RS-14-216, Units 1 and 2, Response to NRC Request for Additional Information, Set 35, Dated June 17, 2014, and Submittal of an Updated License Renewal Commitment List Related to License Renewal Application

Units 1 and 2, Response to NRC Request for Additional Information, Set 35, Dated June 17, 2014, and Submittal of an Updated License Renewal Commitment List Related to License Renewal Application

ML14349A524
Person / Time
Site:	Byron, Braidwood
Issue date:	12/15/2014
From:	Gallagher M Exelon Generation Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
RS-14-216
Download: ML14349A524 (53)

Text

Michael P. Gallagher Vice President. License Renewal Exelon Generation Exelon Nuclear 200 Exelon Way Kennett Square, PA 19348 610 765 5958 Office 610 765 5956 Fax www.exeloncorp.com michaelp.gallagher@exeloncorp.com 10 CFR 50 10 CFR 51 10 CFR 54 RS-14-216 December 15, 2014 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555-0001 Braidwood Station, Units 1 and 2 Facility Operating License Nos. NPF-72 and NPF-77 NRC Docket Nos. STN 50-456 and STN 50-457 Byron Station, Units 1 and 2 Facility Operating License Nos. NPF-37 and NPF-66 NRC Docket Nos. STN 50-454 and STN 50-455

Subject:

Response to NRC Request for Additional Information, Set 35, dated June 17, 2014, and Submittal of an updated License Renewal Commitment List related to the Byron Station, Units 1 and 2, and Braidwood Station, Units 1 and 2, License Renewal Application

References:

1. Letter from Michael P. Gallagher, Exelon Generation Company LLC (Exelon) to NRC Document Control Desk, dated May 29, 2013, "Application for Renewed Operating Licenses"

2. Letter from Lindsay R. Robinson, US NRC to Michael P. Gallagher, Exelon, dated June 17, 2014, "Request for Additional Information for the Review of the Byron Station, Units 1 and 2, and Braidwood Station, Units 1 and 2, License Renewal Application, Set 35 (TAC NOS. MF1879, MF1880, MF1881, and MF1882)"

3. Teleconference Record from Lindsay R. Robinson, US NRC, dated July 16, 2014, "Summary of Telephone Conference Call Held on July 9, 2014, Between the U.S. Nuclear Regulatory Commission and Exelon Generation Company, LLC Concerning Request for Additional Information, Set 35, Pertaining to the Byron Station and Braidwood Station, License Renewal Application (TAC Nos. MF1879, MF1880, MF1881, MF1882)"

In Reference 1, Exelon Generation Company, LLC (Exelon) submitted the License Renewal Application (LRA) for the Byron Station, Units 1 and 2, and Braidwood Station, Units 1 and 2

December 15, 2014 U.S. Nuclear Regulatory Commission Page 2 (BBS). In Reference 2, the NRC requested additional information (Set 35) to support staff review of the LRA. Subsequently, as documented in Reference 3, a telephone conference call was held on July 9, 2014, and it was concluded that a response to Set 35 should be provided within 30 days after the NRC staff issued the BBS Safety Evaluation Report with Open Items (i.e., by December 1, 2014). Due to additional staff requests for information and Exelon changes to license renewal commitments, Exelon requested additional time to incorporate these changes into the updated License Renewal Commitment List. In an e-mail dated November 24, 2014, the NRC License Renewal Project Manager approved submittal of this Set 35 response package by December 15, 2014.

Enclosure A contains the response to this request for additional information.

Enclosure B contains an update to a section of the LRA affected by the response.

Enclosure C provides an update to the License Renewal Commitment List (LRA Appendix A, Section A.5). Appendix A, Section A.5, is provided in its entirety and reflects the integrated effects of this letter and all previous Exelon correspondence that have modified the License Renewal Commitment List since the LRA was submitted on May 29, 2013.

Other than the commitment implementation schedule clarifications provided in the License Renewal Commitment List in Enclosure C as requested by this RAI, and three editorial corrections described on page 1 of Enclosure C, there are no new or revised regulatory commitments contained in this letter.

If you have any questions, please contact Mr. Al Fulvio, Manager, Exelon License Renewal, at 610-765-5936.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on /). -/,S-, 2ol<f-Respectfully,

/J?!~f/4 Michael P. Gallagher

• Vice President - License Renewal Projects Exelon Generation Company, LLC

Enclosures:

A. Byron and Braidwood Stations, Units 1 and 2, License Renewal Application, Response to Request for Additional Information: RAI A.1-1 B. Byron and Braidwood Stations, Units 1 and 2, License Renewal Application (LRA) Update Resulting from the response to: RAI A.1-1 C. Byron and Braidwood Stations, Units 1 and 2 License Renewal Commitment List Update

December 15, 2014 U.S. Nuclear Regulatory Commission Page 3 cc: Regional Administrator- NRC Region Ill NRC Project Manager (Safety Review), NRR-DLR NRC Project Manager (Environmental Review), NRR-DLR NRC Senior Resident Inspector, Braidwood Station NRC Senior Resident Inspector, Byron Station NRC Project Manager, NRR-DORL-Braidwood and Byron Stations Illinois Emergency Management Agency - Division of Nuclear Safety

RS-14-216 Enclosure A Page 1 of 4 Enclosure A Byron and Braidwood Stations, Units 1 and 2 License Renewal Application Response to Request for Additional Information RAI A.1-1

RS-14-216 Enclosure A Page 2 of 4 RAI A.1-1, License Renewal Commitments and the Updated Final Safety Analysis Report Applicability:

Byron Station (Byron) and Braidwood Station (Braidwood), Units 1 and 2

Background:

By letter dated May 29, 2013, Exelon Generation Company, LLC, submitted an application pursuant to Title 10 of the Code of Federal Regulations (CFR) Part 54, to renew the operating licenses NPF-37, NPF-66, NPF-72, and NPF-77 for Byron, Units 1 and 2, and Braidwood, Units 1 and 2, respectively, for review by the U.S. Nuclear Regulatory Commission (NRC or the staff). The staff of NRC is reviewing this application in accordance with the guidance in NUREG-1800, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants. During the review of the Byron and Braidwood license renewal application (LRA) by the NRC staff, the applicant made commitments related to aging management programs (AMPs), aging management reviews (AMRs), and time-limited aging analyses, as applicable, related to managing the aging effects of structures and components prior to the period of extended operation (PEO). The list of these commitments, as well as the implementation schedules and the sources for each commitment, will be included as a Table in Appendix A to the LRA and the safety evaluation report (SER) with Open Items.

In Section 1.7, Summary of Proposed License Conditions, of the SER with Open Items, the staff stated that following its review of the LRA, including subsequent information and clarifications provided by the applicant, it identified proposed license conditions. The first license condition requires the information in the updated final safety analysis report (UFSAR) supplement, submitted pursuant to 10 CFR 54.21(d), as revised during the LRA review process, be made a part of the UFSAR. The second license condition in part states that the new programs and enhancements to existing programs listed in Appendix A of the SER and the applicants USAR supplement be implemented no later than 6 months prior to the PEO.

This license condition also states, in part, that activities in certain other commitments shall be completed by 6 months prior to the PEO or the end of the last refueling outage prior to the PEO, whichever occurs later.

The NRC plans to revise Appendix A of the SER to align with this guidance and to reformat the license condition to be as follows:

The UFSAR supplement submitted pursuant to 10 CFR 54.21(d), as revised during the license renewal application review process, and as supplemented by Appendix A of NUREG [XXXX], Safety Evaluation Report Related to the License Renewal of Byron Station, Units 1 and 2, and Braidwood Station, Units 1 and 2 dated [Month Year],

describes certain programs to be implemented and activities to be completed prior to the PEO.

a) The licensee shall implement those new programs and enhancements to existing programs no later than 6 months prior to PEO.

RS-14-216 Enclosure A Page 3 of 4 b) The licensee shall complete those inspection and testing activities, as noted in Commitment Nos. x through xx of Appendix A of NUREG XXXX, by the 6 month date prior to PEO or the end of the last refueling outage prior to the PEO, whichever occurs later.

The licensee shall notify the NRC in writing within 30 days after having accomplished item (a) above and include the status of those activities that have been or remain to be completed in item (b) above.

The staff also notes that in the course of its evaluating multiple commitments to be implemented in the future in order to arrive at a conclusion of reasonable assurance that requirements of 10 CFR 54.29(a) have been met, these license renewal commitments must be incorporated either into a license condition or into a mandated licensing basis document, such as the UFSAR. Those commitments that are incorporated into the UFSAR are typically done so by incorporating each one verbatim (or by a summary and a commitment reference number) into the respective UFSAR summaries in the applicants LRA Appendix A.

Issue:

As proposed by the applicant and as reflected in the SER Appendix A, the implementation schedule for some commitments may conflict with the implementation schedule intended by the generic license condition. In addition, these licensing commitments need to be incorporated either into a license condition or into the applicants UFSAR summary in such a manner as discussed above.

Request:

1. Identify those commitments to implement new programs and enhancements to existing programs. Indicate the expected date for completing the implementation of each of these programs and enhancements.

2. Identify those commitments to complete inspection or testing activities prior to the PEO. Indicate the expected dates for the completion of each of these inspection and testing activities.

3. For each commitment provided by the applicant in the SER Appendix A, identify where and how Exelon Generation Company, LLC, proposes that it be incorporated: into either a license condition or into the Byron and Braidwood UFSAR.

RS-14-216 Enclosure A Page 4 of 4 Exelon Response:

1. Following is the list of commitments to implement new programs and enhancements to existing programs. This list uses the Item numbers from the Byron Station and Braidwood Station License Renewal Commitment List, LRA Appendix A, Section A.5:

1, 3, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 27, 28, 29, 30, 31, 33, 34, 35, 36, 37, 38, 39, 40, 41 (Byron only), 42, 43, 44, 45, and 46 The Implementation Schedule column within LRA Section A.5, as updated with this submittal, indicates the specific completion timing requirements for each of these commitments. In summary, Exelon will complete implementation of new programs and enhancements to existing programs no later than six months prior to entry into the respective period of extended operation for each Byron and Braidwood unit.

2. Following is the list of commitments that involve completion of inspection or testing activities prior to the PEO. Unless a specific earlier completion date is specified in the LRA Appendix A, Section A.5 License Renewal Commitment List, these activities will be completed either no later than six months prior to entry into the period of extended operation, or prior to completion of the last refueling outage prior to the PEO, whichever occurs later, for each Byron and Braidwood unit. This list uses the Item numbers from the Byron Station and Braidwood Station License Renewal Commitment List, which contains the specific completion timing requirements for each commitment:

10, 16, 17, 18, 19, 20, 21, 22, 28, 30, 31, 34, 35, 37, 38, 39, 41 (Byron only), 42, and 43

3. All of the commitments made by Exelon for license renewal, which are contained in Appendix A of the SER, are included in the updated version of LRA Appendix A, Section A.5, License Renewal Commitment List. Appendix A of the LRA is the UFSAR Supplement required by 10 CFR 54.21(d), and following receipt of the renewed operating licenses, this UFSAR Supplement will be incorporated into the Byron and Braidwood UFSAR in accordance with 10 CFR 50.71(e). Therefore, Exelon proposes that none of the commitments in SER Appendix A be incorporated into a license condition.

