ML19122A289

Response to NRC Requests for Additional Information, Set 1, Dated April 10, 2019 Related to Plant Subsequent License Renewal Application

ML19122A289
Person / Time
Site:	Peach Bottom
Issue date:	05/02/2019
From:	Gallagher M Exelon Generation Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML19122A289 (155)

Text

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May 2, 2019

\\\\ \\\\ \\\\.l!xclnnrorp com 10 CFR 50 10 CFR 51 10 CFR 54 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555-0001 Peach Bottom Atomic Power Station, Units 2 and 3 Renewed Facility Operating License Nos. DPR-44 and DPR-56 NRG Docket Nos. 50-277 and 50-278

Subject:

Response to NRG Requests for Additional Information, Set 1, dated April 10, 2019 related to the Peach Bottom Atomic Power Station, Units 2 and 3, Subsequent License Renewal Application

References:

1. Letter from Michael P. Gallagher, Exelon Generation Company LLC, to NRG Document Control Desk, dated July 10, 2018, "Application for Subsequent Renewed Operating Licenses"

2. E-mail from Bennett Brady, USNRC to Michael P. Gallagher, Exelon Generation Company, LLC, dated April 10, 2019, "Requests for Additional Information for the Safety Review of the Peach Bottom Atomic Power Station, Units 2 and 3 Subsequent License Renewal Application - Set 1" In Reference 1, Exelon Generation Company, LLC (Exelon) submitted the Subsequent License Renewal Application (SLRA) for the Peach Bottom Atomic Power Station (PBAPS),

Units 2 and 3. In Reference 2, the NRG requested additional information to support staff review of the SLRA.

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

Enclosure B contains updates to sections of the SLRA (except for the Subsequent License Renewal Commitment List) affected by the responses.

Enclosure C provides an update to the Subsequent License Renewal Commitment List (SLRA Appendix A, Section A.5) resulting from these responses.

The Enclosure A cover page also provides a cross-reference to the page numbers in Enclosure A containing each RAI response, as well as to the associated Enclosures B and C page numbers for RAls containing updates to the SLRA as described above.

May 2, 2019 U.S. Nuclear Regulatory Commission Page 2 There are no other new or revised regulatory commitments contained in this letter.

If you have any questions, please contact Mr. David J. Distel, Licensing Lead, Peach Bottom Subsequent License Renewal Project, at 610-765-5517.

I declare under penalty of perjury that the foregoing is true and correct. Executed on the 2nd day of May 2019.

Respectfully submitted,

Enclosures:

A: Responses to Set 1 Requests for Additional Information B: Subsequent License Renewal Application Updates C. Subsequent License Renewal Commitment List Updates cc:

Regional Administrator-NRG Region I NRG Senior Project Manager (Safety Review), NRR-DMLR NRG Project Manager (Environmental Review), NRR-DMLR NRG Project Manager, NRA-DORL-Peach Bottom Atomic Power Station NRG Senior Resident Inspector, Peach Bottom Atomic Power Station R.R. Janati, Pennsylvania Bureau of Radiation Protection D.A. Tancabel, State of Maryland

Enclosure A Responses to Set 1 Requests for Additional Information Related to Various Sections of the Peach Bottom Atomic Power Station, Units 2 and 3 Subsequent License Renewal Application (SLRA)

RAI No.

Enclosure A Enclosure B Enclosure C B.2.1.28-1 Paae 1 N/A N/A B.2.1.28-2 Paae 4 N/A N/A B.2.1.36-1 Paqe 6 Paqe 1 Paae 1 B.2.1.36-2 Paae 8 N/A N/A B.2.1.36-3 Paae 10 N/A N/A B.2.1.36-4 Paqe 12 Paae3 N/A B.2.1.29-1 Paae 13 N/A N/A B.2.1.29-2 Paae 15 N/A N/A B.2.1.17-1 Paae 17 Paae5 Paae2 B.2.1.17-2 Paae 21 Paae5 Paae2 B.2.1.17-3 Paae 24 Paae 5 Paae2 B.2.1.17-4 Paae 26 Paae5 Paae2 B.2.1.19-1 Paae 27 N/A N/A B.2.1.39-1, B.2.1.40-Page 31 N/A N/A 1, 8.2.1.41-1 4.3.6.3-1 Paae 34 N/A N/A 4.3.6.3-2 Paae 37 N/A N/A B.2.1.9-1 Paae 39 Paae 8 N/A B.2.1.9-2 Paae 42 N/A N/A B.2.1.22-1 Paqe 45 Paae9 N/A 3.5.2.2.2.4-1 Paae 47 Paae 10 N/A B.2.1.26-1 Paae 51 N/A N/A 3.3.2.2.7-1 Paae 53 Paae 60 Paae4 3.3.2.1.1-1 Paae 58 N/A N/A 3.3.2.2.8-1 Paae 63 N/A N/A 4.2.13-1 Paae 64 N/A N/A 4.3.5-1 Paae 66 N/A N/A 4.3.5-2 Paae 72 N/A N/A 4.3.5-3 Paae 74 N/A N/A 4.3.5-4 Paae 77 N/A N/A

1.

GALL-SLR AMP Xl.M41 Buried and Underground Piping and Tanks Regulatory Basis:

May 2, 2019 Enclosure A Page 1 of 82 1 O CFR 54.21 (a)(3) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the subsequent period of extended operation. One of the findings that the staff must make to issue a renewed license (1 O CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the subsequent period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 1 O CFR 54.29(a), the staff requires additional information in regard to the matters described below.

RAI B.2.1.28-1

Background:

SLRA Section B.2.1.28, "Buried and Underground Piping and Tanks," states the following:

a) The program will be consistent with the ten elements of GALL-SLR Report AMP Xl.M41, "Buried and Underground Piping and Tanks."

b) Coating will be applied to buried portions of the 10-inch diameter stainless steel line from the torus dewatering tank to the condensate transfer pump suction line in accordance with approved station specifications, during the 10-year period prior to the subsequent period of extended operation (SPEO).

c) Visual inspections of buried piping within the scope of license renewal will be in accordance with GALL-SLR Report Table Xl.M41-2, "Inspection of Buried and Underground Piping and Tanks."

GALL-SLR Report AMP Xl.M41 recommends the following:

a) One inspection for buried stainless steel in each 10-year inspection period beginning 10 years prior to the SPEO. This recommendation is based on all in-scope buried stainless steel being coated in accordance with the "preventive actions" program element of GALL-SLR Report AMP Xl.M41 during the inspection period.

b) Additional inspections, beyond those in GALL-SLR Report Table Xl.M41-2 may be appropriate if exceptions are taken to program element 2, "preventive actions."

The staff noted that the buried stainless-steel piping could be uncoated during portions of the 10-year period prior to the SPEO. Additionally, GALL-SLR Report AMP Xl.M41 recommends that additional inspections may be appropriate if exceptions are taken to the "preventive actions" program element. SLRA Section B.2.1.28 does not provide a basis for not being consistent with GALL-SLR Report AMP Xl.M41 in regard to conducting only one inspection of uncoated buried stainless-steel piping during the 10-year period prior to the SPEO.

Request:

May 2, 2019 Enclosure A Page 2 of 82 State the basis for why one inspection is appropriate for buried stainless steel piping during the 10-year period prior to the SPEO. Address relevant parameters such as the approximate length of buried uncoated stainless-steel piping, the approximate length of buried coated stainless-steel piping, results of soil corrosivity testing, etc.

Exelon Response:

Background:

During a 2014 buried piping inspection of adjacent torus dewatering tank attached piping, it was identified that the 10-inch diameter stainless steel line from the torus dewatering tank to the condensate transfer pump suction line was uncoated. This 10-inch diameter stainless steel line is the only known in-scope buried uncoated stainless steel piping. The torus dewatering tank and attached piping were installed following original construction as a plant modification.

Piping Lengths:

The uncoated buried segment of 10-inch diameter stainless steel piping totals approximately 44-inches in length, which is the entire buried portion of this line. There is a total of approximately 270 feet of buried in-scope stainless steel piping installed at Peach Bottom and therefore, the uncoated portion is a small percentage (1.5 percent) of the overall length of piping being age managed. Additionally, the buried piping program at Peach Bottom manages a total of approximately 1100 feet of buried stainless steel piping (including in-scope and not in-scope piping), which includes piping containing radioactive materials required to be inspected by NEI 09-14.

Inspection Results/Projections:

During NEI 09-14 inspection excavations, ultrasonic examination inspections, shear wave of pipe welds, guided wave inspections, and permanent guided wave collar installations for future structural health monitoring were performed on adjacent locations on buried stainless steel piping in the Unit 3 CST moat. Direct ultrasonic examination on not in-scope uncoated stainless steel piping at this excavation location indicated favorable results, with acceptable readings based on minimal amounts of wall loss/corrosion ranging from 0.5 to 0.6 mils per year. Based upon corrosion rates consistent with those found via direct examination methods, the resulting wall thickness projections for the 10-inch diameter stainless steel piping between now and the next inspection result in pipe wall thicknesses that significantly exceed minimum wall thickness requirements. Guided wave inspections indicated that direct UT results were representative for the conditions identified, and nothing beyond the excavation required verification.

Physical Configuration:

Direct visual inspections of the 10-inch diameter stainless steel line confirmed that there is not a pipe support that would result in a carbon steel to stainless steel galvanic interaction (consistent with design). Additionally, the extended exposure to the atmosphere prior to backfill means that a stable oxide layer was formed post-excavation and not disturbed during backfill, which reduces the risk for active to passive stainless galvanic effects. The 10-inch stainless steel line was originally backfilled with select engineered fill (sand) and the portion exposed during the buried piping excavation was backfilled with flowable fill (low-modulus concrete). Stainless steel piping has shown superior corrosion resistance in buried applications when effective

May 2, 2019 Enclosure A Page 3 of 82 preventative measures including proper backfill are utilized. An assessment of the configuration and local environment confirmed that there was a low risk of corrosion on this uncoated piping.

Soil Properties:

Soil samples extracted adjacent to the torus dewatering tank near the subject excavation were classified as non-corrosive based on resistivity and anion/cation abundance in accordance with ANSl/AWWA C105/A21.5-10 soil test evaluation guidance. Soil observed in each boring or excavation was moist, but generally demonstrated good drainage properties (the 10-inch stainless steel pipe is located above the mean ground water levels, thus resulting in minimal water to drive any corrosion effects), aerobic conditions with oxygen reduction potentials greater than 250 mV, and basic to slightly basic pH, which do not generally promote corrosion of buried piping or the growth of sulfide reducing bacteria. Soil resistivity, which is generally inversely correlated with corrosion rates and soil corrosivity is most sensitive to the abundance of specific species of anions and cations in soil pore water and soil particle arrangement, size and mineralogy. Soil sample results from Peach Bottom did not show a strong inverse correlation between the overall abundance and/or specific abundance of anions or cations present in each sample versus the resistivity of each sample (adjacent soil sample resistivity readings exceeded 4000 Ohm-cm). This suggests that electro-chemical processes associated with cathodic protection, stray current, and dissimilar metals are likely the dominant properties controlling soil corrosivity and corrosion rates within site soils, and the soils do not present elevated risk to corrode stainless steel piping.

In support of the station cathodic protection upgrades, a stainless steel electrochemical monitoring device (Smartstack) was installed at a nearby location to monitor for active/potential corrosion concerns for buried stainless steel piping at the site. The installed device yielded a corrosion rate of 0.35 mils per year, which based upon similarities in soil/environment, can be considered applicable to the location of the uncoated stainless steel pipe.

==

Conclusion:==

In summary, one inspection of buried stainless steel piping will be performed in the 10-year period prior to the SPEO. The basis for this approach is that: (a) the percentage of buried uncoated stainless steel pipe is small relative to the overall length of buried stainless steel pipe, (b) favorable UT inspection results have been recorded, (c) resulting projection of remaining wall thickness is acceptable, (d) configuration is favorable, and (e) low soil corrosivity potential results have been demonstrated as described above. Therefore, this sample inspection quantity and frequency are appropriate. The uncoated 10-inch diameter stainless steel line will be the location for the one inspection in the 10-year period prior to the SPEO and prior to the reapplication of the pipe coating, since it represents a worst-case condition of all buried stainless steel piping and is therefore bounding.

No updates to the SLRA are required as a result of this response.

RAI 8.2.1.28-2

Background:

May 2, 2019 Enclosure A Page 4 of 82 SLRA Section B.2.1.28 states "[t]he program uses the -850 mV relative to CSE (copper/copper sulfate reference electrode), instant off criterion specified in NACE SP0169 for acceptance criteria for steel piping and tanks."

GALL-SLR Report AMP Xl.M41 recommends a polarized potential of -950 mV or more negative for steel piping when active microbiologically influenced corrosion (MIC) has been identified or is probable.

During the audit the staff noted that the results of twenty soil corrosivity samples showed that:

(a) anaerobic sulfate reducing bacteria (SRB) were identified in thirteen of twenty tested samples; and (b) oxygen reduction potential values ranged from +263 to +390 mV in all samples.

The staff reviewed Pipeline Integrity - Management and Risk Evaluation (2nd Edition) and noted that for pipelines operating in anaerobic soils with known SRB, potentials more negative than -950 mV relative to CSE are used to control external corrosion.

The staff reviewed Ductile-Iron Pipe and Fittings - Manual of Water Supply Practices, M41 (3rd Edition) which states: "[a] redox potential greater than + 100 mV shows the soil to be sufficiently aerated so that it will not support sulfate reducers. Potentials of Oto +100 mV may or may not indicate anaerobic conditions; however, a negative redox potential definitely indicates anaerobic conditions under which sulfate reducers thrive."

The GALL-SLR Report AMP Xl.M41 recommendation to increase the cathodic protection polarization by-100 mV (i.e., from -850 mV to -950 mV) is based on: (a) active MIC being probable; or (b) operating experience identifying MIC on the external surfaces of buried piping or tanks. The staff noted that aerobic soil conditions support the conclusion that active MIC is not probable at Peach Bottom; however, the SLRA discussion of operating experience lacks sufficient detail to conclude whether or not instances of MIC on the external surfaces of buried steel piping or tanks have been identified.

Request:

State if MIC has been identified on the external surfaces of buried piping or tanks at Peach Bottom. If operating experience has identified one or more instances of MIC on the external surfaces of buried piping or tanks, state that basis for why the Buried and Underground Piping and Tanks program does not recommend a polarized potential of -950 mV or more negative for steel components.

References:

NACE SP0169-2007, "Control of External Corrosion on Underground or Submerged Metallic Piping Systems" Singh, Ramesh. (2017). Pipeline Integrity - Management and Risk Evaluation (2nd Edition) - Chapter 6. Corrosion and Corrosion Protection, page 265

May 2, 2019 Enclosure A Page 5 of 82 Ductile-Iron Pipe and Fittings - Manual of Water Supply Practices, M41 (3rd Edition).

American Water Works Association (AWWA), page 174 Exelon Response:

MIC has not been identified on the external surfaces of buried piping or tanks at Peach Bottom.

Inspections performed by excavations conducted during 201Oto2014 supporting the NEI 09-14 initiative, 'Guideline for the Management of Underground and Piping and Tank Integrity', yielded no instances of the presence of MIC on the external surfaces of buried piping or tanks. A confirmatory Peach Bottom operating experience search was also performed to conclude that there was no occurrence of external MIC on buried piping and tanks.

No updates to the SLRA are required as a result of this response.

May 2, 2019 Enclosure A Page 6 of 82

2.

GALL-SLR AMP XI.SB, "Protective Coating Monitoring and Maintenance Regulatory Basis:

1 O CFR § 54.21 (a)(3) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the subsequent period of extended operation. One of the findings that the staff must make to issue a renewed license (10 CFR Section 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the subsequent period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR Section 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis (CLB). In order to complete its review and enable making a finding under 1 O CFR Section 54.29(a), the staff requires additional information in regard to the matters described below.

RAI B.2.1.36-1

Background:

In its SLRA, Section B.2.1.36, "Protective Coating Monitoring and Maintenance," the applicant claimed consistency with the GALL-SLR Report for the AMP Xl.S8, "Protective Coating Monitoring and Maintenance." The GALL-SLR Report "Detection of Aging Effects," program element, states that ASTM D5163-08, "Standard Guide for Establishing a Program for Condition Assessment of Coating Service Level I Coating Systems in Nuclear Power Plants," paragraph 9 contains the requirements for qualifications of coatings inspection personnel.

During the In-Office audit, the staff reviewed the program basis document PB-PBD-AMP-Xl.S8, "Protective Coating Monitoring and Maintenance," Revision 1, to evaluate whether the applicant is consistent with the GALL-SLR Report recommendations for the "Protective Coatings" AMP.

In the document, the applicant states that coatings inspectors will be "certified," but does not provide a description of the certification. This is also described as an enhancement to the "Protective Coating Monitoring and Maintenance" program in the SLRA.

Issue:

ASTM D5163-08, paragraph 9, states that coatings inspection personnel should be qualified to ASTM D7108, "Standard Guide for Establishing Qualifications for a Nuclear Coatings Specialist." The applicant does not state what certification the coatings inspectors will attain.

Request:

State the certification that coatings inspectors will be required to attain when the proposed enhancement to the program is implemented.

Exelon Response:

The Service Level I coatings inspectors will be certified ANSI N45.2.6, Level II or Level Ill inspectors.

May 2, 2019 Enclosure A Page 7 of 82 SLRA Appendix A, Section A.2.1.36, and Appendix B, Section B.2.1.36 are revised as shown in Enclosure B. SLRA Appendix A, Section A.5, Commitment 36 is also revised as shown in Enclosure C.

RAI B.2.1.36-2

Background:

May 2, 2019 Enclosure A Page B of B2 In its SLRA, Section 8.2.1.36, "Protective Coating Monitoring and Maintenance," the applicant claimed consistency with the GALL-SLR Report for the AMP Xl.S8, "Protective Coating Monitoring and Maintenance." The "Detection of Aging Effects," program element references ASTM 05163-08 paragraph 6 which states that Service Level I coatings should be inspected

"... each refueling outage or during other major maintenance outages, as needed.... "

During the In-Office audit, the staff reviewed the PMID RQ 234247-01, "20S019: Torus Dewatering/Cleaning/lnspection," and PMID RO 234248-01, "30S019: Torus Dewatering/Cleaning/lnspection," to evaluate whether the applicant is consistent with the recommendations for the Water Chemistry AMP in the GALL-SLR Report. Additionally, the staff reviewed the program basis document PB-PBD-AMP-Xl.S8, "Protective Coating Monitoring and Maintenance," Revision 1.

Issue:

ASTM 05163-08 recommends inspection of Service Level 1 coatings during "... each refueling outage or during other major maintenance outages, as needed.... " During its review of the applicant procedures the NRG staff noted that inspections of Service Level I coatings are conducted at a frequency of at least every 2 refueling outages, or 4 years.

Request:

State the basis for why an inspection frequency for Service Level I coatings of every 2 refueling outages, or 4 years, is consistent with the GALL-SLR.

Exelon Response:

GALL-SLR aging management program XI.SB Section 2.1 states that "Regulatory Position C4 in NRG RG 1.54, Revision 2, describes an acceptable technical basis for a Service Level I coatings monitoring and maintenance program that can be credited for managing the effects of corrosion for carbon steel elements inside containment. American Society for Testing and Materials (ASTM) D 5163-0B and endorsed years of the standard in NRG RG 1.54 are acceptable and considered consistent with the Generic Aging Lessons Learned for Subsequent License Renewal (GALL-SLR) Report."

GALL-SLR aging management program XI.SB states in Element 4 "ASTM D 5163-08, paragraph 6, defines the inspection frequency to be each refueling outage or during other major maintenance outages, as needed." ASTM D 5163-08, paragraph 6.1 states "Frequency of in-service coating inspection monitoring shall be determined by the licensee or his designee. In operating nuclear power plants certain monitoring activities may be restricted to major maintenance outages or refueling outages. It is a good practice to perform inspections during each refueling outage or during other major maintenance outages." ASTM D 5163-08 does not prescribe a frequency for inspections but rather leaves the determination of the inspection frequency up to the licensee or his designee.

The current maximum interval for coating inspections in the non-immersion areas of the Primary Containment is 4 years. This frequency has been established by the PBAPS Maintenance Rule Program. Based upon the coating condition found during inspections since 2009, a coating

May 2, 2019 Enclosure A Page 9 of 82 inspection frequency of every other refueling outage (nominally 48 months) remains acceptable for Service Level I coatings in the non-immersion areas of the drywell and torus.

Both Unit 2 and 3 torus immersion areas have been recently recoated (Unit 2 in Fall 2012 and Unit 3 in Fall 2013).

Unit 2 immersion area coating inspections were performed by qualified inspectors in the Fall of 2014 and the Fall of 2018 to confirm the adequacy of the replacement coating.

Overall, the newly applied coating was documented to be in good condition, tightly bonded to the underlying substrate with no evidence of delamination, blistering, flaking, peeling, cracking, or checking.

Unit 3 immersion area coating inspection was performed by qualified inspectors in the Fall of 2015 to confirm the adequacy of the replacement coating. Overall, the newly applied coating was documented to be in excellent condition, tightly bonded to the underlying substrate with no evidence of delamination, blistering, flaking, peeling, cracking, or checking.

Based upon the coating conditions found during the immersion area inspections, a coating inspection frequency of every other refueling outage (nominally 4 years) remains acceptable for Service Level I coatings in the immersion area of the tori.

No updates to the SLRA are required as a result of this response.

RAI B.2.1.36-3

Background:

May 2, 2019 Enclosure A Page 10 of 82 In its SLRA, Section B.2.1.36, "Protective Coating Monitoring and Maintenance," the applicant claimed consistency with the GALL-SLR Report for the AMP XI.SB, "Protective Coating Monitoring and Maintenance." The GALL-SLR report recommends logging the total amount of degraded coatings in containment in order to compare it to the total amount of permitted degraded coatings. This allows for a determination of reasonable assurance of post-accident operability of the ECCS.

During the In-Office audit, the staff reviewed AR 1192421, "MSSRV [Main Steam Safety Relief Valve] Disch. Piping Temp.> Torus Coating Qualified Temp," dated March 25, 2011, which stated that the discharge temperature for the MSSRVs is greater than the coatings qualified temperature. The AR also stated that the coatings in the area of the MSSRVs will be deemed qualified unless a MSSRV opens, at which point it will be deemed unqualified and added to the unqualified coatings log. Additionally, Chapter 14, "Plant Safety Analysis," of the Updated Final Safety Analysis Report (UFSAR) provides an analysis that shows during certain postulated LOCAs, the MSSRVs may open.

Issue:

The "Monitoring and Trending" program element of the GALL-SLR recommends logging the total amount of degraded coatings in containment in order to compare it to the total amount of permitted degraded coatings. However, it is possible that the coatings currently deemed qualified in the area of the MSSRVs will fail as the MSSRV discharge temperature is greater than the coatings qualified temperature. This would result in more unqualified coatings than were accounted for in the unqualified coatings logs.

Request:

State the basis for determining that the coatings identified in AR 1192421 should remain

'qualified,' and how that is consistent with the "Monitoring and Trending" program element that recommends maintaining a log of all unqualified coatings.

Exelon Response:

The current PBAPS licensing and design basis calculation used to establish the Emergency Core Cooling System (ECCS) suction strainers debris loading is in accordance with NED0-32686 "Utility Resolution Guidance for ECCS Suction Strainer Blockage". The purpose of the unqualified coatings log is to control the addition/deletion of unqualified coatings of structures, systems, or components (SSCs) inside the containment so to maintain the amount of unqualified coatings within acceptable design limits, thereby maintaining the suction strainer debris loading margin established by this calculation.

An SSC that has an unqualified coating may exhibit a coating system failure during a Design Basis Loss of Coolant Accident (LOCA). The failed coating material may be transported from its original location to the various suction strainers associated with the ECCS pumps. Blockage of these strainers by the failed coatings may negatively impact the performance of these pumps.

May 2, 2019 Enclosure A Page 11of82 However, as discussed below, failure of the unqualified coating on the Safety Relief Valve (SRV) discharge piping will not impact the mitigation of postulated LOCA events.

The Peach Bottom recirculation suction line break is considered the design basis LOCA. The OBA LOCA has been found to generate the greatest amount of debris that would impact ECCS system performance. In this accident scenario, SRV's are not utilized as the reactor vessel is depressurized via the large pipe break. Therefore, the coating on the discharge piping of the SRV's remains qualified during the OBA LOCA.

In other LOCA events (small and intermediate line breaks) depressurization may require the use of the Automatic Oepressurization System, which utilizes up to 5 SRV's to reduce reactor pressure sufficiently to enable the low pressure ECCS injection systems. While the use of SRV's will cause the coating system to become unqualified for those specific SRV's, the overall debris loading from these types of pipe breaks is significantly less than that of the recirculation suction line break, and the amount of unqualified coatings created as a result of the event would be well within the debris loading margin of the ECCS strainers for both Unit 2 and Unit 3. It is for this reason the OBA LOCA is bounding and permits the ability to consider SRV tailpipe coatings qualified until used, and therefore, are not pre-emptively carried as unqualified coatings in the coatings log.

Should there be an SRV lift, the qualification of the coating associated with that SRV is indeterminant, considered unqualified, and added to the unqualified coatings log. This occurred on 3/14/2016 when Unit 2 SRV RV-2-02-71 K cycled open. An engineering change package was prepared which evaluated this event and determined the amount of unqualified coating that was required to be added to the Unit 2 unqualified coatings log. That particular event added approximately 12 lbs of unqualified coating, increasing the total amount of unqualified coatings for Unit 2 from approximately 51 O lbs to 522 lbs. The allowance for unqualified coating in the Unit 2 primary containment is 715 lbs. Therefore, significant margin exists for the ECCS suction strainers due to unqualified coating. One of the corrective actions of that event was to create an action tracking assignment to the SRV system engineer to track SRV lifts and notify the site coatings engineer after any SRV lift so that the impact of the SRV lift on torus coating could be evaluated. A review of accumulated unqualified coatings is performed to assure available margin exists to address a design basis LOCA, or appropriate actions are taken through the corrective action program.

It is noted that an examination of the RV-2-02-71 K SRV piping coating was performed by a qualified coating inspector during the Unit 2 Fall 2018 refueling outage. The examination noted no evidence of flaking, blistering, peeling, discoloration, checking, cracking, or other deleterious effects associated with extreme temperature exposure. The coating was intact and tightly adhered to the substrate with a single isolated indication of spot corrosion. The coating adjacent to this indication was tightly bonded to the substrate. Coating on this SRV tailpipe is still recorded as unqualified in the Unit 2 unqualified coating log.

No updates to the SLRA are required as a result of this response.

RAI 8.2.1.36-4

Background:

May 2, 2019 Enclosure A Page 12 of B2 The GALL-SLR recommends the UFSAR supplement for the XI.SB, "Protective Coating Monitoring and Maintenance," program reference Regulatory Guide (RG) 1.54, "Service Level I, II, Ill, and In-Scope License Renewal Protective Coatings Applied to Nuclear Power Plants," as the basis for inspecting and maintaining Service Level I Coatings.

The applicant's proposed UFSAR supplement in Section A.2.1.36 of the SLRA doesn't reference RG 1.54 as the basis for the "Protective Coating Monitoring and Maintenance" program. The proposed UFSAR supplement only references RG 1.54 to give the definition of Service Level I coatings. Therefore, it is not clear what standard the program will be based on.

Request:

State the basis for how the proposed UFSAR supplement is consistent with the recommended supplement provided in the GALL-SLR.

Exelon Response:

SLRA Appendix A, Section A.2.1.36 for the Protective Coating Monitoring and Maintenance program does not address RG 1.54 as recommended in GALL-SLR Table Xl-01 for aging management program XI.SB. GALL-SLR AMP XI.SB states in the Program Description that a comparable program for monitoring and maintaining protective coatings inside containment, developed in accordance with NRG RG 1.54, Revision 2, is acceptable as an aging management program for subsequent license renewal. The Peach Bottom SLR Protective Coating Monitoring and Maintenance program is comparable to a monitoring and maintenance program for Service Level I protective coatings as described in RG 1.54, Revision 2.

Accordingly, consistent with GALL-SLR Table Xl-01 for aging management program XI.SB, SLRA Appendix A, Section A.2.1.36 will be revised to state that the program is comparable to a monitoring and maintenance program for Service Level I protective coatings as described in RG 1.54, Revision 2.

SLRA Appendix A, Section A.2.1.36 is revised as shown in Enclosure B. SLRA Appendix B, Section B.2.1.36 is also revised as shown in Enclosure B.

May 2, 2019 Enclosure A Page 13 of 82

3.

GALL-SLR Report AMP Xl.M42 Internal Coatings/linings for In-scope Piping, Piping Components, Heat Exchangers and Tanks Regulatory Basis:

1 O CFR 54.21 (a)(3) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the subsequent period of extended operation. One of the findings that the staff must make to issue a renewed license (1 O CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the subsequent period of extended operation on the functionality of structures and components that have been identified to require review under 1 O CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 1 O CFR 54.29(a), the staff requires additional information in regard to the matters described below.

RAI 8.2.1.29-1

Background:

SLRA Table 3.3.2-17, "High Pressure Service Water System," states that loss of coating integrity and loss of material is managed for internally coated carbon steel residual heat removal (AHR) heat exchanger tube side components exposed to raw water using the Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks program.

During the audit, the staff noted that during development of the Internal Coatings/Linings for in-Scope Piping, Piping Components, Heat Exchangers, and Tanks aging management program, it was identified that the high-pressure service water side of the AHR heat exchanger water box does not appear to be coated.

Issue:

Based on the staff's observation during the audit, it is unclear if the subject components are internally coated. If the subject components are not internally coated, it is unclear to the staff why the Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks program is appropriate to manage loss of material for the subject components.

Request:

State if the high-pressure service water carbon steel AHR heat exchanger tube side components are internally coated. If the subject components are not internally coated, state the basis for why the Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks program is appropriate to manage loss of material for the subject components.

Exelon Response:

May 2, 2019 Enclosure A Page 14 of 82 On January 24, 2019, during testing and inspection of the Unit 3 "D" RHR Heat Exchanger, an inspection of the water box was performed to determine if a protective coating was present.

The coating was verified to be present as shown on the heat exchanger design drawing.

Therefore, the identified material type of carbon steel with an internal coating is correct, and no changes to SLRA Table 3.3.2-17 or the Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks program are required.

No updates to the SLRA are required as a result of this response.

May 2, 2019 Enclosure A Page 15 of 82 RAI B.2.1.29-2

Background:

SLRA Tables 3.3.2-24, "Radwaste System," and 3.3.2-26, "Reactor Water Cleanup System,"

state that internally coated carbon steel tanks exposed to treated water are managed for loss of material and loss of coating or lining integrity using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program. As amended by letter dated January 23, 2019, the plant-specific note associated with the subject components states "[t]he environment is Treated Water that does not have the potential for microbiologically-induced corrosion."

GALL-SLR Report AMP Xl.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks," states that GALL-SLR Report AMP Xl.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," is an acceptable alternative to the inspections recommended in GALL-SLR Report AMP Xl.M42 when six different condition exists. One of the conditions is that the internal environment would not promote microbiologically influenced corrosion (MIC) of the base metal.

NUREG-2221, Technical Bases for Changes in the Subsequent License Renewal Guidance Documents NUREG-2191 and NUREG-2192," states the following:

Issue:

MIC is not likely in treated water systems where sulfates and chlorides are low (<150 ppb); however, contamination of treated water systems can lead to MIC. Treated water systems typically are low in the nutrients required to sustain microorganisms, but in stagnant or low flowing areas, corrosion products and contaminants can accumulate and settle. The same contamination source for the microorganism could also allow introduction of the nutrients required to sustain these microbes.

A basis was not provided for why the internal surfaces of the internally coated carbon steel tanks in the radwaste and reactor water cleanup systems exposed to treated water are not susceptible to loss of material due to MIC.

Request:

State the basis for why internally coated carbon steel tanks exposed to treated water in the radwaste and reactor water cleanup systems are not susceptible to MIC.

