[Federal Register Volume 61, Number 218 (Friday, November 8, 1996)]
[Notices]
[Pages 57917-57923]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-28736]
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NUCLEAR REGULATORY COMMISSION
[Docket Nos. 50-413 and 50-414]
Duke Power Company, et al.; Catawba Nuclear Station, Units 1 and
2; Issuance of Director's Decision Under 10 CFR 2.206
Notice is hereby given that the Director, Office of Nuclear Reactor
Regulation, has taken action with regard to a Petition for action under
10 CFR 2.206 received from Mr. Charles Morris (Petitioner), dated
February 13, 1996, as supplemented May 1, 1996, with regard to the
Catawba Nuclear Station.
The Petitioner requested the NRC to suspend the operating licenses
for the Catawba Nuclear Station and ``some ten other licensees with
uncoordinated breakers'' (not specifically identified in his initial
Petition) until the lack of circuit breaker coordination has been
remedied. Mr. Morris also requested that enforcement conferences be
held on these cases and that Catawba be defueled. Mr. Morris also asked
that the NRC take enforcement action against Catawba for operating with
a ``known safety deficiency of which they did not inform the NRC.''
The Director of the Office of Nuclear Reactor Regulation has denied
the Petition. The reasons for this decision are explained in the
``Director's Decision Pursuant to 10 CFR 2.206'' (DD-96-14), the
complete text of which follows this notice and which is available for
public inspection at the Commission's Public Document Room, the Gelman
Building, 2120 L Street, NW., Washington, DC, and at the local public
document Room for the Catawba Nuclear Station located at the York
County Library, 138 East Black Street, P.O. Box 10032, Rock Hill, South
Carolina.
A copy of this Decision has been filed with the Secretary of the
Commission for the Commission's review in accordance with 10 CFR
2.206(c) of the Commission's regulations. As provided by this
regulation, this Decision will constitute the final action of the
Commission 25 days after the date of issuance unless the Commission, on
its own motion, institutes review of the Decision within that time.
Dated at Rockville, Maryland, this 10th day of October 1996.
For the Nuclear Regulatory Commission.
Frank J. Miraglia,
Acting Director, Office of Nuclear Reactor Regulation.
Director's Decision Under 10 CFR 2.206
I. Introduction
On February 13, 1996, Mr. Charles Morris of Middletown, Maryland,
filed a Petition with the U.S. Nuclear Regulatory Commission (NRC)
pursuant to Title 10 of the Code of Federal Regulations, Section 2.206
(10 CFR 2.206). In the Petition, the Petitioner requested the NRC to
suspend the operating licenses for the Catawba Nuclear Station and
``some ten other licensees with uncoordinated breakers'' (not
specifically identified in his initial Petition) until the lack of
circuit breaker coordination has been remedied. Mr. Morris also
requested that enforcement conferences be held on these cases and that
Catawba be defueled. Mr. Morris also asked that the NRC take
enforcement action against Catawba for operating with a ``known safety
deficiency of which they did not inform the NRC.'' This aspect will be
addressed separately as stated in the April 2, 1996, letter to Mr.
Morris. On May 1, 1996, Mr. Morris submitted an addendum to his
Petition, providing a list of 14 cases involving 9 other nuclear power
plants for which lack of protective device coordination had been
identified as a concern by electrical distribution system functional
inspection (EDSFI) teams; see Section II for information.
II. Discussion
During an EDSFI conducted by the NRC staff from January 13 to
February 14, 1992, at the Catawba Nuclear Station, circuit breaker
coordination deficiencies were identified for the 600-Vac essential
motor control centers (MCCs) and the 125-Vdc system. This circuit
breaker coordination issue was addressed in EDSFI Inspection Report 50-
413, 414/92-01, dated March 18, 1992, as a deviation from a written
commitment. Section 5.3.1 of the Institute of Electrical and
Electronics Engineers (IEEE) Standard 308-1974, ``IEEE Standard
Criteria for Class 1E Power Systems for Nuclear Power Generating
Stations,'' stipulates that protective devices shall be provided to
limit the degradation of Class 1E power systems. The Catawba Final
Safety Analysis Report (FSAR) states that the system meets the
requirements of this standard. The FSAR also states that the protective
devices on the 600-Vac essential auxiliary power (EPE) system are set
to achieve a selective tripping scheme so that a minimal amount of
equipment is isolated for an adverse condition such as a fault.
Contrary to this IEEE Standard, however, the licensee's protective
devices may not limit the degradation of the 125-Vdc vital
instrumentation and control (I&C) power system distribution center and
other main feeder circuit breakers. An analysis performed by the
licensee showed that coordination did not exist for fault currents from
3500 amperes (A) up to the maximum fault current of 9500 A. A fault on
the battery charger feeder cable could cause both the charger and the
battery to be isolated from the remainder of the distribution system
and loads.
In addition, the outgoing feeder breakers for the 600-Vac essential
MCCs have thermal elements and the incoming MCC breakers have
instantaneous elements. The incoming breaker (supply breaker) and the
feeder breakers at each of the 600-Vac MCCs were not coordinated for
the maximum expected short-circuit current. A fault on any of the MCC
outgoing feeders could cause the MCC incoming breakers to trip,
resulting in a loss of the MCC.
