ML041890378

Units I and 2 - License Renewal Application - Response to Requests for Additional Information on Engineered Safety Features, Auxiliary Systems, and Steam and Power Conversion Systems

ML041890378
Person / Time
Site:	Cook
Issue date:	06/30/2004
From:	Nazar M Indiana Michigan Power Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
AEP:NRC:4034-09
Download: ML041890378 (35)

Text

Indiana Michigan Power Company 500 Circle Drive Buchanan, Ml 49107 1395 INDIANA MICHIGAN POWER June 30, 2004 AEP:NRC:4034-09 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 Engineered Safety

Features, Auxiliary Systems, and Steam and Power Conversion Systems (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) that were documented in an NRC letter dated May 26, 2004 (Reference 2), for the following LRA sections:

• 3.2 - Engineered Safety Features

• 3.3 - Auxiliary Systems

• 3.4 - Steam and Power Conversion Systems In addition to the referenced NRC letter, I&M also received questions in the form of draft RAls (D-RAIs) from the Staff.

In a public meeting held on April 13, 2004, the Staff instructed I&M to consider these D-RAIs final, and provide responses as required to support NRC review of the LRA. The NRC's April 13, 2004 meeting summary (Reference 3) includes two D-RAIs pertaining to the fire protection system aging management review, which were not included with I&M's responses to the LRA Section 3.3 RAIs (Reference 4). Therefore, this letter also provides I&M's responses to RAIs 3.3.1-1 and 3.3.1-2, which were referred to as D-RAIs 3.3.1-1 and 2.3.3.8-1 on page 17 of Reference 3.

OqItt

U. S. Nuclear Regulatory Commission AEP:NRC:4034-09 Page 2 The enclosure to this letter provides an affirmation pertaining to the statements made in this letter. Attachment I provides the additional information requested from the NRC Staff. There are no new commitments contained in this submittal.

Should you have any questions, please contact Mr. Richard J. Grumbir, Project Manager, License Renewal, at (269) 697-5141.

Sincerely, M. K. Nazar Senior Vice P sident and Chief Nuclear Officer NH/rdw

Enclosure:

Affirmation

Attachment:

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

Engineered Safety Features, Auxiliary Systems, and Steam and Power Conversion Systems

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.

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, Unit 1 and 2 License Renewal Application," dated May 26, 2004.

3. NRC Memorandum from J. Rowley, License Renewal Section A, License Renewal and Environmental Impacts Program, "Summary of April 13, 2004, Meeting Between the U.S. Nuclear Regulatory Commission (NRC) and Indiana Michigan Power Company (I&M) Representatives, to Discuss Proposed Responses to Draft Request for Additional Information Concerning the License Renewal Application for Donald C. Cook Nuclear Plant, Units I and 2," dated May 10, 2004.

4. 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 Electrical and Auxiliary Systems,"

AEP:NRC:4034-06, dated June 8, 2004.

U. S. Nuclear Regulatory Commission AEP:NRC:4034-09 Page 3 c:

J. L. Caldwell, NRC Region III K. D. Curry, AEP Ft. Wayne, w/o attachment J. T. King, MPSC, w/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:4034-09 AFFIRMATION I, Mano K. Nazar, being duly sworn, state that I am Senior Vice President and Chief Nuclear Officer of American Electric Power Service Corporation and 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.

American Electric Power Service Corporation M. K. Nazar Senior Vice Pro and Chief Nuclear Officer SWORN TO AND SUBSCRIBED BEFORE ME THIS e

DAY OF GorQ

,2004 otary Public My Commission Expires Nr

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(-, /m, 1206-1 BRIDGET TAYLOR Notary Public - Michigan BerrIen County My CommIssion Expires June 10, 2007 to AEP:NRC:4034-09 Page 1 Response to Requests for Additional Information for the Donald C. Cook Nuclear Plant License Renewal Application Engineered Safety Features, Auxiliary Systems, and Steam and Power Conversion Systems 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) provided in a Nuclear Regulatory Commission (NRC) letter dated May 26, 2004 (Reference 1). The RAIs addressed in this letter pertain to the following LRA sections:

• 3.2 - Engineered Safety Features (ESF)

• 3.3 - Auxiliary Systems

• 3.4 - Steam and Power Conversion Systems This attachment also provides I&M's responses to RAIs 3.3.1-1 and 3.3.1-2, which were received in the form of draft RAls with the summary of the NRC Staff's April 13, 2004 meeting with I&M representatives (Reference 2).

References

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, Unit 1 and 2 License Renewal Application," dated May 26, 2004.

2. NRC Memorandum from J. Rowley, License Renewal Section A, License Renewal and Environmental Impacts Program, "Summary of April 13, 2004, Meeting Between the U.S.

Nuclear Regulatory Commission (NRC) and Indiana Michigan Power Company (I&M)

Representatives to Discuss Proposed Responses to Draft Request for Additional Information Concerning the License Renewal Application for Donald C. Cook Nuclear Plant, Units 1 and 2," dated May 10, 2004.

RAI 3.2-1:

LRA Section 3.2.2.2.1 identifies the applicant's aging management for cumulative fatigue damage for components in the ESF systems. In the discussion the LRA refers to Section 4.3 which states that based on a screening criteria, the applicant detenmined that components in the ECCS system exceeded the screening criteria. The piping components that exceeded the screening criteria were evaluated by the applicant for their potential to exceed 7000 thermal cycles in sixty years of plant operation.

to AEP:NRC:4034-09 Page 2 The applicant determined that none of the piping components in the EFS system exceeded 7000 cycles during the period of extended operation. The applicant is requested to provide the highest estimated number of thermal cycles and the basis for derivation for each component type identified in Tables 3.2.2-1, -2, -3 and -4 of the LRA for which TLAA-Metal Fatigue has been designated as the aging management program. For those components whose material or aging effect is not specified in NUREG-1801 (designated as 'F' and 'I' respectively in the notes),

clarify whether or not the applicant performs the thermal cycle evaluation in accordance with NUREG-1801, Section 4.3-1.12.

If so, is the applicants TLAA program consistent with NUREG-1801. If not explain any differences. Also the applicant is requested to address how unanticipated transients and thermal stratification are accounted for in the estimation where applicable.

I&M Response to RAI 3.2-1:

The evaluation of cracking by fatigue was identified as a time-limited aging analysis (TLAA) for selected mechanical components in the containment isolation system (LRA Table 3.2.2-2) and the emergency core cooling system (ECCS) (LRA Table 3.2.2-3). Evaluation of cracking by fatigue was not identified as a TLAA for components in the containment spray system (LRA Table 3.2.2-1) or the containment equalization/hydrogen skimmer system (LRA Table 3.2.2-4).

The containment isolation system mechanical components identified as susceptible to cracking by fatigue in LRA Table 3.2.2-2 are limited to non-Class 1 reactor coolant system (RCS) sample line piping and valves associated with containment penetrations 1-CPN-66 and 2-CPN-66, which were designed in accordance with United States of America Standard (USAS) B31.1. License renewal drawings LRA-1-5141 and LRA-2-5141 show the non-Class I sample line components associated with CPN-66. The evaluation of cracking by fatigue for the non-Class 1 portions of the sample line is discussed in LRA Section 4.3.2 and is the subject of RAI 4.3.2-1 (Reference 1).

The ECCS mechanical components identified as susceptible to cracking by fatigue in LRA Table 3.2.2-3 include non-Class 1 residual heat removal (RHR) heat exchanger (HE-17) and RHR pump mechanical seal heat exchanger (HE-32) tubes; RHR pump (PP-35) casings; and RHR system piping, thermowells, tubing, strainer housings, and valves, which are subjected to elevated temperatures when used during plant cooldown.

License renewal drawings LRA-1-5135A, LRA-1-5143, LRA-2-5135A, and LRA-2-5143 show these non-Class 1 RHR components.

With regard to RHR piping, valves, and other mechanical components designed in accordance with USAS B31.1, the RHR system is restricted to the 200 RCS heatup and cooldown cycles shown in LRATable 4.3-1.

Therefore, RHR mechanical components will not approach 7,000 cycles during the period of extended operation.

to AEP:NRC:4034-09 Page 3 Fatigue of the RHR heat exchangers is discussed in LRA Section 4.3.2. The tube side of these heat exchangers was designed in accordance with American Society of Mechanical Engineers (ASME)

Section III/Class C and the shell side was designed in accordance with ASME Section VIII, Division 1, for unfired welded pressure vessels.

The equipment specification for the RHR heat exchangers required the supplier to verify that all conditions of ASME Section III, Paragraph N-415.1 (i.e., exemption from fatigue for Class 1 components), are satisfied for the transient conditions specified in the equipment specification. Specifically, the RHR heat exchangers shall be capable of a step change of tube side fluid from 85 degrees Fahrenheit (OF) to 3500F simultaneously with 200 cycles of pressurization to the heat exchanger's tube side design pressure of 600 psig.

