ML20212G960

Forwards Faxed Responses Received Between 990428 & 990616 by NRC Staff from Bge to Respond to Open Items or Confirmatory Items Identified in Safety Evaluation Rept on Bge License Renewal Application for Calvert Cliffs NPP

ML20212G960
Person / Time
Site:	Calvert Cliffs
Issue date:	06/17/1999
From:	Dave Solorio NRC (Affiliation Not Assigned)
To:	NRC (Affiliation Not Assigned)
Shared Package
ML20212G964	List: ML20212G960 ML20212G975 ML20212G985 ML20212G989 ML20212H018 ML20212H024
References
NUDOCS 9909300168
Download: ML20212G960 (34)

Text

.

f ia cre ug%

UNITED STATES

.e a NUCLEAR REGULATORY COMMISSION b

If WASHINGTON, D.C. 2068dH1001

)'

(' /

. June 17, 1999 MEMORANDUM TO: File a

FROM: David Solorio, Project Manag #

License Renewal and Standardization Branch Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation

SUBJECT:

FAXED RESPONSES TO OPEN ITEMS AND CONFIRMATORY ITEMS FOR SAFETY EVALUATION REPORT ON THE BALTIMORE GAS AND ELECTRIC COMPANY (BGE) LICENSE RENEWAL APPLICATION FOR CALVERT CLIFFS NUCLEAR POWER PLANT UNITS 1, AND 2.

Enclosure 1 to this memorandum are faxes received between April 28,1999, and June 16,1999. by the NRC staff from BGE to respond to open items or confirmatory items identified in the safety evaluation repoit on BGE's license renewal application for the Calvert Cliffs Nuclear Power Plants Units 1 and 2 (forwarded to BGE by letter dated 3/21/99). Enclosure 2 provides comments made by the staff on some of the faxes in Enclosure 1 which were provided to BGE by telephone.

Docket Nos.50-317 and 50-318) e f

Attachment:

As stated 9

} ( F. G 4 5 990V300168 990617 PDR P

ADOCK 05000317 PDR

u. . .

__J

June 17, 1999 MEMORANDUM TO: File FROM: David Solorio, Project Manager License Renewal and Standardiza io ra g

Division of Regulatory improvement Programs Office of Nuclear Reactor Regulation

SUBJECT:

FAXED RESPONSES TO OPEN ITEMS AND CONFIRMATORY ITEMS FOR SAFETY EVALUATION REPORT ON THE BALTIMORE GAS AND ELECTRIC COMPANY (BGE) LICENSE RENEWAL APPLICATION FOR CALVERT CLIFFS NUCLEAR POWER PLANT UNITS 1, AND 2.

Enclosure 1 to this memorandum are faxes received between A pril 28,1999, and June 16,1999, by the NRC staff from BGE to respond to open items or confirmatory items identified in the safety evaluation report on BGE's license renewal application for the Calvert Cliffs Nuclear Power Plants Units 1 and 2 (forwarded to BGE by letter dated 3/21/99). Enclosure 2 provides comments made by the staff on some of the faxes in Enclosure 1 which were provided to BGE by telephone.

Docket Nos.50-317 and 50-318)

Attachment:

As stated cc w/o attachment: Chris Grimes Stephaine Coffin Barry Elliot Alen Hiser Lee Banic Frank Grubelich John Fair Tanya Eaton Chris Gratton Mike Snodderly DISTRIBUTION:

Docket Files (50-317 and 50-318)

PUBLIC G:\RLSB\SOLORIO\ letter to BGE's Docket getting faxes on the docket.wpd

• See previous concurrence OFFICE LA RLSB g RLSB:D NAME EHylton* DLSoloriod ClGrimeshM DATE 6/4/99 (p/IM99 (,/(l/90 \

OFFICIAL RECORD COPY

(' l l

9

l l MEMORANDUM TO: File

( FROM: David Solorio, Project Manager License Renewal and Standardization Branch l

Division of Regulatory improvement Programs Office of Nuclear Reactor Regulation

SUBJECT:

FAXED RESPONSES TO OPEN ITEMS AND CONFIRMAT RY ITEMS FOR SAFETY EVALUATION REPORT ON THE BALTIM E GAS AND ELECTRIC COMPANY (BGE) LICENSE RENEWAL AP LICATION FOR CALVERT CLIFFS NUCLEAR POWER PLANT UNIT 1, AND 2.

Enclosure 1 to thk memorandum are fsxes received betwee pril 28,1999, and June 10,1999, by the NRC staff from BGE to respond to open items or nfirmatory items identified in the safety evaluation report on BGE's license renewal applicatio or the Calvert Cliffs Nuclear Power Plants Units 1 and 2 (forwarded to BGE by letter dated 21/99). En::losure 2 provides comments made by the staff on some of the faxes in Enclos e 1 which were provided to BGE by telephone.

Docket Nos.50-317 and 50-318)

Attachment:

As stated '

cc w/o attachment: Chris Grimes Stephaine Coffin Barry Elliot Alen Hiser Lee Banic Frank Grube ch i John Fair I Tanya E on Chris G tton Mike odderly l

DISTRIBUTION:

Docket Files (50-317 a 50-318) '

PUBLIC G:\RLSB\SOLORI \ Letter to BGE's Docket getting faxes on the docket.wpd OFFICE LA / RLSB NAME DLSolorio DATE

}//) {/99 / /99 OF ICIAL RECORD COPY .

(

~

I. ... .. .... n. . . . - . - -- ~ ~ - - - ~ - - - ---~~v- '

l' Faxes 'on Open Items and Confirmatiory items for Safety Evaluation Report on Baltimore Gas and Electric Company's License Renewal Application for for Calvert Cliffs Nuclear Power Plant Units 1 and 2.

i Enclosure 1

EqT-t4F%% F12% EXDnNGMLMlGELgwCM eBr7J%rMB P.LWE Calvert Clift License Renewal SER - OPEN ITEM 2.2J.17 2.1-1

( In response to NRC Question No. 5.4.6, regarding exclusion of the emergency dousing function of the containment spray (CS) system from the scope oflicense renewal, the applicant referenced Section 6.7.2 of the UFSAR, 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. 10CFR 50.48 guided the staff to evaluate the plants' fire protection features as satisfying the provisions of Appendix A to Branch Technical Position (BTP) APCSB 9.5-1 and reflects this evaluation in the Fire Protection SER.

In Section F of Appendix A to BTP APCSB 9.51, charcoal filters are identified as needing automatic fixed suppression systems due to their inaccessibility during normal plant operations.

Further, Section 4, " Ventilation," states that fire suppression systems should be installed to protect charcoal filters in accordance with Regulatory Guide 1.52. The fixed fire suppression I system used in this application consists of the water supply piping and direction nozzles. The staff reviewed the applicants response and found no new infonnation that would support the licensee's conclusion that the piping and nozzles that provide the emergency dousing function do not meet the scoping requirements of 10CFR54.4(a)(3).

Response

Overview:

Calvert Cliffs Unit's 1 and 2 containment's, each have three charcoal filter iodine removal units.

h g

Each iodine removal unit is provided with piping and nozrJes that can be connected to a water supply for dousing the charcoal. 'Ihe 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 Containment Spray System for both Units 1 and 2. The current water supply configuration comprises of piping, nozzles, check valves, solenoid operated valves and manual isolation valves which are normally closed during plant operation (Modes 1,2,3 & 4).

The discussion' below will provide a chronological history, regulatory and technice.1 basis for BGE's determination that the Containment Charcoal Filter dousing system piping downstream of the normally closed manual isolation valves, inclusive of solenoid valves, check valves, integral piping and nozzles, are not within the scope oflicense renewal.

Background:

In August 1976 the NRC issued Appendix "A" to Branch Technical Position 9.51, " Guidelines for Fire Protection for Nuclear Power Plants Docketed Prior to July 1,1976." By letter dated September 30,1976, the NRC requested BGE to perform an examination of CCNPPs existing fire protection program by comparing it to Appendix "A" of BTP 9.5 1.