Enclosed with the letter dated April 16, 1992, Duke Power Company
(the licensee) provided a response to this deviation which stated that
the 125-Vdc vital I&C power (EPL) system primarily uses molded-case
circuit breakers in the 125-Vdc distribution centers and power
panelboards for protection. The battery, main, and tie breakers are
equipped only with adjustable magnetic trip units. The battery charger
breaker is a thermal
[[Page 57918]]
magnetic type with an adjustable magnetic trip setting. The rest of the
breakers are of a non-adjustable thermal magnetic type.
The licensee's response concluded that this design was acceptable
for the following reasons:
1. The EPL system is not a shared system between the two Catawba
units; thus, a postulated fault in the EPL system of one unit will not
affect the opposite unit.
2. The EPL system for each unit is composed of two completely
redundant and separate trains, each consisting of two load channels for
a total of four load channels per unit. A postulated fault would, at
worst, disable two load channels of the same train, yet the redundant
train would remain unaffected.
3. Selected loads such as the diesel load sequencer, essential
switchgear and load center controls, and auxiliary feedwater pump
turbine controls are not only fed by the EPL system, but are
auctioneered with the 125-Vdc diesel auxiliary power (EPQ) system. As a
result, if the EPL system was unable to feed these loads, the EPQ
system would supply them without interruption. Further, a fault on the
EPL system will not affect the EPQ system or vice versa.
The licensee's response further states that the incoming 600-Vac
breakers were incorporated in the design to provide a means of local
isolation for the 600-Vac Class 1E MCCs. The licensee deemed acceptable
the use of circuit breakers having a continuous rating equal to the MCC
incoming rating and their instantaneous trip settings at maximum, 10
times their continuous rating.
In the response to the deviation, the licensee committed to perform
a detailed study to identify acceptable methods to achieve improved
protective device coordination within the EPL system and to evaluate
the feasibility of eliminating the incoming 600-Vac MCC breakers. The
licensee committed to either update the FSAR to justify the deviation
from the IEEE Standard 308-1974 or to modify the system to meet this
IEEE standard. Subsequent to completing the detailed study and
evaluating the feasibility of making system modifications, the licensee
proposed modifying the FSAR.
Deterministic Analysis
To review and evaluate the lack of circuit breaker coordination in
the Catawba EPL and EPE circuits, the staff requested the licensee to
provide additional information. The licensee's response of March 2,
1994, addressed fault types, fault locations, breakers that are
coordinated and breakers that are not coordinated, the impact of the
upstream breaker opening, and the safety significance of the loss of a
train. The staff also requested additional information regarding the 2-
kV-rated interlocking armored cabling; the operating history of faults;
the measures provided to detect, locate, and correct faults; and
related criteria and practices incorporated to ensure continued system
functional performance. The licensee's responses to these requests were
enclosed in its letter to the NRC of May 17, 1996.
125-Vdc Vital EPL System
The EPL system is an ungrounded system and therefore can remain
operational for a single postulated fault of either positive-to-ground
or negative-to-ground. In order to render the system inoperable,
postulated faults would have to be either a simultaneous positive-to-
ground and negative-to-ground fault or a double-line (positive-to-
negative) fault. The former type of fault requires that two failures
occur, which is beyond the design basis for the plant. The occurrence
of a single line-to-ground fault will not affect the functional
capability of the power system. However, upon the occurrence of such a
fault, a ground fault detector will alert the control room operator by
way of an annunciator and a computer alarm. A program that seeks to
maintain a dark control room annunciator board promptly addresses
ground faults. The latter type of fault is thought to be unlikely in
view of a study performed with information obtained from the Nuclear
Plant Reliability Database System (NPRDS) and the Catawba probabilistic
risk assessment (PRA). The licensee analyzed failures at Catawba since
1985 and all U.S. plants since 1990. Three reported cases were found in
which a double-line fault occurred on a direct current system. One case
that occurred at Catawba involved a shorted lamp holder and was
attributed to improper installation during maintenance. The two other
cases occurred at nuclear plants operated by other utilities and
involved component failures within battery chargers; in both of these
other cases, the plant status was not affected. No cases were reported
that involved double-line faults attributed to cable faults. In
addition, no faults of the types that could challenge the EPL system
were identified in the NPRDS.
