

[IN 1998-07] NRC Information Notice IN 1998-07, “Offsite Power Reliability 

Challenges from Industry Deregulation,” US NRC, February 27, 

1998.

C-1

APPENDIX C COMMON SWITCHYARD BUS ARRANGEMENTS

This subsection briefly describes the following four basic switchyard bus arrangements in 

nuclear power station high-voltage switchyards: 1) the main and transfer bus, 2) the ring bus, 3) 

the breaker-and-a-half bus, and 4) the double-bus, double-breaker arrangement. Figure C-1 

illustrates these bus arrangements.

Figure C-1 Common high-voltage switchyard bus arrangements
C-2

C.1 Main and Transfer Bus

In the main and transfer bus arrangement, two independent electrical buses are used, as 

depicted in Figure C-1a. The main bus remains energized during normal operation and all 

transmission lines and transformers are electrically connected to it. In the event that 

maintenance is required on a power circuit breaker, the transfer bus is energized through the 

bus-tie breaker by closing its isolation switches and then closing the bypass isolation switch for 

the circuit breaker that is to be isolated, thereby paralleling the transmission line or power 

transformer to both the main and transfer bus. The bypassed circuit breaker and its isolation 

switches may then be opened, removing the main bus breaker from service. The transmission 

line or transformer is then supplied via the bus tie breaker and protected by the bus tie breaker’s 

protective relaying.

The advantages of the main and transfer bus arrangement are: 1) circuit breaker maintenance 

may be performed without loss of transmission line or transformer service; 2) the arrangement 

has relatively small physical size and a moderate cost; and 3) the switchyard can be expanded 

without removal of the entire station from service.

The disadvantages of the arrangement are: 1) an additional bus-tie circuit breaker is required 

with protective relaying capability to protect any transmission line or transformer in the station; 

2) the tie-breaker relay settings must be changed to match the protection scheme for which it is 

being substituted; and 3) somewhat complicated switching is required to remove a breaker from 

service for maintenance. These reliability and operational limitations make this arrangement 

generally unsuitable for use in a NPP switchyard.

C.2 Ring Bus

The ring bus arrangement is shown in Figure C-1b. The arrangement consists of a closed loop 

electrical bus in which each transmission line or transformer connection is flanked by a pair of 

circuit breakers. Since each circuit breaker in the ring bus arrangement is shared, it is possible 

to perform maintenance on any circuit breaker without interrupting service to the transmission 

line or transformer on either side of it. The cost of a ring bus is about 12%-15% less than an 

equivalent switchyard using a main and transfer bus arrangement [McDonald – 2003].

The advantages of a ring bus scheme are

• low cost because the bus requires only one breaker per circuit;

• high reliability and operational flexibility because there is a double feed to each circuit;

• switchyard bus differential protection is not required because each section of the bus is 

protected by the relaying for that circuit or transformer;

• service is not interrupted during circuit breaker maintenance; and

• the switchyard can be readily expanded to a breaker-and-a-half scheme if properly 

anticipated in the design planning.
C-3

The disadvantages of a ring bus are

• each circuit must have a separate potential transformer for protective relaying;

• the bus is limited to no more than four to six transmission line or transformer circuits due 

to reliability concerns as well as ampacity and short circuit duty limitations; and

• a fault can open the ring and cause undesirable circuit combinations.

Due to its high reliability, operational flexibility, and other desirable characteristics mentioned 

above, the ring bus arrangement is sometimes used for NPP switchyards. The nuclear plant 

distribution system shown in the one-line diagram in Figure 1 utilizes a ring bus in its switchyard.

C.3 Breaker-and-a-Half Bus Arrangement

The breaker-and-a-half bus arrangement, depicted in Figure C-1c, utilizes two buses, but unlike 

the main and transfer bus arrangement in subsection 2.2.1 above, both of the buses remain 

energized during normal operation. In this arrangement, for every pair of circuits there are three 

power circuit breakers, with the center circuit breaker being shared by the two circuits in each 

substation bay. The cost of a breaker-and-a-half bus arrangement is about the same as an 

equivalent switchyard using a ring bus arrangement [McDonald – 2003].

