SBK-L-14037, Supplement 33 to License Renewal Application

Supplement 33 to License Renewal Application

ML14072A018
Person / Time
Site:	Seabrook
Issue date:	03/05/2014
From:	Walsh K NextEra Energy Seabrook
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
SBK-L-14037
Download: ML14072A018 (77)

Text

NEXTera ENERGYQN

ýSEABROOK March 5, 2014 SBK-L-14037 Docket No. 50-443 U.S. Nuclear Regulatory Commission Attention: Document Control Desk One White Flint North 11555 Rockville Pike Rockville, MD 20852 Seabrook Station Supplement 33 to 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. LR-ISG-2012-02: Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation (Accession Number ML13227A361)

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.

In Reference 2, the staff issued LR-ISG-2012-02. Enclosure 1 of this Supplement provides changes to the License Renewal Application (LRA) in response to LR-ISG-2012-02. Enclosure 2 provides changes to the LRA to address aging effects of Service Level III (augmented) internal coatings. provides an updated License Renewal Commitment List to reflect changes to date.

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.

There are seven revised and ten new regulatory commitments contained in this letter.

If there are any questions or additional information is needed, please contact Mr. Edward J.

Carley, N. Engineering Supervisor - License Renewal, at (603) 773-7957.

If you have any questions regarding this correspondence, please contact Mr. Michael H. Ossing, Licensing Manager, at (603) 773-7512.

AiLý NextEra Energy Seabrook, LLC.

626 Lafayette Rd, Seabrook, NH 03874

United States Nuclear Regulatory Commission SBK-L- 1403 7/ Page 2 I declare under penalty of perjury that the foregoing is true and correct.

Executed on March 5, 2014 Sincerel I

Kevin T. Walsh Site Vice President NextEra Energy Seabrook, LLC

Enclosures:

Enclosure 1 - Response to LR-ISG-2012-02, Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation Enclosure 2 - Aging Management of Loss of Coating Integrity for Service Level III (augmented) Internal Coatings Enclosure 3 - LRA Appendix A - Final Safety Report Supplement Table A.3, License Renewal Commitment List Updated to Reflect Changes to Date cc:

W.M. Dean, NRC Region I Administrator J. G. Lamb, NRC Project Manager, Project Directorate 1-2 P.C. Cataldo, NRC Senior Resident Inspector R. A. Plasse Jr., NRC Project Manager, License Renewal L. M. James, NRC Project Manager, License Renewal Mr. Perry Plummer 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 Mr. 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-14037 Response to LR-ISG-2012-02 Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation

United States Nuclear Regulatory Commission Page 2 of 45 SBK-L- 14037/ Enclosure 1 LR-ISG-2012-02: Recurring Internal Corrosion Based on a review of the past 10 years of plant-specific OE (August 2003 to August 2013),

recurring internal corrosion has only occurred in the cement lined carbon steel Service Water (SW) piping. The SW piping is managed under the Open-Cycle Cooling Water Program, B.2.1.11.

a. Description of the aging effect and its extent.

The Seabrook Station SW system piping is fabricated from butt welded, cement lined, carbon steel piping. During construction, joint compound was applied at field welds to seal the cement liner crevices. Defects or degradation of the joint compound as well as random defects in the cement lining allowed sea water intrusion to the carbon steel pipe and subsequent internal corrosion. In some cases, corrosion has led to through wall leakage.

Between 1995 and 2000, elastomeric joint seals (WEKO seals) were installed on field-welded joints in the underground piping. A number of WEKO seals were also installed on some of the above ground field welds. These joint seals consist of an elastomer boot which overlaps the field weld cement liner crevice. These seals were installed to prevent corrosion of cement-lined carbon-steel piping at field welds due to degradation of the original joint compound. Access to piping for joint seal installation and maintenance is via the inspection vaults and dropout spools installed in the SW system.

Seabrook Station had 16 through wall leaks between August 2003 and August 2013 in the SW system. While some leaks occurred at or near a weld joint, some leaks were also found in pipe sections and in fittings. In all cases, repairs were made on-line or during the subsequent refueling outage with no loss of SW system function.

b. Description of the applicable programs' examination methods to detect the recurring aging mechanism before affecting the ability of a component to perform its intended function.

The maintenance strategy for the SW piping evolved from ultrasonic testing of above ground field welds to internal visual examinations during WEKO seal inspections. In 2006, it was recognized that ultrasonic testing of just above ground field welds was ineffective in identifying areas of future leaks. However, it was determined that identification of rust stains/corrosion nodules during internal inspections was effective in identifying potential liner degradation and areas susceptible to corrosion/wall thinning.

In January, 2011, a leak was identified at the welded area downstream of a butterfly valve. The extent of condition review for this new leak identified that the wall thinning had occurred in an area of turbulent flow. Subsequent to the January 2011 leak, a root cause analysis was performed to address the through wall leaks in the SW system.

The root cause analysis identified lack of a process that requires the assessment of all material condition data (including failures, leaks, repairs, degradation, and, inspection adjustments). In the case of the 2011 leak, this lack of assessment resulted in an inadequate maintenance strategy for SW piping and did not incorporate the long term effects of turbulent sea water flow on lined piping into the inspection plan. Repairs to the SW piping were not trended or analyzed in the aggregate to determine specific causes or to make changes to the maintenance strategy.

United States Nuclear Regulatory Commission Page 3 of 45 SBK-L- 14037/ Enclosure 1 As part of the corrective actions, the process was changed to require post outage assessment of SW material condition. The assessment includes all SW material condition data including failures, leaks, repairs, and any degradation. The new process includes reevaluation of the maintenance strategy to determine if changes are warranted. An inspection plan was also developed for the SW piping and incorporates turbulent flow considerations and stagnant locations. In addition to the inspection plan, the process was enhanced to include inspection criteria for various coating materials, a WEKO seal inspection and testing plan, tracking SW system leak history, and trending of repairs to SW piping.

c. The basis for the adequacy of augmented or lack of augmented inspections.

The augmented inspections (i.e., visual inspection of the pipe liner for indication of degradation) have enabled identification of under-liner corrosion which had occurred due to defects in the liner or liner degradation. Once located, actual wall loss due to corrosion can be evaluated by ultrasonic testing on above ground piping. After removal of liner material in the area of interest for buried piping, wall loss can again be evaluated by ultrasonic testing.

d. Parameters that will be trended as well as the decision points where increased inspections would be implemented (e.g., extent of degradation at individual corrosion sites, rate of degradation change).

Visual inspection of the pipe liner for indication of degradation has enabled identification of under-liner corrosion which had occurred due to defects in the liner or liner degradation.

Visual inspections are intended to identify defects such as discoloration of the cement liner (rust stains), cracking, and spalling. During visual inspections, other lining materials such as polyurethane, Plastisol, and Belzona are also inspected for defects such as blistering, flaking, peeling, delamination, and rust stains.

The enhanced SW inspection and repair trending process requires trending of all SW material condition data including, inspection results, coating assessment, failures, leaks, repairs, and any degradation. Inspection plans include turbulent flow considerations and stagnant locations as well as repair history. Following identification of any new degradation, maintenance strategies are assessed to determine if changes are warranted.

e. The basis for parameter testing frequency and how it will be conducted.

An inspection plan, which identifies areas of piping that require inspections during each refueling outage, is maintained on an ongoing basis. The lines to be inspected correspond with the applicable train related outage. High susceptible locations are inspected more frequently. For example, each SW strainer bypass line is inspected on an every other refueling outage frequency.

f. Description of how inspections of not easily accessed components will be conducted (i.e.,

buried, underground).

Inspection vaults and dropout spools have been installed in the SW system to allow access to the buried and underground pipe internals.

United States Nuclear Regulatory Commission Page 4 of 45 SBK-L- 14037/ Enclosure I

g. Identification of leaks in buried components.

Buried piping is periodically visually inspected for indications of degraded coating as part of the SW inspection plan. The WEKO seals in the buried piping are also periodically leak tested and repaired or replaced if found to be defective. Access to the buried piping is via the inspection vaults and dropout spools installed in the SW system.

h. The program(s) that will be augmented to include the above requirements.

Recurring internal corrosion observed in the SW system has been due to coating degradation or failure. As discussed in the "Loss of Coating Integrity for Service Level III (augmented) Internal Coatings" section of this supplement letter, the Open-Cycle Cooling Water System Program will be further enhanced to specifically include management of loss of coating integrity due to blistering, cracking, flaking, peeling, or physical damage of Service Level III (augmented) internal coatings in the SW system (Ref. new commitment #79).

LR-ISG-2012-02: Representative Minimum Sample Size for Periodic Inspections in GALL Report AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" The Seabrook Station Inspections of Internal Surfaces in Miscellaneous Piping and Ducting Components Program will be enhanced to include performance of focused examinations to provide a representative sample of 20%, or a maximum of 25, of each identified material, environment, and aging effect combination in each 10 year period during the period of extended operation. Where practical, the population to be inspected will be selected from components most susceptible to aging because of time in service and severity of operating conditions.

Based on the above discussion, the LRA has been revised as follows:

1. In LRA Appendix B, in Section B.2.1.25 (Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components), on page B-I135, the following paragraphs of the Program Description have been revised as follows:

a. The 2 nd paragraph on page B-139 is revised as follows:

The program inspections will be include inspections of opportunity, performed during pre-planned periodic system and component surveillances or during maintenance activities when the systems are opened and the surfaces made accessible for visual inspection. This maintenance may occur during power operations or refueling outages when many systems are opened. The program also includes focused inspections as needed to ensure that a representative sample of material, environment, and aging effect combinations are periodically evaluated. The visual inspections will assure that existing environmental conditions are not causing material degradation that could result in a loss of the component intended function. The program will include indication of borated water leakage on internal surfaces. The Seabrook Station program will provide for visual inspection

United States Nuclear Regulatory Commission Page 5 of 45 SBK-L- 14037/ Enclosure I activities performed by personnel who are qualified in accordance with site controlled procedures and processes.

b. The 2 nd full paragraph on page B-140 is revised as follows:

Visual inspections of internal surfaces of plant components w4i--may be performed during maintenance or surveillance activities. The presence of corrosion or fouling will be identified by visual inspection as localized discoloration and surface irregularities such as rust, scale/deposits, surface pitting, surface discontinuities and coating degradation.

Metallic components including aluminum, brass or bronze, cast austenitic stainless steel, copper alloy, copper nickel and stainless steel will exlhibit indications of loss of material on the surface similar to steel material and visual inspections will be capable of detecting any surface breaking flaws (i.e., cracks or surface areas that have exhibited loss of material) that occur on the same side as that being examined.

c. The 1st full paragraph on page B-141 is revised as follows:

The system engineer review of inspection results will help ensure that the extent and schedule of inspections and testing detect component degradation prior to loss of intended function. The responsible engineer will ensure that an adequate number of inspections have been performed during each 10 year period during the period of extended operation. Where practical,components falling under this program will be assigned to groups of similar material,environment, and aging effect combinations.Approximately 20% of each group, with a maximum of 25 components of a group, will be inspected each 10 year periodin the period of extended operation. Wiere practical,tihe population to be inspected is selectedfrom components most susceptible to aging because of time ill service and severity of operatingconditions. Opportunisticinspections continue in each period despite meeting the sampling limit.

2. In the Enhancements section of B.2.1.25, on page B-143, a new enhancement has been added as follows:

Enhancements None The following enhancement will be made prior to entering the period of extended operation.

1. The Seabrook Station Inspections of Internal Surfaces in Miscellaneous Piping and Ducting Components Program will be enhanced to include performance of focused examinations to provide a representative sample of 20%, or a maximum of 25, of each identified material, environment, and aging effect combination in each 10 year period during the periodof extended operation. Whiere practical,the population to be inspected is selected from components most susceptible to aging because of time in service and severity of operatingconditions.

United States Nuclear Regulatory Commission Page 6 of 45 SBK-L- 1403 7/ Enclosure 1

3. In LRA Appendix A, in Section A.2.1.25 (Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components), on Page A-15, the second paragraph has been revised as follows:

The program inspections are inspections of opportunity, performed during pre-planned periodic system and component surveillances or during maintenance activities when the systems are opened and the surfaces made accessible for visual inspection. This maintenance may occur during power operations or refueling outages when many systems are opened.

Inspections of opportunity are supplemented with focused inspections to ensure that a representative sample of material, environment, and aging effect combinations are inspected in each 10 yearperiod during the period of extended operation. Where practical, the population to be inspected is selectedfrom components most susceptible to aging because of time in service and severity of operatingconditions. Opportunisticinspections continue in each period despite meeting the sampling limit. The visual inspections assure that existing environmental conditions are not causing material degradation that could result in a loss of the component intended function.

4. In LRA Appendix A, in Section A-3 (License Renewal Commitment List), a new commitment #73 has been added as follows:

PROGRAM or UFSAR No. COMMITMENT SCHEDULE TOPIC LOCATION Inspection of Enhance the programto include performance InternalSurfaces offocused examinations to provide a representativesample of 20%, or a maximum Priorto the in Miscellaneous

73. Pipingand of 25, of each identified material,environment, A.2.1.25 period of Ducting and aging effect combinations duringeach 10 extended Ctin yearperiod in the periodof extended operation.

po operation.

LR-ISG-2012-02: Flow Blockage of Water-Based Fire Protection System Piping, GALL Report AMP XI.M27, "Fire Water System"

a. The following information is provided demonstrating consistency with the requirements for inspections of fire water system components relative to Table 4a (Fire Water System Inspection and Testing Recommendations) provided in LR-ISG-2012-02.

1. Sprinklers - Inspections Sprinklers within the scope of License Renewal are inspected every 18 months, consistent with the Nuclear Electric Insurance Limited (NEIL) Property Standards for Fire Protection Systems Testing. NFPA 25 (2011 Edition) specifies an annual inspection of sprinklers from floor level.

The Fire Water System Program will be enhanced to perform sprinkler inspections annually per the guidance provided in NFPA 25 (2011 Edition) Section 5.2.1.1.

Inspection will ensure that sprinklers are free of corrosion, foreign materials, paint, and physical damage and installed in the proper orientation (e.g., upright, pendant, or

United States Nuclear Regulatory Commission Page 7 of 45 SBK-L- 14037/ Enclosure 1 sidewall). Any sprinkler that is painted, corroded, damaged, loaded, or in the improper orientation, and any glass bulb sprinkler where the bulb has emptied, will be evaluated for replacement (Ref. new commitment #74).

2. Sprinklers - Testing Per LRA Appendix B, Section B.2.1.16 and current commitment #9, the Seabrook Station Fire Water System Program includes the guidance referenced in NFPA 25 (2011 Edition) that where sprinklers have been in place for 50 years, they will be replaced or representative samples from one or more sample areas will be submitted to a recognized testing laboratory for field service testing. If laboratory testing is credited in lieu of replacement, this testing will be performed every 10 years after the initial field service testing to ensure that signs of degradation, such as corrosion, are detected in a timely manner.

This activity is consistent with NFPA 25 (2011 Edition).

3. Standpipe and Hose Systems - Flow Tests Seabrook performs 5 year flow tests to validate NEIL Loss Control Standards - Chapter 4 Table I Standpipe & Hose, Section 1.2 which states the following:

"A flow test needs to be conducted at the hydraulically most remote hose connection of each zone of a standpipe system to verify the water supply still adequately provides the design pressure at the required flow. Where a flow test of the hydraulically most remote outlet(s) is not practical, NSO/NEIL needs to be consulted while determining the appropriate location for the test. A flow test needs to be conducted every 5 years."

This activity is consistent with NFPA 25 (2011 Edition).

4. Private Fire Service Mains - Underground and Exposed Piping Flow Tests The Fire Protection System mains are flushed annually to prove the operability of the system. Each valve operated is flowed to insure an adequate flush of the systems' piping has been achieved. The valve is flushed for two minutes or until clear water is emitted.

A 3-year flow test is conducted for flow verification of the fire protection water system on a sufficient number of hydrants to determine the capacity of the system in the area tested.

This activity is consistent with NFPA 25 (2011 Edition).