The licensee's circuit breaker coordination analysis for the EPL
system postulates faults at selected locations within the system. The
analysis was performed in accordance with the guidelines of IEEE
Standard 946-1993, ``IEEE Recommended Practice for the Design of DC
Auxiliary Power Systems for Generating Stations,'' and included EPL
system load groups A and D for both units. These two load groups for
both units were analyzed since the 125-Vdc vital batteries associated
with them are capable of producing the highest fault current. The
coordination analysis postulates faults at nine locations within each
of the four EPL load groups. These locations are as follows: (1)
Battery charger output; (2) auctioneering diode assembly input; (3)
inverter input; (4) auctioneered distribution center bus; (5) load end
of 4160-Vac essential switchgear control power feeder breaker and first
termination point of associated feeder cable; (6) load end of 600-Vac
essential load center control power feeder breaker and first
termination point of associated feeder cable; (7) load end of diesel
generator load sequencer control power feeder breaker and first
termination point of associated feeder cable; (8) power panelboard bus;
and (9) load end of the largest breaker used in a power panelboard and
the first termination point of the associated feeder cable. These fault
locations were chosen to represent a broad cross-section of possible
fault locations. At these locations, calculated fault currents for the
two A load groups (one A load group per unit) and the two B load groups
are very similar, as may be expected since the two units are very
similar. The analysis results also show that for faults at locations
(2) and (4), the breakers are fully coordinated, while for faults at
locations (5), (6), (7), and (9), the breakers are partially
coordinated. For postulated faults at locations (1), (3), and (8), the
breakers are not coordinated. In the analysis, full breaker
coordination is considered to exist if the breaker nearest the fault
clears without operating (opening) any upstream breakers, or if the
consequences of operating an upstream breaker are no more severe than
those associated with operating the breaker nearest the fault. Partial
coordination is considered to exist if some of the upstream breakers,
except the battery breaker or the load center incoming breaker, could
operate before the breaker nearest the fault clears. For those cases in
which either the battery compartment breaker or the load center breaker
could operate before the breaker nearest the fault operates,
coordination is considered not to exist. If an upstream breaker, such
as the load center incoming breaker, operates before the breaker
nearest the fault opens, one of
[[Page 57919]]
the four EPL system load centers would be lost.
The EPL circuit breaker coordination analysis neglects cable faults
and credits cable resistances in the fault current calculations. The
cabling used in the system is 2-kV-rated interlocking armored cable.
This cabling has the same construction as non-armored cable, except
that a steel armor covering is applied around the entire outer
circumference. This interlocked steel outer covering protects the cable
from damage or degradation during loading, unloading, transporting,
installation, and while in service at the plant. The cabling was
purchased with an insulation system rated at 2000 Vac. The cable
conductors were high-potential tested underwater and spark tested at
the factory with values required by standards for 2-kV cable. The low
voltage of the EPL system does not produce internal ionization or
corona that would cause an internal flashover or failure between
conductors within the armored cable. Further, the cable insulation
system has a greater thickness than the insulation system of standard
600-Vac rated cable and therefore provides higher dielectric
capability, enhanced physical protection, and added margin for aging
considerations.
In addition, the licensee had an interlocked armored cable fault
test performed at the High Power Laboratory of the Westinghouse
Electric Corporation. This test did not result in any additional shorts
between conductors within the multiconductor cable. Similar
interlocking armored cabling is used at the Oconee Nuclear Station,
which has an inservice cable monitoring program. For this program, six
cable samples were installed inside one of the containment buildings.
At 5-year intervals, a 5-foot segment is removed from each cable sample
for testing. This testing measures, documents, and trends the
mechanical and electrical properties of the cable. Past test results
from this program collectively show that cable samples are in good
physical condition after 20 years in a reactor building environment.
The installed interlocking armored cabling at Catawba is identical or
superior to the cable that is installed at Oconee. A similar monitoring
program to evaluate and trend cable problems has been in place at
Catawba since January 1995. The purpose of this program is to evaluate
and record problems or malfunctions of plant cables and, if an adverse
trend develops, take corrective actions to address the problem.
Deficiencies that would be reported as a result of this program include
short circuits, insulation damage, and problems with cable terminations
and splices. Since cabling of the same basic specifications and ratings
is used in both safety and nonsafety applications at Catawba, all plant
cabling is included in the scope of this trending program. Data on
failures or problems with cables are collected at the end of each
quarter; since January 1995 there has only been one failure.
Neither of the Catawba units has ever experienced a single line-to-
ground fault that caused the EPL system to become inoperable. As noted
previously, this result is due in part to the ungrounded system design.
A complete review of the EPL system work order history revealed that
five ground faults have been experienced in the last 5 years. Each of
these faults resulted in an alarm both locally and in the control room
and was caused by solenoid valve problems. Three cases involved failed
solenoid valve components, and the other two cases involved water
intrusion into solenoids, which was subsequently corrected. Because of
the intermittent nature and high resistance of these faults, it
sometimes took an extensive amount of time to specifically locate and
correct the ground fault. However, none of these faults caused the EPL
system to become functionally inoperable. The licensee has implemented
additional measures to aggressively locate and correct ground faults
that may occur in the future. These measures include the procurement of
an advanced ground-locating device that will allow ground faults of a
high-resistance nature to be located more readily. The EPL system work
order history search also revealed that only one ground fault detector
has failed during the last 5 years. Because the original ground
detector was no longer available from the manufacturer, a substitute
part had to be located and an evaluation performed to verify its
acceptability for use in the application. As a result, it took longer
than normal to restore the unit to service. However, the EPL system is
checked weekly in accordance with an administrative procedure for
ground faults by way of another method that is independent of the
ground detector system. Thus, in the unlikely event of a ground fault
detector failure, a ground would very likely be detected by way of the
independent alternate means before a fault-related problem developed.
