ML20209C139

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Forwards Responses to Open & Confirmatory Items Based on Review of SER for Bg&E Application for Renewal of Operating Licenses for Calvert Cliffs.Bg&E Intends to Forward Comments Based on Accuracy Verification in Near Future
ML20209C139
Person / Time
Site: Calvert Cliffs  Constellation icon.png
Issue date: 07/02/1999
From: Cruse C
BALTIMORE GAS & ELECTRIC CO.
To:
NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
NUDOCS 9907090182
Download: ML20209C139 (59)


Text

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l CurutEs H. Cco:E Baltimore Gas and Electric Company Vice President Calvert Cliffs Nuclear Power Plant Nuclear Energy 1650 Calvert Cliffs Parkway Lusby, Maryland 20657 b

410 495-4455 July 2,1999 U. S. Nuclear Regulatory Commission Washington, DC 20555 ATTENTION: Docmnent Control Desk

SUBJECT:

Calvert Cliffs Nuclear Power Plant Unit Nos.1 & 2; Docket Nos. 50-317 & 50-318 Response to License Renewal Safety Evaluation Report

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REFERENCES:

(a) Letter from Mr. D. B. Matthews (NRC) to Mr. C. H. Cruse (BGE), dated March 21,1999, "Calvert Cliffs Nuclear Power Plant, Units I and 2, License Renewal Safety Evaluation Report" f

(b) Letter from Mr. W. D. Lanning (NRC) to Mr. C. H. Cruse (BGE), dated March 26,1999, "NRC Inspection Report Nos. 50-317/99-02 and 50-318/99-02" (c) Letter from Mr. W. D. Lanning (NRC) to Mr. C. H. Cruse (BGE), dated

  • May 21,1999, "NRC Inspection Report Nos. 50-317/99-04 and 50-318/99-04" (d) Letter from Mr.C.H. Cruse (BGE) to Document Control Desk, dated March 11,1999, " Revision 1 for License Renewal Application Section 6.2, Electrical Commodities" (e) Letter from Mr. C. H. Cruse (BGE) to Document Control Desk, dated April 2,1999, "First Annual Amendment to Application for License Renewal" Reference (a) forwarded the Safety Evaluation Report (SER) for Baltimore Gas and Electric Company's (BGE's) application for the renewal of the operating licenses for Calvert Cliffs Nuclear Power Plant Units I and 2, and requested that BGE review the SER, verify its accuracy, and provide comments and responses to the open and confirmatory items.

Included herein, Attachment (1) provides responses to the open items and Attachment (2) provides responses to the confirmatory items. Baltimore Gas and Electric Company intends to forward comments based on the accuracy verification in the near future.

9907090182 990702 PDR ADOCK 05000317 NRC Distributbn Code A036D P PDR

Document Control Desk July 2,1999 Page 2

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References (b) and (c) reported the results of the February 1999 NRC Region I inspection of the Calvert Cliffs License Renewal Program in the area of Scoping, and the April 1999 NRC Region I inspection of the Calvert Cliffs License Renewal Program in the area of Aging Management. respectively. Based on l interactions with NRC inspectors during those inspections, BGE has agreed i make changes to the l

application for license renewal. Those changes, plus changes associated with certain open items and confirmatory items, are provided in Attachment (3).

Reference (a) considered information provided by BGE up to March 5,1999. References (d) and (e) were submitted subsequent to March 5,1999. Information from those two submittals should be incorporated into the SER along with the information submitted herein.

Should you have questions regarding this matter, we O be pleased to discuss them with you.

Very truly yours, STATE OF MARYLAND  :

TO WIT:

COUNTY OF CALVERT  :

i I, Charles H. Cruse, being duly sworn, state that I am Vice President, Nuclear Energy Division, Baltimore 1 l

Gas and Electric Company (BGE), and that I am duly authorized to execute and file this response on behalf of BGE. 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 beli ' to e reMable.

/, W' ne l Subscri d nd sworn before me, a Notary Public in and for th of Maryland and County of

o. erf .this 2, day of Liu .1999.

WITNESS my Hand and Notarial Seal:

Notary Public My Commission Expires: CM1

'Date CHC/RCG/ dim Attachments: (1) Responses to License Renewal Safety Evaluation Report Open items (2) Responses to License Renewal Safety Evaluation Report Confirmatory Items (3) Changes to the Application for License Renewal cc: R. S. Fleishman, Esquire C. I. Grimes, NRC J. E. Silberg, Esquire D. L. Solorio, NRC S. S. Bajwa, NRC Resident Inspector, NRC A. W. Dromerick, NRC R. I. McLean, DNR II. J. Miller, NRC J. H. Walter, PSC 1 .

Document Control Desk July 2,1999, Page 3 bec:' R. E. Denton P. E. Katz K. B. Cellars J. R. Lemons I

R. P. Heibel K. L. Boone/AIT No. CT199900016 and CT 199900019 (see Attachment 3, section for 3.3E)

L. S. Larragoite K. R. Neddenien OSSRC Secretary B. S. Montgomery W. C. Holston R. C. Gradle D.L.Shaw B. W. Doroshuk M. E. Bowman J.Rycyna File 16.06 Electronic Docket File )

CHC/RCG/DLS/ dis / dim NRC 99-065 4

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ATTACHMENT (1) l l

l RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS l

Baltimore Gas and Electric Company Calvert Cliffs Nuclear Power Plant July 2,1999

ATTACHMENT (1)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS Open Item 2.2.3.8-1 As a check to determine if the applicant omitted a componentfrom its list of components that are within the scope oflicense renewal, the staff asked the applicant to clarify several issues. In NRC Question No. 3.3.43, the staff noted to the applicant that Section 3.3E, " Auxiliary Building and Safety-Related Diesel Generator Building Structures," cf the license renewal application (LRA) addresses the safety-related diesel buildings but does not address the station blackout (SBO) diesel generator. In its response, the applicant referred to Subsection 4.2.2, " Function Identy1 cation," of Section 2.0 of Appendix A to LRA (i.e., the Integrated Plant Assessment [ IPA]) and stated that the structure that encloses the SBO dieselgenerator does not perform any ofthe seven listedfunctions and, therefore, is not within the scope oflicense renewal. However, Section 8.4.5.1.e of the Updated Final Safety Analysis Report (UFSAR) states that certain structural components of the SBO diesel generator building are designed to preclude seismicfailure andsubsequent impact ofthe structure on the adjacent safety-related emergency diesel generator building. In addition, as stated in the same UFSAR section, certain  ;

equipment located " outdoors or on the building roof" could exceed the parameters for a Spectrum 11 tornado and has been anchored to resist these windloads. Function No. 5 in Section 4.2.2 ofSection 2.0 ofAppendix A to the LRA addresses non-safety-related equipment whosefailure may affect thefamction of safety-related equipment. Therefore, the staffis considering whether the SBO diesel generator building structures and the mounting components securing the aforementioned equipment associated with the SBO

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diesel generator building against tornado wind loads, structures, and components whose failure could directlyprevent satisfactory accomplishment of the emergency diesel generator building 's intended safety function, should be included within the scope oflicense renewal.

BGE Response Baltimore Gas and Electric Company understands that this item is still under NRC staff consideration.

Open Item 2.2.3.17.2.1-1 In response to NRC Question No. 5.6.4, regarding exclusion of the emergency dousingfunction of the Containment Spray (CS) Systemfrom the scope of!! cense renewal, the applicant referencedSection 6. 7.2 of the UFMR, which explains that the dousing system is isolated in Modes 1 through 4. Licensee calculations show that the maximum post-loss-of-coolant accident charcoal bed temperature will not cause lodine desorption or charcoal bed ignition. However, the licensee states that the system is available to provide fire protection to the charcoal beds in order to support certain maintenance activities in Modes 5 and 6. 10 CFR 50.48 guided the staff to evaluate the plants ' fire protectionfeatures as satisfying theprovisions ofAppendix A to Branch TechnicalPosition (BTP) APCSB 9.5-1, " Guidelines for Fire Protection for Nuclear Power Plants Docketed Prior to July 1,1976," and reflects this evaluation in the Fire Protection Safety Evaluation Report (FPSER). In Section F of Appendix A to BTP APCSB 9.5-1, charcoalfilters are identified as needing automaticfixed suppression systems due to their inaccessibility during normal plant operations. Further, Section 4, " Ventilation," states thatfire suppression systems should be installed to protect charcoal filters in accordance with Regulatory Guide 1.52, " Design, Testing, and Maintenance Criteriafor Post Accident Engineered-Safety Feature Atmosphere Cleanup System Air Filtration and Adsorption Units of Light-Water-Cooled Nuclear Power Plants. " Thefixedfire suppression system used in this application consists of the water supply piping and direction no::les. The staff reviewed the applicant's response andfound no new information that would support the licensee 's conclusion that the piping and no::les that provide the emergency dousi sg function do not meet the scoping requirements of10 CFR 54.4(a)(3).

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ATTACIIMENT (1)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS BGE Response Overview Calvert Cliffs' Units 1 and 2 containments each have three charcoal filter iodine removal units. Each iodine removal unit is provided with piping and nozzles that can be connected to a water supply for dousing the charcoal. The primary purpose for the dousing system was to cool the charcoal, should overheating occur during their use following a design basis accident. The water supply to the iodine removal units is provided by the CS System for both Units 1 and 2. The current water supply configuration consists of piping, nozzles, check valves, solenoid-operated valves, and manual isolation valves that are normally closed during plant operation (Modes 1,2,3, and 4).

- The discussion below will provide a chronological history, regulatory, and technical basis for Baltimore Gas and Electric Company's (BGE's) determination that the containment charcoal filter

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dousing system piping downstream of the normally-closed manual isolation valves, inclusive of j solcaoid valves, check valves, integral piping and nozzles, are not within the scope oflicense renewal. '

Background

In August 1976, the NRC issued Appendix A to BTP 9.5-1, " Guidelines for Fire Protection for I Nuclear Power Plants Docketed Prior to July 1, 1976" (Reference 1). By letter dated i September 30,1976 (Reference 2), the NRC requested BGE to perform an examination of Calvert f Cliffs Nuclear Power Plant's (CCNPP) existing fire protection program by comparing it to '

Appendix A of BTP 9.5-1.

Appendix A provides alternative guidance for power "[P]! ants for which construction permits were issued prior to July 1,1976, and operating plants." This alternative guidance applies to CCNPP, which in some cases may be less restrictive than the original issue of BTP 9.5-1. Therefore, the alternative requirement was applied to the containment charcoal filter iodine removal unit dousing system as described be!ow. )j Regidatory Requirement - Branch Technical Position 9.5-1, Appendix A Section D..I(d) - Fire suppression systems should be installed to protect charcoalfilters in accordance l with Regulatory Guide 1.52, " Design Testing and Maintenance Criteriafor Atmospheric Cleamsp Air Filtration ".

BGE Response (Fire Protection Program Evaluation, March 15, 1977 - Pages D-40 and D-41

[ Reference 3]) ,

i The plant has a total of 15 charcoal filters,6 of which are located inside Containment. The ,

charcoal filters located inside Containment are used during post-accident conditions only. Since these filters are located in an area with limited access, and since they are operated during post-accident containment conditions, when the operating temperature is significantly high (up to a l maximum of 273'F steam air mixture in the containment atmosphere), these charcoal filters are j equipped with an emergency cooling water dousing system to dissipate decay heat in the event of  !

loss of air flow through the unit'during post-accident operation. Each unit has a thermistor to I provide control room indication of the charcoal bed temperature. The charcoal bed emergency .

dousing system in each unit will be initiated manually, upon thermistor high temperature indication, by the operator from the Control Room. l l

ATTACIIMENT (1)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS NOTE: Regulatory Guide 1.52, Revision 2, dated March 1978, (Reference 4) does not address charcoal filter suppression systems.

Regulatory Requirement - Branch TechnicalPosition 9.5-1, Appendix A Section F.1(a) - Fire protection requirements for the primary and secondary containment areas should beprovidedon the basis ofspecific identifiedha:ards. For example: i e Lubricating oil or hydraulicfluid systemfor theprimary coolantpumps e Cable tray arrangements and cable penetrations

  • CharcoalFilters Fire suppression systems should be provided based on thepre ha:ards analysis.

Fixedfire suppression capability should be providedfor ha:ards that couldjeopardize safe plant shutdown. Automatic sprinklers are preferred. An acceptable alternate is automatic gas (Halon or CO2) for ha:ards identified as requiring fixed suppression protection. Operation of the fire protection systems should not compromise integrity of the containment or the other safety related systems. Fire protection activities in the containment areas shouldfunction in conjunction with total containment requirements such as control ofcontaminated liquid andgaseous release and ventilation.

BGEle onse (Reference 3 - Pages F-1 through F-4)

The pc accident charcoal filters located inside Containment are equipped with an emergency cooliq vater dousing system to dissipate decay heat in the event of loss of air flow through the unit dur.ng post-accident operation. Each unit has a thermistor to provide control room indication of the charcoal bed temperature. The charcoal bed emergency dousing system in each unit will be initiated manually by the control room operator upon thermistor high-temperature indication.

As determined by the fire hazards analysis presented in Subsection D.l(b), no fire suppression systems are required inside Containment in order to assure safe shutdown of the plant. Except for the post-accident charcoal filters, no fixed suppression systems are provided inside Containment.

In September 1979, the NRC issued an FPSER (Reference 5); Enclosure 3 for Unit 1, Amendment No. 41 and Unit 2, Amendment No. 23. The FPSER documents their evaluation of CCNPP's Fire Protection Program Evaluation and subsequent implementation of NRC guidelines contained in several documents, including BTP 9.5-1. The FPSER specifically addressed containment fire protection, including the adequacy of charcoal filter protection. l l

l Regidatory Requirement - Fire Protection Safety Evaluation Report, September 14,1979 '

Section 2.2, Supplementary Guidance - When the actual configuration of combustibles, safety-related stmetures, systems or components, and the pre protection features are not as assumed in the development of Appendix A or when the licensee has proposed alternatives to the specific recommendations of AppendirA, we have evaluated such unique configurations and altervcdves using the defense-in-depth objectives outlined below:

(1) reduce the likelihood ofoccurrence offires; (2) prompdy detect and extinguishpres ofthey occur; (3) maintain the capability to safely shut down theplant ifpres occur; and

ATTACHMENT (1)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS (4) prevent the release ofsigmfcant amounts ofradioactive materials iffires occur.

In our evaluation, we assure that these objectives are met for the actual relationship of combustibles, safety-related equipment, and fire protection features of the facility.

BGE Response (to FPSER Section 2.2)

None required.

Regulatory Requirement - Fire Protection Safety Evaluation Report, September 14,1979 Section 4.4.2, Filters - A total of16 charcoalfiters are installed in the plant: six inside containment, two in the control room heating, ventilation, and air condtioning (HVAC) system, four in the penetration room exhaust systems, two in thefuelpool exhaust system, and two in the emergency core cooling system pump room exhaust systems. ThepIters in containment, and thosefor the penetration room exhaust system, are used during post-accident conditions. The control roomfilters are used only on detection of high radiation in the control room ventilating system. The otherflters are normally bypassed. The containment flters are provided with high temperature monitors and F

manually actuated emergency cooling water suppression systems.

Charcoalfilters are contained in steel casing. No ignition sources are located near the charcoal fiters nor can the buildup ofradioactiveproducts generate sufficient heat to cause ignition.

Wefind thatfire protectionfor thefiters satisfies the objective identified in Section 2.2 of this report '

andis, therefore, acceptable.

BGE Response (to FPSER Section 4.4.2) l None required. '

Regulatory Requirement - Fire Protection Safety Evaluation Report, September 14,1979 Section 5.19.4 - Charcoalflters in containment are provided with high temperature monitors and manually actuated emergency cooling water suppression systems.

BGE Response (to FPSER Section 5.19.4)

None required.

The following paragraph from the CCNPP Updated Final Safety Analysis Report (UFSAR),

Revision 8, Section 6.7.2, System Description, which corresponds with the FPSER description above, described the charcoal filter iodine removal unit dousing system prior to a modification to remove the system from service in 1990.

. "Each of the recirculation filter units is provided with an emergency dousing system for the charcoal beds to dissipate the decay heat load in the event there is a significant rise in the charcoal bed temperature. Charcoal bed temperatures are measured by thermistors and are monitored, recorded and alarmed in the control room. Upon high temperature indication (375*F) or alarm in the charcoal beds, remote solenoid and air operated valves, normally closed, are opened and admit CS water to the emergency dousing system."

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n ATTACHMENT (1)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS Modification to Remove the Charcoal Filter Dousing System from Service In 1990, BGE performed an evaluation and subsequent modification to isolate the iodine removal charcoal filter dousing systems from service during Modes 1,'2,3, and 4. This work was performed and evaluated in accordance with Facility Change Request 90-020, dated January 22,1990; calculations contained in NUCON Report No. 6BG021/01, dated January 19,1990 (Reference 6), and Supplement 1, dated July 25,1990 (Reference 7); supporting 50.59 Evaluation, Log No. 90-B-061-086-R2, dated December 4,1990 (Reference 8); and supporting Fire Protection Engineering Evaluation No.12, " Fire Protection Impact of Removing Dousing System in Containment Iodine Charcoal Filters," dated March 3,1991 (Reference 9).

This change removed the function of the iodine removal unit dousing system by isolating the iodine i removal unit dousing system when either the CS System or the containment iodine removal system is required to be operable by the Technical Specifications (Modes 1,2,3, and 4). Manual isolation valves SI-4949, SI-4950, SI-4951, SI-4958, SI-4959, and SI-4960 will provide the isolation by  :

remaining shut during Modes 1 - 4. The Main Control Room switches for dousing valves SV-4952, j SV-4953, SV-954, SV-4955, SV-4956, and SV-4957 will not provide any function when the manual  ;

valves are closed. The control circuits for SV-4159 and SV-4160 will be classified as non-safety- l related. Control valves CV-4159 and CV-4160 will retain a safety-related pressure boundary  !

function. In Modes 5 and 6, the manual valves may be opened to allow the dousing system to be functional during iodine removal unit maintenance to provide fire protection if required.

BGE CCNPP UFSAR, Revision 25, reflected this change, as follows:

UFSAR 6.7 Containment Iodine Removal System 6.7.2 - Each of the recirculation filter units is provided with an emergency dousing system for the charcoal beds to dissipate the decay heat load in the event there is a significant rise in the charcoal bed temperature. During Modes 1,2,3, and 4, the dousing system is isolated by manual valves.

An analysis (NUCON Report No. 6BG021/01, dated January 19,1990, and Supplement I dated July 25,1990 [ References 6 and 7, respectively] shows that maximum post-loss-of-coolant ,

accident charcoal bed temperature will not cause iodine desorption or charcoal bed ignition. I During Modes 5 and 6, the manual valves may be orened to allow the dousing system to be i functional during iodine removal unit maintenance to provide fire protection if required.

Summary: 1

1. Calvert Cliffs is not required to provide an " automatic fixed suppression" system as stated above in the Open Item 2.2.3.17.2.1-1. On the contrary, Section F of Appendix A to BTP APCSB 9.5-1 l specifically allows CCNPP to provide a fire suppression system based on the fire hazards analysis "for hazards which could jeopardize safe plant shutdown." Based on the Fire Hazards Analysis Summary (Reference 10) and the guidance provided in Appendix A, neither the charcoal filter  !

iodine removal units or the associated dousing systems serve a safe shutdown function. ,

2. The current revision of Regulatory Guide 1.52 does not specify any fire suppression system I requirements to protect charcoal filters. Therefore, CCNPP's current installation does not conflict l with Regulatory Guide 1.52. I
3. The charcoal filter iodine removal dousing system is not in CCNPP's UFSAR Section 9.9, "Calvert Cliffs Nuclear Power Plant Fire Protection Program." l l
4. The charcoal filter iodine removal dousing system is not in the CCNPP's Fire Hazards Analysis Summary, Revision 0, dated June 4,1997 (Reference 10).

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! ATTACIIMENT (1)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS

5. The 10 CFR 50.59 screening evaluation, Log No.90-B-061-086-R2, (Reference 8) and the l associated Fire Protection Engineering Evaluation, No.12, (Reference 9) determined that the l

dousing system is no longer required. Therefore, de system is no longer within the scope of BTP APCSB 9.5-1, Appendix A.

6. Although the UFSAR states that "During Modes 5 and 6, the manual valves may be open to allow the dousing system to be functional during iodine removal unit maintenance to provide fire l protection if required," this option is not considered a requirement of BTP APCSB 9.5-1.

(NOTE: Containment Spray is only required to be operable during Modes 1 and 2, and Mode 3 i when pressurizer pressure is greater than 1,750 psia, per Technical Specification Bases 3.6.6).

Therefore, it is possible that water to the dousing system may not be available in Modes 4,5, and 6.

Conclusion:

Based on Summary Items I through 6 above, BGE does not consider the emergency dousing function of the CS System to be required by 10 CFR 50.48, as described in CCNPP UFSAR Section 6.7.2.

Therefore, BGE concludes that the emergency dousing system piping, valves, and nozzles downstream of the normally shut isolation valves are not within the scope oflicense renewal.

Open Item 2.2.3.23.2.1-1 l

Section 5.118.1.2 in the LRA states that ductwork downstream of thefusible links is not within the scope oflicense renewal. The containment air recirculation and cooling system provides cooling air via this ductwork to the steam generator (SG) compartment and reactor vessel (RV) annulus. As a result, the staff questioned that the ductwork should be within the scope oflicense renewal. To clarify the staffs question, a conference call was made on December 9,1998 with the applicant's staff in response to the call, the applicant stated that cooling via this ductwork was credited in the long term thermal aging analysis which supports the applicant's Environmental Qual @:ation (EQ) program. The staff is considering whether non-safety-related support systems, such as ductwork, credited in analyses that supportprograms, such as EQ, are within the scope oflicense renewal; therefore, this is an Open item.

BGE Response i Baltimore Gas and Electric Company understands that this item is still under NRC staff consideration.

