ML13267A159

Response to NRC Request for Additional Information Regarding the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application, Set 11 (30-day), and Revised RAI Responses for B.1.14-1a, 2.5.

ML13267A159
Person / Time
Site:	Sequoyah
Issue date:	09/20/2013
From:	James Shea Tennessee Valley Authority
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
TAC MF0481, TAC MF0482
Download: ML13267A159 (54)

Text

Tennessee Valley Authority, 1101 Market Street, Chattanooga, Tennessee 37402 September 20, 2013 10 CFR Part 54 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 Sequoyah Nuclear Plant, Units 1 and 2 Facility Operating License Nos. DPR-77 and DPR-79 NRC Docket Nos. 50-327 and 50-328

Subject:

Response to NRC Request for Additional Information Regarding the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application, Set 11 (30-day), and Revised RAI Responses for B.1.14-1a, 2.5-2a, 2.3.4.3-5a, 2.3.3.15-la, B.1.41-3b (TAC Nos. MF0481 and MF0482)

References:

1. Letter to NRC, "Sequoyah Nuclear Plant, Units 1 and 2 License Renewal," dated January 7, 2013 (ADAMS Accession No. ML13024A004)

2. NRC Letter to TVA, "Requests for Additional Information for the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application (TAC Nos. MF0481 and MF0482) - Set 11," dated August 22, 2013 (ADAMS Accession No. ML13224A126)

3. Letter to NRC, "Response to NRC Request for Additional Information Regarding the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application, Sets 1, 6, 7, and Revised Responses for 1.4-2, 1.4-3 and 1.4-4 (TAC Nos. MF0481 and MF0482)," dated August 9, 2013 (ADAMS Accession No. ML13225A387)

4. Letter to NRC, "Response to NRC Request for Additional Information Regarding the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application, Set 4/Buried Piping, Set 8, and Set 9 (TAC Nos. MF0481 and MF0482)," dated July 25, 2013 (ADAMS Accession No. ML13213A026)

Printedon recycledpaper

U.S. Nuclear Regulatory Commission Page 2 September 20, 2013

5. Letter to NRC, "Response to NRC Request for Additional Information Regarding the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application, Set 10 (30-day), B.1.9-1, B.1.4-4 Revised RAI Responses, and Revision to LRA page 2.4-44 (TAC Nos. MF0481 and MF0482)," dated September 3, 2013 (ADAMS Accession No. ML13252A036)

By letter dated January 7, 2013 (Reference 1), Tennessee Valley Authority (TVA) submitted an application to the Nuclear Regulatory Commission (NRC) to renew the operating licenses for the Sequoyah Nuclear Plant (SQN), Units 1 and 2. The request would extend the licenses for an additional 20 years beyond the current expiration date.

By Reference 2, the NRC forwarded a request for additional information (RAI) labeled Set 11. The required date for responding was within 30 days of the date stated in the RAI (i.e., no later than September 23, 2013). Enclosure 1 provides the RAI responses.

In References 3, 4, and 5, TVA submitted responses that included RAIs B.1.14-1, 2.5-2, 2.3.4.3-5, 2.3.3.15-1, and B.1.41-3a. In an August 23, 2013 telecom, Mr. Richard Plasse, the NRC License Renewal Project Manager, requested clarification for these RAI responses. Enclosure 2 provides the requested clarification. is an updated list of the regulatory commitments for license renewal.

Consistent with the standards set forth in 10 CFR 50.92(c), TVA has determined that the additional information, as provided in this letter, does not affect the no significant hazards considerations associated with the proposed application previously provided in Reference 1.

Please address any questions regarding this submittal to Henry Lee at (423) 843-4104.

I declare under penalty of perjury that the foregoing is true and correct. Executed on this 20th day of September 2013.

Respe y, J W. hea ice resident, Nuclear Licensing nclosures:

1. TVA Responses to NRC Request for Additional Information: Set 1.1 (30-day)

2. Revised Responses for B.1.14-1a, 2.5-2a, 2.3.4.3-5a, 2.3.3.15-1a, and B.1.41-3b

3. Regulatory Commitment List, Revision 7 /

cc: See Page 3

U.S. Nuclear Regulatory Commission Page 3 September 20, 2013 cc (Enclosures):

NRC Regional Administrator- Region II NRC Senior Resident Inspector - Sequoyah Nuclear Plant

ENCLOSURE 1 Tennessee Valley Authority Sequoyah Nuclear Plant, Units I and 2 License Renewal TVA Responses to NRC Request for Additional Information: Set 11 (30-day)

ENCLOSUREI Tennessee Valley Authority Sequoyah Nuclear Plant, Units 1 and 2 License Renewal TVA Responses to NRC Request for Additional Information: Set 11 (30-day)

RAI 4.1-4a

Background:

By letter dated July 11, 2013, the applicantprovided its responses to RAI 4.1-4, Parts a. and b.

on whether the flaw analysis for the reactorcoolant pump (RCP)casings at Sequoyah Units I and 2 would need to be identified as a Time Limited Aging Analysis (TLAA) for the License Renewal Application (LRA) in accordance with 10 CFR 54.21(c)(1) TLAA identification requirements.

Issue:

To resolve the RAI request, the applicantmust demonstrate that the analysis does not conform to one or more of the six definition criteriathat are used to define a plant analysis as a TLAA, as given in 10 CFR 54.3(a). In its response to RAI 4.1-4, Parts a. and b., the applicantrelies on a future licensing basis change that the applicant claims will be done during the Periodof Extended Operation (PEO) and uses this future licensing basis change in the PEO as the sole basis for concluding that the supportingflaw tolerance analysis for the RCP casings does not need to be identified as a TLAA. This is not acceptable because the basis did not demonstrate why the stated analysis is not in conformance with all six definition criteriafor TLAAs in 10 CFR 54.3(a) or why the analysis would not need to be identified pursuantto the TLAA identification requirementin 10 CFR 54.21(c)(1) and the six criteriafor TLAAs in 10 CFR 54.3(a).

Request:

1. Clarify whether ASME Code Case N-481 and the supportingflaw tolerance evaluation for the RCP casings are being relied upon in the current licensing basis (CLB) as the basis for performing alternative visual examinations of the RCP casing welds, and if so, justify why the flaw tolerance analysis would not need to be identified as a TLAA for the LRA, as based on the CLB for the Sequoyah units at time of the LRA review. Respond to Part 2 of this request if this Code Case is still being relied upon for the CLB.

2. Clarify how the flaw tolerance evaluation addressedpotential drops in the fracture toughness property of the CASS RCP casing materialduring the PEO, and justify why the assessment of loss of fracture toughness in the evaluation would not need to be within the scope of a TLAA for the LRA.

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TVA Response to RAI 4.1-4a

1. Although ASME Code Case N-481 was credited in the Sequoyah Nuclear Plant (SQN) second Inservice Inspection. Interval (ISI), both SQN Units 1 and 2 are now in the third ISI inspection interval.

ASME Code Case N-481 is not credited in the third interval for SQN Units 1 or 2. ASME Code Case N-481 and the supporting flaw tolerance evaluation for the reactor coolant pump (RCP) casings are not relied upon in the current licensing basis (CLB) as the basis for performing alternative visual examinations of the RCP casing welds. The CLB for the current ISI inspection interval for both SQN Units 1 and 2 is the 2001 Edition, 2003 Addenda of the ASME B&PV Code, Section Xl.

2. Because ASME Code Case N-481 is not credited in SQN's third ISI inspection interval, the supporting flaw tolerance evaluation for the RCP casings is not contained in the CLB and is not relied upon in making a safety determination.

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RAI 4.1-6a

Background:

By letter dated July 11, 2013, the applicant provided its responses to RAI 4.1-6, Part a., on whether the flaw for the boric acid injection tank (BIT) at Unit 2 would need to be identified as a TLAA for the LRA in accordancewith 10 CFR 54.21(c)(1) TLAA identification requirements.

Issue:

The staff has determined that the applicant'sresponse demonstratesthat the flaw evaluation for the Unit 2 BIT does not need to be identified as a TLAA because the analysis: (a) does not involve time-dependent assumptions defined by the current operatingterm, and (b) does not conform to the definition of a TLAA in 10 CFR 54.3(a). However, the staff noted that the applicant does not identify cracking as an aging effect requiringmanagement for the BIT in LRA Table 3.3.2-1 [Sic, 3.2.2-1], and does not specifically credit augmented inspections under the applicant's Inservice Inspection (ISI) Program(LRA AMP B. 1.16) to manage cracking that was detected in the Unit 2 BIT.

Request:

Identify the mechanism that initiatedthe flaw in the BIT bottom head-to-shell weld and identify whether this mechanism was age-related.

In addition, clarify whether the flaw in the BIT bottom head-to-shell weld could grow by an age-related growth mechanism, such as cyclical loading or one of the stress corrosioncracking mechanisms, regardlessof the cause for initiation of the flaw in the BIT bottom head-to-lower shell weld.

Justify why cracking (including crack growth) has not been listed in LRA Table 3.3.2-1 [Sic, 3.2.2-1] as an aging effect requiringmanagement for welds in the BIT and why the applicant's ISI Program(LRA AMP B. 1.17) has not been credited to manage cracking in the BITs.

TVA Response to RAI 4.1-6a The BIT is a carbon steel tank, clad on the internal surface with stainless steel. As documented in the SQN corrective action program, the flaw that was identified by the site inspection is located at the cladding to base metal interface, 2.1 inches below the exterior surface.

Therefore, it is not exposed to the internal or external environments. Although a root cause analysis was not performed to determine the cause of the flaw, TVA assessed that the flaw was most likely manufacturing-induced and not age-related based on the location of the flaw.

Two augmented inspections have been performed that have identified no flaw growth.

The subsequent crack growth analysis was performed as required by ASME Section Xl for flaws that are detected during inspections. A carbon steel material exposed to temperatures below the fatigue threshold does not have an aging effect of cracking that requires management, so there is no listing for cracking in LRA Table 3.2.2-1 (corrected number). The augmented inspection is specific to the location of the manufacturing-induced flaw. The ISI program augmented inspections of this flaw will continue during the period of extended operation (PEO).

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RAI 4.1-11a

Background:

By letter dated July 11, 2013, the applicantprovided its responses to RAI 4.1-11, which provided the applicant's basis on why the exemption for use of ASME Code Case N-514 as the basis for establishingthe temperature enable settings for the low temperature overpressure protection (L TOP) system does not need to be identified as an exemption for the LRA in accordance with the requirementsin 10 CFR 54.21(c)(2). In its response, the applicant stated that ASME Code Case N-514 has been incorporatedinto ASME Section X1, Appendix G, and therefore, this exemption will not be required when the pressure-temperaturelimits are updated for the PEO. The applicantstated that an LRA amendment is not needed with respect to identifying this exemption as an exemption that meets the requirements in 10 CFR 54.2 1(c)(2).

Issue:

The staff does not find the applicant'sresponse to RAI 4.1-11 to be acceptable because 10 CFR 54.21(c)(2) requiresregulatory exemptions to be identified in the LRA based on the CLB as it exists at the time of the NRC's LRA review, and not on future actions that may or may not be implemented during the period of extended operation. The regulation requires the applicant to identify any regulatoryexemption that was previously grantedunder the requirements of 10 CFR 50.12 and whose basis for the exemption was based on a TLAA. For each exemption that does need to be identified for the LRA, the rule requires the applicant to provide an evaluation in the LRA that justifies the continuation of the exemption during the period of extended operation.

