ML20117J211

Responds to Request for Additional Information Breaker Coordination

ML20117J211
Person / Time
Site:	Catawba
Issue date:	05/17/1996
From:	Mccollum W DUKE POWER CO.
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
TAC-M86367, TAC-M86368, TAC-M94847, TAC-M94848, NUDOCS 9605310017
Download: ML20117J211 (35)

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May 17,1996 U. S. Nuclear Regulatory Commission i ATfN: Document Control Desk Washington, D. C. 20555 i

Subject:

Catawba Nuclear Station Docket Nos. 50-413 and 50-414 Response To Request For Additional Information .

Regarding Breaker Coordination  !

(TAC Nos. M86367, M86368, M94847, M94848)

Attached is the response to the NRC Request For Additional Information, dated April 30,1996, concerning breaker coordination issues at the Catawba Nuclear Station (Attachment A).

l For your convenience, please refer to Attachment B for a list of Systems Designations used in the response and Attachment C for a simplified summary diagram of the 125 VDC Vital I & C Power System (EPL) Batteries, Battery Chargers and Distribution Centers. Attachment D identifies the l

interrupting ratings of various breakers used in the 600 VAC Essential Auxiliary Power System (EPE) and the 125 VDC Vital I & C Power System (EPL).

l if there are any questions as a result of this review, please contact Jeff Lowery, Catawba Regulatory Compliance, at (803) 831-3414.

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/' -r W. R. McCollum, Jr.

Vice President Catawba Nuclear Station 1

l Attachments

} l 9605310017 960517 k PDR ADOCK 05000413 I P pon Rmfed CA WC)CA,0 OdrMY AQQQe g l

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I t s U., S. Nuclear Regulatory Commission

. - May 16,1996 Page 2 xc: S. D. Ebneter, Regional Administrator, Region II 1

P. S. Tam, ONRR I

R. J. Freudenberger, Catawba Senior Resident Inspector l l

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U S. Nucl:ar Regulatory Commission

.' May 16,1996 i Page 3 1 1

bxc: ELL EC050 M. S. Kitlan CN01RC J. E. Snyder MG01RC J. E. Burchfield ONO3RC j P. R. Newton PB05E l K. E. Nicholson CN0lRC J. E. Stoner EC09N K. R. Caraway EC09N P. M. Abraham EC08I R. M. Glover CNO3CE J. W. Caldwell CNO3CE R. A.Dickard CNO3CE J. D. Glasser CNO3CE J. L. Lowery CN0lRC SREC NCMPA-1 NCEMC PMPA l

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ATTACHMENT A DUKE POWER COMPANY i l CATAWBA NUCLEAR STATION  !

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RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION BREAKER COORDINATION l l

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l I. Probabilistic Safety Assessment Issues l l

In general the Licensee's PRA submittal for continued plant operation with uncoordinated circuit breakers in the 125 Volt DC EPL system and 600 Volt AC EPE system should I address the impact of (1) initiating event (IE) fmquency, (2) conditional impact of the IE l on plant operation, (3) recovery of the plant mitigation capability, and (4) accident l recovery via Safe Shutdown Facility (SSF). The Licensee's submittal should specifically address the following-l 1.A 125 Volt DC Vital I&C Power System. EPL )

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1. Estimate initiating event frequency: The breaker coordination study provided with I the letter dated March 2,1994, from D.L. Rehn, Duke Power, excluded line-to-line cable faults in the outgoing feeders of the EPL load distribution centers.

Based on the discussion presented in CINC-1535.00-00-0007, line-to-line cable ,

faults appear rare. Using historical event data and estimated total number of cables 1 from all of Duke's nuclear power facilities (i.e. Oconee, McGuire, and Catawba),

and other industry data, e.g. IEEE Standard 500-1984, estimate the probability of ,

a cable fault tripping any of the 125 Volt DC load groups (e.g.1 EDA, IEDB, l 1EDC, and IEDD). Address the advantages in the use of the 2 kV rated  !

interlocked armor cable. If no cable faults have occurnd, assume one single line- I to-line fault to estimate the EPL cable fault initiating event frequency. Also discuss any cable enhancement programs at Duke that would provide additional ,'

assurance thr.t the probability of cable faults at Duke facilities will continue to remain small.

DUKE POWER COMPANY RESPONSE The initiating event (IE) frequency for the T14 initiator (Loss of a Vital Instrumentation and Control Power Bus) used in the Catawba Integrated Plant Examination (IPE) and the breaker coordination study (December 29,1994) is 0.05 based on one loss of a 125V DC Vital I&C Control Power distribution center in approximately twenty reactor-years (Catawba and McGuire) experience. The single incident was the result of an inadvertent manual tripping of the breaker, and l not an electrical component failure or electrical fault. The initiator frequency .

derived from the McGuire and Catawba operational experience is in agreement with the fault tree solution (see Catawba PRA, Rev.1, Appendix A.11) for failure )

of a control power distribution center.

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l In the 125V DC Vital I&C Power fault tree mentioned above, the various fault components are treated as a single bus fault on the distribution center or de panelboard itself. Thus, the bus fault is a " black box" in which the distribution center or panelboard faults,' faults on cables to the loads, and faults at terminals between the distribution points and the loads are implicitly included. A generic value for bus fault probability,2.E-07/hr, is used in the fault tree for the distribution center fault. This converts to about 2E-03/yr. For comparison,IEEE Standard 500-1984 gives a composite cable failure rate of 7.54E-06/hr/ plant for i power, control, and signal cables combined. Therefore, if a typical plant has ' l approximately 18,500 cables, and a typical distribution center has about 30 loads, then a single distribution center's failure rate due to cable fault is on the order of IE-04/ year. In ourjudgment the cable fault contribution is adequately covered by

, the distribution center fault value.

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! If a single line-to-line cable fault resulting in the loss of a distribution center or a power panelboard is assumed to have occurred at either Catawba or McGuire, j then the EPL cable fault frequency can be determined from the single fault in now 1 approximately 46 reactor years of experience. This is a cable fault frequency of l approximately 2E-02. The probability of that fault causing the loss of a single j distribution center is (2E-02)(30)/l8,500 = 3E-05/ year.

Interlocked ArmorCable 1

i- The cable has the same construction as non-armored cable, except that in addition, j a steel armor covering is applied around the entire outer circumference of the j cable. This interlocked steel outer covering provides protection to the cable from damage or degradation during loading and shipment from the factory to the plant, j protection during unloading at the plant, protection during the cable pulling i mstallation at the plant, as well as protection while in service.

Instead of being rated at only 600VAC, the cable was purchased with an 4 insulation system rated at 2000VAC (2KV). The individual cable conductors are )

high potential tested under water and spark tested at the factory at the values j ]

t required by the standards for 2KV cable. The individual conductors are then i

assembled into a multi-conductor cable with an interlocked armor covering. I i

The low voltage of 125VDC does not produce any internal ionization or corona >

! that would cause an internal flashover or failure between conductors within the i armored cable. The 2KV rated cable insulation system has a greater thickness i j than the insulation system of a standard 600V rated cable (which is adequate for l

this application), hence it provides a higher dielectric capability, better physical protection, and more margin for aging considerations.