Open Item 2.2.3.30-1 t

Since the non-safety-related service water (SRW) header is credited with preserving cooling water inventory in the safety-relatedportions of the system following a seismic event, the staff asked (NRC Question No. 5.17.1) the applicant to clarify why the turbine building header piping is not within the scope of license renewal [per 10 CFR 54.4(a)(2)]. In its response, the applicant reiterated that the turbine building SRW system components do not meet 10 CFR 54.4(a)(1) or 54.4(a)(2) scoping I reqwrements, and citedfour references: the UFSAR: Licensee Event Report 89-03, Revision 2; a BGE l letter dated October 16,1995; and NRC Inspection Report Nos. 50-317/95-08 and 50-318/95-08. The applicantfurther indicated that the turbine building header was discussed in thefire protection section (Section 5.10, " Fire Protection,") of Appendix A to the LRA because it only has intendedfunctions related to 10 CFR 54.4(a)(3)for safe shutdownfrom postulatedfires. The staff reviewed the applicant 's response, including the cited references, and found no new information that would support the applicant's conclusion that the turbine building header did not meet the scoping requirements of 10 CFR 54.4(a)(2). Infact, it is the staff's opinion that the information in the cited references reinforces 6

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ATTACHMENT (1)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS the staff's conclusion that the turbine building header should be within the scope oflicense renewal basedon 10 CFR 54.4(a)(2) because a loss ofthe turbine building headerpressure boundary could result in afailure (loss ofinventory) of the safety-relatedportions ofthe SRW system (portions within the scope oflicense renewal) to provide cooling water to the emergency dieselgenerators, spentfuelpool coolers, and containment coolers, which is an intended function of the SRW system pursuant to 10 CFR $4.4(a)(1).

BGE Response Baltimore Gas and Electric Company addressed this issue in Attachment (1) of the letter "First Annual Amendment to Application for License Renewal" (Reference 1!), in the section on " Chapter 5.17 -

Service Water System." Baltimore Gas and Electric Company now includes the non-safety-related components related to this item within the scope oflicense renewal.

Open Item 2.2.3.33.2.2-1 In other sections (such as Section 4.1.1.2) of Appendix A to the LRA, the applicant stated that certain devices types from the systems are evaluated in Section 6.2, " Electrical Commodities." The staff determined from a review of Table 6.2-1 that not all systems that the applicant identified as cross-referenced to Section 6.2 are included therein. Also, the applicant included in Table 6.2-1 systems (such as the saltwater (SW) system) whose corresponding sections in the application did not refer to Section 6.2for evaluation ofelectrical commodity device types.

BGE Response A need for clarification of Table 6.2-1 exists for multiple reasons. First, at Calvert Cliffs, System 062,

" Control Boards," contains electrical commodity device types associated with (but not contained in) several other systems. Some of these systems incorrectly had references to LRA (Reference 12)

Chapter 6.2 in their LRA chapter. Also, as the Open Item states, certain systems, such as the SW System, should have had a reference to LRA Chapter 6.2 and did not. Additionally, the IPA results for Electrical Commodities have changed through BGE's annual update process.

Baltimore Gas and Electric Company has re-verified that all electrical commodities within the scope oflicense renewal were included and addressed by this chapter of the LRA. Three systems should be added to Table 6.2-1 and are listed below. Baltimore Gas and Electric Company has also verified that j the cross-referencing information in the third column of Table 6.2-1 is accurate. Any reference to Chapter 6.2 found in other chapters can therefore be disregarded. l 041 Chemical and Volume Control 5.2 ,

055 CEA Drive Mechanism & Electrical 4.2 l 096 Fire and Smoke Detection -

l Open Item 3.0-1 )

The content of the Final Safety Analysis Report (FSifR) supplement is dependent upon thefinal basesfor l the staff's safety evaluation, as will be reflected in a subsequent revision to this report. In addition, i improved guidance is being developed for updating the contents of FSARs under 10 CFR $0.7)(e).

Therefore, the resolution of the information that needs to be added to the FSAR will be addressed after i the other open and confirmatory items are resolved, prior to issuance of a renewed license. The content  !

ofthe FSAR will be tracked as an Open hem.

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4 ATTACHMENT (1)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITFMS f BGE Response l Baltimore Gas and Electric Company understands that resolution of this item mmt occur after the l other open and confirmatory items are resolved. Baltimore Gas and Electric Company furthu i understands that, based on NRC Staff agreement during an NRC public meeting on Mareb 0,1999, )

resolution of this item will not delay issuance of th< renewed licenses. Baltimore Gas ..'d E!d }

Company has agreed to work with the NRC Staff in identifying three sample aging mar.cmer. I programs to be used in an exercise to determine the appropriate content for the UFSAR Supplemer.c.

This exercise will be completed when resources currently addressing more immediate Safety Evaluation Report (SER) activities become available Open Item 3.1.4.3-1 In Section 3.2 ofAppendix A to the LRA, the applicant discussed how some internalportions of the RV cooling shroud can harbor pockets of liquid that may be inaccessible for visual inspection without removing interference. The staff's understanding of the boric acid corrosion inspection (BACI) program is that it does not providefor removing interference; thus, it is smclear how the applicant is managing this aging issue.

BGE Response LRA Section 3.2, Group 2, Page 3.2-16, Aging Management Programs states:

" Discovery of Boric Acid Leakage is ensured by the BACI Program . . . This program will be modified to specify examinations during each refueling outage of: (a) the RV cooling shroud anchorage to the RV head for evidence of boric acid leakage; and (b) all RV cooling shroud structural support members for general corrosion / oxidation."

This rnodified program is also shown in the program summary on page 3.2-25.

The statement referring to the inaccessibility of internal portions of the RV cooling shroud without l removing interference is not applicable during refueling outage evolutions that involve the cooling shroud. Plant personnel must actually enter the shroud to disconnect the incore instrumentation thimbles prior to lifting the RV head; and after the head is relocated to its laydown area, the shroud is disconnected to permit closer inspection of the head. These necessary evolutions atTord access to the otherwise inaccessible areas, and coupled with the appropriate modifications to the BACI procedure, will ensure that aging is managed for the RV cooling shroud.

Open Item 3.1.6.3-1 The staff identified several systems in which the applicant proposed to use a one-time age-related degradation inspection (ARDI) to manage age-related degradation mechanisms (ARDMs) that obviously require periodic, regular inspections, such as for verification of acceptable condition of coatings (auxiliary feedwater, component cooling water, auxiliary building heating and ventilation), and verification that corrosion is not occurring due to leakage (SW, nuclear steam supply system (NSSS) sampling, spentfuelpool cooling). The staffrequests that the applicant either expand existing programs (e.g., the BACI program or the structure and system walkdowns) or confirm that a new aging management program will be developed to ensure that regular, periodic inspections will be performedfor these systems.

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I ATTACIIMENT (1)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS BGE Response Auxiliary Feedwater System: The only external pipe surfaces to be inspected by the ARDI Program are those in the No.12 Condensate Storage Tank enclosure and the valve pit. The piping at these locations is heat traced and covered by insulation. 'The ARDI Program is being used to verify that the enclosures and insulation are adequately weatherproofed to protect the external surfaces of the pipe.

The ARDI will assess the condition of the external pipe surfaces and, based on the results, determine what follow-up actions will be required. It is sensible to reserve conclusions about necessary inspection frequencies until after the initial conditions have been assessed. If, after 40 years of operation, the insulation shows no signs of water ingress, and the piping external surfaces show no signs of corrosion, then continued periodic inspections will be unnecessary.

The ARDI Program, in this instance, is to be implemented similar to that described for Case 2 on page 2.0-59 of the LRA, Section 6.3.3.4, Age-Related Degradation Inspections. The applicable mitigation measure is the weatherproofing provided by the enclosures and insulation flashing. The inspection is intended to verify the absence of aging-induced degradation that is thought unlikely to occur, but cannot be ruled out categorically. As further described on page 2.0-60 of the LRA in reference to an early inspection: "When such an early inspection detects no signs of significant aging 1 as expected, there is no need to extrapolate the results of the inspection. If, on the other hand, the inspection reveals significant degradation or unexpected conditions, the results would either be conservatively extrapolated through the end of the period of extended operation or future inspections would be conducted to track the progress of the unexpected degradation."

Component Cooling System: General corrosion of external pipe surfaces is not plausible for this ,

system. All piping is located inside plant structures and is protected from the environment. The ARDI Program is only being used to verify that the chemistry control program is adequately protecting the internal pipe surfaces.

The discussion on page 5.319 of the LRA on this subject is not clear. In the paragraph at the top of the page, the adjective " potential" preceding the phrase " external corrosive chemical environment" was intended to convey BGE's definition of the word as it was used during the IPA evaluation process (refer to page 2.0-51 of the LRA, Section 6.2.1, Creating a Potential ARDM List). " Potential" should not be equated with " plausible." In the subsequent section of the LRA on the same page, under the '

heading " Group 3 (general corrosion) - Methods to Manage Aging," the paragraph discussing mitigation of general corrosion on external surfaces was intended to dismiss the subject from further consideration. Because it receives periodic assessment through the site Structure and System Walkdown Program (CCNPP Administrative Procedure MN-1-L [ Reference 13]), the coating is considered to provide adequate protection during the renewal term without requiring crediting for further specific, periodic monitoring. In general, if there is no exposure to the outside environment, general corrosion of coated external pipe surfaces cannot proceed to the point of affecting the intended function. Thus, it is not plausible (refer to page 2.0-52 of the LRA, Section 6.2.3, Create and Resolve the ARDM Matrix).

Auxiliary Building IWAC: Procedure MN-1-319 is already credited for detecting damaged coatings on HVAC external surfaces.

SW System: The staff's comments on pages 3-33 and 3-34 of the Safety Evaluation Report (SER)

(Reference 14) are in reference to internal coating degradation of Class MC piping that may be lined with saran, kynar, or neoprene. Historically, Calvert Cliffs has not experienced problems with these 9

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RESPONSES To LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS piping segments as was experienced with the cement mortar and epoxy lined components. The saran, kynar, and neoprene linings are expected to be in good condition. Thus, the ARDI Program is intended to verify expectations while assessing the current condition of the linings. Appropriate follow-up actions will be taken based on the results. Most of the Class MC piping in scope has been in service since plant construction, and it is sensible to reserve conclusions about necessary inspection l frequencies until after the initial conditions have been assessed.

As contained in BGE's letter on "First Annual Amendment to Application for License Renewal," j (Reference 11) in response to NRC Question No. I 1.6, BGE has elected to credit MN-1-319 instead of I the ARDI Program to inspect the SW System bolting for signs of general corrosion. Other Saltwater )

System components (besides the buried piping) are located inside plant structures and are, therefore, I protected from the outside environment. Although they receive periodic assessment through MN-1-319, there is adequate protection against corrosion during the renewal term without requiring credit for specific periodic monitoring for license renewal. In general, if there is no exposure to the outside environment, any potential degradation cannot proceed to the point of atTecting the intended function of these components. Thus, no aging mechanisms are plausible.

NSSS Sampling System: The staff's comments are in reference to external corrosion due to possible boric acid leakage from the miscellaneous waste evaporator concentrate pump discharge cooler. The IPA results have been revised based on the determination that there is no boric acid in the cooler.

Therefore, external corrosion due to cooler leakage is not plausible, and the ARDI Program will not be credited for managing this aging. All other locations of plausible external corrosion are already managed by MN-3-301," Boric Acid Corrosion Inspection (BACI) Program."(Reference 15)

Spent Fuel Pool Cooling System: The staffs comments r.re in reference to using the ARDI Program instead of the BACI Program to manage external corrosion due to possible boric acid leakage. The  ;

LRA has been revised, resulting in the BACI Program being credited instead of the ARDI Program for three of the locations of concern. This is reflected in BGE's letter " Changes to Application for License Renewal" (Reference 16) in the 10th bullet under Section 5.18 of Attachment (1). For the remaining two locations, filter IFL1999 and demineralizer OIXSFPI1, the LRA has been revised (see  ;

Attachment 3 of this submittal, Section 5.18) to credit an existing periodic activity that will be modified to perform the necessary inspections. Preventive Maintenance Program Repetitive Task 10672001 (Reference 17) will be modified to inspect OIXSFPil and IFL1999 supports during the vessels' Authorized Nuclear Inspections scheduled concurrent with the deminerahzer resm j changeout every two years. i

[

Open Item 3.2.3.1.1-1 The staff noted that the applicant did not consider the SG carbon steel tube support structures as \

susceptible to erosion-corrosion. The applicant, in its response to Generic Letter 97-06, " Degradation of Steam Generator Internals," referenced a Combustion Engineering (CE) topica! report that states erosion corrosion is a plausible ARDM under certain conditions. The staff requests that the applicant include erosion-corrosion he tube support structures as a plausible ARDM to be managedfor license renewal, and the staffrequests that the applicant submit an appropriate aging management program. In a letter dated November 19,1998, the applicant stated that it performs periodic visual inspections of the secondary side of the SGs (in particular the egg-crates and tube support plates) to lookfor signs of erosion and tube bundlefouling. However, the staffdoes not have enough information to conclude that this description of the applicant actions is enough to ensure the applicant will detect aging effects before there is a loss ofintendedfunction. Specifically, the applicant needs to clearly identify erosion-corrosion 10 l

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RESPONSES TO LICENSE RENEWAL SAFETY EVALUA110N REPORT OPEN ITEMS of the egg-crate supports as a plausible ARDM, and also needs to provide the specific inspection scope, the inspection frequency, and the acceptance criteria for these visual inspections. The staffis also reviewing separately the applicant's response to Generic Letter 97-06 a.ad will provide additional feedback relevant to this issue upon closeout ofthat generic letter.

BGE Response l

Baltimore Gas and Electric Company has determined that erosintccorrosion is a plausible aging mechanism for the CCNPP SG carbon steel tube support structures. Erosion-corrosion of carbon steel I eggerate tube support structures can be caused by an increased flow rate of secondary fluid between the tube bundle and the baffle outside the peripheral tubes. Increased flow of secondary fluid between the tube bundle and the baffle shroud can result from increased flow resistance from tube bundle fouling.

l The CCNPP Administrative Procedure EN-4-106," Steam Generator Tube Surveillance Program," is l credited with discovering erosion-corrosion of the SG tube supports. The procedure allows for the  !

inspectors to use the latest examination techniques to determine if there is any degradation to the SG l tubes or tube supports. [ Reference 18]  !

1 Remote visual inspections are conducted by lowering a video probe along the periphery of the tube l bundle. The results of the inspection are evaluated using a fixed grading criterion. Eggerate lattice bar structures are graded based on the most severe degradation viewed over the length of each lattice 3 bar between and including the adjacent intersections. Categories currently in use for the inspection l and grading criterion are described below: [ References 19 and 20]  !

e Category A - Eggerate lattice bar is in near new condition. This is characterized by a square f edged or near square edged lattice bar or minimal thinning over the length of the lattice bar. J e Category B - Eggerate lattice bar is clearly thinned, but more than 50% of the bar remains in l

place over the length of the lattice bar between and at the intersection with adjacent lattice j bars, i e Category C - Greater than 10%, but less than 50% of the lattice bar remains over the length of the lattice bar between and at the intersection with adjacent lattice bars. l f

. Category D - Less than 10% of the lattice bar remains over the length of the lattice bar or  :

parts of the lattice bar is completely degraded so that no bar remains at a location between adjacent lattice bar intersections or at the would-be intersections.

If two or more of the lattice bars at a single tube location are graded as Category D, then the eggerate is deemed to be inactive at that tube. Unit I was inspected in 1996 and 1998; no eggerate erosion was found. Unit 2 was inspected in 1999 and marginal, loct,lized eggerate lattice bar erosion was found.

All tubes in Unit I and 2 SGs found to be adequately supported. [ References 19 and 20]

The effects of periphery eggerate erosion have been evaluated for design and accident loadings and found to be benign. No wear or affect on the SG tubes has occurred because of the degradation of the {'

eggerates. The erosion-corrosion of the eggerate structures presently has no impact on the ability to comply with the design basis and licensing basis requirements for CCNPP. [ References 19 and 20] l As stated in the November 9,1998 Supplemental Response to NRC Generic Letter 97-06, (Reference 21), BGE will not visually inspect the Unit 1 SGs during the 2000 refueling outage. This l t

i li

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RESPONSES To LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITFMS decision was based on the lack of erosion-corrosion found during the 1996/1998 refueling outages, and the fact that Unit I has very low iron transport rates with no indications of severe tube bundle I fouling. The Unit 1 SGs are currently scheduled to be replaced during the 2002 refueling outage and I would not approach conditions conducive to erosion-corrosion prior to this replacement. The next visual inspection for the Unit 2 SGs is scheduled to occur during the 2001 refueling outage using the same inservice inspection techniques previously described above. The Unit 2 SGs are currently scheduled for replacement during the 2003 refueling outage. The BGE replacement SG eggerate lattice bars are being made of a stainless steel that is significantly more resistant to erosion-corrosion.

[ References 21 and 22]

To limit the effects of erosion-corrosion over the next Unit 2 fuel cycle, BGE flushed the SGs to remove corrosion products from the tube bundle. In addition, BGE preventively removed from service (plugged) those SG tubes that could be subjected to vibratory wear as a result of continued degradation of eggerate supports. To further minimize the effects of erosion-corrosion, BGE will continue to maintain proper secondary chemistry control through the use of CCNPP Technical Procedure CP-0217," Specifications and Surveillance: Secondary Chemhtry" (Reference 23). This secondary chemistry procedure, which is credited with mitigating the effeds of eggerate cosion-corrosion, is fully described in Section 5.9, Feedwater - Group 1, of the BGE LRA, beginning on page 5.9-9. [ Reference 19]

To account for the higher susceptibility of Unit 2 SGs to erosion-corrosion, CCNPP will optimize the Unit 2 secondary chemistry during the next fuel cycle to minimize feedwater iron transport. This strategy will be based on " Cycle pH Control with Advanced Amines to Minimize Feedwater Iron j Transport" and "No-Flow Condensate Demineralizers." Baltimore Gas and Electric Company will also reduce the amount of feedwater hydrazine to incrementally reduce the susceptibility of the Unit 2 SGs to erosion-corrosion. [ Reference 19]

i Open Item 3.2.3.1.1-2 In view of industry experience and data, the staff considers stress corrosion cracking (SCC) to be plausiblefor some pressuri:er and reactor coolant system (RCS) components, and should be managed by aging-management programs (AbfPs). The staf would consider thefollowing existing programs to be acceptable for managing the effects of SCC as AbfPs or portions of AbfPs: American Society of AfechanicalEngineers (AShfE) XI: TechnicalSpecifications leakage requirements; program based on the provisions ofNRC Bulletin 82-02, " Degradation of Thread:d &steners in the RCS Pressure Boundary of PWR Plants;" primary water chemistry control program. The staf would rely on these programs to manage SCC for the specified pressuri:er and RCS components, along with a description of and implementation commitment from the applicant to manage threaded fasteners in accordance with Bulletin 82-02. Otherwise, the applicant mustpropose an acceptable alternative.

BGE Response Stress corrosion cracking is the localized, non-ductile failure of a material caused by the simultaneous presence of tensile stresses, a corrosive medium, and a material with a susceptible microstructure.

Stress corrosion cracking is considered not plausible for the listed components and materials.

(Pressurizer cracking and SCC of the pressurizer is also considered in the response to Open Item 3.2.3.2.1-3.)

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RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS Stress corrosion cracking of stainless and low alloy steel primary system components has not been identified in CE pressurized water reactors (PWRs).

Cast austenitic stainless steel (CASS) and austenitic stainless steel cladding have microstructures that are not susceptible to sensitization and, thus, are not susceptible to intergranular stress corrosion cracking (IGSCC). However, they can be susceptible to chloride SCC Primary syscm water 1 chemistry controls ensure that the chloride concentration remains low so that this form of SCC remains not plausible. (BGE already credits, in its LRA, Administrative Procedure CP-0204,

" Specification and Surveillance, Primary System," (Reference 24) as an AMP for various other ARDMs considered plausible.) l Reactor Coolant System components tha.t were manufactured from low alloy steels and that are exposed to the primary coolant are clad to protect the components from the pwcess fluid environment. l A flaw in the cladding could allow the primary coolant to contact the low alloy steel and initiate l degradation. Reactor Coolant System water chemistry controls are designed to ensure that sulfate, oxygen, and chloride concentrations do not reach levels such that an environment conducive to SCC exists.

The microstructure of wrought austenitic stainless steel can also be susceptible to SCC. Welding procedures used during construction of CCNPP were specifically designed to prevent sensitization of austenitic stainless steels. These techniques were approved by the Atomic Energy Commission in the SER for CCNPP. In addition, as noted above, primary system water chemistry is controlled to ,

minimize the potential for the environmental conditions necessary to cause SCC. i i

No additional aging management programs are necessary.

Open Item 3.2.3.1.2-1 l In 10 CFR S4.21(a)(3), the Commission requires that,for each component subject to aging management, the applicant must demonstrate that the effects of aging will be adequately managedfor ths period of extended operation. The open issue pertains to the applicant's development of the scope of thefatigue monitoringprogram (FAfP)for the rea:torpressure vessel (RPV) and RCS omponents. The applicant has not completed its evaluation to identify the RPVand RCS components to be monitored by the FAfP.

Although the applicant stated it selected the components for monitoring on the basis of highestfa .'guer usage, the applicant has not completed evaluation of a!! RPV and RCS components. These adciOnal component evaluations may result in the identification of additionallocations that require monitoring by the FAfP. As a consequence, the scope of the FAfP, including the parameters that will be monitored by the FAfP, has not been completely defined. The applicant should:

  • Describe the scope of the CE review thatformed the basis for selecting the critical locations monitored by the FAfP.
  • Complete the one-time fatigue analysis of the reactor coolant pumps (RCPs), motor operated valves, andpressuri:er reliefvalves, and modify the FAfP as necessary. Discuss the results of the evaluation, identify additionallocations added to the FAfP, and describe the controlling transients andparameters that will be monitoredfor the locations added to the FAfP.
  • Complete the evaluation of the control element drive mechanism (CEDAf) and RV level monitoring system components and modify the FAfP as necessary. Discuss the results of the evaluation, identafy additionallocations added so the FAfP, and describe the controlling transients andparameters that will be monitoredfor the locations added to the FAfP.

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Complete the evaluation of the reactor vessel internals and modify the FAfP as necessary. The applicant should discuss the results of the evaluation, identify additional locations added to the FAfP, and describe the controlling transients and parameters that will be monitoredfor the locations added to the FAfP.

