ADAMS ACCESSION NUMBER ML031220116

ADAMS PACKAGE NUMBER ML031220101

Final Report

Operating Experience Assessment-Effects of Grid Events on Nuclear

Power Plant Performance

April 29, 2003

Prepared by:
William S. Raughley
Reviewed by:
George F. Lanik

Regulatory Effectiveness Assessment and Human Factors Branch

Division of Systems Analysis and Regulatory Effectiveness
Office of Nuclear Regulatory Research
U.S. Nuclear Regulatory Commission
 ABSTRACT

Deregulation of the electrical industry has resulted in major changes to the structure of the
industry over the past few years. Whereas before, a single unified corporation both produced
the electricity and operated the distribution system, that is no longer the case. The industry has
split into separate generating companies and transmission companies. Most nuclear power
plant (NPP) operators no longer have control of the distribution system operations. NPPs rely
on an outside entity to provide reliable electrical power for NPP operation. An assessment was
completed by the Office of Nuclear Regulatory Research (RES) to identify changes to grid
performance relative to NPPs which could impact safety. The assessment also provides some
numerical measures to characterize grid performance before and after deregulation - in
particular, those related to loss of offsite power (LOOP).

The information gathered provides a baseline of grid performance to gauge the impact of
deregulation and changes in grid operation. The period 1985-1996 was considered “before
deregulation” and 1997-2001 “after deregulation.” The assessment found that major changes
related to LOOPs after deregulation compared to before include the following: 1) the frequency
of LOOP events at NPPs has decreased, 2) the average duration of LOOP events has
increased, 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.

The assessment re-enforces the need for NPP licensees and NRC to understand the condition
of the grid throughout the year to assure that the risk due to potential grid conditions remains
acceptable.

iii
 CONTENTS

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

ABBREVIATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vi

EXECUTIVE SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . viii

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

2 BACKGROUND . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
2.1 Principal Design, Operating, and Maintenance Criteria and Risks . . . . . . . . . . . 2
2.1.1 Principal Offsite Power System Design and Reliability Criteria . . . . . . . . 2
2.1.2 Principal Risks and Regulatory Expectations . . . . . . . . . . . . . . . . . . . . . 3
2.1.3 Control of Risks From EDG Tests to Grid . . . . . . . . . . . . . . . . . . . . . . . . 5
2.2 Reactor Trips Degrade the Grid and Result in Regulatory Actions . . . . . . . . . . 6
2.3 Nuclear Power Plant Voltages Based on Grid Electrical Parameters . . . . . . . . . 8
2.4 Effects of Deregulation of the Electric Power Industry on Nuclear Power Plants 8

3.0 DISCUSSION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
3.1 Methods for Data Collection and Risk Analyses . . . . . . . . . . . . . . . . . . . . . . . . 12
3.2 Risk Insights and General Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
3.2.1 Risk Insights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
3.2.2 General Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
3.3 Nuclear Plant Voltages Not Always Analyzed For Grid Conditions Experienced 20
3.3.1 Grid Loading and Equipment Out of Service . . . . . . . . . . . . . . . . . . . . . . 21
3.3.2 Grid Reactive Capability Weakened . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
3.3.3 Transmission System Faults May Involve Multiple Reactor Trips . . . . . . 24
3.4 NPPs Must Contract For Adequate Voltage Support . . . . . . . . . . . . . . . . . . . . 26
3.5 EDG Test With Grid Degraded Need May Compromise Independence . . . . . . 27
3.6 Potential Damaging Effects of Current Unbalance From Grid Disturbances . . 28
3.7 Grid Transients May Degrade Scram and ATWS Capabilities . . . . . . . . . . . . 29
3.8 Effects of Overfrequency On Reactor Integrity . . . . . . . . . . . . . . . . . . . . . . . . 30

4 ASSESSMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

5 REFERENCES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

iv
 TABLES

1 Grid Event Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

2 Changes in Risk After Deregulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
3 LOOP Recovery Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
4 PJM Base-Line Voltage Limits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

FIGURES
1 Risk Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

APPENDICES

A Grid Events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

B Risk Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-1
C LOOP and Scram Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-1

TABLES

A-1 Types and Number of Grid Events 1994-2001 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-23

A-2 Event Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-24
A-3 Event Causal Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-37
A-4 Summary of Event Group Causal Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-38

B-1 Operating Data From LOOPs At Power Before and After Deregulation . . . . . . . . . . . B-5
B-2 Changes in Risk After Deregulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-7

C-1 LOOPs While At Power 1997–2001 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-1

C-2 Consequential LOOPs 1985–1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-2
C-3 Grid-Related or Initiated LOOPs While At Power 1985–1996 . . . . . . . . . . . . . . . . . . C-2
C-4 Plant Related LOOPs While At Power 1985–1996 . . . . . . . . . . . . . . . . . . . . . . . . . . C-3
C-5 Weather Related LOOPS While AT Power 1985–1996 . . . . . . . . . . . . . . . . . . . . . . . C-4
C-6 Non-Initiating LOOPs While At Power 1985–1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . C-4
C-7 Annual Scrams and Critical Reactor years 1985–2001 . . . . . . . . . . . . . . . . . . . . . . . C-5

FIGURES

B-1 Simplified Event Tree for a Reactor Trip-Consequential LOOP . . . . . . . . . . . . . . . . . B-3

B-2 Simplified Event Tree for a LOOP Event Tree . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-4
B-3 Risk Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-8

v
 ABBREVIATIONS

ASP accident sequence precursor

ATWS anticipated transient without scram

BWR boiling water reactor

CAISO California Independent System Operator

CCDP conditional core damage probability
CDF core damage frequency
CFR Code of Federal Regulations
CPC core protection calculator

DAWG Disturbance Analyses Working Group

DOE Department of Energy

EDG emergency diesel generator

EOC end-of-cycle
EOOS equipment-out-of-service
EPRI Electric Power Research Institute

FERC Federal Energy Regulatory Commission

FSAR Final Safety Analysis Report
FTR failed to run( load)

GDC General Design Criterion

GL Generic Letter

IN Information Notice
INPO Institute of Nuclear Power Operations

kV kilo-volt

LER licensee event report

LOOP loss of offsite power

MTC moderator temperature coefficient

MVAR megavolt-ampere-reactive
MW megawatt
MWt megawatt-thermal

vi
NEPA National Energy Policy Act
NERC North American Electrical Reliability Council
NPP nuclear power plant
NRC Nuclear Regulatory Commission, U.S.

OOS out of service

PJM Pennsylvania-New Jersey-Maryland Interconnection

PNO preliminary notification
PRA probabilistic risk assessment
PWR pressurized water reactor

RA reserve auxiliary transformer

RCP reactor coolant pump
RES Nuclear Regulatory Research, Office of (NRC)
RIS Regulatory Issue Summary
RPT recirculation pump trip
RY reactor year

SAT startup transformer

SBCS steam bypass control system
SBO station blackout
SBO-CT station blackout combustion turbine

TCV turbine control valve

UPS uninterruptible power supply

VOPT variable over power trip

vii
 EXECUTIVE SUMMARY

Deregulation of the electrical industry has resulted in major changes to the structure of the
industry over the past few years. Whereas before, a single unified corporation both produced
the electricity and operated the distribution system, that is no longer the case. The industry has
split into separate generating companies and transmission companies. Increased coordination
times to operate the grid may result from involvement of more companies. In addition,
generating companies have daily open access to the grid and this changes the grid design and
operating configurations that were established before deregulation. Nuclear power plants
(NPPs) rely on an outside entity to provide reliable electrical power for NPP operation. The
Office of Nuclear Regulatory Research (RES) completed an assessment that is intended to
identify changes to grid performance relative to the safety performance of NPPs. The
assessment also provides some numerical measures to characterize grid performance before
and after deregulation - in particular, those related to loss of offsite power (LOOP).

The information gathered provides a baseline of grid performance to gauge the impact of
deregulation and changes in grid operation. The period 1985–1996 was considered “before
deregulation” and the 1997–2001 “after deregulation.” The assessment found that major
changes related to LOOPs after deregulation compared to before include 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).

Simplified event trees were developed to assess the impact of these changes on overall NPP
risk, and to include the impact of the LOOP as a consequence of reactor trip. The combined
impact of the changes noted above, and the reduced frequency of reactor trips, was assessed.
The findings include the following: 1) the average yearly risk from LOOPs and reactor trips
decreased, 2) a small number of events over the first five years of deregulated operation
indicates that most of the risk from LOOPs occurs during the summer, and 3) including LOOP
as a consequence of a reactor trip and the potential for degraded grid during the summer, the
risk associated with an emergency diesel generator (EDG) out of service can be larger than
previously realized.

The assessment re-enforces the need for NPP licensees and NRC to understand the condition
of the grid throughout the year to assure that the risk due to potential grid conditions remains
acceptable. To elaborate:

viii
(1) The NRC does not regulate the grid; however, the performance of offsite power is a major
factor for assessment of risk. With respect to maintaining the current levels of safety,
offsite power is especially important with regard to the risk associated with EDG
maintenance and outage activities. Consequently, NRC and licensee assessments of risk
that support EDG maintenance and outage activities should include: (a) assessment of
offsite power system reliability, (b) the potential for a consequential LOOP given a reactor
trip, and (c) the potential increase in the LOOP frequency in the summer (May to
September). Regarding (a) above, the assessment of the power system reliability and risks
from plant activities can be better managed though coordination of EDG tests with
transmission system operating conditions.

(2) Another important aspect of the changes to the electrical grid is the impact on the electrical
analyses of NPP voltage limits and predictions of voltages following a reactor trip and
whether a reactor trip will result in a LOOP. Recent experience shows that actual grid
parameters may be worse than those assumed in electrical analyses due to transmission
system loading, equipment out-of-service, lower than expected grid reactive capabilities,
and lower grid operating voltage limits and action levels. NPP design basis electrical
analyses used to determine plant voltages should use electrical parameters based on
realistic estimates of the impact of those conditions.

(3) With the structural and operational changes that have occurred in the industry, it is
important to have mechanisms, such as contracts between the NPP and transmission
company, in place to ensure that grid operators will provide reliable electrical power. Some
regional grid operating entities manage and control operational and engineering activities in
real time to maintain grid availability and reliability. Since external factors impact the ability
of licensees to manage risks and understand the condition of the grid, some NPP licensees
have implemented contractual agreements with grid operators to provide a mechanism for
maintaining secure electrical power in the deregulated environment. Contractual
arrangements should include specific electrical requirements, communication protocols,
operating procedures and action limits, maintenance responsibilities, station blackout (SBO)
(alternate ac) power supply responsibilities, and NPP and grid. Within its proper roles and
responsibilities, the NRC should communicate with the industry about the possible need for
these mechanisms.

CAISO, PJM, and Callaway experience provides an opportunity for the industry and NRC to
develop lessons to be learned. The assessment identified the following insights from this
experience:

(1) While the data set is small, recent experience indicates that the average duration of LOOPs
has increased. Based on historical data, power restoration times following a LOOP are
assumed to be less than 4 hours; most recent LOOPs have lasted significantly longer.

ix
 Also, recent grid events, although not directly associated with LOOPs, indicate that grid
recovery times may be longer. For example, in the Northeast, it took the grid operator (of
12 NPPs) 10 hours to resolve problems from unexpected behavior of the grid, despite
implementation of planned voltage and load management programs and investigation found
insufficient reactive capacity to quickly restore voltages. In the Mid-West, the grid operator
needed 12 hours to change regional power flows and restore voltage to a NPP. These
events support the concern identified in SECY 99-129 that the time needed to coordinate
grid operations may increase in a deregulated environment.