Exelon Response:

Internally coated carbon steel tanks exposed to treated water are not susceptible to MIC because the water chemistry of the tank contents does not support the presence of MIC, there is no source of MIC contamination which could be introduced into these tanks, and there is no operating experience documented which identifies the presence of MIC in these tanks. The tanks for which this evaluation is applicable are the Reactor Water Cleanup (RWCU) Backwash Receiving Tanks (BWRTs), the RWCU Filter Demin Precoat Tanks, and the Filter Aid Tank.

The specific sources of treated water for these tanks are reactor water via the RWCU system and condensate from the condensate storage tanks. Water quality standards for treated water systems conform to BWRVI P-190 guidelines, which maintain limits of 5 ppb for chlorides and

May 2, 2019 Enclosure A Page 16 of 82 sulfates in reactor water, and limits of 10 ppb for chlorides and sulfates in the condensate storage tanks. This is well below the 150 ppb value which is cited in various industry documents as the level of concern for MIC. Therefore, the internal environment of these tanks does not promote or sustain the presence of MIC.

The design and operating configurations of these tanks, and of the systems which supply treated water to them, do not present the potential for MIC contamination to occur. The function of the RWCU Filter Demin Precoat Tanks and the Filter Aid Tank is to mix precoat media and filter aid material with condensate, which is then transferred to a filter or demineralizer. The function of the RWCU BWRTs is to receive the backwash of spent resin from the RWCU filter demineralizers, which is then processed in the solid radwaste system. The condensate storage and transfer system is a source of water to each of these tanks. The condensate storage and transfer system supplies high quality water from the Condensate Storage Tanks, which are monitored in accordance with BWRVIP-190 guidelines to detect contaminants.

The RWCU BWRTs, in addition to the condensate storage and transfer system, also communicate with the service air system and the RWCU system. The service air system supplies clean filtered air through a piping distribution network and contains no additional components or potential sources of contamination. The RWCU system is a closed system that circulates reactor quality water through filter demineralizers and heat exchangers. The RWCU regenerative heat exchangers contain reactor water as the process fluid on both sides of the tubes. The RWCU non-regenerative heat exchangers are cooled by the reactor building closed cooling water (RBCCW) system, which is a closed loop system that is treated with corrosion inhibitors and is monitored and treated for microbiological growth. RBCCW is managed by the Closed Treated Water Systems (B.2.1.12) aging management program and maintains water chemistry in accordance with the EPRI Closed Cooling Water Chemistry Guideline. Given this configuration, there is no potential source of cross contamination of the RWCU system through these non-regenerative heat exchangers. Therefore, there is no potential source of MIC contamination of these tanks from any of these sources.

Finally, a review of plant operating experience has not revealed evidence of MIC occurring in these tanks, or in any components in treated water systems. As discussed in EPRI Technical Report 3002011822, Subsequent License Renewal Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, it is highly unlikely that MIC will become a concern during the second license renewal period if it has not been observed through plant operating experience.

For these reasons, loss of material due to MIC is not considered to be an applicable aging effect for these internally coated carbon steel tanks.

No updates to the SLRA are required as a result of this response.

4.

GALL-SLR AMP Xl.M27 Fire Water System Regulatory Basis:

May 2, 2019 Enclosure A Page 17 of 82 1 O CFR 54.21 (a)(3} requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s} will be maintained consistent with the current licensing basis for the subsequent period of extended operation. One of the findings that the staff must make to issue a renewed license (1 O CFR 54.29(a is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the subsequent period of extended operation on the functionality of structures and components that have been identified to require review under 1 O CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 10 CFR 54.29(a}, the staff requires additional information in regard to the matters described below. RAI 8.2.1.17-1

Background:

SLRA Section B.2.1.17, "Fire Water System" program, Enhancement No 1 states the following in relation to inspector tests flushes and main drain tests: "[l]f acceptance criteria are not met, at least two additional tests shall be performed. If acceptance criteria are not met during follow-up testing, the test shall be performed on the same system, on the other unit." SLRA Section B.2.1.17 also states that it will be consistent with GALL-SLR Report AMP Xl.M27, "Fire Water System," with an exception. The exception is not related to inspector test flushes and main drain tests. GALL-SLR Report AMP Xl.M27, "Fire Water System," recommends the following additional corrective actions other than those cited in Enhancement No.1: (a} the additional tests are completed within the interval in which the original test was conducted; and (b} if subsequent tests do not meet acceptance criteria, an extent of condition and extent of cause analysis is conducted to determine the further extent of tests. The Program Basis Document for the Fire Water System, reviewed during the audit, states that: (a} wet pipe sprinkler systems fed directly from the main supply header do not have alarm control valves or a main drain; and (b} inspector test flushes are performed that verify there are no flow blockages in the supply piping. GALL-SLR Report AMP Xl.M27, Table Xl.M27-1, "Fire Water System Inspection and Testing Recommendations," recommends that main drain tests be conducted. Issue: SRP-SLR Section 1.2.1 states: Section 54.21 (a)(3} to 1 O CFR Part 54 requires the application to demonstrate, for SSCs within the scope of license renewal and subject to an AMR pursuant to 1 O CFR 54.21 (a}(1 ), that the effects of aging are adequately managed so that the intended function(s} are maintained

consistent with the current licensing basis (CLB) for the subsequent period of extended operation. For the programs submitted in the SLRA that the applicant claims are consistent with the GALL-SLR Report, the NRG staff will verify that the applicant's programs are consistent with those described in the GALL-SLR Report and/or with plant conditions and OE during the performance of an AMP audit and review. May 2, 2019 Enclosure A Page 18 of 82 The SLRA lacks sufficient information to determine that the Fire Water System program is consistent with GALL-SLR Report AMP Xl.M27; in particular: (a) the adequacy of additional inspections when test acceptance criteria are not met; and (b) the criteria that will be used to determine the number of further tests if any of the initial set of additional inspections do not meet acceptance criteria. During the audit, it was conveyed to the staff that of the 29 wet pipe sprinkler systems that are fed directly from the main supply header, 20 have main drains and 9 do not. The staff noted that the test procedure associated with inspector test flushes is conducted by starting a stop watch, opening a valve, and timing the duration until an alarm window actuates. Based on the potential variability of the time to taken to open the valve, it is not clear whether the results of the inspector test flushes can be accurately trended sufficient to detect potential flow blockage due to fouling. In order to determine whether the Fire Water System program is consistent with GALL-SLR Report AMP Xl.M27, the staff seeks clarification on: (a) whether main drain tests will be conducted on all of the wet pipe sprinkler systems that have main drains; and (b) whether the results of the inspector test flushes can be accurately trended sufficient to detect potential flow blockage due to fouling. Request: a) State when the additional inspections will be conducted when test acceptance criteria are not met. State the criteria or method that will be used to determine the number of further tests if any of the initial set of additional inspections do not meet acceptance criteria. State the basis for the response if the provided information is not consistent with GALL-SLR Report AMP Xl.M27. b) Respond to the following: (a) confirm that of the 29 wet pipe sprinkler systems fed directly from the main supply header, 20 have main drains and 9 do not, or provide the correct quantities; (b) state whether main drain tests will be conducted on all of the wet pipe sprinkler systems that have main drains and provide the basis for the population size if they will not all be periodically tested consistent with GALL Report AMP Xl.M27, Table Xl.M27-1; and (c) if it is assumed that the results of the inspector test flushes can be trended sufficient to detect potential flow blockage due to fouling, state the basis for the consistency of the trend results. Exelon Response:

a. The SLRA Enhancement 1.c (Commitment 17) of the Fire Water System (B.2.1.17) aging management program is revised as shown below to include an investigation in the corrective action program to determine when additional tests will be conducted and how

May 2, 2019 Enclosure A Page 19 of 82 the number of further tests will be determined when test acceptance criteria are not met. Enhancement 1.c is revised as follows: If flow test acceptance criteria are not met, perform an investigation within the corrective action program that includes review for increased testing and perform at least two successful additional tests. shall be performed Additional tests shall be completed within the interval in which the original test was conducted. If acceptance criteria are not met during follow-up testing, an extent of condition and extent of cause analysis shall be conducted to determine the further extent of tests which includes testing The test shall be performed on the same system, on the other unit.

b. a) There are twenty-nine (29) wet sprinkler systems in SLR scope fed directly from the Fire Water System main supply header. This includes twenty (20) wet sprinkler systems with alarm control valves that have two-inch main drains and inspector test flush connections. Of the twenty-nine (29) wet systems, nine (9) wet sprinkler systems do not have alarm control valves or two-inch main drains. The nine (9) wet sprinkler systems without alarm control valves have inspector test connections.

b) Main drain tests are performed on all of the twenty (20) wet sprinkler systems with alarm control valves and two-inch main drains consistent with GALL-SLR AMP Xl.M27. Inspector test flushes are performed on all twenty-nine (29) wet sprinkler systems consistent with GALL-SLR AMP Xl.M27. c) The functional test of the inspector test flush is performed on twenty-nine (29) wet pipe sprinkler systems to verify there is no flow blockage due to fouling in the sprinkler system and fire water supply system. In addition, main drain tests are also performed on the twenty (20) wet sprinkler systems with alarm control valves and two-inch main drains to identify the onset of flow blockage due to fouling in the fire water supply system. The fire water supply test pressures recorded during the main drain test provide the system operational parameters required for trending that will identify the onset of degrading water supply conditions. During the inspector test flushes, the nominal time from opening the test valve to control room alarm annunciation is recorded and compared to the test criteria. The time recorded in the flow test procedure includes variability in the time to open the valve and variability in the time it takes for the operator to report the alarm condition. The inspector test flush acceptance criteria requires water to flow from the supply piping, through the sprinkler system actuating a pressure switch, and initiating an alarm condition within one minute from opening the test valve. The basis for the one-minute criterion is to provide adequate time to bound the variability in the test and still demonstrate water is flowing through the supply piping and sprinkler system and there is no flow blockage. Although inspector test flushes are required by NFPA 25, there is no NFPA code requirement for timing the inspector test flush and alarm annunciation. Therefore, the acceptance criterion of one minute is considered appropriate and will identify flow blockage in the supply piping or sprinkler system. If the test acceptance criterion of one minute is not met due to flow blockage, then the issue is entered into the corrective action program.

May 2, 2019 Enclosure A Page 20 of 82 SLRA Appendix A, Section A.2.1.17, and Appendix B, Section B.2.1.17 are revised as shown in Enclosure B. SLRA Appendix A, Section A.5, Commitment 17 is also revised as shown in Enclosure C.

RAI 8.2.1.17-2

Background:

May 2, 2019 Enclosure A Page 21 of 82 GALL-SLR AMP Xl.M27, Table Xl.M27-1, recommends that hydrants be flushed in accordance with NFPA-25, "Standard for the Inspection, Testing, and Maintenance of Water-Based Fire Protection Systems," Section 7.3.2, which requires that: (a) "[e]ach hydrant shall be opened fully and water flowed until all foreign material has cleared;" and (b) "[f]low shall be maintained for not less than 1 minute." The Water-Based Fire Protection Systems Handbook, Fourth Edition, Testing Procedure for [NFPA 25 Section] 7.3.2 states, "[o]pen the hydrant fully and allow the flow to continue until all foreign material has cleared, with a minimum flow period of 1 minute." Page 196 of this document clarifies this requirement by stating, "[f]low test until all foreign material has cleared (not less than one minute)." The plant-specific procedures do not include a requirement that the hydrant flush be maintained for a minimum of one minute and the SLRA does not include an enhancement to address this, or an exception to justify the difference. NFPA-25, Section 7.3.2, also requires that: (a) "[a]fter operation, dry barrel and wall hydrants shall be observed for proper drainage from the barrel" (b) "[f]ull drainage shall take no longer than 60 minute;" and (c) "[w]here soil conditions or other factors are such that the hydrant barrel does not drain within 60 minutes, or where the groundwater level is above that of the hydrant drain, the hydrant drain shall be plugged and the water in the barrel shall be pumped out." During the audit, the staff's review of plant-specific operating experience revealed that multiple hydrants were found full or a water level was detected within the hydrant. In addition, the plant specific procedure for flushing hydrants states that: (a) the hydrant should be, "drained to a level approximately 3 feet below ground level;" and (b) "[i]f the hydrant is still not drained, or directed by the sign on the fire hydrant, then manually pump it down to 3 feet below the ground." During the audit, it was conveyed to the staff that: (a) the frost line in the vicinity of Peach Bottom is 20 inches to 30 inches deep; and (b) there are some hydrants located in areas where the water table is higher and they might not remain drained following the flush. Table 7.2.2.4 of the NFPA 25 Handbook states that a barrel which contains water or ice could be indicative of a faulty drain, a leaky hydrant valve, or high groundwater table, The recommended corrective action is to "[r]epair and drain; for high groundwater it could be necessary to plug the drain and pump out the barrel after each use." The SLRA does not include an enhancement to address this, or an exception to justify the difference. Issue: The staff has concluded that to be consistent with GALL-SLR Report AMP Xl.M27, a hydrant must be fully open for at least one minute to ensure that an adequate flush was conducted. The staff's position is based on the fact that until the hydrant is fully open, the flow velocity might not be adequate to clear the fire water main of all debris. The SLRA lacks sufficient information to justify this staff-identified difference. Although the plant-specific procedures require that a hydrant be drained below the frost line, the frost line is based on the soil overcharge. In the case of a hydrant, while soil surrounds the hydrant barrel, the barrel internal temperature could be below freezing for depths greater than the frost line. In addition, as conveyed to the staff during the audit, certain hydrants might refill with water due to the water table height. The SLRA lacks sufficient information to justify: (a) why hydrants are only pumped to 3 feet below the ground; and (b) why the hydrant drain is not

May 2, 2019 Enclosure A Page 22 of 82 plugged and the plant-specific procedures enhanced to state that water in the barrel shall be pumped out where the water table can result in leakage into a hydrant barrel. Request: a) State the basis for why an adequate hydrant flush has been conducted when the plant-specific procedures do not include a requirement to fully open the hydrant for at least one minute. b) Respond to the following: (a) confirm the depth of the frost line; (b) state the basis for why water in the hydrant barrel will not freeze even though it is only pumped down to 3 feet below the ground level; and (c) state why the hydrant drain is not plugged and the plant-specific procedures enhanced to state that water in the barrel shall be pumped out where the water table can result in leakage into a hydrant barrel. Exelon Response:

a. The PBAPS fire hydrant inspection and flush test procedure requires hydrant flow until clear assuring mud and debris is flushed from the system; however, the test procedure does not specify a minimum flow duration. Enhancement 15 (Commitment 17) is added to the Fire Water System (B.2.1.17) aging management program to include a minimum flow duration of one (1) minute after the hydrant valve is fully open to assure adequate time is allowed to clear the fire water main of all foreign material.

b. The PBAPS fire hydrant inspection and flush test procedure is performed annually in the summer months. A review of completed tests since 2004 indicate that some hydrants have been found with standing water. Water found in hydrants is the result of either ground water entering through the normally open drain port, or a leaking hydrant valve that cannot completely drain through the drain port.

After a hydrant has been flushed and given time to drain, the hydrant flush test procedure requires the hydrant to be checked for standing water. If water is found, the test requires the water be pumped down to three (3) feet below the ground surface. Pumping down to at least three (3) feet ensures the hydrant is drained below the frost line depth of approximately thirty (30) inches. a) A maximum frost line depth between 20 to 30 inches is anticipated for the PBAPS location based on US Department of Commerce Frost Line Penetration data. b) A search of plant operating experience for freezing fire hydrants was performed since 2004. No occurrences of freezing fire hydrants at PBAPS were found. The operating experience confirms the current fire hydrant flush and drain method is effective since there is no history of freezing fire hydrants. Therefore, the basis for why water in the hydrant barrel will not freeze even though it is only pumped down to three (3) feet below the ground level is that the frost line is above three (3) feet and operating experience has demonstrated the effectiveness of the hydrant flush method. c) Operating experience, including many sub-freezing conditions, has proven the current flush and drain method effective since there is no history of freezing hydrants at PBAPS. Therefore, plant-specific procedures do not need to be enhanced and a design change to the current hydrant configuration is not necessary.

May 2, 2019 Enclosure A Page 23 of 82 SLRA Appendix A, Section A.2.1.17, and Appendix B, Section B.2.1.17 are revised as shown in Enclosure B. SLRA Appendix A, Section A.5, Commitment 17 is also revised as shown in Enclosure C.

May 2, 2019 Enclosure A Page 24 of 82 RAI B.2.1.17-3

Background:

SLRA Section B.2.1.17, Enhancement No. 4 states," [r]evise procedures to improve guidance for external visual inspections of the in-scope sprinkler systems piping and sprinklers at least every two years to inspect for excessive corrosion... " NFPA 25 Section 5.2.1.1.2 states that, "[a]ny sprinkler that shows signs of any of the following shall be replaced: (1) leakage; (2) corrosion... " During its search of plant-specific operating experience, the staff noted four instances of leaking sprinklers. GALL-SLR Report AMP Xl.M27, Table Xl.M27-1, footnote 10 states, "[w]here NFPA 25 or this table cite annual testing or inspections, testing and inspections can be conducted on a refueling outage interval if plant-specific OE has shown no loss of intended function of the in-scope SSC due to aging effects being managed for the specific component (e.g., loss of material, flow blockage due to fouling)." Issue: a) As recommended by GALL-SLR Report AMP Xl.M27, sprinklers exhibiting "corrosion" versus sprinklers exhibiting "excessive corrosion" are to be replaced. The SLRA does not describe the difference between "significant corrosion" and "corrosion" and as a result, the staff cannot conclude whether the changes described in Enhancement No. 4 will be consistent with GALL-SLR Report AMP Xl.M27. b) The SLRA lacks sufficient information for the staff to conclude whether the effects of the leakage identified in the plant-specific operating experience could have adversely affected the sprinkler such that its intended function would not have been met. Request: a) State the criteria that differentiate between corrosion and significant corrosion and the basis for why using the criterion of significant corrosion will be effective at identifying sprinkler degradation prior to a loss of intended function. b) State the percentage of wet pipe sprinklers that exhibited leakage in the past 1 O years. State the basis for why the effects of the observed leakage did not result in a loss of intended function of the sprinkler. If the effects could have resulted in a loss of intended function, state the basis for the effectiveness of the proposed sprinkler visual inspections. Exelon Response:

a. Enhancement 4 (Commitment 17) will be revised to remove the word "significanf' for consistency with GALL-SLR Report AMP Xl.M27. If corroded sprinklers are identified during the inspection, the condition will be entered into the corrective action program for engineering evaluation. Sprinklers that have corrosion that could impact the design function will be replaced.

b. The PBAPS power block fire suppression sprinkler systems consist of approximately 1900 total sprinklers. Of the 1900 sprinklers approximately 500 are dry pre-action

May 2, 2019 Enclosure A Page 25 of 82 sprinklers leaving approximately 1400 sprinklers on wet sprinkler systems. A search of plant operating experience identified five (5) sprinklers on wet pipe sprinkler systems, (0.4 percent) that were found leaking since 2004. The leaks were small (i.e. drops per minute) and found by either plant operators or maintenance personnel performing field work activities. The basis for why the observed leakage was determined to have no effect on the intended function of the sprinklers is that there was no sprinkler assembly corrosion identified or noted on the leaking sprinklers. The leaks did not adversely impact the ability of the sprinklers to perform their design function to actuate at a specific temperature and spray water in an intended spray pattern. Therefore, the intended function of the sprinklers and fire systems were maintained. The leaking sprinklers were replaced. SLRA Appendix A, Section A.2.1.17, and Appendix B, Section B.2.1.17 are revised as shown in Enclosure B. SLRA Appendix A, Section A.5, Commitment 17 is also revised as shown in Enclosure C.

RAI B.2.1.17-4

Background:

May 2, 2019 Enclosure A Page 26 of 82 During its search of plant-specific operating experience, the staff noted a decreasing trend of fire water pump flow testing results. In tests conducted in 2015 and 2018, some of the flow tests did not meet acceptance criteria. Issue: The existing testing results could be indicative of potential degradation of the underground fire water system, leakage past isolation valves, or instrument accuracy issues. Given that potential degradation of the underground fire water system cannot be eliminated as a cause for the adverse results, the SLRA does not include sufficient information to justify conducting underground flow tests every 5 years as recommended by GALL-SLR Report AMP Xl.M27. The staff recognizes that if corrective actions and subsequent inspections establish a trend of meeting the acceptance criteria and the trend results support it; a return to a 5-year interval of testing could be acceptable. Request: State the periodicity of conducting underground flow tests and the basis for why this periodicity will demonstrate that the intended function of the fire water system will be met throughout the subsequent period of extended operation. Exelon Response: To ensure that the periodicity for conducting underground flow tests adequately demonstrates the intended function of the fire water system is maintained when test criteria is not met, Enhancement 16 (Commitment 17) is added to the Fire Water System aging management program, Xl.M27. The basis for the enhancement utilizes the corrective action program to determine an increased periodicity for conducting the underground flow tests when established test criteria is not met, or when significant degraded trends that could adversely affect system intended function are identified as recommended by GALL-SLR AMP Xl.M27. The increased test frequency will be based on providing sufficient system performance data necessary to closely monitor and trend system performance to ensure the fire water system intended function is maintained and that degraded conditions are corrected in a timely manner. When test results pass the established test criteria, the test frequency may be extended to five (5) years in accordance with NFPA 25 Section 7.3.1. SLRA Appendix A, Section A.2.1.17, and Appendix 8, Section B.2.1.17 are revised as shown in. SLRA Appendix A, Section A.5, Commitment 17 is also revised as shown in Enclosure C.

5.

GALL-SLR Report for the AMP Xl.M30, "Fuel Oil Chemistry Regulatory Basis: May 2, 2019 Enclosure A Page 27 of 82 Regulatory Basis: 1 O CFR § 54.21 (a)(3) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the subsequent period of extended operation. One of the findings that the staff must make to issue a renewed license (1 O CFR Section 54.29(a)) is that actions have been identified and have been or will be taken with respect to the managing the effects of aging during the subsequent period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR Section 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis (CLB). In order to complete its review and enable making a finding under 1 O CFR Section 54.29(a), the staff requires additional information in regard to the matters described below. RAI B.2.1.19-1

Background:

In its SLRA, Section B.2.1.19, "Fuel Oil Chemistry," the applicant claimed consistency with the GALL-SLR Report for the AMP Xl.M30, "Fuel Oil Chemistry." The GALL-SLR Report AMP Xl.M30, "detection of aging effects" program element states, "[p]eriodic multilevel sampling provides assurance that fuel oil contaminants are below unacceptable levels. If tank design features do not allow for multilevel sampling, a sampling methodology that includes a representative sample from the lowest point in the tank may be used." During the In-Office audit, the staff reviewed the program basis document PB-PBD-AMP-Xl.M30, "Fuel Oil Chemistry," Revision 1, to evaluate whether the applicant is consistent with the GALL-SLR Report recommendations for the "Fuel Oil Chemistry" AMP. The program basis document for Fuel Oil Chemistry program states, "(d]iesel generator fuel oil storage tank OA(B,C,D)T038 samples are withdrawn from the fuel oil transfer pump suction piping while the transfer pump is in service. The transfer pump suction is located 4" off the tank bottom." Additionally, the design basis document states, that the Peach Bottom site sampling methodology is more conservative than what is recommended in ASTM 04057. ASTM 04057 Table 1, Typical Sampling Procedures and Applicability," states that bottom or thief sampling of liquid is used for storage tanks.

1. It is not clear to the staff that samples taken from the fuel oil transfer pump while the pump is running, meets the recommendations of the GALL-SLR program element "detection of aging effects" for multi-level sampling or a representative sample from the lowest point of the tank. If the pump has been running for some period of time prior to

May 2, 2019 Enclosure A Page 28 of 82 taking the sample, the sample will not be representative of the fuel oil that is normally at the bottom of the stagnant tank. Any water, sediment, and microbiological organisms in the fuel oil that may have been present at the bottom of the tank will have already been pumped out, thus preconditioning the sampled fluid.

2. It is not clear to the staff whether a sample point that is 4 inches above the tank bottom is truly considered a bottom sample.

Request:

1. State the basis for the deviation from the GALL-SLR Report AMP Xl.M30 "detection of aging effects" program element which recommends taking either a multi-level sample, or a representative sample from the lowest point in the tank. Additionally, provide a basis on why pre-conditioning is not being considered when taking samples while the transfer pump is in operation, which could possibly be pumping out any standing water or sediment that would be present in the bottom of the tank during stagnant conditions.

2. State the basis for why the pump intake level of 4 inches above tank bottom provides a representative sample of the fluid on the tank bottom.

Exelon Response:

1. The recommendations for fuel oil sampling were revised in Revision 2 of NUREG-1801, "Generic Aging Lessons Learned (GALL) Report," to allow a "representative sample from the lowest point in the tank" as an acceptable alternative to multi-level sampling. With regard to multi-level sampling, NUREG-1950, "Disposition of Public Comments and Technical Bases for Changes in the License Renewal Guidance Documents NUREG-1801 and NUREG-1800" clarified that "different designs should be reviewed on a case-by-case basis to ensure they are either equivalent or more conservative to multi-level sampling." The recommendations for fuel oil sampling in NUREG-2191 have not changed from NUREG-1801, Revision 2. As discussed below, the PBAPS sampling methodology is more conservative than multi-level sampling and, therefore, is an acceptable approach for managing the effects of aging in fuel oil systems.

The diesel generator fuel oil storage tanks OA(B,C,D)T038 do not have low point drains. Each tank has its own transfer pump. With the transfer pump running, oil is drawn from 4 inches off the bottom of the tank through the transfer pump suction piping which is vertically configured inside the tank. After running the transfer pump for 5 minutes, the sample is taken through a sample connection installed on differential pressure indicator instrument tubing located on the discharge of the transfer pump. Flushing the piping for 5 minutes clears the volume of oil from the transfer pump suction piping and ensures that the oil sample is taken from the contents of the tank. This sample method is used currently to satisfy Technical Specification requirements for fuel oil sampling. ASTM 04057, "Standard Practice for Manual Sampling of Petroleum and Petroleum Products," does not define "multilevel sample" but defines "all-levels sample", "tank composite sample", and "running sample" which are sample methods that combine oil from multiple levels in the tank. The requirements in ASTM 04057 for these sampling methods are as follows:

May 2, 2019 Enclosure A Page 29 of 82 All-levels sample - a sample obtained by lowering the closed sampling device to the bottom of the outlet suction level, but always above free water, then opening the sampler and raising it at a uniform rate such that it is between 70 and 85 percent full when withdrawn from the product. Alternatively, all-levels samples may be taken with samplers designed for filling as they pass downward through the product. Tank composite sample - a sample prepared by combining a number of samples and treated as a single sample. Composite samples include samples from different elevations in the tank referred to as "lower", "middle", and "upper where "lower is defined as 20 percent of the tank diameter above the tank bottom. For the PBAPS diesel generator fuel oil storage tanks, this would be 20 percent of 144 inches or 28.8 inches from the tank bottom. Running Sample - a sample obtained by lowering an open sampling device to the bottom of the outlet suction level, but always above free water, and returning it to the top of the product at a uniform rate such that the sampling device is between 70 and 85 percent full when withdrawn from the product. All three of these methods include combining oil from a lower tank level (i.e., bottom of outlet suction or "lower elevation as described for the tank composite sample above), which does not contain free water, with oil obtained at higher levels in the tank. The PBAPS samples are taken from the outlet suction located 4 inches from the tank bottom and are not combined with oil samples taken at higher levels in the tank. The PBAPS sampling methodology obtains samples which are more likely to contain higher concentrations of contaminants, water, and sediment which tend to settle in the tank. Therefore, the PBAPS sample location and methodology is effective for the determination of contaminants, water, and sediment in fuel oil, and is more conservative than the "multilevel" sample methods described in ASTM 04057. Pre-conditioning of the oil sample due to operation of the transfer pump is not occurring. Prior to obtaining a sample, the transfer pump is run for 5 minutes to flush the transfer piping. The capacity of the pump is a nominal 45.5 gpm. After 5 minutes, 227.5 gallons will have been flushed through the transfer piping. The tank is horizontal with an outside diameter of 144 inches and a length of 45 feet. The tank has a capacity of 39,655 gallons and is required by the station's Technical Specifications to maintain at least 29,500 gallons for emergency diesel generator operability. Pumping 227.5 gallons from the tank for flushing is inconsequential with respect to contaminants, water, and sediment that are in the lower region of the tank where the sample is obtained. Removal of any water at the bottom of the tank prior to taking the sample is also not a concern since the sample methods described above in 04057 are taken above any free water. It is also noted that the diesel generator fuel oil storage tanks are required by the plants Technical Specifications to be checked for standing water every 31 days. If water is found in the sample, the condition is entered into the Corrective Action Program and analysis is performed on the sample for the presence of microbes. Pre-conditioning of the oil sample through filters is not occurring. The diesel generator transfer pump suction piping y-strainers include screens with 0.062 inches perforations which are installed to protect the pump from large foreign materials as the pump is required for diesel generator operability. The fuel oil analysis procedure utilizes a filter pore size of 3

May 2, 2019 Enclosure A Page 30 of 82 microns or 0.0001181102 inches to collect particulate which then gets dried and weighed. The analysis is concerned with particulate on a much smaller scale (525 times smaller) than the y-strainer screen perforations.

2. The pump intake level of 4 inches is not intended to be a bottom sample rather, it is a representative sample from the lowest accessible point in the tank. As described in response to Question 1 above, the PBAPS sample location and methodology is effective for the determination of contaminants, water, and sediment in fuel oil, and is more conservative than the "multilevel" sample methods described in ASTM 04057.

No updates to the SLRA are required as a result of this response.

May 2, 2019 Enclosure A Page 31 of 82

6.

SLRA Sections B.2.1.39, B.2.1.40, and B.2.1.41 Electrical Insulation for Inaccessible Medium-Voltage Power Cables Not Subject to Title 10, Code of Federal Regulations (CFR) 50.49 Environmental Qualification Requirements, Electrical Insulation for Inaccessible Instrumentation and Control Cables Not Subject to 1 O CFR 50.49 Environmental Qualification Requirements, Electrical Insulation for Inaccessible Low-Voltage Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Regulatory Basis: Section 54.21 (a)(1) of 1 O CFR requires the applicant to identify and list those structures and components subject to an aging management review. Section 54.21 (a)(3) of 10 CFR requires the applicant to demonstrate that the effects of aging for structures and components within the scope of license renewal and subject to an AMR pursuant to 10 CFR 54.21 (a)(1) will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the subsequent period of extended operation. As described in SRPSLR, an applicant may demonstrate compliance with 10 CFR 54.21 (a)(3) by referencing the GALL-SLR Report, and when evaluation of the matter in the GALL-SLR Report applies to the plant. SAP-SLR Section 3.6.3.4 states that if the applicant identifies, in the SLRA AMP, an exception to any of the program elements of the GALL-SLR Report AMP, the reviewer is to confirm that the SLRA AMP with the exception will satisfy the criteria of 1 O CFR 54.21 (a)(3). RAI B.2.1.39-1, B.2.1.40*1, B.2.1.41*1

Background:

SLRA Sections B.2.1.39, B.2.1.40, and B.2.1.41 describe electrical insulation for inaccessible medium-voltage, instrumentation and control, and low-voltage power cables not subject to 1 O CFR 50.49 environmental qualification requirements AMPs as consistent with GALL-SLR Xl.E3A, Xl.E3B, and Xl.E3C with exceptions. The "preventive actions" element of the GALL-SLR Report AMPs Xl.E3A, Xl.E3B, and Xl.E3C states in part "... The inspection frequency for water accumulation in manholes/vaults is established and performed based on plant-specific OE with cable wetting or submergence. The periodic inspections occur at least once annually." This element also states in part"... Inspection for water accumulation are also performed after event-driven occurrences, such as heavy rain, rapid thawing of ice and snow, or flooding." Exelon proposed exceptions to "preventive actions" program element as follows: Manholes with level monitoring and alarms that result in consistent, subsequent pump out of accumulated water prior to wetting or submergence of cables, will be inspected at least once every five years, as supported by plant operating experience. Manholes with level monitoring and alarms that result in consistent, subsequent pump out of accumulated water prior to wetting or submergence of cables, will be inspected following event-driven occurrences such as heavy rain, rapid thawing of ice and snow, or flooding, when level monitoring indicates water is accumulating.

