ML13189A197

Third Annual Update to License Renewal Application

ML13189A197
Person / Time
Site:	Seabrook
Issue date:	07/02/2013
From:	Walsh K T NextEra Energy Seabrook
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
SBK-L-13115
Download: ML13189A197 (28)

Text

NEXTera ENERGY, I July 2, 2013 SBK-L-13115 U.S. Nuclear Regulatory Commission Attention:

Document Control Desk One White Flint North 11555 Rockville Pike Rockville, MD 20852 Seabrook Station Third Annual Update to the NextEra Energy Seabrook License Renewal Application

References:

1. NextEra Energy Seabrook, LLC letter SBK-L-10077, "Seabrook Station Application for Renewed Operating License", May 25, 2010. (Accession Number ML101590099)

2. NextEra Energy Seabrook, LLC letter SBK-L-11773, "First Annual Update to the Seabrook License Renewal Application", August 25, 2011. (Accession Number ML 11241A 142)3. NextEra Energy Seabrook, LLC letter SBK-L-12186, "Second Annual Update to the Seabrook License Renewal Application", September 18, 2012. (Accession Number ML12268A171)

4. LR-ISG-2011-03:

Changes to the Generic Aging Lessons Learned (GALL) Report Revision 2 Aging Management Program XI.M41, "Buried and Underground Piping and Tanks", July, 2012. (Accession Number ML12138A295)

5. LR-ISG-LR-ISG-2012-01:

Wall Thinning Due To Erosion Mechanisms, April, 2013.(Accession Number ML 12352A058)

6. NextEra Energy Seabrook, LLC letter SBK-L-13084, "Revised Response to RAI B.2.1.3-5 and RAI 4.7.2-1 ", May 8, 2013. (Accession Number ML 13135A005)

7. NextEra Energy Seabrook, LLC letter SBK-L-12183, "Response to Request for Additional Information-Set 18 .Operating Experience", September 18, 2012. (Accession Number ML I 2268A 170)8. NextEra Energy Seabrook, LLC letter SBK-L-11015, "Response to Request for Additional Information, NextEra Energy Seabrook License Renewal Application, Sets 6, 7 and 8", February 3, 2011. (Accession Number ML 110380081)

9. NextEra Energy Seabrook, LLC letter SBK-L- 11069, "Response to Request for Additional Information, NextEra Energy Seabrook License Renewal Application, Request for Additional Information

-Set 12", April 22, 2011. (Accession Number ML 1111 5Al 16)NextEra Energy Seabrook, LLC.626 Lafayette Rd, Seabrook, NH 03874 United States Nuclear Regulatory Commission SBK-L-13115

/Page 2 10. NextEra Energy Seabrook, LLC letter SBK-L-11207, "Response to Request for Additional Information, NextEra Energy Seabrook License Renewal Application, Request for Additional Information

-Set 16", November 2, 2011. (Accession Number MLI 1308A025)In Reference 1, NextEra Energy Seabrook, LLC (NextEra) submitted an application for a renewed facility operating license for Seabrook Station Unit I in accordance with the Code of Federal Regulations, Title 10, Parts 50, 51, and 54.The License Renewal Rule, 10 CFR 54.21(b) requires that each year following submittal of a license renewal application (LRA), and at least 3 months before scheduled completion of the NRC review, an update to the license renewal application must be submitted that identifies any change to the current licensing basis (CLB) of the facility that materially affects the content of the LRA including the FSAR supplement.

In accordance with the License Renewal Rule, NextEra Energy Seabrook, LLC has performed a third annual review of CLB changes since the submittal of Reference 1, to determine whether any sections of the LRA were affected by these changes. A review has also been completed of plant specific and industry operating experience, including License Renewal applicable ISG's (References 4 and 5), for the same time period. The first and second annual review results are documented in References 2 and 3. Enclosure 1 contains results of the third annual review.In Reference 6, NexEra Energy Seabrook provided a revised response to RAI B.2.3.1-5 and removed the fracture mechanics evaluation as a corrective action alternative.

In Reference 7, NextEra provided additional information regarding the ongoing Operating Experience Review Program. In conjunction with References 6 and 7, additional details have been added to the LRA Appendix A, UFSAR Supplement.

These changes are contained in Enclosure 2.There are no revised and one new regulatory commitment contained in this letter. Commitment Number 72 has been added to enhance the Flow-Accelerated Corrosion Program (FAC) to include management of wall thinning caused by mechanisms other than FAC. An updated LRA Appendix A -Final Safety Report Supplement Table A.3, License Renewal Commitment List is contained in Enclosure 3.Provided in this Supplement are changes to the License Renewal Application (LRA). To facilitate understanding, the changes are explained, and where appropriate, portions of the LRA are repeated with the change highlighted by strikethroughs for deleted text and bolded italics for inserted text.If there are any questions or additional information is needed, please contact Mr. Richard R.Cliche, License Renewal Project Manager, at (603) 773-7003.If you have any questions regarding this correspondence, please contact Mr. Michael H. Ossing, Licensing Manager, at (603) 773-7512.

United States Nuclear Regulatory Commission SBK-L- 13115 / Page 3 I declare under penalty of perjury that the foregoing is true and correct.Executed on July 2, 2013 Sincerely, Kevin T. Walsh Site Vice President NextEra Energy Seabrook, LLC Enclosure 1- Third Annual Update to the Seabrook Station License Renewal Application Enclosure 2 -Changes to LRA Appendix A, UFSAR Supplement Enclosure 3 -LRA Appendix A -Final Safety Report Supplement Table A.3, License Renewal Commitment List Updated to Reflect Changes.cc: W.M. Dean, J. G. Lamb, P.C. Cataldo, R. A. Plasse Jr., L. M. James, NRC Region I Administrator NRC Project Manager, Project Directorate 1-2 NRC Senior Resident Inspector NRC Project Manager, License Renewal NRC Project Manager, License Renewal Director Homeland Security and Emergency Management New Hampshire Department of Safety Division of Homeland Security and Emergency Management Bureau of Emergency Management 33 Hazen Drive Concord, NH 03305 John Giarrusso, Jr., Nuclear Preparedness Manager The Commonwealth of Massachusetts Emergency Management Agency 400 Worcester Road Framingham, MA 01702-5399 Enclosure 1 to SBK-L-13115 Third Annual Update to the Seabrook Station License Renewal Application*

United States Nuclear Regulatory Commission Page 2 of 10 SBK-L-13115

/Enclosure 1 1. Flux Thimble Calibration Tube Layup An alternate flux thimble calibration tube layup configuration has been implemented during this 3rd annual review period. In lieu of capping the flux thimble calibration tube open end, a normally closed isolation valve may serve as a pressure boundary for the calibration tube path.In response to RAIs 3.1.1.60-01 and 3.1.1.60-02 (References 8, 9 and 10), NextEra described the movable incore detector lay-up configuration.

