CNL-14-094, Response to NRC Request for Additional Information Regarding the Review of the License Renewal Application, 2.5-4, 3.0.3-1-3 Request 4c, and B.1.13-4a

Response to NRC Request for Additional Information Regarding the Review of the License Renewal Application, 2.5-4, 3.0.3-1-3 Request 4c, and B.1.13-4a

ML14197A267
Person / Time
Site:	Sequoyah
Issue date:	06/13/2014
From:	James Shea Tennessee Valley Authority
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
CNL-14-094, L44 14063 003, TAC MF0481, TAC MF0482
Download: ML14197A267 (40)

Text

L44 140613 003 Tennessee Valley Authority, 1101 Market Street, Chattanooga, Tennessee 37402 CNL-14-094 June 13, 2014 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, 2.5-4, 3.0.3-1-3 Request 4c, and B.1.13-4a (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 21, dated May 28, 2014 (ADAMS Accession No. ML14143A213)

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 dates.

By Reference 2, the NRC forwarded a request for additional information (RAI) labeled Set 21:2.5-4 with a required response due date no later than June 27, 2014. In addition, TVA is providing revisions to the responses to RAI 3.0.3-1 Request 4b and RAI B.1.13-4. provides the RAI response and the two revisions.

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.

U.S. Nuclear Regulatory Commission Page 2 June 13, 2014 is an updated list of the regulatory commitments for license renewal that supersedes all previous versions. Please address any questions regarding this submittal to Henry Lee at (423) 751-2683 .

I declare under penalty of perjury that the foregoing is true and correct. Executed on this 13th day of June 2014.

Enclosures:

1. TVA Response to NRC Request for Additional Information: 2.5-4, 3.0.3-1-3 Request 4c, and B.1.13-4a

2. Regulatory Commitment List, Revision 16 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:

2.5-4, 3.0.3-1-3 Request 4c, and B.1.13-4a Set 21: RAI 2.5-4

Background:

Title 10 of the Code of Federal Regulations (10 CFR) 54.4(a)(3) requires that all systems, structures, and components (SSCs) relied on in safety analyses or plant evaluation to perform a function that demonstrates compliance with U.S. Nuclear Regulatory Commission regulations for station blackout (SBO) (10 CFR 50.63) be included within the scope of license renewal. The Standard Review Plan for License Renewal (SRP-LR), Section 2.5.2.1.1 provides the guidance to identify electrical and I&C systems components that are relied upon to meet the requirements of the SBO Rule for license renewal. This includes equipment that is required to cope with an SBO (e.g., alternate ac power sources) meeting the requirements in 10 CFR 54.4(a)(3) and the plant system portion of the offsite power system, including the electrical distribution equipment out to the first circuit breaker with the offsite distribution system (i.e., equipment in the switchyard), that is used to connect the plant to the offsite power source meeting the requirements under 10 CFR 54.4(a)(3). In addition, General Design Criteria 17 of 10 CFR Part 50, Appendix A, requires that electric power from the transmission network to the onsite electric distribution system is supplied by two physically independent circuits to minimize the likelihood of their simultaneous failure. SSCs that are relied upon to meet the requirements of the SBO Rule in both circuits are to be included within the scope of license renewal.

The applicant revised the scoping boundaries for SBO in the license renewal application (LRA)

Section 2.5, Scoping and Screening Results: Electrical and Instrumentation and control Systems, to state:

The Unit 1 and Unit 2 preferred offsite power sources required to support SBO recovery are supplied by two physical and electrically independent circuits from the 161-kV and 500-kV switchyards through separate transformers to the electrical distribution system (see LRA Drawing LRA-E-001). The two physically and electrically independent circuits consist of the normal and alternate offsite power sources. The Sequoyah Nuclear Plant (SQN), 500-kV switchyard is the source of one of the physically and electrically independent circuits [].

Specifically, this offsite power recovery path includes the 500-kV switchyard circuit breakers feeding the unit station service transformers (USSTs) (1A or 1B) via the Unit 1 (U1) main transformer []. The SQN 161-kV switchyard is the source of one of the physically and electrically independent circuits []. Specifically, this offsite power recovery path includes the 161-kV switchyard circuit breakers feeding the USSTs (2A or 2B) via the Unit 2 (U2) main transformer.

In the updated final safety analysis report for the SQN, Figure 8.1.2-1 shows three power sources for the 6.9 kV shutdown boards of both Units 1 and 2. One power source is from the 500-kV switchyard via the U1 main transformer and two power sources are from 161-kV switchyard via the U2 main transformer and the common station service transformers (A, B, C).

E 1 of 6

Issue:

The applicant did not identify which of the 161-kV and 500-kV offsite power sources are the normal and alternate power sources for SQN Unit 1 and Unit 2.

The applicant did not identify the 500-kV switchyard circuit breakers feeding the USSTs 1A or 1B and the 161-kV switchyard circuit breakers feeding the USSTs 2A or 2B.

The applicant did not include an updated LRA drawing LRA-E-001 in the annual update submittal.

Request:

1. Clarify which of the 161-kV and 500-kV offsite power sources are the normal and alternate power sources for SQN Unit 1 and Unit 2.

2. Provide an updated LRA drawing LRA-E-001 that shows components (e.g., breakers, transformers, metal enclosed bus), which are (1) included in the SBO power recovery path, (2) included within the scope of license renewal, and (3) subject to an aging management review, starting from the onsite electrical distribution equipment (i.e.,6.9 kV shutdown boards) up to and including the first circuit breakers of the offsite distribution system (i.e., switchyard equipment) under the requirements of 10 CFR 54.4(a)(1) and 10 CFR 54.4(a)(3).

TVA Response to RAI 2.5-4

1. TVA has revised the description of the SBO credited offsite power sources in LRA Section 2.5 to eliminate the terms normal and alternate offsite power sources for the SBO recovery discussion. The phrase normal and alternate offsite power sources were used in the April 22, 2014, annual update submittal, in Section 2.5, in relation to offsite power sources configuration during normal plant operation, and NOT relevant to the SQNs SBO recovery discussion.

The terms normal and alternate in the UFSAR (revision 25) Table 8.2.1-1 describe the electrical board power configuration during normal plant operation. Normal power source is defined as normally in service, as shown on the SQN electrical drawing 15E500, revision 37. The term alternate power source is defined as normally in standby.

The normal offsite power sources to the 6.9-kV shutdown boards (SDBs) for SQN Units 1 and 2 are from the 161/500-kV switchyards to the USSTs (1A, 1B, 2A, 2B), to the unit boards (UBs), then to the 6.9-kV SDBs. (During normal plant operation)

The alternate offsite power sources for SQN Units 1 and 2 are from the 161-kV switchyard, to the common station service transformers (CSSTs), to the start busses (SBs), UBs, then to the 6.9-kv SDBs as specified in the Living UFSAR, Section 8.2.1.1 and Table 8.2.1-1. (During normal plant operation)

The UFSAR (revision 25), Section 8.2.1.1 states:

The intent of GDC 17 has been implemented in the design of the Preferred Power System by providing two physically and functionally independent circuits for energizing safety related load groups. [.]