May 2, 2019 Enclosure A Page 32 of 82

1.

It is not clear to the NRC staff that reliance on level monitoring system to inspect water accumulation every 5 years will prevent inaccessible cables from significant moisture.

2.

Exelon did not address industry operating experience with the installed level monitoring system. Request:

1.

Describe the level monitoring systems and provide industry operating experience with these systems.

2.

If inspections are carried out every 5 years due to reliance on the level monitoring system, describe how the level monitoring systems are monitored for proper functioning and reliability Exelon Response: Item 1: The level monitoring system is a SmartCover system. It consists of ultrasonic water level sensors; antennas that transmit information to a satellite; a receiver that downloads the information to a digital network for processing data, storing data, and initiating alarms; and a web page for the site to receive alarm conditions, view data, and make adjustments to system settings. The sensor, transmitter, and power pack are mounted on the underside of the lid of the manhole. The antenna is mounted on top of the lid of the manhole. The SmartCover system is used to continuously monitor for water accumulation in manholes. Routine monitoring for alarms is performed by Operations. If water is present and has reached the setpoint for alarm or a problem exists with a transmitter (i.e., power or communications) an issue is entered into the corrective action program. Maintenance performs follow-up actions to inspect the manhole, pump out any accumulated water, and initiate additional corrective actions, as needed. Industry and PBAPS operating experience, since 2011, was searched for the SmartCover manhole level monitoring operating experience. In addition to installations in nuclear power plant inaccessible cable manholes, SmartCover proactive monitoring equipment is installed in over 1300 water and wastewater systems, including Camp Pendleton Marine Base, and the cities of San Diego California, San Antonio Texas, Columbia South Carolina, and Ottawa Canada. Only one PBAPS issue for the manhole level monitoring system was found. The issue, a start-up issue, occurred when the level indicators were first installed at PBAPS. It is documented in the PBAPS corrective action program. No adverse PBAPS plant specific or industry operating experience for the SmartCover level monitoring equipment was found. Item 2: The level monitors are continuously self-diagnosing. The level monitors' condition, with respect to water level, power, and communication, is continuously available via the SmartCover system webpage. Alarm conditions and thereby the level monitors are monitored by Operations.

Features include: May 2, 2019 Enclosure A Page 33 of 82 A level monitoring system with ultrasonic sensors that detect the surface of accumulating water (there is no mechanical float). A monitoring webpage for the level transmitters that has a map of the Peach Bottom site, with a marker for each site manhole level monitor. The markers are displayed in a color that indicates the level transmitter's current status. Green is no alarm; blue is communication or power issue; and orange is a level alarm. Alarm conditions are routinely monitored by Operations. The level monitoring system is also monitored by the responsible engineer as part of good system engineering practices. Manholes will continue to be opened and inspected every 5-years, coincident with Structures Monitoring program inspections. The level transmitters' floatless design and continuous monitoring system, with alarms, are self-monitoring, and therefore do not require periodic preventive maintenance. No manhole level monitoring reliability issues were identified at PBAPS during the review of corrective action program issues. No updates to the SLRA are required as a result of this response.

7.

SLRA 4.3.6.3, Core Shroud Support Fatigue Analysis Reevaluation Regulatory Basis: May 2, 2019 Enclosure A Page 34 of 82 In accordance with 1 O CFR 54.21 (c)(1 ), a list of time-limited aging analyses, as defined in 1 O CFR 54.3, must be provided. The applicant shall demonstrate that: (i) The analyses remain. valid for the period of extended operation; (ii) The analyses have been projected to the end of the period of extended operation; or (iii) The effects of aging on the intended function(s) will be adequately managed for the period of extended operation. RAI 4.3.6.3-1

Background:

SLRA Section 4.3.6.3 addresses the reevaluation of the core shroud support fatigue analysis as a time-limited aging analysis (TLAA). In the section, the applicant indicated that the Fatigue Monitoring program is used to manage the aging effect associated with the fatigue analysis for the core shroud support through the subsequent period of extended operation in accordance with 10 CFR 54.21 (c)(1 )(iii). SLRA Section 4.3.6.3 also provides the following information: (1) as described in the first license renewal application of the applicant (July 2, 2001) the core shroud support fatigue analysis was reevaluated in 1998 to consider the effects of the recirculation pump start transient; and (2) the reevaluation described in the first license renewal application conservatively computed a 40-year non-environmental cumulative usage factor (CUF) of 0.834 for the core shroud support. In its review related to the core shroud support fatigue analysis, the staff noted that the following reference discusses the CUF (non-environmental) for the core shroud support as part of the extended power uprate (EPU) project for the Peach Bottom Atomic Power Station (PBAPS): NEDC-33566P, Revision 0, "Peach Bottom Atomic Power Station Units 2 and 3 Constant Pressure Power Uprate," September 2012. Table 2.2-12 of the reference document indicates that the 60-year non-environmental CUF for the core shroud support is 0.26 under the EPU conditions. SLRA Section 4.3.6.3 and Table 4.3.1-3 (80-year CUF table) do not provide the projected 80-year CUF for the core shroud support in comparison with the existing CUF values for the component. Such comparison with the existing CUF calculations is needed to confirm that the 80-year CUF is a reasonable projection. In addition, the 40-year CUF (0.834) discussed in SLRA 4.3.6.3 is significantly greater than the 60-year CUF (0.26) in the EPU submittal. Request:

1. Please compare the projected 80-year CUF and CUFen (environmental CUF) values for the core shroud support with the 40-year CUF (0.834) in SLRA Section 4.3.6.3 and the 60-year CUF (0.26) in the 2012, EPU submittal. As part of the response, confirm that the 80-

May 2, 2019 Enclosure A Page 35 of 82 year CUF is a reasonable projection in comparison with the existing estimates of CUF values (40-year and 60-year). Exelon Response: The 2012 EPU license amendment submittal and SLRA Sections 4.3.1 and 4.3.6.3 document various design and projected CUF and CU Fen values, ranging from 0.17 to 0.834, for the core shroud support component. The primary driver for this range is the number of "Sudden Start of Pump in Cold Recirculation Loop" transient occurrences assumed in the calculation of these various values. This is because the number of "Sudden Start of Pump in Cold Recirculation Loop" transient occurrences contribute to approximately 80 percent of the total CUF or CUFen value for this component location. Below is a description and comparison between: 1) the design 40-year CUF (0.834) documented in SLRA Section 4.3.6.3; 2) the projected 80-year CUF value (0.2395) documented in SLRA basis reports; 3) the projected 80-year CU Fen value (0.726) documented in SLRA Table 4.3.1-3; and 4) the 40 and 60-year CUF values (0.17 and 0.26) documented in the 2012 EPU license amendment submittal. As described in SLRA Section 4.3.6.3 the 40-year design CUF value of 0.834 for the core shroud support component is based on the following assumptions: 130 occurrences of "Design Hydrostatic Test to 1,250 psig" (Table 4.3.1-1and4.3.1-2, transient 2); 216 occurrences of "Startup and Heatup (100°F/hr. max)" (Table 4.3.1-1 and 4.3.1-2, transient 3 and 3a); and 1 O occurrences of "Scram - Loss of Feedpumps - Isolation Valves Close" (Table 4.3.1-1 and 4.3.1-2, transient 11); 40 occurrences of "Sudden Start of Pump in Cold Recirculation Loop" (SLRA Tables 4.3.1-1 and 4.3.1-2 transient 18). The same core shroud support component location is monitored by the PBAPS Fatigue Monitoring program as documented on SLRA Table 4.3.1-3 as location 22, which documents an 80-year projected CUFen value of 0.726. The corresponding 80-year projected CUF value (not adjusted for environmental fatigue) for this same component is 0.2395. These projected values are based on the following 80-year transient projections: 55 occurrences of "Design Hydrostatic Test to 1,250 psig" (Table 4.3.1-1 transient 2); 190 occurrences of "Startup and Heatup (100°F/hr. max)" (Table 4.3.1-1transient3 and 3a); 12 occurrences of "Scram - Loss of Feedpumps - Isolation Valves Close" (Table 4.3.1-1 transient 11 ); and 1 O occurrences of "Sudden Start of Pump in Cold Recirculation Loop" (SLRA Table 4.3.1-1 transient 18) Comparison of the above occurrences shows that projected occurrences used for 80-year projected CUF value (0.2395) are less than the occurrences assumed in the fatigue analysis that resulted in a 40-year design CUF value of 0.834. The difference between the two

May 2, 2019 Enclosure A Page 36 of 82 CUF values (0.2395 and 0.834) is reasonable, especially when considering that the number of "Sudden Start of Pump in Cold Recirculation Loop" transient occurrences contribute to approximately 80 percent of the total CUF value for this component location. Also, the projected 80-year CUFen value (0.726) is consistent with the 80-year projected CUF value (0.2395) since the projected 80-year CUFen value is adjusted for environmental fatigue with an appropriate Fen multiplier, in accordance with the recommendations in NUREG/CR-6909, Revision 1. Therefore, the projected 80-year CUF value of 0.2395 and the projected 80-year CUFen value of 0.726 are reasonable in comparison with the 40-year design CUF value 0.834. The 60-year CUF value (0.26) in the EPU license amendment submittal was simply scaled from the 40-year value (0.17*1.5) which was calculated in the original core shroud support fatigue analysis developed by GE in the late 1960 and early 1970s. In this original fatigue analysis, GE did not assume the "Sudden Start of Pump in Cold Recirculation Loop" transient. Therefore, the projected 80-year CUF value of 0.2395 and projected 80-year CUFen value of 0.726 are reasonable in comparison with the 40 and 60-year CUF values of 0.17 and 0.26 reported in the EPU license amendment submittal, when considering that the calculation of the 40 and 60-year CUF values did not assume the "Sudden Start of Pump in Cold Recirculation Loop" transient. In 1998, PBAPS recognized that Unit 3 was experiencing a high rate of events in which an idle reactor recirculation loop with a temperature differential greater than 50°F of reactor coolant was placed in service. Based on this operating experience, an evaluation was performed by Structural Integrity Associates (SIA) to evaluate the impact of the actual occurrences on RPV fatigue analyses. As part of this effort, SIA reevaluated the core shroud support fatigue analysis and added 40 occurrences of the "Sudden Start of Pump in Cold Recirculation Loop" transient and determined a new design 40-year CUF value of 0.834. Since the 1998 SIA Core Shroud Support fatigue reevaluation is more conservative than the reported EPU license amendment CUF values, and reflects lessons learned from operating experience, this analysis became the basis for the "Core Shroud Support (LAS)" monitored component (location 22 on SLRA Table 4.3.1-3). This design 40-year CUF value (0.834) was documented in Section 4.3.2.1 of the first PBAPS LRA and is described in Section 4.3.6.3 of the SLRA. However, the 2012 EPU license amendment submittal, which was developed by GEH, continued to document the 40-year value of 0.17 and the 60-year value of 0.26. In conclusion, as described above and documented in SLRA Sections 4.3.1 and 4.3.6.3 the current projected 80-year CU Fen value for the core shroud support is 0.726. No updates to the SLRA are required as a result of this response.

RAI 4.3.6.3-2

Background:

May 2, 2019 Enclosure A Page 37 of 82 SLRA Section 4.3.6.3 indicates that the fatigue reevaluation performed in 1998 for the core shroud support considers the "sudden start of pump in cold recirculation loop" transient. In comparison, SLRA Table 4.3.1-1 addresses plant design transients for fatigue TLAAs, including another recirculation pump start transient, that is, "improper start of cold recirculation loop" transient. SLRA Section 4.3.6.3 indicates that the Fatigue Monitoring program will be used to monitor the plant transients in the aging management of fatigue cracking for the core shroud support. SLRA Section 4.3.6.3 does not clearly discuss whether the fatigue monitoring for the core shroud support includes the "improper start of cold recirculation loop" transient, which is another recirculation pump restart transient and may be similar to the "sudden start of pump in cold recirculation loop" transient. Request:

1. Please clarify whether the fatigue monitoring for the core shroud support includes the "improper start of cold recirculation loop" transient, which is another recirculation pump restart transient and may be similar to the "sudden start of pump in cold recirculation loop" transient. As part of the response, describe the differences between the two transients related to the recirculation pump start.

Exelon Response: The "Improper Start of Cold Recirculation Loop" transient is different from the "Sudden Start of Pump in Cold Recirculation Loop" transient. The original and reevaluated CLB core shroud support fatigue analyses do not assume the "Improper Start of Cold Recirculation Loop" transient. The "Improper Start of Cold Recirculation Loop" transient does not significantly impact core shroud support fatigue. Therefore, although the PBAPS Fatigue Monitoring program does monitor the "Improper Start of Cold Recirculation Loop" transient (SLRA Table 4.3.1-1and4.3.1-2 transient 17) for other components, such as SLRA Table 4.3.1 -3 location 7, the program does not monitor this transient for the core shroud support component (SLRA Table 4.3.1-3 location 22). Below is a description of the difference between the two transients. The transient definition of the "Sudden Start of Pump in Cold Recirculation Loop" is that with the reactor operating, a recirculation system loop is isolated and placed out of service and reactor coolant in the isolated idle recirculation loop cools down to 130°F. The transient definition then assumes that the isolated idle loop is not warmed up, the idle recirculation pump is started, and the loop motor operated valve is suddenly opened allowing flow into the recirculation pump discharge line. This causes the 130°F reactor coolant to flow through the recirculation pump discharge line, through the recirculation system manifold, through the jet pumps, directly into regions of the vessel below the jet pump diffuser/shroud support plate, and onto the core shroud

May 2, 2019 Enclosure A Page 38 of 82 support elements. Once the recirculation pump is placed in service the cold reactor coolant will quickly enter the jet pumps and impinge on the core shroud support elements located below the jet pump diffuser/shroud support plate. As a result, the core shroud support elements experience a rapid temperature transient which results in high stresses and potentially fatigue. The transient definition of the "Improper Start of Pump in a Cold Recirculation Loop" is that the reactor is operating with an isolated idle recirculation loop and the reactor coolant in the isolated loop has cooled down to 130°F. A transient is then assumed when the idle loop is improperly aligned to the reactor by suddenly opening the recirculation loop motor operated isolation valve. The idle recirculation pump remains out of service. This results in the second in-service recirculation pump to drive flow through the idle loop in the reverse direction into the reactor vessel. In this transient, the cold water from the idle loop is injected into the vessel via the recirculation pump suction line, RPV outlet nozzle, and into the downcomer above the jet pump diffuser/shroud support plate. The cold reactor coolant does not impinge on core shroud support elements below the jet pump diffuser/shroud support plate. The injection flow rate from the idle loop into the vessel is significantly less than the "Sudden Start of Pump in Cold Recirculation Loop" transient because total recirculation flow remains at approximately 50 percent, since only one recirculation pump is in service. In addition, the idle jet pumps create a flow bypass that significantly reduces cold reactor coolant injection flow rate from the idle loop. Therefore, the transient does not cause significant thermal stresses on the core shroud support elements located below the jet pump diffuser/shroud support plate and fatigue of the core shroud support elements is insignificant. No updates to the SLRA are required as a result of this response.

8.

GALL-SLR AMP Xl.M17, "Flow-Accelerated Corrosion Regulatory Basis: May 2, 2019 Enclosure A Page 39 of 82 10 CFR 54.21 (a)(3) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the subsequent period of extended operation. As provided in 1 O CFR 54.29(a), a renewed license may be issued if the staff finds that actions have been identified, which either have been or will be taken, with respect to managing the effects of aging during the subsequent period of extended operation. As described in SRP-SLR, an applicant may reference the GALL-SLR Report in an SLRA to designate which programs will be used and how those programs correspond to the AMPs in the GALL-SLR Report. If an applicant takes credit for a program in the GALL-SLR Report, it is incumbent on the applicant to ensure the conditions and operating experience at the plant are bounded by those for which the GALL-SLR Report program was evaluated. To complete its review and enable the formulation of a finding under 10 CFR 54.29(a), the staff requires additional information regarding the matters described below. RAI B.2.1.9-1

Background:

Peach Bottom SLRA Section B.2.1.9, Flow Accelerated Corrosion, states that the program is consistent with GALL-SLR AMP Xl.M17, "Flow-Accelerated Corrosion" program and that it relies on implementation of EPRl's NSAC-202L, Revision 4, "Recommendations for an Effective Flow-Accelerated Corrosion Program." GALL-SLR AMP Xl.M17 states the program includes the use of predictive software, such as CHECWORKS, that uses the implementation guidance of NSAC-202L. SLRA Section B.2.1.9 states that the program uses CHECWORKS to predict component wear rates and remaining service life. The Flow-Accelerated Corrosion program is implemented at all Exelon sites through the governing procedure ER-AA-430, "Conduct of Flow-Accelerated Corrosion Activities." During discussions with the staff, Exelon stated that an enhancement to its FAC program governing procedure, similar to what was documented during the staff's previous reviews for the Byron and Braidwood license renewal (Ref response to RAI B.2.1.8-2 (ML14135A179)), was not needed for the FAC program in Peach Bottom's subsequent license renewal. According to Exelon, the statement in the governing procedure: "Ultrasonic inspection data should be evaluated using an approved (i.e., validated and verified) software program," fulfills the enhancement from the Byron and Braidwood review: "to revise program procedures to require the documentation of the validation and verification of updated vendor supplied FAC program software." As discussed during the license renewal reviews for Byron and Braidwood, the software associated with the FAC program is categorized as Class DD, "Screened" in accordance with Exelon's IT-AA-101, "Digital Technology Software Quality Assurance (DTSQA) Procedure." According to the DTSQA, Class DD software requires minimal documentation and does not require validation and verification. In response to the staff's question for Byron and Braidwood,

May 2, 2019 Enclosure A Page 40 of 82 Exelon chose to enhance program procedures to address the validation and verification issue in lieu of changing the software classification through the DTSQA. The staff found Exelon's approach for the Byron and Braidwood review acceptable because the program procedures were to require documentation of the validation and verification for any updated versions of the FAG-related software prior to its use. Although the governing procedure states that the software is validated and verified, it is not clear to the staff how confirmation of this aspect will be implemented, because Class DD software does not require validation or verification in accordance with Exelon's DTSQA. In addition, there are no steps within ER-AA-430 to check if the software has been revised or to verify that the documentation of the software validation and verification is available for the current revision of the software. Consequently, it is unclear to the staff how the FAC program will ensure that the predictive software used to predict component wear rates will be consistent with the guidelines in NSAC-202L. Request: Provide information to show how the program will ensure that updated versions of any software used in the FAC program, which predicts component wear rates and remaining life, has been validated and verified prior to use to confirm that the predictions are done consistent with the guidelines in NSAC-202L. Exelon Response: The Exelon governing implementing procedure for the Flow-Accelerated Corrosion program, ER-AA-430, was recently revised to address software validation, verification, and documentation in response to RAI B.2.1.8-2 for Byron and Braidwood license renewal. The following paragraph was added: 4.9.3. Program Software Updates and Revision When program software (i.e., CHECWORKS and/or Fleet FAC Trending Software) is revised or replaced and the update has potential to affect the calculation of component wear, wear rate, remaining component life, and/or next scheduled inspection, a review will be performed to verify and validate that the software calculates these parameters consistently with NSAC-202L. The verification and validation shall be documented and stored electronically such that it is available for review. Limited or minor revisions or replacements of the software (such as end user enhancements, reporting revisions or additions, etc.) with no potential to affect these calculations (as verified by software change logs, vendor release notes, etc.) are exempt from this requirement and require no documentation. This paragraph will be annotated in ER-AA-430 as a commitment for Peach Bottom SLR. An enhancement and change to SLRA Appendix A, Section A.2.1.9 is not required since the governing implementing procedure now includes the requirement for software validation, verification, and documentation.

May 2, 2019 Enclosure A Page 41 of 82 SLRA Appendix 8, Section 8.2.1.9 is revised as shown in Enclosure 8 to address program software validation, verification, and documentation.

RAI B.2.1.9-2

Background:

May 2, 2019 Enclosure A Page 42 of 82 Peach Bottom SLRA Section B.2.1.9, Flow Accelerated Corrosion, states that the program is consistent with GALL-SLR AMP Xl.M17, "Flow-Accelerated Corrosion" program and that it relies on implementation of EPRl's NSAC-202L, Revision 4, "Recommendations for an Effective Flow-Accelerated Corrosion Program." GALL-SLR AMP Xl.M17 states the program includes the development of FAC predictive models to reflect component geometries, materials, and operating parameters. NSAC-202L, Section 3.3, "Other Documentation" recommends, in part, that the predictive plant model and all revisions be documented and independently checked by a qualified individual. Exelon corrective action document AR02573389 addresses industry-operating experience from Davis-Besse (see LEA 346/2015-002, "Improper Flow Accelerated Corrosion Model Results in 4-lnch Steam Line Failure and Manual Reactor Trip") regarding CHECWORKS modeling discrepancies that resulted in a failure of an elbow. Exelon's associated operating experience review (AR02530386-09) found flow orifice size discrepancies in several FAC predictive models, but unlike Davis-Besse, the discrepancies were conservative because the orifice diameters were modeled as a smaller size resulting in higher velocities than actual. In answering the question 'Why the condition happened," the AR states "Legacy issues with CHECWORKS modeling." More recently, industry-operating experience from Indian Point (see LEA 286/2018-003, "Manual Reactor Trip Due to a Steam Leak on a High-Pressure Feedwater Heater} discussed weaknesses in the initial setup of the CHECWORKS model for the affected system. During follow-up discussions with the staff, Exelon stated its operating experience reviews in AR02530386-09 had only looked at orifice diameter modeling. Exelon added that it had previously performed a comprehensive update of CHECWORKS models in 2012 to support the extended power uprate, and had identified errors in CHECWORKS modeling where several elbows had been modeled as tees. The modeling errors were corrected to reflect the actual geometries; however, Exelon clarified that only those models affected by the extended power uprate were reviewed as part of the comprehensive update in 2012. Industry operating experience shows that legacy errors in CHECWORKS models have resulted in FAC program failures. Although Exelon's FAC program ensures that changes made to CHECWORKS models are performed by and independently reviewed and verified by qualified FAC engineers, it appears that the accuracy of the initial models has not been verified in all cases. Based on the identification of legacy modeling errors during selected reviews of some Peach Bottom FAC models, it is not clear to the staff whether the FAC program will continue to provide reasonable assurance that structural integrity will be maintained between inspections. Request: Based on the identification of legacy modeling errors during selected reviews of some Peach Bottom FAC models, provide information about the need for additional verification activities of FAC model parameters that have not been previously independently checked.

Exelon Response: May 2, 2019 Enclosure A Page 43 of 82 The following verification activities of FAC modeling parameters have occurred since 1995 when the analytical models transitioned from CHECMATE to CHECKWORKS.

1. The CHECWORKS models at Peach Bottom were created in 1995 when the FAC program transitioned from CHECMATE to CHECWORKS. Calculation PM-0974, "CHECWORKS Wear Rate Analysis for PBAPS 2 & 3" documents the methodology and inputs used to create the CHECWORKS models from the CHECMATE modeled piping previously analyzed and documented in CHECMATE calculations. All the CHECMATE models documented in the CHECMATE calcs were loaded into CHECKWORKS. The models were validated and modified where needed for piping configuration, material, and geometry codes based on plant drawings (e.g., piping layout drawings and P&IDs) and FAC program isometrics.

2. The CHECWORKS models are maintained on an ongoing basis by the FAC program engineer in accordance with station procedures.

As a pre-inspection activity, the FAC program engineer is required to review the CHECWORKS model for changes in plant operation, configuration, or other factors that affect FAC to determine if changes have occurred since the CHECWORKS model was last updated. If changes are identified, the model is revised to reflect that change. As a post-inspection activity, the FAC program engineer ensures that the CHECWORKS model is updated using ultrasonic inspection data from the outage, before the next set of inspection locations are identified. This update includes revising the model to account for any design changes, replacements, or other configuration changes that have occurred since the model was last updated. Each individual change made to the CHECWORKS model is done by a qualified FAC Engineer. Each change is documented in such a manner that the person making the change and the date that the change is made is clearly identified. Each change is then independently reviewed and validated by a qualified FAC Engineer. Potential impacts to the CHECWORKS models are screened through the design change process. Changes in piping configuration, materials, or system hydraulic requirements are reviewed by the FAC program engineer to determine if there are FAC or piping erosion concerns.

3. The RAI Background discussion refers to several instances where legacy errors in the CHECKWORKS models were identified. These are addressed as follows:

During the Peach Bottom review of the Davis-Besse industry-operating experience, several errors were identified in flow element modeling in both the Unit 2 and Unit 3 CHECWORKS models. Feedwater pump discharge flow elements for Unit 3 were modelled incorrectly (Unit 2 modeling was correct). Also, flow element sizing for Unit 2 and Unit 3 feedwater heater drains was incorrect in the CHECWORKS models. The throat size for these flow elements was documented as 6 inches in the models but design drawings identified the throat diameter as 8.289 inches. It is noted that the feedwater heater drains are not in scope for SLR.

May 2, 2019 Enclosure A Page 44 of 82 The CHECWORKS models were revised and independently reviewed and validated accordingly. The impact to the FAC program as a result of these discrepancies was considered minor. The piping directly downstream of the feed pump discharge flow elements had been recently inspected for both Unit 2 and Unit 3 and all inspection results were satisfactory. Changing the throat size of the feedwater heater drain flow elements from 6 inches to 8.289 inches resulted in a reduction of localized wear rates. The CHECWORKS models were revised and independently reviewed and validated in 2011 as part of Extended Power Uprate (EPU). Calculation PEAM-EPU-81, "FAC Program Extended Power Uprate Report was issued to provide changes to the model for the thermodynamic conditions associated with EPU conditions as well as to quantify the relative changes in FAC wear rates post EPU conditions. During development of the revised models, a spot check was performed, and it identified several instances where elbows were modeled as tees. Tees and elbows are of different geometry and are coded with different wear factors in the CHECWORKS models, which creates inaccuracies in the predicted wear rates for those respective components. The model was updated to reflect the correct geometries as a result of this finding. The impact to the FAC program as a result of these discrepancies was considered minor and conservative since CHECWORKS would predict more wear on a tee. In conclusion, although there have been legacy modeling errors as discussed above in the initial CHECWORKS analytical models developed in 1995, these errors did not represent significant FAC issues, and, a review of FAC program OE from the past 1 O years did not identify any instance of loss of system or component intended function due to legacy modeling errors in CHECWORKS. Current processes and procedures ensure the CHECWORKS models are maintained on an ongoing basis by the FAC program engineer. Therefore, additional verification activities of FAC model parameters within the PBAPS Unit 2 and Unit 3 CHECWORKS models is not required. No updates to the SLRA are required as a result of this response.

9.

GALL-SLR Report AMP Xl.M33, "Selective Leaching" Regulatory Basis: May 2, 2019 Enclosure A Page 45 of 82 10 CFR 54.21 (a)(3) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. One of the findings that the staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 1 O CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 10 CFR 54.29(a), the staff requires additional information in regard to the matters described below. RAI B.2.1.22-1

Background:

SLRA Section B.2.1.22, "Selective Leaching," states that the program will be consistent with the ten elements of aging management program GALL-SLR Report AMP Xl.M33, "Selective Leaching." GALL-SLR Report AMP Xl.M33 recommends (a) using visual inspections, mechanical examinations, and destructive examinations to detect selective leaching; and (b) that the program includes a process to evaluate difficult-to-access surfaces (e.g., heat exchanger shell interiors, exterior of heat exchanger tubes) if unacceptable inspection findings occur within the same material and environment population. During the audit, the staff noted that for expanded inspections on difficult-to-access surfaces, such as heat exchanger tubes, industry proven technologies found capable of detecting degradation may be used as an initial indicator of the existence of imperfections. The staff also noted that if imperfections are identified, then direct visual inspection or destructive examination should be performed to fully assess the material condition. Uhlig's Corrosion Handbook, 3rd Edition, page 148, states "[i]nspection for dealloying has been very difficult because this form of corrosion usually leaves a surface profile similar to uncorroded metal. The only way of finding dealloying has been by visual inspection for color changes or by mechanical probing to identify a loss of integrity. Several researchers have reported on attempts to develop methods of in situ nondestructive inspection for dealloying, but they have not achieved widespread acceptance." Issue:

1. It is unclear to the staff which industry proven technologies will be used to screen for the existence of selective leaching on difficult-to-access surfaces.

2. Based on the staff's review of Uhlig's Corrosion Handbook and GALL-SLR Report AMP Xl.M33, which recommend visual and mechanical examination techniques to detect selective leaching, it is unclear to the staff if industry proven technologies will be

May 2, 2019 Enclosure A Page 46 of 82 capable of screening for the existence of selective leaching on difficult-to-access surfaces. Request:

1. State which industry proven technologies will be used to screen for the existence of selective leaching on difficult-to-access surfaces.

2. State the basis for how these industry proven technologies will be capable of screening for the existence of selective leaching on difficult-to-access surfaces.

References:

Revie, R. Winston. (2011 ). Uhlig's Corrosion Handbook (3rd Edition) - References. John Wiley & Sons. Retrieved from https://app.knovel.com/hotlink/pdf/id:kt008TZBV1 /uhlig-s-corrosion-handbook/uhliq-s-co-references-2 Exelon Response: EPRI is currently conducting research and testing to assist the industry in various aspects of conducting selective leaching programs. Their work includes assessment of different NDE techniques to identify and quantify selective leaching. Exelon's plan regarding use of industry proven technologies was intended to provide the flexibility to take advantage of the results of this EPRI research when it becomes available. Since this EPRI work is ongoing and has not yielded conclusive results to date, industry proven technologies will not be used to screen for the existence of selective leaching on difficult-to-access surfaces. If it is necessary to conduct inspections on difficult-to-access surfaces due to unacceptable inspection findings occurring within the same material and environment, the implementing documents for this new program will provide the necessary steps to make these surfaces accessible so that direct visual inspections can be performed or so that they can be removed for destructive testing to detect selective leaching. SLRA Appendix B, Section B.2.1.22 is revised as shown in Enclosure B.

May 2, 2019 Enclosure A Page 47 of 82

10.

