ML042450600

License Renewal -Application - Response to Requests for Additional Information on Reactor Vessel, Internals, and Reactor Coolant System

ML042450600
Person / Time
Site:	Cook
Issue date:	08/11/2004
From:	Jensen J Indiana Michigan Power Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
AEP:NRC:4034-12, TAC MC1202, TAC MC1203
Download: ML042450600 (17)

Text

Indiana Michigan Power Company 500 Circle Drive Buchanan, Ml 49107 1395 INDIANA MICHIGAN POWER August 11, 2004 AEP:NRC:4034-12 10 CFR 54 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Mail Stop O-P1-17 Washington, DC 20555-0001

SUBJECT:

Donald C. Cook Nuclear Plant, Units I and 2 Docket Nos. 50-315 and 50-316 License Renewal -Application - Response to Requests for Additional Information on Reactor Vessel, Internals, and Reactor Coolant System (TAC Nos. MC1202 and MC1203)

Dear Sir or Madam:

By letter dated October 31, 2003, Indiana Michigan Power Company (I&M) submitted an application to renew the operating licenses for Donald C. Cook Nuclear Plant, Units I and 2 (Reference 1).

During the conduct of its review, the Nuclear Regulatory Commission (NRC)

Staff identified areas where additional information was needed to complete.its review of the license renewal application (LRA). This letter responds to Staff requests for additional information (RAIs) pertaining to the aging management review results in the following LRA section:

• Section 3.1, Reactor Vessel, Internals and Reactor Coolant System.

These RAIs were documented in two NRC letters dated June 30, 2004 (References 2 and 3), and a third NRC letter dated July 28, 2004 (Reference 4).

The enclosure to this letter provides an affirmation pertaining to the statements made in this letter.

The attachment to this letter provides the additional information requested from the NRC Staff. There are no new commitments contained in this submittal.

U. S. Nuclear Regulatory Commission Page 2 AEP:NRC:4034-12 Should you have any questions, please contact Mr. Richard J. Grumbir, Project Manager, License Renewal, at (269) 697-5141.

Sincerely, Joseph N. Jensen Site Vice President NH/rdw

Attachment:

Affirmation Response to Requests for Additional Information for the Donald C. Cook Nuclear Plant License Renewal Application -

Reactor Vessel, Internals and Reactor Coolant System

References:

1. Letter from M. K. Nazar, I&M, to NRC Document Control Desk, "Donald C.

Cook Nuclear Plant Units I and 2, Application for Renewed Operating Licenses,"

AEP:NRC:3034, dated October 31, 2003

[Accession No. ML033070177].

2. Letter from J. Rowley, NRC, to M. K. Nazar, I&M, "Request for Additional Information for the Review of the Donald C. Cook Nuclear Plant, Units 1 and 2 License Renewal Application,"

dated June 30, 2004

[Accession No. ML041830088].

3. Letter from J. Rowley, NRC, to M. K. Nazar, I&M, "Request for Additional Information for the Review of the Donald C. Cook Nuclear Plant, Units I and 2 License Renewal Application,"

dated June 30, 2004

[Accession No. ML041840218].

4. Letter from J. Rowley, NRC, to M. K. Nazar, I&M, "Request for Additional Information for the Review of Donald C. Cook Nuclear Plant, Units I and 2 License Renewal Application," dated July 28, 2004 [Accession No. ML042100372].

U. S. Nuclear Regulatory Commission AEP:NRC:4034-12 Page 3 c:

J. L. Caldwell, NRC Region III K. D. Curry, AEP Ft. Wayne, w/o attachment J. T. King, MPSC, Nv/o attachment J. G. Lamb, NRC Washington DC MDEQ - WHMD/HWRPS, w/o attachment NRC Resident Inspector J. G. Rowley, NRC Washington DC

Enclosure to AEP:NRC:4034-12 AFFIRMATION I, Joseph N. Jensen, being duly sworn, state that I am Site Vice President of Indiana Michigan Power Company (I&M), that I am authorized to sign and file this request with the Nuclear Regulatory Commission on behalf of I&M, and that the statements made and the matters set forth herein pertaining to I&M are true and correct to the best of my knowledge, information, and belief.