5. Private Fire Service Mains - Hydrants The Yard Hydrant Semi-Annual Inspection and Functional Test is performed at least once per six months by visually inspecting each yard fire hydrant, adding oil to the top of each hydrant to lubricate the hydrant main valve, cycling each hydrant main valve and flowing water from each hydrant for at least two minutes. Each hydrant is checked annually to verify it is draining properly, and, if not a self-draining type, the barrel is pumped out if required.

This activity is consistent with NFPA 25 (2011 Edition).

United States Nuclear Regulatory Commission Page 8 of 45 SBK-L- 14037/ Enclosure 1

6. Fire Pumps The fire pumps are tested by the Fire Pumps Annual Test. However, the fire pumps take suction off fire water storage tanks and do not have suction strainers and therefore, the activity specified in NFPA 25 (2011 Edition), Section 8.3.3.7 is not applicable.

7. Water Storage Tanks - Exterior Inspection The Seabrook Station Aboveground Steel Tanks Program, B.2.1.17, includes the required inspections of the fire water tanks. The tank foundation and supports are to be included in the Structures Monitoring Program. The Fire Water System Program will be enhanced to perform exterior inspection of the fire water storage tanks annually for signs of degradation per the guidance provided in NFPA 25 (2011 Edition) Section 9.2.5.5 (Ref.

new commitment #76)

8. Water Storage Tanks - Interior Inspection Per LRA Appendix B, Section B.2.1.16 and current commitment # 13, the internal bottom surface of the two fire protection water storage tanks will be UT inspected and evaluated within ten years prior to the period of extended operation.

Fire Protection Water Storage Tanks are inspected on a 5 year interval for adherent scale, coating bubbles or blisters, delamination of coating, pitting, corrosion, spalling, rot or other forms of deterioration, and aquatic growth (tubercules and slimes shall be sampled, if possible, and tested for microbiological influenced corrosion); recirculation lines, pipe supports, and other piping is inspected; the anti-vortex plate is inspected for deterioration or blockage. When inspections are made by means of underwater evaluation, silt is removed from the tank floor to facilitate the inspection.

This activity is consistent with NFPA 25 (2011 Edition).

9. Valves and System-Wide Testing - Main Drain Test During the 18-month Deluge and Preaction Sprinkler Valve Actuation Test Flow and System Alarms Test, main drain flow verification is performed for each system tested to ensure that the isolation valve that was closed for the test has not failed and has been returned to full open and to verify the operability of all the flow alarms. This is done by performing a test to simulate a flow to the flow alarm pressure switch, and a test of the air or nitrogen supervisory system low pressure alarm, if applicable. Main drain flow verification includes recording flow prior to and during flow through the main drain and calculating the respective pressure drops.

NFPA 25 (2011 Edition) Section 13.2.5 requires that main drain test be conducted annually at each water-based fire protection system riser to determine whether there has been a change in the condition of the water supply piping and control valves.

Additionally, Section 13.2.5.2 requires that if there is a 10 percent reduction in full flow pressure when compared to the original acceptance tests or previously performed tests, the cause of the reduction be identified and corrected if necessary. Furthermore, Section A. 13.2.5 requires recording the time taken for the supply water pressure to return to the original static (nonflowing) pressure.

United States Nuclear Regulatory Commission Page 9 of 45 SBK-L- 1403 7/ Enclosure 1 The Fire Water System Program will be enhanced to a) revise the frequency of main drain testing to annually, b) to include a requirement that if there is a 10 percent reduction in full flow pressure when compared to the original acceptance tests or previously performed tests, the cause of the reduction shall be identified and corrected if necessary, and c) recording the time taken for the supply water pressure to return to the original static (nonflowing) pressure consistent with NFPA 25 (2011 Edition) Section 13.2.5 and A. 13.2.5 (Ref. new commitments #76 and #77).

10. Valves and System-Wide Testing - Deluge Valves The auto initiation of deluge spray and preaction sprinkler system valves is tested every 18 months by an actuation signal from the local fire alarm panel. Alarms must be generated at the detectors or at a remote manual pull station to achieve the automatic activation. Main drain flow verification will be performed for each system tested to ensure that the isolation valve that was closed for the test has not failed and has been returned to full open and to verify the operability of all the flow alarms. This is done by performing a test to simulate a flow to the flow alarm pressure switch, and a test of the air or nitrogen supervisory system low pressure alarm, if applicable.

The Fire Water System Program will be enhanced to revise the frequency of deluge and preaction valve actuation testing to annually, consistent with NFPA 25 (2011 Edition)

Section 13.4.3.2.2 (Ref. new commitment #76).

An Open Head Spray Nozzle Air Flow Test is performed every 3 years to verify that the open heads and branch lines on the deluge system are free of debris and not blocked.

This is done by connecting the selected deluge system to the service air system and observing air flow through each sprinkler head.

This activity is consistent with NFPA 25 (2011 Edition).

11. Water Spray Fixed Systems - Strainers Water spray fixed systems strainers are cleaned every 5 years during the wet sprinkler alarm valve inspection/maintenance, deluge or sprinkler flooding valve inspection/maintenance, and deluge or sprinkler multimatic valve inspection/maintenance.

This activity is consistent with NFPA 25 (2011 Edition).

12. Water Spray Fixed Systems - Operation Test An Open Head Spray Nozzle Air Flow Test is performed every 3 years to verify that the open heads and branch lines on the deluge system are free of debris and not blocked.

This is done by connecting the selected deluge system to the service air system and observing air flow through each sprinkler head.

This activity is consistent with NFPA 25 (2011 Edition).

13. Obstruction Investigation - Internal Inspection of Piping

a. The Fire Water System Program will be enhanced to conduct an inspection of piping and branch line conditions every 5 years by opening a flushing connection at the end of one main and by removing a sprinkler toward the end of one branch line for the purpose of inspecting for the presence of foreign organic and inorganic material per

United States Nuclear Regulatory Commission Page 10 of 45 SBK-L- 14037/ Enclosure 1 the guidance provided in NFPA 25 (2011 Edition) Section 14.2.2 (Ref. new commitment #75).

b. Follow-up volumetric examinations are conducted when internal visual inspections detect surface irregularities that could be indicative of wall loss below nominal pipe wall thickness. Per LRA Appendix B, Section B.2.1.16 and current commitment #11, the Seabrook Station Fire Water System Program is to be enhanced to include the performance of periodic visual inspection or volumetric inspection, as required, of the internal surface of the fire protection system upon each entry to the system for routine or corrective maintenance to evaluate wall thickness and inner diameter of the fire protection piping.

c. Per LRA Appendix B, Section B.2.1.16 and current commitment #10, the Seabrook Station Fire Water System Program is to be enhanced to include the performance of periodic flow testing of the fire water system per the guidance provided in NFPA 25 (2011 Edition) prior to the period of extended operation. Therefore, no further change is necessary.

d. The Station's Fixed Fire Suppression Systems installation specification states that

"[a]ll piping shall be pitched to permit complete drainage of the system. Drain valves shall be provided at all low points of the system." Therefore, no further change is necessary.

e. The Fire Water System Program will be enhanced to include periodic inspection of the fire water storage tanks (Ref. revised commitment #13). This activity, which includes annual external inspections, five-year interval internal tank inspections, and ultrasonic testing of the tank bottom interior surface prior to entering the PEO, was previously included in the Seabrook Aboveground Steel Tanks aging management program. The following has been added to the Fire Water System Program basis document:

Periodic inspection and testing of the fire water tanks is performed using the guidance in NFPA 25 (2011 Edition). The exterior surface of tanks FP-TK-36-A and FP-TK-36-B are inspected annually. Internal inspections are performed on a 5 year interval for adherent scale, coating bubbles or blisters, delamination of coating, pitting, corrosion, spalling, rot or other forms of deterioration and aquatic growth. The Fire Water System Program will be enhanced to require the performance of a UT inspection and evaluation of the internal bottom surface of the two Fire Protection Water Storage Tanks within ten years prior to the period of extended operation.

Based on the information provided above, the following changes have been made to the License Renewal Application.

1. The 3 rd paragraph of LRA Section 3.3.2.2.10.5 has been revised as follows:

Seabrook Station will implement the Inspection .f internal Surfaces in Miscellaneu.s Piping and Duetinig Cmpon.entsPro.gr.am,B.2. 1.25Fire Water System Program,B2.1.16 to manage loss of material due to pitting and crevice corrosion of the aluminum piping components

United States Nuclear Regulatory Commission Page 11 of 45 SBK-L- 1403 7/ Enclosure 1 exposed to condensation in the Fire Protection system. In addition, galvanic corrosion and microbiologically induced corrosion have been added as is-an additional aging mechanisms.

The inspeetion of Internal Sur-faces in Miseellemeus, Piping and Dueting Components P.eg.a.. Fire Water System Programis described in Appendix B.

2. The 3 rd paragraph of LRA Section 3.3.2.2.10.6 has been revised as follows:

Seabrook Station will implement the Inspection of Inte..al Su.faces in M 1is.ellaneou..s Pipinlg and Ducting C.mp. nents Pr. gr.am,. B.2. 125-, Fire Water System Program, B.2.1.16 to manage loss of material due to pitting and crevice corrosion of the copper alloy piping components exposed to condensation in the Fire Protection System. In addition, microbiologically induced corrosion has been added as an additional aging mechanism.

The Inspection of Internal Surfaces in Miseellaneous Piping and Ductinig Componenits Pr-eg-a. Fire Water System Program is described in Appendix B.

3. In LRA Section 3.2, Table 3.2.1 has been revised as follows:

a. Table 3.2.1, the last paragraph of discussion section of item 3.2.1-32 has been revised and a new paragraph has been added as follows:

Aging Aging Further Item e Component EffectMechanism Management Evaluation Discussion Programs Recommended 3.2.1-32 Steel piping Loss of material due Inspection of No Consistent with NUJREG-1801 with and ducting to general corrosion Internal exceptions. The Inspection of components Surfaces in Internal Surfaces in Miscellaneous and internal Miscellaneous Piping and Ducting Components surfaces Piping and Program (with exceptions), B.2.1.25, exposed to air- Ducting will be used to manage loss of indoor Components material due to general corrosion in uncontrolled steel piping components or steel (Internal) ducting components exposed to air-indoor uncontrolled (internal) in the Auxiliary Boiler, Combustible Gas Control, Containment Air Handling, Containment Air Purge, Containment Enclosure Air Handling, Containment On-Line Purge, Control Building Air Handling, Diesel Generator, Diesel Generator Air Handling, Emergency Feedwater Pump House Air Handling, Fire Proteteee, Fuel Oil, Fuel Storage Building Air Handling, Instrument Air, Primary Auxiliary Building Air Handling, Primary Component Cooling Water, Service Water, and Service Water Pump House Air Handling systems.

Fire Water System Program, B.2.1.16, will be used to manage loss of materialdue to generalcorrosion in steel piping components exposed to air-indooruncontrolled(internal)

United States Nuclear Regulatory Commission Page 12 of 45 SBK-L- 14037/ Enclosure 1 in the Fire Protectionsystem.

Pitting,crevice, and microbiologically-inducedcorrosion have been added as additionalaging mechanisms.

b. Table 3.2.1, the last paragraph of discussion section of item 3.2.1-53 has been revised as follows:

Aging Aging Further Item Number Component Effect/Mechanism Management Evaluation Discussion Programs Recommended 3.2.1-53 Stainless None None NA - No AEM or steel, copper AMP Copper alloy piping components alloy, and exposed to air-indoor uncontrolled nickel alloy (internal) are contained in the piping, piping Chemical and Volume Control, components., Containment Air Handling, and piping Containment Enclosure Air elements Handling, Control Building Air exposed to Handling, Dewatering, Diesel air-indoor Generator., Fire PFeteetie.. Fuel uncontrolled Storage Building Air Handling, and (external) Service Water systems.

4. In LRA Section 3.3, Table 3.3.1 has been revised as follows:

a. Table 3.3.1, the 3rd paragraph of the discussion section of item 3.3.1-27 has been revised as follows:

Aging Further Item Component . Management Evaluation Discussion.

Number Effectl~echani Programs Recommended 3.3.1-27 Stainless steel Loss of material due A plant- Yes, plant HVAC ducting to pitting and crevice specific aging specific Consistent with N UREG- 1801 i*

and aluminum corrosion management e-eeptions. The inspetien af HVAC piping, program is to internal SuFfaees in Miseellaneaus piping be evaluated. Piping and Durting C.mp.nenit.

components Pr,.g.a., (With ..eepti@nS)ý and piping B.2. The Fire Water S;ystem elements Program, B.2.1.16 will be used to exposed to manage loss of material due to condensation pitting and crevice corrosion of the aluminum piping components exposed to condensation in the Fire Protection system. In addition galvanic corrosion and incrobiologicallyinduced corrosion have been added as is-an-additional aging mechanisms.

See subsection 3.3.2.2.10.5.

United States Nuclear Regulatory Commission Page 13 of 45 SBK-L- 1403 7/ Enclosure 1

b. Table 3.3.1, the 3 rd paragraph of the discussion section of item number 3.3.1-28 has been revised as follows:

Item Aging Aging Further Numb Component EfftMhai Management Evaluation Discussion Programs Recommended 3.3.1-28 Copper alloy Loss of material due A plant- Yes, plant Consistent with NUREG-1801 with fire protection to pitting and crevice specific aging specific . The inspeetio, -ef

,eeptiens.

piping, piping corrosion management intemal SuFfaces in Miseellaneeus components, program is to Piping and Ducting Cempenents and piping be evaluated. Program(w.ih e.eepti.ns). B.241.25 elements Fire Water System Program, exposed to B.2.1.16 will be used to manage loss condensation of material due to pitting and (internal) crevice corrosion of the copper alloy piping components exposed to condensation in the Fire Protection System. Additionally, microbiologicallyinduced corrosion has been added as an additionalaging mechanism.

See subsection 3.3.2.2.10.6.

c. Table 3.3.1, the 2nd paragraph of the discussion section of item number 3.3.1-71 has been revised as follows:

Aging Aging Further e Component Management Evaluation Discussion ececanism Programs Recommended 3.3.1-71 Steel piping, Loss of material due Inspection of No Consistent with NUREG-1801 wilh piping to general, pitting, Internal e ,eeptieis.

The .. ispee.ien e.

components, and crevice corrosion Surfaces in Intenal Su-rfaces in MiAc'ellanecu and piping Miscellaneous Piping and Dueting Components elements Piping and PrOgra (with

.:m exeeptions), B.2..25 exposed to Ducting Fire Water System Program, moist air or Components B.2.1.16 will be used to manage loss condensation of material due to general, pitting, (Internal) and crevice corrosion of the steel piping components exposed to condensation in the Fire Protection System. In addition galvanic corrosion and microbiologically induced corrosionis-am have been added as additional aging mechanisms.

