ML13225A387

Response to NRC Request for Additional Information Regarding the Review of the Sequoyah Nuclear Plant, Units I and 2, License Renewal Application, Sets 1, 6, 7, and Revised Responses for 1.4-2, 1.4-3 and 1.4-4

ML13225A387
Person / Time
Site:	Sequoyah
Issue date:	08/09/2013
From:	James Shea Tennessee Valley Authority
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
TAC MF0481, TAC MF0482
Download: ML13225A387 (82)

Text

Tennessee Valley Authority, 1101 Market Street, Chattanooga, Tennessee 37402 August 9, 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 I 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)

References:

1. TVA 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," dated April 26, 2013 (ADAMS Accession No. ML13109A515)

3. NRC Letter to WVA, "Requests for Additional Information for the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application, Set 6,"

dated June 11, 2013 (ADAMS Accession No. ML13144A712)

4. Letter to TVA, "Requests for Additional Information for the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application," dated June 21, 2013 (ADAMS Accession No. ML13144A734)

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 4/Buried Piping, Set 8, and Set 9," dated July 25, 2013 Po3p5 P

rinted on recycled paper K, s e

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U.S. Nuclear Regulatory Commission Page 2 August 9, 2013 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 license for the Sequoyah Nuclear Plant (SQN), Units 1 and 2. The request would extend the license for an additional 20 years beyond the current expiration date.

By Reference 2, the NRC forwarded a request for additional information (RAI) labeled Set 1.

The required date for responding to RAI B.1.34-5 from Set 1 was within 60 days of the date stated in the RAI (i.e., no later than June 25, 2013). However, the NRC License Renewal Project Manager, Richard Plasse, gave TVA a verbal extension for this response until August 9, 2013. Enclosure 1 to this letter provides TVA's response to RAI B.1.34-5.

By Reference 3, the NRC forwarded an RAI labeled Set 6. The required date for the response to certain RAIs within Set 6 was within 60 days of the date stated in the RAI (i.e., no later than August 12, 2013). Enclosure 2 to this letter provides TVA's response to the Set 6/60-day RAIs.

By Reference 4, the NRC forwarded an RAI labeled Set 7. The required date for the response to certain RAIs within Set 7 was within 60 days of the date stated in the RAI (i.e., no later than August 20, 2013). Enclosure 3 to this letter provides TVA's response to the Set 7/60-day RAIs.

By Reference 5, TVA submitted a response to the NRC's RAI Set 4/Buried Piping that included RAIs 1.4-2, 1.4-3 and 1.4-4. In the August 5 and 6, 2013 telecoms, Mr. Plasse requested clarification with regard to these three questions. Enclosure 4 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 9 th day of August, 2013.

Respe ly, J.

Shea c President, Nuclear Licensing Enclosures cc: See Page 3

U.S. Nuclear Regulatory Commission Page 3 August 9, 2013 HL:EDS

Enclosures:

1. TVA Responses to NRC Request for Additional Information: Set 1/RAI B.1.34-5

2. TVA Responses to NRC Request for Additional Information: Set 6/60-day

3. TVA Responses to NRC Request for Additional Information: Set 7/60-day

4. Revised Responses to RAI Questions 1.4-2, 1.4-3 and 1.4-4

5. Regulatory Commitment List, Revision 5 cc (Enclosures):

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

ENCLOSURE I Tennessee Valley Authority Sequoyah Nuclear Plant, Units I and 2 License Renewal TVA Responses to NRC Request for Additional Information: Set I/RAI B.1.34-5

ENCLOSUREI Tennessee Valley Authority Sequoyah Nuclear Plant, Units I and 2 License Renewal TVA Responses to NRC Request for Additional Information: Set I/RAI B.1.34-5 RAI B. 1.34-5

Background:

The applicant's response to A/LAI No. 2 in LRA Appendix C states "SQN reviewed the information in Table 4-4 of MRP-191 and determined that there are no additional components contained in the SQN design. Table 4-4 of MRP-191 contains all of the RVI components that are within the scope of license renewal for SQN Units I and 2."

The staff noted that Table 4-4 of MRP-191 indicates that the "Control Rod Guide Tube Assemblies and Flow Downcomers: Guide plates/cards" were evaluated as Type 304 stainless steel. Similarly, Table 3-3 in MRP-227-A indicates that the guide plates (cards) were evaluated as Type 304 stainless steel. However, LRA Table 3.1.2-2 indicates that the "control rode guide tube assembly and downcomer: guide cards and plates" are fabricated from cast austenitic stainless steel (CASS) and are considered a "No Additional Measures" component for managing reduction of fracture toughness.

AILAI No. 7 states, in part, that it would apply to components fabricated from materials susceptible to thermal and/or irradiation embrittlement for which an individual licensee has determined aging management is required, for example during their review performed in accordance with Applicant/License Action Item No. 2. The plant-specific analysis shall be consistent with the plant's licensing basis and the need to maintain the functionality of the components being evaluated under all licensing basis conditions of operation. The applicants/licensees shall include the plant-specific analysis as part of their submittal to apply the approved version of MRP-227.

Issue:

It is not clear whether the results in Table 4-4 in MRP-191 and Table 3-3 in MRP-22 7-A for the Type 304 stainless steel guide plates (cards) is applicable to the applicant's CASS guide plates/cards and whether the applicant's response to A/LAI No. 2 is accurate. In addition, considering that the applicant's guide plate (cards) are fabricated of CASS, it appears that this component should be evaluated as part of AILAI No. 7 to consider the possible loss of fracture toughness due to thermal and irradiation embrittlement and, if applicable, the limitations on accessibility for inspection and the resolution/sensitivity of the inspection techniques.

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Request:

Considering that the applicant's guide plates (cards) are fabricated of CASS, clarify the applicability of the MRP-191 and MRP-227-A that evaluated the guide plates (cards) as Type 304 stainless steel.

Confirm that there are no other discrepancies in material fabrication of components evaluated in MRP-191 and MRP-227-A with those at the applicant's site. If there are other discrepancies, provide the component (including material) and justify the aging effects and the inspection category, techniques, coverage, and frequency to account for the material differences. Revise the LRA and the response to A/LAI No. 2, as needed.

Since the guide plates (cards) are fabricated from CASS, describe and justify the plant-specific analysis performed in response to A/LAI No. 7 that considers the possible loss of fracture toughness in these components due to thermal and irradiation embrittlement, and, if applicable, the limitations on accessibility for inspection and the resolution/sensitivity of the inspection techniques.

Revise the response to A/LAI Nos. 2 and 7, as necessary.

TVA Response to RAI B.1.34-5 NRC Request #1:

Considering that the applicant's guide plates (cards) are fabricated of CASS, clarify the applicability of the MRP-191 and MRP-227-A that evaluated the guide plates (cards) as Type 304 stainless steel.

TVA Response

1. A detailed review of the materials of fabrication for reactor internals at Sequoyah (SQN)

Units 1 and 2 determined that the guide plates (cards) might have been fabricated from ASTM A351 Grade CF8 cast austenitic stainless steel (CASS) as an alternative material to the ASTM A240 Type 304 wrought stainless steel considered in the Materials Reliability Program (MRP) generic assessment of the guide plates (cards). Table 4-4 of MRP-1 91 identified the guide plates (cards) as being fabricated from ASTM SA240 Type 304 stainless steel in Westinghouse plants. In the generic aging management plan, the MRP-227-A, Table 3-3, summary categorized them as primary inspection components based on a single degradation mechanism, wear. In the generic effort, the degradation mechanisms of irradiation and thermal embrittlement were not considered potential aging mechanisms for the guide plates (cards) since these are not viable degradation mechanisms if the parts are fabricated from ASTM SA240 Type 304 wrought stainless steel. In the event that these components may have been fabricated from the alternative material, ASTM A351 Grade CF8 CASS, as allowed on the plant drawings, irradiation and thermal embrittlement must be considered potential aging mechanisms.

An Expert Panel, therefore, considered the potential impact of the additional mechanisms for aging degradation of guide plates (cards) fabricated from ASTM A351 Grade CF8 CASS.

The results of the failure mode, effects, and criticality analysis (FMECA) conducted consistent with the generic processes concluded that:

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In the case of irradiation embrittlement, due to their location with respect to the core, the accumulated fluence for guide plates (cards) would still be too low to induce irradiation embrittlement in ASTM A351 Grade CF8 CASS. This is true even if the criterion is the lX 1017 neutrons/cm 2 screening level recommended by NRC Letter, "License Renewal Issue No. 98-0030, "Thermal Embrittlement of Cast Austenitic Stainless Steel Components," dated May 19, 2000, (ADAMS # ML003717179), that takes into account potential synergistic thermal and irradiation embrittlement of CASS.

In the case of thermal embrittlement, the Expert Panel identified that these components could be susceptible to thermal embrittlement if the material contained a sufficiently high fraction of ferrite. In the absence of more detailed compositional information a conservative assumption of the possible alloy compositions leads to the conclusion that the cards would be potentially susceptible to thermal embrittlement.

The FMECA process identified that the potential susceptibility to thermal embrittlement introduced possible "loose parts" as a failure effect in addition to "misalignment of guide tubes". The expert panel concluded that the consequence of damage did not change significantly as a result of this additional failure effect. Given that the likelihood of failure due to the wear mechanism was already ranked as high, the expert panel concluded that potential susceptibility to thermal embrittlement had no impact on the FMECA ranking for the guide plates (cards) and they remained in FMECA group 3.

While the FMECA category for the component did not change, the MRP-227-A aging management sampling process required the Expert Panel to evaluate the potential for a change in the overall component inspection ranking and technique requirements due to the additional degradation mechanisms relative to all of the components considered in the sample. The Expert Panel determined that there was no impact on the overall MRP-227-A inspection requirements as a result of the potential for CASS guide plates (cards) to have been used at either of the SQN units.

NRC Request #2:

Confirm that there are no other discrepancies in material fabrication of components evaluated in MRP-191 and MRP-227-A with those at the applicant's site. If there are other discrepancies, provide the component (including material) and justify the aging effects and the inspection category, techniques, coverage, and frequency to account for the material differences. Revise the LRA and the response to A/LAI No.2, as needed.

TVA Response

2.

In addition to the finding that SQN Units 1 and 2 guide plates (cards) could have been fabricated from the alternative CASS material, the evaluation of plant records discovered that the drawings for three other sets of MRP-1 91 components in addition to the guide plates (cards) permitted the use of ASTM A351 Grade CF8 CASS as an alternate material.

The specific sets of components were the upper guide tube enclosures, upper guide tube housing plates, and upper instrumentation brackets, clamps, terminal blocks and conduit straps.

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The Expert Panel considered the implications of the use of the CASS material on the potential additional aging degradation mechanisms that had not been considered in MRP-191 and MRP-227-A where these components were assumed to be fabricated from ASTM FA240 Type 304 wrought stainless steel. In a similar manner to the considerations of the CASS guide plates (cards,) the additional degradation mechanisms that were identified were irradiation and thermal embrittlement. Table 1 presents the components that were identified by the investigation as being potentially fabricated from the alternative material and provides the Expert Panel's assessment of the potential for the susceptibility to the additional aging mechanisms of irradiation and thermal embrittlement.

Table I SQN Units I & 2 Additional Components that May Have Been Fabricated from Alternative Material A351 CF8 Component Irradiation Embrittlement Thermal Embrittlement Upper Guide Tube No - Location from the core Potentially Susceptible Enclosures further than 1017n/cm 2 regime Upper Guide Tube Housing No - Location from the core Potentially Susceptible Plates further than 1017n/cm 2 regime Upper Instrumentation No - Location from the core Potentially Susceptible Brackets, Clamps, Terminal further than 1017 n/cm 2 Blocks, Conduit Straps regime The Expert Panel included all of these components in the updated FMECA effort based on their fabrication from CASS ASTM A351 Grade CF8 CASS and compared it to the original FMECA results for the components based on the MRP-191 and MRP-227-A assumption of their fabrication from ASTM SA240 Type 304 wrought stainless steel. The FMECA analysis considered the impact of the newly identified potential failure modes, identifying the likelihood of failure from these modes and also the consequences of such potential failures.

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The results of this comparison are summarized in Table 2.

Table 2 FMECA Analysis for the Additional Components of SQN Units I and 2 RVI that Might have been Fabricated from CASS ASTM A351 CF8 Wrought ASTM A240 Type 304 CASS ASTM A351 Grade CF8 Component Likelihood Likelihood FMECA Likelihood Likelihood FMECA of Failure of Damage Group of Failure of Damage Group Upper Guide Low Medium 1

Low Medium 1

Tube Enclosures Upper Guide None 0

Low Low 1

Tube Housing Plates Upper None 0

Low Low 1

Instrumentation

Brackets, Clamps, Terminal Blocks, Conduit Straps The expert panel considered the impact of the possible material changes on the overall aging management strategy. Considering the possible changes identified in Table 2, the expert panel concluded that the components remained in the "no additional measures" category and that the aging management strategy is not affected by the possible materials changes in these components.

NRC Request #3:

Since the guide plates (cards) are fabricated from CASS, describe and justify the plant-specific analysis performed in response to AILAI No. 7 that considers the possible loss of fracture toughness in these components due to thermal and irradiation embrittlement, and, if applicable, the limitations on accessibility for inspection and the resolution/sensitivity of the inspection techniques.

TVA Response

3. The evaluation of potential aging degradation mechanisms identified thermal embrittlement (but not irradiation embrittlement) as an additional potential aging degradation mechanism for guide plates (cards) if they were fabricated from the alternative ASTM A351 Type CF8 CASS. Based on the information available, the plant specific evaluation adopted the conservative approach that, in the absence of clarifying information, the guide plates (cards) would have to be considered potentially susceptible to thermal embrittlement. Thus, for El - 5 of 13

SQN Units 1 and 2, additional considerations must be incorporated into the inspections recommended in MRP-227-A in order to account for this difference in materials between those that may have been used in the plant's guide plates (cards) and those considered in MRP-191.

The expert panel FMECA for the guide plate (cards) took into account their possible loss of fracture toughness due to the thermal embrittlement. The panel concluded that the damage as a result of potential thermal embrittlement would be loss of small sections of the guide plates (cards) leading to possible liberation of small loose parts and degradation of the control rod drop functions if the loading on the guide plates (cards) was sufficient to produce fractures. Assessment of the expected loadings of the guide plates (cards) indicated that the stresses in the plates (cards) would be low and that cracking of the plates (cards) would be less likely than in other, more highly loaded and potentially thermally embrittled components. Inspections to manage possible thermal embrittlement of CASS guide plates (cards) should therefore address the possible loss of material sections of the guide plate (card) profiles themselves and also the possible existence of thermal embrittlement derived cracking in other components that have been identified, by virtue of their operating considerations, as more susceptible to cracking than the guide plates (cards).