In these responses, NextEra stated that a pressure retaining cap is installed at the end of the flux thimble calibration tube or a replacement incore detector assembly is installed which replaces the calibration tube with a solid Inconel 600 rod extending beyond the high pressure instrument connection.

Based on the above discussion, Section 2.3 of the LRA is revised as follows. No changes are needed to Section 3.1 as the isolation valves installed at the end of the calibration tubes are already listed under component type "Valve Body" on Table 3.1.2-1, line items 4, 5, and 6 on page 3.1-64.1) In Section 2.3.1.1, on Page 2.3-5, the 3 and 41h paragraphs of the boundary description for PID-1-RC-20845 are revised as follows: The incore instrument guide tubes contain a flux thimble tube which runs from inside the reactor vessel to the seal table at the high pressure instrument connection.

A high pressure seal is utilized where the instrument cabling exits the guide tube. The flux thimble tube contains fixed incore detectors and core exit thermocouples.

The original incore detector assembly flux thimble tubes also contain a flux thimble calibration tube ("calibration tube") that was designed to provide a pathway for movable incore detectors.

These movable incore detectors are no longer utilized.

The movable flux detector drive system is in a laid-up condition and the calibration tube end is isolated by a normally closed valve or capped to form a RCS pressure boundary.

The scoping boundary extends beyond the incore instrument guide tube to include the high pressure instrument connection, the portion of the calibration tube that extends above the high pressure instrument connection and associated normally closed valve or cap.The replacement incore detector assembly thimble tubes (5 out of 58) are not isolated by a normally closed valve or capped as they have a solid Inconel 600 rod in place of the calibration tube. This design eliminates the need for the terminating pressure retaining cap and the RCS pressure boundary extends only to the high pressure seal. The portions of the new incore detector assemblies that are part of the RCS pressure boundary are Safety Class 1 and conform to ASME Section III, Class 1, requirements.

United States Nuclear Regulatory Commission Page 3 of 10 SBK-L- 13115 / Enclosure 1 2. LR-ISG-2011-03:

Changes to the Generic Aging Lessons Learned (GALL) Report Revision 2 Aging Management Program XI.M41, "Buried and Underground Piping and Tanks" LR-ISG-2011-03 recommends that applicants for license renewal revise the Buried Piping and Tanks aging management program to incorporate changes to NUREG-1801, Appendix B,Section XI.M41, Buried and Underground Piping and Tanks, as presented in the ISG.In accordance with LR-ISG-2012-01, the following changes have been made to the NextEra Seabrook License Renewal Application, in Section B.2.1.22, as submitted in Supplement 1 dated September 29, 2010 (SBK-L-10179), Enclosure I and as revised in responses to: a)RAI B.2.1.9-1 and RAI B.2.22-4 (SBK-L-10204, dated December 17, 2010), b) RAI B.2.122-2 (SBK-L-1 1003, dated January 13, 2011), and c) Follow up RAI B.2.1.22-1, RAI B.2.1.22-3, and RAI B.2.1.22-5 (SBK-L-1 1062, dated April 5, 2011),.1. On page 5 of 18, the 7 th and 8 th paragraphs of the "Program Description" are revised as follows: Hydrostatic testing may be performed in lieu of external visual inspections discussed above provided that at least 25% of the piping constructed from the material under consideration is hydrostatically tested in accordance with 19 CFR 195 subpaf "Tran.portation qf .us Liquids by Pipeline Pres sure Testing".

to 110 percent of the design pressure of any component within the boundary with test pressure being held for eight hours on an interval not to exceed 5 years.Internal inspection may also be performed in lieu of external visual inspections discussed above provided that at least 25% of the piping constructed from the material under consideration is internally inspected by a method capable of determining pipe wall thickness.

The inspection method must be capable of detecting both general and pitting corrosion and must be qualified by Seabrook Station and accepted by the NRC.Internal inspections are to be conducted at an interval not to exceed -5 10 years.2. On page 8 of 18, the following new paragraphs are added to the end of "Element 2 -Preventive Actions": Fire mains are installed in accordance with NFPA Standard 24 and do not require the preventive actions of this section. Fire Protection piping is monitored as described in Element 4, Detection of Aging Effects, either by periodic flow testing or by monitoring the activity of the jockey pump.Because some systems or portions of systems are not cathodically protected, Seabrook Station has performed a review of plant-specific operating experience and summarized the findings in this AMP under Element 10, Operating Experience.

3. On pages 9 of 18 and 10 of 18, the 5 th, 6 th, and 7 th paragraphs of "Element 3 -Parameters Monitored/Inspected" are revised as follows: To credit hydrostatic testing in lieu of visual inspection, at least 25% of the piping constructed from the material under consideration must be hydrostatically tested in United States Nuclear Regulatory Commission Page 4 of 10 SBK-L- 13115 / Enclosure 1 acc.r.dance with 49 CFR 195 subpa. E to 110 percent of the design pressure of any component within the boundary with test pressure being held for eight hours on an interval not to exceed 5 years. Such testing will identify boundary leakage in significantly larger portions of the respective piping system than excavation and visual inspection of coating integrity.

To credit internal inspection, at least 25% of the piping constructed from the material under consideration is internally inspected by a method capable of determining pipe wall thickness.

The inspection method must be capable of detecting both general and pitting corrosion and must be qualified by Seabrook Station and accepted by the NRC.Internal inspections are to be conducted at an interval not to exceed $ 10 years.Fire mains may be excluded from the visual inspections if subjected to a flow test as described in section 7.3 of NFPA 25, at a frequency of at least one test in each one year period, or the jockey pump operation (or equivalent paramete e.g., pump starts, run time) is monitored for unexplained changes in pump activity at an interval not to exceed once a month.4. On page 11 of 18, the 4th paragraph of "Element 4 -Detection of Aging Effects" is revised as follows: The number of inspections required during each 10 year interval is shown in the tables below. The number of inspections will be determined by the status of cathodic protection, coating, and adequacy of backfill materials.