United States Nuclear Regulatory Commission Page 14 of 45 SBK-L- 1403 7/ Enclosure 1

5. The following AMR line items have been revised and new ones added as follows:

a. Table 3.3.2-15, Fire Protection System, on Page 3.3-301, line item 4 has been revised and new line items have been added as follows:

Aging Effect Aging NUREG Table Component Intended Material Environment Requiring Management 1801 Vol. 2 3.X.I Note Type Function Management Program Item Item Filter Filter Stainless Raw Water Flow Blockage Fire Water None None A, 6 Element Steel (Internal) Due to Fouling System Program hispeetion-e Internal Surfaces in Mi*cellaneou, Filter Pressure Copper Condensation L o t-9 - ip"'g and VII.G-9 3.3.1-28 Housing Boundary Alloy (internal) GeLipenei-s (AP-78)

Program Fire Water A., 6 System Program Filter Pressure Copper Condensation Flow Blockage Fire Water Housing Boundary Alloy (internal) Due to Fouling System Program Filter Pressure Copper Raw Water Flow Blockage Fire Water Housing Boundary Alloy (Internal) Due to Fouling System Program Filter Pressure Galvanized Raw Water Flow Blockage Fire Water Housing Boundary Steel (Internal) Due to Fouling System Program

United States Nuclear Regulatory Commission Page 15 of 45 SBK-L- 14037/ Enclosure 1

b. Table 3.3.2-15, Fire Protection System, on Page 3.3-302, 1t line item has been revised and new line items have been added as follows:

Aging Effect Aging NUREG Table Component Intended Material Environment Requiring Management 1801 Vol. 2 3.X.1 Note Management Program Item Item Inspeetien-,f Lntzrnal Surfaee, in Miseellanecus Filter Pressure Gray Cast Condensation Loss of Material VII.G-23 3.3.1-71 Housing Boundary Iron (internal) LossofMateri . .omoen..ts (A-23) A, 6 Progra Fire Water System Program Filter Pressure Gray Cast Condensation Flow Blockage Fire Water Housing Boundary Iron (internal) Due to Fouling System Program Filter Pressure Gray Cast Raw Water Flow Blockage Fire Water Housing Boundan, Iron (Internal) Due to Fouling System Program Filter Pressure Steel Raw Water Flow Blockage Fire Water Housing Boundary (Internal) Due to Fouling System Program

c. Table 3.3.2-15, Fire Protection System, on Page 3.3-304, new line items have been added as follows:

Aging Effect Aging NUREG Table Component Intended Material Environment Requiring Management 1801 Vol. 2 3.X.1 Note Type Function Management Program Item Item Heat Exchanger Components Pressure Gray Cast Raw Water Flow Blockage Fire Water (FP-E-46 & 47 Boundar Iron (Internal) Due to Fouling System Program Channel Head)

Heat Heat Exchanger Transfer Stainless Raw Water Flow Blockage Fire Water Components Steel (Internal) Due to Fouling System Program None None A, 6 (FP-E-46 & 47 Pressure Tubes) Boundary

United States Nuclear Regulatory Commission Page 16 of 45 SBK-L- 14037/ Enclosure 1

d. Table 3.3.2-15, Fire Protection System, on Page 3.3-305, 6 th line item has been revised and new line items have been added as follows:

e. In Table 3.3.2-15, on page 3.3-306, the 1st line item that was added under SBK-L-12186 has been revised ( 2 nd line item added under SBK-L-12186 is unchanged) and a new 3 rd line item has been added as follows:

Intended Aging Effect Aging NUREG Table Component Type Inten Material Environment Requiring Management 1801 Vol. 2 3.X.1 Note Management Program Item Item Pressure Air-Indoor NORNene is Orifice Boundary Stainless Steel Uncontrolled Uncontrolle (APN-7) A, 6 (External) Loss of Material Fire Pr None None Throttle Pressure Orifice Boundary Stainless Raw Water Flow Blockage Fire Water None None A, 6 Steel (Internal) Due to Fouling System Program Throttle IIIIII

United States Nuclear Regulatory Commission Page 17 of 45 SBK-L- 1403 7/ Enclosure 1

f. Table 3.3.2-15, Fire Protection System, on Page 3.3-306, 2 "dand 8 th line items have been revised and new line items have been added as follows:

Aging Effect Aging NUREG Table Component Intended Material Environment Requiring Management 1801 Vol. 2 3.X.I Note Type Function Management Program Item Item Inte*ral Su.faces VII.FI-14 3.3.1-27 E;-2 in Miscellaneous (AP-74)

Piping and Pressure Aluminum Condensation Loss of Material Puetin Fittings Boundary (Internal) CO.P......S P2FegFam Fire Water A, 6 System Program Piping and Pressure Aluminum Condensation Flow Blockage Fire Water Fittings Boundary (Internal) Due to Fouling System Program Piping and Pressure Copper Raw Water Flow Blockage Fire Water Fittings Boundary Alloy (Internal) Due to Fouling System Program Air-Indoor None Nene  % 63 Piping and Pressure Galvanized Uncontrolled (iPe 13) A-6 Fittings Boundary Steel (Internal) Loss of Material System Program None None Air-Indoor Piping and Pressure Galvanized Flow Blockage Fire Water Boundary Steel Uncontrolled Due to Fouling System Program None None A, 6 Fittings (Internal)

Piping and Pressure Galvanized Raw Water Flow Blockage Fire Water Fittings Boundary Steel (Internal) Due to Fouling System Program

United States Nuclear Regulatory Commission Page 18 of 45 SBK-L- 1403 7/ Enclosure 1

g. Table 3.3.2-15, Fire Protection System, on Page 3.3-307, 3'd line item has been revised and new line items have been added as follows:

intemal Surfaces in Mbciseaneous Condensation (Internal)

Pregram Fire Water

United States Nuclear Regulatory Commission Page 19 of 45 SBK-L- 1403 7/ Enclosure 1

h. Table 3.3.2-15, Fire Protection System, on Page 3.3-308, 6 th and 7h line items have been revised and new line items have been added as follows:

Component Intended Aging Effect Aging NUREG Table Material Environment Requiring Management 1801 Vol. 2 3.X.1 Note Type Function Management Program Item Item inspeetio internal Suifeees in Misellaneous Air-Indoor Piin and.**

Piping and Pressure SelArIdov.-9 3.2.132 Fittings Boundary Steel Uncontrolled Loss of Material CeOtin, V.A-19 2-3 A6 (Internal) Components (E-29) A, 6 Fire Water Sjstem Program Inpeeten-ef internal Surfaees in Misellaneous Piping and Piping and Pressure Steel Condensation Loss of Material Duetig VII.G-23 3.3.1-71 4 Fittings Boundary (Internal) OMOpen...tS (A-23) A, 6 PFegafam Fire Water System Program Piping and Pressure Air-Indoor Flow Blockage Fire Water Boundary eUnconterolled Due to Fouling System Program Fittings (Internal)

Piping and Pressure Steel Condensation Flow Blockage Fire Water Fittings Boundary (internal) Due to Fouling System Program

i. Table 3.3.2-15, Fire Protection System, on Page 3.3-309, new line items have been added as follows:

Component Intended Aging Effect Aging NUREG Table Cmpnen Fntend Material Environment Requiring Management 1801 Vol. 2 3.X.1 Note Management Program Item Item Leakage Boundary Fire Water Piping and (Spatial) Steel Raw Water Flow Blockage System None None A. 6 Fittings (Internal) Due to Fouling Program Pressure Boundary Piping and Fire Water Fittings Pressure SteelSytmNnNoeRaw Water Flow Blockage System None None A, A6 6 (Containment Boundary (Internal) Due to Fouling Program Isolatiot) Program

United States Nuclear Regulatory Commission Page 20 of 45 SBK-L- 14037/ Enclosure 1

j. Table 3.3.2-15, Fire Protection System, on Page 3.3-310, new line item has been added as follows:

Intended Aging Effect Aging NUREG Table Component Material Environment Requiring Management 1801 Vol. 2 3.X.1 Note Type Function Management Program Item Item Pump Casing Pressure Gray Cast Raw Wafer Flow Blockage Fire Water Boundary Iron (InternaO Due to Fouling System Program None None A, 6 Pump Casing Pressure Stainless Raw Water Flow Blockage Fire Water Boundary Steel (Internal) Due to Fouling System Program None None A, 6

k. Table 3.3.2-15, Fire Protection System, on Page 3.3-311, 4th line item has been revised and new line items have been added as follows:

Intended Aging Effect Aging NUREG Table Component Type Function Material Environment Requiring Management 1801 Vol. 2 3.X.1 Note Management Program Item Item Pressure Fire Water Sprinkler Head Boundary Copper Raw Water Flow Blockage System None None A, 6 Alloy (Internal) Due to Fouling Program hispeetion of Steffnal Pressure .ise.. . ... ous; Boundary Air-Indoor Piin and,,*.

Sprinkler Head Gray Cast Uncontrolled Loss of Material D V.A- 19 3.2.1-32 Iron (Internal) Com..t. s (E-29) - A, 6 Spray P--g -am Fire Water System Program Pressure Air-Indoor Fire Water Sprinkler Head Boundary Gray Cast Uncontrolled UcotrIron oll Due toBlockage Fouling stem None None A,* 6

_______Spray (Itra)Program

United States Nuclear Regulatory Commission Page 21 of 45 SBK-L- 1403 7/ Enclosure 1

1. Table 3.3.2-15, Fire Protection System, on Page 3.3-312, 3 rd, 4 th and 9 th line items have been revised and new line items have been added as follows:

Aging Effect Aging NUREG Table Component Intended Material Environment Requiring Management 1801 Vol. 2 3.X.1 Note Type Function Management Program Item Item Air-Indoor None Nne (EP4-o) A-4 Valve Body Pressure Copper Uncontrolled Fire Water Boundary Alloy (Internal) Loss of Material System Program None None A, 6 hispeetion-ea Internal Surfacee in Nfiseellaneous Piping andE-12 Valve Body Pressure Copper Condensation Loss of Material vIG9 3.3.1-28 Boundary Alloy (Internal) Gempenent4 (AP-78) A, 6 Pr-g-am Fire Water System Program Non VF_ 3 3.2.1 53 Air-Indoor None o (:E~Pi A--4 Pressure Copper Valve Body Boundary Alloy Uncontrolled Fire Water

>15% Zn (.Internal) Loss of Material System Program None None A, 6 Valve Body Pressure Copper Condensation Flow Blockage Fire Water Boundary Alloy (Internal) Due to Fouling System Program None None A. 6 Valve Body Pressure Copper Raw Water Flow Blockage Fire Water Boundary Alloy (Internal) Due to Fouling System Program None None A. 6 Pressure Copper Air-Indoor Flow Blockage Fire Water Valve Body Bounday Alloy

>15% Zn Uncontrolled (Internal) Due to Fouling System Program None None A, 6

United States Nuclear Regulatory Commission Page 22 of 45 SBK-L- 1403 7/ Enclosure 1

m. Table 3.3.2-15, Fire Protection System, on Page 3.3-313, 1s and 10th line items have been revised and new line items have been added as follows:

Aging Effect Aging NUREG Table Component Intended Type Inten Material Environment Requiring Management 1801 Vol. 2 3.X.1 Note Type Function Management Program Item Item in Misellaneous Copper ,Piping*and Valve Body Pressure Alloy Condensation Loss of Material D VII.G-9 3.3.1-28 Boundary >15% Zn (Internal) -eflipef.ents. (AP-78) A, 6 P-rogfam Fire Water System Program ins.petion internal Sur-faees in Misee'laneetu Piping and Air-Indoor V.A- 19 3.2.1-32 A, Valve Body Pressure Boundary Gray Cast Iron Uncontrolled (Internal) Loss of Material ...uetEg

n. (E-29..-...

PEogram Fire Water System Program Copper Condensation Flow Blockage Fire Waler Valve Body Pressure Alloy None None A, 6 Boundary >15% Zn (Internal) Due to Fouling System Program Pressure Copper Raw Water Flow Blockage Fire Water Vah~eBodyB~unat3' AleoyBoundary

>l%

>15% Zn (Internal) Due to Fouling System Program None None A, 6 Valveure Body, Cast Air-Indoor Flow Blockage Fire Waler ValvePressure Gry Cast Uncontrolled DueNone None AF,6 Boundary Iron (Internal) Due to Fouling System Program

n. Table 3.3.2-15, Fire Protection System, on Page 3.3-314, new line items have been added as follows:

United States Nuclear Regulatory Commission Page 23 of 45 SBK-L- 14037/ Enclosure 1

o. Table 3.3.2-15, Fire Protection System, on Page 3.3-315, new line items have been added as follows:

Component Intended Aging Effect Aging NUREG Table Cope inten Material Environment Requiring Management 1801 Vol. 2 3.X.1 Note Type Function Management Program Item Item Valve Body Pressure Sleet Raw Waler Flow Blockage Fire Water Boundary (Internal) Due to Fouling System Program None None A, 6 Valve Body (Containment Pressure Steel Raw Water Flow Blockage Fire Water Isolationm) BoundarS (Internab Due to Fouling System Program None None A, 6 Plate Direct Flow S(E.-ternal/ Raw Waler Flow Due toBlockage Fouling FireWater System Program Vorte Internal) III

p. Table 3.3.2-15, Fire Protection System, on Page 3.3-317, a new plant specific note 6 has been added as follows:

6 Consistent with NUREG-1801 as modified by LR-ISG-2012-02

6. License Renewal Application, Appendix A, Section A.2.1.16 (Fire Water System), on page A-12, the 1 s' paragraph is changed to read as follows:

The Fire Water System Program is established in accordance with the applicable National Fire Protection Association (NFPA) codes and standards. Full flow testing and visual inspections are conducted to ensure that loss of material due to general, pitting, and crevice corrosion, microbiologically influenced corrosion (MIC), orfouling, and blockage due tofouling is adequately managed.

7. License Renewal Application, Appendix B, Section B.2.1.16 (Fire Water System), on page B-100, the 3 rd paragraph is changed and subsequent paragraph added as follows:

The Seabrook Station Aboveground Steel Tanks Program, B.2.1.17, includes required inspections of the fire water tanks and fire protection fuel oil tanks.

Periodic inspection and testing of the fire water storage tanks is performed using the guidance in NFPA 25 (2011 Edition). The exterior surfaces of the tanks are inspected annually. Internal inspections are performed on a 5 year interval for adherent scale, coating bubbles or blisters, delamination of coating, pitting, corrosion, spalling, rot or other forms of deterioration and aquatic growth. UT inspection and evaluation of the internal bottom surface of die two fire water storage tanks is to be performed within ten years priorto the period of extended operation.

8. License Renewal Application, Appendix B, Section B.2.1.16 (Fire Water System), on page B-101, Enhancement 3 is revised as follows:

United States Nuclear Regulatory Commission Page 24 of 45 SBK-L- 14037/ Enclosure 1

3. The Seabrook Station Fire Water System Program will be enhanced to include the performance of periodic visual inspection or volumetric inspection, as required, of the internal surface of the fire protection system upon each entry to the system for routine or corrective maintenance to evaluate wall thickness and inner diameter of the fire protection piping ensuring that corrosion product buildup will not result in flow blockage due to fouling. Where surface irregularities are detected, follow-up volumetric examinations are performed. This inspection will be performed no earlier than 10 years before the period of extended operation.

9. License Renewal Application, Appendix B, Section B.2.1.16 (Fire Water System), on page B-101, new enhancements 4 through 8 are added as follows:

4. The Fire Water System Programwill be enhanced to require the performance of a UT inspection and evaluation of the internal bottom surface of the hvo Fire Protection Water Storage Tanks per the guidance provided in NFPA 25 (2011 Edition) within ten years priorto the periodof extended operation.

ProgramElements Affected: Element 4 (Detection of Aging Effects)

5. The Fire Water System Program will be enhanced to conduct an inspection of piping and branch line conditions every 5 years by opening a flushing connection at the end of one main and by removing a sprinkler toward the end of one branch line for the purpose of inspectingfor the presence of foreign organic and inorganicmaterialper the guidanceprovided in NFPA 25 (2011 Edition).

ProgramElements Affected: Element 4 (Detection of Aging Effects)

6. The Fire Water System Program will be enhanced to perform sprinkler inspections annuallyper the guidanceprovided in NFPA 25 (2011 Edition). Inspection will ensure that sprinklers arefree of corrosion,foreignmaterials,paint,and physical damage and installed in the proper orientation (e.g., upright,pendant, or sidewall). Any sprinkler that is painted, corroded, damaged, loaded, or in the improper orientation, and any glass bulb sprinkler where the bulb has emptied, will be evaluatedfor replacement.

ProgramElements Affected: Element 4 (Detection of Aging Effects)

7. The Fire Water System Program will be enhanced to conduct the following activities annuallyper the guidanceprovided in NFPA 25 (2011 Edition).

" main drain tests

" deluge valve trip tests

• fire water storage tank exterior surface inspections ProgramElements Affected: Element 4 (Detection of Aging Effects)

8. The Fire Water System Program will be enhanced to include the following requirements related to the main drain testing per the guidance provided in NFPA 25

United States Nuclear Regulatory Commission Page 25 of 45 SBK-L- 1403 7/ Enclosure 1 (2011 Edition).

• The requirement that if there is a 10 percent reduction in full flow pressure when compared to the original acceptance tests or previously performed tests, the cause of the reduction shall be identified and correctedif necessary.

• Recording the time taken for the supply water pressure to return to the original static (nonflowing)pressure.

