RS-14-130, Responses to NRC Requests for Additional Information, Set 18, Dated April 10, 2014, Related to the Braidwood Station, Units 1 and 2, and Byron Station, Units 1 and 2, License Renewal Application

Responses to NRC Requests for Additional Information, Set 18, Dated April 10, 2014, Related to the Braidwood Station, Units 1 and 2, and Byron Station, Units 1 and 2, License Renewal Application

ML14132A139
Person / Time
Site:	Byron, Braidwood
Issue date:	05/12/2014
From:	Gallagher M Exelon Generation Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
RS-14-130
Download: ML14132A139 (37)

Text

Michael P. Gallagher Vice President. License Renewal Exelon Nuclear Exelon Generation 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-14-130 May 12, 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:

Responses to NRC Requests for Additional Information, Set 18, dated April 10, 2014, related to the Braidwood Station, Units 1 and 2, and Byron 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 April 10, 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 18 (TAC NOS. MF1879, MF1880, MF1881, AND MF1882)"

In the Reference 1 letter, 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 (BBS). In the Reference 21etter, the NRC requested additional information to support staff review of the LRA.

Enclosure A contains the responses to these requests for additional information.

Enclosure B contains updates to sections of the LRA affected by the responses.

May 12, 2014 U.S. Nuclear Regulatory Commission Page 2 There are no new or revised regulatory commitments contained in this letter.

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

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

Executed on § . . I Z -Z,l)J~

Respectfully,

~rf~

Vice President - License Renewal Projects Exelon Generation Company, LLC

Enclosures:

A: Responses to Requests for Additional Information B: Updates to affected LRA sections 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-14-130 Enclosure A Page 1 of 13 Enclosure A Byron and Braidwood Stations (BBS), Units 1 and 2 License Renewal Application Responses to Requests for Additional Information RAI 3.1.2.3.4-1 RAI 3.0.3-3a RAI B.2.1.7-3 RAI 2.3.4.2-1 RAI 2.3.4.4-1

RS-14-130 Enclosure A Page 2 of 13 RAI 3.1.2.3.4-1 Applicability:

Byron Station (Byron) and Braidwood Station (Braidwood), Unit 1

Background:

License renewal application (LRA) Table 3.1.2-4 addresses loss of fracture toughness in steam generator internal structural supports exposed to treated water > 482 ºF at Byron and Braidwood, Unit 1. The LRA states that the steam generator tube support lattice bar is fabricated from SA-240 410S martensitic stainless steel (SS), and the steam generator tube support lattice bar attachment component is fabricated from SA-351 CF3M cast austenitic SS.

The LRA Table provides a note H for this component, material, and environment. Note H states that this aging effect (i.e., loss of fracture toughness) is not in NUREG-1801 for the component, material, and environment combination. Visual inspections and eddy current testing were proposed to manage this degradation mechanism.

Issue:

The staff needs additional information concerning the degradation mechanism and the component/environment to ascertain whether the proposed aging management program is adequate.

Request:

Please provide a description of these components (including their function) and the extent to which they are used throughout the steam generator. Please discuss the susceptibility of these particular components to thermal aging embrittlement (

Reference:

Letter from C.I. Grimes, NRC, to Douglas J. Walters, Nuclear Energy Institute, License Renewal Issue No. 98-0030, Thermal Aging Embrittlement of Cast Stainless Steel Components, dated May 19, 2000, ML003717179). Discuss how visual inspections and eddy current testing will be adequate to ensure any loss of fracture toughness that does occur will be limited such that the component will continue to be able to perform its intended safety function during normal operation, transient, and accident conditions. That is, discuss the possibility that the loss of fracture toughness would render the component incapable of performing its function without the component showing any visual evidence of cracking, deformation, or damage.

Exelon Response:

The original equipment Westinghouse steam generators at Byron and Braidwood Station, Unit 1 were replaced with Babcock and Wilcox steam generators in 1998. These replacement steam generators were designed for a minimum of 40 years of operation. At the end of the period of extended operation, the Byron Station, Unit 1 steam generators will have been in service for approximately 46 years and the Braidwood Station, Unit 1 steam generators will have been in service for approximately 48 years. The operating temperature of the steam generator internals ranges from approximately 533 degrees Fahrenheit at rated steam flow and 557 degrees

RS-14-130 Enclosure A Page 3 of 13 Fahrenheit at zero steam flow. The Babcock and Wilcox steam generators utilize a lattice grid tube support design rather than a drilled plate tube support design.

SA-240 Type 410S Components The tube support lattice bar consists of the lattice grid supports and U-bend supports. The SA-240 410S martensitic stainless steel is used in the fabrication of the lattice grid supports and the U-bend supports. The lattice grid supports and the U-bend supports are non-pressure retaining components and therefore, not within the ASME jurisdictional boundary. Type 410S martensitic stainless steel was selected for all tube support components that are in contact with the steam generator tubes. Type 410S martensitic stainless steel was selected on the basis of attaining the required strength without cold work, forming a thin, non-voluminous oxide (precluding tube denting), exhibiting good corrosion resistance in the welded and stress-relieved condition, and compatibility with Alloy 690 tube material.

The lattice grid supports are positioned at various steam generator elevations to provide lateral support of the straight section of the steam generator tubes. Each steam generator has nine (9) lattice grid supports made up of a series of non-welded interlocking flat rectangular bars creating diamond-shaped openings for the steam generator tubes to pass through. The Type 410S martensitic stainless steel components that make up the lattice grid supports include the high bars, low bars, medium bars, and span breaker bars. The high, medium, and low bars make up the lattice grid which is sandwiched between the no-tube-line bars (made of carbon steel) and the span breaker bars. The main function of the lattice grid supports is to preclude excessive flow-induced vibration (FIV) and seismic-induced vibration of the steam generator tubes.

The U-bend support (one (1) per steam generator) is made up of flat rectangular bars and tubing welded together in a fan arrangement positioned on each side of the steam generator tube bundle. The U-bend support components made of Type 410S martensitic stainless steel are the fan bars and connector bars. The function of the U-bend support is to restrain the steam generator tubes against FIV.

The potential for thermal aging embrittlement of martensitic stainless steel is addressed in NUREG/CR-6923, Expert Panel Report on Proactive Materials Degradation Assessment.

NUREG/CR-6923 states two (2) main thermal aging embrittlement mechanisms of martensitic stainless steel are recognized. The first reversible temper embrittlement is related to the diffusion of phosphorus, arsenic, antimony, and tin to grain boundaries at aging temperatures generally above 750 degrees Fahrenheit. As stated earlier, the highest normal operating temperature of the steam generator internals is 557 degrees Fahrenheit which is below the 750 degrees Fahrenheit temperature at which reversible temper embrittlement is expected to occur.

The second thermal aging embrittlement mechanism arises from an intra-granular decomposition of the martensitic matrix into two (2) phases. This thermal aging embrittlement mechanism is relevant only to precipitation-hardened stainless steels. The Type 410S martensitic stainless steel used in the lattice grid supports and U-bend support is not precipitation-hardened; therefore this aging mechanism is not applicable.

RS-14-130 Enclosure A Page 4 of 13 Based on the information provided in NUREG/CR-6923, the steam generator components fabricated from Type 410S martensitic stainless steel do not operate in conditions associated with the thermal aging embrittlement of martensitic stainless steel and are not precipitation-hardened. Therefore, the aging effect/mechanism of loss of fracture toughness due to thermal aging embrittlement is not applicable to LRA Table 3.1.2-4, line item Steam Generators (Tube Support Plates and U-bend Supports).

LRA Table 3.1.2-4 and Note 6 are revised as shown in Enclosure B.

SA-351 CF3M Components The steam generator tube support lattice bar attachment components fabricated from SA-351 CF3M cast austenitic stainless steel (CASS) include various hardware fittings (i.e., end connection, centre connection, and link bar) used to clamp the span breaker bars to the lattice grids. The span breaker bars along with the no-tube-lane bars sandwich the lattice grid suppressing the out-of-plane deflection of the lattice grid by distributing loads from the grid bars (high, medium, and low) to the lattice grid assembly as a whole. Out-of-plane forces are generally caused by friction when tubes slide vertically on the lattice grid support due to tube expansion during heat-up and pressure drop as fluid flows across the grid during operation (flow-induced) or a burst pipe event. The failure of a steam generator CASS component would result in a loose part or displacement of a span breaker bar which could impact the steam generator tubes.

The potential for thermal aging embrittlement of CASS is addressed in NRC Letter from C.I.