Appendix A provides altemative guidance for power "[P]lants for which construction permits were issued prior to July 1,1976, and operating plants." This altemative guidance applies to CCNPP, which in some cases may be less mstrictive 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 below.

q t

,1 j

'q

Ragulatory Requirement - Branch Technical Position 9.5-1, Appendix "A" Section D.4(d) . Fire suppression systems should be installed to protect charcoal Siters in

(

accordance with Regulatory Guide 1.52, " Design Testing and Maintenance Criteria for Atmospheric Cleanup Air Filtration".

BGE Response - Fire Protection Program Evaluction, March 15,1977 - Pages D-40 and D-41, BGE Letter dated Nf3/77, famdvall to Stello The plant has a total ofpfteen chancoalpiters, six ofwhich are located inside containment. ne charcoalfiters located inside containment are used during post-accident plant conditions only.

Since thesefiters are located in an area with limited access andsince they are operated during post-accident containment conditions, when the operating temperature is signlycantly high (up to a maximum of 273 0F steam <rir mixtune in the containment atmosphere), these charcoalfiters are equipped with an emergency cooling water dousing system to dissipate decay heat in the event ofloss of airfow through the unit during post-accident operation. Each unit has a thermistor toprovide control room indication ofthe charcoal bed temperature. De charcoal bed emergency dousing system in each unit will be initiated manually, upon thermistor high temperature indication, by the operatorfom the control room.

NOTE: Regulatory Guide 1.52, Rev 2, dated March 1978, does not address charcoal filter suppression systems.

Regulatory Requirement - Branch Technical Position 9.5-1, Appendix "A" Section F.1(a)- Fire protection requirements for the primary and secondary costalament areas should be provided on the basis of specine identified hazantis. For example:

• Labricating oil or hydraulic Bald system for the primary coolant pumps e Cable tray arrnagements and cable penetrations

• CharcoalFilters Fire suppression systems should be provided based on the fire hazards analysis.

Fixed Sre suppression espability should be provided for hazartis that could jeopardire safe plant shutdown. Automatic sprinklers are preferred. An acceptable alternate is automatic gas (Halon or CO 2) for hazards identified as requiring Axed suppression protection.

Operation of the Sre protection systems shonld act compromise integrity of the containment or the other safety related systems. Fire protection activities la the containment areas should fsaction la conjunction with total costalament requirements 1 such as control of contamlasted liquid and gaseous release and ventilation. ,

BGE Response Fire Protection Program Evaluation, March 15,1977 - Pages F-1 through F-4 The post-accident charcoalfiters located inside containment are equipped with an emergency cooling water dousing system to dissipate decay heat in the event ofloss ofairfow through the smit dwing post accident operation. Each unit has a thermistor to provide control room indication ofthe charcoal bed tenveratwe. The charcoal bed emergency dousing system in each amit will be initiated manually by the control room operator spon thermissor high-temperature indication.

As determined by thefsre hasards analysis presented in Subsection D.1(b), nofre suppression ,

systems are requiredinside containment in order to assure sqfr shutdown oftheplant. Exceptfor (

l the post-accident charcoalp!!ers, nopxedssppression systent are provided inside containment.

I

(

8 l

0 , , l

In September 1979 the NRC issued a Fire Protection Safety Evaluation Report (FPSER); NRC Ietter, September 14, 1979, R. W. Reid te A. E. Lundvall Jr., Enclosure 3 for Unit 1,

( Amendment 41 and Unit 2, Amendment 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 9.51. De FPSER specifically addressed containment fire protection, including the adequacy of charcoal filter protection.

Regulatory Requinment - Fire Protection Safety Evaluation Report, September 14,1979 Section 2.2, Supplementary Guidance - When the acMI configuration of combustibles, safety-related structures, systems or components, and the Sre protection features are not as assumed in the development of Appendix A or when the licensee has proposed alternatives to the specine recommendations of Appendix A, we have evaluated such unique coangarations and alternatives anlag the defese<-in-depth objectives outilmed below:

(1) reduce the likelihood of occurrence of Dres; (2) promp'ly detect and extinguish Bres if they occart (3) malatain the capabiury to safely shut down the plant if fires occur; and (4) prevent the release of significant asnosats of radioactive materials if fires occur.

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

BGE Resconse - to FPSER Section 2.2 -NONE REQUIRED Regulatory Requirement - Fire Protection Safety Evaluation Report, September 14,1979 Section 4.4.2, Filters - A total of 16 chartoal Alters are installed in the plant: six inside contalement, two in the control room HVAC system, four in the penetration room exhaust systems, two in the feel pool exhsast system, and two in the ECCS pump room exhaust systems. The Alten la containment, and those for the penetration room exhaust system, are used during post-accident conditions. The control room Alters are used only om detection of high radiation in the control room ventilating system. The other Alters are normally bypassed. The contalament filters are provided with high temperature monitors and manually actuated emergency cooling water soppression systems.

Charcoal Siters are contained la steel casing. No ignittom sources are located near the c.karcoal filters nor can the baudap of radioactive prodnets generate sufficient heat to cause ignities.

We Sad that fire protection for the Siten satis 5es the objective identined la Section 2.2 of this report and is, derefort, acceptable.

BGE Resconse - to FNER Section 4.4.2 NONE REQUIRED Regulatory Ringuirement - Fire Protection Safety Evaluation Report, September 14,1979 Section 5.19.4 - Charcoal Siten la containment are provided with high temperature moniton and maanally actuated emergency cooling water suppression systems.

BGE Response - to FPSER Section 5.19.4 - NONE REQUIRED t

l o ____ _ _ _ _ _ _ _ _ _ I

De following paragraph from the CCNPP UFSAR, Rev 8, Section 6.7.2, System Description, which r~a + ands with the FPSER description above, described the charcoal filter iodine removal unit doudng system prior to a modification to remove the system from service in 1990, e "Each of the reci. cu'2tionfilter smits is provided with an emergency dousing systemfor the charcoc! beds to dissipate she decay heat load in the event there is a signipcant rae in the charcoal bed temperatwe. Charcoal bed tenveratwes are measured by thermisters and are monitored rer.orded and alarmed in the control room. Upon high tenperatwe indication (3730F) or alzm in the charcoal beds, remote solenoid and air operated valves, normally closed, are opened and admit containment spray unter to the emergency dousing system. "

Modification To Remove he Charcoal Filter Dousing System From Service In 1990 BGE performed an evaluation and subsequent modification to isolate the iodine removal charcoal filer dousing systems from service during Modes 1, 2, 3 and 4. This work was performed and evaluated in accordance with Facility Change Request (FCR)90-020, dated January 22,1990; calculations contained in NUCON Report No. 6B0021/01, dated January 19, 1990, and Supplement 1, dated July 25,1990; supporting 50.59 Evaluation, Log No. 90-B-061-086-R2, dated December 3,1990; and supporting Fire Protection Engineering Evaluation No.12, Fi e Protection Impact of Removing Dousing System in Containment Iodine Charcoal Filters, dated March 3,1991.

nis change removed the function of the Iodine Removal Unit (IRU) Dousing System by isolating the IRU Dousing System when either the containment spray 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 j provide the isolation by remaining SHUT during Modes 1 - 4. De Main Control Room switches  ;

for dousing valves SV4952, 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 NSR. 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 Calvert Cl@ Nuclear Power Plant UpdatedFinalSqfety Analysis Report, Rev 23.

UFSAR 6.7 Containmen: todine RemovalSyrtem

6. 7.2 - Each ofthe recirculationpiter smits isprovided with an emergency dousing systemfor the charcoal beds'to dissipate the decay heat load in the event there is a signtycant rise in the charcoal bed tenperatwe. Dwing Modes 1, 2, 3, and 4, the dousing system is isolated by manual valves. An analysis (NDCON Report No. 6B0021/01, dated January 19,1990,and Supplement 1 dated.hdy 23,190) shows that maximumpost40CA charcoal bed temperature will not cc e lodine desorption or charcoal bed ignition. Dwing Modes 3 and 6. the manual valves may b.: opened to allow the dousing system to be factional during iodine removal smit maintenance toprovidefreprotection yrequired

^

4

) .