To ensure continued functional performance of the EPL system, the
following additional criteria and practices are in place at Catawba.
Only a minimal amount of cable splicing is permitted, and no cable
splicing is allowed in raceways. Safety-related cables routed
underground are installed in conduit or cable trenches, and are not
directly buried in the earth. Cable ampacities used for cables are
based on 70 percent of the standard industry ampacity ratings. Further,
for the EPL system, higher rated voltage (2000 Vac versus 125 Vac)
cable is used with the steel interlocking armor jacket to provide
additional physical protection.
Although the EPL system analysis described above demonstrates that
full circuit breaker coordination does not exist for all postulated
faults, this fact has no significance for the operational capabilities
of the system because the faults that result in lack of breaker
coordination are limited. These faults are limited in both type
(doubled-sided, solid, low resistance ones) and location (postulating
such faults at many locations does not result in a lack of breaker
coordination). Monitoring by ground fault detectors further limits such
faults since this activity minimizes the potential for bigger problems,
such as positive-to-negative faults. In the event that such a fault
does result in the loss of an EPL load distribution center, an
independent and redundant EPL load distribution center is provided to
supply safety-related loads. Further, should a fault-induced transient
occur as a result of the loss of one of the two plant transient-
inducing EPL load distribution centers, the plant can be safely shut
down using only the loads powered from either one of the two EPQ system
auctioneered distribution centers. In addition, the safety significance
of the loss of one EPL load group is analyzed in the Catawba FSAR. This
analysis includes the loss of an EPL load group as a result of any
postulated cause. Thus, the loss of an EPL load group as a result of
any cause (faults or any other cause) is within the licensing basis
(i.e., analyzed in the FSAR) for Catawba Units 1 and 2.
600-Vac EPE System
The licensee also provided additional information on the lack of
breaker coordination in the EPE system. This additional information
included the analysis performed for the EPE system, fault locations,
identification of the breakers that are coordinated and those that are
not, the impact of upstream breakers opening, the significance of
taking out an EPE train, and measures taken to prevent degrading the
installed equipment during modification and maintenance work
activities.
The fault current analysis for the EPE system was performed in
accordance with the guidelines in IEEE Standard 141-1986, ``IEEE
Recommended
[[Page 57920]]
Practice for Electric Power Distribution for Industrial Plants.'' For
each 600-Vac essential MCC, all load breakers and cables were reviewed
to determine which circuit can produce the highest fault current. For
each MCC, a coordination evaluation was performed for the worst-case
feeder (load) breaker and the incoming (supply) breaker. In this
analysis, the feeder breaker fault is modeled at the load or at the
first cable termination outside the MCC. For the fault current
analysis, the normal load current for all nonfaulted feeder breaker
loads is added to the feeder breaker fault current to establish the
total current experienced by the incoming breaker during the fault.
Also, in this analysis, the feeder breaker fault current is obtained by
adding the fault contribution from the incoming breaker and the fault
contribution from the large motor loads connected to the bus. The fault
currents were determined for both the normal and accident cases. The
normal operation case produces the highest postulated fault current
and, as such, is used throughout the analysis. The postulated faults in
the analysis are three-phase, bolted faults, and all fault currents and
load currents are based on the highest bus voltage for the normal
operating case.
Fault locations for the Unit 1 Train A and B EPE MCC circuits were
established. The Unit 2 Train A and B circuits are similar. Based on
the unlikely occurrence of bus faults and/or breaker faults at Catawba,
faults were not postulated on the output of the feeder breaker. In
addition, because of the 2-kV-rated interlocked armor cable protection
and the fact that no faults have occurred on any such cable in service
at any of the Duke Power nuclear plants, faults were not postulated
along the routes of the cable. Further, the fault current calculations
credit cable impedances and postulate faults at the input terminals of
the load or at the first cable termination after the cable leaves the
MCCs. The 2-kV-rated interlocking armored cabling used in the EPE
system is the same as that used in the EPL system. Thus, the cable
analysis information previously mentioned for the EPL system is
applicable to the EPE system.
The Unit 1 EPE system includes 11 MCCs. Analysis shows that for 10
of these MCCs, the incoming breakers are coordinated for the worst-case
postulated fault at the first cable termination outside the MCC. The
remaining MCC is provided with two incoming breakers, which can be
powered from either a Unit 1 or a Unit 2 load center. The two incoming
breakers supplying this MCC are not fully coordinated for a fault at
the worst-case load, which is a control room ventilation system air-
handling unit. This unit is connected with a 250 MCM cable that is 100
feet long. The other loads powered by this MCC are fed from smaller
breakers and cables with lower maximum fault current and thus are
coordinated with the incoming breakers.