Grimes, NRC, to Douglas J. Walters, Nuclear Energy Institute, License Renewal Issue No. 98-0030, Thermal Aging Embrittlement of Cast Stainless Steel Components, dated May 19, 2000 (Accession Number ML003717179). This NRC letter applies to reactor coolant pressure boundary and reactor vessel internal components. The steam generator CASS components are not pressure-retaining components. The concern with reactor vessel internal components is the potential synergistic effect of neutron irradiation embrittlement and thermal aging embrittlement.

The steam generator CASS components are not exposed to high neutron fluence levels, therefore, the concern of synergistic effects does not apply.

The temperature of the steam generator CASS components during power operations ranges from 533 degrees Fahrenheit at rated steam flow and 557 degrees Fahrenheit at zero steam flow. These temperatures are in the range of temperatures (536-662 degrees Fahrenheit) stated in the NRC letter that can lead to changes in the mechanical properties of CASS. The concern associated with thermal aging embrittlement is the reduction in fracture toughness of a component at low temperatures (i.e., room temperature) and the potential for non-ductile failure at low temperatures. The material properties at high temperature are not affected. As stated above, the function of the steam generator CASS components is to attach the span breaker bars to the lattice grids. The function of the span breaker bars is to distribute out-of-plane forces to the lattice grid as a whole. These out-of-plane forces are not present at low temperatures since there is no steam flow and minimal tube thermal expansion, therefore, the steam generator CASS components are not required to perform an intended function at low temperatures. The loading on the CASS components at low temperatures is negligible and since the components are not pressure-retaining, no mechanism exists to apply excessive loading. Therefore, fracture of a CASS component is not expected at low temperatures. Since

RS-14-130 Enclosure A Page 5 of 13 the loading on the CASS components at low temperature is negligible, the possibility that loss of fracture toughness would render the component incapable of performing its function without showing any visual evidence of cracking, deformation, or damage is also negligible. Based on the guidance given for reactor vessel internals components in the NRC letter, no additional inspections of the steam generator CASS components due to thermal aging embrittlement are considered necessary. The NRC letter states, If the loading is compressive or low enough to preclude fracture of the component, then the component would not require supplemental inspection.

LRA Table 3.1.2-4, Note 3 is revised as shown in Enclosure B.

Conclusion The possibility that the loss of fracture toughness would render the component incapable of performing its intended function without the component showing any visual evidence of cracking, deformation, or damage is negligible based on:

The relatively young age of the Unit 1 replacement steam generators at the end of the period of extended operation (Byron - 46 years, Braidwood - 48 years)

The components are not pressure-retaining The martensitic stainless steel components are not precipitation-hardened and the operating temperature is below the threshold for reversible temper embrittlement The CASS components do not perform an intended function at low temperatures, and there are no significant stresses or loads on the CASS components at low temperatures LRA Table 3.1.2-4 is revised as shown in Enclosure B.

RS-14-130 Enclosure A Page 6 of 13 RAI 3.0.3-3a Applicability:

Byron and Braidwood

Background:

In a letter dated January 13, 2014, the responses to RAIs 3.0.3-3 and B.2.1.23-1 state that cracking due to stress corrosion cracking is not an aging effect in outdoor air environments for stainless steel and aluminum components that have jacketed insulation.

In regards to potential cracking due to halides in the atmosphere, the responses stated that (a) halide accumulation from the environment is not expected on components that are shielded by jacketed insulation and (b) insulated components located outdoors do not operate at high temperatures where concentration of environmental halides is expected to occur due to evaporation of any present moisture.

The Generic Aging Lessons Learned (GALL) Report age management program (AMP) XI.M36, External Surfaces Monitoring of Mechanical Components, recommends visual inspections for leakage to detect cracking on external surfaces that are exposed to an air environment containing halides.

Issue:

The staff recognizes that proper jacketing configuration can be a preventive measure for atmospheric halide intrusion; however, the staff considers a one-time inspection of exposed metal for evidence of cracking as necessary to ensure that the jacketing at Byron and Braidwood is an effective barrier. Also, it is not clear to the staff why the absence of high operating temperatures would prevent moisture from evaporating on an outdoor components surface.

Request:

For insulated stainless steel and aluminum piping and piping components exposed to outdoor air, provide the technical justification for why insulation does not need to be removed to conduct visual inspections to detect cracking in order to confirm the effectiveness of the insulation jacketing in preventing halide intrusion. Alternatively, propose to remove insulation during a baseline inspection for cracking that may be used to validate the subsequent use of insulation-only inspections and revise the associated AMR items to include cracking as an applicable aging effect. For nonwater-filled piping and piping components, state how potential leakage will be identified.

Exelon Response:

The basis for the changes to NUREG-1801, Generic Aging Lessons Learned (GALL) with respect to corrosion under insulation provided in LR-ISG-2012-02, Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under

RS-14-130 Enclosure A Page 7 of 13 Insulation are (1) two examples of industry operating experience of corrosion (not stress corrosion cracking) of the external surface of insulated components and (2) information provided in NACE Standard SP0198-2010, Control of Corrosion Under Thermal Insulation and Fireproofing Materials - A Systems Approach. As stated in the responses to RAIs 3.0.3-3 and B.2.1.23-1 provided in Exelon letter RS-14-003, dated January 13, 2013, NACE SP0198-2010 states that stress corrosion cracking (SCC) of stainless steel can occur when halides are transported in the presence of water to the hot surface of components and then concentrated by the evaporation of that water. Therefore, it is considered unlikely that SCC will occur due to the concentration of halides from evaporation of moisture on the surface of insulated components in the absence of high system operating temperatures. In addition, halide contamination of the surface of outdoor insulated aluminum and stainless steel piping and piping components is only possible if there is a source of halides. As described in the responses to RAIs 3.0.3-3 and B.2.1.23-1, the insulation in use on the outdoor insulated aluminum and stainless steel piping and components at Byron and Braidwood do not contain leachable halides. Furthermore, as described in LRA Sections 3.2.2.2.6, 3.3.2.2.3, and 3.4.2.2.2, SCC halide contamination from environmental sources is not expected to occur. The conclusions made in LRA Sections 3.2.2.2.6, 3.3.2.2.3, and 3.4.2.2.2 are supported by the results of surface smear sampling of outdoor surfaces which confirms that halide concentrations due to contamination from environmental sources are acceptable with respect to susceptibility to SCC. Based on the above, it is highly unlikely that SCC of outdoor insulated aluminum and stainless steel piping and piping components will occur.

Although SCC of outdoor insulated aluminum and stainless steel piping and piping is highly unlikely, a one-time visual inspection of a representative sample of the external surface of these components will be performed to confirm that SCC is not occurring. Water-filled piping and piping components will be inspected for signs of leakage as recommended GALL Report AMP XI.M36, External Surfaces Monitoring of Mechanical Components. Stainless steel portions of exhaust lines will be visually inspected for signs of discoloration or staining of the external surface of the component due to leakage of exhaust gases. Other nonwater-filled piping and piping components will be inspected using a nondestructive testing technique capable of detecting indications of SCC (i.e., surface or volumetric examinations).

LRA Sections 3.2.2.2.6, 3.3.2.2.3, and 3.4.2.2.2; and LRA Tables 3.2.1, 3.2.2-4, 3.3.1, 3.3.2-1, 3.3.2-12, 3.4.1, and 3.4.2-3 are revised as shown in Enclosure B.

RS-14-130 Enclosure A Page 8 of 13 RAI B.2.1.7-3 Applicability:

Byron and Braidwood

Background:

LRA Appendix C discusses the applicants response to Action/License Action Item (A/LAI) No.3.

The applicant stated that the original equipment alloy X-750 control rod guide tube (CRGT) split pins were proactively replaced at Byron and Braidwood, Unit 1 and 2, with cold-worked 316 stainless steel split pins based on industry guidance. In addition, the applicant explained that there are currently no vendor specific requirements to inspect the replacement CRGT split pins; however, through the stations participation in industry groups and the evaluation of industry operating experience, this position may change as warranted.

The staff noted that Section 3.5.2.3 of the NRCs safety evaluation, Revision 1, for the topical report, MRP-227-A, Materials Reliability Program: Pressurized Water Reactor Internals Inspection and Evaluation Guidelines (MRP-227-A), states that applicants shall evaluate the adequacy of their plant-specific existing program and ensure that the aging degradation is adequately managed during the period of extended operation for type 316 stainless steel split pins. MRP-227 further states, in part, that it is recommended that the evaluation performed by the applicant, in response to A/LAI No. 3, consider the need to replace the Alloy X-750 support pins (split pins), if applicable, or inspect the replacement Type 316 stainless steel support pins (split pins) to ensure that cracking has been mitigated and that aging degradation is adequately monitored during the extended period of operation.