Indiana Michigan Power Company Joseph N. Jensen Site Vice President SWORN TO AND SUBSCRIBED BEFORE ME TN //

DAY 0

-12004 y Commission Expires JULIE E. NEWMILLER Notary Public, Berrien County, Ml My Commission Expires Aug 22,2004

Attachment to AEP:NRC:4034-12 Page I Response to Requests for Additional Information for the Donald C. Cook Nuclear Plant License Renewal Application Reactor Vessel, Internals and Reactor Coolant System This attachment provides Indiana Michigan Power Company's (I&M's) responses to the Donald C. Cook Nuclear Plant (CNP) License Renewal Application (LRA) Requests for Additional Information (RAIs) pertaining to the Aging Management Review results in the following LRA section:

Section 3.1, Reactor Vessel, Internals and Reactor Coolant System The RAIs addressed in this attachment were received in two NRC letters dated June 30, 2004 (References I and 2), and a third NRC letter dated July 28, 2004 (Reference 3).

References I

1. Letter from J. Rowley, NRC, to M. K. Nazar, I&M, "Request for Additional Information for the Review of the Donald C. Cook Nuclear Plant, Units I and 2 License Renewal Application," dated June 30, 2004 [Accession No. ML041830088].

2. Letter from J. Rowley, NRC, to M. K. Nazar, I&M, "Request for Additional Information for the Review of the Donald C. Cook Nuclear Plant, Units 1 and 2 License Renewal Application," dated June 30, 2004 [Accession No. ML041840218].

3. Letter from J. Rowley, NRC, to M. K. Nazar, I&M, "Request for Additional Information for the Review of Donald C. Cook Nuclear Plant, Units 1 and 2 License Renewal Application,"

dated July 28, 2004 [Accession No. ML042100372].

RAI 3.1-1:

Augmented inspection is recommendedfor the steam generator shell assembly, item 3.1.1-2 in Table 3.1.1 of the Aging Management Reviev (AMR). The aging effect is loss of material due to pitting and crevice corrosion, which may not be detected by the inservice inspection and water chemistry control programs. The Standard Review Plan (NUREG-1800) subsection 3.1.2.2.2 recommends an augmented inspection for this aging effect. The applicant states that the Water Chemistry Control Program will be supplemented by the Steam Generator Integrity Program for secondary side components. Neither the Steam Generator Integrity Program description, NEI

[Nuclear Energy Institute] 97-06, or the EPRI [Electric Power Research Institute] Steam Generator Examination Guidelines explain such an inspection. Describe the details of the augmented inspection and explain how it till manage the aging effect.

Attachment to AEP:NRC:4034-12 Page 2 I&M Response to RAI 3.1-1:

NUREG-1 800, Section 3.1.2.2.2, refers to NRC Information Notice (IN) 90-04, "Cracking of the Upper Shell-to-Transition Cone Girth Welds in Steam Generators," dated January 26, 1990, and recommends augmented inspection to manage pitting and corrosion. IN 90-04 states that if general corrosion pitting of the steam generator shell is known to exist, the requirements of American Society of Mechanical Engineers (ASME)Section XI may not be sufficient to differentiate isolated cracks for inherent geometric conditions.

However, as discussed in LRA Section 3.1.2.2.2, a review of operating experience indicates that CNP has not experienced general corrosion pitting of the steam generator shell; therefore, the concerns of IN 90-04 are not applicable to CNP. The Primary and Secondary Water Chemistry Control Program and the Inservice Inspection - ASME Section XI, Subsection IWB, IWC, and IWD Program are adequate to manage loss of material due to pitting and crevice corrosion on the internal surfaces of the steam generator shell.

Assessments of potential degradation mechanisms and consideration of industry events are part of the Steam Generator Integrity Program.

Augmented inspections of the upper shell-to-transition cone girth welds, if required, will be added to the current Inservice Inspection Program as part of these assessments of potential degradation or operating experience.

RAI 3.1-2:

According to Item Number 3.1.1-21 in Table 3.1.1 of the LRA, the feedwvater inlet rings and supports were not included in the scope of the AMR because the aging concern in the GALL

[Generic Aging Lessons Learned] (flow accelerated corrosion of the feedwater inlet ring and support) applies only to CE System 80 steam generators. Although the D. C. Cook plant has different steam generator models, there is still a potentialfor degradation of the feedwater inlet rings that may affect safe operation. As cited in a letter from Progress Energy (ML032650884, response to open and confirmatory items, H. B. Robinson Steam Electric Plant, Unit 2),

operating experience compiled by the Institute of Nuclear Power Operations (INPO) and the World Association of Nuclear Operators (3VANO) indicates tvo cases offeedwvater assembly degradation in Westinghouse Model 51 steam generators. The first case, in 1989, involved erosion corrosion of the J-nozzles, which were replaced The second case, in 1995, was a leak at a previously plugged bottom spray hole. Although no loose parts wvere reported in these incidents, corrosion or cracking of the J-nozzles could generate loose parts that affect steam generator tube integrity.