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4 Duke had an interlocked armor cable fault test performed at Westinghouse Electric

). Corporation's High Power Laboratory in East Pittsburgh, PA in which a short circuit was applied between conductors followed by energization of the cable. The l test did not induce any additional shorts between conductors within the multi-conductor cable. The completed test results are documented in test report:

j MCM-1354.00-00-0029 titled " Cable Application - Fault Tests" and dated August 18-20, 1976. 1 Similar cable is used at Oconee Nuclear Station, where a cable monitoring

program has been established. For the cable monitoring program, six cable j

. samples were installed inside the Unit 2 containment building for this dedicated  ;

i purpose. At five year intervals over the life of the plant, a five foot segment is j removed from each cable sample for testing. The purpose of the test is to j measure, document, and trend the mechanical and electrical properties of the cable. l l In general, the past test results collectively show that the cable samples are in good physical condition after 20 years in a reactor building environment. The cable used q; at Catawba is identical to or better than the cable used at Oconee, including the l type ofinsulation material used, the insulation material formulation, and the overall

cable construction. The environmental qualification requirements of Catawba are enveloped by the Oconee requirements; hence, the data obtained from the Oconee Condition Monitoring Program is directly applicable to the cable at Catawba.

Catawba Cable Failure Trending Program A prcgram to evaluate and trend plant cable problems was put into place in January 1995. The purpose of this program is to evaluate and record problems or 1

malfunctions of plant cables and if an adverse trend develops, action is taken to  !

address the problem. The kinds of deficiencies that would be reported in this program include short circuits, insulation damage, and problems with cable sphces or terminations. Since cable of the same basic specifications and ratings is used in i both safety and nonsafety applications at Catawba, all plant system cables are

] included in the scope of the trending program. This results in a total of i approximately 37,400 cables for both units at Catawba.

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i A baseline failure goal is established for each equipment type in the trending a program. This goal is established from analyzing typical industry experience and

with a goal of supporting high plant reliability. Failure trends are evaluated across 18 month intervals and are classified in one of three color categories. Category

- GREEN means that the failure trend is below, or less than, the baseline goal.

I Category YELLOW means that the failure trend is below the baseline goal but is ]

trending in a direction that will exceed the baseline failure goal if action is not - j j taken, or the failure trend is above the baseline but is trending in a direction that

shows improvement in performance such that the goal is almost obtained.

Category RED means that the failure trend is above the baseline failure goal, l t

showing no sign ofimmediate recovery, and requires action to improve j performance. If a quarterly report shows equipment in the RED category, the j l equipment engineer submits an action plan addressing the significance, cause and j corrective actions planned. An upcoming revision to the program will require j submitting an action plan when equipment is in the YELLOW category. l i l

. Failure data is available from several different sources. The work management ,

] system is searched for all work orders written on the equipment type " CABLE". l

! Word searches are also conducted in the Problem Investigation Process to find any j j reports that include discussion of cable in the problem description section. Finally  !

the plant engineer who does the trending report also helps resolve many of the j

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j questions or problems with plant cables and that engineer will typically have direct i knowledge of cable problems as they are investigated. Data on failures or

problems with cables is collected at the end of each quarter and trend reports are  !

published in the Failure Analysis And Trending System Quarterly Report along

with reports on other types of equipment i

Since the cable failure trending program began in January 1995 there has only been

one failure reported. This failure in the second quarter of 1995 involved a single

i. phase to ground short circuit of a vendor supplied wire in a motor control center, i This wire connected the line side of a 600V breaker to it's bus and the short l- burned through without any breaker clearing. This failure was not specifically

within the scope of the cable trending program but was reported as a failure for j tracking purposes. When the cable trending program was put together in early 1995 a high level review of all available cable problern reports was conducted.

This baseline review did not identify any short circuit type failures of Duke cables back to the 1983 time frame.

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q Some of the criteria and practices used in applying Duke cabling that will .,

contribute to continued reliability are as follows Duke does a minimal amount of I cable splicing and does not allow any_ splices in raceways. Any safety related

, cables routed underground are installed in conduit or cable trenches. None of these cables are direct buried in the earth. Fire detection and/or protection is j provided in all plant areas where cables are routed. Cable ampacities utilized for

Duke cables are based on 70% of the standard industry ampacity ratings. Duke uses conservative conductor voltage ratings and uses the steel interlocked armor I

, for additional physical protection. l j Battery Output Circuit Breaker l 1 l Unlike some other plants where the battery is connected directly to the main dc '

distribution center bus with no automatic or manual disconnect means, Duke plants l

incorporate a battery source output circuit breaker between the battery and the  !

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! bus. If no battery source output disconnect means was provided, a hypothesized

fault on the main de distribution center would unnecessarily deplete the battery of its entire capacity, rendering it unavailable as a source of de power after the fault is

cleared. The battery source output breaker is provided in Duke plants in order to 1

maintain the integrity of the battery during any hypothesized de system fault

, condition and retain the capacity of the battery source that would otherwise be i depleted during the hypothesized fault. This isolation feature preserves the battery

capability, making it available after the faulted equipment is isolated or repaired.

i Accordingly, there is an increased likelihood of fault recovery than otherwise.

j It should be stressed that it is highly unlikely that a fault of the type and magnitude

! necessary to trip the battery source output breaker would occur since the de 1 battery system is ungrounded and is provided with a ground fault detection system.

2. Plant Response: Describe the plant response and conditional loss of mitigating

equipment in the event ofloss of each of the load group distribution centers.

DUKE POWER COMPANY RESPONSE 4

j Note: At Catawba, the Unit 1 125VDC Vital I and C Power (EPL) System is 1 essentially identical to the Unit 2 EPL System; and each is completely independent

from the other. Therefore, in order to simplify the discussion, the following description is for Unit 1; however, it equally applies to Unit 2.

l The effect of the loss of each of the load group distribution centers is as follows:

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1 EDA Loss of 125V DC VitalI&C Power Panelboard IEPA, Auctioneering

- Diode Assembly lEADA, and loss ofInverter IEIA. The loss of IEPA causes the i loss of power to the control solenoids for the A-Train Main Steam Isolation  !

Valves (MSIV), and the control solenoids for the A-Train Main Feedwater Control Valves resulting in secondary plant transients followed by a reactor trip. The loss of Auctioneering Diode Assembly 1EADA causes the loss of only one of two auctioneered sources of power to 125V DC Distribution Center lEDE which is needed for control of Train-A Engineered Safety Features (ESF) equipment and Train-A Turbine Driven Auxiliary Feedwater (AFW) Pump control. The loss of Inverter lEIA causes loss of 120V AC Vital I&C Power Panelboard 1ERPA.

IERPA supplies SSPS Channel I power, ESFAS Train-A slave relay power and process control for the Train-A Pressurizer PORV.

1EDB Loss of 125V DC Vital I&C Power Panelboard IEPB, and loss ofInverter lEIB. The loss ofInverter 1EIB causes loss of 120V AC Vital I&C Power Panelboard IERPB. IERPB supplies SSPS ChannelII power.

1EDC Loss of 125V DC Vital I&C Power Panelboard IEPC, and loss ofInverter IEIC. The loss ofInverter 1EIC causes loss of 120V AC Vital I&C Power Panelboard 1ERPC. IERPC supplies SSPS Channel III power.

