ML13247A427

Summary of Telephone Conference Call Held on August 19, 2013, Between the NRC and Tennessee Valley Authority, Concerning RAI Pertaining to the Sequoyah Nuclear Plant, Units 1 and 2, LRA

ML13247A427
Person / Time
Site:	Sequoyah
Issue date:	09/23/2013
From:	Plasse R License Renewal Projects Branch 1
To:	Tennessee Valley Authority
Sayoc E, 415-4084
References
TAC MF0481, TAC MF0482
Download: ML13247A427 (36)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 September 23, 2013 LICENSEE: Tennessee Valley Authority FACILITY: Sequoyah Nuclear Plant, Units 1 and 2

SUMMARY

OF TELEPHONE CONFERENCE CALL HELD ON AUGUST 19, 2013, BETWEEN THE U.S. NUCLEAR REGULATORY COMMISSION AND TENNESSEE VALLEY AUTHORITY, CONCERNING REQUESTS FOR ADDITIONAL INFORMATION PERTAINING TO THE SEQUOYAH NUCLEAR PLANT, UNITS 1 AND 2, LICENSE RENEWAL APPLICATION (TAG NOS. MF0481 AND MF0482)

The U S_ Nuclear Regulatory Commission (NRC or the staff) and representatives of Tennessee Valley Authority held a telephone conference call on August 19, 2013, to discuss and clarify the staff's requests for additional information (RAis) concerning the Sequoyah Nuclear Plant, Units 1 and 2, license renewal application. The telephone conference call was useful in clarifying the intent of the staff's RAis. provides a listing of the participants and Enclosure 2 contains a listing of the RAis discussed with the applicant, including a brief description on the status of the items.

The applicant had an opportunity to comment on this summary.

R i c d . s e , Project Manager Projects Branch 1 Division of License Renewal Office of Nuclear Reactor Regulation Docket Nos. 50-327 and 50-328

Enclosures:

1. List of Participants

2. List of Requests for Additional Information cc w/encls: Listserv

TELEPHONE CONFERENCE CALL SEQUOYAH NUCLEAR PLANT, UNITS 1 AND 2 LICENSE RENEWAL APPLICATION LIST OF PARTICIPANTS AUGUST 19, 2013 PARTICIPANTS AFFILIATIONS Richard Plasse U.S. Nuclear Regulatory Commission (NRC)

Emmanuel Sayee NRC James Medoff NRC Duke Nguyen NRC Ata lstar NRC Alice Erickson NRC Bart Fu NRC Henry Lee Tennessee Valley Authority (TVA)

Dennis Lundy TVA Andrew Taylor TVA Alan Cox Entergy/Enercon Stan Bach Entergy/Enercon ENCLOSURE 1

REQUESTS FOR ADDITIONAL INFORMATION DISCUSSED SEQUOYAH NUCLEAR PLANT, UNITS 1 AND 2 LICENSE RENEWAL APPLICATION AUGUST 19, 2013 The U.S. Nuclear Regulatory Commission (NRC or the staff) and representatives of Tennessee Valley Authority held a telephone conference call on August 19, 2013, to discuss and clarify the following requests for additional information (RAis) concerning the license renewal application (LRA).

The Sequoyah Nuclear Plant, Units 1 and 2 (SQN), RAis of set 11 (ML13224A126), were discussed and a mutually agreeable date for the response of RAis 4.1-Sa, 4.6-1, B.1.40-4a, and B. 1.17-1 a was set within 60 days from the date of the letter on August 22, 2013. For the rest of the enclosed RAis a mutually agreeable date for the response was set within 30 days from the date of the letter.

RAI4.1-4a (Follow-up)- changes were made as marked up below, and a mutual understanding was reached by the staff and the applicant.

Background:

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

on whether the flaw analysis for the reactor coolant pump (RCP) casings at Sequoyah Units 1 and 2 would need to be identified as a Time Limited Aging Analysis (TLAA} for the L1cense Renewal Application (LRA} in accordance with 10 CFR 54.21(c)(1) TLAA identification requirements.

Issue:

To resolve the RAI request, the applicant must demonstrate that the analysis does not conform to one or more of the six definition criteria that are used to define a plant analysis as a TLAA, as given in 10 CFR 54.3{a). In its response to RAI4.1-4, Parts a. and b., the applicant relies on a future licensing basis change that the applicant claims will be done during the Period of Extended Operation (PEO} and uses this future licensing basis change in the PEO as the sole basis for concluding that the supporting flaw tolerance analysis for the RCP casings does not need to be identified as a TLAA. This is not acceptable because the basis did not demonstrate why the stated analysis is not in conformance with all six definition criteria for TLAAs in 10 CFR 54.3(a) or why the analysis would not need to be identified pursuant to the TLAA identification requirement in 10 CFR 54.12(c)(1) and the six criteria for TLAAs in 10 CFR 54.3(a).

Request:

_1._Ciarify whether ASME Code Case N-481 and the supporting flaw tolerance evaluation for the RCP casings are cuneRtty--being relied upon in the CLB as the basis for performing alternative visual examinations of the RCP casing welds, and if so, justify why the flaw tolerance analysis would not need to be identified as a TLAA for the LRA, as based on the CLB for the Sequoyah units at time of the LRA review. Respond to Part -2 of this request if th1s Code Case is still being relied upon for the CLB.

ENCLOSURE 2

Clarify how the flaw tolerance evaluation addressed potential drops in the fracture toughness property of the CASS RCP casing material during the period of extended ~at+GHPEO, and justify why the assessment of loss of fracture toughness in the evaluation would not need to be within the scope of a TLAA for the LRA.

RAI4.1-6a (Follow-up)- changes were made as marked up below, and a mutual understanding was reached by the staff and the applicant.

Background:

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

The staff has determined that the applicant's response demonstrates that the flaw evaluation for the Unit 2 BIT does not need to be identified as a TLAA because the analysis: (a) does not involve time-dependent assumptions defined by the current operating term, and (b) does not conform to the definition of a TLAA in 10 CFR 54.3(a). However, the staff noted that the applicant does not identify cracking as an aging effect requiring management for the BIT in LRA Table 3.3.2-1 0, and does not specifically credit augmented inspections under the applicant's .!.!:!:

service Inspection (1811 Program (LRA AMP B.1.16) to manage cracking that was detected in the Un1t 2 BIT.

Request:

Identify the mechanism that initiated the flaw in the BIT bottom head-to-shell weld and identify whether this mechanism was age-related. In addition, clarify whether the flaw in the BIT bottom

-head-to:-shell weld could grow by an age-related growth mechanism, such as cyclical loading or one of the stress corrosion cracking mechanisms, regardless of the cause for initiation of the flaw in the BIT bottom head-to-lower shell weld. Justify why cracking (including crack growth) has not been-aflfXGftfiatel-y listed in LRA Table 3.3.2-10 as an applicable aging effect requiring management for welds in the BIT and why the applicant's lnservice lnspectioolSI Program (LRA AMP B.1.17) has not been credited to manage cracking in the BITs.

RAI4.1-8a (Follow-up)- changes were made as marked up below, and a mutual understanding was reached by the staff and the applicant.

Background:

By letter dated July 11, 2013, the applicant provided its responses to RAI 4.1-8, Parts 1 and 2, on whether the UFSAR Section 10.2.3 includes any plant turbine analyses that would need to be identified as TLAAs in accordance with requirements for identifying TL..AAs in 10 CFR 54.21 (c)(1) The staff has determined that the applicant's response to RAI 4.1-8. Part 1 provides adequate demonstration that the probabilistic analyses for the high pressure turbines (HPTs) and low pressure turbines (LPTs) do not need to be identified as TLAAs for the LRA.

Issue 1:

The applicant stated in its response to RAI 4.1-8, Part 2 that evaluation of stress corrosion cracking (SCC) in Westinghouse Report WSTG-1-NP (i.e., Reference 3 in the RAI response) is not a TlAA because it does not involve time-limited assumptions. However, SCC is identified in GALL Table IX.F as time-dependent aging mechanism, which implies that the analysis of SCC involves a time-limited assumption, unless demonstrated to the contrary.

