ML20198G228

Forwards Integrated Plant Assessment Sys & Commodity Repts for Review & Approval IAW 10CFR54,license Renewal Rule

ML20198G228
Person / Time
Site:	Calvert Cliffs
Issue date:	08/21/1997
From:	Cruse C BALTIMORE GAS & ELECTRIC CO.
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
NUDOCS 9708270006
Download: ML20198G228 (86)

Text

- - _ ________-_ __ _- _-____ _ _ _ - _ _ - _ - _ _ -

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Cuant ts 11. C nt: Baltintore Ou and Electric Cornpany Vice President Calvert Cliffs Nuclear Poveer Plant Nuclear Energy 1650 Calvert Cliffs Parkw ay -

Lusby, Maryland 20657 410 495 4455 August 21,1997

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' U. S. Nuclear Regulatory Commission Washington, DC 20555 A*ITENTION: Document Control Desk 4 SUHJECT: Calveit Cliffs Nuclear Power Plant Unit Nos.1 & 2; Docket Nos. 50-317 & 50-318 Request for Review and Approval of System and Commodity Reports for License Renewal

REFERENCES:

(a) Letter from Mr. R. E. Denton (BGE) to NRC Docu.nent Control Desk, dated August 18,1995, Integrated Plant Assessment Methodology (b) Letter from Mr. D. M. Crutchfield (NRC) to Mr. C.11. Cruse (BGE),

dated, April 8,1996, Final Safety Evaluation (FSE) Concerning The Baltimore Gas and Electric Company Report entitled, Integrated Plant Assessment Methodology (c) Letter from Mr. S. C. Flanders (NRC), dated March 4,1997. " Summary of Meeti..; with Baltimore Gas and Electric Company (BGE) on BGE License Renewal Activities" This letter forwards the attached integrated Plant Assessment (IPA) System and Commodity Reports for review and approval in accordance with 10 CFR Part 54, the license renewal rule. Should we apply for License Renewal, we will reference IPA System and Commodity Reports as meeting the requirements of 10 CFR 54.21(a), " Contents of application-technical information," and the demonstration required by 10 CFR 54.29(a)(1)," Standards for issuance of a renewed license."

The information in these reports is accurate as of the dates of the references listed therein. Per 10 CFR 54.21(b), an amendment or amendments will be submitted that identify any changes to the

. current licensing basis that materially affect the content of the license renewal application (e.g., potential modifications resulting from Generic Letter 96-06). I I

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9708270006 970821 PDR ADOCK 05000317

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Document Control Desk August 21,1997 Page 2 in Reference (a), Baltimore Gas and Electric Company submitted the IPA Methodology for review and approval. In Reference (b), the Nuclear Regulatory Commission (NRC) concluded that the IPA Methodology is acceptable for meeting 10 CFR 54.21(a)(2) of the license renewal rule, and if implemented, provides reasonable assurance that all structures and components subject to an aging management review pursuant to 10 CFR 54.21(r.)(1) will be identified. Additionally, the NRC concluded that the methodology provides processes for demonstrating that the effects of aging will be adequately managed pursuant to 10 CFR 54.21(a)(3) that are conceptually sound and consistent with the intent of the licer.re renewal rule.

In Reference (c), the NRC stated that if the format and content of these reports met the requirements of the template developed by HGE, the NRC could begin the technical review. This report has been produced and formatted in accordance with these guidance documents. We look forward to your comments on the reports as they are submitted and your continued cooperation with our license renewal efforts.

l

, ; a: .

t Document Contr$1 Desk

August 21,1997 -

Page 3 e

Sh6uld you have questions regarding this matter, we will be pleased to discuss them with youc Very truly yours, 7

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/

- STATE OF MARYLAND -  :

- : TO WIT:

- COUNTY OF CALVERT  :

1. Charles 11. Cruse, being duly sworn, state that I am Vice President, Nuclear Energy Division,  !

Haltimore Gas and Electric Company (BGE), and that I am duly authorized to execute and file this

response on behalf of BOE. To the best of my knowledge and belief, the statements contained in this document are true and correct. .To the extent that these statements are not based on my personal knowledge, they are based upon information provided by other BGE employees and/or consultants. Such information has been reviewed in accordance with company practice and I believe it - reliable.

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Su ri d and sworn beforepe, a Notary fublic in and for the State of Maryland and County of rDt%) . this #1 atday of dito(A,of) .1997.-

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- WITNESS my lland and Notarial Scal: W RAL Notary Public My Commission Expires: $ 3

' Date '

, CilC/SJR/ dim :

Attachments:' (1) Appendix A - Technical information; 5.17 - Service Water System .

.  ;(2)' ~ Appendix A - Technical Information; 5.18 - Spe it Fuel Pool Cooling System (3)' Appendix A - Technical Information: 6.1 - Catles cc: ' R. S. Fleishman, Esquire . 11. J. Miller,NRC

!J. E. Silberg. Esquire Resident inspector, NRC Director, Project Directorate 1 1, NRC - R.1. McLean, DNR  !

A. W. Dromerick, NRC J.11. Walter, PSC '

' S. C. Flanders, NRC l

t e

ATTACHMENT (1Y l I

l h

4 -

APPENDIX A - TECHNICAL INFOltMATION i

5.17 - SERVICE WATER SYSTEM Baltimore Gas and Electric Company Calvert Cliffs Nuclear Power Plant August 21,1997 z__ . _ _ _ _ . . . _ . _. __

ATTACIIMENT (1)

APPENDIX A - TECHNICAL INFORMATION 5.17 - SERVICE WATER SYSTEM 5.17 Servlee Water System nis is a section cf the Baltimore Gas and Electric Company (BGE) License Renewal Application (LRA), addressi.ig the Service Water (SRW) System. The SRW System was evaluated in accordance with the Calvert Cliffs Nuclear Power Plant (CCNPP) Integrated Plant Assessment (IPA) Methodology described in Section 2.0 of the BGE LRA. Tbc results are presented below. These sections are prepared independertly ad will, collectively, comprise the entire BGE LRA.

5.17.1 Scoping System level scoping describes boundaries for ple.nt systems and structures. develops screening tools that capture the 10 CFR 54.4(a) scoping criteria, and then applies the tools to identify systems and structures within the scope of license renewal. Component level scooing describes the components within the boundaries of those systems and structures that contribute to the intended functions. Scoping to determine components subject to aging management review (AMR) begins with a listing of passive intended functions and then dispositions the component types as either associated with active functions, subject to replacement, or subject to AMR either in this report or ar.other report.

Section 5.17.1.1 presents the results of the systens level scoping 5.17.1.2 the results of the component level scoping, and 5.17.13 the results of scoping to determine components subject to AMR.

Representative historical operating experience pedinent to aging is included in appropriate areas to provide insight supporting the aging management demonstrations. This operating experience was obtained through keyword searches of BGE's electronic database ofinformation on the CCNPP bckets and through documented discussions with currently assigned cognizant CCNPP personnel.

5.17.1.1 System LevelScoping This section begins with a description of the system that includes the boundaries of the system as it was scoped. The intended functions of the system are listed and are used to define what portions of the system are within the scope oflicense renewal.

System Descrintion/Concentual Boundaries The SRW System in each CCNPP unit is a closed loop cooling water system that supplies chemistry-controlled water in normal operation to two safety-related, Seismic Category I trains and a common non-safety-related, non scismic train. The safety-related trains supply cooling water to the spent fuel pool (SFP) heat exchanger, containment cooling units, blowdown recovery heat exchangers, and the emergency diesel generators (EDGs). The non-safety related train provides cooling water to various Turbine Building loads. [ Reference 1, Sections 1.1.1,1.1.2]

The scope of the SRW AMR includes all safety-related SRW pressure boundary components relied on for mitigation of Design Basis Events. This includes both SRW trains in the Auxiliary Building and Containment Building, all components up to and including the Turbine Building SRW Header Isolation Valves, and components downstream of the check valves in the return piping from the Turbine Building to the suction header of each Auxiliary Building train. (Reference 1, Appendix B] The Turbine Building loads are not safety.related and are isolated on a Safety Injection Actuation Signal. - (Reference 1, Section 1.1.l] Service water piping and valves associated with the instrument and plant air compressors Application for License Renewal 5.17 1 Calvert Cliffs Nuclear Power Plant

ATTACIIMENT (1)

APPENDIX A - TECHNICAL INFORMATION 5.17 - SERVICE WATER SYSTEM and aftercoolers are within the scope oflicense renewal to support fire protection functions as described in Section 5.10 of this DGE LRA. [ Reference 2. Section 4.2] The remaining Turbine Buildng loads are not within the scope of license renewal.

The system for each unit has been divided into two trains in the Auxiliary Building to meet single failure criteria. Each safety-related train is comprised of the following major components: [ Reference 1, Section 1.1.2]

Piping and Valves Alignment and transport of cooling water from the pumps to the various loads, licad Tank Each safety related train contains one head tank which maintains the SRW System pressure and allows for thermal expansion. Demineralized water makeup to the head tank is automatically controlled by level controllers. Additional makeup capacity may be provided from the Condensate System. [ Reference 3, Section 9.5.2.2]

Pumps / Motors Each safety related train contains one single-stage, double-volute, centrifugal pump driven by an electric motor. An additional pump / motor combination is available for use by either subsystem. The two SRW pumps are powered from separate Engineered Safety Feature 4 kV buses, and the third pump is capable of being powered from either Engineered Safety Features' 4 kV bus. In the event that one bus is unavailable, the capability to manually transfer the third pump to the operating bus exists.

A low discharge head:r pressure will annunciate in the Control Room and the operator can then manually activate the standby pump. [ Reference 3, Section 9.5.2.2]

SRW/ Saltwater (SW) fleat Each SRW train contains one shell and tube-type heat exchanger that Exchangers transfers heat from the SRW System in the shcIl to the SW System in the tube side of the heat exchanger.

SFP lleat Exchangers One horizontal, counterflow heat exchanger supplied by one SRW train per unit maintains the SFP water temperature below the design temperature.

Containment Coolers Four containment coolers are provided in each unit to remove heat from the containment during normal plant operation and in the event of a loss-of coolant incident. Any cooler can be supplied from any train. During normal operation, only those coolers required to remove the heat load are operating.

EDG Coolers Three EDGs are supplied with cooling water from the SRW System (Unit I supplies No. IB EDG, Unit 2 supplies Nos. 2A and 20 EDGs).

Each diesel generator contains three separate single pass, shell and tube-type heat exchangers used to cool the tube oil, diesel jacket water, and diesel air subsystems.

Application for Licens : Renewal 5.152 Calvert Cliffs Nuclear Power Plant

ATTACllMENT (1)

APPENDIX A - TECIINICAL INFORMATION 5.17 - SERVICE WATER SYSTEM Blowdown Recovery IIcat One blowdown recovery heat exchanger is supplied by one SRW train per Exchanger unit for the Dnal blowdown cooling step.

Instruments Measure Dow rates, pressure and temperature. Provide alarm and initiate automatic actions.

Supply and return line redundancy is provided for containment cooling units and EDGs. Redundancy for the SFP coolers is provided by cooling one SFP cooler from each unit. Radiation monitors are installed in the SRW return header from the SFP coolers to detect possible in-leakage of radioactive liquids through the heat exchangers. [ Reference 3, Section 9.5.2.2]

During normal operation, both subsystems are required and are independent to the degree necessary to assure the safe operation and shutdown of the plant assuming a single failure. During shutdown, operation of the SRW System is the same as normal operation, except that the heat loads are reduced as is the SW Dow required to remove heat from the system. [ Reference 3, Section 9.5.2.2]

During the Loss-of-Coolant Accident (LOCA) mode of operation, each of the two trains for the two units will cool a maximum of two containment air coolers and one EDG. Although Unit 2 trains have identical heat loads and How requirements for LOCA operations, Unit I trains do not have identical heat loads as Unit I has only one SRW cooled EDO. Number 12 SRW train cools No. IB EDG, and No. I A EDG is cooled from an independent cooling source located in the safety-related Diesel Generator Building. The original design heat removal capability of three of the four containment cooling units was to provide the same heat removal capability as the Containment Spray System, The analysis of these systems operating together post LOCA is presented in Section 14.20 of the CCNPP Updated Final Safety Analysis Report (UFSAR) [ Reference 3, Section 9.5.2.2]

T4 rurbine Building SRW lleader Isolation Valves separate the safety-related portion of the system from the non safety-related portion. These valves close on a Safety injection Actuation Sigel, but they do not close automatically upon a seismic event. Calvert Cliffs has evaluated a postulated SRW System pipe rupture in the Turbine Building that renders both Auxiliary Building SRW subsystems inoperable following a seismic event [ Reference 4]. It has been concluded the non-safety-related portions of the SRW System are adequately rugged to withstand a design basis carthquake (Reference 5]. This ruggedness is credited in preserving system inventory regardless of Turbine Building SRW lieader Isolation Valve leakage rate. (Reference 6]

The non-safety-related SRW piping in the Turbine Building and safety-related piping in the Auxiliary Building were both originally designed to (United States of America Standard] USAS B31.1 (1969 Edition through summer 1972 Addenda) and both are subject to the same environmental service conditions and chemistry controls. (Reference 1, Appendix B]

SRW System Functions [ Reference 7, Table 1]

The basic SRW System functions are as follows:

1. To remove heat fro.n the plant's containment cooling units, SFP, and EDG heat exchangers and transfer that hest to the SW System;

2. To serve as an intermediate barrier between various auxiliary systems and the SW System; and Application for License Renewal 5.17-3 Calvert Cliffs Nuclear Power Plant

ATTACHMENT (1)

APPENDIX A - TECIINICAL INFORMATION 5.17 - SERVICE WATER SYSTEM

3. To provide additional heat removal capacity during a LOCA.

System ooerating Exocricac The following are operating experiences related to the SRW System with the potential for affecting the intended functions of the components or system.

- Following a routine tube cleaning of the one of the SRW heat exchangers in 1980, several low pressure alarms were received on the SRW subsystems. A manual reactor trip was then initiated due to high main turbine bearing temperature, The cause of the event was a failed tube in the Unit 1 instrument air compressor aftercooler which allowed air to enter the SRW System. Air became trapped in the idled heat exchanger and air ingress exceeded the air removal capability of the constant vent valves, causing the air binding of the system when the heat exchanger was returned to service. [ Reference 8] A CCNPP design change was implemented to provide greater air removal from the SRW System. This design change included changes to alarms and indications.

Calvert Cliffs has experienced recurring SRW heat exchanger tube leakage for the past several years.

The cause of this leakage is due primarily to erosion and corrosion aging mechanisms. In 1985, CCNPP installed 8 inch long sleeves in the inlet section of each tube (both plugged and unplugged) in the No.11 SRW heat exchanger. Total SRW System leakage was measured at 0.43 gallons per minute following this repair. This low leakage rate was evaluated as not safety significant. Routine monitoring of SRW head tank levels and weekly surveillance to quantify SRW System leakage are adequate to alert operators of an increasing leak rate condition. [ Reference 9]

These events demonstrate that CCNPP modifies and maintains the SRW System to ensure that the SRW components remain capable of performing their intended function under current licensing basis (CLB) conditions.

System Interfaces All safety-related por:lons of the SRW System are within scope for license renewal. Evaluation of the SRW heat exchangers was included in the SW System AMR, and evaluations of the heat exchangers cooled by the SRW System were included in their respective systems' AMRs. Fig tre 5.17-1 shows the SRW cystem flow path and components, including the systems and components that interface with the SRW Sptem. Figure 5.17-1 is simplified and provided for information only. A list of SRW System interfaces is given below: [ Reference 3, Section 9.5.2.2].

• Containment coolers *

• Fairbanks Morse EDG heat exchangers*

• SFP coolers *

• Steam generator blowdown recovery heat exchangers*

• Condensate system *

• Demineralized water system *

' Application for License Renewal 5.17-4 Calvert Cliffs Nuclear Power Plant

NITACHMENT (1)

APPENDIX A - TECIINICAL INFORMATION ,

5.17 - SERVICE WATER SYSTEM Turbine Building Loads

• Generator isolated three phase bus duct coolers

• Exciter air coolers

• - Generator hydrogen coolers

• - Stator liquid coolers (Unit 1 only)

• Circulating water system priming pump seal water coolers

• Condenser vacuum pump seal water coolers

• Feed pump turbine lube oil coolers

• Condensate booster pump lube oil and seal water coolers

• Instrument and plant air compressors and aftercoolers*

• Turbine tube oil cooler

• Electro-hydraulle oil coolers

• ' Turbine Building sample cooling system

• Makeup i.oineralized water system degasifier vacuum pumps (Unit 1 only)

• Nitrogen compressor and aftercooler (Unit 1 only)

• Seal oil system coolers (Unit 2 only)

• Auxiliary Feedwater Pump Room air cooler The SRW System interfaces listed above are not all within the scope oflicense renewal. Those systems or system components interfacing with the SRW System that are within the scope oflicense renewal are noted with an asterisk (*) above and are shown in Figure 5.17-1 as noted with an asterisk. Cooling water to the instrument and plant air compressors are within the scope for license renewal for fire protection ano are evaluated in Section 5.10, Fire Protection, in the BGE LRA. Those portions of the SRW System within the scope oflicense renewal are indicated by solid lines in Figure 5.17-1. Those portions of the SRW System that are not within the scope of license renewal are indicated by a dashed line in Figure 5.171, Where a system, component, commodity, or structure interface is within the scope of license renewal, that system will be addressed by the respective section of this application for that system, structure, or component.

Application for License Renewal 5.17-5 Calvert Cliffs Nuclear Power Plant

ATTACIIMENT (1)

APPENDIX A - TECIINICAL INFORMATION 5.17-SERVICE WATER SYSTEM e , c ,

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FIGURE S.17-1 SERVICE WATER SYSTEM - SIMPLIFIED DIAGRAM (Information Only) npplica; ion for License Renewal 5.17-6 Calvert ClifrS Nuclear Power Plant

ATTACIIMENT (P, .

APPENDIX A - TECIINICAL INFORMATION 5.17 - SERVICE WATER SYSTEM -

System Sconing Results The SRW System is in the scope for license renewal based on 10 CFR 54.4(a). In accordance with Section 4.1,1 of the CCNPP IPA Methodology, the following list of system intended functions was determined based on the requirements of 10 CFR 54.4(a)(1) and (2): [ Reference 10, Table 1]

• Serves as a vital auxiliary to Engineered Safety Features Actuation Signal by processing Agnals; and as a vital auxiliary to the EDGs, SFP coolers, and containment coolers by providing cooling water;

• To provide seismic integrity and/or protection of safety-related components;

• To maintain electrical continuity and/or provide protection of the electrical system; and

. To maintain the pressure houndary of the system liquid.

- The following intended functions of the SRW System were determined based on the requirements of 10 CFR 54.4(a)(3): [ Reference 10, Table 1) e For environmental quaiification ({50.49)- Maintain functionality of the electrical components as addressed by the Environmental Qualification Program.

• For fire protection (f 50.48)- Provide required cooling water to the EDGs, containment coolers, and instrument air / plant air compressor loads to ensure safe shutdown in the event of a postulated severe fire.

• For post nccident monitoring - To provide information used to assess the environs and plant condition during and following an accident.

The SRW Gystem components performing 54.4(a)(1) and (2) intended ft.nctions are safety-related, and are subject to the applicable Codes identified in UFSAR Section 9.5, Table 917.

5.17,1.2 Component Level Scoping flased on the intended functions listed above, the portion of the SRW Systcm that is within the scope of license renewal consists of piping, components (i.e., heat exchangers, pumps and tanks), supports, instrumentation, and cables that are relied on for-mitigation of Design Basis Events, ost-Accident Monitoring, Environmental Qualification and Fire Protection.

A total of 38 device types with>n these SRW equipment types were designated as within the scope of license renewal based on these intended functions. These device types are listed in Table 5.17-1.

[ Reference 1, Section 2.2]

Several components are common to many plant systems and perform the same passive functions regardless of system. These components are listed below:

• Structural supports for piping, cables and components;

• Electrical cabling; and e Process and instrument tubing, instrument tubing manual v ilves, and tuoidg snports.

- Application for License Renewal 5.17 7 Calvert Cliffs Nuclear Power Plant -

NTTACllMENT (1)

APPENDIX A - TECIINICAL INFORMATION 1

5.17 - SERVICE WATER SYSTEM 5.17.1.3 Componente Subject to AMR

'llis section describes the components of the SRW System that are subject to an AMR. It begins with a listing of passive intended functions and then dispositions the device types previously listed as either associated with active functions, subject to replacement, evaluated in other reports, evaluated in commodity reports or remaining to be evaluated for aging management in this section.

Passive Intended Functions in accordance with the CCNPP IPA Methodology Section 5.1, the following SRW System functions were determined to be passive: (Reference 1, Table 3 1]

e To maintain the pressure boundary of the system liquid;

• To provide seismic integrity and/or protection of safety-related components; and e To maintain electrical continuity and/or provide protection of the electrical system.

Application for License Renewal 5.17-8 Calvert Cliffs Nuclear Power Plant

ATTACliMENT f1)

APPENillX A TECilNICAL INFORMATION 5.17 SERVICE WATER SYSTEM TABLE 5.171 SERVICE WATEM SYSTEM DEVICE TVPES Dnke Descripilom Device Type Piping Line 110 Check Valve CKV Coil COIL Control Valve CV I Voltage / Current Device E/l Flow Element FE i Flow Indicator FI Flow Orifice FO Flow Transmitter FT Fnse FU lland Switch IIS Iland Valve llV lleat Exchanger llX Ammeter 11 Power Light Indicator JL 1 Level Gage LO Level Switch LS Level Transmitter I.T 4kV Motor MA 125/250VDC Motor MD 4kV Local Control Station NA 125/250VDC Local Control Station ND Pressure Differential Indicating Controller PDIC >

Pressure indicator Pl Panel PNL Pressure Switch PS Pressure Transmitter PT Pump / Driver Assembly PUMP Radiation Element RE ReliefValve RV Relay RY Temperature Element TE Temperature Indicator - TI Temperature Indicator Alarm TIA Tank TK Power Supply YX Position Indicating Lamp - ZL Position Switch ZS i Application for License Renewal 5.17 9 Calvert ClitTs Nuclear Power Plant

i t

ATTACitMENT (1) l APPENDlX A TECilNICAL INFORMATION 5.17. SERVICE WATER SYSTEM Device Types Subicci to AMR The device types of the SRW System, and the associated supports, cables, and tubing, were reviewed and

. dispositioned as follows: [ Reference 1 Section 3 2, Table 3 2)

• Sixteen device t)),es, including the coil, voltage / current device How indicator, fuse, hand switch, i ammeter, power light indicator, level switch, 4 kV motor, 125/250 VDC motor, pressure Indicator, relay, temperature indicating alarm, power supply, position indicating lamp, and ,

position switch, are only assoc,aded with active functions.

• The SRW heat exchanger is a device type that is evaluated in the SW System in Section 5.16 of the HGB LRA.

• Six device types, including the now transmitter, level gauge, level transmitter, differential pressure indicating controller, pressure switch, and pressure transmitter, are evaluated in the Instrument Lin9 Commodity Evaluation in Section 6.4 of the BGE LRA. Some hand valves that ,

are isolable by instrument root valves are also evaluated in the Instrument Lines Commodity Evaluation.

• Three device types,4kV local control station, 125/250VDC local control station, and panel, are  !

dispositioned in the Electrical and Instrument panels Commodity Evaluation in Section 6.2 of the i HGE LRA. This commodity evaluation partially addresses the SRW System intended function, "To provide seismic integrity and/or protection of safety related components."

• Structural supports for piping, cables, instruments, and components in the SRW System that are subject to AMR are evaluced for the effects of aging in the Component Supports Commodity Evaluation in Section 3.1 of the HGB LRA. This commodity evaluation partially addresses the SRW System passive intendc<l function,"To provide seismic integrity and/or protection of safety related components."

• Electrical cabling for componena in the SRW System that are subject to AMR is eval.iated for '

the effects of aging in the Electrical Cables Commodity Evcluation in Section 6.1 of the BGE LRA. *lhls commodity evaluation completely addresses the SRW System passive intended function,"To maintain electrical continuity and/or provide p otection of the electrical system."

• Instrument tubing and piping, associated instrument valves, and Ottings (generally everything from the outlet of the Unal root valve up to and including the instrument) are all evaluated for the effects of aging in the instrument Lines Commodity Evaluation in Section 6.4 of the DGE LRA.

This commodity evaluation addresses the SRW System passive intended function,"To maintain the pressure boundary of the system liquid."

As a result of the commodity evaluations presented above, the only passive function associated with the SRW System is the following:

• To maintain the pressure boundary of the system liquid.

Of the 38 device types originally within the scope oflicense renewal, only 12 device types remain that have this passive intended function (pressure boundary) and are long lived. 'Ihese 12 SRW device types are listed in Table 5.17 2. The 12 device types are subject to AMR for the SRW System, and are the-subject of the remainder of this report. [ Reference 1 Table 3 2)

Application for License Renewal 5.17-10 Calvert Cliffs Nu': lear Power Plant s

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A'ITACllMENT f1)

APPENDIX A TECilNICAL INFORMATION 5.17. SERVICE WATER SYSTEM i

TAllLE 5.17 2 DEVICE _TYPEE utm111tlNG AMR FOR SERVICE WATEM SYSTEM Piping (.lill)

Check Valve (CKV) ,

Control Valve (CV)

Flow Element (FE)

Flow Orifice (FO) lland Valve (llV)

Purnp/ Driver Assembly (PUMP)

Ridlation Elemer.t (RE)

Relief Valve (RV)

Temperature Element (TE)

Temperature Indicator (TI)

Tank (TK) llaltimore Gas and Electric Company may elect to replace components for which the AMR identlSes further analysis or examination is needed, in accordance with the License Renewal Ru!c, components subject to replacement based on qualined life or specified time period would not be subject te AMR.

5.17.2 Aging Management The list of potential Age Related Degradation Mechanisms (ARDMs) identiDed for the SRW System device types is given in Table 5.17 3 'Ihe plausible ARDMs are identined in the table by a check mark

(/) in the appropriate column. For the AMR, some SRW device types have a number of groups and subgroups associated with them because of the diversity of materials used in their fabrication. A check mark indicates that the ARDM applies to at least one group or subgroup for the devico type listed 'Ihe device types listed in Table 5.17 3 are those previously identified in Table 5.17 2 as passive and long lived.