E 2 of 6

The Preferred Power System consists of: two main bank transformers; six 24-kV isolated phase buses; four 24-6.9-kV unit station service transformers; four 6.9-kV unit station service transformer buses; three 161-6.9-kV CSSTRs (A and C, energized spare B); a 6.9-kv start board; four 6.9-kV start buses; eight 6.9-kV unit boards; four 6.9-kV shutdown boards; and all overhead conductors, buses, cable, and distribution equipment that interconnect the offsite power circuits with the 6.9-kV shutdown boards. The Preferred Power System is supplied power by way of either the plant 161-kV or 500-kV switchyard. The combination of Unit 1 and 2 main bank transformers, USSTs, 24-kV isolated phase buses, and 6.9-kV unit station service transformer buses comprise one qualified independent offsite power circuit.

2. Drawing LRA-E-001 was revised on 5-30-2014 to show the added USSTs and the 500-kV switchyard; the drawing is attached to this enclosure. The path for the USSTs to the UBs is highlighted in green to distinguish it from the previous revision. This drawing shows components (e.g., breakers, transformers, metal- enclosed bus) which are (1) included in the SBO power recovery path, (2) included within the scope of license renewal, and (3) subject to an aging management review under the requirements of 10 CFR 54.4 (a)(3).

The Unit 1 USSTs (1A and 1B) are fed from the 500 kV switchyard (between breakers 5038 and 5034) via the main transformer 1. Back-feeding through main transformer 1 is credited as part of a third GDC-17 offsite power path. Although this offsite power path is not credited in the SBO recovery procedures, the components in the Unit 1 USSTs path are conservatively included in the aging management review.

The Unit 2 USSTs (2A and 2B) are fed from the 161 kV switchyard (between breakers 928 and 924) via the main transformer 2. Back-feeding through main transformer 2 is credited as part of a third GDC-17 offsite power path. Although this offsite power path is not credited in the SBO recovery procedures, the components in the Unit 2 USSTs path are conservatively included in the aging management review.

The cooling system for the iso-phase bus associated with the Unit 1 and Unit 2 USSTs is not needed during the back-feeding function of the main transformers to supply off-site power to the USSTs because of the reduced load on the iso-phase bus when the main generator is offline. Therefore, cooling for the iso-phase bus associated with the USSTs is not a license renewal intended function.

The changes to LRA Sections 2.4.3 and 2.5 below supersede and replace those found in the April 22, 2014 SQN annual LRA update.

LRA Section 2.4.3 Turbine Building, Aux/Control Building and Other Structures (LRA page 2.4-44)

These structures provide physical support to the transformer yard and switchyard components in the SBO offsite power recovery path. These support structures include the transformer foundations and foundations for the associated transformer yard and switchyard breakers, switchyard bus, and fused disconnect.

The SBO offsite power recovery circuits and the normal offsite circuits are discussed in LRA Section 2.5.

E 3 of 6

LRA Section 2.5 Scoping and Screening Results: Electrical and Instrumentation and Control Systems (LRA page 2.5-2)

Scoping Boundaries SBO credited offsite power recovery sources: Units 1 and 2 credited offsite power circuits that support SBO recovery are supplied by two physically and electrically independent GDC-17 circuits from the 161-kV switchyard through separate CSSTs (A and C) to the onsite electrical distribution system (see LRA Drawing LRA-E-001).

In addition, CSST B is connected to the 161-kV switchyard but does not normally carry load; it is a standby-spare for either A or C. If CSST A or C becomes unavailable, the loads supplied by either A or C automatically transfer to B. CSSTs (A, B, or C) are each capable of supplying power to the two 6.9-kV SDBs for each unit (1A-A, 1B-B, 2A-A, 2B-B, a total of four SDBs). These SBO credited offsite power recovery circuits include the six 161-kV switchyard circuit breakers (874, 878, 944, 948, 994, 998) feeding the CSSTs (A, B, or C).

Components in the 161-kV CSSTs offsite power recovery paths are switchyard bus and connections, transmission conductors and connections, high-voltage insulators, 161-kV oil-filled cables and connections, control circuit cables and connections, metal-enclosed bus (non-segregated), and inaccessible power cables and connections with manholes.

For Unit 1: The circuit from the SQN 500-kV switchyard through the USSTs 1A and 1B, the unit boards (UBs) 1A, 1B, 1C, 1D, then to the 6.9-kV shutdown boards (SDBs) 1A-A and 1B-B is the normal offsite power source for the onsite electrical distribution system. The 500-kV switchyard constitutes a third offsite power source for Unit 1.

For Unit 2: The circuit from the SQN 161-kV switchyard through the USSTs 2A and 2B, the unit boards (UBs) 2A, 2B, 2C, 2D, then to the 6.9-kV shutdown boards (SDBs) 2A-A and 2B-B is the normal offsite power source for the onsite electrical distribution system. This source from the 161-kV switchyard constitutes a third offsite power source for Unit 2.

SQN includes components in the normal offsite power circuits for Units 1 and 2 for aging management review. Components in the (Unit 1/500-kV USST 1A/1B and Unit 2/161-kV USST 2A/2B) offsite power circuits are switchyard bus and connections (PCBs 928, 924, 5038 and 5034), transmission conductors and connections, high-voltage insulators, control circuit cables and connections, and metal-enclosed bus (isolated phase and non-segregated). These components are added to the scope of license renewal even though the USST offsite power circuits are not in the current SQN SBO recovery procedures.

Structures supporting breakers, disconnects, transformers, transmission conductors, and switchyard bus within the off-site power recovery paths are evaluated with structures in Section 2.4, Scoping and 500-kV off-site power recovery path are also evaluated in Section 2.4.

E 4 of 6

RAI 3.0.3-1 Request 4c RAI 3.0.3-1 Request 4c supplements RAI 3.0.3-1 Request 4b.

TVAs RAI 3.0.3-1 Request 4b response was previously submitted on January 16, 2014 (ADAMS Accession No. ML14057A808, Enclosure 1, pages E 17 to 30 of 42)

TVA revises the RAI 3.0.3-1 Request 4b response by deleting the c option to Perform a 100%

UT examination of the area that does not drain to identify blockage.

TVA revises Commitment 9.P to clarify that additional inspections are not required if the visual inspection results are acceptable and no subsequent wetting occurs. This is based on LR-ISG-2012-02, Appendix D, Page D-5.

There are a number of changes to the January 16, 2014 letter, Enclosure 1, pages 21, 23, 28 and Commitment 9.P. The changes to RAI 3.0.3-1 Request 4b follow with deletions lined through and additions underlined.

Revise FWSP procedures to perform one of the following inspection methods for those sections of dry piping described in NRC Information Notice (IN) 2013-06, where drainage is not occurring, to ensure there is no flow blockage in each five-year interval beginning with the five-year period before the PEO:

(a) Perform a flow test or flush sufficient to detect potential flow blockage.

(b) Remove sprinkler heads or couplings in the areas that do not drain and perform a 100% visual internal inspection to verify there are no signs of abnormal corrosion (wall thickness loss) or blockage.

(c) Perform a 100% UT examination of the area that does not drain to identify blockage.

If option (a) is chosen, controls will be established to ensure potential blockage is not moved to another part of the system where it may not be detected.

In each five-year interval during the PEO, 20% of the length of piping segments that cannot be drained or piping segments that allow water to collect will be subjected to UT wall thickness examination. The piping examined during each inspection interval will be piping that was not previously examined.

If the results of a 100% internal visual inspection are acceptable, and the segment is not subsequently wetted, no further augmented tests or inspections will be performed.

Commitment #9.P is revised.

E 5 of 6

RAI B.1.13-4a RAI B.1.13-4a supplements RAI B.1.13-4 Response 4.a.