(2) LOOPs, partial LOOPs, momentary LOOPs, and voltage degradations below the technical
specification low limit following or coincident with a reactor trip may provide indication of a
potential electrical weaknesses in the grid and a need for regulatory followup to prevent
more serious events. In some events, plant equipment which control safety bus voltage
levels, is assumed to be functional by the grid controlling entity for the range of external
voltages maintained at the NPP. Periodic verification of NPP or other voltage controlling
equipment operability may require compensatory measures such as a request for voltage
adjustment from the grid control entity.

(3) Realistic assessment of the risk from grid events may need to consider the impact of a grid
event on multiple NPPs. For example, one recent transmission system disturbance resulted
in the simultaneous trip of four NPPs.

(4) Experience indicated that transmission system operation or disturbances may cause
sustained or frequent current unbalances that result in damage to electrical equipment. It
is common practice to protect expensive or important nonsafety equipment from current
unbalances. Safety equipment does not always have the same level of protection. RES will
further analyze this issue in the future.

(5) Grid-induced reactor transients can affect scram capability. Operating experience identified
an instance where anticipated transient without scram mitigation based on end-of-cycle
recirculation pump trip logic failed to operate correctly during a transmission system fault
that produced large electrical load fluctuations. RES will further analyze this issue in the
future.

(6) Grid conditions which result in over-frequency conditions can have unexpected
consequences. At one plant, over-frequency conditions following a load rejection caused
speed-up of the reactor coolant pumps which generated lifting forces on the core to within a
small margin of causing core mechanical tilt. The over-frequency condition was not
properly accounted for by the plant protective relay control logic. RES will further analyze
this issue in the future.

x
(7) The synergistic effects of reduced reactive grid capability on the NPP from hot weather and
multiple reactor power uprates should be evaluated. RES will further analyze this issue in
the future.

xi
1 INTRODUCTION

Deregulation of the electrical industry has resulted in major changes to the structure of the
industry over the past few years. Whereas before, a single unified corporation both produced
the electricity and operated the distribution system, that is no longer the case. The industry has
split into separate generating companies and transmission companies. More companies are
likely to lead to increased coordination times to operate the grid. In addition, generating
companies have daily open access to the grid and this changes the grid design and operating
configurations that were established before deregulation. Nuclear power plants (NPPs) rely on
an outside entity to provide reliable electrical power for NPP operation.

The Nuclear Regulatory Commission (NRC) Office of Nuclear Regulatory Research (RES)
completed the work described in this report to identify and provide an assessment of grid events
at NPPs before (1985-1996) and after deregulation (1997-2001). . The objectives of the work
were to use accumulated operating experience from various sources to identify and assess (1)
the numbers, types, and causes of these events, (2) potential risk-significant issues (3) potential
challenges to the effectiveness of the NRC regulations, and (4) lessons learned. This
assessment is intended to identify changes to grid performance relative to NPPs which could
impact safety. The assessment also provides simplified numerical measures to characterize
grid performance before and after deregulation - in particular, those related to loss of offsite
power (LOOP). The information gathered provides a baseline of grid performance to gauge the
impact of deregulation and changes in grid operation

For the purposes of this assessment, grid events include (1) losses of electric power from any
remaining power supplies as a result of, or coincident with, a reactor trip, (2) reactor trips, losses
of offsite power (LOOPs), or partial LOOPs in which the first event in the sequence of events
occurred in the transmission network, i.e. the NPP switchyard or the transmission and
generation system beyond the NPP switchyard, and (3) “events of interest” that provide an
insight into the plant response to a grid initiated event.

Since our focus is on aspects of grid performance, some events are defined differently here than
in other assessments - a number of the events which are defined in this assessment as grid
related LOOPs or grid initiated based on transmission network equipment failures, personnel
errors, or dependence on grid operator for recovery, are referred to in other event studies as
plant-centered. For the purposes of this assessment a reactor trip from full power operation is a
random test of the capacity and capability of the grid, and as such a LOOP as a consequence of
a reactor trip may be a grid-related LOOP.

As an overview, Section 2 , “Background,” provides basic information necessary to understand

the work. Section 3, “Discussion,” provides the analyses and discussion to satisfy the objectives
of the work. The numbers, types, and causes of these events were developed from Appendix A,

1
“Grid Events,” as as explained in Section 3.1. Analysis of these events identified some grid
related LOOPs that were potentially risk-significant. These risks were assessed in Section 3.2
by comparing the risks from all LOOP events before and after deregulation on an equal basis
using Appendix B, “Event Trees,” and actual operating data which were gathered in Appendix C,
“LOOP and Scram Data, 1985-2001.” Sections 3.2 to 3.8 provide risk insights and lessons
learned and end with assessments that are consolidated in Section 4, “Assessment.”

2 BACKGROUND

The NPP offsite power system is the “preferred source” of ac electric power, often referred to as
the grid. The safety function of the offsite power system is to provide power to ac safety loads
required to shut down the NPP, including loads in the reactor core decay heat removal system
that are required to preserve the integrity of the reactor core and containment following a reactor
trip. For the purposes of this assessment, the grid includes the switchyard or substation at the
NPP, the offsite generating and transmission systems, and the offsite loads. Redundant onsite
ac emergency power supplies, usually emergency diesel generators (EDGs), automatically
provide power to the safety buses following a LOOP.

2.1 Principal Design, Operating and Maintenance Criteria and Risks

The NRC has no jurisdiction over the grid. However, NRC regulations and NPP Technical
Specifications (TS) provide controls over the licensing bases, design criteria, NPP activities, and
risks relative to the grid as discussed below. .

2.1.1 Principal Offsite Power System Design and Reliability Criteria

The principal design criteria for the licensing basis of the offsite electric power system are set
forth in Appendix A Title 10 of the U.S. Code of Federal Regulations, Part 50, “Domestic
Licensing of Production and Utilization Facilities” (10 CFR Part 50) (Ref. 1)

General Design Criterion (GDC) 17,"Electric power systems," of Appendix A states in part, that

An onsite electric power system and an offsite electric power system shall be
provided....The safety function for each system (assuming the other system is not
functioning) shall be to provide sufficient capacity and capability....

Provisions...to minimize the probability of losing electric power from any of the
remaining supplies as result of, or coincident with, the loss of power generated by
the nuclear power unit, the loss of a power from the transmission network, or the
loss of power from the onsite electric power supplies.

2
Common capacity and capability terms are power, voltage, and frequency. While a detailed
electrical engineering discussion of these terms is beyond the scope of this report, it suffices to
understand that power has two components, real and reactive, measured in megawatts (MW)
and megavars (MVAR), respectively. The real power flow between two points depends primarily
on the relative voltage phase angles. The reactive power flow is a direct function of the
difference in the magnitude of the voltage at these points.

The GDC 17 requirements are intended to ensure that the NPP connects to a sufficiently robust
and reliable grid. The GDC 17 provisions to minimize the probability of losing electric power is a
common design practice for any generating plant. The industry uses the same measures as
GDC 17 to define grid reliability. The North American Electric Reliability Council (NERC), an
industry organization that promotes and assesses grid reliability, defines grid reliability in terms
of the “adequacy” of the generation system and the “security” of the transmission system. The
adequacy of the generation system is measured by the amount of reserve power available to
provide uninterruptible power. Grid operating entities maintain “spinning reserves” synchronized
to the grid for immediately use. Voltage reductions and interrupting loads (rolling blackouts) also
help to maintain reserves. The security of the transmission system is defined in terms of the
ability of the system to withstand sudden disturbances, such a reactor trip or transmission line
fault, and is measured by the power restoration time to a particular group of customers.
Spinning reserves, and voltage and load management programs are important factors for grid
operators to maintain system stability, adequate NPP voltages and frequencies, and recover
from grid events in a timely manner.

The capacity and capability of the offsite power system are ensured through analyses
(discussed in Section 2.4) that are part of the licensing bases. The NRC Standard Technical
Specifications (TS) (Ref. 2), which are typical of NPP TS, provide for verification of the
availability of the offsite power supplies every 7 days. The TS impose limiting conditions of
operation (LCO) including shutdown of the reactor should offsite power not be restored in a
timely manner, typically in times up to 72 hours for loss of individual offsite power supplies and
shorter times for loss of multiple offsite power supplies. The NRC TS states that the operability
of ac electrical considers the capacity and capability of the remaining sources, reasonable time
for repairs, and the low probability of a design basis accident occurring in this period. Continued
operation for 72 hours generally requires, consistent with Regulatory Guide 1.93, “Availability of
Electric Power Sources,” 1974, that licensees assess that system stability and reserves are such
that a single failure (including a reactor trip) would not cause a LOOP.

2.1.2 Principal Risks and Regulatory Expectations

Section 50.63," Loss of All Alternating Current Power," is commonly referred to as "the station
blackout rule." A station blackout (SBO) is defined in Section 50.2 as the “complete loss of
electric power to the essential and nonessential electric switchgear buses in an NPP

3
(i.e., a LOOP concurrent with a turbine trip and unavailability of the emergency ac power
system).” The SBO rule requires that NPPs be capable of withstanding an SBO by maintaining
core cooling for a specified duration (coping time) and recover from the SBO event. The
principle parts of SBO accident sequence are: (1) the initiating LOOP-the frequency of a LOOP
(2) the loss of onsite power-the unreliability of the onsite ac emergency power supplies and
common cause failure unreliability, (3) recovery-the likelihood that ac power will be restored
before the core is damaged, and (4) core damage probability - the sequences that result in core
damage from the failure to recover ac power and consequently, the failure of decay heat
removal or support systems necessary to safely shutdown. Core cooling failures, or loss of
reactor core cooling integrity can occur in 1 to 2 hours. Failures can also occur in 4 to 8 or more
hours from support system failures (e.g. batteries, compressed air, HVAC) or design limitations
(e.g. high suppression pool temperatures).

The SBO rule was based on NUREG-1032, “Evaluation of Station Blackout Accidents at Nuclear
Power Plants,” dated June 1988(Ref. 3). According to NUREG-1032, the estimated range for
the frequency of core damage as a result of an SBO accident is 1E-6 to 1E-4 per reactor-year
(RY). NUREG-1032 focused on the reliability of the onsite power system based on the
judgement that it would be easier to implement modifications, if required, on the onsite power
system rather than the grid. NUREG-1032 stated that offsite power system reliability was
dependent on a number of factors, such as repair and restoration capability, that were difficult to
analyze and control.

An RES report, “Regulatory Effectiveness of the Station Blackout Rule,” dated August 15, 2000
(Ref. 4) assessed if the SBO rule achieved the desired outcome. The RES report compared the
risk reduction expectations from SBO rule implementation as established in NUREG-1109,
”Regulatory/Backfit Analysis for the Resolution of the Unresolved Safety Issue A-44, ‘Station
Blackout,” June 1988 to the estimated risks from an SBO as documented in the licensee
probabilistic risk assessments (PRA). The RES report shows that SBO rule implementation
resulted in a risk reduction in the mean SBO core damage frequency (CDF) of 3.2E-05 per
reactor year (RY), slightly better than the 2.6E-05/RY expected.

NUREG-1032 concludes that “the capability to restore offsite power in a timely manner (less
than 8 hours) can have a significant effect on accident consequences.” NUREG-1032 studied
LOOP event frequency and duration data in three categories to i.e., plant-centered, weather-
related, and grid-related events and found the median recovery times to be 18, 210, and 36
minutes respectively, based on data from 1968 through 1985. NUREG-1032 found the overall
median recovery time to be 36 minutes. NUREG-1032 data shows that prior to SBO
implementation, of the 59 LOOPs at power which were identified, only four (7%) were more than
four hours; one was a grid event, three were weather related events, and the longest plant
related event was 165 minutes. NUREG-1032 expected “enhanced recovery times” for grid

4
related and severe weather LOOPs based on the availability of plant recovery procedures and at
least one source of ac power.