The design transients identified in the heat exchanger specification are consistent with the RCS transients defined in Updated Final Safety Analysis (UFSAR) Table 4.1-10 for heatups and cooldowns. As described in LRA Section 4.3.1, the assumed number of RCS design transients is acceptable for 60 years, and the fatigue evaluation considered in the original design of the RHR heat exchangers will remain valid during the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).

The RHR pumps were designed in accordance with the Standard of the Hydraulic Institute, USAS B16.5, and ASME Draft Code for Pumps and Valves-1968.

There were no fatigue requirements for design of the RHR pumps and fatigue is not a TLAA for these pumps.

In the second part of this RAI, the NRC Staff requested a clarification of whether I&M performs the thermal cycle evaluation in accordance with NUREG-1801, Section 4.3-1.12.

In a clarification to this RAI, the NRC Staff indicated that the referenced thermal cycle evaluation is addressed in NUREG-1800, Section 4.3.1.2, not NUREG-1801, Section 4.3-1.12.

NUREG-1800, Section 4.3.1.2, "Generic Safety Issue," discusses the effects of reactor coolant environment on component fatigue life. I&M's review of NUREG-1800 determined that the Generic Safety Issue (GSI) discussion in Section4.3.1.2, does not apply to the non-Class 1 portions of the ESF systems evaluated in LRA Section 3.2 because the scope of the GSI is limited to Class 1 locations identified in NUREG/CR-6260.

The thermal cycle evaluations discussed in this RAI response pertain to those performed for USAS B3.1.1 piping, as discussed in NUREG-1800, Section 4.3.1.1.2, "ANSI B31.1."

The thermal cycle assessment for USAS B31.1 piping, as described in NUREG-1800, Section4.3.1.1.2, was performed for components that operate at temperatures that exceed the screening criteria provided in LRA Section 4.3.2. In addition to the 10 CFR 54.21(a) screening criteria, each mechanical system reviewed for the CNP integrated plant assessment (IPA) was also screened to identify potential metal fatigue TLAAs. This was accomplished by identifying non-Class 1 components that may operate at temperatures in excess of 2200F for carbon steel or 270'F for austenitic stainless steel during normal or upset conditions. Fatigue evaluations of components that exceeded the screening criteria were identified as TLAAs.

These screening to AEP:NRC:4034-09 Page 4 criteria are consistent with those described in Section 4.3.2 of the St. Lucie Units 1 and 2 LRA (Reference 2).

The threshold value of 220'F for thermal fatigue of carbon steel piping is based on an initial ambient temperature of 70'F with a minimum temperature differential of 150'F. The threshold value of 270'F for thermal fatigue of stainless steel piping is based on an initial ambient temperature of 70'F with a minimum temperature differential of 200'F.

The minimum temperature differentials are based on industry-sponsored investigations and evaluations of thermal fatigue in nuclear plant piping systems, as presented in Electric Power Research Institute (EPRI) Report No. TR-104534 (Reference 3).

Thermal stratification in Class 1 portions of systems attached to the RCS is addressed in the I&M responses to NRC Bulletin 88-08, Thennal Stresses in Piping Connected to Reactor Coolant Systems (LRA References 4.3-11 through 4.3-15), as summarized in LRA Section 4.3.1.

UFSAR Section 4.1.4 describes cyclic load considerations. RCS components were designed to withstand the effects of cyclic loads due to reactor system temperature and pressure changes.

Normal power changes, reactor trips, and startup and shutdown operations introduce these cyclic loads. The number of thermal and loading cycles used for design purposes are given in UFSAR Table 4.1-10. To provide a high degree of integrity for the equipment in the RCS, the transient conditions selected for equipment fatigue evaluation were based on a conservative estimate of the magnitude and frequency of the temperature and pressure transients resulting from normal operation, normal and abnormal load transients, and accident conditions. To a large extent, the specific transient operating conditions considered for equipment fatigue analyses were based upon engineering judgment and experience.

The transients chosen are representative of transients which prudently should be considered to occur during plant operation and which are sufficiently severe or may occur frequently enough to be of possible significance to component cyclic behavior. Unanticipated transients are not accounted for in this methodology. If they occur, they are identified and evaluated for impact on design thermal and loading cycles through the Corrective Action Program.

Reference for RAI 3.2-1

1. 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 Time-Limited Aging Analyses," AEP:NRC:4034-08, dated June 16, 2004.

2. License Renewal Application, St. Lucie Units 1 & 2, Section 4.3.2, ASME Boiler and Pressure Vessel Code,Section III, Class 2 and 3, and ANSI B31.1 Components

[ML013400350].

3. EPRI Report No. TR-104534, Fatigue Management Handbook, Volumes 1, 2, and 3, Research Project 3321, Revision 1, Electric Power Research Institute, December 1994.

to AEP:NRC:4034-09 Page 5 RAI 3.2-2:

LRA Table 3.2.2-2 does not list any aging effect requiring management for carbon steel piping with an internal nitrogen environment. The applicant is requested to discuss the potential for moisture in the internal nitrogen and whether or not it is periodically verified.

I&M Response to RAI 3.2-2:

The carbon steel piping with an internal nitrogen environment is shown on license renewal drawings LR.A-1-5143A and LRA-2-5143A. The nitrogen inside this piping is supplied by the on-site nitrogen supply system shown on license renewal drawing LRA-12-51 18B. The nitrogen gas inside the tanks that supply these lines is provided by a vendor as 99.998% pure nitrogen with moisture less than 5.0 parts per million.. The nitrogen supply system does not contain compressors that could introduce contaminants such as moisture.

Since there is minimal potential for moisture inside the carbon steel pipe associated with these containment penetrations, sampling is not required.

RAI 3.2-3:

LRA Table t3.2.2-2 credits the Containment Leak Rate Testing Program for managing loss lof material of carbon steel piping in an air (internal) environment. This is a plant specific program since the comparable environment for carbon steel piping is not evaluated in the GALL report.

The applicant is requested to perform a one-time inspection in addition to the Containment Leak Rate Testing Program to identify and mitigate any aging effects due to moisture in the internal air of the carbon steel piping.

I&M Response to RAI 3.2-3:

The following table identifies containment isolation system containment penetrations with component types "Piping" and "Valve" listed in LRA Table 3.2.2-2 that are constructed of carbon steel, contain air, and credit the Containment Leakage Rate Testing Program for managing loss of material.

License Renewal Penetration Service Drawing (locations)

Number 1-5 140 (L5) 1-CPN-71 containment service penetration 1-5140 (L9) 1-CPN-76 containment thimble removal 1-5140 (L2) 1-CPN-83 containment service penetration 2-5124 (D3/D4) 2-CPN-67 blind flange for maintenance to AEP:NRC:4034-09 Page 6 License Renewal Penetration Service Drawing (locations)

Number 2-5140 (L2) 2-CPN-71 containment service penetration 2-5140 (K8/K9) 2-CPN-76 containment thimble removal 2-5145 (G2/G3) 2-CPN-83 capped piping - no longer used (originally weld channel pressurization line) 2-5146A (M2) 1-CPN-57 access for ice loading line 2-5146A (M2) 1-CPN-80 access for ice loading line 2-5146A (E2) 2-CPN-57 access for ice loading line 2-5146A (E3) 2-CPN-80 access for ice loading line 12-5120B (Bl) 1-CPN-57 access for ice loading line 12-5120B (JI) 2-CPN-57 access for ice loading line In addition to these penetrations, components associated with two penetrations in the plant air system, 1-CPN-29 and 2-CPN-29, are included in LRA Table 3.3.2-4 and shown on license renewal drawing LRA-12-5120B at locations C7 and H7 - K7. The component types "Piping" and "Valve" associated with these penetrations are also carbon steel, contain untreated air, and credit the Containment Leakage Rate Testing Program for managing loss of material.

All of the above penetrations are used during outages or are capped and are no longer used.

During normal operation, these penetrations contain only the air that is trapped internal to the penetration. These penetrations are not exposed to a continuous supply of air that could provide additional moisture and cause a significant loss of material.

The internal surfaces could experience minor general corrosion but significant loss of material is not expected due to the limited amount of moisture in the captured air within the penetration piping.

Containment leakage rate tests verify that leakage through components that penetrate containment does not exceed allowable rates specified in the technical specification or associated bases. In addition, periodic surveillance tests of the components included as part of the Containment Leakage Rate Testing Program are performed to verify that proper maintenance and repairs are made during the service life of the containment. Negative trends and degraded conditions identified by this program that could be indicative of loss of material would be addressed by the Corrective Action Program. Therefore, the Containment Leakage Rate Testing Program is adequate to manage the aging effect of loss of material for these penetrations, and no one-time inspections are necessary.

RAI 3.2-4:

LRA Table 3.2.2-2 credits the Boric Acid Corrosion Prevention Program for managing loss of mechanical closure integrity for carbon steel bolts in an external air environment. This aging to AEP:NRC:4034-09 Page 7 management program relies on implementation of recommendations in NRC Generic Letter (GL) 88-05 "Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWR Plants. " Since this program addresses components inside the containment, the applicant is requested to discuss the managementfor the loss of mechanical closure integrity of carbon steel bolts outside the containment.