TVAs RAI B.1.13-4 Response 4.a was previously submitted on April 22, 2014 (ADAMS Accession No. ML14113A208, pages E 5). TVA stated that Clam/silt inspections at SQN are performed on an annual frequency for selected ERCW stagnant/dead leg piping. TVA provides the following clarification to RAI B.1.13-4 Response 4.a:

The referenced SQN PM program clam/silt inspections in the RAI B.1.13-4 Response 4.a are not credited inspections in the SQN response to NRC Generic Letter (GL) 89-13, submitted to the NRC on September 22, 1995, and are not credited in the Service Water Program aging management program.

The inspections of selected ERCW stagnant/dead leg piping to detect silting/clams discussed in the RAI B.1.13-4 Response 4.a are informal supplemental inspections that are used as an early diagnostic indicator of potential piping blockage in the ERCW stagnant/dead leg piping or used in conjunction with the corrective action program to provide information on potential piping blockage when reduced flow conditions are observed.

E 6 of 6

ENCLOSURE 2 Tennessee Valley Authority Sequoyah Nuclear Plant, Units 1 and 2 License Renewal Regulatory Commitment List, Revision 16 Commitment 9.P has been revised in Revision 16. The changes are identified with additions underlined and deletions lined through.

Commitment 9.G was revised on April 22, 2014 (ADAMS Accession No. ML14113A208, pg E 6). Changes for Commitment 9.G will not be underlined or lined through.

A. This list supersedes all previous versions. The final version will be included in the SQN UFSAR Supplement (LRA Appendix A,) before incorporation into the SQN UFSAR (after NRC approval of the SQN LRA). After incorporation into the SQN UFSAR, changes to information within the UFSAR Supplement (such as LR commitment) will be made in accordance with 10 CFR 50.59.

B. Throughout this document, the phrase prior to entering the PEO means the SQN AMPs will be implemented six months prior to the PEO (For SQN1: prior to 03/17/20; for SQN2: prior to 03/15/21) or the end of the last refueling outage prior to each unit entering the PEO, whichever occurs later.

SQN shall notify the NRC in writing within 30 days after having accomplished items listed in the LR Commitment List and include the status of those activities that have been or remain to be completed [01/16/14 CNL-14-010, A.1-2]

E 1 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 1 A. Implement the Aboveground Metallic Tanks Program as SQN1: Prior to 03/17/20 B.1.1 described in LRA Section B.1.1. [3.0.3-1, Requests 3, SQN2: Prior to 03/15/21 ML13312A005.11/4/13]

B. Aboveground Metallic Tanks Program includes outdoor tanks on soil or concrete and indoor large volume water tanks (excluding the fire water storage 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 conjunction with measuring the thickness of the tank bottoms to ensure that significant degradation is not occurring and that the components intended function is maintained during the PEO.

Internal inspections are conducted whenever the tank is drained, with a minimum frequency of at least once every 10 years, beginning in the 5-year interval prior to the PEO. [3.0.3-1 item 5a, ML13294A462, E 4 of 8, 10/17/13]

2 A. Revise Bolting Integrity Program procedures to ensure the SQN1: Prior to 03/17/20 B.1.2 actual yield strength of replacement or newly procured bolts will be SQN2: Prior to 03/15/21 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 03/17/20 B.1.4 Inspection Program as described in LRA Section B.1.4. SQN2: Prior to 03/15/21 B. Cathodic protection will be provided based on the guidance of NUREG-1801, section XI.M41, as modified by LR-ISG-2011-03.

[B.1.4-4b, ML13252A036. E2 -4 of 7, 9/3/13]

E 2 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 4 A. Revise Compressed Air Monitoring Program procedures to SQN1: Prior to 03/17/20 B.1.5 include the standby diesel generator (DG) starting air subsystem. SQN2: Prior to 03/15/21 B. Revise Compressed Air Monitoring Program procedures to include maintaining moisture and other contaminants below specified limits in the standby DG starting air subsystem.

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

E. Revise Compressed Air Monitoring Program procedures to include periodic and opportunistic visual inspections of surface conditions consistent with frequencies described in ASME O/M-SG-1998, Part 17 of accessible internal surfaces such as compressors, dryers, after-coolers, and filter boxes of the following compressed air systems:

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

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

E 3 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 5 A. Revise Diesel Fuel Monitoring Program procedures to monitor SQN1: Prior to 03/17/20 B.1.8 and trend sediment and particulates in the standby DG day tanks. SQN2: Prior to 03/15/21 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 (PEO) 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 PEO and succeeding ten-year intervals.

6 A. Revise External Surfaces Monitoring Program procedures to SQN1: Prior to 03/17/20 B.1.10 clarify that periodic inspections of systems in scope and subject to SQN2: Prior to 03/15/21 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 E 4 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (6) ten 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 specify the following for insulated components.

Periodic representative inspections are conducted during each 10-year period during the PEO.

For a representative sample of outdoor components, except tanks, and indoor components, except tanks, identified with more than nominal degradation on the exterior of the component, insulation is removed for visual inspection of the component surface. Inspections include a minimum of 20 percent of the in-scope piping length for each material type (e.g.,

steel, stainless steel, copper alloy, aluminum). For components with a configuration which does not conform to a 1-foot axial length determination (e.g., valve, accumulator), 20 percent of the surface area is inspected. Inspected components are 20% of the population of each material type with a maximum of 25.

Alternatively, insulation is removed and component inspections performed for any combination of a minimum of 25 1-foot axial length sections and individual components for each material type (e.g., steel, stainless steel, copper alloy, aluminum.)

For a representative sample of indoor components, except tanks, operated below the dew point, which have not been identified with more than nominal degradation on the exterior of the component, the insulation exterior surface or jacketing is inspected. These visual inspections verify that the jacketing and insulation is in good condition. The number of representative jacketing inspections will be at least 50 during each 10-year period.

If the inspection determines there are gaps in the insulation or damage to the jacketing that would allow moisture to get behind the insulation, then removal of the insulation is required to inspect the component surface for degradation.

For a representative sample of indoor insulated tanks operated below the dew point and all insulated outdoor tanks, insulation is removed from either 25 1-square foot sections or 20 percent of the surface area for inspections of the exterior surface of each tank. The sample inspection points are distributed so that inspections occur on the tank dome, sides, near the bottom, at points where structural supports or instrument nozzles penetrate the insulation, and where water collects (for example on top of stiffening rings).

E 5 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (6) Inspection locations are based on the likelihood of corrosion under insulation (CUI). For example, CUI is more likely for components experiencing alternate wetting and drying in environments where trace contaminants could be present and for components that operate for long periods of time below the dew point.

If tightly adhering insulation is installed, this insulation should be impermeable to moisture and there should be no evidence of damage to the moisture barrier. Given that the likelihood of CUI is low for tightly adhering insulation, a minimal number of inspections of the external moisture barrier of this type of insulation, although not zero, will be credited toward the sample population.

Subsequent inspections will consist of an examination of the exterior surface of the insulation for indications of damage to the jacketing or protective outer layer of the insulation, if the following conditions are verified in the initial inspection.

• No loss of material due to general, pitting or crevice corrosion, beyond that which could have been present during initial construction

• No evidence of cracking Nominal degradation is defined as no loss of material due to general, pitting, or crevice corrosion, beyond that which could have been present during initial construction, and no evidence of cracking. If the external visual inspections of the insulation reveal damage to the exterior surface of the insulation or there is evidence of water intrusion through the insulation (e.g. water seepage through insulation seams/joints), periodic inspections under the insulation will continue as described above.