NUREG-5496, “Evaluation of Loss of Offsite Power Events at Nuclear Power Plants: 1980-
1996,” dated June 1998 (Ref. 5) found the median recovery times to be 20, 204, and 140.5
minutes for plant-centered, weather-related, and grid-related events. NUREG-5496 found the
overall median recovery time for LOOPs at power to be 60 minutes. More specifically, NUREG-
5496 identified six grid-related LOOPs from 1986 to 1989 with a median recovery time of 140
minutes and no grid-related LOOPs from 1990 to 1996. NUREG-5496 found that up to 1996,
the number of grid-related LOOPs was quite low and the recovery times were longer but the
data set was small; the executive summary concluded that the recovery times for SBO type
events were well below the minimum SBO coping time.

2.1.3 Control of Risks From Running EDG Tests To The Grid

EDGs are periodically tested (monthly) to the grid one at a time, for 60 minutes, and
approximately every 18 months for 24 hours, as specified in the TS. NRC Standard TS
surveillance requirements bases state that testing one EDG at a time avoids common cause
failures that might result from offsite circuit or grid perturbations. The 60 minute run stabilizes
engine temperatures, while minimizing the time the EDG is connected to the offsite source. The
Standard TS notes that the 24 hour test is not performed with the reactor at power but may be
performed to reestablish operability provided an assessment determines the safety of the plant
is maintained or enhanced. The TS bases state the assessment shall consider potential
outcomes and transients associated with a perturbation of the offsite or onsite system when tied
together and measure these risks against the avoided risk of a plant shutdown and startup to
determine that plant safety is maintained or enhanced when the surveillance is performed while
at power.

10 CFR 50.65, “ Requirements for monitoring the effectiveness of maintenance at nuclear power
plants,” commonly referred to as the “maintenance rule,” requires licensees to assess and
manage risk when performing maintenance activities as follows:

(a)(4) Before performing maintenance activities (including but not limited to surveillance,
post-maintenance testing, and corrective and preventative maintenance), the licensee
shall assess and manage the increase in the risk that may result form the proposed
maintenance activities. The scope of the assessment may be limited to structures,
systems, and components that a risk-informed evaluation process has shown to be
significant to public health and safety.

5
NRC Regulatory Guide 1.182, “Assessing and Managing Risk Before Maintenance Activities at
Nuclear Power Plants, May 2000 (Ref. 6) provides guidance on implementing the provisions of
10CFR50.65 (a)(4) by endorsing Section 11 to NUMARC 93-01, “Nuclear Energy Institute
Industry Guideline For Monitoring The Effectiveness of Maintenance At Nuclear Power Plants,
February 22, 2000 (Ref. 7). Section 11 to NUMARC 93-01 addresses offsite power in several
areas. For example, Section 11.3.2.8 states “Emergent conditions may result in the need for
action prior to conduct of the assessment, or could change the conditions of a previously
performed assessment. Examples include ......or significant changes in external conditions
(weather, offsite power availability).”

2.2 Reactor Trips Degrade the Grid and Result in Regulatory Actions

All reactor trips from full power operation are a random test of the capacity and capability of the
grid and as such are potentially grid-related events. Under GDC 17 the grid should have
sufficient capacity and capability to allow the NPP to pass this test. When a reactor trips, the
voltage in the vicinity of the NPP drops from the loss of NPP main generator reactive power
supply and the additional loading from the transfer of the NPP loads to the grid. The voltage
normally recovers quickly as “spinning reserves” and other reactive power supplies immediately
supply power. LOOPs, partial LOOPs, momentary LOOPs, and voltage degradations below the
plant specific low limit following or coincident with a reactor trip are evidence of a potential
electrical weaknesses in the grid.

The NRC took generic actions consistent with GDC 17 after two reactor trips in summer months
resulted in degraded NPP voltages below the levels needed to respond to a design basis event.
One of the events involved two occurrences, two weeks apart, in July 1976 at a NPP in the
Northeast. In the first occurrence, when the reactor tripped the 345 kV voltage dropped
approximately 5% from 352 kV to 333 kV for one hour. This voltage reduction along with the
voltage drops through the NPP transformers, reduced the voltage at safety related equipment to
levels that were insufficient to operate the equipment. In addition, certain non-safety related
equipment did not start due to blown fuses. Corrective action included raising undervoltage
relays setpoints to assure the plant would be separated from a degraded grid before the voltage
dropped to a point where equipment operability could no longer be assured.

A few weeks later, the inrush current from the start of a non-safety 1500 horsepower motor
resulted in low voltage and the EDGs automatically started and loaded. However, during
automatic load sequencing the inrush current from safety motor starts caused the bus voltage to
drop below the new undervoltage setpoints. The CCDP for this event was 1.4E-02 due to the
lack of plant procedures to respond to the event. This event resulted in an NRC generic letter
(not numbered at the time) dated June 2, 1977 (referenced in ref. 8) requiring licensees to add
degraded voltage relays to trip the offsite power supply to safety buses and start the emergency

6
onsite power supplies at or above the calculated minimum voltage levels needed to withstand a
design basis event.

The second reactor trip occurred in September 1978 at a dual unit NPP. When the reactor
tripped, the transfer of the station loads tripped a transmission system auto-transformer that was
already feeding the other NPP’s station power transformer. The loads from both NPPs
transferred to, and overloaded, a “back-up” NPP transformer. Power was restored in
approximately 88 minutes and the CCDP was less than 1.0E-06. The licensee’s review of the
event found that degraded voltage conditions would result at the safety buses following a design
basis event and that the safety loads might not transfer to the EDGs. After this his event, the
NRC issued Generic Letter (GL) 79-36, “Adequacy of Station Electric Distribution System
Voltages,” August 8, 1979 (Ref. 8) which expanded the NRC review of the adequacy of the
electric power system to include the results of plant-specific analysis using NRC guidelines for
voltage drop calculations.

The GL 79-39 guidelines for voltage drop calculations require licensees to consider a reactor trip
and the “minimum expected ”and“ maximum expected grid voltage as follows:

Separate analyses assuming the power source to the safety buses is ... (c) other
available connections to the offsite network one by one assuming the need for electric
power is initiated by (1) an anticipated transient (e.g, unit trip) or (2) an accident,
whichever presents the largest load demand situation.

The voltage at the terminals of the safety loads should be calculated based on....the
assumption that grid voltage is at the “minimum expected value” ....and selected based
on the least of the following: (a) The minimum steady-state voltage experienced at the
connection to the offsite circuit. (b) The minimum voltage expected at the connection to
the offsite circuit due to contingency plans which may result in reduced voltage from the
grid. (c)The minimum predicted grid voltage from grid stability analysis (e.g. load flow
studies).

Provide assurance the actions to assure adequate voltage levels for safety loads do not
result in excessive voltage, assuming the maximum expected value of voltage at the
connection of the offsite circuit...

....requests licensees to state planned actions including any LCO for TS in response to
experiencing voltages below analytical values.

7
2.3 Nuclear Power Plant Voltages Based on Grid Electrical Parameters

The North American electric power supply grid consists of four nearly independent large major
areas that are interconnected. Approximately 160 control centers perform the load dispatching
and switching operations. Current flows freely within this system according to the laws of
electricity. The grid operating or transmission entity analyzes this system for stability, short
circuits, load flows, and voltages to ensure that the grid security is maintained. Typically,
thousands of grid operating configurations are analyzed, assuming numerous initial conditions,
such as the availability of the generators, sudden loss of the large generators or loads, the
minimum and peak transmission system loading, equipment out of service (EOOS), and faults.

The results of the grid analyses are typically summarized for the NPP in terms of the minimum
and maximum expected voltages and impedances at the high-voltage terminals of the NPP
power transformers. The NPP uses these parameters to calculate whether NPP internal
voltages are within equipment ratings and the minimum voltages using the GL 79-36 guidelines.
Licensees periodically revise these analyses with updated external voltages and impedances
from the grid operating entity. If the NPP internal voltages are not adequate, i.e expecting that a
unit trip or other condition would result in operating voltage too close to the degraded voltage
relay and alarm setpoint, the licensees and grid operating entity may adjust their systems (e.g.
move NPP or grid transformer voltage taps) or establish compensatory measures (e.g.
procedure revisions) to avoid potentially adverse conditions or configurations. In some cases,
the NPP or the grid operating entity may need to add equipment such as a transformer with an
automatic load tap changer or capacitors.

2.4 Effects of Deregulation of the Electric Power Industry on Nuclear Power Plants

In 1992, the National Energy Policy Act (NEPA) encouraged competition in the electric power
industry. NEPA requires, in part, open generator access to the transmission system and
statutory reforms to encourage the formation of wholesale generators. The electric industry
began deregulating after the April, 1996 issuance of FERC Order 888, “Promoting Wholesale
Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities,
Recovery of Stranded Costs by Public Utilities and Transmitting Utilities,” which requires that
utility and nonutility generators have open access to the electric power transmission system. A
detailed state-by-state status is available on a Department of Energy website and shows about
50% of the state utility regulatory commissions have or plan to deregulate, and 50% have no
plans to deregulate or have put deregulation on hold.

Prior to economic deregulation of the electrical system, NRC licensees were both electrical
generators and transmission system operators. Initial licensing of NPPs included analyses of
electrical system performance with certain contingencies to assure reliable offsite power. With

8
economic deregulation, NRC licensees no longer control the transmission system - typically,
generation and transmission are separate corporations.

Deregulation is of interest to the NRC. The appendices of NRC, “Strategic Plan, Fiscal Year
2000 - Fiscal Year 2005,“ October 4, 2000 (Ref. 8) note that one of the major external factors
that could significantly affect achievement of Strategic or Performance Goals is the ongoing
economic deregulation and restructuring of the electric power industry. The NRC has not asked
its licensees to analyze electrical system performance under the current conditions, however,
SECY-01-0044, “Status of Staff Efforts Regarding Possible Effects of Nuclear Industry
Consolidation on NRC Oversight,” March 16, 2001 (Ref. 9) recommends in the area of grid
stability and reliability issues that the staff monitor the developments unfolding in different parts
of the country and continue the current efforts to assimilate information.

An RES study, “The Effects of Deregulation of the Electric Power Industry on The Nuclear Plant
Offsite Power System: An Evaluation,” dated June 30, 1999 (Ref. 10) was the basis for the
information in SECY 99-129 in response to Commissioners’ questions. The RES study was
based on NPP operating experience, the staff’s review of NERC reliability forecasts, visits to 17
grid control entities, and the actions of two licensees with the California Independent System
Operator (CAISO). The RES study and SECY 99-129 identified the potential impacts of
deregulation of the electric industry on grid reliability that are relevant to this assessment:

• The risk from the potential grid unreliability due to deregulation is likely to be minimal,
although individual plants might have an increase in the CDF due to deregulation of as
much as 1.5E-05/RY.

• The grid design and operating configurations were established before the electric power
industry was deregulated to ensure the correct voltages on the grid and at NPPs. Failure
to analyze and reconfigure the grid under changing conditions could result in abnormal
voltages or frequencies at the NPPs. Deregulation may result in unanalyzed grid
operating configurations because open access to the transmission system changes the
current flows and voltages throughout the grid according to fundamental (Kirchoff’s) laws
of electricity. Today more blocks of power are being transmitted over greater distances;
and grid operating entities not in involved the power transaction may see their operation
disrupted by unexpected power flows. Predicting the amount and path of the current and
power and the voltages throughout the grid requires analyses.