Issue:

Since the applicant has already replaced all of its X-750 split pins at Byron and Braidwood and the applicant is not proposing to inspect the replacement Type 316 stainless steel support pins (split pins), it is not clear to the staff how the applicant will ensure that cracking has been mitigated and that aging degradation is adequately monitored during the period of extended operation.

Request:

1. Describe in detail (e.g., inspection scope, frequency, technique, etc.) and justify how it will be ensured by the applicant that cracking has been mitigated for the replacement Type 316 stainless steel support pins (split pins) and that age-related degradation is adequately monitored during the period of extended operation.

2. If inspection of the replacement Type 316 stainless steel support pins (split pins) are not proposed, provide the basis that Section 3.5.2.3 of the NRCs safety evaluation, Revision 1, for the topical report, MRP-227-A, and A/LAI No.3 are adequately addressed in the LRA and that age-related degradation, including cracking due to stress corrosion

RS-14-130 Enclosure A Page 9 of 13 cracking of the CRGT split pins, will be adequately managed during the period of extended operation.

Exelon Response:

1. Specific inspection of the cold-worked 316 stainless steel replacement control rod guide tube (CRGT) support pins, also known as split pins, for cracking is not considered necessary as justified below.

2. The cold-worked 316 stainless steel replacement CRGT support pins installed at Byron and Braidwood Stations, Units 1 and 2, were qualified for a 40 year life, assuming a capacity factor of 100 percent, and were installed after each of the reactors had operated for at least 20 years. The replacement CRGT support pins were evaluated for long term material-related effects which included irradiation-assisted stress corrosion cracking (IASCC), primary water stress corrosion cracking (PWSCC), irradiation stress relaxation, irradiation swelling and densification, embrittlement, and toughness. The maximum yield strength of the material used to fabricate the CRGT support pins was maintained below 90 ksi in accordance with the guidance in USNRC Regulatory Guide 1.85, Materials Code Case Acceptability ASME Section III Division 1, Revision 30, for strain-hardened austenitic stainless steels (ASME Code Case N-60-4) to prevent concerns with stress corrosion cracking. In addition, fatigue and wear assessments were performed for the replacement support pins. No additional performance monitoring requirements were recommended by the support pin manufacturer.

The CRGT support pins provide alignment of the lower end of CRGTs to the upper core plate within the upper internals assembly. The upper ends of the CRGTs are bolted to the upper support plate within the upper internals assembly. MRP-232, Material Reliability Program: Aging Management Strategies for Westinghouse and Combustion Engineering PWR Internals, states that the failure of the CRGT support pins does not challenge safe plant operation, nor do such failures compromise control rod functionality.

The CRGT support pins do not perform a core support function and are not classified as ASME Section XI Inservice Inspection Program B-N-3 core support components.

The CRGT support pins are located in the upper internals assembly which is classified as an ASME Section XI Inservice Inspection Program B-N-3 core support component.

The upper internals assembly is currently inspected by the ASME Section XI Inservice Inspection Program. The ASME Section XI Inservice Inspection Program provides the inspection category, techniques, and frequency for the upper internals assembly. The upper internals assembly is inspected during each ASME Section XI 10-year inservice inspection interval. The inspection consists of a VT-3 examination of the accessible component surfaces. Although the CRGT support pins are not specifically listed in the components examined, the upper core plate, CRGT, and locking devices are listed in the examination scope. Therefore, the visual inspection of the accessible portions of the exterior CRGT support pins is inherent in the VT-3 examination of the upper core plate, CRGT, and locking devices accessible surfaces.

RS-14-130 Enclosure A Page 10 of 13 In addition to the ASME Section XI Inservice Inspection Program B-N-3 examination, a foreign material inspection of the reactor vessel is performed every refueling outage prior to full core reload. Visual inspection of the steam generators primary channel heads are also conducted during refueling outages when eddy current testing is performed. These examinations and inspections should detect the presence of CRGT support pin fragments in the unlikely event that failure does occur. To date, there have been no documented failures of the cold-worked 316 stainless steel CRGT support pins in the industry due to stress corrosion cracking.

In summary, the evaluations performed to support installation of the cold-worked 316 stainless steel CRGT support pins adequately address potential aging degradation of the CRGT support pins and do not recommend ongoing performance monitoring activities.

The failure of the CRGT support pins does not challenge safe plant operation, nor does such failure compromise control rod functionality. The support pins are not considered B-N-3 core support components under the ASME Section XI Inservice Inspection Program. Existing examinations of the upper internals assembly and visual inspections of the reactor vessel, and steam generators primary channel heads for foreign material are considered adequate to monitor the integrity of the CRGT support pins during the period of extended operation.

LRA Appendix C is revised as shown in Enclosure B.

RS-14-130 Enclosure A Page 11 of 13 RAI 2.3.4.2-1 Applicability:

Byron

Background:

In LRA Section 2.1.5.2, the applicant stated for nonsafety related piping connected to safety related piping, the nonsafety related piping is assumed to provide structural support to the safety-related piping if the nonsafety related is within the analytical boundary of the current licensing basis (CLB) seismic analysis Issue:

LRA drawing LR-BYR-M-41 Sheet 3 (E5) shows a TSI label to indicate the 10 CFR 54.4(a)(2) spatial interaction termination for lines 1HD32BB 14 and 1HD32BD 14. However, for Unit 2 drawing LR-BYR-M-125 Sheet 3B (C/D-4), the staff could not locate the TSI labels to show the 10 CFR 54.4(a)(2) spatial interaction termination for similar lines 2HD32BB 14 and 2HD32BD 14.

Request:

The staff requests the applicant provide additional information to clarify the 10 CFR 54.4(a)(2) spatial interaction termination for lines 2HD32BB 14 and 2HD32BD 14.

Exelon Response:

Unlike LRA drawing LR-BYR-M-41 Sheet 3 (E5) for Unit 1, which shows a TSI label to indicate the 10 CFR 54.4(a)(2) spatial interaction termination for lines 1HD32BB 14 and 1HD32BD 14, LR-BYR-M-125, Sheet 3B (C/D-4) for Unit 2, uses a Note 3 to identify the termination point.

Both approaches are technically correct. In the early stages of boundary drawing development, notes were used to identify turbine spatial interaction end points. As more components were added, the TSI label was utilized to simplify the license renewal boundary drawings. In order to align to the established turbine spatial interaction nomenclature, the TSI labels will be placed on drawing LR-BYR-M-125, Sheet 3B, at the point where the lines 2HD32BB 14 and 2HD32BD 14 terminate at the heater drain tank. Note 3 will be removed from the drawing.

In addition, it was identified as part of this RAI review, that TSI labels were not shown for piping lines 2CDF6AA 1 (coordinate D-2), 2CDF6AB 1 (coordinate D-2), and 2CDF5AB 1 (coordinate D-6) which are connected to either 2HD32BB 14 or 2HD32BD 14 on drawing LR-BYR-M-125, Sheet 3B. Also, piping lines 2CDF6AA 1 and 2CDF6AB 1, including valves 2CD178A and 2CD178B, were inadvertently not shown in scope.

To correct these discrepancies, piping lines 2CDF6AA 1 and 2CDF6AB 1 will be shown in red up to and including isolation valves 2CD178A and 2CD178B, respectively. The TSI labels will be shown to the right of the isolation valves. Piping line 2CDF5AB 1 will remain black with the TSI label shown where the line connects to 2HD32BB 14. The added in scope piping and valves do not add any new component, material, and environment combinations to the Main Turbine and Auxiliaries System Aging Management Review.

RS-14-130 Enclosure A Page 12 of 13 LR-BYR-M-125, Sheet 3B is revised per the above discussion.

RS-14-130 Enclosure A Page 13 of 13 RAI 2.3.4.4-1 Applicability:

Byron

Background:

LRA Section 2.1, Scoping and Screening Methodology, describes the applicants scoping methodology, which specifies how systems or components were determined to be included in scope of license renewal. The staff confirmed the inclusion of all components subject to AMR by reviewing the results of the screening of components within the license renewal boundary.

Issue:

License renewal drawing LR-BYR-M-35 Sheet 3 (C5) shows several lines, including line 1M502EE 8, to be in scope for 10 CFR 54.4(a)(2). However, a portion of line 1M502EE 8 upstream of valve 1WG17DH 3/4 is shown as out of scope for license renewal.

Request:

The staff requests the applicant provide additional information to clarify the scoping classification of the 1M502EE 8 line upstream of valve 1WG17DH 3/4.