[3.0.3-1 Request 6a, ML13357A722, E 24 of 43, 12/16/13]

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.

F. For a representative sample of outdoor insulated components and indoor insulated components operated below the dew point, which have been identified with more than nominal degradation on the exterior of the component, insulation is removed for inspection of the component surface. For a representative sample of indoor insulated E 6 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (6) components operated below the dew point, which have not been identified with more than nominal degradation on the exterior of the component, the insulation exterior surface is inspected. These inspections will be conducted during each 10-year period during the PEO. [3.0.3-1 Request 6a, ML13357A722, E 23 of 43, 12/16/13]

G. Specific, measurable, actionable/attainable and relevant acceptance criteria are established in the maintenance and surveillance procedures or are established during engineering evaluation of the degraded condition. [ML13357A722, E 43 of 43, 12/16/13]

7 A. Revise Fatigue Monitoring Program procedures to monitor and SQN1: Prior to 03/17/20 B.1.11 track critical thermal and pressure transients for components that SQN2: Prior to 03/15/21 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 and cycle-based fatigue waiver evaluations on an as-needed basis if an allowable cycle limit is approached, or in a case where a transient definition has been changed, unanticipated new thermal events are discovered, or the geometry of components have been modified.

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

E 7 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 8 A. Revise Fire Protection Program procedures to include an SQN1: Prior to 03/17/20 B.1.12 inspection of fire barrier walls, ceilings, and floors for any signs of SQN2: Prior to 03/15/21 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 Implement the Fire Water System Program (FWSP) as described in SQN1: Prior to 03/17/20 B.1.13 LRA Section B.1.13. SQN2: Prior to 03/15/21 A. 9.A was deleted in 01/16/14 CNL-14-010, 3.0.3-1, Request 4b B. 9.B was deleted in 3.0.3-1, Request 4a, ML13357A722, E 13 of 43, 12/16/13.

C. Revise FWSP procedures to ensure sprinkler heads are tested in accordance with NFPA 25 (2011 Edition), Section 5.3.1 [3.0.3-1 Request 4a]

D. 9.D was deleted in 01/16/14 CNL-14-010, 3.0.3-1, Request 4b E. Revise FWSP 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.

F. 9.F was in a wrong location and is moved to #24.C. 9.F is deleted in 01/16/14 CNL-14-010, 3.0.3-1-3a, and Request 4b G. Revise FWSP procedures to include periodically remove a representative sample of components, such as sprinkler heads or couplings, within five years prior to the PEO, and every five years during the PEO, to perform a visual internal inspection of the dry fire water system piping for evidence of corrosion, and loss of wall thickness, and foreign material that may result in flow blockage using the methodology described in NFPA-25 Section 14.2.1.

The acceptance criteria shall be no debris (i.e., no corrosion products that could impede flow or cause downstream components to become clogged). Any signs of abnormal corrosion or blockage will be removed, its source determined and corrected, and entered into the CAP.

Due dates:

SQN1: within five years prior to 03/17/20, and every five years during the PEO SQN2: within five years prior to 03/15/21, and every five years during the PEO (due dates for U1&2 are revised in Enc 1 of cnl-14-052, 4/22/14)

E 8 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (9) [3.0.3-1, Request 4a.d, i to vi, ML13357A722, E 11 of 43, 12/16/13], [9.G is revised in 01/16/14 CNL-14-010, 3.0.3-1, Request 4b, and the due dates in CNL-14-052 ]

H. Revise FWSP procedures to perform an obstruction evaluation in accordance with NFPA-25 (2011 Edition), Section 14.3.1.

I. Revise FWSP procedures to conduct follow-up volumetric examinations if internal visual inspections detect surface irregularities that could be indicative of wall loss below nominal pipe wall thickness.

J. Revise FWSP procedures to annually inspect the fire water storage tank exterior painted surface for signs of degradation. If degradation is identified, conduct follow-up volumetric examinations to ensure wall thickness is equal to or exceeds nominal wall thickness.

The fire water storage tanks will be inspected in accordance with NFPA-25 (2011 Edition) requirements.

K. Revise FWSP procedures to include a fire water storage tank interior inspection every five years that includes inspections for signs of pitting, spalling, rot, waste material and debris, and aquatic growth.

Include in the revision direction to perform fire water storage tank interior coating testing, if any degradation is identified, in accordance with ASTM D 3359 or equivalent, a dry film thickness test at random locations to determine overall coating thickness; and a wet sponge test to detect pinholes, cracks or other compromises of the coating. If there is evidence of pitting or corrosion ensure the FWSP procedures direct performance of an examination to determine wall and bottom thickness.

L. 9.L was deleted in 01/16/14 CNL-14-010, 3.0.3-1, Request 4b M. Revise FWSP procedures to perform an annual spray head discharge pattern tests from all open spray nozzles to ensure that patterns are not impeded by plugged nozzles, to ensure that nozzles are correctly positioned, and to ensure that obstructions do not prevent discharge patterns from wetting surfaces to be protected.

Where the nature of the protected critical equipment or property is such that water cannot be discharged, the nozzles shall be inspected for proper orientation and the system tested with air, smoke or some other medium to ensure that the nozzles are not obstructed.

Ensure that the dry piping is unobstructed downstream of deluge valves protecting indoor areas containing critical equipment by flow testing with air, smoke or other medium from deluge valve through the sprinkler heads.

Based on the trip testing of the deluge valves without flow through the downstream piping and sprinkler heads, additional testing in the RCA or areas containing critical equipment is not warranted due to the addition of risk-significant activities and the production of additional E 9 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (9) radwaste. [3.0.3-1, Request 4a, ML13357A722, E 14 of 43, 12/16/13]

N. Revise FWSP procedures to perform an internal inspection of the accessible piping associated with the strainer inspections for corrosion and foreign material that may cause blockage. Document any abnormal corrosion or foreign material in the CAP. [3.0.3-1, Request 4a, ML13357A722, E 15 of 43, 12/16/13]

O. Revise FWSP procedures to perform 25 main drain tests every 18-months with at least one main drain test performed in each of the following buildings: (1) control building, (2) auxiliary building, (3) turbine building, (4) diesel generator building and (5) ERCW building.

The results of the main drain tests from the three 18-month inspection intervals will be evaluated to determine if the NFPA 25 (2014 Edition) main drain test guidance can be applied to the number of main drain tests performed (.i.e., Section 13.2.5, "A main drain test shall be conducted annually for each water supply lead-in to a building water-based fire protection system to determine whether there has been a change in the condition of the water supply" and Section 13.2.5.1 "Where the lead-in to a building supplies a header or manifold serving multiple systems, a single main drain test shall be performed.")

Any flow blockage or abnormal discharge identified during flow testing or any change in delta pressure during the main drain testing greater than 10% at a specific location is entered into the CAP.

Flow or main drain testing increases risk due to the potential for water contacting critical equipment in the area, and main drain testing in the RCAs increases the amount of liquid radwaste. Therefore, SQN will not perform main drain tests on every standpipe with an automatic water supply or on every system riser. [3.0.3-1, Request 4a, ML13357A722, E 15 of 43, 12/16/13]

P. Revise FWSP procedures to perform One of the following inspection methods for those sections of dry piping described in NRC Information Notice (IN) 2013-06, where drainage is not occurring, to ensure there is no flow blockage in each five-year interval beginning with the five-year period before the PEO:

(a) Perform a flow test or flush sufficient to detect potential flow blockage.