MY-03-1999 12:06 BALTIMORE GAS & ELECTRIC 410 495 6946 P.06/06 I e Summary: l

• k

1. CCNPP 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- I

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 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. De current revision of Regulatory Guide 1.52 does not specify any fire suppression system requirements to protect charcoal filters. Derefore, CCNPP's current installation does not conflict with Regulatory Guide 1.52.

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 i

, 4. The charcoal filter iodine removal dousing system is not in the CCNPP's Fire Hazards l Analysis Summary, Rev 0, dated .iune 4,1997.

5. He 50.59 screening evaluation, Log No. 90-B-061-086-R2, and the associated Fire Protection Engineering Evaluation, No.12, determined that the dousing system is no longer required.

Herefore, the system is no longer within the secpe 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 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 I and 2, Mode 3 when pressurizer pressure is greater than 1,750 psia. per Technical Specification Bases 3.6.6). Herefore, it is possible that water to the dousing system may not be available in modes 4,5 and 6.

Conclusion:

Based on Summary items 1 through 6 above, BGE does not consider the emergency dousing fbnetion of the Containment Spray System to be required by 10CFR50.48, as described in CCNPP UFSAR Sectica 6.7.2. Herefore, BOE concludes that the emergency dousing system piping, valves and nozzles downstream of the nonnally shut isolation valves are not within the ,

scopc oflicense renewal. I

]t l 4

6

.L __ _ __ - -

n#fwar-Twr~W0tr IDOfEMCLS~E MJEWHC 410 495 6946 P.02/03 D(lkFW \

j Open item 3.1.6.3-1 k' The staffidentified several systems in which the applicant proposed to use a one-time age-related degradation inspection to manage age-related degradation mechanism 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 sampling, spent fuel pool cooling). De staff requests that the applicant either expand existing programs (e.g., the boric acid corrosion inspection (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 paformed for these systems.

I BGE Response '

Auxiliary Feedwater System: De only external pipe surfaces to be inspected by the ARDI Program am those in the CST 12 enclosure and the valve pit. De piping at these locations is heat traced and covered by insulation. De ARDI Program is being used to verify that the enclosums and insulation are adequately weatherproofed to protect the external surfaces of the pipe. De 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 forty 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 k 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 l

insulation flashina. De 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 meine as expected, there is no need to extrapolate the results of the inspection. If, on the other hand, the inspection reveals I

significant degradation or unexpected conditions. the results would either be I conservatively extrapolated through the end of the period of extended operation or future 1 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. De ARDI Program is only being used to verify that the chemistry control I program is adequately protecting the internal pipe surfaces.

The discuasion 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" proceding the phrase "extemal corrosive chemical environment" was intended to convey BGE's dermition of the word as it was  !

ustd during the IPA evaluation process (refer to page 2.0-51 of the LRA, Section 6.2.1,  !

Creating a Potential ARDM Lise). " Potential" should not be equated with " plausible." In I 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 i

( general corrosion on extemal surfaces was intended to dismiss the subject from further consideration. The costing is considered adeauste protection curing the renewal term

, MAY-24-1999 14: 17 BALTIMORE GAS 8. ELECTRIC 410 495 6946 P.03/03

)MFT

.i.

without further periodic monitoring. In seneral, if there is no exposure to the outside i environment, general corrosion of coated extemal 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 Pasolve the ARDM Matrix).

Aux.iliary Building HVAC: MN.1-319, Structure and System Walkdowns, is already credited for detectmg damaged coatings on HVAC external surfaces.

Saltwater System: The staffs comments on paaes 3-33 and 3-34 of the SER are in l reference to internal coating degradation of class MC piping which may be lined with saran, kynar or neoprene. Historically, Calvert Cliffs has not experienced problems with these 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 components in scope have been in service since plant construction, and it is sensible to reserve conclusions about necessary inspecion frequencies until after the initial conditions have been assessed.

As contained in the first annual amendment to the LRA. in response to RAI 11.6, BGE has elected to credit MN-1-319, Systems and Stmetures Walkdowns instead of the ARDI Program to inspect the SW System bolting for signs of general corrosion.

NSSS Sampling System: De staffs comments are in reference to extemal conosion due to possible boric acid leakage from the miscellaneous waste evaporator concentrate pump

" discharge cooler. He IPA results have been revised and determined that there is no boric acid in the cooler. Herefore 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.

SFPC System The staffs comments are in reference to using the ARDI Program instead  ;

of the BACI Program to manage external corrosion due to possible boric acid leakage. i The LRA has been revised, resulting in crediting the BACI Program instead of the ARDI )

Program for three of the locations of concem. This is reflected in BGE's letter from Mr.

C. H. Cruse to Document Control Desk, dated February 4,1999, " Changes to Application for Linnse Renewal," in the 10' bullet under section 5.18 of Attachment (1). For the remainir.a two locations, filter 1FL1999 and demineralizer DIXSFP11, the LRA has been revised (see Attachment (3), Section 5.18) to credit two existing periodic activities that will be modified to perform the necessary inspections. Procedure GEN-05 will be modified to inspect 1FL1999 supports during filter cartridge replacements approximately every two months, and Preventive Maintenance Program repetitive task 10672001 will be modified to inspect 0IXSFP11 supports during the vessel Authorized Nuclear Inspection scheduled concurrent with resin changeout every two years.

I

\

-w amragugg page 4

Open Item 3.1.6.31 -

(' The staffidentified several systems in which the applicant proposed to use a one-time age-related degradation inspection to manage age related degradation mechanism 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 sampling, spent fuel pool cooling). He staff requests that the applicant either expand existing I programs (e.g., the boric acid corrosion inspection (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 performed for these systems.

BGE Response Auxiliary Feedwater System He only extemal pipe surfaces to be inspected by the ARDI Program are those in the CST 12 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 te 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 aner the l initial conditions have been assessed. If after forty 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.

t Component Coolina System: Geners! carrosion 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 protectmg the internal pipe surfaces.

Auxiliary Building HVAC: MN-1-319, Structure and System Walkdowns, is already credited for detectmg damaged e=*iage on HVAC external surfaces.

Saltwater System: ne staffs comments are in reference to internal coating degradation of class MC piping which may be lined with saran, kynar or neoprene. Historically, Calvert Cliffs has not experienced problems with these piping segments as was experienced with the cement monar and epoxy lined components. He saran, kynar and neoprene linings are expected to be in good condition. Hus, the ARDI Program is intended to verify %6iions while assessing the current condition of the linings.

Appropriate follow-up actions will be taken based on the results. Most of the components in scope have been in wrvice since plant construction, and it is sensible to reserve conclusions about necessary inspection frequencies until after the initial conditions have been assessed.

NSSS Sampling System: ne staffs comments are in reference to external corrosion due i

to possible boric acid leakage from the miscellaneous waste evaporator concentrate pump i discharge cooler. The IPA results have been revised and determined that there is no boric l acid in the cooler. Herefore external conosian due to cooler leakage is not plausible, 7

and the ARDI Program will not be credited for managing this aging. All other locations 1- of plausible external corrosion are already managed by MN-3-301, Boric Acid Corrosion Inspection (BACI) Program.

,1 i

. - - _ --.. . -. _ -- . _- . . _ - - - _ - - _ - . - _ _ - . . j

vamstaw.sr bnms exprynamnrfwnn19Ewns MO%fT#Ms v.is4W o .

o

/ SFPC System: The staffs comments are in reference to using the ARDI Program instead

( of the BACI Program to manage external :orrosion due to possible boric acid leakage.

"Be LRA has been revised, resulting in crediting the BACI Program instead of de ARDI Program for three of the locations of concem. This is reflected in BGE's letter from Mr.