The use of VT-3 inspections is still relevant to inspect for the consequential damage of thermal embrittlement of the guide plates (cards). The consequential damage that would result from possible thermal embrittlement in the guide plates (cards) would be the loss of small sections of the guide plates (cards) and possible impairment of the individual control rod drop functions. These consequences are identical to those already considered in MRP-227-A for wear of the ASTM SA240 Type 304 stainless steel guide plates (cards). As a result of these concerns, MRP-227-A already called for VT-3 inspection of the guide plates (cards). Specifically these inspections are to address the loss of guide plate (card) profile as a result of possible wear. VT-3 inspections monitoring guide plate (card) profiles for wear have the capability to also identify loss of material sections that occur by fractures resulting from loss of toughness due to thermal embrittlement. Since VT-3 inspections are already called for to manage aging degradation of the guide plates (cards) due to wear, the same inspections should be adequate to monitor for the loss of guide plate (card) sections due to thermal embrittlement.

Even though the guide plates (cards) are primary components in the aging management strategy, there are other components that would be expected to exhibit signs of cracking due to thermal embrittlement in advance of the guide plates (cards). Specifically, MRP-1 91 identified the control rod guide tube (CRGT) lower flange welds as lead components for assessing thermal embrittlement of CASS or austenitic weld structures. These welds possess the "austenite plus ferrite" structures that are similar to CASS and are expected to embrittle thermally in a similar manner to CASS. As a result of their expected service loadings and their expected weld residual stresses, these welds are expected to be subjected to greater tensile stresses than any regions of the guide plates (cards). As a consequence of this greater loading, the welds are expected to exhibit thermal embrittlement assisted cracking in advance of the guide plates (cards). MRP-227-A El - 6 of 13

identified the CRGT lower flange welds as the primary components for inspection to monitor for cracking that might result from thermal embrittlement. MRP-227-A called out high resolution enhanced VT-1 inspections to assess these welds for such signs of cracking.

Given these factors, the CRGT lower flange welds are expected to be leading indicator components of thermal damage compared to the guide plates (cards). Enhanced VT-1 inspections of these welds should reveal signs of aging degradation due to thermal embrittlement before similar degradation is manifested in the guide plates (cards). Given that these inspections are already scheduled under MRP-227-A, no further inspections are required to monitor for thermal embrittlement of CASS or austenitic welded components in the event that the guide plates (cards) in SQN Units 1 and 2 may have been fabricated from the alternative ASTM A351 grade CF8 CASS.

NRC Request #4:

0 Revise the response to A/LAI Nos. 2 and 7, as necessary.

TVA Response

4. Changes to Applicant/License Action Items (AILAIs) 2 and 7 follow with additions underlined and deletions lined through.

Response to A/LAI #2 "MRP-189 and Table 4-5 of MRP-191 are not applicable to SQN. SQN reviewed the information in Table 4-4 of MRP-191 and determined that although there are no additional components contained in the SQN design. there are components potentially fabricated from a different material than that evaluated in MRP-191. The control rod guide plates (cards), upper guide tube enclosure tubes, upper guide tube housing plates, and upper instrumentation brackets, clamps, terminal blocks and conduit straps are potentially fabricated from cast austenitic stainless steel (CASS) ASTM A351 grade CF8.

Evaluation of these components as if they were fabricated from CASS does not lead to any modifications to the program defined in MRP-227-A. Tabble 4-4 of MRP 191 contains

-all of. t-ho -R-VI comYpoents# that aro Within the scope Of licence rene.Wal for SQN UiJRts, 1 aAid-2-*.

Response to A/LAI #7 "The lower support column bodies at SQN are fabricated from forged Type 304 and 304a stainless steel. Therefore, no site-specific analysis is necessary for the lower support column bodies.

The lower core support plates in Units 1 and 2 are fabricated from CF8 CASS.

However, based on the certified material test report and the determination of susceptibility to reduction in fracture toughness due to thermal embrittlement described in NUREG-CR-4513, the lower core support plate is not subject to reduction in fracture toughness due thermal embrittlement because the delta ferrite concentration of the plate material is less than 8% in both units In addition, according to MRP-1 91, the lower core support plate is not subject to El - 7 of 13

reduction in fracture toughness due to irradiation embrittlement. Therefore the lower core support plate will maintain its functionality under all licensing basis conditions of operation. The Reactor Vessel Internals Program will continue to manage the effects of aging on the lower core support plate as an expansion component."

The control rod guide plates (cards), upper guide tube enclosure tubes, upper guide tube housing plates, and upper instrumentation brackets, clamps, terminal blocks and conduit straps are potentially fabricated from cast austenitic stainless steel (CASS) ASTM A351 grade CF8.

The evaluation of aging degradation mechanisms identified thermal embrittlement (but not irradiation embrittlement) as an additional potential aging degradation mechanism for guide plates (cards) if they were fabricated from the alternative material, ASTM A351 Type CF8 CASS. The plant specific evaluation adopted the conservative approach that, in the absence of clarifying information, the guide plates (cards) would be considered susceptible to thermal embrittlement. Thus, for Sequoyah Units 1 and 2, additional considerations must be incorporated into the inspections recommended in MRP-227-A in order to account for this difference in materials between those that may have been used in the plant's guide plates (cards) and those considered in MRP-1 91.

An Expert Panel considered the potential impact of the additional mechanisms for aging degradation of guide plates (cards) fabricated from ASTM A351 Grade CF8 CASS.

The expert panel failure mode, effects, and criticality analysis (FMECA) for the guide plate (cards) took into account their possible loss of fracture toughness due to the thermal embrittlement. The panel concluded that the damage as a result of potential thermal embrittlement would be loss of small sections of the guide plates (cards) leading to possible liberation of small loose parts and degradation of the control rod drop functions if the loading on the guide plates (cards) was sufficient to produce fractures.

Assessment of the expected loadings of the guide plates (cards) indicated that the stresses in the plates (cards) would be low and that cracking of the plates (cards) would be less likely than cracking in other, more highly loaded and potentially thermally embrittled components. Inspections to manage possible thermal embrittlement of CASS guide plates (cards) should, therefore, address the possible loss of material sections of the guide plate (card) profiles themselves and also the possible existence of thermal embrittlement derived cracking in other components that have been identified, by virtue of their operating considerations, as more susceptible to cracking than the guide plates (cards).

The use of VT-3 inspections is still relevant to inspect for the consequential damage of thermal embrittlement of the guide plates (cards). The consequential damage that would result from possible thermal embrittlement in the guide plates (cards) would be the loss of small sections of the guide plates (cards) and possible impairment of the individual control rod drop functions. These consequences are identical to those already considered in MRP-227-A for wear of the ASTM SA240 Type 304 stainless steel guide El - 8 of 13

plates (cards). As a result of these concerns, MRP-227-A already called for VT-3 inspection of the guide plates (cards). Specifically, these inspections are to address the loss of guide plate (card) profile as a result of possible wear. VT-3 inspections monitoring guide plates (cards) profiles for wear have the capability to also identify loss of guide plate (card) sections that occur by fractures resulting from loss of toughness due to thermal embrittlement. Since VT-3 inspections are already called for to manage aging degradation of the guide plates (cards) due to wear, the same inspections should be adequate to monitor for aging degradation due to thermal embrittlement.

Even though the guide plates (cards) are primary components in the aging management strategy, there are other components expected to exhibit signs of cracking due to thermal embrittlement in advance of the guide plates (cards). Specifically, MRP-191 identified the control rod guide tube (CRGT) lower flange welds as lead components for assessing thermal embrittlement of CASS or austenitic weld structures. These welds possess the "austenite plus ferrite" structures that are similar to CASS and are expected to embrittle thermally in a similar manner to CASS. As a result of their expected service loadings and their expected weld residual stresses, these welds are expected to be subjected to greater tensile stresses than any regions of the guide plates (cards). As a consequence of this -greater loading, the welds are expected to exhibit thermal embrittlement assisted cracking in advance of the guide plates (cards). MRP-227-A identified the CRGT lower flange welds as the primary components for inspection to monitor for cracking that might result from thermal embrittlement. MRP-227-A called out high resolution enhanced VT-1 inspections to assess these welds for such signs of cracking. Given these factors, the CRGT lower flange welds are expected to be leading indicator components of thermal damage compared to the guide plates (cards).

Enhanced VT-1 inspections of these welds should reveal signs of aging degradation due to thermal embrittlement before similar degradation is manifested in the guide plate (cards). Given that these inspections are already scheduled under MRP-227-A, no further inspections are required to monitor for thermal embrittlement of CASS or austenitic welded components in the event that the guide plates (cards) in Sequoyah Units 1 and 2 may have been fabricated from the alternative ASTM A351 grade CF8 CASS.

The Expert Panel considered the implications of the use of the CASS material on the potential additional aging degradation mechanisms that had not been considered in MRP-191 and MRP-227-A where upper guide tube enclosures, upper guide tube housing plates, and upper instrumentation brackets, clamps, terminal blocks and conduit straps components were assumed to be fabricated from ASTM A240 Type 304 wrought stainless steel. In a similar manner to the considerations of the CASS guide plates (cards), the additional degradation mechanisms that were identified were irradiation and thermal embrittlement. Table 1 presents the components that were identified by the investigation as being potentially fabricated from the alternative material and provides the Expert Panel's assessment of the potential for the susceptibility to the additional aging mechanisms of irradiation and thermal embrittlement.

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Table I Sequoyah Units I & 2 Additional Components that May Have Been Fabricated from Alternative Material A351 CF8 Component Irradiation Embrittlement Thermal Embrittlement Upper Guide Tube Enclosures No - Location from the core Potentially Susceptible further than 100"n/cm2 regime Upper Guide Tube Housinq No - Location from the core Potentially Susceptible Plates further than 1017n/cm 2 regime Upper Instrumentation No - Location from the core Potentially Susceptible Brackets, Clamps, Terminal further than 101'n/cm2 regime Blocks, Conduit Straps The Expert Panel included all of these components in the updated FMECA effort based on their fabrication from CASS ASTM A351 Grade CF8 CASS and compared it to the original FMECA results for the components based on the MRP-191 and MRP-227-A assumption of their fabrication from ASTM SA240 Type 304 wrought stainless steel.

The FMECA analysis considered the impact of the newly identified potential failure modes, identifying the likelihood of failure from these modes and also the consequences of such potential failures. The results of this comparison are summarized in Table 2.

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Table 2 FMECA Analysis for the Additional Components of Sequoyah Units I and 2 RVI that Miaht have been Fabricated from CASS ASTM A351 CF8 Wrought ASTM A240 Type 304 CASS ASTM A351 Grade CF8 Component Likelihood Likelihood FMECA Likelihood Likelihood FMECA of Failure of Damage Group of Failure of Damage Group Upper Guide Low Medium 1

Low Medium 1

Tube Enclosures Upper Guide None 0

Low Low 1

Tube Housing Plates Upper None 0

Low Low 1

Instrumentation Brackets, Clamps, Terminal Blocks, Conduit Straps The expert panel considered the impact of the possible material changes on the overall aging management strategy. Considering the possible changes identified in Table 2, the expert panel concluded that the components remained in the "no additional measures" category and that the aging management strategy is not affected by the possible materials changes in these components."

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The changes to LRA Table 3.1.2-2 line items follow with additions underlined and deletions lined through.

Component Intended Aging Effect Aging NUREG-Table 1 Material Environment Requiring Management 1801 1tm]

Notes Type Function Management Program 1801 Item Item Upper Core Support Assembly Control rod guide Structural Stainless Treated Cracking Reactor IV.B2.RP-3.1.1-53 A

tube assembly and support steel borated Vessel 265 downcomer:

flow water Internals (N)

- Upper guide tube distribution

>140°F Water enclosures Chemistry -

• Housing plates Primary and

" Water flow slot Secondary ligaments Control rod guide Structural Stainless Treated Loss of Water IV.B2.RP-24 3.1.1-87 A

tube assembly and support steel borated material Chemistry -

downcomer:

flow water Primary and

- Upper guide tube distribution

>140°F Secondary enclosures

" Housing plates

" Water flow slot ligaments Control rod -guide Structural CASS Treated Cracking Reactor IV.B2.RP-3.1.1-53 A

tube assembly and suppo borated Vessel 265 downcomer:

flow water Internals (N)

• Upper guide tube distribution

>4820F Water enclosures Chemistry -

- Housinq plates Primary and Secondary Control rod guide Structural CASS Treated Loss of Water IV.B2.RP-24 3.1.1-87 A

tube assembly and support borated material Chemistry-downcomer:

flow water Primary and

- Upper guide tube distribution

>4820F Secondary enclosures

- Housing plates El - 12 of 13

Control rod -guide Structural CASS Treated Reduction in Reactor IV.B2.RP-3.1.1-A tube assembly and support borated fracture Vessel 267 59 downcomer:

flow water toughness Internals (N)

- Upper guide tube distribution

>4820F enclosures

- Housing plates Incore Instrumentation Support Structure Upper Structural Stainless Treated Cracking Reactor IV.B2.RP-3.1.1-A instrumentation support steel or borated Vessel 265 53 conduit and CASS water Internals (N) supports

>40§F Water

" Brackets

>482 0F Chemistry -

" Clamps Primary and

" Terminal blocks Secondary

" Conduit straps Upper Structural Stainless Treated Loss of Water IV.B2.RP-24 3.1.1-A instrumentation support steel or borated material Chemistry -

87 conduit and CASS water Primary and supports

>1440-F Secondary

" Brackets

>4820F

" Clamps

• Terminal blocks

• Conduit straps Upper Structural CASS Treated Reduction in Reactor IV.B2.RP-3.1.1-A instrumentation support borated fracture Vessel 267 59 conduit and water toughness Internals (N) supports

>4820F

• Brackets

• Clamps

• Terminal blocks

• _Conduit straps El - 13 of 13

ENCLOSURE 2 Tennessee Valley Authority Sequoyah Nuclear Plant, Units I and 2 License Renewal TVA Responses to NRC Request for Additional Information: Set 6/60-day

ENCLOSURE 2 Tennessee Valley Authority Sequoyah Nuclear Plant, Units 1 and 2 License Renewal TVA Responses to NRC Request for Additional Information: Set 6/60-day RAI B. 1.41-4

Background:

License renewal application (LRA) Section B. 1.41 states that this program is a new program to manage cracking and reduction in fracture toughness due to thermal aging embrittlement in cast austenitic stainless steel (CASS) piping and piping components, consistent with the Generic Aging Lessons Learned (GALL) Report aging management program (AMP) X1.M12, "Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program (CASS)." GALL Report AMP Xl. M12 states that flaw tolerance evaluation for components with a ferrite content up to 25 percent is performed according to the principles associated with ASME Code,Section XI, IWB-3640 for submerged arc welds. The GALL Report also states that flaw tolerance evaluation for piping with greater than 25 percent ferrite is performed on a case-by-case basis by using the applicant's fracture toughness data.

Issue:

The LRA does not address whether the applicant has any susceptible CASS components with a ferrite content greater than 25 percent. In addition, the LRA does not clearly address whether the flaw tolerance evaluation for susceptible CASS components with greater than 25 percent ferrite will be performed on a case-by-case basis in the applicant's program. The staff also needs additional information regarding the high-ferrite CASS components in the applicant's program and flaw tolerance evaluation for the components.

