ML13252A036

Response to NRC Request for Additional Information Regarding the Review of the License Renewal Application, Set 10 (30-day), B.1.9-1, B.1.4-4 Revised RAI Responses and Revision to LRA Page 2.4-44 (TAC Nos. MF0481 and MF0482)

ML13252A036
Person / Time
Site:	Sequoyah
Issue date:	09/03/2013
From:	James Shea Tennessee Valley Authority
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
TAC MF0481, TAC MF0482
Download: ML13252A036 (48)

Text

Tennessee Valley Authority, 1101 Market Street, Chattanooga, Tennessee 37402 September 3, 2013 10 CFR Part 54 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 Sequoyah Nuclear Plant, Units 1 and 2 Facility Operating License Nos. DPR-77 and DPR-79 NRC Docket Nos. 50-327 and 50-328

Subject:

Response to NRC Request for Additional Information Regarding the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application, Set 10 (30-day), B.1.9-1, B.1.4-4 Revised RAI Responses, and Revision to LRA page 2.4-44 (TAC Nos. MF0481 and MF0482)

References:

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

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

- Set 10," dated August 2, 2013 (ADAMS Accession No. ML13204A257)

3. Letter to NRC, "Response to NRC Request for Additional Information Regarding the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application, Set 4/Buried Piping, Set 8, and Set 9,"

dated July 25, 2013 (ADAMS Accession No. ML13213A026)

4. Letter to NRC, "Response to NRC Request for Additional Information Regarding the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application, Set 7 (30-day)," dated July 29, 2013 (ADAMS Accession No. ML13213A027)

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

Printed on recycled paper

U.S. Nuclear Regulatory Commission Page 2 September 3, 2013 By Reference 2, the NRC forwarded a request for additional information (RAI) labeled Set

10. The required date for responding to new RAI 3.0.3-1 (Requests 2 and 5), and follow-up RAIs 3.5.2.3.4-1a, B.1.41-3a, B.1.23-2a, and B.1.2-2a from Set 10 was within 30 days of the date stated in the RAI (i.e., no later than September 3, 2013, considering the weekend day and holiday). The NRC License Renewal Project Manager, Mr. Richard Plasse, has given a verbal extension for B.1.23-2a until October 1, 2013. Enclosure 1 to this letter provides TVA's response for Set 10 (30-day).

By References 3 and 4, TVA submitted responses that included RAIs B.1.4-4 and RAI B.1.9-1, respectively. In August 5 and August 16, 2013 telecoms, Mr. Plasse requested clarifications for these RAI responses. Enclosure 2 provides the requested clarifications. In addition, Enclosure 2 provides a correction to LRA page 2.4-44 that was requested in an August 14, 2013, email from Mr. Emmanuel Sayoc, an NRC reviewer. 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 3rd day of September 2013.

Respectf Ily, ic President, Nuclear Licensing

Enclosures:

1. TVA Responses to NRC Request for Additional Information: Set 10 (30-day)

2. Revised Responses to RAI B.1.9-1a and B.1.4-4b, and revision to LRA page 2.4-4

3. Regulatory Commitment List, Revision 6 cc (Enclosures):

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

ENCLOSURE 1 Tennessee Valley Authority Sequoyah Nuclear Plant, Units 1 and 2 License Renewal TVA Responses to NRC Request for Additional Information: Set 10 (30-day)

RAI 3.0.3-1 (Request #2)

Background:

Recent industry operating experience (OE) and questions raisedduring the staff's review of several license renewal applications(LRAs) has resulted in the staff concluding that several aging managementprograms (AMP) and aging management review (AMR) items in the LRA may not or do not account for this OE.

These issues are relatedto the following, as describedin detail below.-

2. A representativeminimum sample size for periodic inspections for the Generic Aging Lessons Learned (GALL) Report AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Pipingand Ducting Program" Issue #2:

2. A representativeminimum sample size for periodic inspections for the GALL Report AMP X1. M38, "Inspectionof InternalSurfaces in Miscellaneous Piping and Ducting Program" GALL Report AMP XI. M38 recommends that inspections be performed during periodic system and component surveillancesor during the performance of maintenanceactivities when the surfaces are made accessible for visual inspection.

As stated in program element 4, "detectionof aging effects," "[v]isualand mechanical inspections conducted under this program are opportunisticin nature; they are conducted whenever piping or ducting is opened for any reason." It is possible that opportunisticinspections may not be available for one or more material, environment, and aging effect combinations presentedin the AMR line items where GALL Report AMP XI.M38 is referenced. With the exception of a few GALL Report AMR items where preventive actions alone are consideredsufficient to manage aging effects, it is the staff's position that, to credit a GALL Report AMP for aging management,some assurance that a representativesample of all material, environment, and aging effect combinations will be inspected is necessary. The PeriodicSurveillance and Preventive Maintenance Programprovides for a periodic representativesample, whereas, the InternalSurfaces in Miscellaneous Piping and Ducting Components Programdoes not.

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Request #2:

2. A representativeminimum sample size for periodic inspections in GALL Report AMP XI.M38, "Inspectionof Internal Surfaces in Miscellaneous Piping and Ducting Components"

a. State how LRA Sections A. 1.19 and B. 1.19 will be revised to ensure that the Internal Surfaces in MiscellaneousPiping and Ducting Components Programconducts periodic inspections on a representativesample of in-scope components.

Alternatively, state why no changes to the program are necessary to ensure that each applicable material,environment, and aging effect will be appropriately managed during the period of extended operation.

TVA Response to RAI 3.0.3-1 (Request #2)

a. Changes to LRA Sections A.1.19 and B.1.19 to ensure that the Internal Surfaces in Miscellaneous Piping and Ducting Components Program conducts periodic inspections on a representative samples of in-scope components if opportunistic inspections are not available for one or more material, environment, and aging effect combinations, are shown with additions underlined.

"LRA Section A.1.19 The Internal Surfaces in Miscellaneous Piping and Ducting Components Program manages fouling, cracking, loss of material, and change in material properties using opportunistic visual inspections of the internal surfaces of piping and components during periodic surveillances or maintenance activities when the surfaces are accessible for visual inspection.

This opportunistic approach is supplemented with the following sampling approach.

• In each 1 0-year period during the period of extended operation (PEO), an assessment will be made of the opportunistic inspections completed during that period for each material-environment-aging effect combination within the scope of this program.

" Directed inspections will be conducted to ensure that an inspection sample size of 20 percent, with a maximum sample size of 25 inspections, is completed for each of these material-environment-aging effect combinations during the 10-year period under review.

" Where practical, inspections shall be conducted at locations that are most susceptible to the effects of agqing because of time in service, severity of operating conditions (e.g., low or stagnant flow), and lowest design margin.

• An inspection conducted of a material in a more severe environment may also be credited as an inspection of the same material in a less severe environment.

For metallic components, visual inspection of surface conditions will be used to detect loss of material, fouling and cracking. For elastomeric components, visual inspections and physical manipulation will be used to detect cracking and change in material properties. The program monitors surface condition for visible evidence of loss of material in metallic components and changes in material properties for elastomeric components, including possible evidence of surface discontinuities. Visual examinations of elastomeric components are accompanied by E 2 of 23

physical manipulation such that changes in material properties are readily observable. The sample size for physical manipulation is at least ten percent of available surface area, including visually identified suspect areas.

Specific acceptance criteria are as follows:

• Stainless steel: clean surfaces, shiny, no abnormal surface condition.

• Metals: no abnormal surface condition.

• Flexible polymers: a uniform surface texture and color with no cracks, no unanticipated dimensional change, and no abnormal surface conditions.

• Rigid polymers: no surface changes affecting performance such as erosion and cracking.

Conditions that do not meet the acceptance criteria are entered into the corrective action program for evaluation. Any indications of relevant degradation will be evaluated using design standards, procedural requirements, current licensing basis, and industry codes or standards.

This program will be implemented prior to the PEO.

LRA Section B.1.19 The Internal Surfaces in Miscellaneous Piping and Ducting Components Program is a new program that will manage fouling, cracking, loss of material, and change in material properties using opportunistic visual inspections of the internal surfaces of piping and components during periodic surveillances or maintenance activities when the surfaces are accessible for visual inspection.

This opportunistic approach is supplemented with the following sampling approach.

• In each 10-year period during the period of extended operation (PEO), an assessment will be made of the opportunistic inspections completed during that period for each material-environment-aging effect combination within the scope of this program.

• Directed inspections will be conducted to ensure that an inspection sample size of 20 percent, with a maximum sample size of 25 inspections, is completed for each of these material-environment-aging effect combinations during the 10-year period under review.