C. H. Cruse to Document Control Desk, dated February 4,1999, " Changes to Application for License Renewal," in the 10* bullet under section 5.18 of Attachment (1). For the remaining two locations, filter IFLlP99 and demineralizer 01XSFPI1, the LRA has been revised (see Attachment (3), Section 5.18) to credit two existing periodic activities that will be modified to perform the necessary inspections. Procedure GEN-05 will be modified to inspect IFL1999 supports during filter cartridge replacements approximately every two months, and Preventive Maintenance Program repetitive task 10672001 will be modified to inspect OIXSFP11 supports during the vessel Authorized Nuclear Inspoetion scheduled concurrent with resin changeout every two years.

1 s

e l

t l

2 TOTAL P.03

JLN-10-1999 08:52 BALTit10RE GAS & ELECTRIC 410 495 6946 P.02/04 )

{

Open Item 3.1.6.3-_1 De staff identified several systems in which the applicant proposed to use a one-time age related I degradation inspection to manage age-related degradation mechanism that obviously require  !

periodic, regular inspections, such as for verification of acceptable condition of coatings l (auxiliary feedwater, component cooling water, auxiliary building heating and ventilation), and j verification that corrosion is not occurring due to leakage (SW, nuclear steam supply system l sampling, spent fbel pool cooling). He staff requests that the applicant either expand existing 1 progratas (e.g., the boric acid corrosion inspection (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 performed for these systems.

BGE Response

{

Auxiliary Feedwater System: De only external pipe surfaces to be inspected by the ARDI Program are those in the CST 12 enclosure and the valve pit. He 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. De 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 forty 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.

i The ARDI Program in this instance is to be implemented similar to that described for J Case 2 on page 2.0 59 of the LRA, Section 6.3.3.4, Age Related Degradetion 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 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 intemal pipe surfaces.

T . discussion on page 5.3 19 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. l 1

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

emw o- m s n m e w ens w ruw a erW5'e.m w. p o:

eessidesasien neAlthough it receives periodic asse_ssment through the site structure and

-( system walkdown program, the coating is considered adequate protection during the renewal term without further specific periodic monitoring needing to be credited for License Renewal. In general, if there is no exposure to the outside environment, general l corrosion of coated external pipe surfaces cannot proceed to the point of affecting the intended function. Hus, 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 HVAC: MN-1-319, Structure and System Walkdowns, is already credited for detecting darnaged coatings on HVAC external surfaces.

Saltwater System: ne staffs comments on pages 3 33 and 3 34 of the SER are in reference to intemal coating degradation of class MC piping which may be lined with saran, kynar or neoprene. Historically, Calvert Cliffs has not experienced problems with these piping segments as was experienced with the coment 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. A-mrlate follow up actions will be taken based on the results. ,

Most of the components in scope have been in service since plant constmetion, and it is sensible to mserve conclusions about necessary inspection frequencies until after the initial conditions have been assessed.

As contained in the first annual amendment to the LRA, in response to RAI 11.6, BGE has elected to credit MN-1-319, Systems and Structures Walkdowns, instead of the ARDI Program to inspect the SW System bolting for signs of generaln

\ corrosion. Other Saltwater System components (besides the buried piping) are located inside plant structures and are therefore prtnected 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 affecting the intended function for these components. Thus, no aging mechanisms are plausible.

i NSSS Sampling System: The staffs comments are in reference to external corrosion due i to possible boric acid leakage from the miscellaneous waste evaporator concentrate pump discharge cooler. He IPA results have been revised and determined that there is no boric acid in the cooler. Herefore external corrosion due to cooler leakage is not plausible, and the ARDI Program will not be credited for managNg this aging. All other locations of plausible extemal corrosion are already managed by MN 3-301, Boric Acid Corrosion inspootion (BACI) Pmgram.

SFPC System: ne staffs comments are in reference to using the ARDI Program instead of the BACI Program to manage external conrosion due to possible boric acid leakage.

He LRA has been revised, resulting in crediting the BACI Prerem instead of the ARDI Program f& three of the locations of concern his is reflected in EGE's letter from Mr.

C. H. Cruse to Document Control Desk, dated February 4,1999, " Changes to Application for License Renewal," in the 10* bullet under section 5.18 of Attachment (1). For the remaining two locations, filter IFL1999 and domineralizer OIXSFP11, the LRA has been avised (see Attachment (3), Section 5.18) to credit two existing periodic activities that will be modified to perform the necessary inspections. Procedure GEN 05 will be

. . .~ .. . . . _ . _._.. . _ . .. .

.79frN hh Y EoXt GAS & ELECTRIC 410 495 6946 P.04/04 modified to inspect IFL1999 supports during filter cartridge replacements approximately I every two months, and Pmventive Maintenance Program repetitive task 10672001 will be

(' modified to inspect OIXSFF11 supports during the vessel Authorized Nuclear Inspection scheduled concurrent with resin changeout every two years.

f 1

/

\

1 l

)

i l

l l

l l

1 1

l(( l

NUN-@f-19@9 14:1@ BALTIMORE GAS & ELECTRIC 410 495 6946 P.02/03 ) ,

t Draft responses, with new information bolded. Bolding t

willlater be removed.

\.

Open Item 3.2.3.1.1_-2 -

In view ofindustry experience and data, the staff considers stress corrosion cracking (SCC) to be plausible for some pressurizer and teactor coolant system (RCS ) components, and should be managed by aging-management programs (AMPS). The staff would consider the following existing programs to be acceptable for managing the effects of SCC as AMPS or portions of AMPS: ASME XI; Technical Specifications leakage requirements; program based on the provisions of Bulletin 82-02," Degradation of nreaded Fasteners in the RCS Pressure Boundary of PWR Plants;" primary water chemistry control program. De staff would rely on these programs to manage SCC for the specified pressurizer 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 must propose an acceptable alternative.

BGE Response SCC is the localind, non-ductile failure of a material caused by the simultaneous presence of tensile stresses, a corrosive medium, and a material with a susceptible microstructure. SCC is considered not plausible for the listed components and materals.

(Pressurizer cracking and SCC of the pressurizer is also considered in the response to open item 3.2.3.2.1 3.)

( SCC of stainless and low alloy steel primary system components has not been identified in C-E PWRs. (Open Item 3.2.3.2.1-4 discusses lastances where SCC is considered plausible in the CCNPP RCS. These instances involve Inconel materials or drain piping that is typically " dry" and do not apply to this discussion.)

Cast austenitic stainless steel and austenitic stainless steel cladding havemicrostructures

.which are not susceptib!: to sensitiation and thus are not susceptible to IGSCC.

However, they can be eusceptible to Chloride SCC. Primary system water chemistry controls ensure that the C1 concentration remains low so that this form of SCC remains not plausible. (BGE already credits in its I RA CP-0204, " Specification and '

Surveillance, Primary System," as an aging management progam for various other ARDMs considered plausible.)

RCS components which were manufactred from low alloy steels and that are exposed to the primary coolant are clad to protact the components from the process fluid environment. A flaw in the cladding could allow the primary coolant to contact the low alloy steel and initiate degradation. RCS water chemistry coatrols are designed to ensure that sulfate, oxygen, and chloride concentrations do not reach levels such that an environment conducive to SCC exists, j 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 h the NRC (AEC) in the Safety Evaluation Report for CCNPP. In addition, as noted above, i primary system water chemistry is controlled to minimize the potential for the i k environmental conditions necessary to cause SCC. I i

i y . . . . . . . . . . . . _ . . -

_ . i

JUN-04-1999 14:10 ' BALTIMORE GAS & ELECTRIC 410 495 6946 P.03/03 i

No additional aging management programs are necessary. Although BGE does not i credit any aging management programs for discovery of SCC, the continuing g examinations performed in accordance with the CCNPP Inservice Inspection Plan  !

(~ to the requirements of ASME Section XI would seveal degradation of the subject components.