I&M Response to RAI 3.2-4:

The Boric Acid Corrosion Prevention Program manages loss of mechanical closure integrity for carbon steel bolts on which borated reactor water may leak. It includes carbon steel bolts in an external air environment whether inside or outside of containment.

RAI 3.2-5:

LRA Table 3.2.2-2 credits the Bolting and Torquing Activities programsfor managing the loss of mechanical closure integrity of carbon steel and stainless steel bolts in an external air environment. The applicant is requested to discuss how cracking and loss ofpreload resulting in loss of mechanical closure integrity is managed. Also the applicant is requested to provide the inspection activities in its program which are equivalent to the appropriate ASME Section XI requirements. In addition the applicant is requested to address how the aging effects are managed for inaccessible bolts. These include bolts such as those located in cavities or obstructed by other components and devices.

I&M Response to RAI 3.2-5:

Cracking: Stress corrosion cracking (SCC) occurs through the combination of high stress, a corrosive environment, and a susceptible material (such as that used in high-strength bolts).

CNP piping material specifications do not permit, nor have they historically permitted, high-strength bolting in non-Class 1 systems. Proper lubricants and sealant compounds are used to minimize the potential for SCC. In the aging management reviews, sufficient stress to initiate SCC was assumed if bolting was subject to a corrosive environment. Since bolted closures do not contain high-strength bolting, are not submerged or exposed to lubricants containing contaminants, and are exposed to ambient temperature rather than high-temperature process fluids, cracking is not an aging effect requiring management for non-Class 1 closure bolting in an external air environment.

Review of operating experience did not identify problems with cracking of carbon or stainless steel bolting in air environments.

Loss of Pre-load:

The Bolting and Torquing Activities Program assures that proper torque values are applied to bolted closures such that loss of mechanical closure integrity as a result of loss of pre-load does not occur.

to AEP:NRC:4034-09 Page 8 ASME Code Applicability: The Bolting and Torquing Activities Program, Boric Acid Corrosion Prevention Program, and System Walkdown Program manage loss of mechanical closure integrity for closure bolting as described in LRA Sections B.1.2, B.1.4, and B.1.38, respectively.

Visual inspections of bolting for loss of material and loss of mechanical closure integrity in the Boric Acid Corrosion Prevention Program and System Walkdown Program are adequate to assure that the closure bolting can perform its intended function since loss of material (and ultimately loss of mechanical closure integrity) for external surfaces such as closure bolting is a long-term aging effect that would be observed well before aging progressed to the point of loss of intended function. The Bolting and Torquing Activities Program assures that proper torque values are applied to bolted closures such that loss of mechanical closure integrity as a result of loss of preload due to high temperatures does not occur.

The Bolting and Torquing Activities program is a plant-specific program and is not comparable to NUREG-1801,Section XI.M18, "Bolting Integrity," which stipulates the inspection requirements of ASME Code,Section XI. These requirements are included in the Inservice Inspection Program for Class 1, 2, and 3 bolted closures.

However, these inspection requirements are focused on identifying the aging effect of cracking. Since cracking is not an aging effect requiring management for non-Class 1 bolted closures, the Inservice Inspection Program is not an applicable aging management program for these components.

Inaccessible Bolting AMine Management: When bolted closures are assembled, proper bolting material and appropriate lubricants and sealants are selected in accordance with EPRI NP-5067, Good Bolting Practices. Torque values are monitored when the bolted closure is assembled.

Maintenance personnel visually inspect components used in bolted closures to assess their general condition during maintenance.

Gaskets, gasket seating surfaces, and fasteners are inspected for damage that would prevent proper sealing. Therefore, the Bolting and Torquing Activities Program manages aging effects for bolting, whether accessible or inaccessible. The Bolting and Torquing Activities Program applies to bolting both inside and outside of containment.

RAI 3.2-6:

LRA Table 3.2.2-1 identifies a plant specific In-service Inspection Program for managing the aging effect due to cracking and loss of material of stainless steel thermowells and valves in a sodium hydroxide environment. This combination of environment, material and component is not evaluated in the GALL report. The applicant is requested to discuss the plant specific inspection methods including frequency of inspections and acceptance criteria. Also, identify the differences with the appropriate ASME Section XI requirements, if any, and provide justifi cation for the differences.

to AEP:NRC:4034-09 Page 9 I&M Response to RATI 3.2-6:

To manage cracking and loss of material of stainless steel thermowells and valves in a sodium hydroxide environment, LRA Table 3.2.2-1 and LRA Section B.1.18 identify an Augmented Inservice Inspection (ISI) Program that specifies volumetric inspections for portions of the containment spray system wetted by sodium hydroxide. Augmented inspections are specified for components that are outside the jurisdiction of ASME Section XI inspection requirements.

Augmented inspections use the same non-destructive examination methods used for ASMIE Section XI inspections on Class 1, 2, or 3 components. The inspections of the stainless steel thermowells and valves in the containment spray system will use ultrasonic techniques, where feasible.

The frequency of inspections will be once every 10 years, consistent with ASME Section XI, Subsection IWC, requirements for comparable Class 2 components.

Acceptance criteria will be in accordance with the Class 2 acceptance criteria of IWC-3000.

RATI 3.2-7:

LRA Table 3.2.2-1 identifies a plant specific In-service Inspection Program for managing the aging effect due to cracking and loss of material in stainless steel tanks in an internal sodium hydroxide environment. Neither this component nor the material and environment are evaluated in the GALL report. The applicant is requested to discuss its plant specific inspection methods including frequency of inspections and acceptance criteria. Also, identify the difference with the appropriate ASME XI requirements, if any, and provide justificationfor the same.

I&M Response to RAtI 3.2-7:

To manage cracking and loss of material of the stainless steel spray additive tanks, LRA Table 3.2.2-1 and LRA Section B.1.18 identify an Augmented ISI Program that specifies volumetric inspection for portions of the containment spray system subject to a sodium hydroxide environment. Augmented inspections are specified for components that are outside the jurisdiction of ASME Section XI inspection requirements. Augmented inspections use the same non-destructive examination methods used for ASME Section XI inspections on Class 1, 2, or 3 components. The augmented inspections of the spray additive tanks will use ultrasonic techniques, where feasible. The frequency of inspections will be once every 10 years, consistent with ASME Section XI, Subsection IWC, requirements for comparable Class 2 components. Acceptance criteria will be in accordance with the Class 2 acceptance criteria of IWC-3000.

RAIT 3.2-8:

LRA Table 3.2.2-1 does not identify any aging effect requiring management for stainless steel tanks in a concrete environment. Are periodic thickness measurements taken specially at weld to AEP:NRC:4034-09 Page 10 locations and at the tank bottom, to ensure that the integrity of the tank is maintained? If so provide the frequency and method of inspections.

I&M Response to RAI 3.2-8:

The stainless steel tank exposed to a concrete (external) environment, as indicated in LRA Table 3.2.2-1, is the refueling water storage tank (TK-33), which is depicted on license renewal drawings LRA-1-5144 and LRA-2-5144 at location B4. The tank base is in contact with the concrete pad. The concrete pads are constructed in accordance with American Concrete Institute (ACI) specification 318-63, which results in high quality concrete free of contamination.

Therefore, loss of material is not an aging effect requiring management due to the inherent corrosion resistance of stainless steel, alkalinity of concrete, and lack of contamination. Since there are no aging effects requiring management for this external stainless steel surface, periodic thickness measurements are not required.

RAI 3.2-9:

LRA Tables 3.2.2-1, -2, and -3 do not list the material type for valve bodies. The applicant is-requested to identify the material type environment,,aging effect and management programs for these valve bodies.

I&M Response to RAI 3.2-9:

Valve bodies and the applicable materials, environments, aging effects requiring management, and aging management programs are included under the component type "Valve" identified in the LRA tables, including LRA Tables 3.2.2-1, 3.2.2-2, and 3.2.2-3.

RAI 3.2-10:

The GALL report recommends a plant-specific aging management program for loss of material due to general, pitting, and crevice corrosion and microbiologically induced corrosion (MIC) in carbon steel components exposed to lubricating oil that may be contaminated with water.

Similar aging effects (except general corrosion) are possible for copper alloy. The NRC staff considers a periodic inspection program appropriate to manage this aging effect. For the oil cooler shell in the emergency core cooling system (LRA Table 3.2.2-3) exposed to an oil environment, the applicant is requested to provide a periodic inspection program in addition to an oil analysis program for aging management for loss of material due to general (carbon steel),

pitting, and crevice corrosion and MIC, or provide justification for not managing this aging effect.

to AEP:NRC:4034-09 Page I I I&M Response to RAI 3.2-10:

Loss of material is not an aging effect requiring management for surfaces exposed to lubricating oil unless moisture or contaminants are present.

The Oil Analysis Program monitors and controls abnormal levels of contaminants (primarily water and particulates), thereby preserving an environment that is not conducive to loss of material, cracking, or fouling. This is consistent with the previously approved NRC Staff position documented in NUREG-1743, Safety Evaluation Report Related to the License Renewal of Arkansas Nuclear One, Unit 1, Section 3.3.1.4.7.