Exelon Response:

All of the steam dump lines, including the piping line segment identified above, are in scope for license renewal due to spatial interaction. The license renewal boundary drawing inadvertently shows a portion of the E steam dump line in black. LR-BYR-M-35 Sheet 3, at coordinate C-5, is revised to show the piping line as red to indicate that the piping line segment is within the scope of license renewal in accordance with 10 CFR 54.4(a)(2).

RS-14-130 Enclosure B Page 1 of 22 Enclosure B Byron and Braidwood Stations, Units 1 and 2 License Renewal Application (LRA) updates resulting from the responses to the following RAIs, contained in Enclosure A of this letter:

RAI 3.1.2.3.4-1 RAI 3.0.3-3a RAI B.2.1.7-3 Note: To facilitate understanding, portions of the original LRA have been repeated in this Enclosure, with revisions indicated. Existing LRA text, as revised by prior RAI responses, is shown in normal font. Changes are highlighted with bolded italics for inserted text and strikethroughs for deleted text.

RS-14-130 Enclosure B Page 2 of 22 As a result of the response to RAI 3.1.2.3.4-1 provided in Enclosure A of this letter, Table 3.1.2-4, Steam Generators, pages 3.1-115 and 3.1-122 are revised as shown below. Additions are indicated with bolded italics; deletions are shown with strikethroughs.

Table 3.1.2-4 Steam Generators (Continued)

Component Intended Material Environment Aging Effect Aging Management NUREG-1801 Table 1 Item Notes Type Function Requiring Programs Item Management Steam Generators Structural Support Cast Austenitic Treated Water > 482 F Loss of Material Water Chemistry (B.2.1.2) IV.D1.RP-226 3.1.1-71 A (Tube Support Stainless Steel (External)

Plates and U-Bend (CASS) - (Byron Supports) Unit 1 and Braidwood Unit 1 only)

Nickel Alloy Treated Water Cracking Steam Generators IV.D1.RP-384 3.1.1-71 B (External) (B.2.1.10)

Water Chemistry (B.2.1.2) IV.D1.RP-384 3.1.1-71 A Loss of Material Steam Generators IV.D1.RP-225 3.1.1-76 B (B.2.1.10)

IV.D1.RP-226 3.1.1-71 B Water Chemistry (B.2.1.2) IV.D1.RP-226 3.1.1-71 A Stainless Steel Treated Water > 140 F Cracking Steam Generators IV.D1.RP-384 3.1.1-71 B (External) - (Byron Unit (B.2.1.10) 2 and Braidwood Unit 2 Water Chemistry (B.2.1.2) IV.D1.RP-384 3.1.1-71 A only)

Loss of Material Steam Generators IV.D1.RP-225 3.1.1-76 B (B.2.1.10)

IV.D1.RP-226 3.1.1-71 B Water Chemistry (B.2.1.2) IV.D1.RP-226 3.1.1-71 A Treated Water > 482 F Cracking Steam Generators IV.D1.RP-384 3.1.1-71 B (External) - (Byron Unit (B.2.1.10) 1 and Braidwood Unit 1 Water Chemistry (B.2.1.2) IV.D1.RP-384 3.1.1-71 A only)

Loss of Fracture Steam Generators H, 6 Toughness (B.2.1.10)

Loss of Material Steam Generators IV.D1.RP-225 3.1.1-76 B (B.2.1.10)

IV.D1.RP-226 3.1.1-71 B

RS-14-130 Enclosure B Page 3 of 22 Table 3.1.2-4 Steam Generators (Continued)

Plant Specific Notes: (continued)

3. The Steam Generators (B.2.1.10) program inspection activities include periodic visual inspection of the steam generator secondary side internal components and eddy current testing of the steam generator tubes. The steam generator CASS components are non-pressure retaining, do not perform an intended function at low temperatures, and are not subjected to loads that would result in a non-ductile failure at low temperatures. No additional inspection activities are required to manage the loss of fracture toughness due to thermal aging embrittlement.The aging effect/mechanism of loss of fracture toughness due to thermal aging embrittlement is not in NUREG-1801 for this component, material, environment combination. Steam generator tube support lattice bar attachment components are fabricated from SA-351 CF3M cast austenitic stainless steel and potentially susceptible to loss of fracture toughness due to thermal aging embrittlement. These components are structural components internal to the secondary side of the steam generator and exposed to temperatures greater than 482 degrees Fahrenheit. The steam generator tube support lattice bar attachment components are a redundant set of components where the intended function of the overlying assembly does not rely upon and will not be impacted by a single component failure in the component population. The components are not Class 1 pressure boundary components, therefore, these components are not included in the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) (B.2.1.6) program. Loss of fracture toughness will be indirectly managed by the Steam Generators (B.2.1.10) program which will visually inspect the steam generator tube support lattice structure for gross cracking, deformation, or damage indicating a loss of fracture toughness. Eddy current testing of the steam generator tubes is also used to detect any abnormal or adverse interaction between the steam generator tube support lattice structure and the steam generator tubes.

4. The carbon steel components of the Steam Generators, including the shell, nozzles, instrument bosses, and manways, have an external temperature greater than 212 degrees Fahrenheit and are at a higher temperature than the air-indoor (uncontrolled) environment/air with borated water leakage. Therefore, wetting due to condensation and moisture accumulation will not occur and loss of material (due to general, pitting, and crevice corrosion) does not apply.

5. NUREG-1801 specifies a plant-specific program. The Steam Generators (B.2.1.10) program will be used to verify the effectiveness of the Water Chemistry (B.2.1.2) program to ensure that cracking due to stress corrosion cracking/primary water stress corrosion cracking is not occurring.

RS-14-130 Enclosure B Page 4 of 22

6. The aging effect/mechanism of loss of fracture toughness due to thermal aging embrittlement is not in NUREG-1801 for this component, material, environment combination. Steam generator tube support lattice bars are fabricated from SA-240 410S martensitic stainless steel and potentially susceptible to loss of fracture toughness due to thermal aging embrittlement. These components are structural components internal to the secondary side of the steam generator and exposed to temperatures greater than 482 degrees Fahrenheit. The steam generator tube support lattice bars are a redundant set of components where the intended function of the overlying assembly does not rely upon and will not be impacted by a single component failure in the component population. The components are not Class 1 pressure boundary components, therefore, these components are not included in the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) (B.2.1.6) program. Loss of fracture toughness will be indirectly managed by the Steam Generators (B.2.1.10) program which will visually inspect the steam generator tube support lattice structure for gross cracking, deformation, or damage indicating a loss of fracture toughness. Eddy current testing of the steam generator tubes is also used to detect any abnormal or adverse interaction between the steam generator tube support lattice structure and the steam generator tubes.Not used.

RS-14-130 Enclosure B Page 5 of 22 As a result of the response to RAI 3.0.3-3a provided in Enclosure A of this letter, LRA Section 3.2.2.2.6, is revised as shown below. Additions are indicated with bolded italics; deletions are shown with strikethroughs.

3.2.2.2.6 Cracking due to Stress Corrosion Cracking Cracking due to stress corrosion cracking could occur for stainless steel piping, piping components, piping elements and tanks exposed to outdoor air. The possibility of cracking also extends to components exposed to air which has recently been introduced into buildings, i.e.,

components near intake vents. Cracking is only known to occur in environments containing sufficient halides (primarily chlorides) and in which condensation or deliquescence is possible.

Condensation or deliquescence should generally be assumed to be possible. Applicable outdoor air environments (and associated indoor air environments) include, but are not limited to, those within approximately 5 miles of a saltwater coastline, those within 1/2 mile of a highway which is treated with salt in the wintertime, those areas in which the soil contains more than trace chlorides, those plants having cooling towers where the water is treated with chlorine or chlorine compounds, and those areas subject to chloride contamination from other agricultural or industrial sources. This item is applicable for the environments described above.

GALL AMP XI.M36, External Surfaces Monitoring is an acceptable method to manage the aging effect. The applicant may demonstrate that this item is not applicable by describing the outdoor air environment present at the plant and demonstrating that external chloride stress corrosion cracking is not expected. The GALL Report recommends further evaluation to determine whether an aging management program is needed to manage this aging effect based on the environmental conditions applicable to the plant and requirements applicable to the components.

The only stainless steel components exposed to outdoor air in the Engineered Safety Features Systems are insulated portions of the piping vent line for the refueling water storage tank in the Safety Injection System. There are no stainless steels tanks exposed to an outdoor air environment in the scope of license renewal at Byron and Braidwood Stations (BBS). Stress corrosion cracking of these components is not expected to occur, however, should cracking occur the function of these components would not be affected since an exhaust path for the refueling water storage tank would still be provided.