Houw will aging of the feedvater ring assembly, including the J-nozzles, be managed? If these components were omittedfrom the scope due to design features, please provide a description of these features and the technical basis for wvhy they eliminate the needfor aging management of the feeduwater ring assembly.

Attachment to AEP:NRC:4034-12 Page 3 I&M Response to RAI 3.1-2:

The steam generator feedwater ring and "J" tubes were omitted from the scope of license renewal due to the design features of these components. As described in the referenced response to RAI 2.3.1.6-2, submitted May 20, 2004, the steam generator feedwater ring and "J" tubes are not subject to aging management review, because they do not directly support the steam generator pressure boundary function. Furthermore, a review of the Progress Energy response to H. B. Robinson Steam Electric Plant, Unit No. 2, Open Item 2.3.1.6-1, found that the operating experience information compiled by INPO and WANO do not apply at CNP due to the configuration and materials of construction of the CNP steam generator feedwater rings and "J" tubes. The steam generators of both CNP units have "J" tubes fabricated from Alloy 690, which is inherently resistant to erosion-corrosion. Consequently, the April 25, 1989, operating experience is not applicable to CNP. The Unit I steam generators were replaced in 2000 and the Unit 2 steam generators were replaced in 1988. The steam generator feedrings for both units wvere fabricated with top discharge "J" tubes and have no plugged bottom spray holes.

Consequently, the January 14, 1995, operating experience is not applicable to the CNP steam generator components. Therefore, the concerns of Item Number 3.1.1-21 in LRA Table 3.1.1 are not applicable to CNP, as the steam generator feedwater ring and "J" tubes were appropriately omitted from the scope of the CNP aging management reviews.

Reference for RAI 3.1-2 Letter from M. K. Nazar, I&M, to NRC Document Control Desk, "Donald C. Cook Nuclear Plant, Units 1 and 2, License Renewal Application - Response to Requests for Additional Information on Scoping and Screening Results," AEP:NRC:4034-05, dated May 20, 2004

[Accession No. ML041550038].

RAI 3.1-3:

According to the AMR Results, LRA Table 3.1.2-5, the applicant credits the Water Chemistry Control program (with the Steam Generator Integrity Program in some cases) for managing loss of material during the extended operating period. Since water chemistry control is a preventative strategy, and the Steam Generator Integrity Program does not specify hosv to detect these aging effects, the staff requests that the applicant identify the aging mechanisms and explain how the aging effects vould be detected and monitored ifprevention fails. This applies to the following components:

• stainless steel cladding on the primary head in borated ivater;

• stainless steel cladding on primary nozzles in borated wvater;

• stainless steel primary nozzle safe ends in borated water;

• nickel-base alloy partition plates and nozzle dam retention rings in borated water;

• nickel-base alloy and stainless steelprimary manway insert plates in borated wvater;

• nickel-base alloy tubes and plugs in borated wrater and in treated wvater;

Attachment to AEP:NRC:4034-12 Page 4

• nickel-base alloy tubesheet cladding in borated water; vlo alloy steel tubesheet in treated water; lowv alloy steelfeedivater nozzles in treated wvater;

• nickel-base alloyfeedwtater nozzle thermal sleeve (Unit 1) in treated water;

• nickel-base alloyfeedwvater safe ends (Unit 1) in treated wvater; lowv alloy steel blowdown, instrument and other connections in treated water; lowv alloy steel handhole, inspection, and recirculation port covers in treated water;

• stainless steel steamflow restrictors (Unit I) in treated water;

• nickel-base alloyfeedwtater liner piston rings (Unit 2) in treated water;

• carbon steel tube wrappers (shroud) in treated i'ater;

• stainless steel tube support plates and anti-vibration bars (Unit 2) in treated wvater;

• carbon steel tube support plate stayrods, spacers (Unit 2), and stayrod nuts in treated 1vater;

• nickel-base alloy tube support plate stayrod washers and A VB retaining rings (Unit 2) in treated water;

• carbon steel lattice grid rings, lattice grid ring studs (Unit 1), and U-bend arch bars (Unit 1) in treated water; and

• stainless steel lattice grid bars, U-bendflat bars, and J-tabs (Unit 1) in treated wvater I&M Response to RAT 3.1-3:

Information regarding aging management of secondary side carbon and low alloy steel components exposed to treated water is provided in the response to RAI 3.14 below.