The advantages of the breaker-and-a-half bus arrangement are

• any circuit breaker to be removed from service without interrupting service to the circuits 

in the affected substation bay;

• reliability and operational flexibility are improved because there is a double feed to every 

circuit and a fault on either of the buses can be isolated without losing any circuit; and

• all switching operations may be accomplished using power circuit breakers.

The disadvantages of the breaker-and-a-half arrangement are

• each circuit must have a separate potential transformer for protective relaying; 

• the cost and size of the substation are affected because one-and-a-half breakers are 

needed for each circuit; and 

• protective relaying for the center shared circuit breaker in each bay must be able to 

protect either of the two circuits in the bay in which it is located.
C-4

Due to its high reliability, operational flexibility, reasonable cost, and other desirable 

characteristics mentioned above, the breaker-and-a-half bus arrangement is very frequently 

used for NPP switchyards.

C.4 Double-Bus Double-Breaker Arrangement

The double-bus, double-breaker arrangement, shown in Figure C-1d, uses two normally 

energized buses with two power circuit breakers flanking a single circuit in each bay between 

the two buses. Switchyards using this arrangement will offer the highest level of reliability and 

availability since two buses and two breakers are associated with each circuit. The high 

reliability of the double-bus, double-breaker arrangement comes at price that is nearly 40% 

greater than an equivalent switchyard using a ring bus or breaker-and-a-half bus arrangement 

[McDonald – 2003].

Some advantages of the double-bus, double-breaker arrangement are

• very high reliability and operational flexibility;

• since there are two breakers feeding each circuit, any circuit breaker can be removed 

from service without affecting its circuit;

• either bus can be removed from service without affecting any circuit in the switchyard;

• a fault on either of the main busses will not affect any circuit in the switchyard;

• all switching operations can be performed using circuit breakers;

• protection and control schemes are simplified compared to the ring bus and breakerand-a-half bus arrangements; and

• a breaker failure protective response will only interrupt service from one circuit.

The disadvantage of the double-bus, double-breaker arrangement is the very high cost of 

providing two power circuit breakers for each circuit in the switchyard. Although this bus 

arrangement is very desirable for a nuclear station switchyard from a reliability standpoint, the 

extra cost of the added reliability cannot be justified in most cases.

The double-bus, double-breaker can be incorporated into selected bays of a breaker-and-a-half 

switchyard arrangement in order to improve the reliability of the most critical connections (e.g., 

the main generator connection, the station auxiliary power feed, or one or more important 

transmission line circuits).
C-5

C.5 References

[NUREG/CR-6950, October 2007]

NUREG/CR-6950, “Effects of Switchgear Aging on Energetic 

Faults,” Brookhaven National Laboratory for NRC/RES, October 

2007.

[Mazumdar & Chiramal, Oct 1991] 

S. Mazumdar & M. Chiramal, “Bus Transfer Practices at Nuclear 

Plants,” IEEE Transactions on Power Delivery, Vol. 6, No. 4, 

October 1991.

[MacDonald 2003] McDonald, John D., “Electric Power Substations Engineering,” 

CRC Press, New York, 2003.

[Daume – Feb 2007] J. Daume, “High Voltage Transmission Practices,” Presentation, 

Bonneville Power Association, February 2, 2007.

[GER-3965] G. E. Alexander and J. G. Andrichak, Evaluating Line Relaying 

Schemes in Terms of Speed, Security and Dependability, GER3965, GE Power Management.

[Kundur 1993] P. Kundur, Power System Stability and Control, McGraw-Hill, Inc, 

1993.

[Mason 1956] C. Russell Mason, The Art and Science of Protective Relaying.

Engineering Planning and Development Section, General Electric 

Co., John Wiley & Sons, New York, 1956.

[Blackburn, et. al. – 1976] J. L. Blackburn, et. al., Applied Protective Relaying,” 

Westinghouse Electric Corp., Relay Instrument Division, Newark, 

NJ, 1976.

[IEEE PC37.119-2005] IEEE Std 37.119-2005, “Guide for Breaker Failure Protection of 

Power Circuit Breakers,” Institute of Electrical and Electronics 

Engineers, New York, 2005.