In contrast, the response to the RAI did not provide any reason why the analysis does not involve a time-limited assumption and therefore does not adequately demonstrate that the evaluation of sec in the referenced Westinghouse analysis would not need to be identified as a TLAA for the LRA.

Request 1:

Explain how the analysis of sec was performed in Westinghouse Technical Report No. WSTG-1-NP (i.e., Ref. 3 in the response to RAI4.1-8). Based on this explanation, clarify why the analysis of SCC in the report is not considered to involve time-limited assumptions. Based on your response, provide your basis (i.e., justify) why the analysis of sec in the referenced Westinghouse report does not need to be identified as a TLAA, when compared to the six criteria for defining an analysis as a TLAA in 10 CFR 54.3(a).

Issue 2:

The applicant stated in its response to RA14.1-8, Part 2 that "no fatigue-based analysis was required or used in the turbine missile evaluation." However, UFSAR Section 10.2.3 (i.e.

UFSAR page 10.2-9) makes the following statement:

Prior to 1980, the Westinghouse missile probabilities and energies analyses were directed primarily at missile generation due to destructive overspeed. Fatigue of the rotating elements due to speed cycling was also considered as a missile generation mechanism in these earlier analyses. These earlier Westinghouse analyses indicated that the probabilities of missile generation due to fatigue and destructive overspeed were very low in comparison to the probability estimated by Bush. The Bush probability (1 x 100-4 missile producing disintegrations per turbine operating year) was chosen for the original Sequoyah missile hazard evaluation in order to provide a very liberal margin of safety.

Based on this UFSAR statement, it appears that the Westinghouse fatigue analyses of the LPT rotating elements were used to confirm the missile generation probabilities of the Bush studies (as referenced in the UFSAR and response to RAI 4.1-8, Part 1) that were used for the LPTs. It is not evident why these Westinghouse analyses would not need to be identified as TLAAs for the LRA

Request 2:

1. Identify the Westinghouse fatigue analyses that were referenced on UFSAR page 10.2-9 and performed in analysis of the LPT rotating elements.

2. Explain how the assessment of fatigue was performed in these analyses.

3. Provide your basis (i.e., justify) why the stated Westinghouse fatigue analyses of the LPT rotating elements would not need to be identified as TLAAs for the LRA, when compared to the six criteria for defining an analysis as a TLAA in 10 CFR 54.3(a).

RAI4.1-11a (Follow-up)- changes were made as marked up below, and a mutual understanding was reached by the staff and the applicant

Background:

By letter dated July 11, 2013, the applicant provided its responses to RAI 4.1-11, which provided the applicant's basis on why the exemption for use of ASME Code Case N-514 as the basis for establishing the temperature enable settings for the low temperature overpressure protection (LTOP) system does not need to be identified as an exemption for the LRA in accordance with the requirements in 10 CFR 54.21 (c)(2). In its response, the applicant stated that ASME Code Case N-514 has been incorporated into ASME Section XI, Appendix G, and therefore, this exemption will not be required when the pressure-temperature limits are updated for the penod of exteflded*operationPEO. The applicant stated that an LRA amendment is not needed with respect to identifying this exemption as an exemption that meets the requirements in 10 CFR 54.21(c)(2)

Issue:

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

The Pressure Temperature Limits Report (PTLRl and WCAP-15293 for Un1t 1 and PTLR and WCAP-15321 for Un1t 2 refer to ASME Code Case N-514 1n relationship to establishing the enable temperature for the LTOP system in each un1t. However. the CLB for each un1t still contains an exemption to use ASME Code Case N-514 for the pressure lift setpoints and enable temperatures of the plant LTOP systems. As such. the exemption to use Code Case N-514 may be based on a TLAA since the exemption allows the applicant to establish these setpoints based on a mathematical function of the limiting adjusted reference temperature (RT NoT value) for Jb.e reactor vessel beltline materials. Therefore. the staff needs further justification why the exemption for use of ASME Code Case N-514 had not been identified as an exemption that meets the exemption identification critena in 10 CFR 54.21 (c)(2) and why this exemption has

not been included in the LRA and disposit1oned in accordance w1th the exemption requirements m 10 CFR 54.21jc)(2)

The current Pressure Temperature Lo.ifnHs Report (PTLR}--for-Unit 1 and PTLR-ffir Unit 2 both t1st ASME Code Case-N 514 as the ClJfrent methodology--Gasis--+n the CLB for establishing tf:le enable temperature setpoint -for the-h-+GP system in--each unit, even though the applicant does have the option of--arnendmg its licensing basis during period of extended operation- to etiminate ffie--.need for application -of-AS ME Code Case N 514. This exemption may be an--e-xemptfo-A--#tat is based on a TIJ\A since the enable temperature is based relative to a co~arison to the limiting adjusted reference temperature (RTNDT value) for--the reactor vessel bemtne matenals Therefore,- the--staff needs further JUStification why the-exemption for use of ASME Code Case N--514 had not been ident1f1ed as an exemption that meets the exemption identification criteria in 10 GFR 54_21(c)(2) and why this exemption has not been included in the LRA and dispos1tfe-fl-BG in accordance w1th the exempti-on--requirements in W G-FR 54 2 i (c)(2)_

Request

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

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

3 Clarify whether the use of 1\SME Code Case N 514 is eu+rently-refe-fe-A-GeG----Sequoya-A Report No_ PTLR 1 as the basis 1n the CLB for establishing the LTDP system enable temper-attire--setpoint for Un1t 1 -and in Soquoyah Report No. PTLR 2--as--the basis in the CLB for establishing the LTOP--system enable temperature setpoint for Un~t--2--o

________Based on your responses to Parts a, b .. --3REI----G1 and 2 of this RAI, justify why the exemption to use ASME Code Case N-514 for Units 1 and 2 would not need to be identified as an exemption for the LRA that meets the exemption identification requirements in 10 CFR 54 21(c)(2).

RAI 4.6-1 -changes were made as marked up below, and a mutual understanding was reached by the staff and the applicant.

Background:

Per SRP-LR Section 4.6.1.1.1 for a TLAA to be dispositioned in accordance with 10 CFR 54.21 (c)(1 )(i), the existing analyses must be verified to be valid and bounding for the period of extended operation. SRP-LR Section 4.6.3.1.1 states that the existing analyses should be shown to be bounding even during the period of ex-tended operationPEO.

LRA section 4.6 states "Analyses were identified for bellows assemblies for the penetrations Hnt s!_<.!~ed they_ were qualified for 7000 cycles of the design displacements. The number of design displacements expected to occur from either thermal changes or containment pressurizations is much less than 7000. Therefore, the associated penetrations bellows are

qualified for the PEO. The analysis remains valid for the PEO in accordance with 10 CFR 54.21 (c)(1 )(1)."

Issues:

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

Requests:

To ensure "the est1mated number of cycles"' are within "the qualifying limit of 7000 cycles ..

describe how the qualify1ng limit of 7000 cycles was determined, and provide the estimated number of cycles due to cyclic loading conditions (e.g .. thermal, pressure, etc.) for the containment penetration bellows at the end of PEQ_

Explain- and just1fy hov.*-the existing analyses used in the bRA to estimate the number of displacements-fer bellov+'s assemblies of the penetratiOAs expected to--occur include those fBf thermal changes-or containment pressunzations. and pmvide information on the bas1s--fof sta-hng t-hat the analyses rema1n valid to-the end-of the PEO_

RAI B.1.40-1a (Follow-up)- changes were made as marked up below, and a mutual understanding was reached by the staff and the applicant.

Background:

Based on its audit of the applicant's program basis document for the Structures Monitoring Program, it is not clear that the preventive actions for storage, lubricants, and corrosion potential discussed in Section 2 of the Research Council for Structural Connections--tRCSC-j- publication

Specification for Structural Joints Using ASTM A325 or A490 Bolts," will be used consistent with the recommendations in the GALL Report.