[ Reference 1, Tables 41,4 2) For efuelency in presenting the results of these evaluations in this report, ARDM/ device type combinations are grouped where there are similar characteristics and the discussion is applicable to all device types wkhin that group. Exceptions are noted where appropriate. For this report the device types are grouped according to plausible ARDMs as follows:

Group I crevice corrosion / pitting Group 4 selective teaching Group 2 crosion corrosion Group 5. wear Group 3 general corrosion Application for License Renewal - 5.17 11 Calvert Cliffs Nuclear Power Plant

1 A*fTACitMENT (1)  :

APPENDIX A TECilNICAL INFORMATION 5.17. SERVICE WATER SYSTEM

, TABLE 5.17 3 POTENTIAL AND PLAUSint.E Amt)Ma FOR TIIE MERVICE WATER SYSTEM i Deslee Types fw Which AILDht is Flamalble

.lill CKY CV i t; 10 llV PUMP Rii RV rl: 11 TK

< Cavnation Conosion  ;

ContaminatuWhcdiment [

Conosinn I stigue Device Corrosum v(1) ((l) ((l) ((l) ((l) v(1) ((l) ((l) ((l) ((!) ((l) v(1) i Dynemic I onding ilectrical hirenors 1.roslon/Conotion ((2)

I aligue 1 oulmy f retting Galvanic Garrosum Ocneral Oirtosion (()) v(3) ((3) ((3) ((3) v(3) ((3) ((3)

Ilydrogen ibamage intergranular Attack MIC Particulate Wear 1.rosion Patting v(1) ((l) ((l) ((l) ((l) v(1) ((l) v(l) ((l) v(I) ((l) ((l)

Radiasm l>nmage kubbet ikgradeiam helme Water Attack helective Leaching ((4) v(4) ((4) hiress Unrnmion Cretking

)hermal Damage lhermal i mhrntlement Wear ((5) l MIC Microbiologically influenced Corrosion

/ indicates plausible ARDM determination for component (s) within the Device Type

(#)- indicates the group in which this ARDM is evaluated Note: Not every subgroup within the device types listed here may be susceptible to a given ARDM.

This situation occurs because subgroups within a device type are not always fabricated from the same materials or subjected to the same environment. Exceptions for each device type will be indicated in the materials and environment section for each ARDM discussed in this report.

Crevice corrosion and pitting are grouped together in this report because they both afTect the same device types, have similar effects, and are addressed by the same aging management programs.

The following discussions present information on plausible ARDMs. 'the discussions are grouped by ARDM and address the plausible ARDM, the device types afTected, the materials and environment pertinent to the ARDM, the methods to manage aging, aging mechanism efTects and the aging management program (s); There is then a summary of the aging management dernonstration.

Application for License Renewal 5.17 12 Calvert Cliffs Nuclear Power Plant

ATTACHMENT (1)

APPENDIX A TECHNICAL INFOltMATION 5.17. SERVICE WATER SYSTEM -

Group I (crevice corrosion / pitting) . Materials and Environment Table 5.17 3 shows that ti.s crevice corrosion and pitting ARDMs are plausible for all the SRW System ,

device types listed. Tha material characteristics for each device type that are pertinent to these ARDMs are listed below: [ Reference 1,1113 01, CK%01/02/03, C%01/02/03, FE 01, FO-01,11W01 to 11%08, i PUMP 01/02, RE 01, RV 01/02.TI 01/02,TK 01, Attachments 4,5,6)

• Piping carbon stect; ,

e Check valves carbon steel bodies; e Control valves some groups have carbon steel bodies, some have stainless steel or stellited shans and stainless steel discs, and some have cast iron bodies; e Flow elements stainless steel; e Flow orinces . stainless stect; e lland valves some groups have carbon steel, cast iron, cast brass and brass bodies; some have stainless steel stems or shans, and some have carbon steel or stainless steel discs; and some have stainless steel internals; e Pumps carbon steel or cast iron casings, and some have bronze bushings, cast iron or bronze impeller /shans, and iron seals; e Radiation elements stainless steel; e Relief valves some groups have carbon steel or stainless steel bodies;

• Temperature elements . stainless steel;

• Temperature indicators some groups are either carbon steel or stainless stect; and e Tanks - carbon steel.

The internal environment of the SRW System is chemically treated water at a normal service pressure of 102 psig (design rating 150 psig) and a normal operational temperature of 130'F (design rating of 300'F).

[ Reference 11] The SRW System includes a number of components (i.e., valves, instruments) that are Hange bolted, welded in place, or are gasketed. Within the SRW System there are regions of low or stagnant coolant now conditions.

Group 1 (crevice corrosion / pitting) . Aging Mechanism Effects Crevice corrosion is intense, localized corrosion within crevices or shielded areas. It is associated with a small volume of stagnant solution caused by holes, gasket surfaces, lap joints, crevices under bolt heads, surface deposits, designed crevices for attaching thermal sleeves to safe-ends, and integral weld backing rings or back up bars. The crevice must be wide enough to permit liquid entry and narrow enough to maintain stagnant conditions, typically a few thousandths of an inch or less. Crevice corrosion is closely related to pitting and can initiate pits in many cases. In an oxidizing environment, a crevice can set up a dilTerential aeration cell to concentrate an acid solution within the crevice. Even in a reducing environment, alternate wetting and drying can concentrate aggressive ionic species to cause pitting and crevice corrosion. Pitting is a form oflocalized attack with greater corrosion rates at some locations than at others. These pits are, in many cases, filled with oxide debris, especially in ferritic materials such as Application for License Renewal 5.17 13 Calvert Cliffs Nuclear Power Plant .

_ _ = - _ _ _ _ _ _ _ _ _ _ _ _ _

A'ITACllMI'NT (1)

APPENDIX A TECilNICAL INFORMATION 5.17 SERVICE WATER SYSTEM carbon steel. Deep pitting is more common with passive metals, such as austenitic stainless steels, than with non passive metals. In many cases, erosion corrosion, fretting corrosion, and crevice corrosion can also lead to pitting. It can also occur at locations of relatively stagnant coolant or water, such as in carbon steel piping of cooling systems. [ Reference 1 Pipe Attachment 7]

Long term exposure to environments conducive to these ARDMs may result in crevice corrosion / pitting which, if unmitigated, could eventually result in loss of material and pressure retaining capability under CLB design loading conditions. The components listed above are sometimes subject to stagnant now conditions, or have crevices associated with them. [ Reference 1, Attachments 6s] Therefore, crevice corrosion / pitting have been determined to be plausible ARDMs for which aging effects must be managed for the SRW System.

Group 1 (crevice corrosion / pitting) . Methods to Manage Aging Mitination: Maintaining an environment of purified water with controls on pil, oxygen, suspended solids and chlorides during normal plant operation can mitigate this ARDM. [ Reference 1, Pipe Attachment 6] The initial formation of a passive oxide layer (magnetite) on the interior surface also mitigates the effects of crevice corrosion / pitting by minimizing the exposure of bare metal to system Guids.

Disencry: Inspection of a representative sample of susceptible areas of the system for the signs of crevice corrosion / pitting could identify wheth.r this ARDM is actually occurring in the SRW System.

Maintenance / overhaul of SRW System components also provide opportunities to inspect for signs of crevice corrosion / pitting.

Group 1 (crevice corrosion / pitting) . Aging Management Program (s) hiitigation: Calvert Cliffs Chemistry Procedure (CP) CP 206, " Specifications and Surveillance for Component Cooling / Service Water Systems," provides for monitoring and maintaining SRW chemistry to control the concentrations of oxygen, chlorides, other chemicals and contaminants. The water is treated with hydrazine to minimire the amount of oxygen in the water, which aids in the prevention and control of most corrosive mechanisms. Continued maintenance of system water quality will ensure minimal piping or component degradation. [ Reference 1 Attachment 8]

CP 206 describes the surveillance and specifications for monitoring the SRW System Culd, CP-206 lists the parameters to monitor, the frequency ot~ monitoring these parameters, and the target and action levels for the SRW System Culd parameters. The parameters monitored by CP 206 are pli, hydrazine, chloride, dissolved oxygen, dissolved copper, dissolved iron, suspended solids, gamma activity, and tritium activity (Note: SRW is normally not a radioactive system), [ Reference 12, Attachment 1]

These chemistry parameters are currently monitored on a frequency ranging from three times per week to once a month. All of the parameters listed in CP 206 currently have target values that give an acceptable range or limit for the associated parameter. Two of the parameters, pil and hydrazine, have action levels associated with them. For pil the current action level is less than 9.0 or greater than 9.8, for hydrazine the current action level is less than 5 or greater than 25 pans per million (ppm). Refer to Attachment 1 in Application for License Renewal 5.17 14 Calvert Cliffs Nuclear Power Plant .

ATTACHMENT (1)

APPENDIX A TECHNICAL INFORMATION 5.17-SERVICE WATER SYSTEM CP 206 for the specific monitoring frequency and target values for each chemistry parameter.

[ Reference 12, Attachment 1)

Oneratino ihnerlengs Operational experience related to CP 206 has shown no problems related to use of this procedure with respect to the SRW System. In 1996, CP 206 was revised to include dissolved iron as a chemistry parameter. Dissolved iron was added to CP 206 to act as a method to discover any abnormal corrosion of the SRW components. j i

An internal BGE chemistry summar/ report for 1996 described the CCNPP Unit I and Unit 2 CC/SRW I Systems chemistry as excellent. ... lon levels for all four systems were only exceeded on eight occasions, or approximately 0.7% of the time during the year. Over 70% of the action levels entered were due to major system changes during the 1996 refueling outage. The report recommends  ;

determining outage evolutions that can affect the CC/SRW chemical parameters and taking appropriate action to prevent chemistry targets from being exceeded. j The SRW System usually operates within normal parameters except when the system is restarted aller an  !

outage lay up. During an outage lay up, the SRW System experiences some minor corrosion when the internal component surfaces are exposed to air. After the SHW System is returned to service and flow is once again established, some of this minor corrosion is removed from the pipe inner surface and released into the system where it is detected. It was discovered that suspended solids spike when one SRW header is taken out-of service for heat exchanger cleaning, and total system flow is then directed through the in service heat exchanger. One or two days after the SRW System is aligned to normal, the suspended solids levels drop to the normal value ofless than 10 parts per billion.

Calvert Cliffs procedure CP 206 provides for a prompt review of SRW chemistry parameters so that steps can be taken to return chemistry parameters to normal levels and thus minimize the effects of crevice corrosion / pitting.

Discoverv: The SRW pumps are inspected for crevice corrosion / pitting using the CCNPP PUMP 15,

" Service Water Pump Overhaul," procedure. PUMP 15 instructs the user to inspect certain pump components for crosion, wear, and mechanical damage. The procedure will be modified to include inspections for crevice corrosion / pitting on the pump casing and bushings. The procedure directs the user to contact the System Engineer if any of these indications.are found, and to replace parts as )

necessary. [ Reference 13] The PUMP 15 overhauls and inspections are performed as required based on pump performance trends or corrective actions requirements. [ Reference 1, Attachment 8]

He remaining SRW System components (including the SRW radiation monitoring pumps) susceptible to crevice corrosion / pitting will be included in the Aging Related Degradation Inspection (ARDI) Program to l verify that degradation of the components is not occurring. This program will examine representative components to determine if they will be capable of performing their intended function under all CLB design

- loading conditions during the period of extended operation. These examinations will be performed prior to the period of extended operation. [ Reference 1. Attachment 8] He ARDI Program is defined in the i

CCNPP IPA Methodology presented in Section 2.0 of this application.  :

i Application for License Renewal 5.17 15 Calvert Clifts Nuclear Power Plant

NrfACHMFNT f1) l APPENDIX A TECllNICAL INFORMATION [

5.17 SERVICE WATER SYSTEM The elements of the ARDI Program willinclude:

• Determination of the examination sample site based on plausible aging effects; I

e identlucation of inspection locations in the system / component based on plausible aging effects and consequences ofloss of component intended function;

• Determination of examination techniques (including acceptance criteria) that would be effective.

considering the aging effects for which the component is examined; ,

e Methods for interpretation of examination results; e Methods for resolution of adverse examination Dndings, including consideration of all design loadings required by the CLB and specincation of required corrective actions; and

• Evaluation of the need for follow up examinations to monitor the progression of any age related degradation.

Any corrective actions that are required will be taken in accordance with the CCNPP Corrective Action Program, and will ensure that the components will remain capable of performing their intended function ,

under all CLil conditions, Group 1 (crevice corronlon/ pitting)- 1)emonstration of Aging Management liased on the information presented above, the following conclusions can be reached with respect to the corrosion of the SRW System device types susceptible to crevice cormsion/ pitting:

• The SRW device types suaceptible to these ARDMs have an intended function of maintaining the  ;

system pressure boundary under CLD design conditions, e Crevice corrosion / pitting is plausible for the device types discussed in the material and environment section above, w hlch could lead to loss of pressure retaining boundary integrity.

• CP 206 will mitigate the efTects of crevice corrosion / pitting on SRW System device types by controlling the range of specific chemical additives and providing action levels that ensure timely correction of adverse chemistry parameters.

• The CCNPP ARDI Program will be utilized to discover any crevice corrosion / pitting that may be of concern for the SRW System components, inspections will be performed, and appropriate corrective action will be taken if crevice corrosion / pitting is discovered.

• The CCNPP Technical Procedure PUMP 15 w,ll be modined to inspect susceptible pump components for crevice corrosion / pitting and general corrosion, Any indications of these ARDMs will be reported to the System Engineer and corrective actions taken.

Therefore, there is reasonable assurance that the effects of crevice corrosion / pitting on SRW System device types will be managed in order to maintain their intended function under all design loadings required by the CLil during the period of extended operation.

Application for License Renewal 5.17 16 Calvert Cliffs Nuclear Power Plant

A1TACllSIENT I1) .

APPENDIX A TECilNICAL INFORMATION 5.17. SERVICE WATER SYSTEM Group 2 (erosion corrosion). Materials and Environment Table 5.17 3 shows that crosion corrosion is only plausible for the SRW System piping. The SRW l System piping is made from carbon steel that is fabricated into straight sections, bends, and tees. The internal environment of the SRW System is demineralized water treatad with hydrazine to lower the j dissolved oxygen level. [ Reference 1, Pipe Attachment 6J. The internal environment of the SRW  ;

System is chemically treated water at a nonnal service pressure of 102 psig (design rating 150 psig) and a normal operational temperature of 130'F (design rating of 300'F). [ Reference 11]

Group 2 (erosion corrosion) Aging Mechanism Effects Carb(m steel piping bends, tees, and areas with disturbances in the Dowstream are especially vulnerable to crosion corrosion, lhe SRW System is treated with hydrazine which scavenges the dissolved oxygen and minimites the effects of general corrosion, however, the lower oxygen content increases the susceptibility of the piping to the effects of crosion corrosion. The expected effect of crosion corrosion is a general thinning of the material in areas of higher turbulence due to removal of the protective magnetite coating. [ Reference 1, Pipe Attachment 6]

1he occurrence of erosion corrosion is h8ghly dependent upon material of construction and the Huld now conditions. Carbon or low alloy steels are particularly susceptible when in contact with high velocity water (single or two phase) with disturbances in the Howstream, low oxygen levels, and a Duld pil < 9.3.

Maximum crosion corrosion rates are expected in carbon steel at 130140*C (single phase) and 180*C (two-phase). [ Reference 1. Pipe Attachment 7]

long. term exposure to cro:lon corrosion could lead to material loss and, if unmanaged, could eventually result in loss of the pressure retaining capability under CLB design loading conditions. Therefore, crosion corrosion has been dictennined to be a plausible ARDM for which aging effects must be managed for the SRW System.  ;

Group 2 (crosion corrosion). Methods to Manage Aging Mitigation: The effects of crosion corrosion can be mitigated by selecting resistant materials and/or maintaining optimal Duid chemistry conditions. The low Dow velocity in the SRW System minimlics its susceptibility to crosion corrosion.

Dhtnery: Erosion corrosion can be discovered and monitored by nondestructive examination of potentially afTected areas, inspection of a represen'.ative sample of susceptible areas of the system for the signs of erosion corrosion could identify whether this ARDM is a concern in the SRW System piping.

Application for License Renewal 5.17 17 Calvert Clifts Nuclear Power Plant er-- y+

NITACllMENT (1)

APPENDIX A TECilNICAL INFORMATION 5.17-SERYlCE WATER SYSTEM Group 2 (erosion corrosion) . Aging Management Program (s)

Mitigntion: 'there are no programs credited with mitigating the effects of erosion corrosion on the SRW System piping.

Dhcomy: 'lhe SRW System piping will be included in an ARDI Program to verify that degradation of the piping is not occurring. 'this program will examine representative piping to determine ifit will be capable of perfonr"..g its intended function under all CLB design loading conditions during the period of extended operation. ~1na examinations will be performed prior to the period of extended or ration. For further discussion of the elements of the ARDI Program, see the Group I (crevice corrosion / pitting) discussion for Aging Management Programs under the Discovery section. [ Reference 1, Attachment 8]

To ensure tFat the non safety related Turbine llullding SRW piping maintains its seismic adequacy, SRW ARDI results (which will be based on safety related pressure boundary component inspections)  !

will be evaluated for applicability to the non safety related SRW piping. The non safety related SRW l piping in the Turbine Building and safety related piping in the Auxiliary and Containment Huildings were both originally designed to USAS B31.1 (1969 Edition through summer 1972 Agenda) and both are  !

subject to the same environmental service conditions and chemistry controls. The applicability evaluation will also consider, at a minimum, flow rate and configuration differences between safety-related and non safety related SRW piping. These ARDI results will then be able to provide an j indication of this ARDM's significance on non safety related SRW piping ir the Turbine Building.

Applying the ARDI results of the safety related portion of the system to the non safety related portion of the system will ensure compliance with the CLB during the period of extended operation. (Reference 1, Appendix B)

Inspection of some pipe locations found a tightly adhering layer of magnetite on the inside of the SRW piping. Evidence of erosion corrosion was not found during these system lay up examinations. The evidence of tightly adhering magnetite indicates that the piping has good corrosion resistant characteristics. To date, there have been no indications of significant crosion corrosion in the SRW System.

Group 2 (erosion corrosion)- Demonstration of Aging Management liased on the information presented above, the following conclusions can be reached with respect to the SRW System piping and crosion corrosion:

• The SRW System piping provides a pressure retaining boundary; therefore, its integrity must be maintained under CLB design ecnditions.

• Erosion corrosion is expected to be minimal but is considered plausible for the SRW System piping. This mechanism could result in the loss of piping material and lead to the loss of the pressure retaining boundary.

• The ARDI piping program will provide for discovery of significant erosion corrosion in piping, inspections of representative piping will be performed, and appropriate corrective action will be taken if crosion corrosion is discovered.

{

Application for License Renewal 5.17 18 Calvert Cliffs Nuclear Power Plant

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9 AHACitMENT (1)

APPENDIX A - TECilNICAL INFORMATION 5.17 SERVICE WATER SYSTEM Derefore, there is reasonable assurance that the effects of erosion corrosion of SRW piping will be managed in order to maintain the SRW System piping pressure boundary integrity consistent with the CLil during the period of extended operation.

Group 3 (general corrosion)- Materials and Environment Table 5.17 3 shows that general corrosion is plausible for eight of the SRW device types. The SRW -

System device types susceptible to general corrosion and their material charseteristics are listed below:

[ Reference 1.111101, CKV-01/02/03, CV 01/02/03/04, llV 01 to ilV 07, PUMP 01/02, RV 01/02, TI-01,TK 01. Attachments 4,5,6)

• Piping carbon steel;

• Check valves - caibon steel bodies and discs; e Control valves some groups have carbon steel cr cast iron bodies; e lland valves some groups have carbon steel bodies or cast iron bodies; sorne have carbon steel or Ni Resist discs;

• Pump - cast iron or carbon steel casings, and some have cast iron in peller/ shafts, and iron seals; Relief valve some groups have carbon steel bodies; e

• Temperature indicator some groups are carbon stect; and

• Tank carbon steel.

He internal environment of the SRW System is chemically treated water at a normal service pressure of 102 psig (design rating 150 psig) and a normal operational temperature of 130'F (design rating of 300*F).

[ Reference 11] ne external environment is ambient atmospheric air inside the containment and Auxiliary Buildings, which is climate controlled. The environment of the Containment flullding duri,ng normal operations has a maximum 70% relative humidity and maximum temperature of 120 F.

[ Reference 14, Attachment 1, Table 1 page 13 of 14] During normal operation the Auxiliary

• Building ambient air maximum relative humidity is 70% with a maximum temperature of 160 F (Main Steam Penetration Room). [ Reference 14, Attachment 1, Table 1, page 5 of 14] The temperature and humidity in the Auxiliary Ilullding will vary slightly according to specific local conditions.

The internal environment for the SRW air operated control valves is normally compressed air supplied by the instrument air compressors. The instrument air is very dry, filtered, and oil free air. Particle size, dewpoint, and oil hydrocarbons are controlled for the instrument air supply in accordance with

[ Instrument Society of America] ISA S7.3 [ Reference 3, Section 9.10.2]

The Instrument Air System is maintained in accordance with industry standards for moisture (dewpoint) and particulate concentrations. Ilowever, the possibility of occasional exposure to moisture exists from operation of the SW air compressors (no dryer) or cross tic with the Plant Air System (minimal drying capability). %c exposure to moisture for compressed air systems is minimal and short term, and is not expected to result in significant levels of degradation of the SRW carbon steel components.

[ Reference 1, Attachment 8]

Application for License Renewal 5.17 19 Calvert Cliffs Nuclear Power Plant -

I MIACilMENT m APPENDIX A TECliNICAL INFORMATION 5.17-SERYlCE WATER SYSTEM Group 3 (general corrosion)- Aging Mechnaism Effects Carbon steel is susceptible to general corrosion in water containing oxygen. General corrosion is the >

thinning (wastage) of a metal by chemical attack (dissolution) at the surface of the metal by an aggressive environment. The consequences of the damage are loss ofload carrying cross sectional area.

[ Reference 1, Attachment 6s] The ARDM is plausible for the device types listed above.

tamg term exposure of carbon steel to untreated water may result in general corrosion / area material loss and, if unmanaged, could eventually result in loss of the pressure retaining capability under CLB design loading conditions. Herefore, general corrosion has been determined to be a plausible ARDM for which aging effects must be managed for the SRW System.

General corrosion is also plausible for the SRW System air operated control valves because the carbon 4

steel is exposed to slightly moist air. The expected effects would be superficial rust speckles and a slight dusting ofloose psisive surface rust. [ Reference 1, CV 04, Attachment 6]

Group 3 (general corrosion) . Methods to Manage Aging Mitigation: The efTects oigeneral corrosion can be mitigated with a chemistry control program. Such a program includes monitoring of system chemistry on a frequency capable of detecting abnormal conditions in a timely fashion. Thus, corrective actions may be taken prior to reaching conditions conducive to corrosion.

Maintenance and verification of instrument Air System air quality to industry standards will ensure minimal degradation ofinternal surfaces of air operators. [ Reference 1. Attachment 8]

Discoverv: Inspecting a representative sample of susceptible areas of the SRW System for the signs of general corrosion prior to the period of extended operation can determine whether this ARDM is degrading the intended function of the SRW System components. Maintenance / overhaul of SRW System components also provide opportunities to inspect for signs of general corrosion.

Group 3 (general corrosion) Aging Management Program (s)

Mitigation: Calvert Cliffs procedure CP 206 provides for monitorin6 of the SRW chemistry to control the concentrations of oxygen, chlorides, other chemicals, and contaminants. The water is treated with hydrazine to minimize the amount of oxygen, which aids in minimizing most corrosive mechanisms.

Continued maintenance of system water quality will ensure minimal interlot piping or component degradation. [ Reference 1, Attachment 8]

The CCNPP Preventive Maintenance Checklists IPM10000," Check Unit I instrument Air Quality," and IPM10001," Check Unit 2 Instrument Air Quality," provide verification of air dryer effectiveness. The purpose of these activities is to ensure that the moisture content of the Instrument Air System is as low as possible to mitigate the effects of general corrosion on air operated valves. Preventive Maintenance Tasks that execute these checklists are automatically scheduled and implemented in accordance with safety related Preventive Maintenance Program procedures. These tasks periodically check the Instrument Air System air quality at low points in the system. Measurements of dewpoint and particulate Application for License Renewal 5.17 20 Calvert Cliffs Nuclear Power IE

ATTACllMENT (1)

APPENDIX A TECilNICAL INFORh1ATION &

$.17-SERVICE WATER SYSTEh!

count are taken at three loce.tlons per unit. According to procedure, dewpoint data and particulate sample results are provided to the System Engineer. [ References 15,16,17]

Discoverv: The occurrenet of general corrosion is expected to be limited and is not likely to affect the intended function of the system components. The ARDI Program is intended to provide the additional assurance needed to conclude that the effects of plausible aging are being effectively managed for the period of extended operation. The ARDI Program will focus on the effects of plausible ARDMs and the affected components. The results from implementation of the ARDI Program are to be used to determine actions required to ensure that the ufrected components continue to suppon the identified passive intended functions throughout the period of extended operation. [ Reference 1 Attachment 8] For further details of the ARDI Program, refer to the discussion under Group 1 (crevice corrosion / pitting)-

Aging Management Programs.

The SRW pumps are inspected for general corrosion using the CCNPP PUMP 15 procedure. PUMP 15 instructs the user to inspect certain pump components for erosion, wear, and mechanical damage. The procedure will be modified to include inspections for general corrosion on the pump casing. The procedure directs the user to contact tue System Engineer if any of these indicatloa.s are found, and to replace parts as necessary. [ Reference 13] The PUMP 15 overhauls and inspections are performed as required based on pump performatice trends or corrective actions requirements. [ Reference 1 Attachment 8]

Group 3 (general corrosion) . Demonstration of Aging hianagement flased on the informatica presented above, the following conclusions can be reached with respect to the general corrosion of SRW System equipment:

• 1hc SRW System device types subject to this ARDM provide a pressure retaining boundary ftmetion so their integrity must be maintained under CLB design loading conditions.

e General corrosion is plausible for some of the SRW System device types, if not managed, this ARDM could lead to material loss and impaired capability of the components to perform their passive intended function of retaining the SRW preasure boundary, e Calvert Cliffs procedure CP 206 is a program that will mitigate the efTects of general corrosion on SRW System device types by controlling chemistry and provides action levels for critical chemistry parameters.