Open Item 3.2.3.2.1-4 Th applicant should perform an augmented inspection of small-bott piping for renewal. The {

augm ted inspection would include Inconel materials, and the information resulting from the i respo to Information Notice 90-10 should be considered in developing the augmented inspection Inconel materials.

BGE R nse SCC is cons red plausible for two groups of piping in the Reactor Coolant System (RCS). Neither f these groups contains piping that is small-bore (between one and four inches). The up consists of the main RCS loops, which have various Inconel fittings that are con ered susceptible for SCC. These main loops are large bore pipe (30-inch and 42-inch). ging management for SCC in the RCS is discussed in LRA section 4.1.2 (Group 7) o ages 4.1-43 to 4.1-48.

The second group is small pi' (3/4 inch) used for the Reactor Pressure Vessel flange leakoff detection lines (one per it). Transgranular stress corrosion cracking (TGSCC) f has been experienced in these lines t CCNPP. 'Ihese pipe segments are normally dry; g however, they are filled with refuelin , water during refueling operations. This water is typically not as pure as normal RCS w and can contain small amounts of chloride or caustic ions. If the pipe segments are n blown completely dry after refueling, any contaminants can become concentrated durin RCS operations and can lead to TGSCC.

Aging management of these pipe segments is\ iscussed in the response to open item 1 3.2.3.2.1-2.

In summary, SCC is not considered plausible for any CS small bore piping at CCNPP.

Augmented inspection of small bore piping for evide e of cracking is therefore not necer.sary.

The mechanisms considered plausible for small-bore piping the RCS are Thermal Fatigue, General Corrosion (for botting only), and Wear (for ge mating surfaces). Small bore piping is included in the piping groeps ld tified in the LRA as --CC and -GC piplag. Aging management for these ARDMs is assed in LRA section 4.1.2 Group 2 (Wear), Group 4 (Fatigue) and Group 5 (Gen 1 Corrosion).

Inservice Inspection (among other programs) is credited to manage the Wear and General Corrosion ARDMs for the small bore piping groups. BGE lieves that the combination of programs credited for these ARDMs is adequate demonstrate aging management without the addition of an augmented inse ice inspection.

Operating experience reviews have identified no instances oflow-cycle mechani I Fatigue in the small bore RCS piping at CCNPP. No mechanisms have been

( identifled during the RCS aging management review that woulJ make this ARDM plausible.

Small bore piping at CCNPP does not contala any Income!.

x-- -- -

t1AY-20-1999 16:36 BAl.T!f10RE GAE & ELECTRIC 410 495 69d6 P.02/01

- 3 pgr-Opee Item 3.2J 1.12 gWW c ONO

( In view ofindustry e ence and data, the staff considers stress corrosion cracking (SCC) to be plausible for some surizer and reactor coolant system (RCS ) components, and should be managed by aging anagement programs (AMPS). %e staff would consider the following existing programf to be acceptable for managing the effects of SCC as AMPS or portions of AMPS: ASME /XI; Technical Specifications leakage requirements; program based on the provisions of Bulletin 82-02, " Degradation of Threaded Fasteners in the RCS Pressure Boundary of PWR Plants;" primary water chemistry control program. De staff would rely on these programs to manage SCC for the specified pressurizer and RCS components, along with a description of and implementation commitment from the applicant to manage threaded fasteners in accordance with Bulletin 82 02. Othenvise, the applicant must propose an acceptable .

alternative.

BGE Response SCC is the localized, non-ductile failure of a material caused by the simultaneous presence of1 ensile stresses, a corrosive medium, and a material with a susceptible microstructure SCC 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 3.23.2.13.)

SCC of stainless and low alloy steel primary system components has not been identifled in C-E PWRs.

/

8' Cast austenitic stainless steel and austenitic stainless steel cladding havemicrostructures which are not susceptible to sensitization and thus are not susceptible to IGSCC.

However, they can be susceptible to Chloride SCC. Primary system water chemistry controls ensure that the C1 concentration remains low so that this form of SCC remains not plausible. (BGE already credits in its LRA CP-0204, " Specification and Surveillance, Primary System", as an aging management program for various other ARDMs considered plausible.)

RCS components which were manufactured from low alloy steels and that are exposed to  !

the primary coolant are clad to protect the components from the process fluid environment. A flaw in the cladding could allow the primary coolant to contact the low alloy steel and initiate degradation. RCS 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.

De microstructure of wrought austenitic stainless steel can also be susceptible to SCC.

Welding procedures used during construction of CCh7P were specifically designed to prevent sensitization of austenitic stainless stools. Dese techniques were approved by the NRC (AEC) in the Safety Evaluation Report for CCNPP. In addition, u noted above, primary system water chemistry is controlled to minimize the potential for the environmerital conditions necessary to cause SCC.

No additional aging management programs are necessary.

t

m us w A m nsT:w wns c3W7mTg;Ers mg&r Open Item 3.2J.2.13

( ' For the cracking of pressurizer 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 ARDM that require: aging management, typically by inspections. The applicant should propose an AMP.

BGE Response l

(This response is still being ' smoothed' but is offered in its present draftform tofacilitate timely review and discussion with NRC staff)

)

BGE continues to believe that cracking of the pressurizer is not plausible. The following excerpts from various BGE, industry, and NRC documents, are offered as references supporting that determination.

The first section below concerns " pressurizer cracking" as opposed to stress corrosion cracking. Some of this information pert.dns to the issue ofR,V underclad cracking, but it should also apply to " pressurizer cracking". - After the discussion of underclad cracking, SCC is discussed.

"Pressuriser Cracking" 064 AMRR,Rev.5 No ARDM described simply as " Cracking" is listed in the ARDM. SCC is listed (s but is not plausible for the shell, head, or cladding. (SCC is discussed further below.) Plausible ARDMs are General Corrosion for the shell and head, and Fatigue for the shell, head, and cladding.

EPRI TR-103837,FWR RPV LR IR, Rev. I Section 3.3.2, Underclad Cracking, Page 3-17:

" Underclad crackins is not an ase-related phenomenon. For the few reactor vessels that experienced underclad cracking, such preservice enminatica rmalyses showed that the flaws either met the allowable flaw indication standards or such flaws were removed or repaired to the extent necessary."

Ram Guide 1.43, Control of Stalalees Steel Weld Cinddina of Low-Alloy Steel Composeats,May 1973 From page 1.431, second column:

" Underclad cracking has been reported only in forgings and plate material of SA- l 508 Class 2 composition made to coarwgrain practice when clad using h- ,

depositico-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 l materials clad by " low-host-input" processes controlled to minimize heating of the base metal. Further, er-Ws 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."

064 AMRR.Rev.5 Frorn 064-PZV-01, Att. 4:

1

-~ .- - , , .. ._ : -- , . _ . , , . ,  ;. . . . . . . .

7 s-r-@PwWrWUw 00rEcis L%$ CELECTRIC 410 495 6946 P.03/07 De presurizer shell and head are fabricated from ASTM A533 Grade B Class 1 Again from Reg Guide 1.43, From page 1.43-1 and 2:

"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 degres 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 f concerning the combined effects of strain concentrations and cyclic loading on crack growth, the presence of these cracks is undesirable."

1 Assessment of the Degradation Mechanisms of Imw Concern for Life l Extension for BGE Cahnert Cliffs Units 1 & 2 Rosetor Pressure Vessels From Section 2.10, page 2-24:

" 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 l diffennt mechanisms. Dese mechanisms are reheat cracking and cold cracking." l

" Underclad cracking due to the reheat mechanism is produced by a combination of  !

three factors nese factors which are needed to cause underclad cracking are a  ;

susceptible material (microstructure), residual stress, and heat treatment into the creep temperature range. However, Combustion Engineering precluded these factors from occurring in combination through detailed procedures and quality lx centrol, ne 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, underciad cracking due to reheat cracks is not a degradation mechanism of concern."