As a result of this request, LRA Appendix A, Section A.5, License Renewal Commitment List, is updated to reflect the schedule information summarized above for each commitment, as shown in Enclosure C.

References to the implementation of programs and activities made throughout other portions of LRA Appendix A, and LRA Appendix B do not describe actual schedule dates; rather, they indicate that the associated activities will be completed prior to the period of extended operation. Meeting the implementation schedule provided within LRA Appendix A, Section A.5, License Renewal Commitment List will ensure that the timing for implementation of the commitments is consistent with the intent of the generic license condition.

For clarity and consistency within the UFSAR Supplement (Appendix A), LRA Appendix A, Section A.1.0 is updated as shown in Enclosure B.

RS-14-216 Enclosure B Page 1 of 3 Enclosure B Byron and Braidwood Stations, Units 1 and 2 License Renewal Application (LRA) Update Resulting from the response to:

RAI A.1-1 Note: To facilitate understanding, portions of the LRA have been repeated in this Enclosure, with revisions indicated. Original LRA text is shown in normal font. Additions due to this RAI response are highlighted with bolded italics.

RS-14-216 Enclosure B Page 2 of 3 LRA Appendix A, Section A.1.0, Introduction, shown on page A-4 of the LRA, is revised to add subsection A.1.0.1 as shown below to better define the phrase prior to the period of extended operation as it is used throughout Appendix A, in relation to the license renewal commitment implementation schedule. The added subsection is shown in bolded italics.

A.1.0 Introduction Please refer to Table 1.5-1 for an explanation of how station-specific differences are identified throughout the License Renewal Application.

The application for a renewed operating license is required by 10 CFR 54.21(d) to include a FSAR Supplement. This appendix, which includes the following sections, comprises the FSAR supplement:

Section A.1.1 contains a listing of the aging management programs that correspond to NUREG-1801 Chapter XI programs, including the status of the programs at the time the License Renewal Application was submitted.

Section A.1.2 contains a listing of the plant-specific aging management programs, including the status of the programs at the time the License Renewal Application was submitted.

Section A.1.3 contains a listing of aging management programs that correspond to NUREG-1801 Chapter X programs associated with Time-Limited Aging Analyses, including the status of the programs at the time the License Renewal Application was submitted.

Section A.1.4 contains a listing of the Time-Limited Aging Analyses summaries (TLAAs).

Section A.1.5 contains a discussion of the Quality Assurance Program and Administrative Controls.

Section A.1.6 contains a discussion of the Operating Experience program.

Section A.2 contains a summarized description of the aging management programs.

Section A.2.1 contains a summarized description of the NUREG-1801 Chapter XI programs for managing the effects of aging.

Section A.2.2 contains a summarized description of the plant-specific programs for managing the effects of aging.

Section A.3 contains a summarized description of the NUREG-1801 Chapter X programs that support the TLAAs.

Section A.4 contains a summarized description of the TLAAs applicable to the period of extended operation.

Section A.5 contains the License Renewal Commitment List.

RS-14-216 Enclosure B Page 3 of 3 The integrated plant assessment for license renewal identified new and existing aging management programs necessary to provide reasonable assurance that systems, structures, and components within the scope of license renewal will continue to perform their intended functions consistent with the Current Licensing Basis (CLB) for the period of extended operation. The period of extended operation is defined as 20 years from the units current operating license expiration date.

A.1.0.1 Commitment Implementation Schedule Information LRA Appendix A, Section A.5, License Renewal Commitment List contains the specific implementation schedule requirements for each commitment.

Consistent with the License Renewal Commitment list, when used throughout Appendix A the phrase prior to the period of extended operation means that:

Implementation of new aging management programs and enhancements to existing aging management programs will be completed no later than six months prior to the respective period of extended operation (PEO) for each Byron and Braidwood unit; and Inspection or testing activities identified for completion prior to the PEO will be completed either:

o No later than six months prior to the respective PEO for each Byron and Braidwood unit, or o Prior to the end of the last refueling outage before the PEO for each respective unit, whichever occurs later.

RS-14-216 Enclosure C Page 1 of 43 Enclosure C Byron and Braidwood Stations, Units 1 and 2 License Renewal Commitment List Update This Enclosure provides a complete update to the Byron and Braidwood Station (BBS) LRA Appendix A, Table A.5 License Renewal Commitment List, showing the updated commitment implementation schedule completion requirements resulting from the response to the following RAI:

RAI A.1-1 This updated license renewal commitment list shows the integrated effects of all previous Exelon correspondence that has revised the license renewal commitments since submittal of the LRA on May 29, 2013.

Notes:

Information within the License Renewal Commitment List table that existed prior to this response to RAI A.1-1 is shown in normal font. Text inserted due to this response is shown in bolded italics, with deletions shown using strikethroughs.

With the exception of three editorial corrections described below, this letter, RS-14-216, is not listed in the Source column of the table; rather, a note at the end of the table explains the broad effects of this letter on license renewal commitment implementation timing.

For Commitment Number 30, RS-14-216 corrects two words that had been inadvertently reversed in the last sentence of Enhancement 5, as submitted in Exelon letter RS-14-328, dated November 21, 2014. The correction is shown with the stated convention of bolded italics and strikethroughs within the text. This correction also applies to the corresponding portions of LRA Appendix A (Enhancement 5 of Section A.2.1.30), and Appendix B (Enhancement 5 of Section B.2.1.30), which are revised by this submittal.

For Commitment Numbers 34 and 35, RS-14-216 corrects a typographical error identified during the SER review that had existed in the original LRA. This typo appeared in both Commitments 34 (Enhancement 7) and 35 (Enhancement 2) in the License Renewal Commitment list. The correction is shown with the stated convention of bolded italics and strikethroughs within the text. This correction also applies to the corresponding portions of LRA Appendix A (Enhancement 7 of Section A.2.1.34 and Enhancement 2 of Section A.2.1.35), and LRA Appendix B, (Enhancement 7 of Section B.2.1.34 and Enhancement 2 of Section B.2.1.35), which are revised by this submittal.

For Commitment Numbers 47 and 48, RS-14-216 makes the language in the Implementation Schedule column consistent with similar statements within the License Renewal Commitment List, by changing the number 6 to the word six. The correction is shown with the stated convention of bolded italics and strikethroughs within the text.

RS-14-216 Enclosure C Page 2 of 43 A.5 License Renewal Commitment List Explanatory notes within this table provide the basis for station-specific differences as follows:

Note 1 - Enhancement at one Station only; other Station currently performs activity Note 2 - Design difference Note 3 - Enhancement due to operating experience NO. PROGRAM OR IMPLEMENTATION COMMITMENT SOURCE TOPIC SCHEDULE*

1 ASME Section XI Inservice ASME Section XI Inservice Inspection, Subsections IWB, IWC, and Program to be enhanced no Section A.2.1.1 Inspection, Subsections IWD is an existing program that will be enhanced to: later than six months prior to IWB, IWC, and IWD the period of extended

1. Conduct a visual inspection of the accessible portions of the operation.

ASME Class 2 reactor vessel flange leakage monitoring tube every other refueling outage.

2 Water Chemistry Existing program is credited. Ongoing Section A.2.1.2 3 Reactor Head Closure Stud Reactor Head Closure Stud Bolting is an existing program that will be Program to be enhanced no Section A.2.1.3 Bolting enhanced to: later than six months prior to the period of extended Exelon letter

1. Revise the procurement requirements for reactor head closure operation. RS-13-247 stud material to assure that the maximum yield strength of 11/05/2013 replacement material is limited to a measured yield strength less than 150 ksi. RAI B.2.1.3-2 Exelon letter RS-13-285 12/19/2013 RAI B.2.1.3-2 updated response 4 Boric Acid Corrosion Existing program is credited. Ongoing Section A.2.1.4 5 Cracking of Nickel-Alloy Existing program is credited. Ongoing Section A.2.1.5 Components and Loss of Material Due to Boric Acid-

RS-14-216 Enclosure C Page 3 of 43 NO. PROGRAM OR IMPLEMENTATION COMMITMENT SOURCE TOPIC SCHEDULE*

Induced Corrosion in Reactor Coolant Pressure Boundary Components 6 Thermal Aging Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program to be implemented Section A.2.1.6 Embrittlement of Cast (CASS) is a new program that manages the aging effects of loss of no later than six months Austenitic Stainless Steel fracture toughness due to thermal aging embrittlement of ASME prior to the period of extended (CASS) Code Class 1 CASS components with service conditions above operation.

250oC (482oF). The program will include a screening methodology to determine component susceptibility to thermal aging embrittlement based on casting method, molybdenum content, and percent ferrite.

For potentially susceptible components, thermal aging embrittlement management will be accomplished through either, qualified visual inspections, such as enhanced visual examination, qualified ultrasonic testing methodology, or component-specific flaw tolerance evaluation.

7 PWR Vessel Internals The PWR Vessel Internals is a new program that manages the aging Program to be implemented no Section A.2.1.7 effects of various forms of cracking, including stress corrosion later than the date that the cracking (SCC), primary water stress corrosion cracking (PWSCC), renewed operating licenses irradiation assisted stress corrosion cracking (IASCC), or cracking are issued.

due to fatigue/cyclical loading; loss of material due to wear; loss of fracture toughness due to neutron irradiation embrittlement; changes in dimension due to void swelling and irradiation growth; and loss of preload due to thermal and irradiation-enhanced stress relaxation or creep. Program examination methods include visual examination, enhanced visual examination, volumetric examination, and direct physical measurements.

8 Flow-Accelerated Corrosion The Flow-Accelerated Corrosion aging management program is an Program to be enhanced no Section A.2.1.8 existing program that will be enhanced to: later than six months prior to the period of extended Exelon letter

1. Revise program procedures to require the documentation of the operation. RS-14-143 validation and verification of updated vendor supplied FAC 05/15/2014 program software which calculates component wear, wear rates, remaining life, and next scheduled inspection. The RAI B.2.1.8-2 validation and verification will verify that the updated software

RS-14-216 Enclosure C Page 4 of 43 NO. PROGRAM OR IMPLEMENTATION COMMITMENT SOURCE TOPIC SCHEDULE*

performs these calculations consistently with NSAC-202L-R3 guidelines.

9 Bolting Integrity Bolting Integrity is an existing program that will be enhanced to: Program to be enhanced no Section A.2.1.9 later than six months prior to

1. Prohibit the use of lubricants containing molybdenum disulfide the period of extended on pressure retaining bolted joints. operation.