BGE Response First bulM Combustion Engineering determined the bounding components and locations and the controlling transients that CCNPP used to develop the FMP. The process CE used is as follows:

1. Combustion Engineering identified those systems that the UFSAR and Technical Specifications include for maintaining safe operations and achieving a safe shutdown of the plant. The result of this review was the " Identification of Critical Systems."
2. For each of the critical systems, CE reviewed all components within the system to identify those components with controlling fatigue usage limits. The critical system ceview included a review of industry data and experience as well as the original design documents associated with each system and/or component. The result of this review was the " Identification of l Component Critical Locations." l 1
3. Combustion Engineering then performed an evaluation for each component identified as a j critical location. This evaluation included an evaluation of the original stress reports to I identify the controlling design basis transients with respect to fatigue usage.
4. Combustion Engineering then developed a logging and procedure guideline for tabulatmg I cumulative fatigue usage for CCNPP to use in the development of the FMP. l l

The following systems or components were not included within the CE scope of work:

NSSS Sampling System j Pressurizer safetv valves Power operated n .i:f valves Auxiliary feedwater isolation and check calves Main feedwater check valves Main feedwater isolation valves RCPs Additionally, CE did not include potential thermal stratification loadings identified in NRC Bulletins 88-08 and 88-11 (References 25 and 26, respectively). However, BGE has incorporated components that do experience thermal stratification loadings in the FMP. The LRA did identify that BGE will complete an engineering review of the industry's task reports, with respect to thermal l stratification loadings, and determine any necessary changes to the piping analysis of record for the Safety Injection (SI) System and the impact of such changes on fatigue usage parameters by the FMP.

Calvert Cliffs used the results of the CE work to develop and implement the FMP.

l l

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RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS Remaining bullets Baltimore Gas and Electric Company's nuclear design engiaeering organization has a formal action item to complete the evaluation for these items. The evaluation will consist of a review similar to the CE review described above. If any of these new items are identified as fatigue critical components the FMP will be revised. The current scheduled completion is mid-2003, with any changes to the FMP currently scheduled to be completed by the end of 2003.

Open Item 3.2.3.2.1-1 i

The applicant must identify Technical Specipcation limits on SG leakage, which providefor defense in depth related to the detection of degradation in the SG tubes. The staff considers the Technical Specification limit ofSG leakage to be a necessary component ofan AMPfor SG tubes.

BGE Response Baltimore Gas and Electric Company credits Calvert Cliffs Surveillance Test Procedures (STPs)-O-27-1/2, " Reactor Coolant System Leakage Evaluation," (References 27 and 28) for discovering denting, wear and SCC /IGSCC/ primary water stress corrosion cracking (PWSCC) of the SG heat exchanger (HX) tubes.

l The procedure @l dhover these ARDMs by determining if the SG HX tubes are leaking RCS coolant. Calvert Cliffs Procedures STP-O-27-1/2 direct the user to perform calculations to determine the amount and potential source of RCS leakage. Any abnormal RCS leakage would be detected and actions taken to correct the leakage prior to a loss of the components intended function. The CCNPP STPs-O-27-l/2 are performed daily and in conjunction with other CCNPP procedures to determine i RCS leakage rates. The acceptance criteria for RCS leakage rates are provided by the CCNPP l Technical Specifications. This program has been observed to be historically effective in managing RCS leakage events. On several occasions, CCNPP has shut down due to RCS leakage associated l with the RCPs. These occurred primarily between 1978 and 1985, and resulted from minor leakage in l RCP sensing, instrument, and controlled leakoff lines. The leakage was discovered by STP-O-27-1/2.

Corrective actions were taken to repair the piping and to prevent future leakage in these pipe sections. 1 i

Opcn Item 3.2.3.2.1-2 In view of the SCC experience by the head closure seal leakage detection line and the safety consequences of a leak (a small break loss-of-coolant accident), the applicant needs to propose an AMP for SCC. The program the applicant proposed, RV-78 (Technical Procedure RV-78, " Reactor Vessel Flange Protection Ring Removal and Closure Head Installation (Unit I and 2)"], is merely mitigative.

BGE Response Baltimore Gas and Electric Company credits STP-O-27-l/2 for discovering SCC of the RPV head seal leakage detection line. The RPV head seal leakage detection line is pressurized or.ly in the event of leakage across the RPV head inner o-ring.

The procedure will discover this ARDM by determining if the RPV head seal leakage detection line is leaking RCS coolant. Frocedures STP-O-27-1/2 direct the user to perform calculations to determine the amount and potential source of RCS leakage. Any abnormal RCS' leakage would be detected and actions taken to correct the leakage prior to a loss of the components intended function. Procedures STP-O-27-l/2 are performed daily and in conjunction with other CCNPP procedures to determine 15

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RESPONSES TO LICENSE RENEWAL SAFETY EVALLIATION REPORT OPEN ITEMS RCS leakage rates. The acceptance criteria for RCS leakage rates are provided by the CCNPP t Technical Specifications. This program has been o5 arved to be historically effective in managing j RCS leakage events. On several occasions, CCNFr aa; shut down due to RCS leakage associated with the RCPs. These occurred primarily between 1978 and 1985, and resulted from niinor leakage in RCP sensing, instrument, and controlled leakoff lines. The leakage was discovered by the Prm.edure STP-O-27-1/2. Corrective actions were taken to repair the piping and to prevent future leakage in these pipe sections. l Open Item 3.2.3.2.1-3 For the cracking of pressuri:er shell, heads, including cladding cracking, the applicant stated that cracking was not plausible and did not need aging management. Industry experience has shown that cracking is a plausible ARDhi that requires agmg management, typically by inspections. The applicant shouldpropose an AhfP.

BGE Response I

Baltimore Gas and Electric Company does not consider cracking to be a plausib'e ARDM for pressurizer cladding. The sections below consider industry experience, CCNPP experience, a genal treatment of" pressurizer cracking" as opposed to SCC, and a general treatment of SCC. Some of this information pertains to the issue of R_V cracking, but it should also apply to pressurizer cracking due to the similarity of the materials, fabrication techniques, and process fluid environment.

Baltimore Gas and Electric Company believes the information below supports the position that cracking is not plausible. However, based on interactions with NRC Staff, BGE agrees to perform a one-time visual examination (VT-?, a type of visual examination described in ASME XI) of a portion of the cladding of one pressurizer by 2014. The area to be inspected will include portions of the top head and/or portions of the cylinder within one foot of the head weld. The inspection will look for evidence of cracking.

Industry Experience Industry experience with the cracking of pressurizer shell, heads, including cladding cracking, is extremely limited. The only significant instance known to BGE involved an indication on the pressurizer at the Haddam Neck plant. The Westinghouse Owners Group reported:

"In 1990, the Connecticut Yankee Atomic Power Company (CYAPCO) discovered and reported a 10- to 20-inch wide band of crack like indications in the Haddam Neck pressurizer cladding. The cracking extended 360 degrees around the circumference of the pressurizer and was located about I to 2 feed below the normal water level (References 6 and 7 of Reference 29]. NDE investigations established that at least some of the indications penetrated the cladding to the cladding-ferritic base metal interface. Review of plant operating records revealed that the same band ofindications had been reported as early as 1970. The indications may have been caused by a spray of cold water from the spray nozzle onto the cladding during a low water level transient, which the plant operating records show occurred prior to the 1970 inspection that first discovered the indications. Alternatively, the indications may have been present during initial start-up.

Whatever the cause of the indications, they apparently have been dormant since at least 1970, and therefore were not caused by an aging related degradation process such as fatigue or stress corrosion cracking. This condition has recently been reviewed to the satisfaction of the U.S. NRC.

On the basis that this condition is unique to the Haddam Neck pressurizer, and that it is not an aging related form of degradation, it is not considered further in this evaluation." (Reference 29) 16

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Based on this evaluation, BGE considers that industry experience does not support the plausibility of pressurizer cracking.

i l In response to NRC concerns, Southern California Edison performed a remote visual inspection of the l internal clad . surface of their San .Onofre Unit 1 pressurizer (same design as Haddam Neck i

pressurizer). No evidence of cla'd cracking was noted. Based on this inspection, BGE considers that industry experience does not support the plausibility of pressurizer cracking.

L CCNPP Experience There have been no instances of pressurizer cladding cracking at CCNPP. Fabrication of the pressurizer was controlled to prevent both underclad cracking and SCC. In evaluating these fabrication practices the NRC (Atomic Energy Commission) stated:

l "The applicant has stated in Amendment 15 that significant sensitization of all non-stabilized austenitic stainless steel within the reactor coolant pressure bouni.ry was avoided by materials I selection acd control of all welding and heat treating processes. . . . We have concluded that these )

techniques of avoiding sensitization of austenitic stainless steel during the fabrication period are j acceptable." (Reference 30)

Baltimore Gas and Electric Company's metallurgist has reviewed videos from 1989 pressurizer inspections. The videos clearly show no cracking in the Inconel trattom head cladding adjacent to a penetration. They also show no cracking in stainless steel cladding.

Baltimore Gas and Electric Company has demonstrated through a conservative fracture mechanics analysis that a crack larger than one inch would survive more than 2600 heat-up and cool-down cycles without growing to critical size. (Pressurizer design life is 500 cycles.) (Reference 31)

Baltimore Gas and Electric Company considers that CCNPP experience does not support the plausibility of pressurizer cracking.

Pressurizer Cracking No ARDM described simply as " Cracking" is considered ln the eging management review for the CCNPP pressurizer. Stress corrosion cracking is listed but is not plausible for the shell, head, or cladding. (SCC is discussed further in the following section.) Plausible ARDMs are ger.eral corrosion for the shell and head, and fatigue for the shell, head, and cladding. (Reference 32) i' Pressurizer cracking (as opposed to SCC or one of its variants) in presumed to be synonymous with underclad cracking and may be described as follows:

" Underclad cracking is the development of defects or cracks under the clad in the base metal / clad heat-affected-zone. Underclad cracking can develop by two different mechanisms. These mechanisms are reheat cracking and cold cracking. Underclad cracking due to the reheat mechanism is produced by a combination of three factors. These factors which aie needed to cause underclad cracking are a susceptible material (microstructure), residual stress, and heat treatment into the creep temperature range. Underclad cracking due to the cold cracking mechanism requires the combination of three factors. These factors are a susceptible material (microstructure), stresses on the order of yield stress, and diffusible hydrogen." (Reference 33, Section 2.10, page 2-24) 17

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RESPONSES TO LICENSE lb.NEWAL SAFETY EVALUATION REPORT OPEN ITEMS Underclad cracking is not an age-related phenomenon. For the few RVs that experienced underclad cracking, such preservice examination analyses showed that the flaws either met the allowable flaw indication standards or such flaws were removed or repaired to the extent necessary. (Reference 34)

No instances of underclad cracks have been reported in CE RVs. The two underciad cracking mechanisms are not considered plausible for the CCNPP pressurizer:

(Reheat cracking) Combustion Engineering precluded these factors from occurring in combination through detailed procedures and quality control. The detailed procedures were used to specify weld rod, welding position, speed of welding, interpass temperatures, and heat treatment. The controlled interpass temperatures and control of the heat input process precluded development of the susceptible microstructure and residual stress profiles for underclad cracking to occur.

Consequently, underclad cracking due to reheat cracks is not a degradation mechanism of concern. l (Cold cracking) The Combustion Engineering weld deposition procedures for the stainless steel I clad overlay prevent underclad cracking. The pre and post weld heat treatment specified in the procedures tended to reduce stresses and to produce material structures with less potential for cold cracking. Consequently, underclad cracking due to the cold cracking mechanism is not a degradation mechanism of concern. (Reference 33, Section 2.10, page 2-24) l Regulatory guidance reinforces this conclusion. The NRC has reported that:

" Underclad cracking has been reported only in forgings and plate material of SA-508 Class 2 composition made to coarse-grain practice when clad using high-deposition-rate welding processes identified as "high-heat-input" processes such as the submerged-arc 6-wire processes.

Cracking was not observed in SA-508 Class 2 materials clad by " low-heat-input" processes controlled to minimize heating of the base metal. Further, cracking was not observed in clad SA-533 Grade B Class 1 plate material, which is produced to fine-grain practice, regardless of the welding process used." (Reference 35)

The CCNPP pressurizer shell and 1.cd are fabricated from American Society for Testing and Materials (ASTM) A533 Grade B Class 1 material. (Reference 32)

In addition, for an ARDM to be considered plausible, the degradation must impact the component's ability to perform its intended function. Regulators have not determined that underclad cracking exceeds this threshold:

"The presence of intergranular cracking in low-alloy steel under stainless steel weld cladding has been observed in reactor vessels and other components for nuclear systems in varying degrees depending on the material and the cladding processes." . . . "From the results of certain analytical evaluations, it has been concluded that cracks of this nature will have no detrimental effect on the structural integrity of components under operating conditions. However, because uncertainties exist concerning assumptions made in these analyses as well as concerning the combined effects of strain concentrations and cyclic loading on crack growth, the presence of these cracks is undesirable." (Reference 35) 18

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Stress Corrosion Cracking Stress corrosion cracking is the brittle fracture or cracking of normally ductile material. This type of l failure mode is created by a combination of stress, material , and environment. Specifically, for SCC to occur three requirements must be met. These requirements are: (1) the existence of a tensile stress; (2) the existence of a corrosive environment (i.e., for stainless steels moderate to high oxygen levels);

and (3)the imposition of these conditions on a susceptible material such as sensitized Type 304 stainless steel over an extended period of time. (Reference 33, from Section 2.2, page 2-5)

In the CCNPP IPA RCS aging management review, SCC is evaluated for the pressurizer (including cladding), but is considered not plausible for the shell, head, or cladding. (Plausible ARDMs are general corrosion for the shell and head, and fatigue for the shell, head, and cladding.) The reasons for the non-plausibility determination are summarized:

"RCS pressurizer and subcomponents which are fabricated of stainless steel and are not sensitized (heat-treated) are not applicable to SCC and IGSCC. Components fabricated ofInconel that are not cold-worked are not susceptible to SCC or IGSCC. Those subcomponents fabricated of carbon or low alloy steel not in contact with RC fluid are not applicable to SCC or IGSCC . . . .

Tight water chemistry control via CP-204-2 also help make these ARDMs non-plausible for the pressurizer and subcomponents." (Reference 32)

Combustion Engineering evaluated the susceptibility of the CCNPP RCS to SCC:

" Stress Corrosion Cracking is not anticipated to be of significant concern for the Baltimore Gas and Electric reactor vessels. SCC is not anticipated to be a concern because the oxygen level in the primary water is kept low (<10 ppb). This is below the threshold for SCC to occur in stainless steel based upon a literature search and based upon the general lack of intergranular SCC in the primary system of Pressurized Water Reactors (PWR). In addition, SCC due to external contaminants is not anticipated to be of concern due'to stringent controls on the levels of chlorides, fluorides, sulfates, thiosulfates and nitrates permitted in materials that contact the primary fluid.

" SCC is not expected in the RPV stainless steel since Combustion Engineering carefully

. controlled material sensitization. The austenitic stainless steel applied to the reactor vessel as cladding centains more than 'S FN delta ferrite. In such complex austenitic/ferritic alloys, chromium-an carbides are precipitated at the ferrite-austenite interfaces during exposure to temperatures of 500 to 800*C. To avoid sensitization CE limited the interpass temperature on multiple pass welds in stainless steel to 350*F. In addition the combination the use oflow carbon content materials, of normal heat input using controlled welding procedures and interpass temperature control assured minimum carbide precipitation precluding sensitization of austenitic stainless steels.

"Further, SCC of stainless steel components is not expected because of the low stresses in PWR systems. These must be a significant tensile stress for stress corrosion to occur. A literature search found that 6% strain which is a significant deformation was required to cause intergranular SCC in sensitized type 304 stainless steel in pure water. It is likely that the low stresses and s trains in the PWR coupled with low oxygen in the primary coolant has generated conditions that simply do not promote SCC.

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RESPONSES TO LICENSE ILENEWAL SAFETY EVALUATION REPORT OPEN ITEMS

" SCC is also not expected to be a concern for the low alloy pressure vessel steel. Crack initiation is extremely difficult and requires the presence of 50 ppb oxygen in addition to tensile stresses based upon CERT tests on plate material. However, the stainless steel clad prevents exposure of the low alloy steel base metal to the water environment and its oxygen content. Even if the integrity of the cladding was breached, the low oxygen content in the bulk coolant and the insensitivity of the carbon steel due to heat treatment and controlled residual element content precludes SCC as a concern." (Reference 33, Section 2.2, page 2-5)

As indicated above, fabrication techniques for the CCNPP RCS were designed to prevent sensitization j of the stainless steel:

{

" Sensitization of stainless steel occurs when unstabilized 300 Series stainless material is held m l the temperature range of 900-1400 F for sufficient time to form a continuous network of l' chromium carbide precipitates. Sensitization occurs after approximately 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> at 900 F, as compared to one hour at 1400*F. Stabilized 300 Series stainless material avoids continuity of chromium carbide precipitates in the grain boundaries by careful control of metal chemistry.

"No furnace sensitized stainless steels are employed in the RCS pressure boundary. Sensitization is precluded from NSSSs through materials selection and control of all welding and heat treating procedures.

" Major portions of the RCS boundary in CE's nuclear plants are formed by carbon steels and a high nickel base alloy. None of these materials is susceptible to furnace sensitization (a continuous network of iron-chromium grain boundary carbides) in the sense of unstabilized 300 Series stain!ns steels. All internal carbon steel surfaces are weld-depositor roll-on clad with Inconel or stainless steel, to precluc'e excessive corrosion product release.

" Internal surfaces of the reactor vessel pressurizer and steam generator primary head are overlaid with 308 weld deposited metal. Weld metal composition is carefully controlled to overcome interface dilution and promote an austeno-ferritic duplex structure. Therefore, during the stress relief heat treatment (1150 F i 25 F) required by the ASME code for the pressure vessel, a continuous network of chromium carbide precipitates is not formed in the 308 weld overlay even though this material has been subjected to a furnace heat treatment. The delta ferrite acts as a carbon sink and prevents continuity of carbide precipitates.

" Extensive testing has confirmed that, properly formulated (a duplex structure), 308 weld deposited metal does not form a continuous carbide network within grain boundaries even following a typical vessel post weld beat treatment (viz.,1150 F for 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br />). Hence, the material is immune to intergranular corrosion.

"All other type 300 Series stainless steel used either is not subjected to a furnace sensitization heat treatment or, as is the case of cladding on the primary piping, is of type 304L (low carbon) composition and is not susceptible to the formation of continuous chromium carbide grain boundary networks." (Reference 36)

The NRC has raised the issue of low temperature sensitization. (Reference 37, Table B5 [PWR Pressure Vessel], page B-5) The austenitic stainless steel applied in the RCS is mainly the cladding, which contains more than 5 FN delta ferrite. In such duplex austenitic/ferritic alloys, chromium-iron carbides are precipitated at the ferrite-austenite interfaces during exposure to 500 C - 800 C. This 20

ATTACIIMENT (1)

RESPONSES To LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS precipitate morphology precludes intergranular penetrations. Therefore, there is no concern over sensitization of the cladding. (Reference 38, p. 2-2)

Based on this evaluation BGE maintains our position that cracking (underclad or SCC) is not plausible for the pressurizer shell, heads, and cladding. I Opea Item 3.2.3.2.1-4 The applicant shouldperform an augmented inspection ofsmall-bore pipingfor renewal. The augmented inspection would include inconel materials, and the information resultingfrom the response to[NRC}

Information Notice 90-10 should be considered in developing the augmented impection of Inconel materials. 1 BGE Response l

Baltimore Gas and Electric Company has already committed, in our ARDI Program, to inspect small bore piping in an environment similar to, but more severe than RCS. License Renewal Application pages 5.2-18 through 5.2-25 describe the ARDI Program inspections for Chemical and Volume Control System (CVCS) piping that is similar in material and environment to RCS. The differences in the internal environment is the lack of hydrogen overpressure for the CVCS piping in LRA Group 2.

Also, some of the CVCS piping in Group 2 contains a higher concentration of boric acid than that in the RCS.

l Baltimore Gas and Electric Company will apply the results of the ARDI Program inspections for CVCS Group 2 to RCS piping and take appropriate actions in accordance with our Corrective Actions Program.

Baltimo're Gas and Eicetric Company feels the ARDI inspections in the more severe CVCS Group 2 environment bound conditions in RCS small bore piping.

Open Item 3.2.3.2.4-1 The applicant should present a discussion of the accuracy of visual examinations required to provide reliable measurements of detectable wear used to assess the performance of the hold down ring in managing the aging effects of wear. 1 BGE Response The visual examination technique used for indication of depth of wear is accurate to 1/32-inch. This accuracy is sufficient to assess effects of wear so action may be taken prior to a loss of the intended function.

Open Item 3.4.3.2.1-1 For the chemical and volume control system, the applicant has committed to remove and replace all of the original heat tracing. The stafffinds that the preventive action, removing the source of halogens, will 1 effectively eliminate SCC as a plausible ARDM to be managed. There are no parameters monitored or l inspected as part of this plant modification. However, the staff believes there should be an inspection element to this plant modification to ensure that SCC caused by the original heat tracing adhesive, ifit has already started, will be detected and evaluated. The acceptance criterion and its associated basis should also be reported to the staff 21

ATTACIIMENT (1)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS BGE Response The failure mode of the one instance of SCC was determined in 1990 to be chloride ion SCC. The prerequisites for chloride ion SCC are aqueous chlorides, temperatures above 150 F (the heat trace setpoint), and tensile stress. These prerequisite factors were established at the time of the observed degradation by a damaged hanger (inducing the necessary stresses) and system leakage under the insulation covering the pipe. These conditions are currently less likely to occur in the necessary combination as they are now routinely managed by plant processes including system engineer walkdowns and the BACI Program. No additional SCC has been discovered during the extensive replacements performed thus far. Therefore, it is not expected that any additional SCC will be discovered during the remaining replacement work.

The installation instructions for the modification controlling the replacement of the heat tracing require the technician to completely remove the original heat trace cement and to ensure that the pipe is -le.a from any material that would prev:nt the aluminum tape of the new heat tracing from adhumg to the pipe. Any corrosion or other degradation on the piping surfaces would be discovered and noted during these steps. Appropriate corrective actions would follow. Baltimore Gas and Electric Company is considering additional non-destructive examination (NDE) for this modification to detect incipient SCC. Baltimore Gas and Electric Company will include further information regarding this item in the forthcoming submittal forwarding comments from the SER accuracy verification.

Open Item 3.4.3.2.1-2 Baltimore Gas and Electric Company shouldprovidejustification and an implementation schedulefor the plant modification in the CVCSfor mitigation ofpotential SCC caused by the original heat tracing adhesive.