Underclad cracking due to the cold cracking mechanism requires the combination of three factors. nose factors are a susceptible material (microstructure), stresses  ;

on the order of yield stress, and diffusible hydrogen. The Combustion Engineering weld deposition procedures for the stainless steel clad overlay prevent underclad cracking ne 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 concem."

"In addition, no instances of underclad cracks have been reported in Combustion Engineering reactor vessels."

Stress Corrosion Crackiar 064 AMRR,Rev.5 SCC is listed but is 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.

064 PZV-01, Code 156 says in part:

F

( "RCS pressurizer and subcomponents which are fabricated of stainless steel and are not sensitized (heat treated) are not applicable to SCC and IGSCC. Those 2

vwonMive'er- W% LDSGNKlCTUlGdt3 410 495 6946 P.04/07 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 pressunzer and subcomponents."

Safety Evaluation by the Directorate of Licensing U.S. Atomic Energy Commission in the Matter of BGE Calvert Cliffs Naelear Station,8/28/72 "The applicant has stated in Amendment 15 that significant sensitization of all non-stabilized austenitic stainless steel within the reactor coolant pressure boundary was avoided by materials selection and control of all welding and heat treating pracename." .. "We have concluded that these techniques of avoiding sensitization j of austenitic stainless steel during the fabrication period are acceptable."

CCNPP UFSAR, Rev. 25, Section 4.1.4.3. Welding Procedures

" Sensitization of stainless stod occurs when unstabihzed 300 Series stainless material is held in the temperature range of 900-1400 F for sufficient time to form a continuous network of 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. Stabiliud 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 CEs nuclear plants are formed by carbon steels and a high nickel base alloy. None of these materials is susceptible to fumace i sensitization (a continuous network of iron-chromium grain boundary carbides) in I the sense of unstabilized 300 Series stainters steels. All internal carbon steel surfaces are weld-deposit or roll-on clad with inconel or stainless steel, to preclude excesgive 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 + 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 confinned 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 host 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 fumace 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."

NUREG-1557, Summary of Technical Information and Agreements kom Naclear Management and Resources Connell Indastry Reports Addressier

( IJeense _Remewal 3-r- -

a: = . --. _ . --._ = - - . _ _ . . .

F01f-88-86:X~ DJ:G1 IfOfKfCM LCM B LMKWE 41@ 45@ 6946 P.05/07 From Table BS (PWR RCS),page B-66:

l. NUMARC Proposal: Non-significant ARDM. Basis: " Components fabricated of

( CASS or CS intemally clad with SS (>$% ferrite) have reduced susceptibility to SCC (see S1 S-1), underlying CS base metal is not susceptible to decohesion; &

concentrations of oxygen, halogens, & sulfates are monitored & controlled in the coolant (see S-V-38); and/or not subjected to corrosive environment."

NRC Proposal: "IGSCC een occur mwter the operating conditions (water chemistry) during shutdown because oxygen is introduced to primary coolant during cooldown to control CRUD bursts, & coolant is exposed to air during many shutdowns. The potential of cracking in cladding remote from welds should be addressed. SS cladding may have regions of low delta ferrite that have been sensitized during PWHT & thus susceptible to IOSCC; ASME Sect. XI requires inspection of weld &

weld regions."

From Table BS (PWR Pressure Vessel), page B-5:

NUMARC Proposal: Non-significant. Basis: "I.cw alloy steels & SS cladding

• with >S% ferrite content are not susceptible to SCC in PWR environment:

implementation of RG 1.43 to prevent underclad cracking & guidelines of RG 1.44 to avoid sensitization of SS; control of halogens & oxygen in the primary water to

<5 & <0.01 ppm, respectively; & monitor & control of water chemistry during shutdown to mitigate the potential of SCC; or the componems are not subjected to corrosive environment."

NRC Proposal: " Low temperature sensitization of SS cladding is possible, f Evaluate the effects of oxygen injection during cooldown. Although, SCC of low-

\ alloy steel is unlikely in " typical" PWR environment, it may not be true under crevice conditions; consider the information in NUREG/CR-5020."

Chemistry Procedere CP-0204 In modes 5 & 6 (temperatures < 200F), hydrazine is added to the Shutdown Cooling System to reduce oxygen below 100 ppb before entering Mode 4 (temperature

>200F).

Aseessment of Primary Water Stress Corrosion Cracking for Life Extension for BGE Calvert Cliffs Units 1 & 2 From Section 1, page 1-2:

" ... Shutdown (refueling temperatures were not considered because the probability of SCC becomes low at 60C (140F) and below. .."

i Assessment of Low Temperature Sensitimation of Austenitic Stainless Steels for l

Life Estension for BGE Calvert Cliffs Units 1 & 2 From page 2-2:

"The austenitic stainless steel applied in the reactor vessel is mainly the cladding, which contains more than 5 FN delta ferrite. In such duplex austenitic/ferritic alloys, ehromium-iron carbides are precipitated at the ferrito austenite interfaces during exposure to 500C - 800C. This precipitate morphology precludes l intergranular penetrations. Therefore, there is no concem over sensitization of the cladding."

4

~ , - .

3 _

7 . - - - _ - ._n --.. .

m M GMTbn%dg vW9Wr Assessment of the Degradation Ibfechanisms of Low Concern for Life Extension for BGE Calvert Cliffs Units 1 & 2 Resetor Pressure Vessels

\ From section 2.2, page 2-5:

" Stress Corrosion Cracking (SCC) is the brittle fracture or cracking of normally ductile material. This type of failure mode is created by a combination of stress, material , and environment. Specifically, for stress corrosion cracking 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 i susceptible material such as sensitized 304 stainless steel over an extended period of time."

" Stress Corrosion Cracking is not anticipated to be of significant concem 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 concem 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 WA in the RPV stainless steel since Combustion Engineering carefully controlled material sensitization. The austenitic stainless steel applied to the reactor vessel as cladding contains more than 5 FN delta ferrite. In such complex austenitic/ferritic alloys, chromium-ion carbides are precipitated at the ferrite-austenite interfaces during exposure to temperatures of 500 to 8000. To

. avoid sensitization CE limited the interpass temperature on multiple pass welds in stainless steel to 350F. In addition the combination the use of low 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 intergranulst SCC in sensitized type 304 stainless steel in pure water. It is likely that the low stresses and strains in the PWR coupled with low oxygen in the primary coolant has generated conditions that simply do not promote SCC."

" SCC is also not expected to be a concem 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 concem."

RCS Service Life Evaluation for BGE Calvert Cliffs Units 1 & 2 From section 4.4, page 4-10:

" Cast austenitic stainless steel and sustenitic stainless steel cladding have microstructures which are not susceptible to sensitization and thus, are not

( susceptible to intergranular SCC. Therefore, IGSCC is Not Applicable for RCS 5

,.. .. . . = . - .- - . 7- =.. - - _ . . - . - . - - - . .. .

vca;1RF-henWRJs CSmegl%nn:LMcMRs easrFMTats$ v.tWW

• O components made from cast austenitic stainless steel or for austenitic stainless steel cladding. However, they are susceptible to chloride SCC. Primary system water

( chemistry controls ensure that the chloride concentration remains low. So that, cast and cladding made of sustenitic stainless are rated as having a low probability of being susceptible to SCC."

"RCS components which were manufactured from low alloy steels and that are exposed to the primary coolant are clad to protect the components from the corrosive environment. However, if a flaw in the cladding allows the primary coolant to contact the low alloy steel, there exists a potential for SCC to occur. I Primary systems water chemistry controls are designed to ensure that sulfate, l oxygen, and chloride concentrations do not reach levels such that a corrosive environment conducive to SCC exists. Due to such controls, the RCS components made from low alloy steels and intemally clad are rated as having a Low probability of being susceptible to SCC."

[ Note: The designation " susceptible" from the RCS Service Life Evaluation does not conespond directly with either of the BGE terms " potential" or ')lausible". A

" Low probability of being susceptible" in the CE report falls between " potential" and " plausible", meaning it is certainly potential, but not likely to be. plausible.