Issue:

The applicant's response to RAI 8.1.40-1 dated July 1, 2013 states that the Structures Monitoring Program employs the preventive actions for storage, lubricants, and corrosion potential. The program basis document stated that the preventive actions of Section 2 of Research Council for Structural Connections publication "Specification for Structural Joint Using ASTM A325 and A490 bolts" have been considered in existing plant procedures for ASTM A325 and A490 bolting. However, during its audit, the staff found that the existing procedures provided as part of the program basis document for the Structures Monitoring Program did not include the preventive actions for storage, lubricants and corrosion potential. The staff has not been provided with sufficient information to verify that the preventive actions program element of the Structures Monitoring Program is consistent with the GALL Report without enhancement or exception, as claimed by the applicant in the LRA.

Request:

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

2. If the procedures describing these preventive actions were not refere_Dc§QorovJde-d in the program basis document when audited, provide clarification and make revisions to the LRA and UFSAR supplement as necessary.

RAI B.1.40-4a (Follow-up) - changes were made as marked up below, and a mutual understanding was reached by the staff and the applicant.

Background:

Based on the response dated July 1, 2013, the technical evaluation of the groundwater in-leakage concluded that 1) the condition would not affect the intended function of the structure elements, and 2) the technical evaluation of the crack concluded that the structural capability of the turbine building north wall was not unacceptably impaired and that the wall would continue to perform its design function.

The response stated that minor groundwater in-leakage has been observed and documented in several Category! 1 structures since 1996. Inspections of the turbine building (as listed in the LRA), a non-Category I structure, noted in-leakage in the basement floor slab at elevation 662.5' and significant in-leakage for the north and south perimeter walls above floor elevation 662.5' and floor elevation 685'. The response also stated that the turbine building is the most significant of the structures within the scope of the Structures Monitoring Program due to the constant moisture in-leakage over large areas of the structure. Although leak repairs have been initiated, the staff observed conditions during the audit walkdowns that may need further evaluation to demonstrate that the effects of aging will be adequately managed during the period of extended operation. The staff is concerned that the continued constant exposure to groundwater in-leakage may affect the integrity of the reinforced concrete during the period of extended operation.

Issue:

1. The technical basis, supporting the evaluation that concluded the groundwater in-leakage into the turbine building would not affect the intended function of the structure, was not provided.

2. The technical basis, supporting the evaluation that concluded the structural capacity of the turbine building north wall was not unacceptably impaired, was not provided.

3. Considering the history of constant groundwater in-leakage, in the absence of a plan to further evaluate the condition of the below-grade concrete, the staff is concerned that the periodic visual inspections, performed under the proposed Structures Monitoring Program, may not provide sufficient information, regarding the integrity of the concrete and reinforcing steel, for monitoring and trending of the structure during the period of extended operation.

Request:

1 Provide additional information regarding the technical evaluation that was performed, which concluded the groundwater in-leakage would not affect the intended function of the turbine building. Include the following details in the response:

a. Qompletion dQate in- for which the technical evaluation was--pe-FfefHlBd and if/when it was re-evaluated

b. Description of activities performed (e.g. visual inspection, testing, structural analyses, chemical analyses)

c. Description of the qualitative or quantitative acceptance criteria used

d. Discussion of results obtained supporting the conclusion reached

e. Corrective actions taken, if any

f. Structural drawing(s) detailing the below grade-concrete in the area considered to have the most significant in-leakage, indicating floor elevations, water table elevation, concrete wall and floor slab thickness, rebar details. Indicate on the drawing the approximate locations of groundwater in-leakage.

2. Provide additional information regarding the technical evaluation of the large diagonal crack on the north wall of the turbine building, which concluded that the structural capacity of the turbine building north wall was not unacceptably impaired. Include the following details in the response:

a. Width of the crack at its widest point

b. History of crack growth

c. Discussion about the source of rust colored stains on the wall and flowing out of the crack

d. Description of activities performed (e.g. visual inspection, testing, structural analyses, chemical analyses)

e. Discussion of results obtained supporting the conclusion reached

f. Corrective actions taken, if any

g. Sketch detailing the location and dimensions of the crack, and areas of spalling.

3. In the absence of a plan to mitigate the groundwater in-leakage, explain how the proposed Structures Monitoring Program will adequately manage the potential increase in porosity and permeability and loss of strength due to leaching of calcium hydroxide:

cracking due to expansion from reaction with aggregates; and cracking, loss of bond, and loss of material due to corrosion of embedded steel. Include any plans for testing and/or inspections that may demonstrate the effects of aging will be adequately managed during the period of extended operation.

RAI3.1.2-4-1a (Follow-up)- changes were made as marked up below, and a mutual understanding was reached by the staff and the applicant.

Background:

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

The staff considers reduction of heat transfer in steam generator tubes to be an applicable aging effect requiring management. The staff notes that heat transfer is the intended function for the steam generator tubes, and without proper management. the intended function could be compromised '*EPR.I Steam Generator Integrity Assessment Guidelines** provides -gutdm-BR maintenance for-steam generator components, including secondary side cleaning. Sect-ion---+G-4 Bf--the EPRI guidelines describes tho guidance on preventing "heat.transfer limitat4~

manage reduGtfcn of heat transfer for steam generator tubes_ ---The applicant's-Steam Generator Integrity Program. in part--4ncludes secondary side ma~ntenance activities, such as sludge klnGing. for removing deposits that may contribute to aging related degradation_ The app!icanfs program should-+mplement the EPRI guidelines m-accordance with NEI 97 06, consistent-with

\Ae-GALL Report.

Request:

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

RAI 8.1.25-1a (Follow-up)- changes were made as marked up below, and a mutual understanding was reached by the staff and the applicant

Background:

In a letter dated May 31, 2013 the staff issued RAI 8.1.25-1 requesting additional information t-R-at----demonstrates on the correctiveproact1ve actions taken to prevent in-scope inaccessible power cable exposure to significant moisture including- manhole, sump pump, and cable support structure inspection and, maintenance. and correcbve actions_ The staff also requested the applicant to include a summary discussion of the complete schedule for inaccessible cable corrective actions--and----tAei-f--schedule for completion. The staff further requested the applicant describe inaccessible power cable testing {e.g , test frequency, and test-applicable+hly- tests) pertorme_g_ that demonstrates that in-scope inaccessible power cables will continue to pertorm their intended function consistent with the current licensing basis (CLB)before and during-t-he per-iod of extended -eperation {PEO).

In response to the staff's RAI, in a letter dated July 1, 2013, the applicant stated that as documented in the SON corrective action program, there have been multiple instances of water in manholes at SON. In 2012, a report was initiated in the correction action program to document the trend of high levels of water in manholes that the work control process is not resolving in a timely manner. In response to the identified issues with untimely removal of water

from manholes, the preventive maintenance (PM) task instructions were revised to require water removal, if found, from the manholes before the PM task could be closed SON experience since revising the PM instruction has been that the water, if any, has been removed within a week of initiating the PM activity. The applicant also stated that as a result of operating experience (OE) with water in the manholes, a team of TVA personnel was established in early 2013 to resolve the dewatering issues with safety-related manholes. The team is scheduling activities which will repair or replace sump pumps and discharge piping as necessary to improve dewatering peliormance. In addition, TVA stated it is issuing a modification to enhance the ability to remove water from manholes without having to remove the heavy missile shield manhole covers. The applicant further stated that a cable support structure inspection is performed at least once every five years as part of the SON ptructu[s;§ Cl:JQll.l!..QELrJ.9Surve+ilance maintenance program (SMP). F1nally. the applicant stated and--that the inspections described in NUREG-1801,Section XI.E3 will be implemented as part of the new SON Non-EO Inaccessible Power Cables (400 V to 35 kV) Program described in LRA Section 8.1.25 prior to entering the PEO. During the PEO, the periodic inspections of manholes including cable support structures will be completed at least once every year (annually).

The applicant's-PM program for inaccessible cables may allow unacceptable water levels to remain in the manhole for an extended periodup to a *.veek before corrective action to remove the water is completed. The staff noted that because of the difficulty in removal of the Ae-a-vy manhole covers, there was-has been limited manhole Inspection and preventtve--maintenance of the sump pumps to ensure sump pumps were operable and capable of preventing cable submergence. In addition, based on OE with water in manholes, the staff is concerned that the current five year inspection frequency for manhole structures 1nclud1ng cable supports may not be adequate.