The thermal insulation utilized for the refueling water storage tank vent line piping acts as a barrier to prevent the accumulation of halide contamination due to environmental sources. The insulation used for the Safety Injection System is fiberglass insulation designed to meet the requirements of Regulatory Guide 1.36, Nonmetallic Thermal Insulation for Austenitic Stainless Steel. Therefore, halide contamination due to leaching of contaminants from insulation is not expected to occur.

A large buildup of halide contamination increases the probability of cracking due to stress corrosion cracking which has the potential to lead to loss of component intended function. As explained below, significant halide contamination of stainless steel piping, piping components, and piping elements exposed to outdoor air or exposed to air which has recently been introduced into buildings is not expected at BBS. Additionally, an elevated temperature increases the likelihood of cracking. Experimental studies and industry operating experience in chloride-containing (coastal) environments have shown that stainless steel exposed to an outdoor air environment can crack at temperatures as low as 104°F to 120°F, depending on

RS-14-130 Enclosure B Page 6 of 22 humidity, component surface temperature, and contaminant concentration and composition.

The highest temperatures recorded at BBS over the 10-year period between June 1, 2001 and June 1, 2012 were 94.4°F at Byron Station and 98.2°F at Braidwood Station. A review of historical temperature data since construction for areas surrounding BBS indicates that temperatures rarely exceed 100°F. UFSAR Section 2.3.2.1.2 identifies long-term average temperatures of approximately 50°F for BBS. Therefore, stress corrosion cracking of stainless steel piping, piping components, and piping elements exposed to outdoor air or exposed to air which has recently been introduced into buildings is not expected to occur at BBS.

Halide surface contamination is significant in areas where there are greater concentrations of halides such as near the seacoast where salt spray is prevalent or near industrial facilities.

Byron and Braidwood Stations are not located near the seacoast. They are located inland, in central Illinois. Both Byron and Braidwood are located in areas where industrial halide concentrations are low, since they are located in rural areas with no heavy industry nearby.

Byron and Braidwood Stations are not located within one half mile of a highway treated with salt in the wintertime. Major highways in the vicinity of Byron Station include interstate I-90 northeast of the site approximately 11 miles away, interstate I-39 east of the site approximately 11 miles away, and interstate I-88 south of the site approximately 14 miles away. The only major highway in the vicinity of Braidwood Station is interstate I-55 northwest of the site approximately three quarters of a mile away.

The cooling towers at Byron Station are treated with sodium hypochlorite. However, chloride contamination resulting in the loss of the intended function of stainless steel components located outdoors is not expected since the components are covered by insulation. The insulation acts as a barrier to prevent the accumulation of halides on the component surface.

Additionally, the prevailing wind direction is west to east and is directed away from the site.

Braidwood Station does not have cooling towers.

Halide contamination of stainless steel components from soil containing more than trace chlorides or from agricultural sources is not expected. However, should halide contamination occur, any potential buildup of halide contamination would be gradual and such contamination would be periodically washed away by rainfall or snow. Cracking due to cumulative build up of halides on stainless steel components located outdoors at BBS has not been experienced and is not expected. Surface smear sampling confirms that halide concentrations on the surface of components located outdoors due to contamination from environmental sources are acceptable with respect to susceptibility to SCC. The smooth surfaces of the stainless steel components aid the removal of potential halide contamination. Therefore, the concentration of contaminants necessary to initiate stress corrosion cracking of stainless steel is not expected.

Based on the collective environmental conditions, as described above, and confirmed by a review of operating experience, cracking due to stress corrosion cracking of stainless steel components exposed to outdoor air is not expected to occur. Therefore, aging management activities for cracking due to stress corrosion cracking for stainless steel components exposed to outdoor air are not required for the period of extended operation. Regardless, the One-Time Inspection (B.2.1.20) aging management program will be used to ensure that cracking due to stress corrosion cracking is not occurring.

RS-14-130 Enclosure B Page 7 of 22 As a result of the response to RAI 3.0.3-3a provided in Enclosure A of this letter, LRA Table 3.2.1, Summary of Aging Management Evaluation for the Engineered Safety Features, is revised as shown below. Additions are indicated with bolded italics; deletions are shown with strikethroughs.

Table 3.2.1 Summary of Aging Management Evaluations for Engineered Safety Features Item Component Aging Effect/ Aging Management Further Discussion Number Mechanism Programs Evaluation Recommended 3.2.1-71 Insulated stainless steel, Cracking due to Chapter XI.M36, No Based on the evaluation of the aluminum, or copper stress corrosion "External Surfaces environmental conditions and physical alloy cracking Monitoring of Mechanical configurations at BBS, cracking is not an

(> 15% Zn) piping, piping Components" or Chapter applicable aging effect expected to occur components, and tanks XI.M29, Aboveground for the Engineered Safety Features exposed to condensation, Metallic Tanks, (for Systems stainless steel insulated piping, air-outdoor tanks only) piping components, and piping elements exposed to air - outdoor. Regardless, the One-Time Inspection (B.2.1.20) aging management program will be used to confirm that cracking due to stress corrosion cracking is not occurring.

See subsection 3.2.2.2.6.

RS-14-130 Enclosure B Page 8 of 22 As a result of the response to RAI 3.0.3-3a provided in Enclosure A of this letter, LRA Table 3.2.2-4, Safety Injection System, is revised as shown below. Additions are indicated with bolded italics; deletions are shown with strikethroughs.

Table 3.2.2-4 Safety Injection System (Continued)

Component Intended Material Environment Aging Effect Aging Management NUREG-1801 Table 1 Item Notes Type Function Requiring Programs Item Management Insulated piping, Pressure Boundary Stainless Steel Air - Outdoor (External) Loss of Material External Surfaces V.D1.E-403 3.2.1-69 A piping components, Monitoring of Mechanical and piping elements Components (B.2.1.23)

None None V.D1.E-406 3.2.1-71 I Cracking One-Time Inspection E, 2 (B.2.1.2)

Plant Specific Notes:

2. Based on an evaluation of the environmental conditions at BBS and a review of operating experience, cracking due to stress corrosion cracking (SCC) is not an applicable aging effect for insulated stainless steel in an Air-Outdoor environment. Per NACE SP0198-2010, SCC can occur under insulation when the evaporation of water, due to contact with hot stainless steel, causes the concentration of halides on the surface of stainless steel components. The potential sources of halide contamination are leachable halides from insulating materials and/or external environmental sources. The insulating materials for this component do not contain leachable halides. External sources of halides are not a significant contributor to the occurrence of SCC as the insulation shelters the component external surface. In addition, since this is not hot piping, the concentration of halides is not expected to occur. Therefore, cracking due to stress corrosion cracking (SCC) is not an applicable aging effect for insulated stainless steel in an Air-Outdoor environment. Regardless, the One-Time Inspection (B.2.1.20) aging management program will be used to ensure that cracking due to stress corrosion cracking is not occurring. The External Surfaces Monitoring of Mechanical Components (B.2.1.23) aging management program will be used to manage loss of material of this component. For more information see LRA Section 3.3.2.2.3 3.2.2.2.6.

RS-14-130 Enclosure B Page 9 of 22 As a result of the response to RAI 3.0.3-3a provided in Enclosure A of this letter, LRA Section 3.3.2.2.3, is revised as shown below. Additions are indicated with bolded italics; deletions are shown with strikethroughs.

3.3.2.2.3 Cracking due to Stress Corrosion Cracking Cracking due to stress corrosion cracking could occur for stainless steel piping, piping components, piping elements and tanks exposed to outdoor air. The possibility of cracking also extends to components exposed to air which has recently been introduced into buildings, i.e.,

components near intake vents. Cracking is only known to occur in environments containing sufficient halides (primarily chlorides) and in which condensation or deliquescence is possible.

Condensation or deliquescence should generally be assumed to be possible. Applicable outdoor air environments (and associated indoor air environments) include, but are not limited to, those within approximately 5 miles of a saltwater coastline, those within 1/2 mile of a highway which is treated with salt in the wintertime, those areas in which the soil contains more than trace chlorides, those plants having cooling towers where the water is treated with chlorine or chlorine compounds, and those areas subject to chloride contamination from other agricultural or industrial sources. This item is applicable for the environments described above.

GALL AMP XI.M36, External Surfaces Monitoring is an acceptable method to manage the aging effect. The applicant may demonstrate that this item is not applicable by describing the outdoor air environment present at the plant and demonstrating that external chloride stress corrosion cracking is not expected. The GALL Report recommends further evaluation to determine whether an adequate aging management program is used to manage this aging effect based on the environmental conditions applicable to the plant and ASME Code Section XI requirements applicable to the components.