(b) Remove sprinkler heads or couplings in the areas that do not drain and perform a 100% visual internal inspection to verify there are no signs of abnormal corrosion (wall thickness loss) or blockage.

(c) Perform a 100% UT examination of the area that does not drain to identify blockage. (9.P.c is deleted in 3.0.3-1-3 Request 4c, cnl-14-094)

If option (a) is chosen, controls will be established to ensure potential blockage is not moved to another part of the system where it may be undetected.

E 10 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (9) In each five-year interval during the PEO, 20% of the length of piping segments that cannot be drained or piping segments that allow water to collect will be subjected to UT wall thickness examination. The piping examined during each inspection interval will be piping that was not previously examined. [9.P is added in 01/16/14 CNL-14-010, 3.0.3-1, Request 4b]

If the results of a 100% internal visual inspection are acceptable, and the segment is not subsequently wetted, no further augmented tests or inspections will be performed. (3.0.3-1-3 Request 4c, cnl-14-094) 10 A. Revise Flow Accelerated Corrosion (FAC) Program procedures SQN1: Prior to 03/17/20 B.1.14 to implement NSAC-202L guidance for examination of components SQN2: Prior to 03/15/21 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-1011231, Recommendations for Controlling Cavitation, Flashing, Liquid Droplet Impingement, and Solid Particle Erosion in Nuclear Power Plant Piping, and NUREG/CR-6031, Cavitation Guide for Control Valves. [B.1.14-1 and B.1.38-1]

11 Revise Flux Thimble Tube Inspection Program procedures to SQN1: Prior to 03/17/20 B.1.15 include a requirement to address if the predictive trending projects SQN2: Prior to 03/15/21 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).

E 11 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 12 A. Revise Inservice Inspection-IWF Program procedures to clarify SQN1: Prior to 03/17/20 B.1.17 that detection of aging effects will include monitoring anchor bolts for SQN2: Prior to 03/15/21 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 an indication is identified on a component support exceeding the acceptance criteria of IWF-3400, but an evaluation concludes the support is acceptable for service, the program shall require examination of additional similar/adjacent supports per IWF-2430 unless the evaluation of the identified condition against similar/adjacent supports concludes that it would not adversely affect the design function of similar adjacent supports. This evaluation will be performed regardless of whether the program owner chooses to perform corrective measures to restore the component to its original design condition, per IWF-3112.3(b) or IWF-3122.3(b). [ML13190A276. E1-37of79, 7/1/13]

13 Inspection of Overhead Heavy Load and Light Load (Related to SQN1: Prior to 03/17/20 B.1.18 Refueling) Handling Systems: SQN2: Prior to 03/15/21 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 A. Implement the Internal Surfaces in Miscellaneous Piping and SQN1: Prior to 03/17/20 B.1.19 Ducting Components Program as described in LRA Section B.1.19. SQN2: Prior to 03/15/21 B. Specific, measurable, actionable/attainable and relevant acceptance criteria are established in the maintenance and surveillance procedures or are established during engineering evaluation of the degraded condition. [ML13357A722, E 43 of 43, 12/16/13]

E 12 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 15 Implement the Metal Enclosed Bus Inspection Program as SQN1: Prior to 03/17/20 B.1.21 described in LRA Section B.1.21. SQN2: Prior to 03/15/21 16 A. Revise Neutron Absorbing Material Monitoring Program SQN1: Prior to 03/17/20 B.1.22 procedures to perform blackness testing of the Boral coupons within SQN2: Prior to 03/15/21 the ten years prior to the PEO and at least every ten years thereafter based on initial testing to determine possible changes in boron-10 areal density.

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

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

17 Implement the Non-EQ Cable Connections Program as described SQN1: Prior to 03/17/20 B.1.24 in LRA Section B.1.24 SQN2: Prior to 03/15/21 18 Implement the Non-EQ Inaccessible Power Cable (400 V to 35 kV) SQN1: Prior to 03/17/20 B.1.25 Program as described in LRA Section B.1.25 SQN2: Prior to 03/15/21 A. B.1.25.1a [ML13296A017, E-1-12of25, 10/21/13]

1. Repair the manhole sump pump and discharge piping 18.A.1: Sept 2015 deficiencies associated with the accumulation of water in seven manholes/hand holes that are scheduled for correction and/or 18.A2 & 4: Sept 2014 mitigation by September 2015. (HH3/2B, HH52B, HH54A2, HH55A2, MH7B, MH10A and MH32B as identified on October 1, 18.A.3:

2013) [CNL-14-021]

SQN1: Prior to 03/17/20

2. Grade the ground surface around Manhole 31 to direct runoff SQN2: Prior to 03/15/21 away from the manhole. The re-grading is scheduled for completion by September 2014.

3. Prior to the PEO, the license renewal commitment for the Non-EQ Inaccessible Power Cables (400 V to 35 kV) Program will establish diagnostic testing activities on all inaccessible power cables in the 400 V to 35kV range that are in the scope of license renewal and subject to aging management review.

4. Revise the manhole inspection procedures to specify the maximum allowable water level to preclude cable submergence in the manhole. If the inspection identifies submergence of inaccessible power cable for more than a few days, the condition will be documented and evaluated in the SQN CAP. The evaluation will consider results of the most recent diagnostic testing, insulation type, submergence level, voltage level, energization cycle (usage), and various other inputs to determine whether the cables remain capable of performing their intended current licensing basis function.

5. Once 18.A.1 to 4 are fully completed, Commitments 18.A.1 to 4 can be deleted from this list or the UFSAR.

E 13 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 19 Implement the Non-EQ Instrumentation Circuits Test Review SQN1: Prior to 03/17/20 B.1.26 Program as described in LRA Section B.1.26. SQN2: Prior to 03/15/21 20 Implement the Non-EQ Insulated Cables and Connections SQN1: Prior to 03/17/20 B.1.27 Program as described in LRA Section B.1.27 SQN2: Prior to 03/15/21 21 A. Revise Oil Analysis Program procedures to monitor and SQN1: Prior to 03/17/20 B.1.28 maintain contaminants in the 161-kV oil filled cable system within SQN2: Prior to 03/15/21 acceptable limits through periodic sampling in accordance with industry standards, manufacturer's recommendations and plant-specific operating experience.

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

22 Implement the One-Time Inspection Program as described in LRA SQN1: Prior to 03/17/20 B.1.29 Section B.1.29. SQN2: Prior to 03/15/21 23 Implement the One-Time Inspection - Small Bore Piping Program SQN1: Prior to 03/17/20 B.1.30 as described in LRA Section B.1.30 SQN2: Prior to 03/15/21 24 A. Revise Periodic Surveillance and Preventive Maintenance 24.A&C B.1.31 Program procedures as necessary to include all activities described SQN1: Prior to 03/17/20 in the table provided in the LRA Section B.1.31 program description. SQN2: Prior to 03/15/21 B. For in-scope components that have internal Service Level III or 24.B Other coatings, initial inspections will begin no later than the last SQN1: RFO Prior to scheduled refueling outage prior to the PEO. Subsequent inspections 09/17/20 will be performed based on the initial inspection results. [3.0.3-1, Request 3, ML13312A005, pages E 2,5,7 of 51] SQN2: RFO Prior to 09/15/21 C. Perform a minimum of five MIC degradation inspections per year until the rate of MIC occurrences no longer meets the criteria for recurring internal corrosion.