The Pressure Temperature Limits Report (PTLR) and WCAP-15293 for Unit I and PTLR and WCAP-15321 for Unit 2 refer to ASME Code Case N-514 in relationship to establishing the enable temperature for the L TOP system in each unit. However, the CLB for each unit still containsan exemption to use ASME Code Case N-514 for the pressure lift setpoints and enable temperaturesof the plant L TOP systems. As such, the exemption to use Code Case N-514 may be based on a TLAA since the exemption allows the applicantto establish these setpoints based on a mathematical function of the limiting adjusted reference temperature (RTNDT value) for the reactor vessel beltline materials. Therefore, the staff needs furtherjustification why the exemption for use of ASME Code Case N-514 had not been identified as an exemption that meets the exemption identificationcriteriain 10 CFR 54.21(c)(2) and why this exemption has not been included in the LRA and dispositionedin accordance with the exemption requirements in 10 CFR 54.21(c)(2).

Request:

1. Clarify whether the exemption for use of ASME Code Case N-514 had been granted in accordance with the requirementsin 10 CFR 50.12.

2. Clarify whether the alternative bases in ASME Code Case N-514 were based on a TLAA andjustify your bases for concluding that either the stated exemption is either based on a TLAA or is not based on a TLAA.

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3. Based on your responses to Parts I and 2 of this RAI, justify why the exemption to use ASME Code Case N-514 for Units I and 2 would not need to be identified as an exemption for the LRA that meets the exemption identification requirementsin 10 CFR 54.21(c)(2).

TVA Response to RAI 4.1 -11a

Response

1. TVA confirms that the exemption for the use of ASME Code Case N-514 was granted in accordance with the requirements in 10 CFR 50.12. See NRC to TVA Letter "NRC Exemption for Use of ASME Code Case N-514," dated June 18, 1993.

2. ASME Code Case N-514 provides a method for establishing low temperature overpressure protection (LTOP) system setpoints based on pressure-temperature limit curves and the limiting adjusted reference temperature (RTNDT value) for the reactor vessel beltline materials. Therefore, the exemption to use the code case involves the TLAA that determines pressure-temperature limits and the limiting adjusted reference temperature (RTNDT value) for the reactor vessel beltline materials.

3. As identified in Regulatory Guide 1.147, ASME Code Case N-514 was annulled on April 19, 2002. To resolve the concerns identified in this RAI, the exemption to allow the use of ASME Code Case N-514 is identified in the below change to LRA Section 4.1.2.

Changes to LRA Section 4.1.2 follow with additions underlined and deletions lined through.

"4.1.2 Identification of Exemptions Exemptions for SQN were identified through a review of the UFSAR, the operating licenses, the Technical Specifications, the NRC SERs, ASME Section Xl Program documentation, fire protection documents, NRC Agencywide Documents Access and Management System (ADAMS) database, and docketed correspondence. N1e oXoMptionS that Aill remaine in eaffect1 for tho period -ofextenAd-ed operation are- based on T-AA - One exemption has been identified that involves a TLAA. ASME Code Case N-514 provides a method for establishing LTOP system setpoints based on pressure-temperature limit curves and the limiting adiusted reference temperature (RTNDT value) for the reactor vessel beltline materials. For further information on how the LTOP system setpoint TLAA is evaluated, see LRA Section 4.2.5.

See NRC to TVA Letter "NRC Exemption for Use of ASME Code Case N-514," dated June 18, 1993."

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RAI 4.6-1

Background:

Per SRP-LR Section 4.6.1.1.1 for a TLAA to be dispositionedin accordance with 10 CFR 54.21(c)(1)(i), the existing analyses must be verified to be valid and bounding for the period of extended operation. SRP-LR Section 4.6.3. 1.1 states that the existing analyses should be shown to be bounding even during the PEO.

LRA section 4.6 states "Analyses were identified for bellows assemblies for the penetrations that stated they were qualified for 7000 cycles of the design displacements. The number of design displacements expected to occur from either thermal changes or containment pressurizationsis much less than 7000. Therefore, the associatedpenetrationsbellows are qualified for the PEO. The analysis remains valid for the PEO in accordancewith 10 CFR 54.21(c)(1)(i)."

Issues:

The staff reviewed the SQN UFSAR and was not able to find and verify the analyses used to estimate the number of displacements for bellows assemblies of the penetrationsexpected to occur from thermal changes or containmentpressurizationsand project those analyses to the end of the PEO.

Requests:

To ensure "the estimated number of cycles" are within "the qualifying limit of 7000 cycles,"

describe how the qualifying limit of 7000 cycles was determined, and provide the estimated number of cycles due to cyclic loading conditions (e.g., thermal, pressure,etc.) for the containment penetrationbellows at the end of PEO.

TVA Response to RAI 4.6-1 The qualifying limit of 7000 cycles was a conservative assumption to bound the expected number of operating cycles with ample margin. Although the original containment penetration flued heads and bellows did not have a specific fatigue analysis, analyses were identified for replaced or repaired penetration bellows assemblies at penetrations 13C, 24, and 30. The analyses confirmed that these penetrations were qualified for 7000 cycles of the design displacements.

Penetration 13C is the 32" main steam discharge line from steam generator #3. Displacements of its bellows will occur due to the steam line and containment temperature increasing during plant heatups.

Penetrations 24 and 30 have bellows attached to the penetration sleeve to allow differential expansion between the containment vessel and the shield building. Displacements of the bellows for these penetrations will occur due to containment temperature increasing during plant heatups.

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Also, the bellows will be displaced by loading experienced during containment integrated leak rate testing (CILRT). Therefore, the number of cycles expected for penetrations 13C, 24 and 30 are calculated as follows using a 50% margin:

(200 heat ups + 40 CILRT) x (1.5 (50% margin)) = 360 cycles.

Note that the value of 200 heat ups is from SQN FSAR Table 5.2.1-1.

The expected number of cycles, i.e., 360, is well below the 7000 cycles for which these bellows are qualified.

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RAI B. 1.40-la Backgqround:

Based on its audit of the applicant'sprogram basis document for the Structures Monitoring Program,it is not clear that the preventive actions for storage, lubricants, and corrosionpotential discussedin Section 2 of the RCSC publication "Specificationfor StructuralJoints Using ASTM A325 or A490 Bolts," will be used consistent with the recommendations in the GALL Report.

Issue:

The applicant's response to RAI B. 1.40-1 dated July 1, 2013 states that the Structures Monitoring Program employs the preventive actions for storage, lubricants,and corrosion potential. The program basis document stated that the preventive actions of Section 2 of Research Council for Structural Connections publication "Specification for StructuralJoint Using ASTM A325 and A490 bolts" have been considered in existing plant procedures for ASTM A325 and A490 bolting. However, during its audit, the staff found that the existing proceduresprovided as part of the program basis document for the Structures Monitoring Program did not include the preventive actions for storage, lubricantsand corrosionpotential.

The staff has not been provided with sufficient information to verify that the preventive actions program element of the Structures Monitoring Programis consistent with the GALL Report, without enhancement or exception, as claimed by the applicant in the LRA.

Request:

1. Describe the preventive actions for storage, lubricants,and corrosionpotential employed by the Structures Monitoring Program.

2. If the procedures describingthese preventive actions were not referenced in the program basis document when audited,provide clarificationand make revisions to the LRA and UFSAR supplement as necessary based on the response to #1.

TVA Response to RAI B.1.40-1a

1. The preventive actions for storage, lubricant, and corrosion employed in the Structures Monitoring Program (SMP) are described in SQN procedures G29B-SO1, 4.M.1.1, Section 3.9.2; G29B-SO1, 4.M.4.4, Section 4.2; and NPG-SPP-04.3. They include provisions for storage, handling, and preserving safety-related and quality-related materials, including ASTM A325 and A490 bolting. Consistent with the recommendations of section 2.2 of the Research Council for Structural Connections publication, "Specificationfor StructuralJoints Using ASTM A325 or A490 Bolts," these procedures provide for protected storage of bolts, nuts, washers and other fastener components to ensure their conditions are maintained as near as possible to the as-manufactured conditions, including the manufacturer-applied coatings or lubricants, until they are installed. These procedures include provisions for storing the fastener components in containers for protection from dirt and corrosion. The fasteners in the containers are within a protected compartment and are removed from protected storage only as necessary. Procedures specify promptly returning unused fastener components E 8of17

to protected storage. In summary, the fastener components are received, stored, and handled so as to minimize the possibility of corrosion, contamination, entrance of foreign materials, deterioration, or physical damage.

2. The procedures describing these preventive actions are not clearly identified in the SMP program basis document. However, as described in the response to RAI B.1.40-1a(1) above, the SMP follows the recommendations of the RCSC publication preventive actions for storage, lubricant, and corrosion potential. For clarification, TVA will revise the SMP procedures to explicitly include these preventive actions in Commitment 31.L.

The changes to LRA Sections A.1.40 and B.1.40 follow with additions underlined.

"A.1.40 Structures Monitoring Program

_ Revise Structures Monitorinq Program procedures to include the following preventive actions.

• Specify protected storage requirements for high-strength fastener components (specifically ASTM A325 and A490 bolting.) Storage of these fastener components shall include: (1) maintaining fastener components in closed containers to protect from dirt and corrosion: (2) storage of the closed containers in a protected shelter: (3) removal of fastener components from protected storage only as necessary: and (4) prompt return of any unused fastener components to protected storage.

B.1.40 Structures Monitoring Enhancements: The following enhancements will be implemented prior to the PEO.

Elements Affected Enhancements

2. Preventive Actions Specify protected storage requirements for high-strength fastener components (specifically ASTM A325 and A490 bolting). Storage of these fastener components shall include: (1) maintaining fastener components in closed containers to protect from dirt and corrosion: (2) storage of the closed containers in a protected shelter; (3) removal of fastener components from protected storage only as necessary: and (4) prompt return of any unused fastener components to protected storage."

Commitment 31.L has been added as shown in the above with additions underlined.

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RAI 3.1.2-4-1a

Background:

By letter dated July 29, 2013, the applicant responded to RAI 3.1.2-4-1, and stated that reduction of heat transfer is not an aging effect requiring management for steam generator tubes.

Issue:

The staff considers reduction of heat transferin steam generatortubes to be an applicable aging effect requiringmanagement. The staff notes that heat transferis the intended function for the steam generatortubes, and without propermanagement, the intended function could be compromised.

Request:

Discuss how reduction of heat transfer will be managed for steam generatortubes. Revise the LRA as necessary, consistent with the response.

TVA Response to RAI 3.1.2-4-1a The Water Chemistry Control - Primary and Secondary Program will manage reduction of heat transfer (fouling) for the steam generator tubes.

The change to LRA Section 3.1.2.1.4 follows with additions underlined.

Aging Effects Requiring Management The following aging effects associated with the steam generators require management.

• Cracking

" Cracking - fatigue

" Fouling

• Loss of material

• Loss of material - wear

" Loss of preload The change to LRA Table 3.1.2-4 follows with additions underlined.

Table 3.1.2-4: Steam Generators Aging Effect Aging NUREG Table Component tntended Material Environment Requiring Management -1801 Table Notes Type Function Management Program Item 1 Item Water Chemistry Heat Nickel Treated Tubes transfer alloy water (ext) Fouling Neae Control Primary -and H Secondary NlneP, E 10 of 17

RAI 3.5.2.2.1.3-01

Background:

In LRA Table 3.5.1, item 3.5.1-5, the applicant states that it will manage steel elements of inaccessibleareas of containments for loss of materialdue to general,pitting, and crevice corrosion in accordancewith the GALL Report recommendations. The GALL Report states that additionalplant-specific activities are warrantedif loss of material due to corrosion is significant for inaccessible areas. According to the GALL Report, corrosion is not significant if the following four conditions are satisfied:

1. The concrete that is in contact with the embedded containment steel met the requirements of ACI 318 or 349 or use the guidance of ACI 201.2R,

2. The moisture barrierat the junction where the steel becomes embedded in concrete is subject to aging management activities in accordance with ASME Section XI, Subsection IWE requirements,

3. The concrete is monitored to ensure that it is free of penetrating cracks that provide a path for water seepage to the surface of the containmentshell,

4. Borated water spills and water ponding are cleaned up or diverted to a sump in a timely manner.

SRP-LR Section 3.5.2.2.1.3, which addresses loss of materialdue to general, pitting, and crevice corrosion for steel elements of accessible and inaccessibleareas of containments, recommends further evaluation if the four GALL Report conditions cannot be satisfied.