1EDD Loss of 125V DC VitalI&C Power Panelboard IEPD, Auctioneering Diode Assembly lEADB, and loss ofInverter lEID. The loss of 1EPD causes the loss of power to the control solenoids for the B-Train MSIVs, and the control solenoids for the B-Train Main Feedwater Control Valves resulting in secondary plant transients followed by a reactor trip. The loss of Auctioneering Diode Assembly 1EADB causes the loss of only one of two auctioneered sources of power to 125V DC Distribution Center IEDF which is needed for control of Train-B ESF equipment and Train-B Turbine Driven AFW Pump control. The loss ofInverter lEID causes loss of 120V AC Vital I&C Power Panelboard 1ERPD. IERPD supplies SSPS Channel IV power, ESFAS Train-B slave relay power and process control for the Train-B Pressurizer PORVs. l l

lEDE Loss of Train-A 4160V AC Essential Switchgear control power, loss of Train-A 600V AC Essential Load Center control power, loss of Diesel Generator Load Sequencer Panel A, loss of Train-A Turbine Driven AFW Pump Control, and loss of Train-A Auxiliary Shutdown Panel.

1EDF Loss of Train-B 4160V AC Essential Switchgear control power, loss of l Train-B 600V AC Essential Load Center control power, loss of Diesel Generator l Load Sequencer Panel B, loss of Train-B Turbine Driven AFW Pump Control, loss )

of Train-B PORV Solenoids Control Power and loss of Train-B Auxiliary ,

Shutdown Panel. j Page 6 1 l

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3 In summary, a loss of power on IEDA or 1EDD would result in a plant transient,-

, but would not render the mitigating systems, except for the pressurizer PORV automatic control (one of three in Train A or two of three in Train B), inoperable.  !

A loss of power on IEDB or IEDC simply results in one channel of the SSPS to be tripped. Loss of power on IEDE or 1EDF would cause one train of safety systems to be without control power but would not result in a plant transient and,

therefore, not result in an immediate need for a mitigating system. i When the loss of power on an EPL bus does not cause a plant trip, the affected dc

bus would be considered inoperable, requiring resolution of the problem within j

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the applicable Technical Specifications Action Statement specified time period.

However, since in this situation there is no accident requiring the use of that equipment, continued power operation is not immediately affected.  ;

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3. Plant Recovery: For each of the cable faults that result in plant transients 3 described in response to question 2 above, provide the conditional probability of mitigation failure, without taking credit for the safe shut down facility (SSF). J Describe any credit taken for operator recovery actions.

DUKE POWER COMPANY RESPONSE As stated in response to Question I.A.2, loss of power on IEDA or 1EDD would result in a plant trip. In the existing analysis, one train of safety systems is also  !

assumed to lose control power. The two resulting cut sets, which include the SSF capability, have a combined frequency of 6.7E-8/ Reactor-Yeat. Without the SSF, the value becomes 1.2E-6/ Reactor Year. Thus, the conditional probability of mitigation system failure without taking credit for the SSF is estimated to be 2.4E-5.

The existing PRA analysis of the T14 event did not take credit for recovering from the initiating bus fault.

4. Safe Shutdown Facility: For each scenario described in response to question 3, provide the credit that could be taken for the SSF, i.e. the conditional probability of failure of the SSF given each of the scenarios described in response to questions 2 and 3 above.

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DUKE POWER COMPANY RESPONSE If the plant systems that provide the reactor coolant system heat removal and the reactor coolant pump seal cooling functions are unavailable or are failed following the T14 event, the SSF could be used to maintain safe shutdown of the plant. The failure modes of the SSF include operator failure to utilize the SSF in a timely  ;

manner, maintenance unavailability, latent human error and hardware failures. Of these, the operator failure (0.03) and the maintenance unavailability (0.026) show up in cut sets above IE-8.

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5. Calculation CNC-1535.00-00-0007, page 5, considered the initiating event from the loss of Vital I&C bus, T14, only. Discuss the impact on CDF from loss of other Vital I&C buses in the EPL system. Specifically, provide the rationale for the following statements in paragraph 2, page 5 of the calculation:

a. "The worst case faults result in a loss of one of four load distribution centers, l 1 EDA,1EDB,1EDC, or IEDD. These load group distribution centers are important to normal operation but none are essential for plant shutdown."

l DUKE POWER COMPANY RESPONSE The four load distribution centers 1 EDA,1EDB,1EDC, and IEDD, are normally aligned and operated independent of one another and serve four l independent load channels. Considering the independence of the channels,  !

then a " worst case fault" can result in the loss of only one channel. l The core damage frequency impact of the loss of power on an EPL bus is discussed in response to Question I.A.3.

Loss of IEDB or IEDC results in a loss of a Vital I&C Power 120V ac Inverter and the loss of an SSPS channel, a nuclear instrumentation channel, and a process protection channel. Loss of IEDA or IEDD results in similar channel losses plus the loss of automatic control of one or two primary PORVs and loss of the power maintaining the main steam isolation valves open and the main feedwater control valves open. Loss of either of these load group distribution centers will result in a plant trip.

Since a channel trip would occur on loss of power on any one of these channels, the load groups 1 EDA, IEDB, IEDC, and lEDD are " described" as "important to normal [ power) operation". Further,in the event of power failure to one of these channels, IEDE and IEDF (which provide control power for the safety equipment needed for safe shutdown of the plant) continue to have power; therefore, the statement "but none are essential for shutdown" is made in the referenced calculation.

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b. "None of the faults examined caused the complete loss of Auctioneered ,

Distribution Center 1EDE, although power from one of the two auctioneered I

! diode assemblies providing power to IEDE would be lost when its associated

load group distribution center fails by fault. The second of the auctioneered j distribution center's power supplies is a train of the 125V de Diesel Essential l Auxiliary Power System which is unaffected by any of the documented j breaker coordination problems."

DUKE POWER COMPANY RESPONSE See response 5.a. above.

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I.B 600 Volt AC Es<antial System. EPE

1. Estimate initiating event frequency; The breaker coordination study provided with the letter dated March 2,1994, from D.L. Rehn, Duke Power, excluded cable faults in the outgoing feeders of the EPE system Motor Control Centers (MCCs). ,

Using historical event data and estimated total number of cables from all of Duke's

.l nuclear power facilities (i.e. Oconee, McGuire, and Catawba), and other industry  :

data e.g. IEEE Standard 500-1984, estimate the probability of a cable fault tnpping any one of the 11 EPE MCCs. Address the advantages in the use of the 2 kV rated interlocked armor cable. If no cable faults have occurred, assume one cable fault to estimate the EPE system cable fault initiating event frequency. Also l

discuss any cable enhancement programs at Duke that would provide additional l assurance that the probability of cable faults at Duke facilities will continue to

• remain small.

i DUKE POWER COMPANY RESPONSE i

As indicated in the Duke submittal of December 29,1994 many of the EPE MCCs  :

are considered to be adequately coordinated when considering that cable faults are )

unlikely. To substantiate this assumption, the large body of Duke cable experience 1 (Oconee, McGuire and Catawba) was considered with favorable results. The seven i I

reactor Duke system has accumulated about 120 reactor years of experience as of December 31,1995. Considering that a typical unit contains approximately 18,500 cables, this is a substantial experience base. Our examination of the Duke cable experience did not identify any failures of significance. Even allowing for one or two failures, this data suggests a very low probability of cable faults (of the order of 2E-3 cable failures per year per plant). Further, using the IEEE 500 data of 4.8 failures per million hours per plant for power cable failures and assuming approximately 18,500 cables per plant suggests an estimated cable failure rate of approximately 2.3E-06 per cable year. With approximately 30 cable terminations in a typical 600 V MCC, the resulting probability of MCC failures due to cable fault is very small (7E-05/yr.). Thus, neglecting the cable fault in the breaker coordination analysis is a reasonable assumption. In the Catawba PRA, Section 2.1 is devoted to identifying the internal initiating events for accident sequences.