For stainless steel and nickel-based alloy components exposed to borated water, loss of material may be caused by pitting or crevice corrosion. Stainless steel and nickel-based alloys exposed to treated (borated) water are not susceptible to general, pitting or crevice corrosion if oxygen, halogen, and sulfate concentrations are maintained below 100 parts per billion (ppb), 150 ppb, and 150 ppb, respectively.

Acceptance criteria for reactor coolant system (RCS) chemistry analyses in the Primary and Secondary Water Chemistry Control Program, and the EPRI Primary Water Chemistry Guidelines, upon which the CNP program is based, are consistent with these limits.

Therefore, the Primary and Secondary Water Chemistry Control Program alone is sufficient to prevent loss of material for stainless steel and nickel-based alloys exposed to borated water. Crediting a water chemistry control program alone for age managing components in the RCS is consistent with previously approved Staff positions in the Safety Evaluation Reports for St. Lucie Nuclear Plant, Units 1 and 2, (Reference 1) and for Virgil C. Summer Nuclear Station. (Reference 2)

Stainless steel and nickel-based alloy secondary steam generator internals exposed to treated water are subject to loss of material primarily within crevices. The concentration of system fluid contaminants (due to physical configuration and small surface defects) could lead to loss of material due to pitting or crevice corrosion of nickel-based material. The Primary and Secondary Water Chemistry Control Program limits the concentration of various contaminants that could cause loss of material by crevice and pitting corrosion below the limits specified in EPRI

Attachment to AEP:NRC:4034-12 Page 5 TR-102134 for secondary water chemistry.

In addition to use of water chemistry control to prevent aging effects, visual inspection of steam generator components under the Steam Generator Integrity Program, LRA Section B. 1.31, manages loss of material that could lead to loss of intended function for selected stainless steel and nickel-based alloy secondary components identified in LRA Table 3.1.2-5.

The stainless steel and nickel-based alloy components inspected under the Steam Generator Integrity Program are representative of the stainless steel and nickel-based alloy components discussed in this RAI. If degraded conditions are found, the condition is documented through the Corrective Action Program and the inspection scope in the area of interest is expanded until the condition is bounded.

References for RAI 3.1-3

1. NUREG-1779, Safety Evaluation Report for the License Renewval of St. Lucie Nuclear Plant, Units 1 and 2, Section 3.1.1.1.2, "Staff Evaluation."

2. NUREG-1 787, Safety Evaluation Report for the License Renewal of the Virgil C. Summer Nuclear Station, Section 3.1.2.4.1, "Reactor Coolant System."

RAI 3.1-4:

According to the AMR Results, LRA Table 3.1.2-5, the applicant credits the Water Chemistry Control and Steam Generator Integrity programs for managing cracking during the extended operating period Since wvater chemistry control is a preventative strategy, and the Steam Generator Integrity Program does not specify how to detect these aging effects, the staff requests that the applicant identify the aging mechanisms and explain howv the aging effects wvould be detected and monitored ifprevention fails. This applies to the following components:

• carbon steel tube wrappers (shroud) in treated water;

• stainless steel tube support plates and anti-vibration bars (Unit 2) in treated wvater;

• carbon steel tube support plate stayrod nuts (Unit 2) in treated wvater;

• nickel-base alloy tube support plate stayrod washers and A VB retaining rings (Unit 2) in treated uvater;

• carbon steel lattice grid ring studs (Unit 1) in treated wvater; and

• stainless steel lattice grid bars, U-bendflat bars, and J-tabs (Unit 1) in treated water I&M Response to RAI 3.1-4:

The aging effects and associated mechanisms provided below are based on consideration of materials of construction and normal operating environments.

Attachment to AEP:NRC:4034-12 Page 6 Steam generator stainless steel and nickel-based alloy components exposed to a treated water environment are subject to the following aging effects and associated aging mechanisms:

Cracking, initiated by fatigue, growth of pre-service flaws at welded joints due to service loadings, and stress corrosion cracking (SCC)/intergranular attack;

• Loss of material, due to localized corrosion, such as crevice and pitting corrosion (discussed in I&M's response to RAI 3.1-3 in this letter), and wear; and

• Fouling (discussed in I&M's response to RAI 3.1-5 in this letter)

Steam generator carbon steel and low alloy steel components exposed to a treated water environment are subject to the following aging mechanisms and associated aging effects:

• Cracking, initiated by fatigue and growth of pre-service flaws at welded joints due to service loadings;

• Loss of material, due to localized corrosion, such as crevice and pitting corrosion, general corrosion, wear, and erosion; and

• Loss of mechanical closure integrity (Unit I lattice grid ring studs and Unit 2 tube support plate stayrod nuts).