• Where practical, inspections shall be conducted at locations that are most susceptible to the effects of a-ginq because of time in service, severity of operating conditions (e.g., low or stagnant flow), and lowest design margin.

• An inspection conducted of a material in a more severe environment may also be credited as an inspection of the same material in a less severe environment.

For metallic components, visual inspection of surface conditions will be used to detect loss of material, fouling and cracking. For elastomeric components, visual inspections and physical manipulation will be used to detect cracking and change in material properties. The program monitors surface condition for visible evidence of loss of material in metallic components and changes in material properties for elastomeric components, including possible evidence of E 3 of 23

surface discontinuities. Visual examinations of elastomeric components are accompanied by physical manipulation such that changes in material properties are readily observable. The sample size for physical manipulation is at least ten percent of available surface area, including visually identified suspect areas.

Specific acceptance criteria are as follows:

• Stainless steel: clean surfaces, shiny, no abnormal surface condition.

• Metals: no abnormal surface condition.

• Flexible polymers: a uniform surface texture and color with no cracks, no unanticipated dimensional change, and no abnormal surface conditions.

• Rigid polymers: no surface changes affecting performance such as erosion and cracking.

Conditions that do not meet the acceptance criteria are entered into the corrective action program for evaluation. Any indications of relevant degradation will be evaluated using design standards, procedural requirements, current licensing basis, and industry codes or standards.

This program will be implemented prior to the PEO."

(See Commitment #14)

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RAI 3.0.3-1 (Request #5)

Background:

Recent industry operating experience (OE) and questions raised during the staff's review of several license renewal applications(LRAs) has resulted in the staff concluding that several aging management programs (AMP) and aging management review (AMR) items in the LRA may not or do not account for this OE.

These issues are related to the following, as described in detail below:

5. Scope and inspection recommendations of GALL Report AMP XI.M29, "Aboveground Metallic Tanks" Issue #5:

5. Scope and inspection recommendations of GALL Report AMP X1. M29, "Aboveground Metallic Tanks" There have been several instances of OE related to age-relateddegradation of tanks.

Tanks with defects variously described as wall thinning, pinhole leaks, cracks, and through-wall flaws have been identified by detecting external leakage ratherthan through internal inspections. None of the leaks or degradedcoatings has resulted in a loss of intended function; however, the number of identified conditions adverse to quality and the continued aging of the tanks indicate a need to ensure that internal tank inspections are conducted throughout the PEO. In addition, the staff identified an indoor tank with external SCC that, except for its location, would normally be in the scope of GALL Report AMP X1. M29. As such, in regard to the recommendations in GALL Report X1.M29, the staff position is as follows:

a. Most water-filled indoor tanks are currently managed by GALL Report AMP XI.M36, "ExternalSurfaces Monitoring of Mechanical Components," and GALL Report AMP XI.M38. Neither of these AMPs has a recommendation to conduct periodic volumetric examinations of the bottom of the tank or internalinspections. Based on industry OE, the staff believes that some indoor tanks should have internalinspections.

These include indoor welded storage tanks that meet all of the following criteria:

i. have a large volume (i.e., greaterthan 100,000 gallons) ii. are designed to near-atmosphericinternalpressures iii. sit on concrete or soil iv. are exposed intemally to water

b. Based on industry OE related to cracking due to SCC and fatigue, stainless steel and aluminum tanks should be inspected using surface examination techniques.

c. Based on the tank's materialand environment, the attached Table 5a, "Tank Inspection Recommendations," contains the types of aging effects requiringmanagement (AERM),

inspection type, and frequency of inspections that should be conducted to provide E 5 of 23

reasonableassurancethat the intended functions of the tank will be maintained consistent with the currentlicensing basis (CLB) for the PEO.

Request #5:

5. Scope and inspection recommendationsof GALL Report AMP XI.M29, "Aboveground Metallic Tanks"

a. State whether there are any in-scope indoor welded storage tanks that meet all of the following criteria:

i. have a large volume (i.e., greaterthan 100,000 gallons) ii. are designed to near-atmosphericinternalpressures iii. sit on concrete or soil iv. are exposed internallyto water

b. State how LRA Section 3 Table 2s and Appendices A. 1.1 and B. 1.1 will be revised to be consistent with the attached Table 5a. Alternatively, state andjustify portions that will not be consistent.

17 Table 5a Tank Inspection Recommendations ,

I I Inspection I 9

Material Environment AERM Technique Inspection Frequency Inspections to identify aging of inside surfaces of tank shell, roof, and bottom Inside Surface (IS), Outside Surface (OS)686 Visual from IS or Each 10-year periodstarting 10 years Steel Raw water Loss of material Volumetric from before the period of extended operation Oslo Visual from IS or One-time inspection conducted in Steel Treatedwater Loss of material Volumetric from accordance with AMP XI. M32 Oslo Visual from IS or Stainless Treatedwater Loss of Material One-time inspection conducted in steel Volumetric from accordance with AMP XI.M32 Oslo Visual from IS or One-time inspection conducted in Aluminum Treatedwater Loss of Material Volumetric from accordance with AMP XI.M32 Oslo Inspections to identify aging of external surfaces of tank roof and tank shell, and bottom not exposed to soil or concrete E 6 of 23

7 Table 5a Tank Inspection Recommendations '

Inspection Material Environment AERM Technique9 Inspection Frequency Air- indoor controlled Steel Air - indoor Loss of material Visual from OS Each refueling outage interval uncontrolled Air- outdoor Air - indoor Stainless controlled Each 10-year period starting 10 years steel Air - indoor before the periodof extended operation uncontrolled Loss of material Visual from OS Each refueling outage interval5 Stainless__________________

Stanee Air-outdoor Surface" sg Each 10-year period starting 10 years Cracking Sbefore the period of extended operation Air- indoor Aluminum controlled Cakn ufc1 Each 10-year period starting 10 years Air - indoor before the period of extended operation uncontrolled Loss of material Visual from OS Each refueling outage interval Aluminum Air-outdoor Cracking Surface11 Each 10-yearperiod starting 10 years before the period of extended operation Inspections to identify aging of extemal surfaces of tank bottoms and tank shells exposed to soil or concrete concreteei Loss of material Volumetnic from S Each 10-year period starting 10 years 3 l

concreteS before the period of extended operation Stainless Soil or Loss of material Volumetric from lS4 Each 10-year period starting 10 years steel concrete I before the period of extended operation3 concree Loss of Material Volumetric from IS4 Each 10-year period starting 10 years 3 Aluminu concrete Losbefore the period of extended operation

1. GALL Report AMP XI.M30, "FuelOil Chemistry," is used to manage loss of materialon the internalsurfaces of fuel oil storage tanks. GALL Report AMP XI.M42 is used to manage loss of materialand cracking for the externalsurfaces of buriedtanks.

2. A one-time inspection conducted in accordancewith GALL Report AMP XI. M32 may be conducted in lieu of periodic inspections if the fuel oil specifications have not been changed since 35 years priorto placing the tank in service, or an evaluation has been conducted documenting that any change would not adversely impact the tank's internalsurfaces (e.g., low sulfur fuel interaction with coatings).

3. A one-time inspection conducted in accordance with GALL Report AMP XI. M32 may be conducted in lieu of periodic inspections if an evaluationconducted priorto the PEO and during each 10-year period during the PEOdemonstrates that the soil under the tank is not corrosive using actual soil samples that are analyzed for each individual parameter(e.g., resistivity, pH, redox potential, sulfides, sulfates, moisture) and overall soil corrosivity. Alternatively, a one-time inspection conducted in accordancewith GALL Report E 7 of 23

17 Table 5a Tank Inspection Recommendations '

Material Environment AERM Inspection Inspection Frequency EnIronmen Technique9 I AMP XI.M32 may be conducted in lieu of periodicinspections if the bottom of the tank has been cathodically protectedsuch that the availabilityand effectiveness criteriaof LR-ISG-2011-03, "Changesto the Generic Aging Lessons Learned (GALL) Report Revision 2 Aging Management Program (AMP) XI.M41, 'Buriedand UndergroundPipingand Tanks'," Table 4a., "Inspectionof Buried Pipe," have been met commencing 5 years priorto the PEO, and the criteria continues to be met throughout the PEO. The evaluation should include soil sampling from underneath the tank.

4. When volumetric examinationsof the tank bottom cannot be conducted due to the tank being coated, an exception should be stated, and the accompanying justification for not conducting inspections should include the considerationsin footnote 3, above, or an alternative examination methodology is proposed.