Loss of an individual MCC was not identified as an initiator ofinterest. However, the models for the individual 600 V MCCs are included in the system's analysis I (Appendix A16) so as to include the effect oflosing power to front-line equipment powered from the MCC, following the occurrence of an accident that requires the  ;

mitigative action by this equipment.

Interlocked Armor Cable The discussion ofinterlocked armor cable in the response to question 1.A.1 also '

applies to the 600 VAC Essential Auxiliary Power System (EPE) as well.

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Catawba Cable Failure Trending Program See description of this program in response to question I.A.1 above.

2, Plant Response: Describe the plant response and conditional loss of mitigating i equipment in the event of loss of each of the MCCs. l DUKE POWER COMPANY RESPONSE A review of the loads on each of the essential 600 V MCCs indicates that loss of i power to one of these MCCs would not directly result in a reactor transient. On the other hand, the power failum may render one train of safety systems inoperable (for example, inability to change the position of a MOV). The other  ;

train would not be affected. In this case the applicable Technica: Specification would be entered and the problem resolved within the specified time. Loss of j power to the MCC would be alarmed in the control room. Conditions involving a train of equipment being in maintenance at the time the postulated power failure  ;

occurs are considered infrequent and still may not result in a reactor trip, but may ,

require a plant shutdown if the required Technical Specification allowable time limit (generally one hour) is not satisfied. ,

3. Plant Recovery: For each of the cable faults that usult in plant transients ,

described in response to question 2 above, provide the conditional probability of l mitigation failure, without taking credit for the safe shut down facility (SSF). i Describe any credit taken for operator recovery actions. .

i DUKE POWER COMPANY RESPONSE I l

The response is not necessary since a plant transient is not expected to occur for j this condition.  ;

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4. Safe Shutdown Facility: For each scenario described in response to question 3, provide the credit that could be taken for the SSF, i.e. the conditional probability of failure of the SSF given each of the scenarios described in response to questions 2 and 3 above.

DUKE POWER COMPANY RESPONSE No response is necessary since no scenarios are identified in question 3 above. It must be noted, however, that for conditions involving the loss of de or a loss of ac j power events, the SSF could b used to remove core decay heat and to provide i reactor coolant pump seal protection, should the event lead to the loss off all l plant-side safety systems. i Page i1

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5. Calculation CNC-1535.00-00-0007, page 6, only considered the failure probability of MCC IEMXG from a fault in the Control Room Air Handling Unit (AHU) #1 only. Discuss the impact on CDF from loss of other loads in the EPE )

system. l DUKE POWER COMPANY RESPONSE From the answer to question #1 above, the probability of failure of a MCC due to a cable fault is approximately 7E-05/yr. Thus, the probability ofloss of a MCC due to a cable fault is less by over an order of magnitude than the probability of a T11 initiator,2E-03. The Tl1 initiator causes the loss of an entire train and bounds the consequences of a MCC failure.

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The 600V ac MCCs support safety related frontline equipment. Referring to the j Catawba PRA Appendix A.16, the probability ofloss of power on a 600V ac i MCC is approximately 1.5E-04 for a 24 hr. mission time. The cable fault j contribution to the mission time failure rate is about 5E-07; and, therefore, does i not significantly affect the overall MCC failure probability calculated in the existing documentation.

6. It appears that the 600 Volt MCC incoming breakers may be rated for 10,000 IAC. I Discuss the impact on the above results (I.B,1-5) of having used 10,000 MC l breakers in circuits where the fault currents are higher than 10,000 Amperes.

DUKE POWER COMPANY RESPONSE l

In Oct. 92 Duke completed a follow-up review in response to Deviation 413,414/92-01-06 and documented the results in a report. The background section of this repon stated that non-automatic breakers were considered for local isolation at EPE motor control centers. This option was dropped the report says when Duke teamed that the breaker was " rated for only 10,000 IAC". Since this was strictly a manual disconnect that would not open automatically it did not have an interrupting rating. Engineers who were involved with the original specification of this equipment say that the non-automatic switch would only withstand 10000 amps short circuit current. It was eliminated from consideration because the equipment was being designed for at least 18,000 amps short circuit current. Westinghouse who was the primary supplier of breakers for this equipment says that "IAC" is not a standard abbreviation in their technical literature. The context of the above report was shon circuit withstand rating, and it appears the above mentioned report should have said the breaker was only rated for 10,000 amps rather than 10,000 IAC.

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Regardless of why this term was used it had no bearing on the design of this equipment since the non-automatic switch was determined to be unsuitable for the application before the equipment was built. The wiring diagram (CNM-1314.01-

64) that shows the Westinghouse Type MC instantaneous magnetic incoming j breaker currently used in EPE motor control centers was approved and issued to l the file in Nov.1977. This was 7 years before Catawba began operation in 1985.

l The Westinghouse Type MC breaker which is rated 22,000 UL Listed Interrupting Rating rms Symmetrical Amperes was installed in the EPE motor control centers during original fabrication. All of the EPE motor control centers have a worst case fault current at the bus ofless than 18,000 amps. Data sheets listing the interrupting ratings of various breakers used in the EPE and EPL systems are listed in Attachment D.

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The trip element for the incoming bmaker cannot be removed because the breaker manufacturer has told Duke that the 800 amp frame MC breaker without a trip element is not qualified for use in a system with fault current exceeding 10,000 amps.

l 1.C EPL and EPE Systems

! 1. Confirm that the cable and equipment discussed in response to I.A and I.B above, are not inside containment, or potentially exposed to harsh environments caused by design basis events that could cause a lack of breaker coordination in the EPE and EPL systems. In addition, confirm that no single breaker miscoordination in the EPE and EPL systems can cause simultaneous trip of both Units.

DUKE POWER COMPANY RESPONSE There are no motor control centers, distribution centers or panelboards associated with the EPE or EPL systems located inside containment; therefore none of the  !

main feeder cabling passes through containment or would be directly affected by j degraded containment conditions. These buses are also not located in any other j plant areas where they would be directly exposed to harsh environments caused by design basis events. Although a detailed analysis of the routes of all the downstream feeder circuits to evaluate harsh environment impact on breaker coordination has not been conducted, the criteria used for designing these circuits and some of the reviews that have been performed, reduce the potential that any  :

design basis harsh environment conditions would cause a miscoordination problem.

l l l

l l

Page 13 T

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i ' Any circuits going to devices inside containment are provided with redundant

penetration protective devices. Due to the conservative ampacity rating of the electrical penetrations, the protective devices will typically coordinate with the upstream breakers. Most load feeder breakers in the EPL system serve multiple loads, and the main feeder cable branches out through fuses to the various loads.