Piping contIn. ng. di-l fuel (Auxiliary Boiler- fc oil) or glycl (Diesel Generator cooling water) is treated a.HAZMAT lines. The H4AZMAT 1 may quirc additional inspection criteria as showývn in the table.5. On page 11 of 18, sub- paragraphs (A) and (B) of "Element 4 -Detection of Aging Effects" are revised as follows: (A) Hydrostatic testing may be performed in lieu of the inspections described below.To credit hydrostatic testing, at least 25% of the piping constructed from the material under consideration must be hydrostatically tested in accordance with 49 C'FR 195 subpart E of Hazadous Liquids by Pipeline, Pressuir Testing" to 110 percent of the design pressure of any component within the boundary with test pressure being held for eight hours on an interval not to exceed- 5 years.-..(B) Internal inspection may be performed in lieu of the inspections described below.To credit internal inspection, at least 25% of the piping constructed from the material under consideration is internally inspected by a method capable of determining pipe wall thickness.

The inspection method must be capable of detecting both general and pitting corrosion and must be qualified by Seabrook United States Nuclear Regulatory Commission SBK-L-13115

/ Enclosure 1 Page 5 of 10 Station and accepted by the NRC. Internal inspections are to be conducted at an interval not to exceed 5-10 years.6. On page 12 of 18, the table "Buried Piping Inspection Locations" in "Element 4 -Detection of Aging Effects" is replaced with the following table: Buried Piping Inspection Locations ,Material Sau lCathodic$

'Protection

__atiego ry[Inspei jlO-Y4 Qin this Catego'l y'004 ~4-5t 4 +AL6XN N/A N/A 0 0 0 None Stainless N/A N/A 1 1 1 CO, DG Steel A Adequate Backfills 1 1 1 Polymeric N/A Inadequate Backfill 2'3 FP1 B 1% 2% 3%NTE 2 NTE 3 NTE 6 Installed, available and C 1 1 1 CBAIAFPSW effective 4 C_1_1___BA

__A, _P_,_S External corrosion 1% 1% 1%control not required NTE 2 NTE 2 NTE 2 Not practical, not Steelt installed, or installed E 5% 6% 7.5%but not meeting Cat C; NTE 7 NTE 10 NTE 12 non-corrosive soils AB , CBA, CO, DF, Not installed or DG, FW, FP'installed but not 10% 12% 15%meeting Cat C; NTE 15 NTE 20 NTE 25 corrosive soil6 I I GENERAL NOTES: 1. Each inspection will examine a minimum of 10 feet of pipe or the entire length of a run, whichever is less.2. The adequacy of backfill will be determined by the condition of coatings and base materials noted during inspections.

If damage to the coatings or base materials are determined to have been caused by the bacAfill, the backfill will be considered to be "inadequate" (for the purpose of this program).3. If all polymeric pipe in-scope is non-safety related, the inspection quantities may be reduced by half.4. Cathodic protection is available and effective if it" was installed or refurbished 5 years prior to the end of the inspection period of interest; and* has been operational (available) at least 85 percent of the time since 10 years prior to the PEO or since installation or refurbishment (exclusive of time off-line for testing), whichever is shorter; and" has met the acceptance criteria of Section 6 at least 80 percent of the time since 10 years prior United States Nuclear Regulatory Commission SBK-L-13 115 / Enclosure 1 Page 6 of 10 to the PEO or since installation or refurbishment, whichever is shorter.5. If cathodic protection does not meet Category C and backfill has been determined to be inadequate, buried steel piping will be inspected as Category F.6. Soil corrosivity is determined by soil analysis using a demonstrated methodology such as EPRI report 1021470, Table 8-1. A value greater than 10 using this method is considered corrosive.

The number of inspectionsfor non-cathodically protected steel piping in corrosive soil apply only to the inspections performed during the period of extended operation.

7. This line is not is use. It has been drained and flushed and is awaiting replacement per a design change. The inspection criteria for the replacement piping will be determined based on material selection, coating, cathodic protection, and quality of backfill.8. If Fire Protection piping is inspected by excavation in lieu of by alternative testing (e.g., flow test, jockey pump monitoring), and the extent of examinations is not based on the percentage of piping in the material group, the Not-to-Exceed (NTE) value will be increased by 1 inspection, if normally less than 10, or 2 inspections, if normally 10 or greater.7. On page 12 of 18, the table "Underground Piping Inspection Locations" in "Element 4-Detection of Aging Effects" is revised as follows: Underground Piping Inspection Locationsý Maiteria ype Steel GENERAL NOTES: 1. Each inspection will examine either the entire length of a run of pipe or a minimum of 10 feet.2. ASC and ASH systems are non-safety related.3. Cathodic protection and applied coatings do not factor into the inspection criteria for underground piping as these locations are exposed to an air indoor uncontrolled environment.

8. On page 13 of 18, the table "Inaccessible Submerged Piping Inspection Locations" in"Element 4 -Detection of Aging Effects" is revised as follows:

United States Nuclear Regulatory Commission Page 7 of 10 SBK-L- 13115 / Enclosure 1 Inaccessible Submerged Piping Inspection Locations If ~ Cathodically 1ýSýAppliedRE nIbpectibii P'er10-I;'-w: r,:, r;: O-M " Materal Type'., S 'stem.. ..F k YPtrd. ,-'7 Fi~ecf&td ,Codatings arero Steel SW 2 Ne Yes Yes 21 Copper alloy >15% N zincW Ne No No 2 GENERAL NOTES: 1. Each inspection will examine either the entire length of a run of pipe or a minimum of 10 feet.2. The Service Water vault located north of the cooling tower contains four 24" lines approximately 15' long. The valve pit located north of the cooling tower contains one 32" line less than 10' long.3. Drain valves on the spools in the Service Water vault and valve pit are constructed of aluminum bronze (categorized as "copper alloy >15% zinc") with aluminum bronze body to bonnet bolting. These components will be inspected for loss of material when the respective Service Water spool piping is inspected by this program.9. On page 13 of 18, the following new paragraphs are added to the end of "Element 4 -Detection of Aging Effects": Adverse indications observed during monitoring of cathodic protection systems or during inspections are entered into the plant corrective action program. Adverse indications that are the result of inspections will result in an expansion of sample size as described below. Examples of adverse indications resulting from inspections include leaks, material thickness less than minimum, coarse backfill within 6 inches of a coated pipe or tank with accompanying coating degradation, and general or local degradation of coatings so as to expose the base material.Adverse indications that fail to meet the acceptance criteria described in Element 6, Acceptance Criteria, will result in the repair or replacement of the affected component.