As discussed in LRA Section B.1.40.1, the Primary and Secondary Water Chemistry Control Program is comparable to the program described in NUREG-1801, SectionXI.M2, Water Chemistry, which requires monitoring and control of secondary water chemistry parameters as recommended in EPRI TR-102134 to mitigate aging effects. Corrective actions are required when measured parameters are outside the specified range.

In addition to use of water chemistry control to prevent aging effects, inspection of steam generator components under the Steam Generator Integrity Program verifies the effectiveness of the chemistry control program and ensures that significant degradation is not occurring. Prior to inspections, a steam generator degradation assessment is completed to ensure that inspections are adequately focused on the expected degradation mechanisms.

Based on the results of this assessment, visual examinations of the secondary side internals items included in LRA Table 3.1.2-5 are performed to detect degraded conditions, including deformation, material loss (erosion-corrosion, pitting, wear), cracking, foreign object damage, loss of component integrity, and deposit buildup. These visual inspections are focused on the following major areas of the steam generators: tubesheet region, tube support structures, U-bend region, and the feedwater distribution system.

Attachment to AEP:NRC:4034-12 Page 7 RAI 3.1-5:

In Table 3.1.2-5 of the AMR Results, the applicant identifies fouling as an aging effect for steam generator tubes and plugs.

The applicant intends to manage this fouling with the Water Chemistry Control and Steam Generator Integrity aging management programs. Please explain how these programs address the cleaning of the components iffouling occurs (i.e. corrective actions).

I&M Response to RAI 3.1-5:

Fouling of steam generator tubes is the result of corrosion product accumulation on the tube surfaces (primarily the tube exterior surface), which reduces the ability of the tubes to transfer heat. The Primary and Secondary Water Chemistry Control Program is a mitigation program that maintains an environment in which corrosion products are limited to minimize aging effects.

As part of the Steam Generator Integrity Program, sludge lancing to remove bulk materials from the secondary side of the steam generators and visual inspections of the tubes to access deposit buildup are performed. Based upon the inspection findings, mitigation strategies (e.g., bundle flushing, chemical cleaning) are initiated and developed through the Corrective Action Program, as required to ensure continued operation without a performance (heat transfer) penalty.

RAI 3.1-6:

Table 3.1.2-5 of the AMR lists both loss of material and cracking as aging mechanisms for carbon steel closure bolts in the external-ambient environment. It is unusual for cracking, especially stress corrosion cracking, to occur in a particular alloy in the same environment that causes substantial general corrosion. What are the mechanisms and specific environments causing each aging effect for carbon steel closure bolts in the external-ambient environment?

I&M Response to RAI 3.1-6:

The bolting associated with the steam generator manways and inspection ports is fabricated from SA-193 Grade B7 material, which is susceptible to SCC and fatigue cracking. Although these fasteners are not intentionally exposed to water or steam, inadvertent exposure may result if leaks occur. If leakage is combined with contaminant species, such as sulfides or chlorides, an aggressive environment that can promote SCC may result. Therefore, cracking of the steam generator bolting is considered an aging effect requiring management for the period of extended operation.

While the external surfaces of the steam generators and bolting are not normally exposed to RCS fluid, the potential for boric acid wastage exists due to leakage from the bolted closure. Therefore, external surfaces of the steam generator closure bolts fabricated from ferritic steel are potentially subject to loss of material.

Attachment to AEP:NRC:4034-12 Page 8 RAI 3.1-7:

In Table 3.1.2-5 of the AMR, the applicant credits the Steam Generator Integrity Program for managing the loss of mechanical closure integrity for carbon steel tube support plate stayrod nuts (Unit 2) and carbon steel lattice grid ring studs (Unit 1) in treated water. Neither the Steam Generator Integrity Program description, NEI 97-06, nor the EPRI Steam Generator Examination Guidelines discuss mechanical closure integrity. Please describe in detail how the Steam Generator Integrity Program will be used to manage the effects of the loss of mechanical closure integrity on these components.