10. In LRA Appendix A, in Section A.3 (License Renewal Commitment List), the following changes have been made.

a. Commitments #9, #10, #11 and #13 have been revised as follows:

UFSAR No. PROGRAM or TOPIC COMMITMENT LOCATION SCHEDULE Enhance the program to include NFPA 25 (2011 Edition) guidance for "where Prior to the sprinklers have been in place for 50 years,

9. Fire Water System they shall be replaced or representative A.2.1.16 period extendedof samples from one or more sample areas operation.

shall be submitted to a recognized testing laboratory for field service testing".

Enhance the program to include the Prior to the performance of periodic flow testing of the A.2. 1.16 period of

10. Fire Water System fire water system in accordance with the extended guidance of NFPA 25 (2011 Edition). operation.

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 Within ten corrective maintenance to evaluate wall years prior to

11. Fire Water System thickness apid innerdiameter ofthefire A.2.1.16 the period of protection piping ensuring that extended corrosionproduct buildup will not result inflow blockage due tofouling.

Where surface irregularitiesare detected,follow-up volumetric examinations areperformed. These inspections will be documented and trended to determine if a representative

United States Nuclear Regulatory Commission Page 26 of 45 SBK-L- 1403 7/ Enclosure 1 number of inspections have been performed prior to the period 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.

Enhance the program to perform exterior inspection of thefire water Within ten Ab.v.g.ound Ste. l storagetanks annuallyfor signs of A.2.1.17 years prior to

13. Tanks degradationand include an ultrasonic the period of inspection and evaluation of the internal A.2.1.16 extended Fire Water System bottom surface of the two Fire Protection operation Water Storage Tanks per the guidance provided in NFPA 25 (2011 Edition).

b. New commitments #74, #75, #76, and 77 have been added as follows:

No. PROGRAM or TOPIC COMMITMENT UFSAR SCHEDULE LOCATION Enhance the programto perform sprinkler inspections annuallyper the guidanceprovided in NFPA 25 (2011 Edition). Inspection will ensure that sprinklers arefree of corrosion, Within ten foreign materials,paint, amid physical years priorto

74. Fire Water System damage and installed in the proper A.2.1.16 the period of orientation(e.g., upright,pendant, or extended sidewall). Any sprinklerthat is operation painted,corroded,damaged, loaded,or in the improper orientation,amid anky glass bulb sprinkler where the bulb has emptied, will be evaluatedfor replacement.

United States Nuclear Regulatory Commission Page 27 of 45 SBK-L- 1403 7/ Enclosure 1 No. PROGRAM or TOPIC COMMITMENT UFSASCEDULE LOCATION Enhance the programto conduct an inspection of piping and branchline conditions every 5 years by opening a Within ten flushing connection at the end of one years prior to

75. Fire Water System main and by removing a sprinkler A.2.1.16 the period of towardthe end of one branch linefor extended the purpose of inspectingfor the operation presence offoreign organic and inorganicmaterialper the guidance provided in NFPA 25 (2011 Edition).

Enhance the programto conduct the following activitiesannually per the Within ten guidanceprovided in NFPA 25 (2011 years priorto

76. Fire Water System Edition). A.2.1.16 the period of

• main drain tests extended

• deluge valve trip tests operation

• fire water storage tank exterior surface inspections The Fire Water System Programwill be enhancedto include the following requirements relatedto the main drain testing per the guidanceprovided in NFPA 25 (2011 Edition).

• The requirement that if there is a Within ten 10 percent reduction in full flow years priorto

77. Fire Water System pressure when comparedto the A.2.1.16 the period of originalacceptance tests or extended previously performed tests, the operation cause of the reduction shall be identified andcorrected if necessary.

• Recording the time taken for the supply waterpressure to return to the originalstatic (nonflowing) pressure.

United States Nuclear Regulatory Commission Page 28 of 45 SBK-L- 1403 7/ Enclosure 1 LR-ISG-2012-02: Revisions to the Scope and Inspection Recommendations of GALL Report AMP XI.M29, "Above Ground Metallic Tanks" Review of the Seabrook Station component database indicates that there are three indoor water storage tanks that meet the following criteria:

i. have a large volume (i.e., greater than 100,000 gallons) ii. are designed to near-atmospheric internal pressures iii. sit on concrete or soil iv. are exposed internally to water The indoor tanks that meet the above criteria are as follows:

Tank ID Volume Material Internal (gallons) Environment CBS-TK-8 475000 Stainless steel Treated Borated (Refueling Water Storage Tank) Water CO-TK-25 (Condensate Storage Tank)* 400,000 Stainless steel Treated Water RMW-TK- 12 (ReacTor M112,000 (Reactor Makeup Water Storage Tank)I Stainless steel Treated Water

• Condensate Storage Tank is enclosed in a concrete structure and therefore, the tank sides are not accessible for external inspections. Only the dome of the tank, which is exposed to air-outdoor, is accessible for external inspections.

The Seabrook Station Aboveground Steel Tanks Program, B.2.1.17, has been revised to include tanks CBS-TK-8, CO-TK-25, and RMW-TK-12 in to the scope of the program. Additionally, fire water storage tanks, FP-TK-36A and 36 B, have been removed from the scope of the Above Ground Steel Tanks program. Fire water storage tanks will be age managed under the Fire Water System aging management program as recommended by LR-ISG-2012-02.

In accordance with the recommendations of LR-ISG-2012-02, Appendix M, Table 4a, the three indoor tanks listed above will be inspected as follows:

a. For managing loss of material on the internal surfaces of stainless steel indoor tanks exposed to treated-water or treated borated water, visual inspections will be performed from inside the tank or volumetric examinations from outside tank using the One-Time Inspection Program. At least 25 percent of the tank's internal surface will be inspected by a method capable of precisely determining wall thickness. The inspection method must be capable of detecting both general and pitting corrosion and must be qualified and demonstrated effective by the NextEra Energy Seabrook. The one-time inspection must occur within the 5-year period prior to entering the PEO.

b. For managing cracking on the external surfaces of stainless steel indoor tanks exposed to air-indoor uncontrolled, surface examinations will be performed each 10-year period

United States Nuclear Regulatory Commission Page 29 of 45 SBK-L- 1403 7/ Enclosure 1 starting 10 years before the period of extended operation. A minimum of either 25 1-square-foot sections for tank surfaces or I-linear-foot of weld length, or 20 percent of the tank's surface are examined. The sample inspection points are distributed such that inspections occur in those areas most susceptible to degradation (e.g., areas where contaminants could collect, inlet and outlet nozzles, welds).

c. For managing loss of material on the external surfaces of stainless steel tanks exposed to air-outdoor (dome of the Condensate Storage Tank), visual examinations of the outside surfaces will be performed every 18-months. For managing cracking on the external surfaces of stainless steel tanks exposed to air-outdoor, surface examinations will be performed each 10-year period starting 10 years before the period of extended operation.

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

d. For managing loss of material on the external surfaces of stainless steel indoor tank bottoms exposed to soil or concrete, volumetric examinations will be performed from inside the tanks each 10-year period starting 10 years before the period of extended operation. For tank bottoms exposed to soil, a one-time inspection may be conducted in accordance with GALL Report AMP XI.M32 in lieu of periodic inspections if an evaluation conducted prior to the PEO and during each 10-year period during the PEO demonstrates that the soil under the tank is not corrosive using actual soil samples that are analyzed for each individual parameter (e.g., resistivity, pH, redox potential, sulfides, sulfates, moisture) and overall soil corrosivity. The evaluation should include soil sampling from underneath the tank.

The following tanks are within the scope of LR and located outdoors. These tanks have an internal environment of fuel oil. Fuel Oil Chemistry Program, B.2.1.18, is used to manage loss of material on the internal surfaces of fuel oil storage tanks. Inspections to identify aging of the external surfaces of tank bottoms and tank shells exposed to soil or concrete are conducted in accordance with the Aboveground Steel Tanks Program, B.2.1.17.

Tank ID Material Internal Environment 1-AB-TK-29 Steel Fuel Oil (Auxiliary Boiler Fuel Oil Storage Tank) 1-FP-TK-35-A Steel Fuel Oil (Fire Protection Fuel Oil Tank) 1-FP-TK-35-B Steel Fuel Oil (Fire Protection Fuel Oil Tank)

United States Nuclear Regulatory Commission Page 30 of 45 SBK-L- 14037/ Enclosure 1 In accordance with the recommendations of LR-ISG-2012-02, Appendix M, Table 4a, the three outdoor tanks listed above will be inspected as follows:

a. For managing loss of material on the external surfaces of steel tanks exposed to air-outdoor, visual examinations of the outside surfaces will be performed during each refueling outage.

b. For managing loss of material on the external surfaces of steel tank bottoms exposed to soil or concrete, volumetric examinations will be performed from inside the tanks each 10-year period starting 10 years before the period of extended operation. A one-time inspection conducted in accordance with GALL Report AMP XI.M32 may be conducted in lieu of periodic inspections if an evaluation conducted prior to the PEO and during each 10-year period during the PEO demonstrates that the soil under the tank is not corrosive using actual soil samples that are analyzed for each individual parameter (e.g.,

resistivity, pH, redox potential, sulfides, sulfates, moisture) and overall soil corrosivity.

The evaluation should include soil sampling from underneath the tank.

Based on the above discussion, the following changes have been made to the LRA.

A. In LRA Section 3, the following new environment has been added to Sections 3.2.2.1.2 (Containment Building Spray System), 3.3.2.1.31 (Reactor Makeup Water System), and 3.4.2.1.5 (Condensate System).

• Soil or Concrete B. In LRA Section 3.4.2.2.7(1), on page 3.4-18, Loss of Material due to Pitting and Crevice Corrosion, a new paragraph is added as follows:

Seabrook Station will implement the Above Ground Steel Tanks Program, B.2.1.17, to manage loss of materialdue to pitting and crevice corrosion in stainless steel Condensate Storage Tank exposed to treated water in the Condensatesystem.

C. In LRA Section 3.4.2.2.7(2), on page 3.4-18, Loss of Material due to Pitting and Crevice Corrosion, a new paragraph is added as follows:

Seabrook Station will implement the Above Ground Steel Tanks Program, B.2.1.17, to manage loss of materialdue to pitting and crevice corrosion in stainless steel Condensate Storage Tank exposed to soil in the Condensate system.

United States Nuclear Regulatory Commission Page 31 of 45 SBK-L- 1403 7/ Enclosure I D. In LRA Section 3.2 and 3.4, Tables 3.2.1 and 3.4.1 have been revised as follows:

Item Aging Aging Further Component Effe c Management Evaluation Discussion Number ectfMechanism Programs Recommended 3.2.1-49 Stainless steel Loss of material due Water No Components in the Reactor Coolant piping, piping to pitting and crevice Chemistry system have been aligned to this line item components, corrosion based on material, environment, and piping aging effect. Stainless steel Refueling elements, and Water Storage Tank in the Containment tanks exposed Building Spray system and stainless to treated steel Reactor Makeup Water Storage borated water Tank in the Reactor makeup Water system have also been aligned to this line item based on component, material, environment, and aging effect.

Consistent with NUREG-1801. The Water Chemistry Program, B.2.1.2, will be used to manage loss of material due to pitting and crevice corrosion in stainless steel piping components exposed to treated borated water in the Containment Building Spray, Reactor Coolant, Residual Heat Removal, and Safety Injection systems, and stainless steel heat exchanger components exposed to treated borated water in the Containment Building Spray, Reactor Coolant, and Residual Heat Removal systems, and stainless steel tanks exposed to treated borated water in the Centainment Buildi*g Sp.ay. Reactor Coolant5 and Safety Injection systems.

Refueling Water Storage Tank in the ContainmentBuilding Spray system and Reactor Makeup Wafer Storage Tank in the Reactor makeup Water System will be age managedusing the Aboveground Steel Tanks Proaram.

United States Nuclear Regulatory Commission Page 32 of 45 SBK-L- 14037/ Enclosure 1 3.4.1-6 Steel and Loss of material Water Yes, detection of Components in the Chemical and Volume stainless steel due to general (steel Chemistry aging effects is Control, Containment Building Spray, Fuel tanks exposed only) pitting and and One-Time to be evaluated Handling, Hot Water Heating, Mechanical to treated crevice corrosion Inspection Seal Supply, Reactor Coolant, Reactor Make-water Up Water, Release Recovery, and Sample systems have been aligned to this line item based on material, environment, and aging effect.

Consistent with NUREG-1801. The One-Time Inspection Program, B.2.1.20, will be used to verify the effectiveness of the Water Chemistry Program, B.2.1.2, to manage loss of material due to general, pitting, and crevice corrosion in steel tanks exposed to treated water in the Auxiliary Steam Condensate, Fuel Handling, Hot Water Heating, Release Recovery, and Steam Generator Blowdown systems, and to manage pitting and crevice corrosion in the stainless steel tanks exposed to treated water in the Chemical and Volume Control, Containment Building Spray, Condensate, Mechanical Seal Supply, Reactor Coolant, Reactor Make-Up Water. and Sample systems.

CondensateStorage Tank in the Condensate system will be age managedusing the A bovegroundSteel Tanks Progranm See Subsection 3.4.2.2.2.1 for steel tanks and Subsection 3.4.2.2.7.1 for stainless steel tanks.

United States Nuclear Regulatory Commission Page 33 of 45 SBK-L- 1403 7/ Enclosure 1 E. In LRA Sections 3.2, 3.3, and 3.4, Tables 3.2.2-2, 3.3.1-3 1, and 3.4.2-5 have been revised as follows:

a. Table 3.2.2-2, Containment Building Spray System, on Page 3.2-53, new AMR line items have been added after the 5 th line item as follows:

A new Plant Specific Note I has been added as follows:

1 Consistent with NUREG-1801 as modified by LR-ISG-2012-02

b. Table 3.3.1-31, Reactor Makeup Water System, on Page 3.3-431, the 3 rd, and 5 th AMR line items have been revised and a new line item has been added after the 5 th line item as follows:

United States Nuclear Regulatory Commission Page 34 of 45 SBK-L- 14037/ Enclosure 1 A new Plant Specific Note 2 has been added as follows:

2 Consistent with NUREG-1801 as modified by LR-ISG-2012-02

c. Table 3.4.2-5, Condensate System, on Pages 3.4-73, the 9th AMR line item and the 1 st AMR line item on Page 3.4-74 have been revised as follows:

Aging NUREG Note Aging Effect Aging Effect Aging Vol. 2 NUREG 1801 Component Intended Management Table3.X.1 Material Environment Requiring Management 1801 Vol. 2 Note Type Function Item Management Program Item Nane Air-indoor NIH i 8-34.-I-41 TankBoundary Pressure Stainless A nne Aboveground ( A Steel Uncontrolled Cracking Steel Tanks A, 2 (External) Program None None suffaees Menite~ifg Tank Pressure Stainless Air-Outdoor Loss of P-ogram None None Boundary Steel (External) Material A, 2 Aboveground Steel Tanks Program Water pregf am A

One Tiee Pressure Stainless Treated Water Loss of VIII.E-40 Tank hispeetiea 3.4.1-6 Boundary Steel (Internal) Material (S-13) A PFOegramn A, 2 Aboveground Steel Tanks Program +i +

+i + .i Aboveground Pressure Stainless Soil or Loss of HJJJE-28 Tank Steel Tanks None A, 2 Boundar, Steel Concrete Material (SP-3 7)

Program A new Plant Specific Note 2 has been added as follows:

2 Consistent with NUREG-1801 as modified by LR-ISG-2012-02 F. In LRA Appendix B, Section B.2.1.17 (Above Ground Steel Tanks Program) has been revised as follows:

1. The 1 st and the 2 nd paragraphs of the program description has been revised as follows:

Seabrook Station Aboveground Steel Tanks Program is an existing program that manages the aging effects of loss of material due to general, pitting, and crevice corrosion and cracking on the outside and inside surfaces of aboveground steel tanks within the scope of

United States Nuclear Regulatory Commission Page 35 of 45 SBK-L- 14037/ Enclosure 1 License Renewal. The Program includes preventive measures to mitigate corrosion and crackingand periodic inspections to validate the effectiveness of the preventive actions.

The program includes outdoor tanks within the scope of License Renewal and indoor large volume storage tanks (greaterthan 100,000 gallons) designed to near-atmospheric internalpressures,sit on concrete or soil, and exposed internally to water. Fire water storage tanks are not within the scope of this programand managed separatelyunder the Fire Water System aging management program. Tank inside and outside surfaces are inspected by visual, surface, or volumetric examinations as required to detect the applicableaging effect.