BGE Response The failure mode of the one instance of SCC was determined in 1990 to be chloride ion SCC. The prerequisites for chloride ion SCC are aqueous chlorides, temperatures above 150 F (the heat trace setpoint), and tensile stress. These prerequisite factors were established at the time of the observed degradation by a damaged hanger (inducing the necessary stresses) and system leakage under the insulation covering the pipe. These conditions are currently less likely to occur in the necessary combination as they are now routinely managed by plant processes including system engineer walkdowns and the BACI Program. No additional SCC has been discovered during the extensive replacements performed thus far. Therefore, it is not expected that any additional SCC will be discovered during the remaining replacement work.

Commensurate with these results and experience, the replacement of the boric acid heat tracing is approximately one-third complete on each unit, and the current schedule calls for completion in year 4 2004.

Open Item 3.4.3.2.2-1 The applicant indicated that its FhfP review determined that all components in the CVCSfrom the regenerative HX to the RCS loop piping, andfrom the RCS loop piping to the letdown HX are subjected <

to fetigue loadings. The applicant also indicated that the design criteriafor the piping and valves requiredfatigue analyses. The applicantfurther indicated that, as part of the FhfP, the design analysis documents were reviewed to determine the area ofhighestfatigue usage. However, the applicant did not 22 .

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RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS l describe the process used to evaluate all the Group 1 components listed on page 5.2 14. Specifically, the applicant's response did not appear to address the flX and temperature element (TE) components. In a meetine on February 18,1999 (NRC meeting summary dated March 19,1999), the applicant indicated that the TE was included as part ofthe piping analysis. In addition, the applicant indicated that the result of the review of the HXs is contained in a CE report. On th: basis ofits review of that report, the applicant determined that the expectedfatigue usage ofthe llXs is enveloped by the locatiom monitored ,

by the FMP. The applicant should supplement its response to NRC Question 7.1 to include the review of i the TE andHXs discussedabove. l BGE Response As a supplement to BGE's response to NRC's request for additional information Question No.7.1 ,

(Reference 39), BGE agrees that, as indicated above, the thermal well of the TE is included as part of the pipe device type, and that CE Report CE-NPSD-634-P, " Fatigue Monitoring Program for Calvert Cliffs Nuclear Power Plant Units I and 2," April 1992, indicates that the regenerative and letdown HXs are enveloped by monitoring the charging nozzles.

Open Item 3.7.3.1.1.1-1 The applicant states that the external surfaces of the dieselfuel oil system are protected, in accordance with industrypractice, with external coating and wrapping and an impressed current cathodic protection j system. According to the applicant, the cathodicprotection system is not within the scope of the license renewal because it does not perform any of the system-intendedfunctions defined in 10 CFR 54.4(a)(1),

(2), and (3). The staff disagrees with this position because cathodic protection plays a role in the l protection of the piping. If the coatings are not used, the cathodic protection becomes inefficient. If the cathodic protection is not used, " holidays " [ thin spots, skipped areas, or where coating degradation has occurred] in the coating may cause locali:ed corrosion, and the pipeline mayfail more rapidly than if the

e ,'ine were not coated. Therefore, the staffinds that the applicant needs to identify both coatings and cathodicprotectionfor buriedpipelines to be within the scope oflicense renewal.

BGE Response Crevice corrosion, galvanic corrosion, general corrosion, microbiologically-induced corrosion, and pitting are all considered plausible aging mechanisms for the external surfaces of buried piping.

Baltimore Gas and Electric Company has credited a new program, the Buried Pipe Condition Monitoring Program (BPCMP), in Sections 5.7.2 and 5.1.2 of the LRA, for discovery of corrosion of the subject buried piping. Any evidence of the effects of crevice corrosion, galvar' corrosion, general corrosion, microbiologically-induced corrosion, and pitting will initiate correct . ,tions in accordance with the Corrective Actions Program.

As stated in Sections 5.7.2 and 5.1.2 of the LRA, the external surfaces of buried piping are protected, per standard industry practice, with external coating and wrapping and an impressed current cathodic protection system. The cathodic protection of the buried piping is provided by the non-safety-related cathodic protection system. The coatings and cathodic protection system are not within the scope of license renewal because they do not perform any of the system intended functions defined in 10 CFR 54.4(a)(1), (2), and (3). Although the coatings and cathodic protection system play a role in the protection of the piping, and therefore are key considerations for the new program, they were conservatively not credited when determining plausible aging mechanisms and are not credited as l specific aging management programs for the buried piping.

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RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS The coatings and cathodic protection system are considered to be design features of buried piping.

The failure of the cathodic protection system to operate will not cause or allow significant corrosion of serviced components in the short term. The cathodic protection system is currently tested quarterly l l and adjusted to provide the optimal protection for the serviced components. Checks on syster l operation and performance are included in the site Preventive Maintenance Program. The system a normally not permitted to be out-of-service for more than 60 days. In general, surveys have found  !

l present protection levels to be satisfactory. Where protection levels have been found to be higher or {

lower than desired, the system has been or is being upgraded.

A number ofinspections have been performed on buried piping prior to, and during development of, l l the BPCMP. These inspections, most of which were performed more than 20 years after installation, I have identified some minor coating damage, confirmed the effectiveness of the combined design features of coatings and cathodic protection, and ider.tified piping insulation as a significant factor in buried pipe degradation. Inspection results have been consistent with cathodic protection survey results and resulted in appropriate improvements to the cathodic protection system.

The BPCMP will provide for additional inspections through the period of the current licenses and, as l appropriate, during the period of extended operation. A general description of the program is provided below, including the consideration of the coatings and the cathouic protection system.

l The BPCMP scope will include buried and transition portions of piping in the Diesel Fuel Oil and i Auxiliary Feedwater Systems. Visual inspections will be performed by competent personnel for )

l evidence of coating perforation, holidays, and other damage, for evidence of pipe degradation, and for l evidence of the continued effectiveness of the cathodic protection system. Baltimore Gas and Electric Company may also employ internal examinations to assess pipe wall condition (i.e., eddy current testing).

Baltimore Gas and Electric Company relies on the results of previous inspections and operating experience to determine the scope and timing for subsequent inspections. The periodicity of these inspections will be such that there is reasonable assurance the pipe wall condition will be found acceptable at the next scheduled inspection.

Variables and experience considered in the scope and timing ofinspections will include:

  • Design factors (i.e., cathodic protectEn proximity, materials, coatings, insulation);

l

  • Environment (i.e., soil composition & conditions, wall or surface penetration, other structures  !

in the area that affect the pipe);

e Results of previous inspections; e Results of cathodic protection system preventive maintenance activities, including tap settings, voltage and current readings, and cathodic protection potential surveys; and

  • Occurrence of nearby events that may have damaged pipe coating.

t Evidence of coating perforation, holidays, or damage, and evidence of pipe damage will be evaluated in accordance with the CCNPP Corrective Actions Program. This program implements the requirements of 10 CFR Part 50, Appendix B, and includes provisions for repair or replacement, determining root cause, assessing generic implications, and establishing action to prevent recurrence.

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ATTACIIMENT (1)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS (

Open Item 3.9.3.2.3-1 The licensee has stated thatfatigue is a plausible ARDAffor components such as valves and certain pipe segments in the reactor coolant sampling subsystem associated with sampling of thefluidfrom the RCS hot leg. These components provide the passive intendedfunction of maintaining the system pressure boundary. The materialfor the pressure boundary is stainless steel with an internal environment of borated water. The bolting material is low-alloy steel or carbon steel. Low-cycle thermalfatigue is a plausible ARDAffor components in the reactor coolant sampling subsystem since they experience severe i thermal cycling during routine RCS sampling operations. This aging mechanism, if unmanaged, could \

eventually result in crack initiation and growth so that the components may not be able to perform their l pressure boundaryfunction under current licensing basis (CLB) design loading conditions. However, the licensee has not discovered any low-cycle fatigue-relatedfailures in the NSSS sampling system. The licensee has stated that there are nopracticcble means available to mitigate the effects of the malfatigue, but has established an FAfP to monitor and trackfatigue usagefactors oflimiting components of the NSSS and SGs. Tracking the usage factors of the limiting components ensures that all remaining components willalso remain below theirfatigue limits. The FAfP willinclude an engineering evaluation to determine if the low-cycle fatigue usage ofpiping and valves in the RCS hot-leg sampling line is bounded by the existing analysisfor the bounding components. If these components are not bounded, they will be reviewed under the FAfP to verify the fatigue usage factor for these components, and consideration will be given to the magnitude andfrequency of thermal cycles imposed by RCS sampling activities. The staff considers this approachfor monitoringfatigue usagefactors of components in the NSSS sampling system acceptablefor managing this ARDAf so that these components will be capable of performing their intendedfunctions consistent with the CLB during the period of extended operation under all design loading condition. However, the applicant should provide its evaluation as stated in page S.13-29 of Appendix A to the LRA, to demonstrate that the low-cyclefatigue usage ofpiping and valves in the RCS hot-leg sampling is bounded by the monitoring of11 fatigue-criticallocations in the RCS.

BGE Response Baltimore Gas and Electric Company's nuclear design engineering organization has a formal action item to complete the evaluation for these items. The current scheduled completion is mid-2003, with any changes to the FMP currently scheduled to be completed by the end of 2003.

Open Item 3.10.3.2.1-1 In NRC Question No. 3.3.12, the staf asked the applicant to summart:e the time-limited aging analysis (TLAA) that will be performedfor the three types ofcontainment prestressing tendons and to explain the basic assumptions and limitations that will be used in the evaluation. In response to NRC Question No. 3.3.12, the applicant indicated that the expected tendonforce curve would be based on straight lines plotted on semi-log paper like most time-dependent decay curves. Upper and lower bounds are usually drawn parallel, and superimposed on the plot with some lower limits to reflect design requirements with some margin. During the February 17,1999, meeting (NRC meeting summary dated Afarch 19,1999),

the applicant stated that according to information provided in the letter from the applicant (October 28,1997), the vertical tendons, in general, possess reasonable tendon h'ft-offforce margins in the order of 25 kips. The staff requested the applicant to demonstrate that the trending analyses of the three types of tendons will ensure that the actualprestressingforces in the tendons are above the lower bound limits during the extendedperiod ofoperation.

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RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS in addition, predicted tendon lift-offorce (F )pverssa time (T) curves for each of the three groups of tendons (i.e., vertical, hoop, and dome tendons) having similar characteristics (e.g., alignment, orientation, lockofforces and environmental conditions (such as temperature, humidity, anchorage exposure). Regulatory Guide 1.35.1provides guidance on how to do this. Ifthe trending analysis of the measured tendonforce (Fn) vs. time (T) curve is above the lower boundpredicted curve extended up to the end oflicense renewal term, the extended p F curve (for the group) may be usedfor comparison with the tendon lift-offorces measuredduringfuture surveillance. Ifthe trending ofFm indicates that it will be below the extended Fp curve within the current license or during the extended license term, a systematic program for retensioning the tendons needs to be developed to ensure that the minimum prestressing requirement of the current licensing becis is met up to the end ofthe extended term. Because this type ofinformation is not available in ase LRA, the sta[fcannot make a safetyjudgment regarding the applicant's TLAAfor tendon prestressingforce in containment at this time. This item is considered as a part ofthis Open item.

BGE Response The normalized average lift-off forces (kips) for hoop and dome tendons measured during CCNPP's 20th Year Surveillance of the Unit 1 Containment Building Post-Tensioning System were 621 and 632, respectively. Vertical tendon lift-off forces were 685 for Unit I and 664 for Unit 2. As shown on UFSAR figures 156-1 through -3, the required average forces are:

Hoop tendons 536 kips Vertical tendons 622 kips Dome tendons 555 kips This indicates that there is ample margin. However, the tendons can be retensioned in the unlikely event that they lose enough prestress to fall below required values.

In accordance with American Concrete Institute (ACI) Code 318-63, the containment design provides for prestress losses that can be predicted with sufficient accuracy as described in Calvert Cliffs UFSAR Section 5.1.4.2. The environment of the prestress system and concrete is not appreciably different from that found in numerous bridge and building applications. Considerable research has been done to evaluate the causes of prestress losses and this information was used to assign appropriate allowances. Building code authorities consider it acceptable practice to develop permanent designs based on these allowances. The structural integrity of the containment shall be

. maintained at a level consistent with the acceptance criteria in the verification requirements identified in UFSAR Section 15.6.1. Curves describing the predicted prestress loss behavior are contained in UFSAR Figures 15.6.1-1,15.6.1-2 and 15.6.1-3. These curves will be extrapolated out to 60 years for the extended license period using this CLB.

A licensing basis surveillance change will result from the new rule recently listed in 10 CFR 50.55(a), l I

incorporating ASME Section XI, Subsection IWE/IWL requirements. 10 CFR 50.55a(bXix) requires an evaluation of prestressing force trends for each tendon and groups of tendons to ensure that the predicted tendon forces at the next scheduled examination meet the minimum design prestress requirements. If these requirements are not met, an evaluation is required in accordance with the

! Engineering Evaluation Report as prescribed in IWL-3300. The IWL-3300 Evaluation requires determination of the cause of the condition, acceptability without repair, whether repair / replacement is required, if repair / replacement is required, the extent, method and required completion date. This is j an acceptable inservice inspection and surveillance method for ungrouted tendons in prestressed 26 i

ATTACIIMENT (1)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS concrete containment structures as previously acknowledged by the staff. It currently provides adequate aging management of the tendons and will continue to provide adequate aging management into the extended license peried.

Open Item 3.10.3.2.2-1 In NRC Question No. 3.3.36, the stafraised a concern about sustained exposure ofbelow-grade concrete slabs and walls of the intake structure to groundwater. The applicant 's initial response did not give any information indicating the benign chemistry of the groundwater, or historical evidence to demonstrate that the concrete walls andslabs are not subject to aging efectsfrom sustained exposure to groundwater.

On Afarch 1,1999, the applicantprovided afacsimile, which was subsequently docketed in NRC meeting summary dated Mar h 19,1999, that contains the chemical analysis data for the groundwater. The groundwater analysisfor two out of three wells indicated that the groundwater chemistry is benignfrom )

the standpoint of causing aging related degradation of the exterior of the concrete walls and slab.

However, an analysis ofone well on the west side indicated very high chloride and sulfate content. In a telephone conference on March 2,1999, the staf requested the applicant to commit to inspect some portion of the external surfaces of the exterior walls at least once before the start of the period of extended operation.

BGE Response Baltimore Gas and Electric Company considers the environment on the surfaces of the concrete walls of the Intake Structure to be more aggressive on the bay water side than on the soil side. This is based on the chemical analysis data previously submitted as well as a lower exposure to oxygen on the soil side. Therefore, we will rely on visual inspections performed on the bay water side to verify that no significant degradation of the concrete surfaces on the soil side is occurring. The Intake Structure intake cavity walkdowns are periodically performed during refueling outages (when the intake cavities are dewatered) under CCNPP Maintenance Program (Procedure MN-1-319). If significant evidence of degradation is discovered on the bay water side, an assessment of the potential for similar degraded ,

conditions on soil side will be made. Procedure MN-1-319 will be modified to assure this assessment I l

of potential degradation on the soil side is made. The assessment and any required corrective actions would be conducted in accordance with the Corrective Actions Program.

Open Item 3.10.3.2.3-1 In Table 3.3A-4, " Containment System Components Potential and Plausible ARDMs," in Appendix A to the LRA, the applicant listed corrosion / oxidation of the metal portions as the potential ARDMfor electricalpenetrations (non-EQ). In NUREG/CR-5461, " Aging of Cables, Connections, and Electrical Penetration Assemblies Used in Nuclear Power Plants", the staf concludes that the sealing material, cable insulation, and header plate 0-rings in electrical penetrations may be susceptible to aging degradation. The applicant has not addressed the aging effects ofradiation and temperature upon these and other non-metallic elements.

BGE Response The non-EQ electrical penetration assemblies (EPAs) are in scope for their containment pressure boundary intended function only. Section 3.3A of Appendix A to the LRA has been revised (see Attachment 3 to this letter) to be consistent with the conclusions reached in Section 6.3 of the appendix for the EQ EPAs. Thus, radiation damage and thermal damage are considered plausible in Section 3.3A for the non-metallic subcomponents of the same model EPAs as those for which the mechanisms were considered plausible in Section 6.3. However, because the non-EQ EPAs are not 27

ATTACIIMENT (1)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS encompassad by the EQ Program and are only in scope for their containment pressure boundary intended function, their aging management will be accomplished by existing local leak rate STPs-M-5711-1, M 571J-2, M-571K-1 and M-571K 2 (References 40,41,42, and 43, respectively),

which are part of the overall CCNPP Containment Leakage Rate Testing Program.

Open Item 3.11.3.2.2.1-1 Baltimore Gas and Electric Company should provide information and/or the basis to demonstrate how the preventive maintenance tasks for managing the efects of general corrosion / oxidation for Fuel Handling Equipment and Heasy Load Handling Crane systems will be implemented and why this program adequately manages aging.

BGE Response Baltimore Gas and Electric Company understands from NRC staff that this is not an issue, as indicated by the discussions in the main body of the SER.

Open Item 4.1.31 The list of TIAls providedpursuant to 10 CFR S4.21(c)(1) does not include the upper-shelfenergy of the RV materials, including the most limiting material based onfluence and chemistry of the vessel material.

The applicant stated during the on-site meeting held between February 16-18,1999, that irradiation embrittlement as measured by the drop in Charpy upper shelf energy is not a TIAA since it does not satisfy the Tlk! depnition in 10 CFR S4.3. The NRC staf however, has concluded that this is a Tiht.

The applicant should include upper shelfenergy evaluation in their list of Tikts. This Open item should be resolvedin conjunction with Confirmatory item 3.2.3.2.1-2.

HGE Response Analyses applicable to neutron irradiation of the RVs had been extended from 40 years to 60 years prior to BGE implementing its TLAA identification and evaluation process. Therefore, the analyses did not meet 10 CFR 54.3(a)(3). Had this not been the case, these analyses would have been ,

identified as TLAAs and the activities that extended them to 60 years would have subsequently caused them to be dispositioned as "The analyses have been projected to the end of the period of extended operation" in accordance with 10 CFR 54.21(c)(1)(ii).

Open Item 4.1.3-2 The loss ofprestress on containment tendons is time-dependent as a result of age-related degradation, such as creep and shrinkage ofconcrete, stress relaxation, corrosion and anchorage seating losses, etc.

The calculation of normali:ed hft-of force of tendons specijled in the technical specification Figures 3.6.1-1, 3.6.1-2, and 3.6.1-3 is a Tikt. The technical specapcation surveillance test is a measure of hft-offorce to ensure that the prestress loss of tendons is within acceptable limits. The applicant has stated that the curves in the technical specylcation pertaining to the predicted hft-offorce will be recalculated by the year 2012 to accountfor the period ofextended operation. The deferral of the recalculation of the parameterfor the renewal term is, therefore, identified as an Open item. The details ofthis Open Item are setforth in Section 3.10 of this SER.

BGE Response Baltimore Gas and Electric Company believes this item is very closely related to Open Item 3.10.3.2.1-1 above and that the response to that Open item addresses this item as well.

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RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS  !

Open Item 4.1.3-3 With respect to metalfatigue (from thermal cycles) of USAS B31.7 Class 11 and 111 piping components (other than main steam piping), the applicant stated in the same meeting that these components have a stress limit based on 7000 cycles and,further, their data search did not identify this issue as a TLAA. In the application, however, the applicant discusses expected cycles during theperiod ofextended operation for some components. These assessments as TLAAs. In addition, during the site meeting. the applicant indicated that the number ofcycles was considered in their evaluation ofClass 11and 111 piping. Hence, the applicant should identify its assessment as a TLAA.

BGE Response During the aging management review process for the Class 2 and 3 systems, BGE considered fatigue a potential ARDM. For the Class 2 and 3 systems where the LRA identifies fatigue as not plausible, BGE considered the following to make the not plausible determination:

1. The AT between system shutdown temperature and maximum operating temperature. If the AT was small (say 50 F), fatigue was not plausible.
2. If the AT was larger, BGE conservatively estimated the number of thermal cycles for 60 years using plant operating history. If the number of thermal cycles was less than the design number ofcycles, fatigue was not plausible.

Baltimore Gas and Electric Company does not include this as a TLAA.