Since CE !isted only a level of probability, it was incumbent upon BGE to arrive at a conclusion on plausibility.]

From section5.1, page 5-2: l

" Stress corrosion cracking oflow alloy steels and wrought austenitic stainless steel l is controlled by maintaining primary system water chemistry (Section 4.4). In this  !

I way, the corrosive environment necessary for SCC to occur in these materials is t eliminated."

l l

l 1

, i l

l l

(

6 4 1

TOTAL P.07

- - - . . - -.- . . . _ = .

MAY-21-1999 07:36 BALTIMORE GAS 8. ELECTRIC 410 495 6946 P.01/01 t

{ May 21,1999 s

/

( To: Dave Solorio Phone: 301-415-1973 Fax: 301-415-2279 From: Don Shaw Phone: 410-495-4028 Fax 410-495-6946 Pages: 2 (including this cover page)

Comments:

Dave, Here is information on Haddam Neck that we could fit in with the other excerts we provided for OI 14, for your reviewers to consider.

3 Thanks, 1

Don THE WESTINGHOUSE OWNERS GROUP Aging Management Evaluation for Pressurizers (July 1996), Section 2.6.3, reads as follows:

"2.6.3 Haddam Neck Pressurizer Clad Cracking 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 1 to 2 feed below the normal water level (Refs. 6 and 7] NDE investigations established that at least some of the indications penetrated the cladding to the cladding-ferritic base metal l 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. '

Altemativel, 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 tot he Haddam Neck pressurizer, and that it is not an aging related form of degradation, it is not considered further in this evaluation."

f BGE belives this evaluation supports the position that cracking is not plausible for pressurizer shell, heads and cladding.

. . = _ ___

Open Item 3.2.3.2.1-3 For the cracking of pressurizer 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 ARDM that requires aging management, typically by inspections. The applicant should propose an AMP.

BGE Response This response contains a series of excerpts provided to support BGE's IPA result that cracking is not plausible for the pressurizer shell and heads, including cladding cracking. The sections below consider industry experience, CCNPP experience, a general treatment of" pressurizer cracking" as opposed to SCC, and a general treatment of SCC. Some of this information pertains to the issue of RV cracking, but it should also apply to pressurizer cracking due to the similarity of the materials, fabrication techniques, and process fluid environment.

Industry Experience Industry experience with the cracking of pressurizer shell, heads, including cladding cracking, is extremely limited. De only significant instance known to BGE lavolved an indication on the Pressurizer at the Haddam Neck plant. He 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 i 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 [Refs. 6 ,

and 7 of Ref.1). NDE investigations established that at least some of the indications I

( penetrated the cladding to the cladding ferritic base metal interface. Review of plant operating records revealed that the same band ofindications had been reposted 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." (Ref.1)

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

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 (AEC) stated:

"The applicant has stated in Amendment 15 that significant sensitization of all non-stabilized r austenitic stainless steel within the reactor coolant pressure boundary was avoided by h materials selection and control of all welding and heat treating processes. . . . We have

(

4040 *d 9r69 S6P OTP dim.LO313 'E SOD 3HOW!.L R:E 9C:9i 666I-0I-Nnf

~

_- _ .m - ,_- ._._ _ ..~ . _ _ _ . _ . _ , ,

l concluded that these techniques of avoiding sensitization of sustenitic stainless steel during the fabrication period are acceptabic." (Ref. 2)

BGE's metallurgist has reviewed a video frora August 1989. Tids video clearly shows no cracking in the inconel bottom head cladding adjacent to a penetration. BGE is reviewing other records to assemble additional evidence that no CCNPP Pressurizer clad cracking has or is occurring.

i BGE considers that CCNPP experience does not support the plausibility of Pressurizer cracking.

Presserizer Crscidna  !

No ARDM described simply as " Cracking" is considered in the aging 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 general corrosion for the shell and head, and fatigue for the shell, head, and cladding. (Ref. 3)

Pressurizer cracking (as opposed to SCC or one of its variants) in presumed to be synonomous 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-sone.~ Underciad cracking can develop by two different mechanisms. nese 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 are needed to cause underclad cracking are a susceptible material (microstructure),

residuct 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 an a

( suscepdble material (microstructure), stresses on the order of yield stress, and diffusible hydrogen. (Ref. 4, Section 2.10, page 2-24)

Underclad cracking is not an age-related phenomenon. For the few reactor vessels 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. (Ref. 5)

N'o instances of underclad cracks have been reported in Combustion Engineering reactor vessels.

The two underclad cracking mechanisms are not considered plausible for the CCNPP Pressurizer:

(Reheat cracking) Combustion Engineering precluded these factors Dom occurring in combination through detailed procedures and quality control. De 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, undercled cracking due to reheat cracks is not a degradation mechanism of concern.

(Cold cracking) The Combustion Engineering weld deposition procedures for the stainless steel 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. (Ref. 4, Section 2.10, page 2-24) d!VE0*d- 9P69 S6P OtP 31M133 B 1 SW 3HOW11108 9E:9I 666I--OI-NM

.---.-:-=.~n=.=-=- .

a ~ .. .c.., - ~ . _ .- -- .-.

Regulatory guidance reinfones this conclusion. De NRC has sported 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 wire processes. Cmckhts 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." (Ref. 6)

The CCNPP pressurizer shell and head are fabricated hom ASTM A533 Omde B Class 1 material. (Ref.3)

In addition, for an ARDM to be considered plausible, the degradstion must impact the component's ability to perform its intended function. Regutstors have not determined that underclad cracking e.xceeds this threshhold:

I "The presence ofintergranular cracking in low-alloy steel under stainless steel weld cladding ,

.has been observed in reactor vessels and other components for nuclear systems in varying i 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 conceming the combined effects of strain coricentrations and cyclic loading en crack growth, the presence of these cracks is undesirable." (Ref. 6) e i k Stress Corrosion Cracking Stress Corrosion Cracking (SCC) is the brittle fracture or cracking af normally ductile material.

This type of failure mode is created by a combination of stress, material , and environment.

Specifically, for stress corrosion cracking 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 stools moderate to high oxygen levels); and (3) the imposition of these conditions on a susceptible material such as sensitized SO4 stainless steel over an extended period of time. (Ref. 4, From section 2.2, page 2-5) l In the CCNPP IPA Reactor Coolant System Aging Management Review, Stress Corrosion Cracking is evaluated for the Pressurizer (including claddinF) 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.) De reasons for the non plausibility determination are summarized:

"RCS pressurizer and sobcomponents which are fabricated of stainless steel and are not serwitized (Seat treated) are not applicable to SCC and IGSCC. Components fabricated of Inconc! 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." (Ref 3)

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

g ' D PO*d 9P69 56P OIP 311dD3"G 1500 3dOWI.nWE 2.C 91 6661-01-Hitt -

~

l

' Stress Corrosion Cracking is not anticipated to be of significant concem for the Baltimore

(' Gas and Electric reactor vessels. SCC is not anticipated to be a concern because the oxygen level in the prirnary water is kept low (<10 ppb). This is below the threshhold 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 contains enore than 5 FN delta ferrite. In such complex austenitic/forritic alloys, chromium-ion carbides are precipitated at the ferrite-austenite interfaces during expcsure to temperatures of 500 to 800'C. To avoid sensitization CE limited the interpass tempemture on multiple pass welds in stainless steel to 350'F. In addition the combination the use of low .

carbon content materials, of normal host input using controlled welding procedures and 1 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% strdn 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 strains in the PWR coupled with low oxygen in the primary coolant has f generated conditions that simply do not promote SCC.

i

" 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 beat treatment and controlled residual element content precludes SCC as a concem." (Ref. d, section 2.2, page 2 5)

As indicated above, fabrication techniques for the CCNPP reactor coolant system were designed to prevent sensitization of the stainless steel:

" Sensitization of stainless steel occurs when unstabilized 300 Series stainless material is held in the tempair range of 900-1400'F for sufficient time to form a continuous network of 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 bour at 1400'F. Stabilized 300 Series stainless material avoids conticuity of chromium carbide precipitstes in the grain boundaries by 'arefbi control of metal chemistry.