• The duration of a LOOP or a SBO may increase. Changes in ownership and control of
generation and transmission facilities adds to the number of entities that must be
coordinated and is likely to increase recovery times following a grid disturbance.

9
The NRC issued Information Notice (IN) 98-07, “Offsite Power Reliability Challenges From
Industry Deregulation,” February 27, 1998” (Ref. 11) to alert licensees to the potential adverse
effects of deregulation of the electric power industry on the reliability of the offsite power source.
The NRC also issued IN 2000-06: “Offsite Power Voltage Inadequacies,” March 27, 2000 (Ref.
12) to inform licensees of events that caused concerns about the voltage adequacy of offsite
power sources.

At an industry/NRC meeting on May 18, 2000 (Ref. 13) the industry discussed the initiatives of
the Pennsylvania, New Jersey, Maryland (PJM) Nuclear Owners/Operators (grid operator for 12
NPPs), the California ISO (grid operator for 8 NPPs), and the Institute of Nuclear Power
Operations (INPO) to help maintain GDC 17, the SBO rule, and technical specification
compliance in a deregulated environment. The industry initiatives include a plant-by-plant review
to ensure each NPP has established appropriate interface with the grid operator, verified
procedural adequacy for a LOOP or degraded grid, verified responsibility for NPP and
switchyard high voltage equipment maintenance, confirmed the validity of grid reliability and
design assumptions and the degraded voltage trip settings, and trained operators; these actions
were detailed in a letter from the Nuclear Energy Institute (NEI) to the NRC on June 26, 2000,
“Electric Grid Voltage Adequacy. (Ref. 14)” A followup meeting was held on October 27, 2000
(Ref. 15) to discuss the status of industry activities, the Electric Power Research Institute (EPRI)
Power Delivery Initiative to develop tools to enhance grid reliability, and the agenda for an
industry workshop “Grid Reliability Workshop” that took place in April, 2001.

The NRC issued Regulatory Issue Summary (RIS) 2000-24, “Concerns About Offsite Power
Voltage,” December 21, 2000 (Ref. 16) to inform addressees of concerns about grid reliability
challenges as a result of industry deregulation, potential voltage inadequacies of offsite power
sources, and actions the industry had committed to address this issue. The RIS also stated that
the NRC is continuing to work with the nuclear power industry to address this matter and
acknowledged that the Nuclear Energy Institute would take the following steps as an industry
initiative: (1) provide guidance to utilities on the need for, and acceptable techniques available to
ensure, adequate post-trip voltages; (2) establish provisions to log and evaluate unplanned
post-trip switchyard voltages to help verify and validate that the intent of Item 1 is met; and(3)
determine plant-specific risks of degraded voltage and double sequencing scenarios.
The NRC is periodically reviewing the status of industry initiatives under RIS 2000-24. The
industry and the NRC met on March 15, 2002 (Ref. 17) to discuss the status of industry INPO,
EPRI, CASIO, and PJM activities. The industry concluded that their initiatives verify that barriers
are in place to ensure NPPs are protected from a degraded grid; however, the details of plant
specific results are not available to the NRC.

10
3.0 DISCUSSION

For purposes of this work, since our focus is on aspects of grid performance, some events are
defined differently here than in other assessments - a number of the events which are defined in
this assessment as grid related LOOPs are referred to in other event studies, which had a
different focus, as plant-centered. These aspects are discussed below.

The executive summary of NUREG-5496, which estimates the LOOP frequency and duration
based on operating experience from 1980–1996 states “...For this study, the event was
considered an initiating event if the LOOP caused the reactor to trip or if both the LOOP and the
reactor trip were part of the same plant transient, resulting from the same root cause. It was not
an initiating event if either no reactor trip occurred, or the cause of the reactor trip did not directly
cause the LOOP event, but the reactor trip subsequently caused the LOOP event. All events
included in this study are LOOP events, but only the initiating events were used in the frequency
analysis.”

Consider the following example. An event initiated by a turbine trip which resulted in a LOOP
would be considered a plant-centered event in most instances. However, if the reason that the
plant disconnected from the grid following the turbine trip was that the grid voltage decreased
below the undervoltage relay settings because of the loss of the plant's own generating capacity
or grid voltage or loading conditions at the time of the turbine trip, for our purposes, this event is
considered grid related. One of the goals of GDC 17 is to assure that a plant trip will not result
in a LOOP. If due to lack of capacity or capability to withstand a sudden disturbance, the grid is
in a condition such that the lost generation due to the NPP trip causes conditions which lead to a
LOOP, our interpretation is that the LOOP is grid related. For purposes of this assessment, the
initiating event may be a turbine trip, but the root cause of the LOOP is the degraded condition
of the grid.

This distinction may be important from a risk perspective. Although some licensees risk analysis
may consider the potential for a reactor trip to cause a LOOP; licensee risk analysis often
consider a reactor trip and a LOOP to be independent events. The typical risk analysis
considers a reactor trip and a LOOP to be independent events - the probability of a LOOP is not
impacted by the reactor trip. However, if the grid is in a condition such that a loss of generation
leads to degraded voltage and a consequential LOOP, the risk impact of a reactor trip would be
greater. Also power restoration, which is important from a risk perspective, is also dependent on
grid operator direction and action following grid initiated event-for our purposes it is planned to
investigate if this time is increasing or decreasing.

Consider another example. It is generally assumed that a reactor trip will not lead to a LOOP at
a different NPP. However, if grid conditions are such that loss of generating capacity from a
NPP trip leads to degraded voltage and a LOOP at another site or plant, the LOOP is considered

11
to be grid related. Again, the risk implications of a reactor trip would be greater, particularly if
several units are affected.

The risk impact of grid related events may be underestimated due to the classification of events
as plant centered when the root cause relates to the ability of the grid to maintain adequate
electrical power following a reactor trip.

3.1 Methods for Data Collection and Risk Analyses

For the purposes of this assessment before deregulation was assumed to be 1985–1996 and
after deregulation was assumed to be 1997–2001. As 1997 was first full year of NPP operation
with the grid deregulated it was selected as the starting point for deregulation; in April 1996,
FERC Order 888 required that generators have open access to the transmission system.

To be consistent with other NRC assessments, this assessment considered an event to be a

LOOP when all available EDGs started and loaded. A partial LOOP was indicated by the start
and loading of one or more, but not all the EDGs. Momentary LOOPs and partial LOOPs were
indicated by the start of the EDGs; however, the voltage quickly recovered so the EDGs did not
load. Partial or momentary LOOPs are generally not risk significant unless complications set-in;
however, they helped to identify potential NPP sensitivities to a grid-related event.

Appendix A, provides summaries of grid events that affected NPP performance from 1994
through 2001. Although deregulation did not start until 1997, RES selected 1994 as a starting
point for the collection of events; RES was aware of least one grid entity that used 1994–1996
grid events that affected its NPPs, in part, to obtain the lessons learned for its future operation in
a deregulated environment, so it was judged RES should do the same. The events were
identified and summarized from licensee event reports (LERs) in the NRC Sequence Coding and
Search System, NRC inspection reports, NRC preliminary notification (PNO) reports, NERC
Disturbance Analysis Working Group (DAWG) reports, and CAISO and PJM reports, which are
discussed below. The LER, PNO, and DAWG event dates were cross-referenced to identify the
events affecting multiple NPPs. It is emphasized the CAISO and PJM reports were used not to
be critical, but to gain insights; these entities are proactive with comprehensive programs and
actions for the operating large, robust grids in a deregulated environment.

The DAWG reports helped identify when the NPP event was part of a larger grid disturbance
when this was not evident from the LER. The NERC DAWG analyzes a subset of the grid
events reported to the Department of Energy (DOE) under 10 CFR, Chapter II, “Report of Major
Electric Utility System Emergencies,” Section 205.351 “Reporting Requirements,”(Ref. 18).
Section 205.351 requires electric utilities or other entities engaged in the generation,
transmission, or distribution of electric energy for delivery or sale to the public to report to DOE
certain losses of system “firm” loads, voltage reductions or public appeals, vulnerabilities that

12
could impact system reliability, and fuel supply limitations. Some of the DOE events that involve
the transmission system are of interest for this report. The DOE events and NERC DAWG
reports are available on their websites.

In many of the Appendix A events power restoration, which is important from a risk perspective,
was at least in part, dependent on grid operator direction and action following grid initiated event.
The Appendix A events were defined and grouped as follows:

• R events are losses of electric power from any remaining power supplies as a result of,
or coincident with, a reactor trip at power. R events are random tests of the capacity and
capability of the grid. Losses of electric power with a reactor trip include any LOOPs,
partial LOOPs, momentary LOOPs, or voltage degradations below the plant specific low
limit. The LOOPs are potentially risk significant.

• S events are reactor trips where the first event in the sequence of events leading to the
reactor trip was in the switchyard or substation nearest the plant.

• T events are reactor trips where the first event in the sequence of events leading to the
reactor trip was in the transmission system beyond the switchyard or substation nearest
the plant.

• L events are LOOPs where the first event in the sequence of events leading to the LOOP
was in the grid. LOOPs at zero power are indicated by a zero suffix. Momentary LOOPS
are indicated by LM. LOOPs at power are potentially risk significant.

• PL events are partial LOOPS where the first event in the sequence of events leading to
the partial LOOP was in the grid.

• I events are events of interest that provide insights into the plant response to a grid
initiated event, but did not involve a unit trip, LOOP, or partial LOOP.

Table 1 “Grid Event Summary,” gives the numbers, types, and dominant causes the reactor
events from 1994 to 2001 based on detailed information in Appendix A, Tables A-1 and A-4.
The R and L event groups LOOPs are potentially risk significant and analyzed in Section 3.2 and
discussed in Section 3.3.

13
 Table 1 – Grid Event Summary
Event group Number of reactor events per year (1994–2001) Dominant causes

94 95 96 97 98 99 00 01 Total

R 0 0 2 3 1 3 1 10 3 LOOPs , 6 partial LOOPs, &

one voltage degradation from
plant/grid electrical weaknesses

S 4 6 2 2 2 2 4 2 24 Grid equipment malfunctions

T 4 5 7 3 2 1 22 Grid equipment malfunctions

@ power 1 1 Grid equipment malfunctions

L
0 power 1 1 1 1 4 Human error

PL 3 1 2 1 2 9 Grid equipment malfunctions

Total 12 11 11 10 6 7 10 3 70 Grid equipment malfunctions

Simplified event trees were developed in Appendix B, “Risk Analyses” for the purposes of
estimating and comparing the average industry CDF from an SBO before (1985–1996) and after
(1997-2001) from deregulation using LOOP and other operating data in Appendix C, “LOOP and
Scram Data 1985-2001.” As mentioned above, past risk analysis typically consider a reactor
trip followed by a LOOP, to be two independent events, i.e. risk analysis do not always model
this event because of low probability. However, Table 1 there were more LOOPs from R events
- as a result of or consequence of a reactor trip - than L events. Appendix C, “LOOP and Scram
Data 1985–2001,” Table C-1 shows that two of the six LOOPs between 1997-2001 were as a
consequence of a reactor trip was developed; based on this observation, a model was
developed below to evaluate the risk contribution from a LOOP as a consequence of a reactor
trip. As all of the LOOPs since 1997 occurred in the summer-May to September in contrast to
23 of 54 LOOPs in the summers of 1985-1996, the data was also analyzed after deregulation for
the summer months.