REFERENCES

1. NRC Branch Technical Position (BTP) APCSB 9.5-1, " Guidelines for Fire Protection for Nuclear Power Plants Docketed Prior to July 1,1976," August 23,1976

- 2. Letters from Mr. K. R.. Goller (NRC) to Mr. A. E. Lundvall, Jr. (BGE), and from Mr. R. S. Boyd (NRC) to Mr. J. W. Gore, Jr. (BGE), both dated September 30,1976, Fire Protection

3. Letter from Mr. A. E. Lundvall, Jr. (BGE) to Mr. V. Stello, Jr. (NRC), dated March 15,1977,

" Fire Protection Study" 4.' NRC Regulatory Guide 1.52, " Design, Testing, and Maintenance Criteria for Post Accident ,

Engineered-Safety Feature Atmosphere Cleanup Sy.ttem Air Filtration and Adsorption Units of I Light-Water-Cooled Nuclear Power Plants," March 1978

5. NRC " Safety Evaluation Report by the Office of Nuclear Reactor Regulation U. S. Nuclear Regulatory Commission in the Matter of Baltimore Gas and Electric Company Calvert Cliffs Nuclear Power Plant Units 1 and 2 Docket Nos. 50-317 and 50-318," September 14,1979
6. Nuclear Consulting Services, Inc. Report NUCON 6BG021/01, "A Computer Analysis of the i

Iodine Decay Heat Generated in a Carbon Bed Following a Loss of Coolant Accident,"

. January 19,1990

7. Nuclear Consulting Services, Inc. Report NUCON 6BG021/01, Supplement 1. "A Computer Analysis of the lodine Decay Heat Generated in a Carbon Bed Following a Loss of Coolant Accident," July 25,1990

. 29 L _

ATTACHMENT (1)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS

8. BGE 50.59 Evaluation Log No. 90-B-061-086-R2 (Facility Change Request 90-0020),

December 4,1990

9. BGE Fire Protection Engineering Evaluation No.12, " Fire Protection Impact of Removing Dousing System in Containment iodine Charcoal Filters," March 30,1991

)

10. CCNPP Fire Hazards Analysis Summary Document, Revision 0, June 4,1997
11. Letter from Mr. C. H. Cruse (BGE) to NRC Document Control Desk, dated April 2,1999, ,

"First Annual Amendment to Application for License Renewal" l

12. Letter from Mr. C. H. Cruse (BGE) to NRC Document Control Desk, dated April 8,1988,

" Application for License Reneveal"

13. CCNPP Administrative Procedure MN-1-319," Structure and System Walkdowns," Revision 0
14. Letter from Mr. D. B. Matthews (NRC) to Mr. C. H. Cruse (BGE), dated March 21,1999, "Calvert Cliffs Nuclear Power Plant, Units 1 and 2, License Renewal Safety Evaluation Report" l
15. CCNPP Administrative Procedure MN-3-301, " Boric Acid Corrosion inspection Program,"

Revision 1

16. Letter from Mr. C. H. Cruse (BGE) to NRC Document Control Desk, dated February 4,1999,

" Changes to the Application for License Renewal"

17. CCNPP Procedure GEN-05, " Radioactive Filter Replacement," Revision 10, February 9,1999
18. CCNPP NUCLEIS Database, Repetitive Task 10672001,11 Spent Fuel Pool Filter
19. Calvert Cliffs Administrative Procedure EN-4-106, " Steam Generator Tube Surveillance Program," Revision 1
20. BGE Engineering Service Package ES199900524-000, Revision 0, " Evaluation of Steam Generator Eggerate Erosion," April 22,1999 l
21. BGE Root Cause Analysis Report, PD199900002," Degraded eggerate Tube Support Assembly in Calvert Cliffs 22 Steam Generator," April 23,1999
22. Letter from Mr. C. H. Cruse (BGE) to NRC Document Control Desk, dated November 9,1998,

" Supplemental Response to NRC Generic Letter 97-06: Degradation of Steam Generator internals"

23. CCNPP Steam Generator Project Plan, Revision 2, May 28,1997
24. CCNPP Technical Procedure CP-0217, " Specifications and Surveillance: Secondary Chemistry," Revision 5, December 18,1995
25. CCNPP Technical Procedure CP-0204, " Specification and Surveillance: Primary Systems,"

Revision 8

26. NRC Bulletin 88-08," Thermal Stresses in Piping Connected to Reactor Coolant Systems, June 22,1988
27. NRC Bulletin 88-11," Pressurizer Surge Line Thermal Stratification, dated December 20,1988
28. CCNPP Surveillance Test Procedure 0-27-1, " Reactor Coolant System Leakage Evaluation" l (Unit 1), Revision 16
29. CCNPP Surveillance Test Procedure 0-27-2, " Reactor Coolant System Leakage Evaluation" (Unit 2), Revision 14 l

30 I

I l

ATTACHMENT (1)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT OPEN ITEMS l

30. The Westinghouse Owners Group Aging Management Evaluation for Pressurizers (July 1996), l Section 2.6.3, Haddam Neck Pressurizer Clad Cracking f
31. NRC Safety Evaluation by the Directorate of Licensing U.S. Atomic Energy Commission in the Matter of BGE Calvert Cliffs Nuclear Station, August 28,1972 32 Letter from Mr. C. H. Cruse (BGE) to NRC Document Control Desk, dated August 4,1998, "American Society of Mechanical Engineers Boiler and Pressure Vessel Code Required .

Submittal Related to the Unit 2 Pressurizer Instrument Nozzle Repair"

33. CCNPP IPA Reactor Coolant System Aging Management Review Report, Revision 5
34. Assessment of the Degradation Mechanisms of Low Concern for Life Extension for BGE Calvert Cliffs Units 1 & 2 Reactor Pressure Vessels, Combustion Engineering Report, February 1989
35. Electric Power Research Institute Report EPRI-TR-103837, Pressurized Water Reactor Pressure Vessel License Renewal Industry Report, Revision 1, Section 3.3.2, Underclad l Cracking, page 3-17 l 36. Regulatory Guide 1.43, Control of Stainless Steel Weld Cladding of Low-Alloy Steel l Components, May 1973
37. CCNPP UFS AR, Revision 25, Section 4.1.4.3, Welding Procedures
38. NUREG-1557, Summary of TechnicalInformation and Agreements from Nuclear Management and Resources Council Industry Reports Addressing License Renewal
39. Assessment of Low Temperature Sensitization of Austenitic Stainless Steels for Life Extension for BGE Calvert Cliffs Units 1 & 2, CE Report, February,1989 l
40. Letter from Mr. C. H. Cruse (BGE) to NRC Document Control Desk, dated  ;

November 19,1998," Responses to Requests for AdditionalInformation for the Review of the '

Calvert Cliffs Nuclear Power Plant, Units 1 & 2, Integrated Plant Assessment on Metal Fatigue"

41. CCNPP Surveillance Test Procedure M-571J 1," Unit i Local Leak Rate Test, West Electrical l

Penetrations" l

42. CCNPP Surveillance Test Procedure M-571J-2," Unit 2 Local Leak Rate Test, West Electrical
Penetrations" l 43. CCNPP Surveillance Test Procedure M 571K-1," Unit 1 Local Leak Rate Test, East Electrical l Penetrations" l 44. CCNPP Surveillance Test Procedure M-571K-2," Unit 2 Local Leak Rate Test, East Electrical 1

Penetrations" l

l l

31

ATTACHMENT (2) l l

l RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION R rPORT CONFIRMATORY ITEMS l

Baltimore Gas and Electric Company Calvert Cliffs Nuclear Power Plant July 2,1999

ATTACIIMENT (2)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT CONFIRMATORY ITEMS Confirmatory Item 2.2.3.4.2.2-1 Table 3.3A-1, " Containment Structure Component Types Requiring an aghg management review j (AAfR),"in Appendix A to the License Renewal Application (LRA) designates the containment structural \

components subject to an AAfR. The containment tendon gallery protects the bottom anchorages of the  !

vertical tendons, andgive access to the tendon anchoragesfor inservice inspection activities. The tendon gallery is categori:ed as a non-safety-related element of the containment structures. Baltir.. ore Gas and l Electric Company (BGE) indicated that the tendon gallery is not relied uponfor containment integrity in the seismic ancdyses or design-basis events. Documentation ofthis basisfor excluding the tendon gallery from the scope ofthe structural elements subject to an AAIR is a confirmatory item.

l BGE Response '

This item is addressed in NRC Inspection Report Nos. 50-317/99-02 and 50-318/99-02 (Reference 1),

which, on page 8 indicates,"The NRC inspection team concurs with the applicant's screening of the Primary Containment categories, which require aging management review, and the applicant's exclusion . . ."

Confirmatory Item 2.2.3.17.2.2-1 The basisfor excluding solenoid valvesfrom an AAfR may be validprovided that the pressure boundary provided by the valve body is not relied uponfor the system intendedfunctions, as is describedfor the Safety injection (SI) System in Section 2.2.3.28.1. The solenoid valve pressure boundaryfunction has been properly included in the scope of the AAfRfor other systems (for example, Reactor Coolant System

[RCS) in Section 2.2.3.9.2.2). Verification of the appropriate exclusion basisfor solenoid valves in the Containment Spray System and the Compressed Air Section (see Section 2.2.3.15.2.2) is a Confirmatory item.

BGE Response .

Containment Spray System: The staff's comments are in reference to solenoid valves ISV4150, ISV4151,2SV4150 and 2SV4151. The valve bodies do not perform a pressure boundary intended function.

Compressed Air System: The staff's comments are in reference to solenoid valves ISV2085 and 2SV2085. The entire valves, including the valve bodies, are replaced based on a qualified life that is less than 40 years.

Confirmatory Item 3.1.3.3-1 In addition to the elements discussed above, the staff in a letter dated September 7,1998, requested that the applicant discuss the use ofprocedure ALV 1-319, " Structure and System Walkdowns,"for identifying and managing the aging effects ofreinforced-concrete structures. The applicant, in its response dated November 19,1998 stated that the omission of aging mechanisms for concrete walls, covered by the structure walkdown reports used by procedure AfN-1-319, is an oversight. As such, the structure walkdown reports will be modified to detect the aging effects ofreinforced-concrete structures. This is a Confirmatoryitem.

I

ATTACIIMENT (2)

RESPONSES To LICENSE RENEWAL SAFETY EVALUATION REPORT CONFIR5tATORY ITESIS BGE Response Based on the discussion presented in the BGE response of November 19,1998, (Reference 2)

MN-1-319 (Reference 3) will be revised to clearly provide for the inspection of reinforced concrete walls within Concrete Structures other than Containment.

Confirmatory Item 3.1.4.3-1 The applicant plans to modify the boric acid corrosion inspection program to specify examinations during each refueling outage of the reactor vessel (RV) cooling shroud anchorage to the RV headfor evidence of borated water leakage and all RV cooling shroud structural support members for general corrosion / oxidation. A Confirmatory item will be used to capture this modipcation and its schedule.

BGE Response Baltimore Gas and Electric Company plans to modify the Boric Acid Corrosion Inspection Program as described above. The modification to the procedure is currently scheduled for completion by March 1,2000. ,

l Confirmatory Item 3.1.5.3-1 l An appropriate description should be provided in a supplement to the Final Safety Analysis Report and/or in the applicant's " Quality Assurance Policyfor the Calvert Chffs Nuclear Power Plant" to indicate that the applicant's Appendix B program also applies to non-safety-related structures and components that are subject to AMRfor license renewal. such that any changes to the programs or activitics that may affect their effectiveness in managing aging can be appropriately controlled.

f BGE Response The discussion in Section 3.1.5 of the Safety Evaluation Report (SER)(Reference 4) is on Calvert Cliffs' Corrective Actions Program. While it is true that the Corrective Actions Program is pursuant to 10 CFR Part 50, Appendix B, it is not true that all elements of the Appendix B program applyto all non-safety-related structures and components that are subject to AMR for license renewal. To clarify BGE's position, the current scope of the Corrective Actions Program includes all structures and components that are subject to AMR for license renewal, whether they are safety-related or not. The Corrective Actions Program implements the requirements of 10 CFR Part 50, Appendix B. However, the other aspects of the Appendix B program do not necessarily apply to all the programs or activities associated with non safety-related structures and components that are subject to AMR for license renewal.

For example, BGE considers it inappropriate to apply the same controls to the procurement, records management, or audit of non-safety-related fire hoses or fire main piping as are applicable to safety-related RCS pressure boundary components. Similar examples can be cited for other Appendix B l criteria. l Therefore, the staff should only conclude that BGE's Corrective Actions Program satisfies the elements of " corrective actions," " confirmation process," and " administrative controls." This conclusion is correctly stated in Sections 3.1.3.3, 3.1.4.3, 3.1.6.3, 3.2.3.2, 3.3.3.2, 3.4.3.2, 3.6.3.2, 3.8.3.2, 3.10.3.2, 3.11.3.2, 3.12.3.2, and 3.13.3.2 of the SER. The statements in this Confirmatory item and in Sections 3.1.5.3,3.7.3.2, and 3.9.3.2 should be revised accordingly. The revisions could include the following suggested wording:

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I ATTACIIMENT (3)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT CONFIRMATORY ITEMS Revise the Confirmatory item to read "An appropriate description should be provided in a supplement to the FSAR and/or in the applicant's " Quality Assurance Policy for the Calvert Cliffs Nuclear Power Plant" to indicate that the applicant's Corrective Actions Program covers all non-safety-related structures and components that are subject to AMR for license renewal, and the j applicant's Corrective Actions Program implements requirements of 10 CFR Part 50, Appendix B,

{

l such that any changes to the Corrective Actions Program are appropriately controlled."  !

j Revise the second to last sentence in Section 3.1.5.3 as described above.

Replace the second paragraphs in Sections 3.7.3.2 and 3.9.3.2 with the following paragraph that is used elsewhere in the SER. Please note that there are no non-safety-related components in the AMR for the systems discussed in Section 3.7 or 3.9 of the SER. Therefore, there is no need to discuss non-safety-related scope there.

"The application indicated that the corrective actions process credited for license renewal is in

accordance with the site-controlled Corrective Actions Program, which covers all structures and components subject to AMR. The staff's evaluation of the applicant's Corrective Actions l Program is discussed separately in Section 3.1.5 of this SER. The staff finds that the applicant's l aging management programs for license renewal satisfy the elements of " corrective actions,"

l " confirmation process," and " administrative controls"."

Confirmatory Item 3.2.3.2.1-1 The technical basesfor the cast austenitic stainless steel (CASS) program is contained in Electric Power Research Institute (EPRI) Technical Report 106092. The report describes screening criteria as a function ofcasting method, molybdenum content andpercentferrite. Components that have percentage ferrite below the screening criteria have adequate fracture toughness and do not require inspection.

Components that have percentage ferrite exceeding the screening criteria may not have adequate fracture toughness, as a result of thermal embrittlement, and do require inspection. The proposed screening criteria and inspection are acceptable when revised in accordance with the criteria documented during a meeting on February 16,1999 (NRC meeting summary dated March 19,1999).

The applicant should revise the CASSprogram as discussed in the February 16,1999, meeting.

BGE Response The screening methods, schedule, and flaw-tolerance criteria for managing thermal and neutron embrittlement of SA-351 and SA-451 CASS components of the RCS (including the reactor vessel internals [RVI]) are as follows. They are consistent with the guidance of NUREG/CR-6177, NUREG/CR-4513, EPRI TR-106092, and the NRC meeting summary dated March 19, 1999 l (References 5,6,7, and 8, respectively).

l Screening

  • Screening criteria will not be based on delta ferrite content alone, but will be based on

! combinations of casting procedure (static versus centrifugal), molybdenum content (e.g., CF-3 versus CF-3M), and delta ferrite content that contribute to reduced fracture toughness.

l

  • Reduction of fracture toughness will not be considered plausible for CASS RVI components that do not experience tensile stresses in excess of 15,000 psi during operating and design basis conditions (e.g., normal, upset, emergency, and faulted), regardless of delta ferrite, neutron fluence, or niobium content.

3 l

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ATTACIIMENT (3)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT CONFIRMATORY ITEMS

  • If measured values of delta ferrite content are not available, delta ferrite content will be calculated using one of the following:

> The methods specified by the LRA (Reference 9)(i.e., Hull's equivalent factors); or

> A method that produces an equivalent (or a conservative) level of accuracy (i.e., the absolute difference between % delta ferrite measured and % delta ferrite calculated does not exceed 6% on the non-conservative side).

  • Unless otherwise specified herein, reduction of fracture toughness will be considered plausible for:

> Centrifugally-cast parts with delta ferrite content above 20%;

> Statically-cast low-molybdenum parts (e.g.,CF-8) with delta ferrite content above  !

20%; and l

> Statically-cast hi-molybdenum parts (e.g.,CF-8M) with delta ferrite content above 10%. l

  • A flaw-tolerance evaluation specific to RVI will be performed to demonstrate the applicability of the delta ferrite screening criteria to RVI.
  • Regardless of delta ferrite content, reduction of fracture toughness will be considered plausible for CASS RVI components that experience tensile stresses in excess of 15,000 psi during operating and design basis conditions if either of the following conditions is met:

> The component material specification called for inclusion of niobium; or

> The component receives n "ast-neutron fluence of greater than 1E17 n/cm2.

  • Screening will be completed such that inservice inspection (ISI) schedules for fracture-susceptible components have been established before the beginning of the period of extended operation.

Where reduction of fracture toughness is plausible for CASS, it will be managed through the period of extended operation by periodic ISI and flaw evaluation in accordance with American Society of Mechanical Engineers (ASME) Section XI.

  • The intent is to demonstrate that component fracture toughness is adequate to ensure capability of the component to continue to perform its intended (e.g., pressure boundary) function.
  • All susceptible components will be included in the potential inspection population (e.g., all reactor coolant pumps that screen in) from which the items during each 10-year ISI will be selected.

. When ASME Section XI Examination Categories B-L-1 and B-M 1 limit the examination areas to welds, the examination will be expanded to include susceptible base metal areas. As an alternative to these expanded volumetric examinations, a combination of expanded visual examination and flaw tolerance evaluation in accordance with Nuclear Code Case N-481 will be considered.

  • Examination methods for RV1 components will consist of enhanced VT-1 examination (a visual examination capable of % mil resolution).

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f A'ITACIIMENT (3)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT CONFIRSIATORY ITESIS Where ASME Section XI does not provide flaw acceptance for ISI (e.g.,IWB 3640 for austenitic piping), evaluations to support continued operation of components will be subject to review by the regulatory authority.

For case-by case evaluations, estimation of fracture toughness will consider saturated aging predictions and actual aging data contained in NUREG/CR-6177 and NUREG/CR-4513, Revision 1.

F.aw evaluations will use component-specific fracture toughness data if either of the following conditions is met:

> Component delta ferrite content exceeds 25%; or i > Component specification called for adding niobmm. l Confirmatory Item 3.2.3.2.1-2 l l The applicant should revise the comprehensive RV surveillance program as discussed during a meeting on February 16,1999 (NRC meeting summary dated Afarch 19,1999).

BGE Response Baltimore Gas and Electric Company will revise the surveillance capsule withdrawal schedule from the current 40-year schedule to a 60-year (48 Effective Full Power Year [EFPY]) schedule. The new l schedule will include the withdrawal of at least one capsule from each unit that will provide data at a l

neutron fluence greater than or equal to the projected peak neutron fluence at 60 years (48 EFPY).

l If BGE withdraws the last capsule from either reactor pressure vessel (RPV) prior to year 55, BGE '

l will establish the neutron irradiation environment (fluence, spectrum, temperature, and flux) applicable to the surveillance data and pressure-temperature limits for the affected RPV. If the l RPV(s) operates outside these limits, BGE will inform the NRC and determine the impact of the condition on each RPV's integrity, l If BGE withdraws the last capsule from either pressure vessel (RPV) prior to year 55, BGE will install neutron dosimetry to permit tracking of the fluence to the RPV.  !

l Confirmatory Item 3.2.3.2.1-3 l

l To manage aging effects associated with stress corrosion cracking (SCC) ofAlloy 600 RPV components, l the applicant relles on its Alloy 600 program. The applicant stated that the Alloy 600 program does not predict PWSCC to be an issuefor the period of extended operation. The applicant plans to continue its periodic visual inspections to verify this prediction. The staff requests that the applicant confirm that control element drive mechanisms (CEDAfs) are included in the periodic inspections via the Boric Acid Corrosion Inspection Program, conprm that cracking of CEDAfs has been consideredfor a 60-year hfe, andprovide the results of the susceptibility evaluationfor the CEDAfs relative to this timeframe, and provide operating experiencefrom inspections of CEDAf no::les at Calvert Chffs Nuclear Power Plant l (CCNPP), ifavailable.

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A'ITACIIMENT (2)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT CONFIRMATORY ITEMS l

BGE Response CEDMs are included The reactor vessel head penetrations (of which the CEDMs are a subset) are required to be examined, during each refueling outage or forced outage in which the plant attains Mode 5 or 6, by the Boric Acid Corrosion Inspection Program, BGE Administrative Procedure MN-3-301 Revision 2, " Boric Acid Corrosion Inspection Program" (Reference 10). The examination is a VT-2 examination (a visual examination capable of % mil resolution) to detect boric acid or other signs of leakage.

Confirmation The susceptibility predictions for cracking of CEDMs have been performed for a 60-year life.

Results of Susceptibility Evaluation Enclosure (1) to Reference (11) was a histogram showing the number and identity of pressurized water reactor plants grouped according to the predicted time from January 1,1997, until a certain size crack existed in the worst vessel head penetration. The three groupings were < 5 EFPY,5-15 EFPYs, and > 15 EFPYs The benchmark probability is the probability equal to that of a 75% through-wall crack in one control rod drive mechanism penetration in the D.C. Cook Unit 2 RV head, at the time of the volumetric inspection of the D.C. Cook 2 RV head penetrations in 1994. This probability is 34%.

Using the current methodology (the EPRI Model) outlined in Enclosure (6) to Reference (11), a 34%

chance of a 75% through wall crack is reached in the year 2034 for Calvert Cliffs Unit 1. Therefore, in the year 2029, Calvert Cliffs Unit I will reach the <5 EFPY category as defined by the histogram.

It would, therefore, be reasonable for a volumetric inspection of vessel head penetrations to be scheduled for 2029 or later.

1 For Calvert Cliffs Unit 2, the probability of one RV head penetration developing a 75% through wall '

crack is only 16% at the end of the extended license period. A 34% probability of a 75% through-wall crack in not reached until 47.6 EFPY from January 1,1997, which falls in the year 2044 or later (the actual date depends on the capacity factor of Unit 2). Therefore, BGE does not intend to schedule any volumetric inspections of the Unit 2 CEDM penetrations between now and the end of extended life in 2036.

It should be noted that the methodology of determining the PWSCC susceptibility of CEDM penetrations is subject to change as better models are developed or new information about variables influencing PWSCC comes to light. Baltimore Gas and Electric Company will employ the most current, accurate methodology available to refine the susceptibility predication and adjust our inspection planning accordingly.

Operating Experience VT-2 inspections. have been performed during each refueling outage at Calvert Cliffs Unit 1 and Unit 2. No indications of boric acid leakage due to pressure boundary leakage of Alloy 600 CEDM nozzles have been observed. The CEDM nozzles have not been volumetrically inspected since the Units began commercial operation, f

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ATTACllMENT (2)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT CONFIRMATORY ITEMS Confirmatory Item 3.2.3.2.1-4 To manage aging effects associated with SCC of the control element assembly (CEA) shroud bolts, the applicant, in Section 4.3.2 of Appendh A to the LRA, described a program that would perform an analysis to determine if the applied stresses on these bolts is above or below the " critical stress"for SCC. As discussed during a meeting on February 16,1999 (NRC meeting summary dated March 19,1999), for NRC Question No. 4.3.15, the applicant indicated that after fn-ther review, the function of the CEA shroud bolts is not safety-related and. therefore, this stress analysis program would not be implemented. This is a confirmatory item pending review of an applicant submittal documenting this)inding. l In addition, an age-related degradation inspection (ARDI) program is planned to manage the effects of SCC of the CEA shroud bolts. However, as discussed in 3.2.3.2.lC(8) of this SER, the applicant indicated that the CEA shroud bolts do notperform a safetyfunction in accordance with the requirements of10 CFR S4.4. The applicant was asked to document the resolution ofthe issue with a description of the function of the CEA shroud bolts that included on explanation of why they do not meet the criteria contained in 10 CFR S4.4.

BGE Response The function of the CEA shroud bolts is to provide lateral support and alignment for the CEAs and to maintain CEA spacing, in order to assure proper CEA insertion. This is a safety-related function and meets the criteria of 10 CFR 54.4. Stress corrosion cracking of individual bolts is considered plausible in that random failures of multiple bolts, over a period of time, if not discovered, could result in loss of this function. Baltimore Gas and Electric Company knows of no history of such failures.

There is redundancy in the bolting. The probability of such failures appears to be extremely remote.