RAI 3.2-11:

LRA Table 3.2.2-3 states that the copper alloy oil cooler tubes for the pump in a cooling w'ater environment will be managedfor loss of material using the Water Chemistry Control Program.

For this material type and environment, the staff considers selective leaching to be an aging effect requiring management.

The applicant is requested whether selective leaching is considered to be an aging mechanism for the tubes. If so, describe the types of inspections used by' the applicant to detect selective leaching in the tubes.

I&M Response to RAI 3.2-11:

The copper alloy tubes identified in LRA Table 3.2.2-3 are part of small shell and tube heat exchangers that provide cooling for the oil lubricating the safety injection (SI) pump bearings and centrifugal charging pump (CCP) bearings and gear assemblies. Component cooling water is supplied through the heat exchanger tubes.

The component cooling water system is a closed-loop system treated with corrosion inhibitors.

Selective leaching was identified in the aging management review as one of the mechanisms that could result in the aging effect of loss of material for copper alloy internal surfaces. The Closed Cooling Water Chemistry Control Program includes preventive measures that manage loss of material, including that due to selective leaching, where applicable. The Chemistry One-Time Inspection Program will verify the effectiveness of the chemistry programs to manage the effects of aging such that components will perform their intended functions for the period of extended operation. In addition, these heat exchangers will be included in the Heat Exchanger Monitoring Program, which will inspect the heat exchangers for degradation using nondestructive examinations, such as eddy current inspections or visual inspections or, if appropriate, the heat exchangers will be replaced.

This combination of preventive measures and inspections are adequate to provide reasonable assurance that all aging effects, including selective leaching, will be managed and that the components will perform their pressure boundary intended function during the period of extended operation.

to AEP:NRC:4034-09 Page 12 RAI 3.2-12:

The GALL report recommends further evaluation of programs to manage the loss of material due to pitting and crevice corrosion to verify the effectiveness of the Water Chemistry Control Program. A one-time inspection of select components at susceptible locations is an acceptable method to determine whether an aging effect is occurring or is progressing very slowly so that the intended finction will be maintained during the period of extended operation. LRA Tables 3.2.2-1, 3.2.2.-2, and 3.2.2-3 list various carbon steel components in a treated water environment and stainless steel components in a borated water environment with the aging effect being loss of material. The aging management program for these components is the Water Chemistry Control Program but no one-time inspection program is identified in the Tables listed above. However a new plant specific Chemistry One-Time Inspection Program is discussed in LRA Appendix B, Page B-131. It is stated in the description of this program that it is comparable to the NUREG-1801,Section XI.M32, One-Time Inspection Program but less broad in scope than the NUREG-1801 program. The applicant is requested to clarify that the inspections and examinations performed within the scope of its new Chemistry One-Time.

Inspection Program will verify the effectiveness of the Chemistry Control Program in managing the aging effect of loss of material in the various carbon steel components in a treated water environment and stainless steel components in a borated water environment listed in LRA Tables 3.2.2-1, 3.2.2-2, and 3.2.2-3.

I&M Response to RAI 3.2-12:

NUREG-1801,SectionXI.M2, states, 'The Generic Aging Lessons Learned (GALL) report identifies those circumstances in which the water chemistry program is to be augmented to manage the effects of aging for license renewal... Accordingly, in certain cases as identified in the GALL report, verification of the effectiveness of the chemistry control program is undertaken to ensure that significant degradation is not occurring... As discussed in the GALL report for these specific cases, an acceptable verification program is a one-time inspection of selected components at susceptible locations in the system." NUREG-1801 does not identify stainless steel components in ESF systems as requiring augmentation of the water chemistry program.

Effectiveness of the chemistry control programs will be verified by the Chemistry One-Time Inspection Program, as described in LRA Section B.1.41.

Inspections and examinations performed under this program will verify the effectiveness of chemistry control programs in managing the aging effect of loss of material for carbon steel in a treated water environment and stainless steel in a borated water environment, as specified in NUREG-1801.

RAI 3.2-13:

LRA Table 3.2.2-3 list loss of material and erosion as an aging effects requiring management for theflow orificelelement, but does not list cracking. The staff considers cracking a possible aging to AEP:NRC:4034-09 Page 13 effect requiring management for flow orifice/elements. The applicant is requested to describe theflow orifice/element, their location in the system, and why cracking is not considered to be an aging effect requiring management.

I&M Response to RAI 3.2-13:

The restricting orifices and flow metering orifices in LRA Table 3.2.2-3 are shown at the following license renewal drawing locations:

Component Drawing / Location Description 1-LFI-260-OR LRA-1 -5142 / D9 North SI pump discharge metering orifice 1-IFI-261-OR LRA-1-5142 I E9 North SI pump mini-flow to refueling water storage tank metering orifice 1-IF-262-OR LRA-1-5142 / H9 South SI pump mini-flow to refueling water storage tank metering orifice 1-IFI-266-OR LRA-1-5142 / D8 South SI pump discharge metering orifice& IFI-310-OR LRA-1-5143 /F7 East RHR heat exchanger outlet metering orifice 1-IFI-320-OR LRA-1-5143 / F9 West RHR heat exchanger outlet metering orifice 1-RO-104N LRA-1-5142 / E9 North SI pump mini-flow to refueling water storage tank flow orifice 1-RO-104S LRA-1-5142 / H9 South SI pump mini-flow to refueling water storage tank flow orifice 1-RO-105E LRA-1-5129 I H7 East CCP mini-flow to reactor coolant pump seal water heat exchanger orifice 1-RO-105W LRA-1-5129 / F7 West CCP mini-flow to reactor coolant pump seal water heat exchanger orifice 1-RO-1 19E LRA-1-5129 /J7 East CCP discharge orifice to AEP:NRC:4034-09 Page 14 Component Drawing / Location Description 1-RO-119W LRA-1-5129 / G7 West CCP discharge orifice 1-RO-722 LRA-1-5142 / B9 North SI pump discharge header orifice 1-RO-723 LRA-1-5142 / B8 South SI pump discharge header orifice 2-IFI-260-OR LRA-2-5142 / D9 North SI pump discharge metering orifice 2-IFI-261-OR LRA-2-5142 / E8 North SI pump mini-flow to refueling water storage tank metering orifice 2-IFI-262-OR LRA-2-5142 / H9 South SI pump mini-flow to refueling water storage tank metering orifice 2-IFI-266-OR LRA-2-5142 / D8 South SI pump discharge metering orifice 2-IFI-310-OR LRA-2-5143 / F7 East RHR heat exchanger outlet metering orifice 2-IFI-320-OR LRA-2-5143 I F9 West RHR heat exchanger outlet metering orifice 2-RO-104N LRA-2-5142 / E9 North SI pump mini-flow to refueling water storage tank flow orifice 2-RO-104S LRA-2-5142 / H9 South SI pump mini-flow to refueling water storage tank flow orifice 2-RO-105E LRA-2-5129 / H7 East CCP mini-flow to reactor coolant pump seal water heat exchanger orifice 2-RO-105W LRA-2-5129 / F7 West CCP mini-flow to reactor coolant pump seal water heat exchanger orifice 2-RO-722 LRA-2-5142 / B9 North SI pump discharge header orifice to AEP:NRC:4034-09 Page 15 Component Drawing / Location Description 2-RO-723 LRA-2-5142 / B8 South SI pump discharge header orifice 2-RO-739 LRA-2-5142 / F9 North SI pump discharge restricting orifice These stainless steel components are exposed to water with a temperature below the 140'F cracking threshold for intergranular attack or SCC.

Cracking from thermal fatigue is not applicable to these components because they are not exposed to the elevated temperatures that are required for this aging effect.

Therefore, cracking is not an aging effect requiring management for these components.

RAI 3.2-14:

t LRA Table 3.2.2-3 states that cracking in the pump casing with an internal stainless steel cladding, in a borated water environments, is managed by a plant specific preventive maintenance program. The applicant states that this cracking is not SCC but is a component specific cracking due to stress concentration. The applicant is requested to provide the folloiing information:.(a) the inspection frequency of these charging pumps including the bases

• thereof, (b) operating history of the pumps, and (c) whether or not a fatigue evaluation due to pressure cycling has been performed to nule out fatigue cracking as a factor. If so, provide that evaluation.

I&M Response to RAI 3.2-14:

(a) The current CCP inspection frequency is once every four fuel cycles.

The inspection frequency was based upon the stress analysis and the corrosion rates of carbon steel subjected to boric acid, as described in NRC Information Notice (IN) 80-38, "Cracking in Charging Pump Casing Cladding," and based upon plant-specific inspection results, which are summarized in the following table:

Date Pump Results March 1992 2-PP-SOB No indications that required repairs were found July 1992 1-PP-50E Identified and repaired crack indications (1 inch to 8/2 inches in length) on discharge side.