3.2 Risk Insights and General Observations

3.2.1 Risk Insights

The risk results are summarized in Table 2, “Changes In Risk After Deregulation.” The table
provides a “delta CDF” and “observations” that help explain the delta CDF in term of key data
changes.

The “delta CDF” was obtained by subtracting the risk “BEFORE” deregulation from the risks
after deregulation. A negative delta CDF indicates the risks have decreased since deregulation.
A positive delta CDFs may offset the risk reduction obtained from SBO rule implementation.
Specifically a delta CDF of more than 0.6E-05/RY (the difference between the risk reduction

14
outcome and expectation from SBO rule implementation) and a delta CDF of more than 3.2E-
05/RY (the outcome from SBO rule implementation) partially and completely offsets the risk
reduction from SBO rule implementation, respectively.

Table 2
Changes In Risk After Deregulation

Observation Baseline Change

-Delta CDF/RY

BEFORE Average industry CDF from an SBO is 1.3E-05/RY considering 0

deregulation consequential and plant/grid/weather LOOPs .
1985–1996 -Risk reduction from SBO rule 3.2E-05/RY; expectation 2.6E-05/RY
-Reactor trips/RY=3.4
-LOOPs/RY=0.05
-Probability( LOOP/reactor trip) =0.002
-Percent LOOPs >4hours=17%

AFTER deregulation Risk reduction from SBO rule implementation maintained. -0.9E-05
1997–2001 CDF decreased below baseline due to offsetting changes:
-Reactor trips/RY =1.0
-LOOPs/RY=0.009
-Probability(LOOP/reactor trip)=0.0045
-Percent of LOOPs > 4 hours=67%

SUMMER Risk reduction from SBO rule implementation maintained. -.5E-05

After deregulation CDF decreased below baseline due to offsetting changes:
1997-2001 -Reactor trips/RY=1.1
-LOOPs/RY =0.021
-P(LOOP/reactor trip)= 0.01
-Percent LOOPs > 4 hours =67%

SUMMER Risk reduction from SBO rule implementation offset

SENSITIVITY -EDG out-of-service for 14 days with a chance of a degraded grid 1.1E-05
1997-2001 -Increase time grid degraded to 30 days based on experience 1.4E-05
-EDG out-of-service for 14 days with the grid degraded 7.8E-04

The BEFORE observations benchmark the risks, the risk reduction obtained from SBO rule
implementation which are used to evaluate the significance of changes in risk after deregulation,
and key data that are used to explain the delta CDF. The key data include the number of
reactor trips per RY; the number of LOOPs/RY; the probability of a LOOP as a consequence of
a reactor trip or and the percent LOOPs more than 4 hours. As a point of reference
P(LOOP/RT) is 0.002 and corresponds to the grid being in this condition approximately 18 hours
per year (8760 hours per year times 0.002). The results are compared graphically in Figure 1,
“Risk Profile” in terms of the CDF/RY. Figure 1 and Table 2 indicate the following:

• The risks “AFTER” deregulation (1997-2001) have decreased just below the risk BEFORE
deregulation. This indicates that deregulation has not eroded the risk reduction from SBO

15
 rule implementation. Comparison of the key factors in Table 2 before and after deregulation
help to explain the decrease in the risk; i.e., the decreases in the risk from the decreases in
the number reactor trips/RY and number of LOOPs/RY have offset the increases in the risk
from the increases in percentage of LOOPs more than 4 hours and probability of a LOOP
given a reactor trip. As a point of reference P(LOOP/RT) is 0.0045 (as compared to 0.002
before deregulation) and corresponds to the grid being in this condition approximately 40
hours per year.

• The risks after deregulation in the “SUMMER” - May to September, 1997–2001- have
decreased slightly below that BEFORE deregulation; again deregulation has not eroded the
risk reduction from SBO rule implementation. Comparison of the key factors in Table 2 before
and after deregulation help to explain the decrease in the risk; i.e. the decreases in the risk
from the decreases in the number reactor trips/RY and number of LOOPs/RY have offset the
increases in the risk from the increases in the percentage of LOOPs more than 4 hours and
the probability of a LOOP given a reactor trip. As a point of reference P(LOOP/RT) is 0.01
and corresponds to the grid being in this condition approximately 88 hours per year, all during
the summer months.

• SUMMER SENSITIVITY studies were completed to evaluate the potential risk increases from
(1) the EDG out of service (OOS) for 14 days with a higher likelihood that the grid will be in
degraded condition, (2) increasing in the amount of time that the grid is degraded, and (3) the
EDG OOS for 14 days while the grid is degraded. Actual approved EDG OOS typically range
from 3 to 14 days; plant specific analyses may provide different results.”

Table 2 delta CDFs indicates that in each of these three case, the risk increase partially or
fully offsets the risk reduction from SBO rule implementation. In each of these cases, this
risk increase may not be detected unless the assessment of the risk considers the increased
CDF from an SBO (a) as a result of a consequential LOOP and other LOOPs separately (b)
summer time operation (c) actual demand performance under LOOP conditions (d) the results
of electrical analyses to determine whether a reactor trip will cause a LOOP (discussed in
Section 3.3). The discussion follows:

(1) The first sensitivity study estimated a delta CDF as a result of having one of two EDGS OOS
with a 0.01 chance that a LOOP will result from a reactor trip. Table 2 and Figure 1 shows this
as a spike in the risk as “EDG/Avg” that is just above the risk before deregulation

16
(2) The second sensitivity study evaluated the risk increase from an increase in the amount of
time the grid was degraded (the time that the probability of a LOOP given a reactor trip was 1)
to approximately 800 hours or approximately 30 days . When this time is increased to 800
hours, the risk and delta
CDF increase above the
BEFORE values as shown
in Figure 1, “30Day” and
Table 2. At a recent
meeting, EPRI shared data
that showed that one region
of the country experienced a
“Stage 3" alert
approximately 795.8 hours
over a few months in one
year as a result of market
gaming. Stage 3 is when
the system reserves have
been depleted to
approximately 1.5% of the
load and the final stage of
the grid operators three-step
emergency program that is
Figure 1 - Risk Profile
accompanied by load
curtailment (rolling
blackouts) to keep from further erosion of the reserves needed for system stability should
there be a disturbance such as a large generating unit trip or transmission system fault.

(3) As shown in Figure 1 and Table 2, the worse case increase in the risk above the before
deregulation values is when the one EDGs is unavailable for 14 days with the reactor at power
and the grid is in a condition such that a LOOP could result from a reactor trip. Figure 1
shows this as a spike, “EDG/WC.” As previously discussed, TS typically allow one EDG to be
unavailable for allowed outage times (AOTs) of up to 72 hours, and in some cases with
compensatory measures, up to 14 days. “As previously discussed in Appendix B, Section B.4,
item (4) the CCDPs used in the risk analysis reflect the use of compensatory measures.

The NRC does not regulate the grid; however, the performance of offsite power is a major
factor for assessment of risk. As previously discussed the licensees are expected to assess
and manage the increase in the risk that may result from maintenance and outage activities;
NPPs should understand the condition of the grid before scheduling EDG, maintenance or
AOTs.

17
Assessment

With respect to maintaining the current levels of safety, offsite power is especially important with
regard to the risk associated with emergency diesel generator (EDG) maintenance and outage
activities. Consequently, NRC and licensee assessments of risk that support EDG maintenance
and outage activities should include: (a) assessment of offsite power system reliability, (b) the
potential for a consequential LOOP given a reactor trip, and (c) the potential increase in the
LOOP frequency in the summer (May to September). Regarding (a) above, the assessment of
the power system reliability and risks from plant activities can be better managed though
coordination of EDG tests with transmission system operating conditions.

3.2.2 General Observations

1. Table 1 shows that grid problems that affect the NPP are not infrequent. Table 1 shows
that grid equipment failures and malfunctions were the dominant causal factor for every
event group except the R event group, which was dominated by grid and plant electrical
weaknesses (see Section 3.3.2). Appendix A indicates that most of the grid equipment
failures and malfunctions were in high-voltage circuit breakers and protective relays of
the switchyard and transmission system.

2. Some NPPs and transmission companies used the experience (events 1, 2, 37 in

Appendix A) to establish or strengthen interface agreements to better control operating,
maintenance, and design activities that potentially affect the NPP. Similar agreements
could be used to enhance the maintenance of high-voltage circuit breaker and protective
relays which were previously noted to be a dominant causal factor. The NRC does not
require or review these agreements.

In event 2, the SBO alternate ac power supply failed to start during a NPP test and the
NPP discovered that the transmission company, who owned the alternate ac (SBO)
power supply, installed a modification 4 months earlier that defeated its safety function.
This is an example where a contractual agreement requiring NPP review and approval of
transmission company SBO alternate ac power supply modifications may have ensured
their operability.

3. While the data set is small, recent experience indicates that the average duration of
LOOPs has increased. Based on historical data, power restoration times following a
LOOP are assumed to be less than 4 hours; most recent LOOPs have lasted significantly
longer. In addition, longer LOOPs are not consistent with regulatory expectations . Table
3, “Percent of LOOPs Greater Than 4 Hours,” shows changes in the percent of LOOPs
more than four hours and median recovery times.

18
 Table 3
LOOP Recovery Time

Before SBO rule Before Deregulation After deregulation

NUREG-1032 BASELINE AFTER
1968-1985 1985-1996 1997-2001

Percent of LOOP > 4 hours 7 17 67

Median LOOP restoration time 36 60 612

in minutes

NUREG-1032 concludes that “the capability to restore offsite power in a timely manner
can have a significant effect on accident consequences.” NUREG-1032 found the overall
median recovery time to be 36 minutes based on data from 1968 through 1985.
NUREG-1032 data shows seven percent were more than four hours; one was a grid
event, three were weather related events, and the longest plant related event was 165
minutes. NUREG-1032 expected “enhanced recovery times” for grid related and severe
weather LOOPs based on the availability of plant recovery procedures and at least one
source of ac power. NUREG-5496 data from 1985–1996 indicates the overall median
recovery time for LOOPs at power to be 60 minutes and that 17 percent of the LOOPs
lasted more than 4 hours. More recently, the data from 1997-2001 show 67 percent of
the six LOOPs lasted more than four hours and the median recovery time is 612 minutes.
Appendix C data shows that one plant LOOP was 1980 minutes, two weather (involving
the grid) LOOPs lasted 688 and 1560 minutes, and one LOOP from a reactor trip lasted
612 minutes (event 16). The expectations for enhanced recovery have not been
achieved. In addition, five of the six LOOPs since 1997 involved the grid.

4. Three of the events summarized in Appendix A reached thresholds of interest from a risk
perspective under the NRC ASP Program. The ASP Program found the CCDPs of
events 16, 33, and 58 to be 2.8E-06, 9.6E-06, and 9.1E-05, respectively. The CCDPs
reached a threshold interest because of NPP conditions, not because of grid anomalies.
However the ASP analyses of individual events alone may not be giving the entire picture
from a risk perspective. For example as shown in Figures 1, the CCDP is a factor in the
analysis of the CDF and CCDPs on the order of E-06 and 3.0E-05 can result in CDFs
that could substantially offset the reduction obtained from SBO rule implementation.

5. Events identified equipment sensitivities to low voltage.

Three events in Appendix A (8, 20, 34) identified microprocessor-controlled equipment

that was sensitive to low voltage as follows: a radiation monitor lost program memory
(event 8); several programmable controllers swapped from auto to manual following a
voltage transient (event 20); and voltage-regulating transformers shut down following a

19
 voltage transient, and the licensee found they automatically shut down when voltage
drops to 20% of nominal for 6 to 8 cycles (event 34). Microprocessor-controlled
equipment has been used to replace analog equipment, and the voltage characteristics
of the replacement equipment appears to warrant attention.