Issue:

LRA Section 3.5.2.2.1.3 contains the applicant'sfurther evaluation discussion that considers loss of materialdue to general, pitting, and crevice corrosion. The staff reviewed Section 3.5.2.2.1.3 and noted that it lacked information demonstratingthat the GALL Report recommendations were satisfied. The staff noted that the applicantdid not discuss condition four related to borated water spills and water ponding.

Request:

Discuss plant-specific operating experience related to water ponding on the containment concrete floor, including frequency and resulting corrective actions.

TVA Response to RAI 3.5.2.2.1.3-01 A review of the SQN operating experience, documented in the site corrective action program (CAP), was performed to identify instances of water ponding (standing water) on the containment concrete floor. The search, covering the last ten years of plant operation, identified one occurrence of water ponding on the containment concrete floor in 2004. The visible water ponding on the floor was attributed to a clogged floor drain. Corrective action included clean-up of the water and unclogging the floor drain.

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Instances of water leakage from various systems have been noted during outage activities.

These conditions were investigated, evaluated, and corrected. A review was also performed of the operating experience associated with the Boric Acid Corrosion Program, Containment Inservice Inspection - IWE Program and the Structures Monitoring Program and there were no instances documented of water ponding on the containment concrete floor from these programs.

In addition to visually detecting water ponding (during refueling outages and reported through CAP), water leakage (including borated water) that could cause water ponding is monitored through system performance. System parameters are monitored and adverse operating conditions (including system leakage) are noted, investigated, and areas cleaned up promptly.

Additionally, the containment concrete floor slopes to floor drains minimizing locations where water could accumulate on the containment floor.

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RAI B.1.17-la Backgqround:

In its response of RAI B. 1.17-1 on July 1, 2013, the applicant stated "The configuration of the strainerallows leak off water to flow down the strainerand onto the essential raw cooling water (ERCW) strainersupport causing corrosion.Plannedcorrective actions include a design modification of the strainerto prevent ERCW support from being continuously exposed to water, thus mitigating corrosion. The modification proposed to install a "catchcontainer"to the ERCW strainerto route the leak off watercoming out of the top of the strainerto a floor drain." The LRA states "The program was developed in accordance with ASME Section X1, 2001 Edition through the 2003 Addenda as approvedby 10 CFR 50.55a. "Accordingly the ERCW strainer support components should satisfy the requirements Article IWF-3000, "Standardsfor Examination Evaluations," which may include examinations, corrective measures, evaluations, tests, etc., currently and during the period of extended operation. GALL Report AMP Xl. S3, in program element "acceptancecriteria,"refers to the acceptance standardsof IWF-3400, and states "otherunacceptable conditions include [Ijoss of materialdue to corrosionor wear, which reduces the load bearing capacity of the component support."

Issue:

In summary, the applicant will be implementing a corrective action of redirectingthe leaking water on the ERCW strainersupport components to a floor drain, thus mitigating corrosion. It is not clear how the corrosionprocess will be mitigatedby restrictingthe leaking water on the ERCW strainersupport components only, and is expected to perform its intended function during the period of extended operation.

Changingthe degradingenvironment to a benign environment may not alleviate the initiated corrosion process of carbon steel supports subject to stresses under operating conditions. The incubation-stageof corrosionprocess may have already been completed on some of the support components. Material-weakeningstage (cracking)of the carbon steel supports and their components and attachment welds may already have been initiatedwith an eventual outcome of a reducedload bearing capacity of the component support.It is not clear whether the LRA AMP In-service Inspection - IWF (ISI-IWF) Programwill follow the recommendationof the GALL Report AMP Xl. S3, program element "acceptancecriteria,"which is based on the requirements of ASME Code Section X1, Article IWF-3400 during the period of extended operation.

Request:

Provide the results of the evaluations of the ERCW strainersupport components per the requirements of ASME Code Section X1, Article IWF-3000 "Standardsfor Examination Evaluations."

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TVA Response to RAI B.1.17-1a The essential raw cooling water (ERCW) strainer (A-2A) support components are examined under the SQN Inservice Inspection (ISI)-IWF Program described in LRA Section B.1.17. The examination results are evaluated in accordance with ASME Code Section Xl, Article IWF-3000 following the acceptance standards of Article IWF-3400.

The condition of the ERCW strainer support components was evaluated during the last ISI examination performed in 2008 and subsequently re-evaluated under the TVA corrective action program in 2012. The evaluation performed concluded that the corrosion of the ERCW strainer support components was surface corrosion only and that the observed surface corrosion has insignificant effect on the ability of the ERCW strainer support to perform its intended function.

This conclusion is consistent with the evaluation documented in the 2008 ISI report that the corrosion on the ERCW strainer support is surface corrosion that does not affect the structural integrity of the support.

In addition, the 2012 SQN engineering review of the ERCW strainer support structural calculation concluded that there was no significant degradation attributable to the ERCW strainer support corrosion. The review of the support and its associated qualifying calculation determined that the support capacity for the ERCW strainer had not been degraded. As a result, compliance with IWF-3000, specifically the acceptance criteria of ASME Code Section XI, Article IWF-3400, "Acceptance Standards" was demonstrated.

The SQN ISI-IWF Program will continue to ensure the ERCW strainer support components are inspected and the results are evaluated per ASME Code Section Xl, Article IWF-3000 following the acceptance criteria of ASME Code Section Xl, Article IWF-3400. This provides reasonable assurance that the support will remain capable of performing its intended function during the PEO.

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RAI B.1.11-la

Background:

In its July 1, 2013, response to request for additionalinformation (RAI) B. 1.11-1, the applicant provided its clarification on whether specific transients listed in RAI B. 1.1.11-1 will be monitored as part of the Fatigue Monitoring program. The applicant stated the cycle limits of (1) 2, 000 cycles of "Step changes in letdown stream fluid temperature from IO0°F to 560°F"and (2) 24,000 cycles of "Step changes in letdown stream temperature from 400°F to 560°F"for the Chemical and Volume Control System (CVCS) regenerativeheat exchangers will not be monitored by the Fatigue Monitoring program.

The applicantalso stated that the 15 cycles of design tensioning cycle limit for the RCP hydraulic studs and nuts will not be monitored in the Fatigue Monitoringprogram. LRA Section 4.3.1.6 states the Fatigue Monitoring Program will manage the effects of aging due to fatigue on the RCP in accordance with 10 CFR 54.21(c)(1)(iii). The staff noted that the "parameters monitored/inspected"program element of GALL Report AMP X. M1, "FatigueMonitoring," states that the program monitors all plant design transients that cause cyclic strains, which are significant contributorsto the fatigue usage factor.

Issue:

In its justification for the two transients for the CVCS regenerativeheat exchangers, the applicant stated that the letdown fluid temperature normally remains stable for both units. The applicant further stated that a maximum of 90 cycles for each of the transients are expected through the period of extended operation. The staff is unclearon how the applicantcame to these conclusions. The applicantdid not explain how it determined that the letdown fluid temperature normally remains stable or how it can confirm that the temperature during the transientwill remain stable for the period of extended operation. The staff is unclearif the temperature stability is during normal operationor during the transient. Also, the applicant did not provide an explanation based on its plant configuration and operationalhistory to support its calculation that 90 cycles is expected for each transientthrough the period of extended operation.

In its justification,the applicantstated that the RCPs are rarely disassembledsuch that tensioning the studs and nuts is necessary. The applicant stated that only one RCP has installed hydraulicallytensioned studs in 2005, and the studs have not been disassembledsince its installation. The applicant used this basis to state that the 15 cycles of design tensioning cycle limit for the RCP hydraulic studs and nuts will not need to be monitored. However, the staff is unclearhow the Fatigue Monitoring Program,in accordancewith 10 CFR 54.21 (c)(1)(iii),

will manage the effects of aging due to fatigue on the RCPs if this transientis not monitored.

Request:

1. Confirm whether the letdown fluid temperature normally remains stable during normal operation or during the aforementionedtransients.

E 15of17

a. If the temperatureis stable during normal operation,justify how the temperature stability has any impact on fatigue usage accumulation during the transients- in lieu of a justification, monitor these transientsas part of the Fatigue Monitoring program.

b. If the temperatureis stable during these transients.

i. State the basis for the letdown fluid normally remaining stable during these transients at SQN Units 1 and 2.

ii. Describe what measures will be taken to ensure letdown fluid temperature will remain stable during these transients throughout the period of extended operation.

2. Describe how a maximum of 90 cycles for each of the aforementionedtransients was calculatedandjustify that the calculations are consistent with plant configuration and operationalhistory.

3. Describe andjustify the programmaticelements of the Fatigue Monitoring Programthat will manage the effects of aging due to fatigue on the RCPs, in accordancewith 10 CFR 54.21(c)(1)(iii), given that the 15 cycles of design tensioning cycle limit for the RCP hydraulic studs and nuts will not be monitored.

4. If the Fatigue Monitoring Program will not be used, justify how the effects of aging due to fatigue will be managed for the RCPs in accordancewith 10 CFR 54.21(c)(1)(iii). Revise the LRA as necessary.

TVA Response to RAI B.1.11-1a

1. The source of the letdown fluid to the regenerative heat exchanger is the reactor coolant loop 3 crossover leg that is at the cold leg temperature of approximately 545°F. The reactor coolant loop crossover leg and the letdown fluid temperatures remain within a narrow range during normal plant operation.

To confirm the stability of the CVCS regenerative heat exchanger letdown fluid temperature, two years of SQN temperature data for the regenerative heat exchanger inlet and outlet temperatures were reviewed for each unit. This data does not show frequent significant temperature transients such as the 2,000 cycles of "Step changes in letdown stream fluid temperature from 100°F to 560°F" or the 24,000 cycles of "Step changes in letdown stream temperature from 400°F to 560°F" that were conservatively assumed in the design analysis.

After initial heatup from refueling outages, one cycle approximating the 100°F to 560°F cycle was observed on both Units over the two year period and two cycles approximating the 400°F to 560°F cycle were observed on Unit 1 and five cycles approximating the 400°F to 560OF cycle were observed on Unit 2 over the two year period.

Based on the data reviewed, normal operating procedures do not result in a large number of transients such as those used in the fatigue assessment of the heat exchangers. No additional measures are necessary to limit temperature transients throughout the PEO.

E 16 of 17

2. The 90 cycles in the original RAI response was estimated by assuming three occurrences of each cycle every two years for 60 years of operation. As discussed above, a review of plant data has shown that the cycles that do occur are substantially fewer than the numbers of transients assumed in the fatigue analysis.

Additional details are provided below.

2,000 cycles (100 to 560'F): This represents a letdown temperature step change transient that was assumed to occur approximately one time per week during normal plant operation. The above-discussed observation of two years of SQN data from both Unit 1 and Unit 2 indicates that this transient seldom occurs during normal plant operation. TVA conservatively estimated the number of transients to be 1.5 per year for 60 years or 90 cycles.

The estimated number of cycles, 90, is far less than the 2,000 assumed cycles of a step change in temperature of this magnitude.

• 24,000 cycles (400 to 560'F): This represents a letdown temperature step change transient that was assumed to occur approximately two times per day during normal plant operation. The above-discussed observation of two years of plant data from both Unit 1 and Unit 2 indicates no more than five transients in temperature approximating a 160°F step change. Conservatively increasing the number of transients by a factor of two and applying this to each heatup and cooldown cycle (200) gives a predicted number of transients of 2,000.

The estimated number of cycles, 2000, is far less than the 24,000 assumed cycles of a step change in temperature of 160 0 F.