5. A one-time inspection conducted in accordance with GALL Report AMP XI.M32 may be conducted in lieu of periodicinspections if an evaluation conducted priorto the PEO and during each 10-year period during the PEO demonstrates that environmentalimpacts due to such factors as the plant being located within approximately5 miles of a saltwatercoastline, those within 1/2 mile of a highway that is treated with salt in the wintertime, those areas in which the soil contains more than trace chlorides, those plants having cooling towers where the water is treated with chlorine or chlorine compounds, and those areas subject to chloride contaminationfrom other agriculturalor industrialsources are not present in the vicinity of the plant. The evaluation should include soil sampling in the vicinity of the tank (soil results are indicative of compounds atmosphericfallout that could be present on surfaces of the tank) to ensure that chlorides are not present at sufficient levels to cause pitting and crevice corrosion.

6. Inspections to identify aging of the inside surfaces of tank shell, roof, and bottom should cover all the inside surfaces. Where this is not possible due to tank configuration (e.g., tanks with floating covers or bladders the LRA should include a justification for how aging effects will be detected priorto loss of intended function.

7. When one-time internalinspections in accordance with the above footnotes are used in lieu of periodic inspections, the one-time inspection must occur within the 5 year periodprior to commencement of the PEO.

8. Fortank configurationswhere deleterious materials could accumulate on the tank bottom (e.g., sediment, silt), the tank bottom internal inspections should include inspections of the side wall of the tank up to the top of the sludge affected region.

9. Alternative inspection methods may be used to inspect both surfaces (i.e., internal,external) or the opposite surface (e.g., inspecting the internal surfaces for loss of material from the external surface, inspecting for corrosionunderexternal insulation from the internalsurfaces of the tank) as long as the method has been demonstratedeffective at detecting the AERM and a sufficient amount of the surface is inspected to ensure that localized aging effects are detected. Forexample, the low frequency electromagnetictechnique (LFET) can be used to scan an entire surface of a tank. If follow-up ultrasonic examinations are conducted in any areas where the wall thickness is below nominal, an LFET inspection can effectively detect loss of material in the tank shell, roof,or bottom.

10. At least 25 percent of the tank's internal surface is inspected by a method capable of precisely determining wall thickness. The inspection method must be capable of detecting both general and pitting corrosion and must be qualified and demonstratedeffective by the applicant.

11. A minimum of either a combination of 25 1-square-footsections for tank surfaces and for welds, 1-linear-foot of weld length; or 20 percent of the tank's surface are examined. The sample inspection points are distributedsuch that inspections occur in those areasmost susceptible to cracking (e.g., areas where contaminants could collect, inlet and outlet nozzles, welds).

E 8 of 23

TVA Response to RAI 3.0.3-1 (Request #5) 5.

a. Review of the SQN component database indicates that there are two indoor welded storage tanks that meet the following criteria:

i. have a large volume (i.e., greater than 100,000 gallons) ii. are designed to near-atmospheric internal pressures iii. sit on concrete or soil iv. are exposed internally to water The two tanks are the chemical and volume control system (CVCS) holdup tanks.

b. Changes to LRA Table 3.3.2-10, CVCS, and LRA Table 3.4.1 will reflect the addition of the Aboveground Metallic Tanks Program for the tanks identified in response to 5.a.

above. Changes to LRA Sections A.1.1 and B.1.1 are shown with additions underlined and deletions lined through.

The table of tank inspection details is added without underlining to promote readability of the text. In addition, the table of tank inspection details includes minor variations from the table provided in the RAI as follows.

• Removed note 2 and renumbered subsequent notes. Note 2 applied to diesel fuel storage tanks, which are addressed in a different program as indicated in note 1.

• In note 9, removed "qualified and." The meaning of "qualified" is not defined and may not be clear because the inspections are not ASME Section Xl inspections. The phrase "demonstrated effective by the applicant" adequately conveys the intent of the note.

• A number of editorial changes intended to provide clarification and eliminate ambiguity were also made.

Table 3.3.2-10: Chemical and Volume Control System Type Intended Material Environment Aging Effect Requiring Aging Management NUREG-1801 Item 1Table Item Notes Type function Management Program Pressure Stainless Loss of Aboveqround VIII.E.SP- P.4.1- C. 312 Tank boundary steel material Metallic Tanks 137 1 3.0 Aging Management Review Results Page 3.3-72 Notes for Tables 3.3.2-1 through 3.3.2-17-32 Plant-Specific Notes 312. The CVCS holdup tanks are indoor tanks on a concrete foundation with an oiled sand cushion.

E 9 of 23

Table 3.4.1: Steam and Power Conversion Systems Item Aging Effect/ Aging Further Number Component Mechanism Management Evaluation Discussion Programs Recommended 3.4.1-31 Stainless Loss of material Chapter No Consistent with NUREG-1801.

steel, due to pitting, XI.M29, Loss of material for stainless steel aluminum and crevice "Aboveground tanks exposed to concrete or soil is tanks exposed corrosion Metallic Tanks" managed by the Aboveground to soil or Metallic Tanks Program. This item concrete applies to components in Tables 3.2.2-1 and 3.3.2-10. There are no stainless steel or aluminum tanks exposed to concrete or soil inthe steam and power conversion systems in the scope of license renewal.

A.1.1 Aboveground Metallic Tanks Program The Aboveground Metallic Tanks Program includes outdoor tanks on soil or concrete and indoor large volume water tanks situated on concrete that are designed for internal pressures approximating atmospheric pressure. Periodic external visual and surface examinations are sufficient to monitor degradation. Internal visual and surface examinations are conducted in coniunction with measurina the thickness of the tank bottoms to ensure that significant degradation is not occurring and that the component's intended function i~ m~int~in~d diirino th~ PFO lntArn~il in~nnr.tions ~ r~ondimt~d whenever the tank is drained, with a minimum frequencV of at least once every 10 years, beginning in the 10-year interval prior to the PEO.manages loss; of Matr

• ial-and cGrack*g*

forathe ou,tAr surfaces of the abovegFtroun metalli* tanks using periodic Visual inpections on tanks Within the scope of license renewal as delneated in 10 CFR 54.4. For in scope painted tanks, the progr.m mon.itors, the surfac cnionfor .Ie -blistering,flaking, crackinq, peeling, discoloration, unRdorlying rus6t, and physical damage. For in 6copo stainless steel tanks, the programn will monitor: curfaco GGditiGR to assu1re a c-lean, shiny surface With no visehibiekels The vAisibl exteriorF pqotiGs of the tanks w.Ail be inspected at least once ever,'y refeling cycle.

T-his program also mnanages the bottom. surfaces-r o-f abovegroud- metallicg tanks, which are censtructed on a ring of concrete and oil-filled sand. The program requires ultrasonic testing (UT)ef the tank boto*ms to assess the thickness against the t9hce specif*ioed i n the design specification. The UIT testing of the tank bottoms, will be performed at least Gnce within the five 'ieaF6 nrlio to the period of eXtended onontionp Amd WhAenveF the 4 IFý7-E 10 of 23

16 The following table provides tank inspection details. ',

Material

_ _era Environment AERM _ Inspection T_ __M _Inspection

_ Frequency

_ __e

__ __ ~ __ _ Technique8 I _ _ _ _

Inspections to identify aging of inside surfaces of tank shell, roof, and bottom 57 Inside Surface (IS), Outside Surface (OS) '

Visual from IS or Each 10-year period starting 10 years Steel Raw water Loss of material Volumetric from before the PEO OS, Visual from IS or One-time inspection conducted in Steel Treated water Loss of material Volumetric from accordance with AMP XI.M32 OS9 Visual from IS or Stainless Treated water Loss of Material Volumetric from One-time inspection conducted in steel accordance with AMP XI.M32 Visual from IS or One-time inspection conducted in Aluminum Treated water Loss of Material Volumetric from accordance with AMP XI.M32 OS9 Inspections to identify aging of external surfaces of tank roof and tank shell, and bottom not exposed to soil or concrete Air - indoor controlled Steel Air - indoor Loss of material Visual from OS Each refueling outage interval uncontrolled Air - outdoor Air - indoor Stainless controlled CrackingSurface 10 Each 10-year period starting 10 years steel Air - indoor Crackin before the PEO uncontrolled 4

Loss of material Visual from OS Each refueling outage interval Stainless__________

Stanee _________________ ____

steel Air-outdoor Cracking Surface1 0 Each 10-year period starting 10 years before the PEO Air- indoor Aluminum controlled Cracking Surface 1k Each 10-yearE period starting 10 years bfrete Air - indoor before the PEO uncontrolled Loss of material Visual from OS Each refueling outage interval Aluminum Air-outdoor Cracking Surface10 Each 10-year period starting 10 years before the PEO E 11of23

Inspection Iseto rqec Material I Environment AERM Techniqueto Inspection Frequency Inspections to identify aging of external surfaces of tank bottoms and tank shells exposed to soil or concrete Loss of material Volumetric from S Each 10-year period 2 starting 10 years concreteeli concretebeoeteP Staness Soil or Ls fmtra ouercfo S eoeteP~

Stainless Soil or Loss of material Volumetric from IS3 Each 10-year period 2 starting 10 years steel concreteIbeoeteP Aluminum Soil or Loss of Materl Vic S Each 10-year period starting 10 years concrete al Volumetric from I before the PE02

1. GALL Report AMP XI.M30, "Fuel Oil Chemistry," is used to manage loss of material on the internal surfaces of fuel oil storage tanks. GALL Report AMP XI.M42 is used to manage loss of material and cracking for the external surfaces of buried tanks.

