[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