2. Enhancement Ia has been revised as follows:

Include the Fire Protection Fuel Oil Tanks, Auxiliary Boiler Fuel Oil Storage Tank, Refueling Water Storage Tank, Reactor Makeup Water Storage Tank, and Condensate Storage Tank in the scope of Aboveground Steel Tanks Program.and Fire Protection Watef Storage tanks as pa.t of the scJpe of tankL.s.

3. Enhancement 2 has been revised as follows:

Enhance the Seabrook Station Aboveground Steel Tanks Program implementing procedures to require the performance of visual, surface, and volumetric examinations of the Fire Protection Fuel Oil Tanks, Auxiliary Boiler Fuel Oil Storage Tank, Refueling Water Storage Tank, Condensate Storage Tank, and Reactor Makeup Water Storage Tank asfollows: an ultr-asonic examination and evaluation of the internal bottom surface of the t~w Fire Proecetion Wlater Storage Tanks within ten years prior to the periodo extended operation.

a. For managingloss of materialon the internalsurfaces of stainless steel Refueling Water Storage Tank, Reactor Makeup Water Storage Tank, and Condensate Storage Tank exposed to treated-wateror treated borated water, visual inspections will be performedfrom inside the tank or volumetric examinationsfrom outside tank using the One-Time Inspection Program.At least 25 percent of the tank's internalsurface will be inspected by a method capable of precisely determining wall thickness. The inspection method must be capable of detecting both general and pitting corrosion and must be qualified and demonstratedeffective by the applicant.

The one-time inspection must occur within the 5-year periodprior to enteringthe PEO.

b. For managingcracking on the externalsurfaces of stainless steel Refueling Water Storage Tank, Reactor Makeup Water Storage Tank, and CondensateStorage Tank exposed to air-indooruncontrolled,surface examinations will be performed each 10-yearperiod starting10 years before the period of extended operation.A minimum of either a combination of 25 1-square-footsectionsfor tank surfaces

United States Nuclear Regulatory Commission Page 36 of 45 SBK-L- 1403 7/ Enclosure 1 andfor welds, I-linear-footof weld length; or 20percent of the tank's surface are examined. The sample inspectionpoints are distributedsuch that inspections occur in those areas most susceptible to cracking (e.g., areas where contaminants could collect, inlet and outlet nozzles, welds).

c. For managing loss of material on the external surfaces of stainless steel Condensate Storage Tank exposed to air-outdoor, visual examinations of the outside surfaces will be performed each refueling outage. For potential cracking on the external surfaces of stainless steel Condensate Storage Tank exposed to air-outdoor, surface examinations will be performed each 10-year period starting 10 years before the period of extended operation.

d. For managing loss of materialon the externalsurfaces of Refueling Water Storage Tank, Reactor Makeup Water Storage Tank, and Condensate Storage Tank bottoms exposed to soil or concrete, volumetric examinations will be performed from inside the tanks each 10-year period starting 10years before the period of extended operation*

e. For managing loss of material on the external surfaces of steel Fire Protection Fuel Oil Tanks and A uxiliary Boiler Fuel Oil Storage Tank exposed to air-outdoor, visual examinationsof the outside surfaces will be performed every 18-months f For managing loss of material on the external surfaces of steel Fire Protection Fuel Oil Tanks and Auxiliary Boiler Fuel Oil Storage Tank bottoms exposed to soil or concrete, volumetric examinations will be performedfrom inside the tanks each 10-year period starting 10 years before the period of extended operation. A one-time inspection conducted in accordance with GALL Report AMP XI.M32 may be conducted in lieu of periodic inspections if an evaluation conducted prior to the PEO and during each 10-year period during the PEO demonstrates that the soil under the tank is not corrosive using actual soil samples that are analyzedfor each individual parameter (e.g., resistivity, pH, redox potential, sulfides, sulfates, moisture) and overall soil corrosivity. The evaluation should include soil sampling front underneath the tank.

G. In LRA Appendix B, Section B.2.1.20 (One-Time Inspection Program), on page B- 118, a new bullet has been added under the section titled "This program will be used to" as follows:

• For potential loss of material on the internalsurfaces of stainless steel Refueling Water Storage Tank, Reactor Makeup Water Storage Tank, and Condensate

United States Nuclear Regulatory Commission Page 37 of 45 SBK-L- 1403 7/ Enclosure 1 Storage Tank exposed to treated-wateror treated borated water, visual inspections will be performedfrom inside the tank or volumetric examinationsfront outside tank using the One-Time Inspection Program. At least 25 percent of the tank's internalsurface will be inspected by a method capable of precisely determining wall thickness. The inspection method must be capable of detecting both general and pitting corrosion and must be qualified and demonstrated effective by NextEra Seabrook.

H. In LRA Appendix A, Section A.2.1.17 (Above Ground Steel Tanks Program), the 1st paragraph has been revised and a new 2nd paragraph has been added as follows:

The Aboveground Steel Tanks Program manages the aging effects thrugh pr-eventive measures to m..itigate c.orrsi, of loss of materialand cracking on the outside and inside surfaces of and through per-iodic inspections to mfanage any cffects of ofrrosion o aboveground steeM tanks within the scope of License Renewal.

Tanks within the scope of this program include all in-scope outdoor tanks, except fire water storage tanks, constructed on soil or concrete. Indoor large volume storage tanks (greaterthan 100,000 gallons) designed to near-atmosphericinternalpressures, sit on concrete or soil, and exposed internally to water are included within the scope of this program. Tank inside and outside surfaces are inspected by visual, surface, or volumetric examinations as requiredto detect the applicableaging effect.

I. In LRA Appendix A, Section A.2.1.20 (One-Time Inspection Program), the following new bullet has been added to the end of the program description as follows:

Forpotential loss of material on the internalsurfaces of stainless steel Refueling Water Storage Tank, Reactor Makeup Water Storage Tank, and Condensate Storage Tank exposed to treated-wateror treated borated water, visual inspections will be performed from inside the tank or volumetric examinationsfro"? outside tank using the One-Time Inspection Program.At least 25 percent of the tank's internalsurface will be inspected by a method capable of precisely determining wall thickness. The inspection method must be capable of detecting both general and pitting corrosion and must be qualified and demonstrated effective by Seabrook Station.

United States Nuclear Regulatory Commission Page 38 of 45 SBK-L- 14037/ Enclosure 1 J. In LRA Appendix A, Section A.3, commitment #12 has been revised as follows:

PROGRAM or UFSAR No. TOPIC TOPIC COMMITMENT LOCAT LOCATION SCHEDULE Enhance the program to include components Prior-to the period of and aging effects required by the Aboveground extended operation.

12. Aboveground Steel Tanks and to perform visual, surface, and A.2.1.17 Within lOyears Steel Tanks volumetric examinationsof the outside and priorto Me period inside surfacesfor managingthe aging effects of extended of loss of materialand cracking. operation LR-ISG-2012-02: Corrosion Under Insulation Seabrook Station will perform periodic representative inspections of in-scope insulated steel, stainless steel, copper alloy, aluminum, or copper alloy >15% Zn piping, piping components, and tanks exposed to condensation or air-outdoor. The LRA changes related to the timing, frequency, and extent of these inspections are as follows:

A. LRA Section 2.1.3, "Insulation", on page 2.1-23 and 2.1-24 has been revised as follows:

At Seabrook Station, thermal insulation was treated as a passive, long lived component during the scoping and screening process. There is no aging effect for thermal insulation in an "air-indoor uncontrolled" environment, however, aluminum insulation jacketing in "air with borated water leakage environment" would have an aging effect of loss of material due to boric acid corrosion. This aging effect will be age managed by the Boric Acid Corrosion Program. Additionally, visual inspections are conducted on insulationjacketing under the External Surfaces Monitoring Program to ensure that no aging effects are impairing the function of the thermal insulation. The intended function for "Insulation" per Table 2.1-1 is "Provide temperature control."

For license renewal purposes, thermal insulation jacketing is being addressed as a commodity group in the civil / structural section of the license renewal application. Therefore, insulation is not included as a separate component type in each mechanical in scope system. The thermal insulation jacketing is shown in Table 3.5.2-6.

B. In LRA Appendix B, in Section B.2.1.24 (External Surfaces Monitoring), on page B-133, the 3 rd paragraph has been removed from the Program Description as shown below:

The Scabr-ok Station Exte..al Surfaces M. nit.ring Program will re-uire a peo dic r.evie' of deumentd under insulation inspection res.lts to ver.i. that there we a suffi.ient number of inspectien opportunities to provide a representative indieation of system eendifien, and to assess the need for-farther-insetos

United States Nuclear Regulatory Commission Page 39 of 45 SBK-L- 1403 7/ Enclosure 1 C. License Renewal Application, Appendix B, Section B.2.1.24 (External Surfaces Monitoring),

on page B-135, the following new paragraphs have been added to end of the Program Description as follows:

The External Surfaces Monitoring Program includes visual inspections on insulation jacketing to ensure that no aging effects are impairing the function of the thermal insulation. The External Surfaces Monitoring Program also includes examination of surfaces under insulation. For systems that are within the scope of License Renewal and susceptible to corrosion under insulation, removal of insulation and inspections will be performed duringeach 1 0-yearperiod of the PEO.

For in-scope outdoor components (except tanks) that are insulated and in-scope indoor components that are exposed to condensation (in-scope components are operated below the dew point), removal of insulation and inspection will be performed asfollows:

1) 20% of the piping length for each material type or 20% of the surface area for components where its configuration does not conform to a 1-foot axial length determination(e.g., valve, accumulator)or,

2) Any combination of 25 1-foot axial length sections and componentsfor each material type. Inspections will be conducted in each air environment (e.g., air-outdoor,moist air) where condensation or moisture on the surfaces of the component could occur routinely or seasonally. In some instances, although indoor air is conditioned, significantmoisture can accumulate under insulation during high humidity seasons.

For outdoor tanks and indoor tanks exposed to condensation, remove the insulationfront either 25 1-square-foot sections or 20 percent of the surface area and inspect the exterior surface of the tank. The sample inspection points should be distributed such 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 such as on top of stiffening rings.

Inspection locations should be based on the likelihood of corrosion under insulation occurring (e.g., alternate wetting and drying in environments where trace contaminants could be present,length of time the system operates below the dewpoint).

Removal of tightly adhering insulation that is impermeable to moisture is not required unless there is evidence of damage to the moisture barrier.If the moisture barrieris intact, the likelihood of corrosion under insulation is low for tightly adhering insulation. Tightly adhering insulation should be considered to be a separatepopulationfrom the remainder of insulation installed on il-scope components. The entire population of in-scope piping that has tightly adhering insulation should be visually inspected for damage to the moisture barrier with the same frequency as for other types of insulation inspections.

These inspections would not be credited towards the inspection quantitiesfor other types of insulation.

Subsequent inspections may consist of examination of the exterior surface of the insulation for indications of damage to the jacketing or protective outer layer of the insulation when the following conditions are verified in the initialinspection:

United States Nuclear Regulatory Commission Page 40 of 45 SBK-L- 1403 7/ Enclosure I

i. no loss of materialdue to general,pitting or crevice corrosion, beyond that which could have been present during initialconstruction, and ii. no evidence of SCC.

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 should continue as describedabove.

D. In the Enhancements section of B.2.1.24 (External Surfaces Monitoring), on Page B-137, a 2 "denhancement has been added as follows:

2. Seabrook Station procedures will be enhanced to include periodic inspectionsof in-scope insulatedcomponentsfor possible corrosion under insulation.

ProgramElements Affected: Element 1 (Scope of Program)and Element 4 (Detection of Aging Effects)

E. In LRA Appendix A, in Section A.2.1.24 (External Surfaces Monitoring), on Page A-14, a new paragraph has been added after the last paragraph as follows:

The External Surfaces Monitoring Program includes periodic inspections of ill-scope insulatedcomponentsfor possible corrosion under insulation.

F. In LRA Appendix A, in Section A.3 (License Renewal Commitment List), commitment #26 has been revised as follows:

Enhance the program to specifically address the scope of the program, relevant degradation mechanisms and effects of interest, the refueling Prior to the

26. Surfaces outage inspection frequency, the inspectionset A.2.1.24 period of M 6nitorfas pp Hni'for-pssible ccosion under- isulation, A M onitoringe, ....  :-,v.... ..... ... ...... extended the training requirements for inspectors and the operation.

required periodic reviews to determine program effectiveness.

G. In LRA Appendix A, in Section A.3 (License Renewal Commitment List), a new commitment #78 has been added as follows:

Priorto the External Enhance the programto includeperiodic inspections periodof

78. Surfaces of in-scope insulatedcomponents for possible A.2.1.8 eriodeo Monitoring corrosion under insulation. erten.

operation.

United States Nuclear Regulatory Commission Page 41 of 45 SBK-L- 1403 7/ Enclosure 1 H. The following new component types have been added to Tables 2.3.3-4 (Chlorination System), 2.3.3-10 (Demineralized Water System), 2.3.3-12 (Diesel Generator), 2.3.3-15 (Fire Protection System), 2.3.3-27 (Potable Water System), 2.3.3-29 (Primary Component Cooling Water System), 2.3.3-37 (Service Water System), 2.3.4-2 (Auxiliary Steam Condensate System), 2.3.4-4 (Circulating Water System), 2.3.4-5 (Condensate System), 2.3.4-6 (Feedwater System), and 2.3.4-7 (Main Steam System),.

• InsulatedPipingand Fittings I. The following new AMR line items have been added as follows:

a. Table 3.3.2-9, Control Building Air Handling System, on Page 3.3-244, the following line items have been added as follows:

A new Plant Specific Note 13 has been added as follows:

13 Consistent with NUREG-1801 as modified by LR-ISG-2012-02

b. Table 3.3.2-10, Demineralized Water System, on Page 3.3-254, the following line items have been added as follows:

A new Plant Specific Note 1 has been added as follows:

1 Consistent with NUREG-1801 as modified by LR-ISG-2012-02

United States Nuclear Regulatory Commission Page 42 of 45 SBK-L- 1403 7/ Enclosure 1

c. Table 3.3.2-12, Diesel Generator, on Page 3.3-279, the following line items have been added as follows:

Intended Aging Effect Aging NUREG Table Component Material Environment Requiring Management 1801 Vol. 2 3.X.I Note Type Function Management Program Item Item Insulated Pressure Condensation ExternalSurfaces Piping and Boundary Steel (E.xternal Loss of Material Monitoring None None B, 12 Fittings Program A new Plant Specific Note 12 has been added as follows:

12 Consistent with NUREG-1801 as modified by LR-ISG-2012-02

d. Table 3.3.2-15, Fire Protection System, on Page 3.3-309, the following line items have been added as follows:

Component Intended Aging Effect Aging NUREG Table Cope Inten Material Environment Requiring Management 1801 Vol. 2 3.X.1 Note Type Function Management Program Item Item Insulated Pressure Condensation External Surfaces Piping and Steel Loss of Material Monitoring None None B, 6 Fittings Boundary (External) Program A new Plant Specific Note 6 has been added as follows; 6 Consistent with NUREG-1801 as modified by LR-ISG-2012-02

e. Table 3.3.2-27, Potable Water System, on Page 3.3-396, the following line items have been added as follows:

Intended Aging Effect Aging NUREG Table Component Function Material Environment Requiring Management 1801 Vol. 2 3.X.1 Note Type Management Program Item Item Insulated Leakage Copper Condensation External Surfaces Pipingand Boundary Loss of Material Monitoring None None B, 2 Fittings (Spatial) Alloy (External) Program Insulated Leakage Condensation ExternalSurfaces Pipingand Boundary Steel (External) Loss of Material Monitoring None None B, 2 Fittings (Spatial) Program A new Plant Specific Note 2 has been added as follows:

2 Consistent with NUREG-1801 as iodified by LR-1SG-2012-02

United States Nuclear Regulatory Commission Page 43 of 45 SBK-L- 14037/ Enclosure 1

f. Table 3.3.2-28, Primary Auxiliary Building Air Handling System, on Page 3.3-403, the following line items have been added as follows:

A new Plant Specific Note 3 has been added as follows; 3 Consistent with NUREG-1801 as modified by LR-ISG-2012-02

g. Table 3.3.2-29, Primary Component Cooling water System, on Page 3.3-413, the following line item has been added as follows:

Component Intended Aging Effect Aging NUREG Table Cope Fnten Material Environment Requiring Management 1801 Vol. 2 3.X.1 Note Type Function Management Program Item Item Leakage Insulated Boundary External Surfaces Pipingand (Spatial) Copper Condensation Loss of Material Monitoring None None B, 8 Fittings Pressure Allay (External) Program Boundary Leakage Insulated Boundary External Surfaces Piping and (Spatial) StainlessSte Condensation Etra)Loss ofMaterial Externa Surfnces oMaeilMonitoring None None B, 8 Fittingsan Steel (External) Program Boundary Leakage Insulated Piigad Boundary (Spatial) Stainless CondensationExenlSras ExternalSurfaces Piping and ( enat Cracking Monitoring None None B, 8 Fittings Pressure Steel (External) Program Boundary Leakage Insulated BoundaryExternal Surfaces Piping anid (Spatial) Steel Condensation Loss ofMaterial Monitoring None Nomre B, 8 Fillings Pressure Program Boundary 1___1_____ 1___1 A new Plant Specific Note 8 has been added as follows; 7 Consistent with NUREG-1801 as modified by LR-ISG-2012-02

United States Nuclear Regulatory Commission Page 44 of 45 SBK-L- 14037/ Enclosure 1

h. Table 3.3.2-37, Service Water System, on Page 3.3-470, the following line item has been added as follows:

Component Intended Aging Effect Aging NUREG Table Environment Requiring Management 1801 Vol. 2 3.X.I Note Type Function Material Management Program Item Item Insulated Pressure Condensation/ External Surfaces Pipingand rd Steel Air-Outdoor Loss of Material Monitoring None None B, 9 Fittings younda (External) Program A new Plant Specific Note 9 has been added as follows; 9 Consistent with NUREG-1801 as modified by LR-ISG-2012-02

i. Table 3.4.2-5, Condensate System, on Page 3.4-73, the following line item has been added as follows:

Component Intended Aging Effect Aging NUREG Table Copent nten Material Environment Requiring Management 1801 Vol. 2 3.X.I Note Type Function Management Program Item Item Insulated Pressure Stainless Condensation External Surfaces Piping and Loss of Material Monitoring None Notre B, 2 Fittings Boundar, Steel (External) Program Insulated Pressure Stainless Condensation External Surfaces Piping and Bd Steel Celt Cracking Monitoring None None BA 2 Fittings Boundary Steel (External) Program Insulated Pressure Condensation External Surfaces Piping and ure Steel Loss of Material Monitoring None None B. 2 Fittings Boundary (External) Program A new Plant Specific Note 2 has been added as follows; 2 Consistent with NUREG-1801 as modified by LR-ISG-2012-02

j. Table 3.4.2-6, Feedwater System, on Page 3.4-84, the following line item has been added as follows:

Component Intended Aging Effect Aging NUREG Table Cope Inten Material Environment Requiring Management 1801 Vol. 2 3.X.I Note Type Function Management Program Item Item Insulated Pressure Air-Outdoor External Surfaces Piping and Boundary Steel (External) Loss of Material Monitoring None None B, I Fittings Program A new Plant Specific Note 1 has been added as follows:

United States Nuclear Regulatory Commission Page 45 of 45 SBK-L- 14037/ Enclosure 1 1 Consistent with NUREG-1801 as modified by LR-ISG-2012-02

k. Table 3.4.2-7, Main Steam System, on Page 3.4-94, the following line item has been added as follows:

A new Plant Specific Note 2 has been added as follows:

2 Consistent with NUREG-1801 as modified by LR-ISG-2012-02

1. Table 3.5.2-6, Supports, on page 3.5-239, the following line item has been added as follows:

Aging Effect Aging NUREG Table Component Intended Function Material Environment Requiring Management 1801 Vol. 2 3.X.1 Note Type Management Program Item Item Air-Indoor Reduced Jacketed Structural Fiberglass Uncontrolledi Thermal External Surfaces B, Insulation Support Air-Outdoor Insulation Monitoring None None 517 (Exlernal) Resistance Program A new Plant Specific Note 517 has been added as follows:

517 Consistent with NUREG-1801 as modjfied by LR-ISG-2012-02

Enclosure 2 to SBK-L-14037 Service Level III (augmented)

Aging Management of Loss of Coating Integrity for Internal Coatings

United States Nuclear Regulatory Commission Page 2 of 16 SBK-L-14037 / Enclosure 2 Aging Management of Loss of Coating Integrity for Internal Service Level III (augmented)

Coatings NextEra Energy Seabrook has components within the scope of License Renewal that are coated and subject to the aging effect of loss of coating integrity due to blistering, cracking, flaking, peeling, or physical damage.

The vast majority of the Service Water (SW) system piping is fabricated from butt welded, cement lined, carbon steel piping. During construction, joint compound was applied at field welded joints to seal the cement liner crevices. Defects or degradation of the joint compound as well as random defects in the cement lining allowed sea water intrusion to the carbon steel pipe and subsequent internal corrosion.. In some cases, corrosion has led to through wall leakage.

Repairs were made on-line or during the subsequent refueling outage with no loss of SW system function. Further discussion related to through wall leaks in the SW cement lined piping is provided in the "Recurring Internal Corrosion" section of this supplement letter.

Seabrook Station also has plant specific OE related to the degradation of the Plastisol PVC lining in the SW piping. In 1994, the cement SW piping associated with the Diesel Generator heat exchangers (DGHXs) was replaced with Plastisol PVC lined carbon steel piping. In July 2011, Service Water flow through the Train 'B' DGHX was identified as being degraded. Subsequent inspection of the Train 'B' DGHX downstream flow orifice revealed that pieces of the Plastisol PVC lining had detached from the pipe and was partially restricting flow through the orifice.

NextEra Seabrook has previously provided the staff details of the Plastisol PVC lining failure in SBK-L-12023 dated February 7, 2012 (Supplement 19, Enclosure 1), SBK-L-12084 dated April 26, 2012 (Supplement 22, Enclosure 1), and SBK-L-12217 dated November 2, 2012 (Supplement 27, Enclosure 2). As stated in SBK-L-12084, NextEra Seabrook made a commitment (Commitment #69) to replace the DGHX Plastisol PVC lined SW piping with piping fabricated from AL6XN material prior to entering the period of extended operation.

Plastisol PVC lined piping in the "A" train of the Diesel Generator Heat Exchanger (DGHX) piping was replaced with AL6XN material during Refueling Outage 15 (Fall of 2012). Replacement of the Plastisol PVC lined piping in the "B" train is scheduled for Refueling Outage 16 (Spring of 2014).

In response to NextEra Seabrook's review of draft LR-ISG-2013-01, "Aging Management of Loss of Coating Integrity For Internal Service Level III (Augmented) Coatings" and review of the Staffs questions to Sequoyah and Callaway, NextEra Energy Seabrook has made the following changes to the LRA to address aging effects of Service Level III (augmented) internal coatings. NextEra Energy Seabrook recognizes that LR-ISG-2013-01 is currently in the final stages of comment resolution and approval. Upon issuance, NextEra will evaluate the final version and subsequent revisions under the associated operating experience program elements.

Definition of Internal Service Level III (augmented) Coatings:

All coatings applied to the internal surfaces of an in-scope component if its degradation could prevent satisfactory accomplishment of any of the functions identified under 10 CFR 54.4 (a)(1),

(a)(2), or (a)(3). Service Level III (augmented) coatings are those:

United States Nuclear Regulatory Commission Page 3 of 16 SBK-L-14037 / Enclosure 2

a. Used in areas outside of the reactor containment whose failure could adversely affect the safety function of a safety-related SSC or,

b. Applied to the internal surfaces of in-scope components and whose failure could prevent satisfactory accomplishment of any of the functions identified under 10 CFR 54.4 (a)(3).

The term "coating" includes inorganic (e.g., zinc-based) or organic (e.g., elastomeric or polymeric) coatings, linings (e.g., rubber, cementitious), and concrete surfaces that are designed to adhere to a component to protect its surface. The terms "paint" and "linings" are considered as coatings.

The scope of the program changes include those components exposed to closed-cycle cooling water, raw water, treated water, treated borated water, fuel oil, and lubricating oil. Aging effects for these components will be managed as described below. Fire water storage tanks are not included in the scope of aging management of Service Level III (augmented) internal coatings.

As described in LR-ISG-2012-02, the internal surfaces of fire water storage tanks will be inspected to the requirements of NFPA 25 (Standard for the Inspection, Testing, and Maintenance of Water-Based Fire Protection Systems).

a. The inspection method The program changes consist of periodic visual inspections of Service Level III (augmented) internal coatings.

b. The parameters to be inspected The program includes visual inspections for indication of blistering, cracking, flaking, peeling, or physical damage.

c. When inspections will commence and the frequency of subsequent inspections

" Baseline visual inspections of coatings installed on the interior surfaces of in-scope components will be conducted in the 10-year period prior to the PEO.

" Subsequent inspections are based on an evaluation of the effect of a coating failure on the in-scope component's intended function, potential problems identified during prior inspections, and known service life history. Subsequent inspection intervals are established by a coating specialist. Inspection intervals however, will not exceed those shown in the below table.

United States Nuclear Regulatory Commission Page 4 of 16 SBK-L-14037 / Enclosure 2 Inspection Intervals for Internal Service Level III (augmented) Coatings for Tanks, Piping, and Heat Exchangers 1.6 Inspection Category 2 Inspection Interval A 6 years' B4 , 5 4 years C5 Inspections occur during the next 2 refueling outage intervals

1. Current licensing basis requirements (e.g. Generic Letter 89-13) might require more frequent inspections.

2. Inspection Categories A. No peeling, delamination, blisters, or rusting are observed during inspections. Any cracking and flaking has been found acceptable in accordance with the acceptance criteria. No spalling in cementitious coatings.

B. Prior inspection results do not meet Inspection Category A. However, a coating specialist has determined that no remediation is required.

C. Newly installed coatings or coatings that have been repaired or replaced.

3. If the following conditions are met, the inspection interval may be extended to 12 years:

a. The identical coating material was installed with the same installation requirements in redundant trains with the same operating conditions and at least one of the trains is inspected every 6 years.

b. The coating is not in a location subject to turbulence (e.g., piping downstream of control valve).

4. Specific locations that resulted in subsequent inspections being conducted to Inspection Category B or C are re-inspected as well as new locations.

5. When conducting inspections to Inspection Category B, if two sequential subsequent inspections demonstrate no change in coating condition, subsequent inspections may be conducted at six-year intervals.

6. Internal inspection intervals for diesel fuel storage tanks may meet either this table or if the inspection results meet Inspection Category A.

d. The extent of inspections The extent of inspections is based on an evaluation of the effect of a coating failure on the in-scope component's intended function, potential problems identified during prior inspections, and known service life history. Inspection locations are selected based on susceptibility to degradation and consequences of failure.

United States Nuclear Regulatory Commission Page 5 of 16 SBK-L-14037 / Enclosure 2

- All accessible internal coated surfaces of in-scope tanks and heat exchangers will be inspected.

- A representative sample of internally coated piping components not less than 73 1-foot axial length circumferential segments of piping or 50% of the total length of each coating material and environment combination will be inspected. The inspection surface includes the entire inside surface of the 1-foot sample. If geometric limitations impede movement of remote or robotic inspection tools, the number of inspection segments is increased in order to cover an equivalent of 73 1-foot axial length sections. For example, if the remote tool can only be maneuvered to view 1/3 of the inside surface, then 219 feet of pipe is inspected.

The above listed inspection of coatings may be omitted if the degradation of coatings cannot result in downstream effects such as reduction in flow, drop in pressure, or reduction in heat transfer for in-scope components. However, inspections are performed if corrosion rates or inspection intervals have been based on the integrity of the coatings. In this case, loss of coating integrity could result in unanticipated or accelerated corrosion rates of the base metal.

Alternatively, if corrosion of the base material is the only issue related to coating degradation of the component, external wall thickness measurements can be performed to confirm the acceptability of the corrosion rate of the base metal.

e. The training and qualification of individuals involved in coating inspections Coatings specialists and inspectors will be qualified in accordance with ASTM International Standards.

f. How monitoring and trending of coating degradation will be conducted Monitoring and trending includes pre-inspection reviews of the previous two inspection results and any subsequent repair activities. The review is performed by a coatings specialist and includes a list and location of all areas evidencing deterioration, a prioritization of the repair areas into areas that must be repaired before returning the system to service, areas where repair can be postponed to the next inspection, and, where possible, photographic evidence of inspection locations. When corrosion of the base material is the only issue related to coating degradation of the component, external wall thickness measurements can be used to in lieu of internal visual inspections of the coating and the corrosion rate of the base metal trended.

g. Acceptance criteria

- Indications of peeling and delamination are not acceptable and the coatings are repaired or replaced. For coated surfaces that show evidence of delamination or peeling, physical testing is performed where physically possible. The test consists of destructive or

United States Nuclear Regulatory Commission Page 6 of 16 SBK-L-14037 / Enclosure 2 nondestructive adhesion testing using ASTM International Standards. A minimum of three sample points adjacent to the defective area are tested.

- Blisters are evaluated by a coating specialist. However, inspections are conducted to ensure that the blister is completely surrounded by sound coating bonded to the surface.

If coatings are credited for corrosion prevention, the component's base material in the vicinity of the blister is inspected to determine if unanticipated corrosion has occurred.

- Indications such as cracking, flaking, and rusting are to be evaluated by a coating specialist.

- Minor cracking and spalling of cementitious coatings is acceptable provided there is no evidence that the coating is debonding from the base material.

- As applicable, wall thickness measurements meet design minimum wall requirements.

- Adhesion values provide reasonable assurance that the coating will remain bonded to the substrate as evaluated by the coating specialist.

h. Corrective actions for coatings that do not meet acceptance criteria, and Indications noted will be entered into the Seabrook Station Corrective Action Program for appropriate disposition.

i. The program(s) that will be augmented to include the above requirements.

The following programs will be augmented to include the above requirements:

- Open-Cycle Cooling Water System Program

- Fire Water System Program

- Fuel Oil Chemistry Program

- Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program Based on the above discussion, the following changes have been made to the LRA.