2. A one-time inspection conducted in accordance with GALL Report AMP XL.M32 may be conducted in lieu of periodic inspections if an evaluation conducted prior to the PEO and during each 10-year period during the PEO demonstrates that the soil under the tank is not corrosive by using actual soil samples that are analyzed for each individual parameter (resistivity, pH, redox potential, sulfides, sulfates, moisture) and overall soil corrosivity.

Alternatively, a one-time inspection may be conducted in accordance with GALL Report

-AMP XI.M32 in lieu of periodic inspections ifthe bottom of the tank has been cathodically protected such that the availability and effectiveness criteria of LR-ISG-2011-03, "Changes to the Generic Aging Lessons Learned (GALL) Report Revision 2 Aging Management Program (AMP) XI.M41, 'Buried and Underground Piping and Tanks'," Table 4a., "Inspection of Buried Pipe," have been met commencing 5 years prior to the PEO, and the criteria continues to be met throughout the PEO. The evaluation should include soil sampling from underneath the tank.

3. When volumetric examinations of the tank bottom cannot be conducted due to the tank being coated, an exception should be stated, and the accompanying justification for not conducting inspections should include the considerations in footnote 2 above.

Otherwise, an alternative examination method is proposed.

4. A one-time inspection conducted in accordance with GALL Report AMP XI.M32 may be conducted in lieu of periodic inspections if an evaluation conducted prior to the PEO and during each 10-year period during the PEO demonstrates the absence of the following detrimental environmental factors:

1) Plant location within approximately 5 miles of a saltwater coastline or within 1/2 mile of a highway that is treated with salt for snow or ice control,

2) Tank location on soil containing more than trace chlorides,

3) Plant operates cooling towers where the water is treated with chlorine or chlorine compounds, and E 12 of 23

4) Plant location in areas subject to chloride contamination from agricultural or industrial sources. The evaluation should include soil sampling in the vicinity of the tank (soil sampling results are indicative of contaminants from atmospheric fallout that could be present on surfaces of the tank) to ensure that chlorides are not present at sufficient levels to cause pitting and crevice corrosion.

5. Inspections to identify the effects of aging on the inside surfaces of tank shell, roof, and bottom should cover all the inside surfaces. Where this is not possible due to tank configuration (e.g., tanks with floating covers or bladders), the LRA should include a justification for how aging effects will be detected prior to loss of intended function.

6. When one-time internal inspections in accordance with the above footnotes are used in lieu of periodic inspections, the one-time inspection must occur within the 10-year interval prior to the PEO.

7. For tank configurations where deleterious materials could accumulate on the tank bottom (e.g., sediment, silt), the tank bottom internal inspections should include inspections of the side wall of the tank up to the top of the sludge-affected region.

8. Alternative inspection methods may be used to inspect both surfaces (i.e., internal, external) or the opposite surface (e.g., inspecting the internal surfaces for loss of material from the external surface, inspecting for corrosion under external insulation from the internal surfaces of the tank) as long as the method has been demonstrated effective at detecting the AERM and a sufficient amount of the surface is inspected to ensure that localized aging effects are detected. For example, the low frequency electromagnetic technique (LFET) can be used to scan an entire surface of a tank. If follow-up ultrasonic examinations are conducted in any areas where the wall thickness is below nominal, an LFET inspection can effectively detect loss of material in the tank shell, roof, or bottom.

9. At least 25 percent of the tank's internal surface is inspected by a method capable of precisely determining wall thickness. The inspection method must be capable of detecting both general and pitting corrosion and must be demonstrated effective by the applicant.

10. A minimum of either 25 1-square-foot sections of the tank surfaces, including at least 1-linear-foot of weld length; or 20 percent of the tank's surface are examined. The sample inspection points are distributed such that inspections occur in those areas most susceptible to cracking (e.g., areas where contaminants could collect, inlet and outlet nozzles, welds).

This program will be implemented prior to the PEO. (See Commitment #1)

B.1.1 ABOVEGROUND METALLIC TANKS Program Description The Aboveground Metallic Tanks AMP Prgrqam is a new program that wi4 manages loss of material and crackingof fGFthe euter outside and inside surfaces of the aboveground meta&U.-tanks situated on concrete or soil.using porioidic Vi6ual i.npections On tank Within the c*Opo of the prOgram. as delineated in 10 ,-R 5.41. Outdoor tanks, except fire water storaaqe tanks, and certain indoor tanks are included. The proqram relies on E 13of23

Periodic inspections to monitor for the effects of aging. Tank inside surfaces are inspected by visual or surface examination methods as necessary to detect the applicable aging effcts.Pr.veptiv. moasuros wor applied . du,..rin construction, ,,uch as using tho appropriato matorials, protectiVo coatings, 3nd olovatienas,specified in dE1sign I reaCI a "" .-..

rwt7 t**.--.ot-.., Wr"et~e C Ha " t. MIICH W "

suraco 9o;ndit ion.. for-b,.,iRg, flaking, craina*g, peoGng, disGoloration, undorly.ng rust, and physical damage. For in scope staginls stool tanks, the prFogra will monitor

.u..... con . .. "nto -assurea clean, shn'y rTace MORA no visi.Ie ea...

"s. I n'

" i. I eXterior portions of the tanks will be inspected at leaSt once evor~' refueling cycle-.

This program will also manage the effects of aging on the bottom surface of aboveground metallic tanks, which are supportedGeGRtr,-Gted on earthen or concrete foundations.a ring of concrete and ol filled sand. The program will require ultrasonic testing (UT) of the tank bottoms to assess the thickness against the thickness specified in the design specification. The UT tersting of the tank bottoUms Will be perfermed at least onco within; the five years prier to the period of extended operation and whenever the ta*k6 a.r dFriained duing the period Of eAxeRded operation.

In; accordanco With installation and designR specifications, the tanks doG not employ caulking or sealant at the cencrete/tank interfane.

Tank inspections are performed in accordance with the table in LRA Section A.1.1.

This program will be implemented prior to the PEO. (See Commitment #1)

Conclusion The Aboveground Metallic Tanks Program will be effective at identifying and managing the aging effects of loss of material and cracking on the outee outside and inside surfaces of the in-scope tanks, since it will incorporate proven monitoring techniques, acceptance criteria, corrective actions, and administrative controls. The Aboveground Metallic Tanks Program provides reasonable assurance that the effects of aging will be managed such that applicable components will continue to perform their intended functions consistent with the current licensing basis through the PEO.

E 14 of 23

RAI 3.5.2.3.4-1a (Follow-up)

Background:

The response to RAI 3.5.2.3.4-1 stated that:

1. Jacketing is not present on all in-scope fiberglass and calcium silicate insulation exposed to uncontrolledindoorair in LRA Table 3.5.2-4 with a function to limit heat transfer.

2. When jacketing is provided, the installationis performed in accordance with "skill-of-the-craft."

3. Leakage and spray, if occurring, are abnormal conditions that are identified, corrected and evaluated for the potential effect on surroundingequipment, as necessary, under the corrective action program and work control processes.

4. A review of plant-specific operating experience identified no aging effects that resulted in a loss of intended function for insulation.

LRA Table 3.0-2 defines uncontrolled indoorair as "[ajirwith temperature less than 150 0F, humidity up to 100% and protected from precipitation." The definition continues by stating,

"[hiumiditylevels up to 100 percent are assumed and the surfaces of components in this environment may be wet."