There are two means by which individual failures could be discovered. Therefore, there is reasonable assurance that this aging will be managed during the period of extended operation.

Details There have been no indications of any A286 threaded structural fastener failures to date on any l Combustion Engineering (CE) RVis. Plants that have undergone 10-year inservice inspections have detected no loose parts or gross indications of structural fastener failures. Calvert Cliffs' most recent refueling outages included such inspections.

Industry experience with failures of A286 RV internals threaded structural fasteners has been limited to applications in Babcock & Wilcox (B&W) plants. Combustion Engineering has evaluated the stresses for the CEA shroud bolds relative to the stresses experienced by the failed B&W fasteners.

Combustion Engineering conservatively projected that the potential for a "small percentage" of failures existed.

Combustion Engineering did not explicitly quantify this projected failure percentage. The threaded structural fasteners in all CE applications have been torqued to produce operating stress levels just under 32,000 psi average. To date, the failure rate at 36,000 psi in the B&W applications was less than 4%. At 35,000 psi, no failures were identified.

Combustion Engineering also evaluated the margin for the normal operating plus upset condition loads for the CEA shroud bolds to determine the minimum number of fasteners required per shroud to 7

l l ATTACHMENT (2)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT CONFIRMATORY ITEMS I

maintain thejoint integrhy. There are 20 dual (2 CEAs per assembly) shrouds and 45 single (1 CP A) shrouds. Dual shrouds have 16 bolts. Single shrouds have 8 bolts. There are a total of 680 bolts. a l

minimum of 5 of 8 bolts (62.5%) are required for single shrouds. A minimum of 10 of 16 bolts (62.5%) are required for dual shrouds. This available margin (37.5W above the ASME Code stress allowables far exceeds the most conservative projected failure rate of tue CEA shroud Sids.

Initial Inspection of SG Internals Prior to any entry into the primary side of the SGs, a Foreign Material Exclusion Area (FMEA) will be created per procedure MN-1-109," Foreign Material Exclusion"(Reference 12). From this j procedure, the primary side of the SGs has a Foreign Material Exclus:on Zone Classification of 2. I This classification applies to any FMEA where foreign material intrusion could result in fuel l failure. Material pre-cleaning and material and personnel accountability are called for in Zone 2 l

FMEAs. Procedure MN 1-109 requires an initial entry inspection by a Level l Inspector j (qualified to ANSI N45.2.6,18.1, or other accredited program) per CCNPP Administrative i Procedure CH-1 102," Systems Cleanliness"(Reference 13). The primary side of the SGs has Cleanliness Classification B, which is a high level of cleanliness applicable to systems and ,

components in direct fluid contact with reactor internal components. Attachment 1 of CH-1-102 j provides rigorous cleanliness criteria for Cleanlinea Classification B systems / components. i

!1 Pre-Refueling Core Scan i

Prior to the commencement of fuel movemer.t during refueling operations, a pre-refueling core i scan is performed. This inspection checks for loose debris or other anomalous situations on top of !

the core that could interfere with core reload and is performed using a portable undenvater l camera. The inspection is accomplished via a Maintenance Program repetitive task for each unit that pe6rms the Refueling Outage Reactor Disassembly and Reassembly work scope. The

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j perf rmance of this procedure at CCNPP has resulted in the discovery and removal of foreign j material from the top of the core prior to the commencement of refueling activities. l I

Confirmatory Item 3.2.3.2.4-1 l i

The applicant should document the basis for not considering the hold down ring (HDR) as a device subject to stress relaxation.

BGE Response Baltimore Gas and Electric Con any has found that this ARDM is not plausible since radiation levels are not sufficient for this ART .,1 to occur. Because the HDR is preloaded during installation of the {

RV head, stress relaxation needs to be considered as an ARDM for this component. In-pile testing of i stainless stee! materials has shown that substantial loss of pre-load is possible at pressurized water ,

reactor operating temperatures in e high radiation field (- 5x1020 n/cm2, E>l MEV) when the materials are stressed at or above yield stress. However, extrapolating fluence values from a CE i memorandum on "Relaxa. ion of 13Cr-4Ni Hold Down Ring Material"(Reference 14), fluence lev:!s ,

of the HDR will be in the range of 10" to 10" n/cm2 or f a 60-year life. Consequently, loss of pre- l stress or stress relaxation is not a plausible ARDM for the HDR.

1 Confirmatory Item 3.2.3.3-1 i l

Ifgeneric safety issue (GSI) 190, " Fatigue Evaluation of Metal Componentsfor 60-Year Plant Life, " is not resolvedgenericallyprior to CCNPP operation in the extendedperiod, the applicant must adequately l

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ATTACHMENT (2)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT CONFIRMATORY ITEMS resolve environmental effects on high usagefactors with bounding analyses or a monitoringprogram on aplant-specific basis.

BGE Response

Background

In closing GSI-166, " Adequacy of Fatigue Life of Metal Componer. " the NRC concluded that the I environn ental effects associated with fatigue are not safety significant through the end of the current l

license (i.e.,40 years). This conclusion was primarily based on two studies. The first study was 1 published as NUREG/CR-6260 (Reference 15). This study applied the revised fatigue design curves that incorporated the environmental effects to several plant locations via a detailed fatigue analysis.

The analyses were required to re-allocate design cycles from less likely transients to mow likely transients in order to demonstrate cumulative usage factors (CUFs) less than 1.0. A second study was performed that was a risk analysis considering fatigue failures. The risk analysis considered the I application of the design cycles over a 40-year period, and the effects on core damage frequency when j environmental effects are applied. This second study concluded that there is little to no risk '

significance over the current license period. These two studies formed the primary basis for i

concluding that the effect of environment on the fatigue life of light water reactor (LWR) plant components is not a concern for 40 years.

Closure of GSI-166 resulted in the initiation of GSI-190, " Fatigue Evaluation of Metal Components for 60-Year Plant Life," which limited the concern regarding the effects of environment on the fatigue life of LWR components to operation beyond a 40-year period. While the studies that were performed for GSI-166 were framed in a 40-year operating period, the effects of fatigue are not directly dependent on time in service. Instead, fatigue effects are dependent on number and magnitude of operating transients or cycles. It is understood that more cycles will generally occur the longer an item is operated. The current licensing basis (CLB) with regard to fatigue is to ensure that the overall CUF is maintained less than 1.0 based on the application of various transients. Therefore, for each component there are multiple transients, each with an assumed number of occurrences. One of the features of the CCNPP Fatigue Monitoring Program (FMP)is a cycle tracking function. This function tracks those transients, which have a meaningful or significant impact on the fatigue life of plant components. Based on a straight line projection of the number of controlling transients, the actual number of the events expected through 'O or 60 years will not approach the number of events that is currently allowable.

Plant-Specific Approach Baltimore Gas and Electric Company's program to manage fatigue in the period of extended operation will include one of two alternatives, either of which would ensure that the CLB will continue to be met. These alternatives, which will be described and controlled as commitments in the Updated Final Safety Analysis Report supplement, are:

1. Adoption of NRC's eventual generic resolution of GSI-190. This may or may not require actions to be taken by individual licensees.
2. Implementation of a monitoring program to ensure the CLB is maintained as described below.

9

I ATTACHMENT (2)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT CONFIRMATORY ITEMS I

Description of Monitoring Program The FMP is described in the CCNPP LRA and again in the License Renewal SER. This program has identified a subset oflocations in the systems for which fatigue must be managed that bound all other plant locations. That is to say, the fatigue demands placed on the individual locations are greater than those placed on any other location in the same system. The FMP then monitors the actual demands placed on the bounded locations to monitor the current usage factor. As the usage factor approaches unity, corrective actions are taken to encore that a CUF=1.0 is not exceeded.

Prior to continued operation beyond the term of the initial plant license (i.e.,40 years), the effects of environment on the bounded locations that are monitored would be incorporated into the FMP These effects can be incorporated using the Fen approach as described in EPRI TR-105759 and TR-107515 (References 16 and 17, respectively), except as modified herein. Currently, the relevaat bounded )y locations are as follows:  !

Austenitic Stainless Steel Fatigue Bounding Locations  !

e l

Charging System Piping i e Charging Inlet Nozzles l

e Charging Inlet Nozzle Piping e Hot Leg Surge Nozzle e Pressurizer Spray System Piping j

e Pressurizer Spray Nozzle o Pressurizer Surge Line o Pressurizer Surge Nozzle  !

I e Pressurizer Surge Line Elbow j e SI Nozzle e Shutdown Cooling Outlet Noule  ;

Calculation of the Effective Fen l The effective Fen (Fen-eff) is established by determining the ratio of the allowable number cycles l based on air curves at room temperature, to the allowable number cycles based on LWR environment I curves at the operating temperature. This tio is called Fen. The Fen would be determined using the latest and most appropriate correlations f a sn. Currently, it appears that a correlation similar to the following may be appropuatei,2:

Fen = exp [0.935 + t)*(Tl*-T2'0*)] (1)

I Chopra, O.K., "Effect of LWR Coot 3nt Environment on Fatigue Design Curves of Austenitic Stainless Steels, NUREG/CR-5704.

2 Developed by the follomg expression: In(Fen)=In(Nair)-in(Nwater).

10

l ATTACHMENT (2)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT CONFIRMATORY ITEMS To convert from Fen to the Fen-eff, the Fen is divided by an environmental factor. This factor represents the portion of the ASME Code design factor that is attributable to environmental effects.

The value of this factor is currently under debate. The NRC is of the opinion that this factor should be 1.5. The industry believes that the environmental factor should be 2.0. Using 1.5, the Fen-eff would be found by the following: l Fen-eff = exp [0.935 + q*(Tl*-T2'0*)]/1.5, but not less than 1.0 l (2)

Application of the Fen-eff In general, a CUF is calculated by summing the effects of fatigue damage for individual transients or, more correctly, transient pairs.

U = E ui (3) l n=i I Where:

U = the overall CUF; and l ui si the osage attributable to an individual transient pair.

l When applying the Fen-eff approach to this methodology, ui i s increased by a factor equal to Fen-eff l for those load pairs meeting the threshold criteria for environmental concerns (e.g., currently proposed l as: T > 200 C, c'* < 1%/sec).

l The fatigue evaluation would now be performed in the following manner:

For load pairs that do not exceed the temperature threshold or do not fall below the strain rate threshold, U would be found by the following:

Ut = Eu; (4a) n=i l

For load pairs that do exceed the temf erature threshold or fall below the strain rate threshold, U would be found by the following:

U2 = Eui+Fen-eff (4b) l n =i The overall corrected CUF would then be:

U = Ul + U2 (5)

The fatigue monitoring program would be modified to track limiting locations in the manner described above. This would provide a reliable CUF tracking method to ensure that no locations will exceed a corrected CUF of 1.0. If during the renewal period any locations are found to approach 1.0, they would be addressed in the Corrective Actions Program prior to the CUF exceeding 1.0 in the manner described for the FMP in the BGE LRA. The corrective measures would typically take one of three 11

ATTACHMENT (2)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT CONFIRMATORY ITEMS forms: (a) reanalyze to reduce the CUF; and (b) repair / replace; or (c) monitor the location with NDE3 (e.g., Section XI, Appendix L).

Confirmatory Item 3.33.2.1-1

)

l The licensee plans to modify AfN-1-319 to: (a) specifically identify thefield-erected tanks within the l scope of the performance assessments; (b) provide additional visual inspection criteria specific to l

detecting leakage near the refueling water tank (RWT) penetrations; and (c) add guidance regarding '

approval authorityfor sigmficant departuresfrom the specified walkdown inspection scope and schedule.

BGE Response Procedure MN-1-319 will be revised to: (a) specifically identify the field-erected tanks that are to be included in the scope of the MN-1-319 Attachment 9 walkdowns; (b) provide additional inspection criteria for the identification ofleakage near the RWT penetrations; and (c) add guidance regarding approval authority for significant departures from the specified walkdown inspection scope and schedule. l Confirmatory Item 33.3.2.1-2 The licensee plans to perform an engineering evaluation of SCC at the RhT penetrations to either:

(a) confirm that detection ofleakage through the " telltale" holes is adequate to manageSCC before a challenge to the structural integrity of the penetrations; or (b) include RWTpenetrations in the ARDI program.

BGE Response Baltimore Gas and Electric Company acknowledges and confirms the intended actions described in this confirmatory item.

Confirmatory Item 333.2.2-1 10 CFR 54.21(a)(3) requires thatfor each component subject to AAfR, the applicant demonstrate that the effects of aging will be adequately managed. The staff concern pertains to how the applicant demonstrated that fatigue will be adequately managed for the SI piping. Section 5.15 of the LRA indicates that the applicant identified the potentialfor thermal stratification in the piping between the Si tank check valves and the loop inlet check valves. The LRA also indicates that the applicant will complete an engineering review of the industry task group reports regarding thermal stratification to determine whether SIpipmg changes are necessary and to determine the impact of such changes on fatigue usage parameters used by the CCNPP FAfP. In NRC Question No. 7.21, the staff asked that the applicant indicate whether the plans for the engineering review include reanalysis for thermal strattfication and that the applicant describe the manner by which the time-limited aging analysis for thesefatigue analyses willsatisfy the requirements of10 Cl R 54.21(c). The applicant responded that the engineering review of the SIpiping between the Si tank check valves and the loop inlet check valves does include a reanalysis for thermal stratification. The applicant further indicated that this review will determine if the components are bounded by other components in the FAfP, and of they are not bounded, they will be added to the FAfP. The applicant should discuss the results of the evaluation, identify 3 Application of NDE methods such as Appendix L would require regulatory approval. Such methods require care to ensure that the analytical approach and the NDE technique and quahfications (e g-, Section XI Appendix Vill) are suitable for the application (i.e , material, geometry, and type loading).

12 i

m ATTACHMENT (2)

RESPONSES To LICENSE RENEWAL SAFETY EVALUATION REPORT CONFIRMATORY ITEMS }

additionallocations added to the FAfP, anddes: ribe the controlling transients andparameters monitored for the locations added to the FAfP. The applicant should complete the thermal stratification analysis of the SIpiping and modify the FAiP as necessary.

BGE Response Baltimore Gas and Electric Company's nuclear design engineerin;; organization has a formal action item to complete the evaluation for these items. The current scheduled completion is mid-2003, with I any changes to the FMP currently scheduled to be completed by the end of 2003.

Confirmatory Item 333.231 The licensee plans to modify AfN-1-319 to include addittor,al visual inspection criteria specific to the perknur seal.

l BGE Response Procedure MN-1-319, Attachment 9, will be revised to provide additional inspection criteria specific to the RWT perimeter seal.

Confirmatory Item 3.43.2.2 1 To verify that no sigmficant vibration fatigue is occurringfor Chemical and Volume Control System l (CVCS) components, the applicant indicated that a new program will he developed to provide for inspections ofrepresentative components. The staffasked the applicant to astribe the specific elements ,

of the program that are relevant in monitoring vibrationfatigue (NRC Question No. 7.8). The applicant 1 indicated that the CCNPP ARDIprogram will contain inspections ofrepresentative components to detect the effects of vibrationalfatigue. In a meeting on February 10,1999 (NRC meeting summary dated Afarch 19,1999), held at CCNPP, the applicant stated that it plans to revise the LRA position to indicate l that vibrationalfatigue is notplausiblefor the CVCS. The applicant stated that the basisfor itsfinding is j that no vibrationfatiguefalhcres have been identified since the CVCS modifications, described above,  ;

were implemented. The staffagrees with the applicant's evaluation. l BGE Response l Baltimore Gas and Electric Company addressed this issue in Attachment (1) of the April 2,1999 letter,"First Annual Amendment to Application for License Renewal," in the section on " Chapter 5.2

- Chemical and Volume Control System"(Reference 18).

Confirmatory Item 3.6.2.1.4-1 In Section 5.11C.1.4 of the LRA, the applicant explains that the newly installed heating ventilation and air conditioning (HVAC) system in the diesel generator building is similar to the system for the control room, and it does not need additional AAfR. However, tojustify such a conclusion, the applicant should confirm that the environmental conditions in the diesel generator building (temperature, moisture content of the air, etc.) are similar to the conditions in the control room and that the hardware configuration of the HVAC systemfor the diesel generator building is similar to the configuration of the control room system.

13

ATTACHMENT (2)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT CONFIRMATORY ITEMS BGE Response A comparison of the system design and specifications is presented below. This comparison is based on the information contained in the UFSAR and site system descriptions for Systems 030 (Control Room HVAC) and 103 (Emergency Diesel Generator Building HVAC), and is considered adequate for this comparison.

Design Conditions ( F) System 030 System 103 Summer Inside 75 /104 (maximum)** 78* /120 (maximum)

Summer Outside 95 95 Winter Inside 75 50 (minimum) l Winter Outside 0 0

(*) The Diesel Generator Buildings contain dedicated air conditioning units thct serve certain areas. The Units are sized to maintain a temperature of 78 F during the summer moaths.

(**) Technical Specification maximum.

Concerning relative humidity, the Auxiliary Building, which contains the majority of System 030 HVAC components, and the Diesel Generator Buildings draw supply air from the outside environment and would exhibit the same relative humidity conditions. The exception is that relative humidity and temperature are maintained within specified limits by refrigeration units in the Control Room and ,

other areas that contain safety-related equipment. l The Control Room and Diesel Generator Room HVAC systems contain essentially de mme type of 1 components and equipment, such as ducting, indicators, cooling coils, fans, filters, refrigeration units and unit heaters. Although their physical arrangement is different, their intended functions, component  !

configurations, and materials are very similar.

i Appendix A, Attachment 2, of the System 103. A'MR provides a table comparison of System 103 to System 030 associated device type groups having the same passive intended functions and plausible ARDMs. Control Room HVAC issues that develop during the period of extended plant life will result l in a follow-up impact aging management assessment of the comparison System 103 device group.

Any identified System 103 devi.2 group corrective measures will be taken at that time.

The only device groups that exist in System 103 but not in System 030 are Flow Element (FE) and i Temperature Element (TE). Appendix A, Attachment 2 of the System 103 AMR concludes that aging management of the TE ;,roup components can be directly compared to ti remperature Transmitter (TT) device group in System 030. The Tr and TE device groups have similar pressure boundary component configurations, materials of construction, and service conditions, and were determined to have no plausible aging effects. The pressure boundary components of both device groups are constructed of stainless steel and exposed to a non-aggressive environment of air with some moisture  ;

(condenseion) possible.

The FE desice group in System 103 has no similar System 030 device group. Honver, the AMR i concludes that aging of the FE device group p: asare-saining components is not plausible due to the materials of construction and service cond tuns. Tbs conclusion is based on the material of 14

i A'ITACIIMENT (2)

(

RESPONSES To LICENSE RENEWAL SAFETY EVALUATION REPORT CONFIRMATORY ITEMS 1 construction being stainless steel and environmental conditions consisting of air with some moisture l (condensation) possible. This is considered a non-aggrcssive environment.

Conf?rmatory Item 3.10.3.2.2-1 The applicant consideredfreeze-thaw as aplausible ARDAffor concrete structural components that are exposed to outdoor cold weather because the CCNPP site is located in a geographic region subject to severe weather conditions according to American Society for Testing and Afaterials (ASTAf)-C33,

" Standard Specification for Concrete Aggregates. " The applicant stated that fre::e-thaw is not a potential ARDAffor concrete structural components below the frost line (depth of 20-22 in.) orfor components located indoors. The applican stated that the concrete components potentially subject to freeze-thaw were designed and constructed in accordance with American Concrete institute (ACI)

Standard 318, " Building Code Requirements for Reinforced Concrete," and its relevant ACI standards and ASTAf specifications, which state the physicalproperty requirements of aggregate and air-entraining admixtures, chemical andphysicalreouirements ofair-entraining cements, andproportioning ofconcrete containing entrained air to maximize the concrete resistance to free:e-thaw action. Furthermore, TableB9 in NUREG-1557 (" Summary of Te:hnical Information and Agreements from Nuclear Afanagement and Resources Council Industry Reports Addressing License Renewal") states that free:e-thaw is a non-sigmficant ARDAffor structures that meet the basis requirements. The applicant maintained that since the CCNPP structures meet the basis requirements, free:e-thaw is not a plausibla ARDAffor concrete components exposed to outdoor cold weather. However, the applicant stated that its  ;

walkdown inspectionsfound evidence of damagefromfreeze-thaw of the containment dome with some 1 exposed aggregates, but concluded that the observed degradation, even of the cancrete was left unmanaged, would not result in a loss offunction. During the February 17,1999, meeting (NRC meeting summary dated Afarch 19,1999), the staff asked the applicant to explain the basis for the preceding conclusion. The applicant restated that the possiblefree:e thaw damage on the containment dome is expected to be insigmficant and this item uill be evaluatedfurther as part of the baseline inspectionfor both containments byyear 2002. The stafffinds the applicant commitment to evaluate and resolve the issue via inspection by year 2002 reasonable and acceptable.

BGE Response Baltimore Gas and Electric Company acknowledges and confirms the intended actions described in this confirmatory item.

Confirmatory Item 3.10.3.2.5-1 Administrative Procedure MN-1-319 provides for discovery of corrosion of steel or of conditions that would allow corrosion to occur, such as deterioration ofpaint or pooled waterfor building structural components, byperformance of visual inspections duringplant walkdowns. The purpose of this program is toprovide directionfor the performance ofstructure and system walkdowns andfor the documentation of walkdown results. The applicant's procedure AfN-1-139 requires responsible persomsel to perform periodic walkdowns of their assigned structures and systems during every refueling outage and to schedule walkdowns to ensure that every structure will receive a walkdown at least every third outage.

These walkdowns are intended to assess the condition of the CCNPP building structures, systems, and components so that any abnormal or degraded condition will be identified and documented, and corrective actions will be taken before these structures, systems, and components lose the ability to perform their intended functions. The AfN-1-319 procedure has been improved recently through incorpwation of additional guidance on spectfic activities to be included in the scope of the structural 15

i ATTACHMENT (2)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT CONFIRMATORY ITEMS walkdowns and, according to the applicant, additional enhancements will be made to the procedure to incorporate the following: (1) so help the walkdown personnel to determine whether the intended functions will continue to be met as required by the applicable CL9; and (2) approval authority when ,

significant departurefrom the inspection scope or schedule occurs.

l BGE Response Procedure MN-1-319 is in the process of being enhanced to help walkciown personnel to determine whether intended functions will continue to be met as required by the CLB. The enhancements to the procedure are in the foim of more detailed and explicit inspection requirements for components and potential ARDMs that may not have been included or readily identified, respectively, by existing l walkdown inspection criteria. The changes addressed by items 3.1.3.3-1,3.3.3.2.1-1, and 3.3.3.2.3-1 above sre examples of the types of changes being made to enhance this procedure.