I&M Response to RAI 3.1-7:

The Steam Generator Integrity Program includes actions to verify the overall structural integrity of the steam generator secondary side internals. Loss of mechanical closure integrity of stayrod nuts and ring studs could result in loss of tube support structure integrity. The Steam Generator Integrity Program specifies visual inspections of the tube support structures, as determined by a steam generator degradation assessment. This assessment is performed prior to each inspection and serves to identify areas within the steam generators, based upon plant operating conditions, design features and industry and plant-specific operating experience, that require periodic monitoring to ensure tube and support structure integrity is maintained. Therefore, loss of mechanical closure integrity of the stayrod nuts and ring studs will be effectively managed by the Steam Generator Integrity Program for the period of extended operation.

RAI 3.1-8:

For flaws in the RPV and control rod drive mechanism components listed in LRA Table 3.1.2-1 which have been detected and evaluated to date in accordance with ASME Code Section XI requirements, please propose a plan to monitor and evaluate these flaws during the period of extended operation because disposition of these detectedflawvs to date was based on a period of4O years of operation.

This plan should include monitoring and evaluating detected underclad flawvs exceeding 0.3 inch in depth, the maximum initialflaw depth that was evaluated in TWCAP-15338, "A Review of Cracking Associated with field Deposited Cladding in Operating PWVR Plants."

I&M Response to RAI 3.1-8:

In accordance with ASME Section XI, Subarticle IWB-3600, analytical evaluation of reportable flaws (defects) requires that flaw growth be considered for an evaluation period equal to the time of the next inspection following discovery of the flaw, or until the end of the service life of the item. As reported in LRA Table 4.1-2, inservice inspection records indicated no defects that required analytical evaluation of flaws to the end of the service life of the component.

Attachment to AEP:NRC:4034-12 Page 9 Inspection and evaluation of the control rod drive mechanism nozzles for continued service is addressed by the Control Rod Drive and Other Vessel Head Penetration Program discussed in LRA Section B.1.9.

Resolution of underclad cracking for CNP is discussed in LRA Section 4.7.4. The CNP reactor vessels do not contain SA-508, Class 2, forgings in the beltline regions. Only the vessel and closure head flanges and inlet and outlet nozzles are fabricated from SA 508, Class 2, forgings.

The analytical evaluation contained in WCAP-15338 has been used to demonstrate that fatigue growth of the subject flaws will be minimal over 60 years and the presence of underclad cracks are of no concern relative to the structural integrity of the vessels. Based on this evaluation, additional inspections to detect and monitor crack growth during the period of extended operation are not required, and the analysis of underclad cracking remains valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i). Therefore, an aging management program in accordance with 10 CFR 54.2 1(c)(1)(iii) is not required to manage underclad cracking.

RAI 3.1-9:

For shell rings listed in LRA Table 3.1.2-1, Footnote I and Footnote 8 indicate that certain shell ring welds were fabricated using nickel-based wield material (e.g., Alloy 82/182, 52/152), and primary water stress corrosion cracking is a concern for these welds. Identify all locations under "shell rings "of Table 3.1.2-1 which have nickel-based weld material exposed to borated water environments.

I&M Response to RAI 3.1-9:

The reactor vessel shell ring segments are constructed from SA-533 Grade B Class 1 alloy steel with a cladding overlay on interior surfaces that is primarily stainless steel. The sole exception to stainless steel cladding is the nickel-based alloy cladding under the six core support lugs around the lower shell ring. These six nickel-based weld material overlays on-the reactor vessel shell rings are exposed to a treated (borated) water environment and are susceptible to primary water SCC.

RAI 3.1-10:

The LRA Table B-1 indicates that you do not have an AMP similar to GALL Program XI M3, "Reactor Head Closure Studs " for managing cracks, loss of material, and leakage associated with closure studs, nuts and washers, which are directly related to loss of mechanical closure integrity for these components. By crediting Inservice Inspection and Boric Acid Corrosion Prevention programs, as indicated in LRA Table 3.1.2-1, with the management of this aging effect for closure studs, nuts and washers, you have captured one of the two main elements of GALL Program Xl.M3.

However, to filly justify not having an AMP similar to GALL

Attachment to AEP:NRC:4034-12 Page 10 Program XLM3, please address the other main element of GALL Program XI.M3, i.e., discuss the preventive measures to mitigate cracking in these components. Preventive measures may include avoiding the use of metal-plated stud bolting to prevent degradation due to corrosion or hydrogen embrittlement and the use manganese phosphate or other acceptable surface treatments and stable lubricants (RG 1. 65).

I&M Response to RAI 3.1-10:

I&M incorporates preventive measures to manage cracking of the reactor vessel closure bolting.