The two incoming breakers for the one MCC are mechanically
interlocked such that one breaker is always locked in the open
position. If the incoming breaker in service to this MCC trips to clear
a fault, power is lost to some Train A control room ventilation system
and nuclear service water system loads. An important function
associated with these systems is maintaining pressurization of the
control room. If this MCC is deenergized under nonaccident conditions,
control room pressurization decreases until the operators manually
transfer the system to Train B. This result is not viewed any
differently than the result of losing the pressurizing fan alone and
has little impact. If the MCC is deenergized under accident conditions,
the design is such that pressurization is reestablished automatically
from Train B, and this situation has little impact.
To ensure continued fault-free functional operation of the EPE
system, modifications and maintenance work are controlled by station
procedures. The Catawba inspection and maintenance procedure for MCC
breakers addresses much of the work related to the EPE MCCs. This
procedure, along with other station procedures, provides strict
controls on any changes from the normal system configuration, such as
placement of grounding jumpers or test alignments. These types of
configuration changes are documented on a circuit alteration/
restoration log sheet attached to the procedure. Before the work can be
closed out and the equipment reenergized, the proper steps in the
restoration section of the procedure must be completed and verified by
an independent technician. Typical restoration activities performed at
the completion of maintenance work on EPE MCC feeders include removing
all test equipment and verifying that the MCC compartment is wired
according to the latest wiring diagram. If required, motor phase
rotation testing would also be performed. If the feeder breaker has
been removed or replaced, a thermography test of the energized breaker
will be conducted. Additional specified functional verification
requirements, such as verifying proper full-speed operation and normal
pressure and flow parameters, may be performed, depending on the type
of equipment involved with the work. In addition, the test requirements
section of the inspection and maintenance procedure for MCC breakers
specifies that megger testing of the load is to be performed if a fault
is suspected. The procedure signoff sheet includes a section for
recording such megger readings.
The licensee's March 2, 1994 analysis indicated that selected
circuit breakers associated with certain EPE MCCs are not coordinated
for postulated faults. However, the technical significance of this fact
is low, which is due, in part, to such faults being limited in both
type (bolted low-impedance faults) and location (postulating such
faults in many EPE system locations does not result in lack of breaker
coordination). Assurance that such faults are limited is further
established by the positive test results obtained for the interlocking
armored cabling and the strict adherence to maintenance procedures. In
addition, an analysis of the loads powered by each of the 11 600-Vac
EPE system MCCs indicates that loss of power to any one of these MCCs
because of a fault or for any other reason would not directly result in
a reactor transient. Further, Trains A and B of the EPE system are
redundant and, as such, loss of functions from any MCC is backed up by
the redundant MCC of the other train. Finally, each MCC is provided
with a control room alarm for loss of power to facilitate restoration
of equipment in a timely manner by operator actions.
Probabilistic Risk Assessment
To further supplement the deterministic engineering analysis
results, the staff requested the licensee to consider using PRA
techniques to better understand the likelihood and impact of the lack
of breaker coordination in the Catawba EPL and EPE systems. The
licensee responded in the attachments to a letter dated December 29,
1994, by addressing EPL and EPE system uncoordinated breakers within a
PRA framework. Following the review of the submitted PRA information,
the staff requested by letter dated April 30, 1996, that the licensee
specifically address the uncoordinated breaker issue including the (1)
initiating event (IE) frequency; (2) conditional impact of the IE on
plant operation; (3) ability to recover from an uncoordinated breaker
event; and (4) recovery by way of the standby shutdown facility (SSF).
The licensee provided this additional PRA information in the enclosures
to a letter dated May 17, 1996. The paragraphs below discuss the PRA
and
[[Page 57921]]
the lack of breaker coordination in the EPL and EPE systems.
125-Vdc EPL System
In the Catawba PRA, the licensee identified a ``Loss of Vital
Instrumentation and Control'' as an initiator-coded T14. With
uncoordinated breakers, some line-to-line electrical faults in the 125-
Vdc feeders could cause both the loss of a vital I&C power distribution
center (T14 initiator) and a subsequent turbine trip and reactor trip.
In Calculation CNC-1535.00-00-0007 enclosed in its December 29,
1994, letter, the licensee established the frequency of the T14
initiating event at 5E-02 per year. This value had also been used in
the Catawba PRA, which supported the licensee's individual plant
examination (IPE). The IE frequency had been based on the operational
experience of one event in 20 reactor-years of operation at the
combined Catawba and McGuire units (four units) from 1987 to 1991. The
event involved manual tripping of a 125-Vdc vital I&C power
distribution center at the McGuire station in 1987. In response to this
event, the NRC issued Information Notice 88-45, ``Problems in
Protective Relay and Circuit Breaker Coordination.'' Because no other
T14 IE occurred since that timeframe, the actual IE frequency would be
lower.
In order to establish the fraction of the T14 initiator event
frequency that could be associated with breaker miscoordination, the
licensee performed an NPRDS search for all dc line-to-line faults. The
data search included all U.S. nuclear plants from 1990 (Catawba since
1985) to the present. The NPRDS search identified only one such fault
at Catawba and three faults at all U.S. plants. In recognition of the
fact that the results of NPRDS searches are dependent on the search
commands, the staff requested the Oak Ridge National Laboratory (ORNL)
to perform a similar search. ORNL obtained the same results as did the
licensee for the Duke Power plants. However, ORNL found a slightly
higher rate for the other U.S. plants. In no case did cable failure(s)
result in a line-to-line fault or a plant trip.