The applicant's RAI response did not provide describewfta.t the corrective actions to be that Will be--taken to ensurefor manhole Inspection and maintenance the operahon--of sump pumps to prevent exposure of cables to significant moistureunacceptable 'Nater-levels. The staff is concerned that the applicant's manhole inspections and corrective actions may not be adequate to prevent in-scope inaccessible power cables fro01m being subjected to significant moisture.

The staff could not determine based on current OE if the applicant's non-EQ Inaccessible Power Cable aging management program will ensure that in scope inaccessible power cables will continue to perform their intended function be effective during the period of extended operationPEO.

Request:

1. Describe Row-t-he--inspection frequency for water collection and manhole support stFuctures -are established and adjusted for plant specific and Industry operating experience-

_1._Describe wR--atcorrective -actions (e g., mspection, preventive maintenance) and 1nspections including frequency,...ffi.at- have W+l-l----been taken to ensure the operation of sump pumps to prevent exposure of 1n-scope inaccessible power cables to siqn1ficant

mo1stureurta{;{;f)table water levels1gnificant mo1sture. Include a discuss1on of the completion schedule to Implement the correct1ve act1ons 2.-- Prov1de a technical justification for the current 5 year inspection frequency for in-scope manhole cable support structures g1ven plant specific OE with water 1n the manholes and GALL Report AMP XI E3 guidance. Include a discussion on how the interval for water collection and inspection of manhole structures including cable supports 1s established and adjusted for plant specific and industry operating experience.

2 3 Describe preventive maintenance activities that have _Q:een t-akBR-e-r--wH-l---8e--tak-8-f\--te ensure that sump pumps are operable to prevent cable tlbmergence,

4. Provide---a-technical justification for the Gl:tfrent five year 1nspect1on-fFequency intefva-1--fu.t:

1n scope manholes and cable support structures giYOA-the plant __ specific 0~-with water in the manhe-J.es-,

3 For in-scope inaccessible power cables subjected to submergence (significant moisturel, how is the condition and operability of these cables determined? Describe the tests and inspections performed as part of the corrective action to ensure that these cables remain capable of performing their intended function consistent w1th the current licens1ng basisduring the PE-G.

Xl, __~_3 .Ihe*QU!JlOSe of the aging management program (AMP) .Qescnbed here_i_Q __ is to P.f9VIde reasonable assurance that the intended functions of 1naccessiblt9f oodefground power cables that are not subject to the environmental qualification Feq-lHfements of 10 CFR 50 4Q and are exposed to wett~ng or -submemef1.<#-af8 mamta1ned consistent with the current licensing basis through th_E;!_~r~Df extended GgeFation-RAI B.1.17-1a (Follow up)- changes were made as marked up below, and a mutual understanding was reached by the staff and the applicant.

Background:

In its response of RAI 8.1.17-1 on July 1, 2013, the applicant stated "The configuration of the strainer allows leak off water to flow down the strainer and onto the ERCW strainer support causing corrosion. Planned corrective actions include a design modification of the strainer to prevent ERCW support from being continuously exposed to water, thus mitigating corrosion.

The modification proposed to install a "catch container" to the ERCW strainer to route the leak off water coming out of the top of the strainer to a floor drain." The LRA states "The program was developed in accordance with ASME Section XI, 2001 Edition through the 2003 Addenda as approved by 10 CFR 50.55a." Accordingly the ERCW strainer support components should satisfy the requirements Article IWF-3000, "Standards for Examination Evaluations," which may include examinations, corrective measures, evaluations, tests, etc., currently and during the period of extended operation. GALL Report AMP XI.S3, in program element "acceptance criteria," refers to the acceptance standards of IWF-3400, and states "other unacceptable

conditions include [I] ass of material due to corrosion or wear, which reduces the load bearing capacity of the component support."

Issue: In summary, the applicant will be implementing a corrective action of redirecting the leaking water on the ERCW strainer support components to a floor drain, thus mitigating corrosion. It is not clear how the corrosion process will be mitigated by restricting the leaking water on the ERCW strainer support components only, and is expected to perform its intended function during the period of extended operation.

Changing the degrading environment to a benign environment may not alleviate the initiated corrosion process of carbon steel supports subject to stresses under operating conditions. The incubation-stage of corrosion process may have already been completed on some of the support components. Material-weakening stage {cracking) of the carbon steel supports and their components and attachment welds may already have been initiated with an eventual outcome of a reduced load bearing capacity of the component support. It is not clear whether the LRA AMP In-service Inspection- IWF {ISI-IWF) Program will follow the recommendation of the GALL Report AMP XI.S3, program element "acceptance criteria," which is based on the requirements of ASME Code Section XI, Article IWF-3400 during the period of extended operation.

Request:

Provide what are the results of thethe- acceptance criteria for serv1ce evaluations of the ERCW strainer support components per the requirements of ASME Code Section XI, Article IWF-3000"Standards for Examination Evaluations."

RAI B.1.11-1a (Follow up)- the following RAI was added to the set and mutuallv agreed upon.

Background:

In its July 1, 2013, response to request for additional information {RAI) 8.1.11-1, the applicant provided its clarification on whether specific transients listed in RAI 8.1.1.11-1 will be monitored as part of the Fatigue Monitoring program. The applicant stated the cycle limits of {1) 2,000 cycles of "Step changes in letdown stream fluid temperature from 100°F to 560°F" and (2) 24,000 cycles of "Step changes in letdown stream temperature from 400°F to 560°F" for the Chemical and Volume Control System (CVCS) regenerative heat exchangers will not be monitored by the Fatigue Monitoring program.

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

Issue:

In its justification for the two transients for the CVCS regenerative heat exchangers, the applicant stated that the letdown fluid temperature normally remains stable for both units. The applicant further stated that a maximum of 90 cycles for each of the transients are expected through the period of extended operation. The staff is unclear on the how the applicant came to these conclusions. The applicant did not explain how it determined that the letdown fluid temperature normally remains stable or how it can confirm that the temperature during the transient will remain stable for the period of extended operation. The staff is unclear if the temperature stability is during normal operation or during the transient. Also, the applicant did not provide an explanation based on its plant configuration and operational history to support its calculation that 90 cycles is expected for each transient through the period of extended operation.

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

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

Request:

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

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

b. If the temperature is stable during these transients,

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

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

2. Describe how a maximum of 90 cycles for each of the aforementioned transients was calculated and justify that the calculations are consistent with plant configuration and operational history.

3. Describe and justify the programmatic elements of the Fatigue Monitoring Program that will manage the effects of aging due to fatigue on the RCPs, in accordance with 10 CFR 54.21(c)(1)(iii), given that the 15 cycles of design tensioning cycle lim1t for the RCP hydraulic studs and nuts will not be monitored.

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

• ML13247A427 *concurred via email OFFICE PM:RPB2:DLW PM:RPB1 :DLR PM:RPB1 :DLR BC:RPB1 :DLR NAME I King E Sayoc R Plasse Y Diaz-Sanabria DATE 9111113 911813 9123113 9/t 3113

SUMMARY

OF TELEPHONE CONFERENCE CALL HELD ON AUGUST 19, 2013, BETWEEN THE U.S. NUCLEAR REGULATORY COMMISSION AND TENNESSEE VALLEY AUTHORITY, CONCERNING REQUESTS FOR ADDITIONAL INFORMATION PERTAINING TO THE SEQUOYAH NUCLEAR PLANT, UNITS 1 AND 2, LICENSE RENEWAL APPLICATION (TAC NOS. MF0481 AND MF0482)

DISTRIBUTION:

HARDCOPY:

DLR RF E-MAIL:

PUBLIC RidsNrrDir Resource RidsNrrDirRpb1 Resource RidsNrrDirRpb2 Resource RidsNrrDirRerb Resource RidsNrrDirRarb Resource RidsNrrDirRasb Resource beth.mizuno@nrc.gov brian.harris@nrc.gov john.pelchat@nrc.gov gena.woodruff@nrc.gov siva.lingam@nrc.gov wesley.deschaine@nrc.gov galen.smith@nrc.gov scott shaeffer@nrc.gov jeffrey.hamman@nrc.gov craig.kontz@nrc.gov caudle.julian@nrc.gov generette.lloyd@epa.gov gmadkins@tva.gov clwilson@tva.gov hleeO@tva.gov dllundy@tva.gov

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 September 23, 2013 LICENSEE: Tennessee Valley Authority FACILITY: Sequoyah Nuclear Plant, Units 1 and 2

SUMMARY

OF TELEPHONE CONFERENCE CALL HELD ON AUGUST 19, 2013. BETWEEN THE U.S. NUCLEAR REGULATORY COMMISSION AND TENNESSEE VALLEY AUTHORITY, CONCERNING REQUESTS FOR ADDITIONAL INFORMATION PERTAINING TO THE SEQUOYAH NUCLEAR PLANT, UNITS 1 AND 2, LICENSE RENEWAL APPLICATION (TAC. NOS. MF0481 AND MF0482)

The U.S. Nuclear Regulatory Commission (NRC or the staff) and representatives of Tennessee Valley Authority held a telephone conference call on August 19, 2013, to discuss and clarify the staff's requests for additional information (RAis) concerning the Sequoyah Nuclear Plant, Units 1 and 2, license renewal application. The telephone conference call was useful in clarifying the intent of the staff's RAis. provides a listing of the participants and Enclosure 2 contains a listing of the RAis discussed with the applicant, including a brief description on the status of the items.