SLRA Section 3.5.2.2.2.4 Loss of Material and Cracking Due to Stress Corrosion Cracking (SCC) For Aluminum and Stainless-Steel Support Members, Welds, Bolted Connections and Support Anchorage to Building Structure Regulatory Basis: 1 O CFR § 54.21 (a)(3) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. RAI 3.5.2.2.2.4-1

Background:

SRP-SLR Table 3.5-1 item 099, recommends that Class 1, Class 2, Class 3, and Class MC aluminum and stainless steel support members, welds, bolted connections and support anchorage to building structures be managed for loss of material and cracking due to stress corrosion cracking (SCC) by either the AMP Xl.M32, "One Time Inspection," AMP Xl.S3, "ASME Section XI, Subsection IWF," or AMP Xl.M36, "External Surfaces Monitoring of Mechanical Components" program. SRP-SLR Table 3.5-1 item 100, also recommends that other aluminum and stainless steel support members, welds, bolted connections and support anchorage to building structures be managed for the same aging effects by either the AMP Xl.M32, "One Time Inspection;" AMP XI.SS, "Structures Monitoring," or AMP Xl.M36, "External Surfaces Monitoring of Mechanical Components" program. These Table 1 line items are associated with a further evaluation, SRP-SLR Section 3.5.2.2.2.4, which describes the acceptance criteria, and recommends actions (including AMP enhancements) to address these aging effects when loss of material or cracking has occurred and is sufficient to potentially affect the intended function of these components. SLRA Table 3.5.1, items 99 and 100, state that the One-Time Inspection Program will be used to addresses the aging effect of cracking (due to SCC) and loss of material for these components. SLRA Section 3.5.2.2.2.4 further states that visual inspections conducted in accordance with the One-Time Inspection Program will be performed to confirm that loss of material due to pitting and crevice corrosion or cracking due to sec are not occurring at a rate that affects the intended function of the components. The staff notes that NUREG-2221, Technical Bases for Changes in the Subsequent License Renewal Guidance Documents NUREG-2191 and NUREG-2192," finds the use of visual inspection for these AMR line items, as acceptable when performing periodic inspections to manage the aging effects, and when it can easily be demonstrated that, for these type of structural supports, minor loss of material or cracking that might not be visually detectable during a walkdown inspection will likely not impact the intended function of the support. Issue: Since cracking due to SCC cannot be reliably identified through visual examination, the proposed visual inspection under the One-Time Inspection Program is not sufficient to detect cracking due to SCC in stainless steel and/or aluminum components associated with SLRA Table 3.5.1 items 99 and 100. The staff notes that a method that has been determined to be capable of detecting cracking due to SCC must be used to confirm that this aging effect is not

May 2, 2019 Enclosure A Page 48 of 82 occurring or that is occurring at a rate that affects the intended function of the components during for the subsequent period of extended operations. Request: Provide adequate technical justification to demonstrate that the proposed inspection method will be capable of detecting cracking due to SCC, and that it will be sufficient to adequately demonstrate that the aging effect is not occurring or is not occurring at a rate that affects the intended function of the components. Also clarify what type of visual inspections will be used and if supplemental examination will be performed during the One-Time Inspection. Exelon Response: At PBAPS, reviews of plant specific OE have not identified a loss of intended function due to cracking in aluminum or stainless steel structural components in air environments. Structural components are currently periodically inspected under the structural aging management programs, regardless of the materials or postulated aging effects. This RAI identified concerns regarding the ability of visual inspections to identify cracking due to sec under a One-Time Inspection program, with the potential for the components to not be inspected after the One-Time Inspection program implementation. As a result, aluminum and stainless steel structural components, in air environments, currently aligned to the One-Time Inspection program will be realigned to the other structural aging management programs that perform periodic visual inspections for managing cracking due to any mechanism. As a result of the OE reviews, the periodic visual inspections for cracking under these other structural aging management programs are considered adequate to prevent a loss of intended function. This realignment, of aluminum and stainless steel structural components in air environments currently aligned to the One-Time Inspection program, only affects components aligned to Table 3.5.1 Item Numbers 3.5.1-099 and 3.5.1-100. The changes in aging management of the affected components for these Table 3.5.1 Items are described below. SLRA Table 3.5.1 Item Number 3.5.1-099: The One-Time Inspection program will not be used to manage loss of material and cracking due to SCC in stainless steel structural components exposed to the environments of air-indoor uncontrolled or air-outdoor associated with SLRA Table 3.5.1 Item Number 3.5.1-099. There are no aluminum structural components that use Item Number 3.5.1-099. Although plant-specific OE does not reveal a history of pitting or crevice corrosion or cracking of stainless steel structural components in these environments, the inspection of these components is realigned from the One-Time Inspection program to programs which perform periodic visual inspections for the detection of loss of material and cracking as follows. Supports for ASME Class 1 piping and components and supports for ASME Class 2 and 3 piping and components in SLRA Table 3.5.2-4, Component Supports, are realigned from the One-Time Inspection program to the ASME Section XI, Subsection IWF program. The technical justification as requested above is that the ASME Section XI, Subsection IWF program includes periodic visual inspection (VT-3) for ASME Class 1, 2, and 3 component supports and integral attachments for loss of material and cracking. VT-3 inspections and examination criteria are in accordance with IWF-2500 requirements.

SLRA Table 3.5.2-4, Component Supports, is revised accordingly. May 2, 2019 Enclosure A Page 49 of 82 Containment closure bolting in SLRA Table 3.5.2-5, Containment Structure, is realigned from the One-Time Inspection program to the ASME Section XI, Subsection IWE and 10 CFR Part 50, Appendix J programs (SLRA Table 3.5.1 Item Numbers 3.5.1-01 O and 3.5.1-037). The technical justification as requested above is that: o The ASME Section XI, Subsection IWE program includes periodic visual inspection (VT-3) of pressure-retaining bolting for material conditions that cause the bolted connection to affect either containment leak tightness or structural integrity. Bolting exhibiting degradation is subjected to additional examinations using visual (VT-1). o The 1 O CFR Part 50, Appendix J program does not include visual inspections but provides measures for performance monitoring to detect degradation in the primary containment pressure boundary, including containment closure bolting. SLRA Table 3.5.2-5, Containment Structure, is revised accordingly. SLRA Table 3.5.1 Item Number 3.5.1-100: With the exception of the stainless steel Containment Structure refueling bellows assemblies and the stainless steel and aluminum thermal insulation and thermal insulation jacketing which remain in the One-Time Inspection program as discussed below, the One-Time Inspection program will not be used to manage loss of material and cracking due to sec in stainless steel and aluminum structural components exposed to the environments of air-indoor uncontrolled or air-outdoor associated with SLRA Table 3.5.1 Item Number 3.5.1-100. Although plant-specific OE does not reveal a history of pitting or crevice corrosion or cracking of aluminum or stainless steel structural components in these environments, the inspection of these components is realigned from the One-Time Inspection program to the Structures Monitoring program. The technical justification as requested above is that the Structures Monitoring program is implemented by procedures that include periodic visual inspections by personnel qualified to monitor structures and components for applicable aging effects, such as loss of material and cracking. Accordingly, the following SLRA Tables are revised to realign these structural components from the One-Time Inspection program to the Structures Monitoring program. 3.5.2-3 Circulating Water Pump Structure 3.5.2-4 Component Supports 3.5.2-8 Electrical and Instrumentation Enclosures and Raceways 3.5.2-10 Hazard Barriers and Elastomers 3.5.2-12 Miscellaneous Steel 3.5.2-14 Outdoor Electric Switchgear, North Substation 3.5.2-15 Radwaste Building and Reactor Auxiliary Bay 3.5.2-16 Reactor Building 3.5.2-17 Recombiner Building 3.5.2-18 Stack 3.5.2-19 Station Blackout Structure and Foundations 3.5.2-20 Turbine Building and Main Control Room Complex The stainless steel refueling bellows assemblies in SLRA Table 3.5.2-5, Containment Structure, and the stainless steel and aluminum thermal insulation and thermal insulation jacketing in

May 2, 2019 Enclosure A Page 50 of 82 SLRA Table 3.5.2-11, Insulation, will remain in the One-Time Inspection program and do not require supplemental examination under that program. The technical justification as requested above is that these components will be included in the populations of stainless steel and aluminum components subject to the inspection requirements established for the one-time inspection of mechanical components in GALL-SLR AMP Xl.M32, Table Xl.M32-1 (enhanced visual (e.g., EVT-1) or surface examination (magnetic particle, liquid penetrant) or volumetric examination (radiographic testing or UT)). One-time inspections performed in accordance with GALL-SLR AMP Xl.M32, Table Xl.M32-1 are sufficient to adequately demonstrate that the aging effect of cracking and loss of material is not occurring or is not occurring at a rate that affects the intended function of the components. It is noted that the structural bolting and cranes/hoists aligned to SLRA Table 3.5.1 Item Number 3.5.1-100 in SLRA Table 3.3.2-15, Fuel Handling System, remain unchanged and are managed by periodic inspections in the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems program. In conclusion, periodic visual inspections conducted by the ASME Section XI, Subsection IWF program, ASME Section XI, Subsection IWE program, and Structures Monitoring program, as described above, are adequate for the detection of cracking due to any mechanism in aluminum and stainless steel structural components prior to loss of intended function and is in accordance with the recommendations in NUREG-2221, Technical Bases for Changes in the Subsequent License Renewal Guidance Documents NUREG-2191 and NUREG-2192." SLRA Sections 3.5.2.2.1.6, 3.5.2.2.2.4, Table 3.5.1 Items 3.5.1-010, 037, 099, and 100, Tables 3.5.2-3, 3.5.2-4, 3.5.2-5, 3.5.2-8, 3.5.2-10, 3.5.2-12, 3.5.2-14, 3.5.2-15, 3.5.2-16, 3.5.2-17' 3.5.2-18, 3.5.2-19, 3.5.2-20 are revised as shown in Enclosure B.

11.

GALL-SLR AMP Xl.M39, Lubricating Oil Analysis Regulatory Basis: May 2, 2019 Enclosure A Page 51 of 82 1 O CFR § 54.21 (a)(3) of 1 O CFR requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the subsequent period of extended operation. One of the findings that the staff must make to issue a renewed license (1 O CFR § 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under § 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis (CLB). As described in SRP-SLR, an applicant may demonstrate compliance with 1 O CFR 54.21 (a)(3) by referencing the GALL-SLR Report. In order to complete its review and enable making a finding under 1 O CFR § 54.29(a), the staff requires additional information in regard to the matters described below. RAI B.2.1.26-1

Background:

SRP-SLR Report Table 3.3-1, "Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report," items 3.3.1-99, and 3.3.1-100, recommends managing copper alloy, aluminum piping, stainless steel piping, and piping components exposed to lubricating oil for loss of material due to pitting, crevice corrosion, and microbiologically influenced corrosion (MIC) using GALL-SLR Report AMP Xl.M39, "Lubricating Oil Analysis," and AMP Xl.M32, "One-Time Inspection." SLRA Table 3.3.2-35, Turbine Building Closed Cooling Water System," states that copper alloy with 15% zinc or less, and stainless steel piping, piping components, and valve bodies exposed to lubricating oil will be managed for loss of material using GALL-SLR Report AMP Xl.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components." It is unclear how the GALL-SLR Report AMP Xl.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," program will be effective in managing the loss of material due to pitting, crevice corrosion, and MIC for copper alloy with 15% zinc or less, and stainless steel components in an environment of lubricating oil. The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is an inspection program that is based on a representative sample of 20 percent of the population (defined as components having the same material, environment, and aging effect combination) or a maximum of 25 components per population is inspected at each unit. The GALL-SLR Report AMP Xl.M39, "Lubricating Oil Analysis," program is a sampling program which maintains oil system (lubricating and hydraulic) contaminants (primarily water and particulates) within acceptable limits, thereby preserving an environment that is not conducive to loss of material. Additionally, the effectiveness of the Lubricating Oil Analysis program is verified by the use of GALL-SLR Report AMP Xl.M32, "One-Time Inspection." The One-Time Inspection program is

May 2, 2019 Enclosure A Page 52 of 82 an inspection based program with a representative sample size is 20 percent of the population or a maximum of 25 components at each unit. Request: State the basis for how the GALL-SLR Report AMP Xl.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," program will be effective in managing the loss of material due to pitting, crevice corrosion, MIC for the copper alloy with 15% zinc or less, and stainless steel components in an environment of lubricating oil. Exelon Response: SLRA Table 3.3.2-35, Turbine Building Closed Cooling Water System," identifies copper alloy with 15 percent zinc or less piping, piping components, and valve bodies exposed to lubricating oil. These components are associated with pressure sensing instruments on the radwaste air compressor lubrication subsystem. SLRA Table 3.3.2-35 also identifies stainless steel piping, piping components, and valve bodies exposed to lubricating oil. These components are associated with pressure sensing instruments on the condensate backwash air compressor lubrication subsystem. The lube oil for these compressors is not in the scope of the activities which are performed under the existing Lubricating Oil Analysis (B.2.1.26) aging management program. The lube oil is periodically replaced, but it is not analyzed and there are no oil quality limits to be monitored. Therefore, the preventive measures of the Lubricating Oil Analysis program would not be effective to manage aging of these components, and the One-Time Inspection program verification would not be relevant for the condition of these components. As a result, these lube oil subsystem components are being monitored under the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program for loss of material. The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components aging management program performs periodic inspections on a representative sample of 20 percent of each population (defined as components having the same material, environment, and aging effect combination) or a maximum of 25 components per population. The lube oil system components described above are the only components in the copper/lube oil and stainless steel/lube oil populations. Therefore, these components will be inspected periodically during the second period of extended operation and their condition will be assessed directly. The basis for why the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B.2.1.25) program will be effective in managing the loss of material for these copper alloy with 15 percent zinc or less, and stainless steel components in an environment of lubricating oil is that these components will be subject to periodic visual inspections under the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program. Therefore, the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is the appropriate aging management program to monitor the condition of these components. No updates to the SLRA are required as a result of this response.

May 2, 2019 Enclosure A Page 53 of 82

12.

Recurring Internal Corrosion, Cracking Due to SCC, and Various AMR Items Regulatory Basis: 1 O CFR 54.21 (a)(3) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. One of the findings that the staff must make to issue a renewed license (1 O CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the subsequent period of extended operation on the functionality of structures and components that have been identified to require review under 10CFR54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 1 O CFR 54.2~(a), the staff requires additional information in regard to the matters described below. RAI 3.3.2.2.7-1

Background:

Consistent with the "operating experience" program elements of GALL AMP Xl.M20, "Open Cycle Cooling Water System," and Xl.M27, "Fire Water System," the potential for loss of material due to recurring internal corrosion was evaluated in accordance with SAP SLR Section 3.3.2.2.7. Section 3.3.2.2.7 recommends that a basis be provided for the adequacy of augmented inspections (e.g., periodicity, quantity) if loss of material due to recurring internal corrosion is an applicable aging effect. SLRA Section 3.3.2.2. 7 states that loss of material due to recurring internal corrosion is an applicable aging effect for the open cycle cooling water and fire water systems. SLRA Section 3.3.2.2. 7 states that:

a. The Open-Cycle Cooling Water System program will be used to manage recurring internal corrosion (RIC) in the emergency service water system, high pressure service water system, and service water system. The program utilizes quantitative volumetric examination methods for the detection of aging effects. Screening methods (e.g.,

guided wave) are used to screen for locations that are followed up using conventional nondestructive examination techniques. The program includes methodology for choosing piping inspection locations based on the risk associated with specific pipe locations balanced by other factors to investigate and address potential piping integrity concerns. The risk is determined by the combination of piping corrosion susceptibility and the consequences of pipe leaks or other integrity issues. The size of the inspection scope may include: inspections required for extent of condition, inspections required based on the risk factor, re-inspection locations based on the next scheduled inspection calculations, new inspection locations based on operating experience, and follow-up inspections on repairs. From 2013 through 2017, 150 raw water inspections were performed, for an average of 30 per year.

May 2, 2019 Enclosure A Page 54 of 82 The program includes guidance for the determination of the next scheduled inspection, which is the calculated time frame at which an inspection will be performed based on current measured corrosion rate trending. The program will require no fewer than five additional inspections for each inspection that did not meet acceptance criteria, or 20 percent of each applicable material, environment, and aging effect combination, whichever is less.

b. The Fire Water System program will be used to manage RIC in the fire water system. Periodic ultrasonic inspections were established when RIC was identified to trend pipe wall thickness. The ultrasonic inspections provide representative data for fire water system pipe wall thickness trending and indicates the type of corrosion occurring, which is localized microbiologically influenced corrosion (MIC).

Plant specific operating experience demonstrates that the currently performed flow testing and ultrasonic testing have provided sufficient data for trending fire water system pipe wall conditions prior to loss of intended function. Degraded pipe due to corrosion has been evaluated and replaced when necessary prior to loss of intended function. Additional augmented testing to detect RIC is not required. Engineering evaluations are performed when degraded conditions are identified in order to determine the cause. When corrosion is identified as the cause of the degraded condition, the frequency of inspections is based on the projected corrosion rate, extent of condition for other areas in the system, and necessary repairs if required. The SLRA lacks sufficient detail for the staff to conclude that RIC will be adequately managed during the subsequent period of extended operation. Specifically:

a. For the Open-Cycle Cooling Water System program, although 150 inspections have been conducted between 2014 and 2017, the SLRA does not state a minimum number of inspections that will occur in a set periodicity or the extent of piping that will be examined by screening techniques. Past performance is not reflective of the minimum number of inspections that will occur in the future.

b. For the Fire Water System program, although flushes and flow tests can demonstrate that portions of the system are capable of meeting their intended pressure boundary function at the time of the evolution, they do not provide data that can be trended in regard to the extent of and wall loss associated with MIC. The Fire Water System program lacks sufficient detail on the minimum number of inspections, how inspection locations will be selected, the periodicity of inspections, and the criteria used to expand the scope of inspections when inspection results do not meet acceptance criteria.

c. Both programs cite evaluations being conducted to determine the need for future inspections. During its review of plant-specific documents, the staff noted that the raw water corrosion program guide procedure allows a default to use nominal wall thickness when previous wall thick examinations have not been conducted at the piping location or

May 2, 2019 Enclosure A Page 55 of 82 other applicable locations. The procedure suggests conservatism that can be used (e.g., adding 12.5 percent to the nominal wall thickness), but does not require the use of conservative factors. The SLRA does not state a basis for why the use of nominal wall thickness will provide appropriate reinspection intervals. Request:

a. For the Open-Cycle Cooling Water System program, state the minimum number of inspections that will occur and periodicity of inspections and their basis.

b. For the Fire Water System program, state: (a) the minimum number of inspections; (b) the periodicity of inspections; (c) how inspection locations will be selected; and (d) the criteria used to expand the scope of inspections when inspection results do not meet acceptance criteria and their basis.

c. For both programs, state the basis for why the use of nominal wall thickness will provide appropriate reinspection intervals.

Exelon Response:

a. The risk-based methodology for the determination of inspection locations as described in SLRA Section 3.3.2.2.7 does not provide for a minimum number of inspections. The Open-Cycle Cooling Water System program will be enhanced (Commitment 11, Item #2) to perform a minimum of 20 inspections for recurring internal corrosion in the raw water cooling water systems every 24 months until the rate of recurring internal corrosion occurrences no longer meets the criteria for recurring internal corrosion as defined in SLRA Section 3.3.2.2. 7. The selected inspection locations will be periodically reviewed to validate their relevance and usefulness and adjusted as appropriate. Evaluation of the inspection results will include (1) a comparison to the nominal wall thickness or previous wall thickness measurements to determine rate of corrosion degradation; (2) a comparison to the design minimum allowable wall thickness to determine the acceptability of the component for continued use; and (3) a determination of reinspection interval.

b. A minimum of seven (7) periodic ultrasonic pipe wall inspections on fire water supply piping are performed to trend pipe wall thickness in high flow areas susceptible to RIC such as horizontal runs, vertical runs, elbows, pipe welds, and piping used for frequent flow testing. Test locations include fire water supply piping throughout the plant to identify any new local corrosion issues and trend historical corrosion. The ultrasonic inspections provide representative data points for fire water system pipe wall thickness trending so that corrosion rates can be determined, and corrective actions can be taken if required prior to the loss of system intended function.

The ultrasonic inspection periodicities were determined based on initial test results. At each location, an engineering evaluation was performed using the as-found pipe wall thickness to determine a corrosion rate, a minimum pipe wall value, and an initial test periodicity. Changes to inspection periodicities are based on subsequent test results, degradation found, engineering evaluation, and pipe replacements. The minimum fire

May 2, 2019 Enclosure A Page 56 of 82 water supply piping inspection locations, periodicities, and descriptions are shown below. Location Freguenc~ Description (Years) OPS-2-VS1-2" 3 FWS make up {High Pressure Lube Water) supply line, 2" vertical pipe. Turbine Bldg. centerline FWS main 2TB-1 OVW2-1 O" 6 supply line and underground supply connection, 10" Tee weld. Motor Driven Fire Pump discharge OPS-12VW1-12" 7 12" vertical elbow weld and supply to underoround loop. Underground loop X-tie to plant ORW-6HS3-6" 7 distribution through Rad Waste Bldo., 6" horizontal pipe. OPS-12VS 1-12" 8 Motor Driven Fire Pump supply to underoround loop, 12" vertical pipe. Diesel Driven Fire Pump discharge OPS-12VW3-12" 8 12" vertical pipe weld and supply to underaround loop. Diesel Driven Fire Pump discharge OPS-12HS2-12" 9 12" horizontal pipe and supply to underoround loop. When inspection results do not meet the acceptance criteria, the corrective action program is used to determine the extent of condition, extent of additional inspections {i.e., expanded scope), and impact to test periodicity in accordance with the raw water corrosion program. The Fire Water System aging management program will be enhanced {Commitment 17, Item #17) to perform at least five additional ultrasonic test inspections on fire water supply piping for each Fire Water System pipe wall inspection that does not meet acceptance criteria. The combination of flow tests and ultrasonic pipe wall inspections is utilized to detect RIC prior to loss of intended function.

c. When previous pipe wall thickness measurements are not available for the determination of a corrosion rate, a corrosion rate that has been calculated from other locations with nearly identical operating conditions, material, pipe size, and configuration may be used to determine re-inspection intervals. This corrosion rate assignment must be documented in an Engineering Evaluation to document the location{s) used, basis for correlation, and final corrosion rate assigned. If corrosion rates from other locations are not applicable, then the raw water piping integrity management guide procedure states to use the original installed thickness or tnom for the determination of corrosion rate. It further states that stations may consider using mill tolerance of 12.5 percent for added conservatism when establishing an initial wall thickness value. The raw water piping integrity management guide procedure, which provides direction for the determination of corrosion rates for the Open-Cycle Cooling Water System program {Commitment 11, Item #3} and Fire Water System program {Commitment 17, Item #18), will be enhanced

May 2, 2019 Enclosure A Page 57 of 82 to provide procedural direction to require the use of a mill tolerance of 12.5 percent for added conservatism when determining corrosion rates at new inspection locations if corrosion rates at other locations with nearly identical operating conditions, material, pipe size, and configuration cannot be used. SLRA Appendix A, Sections A.2.1.11 and A.2.1.17, and Appendix 8, Sections B.2.1.11 and B.2.1.17 are revised as shown in Enclosure B. SLRA Appendix A, Section A.5, Commitment 11 and Commitment 17 are also revised as shown in Enclosure C.

RAI 3.3.2.1.1-1

Background:

SLRA Tables 3.1.23, 3.2.22, 3.2.33, 3.2.24, 3.2.25, 3.2.26, 3.2.28, 3.3.21, May 2, 2019 Enclosure A Page 58 of 82 3.3.22, 3.3.23, 3.3.27, 3.3.29, 3.3.210, 3.3.211, 3.3.212, 3.3.214, 3.3.220, 3.3.221, 3.3.222, 3.3.224, 3.3.225, 3.3.228, 3.3.229, and 3.3.235 state that for copper alloy with greater than 15 percent zinc piping, piping components, heat exchanger components, heat exchanger tubes, spray nozzles, fire hydrant, and sprinklers exposed to air indoor uncontrolled, airdry, air outdoor, condensation, treated water, raw water, or waste water, there are either no aging effects requiring management or the aging management review (AMR) item cites loss of material. Various GALL SLR Report AMR items (e.g., A-473b, A473c, S455) state that cracking due to stress corrosion cracking (SCC) should be managed for copper alloy with greater than 15 percent components exposed to air, condensation, raw water, and waste water. NUREG-2221, Technical Bases for Changes in the Subsequent License Renewal Guidance Documents NUREG-2191 and NUREG-2192," states: The staff has concluded that copper alloy (> 15% Zn or >8% Al) exposed to closed-cycle cooling water, raw water, and waste water can be susceptible to cracking due to stress corrosion cracking. EPRI 1010639 states, "[t]he necessary chemical substance to cause sec in copper and copper alloys is ammonia or other ammonium compounds. These chemical substances are sometimes used in treated water systems to control the fluid pH or can be present because of an ammonium-based cleaning solvent. Ammonia can also be present in the atmosphere as a result of organic decay. In addition to ammonia or ammonium compounds, oxygen and moisture are also required to promote sec in the copper alloys while other contaminants such as carbon dioxide may act as catalysts to increase the rate of cracking." Likewise, for raw water and waste water, these deleterious compounds can be present. Based on a review of ASM Handbook, Volume 13B, "Corrosion: Materials, Corrosion of Copper and Copper Alloys," ASM International, 2006, pages 129-133, the staff concluded that copper alloy (> 15% Zn) is susceptible to cracking due to SCC in air or condensation environments depending on the presence of ammonia-based compounds. In addition to being present in the outdoor air environment, they could be conveyed to the surface of a copper alloy (> 15% Zn or >8% Al) component via leakage through the insulation from bolted connections (e.g., flange joints, valve packing). The staff noted that several Table 2 items include cracking as an aging effect in addition to other aging effects such as loss of material. However, there are many AMR items in the above cited Table 2s where cracking is not addressed. Request: State the basis for why cracking due to sec is not cited as an aging effect requiring management for copper alloy with greater than 15 percent zinc components exposed to air indoor uncontrolled, airdry, air outdoor, condensation, treated water, raw water, or waste water.

Exelon Response: May 2, 2019 Enclosure A Page 59 of 82 Cracking due to stress corrosion cracking (SCC) in copper alloy with greater than 15 percent zinc can occur if exposed to ammonia or ammonium compounds. Cracking is cited as an applicable aging effect in certain applications in the condensation and raw water environments as follows: Cracking of copper alloy with greater than 15 percent zinc has been assumed and is cited as an aging effect for insulated components in SLRA Table 3.3.2-4, Chilled Water System Summary of Aging Management Evaluation, and in SLRA Table 3.3.2-10, Domestic Water System Summary of Aging Management Evaluation. Because these insulated components are operated below the dew point, the external environment is identified as condensation. The insulation is assumed to contain contaminants that could leach out onto the copper alloy component due to moisture under the insulation. Cracking of copper alloy with greater than 15 percent zinc exposed to raw water (open-cycle cooling water) has been assumed and is cited as an aging effect in the Circulating Water Pump Structure (SLRA Table 3.5.2-3 Circulating Water Pump Structure Summary of Aging Management Evaluation), Emergency Cooling Water System (SLRA Table 3.3.2-11 Emergency Cooling Water System Summary of Aging Management Evaluation), Emergency Service Water System (SLRA Table 3.3.2-13 Emergency Service Water System Summary of Aging Management Evaluation), and Service Water System (SLRA Table 3.3.2-29 Service Water System Summary of Aging Management Evaluation). Chemicals used for macrobiological control in these raw water cooling systems and structures contain ammonia or ammonium compounds. Although the use of these chemicals is seasonal (3 times per year with each application lasting 3 to 4 days), cracking of copper alloy with greater than 15 percent zinc due to sec in these systems and structures exposed to raw water (open-cycle cooling water) is a conservative assumption. The basis for why cracking due to sec is not cited as an aging effect requiring management for copper alloy with greater than 15 percent zinc components in the environments of air - indoor, uncontrolled, air - outdoor, air - dry, treated water, waste water and certain applications in the condensation and raw water environments is as follows: Air-Indoor, Uncontrolled This environment is for indoor locations that are sheltered or protected from weather. Although chemicals containing ammonia or ammonium compounds may be stored onsite (e.g., chemicals used for macrobiological control) or at offsite facilities, spills are event driven and ammonia or ammonium compounds are not assumed to be present in indoor air for the determination of aging effects. A search of plant specific operating experience for the past 1 O years did not identify any instances of aging effects due to exposure to ammonia or ammonium compounds in the environment of air - indoor, uncontrolled. It is feasible that trace amounts of ammonia or ammonium compounds could exist in the air - indoor, uncontrolled environment due to (1) incidental leakage from the raw water cooling

May 2, 2019 Enclosure A Page 60 of 82 systems from packing, gaskets, seals, and a-rings, and, (2) incidental leakage from packing, gaskets, seals, and a-rings through insulation where the insulation contains contaminants. However, leakage from packing, gaskets, seals, and a-rings onto components is not required to be considered when determining aging effects requiring management. This is supported by NUREG-2221, Table 3-2 SAP-SLR Chapter 2, Scoping and Screening, Differences from SRP-LR, Revision 2 and Their Technical Bases. The technical basis provided for the change made to Table 2.1-3 to address managing leakage from packing, gaskets, seals, and a-rings is as follows: The staff concluded that it is acceptable to not manage loss of leak tightness due to degraded packing, gaskets, seals, and a-rings, for the pressure boundary and leakage boundary (spatial) intended functions in an aging management program based on the following: It is unlikely that leakage from packing, gaskets, seals or a-rings would result in failure of the system to deliver sufficient flow at adequate pressure. In regard to leakage, which could affect either the pressure boundary (containment leak boundary) or leakage boundary (spatial) intended functions, licensees routinely conduct tours of the operating spaces. When leakage is detected it is typically promptly entered into the corrective action program. The leakage is corrected by replacing the packing, gaskets, seals, and o-rings as consumables." Therefore, cracking due to sec is not cited as an aging effect requiring management for copper alloy with greater than 15 percent zinc components in the environment of air - indoor, uncontrolled. Air-Outdoor This environment includes atmospheric air exposed to weather and ambient temperatures and humidity (with a relative humidity up to 100 percent). Although chemicals containing ammonia or ammonium compounds may be stored onsite (e.g., chemicals used for macrobiological control) or at offsite facilities, spills are event driven and ammonia or ammonium compounds are not assumed to be present in outdoor air for the determination of aging effects. A search of plant specific operating experience for the past 10 years did not identify any instances of aging effects due to exposure to ammonia or ammonium compounds in the environment of air - outdoor. Therefore, cracking due to sec is not cited as an aging effect requiring management for copper alloy with greater than 15 percent zinc components in the environment of air - outdoor. Air-Dry This environment is used for ambient air which is drawn into a compressed air system which then is treated to reduce its dew point well below the system operating temperature and treated to control lubricant content, particulate matter, and other corrosive contaminants. Use of this term is only associated with internal air environments located downstream of the compressed air system air dryers and filters. Although chemicals containing ammonia or ammonium compounds may be stored onsite (e.g., chemicals used for macrobiological control) or at offsite facilities, spills are event driven and ammonia or ammonium compounds are not assumed to be present in dry air for the determination of aging effects. A search of plant specific operating experience for the past 1 O years did not identify any instances of aging effects due to exposure to ammonia or ammonium compounds in the environment of air - dry. Therefore, cracking due

May 2, 2019 Enclosure A Page 61 of 82 to SCC is not cited as an aging effect requiring management for copper alloy with greater than 15 percent zinc components in the environment of air - dry. Treated Water This environment is demineralized water or chemically purified water and is the base water for all clean systems. The treated water environment is managed by BWRVIP-190, with the exception of auxiliary boiler chemistry as discussed in the next paragraph. The copper alloy with greater than 15 percent zinc components in treated water are located in the Post Accident Sampling System, Process Sampling System, High Pressure Coolant Injection System, and Reactor Core Isolation Cooling System. The treated water in these systems is reactor grade water, condensate storage water, demineralized storage water, and torus water. These waters do not normally include ammonia or ammonium compounds. Water chemistry excursions that have the potential to produce ammonia are event driven (e.g., unexpected increase in zinc injection flow, resin intrusion event) and ammonia or ammonium compounds are not assumed to be present for the determination of aging effects. A search of plant specific operating experience for the past 1 O years did not identify any instances of aging effects due to exposure to ammonia or ammonium compounds in these treated water environments. The treated water environment also includes steam and feedwater associated with the auxiliary boilers. Chemistry parameters for the auxiliary steam system are monitored in accordance with industry standards, specifically ASME standard ISBN-0-7918-1204-9, Consensus on Operating Practices for the Control of Feedwater and Boiler Water Chemistry in Modern Industrial Boilers. Although ammonia or ammonium compounds can be used in auxiliary boilers as a boiler feedwater pH controlling chemical, Peach Bottom does not use boiler feedwater pH controlling chemicals. A search of plant specific operating experience for the past 10 years did not identify any instances of aging effects due to exposure to ammonia or ammonium compounds in the auxiliary steam environment. Therefore, cracking due to sec is not cited as an aging effect requiring management for copper alloy with greater than 15 percent zinc components in the environment of treated water. Waste Water This environment includes radioactive, potentially radioactive, or non-radioactive waters that are collected from equipment and floor drains, vent system drains, and waters processed by the radwaste system. Waste water normally is not expected to contain ammonia or ammonium compounds. Although chemicals containing ammonia or ammonium compounds may be stored onsite (e.g., chemicals used for macrobiological control), spills are event driven and ammonia or ammonium compounds are not assumed to be present in waste water for the determination of aging effects. A search of plant specific operating experience for the past 10 years did not identify any instances of aging effects due to exposure to ammonia or ammonium compounds in the waste water environment. Therefore, cracking due to sec is not cited as an aging effect requiring management for copper alloy with greater than 15 percent zinc components in the environment of waste water. Condensation This environment is an air environment containing warm or moist air where condensation may occur and periodically wet the component surface. The condensation air environment is used

May 2, 2019 Enclosure A Page 62 of 82 for air drawn inside ventilation systems and tor air spaces within piping and valves and miscellaneous components such as air coolers, sprinklers, and spray nozzles. Although chemicals containing ammonia or ammonium compounds may be stored onsite (e.g., chemicals used for macrobiological control) or at offsite facilities, spills are event driven and ammonia or ammonium compounds are not assumed to be present in condensation for the determination of aging effects. A search of plant specific operating experience tor the past 10 years did not identify any instances of aging effects due to exposure to ammonia or ammonium compounds in the condensation environment. Therefore, cracking due to sec is not cited as an aging effect requiring management tor copper alloy with greater than 15 percent zinc components in this environment of condensation. Raw Water (other than open-cycle cooling water) The environment of raw water has also been identified for systems other than open-cycle cooling water systems such as the Domestic Water System and the Fire Protection System. Neither of these systems operate with chemicals which contain ammonia or ammonium compounds. A search of plant specific operating experience for the past 1 O years did not identify any instances of aging effects due to exposure to ammonia or ammonium compounds in these raw water environments. Therefore, cracking due to sec is not cited as an aging effect requiring management tor copper alloy with greater than 15 percent zinc components in this environment of raw water. In summary, as discussed in detail above, plant specific operating experience tor the past 1 O years did not identify any instances of cracking in copper alloy with greater than 15 percent zinc due to exposure to ammonia or ammonium compounds. Cracking of copper alloy with greater than 15 percent zinc due to exposure to ammonia or ammonium compounds is cited as an aging effect tor insulated components operated below the dew point and in certain raw water applications where chemicals containing ammonia or ammonium compounds are used seasonally tor macrobiological control. Cracking is not cited as an applicable aging effect tor copper alloy with greater than 15 percent zinc in air, condensation and waste water since spills of ammonia or ammonium compounds stored onsite or at offsite facilities are event driven and need not be assumed tor the determination of aging effects. For indoor air, leakage from piping systems that could transport ammonia or ammonium compounds onto susceptible components was not considered, which is consistent with the guidelines of NUREG-2221. Cracking is not cited as an applicable aging effect tor copper alloy with greater than 15 percent zinc in treated water and other raw water environments since these environments do not normally contain ammonia or ammonium compounds. No updates to the SLRA are required as a result of this response.