The only stainless steel components exposed to outdoor air in the Auxiliary Systems are (1) portions of the exhaust lines for the diesel generators and diesel-driven pumps in the Emergency Diesel Generators & Auxiliaries System, Fire Protection System, and Service Water System (Byron only); (2) portions of the Service Water System and Demineralized Water System located within vaults or pits; (3) an insulated length of Auxiliary Building Ventilation System piping that provides a vent path from the refueling water storage tank to the Auxiliary Building filtered vent header; and (4) Service Water System stainless steel piping and valve body associated with the essential service water cooling tower gear reducer assembly (Byron only). There are no stainless steel tanks exposed to an outdoor air environment in the scope of license renewal at Byron and Braidwood Stations (BBS). Stress corrosion cracking of the diesel exhaust line components due to halide contamination is not expected to occur, however, should cracking occur the function of these components would not be affected since an exhaust path for the diesels would still be provided. To confirm that cracking does not occur, the One Time Inspection program (B.2.1.20) will be used to assess the stainless steel components with direct exposure to outdoor air conditions. This includes the essential service water makeup pump diesel exhaust lines (Byron Only), as the other diesel systems stainless steel components are insulated or otherwise sheltered from outdoor conditions. In addition to the diesel generator and diesel-driven fire pump exhaust lines; stainless steel portions of the Service Water System (with the exception of the stainless steel components associated with the essential service water cooling tower gear reducer assembly), the Demineralized Water System (Byron only), and the Auxiliary Building Ventilation System are considered to have an outdoor air external environment. However, these components are either contained in vaults or pits (Service Water

RS-14-130 Enclosure B Page 10 of 22 System and Demineralized Water System), or are insulated (Auxiliary Building Ventilation System) and, therefore, the surface of these components is protected from potential halide contamination from environmental sources.

Thermal insulation is utilized for the Auxiliary Building Ventilation System and Emergency Diesel Generators & Auxiliaries System piping exposed to outdoor air. The insulation exposed to outdoor air for the Emergency Diesel Generators & Auxiliaries System is located in a pipe chase and, as such, is not directly exposed to weather effects that could cause wetting and potential leaching of contaminants. The insulation used for the Auxiliary Building Ventilation System is fiberglass insulation designed to meet the Regulatory Guide 1.36, Nonmetallic Thermal Insulation for Austenitic Stainless Steel requirements for leachable halide levels. Therefore, halide contamination due to the leaching of contaminants from insulation is not expected to occur for insulated piping in the Auxiliary Building Ventilation System and the Emergency Diesel Generators & Auxiliaries System.

A large buildup of halide contamination increases the probability of cracking due to stress corrosion cracking which has the potential to lead to loss of component intended function. As explained below, significant halide contamination of stainless steel piping, piping components, and piping elements exposed to outdoor air or exposed to air which has recently been introduced into buildings is not expected at BBS. Additionally, an elevated temperature increases the likelihood of cracking. Experimental studies and industry operating experience in chloride-containing (coastal) environments have shown that stainless steel exposed to an outdoor air environment can crack at temperatures as low as 104°F to 120°F, depending on humidity, component surface temperature, and contaminant concentration and composition.

The highest temperatures recorded at BBS over the 10-year period between June 1, 2001 and June 1, 2012 were 94.4°F at Byron Station and 98.2°F at Braidwood Station. A review of historical temperature data since construction for areas surrounding BBS indicates that temperatures rarely exceed 100°F. UFSAR Section 2.3.2.1.2 identifies long-term average temperatures of approximately 50°F for BBS. Therefore, stress corrosion cracking of stainless steel piping, piping components, and piping elements exposed to outdoor air or exposed to air which has recently been introduced into building is not expected to occur at BBS.

Halide surface contamination is significant in areas where there are greater concentrations of halides such as near the seacoast where salt spray is prevalent or near industrial facilities.

Byron and Braidwood Stations are not located near the seacoast. They are located inland, in central Illinois. Both Byron and Braidwood are located in areas where industrial halide concentrations are low, since they are located in rural areas with no heavy industry nearby.

Byron and Braidwood Stations are not located within one half mile of a highway treated with salt in the wintertime. Major highways in the vicinity of Byron Station include interstate I-90 northeast of the site approximately 11 miles away, interstate I-39 west of the site approximately 11 miles away, and interstate I-88 south of the site approximately 14 miles away. The only major highway in the vicinity of Braidwood Station is interstate I-55 northwest of the site approximately three quarters of a mile away.

The cooling towers at Byron Station are treated with sodium hypochlorite. However, chloride contamination resulting in the loss of the intended function of stainless steel components located outdoors is not expected since the prevailing wind direction is west to east and is directed away from the site. Braidwood Station does not have cooling towers.

RS-14-130 Enclosure B Page 11 of 22 Halide contamination of stainless steel components from soil containing more than trace chlorides or from agricultural sources is not expected. However, should halide contamination occur, any potential buildup of halide contamination would be gradual and such contamination would be periodically washed away by rainfall or snow. Cracking due to cumulative build up of halides on stainless steel components located outdoors at BBS has not been experienced and is not expected. Surface smear sampling confirms that halide concentrations on the surface of components located outdoors due to contamination from environmental sources are acceptable with respect to susceptibility to SCC. The smooth surfaces of the stainless steel components aid the removal of potential halide contamination. Therefore, the concentration of contaminants necessary to initiate stress corrosion cracking of stainless steel is not expected.

Based on the collective environmental conditions, as described above, and confirmed by a review of operating experience, cracking due to stress corrosion cracking of stainless steel components exposed to outdoor air is not expected to occur. Regardless, the External Surfaces Monitoring of Mechanical Components aging management program is used to monitor liquid-filled stainless steel components directly exposed to an outdoor-air environment for cracking due to stress corrosion cracking. Components which are insulated or which are located in enclosed underground pits are shielded from accumulation of potential contaminants in the environment, and are therefore not susceptible to stress corrosion cracking. Stress corrosion cracking of the diesel exhaust line components due to halide contamination is not expected to occur, however, should cracking occur the intended function of these components would not be affected since an exhaust path for the diesels would still be provided. The One -Time Inspection aging management program is used to verify that gas-filled stainless steel components directly exposed to an outdoor air environment do not exhibit cracking due to stress corrosion cracking. As described above, stress corrosion cracking of insulated stainless steel components exposed to an outdoor environment is not expected to occur.

Regardless, the One-Time Inspection (B.2.1.20) aging management program will be used to ensure that cracking due to stress corrosion cracking is not occurring.

RS-14-130 Enclosure B Page 12 of 22 As a result of the response to RAI 3.0.3-3a provided in Enclosure A of this letter, LRA Table 3.3.1, Summary of Aging Management Evaluations for the Auxiliary Systems, is revised as shown below. Additions are indicated with bolded italics; deletions are shown with strikethroughs.

Table 3.3.1 Summary of Aging Management Evaluations for the Auxiliary Systems Item Component Aging Effect/ Aging Management Further Discussion Number Mechanism Programs Evaluation Recommended 3.3.1-132 Insulated steel, stainless Loss of material Chapter XI.M36, No The External Surfaces Monitoring of steel, copper alloy, due to general "External Surfaces Mechanical Components (B.2.1.23) aluminum, or copper (steel, and copper Monitoring of Mechanical program will be used to manage loss of alloy (> 15% Zn) piping, alloy only), pitting, Components" or Chapter material of steel and stainless steel piping components, and and crevice XI.M29, Aboveground insulated piping, piping components, and tanks exposed to corrosion; cracking Metallic Tanks (for piping elements, and tanks exposed to air -

condensation, air-outdoor due to stress tanks only) outdoor and condensation in the Auxiliary corrosion cracking Building Ventilation System, Chemical &

(aluminum, stainless Volume Control System, Chilled Water steel and copper System, Fire Protection System, and alloy (>15% Zn) Service Water System.

only)

Based on the evaluation of the environmental conditions and physical configurations at BBS, cracking is not an applicable aging effect expected to occur for the stainless steel insulated piping, piping components, and piping elements exposed to air - outdoor or condensation in the Auxiliary Building Ventilation System, Chemical & Volume Control System, Chilled Water System, and Fire Protection System. Regardless, the One-Time Inspection (B.2.1.20) aging management program will be used to confirm that cracking due to stress corrosion cracking is not occurring.

See subsection 3.3.2.2.3.

RS-14-130 Enclosure B Page 13 of 22 As a result of the response to RAI 3.0.3-3a provided in Enclosure A of this letter, LRA Table 3.3.2-1, Auxiliary Building Ventilation System, is revised as shown below. Additions are indicated with bolded italics; deletions are shown with strikethroughs.