Issue:

The staff found the response to RAI 3.5.2.3.4-1 unacceptablebecause while the staff acknowledges that leakage and spray are abnormal conditions that would be addressed by the corrective action program and work control process, the insulation is exposed to indoor uncontrolled air. The staff lacks sufficient information to conclude that routine sweating of pipes that could drip onto unjacketed insulation located below the pipe during humid conditions would be identified in the corrective action program. In addition, the applicantdid not provide any evidence to demonstrate that the "skill-of-the-craft"approach for installingjacketing has been effective.

If the mechanical system environment of indoor airbeen selected, the staff would still find the response to be unacceptable. LRA Table 3.0-1, Service Environments for MechanicalAging Management Reviews," defines indoorair as, "[ajirin an environment protected from precipitation." The correspondingdefinition in GALL Report Table IX.D for air-indoor uncontrolledis, "fu]ncontrolledindoorairis associatedwith systems with temperatureshigher than the dew point (i.e., condensationcan occur,but only rarely; equipment surfaces are normally dry). Although condensation occurs rarely in this airenvironment, insulation can retain the condensation and its ability to reduce heat transferwill be degraded.

E 15of23

Request:

Amend the LRA to include aging management of reduction of insulation effectiveness for in-scope fiberglass and calcium silicate insulation or:

1. State whether sweating of pipes during plant operation is identified as a condition adverse to quality in the corrective action program. If it is, provide evidence that either sweating is not occurring or that it has routinely been identified and corrected.

2. State whether any in-scope unjacketed fiberglassor calcium silicate insulationis installed,or could be installed in the future, in locations that are susceptible to wetting by sweating of pipes duringplant operation.

3. State what evidence is available that "skill-of-the-craft"has been sufficient to ensure that insulationjacketing has been installedin a manner that will preclude insulationmoisture intrusion.

TVA Response to RAI 3.5.2.3.4-la The below changes to the LRA are made to include managing the effects of aging on fiberglass and calcium silicate insulation due to potential exposure to moisture that can cause loss of insulation effectiveness.

Based on these changes, a response to request parts 1, 2 and 3 is not necessary.

The changes to SQN LRA Table 3.5.2-4, Notes for Tables 3.5.2-1 through 3.5.2-4, Section A.1.40 and Section B.1.40 follow with additions underlined and deletions lined through.

Table 3.5.2-4: Bulk Commodities Structure and/or Intended Aging Effect Aging NUREG- Table I Component or Function Material Environment Requiring Management 1801 Item Item Notes Commodity Management Program NQon Insulation ( Fiberglass, Air-indoor Loss of material jacketing, wiro moch, IN, SNS calcium uncontrolled Change in Structures tie wiroc, rape, clip.) silicate material Monitoring properties Notes for Table 3.5.2-1 through 3.5.2-4 5 L*3, of.... Of.insulating chac*..*..itir,duo te...insulation deoFadation in*o t an aging effoc:.t roqirig mnagomont forF insu6lation matorial. Insulation products, Which are rmado; from fibercglassG fibor, calciumFV silicate, stainloss stool, and similar Matorials, in an Air ido uncon trollod. AVOnirom~ent do not oXPorincagg ofctsnb that would significantly dogrado thoir: ability to insulate as dosignod. A roviow of site oporating exporincoidetiio n agingq offects for in~sulation used at SQN.

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A.1.40 Structures Monitoring Program

_ Revise Structures Monitoring Program procedures to include the following in-scope structural components and commodities.

• Insulation (fiberglass, calcium silicate)

_ Revise Structures Monitoring Program procedures to include the following parameters to be monitored or inspected:

• Monitor the surface condition of insulation (fiber-glass, calcium silicate) to identify exoosure to moisture that can cause loss of insulation effectiveness.

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

IInspection of insulation (fiberglass, calcium silicate) to manage loss of material and change in material properties due to exposure to moisture that can cause loss of insulation effectiveness.

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

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

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

Elements Affected Enhancements

1. Scope of Program Revise Structures Monitoring Program procedures to include the following in-scope structural components and commodities:

Insulation (fiberglass, calcium silicate)

3. Parameters Monitored or Inspected Revise Structures Monitoring Program procedures to include the following parameters to be monitored or inspected:

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

4. Detection of Aging Effects Revise Structures Monitoring Program procedures to include the following for detection of aging effects:

• Inspection of insulation (fiberglass, calcium silicate) to manage loss of material and chanqe in material oroperties due to exposure to moisture that can cause loss of insulation effectiveness.

E 17of23

6. Acceptance Criteria Revise Structures Monitoring Pro-gram procedures to include the followinq acceptance criteria for insulation (calcium silicate and fiberglass):

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

Commitment changes Revise Commitment 31 parts C, G, and H. Add new commitment 31.K as shown below.

Additions are shown with underlines.

C. Revise Structures Monitoring Program procedures to include the following in-scope structural components and commodities:

• Insulation (fiberglass, calcium silicate)

G. Revise Structures Monitoring Program procedures to include the following parameters to be monitored or inspected:

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

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

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

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

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

E 18 of 23

RAI B. 1.41-3a (Follow-up)

Background:

By letter dated July 1, 2013, the applicantprovided its response to RAI B. 1.41-3 that addressed the scope of inspection in the Thermal Aging Embrittlement of CastAustenitic Stainless Steel (CASS) Program. In its response, the applicant stated that when the inspection option is selected for aging management of CASS components, the scope of the inspection covers those portions of the CASS components determined to be limiting from the standpointof applied stress, operating time and environmentalconsiderationsin accordancewith the GALL Report.

Issue:

For those CASS components that are screened as being susceptible to loss of fracture toughness due to thermal aging embrittlement, the GALL Report permits an applicant to select eitherinspection br performance of a flaw tolerance evaluation to manage the aging effect in the susceptible components. However, the applicant'sresponse does not clearly address whether or not the limiting portions of each susceptible component will be inspected if the inspection option is selected.

Request:

Clarify whether or not the scope of inspection covers the limiting portions of each susceptible component if the inspection option is selected.

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

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

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

For components selected for inspection, the limiting portions of the component from the standpoint of applied stress, operating time and environmental considerations will be included, as recommended by NUREG-1 801,Section XI.M12.

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RAI B.1.2-2a (Follow-up)

Background:

The response to RAI B. 1.2-2, dated July 1, 2013, stated that the normally inaccessible submerged bolted connections associatedwith the essentialraw water cooling (ERCW) pumps are visually inspected for loss of materialwhen they are made accessible during maintenance.

The response also stated that the frequency of inspection is adequate to prevent significant age-relateddegradation.

Issue:

The staff requires an understandingof the anticipatedfrequency of inspection of the normally submerged ERCW bolted connections and the basis for determining that the frequency is adequate to prevent significantage-relateddegradation.

Request:

1. State the estimated inspection frequency for the normally submerged ERCW bolted connections during the PEO and the basis for that estimation, including such information as historicalmaintenance or planned activities. In addition,justify why that frequency will be sufficient to manage loss of materialfor the bolting.

2. Absent a justification for the proposed opportunisticinspections, state the minimum number of inspections that will be conducted to ensure that aging effects for ERCW bolting will be age managed during the PEO.

TVA Response to RAI B.1.2-2a

1. SQN will visually inspect a representative sample of ERCW system submerged bolts at least once every five years during the PEO. It is anticipated that divers will perform the inspections. (See Commitment 2.D)

Recent operating experience provides the basis for the inspection frequency of at least once every five years.

The N-B ERCW pump was installed in 1993 and replaced in 2013. Maintenance personnel stated that during the N-B ERCW pump replacement, all of the normally submerged bolting was loosened with common tools, indicating no significant bolting degradation. Because the ERCW pump bolts incurred no significant degradation during 20 years of submergence, a visual inspection of a representative sample of normally submerged pump bolts at least once every five years provides reasonable assurance that significant degradation can be identified prior to loss of intended function.

The representative sample for submerged bolts will be 20% of the population, with a maximum of 25, during each five year inspection interval. The inspection focuses on the bounding or lead components most susceptible to aging due to time in service and severity of operating conditions. Adverse bolting indications observed during inspections are entered into the plant corrective action program.

E 20 of 23

2. A minimum of three ERCW bolted inspections will be performed during the PEO.

Changes to LRA Section B.1.2 and LRA Section A.1.2 follow with additions underlined and deletions lined through.