RAI 3.3.2.2.8-1

Background:

May 2, 2019 Enclosure A Page 63 of 82 SLRA Section 3.3.2.2.8 and plant specific note No. 3 to SLRA Table 3.3.2-30 state that 6063-T6 aluminum alloys are not susceptible to cracking due to stress corrosion cracking. SRPSLR Section 3.3.2.?.8 provides a list of aluminum alloys that are not susceptible to cracking; however, 6063-T6 is not on the list. When a specific alloy is not on the list, the basis used to determine that the alloy is not susceptible and technical information substantiating the basis should be provided in the SLRA. The SLRA does not provide a basis for why 6063-T6 aluminum alloys are not susceptible to cracking due to stress corrosion cracking. Request: State the basis for why 6063-T6 aluminum alloys are not susceptible to cracking due to stress corrosion cracking. Exelon Response: SAP-SLR Section 3.3.2.2.8 identifies 6xxx series aluminum alloys in the F temper as susceptible to cracking due to stress corrosion cracking (SCC). F temper aluminum alloys are in the as-fabricated condition and have not been heat treated or work hardened. The basis for why 6063-T6 aluminum alloy is not susceptible to cracking due to stress corrosion cracking is as follows. Aluminum alloys in tempers other than F have either been heat treated or work hardened. The vulnerability of aluminum alloys to sec varies widely depending on the alloy and the heat treatment or work hardening process. 6063-T6 aluminum alloy is solution heat treated and artificially aged. 6063-T6 is not susceptible to cracking due to stress corrosion cracking as described in SLRA Section 3.3.2.2.8 and as shown in Table 1 and Table 5 in NBS Monograph 156, "Stress Corrosion Cracking Control Measures," U.S. Department of Commerce/National Bureau of Standards, Issued June 1977 and Table I in NASA Standard MSFC-SPEC-522B, "Design Criteria for Controlling Stress Corrosion Cracking," July 1, 1987. No updates to the SLRA are required as a result of this response.

May 2, 2019 Enclosure A Page 64 of 82

13.

SLRA TLAA 4.2.13 Replacement Core Plate Extended Life Plug Irradiation - Enhanced Stress Relaxation Analysis Regulatory Basis: 10 CFR 54.21 {a){3) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function{s) will be maintained consistent with the current licensing basis for the period of extended operation. One of the findings that the staff must make to issue a renewed license (1 O CFR 54.29{a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 10 CFR 54.29{a), the staff requires additional information in regard to the matters described below. RAI 4.2.13-1

Background:

SLRA Section 4.2.13, "Replacement Core Plate Extended Life Plug Irradiation -Enhanced Stress Relaxation Analysis," describes Exelon's TLAA for the irradiation induced stress relaxation of the extended life core support plugs {ELCSPs). Exelon dispositioned the TLAA for the ELCSPs in accordance with 10 CFR 54.21{c){1){ii). SLRA Section 4.2.13 states that the reevaluation predicted an end-of-life preload of 111 pounds which exceeds the differential pressure of 46. 7 pounds acting on the ELCSPs. Issue: The staff does not have sufficient information to verify that the evaluation of the stress relaxation {loss of preload) for the ELCSPs is valid for the subsequent period of extended operation. The staff does not have sufficient information regarding the as-installed {beginning-of-life) preload or description of the method used to calculate the stress relaxation. Request: Provide information describing the as-installed preload for the ELCSPs and the methodology used to calculate the stress relaxation. Exelon Response: Exelon dispositioned the TLAA documented in PBAPS SLRA Section 4.2.13 in accordance with 1 O CFR 54.21 {c){1 ){ii). PBAPS installed the extended life core support plugs {ELCSPs) in 2001 at Unit 3 and in 2012 at Unit 2. With respect to preload, the beginning-of-life factor at the time of installation was 6.2, which reflects conservative margin at installation.

May 2, 2019 Enclosure A Page 65 of 82 The methodology used by GEH in the reevaluation to determine the stress relaxation due to fluence is considered by GEH as proprietary. However, BWRVIP-25 Revision 1, Appendix I, Section 6.3 discusses stress relaxation due to fluence and Figure 6-4 shows a curve that is very similar to the one used by GEH in their reevaluation. The discussion in Section 6.3 and the general shape of the curve are suitable for explaining the methodology. It is noted that the curves are not exactly the same, however the GEH results are more conservative than the curve in BWRVIP-25, Revision 1, Appendix I, Figure 6-4 for the projected fluence. No updates to the SLRA are required as a result of this response.

May 2, 2019 Enclosure A Page 66 of 82

14.

SLRA TLAA 4.3.5 Environmental Fatigue Analyses for RVP and Class 1 Piping RAI 4.3.5-1

Background:

During the audit, the staff noted that the following onsite document discusses the applicant's plant transients related to fatigue monitoring and analyses (

Reference:

SIR-99-091, Revision o, Report on System Review and Recommendations for a Transient and Fatigue Monitoring System at Peach Bottom Atomic Power Station, September 1999). The plant transients and associated cycle numbers are used as input for fatigue analyses including the environmental fatigue analysis described in SLRA Section 4.3.5. Specifically, Tables 2.1 and 2.2 of SIR-99-091, Revision O indicates that some cycles will not be included in the automatic counting by the fatigue monitoring system (Sl:FatiguePro software) because they are difficult to track or have insufficient impact on fatigue (e.g., transients related to weekly reduction power cycles and control rod drive scrams). The reference document also indicates that these unaccounted cycles are preloaded in the fatigue monitoring system and therefore there is a need for users to ensure that the actual cycle numbers are reasonable in comparison with the preloaded cycle numbers. SLRA Tables 4.3.1-1 and 4.3.1-2 describe the design transients used in the applicant's fatigue analyses including the environmentally assisted fatigue (EAF) analysis. These tables do not identify or discuss the uncounted, preloaded transients that are addressed in the above reference (SIR-99-091, Revision 0). In addition, SLRA Section 4.3.5 does not discuss the applicant's monitoring activities or evaluations to confirm that the actual cycle numbers for the preloaded transients are below the design basis cycles in the fatigue analyses. Request: Please discuss how the applicant's monitoring activities or evaluations confirm that the preloaded transient cycles are in the reasonable ranges below the design basis cycles. Exelon Response: Report SI R-99-091, Revision 0, "Cycle Counting and Cycle-Based Fatigue Report for the Transient and Fatigue Monitoring System for Peach Bottom Atomic Power Station Units 2 and 3" was issued in 1999 and served as a recommendation report for the implementation of Sl:FatiguePro' prior to the installation of the software at PBAPS. This report documented background information relevant to the PBAPS Fatigue Monitoring program including transients that were identified in PBAPS Fatigue Monitoring program procedures and in GE thermal cycle diagrams. These transients were documented in Tables 2-1 and 2-2 of Report SIR-99-091, Revision 0. The report recommended that the transients in Table 2-1 and 2-2 should be monitored by Sl:FatiuePro', with the exception of transients that were shaded and italicized. The report explained that these shaded and italicized transients are not required to be monitored for one of the following reasons:

May 2, 2019 Enclosure A Page 67 of 82

1) Transients that have insignificant impact on fatigue and therefore need not be monitored,

2) Transients which would be difficult to track, in which case Sl:FatiguePro' would assume

("preload") a conservative number of occurrences to bound the actual number of occurrences which would be expected during the life of the unit,

3) Transients in which the associated nozzle has been capped, or

4) Transients which are One-Time Faulted events.

The table below identifies the transients from Tables 2-1and2-2 of Report SIR-99-091, Revision 0 that were recommended not to be counted by Sl:FatiguePro' and how these transients are dispositioned for the second period of extended operation. SIR-99-091, Transient Description Number of Disposition Revision O Analyzed Category Table and Occurrences Transient Number 2-1 I 8 Power Cycle to Less Than 75% 10,000 Insignificant Fatigue (Daily Reduction)then Recover Impact 2-1 I 9 Power Cycle to Less Than 50% 480 Insignificant Fatigue (Weekly Reduction)then Recover Impact 2-2 I 24 Control Rod Worth Test 400 Insignificant Fatigue Impact 2-2 I 26 RPV Drain Nozzle On/Off Flow 240 Insignificant Fatigue Impact 2-2 I 28 Head Spray Injection 118 Applicable Nozzle Capped 2-2 I 29 Control Rod Drive Isolation 50 Analyzed Occurrences were Preloaded into SI: Fatigue Pro' 2-2 I 30 Single Control Rod Drive Scram 10 Insignificant Fatigue Impact 2-2 I 31 Control Rod Drive Scram 300 Insignificant Fatigue (Pressure= O psig, Impact Temperature s100°F) 2-2 I 33 Instrumentation Nozzle Transient 120 Insignificant Fatigue Impact

SIR-99-091, Transient Description Revision O Table and Transient Number 2-2 I 35 Automatic Slowdown 2-2 I 36 Pipe Rupture and Slowdown Number of Analyzed Occurrences 1 1 May 2, 2019 Enclosure A aae 0 p 68 f 82 Disposition Category Faulted Event Faulted Event Below is a description of each of the above transients segregated into the four categories. The descriptions also document the justification of why each transient is not counted by Sl:FatiguePro'. For purposes of brevity, each transient will be referred by the transient number from Tables 2-1 and 2-2 of the report as documented in the first column in the above table.

1)

Transients with Insignificant Fatigue Impact Transients 8, 9, and 24 Transients 8, 9, and 24 were specified in the original GE reactor vessel thermal cycle diagrams. These thermal cycle diagrams were established by GE in the early 1970s as input for RPV and various RPV nozzle fatigue analyses. The thermal cycle diagrams documented changes in reactor temperature, pressure, and water level in the reactor vessel during normal and upset transients. The thermal cycle diagrams for transients 8, 9, and 24 document no changes in temperature and pressure throughout the transients on the RPV and applicable nozzles, except for the feedwater nozzles as discussed below. Since these transients do not result in temperature or pressure changes, the transients' impact on fatigue is insignificant. As such, the originally specified occurrences for transients 8, 9, and 24 are inconsequential with respect to fatigue of the RPV and applicable RPV nozzles, except for the feedwater nozzles as discussed below. Therefore, SIR-99-091, Revision O did not recommend counting these transients by Sl:FatiguePro'for the RPV and various RPV nozzles, except for the feedwater nozzles. Power reductions such as transient 8, 9, and 24 may affect final feedwater temperature which may impact the feedwater nozzles with respect to fatigue. The Sl:FatiguePro' software monitors feedwater nozzle fatigue utilizing "stressed based" monitoring methods. With "stressed based" monitoring actual real-time feedwater temperature and pressure are monitored and the software then computes real-time stresses in the region of interest. The real-time stresses are then used to calculate cumulative usage consistently with the associated CLB fatigue analyses. Transient 26 The original GE reactor vessel thermal cycle diagram for PBAPS specifies 240 occurrences of this transient specifically for the reactor vessel drain nozzle. The transient definition assumes no changes in nozzle temperature throughout the transient. As such, the originally specified 240 occurrences of transient 26 are inconsequential with respect to fatigue of the reactor vessel drain nozzle. Since, this transient does not result in a temperature or pressure

May 2, 2019 Enclosure A Page 69 of 82 change, the transient's impact on fatigue is insignificant and therefore SIR-99-091, Revision O did not recommend counting these transients by Sl:FatiguePro'. Transient 30 The original GE reactor vessel thermal cycle diagram for PBAPS specifies 1 O occurrences of this transient for each CRD nozzle. The definition of this transient assumes temperature changes to a single CRD nozzle in which the CRD is scrammed by itself, while reactor coolant is at normal operating temperature and pressure. The original GE reactor vessel thermal cycle diagram for PBAPS also specifies for each CRD nozzle, 200 occurrences of various other "Scram" transients in which all CRDs are simultaneously scrammed while reactor coolant is at normal operating temperature and pressure. These "Scram" transients are monitored by Sl:FatiguePro' as documented in SLRA Tables 4.3.1-1and4.3.1-2 as transients 11 through 15. Review of the original CRD nozzle fatigue analysis shows that the contribution of transient 30 to CRD nozzle fatigue is extremely small. For example, the original CRD nozzle fatigue analysis assumed: 120 occurrences of Startup and Shutdown, 271 occurrences in which all CRDs scram at full power (200 were specified in the thermal cycle diagrams), 1 O occurrences in which a single CRD scrams at full power. 50 occurrences of Loss of Cooling Water Events, 3 occurrences of Hydrostatic Pressure Tests, 130 occurrences of Design Pressure Tests, 2 occurrences of Scram-Reactor Over Pressure Transients, and 1 O occurrences of Loss of Feedpump Transients; The resulting CRD nozzle fatigue usage ("design CUF") based on these assumed transients and all the above transient occurrences (596) was calculated in the original fatigue analysis as a CUF value of 0.005 of which the contribution for the 1 O occurrences of transient 30 to this CUF value is estimated to be approximately 0.00008. In addition, operating experience review indicates that an actual scram of a single CRD with the reactor at power is a rare event. Therefore, since it is not credible that this transient will occur more than 1 O times to the same CRD during the life of the unit and because of the small contribution to CRD nozzle fatigue, SIR-99-091, Revision O did not recommend counting this transient by Sl:FatiguePro'. Transient 31 The original GE reactor thermal cycle diagrams for PBAPS specified various CRD cooling water transients specifically for the CRD nozzles. Transient 31 is specified on these thermal cycle diagrams with 300 assumed occurrences where CRD cooling water temperature changes from 60°F to 70°F and back to 50°F; during a scram while the reactor is shutdown and reactor coolant temperature and pressure are less than or equal to 100°F and O psig.

May 2, 2019 Enclosure A Page 70 of 82 A small change in temperature from 60°F to 70°F and back to 50°F results in insignificant impact on fatigue. As such, the specified 300 occurrences are inconsequential with respect to fatigue of the CRD nozzles. Therefore, SIR-99-091, Revision 0 did not recommend counting this transient by Sl:FatigueProTM. Transient 33 The original GE reactor thermal cycle diagram for PBAPS specifies 120 occurrences of this transient specifically for the reactor vessel instrumentation nozzles. The transient definition assumes a small temperature change from 100°F to 60°F and back to 100°F during a pre-startup hydrotest. A small change in temperature from 100°F to 60°F and back results in insignificant impact on fatigue. As such, the originally specified 120 occurrences of this transient is inconsequential with respect to fatigue of the reactor vessel instrumentation nozzles. Therefore, SIR-99-091, Revision O did not recommend counting this transient by Sl:FatiguePro'.

2)

Analyzed Occurrences that were Preloaded into Sl:FatiguePro' Transient 29 The original GE reactor thermal cycle diagram for PBAPS specified for each CRD nozzle 50 occurrences of this transient in which the CRD cooling water flow to a single individual CRD is reduced from 0.34 gpm to 0.06 gpm when the drive to the single CRD is isolated and placed back in service. Since the transient is assumed to occur while reactor coolant is at normal operating temperatures, the transient results in a temperature change from 60°F to 546°F and back to 50°F. This is a local transient that only affects the particular CRD nozzle which is associated with the CRD that is isolated. Operating experience review indicates that actual "Control Rod Drive Isolation" events while reactor coolant is at operating temperatures is a rare event. The contribution of this transient to CRD nozzle fatigue is extremely small. For example, the original CRD nozzle fatigue analysis calculated a design CUF value of 0.005. See the disposition of transient 30 above for more details on this fatigue analysis. The contribution for the 50 occurrences of transient 29 to this design CUF value is estimated to be 0.00042. Because of this small contribution to CRD nozzle fatigue and since this transient is not expected to occur to the same CRD nozzle more than 50 times in the life of the unit, SIR 091, Revision 0 did not recommend counting this transient by Sl:FatiguePro' but rather recommended simply preloading the software with 50 occurrences. Therefore, the Sl:FatiguePro' software conservatively assumes that 50 occurrences of transient 29 have already occurred in the CU Fen calculation of the CAD nozzles (location 1 on SLRA Table 4.3.1-3). As a result, the projected 80-year CU Fan value for the CRD nozzles is 0.186 of which the contribution for 50 occurrences of transient 29 is less than 0.001.

May 2, 2019 Enclosure A Page 71 of 82 Therefore, the preloaded 50 occurrences are a reasonable assumption which conservatively bounds the number of expected occurrences through the second period of extended operation.

3)

Applicable Nozzle Capped Transient 28 The original GE reactor thermal cycle diagram for PBAPS specifies this transient specifically for the reactor vessel head nozzle. However, the reactor head nozzles have been capped and therefore this transient is no longer applicable. Therefore, SIR-99-091, Revision O did not recommend counting this transient by Sl:FatiguePro'.

4)

Faulted Events Transient 35 and 36 These transients are one-time faulted events and are excluded from fatigue analysis. Therefore, SIR-99-091, Revision O did not recommend counting these transients by Sl:FatiguePro'. No updates to the SLRA are required as a result of this response.

RAI 4.3.5-2

Background:

May 2, 2019 Enclosure A Page 72 of 82 SLRA Section 4.3.5 indicates that in 2015 the applicant's fatigue monitoring software was modified to include the calculation and tracking of CUFen at the locations identified in NUREG/CR-6260 for the older-vintage BWR plant, as well as at other locations in contact with reactor water that were monitored by the fatigue monitoring software. NUREG/CR-6260 identifies the following Class 1 locations for CUFen calculations for the older-vintage BWR plants (1) reactor vessel shell and lower head; (2) reactor vessel feedwater nozzle; (3) reactor recirculation piping (including inlet and outlet nozzles); (4) core spray line reactor vessel nozzle and associated piping; (5) residual heat removal (AHR) return line piping; and (6) feedwater line piping. SLRA Table 4.3.1-3 provides the 80-year CUFen values for the applicant's limiting Class 1 locations. In comparison with the NUREG/CR-6260 locations, the table does not provide the EAF analyses results for the core spray line piping locations that are evaluated in NUREG/CR-6260. In addition, the SLRA does not clearly provide justification for the omission of the core spray line locations in the 80-year environmental fatigue projections. Request: Provide justification for why SLRA Table 4.3.1-3 does not address the EAF results for the core spray line piping locations that are evaluated in NUREG/CR-6260. Exelon Response: PBAPS UFSAR Appendix A, Section A.1.1 documents that the Core Spray System was designed and installed in accordance with ANSI 831.1, 1967 Edition. Therefore, the Core Spray System was not designed as ASME Section Ill Class 1 piping and this piping system was not explicitly evaluated for fatigue. In 1999, PBAPS contracted Structural Integrity Associates, Inc. (SIA) to complete a calculation which documented the results of a finite element model analysis of the core spray lines from the RPV core spray nozzles to the containment penetrations. This is what would typically be considered Class 1 piping in later BWRs designed to ASME Section Ill. The finite element model was then used to determine the critical locations for subsequent fatigue evaluations. The calculation concluded that the location with the maximum stresses is the core spray nozzle at the RPV and is the limiting location for fatigue and stress for the entire modeled piping system. This is due to the geometric discontinuities within the nozzle, as well as its close proximity to the hot vessel (thereby creating the largest transients for cold fluid injections). Therefore, since the nozzle and piping are made of the same material and experience the same temperature and pressure transients, the RPV core spray nozzle bounds the entire core spray piping line up to the drywall penetration for environmental fatigue usage.

May 2, 2019 Enclosure A Page 73 of 82 Therefore, core spray system piping locations are not included in SLRA Table 4.3.1-3 because the RPV core spray nozzles {location 2 on SLRA Table 4.3.1-3), with an 80-year projected CU Fen value of 0.510, were demonstrated by finite element analysis to be bounding with respect to fatigue. No updates to the SLRA are required as a result of this response.

RAI 4.3.5-3

Background:

May 2, 2019 Enclosure A Page 74 of 82 SLRA Section 4.3.5 (on pages 4-88 and 4-89) describes the applicant's methodology for environmental fatigue screening to determine the component locations for environmental fatigue monitoring. Specifically, step 8 indicates that all the selected locations with screening 80-year CU Fen (environmental fatigue usage factor) greater than 0.25 were identified and more detailed analysis for EAF was performed on these locations in accordance with NUREG-6909, Rev. 1. SLRA Section 4.3.5 does not describe the difference between the EAF analysis performed during the screening process and the more detailed EAF analysis performed after the screening process (i.e., screening-in of the bounding locations). Request: Please describe the difference between the EAF analysis performed during the screening process and the more detailed EAF analysis performed after the screening process. As part of the response, provide the justification for the difference. Exelon Response: The environmental fatigue screening process methodology described in SLRA Section 4.3.5 is based on EPRI guidance and lessons learned from previous license renewal applications. As described in steps 3, 6, 7, and 8 of the Environmental Fatigue Screening Subsection in SLRA Section 4.3.5, the "screening 80-year CUFen" values were considered in the EAF screening process to eliminate components from further consideration. Components with "screening 80-year CUFen" values less than 0.25 were considered for elimination, however, these components were further evaluated prior to final elimination. Therefore, of the 29 components that were assigned "screening 80-year CUFen" values during the EAF screening process, only 6 components were eliminated (i.e., "screened out") and 23 components were selected (i.e., "screened in") for "more detailed EAF analysis" per the recommendations in NUREG/CR-6909, Revision 1. The evaluation of these 6 components and justification for elimination from the screening process is described in more detail in the response to RAI 4.3.5-4, Question 2. In addition, 3 additional components "screened out during the EAF screening process prior to the assignment of a "screening 80-year CU Fen" value. The evaluation of these components and justification for elimination from the screening process is described in the response to RAI 4.3.5-4, Question 1. EAF Screening Process and Screening 80-year CUFen Values The following is a description of how the "screening 80-year CUFen" values were calculated and used in the EAF screening process. The EAF screening process assigned a "bounding screening Fen" value for each component based on the component's material, assuming the maximum temperature,

May 2, 2019 Enclosure A Page 75 of 82 and assuming a conservative dissolved oxygen (DO) concentration. The "screening 80-year CUFen" value was then calculated by multiplying the "bounding screening Fen" value by either: the known 40-year design CUF value for the component times a factor of 2.0; or the known 60-year design CUF value for the component times a factor of 4/3; as shown below. screening 80-year CUFen =(bounding screening Fen)* 2.0 *(design 40-year CUF) OR screening 80-year CU Fen= (bounding screening Fen)* (4/3) * (design 60-year CUF) Since a CUF value is simply the ratio of the assumed number of transient occurrences divided by the ASME Section Ill allowed number of occurrences, this methodology effectively doubles the number of transient occurrences associated with the "screening 80-year CUFen" value when compared to the transient cycle occurrences assumed in an equivalent 40-year fatigue analysis. More Detailed EAF Analysis and Projected 80-year CUFen Values The "more detailed EAF analysis" calculated a "projected 80-year CUFen" value, in accordance with the methodology described in NUREG/CR-6909, Revision 1, for each of the 23 "screened in" components. The resulting "projected 80-year CUFen" values are shown in SLRA Table 4.3.1-3 in the "80-year CUFen" column. The following is a summary of how "projected 80-year CUFen" values were calculated for each component. For each of the 23 "screened in" components a new 80-year CUF value "in air" was determined by using the applicable NUREG/CR-6909, Revision 1 "in air" fatigue curve and using the larger of the applicable 80-year transient projections documented in SLRA Tables 4.3.1-1 or 4.3:1-2 and using the alternating stress values and load pairings from the original fatigue analyses. Fen values were then computed based upon the applicable formula provided in NUREG/CR-6909, Revision 1 for each material based on the component's operating DO concentration and the operating temperatures. A "projected 80-year CUFen" value was then calculated by multiplying the new 80-year CUF value "in air" for the component by the applicable Fen value based on operating temperatures and DO concentration as shown below. Projected 80-year CUFen =Fen (at operating temperature and DO concentration)

• 80-year CUF "in air (based on 80-year projections)

Comparison of the Differences Between the Screening 80-year CUFen and Projected 80-year CU Fen values The "screening 80-year CUFen" values used in the EAF screening process are more conservative than the "projected 80-year CUFen" values developed in the "more detailed analyses" for the following reasons.

May 2, 2019 Enclosure A Page 76 of 82

1) The calculation of the "screening 80-year CU Fen" values assumed twice the number of transient occurrences than those assumed in an equivalent 40-year fatigue evaluation. In contrast, the calculation of the "projected 80-year CU Fen" values assumed the larger of the projected 80-year number of occurrences from SLRA Tables 4.3.1-1 and 4.3.1-2. Therefore the "screening 80-year CUFen" values are more conservative than the "projected 80-year CUFen" values since all the projected 80-year transient cycle occurrences in column 4 of Tables 4.3.1-1 and 4.3.1-2 are less than twice the number of the assumed 40-year transient occurrences in column 5, except for transients no. 27a, "HPCI Injection", and 27b, "RCIC Injection".

The "HPCI Injection" and "RCIC Injection" transients are used only in the calculation of the "projected 80-year CUFen" values for the "RPV Region 81 (Nl-Cr-Fe)/Jet Pump Shroud Support, Diffuser Weld to Baffle Plate" and the "RPV Region A (LAS)/Refueling Containment Skirt Juncture 1 Outside Vessel" (locations 24 and 20 on SLRA Table 4.3.1-3). As explained in SLRA Section 4.3.6.1, although the projected 80-year transient cycles numbers for transient 27a and 27b exceed twice the number of originally assumed occurrences, the overall effect of these transients on bulk reactor coolant temperature and fatigue damage is insignificant.

2) The calculation of the "screening 80-year CUFen" values assumed "bounding screening Fen" values which are based on the maximum temperature. In contrast, the calculation of the "projected 80-year CU Fen" values developed Fen values which are based on actual operating temperatures for the evaluated component. This is conservative since Fen multipliers increase with temperature. Therefore the "screening 80-year CUFen" values are more conservative than the "projected 80-year CUFen" values.

3) Evaluation of the 6 "screened out components that were assigned "screening 80-year CU Fen" values during the EAF screening process shows that these 6 components are bounded by the 23 components that "screened in". This is described in more detail in the response to RAI 4.3.5-4 Question 2.

Therefore, since the "screening 80-year CUFen" values are more conservative than the "projected 80-year CUFen" values the use of the "screening 80-year CUFen" values during the screening process is justified. No updates to the SLRA are required as a result of this response.

RAI 4.3.5-4

Background:

May 2, 2019 Enclosure A Page 77 of 82 SLRA Section 4.3.5 describes the applicant's methodology for EAF screening to determine the component locations for EAF monitoring. Specifically, steps 6 and 7 address the screening process for the components that have not been monitored for environmental fatigue. In these screening steps, the component locations are screened based on 80-year CUF values (without consideration of environmental effect) and subsequently the selected locations are evaluated in consideration of environmental correction factor (Fen) to determine whether the projected CU Fen values exceed the screening threshold (0.25). For example, in step 6 the location with the greatest estimated screening 80-year CUF value is selected. In addition, the top two locations with the greatest two estimated screening 80-year CUF values were selected, if the estimated screening 80-year CUF values of these locations are within a factor of two. For the locations not included in the existing environmental fatigue monitoring, the applicant's method described above may omit the EAF locations that have a relatively low non-environmental CUF value but have a very high Fen value even though such location may result in the CU Fen value greater than the screening threshold (0.25). In addition, SLRA Section 4.3.5 does not clearly discuss how the applicant confirms that the screened-out locations during the screening process are bounded by the screened-in locations in the EAF analysis (i.e., screened-out 9 component locations out of the 32 component locations that have an identified CUF value in a PBAPS current licensing basis stress report or evaluation and for which EAF applies, as addressed in SLRA Section 4.3.5). Request 1:

1. Please describe how the applicant confirms that the EAF screening does not omit the locations that may have a relatively low CUF value but have a very high Fen value resulting in the CU Fen value greater than the screening threshold.

Request 2:

2. Please describe how the applicant confirms that the screened-out locations during the screening process are bounded by the screened-in locations for the EAF analysis and monitoring.

Exelon Response - Item 1: Exelon confirmed that the EAF screening process did not omit locations with relatively low CUF values but potentially high Fen values which could result in actual fatigue usage of the omitted locations to exceed the ASME Section Ill acceptance criterion of 1.0 during the second period of extended operation.

May 2, 2019 Enclosure A Page 78 of 82 An early step in the EAF screening process was to calculate "screening 80-year CUP' values as follows. "screening 80-year CUP'= 2.0 * (design 40-year CUF) OR "screening 80-year CUP'= (4/3) *(design 60-year CUF) Note, "screening 80-year CUP' values are not adjusted for EAF while "screening 80-year CUFfill" values are conservatively adjusted for EAF. As described in SLRA Section 4.3.5, Environmental Fatigue Screening Subsection step 6, the EAF screening methodology does allow for the consideration for eliminating components with "80-year screening CUP' values of less than 0.25. However, these components were further evaluated prior to final elimination. As such, only 3 components with "80-year screening CUP' values less than 0.25 were eliminated during the EAF screening process as described in step 6) in SLRA Section 4.3.5, Environmental Fatigue Screening Subsection. Although these 3 components had "80-year screening CUP' values that were very small (i.e., 0.14, 0.008, and 0.0015), each component was further evaluated prior to final elimination. Below is a summary of the evaluation for each component:

1) The first of these "screened out components is the "RPV Region B1 (Nl-Cr-Fe)/Shroud Support" (JCT 3) component, which has an original design 40-year CUF value of 0.07.

The "80-year screening CUP' value for this component was calculated as 0.14. This effectively doubled the number transient occurrences when compared to those assumed in the 40-year fatigue analysis. This component was fabricated from Ni-Cr-Fe material. The maximum overall 80-year Fen value for the Ni-Cr-Fe material that can be derived from NUREG/CR-6909, Revision 1, regardless of temperature and water chemistry is a value of 3.33. Therefore, the corresponding approximate "80-year screening CUFen" value for this component is 0.4662. Therefore, even when assuming the maximum Fen multiplier for Ni-Cr-Fe material and twice as many transient cycle occurrences than originally assumed, the resulting "80-year screening CUFen" value (0.4662) does not exceed the ASME Section Ill acceptance criterion of 1.0. In addition, this component is directly bounded by a monitored component documented on SLRA Table 4.3.1-3 as location 23 ("RPV Region B1 (Nl-Cr-Fe)/Shroud Support, Baffle Plate to Vessel Juncture" (JCT A)). Comparisons of the two components shows that the bounding component:

a. Has a design 40-year CUF value (0.167) which is significantly larger than the design 40-year CUF value of the "screened ouf' location (0.07),

b. Is made of the same material as the "screened out component.

c. Was assumed to experience the same transients and transient occurrences as the "screened out component.

d. Was originally evaluated with the same technical rigor (ASME Section Ill, NB-3200) as the "screened out" component.