A magnesium phosphate coating is applied to the bearing surfaces of the CNP reactor vessel closure bolting (studs, nuts, and washers) during fabrication. The CNP reactor vessel stud tensioning procedure requires the use of a lubricant (neolube) which mitigates cracking of the closure bolting.

These preventive measures, along with regular inspections as part of the Inservice Inspection and Boric Acid Corrosion Prevention Programs, will manage the aging effects applicable to the reactor vessel closure bolting for the period of extended operation.

RAI 3.1.2-1 In Table 3.1.2-1, the applicant has identified cracking as an aging effect requiring management for Reactor Vessel and CRDM Pressure Boundary components manufacturedfrom nickel-based alloys and stainless steel alloys exposed to treated (borated) wvater environments. The applicant identified the flange leak tubes as the components that are subject to cracking. The applicant stated that the flange leak tubes in Unit 1 are made from nickel-based alloys and the flange leak tubes from Unit 2 are made from stainless steel. The aging effect is managed by the Water Chemistry Control, Inservice Inspection, and Alloy 600 Aging Management (Unit 1 only) programs. The applicant stated that the component, material, environment, aging effect and aging management program (AMP) is consistent with NUREG-1801.

NUREG-1801 Item A 2.1-F states that a plant-specific AMP needs to be evaluated because existing programs may not be capable of mitigating or detecting crack initiation and growth due to SCC in the vessel flange leak detection line. The applicant has not identified how SCC vill be managed in the stainless steelflange leak tubes.

The staff requests that the applicant identify the AMP that vill be used to mitigate or detect crack initiation and growth due to SCC in the stainless steel vessel flange leak tubes. Included should be a discussion about corrective actions involving repair/replacement.

I&M Response to RAI 3.1.2-1:

The Unit 2 stainless steel flange leak tubes listed in LRA Table 3.1.2-1 are contained entirely within the reactor vessel flange. Stainless steel piping is attached to these tubes, external to the vessel. This piping is included in the RCS stainless steel piping of less than 4-inch nominal pipe

Attachment to AEP:NRC:4034-12 Page I I size, as listed in LRA Table 3.1.2-3. The combination of the Primary and Secondary Water Chemistry Control

Program, described in LRA Section B.1.40.1; the Inservice Inspection - ASME Section XI, Subsection IWB, IWC, and IWD Program, described in LRA Section B.1.14; and, for the piping, the Small Bore Piping Program, described in LRA Section B. 1.30, will manage the SCC aging effect on the stainless steel reactor vessel flange leak detection tubes and external piping.

If required, evaluation, repair, and replacement are performed in accordance with applicable ASME Section XI requirements.

RAI 3.1.2-2 In Table 3.1.2-2, the applicant has identified that loss of material is an aging effect requiring management for Class 1 valve components manufacturedfrom low alloy steel and exposed to an external ambient environment.

The aging effect is managed by the Boric Acid Corrosion Prevention Program. The applicant identified the components as Class 1 valve bodies and bonnets 2 2W', and bolting material (for valves and blind flanges). The aging effect is not identified in GALL for this component, however, the AMP is consistent with the NUREG-1801 AMP description in Section XI.M10. The aging effect for the bolting material (for valves and blind flanges) is consistent with GALL for this component, environment, and material and the AMP is consistent with the NUREG-1801 AMP description in Section XI.MJO. The applicant stated that the Boric Acid Corrosion Prevention program relies on the implementation of recommendations in NRC Generic Letter (GL) 88-05, "Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PJWR Plants," to monitor the condition offerritic steel components on which borated reactor water may leak. The applicant stated that periodic visual inspection of adjacent structures, components, and supports for evidence of leakage and corrosion is an element of the GL 8&05 monitoring program.

The applicant did not identify which aging mechanisms could lead to loss of material in the above components that are fabricated from alloy steel or carbon steel, although the AMP credited with aging management appears to imply that the applicant only considers potential leakage of the borated coolant as a mechanism that could induce loss of material from the external surfaces of these components. Alloy steel and carbon steel components may also be susceptible to general corrosion in atmospheric environments if the atmospheres are damp, moist or humid.

The staff requests that the applicant identify the aging mechanism that CArP has determined are capable of inducing loss of material in alloy steel or carbon steel of the above components that are exposed externally to the inside environments. In addition, the applicant is requested to describe the inside environment and thether the applicant is managing the wtater vapor content in the inside environment to low humidity levels. The staff seeks further clarification on whether the applicant considers loss of material due to general corrosion as an applicable aging effect for external surfaces of alloy steel or carbon steel components that are exposed to the inside environment. If not, the applicant is requested to provide technical justification why CArP does

Attachment to AEP:NRC:4034-12 Page 12 not consider general corrosion to be an aging mechanism that needs management in the external surfaces of alloy steel or carbon steel components during the extendedperiods of operation.