Two events in Appendix A (17 and 45) show that circulating water pump synchronous
motor trips are sensitive to momentary low voltages due to switchyard and transmission
line faults. Optimizing synchronous motor protective trips may avoid some reactor trips.

Assessment

It is important to have mechanisms in place to ensure that grid operators will provide reliable
electrical power. Since external factors impact the ability of licensees to manage risks and
understand the condition of the grid, some NPP licensees have implemented contractual
agreements with grid operators to provide a mechanism for maintaining secure electrical power
in the deregulated environment. Contractual arrangements should include specific,
communication protocols, operating procedures and action limits, maintenance responsibilities,
SBO (alternate ac) power supply responsibilities, and NPP and grid.

While the data set is small, recent experience indicates that the average duration of LOOPs has
increased. Based on historical information, power restoration times following a LOOP are
assumed to be less than 4 hours; more recent LOOPs have lasted significantly longer.
Recently (1997-2001) NPP and grid operating experience power restoration times are typically in
excess of four hours and in the past they were rarely longer than four hours. Longer restoration
for most of the events challenge whether either the NPP or the grid operator could actually
restore power to a NPP in time under accident conditions such as an SBO. These events
support the concern identified in SECY 99-129 that the time needed to coordinate grid
operations may increase in a deregulated environment.

3.3 Nuclear Plant Voltages Not Always Analyzed For Grid Conditions Experienced

The review of the R events in Appendix A found that three LOOPs (events 3, 16, and 33), five
partial LOOPs (events 15, 22, 38, 60, 62, and 64) and a voltage degradation below the minimum
voltage required by the technical specification for 12 hours (event 74 ) occurred coincident with,
or as a result of, a reactor trip. These events were similar as follows:

(1) Up to the time of the reactor trip, the offsite power supplies were operable per NPP control
room voltage readings that verified the technical specification minimum voltage requirements. In
addition, analyses of the offsite power system following a unit trip did not predict these events.

20
(2) A review of the previous and subsequent reactor trips at the NPPs with R events in Appendix
A found that LOOPs, partial LOOPs, and voltage degradations were not coincident with these
reactor trips. The initial grid and plant electrical conditions at the time of the R events were
different than in previous and subsequent reactor trips and did not include heavy transmission
line loading, switchyard and transmission EOOS, and degraded plant voltage-controlling
equipment. This is discussed further in Section 3.3.1.

(3) Eight of the 10 R events took place in June, July, and August. Seven of the 10 events were
in the Northeast (Maryland, New York, New Jersey, Pennsylvania, and Vermont). In the
summer, the increased system loading associated with the temperature lowers the voltage at the
ends of transmission lines. This is discussed further in Section 3.3.2.

(4) The partial LOOPs (events 15, 22, 38, 60, 62, and 64) and a voltage degradation below the
minimum voltage required by the technical specification for 12 hours (event 74) are not risk
significant but provide early indication that NPPs may not have analyzed the grid for the
conditions experience.

3.3.1 Grid Loading and Equipment Out of Service

Ideally, NPPs determine NPP voltage limits based on electrical system analyses which account
for the most limiting transmission system loading conditions and equipment out of service
(EOOS).

In event 74 in Appendix A, the licensee found that their failure to properly consider the impacts
of deregulation (i.e heavy grid loading coupled with the loss of voltage support from the NPP
generator) resulted in lower than expected NPP safety bus voltage. In addition it took 12 hours
to change power flows between Canada and Texas and get the required voltages to the NPP;
this helps to confirm the SECY 99-129 hypothesis that changes in ownership and control of
generation and transmission facilities adds to the number of entities that must be coordinated
and is likely to increase recovery times following a grid disturbance. Coordination of grid
operators in a deregulated environment challenges the expectations of “enhanced recovery” or
power recovery to the grid accident conditions. In event 3 the licensee attributed the LOOP to
the combined effects of heavy grid loading, a 500 kV substation out of service (OOS), loss of
voltage support from the NPP generator (resulting in a 4.5% voltage drop) and the transfer of
the NPP load (which resulted in an additional 3 to 6% voltage drop). The severity of the grid
condition revealed that the NPP station power transformer automatic tap changer had not been
set consistent with the design analyses so it could not compensate for the degraded grid.

Transmission analyses typically assume at least one major pre-event EOOS or contingency.
Events 15, 33, 38, and 60 in Appendix A involved multiple contingencies or very abnormal
operating conditions. Event 15 involved a transmission line outage and a substation outage that

21
left one of two available power generation paths, and a transmission line OOS that disabled a
NPP protective trip. In event 33, the licensee attempted sustaining NPP operation with major
current unbalances in both high-voltage generator output circuit breakers. In event 38, a
switchyard high-voltage circuit breaker was inadvertently closed during troubleshooting with one
of three offsite transmission lines OOS and a latent failure in a high-voltage circuit breaker
control system. In event 60, one of two high-voltage generator circuit breakers was OOS, a
latent failure existed on a switchyard disconnect switch, and NPP electrical equipment
malfunctioned.

In some events plant equipment, such as station power transformer automatic tap changers,
which control safety bus voltage levels, is assumed to be functional in the analyses of internal
voltages and by the grid controlling entity for the range of external voltages maintained at the
NPP. Thus, an inoperable NPP transformer automatic tap changer is a problem for both the
NPP plant and the grid operators As mentioned earlier in event 15 in Appendix A, a NPP
transformer automatic tap changer had not been set consistent with the design analyses. In
event 16 in Appendix A, a NPP transformer automatic tap changer had been in manual for
approximately 1 year due to a degraded relay and procedures that allowed its manual operation
without compensatory measures. Alarms that would draw operator’s attention to inoperable
safety bus voltage controlling equipment can help NPP operators identify the need to request
additional voltage support from the grid operators. Periodic verification of NPP transformer
automatic tap changer or other voltage controlling equipment operability could also help reduce
the likelihood and impact of low voltage damage to plant equipment. In addition, NPP
procedures that allow manual operation of this equipment should require compensatory
measures such as a request for voltage adjustment from the grid control entity prior to operation.

Four events in Appendix A were also random tests of the grid that resulted in unexpected
voltage drops; these types of events may provide early signs of weaknesses in offsite power
system capacity and capability. In event 22, the offsite power system could not support the
simultaneous restart of two 5500 HP feedwater pump motors without a partial LOOP. In event
59 the restart of a reactor recirculation pump motor caused an unexpected voltage transient. In
event 57 the electrical perturbation from Unit 1 reactor trip, tripped a Unit 2 heater drain pump
motor and caused a Unit 2 load reduction. In event 67 seven safety and some nonsafety motors
tripped, and did not restart following the voltage drop from the bus transfer and start of two
auxiliary feedwater pump motors. In events 22 and 67 if the grid does not have the capability,
automatic control circuitry could be used to minimize the probability of a LOOP.

3.3.2 Grid Reactive Capability Weakened

Several of the R events occurred in the summer in the Northeast. The PJM Interconnection
issued a publicly available study, “Results of Heat Wave 1999: July 1999 Low Voltage Condition
Root Cause Analysis,” dated March 21, 2000 (Ref. 19) for the purposes of identifying and

22
correcting the root causes of low-voltage conditions on two exceptionally hot days on July 6 and
19, 1999. On both occasions the 500 kV system voltage at multiple sites dropped approximately
5% from highs ranging from 545 kV to 525 kV, to lows ranging from 515 kV to 495 kV. Short-
term (30 minutes) grid anomalies during periods of high load are not uncommon while the grid
operating entity determines and completes response actions. PJM was concerned that the peak
load was not predicted and noted that it took several hours to restore voltage after implementing
all load management programs and 5% voltage reductions. The PJM concerns are consistent
with those in SECY 99-129, IN-98-07, and IN-00-06.

The PJM data show that, in both cases, widespread voltage reductions began near 10am and
voltages dropped sharply at noon. The voltages were restored to the 10am and noon levels in
approximately 10 and 6 hours, respectively, on July 6 and in 7 and 2 hours on July 19.

PJM found that the low-voltage conditions occurred because reactive demand exceeded reactive
supply due to record usage of electricity from high temperatures in much of the eastern half of
the U.S. Reactive supply was insufficient because some generators were unavailable or unable
to meet their rated reactive capability due to ambient conditions. Specifically, 54 PJM
generators reached a limit that restricted MVAR output to 72% of the reported capability and
weakened the grids capability to maintain adequate levels of voltage.

The PJM system did not have the reactive capacity as required by GDC 17 and consequently
was unable to restore voltages as quickly as expected. The analyses of grid voltage levels were
incorrect because generator reactive capability design limits were used instead of the actual
capabilities. Consequently, NPP voltages used to determine operability and analyses of offsite
voltage performance after a reactor trip are likely to be optimistic. Alternatively compensating
reactive capability can be purchased, obtained from new reactive power sources such as new
generation or capacitor banks.

As another consideration, reactor power uprates also reduce generator reactive capability and
collectively weaken the grid’s capacity to maintain or restore voltages as it did on the PJM
system. Licensees have been using power uprates to increase the output of their NPPs. As of
May 1, 2002, the NRC has completed 62 reviews, and the industry has collectively gained
approximately 3760 megawatt thermal (MWt) or 1200 megawatts electrical (MWe), an average
of approximately 20 MWe increase per NPP. However, the main generator reactive capability
decreases as the power (MW) output increases. For example, if a generator had a nameplate
rating of 1000 MVA, 95% power factor at rated voltage, it would correspond to an operating point
of 950 MW and 312 MVAR. If the power output increased approximately 20 MW to 970 MW,
the reactive capability would decrease to 243 MVAR, a difference of approximately 70 MVAR.
Collectively, the 1200 MW increase on 62 reactors has been accompanied by a 4340 MVAR
decrease.

23
Assessment

An important aspect of the changes to the electrical grid is the impact on the electrical analyses
of NPP voltage limits and predictions of voltages following a reactor trip and whether a reactor
trip will result in a LOOP. Recent experience shows that actual grid parameters may be worse
than those assumed in electrical analyses due to transmission system loading, equipment out-
of-service, lower than expected grid reactive capabilities, and lower grid operating voltage limits
and action levels. NPP design basis electrical analyses used to determine plant voltages should
use electrical parameters based on realistic estimates of the impact of those conditions.

Lessons learned include:

• LOOPs, partial LOOPs, momentary LOOPs, and voltage degradations below the technical
specification low limit following or coincident with a reactor trip are evidence of a potential
electrical weaknesses in the grid.

• The synergistic effects of reduced reactive capability on the NPP from hot weather and
several reactor power uprates should evaluated.

• In some events, plant equipment such as station power transformer automatic tap changers,
which control safety bus voltage levels, is assumed to be functional in the analyses of internal
voltages and by the grid controlling entity for the range of external voltages maintained at the
NPP. Periodic verification of NPP or other voltage controlling equipment operability may be
necessary to ensure their availability and require compensatory measures such as a request
for voltage adjustment from the grid control entity should availability be compromised.

• Under some circumstance degraded grid recovery times may take several hours. In the
Northeast, it took the grid operator for 12 NPPs 10 hours to resolve grid problems from the
unexpected behavior of the grid after planned voltage and load management programs had
been implemented and investigation found the grid power restoration procedures did not work
because the grid did not have the reactive capacity to quickly restore voltages. In the Mid-
West it took grid operations 12 hours to change regional power flows and restore voltage to a
NPP after the grid was stressed. These events support the concern identified in SECY 99-
129 ( as discussed in the background section) that the time needed to coordinate grid
operations may increase in a deregulated environment.