Request:

1. Clarify whether the applicant has any susceptible CASS components with a ferrite content greater than 25 percent.

2. If the applicant has any susceptible CASS components that have a ferrite content greater than 25 percent, provide the following information for the CASS components: (1) component name, (2) casting method and material grade (e.g., centrifugally cast CF8M), (3) ferrite content based on a method consistent with GALL Report AMP XI.M12, (4) clarification as to whether applicant's flaw tolerance evaluation will be performed on a case-by-case basis using relevant fracture toughness data, and (5) applicant's methodology to be used in the flaw tolerance evaluation and the technical basis for the methodology.

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TVA Response to RAI B.1.41-4

1. Using the Hull's equivalent factors (described in NUREG/CR-4513, Rev. 1) method, eight sections of Sequoyah (SQN) Unit 2 Cast Austenitic Stainless Steel (CASS) piping components have a ferrite content greater than 25%. No SQN Unit 1 CASS piping has a ferrite content greater than 25%. Where chemistry data did not exist, molybdenum was conservatively assumed to be 0.5% (the maximum permitted for Grade CF8, per ASME requirements) and nitrogen was assumed to be 0.04% (per the guidance in NUREG/CR-4513, Rev. 1).

2. (1) and (3): The eight sections of SQN Unit 2 piping components that have ferrite content greater than 25% have the following heat numbers and delta ferrite content:

B-2408 (delta ferrite 26.51%), C-2199A (26.46%), C-2199B (26.46%), C-2260A (33.24%), C-2260B (33.24%), C-2216A (26.56%), C-2216B (26.56%), C-2317 (25.57%)

(2): All eight sections of the SQN Unit 2 piping components are centrifugally cast CF8M.

(4): As stated in LRA section B.1.41, the new Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program will be consistent with the program described in NUREG-1801,Section XI.M12. Consistent with of NUREG-1801,Section XI.M1 2, a flaw tolerance evaluation for the CASS components will be performed on a case-by-case basis using relevant fracture toughness data.

(5): A flaw tolerance evaluation will be performed with an approach such as the probabilistic fracture mechanics (PFM) method for CASS piping; as referenced in Commitment #32. A PFM approach has been incorporated into an ASME Section Xl Code Case for approval by the Code Committee. This approach defines the material properties such as strength and toughness in terms of probability distribution functions.

The toughness distributions for potentially susceptible materials are determined using information obtained from the certified material test reports (CMTRs), or equivalent, to calculate the delta ferrite content for the various heats of the affected CASS components, which can be correlated to toughness. These toughness distributions are used for the flaw tolerance evaluations considering the plant-specific geometry and design stresses of the piping system.

This approach is particularly useful for evaluation of CASS components where the identified delta ferrite levels are greater than 25%. The modeling of toughness in the PFM method relies on the Chopra relationships between Cvsat (saturated Charpy impact energy) and the J-R curve for fully saturated, thermal aged CASS materials given in NUREG/CR-4513, Rev. 1. In that report, Chopra defines relationships for the various types of CASS materials including CF8M. Those relationships have been included in the PFM model, along with variations or scatter in the known materials parameters. When a probabilistic analysis is performed, the model samples for a range of known (or estimated) material variables to produce a distribution of the J-R curve toughness.

The output is characterized as quantiles (i.e., percent probability) of the various levels of material J-resistance curve toughness which are then used to calculate maximum E2 - 2 of 18

allowable flaw depths for a specific (very low) probability of failure based on crack tip stability, or instability, of the assumed cracks in the elastic-plastic fracture mechanics (EPFM) analysis. If the delta ferrite content is not known precisely for each component location, then generic ranges are defined for three different populations of CF8M materials:

1)

Delta ferrite content between 20 and 25%,

2)

Delta ferrite content between 25 and 30%, and

3)

Delta ferrite content exceeding 30%.

The PFM model interprets these inputs from a sampling of the distribution of the input variables and gives an output as a distributed function of the J-R curve toughness.

Materials with greater than 25% delta ferrite content require a slight extrapolation of the Chopra model beyond the normal applicability region (i.e., 20 - 25%).

While reviewing the CASS materials, it was determined that the regenerative heat exchanger channel heads are made of CASS materials as well as stainless steel. This clarification has been entered in the TVA corrective action program for resolution.

The changes to LRA Attachment A, Attachment B, and Table 3.3.2-10 follow with additions underlined.

"A.1.41 Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program "The Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program manages the aging effects of cracking and reduction in fracture toughness in cast austenitic stainless steel (CASS) components. The program consists of a determination of the susceptibility of CASS piping, piping components, and piping elements and the pressurizer spray head and regenerative heat exchanger shell and channel head to thermal aging embrittlement based on casting method, molybdenum content, and percent ferrite. For potentially susceptible components, aging management is accomplished through qualified visual inspections, such as enhanced visual examination, qualified ultrasonic testing methodology, or component-specific flaw tolerance evaluation in accordance with ASME Section Xl code, 2001 Edition 2003 addendum. Applicable industry standards and guidance documents are used to delineate the program. A flaw tolerance evaluation for flaws detected in CASS components with >25% ferrite will be performed using a probabilistic fracture mechanics (PFM) approach and plant-specific data."

B.1.41 Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program Description "The Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program is a new program that manages the aging effects of cracking and reduction in fracture toughness in CASS components.

The program consists of a determination of the susceptibility of CASS piping, piping components, and piping elements and the pressurizer spray head and regenerative heat exchanger shell and channel head to thermal aging embrittlement based on casting method, molybdenum content, and percent ferrite.

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For potentially susceptible components, aging management is accomplished through qualified visual inspections, such as enhanced visual examination, qualified ultrasonic testing methodology, or component-specific flaw tolerance evaluation in accordance with ASME Section Xl code, 2001 Edition 2003 addendum. Applicable industry standards and guidance documents are used to delineate the program. A flaw tolerance evaluation for flaws detected in CASS components with >25% ferrite will be performed usingq a probabilistic fracture mechanics (PFM) approach and plant-specific data."

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The changes to Table 3.3.2-10 follow:

Table 3.3.2-10:

Chemical and Volume Control Svstem Aging Effect Aging Component Intended Requiring Management NUREG-1801 Type Function Material Environment Management Program Item Table I Item Notes Heat Pressure CASS Air-indoor None None VII.J.AP-123 3.3.1-120 C

exchanger boundary (ext)

(channel head)

Heat Pressure CASS Treated Cracking Inservice VII.E1.AP-3.3.1-8 A

exchanger boundary borated water Inspection 119 (channel

> 4820F (int) head)

Heat Pressure CASS Treated Cracking Water Chemistry VII.E1.AP-3.3.1-20 A,

exchanger boundary borated water Control - Primary 118 301 (channel

> 482°F (int) and Secondary head)

Heat Pressure CASS Treated Cracking -

TLAA - metal VII.E1.A-3.3.1-2 A

exchanger boundary borated water fatigue fatigue 100 (channel

> 4820F (int)

Heat Pressure CASS Treated Loss of Water Chemistry VII.E1.AP-3.3.1-29 C

exchanger boundary borated water material Control - Primary 79 (channel

> 4820F (int) and Secondary head)

Heat Pressure CASS Treated Reduction of Thermal Aging V.D1.E-47 3.2.1-10 C

exchanger boundary borated water fracture Embrittlement of (channel

> 4820F (int) toughness CASS head)

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RAI 4.1-7

Background:

Paragraph 54.21 (c) indicates that license renewal applicants must include a list of TLAAs, as defined in 10 CFR 54.3 and that all identified TLAAs must be dispositioned in accordance with one of the three acceptance criteria that are specified in 10 CFR 54.21 (c)(1).

Issue:

During the staffs safety audit of the AMPs for mechanical systems in the LRA (i.e., the NRC's audit of March 18 - 22, 2013), the staff noted that the design analyses of for the following reactor coolant system or non-Safety Class 1/non-Safety Class A components may include cyclic assumptions based on 40 years of operation: (a) non-class 1 flexible connections and instrumentation flexible hoses in the reactor coolant system pressure boundary; (b) flexible hose and flexible joints in the component cooling water system; (c) expansion joints in spent fuel cooling systems; and (d) flexible hoses in essential raw cooling water System. However, the applicant has not identified these analyses as TLAAs in accordance with 10 CFR 54.21(c)(1) or provide appropriate justifications that these analyses would not need to be identified as TLAAs, when compared to the six criteria in 10 CFR 54.3 for defining a plant analysis as a TLAA.

Request:

1. Clarify how the design analyses of each of the components in items (a) through (d) above compares to the six criteria for a TLAA as defined in 10 CFR 54.3.

2. Based on the response to Part a. of this request for additional information (RAI), justify whether the design analysis for each of the components should be identified as a TLAA in accordance with 10 CFR 54.21 (c)(1). If the given analysis does need to be identified as a TLAA, amend the LRA accordingly and provide the basis for dispositioning the TLAA in accordance with 10 CFR 54.21(c)(1)(i), (ii), or (iii).

3. Identify any additional design analyses for non-Class 1 non-piping components in the CLB that should be identified as a TLAA in accordance with 10 CFR 54.21(c)(1).

TVA Response to RAI 4.1-7

1. The fatigue analyses for the components listed in items (a) through (d) of the Issue discussion of this RAI are considered to meet the definition of TLAA in 10 CFR 54.3.

2. As flexible connectors or expansion joints were identified during the aging management reviews, TVA searched the site records to determine whether there was an associated design analysis. If it exists, the design analyses for these components are considered TLAA. The components in items (a) through (d) above were qualified by the analyses for more cycles than are expected through the period of extended operation (PEO). To provide documentation of this review, the change to LRA Section 4.3.2.2 follows the response to Request 3 with additions underlined.

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3. Additional design analyses for non-Class 1 non-piping components that were not identified in LRA Section 4.3.2 are the design analyses for the flexible connectors in the following systems.

Fuel Oil System (Table 3.3.2-1)

Chemical and Volume Control System (Table 3.3.2-17-23)

Main Steam System (Table 3.4.2-1)

Main and Auxiliary Feedwater System (Table 3.4.2-2)

These flexible connectors were qualified by their analyses for more cycles than are expected through the PEO. The design analyses were determined to remain valid for the PEO in accordance with 10 CFR 54.21 (c)(1)(i).

The change to LRA Section 4.3.2.2 is a new paragraph added to the end and the addition of line items to the associated Section 3 tables. Additions are underlined.

"TLAAs were identified for flexible connections and expansion ioints included in LRA Tables 3.1.2-3. 3.3.2-1, 3.3.2-11, 3.3.2-12, 3.3.2-14, 3.3.2-17-23, 3.4.2-1, and 3.4.2-2.

The review of these analyses determined these flexible connectors were qualified for more cycles than are expected through the period of extended operation. The design analyses were determined to remain valid for the period of extended operation in accordance with 10 CFR 54.21 (c)(1)(i)."

Add to Table 3.1.2-3 Add Fe Nickel alloy 31e3dborated Crackinq-LAA-metal IIV.C2.R-31-A onnection lboundaryI wtr int gatigue atiq..

k23 Add to Table 3.3.2-1 FIn lx Pressure tainless iFuel (int)

Crackinq-L[nmetal onnection lboundasy steel fatique atigque Add to Table 3.3.2-11 o*lex Pressure tainless Rawwater (int)

Crackin -

_L.AAmetal onnection lboundary steel atique fa.que I

Add to Table 3.3.2-12 F[Fl Fx Pressure tainless

ýreated water mint) Cracking-LAA-metal onnection boundary steel fatique atigue Add to Table 3.3.2-14 Expansion Pressure Ptainless _Treated borated Crackinq-LAA-metal IVII.E1.A-57

.3.2 IC I Loint Lboundary Jsteel water tint atigue atique Add to Table 3.3.2-17-23 Flex Pressure Stainless reatedborated Crackinq-KAA-metal II.E1.A-57

.3.1-2 Q I Lg onnection Iboundary steel Iwater in*

Ifatigque Lafigyue Add to Table 3.4.2-1 Flex Pressu Nickel pteam (int) jICrackginq-

"-metal IV.D2.R-46 [3. 1-I Igo nnection bounda ay Ifaiqe fi.qe I

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RAI 4.1-9 Back.qround:

UFSAR Section 5.5.12 provides the applicant's design bases for valves that are part of the reactor coolant pressure boundary (i.e., for the Safety Class I or Class A valves in the plant design; that is the Group A valves) and identifies that the Group A valves for the facility were "designed and fabricated in accordance with ANSI B16.5, MSS-SP-66, and ASME Section IlI, 1968 Edition." UFSAR Table 3.2.2-1 lists a slightly different design basis for these valves by stating that the Group A valves were designed to MSS-SP-66, ANSI B16.5, and the draft ASME Code for Pumps and Valves.

Issue:

The LRA does not address the fatigue assessments or cyclical loading analyses that may have been required for the specific Group A valves. Specifically, the LRA does not identify the design code of record that was used to design each of the Group A valves for the facility or whether the design code for a given Group A valve would have required the applicant to perform a time-dependent fatigue analysis for the valve. The provisions in the Draft 1968 ASME Pump and Valve Code include applicable time-dependent cyclic or fatigue assessment criteria for Safety Class I or Class A valves exceeding 4-inches in nominal valve size. If a fatigue analysis was performed as part of the design basis for each of these valves, the applicant has not explained why the applicable fatigue analysis would not need to be identified as a TLAA in accordance with the requirement in 10 CFR 54.21(c)(1). Thus, the staff does not have sufficient information to determine whether the applicant should have identified any metal fatigue TLAAs for the Safety Class I or Class A valves that are included its plant design.

Request:

1. Group the Safety Class I valves or Safety Class A valves by design code(s) of record. For each group of Safety Class 1 valves or Class A valves, identify the design code(s) of record, and summarize how the specific design code addresses potential cyclical loading conditions.

2. In consideration of the response to Part I of the RAI, clarify whether the design code of record for the valves would have required the performance of fatigue analysis for the given Safety Class 1 or Class A valve. If so, clarify how the fatigue analysis compares to the six criteria for a TLAA as defined in 10 CFR 54.3 and justify why the given fatigue analysis would not need to be identified as a TLAA in accordance with 10 CFR 54.21(c)(1).

TVA Response to RAI 4.1-9

1. The Safety Class 1 valves or Safety Class A valves are grouped based on valve size. The design codes of record are different for the two size categories discussed below.

Safety Class 1 1 Safety Class A valves four inches or larger were procured as pre-code valves, meaning that they were designed to either a commercial standard such as USAS B1 6.5 or ASME Boiler and Pressure Vessel (B&PV) Code prior to the 1971 Edition.

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The Draft ASME Code for Pumps and Valves for Nuclear Plants, dated November 1968 (also known as the 1968 Draft Pump and Valve Code), was not used in the procurement of any of these valves. Editions of Section III of the ASME Code prior to 1971 do not require fatigue analysis. Additionally, the commercial standards do not require fatigue analysis. Therefore, no fatigue analysis was required as part of the design of the 4-inch or larger valves.

Safety Class 1 / Safety Class A valves less than 4 inches were procured as pre-code valves, to the 1968 Draft Pump and Valve Code, or to ASME Code Section II1. Because these valves are

<4 inch, a fatigue analysis is not required by ASME Section III, the 1968 Draft Pump and Valve Code, or the commercial standards.