Table 3.3.2-1 Auxiliary Building Ventilation System (Continued)

Component Intended Material Environment Aging Effect Aging Management NUREG-1801 Table 1 Item Notes Type Function Requiring Programs Item Management Insulated piping, Structural Support Stainless Steel Air - Outdoor (External) Loss of Material External Surfaces VII.G.A-405 3.3.1-132 A piping components, Monitoring of Mechanical and piping Components (B.2.1.23) elements None None VII.G.A-405 3.3.1-132 I Cracking One-Time Inspection E, 4 (B.2.1.20)

Table 3.3.2-1 Auxiliary Building Ventilation System (Continued)

Plant Specific Notes:

4. Based on an evaluation of the environmental conditions at BBS and a review of operating experience, cracking due to stress corrosion cracking is not an applicable aging effect for insulated stainless steel in an Air-Outdoor environment. Per NACE SP0198-2010, SCC can occur under insulation when the evaporation of water, due to contact with hot stainless steel, causes the concentration of halides on the surface of stainless steel components. The potential sources of halide contamination are leachable halides from insulating materials and/or external environmental sources. The insulating materials for this component do not contain leachable halides. External sources of halides are not a significant contributor to the occurrence of SCC as the insulation shelters the component external surface. In addition, since this is not hot piping, the concentration of halides is not expected to occur. Therefore, cracking due to stress corrosion cracking (SCC) is not an applicable aging effect for insulated stainless steel in an Air-Outdoor environment. Regardless, the One-Time Inspection (B.2.1.20) aging management program will be used to ensure that cracking due to stress corrosion cracking is not occurring. The External Surfaces Monitoring of Mechanical Components (B.2.1.23) aging management program will be used to manage loss of material of this component. For more information see LRA Section 3.3.2.2.3.

RS-14-130 Enclosure B Page 14 of 22 As a result of the response to RAI 3.0.3-3a provided in Enclosure A of this letter, LRA Table 3.3.2-12, Fire Protection System, is revised as shown below. Only those line items affected by the revision are shown below. Additions are indicated with bolded italics; deletions are shown with strikethroughs.

Table 3.3.2-12 Fire Protection System (Continued)

Component Intended Function Material Environment Aging Effect Aging Management NUREG-1801 Table 1 Item Notes Type Requiring Programs Item Management Insulated piping, Pressure Boundary Stainless Steel Air - Outdoor (External) Loss of Material External Surfaces VII.G.A-405 3.3.1-132 A piping components, Monitoring of Mechanical and piping Components (B.2.1.23) elements None None VII.G.A-405 3.3.1-132 I Cracking One-Time Inspection E, 11 (B.2.1.20)

Plant Specific Notes:

11. Based on an evaluation of the environmental conditions at BBS and a review of operating experience, cracking due to stress corrosion cracking (SCC) is not an applicable aging effect for insulated stainless steel in an Air-Outdoor environment. Per NACE SP0198-2010, SCC can occur under insulation when the evaporation of water, due to contact with hot stainless steel, causes the concentration of halides on the surface of stainless steel components. The potential sources of halide contamination are leachable halides from insulating materials and/or external environmental sources. The insulating materials for this component do not contain leachable halides. External sources of halides are not a significant contributor to the occurrence of SCC as the insulation shelters the component external surface. In addition, since this is not hot piping, the concentration of halides is not expected to occur. Therefore, cracking due to stress corrosion cracking (SCC) is not an applicable aging effect for insulated stainless steel in an Air-Outdoor environment. Regardless, the One-Time Inspection (B.2.1.20) aging management program will be used to ensure that cracking due to stress corrosion cracking is not occurring. The External Surfaces Monitoring of Mechanical Components (B.2.1.23) aging management program will be used to manage loss of material of this component. For more information see LRA Section 3.3.2.2.3.

RS-14-130 Enclosure B Page 15 of 22 As a result of the response to RAI 3.0.3-3a provided in Enclosure A of this letter, LRA Section 3.4.2.2.2, is revised as shown below. Additions are indicated with bolded italics; deletions are shown with strikethroughs.

3.4.2.2.2 Cracking due to Stress Corrosion Cracking (SCC)

Cracking due to stress corrosion cracking could occur for stainless steel piping, piping components, piping elements, and tanks exposed to outdoor air. The possibility of cracking also extends to components exposed to air which has recently been introduced into buildings, i.e.,

components near intake vents. Cracking is only known to occur in environments containing sufficient halides (primarily chlorides) and in which condensation or deliquescence is possible.

Condensation or deliquescence should generally be assumed to be possible. Applicable outdoor air environments (and associated indoor air environments) include, but are not limited to, those within approximately 5 miles of a saltwater coastline, those within 1/2 mile of a highway which is treated with salt in the wintertime, those areas in which the soil contains more than trace chlorides, those plants having cooling towers where the water is treated with chlorine or chlorine compounds, and those areas subject to chloride contamination from other agricultural or industrial sources. This item is applicable for the environments described above.

GALL AMP XI.M36, External Surfaces Monitoring is an acceptable method to manage the aging effect. The applicant may demonstrate that this item is not applicable by describing the outdoor air environment present at the plant and demonstrating that external chloride stress corrosion cracking is not expected. The GALL Report recommends further evaluation to determine whether an adequate aging management program is used to manage this aging effect based on the environmental conditions applicable to the plant and ASME Code Section XI requirements applicable to the components.

The only stainless steel components exposed to outdoor air in the Steam and Power Conversion system are associated with the condensate storage tank. These components include instrumentation at Byron and Braidwood Stations and drain valves located on the side of each condensate storage tank at Braidwood Station only. These components are evaluated with the Main Condensate and Feedwater System. The drain valves at Braidwood Station are fully insulated, and, therefore, protected from potential halide contamination from environmental sources. Stress corrosion cracking of these components is not expected to occur. The stainless steel instrumentation components associated with the condensate storage tank and exposed to outdoor air at Byron and Braidwood Stations are not insulated. The condensate storage tanks are fabricated from aluminum alloy. There are no stainless steel tanks exposed to an outdoor air environment in the scope of license renewal at Byron and Braidwood Stations (BBS).

The thermal insulation for the condensate storage tank drain valves is enclosed in waterproof jacketing and is not in contact with the stainless steel valves. Therefore, halide contamination of the stainless steel valves due to leaching of contaminants from the insulation is not credible.

A large buildup of halide contamination increases the probability of cracking due to stress corrosion cracking which has the potential to lead to loss of component intended function. As explained below, significant halide contamination of stainless steel piping, piping components, and piping elements exposed to outdoor air or exposed to air which has recently been introduced into buildings is not expected at BBS. Additionally, an elevated temperature increases the likelihood of cracking. Experimental studies and industry operating experience in

RS-14-130 Enclosure B Page 16 of 22 chloride-containing (coastal) environments have shown that stainless steel exposed to an outdoor air environment can crack at temperatures as low as 104°F to 120°F, depending on humidity, component surface temperature, and contaminant concentration and composition.

The highest temperatures recorded at BBS over the ten year period between June 1, 2001 and June 1, 2012 were 94.4°F at Byron Station and 98.2°F at Braidwood Station. A review of historical temperature data since construction for areas surrounding BBS indicates that temperatures rarely exceed 100°F. UFSAR Section 2.3.2.1.2 identifies long-term average temperatures of approximately 50°F for BBS. Therefore, stress corrosion cracking of stainless steel piping, piping components, and piping elements exposed to outdoor air or exposed to air which has recently been introduced into buildings is not expected to occur at BBS.

Halide surface contamination is significant in areas where there are greater concentrations of halides such as near the seacoast where salt spray is prevalent or near industrial facilities.

Byron and Braidwood Stations are not located near the seacoast. They are located inland, in central Illinois. Both Byron and Braidwood are located in areas where industrial halide concentrations are low, since they are located in rural areas with no heavy industry nearby.

Byron and Braidwood Stations are not located within one half mile of a highway treated with salt in the wintertime. Major highways in the vicinity of Byron Station include interstate I-90 northeast of the site approximately 11 miles away, interstate I-39 east of the site approximately 11 miles away, and interstate I-88 south of the site approximately 14 miles away. The only major highway in the vicinity of Braidwood Station is interstate I-55 northwest of the site approximately three quarters of a mile away.

The cooling towers at Byron Station are treated with sodium hypochlorite. However, chloride contamination resulting in the loss of the intended function of stainless steel components located outdoors is not expected since the prevailing wind direction is west to east and is directed away from the site. Braidwood Station does not have cooling towers.