3.3.3 Transmission System Faults May Involve Multiple Reactor Trips

The review of the T events found that transmission system faults may involve multiple reactor
trips (events 24, 25, 48, and 53 in Appendix A). None of the events caused a LOOP. Events 48
and 53 were similar: two reactors at a dual-unit site tripped after a remote transmission line fault

24
opened multiple high-voltage circuit breakers, including the generator output breakers in the
switchyard.

In events 24 and 25, multiple reactors tripped, and other NPP operations were affected in a
minor way, during a grid disturbance due to the operation of common protective and/or design
features. The licensee final safety analysis reports (FSARs) demonstrated the adequacy of the
offsite power system by summarizing the results from power system analyses without discussing
operation of these features. In event 24, two pressurized water reactors (PWRs) tripped
simultaneously due to reactor coolant pump (RCP) bus undervoltage during a transmission
system disturbance. As a corrective action, one of the NPPs lowered the RCP bus undervoltage
and underfrequency setpoints to the minimum allowed by the technical specifications. In event
25, four PWRs tripped simultaneously: at one site, two reactors tripped due to RCP bus
undervoltage; and at another site, two of three reactors exceeded the variable overpower trip
setpoint (VOPT) during the load swing at the NPP from the transmission system fault.

Differences in the moderator temperature coefficient (MTC) levels explain why two of three
reactors tripped at one site. The MTC is a measure of the reduction in the core reactivity as the
water temperature increases. Two of the three reactors tripped when load fluctuations (a 700
MW decrease and significant load increase due to the grid instability) caused the steam bypass
control system (SBCS) valves to open and exceed the VOPT setpoint within the core protection
calculators (CSCs). The third reactor spiked to 102% power without reaching the VOPT
setpoint. The MTCs for the two reactors that tripped were -34 and -23.5 pcm per degree
Fahrenheit and near the end of core condition (EOC). The MTC for the reactor that did not trip
was more positive (-9 pcm per degree Fahrenheit) and near the beginning of core conditions.
The CPC VOPT is an expected response to the load change, as are the opening of the SBCS
valves, the increased steam demand, and the resulting power increase due to decreasing
temperature with a negative MTC. However, the closer the unit is to the EOC, the more rapid
the power increase and more likely that VOPT will trip the reactor.

The risk significance is that in the cases above the total risk from an event would be equal to the
sum of the risks from individual plants affected. The risk from a transmission line fault is the
sum of the risks from the NPPs involved i.e. 2–4 times individual plant risks.

As summarized in Appendix A, industry analyses of events 24 and 25 resulted in a total of 65

recommendations to address improved regional operational and engineering activities to
maintain grid reliability. The events resulted in recommendations that helped CAISO, which
was under development at the time of these events, to develop and implement a very broad and
comprehensive grid reliability program to manage and control regional operational and
engineering activities in real time. The program includes continuous update of analyses to
reflect operating conditions and changes in operating configurations .

25
Assessment

The significance of a grid event will need to take into consideration the impact of multiple reactor
units. In addition, NPP licensee analysis of the affects of transmission system disturbances had
not been updated to account for current grid conditions. Operation in a deregulated environment
may be better served by a comprehensive grid reliability program to manage and control
regional operational and engineering activities in real time, as is the case with the California ISO
and PJM, to maintain secure electrical power to NPPs.

3.4 NPPs Must Contract For Adequate Voltage Support

As a result of the July 1999 events, PJM identified 20 corrective actions including one in the area
of voltage operating criteria. The PJM website provides the “Voltage Criteria and Voltage Limits
Working Group Report,” dated September 11, 2000 (Ref. 20) that contains the “PJM-Base-Line
Voltage Limits,” which are duplicated below in Table 4. These voltage limits were part of FERC
Docket No. ER00-2993-000, “Order Accepting Tariff Filing,” dated August 31, 2000, which
amends the PJM Operating Agreement to permit and accommodate requests that PJM
schedule and dispatch generation to meet voltage limits (in Table 4) that are more restrictive
than those PJM otherwise determines are required for the reliable operation of the transmission
system in the PJM control area.

Table 4. PJM Base-Line Voltage Limits

Voltage level Load Dump* Emergency Low** Normal Low Normal High Voltage
(kV) (kV) (kV) (kV) (kV) Drop**

500 475 485 500 550 5%

0.95 0.97 1.00 1.10

345 310 317 328 362 5-8%

0.90 0.92 0.95 1.05

230 207 212 219 242 5-8%

0.90 0.92 0.95 1.05

138 124 212 131 145 5-10%

0.90 0.92 0.95 1.05

115 103 106 109 121 5-10%

0.90 0.92 0.95 1.05

69 62 63.5 65.5 72.5 5-10%

0.90 0.92 0.95 1.05
*=post-contingency 5 minute Emergency Limit, **=post-contingency 15 minute Emergency Limit

Table 4 “ “Normal” voltages of 0.95 nominal are likely to be below plant specified limits. NPPs
will have to request more restrictive voltage limits per the tariff. The entity making the request
will be responsible for all incremental generation and other costs, and that PJM will post on its

26
internet site its current determination of the voltage criteria that it will employ for transmission
grid reliability. In its filing, PJM used NPP voltage requirements to demonstrate the need for
the amendment to the operating agreement, stating that NPPs may have internal plant
requirements that require voltage limits different than the generic voltage limits necessary for the
transmission system.

RES previously found (ref 10) that on the west coast the CAISO and its NPP generators have
implemented binding “transmission control agreements” to ensure, in part, that the appropriate
technical parameters in the NPP analyses are explicitly stated. In a meeting between the NRC
and the industry on May 18, 2000 (ref. 13) one of the west coast NPPs discussed the status of
a NPP “grid specification” for the grid operator. The specification gives technical details that the
grid operators need, such as NPP transient and steady state loads, as a function of time, to
ensure the 230 kV offsite power system voltage would not go below the 218 kV. The grid
specification requires inspection and preventive maintenance of 230 kV switchyard equipment
under the control of the transmission entity but important to the adequacy of the NPP offsite
power system.

Assessment

Some grid operating entities that supply offsite power to NPPs, such as PJM and the CAISO,
maintain comprehensive grid reliability programs. They manage and control regional operational
and engineering activities through activities such as: electrical analysis of the grid in real time,
development of time-based voltage criteria, and implementation of binding contracts to supply
electrical power to meet NPP specifications. These programs help NPPs maintain the validity of
technical specifications, recovery times consistent with the SBO rule, and their obligations under
GDC17. These programs have been, in part, implemented through contractual agreements
between NPPs and grid operators so as to provide a mechanism for maintaining some
assurance of secure electrical power in a deregulated system to include specific grid and NPP
electrical requirements necessary to analyze and monitor the grid for the NPP.

3.5 EDG Test With Grid Degraded May Compromise Independence

Operating experience (events 7, 24, and 56) shows that an EDG failed one of three times while
running to the grid for test given a grid transient such as one in the transmission system or from
reactor trip. From a risk perspective, EDG testing to the grid for up to 24 hours was found to be
important, but not as significant EDG AOTs of 14 days with the grid degraded previously
discussed in Section 3.2. In event 7, the EDG tripped as transmission system switching
operations were being performed. In event 24, the EDG was exposed to a transmission system
fault while protective relaying was out of service to allow transmission test activities. In events 7
and 24, the EDG tripped and realigned to the safety buses as designed. However, in event 24

27
the EDG tripped later in the event when attempting to restore offsite power. Better coordination
of EDG test and transmission test and operating activities might have minimized the risks.

In event 56, the EDG overloaded after attempting to assume a greater share of the load on the
grid when the reactor tripped. The licensee estimated that the EDG current exceeded 600 amps
for 5 minutes (at least 133% above its continuous rating and 113 % above its short-time rating)
which was just below its overcurrent trip. No EDG damage was found during follow-up
inspection and tests. It could be argued that there EDG could have been restarted immediately
if required. It could also be argued that the EDGs may not have the thermal capability to restart
immediately successfully for this event, i.e. the EDGs were not typically purchased, or tested, to
demonstrate they have the thermal capability to withstand an initial load sequence, load run, an
overload as described, and immediately begin load sequencing for a second time. Better
protective relaying would trip the EDG from an overcurrent within a few seconds of the reactor
trip.

Assessment

Experience shows that running the onsite emergency diesel generator (EDG) to the grid for
testing with the reactor at power can potentially result in (a) the loss of an offsite and onsite
emergency power supply, or (b) damage to the EDG. The potential for these incidents could be
reduced if the NPP and the transmission company would better coordinate activities so that the
EDG is not tested to the grid when the grid is in a degraded condition.

3.6 Potential Damaging Effects of Current Unbalances From Grid Disturbances

An RES report “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,” dated
February 22, 2002 (Ref. 21) discussed an event that occurred on March 18, 2001, at a nuclear
plant in Taiwan, involving a fire and SBO due to an energetic electrical fault in 4.16 kV
switchgear with an insulation failure. The CCDP for the event was 2.2E-03. The damage was
so extensive that the exact cause could not be determined. A University of Texas consultant
reviewed the NPP station logs and found that frequent unbalanced transmission line voltages
since 1985 may have resulted in current unbalances (also termed negative phase sequence
current) that e prematurely aged the switchgear insulation. The utility suspected that
ferromagnetic resonance–NPP plant and transmission system equipment electrical
interactions–may have resulted in damaging levels of voltage. The available information
indicated there was no safety bus protective relaying to quickly detect the conditions.

In events 33, 50, 75, and 78 in Appendix A, phase current unbalances from grid-initiated events
tripped the reactor. In three of the four events (50, 75, 78), reactor trips were initiated as a result
of current unbalances from grid events that tripped non-safety-related RCP motors, circulating

28
water pump motors, or the main generators. In these events, alarms also alerted operators to
abnormal current unbalances.

Event 33 shows the damaging effects of phase current unbalance on NPP switchyard
equipment. In June 1997 a switchyard relay technician reported unbalanced phase current
readings on phase B of the generator 230 kV output circuit breakers GB1-02 and GB1-12. The
readings for GB1-02 were 1020, 420, and 1080 amps; normally these readings are within a few
percent of each other but these readings indicate a 60% current unbalance. The current
readings for GB1-12 were 1182, 2100, and 1140 amps and indicate an 80% current unbalance.
The plant operated at 100% power for two days when the GB1-02 circuit breaker failed and the
generator and reactor tripped.

Assessment

Experience indicated that transmission system operation or disturbances may cause sustained
or frequent current unbalances that result in damage to electrical equipment. It is common
practice to protect expensive or important nonsafety equipment from current unbalances. Safety
equipment does not always have the same level of protection. RES will further analyze this
issue in the future.

3.7 Grid Transients May Degrade Scram and ATWS Capabilities

Grid-induced reactor transients can affect scram capability . Events 64 and 65 in appendix A
show that the BWR reactor scram or the end-of-cycle reactor recirculation (EOC-RPT) pump trip
may not occur during large load swings (approximately 800 MW) from a grid disturbance. In
events 64 and 65, faults and equipment problems at an offsite 500 kV switchyard that directly
feeds an NPP 500 kV switchyard resulted in generator load fluctuations, fast closure of the
turbine control valves (TCV), and a reactor trip without the EOC-RPT. The licensee’s evaluation
of the events found that a partial load rejection can actuate circuitry that causes TCV motion in
excess of design assumptions and may not always actuate a reactor scram or satisfy the EOC-
RPT control logic. The licensee found the FSAR analyses enveloped these events. Although
not required, the licensee did not investigate if large load fluctuations produce pressure
excursions that approach those analyzed for an ATWS.