In order to estimate (bound) the contribution of a cable fault to
the T14 initiator event frequency, the licensee assumed that one cable
fault occurred out of a combined 46 years of reactor operation at the
Catawba and the McGuire units. This assumption resulted in a cable
fault frequency of 2E-02 per unit-year. Catawba Unit 1 has about 18,500
cables and about 30 feeders per 125-Vdc vital distribution center. From
these data, cable faults causing loss of a single distribution center
have an IE frequency of 3E-05 per year ((2E-02)(30)/18,500 = 3E-05 per
year). A second (somewhat higher) estimate was obtained by using the
IEEE Standard 500-1984, ``IEEE Guide to the Collection and Presentation
of Electrical, Electronic, Sensing Component, and Mechanical Equipment
Reliability Data for Nuclear-Power Generating Stations,'' which
specifies a composite cable failure rate of 7.54E-06 per hour per plant
for power, control, and signal cables combined. Line-to-line cable
failure rate is a small fraction of this rate. With this cable failure
rate, the failure rate of a single distribution center is 1E-04 per
year ((7.54E-06)(8760)(30)/18,500 = 1E-04 per year).
The Catawba PRA used a generic value for bus fault probability of
2E-03 per year, where the term bus fault includes distribution center
or panel faults, cable faults, and terminal faults. Although this IE is
only 4 percent of the T14 initiator frequency, it is obviously higher
than the probability figures derived from plant operational experience
and IEEE 500-1984 data (i.e., the cable fault contribution was 5
percent of the bus fault probability using IEEE data, and 1.5 percent
using operational experience). On the basis of this rationale, the
staff concluded that the cable fault contribution was bounded by the
distribution center fault probability used in the Catawba PRA.
Unit 1 has six 125-Vdc load distribution centers: 1EDA, 1EDB, 1EDC,
1EDD, 1EDE, and 1EDF. The licensee evaluated the plant response on loss
of power for each of the Unit 1 distribution centers. The Unit 2 system
is similar to Unit 1, and the evaluation for Unit 1 is applicable to
Unit 2.
The licensee's evaluation indicates that a loss of power at 1EDB or
1EDC would result in a loss of a vital I&C power 120-Vac inverter, one
solid-state protection system (SSPS) channel, one nuclear
instrumentation channel, and a process protection channel. A loss of
power at 1EDA or 1EDD would result in similar channel losses, plus a
loss of power to process control for associated pressurizer power-
operated relief valves (PORVs), to control solenoids for certain main
steam isolation valves, and to control solenoids for attendant main
feedwater control valves. However, except for the loss of the PORVs, a
loss of any of these four distribution centers would not significantly
impact the plant's accident mitigation capability. Loss of one channel
of the SSPS, process protection channels, main steam isolation valves,
and main feedwater control valves would not preclude mitigation unless
there were additional faults.
Distribution center 1EDE or 1EDF provides control power for safety
equipment. The licensee's breaker coordination analysis indicates that
the other four distribution centers lack full coordination.
Distribution center 1EDE is powered by two power supplies that are
auctioneered. One of these auctioneered power supplies is from 1EDA,
and the other is from one of the trains of the 125-Vdc EPQ system.
Similarly, 1EDF is powered by two power supplies that are auctioneered.
One of these auctioneered power supplies is from 1EDD and the other is
from the other train of the 125-Vdc EPQ system. Thus, even though
distribution centers 1EDE and 1EDF may be fed from uncoordinated
distribution centers 1EDA and 1EDD, respectively, in the event of loss
of 1EDA or 1EDD, the distribution centers 1EDE or 1EDF will continue to
be powered by the alternate power source. Further, a loss of power at
1EDE or 1EDF would not result in a plant transient and thus would not
result in an immediate need for mitigating systems, although the
resulting loss of control power to equipment would require resolution
within the specified time period of the applicable Technical
Specifications Action Statement.
In addition to redundant mitigation capability, Catawba is provided
with a manually activated SSF. The SSF is an independent structure with
its own ac and dc power supplies, instrumentation, and reactor coolant
makeup pump. Upon loss of normal ac or dc power, the SSF can be used to
remove core decay heat and provide reactor coolant pump seal protection
if the event leads to the loss of all plant-side safety systems. The
SSF reduces the contribution of the T14 initiators by more than an
order of magnitude, resulting in a total contribution of 6.7E-08 per
reactor-year, or less than 0.1 percent to the total core damage
frequency (CDF).
Using a T14 IE frequency of 5E-02 per year, the licensee derived a
total CDF of 7.76E-05 per year in the Catawba IPE. Applying information
from the IEEE standard for cable fault frequency to the four
distribution centers lacking full coordination, which is a subset of
the T14 initiator, reveals that the contribution to the total CDF from
the loss of a 125-Vdc load distribution center is less than 1E-09 per
reactor-year. The licensee also performed a sensitivity study by
changing the T14 IE frequency from 5E-02 per year to 1.0 per year. The
total CDF changed by 1.55 percent (i.e., the total CDF changed from
7.76E-05 per year to 7.88E-05 per year).