August 1995 1-PP-SOW Identified and repaired crack indications on pump inboard and outboard ends.

to AEP:NRC:4034-09

. Page 16 Date Pump Results April 1996 2-PP-50W No indications that required repairs were found October 1999 2-PP-50E Identified and repaired a F4-inch long linear indication in the pump inlet nozzle.

August 2000 1-PP-50E Identified and repaired linear indications in the pump inboard and outboard nozzles.

January 2002 2-PP-SOW Identified and repaired two 1/4-inch long flaws in the pump inlet nozzle.

May 2002 1-PP-SOW No indications that required repairs were found May 2003 2-PP-SOW Identified and repaired four indications that reached, the carbon steel substrate under the cladding at the pump inlet nozzle.

(b) A review. of condition reports and inservice testing results since 1999 did not reveal any significant events related to operation of the CCPs. Significant events related to operation of the CCPs prior to 1999 are summarized below:

Licensee Event Report (LER) 50-315n7-18, dated May 3, 1977, reported that the Unit 1 west CCP failed due to a broken shaft. The rotating element was replaced and the pump returned to service. The failure was described as a clean break occurring under the eleventh stage impeller with indications that fatigue was the failure mechanism. The vendor traced the failure to a bad heat used in the manufacture of the shafts.

LER 50-315n7-20, dated June 1, 1977, reported that the Unit 1 east CCP shaft broke between the third and fourth stage impellers. The break appeared to be a fatigue failure. The vendor traced the failure to a bad heat used in the manufacture of the shafts.

LER 82-032/03L-0, dated May 3, 1982, reported that the Unit 2 east CCP was removed from service during the previous month to replace the mechanical seal.

LER 82-046/03L-0, dated July 6, 1982, reported that the Unit 1 east CCP was declared inoperable as a result of excessive vibration. The pump rotating assembly was replaced.

During repairs, pitting erosion/corrosion through the stainless steel cladding and into the carbon steel pump case was identified at the suction and discharge nozzles. The affected areas were ground out and repaired by welding.

to AEP:NRC:4034-09 Page 17 LER 83-090103L-0, dated September 20, 1983, reported that during an ECCS flow balance, the Unit 1 west CCP minimum flow was below the minimum allowable rate.

NRC inspection report 50-31583-14, dated October 5, 1983, documented that the pump rotating element was replaced.

LER 86-012-01, dated December 4, 1986, reported that, with the Unit 2 west CCP operating, attempts to balance system flow failed due to degraded performance of the pump. The pump rotating element was replaced.

LER 93-006-00, dated August 9, 1993, reported that the Unit 2 west CCP was declared inoperable due to high vibration. Upon disassembly of the rotor assembly, the pump shaft was found to be cracked. The pump rotor assembly was replaced with a rebuilt assembly.

(c) Fatigue evaluations for pressure cycling have not been performed, since cladding failure of the charging pump cladding is a defect caused by stress concentrations, as discussed in NRC IN 80-38, and is not a fatigue issue.

RAI 3.3.1-1:

v (1) LRA Table 3.3.13-Autxiliarn Systems - Item 3.3.1-18 Verify all FP underground piping and fittings are included in this item and have an aging management program (AMP) consistent with NUREG-1801.

(2) LRA Table 3.3.1 - Auxiliary Systems - Item 3.3.1-19 Verify if any dry sprinkler systems are included in this item and have an AMP consistent with NUREG-1801.

(3) LRA Table 3.3.1 - Auxiliary Systems - Item 3.3.1-21 Section XL.M27 of NUREG-1801, Vol. 2, does not omit review of aging affects for treated water systems. Many of the aging effect/mechanisms listed are likely to occur even if raw wvater is not used as a primary source. Clarify the discussion pointsfor this item.

(4) LRA Table 3.3.2 Fire Protection Systems - General Notes F, G, H, I, J, and 3 all dictate that a portion of the item is not covered in NUREG-1801, but no means of aging management evaluation is proposed. Provide description of intended AMP.

(5) LRA Table 3.3.2 Fire Protection Systems - General Hose valve stations are not specifically listed under any item in the summary of aging management. Provide item which covers all hose valve stations and verify compliance with Section XI.M27 of NUREG-1801.

to AEP:NRC:4034-09 Page 18 I&M Response to RAI 3.3.1-1:

For clarification, references to the Fire Protection Program in the "Aging Management Programs" column of LRA Table 3.3.2-7 and in the 'Discussion" column of LRA Table 3.3.1 refer to the overall Fire Protection Program, as described in LRA Section B. 1. 1 l. This overall Fire Protection Program consists of the Fire Protection Program (LRA Section B. 1. 1 1. 1) and the Fire Water System Program (LRA Section B. 1.11.2), which are not differentiated in these tables.

(1) LRA Table 3.3.1 - Auxiliary Systems - Item 3.3.1-18 Underground fire water system piping and fittings are not included in this item.

Aging management review results for the fire water system, including the extent of consistency with NUREG-1801, are provided in LRA Table 3.3.2-7. Components that are compared with the items of LRA Table 3.3.1 are indicated by an entry in the "Table 1 Item"' column of LRA Table 3.3.2-7. Loss of material in buried fire water system piping and components is managed by the Fire Water System Program, which, with the inclusion of enhancements, will be consistent with, but include exceptions to, NUREG-1801,Section XI.M27.

(2) LRA Table 3.3.1 - Auxiliary Systems - Item 3.3.1-19 Dry sprinkler systems are not included-in this item. Aging management review results for the fire protection system, including the extent of consistency with NUREG-1801, are provided in LRA Table 3.3.2-7. Components included in Table 3.3.1 are indicated by. an entry in the 'Table 1 Item" column of LRA Table 3.3.2-7. Fire water piping with an internal air environment (i.e., dry sprinkler piping) is included under Item 3.3.1-5 of LRA Table 3.3.1. Loss of material in dry sprinkler piping and components is managed by the Fire Water System Program, which, with the inclusion of enhancements, will be consistent with, but include exceptions to, NUREG-1801, SectionXI.M27.

(A discussion of the Fire Water System Program enhancements and exceptions to NUREG-1801,Section XI.M27, is provided in LRA Section B. 1.11.2.) In LRA Table 3.3.2-7, aluminum and copper alloy dry pipe sprinkler heads identified as component type "Spray nozzles" that are exposed to air internally and externally have no aging effects due to the inherent corrosion resistance of these materials in air.

(3) LRA Table 3.3.1 - Auxiliary Systems - Item 3.3.1-21 LRA Table 3.3.1 - Item 3.3.1-21 provides a comparison of how the CNP aging management review results align to Table 3 of NUREG-1801, Volume 1 on page 23. These items refer to Items VII.G.6-a and VII.G.6-b in NUREG-1801, Volume 2 on page VII G-5, which apply to water-based fire protection system components containing raw water. The CNP fire water system uses treated water rather than raw water. Although LRA Table 3.3.1 - Item 3.3.1-21 is not applicable to CNP, fire water system components with an internal treated water environment were subject to aging management review.

LRA Table 3.3.2-7 lists aging to AEP:NRC:4034-09 Page 19 effects and applicable aging management programs for the fire water system components requiring aging management.

(4) LRA Table 3.3.2 Fire Protection Systems - General As described in Item 9 on LRA page 3.0-5, Notes in Table 3.3.2-7 describe the degree of consistency with the line items in NUREG-1801, Volume 2, and do not exclude components from aging management review. Individual component aging effects and associated aging management programs credited for aging management are identified in the "Aging Management Programs" column of Table 3.3.2-7.

(5) LRA Table 3.3.2 Fire Protection Systems - General As.indicated on license renewal drawings LRA-1-5152B and LRA-2-5152C, hose valve stations are comprised of valves, piping, and fittings. Components of hose valve stations subject to aging management review are included in component types "Fittings," "Piping,"

and "Valve" identified in LRA Table 3.3.2-7.

The aging effects associated with the treated water internal environment for component types "Fittings," "Piping," and "Valve" identified in LRA Table 3.3.2-7 are managed by the Fire Protection Program.

As described in ;LRA Section B.1.11.2, with the inclusion of enhancements, the Fire Water System Program will be consistent with, but include exceptions

-to, the program described in NUREG-1801,Section XI.M27.

LRA Section B. 1. 11.2 describes and justifies those exceptions.

RAI 3.3.1-2:

(1) LRA Drawing LRA-1-SSA. LRA-2-5151A. LRA-1-SS1C. and LRA-2-SSJC Location L-5 shows a 1%12" vent line from the dieselffuel oil day tank through aflame arrester to the room. These drawings do not show the vent line and the flame arrester as being subject to an AMR. However, it appears that the intendedfunction of theflame arrester is to ensure that vented gas will not lead to afire. This intended function meets the criteria for 10 CFR 54.4(a)(3). Justify the exclusion of the flame arrester and vent line from being within the scope of license renewal and subject to an AMR in accordance with the requirements of 10 CFR 54.4(a)(3) andfor 10 CFR 54.21(a)(1).