"B.1.2 Bolting Integrity The Bolting Integrity Program manages loss of preload, cracking, and loss of material for closure bolting for safety-related and nonsafety-related pressure-retaining components using preventive and inspection activities. This program does not include the reactor head closure studs or structural bolting. Preventive measures include material selection (e.g., use of materials with an actual yield strength of less than 150 ksi), lubricant selection (e.g., restricting the use of molybdenum disulfide), applying the appropriate preload (torque), and checking for uniformity of gasket compression where appropriate to preclude loss of preload, loss of material, and cracking. This program supplements the inspection activities required by ASME Section Xl for ASME Class 1, 2 and 3 bolting. For ASME Code Class 1, 2, and 3, and non-ASME Code class bolts, periodic system walkdowns and inspections (at least once per refueling cycle) ensure identification of indications of loss of preload (leakage), cracking, and loss of material before leakage becomes excessive. Normally inaccecsible A representative sample of submerged bolts bolted connoctions in the ERCW system are visually inspected for degradation.... they aremade ac..;sihblo during a....iatod cGompo,nent maPinten,,ance actvi-ities at least once every five years. The representative sample for ERCW system submeraed bolts will be 20% of the population, with a maximum of 25, during each five year inspection interval. The inspection of ERCW system submerged bolts focuses on the bounding or lead components most susceptible to aging due to time in service and severity of operating conditions. Visual inspection methods are effective in detecting the applicable aging effects and the frequency of inspection is adequate to prevent significant age-related degradation. With the exception of one reactor vessel closure stud, which is managed by the Reactor Head Closure Studs Program (Section B.1.33), no high-strength bolting has been identified at SQN. Identified leaking bolted connections will be monitored at an increased frequency in accordance with the corrective action process. Applicable industry standards and guidance documents, including NUREG-1339, EPRI NP-5769, and EPRI TR-104213, are used to delineate the program.

The following enhancements will be implemented prior to the PEO.

Element Affected Enhancement

2. Preventive Actions Revise Bolting Integrity Program procedures to ensure the actual yield strength of replacement or newly procured bolts will be less than 150 ksi.

4. Detection of Aging Effects Revise Bolting Integrity Program procedures to specify a corrosion inspection and a check-off for the transfer canal isolation valve flange bolts.

4. Detection of Aging Effects Revise Bolting Integrity Program procedures to visually inspect a representative sample of normally submerged ERCW system bolts at least once every 5 years.

E 21 of 23

7. Corrective Actions 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.

A.1.2 Bolting Integrity Program The Bolting Integrity Program manages loss of preload, cracking, and loss of material for closure bolting for safety-related and nonsafety-related pressure-retaining components using preventive and inspection activities. This program does not include the reactor head closure studs or structural bolting. Preventive measures include material selection (e.g., use of materials with an actual yield strength of less than 150 kilo-pounds per square inch [ksi]),

lubricant selection (e.g., restricting the use of molybdenum disulfide), applying the appropriate preload (torque), and checking for uniformity of gasket compression where appropriate to preclude loss of preload, loss of material, and cracking. This program supplements the inspection activities required by ASME Section Xl for ASME Class 1, 2 and 3 bolting. For ASME Code Class 1, 2, and 3, and non-ASME Code class bolts, periodic system walkdowns and inspection (at least once per refueling cycle) ensure identification of indications of loss of preload (leakage), cracking, and loss of material before leakage becomes excessive. NOR.al4.,

iP=a=eesib~e-A representative sample of submerged bolts o99t~d connction.s in the ERCW system are visually inspected for degradation Whon thoy . Re m..ade

,o acc...i'ble during as.ociated omponent. m-ainte--anc a.ti..'it-esat least once every five years. The representative sample for ERCW system submerqed bolts will be 20% of the population, with a maximum of 25, during each five year inspection interval. The inspection of ERCW system submerged bolts focuses on the bounding or lead components most susceptible to aging due to time in service and severity of operating conditions. Visual inspection methods are effective in detecting the applicable aging effects and the frequency of inspection is adequate to prevent significant age-related degradation. With the exception of one reactor vessel closure stud, which is managed by the Reactor Head Closure Studs Program (Section A.1.33), no high-strength bolting has been identified at SQN. Identified leaking bolted connections will be monitored at an increased frequency in accordance with the corrective action process. Applicable industry standards and guidance documents, including NUREG-1 339, EPRI NP-5769, and EPRI TR-1 04213, are used to delineate the program.

The Bolting Integrity Program will be enhanced as follows.

• Revise Bolting Integrity Program procedures to ensure the actual yield strength of replacement or newly procured bolts will be less than 150 ksi.

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-1 04213 for the replacement of other pressure-retaining bolts.

E 22 of 23

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

Revise Bolting Integrity Program procedures to visually inspect a representative sample of normally submerged ERCW system bolts at least once every five years."

Commitment # 2.D has been added.

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ENCLOSURE2 Tennessee Valley Authority Sequoyah Nuclear Plant, Units 1 and 2 License Renewal Revised Responses to RAI B.1.9-1a and B.1.4-4b, and revision to LRA page 2.4-44 RAI B.1.9-1a

Background:

The Staff observed in the EQ Health reports that two indicatorsin the EQ program health report (3 & 6E) have been designatedas yellow for three years. These issues also appearin the applicant'sassessment reports without resolution.

Issue: The staff is concerned that LRA EQ AMP B. 1.9 may not meet the GALL Report AMP X.El corrective actions program element when implemented by the applicant.

Identified that the qualified permanent backup engineerposition has been vacant since October2010.

- 6E - Identified that no permanent maintenance EQ coordinatoris availableat Sequoyah which resulted in two instances of site EQ procedure violations.

Request: Explain the actions taken to resolve the EQ program health reports yellow indicators3 and 6E.

Revised TVA Response to RAI B.1.9-1a Note: Revisions are in italics and underlined. Deletions are in italics and lined through. This revised response supersedes the response provided to the NRC on July 29, 2013, ADAMS No.

ML13213A027, page 26 of 50 in the Enclosure.

The two program health report indicators (3 and 6E) are unrelated to the corrective action program element in NUREG-1 801,Section X.E1 which states the following.

"Ifan EQ component is found to be outside the bounds of its qualification basis, corrective actions are implemented in accordance with the station's corrective action program. When unexpected adverse conditions are identified during operational or maintenance activities that affect the environment of a qualified component, the affected EQ component is evaluated and appropriate corrective actions are taken, which may include changes to the qualification bases and conclusions. When an emerging industry aging issue is identified that affects the qualification of an EQ component, the affected component is evaluated and appropriate corrective actions are taken, which may include changes to the qualification bases and conclusions. Confirmatory actions, as needed, are implemented as part of the station's corrective action program, pursuant to 10 CFR 50, Appendix B. As discussed in the Appendix for GALL, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions."

E2 - 1 of 7

The health report indicators were not related to the EQ qualification basis, adverse environmental conditions that could affect the qualified component, or an emerging industry aging issue that affects the qualified component. Therefore, this is not an issue of ineffective corrective actions. Nonetheless, SQN intends to resolve the yellow program health report indicators as described below.

EQ program health report yellow indicator 3 The Engineering Programs manager has been is utilizing a qualified electrical design engineer as a backup to the EQ Program owner. This EQ Program staffing arrangement has resulted in no challenges to any EQ component qualification basis. The ye!!ow W:ndOw indicates only that curr~ent staffing arrangoment is not optimal for-EQ Pro9gram efficiency considerations.

A fully qualified electricaldesign engineer is now designatedas a backup to the EQ Program owner. As a result, the EQ program health report indicator3 is forecast to improve to a "white or green"rating in the next reporting period.

EQ program health report yellow indicator 6E The EQ program health report indicator 6E identified that the transmittal of an EQ maintenance work order completion form by the performing organization to the EQ program owner was not completed in a timely manner (15 days after completing the EQ work) as specified by the EQ program procedure.

This condition involved the organization performing the work not meeting the timeliness provisions of the procedure. The lack of a Maintenance EQ Program coordinator to facilitate the transfer of the EQ work completion forms to the EQ Program owner contributed to the delay in updating EQ program records following EQ maintenance. The Maintenance EQ coordinator is not a position defined in the EQ Program procedure.

The EQ maintenance coordinatorposition has now been staffed. The assignedindividual has completed the necessary training requirements.

These EQ Program staffing issues have not resulted in challenges to the qualification basis for any EQ component.

As a result of new personnel assignments, the EQ program health indicator6E is forecast to improve to a "white"rating in the next reportingperiod.

The re-solution plans to imgprove the yelloew indicators to acceptable status are being ad-dress-ed in the SQN Gorrectie action rorearne.

E2.-2 of 7

RAI B. 1.4-4b

Background:

LRA Section B. 1.4 states, "[i]fcathodic protection is not provided priorto the periodof extended operation, the program will include documented justification that cathodic protection is not warranted."