I&M Response to RAI 3.1.2-2:

Containment temperature is maintained below 120 degrees Fahrenheit (0F) in the containment lower compartment and below 1000F in the containment upper compartment; humidity is not managed inside containment. No Class I valves or low alloy steel materials are listed in LRA Table 3.1.2-2; they are, however, listed in LRA Table 3.1.2-3. The representative component types listed include selected low alloy Class 1 valve bonnets and low alloy steel bolting associated with valves and blind flanges. Low alloy steel components such as ferritic valve bonnets and ferritic bolting are susceptible to loss of material due to boric acid corrosion that might result from system leakage onto these components. Because the valve components are inside containment, no significant general corrosion is expected.

Under the Boric Acid Corrosion Prevention Program described in LEA Section B. 1.4, evidence of moisture that could cause boric acid corrosion (or general corrosion) on ferritic surfaces is detected by visual inspection and evaluated by engineering to determine the leakage source, extent of degradation, and required corrective actions. Therefore, loss of material of low alloy steel valve bonnets and low alloy steel closure bolting will be managed by the Boric Acid Corrosion Prevention Program for the period of extended operation.

RAI 3.1.2-3 In Table 3.1.2-2, the applicant has identified that loss of material is an aging effect requiring management for Reactor Coolant Pump components manufactured from loll alloy steel and exposed to an external ambient environment. The aging effect is managed by the Boric Acid Corrosion Prevention program. The applicant identified the components requiring management are the main flange bolts. The aging effect is not identified in GALL for this component, however, the AMP is consistent vith the NUREG-1801 AMP description in Section XI.MI 0. The aging effect for the main flange bolts is consistent with GALL for this component, environment, and material and the AMP is consistent with the NUREG-1801 AMP description in SectionXI.M10. The applicant stated that the Boric Acid Corrosion Prevention Program relies on the implementation of recommendations in NRC Generic Letter (GL) 88-05, "Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWVR Plants," to monitor the condition of ferritic steel components on which borated reactor wvater may leak The applicant stated that periodic visual inspection of adjacent structures, components, and supports for evidence of leakage and corrosion is an element of the GL 88-05 monitoring program.

The applicant did not identify which aging mechanisms could lead to loss of material in the above components that are fabricated from alloy steel or carbon steel, although the AMP credited with aging management appears to imply that the applicant only considers potential leakage of the borated coolant as a mechanism that could induce loss of material fiom the

Attachment to AEP:NRC:4034-12 Page 13 external surfaces of these components. Alloy steel and carbon steel components may also be susceptible to general corrosion in atmospheric environments if the atmospheres are damp, moist or humid.

The staff requests that the applicant identify the aging mechanism that CNP has determined are capable of inducing loss of material in alloy steel or carbon steel of the above components that are exposed externally to the inside environments. In addition, the applicant is requested to describe the inside environment and whether the applicant is managing the water vapor content in the inside environment to lowv humidity levels. The staff seeks further clarification on whether the applicant considers loss of material due to general corrosion as an applicable aging effect for external surfaces of alloy steel or carbon steel components that are exposed to the inside environment. If not, the applicant is requested to provide technical justification why CNP does not consider general corrosion to be an aging mechanism that needs management in the external surfaces of alloy steel or carbon steel components during the extendedperiods of operation.

I&M Response to RAI 3.1.2-3:

Containment temperature is maintained below 120'F in the containment lower compartment and below 1000F in the containment upper compartment; however, humidity is not managed inside containment. No reactor coolant pump (RCP) or low alloy steel materials are listed in LRA Table 3.1.2-2; the low alloy steel RCP main flange bolting is, however, listed in LRA Table 3.1.2-3. Low alloy steel components, such as bolting, are susceptible to loss of material due to boric acid corrosion that might result from system leakage onto these components. Because the components are inside containment, no significant general corrosion is expected. Under the Boric Acid Corrosion Prevention Program described in LRA Section B.1.4, evidence of moisture that could cause boric acid corrosion (or general corrosion) on ferritic surfaces is detected by visual inspection and evaluated by engineering to determine the leakage source, extent of degradation, and required corrective actions. Therefore, loss of material of low alloy steel RCP main flange bolting will be managed by the Boric Acid Corrosion Prevention Program for the period of extended operation.