May 2, 2019 Enclosure A Page 79 of 82 Therefore, the elimination of this component is justified because even when assuming the maximum possible 80-year Fen value that can be derived from NUREG/CR-6909, Revision 1 for the applicable material and twice as many transient cycle occurrences than originally assumed, the resulting 80-year screening CUFen values remain significantly less than the ASME acceptance criterion of 1.0, and this component is bounded by a "screened in" component that will be monitored during the second period of extended operation.

2) The second of these three "screened ouf' components is the "Core Spray Nozzles (SS)/Thermal Sleeve Location 3" component which has an original design 40-year CUF value of 0.008. The "80-year screening CUP' value for this component was calculated as 0.016. This effectively doubled the number transient occurrences when compared to those assumed in the 40-year fatigue analysis.

This component was fabricated from stainless steel material. The maximum overall Fen multiplier for stainless steel material that can be derived from NUREG/CR-6909, Revision 1 regardless of temperature and water chemistry is a value of 10.55. Therefore, the corresponding approximate "80-year screening CU Fen" value for this "screened ouf' component is 0.1688. Therefore, even when assuming the maximum Fen multiplier for Ni-Cr-Fe material and twice as many transient cycle occurrences than originally assumed, the resulting "80-year screening CUFen" value (0.1688) does not exceed the ASME Section Ill acceptance criterion of 1.0. In addition, this component is directly bounded by a monitored component documented on SLRA Table 4.3.1-3 as location 2 ("Core Spray Nozzles (SS)/Thermal Sleeve Junction 9"). Comparisons of the two locations shows that the bounding location:

a. Has a design 40-year CUF value (0.091) which is significantly larger than the design 40-year CUF value of the "screened out" component (0.008},

b. Is made of the same material as the "screened ouf' component.

c. Requires fewer occurrences to reach its fatigue limit as compared to the "screened ouf' component.

d. Was originally evaluated with the same technical rigor (ASME Section Ill, NB-3200) as the "screened ouf' component.

Therefore, the elimination of this component is justified because even when assuming the maximum possible 80-year Fen value that can be derived from NUREG/CR-6909, Revision 1 for the applicable material and twice as many transient cycle occurrences than originally assumed, the resulting 80-year screening CUFen values remain significantly less than the ASME acceptance criterion of 1.0, and this component is bounded by a "screened in" component that will be monitored during the second period of extended operation.

3) The third of these "screened ouf' components are the new Steam Dryers recently installed on Units 2 and 3. The fatigue evaluation associated with these components is described in SLRA Section 4.3.6.5, which was dispositioned in accordance with 1 O CFR 54.21 (c)(1 )(i). The design 40-year CUF value for this component is 0.0015. The 80-year screening CUF value for this component is 0.003. This component was fabricated from stainless steel material.

May 2, 2019 Enclosure A Page 80 of 82 The maximum 80-year Fen value for 80 years for stainless steel material that can be derived from that NUREG/CR-6909, Revision 1, regardless of temperature and water chemistry is a value of 10.55. Therefore, the corresponding approximate "80-year Screening CUFan" value for this component is 0.032. Therefore, even when assuming the maximum Fen multiplier for stainless steel material and twice as many transient cycle occurrences than originally assumed, the resulting "80-year screening CUFan" value (0.032) does not exceed the ASME Section Ill acceptance criterion of 1.0. Therefore, the elimination of this component is justified because even when assuming the maximum possible 80-year Fen value that can be derived from NUREG/CR-6909, Revision 1 for the applicable material and twice as many transient cycle occurrences than originally assumed, the resulting 80-year screening CUFen values remain significantly less than the ASME acceptance criterion of 1.0. No updates to the SLRA are required as a result of this response. Exelon Response - Item 2: Exelon has confirmed that the 9 "screened ouf' components are bounded by the 23 "screened in" components or the component is no longer in service. The disposition of 3 of the 9 locations that were eliminated during the EAF screening process, with associated "screening 80-year CUP' values less than 0.25, is summarized in the response to Item 1 above. Below is a summary of the disposition of the remaining 6 components. One component was eliminated during the screening process because it was found that this component (the "CRDHSR Nozzle") had been capped early in the life of the plant (refer to SLRA Section 4.7.3 for additional information). The original design CUF value for this component was 0.00024. Since this nozzle is now capped, it cannot experience the originally assumed transients, and this nozzle only heats up and cools down with the reactor vessel. Therefore, it is not credible that the nozzle's usage will exceed ttie ASME Section Ill acceptance criterion of 1.0 during the second period of extended operation. Therefore, this location was eliminated in the EAF screening process per step 6)(d) in SLRA Section 4.3.5, Environmental Fatigue Screening Subsection. Therefore, the elimination of this component is justified because this component has been capped and cannot experience the originally assumed transients. The 5 remaining "screened ouf' components were assigned "screening 80-year CUFan" values as they progressed through the screening process. A description of how the "screening 80-year CUFan" values are calculated is provided in the response to RAI 4.3.5-3. Two of these 5 components are directly bounded by a component that "screened in" and were eliminated in the EAF screening process per step 6)(d) in SLRA Section 4.3.5, Environmental Fatigue Screening Subsection. The "screened in" component is documented on SLRA Table 4.3.1-3 as location 21 ("RPV Region B - Stabilizer Brackets Bracket to Shell Juncture"). The three components are summarized in the table below.

May 2, 2019 Enclosure A Page 81 of 82 Screened Location Material Design Bounding Screening In I CUF Fen 80-year Screened (40-Multiplier CU Fen* Out Years) Screened Location 21 on SLRA Table 4.3.1-3 LAS 0.17 17.31 5.88 In (RPV Region B - Stabilizer Brackets Bracket to Shell Juncture) Screened RPV Region B - RI Nozzle LAS 0.027 10.88 0.59 Out Screened RPV Region B - Core Spray LAS 0.02 11.81 0.47 Out Nozzle Comparisons of these three components shows that the bounding component: Has a design 40-Year CUF value (0.17) that is at least 6 times greater than the design 40-Year CUF values of the 2 "screened out components (0.027 and 0.02), Has a "screening 80-Year CUFen" value (5.88) which is an order of magnitude greater than the "screening 80-Year CUFen" values of the 2 "screened out" components (0.59 and 0.47), Is made of the same low allow steel (LAS) material as the 2 "screened out" components. Requires fewer occurrences to reach its fatigue limit as compared to the two screened out components. Was originally evaluated with the same technical rigor (ASME Section Ill, NB-3200) as the 2 "screened out" components. Therefore, the elimination of these two components is justified because these components are directly bounded by a "screened in" component which will be monitored during the second period of extended operation. The 3 remaining components "screened out" because of extremely small "screening 80-year CU Fen" values. These components were eliminated in the EAF screening process per step 8) in SLRA Section 4.3.5, Environmental Fatigue Screening Subsection and are documented in the table below.

Location Material Design CUF (40-Years) 2-inch inlet Ni-Cr-Fe 0.03 nozzle CRD Nozzles Ni-Cr-Fe 0.003 Core Spray Ni-Cr-Fe 0.008 Nozzles Originally Assumed Transients and Occurrences for 40-year CUF values 1 ) 120 Heatup and Cooldown 2)10 Loss of Feedwater,

3) 250 Pressure Test.

1) 401 - Scrams

2) 50 Loss of Flow

3) 3 Hydro Tests

4) 130 Design Hydros

5) 2 Slowdowns

6) 1 O loss of Feedwater pumps

1) 120 Heat-Up/Cooldown

2) 130 Design Pressure

3) 190 Scrams

4) 3 Hydro Tests

5) 10 Loss of Feedwater pumps

6) 2 Slowdowns May 2, 2019 Enclosure A Page 82 of 82 Bounding Screening Fen 80-year Multiplier CUFen.

2.69 0.16 2.69 0.02 2.69 0.04

1) This table documents the original calculated design 40-year CUF values and the transients and number of transient occurrences that were originally assumed in the fatigue evaluations that determined the design 40-Year CUF values. The table also documents the bounding Fen value and the "screening 80-year CUFen" value for each component. The "screening 80-year CUFen" values were calculated by multiplying the design 40-year CUF value by a factor of 2.0 and by the bounding Fen value. Therefore, in order to achieve an actual CUFen value which approaches the "screening 80-year CUFen" values on the above table, the unit would have to experience more than twice as many transient occurrences as originally assumed.

Also, to exceed the ASME Section Ill acceptance criterion of 1.0, the number of transients originally assumed, documented in the above table, would have to be increased by at least a factor of 12.

2) This table also documents the Fen value that was used to calculate the 80-year screening CUFen value. This Fen value was calculated by assuming the maximum operating temperature for the component location from the applicable formula in NUREG/CR-6909, Revision 1. Even when assuming a hypothetical Fen multiplier of 16.6 (which is more than 6 times than the bounding Fen multiplier that was used) the projected 80-year screening CUFen would remain less than the ASME Section Ill acceptance criterion of 1.0.

Therefore, the elimination of these three components is justified because these components would have to experience more than 12 times as many transient occurrences than assumed in the original fatigue evaluations to exceed the ASME Section Ill acceptance criteria of 1.0; which is not credible. No updates to the SLRA are required as a result of this response.

Notes: Peach Bottom Atomic Power Station, Units 2 and 3 Subsequent License Renewal Application Updates Resulting from the Responses to the following RAls: RAI 8.2.1.36-1 RAI 8.2.1.36-4 RAI 8.2.1.17-1 RAI 8.2.1.17-2 RAI 8.2.1.17-3 RAI 8.2.1.17-4 RAI 8.2.1.9-1 RAI 8.2.1.22-1 RAI 3.5.2.2.2.4-1 RAI 3.3.2.2.7-1 Updated SLRA Information is provided in the same order as the RAI responses contained in Enclosure A. To facilitate understanding, portions of the original SLRA have been repeated in this Enclosure, with revisions indicated. Previously submitted information is shown in normal font. Changes are highlighted with balded italics for inserted text and strikethroughs for deleted text.

May 2, 2019 Enclosure B Page 1of63 As a result of the response to RAI B.2.1.36-1 provided in Enclosure A of this letter, SLRA Appendix A, Section A.2.1.36 on page A-47 of the SLRA is revised as shown below. A.2.1.36 Protective Coating Monitoring and Maintenance The Protective Coating Monitoring and Maintenance aging management program will be enhanced to:

1. Use sertified seating inspestors for the inspestion of Serviss Le\\101 I seatings. Use Level II or Level Ill coating inspectors, certified to ANSI N45.2.6, for inspection of Service Level I coatings.

This enhancement will be implemented no later than six months prior to the second period of extended operation.

May 2, 2019 Enclosure B Page 2 of 63 As a result of the response to RAI 8.2.1.36-1 provided in Enclosure A of this letter, SLRA Appendix B, Section B.2.1.36 on page B-215 of the SLRA is revised as shown below. B.2.1.36 Protective Coating Monitoring and Maintenance Enhancements Prior to the second period of extended operation, the following enhancement will be implemented in the following program elements:

1. Use certified coating inspectors for tho inspection of Service Level I coatings. Use Level II or Level Ill coating inspectors, certified to ANSI N45.2.6, for inspection of Service Level I coatings. Program Element Affected: Detection of Aging Effects (Element 4)

May 2, 2019 Enclosure B Page 3 of 63 As a result of the response to RAI B.2.1.36-4 provided in Enclosure A of this letter, SLRA Appendix A, Section A.2.1.36 on page A-46 of the SLRA is revised as shown below. A.2.1.36 Protective Coating Monitoring and Maintenance The Protective Coating Monitoring and Maintenance aging management program is an existing mitigative and condition monitoring program that manages the effects of loss of coating integrity of Service Level I coatings, as defined in RG 1.54, Revision 1 or latest revision, inside primary containment. The program manages coating system selection, application, visual inspections, assessments, repairs, and maintenance of Service Level I protective coatings as defined in RG 1.54, Revision 1 or latest revision. The program is comparable to a monitoring and maintenance program for Service Level I protective coatings as described in RG 1.54, Revision 2.

May 2, 2019 Enclosure B Page 4 of 63 As a result of the response to RAI B.2.1.36-4 provided in Enclosure A of this letter, SLRA Appendix B, Section B.2.1.36 on page 8-215 of the SLRA is revised as shown below. B.2.1.36 Protective Coating Monitoring and Maintenance Program Description The Protective Coating Monitoring and Maintenance aging management program is an existing mitigative and condition monitoring program which manages the effects of loss of coating integrity of Service Level I coatings inside the primary containment (as defined in Nuclear Regulatory Commission (NRC) Regulatory Guide (RG) 1.54, Revision 1 or latest revision) in air-indoor uncontrolled and treated water environments. The failure of the Service Level I coatings could adversely affect the operation of the emergency core cooling systems (ECCS) by clogging the ECCS suction strainers. Proper maintenance of the Service Level I coating ensures that coating degradation will not impact the operability of the ECCS systems. The Protective Coating Monitoring and Maintenance program includes coating system selection, application, inspection, assessment, maintenance, and repair for any condition that adversely affects the ability of Service Level I coatings to function as intended. The program is comparable to a monitoring and maintenance program for Service Level I protective coatings as described in RG 1.54, Revision 2. Evaluations are performed for test or inspection results that do not satisfy established criteria and the conditions are entered into the corrective action program.

May 2, 2019 Page 5 of 63 As a result of the responses to RAls 8.2.1.17-1, 8.2.1.17-2, 8.2.1.17-3, and 8.2.1.17-4 provided in Enclosure A of this letter, SLRA Appendix A, Section A.2.1.17 beginning on page A-25 of the SLRA, is revised to modify Enhancements 1.c and 4, and add Enhancements 15 and 16 as shown below: A.2.1.17 Fire Water System Change to Enhancement 1.c

1. Revise flow test procedures to include:

a. Inspector test flush acceptance criteria for wet pipe sprinkler systems that currently do not include the requirement to record time to flow from the opened test valve.

b. Acceptance criteria for wet pipe main drain tests. Flowing pressures from test to test will be monitored to determine if there is a 1 O percent reduction in full flow pressure when compared to previously performed tests. An issue report shall be generated in the corrective action program to determine the cause and corrective actions.

c. If flow test acceptance criteria are not met, perform an investigation within the corrective action program that includes review for increased testing and perform at least two successful additional tests. shall be performed Additional tests shall be completed within the interval in which the original test was conducted. If acceptance criteria are not met during follow-up testing, an extent of condition and extent of cause analysis shall be conducted to determine the further extent of tests which includes testing The test shall be performed on the same system, on the other unit.

Change to Enhancement 4

4. Revise procedures to improve guidance for external visual inspections of the in scope sprinkler systems piping and sprinklers at least every two years to inspect for mmossive corrosion, loss of material, leaks, and proper sprinkler orientation.

Corroded, leaking or damaged sprinklers shall be replaced. Additional Enhancements 15 and 16

15. Revise the fire hydrant inspection and flush test procedure to include a minimum flow duration of one (1) minute after the hydrant valve is fully open to remove all foreign material.

16. Revise the underground fire main flow test to utilize the corrective action program to determine an increased test frequency when established test criteria is not met or when significant degraded trends that could adversely affect system intended function are identified. When test results pass the established test criteria, the test frequency may be extended to a five (5) year frequency IA W NFPA25.

May 2, 2019 Enclosure B Page 6 of 63 As a result of the responses to RAls B.2.1.17-1, B.2.1.17-2, B.2.1.17-3, and B.2.1.17-4 provided in Enclosure A of this letter, SLRA Appendix B, Section B.2.1.17 beginning on page 8-102 of the SLRA, is revised to modify Enhancements 1.c and 4 and add Enhancements 15 and 16 as shown below: B.2.1.17 Fire Water System Change to Enhancement 1.c

1. Revise flow test procedures to include:

a. Inspector test flush acceptance criteria for wet pipe sprinkler systems that currently do not include the requirement to record time to flow from the opened test valve.

b. Acceptance criteria for wet pipe main drain tests. Flowing pressures from test to test will be monitored to determine if there is a 1 O percent reduction in full flow pressure when compared to previously performed tests. An issue report shall be generated in the corrective action program to determine the cause and corrective actions.

c. If flow test acceptance criteria are not met, perform an investigation within the corrective action program that includes review for increased testing and perform at least two successful additional tests. shall be performed Additional tests shall be completed within the interval in which the original test was conducted. If acceptance criteria are not met during follow-up testing, an extent of condition and extent of cause analysis shall be conducted to determine the further extent of tests which includes testing Tho test shall be performed on the same system, on the other unit.

Program Elements Affected: Parameters Monitored or Inspected (Element 3), Detection of Aging Effects (Element 4), Acceptance Criteria (Element 6), and Corrective Actions (Element 7) Change to Enhancement 4

4. Revise procedures to improve guidance for external visual inspections of the in scope sprinkler systems piping and sprinklers at least every two years to inspect for oxoossivo corrosion, loss of material, leaks, and proper sprinkler orientation.

Corroded, leaking or damaged sprinklers shall be replaced. Program Elements Affected: Parameters Monitored or Inspected (Element 3) and Detection of Aging Effects (Element 4)

Additional Enhancements 15 and 16 May 2, 2019 Enclosure B Page 7 of 63

15. Revise the fire hydrant inspection and flush test procedure to include a minimum flow duration of one (1) minute after the hydrant valve is fully open to remove all foreign material. Program Element Affected: Preventative Actions (Element 2), Parameters Monitored or Inspected (Element 3), Detection of Aging Effects (Element 4)

16. Revise the underground fire main flow test to utilize the corrective action program to determine an increased test frequency when established test criteria is not met or when significant degraded trends that could adversely affect system intended function are identified. When test results pass the established test criteria, the test frequency may be extended to a five (5) year frequency IA W NFPA 25. Program Elements Affected: Parameters Monitored or Inspected (Element 3), Detection of Aging Effects (Element 4), and Acceptance Criteria (Element 6), Corrective Actions (Element 7)

May 2, 2019 Page 8 of 63 As a result of the response to RAI 8.2.1.9-1 provided in Enclosure A of this letter, SLRA Appendix 8, Section 8.2.1.9 on page 8-56 of the SLRA is revised as shown below. B.2.1.9 Flow-Accelerated Corrosion Program Description The Flow-Accelerated Corrosion aging management program is an existing condition monitoring program that manages wall thinning caused by flow-accelerated corrosion (FAG) in carbon steel heat exchanger components, piping and piping components exposed to reactor coolant, steam, and treated water environments. The program is based on commitments made in response to NRG Generic Letter 89-08, "Erosion/Corrosion Induced Pipe Wall Thinning," and relies on implementation of the Electric Power Research Institute (EPRI) guidelines in the Nuclear Safety Analysis Center (NSAC)-202L-R4 for an effective FAG program. CHECWORKS is used to predict component wear rates and remaining service life in the systems susceptible to FAG which provides reasonable assurance that structural integrity will be maintained between inspections. The model is revised if any changes in operating conditions or other factors that affect FAG (e.g., plant chemistry, power uprate) have occurred since the CHECWORKS model was last updated. Changes may also result from plant modifications that effect FAG behavior such as material changes, the addition of piping systems, piping system configuration changes, and the addition or replacement of in-line components. The CHECWORKS model is also refined by importing actual volumetric inspection data thickness measurements and re-running the wear rate analysis. This improves the predictive capability of the model to ensure that intended functions are maintained. Additionally, the program utilizes industry operating experience, plant experience, and engineering judgment of plant engineers to determine inspection locations. Changes made to the CHECWORKS model are done by a qualified FAG engineer. Each change is then independently reviewed and validated by a qualified FAG engineer. Evaluations documenting the calculation of wear, wear rate, remaining life, next scheduled inspection, and sample expansion are independently reviewed by a qualified FAG engineer. When program software (i.e., CHECWORKS and/or Fleet FAC Trending Software) is revised or replaced and the update has potential to affect the calculation of component wear, wear rate, remaining component life, and/or next scheduled inspection, a review will be performed to verify and validate that the software calculates these parameters consistently with NSAC-202L. The verification and validation shall be documented and stored electronically such that it is available for review. Limited or minor revisions or replacements of the software (such as end user enhancements, reporting revisions or additions, etc.) with no potential to affect these calculations (as verified by software change logs, vendor release notes, etc.) are exempt from this requirement and require no documentation.

May 2, 2019 Enclosure B Page 9 of 63 As a result of the response to RAI B.2.1.22-1 provided in Enclosure A of this letter, SLRA Section Appendix B, Section B.2.1.22, page B-130 of the SLRA, is revised as shown below: B.2.1.22 Selective Leaching When the acceptance criteria are not met such that it is determined that the affected component should be replaced prior to the end of the second period of extended operation, additional inspections will be performed. If subsequent inspections do not meet acceptance criteria, an extent of condition and extent of cause analysis will be conducted to determine the further extent of inspections. If it is necessary to conduct inspections on difficult-to-access surfaces due to unacceptable inspection findings occurring within the same material and environment, the necessary steps to make these surfaces accessible will be taken so that direct visual inspections can be performed or so that they can be removed for destructive testing to detect selective leaching.

May 2, 2019 Enclosure B Page 10 of 63 As a result of the response to RAI 3.5.2.2.2.4-1 provided in Enclosure A of this letter, SLRA Section 3.5.2.2.1.6, beginning on page 3.5-34 of the SLRA is revised as shown below: 3.5.2.2.1.6 Cracking Due to Stress Corrosion Cracking Stress corrosion cracking (SCC) of stainless steel (SS) penetration sleeves, penetration bellows,_vent line bellows, suppression chamber shell (interior surface), and dissimilar metal welds could occur in PWR and/or BWR containments. The existing program relies on ASME Code Section XI, Subsection /WE and1 O CFR Part 50, Appendix J, to manage this aging effect. Further evaluation, including consideration of SCC susceptibility and applicable operating experience (OE) related to detection, is recommended of additional appropriate examinations/evaluations implemented to detect this aging effect for these SS components and dissimilar metal welds. Table 3.5.1 Item Number 3.5.1-01 O and Item Number 3.5.1-039: These items evaluate cracking due to sec in stainless steel penetration sleeves, penetration bellows, vent line bellows, containment closure bolting, and dissimilar metal welds of the PBAPS Mark I containment exposed to an air-indoor environment. The enhanced ASME Section XI, Subsection IWE (B.2.1.30) program and the 1 O CFR Part 50, Appendix J (B.2.1.32) program will be used to manage the cracking of stainless steel penetration sleeves, penetration bellows, vent line bellows, containment closure bolting, and dissimilar metal welds. The suppression chamber shell at PBAPS is made of carbon steel and is not susceptible to sec. Cracking due to SCC in stainless steel penetration sleeves, penetration bellows, vent line bellows, containment closure bolting, and dissimilar metal welds is not expected to occur at PBAPS because stress corrosion cracking requires a concentration of chloride or sulfate contaminants, which are not present in significant quantities inside the containment or in plant systems, as well as high stress levels, and high temperatures. The containment components are located in an air-indoor environment and are not subject to conditions that promote corrosion or sec. Cyclical loading of stainless steel penetration sleeves, penetration bellows, vent line bellows, and dissimilar metal welds is not expected to result in sec at PBAPS because of the containment design which limits cyclical loadings to acceptable levels. The design of penetrations, which exhibit significant differences in temperature during plant operations, limit loads from the piping onto the drywell by either using bellows or installation of small bore diameter pipe. The containment analysis was completed in accordance with the original design specifications. Fatigue analysis, or a fatigue waiver, for the drywell penetrations was not required since no cyclical loads were identified for these components in the applicable design specifications per the CLB. However, PBAPS Units 2 and 3 process lines that penetrate the drywell and experience significant differences in temperature during plant operation were designed with penetration bellows to ensure that fatigue due to thermal loads during plant operation is acceptable, preventing one potential cause of SCC at the penetrations. The following process lines were

May 2, 2019 Enclosure B Page 11 of 63 designed with penetration bellows: the main steam lines, the feedwater lines, the HPCI steam line, the AHR supply and return lines, the RWCU pump suction line, the core spray discharge lines, and the vessel head spray line. In addition, during the preparation of this application, PBAPS has performed an assessment to show that the drywall would have met the criteria for a fatigue waiver. License renewal applications for other similar Mark I containments designed to later code years have credited fatigue waivers. The criteria that were met for the fatigue waiver included: 1) atmospheric to operating pressure cycles, 2) normal operation pressure fluctuations, 3) temperature differences between startup and shutdown,

4) temperature differences during normal operation, 5) temperature differences at dissimilar metals, and 6) mechanical loads. The drywall fatigue waiver assessment concluded that the components that could be subject to cyclic loading but have no current licensing basis fatigue analysis are subjected to an acceptable and negligible amount of fatigue. The fatigue waiver assessment did not include drywell high temperature mechanical penetrations, listed above, which have bellows or are limited to small pipe diameters. A summary of the fatigue waiver assessment is provided in section 3.5.2.2.1.5. The containment components with a fatigue analysis that are addressed in Section 3.5.2.2.1.5 and Sections 4.3.2 and 4.6 are representative of the stainless steel penetration sleeves, penetration bellows, vent line bellows, and dissimilar metal welds and can be used as a leading indicator for these components.

Plant operating experience confirms that SCC of stainless steel penetration sleeves, penetration bellows, vent line bellows, containment closure bolting, and dissimilar metal welds of the PBAPS Mark I containment is not expected. Original design and installation specifications for containment penetration components such as bellows, welds, and penetration adapters required initial surface examinations to ensure no flaws existed as part of initial installation. Appropriate integrated and local leak rate testing is conducted for pressure boundary components per the 1 O CFR Part 50, Appendix J (B.2.1.32) program. Through-wall cracking would be detected by the type A integrated leak rate test. Additionally, VT-3 examinations are performed on accessible portions of the containment penetrations in accordance with the ASME Section XI, Subsection IWE (B.2.1.30) program. Peach Bottom has not experienced a failure of the above listed containment components and integrated leak rate test results have shown significant margin. Industry operating experience has also shown strong performance of the primary containment components. Even though the aging effect of SCC of stainless steel penetration sleeves, penetration bellows, vent line bellows, containment closure bolting, and dissimilar metal welds is not expected to occur, the testing conducted in accordance with the 1 O CFR Part 50, Appendix J (B.2.1.32) program and examinations conducted in accordance with the ASME Section XI, Subsection IWE (B.2.1.30) program are applied to manage this aging effect and provide reasonable assurance that the cracking of stainless steel containment penetration bellows, containment closure bolting, and dissimilar metal welds at containment penetration sleeves will be detected prior to a loss of intended function.

May 2, 2019 Enclosure B Page 12 of 63 In addition, to address concerns identified in this Further Evaluation, as well as Item Number 3.5.1-027, the ASME Section XI, Subsection IWE (B.2.1.30) program will be enhanced to perform surface examinations on accessible portions of drywell high temperature mechanical penetrations, in addition to visual examinations, to detect SCC at penetrations that could be subject to cyclic loading but have no CLB fatigue analysis. The majority of the surface of the stainless steel penetration sleeves, penetration bellows, vent line bellows, and dissimilar metal welds are not accessible for visual inspection or surface examination for cracking due to the Mark I containment design but the ends of these penetrations are accessible, and representative of other areas of these penetrations and the other stainless steel penetration sleeves, penetration bellows, vent line bellows, and dissimilar metal welds. Therefore, the 1 O CFR Part 50, Appendix J (B.2.1.32) program and enhanced ASME Code Section XI, Subsection IWE (B.2.1.30) program, in conjunction with the additional examinations described above, will detect sec for these stainless steel components and dissimilar metal welds prior to a loss of intended function. The ASME Section XI, Subsection IWE (B.2.1.30) program and the 1 O CFR Part 50, Appendix J (B.2.1.32) program are described in Appendix B. Table 3.5.1 Item Number 3.5.1-038: This item is not applicable to the PBAPS Mark I steel containment. This Item is applicable instead to Mark 111 containments.

May 2, 2019 Enclosure B Page 13 of 63 As a result of the response to RAI 3.5.2.2.2.4-1 provided in Enclosure A of this letter, SLRA Section 3.5.2.2.2.4, beginning on page 3.5-51 of the SLRA is revised as shown below: 3.5.2.2.2.4 Cracking Due to Stress Corrosion Cracking, and Loss of Material Due to Pitting and Crevice Corrosion Cracking due to SSC and Joss of material due to pitting and crevice corrosion could occur in (a) Group 7 and 8 SS tank liners exposed to standing water; and (b) SS and aluminum alloy support members; welds; bolted connections; or support anchorage to building structure exposed to air or condensation (see SRP-SLR Sections 3.2.2.2.2, 3.2.2.2.4, 3.2.2.2.8, and 3.2.2.2.10 for background information). For Group 7 and 8 SS tank liners exposed to standing water, further evaluation is recommended of plant-specific programs to manage these aging effects. The acceptance criteria are described in BTP RLSB-1 (Appendix A. 1 of this SRP-SLR). For SS and aluminum alloy support members; welds; bolted connections; support anchorage to building structure exposed to air or condensation, the plant-specific OE and condition of the SS and aluminum alloy components are evaluated to determine if the plant-specific air or condensation environments are aggressive enough to result in Joss of material or cracking after prolonged exposure. The aging effects of Joss of material and cracking in SS and aluminum alloy components is not applicable and does not require management if (a) the plant-specific OE does not reveal a history of pitting or crevice corrosion or cracking and (b) a one-time inspection demonstrates that the aging effects are not occurring or that an aging effect is occurring so slowly that it will not affect the intended function of the components during the subsequent period of extended operation. The applicant documents the results of the plant-specific OE review in the SLRA. Visual inspections conducted in accordance with GALL-SLR Report AMP Xl.M32, "One-Time Inspection," are an acceptable method to demonstrate that the aging effects are not occurring at a rate that affects the intended function of the components. One-time inspections are conducted between the 5(jh and 6<Jh year of operation, as recommended by the "detection of aging effects" program element in AMP Xl.M32. If Joss of material or cracking has occurred and is sufficient to potentially affect the intended function of SS or aluminum alloy support members; welds; bolted connections; or support anchorage to building structure, either: (a) enhancing the applicable AMP (i.e., GALL-SLR Report AMP Xl.S3, "ASME Section XI, Subsection IWF," or AMP Xl.S6, "Structures Monitoring'?; (b) conducting a representative sample inspection consistent with GALL-SLR Report AMP Xl.M36, "External Surfaces Monitoring of Mechanical Components;" or (c) developing a plant-specific AMP are acceptable programs to manage loss of material or cracking (as applicable). Tempers have been specifically developed to improve the SCC resistance for some aluminum alloys. Aluminum alloy and temper combinations which are not susceptible to SCC when used in structural support applications include 1xxx series, 3xxx series, 6061-T6x, and 5454-x. For these alloys and tempers, the susceptibility of cracking due to sec is not applicable. If these alloys or tempers have been used, the SLRA states the specific alloy or temper used for the applicable in-scope components.