(2) LRA Drawing LRA-1-5151A. LRA-2-5151A. LRA-1-5151C. and LRA-2-SS1C A 2" overflow line at location L6 is shown as excludedfrom being subject to an AMR. Justify the exclusion of this overflow line from being within scope of license renewal and subject to an AMR in accordance with the requirements of 10 CFR 54.4(a)(3) and for 10 CFR 54.21(a)(1).

to AEP:NRC:4034-09 Page 20 I&M Response to RAI 3.3.1-2:

The flame arrestor was conservatively installed on the diesel fuel oil tank vent line, but has no required intended function. It is not required to support operation of the diesel engines and performs no function that demonstrates compliance with the commission's regulations for fire protection or other regulated events. The flashpoint for diesel fuel is sufficiently high such that the flame arrestor is not required by National Fire Protection Association (NFPA) Standard NFPA 30 and has no 10 CFR 50.48 function. The overflow line directs fuel oil to a sump if the tank is overfilled. The vent line, flame arrestor, and overflow line on the diesel fuel oil day tank are nonsafety-related and do not perform a pressure boundary function since they are located above the fuel oil level in the tank and their failure would have no impact on the ability of an emergency diesel generator to perform its intended functions. Therefore, the vent line, flame arrestor, and overflow line on the diesel fuel oil day tanks do not have a license renewal intended function and are not subject to aging management review based on the criteria of 10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(3).

RAI 3.3.2.1.11-3:

LRA Table 3.3.2-11 identifies the System Walkdown Program as managing loss of material, cracking, and change in material properties for the internals of various components such as condenser shell, evaporator housing, filter housing, flex hose, heat exchanger shell, heater coil, heater housing, manifold piping,. orifice, piping, pump casing, strainer housing, tank, thenmowell, trap, tubing, valve, and ventilation unit housing. The System Walkdown Program perfonns inspections on accessible surfaces during walkdowns.

Explain how the System WValkdown Program will detect loss of material on the internal surfaces of these components.

I&M Response to RAI 3.3.2.1.11-3:

The System Walkdown Program, as described in LRA Section B.1.38, manages aging through visual inspections of systems and components. These inspections will detect loss of material on the internal surfaces of these components by observing for evidence of leakage on the external surfaces of the components. For those components where the System Walkdown Program is credited as the aging management program for the internal surfaces, the concern is the impact of spray or leakage from nonsafety-related components on safety-related equipment. By managing the aging effects of nonsafety-related component failures on safety-related equipment, safety-related equipment will continue to be able to perform required intended functions.

The System Walkdown Program, as described in LRA Section B.1.38, manages aging through visual inspections of systems and components.

The System Walkdown Program includes periodic walkdowns that will detect and correct failures that could result in long-term exposure to spray or wetting. Short-term exposure is not a concern for passive components such as valve bodies and piping. Active safety-related component failures due to short-term exposure would to AEP:NRC:4034-09 Page 2 1 be detected in the course of normal operation or through monitoring required by the Maintenance Rule and appropriate corrective actions would be taken to prevent recurrence. This is consistent with the NRC's position provided in the Statements of Consideration for the Final Part 54 Rule, which states "On the basis of consideration of the effectiveness of existing programs which monitor the performance and condition of systems, structures, and components that perform active functions, the Commission concludes that structures and components associated only with active functions can be generically excluded from a license renewal aging management review.

Functional degradation resulting from the effects of aging on active functions is more readily determinable, and existing programs and requirements are expected to directly detect the effects of aging."

While this discussion pertains to detecting aging-related degradation of active components, it also applies to detecting degradation of the same active components due to aging-related degradation of nonsafety-related components.

Based on the information presented above, the System Walkdown Program is adequate as an aging management program for managing loss of material on the internal surfaces of components in LRA Table 3.3.2-11 because it includes periodic walkdowns that will detect and correct conditions that could result in failures caused by exposure to spray or wetting.

RAI 3.4-1:

LRA Table 3.4.2-3 identifies no aging effects for copper alloy in an outside environment. The outside environment is generally defined as: "An environment where component are exposed to direct sunlight, precipitation, and freezing conditions.

The outside environment also conservatively includes components located in sheltered areas where the component is beneath some type of roof structure or outdoor enclosure (such as a valve box) but is otherwise open to the ambient environment." T7is material is not identified for this environment in the GALL report. However, the GALL report recommends aging management for the loss of material due to general corrosion on the external surfaces of carbon (alloy) steel components exposed to operating temperatures less than 212 F, such corrosion may be due to air, moisture, or humidity. The applicant is requested to provide a program to manage corrosion on the external surface of copper alloy components in an outside environment or to provide justification for not managing this aging effect.

I&M Response to RAI 3.4-1:

The copper alloy components exposed to outdoor air in LRA Table 3.4.2-3 are instrument tubing, fittings, and valves off the condensate storage tank. Unlike carbon steel materials which are not corrosion resistant, copper alloys are highly resistant to general corrosion in an external air environment.

These copper alloy components are sheltered (either located inside or insulated) and are not directly exposed to the atmosphere. These components are not expected to be exposed to significant moisture or contaminants (such as those deposited as a result of to AEP:NRC:4034-09 Page 22 alternating wetting and drying); therefore, loss of material due to pitting, crevice corrosion, or selective leaching is not an aging effect requiring management.

RAI 3.4-2:

LRA Table 3.4-1, item 1, identifies the applicant's aging management for cumulative fatigue damage for piping and fittings in the main feedwater line, the steam line, and for AFW piping.

In the discussion column for this item, the LRA states, "see Section 4.3 [of the LRA]. "

It is stated in Section 4.3 of the LRA that based on a screening criteria, the applicant determined that the main feedwvater, main steam, AFW and blowdown systems exceed the screening criteria.

The piping components that exceed the screening criteria were evaluated by the applicant for their potential to exceed 7000 thermal cycles in sixty years of plant operation.

The applicant determined that none of the piping components in the steam and powver conversion system, mentioned earlier exceeded 7000 cycles during the period of extended operation. The applicant is requested to provide the highest estimated number of thermal cycles and the basis for derivation for each component type identified in Tables 3.4.2-1, -2, -3 and -4 of the LRA for which TLAA -Metal Fatigue has been designated as the aging management program. For certain components either whose material or aging effect is not specified in NUREG-1801(designated as 'F' and 'I' respectivelyin the notes), clarify whether or not the applicant performs the thermal cycle evaluation as described in NUREG-1801, Section 4.3.1.2.

If so, is the applicants TLAA program consistent with NUREG-1801. If not explain any differences. Also the applicant is requested to address how unanticipated transients and thermal stratification are accountedfor in the estimation.

I&M Response to RAI 3.4-2:

The evaluation of cracking by fatigue was identified as a TLAA for piping and valves in the main feedwater system, main steam system, auxiliary feedwater (AFW) system (i.e., steam supply to the AFW pump and exhaust) and blowdown system.

Mechanical components identified as susceptible to cracking by fatigue were designed in accordance with USAS B31.1.

Main feedwater system and main steam system thermal cycles anticipated over 60 years correspond to heatup and cooldown cycles, for which CNP is restricted to 200 cycles. Therefore, main feedwater and main steam piping and valves will not experience 7,000 cycles during the period of extended operation.

The steam supply to the AFW pump turbine and the turbine exhaust are exercised during AFW pump testing and during certain plant transients in which normal feedwater is unavailable.

Significantly fewer than 7,000 equivalent full-temperature cycles of these components are expected during the period of extended operation, because the plant is restricted to 400 reactor to AEP:NRC:4034-09 Page 23 trips and testing of the AFW pumps is performed on an 18-month cycle, in accordance with plant Technical Specifications.

The steam generator blowdown system is placed in service primarily during startup to obtain the required water -chemistry for normal operation.

The plant is restricted to 200 heatups and cooldowns; therefore, this system will not exceed 200 equivalent full-temperature cycles. After startup, the steam generator blowdown system is used when corrections are required for secondary water chemistry. Sample lines that are connected to the steam generator blowdown system are in service continuously when blowdown is being exercised. Through the period of extended operation, the system is not expected to exceed 5,000 full-temperature equivalent cycles to correct secondary water chemistry during normal operation (assuming two secondary water chemistry corrections per week for 60 years, with an 80 percent capacity factor).

Therefore, steam generator blowdown system will not experience 7,000 thermal cycles during the period of extended operation.

In the second part of this RAI, the NRC Staff requested a clarification of whether I&M performs the thermal cycle evaluation in accordance with NUREG-1801, Section 4.3.1.2. In a clarification to this RAI, the NRC Staff indicated that the referenced thermal cycle evaluation is addressed in Section 4.3.1:2 of NUREG-1800, not NUREG-1801. NUREG-1800, Section 4.3.1.2, "Generic Safety Issue," discusses the effects of reactor coolant environment on component fatigue life.

I&M's review of NUREG-1800 determined that the GSI discussion in Section 4.3.1.2, does not apply to the non-Class I portions of the steam and power conversion systems evaluated in LRA Section 3.2 because the scope of the GSI is limited to Class 1 locations identified in NUREG/CR-6260.