[[Page 57922]]
The sensitivity study indicates that any increase in the CDF from a
lack of breaker coordination would be small.
600-Vac EPE System
As previously mentioned in this report, the licensee's breaker
coordination study indicates that out of 11 MCCs in the EPE system,
only 1 MCC, 1EMXG, is uncoordinated. This calculation, however,
excluded all cable faults from the 600-Vac EPE system MCCs to the first
cable termination on the basis that the occurrence of severe cable
faults was of low probability. The licensee states that no severe cable
faults have been reported in its seven nuclear plants, which have a
combined operational experience of 120 reactor-years. On the basis of
the IEEE Standard 500-1984 data of 4.8 failures per million hours per
plant for power cables, the licensee calculated that a typical plant
with 18,500 cables had a probability of a cable failure of 2.3E-06 per
year per cable, and the probability of an MCC loss as a result of cable
failure is 7E-05 per year for a typical MCC with 30 feeders.
In the Catawba PRA, loss of a 600-Vac MCC is addressed through its
plant response characteristics (mission time) because the loss of an
MCC does not cause a reactor transient. The Catawba PRA study
identified a probability of loss of a 600-Vac MCC as 1.5E-04 for a 24-
hour mission time, and the contribution of cable faults to this mission
time as 5E-07. Therefore, the Catawba PRA indicates that cable faults
did not have any significant impact on the overall MCC failure
probability calculated in the PRA.
The licensee's study revealed that a loss of any of the 11 600-Vac
EPE system MCCs would not directly lead to a reactor trip. In a review
of the 600-Vac EPE system MCC loads, the staff arrived at the same
conclusion. Although such an MCC loss would not result in a reactor
transient, it would render one train of safety systems inoperable and
would require entry into applicable limiting conditions of operation
defined in the Technical Specifications. However, a loss of any MCC
would only affect one train, and the redundant train would be available
for accident mitigation.
The licensee did not provide an analysis of the effect of SSF
availability on the CDF from the loss of a 600-Vac MCC. The SSF
response for the 600-Vac EPE system is expected to be similar to that
previously explained herein for the EPL system.
In Calculation CNC-1535.00-00-0007, enclosed with the licensee's
letter of December 29, 1994, the licensee indicated that on the basis
of the Catawba PRA, the MCC 1EMXG had a failure probability of 1.4E-04
for a 24-hour mission time. Within this MCC, only one breaker feeding a
control room air-handling unit lacked coordination with its upstream
breaker. With this uncoordinated breaker, the MCC failure rate would
increase by 1E-06 for a 24-hour mission time, or the impact would be
approximately two orders of magnitude less than the total MCC failure
probability. The licensee's sensitivity study provided in Calculation
CNC-1535.00-00-0007 indicates that even if the failure rate of the
uncoordinated MCC 1EMXG were increased by an order of magnitude from
1E-06 to 1E-05, the resulting failure probability for the MCC 1EMXG
would increase by only 7.1 percent.
On the basis of these considerations, the staff concluded that the
lack of breaker coordination in the EPE system has a negligible impact
on the MCC failure probability as calculated in the Catawba IPE.
Full circuit breaker coordination is a desirable design feature for
ac and dc power distribution systems in a nuclear plant since it
assists in minimizing equipment losses if electrical faults occur. The
staff has reviewed the licensee's submittals addressing the lack of
full circuit breaker coordination within the 125-Vdc EPL and 600-Vac
EPE systems. The licensee's circuit breaker coordination analysis shows
that the Catawba EPL and EPE systems lack full breaker coordination.
However, the faults that must occur to cause a lack of breaker
coordination in these systems are limited by type and location. Such
faults have a low probability of occurrence because the interlocking
armored cabling is unlikely to develop such faults. Further, ongoing
measures, such as ground fault detection, incorporating design criteria
and practices, and strict adherence to modification and maintenance
procedures, tend to minimize the likelihood of the occurrence of faults
within the EPL and EPE systems that would result in miscoordinated
breakers. Plant operational experience and IEEE Standard 500-1984 data
indicate that line-to-line faults are of low probability. The
probability of a line-to-line fault is 2E-02 per year and the
probability of loss of a 125-Vdc distribution center is 1E-04 per year.
In the 600-Vac EPE MCCs, the licensee has never experienced any severe
cable fault in 120 reactor-years of operation of the seven Duke Power
nuclear plants. The IEEE Standard 500-1984 data indicate a probability
of a cable failure of 4.2E-02 per year and a corresponding probability
of a loss of an MCC resulting from cable failure of 7E-05 per year.
These results further support assumptions used in the licensee's
breaker coordination analysis. However, in the unlikely event that such
faults should occur in an EPL or EPE system train, a redundant and
separate train is provided to perform the safety function.
The Catawba SSF reduces the impact on CDF of a loss of either one
of two 125-Vdc distribution centers by more than an order of magnitude.