2. As described in the response to item 1, the design codes of record for the SQN Units 1 and 2 valves do not require a fatigue analysis.

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RAI4.1-10

Background:

The applicant's metal fatigue analysis for the reactor vessel internal (RVI) components is given in LRA Section 4.3.1.2.

Issue:

LRA Table 4.3-4 identifies that the following RVI core support structure components were analyzed in accordance with fatigue analysis requirements in the ASME Code Section II1:

(a) control rod guide tube (CRGT) assembly support pins, and (b) lower core plate. The LRA states that the remaining RVI components were not subject to metal fatigue analyses because they were not designed to the ASME Code Section III requirements.

UFSAR Section 4.2.2 identifies that the RVI design includes both an "upper core support assembly" and a "lower core support assembly" and defines the RVI core support structure components that make up these assemblies. UFSAR Section 4.2.2 also states that the RVI core support structure assemblies and their components were analyzed to the requirements in the ASME Code Section III and that the analyses considered both the impacts of low-cycle and high-cycle fatigue stresses in the stress analyses.

It is not evident to the staff which specific edition of ASME Section III was used for the stress analyses of the core support structure components in the upper and lower core support structure assemblies. It is also not evident to the staff why these components would not have been required to be analyzed in accordance with the applicable fatigue calculation requirements in the ASME Code Section III edition of record for the components, or at least waived from the applicable calculation requirements in accordance with fatigue waiver analysis provisions in that edition of the code, and if fatigue analyses or fatigue waiver analyses were required as part of the design stress analyses for the components, why the analyses would not need to be identified as TLAAs for the LRA when compared to the six (6) criteria for TLAAs in 10 CFR 54.3.

Request:

Identify all RVI components that are defined in the CLB as RVI core support components for the upper internals and lower internals core support assemblies. Identify the design code of record for the core support structure components and whether the components were subject to either an explicit fatigue calculation (i. e., CUF calculation or It type of fatigue calculation) or a fatigue waiver analysis. If the component was required to be the subject of either a fatigue analysis or alternatively a fatigue waiver analysis, justify why the specific fatigue or fatigue waiver analysis for the component would not need to be identified as a TLAA for the LRA when compared to the six criteria for TLAAs in 10 CFR 54.3.

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TVA Response to RAI 4.1-10 Table 3.2.2-1 of the SQN UFSAR identifies the 1968 Edition of the ASME B&PV Code as the design Code of record for the reactor vessel. As discussed in Section 5.2 of the UFSAR, in some cases, the 1971 Edition of the ASME B&PV Code was used to capture more recent ASME Code conditions. Further definition is provided in Section 4.2.2 of the UFSAR, where it is stated that the materials used for the construction of the reactor internals are based on the 1971 Edition of the ASME B&PV Code.

The 1974 Edition of the Code incorporated Section III, Subsection NG, which provides design rules for core support structures (CSSs). Only plants designed after the incorporation of the Subsection NG, 1974 Edition have complete fatigue analyses of RVI component low-cycle and high-cycle fatigue usage documented in a Code-required plant-specific "ASME Stress Report."

The SQN reactor vessel internals were designed and constructed based on code editions before the 1974 edition. Therefore, there was no requirement in the original design basis to identify CSS components or to conduct an explicit fatigue calculation or fatigue waiver analysis for the CSS components. SQN Units 1 and 2 do not have a plant-specific "ASME Stress Report" for RVI CSS components and no RVI CSS components other than those identified in the LRA were determined to have cumulative usage factors calculated to support plant operation. No RVI components are defined in the CLB as RVI CSS components.

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RAI 4.2-1

Background:

The staffs questions are based on a review of the following background documents:

LRA Section 4.2 and its five subsections: (a) Section 4.2.1, time-limited aging analysis (TLAA) on the reactor vessel (RV) neutron fluence methodology; (b) Section 4.2.2, TLAA on the upper shelf energy (USE) analysis; (c) Section 4.2.3, TLAA on the pressurized thermal shock (PTS) analysis; (d) Section 4.2.4, TLAA on pressure-temperature (P-T) limit analysis; and (e) Section 4.2.5, TLAA on the low temperature overpressure protection (L TOP) system analysis.

Technical Specification 6.9.1.15 for Unit I and the current Pressure-Temperature Limits Report for Unit 1 (PTLR-1, Rev. 4)

Technical Specification 6.9.1.15 for Unit 2 and the current Pressure-Temperature Limits Report for Unit 2 (PTLR-2, Rev. 5)

NRC safety evaluation issued approving the license amendment for the PTLR process dated September 15, 2004 (ADAMS ML042600465)

WCAP-14040-A, Rev. 4, "Methodology Used to Develop Cold Overpressure Mitigating System Setpoints and RCS Heatup and Cooldown Limit Curves" WCAP-16083-NP-A, Rev. 0, "Benchmark Testing of the FERRET Code for Least Squares Evaluation of Light Water Reactor Dosimetry" Capsule reports for Units 1 and 2 (Refer to the Background section of RAI 4.2-2)

The regulation in 10 CFR 54.22 requires the applicant to identify all technical specification (TS) changes or additions that are needed to manage the effects of aging during the period of extended operation. LRA Appendix D states that there are not any TS additions or amendments that are needed to comply with the requirement in 10 CFR 54.22 and to manage the effects of aging during the period of extended operation.

Issue Dart 1:

LRA Section 4.2.1 establishes that two methodologies are used as the basis for estimating neutron fluence to the end of the period of extended operation (i.e., to 52 EFPY):

(a) WCAP-14040 -A, Revision 4, which is referenced in TS 6.9.1.15 for Unit I and for Unit 21, and (b) the FERRET least squares adjustment methodology in WCAP-16083-NP-A, Rev. 0, which has been generically approved by staff. Although WCAP-14040-A does include a general discussion on the topic of applying least squares adjustment, it does not specifically refer to WCAP-16083-NP-A as the basis for performing the least squares adjustment. The staff notes, however, that the FERRET methodology (i.e., WCAP-16083) is referenced in the CLB, in the Capsule Y reports for the units (i.e., WCAP-15224 for Unit I and WCAP-15320 for Unit 2).

1 The TS may refer to the "latest approved revision," rather than Revision 4, as is stated in the LRA.

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Yet the references located at TS 6.9.1.15 do not include WCAP-16083 as an analytical method used for determining the P-T limits for either unit.

Request Part 1:

Provide a basis why the TS 6.9.1.15 references list for the units would not need to be amended under the requirements of 10 CFR 54.22 to include WCAP-16083-NP-A as an additional methodology that will be used to determine future RV P-T limits.

TVA Response to RAI 4.2-1 Part 1 The fluence data required for the pressure-temperature evaluation is from calculations using a Westinghouse transport code. The Westinghouse Licensing Topical Report (LTR)

WCAP-1 4040-A provides a detailed description of the Westinghouse methodology for calculating neutron fluence using the DOORS code package with the BUGLE96 cross-section library. WCAP-16083-NP-A provides further validation using the FERRET code for determination of the best estimation of dosimetry data. Because WCAP-14040-A contains sufficient information on the Westinghouse methodology for transport calculations, referencing WCAP-14040-A alone is sufficient.

Issue part 2:

By letter dated September 26, 2012 (ADAMS ML12249A394 for the cover letter and non-proprietary SE; and ML12249A415 for the proprietary SE), the NRC granted Tennessee Valley Authority (TVA) with a license amendment and applicable TS changes to use high thermal performance AREVA HTP-fuel at SQN Units I and 2. LRA Section 4.2.1 is silent on the subject and the staff is unable to determine whether the neutron fluence projections for 52 effective full-power year (EFPY) in the LRA account for the AREVA HTP-fuel that was approved in the NRC letter of September 26, 2012.

Request. Part 2:

Clarify whether the methodology and assumptions used to estimate the RV neutron fluence values to 52 EFPY account for the use of the AREVA HTP-fuel that was approved in the NRC letter September 26, 2012.

1. If it is does, explain how source flux associated with the AREVA HTP-fuel has been worked into the neutron transport modeling accordant with WCAP-14040-A, Revision 4.

2. If neutron fluence calculations supporting the LRA for 52 EFPY do not account for the use of the AREVA HTP-fuel, explain why the neutron fluence values reported in the LRA for 52 EFPY remain as valid inputs for the remaining neutron irradiation embrittlement TLAAs that are evaluated in the subsections of LRA Section 4.2.

TVA Response to RAI 4.2-1 Part 2 The fluence analysis supporting the LRA does not explicitly account for AREVA HTP fuel because the LRA was submitted in early 2013, with the corresponding fluence analysis performed long before WVA was granted a license amendment for the AREVA HTP fuel on E2 - 13 of 18

September 26, 2012. However, the 52 EFPY fluence projected in the LRA covers the HTP fuel design based on the assumption that future cycles will resemble the average of three most recent completed cycles at the time of analysis, as detailed in the Response to RAI 4.2-1 Request Part 3.

1. Because the fluence analysis supporting the LRA does not explicitly account for AREVA.

HTP fuel, this request is not applicable.

2. The AREVA HTP fuel design has essentially the same fuel pellet and fuel rod design as the previous Mark-BW fuel and the HTP fuel will be loaded in the same manner as the Mark-BW fuel. In order to assess whether the LRA fluence assumption is bounding for the HTP fuel, an examination of the core loading patterns as described in AREVA HTP Fuel Transition Report ANP-2986 was performed. This examination confirmed that the core peripheral power densities of transition cycles as well as representative cycles of HTP fuel are bounded by or consistent with those assumed for the LRA fluence analysis.

Therefore, the neutron fluence values reported in the LRA for 52 EFPY remain as valid inputs for the remaining neutron irradiation embrittlement TLAAs that are evaluated in the subsections of LRA Section 4.2.

Issue. Part 3:

The approved neutron transport methodology in WCAP-14040-A, Revision 4 states that, "The energy distribution of the source is determined on a fuel assembly specific basis by selecting a fuel assembly bumup representative of conditions averaged of each fuel cycle and an initial enrichment characteristic for each assembly. From this average burnup and initial enrichment, a fission split by isotope is derived; and, from that fission split, composite values of energy release per fission, neutron yield per fission, and fission spectrum are determined for each fuel assembly. These composite values are then combined with the spatial distribution to produce the overall absolute neutron source for use in the transport calculations."

However, the methodology in WCAP-14040-A, Revision 4 does not clearly establish how those neutron flux values would be used to project the neutron fluence values for future plant operations, including those that are projected to the end of licensed operating period (for LRA, this is the end of the period of extended operation). Instead, this part of the neutron fluence methodology appears to be established (for the CLB) in the respective Capsule Y report for the unit. The Capsule Y reports for Unit 1 and Unit 2 establish that the neutron fluence values for the end of the current licensing period (i.e., to 32 EFPY) and beyond (i.e., to 48 EFPY) are based on the "assumption that the operating cycles 5 - 9 neutron flux rates for low leakage fuel management will continue to be applicable throughout plant life." The applicant has yet to pull, test and report any surveillance capsule data for any reactor vessel surveillance capsules that would cover power operations through 52 EFPY and the RV neutron fluence values that have been reported in the LRA for 52 EFPY are not consistent with the neutron fluence projection basis assumption given in the Capsule Y reports for the units (i. e., limiting fluence for 52 EFPY is lower than that for limiting fluence value for 48 EFPY as indicated in the Capsule Y report). In E2-14 of 18

many cases, the neutron fluence values reported in the LRA for the RV beltline components at 52 EFPY are less than the limiting best estimate 48 EPFY neutron fluence values that have been reported in the applicable Capsule Y report for the unit.

Request, Part 3:

1. Provide an explanation on the differences in neutron fluence values reported in the LRA as compared to those reported in the CLB (i.e., Capsule Y reports). Specifically, explain why the LRA reports some RV neutron fluence values for 52 EFPY that are approximately the same or lower than the limiting neutron fluence values that were reported for 48 EFPY in the respective Capsule Y report for the unit.

2. Justify why the neutron fluence values reported in the LRA for the clad-to-base metal interface locations and 1/4 T locations of the RV beltline and extended beltline components at 52 EFPY are considered to be valid, best estimate neutron fluence values when compared to the previous 48 EFPY best estimate values that have been provided for those locations in the respective Capsule Y report for Unit 1 and for Unit 2.

TVA Response to RAI 4.2-1 Part 3 1 A summary of SQN Units 1 and 2 Surveillance Capsule and Pressure Vessel Fluence Calculations is provided below. This summary explains the differences in neutron fluence values reported in the LRA compared to those reported in the CLB (i.e., Capsule Y reports) and why the LRA reports some RV neutron fluence values for 52 EFPY that are approximately the same or lower than the limiting neutron fluence values that were reported for 48 EFPY in the Capsule Y reports (WCAP-15224, June 1999, and WCAP-15320, December 1999 for Units 1 and 2, respectively).

In 1999, calculations were completed to assess the neutron fluence (E > 1.0 MeV) received by the withdrawn surveillance capsules and the pressure vessel wall of SQN Units 1 and 2. These calculations were documented in WCAP-1 5224 (June 1999) and WCAP-1 5320 (December 1999) for Units 1 and 2, respectively. The calculations were superseded in March 2012 (WCAP-17539) based on an updated neutron transport methodology as well as on additional fuel cycle specific plant operation. The following discussion describes the changes in the transport methodology over time and the additional operating data that was incorporated in the more recent analysis.

The 1999 calculations followed the guidance documented in Draft Regulatory Guide DG-1 053 (later issued in March 2001 as Regulatory Guide 1.190 "Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence"). In the application of the methodology described in DG-1053, an adjoint neutron transport approach was used with three-dimensional synthesis of the solution based on Equation 3 of the draft regulatory guide. The adjoint approach along with the use of Equation 3 from the guide introduces the following three conservatisms into the analysis:

1. The use of the adjoint methodology does not allow cycle to cycle water density variations in the peripheral fuel assemblies, bypass region, or downcomer region.

E2 - 15 of 18

Therefore, in the analysis, water densities were chosen to conservatively envelope actual plant operation.

2. The use of Equation 3 from DG-1053 does not account for the flattening of the axial flux distribution that naturally occurs as a function of increasing distance from the reactor core. This tends to result in an overestimate in the high fluence areas of the surveillance capsule and pressure vessel.

3. The use of Equation 3 from DG-1053 does not account for the shielding effect introduced by the former plates located at several axial elevations between the core baffle plates and the core barrel.

The methodology used in the 2012 calculations follows the guidance of Regulatory Guide 1.190 that has been approved by NRC. This updated methodology used a forward neutron transport approach with the three-dimensional synthesis of the solution based on Equation 4 of Regulatory Guide 1.190. The use of the forward transport methodology allows water density to be varied on a cycle-specific basis. In addition, use of Equation 4 from the regulatory guide explicitly accounts for changes in the axial neutron flux distribution as a function of radial position and also allows the shielding effect of the former plates to be included in the analysis.