2. Prohibit the use of high strength bolting (actual measured yield strength equal to or greater than 150 ksi) for pressure retaining bolted joints in portions of systems within the scope of the Bolting Integrity program.

3. Perform visual inspection of submerged bolting on fire Note 1 protection system pumps (Byron only) and well water Note 2 system deep well pumps (Byron only) when submerged portions of the pumps are overhauled or replaced during maintenance activities.

10 Steam Generators Steam Generators is an existing program that will be enhanced to: Program to be enhanced no Section A.2.1.10 later than six months prior to

1. Validate that primary water stress corrosion cracking of the the period of extended Exelon Letter divider plate welds to the primary head and tubesheet cladding operation. RS-14-052 is not occurring. BBS commits to perform one (1) of the 03/04/2014 following three (3) resolution options for Units 1 and 2: Schedule for submittal of inspection and analysis RAI B.2.1.10-1 Option 1: Inspection activities, if applicable, identified in Commitment.

Perform a one-time inspection, under the Steam Generators program, of each steam generator to assess the condition of the divider plate welds and the effectiveness of the Water Chemistry (A.2.1.2) program.

For the Byron and Braidwood, Unit 1 steam generators which were replaced in 1998, the inspection will be performed between 2018 and either no later than six months prior to the start of the period of extended

RS-14-216 Enclosure C Page 5 of 43 NO. PROGRAM OR IMPLEMENTATION COMMITMENT SOURCE TOPIC SCHEDULE*

operation or the end of the last refueling outage prior to the PEO, whichever occurs later, to allow the steam generators to acquire at least twenty years of service. For the Byron and Braidwood, Unit 2 steam generators which currently have at least twenty years of service, the inspection will be performed prior to entering the period of extended operation. The examination technique(s) will be capable of detecting primary water stress corrosion cracking (PWSCC) in the divider plate assemblies and associated welds.

or Option 2: Analysis Perform an analytical evaluation of the steam generator divider plate welds in order to establish a technical basis which concludes that the steam generator reactor coolant pressure boundary is adequately maintained with the presence of steam generator divider plate weld cracking.

The analytical evaluation will be submitted to the NRC for review and approval two (2) years prior to entering the associated period of extended operation.

or Option 3: Industry/NRC Studies If results of industry and NRC studies and operating experience document that potential failure of the steam generator reactor coolant pressure boundary due to PWSCC of the steam generator divider plate welds is not a credible concern, this commitment will be revised to reflect that conclusion.

2. Validate that primary water stress corrosion cracking of the tube-to-tubesheet welds is not occurring on BBS Unit 1. BBS commit to perform one (1) of the following three (3) resolution

RS-14-216 Enclosure C Page 6 of 43 NO. PROGRAM OR IMPLEMENTATION COMMITMENT SOURCE TOPIC SCHEDULE*

options for Unit 1:

Option 1: Inspection Perform a one-time inspection, under the Steam Generators (A.2.1.10) program, of a representative number of tube-to-tubesheet welds in each steam generator to determine if PWSCC cracking is present. Since the Byron and Braidwood Unit 1 steam generators were replaced in 1998, the inspection will be performed between 2018 and either no later than six months prior to the start of the period of extended operation or the end of the last refueling outage prior to the PEO, whichever occurs later, to allow the steam generators to acquire at least twenty years of service. The examination technique(s) will be capable of detecting primary water stress corrosion cracking (PWSCC) in the tube-to-tubesheet welds. If cracking is identified, the condition will be resolved through repair or engineering evaluation to justify continued service, as appropriate, and a periodic monitoring program will be established to perform routine tube-to-tubesheet weld inspections for the remaining life of the steam generators.

or Option 2: Analysis - Susceptibility Perform an analytical evaluation of the steam generator tube-to-tubesheet welds to determine that the welds are not susceptible to primary water stress corrosion cracking. The evaluation for determining that the tube-to-tubesheet welds are not susceptible to primary water stress corrosion cracking will be submitted to the NRC for review and approval two (2) years prior to entering the associated period of extended operation.

or Option 3: Analysis - Pressure Boundary

RS-14-216 Enclosure C Page 7 of 43 NO. PROGRAM OR IMPLEMENTATION COMMITMENT SOURCE TOPIC SCHEDULE*

Perform an analytical evaluation of the steam generator tube-to-tubesheet welds redefining the reactor coolant pressure boundary of the tubes, where the steam generator tube-to-tubesheet welds are not required to perform a reactor coolant pressure boundary function. The redefinition of the reactor coolant pressure boundary will be submitted to the NRC for review and approval two (2) years prior to entering the associated period of extended operation 11 Open-Cycle Cooling Water Open-Cycle Cooling Water System is an existing program that will be Program to be enhanced no Section A.2.1.11 System enhanced to: later than six months prior to the period of extended Exelon letter

1. Perform periodic volumetric inspections for loss of material in operation. RS-14-124 the non-essential service water system piping at a minimum of 05/05/2014 two (2) locations on each unit in both the auxiliary building and the turbine building for a total of four (4) periodic inspections per RAI 3.0.3-2a unit every refueling cycle.

Exelon letter

2. Require inspections of internal coatings be performed by RS-14-175 coating inspectors certified to ANSI N45.2.6 or ASTM Standards 06/30/2014 endorsed in Regulatory Guide 1.54.

RAI 3.0.3-2b

3. Specify that signs of peeling, blistering, or delamination of the coating from the base metal, if identified, shall be entered into the corrective action program.

4. Require physical testing of internal coatings, where physically possible, to ensure that remaining coating is tightly bonded to the base metal when peeling, blistering, or delamination is detected and the coating is not repaired or replaced. The testing will consist of adhesion testing using ASTM International standards endorsed in RG 1.54 (e.g., ASTM D4541-09 or ASTM D6677-07).

5. Require that evaluations utilized to return a coated component exhibiting signs of peeling, blistering, or delamination to service without repairing or replacing the coating shall consider the

RS-14-216 Enclosure C Page 8 of 43 NO. PROGRAM OR IMPLEMENTATION COMMITMENT SOURCE TOPIC SCHEDULE*

potential impact on the intended function of the system. This evaluation shall include consideration of the potential for degraded performance of downstream components due to flow blockage and loss of material of the coated component.

6. Require the as-left condition of a coating that exhibited signs of peeling, blistering, or delamination and that is not repaired or replaced is such that the potential for further degradation of the coating is minimized.

12 Closed Treated Water Closed Treated Water Systems is an existing program that will be Program to be enhanced no Section A.2.1.12 Systems enhanced to: later than six months prior to the period of extended

1. Perform condition monitoring, including periodic visual operation.

inspections and non-destructive examinations, to verify the effectiveness of water chemistry control at mitigating aging effects. A representative sample of piping and components will be selected based on likelihood of corrosion, fouling, or cracking and inspected at an interval not to exceed once in 10 years during the period of extended operation. The selection of components to be inspected will focus on locations which are most susceptible to age-related degradation, where practical.

2. Perform periodic sampling, analysis, and trending of water chemistry for the essential service water makeup pump engine glycol-based jacket water system to verify the effectiveness of water chemistry control at mitigating aging effects (Byron only) Note 2.

13 Inspection of Overhead Inspection of Overhead Heavy Load and Light Load (Related to Program to be enhanced no Section A.2.1.13 Heavy Load and Light Load Refueling) Handling Systems is an existing program that will be later than six months prior to (Related to Refueling) enhanced to: the period of extended Handling Systems operation.

1. Consistently include inspections of structural components and bolting for loss of material due to corrosion, rails for loss of material due to wear and corrosion, and bolted connections for

RS-14-216 Enclosure C Page 9 of 43 NO. PROGRAM OR IMPLEMENTATION COMMITMENT SOURCE TOPIC SCHEDULE*

evidence of loss of preload.

2. Ensure periodic inspections are performed on all cranes, hoists, monorails, and rigging beams within the scope of license renewal, including those that are infrequently in use.

14 Compressed Air Monitoring Compressed Air Monitoring is an existing program that will be Program to be enhanced no Section A.2.1.14 enhanced to: later than six months prior to the period of extended

1. Inspect critical component internal surfaces for signs of loss of operation.

material due to corrosion and document deficiencies in the corrective action program.

15 Fire Protection Fire Protection is an existing program that will be enhanced to: Program to be enhanced no Section A.2.1.15 later than six months prior to

1. Include visual inspections of the earthen berm enclosing the the period of extended outdoor fuel oil storage tanks for signs of age-related operation.

degradation such as loss of material and loss of form that could affect the intended function of the berm.

2. Provide additional inspection guidance to identify age-related degradation of fire barrier walls, ceilings, and floors or aging effects such as cracking, spalling, and loss of material.

3. Include visual inspection of halon and low-pressure carbon dioxide fire suppression system piping and component external surfaces for signs of corrosion or other age-related degradation.

16 Fire Water System Fire Water System is an existing program that will be enhanced to: Program to be enhanced no Section A.2.1.16 later than six months prior to

1. Replace sprinkler heads or perform 50-year sprinkler head the period of extended Exelon letter testing using the guidance of NFPA 25 Standard for the operation. RS-14-078 Inspection, Testing and Maintenance of Water-Based Fire 03/13/2014 Protection Systems (2002 Edition), Section 5.3.1.1.1. This Inspection schedule identified testing will be performed at the 50-year in-service date and in commitment. Pre-PEO RAI B.2.1.16-1 every 10 years thereafter. activities specified in RAI B.2.1.16-2

RS-14-216 Enclosure C Page 10 of 43 NO. PROGRAM OR IMPLEMENTATION COMMITMENT SOURCE TOPIC SCHEDULE*

Enhancements 6 and 8 will

2. Provide for chemical addition accompanied with system flushing be completed either no later to allow for adequate dispersal of the chemicals throughout the than six months prior to the Exelon letter system, to prevent or minimize microbiologically induced PEO, or before the end of RS-14-169 Note 3 corrosion (Byron only) . the last refueling outage 06/16/2014 prior to the PEO, whichever

3. Perform main drain testing annually, in accordance with NFPA occurs later. RAI B.2.1.16-1a 25, Standard for the Inspection, Testing and Maintenance of Water-Based Fire Protection Systems, Section 13.2.5. Exelon letter RS-14-175

4. Perform air flow testing of deluge systems that are not subject 06/30/2014 to periodic full flow testing on a three (3) year frequency to verify that internal flow blockage is not occurring (Byron only) RAI 3.0.3-2b Note 1

.

Exelon letter

5. Perform inspections of Fire Protection System strainers when RS-14-235 the system is reset after automatic actuation for signs of internal 8/29/2014 flow blockage (e.g., buildup of corrosion particles) (Braidwood Note 1 only) . RAI B.2.1.16-1c

6. Increase the frequency of visual inspections of the internal surface of the foam concentrate tanks to at least once every ten (10) years. At least one (1) inspection will be performed within the ten (10) year period prior to entry into the period of extended operation, with subsequent inspections performed every ten (10) years thereafter.