If adverse indications are detected, inspection sample sizes within the affected piping categories are doubled. If adverse indications are found in the expanded sample, an analysis is conducted to determine the extent of condition and extent of cause. The size of the follow-on inspections will be determined based on the extent of condition and extent of cause. The timing of the additional examinations should be based on the severity of the degradation identified and should be commensurate with the consequences of a leak or loss of function, but in all cases, the expanded sample inspections should be completed within the 10-year interval in which the original United States Nuclear Regulatory Commission SBK-L- 13115 / Enclosure I Page 8 of 10 adverse indication was identified.

Expansion of sample size may be limited by the extent of piping or tanks subject to the observed degradation mechanism.

If adverse conditions are extensive, inspections may be halted in a piping system, or portion of system that is planned for replacement.

If the initial doubling of the sample size has not been conducted, or the determination of extent of condition or extent of cause requires further inspections, these inspections should be conducted in locations with similar materials and environment.

10. On page 13 of 18, the last paragraph of "Element 5 -Monitoring and Trending" is revised as follows: If aging of fire mains is managed through monitoring jockey pump activity (or similar parameter), jockey pump activity (or- similar paramete e.g., pump starts, run time) will be trended at least once a month to identify changes in pump activity that may be the result of increased leakage from buried fire main piping.11. On page 13 of 18, the 1st paragraph of "Element 6 -Acceptance Criteria" is revised as follows: For coated piping, there should be either no evidence of coating degradation or the type and extent of coating degradation should be insignificant as evaluated by an individual possessing a NACE operatr. qualifieation or by an individual

th.r.vise meeting the qualifications to evaluate coatings as contained in 49 CFR 192 and 195Coating Inspector Program Level 2 or 3 inspector qualification, or an individual has attended the Electric Power Research Institute (EPRI) Comprehensive Coatings Course and completed the EPRI Buried Pipe Condition Assessment and Repair Training Computer Based Training Course.12. On page 13 of 18, the 41h paragraph of "Element 6 -Acceptance Criteria" is revised as follows

Criteria for- pipe to soil potential and cathodic proetection currfent as listed in SPOI 69-2007 are met or evaluated under- the cor.ective ac t. ion pgam. Criteria for soil-to-pipe potential when using a saturated copper/copper sulfate reference electrode is -850m V relative to a CSE, instant off. To prevent damage to the coating, the limiting critical potential should not be more negative than -1200 m V.13. On page 14 of 18, the last paragraph of "Element 6 -Acceptance Criteria" is revised as follows: For hydrostatic tests, if credited in lieu of visual inspections, the con;dition "withou leakage" as requreA b-y 19 CFR 195.302 may be met by demonstrating that thehest pressure, as adjusted for temper.ature, does not vay during the test.. the test acceptance criteria is no visible indications of leakage and no drop in pressure within the isolated portion of the piping that is not accounted for by a temperature change in the test media or quantified leakage across test boundary valves.

United States Nuclear Regulatory Commission Page 9 of 10 SBK-L- 13115 / Enclosure 1 14. On page 16 of 18, the following items are added to "Element 10 -Operating Experience" as recent industry operating experience:

4. NUREG-1801, Revision 2 -December 2010 Although Revision 2 of NUREG-1801 (GALL) was issued subsequent to the initial issue of this program, early versions of the revision were reviewed as industry operating experience and incorporated into the Seabrook Buried Piping Aging Management Program where appropriate.

On final issue of the GALL Revision 2, a gap analysis was performed to determine whether or not the Seabrook program required additional revision.5. LR-ISG-2011-03 In July of 2012, Interim Staff Guidance (ISG) LR-ISG-2011-03 was issued in its final form. The ISG made additional changes to GALL Revision 2 to incorporate industry experience that occurred during and subsequent to the preparation of GALL Revision 2. The ISG was used in preparation of a revised Seabrook Buried Piping Aging Management Program.3. LR-ISG-2012-01, "Wall Thinning Due to Erosion Mechanisms" LR-ISG-2012-01 recommends that applicants for license renewal revise the Flow Accelerated Corrosion aging management program to include management of wall thinning due to erosion by mechanisms other than FAC. The ISG also provides changes to NUREG-1801, Appendix B,Section XI.M17, Flow Accelerated Corrosion.

The following changes have been made to the NextEra Seabrook License Renewal Application in accordance with the guidance provided in LR-ISG-2012-01.

1. In Section A.2.1.8, on Page A-9, a new paragraph is added as follows: This program also manages wall thinning caused by mechanisms other than FAC in accordance with the guidance provided in LR-ISG-2012-01, "Wall Thinning Due to Erosion Mechanisms

" 2. In Section A.3, the following commitment is added to the License Renewal Commitment List: PROGRAM or COMMITMENT UFSAR SCHEDULE TOPIC LOCATION Flow-Accelerated Enhance the program to include Prior to entering the 72 Corrosion management of wall thinning caused by A.2.1.8 period of extended mechanisms other than FAC. operation 3. In Section B.2.1.8, Flow-Accelerated Corrosion, the following changes are made: follows: a. On page B-52, the following sentence is added to the end of the 1 st paragraph:

United States Nuclear Regulatory Commission Page 10 of 10 SBK-L- 13115 / Enclosure 1 With appropriate considerations, this program may also manage wall thinning caused by mechanisms other than FAC, in situations where periodic monitoring is used in lieu of eliminating the cause of various erosion mechanism(s).

b. On page B-52, the 51h paragraph is revised as follows: This aging management program monitors the aging effects of wall thinning due to flow accelerated ceffesion FAC and erosion on the intended function of piping and components by measuring wall thickness using destutive examination.-

and perffefing analý4ical evaluations.

c. On page B-52, the following paragraph is added following the 6 th paragraph:

For erosion mechanisms, the program includes the identification of susceptible locations based on the extent-of-condition reviews from corrective actions in response to plant-specific or industry operating experience.