Therefore, the use of the updated NRC-approved methodology for the 2012 analysis removed the three conservatisms listed above, resulting in a net reduction in the calculated fluence for surveillance capsules T, U, X, and Y at SQN Units 1 and 2.

In addition to the methodology changes noted above, the 2012 analysis accounted for several cycles of actual plant operation that were treated as projections in the 1999 calculations. The following table shows the differences in the analysis for both SQN units.

Operating SQN Unit 1 SQN Unit 2 Periods 1999 Analysis 2012 Analysis 1999 Analysis 2012 Analysis Cycle Specific 0 - 10.03 EFPY 0 -22.1 EFPY 0- 10.54 EFPY 0 -21.6 EFPY Projections 10.03 - 48 EFPY 22.1 - 52 EFPY 10.54 - 48 EFPY 21.6 - 52 EFPY Projection Flux Average Cy 5-9 Average Cy 16-18 Average Cy 5-9 Average Cy 15-17 The data in the above table shows that for both units, the amount of cycle-specific operating history that was included in the analyses doubled from approximately 10 EFPY in the 1999 analysis to approximately 22 EFPY in the 2012 analysis. In addition, the neutron flux used to project the vessel and capsule exposures was based on different fuel cycle averaging between the 1999 and 2012 calculations.

The new operational data listed in the table do not have any additional effect on the calculated neutron exposure of the previously withdrawn capsules. The assigned fluence for those capsules is affected only by the removal of conservatism based on the E2 - 16 of 18

updated methodology. However, while this reduction in conservatism also applies to the pressure vessel, additional changes to the pressure vessel exposure are brought about by the inclusion of operating fuel cycle data up to approximately 22 EFPY and by the choice of new updated power distributions for the future projected fluence.

2. The summary presented above also explains why the neutron fluence values reported in the LRA for the clad-to-base metal interface locations and 1/4T locations of the RV beltline and extended beltline components at 52 EFPY are considered to be valid, best-estimate neutron fluence values when compared to the previous 48 EFPY best-estimate values that have been provided for those locations in the respective Capsule Y report for Unit 1 and 2.

Issue Part 4:

LRA Section A. 2.1.1, "Reactor Vessel Fluence, "provides the applicant's UFSAR supplement summary description for the applicant's TLAA on RV neutron fluence methodology. In the UFSAR supplement, the applicant identifies the neutron fluence calculation methods for calculating the 52 EFPY neutron fluence values in the LRA "have been approved by the NRC and are described in detail in WCAP-14040-A, Revision 4, and WCAP-16083-NP-A, Revision 0." The staff seeks a justification why the UFSAR supplement summary description in LRA Section A. 2. 1.1 omits any reference of the applicable RV surveillance capsule reports (including the Capsule Y reports for the units)..

Request Part 4:

Provide a justification why the UFSAR supplement summary description in LRA Section A.2. 1.1 omits any reference of the applicable RV surveillance capsule reports (including the Capsule Y reports for the units).

TVA Response to RAI 4.2-1 Part 4 The UFSAR supplement summary description in LRA Section A.2.1.1 was considered sufficient based on the reference to UFSAR Section 5.4.3.7 which reported the calculated lead factors of RV surveillance capsules T, U, X, Y of each Unit. However, none of the fluence calculation reports of these withdrawn capsules were mentioned in the UFSAR reference list.

Consequently, the change to LRA Section A.2.1.1 follows with additions underlined.

"A.2.1.1 Reactor Vessel Fluence Fluence is calculated based on a time-limited assumption defined by the operating term.

Therefore, analyses that evaluate reactor vessel neutron embrittlement based on calculated fluence are TLAAs. The neutron fluence values for the SQN Unit 1 and Unit 2 reactor pressure vessel beltline material have been projected to 52 EFPY of operation.

The methods used to calculate the SQN Unit 1 and Unit 2 vessel fluence satisfy the criteria set forth in Regulatory Guide 1.190, "Calculational and Dosimetry Methods for Determining E2 - 17 of 18

Pressure Vessel Neutron Fluence." These methods have been approved by the NRC and are described in detail in WCAP-14040-A, Revision 4, and WCAP-16083-NP-A, Revision 0.

UFSAR Section 5.4.3.7 provides additional information on the specimen capsules and the associated dosimeters used to monitor reactor vessel embrittlement and neutron fluence.

WCAP-15224, June 1999, and WCAP-15320, December 1999 include the results of capsules T, U, X, and Y for Units 1 and 2 respectively. See Section A.1.35 for additional information on the Reactor Vessel Surveillance Program.

Fluence is treated as a TLAA that has been projected to the end of the period of extended operation in accordance with 10 CFR 54.21 (c)(1)(ii) and used as an input to the analyses in the following sections."

E2 -18of 18

ENCLOSURE 3 Tennessee Valley Authority Sequoyah Nuclear Plant, Units I and 2 License Renewal TVA Responses to NRC Request for Additional Information: Set 7/60-day

ENCLOSURE3 Tennessee Valley Authority Sequoyah Nuclear Plant, Units I and 2 License Renewal TVA Responses to NRC Request for Additional Information: Set 7/60-day RAI B.1.14-1

Background:

GALL Report AMP XI. MI 7, "Flow-Accelerated Corrosion," relies on implementation of NSA C-202L, "Recommendations for an Effective Flow-Accelerated Corrosion Program,"

Revision 2 or Revision 3. NSA C-202L, Section 1, "Introduction," states that it is directed at wall thinning caused by FAC and that it does not address other thinning mechanisms, such as erosive wear. LR-ISG-2012-01, "Wall Thinning Due to Erosion Mechanisms," discusses changes to AMP X1. M1 7 to address erosion mechanisms in the FAC Program and provides new AMR items associated with erosion mechanisms.

LRA Sections A. 1.14 and B. 1.14 state that the FAC Program relies on implementation of guidelines in NSAC-202L, Revision 3, and internal and external operating experience. These sections also state that the program manages loss of material due to erosion. LRA Section B. 1.14 states that the program is consistent with the program described in NUREG-1801,Section XI.M17.

In addition, the program basis document SQN-RPT-1O-LRD08, "Operating Experience Report -

Aging Effects Requiring Management," which was provided during the staff's audit, evaluates a number of plant operating experience reports by stating that loss of material due to erosion is an aging effect in the mechanical tools [EPRI 1010639, "Non-Class I Mechanical Implementation Guideline and Mechanical Tools," Revision 4] for stainless steel in high velocity or low quality steam. In several cases, the discussion appears to state that the associated components are being managed through the FAC Program.

Issue:

The SQN FAC Program, which addresses both FAC and erosion, is inconsistent with the program described in NUREG-1801,Section XI. M17, which does not address erosion mechanisms. In addition, the staff notes that the LRA only cites AMR item 3.4.1-5 for all components being managed by the FAC Program. The staff also notes that item 3.4.1-5 is associated with wall thinning due to FAC in carbon steel components, which is not appropriate for components being managed for erosion.

E3 - 1 of 22

Request:

Amend the LRA to reflect:

1. that the FAC Program is inconsistent with the program described in NUREG-1801, AMP Xl. M1 7 with respect to materials and mechanisms being managed (or is consistent with the revised program described in LR-ISG-2012-01); and

2. the appropriate materials and mechanisms in the AMR items 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.

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 aRd e)ternal er"cion, (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 predictivecode 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 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.

E3 - 2 of 22

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-1011231, Recommendations for Controlling Cavitation, Flashing, Liquid Droplet Impingement, and Solid Particle Erosion in Nuclear Power Plant PiDing. 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 i rn And ArnalAeroion, (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 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. 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.

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" E3 - 3 of 22

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 Program Revise FAC Program procedures to implement the qguidance 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-1 011231, Recommendations for Controlling

5. Monitoring and Trendinq 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.

E3 -4 of 22

RAI B. 1.38-1

Background:

LRA Section B. 1.38 states that the Service Water Integrity program is consistent with the GALL Report AMP Xl. M20, "Open-Cycle Cooling Water System," and that it manages loss of material and fouling of components exposed to essential raw cooling water (ERCW) as described in the SQN response to Generic Letter (GL) 89-13. SQN's response dated September 22, 1995, to GL 89-13 states that SQN's preventive maintenance program provides for routine inspections and maintenance of piping and components to ensure that corrosion, erosion, protective coating failure, silting, and biofouling does not degrade the performance of safety-related components supplied by ERCW The response also notes that SQN's inspection/maintenance program includes ultrasonic inspections of selected ERCW piping

[using] SQN's "raw water fouling and corrosion control program" [emphasis added] to monitor for piping degradation and to verify minimum wall thickness.

The operating experience discussion in LRA Section B. 1.38 states that SQN performs quarterly testing using ultrasonic inspections of the raw cooling water and ERCW systems and that there are approximately 150 locations concentrating on low flow and stagnant areas. The source of this statement appears to be from program basis document SQN-RPT-10-LRD09, "Operating Experience Review Results - Aging Management Program Effectiveness," Section 3.1.27, which states that the "MIC and Cavitation Degradation Monitoring Program O-PI-DXX-000-704. 1" performs quarterly ultrasonic inspections. However, the associated reference for that statement in SQN-RPT-IO-LRD09 is "interviews with the service water program owners."

The staff notes that SQN procedure 0- TI-SXX-000- 146. 0, "Program for Implementing NRC Generic Letter 89-13," lists O-PI-DXX-000-704. 1, "MIC and Cavitation Degradation Monitoring Program," as a procedure related to NRC GL 89-13. However, program basis document SQN-RPT-10-LRD03, "Aging Management Program Evaluation Report, " Section 4.12 "Service Water Integrity," does not mention O-PI-DXX-000-704. 1, and a copy of O-PI-DXX-000-704.1 was not included as a reference for this program. In addition, corporate procedure NPG-SPP-09.7, "Corrosion Control Program," which is cited in SQN-RPT-10-LRD03, does not include O-PI-DXX-000-704. 1 as a developmental reference in Section 6.3.37 for SQN.

The staff also notes that program basis document SQN-RPT-1O-LRD08, "Operating Experience Report - Aging Effects Requiring Management," cites a number of operating experience reports that discuss cavitation as the cause of piping degradation in the ERCW system. In each case the associated evaluation states that loss of material due to erosion is an aging effect identified in mechanical tools [EPRI 1010639, "Non-Class I Mechanical Implementation Guideline and Mechanical Tools, "Revision 4] for stainless steel or carbon steel in raw water In addition, during its review of related operating experience reports, the staff noted that several reports (21420, 70344, and 70681) that attributed the apparent cause a "due to cavitation as the valve opens and closes," as opposed to steady state cavitation due to a fixed pressure drop in the system.

E3 - 5 of 22

The staff notes that GL 89-13, Enclosure 4, NUREG-1275, Volume 3, "Operating Experience Feedback Report - Service Water System Failures and Degradation in Light Water Reactors,"

Section 3.1.3, "Corrosion/Erosion," states: "[tihe most commonly specified cause for corrosion/erosion of service water systems at [light water reactors] LWR was the nature of the system's water source. Suspended solids in the water source (e. g., silt or fine sand particles) was most frequently cited as the cause of the erosion of system components."

Issue:

Based on Enclosure 4 of GL 89-13 and the lack of any further clarification, the staff does not consider erosion due to cavitation as an aging mechanism that was addressed by GL 89-13.

However, based on operating experience reports cited in the program basis documents, loss of material due to cavitation is an aging effect requiring management at SQN. The staff notes that although EPRI 1010639 identifies loss of material due to erosion as an aging effect for stainless steel and carbon steel in raw water, it also indicates that there is no corresponding item number in the GALL Report and there is no "Tool vs GALL Match." Based on this, if SQN is managing loss of material due to cavitation erosion with the Service Water Integrity program, then this approach is inconsistent with the GALL Report.

In addition, the staff does not consider that the information and documentation necessary to document compliance with the provisions of Part 54 are in an auditable and retrievable form as required by 10 CFR 54.37, "Additional records and record-keeping requirements." This is based on: 1) the apparent need for SQN to manage loss of material due to cavitation, and the lack of documentation for this aspect in LRD03, Section 4.12, Service Water Integrity, and 2) including statements in the LRA concerning quarterly ultrasonic inspections of ERCW piping that are based on interviews with the service water program owners.

Request:

1. Discuss whether loss of material due to cavitation is an AERM at SQN. If not, provide bases for not requiring management with respect to the associated operating experience reports discussed in SQN-RPT-10-LRD08. If cavitation does require management, provide bases to demonstrate that the implementing procedure(s) will manage the effects of aging so that the intended function(s) will be maintained.

2. If loss of material due to cavitation does require management by the Service Water Integrity program, discuss whether the existing information and documentation required to document compliance with the provisions of Part 54 are being retained in an auditable and retrievable form with respect to managing loss of material due to cavitation.

TVA Response to RAI B.1.38-1

1. Loss of material due to cavitation is an aging effect requiring management (AERM). Loss of material due to cavitation will be managed under the Flow-Accelerated Corrosion (FAC)

Program. The FAC Program will be enhanced to specifically address erosion due to cavitation in accordance with the FAC Program as modified by interim staff guidance in LR-ISG-2012-01 thereby ensuring that the effects of aging will be managed such that the intended functions of affected components can be maintained.

E3 - 6 of 22

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 oternal orocIon, (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 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 particle impingement and solid particle impingement 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-1011231, Recommendations for Controllinq 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 i*ntmnal and oxtornal orosion, (b) conducting E3 - 7 of 22

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 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. 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.

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 particle impingement and solid particle impingement 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

4. Detection of Aging Effects 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

3. Parameters Monitored/Inspected guidance in LR-ISG-2012-01, which will include a

4. Detection of Aging Effects susceptibility review based on internal operating

5. Monitoring and Trending experience, external operating experience, EPRI

7. Corrective Action TR-1011231, 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.

E3 - 8 of 22

2. The aging effect of loss of material due to the erosion mechanism of cavitation will be managed by the enhanced FAC Program. The enhancement is a commitment. The commitment and documentation prepared to demonstrate the commitment is met are auditable and retrievable.

Commitment #10 has been revised.

E3 - 9 of 22

RAI 13.1.38-3

Background:

The "Program Description" for GALL Report AMP Xl. M20, "Open-Cycle Cooling Water System,"

states that the program manages "aging effects caused by biofouling, corrosion, erosion, protective coating failures, and silting." The "detection of aging effects" program element for the AMP states that the inspection scope is in accordance with the applicant's docketed response to NRC Generic Letter 89-13, "Service Water System Problems Affecting Safety-Related Components." The program description for SQN LRA Section B. 1.38, "Service Water Integrity,"

reflects comparable information as the GALL Report AMP. However, the "Conclusion" for SQN LRA Section B. 1.38 states that the Service Water Integrity program has been effective at identifying and managing aging effects of loss of material (including loss of material due to wear), [emphasis added] and fouling for components exposed to ERCW The staff notes that SQN's response dated September 22, 1995, to GL 89-13 does not discuss any activities associated with managing wear for components exposed to ERCW In addition, the staff notes that the program basis document SQN-RPT-I 0-LRD08, "Operating Experience Review Report - Aging Effects Requiring Management," does not identify loss of material due to wear for heat exchanger tubes being managed by the Service Water Integrity program.