The fuses are selected based on guidance in Design Criteria 2.04-1, " Rating Of J ,

Control Circuit Fuses And Resistors For Use At McGuire And Catawba Nuclear j Stations". These guidelines address coordination with upstream devices, and their

purpose is to maximize plant reliability for both normal and accident conditions.

All plant cabling potentially exposed to high energy design basis events such as i steam line break, feedwater line break or LOCA has been covered by interaction  :

reviews. These reviews tabulated all equipment within various break zones and l evaluated the direct impact of disabling that equipment. The purpose of the i i reviews, which are documented in section 3.6 of the FSAR, was to determine if J q any equipment required to mitigate the break or any equipment required to achieve )

F and maintain a cold shutdown was located within the zone. Any equipment within 1

the zone required for these functions had to be moved out of the zone or i protected. Acceptability reviews are required for any plant modification that could impact the earlier analysis.

l The separation criteria (Design Criteria 1.02) governing routing of Catawba cables l also reduces the impact of postulated harsh environment conditions. Redundant e

train cabling is separated by a minimum distance of three feet horizontally and 5 l feet vertically. Furthermore, the Fire Protection Plan typically allows the cabling i for only one shutdown train to be routed in a given plant area. The fire protection

{ analysis addressed the need for protective devices in the analyzed circuits to j coordinate with upstream devices.

! The typical distances from bus locations to areas where harsh environments could exist minimize the potential for the environment to cause a miscoordination l problem since the cable resistances and protective device; on the branch circuits  !

j enhance coordination. Given the separation of the cabling and reviews that have l

! been performed it would not appear credible that a harsh environment condition

! would challenge coordination on more than one train.

i 3

The 125VDC Vital I and C Power (EPL) Systems for Units 1 and 2 are completely

, separate and independent from each other; therefore, in the unlikely event of a

breaker miscoordination due to a fault, at most one train of one unit would be

affected.

J i

4 Page 14 1

e - --

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Unit 1 of the EPE system has one motor control center, IEMXG, that feeds safety related loads such as HVAC and service water that support the operation of both units. Loss of power to this bus is not an accident initiator and does not cause either unit to trip.1EMXG is capable of being powered from Unit 1 or Unit 2 but the incoming breakers are mechanically interlocked such that only one incoming breaker can be closed at a time. The other Unit 1 motor control centers in the EPE i system serve loads related to Unit 1 only. Unit 2 of the EPE system is the same as described here for Unit I with one bus that supplies HVAC and service water to both units. Loss of power to an EPE motor control center is not expected to cause a unit trip and no scenario has been identified that could cause a simultaneous trip of both units.

II. Electrical Engineering Issues

1. On page 5 of Attachment 3 contained in the December 29,1994 submittal,it is 2

indicated that EPL load group distribution centers lEDA, IEDB, IEDC, and lEDD are important for normal plant operation but not; are essential for plant shutdown. Provide a discussion to address if this refers to a plant shutdown following a plant transient that may be caused by the loss of one of these  ;

distribution centers or if accident conditions are also being considered. In addition, for non-accident conditions, address if the plant can be safely shutdown with loads that are powered only from the two auctione red distribution centers. l The response should be applicable to both units. l DUKE POWER COMPANY RESPONSE l

i Note: Though the following discussion makes reference to the Unit 1 125VDC Vital I and C Power (EPL) System, it equally applies to Unit 2.

The discussion in the December 29,1994 submittal refers to a plant shutdown following a fault-induced transient during normal plant operation. As discussed in question 2 of section I.A, the loss of 125VDC Vital I and C Power (EPL) System Distribution Center lEDA or 1EDD would result in a plant secondary system ,

transient and a subsequent reactor trip. The loss of either distribution center IEDB or IEDC would cause the associated Solid State Protection System (SSPS) channel to trip; however, the loss of one of these busses would not in itself cause a plant transient or reactor trip.

The loads fed from distribution centers 1 EDA, IEDB, IEDC, and lEDD are not required to be energized during non-accident conditions in order to accomplish a safe shutdown of the plant. Should a fault-induced transient occur, the plant could be safely shutdown using only the loads powered from either Auctioneered Distribution Center lEDE or 1EDF.

Page 15

j .- .

Reference _the responses to questions 2 and 5 in Section I.A for additional

information.

i ,

) 2. The EPL system design includes tie breakers that may be used to connect load L group distribution center EDA to EDC and load group distribution center EDB to  :

EDD. Identify and discuss any condition for which the tie breakers are to be used  :

to re-configure the EPL system in this manner. The response should also address  ;

i existing measures to limit the time period that such a configuration can be

} maintained and return the system to its normal configuration of four electrically independent distribution centers.

DUKE POWER COMPANY RESPONSE ,

The EPL System may be placed in a tied configuration during normal plant operation when: e

a. A battery parameter monitored under the Technical Specification required weekly and quarterly surveillance is below the administrative and/or Technical Specification limits. The parameters monitored include cell voltage, electrolyte level, and specific gravity,

b. Other weekly and quarterly Technical Specification surveillance requirements ( with respect to battery float voltage, electrolyte leakage, etc.) are not satisfied,

c. ' The Technical Specification required battery charger capacity test is l performed,

d. An equipment failure occurs.

The Technical Specifications limit the amount of time the EPL System can remain in a tied configuration. Each train of the EPL System is typically in a tied configuration less than 2% of the time during normal plant operation. In general, any Technical Specification mandated maintenance activity that requires placing the EPL System in a tied configuration is planned and scheduled to minimize the amount of time the system is left in this configuration. In rare cases, the EPL System may be placed in a tied configuration to accomplish a plant modification.

In general, these activities would be implemented under the Critical Maintena u Process which employs probabilistic risk assessment and additional defense it depth measures during the planning, scheduling, and execution stages. An i

example of where this process was effectively used is the recent Unit 1 EPL System battery replacement modification. In this modification, each of four batteries in Unit I was replaced in less than half of the allowed Technical Specification action statement time period. i Page 16

1

3. If an EPL distribution center is lost, discuss the provisions and measures taken to assure that the redundant load group distribution center loads are operable.

DUKE POWER COMPANY RESPONSE In the event of the loss of an EPL System distribution center that did not cause a unit trip, Operations would immediately review the Technical Specification Action Items Log (TSAIL) to determine the appropriate Technical Specification actior statement to enter. Subs quent actions would be directed toward investigating and resolving the problem within the specified time by utilizing Engineering and Maintenance resources as necessary.

4. Provide a discussion for all single line to ground faults that have occurred on the EPL system within the last five years. The discussion should address the nature of these faults including the length of time that the fault existed, any corrective actions taken to preclude recurrence of such faults, any inoperability period of the EPL ground fault detection system / alarm, and actions taken or to be taken if the fault detection system is inoperable.

DUKE POWER COMPANY RESPONSE Neither unit at Catawba has ever experienced a single line-to-ground fault which caused the 125VDC Vital I and C Power (EPL) System to become inoperable.

This 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 five years. All of these faults resulted in alarms both locally and in the control room and were caused by solenoid valve problems.

Three cases involved failed solenoid valve components, and the other two cases involved water intrusion which was subsequently corrected. Due to the intermittent nature and high resistance of these faults, and the lack of available equipment capable of reliably locating such faults, in the past, it sometimes took in excess of 6 months to correct the ground fault; however, it should be emphasized that none of these faults caused the EPL System to become inoperable at any time. Additional measures have now been implemented in an effort to aggressively locate and correct ground faults which may occur in the future.