• 1he CCNPP Technical Proccu.x PUMP-15 will be modified to inspect susceptible pump components for crevice corrosion / pitting and general corrosion. Any indications of these ARDMs will be reported to the System Enginect and corrective actions will be taken.

e The CCNPP Preventive Maintenance Checklists IMP 10000 and IPM10001 provide for periodic maintenance and verification of air dryer effectiveness to ensure that general corrosion does not degrade the SRW air-operated control valves' ability to perform their intended function.

• A new CCNPP ARDI Program will be utilized to discover general coirosion that may be of concern for the SRW System. Inspections will be performed, and appropriate corrective action will be taken if general corrosion is discovered.

Application for License Renewal 5.17 21 Calvert Cliffs Nuclear Power Plant

ATTAC11MFNT (1) l APPENDIX A . TECHNICAL INFORMATION 5.17 SERVICE WATER SYSTEM Therefore, there is reasonable assurance that the effects of general corrosion will be managed it, order to maintain the SRW System components' pre.suie boundary integrity consistent with the CLil during the period of extended operation.

Group 4 (selective leaching) . Materials and Environment Table 5.17 3 shows that selective leaching is plausible for the SRW device types listed. The SRW l System device types susceptible to selective kaching and their material characteristics are listed below:

[ Reference 1, Attachment 1, and CV02, ilV04/05/06/07/08, and PUMP-02, Attachments 4,5,6) e Control valves those with cast iron bodies; e lland valves those with cast iron bodies / bonnets and discs, or brass bodies, or cast brass bases and shells; and e Pumps - those groups with cast iron casings.

1he internal environment of the SRW System is chemically treated water at a normal service pressure of 102 psig (design rating 150 psig) and a normal operational temperature of 130*F (design rating of 300'F).

[ Reference 11] This SRW water is treated with hydrazine to lower the dissolved oxygen level.

[ Reference 1, Pipe-Attachment 6] Certain regic.ns of the SRW System have low or stagnant flow conditions.

Group 4 (seleelive teaching). Aging MEhanism Effects Selective leaching is the removal of one element from a solid alloy by corrosion processes. The most common example is the selective removal of zine in brass alloys (dezincification). Similar processes occur in other alloy systems in which aluminum, iron, cobalt, chromium, and other elements are removed. There are two types of selectwe leaching, layer type, and plug type. Layer-type is a uniform attack, whereas plug type is extremely localized leading to pitting. Overall dimensions do not change appreciably. Selective leaching requires susceptible materials and a corrosive environment. Conducive environmental conditions include high temperature, stagnant aqueous solution, and porous inorganic scale. Acidic solutions and oxygen may aggravate the mechanism. [ Reference 1, Valve Attachment 7]

The device types discussed in the materials and environmental section above are susceptible to the ARDM (for lined valve bodies, the liner is not credited with aging management; it is conservatively assumed that the material is in contact with the fluid due to degradation of the rubber liner). lhe device types are exposed to flow conditions and may be exposed to stagnant conditions. The expected effect of selective leaching is cracking. [ Reference 1, CV Attachment 6, SV Attachment 6]

Some cast irons are susceptible to a selective leaching process called " graphitic corrosion." The iron or steel matrix leaches from the material leaving a porous mass consisting of a graphite network, voids, and rust. The cast iron loses strength and its metallic properties. [ Reference 18, Valve Attachment 7]

Long term exposure to a conducive environment may result in selective leaching and, if unmanaged, could eventually result in loss of the pressure-retaining capability under CLB dcsign loading conditions.

Therefore, selective leaching has been determined to te a plausible ARDM for which aging effects must be managed for the SRW System.

Application for License Renewal 5.17 22 - Calvert Cliffs Nuclear Power Plant

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CritMENT n)

APPENDIX A TECilNICAL INFORMATION  :

5.17. SERVICE WATER SYSTEM 1

Group 4 (selective leaching). Methods to Manage Aging Mitigation: Maintaining a SRW System environmmt of purified water with controls on pit, suspended solids, and chlorides during normal plant operation can mitigate this ARDM. The addition of hydrazine to lower the SRW System dissolved oxygen level assists in the mitigation of this mechanism.

[ Reference 1, Attachments 6,8]

Discoverv: Inclusion of SRW System device types in an inspection program that examines a representative sample of susceptible areas of the system for the signs of selective leaching prior to the period of extended operation could identify whether this ARDM is of concem for the SRW device types.

Group 4 (selective lenching)- Aging Management Program (s)

Mitigation: CP 206 provides for monitoring of the SRW chemistry to control the concentrations of oxygen, chlorides, other chemicals, and contaminants. The water is treated with hydrazine to minimize the amount of oxygen in the water, which aids in the prevention and control of most corrosive mechanistns. Continued maintenance of system water quality will ensure minimal component degradation. [ Reference 1, Attachment 8] Refer to the discussion of CP 206 under Group 1 (crevice corrosion / pitting), Aging Management Programs.

Disconry: The SRW System device types listed here will be included in the ARDI Program to verify that degradation of SRW device types due to selective teaching is not excessive. Refer to the ARDI discussion under Group 1 (crevice corrosion / pitting), Aging Management Programs for more details on this program.

(Reference 1. Attachment 8]

Group 4 (selective leaching). Demonstration of Aging Management liased on the information presented above, the following conclusions can be react.ed with respect to selective leaching for the SRW device types listed here:

. The control valves, hand valves, and pumps described here act as a pressure-retaining boundary, and their integrity must be maintained under CLB design conditions.

• Selective leaching is plausible for the valve and pump device types discussed in the Materials and Environmental section above, which could lead to the loss of the pressure retaining boundary function of the SRW System.

• Calvert Clifts CP 206 is a program that mitigates the effects of selective teaching on SRW System device types by controlling chemistry, and provides action levels for critical chemistry parameters.

• The CCNPP ARDI Program will be utilized to discover selective teaching that may be of concern for the SRW System components. Inspections will be performed, and appropriate corrective action will be taken if selective leaching is discovered.

Therefore, there is a reasonable assurance that the effects of selective leaching will be managed in order to maintain the components' intended function under all design loadings required by the CLB during the period of extended operation.

Application for License Renewal 5.17 23 Calvert Clifts Nuclear Power Plant

l ATTACilMENT f1)

+  ;

APPENDIX A TECHFICAL INFORMATION 5.17. SERVICE WATER SYSTEM i

Group 5 (wear) . Materials med Environment Table 5.17 3 shows that wear h plausible for relief valves in the SRW System. The valve bodies are ,

either fabricated from stainless snel or carbon steel and have stainless seats and discs. Ilowever, it is only the stainless steel discs and valve seats that are susceptible to wear. [ Reference 1. Attachment 1 .

and RV01/02, Attachments 4,5,6)

'ihe internal environment of the SRW System is chemically treated water at a norrnal service pressure of 102 psig (design rating 150 psig) and a normal operational temperature of 130'F (design rating of 300'F).

[ Reference 11] During normal plant operation, relief valves are usually closed. Some v4. s may remain in the closed position for an extended period of time beforc being actuated.

Group 5 (wear) . Aging Mechanism Effects Wear results from relative motion between two surfaces (adhesive wear), from the in0uence of hard, abrasive particles (abrasive wear), or sliding mations under the in0uence of a corrosive environment (fretting). In addition to material loss from the above wear mechanisms, impeded relative motion between two surfaces held in intimate contact for extended periods may result in galling /self welding.

Motions may be linear, circular, or vibratory in inert or corrosive environments. The most common result of wear is damage to one or both surfaces involved in the contact. Wear most typically occurs in components that experience considerable relative motion, such as valves and pumps, in components that are held under high loads with no motion for lonu periods (e.g., valves, Danges), or in clamped joints where relative motion is not intended but occurs due to a loss of clamping force (e.g., tubes in supports, i valve stems in seats, springs against tubes). Wear ratet increase as worn surfaces experience higher contact stresses than the surfaces of the original geometry. [ Reference 1, Valve, Attachment 7]

Valve discs may periodically relieve pressure and experience movement against the seat. The expected elTect of wear is a progree.sive loss of material on the subcomponent. The SRW device types are ,

therefore susceptible to this ARDM. [ Reference 1, RV, Attachment 6] The subcomponents of the device types are not located in the SRW Auld now stream. Movement of the subcomponent is expected to occur infrequently.

Group 5 (wear) . Methods to Manage Aging hiitigation: There are no reasonable methods of mitigating wear of the relief valves seating surfaces during their infrequent operation. Relief valves that infrequently operate can be periodically bench tested to verify the valve is not leaking or sticking.

Dhcawy: Wear can be discovered by inspecting and testing the valve device types that are susceptible to this ARDM. Routine bench testing and inspection can identify wear and sticking of the relief valve seating surfaces.

~

Application for Licente Renewal 5.17 24 Calvert Cliffs Nuclear Power Plant

NITACllMENT (1) f APPENDIX A TECilNICAL INFORMATION 5.17 SERVICE WATER SYSTEM i

Group 5 (wear). Aging Management Program (s)

Mhiption: Since wear cannot be avoided during plant operation, there are no programs credited with mitigating wear due to relativt motion between two surfaces, llowever, the program mentioned below in the discovery section can mitigate the effects of galling /self welding (sticking) by periodically bench testing (actuating) the relief valves.

Dhcorcry: The CCNPP Mechanical Preventative Maintenance (MPM) Checklists MPM01013, MPM0ll47, MPM0ll53, and MPM0ll55,

• Relief Valves," direct the removal, testing, and reinstallation of the satisfactorily tested relief valves. The checklists refer to another procedure for the performance and acceptance of the relief valve setpoint tests. Thess preventive maintenance checklists are performed at a four. to five year interval. [ References 19,20,21,22] Routine bench testing and inspection will identify wear of the relief valve seating surfaces. [ Reference 1, Attachment 8]

Group 5 (wear) . Demonstration of Aging Management linsed on the Information presented above, it can be concluded that:

• The SRW relief valves described here act as a pressure retaining boundary, and their integrity must be maintained under CLil design conditions, e Wear is plausible for the relief valves discussed in the materials and environment section above, which could lead to the loss of the pressure retaining boundary function of the SRW System.

• The CCNPP MPM01013, MPM0ll47, MPM0ll53, and MPM0ll55 Checklists direct the removal, relief setpoint testing, and reinstallation of SRW relief valves. Routine bench testing and inspection will identify wear of the relief valve seating surfaces.

1herefore, there is a reasonable assurance that the effects of wear will be managed in order to maintain the SRW relief valves intended function under all design loadings required by the CLl! during the period of extended operation.

5.17.3 Conclusion 1he aging management programs discussed for the SRW System are listed in Table 5.17 4. These programs are administratively controlled by a formal review and approval process. As demomtrated above, these prograrns will manage the aging mechanisms and their effects such that the intended functions of the SRW System components will be maintained during the period of extended operation consistent with the CLil unO all design loading conditions.

The analysis / assessment, corrective action, and confirmation / documentation process for license renewal is in accordance with Qt<2, " Corrective Actions Program." QL 2 is pursuant to 10 CFR Part 50, Appendi' 11, and covers all structures and components subject to AMR.

. Application for License Renewal 5.17 25 Calvert Cliffs Nuclear Power Plant

h AITACilMENT.8) (

APPENDlX A - TECHNICAL INFORMATION 5.17. SERVICE WATER SYSTEM TABLE 5.17-4  :

IlET OF AGING MANAGQiENT PROGRAMSE))LillE EFMVICE WATru SYSTEM ].

Program Credit 9d For  !

lixisting Specifications and Surveillance for Mitigating the effects of crevice corroslorvpitting CC/SRW Systems, CCNPP (Group i), general corrosion (Group 3), and selective CP 206 leaching (Group 4) of SRW System components by l monito ing and controllhg the SRW chemistry.

!!xisting Periodic maintenance and Mitigation of general corrosion (Group 3) of the verification of dryer effectiveness: SRW air operated valves. The exposure to moisture  !

IPM10000," Check Unit I la minimal :md short term, and is not expected to instrument Air Quality," and result in significant levels of degradation of the  !

IPM10001," Check Unit 2 carbon steel compoi.ents.

Instrument Air Quality" i lixisting Checklists for SRW Relief Valves; Discovery of wear (Group 5) of the SRW System '

MPM01013, MPM0ll47, relief valves. They r.tc performed on a four. to MPM0ll53, and MPM0ll55 five year interval to remove and test SRW System i relief valves.

Modified SRW Pump Overhaul, CCNPP Will be modified for the discovery of crevice PUMP.15 corrosion /phting (Group 1) and general corrosion (Group 3) of the SRW pumps through inspection and overhaul. These activities are perfonned as required .

based on pump performance trends or corrective action requirements.

~

New ARDI Program Discovery of crevice corrosiordpitting (Group I),

crosion corrosion (Group 2), general corrosion (Group 3), and selective teaching (Group 4). The results from implementation of the ARDI Program

. are to be used to determine actions required to ensure that the affected components continue to suppoit the identified passive intended functions throughout the period of extended operation.

N

. Application for License Renewal 5.17 26 Calvert Clifts Nuclear Power Plant

, r.. . _. . _ , . _ . _ . . . _ _ . _ . . . ~. __ _ _-______..._.--__u.__ - __

A1T. AC11 MIXT _u)

APPENDIX A . TECilNICAL INFORMATION 5.17.SF.RYlCE WATER SYSTEM i 5.17,4 Referencee  !

l- "Senice Water System Aging Manageenent Review," Revision 1,0ctober 18,1996 l

2. CCNPP

• Fire Protection Aging Management Review," Revision 1, January 29,1997

3. Calvert Cliffs Nuclear Po,ser Plant, Updated final Safety An:. lysis Report, Revision 20 l

4. Letter from Mr. R. E. Denton to NRC Documes,t Control Clerk, dated December 14, 1990, LER 89 023. Revision 2," Postulated Rupture in Non Safety Related Service Water Subsystem (SRW) Could Cause Failure ofIloth Safety Related Subsystems"

5. CCNPP " Evaluation of tsolation Provisions for SRW System," July 7,1993

6. Letter from Mr. L. T, DoerDein (NRC) to Mr, R. E. Denten (!!GE), dated October 16, 1995, "NRC Region I inspection Report Nos. 50 317/95 08 and $0 318/95 08"

7. CCNPP System Level Scoping Results (SLSR), Revision 4 April 6,1995

8. Letter from Mr. L 11. Russell (110E) to Mr.11. II. Grier (NRC), dated June 3,1980, Licensee Event Report 80 27/IT.Two week Follow up Report for LER 80 27/IT

9. Letter from Mr. C. J. Cowgill(NRC) to Mr. R. E. Denton f DGE), dated March 31,1995, NRC

• Region i Integrated inspection Report Nos. $0 317/95 01 and $0 318/95 01 (January 1,1995 -  :

February 21,1995)"

l

10. CCNPP Technical Procedure Component Level ITLR Screening Results SRW System, Revision 1, August 8,1996

11. CCNPP Drawing 92769S11110 3,"M 601 Piping Class Summary," Revision 28

12. CCNPP CP 206,"SpeelDeations and Surveillance Component Cooling / Service Water System,"

Revision 3, November 4,1996

13. CCNPP Technical Procedure PUMP l$,"SRW Pump overhaul," Revision 1, February 4,1997

14. Engineering Standard ES 014, " Summary of Ambient Environmental Service Conditions,"

Revision 0, November 8,1993

15. CCNPP IPM10000," Check Unit 1 instrument Air Quality," Revision 0, September 10,1991

16. CCNPP IPM10000," Check Unit 2 Instrument Air Quality," Revision 0. September 10,1991

17. CCNPP Repetitive Task 10191024. " Check Unit 1 instrument Air Quality at Selected System Lowpoints"

18. CCNPP " Component Cooling System Aging Management Review," Revision 1, November 7,1996

19. CCNPP MPM01013 Checklist Sheet," Remove Relief Valve, Test and Reinstall," Revision 0, Januuy 28,1992 20, CCNPP MPM0ll47 Checklist Sheet," Remove Relief Valve, Test and Reinstall," Revision 0, December 24,1991

21. CCNPP MPM0ll53 Checklist Sheet," Remove Relief Valve, Test and Reinstall," Revision 0, December 24,1991

22. CCNPP MPM0ll47 Checklist Sheet,

• Remove Relief Valve, Test and Reinstall," Revision 0, December 24,1991 ,

Ipplication for License Renewal 5.17 27 Cah ert Clifts Nuclear Power Plant

t i

t NITACIIMENT (2) i i

, APPENDIX A - TECilNICAL INFORMATION

, 5.18 - SPENT FUEL POOL COOLING SYSTEM J

h i

Haltimore Gas and Electric Company Calvert Cliffs Nuclear Power Plant August 21,1997

AIIAC)1 MENT (2)

APPMDIX A TECilNICAL INFORMATION  ;

5.18 SPENT FUEL POOL COOLING SYSTEM 5.1N Spent Fuel Pool Coollag System l This is a section of the llaltimore Oas and Electric Company (110E) License Renewal Application (LRA), addresting the Spent Fuel Pool Cooling System (SFPCS). The SFPCS was evaluated in ,

accordance with the Calvert Cliffs Nuclear Power Plant (CCNPP) Integrated Plant Assessment (IPA) '

Methodology de:;ribed in Section 2.0 of the llGE LRA.1hese sections are prepared independently and will, collectively, comprise the entire DGE LRA.

5.18.1 Scoping System level scoping describes conceptual boundaries for plant systems and structures, develops screening tools which capture the 10 CFR $4.4(a) scoping criteria, and then applies the tools to identify systems and structures within 'he scope of license renewal. Component lesel scoping describes the colaponents within the boundaries of those systems and structures that contribute to the intended fimetions. Scoping to determine components subject to aging management review (AMR) begins with a listing of passive intended funcilons and then dispositions the component types as either only associated with active functiuns, subject to replacement, o/ subject to AMR either in this report or another report.

Representative historical operating experience pertinent to aging is included in appropriate areas to provide insight supporting the aging management demon 4 rations. This operating experience was obtained through key word searches of BGE's electronic database ofinformation on the CCNPP dockets and through documented discussions with currently assigned cognizant CCNPP personnel.

Section 5.18.1.1 presents the results of the system level scoping,5.18.1.2 the results of the component level scoping, and $.18.1.3 the results of scoping to determine componeuts subject to an AMR.

5.18.1,1 System Level Ecoping

'this section begins with a description of the sysiem which includes the boundaries of the s3 stem as it was noped. The intended functions of the system are listed and are used to define what portions of the system are within the scope oflicense renewal.

Snicm.Dsstription/Centcytual Iloundaries The SFPCS consists of two Salf capacity pumps and two half caracity heat exchangers in parallel, a bypass P'ter which removes insoluble particulates, a bypass demmeralier which removes soluble ions, and various piping, valves, and instrui..entation. [ Reference 1 Section 9.4.2] The spent fuel pool (SFP) itself, which is covered in Section 3.3 (Structures) of the BGE LR A, is located in the Auxiliary Building.

It is divided into two identical halves, each serving one reactor unit. Both new fuel and spent fuel may be stored in the pool. [ Reference 1. Section 1.2.9.4)

Tit 'uct racks in both halves of the SFP have been replaccJ to increase tne storage density. It has been shown by analysis that the SFPCS has sufficient capacity to support the increased heat loads. These changes have therefore not affected the SFPCS. [ Reference 2)

Following several instances of cracking of SFPCS piping, a detailed study was performed (in early 1990)

'o determine the root cause and appropriate remedy, Reference 3 presents the conclusions of the study, and the resulting recommendations. It was determined that the cracking was due to high cycle fatigue Splication for License Renewal $.18 1 Calvert Cliffs Nuclear Power Plant

ATTACllMENT (D APPENDIX A TECHNICAL INFORMATION 5.18. SPENT FUEL POOL COOL.IG SYSTEM caused by cavitation induced vibretion inherent in the original design of the system. Certain orinces and valves were modified to eliminate system cavitation. Implunentation of these improvements has prevented recurrence of cracking in SFPCS piping. Since normal service loads do not result in significant vibration or other dynamic loading conditions, fatigue is not plausible for SFPCS.

[ Reference 4 Attawhment 6s for Pipe) 1he primary functions of the SFPCS are:

+ to remove decay heat from the spent fuel stored in the SFP; [ Reference 4, Section 1.1.1) to provide cooling for the refueling pools; [ Reference 4, Section 1.1.1)

• to maintain clarity and low activity levels in the SFP, in the refueling pools, and in the refueling water tanks; [ Reference 4 Section 1.1.1)

• to transfer water to and from the refueling water tanks. [ Reference 4, Sectio i 1.1.1)

The SFPCS is composed of the following general categories of equipment and devices: [ Reference 4, Section 1.1.2)

Piping To convey fuel pool water to the heat exchangers and filters and back to the appropriate pool; also, to transfer water to and from the refueling water tanks; Valves Check, hand, and relief valves, which provide containment isolation, system aligninent/ isolation and over. pressure protection; instruments Measure now rates, pressure and temperatures; provide indication and alarm; Filter / Strainer Remove entrained solids and fine particulate matter; Demineralizer Remove dissolved chemical and radioactive impurities; Pumps Pump water through the system; and llent !!xchangers Transfer fuel decay heat from the system water to the Service Water (SRW)

System.

Figure 5.18 l is a simplined diagram of the SFpCS This figure shows the portions of the SFPCS addressed in this section of the 110E LRA and the primary process flow systems' interfaces.

[ Reference 5)

Application for License Renewal 5.18 2 Calvert Cliffs Nuclear Power Plant

ATTACHMENT (2)

APPENDLX A - TECHNICAL INFORMATION 5.18-SPENT FUEL POOL COOLING SYSIDI t,

ccm u eur  :. Amum am.ws r r s

& Da,a4c, ll . . . , u L

i va!ve l, - a m i',

p / -1 r s. - 1 r-4% varve

- _ :j

%  % 16u,aT2 rem POOL (seem) y; wye f, SPENT FUEL POOL Stracer  ;- , .; (WSLR - refer to Section 3.3) 7 ,

'~

,l to 1787 2 REFUEUNG

- , a.

WATER TANK (sameer)

UNIT 1 REFUELING POCL ll REFUELING -'m -

4

'l, (WSLR - refer to Section 3.3) t1

, nr WhTER TANK 4 From

/ N m m (WSLR - refer to DEMINERAI17FD

/ }

3

} '

Sechon 5.15) *'

a 6 ' VATER &

CONDENSATE From SHUTDOWN COOLING HEAT EXCHANG,ERS l STORAGE (WSLR - refer to Sector. 5.6) == '

a L To SOLID WASTE DISPOSAL

/ SYSTEM M *To LOW PRESSURE SAFETY INJECTION PUMPS SYSTEM (not WSLR) *-

- (not WSLR)

(WSLR - refer to Sectxrt 5.15) ,

~

1 r 5 E u From/To r  !

8 0 *

~ SERVICE WATER SYSTEM L C DEMINERALIZER

- --

• WSLR( - refer to Sect.an 5.17)

SPENT FUEL POOL E E

Q Q-SPENT FUEL POOL FILTER COOLING PUMPS E E m-mm Mh 1r - f SPENT FUEL P -8"*'

V+ '?d.s POOL COOLERS L .2 -

, 7 BOLD UNES indcate m.,@,o a l C Fm UN!T 2 SHUTDOWN COOLNG HEAT EXCHANGER (seder) that are WSLR for Spent Fuel '

Fm UNIT 2 REFUEUNG POOL (seder) FIGtJRE 5.18-1 Pool Cooring System.

' To UNrT 2 LOW PRESSURE

' SAFETY PUECTON PUnePS (scwor) SPENT FUEL POOL COOUNG SYSTEM dotted UNES indcate w.w.= e (SIMPUFIED DIAGRAM - FOR INFORMATION OF'LY) that are part ofiamM9 systems Application for License Renewal 5.18-3 Calvert ClitTs Nuclear Pouc Plant

ATTACHMrNT (2)

APPENDIX A - TECHNICAL INFORMATION 5.18. SPENT FUEL POOL COOLING SYSTEM Mm Interfaces lhe SFPCS primary process flow interfaces with the following systems and components: [ Reference $)

• SRW System (cooling water supply);

. - Safety injection System (Refueling Water Tanks, Low Pressure Safety injection Pumps);

• Containment Spray System (Shutdown Cealing !! cal Exchangers);

e Refueling Pool (covered in Section 3.3, Structures, of the BOE LRA);

• Demineralized Water and Condensate Storage System (makeup water source); and

• - Solid Waste Disposal System (spent resin discharge).

Sy3 tem Scaping Resuhn The SFPCS is in scope for license renewal Sased o.i 10 CFR 54.4(aj. 'the following intended functions

- of the SFPCS were determined based on the requirements of $54.4(a)n) and (2) in accordance with the CCNPP IPA Methodology Section 4.?.1: [ Reference 4, Section 1.1.3; Reference 6, Table 1]

Provide containment isolation in the event of a Loss of Coolant Accident or a Control Element Assembly Ejection event;

• Provide heat removal for SFP water and refueling pool water with the initiation of a Fuel llandling incident or a lloron Dilution Event;

• Maintain pressure boundary of the system; and Maintain t.lectrical continuity and/or provide protection of the electrical system.

No intended functions of the SFPCS were determined based on the requirements of 654.4(a)(3).

[ Reference 6, Table 1]

5.18.1.2 Component LevelScoping liased on the intended functions listed above, the portion of the SFPCS that is within the scope oflicense renewal includes all components (electrical, mechanical, and instrument) and their supports from the refueling and SFPs through the SFP cooling pumpe, heat exchangers, filter, and c'emineralizer, and back to the refueling and SFPs. It also includes the isolation valves in the lines to the interfacing systems.