The thermal cycle evaluations discussed in this RAI response pertain to those performed for USASB3.1.1 piping, as discussed in NUREG-1800, Section4.3.1.1.2, "ANSI B31.1.'!

The thermal cycle assessment for USAS B31.1 piping, as described in NUREG-1800, Section 4.3.1.1.2, was performed for components that may operate at temperatures that exceed the screening criteria provided in LRA Section 4.3.2.

In addition to the 10 CFR 54.21(a) screening criteria, each mechanical system reviewed for the CNP IPA was also screened to identify potential metal fatigue TLAAs.

This was accomplished by identifying non-Class 1 components that may operate at temperatures in excess of 220'F for carbon steel or 270'F for austenitic stainless steel during normal or upset conditions. Fatigue evaluations of components that exceeded the screening criteria were identified as TLAAs for license renewal.

These screening criteria are consistent with the screening criteria described in Section 4.3.2 of the St. Lucie Units 1 and 2 LRA (Reference 1).

The threshold value of 220'F for thermal fatigue of carbon steel piping is based on an initial ambient temperature of 700F with a minimum temperature differential of 150IF. The threshold value of 270'F for thermal fatigue of stainless steel piping is based on an initial ambient temperature of 70'F with a minimum temperature differential of 200'F.

The minimum temperature differentials are based on industry-sponsored investigations and evaluations of to AEP:NRC:4034-09 PPage 24 thermal fatigue in nuclear plant piping systems, as presented in EPRI Report No. TR-104534 (Reference 2).

Thermal stratification in Class 1 portions of systems attached to the RCS is addressed in the I&M responses to NRC Bulletin 88-08, Thermal Stresses in Piping Connected to Reactor Coolant Systems (LRA References 4.3-11 through 4.3-15), as summarized in LRA Section 4.3.1.

UFSAR Section 4.1.4 describes cyclic load considerations. RCS components were designed to withstand the effects of cyclic loads due to reactor system temperature and pressure changes.

These cyclic loads are introduced by normal power changes, reactor trips, and startup and shutdown operations. The number of thermal and loading cycles used for design purposes are given in UFSAR Table 4.1-10. To provide a high degree of integrity for the equipment in the RCS, the transient conditions selected for equipment fatigue evaluation were based on a conservative estimate of the magnitude and frequency of the temperature and pressure transients resulting from normal operation, normal and abnormal load transients, and accident conditions.

To a large extent, the specific transient operating conditions considered for equipment fatigue analyses were based upon engineering judgment and experience.

The transients chosen are representative of transients which prudently should be considered to occur during plant operation and which are sufficiently severe or may occur frequently to be of possible significance to component cyclic behavior. Unanticipated transients are not accounted for in this methodology.

If they occur, they are identified and evaluated foriimpact on design thermal and loading cycles through the Corrective Action Progran.L References for RAI 3.4-2

1. License Renewal Application, St. Lucie Units 1 & 2, Section 4.3.2, ASME Boiler and Pressure Vessel Code,Section III, Class 2 and 3, and ANSI B31.1 Components

[ML0134003501.

2. EPRI Report No. TR-104534, "Fatigue Management Handbook," Volumes 1, 2 and 3, Research Project 3321, Revision 1, Electric Power Research Institute, December 1994.

RAI 3.4-3:

It is stated in Table 3.4.2-3 of the LRA that for stainless steel tanks in an external concrete environment there are no aging effects requiring management and also for this component and material there is no aging management program in NUREG-1801 for this environment. The applicant is requested to identify the specific tanks in the auxiliary feedivater system and discuss how the integrity of the welds and wall thickness in inaccessible locations in the tank is assured including method and frequency of inspections and their bases.

to AEP:NRC:4034-09 Page 25 I&M Response to RAI 3.4-3:

The stainless steel tank exposed to a concrete (external) environment, as indicated in LRA Table 3.4.2-3, is the condensate storage tank (TK-32), which is depicted on license renewal drawings LRA-1-5106A and LRA-2-5106A. The tank base is in contact with the concrete pad.

The concrete pads are constructed in accordance with ACI 318-63, which results in high-quality concrete free of contamination.

Therefore, loss of material is not an aging effect requiring management due to the inherent corrosion resistance of stainless steel, the high alkalinity of concrete, and the lack of contamination. Since there are no aging effects requiring management for this external stainless steel surface, periodic thickness measurements are not required.

RAI 3.4-4:

The AMP 1.2 Bolting and Torquing Activities, an existing plant specific programs is credited for managing loss of mechanical closure integrity. The program covers bolting in high temperature systems and in applications subject to significant vibration. The staff notes that NUREG-1801 recommends AMP XL.M 18, Bolting Integrity, for monitoring loss of material, cracking, and loss of preload. In addition, accepted bolting integrity programs (such as EPRI 104213) recommend monitoring for loss of preload as one of the parameters monitored/inspected. Monitoring for cracking of high strength bolts (actual yield strength equal or greater than 150 ksi) is also recommended.

As such, the applicant is requested to provide the following information:

1.

Identify the areas of the Bolting Integrity Program at D. C. Cook which are consistent with the AMP XL.M.18 in the GALL report, and also those aspects in which it is different.

2.

Discuss how the loss of preload aging effect would be managed by the Bolting and Torquing Activities AMP at D. C. Cook.

3.

Discuss the inspections associated with the Bolting and Torquing Activities AMP at D. C.

Cook which may be beyond the requirements ofASME Section XI.

4.

Are there any high strength bolts included within the boundary of these systems (Engineered Safety Features and Steam & Power Conversion Systems)?

5.

The occurrence of SCC in stainless steel bolts can depend on a combination offactors such as stainless steel grade, method of hardening (for example, strain, precipitation or age hardening) environment and stress levels. Discuss how these factors were taken into account to determine whether or not SCC is an applicable aging effect.

to AEP:NRC:4034-09 Page 26 I&M Response to RAI 3.4-4:

(a)

The Bolting and Torquing Activities Program is an existing plant-specific program that was not compared to NUREG-1801,Section XI.M 18.

The program described in NUREG-1801,Section XI.M18, covers all bolting within the scope of license renewal including safety-related bolting, bolting for nuclear steam supply system component supports, bolting for other pressure retaining components, and structural bolting.

It includes periodic inspection of closure bolting for many aging effects, including loss of preload, cracking, and loss of material. Cracking of non-Class 1 stainless steel bolting is not an aging effect requiring management (see response to paragraph (e) below) and loss of material is managed by other programs identified in LRA Appendix B, as indicated in LRA Section 3.0 tables. Thus, the plant-specific Bolting and Torquing Activities Program, used only to manage loss of mechanical closure integrity, is not comparable to ATP XI.M18 of NUREG-1801.

In LRA Section B.1.2, the ten attributes of the Bolting and Torquing Activities Program were provided to allow for its assessment independent of NUREG-1801,Section XI.M18.

t, (b)

Loss of preload is managed by the Bolting and Torquing Activities Program by assuring u.

that proper torque values are applied to bolted closures:;, With proper design of bolted r.

closures;, selection of appropriate torque values prevents loss of preload due to vibration or thermal cycles.

(c)

The Bolting and Torquing Activities Program is a preventive program. The associated inspections are a check of the bolt torque performed prior to joint assembly and verification of proper gasket compression after torquing.

(d)

CNP piping material specifications do not permit, nor have they historically permitted, high-strength bolting in non-Class 1 systems. Review of operating experience did not identify problems with cracking of high-strength bolting in air environments.

(e)

SCC occurs through the combination of high stress (both applied and residual tensile stresses), a corrosive environment, and a susceptible material. Proper lubricants and sealant compounds are used to minimize the potential for SCC.

The Bolting and Torquing Activities Program provides for selection of appropriate lubricants and sealants to preclude introduction of significant contaminants.

In the aging management reviews, sufficient stress to initiate SCC was assumed if stainless steel bolting was subject to a corrosive environment. However, SCC very rarely occurs in austenitic stainless steels below 140'F. Although SCC has been observed in stagnant, oxygenated borated water below 140'F, all of these instances have identified a significant contaminant (halogens, specifically chlorides) affecting the failed to AEP:NRC:4034-09 Page 27 components.

Since stainless steel bolted closures are exposed to ambient temperature rather than high temperature process fluids, cracking of non-Class 1 stainless steel bolting is not an aging effect requiring management.

RAI 3.4-5:

The applicant also does not identify any aging effect for stainless steel tube and tube fittings, valves (body only) in the reactor building environment. Provide justification for this omission.

If insignificant concentration of contaminants is part of the justification, provide the acceptance criterion and the verification/inspection activities on susceptible locations to justify your judgement.

I&M Response to RAI 3.4-5:

The environment is maintained below 1200F in the containment lower compartment and below 1000F in the containment upper compartment.

Stainless steel components are not susceptible to general corrosion in an air environment regardless of humidity level due to the inherent resistance of stainless steel to corrosion. Loss of material due to pitting or crevice corrosion requires a wetted environment (such as condensation (alternating wetting and drying which concentrates contaminants), pooling of liquid, or submergence) to be considered!an aging effect: requiring management.