The applicant had an opportunity to comment on this summary.

Ric~se, Projects Branch 1 Project Manager Division of License Renewal Office of Nuclear Reactor Regulation Docket Nos_ 50-327 and 50-328

Enclosures:

1 _List of Participants 2 List of Requests for Additional Information cc w/encls: Listserv

• ML13247A427 *concurred via email OFFICE PM:RPB2:DLW PM:RPB1 :DLR PM:RPB1 :DLR BC:RPB1 :DLR NAME I K1ng E Sayee R Plasse Y Diaz~Sanabria DATE 9/11113 9/18/3 9/23/13 9/t 3/13 SUBJECT

SUMMARY

OF TELEPHONE CONFERENCE CALL HELD ON AUGUST 19, 2013, BETWEEN THE U.S. NUCLEAR REGULATORY COMMISSION AND TENNESSEE VALLEY AUTHORITY, CONCERNING REQUESTS FOR ADDITIONAL INFORMATION PERTAINING TO THE SEQUOYAH NUCLEAR PLANT, UNITS 1 AND 2, LICENSE RENEWAL APPLICATION (TAG.

NOS. MF0481 AND MF0482)

DISTRIBUTION HARDCOPY:

DLR RF E-MAIL:

PUBLIC RidsNrrDir Resource RidsNrrDirRpb1 Resource RidsNrrDirRpb2 Resource RidsNrrDirRerb Resource RidsNrrDirRarb Resource RidsNrrDirRasb Resource beth.mizuno@nrc.gov brian.harris@nrc.gov john.pelchat@nrc.gov gena.woodruff@nrc.gov siva.lingam@nrc.gov wesley.deschaine@nrc.gov galen.smith@nrc.gov scott shaeffer@nrc.gov jeffrey. hamman@nrc.gov craig.kontz@nrc.gov caudle.julian@nrc.gov generette.lloyd@epa.gov gmadkins@tva.gov clwilson@tva gov hleeO@tva gov dllundy@tva.gov

TELEPHONE CONFERENCE CALL SEQUOYAH NUCLEAR PLANT, UNITS 1 AND 2 LICENSE RENEWAL APPLICATION LIST OF PARTICIPANTS AUGUST 19, 2013 PARTICIPANTS AFFILIATIONS Richard Plasse U.S. Nuclear Regulatory Commission (NRC)

Emmanuel Sayoc NRC James Medoff NRC Duke Nguyen NRC Ata lstar NRC Alice Erickson NRC Bart Fu NRC Henry Lee Tennessee Valley Authority (TVA)

Dennis Lundy TVA Andrew Taylor TVA Alan Cox Entergy/Enercon Stan Bach Entergy/Enercon ENCLOSURE 1

REQUESTS FOR ADDITIONAL INFORMATION DISCUSSED SEQUOYAH NUCLEAR PLANT, UNITS 1 AND 2 LICENSE RENEWAL APPLICATION AUGUST 19, 2013 The U.S. Nuclear Regulatory Commission (NRC or the staff) and representatives of Tennessee Valley Authority held a telephone conference call on August 19, 2013, to discuss and clarify the following requests for additional information (RAis) concerning the license renewal application (LRA)

The Sequoyah Nuclear Plant, Units 1 and 2 (SQN), RAts of set 11 (ML13224A126), were discussed and a mutually agreeable date for the response of RAis 4.1-Sa, 4.6-1, B.1.40-4a, and 8.1.17-1 a was set within 60 days from the date of the letter on August 22, 2013. For the rest of the enclosed RAis a mutually agreeable date for the response was set within 30 days from the date of the letter.

RAI4.1-4a (Follow-up}- changes were made as marked up below, and a mutual understanding was reached by the staff and the applicant.

Background:

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

on whether the flaw analysis for the reactor coolant pump (RCP) casings at Sequoyah Units 1 and 2 would need to be identified as a Time Limited Aging Analysis (TLAA1 for the License Renewal Application (LRA1 in accordance with 10 CFR 54.21(c)(1) TLAA identification requirements.

Issue:

To resolve the RAI request, the applicant must demonstrate that the analysis does not conform to one or more of the six definition criteria that are used to define a plant analysis as a TLAA, as given in 10 CFR 54.3(a). In its response to RAI4.1-4, Parts a. and b., the applicant relies on a future licensing basis change that the applicant claims will be done during the Penod of Extended Operation CPE01 and uses this future licensing basis change in the PEO as the sole basis for concluding that the supporting flaw tolerance analysis for the RCP casings does not need to be identified as a TLAA. This is not acceptable because the basis did not demonstrate why the stated analysis is not in conformance with all six definition criteria for TLAAs in 10 CFR 54.3(a) or why the analysis would not need to be identified pursuant to the TLAA identification requirement in 10 CFR 54.12(c)(1) and the six criteria for TLAAs in 10 CFR 54.3(a).

Request:

_1_Ciarify whether ASME Code Case N-481 and the supporting flaw tolerance evaluation for the RCP casings are Gtlff-l+t.iy being relied upon in the CLB as the basis for performing alternative visual examinations of the RCP casing welds, and if so, justify why the flaw tolerance analysis would not need to be identified as a TLAA for the LRA, as based on the CLB for the Sequoyah units at time of the LRA review. Respond to Part -2 of this request if this Code Case is still being relied upon for the CLB.

ENCLOSURE 2

Clarify how the flaw tolerance evaluation addressed potential drops in the fracture toughness property of the CASS RCP casing material during the period of extended operat.ieAPEO, and justify why the assessment of loss of fracture toughness in the evaluation would not need to be within the scope of a TLAA for the LRA RAI 4.1-Ga (Follow-up) - changes were made as marked up below, and a mutual understanding was reached by the staff and the applicant

Background:

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

Issue:

The staff has determined that the applicant's response demonstrates that the flaw evaluation for the Unit 2 BIT does not need to be identified as a TLAA because the analysis: (a) does not involve time-dependent assumptions defined by the current operating term, and (b) does not conform to the definition of a TLAA in 10 CFR 54.3(a). However, the staff noted that the applicant does not identify cracking as an aging effect requiring management for the BIT in LRA Table 3.3.2-10, and does not specifically credit augmented inspections under the applicant's .!.!:t.

service Inspection (ISil Program (LRA AMP B.1.16) to manage cracking that was detected in the Unit 2 BIT.

Request Identify the mechanism that initiated the flaw in the BIT bottom head-to-shell weld and identify whether this mechanism was age-related. In addition, clarify whether the flaw in the BIT bottom

-head-to:-shell weld could grow by an age-related growth mechanism, such as cyclical loading or one of the stress corrosion cracking mechanisms, regardless of the cause for initiation of the flaw in the BIT bottom head-to-lower shell weld. Justify why cracking (including crack growth) has not been apf.!ropnately listed in LRA Table 3.3.2-1G as an af.JpliGable-*aging effect requiring management for welds in the BIT and why the applicant's lnservice lnspectionl.§l Program (LRA AMP 8.1.17) has not been credited to manage cracking in the BITs.