Assessment

Operating experience identified an instance where ATWS mitigation based on EOC-RPT logic
failed to operate correctly during a transmission system fault that produced large electrical load
fluctuations. However, the risk associated with this failure is expected to be very low.

29
3.8 Effects of Overfrequency On Reactor Integrity

Grid-induced reactor transients can affect reactor vessel integrity. The Westinghouse evaluation
of event 15 in Appendix A found that “gross tilting” or rocking of the reactor internals ( i.e. uplift
of the fuel rods due to excess RCP flow) is limiting with respect to allowable reactor coolant flow.
While the licensee was taking one of two available 345 kV power generation paths for a NPP
OOS, a 345 kV relay malfunctioned, tripped the remaining power path, and tripped the reactor
following a load rejection. The EOOS also disabled an NPP electrical protective trip that left the
RCP electrically connected to the main generator, which was overspeeding from the load
rejection. The RCP rated flows increased from 96% to 111.8% as a result of the increased
frequency from the main generator. In analyzing the effects of the increased RCP flow,
Westinghouse found a new RCP flow limit of 115.8% is more limiting than the previous 125%
limit identified in the licensee’s FSAR. Had the RCP flow been at 100% initially, the new limit
may have been reached.

Assessment

Grid conditions which result in over-frequency conditions can have unexpected consequences.
At one plant, over-frequency conditions following a load rejection caused speed-up of the reactor
coolant pumps which generated lifting forces on the core to within a small margin of causing
core mechanical tilt. The over-frequency condition was not properly accounted for by the plant
protective relay control logic.

4 ASSESSMENT

Deregulation of the electrical industry has resulted in major changes to the structure of the
industry over the past few years. Whereas before, a single unified corporation both produced
the electricity and operated the distribution system, that is no longer the case. The industry has
split into separate generating companies and transmission companies. Increased coordination
times to operate the grid may result from involvement of more companies. In addition,
generating companies have daily open access to the grid and this changes the grid design and
operating configurations that were established before deregulation. NPPs rely on an outside
entity to provide reliable electrical power for NPP operation. RES completed an assessment that
is intended to identify changes to grid performance relative to the safety performance of NPPs.
The assessment also provides some numerical measures to characterize grid performance
before and after deregulation - in particular, those related to a LOOP.

The information gathered provides a baseline of grid performance to gauge the impact of
deregulation and changes in grid operation. The period 1985–1996 was considered “before
deregulation” and the 1997–2001 “after deregulation.” The assessment found that major

30
changes related to LOOPs after deregulation compared to before include 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)..

Simplified event trees were developed to assess the impact of these changes on overall NPP
risk, and to include the impact of the LOOP as a consequence of reactor trip. The combined
impact of the changes noted above, and the reduced frequency of reactor trips, was assessed.
The findings include the following: 1) the average yearly risk from LOOPs and reactor trips
decreased, 2) a small number of events over the first five years of deregulated operation
indicates that most of the risk from LOOPs occurs during the summer, and 3) including LOOP as
a consequence of a reactor trip and the potential for degraded grid during the summer, the risk
associated with an EDG out of service can be larger than previously realized.

The assessment re-enforces the need for NPP licensees and NRC to understand the condition
of the grid throughout the year to assure that the risk due to potential grid conditions remains
acceptable. To elaborate:

(1) The NRC does not regulate the grid; however, the performance of offsite power is a
major factor for assessment of risk. With respect to maintaining the current levels of
safety, offsite power is especially important with regard to the risk associated with EDG
maintenance and outage activities. Consequently, NRC and licensee assessments of
risk that support EDG maintenance and outage activities should include: (a) assessment
of offsite power system reliability, (b) the potential for a consequential LOOP given a
reactor trip, and (c) the potential increase in the LOOP frequency in the summer (May to
September). Regarding (a) above, the assessment of the power system reliability and
risks from plant activities can be better managed though coordination of EDG tests with
transmission system operating conditions.

(2) Another important aspect of the changes to the electrical grid is the impact on the
electrical analyses of NPP voltage limits and predictions of voltages following a reactor
trip and whether a reactor trip will result in a LOOP. Recent experience shows that
actual grid parameters may be worse than those assumed in electrical analyses due to
transmission system loading, equipment out-of-service, lower than expected grid reactive
capabilities, and lower grid operating voltage limits and action levels. NPP design basis
electrical analyses used to determine plant voltages should use electrical parameters
based on realistic estimates of the impact of those conditions.

31
(3) With the structural and operational changes that have occurred in the industry, it is
important to have mechanisms, such as contracts between the NPP and transmission
company, in place to ensure that grid operators will provide reliable electrical power.
Some regional grid operating entities manage and control operational and engineering
activities in real time to maintain grid availability and reliability. Since external factors
impact the ability of licensees to manage risks and understand the condition of the grid,
some NPP licensees have implemented contractual agreements with grid operators to
provide a mechanism for maintaining secure electrical power in the deregulated
environment. Contractual arrangements should include specific electrical requirements,
communication protocols, operating procedures and action limits, maintenance
responsibilities, SBO (alternate ac) power supply responsibilities, and NPP and grid.
Within its proper roles and responsibilities, the NRC should communicate with the
industry about the possible need for these mechanisms.

CAISO, PJM, and Callaway experience provides an opportunity for the industry and NRC to
develop lessons to be learned. The assessment identified the following insights from this
experience:

(2) While the data set is small, recent experience indicates that the average duration of LOOPs
has increased. Based on historical data, power restoration times following a LOOP are
assumed to be less than 4 hours; most recent LOOPs have lasted significantly longer. Also,
recent grid events, although not directly associated with LOOPs, indicate that grid recovery
times may be longer. For example, in the Northeast, it took the grid operator (of 12 NPPs)
10 hours to resolve problems from unexpected behavior of the grid, despite implementation
of planned voltage and load management programs and investigation found insufficient
reactive capacity to quickly restore voltages. In the Mid-West, the grid operator needed 12
hours to change regional power flows and restore voltage to a NPP. These events support
the concern identified in SECY 99-129 that the time needed to coordinate grid operations
may increase in a deregulated environment.

(2) LOOPs, partial LOOPs, momentary LOOPs, and voltage degradations below the technical
specification low limit following or coincident with a reactor trip may provide indication of a
potential electrical weaknesses in the grid and a need for regulatory followup to prevent more
serious events. In some events, plant equipment which control safety bus voltage levels, is
assumed to be functional by the grid controlling entity for the range of external voltages
maintained at the NPP. Periodic verification of NPP or other voltage controlling equipment
operability may require compensatory measures such as a request for voltage adjustment
from the grid control entity.

32
(3) Realistic assessment of the risk from grid events may need to consider the impact of a grid
event on multiple NPPs. For example, one recent transmission system disturbance resulted
in the simultaneous trip of four NPPs.

(4) Experience indicated that transmission system operation or disturbances may cause
sustained or frequent current unbalances that result in damage to electrical equipment. It is
common practice to protect expensive or important nonsafety equipment from current
unbalances. Safety equipment does not always have the same level of protection. RES will
further analyze this issue in the future.

(5) Grid-induced reactor transients can affect scram capability. Operating experience identified
an instance where anticipated transient without scram mitigation based on end-of-cycle
recirculation pump trip logic failed to operate correctly during a transmission system fault that
produced large electrical load fluctuations. RES will further analyze this issue in the future.

(6) Grid conditions which result in over-frequency conditions can have unexpected
consequences. At one plant, over-frequency conditions following a load rejection caused
speed-up of the reactor coolant pumps which generated lifting forces on the core to within a
small margin of causing core mechanical tilt. The over-frequency condition was not properly
accounted for by the plant protective relay control logic. RES will further analyze this issue in
the future.

(7) The synergistic effects of reduced reactive grid capability on the NPP from hot weather and
multiple reactor power uprates should be evaluated. RES will further analyze this issue in
the future.

33
5 REFERENCES

1. U.S. Code of Federal Regulations (CFR), Title 10, Part 50, Domestic Licensing of
Production and Utilization Facilities.

2. U.S Nuclear Regulatory Commission, NUREG-1433, Revision 2, Standard Technical

Specifications, General Electric Plants BWR/4, June 2001 and NUREG-1431, Revision
2, Standard Technical Specifications, Westinghouse Plants, June 2001.

3. U.S. Nuclear Regulatory Commission, NUREG-1032, Evaluation of Station Blackout

Accidents at Nuclear Power Plants, June 1988.

4. U.S. Nuclear Regulatory Commission, Regulatory Effectiveness of the Station Blackout

Rule, August 15, 2000. (ML003471812)

5. U.S. Nuclear Regulatory Commission, NUREG-5496, Evaluation of Loss of Offsite

Power Events at Nuclear Power Plants: 1980-1996, June 1998.

6. U.S. Nuclear Regulatory Commission, NRC Regulatory Guide 1.182, “Assessing and
Managing Risk Before Maintenance Activities at Nuclear Power Plants, May 2000

7. Nuclear Energy Institute, NUMARC 93-01, “Nuclear Energy Institute Industry Guideline
For Monitoring The Effectiveness of Maintenance At Nuclear Power Plants, February 22,
2000.

8. U.S. Nuclear Regulatory Commission, Generic Letter 79-36, Adequacy of Station

Electric Distribution System Voltages, August 8, 1979.

8. U.S. Nuclear Regulatory Commission, Strategic Plan, Fiscal Year 2000 –Fiscal Year
2005, October 4, 2000.

9. SECY-01-0044, Status of Staff Efforts Regarding Possible Effects of Nuclear Industry

Consolidation on NRC Oversight,” March 16, 2001.

10. U.S. Nuclear Regulatory Commission, The Effects of Deregulation of the Electric Power
Industry on The Nuclear Plant Offsite Power System: An Evaluation, June 30, 1999.
(ML003743741)

11. U.S. Nuclear Regulatory Commission, Notice 98-07, Offsite Power Reliability
Challenges From Industry Deregulation, February 27, 1998.

12. U.S. Nuclear Regulatory Commission, NRC Information Notice 2000-06: Offsite Power
Voltage Inadequacies, March 27, 2000. (ML003695551)

13. Meeting Notes, Discussion on Grid Voltage Adequacy Issues, May 18, 2000.
(ML003722320)

14. Letter from Ralph E. Beddle, Nuclear Energy Institute, to Samuel J. Collins, Nuclear
Regulatory Commission, “Electrical Grid Voltage Adequacy,” June 26, 2000.
(ML0037275470)

34
15. Meeting Notes, Grid Reliability Issues, October 27, 2000. (ML003757737)

16. U.S. Nuclear Regulatory Commission, Regulatory Issue Summary 2000-24, Concerns
About Offsite Power Voltage, December 21 2000. (ML003752181)

17. Meeting Notes, “Summary of March 15, 2002 Meeting with NEI on Grid Reliability
Issues,” March 15, 2002. (ML020930268)

18. U.S. Code of Federal Regulations, Title 10, Chapter II, Report of Major Electric Utility
System Emergencies,” Section 205.351, “Reporting Requirements.

19. Pennsylvania, New Jersey, Maryland Interconnection, “Results of Heat Wave 1999: July
1999 Low Voltage Condition Root Cause Analysis,” March 21, 2000.

20. Pennsylvania, New Jersey, Maryland Interconnection, “ Voltage Criteria and Voltage
Limits Working Group Report,” September 11, 2000.

21. U.S. Nuclear Regulatory Commission, “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,” February 22, 2002. (ML021290358)

35