However, the staff notes that SQN-RPT-10-LRD03, "Aging Management Program Evaluation Report, Non-Class I Mechanical," indicates that the "detection of aging effects" for the Service Water Integrity program includes loss of material due to wear for stainless steel in an external treated water environment greater than 140 OF. The staff further notes that this appears to be referring to an item in LRA Table 3.3.2-15, "Standby Diesel Generator System," for heat exchanger tubes.

Issue:

SQN is using the Service Water Integrity program to manage an aging mechanism that a) is not addressed in the corresponding GALL AMP, b) that is not addressed in SQN's docketed response to GL 89-13, and c) that is in a treated water environment instead of a raw water environment. Based on this, the staff needs additional information to ensure that the effects of aging will be adequately managed during the period of extended operation.

Request:

For the loss of material due to wear that is being managed by the Service Water Integrity program, provide information regarding how this aging mechanism will be managed with regard to the a) detection of aging effects (i.e., discuss the inspection method or technique, whether sampling is used and if so how the most susceptible locations are determined, and inspection frequency),

b) monitoring and trending (i.e., discuss the methodology for analyzing inspection results to confirm that inspection frequency will prevent loss of intended function, and include conservatisms that account for inaccuracies in measurements and non-linear wear rates due to increasing clearances), and c) acceptance criteria (i.e., basis for minimum wall thickness criterion or other acceptance criteria if used).

E3 - 10 of 22

TVA Response to RAI B.1.38-3 The item in LRA Table 3.3.2-15, "Standby Diesel Generator System," represents the heat exchanger tubes for the diesel generator jacket water cooler. The external surface of the tubes is exposed to treated water and the internal surface is exposed to raw water (essential raw cooling water or ERCW). Wear could occur on the external side of the tubes due to possible relative motion between the tubes and the tube support members of the heat exchanger due to vibration during engine operation.

The Service Water Integrity Program implements and maintains an ongoing program of surveillance for the jacket water cooler heat exchangers subject to loss of material due to wear by periodically performing non-destructive examination of tubes by eddy current testing. This testing is capable of locating wall thinning at specific locations on the external surfaces of the tubes. This periodic ongoing testing assures that loss of material due to wear on the treated water side of the tubes is adequately managed. Use of the Service Water Integrity Program is appropriate because ERCW provides cooling for these heat exchangers, and as stated in the NUREG-1 801 discussion of the open-cycle cooling water system program, the program applies to cooling systems that use raw water (under "Scope of Program" and "Parameters Monitored/Inspected"). The diesel generator jacket water heat exchangers are included in the discussion of the Service Water Integrity Program in LRA Section B.1.38.

a) As stated in the NUREG-1 801 discussion of the open-cycle cooling water system program, eddy current testing is an effective method to measure the extent of wall thinning associated with the service water system piping and components (under "Detection of Aging Effects").

The inspection methods used for the jacket water heat exchangers include eddy current testing using a bobbin coil probe with ASME wear standard. The periodic testing is scheduled as part of the SQN preventive maintenance (PM) activities and these PM tasks are identified as GL 89-13 commitments. No sampling is used; eddy current testing is performed on 100% of the tubes.

Eddy current testing frequency is based on test results, which is in accordance with the documented SQN response to GL 89-13 dated January 26, 1990.

b) Results from the jacket water heat exchanger inspections are reviewed for findings that should be monitored or trended in accordance with site procedures.

Eddy current testing has identified no service-induced wear damage or volumetric loss in any of the tubes. Minor denting has been detected; however, recent eddy current inspection has shown no growth rate. These dents likely occurred during installation of the tube bundle. There are a few instances of minor deposits.

Whenever eddy current testing is performed, 100% of the tubes are tested. If new degradation is observed, site procedures require an evaluation to determine whether testing frequency needs to increase. Site procedures provide for a systematic method for technical evaluation of heat exchanger tube wall degradation. The history of the heat exchanger is reviewed, and several factors are considered, including material type, wall thickness, previous inspection results, and progression rates.

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c) Site procedures require that abnormal degradation found during a PM task are entered into the corrective action program. Because no service-induced wear damage or volumetric loss has been observed in the tubes of the jacket water heat exchangers, any wall thinning would be considered abnormal. Therefore, the acceptance criteria for the PM task are "no wall thinning." If wall thinning is identified, site procedures require an evaluation to determine whether the remaining tube wall thickness is acceptable.

E3 - 12 of 22

RAI 4.2-2 Back ground:

The applicant's TLAA bases for the upper shelf energy (USE) assessments are given in LRA Section 4.2.2 and LRA Tables 4.2-3 and 4.2-4 for Units I and 2, respectively. Similarly, the applicant's TLAA bases for the pressurized thermal shock (PTS) assessments are given in LRA Section 4.2.3 and LRA Tables 4.2-5 and 4.2-6 for Units I and 2, respectively. The RV surveillance capsule reports that have been docketed for the current operating period in accordance with the reporting requirements in 10 CFR Part 50, Appendix H are given in the following technical or topical reports (TRs):

Unit I Capsule T-Westinghouse TR No. WCAP-10340 Unit I Capsule U - Southwest Research Institute TR No. SWRI-06-8851 Unit I Capsule X-Westinghouse TR No. WCAP-13333 Unit I Capsule Y-Westinghouse TR No. WCAP-15224 Unit 2 Capsule T-Westinghouse TR No. WCAP-10509 Unit 2 Capsule U - Southwest Research Institute TR No. SWRI-17-8851 Unit 2 Capsule X-Westinghouse TR No. WCAP-13545 Unit 2 Capsule Y-Westinghouse TR No. WCAP-15320 Issue:

The applicant's USE evaluations in LRA Section 4.2.2, USE calculational bases in LRA Tables 4.2-3 and 4.2-4, PTS evaluations in LRA Section 4.2.3, and PTS calculational bases in LRA Tables 4.2-5 and 4.2-6 do not reference any of the previous RV surveillance capsule reports. These reports are part of the applicant's CLB and are relevant to the 52 effective full-power year (EFPY) USE assessment bases in LRA Tables 4.2-3 and 4.2-4 and the 52 EFPY PTS assessment bases in LRA Tables 4.2-5 and 4.2-6. In the most recent RV surveillance capsule reports for the units (i.e., Capsule Y reports for Units I and 2), the applicant reanalyzed all prior RV surveillance data that were reported in the previous Capsule T, U, and X reports for the units. Thus, it is not evident to the staff exactly which of the previously docketed RV surveillance data capsule reports for the units are being relied upon and are providing data inputs into the USE calculations in LRA Tables 4.2-3 and 4.2-4 and the PTS calculations in LRA Tables 4.2-5 and 4.2-6.

Request:

1. Identify the RV surveillance capsule reports in the CLB that are relied upon and are providing data inputs into the 52 EPFY USE calculations in LRA Tables 4.2-3 and 4.2-4 and the 52 EFPY PTS calculations in LRA Tables 4.2-5 and 4.2-6.

2. Provide and justify all RV surveillance capsule material data inputs that are providing inputs into the 52 EFPY USE and PTS calculations in the LRA (i.e., the surveillance data inputs to the calculations for Unit I RV beltine forging 04 [heat #980919/281587] and E3 - 13 of 22

circumferential welds W04 and W05 [both made from heat #252951, and for Unit 2 RV beltine forging 05 [heat #288757/981057] and circumferential weld W05 [heat #4278]).

For the explanation on the RV surveillance material alloying contents, clarify how the RV surveillance capsule chemistry data are being derived if more than one RV surveillance document source is being used to derive the RV surveillance chemistry values for the applicable RV surveillance base metal and weld materials.

TVA Response to RAI 4.2-2

1. As documented in Section 3, Section 5 and Appendix A of Reference 1, Westinghouse used the following surveillance capsule analyses of record (AOR) reports for the upper-shelf energy (USE, Section 5) and pressurized thermal shock (PTS, Section 3 for the chemistry factor determination and Appendix A for the credibility evaluation) calculations documented in LRA Tables 4.2-3 through 4.2-6:

1. WCAP-15224, Revision 0 for SQN Unit 1 (Reference 2)

2. WCAP-15320, Revision 0 for SQN Unit 2 (Reference 3)

2. Pertaining to USE, Tables 5-1 and 5-2 of Reference 1 document the surveillance capsule data inputs used in the evaluation. Specifically, percent USE decrease values for the SQN Unit 1 surveillance materials (Lower Shell Forging 04 [heat #

980919/281587 and intermediate to lower shell and lower shell to bottom head circumferential welds W04 and W05 [heat # 25295]) were taken from Table 5-10 of Reference 2. Likewise, percent USE decrease values for the SQN Unit 2 surveillance materials (Intermediate Shell Forging 05 [heat # 288757/981057 and intermediate to lower shell circumferential weld W05 [heat # 4278]) were taken from Table 5-10 of Reference 3.

The surveillance capsule fluence values used in the percent USE decrease evaluations were updated as part of the TLAA analysis and are documented in Table 2-6 for Unit 1 and Table 2-7 for Unit 2 of Reference 1.

The surveillance capsule percent USE decrease inputs were plotted on Figure 5-1 for Unit 1 and Figure 5-2 for Unit 2 in Reference 1.

Pertaining to the PTS calculations documented in Tables 4-1 and 4-2 of Reference 1, surveillance capsule data from References 2 and 3 for SQN Units 1 and 2 were used to determine the chemistry factor values and credibility conclusions of the aforementioned surveillance materials at both units. As stated in Section 3 of Reference 1, the surveillance weld materials for both units do not utilize sister plant results; therefore, the chemistry factor determinations as documented in Tables 3-3 and 3-4 contain data from SQN Units 1 and 2 only.

For the Unit 1 surveillance weld [heat # 25295], the surveillance weld chemistry, as documented in Table 3-1 of Reference 1, was taken from Reference 6. The surveillance weld chemistry documented in this report is a best-estimate value based on an average of three data points [0.424 (Reference 4), 0.406 (Reference 4), 0.33 (Reference 5) for E3 - 14 of 22

copper; 0.084 (Reference 4), 0.085 (Reference 4), 0.17 (Reference 5) for nickel]. This chemistry data is slightly different from the reactor vessel weld chemistry values, also taken from Reference 6; therefore, the ratio procedure of Regulatory Guide 1.99, Revision 2 (Reference 7) was utilized in Table 3-3 of Reference 1 to account for the chemistry differences between the vessel weld material and surveillance weld material by multiplying the surveillance weld measured 30 ft-lb shift (ARTNDT) values by the ratio of 0.90.

For the Unit 2 surveillance weld [heat # 4278], the surveillance weld chemistry, as documented in Table 3-2 of Reference 1, was taken from the baseline surveillance program report, Reference 8. This chemistry data is slightly different from the reactor vessel weld chemistry values, taken from Reference 9; therefore, the ratio procedure of Reference 7 was utilized in Table 3-4 of Reference 1 to account for the chemistry differences between the vessel weld material and surveillance weld material by multiplying the measured 30 ft-lb shift (ARTNDT) values by the ratio of 0.93.

Appendices A.1 and A.2 of Reference 1 for SQN Units 1 and 2, respectively, document the credibility evaluation for the surveillance capsule forging and weld materials. As concluded in these appendices, for Unit 1, the surveillance forging and weld materials were deemed credible; however, only the surveillance forging was deemed credible for Unit 2. The surveillance weld was deemed non-credible. Therefore, as reflected in Tables 4-1 and 4-2 of Reference 1, the margin term for the surveillance data has been reduced by half for the credible Unit 1 materials in Table 4-1, while only the surveillance forging material has a reduced margin term in Table 4-2 for Unit 2. The Unit 2 weld material utilizes a full margin term because it was deemed non-credible. This is consistent with the methodology specified in 10 CFR 50.61 (Reference 10).

References for RAI 4.2-2 Response

1. Westinghouse Report, WCAP-17539-NP, Revision 0, "SQN Units 1 and 2 Time-Limited Aging Analysis on Reactor Vessel Integrity," March 2012.

2. Westinghouse Report, WCAP-15224, Revision 0, "Analysis of Capsule U from the Tennessee Valley Authority (TVA) SQN Unit 1 Reactor Vessel Radiation Surveillance Program," June 1999.

3. Westinghouse Report, WCAP-1 5320, Revision 0, "Analysis of Capsule Y from the TVA SQN Unit 2 Reactor Vessel Radiation Surveillance Program," December 1999.

4. Westinghouse Report, WCAP-10340, Revision 1, "Analysis of Capsule T from the TVA SQN Unit 1 Reactor Vessel Radiation Surveillance Program," February 1984.

5. Westinghouse Report, WCAP-8233, Revision 0, "TVA SQN Unit No. 1 Reactor Vessel Radiation Surveillance Program," December 1973.

6. Westinghouse Report, WCAP-15293, Revision 2, "SQN Units 1 Heatup and Cooldown Limit Curves for Normal Operation and PTLR Support Documentation,"

July 2003.

E3 - 15 of 22

7. Regulatory Guide 1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel Materials," U.S. Nuclear Regulatory Commission, Office of Nuclear Regulatory Research, May 1988.

8. Westinghouse Report, WCAP-8513, Revision 0, "TVA SQN Unit No. 2 Reactor Vessel Radiation Surveillance Program," November 1975.

9. Westinghouse Report, WCAP-15321, Revision 2, "SQN Units 2 Heatup and Cooldown Limit Curves for Normal Operation and PTLR Support Documentation,"

July 2003.

10. Code of Federal Regulations, 10 CFR Part 50.61, "Fracture Toughness Requirements for Protection Against Pressurized Thermal Shock Events," U.S.

Nuclear Regulatory Commission, Washington, D.C., Federal Register, Volume 60, No. 243, dated December 19, 1995, effective January 18, 1996.

E3 - 16 of 22

RAI 4.2-3 Background.-

The bases for the applicant's PTS assessments for the current operating period are given in the applicant's response letter to GL 92-01, "Reactor Vessel Structural Integrity" (Tennessee Valley Authority (TVA) letter of July 7, 1992) or in the applicant's response comments on the contents of the NRC's Reactor Vessel Integrity Database, as given in TVA letter of November 18, 1999, for the SQN units.

Issue:

The LRA does not list any copper (Cu) or nickel (Ni) contents (and the bases for these alloy chemistries) for any of the RV beltine and extended beltine components that were listed in LRA Tables 4.2-5 and 4.2-6. The staff needs identification of these chemistry values in order to verify that the LRA is using acceptable chemistry factor (CF) values for the PTS calculations in LRA Tables 4.2-5 and 4.2-6. The staff also seeks identification of the heats of material that were used to fabricate the RV extended betline forging and ring components in LRA Tables 4.2-5 and 4.2-6 and the weld types and weld fluxes that were used to fabricate those welds that are identified in Tables 4.2-5 and 4.2-6 as RV extended beltine circumferential welds.

Request:

1. Provide or identify the reference documents that include the Cu and Ni contents (in weight percent) for all RV beltline and extended beltline components that are listed in LRA Tables 4.2-5 and 4.2-6, and justify the applicant's bases for the these chemistry values.