As stated in the response to Item 3.3.3.2.1-1 above, MN-1-319 will be revised to add guidance regarding approval authority for significant departures from the specified walkdown inspection scope and schedule.

Confirmatory Item 4.1.3-1 The containment liner platefatigue is a time-limited aging analysis with a limiting number of thermal cycles during the licensed hfe of the plant. As indicated in the February 16,1999 meeting summary, the applicant hns provideden avaluation demonstrating that the current analysis remains validfor the period of extended operation. The staff has reviewed this information andfound it acceptable. However, this information shouldbe documented.

l BGE Response Baltimore Gas and Electric Company addressed this issue in Attachment (1) of Reference (18) in the section on " Chapter 2.1 - Time-Limited Aging Analyses."

REFERENCES

1. Letter from Mr. W. D. Lanning (NRC) to Mr. C. H. Cruse (BGE), dated March 26,1999, "NRC Inspection Report Nos. 50-317/99-02 and 50-318/99-02"
2. Letter from Mr. C. H. Cruse (BGE) to NRC Document Control Desk, dated November 19,1998, " Response to Request for Additional Information for ths Review of the Calvert Cliffs Nuclear Power Plant, Units 1 & 2, Integrated Plant Assessment Reports for Structures and Electrical Commodities, and Errata"
3. CCNPP Administrative Procedure MN .1-319," Structure and System Walkdowns," Revision 0
4. Letter from Mr. D. B. Matthews (NRC) to Mr. C. H. Cruse (BGE), dated March 21, 1999, "Calvert Clilfs Nuclear Power Plant, Units 1 and 2, License Renewal Safety Evaluation Report"
5. NUREG/CR-6177," Assessment of Thermal Embrittlement of Cast Stainless Steels," May 1994
6. NUREG/CR-4513, " Revision 1 - Estimation of Fracture Toughness of Cast Stainless Steels During Thermal Aging in LWR Systems," August 1994
7. EPRI Report TR-106092, " Evaluation of Thermal Aging Embrittlement for Cast Austentic Stainless Steel Components," March 1995 16

ATTACIIMENT (2)

RESPONSES TO LICENSE RENEWAL SAFETY EVALUATION REPORT CONFIRMATORY ITEMS

8. NRC Meeting Summary, dated March 19,1999, " Summary of February 16 and 18,1999, Meetings with Baltimore Gas and Electric Company (BGE) Regarding License Renewal Activities for Calvert Cliffs Nuclear Power Plant (CCNPP), Unit Nos. I and 2"
9. Letter from Mr. C.11. Cruse (BGE) to NRC Document Control Desk, dated April 8,1988,

" Application for License Renewal"

10. CCNPP Administrative Procedure MN-3-301, " Boric Acid Corrosion Inspection Program,"

Revision i

11. Memorandum from Mr. D. J. Modeen (NEI) to Mr. G. L. Lainas (NRC), dated December 11,1998, "Responsc to NRC Request for Additional Information on Generic Letter 97-01"
12. CCNPP Administrative Procedure MN-1-109, " Foreign Material Exclusion," Revision 0600, July 2,1998
13. CCNPP Administrative Procedure C H-1-102, " Systems Cleanliness," Revision 0, February 28,1995
14. Combustion Engineering Memorandum, dated August 4,1977, " Relaxation of 13Cr-4Ni Hold Down Ring Materiel"
15. NUREG/CR-6260, " Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant Components," March 1995 l J
16. EPRI Report TR-105759,"An Environmental Factor Approach to Account for Reactor Water Effects in Light Water Reactor Pressure Vessel and Piping Fatigue Evaluation (" 1995
17. EPRI keport TR-107515," Evaluation of Thermal Fatigue Effects on Systems Requain3 Aging I Management Review for License Renewal for the Calvert Cliffs Nuclear Power Plant," 1997
18. Mr. C. H. Cruse (BGE) to NRC Document Control Desk, dated April 2,1999, "First Annual Amendment to Application for License Renewal," in the section on " Chapter 5.2 - Chemical and Volume Control System."

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ATTACHMENT (3)

CIIANGES TO TIIE APPLICATION FOR LICENSE RENEWAL l

l l

I i

I l

i i

i l

i Baltimore Gas and Electric Company Calvert Cliffs Nuclear Power Plant July 2,1999 l

1

E ATTACIIMENT (3)

CIIANGES TO APPLICATION FOR LICENSE RENEWAL BGE LRA Section 3.1 - Component Supports Loading Due to Hydraulic Vibration or Water llammer Baltimore Gas and Electric Company (BGE) has determined that " Loading Due to Hydraulic Vibration or Water llammer" is a plausible aging mechanism for " Piping Frames Inside Containment" and " Piping  !

Frames Outside Containment." As a result of this plausibility determination, the following portions of I Section 3.1 of the License Renewal Application (LRA)(Refereree 1) should be changed:

. Page 3.1-8, Table 3.1-3, add a "/(1)" under the column headings " Piping Frames and Stanchions Outside Containment" and " Piping Frama and Stanchions Inside Containment" for the fourth row  !

item " Loading Due to Hydraulic Vibration of Water Hammer." i e Page 3.1-11, add " piping frames and stanchions" after " sway struts," in the first sentence of the third paragraph under Group 1 - Aging Mechanism Effects, o Page 3.1-11, second to last paragraph, delete " hydraulic vibration or water hammer and" in the  ;

first sentence.

  • Page 3.1-11, delete "However" and replace "are not normally expected" with "may occasionally" in the first sentence of the last paragraph.
  • Page 3.1-12, in the first full paragraph delete "wh!!e" and delete " thermal expansion" and "not" in l front of the word " plausible." Replace "are not normally expected to" with "could potentially" in  ;

this same paragraph. l I

e Page 3.1-17, change the word " corrosion" to " aging" in the fifth sentence of the second paragraph  !

on this page.

Inspection ofInaccessible Pipe Supports Baltimore Gas and Electric Company has determined that the 24 inaccessible supports located in ,

Section 3.1 of the LRA will no longer be managed by the Age-Related Degradation Inspection (ARDI) l Program. There are three groups of potentially inaccessible component supports identified in Section 3.1  !

of the LRA based on location and environment: spent fuel pool (SFP) cooling piping supports in normally high radiation area adjacent to the SFP demineralizer and filter (five supports); SFP cooling piping supports normally underwater in the SFP (fifteen supports); and refueling water tank (RWT) heater recirculation piping supports inside of the RWTs (four supports). These groups are handled in the following manner: i

1. SFP Cooling Supports in a High Radiation Area- Baltimore Gas and Electric Company has decided to credit a Preventive Maintenance (PM) Program repetitive tasks to manage the aging of the SFP piping supports instead of the ARDI Program. Specifically, Repetitive Task 10672001 will be credited with discovering general co asion due to boric acid leakage. This repetitive task will implement Technical Procedure GE' s5 (Reference 2), which will be modified. This decision will j change t'.: following portions of Section 3.1:
  • Pages 3.1-18 and 3.1-19, delete the discussion of the ARDI Prograrn, which is the fourth full  ;

paragraph and the associated 5 bullets items below this paragraph and the last paragraph on the page. Delete the first, second and third paragraph on page 3.1-19. Add the following discussion to the bottom of page 3.1 18:  !

"There is a Preventive Maintenanca (PM) repetitive task currently in plac : at CCNPP that  !

ca;is for the inspection of the SFP filter and demineralizer vessel / strainer. The PM repetitive task will implement a procedure that will be modified to provide more specific 1

i

r )

l ATTACHMENT (3)

CilANGES To APPLICATION FOR LICENSE RENEWAL guidance on inspecting for signs of boric acid corrosion and to inspect the five piping j supports associated with this equipment. The corrective actions taken as a result of this I repetitive task inspection ensure that these components remain capable of performing their intended functions under all CLB conditions.

Specifically, PM repetitive task 10672001 will implement GEN-05, which will be modified to inspect the SFP demineralizer vessel piping supports for signs of boric acid ,

corrosion during the vessel Authorized Nuclear Inspection. The Authorized Nuclear i Inspection is presently scheduled concurrent with resin change-out every two years.  !

[ References 2,44,45] l "Any conditions adverse to quality discovered during these inspections are documented on Issue Reports in accordance with the CCNPP Corrective Actions Program. Issue Reports are required to identify the extent of the issue, including the suspected boundary of the problem. Corrective actions are taken as required as part of the Issue Report resolution process. [Refererce 44; Reference 46, Attachment 1] l "The PM tasks described above are performed in accordance with the CCNPP PM Program. This program has been established to maintain plaat equipment, structures, systems, and components in a reliable condition for normal operation and emergency use, minimize equipment failure, and extend equipment and plant life. [ Reference 47, i Section 1.1]  ;

"The program is governed by CCNPP Administrative Procedure MN-1-102," Preventive Maintenance Program," and covers all PM activities for nuclear power plant structures and equipment within the plant. Guidelines drawn from industry experience and utility best practices were used in the development and enhancement of this program.

[ Reference 47, Section 2.1]

"The PM Program includes periodic inspection of specific structures and components through various maintenance activities. These activities provide an effective means to discover and manage the age-related degradation effects on these structures and components. The program requires that an Issue Report be initiated according to CCNPP Procedure QL-2-100, " Issue Reporting and Assessment," for deficiencies noted during performance of PM tasks. The corrective actions taken ensure that the affected structures and components remain capable of performing their intended functions under all CLB

> conditions. [ Reference 47, Section 5.2.B.I.f]

" Specific responsibilities are assigned to BGE personnel for evaluating and upgrading the PM Program and for initiating program improvements based on system performance.

Issue Reports are initiated according to CCNPP Procedure QL-2-100 to request changes to the program that could improve or correct plant reliability and performance. Changes to the PM Program that require issue tteports include changes to the PM task scope, frequency, process changes, results from operating experience reviews, as well as other types of changes. [ Reference 47, Sections 5.1.A and 5.4.B]

"The PM Program is subject to periodic internal assessment. Internal audits are performed to ensure that activities and procedures established to implement the requirements of 10 CFR Part 50, Appendix B, comply with BGE's overall Quality 2

ATTACHMENT (3)

CIIANGES To APPLICATION FOR LICENSE RENEWAL Assurance Program. These audits provide a comprehensive independent verification and evaluation of quality-related activities and procedures. Audits of selected aspects of operational phase activities are performed with a frequency commensure.te with their strength of performance and safety significarce, and in such a manner as to assure that an audit of all safety-related functions is completed within a period of two years. An audit l performed in 1997 of the CCNPP Maintenance Program (which includes the PM Program) concluded that the program is effectively implemented at CCNPP.

[ Reference 48, Section 1B.18]"

e Pa- ' 1-22, replace "ARDI sampling inspections" with "PM Program" in the first sentence of the fi 1 ullet. Also replace "ARDI Program" with "PM Program" in the first sentence of the sixth '

OW.ct.

  • Page 3.1-45, Table 3.1-4, delete the fifth row for the ARDI Propam under the column " Credited For." Add the following row to Table 3.1-4:

Modified PM Program Repetitive Task Discovery of corrosion due to potential boric 10672001; CCNPP Technical acid leakage for the piping supports Procedure, GEN-05 associated with the SFP demineralizer vessel and filter. (Group 1) 1

  • Page 3.1-48, add the following references to the Reference section:
44. CCNPP NUCLEIS Database, Repetitive Task 10672001, i1 Spent Fuel Pool Filter
45. CCNPP Technical Procedure, GEN.05, Radioactive Filter Replacement, Revision 10, February 9,1999
46. CCNPP Administrative Procedure QL-2-100, " Issue Reporting and Assessment,"

Revision 8, December 8,1997

47. CCNPP Administrative Procedure MN-1-102, " Preventive Maintenance Program,"

Revision 5, September 27,1996

48. BGE " Quality Assurance Policy for the Calvert Cliffs Nuclear Power Plant," Revision 51, February 12,1999
  • Page 3.1-19, delete the first, second and third paragraphs on this page.
2. SFP Cooling Supports Underwater- All of the underwater supports on these lines are fabricated of stainless steel. They are all welded conrruction and, therefore, have no threaded fasteners. Based on a review of the Aging Management Review Report for Component Supports (Reference 3), there are no age-related degradation mechanisms (ARDMs) considered plausible for welded stainless steel supports. Therefore, there are no aging management programs required for the 15 supports in this group.
3. RWT Standpipes- There are four standpipes, each with one support. These stendpipes are classified as non-safety-related (NSR). Since these standpipes are NSR and do not serve any safety-related function, nor any other intended function as defined by 10 CFR 54.4, they are considered to be outside the scope oflicense renewal. Furthermore, the supports are not considered II/I because their failure would not adversely affect the safety-related function of the RWTs. Therefore, an aging management review of the four RWT standpipes is not required.

~

3

ATTACHMENT (3)

CIIANGES To APPLICATION FOR LICENSE RENEWAL BGE LRA Section 3.3A - Primary Containment Structure

1. Baltimore Gas and Electric Company has determined that corrosion of embedded steel and rebar is plausible for the containment exterior walls and dome due to minor cracking of the concrete that could introduce moisture and air (oxygen). As a result of this plausibility determination, the following portions of Section 3.3 A should be changed:
  • Page 3.3A- 11, Table 3.3A 3, add a "/(2)" under the column headings " Concrete Dome" and

" Concrete Containment Wall" for the aging mechanism " Corrosion of Embedded Steel /Rebar."

l e Pages 3.3A-18,19,20 and 23, add "/ embedded steel and rebar" to " corrosion of steel" in all of  ;

the Group 2 headings. )

4 Pages 3.3A-18, add "and rebar in the containment dome and walls" after " containment e

emergency air lock," in the first sentence of the second paragraph under the Group 2 heading - i Materials and Environment. t e Page 3.3A-22, add the words "or cracks in exernal concrete containment walls and domes for l i

embedded steel /rebar" after the word " containment"in the first sentence of the second paragraph.

e Page 3.3A-23, add ", embedded steel /rebar" after "The structural steel components" in the first I bullet under the Group 2 heading - Demonstration of Aging Management. j e Page 3.3A-23, add "and of the containment walls and dome" after " containment" in the last bullet l on the page.

  • Page 3.3A-32, Table 3.3A-4, add "and embedded steel /rebar within the Containment Wall and l

Dome" at the end of the first sentence in the last row item of this Table concerning MN-1-319, j

" Structure and System Walkdown Program."

2. To be consistent with the conclusions reached in Section 6.3 of the LRA for the Environmentally-  !

Qualified (EQ) electrical penetration assemblies (EPAs), BGE now considers radiation damage and ,

thermal damage plausible for the non-metallic subcomponents of these EPAs in Section 3.3A, l

" Primary Containment Stmeture." This conclusion is applicable for EPAs that are the same model as those for which aging mechanisms were considered plausible in Section 6.3. However, because the i non-EQ EPAs are not encompassed by the EQ Program and are only in scope for their containment  !

pressure boundary intended function, their aging management will be accomplished by the following existing local leak rate surveillance tests (LLRTs) and administrative testing program:

  • M 5713-1," Unit I Local Leak Rate Test, West Electrical Penetrations"(Reference 4);

e M-571J-2," Unit 2 Local Lesk Rate Test, West Electrical Penetrations"(Reference 5); i e M-571K-1," Unit 1 Local Leak Rate Test, East Electrical Penetrations"(Reference 6);

  • M-571K-2," Unit 2 Local Leak Rate Test, East E!ectrical Penetrations"(Reference 7); and e Administrative Procedure EN-4-105, " Containment Leakage Rate Testing Program" 1 (Reference 8) l l

As a result of this determination, a new group was added to Section 3.3A of the BGE LRA. Therefore, i the following portions of Section 3.3A should be changed: l e Page 3.3A-10, add " Group 6 - Radiation and thermal damage of non-EQ electrical penetrations" after Group 5 in the list of Groups for this LRA section.

4

)

ATTACIIMENT (3)

CIIANGES To APPLICATION FOR LICENSE RENEWAL Page 3.3A-12, Table 3.3A-4, add one row to the bottom of this Table for " Radiation Damage."

Place a "/(6)" in this new row and in the row labeled " thermal aging" under the device type column heading," Electrical Penetrations (non-EQ)."

On page 3.3A-31, add the following new group to LRA Section 3.3 A: I Group 6 - (Radiatior and thermal damage of non-EQ electrical penetrations) - Materials and Environmeut The non-EQ r ectrical penetrations have subcomponents constructed of carbon steel, stainless steel, and non-metallic materials, i.e., epoxy, sealants, and adhesives. [ Reference 6, Attachments 3]

The environment to which these penetrations are subjected varies with their location. In the Containment Structure and Auxiliary Building (where containment penetrations are located), a climate-controlled l

environment is normally maintained. The ambient temperature is controlled by a plant ventilation system as described in UFSAR Chapter 9. Elevated radiation and temperature levels can also be experienced by these electrical penetrations. [ Reference 1, Table 9-18, Reference 6, Attachments 6, PEN-02]

Group 6 -(Radiation and thermal damage of non-EQ electrical penetrations)- Aging Mechanism Effects Non-metallies are susceptible to degradation caused by gamma radiation. Affected material properties include tensile strength, hardness, elongation, and compressibility'. Material susceptibility is dependent on strength of the radiation field, duration of exposure, and specific material composition. [ Reference 27, Attachment 7, Valve]

Thermal damage results from exposure of non-metallic components to normal and abnormal environm(nts. Environmental influences that may induce thennal stress may result from general area ambient temperatures or localized high temperatures (hot spots). Elavated temperature produces some degree of aging in most organic materials. The effects of thermally induced degradation of organics may include embrittlement, cracking or crazing, discoloration, melting, and a change in the mechanical and electrical properties of the material. [ Reference 27, Attachment 7]

Group 6 -(Radiation and thermal damage of non-EQ electrical penetrations)- Methods to Manage Aging Mitigation: The effects of radiation and thermal damage cannot be mitigated durine plant operation.  :

llowever, the use of discovery programs would ensure that the intended function of these components is I maintained.

Discoverv: The effects of radiation and thermal damage are detectable by local leak rate testing (LLRT).

Pressure testing for containment penetration leakage, such as LLRT of non-EQ electrical penetrations, would provide an early indication of degradation of the non-metallic portions of the electrical penetrations so that corrective actions can be taken prior to losing their ability to satisfactorily perform their intended function. [ Reference 6, Attachment 8]

5

ATTACHMENT (3)

CIIANGEs TO APPLICATION FOR LICENSE RENEWAL Group 6 -(Radiation and thermal damage of non-EQ electrical penetrations)- Aging Management Program (s) l Mitigation: Since there are no mitigation techniques deemed feasible at this time, there are no mitigation i programs credited for managing corrosion of Group 6 components. The discovery programs discussed below ensure that the components intended function is maintained.

Discovery: All of the non-EQ electrical penetrations that perform the containment pressure boundary function are subject to LLRT under the CCNPP Containment Leakage Rate Testing Program, as required by 10 CFR Part 50 Appendix J," Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors," Option B. This program is implemented in accordance with the plant Technical Specifications. The specific surveillance test procedures (STPs) credited with the discovering the effects of radiation and thermal damage of the non-EQ electrical penetrations are: (Reference 6, Attachment 8, PEN-02, References 28 through 31]

e M-571J-1," Unit 1 Lc,eal Leak Rate Test, West Electrical Penetrations;"

. M-571J-2, " Unit 2 Local Leak Rate Test, West Electrical Penetrations;"

e M-571K-1," Unit i Local Leak Rate Test, East Electrical Penetrations;" and e M-571K-2," Unit 2 Local Leak Rate Test, East Electrical Penetrations."

CCNPP Containment Leakage Rat: Testing Program Calvert Cliffs STPs M-571J-1(2) and M-571K-1(2), r ..h cover LLRT for the electrical penetrations, are part of the overall CCNPP Containment Leakage Rate Testing Program. The CCNPP Containment Leakage Rate Testing 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. 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 ofintegrated 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 23; Reference 32, Section 3.6; References 33 and 34]

The CCNPP Containment Leakage Rate Testing Program is based on 10 CFR Part 50, Appedix J, requirements and implements these requirements in CCNPP Technical Specifications (Surveillance Requirement 3.6.1.1) [ Reference 32]

The LLRTs are performed at a frequency in accordance with 10 CFR Part 50, Appendix J, Optian B. The LLRT currently includes the following procedural steps: (References 28 through 31]

  • Leak rate monitoring test equipment is connected to the appropriate test point.
  • Test volume is pressurized to at least 53

. Leak rate, pxssure, and temperatere are monitored at the frequency specified by the LLRT -

procedure and the results are recorded.

6

ATTACHMENT (3)

CilANGES TO APPLICATION FOR LICENSE RENEWAL e The "as found" and "as left" pressure, flow rate, and temperature are recorded on the LLRT attachment sheets for each penetration tested. The maximum indicated leak rate is then recorded on the penetration data sheet, e "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 appropriate supervisory plant personnel determine if Technical Specification Limiting Condition for Operation has been exceeded. Corrective action is taken as required to restore the leakage rates to within the appropriate acceptance criteria.

The CCNPP Containment Leakage Rate Testing Program has been inspected by the NRC on numerous l occasions through routine inspections and during reviews of Technical Specification amendment )

requests. Routine inspections at the site included procedure reviews, leakage test witnessing, test j reviews, and results evaluation of both integrated leakage rate tests and LLRTs. Inspectors noted when individual leakage tests failed and reviewed the repair and resetting actions taken by BGE. With some specific exceptions, the inspections typically noted acceptable conditions. No aging-related deficiencies j were identified. [ References 35 through 38] 1 l

1 These reviews demonstrate that CCNPP has normal and acceptable operating experience with respect to l component aging of components relied on for containment isolation. The corrective actions taken as part of the Containment Leakage Rate Testing Program will ensure that the non-EQ electrical penetrations remain capable of performing their containment pressure boundary function under all CLB conditions.

Group 6 - (Radiation and thermal damage of non EQ electrical penetrations) - Demonstration of Aging Management Based on the information presented above, the following conclusions can be reached with respect to l radiation and thermal damage for the Group 6 components: I e The non-EQ electrical penetrations provide the passive intended function of containment pressure boundary and their integrity must be maintained under all CLB conditions.