Similar results would be expected for the 600-Vac EPE MCCs. In
addition, a calculation by the licensee indicates that increasing the
T14 IE frequency from 5E-02 per year to 1.0 per year would increase the
total CDF by 1.55 percent from 7.76E-06 per year to 7.88E-05 per year.
A similar calculation for the 600-Vac MCCs indicates that with lack of
breaker coordination, the failure probability of the worst-case MCC
would rise from 1.4E-04 per 24-hour mission time by 1E-06 per 24-hour
mission time. The licensee's sensitivity study indicates that when the
failure rate of the worst-case uncoordinated MCC was increased from 1E-
06 to 1E-05, the resulting failure probability of the MCC would
increase by 7.1 percent. Thus, the lack of circuit breaker coordination
in the Catawba 125-Vdc EPL and 600-Vac EPE systems has a negligible
impact on the CDF.
On the basis of this information, the staff concludes that the
licensee has documented adequate technical justification for the lack
of breaker coordination in the Catawba 125-Vdc EPL and the 600-Vac EPE
systems. Accordingly, the staff concludes that there is no basis to
suspend the Catawba operating licenses. The staff will pursue
separately the requirement for the licensee to bring the FSAR into
conformance with the as-built plant.
Lack of Protective Device Coordination at Other Nuclear Plants
As previously indicated in the introduction section of this
Decision, the Petitioner submitted an addendum to his Petition on May
1, 1996. This addendum included a list of 14 cases, involving 9 other
nuclear power plants, in which lack of protective device coordination
was identified as a concern by EDSFI teams. These 14 cases were
addressed by way of the NRC's inspection report item closeout process.
As documented in the publicly available closeout inspection reports,
these cases were resolved by (1) additional calculations and analyses
showing that protective device coordination exists, and/or (2) plant
hardware modifications such as replacement circuit breakers or
[[Page 57923]]
fuses. The following list identifies each of these 14 cases by an EDSFI
inspection follow-up item (IFI) number and the publicly available
inspection report in which the lack of protective device coordination
issue was closed out.
----------------------------------------------------------------------------------------------------------------
Closeout
Plant name EDSFI IFI No. Report date inspection report Report date
----------------------------------------------------------------------------------------------------------------
1. Oyster Creek................. 219/92-80-11 7/9/92 94-01 3/10/94
2. Nine Mile Point 1............ 220/91-80-07 1/10/92 94-20 11/4/94
3. Nine Mile Point 1............ 220/91-80-07A 1/10/92 94-20 11/4/94
4. Nine Mile Point 1............ 220/91-80-07B 1/10/92 94-20 11/4/94
5. Nine Mile Point 1............ 220/91-80-07C 1/10/92 94-20 11/4/94
6. Dresden...................... 237/91-201-05 9/20/91 92-21 10/8/92
7. Quad Cities.................. 254/91011-09A 6/24/91 94-26 12/5/94
8. Quad Cities.................. 254/91011-9B 6/24/91 94-26 12/5/94
9. Quad Cities.................. 254/91011-9C 6/24/91 94-26 12/5/94
10. Hatch....................... 321/91-202-07 8/22/91 93-19 11/2/93
11. McGuire..................... 369/91-09-01 2/19/91 94-20 10/12/94
12. Fort Calhoun................ 285/91-01-03 5/20/91 92-30 12/31/92
13. WNP2........................ 397/92-01-20 5/5/92 93-16 6/4/93
14. Beaver Valley 2............. 412/91-80-02 4/1/92 93-27 1/24/94
----------------------------------------------------------------------------------------------------------------
III. Conclusion
The institution of proceedings in response to a request pursuant to
10 CFR 2.206 is appropriate only when substantial health and safety
issues have been raised. See Consolidated Edison Co. of New York
(Indian Point, Units 1, 2, and 3), CLI-75-8, 2 NRC 173, 176 (1975), and
Washington Public Power Supply System (WPPSS Nuclear Project No. 2),
DD-84-7, 19 NRC 899, 923 (1984). This standard has been applied to the
concerns raised by the Petitioner to determine if the action he
requested is warranted, and the NRC staff finds no basis for taking
such actions. Rather, as previously explained herein, the NRC staff
believes that the Petitioner has not raised any substantial health and
safety issues. Accordingly, the Petitioner's request for action
pursuant to 10 CFR 2.206, as specifically stated in his letter of
February 13, 1996, and supplemented by a letter dated May 1, 1996, is
denied.
A copy of this Director's Decision will be filed with the Secretary
of the Commission for the Commission's review in accordance with 10 CFR
2.206(c). This Decision will become the final action of the Commission
25 days after issuance unless the Commission, on its own motion,
institutes review of the Decision within that time.
Dated at Rockville, Maryland, this 10th day of October 1996.
For the Nuclear Regulatory Commission.
Frank J. Miraglia,
Acting Director, Office of Nuclear Reactor Regulation.
[FR Doc. 96-28736 Filed 11-7-96; 8:45 am]
BILLING CODE 7590-01-P