7. Perform radiographic testing or internal visual inspections every five (5) years at the end of one (1) fire main and the end of one (1) sprinkler system branch line in half of the wet pipe sprinkler system within the scope of license renewal. If internal flow blockage that could result in failure of the system to deliver the required flow is identified, then perform an obstruction investigation.

8. Perform augmented testing beyond that specified in NFPA 25 on those portions of the water-based fire protection system that are: (a) normally dry but periodically subjected to flow and (b)

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cannot be drained or allow water to collect. The augmented testing will include: (1) periodic full flow tests at the design pressure and flow rate or internal visual inspections and (2) volumetric wall-thickness examinations. Inspections and testing will commence five (5) years prior to the period of extended operation and will be conducted on a five (5) year frequency thereafter.

9. Perform a minimum of 30 volumetric examinations of Fire Protection System piping, using radiographic testing or ultrasonic testing, during each three year interval. If volumetric examinations over a 10-year interval do not identify three (3) or more areas exhibiting reduction in wall thickness greater than 50 percent, then this minimum sample size is no longer required Note 3 (Byron only) .

10. Require inspections of internal coatings be performed by coating inspectors certified to ANSI N45.2.6 or ASTM Standards endorsed in Regulatory Guide 1.54.

11. Specify that signs of peeling, blistering, or delamination of the coating from the base metal, if identified, shall be entered into the corrective action program.

12. Require physical testing of internal coatings, where physically possible, to ensure that remaining coating is tightly bonded to the base metal when peeling, blistering, or delamination is detected and the coating is not repaired or replaced. The testing will consist of adhesion testing using ASTM International standards endorsed in RG 1.54 (e.g., ASTM D4541-09 or ASTM D6677-07).

13. Require that evaluations utilized to return a coated component exhibiting signs of peeling, blistering, or delamination to service without repairing or replacing the coating shall consider the potential impact on the intended function of the system. This evaluation shall include consideration of the potential for degraded performance of downstream components due to flow

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blockage and loss of material of the coated component.

14. Require the as-left condition of a coating that exhibited signs of peeling, blistering, or delamination and that is not repaired or replaced is such that the potential for further degradation of the coating is minimized.

15. Perform a minimum of 25 volumetric examinations of Fire Protection System piping, using radiographic testing or ultrasonic testing, during each 10-year interval.

17 Aboveground Metallic Program to be implemented Section A.2.1.17 Tanks Aboveground Metallic Tanks is a new program that manages aging no later than six months effects of loss of material and cracking on the external surfaces of prior to the period of extended Exelon letter aboveground metallic tanks within the scope of license renewal by operation. RS-14-003 performing periodic visual inspections once per eighteen (18) month 01/13/2014 operating cycle for degradation of the external surface of the UT inspection schedule insulation lagging, flashing, roof, and accessible sealant. The identified in commitment. The RAI B.2.1.17-1 program also requires periodic visual inspections and liquid penetrant pre-PEO inspection RAI B.2.1.17-2 examinations of the tank external surfaces at 25 locations for both activities specified in the tanks combined per site and includes, on a sampling basis, removal commitment will be of selected tank lagging and insulation to permit inspections of the completed either no later external tank surfaces and exposed sealants. The tank external than six months prior to the surface inspections and examinations will be performed each 10-year PEO, or before the end of period starting 10 years prior to the period of extended operation. the last refueling outage The sample locations will include at least four locations below prior to the PEO, whichever penetrations through the insulation and its jacketing (e.g. instrument occurs later.

nozzles, tank heaters, ladder). The remaining sample locations will be distributed such that inspections will occur on the tank dome, sides, and near the bottom.

One-time tank bottom ultrasonic inspections (one CST per station) will be performed within the 5-year period prior to the period of extended operation. The cathodic protection availability and effectiveness criteria in LR-ISG-2011-03 Table 4c, notes 3.ii and 3.iii, respectively, will be required to be met commencing 5 years prior to the PEO and during the PEO.

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18 Fuel Oil Chemistry Fuel Oil Chemistry is an existing program that will be enhanced to: Program to be enhanced no Section A.2.1.18 later than six months prior to

1. Provide for the periodic cleaning of the Fire Protection Fuel Oil the period of extended Exelon letter Note 1 Storage Tank (Byron only) . operation. RS-14-124 05/05/2014

2. Provide for periodic draining of water from the Auxiliary Pre-PEO inspections Feedwater Day Tanks, Diesel Generator Day Tanks, Essential specified in Enhancement 7 RAI 3.0.3-2a Service Water Make/Up Pump Fuel Oil Storage Tanks (Byron will be completed either no Note 2 only) , and Fire Protection Fuel Oil Storage Tanks. later than six months prior to the PEO, or before the Exelon letter

3. Include analysis for the levels of microbiological organisms in end of the last refueling RS-14-175 the Auxiliary Feedwater Day Tanks and Essential Service Water outage prior to the PEO, 06/30/2014 Make-up Pumps Diesel Oil Storage Tanks (Byron only) Note 2. whichever occurs later.

RAI 3.0.3-2b

4. Include analysis for water and sediment content, particulate concentration, and the levels of microbiological organisms for the Diesel Generator Day Tanks.

5. Include analysis for water and sediment content and the levels of microbiological organisms for the Diesel Generator Fuel Oil Storage Tanks.

6. Include analysis for particulate concentration and the levels of microbiological organisms for the Fire Protection Fuel Oil Storage Tanks.

7. Include internal inspections of the Fire Protection Fuel Oil Storage Tanks at least once during the 10-year period prior to the period of extended operation, and at least once every 10 years during the period of extended operation. Each diesel fuel tank will be drained and cleaned, the internal surfaces visually inspected (if physically possible), and, if evidence of degradation is observed during inspections, or if visual inspection is not possible, these diesel fuel tanks will be volumetrically inspected.

8. Include monitoring and trending for the levels of microbiological organisms for the Auxiliary Feedwater Day Tanks and Essential

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Service Water Make-up Pumps Diesel Oil Storage Tanks (Byron Note 2 only) .

9. Include monitoring and trending for water and sediment content, particulate concentration, and the levels of microbiological organisms for the Diesel Generator Day Tanks.

10. Include monitoring and trending for water and sediment content and the levels of microbiological organisms for the Diesel Generator Fuel Oil Storage Tanks.

11. Include monitoring and trending for total particulate concentration and the levels of microbiological organisms for the Fire Protection Fuel Oil Storage Tanks.

12. Require inspections of internal coatings be performed by coating inspectors certified to ANSI N45.2.6 or ASTM Standards endorsed in Regulatory Guide 1.54.

13. Specify that signs of peeling, blistering, or delamination of the coating from the base metal, if identified, shall be entered into the corrective action program.

14. Require physical testing of internal coatings, where physically possible, to ensure that remaining coating is tightly bonded to the base metal when peeling, blistering, or delamination is detected and the coating is not repaired or replaced. The testing will consist of adhesion testing using ASTM International standards endorsed in RG 1.54 (e.g., ASTM D4541-09 or ASTM D6677-07).

15. Require that evaluations utilized to return a coated component exhibiting signs of peeling, blistering, or delamination to service without repairing or replacing the coating shall consider the potential impact on the intended function of the system. This evaluation shall include consideration of the potential for degraded performance of downstream components due to flow blockage and loss of material of the coated component.

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16. Require the as-left condition of a coating that exhibited signs of peeling, blistering, or delamination and that is not repaired or replaced is such that the potential for further degradation of the coating is minimized.

19 Reactor Vessel Reactor Vessel Surveillance is an existing program that will be Program to be enhanced no Section A.2.1.19 Surveillance enhanced to: later than six months prior to the period of extended Exelon Letter

1. Establish operating restrictions to ensure that the plant is operation. RS-14-002 operated under the conditions to which the surveillance 01/13/2014 capsules were exposed. The operating restrictions are as Specimen capsule testing to follows: be performed in accordance RAI B.2.1.19-1 with the schedule described in Byron Station, Unit 1: Enhancement 2. Exelon Letter RS-14-149

- Cold leg operating temperature limitation: 525 05/23/2014 degrees Fahrenheit (minimum) to 590 degrees Fahrenheit (maximum). RAI B.2.1.19-1a

- RPV beltline material fluence: 3.21E+19 n/cm2 (E Exelon Letter

>1.0 MeV) (maximum). RS-14-225 07/28/2014 RAI B.2.1.19-1b Byron Station, Unit 2; Braidwood Station Units 1:

- Cold leg operating temperature limitation: 525 degrees Fahrenheit (minimum) to 590 degrees Fahrenheit (maximum).

- RPV beltline material fluence: 3.19E+19 n/cm2 (E

>1.0 MeV) (maximum).

Braidwood Station, Unit 2:

- Cold leg operating temperature limitation: 525

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degrees Fahrenheit (minimum) to 590 degrees Fahrenheit (maximum).

- RPV beltline material fluence: 3.16E+19 n/cm2 (E

>1.0 MeV) (maximum).

If the reactor pressure vessel exposure conditions (neutron fluence, neutron spectrum) or irradiation temperature (cold leg inlet temperature) are altered, then the basis for the projection to the end of the period of extended operation needs to be reviewed and, if deemed appropriate, updates are made to the Reactor Vessel Surveillance program. Any changes to the Reactor Vessel Surveillance program must be submitted for NRC review and approval in accordance with 10 CFR Part 50, Appendix H.

2. One (1) specimen capsule per reactor vessel, as designated below, irradiated to a neutron fluence of one (1) to two (2) times the projected peak neutron fluence at the end of the period of extended operation will be withdrawn from the spent fuel pool, tested, and the summary technical report submitted to the NRC within one (1) year of receipt of the renewed license.

Alternatively, if a request for extension of the testing schedule is submitted in accordance with 10 CFR Part 50, Appendix H and granted by the Director, Office of Nuclear Reactor Regulation, specimen testing will be performed in accordance with that approved extension.

Reactor Vessel Capsule ID Capsule Fluence (Station, Unit) (n/cm2)(E>1.0 MeV)

Byron, Unit 1 Y 3.97E+19 Byron, Unit 2 Y 4.19E+19 Braidwood, Unit 1 V 3.71E+19 Braidwood, Unit 2 V 3.73E+19

RS-14-216 Enclosure C Page 17 of 43 NO. PROGRAM OR IMPLEMENTATION COMMITMENT SOURCE TOPIC SCHEDULE*

20 One-Time Inspection One-Time Inspection is a new program that will be used to verify the Program to be implemented Section A.2.1.20 system-wide effectiveness of the Water Chemistry, Fuel Oil no later than six months Chemistry and Lubricating Oil Analysis programs. prior to the period of extended Exelon letter operation. RS-14-003 The One-Time Inspection aging management program will also be 01/13/2014 utilized, in specific cases where existing data is insufficient: One-time inspections will be

a. to validate that a particular aging effect is not occurring, or performed within the ten year RAI B.2.1.23-1

b. to verify that the aging effect is occurring slowly enough to not period prior to the period of affect a components intended function during the period of extended operation, and will extended operation. be completed either no later than six months prior to the In these cases, the components will not require additional aging PEO, or before the end of management. the last refueling outage prior to the PEO, whichever occurs later.