Components in this category may be treated in a manner similar to other "susceptible-not-modeled" lines discussed in NSAC-202L-2.

d. On page B-53, the following paragraph is added following the 1 st paragraph:

For erosion mechanisms, the program includes trending of wall thickness measurements at susceptible locations to adjust the monitoring frequency and to predict the remaining service life of the component for scheduling repairs or replacements.

Inspection results are evaluated to determine if assumptions in the extent-of-condition review remain valid.e. On page B-53, the "NUREG-1801 Consistency" section is revised as follows: This program is consistent with NUREG 1801 XI.M17 as amended by LR-ISG-2012-01, "Wall Thinning Due to Erosion Mechanisms".

f. On page B-53, the "Enhancements" section is revised as follows: NeneThe following enhancement will be made prior to entering the period of extended operation.

1. The Seabrook Station Flow-Accelerated Corrosion Program will be enhanced to include management of wall thinning caused by mechanisms other than FA C.Program Elements Affected:

Element 1 (Scope of Program), Element 3 (Parameters Monitored or Inspected), Element 4 (Detection of Aging Effects), Element 5 (Monitoring and Trending), and Element 7 (Corrective Actions).

Enclosure 2 to SBK-L-13115 Changes to LRA Appendix A UFSAR Supplement United States Nuclear Regulatory Commission Page 2 of 3 SBK-L-13115

/ Enclosure 2 1. In Reference 6, NextEra Energy Seabrook revised its response to RAI B.2.3.1-5 and informed the NRC that NextEra Energy Seabrook will not be using fracture mechanics evaluation for performing fatigue assessments in the aging management program associated with the Metal Fatigue of Reactor Coolant Pressure Boundary Program. As part of its revised response, the second to last paragraph of Section A.2.4.2.3, on page A-28, has also been revised as follows: (2) If acceptable CUFs cannot be demonstrated for all the selected locations, then additional plant-specific locations will be evaluated.

For the additional plant-specific locations, if CUF, including environmental effects is greater than 1.0, then Corrective Actions will be initiated, in accordance with the Metal Fatigue of Reactor Coolant Pressure Boundary Program, B.2.3.1. Co..ective A-tions will include reanalyzing the affe.ted component inspection, r.ar ..or- replacement of the affected locations be fore ex.eeding a CUF of 1.0 or the effects-offaiueAwill be managed by an inspection proegram that has been r-eview.ed and approeved by th JRC (e.g., periodic non destruetive examination of the affected locations at inspection inter,'als to be determnined by a mnethod accepted by the NRC).2. In Reference 7, NextEra Energy Seabrook made changes to the LRA which describe corrective action and operating experience program activities.

The LRA Appendix A, Section A. 1.6 has been further revised as follows: A. 1.6 Operating Experience The existing Corrective Action Program and the Operating Experience Program ensure, through the continual review of both plant-specific and industry operating experience, that the license renewal aging management programs are effective to manage the aging effects for which they are credited.

The programs are either enhanced or new programs are developed when the review of operating experience indicates that the programs may not be effective.

For each aging management program operating experience is reviewed on a continuing basis.Plant personnel responsible for screening, assigning, evaluating and submitting operating experience are trained to identify and evaluate aging related issues. Evaluation of aging related issues considers potentially affected plant systems, structures, components, materials, environments, aging effects, aging mechanisms and Aging Management Programs.Aging related program changes, results of inspection activities and evaluation of relevant internal and external operating experience are tracked by the NextEra action tracking/corrective action program.The operating experience reviews will include evaluation of applicable NUREGS, ISGs, etc., such as future revisions of NUREG-1801, "Generic Aging Lessons Learned (GALL)" Report. Programmatic features such as training of personnel, trending, record retention, self-United States Nuclear Regulatory Commission Page 3 of 3 SBK-L- 13115 / Enclosure 2 assessments, etc., will be in accordance with the existing NextEra corrective action and operating experience programs.

The Corrective Action Program is part of the Quality Assurance Program, which meets the requirements of 10 CFR Part 50, Appendix B. The Operating Experience Program meets the criteria of NUREG-0737, "Clarification of TMI Action Plan Requirements," Item LC.5, "Procedures for Feedback of Operating Experience to Plant Staff," and interfaces with and relies on active participation in the Institute of Nuclear Power Operations' operating experience program. Training of plant personnel will be periodic and will account for personnel turnover.

Operating experience concerning aging related degradation will be reported to the industry.

Any enhancements necessary to fulfill the above criteria will be put in place no later than the date the renewed operating license is issued and implemented on an ongoing basis throughout the term of the renewed license.

Enclosure 3 to SBK-L-12258 LRA Appendix A -Final Safety Report Supplement Table A.3, License Renewal Commitment List Updated to Reflect Changes to Date United States Nuclear Regulatory Commission SBK-L- 13115 / Enclosure 3 A.3 LICENSE RENEWAL COMMITMENT LIST.Page 2 of 13 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Program to be implemented prior to the period of extended operation.

Inspection plan to be submitted to An inspection plan for Reactor Vessel Internals will be NRC not later than 2 years after submitted for NRC review and approval.

receipt of the renewed license or not less than 24 months prior to the period of extended operation, whichever comes first.Closed-Cycle Cooling Enhance the program to include visual inspection for cracking, Prior to the period of extended 2. Water loss of material and fouling when the in-scope systems are A.2.1.12 operation opened for maintenance.

Inspection of Overhead Enhance the program to monitor general corrosion on the Heavy Load and Light Load Prior to the period of extended a t Rcrane and trolley structural components and the effects of wear A.2.1.13 (Related to Refueling) onterisi h alsse.operation Handlng Sytemson the rails in the rail system.Handling Systems Inspection of Overhead Heavy Load and Light Load Prior to the period of extended (Related to Refueling)

Enhance the program to list additional cranes for monitoring.