Table 5.181 (in Section 5.18.1.3) lists the specille device types in the SFPCS that have been designated as within the scope of license renewal because they have at least one intended function. [ Reference 4, Section 2.2 Table 21]

Some componients in the SFPCS are common to many other plant systems and have been included in separate commodity AMRs that address those components for the entire plant. These components include the following: [ Reference 4, Section 3.2]

Structural supports for piping, cables, and components are evaluated for the effects of aging in the Component Supports Commodity Evaluation in Section 3.1 of the BGE LRA, except that the supports for the SFPCS filter and demineralizer are addressed herein.

Application for License Renewal 5.18-4 Calvert Cliffs Nuclear Power Plant.

A*ITACllMENT R) i APPENDIX A - TECHNICAL INFORMATION 5.18. SPENT FUEL POOL COOLING SYSTEM  :

i

• Electrical control and power cabling are evaluated for .he effects of aging in the Electrical Cables Commodity Evaluation in Section 6.1 of the BGE LRA. This commodity evaluation completely addresses the passive intended function entitled "msintain electrical continuity anu/or provide l protection of the electrical system" for the SFPCS.

l

• Inorument tubing and piping and the associated supports, instrument valves and fittings, and the pressure boundaries of the inst uments themselves, are all addressed in BGE LRA Section 6.4 (Instrument Lines). In 3:ncral, Section 6.4 addresses everything from the outlet of the final root valve up to and including the instrument.

5.18.1.3 Components Subject to AMR His section describes the components within the SFPCS that are subject to AMR. It begins with a listing of passive intended functions, and then determines which device types are subject to AMR by dispositioning each device type as either:

• associated only with active functions;

• subject to scheduled replacement;

• evaluated in other sections of the BGE LRA; or

• remaining to be evaluated for aging management in this section.

Passive Intended functions in accordance with CCNPP IPA Methodology Section 5.1, the following SFPCS functions were determined to be passive: [ Reference 4, Table 31, p 3 2]

• Provide containment isolation during a Control Element Assembly Ejection and during Loss-of-Coolant Accident;

• Maintain electrical enntinuity anfor provide protection of the electrical system; and

• Maintain the pressure boundary of the system.

UcEke Types Subject to AMR Table 5.181 presents the results of the SFPCS device type pre evaluation. (Reference 4, Table 3 2]

Since the aging analysis in the AMR is carried out partly in consideration of equipment ,ype, rather than device typ, equipment type designators are also shown. This table lists all of the device types that have at least one intended function, and provides additional information relevant to the determination as to whether or not the device type is to be included in the subsequent analyses of this section. D at determination is based upon the three scoping columns as follows:

+

Passis e: Device types having at least one passive function are marked accordingly. A device type will be included in AMR only ifit has at least one passive function. Several device types are excluded from AMR since they do not have any passive functions.

Replace on Basis of Time: Device types that are replaced on a pre-established schedule would not be subjected to additional aging as a result of license renewal, and are therefore excluded from AMR. None of the SFPCS device types fallinto this category. '

Application for License Renewal 5.18 5 Calvert Cliffs Nuclear Power Plant c

AIIAc11 MENT (2) f APPENDIX A TECHNICAL INFORMATION 5.18-SPENT FUEL POOL COOLING SYSTEM

+

Addre=A Elsewhere: If a discussion in another section of the DGE LRA adequately addresses a device type used in the SFPCS, then that section is cited in this column and the device type is not addressed in this section. The hand valve device type (llV) is marked as " partially" addressed because some instrumentation hand valves are addressed in Sectior 4 of the llGE LRA, and the '

remaining hand valves are addressed in this section. i Table 5.181 SFPCS DEVICE TYPE DISPOSITION t V => "yes"; ( ) => " partial"; blank => "no" Dnice Replace Addressed SFPCS Equipment Typ Ikvice Type Description Passive on Basis Eisenhere Type AMR  !

ofTime (see note)

. llc Pipe Line witii Piplug Code of" llc" V _

V Pipe

!!S llasket Strainer V V Filter CKY Check Valve V V- Valve COIL Coil FE Flow Element V V Element Fl Flow Indicator V 6.4 FIS Flow Indicator Switch V 6.4 ~

FL Filter V V Filter .

FO 1]ow Orifice V V Pipe FU Fuse llS llandswitch IIV iland Valve V (6.4) (V) Valve llX lleat Exchanger V V lleat Exchanger IX Demineralizer/lon Exchanger V V Demineralizer JL Power Lamp indicator Mit 480V Motor MD 125/250 VDC Motor PD) Pressure DifTerential Indicator V 6.4 PDIS Pressure DilTerential Indicator Switch V 6.4 Pi Pressure Indicator V 6.4 PS Pressure Switch V 6.4 PMP Pump / Driver Assembly V V Pump RV Relief Valve V V Valve RY Relay TI Temperature Indicator V V Indicator ,-

TS Temperature Switch V V Switch YS Wye Strainer V V Filter 7.L Position Indicating Lamp NOTih An entry in the column labeled "Addrened I:tscu here" in the above tat le indicates the 11011 LRA section in which the item is addressed, items designated

• partial" are not fully covered in the referenced i section. See test for details.

Application for License Renewal 5.18 6 Calvert Cliffs Nuclear Power Plant .

-y., t- . - - -_-~r_ - - - - . ,

. ., ,,_,.r.. ,,e. ,re-cy.,_n -_w._,, _.,,,-,w-- -m- w,-.-, .,,

. . - - - . - - . - _ - _ - _ _ - - _ _ _ - _ ~ - _ - - - - - _ . - - . . _ _ - _ -

NITACllMENT (2) i APPENDIX A TECilNICAL INFORMATION 5.18. SPENT FUEL POOL COOLING SYSTEM j

!!altimore Gas and Electric Company may elect to replace components for which the AMR identifies that i further analysis or examination is needed in accordance with the License Renewal Rule, components subject to replacement based on qualified life or specified time period would not be subject to AMR.

As indicated in Table 5.!81, several device types have no passive function and several others are addressed in other sections of the llGE LRA. The device types remaining to be covered in this sectien are clearly indicated on the table, and are summarlied in Table 5.18 2:

Tule 5.18 2 DEVICE TYPES SUBJECT TO AMR Class llc Piping Ileat Exchanger Dasket Strainer Demineralizer/lon Exchanger Check Valve Pump / Driver Asseinbly Flow Element ReliefValve Filter Temperature Indicator Flow Orifice Temperatum Switch fland Valve Wye Strainer 5.18.2 Aging Management

'the list of potential Age Related Degradation Mechanisms (ARDMs) identified for the SFPCS components is given in Table 5.18 3, with plausible ARDMs identified by an annotation in the appropriate device type column. [ Reference 4 Table 4 2) An annotation indicates that the ARDM applies to at least one subcomponent for the device type listed. For efficiency in presentics; the results of these evaluations in tb8., report, ARDM/ device type combinations are grouped together where there are similar characteristics and the discussion is applicable to all components. Table 5.18 3 also identifies the group to which each ARDM/ device type combination belongs. Exceptions are noted where appropriate.

Some device types are included in more than one of these groups because of the diversity of materials used in their fabrication. The following groups have been defined for the SFPCS:

Group la Dcrice Tyocs or Subcomoonents: bolting and supports; vessel shells and covers; hand valve bodies; heat exchanger shell, nozzles, and channel covers (all carbon steel)

ARDMs: crevice corrosion, galvanic corrosion, general corrosion, pitting Group 2: Dcyltclynes or Subcomponcau: hand valve diaphragm, lining ARDhk: rubber degradation, radiation damage (diaphragm only)

Group 3: Device Tynes or Subcomoonents: hand valve seat / disk ARDMs: wear Group 4: Dericclypcs or Subcomoonenu: pump casing ARDMs: cavitation crosion, crosion corrosion Application for License Renewal 5.18-7 Calvert Clifts Nuclear Power Plant

ATTACHMENT (2)

APPENDIX A - TECHNICAL INFORMATION 5.18 SPENT FUEI, POOL COOLING SYSTEM l'ollow ng Table 5.18 3 is a discussion of the aging management demonstration process for each group ,.

identiGed above, it is presented by group, and includes a discussion of materials and environment, aging mechanism effects, methods of managing aging, aging management program (s), and aging management demonstration.

Table 5.18 3

~

POTENTIAL AND PLAUSIHLE ARDMs FOR Tile SFPCS Equipment / Device T) pes ,

PIPE FILTER VALVE (single-device equipment)

Potential ARDMs - F F B Y C H R F H I P T T H U L S S K V V E X X M i S C V P Cavitation Erosion V(4)

Corrosion Fatigue Crevice Corrosion V(1) V(1) V(1) V(1) V(1) V(1) V(1)

Erosion Corrosion V(4)

'atigue Fouling Galvanic Corrosion V(1) V(1) V(1) V(1) V(1) V(1) V(1)

General Corrosion V(1) V(1) V(1) V(1) V(1) V(1) V(1) V(1) ilydrogen Damage Intergranular Attack Microbiologically induced Corrosion l' articulate Wear Erosion Pitt:ng V(1) V(1) V(1) V(1) V(1) V(1) V(1)

Radiation Damage V(2)

Rubber Degradation V(2)

Saline Water Attack Selective Leaching Stress Corrosion Cracking Stress Relaxation

~

thermal Damage Ihermal Embrittlement Wear V(3)

Note: Not escry subcomponent within the device types listed l'ere may be susceptible to a ghen ARDN1.

This is because groups within a device type are not always fabricated from the same materials or subjected to the same environments. .

Application for License Renewal 5.18 8 Calvert Cliffs Nuclear Power Plant

NITACIIMENT m APPENDIX A TECHNICAL INFORMATION

' 5.18-SPENT FUEL POOL COOLING SYSTEM l Group 1 - (crevice corrosion, galvanic corrosion, general corrosion, and pitting of bolting and T.t orts, vessel shells and covers, hand valve bodies, heat exchanger shell, noites, and channel i overs)- Materials and Environment 1 l

All of the subcomponents included within this group are composed of some variety of carbon steel.

External surfaces of some subcomponents are zinc plated or are painted. Table 5.18-4 presents a summary cthe subcomponents subject to aging, and the associated materials, as derived from the AMR _i Re e V :ence 4, Attachments 4 and 5 for each device type (Attachmeat 4 identifies the materials  !

^

for u " e mponent, and Attachment 5 identifies the susceptible subcomponents))  !

Table 5.18-4 GROUP 1 SUBCOMPONENTS AND MATERIALS SUBJECT TO AGING 1

Equipment Type Subcomponents and Materials PIPE bolting )

bolts: ASTM

• A-193 GR B7 nuts: ASTM A 194 GR 211 1 FILTER SFP filter cover clamp assembly I I

zine-plated crJbon steel ASME* SA-193, GR B7 and SA;105, GR 1 SFP filter vessel support legs ar.d base ring

_,yainted carbon steel )

SFP demineralizer strainer bolting I

carbon or alloy steel VALVE SFP pump discharge check valve cover-to-body bolting ,

studs: ASTM A-193,GR B7 nuts: ASTM A-194, GR 211 some hand valve body /bonn. t bolting bolts: ASTM A '93, GR B7 nuts: ASTM i.- Q4, GR 211 IIEAT EXCIIANGER heat exchanger shell and nozzies she5 carbon steel, ASME SA 285-C, SA 106 GR B nozzles: ASME SA-181, GR 1 heat exchange < J2md :over atik 1 Wil, ASME SA 515, GR 60 DEMINERALIZER vessel support (suIddet to g$neral corrosion only) painted carbon steel PUMP casing stud nuts ASTM A-194.GR 211 American Society for Testing and Materials American Society of Mechanical F1gineers Applicatinn for License Renewr.1 5.18-9 Calvert Cliffs Nuclear Power Plant

. . - . . _ _ . = _ -

l l

ATIAC]IMENT (2) l APPENDIX A - TECIINICAL INFORMATION l 5.18. SPENT FUEL POOL COOLING SYSTEM l 1

The externa environment for all items in this group is climate-controlled air in the Auxiliary Building l and in the Containment. [ Reference 4, Attachment 3s] The Containment atmosphere is applicable only l to some subcomponents. Under normal operation, the temperature and humidity in the Auxiliary Building de not exceed 160*F and 70% [ Reference 7. Attachment I, Table 1, page 5 of 14) and, in the Containment,120'F and 70% [ Reference 7, Attachment 1. Table 1, page 13 of 14).

l De internal environment for all devices, with the exception of the shell side of the heat exch agers, i-controlled-chemistry borated water, with approximately 2500 ppm boron. The shell side of t.t. Lt exchangers are exposed to treated demineralized water. [ Reference 4, Attachment 3s)

The subcomponents in this group are not normally expo;ed to borated water because they are all external to the devices, but they may be exposed to it as a result ofleakage. The possible effects of boric acid are therefore taken into consideration in this analysis.

Group I - (crevice corrosion, galvanic corrosion, general corrosioc, and pitting of bolting and supports, vessel shells and covers, hand valve bodies, heat exchanger shell, nozzles, and channel covers)- Aging Mechanism Effects Crevice corrosion and pitting are related forms of intensive, localized corrosion. Crevice corrosion occurs in crevices such as may exist under bolt heads, within lap joints, or adjacent to weld backing rings. Pitting occurs when corrosion proceeds at one small location at a rate greater than the corrosion of the surrounding area. In either case, the stagnant fluid within the pit or crevice tends to accumulate corrosive chemicals, and thereby to accelerate the local corrosion process. Crevice corrosion can lead to stress corrosion cracking or other material failures, and can also lead to pitting. Pitting can result in complete perforation of the material. [ Reference 4, Attachment 7 for Pipe, Filter, Valve, lleat Exchanger, Demineralizer, Pump)

Galvanic corrosion is an accelerated form of corrosion caused by dissimilar metals in contact in a conductive solutior M rudies two dissimilar metals in physical or electrical contact and a conducting solution. [Referenc: 4, .w ment 7 for Pipe, Filter, Valve,lleat Exchanger, Demineralizer, Pump)

General corrosion is a tnmning of a metal by the chemical attack of an aggressive environment at its i surface. An important concern for pressurized water reactors is boric acid attack upon carbon steels.

General corrosion is not a concern for austenitic stainless steel alloys. [ Reference 4, Attachment 7 for Pipe, Filter, Valve, Ileat Exchanger, Demineralizer, Pump)

Carbon steels are susceptible to all of these forms of corrosion. They are particularly susceptible to significant acceleration of corrosion when exposed to boric acid in the concentrations present in the SFPCS. Due to the potential for leakage of system fluid onto external component surfaces, boric acid corrosion effects were determined to be plausible for the carbon steel and alloy steel bolting components listed in Table 5.18-4. [ Reference 4. Attachment 6s for listed components (Code A)]

! In heat exchangers, crevice corrosion and pitting can occur in cooler shell-side areas that are not exposed to the general Dowstream (such as in areas where intemal parts interface with the shell, and in other crevices). Galvanic corrosion may occur to a limited extent at the carbon steel shell to stainless steel

tubesheet joint due to the dissimilar materials. These areas may comprise small localized volumes of Application for License Renewal 5.18-10 Calvert Cliffs Nuclear Power Plant l

l l

ATTACllMENT (2)

APPENDIX A - TEC11NICAL INFORMATION 5.10 SPENT FUEL POOL COOLING SYSTEM stagnant solution for which Huld chemistry may deviate from bulk system chemistry.

Higher concentrations of impurities may exist in these crevices due to out-of specification system chemistry during excursions, and due to the stagnant Dow conditions of the crevice. The resulting degradation consists of highly localized pits or cracks. General corrosion of the shell side components can meu if adverse chemistry conditions are present for extended periods. [ Reference 4, Attachmece 6 for heat exchangers(Code A)]

In general, regardless of the particular :orrosion mechanism, the result is a reduction in the integrity of the corroded parts and a resulting increase in the likelihood of mechanical failure, in addition, corrosion can compromise the closeness of St of Otted parts, and result in Guid leakage and an increased likelihood of mechanical wear due to vibration or other relative motion.

If unmanaged, long term exposure to these corrosion mechanisms could eventually result in loss of the pressure-retaining capability under current licensing basis (CLB) design loading conditions.

Group 1 - (crevice corrosion, galvanic corrosion, general corrosion, and pitting of bolting and supports, vessel hcIls and covers, hand valve bodies, heat exchanger shell, nozzles, and channel covers)- Methods to Manage Aging Effects Mitigation: Boric acid <:orrosion can be mitigated by minimizing leakage. The susceptible areas of the SFPCS (i.e., bolted joints) can be routinely observed for signs of borated water leakage, and appropriate corrective action can be initiated as necessary to eliminate leakage, clean spill areas, and assess any corrosion. [ Reference 4, Attachment 6 for pipe, check valves, hand valves (Code A) and for heat exchangers and pumps (Code B)]

For heat exchanger internals, the effects of corrosion can be minimized through control of Huid chemistry. (Reference 4, Attachment 6 for heat exchangers (Code A)]

Painting and zinc plating are used as external coatings to minimize corrosion of carbon steels, but corrosion of painted and zinc-plated carbon steel surfaces has nevertheless been observed. Properly maintained paint an,1 zine plating can prevent significant corrosion of protected surfaces. [ Reference 4, for filters (Codes A and B), and for demineralizers (Code A)]

Discoverv: The effects of corrosion are generally detectable by visual techniques.

Corrosion of a painted or zinc-coated carbon stee! surface cannot occur without degrading the paint or coating. Confirmation that this paint or coating is intact is an effective method for ensuring that the effects of the plausible ARDMs have not occurred. Since the paint or coating does not contribute to the components' intended functions, degradation of the coating provides an alert condition, which triggers corrective action before corrosion that affects the equipment's ability to perform its intended function can occur. The paint or coating degradation that does occur can be discovered and managed by periodic inspection of the exposed surfaces and by repair of the surfaces, as needed.

The cooler shell side components of heat exchangers (or representative components from other plant locations) can be subjected to insnection to determine the extent of general and/or localized degradation that may be occurring. [Referenc( e, Attachment 6 for heat etchangers (Code A))

Application for License Renewal 5.18-11 Calvert Cliffs Nuclear Power Plant

ATTACIIMFNT d)

APPENDIX A - TECilNICAL INFORMATION

$.18-SPENT FUEL POOL COOLING SYSTEM Group 1 - (crevice corrosion, galvanic corrosion, general corrosion, and pitting of bolting and supports, Vessel shells and covers, hand valve bodies, heat exchanger shell, noules, and channel covers)- Aging Management Program (s) hiltigation:

The CCNPP Boric Acid Corrosion Inspection (BACI) Program, (MN-3 301, Reference 8, described more fully under " Discovery" in this section) can mitigate the effects of boric acid corrosion through timely discovery of leakage of borated water and removal of any boric acid residue that is found. His program requires visual inspection of the components containing boric acid for evidence of leaks, quantification of any leakage indications, and removal of any leakage residue from component surfaces,

[ Reference 4, Attachment 8]

Maintenance of proper SRW System chemistry will suppress general corrosion, galvanic corrosion, crevice corrosion, and pitting on the shell side of the SFPCS heat exchangers. [ Reference 4, Attachment 8]

Calvert Cliffs Procedure CP-206, "Speci0 cations and Surveillance for Component Cooling / Service Water Systems," provides for monitoring of the SRW and Component Cooling Water System ehemistry to control the concentrations of oxygen, chlorides, and other chemicals and contaminants. Control of the water chemistry prevents a corrosive environment for the shell side of the SFPCS heat exchangers, f Reference 4, Attachment 8)

Calvert Cliffs procedure CP-206 describes the surveillance and specifications for monitoring the SRW System fluid. It lists the parameters to be monitored, the frequency for the monitoring of tho:;c parameters, and the target and action levels for the SRW System fluid parameters. The para;ncters monitored by CP-206 are pil, hydrazine, chloride, dissolved oxygen, dissolved copper, dissolved iron, suspended solids, gamma activity, and tritium activity (normally not a radioactive system).

[ Reference 9, Attachment 1)

These parameters are currently monitored on a frequency ranging from three times per week to once a month. All of the parameters listed in CP 206 currently have target values that give an acceptable range or limit for the associated parameter. Two of the parameters, pli and hydrazine, have action levels associated with them. For pil the current action level is less than 9.0 or greater than 9.8. For hydrazine, the current action level is less then 5 or greater than 25 parts per million (ppm). If any gamma activity or tritium is detected in the SRW System, the procedure currently directs CCNPP personnel to CP-224,

" Monitoring Radioactivity in Systems Normally Uncontaminated." CP 206 presents the specific monitoring frequency and target values for each chemistry parameter. [ Reference 9, Attachment 1]

Review of SRW operational experience identified no problems related to significant deficiencies in CP.

206, in 1996, CP 206 was revised to include moaitoring of dissolved iron as a method for discovering any unusual conosion of carbon steel components.

An internal BGE chemistry summary report for 1996 described the CCNPP Units 1 and 2 Component Cooling /SRW Systems chemistry as excellent. Action levels for all four systems were only exceeded on eight occasioes, or approximately 0.7% of the time during the year. Over 70% of the action levels Application for License Renewal 5.18-12 Calvert Cliffs Nuclear Power Plant l

ATTACllMENT d)

APPENDIX A TECIINICAL INFORMATION 5.18-SPENT FUEL POOL COOLING SYSTEM entered were due to major system changes during the 1996 outage. The report included recommendations to determine outage evolutions that can affect the Component Cooling /SRW chemical parameters and take action to prevent chemistry parameters from being exceeded.

Calvert Cliffs procedure CP 206 provides for rapid assessment of off normal chemistry parameters so that steps can be taken to return them to nonnal levels.

Discoverv:

Discovery of boric acid leakage is ensured by the DACI Program (MN 3 301, Reference 8).

[ Reference 4, Attachment 8] This program also requires investigation of any leakage that is found. A visual examination of external surfaces is perfonned for components containing boric acid.

[ Reference 8]

The Inservice Inspection Program required the establishment of the BACI Program to systematically ensure that boric acid corrosion does not degrade the primary system boundary. [ Reference 10, page 23, Section 5.8.A.I.) ne program also applies to " valves in systems containing borated water which could leak onto Class 1 Carbon Steel Components," and it identifies other plant areas to be examined.

[ Reference 8, Section 5.1B] The program controls examination, test methods, and actions to minimize the loss of structural and pressure-retaining integrity of ccmponents due to boric acid corrosion.

[ Reference 10, page 7, Section 3.0.C] The basis for the establishment of the program is Generic Letter 88 05, " Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWR Plants " [ Reference 8, Section 1.1) ne scope of the program is threefold in that it: (a) identifies locations to be examined; (b) provides examination requirements and methods for the detection ofleaks; and (c) provides the responsibilities for initiating engineering evaluations and necessary corrective actions. [ Reference 8 Section 1.2)

During each refueling outage, inservice inspection personnel perform a walkdown inspection to identify and quantify any leakage found at specific locations inside the Containment and in the Auxiliary Building. The inservice inspection ensures that all components that are the subjects of existing issue Reports (irs) where boric acid leakage has been found are examined in accordance with the requirements of this program. A second inspection is performed prior to plant startup (at nonnal operating pressure and temperature) if leakage was identified and corrective actions were taken.

[ Reference 8, Sections 5.1 and 5.2] Calvert Cliffs procedure QL-2-100, " Issue Reporting and Assessment," defines requirements for initiating, reviewing and processing irs, and resolution of issues.

issue Reports are generated to document and resolve process and equipment deficiencies and nonconfonnances.

Under the BACI Program, the walkdown inspections applicable to the SFPCS are type VT-2 (a type of visual examination described in ASME XI, IWA-2212). The VT-2 visual examinations include the accessible external exposed surfaces of pressure-retaining, non-insulated components; floor areas or equipment surfaces located underneath non-insulated components; vertical surfaces of insulation at the lowest elevation where leakage may be detected, and horizontal surfaces at each insulation joint for insulated components; floor areas and equipment surfaces beneath components and other areas where water may be channeled for insulated components whose external insulation surfaces are inaccessible for direct examination; and for discoloration or residue on any surface for evidence of boric acid

- Application for License Renewal 5.18-13 Calvert Cliffs Nuclear Power Plant

ATTACIIMENT m APPENDIX A - TECHNICAL INFORMATION 5.18-SPENT FUEL POOL COOLING SYSTEM accumulation. Any leakage detected is reported on an IR for assessment and corrective action.

[ Reference 8, Section 5.2]

Issue Reports written in accordance with this program are required to address the removal of the boric acid residue and the inspection of the affected components for general corrosion. If general corrosion is found on a component, the IR is to provide an evaluation of the component for continued service and corrective actions to prevent recurrence. [ Reference 8, Section 5.3]

The BACI Program has evolved with regard to boric acid leaks discovered during other typs of walidowns and inspections. The program specines the minimum quali0 cation level for inspxtors evaluating boric acid leaks. Apparent leaks that are discovered during these other walkdowns/ inspections are documented in irs by the individual discovering the leak. These irs are then routed to the inservice inspection group for closer inspection and evaluation by a quali0cd inspector.

This approach provides for more bar:c acid leakage inspection coverage while still meeting the minimum qualification requirement.

The corrective actions taken as a result ofIRs under this program will ensure that the SFPCS components remain capable of performing their intended function under all CLB conditions during the period of extended operation.

Calvert Cliffs procedure CP-206 provides for the monitoring of SRW System chemistry. This controls galvanic corrosion, crevice corrosion, and pitting on the shell side of the SFPCS heat exchangers, and detects the presence of corrosion products in the SRW The presence of an abnormal concentration of corrosion products in the SRW would suggest that unexpected corrosion is taking place, and would trigger investigations and corrective actions.

Since the following components in Group 1 are installed in arcas that are normally inaccessible due to radiation levels, CCNPP currently plans to include them in an Age Related Degradation inspection (ARDI) Program to verify that degradation of the components by general, crevice, or galvanic corrosion or by pitting is not occurring:

SFP filter cover clamp assembly and filter vessel support legs and base ring;

• body-to-bonnet bolting for stainless steel diaphragm valves not covered by the BACI Program;

• heat exchanger shell and nozzles; demineralizer vessel support legs and Door mounting plate (susceptible to general corrosion only); and SFP demineralizer wye-strainer bolting.