LR-ISG-2011-03 states that the justification for not having cathodic protection must be provided in the LRA.

Issue:

During the audit, the staff reviewed a CorrproReport titled, "TVA - Sequoyah Nuclear Plant -

Buried Piping Integrity Program CorrosionAssessment Report." This report cited several examples demonstrating that the soil at Sequoyah is corrosive and recommended installationof cathodic protection in some locations with in-scope piping. Based on input received during audit breakout sessions, it was noted that a new study was recently completed by a different vendor.

The new study was not availablefor review by the staff during the audit.

Request:

1. If cathodic protection will not be installed,provide an analysis for not providing cathodic protection 10 years priorto commencing the period of extended operation consistent with the recommended detail in LR-ISG-2011-03 Section 2.a.iii.

2. If cathodic protection will not be installed, state the results of a 10 -yearsearch of plant-specific operatingexperience related to in-scope and out-of-scope buried piping consistent with the recommended detail in LR-ISG-2011-03 Section 2.a.iv.

3. Based on the results of (a) and (b) above, state what adjustments to the program will be implemented if cathodic protection is not installed and the study results demonstrate adverse results. If no adjustments will be made, state the basis for why reasonable assurance can be establishedthat the buried in-scope components will meet their intended function consistent with the current licensing basis.

NRC Follow up questions for B. 1.4-4b (via telecom)

Background:

TVA's B. 1.4-4 RAI response on July 25, 2013 revised the LRA Table 3.4.2-2 by deleting the soil environment for piping and bolting.

• If the piping and bolting is not exposed to soil, what environment is it exposed to in the path from the condensate storage tank to the auxiliaryfeedwaterpump suction?

" Is this piping in-scope?

" If this piping is in-scope, and if it passes through a pipe tunnel, is the access to the tunnel unrestricted?

" If this piping is in-scope, what program will be used to manage the loss of material (pipingand bolting) and loss of preload (bolting) aging effects?

E2 - 3 of 7

Revised TVA Response to RAI B.1.4-4b Note, revisions are in italics and underlined. This revised response supersedes the response provided to the NRC by letters dated:

• July 25, 2013, ADAMS No. ML13213A026, in the Enclosure 1, page 10 of 11, and

• August 9, 2013, ADAMS No. ML13225A387, in the Enclosure 4, page 4 of 5.

1. Cathodic 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 XI.M41, as modified by LR-ISG-2011-03, including provisions for providing cathodic protection. (See Commitment # 3.B)

2. Cathodic protection will be provided.

3. Cathodic protection will be provided, so no adjustments are necessary.

LRA Appendix A and B Changes "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 quidance 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.

Gatheodi Prot,-tion i6 RotRintalled. If cathodic po*tetion i6 Rot prI,;ded prior to the period of exoRnded o*prati;*, the prmFram will iRncude doumonxrted ju-tification that cathodic protoctionis no Rt warranted. The utific~ation should incluido the rosults Of Somi tosting (including testsfor; silFresisFA6tiVity, corrosion accolorating bacteria, pH, moisturo, chloridos and redox potential) to domons;trate that the coil enViFronment is; not corrosiv*e to applecab~

bur~ied components. Tho- results of a re-VIew o-f at lfeast ton years Of operating eprec mus6t su1pport the concIlusion that cathodic protection isnot wwarrated. The review ofte years of operating experience Will inclde reAieWW of operating experience With compnPGents net inthe sco-,(pe Of license- rene-wOal if they are fabiriaated- from the saRme materal ;and expesed to the same enVironmonts as in scono buried- and- -Und-eparoud GGm~n9Gn9ts.

E2 -4 of 7

m r i ii *J if a reduction inthe number of inspect0on6 recommo~ndea In Table 4a a; NUI-(L 4804,Section XI.n1 is claimed based on a lack of so*ilcr*r arudetermined by soil testing, nOvity then soil te-sting should be8. ,cndut once in each ten year period 63ta. F

,*f, tn r . t.o the period of ed.ended operation. This program will be implemented prior to the period operation."

NUREG-1801 Consistency The Buried and Underground Piping and Tanks Inspection Program will be consistent with the program described in NUREG-1801,Section XI.M41, Buried and Underground Piping and Tanks as modified by LR-ISG-2011-03."

In addition to the above, it has been determined that the main and auxiliary feedwater (AFW) systems do not have piping or bolting exposed to soil. The reason the soel environment was removed is because the AFW pipinq and bolting are in an accessible tunnel.

The A FWpipina and bolting in the tunnel are contained in LRA Table 3.4.2.2 with external environment of outdoor and indoorair.

The AFW piping is in-scope; see LRA drawings 47W804-1: 1.2-47W804-2: 1.2-47W803-2.

Access to the tunnel is unrestricted.

The External Surface Monitoring Programis mana-ging the loss of materialfor the piping in the tunnel.

The Bolting Integrity Programis managing the loss of materialand loss of preloadfor bolting in the tunnel.

Therefore, the Buried and Underground Piping and Tanks Inspection Program is not applicable.

The change to LRA Table 3.4.2-2 line items follows with deletions lined through.

Component Intended Aging Effect Aging NuREG- Table 1 Type Function Material Environment Requiring Management 1801 Item Item Notes Management Program t§ P-reseue GeFhQA 8emi(ex) Loss of material B1Fied-and VIlH.G.SP 24 447 A be=daey steel Undereund 445 iping-a*d Tanks 13eti§ P-er-U~e GarbeR Semi-(ext) Lccs of raterial Bt.ied a*d VI.*.kH"*" 3.4A-6 A bounda steel Unde§FgeR4 442 Tanks Inepeetiens Belting P-FeSSe~e Garben Seil-(9Xt) 1=966-ef pielead Belting-Integfity V44klH.$P- 3.4.16 A boundary steel 442 E2 - 5 of 7

The change to LRA Table 3.4.1 line items follows with additions underlined and deletions lined through.

Table 3.4.1: Steam and Power Conversion Systems Item Aging Effect/ Aging Further Evaluation Number Component Mechanism Management Recommendation Programs 3.4.1-6 Steel, stainless Loss of preload Chapter XI.M18, No Ccncictnt- with ,IUREG steel bolting "Bolting Integrity 1801. Lose of prolad for exposed to soil Program" boil oxposod to stobleting is

. b,

.*aagdthI Bolting

. .ey-P. e§Fa4* There is no buried steel or stainless steel bolting inthe steam and power conversion systems in the scope of license renewal.

3.4.1-47 Steel (with Loss of material Chapter XI.M41, No Consistent wth NUREG coating or due to general, "Buried and 1801. Loss of matErial for wrapping), pitting, crevice, and Underground rtool comFpnn ,,,o..d. to stainless steel, microbiologically Piping and soil is managed by the Buried nickel alloy influenced corrosion Tanks" and UdOrgrFound Piping and piping, piping Tanks Ifipcct--n Program.

components, There are no buried steel elements; tanks tak, er-stainless steel or exposed to soil nickel alloy components or concrete exposed to soil or concrete in the steam and power conversion systems in the scope of license renewal.

3.4.1-50 Steel bolting Loss of material Chapter XI.M41, No ConicFtent with NUREG exposed to soil due to general, "Buried and 1801. Lo=s of matr!ial for pitting and crevice Underground stoel bolting eMpc6ed to soil is corrosion Piping and mnaged by the Bu'ied and Tanks" UnderFgound Pipingq and Tanks Inp..tin P.erogram.

There is no steel bolting exposed to soil in the steam and power conversion systems in the scope of license renewal.

Change to Section 3.4.2.1.2 is with deletion lined through.

3.4.2.1.2 Main and Auxiliary Feedwater Environments

• Lube oil

. Treated water E2 - 6 of 7

NRC request for clarificationregardingSQN Station Black Out (SBO) transformers(in an email from the NRC to TVA from Mr. Emmanuel Sayoc on August 14, 2013)

LRA Section 2.4 (page 2.4-44, 3rd paragraph,and first sentence), comment from the NRC staff.,

"When reviewing the SBO recovery path for Sequoyah in LRA Section 2.4 describes that there are four transformersthat make up the SBO recovery path. However, the one line SQN electrical diagram that came with the LRA and the additionalwrite-ups imply that there are three SBO recovery common station service transformers (CSST), which are CSSTA, B, and C. There is no CSST D, which is contrary to what is stated in the LRA Section 2.4 (page 2.4-44, 3rd paragraph,and first sentence). This may be a misprint in the LRA Section 2.4."

TVA Response SBO restoration information found in LRA Section 2.4 (page 2.4-44, 3rd paragraph, and first sentence) is revised with deletions lined through.