2. Identify the heats of material that were used to fabricate the RV extended befline forging and ring components that are listed in LRA Tables 4.2-5 and 4.2-6 and the weld types and weld fluxes that were used to fabricate those welds that are identified in LRA Tables 4.2-5 and 4.2-6 as RV extended beltline circumferential welds.

TVA Response to RAI 4.2-3, Requests I and 2 The Cu and Ni weight % (wt. %) values for the reactor vessel traditional beltline materials for SQN Units 1 and 2 are from the most recent Pressure-Temperature (P-T) limit curves in Reference 1 for Unit 1 and Reference 2 for Unit 2, as documented in Section 3 of WCAP-17539-NP (Reference 3).

The SQN Units 1 and 2 extended beltline materials consist of the Upper Shell (US) Forging 06 (heat # 980950/282758 for Unit 1 and heat # 981201/285849 for Unit 2), Bottom Head Ring 03 (heat # 981177/288872 for Units 1 and 2), US to Intermediate (IS) Circumferential Weld W06, and the Lower Shell (LS) to Bottom Head Ring Weld W04. The SQN Unit 1 US to IS Circumferential Weld W06 was fabricated with SMIT 40 weld wire type, heat # 25006 and SMIT 89 flux type, lot # 8985. The SQN Unit 1 LS to Bottom Head Ring Circumferential Weld W04 was fabricated with SMIT 40 weld wire type, heat # 25295 and SMIT 89 flux type, lot # 1135, which is the same material as the Unit 1 reactor vessel beltline circumferential weld I

E3 - 17 of 22

and surveillance material. Both of the Unit 2 extended beltline welds were fabricated using Arcos weld wire type, heat # 721858 and SMIT 89 flux type, lot # 1197. No surveillance data exists for weld heat numbers 25006 and 721858. This weld information was taken from the Rotterdam weld certification records.

For the Units 1 and 2 extended beltline forging materials, US Forging 06 and Bottom Head Ring 03, certified material test report (CMTR) data was used to determine the wt. % Ni values for all four components. The Ni wt. % values in Tables 3-1 and 3-2 of Reference 3 for the beltline forging components are comparable to the extended beltline forging components.

Wt. % Cu values were not reported in the CMTRs; therefore, the maximum weight percent copper value for A508 Class 2 forging materials was conservatively applied based on the generic data provided in Appendix G of the Oak Ridge National Laboratory Report (Reference 4); the justification for this generic Cu wt. % value is provided herein.

As noted in Section 3 of Reference 3, the material test reports for the SQN Units 1 and 2 US and Bottom Head Ring forging materials did not contain measurements of copper content, because the early ASTM A508 material specification did not require analysis of copper content (considered to be a tramp element in the steel alloy). The importance of copper content in the irradiation embrittlement of ferritic pressure vessel steel was not recognized or regulated by the NRC or nuclear steam supply system (NSSS) vendors when the SQN Units 1 and 2 reactor vessel were constructed.

Even though the material specification did not require analysis of copper content of ASTM A508 Class 2 material, chemistry measurements are available for this material specification as collected in the Embrittlement Shift TTS Database that is attached to Reference 4. These measurements, including copper content, were made on pressurized water reactor surveillance capsule materials for various forging and plate specifications, as well as weld metals used to fabricate the vessel seams. Appendix G of Reference 4 tabulates the mean values, standard deviation, and maximum values for the various material specifications, broken out as both low Cu (< 0.072 wt%) and high Cu (> 0.072 wt%). For A508 Class 2 forging material, there were only a limited number of heats (24; 15 with low Cu content and 9 with high Cu content) available for analysis relative to the more common A533 Grade B Class 1 vessel material, which had a total of 73 heats for analysis.

Regulatory Guide 1.99, Revision 2, Position 1.1 (Reference 5) states:

"...'weight-percent copper' and 'weight-percent nickel' are the best-estimate values for the material, which will normally be the mean of the measured values for a plate or forging or for weld samples made with the weld wire heat number that matches the critical vessel weld. If such values are not available, the upper limiting values given in the materials specifications to which the vessel was built may be used. If not available, conservative estimates (mean plus one standard deviation) based on generic data may be used if justification is provided. If there is no information available, 0.35% copper and 1.0% nickel should be assumed."

E3 - 18 of 22

Therefore, because there were fewer heats available, a slightly more conservative approach (than the approach that utilizes the mean + one standard deviation) is prudent to estimate the generic Cu content of A508 Class 2 forging material. This more conservative approach is to use the maximum copper content for high-Cu materials, which is 0.16 wt. %, for the SQN Units 1 and 2 US and Bottom Head Ring Forging materials. Note that utilizing a mean + one standard deviation approach for the high-Cu materials would result in a Cu wt. % value of 0.15, which would have reduced the Reference 5 Position 1.1 chemistry factor values by approximately 8°F for each A508 Class 2 forging material in the SQN Units 1 and 2 extended beltline.

Limited information was available for the SQN Unit 1 extended beltline US to IS circumferential weld (heat # 25006) in the Rotterdam weld certification records. The Cu wt. % value was taken from a chemical analysis performed on the weld wire (heat # 25006) included in the Rotterdam weld certification records. Wt. % percent nickel was not reported in the weld certification records for heat # 25006; therefore, a value of 1.0 was conservatively assumed per 10 CFR 50.61 (Reference 6). The LS to Bottom Head Ring circumferential weld was fabricated using the same weld wire heat number and flux type as the IS to LS circumferential weld.

Therefore, the chemical compositions of the IS to LS circumferential weld were applied to the LS to Bottom Head Ring circumferential weld.

The wt. % Cu value for the SQN Unit 2 extended beltline US to IS and LS to Bottom Head Ring circumferential welds (heat # 721858) was taken from the as-deposited weld analysis in the Rotterdam weld certification records. Similar to the US to IS circumferential weld in the SQN Unit 1 reactor vessel (heat # 25006), wt. % nickel was not reported in the Rotterdam weld certification records for heat # 721858; therefore, a value of 1.0 was conservatively assumed per Reference 6).

References for RAI 4.2-3 Response

1. Westinghouse Report, WCAP-15293, Revision 2, "SQN Units 1 Heatup and Cooldown Limit Curves for Normal Operation and PTLR Support Documentation," July 2003.

2. Westinghouse Report, WCAP-15321, Revision 2, "SQN Units 2 Heatup and Cooldown Limit Curves for Normal Operation and PTLR Support Documentation," July 2003.

3. Westinghouse Report, WCAP-17539-NP, Revision 0, "SQN Units 1 and 2 Time-Limited Aging Analysis on Reactor Vessel Integrity," March 2012.

4. Oak Ridge National Laboratory document ORNLITM-2006/530, "A Physically Based Correlation of Irradiation-Induced Transition Temperature Shifts for RPV Steels,"

November 2007.

5. Regulatory Guide 1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel Materials," U.S. Nuclear Regulatory Commission, Office of Nuclear Regulatory Research, May 1988.

6. Code of Federal Regulations,10 CFR Part 50.61, "Fracture Toughness Requirements for Protection Against Pressurized Thermal Shock Events," U.S. Nuclear Regulatory Commission, Washington, D.C., Federal Register, Volume 60, No. 243, dated December 19, 1995, effective January 18, 1996.

E3 - 19 of 22

RAI 4.7.3-2

Background:

Westinghouse Proprietary Class 2 TR Nos. WCAP-10456 and WCAP-10931 serve as the applicant's basis for establishing the degree of thermal aging that would occur in the CASS components that were evaluated in the LBB analysis over a 60 year licensed operating period. These WCAP reports assume fully thermally aged conditions for the Safety Class I or Class A CASS piping components that are within the scope of the LBB analysis.

Issue:

Since the time of the NRC's approval of the LBB analysis in 1989, considerable information has been developed that provides an improved understanding of the thermal embrittlement behaviors of CASS materials. Even though the LRA does identify that the LBB assumed fully saturated thermally aged conditions for CASS components (i.e., assumed the minimum material fracture toughness value properties possible), the staff also noted that the applicant's basis may be predicated on thermal aging data that are not up to date or conservative when compared to the most recent data for CASS materials for the industry. Examples of documents containing more up-to-date data on material properties and thermal aging behavior of CASS materials are given in, but not limited to, the following reports:

1. NUREG/CR-4513, Revision 1, "Estimation of Fracture Toughness of Cast Stainless Steels During Thermal Aging in LWR Systems" (1994)

2. Appendix A of draft Electric Power Research Institute (EPRI) report 1024966, "Probabilistic Reliability Model for Thermally Aged Cast Austenitic Stainless Steel Piping"

3. ASME Code paper PVP2010-25085, "Flaw Evaluation in Elbows Through French RSEM Code [a French Nuclear Code for PWR mechanical equipment]," by C. Faidy The LRA does not provide sufficient information or justification to support that the assumptions for the thermal aging embrittlement basis will remain valid in light of more recent information that has been compiled on thermal aging behavior of CASS materials over the last 29 years.

Request:

1. Compare the CASS material data and behavior analyses that were used for the LBB analysis to the corresponding CASS material data and behavior analyses in the document sources cited above or in other relevant documents on CASS material properties and behavior, as necessary.

Based on this comparison, provide a justification that the assumed saturated fracture toughness property (i.e., lower bound fracture toughness value) for CASS piping components in the LBB evaluation will remain bounding for the expected drop in the fracture toughness property of those CASS components through 60 years of licensed operations.

2. Based on the response to Part 1, justify whether the analysis of thermal aging embrittlement in the thermal aging embrittlement portion of the LBB analysis needs to be identified as a TLAA for the LRA. If it is determined that the treatment of thermal aging embrittlement for the CASS piping locations does need to be identified as a TLAA for LRA, amend the application accordingly and provide your basis for dispositioning the TLAA in accordance with 10 CFR 54.2 1(c)(1)(i), (ii), or (iii).

E3 - 20 of 22

TVA Response to RAI 4.7.3-2

1. The original SQN Leak-Before-Break (LBB) analysis performed in 1988 (WCAP-12011 Rev. 0, Reference 1) established the thermal aging properties for CASS components per WCAP-1 0456 (Reference 2) and WCAP-10931 (Reference 3). However, for the LBB analysis performed in 2001 (WCAP-1 2011 Addendum 1, Rev. 0, Reference 4) for the replacement steam generators (RSG) at SQN Unit 1 and the reduction of steam generator snubbers for Units 1 and 2, the estimation of saturated fracture toughness properties of the CASS material at SQN Units 1 and 2 primary loop piping was updated to the correlations provided in Argonne National Laboratory (ANL) report NUREG/CR-4513, Revision 1 (Reference 5). The LBB evaluation for the RSG at Unit 2 performed in 2011 (Reference 10) also used the same correlations from Reference 5 to determine the aged fracture toughness values.

The estimation of the saturated fracture toughness values in Reference 5 was based on an extensive research program done at Argonne National Laboratory (ANL) to assess the extent of thermal aging of cast stainless steel materials. As part of the ANL research project, correlations for the saturated fracture toughness were developed based on approximately 85 compositions of cast stainless steel exposed to a temperature range of 290-400°C (550-750°F) for up to 58,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br />.

It was observed that the ANL correlations for fracture toughness values produced conservative estimates that were about 30-50% less than the actual measured values as discussed in the Reference 6 paper by S. Lee, et al.

The correlations from Reference 5 have been used for LBB analysis in accepted licensing submittals for other plants in the PWR fleet. Therefore, for SQN in the LBB evaluation, the saturated fracture toughness property (i.e., lower bound fracture toughness value) for the CASS material is based on the latest fracture toughness correlations and will remain bounding for the expected drop in the fracture toughness property of those CASS components through 60 years of operations.

The probabilistic analysis mentioned in Appendix A of the 2012 EPRI Report 1024966 (Reference 7), also used the correlations of Reference 5 as the source of the fully aged material toughness properties.

The work done by Faidy as published in ASME Paper PVP2010-25085 (Reference 8) was also investigated and compared to another paper published by Faidy in ASME Paper PVP2012-78843 (Reference 9).

In Reference 9, measured fracture toughness values'(J) from removed cast elbows were compared to the prediction curves developed in Reference 8. The specimens removed from the actual elbows then underwent further aging at temperatures of 350'C (6620F) or 400°C (752°F) in order to reach their ultimate aging stage. Based on Figure 7 of Reference 9, the lowest value for J at a crack extension of Aa = 0.2 mm for the worst elbow specimen is approximately 160 kJ/m 2 (913 in\\ lb/in2). Based on the equations in Reference 8, the correlated J value at this same crack extension from Figure 7 of Reference 9 is approximately 55 kJ/m 2 (314 in-lb/in 2). Therefore, the measured data from the removed elbows were shown to be not as limiting as predicted by the correlation equations provided in Reference 8 by a factor of 3.

The ANL correlations based on Reference 5, which are 30-50% more conservative than the actual measured values, are more representative of actual fracture toughness values. Therefore, the E3 - 21 of 22

correlations developed in Reference 8 can be interpreted to be an overestimation of the aged fracture toughness properties and therefore, should not be used for SQN in the LBB evaluation.

2. Because the Leak-Before-Break evaluations for both units use saturated (fully aged) fracture toughness properties, the evaluation of the thermal aging of CASS portion of the analysis does not have a material property time-dependency and therefore is not a TLAA. The leak before break analysis is considered a TLAA due to its use of transient cycles as described in the response to RAI 4.7.3-3. The analysis remains valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).

References for RAI 4.7.3-2 Response

1. WCAP-12011 "Technical Justification for Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis for Sequoyah Units 1 & 2," Revision 0, October 1988

2. WCAP-10456, "The Effects of Thermal Aging on the Structural Integrity of Cast Stainless Steel Piping for Westinghouse Nuclear Steam Supply Systems," Revision 0, November 1983

3. WCAP-10931, "Toughness Criteria for Thermally Aged Cast Stainless Steel," Revision 1, July 1986

4. WCAP-1 2011, Addendum 1, "Technical Justification for Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis for Sequoyah Units 1 & 2," Revision 0, September 2001

5. Argonne National Laboratory (ANL) report NUREG/CR-4513, "Estimation of Fracture Toughness of Cast Stainless Steels During Thermal Aging of LWR Systems," Revision 1, May 1994

6. S. Lee, P. T. Kuo, K. Wichman (USNRC) & 0. Chopra (ANL), "Flaw Evaluation of Thermally Aged Cast Stainless Steel in Light-water Reactor Applications." International Journal of Pressure Vessel and Piping vol. 72 Issue 1, June 1997, pg 37-44

7. EPRI Report 1024966, Appendix A, "Probabilistic Reliability Model for Thermally Aged Cast Austenitic Stainless Steel Piping," 2012

8. C. Faidy (EDF), "Flaw Evaluation in Elbows Through French RSEM Code," ASME Paper PVP2010-25085, July 2010

9. C. Faidy (EDF), "Ageing Management of Cast Stainless Steel Components in French PWRs,"

ASME Paper PVP2012-78843, July 2012

10. WCAP-12011, Addendum 1, "Technical Justification for Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis for Sequoyah Units 1 & 2," Revision 1, April 2011 E3 - 22 of 22

ENCLOSURE 4 Tennessee Valley Authority Sequoyah Nuclear Plant, Units I and 2 License Renewal Revised Responses to RAI Questions 1.4-2, 1.4-3 and 1.4-4

ENCLOSURE4 Tennessee Valley Authority Sequoyah Nuclear Plant, Units I and 2 License Renewal Revised Responses to RAI Questions 1.4-2, 1.4-3 and 1.4-4 RAL 1.4-2 Backaround:

The response to RAI. 1.4-2 stated, "[tlhe thickness measurements showed no indications of loss of material as all were above the nominal thickness less the mill tolerance allowed by API 650."