The program is considered an ARDI Program as defined in the CCNPP IPA Methedology presented in Section 2.0 of the BGE LRA.

Application for License Renewal 5.18-14 Calvert Cliffs Nuclear Power Plant

l ATTACHMENT (2) )

i APPENDIX A - TECilNICAL INFORMATION l 5.18-SPENT FUEL POOL COOLING SYSTEM The elements of the ARDI Program will include:

Determination of the examination sample size based on plausible aging effects; Identification of inspection locations in the system / component based on plausible aging effects and consequences of loss of component intended function;

• Determination of examination techniques (including acceptance criteria) that would be effective, considering the aging effects for which the component is examined;

• Methods for interpretation of examination results;

• Methods for resolution of adverse examination findings, including consideration of all design loading conditions required by the CLB and specification of required corrective actions; and Evaluation of the need for follow-up examinations to monitor the progression of any age-related degradation.

Any corrective actions that are required will be taken in accordance with the CCNPP Corrective Action Program and will ensure that the components will remain capable of performing their intended function under all CLB conditions.

Group 1 - (cretice corrosion, galvanic corrosion, general corrosion, and pitting of botting and supports, vessel shells and covers, hand valve bodies, heat exchanger shell, nozzles, and channel covers)- Demonstration of Aging Management Based on the information presented above, the following conclusions can be reached with respect to crevice corrosion, galvanic corrosion, general corrosion, and pitting of the device types addressed in this section:

These device types contribute to the system pressure boundaries, and their integrity must be maintained under CLB design conditions.

The construction material for components in this group is carbon steel. External surfaces may be coated with paint or plated with zinc.

+

Crevice corrosion, galvanic corrosion, general corrosion, and pitting are plausible ARDMs for this group of components because the components are exposed to boric acid and to a humid, moist, or wet environment, if unmitigated, these ARDMs could eventually result in the loss of pressure-retaining capability under CLB design loading conditions.

The effects of born: acid will be managed by means of the bACI Program, MN-3 301, Reference 8. When boric acid leakage is identified, either through required program inspections or through irs resulting from other types of walkdowns and inspections, this program will ensure th:t corrosion induced by boric acia is discovered and that appropriate corrective action is taken.

Chemistry control in accordance with CP-206, Reference 9, will ensure that the cooling water supplied to the SFPCS heat exchangers is of an appropriate chemistry to minimize corrosion, and will discover any unusual corrosion that may be taking place and ensure that appropriate corrective action is initiated.

Components not adequately protected under the two programs listed above will be subjected to an ARDI Program. This program will examine a representative sample of the components for Application for License Renewal 5.18 15 Calvert Cliffs Nuclear Power Plant

ATTACHMrNT d)

APPENDIX A - TECIINICAL INFORMATION 5.18-SPENT FUEL POOL COOLING SYSTEM degradation, and ensure that appropriate corrective actions are initiated on the basis of the findings.

Therefore, there is a reasonable assurance that the effects of aging will be adequately managed for these components such that they will be capable of performing their intended functions consistent with the CLB during the period of extended operation under all design loading conditions.

Group 2 -(rubber degradation of hand valve linings; rubber degradation and radiation damage of hand valve diaphragms)- Materials and Environment All of the subcomponents included within this group are composed of clastomers. Table 5.18-5 presents a summary of the subcomponents and the associated materialt [ Reference 4, Attachments 4 and 5 for each device type (Attachment 4 identifies the materials for each subcomponent, and Attachment 5 identifies the susceptible subcomponents))

Table 5.18 5 GROUP 2 SUHCOMPONENTS AND MATERIALS Device Type Subcomponents and Materials VALVE body with rubber liner and seat (for rubber lined carbon steel valves) diaphragm (for stainless steel diaphragm valves) ethylene propylene terpolymer The environment for these devices is controlled-chemistry borated water, with approximately 2500 ppm boron, in addition, the diaphragm valves are exposed to an external environment consisting of the Auxiliary Building atmosphere (see the Group 1 discussion for specifications). [ Reference 4, Attachment 3s] Radioactive material accumulating in the SrPCS demineralizer vessel during normal plant operations results in high radiation levels in the vicinity of the diaphragm valves. [ Reference 1, Section 11.2.2]

Group 2 -(rubber degradation of hand valve linings; rubber degradation and radiation damage of hand valve diaphragms)- Aging Mechanism Effects When an elastomer ages, the primary mechanisms involved are scission, crosslinking, and changes associated with the compounding ingredients. Scission is the process of breaking molecular bonds, tynically due to ozone attack, ultraviolet light, or radiation. Crosslinking is the process of creating mobcular bonds between adjacent long-chain molecules, typically due to radiation, oxygen attack, heat, or curing. Scission results in increased elongation, decreased tensile strength, and decreased modulus; crosslinking has the opposite effects (i.e., decreased elongation, increased tensile strength, and increased modulus). The compounding ingredients used in an elastomer / rubber may be affected by evaporation, leaching, or mutation over their service life. Long-term exposure of rubber to water will result in water absorption and swelling, blistering, hardening, and eventual cracking. When utilized as a protective

- Application for License Renewal 5.18-16 Calvert Cliffs Nuclear Power Plant

ATTACHMENT (2)

- APPENDIX A - TECIINICAL INFORMATION 5.18. SPENT FUEL POOL COOLING SYSTEM lining, moisture permeation of the rubber produces blisters beneath the lining and initiates corrosion of the lined surface. [ Reference 4, Attachment 7 for Valve)

Exposure to gamma radiation can result in degradation of non metallic material properties, such as tensile strength, hardness, elongation, and compressibility. Material susceptibility is dependent upon strength of the radiation Held, duration of exposure, and specinc material composition. [ Reference 4, for Valve)

He components in this group are composed of elastomers, which are subject to rubber degradation. The valve diaphragms are also subject to the effects of radiation damage. Failure of a valve body liner would result in exposure of the valve body to the process Guid, which would result in corrosion and reduced wall thickness. Failure of a diaphragm or valve seat would also result in leekage. In either case, the pressure boundary function would eventually be compromised.

Group 2 -(rubber degradation of hand valve linlags; rubber degradation and radiation damage of hand valve diaphragms)- Methods to Manage Aging Effects Mitigation: The degradation of elastomer liners and diaphragms is related solely to time and the environment, and additional shielding of the valve diaphragms from the highly radioactive Guids in the SFPCS demineralizer is impractical. [ Reference 4, Attachment 6 for diaphragm valves (Code D)]

Therefore, there are no reasonable methods of mitigating the effects of these ARDMs for the subject subcomponents.

Discovery: These subcomponents can be inspected and/or tested as the opportunity arises in future valve seat replacements or other maintenance.

Group 2 -(rubber degradation of hand valve linings; rubber degradation and radiation damage of hand valve diaphragms)- Aging Management Program (s)

Mitigation: There are no programs credited with mitigating the effects of these ARDMs for the subject subcomponents.

Discosery: An ARDI Program, as described in the BGE IPA Methodology, will be implemented to address rubber degradation of the clastomers used in the linings and diaphragms for these valves, as well as radiation damage to the clastomers used in the valve diaphragms. The ARDI Program will include the following elements:

IdentiGeation of the specific valves to be inspected;

+

Speci0 cation and use of appropriate inspection techniques; Methods for interpretation of examination results; Requirements for reporting of results and corrective actions if aging concerns are identiGed; Evaluation of the need for follow-up examinations to monitor the progression of any age-related degradation; and Methods for resolution of adverse examination findings, including consideration of all design loading conditions required by the CLB and specification of required corrective actions.

Application for License Renewal 5.18-17 Calvert Cliffs Nuclear Power Plant

ATTACHMENT (M APPENDIX A - TECliNICAL INFORMATION 5.18-SPENT FUEL POOL COOLING SYSTEM ne ARDI Program w!!! ensure that aging of elastomers used in valve body linings and diaphragms due to rubber degradation, as well as radiation damage to the elastomers used in the valve diaphragms, is ident10ed and corrected such that the valves will be capable of performing their intended functions under all design conditions required by the CLB.

Group 2 - (rubber degradation of hand valve linings; rubber degradation and radiation damage of hand valve diaphragms)- Demonstration of Aging Management Based on the information presented above, the following conclusions can be reached with respect to rubber degradation in hand valve linings and diaphragms, and radiation damage in hand valve diaphragms:

The linings and diaphragms of hand valves contribute to the system pressure boundaries. The diaphragms are themselves part of the pressure boundary; the linings protect the valve bodies which are part of the pressure boundary. The integrity of these valves must be maintained under CLU design conditions.

. These components are composed of clastomers.

Rubber degradation is a plausible ARDM for this group of components, in addition, radiation damage is plausible for the diaphragms in this group. If unmitigated, these ARDMs could eventually result in the loss of pressure retaining capability under CLB design loading conditions.

- A new ARDI Program will address the requirements for the inspection and maintenance of elastomers used in valve body linings and in valve diaphragms.

Therefore, there is reasonable assurance that the efTects of aging will be adequately managed for these components such that they will be capable of performing their intended functions consistent with the CLU during the period of extended operation under all design loading conditions.

Group 3 -(wear of hand valve seats and disks)- Materials and Environment This group consists solely of cast or forged stainless steel (Type 304/316 or CF-3/CF 8) hand valve seats and disks for SFPCS containment isolation hand valves. [ Reference 4, Attachments 4 and 5 for each device type (Attachment 4 identifies the materials for each subcomponent, and Attachment 5 identifies the susceptible subcomponents)]

The environment is the process Guid (i.e., controlled-chemistry borated water, approximately 2500 ppm boron). [ Reference 4, Attachment 3]

Group 3 -(wear of hand valve seats and disks)- Aging Mechanism Effects Wear occurs both in components that experience considerable relative motion, and in components that are held under high loads with no motion for long periods. Additionally, impeded relative motion between two surfaces held in intimate contact for extended periods may result from galling /self-welding.

[ Reference 4, Attachment 7] The seating surfaces of the containment penetration isolation hand valves may be subject to all of these forms of wear. The effect of seating surface wear is leakage through the Application for License Renewal 5.18-18 Calvert Cliffs Nuclear Power Plant

ATTACilMENT (2)

APPENDIX A - TECIINICAL INFORMATION 5.18-SPENT FUEL POOL COOLING SYSTEM seat / disk. Excessive seat leakage could prevent the satisfactory performance of the containment pressure boundary function. [ Reference 4, Attachment 6 for containment isolation valves (Code B)]

Group 3 -(wcar of hand valve seats and disks)- Methods to Manage Aging Effects Mitigation: Since the valves in this group are actuated very infrequently, wear of the stainless steel seating surfaces would result principally from galling /scif-welding or from being held under high loads with no motion for long periods. Valves which operate infrequently can be actuated to prevent sticking.

Discoverv: Wear can be discovered by inspecting and testing the valve device types that are susceptible to this ARDM. In addition, local leak rate testing (LLRT) of the containment isolation valves can provide for detection ofleakage that could be the result of wear on valve internals.

Group 3 -(wear of hand valve seats and disks)- Aging Management Program (s)

Mitigation: Since more frequent valve operations are not operationally practical, no programs are credited with mitigating wear.

Discoscry: Calvert Cliffs procedures STP M 571E-1 and M 571E-2, which cover LLRT for penetrations 59 and 61, are part of the overall CCNPP Containment Leakage Rate Program. [ References 11 and 12]

The CCNPP Containment Leakage Rate Program was established to implement the leakage testing of the containment as required by 10 CFR 50.54(o) and 10 CFR Part 50, Appendix J, Option B, " Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors." Appendix J specifies containment leakage testing requirements, including the types of tests required, frequency of testing, test methods, test pressures, acceptance criteria, and reporting requirements. Containment leakage testing requirements include performance of Integrated Leakage Rate Tests, also known as Type A tests, and LLRTs, also known as Type B and C tests. Type A tests measure the overall leakage rate of the containment. Type B tests are intended to detect leakage paths and measure leakage for certain containment penetrations (e.g., airlocks, flanges, and electrical penetrations). Type C tests are intended to measure containment isolation valve leakage rates. [ Reference 13, Section 6.5.6; References 14 and 15]

The CCNPP LLRT Program is based on the requirements of CCNPP Technical Specifications 3.6.1.2, 4.6.1.2, and 6.5.6. The scope of the program includes Type B and C testing of containment penetrations.

The valves that isolate the containment penetration piping for the SFPCS are included in the scope of this program as part of the leakage testing for containment penetrations 59 and 61. [ Reference 13]

The LLRT is performed on a performance-based testing schedule in accordance with Option B of 10 CFR Part 50, Appendix J, as implemented by CCNPP Technical Specifications. [ References 13,14, and 15] Local leak rate testing presently includes the following procedural steps:

Leak rate monitoring test equipment is connected to the appropriate test point.

+

The test volume is pressurized to the LLRT Program test pressure, which is conservative with respect to the 10 CFR Part 50, Appendix J, test pressure requirements. Appendix J requires testing at a pressure "P ," wLeh is the peak calculated containment internal pressure related to the design basis accident.

Application for License Renewal 5.18-19 Calvert Cliffs Nuclear Power Plant

N'TACHMENT (D APPENDIX A - TECHNICAL INFORMATION 5.18-SPENT FUEL POOL COOLING SYSTEM Leak rate, pressure, and temperature are monitored at the frequency specified by the LLRT procedure and the results are recorded.

. The maximum indicated leak rate is compared against administrative limits that are more restrictive than the maximum allowable leakage limits.

"As found" leakage equal to or greater than the administrative limit, but less than the maximum allowable limit, is evaluated to determine if further testing is required and/or if corrective maintenance is to be performed.

For "as found" leakage that exceeds the maximum allowable limit, the Shift Supervisor and the Containment System Engineer are notified and they detersnine if Technical Specification Limiting Condition for Operation 3.6.1.2.b has been exceeded. Technical Specification 3.6.1.2.b contains the maximum allowable combined leaka3e for all penetrations and valves subject to the Type B and C tests. Corrective action is taken as required to restore the leakage rates to within the appropriate acceptance criteria.

. If any maintenatice is required on a containment isolation valve that changes the closing characteristic of the valve, an "as left" test must be performed on the penetration to ensure leakage rates are acceptable.

The corrective actions taken as part of the LLRT Program will ensure that the SFPCS containment isolation valves remain capable of performing their intended function under all CLB conditions during

' the period of extended operation.

Group 3 -(wear of hand valve seats and disks) . Demonstration of Aging Management Based on the information presented above, the following conclusions can be reached with respect to the detection and mitigation of wear in regard to the subject valve parts:

. The SFPCS device types described here act as a pressure-retaining boundary for the Containment, and their integrity must be maintained under CLB design conditions.

Wear is plausible for the valve device types discussed in the materials and environment section above which could lead to the loss of the pressure-retaining boundary function of the SFPCS.

The CCNPP LLRT Program performs leakage testing on the SFPCS valves listed for this ARDM, and contains acceptance crite.-ia that ensure corrective actions will be taken such that there is a reasonable assurance that the containment pressure boundary function will be maintained.

Therefore, there is a reasonable assurance that the effects of wear will be managed in order to maintain the intended function for the containment isolation hand valve seats and disks under all design loading conditions required by the CLB during the period of extended operation.

Group 4 -(cavitation erosion, closion corrosion of pump easings)- Materials and Environment This group consists solely of the SFPCS pump casings and stuffing box extensions. These are camposed of ASTM A 296, GR CA-15 with 12% chrome. [ Reference 4, Attachment 4 for Pump) NOTE: ASTM standard A 296 has been replaced by A-743 and A-744.

Application for License Renewal 5.18-20 Calvert Cliffs Nu: lear Power Plant

A'ITACHMENT (2)

APPENDIX A - TECHNICAL INFORMATION 5.18-SPENT FUEL. POOL COOLING SYSTEM The external environment for these devices is the Auxiliary Building atmosphere (see the Group 1 discussion for specifications). [ Reference 4, Attachment 3 for Pump]

The internal environment for these devices is controlled chemistry borated water, with approximately 2500 ppm boron. [ Reference 4, Attachmect 3 for Pump]

Group 4 -(cavitation erosion, crosion corrosi9n of pumr, casings)- Aging Mechanism Effects C

Erosion is a mechanical action of a fluid and/or particulate matter on a metal surface, without the in0uence of corrosion. Cavitation erosion is localized material erosion caused by formation and collapse of vapor bubbles in close proximity to a metal surface, it car. occur only in the presence of Guid (liquid)

How, and also requires pressure Ductuations which temporarily drop the liquid pressure below the corresponding Duld vapor pressure. Erosion corrosion is characterized by an ircreased rate of movement between a corrosive Guid and the metal surface. Mechanical wear or abrasion can be involved, characterized by grooves, gullies, waves, holes, and valleys on the metal surface. [ Reference 4, Attachment 7 for Pump]

The pump casing has experienced in service loss of material in the area behind the impeller (stuffing box extension), apparently due to erosion corrosion and/or cavitation erosion. [ Reference 4, Attachment 6 for Pump (Code A)]

Group 4 - (cavitation erosion, crosion corrosion of pump casings) - Methods to Manage Aging Effects Mitigation: This ARDM is an unavoidable consequence of the operation of the pump. There is no practicable mechanism for the mitigation of this effect.

Discoverv: The effects of cavitation erosion and crosion corrosion can be evaluated by visual inspection and measurement.

Group 4 -(cavitation erosion, erosion corrosion of pump casings)- Aging Management Program (s)

Mitigation: Since there is no practicable method for miti; sting cavitation erosion and erosion corrosion, no mitigation program is credited.

Discoverv: Calvert Cliffs' Preventive Maintenance Tasks 00672007 and 00672008, " Inspect #11 (#12)

Spent Fuel Pool Cooling Pump," automatically schedule and implement Mechanical Preventive Maintenance Checklist MPM67102," Inspect Snent Fuel Pool Cooling Pump." This checklist directs

- disassembly and inspection of the pumps, and is currently performed on each pump approximately every four years. [ Reference 16] These preventive maintenance tasks will be modified to implement a new maintenance procedure specific to the SFPCS pumps for disassembly, inspection, and re-assembly. The new procedure will explicitly present inspection requirements and acceptance criteria for discovery of material loss from the SFPCS pump casing that may be caused by cavitation erosion and/or erosion corrosion. [ Reference 4, Attachment 10)

Application for License Renewal 5.18 21 Calvert Cliffs Nuclear Power Plant

ATrACilMENT m APPENDIX A - TECIINICAL INFORMATION 5.18-SPENT FUEL POOL COOLING SYSTEM Any corrective actions that are required are taken in accordance with the CCNPP Corrective Action Program and will ensure that the components will remain capable of performing their intended functions under all CLD conditions. ,

Group 4 - (cavitation erosion, erosion corrosion of pump easings) - Demonstration of Aging Management Based on the information presented above, the following conclusions can be reached with respect to the detection and mitigation of cavitation erosion and erosion corrosion in the SFPCS pump casings:

• _ The SFPCS pump casings act as a pressure-retaining boundary, and their integrity must be maintained under CLB design conditions.

Cavitation emsion and erosion corrosion are plausible for the SFPCS pump casings described in the materials and environment section above, and could lead to the loss of the pressure-retaining

- boundary function of the SFPCS.

• Preventive Maintenance Tasks 00672007 and 00672008 will be modified to provide for periodic disassembly of the pump casings, with specific requirements to detect the effects of cavitation erosion and crosion corrosion on the SFPCS Pump casings. This ensures that corrective actions will be taken such that there is a reasonable assurance that the pressure boundary function will be maintained.

Therefore, there is a reasonable assurance that the effects of cavi+ation crosion and erosion corrosion will be managed in order to maintain 'he intended function of the SFPCS pump casings under all design loading cond!! ions required by the CLB during the period of extended operation, 5.18.3 Conclusion The aging management programs discussed for the SFPCS are listed in Table 5.18-6. These programs are administratively controlled by a formal review and approval process. As demonstrated above, these programs will manage the aging mechanisms and their effects in such a way that the intended functions of the components of the SFPCS will be meintained during the period of extended operation consistent with the CLB under all design loading conditions.

The analysis / assessment, corrective action, and confirmation / documentation process for license renewal is in accordance with QL-2, "Conective Actions Program." QL-2 is pursuant to 10 CFR Part 50, Appendix B, and covers all structures and components subject to AMR.

Application for License Renewal 5.18-22 Calvert Cliffs Nuclear Power Plant

ATTACllMENT m APPENDIX A TECHNICAL INFORMATION 5.18-SPENT FUEL POOL COOLING SYSTEM Table 5.18-6 AGING MANAGEMENT PROGRAMS FOR TIIE SFPCS Program Credited For Existing 13ACI Program (MN 3 301) e Management of boric acid induced corrosion in SFPCS Group 1 components Existing SRW System Chemistry, e Management of conditions that could lead to Speci0 cation and Surnillance (CP- corrosion on the shell side of the SFPCS heat 206) exchangers (included in SFPCS Group 1)

~

e Discovery of evidence of corrosion on the shell side of the SFPCS heat exchangers (included in SFPCS Group 1)

Existing Containment Penetration Leak Rate e Discovery of leakage that could be the result of Testing (STP-M 571E-1/2) wear of containment isolation valves in SFPCS Group 3 Modined SFPCS pump housing inspection

• Management of cavitatioa- and flow-related (Repetitive Tasks 00672007, degradation within the SFPCS pump housings 00672008, modided to explicitly (SFPCS Group 4)

Present inspection requirements)

New ARDI Program e Management of corrosion on components not included in the BACI Program (SFPCS Group 1)

• Management of corrosion and coating damage to Olter and demineralizer supports. (SFPCS Group 1)

- Management of aging of elastomer-based valve linings and diaphragms (SFPCS Group 2) i l Application for License Renewal 5.18-23 Calvert Cliffs Nuclear Power Plant l

ATTACIIMENT (2)

APPENDIX A - TECHNICAL INFORMATION 5.18-SPENT FUEL POOL COOLING SYSTEM

- 5.18.4 Referenees

1. CCNPP Updated Final Safety Analysis Report, Revision 19

2. Letter from Mr. D. K. Davis (NRC) to Mr. A. E. Lundvall, Jr. (DGE), dated January 4,1978,

" Amendment Nos. 27 and 12 to Facility Operating License Nos. DPR 53 and DPR 69 for the Calvert Cliffs Nuclear Power Plant Unit Nos. I and 2"

3. Letter from J. W. Johnson (MPR Associates) to J. Makar (DGE), "SFP Cooling System Pipe Failures: Recommended Corrective Actions," August 29,1990

4. CCNPP Aging Management Review Report: Spent Fuel Pool Cooling System (067),

Revision 1

5. CCNPP Drawing 60716, Revision 47," Spent fuel Pool Cooling, Pool Fill & Drain Systems"

6. Component Level ITLR Screening Results for the Spent Fuel Pool Cooling System, Revision 1

7. CCNPP Engineering Standard ES-014, " Summary of Ambient Environmental Service Conditions," Revision 0

8. CCNPP Procedure MN 3 301,"CCNPP Boric Acid Corrosion inspection Program," Revision i Change 0

9. CCNPP Procedure CP 206, " Specifications and Surveillance Component Cooling / Service Water System," Revision 3

10. CCNPP Procedure MN 3110, " Inservice Inspection of ASME Section XI Components,"

Revision 2

11. CCNPP Surveillance Test Procedure STP-M 571E-1," Local Leak Rate Test, Penetrations 15, 16,18,38,59,60,61,62,64"(Unit 1), Revision 0 l' CCNPP Surveillance Test Procedure STP M-571E-2," Local Leak Rate Test, Penetrations 15, 16,18,38,59,60,61"(Unit 2), Revision 1

13. Letter from Mr. A. W. Dromerick (NRC) to Mr. C.11. Cruse (BGE)," Issuance of Amenaments for Calvert Cliffs Nuclear Power Plant, Unit 1(TAC No. M92549) and Unit 2 (TAC No, M92550)," dated December 10,1996 (Amendment Nos. 217/194)

14. 10 CFR Part 50, Appendix J, " Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors"

15. Letter from Mr. C. 11. Cruse (BGE) to NRC Document Control Desk, dated November 26,1996,"Calvert Cliffs Nuclear Power Plant Unit Nos.1 & 2; Docket Nos. 50-317

& 50-318 License Amendment Request: Adoption of 10 CFR Part 50, Appendix J, Option B for Types B and C Testing"

16. CCNPP NUCLEIS Database Repetitive Task 00672007 (00672008), " Inspect #11 (#12) Spent Fuel Pool Cooling Pump" Application for License Renewal 5.18-24 Calvert Cliffs Nuclear Power Plant

i l

ATTACHMENT m l

1 I

APPENDIX A - TECIINICAL INFORMATION 6.1 - CABLES t

l l

l i

Baltimore Gas and Electric Company j- Calvert Cliffs Nuclear Power Plant August 21,1997

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- . ~.

ATTACIMfENT (3)

APPENDIX A - TECilNICAL INFORMATION 6.1- CAHLES 6.1 Cables

'Ihis is a section of the Baltimore Gas and Electric Company (BGE) License Renewal Application (LRA), addressing Cables. Cables have been evaluated as a " commodity" in accordance xith the Calvert Cliffs Nuclear Power Plant (CCNPP) Integrated Plant Assessment (IPA) Methor' ology described in Section 2.0 of the BGE LRA. These sections are prepared independently and will, collectively, comprise the entire LRA.

6.1.1 Scoping 6.1.1.1 Commodity Cables Scoping Cables are associated with equipment in almost every plant system. The CCNPP equipment database does not contain specific equipment connection information for individual cables. Instead, a separate Cable and Raceway System (CRS) database contains information on the CCNPP scheduled cables, their service function (power, control, or instrumentation), their materials, and their routing. Correlation of cable schemes to individual raceways, equipment, and rooms is then possible using the information in the CRS database and design drawings. Due to these methods of documenting information on individual cables and the system non specific nature of plant cabling, the BGE IPA process does not include cables within any of the system Aging Management Reviews (AMRs), but ir. stead evaluates cables as a separate commodity. [lteference 1, Section 2.1)

Commodity Descriotion/ Conceptual Boundaries Cables are within the scope oflicense renewal because the;, support various plant electrical components which are required to perform the functions described in {54.4(a)(1),(2), and (3). In general, cebles provide the electrical path between electrical components in order to provide: AC or DC power requhd for component operation, voltage or current signals for component control functions, and voltage and current signals for instrumentation functions.