These inciude the procurement of an advanced ground locating device which will allow grour.1 faults of a high-resistance nature to be located more readily. Also, a new Nuclear System Directive has been issued which establishes a ground response policy for both continuous and intermittent grounds. Finally, various health indicators are now monitored in the EPL System which tvill help identify any adverse ground fault trends . l l

Page 17

.i

t The EPL System work order history search revealed that only one ground fault detector has failed over the last five years. Because the original ground detector was no longer available from the manufacturer, a substitute part had to be found and an evaluation performed to verify its acceptability for use in the application.

As a result, it took longer than normal - approximately 1.5 years - to replace the unit; however, it should be emphasized that the EPL System is checked weekly i per administrative procedure for ground faults via a method independent of the j ground detector system. Therefore, in the unlikely event of a detector failure, a 1 ground would most likely be detected via the alternate means before a fault-related problem developed.

5. Describe the post modification / maintenance testing used to verify that no detrimental conditions are induced in the 600 Vac essential auxiliary power system (EPE) equipment prior to returning this equipment to operation.

DUKE POWER COMPANY RESPONSE All modification and maintenance work is controlled by station procedures.

Catawba procedure " Inspection and Maintenance Procedure For Motor Control Center Breakers", (IP/0%/36.~O/009), covers much of the work related to EPE motor control centers. This procedure, as well as other station procedures, provides strict controls on any changes from 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 a change to the circuit is made the step is documented on the log sheet and verified to be correct by an independent technician. Before the work can be closed out and the equipment be re-energized, the proper steps in the restoration section of the procedure must be completed and also verified by an independent technician. Use of these controls thrnehout the work activity helps avoid problems that could othenvise be missed, si eb as leaving in temporary jumpers or wiring equipment incorrectly.

Since some spare equipment is held in the warehouse for long periods, some periodic inspections are performed to verify that the equipment is in a serviceable condition. An example of this is that meggar tests are performed every six months on many of the large safety related motors stored in the warehouse. This provides additional assurance that the motors are in good condition and allows for ;

lead time to procure a replacemert if a problem is found with a spare motor, l I

Often when a replacement motor is to be installed, it will also be tested in the maintenance shop prior to taking it out to the field.

The Test Requirements section of the Inspection and Maintenance Procedure For Motor Control Center Breakers referred to above specifies that a meggar test of the load is to be performed if a fault is suspected. The Procedure Signoff Sheet  !

incluoes a section for recording these meggar readings. i Page 18

Typical restoration work performed at the completion of maintenance work on EPE motor control center feeders is as follows: All test equipment is verified to ,

be removed. The motor control center compartment is verified to be wired per the i

latest compartment wiring diagram. Motor phase rotation testing, if required, is performed. Operations closes the breaker and verifies proper operation of the i load. If a feeder breaker has been removed or replaced, a thermography test of the  !

energized breaker is conducted. Any additional functional verification l requirements specified by the engineer supporting the maintenance activity are also performed. This might include verifying proper full speed operation and verifying normal pressure and flow parameters, depending on what type equipment was wo:ted on.

When modification work is performed the engineer provides a Post Modification Test Plan in the modification package. The purpose of this testing is to verify that the modification has been successfully implemented, that the modification accomplishes what it was intended to do and that no adverse effects are l introduced to the plant. The Post Modification Test Plan receives a cross , i disciplinary review while it is being developed if the modification work involves l

. multiple systems or disciplines.

6. Provide a clarifying discussion to explain the meaning of "10,000 IAC". In ,

addition, include data sheets that prodde the current interrupting ratings for the EPE MCC load breakers and incoming and load breakers for the EPL distribution centers.

DUKE POWER COMPANY RESPONSE See response to question I.B.6 above.

i Page 19

o

1. e

• e ATTACHMENT B DUKE POWER COMPANY CATAWBA NUCLEAR STATION SYSTEM DESIGNATIONS l

f

CATAWBA NUCLEAR STATION Page1 System Designator List SYSTEM DESCRIPTION AD SSF Diesel Generator l AM Monitor Tank Bldg Vent i AS Aux Steam BB S/G Blowdown Recycle BW S/G Wet Lay-up Recirc ,

CA Aux Feedwater l CB Aux Boiler Feedwater .

CF Feedwater- Pumps, l&C and Valves CL CF Pump Seal Water I

CM Condensate CS Condensate Storage CT Conventional Sampling EBG 230KV S/Y Fire Protection ECB Normal Communications ECD Microwave (Dispatch)

ECE Emergency Communication ECF Intercommunication ECG Fuel Handling intercom ECH Test Department intercom. -

ECl Inter-plant Telephone ECM Micmwave

( ECP Public Address '

EDA Contml Rod Position Indication EEA Environmental Instrumentation EEB Meteorological Instrumentation EFA Fire Detection EGA . Generator Cooling EGB Generator Excitation EGC Generator l&C EHM Hydrogen Mitigation -

EHT Trace Heating EIA NSSS l&C (7330 PCS)

ElB Balance of Plant instr. (Heated Boxes)

EKA Dispatch Control ELA Emergency Lighting AC ELD Emergency Lighting DC ELN Normal Lighting AC EMA ESF Bypass Ind. Sys.

EMB Annunciation Alarm GMC Event Recorder "MD Loose Parts Monitoring EME Power Monitor- NC Pumps EMF Radiation Monitoring EMG Chart Recorders EMH Vibration Monitor- NC Pump EMI Vibration Monitor- CF Pump EMJ Closed Ckt. T.V. Monitor

( EMK Containment Evacuation Alarm EML Floor Drain Leak Detection EMT Equipment Monitoring

_ _ _ . . _ _- . . _ _ . _ .._ _ _ _ _ __ ._. _ _._ _ ___..___ _ .___ > ~ _ _ ~ _ __

l . .

1 CATAWBA NUCLEAR STATION Page 2 i i

System Designator List

! SYSTEM DESCRIPTION ENA incore System .

ENB Encore NIS  !

ENC Boron Dilution Mitigation  ;

ENS Emergency Notification  !

EOA Main Control Boards ,

EOC SSF Control Board  !

EPA Unit Main Power -

EPB 6.9KV Nomial Aux. Power  !

EPC 4.16KV Essential Aux. Power l EPD 600VAC Normal Aux. Power EPE 600VAC Essential Aux. Power ,

HPF 240/120VAC Aux. Control Power i EPG 120VAC Vital I&C Power i EPH 208/120VAC Normal Aux. Power l EPl 208/120VAC Essential Power  :

EPJ 250VDC Aux. Power (Dead Plant Battery)

EPK 125VDC Aux. Control Power (Aux Battery) l EPL 125VDC Vital l&C Power (Vital Battery)

EPM 13.8KV Normal Aux. Power ,

EPQ 125VDC Diesel Aux. Power (EDG Battery)

EPR 240/120VAC Normal Aux. Power EPW 600VAC Station Norm. Aux. Pwr.