May 2, 2019 Enclosure B Page 14 of 63 Table 3.5.1 Item Number 3.5.1-052: This item is not applicable to PBAPS. PBAPS does not have Group 7 and 8 stainless steel tank liners exposed to standing water. Table 3.5.1 Item Number 3.5.1-099: For stainless steel support members; welds; bolted connections; support anchorage to building structure exposed to air environments, this Item Number evaluates the components aligned to this Item Number for loss of material due to pitting and crevice corrosion and cracking due to SCC. The Ono Time lnspostion (B.2.1.21) ASME Section XI, Subsection IWF (B.2.1.31) program will be used to manage cracking and loss of material of the stainless steel structural bolting and stainless steel elements for ASME Class 1, 2, and 3 supports exposed to air - indoor uncontrolled and air - outdoor in the Containment Strusturo and Component Supports commodity group. There were no aluminum components that were identified as applicable for this Item Number. A plant-specific OE review was performed using key words. The plant-specific OE does not reveal a history of pitting or crevice corrosion or cracking of aluminum or stainless steel support members or connections. However, a periodic inspection program will be implemented in lieu of the One-Time Inspection program. Tho /\\SME Sostion XI, Subsostion IWE (B.2.1.30) program and tho /\\SME Sostion XI, Subsostion l'NF (B.2.1.31) program will sontinuo to be used to o>Eamino tho sonnostions and supports aligned to this Item Number. Cracking has not been identified as an aging effect at PBAPS for stainless steel support members; welds; bolted connections; support anchorage to building structure exposed to air environments, or as a result of exposure to secondary sources, indicating that the environments do not contain sufficient halides in the presence of moisture to result in SCC. /\\ssordingly, Periodic visual inspections conducted in accordance with the Ono Time lnspostion (B.2.1.21) ASME Section XI, Subsection IWF (B.2.1.31) program will be performed to confirm that loss of material due to pitting and crevice corrosion or cracking due to sec are not occurring at a rate that affects the intended function of the components. Tho one time inspostions will be sondustod bot\\*Joon tho 50th and eOth year of operation. If loss of material or srasking is identified during tho one time inspostions and is suffisiont to potentially attest tho intended function of SS or aluminum alloy support members; wolds; bolted sonnostions; OF support anshorago to building stFusturo, tho condition 'Nill be entered into tho sorrostivo astion program. Depending upon tho conditions found, soFrostivo actions will insludo tho actions sush as tho following: (a) onhansing tho /\\SME Sostion XI, S1::1bsostion IWE (B.2.1.30) program and /\\SME Sostion XI, Subsostion IWF (B.2.1.31) program; (b) determining tho o>Etont of condition by sond1::1sting a representative sample inspostion sonsistont with tho E>Etornal Sl::IFfasos Monitoring of Moshanisal Components (B.2.1.24) program; OF (s) developing a plant sposifis /\\MP to manage loss of material OF srasking (as applisablo). Table 3.5.1 Item Number 3.5.1-100: For stainless steel and aluminum components or connections exposed to air environments, this Item Number evaluates the components aligned to this Item Number for loss of material due to pitting and crevice corrosion and cracking due to SCC. With the exception of aluminum alloy thermal insulation jacketing, specific aluminum alloys were typically not specified during original construction so the potential aging effects were considered for all

May 2, 2019 Enclosure B Page 15 of 63 aluminum components aligned to this Item Number. Aluminum alloy thermal insulation jacketing is constructed of alloy 1100, 3003, 3105, or 5005 with a magnesium content less than 3.5 weight percent. The aging effect of cracking is not applicable to aluminum insulation jacketing since these alloys are not susceptible to sec. A plant-specific OE review was performed using key words. The plant-specific OE does not reveal a history of pitting or crevice corrosion or cracking of aluminum or stainless steel components or connections. However, with the exception of the stainless steel Containment Structure refueling bellows assemblies and the stainless steel and aluminum thermal insulation and thermal insulation jacketing, a periodic inspection program will be implemented in lieu of the One-Time Inspection program. The Ono Time lnspostion (B.2.1.21) Structures Monitoring (B.2.1.34) program will be used to manage loss of material and cracking of aluminum and stainless steel structural components exposed to air - indoor uncontrolled and air - outdoor. for alumim:1m insulation jaskoting as well as srasking and loss of material of stainless stool insulation and insulation jaskoting exposed to air environments. Tho Strusturos Monitoring (B.2.1.34) program will sontinuo to be used to examine tho strustural sompononts and sonnostions aligned to this Item Number. The One-Time Inspection (B.2. 1.21) program will be used to manage loss of material and cracking of the stainless steel Containment Structure refueling bellows assemblies exposed to air - indoor uncontrolled and the stainless steel and aluminum thermal insulation and thermal insulation jacketing exposed to air - indoor uncontrolled and air - outdoor. These components will be included in the populations of stainless steel and aluminum SSCs exposed to air - indoor uncontrolled and air - outdoor which are subject to the inspection requirements of GALL-SLR AMP Xl.M32, Table Xl.M32-1 (e.g., EVT-1 Enhanced Visual). The Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems (B.2.1.13) program has been substituted and will be used to manage cracking and loss of material of aluminum and stainless steel cranes, hoists, and their associated structural bolting exposed to air - indoor uncontrolled in the Fuel Handling System. Cracking has not been identified as an aging effect at PBAPS for stainless steel and aluminum components or connections exposed to air environments, or as a result of exposure to secondary sources, indicating that the environments do not contain sufficient halides in the presence of moisture to result in sec. Assordingly, visual Visual inspections, as described above, sondusted in assordanso with tho One Time lnspestion (B.2.1.21 )program will be performed to confirm that loss of material due to pitting and crevice corrosion or cracking due to SCC are not occurring at a rate that affects the intended function of the structural components. Tho one time inspestions will be sondustod bot\\\\'eon tho 50th and eOth year of operation. If loss of material or srasking is identified during the one time inspestions and is suffisient to potentially attest tho intended funstion of tho stainless steel components or connections, the condition will be entered into the

May 2, 2019 Enclosure B Page 16 of 63 corrective action program. Depending upon tho conditions found, corrocti110 actions v,iill include tho actions such as tho following: (a) enhancing tho Structures Monitoring (B.2.1.;34) program and Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems (B.2.1.1d) program; (b) determining tho o*1:ont of condition by conducting a roprosontativo sample inspection consistent with tho E*1:ornal Surfaces Monitoring of Mechanical Components (B.2.1.24) program; or (c) developing a plant specific AMP to manage loss of material or cracking (as applicable).

May 2, 2019 Page 17 of 63 As a result of the response to RAI 3.5.2.2.2.4-1 provided in Enclosure A of this letter, SLRA Table 3.5.1, Item 3.5.1-01 O on page 3.5-62 of the SLRA is revised as shown below: Table 3.5.1 Summary of Aging Management Evaluations for the Containments, Structures and Component Supports Item Aging Aging Management Further Component Evaluation Discussion Number Effect/Mechanism Programs Recommended 3.5.1-010 Penetration sleeves; Cracking due to SCC AMP Xl.S1, "ASME Yes Consistent with NUREG-2191 with penetration bellows Section XI, Subsection exceptions. The 10 CFR Part 50, Appendix IWE," and AMP Xl.S4, J (B.2.1.32) program and ASME Section XI, "10 CFR Part 50, Subsection IWE (B.2.1.30) program will be Appendix J" used to manage cracking of the carbon steel, dissimilar metal welds, and stainless steel electrical and mechanical penetrations, mechanical penetration flued heads and bellows, aAG<:ontainment penetration sleeves, and containment closure bolting exposed to an air - indoor uncontrolled environment in the Containment Structure. Exceptions apply to the NUREG-2191 recommendations for ASME Section XI, Subsection IWE (B.2.1.30) program implementation. See Subsection 3.5.2.2.1.6.

May 2, 2019 Enclosure B Page 18 of 63 As a result of the response to RAI 3.5.2.2.2.4-1 provided in Enclosure A of this letter, SLRA Table 3.5.1, Item 3.5.1-037 on page 3.5-72 of the SLRA is revised as shown below: Table3.5.1 Summary of Aging Management Evaluations for the Containments, Structures and Component Supports Item Aging Aging Management Further Component Evaluation Discussion Number Effect/Mechanism Programs Recommended 3.5.1-037 Steel elements: Loss of material due AMP Xl.S1 I "ASME No Net Applisaele. suppression chamber to general (steel Section XI, Subsection +J::iis lteR'l ~h,1R'l8eF is Rat applisaele te tJ::ie (torus) liner (interior only), pitting, crevice IWE," and AMP Xl.S4, PBAPS MaFk I steel 69RtaiRR'leRt. +J::ie lteR'l surface) corrosion "10 CFR Part 50, ~l1;1R'!8eF is applisaele eRly te BW~ seRsFete AppendixJ" seRtaiRR'leRts witJ::i steel liReF plates. Consistent with NUREG-2191 with exceptions. The 10 CFR Part 50, Appendix J (B.2.1.32) program and ASME Section XI, Subsection /WE (B.2.1.30) program will be used to manage loss of material of the stainless steel containment closure bolting exposed to an air - indoor uncontrolled environment in the Containment Structure. Exceptions apply to the NUREG-2191 recommendations for ASME Section XI, Subsection /WE (B.2.1.30) program implementation.

May 2, 2019 Enclosure B Page 19 of 63 As a result of the response to RAI 3.5.2.2.2.4-1 provided in Enclosure A of this letter, SLRA Table 3.5.1, Items 3.5.1-099 and 100 beginning on page 3.5-109 of the SLRA is revised as shown below: Table 3.5.1 Summary of Aging Management Evaluations for the Containments, Structures and Component Supports Item Aging Aging Management Further Component Evaluation Discussion Number Effect/Mechanism Programs Recommended 3.5.1-099 Aluminum, stainless steel Loss of material due AMP Xl.M32, "One-Time Yes Consistent with NUREG-2191. Although support members; welds; to pitting and crevice Inspection," AMP Xl.S3, the review of plant-specific OE did not bolted connections; corrosion, cracking "ASME Section XI, reveal any instances of loss of material support anchorage to due to sec Subsection IWF," or AMP or cracking in stainless steel exposed to building structure Xl.M36, "External indoor or outdoor air, periodic Surfaces Monitoring of inspections in the ASME Section XI, Mechanical Components" Subsection IWF (B.2.1.31) program +he 0Ae Time IAspestieA (8.2.1.21) prngFam will be used to manage cracking and loss of material of the stainless steel structural bolting and stainless steel elements for ASME Class 1, 2, and 3 supports exposed to air - indoor uncontrolled and air - outdoor in the GeAlaiAmeAl SlF1:16l1:1Fe aAel Component Supports commodity group. See Subsection 3.5.2.2.2.4. 3.5.1-100 Aluminum, stainless steel Loss of material due AMP Xl.M32, "One-Time Yes Consistent with NUREG-2191. Although support members; welds; to pitting and crevice Inspection," AMP XI.SB, the review of plant-specific OE did not bolted connections; corrosion, cracking "Structures Monitoring," reveal any instances of loss of material support anchorage to due to sec or AMP Xl.M36, "External or cracking in aluminum and stainless building structure Surfaces Monitoring of steel exposed to indoor or outdoor air, Mechanical Components" periodic inspections in the Structures Monitoring (B.2.1.34) program Tl:!e 0Ae Time IAspestieA (Q.2.1.21) pmgFam will be used to manage cracking and loss of

Table 3.5.1 Item Number May 2, 2019 Enclosure B Paae 20 of 63 Summary of Aging Management Evaluations for the Containments, Structures and Component Supports Aging Aging Management Further Component Evaluation Discussion Effect/Mechanism Programs Recommended material of aluminum and stainless steel members and bolting, for embedments; conduit; equipment storage racks, expansion joints, fuel storage racks, hatches and plugs, hazard barriers, metal components-cable trays, wireway gutters, poles, and outdoor structures; iASlllatieA aAd iAslllatieA jaeketiA9; panels, racks, frames, cabinets, and other enclosures; penetration seals; roofing; spent fuel pool gates; steel elements-liner, liner anchors, integral attachments, aAd F9fll9liAfil eellews; structural miscellaneous - shielding, siding, and vents; supports for cable trays, conduit, HVAC ducts, tube track, instrument tubing, and non-ASME piping and components exposed to air-indoor uncontrolled and air-outdoor environments in the Circulating Water Pump Structure, CeAtaiAFAeAt, Outdoor Electric Switchgear, North Substation, Radwaste Building and Reactor Auxiliary Bay, Reactor Building, Recombiner Building, Stack, Station Blackout Structure and Foundations, and Turbine Building and Main Control Room Complex, as well as commodity groups Component Supports, Electrical and Instrumentation Enclosures and Raceways, Hazard Barriers and Elastomers, IAslllatieA, and Miscellaneous Steel. The One-Time Inspection (B.2.1.21) program will be used to manage loss of material and cracking of the stainless

Table 3.5.1 Item Number May 2, 2019 Enclosure B Paae 21of63 Summary of Aging Management Evaluations for the Containments, Structures and Component Supports Aging Aging Management Further Component Evaluation Discussion Effect/Mechanism Programs Recommended steel containment structure refueling bellows assemblies and the stainless steel and aluminum thermal insulation and thermal insulation jacketing exposed to air - indoor uncontrolled and air - outdoor environments in the Containment Structure and Insulation commodity group. The Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems (B.2.1.13) program has been substituted and will be used to manage cranes, hoists, and their associated structural bolting for loss of material in aluminum and cracking and loss of material in stainless steel exposed to air - indoor uncontrolled for the Fuel Handling System. See Subsection 3.5.2.2.2.4.

May 2, 2019 Enclosure B Page 22 of 63 As a result of the response to RAI 3.5.2.2.2.4-1 provided in Enclosure A of this letter, SLRA Table 3.5.2-3, on page 3.5-128 of the SLRA is revised as shown below. The table is abbreviated to show only affected line items. Line items not shown from the original SLRA are not revised and remain applicable. Table 3.5.2-3 Circulating Water Pump Structure Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG-2192 Notes Type Function Requiring Programs Item Table 1 Item ManaQement Hatches/Plugs Flood Barrier Stainless Steel Air - Indoor Cracking 0Re Time IRspestiaR lll.B2.T-37ab 3.5.1-100 A Missile Barrier Uncontrolled (B.2.1.21 )Structures Shelter and Monitoring (B.2.1.34) Protection Loss of Material 0Re Time lnspestiaR lll.B2.T-37ab 3.5.1-100 A Structural Support (B.2.1.21 )Structures Monitoring (B.2.1.34) Air - Outdoor Cracking 0Re Time IRspestiaR 111.B2.T-37ab 3.5.1-100 A (B.2.1.21 )Structures Monitoring (B.2.1.34) Loss of Material 0Re Time IRspestiaA lll.B2.T-37ab 3.5.1-100 A (B.2.1.21 )Structures Monitoring (B.2.1.34)

May2,2019 ~clo~reB P~e~cl~ As a result of the response to RAI 3.5.2.2.2.4-1 provided in Enclosure A of this letter, SLRA Table 3.5.2-4, on pages 3.5-132, 133, 134, 138, 142, and 144 of the SLRA is revised as shown below. The table is abbreviated to show only affected line items. Line items not shown from the original SLRA are not revised and remain applicable. Table 3.5.2-4 Component Supports Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG-2192 Notes Type Function Requiring Programs Item Table 1 Item Management Supports for ASME Structural Support Stainless Steel Air - Indoor Cracking 0Re TiFRe IRspestiaR lll.B1.1.T-36ab 3.5.1-099 A Class 1 piping and Uncontrolled (B.2.1.21) ASME Section components: XI, Subsection IWF constant and (8.2.1.311 variable load spring Loss of Material 0Re +iFRe IRspestiaR 111.81.1.T-36ab 3.5.1-099 A hangers; guides; (B.2.1.21) ASME Section stops XI, Subsection IWF (B.2.1.31)

Table 3.5.2-4 Component Supports Component Intended Material Environment Aging Effect Type Function Requiring Management Supports for ASME Structural Support Stainless Steel Air-Indoor Cracking Class 1 piping and Uncontrolled components: support members; welds; bolted Loss of Material connections; support anchorage to building structure Stainless Steel Air-Indoor Cracking Bolting Uncontrolled Loss of Material Aging Management Programs GRe +ime IRspestieR (B.2.1.21) ASME Section XI, Subsection IWF (B.2.1.31) GRe +ime IRspestieR (B.2.1.21) ASME Section XI, Subsection IWF (8.2.1.311 GRe +ime IRspestieR (B.2.1.21) ASME Section XI, Subsection IWF (B.2.1.31) GRe +ime IRspestieR (B.2.1.21) ASME Section XI, Subsection IWF (B.2.1.31) May 2, 2019 Enclosure B Page 24 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item 111.81.1.T-36ab 3.5.1-099 111.81.1.T-36ab 3.5.1-099 111.81.1.T-36ab 3.5.1-099 111.81.1.T-36ab 3.5.1-099 Notes A A c c

Table 3.5.2-4 Component Supports Component Intended Material Environment Aging Effect Type Function Requiring Manaqement Supports for ASME Structural Support Stainless Steel Air-Indoor Cracking Class 2 and 3 Uncontrolled piping and components: support members; Loss of Material welds; bolted connections; support anchorage to building structure Air - Outdoor Cracking Loss of Material Stainless Steel Air-Indoor Cracking Bolting Uncontrolled Loss of Material Aging Management Programs One Time lnspestien (B.2.1.21) ASME Section XI, Subsection IWF (B.2.1.31) One Time lnspestien (B.2.1.21) ASME Section XI, Subsection IWF (B.2.1.31) One Time lnspestien (B.2.1.21) ASME Section XI, Subsection IWF (B.2.1.31) One Time lnspestien (B.2.1.21) ASME Section XI, Subsection IWF (B.2.1.31) One Time lnspestien (B.2.1.21) ASME Section XI, Subsection IWF (8.2.1.31) One Time lnspestien (B.2.1.21) ASME Section XI, Subsection IWF (B.2.1.31) May 2, 2019 Enclosure B Page 25 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item 111.81.2.T-36ab 3.5.1-099 111.81.2.T-36ab 3.5.1-099 111.81.2.T-36ab 3.5.1-099 111.81.2.T-36ab 3.5.1-099 lll.B1.2.T-36ab 3.5.1-099 lll.B1.2.T-36ab 3.5.1-099 Notes A A A A A A

Table 3.5.2-4 Component Supports Component Intended Material Environment Type Function Supports for Cable Structural Support Aluminum Air - Outdoor Trays, Conduit, HVAC Ducts, Tube Track, Instrument Tubing, Non-ASME Piping and Components: support members; Aluminum Bolting Air - Outdoor welds; bolted connections; support anchorage to building structure Aging Effect Aging Management Requiring Programs Management Cracking 0Ae Time IAspestieA (B.2.1.21 )Structures Monitoring (B.2.1.34) Loss of Material 0Ae Time IAspestiaA (B.2.1.21 )Structures Monitorina (B.2.1.34J Cracking 0Ae Time IAspastiaA (~.2.1.21 )Structures Monitorina (B.2.1.34) Loss of Material 0Ae Time IAspestiaA (B.2.1.21 )Structures Monitoring (B.2.1.34) May 2, 2019 Page 26 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item lll.B2.T-37ab 3.5.1-100 111.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 Notes A A c c

Table 3.5.2-4 Component Supports Component Intended Material Environment Aging Effect Type Function Requiring Management Supports for Cable Structural Support Stainless Steel Air - Indoor Cracking Trays, Conduit, Uncontrolled HVAC Ducts, Tube Track, Instrument Tubing, Non-ASME Loss of Material Piping and Components: support members; welds; bolted Stainless Steel Air-Indoor Cracking connections; Bolting Uncontrolled support anchorage to building Loss of Material structure Air - Outdoor Cracking Loss of Material Aging Management Programs GRe +iR'le IRspestieR (B.2.1.21 )Structures Monitoring (B.2.1.34) GRe +iR'le IRspestieR (B.2.1.21 )Structures Monitoring (B.2.1.34) GRe +iR'le IRspestieR (B.2.1.21 )Structures Monitorina (B.2.1.34) GRe +iR'le IRspestieR (B.2.1.21 )Structures Monitoring (B.2.1.34) GRe +iR'le IRspestieR (B.2.1.21 )Structures Monitoring (B.2.1.34) GRe T"iR'le IRspestieR (B.2.1.21 )Structures Monitoring (B.2.1.34) May 2, 2019 Enclosure B Page 27 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 Notes A A A A A A

May 2, 2019 Enclosure B Page 28 of 63 As a result of the response to RAI 3.5.2.2.2.4-1 provided in Enclosure A of this letter, SLRA Table 3.5.2-5, on page 3.5-154 of the SLRA is revised as shown below. The table is abbreviated to show only affected line items. Line items not shown from the original SLRA are not revised and remain applicable. Table 3.5.2-5 Containment Structure Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG-2192 Notes Type Function Requiring Programs Item Table 1 Item Manaaement Bolting Structural Pressure Stainless Steel Air-Indoor Cracking 10 CFR Part 50, 11.84.CP-38 3.5.1-010 c (Containment Barrier Bolting Uncontrolled Appendix J (8.2.1.32) Closure) 0Ae TiA'le IAspestiaA lll.B1.a.T a.a.1 QQQ3.5.1-GD (B.2.1.21 )ASME Section d9all.84.CP-38 010 XI, Subsection /WE (8.2.1.30) Loss of Material 10 CFR Part 50, 11.81.2.C-49 3.5.1-037 c Appendix J (8.2.1.32) 0Aa TiA'le IAspestiaA lll.B1.a.T a.a.1 QQQ3.5.1-GD (B.2.1.21 )ASME Section d9all.81.2.C-49 037 XI, Subsection /WE (8.2.1.30) Structural Support Stainless Steel Air - Indoor Cracking 10 CFR Part 50, 11.84.CP-38 3.5.1-010 c Bolting Uncontrolled Appendix J (8.2.1.32) 0Ae TiA'le IAspestiaA lll.B1.a.T a.a.1 QQQ3.5.1-GD (B.2.1.21 )ASME Section d9all.84.CP-38 010 XI, Subsection /WE (8.2.1.30) Loss of Material 10 CFR Part 50, 11.81.2.C-49 3.5.1-037 c Aooendix J (8.2.1.32) 0Ae TiA'le IAspestiaA lll.B1.a.T a.a.1 QQQ3.5.1-GD (B.2.1.21 )ASME Section d9all.81.2.C-49 037 XI, Subsection /WE (8.2.1.30)

May 2, 2019 Enclosure B Page 29 of 63 As a result of the response to RAI 3.5.2.2.2.4-1 provided in Enclosure A of this letter, SLRA Table 3.5.2-8, on pages 3.5-178 through 180 of the SLRA is revised as shown below. The table is abbreviated to show only affected line items. Line items not shown from the original SLRA are not revised and remain applicable. Table 3.5.2-8 Electrical and Instrumentation Enclosures and Raceways Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG-2192 Notes Type Function Requiring Programs Item Table 1 Item Manaaement Conduit Shelter and Aluminum Air-Indoor Cracking GRe +iFRe IRspestiaR lll.82.T-37ab 3.5.1-100 A Protection Uncontrolled (B.2.1.21 )Structures Structural Support MonitorinQ (8.2.1.34J Loss of Material GRe +iFRa IRspastiaR lll.82.T-37ab 3.5.1-100 A (lil2.1.21 )Structures MonitorinQ (8.2.1.34) Air - Outdoor Cracking GRe +iFRe IRspestiaR lll.82.T-37ab 3.5.1-100 A (B.2.1.21 )Structures MonitorinQ (8.2.1.34J Loss of Material GRe +iFRe IRspestiaR lll.B2.T-37ab 3.5.1-100 A (B.2.1.21 )Structures Monitoring (B.2.1.34) Metal components Shelter and Aluminum Air - Indoor Cracking GRa +iFRe IRspastiaR lll.B2.T-37ab 3.5.1-100 A (cable tray and Protection Uncontrolled (B.2.1.21 )Structures wireway gutter) Structural Support Monitoring (B.2.1.34) Loss of Material GRe +iFRe IRspestiaR lll.82.T-37ab 3.5.1-100 A (B.2.1.21 )Structures Monitoring (B.2.1.34) Air - Outdoor Cracking GRe +iFRe IRspastiaR lll.B2.T-37ab 3.5.1-100 A (B.2.1.21 )Structures Monitorina (8.2.1.34J Loss of Material GRe +iFRe IRspestiaR lll.82.T-37ab 3.5.1-100 A (B.2.1.21 )Structures Monitoring (B.2.1.34)

Table 3.5.2-8 Electrical and Instrumentation Enclosures and Raceways Component Intended Material Environment Aging Effect Aging Management Type Function Requiring Programs Management Metal components Shelter and Stainless Steel Air - Indoor Cracking 0Re TiR'le IRspestieR (cable tray and Protection Bolting Uncontrolled (B.2.1.21 )Structures wireway gutter) Structural Support Monitoring (B.2.1.34) Loss of Material 0Re TiR'le IRspestieR (B.2.1.21 )Structures Monitoring (B.2.1.34) Air - Outdoor Cracking 0Re TiR'le IRspestieR (B.2.1.21 )Structures Monitoring (B.2.1.34) Loss of Material 0Re TiR'le IRspestieR (B.2.1.21 )Structures Monitoring (B.2.1.34) Panels, Racks, Shelter and Aluminum Air - Indoor Cracking 0Re TiR'le IRspestieR Frames, Cabinets, Protection Uncontrolled (B.2.1.21 )Structures and Other Structural Support Monitoring (B.2.1.34) Enclosures (Boxes May 2, 2019 Enclosure B Page 30 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item lll.B2.T-37ab 3.5.1-100 lll.82.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 Notes A A A A A

Table 3.5.2-8 Electrical and Instrumentation Enclosures and Raceways Component Intended Material Environment Aging Effect Aging Management Type Function Requiring Programs Management Panels, Racks, Shelter and Aluminum Air-Indoor Loss of Material 0Re Time IRSflestioR Frames, Cabinets, Protection Uncontrolled (B.2.1.21 )Structures and Other Structural Support Monitorina (8.2.1.34J Enclosures (Boxes: Air - Outdoor Cracking 0Re Time IRSflestioR (B.2.1.21 )Structures Monitoring (B.2.1.34) Loss of Material 0Re Time IRsfJestioR (B.2.1.21 )Structures Monitoring (B.2.1.34) Aluminum Bolting Air-Indoor Cracking 0Re Time IRSflestioR Uncontrolled (B.2.1.21 )Structures Monitoring (B.2.1.34) Loss of Material 0Re Time IRSflestioR (B.2.1.21 )Structures Monitoring (B.2.1.34) Air - Outdoor Cracking 0Re Time IRSflestioR (B.2.1.21 )Structures Monitorina (B.2.1.34} Loss of Material 0Re Time IRSflestioR (B.2.1.21 )Structures Monitoring (B.2.1.34) May 2, 2019 Enclosure B Page 31of63 NUREG-2191 NUREG-2192 Item Table 1 ltem lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 ffl.B2.T-37ab 3.5.1-100 Notes A A A A A A A

May 2, 2019 Enclosure B Page 32 of 63 As a result of the response to RAI 3.5.2.2.2.4-1 provided in Enclosure A of this letter, SLRA Table 3.5.2-10, on pages 3.5-198 through 202 of the SLRA is revised as shown below. The table is abbreviated to show only affected line items. Line items not shown from the original SLRA are not revised and remain applicable. Table 3.5.2-10 Hazard Barriers and Elastomers Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG-2192 Notes Type Function Requiring Programs Item Table 1 Item Management Expansion Joints Expansion/ Aluminum Air-Indoor Cracking 0Ae TiFRe IAsµestieA lll.82.T-37ab 3.5.1-100 c Separation Uncontrolled (B.2.1.21 )Structures Monitoring (B.2.1.34) Loss of Material 0Ae TiFRe IAsµestieA lll.82.T-37ab 3.5.1-100 c (8.2.1.21 )Structures Monitoring (B.2.1.34)

Table 3.5.2-10 Hazard Barriers and Elastomers Component Intended Material Environment Aging Effect Type Function Requiring Management Hazard Barrier Shelter and Aluminum Air-Indoor Cracking Protection Uncontrolled Loss of Material Hazard Barrier Structural Support Stainless Steel Air - Indoor Cracking (permanent lead Uncontrolled shielding blankets) Loss of Material Aging Management Programs One TiFRe lnspestien (B.2.1.21 )Structures Monitoring (B.2.1.34) One TiFRe lnspestien (B.2.1.21 )Structures MonitorinQ fB.2.1.34J One TiFRe lnspestien (B.2.1.21 )Structures Monitoring (B.2.1.34) One TiFRe lnspestien (B.2.1.21 )Structures Monitoring (B.2.1.34) May 2, 2019 Enclosure B Page 33 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 Notes A A A A

Table 3.5.2-10 Hazard Barriers and Elastomers Component Intended Material Environment Aging Effect Type Function Requiring ManaQement Penetration Seals Flood Barrier Stainless Steel Air-Indoor Cracking Shelter and Uncontrolled Protection Structural Support Loss of Material HELB/MELB Stainless Steel Air-Indoor Cracking Shielding Uncontrolled Loss of Material Aging Management Programs 0Re TiFRe IRspestieR (B.2.1.21 )Structures Monitoring (B.2.1.34) 0Re TiFRe IRspestieR (B.2.1.21 )Structures Monitoring (B.2.1.34) 0Re TiFRe IRspestieR (B.2.1.21 )Structures Monitoring (B.2.1.34) 0Re TiFRe IRspestieR (B.2.1.21 )Structures Monitoring (B.2.1.34) May 2, 2019 Enclosure B Page 34 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 Notes A A A A

Table 3.5.2-10 Hazard Barriers and Elastomers Component Intended Material Environment Aging Effect Type Function Requiring Management Penetration Seals Shielding Stainless Steel Air-Indoor Cracking Uncontrolled Loss of Material Structural Pressure Stainless Steel Air - Indoor Cracking Barrier Uncontrolled Loss of Material Aging Management Programs 0Re Time IRspestieR (8.2.1.21 )Structures Monitoring (B.2.1.34) GRe +ime IRspestieR (8.2.1.21 )Structures Monitoring (B.2.1.34) 0Re Time IRspestieR (8.2.1.21 )Structures Monitoring (B.2.1.34) 0Re +ime IRspestieR (8.2.1.21 )Structures Monitoring (B.2.1.34) May 2, 2019 Enclosure B Page 35 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 Notes A A A c

May 2, 2019 Enclosure B Page 36 of 63 As a result of the response to RAI 3.5.2.2.2.4-1 provided in Enclosure A of this letter, SLRA Table 3.5.2-12, on pages 3.5-211 through 213 of the SLRA is revised as shown below. The table is abbreviated to show only affected line items. Line items not shown from the original SLRA are not revised and remain applicable. Table 3.5.2-12 Miscellaneous Steel Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG-2192 Notes Type Function Requiring Programs Item Table 1 Item Management Metal components Direct Flow Aluminum Air - Indoor Cracking GAe Time IAspestieA lll.82.T-37ab 3.5.1-100 A Shelter and Uncontrolled (B.2.1.21 )Structures Protection Monitoring (B.2.1.34) Loss of Material GAe Time IAspestieA lll.82.T-37ab 3.5.1-100 A (B.2.1.21 )Structures Monitoring (B.2.1.34) Air - Outdoor Cracking GAe Time IAspestieA lll.82.T-37ab 3.5.1-100 A (B.2.1.21 )Structures Monitoring (B.2.1.34) Loss of Material GAa Time IAspestieA lll.82.T-37ab 3.5.1-100 A (B.2.1.21 )Structures Monitoring (B.2.1.34)

Table 3.5.2-12 Miscellaneous Steel Component Intended Material Environment Aging Effect Type Function Requiring Manaaement Metal components Direct Flow Stainless Steel Air - Indoor Cracking Shelter and Uncontrolled Protection Loss of Material Air - Outdoor Cracking Loss of Material Structural Direct Flow Aluminum Air - Indoor Cracking Miscellaneous - Shelter and Uncontrolled Vents Protection Loss of Material Air - Outdoor Cracking Loss of Material Aging Management Programs 0Ae Time IAspestieA (B.2.1.21 )Structures MonitorinQ (8.2.1.34) 0Ae Time IAspestieA (B.2.1.21 )Structures MonitorinQ (8.2.1.34) 0Ae Time IAspestieA (B.2.1.21 )Structures Monitorinf:I (8.2.1.34} 0Ae Time IAspestieA (B.2.1.21 )Structures Monitorinf:I (8.2.1.34) 0Ae Time IAspestieA (B.2.1.21) Structures Monitoring (8.2.1.34) 0Ae Time IAspestieA (B.2.1.21 )Structures Monitorina (8.2.1.34) 0Ae Time IAspestieA (B.2.1.21 )Structures Monitorina (8.2.1.341 0Ae Time IAspestieA (B.2.1.21 )Structures Monitoring (8.2.1.34) May 2, 2019 Enclosure B Page 37 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 Notes A A A A A A A A