3. To resolve the concern in Request 3 of this RAI, the reactor coolant pump hydraulic stud tensioning cycles will be added to the tracked transients in the Fatigue Monitoring Program.

Changes to LRA Appendix A. 1. 11 and Appendix B. 1. 11 follow with additions underlined.

The change to LRA Appendix A.1.11 follows:

• Revise Fatigue Monitoring Program procedures to track the tensioning cycles for the reactor coolant Pump hydraulic studs.

The change to LRA Appendix B.1.11 follows:

Element Affected Enhancement

1. Scope of Revise Fatigque Monitoring Program procedures to track Program the tensioning cycles for the reactor coolant pump hydraulic studs.

4. The Fatigue Monitoring Program will be used as identified in the response to Request 3.

Commitment 7.E is added as shown above.

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ENCLOSURE 2 Tennessee Valley Authority Sequoyah Nuclear Plant, Units I and 2 License Renewal Revised Responses for B.1.14-1a, 2.5-2a, 2.3.4.3-5a, 2.3.3.15-1a, and B.I.41-3b

ENCLOSURE2 Tennessee Valley Authority Sequoyah Nuclear Plant, Units I and 2 License Renewal Revised Responses for B.1.14-1a, 2.5-2a, 2.3.4.3-5a, 2.3.3.15-la, and B.l.41-3b RAI B.l.14-1a NRC requested clarificationfor the response to RAI B.1.14-1.

The following response to RAI B.1.14-1a supersedes the response provided to the NRC on August 9, 2013, ADAMS No. ML13225A387, page 1 of 22 in Enclosure 3.

Note: Revisions are in italics and underlined. The majority of the revisions are inserted tables at the end of the revised B.1.14-1 response in Enclosure 2, pages 4 to 8.

Revised TVA Response to RAI B.1.14-1

1. The Flow-Accelerated Corrosion (FAC) Program will be consistent with the program described in NUREG-1801, AMP XI.M17 as revised by LR-ISG-2012-01.

2. The new program enhancement added to LRA Sections A.1.14 and B.1.14 includes a susceptibility review in accordance LR-ISG-2012-01. The susceptibility review is designed to identify the appropriate component types, materials and mechanisms associated with non-FAC erosion. Component types monitored for loss of material due to non-FAC erosion mechanisms are identified in the changes to LRA tables depicted below.

The change to LRA Section A.1.14 follows with additions underlined and deletions lined through.

"A.1.14 Flow-Accelerated Corrosion Program The Flow-Accelerated Corrosion (FAC) Program manages loss of material due to wall thinning caused by FAC for carbon steel piping and components by (a) performing an analysis to determine systems subject to FAC and internal and ekternal eFrocin, (b) conducting appropriate analysis to predict wall thinning, (c) performing wall thickness measurements based on wall thinning predictions, and (d) evaluating measurement results to determine the remaining service life and the need for replacement or repair of components. Measurement results are also used to confirm predictions and to plan long-term corrective action. The program relies on implementation of guidelines published by EPRI in NSAC-202L, Rev. 3, and internal and external operating experience. The program uses a predictive code for portions of susceptible systems with design and operating conditions that are amenable to computer modeling. Inspections are performed using ultrasonic or other approved testing techniques capable of determining wall thickness. Components predicted to reach the minimum allowed wall E2 -1 of 15

thickness before the next scheduled outage are isolated, repaired, replaced, or reevaluated under the corrective action program.

Where applicable, the FAC Program also manages loss of material due to erosion mechanisms of cavitation, flashing, liquid droplet impingement and solid particle erosion for any material in moving fluid environments.

The Flow-Accelerated Corrosion Program will be enhanced as follows.

" Revise Flow-Accelerated Corrosion Program procedures to implement NSAC-202L guidance for examination of components upstream of piping surfaces where significant wear is detected.

• Revise Flow-Accelerated Corrosion Program procedures to implement the guidance in LR-ISG-2012-01, which will include a susceptibility review based on internal operating experience, external operating experience, EPRI TR-1 011231, Recommendations for Controlling Cavitation, Flashing, Liquid Droplet Impingement.

and Solid Particle Erosion in Nuclear Power Plant Piping, and NUREG/CR-6031, Cavitation Guide for Control Valves."

The change to LRA Section B.1.14 follows with additions underlined and deletions lined through.

"B.1.14 Flow-Accelerated Corrosion Program Program Description The Flow-Accelerated Corrosion (FAC) Program manages loss of material due to wall thinning caused by FAC and erosion. The program manages loss of material due to wall thinning for carbon steel piping and components by (a) performing an analysis to determine systems subject to FAC and internal aind nerinal eFrc.in, (b) conducting appropriate analysis to predict wall thinning, (c) performing wall thickness measurements based on wall thinning predictions, and (d) evaluating measurement results to determine remaining service life and the need for replacement or repair of components. A representative sample of components is selected based on the most susceptible locations for wall thickness measurements at a frequency in accordance with NSAC-202L guidelines to ensure that degradation is identified and mitigated before the component integrity is challenged. Measurement results are used to confirm predictions and to plan long-term corrective action. In the event measurements of wall thinning exceed predictions, the extent of the wall thinning is determined as a part of the CAP.

The program relies on implementation of guidelines published by EPRI in NSAC-202L, Rev. 3, and internal and external operating experience. The program uses a predictive code for portions bf susceptible systems with design and operating conditions that are amenable to computer modeling. Inspections are performed using ultrasonic or other approved testing techniques capable of determining wall thickness. When field measurements show that the predictive code is not conservative, the model is recalibrated. The model is also adjusted as a result of any power up-rates.

E2 - 2 of 15

Components predicted to reach the minimum allowed wall thickness before the next scheduled outage are isolated, repaired, replaced, or reevaluated under the CAP.

Where applicable the FAC Program also manages loss of material due to erosion mechanisms of cavitation, flashing, liquid droplet impingement and solid particle erosion for any material in moving fluid environments.

NUREG-1801 Consistency: The FAC Program, with enhancements, is consistent with the program described in NUREG-1801,Section XI.M17, Flow-Accelerated Corrosion, as modified by LR-ISG-2012-01.

Exceptions to NUREG-1801: None" Enhancements: The following enhancements will be implemented prior to the period of extended operation.

Element Affected Enhancement

1. Scope of Program Revise FAC Program procedures to implement NSAC-202L guidance for examination of components upstream of piping surfaces where significant wear is detected.

1. Scope of Pro-gram Revise FAC Program procedures to implement the iguidance in LR-ISG-2012-01, which will include a

3. Parameters Monitored/Inspected susceptibility review based on internal operating

4. Detection of Aging Effects experience, external operating experience, EPRI TR-1011231, Recommendations for Controlling

5. Monitoringq and Trending Cavitation, Flashing, Liquid Droplet Impingement, and

7. Corrective Action Solid Particle Erosion in Nuclear Power Plant Piping.,

and NUREG/CR-6031, Cavitation Guide for Control Valves.

Commitment #10 has been revised.

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The changes to LRA Table 3.3.2-17-4, Raw Cooling Water System, Nonsafety-Related Components Affecting Safety-Related Systems, follow with additionsunderlined.

Component Intended Aging Effect Aging NUREG-cope Inten Materal Environment Requiring Management 1801 Item Table 1 Item Notes Type Function Management Program PiDin Pressure Carbon Raw water (int) Loss of materialdue Flow boundary steel to erosion Accelerated H Corrosion Pinin Pressure Coper Raw water (int) Loss of materialdue Flow boundary alloy to erosion Accelerated H Corrosion Pressure Stainless Raw water (int) Loss of materialdue Flow boundary steel to erosion Accelerated H Corrosion The changes to LRA Table 3.3.2-11, EssentialRaw Cooling Water Systems, follow with additionsunderlined.

Component Intended Aging Effect Aging NUREG-Material Environment Requiring Management 1801 Item Table 1 Item Notes Type Function Management Program Pi~in Pressure Carbon Raw water (int) Loss of material due Flow boundary steel to erosion Accelerated H Corrosion Pipin Pressure Nickel alloy Raw water (int) Loss of materialdue Flow boundary to erosion Accelerated H Corrosion Pinin Pressure Stainless Raw water (int) Loss of material due Flow boundary steel to erosion Accelerated H I I_ I I I Corrosion E2 - 4 of 15

The changes to LRA Table 3.3.2-17-25, EssentialRaw Cooling Water System, Nonsafety-Related Components Affecting Safety-Related Systems, follow with additionsunderlined.

Component Intended Aging Effect Aging NUREG-cope Inten Material Environment Requiring Management 1801 Item Table I Item Notes Type Function Management Program Piin Pressure Carbon Raw water (int) Loss of materialdue Flow boundary steel to erosion Accelerated H Corrosion BMW Pressure Stainless Raw water (int) Loss of materialdue Flow boundary steel to erosion Accelerated H 1 1 1_ 1 Corrosion The changes to LRA Table 3.3.2-2, High PressureFire Protection - Water System, follow with additions underlined.

The changes to LRA Table 3.3.2-17-6, High PressureFire ProtectionSystem, Nonsafety-Related Components affecting Safety-Related Systems, follow with additionsunderlined.

Component Intended Aging Effect Aging NUREG-TypeFu n Material Environment Requiring Management 1801 Item Table 1 Item Notes Type Function Management Program Piin Pressure Carbon Raw water (int) Loss of materialdue Flow boundary steel to erosion Accelerated H Corrosion E2 - 5 of 15

The changes to LRA Table 3.4.2-2, Main and Auxiliary FeedwaterSystem, follow with additions underlined.

Component Intended Aging Effect Aging NUREG-Material Environment Requiring Management 1801 Item Table 1 Item Notes Type Function Management Program Piin Pressure Aluminum Treated water Loss of materialdue Flow boundar*O int) to erosion Accelerated H Corrosion Pining Pressure Carbon Treated water Loss of materialdue Flow boundary steel (int) to erosion Accelerated H Corrosion Pinino Pressure Stainless Treated water Loss of materialdue Flow boundary steel (int) to erosion Accelerated H Corrosion The changes to LRA Table 3.4.2-3-3, Main andAuxiliary FeedwaterSystem, Nonsafety-Related Components affecting Safety-Related Systems, follow with additions underlined.

Component Intended Aging Effect Aging NUREG-Environment Requiring Management 1801 Item Table I Item Notes TypeMaterial Management Program Pressure Carbon Treatedwater Loss of material due Flow boundary steel ) to erosion Accelerated H I _ Corrosion Pressure Stainless Treated water Loss of materialdue Flow boundary steel >140°F(int) to erosion Accelerated H I_ Corrosion The changes to LRA Table 3.4.2-3-2, Condensate System, Nonsafety-Related Components affecting Safety-Related Systems, follow with additions underlined.

Component Intended Aging Effect Aging NUREG-TypeFu n Material Environment Requiring Management 1801 Item Table I Item Notes Type Function Management Program Pressure Carbon Treatedwater Loss of material due Flow boundary steel Ainta to erosion Accelerated H I_ I_ ICorrosion Pressure Stainless Treated water Loss of material due Flow boundary steel >140°F(int) to erosion Accelerated H I_ Corrosion E2 - 6 of 15

The changes to LRA Table 3.4.2-3-4, Extraction Steam System, Nonsafety-Related Components affecting Safety-Related Systems, follow with additions underlined.

Component Intended Aging Effect Aging NUREG-Environment Requiring Management 1801 Item Table I Item Notes TypeMateal Management Program P-ing Pressure Carbon Steam (int) Loss of materialdue Flow boundary steel to erosion Accelerated H Corrosion SPressure Stainless Steam (int) Loss of materialdue Flow boundary steel to erosion Accelerated H I_ I Corrosion The changes to LRA Table 3.4.2-3-5, HeaterDrains and Vents System, Nonsafety-Related Components affecting Safety-Related Systems, follow with additions underlined.