If more than one MIC-caused leak or a wall thickness less than Tmin is identified in the yearly inspection period, an additional five MIC inspections over the following 12 month period will be performed for each MIC leak or finding of wall thickness less than Tmin. The total number of inspections need not exceed a total of 25 MIC inspections per year. [01/16/14 CNL-14-010, 3.0.3-1-3a]

Prior to the period of extended operation, select a method (or methods) from available technologies for inspecting internal surfaces of buried piping (System 26/HPFP Firewater and 67/ERCW) that provides suitable indication of piping wall thickness for a representative set of buried piping locations to supplement the set of selected inspection locations

[3.0.3-1, Request 1a, ML13357A722, E 4 of 43, 12/16/13]

[3.0.3-1 Req 1, ML13294A462, E 6 of 13, 10/17/13; moved from 9.F to 24.C in 01/16/14 CNL-14-010, 3.0.3-1, Request 4b]

E 14 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (24) D.

1. Prior to the PEO, perform a visual inspection of a 50%

sample of the coated piping in each of the following coated piping systems or an area equivalent to the entire inside surface of 73 1-foot piping segments for each combination of type of coating, substrate material, and environment. Inspection location selection will be based on an evaluation of the effect of a coating failure on component intended functions, potential problems identified during prior inspections, and service life history. Visually inspect the surface condition of the coated components to manage loss of coating integrity due to cracking, debonding, delamination, peeling, flaking, and blistering. In addition, if coatings are credited for corrosion prevention, the base material (in the vicinity of delamination, peeling, or blisters where base metal has been exposed) will be inspected to determine if corrosion has occurred.

Piping:

i. High pressure fire protection (cement-lined piping) ii. Essential raw cooling water (where Belzona applied)

2. With the exception of the EDG 7-day fuel oil tanks, perform subsequent inspections of coatings based on the following.

i. If no flaking, debonding, peeling, delamination, blisters, or rusting are observed, and any cracking and flaking has been found acceptable, subsequent inspections will be performed at least once every six years. If the coating is inspected on one train and no indications are found, the same coating on the redundant train would not be inspected during that inspection interval.

ii. If the inspection results do not meet (i), yet a coating specialist has determined that no remediation is required, then subsequent inspections will be conducted every other refueling outage.

iii. If coating degradation is observed that requires newly installed coatings, subsequent inspections will occur during each of the next two refueling outage intervals to establish a performance trend on the coating.

EDG 7-day fuel oil tanks coating inspection:

Subsequent coating inspections for the EDG 7-day fuel oil tanks will be at the same 10 year interval as TS Surveillance Requirement 4.8.1.1.2.f. If any applied Belzona coating on the interior of the fuel oil tanks is peeling, delaminating, or blistering, then the condition will be repaired and entered into the CAP. Given the favorable SQN experience with the current Belzona repairs, it is justifiable to repair the existing coating applied to localized pits with Belzona and not inspect the coating for another 10 years, provided a detached Belzona engineering transportability evaluation has determined that the amount of Belzona applied will not migrate from the EDG 7-day tank to the day-tank. The evaluation will consider Belzonas 2.5 to 3 times higher specific gravity than diesel fuel, potential size of loosened Belzona particles, surface area and depth of the applied Belzona, diesel fuel fluid velocity in the immediate area of the applied E 15 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (24) Belzona, proximity of the repaired area to the suction line, and other factors.

The application of Belzona to repair additional localized pitting in the 7-day EDG fuel oil tanks in the future will be installed per vendor specifications. An engineering evaluation will be performed to ensure that that additional Belzona cannot be transferable out of the tank during the interval between tank inspections and to determine if the interval of inspections should meet the more frequent inspection guidelines of LR-ISG-2013-01, or the NRC approved TS Surveillance Requirement of 10 years. The engineering transportability evaluation will consider factors such as specific gravity, size, depth, surface area, and fluid velocity in the evaluation. [01/16/14 CNL-14-010, 3.0.3-1-3a]

E. Prior to the PEO, perform a visual inspection of the following coated tanks and heat exchangers. Visually inspect the surface condition of the coated components to manage loss of coating integrity due to cracking, debonding, delamination, peeling, flaking, and blistering.

Tanks

i. Cask decontamination collector (where 2 coats Red Lead in oil ,

Fed SPEC TTP-85 Type II applied) ii. Safety injection lube oil reservoir (where 0.006 inch plastic coating applied) iii. Pressurizer relief (where Ambercoat 55 applied) iv. EDG 7-day fuel oil (where Belzona applied)

v. Condensate storage tank Heat Exchangers

i. Electric board room chiller package (where Belzona applied) ii. Incore instrument room water chiller package B (where Belzona applied) [01/16/14 CNL-14-010, 3.0.3-1-3a]

F. Any indication or relevant condition of degradation detected is evaluated.

Include the following acceptance criteria for loss of coatings integrity: For any indication or relevant condition of coating degradation, the indication or relevant condition is evaluated for loss of coatings integrity. [CNL-14-021]

(1) Peeling and delamination are not permitted, (2) Cracking is not permitted if accompanied by delamination or loss of adhesion, and (3) Blisters are limited to intact blisters that are completely surrounded by sound coating bonded to the surface.

Corrective Action: If delamination, peeling, or blisters are detected, follow-up physical testing will be performed where physically possible (i.e., sufficient room to conduct testing) on at least three locations. The testing will consist of destructive or E 16 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (24) nondestructive adhesion testing using ASTM International standards endorsed in Regulatory Guide 1.54. [01/16/14 CNL-14-010, 3.0.3-1-3a]

G.

1. Coating inspections are performed by individuals certified to ANSI N45.2.6, "Qualifications of Inspection, Examination, and Testing Personnel for Nuclear Power Plants," and that subsequent evaluation of inspection findings is conducted by a nuclear coatings subject matter expert qualified in accordance with ASTM D 7108-05, "Standard Guide for Establishing Qualifications for a Nuclear Coatings Specialist."

2. An individual knowledgeable and experienced in nuclear coatings work will prepare a coating report that includes a list of locations identified with coating deterioration including, where possible, photographs indexed to inspection location, and a prioritization of the repair areas into areas that must be repaired before returning the system to service and areas where coating repair can be postponed to the next inspection. [01/16/14 CNL-14-010, 3.0.3-1-3a]

25 A. Revise Protective Coating Program procedures to clarify that SQN1: Prior to 03/17/20 B.1.32 detection of aging effects will include inspection of coatings near SQN2: Prior to 03/15/21 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 03/17/20 B.1.33 ensure that replacement studs are fabricated from bolting material SQN2: Prior to 03/15/21 with actual measured yield strength less than 150 ksi.

B. Revise Reactor Head Closure Studs Program procedures to exclude the use of molybdenum disulfide (MoS2) on the reactor vessel closure studs and to refer to Reg. Guide 1.65, Rev1.

E 17 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 27 A. Revise Reactor Vessel Internals Program procedures to 27.A & B B.1.34 perform direct measurement of Unit 1 304 SS hold down spring SQN1: Within three U1 height within three cycles of the beginning of the period of extended refuel cycles of the date operation. If the first set of measurements is not sufficient to 09/17/20 determine life, spring height measurements must be taken during the next two outages, in order to extrapolate the expected spring height SQN2: Not Applicable to 60 years. (11/15/13, Enclosure 1, pages 24-25)

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

C. Continued monitoring of industry operating experience in the area 27.C SQN 1&2: Within of RVI Clervis Bolt will be performed and the program will be three U1 refuel cycles of modified, if necessary. [01/16/14 CNL-14-010, E-2-5of6, B.1.34-8] the date 09/17/20 D. MRP-227-A serves as the basis for the SQN Reactor Vessel 27.D SQN 1&2 10/31/14 Internals aging management program. TVA plans to provide a response to RAI B.1.34-9, (MRP-227-A) as part of a PWR Owners Group task by October 31, 2014. TVA will keep the NRC staff informed of any potential schedule improvements or delays during the completion of these tasks. The TVA response will be consistent with the guidance provided in MRP 2013-025.