A.2.1.13 operation Handling Systems Enhance the program to include an annual air quality test Prior to the period of extended 5. Compressed Air Monitoring requirement for the Diesel Generator compressed air sub A.2.1.14 operation system.6. Fire Protection Enhance the program to perform visual inspection of A.2..15. Prior to the period of extended penetration seals by a fire protection qualified inspector, operation.

Enhance the program to add inspection requirements such as Prior to the period of extended 7. Fire Protection spalling, and loss of material caused by freeze-thaw, chemical A.2.1.15 operation.

attack, and reaction with aggregates by qualified inspector.

operation.

United States Nuclear Regulatory Commission SBK-L-13115

/ Enclosure 3 Page 3 of 12 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Enhance the program to include the performance of visual Prior to the period of extended 8. Fire Protection inspection of fire-rated doors by a fire protection qualified A.2.1.15 operation.

inspector.

Enhance the program to include NFPA 25 guidance for"where sprinklers have been in place for 50 years, they shall Prior to the period of extended 9. Fire Water System be replaced or representative samples from one or more A.2.1.16 operation.

sample areas shall be submitted to a recognized testing laboratory for field service testing".Enhance the program to include the performance of periodic Prior to the period of extended 10. Fire Water System flow testing of the fire water system in accordance with the A.2.1.16 operation.

guidance of NFPA 25.Enhance the program to include the performance of periodic visual or volumetric inspection of the internal surface of the fire protection system upon each entry to the system for routine or corrective maintenance.

These inspections will be documented and trended to determine if a representative Within ten years prior to the period 11. Fire Water System number of inspections have been performed prior to the period A.2.1.16 Wh tenyea priori of extended operation.

If a representative number of inspections have not been performed prior to the period of extended operation, focused inspections will be conducted.

These inspections will be performed within ten years prior to the period of extended operation.

12. Aboveground Steel Tanks Enhance the program to include components and aging effects A.2.1.17 Prior to the period of extended required by the Aboveground Steel Tanks. A operation.

Enhance the program to include an ultrasonic inspection and 13. Aboveground Steel Tanks evaluation of the internal bottom surface of the two Fire A.2.1.17 Wh tenyea priori Protection Water Storage Tanks. of extended operation.

Enhance program to add requirements to 1) sample and 14. Fuel Oil Chemistry analyze new fuel deliveries for biodiesel prior to offloading to A.2.1.18 Prior to the period of extended the Auxiliary Boiler fuel oil storage tank and 2) periodically operation.

sample stored fuel in the Auxiliary Boiler fuel oil storage tank.

United States Nuclear Regulatory SBK-L-131 15 / Enclosure 3 Commission Page 4 of 12 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Enhance the program to add requirements to check for the Prior to the period of extended 15. Fuel Oil Chemistry presence of water in the Auxiliary Boiler fuel oil storage tank A.2.1.18 operation.

at least once per quarter and to remove water as necessary.

Enhance the program to require draining, cleaning and Prior to the period of extended 16. Fuel Oil Chemistry inspection of the diesel fire pump fuel oil day tanks on a A.2.1.18 operation.

frequency of at least once every ten years.Enhance the program to require ultrasonic thickness measurement of the tank bottom during the 10-year draining, cleaning and inspection of the Diesel Generator fuel oil Prior to the period of extended 17. Fuel Oil Chemistry storage tanks, Diesel Generator fuel oil day tanks, diesel fire A.2.1.18 operation.

pump fuel oil day tanks and auxiliary boiler fuel oil storage tank.Enhance the program to specify that all pulled and tested Prior to the period of extended 18. Reactor Vessel Surveillance capsules, unless discarded before August 31, 2000, are placed A.2.1.19 operation.

in storage.Enhance the program to specify that if plant operations exceed the limitations or bounds defined by the Reactor Vessel 19. Reactor Vessel Surveillance Surveillance Program, such as operating at a lower cold leg A.2.1.19 Prior to the period of extended temperature or higher fluence, the impact of plant operation operation.

changes on the extent of Reactor Vessel embrittlement will be evaluated and the NRC will be notified.Enhance the program as necessary to ensure the appropriate withdrawal schedule for capsules remaining in the vessel such that one capsule will be withdrawn at an outage in which the 20. Reactor Vessel Surveillance capsule receives a neutron fluence that meets the schedule A.2.1.19 Prior to the period of extended requirements of 10 CFR 50 Appendix H and ASTM E185-82 operation.

and that bounds the 60-year fluence, and the remaining capsule(s) will be removed from the vessel unless determined to provide meaningful metallurgical data.Enhance the program to ensure that any capsule removed, without the intent to test it, is stored in a manner which Prior to the period of extended 21. Reactor Vessel Surveillance A..2. 1.19 oeain maintains it in a condition which would permit its future use, operation.

including during the period of extended operation.

I United States Nuclear Regulatory SBK-L,-131 15 / Enclosure 3 Commission Page 5 of 12 Commssion5 Pag Encofur12 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION 22. One-Time Inspection Implement the One Time Inspection Program. A.2.1.20 Within ten years prior to the period of extended operation.

Implement the Selective Leaching of Materials Program. The Selective Leaching of program will include a one-time inspection of selected Within five years prior to the period 23. Materials components where selective leaching has not been identified A.2.1.21 of extended operation.

and periodic inspections of selected components where selective leaching has been identified.

24. Buried Piping And Tanks Implement the Buried Piping And Tanks Inspection Program. A.2.1.22 Within ten years prior to entering Inspection the period of extended operation One-Time Inspection of Implement the One-Time Inspection of ASME Code Class I Within ten years prior to the period 2. ASME Code Class 1 Small SmllBoe-ipngPrgrm eSmall Bore-Piping Program. of extended operation.

Bore-Piping Enhance the program to specifically address the scope of the program, relevant degradation mechanisms and effects of 26. External Surfaces interest, the refueling outage inspection frequency, the A.2.1.24 Prior to the period of extended Monitoring inspections of opportunity for possible corrosion under operation.

insulation, the training requirements for inspectors and the required periodic reviews to determine program effectiveness.

Inspection of Internal 27. Surfaces in Miscellaneous Implement the Inspection of Internal Surfaces in A.2.1.25 Prior to the period of extended Piping and Ducting Miscellaneous Piping and Ducting Components Program. operation.