Component Intended Aging Effect Aging NUREG-Function Material Environment Requiring Management 1801 Item Table I Item Notes Type Management Program BýPi Pressure Carbonsteel Steam (int) Loss of material due Flow boundary to erosion Accelerated H Corrosion Pipin Pressure Carbon steel Treated water Loss of materialdue Flow boundary Aint) to erosion Accelerated H Corrosion Pipin Pressure Stainless Steam (int) Loss of materialdue Flow boundary steel to erosion Accelerated H I__II_ ,_Corrosion Pipin Pressure Stainless Treated water Loss of materialdue Flow boundary steel >140°F(int) to erosion Accelerated H Corrosion E2 - 7 of 15

The changes to LRA Table 3.4.2-3-9, Condenser CirculatingWater System, Nonsafety-Related Components affecting Safety-Related Systems, follow with additions underlined.

Component Intended. Aging Effect Aging NUREG-Material Environment Requiring Management 1801 item Table I Item Notes Type Function Management Program BiQ( Pressure Carbon Raw water (int) Loss of materialdue Flow boundary steel to erosion Accelerated H Corrosionn Pin Pressure Copper Raw water (int) Loss of material due Flow boundary Alloy >15% to erosion Accelerated ZN or >8% Corrosion H Al PiDin Pressure Stainless Raw water (int) Loss of materialdue Flow boundary steel to erosion Accelerated H Corrosion E2 - 8 of 15

RAI 2.5-2a NRC requested clarificationfor the responseto RAI 2.5-2.

The following response to RAI 2.5.2a supersedes the response provided to the NRC on July 25, 2013, ADAMS No. ML13213A026, page 18 of 65 in Enclosure 3. In particular, LRA Tables 2.5-1 and 3.6-2 have been revised and added to this response.

Note: Revisions are in italics with additions underlined and deletions lined through.

Revised TVA Response to RAI 2.5-2 10 CFR 54.4(b) states, "[t]he intended functions that these systems, structures, and components must be shown to fulfill in §54.21 are those functions that are the bases for including them within the scope of license renewal as specified in paragraphs (a)(1)-(3) of this section." LRA Section 2.5 identifies the commodity group "insulated cables and connections" as subject to aging management review because it fulfills the intended function "conducts electricity." LRA Tables 2.5.1 and 3.6-2 identify that the intended function for non-environmental qualification (EQ) electrical cables and connections (includes non-EQ electrical and instrumentation and control penetration conductors and connections), non-EQ electrical cables and connections used in instruments circuits, and fuse holders is to conduct electricity.

Electrical insulated cables and connections have two sub-components: the insulation material and the conducting material. The cable or connection component performs the license renewal intended function of "conducts electricity," which provides electrical connections to specified sections of an electrical circuit to deliver voltage, current or signals. This license renewal intended function applies to the conducting material sub-component.

Aging effects requiring management for cables and connections involve the insulation material sub-component. The insulated cable line items in Chapter VI of NUREG-1801 use the term "insulation material for electrical cables and connections." Therefore, to facilitate comparison to the aging management review results of NUREG-1 801, the insulation sub-component material was identified in LRA Table 2.5-1 and Table 3.6-2. The license renewal intended function of the cables and connections commodity group is "conducts electricity." However, to clarify the aging management of the cables and connections commodity group, the intended function of the insulation material is changed to "Insulation." Accordingly, LRA Table 2.5-1 and LRA Table 3.6-2 are changed to show the intended function "insulation."

E2 - 9 of 15

The changes to LRA Table 2.5-1 follow with additionsunderlinedand deletions lined through.

Structureand/orComponent/Commodity Intended Function1 Cable connections (metallicparts) Conducts electricity Insulationmaterial for electricalcables and connections ,,nd*,*t eloctricit, (includingterminal blocks, fuse holders, etc.) not subject to Insulation 10 CFR 50.49 EQ requirements(includesnon-EQ electricaland I&C penetrationconductors and connections)

Insulationmaterial for electricalcables not subject to 10 CFR ,,,.,dwR 9.."r"..,

50.49 EQ requirementsused in instrumentationcircuits Insulation Fuse holders (not part of active equipment): insulation material C.ndu"tS.,..tr"c.t, Insulation Fuse holders (not part of active equipment): metallic clamps Conducts electricity High voltage insulators(high voltage insulatorsfor SBO Insulation recovery)

Conductorinsulationfor inaccessiblepower cables (400 V to on.duc" O.b.'"*"a"..

35 kV) not subject to 10 CFR 50.49 EQ requirements Insulation Metal enclosed bus: bus/connections Conducts electricity Metal enclosed bus: enclosure assemblies Conducts electricity Metal enclosed bus: external surface of enclosureassemblies Conducts electricity Metal enclosed bus: insulation;insulators Insulation 161-kV oil-filled cable Conducts electricity Insulation 161-kV oil-filled cable: reservoirtanks Insulation 161-kV oil-filled cable: tubing, valves, instruments Insulation Switchyard bus and connections (switchyardbus for SBO Conducts electricity recovery)

Transmission conductors (transmissionconductors for SBO Conducts electricity recovery)

Transmissionconnectors (transmissionconnectors for SBO Conducts electricity recovery)

E2 - 10 of 15

The changes to LRA Table 3.6-2 follow with additions underlined and deletions lined through.

Table 3.6.2: ElectricalComponents Component Aging Effect Aging Intended Requiring Management NUREG- Table 1 Component Type Function Material Environment Management Program 1801 Item Item Notes Insulation material 4E Insulation Heat, moisture, Reduced Non-EQ VI.A.LP-33 3.6.1-8 A for electrical cables IN material- or radiation insulation Insulated and connections various and air resistance(IR) Cables and (including terminal organic Connections blocks, fuse holders, polymers etc.) not subject to 10 CFR 50.49 EQ requirements (includes non-EQ electrical and I&C penetration conductors and connections)

Insulation material CE Insulation Heat, moisture, Reduced Non-EQ VI.A.LP-34 3.6.1-9 A for electricalcables IN material- or radiation insulation Instrumentatio not subject to 10 various and air resistance (IR) n Circuits Test CFR 50.49 EQ organic Review requirementsused in polymers instrumentation circuits Fuse holders (not CE Insulation Air- indoor None None VI.A.LP-24 3.6.1-21 A part of active IN material- controlled or equipment): various uncontrolled insulationmaterial organic polymers Conductorinsulation for rE Insulation Significant Reduced Non-EQ VI.A.LP-35 3.6.1-10 inaccessiblepower IN material- moisture insulation Inaccessible cables (400 V to 35 kV) various resistance (IR) Power Cables not subject to 10 CFR organic (400 V to 35kV) 50.49 EQ requirements polymers E2 - 11 of 15

RAI 2.3.4.3-5a NRC requested clarificationfor the response to RAI 2.3.4.3-5a.

The response to RAI 2.3.4.3-5a provides clarification to the response to RAI 2.3.4.3-5 provided to the NRC on July 25, 2013, ADAMS No. ML13213A026, page 62 of 65 in Enclosure 3.

RAI 2.3.4.3-5

Background:

License renewal drawings LRA-1-47W857-1 and LRA-2-47W857-1, coordinatesG-1/2, G-3, G-5, G-6, G-8, G-10, B-1/2, B-3, B-5, B-6, B-8 and B-IO, depict condensercirculatingwater strainerhousings "1A3", "1A4", "1B3", "1B4", "1C3", "1C4", "IA 1' "1A2", "IB1' "1B2", "1C1",

"1C2", "2A3", "2A4", "2B3", "2B4", "2C3", "2C4", "2A 1", "2A2", "2B1 ", "2B2", "2C1" and "2C2"as not being within the scope of license renewal for 10 CFR 54.4(a)(2).

Issue:

LRA Table 2.3.4-3-9 lists the strainerhousings component types as being subject to an AMR with the intended function of pressureboundary.

Request:

The staff requests the applicantto provide the basis for not including the strainerhousing within the scope of license renewal.

TVA Response to RAI 2.3.4.3-5 Drawings LRA-1-47W857-1 and LRA-2-47W857-1 at coordinates G-1/2, G-3, G-5, G-6, G-8, G-10 show the condenser circulating water (CCW) inlets, which do not have strainer housings.

Locations B-1/2, B-3, B-5, B-6, B-8 and B-10 depict CCW strainer housings that are located within the CCW outlet piping. The strainer housings are represented by two horizontal parallel lines within the CCW piping. Because the strainer housings are enclosed, they do not meet the spatial interaction criteria associated with 10 CFR 54.4(a)(2) and are not subject to aging management review.

NRC Follow-up RAI 2.3.4.3-5a In its response letter, dated July 25, 2013, the applicant stated that license renewal drawings LRA-1-47W857-1 and LRA-2-47W857-1, coordinatesG-1/2, G-3, G-5, G-6, G-8, and G-10, depict the condenser circulating water inlets, which do not have strainerhousings. The applicant also stated that license renewal drawingsLRA-1-47W857-1 and LRA-2-47W857-1, coordinates B-1/2, B-3, B-5, B-6, B-8, and B-1O, depict condenser circulatingwater strainerhousings that are located within the condenser circulatingwater outlet piping. The applicantdescribed the strainerhousings as being enclosed, which would not meet the spatialinteraction criteria associatedwith 10 CFR 54.4(a)(2), and are not subject to AMR. However, the applicant did not clarify whether the condenser circulatingwater inlets at coordinatesG-1/2, G-3, G-5, G-6, G-8, and G-1O would be subject to AMR for spatialinteraction or any other intended function.

E2 - 12 of 15

The staff requests that the applicant to provide the scoping classification of the condenser circulating water inlets on license renewal drawings LRA-1-47W857-1 and LRA-2-47W857-1, at coordinatesG- 1/2, G-3, G-5, G-6, G-8, and G- 10, and discuss if the water inlets are subject to AMR.

TVA Response to RAI 2.3.4.3-5a LRA drawings LRA-1-47W857-1 and LRA-2-47W857-1 depict the condenser tube cleaning system. The components highlighted on these drawings are those in the condenser tube cleaning system that are subject to aging management review. LRA drawings LRA-1-47W831-1-1 and LRA-2-47W831-1-1 show the CCW system. As indicated by the highlighting in locations B-H, 6, the CCW inlets (as well as the outlets) are subject to aging management review based on the criterion of 10 CFR 54.4(a)(2) for spatial interaction.

The line items for strainer housings listed in LRA Table 2.3.4-3-9 represent several other strainers in the CCW system (system code 27), e.g., those represented on drawing LRA-1,2-47W832-1 as squares or rectangles with diagonal lines.

E2 - 13 of 15

RAI 2.3.3.15-1a NRC requested clarificationfor the response to RAI 2.3.3.15-1a.

Background:

In its response letter, dated July 25, 2013, RAI 2.3.3.15-1, the applicant stated that the compressor housings meets the criterion of 10 CFR 54.4(a)(2) for structural support. The applicant also amended LRA Table 3.3.2-17-30 as part of its RAI response to include all of the necessary systems, structures and components subject to AMR. Based on the 10 CFR 54.4(a)(2) criterion, the compressor housing should also be included as a component type in LRA Table 2.3.3-15. However, the applicant did not provide any information in its RAI response about its exclusion of the compressor housing from LRA Table 2.3.3-15.

Request:

The staff requests that the applicant clarifies whether the compressor housing will be included as a new component type or if the component is already included as part of an existing component type in LRA Table 2.3.3-15.

The following response supersedes the response provided to the NRC on July 25, 2013, ADAMS No. ML13213A026, page 39 of 65 in Enclosure 3.

Note: Revisions are in italics and underlined.

TVA ResDonse to RAI 2.3.3.15-1a Upon further review, the air compressor housing meets the criterion of 10 CFR 54.4(a)(2) for structural support of the hydraulic unloader and the %-inch line from the hydraulic unloader to the high pressure tank.