RAI4.1-8a (Follow-up}- changes were made as marked up below, and a mutual understanding was reached by the staff and the applicant.

Background:

By letter dated July 11, 2013, the applicant provided its responses to RAJ 4.1-8, Parts 1 and 2, on whether the UFSAR Section 10.2.3 includes any plant turbine analyses that would need to be identified as TLAAs in accordance with requirements for identifying TLAAs in 10 CFR 54.21(c)(1) The staff has determined that the applicant's response to RAI4.1-8, Part 1 provides adequate demonstration that the probabilistic analyses for the high pressure turbines (HPTs) and low pressure turbines (LPTs) do not need to be identified as TLAAs for the LRA.

Issue 1:

The applicant stated in its response to RAI 4. 1-8, Part 2 that evaluation of stress corrosion cracking (SCC) in Westinghouse Report WSTG-1-NP (i.e., Reference 3 in the RAI response) is not a TLM because it does not involve time-limited assumptions. However, SCC is identified in GALL Table IX.F as time-dependent aging mechanism, which implies that the analysis of sec involves a time-limited assumption, unless demonstrated to the contrary.

In contrast, the response to the RAI did not provide any reason why the analysis does not involve a time-limited assumption and therefore does not adequately demonstrate that the evaluation of SCC in the referenced Westinghouse analysis would not need to be identified as a TLAA for the LRA Request 1:

Explain how the analysis of sec was performed in Westinghouse Technical Report No. WSTG-1-NP (i.e., Ref. 3 in the response to RAI4.1-8). Based on this explanation, clarify why the analysis of SCC in the report is not considered to involve time-limited assumptions. Based on your response, provide your basis (i.e., justify) why the analysis of sec in the referenced Westinghouse report does not need to be identified as a TLAA, when compared to the six criteria for defining an analysis as a TLAA in 10 CFR 54.3(a).

Issue 2:

The applicant stated in its response to RAI4.1-8, Part 2 that "no fatigue-based analysis was required or used in the turbine missile evaluation." However, UFSAR Section 10.2.3 (i.e.

UFSAR page 10.2-9) makes the following statement Prior to 1980, the Westinghouse missile probabilities and energies analyses were directed primarily at missile generation due to destructive overspeed. Fatigue of the rotating elements due to speed cycling was also considered as a missile generation mechanism in these earlier analyses. These earlier Westinghouse analyses indicated that the probabilities of missile generation due to fatigue and destructive overspeed were very low in comparison to the probability estimated by Bush. The Bush probability (1 x 100-4 missile producing disintegrations per turbine operating year) was chosen for the original Sequoyah missile hazard evaluation in order to provide a very liberal margin of safety.

Based on this UFSAR statement, it appears that the Westinghouse fatigue analyses of the LPT rotating elements were used to confirm the missile generation probabilities of the Bush studies (as referenced in the UFSAR and response to RAI 4.1-8, Part 1) that were used for the LPTs. It is not evident why these Westinghouse analyses would not need to be identified as TLAAs for the LRA

Request 2:

1. Identify the Westinghouse fatigue analyses that were referenced on UFSAR page 10.2-9 and performed in analysis of the LPT rotating elements.

2. Explain how the assessment of fatigue was performed in these analyses.

3. Provide your basis (i.e., justify) why the stated Westinghouse fatigue analyses of the LPT rotating elements would not need to be identified as TLAAs for the LRA, when compared to the six criteria for defining an analysis as a TLAA in 10 CFR 54.3(a).

RAI4.1-11a (Follow-up)- changes were made as marked up below, and a mutual understanding was reached by the staff and the applicant.

Background:

By letter dated July 11, 2013, the applicant provided its responses to RAI 4.1-11, which provided the applicant's basis on why the exemption for use of ASME Code Case N-514 as the basis for establishing the temperature enable settings for the low temperature overpressure protection (LTOP) system does not need to be identified as an exemption for the LRA in accordance with the requirements in 10 CFR 54.21 (c)(2). In its response, the applicant stated that ASME Code Case N-514 has been incorporated into ASME Section XI, Appendix G, and therefore, this exemption will not be required when the pressure-temperature limits are updated for the period of extended operationPEO. The applicant stated that an LRA amendment is not needed with respect to identifying this exemption as an exemption that meets the requirements in 10 CFR 54.21(c)(2).

Issue:

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

The Pressure Temperature Limits Report (PTLR) and WCAP-15293 for Unit 1 and PTLR and WCAP-15321 for Unit 2 refer to ASME Code Case N-514 in relat1onsh1p to establishing the enable temperature for the LTOP system in each unit. However, the CLB for each un1t st1ll contains an exemption to use ASME Code Case N-514 for the pressure lift setpoints and enable temperatures of the plant LTOP systems. As such. the exemption to use Code Case N-514 may be based on a TLAA since the exemption allows the applicant to establish these setpoints based on a mathematical function of the lim1t1nq adjusted reference temperature (RT NlJ 1 value) for the reactor vessel beltline materials. Therefore. the staff needs further justification why the exempt1on for use of ASME Code Case N-514 had not been identified as an exemption that meets the exemption Identification critena in 10 CFR 54.21(c)(2) and why this exemption has

not been included 1n the LRA and dispositioned 1n accordance w1th the exempt1or requirements m 10 CFR 54 21(c)(2)

The current Pressure Temperature -Limits-Report (P-TLR) for Unit 1-~R--.for Un1t 2 both--fist ASME-GBee- Case N 511 as the GLH+ent methodology basis in the CLB for establ+s-hing the enable temperature setpo1nt for the l TOP system in each unit. even though the a~

Rave the option of amending 1ts-ficensing basis--dunng penod of extended-operation to el-imi-Rate tf:te--need for app.1icahon of ASME Cede Case N 5-14. This exemption may be an exempt-Jon--tf:t.at is based on a TL/IA since the enable-temperature IS based relative to a comparison to the Hmiting adjusted reference temperature (RTNoT value) for the reactOf--vessel beltlme-matenals--

Therefore. the staff needs further JUstification why the ex~e of ASME Code Case N4t4 had not been identified as an exemption that--meets the exemption identification criteria--i-R

-:l-0 GFR 54 21(c)(2) and why this O*Elmption has not been included in the-bR/\ and d-iSfOSitloned in accordance with the exemption reqwrements in 10-CFR 54_21(c~

Request

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

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

J_ Clarify whet-Aer the use-Bf-ASME Code-Case N 514--ls-currently--referenced in Sequoyah Report t>Jo PTLR :1---as the basis in the CLB for establishing the- LTOP system enable temperature setpo1nt for Unit-1 and in Sequoyah Report No--c---P-TLR-2--as the-basis in the CL-B--for establishing the LTOP system enable temperature setpo1nt for Unit 2-,

Based on your responses to Parts a .. --9-.. and cl and 2. of this RAI justify why the exemption to use ASME Code Case N-514 for Units 1 and 2 would not need to be identified as an exemption for the LRA that meets the exemption identification requirements in 10 CFR 54.21(c)(2)

RAI 4.6 changes were made as marked up below, and a mutual understanding was reached by the staff and the applicant.

Background:

Per_SRP-LR Section 4.6.1 1.1 for a TLAA to be dispositioned in accordance with 10 CFR 54.21{c){1)(i), the existing analyses must be verified to be valid and bounding for the period of extended operation. SRP-LR Section 4.6. 3.1.1 states that the existing analyses should be shown to be bounding even during the period of extended operat1onPEO.

LRA section 4.6 states "Analyses were identified for bellows assemblies for the penetrations t~'JEI stat~_g th<-;_y_were qualified for 7000 cycles of the design displacements. The number of design displacements expected to occur from either thermal changes or containment pressurizations is much less than 7000. Therefore, the associated penetrations bellows are

qualified for the PEO. The analysis remains valid for the PEO in accordance with 10 CFR 54.21 (c)( 1)(i)."

Issues:

The staff reviewed the SON UFSAR and was not able to find and verify the analyses used to estimate the number of displacements for bellows assemblies of the penetrations expected to occur from thermal changes or containment pressurizations and project those analyses to the end of the PEO.