The population of cables at CCNPP includes scheduled and unscheduled cables in power, control, and instrumentation service. Scheduled cables are defined as those cables that are maintained as line items in the CCNPP CRS database, Unscheduled cables at CCNPP (l.c., those not in the CRS database) include internal panel wiring, equipment pigtails and terminal wiring, field installed jumpers, and some non-safety-related cabling. Cable insulation material types for CCNPP scheduled cables include: silicone rubber, ethylene propylene rubber (EPR), crosslinked polyethylene (XLPE), crosslinked polyoletin (XLPO), mineral, Kapton, polyvinyl chloride, Teflon, and other miscellaneous insulation types. In addition, CCNPP uses Tefzel insulated wiring as the currently approved safety-related internal wiring in the Main Control Boards. [ Reference 1, Section 1.1, Table 1-1, Table 1-3; Reference 2, Pages 4 6,4-7, 4 8,4-45,4-46,4-47; Reference 3J The conceptual boundary used to evaluate the CCNPP cables includes all site cables in the CRS database (i.e., all CCNPP scheduled cables). Unscheduled cables are drawn from the same reels of cable used for scheduled cables (except for some internal panel wiring that may be single conductor without jacket),

and are installed using the same installation standards and practices. Intemal panel wiring at CCNPP is not exposed to high temperatures or high radiation levels; therefore, aging which could affect the functionality of the wiring during the period of extended operation is not considered plausible.

Application for License Renewal 6.1- 1 Calvert Cliffs Nuclear Power Plant

ATTACilMENT m APPENDIX A - TECIINICAL INFORMATION 6.1 - CABLES Therefore, the results of the evaluation of scheduled cab:es are applicable to all types of CCNPP cabling that could be subject to plausible aging. [ Reference 1, Section 1.1]

Qocrating Nerienct The following historical operating experience is included to provide insight in supporting the aging management demonstrations provided in Section 6.1.2 of this report. This operating experience was obtained through key word searches of BGE's electronic database of information on the CCNPP dockets, through documented discussions with currently assigned cognirant CCNPP personnel, and through other

ources as indicated below.

Calvert C!iffs cable operating experience includes age related thermal degradation of cables in the Main Steam Isolation Valve rooms. These cables have been replaced as required through routine maintenance practices, in audition, excess heat was identified as a problem for the emergency diesel generator space heater wiring. This wiring has been replaced with high temperature wiring. Calveit Cliffs has also experienced vibnt!on induced loosening of some motor-operated valve terminations. This problem was resolved by replacement of the susceptible motor-operated valve terminations with bolted splices.

Thermal degradation of terminations for continuously run 4kV pump motors has also been observed at CCNPP. Corrective actions for the 4kV motor terminations bas included cutting cut the degraded portion of the onnecting cable and then re terminating the cable. The aging management for the 4kV motor terminations is discussed further in Section 6.1.2 of the BGE LRA. [ Reference 1, Section 4.4]

The NRC performed an Electrical Distribution System Functional Inspection at CCNPF in 1992. The inspectbn was performed to determine if the Electrical Distribution System was capable of performing its intended safety functions as designed, installed, and configured. Although the Elcctrical Distribution System Functional Inspection did not focus on cables, they are an integral pan of the Electrical Distribution System. The NRC concluded that the CrNPP Electrical Distribution System is capable of performing its ictended safety functions. [ Reference 4]

There is a vast wealth of industry operating experience relate.! to performance of electrical cables and cable terminations in nuclear power plants. Much of this information can be found in: NRC Information Notices l Dulletins, Circulars, Generic Letters, and Licensee Event Repons; the Institute for Nuclear Power Operations Nuclear Plant Reliability Data System; industry reports; and plant surveys. These sources of information were reviewed by Sandia Nationel Laboratories aa part of the preparation of Reference 2. Some of the generic observations / conclusions made in Reference 2 regarding historical performance of electrical cables and terminations include: [ Reference 2, Pages 3 53 through 3-55]

. The number of cable and termination failures during normal op~ating conditions (all voltage classes) that have occur ed throughout the industry L extremely low in proportion to the amount of cables and terndnations.

. Thermal aging and embrittlement of insulation is one of the most significant aging mechanisms for low-voltage cab!e. Thermal aging results from ambient temperature effects, ohmic heating (i.e., cable conduaor intemal heating), and localized heating effects (e.g., hot spots due to proximity to hot piping).

Application for Lictase Renewal 6.1-2 Calvert Cliffs Nuclear Power Plant wwr-

ATTACIIMENT m APPENDIX A - TECIINICAL INFORMATION 6.1 - CAHl.ES An industry report on the aging of cables concluded that cables are highly reliable under normal plant operating conditions, with no evidence that there is a significant increase in the failure rate due to aging.

'Ihe most safety-significant aging effects are those that havn the potential to lead to common cause failures during accident conditions. Some of the failure mechanbms that might occur include:

[ Reference 5, Pages 1,41; Reference 6)

. Degradation of cable Jacket and/or insulation that could create electrical paths to adjacent conductors (including other conductors in the same multi-conductor cable) or ground, resulting in electrical failure of the cable; and e Degradation of the cable insulation that reduces the insulation resistance (IR), which could be of concern for some instrumentation cables.

Scooed Structures and Comoonents and Their Intended Fanctions The conceptual boundary (i.e., all cables in the CRS database) includes cables which are covered by the CCNPP Environmental Qualification (EQ) Program (10 CFR 50.49), as well as non EQ cables. As discussed in Section 7.2.1.1 of the CCNPP IPA Methodology, structures and components subject to the EQ Program are associated with Time-Limited Aging Analyses that are evaluated separately. The EQ cables are evaluated in Section 6.3 of the DGE LRA.

Cables which satisfy either of the following conditions are considered to be within the scope of license renewal: [ Reference 1 Section 2.3)

. Any cable associated with a safety related load or a load whose failure could prevent operation of a safety function; and

. Any cable associated with equipment relied upon for response to *.he regulated events in Q54.4(a)(3) if the plant specific evaluation for these events requires such cables to supply power to the load as part of the event response. For example, cables supplying power to a load which is turned off during the response to a station blackout would not be included within the scope of license renewal. Cables providing diverse scram or diverse turbine trip signals in accordance with the anticipated transients without scram rule would be within the scope oflicense renewal.

For the purposes of this evaluation, all scheduled cables were initially assumed to be within the scope of license renewal without prescreening. If a set of non EQ cables otherwise subject to AMR were identified for which an age-related degradation mechanis .RDM) was determined to be plausible, then in-scope for license renewal screening was sometimes employed to determine if further evaluation was necessary, Cables were determined to be not within the scope oflicense renewal and excluded from further evaluation if they met any of the following conditions: [ Reference 1, Section 1.1, Page C-38]

= Cable schemes associated with systems having no bcense renewal ftmetions; e Cable schemes which are non safety-related and are associated with systems which do not support any non safety-related license renewal functions; e Cable schemes for annunciator circuits which do not support any events regulated under the License Renewal Rule [i.e.,10 CFR 54.5(a)(3)];

. Cable schemes which have been spared (i.e., no longer perform any function); or Application for License Renewal 6.1-3 Calvert Cliffs Nuclear Power Plant

ATTACHMENT (3)

APPENDIX A - TECHNICAL INFORMATION 6.1 - CABLES

• Cabic schemes which do not support a license renewal function as determined by specific examination of connection drawings and schematics.

The non EQ cable types within the scope of license renewal fiv the cables evaluation are indicated in Table 6.1 1. [ Reference 1. Table 13; Table 3 6]

The design beJs and associated loading conditions for the CCNPP clectrical systems (which include components such as cables) are descrit ed in UFSAR Section 8.1.1. All cables vital to plant safety are designated as Class IE so that the!r integrity is not impaired by the Safe Shutdown Earthquake, high winds, or disturbances in the external electrical system. (Reference 7, Section 8.1.1)

TABLE 6.11 NON EQ CAULE TYPES WITHIN THE SCOPE OF LICENSE RENEWAL FOR TIIE COMMODITY CAHLES EVALUATION Cable Power Control Instrumentation Insulation Service Scavice - Service

- Material Function Function Function -

Silicone Rubber 4500 7100 11500 _

EPR/XLPE/XLPO 1400 500 1700 Mineral 00 0 20 Kapton 0 0 20 l Miscellaneous 0 2 4

1. = Approximate number of CCNPP cable schemes Notes for Table 6.1-1:

1. All polydnyl chloride and Teflon insulated scheduled cables are associated with cable schemes wWh do not support any .acnse renewal functions. [ Reference 1 Table 1-1]

2. The number of cable schemes shown as within the scope of license renewal in each category is approximate to show the mix of non-EQ cables at CCNPP. Specific numbers of cables are available. [ Reference 1 Table 1-3; Table 3-6]

3. The miscellaneous insulation cables shown in the above table consist of (2) vendor supplied turbme supervisory (control) cables of unknown insulation material and (4) fiber optic (instrumentation) cables. These cables are not subjected to high temperatures or radiation which would result in plausible aging. [ Reference 1, Section 3.4]

4. All of the ..' an insulated cables are used in fire detection service in the containment. The function of these cables is to provide early detection of elevated temperatures in the cable trays.

These cables are part of the "Protectowire" instrumentation system. The Protectowire cables are installed around or on top of the cr.ble trays, and are designed such that the cable insulation melts and the conductors short-circuit if th; cable tray temperature at a specific location rises to approximately 280'F. The short-circuit decreases the resistance in the circuit proportional to the Application for License Renewal 6.1-4 Calvert Cliffs Nuclear Power Plant

FROM BGE/ pet) 'PAGE.003

. .DE h 9ft99 3(55 ATFAcIthEImrF (3)

' f--

)

APPENDEX A - T8,CHNICAL INFORMATION 6.1 - CAars.a __

lenoth of win between the point of the short and the power supply (i.e.,can determine die fire -1

% cation). C:7% of thew cables could potentially result in generation of falso fire alarms, ne function of the Kapton cables is designated u ' active" since the cables must changs state .

. (i.e., insutstion melting and conductors shotting) in (,nin to perform their function. As discussed in Section 5.1 of the CCNPP IPA Methodology, structures and components with active functions l are not subject to AMR.~ [Refotonee 8) .

5. Silicone rubber and minwal insulated cables am not subject to plausible aging. Mineral insulated cabin can be degraded by exposure to moisture. However, moisture esposure is a design consideration that is addressed by Raychem sleeving of the termination where deemed necessary.  !

For example, the minaal insulated cabling to the CCNPP Unit I ,a:_ --.'wi back up heaters is sleeved at the preuurizer. Non-EQ oabling is not requimd to function when exposed to harsh environments indcced by design basis accidents. (Reference I, Sections 3.1.6 and 3.1.7.1]

Pasaims Intended Functions / Cables Raquiring AMR As discussed above, cables are within the scope of license renewal because they support various plant elatrical corupnents which are required to perform the functions described in 554.4(a)(1),(2), and (3).

De scoping ptocess for cables did not evaluate specific passive versus active functions for each of the

- cables within the scope of license renewal; However, the following general passive functions may apply

- to cables, depending on their service: [Refwence 1, Page I-8]

L . Maintenance of dielectric stangth - (applies to most poww and control cables); and

. Malatenance of adequate IR (for non-coax) or impedance (for coax) - (applies to some instrumentation cables).

Section 7.2.1.2 of the CCNPP IPA Methodolog states that cables are passive and long lived. In addition, Section 5.1.1 of the methodology states that the passive function " prevent or isolate faults in an electrical circuit when such protection or isolation does not involve moving parts or a change in proporties or configuration" applies to cable insulation (this function relates directly to the maintenance -

of dielectric strength). Derefore, all cables within the scope of license renewal (as shown in Table 6.1 1) are also subject to an AMR (except for the Kapton insulated cables discussed in Table 6.1-1, Note 4, which have an active function). [ Reference 1, Table 1-3)

- 6.1.2 Aging Management The list of potential ARDMs for cables is given in Table 6.12, with plausibb ARDMs identified by a j check mark (/) in the appropriate column. For emciency in presenting the resuhs of these evaluations '

in this report, cable types /ARDM combinations are grouped where there are similar characteristics and the discussion is applicable to all cables within that group. Exceptions are noted where appropriate.

! - Table 6.12 also identifies the group assigned to each cable type /ARDM combination. De following .

i- proups have been selectedt (Reference 1, Section 3.1, Table 4-2]

Group I Includes thwmal aging for EPR/XLPF/XLPO non EQ cables in power and control service, t v bich are routed without maintained spacing. j l

Group 2 - locludes thwmal aging for EPR/XLPE non-EQ cables in power i,ervice, which are routed with maintained spacing. j l

Application for License Renewal 6.1 5 Calvert Cliffs Nuclear Power Plant I l

.. . . . - - - . _- _ _ _ a

ATTACilMENT 0)

APPENDEX A - TECIINICAL INFORMATION 6.1 - CABLES Group 3 - Includes synergistic radiative and thermal aging for EPR/XLPE non EQ cables in power service, which are routed inside containment.

Group 4 - Includes thermal aging for EPR non EQ cables in power service, associated with the Saltwater System and Service Water System 4kV pump motor terminations.

Group 5 Includes IR reduction for EPR/XLPE/XLP0 non EQ cables in instrumentation service, which are sensitive to reduction in cable IR.

Group 6 - Includes treeing for EPR non EQ cables in 4kV power service. As explained in the Group 6 Aging Management section below, trecing is n form of voitage-induced degradation thst causes hollow microchannels in the cable insulaticu to grow in a tree-like pattern.

Application for License Renewal 6.1-6 Calvert Cliffs Nuclear Power Plant

ATTACHMENT G)

APPENDIX A - TECHNICAL INFORMATION 6.1 - CABLES TABLE 6.1-2 POTENTIAL AND PLAUSIBLE ARDMs FOR CABLES Cable Insulation Matenals Potential A.RDMs ' Silicone' EPR AIEE XLPO Mineral . Kapton MisecIlanem.rs Not Plausible Rubber Mechanical Stress and x installation Dmnage Electncal Stress x Treeing Thermal Aging (1.2.4) (1.2) (1)

Synergistic 1hermal and / /

Radiative Aging (Note 2) (3) (3)

Kapton Specific Aging

• IR Reduction (Notes 1.2) / / /

(5) (5) (5)

/ - indicates plausible ARDM determination

(#)- indicates the group in which this structure and component /ARDM combination is evaluated Group Groun Characteristics 1 Power and Control - routed without maintained spacing 2 ' Power - routed with maintained spacing 3 Power- inside containment 4 Power - associated with the Saltwater System and Service Water System 4kV pump motor terminations 5 Instrumentation - sensitive to reduction in cable IR 6 Power - 4kV service Notes

1. Insulation Resistance Reduction is actually an aging effect rather than an ARDht

2. Radiation stress is included in synergistic thermal and radiative aging and IR reduction.

Application for License Renewal 6.1-7 Calvert Cliffs Nuclear Power Plant NRC97071

NITACIIMENT (3)

APPENDIX A - TECliNICAL INFORMATION 6.1 - CABLES l l

The following discussion of the aging management demonstration process is presented by group and covers riaterials and environment, aging mechanism effects, methods to manage aging, aging l management program (s), and demonstration of aging management.

Group 1 (Thermal aging for EPR/XLPE/XLPO non EQ embles in power and control servlee, which are routed without maintained spacing)- Materials and Environment i Group 1 consists of power and control cables with EPR, XLPE, or XLPO insulation. The power and ,

control cables at CCNPP have an insulation temperature rating of 90*C (194*F) or higher. [P-ference 1, Page 2 2]

The highest (non accident) ambient design temperature of any area in the plant that contains cabling is in the Main Steam Penetration Room. This room has a maximum design ambient temperature of 160'F.

[ Reference 1, Page 2-1]

The Group I cables are also subiect to ohmic heating, which can cause the cables to be exposed to a temperature environment hotter than the ambient temperature. Ohmic heating of a cable conductor is proportional to the square of the current carried by the conductor. Ohmic heating may be significant for energized power cables since they are designed to carry large currents. Ohmic heating is negligible foi control cables since they generally carry small currents. The Group I cables are routed without maintained spacing between individual cables within a cable tray. This installation method is also known as " random lay" or " random fill." Cables in,talled in this manner may be tightly packed together, thus not allowing natural air flow around the cables to dissipate heat. Ileat generated by an energized power cable conductor can transfer through the insulation of the energized cable and affect other cables (including the control cables) routed within the same raceway. Calvert Cliffs' cable installation practices (based on Insulated Power Cable Engineers Association [lPCEA] standards),

include cable ampacity derating factors designed to limit cable operating temperaturn to the cable insulation temperature rating of 90*C (194'F). The ampacity derating factors used at F NPP are based on exposure ofin service cables to a constant ambient temperature of 40 C (104'F). Since the maximum design ambien: temperature is 160'F (as discussed above), this raises the possibility that some cable operating temperatures may sometimes exceed the insulation temperature rating of 90 C (194 F).

Baltimore Gas and Electric Company has developed a temperature survey program to establish an upper bound on the operating service temperatures for the Group I cables. These temperature surveys will determine if the insulation temperature rating is being exceeded (details on the temperature survey program are provided in the " Aging Management Program" section below). [ Reference 1, Pages 1-7, 2 2,3 12, B-15, B-21; Reference 9, Page 962; References 10 through 15]

In addition to the ambient and ohmic heating effects, the temperature environment for cables may potentially be affected by localized heating effects. Localized heating effects could be experienced by cables in close proximity to sources of heat, such as hot piping. [ Reference 2, Pages 4-8,4-9]

Application for License Renewal 6.1-8 Calvert Cliffs Nuclear Power Plant NRC97071

ATTACIIMENT 0)

..PPENDIX A - TECIINICAL INFORMATION 6.1- CABLES Group 1 (Thermal aging for EPR/XLPF/XLPO non EQ cables in power and control service, whleh are routed without maintained spacing). Aging Mechanism Effects

'the Group I cables may be subject to thennal stress resulting from ambient, ohmic, and localized heating effects as discussed above. Elevated temperature produces some degree of aging in mos organic materials. Organic subcomponents typically used in the construction of power and control cables include the outer cable Jacket and the conductor insulation. Thermal aging produces changes in the organic material properties, including reduced elongation, variations in tensile strength, loss of antioxidant, and loss of plasticizer. Visual indications of thermal aging may include embrittlement, cracking, discoloration, and melting of the jacket and insulation. The potential efTects to the jacket due to these degradations include reduced mechanical integrity and protection from the environment. The potential effects to the insulation due to these degradations include reduced IR, naise, changes in flammability, and electrical failure. (Reference 2. Section 4.1,1, Table 4-1 Table 4-13; Reference 16, Page 3 2]

Jackets ve intended to prov de physical protection to the cable insulation during installation and use The Jacket provides no necessary electrical isolation function for power and control service. Therefore, degradation of the Jack ' is not considered significant in maintaining the passive intended function to prevent or isolate faults in an electrical circuit. Nuclear Regulatory Commission Information Notice 92 81 describes a potential aging concern for electrical cables with bonded Ilypalon jackets.

Environmental qualification testing for these type of cables resulted in Jacket cracking that propagated through the EPR conductor insulation. Ilowever, the cracks did not prevent the cables from passing an insulation resistance test that was conducted in a dry environment (cables only failed after being subjected to a loss-of coolant accident test). Therefore, the issues presented in Information Notice 92 81 are not considered to be an aging concern for non-EQ cables. flypalon Jackets bonded to underlying EPR insulation is in limited use at CCNPP. (Reference 16, Pages 3 8,3 9,415; Reference 17]

Cable insulation provides the primary electrical isolation between the conductor and the external environment. The electrical isolation provided by the insulation is important for power, control, and instrumentation service, Cable inselation is a dielectric material (i.e., a nonconductor of electricity). A critical characteristic of the insulation that must be maintained in order to provide its isolation function is its dielectric strength (i.e., its ability to withstand electric stress before breakdowc or electrical discharge r

through the insulation occurs). The higher the dielectric strength of a material, the better insulator it is.

Therefore, degradation of the insulation (which can result in the electrical failure of the insulation) is consklered significant in maintaining the passive intended function to prevent or isolate faults in an electrical circuit. (Reference 1, Pages 18, I-9; Reference 16, Pages 3-6, 3-8; Reference 18, Page 9; Reference 19, Page 460]

For each cable insulation material type, CCNPP has de; ermined a 60-year service limiting temperature.

The serse limiting temperature is the maximum continuous service temperature for which cable life will be not less than 60 years. The 60-year service limiting temperature was determined based on Aahenius analysis of database information for cable insulation materials using the methodology ofIEEE Standard 101-1987, "lEEE Guide for the Statistical Analysis of Thermal Life Data." The database

(" System 1000" database - currently part of the Equipment Qualification Data Bank managed by NUS Information Services, Inc.) contains information on time to failure versus temperature for many organic materials. The calculation of the 60-year service limiting temperatures included the selection of a data set from System 1000 for each insulation material for insulation properties associated with dielectric Applicatio$ for License Renewal 6.1-9 Calvert Cliffs Nuclear Power Plant NRC97071

ATTACHMENT m APPENDIX A - TECilNICAL INFORMATION 6.1 - CABLES failure or retention of elongation. When System 1000 contained more than one set of data. then a conservative selection was made. [ Reference 1. Pages 311, B 18, B 19]

The Arrhenius model relates the rae of degradation (reaction) to temperature through a mathematical function that uses the materials' activadon energy. He activation energy is a measure of the energy required to produce a given type of endothermic reaction within the material. This parameter can be correlated to the rate of degradation; that is, materials with higher activation energies will thermally degrade at a slower rate than those with lower activation energies. [ Reference 2, Section 4.1.1.1.2]

For XLPE, BGE used the lowest activation energy associated with the dielectric failure data in System 1000. For XLPO, an activation energy equal to half the difference between the lowest and median values was selected from the available (11) data sets. The data sets were based on 100%

retention of elongation. n characteristic proviaes a high level of margin to dielectric failure since changes in mechanical properties of cable insulation material precede changes in electrical characteristics. Therefore, the selection of a low, but not the lowest, activation energy was considered justinable. For EPR, the lowest activation energy in the availatte (20) data sets was 1.05eV. An activation energy of 1.06eV was chosen since this corresponds to Kerite (EPR) material used at CCNPP.

The EPR data sets were based on 20% retention of elongation. Similar to the discussion for XLPO above, for EPR the selection of a low, but not the lowest, activation energy was considered justifiable since changes in mechanical properties precede changes in electrical properties. [ Reference 1, Page 3-11]

Using the process and data described above, the service limiting temperatures were determined to be 184'F for EPR,182'F for XLPE, and 189'F for XLPO insulation. [ Reference 1. Page 3 11]

If the cable service temperature (i.e., actual operating temparature) is less than the 60-ycar service limiting temperature for the insulating material, then thermal aging is not p!ausible (i.e., aging will not progress to abnctional failure), if the cable service temperature does or might exceed the 60-year service limiting temperature, then thermal aging is considered plausible and the insulation could be subject to significant dielectric degradation during the period of extended operation. [ Reference 1, Page 2 2]

A margin of 10*C (18*F) is used when these 60-year service limiting temperatures are applied as an

" aging management required" screening criteria. For example, if the service temperature for a XLPE insulated cable exceeds 164'F (i.e., service limiting temperature of 182 F minus the 18 F margin), then aging management is required. The selection of a conservative data set and the use of the 10 C margin introduces suf0cient robustness in the screening process to ensure that no cables needing aging management are excluded. [ Reference 1, Page 4 3]

Since thermal aging can result in breakdown of the dielectric strength of the insulation, this aging mechanism, if unmanaged, could eventually lead to loss of the passive intended function to prevent or isolate faults in an electrical circuit under current licensing basis (CLB) conditions. Therefore, thermal aging was detennined to be a plausible ARDM for which aging effects must be managed for EPR/XLPE/XLPO non-EQ cables in power and control service, which are routed without maintained spacing, and whose service temperature does or might exceed the 60-year service limiting temperature for the respective insulation material type. [ Reference 1, Table 4 2]

Application for License Renewal 61 10 Calvert Cliffs Nuclear Power Plant NRC97071

ATTACHMENT G)

APPENDIX A - TECIINICAL INFORMATION 6.1 - CABLES Group I (Thermal aging for EPR/XLPF/XLPO non-EQ cables in power and control service, whleh are routed without maintained spacing)- Methods to Manage Aging htigntion: Since the degradation of the Group 1 cables is due to the effects of thermal stress resulting from ambient, ohmic, and localized heating efTects, decreasing the service temperatures experienced by the cables could mitigate the thermal aging effects. Decreasing the service 9mperatures would slow the degradation and could be acccmplished by reducing amblent temperatures (e.g., increasing heating, ventilation, and air conditioning system (s) cooling capacity), rerouting the cables through lower ambient temperature areas, reducing the amount and/or time current is carried through the power cables (e.g., replacement of an existing motor with another motor having lower load requirements, or changing procedures to operate a pump for less time), rerouting the cables in trays with maintained spacing, and rerouting the cables away from local heat sources. Of the above methods, only the various cable resauting options are considered feasible methods of mitigating the thermal aging efTects.

Dinoscry; Since thermal aging was only determined to be plausible for the Group 1 cables whose service temperature does or might exceed the 60-year service limiting temperature for the respective insulation material type, measurement of actuct operating service temperatures in the cable raceways could be used to discover if any of the service limiting temperatures are being exceeded. Alternative'y, if the temperature rise due to ohmic heating can be calculated, then a calculated cable service temperature (based on a calculated ambient temperature limit and the calculated ohmic heating effect) for a 60-year cable life can be used in lieu of taking actual temperature measurements. Tha calculated ambient temperature limit would be . qual to the service limiting temperature for the respective insulation material minus the temperr.ture increase due to ohmic heating. The calculated cable service temperature would be equal to the ambient temperature limit plus the ohmic heating effect. Ilowever, an analytical assessment of the ohmic heat rise for the random-lay trays at CCNPP has not proven to be practical.