EPX NPD Power Supply Warehouse f i EPY 240/120VAC Essential Aux. Power \

EPZ 240/120 Station Norm. Aux. Power EQB EDG Load sequencer j EQC EDG CoMmb EQD SSF Diesel Control ERB XFMR Station Cable Support ERC XFMR Station Grounding ERD Unit Mn. Power System Prot. Relaying ERE Unit Mn. Power System Cont. System ERF Unit Mn. Power System Meter & Monitoring ERN EDG Protective Relaying ETA 208/120 Station Normal Aux. Power  !

ETB 4.16KV Blackout Aux. Power j ETC 600VAC Blackout Aux. Power i ETE 208/120VAC Blackout Aux. Power j ETF 600VAC Cooling Tower Aux. Power l ETH 208/120 Cooling Tower Aux. Power i ETL 600VAC SSF Aux. Power l ETM 250/125VDC SSF Power (SSF Battery) i EUC Cathodic Protection  !

EVA Station Grounding EVB instrument Grounding ,

EVC Computer Grounding l EVE Electrical Reach Rods EWA Cable Room Cable Support EWB Equipment Room Cable Support I

1 CATAWBA NUCLEAR STATION Page 3

( System Designator List SYSTEM DESCRIPTION EWC General Plant Cable Support EXA Plant Security EXH Elect. Cranes & Holsts ,

EXS Misc. Electrical Systems l EZA Electrical Penetrations l FC Fuel Handling  ;

FD EDG Fuel Oil FW Refueling Water l GB Hydrogen Blanket j GH Generator Hydrogsn -

GN Generator Nitrogen GO Oxygen GP CO2 Generator Purge GS Hydrogen Bulk Storage HA Bleed Steam To "A" Htrs.

HB Bleed Steam To *B" Htrs.

HC Bleed Steam To "C" Htrs.

HD Bleed Steam To *D" Htts.

HE Bleed Steam To "E" Htrs.

HF Bleed Steam To "F" Htrs.

HG- Bleed Steam To "G" Htts.

HM Moisture Separator / Reheaters

(. HS Moisture Separator / Reheat Drains HW Heater Drain IAE Containment Airlock ICCM inadequate Core Cooling Monitor IDE Steam Dump Control IEE Seismic Monitoring .

IFE Feedwater Control IKE Operator Aid Computer ILE PZR Pressure & Level Control IPE Reactor Protection Actuation IRE Rod Control System ISE ESF Actuation ITE Main Turbine l&C ITM Transient Monitor System IWE Feedwater Pump Turbine l&C KC Component Cooling KD EDG Engine Cooling Water KF Spent Fuel Cooling KG Generator Cooling Water KR Recirculated Cooling Water 1 LD EDG Lube Oil I LF Feedwater Pump Turbine Lube Oil LG Generator Seal Oil LH Main Turbine Hydraulic Oil LP Feedwater Pump Turbine Hydraulic Oil LT Main Turb Lube Oil

(

MI Misc. Instruments MSE Misc. Electrical Systems l NB Boron Recycle 1 l

i CATAWBA NUCLEAR STATION Page 4 g 5

. System Designator List i

.i SYSTEM DESCRIPTION )

NC Reactor Coolant s ND Residual Heat Removal 4 NF Ice Condenser Refrigeration

~

NI Safety injection

, NM Nuclear Sampling NR Boron Thermal Regeneration l NS Containment Spray '

d NV Chemical and Volume Control Contain. Penetration Valve injection j 4

NW RA Condenser Tube Cleaning

RC Condenser Circulating H2O ,

j' RF Fire Protection - Interior  ;

' Low Pressure Service Water RL RN Nuclear Service Water ,

j -RS RL Intake Screen Backwash t RY Fire Protection - Exterior i SA SM Supply to Aux. Equipment i

! SB SM Bypass to Condenser SC Turt>ine Crossover

! Main Steam

SM 4 SP SM Supply to Feedwater Pump Turt>ine SV Main Steam Vent to Atmosphere I TE CFPT Turt>ine Exhaust i

TF CFPT Turbine Steam Seal Main Turbine Steam Seal i TL  !

TS Turbine Exhaust Hood Spray VA Aux. Bldg. Ventilation ,

t VB Breathing Air ,

VC Control Room Area Ventilation l

' VD EDG Room Ventilation ,

VE ' Annulus Ventilation VF Fuel PoolVentilation VG EDG Starting Air fi VH TSC Ventilation VI instrument Air i VJ Computer Room Ventilation VK Relay House Ventilation 2 VM Admin. Bldg. Ventilation VN EDG Airintake & Exhaust VO Turbine Bldg. Ventilation VP Containment Purge Ventilation i'

VQ Containment Air Addition / Release VS Station Air W Containment Ventilation Service Bldg. & Warehouse Ventilation i VW

! VX Containment Air Retum & H2 Skimmer j W Containment H2 Sample & Purge VZ RN Pumphouse Ventilation WB Service Bldg. Sump

- WC Conventional Waste Water j

i i

i

. . 1 l

( CATAWBA NUCLEAR STATION Page 5 System Designator List SYSTEM DESCRIPTION WE Equipment Decontamination WG Gaseous Waste Management WL Liquid Waste Recycle WN EDG Sump Pump WP Turb. Bldg. Sump Pump WS Nuclear Solid Waste Disposal WT Sanitation & Waste Treatment WZ Groundwater Drainage YA Conventional Chemical Add YB Admin. bldg. Chilled Water YC Control Area Chilled Water YD Drinking Water YF Filtered Water YH Heating Water YJ Computer Room Chilled Water YK NPD Office Area Chilled Water YM Make-up Demineralized Water YN Aux. Bldg. Chilled Water YR Aux. Bldg. Rad. Area Chilled Water i

~

YT Cooling Tower WaterTreat )

YV Containment Chilled Water

( YW Service Bldg. Chilled Water i

ZD EDG Crankcase Vacuum i ZJ Condensate Steam Air Ejectors ZM Main Vacuum ZP Vacuum Priming 1

. . l i

l ATI'ACHMENT C i DUKE POWEP OMPANY CATAWBA NUCLEAR STATION i l

SUMMARY

DIAGRAM OF THE 125 VDC VITAL I & C I i'

POWER SYSTEM (EPL) BATTERIES, BATTERY CHARGERS AND i 1

l DISTRIBUTION CENTERS i 5

l, i

t l

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• F B1B - - FSIC 1ECS BATTERY CHARGER F919 } F01A F81C i D11 Y - CErR_ 1EDS i 25m - - -G - 25m SEE NOTE 1 TO 698V MCC  : TO 688V'MCC  : TO 698W MCC 0TO 688W MCC I I I 1EMXI COMPT. FR58 i 1EMXB COMPT. FRiB 1EMXA COMPT. F849 1EMXJ COMPT. F940 1ECA 1ECB 1ECC 1 ECD BATTERY BATTERY BATTERY BATTERY CHARGER MTTER

-E CHARGER M TTER CHARGER pygfd CHARGER pyphd iEBA - tEBB iEBC - iEBD 1 r TE I rM 7 RTE 7 RTE 25m 40m 1EBTBA 25m 25m 40m 1EBTBB 25m 25m 48m 1EBTBC 25m 25m 48m 1ESTBD 25m F R3A F82A FR3B F83A FB2A FR3B F83A F82A FR3B FEDA FE2A F838 40m 40m 40m 49m FS2B DIST. CNTR.1EDB FB2B DIST. CNTR.1EDC FS2B DIST. CNTR.1EDD FB2B DIST. CNTR.1 EDA F 010 F elt F810 FE)C _ ,