"No fumace 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 beunday in CE's nuclear plants are formed by carbon steels and a hi 8h nickel base alloy. None of these materials is susceptible to furnace sensitization (a continuous network of iron-chmmium grain boundary carbides) in the sense of unstabilized h -- . k _. _

)I M N I M 3 OJl1*klE _ _ ,,_2.C39] _6661-Q}.W{f

.~

300 Series stainless steels. All intamal carbon steel surfaces are weld-deposit or roll-or: clad with Inconel or stain!ess steel, to preclude excessive corrosion procuct 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 stmeture. Therefore, during the stress relief heat treatment (!!50*F + 25'F) required by the ASME code for the pressure vessel, a continuous network of chromium carbide precipitates is not fonned 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 stmeture),308 weld deposited metal does not form a continuous carbide network within grain boundaries even following a typical vessel post weld heat 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 sted used either is not subjected to a furnace sensitization heat treatment gr, as is the case of cladding on the primary piping, is of type 304L (Iow carbon) composition and is not susceptible to'the fonnation of continuous chromium carbide grain boundary networks," (Ref. 7)

The NRC has raised the issue oflow temperature sensitization. (Ref. 8, Table BS (PWR Pressure Vessel), page B-5) The austenitic stainless steel applied in the reactor coolant system 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 500C - 800C. This precipitate morphology precludes intergranular psweions. Therefore, i there is no concem over sensitization of the cladding. (Ref. 9, p. 2-2)

Based on this evaluation BGE maintains our position that cracking (underclad or SCC) is not plausible for the Pressurizer she!!, heads, and cladding.

s 40A30*d 9t'69 56t 0it' 31M133"B '8 StfJ 3dOW11M BE89i 666I-01-NFlf

References

(

(1) The Westinghouse Owners Group Aging Management Evaluation for Pressurizers (July 1996), Section 2.6.3, Haddam Neck Pressurizer Clad Cracking

' (2) Safety Evaluation by the Directorate of Licensing U.S. Atomic Energy Commission in the Matter ofBGE Calvert Cliffs Nuclear Station August 28,1972 (3) CCNPP IPA Reactor Coolant System Aging Management Review Repon, Revision 5 (4) Assessment of the Degradation Mechanisms ofImw Concern for Life Extension for BGE Calven Cliffs Units 'l & 2 Reactor Pressure Vessels, Combustion Engineering Report, February 1989 (5) Electric Power Research Institute (EPRI) TR-103837, Pressurized Water Reactor Reactor Pressure Vessel License Renewal Industry Report, Revision 1, Section 3.3.2, Underclad Cracking, Page 317 (6) Regulatory Guide 1.43, Con' trol'of Stainlest Steel Weld Cladding of Low-Alloy Steel

. Components, May 1973 (7) CCNPP UFSAR, Revision 25, Section 4.1.43, Welding Procedures

, (8) NUREG-1557, Summary of Technical Information and Agreements frotr. Nuclear Management and Resources CouncilIndustry Reports Addressing License Renewal

(

(9) Assessment of Low Temperature Sensitization of Austenitic Stainless Steels for Life Extension for BGE Calvert Cliffs Units 1 & 2, CE Report, February,1989 l

I i

i l

/b 40*d er69 s6e etr _.

Dra13: ire 3 suo saowliwi sc:91 6661-0T-Nnf

y M9EWFB%9) W K9 BALT!NORE GAS & ELECTRIC 410 495 6946 P.O!/02 No additi:nal aging m ement programs are necessary. Although BGE does not endit any aging managem programs for discovery of SCC, the continuing caamlaations performed la acco ce with the CCNPP Inservice Inspection Plan to the requirements of ASME Sectio would avveal degradation of the sabject components.

1 Open Item 3.2J.2.14 i

The applicant should perform an augmented inspection of small-bore piping for renewal. The l

augmented inspection would include Inconel materials, and the information resulting from the l response to Information Notice 9010 should be considered in developing the augmented inspection ofInconelmaterials.

BGE Response SCC is considered plausible for two groups of piping in the Reactor Coolant System (RCS). Neither of these groups contains piping that is small-bore (between one and four

{

inches). The first group consists of the main RCS loops, which have various Inconel l

fittings that are considered susceptible for SCC. Dese main loops are large bore pipe (30 inch and 42-inch). Aging sannagement for f,CC la the RCS is discussed la LRA section 4.1.2 (Group 7) on pages 4.1-43 to 4.1-43.

De second group is small pipe (3/4-inch) used for the Reactor Pressure Vessel flange leakoff detection lines (one per Unit). Transgranular stress corrosion cracking (TGSCC) has been experienced in these lines at CCNPP. These pipe segments are normally dry;

(

,- however, they are filled with refueling water during refueling operations. This water is typically not as pure as normal RCS water and can contain small amounts of chloride or caustic ions. If the pipe segments are not blown completely dry after refueling, any contaminants can become concentrated during RCS operations and can lead to TGSCC.

Aging management of these pipe segments is discussed in the response to open item 3.2.3.2.1-2.

In summary, SCC is not considered plausible for any RCS small bore piping at CCNPP.

Augmented inspection of small bore piping for evidence of cracking is therefore not necessary.

The mechanisms considered plausible for smaB-bore piping in the RCS are Thermal Fatigue, Geneml Corrosion (for botting only), and Wear (for Bange mating surfaces). Small bore piplag is lacladed in the piping groups identified in the LRA as -CC and -GC piping. Aglag management for these ARDMs is discussed la LRA section 4.1.2 Group 2 (Wear), Groep 4 (Fatigue) and Groep 5 (General Cortesion).

Iar,ervice Inspection (among other programs)is caudited to manage both the Wear and General Corrosion ARDMs for the small bore piplag groups. BGE believes that the combination of programs credited for these ARDMs is adequate to l demonstrate aging management without the addition of an sugmented insersice  !

laspection.

Operating experience reviews have identified no instances oflow-cycle meebaalcal 7 Fatigee la the small bore RCS piping at CCNPP. No mechaalsass have been identified daring the RCS aging management review that would make this ARDM plausible.

Small bore piping at CCNPF does not costala any IncomeL g . . . . - - - -

E u .EEF .i:17 Ec ;. c:5 ,.,3 , g_g ; : ; ., .

_g g _.

t O T_ I f DRAFT

(

Open Item 3.2J.2.1-4 The applicant should perform an augmented inspection of small-bore piping for renewal. The augmented inspection would include Inconel materials, and the infonnation resulting from the response to Information Notice 9010should be considered in developing the augmented inspection ofInconel materials.

BGE Response SCC is considered plausible for two groups of piping in the Reactor Coolant System (RCS). Neider of these smups contains piping that is small-bore (between one and four inches). De first group consists of the main RCS loops, which have various Inconel l fittings that are considered susceptible for SCC. These main loops are large bore pipe (30-inch and 42 inch).

He second group is small pipe (3/4-inch) used for the Reactor Pressure Vessel flange leakoff detection lines (one per Unit). Transgranular stress corrosion cracking (TOSCC) has been experienced in these lines at CCNPP. These pipe segments are nonaally dry; however, they are filled with refbeling water during refueling operations. This water is typically not as pure as normal RCS water and can contain small amounts of chloride or caustic ions. If the pipe segments are not blown completely dry after refueling, any

/ contaminants can become concentrated during RCS operations and can lead to TGSCC.

i Aging management of these pipe segments is discussed in the response to open item 3.2.3.2.1-2.

In summary, SCC is not considered plausible for any RCS small-bore piping at CCh?P.

Augmented inspection of small bore piping for evidence of cracking is therefere not necessary.

l l

1 1

1

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

__-~3.~~~~~~-