21 Selective Leaching Selective Leaching is a new program that will include one-time Program to be implemented Section A.2.1.21 inspections of a representative sample of susceptible components to no later than six months determine if loss of material due to selective leaching is occurring. prior to the period of extended operation.

One-time inspections will be performed within the five (5) year period prior to the period of extended operation, and will be completed either no later than six months prior to the PEO, or before the end of the last refueling outage prior to the PEO, whichever occurs later.

22 One-Time Inspection of One-Time Inspection of ASME Code Class 1 Small-Bore Piping is a Program to be implemented Section A.2.1.22 ASME Code Class 1 Small- new program that will manage the aging effect of cracking in Class 1 no later than six months Bore Piping small-bore piping that is less than nominal pipe size (NPS) 4-inches, prior to the period of extended Exelon Letter and greater than or equal to NPS 1-inch. operation. RS-14-002 01/13/2014 The socket weld sample population for Byron Unit 1 will include the One-time Inspections will be socket weld on the D safety injection system cold leg injection line performed and evaluated RAI B.2.1.22-1 within the six (6) year period

RS-14-216 Enclosure C Page 18 of 43 NO. PROGRAM OR IMPLEMENTATION COMMITMENT SOURCE TOPIC SCHEDULE*

that was replaced in 1998. prior to the period of extended operation, and will be completed either no later than six months prior to the PEO, or before the end of the last refueling outage prior to the PEO, whichever occurs later.

23 External Surfaces External Surfaces Monitoring of Mechanical Components is a new Program to be implemented Section A.2.1.23 Monitoring of Mechanical program that manages aging effects of metallic and elastomeric no later than six months Components materials through periodic visual inspection of external surfaces for prior to the period of extended Exelon letter evidence of loss of material and cracking. Visual inspections are operation. RS-14-003 augmented by physical manipulation as necessary to detect 01/13/2014 hardening and loss of strength of elastomers. The periodic system walkdowns include visual inspection of insulation jacketing to ensure RAI 2.1.23-1 the integrity of the jacketing is maintained. External visual RAI 3.0.3-3 inspections of the jacketing ensure that there is no damage to the jacketing that would permit in-leakage of moisture. The procedures for planning insulation repairs will be revised to document that Exelon letter insulation repairs are performed in accordance with specification RS-14-051 requirements (e.g., seams on the bottom, overlapping seams) so as 02/27/2014 to prevent water intrusion into the insulation.

RAI 3.5.2-4 Periodic representative inspections to detect corrosion (i.e., loss of material) under insulation will be conducted on in-scope indoor Exelon letter insulated components, where the process fluid temperature is below RS-14-218 the dew point for a period of time sufficient to accumulate 07/18/2014 condensation, and in-scope outdoor insulated components (with the exception of the condensate storage tanks). These periodic inspections will be conducted during each 10-year period of the period of extended operation. Inspections subsequent to the initial inspection will consist of examination of the exterior surface of the insulation for indications of damage to the jacketing or protective outer layer of the insulation if the initial inspection verifies no loss of material due to general, pitting, or crevice corrosion, beyond that which could have been present during initial construction.

If the external visual inspections of the insulation reveal damage to

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the exterior surface of the insulation or if there is evidence of water intrusion through the insulation (e.g., water seepage through insulation seams/joints), then periodic visual inspections under insulation to detect corrosion and cracking under insulation will continue.

24 Flux Thimble Tube Flux Thimble Tube Inspection is an existing program that will be Byron: Ongoing Section A.2.1.24 Inspection enhanced as follows:

Braidwood: Schedule for flux Exelon letter (Note 3)

1. For Braidwood Unit 1  : thimble tube replacement RS-14-336 activities identified in 11/22/2014

a. The 17 Braidwood Station, Unit 1 flux thimble tubes that commitment.

exhibited indications of wear during eddy current testing performed during A1R15 Refueling Outage (Fall 2010), will be replaced or removed from service during A1R18 Refueling Outage (Spring 2015), unless eddy current data is obtained as required by the Flux Thimble Tube Inspection program. (Flux thimble tubes 1 (J-8), 8 (K-6), 9 (H-11), 12 (E-9), 14 (H-4), 18 (L-11), 19 (L-5), 21 (E-11), 23 (D-10), 36 (J-14), 37 (P-9), 41 (N-4), 44 (R-8), 45 (N-13),

48 (P-4), 54 (A-11), 55 (N-14))

b. The remaining Braidwood Station, Unit 1 flux thimble tubes, not replaced during A1R18, will be replaced or removed from service during A1R19 Refueling Outage (Fall 2016),

unless eddy current data is obtained as required by the Flux Thimble Inspection Tube program.

c. Following A1R19, any Braidwood Station, Unit 1 flux thimble tube will be replaced every three (3) refueling outages or removed from service if eddy current data is not obtained in accordance with the Flux Thimble Tube Inspection program.

2. For Braidwood Unit 2 (Note 3):

a. The 29 Braidwood Station, Unit 2 flux thimble tubes that exhibited indications of wear during eddy current testing

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performed during A2R15 Refueling Outage (Spring 2011) and not replaced during A2R17 Refueling Outage (Spring 2014), will be replaced or removed from service during A2R18 Refueling Outage (Fall 2015), unless eddy current data is obtained as required by the Flux Thimble Tube Inspection program. (Flux thimble tubes 1 (J-8), 4 (H-6), 5 (F-8), 6 (J-10), 7 (F-7), 9 (H-11), 10 (L-8), 11 (G-5), 18 (L-11), 22 (K-12), 23 (D-10), 24 (H-13), 25 (N-8), 26 (H-3), 27 (C-8), 29 (N-6), 32 (L-13), 33 (C-5), 34 (H-2), 36 (J-14), 37 (P-9), 40 (F-14), 41 (N-4), 42 (D-3), 45 (N-13), 46 (J-1), 50 (R-6), 52 (L-15), 56 (N-2))

b. The remaining Braidwood Station, Unit 2 flux thimble tubes, not replaced during A2R17 or A2R18, will be replaced or removed from service during A2R19 Refueling Outage (Spring 2017), unless eddy current data is obtained as required by the Flux Thimble Inspection Tube program.

c. Following A2R19, any Braidwood Station, Unit 2 flux thimble tube will be replaced every three (3) refueling outages or removed from service if eddy current data is not obtained in accordance with the Flux Thimble Tube Inspection program.

25 Inspection of Internal Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Program to be implemented Section A.2.1.25 Surfaces in Miscellaneous Components is a new program that manages aging effects of metallic no later than six months Piping and Ducting and elastomeric materials through visual inspections of internal prior to the period of extended Exelon letter Components surfaces for evidence of loss of material. Visual inspections are operation. RS-14-003 augmented by physical manipulation as necessary to detect 01/13/2014 hardening and loss of strength of elastomers.

RAI B.2.1.25-1 This opportunistic approach is supplemented to ensure a representative sample of components within the scope of this program are inspected. At a minimum, in each 10-year period during the period of extended operation, a representative sample of 20 percent of the population (defined as components having the same combination of material, environment, and aging effect) or a

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maximum of 25 components per population is inspected. Where practical, the inspections focus on the bounding or lead components most susceptible to aging because of time in service, and severity of operating conditions. Opportunistic inspections continue in each 10-year period despite meeting the sampling minimum requirement.

26 Lubricating Oil Analysis Existing program is credited. Ongoing Section A.2.1.26 27 Monitoring of Neutron- Monitoring of Neutron-Absorbing Materials Other than Boraflex is an Program to be enhanced no Section A.2.1.27 Absorbing Materials Other existing program that will be enhanced to: later than six months prior to than Boraflex the period of extended Exelon letter

1. Maintain the coupon exposure such that it is bounding for the operation. RS-14-052 Boral material in all spent fuel racks prior to coupons being 03/04/2014 examined, by ensuring that the coupons have been surrounded with a greater number of freshly discharged fuel assemblies RAI B.2.1.27-1 than that of any other cell location.

28 Buried and Underground Buried and Underground Piping is an existing program that will be Program to be enhanced no Section A.2.1.28 Piping enhanced to: later than six months prior to the period of extended Exelon letter

1. Perform manual examinations, in addition to visual inspections, operation. RS-14-003 to detect hardening, softening, or other changes in material 01/13/2014 properties for buried polymeric piping (Braidwood only) Note 2. Pre-PEO activities specified in Enhancements 3, 5, 6 and RAI B.2.1.28-4

2. Cracking will be managed for stainless steel components, 7 will be completed either no RAI B.2.1.28-3 utilizing a method that has been demonstrated to be capable of later than six months prior detecting cracking, whenever coatings are removed and expose to the PEO, or before the Note 2 the base material (Braidwood only) . end of the last refueling outage prior to the PEO,

3. Ensure all underground carbon steel essential service water whichever occurs later.

system piping within the scope of license renewal is coated in accordance with NACE SP0169-2007 prior to the period of extended operation (Byron only) Note 1.

4. Direct visual inspections of coated piping and components will be performed by an individual possessing a NACE Coating Inspector Program Level 2 or 3 operator qualification, or by an

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individual who has attended the EPRI Comprehensive Coatings Course and completed the EPRI Buried Pipe Condition Assessment and Repair Training Computer Based Training Course.

5. Inspection quantities of buried piping within the scope of license renewal will be performed in accordance with LR-ISG-2011-03, Element 4, Table 4a, and based upon the as-found results of cathodic protection system availability and effectiveness during each ten year period, beginning 10 years prior to the period of extended operation.

6. The buried carbon steel condensate system piping within the scope of license renewal will be addressed, through means of a long term mitigation strategy, prior to entering the period of extended operation. Mitigation may include activities such as fully recoating, complete replacement with like or upgraded material, installation of internal polymeric sleeves, and routing of pipe above ground or in an engineered trench for leak detection. Inspections of the condensate system piping will be performed in accordance with LR-ISG-2011-03, Element 4, Table 4a, and based on the mitigation strategy implemented Note 3 (Braidwood only) .

7. Inspection quantities of underground piping within the scope of license renewal will be performed in accordance with LR-ISG-2011-03, Element 4, Table 4b, during each 10 year period, beginning 10 years prior to the period of extended operation.

a. The piping and components inside the Byron 0SX138A and 0SX138B valve vaults will be visually inspected by engineering on a quarterly basis until either measures to prevent immersion of the piping and components inside the vault are implemented, or a coating system is installed that is designed for periodic immersion applications (Byron Note 3 only) .