F918 F01C F01D Falc , F91_B FalC F810 FE)C _ F81_B FB1C FSID FRIC 9m 9m 15 m 9m 9m 9m 9m 9m 9m 9m 9m 15 m V

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i i ATTACHMENT D i

l DUKE POWER COMPANY i CATAWBA NUCLEAR STATION 4

INTERRUPTING RATINGS OF VARIOUS BREAKERS

! USED IN THE 600 VAC ESSENTIAL AUXILIARY POWER SYSTEM (EPE)

AND THE 125 VDC VITAL I & C POWER SYSTEM (EPL) 4 0

4 4

I 1

l i

< = , c, l

4 ,-

i l Tables 1-4 list the types of molded-case circuit breakers used in the EPE and EPL Systems. The manufacturers' data sheets are provided on pages 2 and 3 of this attachment and are referenced accordingly.

l Table 1: FPE System Motor Control Center Breakers j Interrupting Rating Reference page

Breaker Application Manufacturer Type RMSSymmetrical Amperes of attachment Incoming Breakers Westinghouse MC 22,000 2 l Feeder Breakers Westinghouse HFB 18,000 2

} Feeder Breakers Westinghouse LB 22,000 2 i

Table 2: EPL System Distribution Center (EDA, EDB, EDC, EDD) Breakers

! Breaker Application / Interrupting Rating Reference page Compartment Manufacturer Type DC Amperes of attachment l

Battery Breaker / F02A Westinghouse LB 20,000 2 i Main Breaker /F02B Westinghouse LB 20,000 2

. Battery Charger Westinghouse KB 10,000 2 Breaker /F03A Tie Breaker /F03B Westinghouse KB 10,000 2 Feeder Breakers Westinghouse HFB 20,000 2 Table 3: EPL System Auctioneered Distribution Center (EDE, EDF) Breakers i

Breaker Application / Interrupting Rating Reference page Compartment Manufacturer Type DC Amperes of attachment incoming Breakers Westinghouse HFB 20,000 2 Feeder Breakers Westinghouse HFB 20,000 2 Table 4: EPL System Power Panelboard (EPA, EPB, EPC, EPD) Breakers i

Breaker Application / Interrupting Rating Reference page Compartment Manufacturer Type DC Amperes of attachment Feeder Breakers General Electric TED 10,000 3 i

I l

Page 1 of 3

,P A /

MOLDED CASE CIRCulT BREAKERS 33 v ~

.. ATTACHMENT D w [cQieM C.rcu.4 Cont No. Vous poderal UMmed emerruonng Haungs rms hymmeuscas Amperes bodationauruormanon u

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ra' - 4, oc pa s A, unos vote. oc. ine,e,en Pr n9 Page No.

At 40*C l 120 l 120/240l 240 l 277 l480 l 800 125 l 125150lPage No.

l 250

( NHk$MIAL ) Circuit Breakers, Continued EB 15-100 1 120 125 11a 10 000 .... 5.000 . . . 82 82 E8 15 100 2. 3 240 125,'250 10b.11b 12b 10.000 5.000 82 82 EHB 15-100 1 277 125 13a 14.000 . . . . 10.000 . . . . 82 82 EMB 15 100 2 480 250 13b 14.000 10.000 82 82 EMB 15 100 3 480 13b 14.000 82 82 F8 15 150 2 600 250 18a 18.000 14.000 14.000 10.000 83 83 i F8 15 150 3 600 18a 18.000 14.000 14.000 83 83 I HF8 15-30 1 277 125 13a 65.000 10.000 83 83 HF8 40-100 1 277 125 13e . . . . 25.000 .... .... 10.000 .... 83 83 ]

HF8 15 150 2. 3 600 250 22a 65.000 25.000 18.000 20.000 83 83

)

JA.KA 70-225 2. 3 600 250 19a.20a 25.000 22,000 22.000 10.000 84 84 HKA 70 225 2. 3 600 250 19a. 20a 65.000 35.000 25.000 20.000 84 84 1 J8.K8 70 250 2, 3 600 250 19a.20a 25.000 22.000 14.000 10.000 85 85 HK8 70-250 2. 3 600 250 0 65.000 25.000 18.000 20.000 85 85 j L8 70400 2. 3 600 250 21a 42.000 30.000 22.000 20.000 86 86 L88 125 400 2. 3 600 250 21a 42,000 30,000 22.000 20.000 86 86 HLB 125 400 2. 3 600 250 23e 65.000 35.000 25.000 20.000 86 86 DA 250 400 2. 3 240 250 tab 22.000 10.000 87 87 LA 400. 70400 2. 3 600 250 21a 42.000 30.000 22.000 20.000 88 88 LAB 400 a HLA 400 125400 2. 3 600 250 23a 65.000 35.000 25.000 20.000 88 88

/ LA 600 250400 2. 3 600 250 21a 42,000 30.000 22.000 20.000 89 89 L kJ HLA 600 250 600 2. 3 600 250 23a 65.000 35.000 25.000 20.000 89 89 MA 125-800 2. 3 600 250 21a 42.000 30.000 22.000 20.000 90 90 HMA 125400 2. 3 600 250 23a 65.000 35.000 25.000 20.000 90 90 NB 700 1200 2. 3 600 250 21a 42,000 30.000 22,000 20.000 91 91 HN8 700-1200 2. 3 600 250 23a 65.000 35.000 25.000 20.000 91 91 PB 600 2500 2, 3 600 250 25a 125.000 100.000 100.000 75.000 92 92 TLC,LCC 75400 2, 3 600 21a 42.000 30.000 22.000 93 93

, HLC 75400 2. 3 600 23a E5.000 35.000 25.000 93 93 MC.MCC 400-800 2. 3 600 21s 42.000 30.000 22.000 95 95 HMC 400-800 2. 3 600 23a 65.000 50.000 25.000 95 95 NC 600 1200 2. 3 600 21s 42.000 30.000 22.000 96 96 j HNC 600 1200 2. 3 600 23a 65.000 50.000 25.000 91 96 jPC.PCC 1000 3000 2. 3 600 25a t 25.000 100.000 100.000 7 97 l

i{

j CURRENTCurrent LIMIT Limiting 4Q Circuit Breakers - Non-Fused Type s

jFCL 15 100 2. 3 480 0 200.000 150.000 99 99 I LCL 125400 2. 3 600 0 200.000 200.000 100.000 99 99 '

{ MH5AC = ) Current Limiting Circuit Breakers - Fused Type F8 15 100 2. 3 600 250 16a.16b.17a. 26a 200,000 200.000 200.000 100.000 101 101 LA 70400 2. 3 600 250 16a.160.17a. 26a 200.000 200.000 200.000 100.000 101 101 NB 300-800 2. 3 600 250 160.174.26a 200.000 200.000 200.000 100 000 102 102 e PB 600 1600 2. 3 600 250 1Fa.26a 200.000 200.000 200.000 100.000 102 102 g o Not defined an W.C 375b-0 Two-pois circuet breater. or two poles of three-pose circuit breaker at 250 VD..

1 Page 2 of 3 Electric 81 Cornponents Division Febru8ry 1993 d