  • Radiation and thermal damage are plausible due to possible degradation of the non-metallic portions of the non-EQ electrical penetrations, e The non-EQ electrical penetrations are subject to LLRT in accordance with the CCNPP Containment Leakage Rate Testing Program.
  • Leak testing will continue to be performed by these programs in accordance with the plant Technical Specifications. Appropriate corrective actions will be taken if significant leakage due to degradation of the non-metallic portion the non-EQ electrical penetrations is discovered.

Therefore, there is reasonable assurance that the effects of aging due to radiation and thermal damage will be managed in such a way that the non-EQ electrical penetrations will be capable of performing their intended fimetion consistent with the CLB during the period of extended operation.

End of Group 6 insert to Section 3.3 A 7

ATTACHMENT (3)

CIIANGES TO APPLICATION FOR LICENSE RENEWAL

  • Page 3.3A-32, add the following row to the top of Table 3.3A:

Existing Local Leak Rate Testing Discovery and management of radiation and Procedures M-571J-l and thermal damage for non-metallic portions of M-571K-1 for Unit I and non-EQ electrical penetrations (Group 6).

M-571J-2 and M-571K-2 for Unit 2

  • Page 3.3 A 34, add the following references to the Reference section:
27. CCNPP Aging Management Review Report," Safety Injection System," Revision 2
28. CCNPP Surveillance Test Procedure STP-M 571J-1, " Local Leak Rate Test, West Electrical Penetrations," Revision 1, February 11,1998
29. CCNPP Surveillance Test Procedure STP-M-571J-2, " Local Leak Rate Test, West Electrical Penetrations" Revision 0, February 24,1997
30. CCNPP Surveillance Test Procedure STP-M-571K-1, " Local Leak Rate Test, East Electrical Penetrations," Revision 1, February 11,1998
31. CCNPP Surveillance Test Procedure STP-M-571K-2, " Local Leak Rate Test, East Electrical Penetrations," Revision 1, February 24,1997
32. CCNPP Unit 1(2) Technical Specifications, Amendment No. 227(201)  !
33. 10 CFR Part 50, Appendix J, " Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors."
34. Letter from Mr. R. E. Denton (BGE) to NRC Document Control Desk, dated January 16,1996, " License Amendment Request: Adoption of 10 CFR Part 50, Appendix J, Option B for Type A Testing" ,
35. Letter from Mr. T. T. Martin (NRC) to Mr. A. E. Lundvall, Jr. (BGE) dated June 30,1982, Inspection No. 50-317/82-15 (Routine, Unannounced Inspection of the l Containment Penetration Leakage Testing Program, the Containment Integrated  ;

Leakage Rate Test, Tours of Facility, and Follow-up on Previous Inspection Findings, June 16,17,18,21,22,1982)

36. Letter from Mr. T. T. Martin (NRC) to Mr. A. E. Lundvall, Jr. (BGE) dated January 20,1983," Inspection No. 50-318/82-26"(Routine, Unannounced Inspection of Procedure Review, Witnessing and Resulte Evaluation of Local Leak Rate Test and Integrated Leak Rate Test, December 15 through 18,1982)
37. Letter from Mr. S. D. Ebneter (NRC) to Mr. A. E. Lundvr.ll, Jr. (BGE), dated June 25,1985, " Inspection No. 50-317/85-10" (Routine, Announced Inspection of the Containment Leakage Testing Program including Procedure Review of Containment Integrated Leakage Rate Test (CILRT) and Local Leak Rate Test (LLRT) Procedures, CILRT and LLRT Witnes:;ing, CILRT and LLRT Test Review, On-Line Primary Containment Leakage Monitoring, and General Tours of the Facility, April 29 - May 2, and May 17 - 21,1985)
38. Letter from Mr. S. D. Ebneter (NRC) to Mr. A. E. Lundvall, Jr. (BGE), dated December 24,1985, " Combined Inspection Nos. 50-317/85-33 and 50-318/85-33" (November 18 through 25,1985) 8

ATTACHMENT (3)

CIIANGES To APPLICATION FOR LICENSE RENEWAL BGE LRA Section 3.3D - Miscellaneous Tank and Valve Enclosures Baltimore Gas and Electric Company has concluded that the Fire Pump Diesel Fuel Oil Tank dike provides a license reneral intended function for fire protection (FP). The Fire Pump Diesel Fuel Oil Tank dike is sized to contain the entire contents of the tank so as to provide the following passive intended function:

  • To provide protection for the electrically driven fire pump from a fire involving fuel oil.

This dike provides a structural and/or functional support to NSR equipment whose failure could directly prevent satisfactory accomplishment of any of the required safety-related functions. As a result of this  ;

determination, BGE now includes the Fire Pump Diesel Fuel Oil Tank dike in Section 3.3D, i Miscellaneous Tank and Valve Enclosures, as a structure subject to aging evaluation. This addition to Section 3.3D will involve the following changes:

. Page 3.3D-3, Figure 3.3D-3, add a shaded square box labeled " Fire Pump Diesel Fuel Oil Tank House and Dike" and locate i' between the Condensate Storage Tank No.12 Enclosure and the j Auxiliary Feedwater Valve Enclosure in this figure, j e Page 3.3D-4, add the following paragraph for the Fire Pump Diesel Fuel Oil Tank dike after the first paragraph about Auxiliary Feedwater Valve Enclosure.

  • Fire Pump House Diesel Fuel Oil Tank dike is located in the Fire Pump House, which is an independent structure located north of the Turbine Building. This building contains the fire J pumps and jockey pump. The Fire Pump House is protected by an automatic sprinkler system.

All working parts of the electric fire pump are enclosed in a sturdy drip-proof sheet-metal cabin:t >

for protection from the sprinkler systems. In addition, the diesel fuel oil tank is provided with a dike, sized to contain the entire contents of the tank. The dike is 2-1/2 feet high, constructed of reinforced concrete, and is an integral member of the Fire Pump House foundation mat.

Therefore, the layout and FP features installed in the pump house will provide protection for the electrically-driven fire pump from a fire involving fuel oil. The configuration of both of the main fire pumps located in the same area will not prevent the plant reaching a safe shutdown condition in the event of a fire in the Fire Pump House. [ Reference 6, Chapter 9.9.7, Reference 31]

  • Page 3.3D-5, Table 3.3D-1, add "54.4(a)(3)" to row item 6 under the heading " Applicable 10 CFR 54.4(a) Criteria" to account for the Fire Pump Diesel Fuel Oil Tank dike.
  • Page 3.3D-5, add " Fire Pump Diesel Fuel Oil Tank dike" after "No. 21 FOST," in the first and third sentences of the last paragraph.
  • Page 3.3D-7, Table 3.3D-2, add a column to the Table titled " Fire Pump Diesel Fuel Oil Tank Dike" and place a "6" under this column for first row item " Foundations." Place "NA" in the rest of the rows for this column. Change the parenthesis after " Foundations" in the first row item of this table to "(Footings, beams, dikes and mats)" to include the Fire Pump Diesel Fuel Oil Tank dike as part of the foundation category, o Page 3.3D-8, Section 3.3.D.2, add the following sentence after the first sentence in the first paragraph:

"There are no plausible aging mechanisms for the concrete Fire Pump Diesel Fuel Oil Tank dike."

9

ATTACHMENT (3)

CIIANGES To APPLICATION FOR LICENSE RENEWAL Page 3,3D-15, add the following reference for the Fire Pump Diesel fuel Oil Tank dike drawing:

l

31. BGE Drawing 61807," Yard Buildings Foundations, Sheet 1," Revision 4 BGE LRA Section 3.3E - Auxiliary Building and Safety-Related Diesel Generator Building Structures
1. In Section 3.3E.1 Structures Scoping, under "Scoped Structures and Their Intended Functions" (page 3.3E-5), the sentence beginning "All seven generic structural functions . . ." should read "the generic structural functions applicable to these structures are as shown in Table 3.3E-1."
2. In Section 3.3.E.2 Aging Management, replace the first sentence in the first paragraph on l page 3.3E-13 with the following sentence:

"There has been no evidence of settlement at CCNPP that would affect structural integrity."

l BGE LRA Section 4.1 - Reactor Coolant System Steam Generator Primary Manway Studs Baltimore Gas and Electric Company has determined that stress corrosion cracking (SCC) of the steam generator primary manway studs is not plausible.This determination was initially reported in the First Annual Amendment to Application for License Renewal (Reference 9). The occurrence of general corrosion on the external surfaces exposed to boric acid leakage would preclude the initiation of SCC.

However, BGE no longer credits CCNPP Technical Procedure SG-20, " Steam Generator Primary Manway Cover Removal and Installation," for discovering general corrosion on the steam generator primary manway studs. Therefore, SG 20 is no longer credited for managing aging in the BGE LRA.

This program had been previously credited for managing SCC and general corrosion of the steam generator primary manway bolting in a Response to Clarification of NRC Question 4.1.17 (Reference 10). General corrosion of the steam generator primary manway studs will now be managed ,

by the CCNPP Inservice Inspection (ISI) Program, and the Boric Acid Corrosion Inspection Program. As I a result of this deterraination, the following portions of Section 4.1 will change: [ Reference 3, SG-HX,  ! ]

  • Delete SG-20 under Aging Management Programs and under Demonstration of Aging l Management in Group 7 (SCC /IGSCC/PWSCC) of Section 4.1 (starts on page 4.1-44), and on page 4.1-53 under Table 4.1-4 (the sixth row item). This program was previously added to Group 7 according to Reference (10).

l

  • Page 4.1-36, delete "and Technical Procedure SG-20" in the first sentence of the second paragraph. Also delete the fourth paragraph on this page concerning SG-20.
  • Page 4.1-57, delete Reference 41 from the Reference Section.

Reactor Coolant System Piping It was determined that the Reactor Coolant System (RCS) piping (device code CC-01) consisted of piping that was one-inch or smaller (e.g., resistance temperature detector nozzle, pressurizer / sample nozzles necks). Piping that is one-inch or less in size is exempt from ISI requirements. Sine: these components are exposed to the RCS water environment, they should only be susceptible to primary water stress corrosion cracking (PWSCC) and not SCC and intergranular stress corrosion cracking. Because of this determination, the ISI Program will no longer be credited in the BGE LRA with discovering PWSCC en 10

ATTACHMENT (3)

CilANGES To APPLICATI-)N FOR LICENSE RENEWAL these RCS components. Therefore, in Section 4.1.2, Aging Management, the following changes should be made:

  • Page 4.1-48, delete the third paragraph.
  • Page 4.1-49, delete the eighth bullet item (which credits the ISI Program).
  • Page 4.1-53, the seventh row item for the ISI Program should delete crediting discovery of SCC and intergranular stress corrosion cracking for Group 7 components.

The existing programs, CCNPP Technical Procedure CP-204, " Specification and Surveillance Primary Systems"(Reference 11), and the Alloy 600 Program will remain as the credited programs for mitigating ,

and discovering the effects of PWSCC on RCS piping that is one inch or less.

BGE LRA Section 5.10 - Fire Protection Selective Leaching For the FP System it has been determined that CCNPP Administrative Procedure MN-1-319, " Structure and System Walkdowns"(Reference 12), will be credited along with FP STPs in managing aging of the FP System. Because of this change, Table 5.10-2 on page 5.10-9, the row for "FP" should have a "Yes (partial)" in both the " Fire Protection Activities Manage Aging" and " Performance and Conditioning Monitoring Activities Manage Aging" columns. Alsc, Table 5.10-4 on page 5.10-41 should list the FP System in the list of systems in the second row item for MN-1-319. Section 5.10.3.3.3 of the LRA should I also include the following paragraph at the bottom of page 5.10-19:

l "The system parameters during the performance of FP intended functions are bounded by normal operating parameters, and eging of all NSR components in scope for this system are managed by performance and condition monitoring activities during normal operation and system walkdowns. A complete description of the performance and conditioning monitoring activities during normal operations and MN 319, Systems and Structures Walkdowns, are located under subsection 5.10.2.2 on page 5.10-11."

BGE LRA Section 5.16- Saltwater System

~

Baltimore Gas and Electric Company has determined that selective leaching (graphitic corrosion) is plausible for cast iron piping that has a cement mortar lining. TI,is determination will change the following portions of LRA Section 5.16:

1 e Page 5.16-9, add " selective teaching" after " pitting," in Group 2. l

  • Page 5.16-10, Table 5.16-3, add a "/ (2)" under column -LC for Selective Leaching.
  • Pages 5.16-14,15,16 and 17, add the ARDM " selective leaching" after " pitting" in the titles for Group 2.
  • Pay 5.16-14, add the ARDM " selective leaching" after " pitting" in the first paragraph under the heading - Materials and Environment
  • Page 5.16-15, add the following sentence after the end of the sentence at the top of the page:

" Selective leaching is plausible for cast iron piping that has a cement mortar lining."

e Page 5.16-16, add the following paragraph aller the fourth full paragraph on this page:

" Selective leaching is the removal of one element from a solid alloy by corrosion process.

The most common example is the selective removal or zine in brass alloys (dezincification).

I1

ATTACIIMENT (3)

CIIANGES To APPLICATION FOR LICENSE RENEWAL Similar processes occur in other alloy sys: ems in which aluminum, iron, cobalt, chromium, and other elements are removed. There are two types of selective teaching, layer-type, and j 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, Pipe Attachment 7]"

Page 5.16-16, add " selective teaching" after "MIC" in the first sentence of the first paragraph titled Mitigation under Methods to Manage Aging.

Page 5.16-17, add " selective leaching" after "MIC" in the first sentence of the first paragraph titled Mitigation under Aging Management Programs. Also add " selective leaching" after  ;

" pitting," in the third sentence of the last paragraph and add "LC-02" to the reference list at the end of the paragraph.

  • Page 5.16-20, add " selective teaching" after " pitting" in the first sentence of the fourth bullet item, o Page 5.16-35, add " selective teaching" after " pitting" a Table 5.16-5 for the ARDI Program description for Group 2 under the column heading " Credited For."

Flow Orifice As a result of the CCNPP service water heat exchanger replacement, the Unit i service water heat exchanger saltwater emergency outlet flow orifice previously used in this system was climinated. The elimination of the this flow orifice changes the following portions of the BGE LRA:

  • Page 5.16-32, delete "All except one of.." in the first sentence of the fifth paragraph on the page, which is the second paragraph under the heading Aging Management Programs. <

e Page 5.16-32, delete the last paragraph crediting the ARDI Program for managing aging of the Unit 1 service water heat exchanger saltwater emergency outlet orifice.

  • Page 5.16-33, delete the fourth bullet under the heading Demonstration of Aging Management that deals with the ARDI inspection of the flow orifice.
  • Page 5.16-35, delete the fourth paragraph in Table 5.16-5 under the column heading.

BGE LRA Section 5.18- Spent Fuel Pool Cooling System Baltimore Gas and Electric Company has determined that the PM Program will be credited for managing aging of the SFP filter ad demineralizer vessel / strainer,instead of the ARDI Program. As a result of this determination. the following changes should be made to Section 5.18:

  • Pages 5.18-14 and 5.18-15, delete the discussion on the ARDI Program, which is the fifth full paragraph on page 5.18-14, associated bullet items and final sentence. Delete the first sentence and associated six bullet items and last paragraph at the top of page 5.18-15 and the second paragraph.
  • Page 5.18-14, insert the following paragraphs at the bottom of the page:

"There is a Preventive Maintenance (PM) repetitive task currently in place at CCNPP that calls for the inspection of the SFP filter and demineralizer vessel / strainer. The PM repetitive task will be modified to provide more specific guidance on inspecting for signs of boric acid corrosion. The corrective actions taken as a result of this repetitive task inspection ensure that 12

r 1 l

ATTACHMENT (3)  ;

CIIANGES To APPLICATION FOR LICENSE RENEWAL l

these components remain capable of performing their intended functions under all CLB i conditions. l "Specifically, PM Repetitive Task 10672001 provides for the Authorized Nuclear Inspection  !

of the SFP demineralizer vessels. This repetitive task will be modified to further provide for  ;

the inspection of the demineralizer vessel support legs, floor mounting plate, and y-strainer  !

bolting, and the filter vessel support legs / base ring and cover clamp bolting for signs of boric j acid corrosion. [ References 4 -(FILTER-FS, DEMIN-HX),17,18]

I "Any conditions adverse to quality discovered during these inspections are documented on  !

Issue Reports in accordance with the CCNPP Corrective Actions Program. Issue Reports are  !

required to identify the extent of the issue, including the suspected boundary of the problem.

Corrective actions are taken as required as part of the issue Report resolution process. I

[ Reference 17; Reference 20, Attachment 1]

"The PM tasks described above are perfonned in accordance with the CCNPP PM Program.

This program has been established to maintain plant equipment, structures, systems, and components in a reliable condition for normal operation and emergency use, minimize q equipment failure, and extend equipment and plant life. [ Reference 21, Section 1.1] q "The program is governed by CCNPP Administrative Procedure MN-1-102, " Preventive Maintenance Program," and covers all PM activities for nuclear power plant structures and  ;

equipment within the plant. Guidelines drawn from industry experience and utility best j practices were used in the development and enhancement of this program. [ Reference 21, l Section 2.1]

"The PM Program includes periodic inspection of specific structures and components through  !

various maintenance activities. These activities provide an effective means to discover and ]

manage the age-related degradation effects on these structures and components. The program requires that an Issue Report be initiated according to CCNPP Procedure QL-2100, " Issue ,

Reporting and Assessment," for deficiencies noted during performance of PM tasks. The  !

coiTective actions taken ensure that the affected structures and components remain capable of l performing their intended functions under all CLB conditions. [ Reference 21, I Section 5.2.B.I.f] j 1

" Specific responsibilities are assigned to BGE personnel for evaluating and upgrading the PM Program and for initiating progrem improvements based on system performance. Issue Reports are initiated according to CCNPP Procedure QL-2-100 to request changes to the program that could improve or correct plant reliability and performance. Changes to the PM Program that require Issue Reports include changes to the PM task scope, frequency, process l changes, results from operating experience reviews, as well as other types of changes.

[ Reference 21, Sections 5.1.A and 5.4.B]

"The PM Program is subject to periodic internal assessment. Internal audits are performed to l ensure that activities and procedures established to implement the requirements of  ;

10 CFR Part 50, Appendix B, comply with BGE's overali Quality Assurance Program. These  !

audits provide a comprehensive independent verification and evaluation of quality-related 3 activities and procedures. Audits of selected aspects of cperational phase activities are  !

performed with a frequency commensurate with their strength of performance and safety i 13 m

I

c ATTACIIMENT (3)

CIIANGES TO APPLICATION FOR LICENSE RENEWAL 1

significance, and in such a manner as to assure that an audit of all safety-related functions is completed within a period of two years. An audit performed in 1997 of the CCNPP Maintenance Program (which includes the PM Program) concluded that the program is l effectively implemented at CCNPP. [ Reference 22, Section iB.18]"  !

l Page 5.18-15, dUte the last bullet on the page referring to the ARDI Program. Replace this bullet I with the following bullet: I

  • Thc PM Program Repetitive Task 10672001 will be modified to inspect for signs of boric )

acid corrosion on the demineralizer vessel external components and SFP filter. Corrective l actions are taken to correct any degradation that is found to ensure that the affected components remain capable of performing their intended function under all CLB conditions.

  • Page 5.18-23, Table 5.18-6, delete the first two bullets (related to Group I components) in the fifth row for the ARDI Program under the column " Credited For." Add the following row to )

Table 5.18-6: I Modified PM Program Discovery of corrosion due to potential boric Repetitive Task 10672001 acid leakage for the external components of the demineralizer vessel and on the external portions of the SFP filter. (Group 1) l l

  • Page 5.18 24, add the following references to the Reference section:
17. CCNPP NUCLEIS Database, Repetitive Task 10672001,11 Spent Fuel Pool Filter
18. CCNPP Technical Procedure GEN-05, Radioactive Filter Replacement, Revision 10, 1 February 9,1999 l
19. CCNPP NUCLEIS Database, Maintenance Order 1199901050, Replace 11 Spent Fuel Pool Filter, March 22,1999
20. CCNPP Administrative Procedure QL-2-100, " Issue Reporting and Assessment,"

Revision 8, December 8,1997 l

21. l CCNPP Administrative Procedure MN 1-102, " Preventive Maintenance Program,"

Revision 5, September 27,1996

22. BGE " Quality Assurance Policy for the Calvert Cliffs Nuclear Power Plant,"

Revision 51, February 12,1999 BGE LRA Section 6.3 - Environmentally Qualified Equipment Baltimore Gas and Electric Company has determined that electrical stressors are a potential but not plausible ARDM for EQ terminal blocks. This determination will change the following portions of LRA Chapter 6.3:

  • Page 6.3-4, Table 6.3-2, add a row in this Table for " Electrical Stressors" after " Crevice Corrosion" and put an "x" in this row under the column heading for device type "TB."

14 l l

ATTACHMENT (3)

CilANGES To APPLICATION FOR LICENSE RENEWAL  !

References 1.

Letter from Mr. C. II. Cruse (BGE) to NRC Document Control Desk dated April 8,1988,

" Application for License Renewal" 2.

CCNPP Procedure GEN-05," Radioactive Filter Replacement," Revision 10, February 9,1999 3.

"CCNPP Aging Management Review Report for Component Supports," Revision 3, February 4,1997 4.

CCNPP Surveillance Test Procedure M-5711-1," Unit I Local Leak Rate Test, West Electrical Penetrations," Revision 1 5.

CCNPP Surveillance Test Procedure M-571J-2," Unit 2 Local Leak Rate Test, West Electrical Penetrations," Revision 1 6.

CCNPP Surveillance Test Procedure M-571K-1," Unit 1 Local Leak Rate Test, East Electrical Penetrations," Revision 0 7.

CCNPP Surveillance Test Procedure M-571K-2," Unit 2 Local Leak Rate Test, East Electrical Penetrations," Revision 1 8.

CCNPP Administrative Procedure EN-4-105, " Containment Leakage Rate Testing Program,"

Revision 1, March 14,1997 9.

Letter from Mr. C.11. Cruse (BGE) to NRC Document Control Desk, dated April 2,1999, "First Annual Amendment to Application for License Renewal"

10. Letter from Mr. C. 11. Cruse (BGE) to NRC Document Control Desk, dated December 10,1998, Response to Clarification Regarding NRC Question No. 4.1.17; Integrated Plant Assessment Report; License Renewal Application 11.

CCNPP Technical Procedure CP-204, " Specification and Surveillance Primary Systemt,"

Revision 8 12.

CCNPP Administrative Procedure MN 1-319," Structure and System Walkdowns," Revision 0 i

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