Changes to LRA Table 2.3.3-17-30, "StandbyDiesel GeneratorSystem, Nonsafety-Related Components Affectinq Safety-Related Systems, Components Subiect to Aging Management Review" follow with additions underlined.

COmpressOrhousing Pressureboundary Changes to LRA Table 3.3.2-17-30, "Standby Diesel Generator System, Nonsafety-Related Components Affecting Safety-Related Systems, Summary of Aging Management Evaluation" follow with additions underlined.

Compressor Pressure Carbon Air- indoor Loss of External VII.L.A- 3.3.1- A housing boundary steel (ext) material Surfaces 77 78 Monitoring Compressor Pressure Carbon Condensation Loss of Compressed VII.D.A- 3.3.1- A houi boundary steel (int) material Air Monitoring 26 55 TI ITub___ IPressure boundary Copper Uo (int)

Condensation Loss of material Air Compressed IVII.D.AP 3.3.1-Monitoring 1-240 C E2 - 14 of 15

RAI B.1.41-3b NRC requested clarificationfor the first sentence of the last paragraphof the response to RAI B. 1.41-3a.

The following response supersedes the response provided to the NRC on September 3, 2013, page 19 of 23 in the Enclosure-1.

Note: Revisions are in italics and underlined.

Revised TVA Response to RAI B.1.41-3a As recommended in NUREG-1801,Section XI.M12, all components determined to be potentially susceptible to thermal aging embrittlement are within the scope of this program.

Use of a flaw tolerance evaluation is the preferred approach to demonstrate that potentially susceptible components have adequate toughness.

In the event that a volumetric inspection method becomes qualified for this application, TVA may use this approach to perform inspections for some or all potentially susceptible components in lieu of the flaw tolerance evaluation.

For each of the components selected for the inspection ogtion, the limiting portions of the component from the standpoint of applied stress, operating time and environmental considerations will be included, as recommended by NUREG-1801,Section XI.M12.

E2 - 15 of 15

ENCLOSURE 3 Tennessee Valley Authority Sequoyah Nuclear Plant, Units I and 2 License Renewal Regulatory Commitment List, Revision 7

ENCLOSURE3 Tennessee Valley Authority Sequoyah Nuclear Plant, Units I and 2 License Renewal Regulatory Commitment List, Revision 7 Commitments 7.E and 31.L have been added. Additions are underlined.

LRA COMMITMENT IMPLEMENTATION SECTION No.

SCHEDULE IAUDIT ITEM Implement the Aboveground Metallic Tanks Program as described QN1: Prior to 09/17/20 B.1.1 in LRA Section B.1.1 QN2: Prior to 09/15/21 2 A. Revise Bolting Integrity Program procedures to ensure the QN1: Prior to 09/17/20 B.1.2 actual yield strength of replacement or newly procured bolts will be QN2: Prior to 09/15/21 less than 150 ksi B. Revise Bolting Integrity Program procedures to include the additional guidance and recommendations of EPRI NP-5769 for replacement of ASME pressure-retaining bolts and the guidance provided in EPRI TR-104213 for the replacement of other pressure-retaining bolts.

C. Revise Bolting Integrity Program procedures to specify a corrosion inspection and a check-off for the transfer tube isolation valve flange bolts.

D. Revise Bolting Integrity Program procedures to visually inspect a representative sample of normally submerged ERCW system bolts at least once every 5 years. (See Set 10 (30-day), Enclosure 1, B.1.2-2a) 3 A. Implement the Buried and Underground Piping and Tanks SQN1: Prior to 09/17/20 B.1.4 Inspection Program as described in LRA Section B. 1.4. SQN2: Prior to 09/15/21 B. Cathodic protection will be provided based on the guidance of NUREG-1801, section XI.M41, as modified by LR-ISG-2011-03.

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LRA No. OMMIMENTIMPLEMENTATION SCHEDULE I SECTION AUDIT ITEM 4 A. Revise Compressed Air Monitoring Program procedures to QNI: Prior to 09/17/20 B.1.5 include the standby diesel generator (DG) starting air subsystem. SQN2: Prior to 09/15/21 B. Revise Compressed Air Monitoring Program procedures to include maintaining moisture and other contaminants below specified limits in the standby DG starting air subsystem.

C. Revise Compressed Air Monitoring Program procedures to apply a consideration of the guidance of ASME OM-S/G-1998, Part 17; EPRI NP-7079; and EPRI TR-108147 to the limits specified for the air system contaminants D. Revise Compressed Air Monitoring Program procedures to maintain moisture, particulate size, and particulate quantity below acceptable limits in the standby DG starting air subsystem to mitigate loss of material.

E. Revise Compressed Air Monitoring Program procedures to include periodic and opportunistic visual inspections of surface conditions consistent with frequencies described in ASME O/M-SG-1 998, Part 17 of accessible internal surfaces such as compressors, dryers, after-coolers, and filter boxes of the following compressed air systems:

• Diesel starting air subsystem

• Auxiliary controlled air subsystem

• Nonsafety-related controlled air subsystem F. Revise Compressed Air Monitoring Program procedures to monitor and trend moisture content in the standby DG starting air subsystem.

G. Revise Compressed Air Monitoring Program procedures to include consideration of the guidance for acceptance criteria in ASME OM-S/G-1998, Part 17, EPRI NP-7079; and EPRI TR-108147.

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LRA COMMITMENT IMPLEMENTATION SECTION No. SCHEDULE /AUDIT ITEM 5 A. Revise Diesel Fuel Monitoring Program procedures to monitor SQN1: Prior to 09/17/20 B.1.8 and trend sediment and particulates in the standby DG day tanks. SQN2: Prior to 09/15/21 B. Revise Diesel Fuel Monitoring Program procedures to monitor and trend levels of microbiological organisms in the seven-day storage tanks.

C. Revise Diesel Fuel Monitoring Program procedures to include a ten-year periodic cleaning and internal visual inspection of the standby DG diesel fuel oil day tanks and high pressure fire protection (HPFP) diesel fuel oil storage tank. These cleanings and internal inspections will be performed at least once during the ten-year period prior to the period of extended operation and at succeeding ten-year intervals. If visual inspection is not possible, a volumetric inspection will be performed.

D. Revise Diesel Fuel Monitoring Program procedures to include a volumetric examination of affected areas of the diesel fuel oil tanks, if evidence of degradation is observed during visual inspection. The scope of this enhancement includes the standby DG seven-day fuel oil storage tanks, standby DG fuel oil day tanks, and HPFP diesel fuel oil storage tank and is applicable to the inspections performed during the ten-year period prior to the period of extended operation and succeeding ten-year intervals.

6 A. Revise External Surfaces Monitoring Program procedures to SQN1: Prior to 09/17/20 B.1.10 clarify that periodic inspections of systems in scope and subject to SQN2: Prior to 09/15/21 aging management review for license renewal in accordance with 10 CFR 54.4(a)(1) and (a)(3) will be performed. Inspections shall include areas surrounding the subject systems to identify hazards to those systems. Inspections of nearby systems that could impact the subject systems will include SSCs that are in scope and subject to aging management review for license renewal in accordance with 10 CFR 54.4(a)(2).

B. Revise External Surfaces Monitoring Program procedures to include instructions to look for the following related to metallic components:

• Corrosion and material wastage (loss of material).

• Leakage from or onto external surfaces loss of material).

" Worn, flaking, or oxide-coated surfaces (loss of material).

" Corrosion stains on thermal insulation (loss of material).

" Protective coating degradation (cracking, flaking, and blistering).

" Leakage for detection of cracks on the external surfaces of stainless steel components exposed to an air environment containing halides.

C. Revise External Surfaces Monitoring Program procedures to include instructions for monitoring aging effects for flexible polymeric components, including manual or physical manipulations of the material, with a sample size for manipulation of at least ten E 3of16

LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE I AUDIT ITEM (6) percent of the available surface area. The inspection parameters for polymers shall include the following:

" Surface cracking, crazing, scuffing, dimensional changes (e.g., ballooning and necking) -).

" Discoloration.

• Exposure of internal reinforcement for reinforced elastomers (loss of material).

• Hardening as evidenced by loss of suppleness during manipulation where the component and material can be manipulated.

D. Revise External Surfaces Monitoring Program procedures to ensure surfaces that are insulated will be inspected when the external surface is exposed (i.e., during maintenance) at such intervals that would ensure that the components' intended function is maintained.

E. Revise External Surfaces Monitoring Program procedures to include acceptance criteria. Examples include the following:

• Stainless steel should have a clean shiny surface with no discoloration.

" Other metals should not have any abnormal surface indications.

" Flexible polymers should have a uniform surface texture and color with no cracks and no unanticipated dimensional change, no abnormal surface with the material in an as-new condition with respect to hardness, flexibility, physical dimensions, and color.

" Rigid polymers should have no erosion, cracking, checking or chalks.

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LRA COMMITMENT IMPLEMENTATION SECTION No.

SCHEDULE IAUDIT ITEM 7 A. Revise Fatigue Monitoring Program procedures to monitor and SQNI: Prior to 09/17/20 B.1.11 track critical thermal and pressure transients for components that SQN2: Prior to 09/15/21 have been identified to have a fatigue Time Limited Aging Analysis.

B. Fatigue usage calculations that consider the effects of the reactor water environment will be developed for a set of sample reactor coolant system (RCS) components. This sample set will include the locations identified in NUREG/CR-6260 and additional plant-specific component locations in the reactor coolant pressure boundary if they are found to be more limiting than those considered in NUREG/CR-6260. In addition, fatigue usage calculations for reactor vessel internals (lower core plate and control rod drive (CRD) guide tube pins) will be evaluated for the effects of the reactor water environment. Fen factors will be determined as described in Section 4.3.3.

C. Fatigue usage factors for the RCS pressure boundary components will be adjusted as necessary-to incorporate the effects of the Cold Overpressure Mitigation System (COMS) event (i.e., low temperature overpressurization event) and the effects of structural weld overlays.

D. Revise Fatigue Monitoring Program procedures to provide updates of the fatigue usage calculations on an as-needed basis if an allowable cycle limit is approached, or in a case where a transient definition has been changed, unanticipated new thermal events are discovered, or the geometry of components have been modified.

E. Revise Fatigue Monitoring Program procedures to track the tensioning cycles for the reactor coolant pump hydraulic studs.

8 A. Revise Fire Protection Program procedures to include an SQN1: Prior to 09/17/20 B.1.12 inspection of fire barrier walls, ceilings, and floors for any signs of SQN2: Prior to 09/15/21 degradation such as cracking, spalling, or loss of material caused by freeze thaw, chemical attack, or reaction with aggregates.

B. Revise Fire Protection Program procedures to provide acceptance criteria of no significant indications of concrete cracking, spalling, and loss of material of fire barrier walls, ceilings, and floors and in other fire barrier materials.

9 A. Revise Fire Water System Program procedures to include periodic SQN1: Prior to 09/17/20 B.1.13 visual inspection of fire water system internals for evidence of SQN2: Prior to 09/15/21 corrosion and loss of wall thickness.

B. Revise Fire Water System Program procedures to include one of the following options:

• Wall thickness evaluations of fire protection piping using non-intrusive techniques (e.g., volumetric testing) to identify evidence of loss of material will be performed prior to the period of extended operation and periodically thereafter. Results of the E 5of16

LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE I AUDIT ITEM (9) initial evaluations will be used to determine the appropriate inspection interval to ensure aging effects are identified prior to loss of intended function.

A visual inspection of the internal surface of fire protection piping will be performed upon each entry into the system for routine or corrective maintenance. These inspections will be capable of evaluating (1) wall thickness to ensure against catastrophic failure and (2) the inner diameter of the piping as it applies to the design flow of the fire protection system. Maintenance history shall be used to demonstrate that such inspections have been performed on a representative number of locations prior to the period of extended operation. A representative number is 20%

of the population (defined as locations having the same material, environment, and aging effect combination) with a maximum of 25 locations. Additional inspections will be performed as needed to obtain this representative sample prior to the period of extended operation and periodically during the period of extended operation based on the findings from the inspections performed prior to the period of extended operation.