8. If adverse indications are detected during inspection, inspection

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sample sizes within the affected piping categories will be doubled. If adverse indications are found in the expanded sample, an analysis will be conducted to determine the extent of condition and extent of cause. The size of the follow-on inspections will be determined based on the analysis. Timing of the additional inspections will be based on the severity of the identified degradation and the consequences of leakage. In all cases, the additional inspections will be performed within the same 10-year inspection interval in which the original adverse indication was identified. Expansion of sample size may be limited by the extent of piping subject to the observed degradation mechanism.

9. In performing cathodic protection surveys, only the -850mV polarized potential criterion specified in NACE SP0169-2007 for steel piping will be used for acceptance criteria and determination of cathodic protection system effectiveness.

Alternatively, soil corrosion, or electrical resistance, probes may also be used to demonstrate cathodic protection effectiveness during the annual surveys. An upper limit of -1200mV for pipe-to-soil potential measurements of coated pipes will also be established, so as to preclude potential damage to coatings.

10. An extent of condition evaluation will be conducted if observed coating damage caused by non-conforming backfill has been evaluated as significant. The extent of condition evaluation will be conducted to ensure that the as-left condition of backfill in the vicinity of the observed damage will not lead to further degradation.

29 ASME Section XI, ASME Section XI, Subsection IWE is an existing program that will be Program to be enhanced no Section A.2.1.29 Subsection IWE enhanced to: later than six months prior to the period of extended Exelon Letter

1. Provide guidance for specification of bolting material, lubricant operation. RS-14-183 and sealants, and installation torque or tension to prevent or 7/8/2014 mitigate degradation and failure of structural bolting.

Updated

2. Use the condition of the embedded reinforcing steel at the inner response to RAI

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surface of the tendon tunnel as a representative indicator for the B.2.1.29-1 potential for corrosion at the exterior surface of the containment liner plate. Use the results of Structures Monitoring (B.2.1.34) aging management program, Enhancement 16 activities and results from ongoing examinations of the tendon tunnel performed as part of the ASME Section XI, Subsection IWL (B.2.1.30) and Structures Monitoring (B.2.1.34) aging management programs to identify changing conditions.

Changing conditions consisting of the identification of significant corrosion of embedded steel in the tendon tunnel structure require an evaluation to determine if augmented examinations in accordance with requirements of IWE-1240 Surface Areas Requiring Augmented Examination are required due to the potential for accelerated corrosion at the exterior surface of the containment liner plate.

30 ASME Section XI, ASME Section XI, Subsection IWL is an existing program that will be Program to be enhanced no Section A.2.1.30 Subsection IWL enhanced to: later than six months prior to the period of extended Exelon Letter

1. Include additional augmented examination requirements after operation. RS-14-183 post-tensioning system repair/replacement activities in 7/8/2014 accordance with Table IWL-2521-2. Pre-PEO inspections specified in Enhancements 2 Updated and 3 will be completed response to RAI

2. A one-time inspection of one (1) vertical and one (1) horizontal either no later than six B.2.1.30-3 tendon on each unit will be performed prior to the period of months prior to the PEO, or extended operation. The inspection will consist of visually before the end of the last Exelon Letter examining one (1) wire from each of the two (2) types of refueling outage prior to the RS-14-328 tendons at a worst-case location based on evidence of free PEO, whichever occurs later. 11/21/2014 water, grease discoloration, and grease chemistry results. This location will serve as a leading indicator for potential RAI B.2.1.30-6 degradation or tendon surface corrosion. The visual inspection of these wires will be performed in accordance with existing station procedures used for inspections consistent with IWL- Exelon Letter 2523.2. The acceptance criteria will consist of each wire being RS-14-216 free of any active corrosion, including general and pitting 12/15/2014 corrosion. In the event that the acceptance criteria are not met

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and corrosion is identified, the condition will be entered into the corrective action program. The condition will be evaluated to characterize the corrosion, determine the cause of the corrosion, the location, depth, extent of the condition, and applicability of the condition to other wires that comprise that tendon. Corrective actions may include activities such as grease analysis, replacement of grease within the tendon duct, additional wire inspections from the same tendon, evaluation of the tendon capacity, potential replacement of the tendon, and augmented inspections and grease sampling of other leading indicator tendons, based, in part, on previous evidence of free water, observed grease leakage, grease discoloration, and grease chemistry results. Specific corrective actions will depend upon the cause, extent of condition, and grease properties. These corrective actions will be consistent with those actions which would be evaluated during periodic Note 3 required IWL examinations (Braidwood only) .

3. In order to monitor for tendon exposure to free water and moisture and manage any potential adverse effects, a periodic tendon water monitoring and grease sampling program will be implemented (Braidwood only) Note 3. The program will consist of:

a. A baseline inspection of tendon grease caps at the bottom of all vertical and dome tendons, as well as all below-grade horizontal tendons, prior to the period of extended operation. The baseline inspection will check for evidence of free water and grease discoloration, with further actions taken based on the condition of the grease.

b. A follow-up tendon grease cap inspection of all vertical and dome tendons, as well as all below-grade horizontal tendons, will be performed within 10 years of the initial inspection, using the same approach as the baseline inspection.

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c. For those tendons where free water, moisture, and grease did not meet acceptance criteria during the two (2) previous inspections, periodic monitoring of grease chemistry and moisture, free water, and grease discoloration will be performed on a frequency not to exceed 10 years.

Tendons, which exhibit significant quantities of free water (e.g., more than eight ounces) during periodic monitoring, will be inspected more often, with the timing of follow-up inspections increased until a frequency is achieved that no longer results in significant amounts of free water observed during successive inspections. Tendon water inspection and draining frequencies may vary from annual to every ten (10) years, depending upon grease chemistry and moisture parameters meeting IWL acceptance criteria. The maximum ten (10) year periodic frequency is meant to address any tendons which exhibit evidence of free water but the quantity is observed to be insignificant, with no observable grease discoloration, and given that the tendon wasnt inspected for at least ten (10) years prior. More frequent follow-up inspections will be performed for tendons which exhibit insignificant quantities of free water, but were inspected within the ten (10) years prior. In all cases, the frequency of inspections for water in individual tendons will be adjusted to be commensurate with the severity of the conditions found during each examination.

d. Braidwood has performed augmented inspections on additional tendons beyond those selected for the ASME Section XI, Subsection IWL program. The Braidwood augmented inspections are performed on a 5 year frequency, in conjunction with the ASME Section XI, Subsection IWL aging management program. The current augmented examinations of additional tendons will continue until the periodic tendon water monitoring and grease sampling program described above is implemented.

Corrective actions will be taken as necessary to ensure that the

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tendon grease meets ASME Section XI, Subsection IWL requirements

4. Explicitly require that areas of concrete deterioration and distress be recorded in accordance with the guidance provided in ACI 349.3R. The visual resolution capability of direct and remote examination techniques will be sufficient to detect concrete degradation at the levels described in Chapter 5 of ACI 349.3R. The resolution capability of the optical aids used for remote examinations will be demonstrated as equivalent to direct visual examination.

5. Include quantitative acceptance criteria, based on the "Evaluation Criteria" provided in Chapter 5 of ACI 349.3R, that will be used to augment the qualitative assessment of the Responsible Engineer. In addition, the Responsible Engineer will confirm that the visual resolution capability used for the concrete Containment Structure examinations was sufficient to evaluate the examination results against the quantitative criteria acceptance criteria described in Chapter 5 of ACI 349.3R.

31 ASME Section XI, ASME Section XI, Subsection IWF is an existing program that will be Program to be enhanced no Section A.2.1.31 Subsection IWF enhanced to: later than six months prior to the period of extended Exelon Letter

1. Add the MC supports for the transfer tube in the refueling cavity operation and one-time RS-14-052 in the Containment Structure and refueling canal in the Fuel volumetric examinations to be 03/04/2014 Handling Building to the scope of the program. performed prior to the period of RAIs extended operation. B.2.1.31-1

2. Revise implementing documents to provide guidance for proper B.2.1.31-2 specification of bolting material, storage, lubricants and Pre-PEO examinations B.2.1.31-3 sealants, and installation torque or tension to prevent or specified in Enhancements 4 mitigate degradation and failure of structural bolting. Bolting and 5 will be completed material with actual measured yield strength of 150 ksi or either no later than six Exelon Letter greater shall not be used in plant changes without engineering months prior to the PEO, or RS-14-170 approval, due to consideration of stress corrosion cracking before the end of the last 06/16/2014 vulnerability. Storage requirements for high strength bolts shall refueling outage prior to the RAI include the recommendations of the Research Council for PEO, whichever occurs later. B.2.1.31-1a Structural Connections, Specification for Structural Joints

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Using ASTM A325 or A490 Bolts, Section 2. Lubricants that Exelon Letter contain molybdenum disulfide (MoS2) shall not be applied to RS-14-235 high strength structural bolts within the scope of license 08/29/2014 renewal.

3. Provide procedural guidance, regarding the selection of supports to be inspected on subsequent inspections, when a support is repaired in accordance with the corrective action program. The enhanced guidance will ensure that the supports inspected on subsequent inspections are representative of the general population.

4. Perform one-time volumetric examinations on a sample of ASTM A490 bolts, greater than one-inch nominal diameter for the detection of stress corrosion cracking prior to the period of extended operation. Volumetric examinations will be performed in accordance with the requirements of ASME Code Section XI, Appendix VIII, Supplement 8. The sample will consist of bounding and representative A490 bolt sizes, joint configurations, and environmental exposure conditions. The sample will consist of 20% of the ASTM A490 bolts greater than one-inch nominal diameter or a maximum of 25 ASTM A490 bolts total for both Byron and Braidwood stations. The selection of the samples will consider susceptibility to stress corrosion cracking (e.g., actual measured yield strength) and ALARA principles. Any adverse results of the volumetric examinations will be entered into the corrective action program and will be evaluated by engineering to determine if additional actions are warranted such as expansion of sample size, scope, and frequency of any additional supplemental visual or volumetric examinations, as well as any code requirements specified by ASME Section XI, Subsection IWF. Specifically, the implementing documents for performing the one-time volumetric examinations will have criteria for extending the ASTM A490 bolt examination scope to other ASTM A490 bolts used in similar joint configurations and environmental exposure conditions if the volumetric examination of a bolt shows adverse

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results, which is similar to the methodology used by the ASME Code IWF-2430 for IWF component supports. In addition, the program will be revised to include periodic volumetric examinations, of ASTM A490 bolts in sizes greater than one-inch nominal diameter, if the one-time volumetric examination of an ASTM A490 bolt shows signs of cracking. The periodic examinations of the ASTM A490 bolts are included in the periodic examination of the supports. For the periodic examinations of supports, the population of the supports examined is specified in Table IWF-2500-1. Consistent with the GALL Report, the periodic examinations will include volumetric examinations of high-strength bolts to detect cracking, if required, in addition to the VT-3 examinations of the high-strength bolts.