A. LRA Section 3.3, Aging Management of Auxiliary Systems and Section 3.4, Aging Management of Steam and Power Conversion Systems have been revised as follows:

1. The following new material has been added to Sections 3.3.2.1.1, Auxiliary Boiler, 3.3.2.1.4, Chlorination System, 3.3.2.1.12, Diesel Generator, 3.3.2.1.15, Fire Protection System, 3.3.2.1.17, Fuel Oil System, 3.3.2.1.26, Plant Floor Drain System, 3.3.2.1.36, Screen Wash System, 3.3.2.1.37, Service Water System, 3.4.2.1.44, Waste Processing Liquid System, and 3.4.2.1.4, Circulating Water System

United States Nuclear Regulatory Commission Page 7 of 16 SBK-L-14037 / Enclosure 2 Materials

• Metallic with Service Level III (augmented)InternalCoating

2. The following new AMR line items have been added as follows:

a. Table 3.3.2-1, Auxiliary Boiler, on Page 3.3-133, the following line item has been added as follows:

Aging Effect Aging NUREG Table Component Intended Material Environment Requiring Management 1801 Vol. 2 3.X.1 Note Type Function Management Program Item Item Metallic with Service Level Fuel Oil Tank Pressure III Fuel Oil Loss of Coating Chemistry None None G Boundary (augmented) (Internal) Integrity Program Internal Coating

b. Table 3.3.2-4, Chlorination System, on Page 3.3-190, the following line item has been added as follows:

Aging Effect Aging NUREG Table Component Intended Material Environment Requiring Management 1801 Vol. 2 3.X.1 Note Type Function Management Program Item Item Metallic with Inspection of InternalSurfaces Service Level Leakage in Miscellaneous ar I Raw Water Loss of Coating Piping and None None G Fittings (Spatial) (augmented) (Internal) Integrity Ducting Intern:al Components Coating Program

c. Table 3.3.2-12, Diesel Generator, on Page 3.3-285, the following line item has been added as follows:

Aging Effect Aging NUREG Table Component Intended Environment Requiring Management 1801 Vol. 2 3.X.1 Note Type Function Material Management Program Item Item Metallic with Service Level Fuel Oil Tank Pressure III Fuel Oil Loss of Coating Ciemistry None None G Boundary (augmented) (Internal) Integrity Program Internal Coating

United States Nuclear Regulatory Commission Page 8 of 16 SBK-L-14037 / Enclosure 2

d. Tables 3.3.2-15, Fire Protection System, on Pages 3.3-309 and 3.3-311, the following line items have been added as follows:

Aging Effect Aging NUREG Table Component Intended Material Environment Requiring Management 1801 Vol. 2 3.X.1 Note Type Function Management Program Item Item Metallic with Service Level Piping and Pressure III Raw Water Loss of Coating Fire Water System None None G Fittings Boundary (augmented) (Internal) Integrit. Program Internal Coating

e. Table 3.3.2-26, Plant Floor Drain System, on Page 3.3-392, the following line item has been added as follows:

Component Intended Aging Effect Aging NUREG Table Type Fntin Material . Environment Requiring Management 1801 Vol. 2 3.X.I Note Type Function Management Program Item Item Metallic with Inspection of Service Level InternalSurfaces Leakage III Raw Water Loss of Coating in Miscellaneous Tank Boundary Integrit, Piing Ductingand None None G (Spatial) (augmented) (Internal)

(Spatial) InternalDutn CoaternaComponents Coating Program

f. Table 3.3.2-36, Screen Wash System, on Page 3.3-459, the following line item has been added as follows:

Intended Aging Effect Aging NUREG Table Component Material Environment Requiring Management 1801 Vol. 2 3.X.J Note Type Function Management Program Item Item Metallic with Inspection of Service Level InternalSurfaces Piping and Leakage I in Miscellaneous Fiting Boundary III Raw Water Loss of Coating Piping and None None G Fittings (Spatial) (augmented) (Internal) Integrity Ducting Internal Components Coating Program

United States Nuclear Regulatory Commission Page 9 of 16 SBK-L-14037 / Enclosure 2

g. Table 3.3.2-37, Service Water System, on Page 3.3-470, the following line item has been added as follows:

Component Intended Aging Effect Aging NUREG Table Cope Fnten Material Environment Requiring Management 1801 Vol. 2 3.X.I Note Type Function Management Program Item Item Metallic with Service Level Piping and Pressure 111 Raw Water Loss of Coating Open-Cyncle Fittings Boundary (augmented) (Internal) Integrity System Program Internal Coaling

h. Table 3.4.2-44, Waste Processing Liquid System, on Page 3.4-508, the following line item has been added as follows:

Aging Effect Aging NUREG Table Component Intended Material Environment Requiring Management 1801 Vol. 2 3.X.1 Note Type Function Management Program Item Item Metallic with Inspection of Service Level InternalSurfaces Piping and Leakage II1 Raw Water Loss of Coating in Miscellaneous Boundary Piping and None None G Fittings (Spatial) (augmented) (Internal) Integritv Ducting (Spatial) InternalDutn Coternal Components Coating Program

i. Table 3.4.2-4, Circulating Water System, on Page 3.4-67, the following line item has been added as follows:

Aging Effect Aging NUREG Table Component Intended Environment Requiring Management 1801 Vol. 2 3.X.1 Note Type Function Material Management Program Item Item Metallic with Piping and Leakage Service Level W Open-Cycle Fiting Boundary III Raw Water Loss of Coating Cooling Water None None G Fittings (Spatial) (augmented) (Internal) Integrit, System Program Internal Coating B. LRA Appendix B, Section B.2, Aging Management Programs, has been revised as follows:

1. In LRA Section B.2. 1.11, Open-Cycle Cooling Water System, the 1st paragraph of the program description has been revised as follows:

United States Nuclear Regulatory Commission Page 10 of 16 SBK-L-14037 / Enclosure 2 The Seabrook Station Open-Cycle Cooling Water System Program is an existing program that manages the aging effects of:

a. hardening and loss of strength due to elastomer degradation,

b. loss of material due to erosion, due to general, pitting, crevice and galvanic corrosion, due to microbiologically influenced corrosion and fouling and due to liner/coating degradation, and

c. reduction of heat transfer by fouling of specific components, and

d. loss of coating integrity due to blistering, cracking,flaking, peeling, or physical damage of Service Level III (augmented)internalcoatings.

2. In LRA Section B.2.1.16, Fire Water System, the 1 st paragraph of the program description has been revised as follows:

The Seabrook Station Fire Water System Program is an existing program that manages the effects of aging on Fire Water System components through detailed inspections in accordance with the Seabrook Station Surveillance Test Procedures. Specifically, the program manages the following aging effects: (a) loss of material due to general, crevice, pitting, galvanic, and microbiologically influenced corrosion, (b) fouling, and (c) reduction of heat transfer due to fouling of the Fire Water System components, and loss of coating integrity due to blistering,cracking,flaking, peeling, or physical damage of Service Level III (augmented)internalcoatings.

3. In LRA Section B.2.1.18, Fuel Oil Chemistry, the 1st paragraph of the program description has been revised as follows:

The Seabrook Station Fuel Oil Chemistry Program is an existing program that manages the aging effects of loss of material due to general, pitting, crevice, galvanic, and microbiologically influenced corrosion, and due to fouling in the diesel fuel oil systems for the Emergency Diesel Generators, diesel engine driven Fire Protection system pumps, and the Auxiliary Boiler fuel oil system, through monitoring and maintenance of diesel fuel oil quality. The program also manages loss of coating integrity due to blistering, cracking, flaking, peeling, or physical damage of Service Level III (augmented) internal coatings. The program complies with the Seabrook Station Technical Specifications and associated Technical Requirements.

4. In LRA Section B.2.1.25, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components, thelst paragraph of the program description has been revised as follows:

The Seabrook Station Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is a new program that will manage the aging effects of (a) cracking due to stress corrosion cracking, (b) loss of material due to general, pitting, crevice, galvanic and microbiologically influenced corrosion and due to fouling (c) loss of material

United States Nuclear Regulatory Commission Page 11 of 16 SBK-L-14037 / Enclosure 2 due to erosion and wear (d) reduction of heat transfer due to fouling, and (e) hardening and loss of strength due to elastomer degradation, and ]) loss of coating integrity due to blistering, cracking, flaking, peeling, or physical damage of Service Level III (augmented) internal coatings. This program will consist of inspections of the internal surfaces of aluminum, cast austenitic stainless steel, copper alloy, copper alloy >15% Zn, elastomer, galvanized steel, gray cast iron, nickel alloy, stainless steel, and steel piping, piping components, ducting and other components that are not covered by other aging management programs.

5. In LRA Sections B.2.1.11, Open-Cycle Cooling Water System, B.2.1.16, Fire Water System, B.2.1.18, Fuel Oil Chemistry, and B.2.1.25, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components, the following has been added to the end of the program descriptions as follows:

Loss of Coating Integrityfor Service Level III (augmented)InternalCoatings:

The program also manages loss of internalcoating integrity due to blistering,cracking, flaking, peeling, or physical damage of Service Level III (augmented) internal coatings.

Definition of InternalService Level III (augmented) Coatingsis asfollows:

All coatings applied to the internal surfaces of an in-scope component if its degradation could prevent satisfactory accomplishment of any of the functions identified under 10 CFR 54.4 (a)(1), (a)(2), or (a)(3). Service Level III (augmented) coatings are those:

a. Used in areas outside of the reactor containment whose failure could adversely affect the safety function of a safety-relatedSSC or,

b. Applied to the internalsurfaces of in-scope components and whose failure could prevent satisfactory accomplishment of any of the functions identified under 10 CFR 54.4 (a)(3).

The term "coating" includes inorganic (e.g., zinc-based) or organic (e.g., elastomeric or polymeric) coatings, linings (e.g., rubber, cementitious), and concrete surfaces that are designed to adhere to a component to protect its surface. The terms "paint" and "linings" are consideredas coatings.

The program consists of periodic visual inspections of Service Level III (augmented) internalcoatings and includes:

a. Baseline visual inspections of coatings installedon the interiorsurfaces of in-scope components will be conducted in the 10-yearperiodprior to the period of extended operation.

United States Nuclear Regulatory Commission Page 12 of 16 SBK-L-14037 / Enclosure 2

b. Subsequent inspections are based on an evaluation of the effect of a coatingfailure on the in-scope component's intended function, potential problems identified during prior inspections, and known service life history. Subsequent inspection intervals are established by a coating specialist. Inspection intervals however, should not exceed those shown in the below table.

Inspection Intervalsfor InternalService Level III (augmented) Coatingsfor Tanks, I, 6 Piping,and Heat Exchangers Inspection Category2 Inspection Interval A 6years3 B 4, 5 4 years C" Inspections occur during the next 2 refueling outage intervals

1. Current licensing basis requirements (e.g. Generic Letter 89-13) might require more frequent inspections.

2. Inspection Categories A. No peeling, delamination, blisters, or rusting are observed during inspections. Any cracking andflaking has been found acceptable in accordance with the acceptance criteria.No spalling in cementitious coatings.

B. Prior inspection results do not meet Inspection Category A. However, a coating specialist has determined that no remediation is required.

C. Newly installedcoatings or coatings that have been repairedor replaced.

3. If the following conditions are met, the inspection interval may be extended to 12 years:

a. The identical coatingmaterialwas installed with the samte installationrequirements in redundant trains with the same operating conditions and at least one of tile trains is inspected every 6 years.

b. The coating is not in a location subject to turbulence (e.g., piping downstream of a control valve).

4. Specific locations that resulted in subsequent inspections being conducted to Inspection Category B or C are re-inspectedas well as new locations.

5. When conducting inspections to Inspection Category B, if two sequential subsequent inspections demonstrate no change in coating condition, subsequent inspections may be conducted at sit-year intervals.

6. Internalinspection intervalsfor dieselfuel storage tanks may meet either this table or if the inspection results meet Inspection Category A.

United States Nuclear Regulatory Commission Page 13 of 16 SBK-L-14037 / Enclosure 2

c. The extent of inspections is based on an evaluation of the effect of a coatingfailure on the in-scope component's intended function, potential problems identified during prior inspections, and known service life history. Inspection locations are selected based on susceptibility to degradationand consequences offailure.

- All accessible internal coated surfaces of in-scope tanks and heat exchangers will be inspected.

- A representativesample of internally coatedpipingcomponents not less than 73 1-foot axial length circumferential segments of piping or 50% of the total length of each coating material and environment combination will be inspected.

The inspection surface includes the entire inside surface of the 1-foot sample. If geometric limitations impede movement of remote or robotic inspection tools, the number of inspection segments is increasedin order to cover an equivalent of 73 1-foot axial length sections. For example, if the remote tool can only be maneuvered to view 1/3 of the inside surface, then 219feet of pipe is inspected.

The above listed inspection of coatings may be omitted if the degradation of coatings cannot result in downstream effects such as reduction ill flow, drop in pressure, or reduction in heat transfer for ill-scope components. However, inspections are performed if corrosion rates or inspection intervals have been based on the integrity of the coatings.In this case, loss of coating integrity could result in unanticipated or accelerated corrosion rates of the base metal. Alternatively, if corrosion of the base materialis the only issue related to coating degradationof the component, external wall thickness measurements can be performed to confirm the acceptability of the corrosionrate of the base metal.

d. Coatings specialists and inspectors will be qualified in accordance with ASTM InternationalStandards.

e. Monitoring and trending includes pre-inspection reviews of the previous two inspection results and any subsequent repairactivities. The review is performed by a coatings specialist and includes a list and location of all areas evidencing deterioration,a prioritization of the repair areas into areas that must be repaired before returningthe system to service, areas where repair can be postponed to the next inspection, amid, where possible,photographicevidence of inspection locations.

When corrosion of the base material is the only issue related to coating degradation of the component, external wall thickness measurements caml be used to in lieu of internal visual inspections of the coating amid the corrosion rate of the base metal trended.

f Acceptance criteriaare as follows:

United States Nuclear Regulatory Commission Page 14 of 16 SBK-L- 14037 / Enclosure 2

- Indicationsof peeling and delamination are not acceptable and the coatings are repairedor replaced.For coated surfaces that show evidence of delamination or peeling, physical testing is performed where physically possible. The test consists of destructive or nondestructive adhesion testing using ASTM InternationalStandards. A minimum of three sample points adjacent to the defective area are tested.

- Blisters are evaluated by a coating specialist. However, physical testing is conducted to ensure that the blister is completely surroundedby sound coating bonded to the surface. If coatings are credited for corrosion prevention, the component's base materialin the vicinity of the blister is inspected to determine if unanticipatedcorrosion has occurred.

- Indications such as cracking, flaking, and rusting are to be evaluated by a coatingspecialist.

- Minor cracking and spalling of cementitious coatings is acceptable provided there is no evidence that the coating is debondingfrom the base material.

- As applicable, wall thickness measurements meet design minimum wall requirements.

- Adhesion testing results meet or exceed the degree of adhesion recommended in engineering documents specific to the coating and substrate.

7. In LRA Sections 13.2.1.11, Open-Cycle Cooling Water System, B.2.1.16, Fire Water System, and 13.2.1.18, Fuel Oil Chemistry, the following new enhancement has been added to the enhancements section of the aging management programs:

Enhancements Enhance tieprogram to include visual inspection of Service Level III (augmented) internalcoatingsfor loss of coating integrity.

United States Nuclear Regulatory Commission Page 15 of 16 SBK-L-14037 / Enclosure 2 C. LRA Appendix A, Section A.2, Aging Management Programs, the program descriptions have been revised as follows:

1. In LRA Section A.2. 1.11, Open-Cycle Cooling Water System, the Is' paragraph has been revised as follows:

The Open-Cycle Cooling Water System Program manages the aging effects of hardening and loss of strength, loss of material, and reduction of heat transfer, and loss of coating integrity of Service Level III (augmented)internalcoatings.

2. In LRA Section A.2.1.16, Fire Water System, the 1 st paragraph has been revised as follows:

The Fire Water System Program manages the aging effects of loss of material, and reduction of heat transfer due to fouling of the Fire Water System components through detailed inspections via the Seabrook Station Surveillance Test Procedures. The program also manages loss of coating integrity of Service Level III (augmented) internal coatings.

3. In LRA Section A.2.1.18, Fuel Oil Chemistry, the last paragraph has been revised as follows:

Fuel Oil storage tanks are periodically drained and inspected. This inspection includes ultrasonic thickness measurements of the tank bottom surface to ensure that significant degradation has not occurred. The program also manages loss of coating integrity of Service Level III (augmented)internalcoatings.

4. In LRA Section A.2.1.25, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components, the Is paragraph has been revised as follows:

The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program manages the aging effects of cracking, loss of material, fouling, reduction of heat transfer, and hardening and loss of strength, and loss of coating integrity of Service Level III (augmented) internal coatings. This program consists of inspections of the internal surfaces of aluminum, CASS, copper alloy, copper alloy > 15% zinc, elastomer, galvanized steel, gray cast iron, nickel alloy, stainless steel, and steel piping, piping components, ducting and other components that are not covered by other aging management programs.