Therefore, only actual temperature measurements are a feasible method to discover if any of Se service limiting temperatures are being exceeded. [ Reference 1, Pages 3-12, B-15, B 21]

If any of the service limiting temperatures are being exceeded (as discovered by measurement of the actual operating service temperatures), additional activities (e.g., analysis, monitoring, testing) would need to be performed in order to assess the thermel aging that does occur. These activities would ensure that cables are replaced prior to degradation of the insulation that could compromise the passive intended function (i.e., prevent or isolate faults in an electrical circuit). (Reference 1, Pages 4-1, F-2]

Group 1 (Thermal aging for EPR/XLPE/XLPO non-EQ embles in power and control service, which are routed without maintained spacing)- Aging Management Program (s)

Mitigation: Tc, mitigate the effects of thermal aging, the Group I cables can be rerouted, as deemed appropriate, as a result of the corrective actions taken per the Age-Related Degradation Inspection (ARDI) program described below.

Discoiety; To manage the effects of thermal aging for the Group I cables, a new plant program will be developed to provide monitoring, testing, or analysis (or an appropriate combination thereof). The program is considered an ARDI program as defined in the CCNPP IPA Methodology (Section 2.0 of the BGE LRA). The purpose of the Cables ARDI program is to determine if plausible aging could Application for License Renewal 6.1-11 Calvert Cliffs Nuclear Power Plant NRC97071

AffACllMENTJ)

APPENIHX A . TECilNICAL INFORMATION 6.1. CAHLES potentially progress to cable failure such that ongoing aging management is required to be implemented.

[ Reference 1, Pages 41,4 2,17 2)

'the Cables ARDI program will include the elements listed below. Some of the elements have already been completed and are so noted. [ Reference I, Pages 41,4 2, F 2) e Ranking all 480V power service cable tr,iy: by using a heat transfer model which takes into consideration the circuit loads, ambient temperatures, cable mass, fire barriers, and tray covers.

(Completed)

J e identifying cable trays near significant external radiant heat sources (i.e.,locallred heating effet th) such as hot pipes. (Completed) l

• Analyzing the results of the tray ranking and external radiant heat sources and selecting thermal survey locations. (Completed)

• Performing a thermal sun cy of candidate " hot" tray locations and external radiant heat sources to find " bounding" locations for long term te.nperature monitoring. (Partially Completed) e Installing teq erature probes at " bounding" locations. (Partially Completed)

. Collecting temperature data over sufficient time to capture peak cable service temperatures (i.e., determine upper b:und of serv!:e trmperatures for the Group I cables).

• Con paring peak cable service temperatures against the 60 year service limiting temperature for the applicable insulation materials. 'the 60 year service limiting temperatures are considered the acceptance criteria for this ARDI.

e if any of the service limiting temperatures are exceeded (i.e., acceptance criteria not met),

generate an issue Report (per Reference 20) and determine the appropriate corrective action (i.e., ongoing aging manage:nent). Corrective action may include one or a combination of the following ilms:

1. Rerouting esble such inat service limitinF tempratures will not be exceeded;

2. Analysis to detrimine a cable replacement date;

3. Visual or physical inspection (for detection of embrittlement, cracking, discoloration, and melting);

4 Pulling c Sie samples for testing of chemical, mechanical, or electrical properties (e.g.,clongation, dielectric strength) and subsequent replacement and repair of the tested cable sections;

5. Cable condition monitoring (l.c., in situ non destructive testing); or

6. Replacement of cabh.

Items 3,4, and 5 above will include acceptr.nce criteria to trigger cable replacement prior to degradation that would preveat the cable from performing its intended function if any of the acceptance criterit sre not met, an issue Report would tm generated, per Reference 20, to document the degraded condition and the required corrective nctions (i.e., cable replacement).

Application for License Renewal 6.1 12 Calvert Clifts Nuclear Power Plant NRC97071 -

ATTACHhirNT m APPENDIX A TECHNICAL INFORMATION 6.1 CAHLES Cable condition monitoriq is presently considered an optional approach to ongoing cable management.

llowever, it does not have industry consensus or regulatory acceptan e as a means of establishing cable residual life. Italtimore Gas and Electric Company considers condition monitoring to be a viable alternative and will monitor research in this area through Electric Power Research Institute (EPRI) and Nuclear Energy Institute (NEI) to develop this aspect of the aging management progr am accordingly.

1he corative actions taken as a resuh of the Cables ARDI program will ensure that the Gnup I cables remain capable of performing their intended function to prevent or isolate faults in an electrical circuit under all CLil conditions.

Group I (Thermal aging for EPR/XLPE/XLPO non EQ cables in power and control sendwhich are routed without maintained spacing). Demonstration of Aging Management liased on the factors presented above, the following conclusions can be reached with respect to thermal aging for EPR/XLPF/XLPO non EQ cables in power and control service, which are routej without maintained spacing:

e lhe Group I cables provide the passive intended function to prevent or isolate faults in an  ;

electrical circuit under CLil conditior's.

. Thennal aging is plausible for the Gioup I cables that are subject to senice temperatures greater than their service limith.g temperatures, causing a breakdown of the cable insulation dielectric strength, which could eventually lead to electrical failure of the insulation and loss of the function to prevent or isolate faults in an electrical circuit under CLH conditions, e The CCNPP Cables ARDI program will determine if plausible aging couV potentially progress to cable failure, such that ongoing aging management is required to be implemented. The program will also contain acceptance criteria that ensure corrective actions will be taken, such that there is reasonable assurance that the prevention or isolation of faults in an alectrical circuit function will be maintained.

Therefore, there is reasonable assurance that the effects of thermal aging will be managed in order to maintain the function to prevent or isolate faults in an elec'rical circuit as provided by the Group I cables, consistent with the CLB, during the period of extended operation, Group 2 (Thermal aging for EPR/XLPE non EQ cables in power service, which are routed with maintained spacing) . Materials and Environment Group 2 consists of power cables with EPR or XLPE insulation. The power cables at CONPP have an insulation temperature rating of 90*C (194'F) or higher. [ Reference 1 Page 2 2)

The highest (non accident) ambient design temperature of any area in the plant that contains cabling is in the Main Steam Penetration Room. This room has a maximum design ambient temperature of 160'F.

. [ Reference 1. Page 2 1).

The Group 2 cables are also subject to chmic heating effects, which can cause the cables to be exposed to a temperature environment hotter than the ambient temperature. Ohmic heating of a cable conductor is proportional to the square of the current carried by the conductor. Ohmic heating may be significant for l

Application for License Renewal 6.1 13 Calvert Clifts Nuclear Power Plant NRC97071

. _ r ,_ _ - _ _ _ . . _ _ _ _ , _ _ _ _ __ _ ,- -_.-.._.___ _ __

ATTACllMENT 0)

APPENDIX A TECHNICAL INFORMATION 6.1 - CAHLES energized power cables since they are designed to carry large currents. The Group 2 cables are routed with maintained spacing between individual cables within a cable tray. Cables installed in this manner -

are separated by a specified percentage of cable diameters, thus allowing natural air flow around the cables to dissipate the heat. lleat generated by an energized power cable conductor can transfer through ,

the insulation of the energired cable and affect other cables routed within the same raceway. Calven Cliffs' cable installation practices (based on IPCEA standards) include cable ampacity derating factors designed to limit cable operating temperatures to the cable insulation temperature rating of 90'C (194T). The ampacity derating factors used at CCNPP are based on exposure of in service cables to a constant ambient temperature of 40'C (104'F). Since the maximum design ambient temperature is ,

160T (as discussed above), this raises the possibility that some cable operating temperatures may sometimes exceed the insulation temperature rating of 90'C (194T). Ilowever, BGE has performed analysis to verify that none of the operating temperatures for the Group 2 cables exceed the 90'C insulation rating. [ Reference 1. Pcges 17,2 2,312, B IS, B 21; Reference 9, Page 962; References 10 through 15]

In addition to the ambient and ohmic heating effects, the temperature environment for cables may potentially be affected by localized 1 eating effects. Localized heating effects could be experienced by cables in close proximity to sources of heat such as hot piping. (Reference 2, Pages 4 8,4 9]

Group 2 (Thermal aging for EPR/XLPE non EQ cables in power senlee, which are routed with maintained spacing). Aging Mechanism Effects The Group 2 cables may be subject to thermal stress resulting from ambient, ohmic, and locallred he.ating efTects as discussed above.1hc aging mechanisms, resultant aging effects, and the plausibility concerns for the Group 2 cables are the same as for the Group I cables. Therefore, degradation of the cable insulation dielectric strength (which can result in the electrical failure of the insulation) is considered significant in maintaining the passive intended function to prevent or isolate faults in an electrical circuit. [ Reference 1, Pages 18,19]

As discussed in the Group 1 Aging Mechanism Effects section, the 60-year service limiting temperatures were determined to be 184T for EPR and 182T for XLPE insulation. If the cable service temperature (l.c., actual operating temperature) is less than the 60 year service limiting temperature for the insulating material, then thermal aging is not plausible (l.c., aging will not progress to functbnal failure). If the cable service temperature does or might exceed the 60 year service limiting temperature, then thermal aging is considered plausible and the insulation could be subject to significant dielectric degradation ,

during the period of extended operation. [ Reference I, Pages vil,2 2,311)

Since thermal aging can result in breakdown of the dielectric strength of the insulation, this aging mechanism, if unmanaged, could eventually lead to loss of the passive intended function to prevent or isolate faults in an electrical circuit under CLB conditions. Therefore, thermal aging was determined to be a plausible ARDM for which aging effects must be managed for EPR/XLPE non EQ cables in power service, which are routed with maintained spacing, and whose service temperature does or might exceed the 60 > car service limiting temperature for the respective insulation material type. (Reference 1,

'Iable 4 2]

i j - Application for License Renewal 6.1 14 Calvert Clifts Nuclear Power Plant l NRC97071 l

l - . _ _. _ __ _ _ _

AITACilMl'NT 0)  !

APPENDIX A TECliNICAL INFORMATION 6.I . CAllLES i

Group 2 (Thermal aging for EPR/XLPE non EQ embles in power ser lee, which are routed with ,

maintained spacing). Methods to Manage Aging Mitiption; The feasible methods of mitigating thermal aging for the Group 2 cables are the same as discussed above for the Group 1 cables (i.e., rerouting of cables such that service temperatures are decreased).

Dhsnitty: Since thermal aging was only determined to be plausible for the Group 2 cables whose service temperature does or might exceed the 60 year service limiting temperature for the respective insulation material type, analysis of the cable routing (including calculation of cable operating service

, temperatures in the cable raceways) could be used to discover if any of the service limiting temperatures are being exceeded. The cable service temperature could be calculated as described in the Group 1, Methods to Manage Aging section above. (Reference 1. Pages 4 2,iblS,1121]

If any of the service limiting temperatures are being exceeded (as discovered by the cable rou g analysis), additional activities (e.g., analysis, monitoring, testing) would need to be performed in order ,o assess the thermal aging that does occur 1hese activities would ensure that cables are replaced prior to degradation of the insulation that could compromise the passive intended functien (i.e., prevent or isolate faults in an electrical circult) (Reference I, Pages 41. F 2]

Group 2 (Thermal aging for EPR/XLPE non EQ embles in power service, which are routed with maintained spacing). Aging Management Program (s)

Midgation: To mitigate the effects of thermal aging, the Group 2 cables can be rerouted, as deemed ,

appropriate, as a result of the corrective actions taken per the ARDI program described below.

Discatcry: To manage the effects of thermM aging for the Group 2 cables, a new plant program will be developed to provide monitoring, testing, or analysis (or an appropriate combination thereof). The program is considered an ARDI program as defined in the CCNPP IPA Methodology (Sectbn 2.0 of the 110E 1.RA). The purpose of the Cables ARDI program is to determine if plausible aging could 4

potentially progress to cable failure such that ongoing aging management is required to be implemented.

4 (Reference 1. Pages 41, F 2) 1he Cables ARDI program will include the following elements: [ Reference 1. Pages 41,1122, F 2]

e Performing a routing and ohn

• heat rise analysis in order to determine the cable service temperatures. The routing analysis determines the maximum bulk ambient temperature to which the cable is exposed. The ohmic heat rise is calculated using the computational method established by Reference I to IPCEA Standard P 46 426.

• Comparing calculated cable service temperatures against the 60 year service limiting temperature for the applicable insulation materials. 'the 60 year service limiting temperatures are considered the acceptance criteria for this ARDI.

e if any of the service limiting temperatures are exceeded (i.e., acceptance criteria not met),

generate an issue Report (per Reference 20) and determine the appropriate corrective action  ;

, (l.c., ongoing aging management). Corrective action is the same as for Group 1 and may include one or a combination of the following items:

Application for License Renewal 6,1 15 Calvert Cliffs Nuclear Power Plant NRC97071

ATTACllM6fn' fM APPENDIX A TECHNICAL INFORMATION 6.1 CAllLES

1. Rerouting cable sach that service limiting temperatures will not be exceeded;

2. Analysis to determine a cable replacement date;

3. Visual or physical inspection (for detection of embrittlement, cracking, discoloration, and melting);

4. Pulling cable samples for testing of chemical mechanical, or electrical properties (e.g., Elongation, dielectric strength) and subsequent replacement and repair of the tested cable sections;

$. Cable condition monitoring (i.c., In. situ non destructive testing); and

6. Replacemerit i cable, items 3,4, and 5 above will include acceptance criteria to trigger cable replacement prior to degradation that would prevent the cable from performing its intended function. If any of the acceptance criteria are not met, an issue Report would he generated, per Reference 20, to document the degraded condition and the required corrective actions (i.e., cable replacement).

Cable condition monitoring is presently considered an optional approach to ongoing cable management llowever, it does not have industry consensus or regulatory acceptance as a means of establishing cable residual life. Baltimore Oas and Electric Company considers condition monitoring to be a viable alternative and will monitor research in this area through EPRI and NEl to develop this aspect of the aging management program accordingly.

The corrective actions taken as a result of the Cables ARDI program will ensure that the Group 2 cables remain capable of performing their intended function to prevent or isolate faults in an electrical circuit under all CLH conditions.

Group 2 (Thermal aging for EPR/XLPE non EQ cables in power service, whlch are routed with maintained spacing)- Demonstration of Aging Management Based on the factors presented above, the following conclusions can be reached with respect to thermcl aging for EpR/XLPE non-EQ cables in power service, which are routed with maintained spacing:

• The Group 2 cables provide the passive intended function to prevent or isolate faults in an electrical circuit under CLD conditions, e Thermal aging is plausible for the Group 2 cables that are subject to service temperatures greater than their service limiting temperatures, causing a breakdown of the cable insulation dielectri:

strength, which could eventually lead to electrical failure of the insulation and loss of the function to prevent or isolate faults in an electrical circuit under CLB conditions, e The CCNPP Cables AttDI program will determine if plausible aging could potentially progress to cable failure, such that ongoing aging management is required to be implemented. iihe program will also contain acceptance criteria that ensure corrective actions will be taken, such that there is reasonable assurance that the prevention or isolation of faults in an electrical circuit function will be maintained.

Application for License Renewal 6.1 16 Calvert Cliflis Nuclear Power Plant

- NRC97071

~. , . . - -- , . - - . - - - - - - - .

r A1TACllMENT (3)

APPENDIX A TECilNICAL INFORMATION 6.1 CAllLES Therefore, there is reasonable assurance that the effects of thennal aging will be managed in order to maintain the function to prevent or isolate faults in an electrical circuit as provided by the Group 2 cables, consistent with the CLI), during the period of extended operation.

Group 3 (Sy nerg itic radiative and thermal aglag for EPR/XLPE non EQ cables la power senlee, whieb are routed lantde contalement) Materials and Environment Group 3 consists of power cables inside containment with EPR or XLPE insulation. De power cables at CCNPP have an insulation temperatnre rating of 90'C (194'F) or higher. [ Reference 1, Page 2 2) ne maximum normal ambient temperature in the containment is 120'F. De normal general background radiation level is I rad / hour (although may it be higher in some locations). [ Reference 21 Section 5.4.A]

The Group 3 cables may also be subject to ohmic heating and localized heating effects as previously discussed in Groups I and 2. [ Reference 1, Pages 17,2 2,312,1115,1121; Reference 2, Pages 4 8, 49]

.c m Group 3 (Synergistic radiative and thermal aging for EPRMLTATQ embles in power service, which are routed inside containment)- Aging Mechanism Effects Since the Group 3 cables are located inside containment, they are subject to ndiation strese in addition to thermal stress, ne lowest radiation dose required to produce a 25% change in clongation for the polymers used in fabricating cables for CCNPP, with the exception of Teflon, is 7E06 rads.

[ Reference 22, Figure 3 3, Figure 3 7 Page 11175] As noted previously, all Tenon insulated cables are associated with cable schemes which do not support any license renewal functions. Changes in electrical properties lag behind the chamjes in mechanical properties. Therefore, no observable change in dielectric strength is exrected at doses of 7E06 rads or lower. The maximum non accident dose for CCNPP for 40 years is s lE06 rads, as determined from radiation data collected over the Orst twenty years of plant operation. Extrapolating to 60 years results in a maximum non accident dose of 1.5E06 rads. Comparison of the maximum 60 yeu non accident service dose to the 7E06 threshold for the polymers in service at CCNPP, results in the conclusion that the effects of radiation on non EQ cables at CCNPP oser 60 years is considered insignificant, llowever, EPR on XLPE insulated cables in power service inside containment may be affected by synergistic thermal and radiative aging. Synergistic thennal and radiative aging must be considered when both aging mechanisms are active and at least one may be significant, lloth of these cable types are subject to plausible thermal aging when used in power service, therefore, synergistic thermal and radiative aging is plausible for the EPR and XLPE power cables inside containment. [ Reference 1, Pages 3 2,4 4; Reference 2, Page 5-4)

Radiation induced degradation of organics (e.g., cable jacket and insulation) produces changes in the

-organic material propenies, including reduced clongation and changes in tensile strength. Visible indications of radiative aging may include embrittlement, cracking, discoloration, and swelling of the jacket and insulation. The potential effects to the jacket due to these degradations include reduced-mechanical integrity and reduced protection from the environment. The potential effects to the insulation due to these degradations include reduced IR, changes in flammability, and electrical failure.

{ Reference 2, Page 4 46 Table 413]

Application for License Renewal _6.1 17- Calvert Cliffs Nuclear Power Plant l NRC97071

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ATTACllMENT (3)

APPENI)lX A - TECIINICAL INFORMATION 6.1 CAHLES The aging mechanism and resultant aging effects for the Group 3 cables relative to thermal aging are the same as for the Group I cables.

"Ihe functions of the jarket and insulation for the Group 3 cables are the same as for the Group 1 cables.

Therefore, degradation of the cable insulation dielectric strength (which can result in the electrical failure of the insulation) is considered significant in maintaining the passive intended function to prevent or isolate faults in an electrical circuit. [ Reference 1, Pages 18,19]

Since synergistic thennal and radiative aging can result in breakdown of the dielectric strength of the insulation, this aging mechanism, if unmanaged, could eventually lead to loss of the passive intended function to prevent or isolate faults in an electrical circuit under CLil condit ions. Therefore, synergistic thermal and radiative aging was detennined to be a plausible ARDM for which aging efTects must be managed for EPR/XI.PE non EQ cables in power service, which are routed inside containment.

[ Reference 1. Table 4 2)

Group 3 (Synergistic radiative and thermal aging for EPR/XLPE non EQ cables in power service, which are routed inside containment)- Methods to Manage Aging Mitigation: Since all the Group 3 cables are inside containment, there are no feasible means of reducing the cable service temperature or to reduce the cifects due to radiation. Therefore, there are no methods deemed necessary to mitigate the effects of synergistic radietbe and thermal aging for the Group 3 cables.

Marm The effects of synergistic radiative and thennal aging that do occur can be discovered through a combination of analysis, monitoring, and testing. These activities would ensure that cables are replaced prior to degradation of the insulation that could compromise the passive intended function (i.e., prevent or isolate faults in an electrical circuit). [ Reference 1. Pages 4 1, F 2]

Group 3 (Synergistic radiative and thermal aging for EPR/XLPE non EQ cables in power service, which are routed inside containment) Aging Management Program (s)

Mitigation: Since these are no methods deemed necessary to mitigate the effects of synergistic radiative and thermal aging for the Group 3 cables, there are no programs credited with mitigation of these effects.

Mmsm To manage the effects of synergistic radiative and thermal aging for the Group 3 cables, a new plant program will be developed to provide monitoring, testing, or analysis (or an appropriate combination thereof). The program is considered an ARDI program as defined in the CCNPP IPA Methodology (Section 2.0 of the BGE I.RA). The purpose of the Cables ARDI program is to determine if plausible aging could potentially progress to cable failure such that ongoing aging management is requhrd to be implemented. [ Reference 1, Pages 4 1, F-2]

The Cables ARDI program will include the following elements as appropriate: [ Reference 1, Pages 4 1, F2)

. Analysis to determine a cable replacement date; Application for License Renewal 6.1 18 Calvert Cliffs Nuclear Power Plant l; NRC97071 L

ATTAcitMENT m APPENDIX A TECHN%'AL INFORMATION 6' LAHLES I i

e Visual or physical inspection (for detection of embrittlement, cracking, discoloration, melting,  ;

and swelling);

• Pulling cable samples for testing of chemical, mechanical, or electrical properties (e.g.,clongation, dielectric strength) and subsequent replacement and repair of the tested cable -

sections; e Cable condition monitoring (i.e., in situ non-destructive testing); and

. Replacement of cable.

Visual or physical inspection, pulling cable samples for testing, and cabic condition monitoring will include acceptance criteria to trigger cable replacement prior to degradation that would prevent the cable from performing its intended function, if any of the acceptance criteria are not rnet, an lasue Report would be generated, per Reference 20, to document the degraded condition and the required corrective actions (i.e., cable replacement).

Cable condition monitoring is presently considered an optional approach to ongoing cable mars.gement, llowever, it does not have industry consensus or regulatory acceptance as a means of establishing cable residual life. llattimore Gas and Electric Company considers condition monitoring to be a viable alternative and will monitor research in this area through EPRI and NEl to develop this aspect of the aging management program accordingly.

The corrective actions taken as a result of the Cables ARDI program will ensure that the Group 3 cables remain capable of performing their intended function to prevent or isolate faults in an electrical circuit under all CLB conditions.

Group 3 (Synergistic radiatise and thermal aging for EPR/XLPE non EQ embles in power servlee, w hieb are muted inside containment) 1)emonstration of Aging Management Based on the factors presented above, the following conclusions can be reached with respect to synergistic radiative and thermal aging for EPR/XLPE non EQ cables in power service, which are routed inside containment:

• The Group 3 cables provide the passive intended function to prevent or isolate faults in an electrical circuit under CLH conditions. ,

e Synergistic radiative and thermal aging is plausible for the Group 3 cables, causing a breakdown of the cable insulation dielectric strength, which could eventually lead to electrical failure of the insulation and loss of the function to prevent or isolate faults in an electrical circuit under CLB conditions, e The CCNPP Cables ARDI program will determine if plausible aging could potentially progress to cable failure, such that ongoing aging management is required to be implemented, The program will also contain acceptance criteria that ensure corrective actions will be taken, such that there is reasonable assurance that the prevention or isolation of faults in an electrical circuit function will be maintained.

Application for License Renewal 6.1 19 Calvert Cliffs Nuclear Power Plant NRC97071

ATTACHMENT 0)

APPENDIX A . TECHNICAL INFORMATION 6.1 - CAHLES Therefore, there is reasonable assurance that the effects of synergisth cadiative and thermal aging will be managed in order to maintain the function to prevent or isolate faults in an electrical circuit as provided by the Group 3 cables, consistent with the CLD, during the period of extended operation.

Group 4 (Thermal aging for EPR non EQ cables in power service, associated with the Saltwater System and Service Water System 4kV pump motor te'/minations) Materials and Environment Group 4 consists of power cables with EPR insulation which are associated with the Saltwater System and Service Water System 4kV pump motor terminations. He power cable for each of the pump motors  ;

is routed from the power source, via conduits and trays, to a junction box on the pump motor which contains the motor leads. %c power cable is bolt spliced to the motor leads in this junction box. He bolted splice is wrapped with Insulating tape. [ Reference 23]

ne portions of the cables that are subject to aging management (i.e., the motor terminations) are located in the intake Structure Pump Room (for Saltwater System pump motors) and in the Service Water Pump Room. He cables in these areas are subjected to localized heating effects due to their close proximity to the pump motors. [ Reference 7, Figures 114,1$,130]

The nonnal maximum temperatures are 104'F in the intake Structure Pump Room and ll3'F in the Service Water Pump Room. [ Reference 21, Pages $1, $3,63]

Group 4 (Thermal aging for EPR non EQ cables in power service, associated with the Saltwater System and Senice Water System 4kV pump motor terminations)- Aging Mechanism E& cts

%ennal degradation of organic material (i.e., cable jacket and insulation) is considered plausible for cable terminations on continuously run 4kV motors which are within the scope of license renewal (i.e.,thennal degradation is due to heat generated by motor operation). The Saltwater System and Service Water System pump motors are the only continuously run 4kV motors determined to be within the scope of license renewal. ne portion subject to thermal aging consists of the cabling in close proximity to the pump motors. [ Reference 1, Page 4 5; Reference 2, Table 413]

The aging mechanism and resultant aging effects for the Group 4 cables relative to thermal aging are the same as for the Group I cables. The functions of theJacket and insulation for the Group 4 cables are the same as for the Group I cables. Therefore, degradation of the cable insulation dielectric strength (which can result in the electrical failure of the insulation) is considered significant in maintaining the passive intended function to prevent or isolate faults in an electrical circuit.