C, Revise Fire Water System Program procedures to ensure a representative sample of sprinkler heads will be tested or replaced before the end of the 50-year sprinkler head service life and at ten-year intervals thereafter during the extended period of operation.

NFPA-25 defines a representative sample of sprinklers to consist of a minimum of not less than four sprinklers or one percent of the number of sprinklers per individual sprinkler sample, whichever is greater. If the option to replace the sprinklers is chosen, all sprinkler heads that have been in service for 50 years will be replaced.

D, Revise the Fire Water System Program full flow testing to be in accordance with full flow testing standards of NFPA-25 (2011).

E. Revise Fire Water System Program procedures to include acceptance criteria for periodic visual inspection of fire water system internals for corrosion, minimum wall thickness, and the absence of biofouling in the sprinkler system that could cause corrosion in the sprinklers.

10 A, Revise Flow Accelerated Corrosion (FAC) Program procedures SQNI: Prior to 09/17/20 B.1.14 to implement NSAC-202L guidance for examination of components SQN2: Prior to 09/15/21 upstream of piping surfaces where significant wear is detected.

B, Revise FAC Program procedures to implement the guidance in LR-ISG-2012-01, which will include a susceptibility review based on internal operating experience, external operating experience, EPRI TR-1 011231, Recommendations for Controlling Cavitation,Flashing, Liquid Droplet Impingement, and Solid ParticleErosion in Nuclear Power Plant Piping, and NUREG/CR-6031, Cavitation Guide for Control Valves. (TVA Response to Set 6.60day RAI B. 1.14-1 and I B, 1.38-1) 1 E 6of16

LRA COMMITMENT IMPLEMENTATION SECTION No.

SCHEDULE I AUDIT ITEM 11 Revise Flux Thimble Tube Inspection Program procedures to SQN1: Prior to 09/17/20 B.1.15 include a requirement to address if the predictive trending projects SQN2: Prior to 09/15/21 that a tube will exceed 80% wall wear prior to the next planned inspection, then initiate a Service Request (SR) to define actions (i.e.,

plugging, repositioning, replacement, evaluations, etc.) required to ensure that the projected wall wear does not exceed 80%. If any tube is found to be >80% through wall wear, then initiate a Service Request (SR) to evaluate the predictive methodology used and modify as required to define corrective actions (i.e., plugging, I repositioning, replacement, etc).

12 A. Revise Inservice Inspection-IWF Program procedures to clarify SQN1: Prior to 09/17/20 B.1.17 that detection of aging effects will include monitoring anchor bolts for SQN2: Prior to 09/15/21 loss of material, loose or missing nuts, and cracking of concrete around the anchor bolts.

B. Revise ISI - IWF Program procedures to include the following corrective action guidance.

When a component support is found with minor age-related degradation, but still is evaluated as "acceptable for continued service" as defined in IWF-3400, the program owner may choose to repair the degraded component. If the component is repaired, the program owner will substitute a randomly selected component that is more representative of the general population for subsequent inspections.

13 Inspection of Overhead Heavy Load and Light Load (Related to SQN1: Prior to 09/17/20 B.1.18 Refueling) Handling Systems: SQN2: Prior to 09/15/21 A. Revise program procedures to specify the inspection scope will include monitoring of rails in the rail system for wear; monitoring structural components of the bridge, trolley and hoists for the aging effect of deformation, cracking, and loss of material due to corrosion; and monitoring structural connections/bolting for loose or missing bolts, nuts, pins or rivets and any other conditions indicative of loss of bolting integrity.

B. Revise program procedures to include the inspection and inspection frequency requirements of ASME B30.2.

C. Revise program procedures to clarify that the acceptance criteria will include requirements for evaluation in accordance with ASME B30.2 of significant loss of material for structural components and structural bolts and significant wear of rail in the rail system.

D. Revise program procedures to clarify that the acceptance criteria and maintenance and repair activities use the guidance provided in ASME B30.2 14 Implement the Internal Surfaces in Miscellaneous Piping and QN1: Prior to 09/17/20 B.1.19 Ducting Components Program as described in LRA Section B. 1.19. QN2: Prior to 09/15/21 E 7of16

LRA COMMITMENT IMPLEMENTATION SECTION No. SCHEDULE / AUDIT ITEM 15 Implement the Metal Enclosed Bus Inspection Program as SQN1: Priorto 09/17/20 B.1.21 described in LRA Section B.1.21. 3QN2: Prior to 09/15/21 16 A. Revise Neutron Absorbing Material Monitoring Program 3QN1: Prior to 09/17/20 B.1.22 procedures to perform blackness testing of the Boral coupons within 3QN2: Prior to 09/15/21 the ten years prior to the period of extended operation and at least every ten years thereafter based on initial testing to determine possible changes in boron-10 areal density.

B. Revise Neutron Absorbing Material Monitoring Program procedures to relate physical measurements of Boral coupons to the need to perform additional testing.

C. Revise Neutron Absorbing Material Monitoring Program procedures to perform trending of coupon testing results to determine the rate of degradation and to take action as needed to maintain the intended function of the Boral.

17 Implement the Non-EQ Cable Connections Program as described QN1: Prior to 09/17/20 B.1.24 in LRA Section B.1.24 QN2: Prior to 09/15/21 18 Implement the Non-EQ Inaccessible Power Cable (400 V to 35 kV) QNI: Prior to 09/17/20 B.1.25 Program as described in LRA Section B. 1.25 SQN2: Prior to 09/15/21 19 Implement the Non-EQ Instrumentation Circuits Test Review SQN1: Prior to 09/17/20 B.1.26 Program as described in LRA Section B.1.26. SQN2: Prior to 09/15/21 20 Implement the Non-EQ Insulated Cables and Connections QNI: Prior to 09/17/20 B.1.27 Program as described in LRA Section B.1.27 QN2: Prior to 09/15/21 21 A. Revise Oil Analysis Program procedures to monitor and QN1: Prior to 09/17/20 B.1.28 maintain contaminants in the 161-kV oil filled cable system within SQN2: Prior to 09/15/21 acceptable limits through periodic sampling in accordance with industry standards, manufacturer's recommendations and plant-specific operating experience.

B. Revise Oil Analysis Program procedures to trend oil contaminant levels and initiate a problem evaluation report if contaminants exceed alert levels or limits in the 161 -kV oil-filled cable system.

22 Implement the One-Time Inspection Program as described in LRA 3QN1: Prior to 09/17/20 B.1.29 Section B.1.29. SQN2: Prior to 09/15/21 23 Implement the One-Time Inspection - Small Bore Piping Program SQN1: Prior to 09/17/20 B.1.30 as described in LRA Section B.1.30 SQN2: Prior to 09/15/21 24 Revise Periodic Surveillance and Preventive Maintenance SQN1: Prior to 09/17/20 B.1.31 Program procedures as necessary to include all activities described SQN2: Prior to 09/15/21 in the table provided in the LRA Section B. 1.31 program description.

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LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE / AUDIT ITEM 25 A. Revise Protective Coating Program procedures to clarify that SQN1: Prior to 09/17/20 B.1.32 detection of aging effects will include inspection of coatings near SQN2: Prior to 09/15/21 sumps or screens associated with the emergency core cooling system.

B. Revise Protective Coating Program procedures to clarify that instruments and equipment needed for inspection may include, but not be limited to, flashlights, spotlights, marker pen, mirror, measuring tape, magnifier, binoculars, camera with or without wide-angle lens, and self-sealing polyethylene sample bags.

C. Revise Protective Coating Program procedures to clarify that the last two performance monitoring reports pertaining to the coating systems will be reviewed prior to the inspection or monitoring process.

26 A. Revise Reactor Head Closure Studs Program procedures to SQN1: Prior to 09/17/20 B.1.33 ensure that replacement studs are fabricated from bolting material SQN2: Prior to 09/15/21 with actual measured yield strength less than 150 ksi.

B. Revise Reactor Head Closure Studs Program procedures to exclude the use of molybdenum disulfide (MoS 2) on the reactor vessel closure studs and to refer to Reg. Guide 1.65, Revl.

27 A. Revise Reactor Vessel Internals Program procedures to take SQN1: Priorto 09/17/20 B.1.34 physical measurements of the Type 304 stainless steel hold-down springs in Unit 1 at each refueling outage to ensure preload is SQN2: Not Applicable adequate for continued operation.

B. Revise Reactor Vessel Internals Program procedures to include preload acceptance criteria for the Type 304 stainless steel hold-down springs in Unit 1.

28 A. Revise Reactor Vessel Surveillance Program procedures to SQNI: Prior to 09/17/20 B.1.35 consider the area outside the beltline such as nozzles, penetrations SQN2: Prior to 09/15/21 and discontinuities to determine if more restrictive pressure-temperature limits are required than would be determined by just considering the reactor vessel beltline materials.

B. Revise Reactor Vessel Surveillance Program procedures to incorporate an NRC-approved schedule for capsule withdrawals to meet ASTM-E1 85-82 requirements, including the possibility of operation beyond 60 years (refer to the TVA Letter to NRC, "Sequoyah Reactor Pressure Vessel Surveillance Capsule Withdrawal Schedule Revision Due to License Renewal Amendment," dated January 10, 2013, ML13032A251.)

C. Revise Reactor Vessel Surveillance Program procedures to withdraw and test a standby capsule to cover the peak fluence expected at the end of the period of extended operation.

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LRA COMMITMENT IMPLEMENTATION SECTION No.

SCHEDULE / AUDIT ITEM 29 Implement the Selective Leaching Program as described in LRA SQN1: Prior to 09/17/20 B.1.37 Section B.1.37. QN2: Prior to 09/15/21 30 w_ Revise Steam Generator Intearitv Proaram Drocedures to ensure SQN1: Prior to 09/17/20 B.1.39 that corrosion resistant materials are used for replacement steam SQN2: Prior to 09/15/21 generator tube plugs.

-4 1 31 A. Revise Structures Monitoring Program procedures to include SQN1: Prior to 09/17/20 the following in-scope structures: SQN2: Prior to 09/15/21

• Carbon dioxide building

• Condensate storage tanks' (CSTs) foundations and pipe trench

• East steam valve room Units 1 & 2

" Essential raw cooling water (ERCW) pumping station

• High pressure fire protection (HPFP) pump house and water storage tanks' foundations

• Radiation monitoring station (or particulate iodine and noble gas station) Units 1 & 2

" Service building

• Skimmer wall (Cell No. 12)

• Transformer and switchyard support structures and foundations B. Revise Structures Monitoring Program procedures to specify the following list of in-scope structures are included in the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program (Section B.1.36):

• Condenser cooling water (CCW) pumping station (also known as intake pumping station) and retaining walls

• CCW pumping station intake channel

• ERCW discharge box

" ERCW protective dike

• ERCW pumping station and access cells

" Skimmer wall, skimmer wall Dike A and underwater dam C. Revise Structures Monitoring Program procedures to include the following in-scope structural components and commodities:

" Anchor bolts

• Anchorage/embedments (e.g., plates, channels, unistrut, angles, other structural shapes)

• Beams, columns and base plates (steel) 0 Beams, columns, floor slabs and interior walls (concrete)

S Beams, columns, floor slabs and interior walls (reactor cavity and primary shield walls; pressurizer and reactor coolant pump compartments; refueling canal, steam generator compartments; crane wall and missile shield slabs and barriers)

Building concrete at locations of expansion and grouted anchors; grout pads for support base plates 0 Cable tray 0 Cable tunnel 0 Canal gate bulkhead 0 Compressible joints and seals E 10of16

LRA I IMPLEMENTATION NO MSCHEDULE SECTION

/ AUDIT ITEM (31) 9 Concrete cover for the rock walls of approach channel

• Concrete shield blocks

• Conduit 0 Control rod drive missile shield

• Control room ceiling support system

• Curbs

• Discharge box and foundation

• Doors (including air locks and bulkhead doors) 0 Duct banks 0 Earthen embankment 0 Equipment pads/foundations

• Explosion bolts (E. G. Smith aluminum bolts)

• Exterior above and below grade; foundation (concrete)

• Exterior concrete slabs (missile barrier) and concrete caps

• Exterior walls: above and below grade (concrete)

• Foundations: building, electrical components, switchyard, transformers, circuit breakers, tanks, etc.