May 2, 2019 Enclosure B Page 38 of 63 As a result of the response to RAI 3.5.2.2.2.4-1 provided in Enclosure A of this letter, SLRA Table 3.5.2-14, on pages 3.5-220 and 223 of the SLRA is revised as shown below. The table is abbreviated to show only affected line items. Line items not shown from the original SLRA are not revised and remain applicable. Table 3.5.2-14 Outdoor Electric Switchgear, North Substation Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG-2192 Notes Type Function Requiring Programs Item Table 1 Item Manaqement Bolting (Structural) Structural Support Aluminum Bolting Air - Indoor Cracking GAe +iR'le IAspesliGA lll.B2.T-37ab 3.5.1-100 A Uncontrolled (8.2.1.21 )Structures Monitorina (8.2.1.34) Loss of Material GAe +iR'le IAspesliGA lll.B2.T-37ab 3.5.1-100 A (8.2.1.21 )Structures Monitorina (8.2.1.34) Air - Outdoor Cracking GAe +iR'le IAspesliGA lll.B2.T-37ab 3.5.1-100 A (8.2.1.21 )Structures Monitorina (8.2.1.34) Loss of Material GAe +iR'le IAspesliGA lll.B2.T-37ab 3.5.1-100 A (8.2.1.21 )Structures Monitorina (8.2.1.34)

Table 3.5.2-14 Outdoor Electric Switchgear, North Substation Component Intended Material Environment Aging Effect Type Function Requiring ManaQement Metal components Structural Support Aluminum Air - Outdoor Cracking (includes poles and outdoor structures) Loss of Material Aging Management Programs One Time lnspestien (B.2.1.21 )Structures Monitorina (8.2.1.34J One Time lnspestien (B.2.1.21 )Structures Monitoring (B.2.1.34) May 2, 2019 Enclosure B Page 39 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item lll.82.T-37ab 3.5.1-100 lll.82.T-37ab 3.5.1-100 Notes A A

May 2, 2019 Enclosure B Page 40 of 63 As a result of the response to RAI 3.5.2.2.2.4-1 provided in Enclosure A of this letter, SLRA Table 3.5.2-15, on pages 3.5-231 and 232 of the SLRA is revised as shown below. The table is abbreviated to show only affected line items. Line items not shown from the original SLRA are not revised and remain applicable. Table 3.5.2-15 Radwaste Building and Reactor Auxiliary Bay Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG-2192 Notes Type Function Requiring Programs Item Table 1 Item Management Structural Shelter and Stainless Steel Air-Indoor Cracking GAe :+iFAe IAs1:1estieA lll.B2.T-37ab 3.5.1-100 A Miscellaneous - Protection Bolting Uncontrolled (B.2.1.21 )Structures Siding Monitoring (B.2.1.34) Loss of Material 0Ae :+iFAe IASJ:ISStieA lll.B2.T-37ab 3.5.1-100 A (B.2.1.21 )Structures Monitoring (B.2.1.34)

Table 3.5.2-15 Radwaste Building and Reactor Auxiliary Bay Component Intended Material Environment Aging Effect Type Function Requiring ManaQement Structural Shelter and Stainless Steel Air - Outdoor Cracking Miscellaneous - Protection Bolting Siding Loss of Material Aging Management Programs GRe +ime IRSJ:iestieR {B.2.1.21 )Structures Monitoring (B.2.1.34J GRe +ime IRSJ:iestieR {B.2.1.21 )Structures Monitoring (B.2.1.34) May 2, 2019 Page 41 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item 111.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 Notes A A

May 2, 2019 Enclosure B Page 42 of 63 As a result of the response to RAI 3.5.2.2.2.4-1 provided in Enclosure A of this letter, SLRA Table 3.5.2-16, on pages 3.5-234, 235, and 238 through 246 of the SLRA is revised as shown below. The table is abbreviated to show only affected line items. Line items not shown from the original SLRA are not revised and remain applicable. Table 3.5.2-16 Reactor Building Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG-2192 Notes Type Function Requiring Programs Item Table 1 Item Management Bolting (Structural) Structural Support Stainless Steel Air-Indoor Cracking One Time lnspestien lll.B2.T-37ab 3.5.1-100 A Bolting Uncontrolled (8.2.1.21 )Structures Monitoring (B.2.1.34) Loss of Material One Time lnspestien lll.B2.T-37ab 3.5.1-100 A (8.2.1.21 )Structures Monitoring (B.2.1.34)

Table 3.5.2-16 Reactor Building Component Intended Material Environment Aging Effect Type Function Requiring Management !Concrete elements: Structural Support Stainless Steel Air - Indoor Cracking Embedments Uncontrolled Loss of Material Aging Management Programs 0Re Time IRspestieR (B.2.1.21 )Structures Monitoring (B.2.1.34J 0Re Time IRspestieA (B.2.1.21) Structures Monitoring (B.2.1.34) May 2, 2019 Enclosure B Page 43 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item lll.B2.T-37ab 3.5.1-100 111.B2.T-37ab 3.5.1-100 Notes c c

Table 3.5.2-16 Reactor Building Component Intended Material Environment Aging Effect Type Function Requiring Management Equipment Storage Structural Support Stainless Steel Air - Indoor Cracking Racks (inside Uncontrolled spentfuelpooland reactor well) Loss of Material Aging Management Programs GRe +ime IRspestieR (8.2.1.21 )Structures Monitorin!I (8.2.1.34) GRe Time IRspestieR (8.2.1.21 )Structures Monitoring (B.2.1.34) May 2, 2019 Enclosure B Page 44 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item lll.82.T-37ab 3.5.1-100 lll.82.T-37ab 3.5.1-100 Notes A A

Table 3.5.2-16 Reactor Building Component Intended Material Environment Aging Effect Type Function Requiring ManaQement Fuel Storage Structural Support Stainless Steel Air-Indoor Cracking Racks {New Fuel) Uncontrolled Loss of Material Aging Management Programs GRe +ime IRspestieR (B.2.1.21 )Structures Monitoring (B.2.1.34) GRe +ime IRspestieR (B.2.1.21 )Structures Monitoring (B.2.1.34) May 2, 2019 Enclosure B Page 45 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 Notes A A

Table 3.5.2-16 Reactor Building Component Intended Material Environment Aging Effect Type Function Requiring Manaaement Metal components Direct Flow Stainless Steel Air - Indoor Cracking Uncontrolled Loss of Material Aging Management Programs GRe +ime IRspestieR (B.2.1.21 )Structures Monitorina (8.2.1.34J GRe +ime IRspestieR (B.2.1.21 )Structures Monitorina (8.2.1.34J May 2, 2019 Enclosure B Page 46 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item lll.82.T-37ab 3.5.1-100 lll.82.T-37ab 3.5.1-100 Notes A A

Table 3.5.2-16 Reactor Building Component Intended Material Environment Aging Effect Type Function Requiring ManaQement Metal components Shelter and Aluminum Air - Indoor Cracking Protection Uncontrolled Loss of Material Structural Support Aluminum Air-Indoor Cracking Uncontrolled Loss of Material Stainless Steel Air-Indoor Cracking Uncontrolled Loss of Material Aging Management Programs 0Ae Time IAspestieA (8.2.1.21 )Structures Monitoring (B.2.1.34) 0Ae Time IAspestieA (B.2.1.21 )Structures Monitoring (B.2.1.34) 0Ae Time IAspestieA (8.2.1.21 )Structures Monitoring (B.2.1.34) 0Ae Time IAspestieA (8.2.1.21 )Structures Monitoring (B.2.1.34) 0Ae Time IAspestieA (8.2.1.21 )Structures Monitoring (B.2.1.34) 0Ae Time IAspestieA (8.2.1.21 )Structures Monitoring (B.2.1.34) May 2, 2019 Enclosure B Page 47 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item lfl.82.T-37ab 3.5.1-100 lfl.B2.T-37ab 3.5.1-100 lfl.82.T-37ab 3.5.1-100 lfl.82.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lfl.B2.T-37ab 3.5.1-100 Notes A A A A A A

Table 3.5.2-16 Reactor Building Component Intended Material Environment Aging Effect Type Function Requiring ManaQement Spent fuel pool Water Retaining Aluminum Air-Indoor Cracking gates Boundary Uncontrolled Loss of Material Aluminum Bolting Air-Indoor Cracking Uncontrolled Loss of Material Stainless Steel Air - Indoor Cracking Uncontrolled Loss of Material Aging Management Programs GAs +ims IAspsstisA (B.2.1.21 )Structures Monitoring (B.2.1.34) GAS +ims IAspsstieA (B.2.1.21 )Structures Monitoring (B.2.1.34) GAs +ims IAspsstieA (B.2.1.21 )Structures Monitoring (B.2.1.34) GAs +ims IAspsstieA (B.2.1.21 )Structures Monitoring (B.2.1.34) GAs +ims IAspsstieA (B.2.1.21 )Structures MonitorinQ (B.2.1.34) GAs +ims IAspsstieA (B.2.1.21 )Structures Monitoring (B.2.1.34) May 2, 2019 Page 48 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 Notes A A A A A A

Table 3.5.2-16 Reactor Building Component Intended Material Environment Type Function Spent fuel pool Water Retaining Stainless Steel Air-Indoor gates Boundary Bolting Uncontrolled Steel elements: Structural Support Stainless Steel Air - Indoor Liner, liner Uncontrolled anchors, integral attachments - accessible areas Aging Effect Aging Management Requiring Programs Management Cracking 0Ae Time IAspestieA (R2.1.21 )Structures Monitoring (B.2.1.34) Loss of Material 0Ae Time IAspestieA (R2.1.21 )Structures Monitoring (B.2.1.34) Cracking 0Ae Time IAspestieA (B.2.1.21 )Structures Monitoring (B.2.1.34) Loss of Material 0Ae Time IAspestieA (R2.1.21 )Structures Monitoring (B.2.1.34) May 2, 2019 Enclosure B Page 49 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item lll.B2.T-37ab 3.5.1-100 111.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 Notes A A A A

Table 3.5.2-16 Reactor Building Component Intended Material Environment Aging Effect Type Function Requiring Manaaement Steel elements: Water Retaining Stainless Steel Air - Indoor Cracking Liner, liner Boundary Uncontrolled anchors, integral attachments - accessible areas Loss of Material Steel elements: Structural Support Stainless Steel Air - Indoor Cracking Liner, liner Uncontrolled anchors, integral attachments - Loss of Material inaccessible areas Water Retaining Stainless Steel Air-Indoor Cracking Boundary Uncontrolled Loss of Material Aging Management Programs One Time lnspestian (B.2.1.21 )Structures Monitoring (B.2.1.34) One Time lnspastian (B.2.1.21 )Structures Monitoring (B.2.1.34) One Time lnspestian (B.2.1.21 )Structures Monitoring (B.2.1.34) One Time lnspestian (B.2.1.21 )Structures Monitoring (B.2.1.34) One Time lnspestian (B.2.1.21 )Structures Monitoring (B.2.1.34) One Time lnspestian (B.2.1.21 )Structures Monitoring (B.2.1.34) May 2, 2019 Enclosure B Page 50 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item 111.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 Notes A A A A A A

Table 3.5.2-16 Reactor Building Component Intended Material Environment Type Function Structural Shielding Aluminum Air-Indoor Miscellaneous - Uncontrolled Shielding Structural Shelter and Stainless Steel Air - Indoor Miscellaneous - Protection Bolting Uncontrolled Siding Structural Pressure Barrier Aging Effect Aging Management Requiring Programs Manaaement Cracking 0Ae Time IAs~estioA (B.2.1.21 )Structures Monitoring (B.2.1.34) Loss of Material 0Ae Time IAs~estioA (B.2.1.21 )Structures Monitoring (B.2.1.34) Cracking 0Ae Time IAs~estioA (B.2.1.21 )Structures Monitoring (B.2.1.34) Loss of Material 0Ae Time IAs~estioA (B.2.1.21 )Structures Monitoring (B.2.1.34) May 2, 2019 Enclosure B Page 51of63 NUREG-2191 NUREG-2192 Item Table 1 Item lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 Notes A A A A

Table 3.5.2-16 Reactor Building Component Intended Material Environment Aging Effect Type Function Requiring Management Structural Shelter and Stainless Steel Air - Outdoor Cracking Miscellaneous - Protection Bolting Siding Structural Pressure Barrier Loss of Material Structural Pressure Relief Aluminum Air - Indoor Cracking Miscellaneous - Shelter and Uncontrolled Vents (blowout Protection panels) Structural Pressure Loss of Material Barrier Air - Outdoor Cracking Loss of Material Aluminum Bolting Air-Indoor Cracking Uncontrolled Loss of Material Air - Outdoor Cracking Loss of Material Aging Management Programs 0Ae Time IAspestieA (8.2.1.21 )Structures Monitoring (B.2.1.34) 0Ae Time IAspestieA (8.2.1.21 )Structures Monitoring (B.2.1.34) 0Ae Time IAspestieA (8.2.1.21 )Structures Monitoring (B.2.1.34) 0Ae Time IAspestieA (8.2.1.21 )Structures Monitoring (B.2.1.34) 0Ae Time IAspestieA (8.2.1.21 )Structures Monitoring (B.2.1.34) 0Ae Time IAspestieA (8.2.1.21 )Structures Monitoring (B.2.1.34) 0Ae Time IAspestieA (8.2.1.21 )Structures Monitoring (B.2.1.34) 0Ae Time IAspestieA (8.2.1.21 )Structures Monitorina (8.2.1.34J 0Ae Time IAspestieA (8.2.1.21 )Structures Monitoring (B.2.1.34J 0Ae Time IAspestieA (8.2.1.21 )Structures Monitoring (B.2.1.34) May 2, 2019 Enclosure B Page 52 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 Notes A A A A A A A A A A

May 2, 2019 Enclosure B Page 53 of 63 As a result of the response to RAI 3.5.2.2.2.4-1 provided in Enclosure A of this letter, SLRA Table 3.5.2-17, on pages 3.5-253 and 254 of the SLRA is revised as shown below. The table is abbreviated to show only affected line items. Line items not shown from the original SLRA are not revised and remain applicable. Table 3.5.2-17 Recombiner Building Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG-2192 Notes Type Function Requiring Programs Item Table 1 Item Management Structural Shelter and Aluminum Air-Indoor Cracking Ona Time lnspastion lll.82.T-37ab 3.5.1-100 A Miscellaneous - Protection Uncontrolled (Q.2.1.21 )Structures Siding Structural Support Monitoring (B.2.1.34) Loss of Material One Time lnspastion lll.82.T-37ab 3.5.1-100 A (Q.2.1.21 )Structures Monitoring (B.2.1.34J Air - Outdoor Cracking Ona Time lnspastion lll.82.T-37ab 3.5.1-100 A (Q.2.1.21 )Structures Monitoring (8.2.1.34J Loss of Material Ona Timo lnspastion lll.B2.T-37ab 3.5.1-100 A (Q.2.1.21 )Structures Monitorina (8.2.1.34J Stainless Steel Air-Indoor Cracking Ona Time lnspastion lll.82.T-37ab 3.5.1-100 A Bolting Uncontrolled (Q.2.1.21 )Structures MonitorinQ (B.2.1.34) Loss of Material Ona Time lnspastion lll.82.T-37ab 3.5.1-100 A (B.2.1.21 )Structures Monitoring (B.2.1.34)

Table 3.5.2-17 Recombiner Building Component Intended Material Environment Aging Effect Type Function Requiring ManaQement Structural Shelter and Stainless Steel Air - Outdoor Cracking Miscellaneous - Protection Bolting Siding Structural Support Loss of Material Aging Management Programs GAe +ime IAspesUeA (R2.1.21 )Structures Monitoring (8.2.1.34) GAe +ime IAspestieA (8.2.1.21 )Structures Monitoring (B.2.1.34) May 2, 2019 Enclosure B Page 54 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item lll.B2.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 Notes A A

May 2, 2019 Enclosure B Page 55 of 63 As a result of the response to RAI 3.5.2.2.2.4-1 provided in Enclosure A of this letter, SLRA Table 3.5.2-18, on page 3.5-259 of the SLRA is revised as shown below. The table is abbreviated to show only affected line items. Line items not shown from the original SLRA are not revised and remain applicable. Table 3.5.2-18 Stack Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG-2192 Notes Type Function Requiring Programs Item Table 1 Item ManaQement Roofing Shelter and Stainless Steel Air - Outdoor Cracking GRe +ime IRspestieR lll.B2.T-37ab 3.5.1-100 A Protection Bolting (B.2.1.21 )Structures Monitoring (B.2.1.34) Loss of Material GRe +ime IRspestieR lll.B2.T-37ab 3.5.1-100 A (Q.2.1.21 )Structures Monitorina (8.2.1.34J

May 2, 2019 Page 56 of 63 As a result of the response to RAI 3.5.2.2.2.4-1 provided in Enclosure A of this letter, SLRA Table 3.5.2-19, on pages 3.5-262, 263, and 267 of the SLRA is revised as shown below. The table is abbreviated to show only affected line items. Line items not shown from the original SLRA are not revised and remain applicable. Table 3.5.2-19 Station Blackout Structure and Foundations Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG-2192 Notes Type Function Requiring Programs Item Table 1 Item ManaQement Bolting (Structural) Structural Support Aluminum Bolting Air-Indoor Cracking GAe +ime IAspes&ieA lll.B2.T-37ab 3.5.1-100 A Uncontrolled (8.2.1.21 )Structures Monitoring (B.2.1.34) Loss of Material GAe +ime IAspeslieA 111.B3.T-37ab 3.5.1-100 A (121.2.1.21 )Structures Monitoring (B.2.1.34J Air - Outdoor Cracking GAe +ime IAspeslieA lll.B2.T-37ab 3.5.1-100 A (B.2.1.21 )Structures Monitoring (B.2.1.34J Loss of Material GAe +ime IAspeslieA lll.B3.T-37ab 3.5.1-100 A (B.2.1.21 )Structures Monitoring (B.2.1.34J

Table 3.5.2-19 Station Blackout Structure and Foundations Component Intended Material Environment Aging Effect Type Function Requiring Management Concrete elements: Structural Support Stainless Steel Air - Indoor Cracking Embedments Uncontrolled Loss of Material Air - Outdoor Cracking Loss of Material Aging Management Programs 0Re Time IRspestieR (B.2.1.21 )Structures Monitoring (B.2.1.34) 0Re Time IRspestieR (B.2.1.21 )Structures Monitoring (B.2.1.34) 0Re Time IRspestieR (B.2.1.21 )Structures Monitorina (B.2.1.34) 0Re Time IRspestieR (B.2.1.21 )Structures Monitoring (B.2.1.34) May 2, 2019 Enclosure B Page 57 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item lll.82.T-37ab 3.5.1-100 lll.83.T-37ab 3.5.1-100 lll.B2.T-37ab 3.5.1-100 lll.83.T-37ab 3.5.1-100 Notes A A A A

Table 3.5.2-19 Station Blackout Structure and Foundations Component Intended Material Environment Aging Effect Type Function Requiring ManaQement Metal components Structural Support Aluminum Air - Outdoor Cracking Loss of Material Aging Management Programs GAs +ims IAs~sstieA (Q.2.1.21 )Structures Monitoring (B.2.1.34) GAs +ims IAs~sstieA (Q.2.1.21 )Structures Monitoring (B.2.1.34) May 2, 2019 Enclosure B Page 58 of 63 NUREG-2191 NUREG-2192 Item Table 1 Item lll.82.T-37ab 3.5.1-100 lll.83.T-37ab 3.5.1-100 Notes A A

May 2, 2019 Enclosure B Page 59 of 63 As a result of the response to RAI 3.5.2.2.2.4-1 provided in Enclosure A of this letter, SLRA Table 3.5.2-20, on pages 3.5-275 of the SLRA is revised as shown below. The table is abbreviated to show only affected line items. Line items not shown from the original SLRA are not revised and remain applicable. Table 3.5.2-20 Turbine Building and Main Control Room Complex Component Intended Material Environment Aging Effect Aging Management NUREG-2191 NUREG-2192 Notes Type Function Requiring Programs Item Table 1 Item Management Structural Shelter and Stainless Steel Air-Indoor Cracking One Time lnspestian lll.B2.T-37ab 3.5.1-100 A Miscellaneous - Protection Bolting Uncontrolled (B.2.1.21 )Structures Siding Monitoring (B.2.1.34) Loss of Material One Time lnspestian lll.B2.T-37ab 3.5.1-100 A (B.2.1.21 )Structures Monitoring (B.2.1.34) Air - Outdoor Cracking One Time lnspestien lll.B2.T-37ab 3.5.1-100 A (B.2.1.21 )Structures Monitorina fB.2.1.34J Loss of Material One Time lnspestien lll.B2.T-37ab 3.5.1-100 A (B.2.1.21 )Structures Monitoring (B.2.1.34)

May 2, 2019 Enclosure B Page 60 of 63 As a result of the response to RAI 3.3.2.2.7-1 provided in Enclosure A of this letter, SLRA Appendix A, Section A.2.1.11 on page A-20 of the SLRA is revised as shown below: A.2.1.11 Open-Cycle Cooling Water System Additional Enhancements 2 and 3

2.

Perform a minimum of 20 inspections for recurring internal corrosion in the raw water cooling water systems every 24 months until the rate of recurring internal corrosion occurrences no longer meets the criteria for recurring internal corrosion as defined in SLRA Section 3.3.2.2. 7. The selected inspection locations will be periodically reviewed to validate their relevance and usefulness and adjusted as appropriate. Evaluation of the inspection results will include (1) a comparison to the nominal wall thickness or previous wall thickness measurements to determine rate of corrosion degradation; (2) a comparison to the design minimum allowable wall thickness to determine the acceptability of the component for continued use; and (3) a determination of reinspection interval.

3. Provide procedural direction to require the use of a mill tolerance of 12.5%

for added conservatism when determining corrosion rates at new inspection locations if corrosion rates from other locations with nearly identical operating conditions, material, size, and configuration cannot be used. +Ris These enhancements will be implemented no later than six months prior to the second period of extended operation.

May 2, 2019 Enclosure B Page 61 of 63 As a result of the response to RAI 3.3.2.2.7-1 provided in Enclosure A of this letter, SLRA Appendix A, Section A.2.1.17 beginning on page A-25 of the SLRA is revised as shown below: A.2.1.17 Fire Water System Additional Enhancements 17 and 18

17. Perform at least five additional ultrasonic test inspections on the fire water supply piping for each Fire Water System pipe wall inspection that does not meet acceptance criteria.

18. Provide procedural direction to require the use of a mill tolerance of 12.5%

for added conservatism when determining corrosion rates at new inspection locations if corrosion rates from other locations with nearly identical operating conditions, material, size, and configuration cannot be used.

May 2, 2019 Enclosure B Page 62 of 63 As a result of the response to RAI 3.3.2.2.7-1 provided in Enclosure A of this letter, SLRA Appendix 8, Section B.2.1.11 beginning on page B-71 of the SLRA is revised as shown below: B.2.1.11 Open-Cycle Cooling Water System Additional Enhancements 2 and 3

2.

Perform a minimum of 20 inspections for recurring internal corrosion in the raw water cooling water systems every 24 months until the rate of recurring internal corrosion occurrences no longer meets the criteria for recurring internal corrosion as defined in SLRA Section 3.3.2.2. 7. The selected inspection locations will be periodically reviewed to validate their relevance and usefulness and adjusted as appropriate. Evaluation of the inspection results will include (1) a comparison to the nominal wall thickness or previous wall thickness measurements to determine rate of corrosion degradation; (2) a comparison to the design minimum allowable wall thickness to determine the acceptability of the component for continued use; and (3) a determination of reinspection interval. Program Element Affected: Program Elements Affected: Parameters Monitored/Affected (Element 3)1 Detection of Aging Effects (Element 4)1 Monitoring and Trending (Element 5)

3. Provide procedural direction to require the use of a mill tolerance of 12.5%

for added conservatism when determining corrosion rates at new inspection locations if corrosion rates from other locations with nearly identical operating conditions, material, size, and configuration cannot be used. Program Element Affected: Monitoring and Trending (Element 5)

May 2, 2019 Page 63 of 63 As a result of the response to RAI 3.3.2.2.7-1 provided in Enclosure A of this letter, SLRA Appendix 8, Section 8.2.1.17 beginning on page 8-102 of the SLRA is revised as shown below: 8.2.1.17 Fire Water System Additional Enhancements 17 and 18

17. Perform at least five additional ultrasonic test inspections on the fire water supply piping for each Fire Water System pipe wall inspection that does not meet acceptance criteria. Program Elements Affected: Corrective Actions (Element 7)

18. Provide procedural direction to require the use of a mill tolerance of 12.5%

for added conservatism when determining corrosion rates at new inspection locations if corrosion rates from other locations with nearly identical operating conditions, material, size, and configuration cannot be used. Program Element Affected: Monitoring and Trending (Element 5)

Enclosure C PBAPS Subsequent License Renewal Commitment List Updates This Enclosure identifies commitments made in this document and is an update to the P8APS SLRA Appendix A, Section A.5 Subsequent License Renewal Commitment List. Any other actions discussed in the submittal represent intended or planned actions. They are described to the NRC for the NRC's information and are not regulatory commitments. Changes to the P8APS SLRA Appendix A, Section A.5 Subsequent License Renewal Commitment List are as a result of the Exelon response to the following RAls: RAI 8.2.1.36-1 RAI 8.2.1.17-1 RAI 8.2.1.17-2 RAI 8.2.1.17-3 RAI B.2.1.17-4 RAI 3.3.2.2.7-1 Note: To facilitate understanding, relevant portions of the previously submitted Subsequent License Renewal Commitment List have been repeated in this Enclosure, with revisions indicated. Previously submitted information is shown in normal font. Changes due to this submittal are highlighted with balded italics for inserted text and strikethroughs for deleted text.

May 2, 2019 Enclosure C Page 1of5 As a result of the response to RAI B.2.1.36-1 provided in Enclosure A of this letter, SLRA Appendix A, Section A.5, Commitment 36 on page A-111 of the SLRA is revised as shown below. NO. PROGRAM OR COMMITMENT IMPLEMENTATION SOURCE TOPIC SCHEDULE* 36 Protective Coating Protective Coating Monitoring and Maintenance Program is an existing program Program will be Section A.2.1.36 Monitoring and that will be enhanced to: enhanced no later than Maintenance

1.

blse seRifiea seatiR§ iRspesleFS teF ltle iRspeslieR et SeFYise be1,*el I six months prior to the Exelon Letter Program sealiR§S. Use Level II or Level Ill coating inspectors, certified to second period of ANSI N45.2.6, for inspection of Service Level I coatings. extended operation. PBAPSSLRA RA/ Response datedMay2, 2019

May 2, 2019 Enclosure C Page 2 of 5 As a result of the responses to RAls B.2.1.17-1, 8.2.1.17-2, 8.2.1.17-3, and 8.2.1.17-4 provided in Enclosure A of this letter, SLRA Appendix A, Section A.5, Commitment 17, beginning on page A-95 of the SLRA, is revised as shown below: NO. PROGRAM OR COMMITMENT IMPLEMENTATION TOPIC SCHEDULE* SOURCE 17 Fire Water System Fire Water System is an existing program that will be enhanced to: Program will be Section A.2.1. 17

1.

Revise flow test procedures to include: enhanced no later than

a. Inspector test flush acceptance criteria for wet pipe sprinkler six months prior to the second period of systems that currently do not include the requirement to record time extended operation.

to flow from the opened test valve. Inspections that are to be

b. Acceptance criteria for wet pipe main drain tests. Flowing completed prior to the pressures from test to test will be monitored to determine if there is second period of a 10 percent reduction in full flow pressure when compared to extended operation will previously performed tests. An issue report shall be generated in be completed no later the corrective action program to determine the cause and corrective than six months prior to actions.

the second period of Exelon Letter

c. If flow test acceptance criteria are not met, perform an extended operation, or PBAPSSLRA investigation within the corrective action program that no later than the last RA/ Response, includes review for increased testing and perform at least two refueling outage prior to datedMay2, successful additional tests. sl'lall be perfaFR'tae Additional tests the second period of 2019 shall be completed within the interval in which the original test extended operation.

was conducted. If acceptance criteria are not met during follow-up testing, an extent of condition and extent of cause analysis shall be conducted to determine the further extent of tests which includes testing Tl'le test sl'lall ba perfa~mee on the same system, on the other unit.

4. Revise procedures to improve guidance for external visual inspections of the in scope sprinkler systems piping and sprinklers at least every two years to inspect for exsessiva corrosion, loss of material, leaks, and proper sprinkler orientation. Corroded, leaking or damaged sprinklers shall be replaced.

NO. PROGRAM OR COMMITMENT TOPIC

15. Revise the fire hydrant inspection and flush test procedure to include a minimum flow duration of one (1) minute after the hydrant valve is fully open to remove all foreign material.

16. Revise the underground fire main flow test to utilize the corrective action program to determine an increased test frequency when established test criteria is not met or when significant degraded trends that could adversely affect system intended function are identified. When test results pass the established test criteria, the test frequency may be extended to a five (5) year frequency IA W NFPA25.

IMPLEMENTATION SCHEDULE* May 2, 2019 Enclosure C Page 3 of 5 SOURCE Exelon Letter PBAPSSLRA RA/ Response, datedMay2, 2019

May 2, 2019 Enclosure C Page 4 of 5 As a result of the response to RAI 3.3.2.2.7-1 provided in Enclosure A of this letter, SLRA Appendix A, Section A.5, Commitment 11 on page A-93 of the SLRA is revised as shown below: PROGRAM OR IMPLEMENTATION SOURCE NO. COMMITMENT TOPIC SCHEDULE* 11 Open-Cycle Cooling Open-Cycle Cooling Water System is an existing program that will be enhanced to: Program will be Section A.2.1. 11 Water System

1.

Provide procedural direction to perform additional inspections if the cause enhanced no later than of the aging effect for each applicable material and environment six months prior to the combination is not corrected by repair or replacement for all components second period of constructed of the same material and exposed to the same environment. extended operation. These additional inspections will be conducted if any of the inspections do not meet acceptance criteria. No fewer than five additional inspections will be performed for each inspection that does not meet acceptance criteria, or 20 percent of each applicable material, environment, and aging effect combination, whichever is less.

2.

Perform a minimum of 20 inspections for recurring internal Exelon Letter corrosion in the raw water cooling water systems every 24 months PBAPSSLRA until the rate of recurring internal corrosion occurrences no longer RA/ Response, meets the criteria for recurring internal corrosion as defined in SLRA datedMay2, Section 3.3.2.2.7. The selected inspection locations will be 2019 periodically reviewed to validate their relevance and usefulness and adjusted as appropriate. Evaluation of the inspection results will include (1) a comparison to the nominal wall thickness or previous wall thickness measurements to determine rate of corrosion degradation; (2) a comparison to the design minimum allowable wall thickness to determine the acceptability of the component for continued use; and (3) a determination of reinspection interval.

3.

Provide procedural direction to require the use of a mill tolerance of 12.5% for added conservatism when determining corrosion rates at new inspection locations if corrosion rates from other locations with nearly identical operating conditions, material, size, and configuration cannot be used.

May 2, 2019 Enclosure C Page 5 of 5 As a result of the response to RAI 3.3.2.2.7-1 provided in Enclosure A of this letter, SLRA Appendix A, Section A.5, Commitment 17, beginning on page A-95 of the SLRA is revised as shown below: NO. PROGRAM OR COMMITMENT IMPLEMENTATION SOURCE TOPIC SCHEDULE* 17 Fire Water System

17. Perform at least five additional ultrasonic test inspections on the fire Program will be Section A.2.1.17 water supply piping for each Fire Water System pipe wall inspection enhanced no later than Exelon Letter that does not meet acceptance criteria.

six months prior to the second period of PBAPSSLRA

18. Provide procedural direction to require the use of a mill tolerance of extended operation.

RA/ Response, Inspections that are to be datedMay2, 12.5% for added conservatism when determining corrosion rates at completed prior to the 2019 new inspection locations if corrosion rates from other locations with second period of nearly identical operating conditions, material, size, and extended operation will configuration cannot be used. be completed no later than six months prior to the second period of extended operation, or no later than the last refueling outage prior to the second period of extended operation.}}