Components Enhance the program to add required equipment, lube oil C, Prior to the period of extended 28. Lubricating Oil Analysis analysis required, sampling frequency, and periodic oil A.2.1.26 operation.

changes.Enhance the program to sample the oil for the Reactor Coolant Prior to the period of extended 29. Lubricating Oil Analysis pump oil collection tanks. A.2.1.26 operation.

Enhance the program to require the performance of a one-time ultrasonic thickness measurement of the lower portion of the Prior to the period of extended 30. Lubricating Oil Analysis Reactor Coolant pump oil collection tanks prior to the period A.2.1.26 operation.

of extended operation.

United States Nuclear Regulatory Commission SBK-L- 13115 / Enclosure 3 Page 6 of 12 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION 31. ASME Section XI, Enhance procedure to include the definition of "Responsible A.2.1.28 Prior to the period of extended Subsection IWL Engineer".

operation.

Structures Monitoring Enhance procedure to add the aging effects, additional Prior to the period of extended 32. Program locations, inspection frequency and ultrasonic test A.2.1.31 operation.

requirements.

Structures Monitoring Enhance procedure to include inspection of opportunity when Prior to the period of extended 33. Program planning excavation work that would expose inaccessible A.2.1.3.1 operation.

concrete.Electrical Cables and Connections Not Subject to Implement the Electrical Cables and Connections Not Subject 34. 10 CFR 50.49 to 10 CFR 50.49 Environmental Qualification Requirements A.2.1.32 prratote Environmental Qualification program.Requirements Electrical Cables and Connections Not Subject to Implement the Electrical Cables and Connections Not Subject 35. 10CFR50.49 to 10 CFR 50.49 Environmental Qualification Requirements A.2.1.33 Prior to the period of extended Environmental Qualification operation.

Requirements Used in Used in Instrumentation Circuits program.Instrumentation Circuits Inaccessible Power Cables Implement the Inaccessible Power Cables Not Subject to 10 Not Subject to 10 CFR CFR 50.49 Environmental Qualification Requirements A.2..34the period of extended 36. 50.49 Environmental pro50. operation.

Qualification Requirements program.Prior to the period of extended 37. Metal Enclosed Bus Implement the Metal Enclosed Bus program. A.2.1.35 operaton.operation.

Prior to the period of extended 38. Fuse Holders Implement the Fuse Holders program. A.2.1.36 operaton.operation.

United States Nuclear Regulatory Commission Page 7 of 12 SBK-L-13115

/ Enclosure 3 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Electrical Cable Connections Not Subject to Implement the Electrical Cable Connections Not Subject to 10 Prior to the period of extended 39. 10 CFR 50.49 CFR 50.49 Environmental Qualification Requirements A.2.1.37 operation.

Environmental Qualification program.Requirements

40. 345 KV SF 6 Bus Implement the 345 KV SF 6 Bus program. A.2.2.1 Prior to the period of extended operation.

41. Metal Fatigue of Reactor Enhance the program to include additional transients beyond A.2.3.1 Prior to the period of extended Coolant Pressure Boundary those defined in the Technical Specifications and UFSAR. operation.

42. Metal Fatigue of Reactor Enhance the program to implement a software program, to Prior to the period of extended 42. count transients to monitor cumulative usage on selected A.2.3.1 Coolant Pressure Boundary operation.

Coolantcomponents.

The updated analyses will be Pressure -Temperature Seabrook Station will submit updates to the P-T curves and submitted at the appropriate time to 43. TemitureiOverprng sure LTOP limits to the NRC at the appropriate time to comply A.2.4.1.4 comply with 10 CFR 50 Appendix Temperature Overpressure wih1 F 0Apni .G, Fracture Toughness Protection Limits with 10 CFR 50 Appendix G.rureT I I I IRequirements.

United States Nuclear Regulatory Commission SBK-L-13 115 / Enclosure 3 Page 8 of 12 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION 44.Environmentally-Assisted Fatigue Analyses (TLAA)NextEra Seabrook will perform a review of design basis ASME Class 1 component fatigue evaluations to determine whether the NUREG/CR-6260-based components that have been evaluated for the effects of the reactor coolant environment on fatigue usage are the limiting components for the Seabrook plant configuration.

If more limiting components are identified, the most limiting component will be evaluated for the effects of the reactor coolant environment on fatigue usage. If the limiting location identified consists of nickel alloy, the environmentally-assisted fatigue calculation for nickel alloy will be performed using the rules of NUREG/CR-6909.

(1) Consistent with the Metal Fatigue of Reactor Coolant Pressure Boundary Program Seabrook Station will update the fatigue usage calculations using refined fatigue analyses, if necessary, to determine acceptable CUFs (i.e., less than 1.0)when accounting for the effects of the reactor water environment.

This includes applying the appropriate Fen factors to valid CUFs determined from an existing fatigue analysis valid for the period of extended operation or from an analysis using an NRC-approved version of the ASME code or NRC-approved alternative (e.g., NRC-approved code case).(2) If acceptable CUFs cannot be demonstrated for all the selected locations, then additional plant-specific locations will be evaluated.

For the additional plant-specific locations, if CUF, including environmental effects is greater than 1.0, then Corrective Actions will be initiated, in accordance with the Metal Fatigue of Reactor Coolant Pressure Boundary Program, B.2.3.1. Corrective Actions will include inspection, repair, or replacement of the affected locations before exceeding a CUF of 1.0 or the effects of fatigue will be managed by an inspection program that has been reviewed and approved by the NRC (e.g., periodic non-destructive examination of the affected locations at inspection intervals to be determined by a method accepted by the NRC).A.2.4.2.3 At least two years prior to entering the period of extended operation.