Requests:

To ensure *'the est1mated number of cycles'* are Within "the qualifying l1mit of 7000 cycles."

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

Explain and justify how the existing analyses---ttSed -in the LRA to esti-mate the number of displacements for bellm\'S assemblies of the penetrations expect:ed to occur 1nclude those-fef thermal changes or containment pressurizations. and provide i-nformation on the bas1s for stating that-tAe-a-na-lyses remain valid to the eRG-of the PEO.

RAI B.1.40-1a (Follow-up)- changes were made as marked up below, and a mutual understanding was reached by the staff and the applicant.

Background:

Based on its audit of the applicant's program basis document for the Structures Monitoring Program, it is not clear that the preventive actions for storage, lubricants, and corrosion potential discussed in Section 2 of the Research Council for Structural Connect1ons (RCSCt publication "Specification for Structural Joints Using ASTM A325 or A490 Bolts," will be used consistent with the recommendations in the GALL Report.

Issue:

The applicant's response to RAI 8.1.40-1 dated July 1, 2013 states that the Structures Monitoring Program employs the preventive actions for storage, lubricants, and corrosion potential. The program basis document stated that the preventive actions of Section 2 of Research Council for Structural Connections publication "Specification for Structural Joint Using ASTM A325 and A490 bolts" have been considered in existing plant procedures for ASTM A325 and A490 bolting. However, during its audit, the staff found that the existing procedures provided as part of the program basis document for the Structures Monitoring Program did not include the preventive actions for storage, lubricants and corrosion potential. The staff has not been provided with sufficient information to verify that the preventive actions program element of the Structures Monitoring Program is consistent with the GALL Report without enhancement or exception, as claimed by the applicant in the LRA.

Request:

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

2. If the procedures describing these preventive actions were not refere_D_c;~Qprov1ded in the program basis document when audited, provide clarification and make revisions to the LRA and UFSAR supplement as necessary.

RAI B.1.40-4a (Follow-up) -changes were made as marked up below, and a mutual understanding was reached by the staff and the applicant.

Background:

Based on the response dated July 1, 2013, the technical evaluation of the groundwater in-leakage concluded that 1) the condition would not affect the intended function of the structure elements, and 2) the technical evaluation of the crack concluded that the structural capability of the turbine building north wall was not unacceptably impaired and that the wall would continue to perform its design function.

The response stated that minor groundwater in-leakage has been observed and documented in several Category!+ structures since 1996. Inspections of the turbine building (as listed in the LRA), a non-Category I structure, noted in-leakage in the basement floor slab at elevation 662.5' and significant in-leakage for the north and south perimeter walls above floor elevation 662.5' and floor elevation 685'. The response also stated that the turbine building is the most significant of the structures within the scope of the Structures Monitoring Program due to the constant moisture in-leakage over large areas of the structure. Although leak repairs have been initiated, the staff observed conditions during the audit walkdowns that may need further evaluation to demonstrate that the effects of aging will be adequately managed during the period of extended operation. The staff is concerned that the continued constant exposure to groundwater in-leakage may affect the integrity of the reinforced concrete during the period of extended operation.

Issue:

1. The technical basis, supporting the evaluation that concluded the groundwater in-leakage into the turbine building would not affect the intended function of the structure, was not provided.

2. The technical basis, supporting the evaluation that concluded the structural capacity of the turbine building north wall was not unacceptably impaired, was not provided.

3. Considering the history of constant groundwater in-leakage, in the absence of a plan to further evaluate the condition of the below-grade concrete, the staff is concerned that the periodic visual inspections, performed under the proposed Structures Monitoring Program, may not provide sufficient information, regarding the integrity of the concrete and reinforcing steel, for monitoring and trending of the structure during the period of extended operation.

Request

1. Provide additional information regarding the technical evaluation that was performed, which concluded the groundwater in-leakage would not affect the intended function of the turbine building. Include the following details in the response:

a. Completion d.Qate tR-for which the technical evaluation was perlotme-d and if/when it was re-evaluated

b. Description of activities performed (e.g. visual inspection, testing, structural analyses, chemical analyses)

c. Description of the qualitative or quantitative acceptance criteria used

d. Discussion of results obtained supporting the conclusion reached

e. Corrective actions taken, if any

f. Structural drawing(s) detailing the below grade-concrete in the area considered to have the most significant in-leakage, indicating floor elevations, water table elevation, concrete wall and floor slab thickness, rebar details. Indicate on the drawing the approximate locations of groundwater in-leakage.

2. Provide additional information regarding the technical evaluation of the large diagonal crack on the north wall of the turbine building, which concluded that the structural capacity of the turbine building north wall was not unacceptably impaired. Include the following details in the response:

a. Width of the crack at its widest point

b. History of crack growth

c. Discussion about the source of rust colored stains on the wall and flowing out of the crack

d. Description of activities performed (e.g. visual inspection, testing, structural analyses, chemical analyses)

e. Discussion of results obtained supporting the conclusion reached

f. Corrective actions taken, if any

g. Sketch detailing the location and dimensions of the crack, and areas of spalling.

3. In the absence of a plan to mitigate the groundwater in-leakage, explain how the proposed Structures Monitoring Program will adequately manage the potential increase in porosity and permeability and loss of strength due to leaching of calcium hydroxide; cracking due to expansion from reaction with aggregates; and cracking, loss of bond, and loss of material due to corrosion of embedded steel. Include any plans for testing and/or inspections that may demonstrate the effects of aging will be adequately managed during the period of extended operation RAJ 3.1.2-4-1a (Follow-up)- changes were made as marked up below, and a mutual understanding was reached by the staff and the applicant.

Background:

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

The staff considers reduction of heat transfer in steam generator tubes to be an applicable aging effect requiring management The staff notes that heat transfer is the intended function for the steam generator tubes, and without proper management, the intended function could be compromised ~-Steam Generator Integrity Assessment " -Bf!

maintenance for steam generator compoRents, including secondary side clean1ng. Section -WA of-the EPRI guidelines describes the guidance on preventing heat transfer limitatif:m,':-te f'f!-aftage-reOOction of heat transfer for steam generator tubes. The-apptiGaRt-'s Steam Generator lntegr~ty Progran+;-ffi-part includes secondary--stde maintenance act1vities,--such as sludge lancing. for remo~Jing deposits that may--oontnbute to aging related degradation. The applicant:s

~am-sh-&Hkl1mplement the EP-RI guideltnes 1n accordance *.vith-NEI 97 06. cons1stent--wHh

~eport-Request:

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

RAI 8.1.25-1 a (Follow-up) - changes were made as marked up below, and a mutual understanding was reached by the staff and the applicant.

Background:

In a letter dated May 31, 2013 the staff issued RAI 8.1.25-1 requesting additional information that demonstrates-__QQ_the correct1veproactive actions taken to prevent in-scope inaccessible power cable exposure !Q_significant moisture including- manhole, sump pump, aGd cable support structure inspection and, maintenance and corrective actiG-A-S. The staff also requested the applicant to include a summary discussion of the complete schedule for inaccessible cable corrective actions and their schedule~- The staff further requested the applicant describe inaccessible power cable testing (e.g., test frequency, and te-st-applicableOOy tests)

~rformed that demonstrates that in-scope inaccessible power cables will continue to perform their intended function consistent with the current licensing basis (CLB)befo.fe---a-M during-me per~od of extended operat,;on (PEO).

In response to the staff's RAI, in a letter dated July 1, 2013, the applicant stated that as documented in the SQN corrective action program, there have been multiple instances of water in manholes at SQN. In 2012, a report was initiated in the correction action program to document the trend of high levels of water in manholes that the work control process is not resolving in a timely manner. In response to the identified issues with untimely removal of water

from manholes, the preventive maintenance (PM) task instructions were revised to require water removal, if found, from the manholes before the PM task could be closed.