The containment environment does not contain significant moisture such that.loss of material due to pitting and crevice corrosion is an aging effect requiring management for stainless steel components.

Stainless steel components that are subject to a wetted environment are included in the LRA aging management review results tables with an environment other than air (e.g., condensation, raw water, treated water). In addition, a review of plant operating experience identified no significant degradation of stainless steel components due to the containment environment.

RAI 3.4-6:

The applicant identifies no applicable aging effect for carbon steel components in an embedded environment. If this environment involves concrete, corrosion of carbon steel components embedded in concrete through carbonation etc., is commonly known degradation process. If there are no carbon steel components in an embedded environment in the steam and power conversion systems, then the applicant is requested to validate this statement.

I&M Response to RAI 3.4-6:

During scoping and screening of mechanical portions of the steam and power conversion systems, no carbon steel components in an embedded environment were identified as subject to aging management review. LRA Table 3.4.1, Items 3.4.1-11 and 3.4.1-12, document this result.

to AEP:NRC:4034-09 Page 28 Therefore, this material and environment combination is not identified in the aging management review results tables in LRA Section 3.4.

The only steam and power conversion systems mechanical component subject to an embedded environment is the stainless steel condensate storage tank, which is discussed in I&M's response to RAI 3.4-3. This tank is identified in LRA Section 3.4.2.1.3 as being exposed to concrete; is addressed in the Discussion column of LRATable 3.4.1, Item 3.4.1-11; and is included in LRA Table 3.4.2-3 as a stainless steel tank in a concrete environment.

RAI 3.4-7:

It is stated in Table 3.4.2-3 of the LRA that Oil analysis and Water Chemistry Control aging management programs will be utilized to manage fouling in heat exchanger with copper alloy tubes in lube oil and treated water environments to assure the heat transfer capability. The applicant is requested to explain how these two aging management programs will manage fouling and assure adequate heat transfer. The applicant is also requested to address whether any cleaning, visual inspections, and thermal performance testing would be performed including the frequency of such inspections and tests and the bases thereof I&M Response to RAI 3.4-7:

The heat exchangers in LRA Table 3.4.2-3 are the turbine-driven AFW pump turbine bearing lube oil cooler (HE-70) and governor oil cooler (HE-71), which are depicted on license renewal drawings LRA-1-5106A at locations L3 and M2 and LRA-2-5106A at locations D2 and E2. As part of the Primary and Secondary Water Chemistry Control Program, water quality and level of contaminants in the secondary plant water (i.e., AFW) are monitored and maintained within the specifications of EPRI TR-102134, Revision 5. The Oil Analysis Program monitors and controls abnormal levels of contaminants (primarily water and particulates), thereby preserving an environment that is not conducive to fouling. By maintaining proper water chemistry and oil quality, contaminants within these fluids are minimized such that fouling that could result in the loss of heat transfer function is prevented. Visual inspections and thermal performance testing are not included in these programs. However, the Chemistry One-Time Inspection Program, as described in LRA Section B.1.41, includes inspections to verify effectiveness of the chemistry control programs. Based on plant operating experience, there is reasonable assurance that the Oil Analysis Program and the Primary and Secondary Water Chem istry Control Program will continue to adequately manage fouling associated with components exposed to lubricating oil and secondary plant water so that the intended functions will be maintained consistent with the current licensing basis for the period of extended operation.

to AEP:NRC:4034-09 Page 29 RAI 3.4-8:

LRA Table 3.4.2-3 identifies loss of material andfouling for copper alloy heat exchanger tubes in treated water environment. The applicant credits the Water Chemistry Control Program to manage this aging effect. This material is not identified for this component in the GALL report, but the GALL report recommends Water Chemistry Control and a one-time inspection to manage loss of materialfor carbon/alloy steel components in a treated water environment. LRA Table 3.4.2-3 does not identify a one time inspection to verify the effectiveness of the Water Chemistry Control Program. However, a new plant specific one time inspection program is discussed in LRA, Appendix B (B.1.41). The applicant is requested to clarify that this program vill include inspections and examinations to verify the effectiveness of the Water Chemistry Control Program to manage loss of material andfouling for copper alloy heat exchanger tubes in treated water environment.

I&M Response to RAI 3.4-8:

The heat exchangers in LRA Table 3.4.2-3 are the turbine-driven AFW, pump turbine bearing lube oil cooler (HE-70) and the governor oil cooler (HE-71), which are depicted on license renewal drawings LRA-1-5106A at locations L3 and M2 and LRA-2-5106A at locations D2 and E2. Effectiveness of the water chemistry control programs will be verified by the Chemistry One-Time Inspection program as described in LRASection-B.1.41.

Inspections and t

examinations performed under the Chemistry One-Time Inspection Program will verify the effectiveness of the Primary and Secondary Water Chemistry Control Program in managing loss of material and fouling for copper alloy heat exchanger tubes in a treated water environment.

RAI 3.4-9:

LRA Table 3.4.2-3 states that Preventive Maintenance Program will manage change in material properties and cracking of elastomeric material of tanks in a treated water environment.

However, the Preventive Maintenance Program in Appendix B of the LRA does not provide any discussion of the aging management of pressure retaining elastomeric tanks in a treated water environment. Describe how the applicant will manage the change in material properties and cracking in tanks including inspection methods for inaccessible locations, frequency of inspections and acceptance criteria and the bases thereof.

I&M Response to RAI 3.4-9:

The elastomer material identified for the component type 'Tank" listing in LRA Table 3.4.2-3 refers to the condensate storage tank floating head seals. The floating head seals and associated support posts were included in the aging management review because the failure of these seals could cause flow blockage.

As stated in LRA Section B.1.25, the Preventive Maintenance Program will be enhanced prior to the period of extended operation to include visual inspection to AEP:NRC:4034-09 Page 30 and replacement, as needed, of these elastomer floating head seals. Inaccessible locations will be exposed to the same environments (i.e., air and treated water) as the accessible locations that will be subject to the visual inspections; therefore, the condition of the accessible surfaces of the elastomer seal would be representative of the inaccessible locations.

The seal inspection frequency will be established based on industry and plant-specific operating experience and manufacturer's recommendations. Acceptance criteria will be defined by specific inspection and testing procedures based on industry and plant-specific operating experience and manufacturer's recommendations.

RAI 3.4-10:

LRA Table 3.4.2-1, -2, -3, and -4 identify loss of material and cracking as an aging effect for various stainless steel components in treated water and steam environments. Th7e applicant credits the Water Chemistry Control Program to manage this aging effect. Stainless steels are susceptible to loss of material in this type of environment and the GALL report recommends that, for loss of material due to pitting and crevice corrosion, the effectiveness of the Water Chemistry Control Program should be verified to ensure that significant degradation is not occurring. The applicant is requested to confinn that the one-time inspection program discussed in LRA, Appendix B, will verify the effectiveness of the Water Chemistry Control Program for various stainless steel components'in treated water and steam environments.

4 a I&M Response to RAI 3.4-10:

NUREG-1801, SectionXI.M2, states, 'The Generic Aging Lessons Learned (GALL) report identifies those circumstances in which the water chemistry program is to. be augmented to manage the effects of aging for license renewal.... Accordingly, in certain cases as identified in the GALL report, verification of the effectiveness of the chemistry control program is undertaken to ensure that significant degradation is not occurring... As discussed in the GALL report for these specific cases, an acceptable verification program is a one-time inspection of selected components at susceptible locations in the systemn" For steam and power conversion systems stainless steel components, NUREG-1801 only recommends augmentation of the water chemistry program for the condensate storage tank and heat exchanger tubes. Confirmation of the water chemistry program effectiveness is not recommended for other stainless steel components.

Effectiveness of the water chemistry control programs will be verified by the Chemistry One-Time Inspection Program as described in LRA Section B.1.41.

Inspections and examinations performed under this program will verify the effectiveness of the chemistry control programs in managing the aging effects of loss of material and cracking for stainless steel in treated water and steam environments, as specified in NUREG-1801.

to AEP:NRC:4034-09 Page 31 RAI 3.4-11:

LRA Table 3.4.2-1 identifies loss of material as an aging effectfor alloy steel steam/fluid traps in a steam and treated water environment. The applicant credits the Water Chemistry Control Program to manage this aging effect. The GALL report recommends Water Chemistry Control and a one-time inspection to manage loss of material for carbon/alloy steel components in a treated water environment.

The applicant is requested to confirm that the new one-time inspection program discussed in LRA, Appendix B, will include inspections and examinations to verify the effectiveness of the Water Chemistry Control Program to manage loss of material for alloy steel steam/fluid traps in a steam and treated water environment.

I&M Response to RAI 3.4-11:

The component type 'Trap" is not identified in any aging management review results table for the steam and power conversion systems in LRA Section 3.4.

Effectiveness of the water chemistry control programs will be verified by the Chemistry One-Time Inspection program as described in LRA Section B.1.41.

Inspections and examinations performed under this program will verify the effectiveness.of chemistry control programs in managing loss of material for carbon/alloy steel in a steam and treated water environment.