API-650 (1998) Section 2.2.1.2.3 states, "[w]hether an edge-thickness or a weight basis is used, an underrun not more than 0.25 mm (0.01 in.) from the computed design thickness or the minimum permitted thickness is acceptable."

Follow-up Questions:

1. Is the 0.01" value in API-650 the mill tolerance referred to in the RAI response?

2. For the available tank UT inspections results, what are the minimum reading, maximum reading, and nominal reading for each of the tanks? In addition, provide the design minimum wall thickness for the tanks. Alternatively, place the tank UT wall thickness inspection reports on the docket.

TVA Response to Follow-up Questions on RAI B.1.4-2

1. The 0.01 inch value is the API-650 mill tolerance referred to in the RAI response.

2. To respond to this follow-up question, the response to RAI B.1.4-2 has been changed to the following with additions underlined and deletions lined through.

"There is reasonable assurance that the exterior surface of the seven-day emergency diesel generator (EDG) fuel oil storage tanks will continue to perform their intended function during the period of extended operation consistent with the current licensing basis because the tanks are encased in structural concrete that meets American Concrete Institute (ACI) 318.

Cracking of this concrete is controlled through proper arrangement and distribution of reinforcing steel and is constructed of a dense, well-cured concrete with an amount of cement suitable for strength development, and achievement of a water-to-cement ratio which is characteristic of concrete having low permeability. This is consistent with the recommendations and guidance provided by ACI. The EDG tanks are located approximately twenty three feet above the anticipated high ground water elevation. In addition the exterior of the tanks are coated with red lead in oil paint.

Internal inspections of the sixteen EDG seven-day fuel oil storage tanks were completed in February 2013. The inspections included ultrasonic (UT) thickness measurements at E4 - 1 of 5

96 locations on each tank. The thickns messeasur*e*mts showe-d no indications of los ot mnaterial as all were above the nomn*f,.l thiGcRkes less the mill tlera*nA alloAed by API 650.

The minimum UT inspection wall thickness reading for the EDG tanks was 0.24 inches and the maximum wall thickness was 0.296 inches.

The minimum wall thickness for each tank ranged from 0.24 inches to 0.261 inches. The maximum wall thickness for each tank ranged from 0.26 inches to 0.296 inches.

The average wall thickness reading for the EDG tanks was 0.258 inches. The nominal wall thickness is 0.25 inches.

The minimum EDG tank wall thickness (hoop stress plus a corrosion allowance of 0.125 inches) is 0.175 inches.

These UT inspection results following more than 30 years of service provide additional assurance that the buried EDG fuel oil storage tanks will remain capable of performing their intended functions through the period of extended operation In summary, there is reasonable assurance that the seven-day EDG carbon steel fuel oil storage tanks will continue to perform their intended function during the period of extended operation consistent with the current licensing basis due to the design of the structural concrete encasing the tanks, the elevation of the tanks above groundwater, and the coating, on the exterior of the tanks."

E4 - 2 of 5

RAI B. 1.4-3 Backlround The Background for RAI B. 1.4-3 Part (1) stated, "[e]arthfill is, in part, defined as possibly containing organic material." The response stated, "fe]arthfill has been used as backfill in the vicinity of buried in-scope components at SQN." The RAI response addressed the size of rocks in the backfill; however, it did not address the potential for organic materials to be in close vicinity to buried in-scope piping.

Follow-up Question:

The staff cannot complete its evaluation of this issue without understanding how the presence of organic materials was controlled by either alternative plant-specific specifications that were not discussed in the RAI response or by the results of examining backfill content during recent excavations. Alternatively, a set number of excavated direct visual inspections of backfill and piping could be proposed that would include examination for organic materials with an accompanying proposal of augmented inspections if organic materials are found.

TVA Response to Follow-up Question on RAI B.1.4-3 To respond to this follow-up question, the response to RAI B. 1.4-3 Response #1 has been changed to the following with additions underlined and deletions lined through.

"1. Earthfill has been used as backfill in the vicinity of buried in-scope components at SQN.

En-gineering specifications require materials, including earth, used for earthfill to be free of organic matter. Fine granular fill (sand), meeting the gradation limitations of ASTM C33 and free of deleterious material, may have also been used as backfill. The design requirements do not allow for coarse granular backfill (rockfill) in the vicinity of buried in-scope components. The backfill used at SQN, as defined in installation requirement documents, meets the aggregate size and compactability requirements defined in LR ISG-2011-03.

Reasonable assurance has been established that the buried in-scope components will meet their intended function consistent with the current licensing basis because design documents specify that the backfill is free of rock."

E4 - 3 of 5

RAI B. 1.4-4

Background:

The response to RAI 1.4-4 stated, "[c]athodic protection will be provided based on the guidance of NUREG-1801, section XI. M41, as modified by LR-ISG-2011-03. Thus, as indicated in LRA section B. 1.4, the Buried and Underground Piping and Tanks Inspection Program will be consistent with the program described in NUREG-1801, section X1.M41, as modified by LR-ISG 2011-03, including provisions for providing cathodic protection."

The staff noted that Commitment No. 3 was revised to state, "[c]athodic protection will be provided based on the guidance of NUREG-1801, section XI. M41, as modified by LR-ISG-2011-03."

However, the UFSAR supplement was not revised to reflect that cathodic protection will be installed prior to the period of extended operation.

Follow-up Question:

The UFSAR supplement should reflect that cathodic protection will be installed prior to the period of extended operation in order to be consistent with LR-ISG-2011-03.

TVA Response to Follow-up Question on RAI B.1.4-4 To respond to this follow-up question, the following sentence has been added to the LRA changes detailed in the original response to RAI B.1.4-4:

"Based on the guidance of NUREG-1801,Section XI.M41, as modified by LR-ISG-2011-03, cathodic protection will be provided at SQN prior to the period of extended operation of Unit 1."

Therefore, the changes to LRA Appendix A, Section A.1.4, (Buried and Underground Piping and Tanks Inspection Program) and LRA Appendix B, Section B.1.4, (Buried and Underground Piping and Tanks Inspection Program) follow with additions underlined and deletions lined through.

The Buried and Underground Piping and Tanks Inspection Program manages loss of material and cracking for the external surfaces of buried and underground piping fabricated from carbon steel and stainless steel through preventive measures (i.e., coatings, backfill, and compaction), mitigative measures (e.g., electrical isolation between piping and supports of dissimilar metals), and periodic inspection activities (i.e., direct visual inspection of external surfaces, protective coatings, wrappings, and quality of backfill) during opportunistic or directed excavations. There are no underground or buried tanks at SQN for which aging effects are managed by the Buried and Underground Piping and Tanks Inspection Program.

Based on the guidance of NUREG-1801,Section XI.M41, as modified by LR-ISG-2011-03, cathodic protection will be provided at SQN prior to the period of extended operation of Unit 1.

GCRt ho9dicG protection is-not intlld I athedic protection i6 not provided prior to the poriod of extended operation, tho progFram Will inc-lude documented justification that ctoi protection i6 not warranted. The justificationR should include-19 the result6 Of soltesting E4 - 4 of 5

(inc~luding tostS for soil resistivity, corrosion accelerating bacteria, pH, moisture, chlorides and-ro-dox potential) to demonsRtra;te that the soil envr10Onmont is not corrosive to applicable bmried v

cmponents. ThV re-lits of a re*i*es of I;t least ton years of operating expvi MUst support the conclusionR that cathodic protection is not warranted. The review of ten years of operatrg e nreview of operating experience with ompnGeRn*

vnot in the scope of Icense remne al if they are fabrmiated from thetvmevm;vv materials 2nd exposed to-the sameRr enionets. -AsAnscp buried and underqgroud coemponen.

If a reduc-tion i the number~q of inpetin GrcomnnRded inTabl 4:; of hi REG-1 8014, Sec-tion XI.MI OR is lai.meqd basred on; a lack of soil coerro-sivity as determined by coil testing, then AsAOil testing shou-Ild be conducQted once in each ton year period starting ten years prior to the perio-d of extended operation. This program will be implemented prier to the period operation."

This programn will be ipentdprior to the period of extended operatfion."

E4 - 5 of 5

ENCLOSURE 5 Tennessee Valley Authority Sequoyah Nuclear Plant, Units I and 2 License Renewal Regulatory Commitment List, Revision 5

ENCLOSURE5 Tennessee Valley Authority Sequoyah Nuclear Plant, Units I and 2 License Renewal Regulatory Commitment List, Revision 5 Commitments 10 and 37 have been revised.

LRA No.

COMMITMENT IMPLEMENTATION SECTION SCHEDULE IAUDIT ITEM Implement the Aboveground Metallic Tanks Program as described 3QNI: Prior to 09/17/20 B.1.1 in LRA Section B.1.1 3QN2: Prior to 09/15/21 2

A. Revise Bolting Integrity Program procedures to ensure the 3QN1: Prior to 09/17/20 B.1.2 actual yield strength of replacement or newly procured bolts will be 3QN2: 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.

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.

E I of 16

N IMPLEMENTATION SECTION SCHEDULE I AUDIT ITEM 4

A. Revise Compressed Air Monitoring Program procedures to SQNI: 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-1998, 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.

E 2of16

LRA No.

COMMITMENT IMPLEMENTATION SECTION 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

/ 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.

E 4of16

LRA No.

COMMITMENT IMPLEMENTATION SECTION SCHEDULE

/AUDIT ITEM 7

A. Revise Fatigue Monitoring Program procedures to monitor and SQN1: 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.

8 A. Revise Fire Protection Program procedures to include an 3QN1: Prior to 09/17/20 B. 1.12 inspection of fire barrier walls, ceilings, and floors for any signs of 3QN2: 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 3QN1: Prior to 09/17/20 B.1.13 visual inspection of fire water system internals for evidence of 3QN2: 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 initial evaluations will be used to determine the appropriate inspection interval to ensure aging effects are identified prior to loss of intended function.

E 5of16

LRA No.

COMMITMENT IMPLEMENTATION SECTION SCHEDULE

/AUDIT ITEM (9)

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 SQN1: 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 Controllinq Cavitation, Flashing, Liquid Droplet Impingement, and Solid Particle Erosion in Nuclear Power Plant Pipinq, and NUREG/CR-6031, Cavitation Guide for Control Valves. (TVA Response to Set 6.60day RAI B. 1.14-1 and B. 1.38-1)

E 6of16

LRA IMPLEMENTATION SECTION No.

COMMITMENT SCHEDULE

/ AUDIT ITEM 11 Revise Flux Thimble Tube Inspection Program procedures to 3QN1: Prior to 09/17/20 B.1.15 include a requirement to address if the predictive trending projects 3QN2: 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, 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

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LRA No.

COMMITMENT IMPLEMENTATION SECTION SCHEDULE I AUDIT ITEM 15 Implement the Metal Enclosed Bus Inspection Program as SQNl: Prior to 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)

QN 1: Prior to 09/17/20 B.1.25 Program as described in LRA Section B.1.25 QN2: 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 SQNI: Prior to 09/17/20 B.1.27 Program as described in LRA Section B.1.27 SQN2: Prior to 09/15/21 21 A. Revise Oil Analysis Program procedures to monitor and SQN1: 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 SQN1: 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 SQNI: 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 SQNI: 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 I 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, Revi.

27 A. Revise Reactor Vessel Internals Program procedures to take SQNI: Prior to 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-E185-82 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.

E 9of16

LRA No.

COMMITMENT IMPLEMENTATION SECTION SCHEDULE I 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.

3QN2: Prior to 09/15/21 30 Revise Steam Generator Integrity Program procedures to ensure 3QN1: Prior to 09/17/20 B.1.39 that corrosion resistant materials are used for replacement steam 3QN2: Prior to 09/15/21 generator tube plugs.

31 A. Revise Structures Monitoring Program procedures to include the following in-scope structures:

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)

Beams, columns, floor slabs and interior walls (concrete)

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 Cable tray Cable tunnel Canal gate bulkhead Compressible ioints and seals 3QN1: Prior to 09/17/20 3QN2: Prior to 09/15/21 B.1.40 E

10of16

LRA N.COMMITMENT IMPLEMENTATION SECTION SCHEDULE

/ AUDIT ITEM (31) e Concrete cover for the rock walls of approach channel Concrete shield blocks Conduit Control rod drive missile shield Control room ceiling support system Curbs Discharge box and foundation Doors (including air locks and bulkhead doors)

Duct banks Earthen embankment 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 Ice baskets lattice support frames Ice condenser support floor (concrete)

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 Penetration seals (steel end caps)

Penetration sleeves (mechanical and electrical not penetrating primary containment boundary)

Personnel access doors, equipment access floor hatch and escape hatches Piles Pipe tunnel Precast bulkheads Pressure relief or blowout panels Racks, panels, cabinets and enclosures for electrical equipment and instrumentation E

11of16

LRA No.

COMMITMENT IMPLEMENTATION SECTION SCHEDULE

/AUDIT ITEM (31)

Riprap Rock embankment Roof or floor decking Roof membranes Roof slabs RWST rainwater diversion skirt RWST storage basin Seals and gaskets (doors, manways and hatches)

Seismic/expansion joint Shield building concrete foundation, wall, tension ring beam and dome: interior, exterior above and below grade Steel liner plate Steel sheet piles Structural bolting Sumps (concrete)

Sumps (steel)

Sump liners (steel)

Sump screens 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)

Support pedestals (concrete)

Transmission, angle and pull-off towers Trash racks Trash racks associated structural support framing Traveling screen casing and associated structural support framing Trenches (concrete)

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 buildinq E

12 of 16

LRA N IMPLEMENTATION SECTION SCHEDULE I AUDIT 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).

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.

Perform special inspections of water control structures immediately (within 30 days) following the occurrence of significant natural phenomena, such as large floods, I

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/ AUDIT ITEM (31) earthquakes, hurricanes, tornadoes, and intense local rainfalls.

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.

32 Implement the Thermal Aging Embrittlement of Cast Austenitic SQN1: 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 3QN1: Prior to 09/17/20 B.1.42 Systems Program procedures to provide a corrosion inhibitor for the SQN2: 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 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.

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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 I 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.

35 Modify the configuration of the SQN Unit 1 test connection access SQN1: 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 SQN1: 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.

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/AUDIT ITEM 37 TVA will implement the Operating Experience for the AMPs in No later than the B.0.4 accordance with the TVA response to the RAI B.O.4-1 on-July L9,

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

.Wo Yr ;aftkeri tthe SQN.

Jniots I A 21 RA i 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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