United States Nuclear Regulatory Commission Page 16 of 16 SBK-L-14037 / Enclosure 2 D. LRA Appendix A, Section A.3, License Renewal Commitment List, new commitments #79,

1. 80, #81, and #82 have been added as follows:

PROGRAM or UFSAR No. TOPIC COMMITMENT LOCATION SCHEDULE Enhance the programto include visual Open-Cycle inspection of Service Level III Within 10 years prior

79. Cooling Water (augmented) internalcoatingsfor loss of A.2.1.11 to the periodof System coating integrity. evtended operation Enhance theprogram to include visual inspectionof Service Level III Within 10yearsprior

80. Fire Water System (augmented)internalcoatingsfor loss of A.2.1.16 to the period of coating integrity. extended operation Enhance theprogram to include visual inspection of Service Level III Within 10 yearsprior

81. Fuel Oil Chemistry (augmented)internalcoatingsfor loss of A.2.1.18 to the period of coating integrity. e-tended operation Inspection of Enhance the programto include visual InternalSurfaces inspectionof Service Level III Within 10 yearsprior

82. in Miscellaneous (augmented)internalcoatingsfor loss of A.2.1.25 to the period of Piping and Ducting coating integrity, extended operation Components

Enclosure 3 to SBK-L-14037 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 Page 2 of 14 SBK-L-14037 / Enclosure 3 A.3 LICENSE RENEWAL COMMITMENT LIST UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Program to be implemented prior to the period of extended operation. Inspection plan to be

1. PWR Vessel Internals An inspection plan for Reactor Vessel Internals will be submitted A.2.1.7 submitted to NRC not later than 2 for NRC review and approval. years after 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 Heavyn of Overhead Load andvLightLad Enhance the program to monitor general corrosion on the crane and trolley structural components and the effects of wear on the A.2.1.13 Prior to the period of extended

3. Heavy Load and Light Load (Related to Refueling) rails in the rail system. operation.

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 requirement for the Diesel Generator compressed air sub system. operation.

Enhance the program to perform visual inspection of penetration Prior to the period of extended 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.

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.

United States Nuclear Regulatory Commission Page 3.of 14 SBK-L-14037 / Enclosure 3 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Enhance the program to include NFPA 25 (2011 Edition) guidance for "where sprinklers have been in place for 50 years, Prior to the period of extended

9. Fire Water System they shall be replaced or representative samples from one or A.2.1.16 operation.

more sample areas shall be submitted to a recognized testing laboratory for field service testing".

Enhance the program to include the performance of periodic flow Prior to the period of extended

10. Fire Water System testing of the fire water system in accordance with the guidance A.2.1.16 operation.

of NFPA 25 (2011 Edition).

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 to evaluate wall thickess and inner diameter of thefire protection piping ensuringthat corrosion product buildup will not result in flow blockage due to fouling.

Where surface irregularitiesare detected,follow-up volumetric Within ten years prior to the

11. Fire Water System exanduations are performed. These inspections will be A.2.1.16 period of extended operation.

documented and trended to determine if a representative number of inspections have been performed prior to the period 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.

Enhance the program to include components and aging effects required by the Aboveground Steel Tanks and to perform visual, .P.ri tohn d

12. Aboveground Steel Tanks surface, aiid volutmetric exvaminations of the outside and inside A.2.1.17 Wh .........

With in 10 ,ears prior to the surfacesfor managing the aging effects of loss of materialand periodof extended operation.

cracking.

Enhance the program to perform exteriorinspection of the fire Tankz water storage tanks annuallyfor signs of degradation amid Above-r...d t A.2116 perio tended prio n.

13. F reundS include an ultrasonic inspection and evaluation of the internal bottom surface of the two Fire Protection Water Storage Tanks per the guidance provided in NFPA 25 (2011 Edition).

United States Nuclear Regulatory Commission Page 4 of 14 SBK-L-14037 / Enclosure 3 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Enhance program to add requirements to 1) sample and analyze new fuel deliveries for biodiesel prior to offloading to the Prior to the period of extended Auxiliary Boiler fuel oil storage tank and 2) periodically sample operation.

stored fuel in the Auxiliary Boiler fuel oil storage tank.

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 at A.2.1.18 operation.

least once per quarter and to remove water as necessary.

Enhance the program to require draining, cleaning and inspection Prior to the period of extended

16. Fuel Oil Chemistry of the diesel fire pump fuel oil day tanks on a frequency of at A.2.1.18 operation.

least once every ten years.

Enhance the program to require ultrasonic thickness measurement of the tank bottom during the 10-year draining,

17. Fuel Oil Chemistry cleaning and inspection of the Diesel Generator fuel oil storage A.2.1.18 opera ttion.

tanks, Diesel Generator fuel oil day tanks, diesel fire pump fuel oil day tanks and auxiliary boiler fuel oil storage tank.

Enhance the program to specify that all pulled and tested

18. Reactor Vessel Surveillance capsules, unless discarded before August 31, 2000, are placed in A.2.1.19 operation.

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 capsule receives a neutron fluence that meets the schedule Prior to the period of extended

20. Reactor Vessel Surveillance A.2.1.19 oeain requirements of 10 CFR 50 Appendix H and ASTM E1 85-82 and operation.

that bounds the 60-year fluence, and the remaining capsule(s) will be removed from the vessel unless determined to provide meaningful metallurgical data.

United States Nuclear Regulatory Commission Page 5 of 14 SBK-L-14037 / Enclosure 3 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Enhance the program to ensure that any capsule removed, without the intent to test it, is stored in a manner which maintains Prior to the period of extended it in a condition which would permit its future use, including operation.

during the period of extended operation.

Within ten years prior to then.

Implement the One Time Inspection Program. A.2.1.20 perio tendedprio

22. One-Time Inspection 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

23. Materials components where selective leaching has not been identified and A.2.1.21 period of extended operation.

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 1 Within ten years prior to the

25. ASME Code Class I Small Small Bore-Piping Program. period 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 insp. tions

. f .pp..tunity for pessible c..r.si.n

..... undc 1.24 operation.

isultie,., -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 Miscellaneous A.2.1.25 Prior to the period of extended Piping and Ducting Piping and Ducting Components Program. operation.

Components

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

Enhance the program to sample the oil for the Reactor Coolant Prior to the period of extended

29. Lubricating Oil Analysis A.2.1.26 operation.

United States Nuclear Regulatory Commission Page 6 of 14 SBK-L-14037 / Enclosure 3 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION 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 of A2126 operation.

extended operation.

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.

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

Enhance procedure to include inspection of opportunity when 33.tProgram planning excavation work that would expose inaccessible A.2.1.31 operation.

concrete.

Electrical Cables and Connections Not Subject to Implement the Electrical Cables and Connections Not Subject to Prior to the period of extended

34. 10 CFR 50.49 10 CFR 50.49 Environmental Qualification Requirements A.2.1.32 operation.

Environmental program.

Qualification Requirements Electrical Cables and Connections Not Subject to 10 CFR 50.49 Implement the Electrical Cables and Connections Not Subject to Prior to the period of extended

35. Environmental 10 CFR 50.49 Environmental Qualification Requirements Used A.2.1.33 operation.

Qualification Requirements in Instrumentation Circuits program.

Used in Instrumentation Circuits Inaccessible Power Cables

36. Not Subject to 10 CFR Implement the Inaccessible Power Cables Not Subject to 10 CFR A.2.1.34 Prior to the period of extended 50.49 Environmental 50.49 Environmental Qualification Requirements program. operation.

Qualification Requirements Prior to the period of extended

37. Metal Enclosed Bus Implement the Metal Enclosed Bus program. A.2.1.35 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 14 SBK-L-14037 / 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. 10OCFR 50.49 EnvironmetalCFR A.2.1.37 50.49 Environmental Qualification Requirements program. operation.

Environmental Qualification Requirements 345 KV SF 6 Bus Implement the 345 KV SF6 Bus program. A.2.2.1 Prior to the period of extended 40.

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 count A.2.3.1 Prior to the period of extended Coolant Pressure Boundary transients to monitor cumulative usage on selected components. operation.

The updated analyses will be Pressure -Temperature Seabrook Station will submit updates to the P-T curves and submitted at the appropriate time

43. Limits, including Low LTOP limits to the NRC at the appropriate time to comply with A.2.4.1.4 to comply with 10 CFR 50 Temperature Overpressure 10 CFR 50 Appendix G. Appendix G, Fracture Toughness Protection Limits Requirements.

United States Nuclear Regulatory Commission Page 8 of 14 SBK-L-14037 / Enclosure 3 No. PROGRAM or TOPIC COMMITMENT UFSAR SCHEDULE LOCATION 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 At least two years prior to Environmentally-Assisted

44. environment. This includes applying the appropriate Fen factors A.2.4.2.3 entering the period of extended Fatigue Analyses (TLAA) to valid CUFs determined from an existing fatigue analysis valid operation.

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).

United States Nuclear Regulatory Commission Page 9 of 14 SBK-L-14037 / Enclosure 3 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION

45. Number Not Used Protective Coating Enhance the program by designating and qualifying an Inspector Prior to the period of extended Prontetnivo aiang Coordinator and an Inspection Results Evaluator. A.2.1.38 operation.

Maintenance Enhance the program by including, "Instruments and Equipment Protective Coating needed for inspection may include, but not be limited to, Prior to the period of extended

47. Monitoring and flashlight, spotlights, marker pen, mirror, measuring tape, A.2.1.38 prratote Maintenance magnifier, binoculars, camera with or without wide angle lens, and self sealing polyethylene sample bags."

ProtorCoating Enhance the program to include a review of the previous two Prior to the period of extended

48. Monitoring and monitoring reports. operation.

Maintenance Enhance the program to require that the inspection report is to be Protective Coating evaluated by the responsible evaluation personnel, who is to Prior to the period of extended Montenand prepare a summary of findings and recommendations for future A.2.1.38 operation.

surveillance or repair.

Within the next two refueling outages, OR I5 or OR16, and Perform UT testing of the containment liner plate in the vicinity A.2.1.27 repeated at intervals of no more ASME Section XI, Subsection IWE of the moisture barrier for loss of material. th a ivervals t outage than five refueling outages.

51. Number Not Used ASME Section XI, Implement measures to maintain the exterior surface of the

52. Containment Structure, from elevation -30 feet to +20 feet, in a A.2.1.28 Ongoing 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 do A.2.1.3 operation.

not exceed 150 ksi.

United States Nuclear Regulatory Commission Page 10 of 14 SBK-L-14037 / Enclosure 3 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 tube-to-Steam Generator Tube tubesheet weld inspections for the remaining life of the steam A.2.1.10 Complete Integrity 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 reactor coolant pressure boundary must be approved by the NRC as part of a license amendment request.

Within five years prior to Steam Generator Tube Seabrook will perform an inspection of each steam generator to A.2.1.10 entering the period of extended Integrity assess the condition of the divider plate assembly. operation.

Closed-Cycle Cooling Revise the operating station program ranges documents and Action toLevel reflect the EPRI values for A.2.1.12 Prior to entering extended the period of operation.

56. Guideline Water System

56. hydrazine and sulfates.

Closed-Cycle Cooling Revise the station program documents to reflect the EPRI Prior to entering the period of

57. Water SystemC 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 Prior to the period of extended

58. Fuel Oil Chemistry Testing Program) ASTM standards to ASTM D2709-96 and A.2.1.18 operation.

ASTM D4057-95 required by the GALL XI.M30 Rev 1

United States Nuclear Regulatory Commission Page 11 of 14 SBK-L-14037 / Enclosure 3 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION The Nickel Alloy Aging Nozzles and Penetrations program will

59. Nickel Alloy Nozzles and implement applicable Bulletins, Generic Letters, and staff A.2.2.3 Prior to the period of extended Penetrations accepted industry guidelines. operation.

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 with A.2.1.22 extended operation.

leak detection capability. extendedoperation.

61. Compressed Air Monitoring Replace the flexible hoses associated with the Diesel Generator A.2.1.14 Within ten years prior to entering Program 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 the

63. Flow Induced Erosion test procedure to state that an increase in the CVCS Charging N/A Prior to the period of extended Pump mini flow above the acceptance criteria may be indicative operation.

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 the vicinity of non-cathodically protected steel pipe within the scope A.21.22 Prior to entering the period of

64. Buried Piping and Tanks of this program. If the initial analysis shows the soil to be non- A extended operation.

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

Implement measures to ensure that the movable incore detectors Prior to entering the period of

65. Flux Thimble Tube are not returned to service during the period of extended N/A extended operation.

operation.

66. Number Not Used Perform one shallow core bore in an area that was continuously

67. Structures Monitoring wetted from borated water to be examined for concrete A.2.1.31 No later than December 31,2015.

Program degradation and also expose rebar to detect any degradation such as loss of material.

United States Nuclear Regulatory Commission Page 12 of 14 SBK-L-14037 / Enclosure 3 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Starting Januiary 2014.

Perform sampling at the leakoff collection points for chlorides, A.2.1.31 QuarterlyPreventive

68. Structures Monitoring Program sulfates, pH and iron once every three months. . MaintenanceActivity Implemented Open-Cycle Cooling Water Replace the Diesel Generator Heat Exchanger Plastisol PVC Prior to the period of extended

69. S yste lined Service Water piping with piping fabricated from AL6XN A.2.1.11 oratote System material. operation.

Inspect the piping downstream of CC-V-444 and CC-V-446 to

70. Closed-Cycle Cooling determine whether the loss of material due to cavitation induced A.2.1.12 Within ten years prior to the Water System erosion has been eliminated or whether this remains an issue in period of extended operation.

the primary component cooling water system.

Implement the Alkali-Silica Reaction (ASR) Monitoring

71. Alkali-Silica Reaction Program. Testing will be performed to confirm that parameters A.2.1.31A Prior to entering the period of (ASR) Monitoring Program being monitored and acceptance criteria used are appropriate to extended operation.

manage the effects of ASR.

Flow-Accelerated Enhance the program to include management of wall thinning A.2.1.8 Prior to entering the period of

72. Corrosion caused by mechanisms other than FAC. extended operation.

Enhance the program to include performance offocused Surnacspection ofinternexuaminationsto provide a representativesample of 20%, or a

73. Sfein Mine maximum of 25, of each identified material,environment, and A.2.1.25 Priorto entering the periodof Pipin ti aging effect combinations during each 10 year periodin the extended operation.

Components periodof extended operation.

Enhance the program to perform sprinklerinspections annually per the guidanceprovided in NFPA 25 (2011 Edition). hispection will ensure that sprinklers arefree of corrosion,foreign materials,paint, and physical damage and Withintenyears prior to the

74. Fire Water System installedin the proper orientation (e.g., upright,pendant, or A.2.1.16 periodof extended operation.

sidewall). Amy sprinkler th at is painted, corroded,damaged, loaded, or in the improperorientation,and any,glass bulb sprinkler where the bulb has emptied, will be evaluatedfor replacement.

United States Nuclear Regulatory Commission Page 13 of 14 SBK-L-14037 / Enclosure 3 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Enhance the program to conduct an inspection of piping and branch line conditions every 5years by opening aflushing connection at the end of one main and by removing a sprinkler Within ten yearsprior to the Fire Water System toward the end of one branch linefor the purpose of inspecting period of extended operation.

for the presence offoreign organicand inorganicmaterialper the guidanceprovidedin NFPA 25 (2011 Edition).

Enhance the Programto conduct thefollowing activities annuallyper the guidanceprovided in NFPA 25 (2011 Edition). Within ten years priorto the

76. Fire Water System

• main drain tests A.2.1.16 period of extended operation.

• deluge valve trip tests

• fire water storage tank exterior surface inspections The Fire Water System Program will be enhanced to include the following requirements relatedto the main drain testingper the guidanceprovidedin NFPA 25 (2011 Edition).

7 Fire Water System The requirementthat if there is a 10 percent reduction'in A.21.16 Within ten years priorto the full flow pressure when compared to the originalacceptance period of extended operation.

tests or previously performedtests, the cause of the reduction shall be identified and corrected if necessary.

• Recording the time taken for the supply waterpressure to return to the originalstatic (nonflowing) pressure.

78. External Surfaces Enhance the program to include periodicinspections of il-scope A.21.8 Priorto the period of extended Monitoring insulatedcomponents for possible corrosion under insulation. operation.

Enhance the program to include visual inspection of Service Level Within 10 years prior to the

79. Open-cle Cooling Water 11 (augmented)imternal coatingsfor loss of coating iitegrit, A.2.111 period1of extendedioperation

,Svstem period of extended operation.

United States Nuclear Regulatory Commission Page 14 of 14 SBK-L-14037 / Enclosure 3 UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Enhance the program to include visual inspection of Service Level

80. Fire Water System III (augmented)internalcoatingsfor loss of coating integrity. A.2.1.16 Within 10 j'earsepriorrtoithe

80. Iperiod of extended operation.

Enhance the program to include visual inspection of Service Level

8. Surfaces in Miscellaneous III (augmented)internalcoatingsfor loss of coating integrity. A.2.1.25 With in 10 years prior to the Piping aOid Ducting period of extended operation.

Components