Since thennat aging of the insulation can result in breakdown of the dielectric strength of the insulation, this aging mechanism, if unmanaged, could eventually lead to loss of the passive intended function to prevent or isolate faults in an electrical circuit under CLU conditions. Therefore, thermal aging was detennined to be a plausible ARDM for which aging effects must be managed for EPR non EQ cables in power service, associated with the Saltwater System and Service Water System 4kV pump motor tenninations. [ Reference 1. Pages 4 5, F 2]

Application for License Renewal 6.1 20 Calvert Cliffs Nuclear Power Plant NRC97071

ATTACHMENT (M  ;

APPENDIX A - TECHNICAL INFORMATION 6.1 - C4HLES Group 4 (Thermal aging for EPR non EQ cables in power senice, associated with the Saltwater System and Service Water System 4kV pump motor terminations) Methods to Manage Aging hiitigation: Since the degradation of the Group 4 cables is due to heat generated from pump motor operation, the only feasible means of mitigating the thermal aging effects is by selection of suitable cable  !

materials. Therefore, there are no additional specific methods deemed necessary to mitigate the effects  :

of thennal aging for the Group 4 cables, j Discoscry: The cliccts of thennal aging that do occur can be discovered through visual inspection performed during periodic maintenance to the pump motors. This activity would ensure that cables are replaced prior to degradation of the insulation that could compromise the passive intended function (i.e., prevent or isolate faults in an electrical circuit). (Reference 1. Page F.2)

Group 4 (Thermal aging for EPR non EQ cables in power service, associated with the Saltwater System and Service Water System 4kV pump motor terminations) - Aging Management Program (s) hiitisatiom Since there are no methods deemed necessary to mitigate the effects of thennal aging for the Group 4 cables, there are no programs credited with mitigation of this effect.

Discoverv: To manage the effects of thermal aging for the Group 4 cables, the existing Electrical Preventative Maintenance (EPM) Program will be modified. [ Reference I, Page F.2)

Visual inspection will take place as part of the periodic EPM on the pump motors. The EPM checklists associated with pump motors for the Group 4 cables will be revised to intlade appropriate inspection criteria. If any of the acceptance criteria are not met, an issue Report would be generated, per Reference 20, to document tbc degraded condition and the required corrective actions (i.e., cable replacement). [ Reference 24]

1he corrective actions taken as a result of the EPM Program will ensure that the Group 4 cables remain capable of performing their intended function to prevent or isolate faults in an electrical circuit under all CLD conditions.

Group 4 (Thermal aging for EPR non EQ cables in power service, associated with the Saltwater Syste6n and Service Water System 4kV pump motor terminations) - Demonstration of Aging Management Based on the factors presented above, the following conclusions can be reached with respect to thermal aging for EPR non EQ cables in power service, associated with the Saltwater System and Service Water System 4kV pump motor terminations:

. The Group 4 cables provide the passive intended function to prevent or isolate faults in an l

electrical circuit under CLB conditions.

I

. Thennat aging is plausible for the Group 4 cables, causing a breakdown of the cable insulation dielectric strength, which could eventually lead to electrical failure of the insulation and loss of the fimction to prevent or isolate faults in an electrical circuit under CLD conditions.

l Application for License Renewal 6.1 21 Calvert Cliffs Nuclear Power Plant NRC97071

ATTACIIMENT 0)

APPENDIX A - TECHNICAL INFORMATION 6.1 - CAHLES e ne CCNPP EPM Program will conduct visual inspections to detect the elTects of thermal aging, and will contain acceptance criteria that ensure corrective actions will be taken such that there is reasonable assurance that the prevention or isolation of faults in an electrical circuit function will be maintained, nerefore, there is reasonable assurance that the effects of thermal aging will be managed in order to maintain the function to prevent or isolate faults in an electrical circuit as provided by the Group 4 cables, consistent with the CLil, during the period of extended operation.

Group 5 (IR reduction for EPR/XLPF1XLPO non EQ cables in instrumentation servlee, which are sensitive to reduction in cable IR)- Materials and Environment Group 5 consists of instrumentation cables with EPR, XLPE, or XLPO insulation. The cable is used in Radiation Monitoring System, power range nuclear instrumentation, and wide range nuclear instrumentation circuits routed throughout the plant (inside and outside of containment). [ Reference 1

- Pages 3 3 through 310]

ne highest (non accident) ambient design temperature of any area in the plant that contains cabling is in the Main Steam Penetration Room. This room has a maximum design ambient temperature of 160'F.

[ Reference 1, Page 2 l]

He normal general background radiation level insik ontainment is I rad / hour (although may be higher in some locations). There are no design rs{4 tion requirements outside containment during normal operating conditions. [ Reference 21, Sectk,is 5.4.A,5.4.C)

Group 5 (IR reduction for EPR/XLPE/XLPO non-EQ cables in instrumentation service, which are sensitive to reduction in cable IR)- Aging Mechanism Effects The Group 5 cables may be subject to thermal stress due to ambient heating effects. The Group 5 cables inside containmer,t are also subject to radiation stress.

110th the thermal and radiation-induced degradation of the cable insulation can result in reduced IR.

Insulation resistance (also called DC resistivity) is a measure of resistance to the transport of electrical charge (or DC) through the insulation. Insulation resistance for cable is typically specified in terms of ohms per 1000 feet of cable length Unaged cables typically have IR specifications of 10' to 10" ohms per 1000 feet. Cable tests (e.g., for EQ of cable under accident conditions) have demonstrated that radiation and thermal aging may result in a decreate in IR of several orders of magnitude, insulation resistance decreases with increasing temperature and may recover as temperature decreases.

[ Reference 5, Pages 29,4It Reference 16, Pages 4 2,4 3,4 5; Reference 25, Appendix D)

De reduction in IR causes an increase in leakage currents between conductors, and from individual conductors to ground. Leakage currents are typically negligibly small under normal, non accident conditions and are more of a concern under harsh conditions (i.e.,high temperature, humidity, and radiation). liarsh environmental conditions would only be a concern for EQ cables since they are required to function in a post-accident environment. The IR reduction effect can be a concern for circuits with sensitive, low level signals such as current transmitters, resistance temperature detectors, and Application for License Renewal 6.1 22 Calvert ClitTs Nuclear Power Plant NRC97071

ATTACllMENT G)

APPENDIX A TECilNICAL INFORMATION 6.1 - CAHLES thermocouples, it is especist!y a concern for channels with logarithmic signals such as radiation monitors and neutron monitoring instrumentation. De IR reduction effect contributes to inaccuracies in the instrument loop current signal (e.g.,4 20 mA) such that the measurement of the process variable (e.g., rads / hour) becomes more uncertain. These uncertainties are taken into account when calculating instrument loop setpoints and instrument loop indication uncertainties. For CCNPP, reduction in IR was determined to be plausible for cables associated with Radiation Monitoring System, power range nuclear instrumentation, and wide range nuclear instrumentation circuits. His determination of plausibility is considered conservative since IR reduction effects were calculated to have negligible impact on the operation of radiation monitoring and neutron monitoring instrument loops even during accident conditions. [ Reference I, Page 3 3; Reference 6; Reference '45, Appendix D; Reference 26, Sections 3.7, 3.8,10.6,10.7; Hererences 27 and 28; Reference 29, Page 112]

Since thermal and rudiation induced aging can result in reduced IR, these aging mechanisms, if unmanaged, could eventually lead to the loss of the passive function to maintair. adequate IR under CLD conditions. Therefore, IR reduction was determined to be a plausible effect which must be managed for EPR/XLPF/XLPO non EQ cables in instrumentation service, which are sensitive to reduction in cable IR. [ Reference 1, Page 41)

Group 5 (IR reduction for EPR/XLPE/XLPO non EQ cables in instrumentation service, which are sensitive to reduction in cable IR)- Methods to Manage Aging Mitigntiom in normal environmental conditions, the leakage currents due to IR reduction will be small enough such that periodic instrument loop calibration will be sufficient to mitigate the IR reduction effects. [ Reference 27; Reference 29, Page i12] )

Discoverv; There are no methods deemed necessary to discover the IR reduction effects since the effects can be mitigated through periodic calibration of the instrument loops.

Group 5 (IR reduction for EPR/XLPE/XLPO non EQ cables in instrumentation service, which are sensitive to reduction in cable IR)- Aging Management Program (s)

Mhigation: To manage the IR reduction effects on the Group 5 cables, the existing Instrument Calibration Program, MN 1211, will be used to provide performance monitoring of the affected circuits.

[ Reference 1. Pages 3 10,4.); Reference 30]

The Instrument Calibration Program provides the administrative controls that ensure proper calibrations of instrumentation used for tests, surveillances, and other procedures are performed. The program

, applies to CCNPP installed process instrumentation. Instrument loops are normally calibrated using a Surveillance Test Procedure or a Preventative Maintenance Task. The Surveillance Test Procedure is a stand alone procedure that ensures instruments important to safety keep the plant parameters in normal bounds or put the plant in a safe condition if those parameters exceed normal bounds. Surveillance Test Procedures are performed t.t specific intervals to satisfy Technical SpeciGcation requirements. The tests assure that the quality of systems and components are maintained, their operation will be within safety limits, and the limiting conditions for operation will be met. Preventative Maintenance Tasks maintain equipment, structures, systems, and components in a reliable condition for normal operation and Application for License Renewal 6.1 23 Calvert Cliffs Nuclear Power Plant NRC97071 l

a -av. - A -.-___A w - , _ - a -.,___a. 4m-_ a_ ------iaa-ATTACllMENT d)

APPENDIX A - TECilNICAL INFORMATION 6.1 - CABLES i b

emergency use, minimize equipment failure, and extend equipment and plant life. [ Reference 30, Sections 1.1,1.2, 5.2]

Instrument loops are normally calibrated by applying a test input signal at the sensor end of the loop and then observing a desired output signal (based on the instruments input / output scaling relationships such ,

as linear, $quare root, logarithmic, etc.) at the bistable or indicator end of the loop. Calibration data >

points are normally chosen such that they span the entire instrument loop range at evenly spaced ,

intervals (e.g., 0%, 25%, 50%, 75%,100%). Each desired output value has an acceptance band based on s the desired output value plus or minus the instrument loop setting tolerance. The setting tolerance is derived from instrument uncertainty calculations, design basis documents, or documented engineering '

evaluations. When an instrument is found to be out of calibration during the performance of a Surveillance Test Procedure, Preventative Maintenance Task, or corrective maintenance activity, BGE determines if the out of-calibration instrument could effect any surveillance test. If necessary, an issue Report is initiated (per Reference 20) and the necessary corrective actions are taken. [ Reference 30, Sectior. 5.7; Reference 31, Section 3.0.T, Attachment 7) ,

Since IR reduction causes inaccuracles in the instrument loop current signal, periodic instrument loop calibration to eliminate the inaccuracles (whether due to IR or other effects) is an effective r..eans to mitigate the IR reduction effects.

He Instrument Calibration Program is subject to internal quality assurance audits and extemal assessments (e.g.,NRC inspections). Nuclear Regulatory Commission inspections have noted weaknesses in the program in two general areas. First, there were program inconsistencies that did not permit a readily acce=sible mechanism to ensure safety related process instrumentation was scheduled and periodically calibrated. Second, there was no process to evaluate the effect on equipment operability of instrumentation found out of caFbration. Baltimore Gas and Electric Company has subsequentry taken corrective actions to address these items and the NRC concerns with installed safety-related instrumentation calibration have been resolved. [ References 32 through 36)

The corrective actions taken as a result of the Instrument Calibration Program will ensure that the Group

$ cables will remain capable of performing their function to maintain adequate IR under all CLB conditions.

Discoverv: Since there are no methods deemed necessary to discover the IR reduction effects, there are no programs crediting with discovery of these effects.

Group 5 (IR reduction for EPR/XLPE/XLPO non EQ cables in instrumentation service, which are sensitive to reduction la cable IR)- Demontration of Aging Management Based on the factors presented above, the following conclusions can be reached with respect to IR reduction for EPR/XLPE/XLPO non-EQ cables in instrumentation service, which are sensitive to reduction in cable IR:

e ne Group 5 cables provide the passive intended fun. tion to maintain adcquate IR under CLB conditions.

Application for License Renewal 6.1 24 Calvert Clifts Nuclear Power Plant NRC97071

ATTACHMENT (3)

APPENDIX A TECHNICAL INFORMATION 6,1. CAHLES e %ermal and radiation induced agirg can result in plausible IR reduction for the Group 5 cables, which could eventually lead to the loss of the passhe function to maintain adequate IR under CLB conditions.

• De CCNPP instrument Calibration Program will periodleally calibrate the instrui.ient loops associated with the Group 5 cables to mitigate tlee IR reduction effects, and contains acceptance criteria that ensures corrective actions will be taken such tnat there is reasonable assurance that the maintenance of adequate IR function will be maintained.

Therefore, there is reasonable assurance that the IR reduction effects will be managed in order to maintain the maintenance of adequate IR function as provided by the Group 5 cables, consi: tent with the CLil, during the period of extended operation.

Group 6 (Treeing for EPR non EQ cables in 4kV power service). Materials and Environment Group 6 consists of 4kV power cables with EPR insulation associated with the saltwater pumps, the service water pumps, and the safety related 4kV feeds from the 4kV unit busses to the 480V unit busses.

[ Reference 1. Page 31]

The Group 6 cables are subjected to the following conditions: [ Reference 1, Page 3 1]

e 4kV service voltage; e Continuously energized; and e insulation is subject to electrical stress of 35V/ mil or greater.

Group 6 (Treeing for EPR non EQ cables in 4kV power service). Aging Mechanism Effects Trecing is a form of voltage induced degradation of the cable insulation. llollow microchannels with a tree like pattern can initiate from electrical stress concentrations within a polymer, and progressively cause localized polymer decomposition. %c stress concentrations may be protrusions on an electrode surface or contaminants within the insulation. Trecing requires insulation exposure to a high electrical field stress. Degradation of the insulation due to treeing can result in an eventual breakdown of the insulation dielectric strength. [Refecence 2, Table 4 4; Reference 16, Section 4.7.1)

Treeing is considered plausible if all of the following conditions are met: [ Reference 1, Page 3 1]

e Cable is in 4kV service; e Cable is continuously energized; and

. Cable insulation is subject to electrical stress of 35V/ mil or greater, ne function of the insulation for the Group 6 cables is the same as for the Group I cables. Therefore, degradation of the cable insulation dielectric strength (which can result in the electrical failure of the insulation) is considered significant in maintaining the passive intended function to prevent or isolu faults in an electrical circuit.

Since degradation of the insulation due to treeing can result in breakdown of the dielectric strength of the insulation, this aging mechanism, if unmanaged, could eventually lead to ioss of the passive intended

~

Application for License Renewal 6.1-25 Calvert Cliffs Nuclear Power Plant NRC97071

ATTACliMENT LH i

APPENDIX A TECilNICAL INFORMATION i 6.1 CAHLES  !

function to prevent or isolate faults in an electrical circuit under CLB conditions. Therefore, treeing was l determined to be a plausible ARDM for which aging effects must be managed for EPR non EQ cables in 4kV power service.

Group 6 (Treeing for EPR non EQ embles in 4kV power ser ice) . Methods to Manage Aging Mitigation: Since the degradation of the Group 6 cables is due to operational conditions which cannot be changed, there are no feasible means of mitigating these effects. Therefoie, there are no methods deemed necessary to mitigate the effects of trecing for the Group 6 cables, j

Dhcnycty; The efic:ts of treeing that do occur can be discovered through a combination of analysis, monitoring, and testiig. These activities would ensure that cables are replaced prior to degradation of the insulation that co,ild compromise the passive intended function (i.e., prevent or isolate faults in an electrical circuit). [ Reference 1, Pages 4 8, F 2) r Group 6 (Treeing for EPR non EQ cables in 4kV power service). Aging Management Program (s)

Mitigation: Since there are no meuiods deemed necessary to mitigate the effects of trecing for the Group 6 cat les, there are no programs credited with mitigation of this effect.

Discovem To manage the clTects of treeing for the Group 6 cables, a new plant program will be developed to provide monitoring, testing, or analysis (or an appropriate combination thereof). The program is considered an ARDI program as defined in the CCNPP IPA Methodology (Section 2.0 of the llGE LRA) The purpose of the Cables ARDI program is to determine if plausible aging could potentially progress to cable failure such that ongoing aging management is required to be implemented.

[ Reference i, Page 41 Section 4.7, Appendix F]

1he Cables ARDI program will include the following elements as appropriate: [ Reference 1, Pages 41.

F 2} .

. Analysis to determine a cable replacement date;

. Pulling cable samples for testing of chemical, mechanical, or electrical properties and subsequent replacement and repair of the tested cable sections; e Cable condition monitoring (i.e . in situ non-destructive testing); and

. Replacement of cable.

Pulling cable samples for testing and cable condition monitoring will include acceptance criteria to trigger cable replacement prior to degradation that would prevent the cable from performing its intended function. if any of the acceptance criteria are not met, an issue Report would be generated, per Reference 20, to document the degraded condition and the required corrective actions (i.e., cable replacement).

Cable condition monitoring is presently considered an optional approach to ongoing cable management, llowever, it does not have industry consensus or regulatory acceptance as a means of establishing cable residual life. Haltimore Gas and Electric Company considers condition monitoring to be a viable Application for License Renewal 6.1 26 Calvert Cliffs Nuclear Power Plant NRC97071

_ _ _ - _ _ - - - - _ - = _ _ _ - - -. . - . - - - . - - - - ~. -

ATTACHMENT di APPENDIX A TECHNICAL INFORMATION 6.1 CABLES alternative and will monitor research in this area through EPRI and NEl to develop this aspect of the aging management program accordingly.

1hc corrective actions taken as a result of the Cables ARDI program will ensure that the Group 6 cables remain capable of performing their intended function to prevent or inolt'e faults in an electrical circuit under all CLB conditions.

Group 6 (Treeing for EPH non EQ cables la 4kV power se Tice) - Demonstration of Aglag Management Based on the factors presented ab ive, the following conclusions can be reached with respect to trecing for !!PR non EQ cables in 4kV power service:

• The Group 6 cables provide the passive intended function to prevent or isolate faults in an l electrical circuit under CLB conditions. I e Treeing is plausible for the Gron hables, causing a breakdown of the cable insulation dielectric strength, which could eventually lead to electrical failure of the insulation and loss of the function ,

to prevent or isolate faults in an electrical circuit under CLB conditions. ]

e- 1he CCNPP Cables ARDI program will determine if plausible aging could potentially progress to cable failure, such that ongolag aging management is required to be implemented. The program l will also contain acceptance criteria that ensure corrective actions will be taken, such that there is reasonable assurance that the prevention or isolation of faults in an electrical circuit function will be maintained.

Therefore, there is reasonable assurance that the effects of trecing will be managed in order to maintain i the function to prevent'or isolate faults in an electrical circuit as provided by the Group 6 cables, ,

consistent with the CLil, during the period of extended operation.

~

6.1.3 Conclualon I

The programs discussed for cables are listed in the following table. Ther' programs are (or will be for new programs) administratively controlled by a formal review and approval process. As demonstrated above, these programs will manage the aging mechanisms and their effects such that the intended ftmetions of the cable will be maintained, consistent with the CLD, during the period of extended operation. 1 The analysis / assessment, corrective action, and confirmation' documentation process for lleense renewal is in accordance with QL-2, " Corrective Actions Program." QL 2 is pursuant to 10 CFR Part 50,

- Appenoix 11, and covers all struciurcs and components subject to aging management review.

4 i

i Application for License Renewal 6.1 27 Calvert Cliffs Nuclear Power Plant  ;

NRC97071 1

t A*ITAC11 MENT (3) i APPENDIX A TECHNICAL INFORMATION 6.1 - CABLES l TABLE 6.13 '

LIST OF AGING MANAGEMENT PROGRAMS FOR CAHLES .

Program Credited For Existing Instrument Calibration Program, MN.I 211 Management of the elrects ofIR reduction for >

Group 5 (EPR/XLPE/XLPO non EQ cables in instrumentation service, sensitive to reduction in cable IR).

Modified EPM Program Management of the effects of thermal aging ,

for Group 4 (EPR non EQ cables in power  :

EPM Checklists EPM 04000, EPM 04003, service, associated with Saltwater Systet snd EPM 05135 Service Water System 4kV pump rootor terminations). i New Cables ARDI Program Managernen,' of the effects of:

. Thermal aging for Group I (EPR/XI.PE/XLPO non EQ cables in power and control service, routed without maintained spacing), and Group 2 (EPR/XLPE non EQ cables in power  ;

service, routed with maintained spacing)

- Synergistic thermal md radiative aging for Group 3 (EPR/XLPE non EQ cables in power service, routed inside containment)

- Treeing for Group 6 (EPR non EQ cables in 4LV power service) t Application for 1.icense Renewal 6.1-28 Calvert Clifts Nuclear Power Plant NRC97071

AITACitMrNT m APPENDIX A . TECHNICAL INFORMATION 6.1 - CAHLES 6,1.4 References I, "CCNPP Aging hianagement Review Report for the Cables & Terminations (Commodity Evaluation)," Revision 2. June 9,1997

2. Department of Energy Contractor Report SAND 96 0344," Aging hianagement Guideline for Commercial Nuclear Power Plants Electrical Cable and Terminations," September 1996

3. CCNPP Drawing 61406 A, See 109.1, Sheet 3. " Control Panel Wiring," Revision 3 October 10,1995

4. Letter from Mr. M. W. Ilodges (NRC) to Mr. G. C. Creel (DGE), dated June 5,1992, Transmittal ofInspection Report $0 317/92 80,50-318/92 80 (Electrical Distribution System Functionalinspection)

$. NUREG/CR 3461," Aging of Cables, Connections, and Electrical Penetration Assen blies Used in Nuclear Power Plants," July 1990

6. NRC Information Notice 93 33 " Potential Deficiency of Certain Class 1H Instrumentation and Control Cables," April 28,1993

7. CCNPP Updated Final Safety Analysis Report, Revision 20

8. Letter from Mr. D. II. Jaffe (NRC) to Mr. A. E. Lundvall, Jr. (DGE), dated December 9,198$,

Transmiital of t.icense Amendments 109 and 92

9. IEEE Paper 70 TP $57 PWR, "Ampacities for Cables in Randomly Filled Trays," submitted September 18,1969 by J. Stolpe

10. CCNPP Drawing 61406SEC001A Sil0012 " Design and Construction Standards Cable Derating," Revision 2, April 10,1991

11. CCNPP Drawing 61406SEC00l A Sil0013, " Design and Construction Standards Cable Derating," Revision 2. April 10,1991

12. CCNPP Drawing 61406SEC001 A Sil0014, " Design and Construction Standards - Cable Derating," Revision 2, April 10,1991

13. CCNPP Drawing 61406SEC001 A S110015, " Design and Construction Standards Cable Derating," Revision 3, April 10,1991

14. CCNPP Drawing 61406SEC001 A S110016. " Design and Construction Standards Cable Derating," Revision 2. April 10,1991

15. CCNPP Drawing 61406SEC001 A Sil0017. " Design and Construction Standards Cable Derating," Revision 2, April 10,1991

16. EPRI Report TR 103841, " Low Vol' age Environmentally-Qualified Cable License Renewal Industry Report," Revision 1 July 1994

17. NRC Information Notice 92 81, " Potential Deficiency of Electrical Cables with Bonded llypalon Jackets," December 11,1992

18. Engineered Materials llandbook, Volume 1, " Composites," ASM International, Copyright 1987 Application for License Renewal 6.1 29 Calvert Cliffs Nuclear Power Plant

- NRC97071

ATTACHMMT (3)

APPENDIX A . TECilNICAL INFORMATION 6.1- CAULES

19. Engineered Materials llandbook, Volume 2, " Engineering Plastics," ASM International, Copyright 1989 20, CCNPP Administrative Procedure QL-2100, " Issue Reporting and A.sessment," Revision 4, January 2,1996

21. CCNPP Engineering Standard ES 014, " Summary of Ambient Environmental Service Conditions," Revision 0, Nos ember 8,1995

22. EPRI Report NP 4172SP," Radiation Data for Design and Qualification of Nuclear Plant Equipment, August 1985

23. CCNPP Drawing 61406 A Sec. Vil, Sheet l$, "Kerite 4KV SR/EQ Motor Termination,"

Revision 4, January 18,1991

24. CCNPP Nuclels Database, Electrical Presentative Maintenance Checklists EPM 04000, EPM 04003, and EPM 05135

25. Instrument Society of America Recommended Practice ISA RP67.04 Part 11,"Methodolopes for the Determination of Setpoints for Nuclear Safety Related Instrumentation,"

September 1994

26. CCNPP Calculation 193 87, " Insulation Resistance Degradation Uncertainty Effects,"

Revision 2, March 8,1995

27. NRC Information Notice 92 12," Effects of Cable Leakage Currents on Instrument Settings and Indications," February 10,1992

28. Title 10 Code of Federal Regulations Part 21 Notification by GA Technologies Inc.," Defect in ion Chamber Signal Coaxial Cable," February 23,1987

29. CCNPP Engineering Standard ES 028. " Instrument Loop Uncertainty and Setpoint Methodology," Revision 0, October 17,1995

30. CCNPP Administrative Procedure MN 1211. " Instrument Calibration Program," Revision 1 January 17,1996

31. CCNPP Engineering Standard ES-026, " Instrument Calibration Data Development,"

Revision 0, November 8,1995

32. Letter from Mr. E. C. Wenzinger (NRC) to Mr. J. A. Tiernan (BGE), dated June 6,1986, Transmittal of NRC Inspection Report 50 317/86-07,50 318/86-07

33. Lettei from Mr. J. A. Tiernan (BGE) to Mr. E. C. Wenzinger (NRC), dated July 17,1986, Response to NRC Inspection Report 50 317/86-07,50 318/86 07

34. Letter from Mr. G. C. Creel (BGE) to NRC Document Control Desk, dated June 21,1989, Response to NRC Inspection Report 50 317/89 200,50-318/89 200 (Special Team inspection)

35. Letter from Mr. C. J. Cowgill (NRC) to Mr. G. C; Creel (BGE), dated June 6,1986, Transmittal of NRC Inspection Report 50 317/91 14,50 318/91 14

36. Letter from Mr. C. J. Cowgill (NRC) to Mr. G. C. Creel (BGE), dated May 13,1o92, Transmittal of NRC Inspection Report 50 317/92 12,50-318/92 12 o

Application for License Renewal 6.130 . Calvert Cliffs Nuclear Power Plant NRC97071