Once 27.D is fully completed, Commitments 27.D can be deleted from this list or the UFSAR. [ML13296A017, E-1-10 of 25, 10/21/13]

[01/16/14 CNL-14-010, B.1.34-9] [CNL-14-021]

28 A. Revise Reactor Vessel Surveillance Program procedures to SQN1: Prior to 03/17/20 B.1.35 consider the area outside the beltline such as nozzles, penetrations SQN2: Prior to 03/15/21 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 01/10/13, ML13032A251; NRC FSER approved on 09/27/13, ML13240A320)

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 PEO.

29 Implement the Selective Leaching Program as described in LRA SQN1: Prior to 03/17/20 B.1.37 Section B.1.37. SQN2: Prior to 03/15/21 E 18 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 30 Revise Steam Generator Integrity Program procedures to ensure SQN1: Prior to 03/17/20 B.1.39 that corrosion resistant materials are used for replacement steam SQN2: Prior to 03/15/21 generator tube plugs.

31 A. Revise Structures Monitoring Program (SMP) procedures to SQN1: Prior to 03/17/20 B.1.40 include the following in-scope structures: SQN2: Prior to 03/15/21 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 SMP 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 SMP procedures to include the following in-scope structural components and commodities:

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

Beams, columns and base plates (steel)

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

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

Building concrete at locations of expansion and grouted anchors; grout pads for support base plates Cable tray Cable tunnel Canal gate bulkhead Compressible joints and seals Concrete cover for the rock walls of approach channel Concrete shield blocks Conduit Control rod drive missile shield E 19 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (31) 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 equipment and instrumentation Riprap Rock embankment Roof or floor decking E 20 of 30

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

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 SMP 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 M asonry Wall Program p rocedures to specify ma sonry walls located in the foll owing in-scope structures are in the scope of the Masonry Wall Program:

Auxiliary building Reactor building Units 1 & 2 Control bay ERCW pumping station HPFP pump house Turbine building F. Revise SMP 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 E 21 of 30

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

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

G. Revise SMP 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).

[moved to the last bullet on 31.F ]

H. Revise SMP procedures to include the following for detection of aging effects:

Inspection of structural bolting for loose or missing nuts.

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

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

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

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

Inspection of submerged structures at least once every five years.

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

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

Perform special inspections of water control structures immediately (within 30 days) following the occurrence of significant natural phenomena, such as large floods, E 22 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (31) earthquakes, hurricanes, tornadoes, and intense local rainfalls.

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

Revise SMP 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.

I. Revise SMP procedures to prescribe quantitative acceptance criteria 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. [moved to the last bullet on 31.H ]

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

No moisture or surface irregularities that indicate exposure to moisture.

L. Revise SMP procedures to include the following preventive actions.

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

Storage of these fastener components shall include:

1. Maintaining fastener components in closed containers to protect from dirt and corrosion;

2. Storage of the closed containers in a protected shelter;

3. Removal of fastener components from protected storage only as necessary; and

4. Prompt return of any unused fastener components to protected storage.

M. RAI B.1.40-4a Response (Turbine Building wall crack):

1. SQN will map and trend the crack in the condenser pit north wall.

2. SQN will test water inleakage samples from the turbine building condenser pit walls and floor slab for minerals and iron content to assess the effect of the water inleakage on the concrete and the reinforcing steel.

3. SQN will test concrete core samples removed from the turbine building condenser pit north wall with a minimum of one core sample in the area of the crack. The core samples will be tested for compressive strength and modulus of elasticity and subjected to petrographic examination.

E 23 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (31) 4. The results of the tests and SMP inspections will be used to determine further corrective actions, including, but not limited to, more frequent inspections, sampling and analysis of the inleakage water for minerals and iron, and evaluation of the affected area using evaluation criteria and acceptance criteria of ACI 349.3R.

[Outcome of the Nrc 01/14/14 telecom]

5. Commitment #31.M will be implemented before the PEO for SQN Units 1 and 2. . [ML13296A017, E-1-10of25, 10/21/13, for 31.M.1 to 5]

32 Implement the Thermal Aging Embrittlement of Cast Austenitic 32.A B.1.41 Stainless Steel (CASS) as described in LRA Section B.1.41 SQN1: Prior to 03/17/20 SQN2: Prior to 03/15/21 A. B.1.41-4a: For those CASS components with delta ferrite content

> 25%, additional analysis will be performed using plant-specific materials data and best available fracture toughness curves.

(B.1.41-4a, ML13225A387, E 19 of 25)

B. B.1.41-4b: For CASS materials with estimated delta ferrite > 20% 32.B that have been determined susceptible to thermal aging, a flaw SQN1: Prior to 09/17/18 tolerance analysis may be necessary. If a flaw tolerance analysis will SQN2: Prior to 09/15/19 be required for the susceptible CASS components, the SQN-specific flaw tolerance method will be submitted to the NRC for review and approval at least two years prior to the PEO; unless ASME has approved the flaw tolerance analysis methodology that SQN will use.

(SQN1: Prior to 09/17/18 SQN2: Prior to 09/15/19)

[ML13357A722, E 1 of 43, 12/16/13]

33 A. Revise Water Chemistry Control - Closed Treated Water SQN1: Prior to 03/17/20 B.1.42 Systems Program procedures to provide a corrosion inhibitor for the SQN2: Prior to 03/15/21 following chilled water subsystems in accordance with industry guidelines and vendor recommendations:

Auxiliary building cooling Incore Chiller 1A, 1B, 2A, & 2B 6.9 kV Shutdown Board Room A & B B. Revise Water Chemistry Control - Closed Treated Water Systems Program procedures to conduct inspections whenever a boundary is opened for the following systems:

Standby diesel generator jacket water subsystem Component cooling system Glycol cooling loop system High pressure fire protection diesel jacket water system Chilled water portion of miscellaneous HVAC systems (i.e.,

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

C. Revise Water Chemistry Control-Closed Treated Water Systems Program procedures to state these inspections will be conducted in accordance with applicable ASME Code requirements, industry E 24 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM (33) 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 03/17/20 B.1.7 venting the SCV bottom liner plate weld leak test channels to the SQN2: Prior to 03/15/21 containment atmosphere prior to the CILRT and resealing the vent path after the CILRT to prevent moisture intrusion during plant operation.

E 25 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 35 A. From RAI B.1.6-1 Response: Modify the configuration of the SQN 35.A: B.1.6 Unit 1 test connection access boxes to prevent moisture intrusion to SQN1: Prior to 03/17/20 the leak test channels. Prior to installing this modification, TVA will SQN2: Not Applicable perform remote visual examinations inside the leak test channels by inserting a borescope video probe through the test connection tubing.

B. From B.1.6-1b Response: To monitor the condition of the access 35. B & C:

boxes and associated materials, develop and implement an SQN1: Prior to 03/17/20 instruction/procedure to perform visual examinations of all accessible SQN2: Prior to 03/15/21 surfaces, including the access box surfaces, cover plate, welds, and gasket sealing surfaces of the access boxes on each unit every other refueling outage with the gasketed access box lid removed.