5. Revise implementing documents to perform periodic visual examinations to detect a corrosive environment that supports SCC potential for all (100%) of high strength bolting greater than one-inch nominal diameter prior to the period of extended operation, and then each inspection interval of 10 years thereafter. The periodic visual examinations will include criteria to identify if the bolting has been exposed to moisture or other contaminants by evidence of moisture, residue, foreign substance, or corrosion. Adverse conditions identified during the examinations will be evaluated by engineering to determine if the bolt has been exposed to a corrosive environment with the potential to cause SCC. The bolts determined to have been exposed to corrosive environment with the potential to cause SCC will be included in a sample population for each specific bolt material where SCC is a concern. A sample size equal to 20 percent (rounded up to the nearest whole number) of the bolts in the sample population, with a maximum sample size of 25 bolts will be subject to supplemental volumetric examination to determine if SCC is present. The selection of the samples will consider susceptibility to stress corrosion cracking (e.g.,

actual measured yield strength) and ALARA principles.

Volumetric examinations will be performed in accordance with the requirements of ASME Code Section XI, Appendix VIII,

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Supplement 8. The results of the volumetric examinations will be evaluated by engineering to determine if additional actions are warranted such as expansion of sample size, scope, and frequency of any additional supplemental visual or volumetric examinations, as well as any code requirements specified by ASME Section XI, Subsection IWF.

6. Add the control rod drive mechanism seismic support assembly to the scope of the program to implement additional examinations.

32 10 CFR Part 50, Existing program is credited. Ongoing Section A.2.1.32 Appendix J 33 Masonry Walls Masonry Walls is an existing program that will be enhanced to: Program to be enhanced no Section A.2.1.33 later than six months prior to

1. Add masonry walls in the following structures to the program the period of extended scope: operation.

a. Radwaste and Service Building Complex

i. Radwaste Building ii. Original Service Building

b. Turbine Building Complex

c. Switchyard Structures

i. Relay House

2. Provide additional guidance for inspection of masonry walls for shrinkage, separation, and for gaps between the supports and the masonry walls that could impact the intended function of the masonry walls.

3. Require that personnel performing inspections and evaluations meet the qualifications described in ACI 349.3R.

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34 Structures Monitoring Structures Monitoring is an existing program that will be enhanced to: Program to be enhanced no Section A.2.1.34 later than six months prior to

1. Add the following structures: the period of extended Exelon Letter

a. Radwaste and Service Building Complex operation. RS-13-274

i. Radwaste Building 12/19/2013 ii. Original Service Building Pre-PEO activities specified RAI 2.1-3

b. Turbine Building Complex in Enhancement 16 will be

c. Yard Structures completed either no later

i. Transformer foundations than six months prior to the Exelon letter ii. Valve and line enclosures PEO, or before the end of RS-14-097

d. Fire protection structures-features the last refueling outage 04/17/2014

i. Transformer fire barrier walls prior to the PEO, whichever RAI B.2.1.34-1 ii. Fuel oil storage tank berm occurs later.

e. Containment structure features

i. Containment access facility hallway Exelon letter RS-14-169

2. Add the following components and commodities: 06/16/2014

a. Blowout panels RAI 3.5.2.10-1

b. Building features - doors and seals, bird screens, louvers, windows Exelon Letter

c. Compressible joints and seals, gaskets and moisture RS-14-216 barriers 12/15/2014

d. Concrete curbs

e. Electrical cable trays, conduits and tube tracks

f. Hatches and plugs

g. Insulation including jacketing

h. Manholes, handholes and duct banks

i. Metal components, including metal decking for concrete slabs, miscellaneous steel, sump screens and trench covers, and scuppers around the spent fuel pool

j. New fuel storage racks

k. Offgas stack and flue

l. Panels, racks, cabinets, and other enclosures

m. Penetration seals and sleeves

n. Pipe whip restraints, jet impingement shields, and spray shields

o. Pipe, electrical and equipment component support members

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p. Sliding surfaces

q. Spent fuel pool gates

r. Sumps and liners

3. Monitor groundwater chemistry on a frequency not to exceed five (5) years for pH, chlorides, and sulfates and evaluate results exceeding the threshold criteria to assess impact, if any, on below-grade concrete.

4. Based on groundwater chemistry monitoring results, select and inspect every five (5) years a structure that will be used as a leading indicator for the condition of below grade concrete exposed to groundwater.

5. Require (a) evaluation of the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of, or result in, degradation to such inaccessible areas and (b) examination of representative samples of the exposed portions of the below grade concrete, when excavated for any reason.

6. Provide guidance for proper specification of high strength bolting material and lubricant to prevent or mitigate degradation and failure of structural bolting.

7. Revise storage requirements for high strength bolts to include recommendations of Research Council on Structural Connections (RSCSRCSC) Specification for Structural Joints Using High Strength Bolts, Section 2.0.

8. Clarify that loose bolts and nuts, and cracked high strength bolts are not acceptable unless accepted by engineering evaluations.

9. Include the potential for reduction in concrete anchor capacity due to local concrete degradation.

10. Require that personnel performing inspections and evaluations

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meet the qualifications specified within ACI 349.3R with respect to knowledge of in-service inspection of concrete and visual acuity requirements.

11. Require acceptance and evaluation of structural concrete using quantitative criteria based on Chapter 5 of ACI 349.3R.

12. Perform inspection of elastomeric components such as vibration isolation elements and structural seals for cracking, loss of material and hardening. Visual inspections of elastomeric components are to be supplemented by feel or manipulation to detect hardening.

13. Monitor accessible sliding surfaces to detect loss of mechanical function or significant loss of material due to wear, corrosion, debris, dirt, distortion, or overload that could restrict or prevent sliding of surfaces as required by design.

14. Formalize requirements for the monitoring of the leak detection sight glasses associated with the refuel cavity, transfer canal, spent fuel pool, and refueling water storage tank on a periodic basis.

15. Require visual inspections of submerged concrete structural elements by dewatering a structure or by a diver if the structure is not dewatered at least once every five (5) years Note 2 (Byron only) .

16. At each site, perform one-time sampling activities on below grade, reinforced concrete at specific locations in the tendon tunnels. Select the locations exhibiting significant mineral deposits to serve as leading indicators for potential reinforced concrete degradation as a result of exposure to ground water in-leakage and build-up of mineral deposits. Take corrective actions, if necessary, prior to the period of extended operation.

Perform the one-time sampling activities as follows:

a. Obtain water in-leakage samples, at representative

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locations with mineral deposits due to water in-leakage, and analyze for pH, chlorides, sulfates, minerals, and iron content.

b. Obtain representative mineral deposit samples and analyze for chemical composition.

c. Remove three concrete core samples.

i. Test two of the concrete core samples for compressive strength and perform petrographic examination of the core samples. Select representative locations for the concrete core samples that include one with significant mineral deposits and another at a location with no mineral deposits for comparative purposes.

ii. Drill an additional core at a crack with significant mineral deposits and subject the core to petrographic examination.

d. Expose and examine reinforcing steel at two locations, with water in-leakage, cracks, and significant mineral deposits.

e. Collectively evaluate the results from the water in-leakage analysis, the chemical composition of the mineral deposits, examination of the exposed reinforcing steel, and the core sample testing to confirm there is no significant degradation to the reinforced concrete material properties and to determine if additional corrective actions are necessary.

Additional corrective actions may include, but are not limited to, an extent of condition review for other potentially impacted structures, more frequent examinations, and additional sampling and analysis, as appropriate.

17. Perform visual inspections of polymeric components, such as blowout panels, for changes in material properties.

Observations of material discoloration, cracking, crazing, and loss of material will provide visual indications of changes in material properties prior to a loss of component intended

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function.

35 RG 1.127, Inspection of RG 1.127, Inspection of Water-Control Structures Associated with The Byron Essential Service Section A.2.1.35 Water-Control Structures Nuclear Power Plants is an existing program that will be enhanced to: Water Cooling Tower Associated with Nuclear inspection and maintenance Exelon Letter Power Plants 1. Provide guidance for specification of structural bolting material plan (Enhancement 16) will RS-14-216 and bolting lubricants to prevent or mitigate degradation and be initiated upon receipt of the 12/15/2014 failure of structural bolting. renewed licenses, and will continue through the period of

2. Revise storage requirements for structural bolting to include extended operation to ensure recommendations of Research Council on Structural the condition of the SXCT is Connections (RSCSRCSC) Specification for Structural Joints maintained. The remainder of Using High Strength Bolts, Section 2.0. the enhancements will be implemented no later than six

3. Include the potential for reduction in concrete anchor capacity months prior to the period of due to local concrete degradation. extended operation.

4. Include all aging affects addressed by ACI 349.3R in procedures and require acceptance and evaluation of structural concrete using quantitative criteria based on Chapter 5 of ACI 349.3R.

5. Clarify that loose bolts and nuts, and cracked bolts are not acceptable unless accepted by engineering evaluations.

6. Require that steel components subject to RG 1.127 are inspected for loss of material.

7. Require that inspectors work under the direction of a qualified engineer for submerged concrete inspections.

8. Require special inspections also be performed in the event of large floods, hurricanes, and intense local rainfalls.

9. Require increased inspection frequency if the extent of the degradation is such that the structure or component may not meet its design basis if allowed to continue uncorrected until the next normally scheduled inspection.

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10. Require (a) evaluation of the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of, or result in, degradation to such inaccessible areas and (b) examination of representative samples of the exposed portions of the below grade concrete, when excavated for any reason.

11. Monitor raw water and groundwater chemistry at least once every five (5) years for pH, chlorides, and sulfates and verify that it remains non-aggressive, or evaluate results exceeding criteria to assess impact, if any, on submerged concrete.

12. Based on groundwater chemistry monitoring results, select and inspect every five (5) years a structure that will be used as a leading indicator for the condition of below grade concrete exposed to groundwater.

13. Require visual inspections of submerged concrete structural components by dewatering a structure or by a diver if the structure is not dewatered at least once every five (5) years.

Maintenance procedures will be enhanced to require opportunistic inspection of submerged concrete structures when they are dewatered and made accessible.

14. Require that degraded conditions be documented and trended until the condition is no longer occurring or until a corrective action is implemented.

15. Clarify parameters to be monitored and inspected at the Essential Service Water Cooling Towers to include visual inspection for loss of material and reduction of heat transfer for the cooling tower fill, and visual inspection with physical manipulation for change in material properties associated with the PVC drift eliminators and fiberglass support beams for the Note 2 drift eliminators (Byron only) .

16. Manage the condition of the Byron Essential Service Water

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Cooling Towers (SXCTs) as follows:

a. Monitor and trend inspection activities at the SXCTs on an increased frequency, with inspections of the entire tower on a three (3) year interval, and inspections of the fill support beams and air-inlet framing on a 1.5-year interval. The recommendations in Chapter 5 of ACI 349.3R will be used for quantitative acceptance and evaluation criteria.

b. Develop a repair plan to address degradation of the SXCTs with specific emphasis and consideration for the fill support beams. Repairs that are required will be scheduled based on a ranking of the condition observed and the potential for the degradation to progress or propagate.