• Ice baskets 0 Ice baskets lattice support frames

• Ice condenser support floor (concrete)

• Insulation (fiberglass, calcium silicate) 0 Intermediate deck and top deck of ice condenser

• Kick plates and curbs (steel - inside steel containment vessel)

• Lower inlet doors (inside steel containment vessel)

• Lower support structure structural steel: beams, columns, plates (inside steel containment vessel)

• Manholes and handholes

• Manways, hatches, manhole covers, and hatch covers (concrete)

• Manways, hatches, manhole covers, and hatch covers (steel)

• Masonry walls

• Metal siding

• Miscellaneous steel (decking, grating, handrails, ladders, platforms, enclosure plates, stairs, vents and louvers, framing steel, etc.)

• Missile barriers/shields (concrete)

• Missile barriers/shields (steel)

• Monorails

• Penetration seals 0 Penetration seals (steel end caps) 0 Penetration sleeves (mechanical and electrical not penetrating primary containment boundary)

• Personnel access doors, equipment access floor hatch and escape hatches

• Piles

• Pipe tunnel 0 Precast bulkheads

• Pressure relief or blowout panels

• Racks, panels, cabinets and enclosures for electrical E 11of16

LRA No. COMMITMENT IMPLEMENTATION SECTION NO MSCHEDULE I AUDIT ITEM (31) equipment and instrumentation Riprap 0 Rock embankment 0 Roof or floor decking 0 Roof membranes 0 Roof slabs 0 RWST rainwater diversion skirt S RWST storage basin 0 Seals and gaskets (doors, manways and hatches) 0 Seismic/expansion joint 0 Shield building concrete foundation, wall, tension ring beam and dome: interior, exterior above and below grade 0 Steel liner plate 0 Steel sheet piles 0 Structural bolting 0 Sumps (concrete) 0 Sumps (steel) 0 Sump liners (steel)

S Sump screens S Support members; welds; bolted connections; support anchorages to building structure (e.g., non-ASME piping and components supports, conduit supports, cable tray supports, HVAC duct supports, instrument tubing supports, tube track supports, pipe whip restraints, jet impingement shields, masonry walls, racks, panels, cabinets and enclosures for electrical equipment and instrumentation) 0 Support pedestals (concrete) 0 Transmission, angle and pull-off towers 0 Trash racks 0 Trash racks associated structural support framing 0 Traveling screen casing and associated structural support framing 0 Trenches (concrete) 0 Tube track Turning vanes Vibration isolators D. Revise Structures Monitoring Program procedures to include periodic sampling and chemical analysis of ground water chemistry for pH, chlorides, and sulfates on a frequency of at least every five years.

E. Revise Masonry Wall Program procedures to specify masonry walls located in the following in-scope structures are in the scope of the Masonry Wall Program:

• Auxiliary building

" Reactor building Units 1 & 2

• Control bay

" ERCW pumping station

" HPFP pump house

" Turbine building E 12 of 16

LRA COMMITMENT IMPLEMENTATION SECTION No.

NMSCHEDULE IAUDIT ITEM (31) F. Revise Structures Monitoring Program procedures to include the following parameters to be monitored or inspected:

• Requirements for concrete structures based on ACI 349-3R and ASCE 11 and include monitoring the surface condition for loss of material, loss of bond, increase in porosity and permeability, loss of strength, and reduction in concrete anchor capacity due to local concrete degradation.

• Loose or missing nuts for structural bolting.

" Monitoring gaps between the structural steel supports and masonry walls that could potentially affect wall qualification.

G. Revise Structures Monitoring Program procedures to include the following components to be monitored for the associated parameters:

• Anchors/fasteners (nuts and bolts) will be monitored for loose or missing nuts and/or bolts, and cracking of concrete around the anchor bolts.

• Elastomeric vibration isolators and structural sealants will be monitored for cracking, loss of material, loss of sealing, and change in material properties (e.g., hardening).

• Monitor the surface condition of insulation (fiberglass, calcium silicate) to identify exposure to moisture that can cause loss of insulation effectiveness.

H. Revise Structures Monitoring Program procedures to include the following for detection of aging effects:

• Inspection of structural bolting for loose or missing nuts.

" Inspection of anchor bolts for loose or missing nuts and/or bolts, and cracking of concrete around the anchor bolts.

• Inspection of elastomeric material for cracking, loss of material, loss of sealing, and change in material properties (e.g.,

hardening), and supplement inspection by feel or touch to detect hardening if the intended function of the elastomeric material is suspect. Include instructions to augment the visual examination of elastomeric material with physical manipulation of at least ten percent of available surface area.

• Opportunistic inspections when normally inaccessible areas (e.g., high radiation areas, below grade concrete walls or foundations, buried or submerged structures) become accessible due to required plant activities. Additionally, inspections will be performed of inaccessible areas in environments where observed conditions in accessible areas exposed to the same environment indicate that significant degradation is occurring.

• Inspection of submerged structures at least once every five years.

Inspections of water control structures should be conducted under the direction of qualified personnel experienced in the investigation, design, construction, and operation of these types of facilities.

" Inspections of water control structures shall be performed on an interval not to exceed five years.

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LRA IMPLEMENTATION SECTION N.COMMITMENT SCHEDULE / AUDIT ITEM (31)

• Perform special inspections of water control structures immediately (within 30 days) following the occurrence of significant natural phenomena, such as large floods, earthquakes, hurricanes, tornadoes, and intense local rainfalls.

• Insulation (fiberglass, calcium silicate) will be monitored for loss of material and change in material properties due to potential exposure to moisture that can cause loss of insulation effectiveness.

I. Revise Structures Monitoring Program procedures to prescribe quantitative acceptance criteria is based on the quantitative acceptance criteria of ACI 349.3R and information provided in industry codes, standards, and guidelines including ACI 318, ANSI/ASCE 11 and relevant AISC specifications. Industry and plant-specific operating experience will also be considered in the development of the acceptance criteria.

J. Revise Structures Monitoring Program procedures to clarify that detection of aging effects will include the following.

Qualifications of personnel conducting the inspections or testing and evaluation of structures and structural components meet the guidance in Chapter 7 of ACI 349.3R.

K. Revise Structures Monitoring Program procedures to include the following acceptance criteria for insulation (calcium silicate and fiberglass)

• No moisture or surface irregularities that indicate exposure to moisture.

L. Revise Structures Monitoring Program procedures to include the following preventive actions.

Specify protected storage requirements for high-strength fastener components (specifically ASTM A325 and A490 bolting).

Storage of these fastener components shall include:

1) maintaining fastener components in closed containers to protect from dirt and corrosion:

(2) storage of the closed containers in a protected shelter:

(3) removal of fastener components from protected storage only as necessary: and (4) prompt return of any unused fastener components to protected storage.

32 Implement the Thermal Aging Embrittlement of Cast Austenitic QNI: Prior to 09/17/20 B.1.41 Stainless Steel (CASS) as described in LRA Section B.1.41 QN2: Prior to 09/15/21 33 A. Revise Water Chemistry Control - Closed Treated Water QN1: Prior to 09/17/20 B.1.42 Systems Program procedures to provide a corrosion inhibitor for the QN2: Prior to 09/15/21 following chilled water subsystems in accordance with industry guidelines and vendor recommendations:

" Auxiliary building cooling

" Incore Chiller 1A, 1B, 2A, & 2B

• 6.9 kV Shutdown Board Room A & B E 14 of 16

LRA I

m IMPLEMENTATION SECTION No. COMMITMENT I SCHEDULE /AUDIT ITEM

___________________________I_________IE (33) B. Revise Water Chemistry Control - Closed Treated Water Systems Program procedures to conduct inspections whenever a boundary is opened for the following systems:

• Standby diesel generator jacket water subsystem

• Component cooling system

• Glycol cooling loop system

• High pressure fire protection diesel jacket water system

" Chilled water portion of miscellaneous HVAC systems (i.e.,

auxiliary building, Incore Chiller 1A, 1B, 2A, &2B, and 6.9 kV Shutdown Board Room A & B)

C. Revise Water Chemistry Control-Closed Treated Water Systems Program procedures to state these inspections will be conducted in accordance with applicable ASME Code requirements, industry standards, or other plant-specific inspection and personnel qualification procedures that are capable of detecting corrosion or cracking.

D. Revise Water Chemistry Control - Closed Treated Water Systems Program procedures to perform sampling and analysis of the glycol cooling system per industry standards and in no case greater than quarterly unless justified with an additional analysis.

E. Revise Water Chemistry Control - Closed Treated Water Systems Program procedures to inspect a representative sample of piping and components at a frequency of once every ten years for the following systems:

" Standby diesel generator jacket water subsystem

• Component cooling system

• Glycol cooling loop system

• High pressure fire protection diesel jacket water system

• Chilled water portion of miscellaneous HVAC systems (i.e.,

auxiliary building, Incore Chiller 1A, 1B, 2A, &2B, and 6.9 kV Shutdown Board Room A& B)

F. Components inspected will be those with the highest likelihood of corrosion or cracking. A representative sample is 20% of the population (defined as components having the same material, environment, and aging effect combination) with a maximum of 25 components. These inspections will be in accordance with applicable ASME Code requirements, industry standards, or other plant-specific inspection and personnel qualification procedures that ensure the capability of detecting corrosion or cracking.

34 Revise Containment Leak Rate Program procedures to require SQN1: Prior to 09/17/20 B. 1.7 venting the SCV bottom liner plate weld leak test channels to the SQN2: Prior to 09/15/21 containment atmosphere prior to the CILRT and resealing the vent path after the CILRT to prevent moisture intrusion during plant operation. I E 15 of 16

LRA COMMITMENT IMPLEMENTATION SECTION No. SCHEDULE /AUDIT ITEM 35 Modify the configuration of the SQN Unit 1 test connection access SQNI: Prior to 09/17/20 B.1.6 boxes to prevent moisture intrusion to the leak test channels. Prior to installing this modification, TVA will perform remote visual SQN2: Not Applicable examinations inside the leak test channels by inserting a borescope video probe through the test connection tubing.

36 Revise Inservice Inspection Program procedures to include a SQNI: Prior to 09/17/20 B.1.16 supplemental inspection of Class 1 CASS piping components that SQN2: Prior to 09/15/21 do not meet the materials selection criteria of NUREG-0313, Revision 2 with regard to ferrite and carbon content. An inspection techniques qualified by ASME or EPRI will be used to monitor cracking.

Inspections will be conducted on a sampling basis. The extent of sampling will be based on the established method of inspection and industry operating experience and practices when the program is implemented, and will include components determined to be limiting from the standpoint of applied stress, operating time and environmental considerations.

37 TVA will implement the Operating Experience for the AMPs in No later than the B.0.4 accordance with the WVA response to the RAI B.0.4-1 on scheduled issue date of

he renewed operating July 29, 2013 letter to the NRC. (See Set 7.30day RAI B.0.4-1 icenses for SQN Units 1 Response, EDMS # L44130725002) 2.

The above table identifies the 37 SQN NRC LR commitments. Any other statements in this letter are provided for information purposes and are not considered to be regulatory commitments.

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