Halide contamination of stainless steel components from soil containing more than trace chlorides or from agricultural sources is not expected. However, should halide contamination occur, any potential buildup of halide contamination would be gradual and such contamination would be periodically washed away by rainfall or snow. Cracking due to cumulative build up of halides on stainless steel components located outdoors at BBS has not been experienced and is not expected. Surface smear sampling confirms that halide concentrations on the surface of components located outdoors due to contamination from environmental sources are acceptable with respect to susceptibility to SCC. The smooth surfaces of the stainless steel components aid the removal of potential halide contamination. Therefore, the concentration of contaminants necessary to initiate stress corrosion cracking of stainless steel is not expected.

Based on the collective environmental conditions, as described above, and confirmed by a review of operating experience, cracking due to stress corrosion cracking of stainless steel components exposed to outdoor air is not expected to occur. Regardless, the External Surfaces Monitoring of Mechanical Components (B.2.1.23) aging management program is used to monitor liquid-filled stainless steel components, which are not insulated and are directly exposed to an outdoor air environment, for cracking due to stress corrosion cracking.

Components which are insulated are shielded from accumulation of potential contaminants in the environment, and are therefore not susceptible to stress corrosion cracking. As described above, stress corrosion cracking of insulated stainless steel components exposed to an

RS-14-130 Enclosure B Page 17 of 22 outdoor environment is not expected to occur. Regardless, the One-Time Inspection (B.2.1.20) aging management program will be used to ensure that cracking due to stress corrosion cracking is not occurring.

RS-14-130 Enclosure B Page 18 of 22 As a result of the response to RAI 3.0.3-3a provided in Enclosure A of this letter, LRA Table 3.4.1, Summary of Aging Management Evaluations for the Steam and Power Conversion System, is revised as shown below. Additions are indicated with bolded italics; deletions are shown with strikethroughs.

Table 3.4.1 Summary of Aging Management Evaluations for the Steam and Power Conversion System Item Component Aging Effect/ Aging Management Further Discussion Number Mechanism Programs Evaluation Recommended 3.4.1-63 Insulated steel, stainless Loss of material Chapter XI.M36, No The External Surfaces Monitoring of steel, copper alloy, due to general (steel, "External Surfaces Mechanical Components (B.2.1.23) aluminum, or copper and copper alloy), Monitoring of Mechanical program will be used to manage loss of alloy pitting, or crevice Components" or Chapter material of steel, stainless steel, and

(> 15% Zn) piping, piping corrosion, and XI.M29, Aboveground aluminum insulated piping, piping components, and tanks cracking due to stress Metallic Tanks (for components, and piping elements exposed exposed to condensation, corrosion cracking tanks only) to air - outdoor and condensation in the air-outdoor (aluminum, stainless Auxiliary Feedwater System and Main steel and copper alloy Condensate and Feedwater System.

(>15% Zn) only) Based on the evaluation of the environmental conditions and physical configurations at BBS, cracking is not an applicable aging effect expected to occur for the stainless steel and aluminum insulated piping, piping components, and piping elements exposed to air - outdoor in the Main Condensate and Feedwater System. Regardless, the One-Time Inspection (B.2.1.20) aging management program will be used to confirm that cracking due to stress corrosion cracking is not occurring.

See subsection 3.4.2.2.2.

RS-14-130 Enclosure B Page 19 of 22 As a result of the response to RAI 3.0.3-3a provided in Enclosure A of this letter, LRA Table 3.4.2-3, Main Condensate and Feedwater System, is revised is revised as shown below. Only those line items affected by the revision are shown below. Additions are indicated with bolded italics; deletions are shown with strikethroughs.

Table 3.4.2-3 Main Condensate and Feedwater System (Continued)

Component Intended Material Environment Aging Effect Aging Management NUREG-1801 Table 1 Item Notes Type Function Requiring Programs Item Management Insulated piping, Pressure Boundary Aluminum Alloy Air - Outdoor (External) None None VIII.H.S-402 3.4.1-63 I piping Cracking One-Time Inspection E, 1 components, and (B.2.1.20) piping elements Loss of Material External Surfaces VIII.H.S-402 3.4.1-63 A Monitoring of Mechanical Components (B.2.1.23)

Stainless Steel Air - Outdoor (External) None None VIII.H.S-402 3.4.1-63 I Cracking One-Time Inspection E, 1 (B.2.1.20)

Loss of Material External Surfaces VIII.H.S-402 3.4.1-63 A Monitoring of Mechanical Components (B.2.1.23)

Insulated Valve Pressure Boundary Stainless Steel Air - Outdoor (External) None None VIII.H.S-402 3.4.1-63 I Body Cracking One-Time Inspection E, 1 (B.2.1.20)

Loss of Material External Surfaces VIII.H.S-402 3.4.1-63 A Monitoring of Mechanical Components (B.2.1.23)

RS-14-130 Enclosure B Page 20 of 22 Plant Specific Notes:

1. Based on an evaluation of the environmental conditions at BBS and a review of operating experience, cracking due to stress corrosion cracking (SCC) is not an applicable aging effect for insulated stainless steel and aluminum in an Air-Outdoor environment. Per NACE SP0198-2010, SCC can occur under insulation when the evaporation of water, due to contact with hot stainless steel, causes the concentration of halides on the surface of stainless steel components. The potential sources of halide contamination are leachable halides from insulating materials and/or external environmental sources. The insulating materials for this component do not contain leachable halides.

External sources of halides are not a significant contributor to the occurrence of SCC as the insulation shelters the component external surface. In addition, since this is not hot piping, the concentration of halides is not expected to occur. Therefore, cracking due to stress corrosion cracking (SCC) is not an applicable aging effect for insulated stainless steel in an Air-Outdoor environment. Regardless, the One-Time Inspection (B.2.1.20) aging management program will be used to ensure that cracking due to stress corrosion cracking is not occurring. The External Surfaces Monitoring of Mechanical Components (B.2.1.23) aging management program will be used to manage loss of material of this component. For more information see LRA Section 3.4.2.2.2.

RS-14-130 Enclosure B Page 21 of 22 As a result of changes to the PWR Vessel Internals aging management program identified in the response to B.2.1.7-3, LRA Appendix C, page C-8, is revised as shown below. Revisions are indicated with bold italics for inserted text and strikethroughs for deleted text:

Applicant/Licensee Action Item 3: NRC SER Section 4.2.3, Evaluation of the Adequacy of Plant-Specific Existing Programs Applicant/Licensee Action Item Byron and Braidwood Response Applicants/Licensees of CE and Westinghouse are BBS are Westinghouse designed plants. The required to perform plant-specific analysis either to original equipment alloy X-750 CRGT split pins justify the acceptability of an applicants/licensees were proactively replaced at the Byron and existing programs, or to identify changes to the Braidwood Stations, Unit 1 and 2 with cold programs that should be implemented to manage worked 316 stainless steel split pins based on the aging of these components for the period of industry guidance. The cold worked 316 extended operation. The results of this plant- stainless steel split pins are less susceptible to specific analyses and a description of the plant- PWSCC. As stated in MRP-232, Material specific programs being relied on to manage aging Reliability Program: Aging Management of these components shall be submitted as part of Strategies for Westinghouse and Combustion the applicants/licensees AMP application. The CE Engineering PWR Internals, Section 4.2.5.2; and Westinghouse components identified for this The most reliable management approach for type of plant-specific evaluation include: CE eliminating concerns over guide support pin thermal shield positioning pins and CE in-core cracking is a proactive replacement with Type instrumentation thimble tubes (Section 4.3.2 in 316 CW SS support pins. The replacement MRP-227), and Westinghouse guide tube support split pins were designed for a 40 year life, with pins (split pins)(Section 4.3.3 in MRP-227). a 100% capacity factor and were installed after each of the reactors had operated for at least 20 years. Therefore, the current design life is through the end of the period of extended operation. It is also stated in MRP-232 that the failure of the CRGT support pins does not challenge safe plant operation, nor does such failures compromise control rod functionality.

The main issue with the failure of the CRGT split pins was determined to be damage from the loose parts. BBS started replacing split pins in 2005, however, other utilities have installed cold worked 316 stainless steel split pins as early as 1997, therefore a failure at another plant would be expected before a potential failure at a BBS plant. No plants have experienced any failures of cold worked 316 stainless steel split pins to date. Currently there areis no vendor specific requirements to inspect the replacement CRGT split pins, however existing foreign material inspections of the reactor vessel and steam generators during refueling outages and the ASME Section XI Inservice Inspection Program B-N-3 examination of the upper internals assembly will monitor the integrity

RS-14-130 Enclosure B Page 22 of 22 of the CRGT split pins during the period of extended operation.through the stations participation in industry groups and the evaluation of industry operating experience this position may change as warranted.

The PWR Vessel Internals AMP is described in LRA Appendix B, Section B.2.1.7.