36 Protective Coating Protective Coating Monitoring and Maintenance Program is an Program to be enhanced no Section A.2.1.36 Monitoring and existing program that will be enhanced to: later than six months prior to Maintenance Program the period of extended

1. Add recurring work orders requiring Service Level I coating operation.

inspections every refuel outage.

2. Require qualification of coating inspectors to ASTM D 5498.

3. Require qualification of personnel in accordance with ASTM D 7108.

4. Incorporate guidance for inspection and maintenance of Service Level I coatings per Regulatory Guide 1.54 and impose ASTM D 5163-08 requirements for Service Level I coatings condition assessment, reporting, evaluation, and documentation.

5. Require thorough visual inspections of all coatings near sumps or screens associated with the Emergency Core Cooling System (ECCS) by the coatings inspector(s).

6. Specify instruments and equipment that may be needed for

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Service Level I coatings inspections.

37 Insulation Material for Insulation Material for Electrical Cables and Connections Not Subject Program and initial inspections Section A.2.1.37 Electrical Cables and to 10 CFR 50.49 Environmental Qualification Requirements is a new to be implemented no later Connections Not Subject to program that will be used to manage aging of the insulation material than six months prior to the 10 CFR 50.49 for non-EQ cables and connections. Accessible cables and period of extended operation.

Environmental Qualification connections located in adverse localized environments will be visually Requirements inspected at least once every 10 years for indications of reduced Initial inspections will be insulation resistance, such as embrittlement, discoloration, cracking, completed either no later melting, swelling, or surface contamination. than six months prior to the PEO, or before the end of the last refueling outage prior to the PEO, whichever occurs later.

38 Insulation Material for Insulation Material for Electrical Cables and Connections Not Subject Program and initial Section A.2.1.38 Electrical Cables and to 10 CFR 50.49 Environmental Qualification Requirements Used in assessment of calibration and Connections Not Subject to Instrumentation Circuits is a new program that will be used to test results to be implemented Exelon letter 10 CFR 50.49 manage aging of non-EQ cable and connection insulation of the in- no later than six months RS-14-030 Environmental Qualification scope portions of the radiation monitoring system (Byron and prior to the period of extended 02/04/2014 Requirements Used in Braidwood) and the neutron monitoring inputs to the reactor operation.

Instrumentation Circuits protection system (Braidwood only) Note 2. RAI B.2.1.38-2 Assessment schedule RAI B.2.1.38-3 Calibration and cable tests (such as insulation resistance tests, time identified in commitment.

domain reflectometry tests, or other testing judged to be effective in Initial calibration, cable tests determining cable system insulation condition) will be performed and and evaluation of results will results will be assessed for reduced insulation resistance prior to the be completed either no later period of extended operation and at least once every 10 years during than six months prior to the the period of extended operation. PEO, or before the end of the last refueling outage prior to the PEO, whichever occurs later.

39 Inaccessible Power Cables Inaccessible Power Cables Not Subject to 10 CFR 50.49 Program to be implemented Section A.2.1.39 Not Subject to Environmental Qualification Requirements is a new program that will no later than six months 10 CFR 50.49 be used to manage the aging effects and mechanisms of non-EQ, in prior to the period of extended Exelon letter Environmental Qualification scope, inaccessible power cables. operation. RS-14-041 Requirements 02/19/2014 Cables will be tested using one or more proven tests for detecting First cable tests and manhole

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reduced insulation resistance of the cables insulation system. The inspections will be completed RAI B.2.1.39-2 cables will be tested at least once every 6 years. More frequent either no later than six testing may occur based on test results and operating experience. months prior to the PEO, or before the end of the last Periodic actions will be taken to prevent inaccessible cables from refueling outage prior to the being exposed to significant moisture. Manholes associated with the PEO, whichever occurs later.

cables included in this program will be inspected for water collection to be performed prior to the with subsequent corrective actions (e.g., water removal), as period of extended operation.

necessary. Prior to the period of extended operation, the frequency of inspections for accumulated water will be established and adjusted based on plant specific operating experience with cable wetting or submergence, including water accumulation over time and event driven occurrences such as heavy rain or flooding. Operation of dewatering devices, if installed, will be verified prior to any known or predicted heavy rain or flooding event. During the period of extended operation, the inspections will occur at least annually.

40 Metal Enclosed Bus Metal Enclosed Bus is an existing program that will be enhanced to: Program to be enhanced no Section A.2.1.40 later than six months prior to

1. Specify that a sample size of 20 percent of the accessible the period of extended bolted connection population with a maximum sample size of 25 operation.

to be inspected for increased resistance of connection by measuring the connection resistance using a micro-ohmmeter.

3. Specify that the external surfaces of metal enclosed bus enclosure assemblies are to be inspected for loss of material due to general, pitting, and crevice corrosion.

4. Specify maximum allowed bus connection resistance values.

41 Fuse Holders Fuse Holders (Byron only) Note 2 aging management program is a new Program and initial tests to be Section A.2.1.41 (Byron only) Note 2 program that applies to fuse holders located outside of active devices implemented no later than six that have been identified as susceptible to aging effects. months prior to the period of extended operation.

Fuse holders subject to increased resistance of connection or fatigue, will be tested, by a proven test methodology, at least once every 10 Initial resistance tests will be years for indications of aging degradation. Visual inspection is not completed either no later part of this program. than six months prior to the

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PEO, or before the end of the last refueling outage prior to the PEO, whichever occurs later.

42 Electrical Cable Electrical Cable Connections Not Subject to 10 CFR 50.49 Program and one-time tests to Section A.2.1.42 Connections Not Subject to Environmental Qualification Requirements program is a new program be implemented no later than 10 CFR 50.49 that will implement one-time testing of a representative sample (20 six months prior to the period Environmental Qualification percent with a maximum sample size of 25) of non-EQ electrical of extended operation.

Requirements cable connections to ensure that either aging of metallic cable connections is not occurring or that the existing preventive One-time tests will be maintenance program is effective such that a periodic inspection completed either no later program is not required. than six months prior to the PEO, or before the end of the last refueling outage prior to the PEO, whichever occurs later.

43 Fatigue Monitoring Fatigue Monitoring is an existing program that will be enhanced to: Program to be enhanced no Section A.3.1.1 later than six months prior to

1. Address the cumulative fatigue damage effects of the reactor the period of extended Exelon letter coolant environment on component life by evaluating the impact operation. RS-14-002 of the reactor coolant environment on critical components for 01/13/2014 the plant identified in NUREG/CR-6260. Additional plant- Environmental fatigue specific component locations in the reactor coolant pressure evaluations to be performed RAI B.3.1.1-2 boundary will be evaluated if they are more limiting than those will be completed no later considered in NUREG/CR-6260. than six months prior to the period of extended operation.

2. Monitor and track additional plant transients that are significant contributors to component fatigue usage.

3. Evaluate the effects of the reactor coolant system water environment on the reactor vessel internal components with existing fatigue CUF analyses to satisfy the evaluation requirements of ASME Code,Section III, Subsection NG-2160 and NG-3121.

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4. Increase the scope of the program to include transients used in the analyses for ASME Section III fatigue exemptions, the allowable stress analyses associated with ASME Section III and ANSI B31.1, and the flaw evaluation analyses performed in accordance with ASME Section XI, IWB-3600.

44 Concrete Containment Concrete Containment Tendon Prestress is an existing program that Program to be enhanced no Section A.3.1.2 Tendon Prestress will be enhanced to: later than six months prior to the period of extended

1. For each surveillance interval, the predicted lower-limit, operation.

minimum required value, and trending lines will be developed for the period of extended operation as part of the regression analysis for each tendon group.

45 Environmental Qualification The Environmental Qualification (EQ) of Electric Components aging Program to be enhanced no Section A.3.1.3 (EQ) of Electric management program will be enhanced: later than six months prior to Components the period of extended Exelon letter

1. To expand the scope of the program to include mechanical operation. RS-14-079 environmental qualification (MEQ) components. 03/04/2014 RAI 4.7.3-1 46 Operating Experience The Operating Experience Program is an existing program that will Program to be enhanced no Section A.1.6 be enhanced to: later than the date that the renewed operating licenses

1. Require the review of internal and external operating experience are issued and conducted on for aging-related degradation or impacts to aging management an ongoing basis throughout activities, to determine if improvements to Byron and Braidwood the terms of the renewed Units 1 and 2 aging management activities are warranted. NRC licenses.

and industry guidance documents and standards applicable to aging management are considered part of this information (e.g.,

License Renewal Interim Staff Guidance (LR-ISG) documents, NUREG-1801 (GALL) revisions, etc.) Ensure there are written expectations for identifying and processing these documents as operating experience.

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2. Establish criteria to define aging-related degradation. In general, the criteria will be used to identify aging that is in excess of what would be expected, relative to design, previous inspection experience and the inspection intervals.

3. Establish identification coding within the corrective action program for use in identification, trending and communications of aging-related degradation. Provide a definition for the coding.

This coding will assist plant personnel in ensuring that, in addition to addressing the specific issue, the adequacy of existing aging management programs is assessed. Station personnel are required to periodically assess the performance of the aging management programs, including insights obtained through operating experience. Adverse trends are entered into the corrective action program for evaluation. This could lead to AMP revisions or the establishment of new AMPs, as appropriate.

4. Require communication of significant internal aging-related degradation, associated with SSCs in the scope of license renewal, to other Exelon plants and to the industry. Criteria will be established for determining when aging-related degradation is significant.

5. Provide training to those responsible for screening, evaluating and communicating operating experience items related to aging management and aging-related degradation. This training will be commensurate with their role in the process, will be provided periodically and include provisions to accommodate personnel turnover.

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47 Byron Unit 2 Reactor Head Byron Unit 2 reactor head closure stud location 11 will be repaired so No later than 6six months prior Exelon letter Closure Stud Configuration that all 54 reactor head closure studs are tensioned during the period to the period of extended RS-13-285 (Byron only)Note 2 of extended operation. operation. 12/19/2013 RAI B.2.1.3-2 updated response Exelon letter RS-14-216 12/15/2014 48 Braidwood Unit 2 Reactor Braidwood Unit 2 reactor head closure stud location 35 will be No later than 6six months prior Exelon letter Head Closure Stud repaired so that all 54 reactor head closure studs are tensioned to the period of extended RS-13-285 Configuration during the period of extended operation. operation. 12/19/2013 (Braidwood only)Note 2 RAI B.2.1.3-2 updated response Exelon letter RS-14-216 12/15/2014

• The dates for the start of the respective periods of extended operation for the Byron and Braidwood Units are:

Byron Unit 1: October 31, 2024 Bryon Unit 2: November 6, 2026 Braidwood Unit 1: October 17, 2026 Braidwood Unit 2: December 18, 2027 Exelon letter RS-14-216, responding to NRC RAI A.1-1, resulted in refining commitment implementation timing requirements as shown throughout the above table, in order to provide time for NRC inspection of commitment implementation prior to the plants entering their respective periods of extended operation.