"The offsite power source required to support SBO recovery is theo Chickamauga No. 1 Lino or Watts Bar Hydro Line, fed through one of the common station service transformers (CSST) A, B -,orC er-D."

E2 - 7 of 7

ENCLOSURE3 Tennessee Valley Authority Sequoyah Nuclear Plant, Units 1 and 2 License Renewal Regulatory Commitment List, Revision 6 Commitments 2.0, 31 .C/G/H and 31 .K have been revised. Additions are underlined.

LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE IAUDIT ITEM W

Implement the Aboveground Metallic Tanks Program as described SQN1: Prior to 09/17/20 B.1.1 in LRA Section B.1.1 SQN2: Prior to 09/15/21 2 A. Revise Bolting Integrity Program procedures to ensure the SQN1: Prior to 09/17/20 B.1.2 actual yield strength of replacement or newly procured bolts will be SQN2: Prior to 09/15/21 less than 150 ksi B. Revise Bolting Integrity Program procedures to include the additional guidance and recommendations of EPRI NP-5769 for replacement of ASME pressure-retaining bolts and the guidance provided in EPRI TR-104213 for the replacement of other pressure-retaining bolts.

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

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

E I of 16

LRA COMMITMENT IMPLEMENTATION SECTION No. IAUDIT SCHEDULE ITEM 4 A. Revise Compressed Air Monitoring Program procedures to QNI: Prior to 09/17/20 B.1.5 include the standby diesel generator (DG) starting air subsystem. QN2: Prior to 09/15/21 B. Revise Compressed Air Monitoring Program procedures to include maintaining moisture and other contaminants below specified limits in the standby DG starting air subsystem C. Revise Compressed Air Monitoring Program procedures to apply a consideration of the guidance of ASME OM-S/G-1998, Part 17; EPRI NP-7079; and EPRI TR-108147 to the limits specified for the air system contaminants D. Revise Compressed Air Monitoring Program procedures to maintain moisture, particulate size, and particulate quantity below acceptable limits in the standby DG starting air subsystem to mitigate loss of material.

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

• Diesel starting air subsystem

• Auxiliary controlled air subsystem

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

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

E 2of16

LRA COMMITMENT IMPLEMENTATION SECTION No. SCHEDULE I AUDIT ITEM 5 A. Revise Diesel Fuel Monitoring Program procedures to monitor SQNI: 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 COMMITMENT IMPLEMENTATION SECTION No.

SCHEDULE IAUDIT 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 COMMITMENT IMPLEMENTATION SECTION No.

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

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

9 A. Revise Fire Water System Program procedures to include periodic SQN1: Prior to 09/117/20 B.1.13 visual inspection of fire water system internals for evidence of SQN2: Prior to 09/15/21 corrosion and loss of wall thickness.

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

• Wall thickness evaluations of fire protection piping using non-intrusive techniques (e.g., volumetric testing) to identify evidence of loss of material will be performed prior to the period of extended operation and periodically thereafter. Results of the 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 COMMITMENT IMPLEMENTATION SECTION No.

SCHEDULE I 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 Controlling Cavitation, Flashing, Liquid Droplet Impingement, and Solid ParticleErosion in Nuclear Power Plant Piping, and NUREG/CR-6031, Cavitation Guide for Control Valves. (TVA Response to Set 6.60day RAI B. 1.14-1 and B. 1.38-1)_

E 6of16

LRA COMMITMENT IMPLEMENTATION SECTION No.

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

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

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

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

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

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

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

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

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

LRA COMMITMENT IMPLEMENTATION SECTION No. IAUDIT SCHEDULE ITEM 15 Implement the Metal Enclosed Bus Inspection Program as SQN1: Prior to 09/17/20 B.1.21 described in LRA Section B.1.21. SQN2: Prior to 09/15/21 16 A. Revise Neutron Absorbing Material Monitoring Program SQN1: Prior to 09/17/20 B.1.22 procedures to perform blackness testing of the Boral coupons within SQN2: 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-1 0 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 SQN1: Prior to 09/17/20 B.1.24 in LRA Section B.1.24 SQN2: Prior to 09/15/21 18 Implement the Non-EQ Inaccessible Power Cable (400 V to 35 kV) QN1: 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 QN1: Prior to 09/17/20 B.1.26 Program as described in LIRA Section 13.1.26. SQN2: Prior to 09/15/21 20 Implement the Non-EQ Insulated Cables and Connections QNI: Prior to 09/17/20 B.1.27 Program as described in LRA Section B.1.27 SQN2: Prior to 09/15/21 21 A. Revise Oil Analysis Program procedures to monitor and QN1: Prior to 09/17/20 B.1.28 maintain contaminants in the 161-kV oil filled cable system within IQN2: 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 QN1: Prior to 09/17/20 B.1.29 Section B.1.29. QN2: Prior to 09/15/21 23 Implement the One-Time Inspection - Small Bore Piping Program QN1: Prior to 09/17/201 B.1.30 as described in LRA Section B.1.30 QN2: Prior to 09/15/21 24 Revise Periodic Surveillance and Preventive Maintenance SQN1: Prior to 09/17/20 B.1.31 Program procedures as necessary to include all activities described SQN2: Prior to 09/15/21 in the table provided in the LRA Section B.1.31 program description.

E 8of16

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

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

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

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

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

27 A. Revise Reactor Vessel Internals Program procedures to take SQN1: 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 SQN1: 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 COMMITMENT IMPLEMENTATION SECTION No.

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. SQN2: Prior to 09/15/21 30 Revise Steam Generator Integrity Program procedures to ensure SQN1: Prior to 09/17/20 B.1.39 that corrosion resistant materials are used for replacement steam ;QN2: Prior to 09/15/21 generator tube plugs.

31 A. Revise Structures Monitoring Program procedures to include 3QNI: Prior to 09/17/20 B.1.40 the following in-scope structures: 3QN2: Prior to 09/15/21

" Carbon dioxide building

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

" East steam valve room Units 1 & 2

• Essential raw cooling water (ERCW) pumping station

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

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

• Service building

• Skimmer wall (Cell No. 12)

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

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

" CCW pumping station intake channel

" ERCW discharge box

• ERCW protective dike

" ERCW pumping station and access cells

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

• Anchor bolts

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

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

" 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 E 10 of 16

LRA COMMITMENT IMPLEMENTATION SECTION No SCHEDULE I AUDIT ITEM (31)

• 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)

• Insulation (fiberglass, calcium silicate)

" 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 E 11 of 16

LRA No. COMMITMENT IMPLEMENTATION SCAUDIT ITEM (31) equipment and instrumentation

• 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 buildina E 12 of 16

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE IAUDIT ITEM (31) F. Revise Structures Monitoring Program procedures to include the following parameters to be monitored or inspected:

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

" Loose or missing nuts for structural bolting.

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

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

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

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

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

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

" Inspection of structural bolting for loose or missing nuts.

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

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

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

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

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

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

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

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LRA COMMITMENT IMPLEMENTATION SECTION No. SCHEDULE /AUDIT ITEM (31)

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

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

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

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

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

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

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

32 Implement the Thermal Aging Embrittlement of Cast Austenitic 3QN1: Prior to 09/17/20 B.1.41 Stainless Steel (CASS) as described in LRA Section B. 1.41 3QN2: Prior to 09/15/21 33 A. Revise Water Chemistry Control - Closed Treated Water SQN1: 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 0 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)

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LRA COMMITMENT IMPLEMENTATION SECTION No.

SCHEDULE /AUDIT ITEM (33) C. Revise Water Chemistry Control-Closed Treated Water Systems Program procedures to state these inspections will be conducted in accordance with applicable ASME Code requirements, industry standards, or other plant-specific inspection and personnel qualification procedures that are capable of detecting corrosion or cracking.

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

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

• Standby diesel generator jacket water subsystem

" Component cooling system

• Glycol cooling loop system

• High pressure fire protection diesel jacket water system

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

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

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

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

35 Modify the configuration of the SQN Unit 1 test connection access SQNI: Prior to 09/17/20 B.1.6 boxes to prevent moisture intrusion to the leak test channels. Prior to installing this modification, TVA will perform remote visual SQN2: Not Applicable examinations inside the leak test channels by inserting a borescope video probe through the test connection tubing.

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LRA No. COMMITMENT IMPLEMENTATION SECTION SCHEDULE IAUDIT ITEM 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.

37 TVA will implement the Operating Experience for the AMPs in 1o later than the B.O.4 accordance with the TVA response to the RAI B.0.4-1 on-July 29, scheduled 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.

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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