C. From B.1.6-2b Response: develop and implement an instruction/procedure to continue volumetric examinations where the SCV domes were cut at the frequency of once every five years until the coatings are reinstalled at these locations.

E 26 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 36 A. Revise Inservice Inspection Program procedures to include a SQN1: Prior to 03/17/20 B.1.16 supplemental inspection of Class 1 CASS piping components that SQN2: Prior to 03/15/21 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. (RAI 3.1.2.2.6.2-1)

B. Revise the Inservice Inspection Program procedures to perform an augmented visual inspection of the Unit 1 and Unit 2 CRDM thermal sleeves and a wall thickness measurement of the six thermal sleeves exhibiting the greatest amount of wear. The results of the augmented inspection should be used to project if there is sufficient wall thickness for the PEO, or until the next inspection. (RAI B.1.23-2d)

C. Evaluate industry operating experience related to CRDM housing penetration wear and initiatives to measure CRDM housing penetration wear and resulting wall thickness. Upon successful demonstration of a wear depth measurement process, SQN will use the demonstrated process at accessible locations to measure depth of wear on the CRDM housing penetration wall associated with contact with the CRDM thermal sleeve centering pads. (RAI B.1.23-2c)

D. Revise Inservice Inspection Program procedure to perform an examination of the accessible CRDM housing penetrations to determine the amount of wear in the area of the thermal sleeve centering pads for Units 1 and 2. The accessible locations consist of the centermost CRDM housing penetrations 1 through 5. (RAI B.1.23-2c)

E. Revise Inservice Inspection Program procedure to estimate the CRDM housing penetration wear at the end of the next RVH inspection interval and compare the projected wall thickness to the thickness used in Sequoyah design basis analyses to demonstrate validity of the analyses. (RAI B.1.23-2c)

F. Revise Inservice Inspection Program procedure to monitor the wear of the accessible CRDM housing penetrations in weld examination volume. (RAI B.1.23-2c)

G. TVA ASME Section XI Program procedure which defines the Class 1 components subject to examination will be revised to specifically require a visual examination method VT-3 of the clevis bolts, dowel pins and tack welds as well as the six core support pads.

[CNL-14-021, E-1-5 of 7, B.1.34-8a]

E 27 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 37 TVA will implement the Operating Experience for the AMPs in 37.A, B, D-G: No later B.0.4 accordance with the TVA response to the RAI B.0.4-1 on than the scheduled issue 07/29/13, ML13213A027; and 10/17/13 letter, RAIs B.0.4-1a and date of the renewed A.1-1a. operating licenses for SQN Units 1 & 2.

A. Revise OE Program Procedure to include current and future (Currently February revisions to NUREG-1801, Generic Aging Lessons Learned 2015)

(GALL) Report, as a source of industry OE, and unanticipated age-related degradation or impacts to aging management activities as a screening attribute.

B. Revise the Corrective Action Procedure (CAP) Procedure to provide a screening process of corrective action documents for aging management items, the assignment of aging corrective actions to appropriate AMP owners, and consideration of the aging management trend code.

C. Revise AMP procedures as needed to provide for review and 37.C:

evaluation by AMP owners of data from inspections, tests, SQN1: Prior to 03/17/20 analyses or AMP OEs. SQN2: Prior to 03/15/21 D. Revise the OE Program Procedure to provide guidance for [CNL-14-021]

reporting plant-specific OE on unanticipated age-related degradation or impact to aging management activities to the TVA fleet and/or INPO.

E. Revise the OE, CAP, Initial and Continuing Engineering Support Personnel Training to address age-related topics, the unanticipated degradation or impacts to the aging management activities; including periodic refresher/update training and provisions to accommodate the turnover of plant personnel, and recent AMP-related OE from INPO, the NRC, Scientech, and nuclear industry-initiated guidance documents and standards.

F. A comprehensive and holistic AMP training topic list will be developed before the date the SQN renewed operating license is scheduled to be issued.

G. TVA AMP OE Process, AMP adverse trending & evaluation in CAP, AMP Initial and Refresher Training will be fully implemented by the date the SQN renewed operating license is scheduled to be issued.

Once Commitment 37 is fully completed, Commitment 37 can be deleted from this list or the UFSAR.

E 28 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 38 A. Implement the Service Water Integrity Program (SWIP) as SQN1: Prior to 03/17/20 B.1.38 described in LRA Section B.1.38. [3.0.3-1, Requests 3, SQN2: Prior to 03/15/21 ML13312A005.E 11 of 51, 11/4/13, for 38.A to F]

B. Parameters Monitored/Inspected: Revise SWIP procedures to monitor the condition of coated surfaces in the heat exchangers credited in the response to NRC Generic Letter (GL) 89-13 response.

C. Detection of aging Effect : Revise the SWIP procedures to perform periodic visual inspections to manage loss of coating integrity due to cracking, debonding, delamination, peeling, flaking, and blistering in heat exchangers credited in the NRC Generic Letter (GL) 89-13 response.

D. Acceptance Criteria: Revise the SWIP procedures to include the following coating integrity acceptance criteria:

(1) peeling and delamination are not permitted, (2) cracking is not permitted if accompanied by delamination or loss of adhesion, and (3) blisters are limited to intact blisters that are completely surrounded by sound coating bonded to the surface.

E. Monitoring and Trending: Revise SWIP procedures to ensure an individual knowledgeable and experienced in nuclear coatings work will prepare a coating report that includes a list of locations identified with coating deterioration including, where possible, photographs indexed to inspection location, and a prioritization of the repair areas into areas that must be repaired before returning the system to service and areas where coating repair can be postponed to the next inspection.

F. Qualification: Revise SWIP procedures to ensure coating inspections are performed by individuals certified to ANSI N45.2.6, "Qualifications of Inspection, Examination, and Testing Personnel for Nuclear Power Plants," and that subsequent evaluation of inspection findings is conducted by a nuclear coatings subject matter expert qualified in accordance with ASTM D 7108-05, "Standard Guide for Establishing Qualifications for a Nuclear Coatings Specialist."

39 Implement the Boric Acid Corrosion Program as described in LRA SQN1: Prior to 03/17/20 B.1.3 Section B.1.3. SQN2: Prior to 03/15/21 40 Implement the Environmental Qualification (EQ) Of Electric SQN1: Prior to 03/17/20 B.1.9 Components Program as described in LRA Section B.1.9. SQN2: Prior to 03/15/21 41 Implement the Masonry Wall Program as described in LRA Section SQN1: Prior to 03/17/20 B.1.20 B.1.20. SQN2: Prior to 03/15/21 42 Implement the Nickel Alloy Inspection Program as described in SQN1: Prior to 03/17/20 B.1.23 LRA Section B.1.23. SQN2: Prior to 03/15/21 E 29 of 30

LRA IMPLEMENTATION SECTION No. COMMITMENT SCHEDULE / AUDIT ITEM 43 Implement the Water Chemistry Control - Primary And Secondary SQN1: Prior to 03/17/20 B.1.43 Program as described in LRA Section B.1.43. SQN2: Prior to 03/15/21 44 Implement the RG 1.127, Inspection Of Water-Control Structures SQN1: Prior to 03/17/20 B.1.36 Associated With Nuclear Power Plants Program as described in SQN2: Prior to 03/15/21 LRA Section B.1.36.

The above table identifies the 44 SQN NRC LR commitments. Any other statements in this letter are provided for information purposes and are not considered to be regulatory commitments.

This commitment list revision supersedes all previous versions.

E 30 of 30