SON experience since revising the PM instruction has been that the water, if any, has been removed within a week of initiating the PM activity. The applicant also stated that as a result of operating experience {OE) with water in the manholes, a team of TVA personnel was established in early 2013 to resolve the dewatering issues with safety-related manholes. The team is scheduling activities which will repair or replace sump pumps and discharge piping as necessary to improve dewatering performance. In addition, TVA stated it is issuing a modification to enhance the ability to remove water from manholes without having to remove the heavy missile shield manhole covers. The applicant further stated that a cable support structure inspection is performed at least once every five years as part of the SON ?Jf.1JClures rr:o~lltoringsurve+J.Iance mamtenance program {SMP). F1nally, the applicant stated ...a-ftG.. that the inspections described in NUREG-1801, Section Xl.E3 will be implemented as part of the new SON Non-EO Inaccessible Power Cables {400 V to 35 kV) Program described in LRA Section 8.1.25 prior to entering the PEO. During the PEO, the periodic inspections of manholes including cable support structures will be completed at least once every year (annually).

The applicant's-PM program for inaccessible cables may allow unacceptable water levels to remain in the manhole for an extended periodup to a..Wek before corrective action to remove the water is completed. The staff noted that because of the difficulty in removal of the Heavy manhole covers, there was-has been limited manhole Inspection and preventive -maintenance of the sump pumps to ensure sump pumps were operable and capable of preventing cable submergence. In addition, based on OE with water in manholes, the staff is concerned that the current five year inspection frequency for manhole structures including cable supports may not be adequate.

The applicant's RAI response did not provide descnbewhat the correct1ve actions to be tAatwill 9&-taken to ensurefor manhole mspect1on and maintenance tl1&-operation of sump pumps to prevent exposure of cables to significant moistureunacceptable water level-s. The staff is concerned that the applicant's manhole inspections and corrective actions may not be adequate to prevent in-scope inaccessible power cables fromm being subjected to significant moisture.

The staff could not determine based on current OE if the applicant's non-EO Inaccessible Power Cable aging management program will ensure that in scope inaccessible power cables will continue to perform their intended function be effective during the period of extenaeG Gf1CfationPEO.

Request:

1. Describe ~1ow the inspection frequency. for water collection and manhole wWOO struc-tures are established and adjusted for plant specific and-1ndustry-oper~

experience.

_1._Describe whatcorrect1ve -actions (e.g .. 1nspection. preventive maintenance) ar>d msoect1011S ~ng frequency. that have wilt-been taken to ensure the operation of sump pumps to prevent exposure of In-scope inaccessible power cables to significant

moistureunacceptable water levelsi.QB:i!icant moisture. Include a discussion of the completion schedule to implement the corrective acttons.

&-Provide a technical justification for the current 5 year inspect ton frequency for in-scope manhole cable support structures qtven plant spectftc OE with water in the manholes and GALL Report AMP XLE3 guidance. Include a discussion on how the interval for water collectton and inspection of manhole structures including cable supports is established and adjusted for plant specific and industry operattng experience 2

J-:- Describe preventtve maintenance activities that have been taken m wtH be tak-e-A-te ensure that sump--pumps are operable to prevent cable submergence.

4 Provide a technical justiHGa-t-ioo for the current f1ve year inspection frequencyj_[tt~l{§! fo.r 1n scope manholes- and cable support strUGkJres given the plant_ specific OE with water if:t--the manholes.

3 For in-scope inaccessible power cables subjected to submergence (significant moisture},

how is the condition and operability of these cables determined? Describe the tests and inspections performed as part of the corrective act1on to ensure that these cables remain capable of performing their intended function consistent with the current licensing basisduring the PEO.

Xlg.3 The purpose of the aging management program (AMP+tlescnbed___herei~ __ j_!?,_t_q Qrovide reasonable assurance that-the intended functions of Inaccessible or undergrQ.\,!lli} power cables that are not subject to the environmental qualificat_i_qn

@Ukements-of--1 0 CFR 50 49 and are exposed to \~et~LI}9 __Qr subm_~rQCnQB are maintained consfstent with the current licensing basis th[QVQ.i]__ the penod of e.x!e_~

9Ptfation-RAI B.1.17-1a (Follow up)- changes were made as marked up below, and a mutual understanding was reached by the staff and the applicant

Background:

In its response of RAI 8.1.17-1 on July 1, 2013, the applicant stated "The configuration of the strainer allows leak off water to flow down the strainer and onto the ERCW strainer support causing corrosion. Planned corrective actions include a design modification of the strainer to prevent ERCW support from being continuously exposed to water, thus mitigating corrosion.

The modification proposed to install a "catch container" to the ERCW strainer to route the leak off water coming out of the top of the strainer to a floor drain." The LRA states 'The program was developed in accordance with ASME Section XI, 2001 Edition through the 2003 Addenda as approved by 10 CFR 50.55a." Accordingly 1he ERCW s1rainer support components should satisfy the requirements Article IWF-3000, "Standards for Examination Evaluations," which may include examinations, corrective measures, evaluations, tests, etc., currently and during the period of extended operation. GALL Report AMP XLS3, in program element "acceptance criteria," refers to the acceptance standards of IWF-3400, and states "other unacceptable

conditions include [I joss of material due to corrosion or wear, which reduces the load bearing capacity of the component support."

Issue: In summary, the applicant will be implementing a corrective action of redirecting the leaking water on the ERCW strainer support components to a floor drain, thus mitigating corrosion. It is not clear how the corrosion process will be mitigated by restricting the leaking water on the ERCW strainer support components only, and is expected to perform its intended function during the period of extended operation.

Changing the degrading environment to a benign environment may not alleviate the initiated corrosion process of carbon steel supports subject to stresses under operating conditions. The incubation-stage of corrosion process may have already been completed on some of the support components. Material-weakening stage (cracking) of the carbon steel supports and their components and attachment welds may already have been initiated with an eventual outcome of a reduced load bearing capacity of the component support. It is not clear whether the LRA AMP In-service Inspection -IWF (ISI-IWF) Program will follow the recommendation of the GALL Report AMP XI.S3, program element "acceptance criteria," which is based on the requirements of ASME Code Section XI, Article IWF-3400 during the period of extended operation Request:

Provide wA-at are the results of the#:!e acceptance criteria for service evaluations of the ERCW strainer support components per the requirements of ASME Code Section XI, Article IWF-3000"Standards for Examination Evaluations."

RAI B.1.11-1a (Follow up)- the following RAI was added to the set and mutuallv agreed upon.

Background:

In its July 1, 2013, response to request for additional information (RAI) 8.1.11-1, the applicant provided its clarification on whether specific transients listed in RAI 8.1.1.11-1 will be monitored as part of the Fatigue Monitoring program. The applicant stated the cycle limits of (1) 2,000 cycles of "Step changes in letdown stream fluid temperature from 100°F to 560°F" and (2) 24,000 cycles of "Step changes in letdown stream temperature from 400°F to 560°F" for the Chemical and Volume Control System (CVCS) regenerative heat exchangers will not be monitored by the Fatigue Monitoring program.

The applicant also stated that the 15 cycles of design tensioning cycle limit for the reactor coolant pump (RCP) hydraulic studs and nuts will not be monitored in the Fatigue Monitoring program. LRA Section 4.3.1.6 states the Fatigue Monitoring Program will manage the effects of ag1ng due to fatigue on the RCP in accordance with 10 CFR 54.21(c)(1)(iii). The staff noted that the "parameters monitored/inspected" program element of GALL Report AMP X.M1, "Fatigue Monitoring," states that the program monitors all plant design transients that cause cyclic strains, which are significant contributors to the fatigue usage factor.

Issue:

In its justification for the two transients for the CVCS regenerative heat exchangers, the applicant stated that the letdown fluid temperature normally remains stable for both units. The applicant further stated that a maximum of 90 cycles for each of the transients are expected through the period of extended operation. The staff is unclear on the how the applicant came to these conclusions. The applicant did not explain how it determined that the letdown fluid temperature normally remains stable or how it can confirm that the temperature during the transient will remain stable for the period of extended operation. The staff is unclear if the temperature stability is during normal operation or during the transient. Also, the applicant did not provide an explanation based on its plant configuration and operational history to support its calculation that 90 cycles is expected for each transient through the period of extended operation.

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

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

Request:

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

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

b. If the temperature is stable during these transients,

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

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

2. Describe how a maximum of 90 cycles for each of the aforementioned transients was calculated and justify that the calculations are consistent with plant configuration and operational history.

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

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