United States Nuclear Regulatory Commission SBK-L-131 15 / Enclosure 3 Page 9 of 12 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION 45. Number Not Used Protective Coating Enhance the program by designating and qualifying an A.2.1.38 Prior to the period of extended 46. Monitoring and Inspector Coordinator and an Inspection Results Evaluator.

operation Maintenance Enhance the program by including, "Instruments and Protective Coating Equipment needed for inspection may include, but not be 47. Monitoring and limited to, flashlight, spotlights, marker pen, mirror, A.2.1.38 prratot Maintenance measuring tape, magnifier, binoculars, camera with or without operation wide angle lens, and self sealing polyethylene sample bags." Protective Coating Enhance the program to include a review of the previous two Prior to the period of extended 48. Monitoring and monitoring reports. A.2.1.38 operation Maintenance Enhance the program to require that the inspection report is to Protective Coating be evaluated by the responsible evaluation personnel, who is A.2.1.38 Prior to the period of extended Montenand to prepare a summary of findings and recommendations for operation future surveillance or repair.Within the next two refueling ASME Section XI, Perform UT testing of the containment liner plate in the outages, ORs 15 or OR16, and 50. Subsection I, PerformyUT te oistue baie nt loss platerin A.2.1.27 repeated at intervals of no more Subsection IWE vicinity of the moisture barrier for loss of material.

than five refueling outages 51. Number Not Used ASME Section XI, Implement measures to maintain the exterior surface of the 52. Subsection IWL Containment Structure, from elevation

-30 feet to +20 feet, in A.2.1.28 Ongoing a dewatered state.Replace the spare reactor head closure stud(s) manufactured Prior to the period of extended 53. Reactor Head Closure Studs from the bar that has a yield strength > 150 ksi with ones that A.2.1.3 operation.

do not exceed 150 ksi.

United States Nuclear Regulatory Commission SBK-L- 13115 / Enclosure 3 Page 10 of 12 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION NextEra will address the potential for cracking of the primary to secondary pressure boundary due to PWSCC of tube-to-tubesheet welds using one of the following two options: 1) Perform a one-time inspection of a representative sample of tube-to-tubesheet welds in all steam generators to determine if PWSCC cracking is present and, if cracking is identified, resolve the condition through engineering evaluation justifying continued operation or repair the condition, as appropriate, and establish an ongoing monitoring program to perform routine 54. Steam Generator Tube tube-to-tubesheet weld inspections for the remaining life of the A.2. 1.10 Complete Integrity steam generators, or 2) Perform an analytical evaluation showing that the structural integrity of the steam generator tube-to-tubesheet interface is adequately maintaining the pressure boundary in the presence of tube-to-tubesheet weld cracking, or redefining the pressure boundary in which the tube-to-tubesheet weld is no longer included and, therefore, is not required for reactor coolant pressure boundary function.

The redefinition of the rector coolant pressure boundary must be approved by the NRC as part of a license amendment request.55. Steam Generator Tube Seabrook will perform an inspection of each steam generator A.2. 1.10 Within five years prior to entering Integrity to assess the condition of the divider plate assembly.

the period of extended operation.

56c CRevise the station program documents to reflect the EPRI 56. Guideline operating ranges and Action Level values for A.2.1.12 Water System hydrazine and sulfates.

extended operation.

Closed-Cycle Cooling Revise the station program documents to reflect the EPRI Prior to entering the period of 57. Water System Guideline operating ranges and Action Level values for Diesel A.2.1.12 extended operation.

Generator Cooling Water Jacket pH.Update Technical Requirement Program 5.1, (Diesel Fuel Oil 58. Fuel Oil Chemistry Testing Program) ASTM standards to ASTM D2709-96 and A.2.1.18 prratote ASTM D4057-95 required by the GALL XI.M30 Rev I Nickel Alloy Nozzles and The Nickel Alloy Aging Nozzles and Penetrations program Prior to the period of extended 59. Penetrations will implement applicable Bulletins, Generic Letters, and staff A.2.2.3 operation.

accepted industry guidelines.

United States Nuclear Regulatory Commission SBK-L- 13115 / Enclosure 3 Page 11 of 12 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Buried Piping and Tanks Implement the design change replacing the buried Auxiliary Prior to entering the period of 60. Inspection Boiler supply piping with a pipe-within-pipe configuration A.2.1.22 extended operation.

with leak detection capability.

61. Compressed Air Monitoring Replace the flexible hoses associated with the Diesel A.2.1.14 Within ten years prior to entering Program Generator air compressors on a frequency of every 10 years. the period of extended operation.

Enhance the program to include a statement that sampling Prior to the period of extended 62. Water Chemistry frequencies are increased when chemistry action levels are A.2.1.2 operation.

exceeded.Ensure that the quarterly CVCS Charging Pump testing is continued during the PEO. Additionally, add a precaution to 63. Flow Induced Erosion the test procedure to state that an increase in the CVCS Prior to the period of extended Charging Pump mini flow above the acceptance criteria may operation be indicative of erosion of the mini flow orifice as described in LER 50-275/94-023.

Soil analysis shall be performed prior to entering the period of extended operation to determine the corrosivity of the soil in 64. Buried Piping and Tanks the vicinity of non-cathodically protected steel pipe within the Prior to entering the period of Inspectin scope of this program. If the initial analysis shows the soil to A2.1.22 extended operation.

Inspection be non-corrosive, this analysis will be re-performed every ten years thereafter.

Implement measures to ensure that the movable incore Prior to entering the period of 65. Flux Thimble Tube detectors are not returned to service during the period of N/A extended operation extended operation.

66. Number Not Used Perform one shallow core bore in an area that was 67. Structures Monitoring continuously wetted from borated water to be examined for A.2.1.31 No later than December 31,2015 Program concrete degradation and also expose rebar to detect any degradation such as loss of material.68. Structures Monitoring Perform sampling at the leakoff collection points for A.2.1.31 Starting January 2014 68 Program chlorides, sulfates, pH and iron once every three months.

United States Nuclear Regulatory Commission SBK-L- 1311 5 / Enclosure 3 Page 12 of 12 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Open-Cycle Cooling Water Replace the Diesel Generator Heat Exchanger Plastisol PVC Prior to the period of extended 69. System lined Service Water piping with piping fabricated from A.2. 1.11 operation.

AL6XN material.Inspect the piping downstream of CC-V-444 and CC-V-446 to 70. Closed-Cycle Cooling Water determine whether the loss of material due to cavitation A.2.1.12 Within ten years prior to the period System induced erosion has been eliminated or whether this remains of extended operation.

an issue in the primary component cooling water system.Alkali-Silica Reaction Implement the Alkali-Silica Reaction (ASR) Monitoring Prior to entering the period of (ASR) Monitoring Program Program extended operation.

72. Flow-Accelerated Enhance the program to include management of wall A.2.1.8 Prior to entering the period of Corrosion thinning caused by mechanisins other than FA C. extended operation