[IEEE Std. C37.234-2009] IEEE Std. C37.234-2009, “Guide for Protective Relay Applications 

to Power System Buses,” Institute of Electrical and Electronics 

Engineers, New York, 2009.Typical Unit-connected Main 

Generator & Transformer Protection

D-1

APPENDIX D TYPICAL UNIT-CONNECTED MAIN GENERATOR & 

TRANSFORMER PROTECTION

Typical NPP main generator and output transformer protection, operating, and control relaying 

devices and their functions are tabulated in Table D-1 for a 1525 MW generator at a BWR plant. 

These devices protect the generator against problems such as, internal faults in the generator 

winding, overload, overheating of windings and bearings, overspeed, phase sequence,

directional power flow, loss of excitation, motoring, and single-phasing or unbalanced operation 

[NUREG/CR-6950].

Table D-1 Typical Main Generator & Transformer Protective Devices & Functions

Device/ID No. Description Mfg Type Function

786/UT11 Unit Lockout GE HEA61C trip and lockout unit

763/UT11 Main Transformer Sudden Pressure GE 900-1 trip lockout relay 763X/UT11

763/786/UT11 Main Transformer Sudden Pressure Lockout GE HEA61A trip lockout relay 786/UT11

751N/UT11 Main Transformer Ground Overcurrent GE IAC51A trip lockout relay 786/UT11

787/G11 Main Transformer Differential GE BDD16B trip lockout relay 486/G11

787/UT11 Unit Differential GE BDD15B trip lockout relay 786/UT11

486/G11 Unit Lockout GE HEA61C trip and lockout unit

487/G11 Generator Differential GE CFD22B trip lockout relay 486/G11

464N/G11 Generator Ground Fault GE IAV51K trip lockout relay 486/G11

464LF/G11 Low Frequency Generator Ground Fault W SV trip lockout relay 486/G11

451N/G11 Generator Neutral Time Overcurrent GE IAC51A trip lockout relay 786/UT11

486/G12 Unit Lockout GE HEA61C trip and lockout unit

763X/UT11 Main Transformer Sudden Pressure Aux Relay GE HAA16B trip main transformer sudden 

pressure lockout annunciator

432/G12 Generator Power Directional GE GGP53B trip lockout relay 486/G12

460/G11 Voltage Balance GE CFVB11B Monitor PT fuses, alarm, interlocks

440-1/G12 Generator Loss of Field GE CEH51A trip lockout relay 486/G12

440-1/G12 Generator Negative Phase Sequence GE STV11A1A trip lockout relay 486/G12

459-1/481/G11 Generator Volts/Hertz GE CEH51A trip lockout relay 486/G11

421/G12 Generator Phase Distance GE CEB18C trip lockout relay 486/G12

427/G11 Generator Undervoltage GE NGV alarm

481-1/G12 Generator Underfrequency GE CFF23A trip lockout relay 486/G12

481-2/G12 Generator Underfrequency GE CFF23A trip lockout relay 486/G12

460/G12 Voltage Balance GE CFVB11B Monitor PT fuses, blocks LRR

726/UT11 Hot Spot Temperature Detector --- internal start 2nd bank mn xfrmr clng fans
D-2

Table D-1 Typical Main Generator & Transformer Protective Devices & Functions

Device/ID No. Description Mfg Type Function

LRR Load Rejection Relay Sie 7UO2182 MHC control

459-2/481/G11 Generator Volts/Hertz GE STV11A2A trip lockout relay 486/G11

432/G12 Generator Power Directional GE GGP53B trip lockout relay 786/UT11

D.1 References

[NUREG/CR-6950] NUREG/CR-6950, “Effects of Switchgear Aging on Energetic 

Faults,” Brookhaven National Laboratory for NRC/RES, October 

2007.

[IEEE PC37.102-2006] IEEE Std. 37.102-2006, “Guide for AC Generator Protection,” 

Institute of Electrical and Electronics Engineers, New York, 2006.

[IEEE Std. C37.101-2006] IEEE Std. C37.101-2006, “Guide for Generator Ground Protection,”

Institute of Electrical and Electronics Engineers, New York, 2006.

[IEEE Std. C37.91-2008] IEEE Std. C37.91-2008, “Guide for Protective Relay Applications 

to Power Transformers,” Institute of Electrical and Electronics 

Engineers, New York, 2008.



UNITED STATES

NUCLEAR REGULATORY COMMISSION

WASHINGTON, DC 20555-0001

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OFFICIAL BUSINESS
NUREG/CR-7175 Susceptibility of Nuclear Stations to External Faults